annex 4a.25: sp manweb company specific factors

Annex 4A.25: SP Manweb – Company Specific Factors

RIIO-ED2 Business Plan

December 2021


1

Contents

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

1.1 BPI signpost .............................................................................................................................. 4

1.2 Meeting Ofgem’s criteria for a Company Specific Factor ......................................................... 4

1.3 List of Figures ............................................................................................................................ 6

1.4 List of Tables ............................................................................................................................. 7

2. BACKGROUND AND CONTEXT OF THE INTERCONNECTED NETWORK ................................. 8

2.1 History of our Unique Network .................................................................................................. 8

2.2 Three principles of the SP Manweb interconnected network .................................................... 9

3. INTERCONNECTED NETWORK PERFORMANCE AND COSTS ................................................ 12

3.1 Overview ................................................................................................................................. 12

3.2 Higher network reliability ......................................................................................................... 13

3.3 Additional benefits of the interconnected network .................................................................. 15

3.4 Case Study 1: EV car park ...................................................................................................... 18

3.5 Case Study 2: Large Solar Photo Voltaic (PV) Connection to the EHV network .................... 19

3.6 Incremental costs of our interconnected network ................................................................... 20

4. OUR LONG TERM NETWORK STRATEGY AND INNOVATION .................................................. 27

4.1 Underpinned by customer and stakeholder engagement ....................................................... 27

4.2 The cost of whole system transition ........................................................................................ 28

4.3 Our long-term strategy to maintain benefits and reduce costs ............................................... 29

4.4 Enabled by innovation ............................................................................................................. 30

4.5 Case Study: Southport Network Transition ............................................................................. 31

4.6 Additional cost mitigating measures........................................................................................ 32

4.7 Wider industry activity and innovation ..................................................................................... 32

4.8 Future learning in LV automation ............................................................................................ 33

5. COMPANY SPECIFIC FACTOR (CSF) BUSINESS PLAN ............................................................ 35

5.1 What is the SP Manweb CSF .................................................................................................. 35

5.2 Approach to defining the CSF ................................................................................................. 35

5.3 Review and assurance ............................................................................................................ 37

5.4 Contents of this chapter .......................................................................................................... 39

5.5 Summary of M25 memo table costs ....................................................................................... 40

5.6 Load related expenditure ........................................................................................................ 41

5.7 Non-load related expenditure .................................................................................................. 48

5.8 Network operating costs .......................................................................................................... 80

6. GLOSSARY ..................................................................................................................................... 97


2

1. An introduction to this annex

The SP Manweb network is unique due to its

alternative, interconnected or ‘meshed’ design,

adopted from its outset in the late 1940s and

inherited when the electricity supply industry was

privatised.

Over half of our network – predominantly that in

urban areas across Merseyside, Cheshire, and

Wirral – is operated fully interconnected at all

voltage levels. The primary system is wholly

configured to support this interconnected operation.

Put very simply, interconnected operation means

power can flow through more than one path to reach

its destination in normal operation. By comparison,

most GB distribution networks have a traditional

‘radial’ design, in which power typically has a single route.

This unique design provides embedded benefits to

our customers, including excellent reliability in terms

of reduced interruptions, better facilitation of LCTs,

and a network that is more readily adaptable to

changing demand.

Figure 1: Customer interruptions per 100 customers

Showing average performance benefit of SP Manweb

Urban Networks for the period 2016-2020. “Urban

networks” showing underground network areas with 25%

or more X-type (fully interconnected and unit protected)

secondary substations, which supply approx. half of all

customers. Data from 2018/2019 NAFIRS QoS HV

Disaggregation Reporting Pack.

Urban areas of the SP Manweb network, which

supply nearly half of connected customers,

experience an outage due to a high-voltage network

fault approximately once every 45 years – this is

nearly twice as good as the best performing licence

area in GB. For over 92% of the faults experienced

on our 33kV network, no customer supplies are lost

due to the resilience in our network design and

interconnected operational arrangements.

Extensive engagement has shown that our

customers consider network reliability to be of

utmost importance. Therefore, it can be concluded

that the interconnected network caters better for this

key customer priority.

In the SP Manweb interconnected network areas,

customers are off supply for nearly 22 minutes

(63%) less per year on average than customers

connected to other distribution networks. We

estimate that the value of this network performance

benefit is in the region of £12.9m per annum, using

the socialised cost of supply interruptions from the

Ofgem cost benefit analysis methodology.

The interconnected design is more scalable than an

equivalent radial network, accommodating

reinforcement as and when it is required. This is

advantageous given that, whilst the overall direction

towards Net Zero is clear, there is still uncertainty

around how and when distribution networks will

need to increase capacity. Further benefits of the

interconnected network can be realised in the

connection of LCTs, distributed generators,

facilitation of flexible connections, capacity released

through intelligent network control and automation,

and reducing technical network losses. This

complements our strategy to deliver successful

Distribution System Operation (DSO).

However, these benefits are brought about by

several key legacy design and engineering

characteristics unique to our network. These

characteristics result in additional costs associated

with operating, maintaining and modernising the

network.

They are associated with greater volumes of assets,

and increased asset and network complexity

compared to a radial network. These additional

costs, all related to the unique interconnected

design, form the basis of the SP Manweb Company

Specific Factor (CSF) adjustment. They equate to

£116.8m, which is 7.0% of the RIIO-ED2 Totex plan.


3

Figure 2: SP Manweb Unique Network Cost

Adjustments (£millions)

The expenditure is distributed throughout our RIIO-

ED2 Totex plan and justified by our robust series of

Engineering Justification Papers (EJPs). This annex

identifies and collates the individual CSF

expenditure areas that are affected by SP Manweb’s unique design.

We have calculated the CSF using tried and

accepted approaches, refreshed with new

information and up-to-date assumptions. It also

takes account of Ofgem’s feedback from the RIIO-

ED1 determinations and relevant working group

meetings and against a backdrop of the changes

being seen as we transition to Net Zero. To validate

our approach, the costs and benefits associated

with our unique network have been scrutinised

through both internal and external assurance.

In RIIO-ED2, we must continue to ensure we are

providing best value for money to our customers,

whilst meeting our customers’ evolving needs in delivering Net Zero and operating a safe, reliable,

and efficient distribution network. Our plans for the

interconnected network must continue to meet this

objective.

The costs of wholly moving away from the existing

interconnected design are prohibitive financially and

logistically – in essence it would involve “re-wiring” our whole network.

We estimate this would more than double the

distribution component of the customer bill over the

next forty years, whilst eroding the embedded

benefits of the existing interconnected system.

In RIIO-ED1, supported by innovative network

developments, we have progressed ways to

minimise the additional costs associated with the

unique network where this is possible without a

significant reduction in benefits. This can be

achieved in parallel with refurbishment or

reinforcement work at ‘fringe’ areas of our fully

interconnected regions.

This ensures that we will continue to best meet our

customers’ needs at the lowest possible cost.

This annex sets out in detail how we have

calculated the CSF adjustment. It also describes the

activities we are undertaking to mitigate the

additional costs associated with the CSF in the

longer term, so we maintain the benefits it provides

customers, whilst minimising the cost to customers

in its ongoing upkeep and management.

An overview of the content of each chapter is as

follows:

Chapter 2: Background and context – this explains

what is unique about the Manweb network, a brief

history of how it came about, and a summary of the

benefits.

Chapter 3: Network performance and costs – this

chapter sets out the network performance benefits

of our unique network compared to a radial

equivalent, and also explains why this results in

higher costs.

Chapter 4: Our long-term strategy for the

interconnected network – this sets out our strategy

for development of the SP Manweb network in RIIO-

ED2 and beyond and explains the innovation that

we have undertaken to support this.

Chapter 5: CSF business plan – this sets out in

detail the additional costs that result from the unique

network as set out in the Business Plan Data Tables

(BPDTs) under the M25 Company Specific Factor

memo table. It demonstrates how we have

calculated these costs.

1,661.1

1,544.3

19.7 82.0

15.2

1,400

1,450

1,500

1,550

1,600

1,650

1,700

SPM Totex Loadrelated

investment

Non-loadrelated

investment

NetworkOperating

Costs

AdjustedTotex

withoutCSF

£M

Regulatory Expenditure Category


4

1.1 BPI signpost

Ofgem BP Guidance No Annex Page Number

5.26 See Section 1.2 for further details.

1.2 Meeting Ofgem’s criteria for a Company Specific Factor

Company Specific Factor criterion How we have met this requirement

The Regional or Company Specific Factor

in question is clearly defined.

Section 2.

The SP Manweb Company Specific Factor is its unique

interconnected and unit protected design.

The fundamental design has wide-reaching impacts on the

volumes, cost and complexity of multiple assets and operational

practices that are not shared with any other DNOs. Almost

every area of the network is different to an equivalent radial

system.

Is the cost impact of the Company

Specific Factor material in nature?

Material cost impact will be more than

0.5% of a DNO’s gross unnormalised total expenditure. DNOs should use this ‘soft’ materiality threshold as a guide when

submitting a Company Specific Factor.

Section 5.5

The SP Manweb Company Specific Factor represents 7.0% of

the RIIO-ED2 Totex plan.

DNOs should clearly explain the rationale

for how they have grouped costs together.

Unrelated cost categories should not be

grouped together simply to exceed the

materiality threshold.

Section 5

All additional costs are directly related to the unique engineering

design and operation of the unit-protected, interconnected

network as compared to an equivalent network of radial design.

Is the Company Specific Factor unique in

nature?

The Company Specific Factor should be

limited to a single DNO or a small number

of DNOs. Only claims that reflect a

material asymmetry between DNOs are

justified.

Sections 2 and 3

The SPM is unique in that it operates in meshed ‘groups’ rather than radial spurs from the top downwards. The primary network

is unique in this regard, it is fully interconnected to support

interconnection at lower levels.

In the LV system, there are similarities to the London Power

Networks (LPN) region, which has a number of areas of LV

interconnection. LPN does not have the same unit protection

system at LV as Manweb, which is described in Section 2.2.-

Three principles of the SP Manweb interconnected network.

Nevertheless, we have drawn comparisons to the LPN network

throughout this document where applicable. In particular, within

the reliability comparison (Chapter3 – Interconnected Network

Performance and Costs ) and in our consideration of innovation

(Section 4.7 – Wider industry activity and innovation).


5

Is the Company Specific Factor outside

the control of an efficient company?

DNOs should demonstrate that, where

possible, they have mitigated the

additional costs associated with the

Company Specific Factor.

Section 2.

The engineering design has been unique since its conception in

the late 1940s and was inherited. The design is integral to the

operation and hence the correct functioning of the network. This

is detailed in Chapter 2 – Background and Context.

However, there are ways we can try to control or limit the costs

to our customers, where it is in their best interests (i.e. where it

doesn’t lead to a significant reduction in performance). We

outline how we seek to make cost improvements in Chapter 4 –

Our Long Term Network Strategy and Innovation.

Throughout Chapter 5, we have discussed measures taken

directly to reduce the additional costs associated with the

interconnected network CSF, and any wider cost mitigation

activities we are undertaking as business as usual in the

creation of an overall, efficient business plan that are of

relevance to the interconnected network CSF.

Is the cost related to the Company

Specific Factor excluded from our other

adjustments, such as Regional Factors or

as part of our approach to cost

assessment?

If the cost is accounted for by other

adjustments, we will consider whether

there is any remainder that is not, and

whether the remainder passes our

materiality test.

Section 5.5

Yes, it is excluded from other adjustments.

There must be a high evidential bar for

the acceptance of Regional and Company

Specific Factor submissions.

Section 5 (see 5.6, 5.7, and 5.8)

Company Specific Factor (CSF) Business Plan, we have

presented a detailed methodology of how the costs associated

with the Company Specific Factor are derived. We have

discussed alternative approaches where applicable, and

explained how we have made balanced assumptions.

Our approach to deriving these costs has been subject to

multiple reviews and we have sought independent assurance.

Section 3 – Interconnected Network Performance and Costs

provides a detailed summary of the key cost drivers but also the

benefits afforded by our unique interconnected and unit

protected design.

Also see Annex 7.1c for the External Assurance report

completed by S&C Electric on this Annex.


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1.3 List of Figures

Figure 1: Customer interruptions per 100 customers .............................................................................................2

Figure 2: SP Manweb Unique Network Cost Adjustments (£millions) ...................................................................3

Figure 3: System of networks for distribution of electricity .....................................................................................8

Figure 4: Industry typical and SP Manweb typical configuration ............................................................................9

Figure 5: Distance (top) and unit (bottom) protection .......................................................................................... 10

Figure 6: Customer Interruptions in GB underground networks .......................................................................... 14

Figure 7: Customer Minutes Lost in GB underground networks ......................................................................... 14

Figure 8: Customer Interruptions in EHV networks ............................................................................................. 14

Figure 9: Customer Interruptions in LV networks ................................................................................................ 14

Figure 10: Customers per fault in EHV networks ................................................................................................ 14

Figure 11: Customers per fault in LV networks ................................................................................................... 14

Figure 12: Supply at a single end of a feeder vs. supplied by both ends of a feeder leads to ‘tapered’ vs. ‘distributed’ cable loading .................................................................................................................. 16

Figure 13: Proposed EV car park at Orford Street (brown lines - LV feeders, red circles - substations) ............ 18

Figure 14: Schematic connection of Orford Street EV car park .......................................................................... 18

Figure 15: Left: Typical 33kV SP Manweb connection. Right: Equivalent 33kV radial connection. .................... 19

Figure 16: Mean Equivalent Asset Value (as used by Ofgem in ED1) of HV and EHV switchgear across all

DNOs, in £ per customer ................................................................................................................... 21

Figure 17: Volume of pilot wires per million customers, across all DNOs (from 2020 DNO asset register) ....... 21

Figure 18: Volume of primary substations per million customers, across all DNOs (from 2020 DNO asset

register) ............................................................................................................................................. 21

Figure 19: Volume of batteries per million customers, all voltage levels, across all DNOs (from 2020 DNO asset

register) ............................................................................................................................................. 21

Figure 20: Fault infeeds for an LV fault in the SP Manweb interconnected network........................................... 22

Figure 21: Fault infeeds for an LV fault in a radial network ................................................................................. 22

Figure 22: LV fault detection and clearance activities in a typical radial network ............................................... 23

Figure 23: LV fault detection and clearance activities in the SP Manweb unit protected, interconnected network

........................................................................................................................................................... 23

Figure 24: Areas of Liverpool City Centre showing extensive reinforcement and overlay that would be required

to convert to a radial design. Top shows existing network in blue and green, bottom shows

alternative transformers and cable overlay in red. ............................................................................ 28

Figure 25: Overview of our Long-Term Network Strategy for the interconnected network ................................. 29

Figure 26: Existing Southport X and Y type 6.6kV network group ...................................................................... 31

Figure 27: Transitioned Southport network to a Y type 11kV configuration with automation .............................. 31

Figure 28: Challenge and review timeline ........................................................................................................... 38

Figure 29: The number of primary transformers in SPM Manweb compared to industry average and our

calculated radial equivalent, per 100,000 customers (left) and per TWh distributed (right) ............. 53

Figure 30: System of networks for distribution of electricity (as per Figure 3) additionally showing location of

primary switchgear ............................................................................................................................ 55

Figure 31 – Mean Equivalent Asset Value (MEAV) of switchgear per 100km of EHV network .......................... 55

Figure 32: Secondary (HV) transformers in the SP Manweb network (not to scale), showing example LV

feeders and services. ........................................................................................................................ 57

Figure 34: Industry volumes of pilot wire (from V1 DNO Asset Register 2019) .................................................. 64

Figure 33: Left: Primary sites per TWh distributed, Right: Primary sites per 100,000 customers. Showing SP

Manweb compared to SP Distribution, industry average and industry median. Source: V1 asset

register. ............................................................................................................................................. 66

Figure 35: 33kV Cable Faults – RIIO-ED1 first five years showing the high anomalous values for both SPM and

SPD ................................................................................................................................................... 82


7

Figure 36: 33kV Cable Faults – RIIO-ED1 first five years showing SPM fault volumes showing Trif Joint and

Non Trif Joint related with the median/average of other UK DNOs excluding outlier SPD ............... 83

Figure 37: 33kV Cable Faults – RIIO-ED1 first five years showing SPM fault rates per km showing Trif Joint and

Non Trif Joint related with the median/average of other UK DNOs excluding outlier SPD ............... 83

Figure 38: 33kV Cable Faults during 2018 showing Trif Joint and other fault causes against ambient air

temperatures recorded ...................................................................................................................... 84

Figure 39: LV network arrangements comparing typical radial configuration with SPM’s interconnected arrangements .................................................................................................................................... 86

Figure 40: LV network faults by district area against the level of interconnection ............................................... 86

Figure 41: Typical thermovision inspection image showing 33kV ‘hotspot’ ........................................................ 88

Figure 42: X-type unit protection with HV CBs at each secondary substation .................................................... 90

Figure 43: Typical 33kV urban interconnected network (left) and typical 33kV rural interconnected network

arrangement (right) ............................................................................................................................ 93

1.4 List of Tables

Table 1: Connection scenarios for example EV scheme at Orford Street ........................................................... 19

Table 2: SP Manweb Special Case additional cost summary ............................................................................. 25

Table 3: Summary of costs attributed to the CSF by spending category ............................................................ 40

Table 4: Load related expenditure plan – top down costs ................................................................................... 41

Table 5: Non-load related expenditure plan – asset modernisation and refurbishment ...................................... 48

Table 6: Network operating costs expenditure plan ............................................................................................ 80


8

2. Background and Context of the Interconnected

Network

This chapter gives a brief history of how our unique

network came about and explains what makes it

unique.

2.1 History of our Unique Network

At the time that Manweb came into being in 1948,

the electricity distribution industry was entering a

new era of development, which resulted in the

system that we are familiar with today: as

generators got larger, distribution networks, which

originally comprised of circuits of all voltages from

LV to 132kV emanating from single, localised points

of supply, were beginning to adopt an integrated

method of distribution with a standard design

philosophy.

By the late 1950s, the newly established Central

Electricity Generating Board (CEGB) was

developing a 275kV and later the 400kV nation-wide

transmission system. This development saw most

generation connect at large, centralised power

stations to benefit from economies of scale. Power

was then transported via the transmission system to

several bulk supply points within local distribution

networks, as is the case today.

It was also a time for huge growth in supply and

demand: the amount of electricity supplied between

1950 and the early 2000s grew relatively steadily

from 50TWh to over 350TWh, except for a brief

decline in the 1980s.

In the mid-1950s, the Manweb Chief Engineer, took

his distribution network design philosophy in a

unique direction.

As the demand grew, simply increasing the lengths

and capacities of the distribution feeders left large

number of customers exposed in the event of a

network fault at the top of the feeder. Other

distribution networks overcame this by duplicating

transformers at each substation to provide

redundancy. However, Manweb opted for an

interconnected design philosophy, which instead

supplies feeders from both ends (i.e. the feeders

interconnect two or more substations into a group).

This design philosophy is based on higher

transformer utilisation, as loading is shared among

neighbouring transformers, with each voltage layer

providing support to the voltage layer immediately

above (LV, HV, EHV and 132 kV) via

interconnection. This results in a fully integrated and

meshed network, demonstrated by Figure 3.

At the time of its inception, this design philosophy

led to lower costs and excellent network

performance. As will be described in following

sections of this Annex, whilst the reliability benefits

are still enjoyed today, maintaining the

interconnected network comes with additional costs.

Figure 3: System of networks for distribution of

electricity


9

2.2 Three principles of the SP Manweb

interconnected network

The three underlying principles of the Manweb

interconnected network design were established as

follows:

2.2.1 Uniformity

Traditional, radial networks tend to radiate outwards

from bulk supply points (connected to the 132kV

system) to EHV (primary) substations, from which

HV networks radiate.

Traditional HV networks can be constructed as

‘looped’ radial circuits that return to the same

substation, or as an ‘interconnector’ to an adjacent

primary substation to provide post-fault support and

resilience. In all cases, the circuit must be run with a

split or ‘normal open point’.

Traditional LV networks, whilst having the capability

to offer interconnection in the event of faults or

outages, are also normally run radially. Historically,

LV cables are tapered as distance from the

transformer increases.

By comparison, an interconnected network

comprises a mesh of uniform circuits (more dense at

lower voltages), with each layer fed from the voltage

1 ‘Firm’ refers to the capacity rating of a substation or group of substations that can be maintained even

level above. Transformers and cables tend to be

uniform in size, such that at each voltage level there

is a standard rating for circuits and design for

switchgear, protection and relay settings. Between

each voltage level there is also a standard

transformer rating. This allows for a ‘plug-and-play’ network configuration.

2.2.2 Interconnection

Figure 4 shows a radial primary (EHV) substation in

an industry typical configuration with a firm1 capacity

of 24MVA, compared to a typical group of three

primary substations in SP Manweb, with a similar,

combined firm capacity of 20MVA.

Figure 4: Industry typical and SP Manweb typical

configuration

in abnormal/fault conditions, transformers can

operate above their ratings.

Uniformity

Similar sized components such as cables

and transformers at all voltage levels, and

uniformity of application

Interconnection

Circuits run between substations with all

switches predominately in the ‘closed’ position – like a mesh

Unit protection

Accurate fault locating by checking at

current entering and leaving ‘zones’, and fault isolation without the loss of supplies to

customers


10

In the typical radial configuration, the primary

substations supply several secondary (HV/LV)

substations along each feeder, which are not

connected in normal operation. The loading will

reduce along the feeder. (Note: only two radial

circuits are shown for simplicity, but there would be

more at full capacity.)

By contrast, in the typical SP Manweb configuration,

feeders supplying the secondary substations

(typically rated at 0.5MVA) are connected to a

primary substation and fed from both ends in normal

operation, with the ability to be fed by either end.

Just over half of the SP Manweb network is solidly

interconnected at all voltage levels – this is termed

‘X-type’. Of the remaining network, just over half again is solidly interconnected at 33kV and HV but

less so at LV – termed ‘Y-type’. The remainder, mainly in our rural areas – just under a quarter of

the whole network – is designed and operated as a

radial network with single transformers feeding a

non-interconnected HV and LV system.

2.2.3 Unit protection

Key to the operational value of the X-type network is

a concept called unit protection, which accurately

locates a fault by checking the current entering and

leaving ‘zones’. This gives the SP Manweb

interconnected network a very high reliability of

supply in terms of very low customer interruptions.

In a radial network, traditional distance protection is

typically used. Fault isolation is achieved by opening

the source circuit breaker to de-energise the whole

circuit and downstream LV circuits until the fault is

isolated and supplies restored.

To reduce the impact, radial EHV substations

normally have two transformers (one to back up the

other) and HV feeders are arranged to have

switchable back-feeds to reduce duration of

interruption. The transformers are each sized to

meet the entire load on the substation. Under

normal conditions neither unit achieves greater than

50% utilisation.

Customers will be without power until the fault is

located and either manual switching, remote

telecontrol switching or automation switching is used

to restore the non-faulted sections to service with

some customers off for repair time or alternative

supply restoration.

In the X-type network, HV/LV substations are

configured in unit protected zones. For the same

HV fault on a unit protected system, it can be

pinpointed to a specific location. The protection

system would automatically isolate the faulted

section of HV cable section and the in-zone HV/LV

transformer. Supply to the neighbouring HV/LV

substations would be unaffected, fed from the

primary transformer at either end. The occurrence of

a single fault rarely results in lost load or customer

interruptions.

Additional protection equipment and switchgear is

required on the X-type network to summate the

current on the incoming and the outgoing feeders,

and to isolate faulted sections of HV circuit as well

tripping a LV ACB on the LV board to prevent back

feeds from the surrounding interconnected LV

network.

The LV supplies downstream of the isolated HV/LV

substation would also be unaffected, fed from the

neighbouring HV/LV substations, ensuring supplies

to all customers are maintained. The resultant

network configuration is shown in Figure 5.

Figure 5: Distance (top) and unit (bottom) protection


11

Today, this design philosophy still brings significant

embedded benefits, including higher reliability,

increased asset utilisation and ability to

accommodate new connections.

However, the ongoing operational and capital

investment costs to maintain performance are

greater due to the additional plant, switchgear,

protection equipment and civils requirements the SP

Manweb network requires compared to a typical

DNO with a radial designed network.

Our strategy is to ensure that we appropriately

balance the benefits of the interconnected network

with the costs of providing them (see Chapter 4 of

this Annex).


12

3. Interconnected Network Performance and Costs

This chapter sets out the network performance

benefits of our unique network compared to a radial

equivalent and explains, at a high-level, why this

results in higher costs.

3.1 Overview

Benefits of an interconnected network include:

• Significantly lower number of interruptions to

supply through interconnection and unit

protection.

• Higher utilisation of assets and standardised

component sizes leading to a more

adaptable and scalable network, reducing

the risk of uncertainty about the future.

• Improved facilitation of customer uptake of

Low Carbon Technologies (LCTs) through

the capability of sharing loads amongst

circuits.

Extensive engagement has shown that customers

and stakeholders consider system supply standards

to be of utmost importance. Therefore, it can be

concluded that the interconnected network caters

better for this key customer priority.

As we transition towards Net Zero, and as our

customers increasingly depend upon electricity

networks to live their lives, as well as for their

heating and transport needs, these benefits will

become increasingly valuable.

With enhanced network performance and

incremental benefits in supply reliability, it is also

recognised that the costs associated with SP

Manweb’s unique network are marginally higher than the GB average.

We have also developed a long-term strategy (see

Chapter 4) that will ensure these costs are

minimised further in the longer term.


13

3.2 Higher network reliability

The SP Manweb interconnected network offers

some of the best reliability in GB in terms of lowest

number of customer interruptions, with the X-type

(unit protected) network offering the best reliability of

any network type.

Any single fault or failure on an interconnected

network will rarely result in any loss of supply, even

for a short period of time. This can be seen in

published data on Customer Interruptions (CI) and

Customers’ Minutes Lost (CML).

Overall, SP Manweb has the lowest rate of CIs in

GB except for LPN (owned by UK Power Networks),

supplying London. However, LPN is an outlier with

excellent reliability due to being a wholly

underground network, with part interconnection.

Disaggregated analysis has been undertaken to

examine the enhanced performance benefits

associated with the fully interconnected or ‘X-type’ areas of the SP Manweb network compared to wider

industry. This analysis shows that the rate of CIs on

the X-type network, which supplies just over half of

all our customers, outperforms even LPN in

performance.

