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RIIO-ED1 RIGs Environment and Innovation Commentary, version 4.0

2017/18

UK Power Networks

Contents

Summary – Information Required 1Worksheet by worksheet commentary 1

E1 – Visual Amenity 2E2 – Environmental Reporting 2E3 –BCF 3E4 – Losses Snapshot 5E5 – Smart Metering 6E6 – Innovative Solutions 7E7 – LCTs 8

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 commentaryAt 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 (i.e. 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.

Environment and Innovation Commentary 1

E1 – Visual AmenityAllocation 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 2017/18:

DNO Designated Area

OHL Inside Designated

Areas at End of Reporting

Year (km)

OHL (km) Removed

During Year

UG Cables Installed During

Year (km)

EPN

The Broads National Park 151.58 1.40 1.61Suffolk Coast and Heaths AONB 411.09 0.00 0.00Norfolk Coast AONB 436.22 0.66 1.84Dedham Vale AONB 135.29 0.00 0.00

SPN

South Downs National Park 1947.38 0.00 0.00High Weald AONB 1100.65 0.00 0.00Surrey Hills AONB 811.91 0.00 0.00Kent Downs AONB 1077.85 0.00 0.00

E2 – Environmental ReportingAllocation 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)

SF6 volumes: include assets that are in service on the network, items that are available on the network but not currently in service and items that are under test and therefore unavailable.

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.During the regulatory period 2017/18 UK Power Networks received 35 enquiries and


complaints about noise. These mainly related to substations and transformers, with a small number relating to alarms or street noise.

Bespoke acoustic enclosures were fitted to both transformers at Noak Hill Primary substation, and innovative noise screens were successfully installed on four transformer bays at Moscow Road main substation. Anti-vibration pads were fitted in response to a complaint about a secondary substation and at another the transformer was replaced.

The Salford University Methodology (NANR 45) is used to assess the likelihood of statutory nuisance.

We continue to engage with local authorities and others to highlight the need to consider low frequency noise at the planning stage of new developments.

The world-first Noisetrap panels have been installed by UK Power Networks at a substation in the Bayswater area, reducing the noise level from that of a busy restaurant to a typical library. Designed by Sonobex Limited and manufactured and installed by Merford Noise Control, the panels absorb and cancel low frequency noise, whilst crucially allowing natural airflow to cool the electrical equipment inside the building.

Following a successful trial the company is now piloting the screens to see if they would be suitable for other sites where equipment can sometimes be heard from outside.

Unlike other solutions, the modular Noisetrap panels also allow easy access to the equipment for essential maintenance.

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.N/A

Where reported in the Regulatory Year under report, DNOs must provide 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 eight interactions with the Environment Agency, all of which were rated as Minor or No Impact. We received three notices from local authorities in relation to Waste; one of which was formally rejected because the land in question was not owned by UK Power Networks and the waste not our responsibility.

One noise abatement notice was received following the building of a residential development overlooking a primary substation. Positive engagement with the local authority environment officer ensured a reasonable and workable timeframe for completion of mitigation.

Where reported in the Regulatory Year under report, DNOs must provide discussion of details of any Environmental Management System (EMS) certified under ISO or other recognised accreditation scheme.In 2018 UK Power Networks underwent re-certification audit and the external regulator recommended the company for certification to the new ISO 14001: 2015 standard.

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.No new permits, or variations to existing permits, were applied for in the regulatory year.


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.

SF6 Mitigation - ReplacementsCircuit Breakers 105 and 205 at Colchester Grid are 132kV AIS type Brush DB145 circuit breakers, situated outdoors. They are feeder breakers that feed Colchester Grid 132/33kV, Colchester Grid 132/25kV and Colchester Grid 132/11kV.

These circuit breakers were a priority, with total SF6 topped-up of 21.85kg in 2017, making it the most significant SF6 leaking assets in EPN.

The most cost-effective solution was deemed to be replacement of the circuit breakers following assessment of the condition of the breakers. This intervention was completed on 05/11/17 and 30/11/17 respectively for 105 and 205 and resolved the issue with SF6 leakage on these breakers as we have had no reported leaks on this asset since the intervention.

SF6 Mitigation – RefurbishmentsCity Road – Three 132kV circuit breakers at City Road were leaking significantly, to the tune of 9kg in 2017. Following an assessment by the manufacturer, they were deemed amenable to repair. They were refurbished in March 2018 with a replacement of all worn or defective parts and there have been no more reported leaks since.Rumburgh – Two 132kV Siemens circuit breakers (SPS model) were refurbished following leak incidents and a condition assessment. The work was completed in January 2018 and there have been no leaks since.Ilketshall – One 132kV Siemens circuit breaker (SPS model) was refurbished following a leak incident and condition assessment. The work was completed in January 2018 and the leak incidents have ceased.Halesworth – One 132kV Siemens circuit breaker (SPS model) was refurbished following leak incidents and a condition assessment. The work was completed in December 2017 and has resolved the leak issue.

E3 – BCFAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.

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 2018. These apportionments are covered in the detailed commentary for the individual areas.

BCF reporting boundary and apportionment factorDNOs 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 2017 to March 2018). In all calculations the Defra conversion factors in place on March 31st 2018 - as recommended in the reporting guidelines from Ofgem - have been used unless stated otherwise.

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 processThe 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

1 Greenhouse gas protocol


http://www.ghgprotocol.org/

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 our 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 2018 and the latest Regulatory Information Guidelines are reviewed for any changes to the reporting process.

Data for the regulatory year is 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.

The entire Business Carbon footprint process was examined for three consecutive years by UK Power Networks own internal audit team. They have moved this to every second year as they have sufficient confidence in the process.

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 BCFFor each category of BCF in the worksheet (i.e. 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 i.e., 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 (e.g.,

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 (e.g., a mixture of mileage and fuel volume for transport), DNOs should describe their methodology in commentary, including the relevant physical units, e.g. 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 99.35% of fuel purchased in 2017/18 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 Sourc

e

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data

provided e.g. Direct

Measurement, Estimated or Excluded

Data

Scope (GHG

Protocol)

X Diesel Fuel Card

2.600 (litres to kgC02e)

16,432.54

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 43.6% in EPN, 29.8% in LPN and 26.5% in SPN. This compares with 43.5% in EPN, 29.7% in LPN and 26.7% in SPN last year. 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.

This represents an increase of 2,609 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 26,718.82 tCO2e in 2017/18. This represents a 13.7% decrease, mainly due to 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 798 29.8% 4,900.29B SPN 710 26.5% 4,359.90C EPN 1168 43.6% 7,172.35

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 km 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)

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

Business Transport - Passenger ROADKey

Data Type/

Description

Data Sourc

e

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data



Data

Scope (GHG

Protocol)

X Business Kms (UKPN company

cars)

SAP 0.116 (Kms to kgCO2e)

(weighted average)

798.81 Measurement and

Estimation

3

X Business Kms (Non

UKPN owned

cars/taxis)

SAP 0.179 (Kms to kgCO2e) (average

car factor)


estimation

3

X Diesel Fuel Card and fuel

expense

claims



estimation

3

Total 3565.39

Business Transport - Passenger RAILKey

Data Type/

Description

Data Source

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data



Data

Scope (GHG

Protocol)

X Rail Travel SAP; corporate card and

Clarity

0.04678 (£ to kms to kgC02e)

(Clarity data is

already in kms)

278.23 Estimate and measurement

3

Business Transport - Passenger AIRKey

Data Type/

Description

Data Source

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data

provided e.g. Direct Measureme

nt, Estimated or

Excluded Data

Scope (GHG

Protocol)

X Air Travel Corporate Credit

Card

0.19452 (£ to kms) to kgC02e(weighted

132.84 Estimate and Measurement

3


and Clarity

factor - proportional to % of long haul, short haul

or domestic

travel)Total 3979.6

7

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

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 29%, EPN 39% and SPN 32% compared to LPN 30%, EPN 38% and SPN 33% 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.


