annex 4a.10: substations and switchgear strategy; ehv to lv

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Annex 4A.10: Substations and Switchgear Strategy; EHV to LV Including EHV & Primary Switchgear, 33/11kV Transformers, Secondary Substations and LV plant RIIO-ED2 Business Plan December 2021

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Page 1: Annex 4A.10: Substations and Switchgear Strategy; EHV to LV

Annex 4A.10:

Substations and Switchgear Strategy; EHV to LV Including EHV & Primary Switchgear, 33/11kV Transformers, Secondary Substations and LV plant

RIIO-ED2 Business Plan December 2021

Page 2: Annex 4A.10: Substations and Switchgear Strategy; EHV to LV

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Contents

1. AN INTRODUCTION TO THIS ANNEX ....................................................................................... 2

2. ANNEX STRUCTURE .................................................................................................................. 5

3. ASSET IDENTIFICATION & PRIORITISATION PROCESS ....................................................... 5

Network Asset Risk ................................................................................................................... 6 Data, Modelling & Selection Process ........................................................................................ 6

4. ASSET INTERVENTION & OPTIONEERING ............................................................................. 7

Innovation .................................................................................................................................. 8 EHV Switchgear (33kV) Plant Replacement Types & Summary .............................................. 9 EHV Switchgear (33kV) Refurbishment .................................................................................. 11 EHV Transformers Type Issues & Summary .......................................................................... 11 Primary Switchgear Plant Types & Summary ......................................................................... 12 Secondary Switchgear Type Issues & Summary .................................................................... 15 HV Transformers Type Issues & Summary ............................................................................ 19 LV Switchgear at Substation Type Issues & Summary .......................................................... 20 LV Street Furniture Issues & Intervention Drivers ................................................................... 21

Transition to SF6-Free Switchgear .......................................................................................... 21

5. SP MANWEB COMPANY SPECIFIC FACTORS ..................................................................... 22

6. ASSET MODERNISATION FORECASTS................................................................................. 23

EHV Switchgear (33kV) .......................................................................................................... 23 EHV Transformers .................................................................................................................. 24 Primary Switchgear ................................................................................................................. 25 Secondary Switchgear ............................................................................................................ 27 HV Transformers ..................................................................................................................... 28 LV Switchgear in Substations ................................................................................................. 29 LV Street Furniture .................................................................................................................. 30 Overall Risk Benefits from Substation Interventions ............................................................... 32

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1. An introduction to this annex

Scope

This annex details the strategy for SP Distribution (SPD) & SP Manweb (SPM) substations and switchgear from EHV to LV Including EHV & Primary Switchgear, 33/11kV Transformers, Secondary Substations and LV plant as a part of the RIIO-ED2 Non-Load plan.

The scope of this annex relates to Asset Modernisation activity (captured within the CV7, 8, 9 Business Plan Data Tables).

The key driver for the activity included within this strategy is optimising the management of our network asset risk for NARM (Network Asset Risk Metric) and Non-NARM assets.

This incorporates the management of requirements and application of asset management policies, business strategy, assessment processes and techniques (including CNAIM V2.1) as well as considerations of sustainability and deliverability.

The focus of this strategy is on the following asset types:

EHV switchgear (33kV)

o 33kV Circuit Breakers ID (Indoor)

o 33kV Circuit Breakers OD (Outdoor)

o 33kV Ring Main Units ID (Indoor)

EHV Transformers (EHV/HV)

o 33kV-11kV/6.6kV Transformers

Primary Switchgear (6.6/11kV),

o Primary Circuit Breakers

Secondary substation plant (6.6/11kV)

o 6.6/11kV Ring Main Units

o 6.6/11kV Circuit Breakers

o 6.6/11kV Switches

o LV Circuit Breakers/X-Type Fuseboards

o LV Fuseboards and LV cabinets

o Secondary Transformers (HV/LV – 11/6.6-0.415kV)

LV Street Furniture

o LV Link pillars

o LV Link boxes

This document should be read in conjunction with the below:

Network Asset Risk Annex (Annex 4A.4)

Future System Strategy Annex (Annex 4A.1)

Engineering Justification Papers (EJPs) associated with the activity within this strategy are referenced throughout the document.

Key highlights

The proposed investment activities detailed in this annex result in a total programme investment of £214.4m - £109.4m in SPD and £105.0m in SPM. This includes the following:

Replacement of 210 EHV Switchgear assets (109 in SPD, 101 in SPM)

Refurbishment of 101 EHV Switchgear assets (35 in SPD, 66 in SPM)

Replacement of 104 EHV Transformers (64 in SPD, 40 in SPM)

Refurbishment of 60 EHV Transformers (41 in SPD, 19 in SPM)

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Replacement of 553 HV Primary Circuit Breakers (363 in SPD, 290 in SPM)

Refurbishment & Retrofit of 466 HV Primary Circuit Breakers (182 in SPD, 284 in SPM)

Replacement of 2,092 Secondary Switchgear assets (1,045 in SPD, 1,037 in SPM)

Refurbishment of 204 Secondary Switchgear assets (204 in SPD)

Replacement of 491 HV Transformers (266 in SPD, 225 in SPM)

Refurbishment of 327 HV Transformers (327 in SPM)

Replacement of 1,077 LV Switchgear assets (447 in SPD, 630 in SPM)

Replacement of 4,037 LV Street Furniture assets (2,052 in SPD, 1,985 in SPM).

This programme results in a total monetised risk benefit of £279.1m across the 5 years of RIIO-ED2. This is split across the licences with £149.3m risk benefit in SPD and £129.8m risk benefit in SPM. Whilst the overall risk associated with Distribution Switchgear & Transformers does increase over the ED2 period, and the impact of intervention varies, the increase in risk is significantly less than it would be without intervention.

Benefits

The RIIO-ED2 period aligns with wider societal change. During this time distribution networks will be a key enabler of Net Zero and will stimulate the national Green Recovery.

Network utilisation is forecast to be stressed beyond the original design capacity of the network. Complexity of network operation is increasing significantly as we rely on flexibility, DSO constraint management and innovation for real-time advanced network management. The criticality of our assets is rising as customers transition to Net Zero and connect greater numbers of electric vehicles and heat pumps in response to the climate emergency. All of this is set against the unavoidable and contemporaneous deterioration of our asset base.

Our RIIO-ED2 asset management plans will ensure the safety, reliability, and resilience of the network is maintained by investing in the underlying integrity and health of our existing asset infrastructure. This ensures the network can support the forecast growth in demand, generation, complexity of operation and new DSO functionality required to allow our customers to decarbonise, and the UK to transition to Net Zero.

Our customers prioritise four main things in their electricity supply: reliability, safety, cost-efficiency, and the freedom to consume when they want (domestic customers especially do not want to be constrained). The challenge for us in RIIO-ED2 is how to continue delivering these customer priorities against a radically changing energy landscape. In RIIO-ED2 we have a critical role to enable these evolving customers’ needs, deliver a Just Transition to Net Zero, and ensure the continued safe, reliable, and efficient operation of the distribution network and wider system.

Why Asset Management is important in RIIO-ED2

our customers are increasingly

dependent on a reliable

electricity supply as they

increasingly use electricity for

transport and heating.

Our customers depend

on us…

our plans will manage the

deterioration of our assets in

RIIO-ED2 by targeting

modernisation on our poorest

condition assets, promoting life

extension where possible, and

prioritising assets with the

greatest consequence of failure.

We are managing an

ageing and deteriorating

asset base…

the electrification of heat and

transport will increase network

power flows. Network assets

will be operating at a higher level

of utilisation, increasing the

deterioration (‘wear and tear’ rate) of assets.

We are pushing the

network harder…

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Customer and stakeholder input We have undertaken significant stakeholder engagement as part of our plan development and have sought feedback from a range of stakeholders. See Annex 3.1 – Co-creating our RIIO-ED2 Business Plan with our Stakeholders for more information on this process. Following this engagement, we have developed the below commitments for RIIO-ED2 which are relevant to this Annex:

Improving public safety from our LV assets: We will improve public safety risk by replacing over 2,000 of our last remaining poorest condition underground link boxes and modernising nearly 2,000 low voltage pillars in publicly accessible areas during RIIO-ED2.

o Stakeholder feedback phase 3, S3.6 Reliability: Many stakeholders agreed with the level of ambition for this commitment, and there was overarching sentiment that this commitment is proactive and useful.

o Customer acceptability phase 3, C3.6 Reliability: There was 98.2% acceptability for this commitment.

Improving the reliability of our networks:

We will continue to optimise the level of network risk, reducing asset deterioration from around 5.4% per year without intervention to around 1.1% through our targeted and optimised asset modernisation programme over RIIO-ED2.

We will improve the reliability of our supply to customers, ensuring that on average customers will be 19% less likely to experience an unplanned interruption, and average duration will reduce by 19%. We will do this over the duration of RIIO-ED2 by investing in new & proven technologies and embedding innovation.

o Stakeholder feedback phase 3, S3.3 Reliability: Stakeholders praised SPEN’s stated focus on short as well as long interruptions.

o Customer acceptability phase 3, C3.3 Reliability: There was 95.9% acceptability for this commitment.

Delivering our Plan

Our RIIO-ED2 plans in this area are consistent with our historic levels of activity and our RIIO-ED1 track record, delivery profiles have been optimised where possible to ensure maximum customer benefit. By comparing to our past performance, and considering deliverability constraints in the planning stage, we are confident the RIIO-ED2 plans set out in this annex are deliverable, realistic, and required by our customers. Programme development and deliverability assessments have been completed in parallel to ensure our business can deliver the required level of investment.