3.2.1 Ensuring a like-for-like comparison

Most of the X-type network areas are underground

(UG), and these areas largely correspond to our

urban network. Therefore, in assessing network

performance we compare RIIO-ED1 performance to

date for our underground interconnected network

with the underground networks from other GB

DNOs. Underground networks outperform overhead

equivalents, (due to transient weather and air borne

debris type faults), therefore it is more appropriate,

in the context of the CSF, to compare equivalent

network types for supply reliability and security

performance.

It is also important to note we have used

disaggregated fault data that enables us to show the

respective fault performance of our X-type and Y-

type areas of our HV network to allow us to compare

our unique interconnected underground HV network

with the underground HV network of other DNOs.

As part of our review, we have considered network

size, topology and voltage in comparing network

performance and reliability.

3.2.2 Faults on the HV network

A review of CIs and CMLs caused by faults on the

HV network, which make up the majority (two thirds)

of all faults that result in customer interruptions, has

shown significantly better performance in the

network with HV interconnection.

3.2.2.1 Customer Interruptions (CIs)

Figure 6 shows the number of CIs per year is less

than half that of LPN.

However, it is important to note that the areas of the

network that are not interconnected do not perform

this well. It is important that we consider this, and

the priorities of customers in these regions, within

our longer-term strategy (see Chapter 4).

3.2.2.2 Customer Minutes Lost (CMLs)

When there is a fault on the network that results in

an interruption, it is our responsibility to make sure

we safely and securely restore the supply in the

least time possible.

SP Manweb has a higher Average Time off Supply

(ATOS), largely due to the complexity of the network

and the requirement for an enhanced voltage and

insulation test regime before restoration switching,

and partly because interruptions on the X-Type

interconnected network are generally harder to

repair i.e. they will normally consist of two faulted

pieces of equipment or apparatus.

Despite this, the X-type network also outperforms

LPN on CMLs by over 20% as shown in Figure 7.


14

Figure 6: Customer Interruptions in GB underground

networks

Figure 7: Customer Minutes Lost in GB underground

networks

3.2.3 Faults on the rest of the system

The available dataset for interruptions caused by

faults in other areas of the network during RIIO-ED1

(making up one third of all faults that result in

customer interruptions) is not as detailed: the data is

not disaggregated into network type.

Nevertheless, analysis of the overall figures shows

that SP Manweb’s performance is good when

compared to the rest of the industry for faults in the

EHV network (Figure 8), and is industry leading for

the LV network (Figure 9). The number of customers

affected per fault is the lowest in the industry owing

to the interconnected design (Figure 10 & Figure

11).

Figure 8: Customer Interruptions in EHV networks

Figure 9: Customer Interruptions in LV networks

Figure 10: Customers per fault in EHV networks

Figure 11: Customers per fault in LV networks


15

3.3 Additional benefits of the


3.3.1 An adaptable network

The SP Manweb interconnected network uses

standardised network components throughout,

generally smaller than in a radial network. Grid

transformers are generally 60MVA, primary

transformers are generally 7.5/10MVA and ground-

mounted secondary transformers are generally

0.5MVA. Compared to 90-120MVA, 20-24MVA and

1MVA units respectively, in radial networks.

Similarly, conductors do not taper along the length

of feeders and we generally only adopt two sizes for

new build equipment. This enables access to

economies of scale and efficiencies in procurement

and engineering design.

Because current in an interconnected system is

supplied from multiple source infeeds, or as a

minimum from both ends, on a balanced system, the

maximum current compared to a radially fed system

is split. Although the system is based around high

utilisation, in many instances, depending on the

comparative cable sizes, this effectively increases

tolerance to peak loads.

This uniformity of equipment and ratings, along with

the ability to operate at high utilisation factors,

provides opportunity for expansion in line with

network growth and facilitates reinforcement by the

addition of a new transformer with minimal cable

laying and no change to protection or settings.

Overloaded feeders can be resolved by installing a

new in-feed near the mid-point. In radial networks,

the introduction of new or larger substation can lead

to circuits having to be replaced or reinforced due to

the non-uniformity of the network.

Conversely, if demand falls in an area, substations

in a meshed network can be more easily

decommissioned, and their equipment used

elsewhere.

Whilst the asset volumes and network complexity

can increase the cost of network reinforcements on

a per MVA basis, smaller network reinforcements

can be implemented with shorter lead times, and

defer the need for larger, more expensive

reinforcements if more time is needed for the final

requirements to evolve. This reduces the risk of

stranded assets.

In the transition to Net Zero, there will be compound

factors at play. On the one hand, the more

adaptable interconnected network may be more

resilient in the face of future network uncertainty.

However, given the scale of the forecast increase in

demand and generation on our network, this will

result in increasing numbers of significant

reinforcements.

In an interconnected network, reinforcement comes

at a higher cost – as discussed in more detail in

Section 5.6.

3.3.2 Supporting the Distribution System

Operator transition

The adaptability of the interconnected network

supports our business in its transitioning into a

Distribution System Operator (DSO), where network

constraints caused by demand and fluctuating local

generation are managed through smarter

technologies, network automation, demand

reduction or levelling schemes, and the provision of

new services such as flexibility – where we pay

generators and consumers to change their patterns

of supply and demand.

In the near-term, uncertainty in the uptake of new,

smarter technologies and markets, maximizing

optionality in the network can be very beneficial.

Interconnected networks may have many more

options to reconfigure demand and generation

uniformly across the network. In many cases

meshed networks are more robust and capable in

accommodating changes in load patterns and

locations.

Our DSO strategy for RIIO-ED2 is to deploy all

necessary DSO infrastructure including the

centralised systems and all network / field

infrastructure, that will enable DSO functions and

activities, including Active Network Management

and flexibility services. This deployment has been

considered across both our SP Distribution and SP

Manweb licence areas, taking into consideration the

different network topologies (considering Grid

Groups for SPM and Grid Supply Points for SPD)

with prioritisation based on capacity requirements


16

from our Distribution Future Energy Scenario

(DFES) forecasts.

The application of DSO technology has a consistent

approach across both licence areas. However, for

DSO within SP Manweb, further considerations

have been made on the additional optionality that is

offered by the meshed network.

This benefit will be further enhanced in ED2 by SP

Energy Networks’ ambitious monitoring proposals,

which cover installation of:

• Innovative active fault level monitoring

across constrained locations on our HV and

EHV network to help safely accommodate

more renewable generation.

• Substation monitors to improve network

visibility.

• Widescale LV network monitoring,

combined with extensive use of smart meter

data.

This monitoring has benefits on any network, but in

particular will help to characterise the more complex

flows in an interconnected network. This will give us

the information required to expand our network

when there is a need, reducing the risk of asset

stranding.

Figure 12: Supply at a single end of a feeder vs. supplied by both ends of a feeder leads to ‘tapered’ vs.

‘distributed’ cable loading


17

3.3.3 Facilitating Low Carbon Technologies

The increase in Low Carbon Technology (LCT)

loads poses challenges to the performance and

design of both HV and LV systems due to its effects

on steady state current, steady state voltage

regulation and harmonics. LCT generation affects

net loading and influences steady state current,

steady state voltage regulation and harmonics.

It is widely recognised that an interconnected

network design has benefits when adapting to meet

new levels of LCTs, including increased demand

from domestic electric vehicles and electric heat

pumps, as well as low-carbon distributed

generation. This is due to the following advantages:

• Unit protection is more advanced than

typical radial system protection and is more

tolerant to bi-directional power flows,

meaning distributed generation can be

accommodated without too many complex

changes to protection systems.

• The parallel paths for power place less

demand on the system above, deferring

costs for network reinforcement.

• The interconnected network means there is

a wider distribution of reactive power, which

supports local voltages.

In future, against unprecedented increase in LCTs

to meet the transition to Net Zero, our distribution

network like any other requires significant

expenditure for network investment as the smaller,

more incremental headroom release solutions

become less effective. Furthermore, the cost of a

particular network intervention in interconnected

networks to release headroom is generally higher

than the cost of a similar intervention in radial

networks.

Nevertheless, the better facilitation of LCTs has

been subject to multiple independent reviews and

assessments, demonstrating that the interconnected

network continues to provide a benefit in this regard.

It also provides additional network performance

benefits to generation customers in terms of

increased security of connection, improved voltage

regulation and power quality.

For RIIO-ED1, we completed a detailed assessment

of our network using the Transform model that

showed the need for intervention in meshed

networks as a result of distributed generation is

lesser than in radial networks. An independent

analysis validated the outputs.

Independent consultants PB Power (now part of

WSP) also conducted a detailed review supporting

the view that accommodation of LCTs is facilitated

by the interconnected LV network design2. Many

DNOs are exploring the benefits that interconnection

brings to the Net Zero transition (see Section 4.7).

The benefits are more tangibly demonstrated by the

two case studies overleaf.

Case Study 1: Looks at the capacity to connect a

large EV load for a public EV charging car park; a

growing problem faced by many urban networks.

Case Study 2: Looks at the connection of a large

distributed, renewable generation.

2 2014 00363 – 001: Assessment of Special Case

for SP Manweb Operating an Interconnected

Network, PB Power, March 2014


18

3.4 Case Study 1: EV car park

As heat and transport is increasingly electrified in the move to Net Zero, the demand on GB distribution

networks is increasing. This will be particularly challenging in more built-up areas, where network reinforcement

will be more expensive and more challenging due to space limitations and access issues.

We have reviewed the interconnected, underground urban networks for sites that may see large connections

and have modelled a potential EV car park connecting to the highly interconnected LV network in the

Warrington area compared to what would be possible in the average, radial equivalent.

Figure 13 shows the possible connection point at an existing car park on Orford Street, Warrington and Figure

14 shows the simplified network schematic including interconnection of the LV feeders.

Figure 13: Proposed EV car park at Orford Street (brown lines - LV feeders, red circles - substations)

Figure 14: Schematic connection of Orford Street EV car park


19

Feasible options for the connection are shown in Table 1 – either connection between substation A and

substation B, between substation A and substation C, or connection to all three.

Table 1: Connection scenarios for example EV scheme at Orford Street

Public EV Car Park Supply

Arrangement

Connection Option Max Network Capacity

Available (kVA) Sub A Sub B Sub C

Interconnected Yes Yes Yes 350

Interconnected Yes Yes No 300

Interconnected Yes No Yes 170

Average Radial Equivalent - - - 160

Modelling the network capacities and maximum connection capacities of each case, as well as the theoretical

average radial connection, reveals that in every interconnected option for this connection the maximum supply

is greater than for a radial equivalent, on average - 23% higher.

3.5 Case Study 2: Large Solar Photo Voltaic (PV) Connection to the EHV network

This case study illustrates some of the benefits that the interconnected network brings to distributed generators

seeking a new point of connection to the distribution system. A typical example might be the connection of a

solar photovoltaic farm in north Wales, with a potential export capacity of 28MVA.

For a typical radial connection, a new, larger circuit and bus bar extension would be required to provide the

desired capacity, shown on the right of Figure 15. In this example, this would involve a 7.5km distance to the

point of connection at the 132/33kV Grid Substation, which is not uncommon. A second parallel circuit would

also be required for security, otherwise the solar farm would be constrained for faults and planned outages

(abnormal conditions).

The SP Manweb interconnected 33kV network connection is shown on the left of Figure 15. The connection is

facilitated by ‘looping in’ to a nearby interconnected 33kV circuit providing a ‘system-normal’ 28MVA export capacity, generally requiring less new cabling.

The interconnected connection offers increased security under abnormal conditions. The export capacity is

constrained to ca. 19.7 MVA by local monitoring, rather than fully constrained as in a single radial connection.

The solar farm may also benefit from slightly improved voltage regulation and power quality.

Figure 15: Left: Typical 33kV SP Manweb connection. Right: Equivalent 33kV radial connection.


20

3.6 Incremental costs of our


With enhanced network performance and

incremental benefits in supply reliability, it is also

recognised that the costs associated with SP

Manweb’s unique network are higher than the GB

average.

We have a long term strategy (see Chapter 4) that

will ensure these costs are minimised in the longer

term. Key to ensuring our customers get the best

possible value for money is ensuring we accurately

recognise where these costs come from.

The additional costs are underpinned by the three

principles of our network (uniformity, interconnection

and unit protection), which result in a handful of

related, key design and engineering characteristics.

These characteristics result in a series of related

additional asset and operational costs.

A summary of the additional costs associated with

the interconnected network is shown later in this

document in Table 2, but the key differences are as

follows.

3.6.1 Greater volumes and complexity of

assets

Predominantly, the costs associated with the

interconnected network are driven by the higher

volume of assets required compared to an

equivalent radial network. A number of these assets,

some of which are exclusive to SP Manweb’s network, also have added complexity when

compared with radial equivalents, in turn increasing

asset cost.

The notable differences are as follows:

• More primary substations and transformers.

We have more than twice the number of

primary transformers than average when

scaled by customers served, and a greater

number of substations than any DNO with

the exception of Scottish and Southern

Electricity Networks’ (SSEN) Northern Scotland network (SSEH), which operates

across the unique geography of the Scottish

Highlands and islands.

• Greater volume of and more expensive

switchgear. In traditional radial designed

networks, the circuit is controlled by the

switch or circuit breaker (CB) at the source

or infeed end of the circuit only. In

interconnected networks, where circuits are

fed from two (or more) substations, there is

additional switchgear at each end of the

individual circuits.

• Greater volume of protection and control at

primary and secondary substations. To

enact the unit protection, neighbouring

substations must be able to work together to

detect fault locations. This requires relays at

each end of the circuit, connected together

by pilot wires. The unit protection schemes

also require the use of dedicated battery

systems to operate.

• SP Manweb’s interconnected unit protection requires secure, well-heated/ventilated

buildings to remain serviceable. As a result,

SP Manweb has a larger number of brick-

built primary and secondary substations

than other DNOs with radial networks,

where open-compound and glass reinforced

plastic (GRP) style substations are more

common. These brick-built sites are

generally more expensive to install and

maintain.

These differences are demonstrated in Figure 16 to

Figure 19 overleaf. As a result, although the

interconnected network is a more adaptable network

allowing for reinforcement in smaller increments,

when reinforcement is required, this can be

considerably more expensive. Similarly, asset

management and network operating costs are much

higher in a number of areas.


21

Figure 16: Mean Equivalent Asset Value (as used

by Ofgem in ED1) of HV and EHV switchgear

across all DNOs, in £ per customer

Figure 17: Volume of pilot wires per million

customers, across all DNOs (from 2020 DNO asset

register)

Figure 18: Volume of primary substations per million

customers, across all DNOs (from 2020 DNO asset

register)

Figure 19: Volume of batteries per million

customers, all voltage levels, across all DNOs (from

2020 DNO asset register)

0

100

200

300

400

500

HV EHV

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

UG OH

0

200

400

600

800

1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

132kV EHV HV


22

3.6.3 Higher asset utilisation

The high utilisation factors offer many benefits in

terms of reduced investment costs in some areas,

however operating at higher utilisation leads to

some additional expenditure. Two key areas are as

follows:

• Link boxes. Interconnected networks

typically operate with the link boxes in their

‘closed’ position, with current flowing through the assets during normal operation.

Additionally, when a fault occurs, multiple

fault infeeds – shown in Figure 20 and

Figure 21 – impose significantly more

demanding requirements. Hence the

consequences of disruptive link box failures

in interconnected networks are far more

severe than in traditional radial networks.

• EHV cable fault rates. As above, operating

at higher utilisation factors increases the

fault level of the systems and the fault

current that flows at the time of a circuit

fault.

• Similarly, the unique interconnected

operational arrangements lead to higher

circulating Var’s (Reactive Power) in the

EHV system, which can result in higher

levels of stress on the cable compared to a

radial design, and greater carbonisation and

deterioration of insulation papers in the

cable in the vicinity of a cable fault.

Figure 20: Fault infeeds for an LV fault in the SP Manweb interconnected network.

Figure 21: Fault infeeds for an LV fault in a radial network


23

3.6.4 Increased operational costs

As well as the higher operational costs related to the

greater volumes and complexity of assets (above),

there are also additional costs associated with the

network when it is under fault conditions.

Although our network performance is generally

much more resilient to faults, the process of fixing

faults that do occur takes longer in our unique

interconnected, unit-protected network.

In the interconnected LV network, fault restoration

and fault finding requires visits to multiple locations

for testing, fuse replacement or network Link Box

linking to ensure safe network operations before re-

energisation.

This is shown in Figure 22 and Figure 23 below.

Figure 22: LV fault detection and clearance activities

in a typical radial network

0800 - First Off Supply Call(s) (staff dispatched)

0830 - staff arrive on site @ Sub A

0840 - @Sub A Fuse(s) replaced [100% customers

restored, 40 minutes off supply]

0900 - Staff finish on site

Figure 23: LV fault detection and clearance activities

in the SP Manweb unit protected, interconnected

network

0800 - First Off Supply Call(s) (staff dispatched)

0830 - Staff arrive on site at (Sub A)

0840 - @ Sub A Fuse(s) Replaced [80% customers

restored, 40 minutes off supply]

0845 - Additional Network Points to Check

0915 - @Sub B Fuse(s) Replaced [No further customers

restored as already supplied by Sub A]

0930 - @Sub C Fuse(s) Replaced [Remaining 20%

customers restored, 75 minutes off supply]

0935 - Additional Staff required to check UG LBs

1015 - Additional Staff AOS

1100 - @LB1 All live, plans correct, No Back-Feed from

LB2

1145 - @LB2 All live, plans correct, No Back feed from

LB1

1050 - Confirmed 80% customers restored @ 08:40,

100% Restored at 9:15

1215 - Staff finished on site


24

3.6.5 Costs of the Company Specific Factor

(CSF)

The RIIO-ED2 CSF is calculated to be circa

£116.8m, or £23.4m per year on average: this is

based on our forecast of planned volumes of

equipment and activities associated with

replacement, refurbishment, reinforcement and

maintenance expenditure in RIIO-ED2 (the detailed

derivation of this cost is presented in Chapter 5 of

this Annex).

This is 7.0% of the Totex value of the SP Manweb

RIIO-ED2 Business Plan3. In comparison, the cost

of the RIIO-ED1 CSF submission, combined with

the cost of the link-box reopener also specific to SP

Manweb (the equivalent of which is included in the

CSF in RIIO-ED2), is 7.5% of the whole cost of our

plan.

Our strategy (see Chapter 4 of this Annex) will

ensure that we continue to minimise this cost over

time where it is beneficial to our customers to do so,

in line with Ofgem recommendations from the RIIO-

ED1 final determinations.

3.6.6 Links to price control mechanisms

As discussed above, the SP Manweb

interconnected and unit protected network supports

greater performance in areas such as reliability,

time-to-connect and capacity utilisation.

However, as the CSF is not an area of expenditure

in its own right, there is no direct link to any Licence

Obligations (LOs), Output Delivery Incentives (ODIs)

or Price Control Deliverables (PCDs). These

mechanisms should be considered alongside the

Totex values in the relevant parts of the plan.

3 CSF adjustments have only been applied within the Load, Non-

Load, and Network Operating Costs parts of our plan – although

it is acknowledged that the complexity of SP Manweb’s unique interconnected network does influence the level of indirect and

business support costs – see Table 2.


25

Table 2: SP Manweb Special Case additional cost summary

Cost category Comments

Primary transformers Interconnected network with standardised, lower capacity ratings means additional

transformers to modernise / refurbish compared to an equivalent radial network.

EHV outdoor Circuit

Breakers (CBs)

Outdoor EHV (33kV) circuit breakers (CBs) within SP Manweb’s interconnected network are unique. They are integral to the design and operation of the unit

protection system. There is no requirement for 33kV CBs at downstream 33kV

primary substations in a radial system.

EHV indoor

switchgear: Ring Main

Units (RMUs)

Indoor 33kV RMUs within SP Manweb’s interconnected network are unique. They are integral to the design and operation of the unit protection system. There is no

requirement for 33kV RMUs at downstream 33kV primary substations in a radial

system.

Pilot Wires

Extensive use of pilot wires for communication of protection devices between

substations is unique to SP Manweb’s unit protected network. Hardex, used on 33kV overhead lines, is also an obsolete asset that was designed to be self-

supporting.

Cables and link box

utilisation

More stress is placed on this equipment compared to equivalent radial system, as a

result of higher operating current – due to higher utilisation – and higher fault

currents – due to interconnected configuration and operation.

Primary and

secondary substation

battery systems

The unit protection schemes at primary and secondary substations require the use

of dedicated battery systems to operate. The extent to which batteries are required

is unique to SP Manweb. The incremental cost has been based on the difference

between the volumes of battery replacements and the difference in costs of assets

between the interconnected network and an equivalent radial network.

Secondary HV

switchgear: X-type

RMUs

The use of X-type RMUs is unique to SP Manweb’s interconnected HV network and the incremental cost for SP Manweb has been based on the difference in cost

between an X-type RMU and a traditional HV RMU used on a typical radial network.

Secondary X-type

transformers and LV

boards

The costs associated with X-type secondary transformers and X-type LV boards,

which includes a LV air CB (ACB) as part of the unit protection scheme, are more

than for an equivalent radial system due to different switchgear and protection

requirements. The more expensive asset cost has been applied to the volumes of

assets to be modernised.

Although there are slightly more secondary transformers in the SP Manweb network

compared to an equivalent radial network, we have not included this cost to be

conservative.

EHV & HV unit

protection

maintenance

The incremental cost of maintenance of unique assets within SP Manweb’s interconnected network has been compared with SP Distribution, to estimate the

difference with an equivalent radial network operator.

Primary & secondary

X-type substation civils

SP Manweb’s unit protection requires secure, well-heated/ventilated buildings to

remain serviceable, i.e. brick-built substations. We have included the cost of

continuation of our modernisation programme for brick-built primary and secondary


26

Cost category Comments

substations. Civil costs associated with non-X-type substations, e.g. outdoor

compounds, are excluded.

Telecomms & IT

The incremental cost includes the difference in telecoms and IT O&M compared to

an equivalent radial system, due to increased numbers of substation sites

associated with SPM’s 33kV network.

Electricity System

Restoration (ESR -

Black start resilience)

A ‘black start’ is when a network has to restart from a complete blackout, which

requires particular arrangements. A programme of work is being undertaken to

improve the resilience of substation sites to black start. The incremental cost

includes the difference in black start resilience work compared to an equivalent

radial system, due to increased numbers of substation sites.

Costs not included

(Closely Associated

Indirects (CAI) and

Business Support)

There are some areas of higher cost that are not easy to quantify – such as

workforce costs, due to retention of more specialist knowledge associated with the

interconnected network, e.g. design, network analysis, project management, and

costs associated with a more difficult planning for X-type substations. These costs

are not included in the CSF submission, but the complexity of SP Manweb’s unique interconnected network, and the increased level of investment and

maintenance, influences the level of indirect and business support costs.


27

4. Our Long Term Network Strategy and Innovation

The unique SP Manweb interconnected network has

a series of operational, performance and

investment-related benefits. However, these

additional benefits have an associated cost. As

customer priorities change, and as the energy

sector continues to evolve and innovate to meet the

UK and Welsh governments’ Net Zero targets, it is

our responsibility to ensure that our network

continues to provide best value for our customers

through reliable, efficient and sustainable operation.

Key to this is our strategy for the interconnected

network.

SP Manweb’s strategy and its supporting policies are designed with feedback from Ofgem during

RIIO-ED1 and developed through ongoing customer

engagement. It is designed to ensure we take all

feasible measures to mitigate the incremental costs

of the SP Manweb network.

Throughout RIIO-ED1, we have invested

strategically in innovation, leading to the

development of new network types and better value

X-type assets. These new innovations now underpin

our long-term plans for the interconnected network.

This chapter outlines the progress made in RIIO-

ED1, and our long-term strategy for the

interconnected network.

4.1 Underpinned by customer and

stakeholder engagement

We have undertaken several stages of stakeholder

engagement. In Phase 1, between October and

December 2020, we asked 91 stakeholders their

priorities that should guide our investments. 46

stakeholders placed “Ensuring that we keep electricity supplies reliable and secure” in their top

three priorities. An overall a score of 4.63/5 was

awarded to this priority.

In Phase 2 in late 2020, we undertook more in-depth

Stakeholder Engagement on Network Performance

via an online workshop – attended by

manufacturers, energy consultants, investors and

the industry association & business community –

and an online survey – completed by energy

consultants, the industry association & business

community and manufacturers. The discussion

points comprehensively showed support and

willingness for us to invest in network performance.

In addition to the stakeholder feedback above, our

customer engagement programme resulted in the

following key findings:

• For most customers resilience of the

electricity supply is extremely important,

with an average score of 7/10 and 8.5/10 for

commercial and domestic customers

respectively.

• When considering the electrification of

transport, heat and a low carbon future, all

commercial customers increase their score

to 10/10. In contrast, domestic customers

would maintain the same score.

The full portfolio of stakeholder and customer

feedback on network performance strategy can be

found in Annex 2.1 Co-creating our plan with our

Stakeholders.

We have also presented this Company Specific

Factor proposal specifically at both the Customer

Engagement Group and at our Future System

Strategy (FSS) CEG sub-group.

No major challenges were brought forward. The

group encouraged us to consider how the

interconnected network can be utilised to support

the DSO transition. We outlined that the application

DSO for SP Energy Networks has a consistent

approach across both licence areas. However, for

DSO within SP Manweb, considerations have been

made on the additional optionality that is offered by

the meshed network (Section 3.3.2).

The group acknowledged the network was an

inherited, legacy design that required additional

investment. They accepted our view that the costs

of transitioning the network from a legacy

interconnected design to a typical radial design are

prohibitive.

Finally, we have also learnt from engagement on

specific areas of the business plan that are of

relevance to the Company Specific Factor, notably,

our discussions with HSE and their relevance to the


28

inclusion of link boxes within the Company Specific

Factor adjustment for RIIO-ED2. This is discussed

in the relevant cost area in business plan

methodology in Chapter 5.

4.2 The cost of whole system transition

We have considered the activities and costs

associated with transitioning the whole network to a

more traditional, radial configuration.

Although the costs are very difficult to quantify in

every detail, it is certain that they would be

significant.

