RIIO-ED1 RIGs Environment and Innovation Commentary ... · PDF fileDNO’s may include...

RIIO-ED1 RIGs Environment and Innovation Commentary, version 3.0

2016/17

UK Power Networks

Contents

Summary – Information Required 1

Worksheet by worksheet commentary 1

E1 – Visual Amenity 2

E2 – Environmental Reporting 2

E3 –BCF 5

E4 – Losses Snapshot 15

E5 – Smart Metering 15

E6 – Innovative Solutions 27

E7 – LCTs 80

Environment and Innovation Commentary 1

Summary – Information Required One Commentary document is required per DNO Group. Respondents should

ensure that comments are clearly marked to show whether they relate to all the

DNOs in the group or to which DNO they relate.

Commentary is required in response to specific questions included in this

document. DNO’s may include supporting documentation where they consider it

necessary to support their comments or where it may aid Ofgem’s understanding.

Please highlight in this document if additional information is provided.

The purpose of this commentary is to provide the opportunity for DNOs to set out

further supporting information related to the data provided in the Environment

and Innovation Reporting Pack. It also sets out supporting data submissions that

DNOs must provide to us.

Worksheet by worksheet commentary

At a worksheet by worksheet level there is one standard question to address,

where appropriate, as follows:

Allocation and estimation methodologies: DNOs should detail

estimates, allocations or apportionments used in reaching the numbers

submitted in the worksheets.

This is required for all individual worksheets (ie not an aggregate level),

where relevant. Not all tables will have used allocation or estimation

methods to reach the numbers. Where this is the case simply note “NA”.

Note: this concerns the methodology and assumptions and not about the

systems in place to check their accuracy (that is for the NetDAR). This

need to be completed for all worksheets, where an allocation or estimation

technique was used.

In addition to the standard commentary questions, some questions specific to

each worksheet are asked.


E1 – Visual Amenity

Allocation and estimation methodologies: detail any estimations, allocations

or apportionments to calculate the numbers submitted.

Direct costs: For the allocation and estimation methodologies for direct costs

please refer to this section for C3 – Physical Security (to avoid repetition across

all the direct cost tables)

Explanation of the increase or decrease in the total length of OHL inside

designated areas for reasons other than those recorded in worksheet E1. For

example, due to the expansion of an existing, or creation of a new, Designated

Area.

The only change in the total length of OHL inside designated areas is as a result

of the reasons recorded in the E1 table.

Here is a summary of the E1 table for 2016/17:

E2 – Environmental Reporting



Direct costs: For the allocation and estimation methodologies for direct costs

please refer to this section for C3 – Physical Security (to avoid repetition across

all the direct cost tables)

DNOs must provide some analysis of any emerging trends in the environmental

data and any areas of trade-off in performance.

n/a

Where reported in the Regulatory Year under report, DNOs must provide

discussion of the nature of any complaints relating to Noise Pollution and the

nature of associated measures undertaken to resolve them.

UK Power Networks received 26 Enquiries/Complaints about noise during the

regulatory period. The majority relate to low frequency noise associated with

transformers and substations as in previous years.

We continue to use the Salford University Low Frequency Noise Rating

2016/17 LV HV 33/66kV LV HV 33/66kV

Kent Downs AONB 0.01 1.35 1.83 - - 1.86

Dedham Vale AONB 0.93 0.54 1.18 0.61

OHL removed UG cable installed


Methodology, which gives an accurate reflection of whether the noise is likely to

cause a statutory nuisance. We are trying to engage proactively with local

authorities to highlight the issue of low frequency noise and ensure that it is

considered when giving planning consent.

UK Power Networks is in the process of designing and fitting acoustic screens to

Noak Hill primary substation and Moscow Road main substation; the latter is a

new style screen that works by matching the peaks and troughs of the wave

length to cancel the noise. This screen is being employed due to the high

temperatures that would be created by the use of a conventional screen.

Where reported in the Regulatory Year under report, DNOs must provide details

of any Non-Undergrounding Visual Amenity Schemes undertaken.

N/A

Any Undergrounding for Visual Amenity should be identified including details of

the activity location, including whether it falls within a Designated Area.

UK Power Networks is committed to undergrounding on its AONB as summarised

below:


discussion of details of any reportable incidents or prosecutions associated with

any of the activities reported in the worksheet.

In the regulatory year we had 3 interactions with the Environment Agency. All

incidents were categorised as ‘Minor of No Impact’ by the Environment Agency

and have not attracted any prosecutions.

There were also 9 interactions with Local Authorities, the majority of which were

requests to remove waste from substations. These are often issued as notices

under the Environmental Protection Act or Anti-social Behaviour Crime and

Policing Act. All notices were complied with and no further action was taken. It is

also worth noting that the figure includes 3 Noise Abatement Notices all issued on

the same site to ensure that the notice was served on the correct entity. In all

cases UK Power Networks contacts the issuing officer to promote positive

engagement.

OHL Inside Designated Areas at End of

Reporting Year (km) LV HV 33kV & 66kV 132kV

The Broards National Park 47.8 99.4 4.4 -

Suffolk Coast & Heaths AONB 90.0 294.8 26.3 -

Norfolk Coast AONB 123.1 265.5 47.6 -

Dedham Vale AONB 46.9 79.8 1.7 6.9

Chilterns AONB 219.7 388.6 60.3 17.8

South Downs National Park 795.9 894.6 147.9 108.9

High Weald AONB 287.2 415.5 246.5 151.5

Surrey Hills AONB 327.9 406.4 44.1 33.6

Kent Downs AONB 191.0 576.4 140.8 169.6



discussion of details of any Environmental Management System (EMS) certified

under ISO or other recognised accreditation scheme.

UK Power Networks has maintained its ISO 14001 Accreditation through the

regulatory period.

DNOs must provide a brief description of any permitting, licencing, registrations

and permissions, etc related to the activities reported in this worksheet that you

have purchased or obtained during the Regulatory Year.

UK Power Networks continues to operate the 7 SR2012 No.15 Standards Rules

Permits for the storage of waste insulating oil. No additional permits have been

applied for at this time.

A variation of our Falconwood permitted facility was submitted to the

Environment Agency to allow the storage of acidic oil on site. This variation has

been granted ref no. EPR/PP3690VN/V002

DNOs must include a description of any SF6 and Oil Pollution Mitigation Schemes

undertaken in the Regulatory Year including the cost and benefit implications and

how these were assessed.

Retro Bunding to 2 Transformer Bays was completed at Houghton Regis in

2016/17, which had been identified as a medium pollution risk due to proximity

to surface and ground water systems. The bunds were designed to accommodate

the full transformer oil volume in order to contain it in the event of a catastrophic

failure and will also prevent the contamination of the ground within the site

boundary and beyond.

Previously contaminated earth was also removed from a site in Chertsey.

Noise protection measures were installed at Hatchard Road to reduce noise

pollution from transformers to local residents.

Circuit Breaker 405 at Kemsley Grid is a 132kV AIS type Brush DB145 circuit

breaker, situated outdoor. It is a feeder breaker that feeds Grovehurst Grid

132kV substation.

This circuit breaker was a known leaker, with total SF6 topped-up of 5kg in 2016,

making it the most significant SF6 leaking asset in SPN.

The most cost-effective solution was deemed to be replacement of the circuit

breaker stacks on all three phases. This intervention was completed on

13/10/2016 and resolved the issue with SF6 leakage on this breaker as we have

had no reported leaks on this asset since the intervention.

In 2016/17 we carried out the following refurbishments of transformers to

reduce/stop significant oil leaks.

EPN

Old Welwyn Primary (2 x 33/11kV Tx)

Ilmer Primary (2 x 33/11kV Tx)

LPN

Wimbledon Grid C (1 x 132/33k Tx)

Bromley Grid (1 x 132/33kV Tx)


SPN

Canterbury South Grid (1 x 132/33kV Tx, 2 x 33kV reactors also refurbished but

not specifically to address oil leaks)

Purley Grid (2 x 132/33kV Tx)

Bolney Grid (1 x 132/33kV Tx)

Three Bridges Grid (1 x 132/33kV Tx)

Crawley Industrial East Primary (2 x 33/11kV TX)

Woking Primary (1 x 33/11kV Tx)

The transformer refurbishment at Wimbledon Grid C included the use of a Belzona

compound to seal around the leaking gaskets without having to remove the main

lid. This allowed for a faster completion and less invasive work at a better cost

than a traditional re-gasketting job. This was preferred because the transformer

is likely to be replaced in ED2 after the completion of ongoing works on site to

replace the 132kV switchgear and reactors in conjunction with National Grid. This

is the first time we have used this solution. The remainder of the refurbishments

all included re-gasketting to cure the oil leaks. In addition to re-gasketting, the

cooler was replaced on one of the transformers at Ilmer Primary due to severe

corrosion.

E3 –BCF



The following commentary details the processes used to calculate the BCF for UK

Power Networks specific to our three licensed distribution networks; Eastern

Power Networks plc (EPN), London Power Networks plc (LPN) and South Eastern

Power Networks plc (SPN).

All data in this commentary that is indicated with a yellow box as shown in the

example below corresponds with the completed E3 summary tables returned to

Ofgem.

Example:

Where data is only collected centrally this is apportioned between UK Power

Networks three DNOs based on headcount as of March 2017. These

apportionments are covered in the detailed commentary for the individual areas.

BCF reporting boundary and apportionment factor

DNOs that are part of a larger corporate group must provide a brief introduction outlining

the structure of the group, detailing which organisations are considered within the

reporting boundary for the purpose of BCF reporting.

Any apportionment of emissions across a corporate group to the DNO business units must

be explained and, where the method for apportionment differs from the method proposed


in the worksheet guidance, justified.

All data provided is for the Regulatory reporting year (April 2016 to March 2017) unless

stated otherwise.

In all calculations the Defra conversion factors in place on March 31st 2017 - as

recommended in the reporting guidelines from Ofgem - have been used unless stated

otherwise. The 2015/16 figures which had used the Defra conversion factors released on

June 1st 2016 have been replaced with the factors in place on March 31st 2016. No change

was necessary to the 2014/15 baseline year data as this already used the factors in place

on March 31st 2015.

The Greenhouse Gas (GHG) Protocol categorises direct and indirect emissions into three

broad scopes:

Scope 1: Direct GHG emissions from sources owned or controlled by UK Power

Networks.

Scope 2: Indirect GHG emissions from consumption of purchased electricity, heat

or steam.

Scope 3: Other indirect emissions, such as the extraction and production of

purchased materials and fuels, transport-related activities in vehicles not owned or

controlled by UK Power Networks, electricity-related activities (e.g. T&D losses)

not covered in Scope 2, outsourced activities, waste disposal, etc.

UK Power Networks is a parent company Z that has full ownership and financial control of

operations A, B, C and D Unregulated. Data indicated with an X in our submission is

inclusive of data from subsidiaries; A, B, and C unless stated otherwise.

Data defined as D refers to our unregulated business and is excluded from the tables.

Data indicated with a Y is from our main contractors and their sub-contractors for the

regulated activities.


BCF process

The reporting methodology for BCF must be compliant with the principles of the

Greenhouse Gas Protocol.1 Accounting approaches, inventory boundary and calculation

methodology must be applied consistently over time. Where any processes are improved

with time, DNOs should provide an explanation and assessment of the potential impact of

the changes.

Monthly reports are received from various sources within UK Power Networks covering

electricity and gas meter readings; Fleet fuel usage; business mileage and transport

expense claims; generator fuel usage; SF6 top ups and head count.

Externally contractors provide monthly reports of fuel usage for fleet and plant and

equipment and provide business mileage on UKPN contracts. Booking reports are received

from external travel provider, all on a monthly basis.

Annually a report on network losses is received.

The conversion factors were sourced from Defra on 31st March 2017 and the latest

Regulatory Information Guidelines are reviewed for any changes to the reporting process.

Data for the regulatory year is gathered from the latest monthly performance report and

apportioned between UK Power Networks three DNOs, directly where possible and based

on headcount where unique data is not available.

A monthly carbon footprint is produced from all the monthly reports to check on progress.

Any anomalies in the data are highlighted in this monthly report and carefully examined

to understand the reasons behind them.

Corrective actions are put in place if necessary.

1 Greenhouse gas protocol

http://www.ghgprotocol.org/


The entire Business Carbon footprint process has been examined for the last three years

by UK Power Networks own internal audit team.

Elements of the reporting process have also been examined on an annual basis by

external auditors DNV, as part of our ISO 14001 accreditation.

Commentary required for each category of BCF

For each category of BCF in the worksheet (ie Business Energy Usage, Operation

Transport etc) DNOs must, where applicable, provide a description of the following

information, ideally at the same level of granularity as the Defra conversion factors: the methodology used to calculate the values, outlining and explaining any specific

assumptions or deviations from the Greenhouse Gas Protocol

the data source and collection process

the source of the emission conversion factor (this shall be Defra unless there is a

compelling case for using another conversion factor. Justification should be

included for any deviation from Defra factors. )

the Scope of the emissions ie, Scope 1, 2 or 3

whether the emissions have been measured or estimated and, if estimated the

assumptions used and a description of the degree of estimation

any decisions to exclude any sources of emissions, including any fugitive

emissions which have not been calculated or estimated

any tools used in the calculation

where multiple conversion factors are required to calculate BCF (eg, due to use of

both diesel and petrol vehicles), DNOs should describe their methodology in

commentary

where multiple units are required for calculation of volumes in a given BCF

category (eg, a mixture of mileage and fuel volume for transport), DNOs should

describe their methodology in commentary, including the relevant physical units,

eg miles.

DNOs may provide any other relevant information here on BCF, such as commentary on

the change in BCF, and should ensure the baseline year for reference in any description

of targets or changes in BCF is the Regulatory Year 2014-15. DNOs should make clear

any differences in the commentary that relate to DNO and contractor emissions.

Operational Transport

Fuel purchased for UKPN fleet vehicles is captured via fuel cards. Contractor transport

data is included from contractor fuel cards submitted via manual reporting. The diesel

factor has been used for conversion in the E3 template as 99.36% of fuel purchased in

2016/17 was diesel.

A small amount of diesel for temporary generation is purchased on the fuel cards but

recorded separately. This is reported as part of our temporary generation carbon

footprint.

Table 1a shows tCO2e emitted from the UK Power Networks fleet (X)

Key Data Type/

Description

Data

Source

Conversion

Factor

Conversion

Factor

explained

Total Apr 16 to

Mar 17 (tC02e)

Details of data provided

e.g. Direct Measurement,

Estimated or Excluded

Data

Scope

(GHG

Protocol)

X Diesel Fuel

Card 2.612 (litres to

kgC02e) 15,864.32 Measurement 1

The methodology used for calculating operational transport is consistent each year to

obtain comparable data. Fuel usage is not recorded separately for each licence area. The

total has been apportioned based on the number of direct operational staff per area. This


year’s operational staff split was 43.5% in EPN, 29.7% in LPN and 26.7% in SPN. This

compares with 37.0% EPN, 30.3% LPN and 32.7% in SPN in 2014/15. This method was

favoured over geographic area as a split based on km2 shows that our London network

accounts for only 2% of the total km2 across our three areas and this would be a

disproportionate split of CO2e from our transport fleet. The significant increase in EPN’s

apportionment is a result of bringing both the tree trimming and streetworks contracts in-

house.

This represents an increase of 2,152 tCO2e in our Scope 1 operational transport fleet fuel

figures against the baseline year of 2014/15. However, this has to be seen in conjunction

with the related decrease in Scope 3 contractor fleet fuel emissions. Overall Operational

Transport emissions have reduced from 30,948.23 tCO2e in 2014/15 to 25,883.47 tCO2e

in 2016/17. This represents a 16.4% decrease, mainly due to continued modernisation of

our operational fleet.

Table 1b shows the breakdown and the final submitted figures to Ofgem per licence area.