The key differences between RIIO-ED1 and RIIO-ED2 for the strategy covered by this annex are:

Increase in LV switchgear asset replacements due to improved condition data collected in RIIO-ED1.

Increase in HV Primary circuit breaker retrofits based on advanced analysis of health and condition of our underlying asset base. This has revealed a requirement for increased levels of intervention to manage network risk. This solution has also proven to be a cost-effective and efficient life-extension practice in ED1 which offers a lower disruption alternative to full replacement. By increasing the proportion of retrofit activity undertaken, we are satisfied the overall HV Switchgear program is deliverable.

Decrease in HV Underground (Buried) Transformers because of updated tenders affecting unit cost.

Decrease in HV Primary circuit breaker replacements to offset increase in retrofits and ensure our overall program is comparable with our delivery track-record, making use of our current and forecast resources.

For further information on the deliverability of activities included within this strategy, and evidence of our RIIO-ED1 track record, refer to the EJPs detailed throughout this document. For more information on our Deliverability strategy, see Annex 6.1 – Delivering our Plan.

Signpost for Ofgem’s business plan requirements

Ofgem BP Guidance No Annex Page Number N/A

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2. Annex Structure

This annex will outline the methodology for assessing and identifying an initial list of assets for intervention, followed by the process for selecting the optimal intervention type and time for each asset. It also provides detail on known type issues, current volumes, forecast issues and other considerations. Finally, the cost and benefit of proposed interventions will be discussed, including risk point movements using CNAIM v2.1.

This annex covers several forecast interventions, full engineering justification for these activities can be found in the following EJPs:

ED2-NLR(A)-SPEN-001-SWG-EJP LV Switchgear

ED2-NLR(A)-SPEN-001-SWGTX-EJP Secondary Substation

ED2-NLR(A)-SPEN-001-TX-EJP Primary Transformer Modernisation

ED2-NLR(A)-SPEN-002-SWG-EJP Primary Switchgear

ED2-NLR(A)-SPEN-002-TX-EJP HV Underground Transformer Replacement

ED2-NLR(A)-SPEN-003-SWG-EJP EHV Switchgear

ED2-NLR(A)-SPEN-004-SWG-EJP SF6 Primary (11/6.6kV) Switchgear Refurbishment

3. Asset Identification & Prioritisation Process

The investment strategy for distribution plant modernisation is directed at maintaining, managing, and optimising the overall network risk experienced by customers and follows the principles set out in the business plans and strategies for managing risk.

This will be achieved through prioritised and targeted site and asset specific approach. Such an approach is necessary to effectively manage the risks and ensure long-term sustainability, utilising appropriate engineering interventions and risk management techniques as set out in our Network Asset Risk Strategy Annex (Annex 4A.4). Specifically, the strategy aims to maintain safety, integrity and performance of the network whilst meeting the long-term objectives in Annex 4C.3 Environmental Action Plan and Annex 4A.4.

Risk will be addressed through interventions targeting assets at, or approaching, end of life within the RIIO-ED2 period or, where appropriate, can be refurbished - thereby extending the useful life. This will be achieved through a combination of engineering condition and type information, application of the Common Network Asset Indices Methodology (CNAIM v2.1), our CBRM and Arcadis Gen Optimisation system and the guidance provided through the supporting internal documents e.g. SWG-02-007 (Issue 16) Switchgear Type Assessment, and TRAN-02-002 (Issue 8) Assessment of Operational Adequacy of Transformers & Reactors (22kV & Above).

This methodology is applied to each individual asset and may identify only a proportion of, for example, a large switchboard in need of intervention and, if appropriate, action to defer wider investment in that switchboard will be taken. This may be achieved through enhanced maintenance, or refurbishment of units with type issues or poor condition assessments.

While the NARMS methodology identifies the risks raised by each assessed asset, a decision to intervene in specific assets also considers factors and concerns specific to that asset, its location, and the availability of appropriate interventions.

Our asset identification process involves:

Inspection & condition data collection: following ESQCR regulations by inspecting all our assets at regular intervals to ensure our assets are safe and secure, whilst gathering necessary condition data to inform our asset management database, as per Annex 4A.20 Network Operating Costs.

Health index and criticality mapping to develop risk score: using CNAIM methodology to assign health and consequence of failure scores to every NARMs asset, and SPEN company-specific scoring methodologies to assign health and risk scores to all non-NARMs assets.

Removing PTIs/SOPs: (Plant Type Issues/Suspension of Operational Practice) identifying assets which may have type issues or SOPs associated with their model and reducing the number of live SOPs and PTIs on our network.

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Identifying optimum intervention type: assessing the intervention types possible for each asset and identifying the most cost-efficient and beneficial intervention to undertake in RIIO-ED2.

Prioritisation of asset intervention: recognising that some assets require intervention sooner than others and prioritising based on condition data and local district knowledge.

Optimisation strategies: calculating the optimum time to intervene on an asset based on its long-term risk profile developed from known condition inputs – refer to Sections 7-9 of Annex 4A.4 – Network Asset Risk Strategy for more details.

Bundling: alignment of asset intervention works at the location or within the same programme to improve efficiency of schemes and reduce customer interruptions.

Automation and monitoring: introducing increased automation and monitoring on the HV and LV network to reduce customer interruptions (CIs) and customer minutes lost (CMLs), improve efficiency of our operational staff, and gain increased visibility of our network loading.

Repair & maintenance: ensuring all our assets are kept in working condition by maintaining and repairing in line with manufacturers’ recommendations and internal policies.

Network Asset Risk

To understand the level of risk across the network, each asset is given a risk score using a common methodology across all UK DNOs – currently CNAIM v2.1. The risk score is a combination of health index and criticality of the asset. These can be thought of as the probability and consequence of failure.

In SPD & SPM, known asset data such as age, location, and asset type with condition inputs from inspections is combined to develop the health index (HI) for each asset. The criticality index (C) is developed from the safety, financial, environmental and network performance consequences of the failure of each asset.

Combining the health and criticality scores with local network knowledge further improves our understanding of the risk on the network. Asset defects, plant type issues and SOP notices are all factors which increase the perceived risk an asset is assigned.

Removing some of this risk to keep the overall network risk at managed levels is an important part of our ED2 strategy and is essential to ensure the distribution network continues to work efficiently and safely. Ignoring at-risk assets could have catastrophic consequences on customers’ supplies, the safety of the public and our employees, and the environment surrounding our assets. For this reason, identifying assets in need of modernisation is a highly critical and essential part of our business plan, and must be carried out pro-actively rather than reactively.

To understand more of our Network Asset Risk Strategy, see Annex 4A.4.

Data, Modelling & Selection Process

The assessment of the switchgear and transformer fleet and the drivers for intervention follow a structured process which has been shown to identify the candidate assets with a high degree of confidence. This is achieved through a hierarchy of data flows which are weighted and refined to achieve risk management and optimal timing of the intervention.

In line with regulatory requirements and best practice, particularly the Common Network Asset Indices Methodology (CNAIM v2.1) the plant assessment and selection utilise inputs (data) from the basic asset data (make/type/rating etc.) and data learned during from maintenance and inspection activities.

The determination of key asset indicators – Health, Criticality, Probability of Failure and Risk – are then produced from the data utilising the Condition Based Risk Management (CBRM) system. CBRM is a widely used proprietary asset modelling system and the processes is highlighted below in Figure 1.

Inputs – Field condition and measured data points from asset inspections.

Asset Records – SAP database. Core asset data – make/type/age/maintenance history augmented condition.

Health and Criticality – CNAIM and CBRM assessment of condition, probability of failure (including future PoF) and asset criticality.

Optimisation – determination of optimal intervention point based on deterioration rate.

Prioritised model – review and weighting of all above factors to assess all assets on a common base.

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Initial candidate assets identified, and intervention threshold established.

Review and refine candidate units with Engineering and Programme delivery teams.

Establish optimal intervention type for each asset – Replace/Refurbish.

The CBRM outputs are further enhanced and weighted for the assessment of SPD and SPM plant assets by considering the lifetime risk based on a future Probability of Failure metric. This process identifies the optimum intervention point (year) for each asset.

While health and criticality, the use of risk metrics and whole of life evaluation are key features of this assessment, a range of other factors have also been used to prioritise the selection of assets for “Non-Load” intervention. These include:

The severity of type issues – operational and safety impact.

Inclusion in “Load” related investment or other redevelopment schemes.

Asset, Project, and Field engineering team assessment.

The availability of telecontrol facilities.

Optimal economic replacement year.

Outage constraints and geographical concentration of assets.

OEM support and spares availability.

Figure 1. Outline Asset Selection Process

4. Asset Intervention & Optioneering

A broad range of interventions for each asset type has been considered in the identification and prioritisation process as documented in the relevant Engineering Justification Papers. These intervention types are summarised below in Table 4.1.

Table 4.1. Asset Intervention Options

Options Details Advantages Disadvantages

Do nothing Maintenance only and replacement failed assets (Post fault repair).

Low capital cost. Unacceptable safety and performance risk.

Refurbish Undertake enhanced maintenance replacing key plant components.

Low capital costs and system outage requirements.

Poor spares and skills availability for legacy plant. Increased safety risk.

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Options Details Advantages Disadvantages

Retrofit Partial replacement of elements of asset using modern equivalent parts.