Area

Headcount

Percentage of staff

tC02e

A LPN 903 29% 941.99B EPN 1,189 39% 1433.07C SPN 984 32% 1190.33

Business Transport - Passenger RAILKey

Area

Headcount

Percentage of staff

tC02e

A LPN 903 29% 81.68B EPN 1,189 39% 107.54C SPN 984 32% 89.01

Business Transport - Passenger AIRKey

Area

Headcount

Percentage of staff

tC02e

A LPN 903 29% 39.00


B EPN 1,189 39% 51.35C SPN 984 32% 42.50

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. SPN’s figure increased in 2017/18 due to a single end box failure which resulted in 32.6kgs of SF6 being released, more than 91% of SPN’s total figure. The circuit breakers are being replaced at 3 of EPN’s sites which suffer from the most gradual leakage.

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

Key

Data Type/

Description

Data Sourc

e

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data



Data

Scope (GHG

Protocol)

A LPN SF6 Losses

Ellipse 22800 (kg to kgC02e)

167.58 Measurement 1

B SPN SF6 Losses



C EPN SF6 Losses


2126.78

Measurement 1

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. 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.

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

Data Source

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data



Data

Scope (GHG

Protocol)

X Stand-by Diesel

Invoices; Deliverie

2.954 (red diesel litres to

9657.04

Measurement 1


generators; Plant and

Equipment

s to bowsers;

fuel cards

kgC02e)

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

Key

Area

tC02e

A LPN 582.97B SPN 4691.45C EPN 4382.62

LossesThese 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 2017/18 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

Data Sourc

e

Conversion Factor

Conversion Factor

explained

Total Apr 17 to

Mar 18 (tC02e)

Details of data


nt, Estimated or

Excluded Data

Scope (GHG

Protocol)

A LPN Losses Billing for

each site

0.412 (kWh to tC02e)

644,057.92

Measurement

B SPN Losses Billing for

each site


489,723.08

Measurement

C EPN Losses Billing for

each site


838,822.16

Measurement

ContractorsWhen 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 DefinitionContractors 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 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 43.6% in EPN, 29.8% in LPN and 26.5% in SPN. The proportion attributed to EPN has increased by 6.6% 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 17 to Mar

18 (tC02e)

Details of data


nt, Estimated

or Excluded Data

Scope (GHG

Protocol)

Y Diesel Contractor fuel card


10286.28

Measurement 3


Key

Area

Direct op. staff

Percentage of staff

tC02e

A LPN 798 29.8% 3067.43B SPN 710 26.5% 2729.17C EPN 1168 43.6% 4489.68

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

17 to Mar 18 (tC02e)

Details of data



Data

Scope (GHG

Protocol)

Y Contractor Business

kms

Contractor

records

0.179 (Kms to kgCO2e) (average

car factor)




Area

Headcount

Percentage of staff

tC02e

A LPN 798 29.8% 107.18B SPN 710 26.5% 95.36C EPN 1168 43.6% 156.87

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


Key

Data Type/

Description

Data Source

Conversion Factor

Conversion Factor

explained

Total Apr

17 to Mar 18 (tC02e)

Details of data



Data

Scope (GHG

Protocol)

Y Contractor Plant and

equipment

Contractor

records

2.954 (red diesel litres to kgC02e)



Key

Area

Direct op. staff

Percentage of staff

tC02e

A LPN 798 29.8% 154.72B SPN 710 26.5% 137.66C EPN 1168 43.6% 226.46

Building energy usageNatural 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 41%, LPN 30%, SPN 29%. This headcount split is only a slight variation 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 Sourc

e

Conversion Factor

Conversion Factor

explained

Total Apr 17 to Mar

18 (tC02e)

Details of data


Measurement, Estimated

Scope (GHG

Protocol)


or Excluded Data

A LPN Electricity

Usage

Energy Bills

0.352 (kWh to kgC02e)


B SPN Electricity

Usage

Energy Bills



C EPN Electricity

Usage

Energy Bills



Total 3626.56

A LPN Gas Usage

Energy Bills

0.184 (Gross CV)

(kWh to kgC02e)

39.39 Measurement 2

B SPN Gas Usage

Energy Bills

0.184 (Gross CV)

(kWh to kgC02e)

94.69 Measurement 2

C EPN Gas Usage

Energy Bills

0.184 (Gross CV)

(kWh to kgC02e)


Total 257.12

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 17 to Mar

18 (tC02e)

Details of data


nt, Estimated

or Excluded Data

Scope (GHG

Protocol)

A LPN Metered

and Unmetered

Energy Bills and

Assessed



B SPN Metered

and Unmetered

Energy Bills and

Assessed



C EPN Metered

and Unmetered

Energy Bills and

Assessed



Total 16204.43


E4 – Losses SnapshotAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.EPN

As reported in our 2016/17 E4 submission it became apparent that our previous reporting methodology (prior to 2016/17), in relation to transformers, didn’t 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 in our E4 submission.

The volumes of distribution transformers that delivered energy improvements and conformed to the above-mentioned criteria during the 2015/16 financial year were also adjusted to comply with Ofgem’s guidance in this submission; the changes appear in column N of the E4 Losses Snapshot.

Transformer replacementsCBA analyses have demonstrated that the following secondary transformer size increments are economically justifiable from a losses perspective:

GMTs, upsize 500kVA to 800 kVA, and 800kVA to 1000kVA, and PMTs upsize 25kVA to 50kVA. The justification for PMTs first emerged during this year’s economic appraisal, hence the introduction in this year’s submission. Table 1 below captures the relevant numbers and losses benefits:

Table 1 : Energy savings attributed to secondary transformers: Number of transformers MWh savings

GMTs 40 322PMTs 22 16Totals 62 337.5

Prices for different transformer sizes were obtained from UKPN’s Compatible Units2 price list, and the costs of the various upgrades were determined using this information. This approach yielded a total cost increment of £80.6k 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 & PMT volumes that deliver loss improvements in EPN and are reported in column P.

Column J of E4 relates to unit costs, and these costs were obtained from our Compatible Units Price List.

Column X values are determined by multiplying the volumes and the unit costs to provide the Estimated Total Cost. Column AF multiplies the asset volumes in column P by the justified unit costs in column M to provide the total Justified Cost.

Column AN shows the cumulative loss reductions for each category and activity.

LV CablesLV cable size increases to decrease network energy losses were reviewed and subjected to continued CBA assessment in the past year, and it was found that these upgrades are still justified.

Costs to increase cable sizes were calculated based on the price differentials between cables of various sizes (95mm2, 185mm2 and 300mm2). Across all three licence areas in

2 Our Compatible Units Price List is ordinarily used to calculate the cost of planned work


2015, the split of LV cable used was 45% as 95mm2, 35% as 185mm2 and 20.0% as 300mm2. This ratio is used as a datum to measure subsequent E4 submissions against as this represents the ratio before changes to relevant Engineering Design Standards came into effect. The continued shift towards the use of larger conductor meant that in 2017/18 the percentage split improved to 26% of 95mm2, 44% of 185mm2 and 29% of 300mm2.

