Business plans - UK Power Networks

Business plans
for our three electricity networks
Draft for consultation – business plan for 2015 to 2023
November 2012
ukpowernetworks.co.uk

Thank you for taking the time to read our draft business plan for 2015
to 2023.
We are due to submit our final business plan for approval to our regulator
Ofgem in July 2013. This document sets out in detail our planning process,
the outputs we propose to deliver for our customers, and our current
estimates of our costs and revenues. Our draft plan is dedicated to achieving
our target of top third performance compared to the other electricity
distribution networks in Great Britain.
We also describe the step change in performance that we have delivered for
our customers since we became UK Power Networks in October 2010. I am
delighted that we have reduced customer minutes lost by 41.5 per cent over
the last two years, whilst at the same time reducing our overhead costs by
19 per cent and customer complaints by 81 per cent.
The next ten years or so will be a time of challenge and change for our
networks, as we try and balance the different priorities of affordable
tariffs, investment in the health and capacity of the network and supporting
the UK’s low carbon transition, whilst keeping the public and our employees
safe. We must also innovate to utilise our network more efficiently, and
prepare for a possible transition to a smart grid without creating
stranded costs.
Your feedback on our plan is important to us and I encourage you to
comment on any aspect of our plans or forecasts. Our consultation period
closes on 1 February. After that we will publish a final draft plan reflecting
all the feedback we receive, and this will form the basis of the business plan
we then submit to Ofgem next summer.
With your help, our business plan for 2015 to 2023 will balance appropriately
the needs of all our stakeholders.”
Thank you
Basil Scarsella
Chief Executive

Contents
1.0 What does UK Power Networks do 4
2.0 How to respond to this consultation 6
3.0 Executive summary 10
4.0 UK Power Networks and our step
change in performance
4.1 Where we operate 17
4.2 Our ownership structure 18
4.3 Our vision and values 18
4.4 Our legal and regulatory framework 20
4.5 Improving network performance 21
4.6 Improving customer satisfaction 27
4.7 Improving our connections work 31
4.8 Improving safety 34
4.9 Delivering long-term value
for customers
4.10 Innovating to excel as a business 40
4.11 Smart innovation to meet demand 45
5.0 Process: how we are planning
for the future
37
52
5.1 Our stakeholder engagement activities 54
5.2 Developing the plans for expanding
our network (load related forecast)
5.3 Developing our asset replacement
(non-load related) expenditure forecast
57
63
5.4 Developing our operating
cost expenditure forecast
68
5.5 Regional cost effects 68
5.6 Changes for 2013 74
6.0 Outputs: our commitments
to customers
79
6.1 Performance outputs 79
7.0 Expenditure: what we will spend to
deliver to 2023
7.1 Our plans build on current
improvements
84
86
7.2 Expenditure: plans for our networks 86
8.0 Financing: what this means
for bills
100
8.1 Developing the revenue requirement 101
8.2 The impact on our customers 102
9.0 Managing risk and uncertainty 104
9.1 Key areas of uncertainty in the future 105
9.2 Allowing flexibility 106
10.0 Glossary 108
This document is published in conjunction with three summary plan documents for each of our three licensed
electricity distribution networks. This detailed document contains extra information in Section 4 on our step change
in performance, Section 5 on our planning process and stakeholder engagement, and Section 9 on managing risk and
uncertainty which has been omitted from the summary documents.

1
What
does
UK Power Networks do
UK Power Networks owns, operates and manages three of the
fourteen regional electricity distribution networks in the UK. Our
licensed distribution networks are in the East of England (EPN),
London (LPN) and the South East (SPN). UK Power Networks is
one of the largest Distribution Network Operators (DNOs) in the
UK, covering an area of approximately 30,000km 2 , extending
from the Wash in the east, through London, to Littlehampton on
the Sussex coast. Approximately eight million connected
customers depend on us for their power.
Our job is to deliver electricity to our customers safely, to ‘keep
the lights on’ and to connect new customers. We are responsible
for maintaining and modernising our networks and ensuring that
there is adequate capacity to support the needs of our customers.
We are not the National Grid (the Great Britain-wide ‘motorway
system’ for electricity). Also we are not an electricity retailer; we
don’t bill end customers and we don’t own the electricity flowing
through our networks. Instead we deliver electricity on behalf of
the ‘big six’ and other energy retailers in our service area.
Electricity distribution costs represent approximately 18 per cent 1
of the average domestic electricity bill.
We are a monopoly and our distribution tariffs are regulated by
Office of Gas and Electricity Markets (Ofgem). Ofgem has already
set our prices for 2010 to 2015. Now we are consulting on the
business plan that we will submit to Ofgem to form the basis of
our prices for 2015 to 2023.
1
Ofgem Fact sheet 97, 31 May 2012
>pg4 | Business plan

What we do
We take electricity at high voltages from
the National Grid and transform it down
to voltages suitable for commercial and
domestic use.
Where we operate
Power Station
Generates at
25,000 volts
National Grid
Electricity leaves
here at 400,000/
275,000 volts
Grid Supply Points
Electricity leaves
here at 132,000
volts
Primary Substation
Electricity leaves
here at 11,000 volts
Grid Substation
Electricity leaves here
at 33,000 volts and is
used by heavy industry
Regional Distribution
Network Electricity
is transported at
132,000 volts
Electricity Cables
Electricity is
transported at
11,000 volts
Secondary Substation
Electricity leaves here
at 230 volts
Your Property
Electricity enters your
home or business at
230 volts
Peterborough
Norwich
Cambridge
Stevenage
EPN
Bury St Edmunds
Colchester
Ipswich
MANAGED BY UK POWER NETWORKS
LPN
London
Crawley
SPN
Maidstone
Tunbridge Wells
East Grinstead
Worthing
Eastbourne
London business plan | >pg5
Business plan | >pg5

2 How to respond to this consultation
Thank you for taking the time to read this consultation paper. Your views are
important to us and you can have your say on the issues we have raised by
logging on to our consultation website.
http://www.ukpowernetworks.co.uk/internet/en/have-your-say/business-plan/
The consultation pages will take you through each section of the document and
give you an opportunity to respond to a number of focused questions,
as reiterated in this section below:
>pg6 | Business plan

Summary of all consultation questions
Reliability and security of electricity supply
Q1. Are you satisfied with the reliability of your electricity supply If not, please let us know
why not, and what specifically you would like to see us do better
Q2. We propose to hold our reliability performance approximately constant in future years.
Do you agree with this or do you think that we should spend more to reduce either the
number or the duration of power cuts, even if this would mean higher charges
Q3. Do you support our plan for Central London, including new strategic capacity,
increased resilience, and improved customer service, and do you think it has
the correct priorities Who do you think should pay for the investment required
(e.g. between existing and connection customers, or between different geographies
or categories of existing customers)
Q4. Do you think we should broaden our measures of quality of service to include additional
customers In particular, should we measure customers that experience a power cut of less
than three minutes
Conditions for electricity connections
Q5. What do you think is important to customers when they request a new electricity
connection, and what should we focus on improving For example, the cost, the time to
connect, the quality of our customer service
Q6. Do you think we should proactively provide more electrical infrastructure, before the
capacity is required, so that electricity connections can be made more quickly or easily In
particular, is London a special case and, if so, why
Q7. Do you think we should invest more in the electricity network to make it quicker or easier
for renewable or distributed generators to connect
Q8. Should any investment to make connections quicker and easier be subsidised by all
customers in the region, or purely paid for by those wishing to make new connections
Business plan | >pg7

Incentives and innovation
Q9. Do you think our approach to innovation and change is sufficient Do you think we should
be researching additional areas in relation to change and innovation, and if so what
Q10. How much of a priority should each of the following areas be for us in 2015 to 2023
• Facilitating renewable generation
• Facilitating new demand sources such as electric vehicles, heat pumps, etc.
• Empowering customers with information
• Managing customer demand to avoid the need for network reinforcement
• Improving electricity network service and reliability
• Increasing network control and automation in preparation for a ‘smart grid’
Customer satisfaction and social obligations
Q11. What do you think we should do to improve customer service and to measure the
satisfaction of our customers
Q12. How can we make it easier for our customers to communicate with us, either in a power
cut situation, for a new connection, or for a general enquiry
Q13. Do you think there are additional services we should be providing to vulnerable or fuel
poor customers
Safety
Q14. Would you value more engagement or information around safety and electricity
Q15. We believe we have improved signage and security around our excavations on the public
highway. How should we improve the safety of employees and the general public
Q16. What should we be doing more of in the future For example:
• Greater prevention of metal theft and vandalism
• Additional safety education programmes
Environment
Q17. What are the current initiatives and issues that concern you surrounding our impact on
the environment
Q18. What should we be doing more of in the future For example:
• Extending our programme of undergrounding overhead electricity lines beyond Areas
of Outstanding Natural Beauty to other sensitive areas
• Installing equipment with lower lifetime carbon impact
>pg8 | Business plan

• Increasing our programme to actively remove oil filled equipment
• Change our monitoring of SF6 (a greenhouse gas commonly used in
electrical transformers)
• More challenging targets for our carbon footprint
Expenditure
Q19. Do you think our proposed level of expenditure is appropriate to meet the output targets in
our business plan If not, please be specific as to your views on what should change
Financing
Q20. What do you think about our assumptions regarding the financing of our activities and our
proposed revenues and prices
General
Q21. Is this consultation helpful What could we have done better
Q22. Do you have any general comments you would like to make about our forecast business
plans for our electricity networks
Q23. Please let us know if you have any other thoughts or comments on the points raised in this
document, or if you would like to highlight any other issues you consider important
Alternative ways of responding
If you do not have access to the internet you can reply to this consultation by post.
Please send your comments to:
Nawaz Ahmed
Head of Stakeholder Engagement
UK Power Networks
Newington House
237 Southwark Bridge Road
London, SE1 6NP
We look forward to hearing from you. All the responses we receive
will be fed into our findings to help shape our business plans in a
sustainable direction for RIIO-ED1. At the end of the consultation all
submissions will be posted on our website.
Consultation period ends 1 February 2013
Business plan | >pg9

3 Executive summary
Our business
Since October 2010 we have been owned by the Cheung Kong
Group, and the Li Ka Shing Foundation, long-term investors
in utility businesses around the world. We own three of the
14 electricity distribution networks in Great Britain. We are a
monopoly 2 business and the tariffs we charge are regulated by
the Office of Gas and Electricity Markets (Ofgem).
As a result we periodically go through a process to justify our
forecast expenditure to Ofgem. We are approaching the next
review, which starts next year and will define our tariffs for the
period from 2015 to 2023.
Consulting on our business plan for 2015 to 2023
This document outlines our forecast business plan for that period.
It describes the drivers for our investment and the total amount
we will need to spend to deliver the outputs our customers
value. We are publishing this consultation document in order to
gather our stakeholders’ input on our thinking so far. Doing this
now enables us to integrate these views into our plans in time
for the formal submission of our forecast business plan to Ofgem
in July 2013.
This is the first time the electricity distribution business will be
subject to Ofgem’s new framework for agreeing our business
plans, called ‘RIIO’ - Revenue = Incentives + Innovation + Outputs.
This approach was adopted in 2009 and provides a toolkit with
which to address future uncertainty and the transition to the low
carbon economy.
We welcome the views of our stakeholders and have outlined in
each chapter a series of questions that can help guide responses
to this document.
Our step change in performance
Our vision is to deliver top third performance amongst the
14 distribution networks in Great Britain in the key areas of
safety, network reliability, customer service, cost efficiency and
employee engagement. We want each of our three networks to
perform equivalent to or better than comparable networks.
We have delivered a step change towards that performance over
the last two years. We have made significant improvements in
quality of supply, with customer minutes lost (CML) down by
41.5 per cent. We have improved our customer service with
complaints down by 81 per cent.
At the same time we are improving our cost efficiency to
bring better value for money through sustainable cost savings
programmes that have driven down our overhead costs by
19 per cent and are improving our employee and public
safety performance.
Our plan lays the platform for a low carbon future
Electricity distribution companies have a role to play in facilitating
the UK’s transition to a lower carbon economy. We are expecting
growth in electric vehicles and domestic heat pumps 3 and that
connecting these technologies will lead to new demands on
our networks. We are planning now for these to appear on our
networks to ensure we are prepared and can ensure we build the
capacity to accommodate them. We are also expecting growth in
distributed generation from smaller scale generation from solar
panels on roofs to onshore wind farms. We are developing our
thinking on how to best to develop our networks (e.g. taking
into account smart technologies) and the ways we work so that
our networks continue to provide long-term value for money
for a range of plausible future scenarios. Our approach includes
proactively participating in small and large scale real-time trials
of innovative new approaches and technologies through our
projects Low Carbon London 4 and Flexible Plug and Play 5 , and
other innovation activities. We will also support energy suppliers
in their roll-out of smart meters and will seek opportunities to
adapt our business to use the data to better serve our customers.
Our plan is informed by the views of stakeholders
We have been developing this plan over the past two years
and have engaged widely with our stakeholders in a variety
of forums. Our objective is to ensure our stakeholders have
the opportunity to influence the way in which we plan for the
future. We have sought the views of stakeholders and ensured
these views have been included in the plans so far and we have
reflected that throughout this document. We are undertaking
specific stakeholder engagement for our forecast business plan
alongside our on-going engagement activities that continuously
inform our decision making.
2
We are a monopoly as it is economically efficient for there to be only
one network that provides electricity to homes and businesses in any
given area, rather than multiple independent networks
3
A technology that can take energy from the air or ground and makes it
useable to heat our homes
4
http://lowcarbonlondon.ukpowernetworks.co.uk/
5
http://www.ukpowernetworks.co.uk/internet/en/innovation/fpp
>pg10 | Business plan

Expanding our networks to reflect
customer needs
The need to extend and expand our networks is driven by
increases in electricity demand. We forecast electricity demand
based on a wide range of factors including the number of new
households and the rate of economic growth. We have worked
with our stakeholders to refine our planning scenarios and have
developed innovative models to enable us to take a longerterm
view. We are also considering how new uses and ways in
which people use electricity (such as electric vehicles or heat
pumps) may impact our networks. We have taken views for
the uptake on the more uncertain future demands from low
carbon technologies (electric vehicles and heat pumps), how
people may respond to tariffs that change with the time of day,
and how much renewable generation may seek to connect to
the networks. In formulating our views on the future electricity
demand we have taken our stakeholders’ views into account to
build up our view on a core electricity demand growth scenario
upon which to base our investment plans (see Figure 3.1 to
Figure 3.3).
Figure 3.1: EPN peak load evolution
Forecast growth of electricity demand
Mega watts
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
Totals
2011: 6966 MW
2015: 6996 MW
2023: 7524 MW
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
Domestic demand I&C demand EV's demand HP's demand
Our EPN forecast is based on the long-term trend in background
growth in domestic and industrial and commercial (I&C) demand,
together with a modest increase in new connections for heat
pumps (233,000) and electric vehicles (243,000) by 2030.
Figure 3.2: LPN peak load evolution
Forecast growth of electricity demand
Mega watts
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
Totals
2011: 5417 MW
2015: 5605 MW
2023: 6151 MW
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
Domestic demand I&C demand EV's demand HP's demand
Our LPN forecast is based on the higher long-term trend in
background growth in domestic and industrial and commercial
(I&C) demand for London, together with a small increase in
new connections for heat pumps (61,000) and electric vehicles
(130,000) by 2030.
Figure 3.3: SPN peak load evolution
Forecast growth of electricity demand
Mega watts
5,000
4,000
3,000
2,000
1,000
0
Totals
2011: 4090 MW
2015: 4168 MW
2023: 4303 MW
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
Domestic demand I&C demand EV's demand HP's demand
Our SPN forecast is based on the long-term trend in background
growth in domestic and industrial and commercial (I&C) demand,
together with an increase in new connections for heat pumps
(121,000) and electric vehicles (156,000) by 2030.
Business plan | >pg11

Regional challenges
Our three networks serve London, the South East and the East.
This is the most densely populated and expensive part of the
country. This fact has a direct impact on how we must operate
and the overall cost of our business. We face higher than average
salary costs as a result of the increased cost of living in our
region compared to other parts of the country. We also face
additional operational challenges from the urban environment.
Our consultations suggest that our urban customers are typically
more sensitive to power cuts and require us to do more of our
work out-of-hours or at weekends – fitting this in between highprofile
public events. As an extreme example, this year we had
to cease planned work in parts of London during the Olympic and
Paralympic Games. We also have to deal with congestion under
pavements and roads, meaning we have to avoid other pipes
and wires when we do work, which increases the complexity of
what we do. We also regularly have to put our equipment into
small spaces and often underground to minimise how much land
we use. This leads to higher costs to install and maintain
our equipment.
Our Central London Plan
We are also aware of our responsibility to ensure that London’s
electricity network is fit for purpose and comparable to other
world cities in terms of resilience, quality of supply, and the
ability to deliver new connections. In order to ensure this, our
business plan proposes £210 million of strategic investment in
a ‘Central London Plan’ including additional capacity through
six new main substations, increased resilience from more
automation at both HV and LV, and a trial of unit protection at
four Central London sites.
The outputs we will deliver
Our forecast business plan is based on a range of assumptions
including the commitments to our customers to what we will
deliver across a range of outputs. The outputs and the target
performance have been developed in conjunction with our
stakeholders and a summary of those assumed in making this
forecast business plan are presented in Figure 3.4. Our plan
delivers against Ofgem’s output categories and set ambitious
targets for RIIO-ED1.
Figure 3.4: Our plans delivers against Ofgem’s output categories and set ambitious targets for RIIO-ED1
Category
Our
forecast
for 12/13
Our
forecast
for 14/15
Our
focus in
RIIO-ED1
Reliability and
availability
Customer
satisfaction Connections
Social
responsibility Environment Safety
LPN • • • • • •
SPN • • • • • •
EPN • • • • • •
LPN • • • • • •
SPN • • • • • •
EPN • • • • • •
• Top third IIS
performance
• Maintain
network risk in
EPN and SPN as
measured by
HI/LI
• Reduce
network risk in
LPN for both
HI/LI
• Top third
BMoCS
performance
• Smart fault
handling
• Improve time
to connect
every year
• Targeted
anticipatory
investment
in Central
London and
for DG
• Value for
money focus
• Reflect wider
distribution
system
optimisation role
in our investment
decisions
• Target investment
on vulnerable
and worst served
customers
• Top third
performance
amongst
DNOs in BCF
league table
• Continue to aim
for Zero Harm
• Public safety
awareness
Managing risk and uncertainty
Our forecast business plan considers the risks of the future
being different to our forecasts. The management of risk and
uncertainty in this time of transition to a decarbonised energy
sector for our stakeholders is an important consideration in our
plans. We have a well-developed strategy for the management
of corporate risk and this is reflected in our business plan.
The primary considerations in developing our approach to risk
management for our forecast business plan are to:
• Recognised that we are best placed to manage risks to the
delivery of the business plan
• Reflect the overall risks with an appropriate regulated rate of
return on equity
• To only use uncertainty mechanisms proposed by Ofgem where
we can materially demonstrate that we have considered the
impact on customers as well as stakeholders
Figure 3.5 highlights the key areas of uncertainty that we
consider need to be appropriately managed into the future.
>pg12 | Business plan

Figure 3.5: Key areas of uncertainty
Category Area of uncertainty Our proposed uncertainty mechanism
Load
• Rate of take up of low carbon technologies (e.g. electric
vehicles, heat pumps) – time to connect
• A measure of the volume of work we have to
undertake on our low voltage network as a result
• Rate of load growth due to decarbonisation
of low carbon technologies connecting –
annual frequency
• Ability to predict and manage load growth
• Clustering – regional combination of low
carbon technology take up and load growth due
to decarbonisation
Non-load • New technologies on the network (new standard of higher • Re-opener in 2019
specification to be rolled-out as part of
non-load replacement)
Cost
• Increase in general official measure of inflation
• Indexation of annual revenues
Specific issues
• Costs of operating network business out-turns higher
than forecast
• Higher than inflation increase in cost of material
(e.g. copper, fuel)
• Increase in pension deficit caused by exogenous factors
• Government requirements to increase security standards
• Legislation of enable local authorities to increase charges
for lane rental for essential infrastructure repair works
• Increased expenditure to allow network systems to
recover from major national outage
• Increased costs of roll out of new innovations
in technology
• Ex ante allowance with cost saving/overrun shared
with customers
• Fixed ex ante allowance
• Allowed pass through of efficient costs
• Re-opener in 2019 to allow for efficiently incurred
cost increases
• Re-opener in 2019 to allow for efficiently incurred
cost increases
• Re-opener in 2019 to allow for efficiently incurred
cost increases
• Re-opener in 2019 to allow for efficiently incurred
cost increases
Our expenditure plans
Our plan is created to ensure the delivery of the commitments
we are making and to ensure we meet our statutory obligations
(placed upon us through legislation, regulations and our licence).
Taking all of the assumptions, risks and uncertainties into account
we have developed our view of expenditure for the period from
2015 to 2023.
Overall our future plans as presented in this document are
largely a continuation of today, with the addition of increasing
prominence of low carbon technologies on our network
(including wind generation), smart metering and the enabling
steps for the future smart grid. We are expecting a return
to more normal levels of reinforcement on our network as
economic growth returns.
Our final business plan in 2013 will reflect the impact of ‘smart’
alternatives to traditional network reinforcement, including
demand side reduction, more automation and controls and other
innovative solutions. These are not included in the current draft
plan, and should reduce costs further.
The following charts show what we consider to be an efficient
level of expenditure to deliver the outputs, meet our obligations
and responsibilities and allow us to finance our business.
Across our three networks we are forecasting to spend £7.4bn
in 2015 to 2023 before inflation. This is an increase of £0.8bn
on the equivalent forecast for the current 2010-2015 period.
The increase is primarily driven by increased work volumes
and by our strategic investments in Central London, EPN wind
infrastructure and smart meter readiness, offset by reductions in
unit costs and in overheads savings.
Total EPN forecast expenditure for the period
2015 to 2023 = £3.1 billion
Our plans for EPN include our current estimates of strategic
investments in network capacity to support lower cost connection
of renewable generation and for the smart meter roll-out.
Figure 3.6: EPN total forecast expenditure from 2015 to 2023
Forecast plan period 2015 to 2023 (RIIO-ED1) (£bn)
Total £3.1bn 6
0.8
0.1 0.1 Load related
0.6
Non load related
0.6
0.9
Network operating costs
Indirect costs
Non operational capex
RPEs
6
All prices are real 2012 prices for ease of comparison
Business plan | >pg13

l
Total LPN forecast expenditure for the period
2015 to 2023 = £2.3 billion
Our plans for LPN include our current estimates of strategic
investments in network capacity to support the growth in London
and for the smart meter roll-out.
Figure 3.7: LPN total forecast expenditure from 2015 to 2023
Forecast plan period 2015 to 2023 (RIIO-ED1) (£bn)
Total £2.3bn 5
0.5
0.3
0.1 0.1 Load related
0.6
0.7
Total SPN forecast expenditure for the period
2015 to 2023 = £2.1 billion
Our plans for SPN include our current estimates of strategic
investments in network capacity to support the smart
meter roll-out.
Figure 3.8: SPN total forecast expenditure from 2015 to 2023
Forecast plan period 2015 to 2023 (RIIO-ED1) (£bn) Total £2.1bn 5
0.5
Finances and customer bills
Non load related
Network operating costs
Indirect costs
Non operational capex
RPEs
0.1 Load related
0.1
0.4
Non load related
0.4
0.6
Network operating costs
Indirect costs
Non operational capex
RPEs
Our expenditure is paid for through the bills customers receive
from their electricity supplier. Our revenues amount to around
18 per cent of the average bill. Figures 3.9 and 3.10 present a
forecast of the average domestic and non-domestic bills may
change and how that compares today to other distribution
network companies (DNO). Currently our tariffs are amongst
the lowest in Great Britain. Overall we expect to maintain our
contribution to electricity bills at constant levels in real terms
from 2015 for LPN and SPN and from 2019 for EPN through to
2023. Excluding the impact of the charges we pay National Grid,
our revenues would fall on average for our three networks in real
terms over 2015-2023.
Figure 3.9: Forecast impact on a typical domestic bill 7
£ (2012 prices)
160
140
120
100
80
60
40
20
0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
EPN
SPN
DNO average forecast
Figure 3.10: Forecast impact on a typical non-domestic bill 7
£ (2012 prices)
450
400
350
300
250
200
150
100
50
0
This forecast business plan should see each of our networks
remain amongst the lowest cost electricity distribution
companies in Great Britain.
7
All prices are real 2012 prices for ease of comparison
LPN
DNO average
Highest cost DNO
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
EPN
SPN
DNO average forecast
LPN
DNO average
Highest cost DNO
>pg14 | Business plan

Business plan | >pg15

4 UK Power Networks and our step
change in performance
UK Power Networks was created in October 2010 from the sale of EDF Energy’s
three electricity networks in London, the South East and East of England. We are
owned by the Cheung Kong Group and the Li Ka Shing Foundation, long term
investors in utility infrastructure worldwide.
Our vision is to deliver top third performance in our industry in the key
areas of safety, network reliability, customer service, cost efficiency and
employee engagement.
We have delivered a step change in performance over the last two years.
Customer minutes lost are down 41.5 per cent, complaints are down 81 per cent
and our overhead costs are down 19 per cent.
This chapter explains where we operate, our corporate ownership, our vision, and
the industry framework. It also summarises the improvements we have made
and how we will continue to improve our performance with innovative thinking
for the rest of our current price control period to 2015.
>pg16 | Business plan

4.1 Where we operate
We work in some of the most densely populated areas of the
country and in some of the most rural. Our London network
delivers more energy per km 2 than any other network within
the UK. Our other networks extend from suburban London
into the largely rural counties and down to the south coast of
England as well as north into East Anglia.
Eastern Power Networks (EPN) supplies electricity over an area
of approximately 20,300 Km 2 incorporating all of the counties of
Norfolk, Suffolk and Hertfordshire, most of Cambridgeshire, Essex
and Bedfordshire, parts of Buckinghamshire and Oxfordshire, and
the northern suburbs of Greater London.
London Power Networks (LPN) supplies over two million
customers within an area of only 665 Km 2 . It is almost entirely
urban and serves the most densely populated region in the
country. Almost all of the network is underground, helping us to
give London the most reliable electricity distribution system in
the UK.
South Eastern Power Networks (SPN) supplies electricity over an
area of approximately 8,200 Km 2 , incorporating all of Kent, East
Sussex, West Sussex and much of Surrey. In addition large urban
conurbations not only exist in the areas bounding London, such
as Croydon, but also in each county in the area.
Figure 4.1
Kilometres of
underground
cable
Kilometres of
overhead lines
Number of
substations
Number of
transformers
Peak demand
(MW)
South East of
London East England Total
30,000 33,000 35,000 98,000
n/a 12,300 53,000 65,300
17,300 38,700 79,600 135,600
15,400 35,200 71,200 121,800
5,203 3,976 6,586 n/a
Business plan | >pg17

Figure 4.2
Our service area covers
• 28 per cent of UK electricity consumption
• 37 per cent of the UK by GDP
• London – a major world city
• Highly rural areas in the counties of Norfolk and Suffolk
We take on challenges faced by no other DNOs
• Load density – LPN is over 15 times that of the next
highest DNO
• Major point loads in the City, the West End and Canary Wharf
• Terrorism and security challenges
4.2 Our ownership structure
The owners of UK Power Networks are experienced in the
utility business and are long-term investors in infrastructure.
Figure 4.3
Cheung Kong Infrastructure
An investor in utility
infrastructure worldwide
The integrated electricity utility
for Hong Kong island and an
investor in energy utilities world
wide
A charitable organisation founded
by Li Ka Shing
40% 40% 20%
Eastern Power
Networks plc
our network
for the East
London Power
Networks plc
our network
for London
South Eastern Power
Networks plc
our network for
the South East
UK Networks Services
Holdings Ltd
our private networks
for airports, rail and
defence clients
UK Power Networks is owned by a consortium of three partners.
The consortium constitutes a robust, well-capitalised shareholder
group which has significant global experience in the ownership
and operation of utility and infrastructure businesses.
The strong, stable regulatory framework in the UK has been a
key factor in attracting investors of the stature of the UK Power
Networks ownership group. Such investors, with significant
experience in international utilities and infrastructure assets,
who look to invest for the longer term, will be key players in
delivering the necessary investment required to meet the UK’s
future energy and environmental challenges.
All three owners are committed to long-term ownership of UK
Power Networks and to supporting our vision and values.
4.3 Our vision and values
Our corporate vision is to achieve top-third performance
amongst our electricity distribution peers and establish UK Power
Networks as:
• An employer of choice
• A respected corporate citizen
• Sustainably cost efficient
>pg18 | Business plan