Low capital costs and system outage requirements. Retrofit of SF6-free circuit breakers for leaking units’ important element of EAP SF6 management

Very few assets supported by OEMs or Third-party manufacturers.

Replacement with alternative plant type

Removal of asset type and deployment of new types.

Removes legacy “high risk” asset types and assets with an environmental effect.

Only applicable to limited asset types (i.e. LV street furniture, SF6-Filled assets).

Blended intervention based on risk-based assessment.

Prioritised intervention type utilising best available solution for each asset.

Optimised intervention with appropriate mix of cost and risk.

More complex programme management.

Replace all HI5 Assets

Replace all HI5 plant based on condition.

Straight-forward intervention. Will achieve lowest risk.

High capital cost, extensive system outages.

Civil Intervention for LV Street Furniture

Undertake interventions to improve the civil condition of an asset.

Low capital costs and system outage requirements.

Only applicable to limited asset type under this annex (i.e. LV street furniture).

Innovation

The range of power system plant covered by this annex includes switchgear and transformers from 33kV to LV and at each level the strategy has been influenced by various innovations. In addition, the provision of modern switchgear capacity and operational features will provide support to some innovation initiatives. This is summarised below:

Optimal Intervention – the right time to intervene. For RIIO-ED2, we are applying a sophisticated cloud-based optimisation engine to inform our planning process. Our collaboration with market leading analytics specialists is designed to determine the optimal intervention timing point based on the outputs of our CBRM planning process described above. Establishing the optimum economic point for any network intervention is a process that attempts to balance both the cost of intervention (i.e. asset replacement or refurbishment) with the benefits of that intervention (reduced asset risk). Once asset risk for each future year has been established and quantified as a monetised value (by considering monetised consequences should a failure occur, along with the PoF), the cost/benefit can be compared against the long-term asset risk for each future year. For more information, see the Network Asset Risk Strategy (Annex 4A.4).

Active Network Management. Where primary switchgear is being replaced, the new switchboard will be fitted with tele-control facilities which will support smart features including ANM and DSO initiatives.

LV Monitoring. The connectivity models (incl. the NAVI platform) will influence the requirement and locations of equipment in the LV pillar/link box replacement programme.

Fault Level Management. As fault levels rise across the system due to the adoption of low carbon generation, modern switchgear - driven by standards - has a higher fault level limit than the units being replaced. Typically, this means that 11kV primary and secondary fault interruption capacity will be raised significantly over the existing nameplate rating of 250MVA/13.1kA.

Novel Transformer Bunding. Where transformer replacements are being undertaken, the opportunity to apply recently developed bunding techniques will be considered to efficiently comply with environmental standards and support the Net Zero transition.

Transformer Oil Regeneration. A trial of a transformer mounted online canister-based oil regeneration will be extended into RIIO-ED2. This online canister method used by SPEN is filled with a high purity alumina oxide adsorbent which removes moisture and acids from the oil whilst keeping dissolved gases which are key to fault diagnosis.

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33kV RMU (SPM). In addition to the programmed innovation projects, specific developments in switchgear application such as the introduction of new types of plant in place of the traditional SPM 33kV RMU are expected to bring efficiency benefits.

SF6-Free Switchgear. A specific environmental challenge is the availability of SF6-free switchgear at 33kV. We are actively working with manufacturers to develop these new solutions and are working to manage physical size as well as the carbon footprint of the new equipment. As a result of innovation in this area it is expected that SF6-free/alt gas solutions will be increasingly available for deployment within the RIIO-ED2 period. This is discussed further in Section 4.10. For more information see Annex 4C.3-Environmental Action Plan.

LV Engine. It is anticipated that following on from SPEN’s LV Engine ED1 innovation project, forecast to complete in 2022, smart transformers will be installed in locations likely to experience higher LCT uptake volumes as part of the HV transformer asset replacement strategy. These will provide benefits such as on-load phase voltage regulation, power sharing, LVDC supplies and real-time network data collection. The successful rollout of LV Engine in Great Britain has the potential to represent a saving of £62m by 2030.

On Load Tap Changers. A SPEN innovation project associated with secondary transformers is the On-Load Tap Changers (OLTCs) project. OLTCs reduce energy losses by enabling operation at lower voltage, representing a customer saving of up to £70 annually. The faster connection of LCTs and avoidance of network reinforcement result in reduced carbon emissions, and there is less planning and site works than for conventional reinforcement. This also leads to lower customer interruptions and improved quality of supply due to voltage regulation.

For more information on how we will continue to innovate in RIIO-ED2, see Annex 2.1 – Our Innovation Strategy.

EHV Switchgear (33kV) Plant Replacement Types & Summary

This asset group consists of EHV switchgear at 33kV substations on the SPD and SPM networks. RIIO-ED2 plan builds on our existing (RIIO-ED1) investments through the health and criticality process which will require a widening of the asset replacement programme to some additional plant types. The SPD network has 1,324 switchgear units on the EHV system while the SPM network has 2,446 due to the network design and the use of 33kV Ring Main Units (RMUs).

Four main EHV switchgear intervention modes have been considered and the most economic and practical intervention is identified for each case. These interventions are:

Replace – In this case EHV switchgear plant will be replaced with a modern equivalent which will also provide safety, environmental and operational benefits over the existing legacy plant.

Retrofit – Where the circuit breaker being assessed is “isolatable” (i.e. the active circuit breaker components can be removed from their fixed panel housing for maintenance and earthing purposes) the replacement of the circuit breaker truck/carriage with a modern equivalent may be an efficient means of life extension.

Refurbish – In situations where switchgear units are suitable for continued service but are affected by known type issues, OEM refurbishment and remedial work has been considered.

Retain & Maintain – Where the assessment and modelling indicate that the asset should be retained, it will be subject to regular inspection and routine maintenance. The health index will be regularly reviewed and updated from information derived from routine maintenance procedures.

Due to a large population of certain models of switchgear, interventions tend to be focussed on a relatively small number of manufacturer’s types which are also exposed to lack of OEM support/spares and have existing operational issues.

In SPD the following types account for over 80% of the proposed circuit breaker replacement activity:

South Wales Switchgear EO1 (OD)

Cooke & Ferguson FE5 (ID)

English Electric JB424 (OD)

English Electric OKM4 (OD)

GEC KDJ8S (OD)

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Similarly, in SPM four types of switchgear account for 79% of the proposed circuit breaker replacement intervention:

South Wales Switchgear EO1 (OD)

Cooke & Ferguson FE5 (ID)

English Electric JB424 (OD)

AEI MF36 (ID)

The types, asset count, plan volume and a summary of the drivers for investment are detailed in Table 4.2 below for replacement and refurbishment.

Table 4.2. EHV Switchgear Asset Replacement Intervention [Engineering Justification Paper ED2-NLR(A)-SPEN-002-SWG-EJP]

Switchgear Make/Type Typical Example Commentary

South Wales Switchgear EO1 (OD)

SPD Volume 44 [ED2 Plan – 28] SPM Volume 35 [ED2 Plan – 25]

The EO1 OCB suffers from disruptive failure risk due to bushing moisture contamination and tank seal failures. It is also known to suffer from mechanism fouling and distortion. Installed between 1962 and 1976, these units are no longer supported by OEM and there is no spares support.

Cook & Ferguson FE5 (ID)

SPD Volume 44 [ED2 Plan – 22] SPM Volume 9 [ED2 Plan - 7]

A 1940s design 33kV OCB installed on both SPD and SPM networks utilising small oil volume tanks. Many now at HI5 with no support from manufacturer or third parties for maintenance or spares.

AEI/Metropolitan Vickers VSLP9 (ID)

SPD Volume 59 [ED2 Plan – 5] SPM Volume 101 [ED2 Plan – 0]

Installed between 1951 and 1975 on both SPD & SPM networks, the VSLP range is known to suffer compound busbar and riser failures. Now becoming increasingly difficult to maintain and source spares. Very limited OEM and TP (third party) support is available.

English Electric JB424 (OD)

SPD Volume 15 [ED2 Plan – 12] SPM Volume 14 [ED2 Plan – 11]

This circuit breaker is deployed on both the SPD and SPM networks and mainly installed during the 1960s. Frequent failure to trip due to mechanism problems and corrosion. Also suffers from moisture ingress and bushing failures.

33kV RMU (SPM) BTH/Metropolitan Vickers/AEI MF36 Ferguson-Palin VSP32/9, VSRP32

SPD [N/A] SPM Volume 201 [ED2 Plan – 33]

GEC 33kV RMU

A high proportion of the 33kV RMU fleet will be in HI5 category without intervention. the intervention is distributed over a wide RMU age spread, ranging from 62 to 78 years at the end of the ED2 period. as shown in Figure 5. The 33kV RMU design is unique to the SPM network but has not been manufactured or supported by the OEMs since the 1970s. Spares and skills are now extremely limited.

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EHV Switchgear (33kV) Refurbishment

Although not available for many legacy plant assets, refurbishment of suitable mid-life plant that is supported by the OEM can efficiently provide operational, safety and environmental benefits. Two main types of switchgear have been identified for refurbishment - FKI Horizon OD 33kV CB and Schneider (MESA) CBGS-0 ID CB as summarised in Table 4.3 below.

Table 4.3. EHV Switchgear Asset Refurbishment Intervention Switchgear Make/Type Typical Example Commentary

FKI Horizon 33kV Outdoor Circuit Breaker.