Comparison of the 2017/18 ratios to those reported in 2015/16 enabled the effective reduction in use of 95mm² cable to be calculated. In EPN this amounted to a total of 55.6km being installed as either 185mm² or 300mm² rather than 95mm². Visibility of this data enabled incremental losses improvements to be calculated using assumed utilisation and load loss factors, resulting in a total losses improvement figure of 2019.8MWh across all licence areas. It should be noted that due to a change in the methodology used to calculate these values the reported values for 2015/16 and 2016/17 have also been revised on the E4 return. In EPN, the total improvement equates to 1091MWh at an incremental cost of £236k in nominal terms. This incremental cost was further apportioned according to volumes stated for the various work categories and entered into column AF of the losses snapshot E4. The incremental loss benefits (MWh) were accounted for in column AN.

As mentioned above, cable-related activities saved 1091 MWh in EPN. Combining this with the above-mentioned CBA justified transformer activities (337.5 MWh) yields 1428.5 MWh and represents UK Power Networks’ 2017/18 E4 submission for EPN.

The following sections below explain the methodology used to calculate the loss improvements associated with transformer replacements. These sections further elaborate on loss improvements attributed to work both supported and unsupported by CBAs to create a complete understanding of the losses improvement attributed to work completed in 2017/18.

In summary, a total of 679 secondary transformers that were installed delivered improvements in network losses relative to the units that they replaced. All secondary units together (including the CBA justified installations) yielded an annual improvement of 2,642MWh. In addition, four grid and twelve primary substation transformers were replaced in EPN, which together realised an improvement of 1627.4MWh/annum. The values unsupported by CBAs are not included within our RIGs return but are highlighted in this commentary for information purposes only.

Calculating Secondary Transformer BenefitsIn EPN a total of 679 new secondary transformers delivered energy savings benefits during 2017/18. Using UK Power Networks’ asset register, details of the sites where new transformers were installed have been identified. These were cross-referenced with units that were removed from site.

Using each unit’s 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 utilisation 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 annual energy 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. The 679 secondary transformers that delivered benefits consist of 315 PMTs and 364 GMTs. Combined, these units yielded an annual losses improvement of 2,642MWh

Calculating Grid and Primary Transformer BenefitsThe energy savings associated with Grid and Primary transformer replacements were calculated using transformer test certificate information and circuit-specific Load Loss Factors. 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:

1. Obtain iron and copper loss specifications along with the transformers’ MVA and voltage ratings.2. Introduce a circuit-specific Load Loss Factor (LLF) for each site in question to account for the nonlinear characteristics of copper losses (I2R). The LLF values used were as follows:-132kV Primary Voltage Level: 0.4-66kV Primary Voltage Level: 0.37-33kV or 22kV Primary Voltage Level: 0.354. 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.

As mentioned earlier, Grid and Primary Substation transformer replacements combined yielded a total energy savings benefit of 1627.4MWh for EPN. Table two below summarises the overall improvement, including loss reductions due to the adoption of Eco 2015 transformers that are mandatory at present.

Table 2 : Total annual energy savings for EPN (Previous Approach) EPN MWh losses reducedPrimary & Grid Transformers 1627.4Secondary Transformers 2642.0LV Cables 1091.0Total 5360.4

LPN

As reported in our 2016/17 E4 submission it became apparent that our previous reporting methodology (prior to 2016/17), in relation to transformers, didn’t 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 in our E4 submission.


Transformer replacementsCBA analyses have demonstrated that the following secondary transformer size increments are economically justified from a losses perspective:



GMTs 74 931.2PMTs 0 0Totals 74 931.2

Prices for different transformer sizes were obtained from UKPN’s Compatible Units3 price

3 Our Compatible Units Price List is ordinarily used to calculate prices for planned work.


list, and the costs of the various upgrades were determined using this information. This approach yielded a total cost increment of £127.3k 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 LPN and are reported in column P.

Column J of E4 relates to unit costs, and these costs were obtained from our Compatible Units Price List.



LV CablesLV cable size increases to decrease network energy losses were also reviewed and subjected to continued CBA assessment in the past year, and it was found that these upgrades are still justified.

Costs to increase cable sizes were calculated based on the price differentials between cables of various sizes (95mm2, 185mm2 and 300mm2). Across all three licence areas in 2015, the split of LV cable used was 45% as 95mm2, 35% as 185mm2 and 20.0% as 300mm2. This ratio is used as a datum to measure subsequent E4 submissions against as this represents the ratio before changes to relevant Engineering Design Standards came into effect. The continued shift towards the use of larger conductor meant that in 2017/18 the percentage split improved to 26% of 95mm2, 44% of 185mm2 and 29% of 300mm2.

Comparison of the 2017/18 ratios to those reported in 2015/16 enabled the effective reduction in use of 95mm² cable to be calculated. In LPN this amounted to a total of 16.4km being installed as either 185mm² or 300mm² rather than 95mm². Visibility of this data enabled incremental losses improvements to be calculated using assumed utilisation and load loss factors, resulting in a total losses improvement figure of 2019.8MWh across all licence areas. It should be noted that due to a change in the methodology used to calculate these values the reported values for 2015/16 and 2016/17 have also been revised on the E4 return. In LPN, the total improvement equates to 322.7MWh at an incremental cost of £70k in nominal terms. This incremental cost was further apportioned according to volumes stated for the various work categories and entered into column AF of the losses snapshot E4. The incremental loss benefits (MWh) were accounted for in column AN.

As mentioned above, cable-related activities saved 322.7 MWh in LPN. Combining this with the above-mentioned CBA justified transformer activities (931.2 MWh) yields 1254 MWh and represents UK Power Networks’ 2017/18 E4 submission for LPN.

The next sections below describe the methodology used to calculate the losses improvement attributed to the use of more efficient transformers on our networks (supported and unsupported by CBAs). During 2017/18, a total of 344 secondary transformers that were installed delivered improvements in network losses relative to the units that they replaced. All units together yielded an annual improvement of 2,604MWh. In addition, eight grid and five primary substation transformers were replaced in LPN, which together realised an improvement of 1569.7MWh/annum. The values unsupported by CBAs are not included in our E4 return but are highlighted in this commentary to create a full understanding of losses improvement in our networks.

Calculating Secondary Transformer BenefitsIn LPN a total of 344 new secondary transformers delivered energy savings benefits during the 2017/18 period. Using UK Power Networks’ asset register, details of the sites where new transformers were installed have been identified. These were cross-referenced with any units that were removed from site.


Using each unit’s age and capacity, and referring to generic transformer specifications (pre 1955, 1971, 1979, 1984 and ECO 2015) enabled us to quantify the iron and copper losses associated with the various transformers. Using an assumed utilisation 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 annual energy losses were estimated.

Subtracting the sum of new losses from the old yields the annual energy savings 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. Of the 344 units that deliver benefits, 99 relate to sites where a larger replacement unit was installed. The other units delivered benefits through the use of lower loss transformers compared to those that were replaced.

Calculating Grid and Primary Transformer BenefitsThe energy savings associated with Grid and Primary transformers were calculated using transformer test certificate information and circuit-specific Load Loss Factors. 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:

1. Obtain iron and copper loss specifications along with the transformers’ MVA and voltage ratings.2. Introduce a circuit-specific Load Loss Factor (LLF) for each site in question to account for the nonlinear characteristics of copper losses (I2R). The LLF values used were as follows:-132kV Primary Voltage Level: 0.4-66kV Primary Voltage Level: 0.37-33kV or 22kV Primary Voltage Level: 0.354. 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.

As mentioned earlier, Grid and Primary Substation transformer replacements combined yielded a total energy savings benefit of 1569.7MWh for LPN. Table two below summarises the overall improvement, including loss reductions due to the adoption of Eco 2015 transformers that are mandatory at present.