Radial operation and removal of unit protection

would require a reconfiguring of the secondary and

LV network in the interconnected areas.

Furthermore, the entire primary system is designed

to support interconnected operation. To build in the

same level of resilience would require significant

reinforcement of this system across SP Manweb.

Full transition would require new transformers and

extensive re-laying of cable, as well as the laying of

new cable circuits, throughout the whole network

The whole SP Manweb network has an estimated

Modern Equivalent Asset Value (MEAV) of over

£8.5bn. We estimate the associated capital

expenditure would total between £5bn and £7bn,

adding over 30 pence per day on average to

customer bills when evaluated over the next forty

years.

This would more than double the typical distribution

component from RIIO-ED1 of the average annual

bill for SP Manweb customers. This does not

account for the societal cost of the loss of network

benefits associated with the interconnected system,

nor the considerable disruption to customers and

public.

Difficulties would be faced in accommodating new

equipment within existing sites, and in acquiring new

land in already congested urban areas. There would

also be a significant, negative environmental impact

associated with the required civils work and the

carbon footprints of the replacement assets.

As a whole system transition is therefore very likely

to be acceptable, we have developed a strategy that

looks for least regrets options to minimise the cost

of the interconnected network to customers in

targeted areas, whilst still providing good value for

money in terms of network benefits.

Figure 24: Areas of Liverpool City Centre showing extensive reinforcement and overlay that would be required

to convert to a radial design. Top shows existing network in blue and green, bottom shows alternative

transformers and cable overlay in red.


29

4.3 Our long-term strategy to maintain

benefits and reduce costs

Our strategy is focused on maximising the

embedded benefits that the interconnected network

provides to customers, and minimising the ongoing

costs to customers of its upkeep and ongoing

management.

Our customer engagement has reinforced our

position on maintaining the reliability of the network,

even where this comes at a slightly higher cost, with

88% of both domestic and commercial customers

saying that security of supply is very important, and

indicate a low appetite to accept any reduction in

performance.

However, we must endeavour to mitigate the

additional costs associated with the SP Manweb

interconnected network where this presents best

value for money to our customers.

Therefore, we must consider whether the

interconnected, unit protected network remains

viable in the longer term, particularly given the

availability of new innovation, the changes that the

transition to Net Zero will bring.

As discussed, the activities and costs associated

with transitioning the whole network towards a radial

configuration are prohibitive in terms of both

logistics and cost. We must therefore take a more

granular view of the opportunities to transition.

This is implemented through our newly updated

“Interconnected Network Transitioning Policy”,

which guides the way we design, operate, maintain

and modernise assets of SP Manweb’s uniquely interconnected network. Broadly, it assesses where

costs can be minimised without a significant

detriment to performance and reliability, by

transitioning the unit-protected X-type network to

non-unit protected ‘Y-type’ network in some areas.

The three key themes underpinning this are:

• Maintain: in fully X-type areas, our network

continues to provide excellent reliability.

Where there is no immediate need to

significantly reinforce the network, we will

operate efficiently but modernise only at the

end of asset life, replacing with modern

equivalent assets and retaining the full

benefits of the interconnected network when

cost-effective

Figure 25: Overview of our Long-Term Network Strategy for the interconnected network


30

• Enhance: we will innovate to improve how

we monitor, operate, manage and extend

the asset life of our interconnected network.

For X-type networks, this means telecontrol

and telemetry that allow HV automation

along the feeder, and a faster response to

faults.

• For existing mixed X-Y-type areas, we will

enhance with new, innovative differential

protection and automation, allowing for a

degree of interconnection and its benefits

whilst reducing incremental costs.

• Transition: in areas of our interconnected

network, particularly the fringes and parts

with mixed network configurations, the full

interconnected benefits are not realised.

• In these areas we will proactively transition

to a non-unit-protected and more typical

radially configured network by replacing

assets, particularly at end of life as part of

planned or customer driven investment. This

will see a transition to the use of more

standard industry assets, and enhanced

technologies as above to maximise the

supply reliability benefits as far as

practicable.

We believe this three-fold approach is in line with

Ofgem’s expectations of progress carried over from RIIO-ED1, to consider moving towards a radial

network design at the fringes of the interconnected

network and perform a cost-benefit evaluation of

allowing network performance (CI and CML) to

move towards national averages.

4.4 Enabled by innovation

To support the activities within our policy for how we

manage the SP Manweb interconnected network,

we have made considerable progress during RIIO-

ED1 on innovative schemes using both existing and

new technologies. These initiatives have furthered

our knowledge of the opportunities for, and

challenges of, the ongoing management and

transition of our interconnected network.

We are trialling innovative alternatives that deliver

similar reliability benefits but at a lower cost using

modern solutions, including the use of automation to

facilitate remote network switching and active LV

monitoring equipment to reconfigure the

interconnected LV network.

A project in the Southport area has provided the

opportunity to transition an area of network

comprising both fully meshed sections of network

(X-Type) with radial and partially interconnected HV

circuits. This case study is provided overleaf.

It has been a successful project; however, there

were technological barriers to overcome relating to

the levels and positioning of LV automation required

to match the historical level of network reliability.

As a result, when applying this method in future it is

still important to consider each scheme on its own

merits, as set out in our Interconnected Network

Transitioning Policy. We have applied this learning

to our RIIO-ED2 plans – this is covered later in the

document, in Section Error! Reference source not

found..

Similarly, we are also trialling new design solutions

which enable lower cost connections using existing

technologies. Currently, the maximum size of an

additional Y-type substation between two X-type

substations in 500kVA. This innovative approach will

enable up to 1.5MVA connections to be offered in

our interconnected network providing customers

with lower cost connection options. Proof of concept

is expected before the end of RIIO-ED1, allowing us

to apply this in RIIO-ED2. This is covered in Section

5.6.2.

We also keep abreast of industry activity that may

support our interconnected operation, and we are a

fast follower of innovation.

We are involved in an innovation project “Active Response” with UK Power Networks and partners, which looks to trial a responsive, automated

electricity network that re-configures the network in

real-time, moving available capacity to areas with

peak demand.


31

4.5 Case Study: Southport Network

Transition

The transition of a network group (in part or in full),

which has a mix of fully meshed HV/LV (X-Type)

circuits and radial (Y-Type) circuits will be driven by

other investment interventions as part of asset

condition modernisation and/or a secondary

reinforcement e.g. voltage uprating programme.

The Southport network met the transition criteria, as

it was an existing network group that operated at

6.6kV with a combination of both fully meshed and

partially interconnected circuits with approximately a

third of the group being X-type configured and the

remainder being of a mixed X- and Y- type

arrangement. Over 50% of the switchgear assets

were also at end of life (Health Index (HI) 5) and

approximately a third of the existing secondary

transformers were already dual ratio, i.e. 6.6/11kV.

Figure 26 shows the existing network arrangement

which provided the opportunity to combine the need

to uprate the network group from 6.6kV to 11kV,

thereby increasing overall capacity to accommodate

load growth and future connections, with the

modernisation plan to replace end of life switchgear

and transformer assets.

Whilst the network transition reduces future

operational, maintenance and modernisation costs,

the application of innovative technologies to

introduce automation switching points and

telecontrol capability is integral to the transition cost

benefit case.

The use of HV telecontrol and automation together

with automatic LV switching points to reconfigure

the network during fault conditions is required to

maintain supply reliability levels as close as possible

to fully meshed X-type parts of the network in

Southport. Figure 27 illustrates the network

transition proposals and introduction of automation

switching points to the HV circuits.

Outcomes and learning

The Southport transition scheme is still ongoing,

though the majority of the work is now complete.

The smart sectionalisers were critical to the LV

network switching and improvement of network

performance. These innovative products were not

ready for business as usual use on the project, and

so a new network configuration method was

designed using some of the existing technology (the

ACBs at the original X-type substations). We expect

nevertheless that this revised design will continue to

meet the requirements set out for the scheme.

However, for future network groups or HV circuits,

the options for transitioning must continue to be

considered and assessed on each scheme’s own

merits. This is because in areas of overall excellent

reliability, the modern automation may in fact reduce

the overall network performance.

We are continuing to proactively investigate

alternative technologies and learning in this area is

ongoing – see Section 4.7.

Figure 26: Existing Southport X and Y type 6.6kV

network group

Figure 27: Transitioned Southport network to a Y

type 11kV configuration with automation


32

4.6 Additional cost mitigating

measures

To maximise value from existing and future

transformer fleet, we are looking at new

refurbishment options to defer eventual replacement

and may even, in the longer term, reduce the oil

replacement frequency. Given the uniquely high

number of primary transformers in SP Manweb, this

could result in a reduction in the Company Specific

Factors in future. (Primary transformer replacement

currently contributes £4.0m to the overall ED2 cost

adjustment – see Section 5.7.1.)

Innovative oil regeneration canisters are currently

being trialled in RIIO-ED1. These units, designed

and supplied by Global Transformer Solutions, are

fitted to valves at the top and bottom of a

transformer to allow oil flow while trapping

contaminants and insulation degradation products

such as water and acids. The aim is to slow

insulation degradation, thus extending transformer

usable life.

If successful, the use of this technology will be rolled

out in RIIO-ED2 to a carefully selected number of

grid 132kV and Primary 33kV transformers. Cost

savings may be realised from the deferral of

eventual replacement of the transformers, or

potentially from avoiding a complete oil change and

a reduction in oil sampling frequency if a condition-

based oil sampling regime is implemented.

Additionally, we are also collaborating with

manufacturers to establish new 33kV RMU designs

that have a more efficient configuration and,

therefore, a reduced unit cost. Currently, due to

obsolescence, a 33kV RMU is replaced with three

indoor circuit breakers (CBs) in every case.

We are developing a solution, which at double RMU

sites uses only four or five CBs in total, depending

on the network configuration at the site. At single

RMU sites, we are also developing another

reduced-footprint solution by using a CB in

combination with two switch disconnectors. We

estimate the new design could realise a 20-25% unit

cost saving if successful. (33kV RMU replacement

4 https://www.smarternetworks.org/project/prj_395/documents -

Closedown Report May 03, 2016

currently contributes £17.6m to the overall ED2 cost

adjustment across fault level reinforcement and

asset replacement programmes – see Section

5.7.2.)

4.7 Wider industry activity and

innovation

Following work done by the industry, network

interconnection has now been recognised to support

the early uptake of low carbon technologies such as

Electric Vehicles and solar PV. Other DNOs are

therefore targeting innovation funding to achieve

interconnection, and associated benefits, in LV and

HV networks.

Several innovation projects throughout RIIO-ED1

have focused on achieving more network

interconnection. These have further exemplified the

benefits that the SP Manweb interconnected

network already has.

Like SPEN, other DNOs continue to explore

methods of interconnection using cutting-edge grid

technologies. We are leading, following and

supporting innovation within the wider industry, to

support our future strategy.

Below is a summary of innovation projects carried

out or completed within RIIO-ED1, many of them

funded through Ofgem’s Low Carbon Network Fund (LCNF), Network Innovation Allowance (NIA) or the

Network Innovation Competition (NIC) mechanisms.

4.7.1 Innovation project highlights in RIIO-ED1

so far

The LCNF project FALCON, run by Western Power

Distribution (WPD), focused on releasing capacity in

suburban and rural areas through several

techniques - one of which was to implement and

operate a meshed network at 11kV. WPD includes

the following within its conclusions4&5:

“An overall reduction in CML and CI is seen where meshed networks are applied.”

5 http://www.westernpowerinnovation.co.uk/Documentlibrary/2015/Project-

FALCON-Engineering-Mesh.aspx

https://www.smarternetworks.org/project/prj_395/documents

http://www.westernpowerinnovation.co.uk/Documentlibrary/2015/Project-FALCON-Engineering-Mesh.aspx

http://www.westernpowerinnovation.co.uk/Documentlibrary/2015/Project-FALCON-Engineering-Mesh.aspx


33

“Installation increases complexity of the network, and introduces additional equipment requiring

inspection, maintenance and testing requirements.”

“A 5% reduction in losses was estimated on this trial network, though this should not generally be

assumed to be the case. “

Electricity North West (ENWL) targeted the use of

retrofit smart devices for fuses and link boxes to

form part of their innovation strategy in their RIIO-

ED1 business plan6.

The intended use of these devices is to create

interconnected networks and provide flexibility to

reconfigure networks in real time. ENWL assigned

£1.2m to develop and deploy these devices on low

voltage feeders to trial the performance. A number

of technical issues are restricting a business as

usual deployment such as condensation,

communications and water ingress, and so an

innovation project called ‘Intelligent Network meshing switch’ has recently been carried out with a view to address these issues7.

ENWL’s LCNF project Capacity to Customers (C2C)

proposed to make efficient use of spare capacity in

existing HV circuits to facilitate the connection of

new loads and generation8. The project explored the

redesign of the network to facilitate the closure of

normally open points; feeders were interconnected,

allowing spare conductor capacity to be released to

customers (for generation projects, new loads),

without compromising levels of security of supply.

ENWL includes the following within its conclusions9:

“On average, interconnected C2C operation (with closed HV rings) releases more demand and DG

capacity when compared to radial C2C operation

(with radial HV feeders).”

The ENWL Smart Street project explored five trials,

two of which looked at LV and HV interconnection.

ENWL provide the following within its conclusions10:-

“Analysis showed that the use of interconnection

particularly can have a positive effect on the majority

6 http://cdn2.enwl.co.uk/ENW_WJBP-PDF-Annexes-New.pdf

7 https://www.smarternetworks.org/project/enwl023

8 http://www.enwl.co.uk/docs/c2c-key-documents/c2c-submission-to-low-

carbon-networks-fund.pdf?sfvrsn=6

9 https://www.smarternetworks.org/project/enwlt203/documents -

Closedown Report Apr 14, 2015

of power quality metrics. There can be a negative

effect on fault level, but it is not shown to increase

beyond design levels – this should be monitored as

the demand and generation change on the network.”

“The LV network is more robust than previously thought. The monitoring and analysis has shown

that headroom does already exist to cater for the

adoption of some LCTs but as this adoption

increases, the use of voltage control and

interconnection can provide even more headroom,

thereby reducing the need for reinforcement.”

“Smart Street can deliver up to 15% reduction in losses depending on the network type, amount of

generation and levels of demand. The use of on-

load tap changers and interconnection provide the

greatest benefit for losses.”

The LCNF project Flexible Urban Networks - Low

Voltage (FUN-LV), led by UK Power Networks

(UKPN), looked at how to defer reinforcement of the

network by conventional means, particularly at LV.

It explored the use of power electronics (smart

devices) to make power distribution across low

voltage networks more efficient. The power

electronics can create ‘soft’ normally-open points

(e.g. points that can be opened and closed to

reconfigure the network) to provide load sharing

between substations. UKPN state the following

within their conclusions11:-

“Each of the three FUN-LV methods was proven

successful in sharing capacity between

neighbouring substations. … The project was

successful in proving first-of-kind technologies and

advancing tools available to DNOs in facilitating

solutions to a changing LV network.“

4.8 Future learning in LV automation

SP Energy Networks are partnering with UK Power

Networks in a multi-million innovation project, Active

10 https://www.smarternetworks.org/project/enwt205/documents -

Closedown Report Aug 09, 2018

11 https://www.smarternetworks.org/project/ukpnt204/documents -

Closedown Report May 09, 2017

http://cdn2.enwl.co.uk/ENW_WJBP-PDF-Annexes-New.pdf

https://www.smarternetworks.org/project/enwl023

http://www.enwl.co.uk/docs/c2c-key-documents/c2c-submission-to-low-carbon-networks-fund.pdf?sfvrsn=6

http://www.enwl.co.uk/docs/c2c-key-documents/c2c-submission-to-low-carbon-networks-fund.pdf?sfvrsn=6

https://www.smarternetworks.org/project/enwlt203/documents

https://www.smarternetworks.org/project/enwt205/documents

https://www.smarternetworks.org/project/ukpnt204/documents


34

Response12, which continued from the FUN-LV

project.

This project is trialling a responsive, automated

electricity network that re-configures in real-time,

moving spare capacity to areas of peak demand.

The project predicts customer savings of £271

million and reduction of 448,000 tonnes of carbon

emissions by 2030.

The overarching aim of the project is to explore the

use of power electronics (smart devices) to enable

the deferment of reinforcement and facilitate the

connection of low carbon technologies and

distributed generation in urban areas, by meshing

existing networks, which are not meshed, and by

breaking down boundaries within existing meshed

networks.

The outcomes of this project will complement our

own work on network automation and controllable

network points, to support the possible transition of

substations from X-type to Y-type without reducing

operational benefits and network reliability.

We will continue to share our own learning and

support the wider industry in its development of

approach to interconnection. We commit to being a

leader and fast follower of innovation, and will

actively seek to adopt new approaches that will

support or improve our future transition strategy.

12 https://innovation.ukpowernetworks.co.uk/projects/active-

response/

https://innovation.ukpowernetworks.co.uk/projects/active-response/

https://innovation.ukpowernetworks.co.uk/projects/active-response/


35

5. Company Specific Factor (CSF) Business Plan

This chapter sets out in detail the incremental

funding we’re asking for as part of the unique

Manweb Interconnected Network CSF, and how we

have calculated the adjustment, based on tried and

accepted approaches, refreshed with new

information and up-to-date assumptions.

5.1 What is the SP Manweb CSF

The SP Manweb Interconnected Network Company

Specific Factor is the adjustment to our business

plan accounting for the additional costs of our

unique network. They equate to £116.8m, which is

7.0% of SP Manweb’s RIIO-ED2 Totex plan, and

11% of the total Load, Non-Load and Network

Operating Costs areas of this plan.

The expenditure is distributed throughout plan and

the Totex is justified by our robust series of

Engineering Justification Papers (EJPs). The

relevant EJPs are referenced throughout the

remainder of this section.

This section identifies and collates the individual

expenditure areas that are affected by SP Manweb’s unique design.

The cost adjustments against the Company Specific

Factor for ED2, as well as the actual and remaining

forecast cost adjustments in ED1, will be reported in

the M25 Company Specific Factor memo table.

5.2 Approach to defining the CSF

Ofgem recognised the higher costs associated with

our interconnected network at both DPCR5 and

RIIO-ED1. Similarly an adjustment at RIIO-ED2 is

equally appropriate based on our overall investment

proposal.

Broadly, our approach is to identify the additional

assets and activities required for the inherited

interconnected network compared to a radial

equivalent. We have compared SP Manweb to our

other licence area, SP Distribution, as both networks

are on the whole managed and operated against the

same asset management policies. We have also

compared our costs to other GB DNOs.

Whilst the approach is consistent with the

submission made for ED1, we have reviewed all

aspects of our unique interconnected network

against a backdrop of change in the demands of the

network and the expectations of customers as we

transition to Net Zero.

We know from reviewing our ED2 CSF against the

new CSF regulatory definition that our ED1 CSF

was understated as it did not include all of the

activity additional costs that result from the

interconnected and unit protected network. These

are detailed in this chapter of the annex and

similarly we have removed some CSF costs

submitted in ED1 that are no longer applicable due

to factors that have changed, and we have

explained these within the new ED2 memo table

M25 for CSF.

Our methods are supported by independent external

review by PB Power (now part of WSP) and Mott

MacDonald, who conducted parallel bottom-up and

top down analyses, respectively. This approach was

accepted by Ofgem, and its independent

consultants, as part of RIIO-ED1 business case

submission.

We have netted-off areas where SP Manweb enjoys

a cost advantage from operating an interconnected

network relative to a radial design. For example, in

estimating the costs of greater levels of replacement

activity for substations and related equipment, we

have taken into account the lower unit costs of some

equipment.

The unique costs for SP Manweb interconnection

are based on a robust and objective cost estimate.

There are some areas of higher cost that we cannot

easily quantify – such as workforce costs due to

retention of more specialist knowledge associated

with the interconnected network, and costs

associated with a more difficult planning consent

process for X-type substations. These have not

been included into the additional costs for RIIO-

ED2.

In order to estimate our special case adjustment, we

have considered the actual costs of the SP Manweb

interconnected network with those of a notional SP

Manweb radial network.


36

In deriving notional costs of the notional SP Manweb

radial network, we have used a combination of

engineering theory and comparisons with average

asset volumes across all DNOs using the V1 Asset

Register and the Mean Equivalent Asset Value

(MEAV) tables, taking into account both differences

in activity levels as well as unit costs, to ensure our

comparisons are fair and proportionate.

Where there is insufficient data at the level of detail

required for comparison, we have calculated the

extra costs of operating the SP Manweb

interconnected network based on comparison with

elements of SP Distribution’s network costs. We

consider SP Distribution provides a reasonable

basis for estimating SP Manweb costs as if it were a

radial network for the following reasons:

• SP Manweb and SP Distribution have a

similar demographic; many customers are

based in urban networks with SP

Distribution’s Glasgow and Edinburgh being

similar to SP Manweb’s Liverpool and

Chester cities in Merseyside and Cheshire.

• Both SP Manweb and SP Distribution have

extensive west coast and rural networks

areas constructed at 11kV in traditional rural

network design.

• SP Manweb and SP Distribution share the

same asset management, and operational

policies, and in general have similar unit

costs.

We have sourced the costs of the net additional

assets employed (greater number of substations,

switchgear etc.) and activities undertaken from our

Unit Cost Manual Annex 5A.5, which is the basis for

costing our investment plan.

The approach to our RIIO-ED2 CSF incorporates

the feedback from Ofgem on our RIIO-ED1 CSF in

each detailed cost area, and the feedback from

stakeholders on our overall business plan proposal

(as summarised in Section 4.1) in that we have

ensured network reliability remains a priority.

It also reflects the changes since RIIO-ED1 and the

assumptions in looking beyond in RIIO-ED2. Some

key assumptions used in RIIO-ED2 are:

• The number of primary sites in SP Manweb

are more than twice the volume than would

be found in an equivalent, radial network

(Section 5.7.8.1).

• The number of Primary transformers in SP

Manweb are 60% higher than would be

found in an equivalent, radial network

(Section 5.7.1).

• The cost to reinforce the network due to

load growth is higher than for an equivalent,

radial network: 39.3% more at EHV, 47.2%

more at 11kV and 23.2% more at secondary

(Section 5.6).

• Radial equivalent has 25% of the length of

pilot wire than an interconnected network.

• The length of pilot wire in SP Manweb is

four times the length that would be found in

an equivalent, radial network (Section

5.7.7.1).

All assumptions, and how these have differed from

RIIO-ED1, are included in the detailed methodology

sections later in this chapter (see Section 5.6

onwards).

A notable exclusion from the CSF submission is

Closely Associated Indirects (CAIs) and Business

Support costs. These costs arise due to indirect

activities associated with the interconnected being

more complex and time consuming than for a radial

network, for example project management,

engineering design, network analysis, and more

convoluted land and planning arrangements.

Whilst these have been acknowledged in all

previous submissions, including in DPCR5 and

RIIO-ED1, they have not been included in previous

CSF adjustments. As such, they have not been

included in this CSF valuation. However, it is

recognised that these costs are material and at least

proportional to the incremental direct costs, as such

they should be considered in the overall assessment

of the SPM CSF submission.

The CSF adjustment is directly linked to the

expenditure plans for RIIO-ED2, which are justified

in the EJPs (Annex 4A.23) and presented in

Business Plan Data Tables (BPDTs). Uncertainty,

and mitigation of deliverability risk, is dealt with in

the EJPs. Reduced or increased direct Totex will be

reflected in the CSF adjustment in the M25 memo

table.


37

Key challenges in RIIO-ED2 to maintain the SP

Manweb urban networks have remained broadly the

same as in RIIO-ED1. These include:

• Ongoing maintenance of substation

environment to provide a safe, watertight

environment for X-type substations, this will

not only ensure safe operation of primary

equipment but will safeguard the integrity of

the associated unit protection equipment.

• Ongoing maintenance and repair of the

11kV and 33kV network communications

system (pilot wires), without which the

integrity of the associated unit protection

systems will fall into disrepair, with

significant deterioration in performance of

the protection systems and consequential

decrease in customer performance and

supply reliability.

• Maintenance and inspection of LV link

Boxes (including confirming network

configuration of the internal switching

points) utilised in the operation and control

of LV interconnected network.

• Ongoing maintenance of 33 kV RMUs and

circuit breakers used extensively on X-type

interconnected 33kV networks, unique at

downstream primary sites, and replacement

of 33kV RMUs due to asset condition and

fault level constraints.

• Ongoing maintenance of secondary

substation battery systems associated with

X-type networks – simple Y-type secondary

substations are generally battery free.

5.2.1 Deriving Unit Costs

The Company Specific Factor adjustments are

underpinned by our RIIO-ED2 Unit Cost Manual

(UCM) Annex 5A.5, as is the whole investment plan.

The UCM has been created using a meticulous

bottom-up approach to maximise accuracy.

In producing the UCM, we have analysed SPEN’s historical values, accounted for latest framework

13 Appendix A of our ED1 CSF annex:

https://www.spenergynetworks.co.uk/userfiles/file/201403_SPEN

_ManwebCompSpecificFactors_AJ.pdf

values, and compared unit costs to industry outturn

values – embedding efficiency wherever possible.

The UCM has been developed with Procurement

and reviewed throughout the development process

by subject matter experts.

5.3 Review and assurance

SP Energy Networks is continually aware of the

need to review and evaluate this position to ensure

it remains viable to retain the ‘X type’ network, and to consider alternative network designs and

solutions.

This ensures our customers continue to receive best

value for money, as well as a safe, sustainable and

reliable supply of electricity.

Of note, were the two independent consultant

reports carried out in 2014 to support the RIIO-ED1

CSF adjustment. These reports undertook in-depth

engineering analysis to give us a firm foundation

upon which to estimate the costs associated with

the interconnected network.

• PB Power (PB) (now part of WSP) reviewed

our strategy for managing and developing

the SP Manweb network, and the

associated incremental costs and benefits.

They reviewed detailed, asset-based

comparisons of the interconnected network

versus an equivalent, radial topology13.

• Mott MacDonald (MM) undertook theoretical

modelling of the development of the

interconnected network and compared this

to a radial design14.

The work done in the run up to RIIO-ED2 is

underpinned by a series of historical reviews and

evaluations instigated by SP Energy Networks, both

internally and externally. In compiling the cost

adjustment, all responsible engineers for the

scheme and asset expenditures have been

consulted, as well as liaising with the relevant

systems and operations experts across both SP

Manweb and SP Distribution.