SPD Volume 14 [ED2 Plan – 6] SPM Volume 22 [ED2 Plan – 15]

The FKI (Brush) Horizon 33kV is an outdoor SF6 circuit breaker which will be circa 25 years old by the end of the RIIO-ED2 period. This type has suffered from SF6 leaks and while the CB was designed to a higher leak specification, the unacceptably high leakage rate has been attributed to inadequate and degrading gas seals. This type is fully supported by the OEM who will carry out the factory refurbishment.

Schneider MESA CBGS-0 Indoor Circuit Breaker

SPD Volume 94 [ED2 Plan – 29] SPM Volume 207 [ED2 Plan – 51]

A proportion of the CBGS-0 circuit breakers have suffered from a 33kV bushing defect which has led to several disruptive failures. Some units have also been affected by a disconnector link failure which is managed by a SOP (Suspension of Operational Practice) but this is as critical safety issue that is becoming increasingly difficult to manage. It is proposed that both issues will be addressed by a factory refurbishment with the full support of the OEM.

EHV Transformers Type Issues & Summary

Power transformers are a key component of the distribution network and their failure can lead to widespread loss of supplies, create a safety risk or environmental hazards. The asset base must be managed properly to ensure a reliable supply and greatest customer benefit in the near and long term. Much of the EHV transformer fleet in SPM and SPD is in urban areas and actions to avoid a catastrophic failure is a priority for DNOs. Replacement is favoured for HI5 assets and refurbishment is favoured for HI4 units. SPEN’s Transformer Fleet Management database has also been applied to assess internal oil condition trends (dissolved gas analysis (DGA), moisture, acidity, and breakdown voltage) to verify needs case and confirm appropriate interventions types. Functionality and operational adequacy of tap changer units and automatic voltage control (AVC) systems have also been used to prioritise RIIO-ED2 intervention plans.

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Table 4.4. EHV Transformer Replacement & Refurbishment [Engineering Justification Paper ED2-NLR(A)-SPEN-001-TX-EJP]

Transformer Make/Type

Example Issues Comment

SPD 33/11/6.6kV SPD Volume 768 ED2 Plan Replace 64 units, Refurbish 41 units

Typical SPD Transformer with separate

radiator.

Transformer condition is the primary driver for intervention, and this is established from a) External condition - broadly the level of oil leaks and/or corrosion of the main tank, fins/radiators, bushings, gaskets, kiosks etc. and b) Internal condition – indicators from the transformers active part, including the core, windings and insulation; both paper and oil. The internal condition is best captured by oil and dissolved gas analysis. Without intervention 199 SPD transformers (26%) will reach HI5 by the end of the RIIO-ED2 period. Over 60% of SPD interventions will be through refurbishment.

In SPD the majority of the 33kV transformer fleet was installed during the 1960‘s and 1970‘s. It is notable that in SPD a larger proportion of the asset base is skewed toward an older age with a significant increase in investment between 1958 and 1963. Typically, SPD transformers are rated 12/24 MVA.

SPM 33/11/6.6kV SPM Volume 840 ED2 Plan Replace 40 units, Refurbish 19 units

Typical SPM Transformer with tank

mounted radiator.

Without intervention 91 SPM transformers (11%) will reach HI5 by the end of the RIIO-ED2 period. When compared to the SPD transformers the SPM fleet is somewhat younger with lower historical investment peaks. The tap changer is a key transformer component which adjusts the voltage through the selection of winding “taps”. Spares and support for these electromechanical devices are becoming scarce as most manufacturers are no longer in business. Where the condition of a unit is recoverable, this may be through a combination of refurbishment and oil regeneration as appropriate. Approximately 50% of SPM interventions will be through refurbishment.

The SPM network design utilises 33/11kV transformers in an interconnected mesh arrangement typically with a single 10MVA transformer at primary substation sites.

Primary Switchgear Plant Types & Summary

This asset group consists of HV switchgear at Primary Substations on the SPD and SPM networks. RIIO-ED2 builds on our existing activity by expanding the range of assets which could utilise retrofit equipment to address health and criticality and to facilitate network automation and condition monitoring. Additional switchgear types identified through the health and criticality process will require a widening of the asset replacement programme to additional plant types. The SPD network has 4,737 switchgear units on the 6.6/11kV system while the SPM network has 5,739.

Due to a large population of certain models of switchgear, interventions tend to be focussed on a relatively small number of manufacturer’s types which are also exposed to lack of OEM support/spares and have existing operational issues. These models include the following high population units listed below and described in Table 4.5 below:

Reyrolle ‘C’ equipment (SPD)

South Wales Switchgear C4X/C8X/D12 (SPD/SPM)

English Electric BVP/BVRP (SPD/SPM)

Johnson and Phillips JPBF OCBs (SPM)

In the assessment of primary substation switchgear, the most economic and practical intervention is identified for each case. However, whilst asset replacement can be applied to all assets, retrofit and refurbishment is limited

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by product, skills, and legacy component availability and therefore applicable to a subset of the circuit breaker population. In addition, and in line with the requirements of the F-Gas regulations and the SP Energy Networks Environmental Action Plan, 100 SF6 circuit breakers which have been identified with high SF6 leakage rates will be retrofitted with an equivalent gas-free unit.

The equipment identified in this proposal has been selected through a process which will deliver the most efficient intervention to manage operational, safety and customer service risks that would arise from the continued use of this plant.

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Table 4.5. Primary Switchgear Replacement & Refurbishment [Engineering Justification Paper ED2-NLR(A)-SPEN-002-SWG-EJP]

Switchgear Make/Type & Volumes

Example Issues Comment

Reyrolle C5/6/7 6.6/11kV OCB SPD Volume 469 [ED2 Plan –163] SPM Volume 0 [ED2 Plan – N/A]

Frequent failure of the shutter mechanism to close properly and exposing live spouts to the operator as a consequence. Regular mechanism "failure to latch" when (manually) charging the spring mechanism. Both feeder and busbar spouts are earthed through extension earthing attachments which expose the operator to risk in application and operation as well as hidden damage to the fixed contacts. As the extension equipment is inserted any minor misalignment can damage fixed contacts and it is not possible to check/adjust.

Reyrolle C type switchgear that remains on the network was installed in the 1950s and 1960s and was superseded by the vertically isolated LMT variants in the 1960s. The oldest Reyrolle C type units will be around 75 years old at the end of the ED2 period without intervention.

South Wales Switchgear C4X/C8x Range SPD Volume 787 [ED2 Plan – 68] SPM Volume 1,297 [ED2 Plan – 41]

This OCB range is present in high volumes on the SPD and SPM networks with over 2,500 assets in service in Primary substations alone. The type has experienced failures to trip, to close and bushing/spout and busbar failures.

A successful 50s/60s OCB now developing end-of-life characteristics. High volumes in service give rise to concerns over the ability to manage asset intervention.

Ferguson Palin/English Electric/GEC BVP/BVRP Range SPD Volume 347 [ED2 Plan – 41] SPM Volume 443 [ED2 Plan – 51]

A contemporary of the SWS C4X OCBs above is again present in high volumes on the SPD and SPM networks. Has suffered from numerous failures to trip/close, interrupt faults and component failures. BVRP variants (SPM only) in SPM have suffered from disruptive failures associated with poor contact engagement due to buffer washer failures.

Not all units are at end of life but there is a significant population considered viable for intervention.

Johnson and Phillips PDB/JPBF SPD Volume 9 [ED2 Plan – 9] SPM Volume 227 [ED2 Plan – 186]

Johnson & Philips PDB and PDB-M (SPM variant) circuit breakers are an early 1950s design of indoor OCB installed in multi-panel switchboards and in secondary substation RMUs. Early versions fitted with a direct manual mechanism i.e. the movement of the contacts is directly dependent upon the effort of the operator. Early versions (type TDB OCB) were also unpotted (i.e. no arc control device was fitted) and were rated at 150MVA. All these OCBs where rebuilt between 1976 and 1985 to a 250MVA specification with independent manual mechanisms meaning that the speed of the contacts on closing and opening is spring powered and independent of the operator effort.

The switchgear units were "re-dated" following ‘Baldwin and Francis’ modifications in the 1980’s Fundamentally these circuit breakers date from the 1950s and therefore many will be over 70 years old & severely deteriorated by the end of RIIO-ED2.

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Table 4.6. Primary Switchgear Retrofit Intervention - See ED2-NLR(A)-SPEN-SWG-004-EJP

Switchgear Make/Type

Example Issues/Retrofit Comment

South Wales Switchgear (Brush) C4X/C8X Range SPD 787 [ED2 Plan 70] SPM 1,297 [ED2 Plan 116]

SWS HG12 Retrofit for SF6

Leakage reduction. SPD 639 [ED2 Plan 30] SPM 447 [ED2 Plan 50]

As noted above the C4X/D8X range has suffered from several degradation related problems but where the substation environment, the fixed components, control systems and operational earthing arrangements are all considered satisfactory, a retrofit CB can be deployed. This is offered by the OEM (Brush) and known as the SWR12. High leak rate SWS HG12 6.6/11kV primary circuit breakers will be retrofitted with Brush SWR gas-free units or equivalent.

