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Consultancy Support for Electricity Transmission and Distribution Revenue Controls (2016-2020) COMMISSION FOR ENERGY REGULATION (CER) DSO Final June 2015
Transcript of Consultancy Support for Electricity Transmission … Consultancy Support for Electricity...
Consultancy Support for Electricity Transmission
and Distribution Revenue Controls (2016-2020)
COMMISSION FOR ENERGY REGULATION (CER)
DSO
Final
June 2015
DSO
i
Consultancy Support for Electricity Transmission and Distribution Revenue
Controls (2016-2020)
Project no: PG021000
Document title: DSO
Document no: Final
Revision: 1
Date: June 2015
Client name: Commission for Energy Regulation (CER)
Client no: Client Reference
Project manager: Gary Flynn
Author: Paul Francis, Keith Paintin
File name: DSO
Sinclair Knight Merz (Europe) Ltd (Jacobs)
7th Floor, Stockbridge House
Trinity Gardens
Newcastle upon Tyne, NE1 2HJ
T +44 191 211 2400
F +44 191 211 2401
www.jacobs.com
COPYRIGHT: The concepts and information contained in this document are the property of Sinclair Knight Merz (Europe) Limited (Jacobs). Use
or copying of this document in whole or in part without the written permission of Jacobs constitutes an infringement of copyright.
Document history and status
Revision Date Description By Review Approved
Draft April 2015 Consolidated Interim Reports G Flynn
P Francis
K Paintin
R Clark R Clark
Draft-Final May 2015 Consolidated Interim Reports – CER comments addressed G Flynn
P Francis
K Paintin
R Clark R Clark
Final June 2015 CER and Company comments addresed G Flynn
P Francis
K Paintin
R Clark R Clark
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Contents
Executive Summary ............................................................................................................................................... 1
1. Introduction .............................................................................................................................................. 20
1.1 This Report ................................................................................................................................................................................... 20
1.2 Data Sources and Assumptions.................................................................................................................................................... 21
2. Review of PR3 Operating Expenditure .................................................................................................. 22
2.1 Overview ....................................................................................................................................................................................... 22
2.2 Controllable Costs......................................................................................................................................................................... 24
2.2.1 Network Operations and Maintenance.......................................................................................................................................... 24
2.2.2 Asset Management ....................................................................................................................................................................... 29
2.2.3 Metering ........................................................................................................................................................................................ 30
2.2.4 Customer Service ......................................................................................................................................................................... 31
2.2.5 Provision of Information ................................................................................................................................................................ 32
2.2.6 Corporate charges ........................................................................................................................................................................ 33
2.2.7 Sustainability and R&D ................................................................................................................................................................. 33
2.2.8 Other ............................................................................................................................................................................................. 34
2.3 Non Controllable Costs ................................................................................................................................................................. 34
2.4 Conclusions and Findings ............................................................................................................................................................. 35
3. Review of PR4 Operating Expenditure .................................................................................................. 36
3.1 General / Overview ....................................................................................................................................................................... 36
3.2 Controllable Costs......................................................................................................................................................................... 38
3.2.1 Overall Manpower ......................................................................................................................................................................... 38
3.2.2 Network Operations and Maintenance.......................................................................................................................................... 39
3.2.3 Asset Management ....................................................................................................................................................................... 41
3.2.4 Metering ........................................................................................................................................................................................ 42
3.2.5 Customer Service ......................................................................................................................................................................... 43
3.2.6 Provision of Information ................................................................................................................................................................ 44
3.2.7 Telecoms ...................................................................................................................................................................................... 45
3.2.8 Sustainability and R&D ................................................................................................................................................................. 45
3.2.9 Corporate charges ........................................................................................................................................................................ 46
3.2.10 Insurance ...................................................................................................................................................................................... 47
3.2.11 Legal ............................................................................................................................................................................................. 47
3.2.12 Pensions ....................................................................................................................................................................................... 48
3.2.13 Environmental ............................................................................................................................................................................... 48
3.2.14 Health and Safety ......................................................................................................................................................................... 49
3.2.15 Non controllable costs................................................................................................................................................................... 49
3.3 Report Findings............................................................................................................................................................................. 50
4. Review of PR3 Capital Expenditure ....................................................................................................... 51
4.1 General ......................................................................................................................................................................................... 51
4.2 Network Related Expenditure ....................................................................................................................................................... 55
4.2.1 New Demand Connections ........................................................................................................................................................... 55
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4.2.2 Generator Connections ................................................................................................................................................................. 61
4.2.3 Load Related Reinforcement ........................................................................................................................................................ 63
4.2.4 Dismantling Costs ......................................................................................................................................................................... 73
4.2.5 Non-Repayable Line Diversion Costs ........................................................................................................................................... 75
4.3 Non Load Related Capex.............................................................................................................................................................. 76
4.3.1 Renewal Programme .................................................................................................................................................................... 78
4.3.2 Response Capex .......................................................................................................................................................................... 90
4.3.3 Continuity Capex........................................................................................................................................................................... 91
4.3.4 System Control Network Capex .................................................................................................................................................... 92
4.4 Non Network Related Expenditure................................................................................................................................................ 92
4.4.1 Accommodation Fixtures and Fittings and Office Equipment ....................................................................................................... 93
4.4.2 Vehicles ........................................................................................................................................................................................ 94
4.4.3 IT Systems .................................................................................................................................................................................... 94
4.4.4 Environment .................................................................................................................................................................................. 94
4.4.5 System Control and Telecoms ...................................................................................................................................................... 94
4.4.6 Smart Metering Expenditure ......................................................................................................................................................... 95
4.5 Summary & Conclusions............................................................................................................................................................... 95
4.5.1 Capex Overview............................................................................................................................................................................ 95
4.5.2 Demand Connections ................................................................................................................................................................... 96
4.5.3 Generator Connections ................................................................................................................................................................. 96
4.5.4 Load Related Reinforcement ........................................................................................................................................................ 97