Key Area Direct op. staff Percentage of staff tC02e

A LPN 797 29.7% 4,715.89 B SPN 717 26.7% 4,242.32 C EPN 1167 43.5% 6,906.11

Business Transport

This section refers primarily to employee’s mileage and public transport (attending

meetings etc.) which constitutes our indirect operational emissions. Some of the

emissions included will be directly related to our operational work (such as visits to

projects) due to the data being combined. Any source data available as costs only, has

been converted into kms or litres using best available methodologies before applying the

Defra conversion factors.

Transport records for shared services such as IT, HR, etc. relating to the unregulated

business (D) as well is not recorded separately and all data is included within the

calculations. This is consistent with previous submissions.

The data is captured from four different sources:

1) SAP (financial management system): mileage and travel claimed through expenses

2) Clarity Travel: our approved travel provider

3) Corporate credit card (CCC): travel purchased through company credit cards

4) Fuel cards: fuel purchased through company fuel cards (Private mileage by those using

fuel cards is declared in miles so this is deducted from the mileage expense claims in

SAP)

The data is recorded by type of travel e.g. air, rail and road.

Table 2a shows a breakdown of the amount of tCO2e emitted by our employees (X)

Business Transport - Passenger ROAD

Key Data Type/

Description

Data

Source

Conversion

Factor

Conversion

Factor

explained

Total Apr

16 to Mar

17 (tC02e)


e.g. Direct

Measurement,


Data

Scope

(GHG

Protocol)

X Business Kms

(UKPN company

cars)

SAP 0.118 (Kms to

kgCO2e)

(weighted average)

1063.03 Measurement and

Estimation

3

X Business Kms

(Non UKPN

SAP 0.187 (Kms to

kgCO2e) 340.75 Measurement and

estimation

3

Environment and Innovation Commentary

10

owned

cars/taxis)

(average car

factor)

X Diesel Fuel Card

and fuel

expense claims

2.612 (litres to

kgC02e) 1987.52 Measurement and

estimation

3

Total 3391.3

Business Transport - Passenger RAIL

Key Data Type/

Description

Data Source Conversion

Factor

Conversion

Factor

explained

Total Apr

16 to Mar

17 (tC02e)




Data

Scope

(GHG

Protocol)

X Rail Travel SAP;

corporate

card and Clarity

0.04885 (£ to kms to

kgC02e)

(Clarity data is already in kms)

302.34 Estimate and measurement 3

Business Transport - Passenger AIR

Key Data Type/

Description


Factor

Conversion Factor

explained

Total Apr

16 to Mar

17 (tC02e)

Details of data

provided e.g. Direct

Measurement,


Data

Scope

(GHG

Protocol)

X Air Travel Corporate Credit Card

and Clarity

0.19452

(£ to kms) to kgC02e (weighted factor -

proportional to % of

long haul, short haul or domestic travel)

112.95 Estimate and Measurement

3

Total 3806.59

Business travel data is not recorded by each licence area; therefore the total business

mileage has been apportioned based on the number of indirect staff employed per area.

In 2016/17 this was LPN 30%, EPN 38% and SPN 33% compared to LPN 23%, EPN 50%

and SPN 27% in 2014/15. Vehicles owned by UK Power Networks or bought through the

business needs self-purchase scheme use the actual CO2 rating to improve the quality

and accuracy of data while for privately owned vehicles the DEFRA unknown vehicle

average conversion factor has been used.

Business kilometres are based on actual kilometres claimed. Fuel card usage is based on

actual litres used. Private mileage by fuel card users is reported and paid back. These

kilometres are deducted from the overall business mileage figures. Fuel expense claims

are a monetary value converted into litres based on the average price of a litre of fuel

over the reporting period. Taxi data is in monetary value only. A cost per mile calculation

is ascertained using best available methodologies and applied to the SAP and credit card

data. There has been a push towards those with company cards using fuel cards. This

provides a more accurate measure from a carbon footprinting perspective as it provides a

figure in litres of fuel which eliminates the wide variations between cars and drivers in

actual carbon used per km.

Air and rail travel data is provided by our external travel provider Clarity as actual

kilometres; however the air and rail travel data from SAP and corporate credit cards is in

monetary value only. A cost per kilometre calculation is ascertained using the Clarity data

and applied to the SAP and credit card data. This includes an assumption that the cost of

air and rail transport from SAP data will be the similar to the cost of air and rail transport

from Clarity data.

The provision and encouragement of teleconferencing facilities and a business wide

attempt to reduce travel generally are measures introduced to reduce business mileage.

Table 2b shows the breakdown and the final figures per licence area submitted to Ofgem.


11


Key Area Headcount Percentage of staff tC02e

A LPN 885 30% 917.99

B EPN 1,108 38% 1313.32

C SPN 961 33% 1159.98

Business Transport - Passenger RAIL


A LPN 885 30% 90.58

B EPN 1,108 38% 113.41

C SPN 961 33% 98.36

Business Transport - Passenger AIR


A LPN 885 30% 33.84

B EPN 1,108 38% 42.37

C SPN 961 33% 36.75

Fugitive Emissions

SF6 is an electrical insulating gas that is commonly found in modern electrical switchgear.

This gas can leak following faults or from old equipment. We continue to actively monitor

our assets and have a number of procedures to minimise the escape of SF6 to the

environment. We measure the SF6 that is lost in terms of top ups required. Emissions

from air conditioning has not been included, consistent with our return in previous years.

Table 3a shows the data by licence area submitted to Ofgem.

Key Data Type/

Description

Data

Source

Conversion

Factor

Conversion

Factor

explained

Total Apr

16 to Mar

17 (tC02e)

Details of data provided e.g.

Direct Measurement,

Estimated or Excluded Data

Scope

(GHG

Protocol)

A LPN SF6

Losses

Ellipse 22800

(kg to kgC02e) 367.08 Measurement 1

B SPN SF6

Losses

Ellipse 22800


C EPN SF6

Losses

Ellipse 22800


Fuel Combustion

This section refers to the emissions from plant and equipment such as temporary

generators used during fault repairs and planned work on the network.

The data is captured through three different sources:

1) Contractors provide standby diesel generators and report the monthly fuel usage of

these generators. Invoices from diesel fuel supplied are used to collate the monthly fuel

usage by licence area. Though provided by external contractors on an as needed basis, as

they are in direct use on our networks, we class these as Scope 1 rather than Scope 3

emissions

2) Data from fuel cards capture the fuel used by company owned plant and equipment.

3) Invoices from the tanker company which fills the bowsers at several of our sites used

to fuel our own generators.


12

The source data is separated by area so no headcount conversion needs to be applied.

This is consistent with previous years.

Table 4a details our generator and bowser usage.

Key Data Type/

Description


Factor

Conversion

Factor

explained

Total

Apr 16 to

Mar 17

(tC02e)

Details of data

provided e.g.

Direct

Measurement,

Estimated or

Excluded Data

Scope

(GHG

Protocol)

X Stand-by Diesel generators; Plant and

Equipment

Invoices; Deliveries to

bowsers; fuel

cards

2.966

(red diesel litres to

kgC02e)

10507.72 Measurement 1

Table 4b shows the final figures per licence area submitted to Ofgem.

Key Area tC02e

A LPN 724.71

B SPN 5,516.29

C EPN 4,266.72

Losses

These calculations measure units exiting our distribution network compared to units

entering from Grid Supply Points and any other sources.

Please note the final data for 2016/17 is expected to deteriorate as future reconciliations

are received. The current position should therefore not be taken as a forecast of future

performance.

Table 5a shows the data by licence area submitted to Ofgem.

Key Data Type/

Description


Factor

Conversion

Factor

explained

Total Apr 16

to Mar 17

(tC02e)

Details of data

provided e.g.

Direct

Measurement,

Estimated or

Excluded Data

Scope

(GHG

Protocol)

A LPN Losses Billing for

each site 0.412

(kWh to

tC02e) 779,598.60 Measurement

B SPN Losses Billing for

each site 0.412

(kWh to

tC02e) 541,021.65 Measurement

C EPN Losses Billing for each site

0.412

(kWh to tC02e)

1,016,939.40 Measurement

Contractors

When reporting BCF emissions due to contractors in the second half of the worksheet

please:

Explain, and justify, the exclusion of any contractors and any thresholds used for

exclusion.

Provide an indication of what proportion of contractors have been excluded. This

figure could be calculated based on contract value.

Please provide a description of contractors’ certified schemes for BCF where a breakdown

of the calculation for their submitted values is not provided in the worksheet.

If a DNO’s accredited contractor is unable to provide a breakdown of the calculation and

has entered a dummy volume unit of ‘1’ in the worksheet please provide details of the

applicable accredited certification scheme which applies to the reported values. Contractor Definition

Contractors were originally selected for inclusion by the size of the financial contract

(above a £250k spend) and the scope of work i.e. activities involved in developing and


13

operating the electricity network. Where there have been contractual changes, data from

the new contractors has been included maintaining a level of consistency within the scope

of work.

Contractors are reviewed regularly to maintain a consistent approach.

As part of our agreement with our contractors they are required to include any data from

work that they sub-contract, and to report data that is accumulated as a direct result of

works undertaken for UK Power Networks.

The data is not gathered by individual DNO so contractor emissions are based on direct

operational staff headcount. This year’s operational staff split was 43.5% in EPN, 29.7%

in LPN and 26.7% in SPN. The proportion attributed to EPN has increased by 6.5% since

2014/15, due to bringing streetworks and tree trimming functions in-house with some

contracting staff being transferred over. This makes an increase in share in contractor

emissions for EPN counter intuitive but it maintains consistency with other areas of the

Business Carbon Footprint and is the methodology that works best for UK Power

Networks and the atypical nature of the London Network.

Table 6a shows a breakdown of tCO2e emitted from our contractors (Y) operational transport.

Key Data Type/

Description

Data

Source

Conversion

Factor

Conversion

Factor

explained

Total Apr 16

to Mar 17

(tC02e)




Data

Scope

(GHG

Protocol)

Y Diesel Contractor

fuel card 2.612 (litres to

kgC02e) 10019.15 Measurement 3



A LPN 797 29.7% 2,978.33 B SPN 717 26.7% 2,679.25 C EPN 1167 43.5% 4,361.57

Table 7a shows a breakdown of the amount of tCO2e emitted by our contractors (Y) Business mileage.

Key Data Type/

Description

Data

Source

Conversion

Factor

Conversion

Factor

explained

Total Apr

16 to Mar

17 (tC02e)




Data

Scope

(GHG

Protocol)

Y Contractor

Business kms

Contractor

records 0.187 (Kms to

kgCO2e) (average car

factor)





A LPN 797 29.7% 85.86

B SPN 717 26.7% 77.24

C EPN 1167 43.5% 125.73

Table 8a shows a breakdown of the amount of tCO2e emitted by our contractors (Y) for Plant and Equipment

Key Data Type/

Description


Factor

Conversion

Factor

explained

Total

Apr 16 to

Mar 17

(tC02e)

Details of data

provided e.g.

Direct

Measurement,

Estimated or

Excluded Data

Scope

(GHG

Protocol)

Y Contractor Plant and

equipment

Contractor

records

2.966

(red diesel

litres to kgC02e)



14



A LPN 797 29.7% 226.67 B SPN 717 26.7% 203.90 C EPN 1167 43.5% 331.94

Building energy usage

Natural gas, Diesel and other fuels are all categorised as fuel combustion and must be

converted to tCO2e on either a Gross Calorific Value (Gross CV) or Net Calorific Value (Net

CV) basis. The chosen approach should be explained, including whether it has been adapted

over time. Substation Electricity must be captured under Buildings Energy Usage. Please explain the

basis on which energy supplied has been assessed.

Building Energy Usage data is collated from electricity and gas bills received for each

location. Staff for the unregulated business are predominantly concentrated on two sites,

Chatham depot and Newington House. Half of the electricity consumption at each of these

sites is deducted to allow for the unregulated business (D). Offices at the airports for

example, where all staff are part of the unregulated business are excluded entirely.

Data is measured in kWh then converted into tCO2e. In shared buildings overall UK Power

Networks headcount is used as a factor to determine energy used per DNO. The split used

this year is EPN 40%, LPN 30%, SPN 30%. This headcount split is only a slight change on

that used for the 2014/15 baseline carbon footprint of EPN 41%, LPN 29%, SPN 30%. Large

offices, containing many staff with centralised functions are designated as shared offices as

opposed to belonging to the DNO in which they are geographically located and their energy

usage divided between all 3 DNOs.

We use the Gross CV conversion factor for gas as recommended by Defra, as it represents

the CO2 content of gas as it is delivered to buildings. Gas is a very minor element of our

overall footprint.

Savings have been introduced through consolidation of staff into fewer building and energy

saving initiatives such as the introduction of LED lighting in many offices.

Table 9a shows a breakdown by energy type and licence area submitted to Ofgem.

Key Data Type/ Description Data Source Conversion

Factor

Conversion

Factor

explained

Total Apr

16 to Mar

17 (tC02e)

Details of data

provided e.g.

Direct

Measurement,

Estimated or

Excluded Data

Scope

(GHG

Protocol)

A LPN Electricity Usage Energy Bills 0.412

(kWh to kgC02e)

1,550.06 Measurement 2

B SPN Electricity Usage Energy Bills 0.412

(kWh to


C EPN Electricity Usage Energy Bills 0.412

(kWh to


Total 4,442.48

A LPN Gas Usage Energy Bills 0.184 (Gross

CV)

(kWh to

kgC02e) 51.32

Measurement 2

B SPN Gas Usage Energy Bills 0.184 (Gross

CV)

(kWh to

kgC02e) 81.87

Measurement 2

C EPN Gas Usage Energy Bills 0.184 (Gross

CV)

(kWh to kgC02e)


Total 263.55


15

A detailed project to analyse electricity usage in our substations is the basis of the reporting

and billing of our unmetered supply. Substations were separated into Grid, Primary and

Secondary substations and comprehensive analysis of the energy usage of each type

undertaken. Typical energy usage on aspects like heating, lighting and security were

determined and then applied across the business based on the numbers of unmetered

substations of that type in operation. Annual consumption of energy used in unmetered

substations has been assessed based on the number and type of plant installed in each

licence area. This method has been consistent with that used in previous years.

In 2014/15 an estimated figure was used for our metered substations due to the large

number with unread meters. However, after a drive to get meters read and a major push on

any properties more than 90 days in arrears on a meter reading, actual data from all

metered substations is included in the data for the RIIO ED1 period. This has had the

biggest impact in LPN where the majority of substations are metered. On the few occasions

where it has not been possible to obtain a reading for the latest month at the time of

submission an average reading based on all previous readings this year has been inserted.

Table 9b shows the substation electricity usage for metered and unmetered sites by licence area.

Key Data Type/

Description

Data

Source

Conversion

Factor

Conversion

Factor

explained

Total Apr 16

to Mar 17

(tC02e)




Data

Scope

(GHG

Protocol)

A LPN Metered

and Unmetered

Energy

Bills and

Assessed

0.412

(kWh to

kgC02e) 6345.02 Measurement 2

B SPN Metered

and Unmetered

Energy

Bills and

Assessed

0.412

(kWh to


C EPN Metered and Unmetered

Energy Bills and

Assessed

0.412

(kWh to kgC02e)

9,322.46 Measurement 2

Total 19682.35

E4 – Losses Snapshot



Since our previous E4 submission it has become apparent that our previous

reporting methodology, in relation to transformers, does not align with Ofgem’s

guidance. As ECO2015 specifications are now mandatory, and therefore represent

the baseline scenario, claiming benefits solely attributable to the installation of

ECO2015 specification is no longer justified. Instead, only transformer activities

that deliver energy improvements, have an incremental cost over the baseline

scenario and demonstrate a positive CBA are now included within our submission.

EPN

Transformer replacement

Recent CBA analyses have demonstrated that the following secondary

transformer size increments are economically justifiable from a losses

perspective:

GMTs, upsize 315kVA to 500 kVA, and 800kVA to 1000kVA.