The following diagram shows what we mean by this:
Figure 4.4
• Safe employees and contractors
• Aligned objectives and targets
• Clear roles, accountabilities and
strong leadership
• Pride in working for UK Power
Networks
• Employees who feel recognised,
developed and rewarded
• A mutually constructive
relationship with the unions
• Committed to personal and career
development
• Embrace diversity and
inclusiveness
• Keep the public safe
• High levels of consumer
satisfaction
• A regulatory relationship
characterised by mutual respect
• Improved network service
with increased reliability and
rapid restoration
• A competitive connections service
• Recognised community
involvement
• Respect for our environment
• Meet the expectations of all our
stakeholders including Ofgem
• Outperformed Ofgem allowances
for capex and direct and
indirect opex
• An upper third ranking forecast
efficiency by April 2014
• Well managed asset development
• Effective governance and
performance management
• Sustainable levels of free
cash flow
• Continually improve processes
and systems
“Our values form the basis
of who we want to be”
Our vision is supported by our values. Our values set out what we
expect from ourselves and those who work with us. They form
the basis of the way we do business and how we will achieve
our vision. We have taken the time to learn from our past
performance and how we can best deliver our vision.
Figure 4.5
Integrity
We will do what we say we will do and
build trust and confidence by being honest
to ourselves, our colleagues, our partners
and our customer
Continuous improvement
We are committed to learning,
development, innovation and achievement
Diversity and inclusiveness
We recognise and encourage the value
which difference and constructive challenge
can bring
Respect
We treat our colleagues and our customers
the way in which we would want to be
treated
Responsibility
We always act in an ethical, safe and
socially/ environmentally aware manner
Unity
We are stronger together and this comes
from a shared vision, a common purpose,
supportive and collaborative working
Our
values
Our values are the DNA of our
business; they will help us to
deliver our Vision ‘To become
an organisation which is an
Employer of Choice, a
respected Corporate Citizen and
Sustainably Cost Efficient’
Business plan | >pg19

4.4 Our legal and regulatory framework
Our three networks operate within a legislative and regulatory
framework determined by primary legislation, including
the Electricity Act 1989, the Utilities Act 2000 and the
Health and Safety at Work Act 1974. Our networks operate
under electricity distribution licences overseen by Ofgem
which defines the broad range of licensed activities and
responsibilities, and set out the rules and standards to which
the network companies must adhere.
Our current plan for 2010 to 2015 was agreed with Ofgem
as part of the Distribution Price Control Review number five
(DPCR5). This laid out our plans from 2010 to 2015. DPCR5
was set under the RPI-X price control regime. The RPI-X regime
has at its heart a drive for continued efficiency improvement.
In addition to efficiency we are subject to a number of other
incentives including those on network reliability and customer
service. These supplement the guaranteed standards of
performance that we are required to deliver. During DPCR5
further focus has also been given to environmental issues
through the provision of schemes to support the deployment
of renewable and low carbon generation. These schemes
provided funding arrangements and incentives to encourage the
network companies to deliver what customers value, such as
undergrounding of our lines in areas of outstanding
natural beauty.
In 2009, Ofgem updated its RPI-X approach to network price
controls introducing the RIIO Revenue = Incentives + Innovation
+ Outputs framework. This provides a broader toolkit with which
the network companies and Ofgem can better address the future
challenges faced by the UK in its transition to an affordable,
secure and low carbon electricity industry. RIIO is the regulatory
framework that will apply going forward for setting the revenue
we can collect from our customers. It aims to provide benefits for
customers and ensure sustainability of our businesses.
The framework will apply to us for the first time in ‘RIIO-ED1’
through which we will agree with Ofgem our forecast business
plan for the period from 2015 to 2023. The process is well
underway and we will submit our final draft business plan to
Ofgem in July 2013.
Our plan aims to address the objectives of the RIIO framework:
• Long-term value for money for our customers
• Facilitate transition to a low carbon economy
• Outputs focussed – at the heart of our plan is the commitment
to the efficient delivery of specified outputs
• Stakeholder led – outputs, levels and expenditure and the
impact upon customer bills reflect the view expressed by our
stakeholders
• A strong incentive for efficient delivery – the plan is based on
industry leading levels of efficiency and continuing productivity
and service improvement
• Requirement for innovation – the plan includes a strategy
for innovation to address the key challenges in the forecast
business plan period and beyond
• Ensuring investment is financeable – the plan includes a fully
justified and financeable package that maintains investment
grade credit ratings
The outputs will form a ‘contract’ between us and our customers.
Ofgem arranges the outputs across six categories:
• Safety
• Reliability and availability
• Customer service
• Conditions for connections
• Environmental
• Social obligations
As part of this business plan we have set out the outputs we
plan to deliver. Throughout the development of our plan we will
consult with our stakeholders to ensure our target measures
meet their expectations.
>pg20 | Business plan

Consultation questions for this section
Reliability and security of supply
Q1. Are you satisfied with the reliability of your electricity supply If
not, please let us know why not, and what specifically you would
like to see us do better
Q2. We propose to hold our reliability performance approximately
constant in future years. Do you agree with this or do you think
that we should spend more to reduce either the number or the
duration of power cuts, even if this would mean higher charges
Q3. Do you support our plan for Central London, including new
strategic capacity, increased resilience, and improved customer
service, and do you think it has the correct priorities Who do
you think should pay for the investment required (e.g. between
existing and connection customers, or between different
geographies or categories of existing customers)
Q4. Do you think we should broaden our measures of quality of
service to include additional customers In particular, should we
measure customers that experience a power cut of less than
three minutes
Business plan | >pg21

Our first full year as an independent network company has
seen substantial progress. We have invested in the reliability
of our network and changed the way we work. This has led to
significant performance improvements, reducing the number
and duration of power interruptions experienced by
our customers.
How network reliability is measured
In the UK, power cuts are usually infrequent and short in
duration. Our primary role is to deliver reliable electricity supplies
to customers through the efficient operation and maintenance
of our networks. When customers experience power cuts, we
aim to respond rapidly to restore supplies as quickly as possible.
There are two key measures that we use to track how well we
are doing:
• Customer Interruptions (CIs): a measure of the average number
of power cuts experienced per hundred customers per year
• Customer Minutes Lost (CML): a measure of the time in minutes
that a customer on average will be without power in a year
A step change in performance
Implementation of our Quality of Supply strategy and focus on
supply restoration resulted in a step change in performance
in 2011. Across our three networks the number of customers
experiencing a loss of supply has fallen (see Figure 4.6). The
average minutes lost per customer fell by 41.5 per cent and the
number of eight hour power cuts fell by more than 60 per cent.
Figure 4.6: CIs and CMLs across the three networks (calendar
years 2009 to 2011)
LPN SPN EPN
CML
CI
CML
CI
CML
CI
31.9
27.5
27.7
25.2
Where customers experience an electricity supply
interruption lasting more than 18 hours, they are entitled to
a compensation payment under the Electricity Guaranteed
Standards of Performance. This standard will become more
challenging in the 2015 to 2023 period as customers will be
entitle to compensation following 12 hour supply interruptions.
Our focus will be to minimise the number of these incidents,
so that long duration outages become increasingly rare for
all customers.
45.5
49.7
45.7
50.1
54.8
64.1
89.7
81.4
85.8
92.4
85.9
78.4
84.5
96.5
0 20 40 60 80 100 120
2009 2010 2011
Figure 4.7: Number of long duration power outages (calendar
years 2009 to 2011)
Customers off over 8 hours
Customers off over 12 hours
Customers off over 18 hours
How we have delivered the improved
performance
We have undertaken a series of initiatives to improve supply
restoration performance. Our Operational Recovery programme
has focussed on promptly rectifying network faults and
equipment failures, increasing the use of portable generators
to temporarily restore supplies where possible, improving
operational responsiveness by deploying specialist teams with
sufficient resources to resolve network problems and improving
the performance management of field based teams. We have
also shortened response times by taking smarter approaches to
the dispatch of skilled staff to ensure failures are identified and
rectified promptly.
Building on these tactical changes we have developed a longerterm
Quality of Supply programme that has taken a holistic view
of performance and deployed automatic network reconfiguration,
focussed on improving the reliability and dependability of
network automation and remote control, and improved the
efficiency of operational procedures.
Quality of Supply Strategy
71,274
84,588
23,582
109,789
29,602
3,311
178,782
183,802
0 100,000 200,000 300,000
2009 2010 2011
Our Quality of Supply programme is focussed on the two
measures of network reliability, CIs and CMLs. It consists of
two complementary strategies that will reduce the number of
network failures and ensure a reliable service for customers.
CI Strategy: Reducing the number of power interruptions
321,228
Network automation: allows our systems to reliably
reconfigure the network to avoid customers being interrupted.
This may include short power interruptions of less than three
minutes as the network re-routes supplies.
Maintaining the network: inspecting and fixing faults and
open points in our network to ensure the long-term integrity
of our networks is not jeopardised. Clearing any backlogs of
maintenance and tree cutting.
>pg22 | Business plan

CML Strategy: Reducing the duration of supply interruptions
Remote control: Increased investment in remote control
infrastructure and improving the reliability of existing systems
provides control centre staff with more options to reconfigure
networks for rapid supply restoration.
• We have made investments in additional remote control
equipment in the EPN and SPN networks to enable
remote switching thus avoiding the dispatch of field staff
to restore supplies
• We are removing defects from our networks to ensure
that remote controlled devices operate at the maximum
possible efficiency
Improved first response times: we have changed our working
patterns to better match the volume and timing of fault
calls received. We have also improved first responder time
to attend incidents and increased our use of back-feeding
techniques to restore supplies to customers. Across all of
our networks, we now deploy skilled Distribution Supply
Technicians to provide immediate on site capability to identify
the problem, reconfigure the network and where appropriate
apply local generators to restore supply. We have improved
staff accountability and the monitoring of performance.
Improved reporting will underpin on-going performance:
• The quality of fault reporting is being reviewed and training
programmes are being implemented to improve accuracy
and consistency
• An integrated automated reporting system is being
developed to provide readily accessible operational
management reports and strategic asset management
information
Figure 4.8: EPN network reliability performance to date and
forecasts to 2015 (years to March)
100
80
60
40
20
0
100
80
60
40
20
0
2010 2011 2012 2013 2014 2015
Past performance
Forecast performance
(Regulatory years ending 31 March)
Ofgem CI target
CI actual/forecast
2010 2011 2012 2013 2014 2015
Past performance
Forecast performance
(Regulatory years ending 31 March)
Ofgem CML target
CML actual/forecast
Figure 4.9: SPN network reliability performance to date and
forecasts to 2015 (years to March)
Building on our step change
We have put plans in place to sustain the recent improvements
through to the end of 2015. Our Quality of Supply strategy
will ensure delivery of a more reliable service to customers.
Reliability performance projections for EPN and SPN are
presented in Figures 4.8 and 4.9. We expect to outperform all
regulatory targets and deliver a more reliable service to
our customers.
100
80
60
40
20
0
2010 2011 2012 2013 2014 2015
Past performance
Forecast performance
(Regulatory years ending 31 March)
Ofgem CI target CI actual/forecast
100
80
60
40
20
0
2010 2011 2012 2013 2014 2015
Past performance
Forecast performance
(Regulatory years ending 31 March)
Ofgem CML target CML actual/forecast
Business plan | >pg23

Innovation!
Smart urban low voltage network
We have collaborated with an innovation project partner to develop a
new retrofittable solid-state switching technology which allows remote
switching and re-configuration of the LV distribution network.
The new technology provides our control engineers with the ability
to remotely monitor and reconfigure the LV network, rather than an
engineer attending site to reconfigure the network manually.
Remote monitoring and control is enabled by a Power Line Carrier
communications link using the existing power cables as the
communications medium, thus avoiding extensive works to
install a new communications infrastructure.
Following a successful initial demonstration we have
commenced a large scale trial of the technology in
two areas of the London network. The large scale
trial will allow us to evaluate how proactive LV
network management can improve performance
and optimise the use of existing LV plant. It will
also allow us to analyse the benefits to
Quality of Supply performance through
remote control and automated
switching under fault conditions.
>pg24 | Business plan

Focus on London reliability
The distribution network serving central London differs from most
other GB electricity networks in the following ways:
• High levels of interconnected (meshed) network at low voltage
• An almost entirely underground network (which is inherently
more reliable, but more expensive to reinforce and maintain)
• Greater reliance on low voltage infrastructure
These features have consistently delivered high levels of network
reliability to London customers, as recognised in the targets set
by the regulator for Customer Interruptions (CI) and Customer
Minutes Lost (CML). In recent years, we have outperformed these
network reliability targets as shown in Figure 4.10. 2011 was an
exceptionally benign year for weather and 2012’s CI performance
reflects more normal conditions. However, we plan to make
investments which will maintain the reliability of supplies in
central London even as demand grows.
Figure 4.10: LPN network reliability performance to date and
forecasts to 2015 (years to March)
40
30
20
10
0
50
40
30
20
10
0
2010 2011 2012 2013 2014 2015
Past performance
Our plan for Central London
Forecast performance
(Regulatory years ending 31 March)
Ofgem CI target
CI actual/forecast
2010 2011 2012 2013 2014 2015
Past performance
Forecast performance
(Regulatory years ending 31 March)
Ofgem CML target
CML actual/forecast
We are very conscious of our responsibilities as the network
operator for London. We understand that a cost-effective
network with adequate capacity and resilience is key to London’s
competitiveness with other world cities and in to supporting
development in London and London’s role as a major growth
driver for the entire United Kingdom. London also presents
unique operating challenges, for example: major point load
connections not seen elsewhere in the UK, traffic congestion,
access and planning difficulties, and the requirement to manage
high profile events. In eighteen months we have seen a
Royal Wedding, a Royal Jubilee and the Olympic and
Paralympic Games. We must also consider the strategic targets
of the London Mayor and other London authorities in areas such
as the electrification of heat and transport, and the decentralised
production of energy.
Therefore we are planning strategically for the future of the
London network. In this section we describe briefly our plans
in the areas of capacity, resilience, and customer service.
Our detailed London plans will be the subject of a separate
consultation early in 2013.
More capacity for London
Our forecast investment plans will add significant network
capacity in London, to meet growth in load from existing
customers and from new connections.
We are forecasting to add c.1.5GW of new capacity in the period
to 2021, as Figure 4.11 shows. This is a significant increase in the
context of peak demand in London of c.5.2GW.
Figure 4.11: Forecast London capacity additions
2,000
1,000
0
2013 2014 2015 2016 2017 2018 2019 2020 2021
MVA additions
This capacity increase includes six proposed new main
substations at an estimated cost of c. £170 million, targeted at
key growth and development areas in Central London:
• Vauxhall-Nine Elms-Battersea
• White City
• Calshot Street (near King’s Cross)
• Isle of Dogs
• City (location to be determined)
• West End (location to be determined)
These new substations would facilitate the substantial forecast
load growth in these areas, reduce connection times and
costs, and avoid the need for long cable lengths to other main
substations and the associated consequences of cost, street
works disruption and higher fault rates. However since the main
beneficiaries of the new capacity from these substations would
be new connection customers we believe it is fair to existing
customers to charge new connections for their proportionate
share of the capacity in these substations, even if they connect
after the substations have been constructed. We are in discussions
with Ofgem regarding the regulatory treatment of this proposal.
Increased resilience for London
National Grid is investing in additional ‘supergrid’ exit points
within London that, together with our own capacity additions,
will increase significantly the capacity and resilience of the
London network.
In addition to this, we plan to invest in increased automation and
remote control to improve quality of supply further. We propose to
install remote control at one third of HV substations in the Central
London area, and at all the circuit breakers on the low voltage
network. This would involve a total cost of c. £16 million.
We also propose to convert to unit protection the network around
Leicester Square at a cost of £26 million.
Improved customer service
The performance improvements described elsewhere in this
document will benefit London. In addition we also propose
operational changes to enable faster response to faults in central
London, and plans to provide more publicly available information
on the available capacity in our networks so that developers
and other prospective connection customers can optimise their
projects and will face more predictable connection costs.
Business plan plan | | >pg25

What do our stakeholders say
What they said in 2011
Network availability is an important issue for stakeholders, with many of them
expressing support for all of the existing outputs. It was also suggested that
performance against these outputs should be made more visible
to stakeholders.
Our business plan says in 2012
We agree with stakeholders’ desire for greater visibility of performance
measures. We will produce an annual stakeholder report to address
this, together with the inclusion of up-to-date measures on
our website.
What do our stakeholders say today
Do you think we can do more We welcome
your views.
Go to our stakeholder website at
http://yourviews.
ukpowernetworks.co.uk
>pg26 | Business plan

4.6 Improving customer satisfaction
Consultation Questions for this section
Customer satisfaction and social obligations
Q11. What do you think we should do to improve customer service
and to measure the satisfaction of our customers
Q12. How can we make it easier for our customers to communicate
with us, either in a power cut situation, for a new connection, or
for a general enquiry
Q13. Do you think there are additional services we should be
providing to vulnerable or fuel poor customers
Business plan | >pg27

We take customer service very seriously with many of our
employees in day-to-day contact with our customers. We
have made our service quicker by reducing average telephone
answer times to less than 20 seconds and better, achieving
improved results in the Ofgem telephone survey. However,
we still have more to do to improve customer service
Ofgem’s new Broad Measure of Customer Satisfaction
measures our performance across a range of areas including
power cuts, new connections, customer complaints and
stakeholder engagement.
Customer care is at the heart of our business
Our Customer Service Centre in Ipswich receives over a million
calls each year. Generally people contact us when their power
goes off, when they require us to do some work on our network
or when making a new connection.
We have already seen a step change improvement in customer
satisfaction with customer complaints down by 81 per cent.
The number of complaints referred to the Ombudsman (see
Figure 4.13) is down by almost 50 per cent and the average time
it takes us to answer customer calls is down by over 70 per cent
to less than 20 seconds.
Figure 4.12: Number of customer complaints (across our
three networks)
18,000
12,000
Figure 4.13: Number of customer complaints taken up by the
Ombudsman (across our three networks)
Figure 4.14: Average time to answer customer enquires (across
our three networks)
Seconds
6,000
0
100
80
60
40
20
0
70
60
50
40
30
20
10
0
2009 2010 2011
Number of customer complaints
2009 2010 2011
Complaints taken up by Ombudsman
2009 2010 2011
How we have delivered improved performance
We are radically overhauling our approach so that we manage
the customer experience from the point of initial contact through
to confirming customer satisfaction, making contact with
customers at key points within their journey.
We are reducing the time it takes us to deliver work for our
customers in both connections and general enquiries. We are
aiming to improve our approach so that we can deliver on the
day the customer chooses. We are redefining our approach
to provide a single point of contact, with ownership for our
customer’s request. This will mean that when customers call our
staff will have the relevant information from previous contacts.
These improvements aim to answer enquiries quickly and
clearly, which then helps avoid a customer feeling the need to
make a complaint. When issues do escalate into complaints, the
customer service improvement programme has already resulted
in a reduction in the time taken to resolve them. The Broad
Measure complaints metric incentivises us to handle complaints
effectively, to resolve disputes quickly to our customers’
satisfaction and to avoid customers having to repeatedly
complain about an issue. To assess the quality of our complaints
handling procedure the current metrics measure performance
on four indicators that are weighted to calculate a composite
score. The weight Ofgem applies to each individual indicator is:
complaints over one day (10 per cent), complaints over 31 days
(20 per cent), percentage of the total that are repeat complaints
(50 per cent) and findings against us by the energy Ombudsman
(20 per cent).
Figure 4.15 shows our performance and forecast against the
Broad Measure complaints metric. This shows the weighted
percentage of complaints not resolved within the thresholds
outlined above. We are targeting a 65 per cent reduction in
complaints that exceed these thresholds by the end of 2015.
Figure 4.15: Performance and forecast against the Broad
Measure complaints metric
35%
30%
25%
20%
15%
10%
5%
0%
2011 2012 2013 2014 2015
Historic
DPCR5 Forecast
LPN Weighted complaints unresolved
SPN Weighted complaints unresolved
EPN Weighted complaints unresolved
We have increased our presence on social media e.g. Twitter and
our web page to radically improve how our customers are able to
interact with us. This includes functionality to enhance our web
offering such as postcode based power outage enquiries and
improved customer call-back. We are continuing to build on this
performance improvement to deliver the service experience that
our customers want.
>pg28 | Business plan
Average time to answer calls in seconds

d
n
How we will continue to deliver
We are looking at all aspects of our business and we are planning
on rolling out a programme of training so all of our staff can
improve their skills in providing a consistently high standard of
service. We will ensure that our interactions with customers are
positive. A key building block in the foundation of good services
is resolving enquiries quickly. This helps us to avoid customers
feeling the need to escalate to a complaint. When we receive a
complaint we aim to resolve it quickly and fairly.
The way performance measurement is changing
From April 2012 Ofgem introduced the ‘Broad Measure of
Customer Satisfaction’ which involves a survey of customers who
have had a new connection, experienced an interruption to their
supply or made a general enquiry.
The measure comprises a customer satisfaction survey, a
complaints metric and incentives for stakeholder engagement.
The customer satisfaction survey helps to gauge how we deal
with our customers. The results from each type of customer
contact are weighted; Supply Interruptions (40 per cent),
Connections (40 per cent) and General Enquiries (20 per cent).
How we resolve any complaint is also an important measure of
customer satisfaction.
Figure 4.16 shows how our three networks have fared against
the industry average since the introduction of the measure
in 2012.
Figure 4.16: The performance of our three networks against the
industry average in the industry Broad Measure of Customer
Satisfaction survey
9.0
Figure 4.17: EPN forecast for the Broad Measure of
Customer Satisfaction
Regulatory year ending 31 March
9.0
8.5
8.0
7.5
7.0
Figure 4.18: LPN forecast for the Broad Measure of
Customer Satisfaction
Regulatory year ending 31 March
9.0
8.5
8.0
7.5
7.0
2012 2013 2014 2015
Where we are
now
Where we will be (DPCR5 Forecast)
EPN score Best overall DNO 2012
Industry average 2012
2012 2013 2014 2015
Where we are
now
Where we will be (DPCR5 Forecast)
8.5
8.0
LPN score
Industry average 2012
Best overall DNO 2012
7.5
7.0
April 2012 May 2012 June 2012 July 2012
Figure 4.19: SPN forecast for the Broad Measure of
Customer Satisfaction
Regulatory year ending 31 March
EPN
SPN
LPN
Upper third in the Broad Measure
Industry average
Industry best company (to date)
We have set ourselves a challenging target to be in the upper
third of the fourteen distribution networks in Broad Measure
performance. Figures 4.17 to Figure 4.19 show how we
expect our performance to improve to 2015 compared to the
current best performance score in the industry. In addition to
our customer service training initiatives, we have identified a
number of key performance indicators mapped to Ofgem’s new
Broad Measure. We have targeted specific improvements in each
of those key performance areas.
This target is easily the most challenging in LPN. It consists of
entirely urban customers with perhaps the highest expectations
of all customers and where we face the greatest challenges in
meeting their needs.
9.0
8.5
8.0
7.5
7.0
2012 2013 2014 2015
Where we are
now
SPN score
Industry average 2012
Where we will be (DPCR5 Forecast)
Best overall DNO 2012
Business plan | >pg29

Supporting vulnerable customers
We maintain a register of vulnerable customers and we liaise with
local stakeholders to keep this up to date.
As part of our approach to customer satisfaction we operate a
community support partnership with the British Red Cross. Our
partnership allows us to provide information and practical support
to customers on their doorstep, in the rare event of our customers
experiencing a long power cut. We work with British Red Cross
volunteers to provide the latest information on how the work to
restore power supplies is progressing and can provide hot drinks and
torches to those who need them.
The British Red Cross fleet includes access to four-wheel drive vehicles
which can visit customers in all weather conditions. The service is
available 24 hours a day, every day of the year.
In 2010, British Red Cross volunteers responded to more than 1,000
incidents in London, the East of England and the South East. This
was particularly important during the prolonged snow and ice in
December, which tripled the number of British Red Cross callouts
arranged by us.
>pg30 | Business plan

4.7 Improving our connections work
Consultation questions for this section
Conditions for electricity connections
Q5. What do you think is important to customers when they request
a new electricity connection, and what should we focus on
improving For example, the cost, the time to connect, the
quality of our customer service
Q6. Do you think we should proactively provide more electrical
infrastructure, before the capacity is required, so that electricity
connections can be made more quickly or easily In particular, is
London a special case and, if so, why
Q7. Do you think we should invest more in the electricity network to
make it quicker or easier for renewable or distributed generators
to connect
Q8. Should any investment to make connections quicker and easier
be subsidised by all customers in the region, or purely paid for
by those wishing to make new connections
Business plan | >pg31

In 2011 over 104,000 new connections were made to our
electricity network. We are speeding up our processes,
promoting competition and getting ready for the low carbon
future. We are continuing to improve how we work to give our
customers a timely and a consistent service that is recognised
by them as value for money.
Speeding up the process
For our customers seeking a connection, we are improving how
they can interact with us and speeding up the process. In many
market segments customers do have a choice of connections
provider and we are currently in the process of demonstrating
that there is a competitive market in our regions. We welcome
strong competition, providing our customers with a choice for
contestable connection works. We are undertaking a review of
the whole connections process to support our vision to achieve
top-third performance compared to our electricity
distribution peers.
Our programme is further enhancing our customer service
culture throughout our connections activities. The programme
has three aims:
• Reduce the time that a customer waits for a connection
• Put the customer at the centre of our business processes and
• Reduce the cost to our customers
Future competition
In July 2012, we submitted our Competition Notice to Ofgem that
demonstrates how we have effective competition in connections
across our three networks. We have worked hard to remove
barriers to allow competition to flourish. We have redesigned our
website in order to clearly explain to those seeking a connection
that they have an option to use a third party company, how the
process works and what they also need to do with us to ensure
the smooth delivery of the connection. We have undertaken a
stakeholder engagement process, with direct engagement and
consultation with the competitors operating in our areas in order
to develop an agreed and prioritised set of improvement actions.
We have also worked to ensure we have the resources to respond
to work volumes in order to deliver improved customer service.
The roadmap
We have a roadmap for improvement for UK Power Network’s
connections service with three distinct phases, Insight, Design
and Implementation. The Insight Phase has been completed
and has established stakeholder best practice requirements for
a leading edge connections service provision. We are currently
progressing through the Design Phase. We expect the project to
deliver improvements in the short term and to deliver a longterm
sustainable approach that will consistently provide our
customers with a connection service they see as value for money.
To ensure our customers receive a timely connections service,
we have launched a web based self-service system. This will
speed up the process for less complex connection enquiries by
enabling customers to create an illustrative quotation. We are
also improving our accessibility information across the board
to ensure customers understand the choices they have, the
information we need and our commitments to them.
>pg32 | Business plan

What do our stakeholders say
What they said in 2011
Stakeholders require better communication between us and
them at every stage of the project. They expect us to be more
customer‐focused.
A number of stakeholders suggested that having an account
manager would help achieve better communication between us and
our customers.
Our business plan says in 2012
In the current regulatory year our connections service is ranked 11th
in the Ofgem customer satisfaction survey. We are improving our
process and performance by:
• Providing a single point of contact and ownership for a connection,
with improved contact choice and service
• Reducing lead times to less than 20 days. We will deliver on the
day the customer chooses
• Reducing connection charges by increasing efficiency
• Calling each customer at the end of the job to understand how
satisfied they are
• Further training our staff to ensure they understand what our
customers expect of them and how we can best serve them
What do our stakeholders say today
Do you think we can do more We welcome your views.
Go to our stakeholder website at:
http://yourviews.ukpowernetworks.co.uk
Business plan | >pg33

4.8 Improving safety
Consultation questions for this section
Safety
Q14. Would you value more engagement or information around
safety and electricity
Q15. We believe we have improved signage and security around our
excavations on the public highway. How should we improve the
safety of employees and the general public
Q16. What should we be doing more of in the future For example:
• Greater prevention of metal theft and vandalism
• Additional safety education programmess
>pg34 | Business plan

Ensuring the public and our employees are safe is our highest
priority when we work. Since 2010, we have nearly halved our
accident rate and injuries to the public.
Working safely
Safety is our primary focus for the public, our staff and our
contractors. We are bound by Health and Safety Legislation which
is enforced through the Health and Safety Executive (HSE).
Public safety
We take health and safety extremely seriously and over the
last two years we have been on a journey to improve our
safety performance.
The number of injuries involving members of the public has
already fallen in 2012 compared to 2011. While the figures are
not complete for this year, we are encouraged by the progress
we are making.
The progress we have made was put in perspective by a fatal
incident. In July, a member of the public came into contact with
an overhead line that had fallen from a pole and suffered a fatal
injury. This is an extremely rare event. We have launched an
internal investigation and are cooperating fully with the Health
and Safety Executive to understand the failure mechanisms and
to learn any lessons that could reduce the chances of a tragedy
of this nature occurring again.
Importance of employee safety
We operate a safe system of working that defines how we work
to protect the safety of all of our employees and contractors.
We have taken steps to improve our performance and have
delivered a consistent downward trend in accident rate. Figure
4.20, shows that in 2011, the accident rate for employees has
fallen considerably.
Our recent performance has been overshadowed by a tragic
event that led to a fatality of a member of our staff. This has
prompted a considered and immediate response to the incident
including changes to our monitoring regimes, increased safety
training and a zero tolerance approach to non-compliance. We
are using our first Safety Climate Survey to further inform our
safety action plans going forward.
Our approach to safety is wider than solely reducing lost time
incidents. We have put significant effort into ensuring and
promoting the health of all those who work for us. We have
published an Occupational Health and Wellbeing Strategy
and have launched Fitness to Work assessments for all of our
operational staff. Other preventative measures include a flu
vaccination programme that is available to all staff. We have also
arranged ‘office walk-arounds’ by physiotherapists to promote
good posture. These improvements have been achieved through
continued communication efforts and incentives.
Figure 4.20: Accident rate 8 for employees (across our
three networks)
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
2008 2009 2010 2011
8
Accident rate is defined as the number of reportable accidents per 100
employees. Reportable accidents are those that are fatal, major or over
three days in lost time
Business plan | >pg35