Table 4 : Total annual energy savings for LPN LPN MWh losses reducedPrimary & Grid Transformers 1569.7Secondary Transformers 2604LV Cables 322.7Total 4496.4

SPN

As reported in our 2016/17 submission it became apparent that our previous reporting methodology (prior to 2016/17), in relation to transformers, didn’t 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 in our E4 submission.



Transformer replacementCBA analyses have demonstrated that the following secondary transformer size increments are economically justifiable from a losses perspective:



GMTs 12 137.9PMTs 9 5.5Totals 21 143.5

Prices for different transformer sizes were obtained from UKPN’s Compatible Units4 price list, and the costs of the various upgrades were determined using this information. This approach yielded a total nominal cost increment of £25.5k 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 & PMT volumes that deliver loss improvements in SPN and are reported in column P.

Column J of E4 relates to unit costs, and these costs were obtained from our Compatible Unit Price List.



LV CablesLV cable size increases to decrease network energy losses were also reviewed and subjected to continued CBA assessment in the past year, and it was found that these upgrades are still justified.

Costs to increase cable sizes were calculated based on the price differentials between cables of various sizes (95mm2, 185mm2 and 300mm2). Across all three licence areas in 2015, the split of LV cable used was 45% as 95mm2, 35% as 185mm2 and 20.0% as 300mm2. This ratio is used as a datum to measure subsequent E4 submissions against as this represents the ratio before changes to relevant Engineering Design Standards came into effect. The continued shift towards the use of larger conductor meant that in 2017/18 the percentage split improved to 26% of 95mm2, 44% of 185mm2 and 29% of 300mm2.

Comparison of the 2017/18 ratios to those reported in 2015/16 enabled the effective reduction in use of 95mm² cable to be calculated. In SPN this amounted to a total of 30.9km being installed as either 185mm² or 300mm² rather than 95mm². Visibility of this data enabled incremental losses improvements to be calculated using assumed utilisation and load loss factors, resulting in a total losses improvement figure of 2019.8MWh across all licence areas. It should be noted that due to a change in the methodology used to calculate these values the reported values for 2015/16 and 2016/17 have also been revised on the E4 return. In SPN, the total improvement equates to 606.2MWh at an incremental cost of £131k in nominal terms. This incremental cost

4 Our Compatible Units Price List is ordinarily used to estimate costs for planned work.


was further apportioned according to volumes stated for the various work categories and entered into column AF of the losses snapshot E4. The incremental loss benefits (MWh) were accounted for in column AN.

As mentioned above, cable-related activities saved 606.2 MWh in SPN. Combining this with the above-mentioned CBA justified transformer activities (143.5 MWh) yields 749.7 MWh and represents UK Power Networks’ 2017/18 E4 submission for SPN.

The next sections below explain the methodology used to calculate the energy efficiency improvements associated with transformer replacements. These sections relate to work supported and unsupported by positive CBAs. In these sections, we aim to create a complete understanding of the losses improvement associated with work completed in 2017/18.

In summary, a total of 370 secondary transformers that were installed during 2017/18 delivered improvements in network losses relative to the units that they replaced. All distribution transformers together (supported and unsupported by CBAs) yielded an annual improvement of 1,752.6MWh. In addition, two grid and eight primary substation transformers were replaced in SPN, which together realised an improvement of 1044.3MWh/annum.

Calculating Secondary Transformer BenefitsIn SPN a total of 370 new secondary transformers delivered energy savings benefits during the 2017/18 period. Using UK Power Networks’ asset register, details of the sites where new transformers were installed have been identified. These were cross-referenced with any units that were removed from site.

Using each unit’s age and capacity, and referring to generic transformer specifications (pre 1955, 1971, 1979, 1984 and ECO 2015) enabled us to quantify the iron and copper losses associated with the various transformers. Using an assumed utilisation 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 annual energy losses were estimated.

Subtracting the sum of new losses from the old yields the annual energy savings 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 did not deliver benefits were dismissed. Of the 370 units that deliver benefits, 153 relate to sites where a larger replacement unit was installed. The other units delivered benefits through the use of lower loss transformers compared to those that were replaced.

Calculating Grid and Primary Transformer BenefitsThe energy savings associated with Grid and Primary transformers were calculated using transformer test certificate information and circuit-specific Load Loss Factors. 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:

1. Obtain iron and copper loss specifications along with the transformers’ MVA and voltage ratings.2. Introduce a circuit-specific Load Loss Factor (LLF) for each site in question to account for the nonlinear nature of copper losses (I2R). The LLF values used were as follows:-132kV Primary Voltage Level: 0.4-66kV Primary Voltage Level: 0.37-33kV or 22kV Primary Voltage Level: 0.354. 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.

As mentioned earlier, Grid and Primary Substation transformer replacements combined yielded a total energy savings benefit of 1044.3MWh for SPN. Table two below summarises the overall improvement, including loss reductions due to the adoption of Eco 2015 transformers, which did not have to be supported by positive CBAs.

Table 6 : Total annual energy savings for SPN SPN MWh losses reducedPrimary & Grid Transformers 1044.3Secondary Transformers 1752.6LV Cables 606.2Total 3403.1

Programme/Project TitlePlease 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 activityIf, 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 ScenarioPlease 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 ToolDNOs 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.

CBAs have been submitted with the workbooks.

Changes to CBAsIf, 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.

n/a

Cost benefit analysis additional informationPlease 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.

Generic CBA RIIO ED1_v4 GMTsGeneric CBA RIIO ED1_v4 LV CableGeneric CBA RIIO ED1_v4 PMTs

E5 – Smart MeteringAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.

N/A

Actions to deliver benefitsDetail 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

Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.N/A


Use of the RIIO-ED1 CBA ToolDNOs 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

Cost benefit analysis additional informationPlease 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 solution reported in the Regulatory Year under report.N/A

E6 – Innovative Solutions

3D Laser SurveyingAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.Due to the low volume of three dimensional (3D) Laser Scans completed per year, actual records are used to determine the evaluation case, and a case-by-case basis is used to calculate the counter-factual case. Standard cost units for CAD technician, confined space team, and surveyors are used in each case.

GeneralFor 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 solution is 3D surveying using a scanner which uses Lidar (laser imaging, detection and ranging) technology. The information captured in this way can then easily be turned into traditional 2D diagrams.

How it is being used?It is using a 3D laser scanning device to take records of sites, instead of a traditional two dimensional (2D) topographical survey.

How is it delivering benefits?3D surveys were introduced to the company in 2015, and have been extremely beneficial in a number of circumstances. The benefits from using this type of technology are as follows:

The 3D scans enable detail to be captured which would be extremely complex in a traditional 2-d survey.

It is more accurate than a topographical survey, with 0.5mm tolerance. For a very complex site, it is much faster to collect data compared to a traditional

survey For a high-risk site, confined spaces, the reduction in time required to complete the

survey also results in improved safety. A 3D Laser Scan is more cost effective than a traditional survey.


What is the volume unit and what has been counted as a single unit?The volume unit used is defined as an event where a scan has been conducted of a site. This could be a tunnel, substation or other discrete part of network.

How have each of the impacts been calculated? The impacts are considered jointly with benefits in the “Calculation of Benefits” box below.

What assumptions have they been relied upon?The assumptions behind the impacts are considered jointly with benefits in the “Calculation of Benefits” box below.

Use of the RIIO-ED1 CBA ToolDNOs should use the latest version of the RIIO-ED1 CBA Tool for each solution 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 RIIO-ED1 CBA Tool has been used

Changes to CBAsIf, 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, the DNO should include an explanation of what has changed and why the DNO is continuing the activity.n/a

Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.Due to the low volume of 3D Laser Scans completed per year, actual records are used to determine the evaluation case, and a case-by-case basis is used to calculate the counter-factual case. Standard cost units for CAD technician, confined space team, and surveyors are used in each case.