4.5.5 Retirements (Dismantling) Capex ................................................................................................................................................. 98
4.5.6 Diversions ..................................................................................................................................................................................... 98
4.5.7 Non-Load Related Capex ............................................................................................................................................................. 98
4.5.8 Non-Network Capex.................................................................................................................................................................... 100
5. Review of PR4 Capital Expenditure ..................................................................................................... 101
5.1 Load Related Expenditure .......................................................................................................................................................... 103
5.1.1 PR4 New Demand Connections ................................................................................................................................................. 104
5.1.2 Generator Connections ............................................................................................................................................................... 108
5.1.3 Load Related Reinforcement ...................................................................................................................................................... 110
5.1.4 Dismantling Costs ....................................................................................................................................................................... 123
5.1.5 Non-Repayable Line Diversion Costs ......................................................................................................................................... 124
5.2 Non Load Related Capex............................................................................................................................................................ 125
5.2.1 Non Load Related Capex – Overview ........................................................................................................................................ 125
5.2.2 Renewal Programmes ................................................................................................................................................................ 129
5.2.3 Continuity Capex......................................................................................................................................................................... 158
5.2.4 Response Capex ........................................................................................................................................................................ 159
5.2.5 System Control Network Capex .................................................................................................................................................. 160
5.2.6 Integrated Vision for an Active Distribution Network (IVADN) .................................................................................................... 161
5.2.7 North Atlantic Green Zone (NAGZ) ............................................................................................................................................. 162
5.2.8 Non Load Related Expenditure – Summary of Allowances ........................................................................................................ 163
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5.3 Non Network Related Expenditure.............................................................................................................................................. 164
5.3.1 Accommodation Fixtures and Fittings and Office equipment...................................................................................................... 165
5.3.2 Vehicles ...................................................................................................................................................................................... 166
5.3.3 Tools ........................................................................................................................................................................................... 167
5.3.4 IT associated with Asset Management, Control/Operations, IT Infrastructure and Enterprise Applications ............................... 167
5.3.5 Environment ................................................................................................................................................................................ 169
5.3.6 System Control and Telecoms .................................................................................................................................................... 170
5.3.7 Non-Network Capex – Recommendations and Conclusions on Proposed Allowances ............................................................. 172
5.3.8 Smart Metering Expenditure ....................................................................................................................................................... 173
5.4 Summary & Conclusions............................................................................................................................................................. 173
5.4.1 Capex Overview.......................................................................................................................................................................... 173
5.4.2 Demand Connections ................................................................................................................................................................. 175
5.4.3 Generator Connections ............................................................................................................................................................... 176
5.4.4 Load Related Reinforcement ...................................................................................................................................................... 176
5.4.5 Retirements (Dismantling) Capex ............................................................................................................................................... 177
5.4.6 Diversions ................................................................................................................................................................................... 177
5.4.7 Non-Load Related Capex ........................................................................................................................................................... 177
5.4.8 Non-Network Capex.................................................................................................................................................................... 180
6. Conclusions ........................................................................................................................................... 182
Appendix A. Benchmarking .............................................................................................................................. 185
Appendix B. Incentives ..................................................................................................................................... 206
Appendix C. Smart Meter Procurement ........................................................................................................... 241
Appendix D. Asset Lives & Depreciation ........................................................................................................ 258
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Executive Summary
ESB Networks carry out the function of Distribution System Operator (DSO) in Ireland. This report sets out the
DSO’s capital expenditure (capex) and operating expenditure (opex) over the PR3 (2011 to 2015) and PR4
(2016 to 2020) periods. The review considers the costs, systems processes, and initiatives of the DSO over
PR3 and identifies key issues to be considered in PR4. The report then reviews the DSOs proposals for
expenditure in PR4 and makes recommendations on the level of expenditure, outputs and incentives to be
allowed by CER.
Data Submissions over the PR4 process
ESBN provided data for the PR4 review according to the following timetable:
Historic Questionnaire Submission: 31 October 2014
Forecast Questionnaire Submission: 21 November 2014
ESBN was provided with the questionnaires in July 2014.
The data requested is in essentially the identical format that was used in PR3 and preceding Price Reviews.
ESBN was advised early in 2014 that the data requested would be the same and in the same format as
previous Price Reviews.
During the review process there has been a number of changes made to the data provided by ESBN through to
May 2015. Although there are invariably corrections and modifications through a review process, in some areas
data which would have been expected to be available was not available causing some delays in the process
and the completion of the reports. ESBN are reviewing internal processes to ensure future reviews and data
requests are more efficiently managed.
PR3 Opex
The CER decision paper (CER/10/198) set out the DSO’s original allowed opex for the PR3 price control period.
This allowance equated to €896.9m in controllable opex, €190.0m in non-controllable opex and €1086.9m in
total1. The price control mechanism allows for a number of adjustments to be applied to the initial opex
allowances set out by the CER. The opex allowances of some of the opex sub-categories were adjusted during
the PR3 period. This resulted in an adjusted PR3 allowance of €1138.8m (excluding commercial costs and
depreciation), comprising of an allowance of €945.5m on controllable opex and €193.3m on non-controllable
opex.
Prior to any adjustments for high level efficiencies; the DSO is broadly operating at the adjusted PR3
allowances with an expected expenditure on controllable and non-controllable items of €1140.4m against an
adjusted allowance of €1138.8m. The most significant overspend is on Network Operations and Maintenance
(€24.1m), with the main underspend being on the Provision of Information (€21.5m). Owing to the pass through
nature of non-controllable opex, PR3 allowance is expected to equal actual expenditure. Taking into account
the CER’s efficiency driver (€-31.3 million) which the DSO acknowledge was not achieved, the DSO Total opex
is overspent by €32.9m (or 3% of total allowed expenditure). A comparison of the adjusted PR3 allowance and
the DSO’s expected outturn is shown below in Table ES.1.
Table ES.1 : Final Allowances v Expected Outturn (PR3)
DSO Operating Costs
(€m 2009 Prices)
PR3 Total
Allowed Forecast Variance %
Network O&M Total 469.3 493.4 24.1 5%
1 2009 prices and excluding Commercial costs and depreciation.
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DSO Operating Costs
(€m 2009 Prices)
PR3 Total
Allowed Forecast Variance %
Asset Management 60.2 64.7 4.5 8%
Metering 127.2 130.8 3.6 3%
Customer Service 81.2 74.0 -7.2 -9%
Provision of Information 74.1 52.6 -21.5 -29%
Corporate Costs 64.3 54.0 -10.3 -16%
Telecoms 0.0 0.0 0.0 -
Sustainability and R&D 18.2 8.0 -10.2 -56%
Other 51.0 69.7 18.7 37%
Controllable Total 945.5 947.1 1.6 0%
Network Rates 183.4 183.4 0.0 0%
Car Levy 9.9 9.9 0.0 0%
Non Controllable 193.3 193.3 0.0 0%
Total (Excl Commercial and
Depn)
1138.8 1140.4 1.6 0%
Less High Level Efficiencies -31.3 0.0 31.3 -
Total (Excl. Commercial and
Depreciation)
1107.5 1140.4 32.9 3%
The overspend on Network Operations and Maintenance is predominantly driven by planned maintenance
which is expected to incur a 20% overspend during PR3 (€39.1m) due to significant expenditure on Tree cutting
over and above the allowance. This is partially negated by an underspend of €20.5m on fault maintenance.
There was an underspend of €21.5m on Provision of Information expenditure a significant element of which is
charged from the Business Support Centre. A change of pricing mechanism for IT Services was agreed in 2011
moving to a cost recovery mechanism rather than market price cost. This contributed to lower costs for the
DSO. The most significant element to this reduction is the efficiencies associated with Market Opening
activities. A number of strategies were employed to provide cost reductions, such as headcount reductions,
offshoring work where practicable, development of longer term contracts to drive cost reductions,
implementation of new technologies such as cloud hosting.
Overall expenditure on other opex items is forecast to exceed the PR3 allowance by €18.7m (37%). There are
several factors which impact on the variance in ‘Other’ expenditure:
The DSO have indicated in a number of discussions that costs for Network Assets and Employers/ Public
Liability Insurance is passed from Corporate centre and relates to increases in the Network Asset base.
This does not sufficiently account for the increases and subsequent decreases in the charges during the
PR3 period.
The legal costs would be expected to rise given the increased revenue protection work that the DSO is
experiencing as customers find themselves under economic pressure.