This approach yielded a loss improvement of 34.9MWh in EPN (10 GMTs, no PMTs


16

reported).

Prices for different transformer sizes were obtained from UKPN’s Compatible Units

price list, and the costs of the various upgrades were determined using this

information. This approach yielded a total cost increment of £18.2k for the above-

mentioned secondary transformers.

In order to report the RIGs volumes in the required format the split between work

activities was taken from the ratio of work reported elsewhere in our RIGs tables,

with ‘Asset Replacement’, Reinforcement’ and ‘Other’ being the three reportable

categories. These percentages have been applied to the GMT volumes that deliver

loss improvements in EPN and are reported in column O.

Column J of E4 relates to unit costs, and these unit costs were taken as the

average of the last five years’ values reported in CV7.

Column W values are determined by multiplying the volumes and the unit costs to

provide the Estimated Total Cost. Column AE multiplies Ofgem’s value of losses

at £48.42/MWh by the estimated energy loss improvements in column AM to

provide the Justified Cost.

Column AM shows the loss reductions for each category and activity.

As mentioned earlier, in EPN £18.2k was spent installing 10 larger GMTs. The cost

of these upgrades is shown in column AT, split according to volumes of work

reported.

In summary, the loss improvement given the revised methodology stands at

34.9MWh for secondary transformers.

Using our previous reporting methodology, detailed in the section below entitled

‘Earlier approach’, a total of 610 secondary transformers were installed which

delivered improvements in network losses relative to the units that they replaced.

Overall, an improvement of 2321.3 MWh related to secondary network

transformers was achieved. In addition, five grid transformers were replaced

which realised improvements of 2335MWh. These values are not included within

our RIGs return but are highlighted in this commentary for information purposes

only. A supplementary E4 snapshot is also included for information purposes.

LV Cables

LV cable size increases aimed at decreasing network energy losses were reviewed

and subjected to continued CBA assessment in the past year, and it was found

that these upgrades still stand justified.

Costs to increase cable sizes were calculated based on the price differentials

between cables of various sizes (95mm = £6.17, 185mm = £11.00 and 300mm =

£13.84 per metre in 12/13 monetary values). Across all three licence areas in

2015, 625km of LV cable was used with a split of 45% as 95mm, 35% as 185mm

and 20% as 300mm. In 2016/17 a total of 576 km of LV cable was utilised but it

was noted that there has been a shift toward larger sizes following the

amendment of associated LV Engineering Design Standards. The percentage split

is now 31% of 95mm, 41% of 185mm and 28% of 300mm.

This change means that the use of 95mm cable was reduced by 80.7km in total,

while we saw corresponding increments of 33.1km for 185mm and 47.6km for

300mm respectively. As the geographical split is known, values have been

calculated across the licence areas. In EPN, the total improvement equates to


17

1614.8 MWh at a cost of £174k (in 12/13 money). This cost was further

apportioned according to volumes stated for the various work categories and

entered into column AT of the losses snapshot E4. The loss benefits (MWh) were

accounted for in column AM.

As mentioned above, cable-related activities saved 1614.8 MWh in EPN.

Combining this with the above-mentioned reportable transformer activity yields

1649.7 MWh and represents UK Power Networks’ 2016/17 E4 submission for

EPN.

Earlier approach2

In EPN a total of 834 secondary network transformers were replaced in 2016/17.

Using UK Power Networks’ asset register, details of the sites where transformers

were installed have been identified. These were cross referenced with units that

were removed from site.

Using the age and capacity, and referring to a number of generic transformer

specifications (pre 1955, 1971, 1979, 1984 & ECO 2015), enabled us to quantify

the iron and copper losses associated with the various transformers . Using an

assumed loading level and load loss factor, and assuming that the load on the

transformer remains constant even if a larger unit is installed, the old and new

copper losses were estimated. Subtracting the sum of new losses from the old

yields the loss-related differential benefit of the work undertaken on a site-by-site

basis. UK Power Networks recognise that where a larger transformer has been

installed it likely corresponds with a load-related increase. However, in the

interest of comparing losses on a like-for-like basis, a constant load has been

assumed.

To identify work that delivered improvements in losses the transformer

replacements that didn’t deliver benefits were dismissed. This meant that in EPN

610 of the 834 transformers have been considered. The 610 transformers

mentioned here consist of 201 PMTs and 409 GMTs. Amongst the 610

transformers that delivered benefits were 233 units of increased capacity. The

233 transformers further consist of 113 PMTs and 120 GMTs.

To calculate the incremental cost associated with this work the volumes

associated with like-for-like replacement were dismissed as the cost of an ECO

2015 specification transformer is accepted as equal to the previous specification

that was used.

To calculate the incremental cost of installing larger units, we used information

from our “Compatible Units” price list, which is ordinarily used to estimate quotes

for new installations. Overall, calculations revealed a total price increment of

£471.3k to upsize the above-mentioned 233 units (PMT’s and GMT’s combined, in

12/13 monetary values).

In EPN, based on the information above, an overall improvement in network

losses of 2,321.3 MWh per annum was achieved at a total incremental cost of

£471.3k. Columns AT & AM were populated accordingly.

The energy savings associated with Grid and Primary transformers were

calculated using half-hourly average currents and transformer test certificate

information. In instances where there were no transformers previously installed,

we compared loss performance against a 1984 specification equivalent unit to

establish an energy loss differential (given that ECO 2015 transformers are used

2 Earlier approach aligns with E4 Losses Snapshot described as “Losses Snapshot E4 (Earlier Approach)”.


18

at present). In brief, the methodology was as follows:

1. Obtain iron and copper loss specifications along with the transformers’ MVA

and voltage ratings.

2. Obtain half-hourly loads over the course of a full year, and obtain the

maximum load within this period.

3. Using the above-mentioned information, calculate a Load Loss Factor (LLF) for

each site in question to account for the nonlinear characteristics of copper losses

(I2R).

4. Calculate the annual copper losses by multiplying the copper loss at peak load

by the LLF and 8760 hours.

5. Multiply the iron loss value by 8760 hours to calculate annual iron losses.

6. The annual iron and copper losses are summated for each transformer to

derive the unit’s total annual losses.

7. The differences between the total annual losses associated with the old and

new units thus account for the energy savings achieved using transformers of the

latest specification.

There has been no Primary Transformer replacement in EPN during the past fiscal

year, but five Grid Transformers were replaced during the interval. The losses

saving for each Grid Transformer was 467 MWh on average, which summates to

a total of of 2,335 MWh. These replacements were done at zero additional cost

as the work was funded through “Other” funded activities. This loss decrease

benefit was recorded in Column AM of the Losses Snapshot E4.

To conclude this section, the table below shows a summary of energy savings

attributed to the various asset classes.

EPN MWh losses reduced

Primary & Grid Transformers 2335.0

Secondary Transformers 2321.3

LV Cables 1614.8

Total 6271.1

LPN




perspective:


This approach yielded a loss improvement of 24.4 MWh in LPN (7 GMTs, no PMTs

reported).

Prices for the various transformer sizes were obtained from our Compatible Units

price list, and the overall cost of the above-mentioned upgrades was calculated

using this information. This approach yielded a total cost increment of £12.7k for

the above-mentioned secondary transformers.





loss improvements in LPN and are reported in column O.


19



Column W values are determined by multiplying the volumes by the unit costs to


at £48.42/MWh by the estimated losses benefits taken from column AM to


Column AM shows the losses benefits for each category and activity.

As mentioned earlier, in LPN £12.7k was spent installing 7 larger GMTs. The cost

of these upgraded is shown in column AT, split according to volumes of work

reported.

In summary then, the loss improvement given the current methodology stands at

24.4 MWh for secondary transformers. At the same time, cable-related activities

annually save 464.9 MWh in LPN.


‘Earlier approach’, a total of 293 secondary transformers were installed which

delivered improvements in network losses relative to the units that they replaced.

Overall, an improvement of 1501.2 MWh related to secondary network

transformers was achieved. In addition, Primary & Grid transformers were

replaced which realised improvements of 1195MWh. These values are not

included within our RIGs return but are highlighted in this commentary for

information purposes only. A supplementary E4 snapshot is also included for

information purposes.

LV Cables

LV cable size increases aimed at decreasing network energy losses were reviewed

and subjected to continued CBA assessment in the past year, and it was found

that these upgrades still stand justified.





and 20% as 300mm. In 2016/17 a total of 576km of LV cable was utilised but it







calculated across the licence areas. In LPN, the total improvement equates to

464.9 MWh at a cost of £50.09k (in 12/13 money). This cost was apportioned

according to volumes stated for the various work categories and entered into

column AT of the losses snapshot E4. The loss benefits (MWh) were accounted for

in column AM.

Cable-related activities saved 464.9 MWh in LPN.

Combining improvements in reportable transformer activity and LV cable

installation yields 489.3 MWh and represents UK Power Networks’ 2016/17 E4

submission for LPN.


20

Earlier approach3

In LPN a total of 346 secondary network transformers were replaced in 2016/17.




Using the age and capacity of the units that were replaced, and referring to a

number of generic transformer specifications (pre 1955, 1971, 1979, 1984 & ECO

2015), enabled us to quantify the iron and copper losses associated with the

various transformers . Using an assumed loading level and load loss factor, and

assuming that the load on the transformer remains constant even if a larger unit

is installed, the old and new copper losses were estimated. Subtracting the sum

of new losses from the old yields the differential loss benefit for the work

undertaken on a site-by-site basis. UK Power Networks recognise that where a

larger transformer has been installed it likely corresponds with a load-related

increase. However, in the interest of comparing losses on a like-for-like basis, a

constant load has been assumed.

To identify work that delivered improvements, transformer replacements that

didn’t deliver benefits were dismissed. This meant that in LPN 293 of the 346

transformers have been considered. The 293 transformers mentioned here were

all GMTs. Amongst the 293 transformers that delivered benefits were 86 units of

increased capacity.

To calculate the incremental costs associated with this work the volumes

associated with like-for-like replacement were dismissed as the cost of an ECO

2015 spec transformer is accepted as equal to the previous specification that was

used.


from our “Compatible Units” price list, which we ordinarily use to estimate quotes

for new installations. Overall, we calculated a total price increment of £267.9k to

upsize the above-mentioned 86 units (in 2012/13 monetary values).

In LPN, based on the information above, an overall improvement in network

losses of 1501.2 MWh per annum was achieved at a total incremental cost of



calculated using individual half-hourly average currents and transformer test

certificate information. In instances where there were no transformers previously

installed, we compared loss performance against a 1984 specification equivalent

unit to establish an energy loss differential (given that ECO 2015 transformers

are used at present). In brief, the methodology was as follows:







(I2R).






21




new units thus account for the energy savings achieved using transformers of the

latest specification.

There were 4 Primary Transformer replacements in LPN during the past fiscal

year, and 1 Grid Transformer was replaced during the same interval. The losses

saving for the Grid Transformer was 467.4 MWh, while the Primary Transformer

replacements yielded savings of 727.6 MWh collectively. The Grid and Primary

Transformer savings hence add up to 1195 MWh in total. These replacements

were done at zero additional cost as the work was funded through asset

replacement and “other” activities. These loss decrease benefits were recorded in

Column AM of the Losses Snapshot E4.

In summary then, transformer-related activities save 2696.3 MWh annually in

LPN based on the above-mentioned methodology.



LPN MWh losses reduced



LV Cables 464.9

Total 3161.1

SPN




perspective:


This approach yielded a loss improvement of 17.5 MWh for GMTs in SPN (5 GMTs,

no PMTs reported).

Prices for the various transformer sizes were obtained from UKPN’s Compatible

Units price list, and the overall incremental cost of the upgrades was calculated

using this information. This approach yielded a total cost increment of £9.08k for

the above-mentioned five secondary transformers.





loss improvements in SPN and are reported in column O.



Column W values are determined by multiplying the volumes by the unit costs to


at £48.42/MWh by the estimated losses benefits taken from column AM to


22


Column AM shows the loss reductions for each category and activity.

As mentioned earlier, in SPN £9.08k was spent installing 5 larger GMTs. The cost

of these upgrades is shown in column AT, split according to volumes of work

reported.

In summary then, the loss improvement given the current methodology stands at

17.5 MWh for secondary transformers.


‘Earlier approach’, a total of 336 transformers were installed which delivered

improvements in network losses relative to the units that they replaced. Overall,

an improvement of 1340.2 MWh related to secondary network transformers was

achieved. In addition, Primary & Grid Transformer replacements realised

improvements of 557.3 MWh. These values are not included within our RIGs

return but are highlighted in this commentary for information purposes only. A

supplementary E4 snapshot is also included for information purposes.

LV Cables

LV cable size increases aimed at decreasing network energy losses were also

reviewed and subjected to continued CBA assessment in the past year, and it was

found that these upgrades still stand justified.





and 20% as 300mm. In 2016/17 a total of 576km of LV cable was utilised but it







calculated across the licence areas. In SPN, the total improvement equates to

660.6 MWh at a cost of £71.2k (in 12/13 money). This cost was apportioned

according to volumes stated for the various work categories and entered into

column AT of the losses snapshot E4. The loss benefits (MWh) were accounted for

in column AM.

Combining the above improvements due to transformer-related activity with LV

cable-related loss reductions yields 678 MWh and represents UK Power Networks’

2016/17 E4 submission for SPN.

Earlier approach4

In SPN a total of 452 secondary network transformers were replaced in 2016/17.




Using the age and capacity of the units that were replaced, and referring to a



23

number of generic transformer specifications (pre 1955, 1971, 1979, 1984 & ECO

2015), enabled us to quantify the iron and copper losses associated with the

various transformers . Using an assumed loading level and load loss factor, and

assuming that the load on the transformer remains constant even if a larger unit

is installed, the old and new copper losses were estimated. Subtracting the sum

of new losses from the old yields the differential loss benefit of the work

undertaken on a site-by-site basis. UK Power Networks recognise that where a

larger transformer has been installed it likely corresponds with a load-related

increase. However, in the interest of comparing losses on a like-for-like basis, a

constant load has been assumed.

To identify work that delivered improvements in losses the transformer

replacements that didn’t deliver benefits were dismissed. This meant that in SPN

336 of the 452 transformers have been considered. The 336 transformers

mentioned here consist of 96 PMTs and 240 GMTs. Amongst the 336 transformers

that delivered benefits were 124 units of increased capacity.

To calculate the incremental cost associated with this work the volumes

associated with like-for-like replacement were dismissed as the cost of an

ECO2015 spec transformer is accepted as equal to the previous specification that

was used.


from our “Compatible Units” price list, which we ordinarily use to estimate quotes

for new installations. Overall, we calculated a total price increment of £266.5k to

upsize the above-mentioned 124 units (PMT’s and GMT’s combined, in 2012/13

monetary values).

In SPN, based on the information above, an overall improvement in network

losses of 1,340.2 MWh per annum was achieved at a total incremental cost of



calculated using individual half-hourly average currents and transformer test

certificate information. In instances where there were no transformers previously

installed, we compared loss performance against a 1984 specification equivalent

unit to establish an energy loss differential (given that ECO 2015 transformers

are used at present). In brief, the methodology was as follows:







(I2R).







new units thus account for the energy savings achieved by using transformers of

the latest specification.

There has been 1 Primary Transformer replacement in SPN during the past fiscal

year, and 2 Grid Transformers were replaced during the same interval. The losses


24

saving for the Grid Transformers amounted to 518.2 MWh, while the Primary

Transformer brought about a loss improvement of 39.1 MWh. Combined, these

two figures add up to 557.3 MWh. These replacements were done at zero

additional cost as the work was funded through asset replacement and “other”

activities. These loss decreasses were recorded in Column AM of the Losses

Snapshot E4.

In summary then, transformer-related activities save 1,897.5 MWh annually in

SPN based on the above-mentioned methodology.



SPN MWh losses reduced



LV Cables 660.6

Total 2558.1

Programme/Project Title

Please provide a brief summary and rationale for each of the activities in column

C which you have reported against.