A successful 50s/60s OCB now developing end-of-life characteristics including bushing failures/degradation and mechanism failure High volumes in service give rise to concerns over the ability to manage asset intervention through replacement only. The retrofit solution can also be applied to legacy SF6 switchgear installed between 1984 and 2000. High design leakage together with degraded seals result in unacceptable SF6 emission. See ED2-NLR(A)-SPEN-SWG-004-EJP

Reyrolle Switchgear (Siemens) LMT Range SPD Volume 326 [ED2 Plan 38] SPM Volume 205 [ED2 Plan 8]

LMT variants are present in high volumes on both SPD and SPM networks and have experienced several mechanism seizures and circuit breaker bushing failures.

The LMT range was installed on both the SPD and SPM networks from 1960 until around 1989. Support is available from the successor OEM and third party retrofit providers.

Yorkshire YSF6 Retrofit for SF6

Leakage reduction. SPD 126 [ED2 Plan 20] SPM 0 [ED2 Plan 0]

High leak rate Yorkshire YSF6 6.6/11kV primary circuit breakers will be retrofitted with Schneider (or equivalent) gas-free units.

Increasing volume of units affected by known leakage issues associated with gauges, seals, and gaskets.

See ED2-NLR(A)-SPEN-SWG-004-EJP

Secondary Switchgear Type Issues & Summary

This asset category includes all ground-mounted HV switchgear located at secondary substation sites across the SPD and SPM networks, including HV RMUs, HV X-Type RMUs, HV Switches and HV Circuit Breakers. The intervention options considered differ depending on the asset class.

For HV RMUs and X-Type RMUs, asset replacement is planned in both licences whilst asset refurbishment is also considered in SPD.

For HV Switches and HV Circuit Breakers, only asset replacement is planned in both licence areas.

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Over 31,700 secondary substations are connected to the SPD and SPM networks with 18,319 in SPD and 13,467 in SPM. Although there are obvious differences between the SPD and SPM networks, almost all secondary substations will contain HV switchgear, a transformer and LV fused distribution equipment. Before the development of the integrated Ring Main Unit (RMU) which facilitates interconnection between alternative supply sources, this function was often undertaken by multiple circuit breakers or a combination of oil switches and circuit breakers. Due to the meshed network configuration in SPM, the RMU was often a hybrid which utilised a fixed portion housing two oil switches and an isolatable oil circuit breaker. The switchgear types illustrated in the table below account for over 75% of the RIIO-ED2 secondary switchgear plan with the remainder of the switchgear comprising much smaller volumes of niche equipment types.

Table 4.7. Secondary Switchgear Replacement Intervention [Engineering Justification Paper ED2-NLR(A)-SPEN-001-SWGTX-EJP]

Switchgear Make/Type & Volumes

Example Issues

S&C RA4, RAE4, RAE6, RA04 11kV oil switch SPD Volume N/A [ED2 Plan N/A] SPM Volume 458 [ED2 Plan 248]

Switchgear & Cowans RA range of switchgear has been in service since the early 1960s but has suffered from a range of serious issues. These include numerous cable box failures, internal disruptive failures associated with switch contact overheating and mechanism failures. A total of 18 SOPs have been issued on this range of plant and SPD/SPM have issued 30 NEDERS notifications.

Lucy Type FRMU & FRMU Mk1 RMU SPD Volume N/A [ED2 Plan N/A] SPM Volume 693 [ED2 Plan 189]

Several types of Lucy FRMU (Fused Ring Main Unit) remain in service with the Mk1 version in particular experiencing excessive disruptive failures. This has been due to manufacturing defects (component mechanical failure) moisture ingress and numerous cable box failures. A total of 7 SOPs have been applied to this variant and 36 DINs have been issued by SPD/SPM and other network operators.

ABB Sentinel 2 RMU Serial number range 241-534 SPD Volume N/A [ED2 Plan N/A] SPM Volume 208 [ED2 Plan 75]

The ABB Sentinel is a circuit breaker ring main unit which has a serious manufacturing defect in the CB bushings. This has caused many disruptive failures and the majority of NEDERS reports (26) are associated with this defect. Other issues include defective mechanical interlocking and tripping failures.

South Wales Switchgear CRT 4 SPD Volume N/A [ED2 Plan N/A] SPM Volume 520 [ED2 Plan 93]

The CRT4 is a South Wales Switchgear OCB RMU which was utilised on the SPM network between 1955 and 1978. The CRT and variants have been known to suffer from mechanism wear and disruptive cable box failures. These units are a significant component of the SPM X-type network and none are deployed on the SPD network.

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Switchgear Make/Type & Volumes

Example Issues

GEC/EE BVRP17 & BVRP 500 Range SPD Volume 281 [ED2 Plan 31] SPM Volume 206 [ED2 Plan 14]

The BVP switchgear exists in high volumes on both the SPD and SPM networks in several variants. In total 5 SOPs and 33 DINS have been issued which include disruptive failures due to CTs, bushing failures and moisture ingress. A common issue is the poor or incomplete HV contact engagement of Voltage Transformer (VT) following return to service, leading to progressive partial discharge and disruptive failure of both VT and VT receptor The BVRP500 circuit breaker was only supplied to SPM in the UK in 1974. Deterioration of contact components have led to disruptive failure (Two SPM SOPs applied) and this type has also experienced mechanism problems that caused slow closing. Spares and support are no longer available.

Johnson & Phillips NX RMU SPD Volume 24 [ED2 Plan 6] SPM Volume 301 [ED2 Plan 117]

Most of the J&P NX RMUs are installed on the SPM network – usually in X-type configuration. These units were introduced to the SPD & SPM networks in 1960 and continued for ~20 years. This design is very vulnerable to failure from rainwater ingress as there is no protection for oil switch tank breather under test access lids. No manufacturer support or spares from either J&P or Baldwin and Francis is available.

Reyrolle C5/6/7 Range SPD Volume 611 [ED2 Plan 84] SPM Volume N/A [ED2 Plan N/A]

Reyrolle C was installed in the 1950s and 1960s in both primary and secondary substations and was superseded by the vertically isolated LMT variants in the 1960s. The oldest Reyrolle C type units will be around 75 years old at the end of the ED2 period without intervention. Suffers from frequent failure of the shutter mechanism to close properly and exposing live spouts to the operator. Regular mechanism "failure to latch" is experienced when (manually) charging the spring mechanism. Both feeder and busbar spouts are earthed through extension earthing attachments which expose the operator to risk in application and operation as well as hidden damage to the fixed contacts. As the extension equipment is inserted any minor misalignment can damage fixed contacts and it is not possible to check/adjust.

Reyrolle LMI RMU SPD Volume N/A [ED2 Plan N/A] SPM Volume 330 [ED2 Plan 46]

TBA

The LMI is a Reyrolle OCB equipped RMU which has suffered repeated disruptive failures due to moisture ingress and cable box failures. A SPEN raised SOP (406) prohibiting live operation was raised in 2017 due to mechanism failure.

Cubicle Substations

A legacy substation design in the SPD licence area is the cubicle-style secondary substation. This consists of a brick-built enclosure with 4 rooms which housed 2 transformers, LV oil circuit breakers, LV Skeltag open board, and HV circuit breakers or links. In DPCR5, HV switchgear was targeted for replacement in this type of substation and one of the transformers was removed, leaving a legacy open LV board, dis-used LV circuit breakers and poor condition civil structures. There may also remaining HV switchgear including exposed HV links. One of the key ED2 strategies is to remove this legacy design completely from the network due to the associated risks. This will involve:

• Identification of all remaining sites

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Switchgear Make/Type & Volumes

Example Issues

• Removal of newer HV switchgear for re-use

• Removal of open HV links

• Transformer, LV board and circuit breaker

removal

• Installation of new GRP enclosure with new

unit substation (Transformer, RMU and LV

cabinet)

• Possible land buying for relocation.

South Wales Switchgear C4X/C8X/C4X1 Range SPD Volume 283 [ED2 Plan 33] SPM Volume 613 [ED2 Plan 17]

This OCB range is present in high volumes on the SPD and SPM primary and secondary networks with approx. 1500 variants in service in Secondary substations. The type has experienced failures to trip, to close and bushing/spout and busbar failures.

Johnson and Phillips PDB/PDB-M/JPBF SPD Volume 10 [ED2 Plan 3] SPM Volume 94 [ED2 Plan 94]

Johnson & Philips PDB and PDB-M (SPM variant) circuit breakers are an early 1950s design of indoor OCB installed in multi-panel switchboards and in secondary substation RMUs. Early versions fitted with a direct manual mechanism i.e. the movement of the contacts is directly dependent upon the effort of the operator. Early versions (type TDB OCB) were also unpotted (i.e. no arc control device was fitted) and were rated at 150MVA. All these OCBs where rebuilt between 1976 and 1985 to a 250MVA specification with independent manual mechanisms meaning that the speed of the contacts on closing and opening is spring powered and independent of the operator effort. The circuit breaker units were “redated” following the Baldwin and Francis modifications but fundamentally these circuit breakers date from the 1950s and therefore many will be over 70 years old by the end of RIIO-ED2.

Long & Crawford T4GF3, T3GF3 RMU, GF3F SPD Volume 5,795 [ED2 Plan 493] SPM Volume 619 [ED2 Plan 56]

The L&C T4GF3 and the T3GF3 Ring Main Units are the most populous oil filled RMU on the network with a total of 6422 currently in commission. They were commissioned between 1969 and 1996 and a significant proportion were installed outdoors with little or no weather protection. As a result, a relatively high number are suffering from corrosion, moisture ingress and weakening of internal components. Around 40 DIN notices have been posted ranging from internal weld failures and flashovers, cable box failures and oil leakage.