The change in costs between the factual and counter-factual scenarios have to do with the number of days spent on site scanning, and the number of days spent with CAD drafting. This is evaluated on a case-by-case basis with a business owner.

Cost benefit analysis additional informationPlease 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 solution reported in the Regulatory Year under report.

Cost Units: Confined space team costs £1000/day (CU-SUR081) Cost of a surveyor is £522/day (average of cost units for all 3 DNOs) (CU-LAB151) Cost of a CAD technician is £44.38/hour (=£328.41/day) (CU-LAB006) Cost of renting laser scanner varies project-to-project, but the average day rate is

£1,350 (there is no current CU for this)


APRSAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.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.




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 being strategically 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 supplies in less than 3 minutes by automatic 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 methodology and assumptions.



Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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 £/interruptionThe 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

The costs are captured as the APRS deployment project costs, including development, testing, and deployment of the software solution and license costs.


2017-18 RIGS E6 CBA Master_v4.0

CNAIMAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.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 profileb) 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.






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.

Are there any external documents to link to?

DNO COMMON NETWORK ASSET INDICES METHODOLOGY - Health & Criticality - Version 1.1



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 lifespan of assets is increased.

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

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.




Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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 average decommissioned age after implementing CNAIM.



Demand Side ResponseAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.The following section details the high level assumptions made in the calculations for this solution.• The solution has been implemented on a substation within UKPN’s EPN network.

• The approach to calculating Totex is to refer to the Submission NAMP for the baseline Totex and the Current NAMP 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.







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.


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 trailing DSR and service improvement opportunities with vulnerable customers through specialised ToU tariffs


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”. DSR service costs have been reported for the period that it should have been incurred as opposed to when payment was actually made.









Benefit: MVA ReleasedThe 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 CostsThe 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 for the following cost areas though these were not incurred as actual costs in this reporting period:

Cost: Total Program Implementation CostThe cost of implementing the program (system and process change related) is considered in total.

Cost: Initial Substation Monitoring and Contract Telecom CostThe 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. This is set as zero as no cost were incurred.

Cost: Ongoing Substation Monitoring and Contract Telecom CostThe 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. This is set as zero as no cost were incurred.

CounterfactualThe 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.



Supporting documents and CBA stored in the innovation RIG folders:• 180207_Cost Summary – contain details of the contract cost• Confidential Demand Response Contract - KiWi 300316 – the DSR contract• Current APP – the latest agreed plan (Mar 2017)• Submission APP – Submission_NAMP worksheet


DNVAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.• All investment costs incurred prior to this regulatory year, hence no investment costs are reported in 2017/18.

• 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 that 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 2017/18.




assumptions have been relied upon.What is the solution?

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_170201143749.pdfii) Link to the registration document for the Distribution Network Visibility project through which the application was developed: http://www.smarternetworks.org/project/ukpnt1002

How is the DNV application being used?


http://www.smarternetworks.org/project/ukpnt1002

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

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.

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 2017/18 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 2017/18.

How has each of the impacts been calculated?


What assumptions have they been relied upon?





Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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 2017/18 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 2017/18 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.



Energy StorageAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.The following section details the high level assumptions made in the calculations 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 Evaluation Totex – Reinforcement. • Actual operating costs and revenues up to March 2018; accruals not included

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.






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


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”


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



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








CounterfactualIt 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 ReleasedThe 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 CostsThe 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 ImpactThe 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.


Additional evidence and the CBA are stored in the innovation folders. The additional evidence documents consist of:• Energy Storage only CBA (generated 2018-4-24) – trial costs • SAP Extract - SNS BAU SO 2017-18 – actual costs and revenues


Innovative BundingAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.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.





The solution is polymer-based bunding equipment (Omnibund and Bundsep) which replaces the traditional concrete/brickwork wall and sump pump systems. 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.

How is the Innovative Bund being used?

The Innovative Bund and Bundsep have been adopted as business as usual in the current Oil Containment Engineering Design Standard of UK Power Networks. The decision on


whether to use this innovative solution is made on a case by case basis.

How is the Innovative Bund delivering benefits?

Omnibund – It provides a solution to the site where traditional bund cannot be adopted. It is easier and quicker to install because no need in excavation. This also reduce cost and carbon emissions.

Bundsep – It is a cheaper yet better solution than the traditional sump system. It allows water and oil to be separated and therefore reduce environment risk and maintenance.

These benefits are proved and captured in projects since 2016.

Volumes

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”

How has each of the impacts been calculated?


What assumptions have they been relied upon?




Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.Benefits are captured from following aspects:• 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

Counterfactual scenario:

• Cost or 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.



Joint ShellAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.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 is 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.




assumptions have been relied upon.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.

In the regulatory year 2017/2018, we have installed 90 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.



Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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 £ TotalEPN 924 1,652 170 84 33 2,863SPN 870 1,508 170 84 23 2,655LPN 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 2,030SPN 833 1,822LPN 1100 2,819

Number of Joint shells Installed:

Region Number of Joint shells Installed in 2017/2018:

Total Savings per DNO(£)

EPN 20 40,600SPN 20 36,440LPN 50 140,950



LiDARAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.The following section details the high level assumptions made in the calculations 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 DPRC5 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 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 efficiency.







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 the 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 minimise the impact of tree (-growth) related faults. It should also help to reduce the amount of cutting required to achieve at least equivalent levels of fault prevention as in DPCR5.


UK Power Networks (UKPN) saves surveying costs by using LiDAR or similar techniques to produce an intelligent risk-based cutting program, contributing towards cost-savings through targeted tree-cutting.


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


Impacts have been calculated as cost reductions in total cutting and surveying costs. See the “Calculation of Benefits” section below.






Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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. 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 is applied.




LPN InterconnectionAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.The following section details the high level assumptions made in the calculations 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.

• 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.






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_Plan_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 HV network is reduced.


Gross Avoided Costs:Avoided Reinforcement Costs – The volume unit for Avoided Reinforcement Costs is “1 project deferred”.







Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.CounterfactualIt 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 CostsThe 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 (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− MeshedUtilisationConventionalUtilisation )×£ spentevaluationcase

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.



LV Re-Energising DevicesAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.

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 basisBenefits

• This model uses Ofgem’s societal benefit £/interruption rates.o CI (£s per interruption) £15.44o 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, includingo Number of affected customerso Identification of those incidents with a beneficial expected outcome 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 2018. Renewal and ongoing Bidoyng Fault Centre costs start again in the regulatory year 2018/19.




assumptions have been relied upon.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 Bidoyngii) 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.


i) Bidoyngs: https://www.ofgem.gov.uk/sites/default/files/docs/2010/12/enwt1001_0.xls

https://www.camlingroup.com/product/bidoyng

ii) ALVIN Reclose: https://www.eatechnology.com/products/low-voltage-alvin-range/alvin-reclose/

How is the solution being used? 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 2017/18, 1,284 LV Re-energising Devices were deployed and are operating on UK Power Networks’ distribution network, 117 of which are ALVIN Reclose devices and the


https://www.eatechnology.com/products/low-voltage-alvin-range/alvin-reclose/

https://www.camlingroup.com/product/bidoyng

https://www.ofgem.gov.uk/sites/default/files/docs/2010/12/enwt1001_0.xls

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 customer minute lost”.

Cost Categories

In 2017/18, 120 ALVIN Recloser units have been purchased. The volume unit for the purchase of ALVIN reclose devices is “Price for 1 ALVIN Reclose”.








Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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 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.



MAAVAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.In 2018 Princeton University completed a study of contact voltage losses for each of UK Power Networks License areas. The study, which is included in the UKPN Tranche 2 LDR Submission to OFGEM, provides significant details on the calculations of losses, avoided customer interruptions and customer minutes lost and emissions. The full report is available at: https://www.ukpowernetworks.co.uk/losses/static/pdfs/analysis-of-contact-voltage-losses.f7e1d56.pdf

The Princeton Report concludes that the largest category of addressable losses on our networks are the result of contact voltage losses. In fact, 75% of the total addressable losses are contact voltage related, 7.5 times greater than all of the other actions that have been traditionally considered. To put the losses benefit into perspective, repairing one lighting column fault has the same impact on losses as replacing 88 - 25 KVA transformers.


Table 8 of the Princeton report estimates the losses for each of the UKPN License areas as follows.

DNO

License Area

Average

watts per CV

LV cable miles

Potential Annual CV detections

Avoidable losses, MWh/yr

UKPN

Eastern Power Networks

1,110 42,064 3,875 37,460

London Power Networks

1,961 23,912 2,203 37,684

South Eastern Power Networks

1,868 28,304 2,607 42, 500

Total Estimated Contact Voltage Losses (assuming 4% loss from generator to DNO receipt) 122,537

It will require approximately 9 MAAV systems to identify all of the losses forecasted by Princeton on an annual basis. It is estimated that one MAAV would identify approximately 115 cable and 140 lighting column faults which are responsible for a total of 14,090 MWh of losses each year. This estimate assumes that the MAAV is being operated in territory, which has not been surveyed in the prior year.

The MAAV was trailed by surveying the Central London area. In the trial, the MAAV identified large numbers of contact voltage defects. As well as representing a hazard to the public, according to the methodology developed by Princeton University, these contact voltage defects are responsible for significant network losses. Some classes of contact voltages, if left unaddressed, will also eventually turn into faults on our LV network, causing fuse operation and CIs and CMLs. By mitigating these contact voltage defects we will address both the health and safety risk and reduce CIs and CMLs for our customers.

During the trial period we focused on resolving the most immediately hazardous contact voltages, which were almost all caused by faulty lighting columns. This means there are significant losses benefits still to be claimed, but we will only claim these after the defects on the network have been repaired. This process requires excavation and replacement of cable which was not undertaken during the trial period, but will be undertaken as subsequent BAU work. For the duration of the trial period the losses associated with lighting columns were estimated at 884.1 MWh. The assumption made is that these have been repaired because the fuses were pulled at the time of discovery by the LFEs and they are not showing up as repeat detections on subsequent surveys.

CI/CML Analysis

Using the groupings in the table above, it is projected that MAAV could identify approximately 115 faults annually, which would impact customers. The nature of the faults that have been remediated so far shows that they are of the type that impact customer reliability and lead to fuse operations overtime.

For the Customer Interruption data, the following assumptions were used:

Average of 10 customers per faultAverage of 3 fuse operations before repairAverage duration of 60 minutes per fuse operation

Customer Interruptions: 115 Faults × 10 Customers per fault × 3 Fuse Operations Before


Permanent Fault RepairCustomer Minutes Lost:115 Faults × 10 Customers per fault × 3 Fuse Operations Before Permanent Fault Repair × 60 Minutes per Fuse Operation





A Mobile Asset Assessment Vehicle (MAAV) can be used to detect contact voltages in the carriageways which could potentially lead towards avoiding an LV fault.

How does it work?

MAAV surveys the carriageways of London in search of contact voltage faults on the low voltage network of UK Power Networks. When a fault is detected the technicians will exit the vehicle and use handheld test equipment to pinpoint the location of the fault as well as an acceptable ground reference location. The data will be recorded using a laptop computer installed in the truck and stored in the Amazon EC2 storage environment.


The MAAV delivers benefits in three main areas:

Avoided Losses – As described previously, many of the events identified by the MAAV represent significant losses on the LV system. By proactively identifying and repairing losses can be significantly reduced on the system. There are also significant avoided emissions associated with the reduced losses.

Avoided Customer Interruptions - The contact voltage detected could potentially lead towards an LV failure hence causing customer interruptions (CI) and customer minute loss (CML). The detected contact voltage is treated to avoid LV failure hence save on CIs and CMLs.

Improved Safety – Some of the structures which are identified represent safety concerns to the public or employees. The underlying faults may be the responsibility of customers, local councils or UKPN; regardless of who is responsible for the underlying fault, proactive identification significantly reduces the safety risk.




Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.From a losses perspective there are five main types of faults, two of which are responsible for unmetered losses on the LV system LV Cable Phase Faults and “Lighting Column Phase Faults”. For each of those types of faults an estimated loss value will be assigned based on the calculation and method developed by Princeton University.

LV Cable Phase Fault – These are faults which are located on UKPN LV cables in the street. Losses from these faults are always unmetered losses. The losses from these faults are significant and can be modelled mathematically using formulas developed by H.B Dwight for the analysis of driven earthing rods. Field observations have shown that the faults tend to energize the sheath of the cable or nearby, low impedance underground objects. The loss can be modelled using the following equation:

Where: R = Resistance (Ω) ρ = (Rho) Earth Resistivity (Varies with soil type) (Ω*CM)-9 L = 2X Length of horizontal wire (in cm) a= Radius of conductor (in cm) S = 2X depth of conductor (in cm)

The average ρ value at the locations where voltage was found was 3,850 (Ω*CM)-9 . Using the formula and the following assumptions:

ρ = 4,860 Ω*CM)-9 Average Soil Resistivity L = 2 Meters of Energised Sheath a= 1 cm Sheath Radius (OD/2 of cable) S = 25 cm depth of conductor

The average earth impedance is 8.61 Ω with instantaneous load 6,144 watts. This is consistent with observations in the field. These faults represent an annual loss of 53.8 MWh/yr

• Lighting Column Phase Fault – These faults are similar to LV Cable Phase faults. When the line conductor is inadvertently faulted to the earth, current flows into the earth, resulting in an unmetered loss. The analysis performed by H.B. Dwight also provides a formula to model the impedance of the lighting column to earth.

Where: R = Resistance (Ω) ρ = (Rho) Earth Resistivity (Varies with soil type) (Ω*CM)-9 L = 2X Length of horizontal wire (in cm)


a = Radius of conductor (in cm)

The impedances of 15 different types of lighting columns were calculated by Princeton using the formula outline above using the various diameters and depths of the columns and the results were averaged.

The average earth impedance is 10.93 Ω with an instantaneous load of 4,839 watts. These faults represent an annual loss of 42.4 MWh/yr.


For a detailed analysis of the losses refer to the full text of the Princeton University Report: https://www.ukpowernetworks.co.uk/losses/static/pdfs/analysis-of-contact-voltage-losses.f7e1d56.pdf


Perfluorocarbon Tracer (PFT)

Allocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.Hourly Costs for labour across the networks are taken from the 2017 Activity Rates Model provided by Finance:

EPN LPN SPNStaff £44.69 £58.55 £48.30Engineer £55.97 £57.08 £64.10

Labour lengths were provided by EHV Cables Project Manager and are referenced in RE PFT benefits estimation email. Material and job costs are obtained from the CU Catalogue_Excavations spreadsheet extracted from CU Catalogue.

Evaluation Method: PFT 2 staff for 3 days per leak 45 hours1 engineer for 1 day per leak 7.5 hoursPFT material cost per leak £100.00 Base Method: Cable Freeze (assuming 4 freezes per location)

4 2mx2m excavations at estimated cost of £10,306.38 each£41,225.5

24 staff for 8 days per leak 240 hours1 engineer for 8 days per leak 60 hoursNitrogen material cost ~£500 per excavation £2,000.00

The Cable Freeze method had been chosen as a general method for the leak location and was used for the base case cost calculation. Although, other leak location methods exist, Cable Freeze is used the most.