As we work through the activities detailed within our losses strategy we currently

are tackling areas where data is available. As more data becomes available the

number of topics that we report will correspondingly increase. We will proactively

seek to obtain the relevant data to enable us to report further areas in future

RIGs submissions.

Currently we are able to report loss improvements associated with cables and

transformers. These activities are split between Asset Replacement,

Reinforcement and ‘Other’. Distribution transformers are split further between

PMT and GMT categories.

Primary driver of activity

If, in column E, you have selected ‘Other’ as the primary driver of the activity,

please provide further explanation.

The “Other” category mentioned above captures volumes associated with:

Diversions, Quality of Supply, OHL Clearance, Faults, Legal + Safety,

Environmental and Connections i.e those associated with volumes from V3 and

V5.

Baseline Scenario

Please provide a brief description of the ‘Baseline Scenario’ inputted in column K

for each activity.

The baseline scenario captures the unit cost to do work in the ‘business as usual’

mode. The unit costs of work undertaken to improve network losses are detailed

in the respective CBA worksheets.

Use of the RIIO-ED1 CBA Tool


25

DNOs should use the latest version of the RIIO-ED1 CBA Tool for each of the

activities reported in column C. Where the RIIO-ED1 CBA Tool cannot be used to

justify an activity, DNOs should explain why and provide evidence for how they

have derived the equivalent figures for the worksheet. The most up-to-date CBA

for each activity reported in the Regulatory Year under report must be submitted.


26

Changes to CBAs

If, following an update to the CBA used to originally justify the activity in column

C, the updated CBA shows:

a negative net benefit for an activity, but the DNO decides it is in the best

interests of consumers to continue the activity, or

a substantively different NPV from that used to justify an activity that has

already begun.

the DNO should include an explanation of what has changed and why the DNO is

continuing the activity.

For example, where the carbon price used in the RIIO-ED1 CBA Tool has changed

from that used to inform the decision such that the activity no longer has a

positive NPV.

Cost benefit analysis additional information

Please include a reference to the file name and location of any additional relevant

evidence submitted to support the costs and benefits inputted into this

worksheet. This should include the most recent CBA for each activity reported in

column C in the Regulatory Year under report.

E5 – Smart Metering



n/a

Actions to deliver benefits

Detail what activities have been undertaken in the relevant regulatory year to

produce benefits of smart metering where efficient and maximise benefits overall

to consumers. At a minimum this should include:

A description of what the expenditure reported under Smart Meter

Information Technology Costs is being used to procure and how it expects

this to deliver benefits for consumers.

A description of the benefits expected from the non-elective data procured

as part of the Smart Meter Communication Licensee Costs. The DNO

should set out how it has used this data.

A description of the Elective Communication Services being procured, how

it has used these services, and a description of the benefits the DNO

expects to achieve.

n/a


27

Calculation of benefits

Explain how the benefits have been calculated, including all assumptions used

and details of the counterfactual scenario against which the benefits are

calculated.

n/a


DNOs should use the latest version of the RIIO-ED1 CBA Tool for each solution

reported in the worksheet in the Regulatory Year under report. Where the RIIO-

ED1 CBA Tool cannot be used to justify a solution, DNOs should explain why and

provide evidence for how they have derived the equivalent figures for the

worksheet. The most up-to-date CBA for each activity reported in the Regulatory

Year under report which are used to complete the worksheet must be submitted.

n/a




worksheet. This should include the most recent CBA for each solution reported in

the Regulatory Year under report.

n/a

E6 – Innovative Solutions

Automated Power Restoration System



The following section details the high level assumptions made in the calculations

for this solution.

Benefits are calculated for each individual outage actually occurring in the

reporting period on the APRS-enabled circuits, including the number of

affected customers on the specific network.

The number of CIs that would not have been restored without APRS in less

than 3 minutes is estimated as a percentage of the total CIs saved

For outages with a counterfactual that would not have restored supplies in

less than 3 minutes (incurring a CI) an outage duration and corresponding

CML impact is conservatively assumed at 4 minutes.


28

General

For each of the solutions please explain:

In detail what the solution is, linking to external documents where

necessary.

How this is being used, and how it is delivering benefits.

What the volume unit is and what you have counted as a single unit.

How each of the impacts have been calculated, including what

assumptions have been relied upon.

What is the solution?

The Automated Power Restoration System (APRS) is a module of PowerOn. It is

an algorithm triggered when an ‘unexpected’ open is received via SCADA where it

is deployed. The Algorithm traces the circuit, polls SCADA on circuit, identifies

fault from FPIs and or Protection devices. It uses the current running conditions,

isolates identified fault, restores healthy network after checking loads.

How is the solution being used?

APRS is currently been applied on the 11kV & 6.6kV network in all three UK

Power Network’s licences.

How is the solution delivering benefits?

CI Impact

CI’s are reduced by enabling the control system to restore suppliers in less than 3

minutes by automatically fault switching via SCADA , in many cases faster than a

human operator.

CML Impact

For those outage events where CIs are saved, there is a corresponding

improvement in CMLs due to the longer restoration time that would have

occurred without the APRS solution.

What is the volume unit and what has been counted as a single unit?

Addition Unit: “1 APRS scheme, or instance of the algorithm, commissioned on

the distribution network”

Disposal Unit: 1 APRS scheme decommissioned.

CI Impact

The volume unit for CI is “1 interruption per 100 customers”

CML Impact

The volume unit for CML is “1 minute lost”

How have each of the impacts been calculated?

Impacts have been calculated as CI and CML reduction benefits. See the

“Calculation of Benefits” section below.

What assumptions have been relied upon?

See the “Calculation of Benefits” box below for details of the calculation


29

methodology and assumptions.



reported in the Regulatory Year under report. Where the RIIO-ED1 CBA Tool

cannot be used to justify a solution, DNOs should explain why and provide

evidence for how they have derived the equivalent figures for the worksheet. The

most up-to-date CBA for each solution reported in the Regulatory Year under

report which are used to complete the worksheet must be submitted.

The standard RIIO-ED1 CBA Tool has been used.

Changes to CBAs


C, the updated CBA shows a negative net benefit for an activity, but the DNO

decides it is in the best interests of consumers to continue the activity, the DNO

should include an explanation of what has changed and why the DNO is


No changes to the Ofgem CBA template have been made.




calculated.

Counterfactual

Now based on less than 3 minute restoration performance (CIs saved) in the last

3 years. 2014 – 2015 used as baseline

CI Impact

The benefit is calculated as the reduction in number of customers interrupted per

100 customers using the solution compared to not using the solution for each

specific outage. (Number of customers interrupted per 100 customers, ∆ between

counterfactual and baseline) x £/interruption

The percentage of APRS interventions that could otherwise have been prevented

from incurring CIs through traditional means is assumed to be as outlined below.

This is based on a sample of 180 events in LPN taken in 2015/16.

a. LPN: 25%

b. SPN: 25%

c. EPN: 25%

CML Impact

The benefit is calculated as the reduction in Customer Minutes Lost using APRS

compared to not using ARPS for each specific outage. Customer minutes lost (∆

between counterfactual and baseline) x £/minute. A minimum 4 minutes outage

is conservatively assumed for those events reported where CMLs were avoided.

Cost: Ongoing and Investment


30

The costs are captured as the APRS deployment project costs, including

development, testing, deployment of the software solution and license costs.






Automated Power Restoration System_2016-17 E6 CBA_v1.0

CNAIM (ARP)



Benefits are only calculated when there is sufficient data (i.e. if there is no data

life expectancy for 2010/11 or 2014/15 then benefits aren’t calculated.

It is assumed that assets whose current life at the time of the introduction of

Asset Risk Prioritisation (ARP) is within 1 standard deviation of the average life

will not be impacted by the solution. This removes assets that are already at the

end of the useful life at the time of the introduction of ARP from being included in

the benefits as it is unlikely that ARP would extend their lives.

It is assumed that there are 3 parts to the profile of replacements. These are as

follows:

a) Where the number of replacements follows the baseline profile

b) Where the number of replacements is zero (because they are deferred)

c) Where the number of replacements follows the evaluation case profile with

the extended lifespan of assets.

The modelling assumes all assets are replaced, none are disposed of.

General



necessary.






The introduction in ED1 of the Common Network Asset Indices Methodology

(CNAIM) for DNOs to report information relating to asset health and criticality

provides the capability to trade off the financial and technical consequences of

future decisions to replace assets, refurbish assets or introduce an enhanced

maintenance regime.


31

Are there any external documents to link to?

DNO COMMON NETWORK ASSET INDICES METHODOLOGY - Health & Criticality -

Version 1.1

(30/01/2017 )


UK Power Networks is considered to be actively managing a pool of health indices

4 and 5 assets which are closer to service failure than may be the case for other

DNOs with different asset replacement methodologies where assets could

potentially be retired too early.

The CNAIM models are another example of modelling innovation. These models

use a combination of information relating to an asset’s age, environment, duty

and specific condition and performance information to calculate network risk. This

can inform investment decisions as to when an asset requires intervention

(replacement, refurbishment, retrofit or other appropriate action) and how to

prioritise the order of such interventions to ensure value for money.


Gross Avoided Costs

Costs of replacement are deferred as the life of assets is increased.


Gross Avoided Costs

Avoided Replacement Costs – The volume unit for Avoided Replacement Cost is 1

asset.


The impacts are considered jointly with benefits in the “Calculation of Benefits”

box below.


The assumptions behind the impacts are considered jointly with benefits in the

“Calculation of Benefits” box below.










32

Changes to CBAs






No changes to the CBA template have been made




calculated.

Counterfactual

The counterfactual assumed is the based on the assumed lifespan of assets prior

to the implementation of CNAIM modelling in 2016.

Gross Avoided Costs

The benefit is calculated as the sum the deferred costs of replacement of assets

for all assets modelled by CNAIM.

Assumptions: It is assumed that only assets younger than 1 standard deviation of

age less than the average age are impacted by this solution. This removes the

benefits from assets already at the end of their useful life.

Cost:

Costs reported for the reporting period are calculated using the UK Power

Networks ED1 asset specific unit cost allowances ( CV3) and the population of

assets aged beyond the CNAIM-based life expectancy.






CNAIM (ARP)_2016-17 E6 CBA_v1.0

Demand Side Response




for this solution.

The solution has been implemented on a substation within UKPN’s EPN

network.


33

The approach to calculating Totex is to refer to the Submission Asset

Management Plan for the baseline Totex and the Current Asset

Management Plan forecast for the evaluation Totex. This allows the

evaluation case to consider changes to both expenditure levels and timing

of reinforcement due to DSR deployment as opposed to the alternate

approach of time-shifting the baseline Totex to derive the evaluation

Totex.

Within the CBA, where actual cost data is available (i.e. for the current

reporting year) the model overwrites forecast expenditure in the

evaluation case.

General



necessary.






Demand Side Response (DSR) can be delivered either from a reduction in

demand from demand customers, or by generators generating for a contracted

period. It can address occasional shortfalls in capacity on the network and

thereby avoid reinforcement.

The solution is qualified as an innovative solution as it was developed through UK

Power Networks’ LCNF Tier 2 funded project “Low Carbon London”.


http://innovation.ukpowernetworks.co.uk/innovation/en/research-area/demand-

side-response/


The solution has been developed through a number of UK Power Networks

innovation projects and is now integrated into business as usual for deployment.

Low Carbon London – trial program that contracted with industrial and

commercial (I&C) customers to reduce their peak loads (through either

reducing demand or using local generation) in exchange for payments and

also deployed a dynamic time-of-use (ToU) tariff with early smart

metering customers.

Smarter Network Storage – LCNF-funded project that is demonstrating

a multi-purpose application of 6MW/10MWh of energy storage at Leighton

Buzzard primary substation.

Vulnerable Customers and Energy Efficiency – UKPN is trialing DSR

and service improvement opportunities with vulnerable customers through

specialised ToU tariffs


http://innovation.ukpowernetworks.co.uk/innovation/en/research-area/demand-side-response/

http://innovation.ukpowernetworks.co.uk/innovation/en/research-area/demand-side-response/


34

The solution delivers benefits by reducing load on the system during peak hours,

thus allowing UKPN to avoid or defer reinforcement projects.


Addition Unit: “deployment of 1 DSR scheme”

Disposal Unit: “cancellation of 1 DSR scheme”

Benefit Categories:

The volume unit for Total MVA Released is: “1 MVA of capacity released”

The volume unit for Gross Avoided Costs is: “£ of deferred cost”

Cost Categories:

The volume unit for solution Costs is: “£ of deployment cost”. In the previous

submission, the timing of the DSR service contract milestones resulted in no

invoiced costs being incurred in the first year of deployment. In this submission

no DSR service costs has been incurred. DSR service costs for the reported

scheme will be included in the next reporting year.



box below.












Changes to CBAs








35




calculated.

Benefit: MVA Released

The benefit is calculated as the amount of MVA released using the summation of

the DSR contracted from each DSR service provider against each supported

network site.

Benefit: Gross Avoided Costs

The benefit is calculated as the amount of Gross Avoided Cost is calculated by

summing the costs of the avoided reinforcement projects as a result of the

solution.

The CBA model will include apportioned costs across the UK Power Networks

forecast RIIO-ED1 DSR programme:

Cost: Total Program Implementation Cost

The cost of implementing the program (system and process change related) is

considered in total.

Cost: Initial Substation Monitoring and Contract Telecom Cost

The initial cost of monitoring substations implemented with DSR solutions. This is

calculated as the initial substation monitoring and contract telecom cost per DSR

solution x the number of DSR solutions implemented.

Cost: Ongoing Substation Monitoring and Contract Telecom Cost

The ongoing cost of monitoring substations implemented with DSR solution. This

is calculated as the ongoing substation monitoring and contract telecom cost per

DSR solution x the number of DSR solutions implemented.

Counterfactual

The counterfactual is the case where the innovative solution is not implemented

and the existing, traditional reinforcement is deployed at full cost. MVA released

will be reported as a gross figure, not the net difference between MVA released by

the innovative and traditional solutions.






Demand Side Response_2016-17 E6 CBA_v1.0


36

Distribution Network Visibility (DNV)



All investment costs incurred prior to this regulatory year, hence no

investment costs are reported in 2016/17.

The baseline Totex has been calculated based on the below:

The London Power Networks (LPN) Distribution Planning department have quoted

that on average they save 8hrs/week on new connection referral assessments

using the DNV application. The baseline scenario therefore assumes the without

the application, the Planners would have to spend 8hrs more per week on

referrals.

To calculate the cost of the extra worked hours, the hourly rate for the

LPN planners has been used (source: UK Power Networks’ Finance

department) and the number of working days within 2016/17.

General



necessary.






The DNV application is a web-based application that enables the integration of

multiple data sources (including Ellipse, PowerOn Fusion, analogues outputs from

secondary and primary RTUs, weather stations etc.), and makes it available to

users through an easy to use visual interface.

Links to external documents:

i) Link to close down report for the Distribution Network Visibility project through

which the application was developed:

http://www.smarternetworks.org/Files/Distribution_Network_Visibility_17020114

3749.pdf

ii) Link to the registration document for the Distribution Network Visibility project

through which the application was developed:

http://www.smarternetworks.org/Files/Distribution_Network_Visibility_13011611

3540.xls

How is the DNV application being used?

The DNV application has been used as business as usual since late 2012, early

2013. It is primarily used to inform network planning decisions and proactively

manage UK Power Networks’ distribution network.

http://www.smarternetworks.org/Files/Distribution_Network_Visibility_170201143749.pdf

http://www.smarternetworks.org/Files/Distribution_Network_Visibility_170201143749.pdf

http://www.smarternetworks.org/Files/Distribution_Network_Visibility_130116113540.xls

http://www.smarternetworks.org/Files/Distribution_Network_Visibility_130116113540.xls


37

How is the DNV application delivering benefits?