The increase in Health and Safety costs is due to the recent severe safety incidents that have occurred
within the DSO activities. There has been a full review of the Health and Safety processes and procedures
necessitating a significant increase in the level of expenditure (which is over and above the PR3 allowance)
in order to put the requisite changes in place to ensure that the processes and procedures and staff
training / education are in place are fit for purpose from a Health and Safety perspective. This increase is
expected to continue into PR4.
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The DSO has not provided a view of their Asset condition at a company-wide level. This is a concern and
should be addressed during PR4. The high level view will allow the DSO to understand the long term effect of
maintenance levels on their asset condition and allow it to take a more informed long term approach to
maintenance and Capex replacement programmes.
The DSO has achieved the cost targets set out in the CER decision paper however we are of the opinion that it
has not achieved the additional cost efficiencies required by the CER. It is our view that the company has
underspent by €10.2m on Sustainability and R&D activities and this may be treated as a windfall gain.
PR4 Opex
The DSO has proposed a total opex allowance for PR4 of €1506.0m, excluding Commercial Costs and
Depreciation. The total proposed opex allowance is broken down as follows:
Proposed controllable opex of €1219.9 (an increase of €245.0m - 25% - from PR3 outturn)
Proposed non-controllable opex of €286.1m (an increase of €87.2m - 44% - from PR3 outturn)
The DSO has proposed a total opex allowance for PR4 of €1506.0m, which represents an increase of €332.3m
(28%) from PR3 forecast outturn.
The DSO has provided a significant amount of narrative on the proposed PR4 forecast operating costs. We
have reviewed the submissions provided and in some cases requested additional information, to clarify
justifications or provide additional supporting information. As a result of our reviews, we have recommended a
reduction of €106.9m to the level of operating expenditure proposed by the DSO. All of our recommended
€106.9m reduction to the DSO’s opex allowance is identified in controllable costs only.
A table summarising the DSO proposed opex for PR4 and our recommended allowances for the same period is
provided below in Table ES.2.
Table ES.2 : DSO Proposed Opex v Jacobs Recommended Allowances (PR4)
DSO Proposed Operating Costs Jacobs Proposed Operating Costs
Proposed Operating Costs
(€m 2014 Prices) PR3 PR4
Variance
PR3 – PR4
Variance
%
PR4
Changes
PR4
Allowed
Variance
to PR3
Network O&M Allowance 507.8 581.1 73.3 14% -43.4 537.7 6%
Asset Management
Allowance 66.6 72.3 5.7 9% 0.0 72.3 9%
Metering Allowance 134.6 180.1 45.5 34% -21.3 158.8 18%
Customer Service Allowance 76.2 90.2 14.1 18% -3.2 87.0 14%
Provision of Information
Allowance 54.2 63.3 9.1 17% -2.9 60.4 11%
Corporate Costs Allowance 55.6 51.4 -4.2 -7% -3.0 48.4 -13%
Telecoms Allowance 0.0 67.7 67.7 - -48.4 19.3 -
Sustainability & R&D
Allowance 8.2 15.6 7.4 91% -4.5 11.1 36%
Other Allowance 71.7 98.2 26.5 37% -12.2 86.0 20%
Controllable Allowance 974.8 1,219.9 245.0 25% -143.9 1076.0 10%
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DSO Proposed Operating Costs Jacobs Proposed Operating Costs
Proposed Operating Costs
(€m 2014 Prices) PR3 PR4
Variance
PR3 – PR4
Variance
%
PR4
Changes
PR4
Allowed
Variance
to PR3
Network Rates 188.7 275.1 86.4 46% 0.0 275.1 46%
CER Levy 10.2 11.0 0.8 8% 0.0 11.0 8%
Non Controllable
Allowance 198.9 286.1 87.2 44% 0.0 286.1 44%
Total Allowance (excl.
Commercial and
Depreciation)
1,173.7 1,506.0 332.3 28% -143.9 1362.1 16%
The DSO has proposed a total allowance of €581.1m over the PR4 period for Network Operations and
Maintenance opex. This is €73.3m in excess of the spend in PR3. This increase is predominantly driven by
increased Planned Maintenance expenditure on HV stations. We have proposed reductions of €41.5m in this
activity and a reduction of €1.9m in system control, reducing the total allowance to €537.7m.
The DSO are requesting an increase in metering costs of €45.5m (34%) over the costs forecast for PR3, raising
the PR4 allowance to €180.1m. The main driver for the increase in Metering expenditure (compared to PR3) is
due to Customer Meter Operation (an increase of €13.5m) and Keypad/Token meters (an increase of €26.4m).
The Customer Meter Operation includes Revenue Protection activities. There has been increased activity in
this area in PR3 (see Table 2.16) and we consider that this is likely to continue in PR4. We have accepted the
DSO’s proposed opex allowance for Customer Meter Operation on this basis.
The DSO has proposed an expenditure of €55.3m on keypad/token meters during PR3. Our PR4 proposed
allowance has been based on a unit cost of €400 per keypad/token meter installation and results in a total
expenditure of €34.0m, a reduction of €21.3m.
The DSO has proposed a total PR4 allowance of €47.0m (an increase of €6.2m or 15% on PR3) for Market
Opening activities. The company has identified the cost increases going forward for Retail Market Design
Services in PR4. This increase over PR3 expenditure has been identified to relate to the release of scheme
updates that were not required during PR3 , we have proposed reducing the PR4 allowed expenditure by a total
of €2.9m over the PR4 period.
It is unclear, what level of cost was incurred by the DSO for Telecoms activities in the PR3 period.
Supplementary questions have been issued to the DSO and details have been provided, however this has not
sufficiently clarified the information. On this basis it is not possible to determine how these costs have changed
from PR3 to PR4. The DSO has indicated that there will be external revenue generated from this business
activity, which will be passed on to the customer.It is our view that this income should be netted off the
operating costs and the allowance should be the net costs of operating the service. We have therefore reduced
the proposed expenditure allowance on Telecoms by the expected level of revenue from Telecoms activities
(€48.4m).
The DSO have proposed an allowance of €18.6m for environmental activities over the PR4 period. This
represents a €12.1m (183%) increase over expenditure in PR3. The DSO has not identified any new legislation
that is not currently in force and therefore there should be no additional compliance requirements in PR4. As
the company are presumed to be meeting the current environmental compliance levels, we have reduced the
PR4 allowance by €11.0m to match the levels of expenditure expected at the end of PR3.
The DSO have proposed a PR4 allowance on Health and Safety of €38.8m which equates to an increase of
€18.9m (95%) on PR3 expenditure. It should be noted that the circumstances currently facing the DSO are not
the same as those at the start of PR3 as a result of recent severe safety incidents that have occurred within the
Company Operations. The company has carried out a full review of its Health and Safety processes and
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procedures. The resultant corrective actions have resulted in the above expenditure profile. We are supportive
of these actions and the accelerated profile of expenditure. We do believe however that the approach to the
improvement in health and safety should be able to deliver the benefits more speedily and have shown a
reduction in the increase in the later years of PR4. We recommend a reduction of €5.0m giving an allowance of
€33.8m which is 70% higher than in PR3.
We have suggested that the DSO develops an appropriate method to understand the asset heath of its asset
portfolio, in order to understand the overall level of maintenance required and to inform future Asset
Maintenance and Replacement Programmes.