14 Appendix B of our ED1 CSF annex.

https://www.spenergynetworks.co.uk/userfiles/file/201403_SPEN_ManwebCompSpecificFactors_AJ.pdf

https://www.spenergynetworks.co.uk/userfiles/file/201403_SPEN_ManwebCompSpecificFactors_AJ.pdf


38

We have reviewed the approaches to ensure they

remain applicable in RIIO-ED2. On the whole,

methods have not changed substantially.

We have sought an independent review from

network experts TNEI on our methods for

calculating the load related adjustment.

This has confirmed they remain appropriate in RIIO-

ED2 in the context of the changes as a result of Net

Zero.

We have contracted independent experts S&C

Electric Company to review this Annex and the

evidence for the CSF proposal, which concluded

that the approach adopted is robust, accompanied

by strong supporting justification and clearly meets

the requirements outlined by Ofgem for RIIO-ED2

submissions15.

Figure 28: Challenge and review timeline

These reviews widely support that there are

substantive benefits associated with an X-type

configured network, supported our strategy for

managing future network development. They also

widely support that the network design is inherently

“smart” as it is designed to accept power flowing in either direction, and alternative paths are available

when there is a fault. They have recognised the

network more readily facilitates customer uptake of

low carbon technologies through ‘plug in’ substations and with minimal cable laying and

provides scalable reinforcement to meet changing

demand and generation.

The reviews also widely recognised that the SP

Manweb urban network design is generally slightly

more expensive to build and maintain.

15 Annex 7.1c - S&C Electric Company, RIIO-ED2 Business Plan

Company Specific Factors – Final Assurance Report, Nov 2021

Nevertheless, the repeated internal design reviews

have confirmed that the size and complexity of the

existing network does not allow a whole-system

change away from the X-type network without

significant capital spend, and a decrease in

performance of the network to existing customers.

We are also carrying out external assurance of the

methodology used to derive unit costs. This involves

an assessment of the accuracy of data sources,

adequacy of ongoing unit costs updates in line with

renewing framework contracts, and assessment of

risk associated with short term frameworks most of

which will have expired prior to RIIO-ED2.


39

5.4 Contents of this chapter

A summary of the CSF adjustment by cost area as

reported in the M25 Company Specific Factor memo

table is shown in Table 3 overleaf. The remaining

sections of this chapter provide the detailed

methodology behind calculation of this adjustment

by detailed cost area.

In each spend category, we will provide where

applicable:

• The basis of the proposed costs (our

approach to calculating the CSF adjustment

in each area of the plan).

• A comparison to the RIIO-ED1 CSF and

reasons for any changes.

• The options considered and justification for

selected option.

• The optioneering undertaken in the

derivation of our business plan has been

carried out within the EJPs. However, there

are a few key areas where the outcome is

affected by the Interconnected Network

Transitioning Strategy – particularly, many

of the load-related reinforcement plans, and

in the management of the specific assets

key to the interconnected and unit protected

network. These considerations are

discussed.

• This chapter also describes how, in a few

areas, different ways of calculating the

Company Specific Factor adjustment have

been considered. This is particularly

important where engineering assumptions

have had to be made in calculating the

adjustment.

• Measures taken to reduce the costs

associated with the interconnected network.

• This includes measures taken directly to

reduce the additional costs associated with

the interconnected network CSF, and any

wider cost mitigation activities we are

undertaking as business as usual in the

creation of an overall, efficient business plan

that are of relevance to the interconnected

network CSF.

• Note – where we say that the same cost

mitigation measures apply as to the rest of

our Totex plan, for example, we mean

through making efficient, well-justified

investment decisions and carrying out

efficient purchasing and procurement.

• Relevance of the approach to key strategic

aims of our business plan.


40

5.5 Summary of M25 memo table costs

A comprehensive summary of the constituent parts of the proposed interconnected network CSF is shown

below in Table 3. The methods and evidence for deriving each part of the adjustment then follows in the rest of

this chapter: Section 5.6 covers Load Related Expenditure (LRE), Section 5.7 covers Non-Load Related

Expenditure (NLRE), and Section 5.8 covers Network Operating Costs (NOCs).

The cost adjustments against the Company Specific Factor for ED2, as well as the actual and remaining

forecast cost adjustments in ED1, will be reported in the M25 Company Specific Factor memo table.

Table 3: Summary of costs attributed to the CSF by spending category

Spending

Category Activity

Cost

attributed to

CSF

(£m)

Direct Totex

within RIIO-

ED2 Plan

(£m)

CSF value

of Direct

Totex

%

Load

(§ 5.6)

CV1 Primary reinforcement £9.1 £50.6 18.0%

CV2 Secondary reinforcement £4.5 £88.3 5.1%

CV3 Fault level reinforcement £6.1 £17.3 35.1%

Non-load

(§ 5.7)

CV7 Asset Replacement £45.6 £285.0 16.0%

CV8 Asset Refurbishment £3.0 £27.9 10.7%

CV9 Asset Refurbishment £3.4 £14.4 23.5%

CV10 Civil works £3.5 £19.6 17.8%

CV11 Op & IT&T £21.0 £115.3 18.3%

CV12 Electricity System

Restoration (ESR Black Start) £0.6 £3.9 14.4%

CV14 Legal & Safety £2.0 £22.4 9.1%

CV16 Flooding £1.3 £4.3 30.0%

CV22 Environmental £1.5 £39.9 3.7%

Network

Operating Costs

(§ 5.8)

CV26 Faults £7.6 £120.8 6.3%

CV30 Inspections (thermovision) £0.1 £12.0 0.5%

CV31 Repair and maintenance

(R&M) £7.5 £52.9 14.2%

All Balance of Totex Plan - £786.5 -

Total £116.8 £1,661.1 7.0%

Note: In accordance with regulatory guidance, the total investment cost of some assets is split across multiple

CV categories within the BPDTs. For example, the costs associated with the replacement of a primary 33kV

transformer is split between CV7a (asset replacement) and CV7c (asset replacement civil driven costs) and

similarly with primary 33kV switchgear the costs are shown against all CV7 categories together with CV8 and

CV11 to cover associated battery and protection related costs. The make-up of asset total costs is reflected in

our unit costs. The table above shows the costs split over the CV categories.


41

5.6 Load related expenditure

A breakdown of the CSF load related expenditure is shown in Table 4, and a detailed rationale for the individual

costs follows beneath.

Table 4: Load related expenditure plan – top down costs

Asset categories Calculation of CSF

Resultant CSF

adjustment

(£m)

CV1 – Primary reinforcement –

132/33kV (§ 5.6.1)

Cost of reinforcement 39.3% greater for an

interconnected system relative to a radial system 6.82

CV1 – Primary reinforcement –

33/11kV (§ 5.6.1)


interconnected system relative to a radial system 2.29

CV2 – Secondary reinforcement

– HV & LV excluding services

and monitoring (§ 5.6.2)


interconnected system relative to a radial system.

Applied only to the heavily interconnected / urban

areas in Merseyside and Wirral.

4.48

CV3 – Fault Level reinforcement

– 6.6kV to 11kV upgrade

(§ 5.6.3)

Cost of HV transformer in interconnected system

is £0.7k more expensive than an equivalent radial

system with plan to replace 38 as part of the CV1

voltage uprating plan and 86 as part of the CV3

voltage uprating plan

0.09

CV3 – Fault level reinforcement

– 33kV RMUs (§ 5.6.4)

33kV RMUs are unique to interconnected

networks and the cost (£353k) of each RMU

replacement is included with 17 to be replaced

during RIIO-ED2 across 15 primary sites.

5.99

Total 19.67

5.6.1 Primary reinforcement – 132kV/33kV and 33kV/11kV

Basis of proposed costs

To quantify load related costs, we have used the detailed engineering analysis undertaken by PB Power

(PB) (now part of WSP) and Mott MacDonald (MM) at RIIO-ED1 to estimate the cost differential between the

expansion of an interconnected system and an equivalent radial system to release capacity on the primary

network. This method was accepted in RIIO-ED1 by Ofgem and their appointed consultants DNV GL as an

approach to scale the additional cost associated with SP Manweb’s unique network.

The two consultants applied different approaches to the analysis with MM applying a top down theoretical

modelling approach and PB applying a bottom up approach based on a comprehensive evaluation of the

development stages of interconnected and radial networks. Further details of the two approaches can be

found in their respective reports.

The PB report estimated the cost of providing an incremental primary reinforcement of the 132kV/33kV

system by comparing two actual interconnected systems, namely the Warrington Group and Lostock Group,

with costs of hypothetical equivalent radial systems. They concluded on average the cost of reinforcement

was 39.3% greater per MVA for an interconnected system relative to a radial system at 132/33kV level.

For reinforcement at the 33kV/11kV level, the system may be in various stages of development. The PB

Power report estimated the costs of staged development of an interconnected system example and of an


42

equivalent radial system. Both example systems were considered to have the same initial capacity and be

subject to the same demand increases. They concluded on average the cost of reinforcement was 47.2%

greater per MVA for an interconnected system. A more recent review of this approach has been undertaken

by consultants TNEI who confirmed the modelling and principles used were still relevant for ED2.

We have therefore applied these scaling factors to the relevant areas of the CV1 plan to provide primary-

level reinforcement.

There are five applicable 132kV/33kV schemes, amounting to a £24.16m Totex. We have applied the 39.3%

factor to this spend, to calculate a CSF adjustment of £6.82m, as follows: 24.16 × (1 − 11.393) = 6.82.

There are five applicable 33kV/11kV schemes, amounting to a £7.13m Totex. We have applied the 47.2%

factor to this spend, to calculate a CSF adjustment of £2.08m, as follows: 7.13 × (1 − 11.472) = 2.29.

See Table 4 for a summary of costs.

We have excluded from these calculations any expenditure associated with flexibility, automation, and the

addition of any STATCOMs, as these types of reinforcement are not considered in the PB Power report.

Changes from ED1

The methodology for calculating the cost difference between an interconnected and equivalent radial

network has not changed since ED1, which was supported by multiple internal and external reviews (see

Section 5.3). It is based on the 2014 analysis from PB and MM, which remains valid for the reinforcement

planned for RIIO-ED2. The analysis is based upon traditional expansion methods that upon comparison

remain broadly the same between ED1 and ED2. Furthermore, we have sought the views of independent,

specialist energy consultancy TNEI, who have significant working experience of our interconnected network.

It is also their opinion that the methods used in the ED1 consultants’ reports remain valid for ED216.

Our total CV1 ED2 CSF proposal of £9.1m has decreased from the CSF adjustment of £15.24m in ED1 (5-

year, 20/21 prices). This mirrors the overall CV1 load plan, which has reduced by a similar amount.

The actual and forecast remaining costs against the Company Specific Factor in ED1 will be calculated using

the same methodology and reported in the BPDTs under the M25 Company Specific Factor memo table.

Other options considered

For primary reinforcement, the reinforcement options in each scheme are considered within the relevant

EJP. We have selected only those schemes for which the preferred option has additional costs attributable to

the interconnected network, which for reinforcement at the 132kV/33kV level are:

• Formby-Southport 33kV circuit reinforcement (ED2-LRE-SPM-012-CV1-EJP)

• Weston-Basford 33kV circuit reinforcement (ED2-LRE-SPM-016-CV1-EJP)

• Connah’s Quay 132kV: new GT at Deeside Park (ED2-LRE-SPM-001-CV1-EJP)

• Radway Green 33kV: replacement GT (ED2-LRE-SPM-015-CV1-EJP)

• Maentwrog-Llanfrothen 33kV cable (ED2-LRE-SPM-005-CV1-EJP)

And for reinforcement at the 33kV/11kV level are:

16 SP Manweb Company Specific Factors (CSF) - Evaluation of Load Related Costs, Version 2, TNEI, May

2021


43

• Middlewich: additional primary transformer (ED2-LRE-SPM-027-CV1-EJP)

• Acer Avenue: additional primary transformer (ED2-LRE-SPM-008-CV1-EJP)

• Sandbach: additional primary transformer (ED2-LRE-SPM-009-CV1-EJP)

In calculating the CSF adjustment, we considered applying analysis from the MM report to the same

schemes. The MM report concluded a similar cost differential of 44% at 132/33kV level and a higher cost

differential of 74% at the 33/11kV voltage level. Although the modelling approaches adopted by the two

consultants were very different, the two sets of results are broadly of a similar magnitude of order (with the

MM’s estimates being somewhat higher particularly at higher voltage levels). We have used the lower cost

differentials from the PB report to provide a conservative estimate for primary and 132kV reinforcement.

Using the MM report values, the CSF adjustment would be a higher value of £10.42m as follows: 24.16 × (1 − 11.44) + 7.13 × (1 − 11.74) = 10.42. We went for the more conservative analysis in line with our

approach in ED1.

Cost mitigation measures

There are no feasible options to move away from an interconnected system that relieve constraints on the

primary system without significant reconfiguration of large areas of network.

Relevance of approach to strategic aims

The CV1 plan is based on the ‘Engineering Net Zero’ model, that will deliver our customers’ requirements as the UK transitions to Net Zero, whilst maintaining a safe, resilient and efficient network.

Overall, load related network investment is designed to deliver the lower of the credible range from our

Distribution Future Energy Scenarios, which includes over 1GW of additional capacity and enabling

connection of 700k EVs, 400,000 heat pumps, and 4.7GW of decentralised generation. This strategy

protects customers from excessive early investment. However, as discussed in Section 3.3, the

interconnected network provides an adaptable network that is resilient to change.

5.6.2 Secondary reinforcement – HV and LV


To quantify load related costs, we have used the detailed engineering analysis undertaken by Mott

MacDonald (MM) at RIIO-ED1 to estimate the cost differential between the expansion of an interconnected

system and an equivalent radial system to release capacity on the secondary network. This is based on a

top down theoretical modelling approach of network expansion by the addition of more plant as the load

requires it. This model estimated that expenditure for reinforcing an interconnected system was about 23%

greater than for an equivalent radial system at the secondary level.

We have applied this factor to the relevant CV2 secondary (HV and LV) reinforcement areas. This excludes

services and OHL infrastructure. It also conservatively excludes LV monitoring and smart investment

expenditure, as this is not covered by the scope of the MM study. Any differences in these areas resulting

from the interconnected network are likely to be less significant.

We have accounted for reinforcement planned within the heavily interconnected regions only – namely in

Merseyside and Wirral, by scaling the CV2 spend by a factor of 55%. This is a conservative assumption, as

X-type substations and HV/LV interconnected network arrangements are found throughout all regions of the

SP Manweb licence area.


44

The resultant applicable CV2 expenditure is £43.28m, leading to a CSF adjustment of £4.48m, as follows: 43.28 × 0.55 × (1 − 11.23) = 4.48.

See Table 4 for a summary of costs.

Changes from ED1

For secondary reinforcement, due to the relatively small expenditure in RIIO-ED1, this was excluded from

our CSF claim as the total contribution was small. However, RIIO-ED2 will see a significant investment into

secondary reinforcement in preparation for the Net Zero transition, particularly for the accommodation of

heat pumps and electric vehicles. The total CV2 expenditure in ED2 is approximately five times the ED1

expenditure (in 5-year, 20/21 prices). The CSF adjustment remains quite a small percentage (5.1%) of the

total CV2 expenditure in ED2, but it does lead to a now significant adjustment.


the updated methodology and reported in the BPDTs under the M25 Company Specific Factor memo table.


The £43.28m expenditure in this area is driven by a model-based approach based on a ‘baseline view’ of the reinforcement requirements from the ED2 future energy scenarios. Details can be found in paper ref. ED2-

LRE-SPEN-002-CV2-EJP. Specific reinforcement options have not been considered on a case by case

basis.


Although no X-type to Y-type transitions are specifically planned, all secondary reinforcement interventions in

SP Manweb will be governed by our Interconnected Network Transitioning Policy. This means that X-type

substations should be assessed for transition based on a number of quantitative and qualitative criteria. This

includes, but is not limited to, if the level of interconnection on the LV network is low, if there is a mixed

configuration of X-type and Y-type substations on the HV feeder and a high (>=50%) number of Y-type

substations on HV feeder, if there is poorly performing protection equipment or if further development is

anticipated in future. If a specific reinforcement of the interconnected secondary system is flagged for

assessment, the whole life costs of both transitioning to Y-type and maintaining the X-type equipment will be

considered. The option that presents the best overall value will be selected, noting that transition will often

lead to an increase in customer interruptions.

Transition candidates are likely to only occur within the ‘fringe’ areas of our urban network. Our learning from

the Southport network transition scheme (Section 0) indicates that any such transition away from X-type is

unlikely to save significant costs in the initial period; the benefit is seen due to asset management, operation,

repair and maintenance savings in the longer term. As mentioned in Section 4.8, we are following the latest

innovations in LV automation that may allow us to complement our interconnected network technology at

lower cost.

As mentioned in Section 0, we are also trialling new design solutions which enable lower cost connections

using existing technologies. Currently, the maximum size of an additional Y-type substation between two X-

type substations is 500kVA. This innovative approach will enable up to 1,500kVA connections to be offered

in our interconnected network providing customers with lower cost connection options. It is mainly

connecting customers who will benefit from these savings.




45

Overall, load related network investment is designed to deliver the lower of the credible range from our

Distribution Future Energy Scenarios, which includes over 1GW of additional capacity and enabling

connection of 700k EVs, 400,000 heat pumps, and 4.7GW of decentralised generation. This strategy

protects customers from excessive early investment. However, as discussed in Section 3.3, the

interconnected network provides an adaptable network that is resilient to change.

5.6.3 HV uprating schemes (6.6kV to 11kV)


During RIIO-ED2, three primary groups are planned to be uprated from 6.6kV to 11kV to relieve fault level

constraints and release additional network capacity under CV3. As part of this scheme, 86 X-type secondary

transformers need to be replaced. Another primary group, in which a further 38 X-type secondary

transformers need to be replaced, will release network capacity under CV1 primary reinforcement.

Unique to our interconnected and unit protected network, these X-type transformers have additional current

transformers (CTs) connected to the HV side to allow the unit protection schemes to operate. These CTs

require additional termination accommodation for the cable connecting the transformer to the X-type RMU.

This leads to a higher unit cost.

We have calculated this unit cost differential based on the difference between that of a standard transformer

and the higher-cost unit that includes the additional equipment and termination needed on SP Manweb’s unique 11kV network. The difference in cost is driven by additional fitting costs (£2.5k compared to £2.0k)

and the cost of additional CTs (6 off at ~£38 each). This leads to an additional cost of circa £0.7k per

transformer. This leads to a total CSF adjustment of £0.1m (£0.03m for HV uprating under CV1, and £0.06m

under CV3).

Changes from ED1

This adjustment has reduced quite significantly from the ED1 adjustment of £0.38m (in 5-year, 20/21 prices).

Partly this is due to the scale of the HV voltage uprating schemes planned for ED1 being bigger – in ED1 we

were required to replace a total of 256 X-type secondary transformers. Additionally, for the additional cost of

the CTs and terminations required in the X-type network, we have used the difference between HV

transformer unit cost in SP Distribution and SP Manweb. This leads to an underestimate of the CTs and

termination costs, but this is therefore a conservative adjustment. In the ED1 adjustment calculation, we

used the difference between the X-type and Y-type transformer unit costs, which is a greater difference of

£1.9k.




The uprating of primary groups has been identified as having an increased potential for X-type transition, due

the volume of equipment replacement on the same HV feeders. In line with our Interconnected Network

Transitioning Policy (Section 4.3) we must make an assessment to identify whether transitioning provides

better overall value for money for our customers.

Cost benefit analysis has been carried out using the learning from our Southport network transitioning trial

(this project is described in Section 0). Although there are some avoided future costs relating to asset

maintenance, asset replacement and network operating costs, there is an upfront cost to the transition.

Additionally, some of the ongoing costs – such as maintenance of the civil assets (e.g. the brick-built

substation enclosures) cannot be reduced without proactive investment to change the substation housing

type to a cheaper alternative.


46

Furthermore, the network performance of the existing groups in terms of CIs and CMLs is excellent. Any

known alternative solution to the LV interconnection would likely reduce this performance (noting the

technological challenges in the Southport project), and this comes through in the results of the CBA. As

mentioned in Section 4.8, we are following the latest innovations in LV automation that may allow us to

complement our interconnected network technology at lower cost.

Therefore, for ED2, best overall value was shown to be achieved through perpetuation of the X-type network

in these areas. We will review this position as the innovative LV interconnection technology develops and the

Southport scheme is finalised and has been tested at business as usual.

Details of this analysis can be found in the relevant EJPs: ED2-LRE-SPM-008-CV3-EJP Fault level

mitigation - HV group reconfiguration and ED2-LRE-SPM-031-CV1-EJP Bootle Canal Quarter Regeneration

Scheme.


As above, transitioning any of the groups to Y-type or radial design was not anticipated to provide best value

for the customer due to both higher costs and reduced longer-term benefits.


Increased fault level headroom enables the further connection of LCTs & distributed generators, completing

both our strategy to deliver successful Distribution System Operation (DSO) and also in the move towards

Net Zero. As discussed in Section 3.3, continuing the interconnected network in these primary groups

provides an adaptable network that is resilient to change.

Furthermore, the proposed works contribute further towards the Net Zero aim by reducing network losses in

all the groups to the tune of 3GWh per year.

5.6.4 Fault level reinforcement: 33kV RMU replacement


As discussed in Section 3.4.2, an outcome of the heavily interconnected networks is that the fault levels are

higher compared to radially fed networks. In general, for such networks, besides the connected levels of

generation and demand, the network configuration (i.e. the open and closed points on the network) dictates

the fault levels. With the growth of the network and in particular the addition of LCTs, fault levels are

increasing. The exceedance of the ratings increases the risk of failure during switching operations either as a

mechanical failure or electrical failure, which could be a health and safety concern.

Whilst the modern switchgear installed in SP Manweb network can generally withstand these higher levels,

to maintain the safe functioning of the interconnected and unit protected network, many of the 33kV ring

main units (RMUs) at the primary substations require uprating.

Our plan includes the replacement of 13 single 33kV RMUs and two double 33kV RMUs as a result of fault

level constraints across 15 primary sites.

As discussed in Section 3.6.1, the 33kV RMUs are unique to SP Manweb’s interconnected network and are a fundamental requirement to operation of the existing unit protection schemes with no radial alterative.

Therefore, the whole cost of the RMU replacement is considered as an additional cost relative to the cost of

operating a radial system. At a cost of £353k for each RMU, the associated additional load related cost is

£5.99m.


47

Changes from ED1



Section 5.3).

This adjustment has increased from that in ED1, which was £1.22m (in 5-year, 20/21 prices). This is due to

increased requirement and activity in this area – in ED1 only four 33kV RMUs we were required to be

replaced to resolve primary fault level constraints.




Options for resolving primary fault level constraints that did not include the replacement of the 33kV RMUs

were considered. These were ruled out on the basis of cost, risk, performance and/or technology readiness.

Details can be found in EJP paper ref. ED2-LRE-SPM-011-CV3-EJP.

We considered whether, given the increased fault levels within the SP Manweb network, there should be a

further Company Specific Factor adjustment related to other activities in this area. However, fault level

constraints are a common problem faced by other DNOs and hence we considered that only the

replacement of the unique 33kV RMU switchgear was applicable to the Company Specific Factor as this

switchgear is used at downstream primary substations unlike a typical radial design that does not have 33kV

switchgear at similar located primary substation sites.


Overall, the selected option within the primary reinforcement EJP contains some real time fault level

monitoring in order to mitigate the number of RMUs requiring replacement. As above, details can be found in

paper ref. ED2-LRE-SPM-011-CV3-EJP.

To further reduce the additional costs associated with the SP Manweb interconnected network, we are

developing designs of lower cost modern equivalent 33kV RMUs as discussed in Section 4.6. Primary sites

with a double RMU arrangement will be replaced with 4 or 5-panel board (i.e. 4 or 5 circuit breakers (CBs))

and at single-RMU sites, we are a developing another reduced-footprint solution by using a CB in

combination with two switch disconnectors. We estimate the new design could realise a 20-25% unit cost

saving, subject to successful development of a modern equivalent 33kV RMU by approved manufacturers.


Increased fault level headroom enables the further connection of LCTs & distributed generators, completing

both our strategy to deliver successful Distribution System Operation (DSO) and to support the transition

towards Net Zero.


48

5.7 Non-load related expenditure

Asset modernisation is required for a variety of reasons such as: to maintain or improve performance and

reliability of aged or poor condition assets, e.g. based on Health Index (HI) and criticality rating, or for

environmental improvements, and to ensure our primary substations remain resilient for extended duration

power outages known as ‘Black Start’ events.

A breakdown of the CSF non-load related expenditure is shown in Table 5, and a detailed rationale for the

individual costs follows beneath.