The DNV application has delivered several benefits to date. It is used by UK

Power Networks’ Distribution Planners to assess connection referrals and it saves

them approximately 8hrs/week.

Benefits not reported in 2016/17 as realised in past years:

It is also used to proactively manage UK Power Networks’ distribution network.

Benefits were realised in past years from identifying early problems at primary

substations by spotting high voltages at secondary substations supplied by these

primary substations.

The DNV application has also been informing planning decisions. In two historic

cases, the DNV application provided enough information to prevent network

reinforcement triggered by Maximum Demand Indicator readings.


Units for Additions / Disposals: N/A to this solution as DNV is a process-based

initiative.

Benefits Categories

The volume unit is “the cost of 1 LPN Distribution Planner man-hour (hourly

rate)” spent on assessing connection referrals.

Single unit in this case is “1 man-hour saved” by a LPN Distribution Planner using

the DNV application.

Cost Categories

Not applicable for this year’s submission as no costs incurred in 2016/17.

How has each of the impacts been calculated?


box below.

What assumptions have they been relied upon?












38

Changes to CBAs










calculated.

Benefit: Labour Cost Savings

The benefit was calculated as follows:

1. The main DNV application users (LPN Distribution Planners) were

contacted and quoted that as a team the DNV application saves them

8hrs/week on average when assessing new connection referrals.

8hrs/week equals 1.6hrs/working day.

2. The number of working days in 2016/17 were then calculated (days with

the regulatory year excluding bank holidays and weekends). Based on the

number of working days within the regulatory year and the number of

hours/working day saved by using the DNV application, the total number

of hours saved within the year was calculated.

3. The hourly rate for the LPN Distribution Planners was then used to

quantify benefits in financial terms. Using the rate and total hours saved

within the regulatory year, the total labour costs savings realised in

2016/17 were calculated.

Counterfactual Scenario

The counterfactual scenario assumes that the LPN Distribution Planners assess

connection referrals in the conventional way, without the use of the DNV

application. In this case, they would have to spend on average 8hrs/week more

on assessing new connection referrals.






DNV_2016-17 E6 CBA_v1.0


39

Energy Storage (SNS)




for this solution.

Operating Costs and Revenue:

Operating costs and revenue have been extrapolated out to 15 years,

operating from 2016 to 2030 regulatory year based on latest year of

actuals data. This time period reflects the upper bound estimate of the life

of the storage asset.

Ancillary services revenue treated as a reduction of ongoing storage

operating costs.

Actual operating costs and revenues up to March 2017; the rest is a

forecast of enduring costs and revenues.

Deferred Reinforcement Expenditure:

Leighton Buzzard project defers need for reinforcement investment and

associated O&M costs by 6 years.

Storage Analysis:

MVA release timing aligned with start of ancillary services revenue and

storage operating costs. MVA release reported once, not ongoing to be

consistent with CBA guidance document.

CO2 emission reduction associated with a 6MW storage facility was sourced

from Poyry emissions model. See Appendix G - Cost Benefit Analysis

vFinal2 (RE-SUBMISSION, Clean) p.6.

General



necessary.






This solution involves the deployment of utility-scale batteries for providing

ancillary services (i.e. load following) as well as peak loping to reduce distribution

reinforcement need. The implementation of this solution is being considered

under two mechanisms: (1) enrolment of a third party storage device in DSR

program or (2) deployment of a UKPN-owned device onto the distribution system.

Batteries used for bulk storage (i.e. load shifting) are separate from this solution

and should instead be included in the DSR solution line item.


• Project Funding Submission Bid

http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-

http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-projects/Smarter-Network-Storage-(SNS)/Project-Documents/SNS+Full+Re-Submission+Proforma+%28Clean%29.pdf


40

projects/Smarter-Network-Storage-(SNS)/Project-

Documents/SNS+Full+Re-Submission+Proforma+%28Clean%29.pdf


A 6MW energy storage device has been implemented at one primary substation

(Leighton Buzzard to defer reinforcement schemes).


This solution delivers the following benefits: the deferral of reinforcement

projects, MVA, and avoided CO2 emissions as a result of increased network

flexibility utilisation.


Addition Unit: “1 storage unit commissioned on network”

Disposal Unit: “1 storage unit decommissioned from network”

Benefit Categories:

The volume unit for Total MVA released is: “1 MVA released”

The volume unit for Gross Avoided Cost is: “£ of deferred cost”

The volume unit for Avoided Emissions is: “tonnes CO2 emissions avoided from

one 6MW storage unit”

Cost Categories:

The volume unit for Trial Cost is: “1 trial project”

The volume unit for Ongoing O&M costs is: “1 trial project”



box below.















41

Changes to CBAs










calculated.

Counterfactual

It is assumed in the counterfactual that without energy storage devices on the

distribution network, UKPN proceeds with plans to implement reinforcement

projects where necessary.

MVA Released

The benefit is calculated as the amount of MVA released based on the summation

of MVA rating of the storage device installed at the Leighton Buzzard primary

substation.

Gross Avoided Costs

The benefit is calculated as the amount of Gross Avoided Cost is calculated by

summing the costs of the avoided reinforcement projects as a result of the

solution.

Emissions Impact

The benefit is the amount of emissions avoided as a result the displacing

traditional generation from peaking plants and reducing curtailment of renewable

generation. This value is determined from a Poyry study that determines the

annual CO2 emissions benefit from a storage device such as the device installed

at Leighton Buzzard.

Trial Cost:

The total cost of running the SNS trial program is determined from the

summation of Labour, Equipment, Contractor, IT, Travel & Expenses, Contingency

and Other Trial costs from the start to the end of the trial program (2013-2017).

Ongoing Cost:

The ongoing cost of operating and maintaining the storage device at Leighton

Buzzard. This is calculated as the ongoing operating cost per annum minus

ancillary services revenue per annum. Asset life assumed to be 15 years from

2016 (when the storage unit is fully operational) to end of 2030 regulatory year.


42






Energy Storage_2016-17 E6 CBA_v1.0

Flex DG Connections



The methodology for determining costs where the non-contestable portion

of the connection work was completed by UK Power Networks is as

follows: Where connection costs were for the non-contestable portion of

the connection work only, the connection work was subject to tender and

serviced by an alternate provider. Total costs were provided for about 15

connections from 2016. Using these total figures, an average ratio of

Flexible Distributed Generation (FDG) to BAU costs (about 18%) was

determined. This ratio was then applied to all non-contestable costs

figures, whether for BAU or FDG connection, in order to estimate the total

connection cost.

Reduction in output should vary by connection. However, in lieu of data,

3.13% is assumed for all connections.

Annual production estimates were derived using the nameplate capacity of

each connection multiplied by 8760 hours multiplied by capacity factors

referenced off Flexible Plug & Play (FPP) SDRC 9.7. Wind – 30%, PV –

11.6%, CHP – 100%

A power factor of 0.95 was used to convert nameplate capacity (in MW) to

MVA.

Emissions conversion factor: 0.41205 tCO2e per MWh generated

(Government Greenhouse Gas Reporting Conversion Factors 2016)

1007 tCO2e avoided per annum per MW of CHP installed (POWERFuL-CB NIC Full

Bid Submission Benefits Calculation, prepared by Navigant Consulting)

General



necessary.






A technical and commercial agreement where customers’ DG devices are subject

to temporary UKPN control to reduce power export in order to ensure network

voltages and currents are kept within operational limits. This solution is required

when the network is experiencing reverse power issues. Flexible Distributed

Generation – Connections (FDG-C is) operated by an Active Network Management


43

(ANM) solution, and is open on the basis of Last-In, First-out (LIFO) principle –

each generator is assigned a position within a global priority stack. When new

generators apply for a connection in the area, they are given a position at the

bottom of the priority stack and are curtailed first during a constraint event. This

solution was initially implemented through UKPN's "Flexible Plug & Play" Program.

The Business as usual solution deployed is now called Flexible Distributed

Generation (FDG)


https://www.gov.uk/government/publications/greenhouse-gas-reporting-

conversion-factors-2016

FDG High Level Process:

http://www.ukpowernetworks.co.uk/internet/en/our-

services/documents/FDG_high_level_process(Jan-17).pdf

FDG FAQs: http://www.ukpowernetworks.co.uk/internet/en/our-

services/documents/FDG_FAQs_v0.4.pdf

LIFO Connection Agreement:

http://www.ukpowernetworks.co.uk/internet/en/our-

services/documents/PR_CN_FLEX_002X_Connection_Agreement_-

_FDG%20LIFO_-_01122016.pdf


The solution is being used to connect DG customers to the grid through a lower

connection cost that allows for these customers to be curtailed at times of

network stress. Without FDG-C, these customers would only have had the option

of a more expensive traditional connection costs that allow for the cost of the

reinforcement projects that may be required to connect the customer to the

network. The FDG-C also has a shorter lead time and allows DG customers to

connect to the network earlier (by 29 weeks on average).


General Comment:

Potentially as a result of changes to the feed-in tariff, the update of distributed

generation has slowed considerably. This year, only 2 flexible DG connections

were installed, compared to 6 the year before. As such, the quantity of benefits

delivered through FDG has been lower in the 2016/17 year than it was in

2015/16.

Gross Avoided Costs:

Avoided Connection Costs – this assumes a counterfactual where all DG that has

connected under a flexible DG connection agreement would have connected

through a more expensive traditional connection agreement in the absence of a

flexible DG connection alternative. The benefit is that consumers are able to

connect their DG to the network through a much lower connection cost.

MVA Connected:

MVA reduction – this assumes a counterfactual where no DG that has connected

under a flexible DG connection agreement would have connected through a more

expensive traditional connection agreement in the absence of a flexible DG

connection alternative. By enabling this DG generation to connect to the network,

MVA is released.

https://www.gov.uk/government/publications/greenhouse-gas-reporting-conversion-factors-2016

https://www.gov.uk/government/publications/greenhouse-gas-reporting-conversion-factors-2016

http://www.ukpowernetworks.co.uk/internet/en/our-services/documents/FDG_high_level_process(Jan-17).pdf

http://www.ukpowernetworks.co.uk/internet/en/our-services/documents/FDG_high_level_process(Jan-17).pdf

http://www.ukpowernetworks.co.uk/internet/en/our-services/documents/FDG_FAQs_v0.4.pdf

http://www.ukpowernetworks.co.uk/internet/en/our-services/documents/FDG_FAQs_v0.4.pdf


44

The total renewables connected due to FDG connections in the 2016/17

regulatory year is 9.5 MVA.

These values have not been included in the E6 table as these relate to specific

customer connections, not a release of capacity available to the market..

Emissions Impact

Avoided Emissions – this assumes a counterfactual where all DG that has



flexible DG connection alternative. The benefit is the amount of emissions saved

as a result of being able to connect these DG consumers on average 29 weeks

earlier.

Avoided Emissions – this assumes a counterfactual where no DG that has



flexible DG connection alternative. This benefit is for the savings in emissions as a

result of the DG connecting that would not have connected in the counterfactual.

The overall emissions this year are also lower - as was the overall number of

schemes energised in the year – though one of the flexible DG connections was

for a CHP with a much higher total energy output assumed due to its dispatchable

nature.


Addition Unit: “1 Flexible DG connection energised”

Disposal Unit: “1 Flexible DG connection decommissioned”

Benefit Categories:

The volume unit for Avoided Connection Cost is: “1 DG Connection under a

flexible connection agreement”

The volume unit for Avoided Emissions is “tCO2e”.



box below.





45









Changes to CBAs










calculated.

Counterfactual 1:

All DG that has connected under a flexible DG connection agreement would have

connected through a more expensive traditional connection agreement in the

absence of a flexible DG connection alternative.

Gross Avoided Costs

Avoided Connection Costs – Consumers are able to connect their DG to the

network through a much lower connection cost. The benefit is calculated by:

(Traditional Connection Cost – Flexible Connection Cost) x Number of DG

Connections under a Flexible connection agreement.

Counterfactual 2:

No DG that has connected under a flexible DG connection agreement would have

connected through a more expensive traditional connection agreement in the

absence of a flexible DG connection alternative.

Emissions Impact

Avoided Emissions – The benefit is the amount of emissions saved as a result of

being able to connect these DG consumers. This is calculated as MWh Produced *

(1 + % T&D Losses) * Emissions Rate * 1 year, for each DG connection.


46






Flex DG Connections_2016-17 E6 CBA_v1.0

FUN-LV




for this solution:

The reinforcement solution was assumed to occur based on the load growth

forecasts predicted by the Element Energy model.

Assume that conventional reinforcement is required in the year where

Method Costs are incurred i.e. 2015/2016. In reality the majority of sites

were not sufficiently constrained to require immediate reinforcement but

were highly loaded to demonstrate the impact of the project methods.

Method Costs are those estimated from the trial and therefore are higher

than expected for any future replication.

The only schemes included in the E6 reporting are those determined to be

capable of continuous operations and providing net financial benefits (this

relates to a subset of 13 from the original 36 trial schemes).

General



necessary.






The overarching aim of the Flexible Urban Networks – Low Voltage (FUN-LV)

project was to explore the use of power electronics to enable the deferment of

reinforcement and facilitate the connection of low carbon technologies and

distributed generation in urban areas. This was achieved by meshing existing

networks, which are not meshed, and by breaking down boundaries within

existing meshed networks.

The FUN-LV project trials demonstrated three different methods with increasing

levels of capacity sharing functionality. Method 1 (M1) used remote control Circuit

Breakers and Link Box Switches developed by TE Connectivity and supplied under

licence by EA Technology Ltd. The Link Box Switch replaces a solid link in the link

box. This equipment joins substations together providing uncontrolled levels of

current flow. This equipment was already approved for use on the LV network.

However, joining two radial circuits required an additional tripping unit, which

monitored reverse power flow through the transformer, to send a trip signal to

the circuit breakers should a HV fault or transformer fault occur to prevent


47

continued fault current flow from the donor circuit.

Method 2 (M2) and Method 3 (M3) consist of two or three back-to-back power

inverters, respectively, with a common DC busbar. The inverters were controlled

by an autonomous control system (developed by project partner Imperial College

London) that takes measurements from various points in the system and

calculates the level of power flow required across the DC busbar. Each inverter is

able to import or export real and reactive power between different AC LV

networks and the DC busbar, dependent on how the inverter is switched. M1 and

M3 are installed within distribution substations whereas M2 is installed as a piece

of street furniture.

Link to external documentsDetails of the solution are illustrated on the

project innovation site. The methodology is outlined well in the Close

Down, SDRC 9.2 and SDRC 9.4 reports.

http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-

projects/Flexible-Urban-Networks-Low-Voltage/


The three trial Methods are being used to mesh previously radial or

interconnected networks. The FUN-LV methods were trialled in 36 installations in

London and Brighton. Twelve installations of each of the three methods was

demonstrated across three different network types:

1. London Radial LV networks

2. London Interconnected LV networks

3. Brighton Radial LV networks.


The primary benefit arising from the solution is the ability to defer and reduce the

need for network reinforcement by making use of neighbouring substations with

spare capacity. This results from transferring power between substations to

balance loads and release MVA headroom.

Secondary potential benefits for the technology that are not captured in this

report include:

- Controlling fault levels on the network through the use of power electronics

and thereby meshing the network whilst protecting assets;

- Controlling voltage to ensure continued compliance with standards and reduce

losses;

- Collecting granular information on the performance of the LV network;

- Providing a network upgrade option with fewer logistical and disruption issues

for customers (e.g. reduced carriageway works and road closures); and

- Providing capacity in a shorter timescale for new connections and reconnection

following building redevelopment.


Categories:


The volume unit for Baseline and Evaluation Totex is: “£m of deferred cost”

The volume unit for additions is: “one FUN-LV scheme”


http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-projects/Flexible-Urban-Networks-Low-Voltage/

http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-projects/Flexible-Urban-Networks-Low-Voltage/


48

Impacts have been calculated as load-related investment reduction or deferral

and in capacity released. See the “Calculation of Benefits” section below.












Changes to CBAs










calculated.