PR3 Capex
Capex Overview:
During the PR3 period, there are a number of significant factors that need to be considered when
assessing DSO outturn capex v CER allowed costs.
In consultation with the CER, ESBN Networks reduced the PR3 Gross Capex delivery programme in two
stages from the original CER allowed value of €4,200m to €2,400m (including Transmission Projects).
Given the reduction in peak demand during the PR3 period, together with pressure to reduce potential
increases on DuoS charges, the DSO considered it appropriate to critically review the network
requirements and the related project portfolio, allowing for deferment of reinforcement projects where the
resultant risks were considered acceptable to do so.
In headline terms, during PR3 the DSO is forecasting to invest net €1,075.3m on network and non-network
assets, which is €91.3m (9.3%) higher than its 2012 revised capex total of €984m (excluding Smart
Metering and R&D costs associated with studying impact of Electric Vehicles). Its latest forecast is €637m
(37%) lower than the initial CER allowed capital expenditure for PR3 of €1,712m.
Due to the unique circumstances that were faced by the DSO in the period leading up and resulting in its
revised capex plans in 2012, it is considered appropriate to use the rebased 2012 capex forecast for
comparison throughout this report wherever possible, although, for completeness, reference is also made
to CER allowed values.
The DSO has been asked for more detailed breakdown of costs associated with the 2012 revised capex
plan broken down into an annual expenditure profile for each of the work programmes for which CER had
made allowances for the PR3 period. However, it is our understanding that this information is not available
due to the progressive and incremental nature of Capex assessment and reprioritisation over the 2012-
2015 period.
Consequently we have not been able to carry out a comparable analysis of DSO forecast v rebased 2012
capex at a work programme level and such analysis has therefore been carried out relative to CER allowed
capex for each defined category of capex.
Table ES.3 summarises the PR3 capex allowances and the DSO forecast.
Table ES.3 : PR3 Capex Summary
Capex Investment Category
CER Allowed
Capex
(GROSS)
Revised
DSO
Proposal
(2012)
DSO
Forecast
(GROSS) -
2014
Variance – DSO
Forecast to CER
Allowed Capex
Variance – DSO
Forecast (2014) to DSO
Revised Proposal (2012)
€m % €m %
New Business 452.7 252.0 235.5 -217.2 -48.0% -16.5 -6.6%
Generation Connections 162.5 70.0 86.7 -75.8 -46.6% 17.7 25.7%
Line Diversions 51.8 52.0 47.1 -4.7 -9.0% -4.9 -9.4%
Distribution Reinforcement 632.6 277.0 316.9 -315.7 -49.9% 39.9 14.4%
Asset Replacement 622.1 433.0 462.4 -159.7 -25.7% 29.4 6.8%
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Capex Investment Category
CER Allowed
Capex
(GROSS)
Revised
DSO
Proposal
(2012)
DSO
Forecast
(GROSS) -
2014
Variance – DSO
Forecast to CER
Allowed Capex
Variance – DSO
Forecast (2014) to DSO
Revised Proposal (2012)
€m % €m %
Non Network 179.1 96.0 135.6 -43.5 -24.3% 39.6 41.2%
Total – DSO Excluding Smart
Metering 2,100.8 1,179.0 1284.3 -816.5 -38.9% 105.3 8.9%
Note – “Asset Replacement” Costs include costs associated with the retirement of assets (costs for period from 2011-2013 obtained from
Opex Table 5.1 and costs for period 2014/15 are from Capex Table 6.3, both in the DSO’s PR4 submissions to CER)
Demand Connections (new business):
For Demand Connections, the total DSO Actual Capex (Gross) over the PR3 period is forecast to outturn at
€235.5m, this is €217.2m (48%) less than the CER Allowed capex. It is also €16.5m (6.6%) less than the
DSO Revised Capex Proposal of 2012.
The total DSO Actual Capex (Net) over the PR3 period is forecast to outturn at €123.2m, this is €103.1m
(45.6%) less than the CER Allowed capex.
Customer contributions of €112.3m for a gross expenditure on demand connections of €235.5m (gross)
resulted in a contribution ratio of 48% in PR3 compared with the agreed rate of 50%. The DSO may need
to revise the Basis for Customer Connection Charges for future recovery of the agreed rate of 50% of total
connection charges, although we would expect any revision to be presented to the CER for review and
approval.
The main driver for this significantly lower capex, compared to the original CER allowances, is the reduced
number of customer connections that have been requested to be provided by the DSO over the PR3
period. Based on the DSO latest forecast for 2014 and 2015, it is anticipated by the DSO that the 5-year
total will outturn at 70,417. This is more than 86,000 (i.e. 55%) lower than the PR3 forecast connection
volumes for the full 5-year period.
CER should review the outturn costs for 2014 before finalising its allowances for PR3 period.
It is observed that the DSO total meter costs for PR3 period are 17.9% higher than the CER allowed costs.
This is despite a forecast reduction in connection volumes of 55% over the PR3 period. The DSO has
provided a detailed explanation to explain this apparent adverse variance. The closing of cost accounts
relating to dormant connection projects, to prevent misallocation of costs, has resulted in final connection
cost and the metering cost both being allocated to the metering cost code.
The analysis provided by the DSO supports the higher metering capex costs incurred during PR3. It is
important however that the assessment of PR4 allowed revenues for connections and metering takes due
account of the fact that a proportion of G1-G3 connections costs have been allocated to metering capex
during PR3.
Generator Connections:
The DSO is forecasting to incur gross generation connections costs of €86.7m during PR3, representing an
underspend of €75.8m compared with the CER allowed gross capex of €162.5m. This DSO forecast is
€17.7m (25.7%) higher than the DSO Revised Capex Proposal of 2012.
Customer contributions for generation connections are forecast to be €96.7m, equivalent to a contribution
ratio (or recovery rate) of 112% compared with the allowed recovery rate of 100%.
This over-recovery of connection costs in PR3 will undoubtedly result in DSO net cash outflows during the
early years of PR4 period and this will need further consideration when reviewing the proposed DSO
forecast capex for PR4.
Load Related Reinforcement:
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For load related reinforcement, the DSO forecasts a total capex of €316.9m by end of PR3 – this is
€315.7m lower than the original CER allowed load-related reinforcement capex of €632.6m – representing
a variance of 50%.
This DSO forecast is approximately €39.9m higher than the revised proposal of ESBN (€277m) submitted
to CER in 2012.
The main drivers on load-related reinforcement expenditure are the growth in peak demand and energy
delivered (GWh). It is noticeable that from a total of circa 24,000 units in 2008, the DSO has experienced a
reduction to 23,000 GWh units in 2010, followed by a further reduction in actual units to circa 22,100 GWh
by 2013.
Similarly, the system peak demand has not increased in line with the DSO forecast for PR3. The peak in
2007/08 was 4,914 MW and the peak in 2013/14 has reduced to 4,523 MW.
As part of its response to the Business Plan Questionnaire, the DSO was requested to provide a
breakdown of planned v actual cost details of the major projects (38kV and above) that have been
progressed during PR3. This would have allowed us to carry out a more detailed analysis of a sample
number of projects completed during PR3. The purpose of carrying out a detailed analysis of a
representative sample of individual projects is to assess the reasonableness of costs incurred compared to
planned/allowed costs, the reasonableness of the DSO project delivery process and hence to determine
the efficiency of the DSO project delivery and resulting capex.