Table 5: Non-load related expenditure plan – asset modernisation and refurbishment

Asset categories

SP Manweb

Interconnected

Network

Equivalent Radial

Network

Resultant

CSF

adjustment

(£m) Asset type Spend category

CV

code Volume

Cost

(£k) Volume

Cost

(£k)

Primary

ground-

mounted

transformers

Asset replacement

(§ 5.7.1.1)

CV7a

40

314.36 25

369.24

3.99 CV7c

60.00

70.00

Asset refurbishment

(§ 5.7.1.2) CV9 19

37.15 12

37.15

0.26

Secondary

X-type

transformers

Asset replacement

(§ 5.7.3.1) CV7a 225

14.50 225

13.90

0.16

Asset refurbishment

(§ 5.7.3.2) CV9 327

4.62 -

-

1.51

Primary

switchgear –

33kV outdoor

CBs (air

insulated

busbars)

Asset replacement -

(§ 5.7.2.1)

CV7a

57

90.48

-

-

7.94

CV7c

9.00

-

CV7b

5.87

-

CV8

13.00

-

CV11

21.00

-

Asset refurbishment

(§ 5.7.2.2) CV9 65

25.00 -

-

1.63

Primary

switchgear –

33kV RMUs

Asset replacement

(§ 5.7.2.1)

CV7a

33

228.58

-

-

11.63 CV7c

65.00

-

CV7b

7.98

-


49

Asset categories

SP Manweb

Interconnected

Network

Equivalent Radial

Network

Resultant

CSF

adjustment


CV

code Volume

Cost

(£k) Volume

Cost

(£k)

CV8

21.00

-

CV11

30.00

-

Primary

switchgear –

33kV indoor

CBs (air

insulated

busbars)

Asset replacement

(§ 5.7.2.1)

CV7a

9

124.54

-

-

1.49

CV7c

12.00

-

CV7b

2.58

-

CV8

21.00

-

CV11

5.00

-

Pilot wires

Asset replacement –

33kV network Hardex

(§ 5.7.7.1)

CV7b 47.0

18.50 -

-

0.87


33kV Hardex protection

schemes (§ 5.7.7.1

CV7b 39.0

23.70 -

-

0.92


33kV network short

section UG repair

(§ 5.7.7.1)

CV7b 7.5

140.74 1.9

140.74

0.79


11kV network short

section UG repair

(§ 5.7.7.1)

CV7b 5

118.92 -

-

0.59


pilot wire with 11kV UG

cable overlays

(§ 5.7.7.1)

CV7b 23

30.75 -

-

0.72


pilot wire with 33kV UG

cable overlays

(§ 5.7.7.1)

CV7b 24

42.36 6

42.36

0.75

LV link boxes Asset replacement

(§ 5.7.6) CV7a 1,978

7.47 95

7.47

14.06

Secondary

switchgear


11kV X-type RMUs

(§ 5.7.4.1)

CV7a 458

18.75 458

18.34

0.19


50

Asset categories

SP Manweb

Interconnected

Network

Equivalent Radial

Network

Resultant

CSF

adjustment


CV

code Volume

Cost

(£k) Volume

Cost

(£k)

Asset Replacement –

11kV X-type CBs

(§ 5.7.4.1)

CV7a

134

28.02

134

8.54

3.83

CV7c

11.00

1.00

CV7b

0.05

-

CV11

1.15

2.08

Asset replacement – X-

type LV boards

(§ 5.7.4.1)

CV7a

89

11.52

89

10.08

0.13

Secondary

protection


11kV secondary

batteries (§ 5.7.5.1)

CV7b 4,175

0.38 380

1.07

1.17


11kV secondary battery

chargers (§ 5.7.5.1)

CV7b 550

0.83 54

2.01

0.35

Primary sites

Civil works – primary

substations (§ 5.7.8.1) CV10 390

15.12 186

21.56

1.89

IT&T – RTU

replacement (§ 5.7.8.3) CV11 1

3,183.01 0

3,183.01

1.67

IT&T – telecoms

improvement (§ 5.7.8.4) CV11 1

20,170.00 48%

20,170.00

10.56

IT&T O&M (including

pilot rentals) (§ 5.7.8.5) CV11 1

15,101.64 48%

15,101.64

7.91

Electricity System

Restoration (ESR)

(Black start resilience) –

DC supplies (§ 5.7.8.6)

CV12 63

5.00 45

5.00

0.09

Electricity System

Restoration (ESR)

(Black start resilience) –

telecoms (§ 5.7.8.6)

CV12 585

2.86 418

2.86

0.48

Substation security

(§ 5.7.8.7) CV14 523

4.50 249

4.50

1.23

Asbestos management

(§ 5.7.8.8)

CV14 1

389 0

389

0.20

Fire protection - Fire

Risk assessment

programme (§ 5.7.8.9)

CV14

1

639 0

639

0.33


51

Asset categories

SP Manweb

Interconnected

Network

Equivalent Radial

Network

Resultant

CSF

adjustment


CV

code Volume

Cost

(£k) Volume

Cost

(£k)

Fire protection - Primary

Site actions (§ 5.7.8.9)

CV14 530

1 253

1

0.14

Fire protection - Primary

Site embedded actions

(§ 5.7.8.9)

CV14

53

5 25

5

0.14

Flood resilience

(§ 5.7.8.10) CV16 1

2,462.19 48%

2,462.19

1.29

Transformer bunds

(§ 5.7.8.11) CV22 38

74.02 18

74.02

1.47

Secondary

sites

Civil works – secondary

substations (§ 5.7.9.1) CV10 2,020

2.65 1,251

3.01

1.59

Total 81.98


52

5.7.1 Primary (EHV) transformers

5.7.1.1 CV7 – Asset replacement


As shown in Section 3.6 and supported by multiple internal and external reviews (see Section 5.3), our

unique network employs more primary transformers compared to an equivalent radial network, though these

transformers tend to be smaller in rating. Overall, this leads to a higher cost of transformer replacement in

the SP Manweb interconnected network. We have considered the replacement volume and unit cost for SP

Manweb over RIIO-ED2 and compared this with the MVA equivalents for a notional radial system.

Based on our asset age and condition profile SP Manweb plans to replace 40 primary (ground-mounted)

transformers in RIIO-ED2 to manage our Health Index HI5 assets which cost £374k each based on CV7a

(£314k for asset replacement) and the related CV7c (£60k civils associated with asset replacement) unit

costs in SP Manweb’s unit cost manual – this represents a total cost of £14.97m.

The typical transformer size in the interconnected network is 7.5/10MVA, compared to 12/24MVA in a radial

network (as used in our SP Distribution region). We therefore calculate that we would need to replace 40 × 7.512 = 25 primary transformers if SP Manweb were designed as a radial network, based on firm capacity

requirements17. However, the transformers for a radial network are larger, and more expensive, at a total unit

cost of £439k each (based on SP Distribution’s unit cost manual).

The difference between the two totals is the resultant CSF adjustment, £3.99m (shown in Table 5).

Changes from ED1


network has not changed significantly since ED1; however, we have applied an updated (more conservative)

scaling factor to the number of transformers in our interconnected network compared to an equivalent radial

– this is discussed in more detail below.

Our ED2 CSF proposed adjustment has decreased slightly from the CSF adjustment of £4.34m in ED1 (5-

year, 20/21 prices). The decrease is due to the more conservative scaling factor. Overall, the adjustments

are similar as the programme of transformer replacement in ED2 has increased annually compared to ED1,

but not significantly.




For primary transformer modernisation needs, the options are considered within the relevant EJP: ED2-

NLR(A)-SPEN-001-TX-EJP – Transformer Condition Modernisation Programme. The paper considers

various replacement and refurbishment options, and the optimum scheme is selected based on deliverability

and 45-year value.

In calculating the CSF adjustment, we re-considered the typical number of transformers than would be

present on an equivalent radial network. In ED1, we scaled the number of transformers according to force-

cooled ratio of 24MVA (typical SP Distribution rating) to 10MVA (typical SP Manweb rating). Whilst the use of

17 This is a change in approach from RIIO-ED1, which took the emergency rating and force cooled rating of

transformers as the basis for comparison (24:10). Upon a more detailed investigation of transformer usage (and

accounting for the higher utilisation), we believe the 12:7.5 ratio is a better reflection of transformer capacity.

This is also the more conservative comparison.


53

the forced cooled ratings are a better representation of how transformers are utilised in practice (as

concluded by the PB Power review of our ED1 CSF adjustment), on closer inspection this may not account

for the lower transformer utilisation on traditional radial networks.

Use of the force-cooled ratio would indicate an equivalent 40 × 1024 = 17 primary transformers if SP Manweb

were designed as a radial network, leading to an adjustment of £7.51m. Therefore, our adjustment is

conservative to the tune of £3.51m.

We also considered the average transformer rating in SP Manweb compared to the average rating in SP

Distribution – which is virtually identical to the 7.512 ratio. Figure 29 shows the number of transformers in an

equivalent radial network (using the 7.512 ratio) for comparison, normalised by both customers numbers and

units distributed. This shows that our assessment is conservative when compared to industry average.

Figure 29: The number of primary transformers in SPM Manweb compared to industry average and our

calculated radial equivalent, per 100,000 customers (left) and per TWh distributed (right)

Source: 2019/2020 V1 asset datashare and 2019 RIIO 2019/2020 report supplementary data file.

Additionally, it is interesting to note that SP Manweb has one of the highest MWh distributed per customer in

the industry excluding LPN, which has a much higher MWh distributed per customer than the rest of the

industry due to its unique geography. (SP Manweb distributes 5.4% more MWh per customer than average

including LPN, and 7.3% more than average excluding LPN.) This also contributes to the higher average

transformer utilisation in the SP Manweb network.


There are no feasible options to move away from an interconnected system that reduce the volumes of

primary transformers that need to be modernised. However, we are undertaking a programme of transformer

refurbishment, which can be a more cost-effective option to replacement and has significantly lower initial

expenditure – this is discussed in the next section.


The drivers for primary transformer replacement across both of our licence areas are to maintain a safe and

resilient network and to maintain its performance and reliability for our customers. The additional costs

incurred by the SP Manweb interconnected network are necessary to ensure an equivalent level of benefit.

As discussed in Section 3.3, the interconnected network provides an adaptable network that is resilient to

change. This is due to the uniformity of transformer and cable size, and standard rating for circuits and

design for switchgear, protection and relay settings, which allows for a ‘plug-and-play’ of additional network. This means the replacement of primary transformers is consistent with future increases in demand, reducing

the risk of stranding.

0

20

40

60

80

SPMW Average Equivalent

radial network

Primary transformers (GM) per

100,000 customers

0

20

40

60

80

SPMW Average Equivalent

radial network

Primary transformers (GM) per TWh

distributed


54

5.7.1.2 CV9 – Asset refurbishment


As part of our asset strategy for primary transformers, where possible and cost effective to do so, to extend

the life of the asset SP Manweb plan to refurbish primary transformers as part of RIIO-ED2 to further improve

the condition profile of our assets.

As our unique network employs more primary transformers compared to an equivalent, radial network, our

refurbishment volumes are also proportionately greater. We have assumed the cost of each refurbishment is

no different in the interconnected network compared to a radial equivalent; indeed, the unit costs are the

same in both SP Manweb and SP Distribution.

We plan to refurbish 19 primary transformers in RIIO-ED2. We therefore calculate that we would need to

refurbish only 19 × 7.512 = 12 primary transformers if SP Manweb were designed as a radial network, based on

firm capacity requirements. At an average refurbishment cost of circa £37k, this leads to a CSF adjustment

of £0.26m (shown in Table 5).

Changes from ED1

The cost of refurbishing an increased volume of transformers was not identified in ED1 Company Specific

Factor, so was not included. This is considered to be an omission in the ED1 CSF submission.

We have applied an updated (more conservative) scaling factor to the number of transformers in our

interconnected network compared to an equivalent radial – this is discussed in Section 5.7.1.1 above.




For primary transformer modernisation needs, the options are considered within the relevant EJP: ED2-

NLR(A)-SPEN-001-TX-EJP – Transformer Condition Modernisation Programme. The paper considers

various replacement and refurbishment options, and the optimum scheme is selected based on deliverability

and 45-year value.


Transformer refurbishment is already considered a means to mitigate the costs of asset modernisation. It can

be a more cost-effective option to replacement and has significantly lower initial expenditure.

As discussed in Section 4.6, to maximise value from existing and future transformer fleet, we are looking at

new refurbishment options to defer eventual replacement and may even, in the longer term, reduce the oil

replacement frequency. Given the uniquely high number of primary transformers in SP Manweb, this could

result in a reduction in the Company Specific Factors in future price reviews beyond RIIO-ED2. Further

details of this work are given in Section 4.6.


This is in line with our programme of primary transformer replacement above (Section 5.7.1.1).


55

5.7.2 Primary switchgear (33kV outdoor ground-mounted CBs, 33kV indoor ground mounted CBs and

33kV RMUs)



As introduced in Section 3.6, 33kV switchgear and circuit breakers (CBs) in downstream primary substations

– as shown in Figure 30 – are unique to SP Manweb. They are integral to the design and operation of the

unit protection system in SP Manweb’s interconnected network. This switchgear would not be required in

downstream primary substations in a radial network, and therefore there would be no associated costs. SP

Manweb has the highest switchgear Asset Value within the EHV network of any DNO, both absolute, and by

km of network as shown in Figure 31.

Figure 30: System of networks for distribution of

electricity (as per Figure 3) additionally showing

location of primary switchgear

Figure 31 – Mean Equivalent Asset Value (MEAV) of

switchgear per 100km of EHV network

In RIIO-ED2, we plan to replace 57 outdoor air CBs in RIIO-ED2, due to age and condition and to reduce our

risk exposure to Health Index HI5 assets and improve the reliability of our network. The total individual cost is

£139k each (of which circa £103k are the direct costs against CV7a and £36k are ‘other’ costs associated

with the replacement) resulting in a total cost of £7.94m. The full cost has been included in the CSF

adjustment.

In line with our CNAIM approach and asset modernisation strategy, SP Manweb also plan to replace 9

ground-mounted indoor air CBs, which are at primary sites, and a further 33 indoor RMUs. The total costs of

an individual indoor 33kV CB is £165k (the CV7a costs and ‘other’ costs being £124k and £41k respectively)

and a 33kV RMU is £352k (the CV7a costs and ‘other’ costs being £229k and £124k respectively) which is a

three-panel board comprising of three indoor CBs).

The total cost of the indoor 33kV switchgear is therefore £13.12m, the full cost of which has been included in

the CSF adjustment in line with previous price controls (shown in Table 5).

Changes from ED1



Section 5.3).

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000£

k


56

Our ED2 CSF proposed adjustments for outdoor and indoor switchgear have increased slightly from the CSF

adjustment of £5.96m and £8.99 in ED1 (5-year, 20/21 prices), respectively.

The increase in total cost is due to a rise in unit costs; £139k in ED2 compared to ~£80k planned for ED1 for

outdoor CBs, and £165k in ED2 compared to ~£110k planned for ED1 for indoor CBs.

The actual and forecast remaining costs against the Company Specific Factor in ED1 will be reported in the

BPDTs under the M25 Company Specific Factor memo table.



primary switchgear that need to be modernised. However, we are undertaking a programme of asset

refurbishment, which can be a more cost-effective option to replacement and has significantly lower initial

expenditure – this is discussed in the next section.

For primary switchgear modernisation needs in SP Manweb in ED2, the options are considered within the

relevant EJP: ED2-NLR(A)-SPEN-003-SWG-EJP: SPD & SPM EHV (33kV) Switchgear Modernisation. The

paper considers various replacement and refurbishment options, and the optimum scheme is selected based

on deliverability and 45-year value.


As per Section 5.6.4 above, to reduce the additional costs associated with the SP Manweb interconnected

network, we are developing designs of lower cost modern equivalent 33kV RMUs. This is discussed in more

detail in Section 4.6. Double RMUs will be replaced with 4 or 5-panel board (i.e. 4 or 5 CBs) and at single-

RMU sites, we are a developing another reduced-footprint solution by using a CB in combination with two

switch disconnectors. We estimate the new design could realise a 20-25% unit cost saving, subject to

successful development of a modern equivalent 33kV RMU with approved manufacturers.


The drivers for primary switchgear replacement across both of our licence areas are to maintain a safe and

resilient network and to maintain its performance and reliability for our customers. The additional costs

incurred by the SP Manweb interconnected network are necessary to ensure an equivalent level of benefit.

As discussed in Section 3.3, the interconnected network provides an adaptable network that is resilient to

change. This is due to the uniformity of transformer and cable size, and standard rating for circuits and

design for switchgear, protection and relay settings, which allows for a ‘plug-and-play’ of additional network. This means the replacement of primary switchgear is consistent with future increases in demand, reducing

the risk of stranding.



In addition to primary switchgear replacement, where it presents a more cost-effective solution, we plan to

refurbish primary switchgear as part of RIIO-ED2 to further improve the condition profile of our assets.

We plan to refurbish 65 33kV CBs in RIIO-ED2 that are at downstream primary substations. The individual

cost is £25k per refurbishment, resulting in a total cost of £1.63m. The full cost has been included in the CSF

adjustment (shown in Table 5).

Changes from ED1

Although the refurbishment of assets unique to SP Manweb was identified as an additional cost in the ED1

Company Specific Factor annex, the cost was not included in the adjustment. This is considered to be an


57

omission in the ED1 CSF submission; and in any case, there has not been a significant volume of 33kV

switchgear refurbishments that have taken place in ED1.

The actual and forecast remaining costs against the Company Specific Factor in ED1 will be reported in the

BPDTs under the M25 Company Specific Factor memo table.


For primary switchgear modernisation needs in SP Manweb in ED2, the options are considered within the

relevant EJP: ED2-NLR(A)-SPEN-003-SWG-EJP: SPD & SPM EHV (33kV) Switchgear Modernisation. The

paper considers various replacement and refurbishment options, and the optimum scheme is selected based

on deliverability and 45-year value.


Switchgear refurbishment is considered a means to mitigate the costs of asset modernisation. It can be a

more cost-effective option to replacement and has significantly lower initial expenditure.


This is in line with our programme of primary switchgear replacement above (Section 5.7.2.1).

5.7.3 Secondary (HV) transformers



Figure 32 shows the different secondary (HV) transformer arrangements in the SP Manweb network. The X-

type transformer setup provides the maximum level of LV interconnection, allowing connection at LV of

transformers on other HV feeders in the HV group. The Y-type transformer can provide a degree of LV

interconnection, allowing connection at LV of transformers on the same HV feeder. A radialised HV feeder,

supplying radial LV feeders, is shown to the right-hand side of the image for comparison.

Figure 32: Secondary (HV) transformers in the SP Manweb network (not to scale), showing example LV

feeders and services.

X-type, ground-mounted transformers are unique to the interconnected network, and have additional

components connected to the HV voltage side of the transformer in the form of additional current

transformers (CTs) to allow the unit protection schemes to operate. These CTs require additional termination

accommodation for the cable connecting the transformer to the X-type RMU.


58

We plan to replace 225 indoor X-type HV transformers in RIIO-ED2 due to age and condition, and to reduce

prevalence of assets categorised as Health Index HI5. We have conservatively assumed that on a traditional

radial network, the same volumes of HV transformers would be replaced, though the additional complexity

would not be required.

The unit cost of the X-type transformer is approx. £0.7k more expensive, as discussed in Section 5.6.3. This

leads to a CSF adjustment of £0.16m (shown in Table 5).

Changes from ED1



Section 5.3).

Our ED2 CSF proposed adjustment of £0.1 has decreased slightly from the CSF adjustment of £0.2m in ED1

(5-year, 20/21 prices). This is due to a smaller different in unit cost between the transformer types in ED2

than was planned for ED1.




For HV transformer modernisation needs, the options are considered within the relevant EJP: ED2-NLR(A)-

SPEN-001-SWGTX-EJP – Asset Modernisation at Secondary Substations. The optioneering covers targeted

replacement and refurbishment compared to a replacement-only option.


In the creation of our plans, we have considered whether there are ways to reduce the additional cost

associated with the interconnected, unit-protected network through the application of our Interconnected

Network Transitioning Policy ESDD-01-013. This means that X-type substations should be assessed for

transition to Y-type or ‘i-Type’, or for several X-type substations along an HV feeder to be radialised. These

modifications remove some to all LV interconnection.

The assessment is based on a number of quantitative and qualitative criteria. This includes, but is not limited

to, if the level of interconnection on the LV network is low, if there is a mixed configuration of X-type and Y-

type substations on the HV feeder and a high (>=50%) number of Y-type substations on HV feeder, if there

is poorly performing protection equipment or if further development is anticipated in future.

For asset modernisation that is flagged by the initial assessment, the whole life costs of both transitioning

and maintaining the X-type equipment will be considered through detailed cost benefit analysis and the

option that presents the best overall value will be selected, noting that transition will often lead to an increase

in customer interruptions. However, for this programme of work, no options were flagged for detailed (cost-

benefit) analysis. For this asset modernisation driven programme of work, the decision to plan for like-for-like

replacement was selected using engineering judgement of the network locations of the assets for

replacement.


The driver for replacement of the X-type transformers is to maintain the excellent performance and reliability

for our customers, whilst maintaining a safe and resilient network. The additional costs incurred by the SP

Manweb interconnected network are necessary to ensure there is no reduction in network performance, in

terms of increased customer interruptions, or network safety. As discussed in Section 4.1 on customer and

stakeholder engagement, our customers consider network reliability to be of utmost importance. A reliable


59

network will become even more important as customers rely on their electricity for an increasing proportion of

their energy needs, such as heating and transport, as part of the Net Zero transition.



As part of our asset strategy for secondary substations, we also plan to refurbish 327 HV transformers in SP

Manweb, where possible and cost effective to do so, to extend the life of the asset SP Manweb plan and

further improve the condition profile of our assets.

HV transformer refurbishment is not carried out in the SP Distribution network. The programme in SP

Manweb is predominantly driven by the X-type 11kV RMU replacement programme as the work involves

changing the transformer cable tails between the replacement X-type RMU and the transformer. The

refurbishment works also involves replacing the transformer cable back-box and the CTs associated with the

X-type unit protection scheme and for efficiency is co-ordinated wherever possible with the RMU

replacement.

The unit cost of the transformer refurbishment is £4.62k which is unique to SP Manweb’s network and as such we have allocated £1.51m towards the CSF (shown in Table 5).

Changes from ED1

Although the refurbishments of assets unique to SP Manweb was identified as an additional cost in the ED1

Company Specific Factors, the cost of HV transformer refurbishment was not included. This is considered to

be an omission in the ED1 CSF submission.


the new methodology and reported in the BPDTs under the M25 Company Specific Factor memo table.


For HV transformer modernisation needs, the options are considered within the relevant EJP: ED2-NLR(A)-


replacement and refurbishment compared to a replacement-only option.


Transformer refurbishment is considered a means to mitigate the costs of asset modernisation, as it can be a

more cost-effective option to replacement and has significantly lower initial expenditure.


As above for HV transformer replacement, the driver for refurbishment of the X-type transformers is to

maintain the excellent performance and reliability for our customers, whilst maintaining a safe and resilient

network. This will become even more important as customers rely on their electricity for an increasing

proportion of their energy needs, such as heating and transport, as part of the Net Zero transition.

5.7.4 Secondary switchgear (11kV X-type RMUs and X-type CBs) and LV boards



Just as for primary sites, there is additional complexity in the switchgear at secondary substation to support

operation of SP Manweb’s unique unit HV protection scheme (known as Solkor). Firstly, an X-type RMU


60

requires additional protection CT’s and small wiring compared to a standard 11kV RMU used on a traditional radial network, and its unit cost is circa £411 higher.

To maintain the reliability of our network in interconnected areas, we plan to replace 458 indoor 11kV X-type

RMUs in RIIO-ED2 to improve asset condition and to reduce the prevalence of assets categorised as Health

Index HI5. We have conservatively assumed that on a traditional radial network, the same volumes of RMUs

would be replaced, though lower-cost, Y-type RMU would be required. Therefore, we have compared the

unit costs of the X-type RMU to the Y-type alternative, and attributed the difference in cost to the

interconnected network.

As the unit cost of the X-type RMUs is £41 more expensive, a total CSF adjustment of £0.19m.

Additionally, unlike secondary CBs on a traditional radial network, the X-type CB is larger and more

expensive compared to a standard CB due to the complexity and requirements of our unit protection. We

have plans to replace 134 secondary network X-type CBs which are embedded within our 11kV network and

are an integral part of our unique unit protection system.

As the unit cost of an X-type CB is circa £28.6k more expensive, a total CSF adjustment of £3.83m.

Lastly, the X-type LV boards are also more complex as they have a LV air CB included as part of the unit

protection scheme to automatically isolate the LV board for a fault on the 11kV network. For this reason, the

X-type LV board has a higher unit cost that the radial equivalent. We have conservatively assumed that on a

traditional radial network, the same volumes of LV boards would be replaced, though lower-cost, traditional

LV boards would be required.

The unit cost of the X-type LV board is £1.5k more expensive. We plan to replace 89 LV boards in X-type

secondary transformers in RIIO-ED2 due to age and condition, leading to a CSF adjustment of £0.13m.

These adjustments are summarised in Table 5.

Changes from ED1

The additional cost and complexity of X-type RMUs was identified as an additional cost in the ED1 Company

Specific Factors, and the methodology for calculating this adjustment has not changed since ED1, which was

supported by multiple internal and external reviews (see Section 5.3). However, our ED2 CSF proposed

adjustment has decreased significantly from the CSF adjustment of £5.64m in ED1 (5-year, 20/21 prices).

The decrease in total cost is due to a reduction in volumes to be replaced in ED2 compared to ED1 – the

planned investment in X-type RMU modernisation in ED1 was £26.7m. This compares to £8.59m planned for

ED2 (and an additional £5.39m planned for X-type CB replacement). Furthermore, there is a smaller

difference in X-type RMU unit cost between the transformer types in ED2 than was planned for ED1.

The additional cost and complexity of X-type CBs was not identified in ED1 Company Specific Factors, so

the cost was not included. This is considered to be an omission in the ED1 CSF submission. Additionally, the

costs of the ACBs on the LV boards that are unique to SP Manweb were also omitted.

Including the new cost areas, overall, the HV switchgear cost adjustment associated with the interconnected

network have gone down slightly from £5.64m in ED1 (5-year, 20/21 prices) to £4.15m planned for ED2.




61


As above, the options for HV switchgear modernisation are considered within the relevant EJP: ED2-NLR(A)-


replacement compared to the replacement of all Health Index HI5 assets.


As above, in the creation of our HV transformer modernisation plans, we have considered whether there are

ways to reduce the additional cost associated with the interconnected, unit-protected network through the

application of our Interconnected Network Transitioning Policy ESDD-01-013 – see Section 5.7.3.1 for

details.

For this asset modernisation driven programme of work, the decision to plan for like-for-like replacement was

selected using engineering judgement of the network locations of the assets for replacement.


The driver for replacement of the X-type switchgear is to maintain the excellent performance and reliability

for our customers, whilst maintaining a safe and resilient network. The additional costs incurred by the SP

Manweb interconnected network are necessary to ensure there is no reduction in network performance, in

terms of increased customer interruptions, or network safety. As discussed in Section 4.1 on customer and




5.7.5 Secondary protection – 11kV batteries

5.7.5.1 CV7 - Asset replacement


As shown in Section 3.6 (see in particular Figure 19), the SP Manweb interconnected network requires

additional tripping batteries at secondary substations than is the case for radial networks, to support

operation of the X-type unit protection.