It was assumed that: fixed amount of PFT is used for every leak,


https://www.ukpowernetworks.co.uk/losses/static/pdfs/analysis-of-contact-voltage-losses.f7e1d56.pdf

https://www.ukpowernetworks.co.uk/losses/static/pdfs/analysis-of-contact-voltage-losses.f7e1d56.pdf

on average, there are four cable freezes and excavations required to locate a leak.




assumptions have been relied upon.Solution & Benefits Explanation:Fluid filled cable leaks have been traditionally 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 via 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 where possible.Counterfactual Case: Cable Freezing with N2 is used to locate the leak.



Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.The benefits of using PFT are in costs.

Evaluation Cost:


Evaluation cost is based on several parameters:

Hourly labour costs

Hourly Cost

Engineer Staff

EPN £55.97 £44.69

LPN £57.08 £58.55

SPN £64.10 £48.30

Labour length and material costs

Resource Value2 staff for 3 days per leak 45 hours1 engineer for 1 day per leak 7.5 hoursPFT material cost per leak £100.00

Number of leaks located with PFT

DNO

Number of leaks (2018)

EPN 12LPN 1SPN 13

Leak location with PFT cost is calculated by this formula:

EvaluationCost= (MaterialCost +LabourCost )∗Number of LeaksTherefore, the evaluation cost is as follows:

DNO Evaluation Method Cost

EPN £30,369.90LPN £3,162.85SPN £35,805.25UKP

N £69,338.00

Counterfactual (baseline) cost:Likewise to the evaluation cost, counterfactual cost consists of several parameters:

Same hourly labour costs

Hourly Cost

Engineer Staff

EPN £55.97 £44.69

LPN £57.08 £58.55

SPN £64.10 £48.30

Labour length and material costs

Resource Value4 2mx2m excavations £41,225.52


4 staff for 8 days per leak 240 hours1 engineer for 8 days per leak 60 hoursNitrogen material cost £2,000.00

And the number of leaks located with PFT

DNO

Number of leaks (2018)

EPN 12LPN 1SPN 13

Counterfactual cost can be calculated from following formula:

BaseCost= (MaterialCost +LabourCost+ExcavationCost )∗Number of LeaksThe Counterfactual (base) cost is as follows:

DNO Base Method Cost

EPN £687,711.84LPN £60,702.32SPN £762,625.76UKP

N £1,511,039.92



Public Safety

Allocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.Case-by case cost information was provided, as was the list of events attended.

The wage cost of the team which organises and attends these events is £174,000. Assume that this is spread evenly across EPN, LPN, SPN.

As such, the total annual cost for public safety is £200,462

The total population reached in the public safety events comes to over 45,000 in the 2017/18 regulatory year.






The solution is targeted safety efforts in our areas to prevent injuries to members of the public by the most frequent types of hazards to affect them. For example, for agricultural areas we focus on overhead line safety and in urban areas with buried cables we focus on excavation risk.

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:

• Attending a trade fair• Any other specific safety event• Working with agricultural colleges.

Disposal Units: will not be reported, as this solution is an action



Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are 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 predict that this will lead to a reduction of 15 injuries to members of the public over the duration of ED1. This averages the average ED1 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 £7400.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+ 5.67x7400) – (8x190,555.40) = £87,514.80



Dynamic Transformer Rating

Allocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.The following section details the high level assumptions made in the calculations for this solution.

• In the first phase of the project the solution has been implemented at 2 substations, 1 each on UK Power Networks London (LPN) and Southern (SPN) networks. In the second phase seven additional substations are currently being equipped with Transformer Management Systems.

• 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 (LPN) has been maintained due to other site constraints. The transformers at Weybridge (SPN) 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.

• For post-current submission it was assumed that in future UKPN will invest in the two most critical sites per network every year (i.e. 4 TXs/year for each of LPN, EPN & SPN to have the new DTR solution) in addition to the current replacement schemes on the Annual Baseline Plan (ABP).

• The average investment cost for substations with Transformer replacement is £1.2m/TX (based on previous substation figures).

• The solution will allow deferral of transformer replacement by 3 years.

• The solution will on average increase each transformers’ MVA capacity by 10%.







Dynamic Transformer Rating (DTR) allows additional capacity to be made available from existing assets and defer reinforcement by three years or more. It is estimated that transformers can be loaded up to 10-20% above static seasonal rating.

Changes in environmental conditions have a significant effect on transformer loading and in urban areas, due to increasing air conditioning installations, existing summer or winter firm ratings may not be fully representative of the actual real time environmental conditions at particular sites.

Benefits from DTR are achieved by retrofitting Transformer Management System (TMS) onto existing assets. TMS enables real-time monitoring of the transformer's health, and continuously calculates 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 transformer 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 and visibility of 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_Plan_Documents_and_Annexes/UKPN_Smart_Grid_Strategy.pdf


TMS has been implemented at two substations (on a total of six transformers) to defer reinforcement schemes.

In the second phase of the project, monitoring equipment has been installed at seven primary substations with 16 transformers in total and UK Power Networks will monitor all connected primary transformers on those substations.

The thermal modelling tool developed through the project will include a complex software platform integrated with PowerOn (UKPN SCADA). This can collate and capture all the data received from the sites and enable different business users to embed it in their Business as Usual (BaU) processes for:: Future long term planning purposes for Infrastructure Planning/Asset Strategy to plan

for future replacement of assets. Real Time Control for control engineers to use in emergency or <24hours ratings

calculations purposes.


This solution delivers the following benefits: the deferral of reinforcement projects increased transformer utilisation due to real time monitoring.

While the solution is still under trial, the deployment costs reported here are linked to those in CV38 as eligible NIA project costs. The benefits reported are those of the expected




http://www.smarternetworks.org/NIA_PEA_PDF/NIA_UKPN0001_4644.pdf

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 are being conducted to confirm the overall site rating. This will update the Totex profile (based on current Investment pan).

The software platform will enable infrastructure planners to defer reinforcement of transformer schemes by up to 3 years and also allow Control Engineers to use it for real time loading purposes which could potentially reduce the amount of customers disconnected in emergency cases. The confidence of the predicted top oil temperatures used to calculate the ratings will increase as more data is collected and compared with actual received data.


Additions units: TMS commissioned at 1 transformer

Disposal units: TMS decommissioned from 1 transformer

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”


Impacts have been calculated as load-related investment reduction or deferral and in capacity released. See the “Calculation of Benefits” section below.






Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.Benefit: MVA Released

The benefit is calculated as the amount of MVA released using the summation of MVA released for each transformer with DTR installed.

Benefit: Gross Avoided Costs

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

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.



Timed Connections

Allocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.It is assumed that if customers had preferred to pay for a full (i.e. 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







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


For load, generation connections, the customer can be offered up to four time slots per 24hour period. The time slots indicate the periods where the customer is allowed to consume/generate with additional capacity. Customers wishing to charge electric vehicles over their connection require a large connection agreement. These are difficult and time-consuming to accommodate, and come at a high cost to the customer. Two bus garages in London have agreed to accept innovative time-restricted connections which allow them to have a higher connection agreement in the evening (23:00-07:00). This allowed their connections to be made faster and cheaper. This alternative connection solution can also be offered to generation and storage customers.


• Lower connection costs• Faster connection times• 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 explanation.


Benefit Categories

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

Addition Units

The volume unit is: “1 Timed Connection accepted”

Disposal Units

The volume unit for this is “1 timed connection decommissioned ”








Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.Benefit: MVA Released

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).