We have experienced significant delay in receiving the requested information for a sample of 11 major
projects expected to be completed during PR3. Both the delays in providing the required information and
the fact that information was only provided for a small sample of projects rather than all major projects is
disappointing. We would have expected the project information requested to be generally available within
the DSO and find the prolonged delay in providing this information to be a concern. – it is standard
information that we would expect the project managers to be using on a routine basis to manage and
control project delivery and associated costs.
Given the time the DSO has had to provide such information, we consider that their inability to provide such
information to the CER in a timely manner to be an area of weakness that requires improvement during
PR4.
For 10 of the 11 projects, we have observed that the DSO is forecasting total costs (PR2 and PR3) that are
lower than the Capital Approval Amount – with variances in the range of €0.1m to €0.8m. For the remaining
major project (N-D-1027), we observe that the DSO is forecasting a total cost (PR2 and PR3) which is
higher than the Capital Approval amount by €1.0m.However as the lack of cost granularity has limited our
assessment on a constant 2009 price base, conclusions made from any comparison of projects costs need
to recognise this cost base inconsistency. We have not investigated the reasons behind any variance in
total costs v CA costs nor has the DSO provided any details or explanation of the variance.
It was also our intention to request a sample number of post investment appraisal documents for a
selection of completed major projects. The DSO has advised us that they do not presently carry out a
formal post investment review of individual projects and hence no documentation was available for us to
review.
We consider this gap to be an area for improvement within the DSO project delivery process – this has
been recognised by the DSO, who has stated their plans to introduce this improvement over the coming
months.
However, the DSO has provided a supporting narrative document (DH02 – PR3 Load Driven Programme)
that provides detailed commentary of investment during PR3 – this has allowed us to make a quantitative
assessment of non-financial project outputs.
Our analysis suggests that the reduction in DSO forecast capex for 110kV reinforcement projects is higher
than the equivalent volume reductions in transformer capacity or circuit km commissioned. It is expected
that this disparity will be partly due to a number of projects being completed in PR3 that commenced in
PR2 period; with the costs incurred on these projects during PR2 being added to the DSO RAB during
PR2.
DSO
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Further analysis of 38kV reinforcement projects suggests that the reduction in DSO forecast capex is
higher than the equivalent volume reductions in transformer capacity or circuit km commissioned. Similar to
110kV projects, it is expected that this disparity will be partly due to a number of projects being completed
in PR3 that commenced in PR2 period; the costs incurred on these projects during PR2 being added to the
DSO RAB during PR2.
Using the Planning policy (which permits 180% loading of single transformer nameplate rating under N-1
conditions for dual transformer stations), the DSO has forecast that a total of 48 of their population of 38kV
stations will be outside Planning Standards by the end of PR3 (rather than 32 loaded above nameplate
rating).
These stations will require further attention during PR4 and will be a consideration within the review of DSO
forecast capex.
The DSO has continued its programme to convert its 10kV network to 20kV operation, albeit at lower
volumes. The PR3 forecast volume for this activity was 15,000km. The DSO has reported that by the end
of PR3 a total of 10,000km will be converted to 20kV. The reduction in capex associated with the 20kV
conversion programme is consistent with the reduced circuit lengths converted during PR3 and it appears
to be efficiently incurred.
The DSO is forecasting that capex associated with other MV/LV System improvements during PR3 will
outturn at €33.6m. This is approximately 51% less than the CER allowed capex of €69.1m. The scale of
reduction in DSO capex during PR3 for MV/LV system improvements is consistent with the overall
reduction in PR3 load related reinforcement expenditure (being 50% of CER allowed capex).
Retirements (Dismantling) Capex:
The DSO has continued its practice of charging dismantling costs to its Income Statement for years 2011
to 2013 and proposes a change in Accounting Practice for the remaining two years of PR3 such that the
costs are allocated to capital. Our analysis of DSO dismantling costs has been carried out on a total cost
basis. Total dismantling cost over the PR3 period is forecast at €47.1m, 17.9% less than the CER allowed
capex of €57.4m.
The DSO has introduced revised project costing procedures (Integrated Work Management Module) within
their SAP application from 2009 onwards. This has allowed the DSO to allocate dismantling costs more
directly to the work activity that has driven the need for the dismantling to be carried out.
We would generally agree with the DSO that the proportion of dismantling costs is likely to vary across
each of the work activities. The change in the DSO cost allocation procedures has provided improved
visibility of the drivers on the dismantling activity and associated costs
We would expect the DSO dismantling costs over the PR3 period to be charged to capex for the full five
years, this being consistent with CER allowances. This will result in a transfer of €28.4m of costs from opex
(2009 prices) to capex covering the years 2011 to 2013.
Diversions:
Line diversion costs have historically been proportional to capital expenditure in the category of “gross new
demand connections”. For the PR3 period, this allowance was set at a value equivalent to 11.4% of the
PR3 forecast capex for new connections. The actual diversion costs over 2011 to 2013 are in the range of
19.2% to 21% of the gross connections capex over the same period. The DSO has provided an
explanation for this % increase in percentage costs experienced during PR3 and we consider this to be
reasonable.
In its response (DSO report DR01) to our Interim Report, the DSO provided aThe DSO revised forecast of
line diversions capex for the remaining two years of the PR3 period suggesting line diversionsuggests
costs in the range of 20% for the remainder of PR3- these values are broadly consistent with the first three
years of PR3 and are considered to be reasonable.
Non-Load Related Capex
For non-load related capex, the DSO has forecast a total capex of €415.3m by end of PR3 – this is
€149.4m lower than the CER allowed load-related reinforcement capex of €564.7m – representing a
DSO
Page 9
variance of -26%. This DSO forecast is €29.4m higher than the revised proposal of ESBN (€387m )
submitted to CER in 2012
It should be noted that this forecast includes for a one-off capex of €26.8m in 2014 associated with Storm
Darwin and it also includes a significant increase in capex for year 2015 (relative to 2012 and 2013).
Certain asset replacement projects were deferred in whole or were scaled down based on the DSO’s
prioritisation process.
For PR3, the allowed capex for HV Overhead Line Replacements was €16.3m and the DSO latest forecast
is €15.1m, representing 93% of allowed capex.
The DSO states that the 38kV OCR programme will be substantially completed, although this is dependent
on the delivery of 1,000km during Q4, 2014 and end of 2015. There is a significant risk that this volume of
work associated with the 38kV OCR programme is not delivered in 2015 – it represents a significant
increase in volumes previously delivered and is heavily dependent on contractor resources being in place
and fully operational. Whilst the DSO also acknowledges the 2015 volumes represent a significant increase
in the rate of delivery, it considers its 2015 forecast to be reasonable, citing contractor resource availability
to deliver the majority of the work programmes.
The reduction in capex by deferring 110kV line works has been largely offset by the additional capex
associated with 38kV copper overhead line replacements. Generally, the reduced costs in PR3 are broadly
consistent with the reduced PR3 volumes delivered
The DSO has deferred significant capex during PR3 associated with 110kV and 38kV cable replacement
projects. The reductions in work volumes stated by the DSO are broadly consistent with the reduced
capex.