Innovation!
National Underground Assets Group (NUAG)
The aim of this group is to develop and trial the concept
of having a UK-wide IT portal to enable anyone
planning to undertake excavation in the highway or
on private land to request information about the
location of utility assets. This helps to prevent
people from digging up our underground
cables and suffering injuries, and can
facilitate improved joint working
between utility companies.
>pg36 | Business plan

4.9 Delivering long-term value
for customers
Electricity distribution accounts for around 18 per cent 9 of a
customer’s overall bill.
Our charges to our customers are amongst the lowest in
the industry.
We continue to focus on delivering greater efficiency while
managing the uncertainties of the economy and the risks of
ageing assets. Our vision is to be amongst the top-third of our
electricity distribution peers in terms of cost efficiency, while
maintaining the long-term health and capacity of our network.
Figure 4.21: Pie chart showing the breakdown of a typical
customer electricity bill
5% 7%
5%
10%
18%
54%
Wholesale energy, supply costs and supplier margin
Distribution
Environmental
VAT
Transmission
Meter provision and other
Our customer tariffs are amongst the lowest in
the industry
The cost of operating, maintaining, renewing and expanding
the network that carries electricity from generators to customers
is on average 18 per cent of a customer’s electricity bill. The
amount we charge is tightly controlled by Ofgem, the industry
regulator. The amount customers are charged varies across the
country depending on which of the 14 networks customers are
connected to. Customers can pay anywhere between £70 and
£140 per year.
Customers connected to our three networks see some of
the lowest annual charges in the country when compared to
the other eleven DNOs. All three of our networks have been
consistently ranked in the top five lowest contributors to a typical
domestic customer’s bill for the past four years. EPN has also
been in the top two for the past three years and is currently the
best ranked among all fourteen DNOs. We are determined to
deliver the best possible service to our customers at the lowest
possible price. Throughout the rest of this section we summarise
our current financial performance and how we will deliver an
even better service.
9
Ofgem fact sheet 97 31 May 2012
Figure 4.22: Annual cost to domestic customers (based on
average annual domestic consumption of 3330kWh real
2012 prices)
£ (2012 prices)
160
140
120
100
80
60
40
20
0
2009 2010 2011 2012 2013 2014 2015
EPN
SPN
DNO average forecast
Our financial performance
LPN
DNO average
Highest cost DNO
We are regulated by Ofgem to ensure that our operations are
cost efficient and that we offer appropriate levels of service
to our customers. Through the regulatory price control process
Ofgem sets how much we can collect from our customers.
Our expenditure plans are periodically scrutinised and challenged
by Ofgem. In between these period 7% reviews, they use incentives
5%
to encourage us to continually seek greater efficiency and
5%
improve our service performance.
In 2010 a five 10% year plan was agreed with Ofgem that set the
revenue we were allowed to collect from our customers for the
period to 2015. This included a strong incentive for efficiency and
for improving the reliability of our service.
We are now just over two years into the five year plan. We have
taken steps to make
18%
our business more efficient in response to
the incentives to do so. However, we have also had to undertake
more work, particularly on our EPN network to keep our network
healthy for the long-term benefit of our customers.
In addition we have felt the effect of the prolonged economic
downturn. In general an economic downturn reduces the growth
in demand for electricity. In turn this has the effect of reducing
the need for us to expand the capacity of our networks.
In the following sub-sections we provide more detail on the
impact of each of these factors on our expenditure.
Increasing our efficiency; reducing the cost
to customers
At the time of the last price control Ofgem assessed our costs
for delivering capital projects to be 20 per cent above the
efficient benchmark.
We have embarked on an improvement programme to improve
efficiency and improve our service to our customers. Our
objective is to achieve a top-third ranking against our peers
in cost efficiency. This will address the efficiency opportunities
identified in the last price control reset.
We are now seeing the results of the cost efficiency programmes
we have undertaken, with a 19 per cent reduction in our
overhead (indirect) costs since October 2010.
54%
Business plan | >pg37

Indirect Cost Efficiency Programme
The ICE programme was launched in 2011 in order to close
the cost performance gap between us and the benchmark
distribution companies in overhead costs. The project
targeted a reduction of £50 million of annual operational
expenditure by the end of 2013. The executive team provided
recommendations and options to achieve savings by ‘right
sizing’ our operational support functions.
Employee participation was encouraged and we invited over
2,400 employees to provide us with ideas for improving our
efficiency. We generated over 1,000 responses.
We achieved a reduction in headcount of approximately
600 employees through reducing agency staff and offering
voluntary redundancy packages to members of staff.
The programme has delivered the majority of its intended
savings. The remaining benefit will be achieved by an ongoing
focus on eradicating waste and driving efficiency in our
non-labour indirect cost initiatives including:
• Reviewing our transport travel policy and fleet size
• Reducing spend on consultants and other
external contractors
• Reducing insurance, legal and property costs
• Renegotiating our contracts with key suppliers
Responding to the economic down turn
The persistent economic slowdown has reduced the overall
growth of demand for new capacity in our electricity networks.
The effect has varied across our networks reflecting the regional
variability in economic activity.
As can be seen in Figure 4.23, peak demand for electricity from
our networks has been broadly flat or on a downward path.
This is in contrast to the long-term trend that has seen year-onyear
growth in peak demand over the previous 10 years with
compound average growth rates 10 of 0.7 per cent for EPN, 1.8 per
cent for LPN and 0.3 per cent for SPN.
At the time we set out on our current plan, we were anticipating
a short economic downturn followed by a return to growth. The
return to growth has been slower and we have seen a reduced
need for the projects identified when we set out in 2010. The
need to expand the capacity of our networks has reduced with
economic redevelopment slowing and demand growing more
organically with larger scale developments and redevelopments
being slowed by the economic conditions.
Our LPN network has seen the smallest fall in electricity demand
of our three networks, despite the wider economic difficulties.
This means we are still forecasting to spend close to our original
plan over the entire 2010 to 2015 period, especially with regard
to the larger ‘high-value’ projects to support the wide held
stakeholder expectation of continuing growth in demand for
network capacity in London.
For EPN growth has tailed off, with a downward turn in the latest
peak demand figures compared to the previous year. It appears
that the high peak in 2010/11 that was coincident with the
very cold spell in that year may be less representative of the
underlying long-term trend of electricity peak usage. We are
currently assessing the underlying driver for this high peak. For
SPN the downward trend has been apparent from the very start
of the financial down turn. We do not expect these networks to
recover to pre-financial crisis levels of peak load for some years
and we are forecasting an overall underspend compared to our
original plans for expanding the network.
Figure 4.23: Actual peak demand against long-term forecast
peak demand (MW)
8,000
7,000
6,000
5,000
4,000
3,000
2006/07
2007/08
2008/09
2009/10
EPN actual
SPN actual
LPN long-term trend
Increasing volumes of work to maintain the
long-term health of our assets
We take a long-term view of managing our networks and are
mindful of the expenditure required to replace ageing assets. In
order to ensure a sustainable future we assess the health of our
assets. The continuing process can highlight new requirements
or factors that drive additional work. So while we drive down
our cost-per unit of work the overall money we spend on asset
replacement can rise.
We have taken steps to improve our understanding of the health
of our assets. Asset management is an ever-developing field
and we have worked in partnership with experts to develop
improved risk based investment modelling capability. These
models use the latest available condition data and apply stateof-the-art
degradation modelling techniques to predict the future
health of the populations of our assets.
2010/11
2011/12
2012/13
2013/14
2014/15
LPN actual
EPN long-term trend
SPN long-term trend
10
Compound average growth rate between 2001/02 and 2010/11
>pg38 | Business plan

We use regular inspections and targeted asset condition reviews
to ensure we understand the state of our assets.
Through this work we have found evidence to suggest that for
some of our assets, an intervention is expected to be required
earlier or later than previously thought. An intervention could be
a scheduled maintenance activity, refurbishment or a complete
asset replacement.
The effect of this is to introduce additional volumes of work
mostly in EPN that we need to deliver in the short term to
maintain the health of our network. These work volumes relate
to additional inspection and maintenance on our link boxes
due to an observable rise in disruptive failures and to our
having found larger numbers of defective poles following our
inspection programme. We are also undertaking additional work
to address safety issues to comply with our statutory obligations
under the Electricity Supply Quality and Continuity Regulations
(ESQCR). In addition, in EPN, we are undertaking additional
asset replacement to maintain the health of the network on a
sustainable basis. The current regulatory settlement does not
fund all of these additional costs and we are exposed to 45 per
cent of the costs. We believe it is in the best long-term interests
of our customers to complete this work now.
The net result of our investment over the period is intended to
maintain the overall health at a network level. We use a series
of models to assess the Health Index (HI) of our assets. The HI is
an industry approach to categorising the health of our assets. The
categories are from HI 1 to 5 as described below:
• HI1: new or as new
• HI2: good or serviceable condition
• HI3: deterioration requires assessment and monitoring
• HI4: material deterioration, intervention requires consideration
• HI5: end of serviceable life, intervention required
Figure 4.24 to Figure 4.26 show how we measure progress
against HI output scores monitored by Ofgem over the current
period from 2010 to 2015.
Ofgem HI scores are calculated from the sum of the difference
between the HI forecasts with and without investment for each
asset type, weighted by both significance of HI category and by
asset unit cost. The resultant total value of the HI delta forms
the target profile indicated in orange. Our actual progress and
forecast against the target is shown in red.
Figure 4.24: EPN actual and forecast progress against
Ofgem DPCR5 HI scores
Regulatory year ending 31 March
18,000,000
12,000,000
6,000,000
0
Year 20111 Year 20122 Year 20133 Year 20144 Year 20155
FBPQ target points
Points actual/forecast
Figure 4.25: LPN actual and forecast progress against
Ofgem DPCR5 HI scores
Regulatory year ending 31 March
18,000,000
12,000,000
6,000,000
0
Year 20111 Year 20122 Year 20133 Year 20144 Year 20155
FBPQ target points
Points actual/forecast
Figure 4.26: SPN actual and forecast progress against
Ofgem DPCR5 HI scores
Regulatory year ending 31 March
18,000,000
12,000,000
6,000,000
0
Year 20111 Year 20122 Year 20133 Year 20144 Year 20155
FBPQ target points
Points actual/forecast
Business plan | >pg39

4.10 Innovating to excel as a business
Consultation questions for this section
Incentives and innovation
Q9. Do you think our approach to innovation and change is sufficient
Do you think we should be researching additional areas in relation
to change and innovation, and if so what
Q10. How much of a priority should each of the following areas be for us
in 2015 to 2023
• Facilitating renewable generation
• Facilitating new demand sources such as electric vehicles, heat
pumps, etc.
• Empowering customers with information
• Managing customer demand to avoid the need for
network reinforcement
• Improving electricity network service and reliability
• Increasing network control and automation in preparation for
a ‘smart grid’
Environment
Q17. What are the current initiatives and issues that concern you
surrounding our impact on the environment
Q18. What should we be doing more of in the future For example:
• Extending our programme of undergrounding overhead
electricity lines beyond Areas of Outstanding Natural Beauty
to other sensitive areas
• Installing equipment with lower lifetime carbon impact
• Increasing our programme to actively remove oil
filled equipment
• Change our monitoring of SF6 (a greenhouse gas commonly
used in electrical transformers)
• More challenging targets for our carbon footprintMore
challenging targets for our carbon footprint
>pg40 | Business plan

Innovation is core to the success of our business. We see
innovation as the way to deliver our vision of being an
employer of choice, a respected corporate citizen and
sustainably cost efficient. We drive business innovation to
improve our customer satisfaction, be more cost efficient and
optimise our investment to keep customers’ bills down.
Business innovation
We believe strongly that through innovation we can improve
how we operate our business. Our step change in performance
is based on changing the way we work and finding new and
innovative ways to deliver better service for our customers.
Alongside general business improvement, we have a portfolio of
network innovations aimed at increasing reliability and quality of
supply to improve public and employee safety and support our
role in the UK’s low-carbon transition.
We keep our innovation portfolio fresh by continually looking for
new opportunities, stimulated either by a specific business need
or by technological advancements. If we think the opportunity
has merit, we launch a project to trial the innovation to get a
better understanding of the potential and impact of it. If the
benefits prove favourable, we roll the innovation out across the
business and monitor the improvements to ensure they deliver
over time.
Innovation in business improvements or efficiency can be
self-funding. Where there are significantly higher risks, such as
deploying new technology, then we seek to utilise risk sharing
arrangements with partners or through the innovation funding
mechanisms within the regulatory framework. In the remainder
of this section we describe the innovations and improvements
we are delivering now. Later in this chapter we outline the
bigger innovations that will define the future distribution
business, where smart technology is more widely deployed to
fulfil our role in the low carbon economy.
Figure 4.27: Our approach to innovation
Drivers to innovate
Improve customer
satisfaction
Example outcomes
Minimise impact of
street works
Improve business
efficiency
Improve network
performance
Continuous
improvement
through
innovation
New ‘state of the art’
decision support tools
Fast overhead line fault
detection
Prepare for the low
carbon economy
Low carbon London and
flexible Plug & Play
Improving our business performance
Innovation has played a key role in helping us deliver the stepchange
in performance achieved over the last year. We have
looked at best practice outside our own industry to identify and
apply appropriate initiatives. For example, to improve our safety
performance we have:
• Undertaken a Safety Climate Survey, in conjunction with the
Health and Safety Laboratory, to help us understand and
improve our own safety culture and overall performance
• Started to roll out a behavioural safety programme across
the company
For cost efficiency we have implemented a new performance
management framework. This framework improves
accountability for the delivery of targets by ensuring that these
targets are cascaded appropriately throughout the business at
an individual level and that delivery of targets is linked to the
company bonus structure.
An integral part of improving business performance is having
good data on which to base decisions. In 2011 we undertook a
full review of our business critical data items. As a result of this
review we now actively monitor and report on network related
data in a monthly scoreboard – increasing both the visibility and
integrity of our core data set.
Our unit cost project supports better performance management
and improves the accuracy of cost forecasting. By ensuring the
cost of network related expenditure is clearly visible and actively
tracked we have been able to see where there are areas to bring
unit costs down.
With respect to customer service we have looked to extend the
range of communication channels that we use to interact with
customers. An example of this is that we now use Twitter to
keep customers updated during power cuts. The increasing use
of smartphones makes this an effective tool for communicating
with customers, and has been received positively.
Business plan | >pg41

More recently we have started to trial the use of iPads and a
‘GeoSub’ app for London field staff. The aim is to reduce the
number of Customer Minutes Lost (CMLs) by helping engineers to
quickly navigate around the city’s 16,000 substations and pulling
up detailed drawings of each upon arrival.
Minimising our impact when we work
While we improve our networks and deliver connections
efficiently, we seek to minimise our impact of our work. We have
focussed our efforts on reducing the impact of our street works in
response to what our stakeholders consider important.
We provide services to residences and businesses in the most
densely inhabited areas in the UK. We appreciate the impact our
work has on traffic congestion and the structure of the highways
when we excavate verges, footways and carriageways.
We have a higher proportion than most of local authorities
(29) in our areas that run road permit schemes. We have the
only two authorities in the UK that are applying for lane rental
schemes. There is also the Mayor’s Code of Conduct, as well as
Westminster and the City of London codes. We must comply
with these regulations, which do not apply to other distribution
companies. Undertaking street works within London, as we will
explain later, presents its own unique challenges.
We undertake more than 70,000 excavations a year across 52
authorities. The majority of excavations are to provide new
connections for customers or to repair faults on the network.
Over 50 per cent of our works in London are due to customers
requesting new connections. A further 44 per cent of our work is
to fix faults that are causing a loss of electrical supply. Of these
works, 93 per cent is undertaken off the carriageway.
How we are meeting the challenge
To meet the challenge of reducing our impact while undertaking
street works we are:
• Investing in a new street works IT hub. This will simplify our
processes and ensure we manage our work to avoid fixed
penalty notices, overstay charges and the impact of lane
rental charges
• Investing in a new customer service street works information
system. This is on our website to improve information flow to
our customers. There will also be a smartphone application to
support this service
• Implementing a new policy on site information signs that will
provide better information for the travelling public. This will
inform them of what is happening at our works
• Working with local authorities and other utilities (particularly in
London) to understand how we can collaborate on works and
reduce our impact on traffic congestion
• Continuing to be environmentally friendly by recycling 99 per
cent of all excavated street works spoil and using recycled
material where possible for back fill
We are committed to reducing the impact of our street works
through this on-going programme
Following detailed analysis into sourcing strategies for street
works teams we have started to pilot an insourcing approach
in SPN. The trials are proving successful and suggest that we
can realise some significant efficiencies by reducing our use of
contractors. We will continue to explore such opportunities and
exploit them where they are in the interests of our customers.
>pg42 | Business plan

Innovation Funding Incentive (IFI)
We are an active participant in Ofgem’s Innovation Funding
Incentive (IFI) programme. Through innovation we are committed
to improving the level of service efficiency that we provide to our
customers, while ensuring that our networks remain fit for new
technologies that lie ahead. Innovation in our everyday business
activities has already demonstrated its benefit to how we work
and we will continue to increase the pace at which this happens.
Our innovation activities typically fall into a number of categories:
• To understand a future issue and build a timeline for action
• To inform engineering decisions
• To develop new solutions such as test equipment, sensors,
network management controllers, network management
software and desktop design tools
We operate a range of projects, from early stage research
through to trials on our network. While the IFI has been a
significant source of funding for our innovation activities we have
sought to leverage other sources of lending wherever possible.
Our spending on IFI projects can be summarised into three high
level areas:
• Innovation and our current assets
• Managing customer demand through innovation
• Using innovation to release extra capacity in our networks
Innovation and our current assets
Managing our assets better is a continuous process. Ensuring
the accuracy of our asset information is vital to our current
operations and to future business planning. As can be seen from
our planning forecasts later in this document, monitoring asset
condition and performance feeds directly into our expenditure.
Reducing customer power interruptions is our top priority.
While our London network has the advantage of underground
cabling reducing fault rates, EPN and SPN have a mix of both
underground cables and overhead lines. We launched the
Overhead Line Incipient Fault Detection project to trial fault
location solutions on overhead lines, using detection points
installed on the high voltage network. Working with another
DNO, Electricity North West, we aim to develop a proactive
approach to reducing interruption duration as well as
reducing the switching required to locate faults and reduce
recurrent faults.
Four 11kV circuits have been identified for the trial installation.
Once installed, the system will be operated for a 12 month
period with all data being gathered and compared with system
fault and switching data. Conclusions about the system’s
effectiveness and reliability will be drawn and if successful it has
the potential to be rolled out across EPN and SPN.
Managing customer demand through innovation
Customer demand is expected to rise over the coming years.
To reduce the need for reinforcement and hence the costs, we
are using innovation to manage customer demand. We aim to
reduce the amount of reinforcement necessary and to mitigate
the associated costs.
London has some of the largest commercial buildings in the
country, requiring large amounts of electricity to heat and
cool them. As an innovative example of how we are managing
the demand for electricity from our commercial customers, we
developed a water cooled heat exchanger for our substation at
Bankside on the Thames, adjacent to the Tate Modern.
Substation transformers generate heat that is lost to the
environment. We have upgraded the substation so that it is
water cooled, allowing the waste heat to assist the space heating
at the Tate. The benefits for us are that less energy will need
to be expended within cooler fans at the substation, and lower
maintenance and replacement cost will be incurred. The overall
carbon footprint of the site and assets will be reduced.
Business plan | >pg43

Innovation!
Bankside heat transfer
Substation transformers generate heat, particularly during
peak loads. This heat is normally lost to the environment,
often through energy-intensive forced cooling. The upgraded
substation at Bankside, adjacent to the Tate Modern, has
used transformers with water cooled heat exchangers.
It is proposed that the waste heat from the transformers
will be used by the Tate Modern to assist with their
space heating. This will benefit the Tate by providing
low-carbon heat. The benefits for UK Power
Networks are that less energy will need to
be expended within cooler fans at the
substation, and lower maintenance and
replacement cost will be incurred.
The overall carbon footprint of
the site and assets will
be reduced.
>pg44 | Business plan

Using innovation to release extra capacity on
our networks
There are many innovative ways that we can increase capacity
on our networks. We have been exploring methods to increase
capacity from existing overhead line routes. Standard techniques
can be intrusive, often requiring support structures. For the
pilot study, two overhead line routes have been chosen. A
collaborative team has been brought together from across our
engineering standards, capital projects and network planning
teams with additional external consultants with significant
overhead line experience. The project team are investigating new
ways of increasing capacity. They are exploring novel conductors,
potentially re-tensioning cables or other minor modifications to
structures to increase capacity. They are also reviewing operating
regimes to see if they can be improved.
Our London network is entirely underground. It is often difficult
to reinforce circuits in densely populated areas mainly because
there is limited physical space available. London substations are
commonly built underground, are therefore expensive to build,
and can cause disruption during construction. We currently have
an innovation project that will evaluate if an urban distribution
substation developed by a Spanish company (Twelcon) could
help address these issues. As these substations can be placed, for
example, in car parks, the additional headroom these substations
may provide could enable electric vehicle charging points to
connect to the distribution network. The cost of the urban
substation could be partially offset by revenue generated from
the sale of advertising space on its external walls.
Innovation in decision support models
Innovation also extends to the tools we use to run our business.
To improve our planning process we developed two new models
to inform our future expenditure forecasts:
• A long-term network reinforcement model to quantify Load
Related Expenditure
• Asset replacement and refurbishment models to quantify
Non-Load Related Expenditure
The new Load Related Expenditure Model was developed with
Imperial College London and provides enhanced long-term
network reinforcement forecasting to supplement established
bottom-up planning techniques. This new reinforcement
tool enables the rapid assessment of a range of network
development scenarios.
The new model is capable of projecting optimised network
expenditure profiles to reflect the increasing deployment of
low carbon technologies such as electric vehicles, heat pumps,
commercial air conditioning, the various forms of distributed
generation, smart appliances and energy efficiency measures.
Our new ‘Asset Risk and Prioritisation’ model has been
developed to inform asset replacement and refurbishment
options. Through an improved understanding of asset
degradation and failure risk we are able to better prioritise
the assets requiring renewal over time. This innovative model
enables evaluation of the financial and technical consequences of
different intervention strategies. This new approach is informing
our decisions to replace and refurbish assets or to introduce an
enhanced maintenance practices.
4.11 Smart innovation to meet demand
We are committed to playing our full role in facilitating the
transition to a low carbon economy. We will need to adapt our
business as our customers take up low carbon technologies
and connect distributed generation. We are preparing for
the journey and are developing our thinking as to what
the network of the future looks like, learning how new
technologies can help, and how our role might change to
allow us to more actively manage the electricity flows across
our network.
Enabling the transition to a low carbon future
The Government’s Carbon Plan sets ambitious targets to reduce
emissions by 18 per cent on 2008 levels by 2020. In order to
achieve this, 40 per cent of our electricity must come from low
carbon sources by 2020. We see these challenges as an exciting
opportunity for innovation.
Our commitment to the low carbon economy and innovation is
long-standing. Since 2005 we have built up a portfolio of projects
that will enable the transition to a low carbon future. We want to
be recognised as a low carbon leader in our industry, leading the
way by ensuring the decarbonisation of electricity and playing
our part in enabling the electrification of heat and transport.
Figure 4.28: Demand, aggregated demand and typical wind
generation over a 24 hour period
Demand (Giga watts)
90
80
70
60
50
40
30
20
10
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Total charge
Time (hours)
Demand
Aggregate
Wind
With the new approach, we are able to quantify the benefits
of alternative investment strategies such as demand response
and active network management techniques to understand
the trade-offs between operational measures and capital
expenditure. It will also be important to consider network
losses in the process of optimising reinforcements aligned
with low-carbon strategic objectives.
Business plan | >pg45

Impacts on DNOs
We share the low carbon future vision and see the challenges
it presents as opportunities to bring more value and reliability
to our customers. If extensive reinforcement is to be avoided
then smarter means of accommodating energy resources and
of managing demand will be essential. The low-carbon future
presents a scenario where wind generation will be the most
significant generation source. This will provide low carbon energy
for millions of home and businesses. This will also provide new
challenges in forecasting generation output and in keeping the
electricity system in balance on a second-by-second basis.
The challenges we face as an industry should be welcomed as an
opportunity to change and improve. These challenges will impact
distribution network daily load profiles. The increased use of
wind and micro-generation and the new demands from electric
vehicles and heat pumps will require close monitoring to respond
to them. Over time the real-time management of electricity
demand may become more critical to the successful delivery of
the low carbon transition and to optimise network investment.
Smart Grids: The road to DSO
Moving to a low carbon economy, with increased customer
interaction to manage the network, our role may change.
The traditional role of a DNO is to passively distribute electricity
along its networks to customers. A DNO does not generally
have the tools to manage demand and generation flexibly.
As we move into a low carbon future, the relative inflexibility
of traditional supply and demand is expected to change. As
intermittent generation is brought on-line and new innovative
technologies are harnessed, we must adapt our networks to
facilitate this new flexible system. This gives rise to the concept
of ‘Smart Grids’.
As we potentially move towards new and innovative smart
technologies, we should consider if moving to become a
Distribution System Operator (DSO) would be of benefit. A DSO
would provide a highly flexible network to adapt to responsive
demand, by using electrical storage and controllable generation.
Flexibility could be achieved by offering our own new incentives
for customers or by using third party commercial aggregators.
The DSO concept is illustrated by the diagram in Figure 4.29:
Figure 4.29: Transition from a DNO to a DSO
Non-flexible demand
Non-flexible DG
EVs
Heat
Flexible demand
Cooling
Technical Aggregation
White
goods
Storage
Network
storage
Dispatchable resources
DG
contracts
Demand
response
Ancillary services
Enabling
infrastructure
Commercial
aggregation
By way of contrasting the current role of a DNO with that of a DSO
A Distribution System Operator (DSO) has access to a portfolio of responsive demand, storage and controllable generation assets that
can be used to actively contribute to distribution system operation. A DSO builds and operates a flexible network with the ability to
control load flows on its network. The combination of a highly flexible network and access to demand and generation response allows
the DSO to contribute to the increasing UK-wide challenge of system balancing.
By contrast, a Distribution Network Operator (DNO) continues to build in response to growth in maximum or peak demand. A DNO does
not have the ability or desire to influence demand and generation, and tends to introduce flexibility only to the extent that it supports
existing regulatory priorities (such as to reduce supply interruptions and the risk of catastrophic asset failure).
>pg46 | Business plan

Future network development plan
We are preparing for a journey that may take us from DNO to
DSO. The pace of our journey is closely linked to the uptake of
low carbon technologies – which in turn depends on factors
such as customer acceptance, economic conditions and
government policies.
Change will be gradual, with incremental innovation and
implementation. This incremental investment approach will
allow us flexibility until we have more certainty on the impact of
the low carbon transition, and allow us to avoid any unnecessary
investments. We do expect changes to accelerate when certain
technologies gain critical mass. This might well be the tipping
point at which we move from an incremental to integral solution
approach and when we have become a DSO.
Based on the current forecasts of low carbon technology uptake,
we do not expect to reach this point until well beyond the end
of the forecast period into the mid to late 2020s. Nevertheless,
in preparation of this change we will need to start investing
in enabling technologies such as increased monitoring and
communications infrastructure during the forecast business plan
period (2015 to 2023).
We have spent considerable effort, developing our thinking
on how this will evolve and have captured this in our ‘Future
Network Development Plan (FNDP)’, which provides guidance for
our activities throughout the forecast business plan period
and beyond.
This not only provides an exhaustive up-to-date review of
technical and commercial solutions, but also brings these
together into logical solution sets aligned with those developed
in the cross-industry ‘Smart Grid Forum’ which is jointly chaired
by Ofgem and the Department for Energy and Climate Change
(DECC). In line with our FNDP we are trialling a series of
technologies and approaches to develop our thinking on the
best means to deliver the efficient development of our network
in the future.
Figure 4.30: Transition to a low carbon future: response through innovation
Real time thermal
ratings
Using network
capacity more
effectively
Controlled generators
Connect more by
managing generators
output
Flexible networks
Making our networks more
flexible by managing our
power flows and other
limitations and allowing us to
dynamically reconfigure our
network
Smart enablers:
automation, network monitoring, comms,
IT, design, smart meters
Electricity storage
Creating additional
flexibility to manage
peak demand
Intelligent EV
charging
Managing EV
charging rates to
moderate the
demands on our
network
Demand side response
Managing domestic and
commercial electricity
demand directly or through
third parties
Low Carbon Network Fund
We are currently trialling innovative solutions to ease the
transition to a low-carbon future. This is being funded by the
Low Carbon Network Fund, which has two elements for funding
projects – non-competitive (LCNF Tier 1) and competitive
(LCNF Tier 2). In addition to research and development, an
important aspect of the Low Carbon Network Fund is knowledge
dissemination. We are sharing the knowledge gained from
our projects with key stakeholders including the entire DNO
community and other interested parties using a variety of
methods to appeal to a wide audience.
Five LCNF Tier 1 projects have been registered to date:
Short-term energy storage on the distribution network
(June 2010) – investigating how storage can be an alternative
to traditional reinforcement of substation when additional
capacity headroom (either thermal or voltage support) is needed
infrequently for limited periods of time to avoid building network
capacity where the long-term demand is uncertain.
Distribution network visibility (September 2010) – demonstrating
the business benefits of collection, utilisation and visualisation of
network data that is already available to improve our operational
and investment decisions e.g. to improve time required to
connect new customers.
LV current sensor technology evaluation (December 2011) –
the first collaborative project (with Western Power Distribution)
evaluating a range of network monitoring solutions that can
help us understand the available network capacity to enable
us to minimise customer disruption or delay when low-carbon
technologies are deployed future.
Validation of Photovoltaic (PV) connection assessment tool
(January 2012) – This project is testing the validity of our new
planning tool, which assesses the impact of concentrations
of small scale generation on our networks e.g. solar panels,
enabling us to provide a better and faster service to
our customers.
Business plan | >pg47