Long & Crawford J3 SPD Volume 802 [ED2 Plan 148] SPM Volume N/A [ED2 Plan N/A]

The L&C J3 oil switch is an extensible unit which is coupled to adjacent partner units using a band jointed busbar section. The majority of the reported 36 DINs were associated with moisture ingress and subsequent catastrophic failure of a band joint. A significant number of other failures were associated with internal oil switch disruptive failures with ejected burning oil. The L&C J3 units were installed on the SPD network between 1972 and ~1990.

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Switchgear Make/Type & Volumes

Example Issues

South Wales Switchgear RMN4 RMU SPD Volume N/A [ED2 Plan N/A] SPM Volume 259 [ED2 Plan 54]

The RMN4 Ring Main Unit was installed on the SPM network between 1962 and 1977. It consists of two oil switches and a SWS circuit breaker, often in the SPM “X-type” configuration. Severe disruptive failures have occurred due to insulation failures and associated tank breaches which have occasionally resulted in serious building damage.

South Wales Switchgear IF4X oil switch SPD Volume 86 [ED2 Plan 31] SPM Volume N/A [ED2 Plan N/A]

The IF4X oil switch, typically used in conjunction with C4X oil circuit breakers in secondary substations, was installed in the SPD network between 1963 until the late 1980s. This type has been affected by several manufacturing and operational issues including;

• Defective operation mechanisms sometimes

involving false status indication.

• Permali drive bar insulation failures

• Undetected oil migration leading to flashovers.

7 Suspensions of Operational Practice and 13 Dangerous Incident Notifications have been issued by UK DNOs.

The remaining asset types which make up the ED2 plan but have lower volumes include:

Table 4.8. HV Secondary Switchgear Asset Interventions

Manufacturer Type RIIO-ED2 Plan Replacement Volume

Schneider Ringmaster 2 & RN2C 6

Reyrolle ROK & ROKSS 19

AEI/Metropolitan Vickers/Ferguson-Palin IB4 15

Reyrolle IM23/X1/JO & IMS/X2/JO 41

South Wales Switchgear CRT 4 93

HV Transformers Type Issues & Summary

This section covers secondary transformers, which transform the voltage from HV (11kv or 6.6kV) down to LV (415V).

For HV transformers in the SPM licence, both asset replacement and asset refurbishment have been considered, whilst in SPD only asset replacement is considered for this asset category. It is worth noting that for some transformer replacements in RIIO-ED2, an entire new substation will need to be built on a new site which is a much larger intervention than simple asset replacement.

The HV transformer ED2 plan was not built based on asset type, but on different assessment criteria to identify which candidates should be targeted for intervention in ED2. These criteria are discussed in Table 4.9 below.

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Table 4.9. Secondary Transformer Replacement Intervention [Engineering Justification Paper ED2-NLR(A)-SPEN-001-SWGTX-EJP]

Transformer Assessment

Transformer Condition Issues

Details Comment

Underground / Buried Transformers

A major risk identified is the quantity of buried or underground HV transformers, significantly in SPD, with 82 known buried transformers here whilst SPM has none. All these transformers are approaching end-of-life due to their age. Their location is also a risk, as many are located under busy streets or in residential areas. The condition of these assets is extremely poor due to their buried installation and direct contact with moisture-retaining soil/earth for many years, however it is impractical to gather condition data on these assets without full intervention

These transformers will need to be removed from underground, and a new substation installed at a new site with above ground transformer and switchgear. Unit cost for this is much greater than for a standard CV7 asset replacement.

Pre-1962 Transformers

Transformers installed on the network before 1962 have been identified as high loss transformers, due to their steel core which pulses and heats even without load flowing through – these are known as iron losses. Modern transformers have much lower iron losses than pre-1962 transformers. The advanced age of these assets also results in poor condition as they are approaching end-of-life.

High loss transformers are not considered under this annex as they are included under the Losses annex (Annex 4A.8), however they are worth highlighting as many poor condition transformers are replaced under this reasoning.

High acidity and poor condition transformers

The remainder of transformers which are identified for replacement are found by comparing the condition, risk, and acidity readings of each asset. High acidity readings imply that oil oxidisation and sludging has been occurring – usually associated with high historical load levels - and this can ultimately lead to failure. Other condition factors such as external corrosion and tank leaks generally indicate that the transformer is at or beyond end-of-life.

Some poor condition and high acidity transformers are identified for refurbishment rather than replacement. This is on a case-by-case basis, after weighing up the costs and benefits of each intervention type.

LV Switchgear at Substation Type Issues & Summary

This asset category includes all LV switchgear located at secondary substation sites in both SPD and SPM licence areas. This includes LV Boards (wall mounted) and X-Type boards, LV pillars (indoor and outdoor) and LV Circuit Breakers.

LV Circuit Breakers are installed directly onto X-Type boards, and so if an X-Type board has been identified for replacement the circuit breaker will be replaced as a secondary action.

The factors which determine whether an LV board or pillar will be replaced are given in Table 4.10.

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Table 4.10. Substation LV Pillar Replacement Intervention [Engineering Justification Paper ED2-NLR(A)-SPEN-001-SWGTX-EJP]

LV Switchgear assessment

Photo Issues Comment

Directly coupled to transformer (SPD only)

[ED2 Plan SPD - 301]

Some metal-clad outdoor LV Pillars are directly coupled to the HV transformer in the substation. If the transformer has been identified for replacement for one of the reasons given in Table 7, then the pillar will also be replaced as a secondary action.

Generally, LV pillars which are coupled to transformers are of the same age and condition as the transformer, so it’s unlikely a good condition pillar would be replaced through this assessment.

Fibreglass pillars

Similar to the metal clad fuse pillars above a directly coupled fibreglass enclosure has been used to protect the LV equipment. Many of these fibreglass enclosures are significantly degraded and suffering from cracking and surface fractures causing safety and performance risks.

LV Street Furniture Issues & Intervention Drivers

Table 4.11. LV Pillar & Link Box Replacement Intervention [Engineering Justification Paper ED2-NLR(A)-SPEN-001-SWG-EJP]

LV Street Furniture Assessment

Photo Issues Comment

Single phase link boxes

SPD – N/A [SPM total volume – 125]

N/A

A specific SPM legacy asset which is often found in poor condition. Safety concerns over lack of phase barriers, use of non-standard links, condition of bell covers.

Cannot be removed without customer outages due to lack of back-feed on single phase concentric mains. Solution is to bolt covers onto link box, backfill pit and cover with flag stone to create a breech joint.

Poor Condition Pillars and Link Boxes, (including ”Glasgow solid” type street pillars)

[ED2 Plan SPD – 2052] [ED2 Plan SPM – 1985]

Street pillars, particularly when degraded or distressed present a particular hazard to the public and ED2 intervention seeks to remove these pillars and replace with the equivalent link box. Older, poor condition link boxes which have operational and safety concerns will also be targeted for replacement.

The “Glasgow Solid” pillar is a cast iron legacy pillar from Glasgow Corporation Electricity Department which has a unique configuration that presents several operational risks. The connection between the circuit and the pillar busbars is achieved by the insertion of a brass “washer” which has high operational risk.

Transition to SF6-Free Switchgear

As part of our Environmental Action Plan (Annex 4C.3), we have forecast that during RIIO-ED2 we will transition from installing SF6-Filled assets to using SF6-Free alternatives. Whilst the technology is not currently fully ready, we have estimated unit costs based on SF6-Filled asset costs and discussions with internal and external stakeholders. Our forecast transition profiles are based on current technology readiness levels, and are shown in Table 4.12 and Table 4.13. Unit costs are given in relevant EJPs. Furthermore, we are experiencing increasing levels of SF6 leakage in legacy units installed between 1984 and 2000 and 100 of these high leakage units will be retrofitted with gas-free equivalents as detailed in Table 4.6 above and in EJP ED2-NLR(A)-SPEN-004-SWG-EJP.

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Table 4.12. SPD SF6 Transition Profiles

SPD Units 2024 2025 2026 2027 2028 Total

6.6/11kV CB (GM) Secondary 39 47 36 7 0 129

6.6/11kV CB (GM) Secondary SF6 Free 0 0 0 53 61 114

6.6/11kV Switch (GM) 56 40 64 26 0 186

6.6/11kV Switch (GM) “C” Free 0 0 0 63 106 169

6.6/11kV RMU 155 6 0 0 0 161

6.6/11kV RMU SF6 Free 0 141 88 37 20 286

6.6/11kV X-type RMU 0 0 0 0 0 0

6.6/11kV X-type RMU SF6 Free 0 0 0 0 0 0

33kV CB (Gas Insulated Busbars) (ID) (GM) 26 23 20 0 0 69

33kV CB (Gas Insulated Busbars) (ID) (GM) SF6 Free 0 0 0 12 3 15

33kV RMU 0 0 0 0 0 0

33kV RMU SF6 Free 0 0 0 0 0 0

33kV OD 0 0 0 0 0 0

33kV OD SF6 Free 0 0 0 8 17 25

Table 4.13. SPM SF6 Transition Profiles

SPM Units 2024 2025 2026 2027 2028 Total

6.6/11kV CB (GM) Secondary 51 0 4 15 20 90

6.6/11kV CB (GM) Secondary SF6 Free 0 0 0 0 44 44

6.6/11kV Switch (GM) 0 0 0 0 0 0

6.6/11kV Switch (GM) SF6 Free 0 0 0 1 0 1

6.6/11kV RMU 32 65 44 0 0 141

6.6/11kV RMU SF6 Free 0 0 115 110 78 303

6.6/11kV X-type RMU 167 80 8 0 0 255

6.6/11kV X-type RMU SF6 Free 0 0 97 61 45 203

33kV CB (Gas Insulated Busbars) (ID) (GM) 6 0 0 0 0 6

33kV CB (Gas Insulated Busbars) (ID) (GM) SF6 Free 0 0 0 1 3 4

33kV RMU 2 13 4 8 0 27

33kV RMU SF6 Free 0 0 0 2 4 6

33kV OD 0 0 0 0 0 0

33kV OD SF6 Free 14 11 14 8 11 58

5. SP Manweb Company Specific Factors

Due to the unique nature of the SPM network, detailed in Annex 4A.25 SP MANWEB Company Specific Factors (CSFs), a number of assets included in this document are affected either by specific equipment type or the network configuration required within the SPM system.