To estimate the additional cost, we have compared planned RIIO-ED2 investment in batteries and battery

chargers at secondary substations for SP Manweb’s interconnected network with that planned SP Distribution’s radial network, used for activities such as network automation or remote control. This is more conservative than comparing the volume of SP Manweb’s asset base to the industry average and scaling accordingly, as it accounts for any contribution to the total volume of batteries as a result of company-wide

design and investment policies. It also accounts for the slightly lower unit cost in SP Manweb.

Our planned investment in these assets in SP Manweb is £1.58m for batteries and £0.46m for chargers; the

planned investment in these assets in SP Distribution is £0.41m and £0.11m respectively. The difference in

these amounts results to a CSF adjustment of £1.52m (shown in Table 5).

Changes from ED1



Section 5.3).

Our ED2 CSF proposed adjustment of £1.52 has increased slightly from the CSF adjustment of £1.0m in

ED1 (5-year, 20/21 prices). This is due to a slightly increased planned spend in these areas in ED2: £2.04m

in SP Manweb and £0.51m in SP Distribution, compared to £1.26m and £0.25m in ED1, respectively.


62




For HV battery modernisation needs, the options are considered within the relevant EJP ED2-NLR(A)-SPEN-

001-PROT-EJP – Light Current, Protection and Pilots. It considers different options surrounding the timing of

battery replacement.


There are no feasible options that would move away from an interconnected system that reduce the volumes

of HV batteries that need to be modernised, and no innovations in this area. Therefore, the same cost

mitigation measures apply here as to the rest of our Totex plan.


The driver for replacement of the HV batteries is to maintain the excellent performance and reliability for our

customers, whilst maintaining a safe and resilient network. The additional costs incurred by the SP Manweb

interconnected network are necessary to ensure there is no reduction in network performance, in terms of

increased customer interruptions, or network safety. As discussed in Section 4.1 on customer and




5.7.6 LV Link boxes


As shown in Section 3.6.3, interconnected networks typically operate with the link boxes in their ‘closed’ position to improve security of supply, with current flowing through the assets during normal operation.

Additionally, when a fault occurs, the presence of multiple fault level infeeds imposes significantly more

demanding requirements. Hence the consequences of disruptive link box failures in interconnected networks

are far more severe than in traditional radial networks. Link boxes are critical to network switching, to

minimise disruption to customers while working on the network and to restore supplies after a fault.

In RIIO-ED1, we saw the average annual link box disruptive failure rate increase by 1,045% with respect to

DPCR5 observed rates, due to asset age, condition and the interconnected nature of the SP Manweb

network. Both SP Manweb and UK Power Networks (UKPN), which operate interconnected networks,

experienced similar issues.

As a result, we developed a strategy to replace 8,008 link boxes at the end of their operational life, many of

which are located at highly challenging locations in the city centre and areas with limited accessibility.

Stakeholder feedback has been sought in the development of this strategy. SPEN has been in contact with

the HSE since disruptive failures volumes started to increase in 2015, and a number of workshops were

organised between HSE and SPEN to show the failed link boxes, while providing more information on the

extent of the damage, the last inspection and the outcomes of the inspection. The strategy is crucial to

ensure safety to the public and staff and aligns with HSE’s Guidance as stated in “Reducing Risks, Protecting People” (Health and Safety Executive, 2001).

In RIIO-ED1, Ofgem allowed an adjustment to SP Manweb's allowance to cover additional costs incurred

related to the efficient management of asset risk associated with link boxes, due to the >300% increase in

required Health Index HI5 link box replacements. The re-opener adjustment covered the direct costs of the

4,137 additional units delivered in RIIO-ED1, which we are on track to deliver.


63

The programme will conclude in 2025/26, with an additional 1,978 units delivered in RIIO-ED2 at a unit cost

of £7.5k.

As the allowed re-opener adjustment in ED1 was specific to SP Manweb and the number of faults is heavily

correlated with the operating and fault conditions of the interconnected network, we believe it is appropriate

to incorporate part of the LV link box cost in this RIIO-ED2 CSF.

The adjustment is based on a comparison to the volumes in our SP Distribution area, where we plan to

deliver 95 units (at the same unit cost). This leads to a CSF adjustment of £14.06m (shown in Table 5).

We believe this is the most appropriate comparison, given that both licence areas are underpinned by the

same asset management policies. In our comparison we have conservatively not accounted for the larger

size of the SP Distribution network.

Changes from ED1

This is a new inclusion to the Company Specific Factor adjustment.

The re-opener adjustment covered the direct costs of the 4,137 additional units delivered in RIIO-ED1, which

we are on target to deliver. Link box assets in SP Manweb have been subject to intrusive inspection to

provide a health and risk index. As of 14/09/2020, 17,594 link boxes were surveyed, of which 3,279 were

replaced.

The ED1 allowance adjustment was for a total of £23.4m to cover the direct costs only (the unit costs of the

equipment, and not the additional delivery support team). Consistent with this (and in line with all other non-

load related expenditure parts of the CSF) we have included just the direct costs in our CSF adjustment

calculation.




LV link box modernisation is covered under the asset modernisation strategy for LV switchgear outdoor

within the LV Outdoor Switchgear EJP – ED2-NLR(A)-SPEN-001-SWG-EJP. It considers different options

surrounding the volume, timing and scope of Health Index HI4 or HI5 switchgear replacement.


There are no identified cost saving measures applicable to link boxes in the context of our Company Specific

Factor adjustment. Therefore, the same cost mitigation measures apply here as to the rest of our Totex plan.


The key driver for replacement of the LV link boxes is to manage overall levels of network risk, whilst

maintaining the excellent performance and reliability for our customers. The additional costs incurred by the

SP Manweb interconnected network are necessary to ensure there is no reduction in these standards

through increased risk of failure.

As discussed in Section 4.1 on customer and stakeholder engagement, our customers consider network

reliability to be of utmost importance. A reliable network will become even more important as customers rely

on their electricity for an increasing proportion of their energy needs, such as heating and transport, as part

of the Net Zero transition.


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5.7.7 Pilot wires – 33kV and 11kV



The SP Manweb interconnected network requires robust communications channels for its unit protection to

operate effectively and reliably to avoid unnecessary CI/CML should a fault occur. Pilot wires are an integral

part of SP Manweb’s unit protected design for both its 11kV and 33kV interconnected network.

For a typical radial network, a direct comparison of pilot wires in the EHV network is not available. Though

much less extensively, other DNOs do utilise pilot cables in 33kV networks protection, particularly with

intertrip signalling. However, due to disparity in volumes, no direct comparison from which to calculate an

adjustment is available. Furthermore, during RIIO-ED2 the SP Distribution network does not plan any

investment in this asset base.

Therefore, we have used the 2019 V1 Asset Register from the DNO datashare to assess industry pilot wire

volumes – see Figure 33.

Figure 33: Industry volumes of pilot wire (from V1 DNO Asset Register 2019)

SP Manweb has over five times the length of pilot wires than industry average, and twice that of the next

highest DNO. In line with our headline approach – that we consider SP Distribution to have the best

comparative radial network design – we have assumed SP Manweb would have the same volume of pilot

wires if it were also of radial design. SP Manweb has approximately four times the volume of underground

pilot wires to SP Distribution, leading to 75% of underground pilot wire investment being attributed to the

special case. This is considered to be a conservative comparison due to SP Distribution being a larger

network, and is a more conservative than a comparison with the GB average. Furthermore, normalising kms

of pilot wire (either by customer, by km of network, or by GWh distributed) would result in a larger difference.

In RIIO-ED2, in the 33kV (HV) network, we have planned approximately 7.5km of targeted short section

overlays of poorly performing underground pilot cables at an average cost of £140.7k per km. We have also

planned 23.5km of pilot cable as part of our 33kV cable modernisation plan, at an average cost of £42.4k per

km as the pilot will be installed with the associated 33kV interconnector cable. This is a total spend of £2.1m.

Using the ration above, we calculate that we would need to spend £0.5m if SP Manweb were designed as a

radial network. This leads to a total adjustment of £1.5m towards the CSF.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

km

OH UG


65

In the interconnected 11kV (HV) network, pilot wire is present along all interconnected cable routes, which

conservatively make up ~50% of all cable routes. This compares to virtually no pilot wire requirement in a

traditional radial network at 11kV, and so we assume pilot wire costs at 11kV are wholly attributed to the

unique interconnected and unit protected network. We have planned approximately 5km of targeted short

section overlays of poorly performing underground pilot cables in the 11kV network in RIIO-ED2, at an

average cost of £118.9k per km. We have also planned 23.3km of pilot cable as part of our 11kV cable

modernisation plan, at an average cost of £30.8k per km, as the pilot will be installed alongside

approximately 50% of 11kV. This leads to a total cost of £1.31m towards the CSF.

In summary, the above activities for underground pilot cables, for both 33kV and 11kV interconnected

circuits represent an overall £2.8m towards the CSF.

Finally, for overhead pilots, we plan to replace 47km of end of life ‘Hardex’ pilot cables on the overhead EHV network over RIIO-ED2. For overhead cable a combination of overhead and underground fibre-based

technology must be deployed since Hardex – the self-supporting pilot cable which is ‘under slung’ from 33kV overhead lines – no longer has a recognised manufacturer. As a result, a further 39 Hardex protection

schemes also need to be upgraded. This replacement programme is unique to Manweb, and is required to

maintain protection signals for the interconnected network18. The average cost of each replacement is

£18.5k per km of Hardex and £23.7k per protection scheme, leading to a total cost of £1.8m towards the

CSF (shown in Table 5).

Changes from ED1

The methodology for calculating the CSF in ED1 for overhead line pilots, e.g. ‘Hardex’ was the same as we propose for ED2 as part of plans to replace a unique and obsolete asset on SP Manweb’s 33kV overhead network. The cost of upgrading the protection schemes alongside the Hardex replacement was not

specifically called out in the ED1 Company Specific Factor, which may have been an omission in the ED1

submission.

With regard to underground pilot cables we have taken a similar approach to ED1. However, we have

differentiated between those pilot cables that, due to their performance or condition, need replacement along

a short section and those pilot cables that will be replaced in conjunction with plans to overlay a 33kV or

11kV interconnector cable. In line with wider methodology improvements, we have also compared the SP

Manweb plans to an equivalent radial network based on SP Distribution volumes (more conservative than

industry average volumes), rather than taking a direct comparison between the two ED2 plans.


The optioneering for the short-section pilot repairs is detailed in EJP is ED2-NLR(A)-SPEN-001-PROT-EJP –

Light Current, Protection and Pilots. The optioneering for the overlay of pilot cables in parallel to cable

modifications is detailed in D2-NLR(A)-SPEN-002-UG-EJP for 11kV and ED2-NLR(A)-SPEN-001-UG-EJP

for 33kV.


The monitoring and testing of pilot cables is undertaken routinely as part of our planned inspection and

maintenance activities to ensure we are able to prioritise appropriate interventions to maintain their

performance and reliability. This may require just replacement of short sections of pilot cable or where the

performance of the power cable means it is efficient to combine the pilot and power cable overlay

replacement works.

18 The entire EHV network is unit protection in order to support the unique design and operation of the SP Manweb network.


66


The ED2 plan is based on the ‘Engineering Net Zero’ model, that will deliver our customers’ requirements as the UK transitions to Net Zero, whilst maintaining a safe, resilient and efficient network.

SPM’s 33kV and 11kV network provides leading performance in terms of reliability with the lowest CI of all

UK DNOs – the proposals for pilot cable modernisation are critical to the maintaining the integrity and

reliability of the network.

5.7.8 Primary substation sites

5.7.8.1 Primary site numbers

As well as primary transformers, SP Manweb also have a greater volume of primary sites due to the meshed

network design. This drives a number of additional costs throughout our non-load related expenditure plan, as

set out in the following sections.

Figure 34: Left: Primary sites per TWh distributed, Right: Primary sites per 100,000 customers. Showing SP

Manweb compared to SP Distribution, industry average and industry median. Source: V1 asset register.

We estimate SP Manweb has 110% more primary sites than it would if it were designed as a traditional

network. To do this, we have compared SP Manweb’s number of primary substations with the number in SP Distribution (SP Manweb have 78% more of these sites than SP Distribution) and accounted for the difference

in size of network, using the number of units distributed (SP Distribution distributes 18% more units than SP

Manweb). This is more conservative than using the industry average or industry median of the comparisons

considered, shown in Figure 34.

5.7.8.2 CV10 – Civil works


Our proposed condition-based civil strategy is vital to ensure that all civil assets and buildings are kept in a

good condition to maintain safe and secure sites to protect members of the public, staff and network assets,

maximising the life of our electrical equipment. This may comprise of, but not limited to, maintenance, repair

or replacement of doors, fencing, walls, roofs, building services, building structures, drainage infrastructure,

paths, roadways and plant supporting structures.

In RIIO-ED2, SP Manweb plan to perform civils modernisation work at 390 indoor primary substations. If SP

Manweb were a radial network. We calculate that we would need to replace 390 × 12.1 = 186 primary

-

10

20

30

40

50

60

70

80

SPM SPMscaled

SPD Industryaverage

Industrymedian

Primary sites per TWh distributed

-

10

20

30

40

50

60

70

80

SPM SPMscaled

SPD Industryaverage

Industrymedian

Primary sites per 100,000 customers


67

transformers if SP Manweb were designed as a radial network. (Secondary civil modernisation is discussed

in Section 5.7.9.1)

However, although there are more primary substations in SP Manweb, the average modernisation cost seen

over RIIO-ED1 is lower than for SP Distribution - £15k compared to £21.6k. We have therefore accounted for

this by using the SP Distribution unit cost in the comparison. This results in a CSF adjustment of £1.89m

(shown in Table 5).

Changes from ED1

In the ED1 CSF, there was an adjustment proposed for primary site civil modernisation. However, the

detailed analysis into equivalent site volumes was not conducted. The adjustment was calculated as the

difference between SP Manweb and SP Distribution. This resulted in a proposed adjustment of £6.4m (8-

year, 12/13 prices). Overall, the investment in CV10 in has gone down considerably from ED1 to ED2, and

the CSF adjustment reflects this.

In the assessment of the ED1 CSF, Ofgem’s consultants DNV GL agreed that SP Manweb will incur extra

substation civil costs due to the higher number of substations on an interconnected network. DNV GL agreed

with the assessment of the number of additional assets; however, they believed there was insufficient

evidence that the unit cost of civil works was higher in SP Manweb. DNV GL used the lower unit cost from

SP Distribution to reduce the claim by roughly 10%.

In ED1, SP Distribution civil repair work was more reactive, whereas SP Manweb had a dedicated

programme to close out all Health Index HI4 & HI5 defects, resulting in higher unit costs for SP Manweb. The

actual and forecast remaining costs against the Company Specific Factor in ED1 will be calculated using the

updated methodology and reported in the BPDTs under the M25 Company Specific Factor memo table.

However, following this programme of modernisation work, the planned unit cost for ED2 is now in line with

DNV GL’s previous expectations, in fact the planned unit costs for SP Manweb in ED2 is now significantly

lower as shown above. We have therefore been conservative by using the SP Distribution unit cost to

calculate the ‘equivalent radial network’ for comparison. Furthermore, there are reduced volumes of primary

sites requiring civil work.

This results in a significant reduction in the proposed ED2 adjustment of £1.89m from the CSF allowance of

£4.34m in ED1 (5-year, 20/21 prices).


If instead of using the comparative volume of sites to scale the expenditure we had compared the planned

primary civils expenditure between SP Manweb (£5.9m) compared to SP Distribution (£7.2m), this would

have resulted in no adjustment. However, this would not account for the scale of SP Manweb and

furthermore SP Manweb had a more proactive programme in ED1 that will be completed ahead of ED2. SP

Distribution on the other hand are proposing a full proactive programme with named substation projects in

ED2. Therefore, we do not feel this is a fair or representative comparison.

The options for civils modernisation are covered in the relevant EJP: ED2-NLR(A)-SPEN-002-RES-EJP –

CV10 Condition Driven Civils. The optioneering covers various timescales for modernisation.



primary substation buildings that need to be modernised. However, the planned civils repair and

maintenance costs associated with primary substations are also higher in SP Manweb due to the volume of

primary sites – as covered in Section 5.8.3.6. The preferred civil modernisation programme selected as the

most cost effective and correct solution to reduce future maintenance costs.


68


The driver for civils condition improvements is to maintain the excellent performance and reliability for our



increased customer interruptions, or in network safety. As discussed in Section 4.1 on customer and




5.7.8.3 CV11 – Op IT and telecoms – RTU replacement


Constant monitoring and control of the primary networks are critical to ensure a safe, secure and reliable

supply to all customers. The Supervisory Control and Data Acquisition (SCADA) system is the means by

which each item of plant on the network is securely monitored and controlled in real time. SCADA enables

the network to be managed including remote control of plant for planned and unplanned works and recovery

of critical alarms and indications. SCADA is not only critical for network management but also safety

management, risk mitigation and resource response.

Managing the electrical network requires constant data communications between the SPEN control room

and substations. Remote Terminal Units (RTUs) take the signals from all the plant in the substation and

convert them to signals suitable to be transmitted to the SPEN control room.

The main drivers for the replacement of legacy RTUs are obsolescence and associated support issues. In

RIIO-ED2, SP Manweb plan to perform 296 remote terminal unit (RTU) replacements at primary sites, at a

total cost of £3.18m, in order to ensure continued robust operation of the telecoms systems. In line with the

approach as above, due to the high number of primary sites in SP Manweb, we calculate that this is

equivalent to a replacement programme of only 296 × 12.1 = 141 RTUs if SP Manweb were designed as a

radial network. This results in a CSF adjustment of £1.67m (shown in Table 5).

Changes from ED1

In the ED1 CSF, there was an adjustment proposed for RTU replacement, calculated as the difference

between SP Manweb and SP Distribution. This resulted in a proposed adjustment of £6.4m (8-year, 12/13

prices).

In the assessment of the ED1 CSF, Ofgem’s consultants DNV GL agreed that SP Manweb will incur extra primary RTU costs due to the interconnected network. However, DNV GL could not see why the ratio of

RTUs between SPM and SPD differed from the ratio of primary substations – which it calculated as 1.63, and

so recommended that this lower ratio be applied. The allowed adjustment was £2.59m (5-year, 20/21 prices).

We agree with the logic followed by DNV GL, and more detailed analysis to derive a radial equivalent site

volume has since been conducted for ED2. This scaling factor is the most appropriate comparison, as it

removes any influence from programme differences that are driven by historical asset strategies in SP

Manweb and SP Distribution, and is purely driven by the topology of the network. The RTU volumes

correlate with the volume of substations. However, the ratio calculated by DNV GL (1.63) appears to have

been based on the planned ED1 Black Start interventions at SP Manweb substations compared to at SP

Distribution substations. This was specific only to the Black-Start activities. The correct ratio is 2.1, as

explained at the start of this section (Section 5.7.1). In the updated approach above, we have shown that our

assessment of primary substations in SP Manweb compared to an equivalent radial network (i.e. including of

equivalent size) is conservative.


69




The preferred solution for RTU replacement is compared against the ‘do nothing’ option in EJP ED2-NLR(O)-

SPEN-001-RTU-EJP – Primary RTU Replacement.



primary substations and therefore reduce the volumes of communications equipment requiring

modernisation.

The EJP outlines how the move to modern SCADA protocols as part of the RTU replacement programme is

a cost-effective option. Although it is possible to carry out bespoke development works to enable legacy

protocols on modern RTUs and this would have reduced the work required on the telecoms infrastructure,

this would have added significant RTU development costs, severely limited vendors capable of providing a

solution and would have failed to deliver the required level of cyber security. Based on experience, bespoke

engineered RTUs are more expensive to purchase than industry standard equipment. Failure to move to

industry standard equipment would have resulted in extremely high RTU costs (in comparison to industry

averages) both to SPEN and third parties wishing to connect to our network.


The driver for RTU replacement is to maintain the excellent performance and reliability for our customers,

whilst maintaining a safe and resilient network. The additional costs incurred by the SP Manweb






5.7.8.4 CV11 – Op IT and telecoms – 33kV infrastructure improvements


In RIIO-ED2 and beyond, a significant programme of work is required to modernise and improve the 33kV

telecommunications in SP Manweb. Our strategy for RIIO-ED2 is to maintain the legacy network, replace

obsolete equipment, and add supporting Operational Data Network (ODN) across the primary network in SP

Manweb. This solution retains more of the existing infrastructure over the period of RIIO-ED2, which

represents an initial cost saving19. This amounts to a total programme spend of £20.17m.

As the increased volume of primary sites leads to proportionately higher telecoms infrastructure

requirements, we have scaled the non-DSO spend according to the number of primary sites in SP Manweb

compared to a radial equivalent radial network. We calculate an equivalent programme of work would

therefore cost £20.17m × 12.1 = £9.61m if SP Manweb were designed as a radial network. This results in a

CSF adjustment of £10.56m (shown in Table 5).

19 Replacement of end-of-life equipment will not be completed during RIIO-ED2 and significant expenditure will

be required in RIIO-ED3 to extend the programme.


70

Changes from ED1

In the ED1 CSF, there was an adjustment proposed for telecoms infrastructure replacement, calculated as

the difference between SP Manweb and SP Distribution. This resulted in a proposed adjustment of £4.7m (8-

year, 12/13 prices). It is our view that, for this programme of work, a direct comparison between SP Manweb

and SP Distribution in ED1 led to an overly conservative comparison.

As above (Section 5.7.8.3), in the assessment of the ED1 CSF, Ofgem’s consultants DNV GL agreed that SP Manweb will incur extra primary telecomms infrastructure costs due to the interconnected network but

recommended that in fact a lower ratio (1.63) be applied. The resultant, allowed adjustment was £3.2m (5-

year, 20/21 prices). Also as described above (Section 5.7.8.3), whilst we agree the ratio of primary

substations is an appropriate scaling factor, the 1.63 ratio was incorrectly calculated – the correct primary

substation ratio is 2.1 as explained at the start of this section (Section 5.7.1). The corrected scaling factor

based on a radial equivalent volume of primary sites is the most appropriate adjustment method, and in the

updated approach above, we have shown that our assessment of primary substations in SP Manweb

compared to an equivalent radial network (i.e. including of equivalent size) is conservative.

Finally, it is clear that overall, the proposed adjustment in this area had increased significantly from ED1 to

ED2. This is driven by an ambitious programme of modernisation and a resultant greater level of expenditure

planned for ED2 – £20.4m compared to just £10m in ED1 (8-year, 12/13 prices).




The other options considered are detailed with the relevant EJP, ref. ED2-NLR (0)-SPEN-003-TEL-EJP,

which considers a do nothing approach as well as exploring alternative existing and different technologies,

as well as site requirements.

The proposal for RIIO-ED2 maintains the separation of technology and services which will sustain the cyber

security profile of the service as well as being the most efficient to meet network performance requirements.



primary substations and therefore reduce the infrastructure investments required. However, the preferred

solution maximises use of the existing infrastructure over the period of RIIO-ED2, which represents an initial

cost saving and reduces any asset stranding risk.


The driver for telecommunications network is to support a range of critical services that are required to

ensure safe, reliable, and secure electrical network management system. The services provide the following

functionality: -

• Protection signalling to protect people and assets in the event of faults.

• Supervisory Control and Data Acquisition (SCADA) monitoring for the electrical network.

• Operational telephony across the control rooms and sub-stations.

• Additional capability for cyber security enhancements such as Incident Event Monitoring.

• The capability to transfer data for applications such as security management and detailed electrical

phasor point measurements.

• Support the growth of the distributed generation activities.


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5.7.8.5 CV11 – Op & IT&T – operation and maintenance (including pilot rentals)


As stated in Section 5.7.7 above, the SP Manweb interconnected network relies heavily on pilots wires for

effective operation of its unit protection between primary substations and remote monitoring and control of

33kV switchgear at substations. In non-urban areas, other than the Hardex referred to above, where we use

overhead line circuits rather than underground cables, we do not own our own pilot wires. In this case we

rent third party communication channels from British Telecom and other service providers. The extensive

telecoms network to support the unit protected network also requires additional, specialist external support

from telecoms companies.

For a typical radial network, a direct comparison is not available. Other DNOs do have telecoms O&M

requirements, but to a much lesser extent on average. The detailed breakdown of these costs is not

available for us to compare.

However, broadly the telecoms O&M spend is directly proportional to the number of primary sites on a

network (based on the factor of 2.1 which is the SPM:SPD ratio).

Furthermore, the interconnected network has greater telecoms routine maintenance and repair costs also all

associated with the increased number of primary sites.

In RIIO-ED2, SP Manweb will invest a combined £21.42m on non-DSO telecoms O&M activities. This

includes Network Management Services (NMS), routine maintenance, repair management, leased lines

(“pilot rentals”) and ancillary services (such as JRC, airwave, and firewalls).

Of this, ancillary services are not considered eligible for a CSF adjustment, as this cost does not vary greatly

with size and topology of network. Approximately 76% of the remaining cost is attributed to 33kV networks20.

The resultant expenditure that is eligible for the CSF adjustment is therefore £15.10m.

We therefore calculate the equivalent expenditure would cost £15.10m × 12.1 = £7.20m if SP Manweb were

designed as a radial network. This results in a CSF adjustment of £7.91m (shown in Table 5).

Changes from ED1

In ED1, the cost adjustment in this area was significantly underestimated. Only the area of leased lines (pilot

rentals) was included, whereas it should have covered the wider operations and maintenance areas of the

pilot wire network, which requires specialist external support from telecoms companies. Our CSF adjustment

has increased from £1.07m in ED1 (5-year, 20/21 prices) to £10.03m in ED2.

In the assessment of the ED1 CSF, Ofgem’s consultants DNV GL agreed that SP Manweb will incur extra pilot rental costs; however, it is unclear why this was reduced. It appears to be a recalculation using SP

Distribution costs. However, the equipment costs at a disaggregated level are not dissimilar between SP

Manweb and SP Distribution – the driver for the difference in total costs is one of scale driven by the size of

the SP Manweb primary telecoms network and the additional line leasing (see EJP paper, reference ED2-

NLR (0)-SPEN-001-TEL-EJP, for details).

The cost of 33kV telecoms O&M activities excluding ancillary services in SP Distribution is £12.91m,

compared to SP Manweb’s equivalent cost of £15.10m. Therefore, a CSF adjustment calculated from a

direct comparison between SP Manweb and SP Distribution would be £2.19m; however, this is not

accounting for the sizes of the networks or the larger planned programme of spend in SP Distribution.