Smart urban low voltage network (July 2012) – Most LV networks
are passive, meaning they cannot be actively reconfigured to
match user requirements. We have been working in collaboration
with TE Connectivity, to develop a new solid-state switching
technology for use these networks. The devices developed can
provide us with remote switching and re-configuration of the
LV network. The system also has the ability to provide visibility
of power flows on the network, using the near real-time
communications and built in sensors. This enables extensive
load monitoring so we can better understand the live state of the
LV network.
Two LCNF Tier 2 projects have been awarded funding and a third
proposal has been submitted:
• October 2010: Low Carbon London – Ofgem awarded
£24.9 million to our first flagship project, supported by a £5
million investment by us
• November 2011: Flexible Plug and Play – awarded £6.8 million
for a second flagship project
• Smarter Network Storage – the aim of this proposed project is
to install a storage plant to solve a network constraint and to
investigate additional revenue streams for providing network
services. Electricity storage could provide value for customers
by reducing the need for network reinforcement and has
wider system benefits such as providing network services such
as reserve and response to help keep electricity supply and
demand in balance
Low Carbon London
January 2011 to June 2014
Low Carbon London is a £30 million pioneering learning
programme. It uses London as a test area to support the
development of a smarter electricity networks that can manage
the demands of a low-carbon economy. It is a collaborative
programme with partners including the Mayor, Transport
for London, academia, and leaders in low carbon and
smart technologies.
Through a series of trials we are monitoring the electricity
demand of homes and businesses across London, and
testing a number of initiatives designed to encourage
changes in electricity usage patterns. We will be improving our
understanding of the effect that the low-carbon transition will
have on the operation of the electricity network. Low Carbon
London is trialling some ground-breaking commercial contracts
with larger industrial and commercial organisations, aimed at
reducing electricity consumption at times of peak demand by
tapping into surplus small-scale generation. The understanding
gained from these trials will help us to ensure the most
cost-effective approach to providing a sustainable electricity
network to meet demand in a low carbon future. The trials
started at the beginning of 2012 and will run through to the end
of 2013, with final reporting delivered in early 2014.
Progress to date
We have established a common demand response contract with
three external aggregators to enable the sign up of customers to
reduce load at peak times on selected substations. 13.8MW has
been signed up and further 115MW is in pipeline.
Distributed generation and active network management trials:
approximately 30 sites currently identified, 12 being signed up
with a further eight in advanced stages of negotiation. These
trials are aimed to inform how we can maximise opportunities
for low carbon, distributed and micro-generated electricity,
respond to new demands on the electricity network from a low
carbon economy and match local energy demand with national
low carbon energy demand. We will trial techniques to assess
how we can best enable, facilitate, and manage distributed
generation to improve security of supply and reduce network
investment costs.
First customers identified and signed up for electric vehicle
trial: 30 residential and 70 commercial participants with access
to more than 750 charging points across London through
collaboration with the Source London e-mobility scheme.
This will allow us to monitor electric vehicle charging behaviour
and its impact on the electricity network; investigate how EV
charging can be influenced by time-of-user tariffs to influence
when customers charge to seek to minimise the cost of
expanding the network.
>pg48 | Business plan

Smart meter rollout – approximately 6,500 customers signed
up; with a further 500 expected by the end of November 2012.
We are planning for the roll-out of dynamic time-of-use tariffs
to these customers by December 2012 that will see their tariffs
change over the day. We are also using these meters to provide
data that informs smarter network operating techniques and to
improve our real-time understanding of power flows on
the network.
Flexible Plug and Play
January 2012 to December 2014
Flexible Plug and Play aims to enable faster and cheaper
integration of renewable generation, such as wind power,
into the electricity distribution network. The project will achieve
this by:
• Trialling innovative technical and commercial solutions with
real customers (renewable generation developers) to provide
the most flexible and cost effective means of connecting
renewable generation to the distribution network in a trial area
of around 700km 2 between Peterborough, March and Wisbech
in Cambridgeshire. These solutions would seek commercial
arrangements which provide the customer with a non-firm
(interruptible) connection which allows the generator’s
output to be changed by us to match the prevailing network
conditions and needs
• Deploying smart technologies on the network that will make
best use of the existing electricity network through, for
example, dynamic rating of overhead lines based on
weather conditions
• Allowing real-time management of network constraints
through active control of generator output (for those
generators with non-firm connections)
• Deploying the first Quadrature Booster on the distribution
network; the Quadrature Booster will balance the load on
parallel circuits by forcing the power away from the
weaker circuit
• Developing an investment modelling tool that will determine
the optimum network investment from both an economic and
carbon emission perspective
Flexible Plug and Play will contribute towards the Department
of Energy and Climate Change’s (DECC) target of 30 per cent
of the UK’s electricity to be generated from renewable energy
sources by 2030 by enabling the faster and cheaper integration
of renewable generation to the network.
The first public deliverable from the Flexible Plug and Play
project, the first Stakeholder Engagement Report, was delivered
successfully in September 2012 11 . The major conclusion from this
stakeholder engagement exercise is that generator curtailment is
seen as offering substantial opportunities, implemented as part
of Active Network Management schemes optimising the export
of multiple generation developers onto the distribution network
against known network constraints. Active Network Management
can be used in conjunction with other smart technologies such
as dynamic rating of lines or other assets. Generation developers
had no concerns about being offered connections with some
form of curtailment, as long as the implementation was
transparent and the estimate of curtailment had low uncertainty.
The learning from this exercise has informed current activity on
the project to develop proposed commercial arrangements for
non-firm connections.
The project has had very positive engagement with many of the
generation developers in the trial area. To date, five of these
developers have received business as usual connection offers
and have been invited to participate in the project in parallel.
Three of these developers have already opted in to the project,
with decisions pending from the other two. These developers
will receive their formal flexible plug and play connection offer
by March 2013, and the business as usual connection offer also
remains open. Budgetary estimates developed to date indicate
that flexible plug and play connection offers will be in the range
of 33 per cent to 90 per cent cheaper than business as usual
connection offers, representing a significant cost saving for
the developer and thus providing a key enabler for faster and
cheaper integration of renewable generation to the
distribution network.
11
http://www.ukpowernetworks.co.uk/internet/en/innovation/
learning-zone/
Business plan | >pg49

Innovation!
Energy storage
Flexibility of the electricity system is recognised as vital for a
low carbon energy sector, particularly considering the increased
penetration of intermittent renewable generation and the potential
misalignment between times of peak generation and times of
peak demand. Energy storage is one source of flexibility that has
significant potential to support the system at the distribution
level by mitigating the misalignment of these peaks.
We commissioned an energy storage system at Hemsby
in April 2011. For the first year it operated as a source
(export) and sink (import) of reactive power. Subsequently
it has been operated to enable real power exchanges
on the network through charging and discharging of
the battery. The results so far are positive and have
verified that the system is having the desired
impact on the network in terms of both real and
reactive power, as generation and demand
changes over time. Further tests are now
planned to demonstrate how we can
improve the management of the
distribution network and address
some typical network issues using
energy storage.
>pg50 | Business plan

Business plan | >pg51

5 Process: how we are planning
for the future
This 2012 business plan is our first public proposal for the RIIO-ED1 period
(2015 to 2023). At present, this plan is largely based on conventional approaches
to network expansion and asset renewal with minimal deployment of smart
technologies. However, by 2013 we intend to integrate a range of smart
technologies within our RIIO-ED1 business plan. We have included a high level
view of the costs and benefits of smart metering in this plan.
This chapter provides an overview of the methods and tools we use in the
construction of our business plan. It also outlines the impact of the future
challenges, how we are incorporating stakeholder views and summarises the
innovative thinking we are using to meet the challenges of a transition to a
low-carbon economy.
We explain the tools used to develop detailed demand scenarios, assess the
uncertainties associated with the deployment of low-carbon technologies, the
impact of smarter networks and how we will improve the management of our
existing assets.
>pg52 | Business plan

Business plan | >pg53

5.1 Our stakeholder engagement activities
We are undertaking a range of engagement activities with
diverse groups of stakeholders ranging from domestic
customers, commercial and industrial customers, local
governments, major energy users, customer organisations
and those representing the community sector. We are testing
all aspects of this business plan with stakeholders through
different forums including willingness to pay surveys, specific
stakeholder events on key topics and one to one meetings.
Prior to developing the business plan, we have sought
stakeholders’ views of what they consider to be the critical
issues and areas where we can improve performance. We
have explained how we are developing scenarios to underpin
our future plans. We have also provided detail on the output
measures that Ofgem will use to incentivise our performance
and against which customers can judge our progress. It
is important to test these output measures and incentive
mechanisms with stakeholders to ensure they are relevant to
stakeholder views.
We promote a broad dialogue with stakeholders in each of our
networks to ensure that our plans recognise the interests of
the local communities we serve.
Stakeholder engagement strategy
Our stakeholder engagement objective is to ‘develop
arrangements that will provide meaningful opportunities to
a range of our stakeholders to influence the direction of our
thinking on network development and business operation on an
on-going basis’.
In delivering our strategy we have followed the
following process:
• Prepare for engagement: We have established a range of
stakeholders with whom to engage, the issues appropriate
to engage them on and an understanding of the support
stakeholders need to allow them to effectively participate in
our engagement processes
• Engage with stakeholders: We have developed different
formats and methods for engagement to facilitate participation
from different groups
• Record, assess and respond: To secure the full value of
engagement we have recorded the views expressed, assessed
the options available to address issues raised and ensured
transparency about the impact that the engagement has had;
where engagement does not impact on our plans, we will
provide clear reasoning for this outcome
Stakeholder engagement is an on-going process which has
been embedded in our business as usual plans and will continue
during and after the current RIIO-ED1 assessment. We will
also continually evaluate the effectiveness of our stakeholder
engagement strategy. To support this process, a set of criteria has
been developed against which we can assess performance. We
will use this process to ensure that our strategy
remains applicable.
Addressing stakeholder feedback
It is not sufficient to merely listen to our stakeholders: we must
assess how to address the issues they have raised and provide
prompt and decisive feedback on the conclusions we have
reached. It is only by maintaining open and proactive two-way
communication with our stakeholders that we will build trust,
allow working relationships to prosper and establish a solid
stakeholder partnership.
We aim to promote a broad dialogue with stakeholders in each
of our operating regions to ensure that our plans are aligned to
the interests of the communities we serve.
Engaging on our forecast business plan
We launched a series of stakeholder consultations in 2011 as part
of the development of this forecast business plan.
Stakeholder consultation: ‘scenarios’
Scenario planning aims to explore possible futures for the UK’s
energy networks in the context of a low-carbon economy. We
recognised that stakeholders should be involved from the earliest
phases of our business planning cycle, so we involved our key
stakeholders in a review of the scenarios we developed and
provided the opportunity for comment, in order to refine and
improve our plans.
We recognised the diverse nature of our networks by developing
regionally-specific scenarios and seeking the views of
stakeholders from each of our three network areas. We hosted
four dedicated stakeholder events – three regional workshops
and an online forum – to debate four very different scenarios and
the resulting potential planning assumptions that would then
underpin the development of our 2013 forecast business plan.
These events and the generated outcomes are described more
fully below.
At each workshop the business planning process was explained,
the scenarios that had been developed were presented and
attendees were given the opportunity to review, discuss and
challenge the scenarios.
The scenarios focused on the main elements which we believe
will influence the requirement for future network capacity
in our three regions: economic growth and the take-up of
green behaviours and technologies. We gathered a range of
stakeholders’ views on the different assumptions that made
up each scenario and the likelihood of those assumptions
being realised.
In parallel with the workshops, we hosted an online forum via
our stakeholder engagement website to give stakeholders a
further opportunity to provide feedback on the scenarios.
Over 50 people visited the web site, 11 of whom offered
feedback on one or more of the scenarios.
>pg54 | Business plan

Stakeholder consultation: ‘outputs’
The development of meaningful ‘outputs’ – where an output is
the delivery of a product or level of service – is another essential
process within the overall review of our investment plans for
2013. It was the focus of the second phase of our stakeholder
engagement around business planning.
Ofgem established a number of output categories in which we
must ensure delivery during the forecast business plan period
(2015 to 2023). As an input to our planning process, we wanted
to give our stakeholders the opportunity to explain how they
interpreted the outputs and to define what they regarded as
meaningful performance measures for our business. We were
also keen to hear their views on the potential outputs we
had developed.
During the autumn of 2011, we undertook four separate
strands of engagement in order to gauge the views of a broad
range of stakeholders: a workshop, an online consultation,
targeted interviews with stakeholders with expertise in one or
more of the output categories, and focus groups made up of
domestic customers.
The event was well attended: 62 stakeholders participated,
drawn from our three network regions.
From 12 October to 1 December, 2011, we gave our stakeholders
a further opportunity to comment on this topic via an online
consultation. We also made sure that the output materials that
were made available to the workshop attendees were published
on our stakeholder engagement website.
Participants were asked to provide their opinions on both the
existing outputs and possible new proposed outputs in each
category, along with any suggestions of their own. A total of
21 stakeholders responded to the online consultation.
In November and December 2011, in the interests of ensuring
the widest possible coverage of views, we conducted interviews
with stakeholders who were unable to attend the workshop.
Examples included: an environmental charity; a local authority
street works manager; and a local authority lighting engineer.
The primary objective was to facilitate an in-depth discussion
about a couple of the output categories, as selected
by interviewees.
While the event, online consultation and interviews enabled us
to consult with a diverse range of stakeholders, they were not
ideal forums for engaging with domestic customers. It is our
belief that we should seek to include this stakeholder group
wherever possible in the planning process and hence we opted
to organise a number of focus groups. Each group was made
up of a mixture of customers who had previously interacted
with us (due either to experiencing a power cut or requiring a
connection) and customers who had not. The objective was to
identify activities that domestic customers regarded as being
important for us and thereby stimulate ideas as to what would
constitute ‘good’ and ‘great’.
Critical friends regional panel process
Following our extensive consultation with stakeholders in
2011, we have used the feedback from the various engagement
forums to test issues to include in our business plan with three
critical friends panels. These panels were established in 2012
and involved one panel for each of our three separate
distribution areas.
During the course of 2012 and into 2013, we expect that over
90 critical friends will participate in this process. The panels have
been a very useful sounding board to test strategies, ideas and
concepts for inclusion in the final business plan.
The critical friends panel contains representatives from customer
groups, vulnerable customers, major energy users, developers,
local governments, industry organisations, energy sector
participants, water utilities and others.
Not all issues presented to the panels will be included in the final
business plan. The important part of this process is to critically
test concepts with stakeholders. Equally, specific issues raised by
stakeholders will be included in the final plan.
The panel process is on-going over 2012-13 and will conclude
in April 2013, prior to the submission of our final business plan
to Ofgem.
Assessing what our customers and
stakeholders want
We have commissioned a programme of research designed to
inform our future investment strategy. The research will derive
what our customers’ priorities and their ‘willingness to pay’ for
different levels of performance. The pilot results are promising
and will be ratified through the main research programme that
will deliver more comprehensive results.
Our pilot programme uses four main elements to research
customers’ willingness to pay for additional investments:
• 14 focus groups with domestic customers
• 21 business customer teleconferences
• 1200 Phone-Post-Phone (PpP) stated preference interviews
with domestic customers preceded by 160 pilot interviews.
This is currently being undertaken
• 300 PpP stated preference interviews with business
customers, preceded by 160 pilot interviews. This is currently
being undertaken
The data from the survey is presented in terms of a score to
rate how willing customers are to pay for a programme or
investment. This score is based on the status quo, which is given
a score of zero. Essentially the more willing the customer is to
pay for the investment the greater the score will be. It can also
be negative, showing customer’s unwillingness to pay.
This score also has a corresponding statistical robustness score
that allows the quality of the result to be assessed. Again the
higher the robustness score, the more reliable the data is.
The greater the willingness to pay score and the robustness of
data score, the more attractive the potential investment is with
the sampled customers and the more confident we can be in
the result. Higher robustness scores illustrate that a result is
statistically sound, suggesting we can have greater confidence in
the indicated willingness to pay.
Based on the pilot data from the willingness to pay survey, we
show four examples of the insights that we can achieve through
such research. We expect to be able to draw a number of
conclusions once the work on our main survey is complete.
Business plan | >pg55

Figure 5.1: Domestic customers’ willingness to pay for
investments to support low carbon technologies (all networks)
Figure 5.3: Willingness to pay for quicker time to connect
(all networks)
0.6
0.35
Willingness to pay
0.5
0.4
0.3
0.2
0.1
0
0 1 2 3 4 5 6
Robustness of data
Investment to enable greater uptake of electric vehicles
Investment in infrastructure to enable greater uptake of
low carbon electric heating technologies
Willingness to pay
0.30
0.25
0.20
0.15
0.10
0.05
0.00
0 0.2 0.4 0.6 0.8 1 1.2
Robustness of data
As now, i.e. within 90 days
30 days quicker than new, i.e. within 6 months
60 days quicker than now, i.e. within 30 days
75 days quicker than now, i.e. within 15 days
r
Investment to enable large-scale renewable generation
(e.g. onshore wind farms, biomass plants, etc.)
Investment to enable uptake of micro-generation e.g.
solar panels etc.
This indicates that customers are willing to pay more for a
simple, low voltage, connection e.g. domestic connection, which
is completed within 15 days compared to longer time periods.
Figure 5.4: Willingness to pay for quicker time to connect
(all networks)
This indicates that customers are willing to pay for the additional
investments to allow for the connection of low-carbon
technologies with a greater preference for low-carbon generation
and heat compared to electric vehicles.
Figure 5.2: Customers’ willingness to pay for investments to
allow us to automatically detect loss of supply events
(all networks)
Willingness to pay
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0 2 4 6 8
Robustness of data
Business
Domestic
Willingness to pay
0.8
0.6
0.4
0.2
0
-0.2
-0.4
-0.6
-0.8
0 0.5 1 1.5 2 2.5 3
LPN
EPN/SPN
Robustness of data
Automated text messages to
registered customers
Automated update calls and
follow-up after power cut
Additional information services
This indicates that domestic customers in EPN and SPN are less
willing to pay for additional information than customers in LPN.
This indicates that both business and domestic customers are
willing to pay for investments in communication infrastructure
to allow us to know immediately when they have a loss of
electricity supply.
>pg56 | Business plan

5.2 Developing the plans for expanding
our network (load related forecast)
Requirements for network reinforcement and expansion
are driven by locational demand growth. The future
growth of electricity demand will be driven by a range of
well-established and emergent factors. We face increased
uncertainty due to the emergence of new applications
for electricity such as electric vehicles and new heating
technologies. We have worked with stakeholders to develop
realistic baseline scenarios for each of our networks to inform
future network reinforcement aligned with the needs of
our customers.
Future network investment requirements are uncertain given the
anticipated transition to a low-carbon economy. Our approach
to business planning seeks to recognise this uncertainty, inform
our plans with a wide range of stakeholder views to better
understand the uncertainty and ensure the framework is
adaptable to change over the longer regulatory period.
The requirement for new network capacity is driven by the
demand at each of our substations. A range of external factors
influence this demand. Historically, it has primarily been driven
by the number of new households and the rate of economic
growth in each of our areas. In the future we expect to see
growth in distributed generation and low-carbon technologies in
response to Government policies to decarbonise the UK economy.
There is significant uncertainty regarding the types of technology
that will be deployed and associated timings.
Alongside this, the electricity industry is developing alternative
responses to these challenges through ‘smart grid’ developments
to help to reduce the cost of future network reinforcement.
During the last 18 months we have embarked on a major
development of our load (and non-load) forecasting capabilities.
Our new load related expenditure model allows us to take a
longer-term view of multiple growth scenarios and enables
evaluation of these ‘smart grid’ solutions.
The diagram in Figure 5.5 shows at a high level the load related
expenditure forecasting process.
Figure 5.5: Forecast business plan preparation
General economic uncertainty
Economic growth is a significant factor in increasing demand for
electricity and hence the required capacity of our networks.
The UK, the wider European and global economies are facing a
significant period of continuing uncertainty. The rate of growth in
the economy affects our network expenditure levels, as it drives
both new network capacity requirements and new connections
volumes. The graph details the range of independent forecasts
by the Office of National Statistics (ONS) and Office of Budget
Responsibility (OBR) for Gross Domestic Product 12 (GDP) growth
in the UK. It illustrates the high degree of uncertainty regarding
the timing and extent of economic recovery. These independent
forecasts of GDP assume that recovery will happen gradually
through the forecast period.
A more buoyant economy is likely to mean that demand
increases, both through current and new connections. Also
customers (both domestic and business) may be more willing
to invest in reducing their emissions and Government may have
more scope to provide incentives to facilitate the take up of
emission reduction technology.
The converse is likely to be true if the rate of economic growth
is slow. A slow growth rate may mean that customers are even
more sensitive to price changes.
Figure 5.6: Current ONS, OBR GDP forecast
8%
6%
4%
2%
0%
-2%
-4%
-6%
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
12
In our forecasting of growth in electricity demand we use a different
measure of economic growth ‘Gross Value Added’ (GVA). This is directly
related to GDP, but is not forecast as widely. To illustrate the point
around uncertainty in economic recovery we have chosen instead to use
independent forecasts of GDP
ED1 Business plan preparation
Scenarios
Load & non-load
related network
data
Selected levels of
performance
(outputs)
‘State of the art’
models
• Asset Replacement
Model
• Load Related
Model
• Smart Grid Forum
WS3
Planners assess
recommended
interventions
Plan tested for
deliverability
and
Financeability
Expenditure
Plan for the
next 8 years
Consistent and
evidence based
inclusion of
innovative solutions,
as part of normal
business practices
Smart Solution
sets, trialled in IFI
and LCNF projects
Revised standards
& policies to
consider smart
interventions
Cost of capital,
supply chain
constraints
Business plan | >pg57

Uncertainties around the uptake of low
carbon technologies
The UK is seeking to decarbonise its economy and this has
influenced our future planning scenarios. The UK is committed to
reducing carbon emissions by 80 per cent by 2050 with medium
term goals being set to be achieved by 2020. The reduction will
come both from increased renewable sources (heat and power)
and reduction in emissions.
The achievement of these medium term targets is increasing the
incentive for smaller scale renewable generation to connect to
our network, encouraging new electricity demands to connect
and is changing stakeholders’ views of the role of the network.
In the long-term this will alter how we build and operate our
networks and what services we need to deliver to our customers.
Exactly what technologies will be deployed to achieve these
targets remains uncertain. For example if ground and air
source heat pumps are the key technology deployed to meet
the renewable heat obligation then the consequences for our
networks could be significant. Conversely, if biomass and biogas
are the key technologies then there will be a lower impact on
our network.
Depending on penetration rates, these could also eventually
result in electricity consumption increases of up to 50 per cent. If
such scenarios were to materialise, there would be a significant
need to reinforce our networks. Such extensive reinforcement of
distribution networks could lead to significant price increases for
customers, risk damage to the UK economic competitiveness as
well as result in significant disruption through increased
street works.
More distributed generation
To help meet carbon emission targets, the UK will be increasing
the amount of electricity generation from renewable sources.
The Department of Energy and Climate Change has stated that up
to 18GW of offshore wind capacity could be available by 2020.
A significant increase in renewable generation is expected to fall
within the forecast period from 2015. In addition, there is likely
to be wider use of distributed energy resources, e.g. solar panels
on homes and commercial property so that power flows on our
networks become more varied.
Operating in a low-carbon world
We are already considering the challenges of operating in a
low-carbon world to provide a long-term view as to the best
approach to mitigate the impact on electricity networks.
We welcome this challenge as an opportunity to provide
greater value to our customers in a low carbon future. We are
already seeking new ways to accommodate distributed energy
resources and combine them with smarter management
and control of electricity demand through technological and
commercial innovation.
To better understand the potential impact on our network of all
of these issues we have developed:
• A range of possible planning scenarios with our stakeholders
• A scenario modelling tool that can convert the inputs from the
planning scenarios into an overall impact on electricity demand
at the network level
• A detailed load related expenditure modelling tool that uses
the scenarios and will integrate smart solutions to produce a
cost forecast for interventions at each voltage level on
each network
These are described in more detail below.
Forecasting electricity demand: developing our
future planning scenarios
Our scenario modelling tool seeks to analyse the effect of
varying the uncertainties we described above. This includes
general economic growth, low carbon technology deployment
in response to the policies and how market mechanisms may
alter customers’ energy consumption behaviour. Taken together
these factors determine the general growth in demand and
the deployment and expected use of the emerging low-carbon
technologies. The key factors within the model are:
• Economic growth: rate of economic activity
• Technology deployment: impact of the deployment of low
carbon technology on the distribution network
• Market mechanisms: impact of new electricity market
mechanisms on the distribution network
The elements of the first two key factors are listed in Figure 5.9.
The market mechanisms are:
• Time of Use tariffs – where tariffs change over the day or in
response to balance of energy supply and demand
• Domestic customer response
• Industrial and commercial customers response
• A range of possible planning scenarios with our stakeholders
We worked in partnership with Element Energy, a specialist
energy consultancy to develop the assumptions and scenarios.
The data for each of our assumptions has been chosen from
robust and respected primary sources e.g. Office of National
Statistics and their experience of developing similar studies for
DECC, Committee on Climate Change and the Energy Savings
Trust. The resulting models provide credible views of the effect
of incentives on competing technologies in solving specific
policy objectives.
We have created a range of scenarios for stakeholder feedback
based on selecting high, medium or low choices against the
three main factors, economic growth, technology deployment
and market mechanisms.
Our core planning scenario: Presenting our
original scenarios
Scenario planning is a core process within the overall review of
the investment plans and aims to explore possible futures for the
UK’s energy networks in the context of a low-carbon economy.
We started from the premise that the diverse nature of our
networks would necessitate regionally-specific scenarios and
that, consequently, we should seek the views of stakeholders in
each of our network areas. To this end, we hosted four dedicated
stakeholder events; three regional workshops and an online
forum. Through discussion of each of the scenarios in turn,
we gathered a range of stakeholders’ views on the different
assumptions that made up each scenario and the likelihood of
those assumptions being realised.
>pg58 | Business plan

What did our stakeholders say
Our stakeholders believed that we are about to face a tactical
issue with regard to the uptake of low carbon technologies. Some
challenged the idea that the UK will be off gas by 2050 and believed
that we could relieve some of the demand on the networks by
facilitating CHP to reduce the amount of electric heating. Others
believed we could also decrease load demand at peak times through
innovative solutions such as controlling fridges and other electrical
heating/cooling devices. Stakeholders commented that we now have
a good opportunity to position ourselves in the middle of this now.
Our business plan says in 2012
Our approach to planning, based on stakeholder-informed scenarios,
reflects the on-going uncertainties and risk surrounding the transition
to a low carbon economy. We share the views of our stakeholders
that through innovation we can utilise the challenges of a low carbon
transition as opportunities to deliver our customers better service.
To prepare for the low carbon transition, we currently run two large
demonstration trials to better understand new smart solutions
to reduce peak demand. These trials are set up with a multitude
of stakeholders and customers. We welcome the views of our
stakeholders on this topic and are planning to incorporate how we
will be using smart technologies and the potential transition to active
management of our networks.
Do you think we can do more We welcome your views
Go to our stakeholder website at
http://yourviews.ukpowernetworks.co.uk
Business plan | >pg59