MVA released for each site with FUN-LV methods installed. The amount of MVA

released is equal to the additional apparent power headroom created through

transformer equalisation (matching % utilisation) on the connected substations.

Cost: Baseline Totex

The total cost of the counterfactual solution to connect additional capacity of

200kVA, 240kVA or 400kVA (equivalent to Method 1, Method 2 or Method 3

respectively).

Cost: Evaluation Totex

The total cost of installing FUN-LV Methods to each site in addition to traditional

reinforcement after the number of years of deferral.

Years of Deferral

The number of years that a reinforcement can be deferred is calculated according

to the current headroom divided by the assumed annual load growth for the

secondary substation in line with Element Energy model.

Headroom


49

The amount of capacity available in a scheme before exceeding the rating of

connected transformers, for distribution transformers this is 120% (radial) and

80% (interconnected) of the name plate rating.

Counterfactual


and the minimum traditional reinforcement is to achieve the required additional

capacity.






FUNLV_2016-17 E6 CBA_v1.0

Innovative Bunding



It has been assumed that for every 1000kg of excavation avoided by the

innovative solution has led to a saving of 2kg of CO2e. This is noted in the DEFRA

emission guidelines.

It has been conservatively estimated that the excavation depth required with a

traditional concrete bund is 50cm.

The cost of avoiding an outage for a transformer at every site where the

Omnibund or Bundsep was installed has been estimated as follows:

Cost of a senior authorised person is £550 per day as noted in the May

2017 CU catalogue CU-LAB171-EA

Cost of a planner to arrange the outage is £43/hr CU catalogue CU-LAB146-LA

and the average time to complete an outage is 0.5 hours for a primary site and 2

hours for a grid site.

General



necessary.





The solution is polymer-based bunding equipment which replaces the traditional

concrete and sump pump systems. They are introduced in EDS 07-0110

It is being used to bund large transformers in a way that costs less and results in

fewer emissions than the base case. These have been assessed and are included

in the E6 table.

Volumes


50

Addition Units:

Omnibund volume unit: “1 Omnibund bund system installed”

Bundsep volume unit “1 Bundsep installed”

Disposal Units: Removal of “1 Omnibund bund system” or “1 bundsep”

Benefits

Cost saving: the difference between the base case and evaluation case

plus the cost of avoiding an outage at each site

Emissions saving: 2kgCO2 avoided per tonne of excavated aggregate

avoided

Cost saving: the difference between the base case and evaluation case

plus the cost of avoiding an outage at each site

Emissions saving: 2kgCO2 avoided per tonne of excavated aggregate avoided









Changes to CBAs










calculated.

Counterfactual scenario:

Cost of work: known from prior installations or installations at similar sites

Cost of outage: estimated as per section 1.

Excavation: calculated based on known average size of bund and assumed

depth of 50cm.

Evaluation scenario:

Cost: as from Service Order

Excavation: 4 inch surface dig to prepare area for each Omnibund. No

excavation for Bundsep.


51






Innovative Bunding _2016-17 E6 CBA_v1.0

Joint Shell



The cost of replacing an LV lead cable ‘T’ joint is detailed in the table included in

the “calculation of benefits” section. The cost is different in three licence areas of

UK Power Networks, the split is shown in the table below which is taken into

calculation. These costs assumptions are based on the approved internal

‘compatible units’ planning values for completing the traditional solution work.

The innovative joint shell that has been developed as part of this project will be

installed on LV joints identified to be in slightly poor condition during cable pit

inspections. The shell is designed to protect the joint from water ingress due to

cracking of the original lead casing that could potentially trigger its failure.

It is estimated the cost of putting the shell on the joints including the associated

labour cost is approximately £1100 per joint. These are based on the actual

costs incurred purchasing the materials, approved internal labour rates, and a

baseline of hours effort required. The cost is different in three licence areas, the

split between licence areas is shown in the table below and is considered in

calculation. The new shell will increase the estimated life of the joint allowing us

to defer our investment on joint replacement. It will also allow us to save costs by

not having the fault on joints, saving on CIs and CMLs and improving public

health and safety.

General



necessary.





LV lead cable ‘T’ joints that are identified during cable pit inspections as in poor

health that could potentially become weaker from water ingress will have the new

shell applied together with associated earthing improvements, filled with resin

that will give these joints an extra layer of protection that will reduce the

probability of failure.

The extra layer of mechanical shell protection on joints will stop any ingress of

water potentially triggering a failure. Using this activity will extend the life of a

joint, as previously the only option available was to undertake a replacement of

the joint asset. This innovative approach will allow UK Power Networks to defer

our asset replacement investment policy and save on customer interruptions and

associated customer minutes loss by not having joint failures.


52

In the regulatory year 2016/2017, we have installed approximately 108 units on

the network since developing the solution. As we continue with cable pit

inspections and other maintenance & inspection activities on our underground

cable assets, any poor condition LV lead ‘T’ joint identified will have the new joint

shell installed to avoid their failure due to water ingress.

The estimated cost of saving per joint calculated is different in three licence areas

based on savings on CIs and CMLs that could have occurred due to joint failure.

See the “calculation of benefits” section for more detail.

Addition Units: “1 joint shell installed on network”

Disposal Units: “1 joint shell removed from network”

Benefit Categories: “£ cost saved”

Cost Categories: The costs considered include cost of joint, excavation and

installation of the joint shell on top of an existing joint. Counterfactual cost

categories include cost of joint, excavation and installation of a new traditional

joint.









Changes to CBAs










calculated.

The saving on joint failure is different in all three different licence areas. The

saving is from avoiding joint failure, reducing CIs and CMLs and improving safety

for member of staff and public. The split between three licence areas is shown in

the table below:

Counterfactual: Traditional Cost of repairing an LV joint

Region Labour Contractor Material Generator Other £ Total

EPN 924 1,652 170 84 33 2,863


53

SPN 870 1,508 170 84 23 2,655

LPN 1,571 1,606 191 324 228 3,919

Baseline: Cost of putting a new Joint shell per DNO and savings

Region Cost Of Putting a

Joint Shell Savings per joint

(£)

EPN 833 2,030

SPN 833 1,822

LPN 1100 2,819

Number of Joint shells Installed:

Region Number of Joint shells

Installed in 2016/2017: Total Savings per

DNO(£)

EPN 30 60,900

SPN 30 54,660

LPN 48 135,312






Joint Shell_2016-17 E6 CBA_v1.0

LIDAR Vegetation Management




for this solution.

LiDAR will be carried out approximately every two years

It is assumed that LiDAR-enabled approaches to vegetation management

have no material impact on CI and CML rates. This will be reassessed for

future submissions.

LiDAR has primarily been carried out on the HV, EHV and 132kV Overhead

line networks.

The average Opex spend rate for the submission year baseline was

assumed to be the average annual cost from DPCR5 actuals.

The Opex spend rate within the RIIO-ED1 allowances was assumed for the

forecast post-2017 evaluation case. The ED1 Business Plan Submission

tables were used to develop the post 2017 baseline case.

This performance improvement has been enabled by the LIDAR solution by

removing the need to conduct large scale ground surveys of OHL routes and by

categorising risk for all our OHL spans, thus enabling more efficient prioritisation

and targeting of cutting effort.

The benefits achieved in the CBA forecasts are conservative assumptions

compared to our year 1 actual performance, acknowledging that the new

contracts were only implemented in September 2015 and followed a considerable


54

period of the year where no cutting took place. It should also be noted that this

methodology does not quantify secondary effects of implementing the solution,

such as equipment and small tools costs moving into the evaluation case

embedded within the new contractor costs where they were previously separated

into indirect Opex costs.

This methodology may then lead to higher spend levels and thus lower benefits in

future years, though we remain confident that the LIDAR-based approach will

continue to deliver improved cost performance.

General



necessary.






Using helicopters or light aircraft equipped with LiDAR (i.e. aerial laser

imaging/surveying) to identify critical clearances, danger and hazard vegetation,

and abnormal line states along the right-of-way (ROW) of the distribution system.

This then leads to more complete visibility of relative risks posed by vegetation

growth on OHL routes and thus enables more targeted vegetation cutting.


The solution is being used to provide greater confidence in using the allocated

budget in the most targeted and priority manner to minimize the impact of tree

related faults. It should also help to reduce the amount of cutting required to

achieve at least equivalent levels of fault prevention.


UK Power Networks (UKPN) saves surveying and cutting costs by using LiDAR or

similar techniques to produce an intelligent risk-based cutting program.


Addition units: “1km of overhead line surveyed”

Disposal units: will not be reported as it is not applicable to this solution, which is

process-based.

Benefit Categories

The volume unit for Reduced Cutting and Surveying Costs is: “1 km of OHL line”

Cost Categories

Additional cost of surveying


55


Impacts have been calculated as cost reductions in total cutting and surveying

costs. See the “Calculation of Benefits” section below.












Changes to CBAs










calculated.

Benefit: Avoided Costs of Surveying

The benefit is calculated as the “km of line surveyed“ x (“£/surveyed km” ∆

between evaluation and baseline)

Assumptions: baseline surveying costs are based on the average of 2010-2014

surveying costs. For CBA and forecast years the baseline costs are those from

the UK Power Networks ED1 Business Plan submission.

Benefit: Avoided Costs of Cutting

The benefit is calculated as the “km of line cut“ x (“£/cut km” ∆ between

evaluation and baseline)

Assumptions: For the current year, baseline cutting costs are based on the

average of 2010-2014 cutting costs. For CBA and forecast years the baseline

costs are those from the UK Power Networks ED1 Business Plan submission.

Cost: Increased analysis costs for LiDAR data

The solution cost is included as the total cost of procuring the LiDAR survey data.


56

A volume unit for the Cost of LiDAR data analysis, representing any additional

scaling or Opex costs associated with LiDAR analysis, is not considered.

Assumptions: LiDAR data analysis costs are the same as baseline data analysis

costs.

Counterfactual

The counterfactual is the case where the solution is not implemented and the

amount of line cut is determined by the use of standard on-the-ground surveying

methods to identify overgrown vegetation.






LIDAR_2016-17 E6 CBA_v1.0

Load Blinding Relays



No reported volumes or costs in 2016/17


for this solution.

It is assumed that in the absence of the load blinding relay solution for

releasing DG connection capacity on the network, customers benefiting

from the solution would have connected at the full traditional cost without

the benefit of load blinding relays.

General



necessary.






This solution uses ModNovel Protection Relays with “load blinding” functionality to

manage constraints and maximise network utilisation. Load blinding relays allow

greater volumes of DG to be connected to the network, producing greater reverse

power flows because these relays can discriminate between acceptable reverse

power flows and an upstream fault, which traditional protection would need to

operate to clear fault infeed.

Load blinding is useful in the cases such as of heavily loaded lines or where


57

quadrature characteristics are used for the distance zone reaches. If the current

increases and its angle is within the expected the load area, the distance relay

will be restrained from operating. This scheme will have the benefit of removing

the protection-related constraints on reverse power flow whilst maintaining

relatively simple tried and tested philosophy for the protection settings.


The solution is being used to connect DG customers to the grid through a lower

connection cost. Without load blinding relays, these customers would only have

had the option of a more expensive traditional connection that allows for the cost

of the reinforcement projects that may be required to connect the customer to

the network.



Avoided Connection Costs – The benefit is that consumers are able to connect

their DG to the network through a much lower connection cost.


Benefit Categories:

The volume unit Additions is: “1 DG Connection energised under a Load Blinding

Relay connection agreement”

The volume unit for Disposals is: “1 DG Connection decommissioned under a Load

Blinding Relay connection agreement removed”



box below.













58

Changes to CBAs










calculated.

All DG enabled by a load blinding relay would have connected through a more

expensive reinforcement connection costs in the absence of a load blinding relay

solution.

Gross Avoided Costs

Avoided Connection Costs – Consumers are able to connect their DG to the

network through a much lower connection cost. The benefit is calculated by:

(Traditional Connection Cost – Load Blinding Relay Connection Cost) x Number of

DG Connections under a Load Blinding Relay connection agreement.






n/a

LPN Interconnection




for this solution.

The benefits methodology is based on the design policy of limiting an HV

feeder group utilisation to be able to support group demand following a

single feeder outage. Thus by adding an additional feeder to an existing

feeder group with 2 feeders, utilisation can increase from 50% to 67% and

with 4 feeders, utilisation can increase to 75%. The reported benefit is the

additional utilisation above a traditional, two feeder design at 50%

utilisation.

It is assumed that the avoided cost benefits are directly proportional to

the increased utilisation percentage benefit.


59

The average number of feeders in an LPN 11kV feeder group has been

calculated and used as the percentage benefits ratio for all schemes

eligible for reporting.

Individual reinforcement projects were selected as eligible for inclusion in

the innovative solutions table based on load-related driver for the project

and based on the level of interconnection operated in that specific

network.

General



necessary.






This solution is the advanced design philosophy for interconnected 11kV feeder

groups in the LPN network. Including a relatively high number of feeders per

feeder group to support higher utilisation while maintaining N-1 resilience such

that in the event of a loss of one 11kV feeder from the group due to a fault, all

the substations supplied by that feeder can be energised through multiple 11kV

interconnection points (normally open). By designing the network with larger

numbers of 11kV feeders connected in this way as a feeder group, resilience can

be maintained with significant benefits in the percentage utilisation of each

individual feeder.

This arrangement allows these higher circuit utilisation levels, since each 11kV

circuit (for a four feeder group) can be loaded to 75% of its thermal capacity (or

80% for a five-feeder group) as opposed to 50% for a conventional radial

network single points of interconnection between two feeders.


https://library.ukpowernetworks.co.uk/library/en/RIIO/Main_Business_Pla

n_Documents_and_Annexes/UKPN_Smart_Grid_Strategy.pdf


UK Power Network’s LPN LV-interconnected HV system has continually evolved

and enables significantly higher levels of HV and LV asset utilisation than

conventional HV and LV distribution systems.


MVA Released – linked to data reported in CV2, no MVA has been released for the

relevant reinforcement projects reported in this table.

Gross Avoided Costs – due to the increased utilisation of the network, future

network reinforcement is deferred and the £ per MVA cost of reinforcement in the


60

HV network is reduced.



Avoided Reinforcement Costs – The volume unit for Avoided Reinforcement Costs

is “1 project deferred”.


The impacts are considered jointly with benefits in the “Calculation of

Benefits” box below.


The assumptions behind the impacts are considered jointly with benefits in

the “Calculation of Benefits” box below.









Changes to CBAs










calculated.

Counterfactual

It is assumed in the baseline case that there can only be a maximum of 2 feeders

per feeder group, as per a traditional network arrangement. This means that

feeder groups can only be loaded up to a maximum of 50% capacity to maintain

n-1 security of supply.

Gross Avoided Costs

The amount of Gross Avoided Cost is calculated by considering reinforcement

costs incurred in this reporting period reinforcing those sections of the LPN

network with a high number of interconnected feeders within the feeder group


61

(greater than 2). Counterfactual costs are determined as what would have been

spent reinforcing an equivalent, large number of two feeder groups.

Assumption: to calculate the amount that would have been spent in the

counterfactual scenario, a multiplier has been for each feeder group, based on the

average number of feeders in an LPN feeder group, calculated using the formula:

= (1 − 𝑀𝑒𝑠ℎ𝑒𝑑 𝑈𝑡𝑖𝑙𝑖𝑠𝑎𝑡𝑖𝑜𝑛

𝐶𝑜𝑛𝑣𝑒𝑛𝑡𝑖𝑜𝑛𝑎𝑙 𝑈𝑡𝑖𝑙𝑖𝑠𝑎𝑡𝑖𝑜𝑛 ) × £𝑠𝑝𝑒𝑛𝑡𝑒𝑣𝑎𝑙𝑢𝑎𝑡𝑖𝑜𝑛 𝑐𝑎𝑠𝑒

Assumption: A feeder group under the counterfactual is assumed only to be able

to reach 50% utilisation for n-1 supply. The evaluation case assumes that for a 3

feeder group, utilisation can reach 67%, while a 4 feeder group can reach 75%

and a 5 feeder group can reach 80% utilisation.