The design philosophy is of high transformer utilisation (where transformers smaller than industry standard are run interconnected at lower voltages) and standard cable sizes used throughout the network. Each voltage layer provides support to the voltage layer immediately above (LV, HV, EHV and 132kV) offering a fully integrated and interconnected network. The SPM assets affected by the CSF include,

Primary Transformers (33/11/6.6kV)

Secondary X-Type network transformers

33kV OD Circuit Breakers

33kV ID Circuit Breakers

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33kV Ring Main Units

X-Type HV (11/6.6kV) Ring Main Units

X-Type HV Circuit Breakers

Link boxes

X-Type LV boards

The total Company Specific Factors adjustment value for assets detailed in this Annex is £45.20m.

6. Asset Modernisation Forecasts

The ED2 planned intervention volumes are given in the following section. This also details the related ED1 volumes with an annual comparison rate. The monetised risk forecast is shown for each asset category, comparing the risk movement if no intervention occurred in ED2 against the proposed ED2 strategy. Total costs per asset category are also provided in each section below.

EHV Switchgear (33kV)

The assessment process has resulted in the planned intervention volumes detailed in Table 6.14 and Table 6.15. The forecast monetised risk movement is shown in Figure 2 and Figure 3. Asset replacement and refurbishment are the interventions planned for this asset category, and as a result deliver a NARMs monetised risk benefit of £18.0m in SPD and £15.8m in SPM. These benefits arise from ED2 investment of 144 interventions in SPD and 167 in SPM. Due to the differences in network configuration and types of assets deployed, the total risk profile in SPD in EHV switchgear is significantly different to that in SPM. The total volume of EHV switchgear assets in SPD is 1,324 and in SPM is 2,446. The risk benefit as a result of ED2 intervention is broadly similar for both licences, however due to the difference in total asset volumes and forecast degradation rates the SPM overall asset risk continues to increase, albeit at a lower rate than without intervention.

Table 6.14. SPD EHV Switchgear Types & Volumes

EHV Switchgear Type SPD Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

33kV Circuit Breaker OD 9 25 1.125 5 +3.875

33kV Circuit Breaker ID 105 84 13.125 16.8 +3.675

33kV RMU 0 0 0 0 -

33kV Circuit Breaker Refurb 0 35 0 7 +7

Total 114 144 14.25 28.8 +14.55

Figure 2. SPD EHV Switchgear Risk Forecast

40,000,000

45,000,000

50,000,000

55,000,000

60,000,000

65,000,000

70,000,000

75,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - EHV Switchgear SPD

ED1 Interventions Only

ED1 & ED2 Interventions

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Table 6.15. SPM EHV Switchgear Types & Volumes

EHV Switchgear Type SPM Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

33kV Circuit Breaker OD 104 58 13 11.6 -1.4

33kV Circuit Breaker ID 55 10 6.875 2 -4.875

33kV RMU 105 33 13.125 2.625 -10.5

33kV Circuit Breaker Refurb 0 66 0 13.2 +13.2

Total 264 167 33 29.425 -3.575

Figure 3. SPM EHV Switchgear Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.16 below.

Table 6.16. SPD & SPM EHV Switchgear Expenditure

Licence Proposed Cost for EHV Switchgear, £m

Total Annual

SPD 17.93 3.59

SPM 22.75 4.55

Total 40.68 8.14

EHV Transformers

The assessment process has resulted in the planned intervention volumes detailed in Table 6.17 and Table 6.18. Primary transformers will be replaced with modern equivalent, Low-Loss Eco-Tier 2 design units. The forecast monetised risk movement is shown in Figure 4 and Figure 5. Asset replacement and refurbishment are the interventions planned for EHV transformers. In SPD, 132 interventions are planned in SPD with a monetised risk benefit of £52.9m, and in SPM 59 interventions result in a monetised risk benefit of £29.0m. Due to network configuration differences, standard 33/11kV transformers in SPD are typically rated 24/12MVA whereas SPM units are 7.5/10MVA. Furthermore, the network design in SPD normally requires 2 transformers at each 33/11kV site while due to the meshed network, SPM sites normally contain 1. Total volumes of EHV Transformers in SPD is 768 and in SPM is 840. This results in a higher criticality of transformer in the SPD network in comparison to the SPM network, hence the higher total risk in SPD. However, the risk benefit arising from each intervention in ED2 is similar for each licence.

Table 6.17. SPD EHV Transformer Intervention volumes

EHV Transformer Intervention SPD

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

Replacement 56 64 7 12.8 +83%

Refurbishment 75 41 9.4 8.2 -12%

Total 131 105 16.4 21 +28%

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - EHV Switchgear SPM

ED1 Interventions Only

ED1 & ED2 Interventions

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Figure 4. SPD EHV Transformers Risk Forecast Table 6.18. SPM EHV Transformer Intervention volumes

EHV Transformer Intervention SPM

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

Replacement 67 40 8.4 8 -5%

Refurbishment 56 19 7 3.8 -45%

Total 123 59 15.4 11.8 -23%

Figure 5. SPM EHV Transformers Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.19 below.

Table 6.19. SPD & SPM EHV Transformer Expenditure

Licence Proposed Cost for EHV Transformers, £m

Total Annual

SPD 29.63 5.93

SPM 15.68 3.14

Total 45.31 9.06

Primary Switchgear

Asset intervention in three modes (Replace/Retrofit/Refurbish) is planned for Primary switchgear, as detailed in Table 6.20 and Table 6.21 below. The forecast risk movement is shown in Figure 6 and Figure 7. 495 interventions in SPD will result in monetised risk benefit of £25.6m, and 524 interventions in SPM will result in £32.0m monetised risk benefit. The risk reductions achieved in both SPD and SPM are closely aligned, as similar investment is proposed. On top of this, £0.96m per licence is to be spent on retrofitting SF6-filled HV Primary circuit breakers, these interventions do not carry a risk benefit but will have a carbon reduction benefit.

140,000,000

160,000,000

180,000,000

200,000,000

220,000,000

240,000,000

260,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - EHV Transformers SPD

ED1 Interventions Only

ED1 & ED2 Interventions

100,000,000

120,000,000

140,000,000

160,000,000

180,000,000

200,000,000

220,000,000

240,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - EHV Transformers SPM

ED1 Interventions Only

ED1 & ED2 Interventions

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Table 6.20. SPD Primary Switchgear Intervention volumes

HV CB Primary Intervention SPD

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

Replacement 343 363 42.875 72.6 +29.725

Condition Retrofit (CV7) - 122 - 24.4 -

Refurbishment - 10 - 2 -

SF6 Retrofit (CV22) - 50 - 10 +10

Total 343 545 42.875 109 +39.725

Figure 6. SPD HV Primary Risk Forecast Table 6.21. SPM Primary Switchgear Intervention volumes

HV CB Primary Intervention SPM

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

Replacement 287 290 35.875 58 +22.125

Condition Retrofit (CV9) - 141 - 28.2 -

Refurbishment - 93 - 18.6 -

SF6 Retrofit (CV22) - 50 - 10 +10

Total 287 574 35.875 114.8 +32.125

Figure 7. SPM HV Primary Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.22 below.

Table 6.22. SPD & SPM Primary Switchgear Expenditure

Licence Proposed Cost for HV CBs Primary, £m

Total Annual

SPD 17.45 3.49

SPM 15.60 3.12

Total 33.05 6.61

120,000,000

140,000,000

160,000,000

180,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - HV Primary Switchgear SPD

ED1 Interventions Only

ED1 & ED2 Interventions

100,000,000

120,000,000

140,000,000

160,000,000

180,000,000

200,000,000

220,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - HV Primary Switchgear SPM

ED1 Interventions Only

ED1 & ED2 Interventions

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Secondary Switchgear

The forecast ED2 volumes are given in Table 6.23 and Table 6.24 below, with both asset replacement and asset refurbishment considered for secondary switchgear. The forecast monetised risk change is shown in Figure 8 and Figure 9. The monetised risk benefit in SPD in ED2 will be £15.1m because of 1,249 interventions, whereas in SPM the risk benefit of 1,037 interventions will be £14.1m. Once more, the differing network arrangements between SPD and SPM result in differing levels of total risk. In this case, standard SPM secondary substations are rated at 500kVA whereas SPD substations are often rated at 1000kVA. Therefore, the criticality of individual secondary plant is significantly lower in SPM than in SPD. In SPD there are 24,210 items of secondary switchgear, and only 14,917 in SPM. Investment in SPD and SPM, while commencing from different levels of total risk, deliver identical levels of risk reduction for each licence.