Stakeholder engagement
In the workshops and in the online feedback forms submitted,
a number of issues were raised generally about the scenarios or
came up repeatedly when specific scenarios were discussed.
A frequently expressed view was that business and domestic
users might respond differently within each scenario, and that
there would be some value in exploring likely experiences for
both sectors.
A number of technologies were mentioned repeatedly.
Significant increases in technologies such as wind power,
both onshore and offshore, were frequently questioned by
our stakeholders.
The general view was that the DECC forecast for the development
of onshore wind was somewhat optimistic due to on-going
public opposition, planning constraints and the like. It was also
felt that there should be a greater focus on other technologies
that may well have a significant impact in the future, such as
Combined Heat and Power (CHP) and energy from waste.
We have used this feedback as the basis for an additional
‘hybrid’ scenario which contains elements of the original
scenarios but takes a more conservative approach in a number of
areas – one being the take-up of green technology in its various
forms. We have used this scenario to define the basic planning
assumptions that underpin our business plan.
Economic growth
The overwhelming view from our stakeholders was that the
current poor economic conditions were exceptional and that
economic growth would return in time. However, there was little
consensus on when this would occur. In addition, there was a
general expectation from our London stakeholders that London
had been relatively insulated from the worst effects of the
recession and that, ultimately, growth in London would return
to its previous high levels.
Stakeholders suggested that we should put more weight on
long-term trends for economic growth, rather than the more
volatile short-term effects. We have therefore adopted longer
term views of key the economic measures of Gross Value Added
(GVA – the income generated by individuals and businesses in
the production of goods and services) and housing growth. These
trends are shown in the two graphs.
Figure 5.7: Long-term trend in regional GVA growth
12%
10%
8%
6%
4%
2%
0%
-2%
-4%
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
Figure 5.8: Long-term household growth trend
3%
2%
2%
1%
1%
0%
-1%
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
Technology deployment
There was a widely held view that projections of the levels
of penetration of the Government’s favoured low carbon
technologies, such as heat pumps, electric vehicles, and small
scale renewable generation, are highly optimistic. The rationale
for this was that significant on-going levels of financial support,
from either Government or from customers, would be required to
deliver the high levels of take up suggested.
Market mechanisms
EPN LPN SPN
There was considerable debate about whether individual
households and companies were likely to be receptive to price
signals, such as time-of-use tariffs. There was great scepticism
that people would modify their behaviour by, for example,
charging their electric vehicles or operating certain appliances
at specific times of the day or night. The conclusion was that
significant incentives would be required to drive such changes
and that there is little evidence that these are likely to be
available. On this basis and in the absence of any information
as to possible incentive arrangements, we have assumed that
few customers will modify their usage and hence market
mechanisms are likely to have a minimal impact on demand.
This assumption could be reviewed subject to any
future announcements.
Subsequent to our stakeholder engagement on our scenarios
DECC and Ofgem announced that they would be sponsoring
industry discussions on planning scenarios. We have played an
active role in these discussions and our earlier engagement
has given us a real insight into stakeholders’ views which
could be shared as part of this process. This culminated in the
development of a set of scenarios (shown in Figure 5.9) during
the spring of 2012 which we are considering as part of our
preparation for our forecast business plan submission
in 2013.
East of England London South East
>pg60 | Business plan

Discussions with industry
Figure 5.9: Core planning scenarios
Core planning scenario to take forward
Planning scenario Selected assumption to be utilised EPN LPN SPN
Economic assumptions
Economic growth (per annum) 20 year average of regional GVA statistics 5.40% 6.10% 4.50%
Population growth − historic Average of regional household growth over period from 0.93% 0.95% 0.78%
(per annum)
1992 to 2008 (DCLG statistics)
Domestic stock – thermal efficiency Defra Reference energy efficiency scenario 931k 542k 562k
improvement (houses improved
by 2023)
Domestic cooking/
Defra Market Transformation Programme – reference energy efficiency scenario
lighting/appliances
Technology deployment assumptions
Heat pump uptake (to 2023) RHI incentive applied at proposed rate to 2030.
(Take up based on EE assessment of house type suitability
and analysis of customer response to incentive.) Some
assumptions are not an interest locally (heat pumps are
not really used in certain districts). Investing to save is not
what people are thinking of
233k 61k 121k
Feed in tariff (uptake of

Figure 5.11: LPN peak load history/forecast
Mega watts
Figure 5.12: SPN peak load history/forecast
Mega watts
10,000
5,000
0
5,000
0
CAGR
2002-11: 1.7%
2011-23: 1.1%
2023-30: 1.1%
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
Year
Actual Domestic demand I&C demand
EV's demand HP's demand Long-term trend
CAGR
2002-11: 0.4%
2011-23: 0.3%
2023-30: 0.3%
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
Year
Actual Domestic demand I&C demand
EV's demand HP's demand Long-term trend
Applying the scenarios to our load-related
expenditure planning tool
Combining the scenario tool with our load-related planning tool
allows us to take a long-term view of the best way to develop
our network to serve the customers of today and tomorrow and
to deliver long-term value for money.
We have developed a new decision support tool with
Imperial College that is able to provide a long-term view
of the load-related investment programme.
It uses the growth in peak power from the scenario modelling
tool and applies this across a representation of our networks.
It can be adapted to present outputs based on different
scenarios,apply sensitivities and to provide insights around
the application of smart network technology.
Managing load related risk
As part of our current regulatory settlement, we are committed
to deliver a certain profile of network utilisation in each of our
network areas. This is measured by the Load Index (LI). Under
the load index methodology each primary or grid substation
on our network is assigned a load index number from 1 to 5,
representing an increasing level of utilisation.
We have developed our load related investment plans to broadly
deliver the same LI distribution profile at the end of the period
as it was at the start based on our best forecast in use of our
networks. To ensure we adequately manage utilisation over the
coming years, we use a well-established specialised short-term
tool, our Planning Load Estimation tool (PLE). This uses the latest
loading information, overlaid with growth projections. The PLE
model is used to ensure compliance with our licence obligations,
to calculate our regulatory performance (Load Index) and is used
to evaluate which projects should be accelerated, deferred or
changed to deliver our commitments to our customers.
Integrating our expenditure for connections
The above tools provide a total investment requirement to
reinforce our current networks. We also need to include
forecasts for new connections, for which we might need to
add new sites or additional circuits to connect new customers.
Some of the expenditure is included in our forecast business
plan with the remainder being recovered directly from the
connecting customer.
Our connections expenditure is derived from our connections
forecast model. The model uses our best view of connections
activity to determine the base line position. This is based on our
views of the competitive market segments, load categories and
volume data in the form of exit points, points of connection and
the number of expected orders.
We use an aligned view of external market assumptions in areas
such as housing and employments growth rates but apply these
to individual market segments within each licence area to derive
the expected expenditure.
Our 2013 forecast business plan will cover in more detail the
growth in competitor activity and market share assumptions as
well as the impact of the growth of green technologies which
could drive an increase in reinforcement associated with changes
in the mix of technologies being connected.
The model incorporates our network performance requirements
to meet planning practices and compliance requirements to
derive a long-term reinforcement schedule of investment over
a 40 year horizon.
>pg62 | Business plan

5.3 Developing our asset replacement
(non-load related) expenditure forecast
We have enhanced our understanding of the condition
of network assets and developed innovative techniques
to optimise intervention and expenditure plans for asset
replacement, refurbishment and maintenance whilst
managing network risk within pre-determined parameters.
Non-load related expenditure (NLRE) refers to the investment
in replacement, refurbishment and life extension activities of
existing assets across our three regional networks. The NLRE
programme’s scope includes the following asset categories:
• Overhead conductor
• Overhead support
• Underground cables
• Switchgear
• Transformers
• Civil structures and buildings
• Protection and control
Managing our assets effectively
Alongside the challenges faced in relation to expanding our
networks, we also have a major challenge to safely and
efficiently manage our ageing asset base. All three regions
comprise a significant proportion of assets over 50 years old, and
it is therefore important we undertake interventions in a timely
fashion to ensure we continue to operate a safe and reliable
network for our customers.
A key driver for investment is to maintain an acceptable level of
health across all our assets in order to effectively manage overall
network risk. This must be achieved, of course, whilst continuing
to deliver the best value for our customers.
We perform this by undertaking the right mix of maintenance,
refurbishment and planned replacement at the right times to
optimise whole life ownership costs and risks.
Managing asset health risks
Understanding asset health is key to informing our asset
management decisions. We utilise a wide range of information
relating to our assets that ensures we have a rounded and
accurate view of asset health in order to enable timely and
appropriate intervention. These information sources include
condition assessments, fault trends, risk assessments,
obsolescence information, maintenance history, inspection and
test results, manufacturers known defect reports and agreed
asset lives.
This data is used to assess the overall health of an asset, which
is categorised using the industry recognised Health Index (HI).
HI is an output measure Ofgem uses to evaluate the DNOs’
stewardship of their networks. The different HI categories are
outlined below.
• HI1: new or as new
• HI2: good or serviceable condition
• HI3: deterioration requires assessment and monitoring
• HI4: material deterioration, intervention requires consideration
• HI5: end of serviceable life, intervention required
Whilst we would ideally like to reduce the proportion of HI4
and HI5 assets on an increasing basis across all three of our
networks, we need to consider value for money delivered to our
customers and stakeholders in determining an appropriate level
of investment.
We have therefore taken a decision to retain broadly the same
proportion of assets in the different HI categories (1-5) at the end
of the plan compared to the beginning.
Enhancing our decision making
capability: modelling
In order to help us better interpret the rich asset health data
that we collect, and as part of UK Power Networks’ continuous
development of our asset management capability, we have
worked in partnership with industry experts to further enhance
our risk based investment modelling capability.
We have developed a suite of models to support our decision
making and long-term planning. These models include Asset Risk
and Prioritisation (ARP) models, Statistical Asset Replacement
Model (SARM), stocks and flows (Markov) modelling and a
Condition Index model, which are used to identify the existing
and predicted HI profile of the asset categories for which
they cater. The mechanics of the models and their levels of
sophistication reflect the characteristics and risk/priority of the
asset categories to which they correspond. Figure 5.13 indicates
which models are used for all major asset categories.
Figure 5.13
Asset Group
HI model approach
EHV OHL fittings and ARP model
conductor
EHV OHL support towers ARP model
EHV OHL support roles ARP model
HV OHL support poles ARP model
EHV UG cable (oil) ARP model
EHV (gas) cables
Statistical Asset Replacement
Model (SARM)
132kV transformers Statistical Asset Replacement
Model (SARM)
EHV transformer
ARP model
HV transformer – (ground Condition index model
mounted)
132kV transformers ARP model
EHV switchgear (GM) ARP model
EHV switchgear (GM) ARP model
primary
HV switchgear and other ARP model
LV swtichgear and other Statistical Asset Replacement
Model (SARM)
132kV circuit breakers ARP model
Link boxes
Markov model
Business plan | >pg63

ARP models
UK Power Networks has been working in collaboration with EA
Technology to enhance and expand upon existing modelling
techniques for establishing and managing asset health.
We have invested in the development of ARP models, which
build upon the long established methodology of Condition
Based Risk Models (CBRM), to support our high value investment
decisions. The ARP models provide decision support information
to 75 per cent of the HI reportable asset categories.
ARP has the capability of using asset health, risk and criticality as
a decision support tool to drive future investment interventions.
The new models employ our latest thinking on deterioration
of our assets, and are automatically fed from our most up to
date condition information held in our asset register, Ellipse.
The models are also driven by a significantly higher number
of asset condition and defect points, increasing the accuracy
and reliability of their output, than previously achieved. The
models and their outputs have undergone a rigorous testing and
calibration regime to ensure validity.
The ARP models use a combination of information relating to
an asset’s age, environment, duty and specific condition and
performance information to derive a health score for each asset,
underpinned by proximity to end of life (EOL) and probability
of failure. This score is then translated into the corresponding
HI category. This helps us to determine when an asset requires
intervention (replacement, refurbishment, retrofit or other
appropriate action). The detail of the ARP score formulation is
different for each asset category, reflecting the differing asset
lives and patterns of degradation. There is, however, a consistent
underlying algorithm and architecture.
The three supporting modelling approaches, SARM, Markov
(stocks and flows) and condition index models are used for the
assets that represent a smaller proportion of our asset base,
or where the benefit of collecting the additional condition
information required is not proportionate to the cost.
Statistical asset replacement model (SARM)
The SARM model uses statistical techniques to estimate the
volume of required interventions based on population level
assessments of asset lives and applies these to the existing asset
base in order to forecast replacement volumes. In addition, we
use current condition information to develop an age/condition
relationship, which is applied to the future age profile to predict
the evolution of the asset condition.
Stocks and flows modelling
The stocks and flows modelling approach was developed to
model asset condition and replacement volumes for linkboxes.
The approach models movement between conditions
independently of asset age and uses the estimated numbers
of assets (in 2012) in each of condition rating as a base line.
By considering the transitional probabilities (chance of moving
between conditions in any one year), the model calculates the
likely number of units to fail in each future year and hence
provides a forecast of interventions required.
Condition index model
We use a condition index model for HV ground mounted
distribution transformers which utilises age and condition data.
The model assumes straight line deterioration over the expected
life of the asset based on an average life modified by the asset’s
duty and observed condition.
>pg64 | Business plan

Innovation!
Online partial discharge mapping
The use of partial discharge measurement is a well-known
method of checking the condition of electrical insulation. Over
the past seven years, we have been actively involved in the
development of online partial discharge monitoring and
mapping techniques. An advanced substation monitor that
can remotely screen and locate partial discharge has
been developed.
We have developed the system under the Innovation
Funding Incentive scheme. The system is now
enabling an increasing number of preventative
cable and switchgear repairs to be carried out,
thus avoiding potential failures. A formal
policy has been developed and this
technology has been embedded
into the business in 2011.
Business plan | >pg65

Enhancing our decision making capability:
improving data quality
We recognise that the completeness and quality of our asset
data is crucial if we are to make the right asset management
decisions. As such we have embarked on a journey to improve
the standard of our asset information and our information
management practices. We have approached this in an
innovative way, acknowledging that in order to achieve
world-class standards of data integrity, we need to engage our
people at all levels of the organisation to ensure we specify,
collect, retain and retrieve information in the most effective way.
To measure and promote the quality of the data feeding into our
ARP models we have developed a completeness, accuracy and
timing (CAT) scoring methodology. This enables us to identify
in which areas we need to make improvements and allows us
to benchmark our progress against other organisations. It also
guides our engineers to the weight that should be placed on
the model outputs, dependent on the quality of the inputs.
Furthermore, the approach will drive future data improvements
by articulating the business’s expectations of data completeness,
quality and timeliness, and by fostering a culture where high
quality information is recognised as paramount.
Incorporating criticality criteria into our
investment plans
We understand that asset criticality is an important facet of
investment planning. Assessing the criticality of assets in a
consistent way helps to prioritise the order in which interventions
are undertaken.
The subject of criticality is currently being developed by an
industry wide working group led by UK Power Networks. It is
intended that the Health Index of an asset combined with the
Criticality Index will inform risk driven investment planning.
We have already made significant progress in developing our
thinking around criticality and have also considered how it will
be built into our ARP models, once the methodology has been
agreed amongst all parties.
Criticality considers the consequences of failure of an asset in
each of the following categories:
• Network performance
• Safety
• Financial (e.g. cost of repairs/replacement
• Environmental impact
Making the right intervention choices
Traditionally, our assets have been replaced on a like for like
basis to deliver a relatively stable health and cost profile. We
have now adopted a more innovative and sophisticated approach
to non-load related investment, that considers a wider range of
intervention options, as we strive to continually deliver value for
our customers.
For each asset category we have looked to the marketplace for
new solutions, as well as drawing on our wealth of experience,
to identify the range of intervention options available to us.
These typically include replacement, refurbishment, retrofit,
repair and maintenance activities. Each of these intervention
options carries a different cost (both in relation to capex and its
impact on on-going opex) and impact on health.
We are currently developing an approach to assess the relative
whole life costs and benefits of each intervention scenario,
to help inform our investment decisions and to enable us to
model capex/opex trade-offs. The approach is used to inform
the volumes of each intervention to be delivered over ED1 and
can also enhance our decision making in the following ways: it
enables us to understand the impact of ‘smoothing’ our capex
spend across the period, in terms of health profile; it helps us
to ascertain which intervention scenario has the lowest whole
life cost; and it can be used to identify the savings that can be
realised through adjusting the timings of capex interventions in
order to coincide with other capex work in the area.
Optimising the non-load related expenditure plan
Based on the foregoing enhanced top-down modelling capability
the initial output is then refined and validated by our asset
engineers taking a bottom-up approach that ensures evidence
captured on asset condition and environment supports and
shapes the final plan. Optimisation considers;
• Benefits of refurbishment and retrofit options
versus replacement
• Managing HI profiles with interventions that maintain a stable
level of network risk
• Capex and Opex cost and benefit trade-offs to optimise whole
life costs
• Rationalisation with the load related reinforcement plan.
Criticality is categorised using the following Criticality Index;
• C1 – ‘Low’ criticality
• C2 – ‘Average’ criticality
• C3 – ‘High’ criticality
• C4 – ‘Very High’ criticality
We have described how our suite of models, together with the
agreed measure of criticality, assists us in identifying the most
appropriate time to undertake interventions. It is also vital for us
to ensure we are undertaking the right type of interventions to
ensure we are delivering maximum value to our customers.
>pg66 | Business plan

Innovation!
Overhead line incipient fault detection
This project aims to trial a solution to locate emerging faults
on overhead lines, using detection points installed on the
HV overhead network before they cause a line to fail.
The objectives are to:
• Help identify more rapidly network sections
containing faults
• Predict and accurately locate a potential
fault on the system
Business plan | >pg67

5.4 Developing our operating
cost expenditure forecast
Our operating expenditure is what we need to run our
operations. This is split into two broad categories; direct
operating costs such as those associated with field force
activities, and indirect operating costs such as those associated
with business support functions, such as HR and finance.
Direct operating costs
Direct operating costs are comprised of three main areas;
fault rectification, inspection and maintenance, and vegetation
management. The associated costs are forecast from information
in our Network Asset Management Plan (NAMP). The NAMP
outlines volumes required for each of the three activities,
which are derived from our knowledge of asset condition,
our inspection and maintenance policies for each asset, and
reported defects.
Our aim is to anticipate any significant rise in our fault or failure
rates before they occur, so that we can undertake appropriate
interventions (repair, refurbish or replace) so as not to cause
disruption to our customers. We do this through analysing
inspection reports, condition data and fault trends. This helps
us to understand the precursors to failure which we can use to
help us eliminate future faults where it is efficient to do so. It is,
however, impossible to identify all faults before they materialise,
especially since failure rates can also be driven by issues such as
inherent defects with the asset and third party damage.
Each of our asset categories has its own inspection and
maintenance policy, which defines the type and frequency of
inspection and maintenance activity that needs to be undertaken
to maintain asset health at an acceptable level. This varies
across the different asset categories. Direct costs for inspection
and maintenance are forecast from the projected volumes of
inspection and maintenance activity.
All of our vegetation management activities are outsourced to
contractors, who undertake inspection and tree cutting in line
with our policies. The forecast costs relating to this are derived
from the known spans of our overhead lines that are affected by
tree growth, in conjunction with the forecast efficient unit cost
per span.
We are currently undergoing a direct cost efficiency review.
Following this, we will update our forecast within the revised
business plan for the final regulatory submission in July 2013.
It is our assumption that we will move to median industry unit
costs for direct cost activities for the ED1 period.
Indirect operating costs
Indirect costs cover two main types of costs. Business support
costs, such as HR, IT and finance functions and ‘Closely
Associated’ costs that consist of activities that are related to our
core work on the network, such as design, project management,
engineering and clerical. We have undertaken two major cost
efficiency programmes since the last price control and have
achieved a 19 per cent reduction in our indirect costs. We aim to
achieve a targeted reduction of £50 million of annual operating
expenditure by the end of 2013.
In general we utilise an indirect cost model to forecast the level
of closely associated and business support indirect costs. The
exceptions to this are IT and property costs which have been
constructed on a bottom up basis. The basic premise behind the
model is that as direct costs increase or decrease then indirect
costs will increase or decrease. The relationship is symmetrical
in the model. To derive the relationship between direct cost
movement and indirect costs we used regression analysis and
insight from our management teams.
For those costs that we do not construct using our indirect costs
model we use a number of underpinning assumptions Figure
5.14 below sets out the forecasting basis for these costs.
Our indirect and non-operational capital investment costs for IT,
transport and property are all formed from bottom-up analysis of
the requirements based upon key drivers such as actual vehicle
replacement profiles and known IT system refresh programmes.
Figure 5.14: Underpinning assumptions for the indirect costs not
derived by models
Expenditure type Forecast approach
Pension deficit
Based on existing deficit repair
plan agreed with trustees
IFI/LCNF
IFI expenditure rolled forward at
2014/15 levels
Existing LCNF projects which
continue beyond 2015 are
included
No expenditure included for
Network Innovation Competition
Transmission exit charges Based on information received
from National Grid
Business rates
Small tools and equipment
Other costs (Water rates,
GSOP payments, etc.)
Insurance
5.5 Regional cost effects
Extrapolated from historical
actuals
We operate entirely in the south east of England. This is the
most densely populated, most expensive area to live in the
UK delivering around 45 per cent of the UK economic output 13 .
We also experience the highest power densities in the country.
These factors have a direct impact on the way we operate e.g.
requiring us to locate our substations within the basements
of buildings and restricting when and how we work. We also
experience higher costs in general within the M25 region
driven from independently observable differences in pay due
to the cost of living. We describe in this section the challenges
we have in operating, which on the scale we observe them,
are unique in the industry.
Urban environments
All of our networks distribute electricity to our customers in
London. LPN is our only network that distributes electricity in
London alone, but both EPN and SPN service areas start in Central
London and stretch out to East Anglia or the South Coast of the
UK respectively. It has long-been accepted that operating in the
South East is more expensive than other areas of the UK due to
the inherent cost of living and the need to import skills, leading
to rises in the cost of labour, that we term regional cost effects.
Government statistics on wages and rates of pay consistently
demonstrate this effect. Figure 5.15 shows data from the ONS
Annual Survey of Hours and Earnings that show London is higher
13
Measured in terms of Gross Value Added
>pg68 | Business plan

than the UK average (score of 1.00) across all reported job
categories. We will bring forward more network specific evidence
in our 2013 forecast business plan to justify this regional effect.
Figure 5.15: Ratio of regional job pay versus UK average pay
2.0
1.8
1.6
1.4
1.2
1.0
0.8
0.6
0.4
0.2
0.0
London
In addition, it is widely accepted that the cost of operating in
rural, urban and super-urban environments vary. The additional
costs from the urban and super-urban environments arise due to
external factors that impact on our operations, including:
• Population and load density – leading to increased complexity
and density of utility services
• Underground working – driving the need for tunnelling and
forced ventilation, and increased issues of confined spaces and
complex movements of equipment
• Buildings and access – as equipment in third party owned
premises is more common
• Traffic management – imposing more restrictions, such as
red routes or the need for rapid reinstatement and reopening
of roads
• Out-of-hours working
• Security costs and terrorism insurance
Figure 5.16
South East
Scotland
East
North West
Supporting the UK economic engine
Our networks support a significant proportion of the economic
output of the UK. London produces (22 per cent) the South East
East Midlands
North East
West Midlands
Yorkshire and The
Humber
14
ONS, Regional, Sub-Regional local Gross Value Added 2010 – 14 December 2011
South West
Wales
(14 per cent) and the East (9 per cent) of the UK’s Gross Value
Added 14 , which is dependent on us providing a reliable supply
of electricity and expanding our network to support future
economic growth.
Figure 5.17: Historic trend of GVA in our regions
£ m
300,000
250,000
200,000
150,000
100,000
50,000
0
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
East of England London South East
Population and load density
A large proportion of the UK population lives and works in
the South East of England to support the economic output.
Specifically, the population density of inner London Boroughs is
more than double that of other major cities in the UK; see
Figure 5.18.
The crowded streets and closely packed housing of the capital
means that space is at a premium. Not only does our network
cover the area with the highest population density, but this
area also has a high share of ‘sensitive’ customers such as
Government buildings, key infrastructure, multi-national head
offices, the banking sector, etc. These customers want higher
levels of service and greater security of supply. This was
evidenced by Ofgem’s willingness to pay survey, where LPN
customers showed a significantly higher willingness to pay for
reductions in interruptions.
Higher population and housing density means we need to place
more assets amongst the buildings, in the pavements and in our
roads. This is repeated across all utilities leading to high levels of
congestion under our feet that we must untangle every time we
want to work on our assets.
The density of cables provides particular challenges where we are
replacing our assets, e.g. due to a fault. In these circumstances
the small and tightly packed terraced houses creates complexity
in excavating around other services and locating the right cable
before we can carry out a reconnection. In this environment
we tend to see shorter length of cables which lead to a larger
number joints per length of cable required compared to a less
urban environment. Joints and jointing are more expensive than
the cable itself and are one source of cable failures.
Our London Power Networks area has one of the highest demand
densities in Europe, with an average density in London of 6.6MW
per km 2 compared to an average UK density of circa 0.3MW
per km 2 . Central London peak loads can vary between 25MW
and 170MW per km 2 and are expected to increase in the future
to over 300MW per km 2 . High load density typically leads to
increased operating costs due to:
• Maintenance work which needs to be done at weekends
and overnight
• A greater urgency in equipment to service following faults
Business plan | >pg69

Figure 5.18: Population density across UK cities
(residents per Km 2 )
Figure 5.20: London boroughs power density (peak power used
in each Km 2 of the city)
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
Inner London Boroughs
Manchester
Birmingham
Liverpool
Bristol
Sheffield
Bradford
Leeds
1,000
0
Figure 5.19: UK power density (peak power used in each Km 2 )
Figure 5.21: London power density (peak power used in each
Km 2 of the city)
Underground working
London Power Networks is almost completely made up of
underground cables. We also sometimes have to locate our
substations underground to adapt to the constraints on space
made available to us for our equipment.
Excavations are necessary to install and maintain underground
network equipment, requiring extensive planning and
co-ordination with other utility owners. Our approach to the
installation of new circuits in central London has been via utility
cable tunnels, which are expensive to build and operate. LPN
is responsible for 45 cable tunnels and incurs considerable
on-going costs associated with the maintenance of the tunnel
infrastructure, ensuring the serviceability of the tunnel entry
points, ensuring the safety of tunnel works, and tunnel rent
charges from local authorities.
Heat dissipation from our underground substations is complicated
with greater risk of overheating due to the limitations of air
movement. To mitigate the risk of substation equipment
overheating, LPN’s substations are fitted with forced ventilation
equipment to assist with the heat dissipation. Our larger
>pg70 | Business plan

substations, such as the Leicester Square substation, have
expensive specialist cooling systems to dissipate transformer
heat and, additionally, a large proportion of our central London
smaller secondary substations need forced ventilation. This is a
cost unique to LPN.
Buildings and access
In super-urban environments there is often no room to site
stand-alone prefabricated substations, and availability of space
comes at a premium. This is also the case in central London and
as a consequence LPN’s new substations:
• Need to be built in specific locations owned privately and/or
integral to buildings
• Require innovative solutions which often lead to more complex
building designs that are more costly to build and maintain
These factors combine to make new build and regular
operational tasks more complicated and time consuming. Access
difficulties, working in an underground environment and the
physical movement of equipment in a ‘super-urban’ area are
also challenges. Whilst such jobs are not unique to London, the
proportion of similar work is much higher.
A significant proportion of our central London network cables and
equipment are located in close proximity to London’s historic,
cultural or architectural places of interest. Our work in these areas
is subject to increased costs due to extensive planning consent.
We strive to ensure our work satisfies all interested parties,
such as local authorities, architects, archaeologists, business and
residents. The aesthetics and environment of these areas are
very important to us.
Most of the central London Boroughs contain large sites of special
national archaeological importance. The City of Westminster,
for example, contains six large sites of special national
archaeological importance, including the area around the Houses
of Parliament and Westminster Abbey. Current archaeological
thinking, Government advice, and City Council policies favour
retaining archaeological remains in situ, leading to extensive and
costly planning and consent processes for undertakers.
Excavations are necessary to install and maintain network
equipment which is underground. This requires extensive
planning and co-ordination with other utility owners.
Traffic management
In common with other super-urban areas, London is subject to
extreme traffic congestion, leading to strict traffic management
measures. In the case of London these measures are very
onerous, such as congestion charging.
London has a congestion charging zone which covers eight of
the fourteen London Boroughs that LPN serves. These costs are
unique to our network. Many of the roads in London are also
strategic and designated as traffic sensitive. Traffic sensitive roads
impact our operations leading to increased costs and additional
out-of-hours work.
Out-of-hours working
We pride ourselves on providing an excellent service to all our
customers. In the case of our more sensitive customers, such as a
critical government offices, health-service facilities, and financial
institutions, this required more frequent out-of-hours work to
minimise disruption.
Capital cities often have the largest share of special events
and this also applies to London. Examples include the London
2012 Olympics, the London Marathon, Wimbledon, Notting Hill
Carnival, the Lord Mayor’s show, and frequent state visits. We
are required to work around these events, thus placing further
restrictions on when we can carry out our work, reducing the
number of evenings and weekends for areas of the city.
Terrorism and security
Due to the profile of London and its significance within the
economy, our network faces a higher risk of terrorist attack.
Security measures put in place for mitigating this increased risk
add to our overall operating costs. Additionally, we face increased
costs in insuring against network asset damage and any business
interruptions following attacks. These costs are unique to
our network.
How these challenges affect our networks
The factors outlined have an impact on many of the costs of
running our business. This includes our new investment, our
contractors and the day-to-day operational expenditure.
We have undertaken studies and benchmarked these effects over
time. We have commissioned a range of studies and analysed
our own costs. We will refresh these studies for our full business
plan in 2013. In summary we have previously demonstrated
that the effect in super urban environments can be as large as
60 per cent higher than the urban environment. This is on top of
the premium for urban over rural environments. Adjustments for
both the regional cost and urbanity cost are widely accepted as
the reality of operating in the South East and in world cities.
We expect today’s ‘always-on’, connected culture to increasingly
affect our networks as we transition to a low carbon economy
and heat and transport becomes increasingly dependent
on electricity.
The recent analysis done by Ofgem for the gas distribution
network company review recognised that labour and contractor
costs are higher within London (defined as within M25).
The overall labour and contractor cost adjustment to reflect
these effects for a gas distribution network company operating
within the M25 was 23 per cent.
Ofgem also recognised there were productivity impacts of
operating in an urban environment, due to longer travel
times, and greater complexity of excavation as we have outlined
in this section.
In recognition of the productivity impacts Ofgem made a
15 per cent adjustment in respect of the gas distribution network
capital expenditure schemes, mains replacement programme
and connections schemes. Other adjustments were also made in
respect of reinstatement and transport activities within London.
Business plan | >pg71