20 We have assumed all DNOs have pilot costs at the 132kV level. The total is scaled on the basis that there are over 6.2 times more

primary sites than 132kV sites, but that there is twice as much expenditure on average at 132kV sites than at primary sites.


72

Our review of this area of expenditure reflect the justified requirements of SPM’s unique network and is considered conservative as ancillary services have been excluded from the CSF calculation.


All constituent actions are compared against a ‘do nothing’ options in the EJP paper, reference ED2-NLR

(0)-SPEN-001-TEL-EJP – SPD & SPM Telecommunications Operations and Maintenance.



primary substations and therefore reduce the infrastructure investments required. This investment is

necessary to maintain the existing assets in a fit for purpose state and therefore avoid stranding.


The telecommunication network is critical to the safe operation and overall performance in terms of reliability

under both normal and abnormal network conditions.

The O&M function provides a range of services, enabling electrical protection services, provision of SCADA

capability, sub-station telephony and other data related activities, which without will result in significant

issues in the telecoms network that would have a consequential impact to the integrity of the distribution

network and to supply reliability.

5.7.8.6 CV12 – Electricity System Restoration (ESR - Black start) – interventions at primary substations


As recommended by the Government and the UK Electricity Industry, in RIIO-ED2 we will continue to

increase the resilience of our equipment on which the recovery process following a grid blackout relies. This

is achieved by installing backup power supplied capable of energising the necessary functions at key

locations on the network – including primary substations. These functions include remote control facilities,

data (SCADA) and voice communications, and protection systems. These power supplies can be either

generators or battery systems depending upon individual site requirements.

In SP Manweb, the RIIO-ED2 plan involves 648 site interventions at an average cost of ~£3.1k. To calculate

the cost of an equivalent radial network for comparison, we have taken into account two factors. The first is

to apply the site ratio calculated above to account for the additional number of primary sites in SP Manweb

compared to a radial equivalent radial network.

We have also applied a factor to take account for the inherent resilience of the interconnected network,

following feedback from the Ofgem and DNV GL review of our RIIO-ED1 CSF methodology for black start.

We have assumed that two of three primary substations in a group21 are required for the network to be

resilient and have a sufficiently energised system for a short period of time. We believe due to the high

utilisation of our network, this is a conservative comparison.

We therefore calculate that we would need to make 648 × 12.1 × 32 = 463 site interventions if SP Manweb were

designed as a radial network. This leads to a CSF adjustment of £0.57m (shown in Table 5).

21 In the interconnected network, operational groups of primary transformers typically comprise between three

and five primary transformers. More than two transformers would be required for resiliency in a larger group.


73

Changes from ED1

The method for deriving a radial equivalent network for comparison of black start costs has been updated to

include the updated site volumes and to account for feedback from the ED1 slow track determinations, as

above. Overall though, the additional adjustment has stayed the same: it is proposed at £0.57m in ED2 and

this was the allowed adjustment in ED1 (5-year, 20/21 prices).




Options for black start resilience are addressed in ED2-NLR(A)-SPEN-001-RES-EJP – Energy System

Restoration (ESR) (formally known as Black Start) with power supply optioneering including the installation of

generation at all core/critical substation sites, and reducing the resilience level to 3 days resilience in line

with previous policy.

Alternative approaches to calculating the CSF adjustment are not considered.


Alternative approaches that reduce the additional costs associated with the interconnected network are not

available.

The ESR EJP explains that there is relatively small cost increase between three- and five-day battery

systems relative to the higher costs of wholesale replacement prior to end of life, which makes the preferred

five-day solution the most economic, and provides best value to customers as a result.


The driver for black start is to maintain a safe and resilient network in the event of a network blackout. The

additional costs incurred by the SP Manweb interconnected network are necessary to ensure there is no

reduction in network performance, in terms of increased customer interruptions, or in network safety. Black

start resilience will become even more important as part of the Net Zero transition. Customers rely on their

electricity for an increasing proportion of their energy needs, meanwhile the chances of blackouts may

increase as increased amounts of electricity are generated by renewable technology, which is more

intermittent and has less inertia than conventional, fossil-fuel power plants.

5.7.8.7 CV14 – Site security


To ensure we meet minimum legislative requirements detailed in the Electricity, Safety, Quality and

Continuity Regulations (ESQCR), all substations are required to have adequate security measures in place.

We plan to progress an intervention strategy over multiple price control periods (ED2, ED3, & ED4) that

covers the programmes of works to upgrade, install or refurbish security systems including, but not limited to;

intruder detection systems, access control or locking, perimeter intruder detection, and security lighting

installed within the substations.

The greater number of primary sites leads to an additional cost associated with our site security

requirements. At our 33kV primary substations the main programme is focused on upgrading our building

alarm systems to a modern standard. This involves targeting our highest risk sites, sites where the alarm

systems are end of life and connection of existing alarm systems into our alarm receiving centre to allow a

standard monitoring of alarms across our substation fleet. Sites where security risk is higher than normal,

additional measures may be taken to including higher security fencing, perimeter detection or CCTV.


74

We plan make a total of 523 interventions at 33kV primary substations at an estimated cost of £4.5k per site.

Using the same method as above, we have compared SP Manweb’s number of primary substations with a typical radial network comparator. We therefore calculate that we would need to upgrade just 523 × 12.1 =249 primary sites if SP Manweb were designed as a radial network. This results in a CSF adjustment of

£1.23m (shown in Table 5).

Changes from ED1

There was no inclusion of site security (or indeed any wider legal and safety) costs in the CSF adjustment in

ED1, which was an oversight in the ED1 submission. This cost has been emphasised by the more holistic,

top-down assessment of the consequences of the different primary-site volumes in SP Manweb compared to

an equivalent, radial network.




Options for site security are covered in ED2-NLR(A)-SPEN-002-SAF-EJP. The optioneering covers

comparison against the “do nothing” scenario, which is rejected on the basis of ensuring regulatory and legal

requirements. The chosen option presents the “do minimum” solution.



available. The EJP explains that the best net present value solution has been chosen, which is also the

lowest cost option.


The driver for site security modernisation is to keep members of the public safe, and to protect our

equipment, which maintains the excellent performance and reliability for our customers, whilst maintaining a

safe and resilient network. The additional costs incurred by the SP Manweb interconnected network are

necessary to ensure there is no reduction in the levels of security.





5.7.8.8 CV14 – Asbestos management


The Control of Asbestos Regulations 2012 (CAR 2012), Part 2, Regulation 4, places a legal duty on SP

Distribution and SP Manweb to manage asbestos within the sites and buildings within our network. In line

with these regulations, we must carry out assessment of all premises to determine the presence of asbestos,

and manage the risk associated where asbestos is identified.


75

Our forecast volumes of interventions in SP Manweb is higher than in SP Distribution due to more primary

interventions22.

In RIIO-ED2, SP Manweb will invest a total of £1.65m spent on asbestos management activities, of which

approximately £388k23 will be spent at primary sites. We calculate an equivalent programme of work would

therefore cost £0.39m × 12.1 = £0.19m if SP Manweb were designed as a radial network. This results in a CSF

adjustment of £0.20m (shown in Table 5).

Changes from ED1

As above, legal and safety costs were not included in the CSF adjustment in ED1, which was an oversight in

the ED1 submission. This included asbestos management costs. These costs have been identified through

the more holistic, top-down assessment of the consequences of the different primary-site volumes in SP

Manweb compared to an equivalent, radial network.




Options for asbestos management are covered in ED2-NLR(A)-SPEN-001-SAF-EJP. The optioneering

covers comparison against the “do nothing” scenario, which is rejected to ensure compliance with regulatory

and legal requirements. The chosen option presents the “do minimum” solution.




lowest cost option.


The driver for site asbestos management is to keep our staff and members of the public safe. The additional

costs incurred by the SP Manweb interconnected network are necessary to ensure there is no reduction in

the levels of safety.

5.7.8.9 CV14 – Fire management


SP Energy Networks’ (SPEN) Substation Fire Protection Policy (SUB-01-012 Issue 3, 2018) sets out the

overarching guidance that we require to follow to ensure compliance with fire safety legislation at

substations. In line with this policy, in RIIO-ED2 we will undertake an extensive programme of Fire Risk

Assessments (FRAs) at all our substation locations and a dedicated programme to close out actions raised,

as well as fire systems upgrades at grid and primary sites.

The investment at SP Manweb primary sites is as follows:

22 Volumes of secondary site interventions in SP Manweb is also higher than in SP Distribution, due to the greater number of indoor

substations – as discussed in Section 5.7.8.2. Secondary site volumes in SP Manweb are 40% higher than in SP Distribution, and this 40%

represents about 20% of all volumes in SP Manweb. This should lead to a necessary adjustment for secondary sites of similar scale to

primary sites, but it has not been included as it would have been a late addition to the plan. However, this exclusion also ensures the

adjustment for asbestos management is conservative overall – this is important as we do not have the data to account for unit cost or

average ‘per site’ differences in a radial network, which may be higher. 23 Workstream totals that are not usually disaggregated have been split across grid, primary and secondary sites activity volumes to get this

value.


76

• A cost of £0.64m for the FRA programme

• A forecast 530 sites will require primary site ‘system upgrade’ actions (at ~£500 per site)

• A forecast 53 sites will require primary site ‘close out’ actions (at ~£5k per site)

Using the primary site scaling factor, if SP Manweb were designed as a radial network, we calculate an

equivalent programme of work would be as follows:

• £0.64m × 12.1 = £0.30m cost for the FRA programme

• 530 × 12.1 = 253 sites would require primary site ‘system upgrade’ actions (at ~£500 per site)

• 53 × 12.1 = 25 sites would require primary site ‘close out’ actions (at ~£5k per site)

The total spend on fire protection activities if SP Manweb were designed as a radial network would therefore

be £0.56m. This results in a CSF adjustment of £0.61m (shown in Table 5).

Changes from ED1

As above, legal and safety costs were not included in the CSF adjustment in ED1, which was an oversight in

the ED1 submission. This included fire protection costs. These costs have been identified through the more

holistic, top-down assessment of the consequences of the different primary-site volumes in SP Manweb

compared to an equivalent, radial network. Furthermore, the overall levels of investment in fire protection will

increase significantly in RIIO-ED2 compared to RIIO-ED1 – as shown in Engineering Justification Paper

ED2-NLR(A)-SPEN-003-SAF-EJP - CV14 Legal and Safety - Fire Protection.




Options for fire protection are covered in ED2-NLR(A)-SPEN-003-SAF-EJP. The optioneering covers

comparison against the “do nothing” scenario, which is rejected to ensure compliance with regulatory and

legal requirements. The chosen option presents the “do minimum” solution.




lowest cost option.


The driver for fire protection activities is to keep our staff and members of the public safe, and also to protect

our equipment, which maintains the excellent performance and reliability for our customers. The additional

costs incurred by the SP Manweb interconnected network are necessary to ensure we reduce fire risk as far

as reasonably practicable.






77

5.7.8.10 CV16 – Flood resilience


Items of plant and equipment across our network can be susceptible to operational issues because of

flooding resulting in wider issues with the network and loss of supply. Our strategy for RIIO-ED2 is to ensure

all new substations are constructed and plant installed in locations, and at levels which guard against

flooding. Where existing network assets are at risk from flooding appropriate flood protection measures shall

be implemented to protect the assets from flooding.

For primary sites, all existing primary substations identified within the flood risk areas, where no adequate

defences are currently in place, shall have a detailed flood risk assessment completed by a specialist

contractor. Where the site assets are proved to be at risk of flooding, appropriate flood prevention measures

shall be implemented, where reasonably practicable to do so.

This results in a programme of work at primary sites of £2.46m. In line with the approach as above, we have

scaled this spend according to the number of primary sites in SP Manweb compared to a radial equivalent

radial network. We calculate an equivalent programme of work would therefore cost £2.46m × 12.1 = £1.17m if SP Manweb were designed as a radial network. This results in a CSF adjustment of £1.29m (shown in Table

5).

Changes from ED1

There was no inclusion of flooding resilience costs in the CSF adjustment in ED1, which was an oversight in

the ED1 submission. This cost has been emphasised by the more holistic, top-down assessment of the

consequences of the different primary-site volumes in SP Manweb compared to an equivalent, radial

network.




The preferred option as presented in ED2-NLR(A)-SPEN-003-RES-EJP –Flood Resilience has been

presented as the only option available as failure to invest in flood mitigation will result in failure to comply

with recognised industry guidance and potential for unacceptable loss of supply during flood events.




available.

As set out by the EJP, there are numerous solutions available for flood mitigation ranging in permanence

and, therefore, cost. In every instance, the correct solution is installed to ensure protection is provided to the

necessary design flood level, while also ensuring the solution is cost effective.


The driver for flood resilience improvement is to maintain the excellent performance and reliability for our






their energy needs, such as heating and transport, as part of the Net Zero transition. Furthermore, the impact


78

of climate change in the UK is likely to be increased flood levels and frequency. This places additional

importance on the need for this improvement to be made to our network.

5.7.8.11 CV22 – Transformer bunds (Oil Pollution Mitigation Scheme at Operational Sites)


In RIIO-ED2, SP Manweb are undertaking a programme of work to mitigate against oil pollution, which

includes the replacement and addition of bunds to primary transformers. The programme is targeting existing

primary sites where intervention will have the maximum environmental benefit.

SP Manweb plan to add/replace 38 bunds at an average unit cost of £38.6k. The unit cost is equivalent to a

radial network as, although transformer sizes at primary substations vary between SPD and SPM, as a result

of the interconnected network equipment, bund sizes are relatively comparable. The size is driven by

footprint of the transformer more often than transformer rating, due to minimum distance from oil containing

plant to bund wall.

In line with the approach as above, we have scaled this spend according to the number of primary sites in

SP Manweb compared to a radial equivalent radial network. We therefore calculate that we would need to

replace 38 × 12.1 = 18 bunds if SP Manweb were designed as a radial network. This results in a CSF

adjustment of £1.47m (shown in Table 5).

Changes from ED1

There was no inclusion of transformer bunding costs in the CSF adjustment in ED1, which was an oversight

in the ED1 submission. This cost has been emphasised by the more holistic, top-down assessment of the

consequences of the different primary-site volumes in SP Manweb compared to an equivalent, radial

network.




The options for primary transformer bunding are presented in ED2-NLR(A)-SPEN-002-ENV-EJP

Environment – Oil Pollution. The optioneering covers alternative options including the installation of bunds at

all non-bunded sites within ED2, and the use of different bund types.




available.

As set out by the above EJP, the use of HDPE bunds over concrete bunds where appropriate can reduce

cost due to the prefabricated nature of the design, lower ground preparation requirements and significantly

reduced time on site. Subject to site requirements, we have utilised an overall average unit cost.


The driver for transformer bunding, and the mitigation of oil release, is to reduce our environmental footprint

and protect the natural environment. This is an important driver in itself, there are limited links to other

strategic aims.


79

5.7.9 Secondary substation sites

5.7.9.1 CV10 – Civil works


As discussed in Section 5.7.8.2 for primary substations, our proposed condition-based civil strategy ensures

buildings are kept in a good condition to maintain safe and secure sites.

As discussed in Section 3.6.1 and supported by multiple internal and external reviews (see Section 5.3), the

unique SP Manweb interconnected unit protection requires secure well heated/ventilated buildings to remain

serviceable. As a result, SP Manweb has a larger number of brick-built secondary substations than other

DNOs with radial networks, which use more open compound and glass reinforced plastic (GRP) style

substations.

At the time of writing, a survey of the SP Manweb secondary substations is underway, which should reveal

more accurate numbers of brick-built substations, their condition, and the additional costs of repair. To

calculate the CSF adjustment in the interim, we have used the volumes of all indoor substations.

We have compared SP Manweb’s number of indoor substations with the number in SP Distribution, as a typical radial network comparator. In SP Manweb, over 90% of all GM HV substations are indoor – the

highest percentage of any DNO. SP Manweb have 61% more of these sites than SP Distribution. In ED2, SP

Manweb plan to perform civils modernisation work at 2,020 indoor secondary substations, at a unit cost of

£2.6k. We therefore calculate that we would need to replace 2020 × 11.61 = 1201 secondary substations if SP

Manweb were designed as a radial network. However, the SP Manweb average indoor site modernisation

cost seen over RIIO-ED1 is slightly lower than for SP Distribution (possibly due to economies of scale) –

£2.6k compared to £3k. We have used the SP Distribution unit cost in the equivalent network for

comparison. This results in a CSF adjustment of £1.59m (shown in Table 5).

Changes from ED1

In ED1 we compared the overall expenditure on brick-built substations between SP Manweb and SP

Distribution. Our previous estimate on brick-built substation volumes at ED1, SP Manweb has 5,197 such

substations in the ED1 plan compared to only 2,377 for SP Distribution, both at a unit cost of £4k for

maintaining brick buildings.

In the assessment of the ED1 CSF, Ofgem’s consultants DNV GL agreed that SP Manweb will incur extra

secondary site civils costs due to the interconnected network. However, they considered that the claim

should be reduced to reflect the lower number of non-brick sites that will need investment and therefore

recommended that the claim be reduced from £10.1m to £7.5m (8-year, 12/13 prices).

As our updated assessment is now based on all indoor substations, and therefore captures the lower unit

price, we believe this is now a more conservative comparison in line with the previous comments.

Overall, however, due to the much-reduced volumes of sites to be modernised in ED2 compared to ED1, the

proposed adjustment has significantly reduced – £1.57m in ED2 compared to allowed adjustment of £5.72m

in ED1 (5-year, 2021 prices).



The options for civils modernisation are covered in the relevant EJP: ED2-NLR(A)-SPEN-002-RES-EJP –

CV10 Condition Driven Civils. The optioneering covers various timescales for modernisation.


80


There is no real alternative to reducing the civils costs, e.g. by converting from X to Y-type transformers and

removing the unit protection equipment. The reduction is costs would only materialise if the substation is

demolished and replaced with a GRP or other containerised housing, with a much higher up-front cost and a

long payback period. Furthermore, the majority of these assets are in the community and this would prove in

the majority of situations to be unacceptable to our customers from an aesthetic perspective. It is possible

that the necessary planning consents may be difficult to achieve.


The driver for civils condition improvements is to maintain the excellent performance and reliability for our







5.8 Network operating costs

A breakdown of the CSF Network Operating Costs is shown in Table 6, and a detailed rationale for the

individual costs follows beneath.

Table 6: Network operating costs expenditure plan

Asset categories

SP Manweb

Interconnected

Network

Equivalent Radial

Network

Resultant

CSF

adjustment

Category

Volume Cost

(£k) Volume

Cost

(£k) (£m)

CV26 Faults

33kV Underground Cable

Repairs (Non-Pressure

Assisted) (§ 5.8.1.1)

339.5 10.33 143.00 10.33

2.03

LV Underground Network

• LV switching only

• UG Cables (Non

CONSAC) - Asset

Repair/Replacement

Required

• Plant & Equipment

LV link boxes only

1 5,590.76 - -

5.59

CV30

Inspections

Primary substations -

thermovision 1 55.77 - - 0.06

CV31 Repairs

&

Maintenance

33kV RMU (§ 5.8.3.1) 828 0.52 - - 0.43

33kV CB (Air Insulated

Busbars) ID (GM) (§ 5.8.3.1) 1,530 0.24 557.41 0.24 0.23

33kV CB (Air Insulated

Busbars) OD (GM) (§ 5.8.3.1) 720 0.06 176.33 0.06 0.03


81

Asset categories

SP Manweb

Interconnected

Network

Equivalent Radial

Network

Resultant

CSF

adjustment

33kV CB (Gas Insulated

Busbars ID (GM) (§ 5.8.3.1) 2,478 0.10 850.37 0.10 0.16

33kV CB (Gas Insulated

Busbars OD (GM) (§ 5.8.3.1) 1,055 0.12 527.50 0.12 0.06

Batteries at 33kV Substations

(§ 5.8.3.1) 6,270 0.12 2,987.89 0.12 0.38

33kV Transformer (GM)

(§ 5.8.3.4) 4,010 0.31 2,506.25 0.31 0.46

ACB on LV Board (X- Type

Network) (WM) (§ 5.8.3.2) 1,000 0.10 - - 0.10

6.6/11kV X Type RMU

(§ 5.8.3.2) 2,000 0.70 2,000.00 0.51 0.38

Batteries at GM HV

Substations (X type only)

(§ 5.8.3.2)

7,500 0.10 3,073.77 0.10 0.44

Secondary HV CBs (X-type)

(§ 5.8.3.2) 1,160 0.30 - - 0.35

Pilot Wire underground

(§ 5.8.3.5) 365 1.50 - - 0.55

Protection schemes (X-type

only at HV/EHV sites)

(§ 5.8.3.3)

2,215 0.52 1,683.40 0.52 0.28

Secondary civils (§ 5.8.3.6) 61,170 0.11 37,882.30 0.11 2.45

Primary civils (§ 5.8.3.6) 4,560 0.51 2,173.01 0.51 1.22

Total 15.20

5.8.1 CV26 Faults – cable repairs

5.8.1.1 EHV underground cables (non-pressure assisted)


SP Manweb interconnected network operates with high utilisation factors as described in Section 9. The

high utilisation factors offer many benefits in terms of reduced investment costs in some areas, however

operating at higher utilisation factors does increase the fault level of the systems and the fault current that

flows at the time of a circuit fault.

Under fault conditions the interconnected operational arrangements lead to higher circulating fault currents,

which coupled with power flows, (e.g. VARs), higher utilisation and circuit loadings, results in SPM’s 33kV cables being stressed more by increased thermal and mechanical expansion in cable/joints. This leads to

accelerated deterioration of cable insulation papers, in the vicinity of the fault compared to a radial network

design.


82

Figure 35: 33kV Cable Faults – RIIO-ED1 first five years showing the high anomalous values for both SPM

and SPD

Both SPM and SPD fault rates are affected by a known legacy trifurcating joint type issue, which is unique

to both licences, who over a 9-year period used a cold shrink type joint which was found to have an internal

defective component that resulted in an accelerated failure rate. A High Value Project (HVP) re-opener

application, referenced CRC 3F, was made in May 2019 to request increased levels of expenditure during

ED1 to target the proactive removal of known trifurcating joints was rejected. At the time, from a review

undertaken SPD had circa 1,805 (57%) defective joints and SPM circa 1,387 (43%) of the total joints

procured and installed during the period 2001/02 and 2010/11.

Considering this re-opener outcome, further analysis has been undertaken to compare SPM’s 33kV cable network performance and fault rate with all other UK DNOs taking account of the unique factors its

interconnected design has to its performance and failure rate. Several studies show that impregnated paper

insulation will deteriorate faster if heated. One of the studies is from CIRED 2011, which states that as

temperature increases, the paper desorbs water (making it dry) and the impregnant absorbs water – the

converse is true as the cable cools, but over time the paper becomes less able to reabsorb moisture leaving

it permanently dry. An engineering paper presented at the 21st International Conference on Electricity

Distribution (CIRED) referenced ‘CIRED2011 PILC Ageing’, recognised the reduction of insulation life

correlated with operating temperature. Higher power flows (VArs) on an interconnected network will give

higher cable operating temperatures and therefore lower life expectancy, which will be exacerbated in

Manweb due to its unique interconnected design.

By excluding the “legacy trifurcating joint type issue” the CSF only compares the performance of SPM’s 33kV cable fault rate with other UK DNOs, and is illustrated in Figures 35 and 36, which compares SPM’s 33kV cable network length and fault rate with UK DNOs.

Even accounting for a known joint issue, unique to SP Manweb and SP Distribution, (which account for

approximately half the faults reported) the fault rate in SP Manweb is still 2 – 3 times higher than the median

of all other DNOs.

These are significant contributing factors to SP Manweb’s higher fault rate on the 33kV cable network.

240

31

102

113

162

77

125

364

356

30

230

92

775

697

0 100 200 300 400 500 600 700 800 900

ENWLNPGNNPGYSSEHSSESLPNSPNEPN

EMIDWMIDSWEST

SWALESSPD

SPM

33kV Cable Faults - RIIO-ED1 5 Years


83

Figure 36: 33kV Cable Faults – RIIO-ED1 first five years showing SPM fault volumes showing Trif Joint and

Non-Trif Joint related with the median/average of other UK DNOs excluding outlier SPD

Figure 37: 33kV Cable Faults – RIIO-ED1 first five years showing SPM fault rates per km showing Trif Joint

and Non-Trif Joint related with the median/average of other UK DNOs excluding outlier SPD

Under CV26, a total of 679 EHV UG cable faults are forecast. Using analysis above, we have assumed that

50% of these (340) will be non-Trif joint related repairs, and that the CSF adjustment is applied to this

volume only. We have compared this volume to the industry median ED1 5-year fault volumes of 143 –

taken from the analysis above.

This represents an additional 196.5 cable faults on SPM’s 33kV cable network due to its unique interconnected operational arrangements and design. Based on average repair costs of £10.2k per fault this

represents £2.0m of CV26 costs towards the CSF (see Table 6).

Changes from ED1

The methodology for calculating the CSF for 33kV cable faults has changed from the claim made in RIIO-

ED1 against this repair activity. The CSF claim in ED1 simply compared the difference in the average unit

costs between SPM and SPD given the requirement in SPM to replace a longer section of faulted cable due

to the levels of carbonisation and deterioration of insulation papers in the 33kV cable in the vicinity of the

cable fault.

Whilst Ofgem appointed consultants DNV GL acknowledged this fact, the claim was reduced as DNV GL

did not agree that the difference in unit cost was the only factor that contributed to a higher cost.

A full review of 33kV cable fault performance in 2018/19, which was initiated following an unprecedented

level of faults in 2018, found a legacy trifurcating joint used between 2001/02 and 2010/11 was the reason

351

697

119

160

0 100 200 300 400 500 600 700 800

SPM (Excl 3M Trif)

SPM

DNO Median

DNO Average

Comparison of SPM Faults with UK DNO - RIIO-ED1 5 Years

0.18

0.36

0.11

0.14

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40

SPM (Excl 3M Trif)

SPM

DNO Median

DNO Average

33kV Cable Faults per km - RIIO-ED1 5 Years


84

for an increase in fault volumes. Analysis also determined that temperature variations contribute in part to

their failure; explaining the seasonal peak.