The DSO has deferred a number of the higher cost HV station replacement projects / programmes
completely, whilst at the same time focussing on the substantial completion of various safety driven and
security driven programmes of work, typically of a much lower cost. These two factors contribute to an
overall underspend of PR3 capex of 36% relating to the HV Station renewal programme.
For the MV OCR programme, the DSO is forecasting the completion of 33,000 km by end of PR3 (i.e. 73%
of the original target (45,000km) upon which allowances were made, although it forecasts a spend of 86%
of the PR3 allowance. This increase in unit costs is being driven by higher labour costs being forecast in
2014 and 2015 - associated with more stringent pole testing procedures that the DSO has introduced to
addressed potential risks associated with accelerated pole rot.
The forecast includes a target of 14,500km being delivered in 2015 alone, predominantly by using contract
resources, this being subject to completion of the tendering and contract procedures. Achieving the 2015
target volumes is therefore considered to be a significant challenge to the DSO.
The DSO is forecasting that approximately 10km of MV cable to be replaced by 2015 – representing an
under-delivery of about 33%, broadly in line with the forecast underspend.
In relation to the MV Station Renewal Programme, the DSO is forecasting an overspend in this category of
27%. Any expected reductions in capex due to the reduction in volumes for many of the categories have
been largely offset by increased costs associated with the higher volume of work associated with the
Magnefix Cast Resin Switchgear programme.
The plan for PR3 period was to refurbish 35,000 spans of LV urban networks. The DSO is forecasting that
less than 50% (~17,000km) of the programme will be completed during PR3 period. The percentage
reduction in capex for the Urban LV Renewal programme is broadly consistent with the equivalent
reduction in work volumes.
For the Rural LV Network Renewal Programme, the reduction in the volume of works compared to PR3
programme (approximately 20%) is higher than the reduction in the Capex (6%) suggesting increase in unit
costs. Of the 20,000+ Groups refurbished during PR3, the DSO has selected more than 1,800 Groups that
were prioritised and selected for refurbishment in conjunction with other works to improve network
performance and power quality, with significantly higher unit costs than the basic fabric only refurbishment
works.
DSO
Page 10
For the LV Cable Renewal Programme - the DSO current forecast for this programme is €6.1m against the
CER PR3 allowed capex of €16.8m. During PR3, the LV cable programmes have been subject to a
significant reduction in order to reduce impact on DUoS charges.
For the Renewal Programme associated with cutouts, the PR3 programme consisted of the planned
replacement of 40,000 pre 1976 indoor cut-outs. This is a continuation of works from PR2 cut-out
replacement programme. The DSO is forecasting to replace up to 30,000 cut-outs by the end of 2015.
(75% of the original target)
For Response Capex, CER PR3 allowed capex of €98.7m, although the DSO revisedforecast for this
programme is €3.055.1m (representing an underspend of 44%). The area of largest underspend relates to
voltage complaints where the DSO is forecasting a -€16.4m variance to CER allowances. The reduced
investment in this category over PR3 period is likely due to a number of factors, such as reduced demand,
impact of MV and LV network renewal, 20kV conversion programmes and replacement of small capacity
transformers in rural areas. A total of 2,748 voltage complaints were resolved during PR3 period up to the
end of 2014. This is noticeably less than the 9,570 voltage complaints resolved during PR2.
In its response to our PR4 capex IR, the DSO explained the need for urgent works that are scheduled for
2015 to address risks associated with the theft of 50mm2 Copper conductor from 4 x 38kV overhead line
circuits. The works involved replacement of the copper conductor with aluminium conductor (of equivalent
rating) and the estimated capex for this new work programme is €2.0m in 2015.
The DSO is forecasting capex relating to the Continuity programme of €13.7m, which is approximately 39%
less than the CER allowed costs of €22.3m. This programme primarily consists of the installation of
automatic and remote control switches and other measures to improve the performance of the network,
The DSO determined that the continuity improvement projects intended for delivery in PR3 would be
largely deferred and priority given to core capex activities that addressed higher priority safety issues.
Non-Network Capex:
For non-network capex, the DSO has forecast a total non-network capex of €135.6m by end of PR3 – this
is €43.5m lower than the CER allowed Non-Network capex of €179.1m, representing a variance of 24.3%.
In general the DSO has deferred expenditures in all areas, and has reprioritised expenditure in areas
necessary to maintain customer service, operations and legislative requirements.
In most cases this can be viewed as efficiency and indeed represents a lower than allowed expenditure
while maintaining network performance. It is likely that there will some elements of catching up with the
DSO capex submission for PR4.
Total PR3 smart meter capex of €12.2m is significantly below the original €500m provisioned by CER
(which included a significant proportion of the proposed full roll-out costs) and also substantially less than
the €50m that the DSO had forecast in 2012 as part of the overall capex re-profiling exercise carried out in
consultation with CER. PR3 capex relates to the design and procurement activity carried out by the DSO in
preparation for approval of the Smart Metering programme. These activities would generally fall into the
classification of enabling works associated with the roll-out of the Smart Metering capex programme if the
programme is approved.
PR4 Capex
Capex Overview:
In headline terms, the DSO is forecasting a total gross expenditure of €1.72bn. This is €433m (25%) lower
than PR3 allowed capex of €2.15bn and €391m higher than PR3 actual/forecast capex of €1.33bn.
Net of customer contributions, the DSO is forecasting total PR4 capex of €1.48bn. This is €273m lower
than PR3 allowed capex and €351m higher than PR3 actual/forecast capex of €1.13bn.
The DSO PR4 forecast can be described in headline terms by the following characteristics:
- Demand Connections – DSO is forecasting a total number of connections in PR4 of 108,000 – this
represents an increase of 53% compared to the total of 70,417 during PR3, but is still only 33% of the
total number of connections made during PR2;
DSO
Page 11
- The DSO is forecasting 0% cumulative growth in peak demand during PR4 – reinforcement
expenditure during PR4 is focused on addressing parts of the system which do not presently comply
with the Planning Standards;
- Capex (gross) associated with generator connections is forecast to increase by 23% from €88.9m in
PR3 to €109.5m to connect a total of 1,250 MW of renewable generation over PR4 period (compared
to 1,200 MW expected by the end of PR3);
- Capex associated with non-load related projects and programmes is the category where the DSO is
forecasting the largest increase in capex in PR4 compared to PR3 – with a variance of €245.6m
(around 58%). The renewal programmes for which the DSO has forecast the largest increases in
capex in PR4 relate to HV Station works and HV and MV overhead line works. The DSO’s plans are
focused on the replacement of aging and defective assets.
- In addition, the DSO has included €87.6m of PR4 capex relating to the North Atlantic Green Zone
(NAGZ) smart grid initiative;
- The forecast increase in PR4 non-network capex (of 24%) is driven by increased expenditure on
vehicles, Distribution Asset Management (including IT infrastructure), Telecoms and System Control;
- In relation to the Smart Metering project, the DSO submission for PR4 includes further development
and project costs necessary to take the project to the next major milestone in 2017. It does not include
capex associated with a country-wide roll out programme as the final investment decision has not yet
been taken.
We have carried out an assessment of the DSO’s proposed capex plan and we have identified a number of
recommended adjustments to the allowed capex for PR4 – these are explained in more detail within the
following sections of the report.