This supports the assessment in the previous (DPCR5
review) where the treatment of regional factors, was less
well-developed.
Within our current business plan we received a pre-settlement
adjustment to reflect the increased labour and contractor costs
(£29.4m), productivity impacts (£2.5m), and costs for specific
London infrastructure e.g. cable tunnel maintenance (£0.4m).
These figures are applied annually to ensure a consistent
benchmark is applied, (all figures shown in 2007/08 prices).
All these factors are incorporated into our forecasting for the
coming price control period by recognising regional differences
in the unit cost applied to each of our networks.
Figure 5.22: Complex underground substation build in
Leicester Square
As part of our 2013 forecast business plan we will be providing a
range of evidence in support of the cost implications of operating
within the M25, which applies to all of our networks.
>pg72 | Business plan

Innovation!
Urban transformer substation
It is often difficult to reinforce circuits in densely populated areas
mainly because there is limited physical space available. London
substations are commonly built underground, are therefore
expensive to build, and can cause disruption during construction.
The project will evaluate if an urban distribution substation
developed by a Spanish company (Twelcon) could help
address these issues.
The urban substation houses an LV panel, Ring Main Unit
(RMU), Remote Terminal Unit (RTU) and Transformer
(up to 1,000 kVA). Twelcon currently use continental
equipment in the substation; hence development
and further testing may be required to ensure
that components meet UK Power Networks
specifications and perform efficiently
and safely within the urban substation
environment. The Twelcon substation
also has four backlit advertising
panels that could be used for
public information.
Business plan | >pg73

5.6 Changes for 2013
Our plans for the next 10 years are under development.
This 2012 forecast business plan is a work in progress. We
have published it to gather stakeholder views on our current
thinking so that we can incorporate those into our 2013 plan
that will be submitted to Ofgem in July 2013.
In this section we outline a number of areas of uncertainty
and ideas under development where our evolving thinking is
likely to result in changes in our forecast business plan. Key
uncertainties include the number of interventions we will need
to undertake in support of the smart metering programme,
the cost of integrating smart meter data into our business,
the applicability and cost of smart grid technologies and how
stakeholders view strategic investments that anticipate future
customer needs.
How do we expect our plan to change for 2013
This 2012 forecast business plan lays out our current thinking
to allow for detailed engagement to allow us to consider and
integrate stakeholder views ahead of our submission to Ofgem
in July 2013.
There are a number of things that we already know will change
between now and when we submit to Ofgem in 2013. The
known changes are described below.
Planning assumptions
We will revise our planning assumptions and update our
scenarios in line with the views and guidance we receive from
our stakeholders and expert opinions. For example, we expect
to make updates to reflect the latest information on economic
growth, deployment rates for low-carbon technologies and
renewable generation. We will also reflect the latest thinking
from the various industry groups that are looking at the evolution
of the industry, including the joint DECC and Ofgem Smart
Grid Forum.
Benchmarking of costs
We intend to provide a further base of evidence to support
our view that the costs we incur in running the networks are
efficient. Efficiency in delivering our outputs considers what we
do, where we do it, how we do it and what it costs. Much of our
direct work and the associated indirect costs are specific to our
industry, making peer benchmarks the most obvious yardstick
against which to measure our performance. We will use these
benchmarks together with bottom-up analysis of the drivers of
our costs to influence the efficiency of delivering our outputs.
In the case of business support costs, these are more generic
corporate costs and as such we will put forward a range of
external, independent benchmarking or expert evidence to
justify that they are efficient.
Relationship between direct and indirect costs
Much of our indirect cost expenditure is driven by a modelled
relationship with the growth in our direct work. We use a
relationship that was established for the current business plan
period (DPCR5) such that for a one per cent movement in direct
costs there was a one third of one per cent movement in indirect
costs. We are making changes to how we operate our business
and this may include a change in the mix of the work that
we insource and outsource. This may lead to a change in the
relationship from that observed. Therefore, we plan to review
and re-test the current assumption for inclusion in our 2013
forecast business plan.
Smart metering – cost benefit
Over the coming months we are reviewing our planned response
to the smart meter programme based on the latest information.
Our plans will reflect the activity and costs of implementation
and the IT and business changes that are required to enable us
to utilise the smart meter data effectively. We have also included
in this forecast business plan our expectations for the costs of
supporting the roll-out programme, where our staff may need to
visit homes to allow the smart meter to be fitted safely.
Smart meters will provide customers with real time information
on their energy consumption, enabling them to manage their
energy use and the cost of their bills. This will also help to reduce
emissions. There is a large task facing all energy suppliers. Over
53 million gas and electricity meters must be replaced, visiting
30 million homes and small businesses between 2014 and 2019
as part of the roll out. A proportion of these installations will
require our people to attend site to rectify defects and faults
associated with the meter installation. Estimates vary for the
number of interventions that we will need to perform, but we
are anticipating around 10 per cent of our customers may need
to call us and perhaps require us to visit their home.
We also believe that smart metering provides a unique
opportunity to improve customer service and network efficiency.
We are proactively involved in the smart meter development
programme. It is anticipated that smart meters will contribute
to the efficient operation of our networks and the decarbonising
agenda. They will provide many opportunities to improve
including network planning, income management and
fault handling.
In anticipation of the roll-out, we are preparing the business to
improve our performance by making the most efficient use of
the data available to us. We see an opportunity to:
• Improve customer service – by proactively knowing when the
customer is off and being able to provide better information
about recovery time
• Improve restoration times (CML performance) – through
enhanced network information we can dispatch our resources
more efficiently in response to LV faults, storm response and
other fault conditions
• Improve investment efficiency – enhanced network
information to improve accuracy and efficiency of network
investment needs and options
• Improve quality of supply – by automatic detection of lost
neutrals (with potential self-disconnect), high/low voltage
alarms, leading to more informed problem identification and
improved scheduling of actions
• Improve our asset safety – as the smart meter roll out will
necessitate the inspection of all meters and fuses on
the network
We expect that the majority of these benefits will be realised
towards the end of the smart meter roll-out – although some
benefits such as customer outage notification could be
realised earlier.
>pg74 | Business plan

Figure 5.23
Summary of costs and
benefits
Customer contact details
and fault records
Determine customers
affected
Outbound fault comms
Meter polling for fault
detection and restoration
verification
Group volumes for
HV faults
Field force faults response
Full visibility of network
down to LV
Improved network and
connectivity information
Optimised load and
non-load capex
Cost (£m)
(and timing)
4.5-6.5
(by 2014/15)
14-27
(by 2015/16)
14-27
(by 2017/18)
Benefit
(£m p.a.)
TBC
4.5-6.5
~4
(ENA view)
Enhanced billing 3-6 Negligible
(by 2014/15)
Data warehouse, etc. 7-13
(by 2014/15)
Total 42.5-76.5 8-10.5
Alongside this stakeholder consultation we are continuing to
refine our approaches and develop our detailed plans ready to
submit a plan that stands up to the scrutiny of our stakeholders
and Ofgem. We highlight below areas within our plans for which
there remains significant uncertainty or we have more work to
do to refine the approach that will ensure that our forecasts are
as robust as possible for defining the next 10 years. There are
three major areas that will lead to changes in our plans, adoption
of smart grid technologies (and the preparatory work we will
do ahead of them being needed), responding efficiently and
differently to support stakeholder and customer requirements
and improving our approaches to forecasting expenditure.
Incorporation of Smart Grids into our plans
We have made the decision not to include smart grids
technologies in this 2012 forecast business plan. This allows
stakeholders to clearly see the impact of these technologies
when they are included next year. Smart grid technology may
offer new solutions to the challenges we face as we move into a
low-carbon future.
Smart grid technology may present the best option to deal with
the challenges of uncertainties in the demand for electricity.
The pace of transition to the low carbon economy is uncertain,
however if electric vehicles and heat pumps are widely adopted
over the new regulatory period, this new demand must be
matched with network capacity. Concurrently we will be
accommodating dispersed, variable generation sources, primarily
wind and solar into across our networks. In the past this has
been a minority issue, but the volumes of generation stimulated
by government policy initiatives requires new solutions that
can efficiently manage the uncertainties and deliver for our
customers. These are challenges we and the wider industry
will face.
The earlier section on innovation describes how we are
leading trials of the technologies and approaches to adapt
to these challenges and the learning from these will support
our approach. In addition we are improving our modelling
approaches to allow us to incorporate smart technologies into
our network development and planning processes to make them
part of our future investment plants.
In addition the industry, through the Smart Grids Forum –
Workstream 3 is assessing the impact of low carbon technologies
on Great Britain’s power distribution networks. As an industry we
wish to better understand how low carbon technologies will form
part of our plans for the future.
The Workstream has issued its report and we are in the process
of evaluating its recommendations. We will consider the outputs
of Workstream 3 of the Smart Grids Forum. It is our intention
to utilise, where appropriate, its recommendations in the
construction of our 2013 forecast business plan.
Strategic load related investments:
Distributed Generation (DG) Infrastructure
We would expect our networks to take their fair share of the UK’s
commitment to renewable generation. We are seeing a large
potential for new wind farms connecting to our networks. This is
particularly true in the east of England where there quality of the
wind resource is high.
We have included a first view of a potential strategic investment
for our EPN network. This concept is to provide a high-capacity
‘spine’ to allow new renewable generators to connect in a
timely and cost effective way. We see blockers to renewables
developments e.g. where small developments need extensive
network reinforcements. These can make a project unviable as
a result of when they have come forward. We are looking at the
options and undertaking analysis on the benefits of developing
new capacity on an anticipatory basis. This will be explored
further in our 2013 forecast business plan.
London capacity and resilience
We are looking in detail at how we can ensure we can meet the
resilience and capacity expectations of our customers in London,
as discussed in Section 4.5. We are developing options to be
presented for the 2013 forecast business plan that has a full cost
benefit case.
Improvements to forecasting methods –
Load Related Expenditure
Clustering of low carbon technology deployment
Over the next two decades, many new low carbon technologies,
both consumption and generation, are expected to connect to
the network as part of the transition to a low-carbon economy.
At first glance it appears that networks would be able to
accomodate the national take-up of these technologies.
This assumes, however, that these technologies are evenly
distributed across the population and networks. In reality it
is much more likely that the technologies will be irregularly
deployed, creating local clustering, as a result of local conditions,
demographics and customer behaviour. The clustering of these
new technologies in localised parts of the network would drive
much greater investment.
Business plan | >pg75

A good example of this effect is the adoption of photovoltaic
solar panel over the recent years. The supporting subsidy
applies across Great Britain, but in practice the adoption has
been clustered. In part because geographic conditions (days of
sun, orientation of roof) but there is also evidence of irrational
clustering when neighbours copy others in their street.
We are therefore working on analysis techniques to allow us to
better represent these factors into our modelling approach. We
are working with experts to refine the methodology for applying
these new demands and generation sources onto our networks.
This will see a potentially very different distribution (higher and
lower) of new electricity consumption across our substations.
A full description of the methodology and outcome will be
provided in our 2013 forecast business plan.
Improvements to forecasting methods –
non-load related
Incorporating criticality into our forecasting models
There have been a number of improvements to forecasting nonload
related expenditure that will have significant benefits for
long term planning.
The development of ARP models will provide more accurate and
reliable forecasts of asset health, enabling us to make the right
decisions about our assets. The models have been developed in
conjunction with EA Technology, utilising our latest knowledge of
asset deterioration.
In addition, we are leading the working group of DNOs to
develop a criticality index. Alongside this we have been
developing our approach to criticality, which will be incorporated
into our ARP models and will help us to better prioritise the
interventions in our long term plan.
>pg76 | Business plan

Business plan | >pg77

6 Outputs: our commitments
to customers
We are committed to delivering an excellent service to our customers. We will
be measured by Ofgem against the commitments we make as part of our 2013
forecast business plans.
Ofgem has defined six categories of output, as follows:
• Network availability and reliability
• Customer service
• Connections
• Safety
• Environmental performance
• Social obligations
In this chapter we describe the outputs we have used in building the 2012
forecast business plan. These have been developed in consultation with our
stakeholders. The outputs and the level of performance will be refined in
response to the insights and conclusions from our research on customers’
willingness to pay and Ofgem’s policy decisions on how it will measure the
performance of the industry.
>pg78 | Business plan

6.1 Performance outputs
This section describes our current thinking on output levels
and how we are continuing to seek views to help us find the
right balance of cost for the level of output performance. Our
proposed outputs have been developed in consultation with
our stakeholders, although many of the outputs ultimately
may be set on an industry wide basis. We have quantified
the outputs we will deliver where our work is suitably well
progressed; in other areas such as the ‘time-to-connect’ we
are continuing to work as an industry to set out how such an
incentive will work.
Working with our stakeholders
to understand what they want
The development of meaningful outputs (an output in this
context being the delivery of a commitment or level of service)
is part of the overall review of our investment plans for 2013.
It was the focus of the second phase of our stakeholder
engagement around business planning in 2011.
Stakeholders were asked to provide their opinions on the existing
outputs and possible new outputs we proposed, along with any
suggestions of their own. Specifically, stakeholders were asked to
provide their opinion of network reliability and the transition to a
low carbon economy.
We learned some significant lessons from our engagements:
• Domestic customers were able to provide valuable insights,
although they needed some time to more fully understand the
role of distribution companies within the wider energy market
• When asked what was most important to them, each group
arrived ultimately at the six output categories defined by
Ofgem. Within those categories, the participants were able to
apply their experience of other service organisations and so
provide extremely valuable feedback on their expectations
We plan to consult with stakeholders further on the proposed
measures later this year through our willingness to pay work that
will help us to understand an appropriate performance target
that can be integrated within the future business plan.
The potential outputs that have been developed to date are
described below.
Network availability and reliability
Network reliability has always been an area of strong focus and
will continue to be so during the forecast business plan period.
We are acutely aware of how reliability issues impact
our customers, as highlighted in customer satisfaction surveys.
The scope for major reliability improvement programmes
following the step change achieved during the past five years
may be more limited without significantly larger investments
being made. While in general this may not be appropriate, we
are considering in our willingness to pay research more specific
and regional questions to establish if there are areas where
investment is wanted where higher reliability is of
particular importance.
The proposed outputs for network availability and reliability are
suggested to remain:
• Customer Interruptions (CI) (planned as well as unplanned):
Number of customers whose supplies have been interrupted
per 100 customers each year
• Customer Minutes Lost (CML): (planned as well as unplanned):
duration of unplanned interruptions to supply each year,
measured by average customer minutes lost per customer
where an interruption of supply to the customer lasts three
minutes or longer
• Health Index – maintaining the overall risk for our networks –
with the addition of criticality
• Load Index – maintaining a similar level of utilisation across
our networks – with improvements on the consistency of
application across the industry
Our plan is built on the expectation of delivering the outputs
described in this section. All of the projected performance is
provisional and work continues to validate these in terms of the
cost to deliver the output and our customers’ willingness to pay
for different levels of performance.
Figures 6.1 and 6.2 below indicate Ofgem’s proposed CI and CML
targets for ED1, as at September 2012.
Business plan | >pg79

Figure 6.1: Targets proposed by Ofgem in September strategy
paper for unplanned CI over the forecast business plan period
(2015 to 2023)
80
70
60
50
40
30
20
10
0
2015/16
2016/17
2017/18
2018/19
2019/20
2020/21
2021/22
Ofgem targets for unplanned Customer Interuptions (CI)
2022/23
Figure 6.3: Commitment to EPN asset health at the end of the
forecast business plan period (2023)
80%
60%
40%
20%
0%
End of DPCR5
End of ED1
HI 1 HI 2 HI 3 HI 4 HI 5
EPN SPN LPN
Figure 6.2: Targets proposed by Ofgem in September strategy
paper for unplanned CML over the forecast business plan period
(2015 to 2023)
Figure 6.4: Commitment to LPN asset health at the end of the
forecast business plan period (2023)
60
50
40
30
20
10
0
2015/16
2016/17
2017/18
6.1
2018/19
2019/20
2020/21
2021/22
2022/23
Ofgem targets for unplanned Customer Minutes Lost (CML)
EPN SPN LPN
80%
60%
40%
20%
0%
6.3
End of DPCR5
End of ED1
HI 1 HI 2 HI 3 HI 4 HI 5
We are committed to delivering against our HI and LI targets;
Figures 6.3 to 6.5 show our commitments to improving the
Health of the assets across our three networks, and Figures 6.6
to 6.8 indicate our delivery of our load targets through DPCR5.
We will have a better understanding of our utilisation forecasts
at the end of the forecast business plan period (2023) when we
provide our revised plan to Ofgem in July.
Figure 6.5: Commitment to SPN asset health at the end of the
forecast business plan period (2023)
80%
60%
40%
6.2
20%
0%
6.4
End of DPCR5
End of ED1
HI 1 HI 2 HI 3 HI 4 HI 5
>pg80 | Business plan

Figure 6.6: Delivery of DPCR5 Load Indices in EPN
Weighted LI
Average
2009/10
DPCR5 Start 2011/12 2014/15
DPCR5 forecast 2.26 2.20 2.13
Actual/revised
2.05 1.82 1.94
forecast
Figure 6.7: Delivery of DPCR5 Load Indices in LPN
Weighted LI
Average
2009/10
DPCR5 Start 2011/12 2014/15
DPCR5 forecast 2.55 2.45 2.35
Actual/revised
2.48 2.30 2.40
forecast
Figure 6.8: Delivery of DPCR5 Load Indices in SPN
Weighted LI
Average
2009/10
DPCR5 Start 2011/12 2014/15
DPCR5 forecast 2.30 2.21 2.12
Actual/revised
2.15 1.92 2.06
forecast
Customer Service
Our customer satisfaction performance over the forecast business
plan period will be measured by the broad measure of customer
satisfaction (BMoCS).
The BMoCS is intended to replicate the sorts of measures typically
used by customer-facing businesses in competitive markets to
monitor and improve the service they offer their customers. The
measure comprises three different components:
• Customer satisfaction survey
• Complaints metric
• Stakeholder engagement
This is a compound measure that takes the results from customer
surveys from customers who have contacted us, i.e. for a power
cut, a connection or a general enquiry relating to our wires or
substations or issue affecting their property. It also takes into
account our speed and effectiveness in responding to complaints
and how we engage with our stakeholders.
The customer survey captures customer interactions
for connection customers regardless of the method of
communication (ie telephone, email, website applications) used
to contact the DNO. For general enquiries and interruptions only
customers that made contact via the telephone are currently
surveyed. Ofgem is considering changing the survey sample in
two ways.
• Extending the survey to include customers interacting via social
media, the internet and those who unsuccessfully attempted
a call
• Splitting out the large and small connection customers into two
groups to provide larger connection customers who are smaller
in number or have a larger voice in customer satisfaction
The complaints metric measures performance on four indicators
that are weighted to calculate a composite score (the weightings
are shown in brackets): the percentage of total complaints
outstanding after one day (10 per cent) the percentage of
total complaints outstanding after 31 days (20 per cent) the
percentage of total complaints that are repeat complaints (50 per
cent) the percentage of Energy Ombudsman decisions that find
in favour of the complainant (20 per cent). Ofgem is proposing
to modify the final element around the Energy Ombudsman to
either reduce the weighting or include all referrals to increase
the currently small sample sizes.
Our vision for our company is to be in the upper third amongst
our peers for customer satisfaction performance.
Connections
Our connections business is one of the largest in the UK. The
areas in which we provide our services are amongst the most
dynamic in the UK, with the highest load and population density
of all networks and significant economic growth activity.
Listening to our stakeholders’ views we support the introduction
of a ‘time-to-connect’ measure. We welcome this introduction
and we would be willing to enter into arrangements to
incentivise us to deliver and provide a downside risk where we
fail and it is our fault.
Our connections performance over the forecast business plan
period will be measured against the following indicators (with
the values to be determined through the Ofgem review process):
• Average time to produce a quote
• Average time taken from quotation acceptance to completion
of works
The proposal is that performance will be assessed relative to a
target based on current levels of performance, with the target
ratcheted up over time to incentivise improving performance.
Ofgem is suggesting that this incentive would be less strong
than that proposed for the enhanced Broad Measure of
Customer Satisfaction.
Safety
The safety of the public and our employees are our highest
priority. Following on from stakeholder engagement we
will continue to measure our own safety against the
following measures:
• Accident Rate per 100 employees
• Injuries to members of the public
We are targeting to reach our target of zero injuries by the end
of the forecast plan period. We also have a zero injury target for
members of the public.
Ofgem is proposing not to include any further incentive within
its regulatory framework than that which applies through health
and safety legislation.
Business plan | >pg81

Environmental performance
As a DNO, we are committed to the low carbon transition. In
addition to playing our role in facilitating a low carbon economy,
we are also reducing our own CO 2
emissions. We have reduced
our business footprint by 11 per cent and we are committed
to reducing it further. Figure 6.5 shows our progress to date in
reducing our carbon footprint.
We have sought the views of our stakeholders on how our
environmental performance is measured. Stakeholders felt that
reducing carbon emissions is now simply good business practice
and we should concentrate our efforts on the biggest
CO 2
emitting operations of our business.
Our environmental performance over the forecast business plan
period will be measured against the following indicators:
• Innovation funding: percentage of allowance used – more
than 80 per cent of allowance used over the forecast business
plan period
• Business Carbon Footprint: Carbon emission related to business
operations according to categories of building energy usage,
operational and business transport, etc. – top third sector
performance for our London network on average over the
forecast business plan period
Social obligations
The existing criteria on which our social obligations are
measures are:
• Worst served customers – defined as those customers who
experience on average at least five higher voltage interruptions
per year, over a three year period, subject to a minimum of
three in each year
• Provision of Priority Services Register and associated services to
customers – a list of customers who are particularly vulnerable
to the loss of the electricity supply and the precise nature of
their needs
Ofgem believe that DNOs can improve the quality and extend the
reach of the Priority Services Register. We will outline in our 2013
forecast business plans how the information held could be used
to benefit customers. Specifically we will outline how we will
build on our current partnerships to include other stakeholders
(e.g. suppliers, other distributors and local authorities) to share
and use information on customer vulnerability more strategically.
Figure 6.9: Current business carbon footprint reductions across
our networks
Tonnes of CO 2 equivalent
(tCo 2 e)
50,000
40,000
30,000
20,000
10,000
0
2009 2010 2011 2012
EPN business carbon footprint
LPN business carbon footprint
SPN business carbon footprint
6.6
>pg82 | Business plan

Business plan | >pg83

7 Expenditure: What we will spend to
deliver to 2023
Consultation questions for this section
General
Q21. Is this consultation helpful What could we have done better
Q22. Do you have any general comments you would like to make
about our forecast business plans for our electricity networks
Q23. Please let us know if you have any other thoughts or comments
on the points raised in this document, or if you would like to
highlight any other issues you consider important
Expenditure
Q19. Do you think our proposed level of expenditure is appropriate to
meet the output targets in our business plan If not, please be
specific as to your views on what should change
>pg84 | Business plan

The forecast business plan is created to ensure the delivery
of the commitments we are making and to ensure we meet
our statutory obligations (placed upon us through legislation,
regulations and our licence). The expenditure forecast
reflects our expectations of the challenges and assumptions
outlined in this document. This chapter describes our plan and
represents our current best view of the future justified needs
and corresponding efficient expenditure.
Figure 7.1: Forecast plan period 2015 to 2023
Overall our future plans are largely a continuation of today,
with the addition of an increasing prominence of low carbon
technologies on our network, smart metering, the enabling
steps for the future smart grid, and further efficiency savings.
We are expecting a recovery in required levels of reinforcement
on our network as economic growth returns.
Our current view for the future business plan period indicates a
total spend of £7.4 billion from 2015 to 2023.
Figure 7.1 breaks this total down across the major cost
categories. This compares to an eight year equivalent of our
2010 to 2015 plan of £6.6 billion.
Figure 7.2: Current plan period 2010 to 2015
15
1.8
0.4 0.2 Load related
1.7
Non load related
Network operating costs
2.0
0.2
1.3
Load related
Non load related
Network operating costs
1.3
2.1
Indirect costs
Non operational capex
RPEs
1.3
1.8
Indirect costs
Non operational capex
RPEs
Figure 7.3: Material cost differences
Cost driver Difference Where it impacts
Smart metering (including IT and interventions) +£115 million Shared out across our networks
Additional work volumes including low carbon
technologies and limited smart grid enablers
+£845 million Shared out across our networks
London strategic investments in capacity and resilience +£210 million LPN only
Distributed generation strategic investments to reduce
the barriers for connecting new renewable generation
+£50 million EPN only
Direct Unit cost savings -£175 million Shared out across our networks
7.1
7.2
Indirect cost savings -£262 million Shared out across our networks
Real price effects +£16 million Shared out across our networks
Total change
+£800 million
Business plan | >pg85

7.1 Our plans build on
current improvements
Much of what we do today we will continue to do in the
future. The majority of our expenditure continues to be related
to maintaining the existing network and expanding it to serve
new customers and growth in electricity usage. As such the
expenditure in this 2012 forecast business plan is generally in
line with what we have committed to and are forecasting for
the current plan period.
This 2012 forecast business plan for 2015 to 2023 is a work in
progress. The 2012 plan remains subject to uncertainty around
some of the underlying assumptions. The level of uncertainty in
some areas is greater in this business plan than in the past. This
is predominantly due to the unknown rate at which the transition
to the low carbon economy will occur. The emerging policy
framework and rate of technology development both contribute
to the uncertainty in the need for network capacity over the
long-term. We believe that this uncertainty is higher than it was
in the past.
We are still in the process of finalising our views on how
our business will evolve over the next ten years to deliver
improvements in service and efficiency. We have an ongoing
dialogue with our stakeholders to understand what they want
from our networks. We are active in the cross-industry working
groups that are seeking to provide a more consistent view of the
smart grid investments that we should undertake to enable and
facilitate the transition to the low carbon economy. The outcomes
from this work will be incorporated into our 2013 forecast
business plan.
This 2012 plan does include expenditure to enable us to extract
the benefits for network companies identified by DECC from
the roll out of smart meters (being undertaken by electricity
suppliers). It also includes our initial thinking on strategic
investments in our EPN network to facilitate the connection of
new wind generation in areas with high quality wind resource.
We have also outlined in this 2012 plan our plans to develop
a strategic investment programme for London that reflects
stakeholders’ views on the current resilience and capacity of the
network and its importance to the UK economy.
Our forecast business plan is actually three plans, one for each of
the networks. There are many commonalities across the plans,
for example, because they use similar or the same types of
assets, albeit in different proportions. There are also differences
between our networks resulting from how they have developed
over time, where they are and what future customers expect
from them. A summary of the expenditure for each of the
networks forecast plan is shown in the charts in section 7.2.
We also show for comparison the current forecast for expenditure
(on an eight year equivalent basis) for 2010 to 2015.
7.2 Expenditure: plans for
our networks
Our three distribution networks use common policies and
approaches to managing the assets that make up those
networks. As a result significant elements of our plan are
common to all three networks. Our expenditure plans are
broadly aligned between the current plan period and what
we are forecasting. We are forecasting some increases in
expenditure that result from a mix of additional volumes and
rising underlying costs of doing work. We are also forecasting
further increases in efficiency as we carry out changes to the
ways we work to deliver better service, more efficiently.
We expect the costs of operating our network in the future to be
largely similar to today. We have split the description of our plan
into two pieces. The first part describes costs that are network
specific, which includes our expenditure on maintenance, faults
and capital investments in our network. These costs can vary
significantly between our networks, for example LPN has no
tree cutting costs, but higher costs for managing its underground
cables. These variations reflect the history (design choices,
equipment choices), geography (density of population, SSSI,
terrain, etc.) and our customers’ demands of the network e.g. in
EPN there is a greater interest in connecting onshore wind farms,
whereas in London our customers often want to connect large
buildings to our networks e.g. the Shard.
The Shard
>pg86 | Business plan