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.

Benefit: Gross Avoided Costs

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

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.



Woodpecker Hole Filler

Allocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.Work force cost per repair was estimated using LV inspection labour costs as it is comparable to the type of work carried out).

Assumption of average usage of kit per pole as well as estimated labor cost for deployment is based on UKPN’s trial as well as manufacturer’s recommendations on usage.

It is assumed that 80% of filler purchases are effectively utilised within the assets, this is estimated in order to take into account waste and stock.





assumptions have been relied upon.This solution repairs woodpecker damaged poles by using a filler. When used correctly it strengthens the damaged pole and avoids expensive substitutions while reducing chances of rot developing as a consequence of the holes.

This solution can only be applied in certain scenarios based on the number, extent and distance of holes.

More details on the product use is available in the bulletin and manual for use provided by the manufacturer.

The volume unit considered is the average amount of filler used per pole.

The only impact considered is avoided costs of asset substitution.



Calculation of benefitsExplain how the benefits have been calculated, including all assumptions used and details of the counterfactual scenario against which the benefits are calculated.Benefits are calculated by estimating the number of poles where the solution was used, against the gross avoided cost. The cost of using the filler method is compared against the cost of substituting a pole to calculate the gross avoided cost.

Gross avoided costs:

¿ (Unit CostWood Pole+Labour Costs¿−(Cost of fixingone polewith filler(Material+Labour)))×number of treated poles

The amount of filler used on average per pole is calculated through a case study carried out during trial. This number is then used to estimate the number of poles treated. It is assumed only 80% of purchased fillers is effectively used. This assumption helps to weigh in waste caused by spillage or misuse.




E7 – LCTsAllocation and estimation methodologies: detail any estimations, allocations or apportionments to calculate the numbers submitted.

Heat Pump Data

Where the MPAN is omitted, records have been allocated to a DNO in accordance with the postcode. Where 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. There were only 1.0% of records for which neither the MPAN nor postcode was specified.

Where system capacity is omitted for a record, it has been estimated by the average size of known heat pumps connected to the given DNO. Where DNO is unknown, the capacity is estimated by the average size of all known heat pumps connected to our networks.

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 system size (32A).

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.

For the EV Homecharge Scheme, as the capacity of each charge point was not provided, it was necessary to infer the capacity from the information provided. The primary basis for inferring the capacity was the charge point model. In some cases the model could not be determined with certainty.

Where model information is available but does not enable unambiguous mapping to a particular model, the model has been estimated according to the available information.

Where no model information is available but manufacturer information is available, the model has been assumed to be the most common model for the given manufacturer.

Where no model or manufacturer information is available, the model has been assumed to be the most common model under the schemes (the Rolec EVWP2026).

Where possible, the capacity of each approved charge point model was obtained from the manufacturer. Where the model capacity could not be obtained from the manufacturer or inferred from the model name, it was assumed to be 7kW as this is by far the capacity most commonly occurring in the data provided.

For the Workplace Charging Scheme, where the capacity of a charge point was not provided, it was estimated to be the average of known capacities in the data provided.

For both the EV Home Charge and Workplace Charging Schemes, no estimation of installation date or DNO was necessary.


Zap-Map Public Charge Point Data

As the capacity information for public charge points was limited to the range of slow (3kW), fast (7-22kW) and rapid (≥43kW) charge points, the aggregate capacity connected to each DNO was estimated using the following assumptions:

1. All slow chargers were assumed to be 3.68kW and ≤16A.2. On the basis of data from the Workplace Charging Scheme, all fast charge points

were assumed to be 10kW and >16A. 3. All rapid chargers were assumed to be 43kW and >16A. This represents the

minimum capacity of a rapid charge point as defined by Zap-Map.

As the Zap-Map public charge point information provided only the total change points connected by DNO as at March 2018, the split across the three years of ED1 to date was assumed to be in line with that observed in the EV Home Charge Scheme. This split was performed separately for the count and capacity data, as the split may be different for different quantities.

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 information indicating whether a site is connected to the primary or secondary network it has been assumed that sites less 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.

(i)

The below processes are performed for each DNO.

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 record to the corresponding DNO.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. Obtain EV Home Charge and Workplace Charging Scheme databases from the Office of Low Emission Vehicles as per the established data sharing agreement.


2. For the EV Home Charge Scheme, use the best available information to map each record to a charge point model eligible for the given scheme.

3. Use the UK Power Networks Model Capacity Database to determine the capacity and current of each charge point.

4. For the Workplace Charging Scheme, where the charge point capacity is not provided, estimate it by the average of known capacities in the data provided.

5. Categorise each charge point model as Slow Charge (≤16A) or Fast Charge (>16A).

6. Determine the regulatory year of installation from the installation date.7. Determine the DNO from the postcode.8. Calculate the required summary of number and aggregate capacity of slow and

fast charge points by DNO and regulatory year.9. Obtain number of slow, rapid and fast public charge points by DNO from Zap-Map.10. Estimate the aggregate capacity by DNO based on conservative assumptions and

average capacity data from Workplace Charging Scheme.11. Estimate the number and capacity of slow and fast public charge points connected

in each DNO by regulatory year on the basis the annual connections observed in the EV Home Charge Scheme data.

12. Sum the summaries of the three input datasets to obtain the total number and capacity of slow and fast charge points connected in each DNO by regulatory year.

Distributed Generation

1. Obtain from Ofgem the FiT Database with MPAN in accordance with the data sharing agreement finalised in 2016 and the Renewables Obligation Accredited Stations Public Report.

2. For the FiT database, map each record to the appropriate DNO on the basis of the MPAN.

3. For the Renewables Obligation database, map each record to the appropriate DNO on the basis of the postcode provided or other available information, such as the site description.

4. For each dataset, append any records identified from UK Power Networks’ Connections data that do not appear to be included in the FiT and ROC databases.

5. Map the appended records to the appropriate DNO on the basis of the postcode or other available information.

6. For each dataset, determine the regulatory year from the commissioning date or installation date. Where such a date is unavailable, estimate it on the basis of the best available data.

7. Determine whether each site was connected under G83, and whether to the primary or secondary network in accordance with the assumptions outlined under Extent of manual intervention below.

8. Populate E7 as required.

(ii)

All assumptions are outlined, together with the estimation methodologies, under Allocations and estimation methodologies, above.

LCT - UptakePlease 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 over 33,000 PV units to connect to the secondary network in 2017/18 whereas 2805 units actually connected. We highlighted in previous years that the changes in both the Feed-in Tariff and Renewables Obligation schemes would result in lower volumes. We have seen a significant reduction since 2015/16 reflecting those


changes. This is particularly true in the small scale generation market where volumes have decreased by 91% since 2015/16. We expect no significant increase in volumes in the next regulatory year, as any successor to the Levy Control Framework has yet to be determined.

In our original business plan we expected over 31,000 heat pumps to connect in 2017/18 whereas 1013 actually connected. As we highlighted in previous years, the BPDT assumption was that in 2016 the Zero Carbon Homes policy would have been implemented which would have kick started the heap 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. Whilst the GLA and some local authorities are working on policies to encourage uptake of low carbon heating technologies, we do not expect to see significant growth above historic levels in the number of heat pumps connecting to our networks in the next regulatory year.

In the BPDT we predicted over 14,000 charge points connecting in 2017/18 whereas our records show that 6615 actually connected. However, the volume of electric vehicles registered in 2017/18 is thought to be approximately 15,000, an increase of approximately 60% on the 2015/16 value of 9500. 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 electric vehicle charge points to increase in the next regulatory year.