Following our assessment, we recommend PR4 net capex allowance of €1336.72m – representing a
reduction of €144.38m. The PR4 capex proposed by DSO, together with our recommended allowances
are itemised below in Table ES.4.
Table ES.4 : DSO PR4 Capex Summary (€m – 2014 Prices)
SUMMARY OF ALLOWANCES PR3
Allowed
PR3
Actual
PR4
Requested
(Table 6.3)
Revised PR4
Requested
(Table 6.3)
PR4
Recommended
Variance
(Recommended
to Revised
Request)
(G1) New housing Schemes 74.6 16.7 46.5 44.2 45.1 0.9
(G2) Non-scheme Houses 164.4 89.0 106.1 107.7 102.6 -5.1
(G3) Commercial/Industrial Supplies 212.5 120.8 128.5 129.8 125.3 -4.5
Whole Current Metering 12.5 14.7 24.1 19.5 17.8 -1.8
New Business 464.0 241.2 305.2 301.2 290.8 -10.4
Transmission Connection Costs 26.3 0.0 15.2 15.2 15.2 0.0
110kV 236.1 144.4 150.4 150.4 150.4 0.0
38kV 215.2 86.5 85.9 85.9 85.9 0.0
MVLV System Improvements 70.8 34.5 40.9 40.9 36.3 -4.6
IFTs associated with 20kV
Conversion
16.6 22.9
0.0 11.1 11.1 0.0
20kV Conversion 83.0 36.5 25.4 14.3 13.9 -0.4
Reinforcements 648.1 324.7 317.8 317.8 312.8 -5.0
Generation Connections 166.5 88.9 109.5 109.5 109.5 0.0
Dismantling 58.8 48.3 70.2 64.4 55.1 -9.3
Non-Repayable Line Diversions 53.1 48.3 92.1 60.2 50.6 -9.6
DSO
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SUMMARY OF ALLOWANCES PR3
Allowed
PR3
Actual
PR4
Requested
(Table 6.3)
Revised PR4
Requested
(Table 6.3)
PR4
Recommended
Variance
(Recommended
to Revised
Request)
Total Load Related CAPEX 1390.4 751.3 894.8 853.1 818.7 -34.4
Renew Prog - 110kV & 38kV Lines 16.7 15.5 46.5 38.4 27.5 -10.9
Renew Prog - 110 & 38kV Cables 21.0 6.2 24.5 28.6 25.8 -2.2
Renew Prog - HV Substation 120.4 77.1 126.4 126.5 116.9 -9.6
Renew Prog - MV Overhead Lines 70.7 61.0 131.9 82.2 78.2 -4.1
Renew Prog - MV Cables 2.6 2.0 0.0 0.0 0.0 0.0
Renew Prog - MV Substations 24.7 31.2 23.3 33.2 31.1 -2.1
Renew Prog - Urban LV Renewal 64.3 36.2 46.5 46.4 38.2 -8.3
Renew Prog - Rural LV Network 95.8 84.1 74.8 84.5 78.5 -6.0
Storm Rectification Project 0.0 27.4 0.0 0.0 0.0 0.0
Renew Prog - LV cables and
associated items
17.2 6.2
16.2 16.4 15.7 -0.8
Meters and Time Switches 0.0 0.0 14.0 14.1 10.8 -3.3
Renew Prog - Cut-outs 5.8 4.0 14.3 14.3 5.6 -8.7
Continuity Improvement 22.8 14.0 13.5 13.5 13.5 0.0
Response capex 101.1 56.5 51.3 61.4 54.7 -6.6
System Control 15.4 3.9 16.5 16.5 9.7 -6.8
IVADN 0.0 0.0 7.1 7.1 4.5 -2.6
NAGZ 0.0 0.0 87.6 87.6 70.0 -17.6
Other (specify)2 0.0 0.0 0.0 0.0 0.0 0.0
NRP/ Bulk Supply 0.0 0.0 0.0 0.0 0.0 0.0
Total Non-Load Related CAPEX 578.5 425.4 694.4 671.0 580.65 -90.46
Capex - Non Network 183.5 138.9 172.2 172.2 154.3154.25 -18.017.95
Other (Smart Metering) 0.0 12.9 22.9 22.9 12.9 -10.0
Contributions -398.3 -198.5 -200.1 -238.2 -229.6 8.6
TOTAL NET CAPEX 1754.1 1130.1 1544.3 1481.0 1336.91340 -144.2
Demand Connections:
The DSO PR4 forecast capex (gross) is €301.2m, this is €60.0m (25%) higher than the expected PR3
outturn total capex of €241.2m. Net of customer contributions, the DSO PR4 forecast capex is €150.6m,
some €14.0m higher than expected PR3 outturn.
The increase in gross capex as forecast by the DSO for PR4 period is based on an increased number of
connections for each of G1/G2/G3 categories. Steady growth during PR4 is forecast by the DSO and a
total of 108,000 connections are expected to be made over this period, representing a 53% increase to
PR3 volumes.
We consider that the DSO PR4 forecast of new connections of 108,000 is a reasonable assumption for
tariff purposes, recognising that CER will make adjustments for higher or lower connections based on
allowed unit costs.
2 Included within the Continuity Work Programme
DSO
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The DSO has proposed standard unit costs for each of the G1/G2/G3 connections. We have concluded
that the proposed DSO unit costs for 2016 and 2017 are reasonable. However we recommend that the
additional costs that the DSO has factored in to its unit cost calculation from 2018 onwards should be
removed, this being consistent with the DSO a priori assumption that its forecast does not include for the
introduction of smart metering.
A reduction in allowed PR4 gross capex of €8.7m is recommended for PR4 demand connections, based on
the difference in unit costs proposed above for G1/G2/G3 connections.
For PR4, the DSO is forecasting total metering capex of €19.5m – this is €4.8m (32.6%) higher than PR3
expected outturn costs and €7.0m (56.3%) higher than PR3 allowed costs.
We recommend allowances for PR4 period based on 6.5% of our recommended PR4 gross capex for
G1/G2/G3 connections of €273m. This results in a recommended allowance for metering of €17.8m
representing a reduction of €1.8m compared to the DSO revised PR4 proposed capex of €19.5m.
Generator Connections:
For generator connections, the DSO is forecasting gross capex in PR4 of €109.5m. This represents an
increase of 24.4% compared to expected PR3 outturn.
Capex during PR4 will be focused on Gate 3 projects that have contracted since mid-2013. The DSO is
estimating that a total of 1,250 MW is to be connected to the distribution system during PR4.
As expected in our review of DSO historic capex, the over-recovery of connection costs in later years of
PR3 results in net cash outflows throughout the PR4 period, with a total net capex over the PR4 period of
€47.4m.
We recommend acceptance of the DSO proposed gross capex of €109.5m.
Load Related Reinforcement:
The DSO load-related reinforcement capex for the PR4 period is €317.8m. Although this is significantly
below the PR3 allowed capex of €648.1m, it is only €6.9m (2.1%) lower than DSO expected outturn
(€324m) for the PR3 period.
The DSO’s proposed PR4 reinforcement capex forecast has been prepared on a zero cumulative load
growth forecast for peak demand from 2013 - 2020. The DSO has made significant investment to reinforce
the network during previous price controls. However, there are still many parts of the network that do not
comply with the Planning Standard.