The second part addresses costs that are derived centrally for
all three networks or those over which we have little control or
influence. The cost each network faces is a result of an allocation
from a centrally derived costs e.g. based on activity drivers.
This covers the indirect (overhead) costs and pass-through costs
(e.g. licence fees and transmission exit charges).
Volume and unit cost efficiency
Large parts of our forecast spend is derived by taking the
volumes of work we believe we need to do and applying
our forecast of the efficient unit cost to those volumes. In the
following sub-sections we provide an overview of the main
drivers of change in volumes of work. Alongside this we show
how the cost of delivering the work is expected to change.
Aligned: our current and future plans
Our forecast business plan expenditure for 2015 to 2023 for each
network is shown in the following sections.
Eastern Power Networks business plan
This network covers the largest land area of our three networks
from north London out to our most rural communities. It serves
areas that have high quality wind resource and we expect
the trend of wind generation connections to support the UK’s
renewable energy targets to continue. We would expect this
region to attract its fair share of wind turbines to support the
renewables being deployed across the UK. We also expect
this region to see noticeable numbers of heat pumps
being deployed.
The charts show how the future business plan compares to our
current plans.
Figure 7.4: Current period expenditure total = £2.8 billion
0.8
0.4
0.1 Network operating
costs
0.7
Indirect costs
Figure 7.5: Forecast period expenditure total = £3.1 billion
0.8
0.8
7.4
Non load related
Load related
Non operational capex
0.1 0.1 Load related
0.6
Non load related
0.6
0.9
Network operating costs
Indirect costs
Non operational capex
RPEs
Direct capital expenditure
Direct capital expenditure primarily consists of the expenditure
on expanding our network (load-related or reinforcement
expenditure) and replacing and refurbishing our assets (non-load
related). The underlying changes and drivers are explained in the
following sub-sections.
Load related expenditure
Figure 7.6: EPN load related capital expenditure
£m (2012 prices)
100
80
60
40
20
0
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
Load related
Non-load related capit
We are expecting our expenditure on expanding and extending
the network to return to more normal (higher) levels over the
future business plan period. This is based on our core scenario
that shows a return to growth in electricity demand early in the
forecast period.
7.6
This growth in demand is also reflected in our expectations of
connection volumes, which anticipate a significant increase in
connections compared to the current plan period.
Taken together these forecasts of increasing electricity growth
and new connections lead to our overall view of the need Direct for operating costs
load-related expenditure.
0.1
0.4
Figure 7.7: Forecast connection activity
0.7 Indirect operating cost
investment
25,000
500
0.8
Load-related capital
20,000
400 investment
0.8
Non-operational capita
15,000
300
investment
10,000
200
5,000
100
0
0
LV connections
2015
2016
2017
2018
2019
2020
2021
2019/20
2022
2020/21
LV
LV DR5 average
HV & EHV
HV & EHV DR5 average
2023
2021/22
2022/23
HV and EHV connections
7.7
Business plan | >pg87

DG infrastructure
In addition to demand growth, we are expecting a considerable
uptake in wind generation in the EPN region. Our view of likely
activity suggests that considerable volumes of new wind farms
are likely to come forward for connection in the forecast period
between 2015 and 2023.
We are investigating and have made provision in this 2012
business plan for a strategic investment in infrastructure for the
currently expected levels of wind farms in the region. The cost
benefit case for this investment will be developed further for
2013, but rests on the principle that will result in a lower cost
solution than a project-by-project development. We believe
that this is consistent with our role in facilitating the lower
carbon economy.
Asset replacement
Our expenditure on asset replacement is forecast to increase on
average by approximately 30 per cent over the forecast plan
period. The additional asset replacement volumes are being
driven by ever improving understanding of the condition of our
assets and how they are expected to deteriorate over time. The
new modelling approach ARP is assisting how we decide on our
interventions based on a more holistic view of risk and condition.
The results show additional replacement volumes are required
compared to the current plan period and we are currently
reviewing and validating these outputs e.g. via additional
condition sampling.
Figure 7.8: Actual/forecast asset replacement capital expenditure
£m (2012 prices)
160
140
120
100
80
60
40
20
0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/20
2020/21
2021/22
2022/23
Non load related
Expenditure on the asset types shown in Figure 7.9 represents
a significant proportion of the increase in asset replacement
expenditure compared to the current plan. We have included a
brief commentary on the drivers that lead to these changes
in volumes.
Our future expenditure plans show both rises and falls in
expenditure. We have found reduced need for investment in the
asset types shown in Figure 7.10 which represent a significant
proportion of the reductions in spend, the remainder being
spread across other asset types due to the normal variation in
replacement profiles.
7.8
Figure 7.9
Asset group Component Commentary
Overhead Pole Line LV Main (OHL) Conductor We plan to return to our original strategy of conductor replacement following a
short-term programme of rectification of defects during the current period
Cable 6.6/11kV UG Cable We have revised the policy for this cable type. This includes collecting additional
condition information to further improve our understanding of the future need
for replacement. Our current replacement rates remain at a level that will see
cables in service well beyond design life. Our long-term replacement strategy
will be reviewed in light of the improving condition information
Switchgear
6.6/11kV CB
(GM) Primary
We are experiencing increased unreliability of our oil filled switch gear that is
driving increased forecasts of the need for replacement
Overhead Tower Line
132kV OHL (Tower
Line) Conductor
We are anticipating a greater proportion of conductor replacement compared to
the current mix that has more fittings only work
Figure 7.10
Asset group Component Commentary
Switchgear
33kV indoor, gas
insulated, ground
mounted circuit breakers
Switchgear
132kV indoor, gas
insulated, ground
mounted circuit breakers
The population of assets in these classes are relatively small and reducing
so we will spend significantly less on this asset category once our current
programme of replacement ends in the current plan period
>pg88 | Business plan

We are currently reviewing all of our investment plans to seek
further efficiencies in delivery, to recognise changes in mix and
to validate the underlying data to support our future forecast
of efficient costs. We are undertaking further work to refine
distribution asset replacements unit costs before submission of
our business plan in July 2013.
Direct operating expenditure
Inspection and maintenance expenditure
Figure 7.11: Actual/forecast inspection and maintenance costs
£m (2012 prices)
30
20
10
0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Inspection & maintenance
In the current plan period we believe we are currently spending
at above the steady-state level that is required going forward.
This is to carry out an identified backlog of work. This does result
in us overspending against our current allowances, in this plan
period, and we are exposed to 45 per cent of these costs. We
believe that this is in the long-term best interests of the network
and our customers.
Our forecast inspection and maintenance costs reduce from the
current spend levels but have a number of movements both
positive and negative. We are forecasting a significant growth
in tower line painting based on our assessment of the optimum
lifecycle policy for our tower lines. This is expected to preserve
the asset life to defer replacement. Other upward drivers of cost
are increasing inspection volume for rising and lateral mains and
we continue to explore the scale of costs and the approaches
7.9
to managing these assets. The second driver is the volumes of
pole line inspections. These have increased following the results
from recent surveys that have shown examples of poles in worse
condition than expected and identified poles missing from our
asset register.
The workload for protection schemes is reducing in the forecast
period following a detailed survey of protection equipment
and evaluation of the appropriate policy to apply to the actual
population of assets.
The final area is an expected increase in the volumes for 33kV
substation work, where we are also anticipating delivering
significant efficiencies in how we deliver the work such that
overall this results in lower costs for our customers.
In summary, the known upward volume effects are outweighed
by volume reductions and compared to the current plan period
our unit costs fall for these activities (see Figure 7.12).
Figure 7.12: EPN I&M; composite unit cost efficiency trend
1.2
1.0
0.8
0.6
0.4
0.2
0.0
2012
2013
2014
2015
Faults expenditure
2016
2017
Figure 7.13: Actual/forecast fault costs
£m (2012 prices)
60
50
40
30
20
10
0
Figure 7.14: EPN faults; composite unit cost efficiency trend
1.2
1.0
0.8
0.6
0.4
0.2
0.0
Our costs are based on our projections of fault rates by voltage
and asset group multiplied by our forecast of efficient cost for
fault repair for each.
Our projections of fault rates are generally forecast to be
maintained at a constant level based on the delivery of our
replacement and maintenance policies. We are forecasting rises
in HV underground cable and LV underground mains (those that
are not Concentric Neutral Solid Aluminium Conductor). This
growth is expected due to deterioration in condition of these
assets. We are increasing our understanding of the condition of
our underground assets through increasing our use of post-fault
analysis and investigation.
7.12 Business plan | >pg89
2018
2019
2020
Forecast vs 2011/12
7.10
Faults
2021
2022
2023
2024
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
2012
2013
2014
2015
2016
2017
2018
2019
2020
7.11
Forecast vs 2011/12
2021
2022
2023
2024

Overall the number of faults we are forecasting is expected to
rise slightly by around 6 per cent over the forecast plan period.
We expect our unit costs to fall, such that the total cost of
repairing faults will remain broadly aligned to our current annual
cost of repairing faults.
Figure 7.15: EPN fault rate chart for 2015 to 2023 for
LV underground cables (non-consac) and HV
underground cables
8,000
7,000
6,000
5,000
4,000
2015/16
2016/17
2017/18
Tree cutting costs
2018/19
2019/20
2020/21
2021/22
LV Main (UG non-Consac)
Figure 7.16: Actual/forecast costs for tree cutting
2022/23
LV Main (UG non-Consac) DR5
Average
HV UG Cable
HV UG Cable DR5 Average
1,000
900
800
700
600
Total cost underpinning our plan
In summary the EPN plan remains largely a continuation of
our spend profile today. There is a step up in our direct capital
expenditure which is due to an increase in asset replacement
expenditure required to maintain the long-term health of the
network and the return to more normal levels of reinforcement
as we see the economy recover early in the forecast period. In
addition to these volume increases we expect our civil costs to
rise from those seen in the current plan period. We believe that
we will achieve greater efficiency and reductions around our
expenditure on inspection and maintenance and continue to
maintain our efficient level of indirect costs. A summary of our
forecast expenditure is shown in Figure 7.17 that shows how the
main cost categories change from our current plan (to 2015) to
the end of the forecast planned expenditure (to 2023).
Figure 7.17: EPN expenditure profile (excluding pass
through items)
£m (2012 prices)
600
500
400
300
200
100
425 422 415 412
385 388 20 396
32
15
8 31 30 378
363
371 377
8
32 35
17 8
17
8 28
7
17 8 26
30
25 25
19
17 13
7
7
7
94
19 18
4 17
3
22
93 93 92
88 92
90
90
84
10
90 90
10 10
10
10
214
146
165 165
187 181 179 166 151 158 164
£m (2012 prices)
18
17
16
15
14
13
2010/11
2011/12
2012/13
7.13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
0
73 76 76 74 76 75 76 75 76 76 77
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Direct opex Direct capex DG Spine
Indirects Non op and other costs Pension deficit
Tax allowance
Tree cutting
Our costs are based on the line length affected by trees. Our total
costs are forecast to be broadly constant through the forecast
plan period which assumes that any increases in cost due to
additional new lines affected by trees will be largely offset by
efficiencies in delivering tree cutting.
7.15
7.14
>pg90 | Business plan

London Power Networks business plan
The LPN network is almost entirely underground and is urban in
nature. It must continue to fulfil the constant growth in customer
demand for network capacity. We have to work in congested
streets where pipes and wires from all the utilities that serve
the population are located close together. Street works are
particularly challenging in central areas where access to dig in
the street is carefully controlled and therefore alternatives such
as tunnelling underground become the efficient option. We are
looking closely at bolder strategic options to make the network
more resilient and release capacity to facilitate economic growth.
These challenges are done in a region where the costs of labour
are typically higher and the urban working environment, with
more indoor, basement and working restrictions leading to lower
productivity of our people.
The LPN plan remains largely a continuation of our spend profile
today. There is a step up in our direct capital expenditure which is
due to an increase in asset replacement expenditure required to
maintain the long-term health of the network and the need for
greater reinforcement than we have seen in the current period
as we see the economy to recover strongly in London. In addition
to these we expect our civil costs to rise from those seen in the
current plan period.
Figure 7.18: Current period expenditure total = £1.8 billion
(DPCR5 – eight year equivalent)
0.4
0.5
0.1 Network operating
0.3 costs
Indirect costs
0.5
Figure 7.19: Forecast period expenditure total = £2.3 billion
(RIIO-ED1)
0.5
0.3
0.7
0.6
7.16
Non load related
Load related
Non operational capex
0.1 0.1 Load related
Non load related
Network operating costs
Indirect costs
Non operational capex
RPEs
Direct capital expenditure
Direct capital expenditure primarily consists of the expenditure
on expanding our network (load-related or reinforcement
expenditure) and replacing and refurbishing our assets
(non-load related).
Load-related expenditure
Figure 7.20: LPN load related capital expenditure
£m (2012 prices)
120
100
80
60
40
20
0
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
We are expecting our expenditure on expanding and extending
the network to return to more normal levels
0.1
Direct operating
over 0.3 the business
plan period. This is based on our core scenario that shows Indirect operatin
0.4
a return to growth in peak demand, which alongside new
connections drives reinforcement spend. Our forecast average Non-load related
annual spend in the forecast period is more than double than we investment
0.5
expect to spend over the current plan period.
Load-related cap
investment
This growth in demand is reflected in our 0.5 expectations of Non-operational
connection volumes which are shown in Figure 7.21, that investment
anticipate a significant increase in connections compared to the
current plan period.
7.18
Figure 7.21: Forecast connection activity
20,000
300
LV connections
15,000
10,000
5,000
0
2015
2016
2017
2018
2018/19
Load related
2019
LV
HV & EHV
Linear (LV DR5 average)
2020
2021
2019/2020
2022
2020/21
2023
2021/22
V
LV DR5 average
720
HV & EHV 513 DR5 average VERSION
333
250
2022/23
HV and EHV connections
200
107 59
OLD
597
7.17
7.19
Business plan | >pg91

Asset replacement
Our asset replacement expenditure is forecast to increase by
more than 20 per cent over the plan period. The additional
asset replacement volumes are being driven by ever improving
understanding of the condition of our assets and how they
are expected to deteriorate over time. The new modelling
approach ARP is improving how we decide on when and how
we intervene based on a more holistic view of risk and condition
of our assets. The results have shown additional replacement
volumes are required compared to the current plan period and
we are currently reviewing and validating these outputs e.g. via
additional condition sampling.
Figure 7.22: Actual/forecast asset replacement
capital expenditure
£m (2012 prices)
100
80
60
40
20
0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
Non load related
2018/19
2019/2020
2020/21
2021/22
2022/23
We are currently reviewing all of our investment plans to
seek further efficiencies in delivery, to recognise changes in
mix and to validate the underlying data to support our future
forecast costs and effects of the urban environment. These unit
costs are applied to our current view of the volumes of work
to maintain our network to provide an expenditure profile.
We are undertaking further work to refine distribution asset
replacements unit costs before submission of the final business
plan in July 2013.
Expenditure on the asset types shown in Figure 7.23 represent
a large proportion of the increase in expenditure within
our forecast.
We have also found significant efficiencies and potential
reductions in need for investment in the asset types shown in
Figure 7.24 which represent a large proportion of the reductions
in spend, the remainder being spread across other asset types
due to the normal variation in replacement profiles.
Figure 7.23
Asset group Component Commentary
HV Switchgear
6.6/11kV ground
mounted circuit breakers
Our approach to modelling the deterioration of these assets has improved with
additional condition data. This is suggesting that there are significant volumes
of oil switchgear, which are likely to become more unreliable and are forecast
to require intervention
EHV Cable
123kV Cable
33kV underground cable
(non Pressurised)
132kV underground cable
(non Pressurised)
A programme of removing existing leaking oil cables is leading to increasing
volumes of these more environmentally friendly assets
A programme of removing existing leaking oil cables is leading to increasing
volumes of these more environmentally friendly assets
132kV Transformer 132kV Transformer Better condition information is suggesting that replacement within the current
population can be at a lower rate following the replacement programme in the
7.20
current plan
Figure 7.24
Asset group Component Commentary
LV Switchgear
LV link boxes & LV pillars
(outdoor not
at Substation)
The rate of replacement of these assets reduces in the future business plan
period as the programme of replacements in the current period has seen a
volume defective units replaced
HV Switchgear
6.6/11kV Ring
Main Unit
132 kV Switchgear 132kV indoor, gas
insulated, ground
mounted circuit breakers
There is a significant drop in expenditure as these assets are replaced by
alternatives and the overall population falls
A strategy of more refurbishments means our asset replacement spend
is reduced
>pg92 | Business plan

Direct operating expenditure
Inspection and maintenance expenditure
Figure 7.25 Actual/forecast inspection and maintenance costs
£m (2012 prices)
20
18
16
14
12
10
8
6
4
2
0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Inspection & maintenance
These volume rises are offset by reductions in volumes and
anticipated future unit cost efficiencies (shown in Figure 7.26)
in most of our inspection, repair and maintenance work. This is
alongside volume reductions from recent survey results for our
substations and indoor switchgear in London which is showing
the assets may be in better condition than anticipated.
Faults expenditure
Figure 7.27: Actual/forecast fault costs
£m (2012 prices)
29
28
27
26
25
24
23
We expect our total inspection and maintenance expenditure to
remain broadly at the steady-state rate that we have seen during
the recent past. Our forecast inspection and maintenance costs
are within approximately 5 per cent above those in the current
plan period and is a result of minor changes in approaches and
workload across the plan.
There are a number of upward drivers that outweigh the
efficiencies that we can foresee across the forecast plan period.
A significant upward movement is the increase in volume of
underground cable inspections as we take a more in depth
look at the deterioration of these assets that dominate the
network in London. We are seeking to better understand and
evaluate the potential
7.21
for sustained operational reliability and
how their condition is evolving. We are also anticipating greater
maintenance costs for our 132kV switchgear and an increasing
workload to maintain the increasing length of tunnels that
we own.
Figure 7.26: LPN I&M; composite unit cost efficiency trend
1.2
1.0
0.8
0.6
0.4
0.2
0.0
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Our total fault costs are based on our projections of fault rates by
voltage and asset group multiplied by the forecast efficient cost
of fault repair for each of these.
Our projections of fault rates are generally forecast to be
maintained at a constant level based on the delivery of our
replacement and maintenance policies. We are forecasting rises
in HV underground cable and LV underground mains (those that
are not Concentric Neutral Solid Aluminium Conductor). This
growth is expected due to deterioration in condition of these
assets. We are increasing our understanding of the condition of
our underground assets through increasing our use of post-fault
analysis and investigation. We are forecasting an average 0.6 per
cent growth in faults per annum in these categories.
7.23
Figure 7.28: LPN faults composite unit cost efficiency trend
1.2
1.20
1.0
0.8
0.6
0.4
0.2
0.0
2012
2013
2014
2015
2016
2017
Faults
2018
2019
1.00
0.80
0.60
0.40
0.20
2020
2021
OLD
VERSION
2022
2023
2024
Forecast vs 2011/12
0.00
Forecast vs 2011/12
2012
2013
2014
2015
2016
2017
2018
Forecast
7.22
7.24
Business plan | >pg93

Overall the number of faults we are forecasting is expected to
rise by around 11 per cent. We expect our unit costs to fall, such
that the total cost of repairing faults will remain broadly aligned
to our current annual cost of repairing faults.
Figure 7.29: LPN fault rate for 2015 to 2023 – LV underground
cable (non-consac) and HV underground cable
4,500
4,100
3,700
3,300
2,900
2,500
2015/16
2016/17
2017/18
2018/19
Total expenditure underpinning our plan
In summary the LPN plan remains largely a continuation of
our spend profile today. There is a step up in our direct capital
expenditure which is due to an increase in asset replacement
expenditure required to maintain the long-term health of the
network and the need for growing reinforcement that we
anticipate from the later years of the current plan period as the
economy recovers strongly in London. In addition to these we
expect our civil costs to rise from those seen in the current
plan period.
2019/20
7.25
2020/21
LV Main (UG non-Consac)
2021/22
2022/23
LV Main (UG non-Consac) DR5 Average
HV UG Cable
HV UG Cable DR5 Average
500
400
300
200
100
0
We believe that we will achieve greater efficiency and reductions
around our expenditure on inspection and maintenance and
continue to maintain our efficient level of indirect costs.
A summary of our forecast expenditure is shown in Figure
7.30 that shows how the main cost categories change from
our current plan (to 2015) to the end of the forecast planned
expenditure (to 2023).
Figure 7.30: LPN expenditure profile (excluding pass
through costs)
4,500
£m (2012 prices)
400
350
300
250
200
150
100
50
0
4,000
3,500
3,000
310 313
299
288 2,500 17 293
21 285 290
274
15
280
32
15
22 23 15
31
15 261
11 12 24
253
30
26
24
24
26
10
12
13
21 15 15
14
26 13 61
13 13
61
13
10
14
17
60
63
62 63
64
59
65 64
56
105
118 131
159 154
2015/16
2016/17
2017/18
2018/19
3,500
3,000
2,500
2019/20
2020/21
40 42 42 41 41 41 41 42 42 42 42
2013 2014 2015 2016 2017 2018 2019 2020 2021
4,500
2022 2023
Direct opex Direct capex Indirects
Non op and other costs Pension deficit 4,000 Tax allowance
7.26
130 138 134 125 113 109
2015/16
2016/17
2021/22
2017/18
2022/23
2018/19
5
4
3
2
1
0
LV Main (
LV Main (
Average
HV UG Ca
>pg94 | Business plan

South Eastern Power Networks business plan
This network has a similar combination of drivers as EPN, serving
a mix of London and rural areas, with a lower expectation for the
connection of wind generators.
Figure 7.31: Current period expenditure total = £1.9 billion
0.6
0.1 Network operating
0.2 0.4
costs
Indirect costs
0.6
Figure 7.32: Forecast period expenditure total = £2.0 billion
0.5
0.1 0.1
0.4
0.4
0.6
Direct capital expenditure
7.27
Direct capital expenditure primarily consists of the expenditure
on expanding our network (load-related or reinforcement
expenditure) and replacing and refurbishing our assets
(non-load related).
Load-related expenditure
Non load related
Load related
Non operational capex
Load related
Non load related
Network operating costs
Indirect costs
Non operational capex
RPEs
Figure 7.33: SPN load related capital expenditure
£m (2012 prices)
60
50
40
30
20
10
0
2012/13
2013/14
7.28
32
2014/15
2015/16
2016/17
We are expecting our expenditure on expanding and extending
the network to return to more normal levels over the business
plan period. This is based on our core scenario that shows a
return to more normal demand growth patterns.
This forecast alongside new connections forecasts drives our
reinforcement expenditure. Our forecast average annual spend
in the forecast period is more than one and a half times than we
expect to spend over the current plan period.
2017/18
Load related
2018/19
2019/2020
2020/21
2021/22
2022/23
Figure 7.34: Forecast connection activity
LV connections
Asset replacement expenditure
Figure 7.35: Actual/forecast asset replacement
capital expenditure
£m (2012 prices)
15,000
10,000
5,000
120
100
80
60
40
20
0
0
2015
2016
2017
2018
2019
Our expenditure on asset replacement is forecast to decrease
slightly in the forecast period compared to our current plans.
The reduced spend is justified by ever improving understanding
of the condition of our assets and how they are expected to
deteriorate over time. The new modelling approach ARP is
assisting how we decide on our interventions based on a
60
more
holistic view of risk and condition. There are slightly reduced
replacement volumes compared to the current plan period 50and
we are currently reviewing and validating these outputs e.g. via
additional condition sampling.
40
We are currently reviewing all of our investment plans to seek 28
30
30
29
300
200
100
629
226
further efficiencies in delivery, to recognise changes in mix and
to validate the underlying data to support our future forecast 20
costs. These
7.31
unit costs are applied to our current view of the
10
volumes of work to maintain our network to form the total
expenditure plan. We are undertaking further work to refine 0
distribution asset replacements unit costs before submission of
the final business plan in July 2013.
Expenditure on the asset types shown in Figure 7.36 represent
the significant rises in expenditure in our plans which are
alongside more general rises in civil works.
We are also forecasting significant efficiencies and reduced
need for investment in the asset types shown in Figure 7.37
which represent most of the of the reductions in the plan, the
remainder being spread across other asset types due to the
normal variation in replacement profiles.
2020
2021
2022
LV
LV DR5 average
HV & EHV
HV & EHV DR5 average
7.30
Non load related
2023
0
£m
HV and EHV connections
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/20
2020/21
2021/22
2022/23
103
376
OLD
VERSION
123
360
540
58
OLD
488
VERSION
OLD
VERSION
2010/11
2011/12
2012/13
2013/14
7.29
Business plan | >pg95

Figure 7.36
Asset group Component Commentary
Overhead Pole Line LV overhead line We plan to return to our original strategy of conductor replacement following a
main conductor programme of rectification of defects during the current period
Cable
Figure 7.37
33kV underground cable
(Non Pressurised)
A programme of removing existing leaking oil cables is leading to increasing
volumes of these more environmentally friendly assets
Asset group Component Commentary
Switchgear 6.6/11kV Ring Main Units Following an accelerated programme of replacement in the current period the
forecast is to return to more usual levels of work
Cable
132kV underground cable
(non Pressurised)
Forecast is based on leak rates remaining acceptable on pressurised systems
not requiring replacement with these assets
Cable
Switchgear
132kV underground
cable (Gas)
132kV indoor, gas
insulated, ground
mounted circuit breakers
Direct operating expenditure
Inspection and maintenance expenditure
Data suggests that the remaining assets are in good condition following the
programme of work completed in the current plan
A strategy of more refurbishments means our asset replacement spend
is reduced
Figure 7.38: Actual/forecast inspection and maintenance costs
£m (2012 prices)
16
14
12
10
8
6
4
2
0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Inspection & maintenance
Our workload will increase following our comprehensive review.
Our review recognises the criticality of these assets to the
resilience of our networks and need for increased vigilance
against condition deterioration and vandalism.
These upward effects are outweighed by downward movements.
The more significant movements are in ground mounted
substations civil works following a review of how we manage
our civil assets and deliver work. The workload for protection
schemes is also reducing in the forecast plan period following a
detailed survey of protection equipment and evaluation of the
appropriate policy to apply to the actual population of assets.
We are forecasting efficiencies in the unit costs of inspection and
maintenance work, which is shown in Figure 7.39.
Figure 7.39: SPN I&M; composite unit cost efficiency trend
We are currently spending at around the steady-state rate that
we currently expect to be required going forward.
Our total forecast inspection and maintenance costs reduce from
the current spend levels. There are a number of movements
both positive and negative. Two major upward drivers of cost
are increasing inspection volumes for rising and lateral mains as
we identify the scale and scope of the requirements to manage
these assets. In addition we are planning greater volumes of pole
line repairs as a result of the recent survey outcomes suggesting
the condition is worse than anticipated and we are identifying
poles missing from our asset register. We are also seeing growing
needs for other types of inspections including cable bridges.
1.2
1.0
0.8
0.6
0.4
0.2
0.0
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Forecast vs 2011/12
2022
2023
2024
7.32
>pg96 | Business plan

Faults expenditure
Figure 7.40: Actual/forecast faults costs
Figure 7.42: SPN fault rate chart for 2015-2024 (DR5 average
line) – LV UG non-consac and HV UG
£m (2012 prices)
28
27
26
25
24
23
22
21
Our costs are based on our projections of fault rates by voltage
and asset group multiplied by the average cost of fault repair for
each of these assets.
Overall we expect fault costs to be broadly similar to history
with volumes and costs falling slightly between our current plan
period and the future period but with greater efficiency in
repair faults.
Figure 7.41: SPN faults, composite unit cost efficiency trend
1.2
1.0
0.8
0.6
0.4
0.2
0.0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Faults
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Forecast vs 2011/12
Our projections of fault rates are forecast to be maintained at
a constant level based on the delivery of our replacement and
maintenance policies. We are forecasting rises in HV underground
cable and LV underground mains (those that are not Concentric
Neutral Solid Aluminium Conductor). This growth is expected
due to deterioration in condition of these assets. We are
increasing our understanding of the condition of our underground
assets through increasing our use of post-fault analysis and
investigation. We are forecasting an average 0.6 per cent growth
in these faults per annum, but overall we are expecting a small
reduction in the fault volumes.
7.35
4,500
4,000
3,500
3,000
2,500
2,000
Linear ( LV Main (UG non-Consac) DR5
Tree cutting expenditure
Average)
Figure 7.43: Actual/forecast tree cutting costs
7.34 7.36
£m (2012 prices)
7.8
7.6
7.4
7.2
7.0
6.8
6.6
6.4
2015/16
2016/17
2017/18
2018/19
Our costs are based on the line length affected by trees. Our
cost are held constant through the forecast plan period which
assumes that any increase cost due to additional new lines
affected by trees will be offset by efficiencies in delivering
tree cutting.
Total expenditure underpinning our plan
1,000
900
800
700
600
500
In summary the SPN plan remains largely a continuation of
our spend profile today, with little change between our latest
forecast for the current plan period and future plan levels
of expenditure. There is a rebalancing of the mix of drivers
underpinning the plan, showing the increased forecast for
network reinforcement work (consistent across the region) and
cost of civil works, being offset by a reduction in the forecast of
need for asset replacement.
7.37
2019/20
2020/21
2021/22
2022/23
LV Main (UG non-Consac)
LV Main (UG non-Consac) DR5 Average
HV UG Cable
HV UG Cable DR5 Average
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Tree cutting
Business plan | >pg97