Table 6.23. SPD Secondary Switchgear Intervention volumes

Secondary Switchgear Type SPD

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

HV CB (GM) Secondary 562 243 70.25 48.6 -21.7

HV Switch (GM) 290 355 36.25 71 +34.8

HV RMU Replacement 1,020 447 127.5 89.4 -38.1

HV RMU Refurbishment 663 204 82.875 40.8 -42.075

HV X-Type RMU 0 0 0 0 0.0

Total 2,535 1,249 316.875 249.8 -67.1

Figure 8. SPD Secondary Switchgear Risk Forecast Table 6.24. SPM Secondary Switchgear Intervention volumes

Secondary Switchgear Type SPM

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

HV CB (GM) Secondary 138 134 17.25 26.8 +9.6

HV Switch (GM) 0 1 0 0.2 +0.2

HV RMU Replacement 528 444 66 88.8 +22.8

HV RMU Refurbishment 87 0 10.875 0 -10.9

HV X-Type RMU 1,511 458 188.875 91.6 -97.3

Total 2,264 1,037 283 207.4 -75.6

50,000,000

70,000,000

90,000,000

110,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - Secondary Switchgear SPD

ED1 Interventions Only

ED1 & ED2 Interventions

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Figure 9. SPM Secondary Switchgear Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.25 below.

Table 6.25. SPD & SPM Secondary Switchgear Expenditure

Licence Proposed Cost for HV Switchgear, £m

Total Annual

SPD 18.58 3.72

SPM 25.50 5.10

Total 44.08 8.82

HV Transformers

The ED2 proposed volumes for HV Transformers are given in Table 6.26 and Table 6.27. This includes intervention on underground or buried transformers, which have an elevated unit cost due to the scope of works to replace them. The 266 interventions in SPD will result in a risk benefit of £4.8m (note this excludes pre-1962 high-loss units which have a large ED2 investment programme under CV21 Losses), and in SPM 552 interventions provide a monetised risk benefit of £6.9m. There is a higher volume of higher rated assets in SPD, with total volume of 16,421 HV transformers in SPD and with 11,552 in SPM. As standard SPM secondary transformers are rated at 500kVA whereas SPD transformers are often rated at 1000kVA, the criticality of individual secondary transformers is significantly lower in SPM than in SPD leading to higher risk benefit per intervention in SPD.

Table 6.26. SPD HV Transformer Intervention volumes

HV Transformer Type & Intervention SPD

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

Replacement 274 187 34.25 37.4 +3.2

Refurbishment 0 0 0 0 0.0

UG Transformer 0 79 0 15.8 +15.8

Total 274 266 34.25 53.2 +19

Figure 10. SPD HV Transformers Risk Forecast

20,000,000

30,000,000

40,000,000

50,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - Secondary Switchgear SPM

ED1 Interventions Only

ED1 & ED2 Interventions

85,000,000

95,000,000

105,000,000

115,000,000

125,000,000

135,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - HV Transformers SPD

ED1 Interventions Only

ED1 & ED2 Interventions

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Table 6.27. SPM HV Transformer Intervention volumes

HV Transformer Type & Intervention SPM

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

Replacement 426 225 53.25 45 -8.3

Refurbishment 818 327 102.25 65.4 -36.9

Total 1,244 552 155.5 110.4 -45.2

Figure 11. SPM HV Transformers Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.28 below.

Table 6.28. SPD & SPM HV Transformer Expenditure

Licence Proposed Cost for HV Transformers, £m

Total Annual

SPD 6.96 1.39

SPM 4.77 0.95

Total 11.73 2.34

LV Switchgear in Substations

Table 6.29 and Table 6.30 give the proposed ED2 volumes for LV Switchgear at substation interventions. These are all asset replacement volumes. The forecast risk movement as a result of these interventions is shown in Figure 12 and Figure 13. 447 interventions in SPD in ED2 will result in a monetised risk benefit of £4.9m, whilst 630 interventions in SPM results in a risk benefit of £5.8m. In both licences, the starting total risk level is broadly similar. The ED2 investment plans deliver similar risk benefit per asset in both licences. SPM secondary substations with X-Type wall mounted boards require an LV circuit breaker to facilitate the interconnection across LV and HV networks.

Table 6.29. SPD Substation LV Switchgear Intervention

LV Switchgear Type SPD Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

LV Circuit Breaker 0 0 0 0 0

LV Board X-Type (WM) 0 0 0 0 0

LV Board (WM) 64 0 8 0 -8

LV Pillar (ID) 16 25 2 5 +3

LV Pillar (OD at substation) 320 422 40 84.4 +44.4

Total 400 447 50 89.4 +39.4

30,000,000

35,000,000

40,000,000

45,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - HV Transformers SPM

ED1 Interventions Only

ED1 & ED2 Interventions

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Figure 12. SPD LV Switchgear Risk Forecast

Table 6.30. SPM Substation LV Switchgear Intervention

LV Switchgear Type SPM Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

LV Circuit Breaker 0 85 0 17 +17

LV Board X-Type (WM) 80 89 10 17.8 +7.8

LV Board (WM) 0 10 0 2 +2.0

LV Pillar (ID) 61 370 7.625 74 +66.4

LV Pillar (OD at substation) 80 76 10 15.2 +5.2

Total 221 630 27.625 127.6 98.4

Figure 13. SPM LV Switchgear Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.31 below.

Table 6.31. SPD & SPM Substation LV Switchgear Expenditure

Licence Proposed Cost for LV Switchgear, £m

Total Annual

SPD 4.10 0.82

SPM 5.91 1.18

Total 10.0 2.0

LV Street Furniture

The proposed ED2 volumes for LV street furniture are shown in Table 6.32 and Table 6.33. Note that all link boxes and pillars intervened on in ED2 will be replaced with a link box, as all LV street pillars are to be replaced with a link box where possible. The forecast risk movement as a result of these interventions is shown in Figure 14 and Figure 15 below. The 2,052 proposed interventions in SPD will result in a monetised risk benefit of £22.7m and the 1,985 interventions in SPM will result in a risk benefit of £26.2m. The large drop in monetised risk in LV

40,000,000

50,000,000

60,000,000

70,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - LV Switchgear SPD

ED1 Interventions Only

ED1 & ED2 Interventions

30,000,000

35,000,000

40,000,000

45,000,000

50,000,000

55,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - LV Switchgear SPM

ED1 Interventions Only

ED1 & ED2 Interventions

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street furniture is demonstrative of the high volume of high-risk assets being removed from the public domain through this programme to convert above ground pillar assets to underground link boxes.

Table 6.32. SPD LV Furniture Intervention

LV Street Furniture Type SPD – DISPOSAL VOLUMES

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

LV Link Box 1,504 95 188 19 -169

LV Pillars (OD not at Substation) removed (to be replaced with a link box)

1,008 1,957 126 391.4 +265.4

Total 2,512 2,052 314 410.4 +96.4

Figure 14. SPD LV Street Furniture Risk Forecast Table 6.33. SPM LV Furniture Intervention

LV Street Furniture Type SPM - DISPOSALS

Total Volume Av per year

ED1 ED2 ED1 ED2 Delta

LV Link Box 6,092 1,978 761.5 395.6 -365.9

LV Pillar (OD not at Substation) 80 7 10 2 -8

Total 6,892 1,985 771.5 397.6 -373.9

Figure 15. SPM LV Street Furniture Risk Forecast The interventions outlined above would result in the expenditure given in Table 6.34 below.

Table 6.34. SPD & SPM LV Furniture Expenditure

Licence Proposed Cost for LV Street Furniture, £m Total Annual

SPD 14.7 2.9 SPM 14.8 3.0

Total 29.5 5.9

80,000,000

90,000,000

100,000,000

110,000,000

120,000,000

130,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - LV Street Furniture SPD

ED1 Interventions Only

ED1 & ED2 Interventions

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

90,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - LV Street Furniture SPM

ED1 Interventions Only

ED1 & ED2 Interventions

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Overall Risk Benefits from Substation Interventions

Overall, the proposed investment results in a total programme cost of £109.4m in SPD and £105.1m in SPM. This programme results in a monetised risk benefit of £143.9m in SPD and £129.8m in SPM across the 5 years of ED2. Overall risk does increase over RIIO-ED2, but the increase is significantly less than it would be without intervention with 6.9% increase in SPD (rather than 27.6%) and 15.9% increase in SPM (rather than 38.4%).

This programme reflects the optimal intervention plan, and demonstrates our approach is not too conservative or ambitious.

Figure 16. SPD Risk Forecast

Figure 17. SPM Risk Forecast Table 6.35. SPD & SPM Total Expenditure

Note: These costs include activities reported against CV7a, CV7b, CV7c, CV8, and CV9, and in the cast of high leak rate SF6 retrofits – CV22.

580,000,000

680,000,000

780,000,000

880,000,000

980,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - All Substation Assets (LV-EHV) SPD

ED1 Interventions Only

ED1 & ED2 Interventions

450,000,000

550,000,000

650,000,000

750,000,000

850,000,000

2022 2023 2024 2025 2026 2027 2028 2029

LTR

Year

ED2 Long Term Risk Forecast - All Substation Assets (LV-EHV) SPM

ED1 Interventions Only

ED1 & ED2 Interventions

Licence Proposed cost for all substation plant, £m

Total Annual

SPD 109.35 21.87

SPM 105.01 21.00

Total 214.36 42.87

Page 34: Annex 4A.10: Substations and Switchgear Strategy; EHV to LV