As a consequence of our review and the experience from the information gathered to support the HVP re-

opener for EHV cable trifurcating joints, the CSF proposal for ED2 has been reflected into the adjustment

reported for ED1, which is detailed in the new CSF memo table M25.

Figure 38: 33kV Cable Faults during 2018 showing Trif Joint and other fault causes against ambient air

temperatures recorded

Notwithstanding the faults associated with the legacy trifurcating joint, which accounted for approximately

50% of the faults on SPM’s 33kV cable network, the remaining 50% of 33kV cable fault volumes in SPM are still nearly 3 times that of the median of the other UK DNOs.

Our ED2 CSF proposed adjustment of £2.03m has increased from the CSF allowance of £0.46m in ED1 (5-

year, 20/21 prices) as the ED2 CSF reflects the interconnected network fault level currents and circulating

power flows that result in higher stresses on cables and joints leading to increased failures compared to a

radial design typical of other UK DNOs.


There are no feasible options to move away from an interconnected system however, we are proposing a

programme of targeted investment to overlay 20km of 33kV cable and proactive joint removal against CV7

and CV8 respectively.

For 33kV cable modernisation needs in SP Manweb in ED2, the options are considered within the relevant

EJP: ED2-NLR(A)-SPEN-001-UG-EJP: SPD & SPM EHV (33kV) Underground Cable Modernisation. The

paper considers various overlay replacement options, and the optimum scheme is selected based on

deliverability and net benefit over a 45-year period.


As part of our 33kV cable review, Health Index categories for EHV non-pressurised cables has been

developed together with an extensive exercise to verify all known joint positions and types across the whole

underground cable network. The Health Index category is determined based on several factors, including

age, utilisation and condition inputs such as fault rate per kilometre. It represents a measure of the condition

of an asset, with HI1 being little to no degradation and HI5 being advanced stages of degradation.


85

It has been determined that applying a marginal voltage reduction, may mitigate faults. Voltage reduction

have been applied seasonally to reduce electrical stresses and fault prevalence.

Innovation techniques involving the use of on-line cable partial discharge (PD) monitoring equipment has

been used which enables the early identification of faults through pre-emptive detection. This informs the

prioritised intervention and network re-configuration to secure supplies, however its application on SPM’s network is limited to 33kV feeders at grid sites due to the earthing arrangements on primary switchgear and

the physical constraints to fit PD equipment at non-grid sites.



SPM’s 33kV network provides leading performance in terms of reliability with the lowest CI of all UK DNOs

and during the first 5-year period of ED1 reported no customer supplies being lost for over 92% of the

network faults experienced on its 33kV interconnected network.

5.8.1.2 LV Network


Like the EHV and HV voltage levels the LV network also operates interconnected with over 70% of the LV in

Merseyside and Wirral being interconnected and circa 30% of the LV networks across its more rural areas of

North Wales, Shropshire and Cheshire also operating interconnected. Overall, around 53% of the LV

network is designed and operated interconnected.

As was explained in Section 3, SPM’s interconnected LV network provides leading performance in terms of supply reliability, as well as flexibility in how the network can be reconfigured to accommodate changing

loads. It also facilitates planned works on the HV system to be carried out without the need, in many

instances, to interrupt customer supplies (CIs), as running arrangements can be altered to maintain supply to

customers, who otherwise would be impacted. This benefit, which is embedded within the network’s legacy design, is provided extensively across our urban areas of Merseyside and Wirral as well as some parts of

Cheshire and North Wales where the LV network is interconnected between 2 or 3 secondary substations.

SPM’s unique network does mean it is more complex due to the multiple paths power can flow compared to the single path in a typical radial design network. Whilst this means additional LV network studies are

needed to design and plan any changes or additions to the LV system, it also means that operating the

interconnected LV network is more complex when the network experiences an intermittent or permanent

fault.


86

Figure 39: LV network arrangements comparing typical radial configuration with SPM’s interconnected arrangements

The CSF is based on the additional direct time and activities involved with operating, testing and responding

to LV network faults, both intermittent and permanent, compared to a radial network. The schematic

diagrams shown in Figure 39 illustrate the differences between a radial arrangement and SPM’s interconnected network design for a routine fault on a single LV circuit feeder. In contrast to a single visit on

a radial network, SPM’s interconnected network requires multiple visits to all LV circuit infeeds from each of

the secondary substations together with on-site intrusive checks at LV link boxes to test individual live

phases and confirm live or not live status and voltage on all interconnected LV infeeds.

To calculate the CSF, we have also identified and recorded all permanent faults reported in the first 5 years

of ED1 by overlaying on our LV mapping system, ERSI, each fault position. Coupled with this analysis, we

have also determined the geographical areas of each fault and how many of the faults have occurred on our

interconnected underground cable network. Against this information we have estimated the additional

average man-hours required in visiting multiple secondary substations and LV link boxes to undertake the

necessary operational checks and circuit testing to restore supplies, reconfigure the network and/or locate a

permanent fault.

Whilst the forecast number of faults across the ED2 5-year period is 18,950 across activities for restoration

by LV switching, LV underground (non Consac) cables and LV link boxes faults, the CSF only applies to the

proportion of LV network incidents associated with the interconnected LV network. The number of CSF

incidents is based on the analysis completed over the 5-year ED1 period for the above fault activities, which

represents overall around 68% of incidents. This assumption is based on the analysis of cable faults on our

LV interconnected network and how the fault distribution increases against the level of interconnection, as

shown in Error! Reference source not found. below.

Figure 40: LV network faults by district area against the level of interconnection

The make-up and distribution of these faults across our interconnected network does vary between the

different geographical areas. This, together with the fact that a proportion of incidents occur outside normal

working hours, i.e. 50% are responded to by 24/7 standby teams, the proposed CSF adjustment for ED2 is

estimated to be between £5.59m and £6.78m.

To be conservative, we have taken the bottom of this range and propose a CSF adjustment of £5.59m for all

LV network faults against CV26 for restoration by LV switching, LV underground (non Consac) cables and

LV link boxes faults (see Table 6).

Dee Valley & Mid Wales

North Wales

Merseyside

Mid Cheshire

Wirral

0

100

200

300

400

500

600

700

0% 10% 20% 30% 40% 50% 60% 70% 80%

2020/2

1 L

V U

G fault v

olu

mes

% of Network Interconnected at LV


87

Changes from ED1

The methodology for calculating the CSF in ED1 was simply based on the unit cost difference between SPD

and SPM and whilst the full CSF value of £1.37m (5-year, 20/21 prices) was allowed for in ED1, we believe

the difference in unit cost was not the only factor that contributed to a higher cost in CV26 for responding to

and repairing faults on the underground interconnected LV network.

The CSF claim in ED1 did not compare all the differences and additional activities associated with every

aspect of operating and switching on an interconnected network under fault conditions and nor were we able

to map reported LV faults on to the LV network to assess the volumes of faults experienced on the

interconnected LV network areas.

This we have been able to achieve in justifying our ED2 CSF to reflect fully the higher costs associated with

our LV network fault activities, which represent circa 41% (excluding service underground cable faults) of our

CV26 expenditure over the 5-year period.

As a consequence of our review and the experience from the information and analysis undertaken to support

the CSF proposal for ED2, this has been reflected into the adjustment reported for ED1, which is detailed in

the new CSF memo table M25.


There are no feasible options to move away from an interconnected system however, we are proposing a

programme of proactive targeted investment to overlay 104.4km of LV cable to provide the greatest benefits

to customers in terms of avoided faults, derived on a circuit level.

For LV cable modernisation needs in SP Manweb in ED2, the options are considered within the relevant

EJP: ED2-NLR(A)-SPEN-003-UG-EJP: SPD & SPM LV Underground Cable Modernisation. The paper

considers various overlay replacement options, and the optimum scheme is selected based on deliverability

and net benefit over a 45-year period.


Whilst an increasing trend in LV underground cable faults has been observed in the years 2019/20/21, the

proposals reflected in ED2 take account of a proactive and targeted intervention strategy to reduce fault

levels by the end of the ED2 period.

This coupled with the innovative proposals for deploying increased levels of active LV network monitoring

devices and the increased utilisation of new and emerging cable fault monitoring equipment has been

reflected in our overall expenditure for LV network faults in our ED2 CV26 proposal and hence is built into

our CSF adjustment proposed.



SPM’s LV network provides leading performance in terms of reliability with the lowest CI of all UK DNOs,

however the complexity of the interconnected LV network means we need to reflect fully the higher costs in

operating it compared to a radial system.


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5.8.2 CV30 Inspections – Thermovision at Primary Substations

5.8.2.1 Thermovision inspections at Primary Substations with outdoor switchgear and busbar arrangements


Inspections costs are driven by existing policies in order to comply with statutory requirements, ensure

safety, minimise risk of failure, prolong asset life, and allow cost effective interventions to ensure plant,

switchgear and protection systems perform reliably.

The inspection activities are based on the SPEN Asset Inspection and Condition Assessment Policy

document ASSET-01-021, which covers all asset types at all voltage levels.

We have determined the volumes and costs of carrying out thermovision inspections on primary switchgear

associated with SPM’s unique interconnected network, which is not required on an equivalent radial network.

To calculate the CSF, we have only identified costs associated with thermovision inspections of primary

substation (non-grid sites) 33kV plant, switchgear and associated assets, (such as reference voltage

transformers, disconnectors and earth switches, bus bar connections as appropriate) associated with SP

Manweb’s discrete interconnected 33kV unit systems.

Figure 41: Typical thermovision inspection image showing 33kV ‘hotspot’

We calculate the CSF as £0.06m for thermovision inspections associated with primary plant and switchgear

associated with non-grid sites where SPM has plant and equipment unique to its interconnected design

arrangements.

Changes from ED1

The methodology for calculating the CSF is consistent with the approach taken for ED1, which was allowed

in full following a review by Ofgem appointed consultants DNV GL.

The actual CSF adjustment for ED1 is detailed in the new CSF memo table M25 and is based on all primary

switchgear non grid sites being inspected using thermovision equipment once every 2 years, i.e. 50% in year

1 and 50% in year 2.


For plant and switchgear our inspections activities are determined by established policies and robust work

practices that comply with statutory requirements, ensure safety, minimise risk of failure, prolong asset life,

make cost effective interventions to ensure plant, switchgear and protection systems perform reliably. Whilst

we continue to use new or innovative approaches as well as new technologies the efficient delivery of our

inspection programme is a licence condition for which there are no other options.


Whilst inspection costs are driven by policies that cover the type and frequency of inspection needed, the

cost mitigation is driven by working practices and the use of innovative technologies available to support the


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testing and non-intrusive maintenance tasks required. The use of thermovision equipment for this activity is

deemed effective and efficient.



5.8.3 CV31 Repair and Maintenance (R&M)

5.8.3.1 Primary switchgear and associated unit protection equipment


Operational repair and maintenance costs are driven by existing policies in order to comply with statutory

requirements, ensure safety, minimise risk of failure, prolong asset life, make cost effective interventions to

ensure plant, switchgear and protection systems perform reliably. The R&M activities are based on the SP

Manweb substation maintenance policy, SUB-01-009 inclusive of post fault maintenance requirements.

Existing policies set out the repair and maintenance intervention activities, ranging from a full major

maintenance (including oil change) through to trip testing and condition monitoring. Subject to the

manufacturer type, operating voltage and intervention activity the policy determines the frequency of when

R&M is performed.

We have determined the volumes and costs of maintaining primary substation (non-grid sites) 33kV CBs and

associated equipment (such as reference voltage transformers, disconnector’s and earth switches as appropriate) and 33kV RMUs (exclusive assets used by SPM) associated with SP Manweb’s discrete interconnected 33kV unit systems.

All the unit protection schemes supporting SPM’s unique interconnected network require the use of

additional battery systems and charger units. Whilst these are relatively low-cost items, they are discrete to

the SP Manweb interconnected network and compared to typical radial design networks, SPM’s network has significantly more battery systems, particularly with its HV network as shown in Figure 19 within section

3.4.1– Volume of batteries per 1 million customers, all voltage levels, across all DNOs (from 2020 DNO asset

register).

We have scaled the R&M switchgear expenditure by the percentage of 33kV CBs that are at primary sites

(i.e. unique to the interconnected network), according to the asset register, and by CB type. For batteries, we

have scaled the R&M expenditure by the number of primary sites in SP Manweb compared to an equivalent

radial network (factor of 2.1 – see section 5.7.7).

Given SP Manweb’s unique design and requirement for (non-grid site) 33kV CBs, 33kV RMUs which are not

required in primary substations in a radial network, we calculate the CSF as £1.30m for primary plant,

switchgear, associated protection and battery systems.

Our ED2 CSF proposed adjustment of £1.30m has reduced from the CSF allowance of £1.49m in ED1 (5-

year, 20/21 prices) as the ED2 CSF reflects the changes from ED1 in the overall reduction in R&M activities

driven by our ED1 and ED2 asset modernisation delivery plan, particularly removal of oil filled switchgear.

Changes from ED1



The actual CSF adjustment for ED1 is detailed in the new CSF memo table M25.


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For switchgear, protection systems including batteries the R&M activities and interventions are determined

by established policies and robust work practices that comply with statutory requirements, ensure safety,

minimise risk of failure, prolong asset life, make cost effective interventions to ensure plant, switchgear and

protection systems perform reliably. Whilst R&M activities look to use new or innovative approaches as well

as opportunities to use new technologies the efficient delivery of our R&M programmes is a licence condition

for which there are no other options.


Whilst R&M costs are driven by policies that cover the type and frequency of intervention needed, the cost

mitigation is driven by working practices and the use of innovative technologies available to support the

testing and non-intrusive maintenance tasks required.

As in ED1, the efficient delivery of ED2 R&M will also be through the effective co-ordination of our R&M

plans with our investment modernisation and refurbishment plans, i.e. touch once approach during the

period. This coupled with the use of available technologies, e.g. partial discharge test devices, CB trip-timing

multiple test devices are key cost mitigation approaches we will continue to use that are reflected in our

overall ED2 submission.



5.8.3.2 Secondary X-type switchgear and associated unit protection equipment









R&M is performed.

Figure 42: X-type unit protection with HV CBs at each secondary substation


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With regard to secondary X-type switchgear in SP Manweb, testing and maintenance of the unit protection

equipment at secondary substations (protection relays and LV board ACB) including battery systems is

unique to its HV interconnected network. It is carried out as part of the routine maintenance visits to the

secondary site. The CSF adjustment is based on the R&M activities (direct labour costs) associated with the

additional HV secondary assets (additional HV CBs, unit protection relays, battery systems and LV board

ACBs) that are unique to SPM’s interconnected network. The CSF adjustment excludes the costs associated

with routine R&M of secondary RMUs and CBs, i.e. oil handling / changing and general routine R&M tasks

any DNO would normally perform.

The higher level of maintenance is related to the fact that SP Manweb’s interconnected network requires HV CBs at each secondary substation along the interconnector circuit between primary substations, for its unit

protection principle to operate safely and effectively as shown in Figure 41. In a typical radial network, a

single HV CB is required at the primary source only. For a fault on a circuit along the interconnector between

two or more primary substations, then the two CBs (typically one at each of the X-type RMU’s or on a X-type

CB panel board), at each adjacent secondary substation will operate to isolate just the faulted cable section

to ensure that no customer supplies are disconnected.

This places additional duty on the CBs, and they must be maintained for safety and operational integrity

purposes.

Regarding post fault maintenance the CSF is based on the additional cost of post fault maintenance costs

associated with X-type RMU CBs and to a lesser extent CBs at HV customer feeder sites and mid-feeder

panel board substation sites.

Based on the unique and additional HV secondary assets SPM’s interconnected network requires, we calculate the CSF adjustment for HV secondary R&M as £1.27m. Our ED2 CSF proposed adjustment of

£1.27m has reduced from the CSF allowance of £1.6m in ED1 (5-year, 20/21 prices) as the ED2 CSF

reflects the changes from ED1 in the overall reduction in R&M activities driven by our ED1 and ED2 asset

modernisation delivery plan, particularly the removal of oil filled switchgear.

Changes from ED1





For switchgear, protection systems including batteries the R&M activities and interventions are determined







Whilst R&M costs are driven by policies that cover the type and frequency of intervention needed, the cost

mitigation is driven by working practices and the use of innovative technologies available to support the

testing and non-intrusive maintenance tasks required.



period. This coupled with the use of available technologies, e.g. partial discharge test devices, CB trip-timing


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multiple test devices are key cost mitigation approaches we will continue to use that are reflected in our

overall ED2 submission.



5.8.3.3 Protection – at all voltages


Protection systems form a critical part in providing a safe, reliable network that protect the integrity of assets

by operating correctly under fault or abnormal conditions.

Within SP Manweb, the application of unit protection schemes is unique and used widely across its 33kV and

11kV interconnected network. The application and routine maintenance requirements are defined in existing

policies, specifically PROT-01-016 Protection Inspection and Maintenance Policy and PROT-03-019 Primary

and Secondary Substation Protection and Control Equipment.

The circuits in a 33kV urban network consist mainly of standard sized underground cables that form

interconnections between BSP substations and provide connections to primary substations. The network is

generally operated in interconnected groups of two or more BSP transformers, with its exact configuration

and operating regime determined by system analysis. The primary substation connections are made so as to

form discrete sections of network that may be protected by individual zones of unit protection. The unit

protection schemes utilise pilot cables that are laid with the associated 33kV cable.

In more rural and semi-urban areas, again the use of unit protection is used where the zone of protection is

the circuit between primary substations or primary substation and BSP, however at primary substations sites

with outdoor 33kV switchgear there is also the requirement for bus bar protection schemes which also are

integral to how the unit protected zones operate.

It is desirable for transformers that are to be operated in parallel at HV, as an interconnected group, to be

connected to different 33kV interconnectors.

Figure 43 shows typical urban and rural 33kV running arrangements.


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Figure 43: Typical 33kV urban interconnected network (left) and typical 33kV rural interconnected network

arrangement (right)

The unit protection schemes have protection relays that rely on pilot cables to ensure the protection relays at

either end of the circuit communicate correctly to detect and clear faults.

One type of 33kV unit protection relays used throughout the more urban and semi urban areas in called

‘Translay’ where the pilot cables are run overhead or over non-SP Manweb owned pilots. For safety,

isolation transformers are used between the pilot wires and the substation relay panels and protection relays

and staff. Other unique unit protection schemes include the MPR relay scheme which relies on

communication across telecommunication channels, some SP Manweb owned and others that are leased

from third party service providers.

The CSF adjustment is based on the protection R&M associated with the unit protection and bus bar

protection schemes which are unique to SP Manweb’s interconnected when compared to a radial design. The CSF adjustment value is £0.28m.

Changes from ED1


in full following a review by Ofgem appointed consultants DNV GL. However, for ED2 we have

disaggregated these unique protection costs against the appropriate line within CV31 for Protection costs,

whereas in ED1 all CSF protection costs were shown against the respective lines for 33kV CBs and

6.6/11kV CB (GM) secondary switchgear.



Like switchgear, protection systems including batteries the R&M activities and interventions are determined









period., which we have reflected in our overall ED2 submission.



5.8.3.4 Primary 33kV transformers







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R&M is performed

We have calculated the costs associated with R&M Opex for 33kV primary transformer by reviewing the

volumes of assets compared to an equivalent radial network. Based on the R&M policies for interventions

required for oil plant and associated voltage control equipment the total R&M Opex across RIIO-ED2 is

£1.24m of which we calculate the R&M activities that contribute to the CSF as £0.46m.

Changes from ED1

The methodology for calculating the CSF for primary 33kV transformers was an oversight as it was not

included in the ED1 CSF submission. Like the approach and justification for primary 33kV transformer

modernisation in the ED2 CSF, we have applied the same principles to calculate the R&M CSF for the ED2

period.

The actual CSF adjustment for ED1 against this R&M activity is shown in the new CSF memo table M25.


Like switchgear, primary 33kV transformer R&M activities and interventions are determined by established

policies and robust work practices that comply with statutory requirements, ensure safety, minimise risk of

failure, prolong asset life, make cost effective interventions to ensure plant, switchgear and protection

systems perform reliably.

Whilst refurbishment proposals are built into our ED2 plan it does not replace the need for routine R&M

activities on primary 33kV transformers. Also, there are trials we are progressing with new innovative oil re-

generation approaches with the aim to retard insulation degradation, thus extending transformer usable life.

On this basis we do not believe it provides a viable option for R&M costs.




period, which we have reflected in our overall ED2 submission.



5.8.3.5 Underground pilot wire repairs


The use of underground pilot wires is an integral part of SP Manweb’s unit protected design for both its 11kV and 33kV interconnected network with circa 3,665km of underground pilot wires across its 11kV X-type and

nearly 2,000km of underground pilot associated with its 33kV underground cable network.

The underground pilot cables owned by SP Manweb ensure the safe and effective operation of its unique

unit protection schemes and when pilot cables degrade beyond an adequate condition, associated protection

schemes are likely to fail to operate correctly which may cause danger to the public and/or increased

interruptions to customer’s supplies. Tests have shown the insulation resistance has degraded on some protection pilot assets, some to levels where protection operation would be affected if called to operate.


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SP Manweb’s exceptional supply reliability in urban area, as highlighted in section 3, is dependent on the

reliability and effective operation of its underground pilot cables.

For a typical radial network, a direct comparison is not available as other DNOs do not operate an

interconnected X-type 11kV network and do not utilise pilot cables for 33kV network unit protection,

particularly for intertrip signalling. The requirement for ongoing repairs and maintenance of underground pilot

cable is essential to the performance and reliability of SP Manweb’s network. The relevant EJP is ED2-

NLR(A)-SPEN-001-PROT-EJP – Light Current, Protection and Pilots, which covers non-load proposals for

ED2.

In ED2, we have only allowed for carrying out 365 repairs on underground pilot cables associated with the

11kV interconnected X-type network which contributes £0.55m to the CSF value.

Changes from ED1

The methodology for R&M has changed from the CSF proposal for ED1 in that the ED2 CSF focuses on the

unique underground pilots, of which there is a high proportion of 3-core pilot cables, which support 11kV

protection applications in the SP Manweb X-type network. These are predominantly in urban areas across

Merseyside and Wirral.

The actual CSF adjustment for ED1 against this R&M activity is shown in the new CSF memo table M25.


There is a large installed asset base of protection only underground pilots in SP Manweb, which is detailed in

section 3.4.1, Figure 17. There are dedicated pilots with small numbers of cores for protection applications

which are essential to ensuring clearance of faults within design clearance times. Alternatives for providing

the same reliable form of protection tripping and inter-tripping on the 11kV interconnected network are not

available.


Like cable fault location, pilot cables require the effective use of similar fault location techniques to pre-locate

and pin-point cable sheath faults, or cable faults caused by earth contact or particularly the ability to measure

insulation resistance, which is critical to the performance of the pilot cable for correct protection operation.

The efficient and effective use of these types of fault location devices is essential in mitigating costs for this

repair activity for which dedicated operational engineers and technical team members are trained and

proficient in their use.



5.8.3.6 Primary and secondary substation civil repairs


SP Manweb plan to undertake a £6.45m programme of civils R&M to improve the condition of our secondary

substations. The costs associated with X-type, brick-built substations are unique to SP Manweb’s network. We have therefore scaled the investment by the number of indoor secondary substations in SP Manweb

compared to an equivalent radial network (factor of 1.61 – see Section 5.7.9.1), leading to a CSF adjustment

of £2.45m.

A £2.34m programme of civils R&M is planned to improve the condition of our primary substations. To

calculate the primary civils R&M cost of an equivalent radial network for comparison, we have scaled the


96

investment by the number of primary sites in SP Manweb compared to an equivalent radial network (factor of

2.1 – see section 5.7.7). On this basis we have calculated a CSF adjustment of £1.22m for ED2.

Changes from ED1

The methodology for calculating the CSF for civil R&M in ED1 for both primary substations and secondary

substations was an oversight as it was not included in the ED1 CSF submission.

From the review of the CSF for ED2, the approach and justification for the CSF costs for non-load primary

33kV assets have been applied to calculate the civil costs associated with the R&M CSF, which we have

calculated a CSF value of £.1.2m over the 5-year period.

For HV secondary substations we have only considered the civil R&M costs associated with the upkeep and

maintenance of SP Manweb’s unique X-type substations. Based on this approach we have calculated a CSF

value of £2.45m over the 5-year period.

The actual CSF adjustment for ED1 against this R&M civil repairs activity is shown in the new CSF memo

table M25.




ensure plant, switchgear and protection systems perform reliably. R&M civil activities form part of this overall

asset management strategy. To ensure its effectiveness a quality management policy is in place for all Civil

and Groundwork associated with both Transmission & Distribution Substation / Sites. The procedure is

documented under QUAL -10-013 Issue 4.




period, which we have reflected in our overall ED2 submission.




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6. Glossary

ACB Air Circuit Breaker

ATOS Average Time Off Supply

CAI Closely Associated Indirects

Capex Capital Expenditure

CB Circuit Breaker

CCTV Closed Circuit Television

CI Customer Interruption (of over 3 minutes)

CML Customer Minute Lost

CNAIM Common Network Asset Indices Methodology

CSF Company Specific Factor (Manweb’s unique interconnected network)

CV Costs and Volumes

DNO Distribution Network Operator

DSO Distribution System Operator

EHV Extra High Voltage (typically 33kV)

EJP Engineering Justification Paper

ESQCR Electricity, Safety, Quality and Continuity Regulations

EV Electric Vehicles

GM Ground Mounted

HI Health Index

HV High Voltage

ID Indoor

IT&T Information Technology and Telecommunications

kV 1,000 volts

LPN London Power Networks

LV Low Voltage

MEAV Mean Equivalent Asset Value

MM Mott MacDonald

MVA Megavolt-ampere (1 million volt-amperes, power)

OD Outdoor

Opex Operation Expenditure

PB PB Power Ltd., was Parsons Brinckerhoff, now part of WSP

R&M Repair and Maintenance

RIIO Revenue = Incentives + Innovation + Outputs

RMU Ring Main Unit

RTU Remote Terminal Unit

SCADA Supervisory Control and Data Acquisition

SPD SP Distribution

SPM SP Manweb

Totex Total Expenditure

UCM Unit Cost Manual

UG Underground

UKPN UK Power Networks

annex 4a.25: sp manweb company specific factors

Documents