Figure 7.44: SPN total expenditure profile (excluding pass
through costs)
£m (2012 prices)
400
350
300
250
200
150
100
50
0
280 285
279 273
264
21 23
245
251
256
22
254 254 257
19
21 21
16
15 20 20 14 12 11 11
17 15 23
19
12
20
13 20 18 11 9
14
11
15 15
16 17
21
60 61 11
60
60
60
59 59 59
60 60
59
114 120
86
103
46 45 45 44 44 45 44 44 45 46 45
Common and allocated costs
Overall indirect costs
Figure 7.45: Actual/forecast indirect costs
£m (2012 prices)
300
250
200
150
100
50
0
120 116 111 105 104 110 116
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Direct opex Direct capex Indirects
Non op and other costs Pension deficit Tax allowance
7.38
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
2023/24
Total indirect costs
During the current plan period we have made significant
efficiency gains in the provision of business support activities and
our closely associated indirects. For our 2013 forecast business
plan we will incorporate additional benchmarking of our business
supports costs and factor in further achievable efficiency that
is revealed. At this time we believe that maintaining our total
business support costs constant over the forecast plan period is
efficient. This implies productivity gains are found to compensate
for growth in requirements, e.g. through new legislation,
additional technology (e.g. providing platforms to support social
media were not envisaged at the setting of DPCR5).
7.39
Our closely associated indirect costs are assumed to move with
our direct costs. Our 2012 forecast business plan shows these are
expected to be broadly constant on an average annual basis and
approximately the same per annum as 400
400
we are forecasting to the
end of the 2015. We are assuming that we can deliver efficiency
350
in our operations to 350 largely offset any expected growth.
We expect some changes to these costs as we develop our
300
thinking on the future 300operating 280 285 279.7
model and build 284.6 278.6
in our thinking 272.8 2
21.2 22.7
264.0
22.0
on the overall effect on efficiency and performance 21.1 21.1 that 244.7 our
251.4 19.2 2
21 23
250
245 251 16.3
15.2 19.9 20.1
1
250
transformation plans will have on the 21 customer
17.2
21 15.1 23.4
12.1
20.1
facing functions 19.2
13.0
2
14.0
17 15
21.1 23
OLD 15
10.8
1
(Customer Service, Connections and Network
200
19
60.3 Operations).
60.5 11.0
60.2 1159.6
200
21
59.1
We expect these transformations 60 61 11 59.7
5
to deliver higher VERSION
levels 58.7 of
150
60
service at a more efficient 150 cost.
59
100 113.6 120.3
120.1 116.5
102.8
110.6 Average annual spends for our total indirect costs across 85.7
100 114 120
all three
networks are therefore predicted to remain consistent 86 103
1
50
with the
current efficient level 50and to be maintained 46.3 over 44.9 the 44.8 forecast
43.7 44.3 44.5 43.9 4
business plan period. This shows 46 a slight 0 increase 45 in our 45 closely 44
associated indirects costs 0
2013 2014 2015 2016 2017 2018 2019 2
(circa 1 per cent) that reflects the
increase in direct work that we
2013
plan to complete
2014
Direct and
2015
opexa focus on
2016 2
Direct ca
increasing our call centre capabilities. There is Indirects a small reduction Non op
(circa 3 per cent) in our business Direct opex support costs Pension Direct that keeps deficit capexthe
Indirects Tax allow
average total indirects costs flat over the forecast business
plan period.
Non-operational capital expenditure
Our 2012 forecast business plan contains expenditure on
transport and property that largely unchanged throughout the
period. These are based on bottom-up analysis of requirements
for properties and vehicles to enable the organisation to be
effective in delivering on its commitments. Our approaches to
running our property and transport were well regarded at the
previous review by Ofgem’s experts.
IT
Our expenditure on IT is much more dependent on the drivers on
our business to adapt to the changing needs and expectations
of our customers. Our 2012 forecast business plan includes a
budget of circa £100 million for IT transformation across our
business over the period. As part of our benchmarking of other
utility businesses we have identified that integration of key IT
systems is a key enabler of future efficiency improvements and
appears essential to support the transition to the low carbon
economy. The business case for this expenditure is still at the
developmental stage. We will refine this for the 2013 business
plan submission and we will amend our view of the appropriate
and well justified expenditure.
Real price effects
We have taken a view for the forecast business plan period of
the real price effects that should apply for internal and contract
labour. This is based on the existing work undertaken for the Gas
Distribution Networks and the work we carried out at the time of
Ofgem’s previous review.
On materials it is based on our own internal forecasts of key
commodities and reflects the mix of materials that we purchase.
The latter is most effected by global movements and hence is
subject to the balance of supply and demand. The economic
downturn has generally suppressed demand amongst key
commodities with examples of the supply side allowing stocks to
run down leading to oversupply in some markets. We will review
all of these assumptions for our 2013 forecast business
plan submission.
£m
>pg98 | Business plan

Figure 7.46
Real price effects
Current plan
(DPCR5)
Forecast business
plan (RIIO-ED1)
Direct capital
1.1% 1.0%
expenditure
Direct operating
1.4% 1.3%
expenditure and
indirects
Efficiency 1.0% 0.9%
Pass through costs
All electricity distribution companies in Great Britain incur
costs due to the way in which the industry is structured and
over which they have no control. Three costs that we incur
are described in the Figure 7.47. Based on the transmission
companies business plans, we anticipate that Transmission Exit
Charges are expected to grow significantly (more than 60 per
cent for EPN and LPN and more than 80 per cent for SPN) over
the forecast plan period. The charts show the forecasts of these
charges for our three networks. Ofgem has proposed a lower
amount of expenditure for National Grid and therefore the values
shown here are likely to reduce. These will be refined in our next
business plan.
Figure 7.47
Pass through
item
Licence
charges
Business rates
Transmission
exit charges
Who charges them and why
Levied by Ofgem on all companies who are
subject to their authority. The licence fee is
allocated by them in order to recover the
costs of their obligations in regulating the
electricity industry
Levied by HM Treasury based on the Valuation
Office’s assessment of the rateable value of
our assets
Levied by National Grid based on the capacity
of interconnections between their network
and ours. These charges are expected to
grow significantly over the period between
2015 and 2023 to reflect the increases in
investment in the transmission network as
agreed with Ofgem
Figure 7.48: EPN pass through costs
£m (2012 prices)
120
100
80
60
40
20
0
2013 2011 2012 2014 2013 2015 2014 2016 2015 2017 2016 2018 2017 2019 2018 2020 2019 2021 2020 2022 2021 2023
Figure 7.49: LPN pass through costs
£m (2012 prices)
120
100
80
60
40
20
0
Figure 7.50: SPN pass through costs
£m (2012 prices)
120
100
80
60
40
20
0
Transmission exit charges
Pass through costs
Pass through cost related revenue
7.48
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Transmission exit charges
Pass through costs
Pass through cost related revenue
7.49
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Transmission exit charges
Pass through costs
Pass through cost related revenue
7.50
Business plan | >pg99

8 Financing: what this means for bills
Consultation questions for this section
Financing
Q20. What do you think about our assumptions regarding the
financing of our activities and our proposed revenues and prices
>pg100 | Business plan

In this chapter we outline the impact on our customers’ bills
from our forecast business plan.
Customers who receive service and ultimately pay for the
upkeep and development of our three distribution networks
have been involved in defining this plan. As a result we have
made changes that reflect their views on priorities and how
the future may evolve.
We are requesting revenue to allow us to operate our business
that reflects the risk we take, to ensure we are able to finance
our activities.
Our charges to our customers are amongst the lowest in the
industry and this forecast business plan would allow us to
keep our charges flat (excluding inflation) into the future for
the majority of our customers (LPN and SPN) with rise in our
charges to our customers in EPN.
8.1 Developing the revenue requirement
We are required to operate our business in a financially sound
manner, maintaining an investment grade credit rating and
avoiding financial distress. The revenue we require to fund our
business covers the costs of operation, the cost of financing our
investments, the associated tax and other liabilities such as
the pensions for our employees.
Cost of capital
With the adoption of an indexation for the cost of debt in the
RIIO-ED1 framework, the cost of capital discussion is limited to
a smaller number of factors. Our current view based on initial
financial modelling is that most of the factors could remain
unchanged from today. We believe that the transition to the
low carbon economy introduces greater uncertainty and without
additional mitigations will lead to a higher cost of equity. We are
currently working on the basis of a cost of equity of 7 per cent
and we will provide evidence to support that in our next business
plan. This will include analysis of cash flow risk, investment
uncertainties and market viewpoints to help identify the
appropriate value.
For reference Figure 8.1 summarises the values that support our
view on the appropriate cost of capital.
Figure 8.1
Current plan
(DPCR5)
Forecast business
plan (RIIO-ED1)
Cost of equity 6.73% 7.00%
Notional
65.0% 65.0%
gearing
Cost of debt 3.6% Rolling 10 year
average
Vanilla WACC 4.69% 4.24%-4.17%
estimated
Totex split
(fast/slow)
RAV
depreciation
Ofgem target
dividend yield
Tax and pensions
15/85 (business
support + nonoperational
capital
expenditure100% fast)
30/70 on all
expenditure
categories
20 years Single period
transition to 45 years
5% on regulatory
equity
5% on regulatory
equity
We are assuming the DPCR5 approach and assumptions for the
on-going treatment of pensions and tax.
Revenue requested per network
In the revenue analysis in this sub-section we have shown our
plans with and excluding those costs that we cannot control,
such as transmission exit charges. We have included all of the
expenditure we have forecast to spend over the period.
The charts show the year-by-year revenue we believe is efficient
to allow us to finance our operations. In general, the revenue
requirement is flat in real terms for our networks.
One significant factor is the increasing pass through costs
(predominately transmission exit charges) that are causing a
significant rise of revenue compared to the current plan period.
This is in addition to the funding of additional investments as
described above.
EPN revenues are forecast to average £544 million per annum,
with a compound average growth rate of 1.3 per cent from 2015.
Business plan | >pg101

l
Figure 8.2: EPN revenue profile (real terms)
£m (2012 prices)
LPN revenues are forecast to average £422 million per annum,
with a zero compound average growth rate from 2015.
Figure 8.3: LPN revenue profile (real terms)
£m (2012 prices)
600
500
400
300
200
100
0
CAGR: 6.5%
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
Profiled revenue
CAGR: 0.0%
CAGR: 6.6%
8.1
CAGR: -1.5%
Profiled revenue ex pass through
SPN revenues are forecast to average £352 million per annum,
with a zero compound average growth rate from 2015.
Figure 8.4: SPN revenue profile (real terms)
£m (2012 prices)
600
500
400
300
200
100
0
600
500
400
300
200
100
0
CAGR: 4.9% CAGR: 1.3%
CAGR: 4.8% CAGR: 0.5%
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
Profiled revenue
CAGR: 8.1% CAGR: 0.0%
CAGR: 7.7% CAGR: -1.2%
8.2 The impact on our customers
We have developed our forecast business CAGR plan 5.5% with our
600
customers and stakeholders. The overall impact on our
customers is to keep bills constant 500from 2015 in the forecast
plan period for LPN and SPN, with 400bills in EPN rising due
to increases in investment until 2018 and then remaining
300
constant for the remainder of the forecast period to 2023.
200
We have estimated the impact on domestic and non-domestic
100
customers. This has been done by extrapolating from today’s
charges in line with the increase in 0revenue that we have
estimated we need to finance our businesses in the forecast
plan period.
Underlying this is the flat revenue profile for our three Profiled networks, revenue
with rises beyond 2015 due to inflation for LPN and SPN,
whereas for EPN revenues flatten from 2019. If we were to
exclude the effects of pass through costs we would expect to
see bills fall in real-terms. We show the real-terms bill impact
in Figure 8.5 and Figure 8.6 (including pass through costs) to
demonstrate the underlying cost impact of our plans (without
the inflation impact).
This forecast business plan 500 should see each of our networks
450
remain amongst the lowest cost electricity distribution
400
companies in Great Britain.
350
Figure 8.5: Projected change
300in average annual domestic bill
250
(consumption = 3,330kWh) (excluding inflation)
£m
200
150
100
50
0
2010/11
EPN
SPN
400
DNO average forecast
350
300
250
Figure 8.6: Projected change in average annual non-domestic bill
(consumption = 9,900kWh) (excluding 200 inflation)
8.2
0
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
2020/21
2021/22
2022/23
Profiled revenue
Profiled revenue ex pass through
Profiled revenue ex pass through
£ (2012 prices)
£ (2012 prices)
160
140
120
100
80
60
40
20
0
450
400
350
300
250
200
150
100
50
0
£m
£m
150
100
50
2011/12
2010/11
2012/13
2011/12
2013/14
OLD
VERSION
2014/15
2015/16
2016/17
2017/18
2018/19
2019/2020
Profiled revenue
Profiled revenue ex pass through
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
LPN
DNO average
CAGR 9%
Highest cost DNO
2012/13
OLD
VERSION
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2020/21
2019/2020
Profiled revenue
Profiled revenue ex pass through
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
EPN
SPN
DNO average forecast
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
LPN
DNO average
Highest cost DNO
2016/17
2017/18
2018/19
CA
OLD
VERSION
2019/2020
Profiled revenue ex pass through
CAGR
>pg102 | Business plan
8.3

Business plan | >pg103

9 Managing risk and uncertainty
A key consideration for our business plan is the management of risk and
uncertainty in a time of transition to a decarbonised energy sector in the UK.
We are mindful of our obligations as a DNO to manage risk in the interest of
all our stakeholders. We have a well-developed strategy for the management
of corporate risk and this is reflected in our business plan. The primary
considerations in developing our approach to risk management in our forecast
business plan are to:
• Recognise that we are best placed to manage risks to the delivery of the
business plan
• Reflect the overall risks with an appropriate rate of regulated return on equity
• To use uncertainty mechanisms proposed by Ofgem where we can materially
demonstrate that we have considered the impact on customers as well
as stakeholders
>pg104 | Business plan

9.1 Key areas of uncertainty in
the future
There is considerable uncertainty about the best way to
meet the challenges around the transition to the low-carbon
economy whilst continuing to deliver reliable, value for money
for networks for both existing and future customers.
We share the Government’s vision for the low carbon transition.
It is up to us to meet the challenges and opportunities of
delivering the networks required for a sustainable, low carbon
energy sector. However there is considerable uncertainty about
the best way to meet these challenges whilst delivering value
for money for existing and future customers.
Even with the most advanced forecasting models it remains
impossible to accurately predict the future. Under the new
regulatory framework, the price control will be set for eight
years (previously five years) and we will need to make decisions
about the longer term, including taking action in the current price
control period to deliver primary outputs and value for money in
future periods.
Examples of uncertainty include the possibility that revenues
raised from customers could be higher or lower than necessary
to cover the costs of providing network services, with customers
paying more or less for network services than was required.
The key areas of uncertainty that we have identified for our
business plan are summarised in the table.
Figure 9.1
Category Area of Uncertainty Our Proposed Uncertainty Mechanism
Load
• Rate of take up of low carbon technologies
(e.g. electric vehicles, heat pumps) – time to connect
• A measure of the volume of work we have to
undertake on our low voltage network as a result of
• Rate of load growth due to decarbonisation
low carbon technologies connecting –
annual frequency
• Ability to predict and manage load growth
• Clustering – regional combination of low
carbon technology take up and load growth due
to decarbonisation
Non-load • New technologies on the network (new standard of • Re-opener in 2019
higher specification to be rolled-out as part of
non-load replacement)
Cost
• Increase in general official measure of inflation • Indexation of annual revenues
Specific issues
• Costs of operating network business outturns higher
than forecast
• Higher than inflation increase in cost of material
(e.g. copper, fuel)
• Increase in pension deficit caused by exogenous factors
• Government requirements to increase security
standards
• Legislation to enable local authorities to increase
charges for lane rental for essential infrastructure
repair works
• Increased expenditure to allow network systems to
recover from major national outage
• Increased costs of roll out of new innovations
in technology
• Ex ante allowance with cost saving/overrun sharing
with customers
• Fixed ex ante allowance
• Allowed pass through of efficient costs
• Re-opener in 2019 to allow for efficiently incurred cost
increases
• Re-opener in 2019 to allow for efficiently incurred cost
increases
• Re-opener in 2019 to allow for efficiently incurred cost
increases
• Re-opener in 2019 to allow for efficiently incurred cost
increases
Business plan | >pg105

9.2 Allowing flexibility
Ofgem recognises the issues around uncertainty and the
regulatory framework aims to manage this risk via a
combination of scenarios, uncertainty mechanisms, and
frameworks that allow revenue to be adjusted during the price
control period in response to changes in operating conditions.
Before uncertainty mechanisms are considered, Ofgem need
to have the confidence that we have tried to capture the
uncertainty via a rigorous scenario process. We will include four
scenarios in our business plan, based on the DECC scenarios, and
determine the efficient allowance corresponding to
each scenario.
DNOs have the flexibility to choose one of these scenarios
as their ‘baseline’ or submit an alternative scenario with an
alternative baseline efficient allowance as long as:
• They can justify the reasonableness of the chosen ‘base line’
scenario (in both cases)
• They can justify the differences with the DECC scenarios (in the
latter case)
• They can demonstrate they can move (efficiently) to the DECC
‘high’ or ‘low’ scenarios (as applicable)
This process ensures Ofgem that the most efficient
ex-ante allowance has been set, given all the information and
knowledge available at that time, including the flexibility in the
plan to achieve its outputs efficiently across a range of scenarios,
including the ‘high’ scenario.
For the residual uncertainty, Ofgem and the DNOs can propose
frameworks to adjust the revenue. In the current plan period
(DPCR5) we have 21 areas where we are incentivised in
various ways. An overview of all incentivised activities will be
maintained during the DPCR5 in order to ensure that we have
set appropriate targets and that action plans are in place to
deliver them.
>pg106 | Business plan

Business plan | >pg107

10 Glossary
A
Asset risk and prioritisation (ARP)
Models for establishing and forecasting the health of network
assets. The ARP models use a combination of information relating
to an asset’s age, environment, duty and specific condition and
performance information to derive a health score for each asset,
underpinned by proximity to end of life and probability of failure
B
Business carbon footprint (BCF)
The BCF scheme was introduced as a reputational incentive in
DPCR5 to encourage DNOs to consider the direct carbon impact of
conducting their operations and to be proactive in the reduction
of emissions
Broad measure of customer satisfaction
(BMoCS)
A composite incentive consisting of a customer satisfaction
survey, a complaints metric and stakeholder engagement. It was
introduced for DPCR5 and is designed to drive improvements in
the quality of the overall customer experience by capturing and
measuring customers’ experiences of contact with their DNO
across the range of services and activities the DNOs provide
C
Capital expenditure (Capex)
Expenditure on investment in long-lived distribution assets, such
as underground cables, overhead electricity lines and substations
Combined heat and power (CHP)
The simultaneous generation of usable heat and electricity in a
single process, thereby discarding less wasted heat
Compound annual growth rate (CAGR)
Average annual growth rate over a defined period of time
Customer interruptions (CIs)
The number of customers whose supplies have been interrupted
per 100 customers per year over all incidents, where an
interruption of supply lasts for three minutes or longer, excluding
re-interruptions to the supply of customers previously interrupted
during the same incident.
Customer minutes lost (CMLs)
The duration of interruptions to supply per year – average
customer minutes lost per customer per year, where an
interruption of supply to customer(s) lasts for three minutes
or longer
D
DCLG
Department for Communities and Local Government
DECC
Department of Energy and Climate Change
DEFRA
Department for Environment, Food and Rural Affairs (DEFRA)
Distributed generation (DG)
Distributed generation (also known as embedded or dispersed
generation) refers to an electricity generating plant connected
to the distribution network . There are many types and sizes of
distributed generation facilities. These include Combined Heat and
Power (CHP), wind farms, hydro-electric power or one of the new
smaller generation technologies such as photo-voltaic cells
Distribution network operators (DNOs)
A DNO is a company which operates the electricity distribution
network which includes all parts of the network from 132kV down
to 230V in England and Wales. In Scotland 132kV is considered
to be a part of transmission rather than distribution so their
operation is not included in the DNOs’ activities. There are 14
DNOs in the UK which are owned by six different groups
Distribution price control review 5 (DPCR5)
Distribution price control review 5. This price control runs from 1
April 2010 until 31 March 2015
>pg108 | Business plan

Distribution system operator (DSO)
As DNOs actively manage the local levels of demand, whilst at
the same time accommodating varying amounts of generation
onto the network, they will start to behave like system operators
(ie locally balancing demand and supply on their networks),
known as the DSO
E
EA
Environment Agency
Eastern Power Networks (EPN)
One of the three distribution network licence areas owned and
operated by UK Power Networks. The EPN network covers the
East of England
Element Energy (EE)
Element Energy, a strategic energy consultancy, have provided
economic analysis to inform the 2013 forecast business plan
Electric vehicle (EV)
Vehicles that utilise electric motor(s) or traction motor(s) and are
powered by either an external power station, on-board electrical
generators, or stored electricity
Electricity, safety, quality and continuity
regulations 2002 (ESQCR)
The ESQCR specify safety standards, which are aimed at
protecting the general public and customers from danger. In
addition, the regulations specify power quality and supply
continuity requirements to ensure an efficient and economic
electricity supply service to customers
Extra high voltage (EHV)
Voltages over 20kV up to, but not including, 132kV
F
Fast money
Fast money is the revenue that is matched to the year
of expenditure
Feed in tariff (FIT)
The price per unit of electricity that a utility or supplier has to
pay for renewable electricity from private generators. These are
used to encourage distributed renewable generation through
private generators
Forecast business plan questionnaire (FBPQ)
Questionnaire through which data is submitted to Ofgem to help
form Ofgem’s initial views on the revenue requirements for price
control reviews
G
Gigawatt (GW)
Measure of power equal to one billion watts
Guaranteed standards of performance (GSOPs)
Guaranteed Standards set service levels to be met in each
individual case and are established by a Statutory Instrument.
If the licence holder fails to provide the level of service required,
it must make a payment to the customer affected subject to
certain exemptions
H
Health index (HI)
Framework for collating information on the health (or condition)
of distribution assets and for tracking changes in their condition
over time. The HI will be used by Ofgem to inform an assessment
of the efficacy of the DNOs’ asset management decisions over the
price control period. Health index arrangements were introduced
as a part of DPCR5
High voltage (HV)
Voltages over 1kV up to, but not including, 22kV
Business plan | >pg109

I
Indirect cost efficiency (ICE)
The ICE programme was launched in 2011 in order to close the
gap with the benchmark distribution companies in relation to
indirect costs
Information technology (IT)
Technology systems used to manage information. In UK Power
Networks this includes our management information systems,
asset information systems and operational IT
Inspections and maintenance (I&M)
The activities of both:
• Inspections – the visual checking of the external condition
of assets
• Maintenance – the invasive (‘hands on’) examination of plant
and equipment
Innovation funding incentive (IFI)
The IFI is intended to encourage DNOs to invest in appropriate
research and development activities that are designed to enhance
the technical development of distribution networks (up to and
including 132 kV) and to deliver value (ie financial, supply quality,
environmental, safety) to end customers
Interruption incentive scheme (IIS)
The interruption incentive scheme is a symmetric annual rewards
and penalties scheme based on each DNO’s performance against
their targets for the number of customers interrupted per 100
customers (CI) and the number of customer minutes lost (CML)
K
KiloWatt hour revenue driver (kWh)
A revenue allowance based on units distributed (kWh)
L
Load index (LI)
Framework for collating information on the utilisation of individual
substations or groups of interconnected substations and for
tracking changes in their utilisation over time. The LI will be used
by Ofgem to inform an assessment of the efficacy of the DNOs’
general reinforcement decisions over the price control period. The
Load Index was introduced as a part of DPCR5
Load related expenditure (LRE)
The installation of new assets to accommodate changes in the
level or pattern of electricity or gas supply and demand
London Power Networks (LPN)
One of the three distribution network licence areas owned and
operated by UK Power Networks. The LPN network covers
Greater London
Low Carbon Networks Fund (LCNF)
A mechanism introduced under the fifth distribution price control
review to encourage the DNOs to use the forthcoming price
control period to prepare for the role they will have to play as GB
moves to a low carbon economy. The fund will see up to
£500 million made available for DNOs and partners to innovate
and trial new technologies, commercial arrangements and ways
of operating their networks
Low voltage (LV)
This refers to voltages up to, but not including, 1kV
M
Megawatt (MW)
Measure of power equal to one million watts
Megawatt-hour (MWh)
A measure of energy production or consumption equal to one
million watts produced or consumed for one hour
N
Non load related expenditure (NLRE)
The replacement or refurbishment of assets which are either at
the end of their useful life due to their age or condition, or need
to be replaced on safety or environmental grounds
O
Office of gas and electricity markets (Ofgem)
Responsible for regulating the gas and electricity markets in the
UK to ensure consumers’ needs are protected, including their
interests in the reduction of greenhouse gases and in the security
of the supply of gas and electricity. This involves promoting
competition, wherever appropriate, and regulating the monopoly
companies which run the gas and electricity networks
P
Photovoltaic (PV) connection assessment tool
Planning tool which assesses the impact of concentrations of
small scale generation on our networks e.g. solar panels, enabling
us to provide a better and faster service to our customers
R
Real price effects (RPE)
Increase in prices over and above increases in the Retail Price
Index (RPI). For example, increases in the cost of copper, steel,
direct or contract labour over and above increases in RPI
>pg110 | Business plan

Regulatory asset value (RAV)
The value ascribed by Ofgem to the capital employed in the
licensee’s regulated distribution or (as the case may be)
transmission business (the ‘regulated asset base’). The RAV is
calculated by summing an estimate of the initial market value
of each licensee’s regulated asset base at privatisation and
all subsequent allowed additions to it at historical cost, and
deducting annual depreciation amounts calculated in accordance
with established regulatory methods. These vary between classes
of licensee. A deduction is also made in certain cases to reflect
the value realised from the disposal of assets comprised in the
regulatory asset base. The RAV is indexed to RPI in order to allow
for the effects of inflation on the licensee’s capital stock. The
revenues licensees are allowed to earn under their price controls
include allowances for the regulatory depreciation and also for the
return investors are estimated to require to provide the capital
RPI-X
The form of price control currently applied to network monopolies.
Each company is given a revenue allowance in the first year of
each control period. The price control then specifies that in each
subsequent year the allowance will move by ‘X’ per cent in
real terms
Revenue = incentives + innovation + outputs
(RIIO)
Ofgem’s new regulatory framework, stemming from the
conclusions of the RPI-X@20 project, to be implemented in
forthcoming price controls. It builds on the success of the
previous RPI-X regime, but better meets the investment and
innovation challenge by placing much more emphasis on
incentives to drive the innovation needed to deliver a
sustainable energy network at value for money to existing
and future consumers
RIIO electricity distribution 1 (RIIO-ED1)
The first RIIO price control review to be applied to the electricity
distribution network operators, following DPCR5. This price control
will run from 1 April 2015 to 31 March 2023
Remote terminal unit (RTU)
Communications device that transmits readings and information
about the status of the network back to the control centre
Renewable heat incentives (RHI)
Financial incentive scheme for renewable heat generation that
will help the UK reduce carbon emissions and hit its European
Union renewable energy targets
Ring main unit (RMU)
A HV switchgear arrangement for the connection and protection
of distribution transformers
S
Slow money
Slow money is where costs are added to the RAV and revenues
allow recovery of the costs over time together with the cost of
financing this expenditure in the interim
South Eastern Power Networks (SPN)
One of the three distribution network licence areas owned and
operated by UK Power Networks. The SPN network covers the
South East of England
Site of Special Scientific Interest (SSSI)
Sites of Special Scientific Interest give legal protection to wildlife,
geological and physiographical heritage under the Wildlife and
Countryside Act 1981 There are over 4000 SSSIs in England,
covering around 8 per cent of the country
Sulphur Hexafluoride (SF6)
One of the most potent greenhouse gases and is widely used in
transmission and distribution equipment
System operator (SO)
National Grid Electricity Transmission is the electricity system
operator, responsible for managing the operation of the
electricity transmission system. They balance supply and demand
ensuring the stability and security of the power system and the
maintenance of satisfactory voltage and frequency
T
Tonnes of carbon dioxide equivalent (tCO 2
e)
Unit of measurement that allows global warming potential of
different greenhouse gases to be compared
Total operating and capital expenditure (totex)
Total of capital expenditure (capex) plus operational
expenditure (opex)
W
Weighted average cost of capital (WACC)
This is the weighted average of the expected cost of equity and
the expected cost of debt
Business plan | >pg111

UK Power Networks (Operations) Limited
Registered office: Newington House, 237 Southwark Bridge Road, SE1 6NP
Registered number: 3870728 registered in England and Wales