LPN Interconnection_2016-17 E6 CBA_v1.0

LV Re-energising Devices



The following section details the allocations and high level assumptions made in

the calculations for this solution.

The solution has been implemented across UK Power Networks’ EPN, LPN

and SPN networks.

The reported additions total has been taken to be the average of the

number of Bidoyngs and ALVIN Reclose devices deployed on a monthly

basis

Benefits

This model uses Ofgem’s societal benefit £/interruption rates.

o CI (£s per interruption) £15.44

o CML (£s per minute lost) £0.38

No O&M impacts result from installing and operating LV Re-energising

Devices have been assumed or calculated. These benefits will be reviewed

in future submissions.

Benefits are calculated for each individual outage actually occurring in the

reporting period on the circuits equipped with either Bidoyngs or ALVIN

Reclose devices, including

o Number of affected customers

o Identification of those incidents with a beneficial expected outcome


62

compared to without the solution (i.e. for Bidoyngs those

operations where the second fuse did not operate and restored

supplies and for the ALVIN Reclose devices, those operations were

the ALVIN Reclose has successfully auto-reclosed)

Flat forecast Customer Interruption (CI) and Customer Minute Lost (CML)

benefits rate assumed to end of reporting period, based on most recent

year’s performance.

Costs

Costs reported include those for the purchase and service provision (where

relevant) for equipment. Operational costs deploying and utilising the equipment

are considered to be the same in both the evaluation and the baseline case and

thus not presented in the net CBA.

The Fault Centre service for the Bidoyng was largely paid for in advance for the

period 2014 to 2019. Renewal and ongoing Bidoyng Fault Centre costs start again

in 2019 and is valued at £750/Bidoyng/annum.

General



necessary.





What is the solution reported?

In this submission period two different types of LV re-energising devices have

been operated on the network:

i) The Bidoyng

ii) The ALVIN Reclose

A Bidoyng uses two fuses (i.e., Primary and Secondary) in parallel as a single

shot auto recloser. The Primary fuse operates first in the event of an intermittent

fault. Then, after a programmed delay (less than 3 minutes), the Secondary fuse

is switched in causing the network to re-energise. For sustained faults, the

Secondary fuse will also operate and customers will remain off supply until a UK

Power Networks’ crew manually fixes the fault.

An ALVIN Reclose is a solid state Low Voltage (LV) Circuit Breaker. When a fault

occurs the Circuit Breaker will operate and open. The ALVIN Reclose will then test

the power cable (using modulated power pulses) for the presence of a sustained

fault before attempting to energise the circuit again. If the fault has been cleared

(i.e. the fault was not a sustained but an intermittent one), the ALVIN Reclose will

automatically reclose restoring supply to customers.

Both LV Re-energising Devices included in this year’s submission contribute

towards reducing CIs and CMLs.


63


i) Bidoyngs:

https://www.ofgem.gov.uk/sites/default/files/docs/2010/12/enwt1001_0.

xls

http://www.kelvatek.com/bidoyng.php

ii) ALVIN Reclose:

https://www.eatechnology.com/products/low-voltage-alvin-range/alvin-

reclose/


Both types of LV Re-energising Devices are used at secondary substations across

all three UK Power Networks’ DNO areas in order to reduce CIs and CMLs. They

are both installed on LV boards, directly replacing fuses.

In 2016/17, 1,108 LV Re-energising Devices were deployed and are operating on

UK Power Networks’ distribution network, 34 of which are ALVIN Reclose devices

and the rest Bidoyngs.


The solution is being used to reduce CIs and CMLs from momentary outages by

allowing the system to re-energise.


Addition Units: “1 device installed on the network for the duration of 1 year” This

number has been calculated by taking the average of devices installed on the

network over the year.

Disposal Units

Will not be reported for this solution.

Benefits Categories

The volume unit for Customer Interruptions is “1 interruption per 100 customers

connected”.

The volume unit for Customer Minutes Lost is “1 minute lost”.

Cost Categories

The volume unit for costs associated with the purchase of goods is “Price for 1

device”.

The volume unit for costs associated with the provision of services in relation to

the LV Re-energising Devices is “annual license fee for 1 device”.

Please note that only costs associated with the purchase of goods has been

included in the current submission. Services were largely paid for in advance for

the period 2014 to 2019.


https://www.ofgem.gov.uk/sites/default/files/docs/2010/12/enwt1001_0.xls

https://www.ofgem.gov.uk/sites/default/files/docs/2010/12/enwt1001_0.xls

http://www.kelvatek.com/bidoyng.php

https://www.eatechnology.com/products/low-voltage-alvin-range/alvin-reclose/

https://www.eatechnology.com/products/low-voltage-alvin-range/alvin-reclose/


64


box below.












Changes to CBAs










calculated.

Benefit: Reduced CIs

The benefit is calculated as follows:

1. Number of customer interruptions = (Number of CIs per 100 customers

connected, ∆ between counterfactual and baseline) x (Total number of

customers connected on network in relevant DNO area)/100

2. Societal Benefit (£m) from reduced CIs = Number of customer

interruptions x £/interruption

Assumptions

The CBA forecast benefits assume constant CI benefit into the future once all LV

Re-energising Devices are installed.

Benefit: Reduced CMLs

The benefit is calculated as Customer minutes lost (∆ between counterfactual and

baseline) x £/minute

Assumptions: Assumes i) length of avoided outage (based on average restoration

time for each DNO area), and ii) constant CML benefit into the future once all LV


65

Re-energising Devices are installed.

Counterfactual

The counterfactual assumes that no LV Re-energising Devices are installed on the

system. Thus, no intelligent devices (fuses or circuit breakers) are available to re-

energise the system in the event of a momentary outage.






LV Re-energising_2016-17 E6 CBA_v1.0

Oil Regeneration




for this solution.

It is assumed that the solution extends the life of transformers by 16

years.

It is assumed that there is no change in the required, on-going operations

and maintenance costs for transformers kept in service through the use of

this innovative solution

It should be noted that this methodology does not typically produce

financial benefits within the RIIO-ED1 benefits, as the replacement

investment counterfactual is typically in ED2.

No financial value has been assigned to the health risk improvement benefits

delivered in by the solution and the E6 table does not provide for reporting HI

benefits.

General



necessary.






Oil Regeneration extends the life of transformers by regenerating oil in

transformers where the oil has high moisture and acidity. By regenerating the oil,

not only does this improve the moisture and acidity condition, but also removes

sludge from transformer oil, additionally resulting in an ‘as new’ oil condition

which will extend the expected lifetime of the transformer. Oil regeneration

involves circulating the oil through bauxite pillars in order to remove acidity and

sludge from the transformer oil, as well as remove the moisture from the winding


66

papers. On top of this, the regeneration also helps to remove sludge deposits in

the transformer and cooler. By restoring the transformer oil to its original new

condition, oil regeneration can provide a minimum extension of serviceable life of

16 years.


None to note


Oil regeneration is being used on primary system transformers to improve the

overall asset health risk on the network (e.g. provide HI improvement from HI4

to HI2) and to extend the expected lifetime of the assets.



Avoided Replacement Costs – The costs saved by deferring the replacement of

transformers.


Additions Unit: “regeneration of oil for 1 transformer”

Disposals Unit: N/A for this solution as it is action-based


Avoided Replacement Costs – The volume unit for Avoided Replacement Cost is 1

transformer with Oil Regeneration applied.



box below.




Note that there were no new regeneration activities completed this period.










67

Changes to CBAs










calculated.

No benefits claimed in 16/17 reg. year

Counterfactual

The counterfactual solution is when UKPN would choose not to apply Oil

Regeneration and the transformers would be left to degrade to a point where the

only option would be to replace the transformer at an earlier date.

Gross Avoided Costs

The benefit is calculated as sum of the time value of money saving as a result of

deferral of the investment in new transformers. It is assumed that the solution

extends the life of transformers by 16 years.

Cost: Implementation of Oil Regeneration

The cost of the implementation of Oil Regeneration for 11 transformers is taken

as the full project cost to complete oil regeneration for the reported volume of

transformers.






n/a

PFT



Based on a sample of leak-location outcomes across our three networks, it

has been determined that PFT is successfully used to locate leaks with the

following frequency:

EPN: 60% (based on a sampling of actual leak-location events)

LPN: 15% (conservatively estimated)

SPN: 60% (based on a sampling of actual leak-location events)

Hourly Costs for labour across the networks are taken from the 2017


68

Activity Rates Model provided from Finance:

EPN LPN SPN

Staff £44.69 £58.55 £48.30

Engineer £55.97 £57.08 £64.10

Fluid Filled cable leak location is not a clear-cut process or a simple choice

between the leak location methods available. Different methods are used

and often a successful location is an amalgamation of all methods. For our

CBA calculation, we have assumed the following:

PFT is the 1st choice for locating a leak

If PFT alone is not able to locate the leak, the Freezing method is

also used

General



necessary.





Solution & Benefits Explanation:

Fluid filled cable leaks have been traditionally been difficult and costly to

locate. The Perfluorocarbon tracer (PFT) fluid-filled cable leak location

method allows cable leaks to be found faster and at lower cost than other

methodologies. The detection technique is based upon introducing a small

amount of PFT into cable fluid, which is detectable by a mobile unit. PFTs

are man-made, non-toxic, non-flammable, non-corrosive, chemically

stable material which have been proven to cause no environmental or

health issues. Additionally, it has been shown that PFT does not lead to

degradation of premature ageing of our assets.

For the benefits calculation methodology, please see section 5 below

Volume Units:

Addition unit: “1 fluid-filled cable leak”

Disposal unit: Will not be reported for this solution as it is process-based

Scenarios:

Evaluation Case: Leaks are located with PFT when possible, using other

methods to assist when necessary. Freezing is the highest cost alternative

method.

Counterfactual Case: Freezing with N2 is used to locate the leak.


69









Changes to CBAs










calculated.

The benefits of using PFT are in costs.

Evaluation Cost:

A weighted average of the cost of a PFT location and the cost of a Cable

freezing location (as in the counterfactual case), given the success rates

noted in section 1.

Cable leak found using PFT method, which includes the following:

Unit Cost

EPN LPN SPN

2 staff for 3 days (45

hours) £2,011.05 £2,634.75 £2,173.50

1 engineer for 1 day

(7.5 hours) £419.78 £428.10 £480.75

PFT Material Cost £100.00 £100.00 £100.00

Total £2,530.83 £3,162.85 £2,754.25

Therefore, the weighted cost of the evaluation cost is as follows:

EPN LPN SPN

£25,454.55 £54,629.82 £26,119.66

Counterfactual (baseline) Cost:

Cable leak found using Cable Freeze method, which includes the following:

Unit Cost

EPN LPN SPN

4 x 2x2m excavations £41,225.52 £41,225.52 £41,225.52

4 staff for 8 days

(240 hours) £10,725.60 £14,052.00 £11,592.00


70

1 engineer for 8 days

(60 hours) £3,358.20 £3,424.80 £3,846.00

Nitrogen and material

costs £2,000.00 £2,000.00 £2,000.00

Total £57,309.32 £60,702.32 £58,663.52






PFT_2016-17 E6 CBA_v1.0

Point of Connection (POC)



The cost and benefits data used in the CBA have been built up from either project

actual costs or using Compatible Units (CUs), each of which gives the cost of

carrying out a particular activity. These CUs have been created following

consultation with contractors who are part of the UK Power Networks Alliance.

These CUs have been used to build up the tower replacement costs.

General



necessary.





Summary

The POC mast and underslung air brake switch disconnector (ABSD) mast are

both new methodologies that can be used for customer cable connections at 33kV

suspension towers where other traditional solutions are not technically possible.

They provide an additional cost effective option for customers wishing to connect

to the network and avoid the expensive and complicated option of complete tower

replacement.

Both consist of steel poles located to the side or underneath the tower being

connected to and have jumpers connected to the tower circuit. An ABSD and

cable termination are located on the steel pole and the signal, the point of

connection for the customer.

The POC mast design includes a hinge at the bottom of the mast so that work can

be done at ground level before erecting the mast. This allows the outage work to

be kept to a minimum as the only work required will be to connect the jumpers

between the mast and the tower.


71

Benefits

The POC mast and underslung ABSD mast add additional options to the hierarchy

of solutions available to UK Power Networks for making connections to overhead

tower lines. Although they won’t be used as the first option for all connections it

does offer a lower-cost alternative on occasions where an expensive tower

replacement would otherwise be required.

Volumes

Addition Units: “1 connection energised using POC Mast technology”

Disposal Units: “Decommissioning of 1 connection which has used POC Mast

technology”









Changes to CBAs










calculated.

If the solution was not available then in the majority of cases the connecting

tower would need to be replaced with a new tower with cable connections

included. The cost of this replacement has been used as the counterfactual

scenario.

All projects within the business are costed using Compatible Units (CUs), each of

which gives the cost of carrying out a particular activity. These CUs have been

created following consultation with contractors who are part of the UK Power

Networks Alliance. These CUs have been used to build up the tower replacement

costs.


72






POC_2016-17 E6 CBA_v1.0

Dynamic Transformer Rating




for this solution.

The solution has been implemented at 2 substations, 1 each on UK Power

Networks’ London (LPN) and Southern (SPN) networks.

Where actual spend for traditional reinforcement and the cost of the

solution are available (i.e. for this reporting year) these have been used

instead of forecast values in the E6 table and in the lifetime CBA.

The amount of capacity released varies per substation and is calculated

through a technical study for each substation. The rating at Lithos Road

has been maintained due to other site constraints. Using accurate

Dynamic Transformer Rating monitoring it was possible to safely avoid de-

rating and associated costs incurred with this derating effect on the

network. The transformers at Weybridge were uprated to an asset rating

of 25MVA using the DTR solution, we expect to confirm the overall site

rating subject to replacement of switch boards by 2020 which are the next

most limiting factor.

The benefits calculation is based on the originally planned traditional

reinforcement schemes with expenditures shown in regulatory year 15/16

which were not incurred are then deferred to following years after present

(e.g., 2018, if 2017 is the current year).

General



necessary.






Dynamic Transformer Rating (DTR) allows additional capacity to be made

available from existing assets and defer reinforcement by three years or more. It


73

is estimated that transformers can be loaded up to 20% above static seasonal

rating.

Changes in environmental conditions have a dramatic effect on transformer

loading and in urban areas due to rise in air conditioning installations, existing

summer or winter firm ratings may not be fully representative of the situation at

particular sites. This seasonal increase in loading may be leading to premature

network reinforcement decisions.

Benefits from DTR are achieved by retrofitting Transformer Management System

(TMS) onto existing assets to provide real-time monitoring of the transformer's

health, and continuously calculate the transformer thermal capacity, thereby

safely loading the transformer close to the maximum top oil temperature less 2°

Celsius allowed by design nameplate.

An increase in capacity is achieved by carrying out the following:

Installation of an active TMS, monitoring ambient & top / bottom oil

temperatures;

Installation of additional fans, modification to cooling set-points and

enabling pre-cooling;

Initiate pre-cooling in the event of a loss of one transformer (N-1

scenario);

Use the TMS to continuously ensure design limits are not exceeded and

calculate impact on degradation.

A greater understanding, visibility in asset performance leads to a reduction in

assets replacement, facilitating the connection of additional loads and low carbon

technologies.


http://www.smarternetworks.org/NIA_PEA_PDF/NIA_UKPN0001_4644.pdf

https://library.ukpowernetworks.co.uk/library/en/RIIO/Main_Business_Pla

n_Documents_and_Annexes/UKPN_Smart_Grid_Strategy.pdf


TMSs have been implemented at two substations (on a total of six transformers)

to defer reinforcement schemes.


This solution delivers the following benefits: the deferral of reinforcement projects

and MVA released as a result of increased transformer utilisation.

Note that the DTR solution continues to be under development and trialing as an

innovative solution, with these two sites the trial locations for the NIA-funded

project ‘ Power Transformer Real-Time Thermal Rating’ identified above. While

the solution is still under trial the deployment costs reported here are linked to

those in CV36 as eligible NIA project costs. The benefits reported are those of

the expected deferral period of the traditional reinforcement solution from the UK

Power Networks ED1 Business Plan. For Lithos Road the reinforcement is

expected to begin in 2019 and for Weybridge new analyses is being conducted to

confirm the overall site rating, this will update the Totex profile (based on current

Investment pan).


http://www.smarternetworks.org/NIA_PEA_PDF/NIA_UKPN0001_4644.pdf

https://library.ukpowernetworks.co.uk/library/en/RIIO/Main_Business_Plan_Documents_and_Annexes/UKPN_Smart_Grid_Strategy.pdf

https://library.ukpowernetworks.co.uk/library/en/RIIO/Main_Business_Plan_Documents_and_Annexes/UKPN_Smart_Grid_Strategy.pdf


74

Additions units: TMS commissioned at 1 transformer

Disposal units: TMS decommissioned from 1 transformer

Benefit Categories


The volume unit for Gross Avoided Costs is: “£ of deferred cost”

Cost Categories

The volume unit for solution Costs is: “£ of deployment cost”


Impacts have been calculated as load-related investment reduction or deferral

and in capacity released. See the “Calculation of Benefits” section below.



methodology and assumptions









Changes to CBAs










calculated.



MVA released for each transformer with DTR installed.



75

The Gross Avoided Cost is the cost of traditional reinforcement in the

counterfactual case.

Cost: Total Pilot Project Cost

The cost of the phase one of pilot project is accounted.

Cost: Total DTR Cost

The total cost of installing DTR devices to each transformer. This is calculated as

the total cost per DTR installed x the number of DTR installations implemented.

Counterfactual


and the existing, traditional reinforcement is deployed at full cost. MVA released

will be reported as a gross figure, not the net difference between MVA released by

the innovative and traditional solutions.






Power Transformer Real Time Thermal Rating_2016-17 E6 CBA_v1.0

Public Safety



Aggregate cost information was provided, as was the list of events

attended/articles published. An average cost per item was:

Cost Item Type Number attended Cost per Item

£4,000 County Shows 3 £1,333.33

£3,000 Articles 32 £93.75

The value of printing costs was spread over small events as well as county shows.

To calculate a per/event cost, this was done in the following way:

Total cost of printing £12,000

Events where printed material was used, and attendance in all:

o Education Initiatives (95)

o Events (7,326)

o Shows (5,350)

Total attendance =12,771

Therefore cost of printing per person reached = £0.9396

Cost of printing per event = £0.9396*event attendance

The wage cost of the team which organises and attends these events is

£174,000. Assume that 50% of this cost is dedicated to each EPN and SPN.


76

As such, the total annual cost for public safety is £190,555.49

The total population reached in the EPN and SPN public safety campaigns comes

to just over 300,000 in the 2016/17 regulatory year.

General



necessary.





The solution is targeted safety efforts in the EPN and SPN agricultural areas to

prevent injuries to members of the public by coming into contact with live

overhead equipment.

This is delivering benefits by reducing the number of incidents.

Volumes

Addition Units: “1 event”

The volume unit is 1 Event, and it can be any one of the following:

Article in a journal

E-Article

Attending a trade fair

Any other specific safety event

Working with agricultural colleges.

Where an article or e-article has been published and it is not region specific, a

50/50 split between EPN/SPN audience has been assumed.

Disposal Units: will not be reported, as this solution is an action










77

Changes to CBAs










calculated.

Benefit Methodology:

We believe that the efforts from the dedicated team regarding public safety will

lead to a reduction of 1 fatality over the duration of ED1. This is a conservative

estimate based on the large audience reached with our public safety campaign.

We also assume that this will lead to a reduction of 5.67 injuries to members of

the public over the duration of ED1. This preserves the current ratio of public

safety injuries to fatalities.

According to the HSE, the cost of a fatal injury to a member of the public is

£1,570,000 and a non-fatal injury is £7,400. The current ratio of public fatalities

to injuries at UK Power Networks is 3:17.

As such, the public safety spend is justified as (cost of incidents avoided) >

(spend)

(1,570,000+ 5.67x7,400) – (8x190,555.40) = £87,514.80






Public Safety_2016-17 E6 CBA_v1.0

Timed Connections



It is assumed that if customers had preferred to pay for a full (ie non-timed)

connection, the associated reinforcement costs to enable the connection would

have taken three months.

It is assumed that the average MVA connected is equal to a time-weighted

average

http://www.hse.gov.uk/economics/eauappraisal.htm


78

General



necessary.






Offering customers time-dependent connections which allow a higher MVA level to

be taken in periods of reduced network demand.


Timed Connections Standard:

http://library.ukpowernetworks.co.uk/library/asset/3634a9c6-d825-44bd-a5ac-

12a068401d0N/EDS+08-5021+Timed+Connections.pdf


Timed connections have been taken at two customer sites in LPN.

Waterloo Bus Garage: 0.5 MVA during the day, 1.9 overnight (until UK

Power Networks’ reinforcement job in the area is complete, at which point

they will transition to 2.5 MVA all the time)

Camberwell Road: 1.5 MVA during the day, 2 MVA overnight

(permanently)


Lower connection cost for Camberwell Road

Faster connection times for both locations

MVA released much faster than if a non-timed connection (at the max

load) was sought. *Note: this has not been listed in E6 tables. See section

5 for further explanatnion.


Benefit Categories

The volume unit for Gross Avoided Costs is: “£ of avoided cost”

Addition Units

The volume unit is: “1 Timed Connection energised”

Disposal Units

The volume unit for this is “1 timed connection decommissioned ”



box below.

http://library.ukpowernetworks.co.uk/library/asset/3634a9c6-d825-44bd-a5ac-12a068401d0N/EDS+08-5021+Timed+Connections.pdf

http://library.ukpowernetworks.co.uk/library/asset/3634a9c6-d825-44bd-a5ac-12a068401d0N/EDS+08-5021+Timed+Connections.pdf


79












Changes to CBAs










calculated.


The benefit is calculated as the amount of MVA per timed connection less the

counterfactual (amount of MVA per firm connection for the max if a timed

connection was not available). A time-weighted average has been used to

calculated the average MVA released per calculation.

𝑀𝑉𝐴𝑎𝑣𝑒𝑟𝑎𝑔𝑒 = (8

24∗ 𝑜𝑣𝑒𝑟𝑛𝑖𝑔ℎ𝑡𝑀𝑉𝐴) + (

16

24∗ 𝑑𝑎𝑦𝑡𝑖𝑚𝑒𝑀𝑉𝐴)

For Waterloo, this results in 0.9375 MVA capacity connected for 8 months

For Camberwell, this results in 1.83 MVA capacity connected for 3 months

These values have not been included in the E6 table as these relate to specific

customer connections, not a release of capacity available to the market.


The Gross Avoided Cost is the difference in the NPV of the cost profile for the

counterfactual case and the cost profile for the evaluation case


80

Cost: Total Connection Cost

The cost of each connection is considered in total.

Counterfactual Cost

The counterfactual is the case where the customer would have paid for a firm

connection, whereby they could take their maximum demand any time of day.






Timed Connections_2016-17 E6 CBA_v1.0

E7 – LCTs



Heat Pump Data

Where the MPAN is omitted for a record it has been allocated to a DNO in

accordance with its postcode. Where the postcode is also unavailable records

have been spread across the three DNOs in accordance with the proportions

observed among records successfully mapped to a DNO.

Where installed capacity is omitted for a given record, the size has been

estimated to be equal to the average size of systems with known capacity.

Electric Vehicle Charge Point Data

In the event of the system size being indeterminable or unclear for a given

record it was either estimated on the basis of other available information or

assumed to be the most common (Ie mode) system size (32A).

For the purpose of conversion from kVA to kW the voltage was assumed to be

230V and the power factor 0.96.

Where the installation date is unavailable, in the absence of evidence to the

contrary the installation date is assumed to fall in the regulatory year in which

it was received.

Charge points of 16A or less have been reported as slow charge. Charge points

of greater than 16A have been reported as fast charge.

The National Chargepoint Registry (NCR), which contains data relating to

public chargepoints, does not specify the installation date. The installation date

has been estimated based on the creation date of the record. The installation

history implied by the estimation methodology is in line with UKPN’s

expectations. It was considered better to reflect the NCR data in the table with

an approximation of the installation date rather than exclude this data.

Distributed Generation

Sites less than or equal to 11.04kW have been treated as G83 and sites

greater than 11.04kW have been treated as non-G83.

In the absence of evidence to the contrary it has been assumed that sites less


81

than or equal to 1MW are connected to the secondary network and sites

greater than 1MW are connected to the primary network.

As some of the data sources are overlapping and it is expected that the data

relating to some sites may not be precisely accurate. If two records are

sufficiently similar they have been considered to relate to the same site and

the data believed to be most reliable has been used in all calculations. It was

necessary to apply an element of judgment in this review process.

In the case of an unpopulated or incomplete data field for records believed to

represent true sites not represented elsewhere, the missing field has been

estimated based on the best available information. The most common missing

fields were postcode and generation type. Such estimation was not frequently

necessary.

LCT – Processes used to report data

(i) Please explain processes used to calculate or estimate the number and size of

each type of LCT.

(ii) If any assumptions have been made in calculating or estimating either of

these values, these must be noted and explained.

Update to 2015/16 Generation Volumes and Capacities

(i)

Heat Pump Data

1. Obtain Renewable Heat Incentive data for UKPN’s licence areas from

Ofgem in accordance with the Data Sharing Agreement signed on 30th May

2017.

2. Use MPAN and/or postcode to map each unique record to the

corresponding DNO (EPN, LPN or SPN).

3. Determine regulatory year of installation based on the commissioning

date.

4. Calculate the quantity and aggregate capacity of installed systems by DNO

and regulatory year.

Electric Vehicle Charge Point Data

1. Review data, identify and remove duplicates.

2. For each entry in the UKPN EV Charge Point database, convert the charge

point size (specified in amps or volt-amps) to kilowatts in accordance with

voltage and power factor assumptions outlined under Allocation and

Estimation Methodologies above.

3. For all unique sites appearing in the UKPN EV Charge Point database and

the National Chargepoint Registry (NCR) use UKPN postcode-DNO

mapping to map each record to the corresponding DNO.

4. Determine the charge speed category (fast or slow) in accordance with the

assumptions outlined under Allocation and Estimation Methodologies

above.

5. Determine the regulatory year of installation from the installation date.

6. Calculate the quantity and aggregate capacity of installed charge points by

DNO, charge speed and regulatory year.

Distributed Generation


82

1. Obtain FiT Installation Report parts 1 and 2 from

https://www.ofgem.gov.uk/environmental-programmes/feed-tariff-fit-

scheme/feed-tariff-reports-and-statistics/installation-reports.

2. Obtain Renewables Obligation Accredited Stations Public Report from

https://www.renewablesandchp.ofgem.gov.uk/Public/ReportManager.aspx

?ReportVisibility=1&ReportCategory=0.

3. For each of the above databases use UKPN postcode-DNO mapping to map

each site to the corresponding DNO.

4. Determine regulatory year of installation from commissioned date.

5. Using the available technology type data, classify each site as Photovoltaic

or Non-Photovoltaic.

6. Classify each site as G83 (<11.04kW) or non-G83.

5. Classify each site as being connected to the primary or secondary grid in

accordance with the assumptions outlined under Allocation and Estimation

Methodologies above.

7. Calculate the number of sites and aggregate capacity installed in the

2016/17 regulatory year by DNO, including all data outlined in the

preceding steps.

(ii)

Assumptions made in the calculation and estimation of quantities are outlined in

the previous section of this commentary.

LCT - Uptake

Please explain how the level of LCT uptake experienced compares to the forecast

in your RIIO-ED1 Business Plan and the DECC low carbon scenarios. This must

also include any expectation of changes in the trajectory for each LCT over the

next Regulatory Year in comparison to actuals to date.

In the BPDT we expected 33,217 PV units to connect to the secondary network

whereas 3,241 units actually connected. We highlighted last year that the

changes in both the Feed-in Tariff and Renewables Obligation schemes would

result in lower volumes. We have seen a significant reduction from 2015/16 to

2016/17 reflecting those changes. This is particularly true in the small scale

generation market where volumes have decreased by 89%. We expect volumes

in 2017/18 to be lower than in 2016/17.

In our original business plan we expected 28,300 heat pumps to connect in

2016/17 whereas 1,088 actually connected. As we highlighted last year, the

BPDT assumption was that in 2016 the Zero Carbon Homes policy would have

been implemented which would have kick started the heat pump deployment.

The Committee On Climate Change has highlighted that the UK heat

decarbonisation policy needs to be rethought if the 2050 heat decarbonisation

targets are to be achieved. In 2016/17 we have been able to source heat pump

data from the Renewable Heat incentive database. This has shown that UK

Power Networks were not informed about 736 heat pumps which connected to

our three networks in 2015/16. We do not expect to see significant growth,

above historic levels, in the amount of heat pumps connecting to our networks in

2017/18.

In the BPDT we predicted 6,781 charge points connecting in 2016/17 whereas our

records shows that 988 actually connected. However, the volume of electric

vehicles registered in 2016/17 was over 11,000, an increase of 21% on 2015/16.

This growth is being driven by a focus on air quality in urban areas as well as

increasing popularity of electric vehicles. Consequently we expect the number of

https://www.ofgem.gov.uk/environmental-programmes/feed-tariff-fit-scheme/feed-tariff-reports-and-statistics/installation-reports

https://www.ofgem.gov.uk/environmental-programmes/feed-tariff-fit-scheme/feed-tariff-reports-and-statistics/installation-reports

https://www.renewablesandchp.ofgem.gov.uk/Public/ReportManager.aspx?ReportVisibility=1&ReportCategory=0

https://www.renewablesandchp.ofgem.gov.uk/Public/ReportManager.aspx?ReportVisibility=1&ReportCategory=0


83

electric vehicle charge points to increase in 2017/18. For example, in London the

GLA are looking to install an additional 300 charge points by 2020 and have

mandated that all new private hire taxis from 2018 should be zero emission

capable. We are also working with the Office of Low Emission Vehicles (OLEV) to

compare their information on charge points to ours.

In February 2017, streetlights connected to UK Power Networks electricity

network in Kensington and Chelsea have been converted into charge points for

electric vehicles – a first for central London.

The trial by the Royal Borough of Kensington and Chelsea, UK Power Networks,

and Ubitricity has started with the conversion of the first three Kensington street

lights into electric vehicle (EV) charge points. This installation allows two local

residents to charge their vehicles from a street light near their front door, and

receive accurate bills for their electricity use via their smart phone or home PC.

In the trial in Onslow Gardens, Kensington, drivers who previously charged their

EV at a nearby shopping centre now park and plug in at one of the street lights

that have been retro-fitted with charging technology. Access to the charge points

is managed with smart charging cables. This way the amount of electricity being

used can be accurately determined, so it can be paid for.

The trial which started in November could pave the way for greater EV use and

tackle air pollution in London by allowing drivers to conveniently charge their

vehicles closer to home over-night. In outer London, 33% of households have no

access to off-street parking to charge an EV, and in inner London this rises to

46%.

This solution means we can monitor how much electricity is being used in order to

maintain reliable electricity supplies as more EVs connect to our networks. It

should also release more parking spaces currently set aside as dedicated EV

charging bays, result in less street furniture and fewer excavations to install new

charging points. It is another example of how our business is supporting the

transition to a low carbon future.

http://www.ukpowernetworks.co.uk/internet/asset/14218fd8-825b-43eb-aeae-094e4c2e796M/Leading+the+charge+on+electric+cars1+(002).jpg?rendition=largeNewsThumbnail

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