Unit sales (GWh) during PR4 are forecast to grow at approximately 2.2% per year. The DSO has assumed
that that the unit sales growth does not result in peak demand growth.
Zero load growth and peak demand reduction due to smart metering impact act to suppress the capex
forecast requirements for PR4 relative to previous price controls. There is a risk that the smart metering roll
out is either deferred beyond PR4 or does not have any impact on DSO peak demand. The DSO will need
to res-assess its reinforcement investment plans for later years of PR4 to account for the impact of such a
scenario.
We are satisfied that the DSO has established good practice relating to its preparation of investment plans
for its 110kV and 38kV network development and undertaking project investment appraisals before seeking
technical and financial approval and subsequent commitment of capex to a project.
Notwithstanding some errors and/or inconsistencies with the consolidated list of HV reinforcement projects
compared to individual projects and which are not considered to be material, we conclude that the DSO
proposed PR4 reinforcement capex for 110kV and 38kV is reasonable.
The DSO has proposed a total of €40.9m of reinforcement capex relating to the MV and LV network. The
proposed PR4 capex (€40.9m) represents a 18.8% increase compared to expected costs for PR3
(€34.5m), although considerably less than PR3 allowed costs of €70.8m.
We generally agree with this work being necessary although we would recommend allowances for PR4
such that PR3 actual and PR4 forecast capex is consistent with the PR3 allowed capex of €70.8m – this
was allowed to address known network deficiencies and is considered adequate for the DSO’s zero growth
DSO
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scenario. In addition we would expect the ongoing 20kV conversion programme to improve the network
and reduce reinforcement requirements.
This will reduce PR4 allowances for MV/LV System reinforcements by €4.6m to €36.3m (a reduction of
11%).
With regard to the 20kV conversion programme, the DSO expected PR3 volumes (10,500km) and capex
(€36.5m) result in a unit cost per km converted of approximately €3,475/km. The DSO proposed PR4
programme is based on converting 4,000km at the same unit cost, giving a total cost of €13.9m. Further
IFT works at cost comparable with PR3 are also proposed. We consider these to be reasonable costs and
consequently we recommend PR4 allowance of €25.0m.
Retirements (Dismantling) Capex:
We recommend PR4 allowances for dismantling which are derived as a proportion of our recommended
PR4 gross network capex – with allowances set at 4.1% of this gross value - this results in a recommended
PR4 capex for dismantling of €55.1m, representing a reduction of €9.3m compared to the DSO forecast of
€64.4m.
Diversions:
It is observed that there is a strong historic relationship between new business gross costs and diversion
gross costs. However, the DSO forecast is not consistent with this historic relationship. We therefore
recommend PR4 allowances for diversion works that are consistent with the historic relationship between
new business and diversion gross costs. We have applied this to our recommended allowances for New
Business gross capex.
This results in a PR4 forecast capex for diversions of €50.6m, representing 17.4% of PR4 gross new
business capex. This is €9.6m (16%) lower than the DSO revised forecast of €60.2m and €42.5m (45%)
lower than the DSO original forecast of €92.1m.
Non-Load Related Capex:
The DSO’s revised non load-related (NLR) capex for the PR4 period is €669.1m. This is significantly above
the expected PR3 outturn capex of €425.4m, although only €92.5m higher than the CER allowed capex for
non-load related capex during PR3.
The main drivers for the proposed PR4 works are to address safety risks, ensure compliance with health &
safety and environmental obligations and to maintain continuity of supply. Replacement works are driven
by the condition and performance of particular asset categories. The DSO NLR PR4 programme consists
of the following projects/programmes:
- Completion of major 110kV and 38kV HV Station replacement projects originally planned for
completion in PR3 but subsequently deferred due to prevailing financial situation at the time;
- Continuation of existing HV & MV asset renewal and security programmes to mitigate safety risk to the
public and the DSO workforce;
- Continuation of cyclical refurbishment of the 38kV & MV overhead lines, together with a project to
rebuild a number of 110kV double circuit tower lines in the Dublin area;
- Commencement of a small number of targeted asset renewal/ refurbishment programmes
- NAGZ is a major smart grid investment initiative aimed at addressing the impact caused by increasing
levels of renewable generation. The project will look to combine intelligent smart grid networks, high
speed communications and IT, linked with increased cross-border connectivity
- The proposed plans also include for a small number of relatively low cost pilot projects to allow for
assessment of emerging/ different technologies before any decision is made regarding roll out of such
technologies on a wider scale. The costs of these are presently incorporated within the DSO’s main
asset renewal programme categories but these could be ring-fenced within the DSO PR4 R&D
forecast expenditure category
DSO
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In general, we consider the justification for the various PR4 works proposed by the DSO is proven and in
many cases, we agree with the proposed volumes of work. However, our review has identified a number of
significant increases in the DSO PR4 planned costs, compared to PR3 planned costs (for deferred works)
or PR3 expected outturn costs (for works progressed during PR3).
We have therefore made proposed adjustments to the proposed DSO PR4 non-load related capex to
account for such differences where the DSO has been unable to provide further justification supporting
such increases in planned costs for its major projects and its planned unit costs for its asset renewal work
programmes.
In relation to the 38kV Overhead Cyclical Refurbishment Programme, the DSO revised forecast for PR4 is
based on a unit cost which is consistent with outturn cost in PR3. We recommend allowances for PR4 that
are consistent with the PR3 outturn unit costs.
In relation to the re-conductoring of 110kV double circuit tower lines in the Dublin area, it is our
understanding that there has not yet been any detailed line survey and analysis to inform the assessment
of the potential costs and that the DSO has not yet fully developed its proposed investment case. The DSO
PR4 forecast is therefore based on a middle-ground cost scenario. However, taking a low cost based on a
line refurbishment using existing towers, and a high cost based on fully undergrounding and stating that a
half way position is part underground, part tower replacement and part fittings replacement does not
constitute a planned investment.. We would however agree that the requirement to carry out the lowest
cost practical solution at this time seems reasonable and therefore would recommend this cost of €6.8m.
We do recognise the risk associated with this cost uncertainty and therefore once the DSO has developed
its planned investment for these circuits, this should be reviewed to assess the efficiency of their proposed
investment during PR4
The proposed changes result in PR4 recommended capex of €27.5m for 110kV and 38kV lines (with capex
reduced by €10.9m).
Our recommended PR4 capex allowances for 110kV and 38kV cable asset renewal works is €25.8m
broadly in line with DSO original capex submission of €24.5m within Table 6.3 of Forecast Business Plan
Questionnaire, but some €2.2m less than the DSO’s revised capex submission of €28.0m.
For a number of the sub-programmes associated with HV Station Asset Renewals, we have applied a
reduction to the proposed unit costs that the DSO has used in its PR4 forecast. These result in a
recommended PR4 capex of €116.9m, a reduction of €9.0m compared to the DSO forecast of €125.9m.
The DSO is proposing to inspect and refurbish where required, 34,500km of MV OHL as part of a 12 year
cyclical refurbishment programme at a unit cost of more than €2,200 per km. During PR3 period 2011 to
2014, the DSO has completed the refurbishment of approximately 18,400km at an expected unit cost of
€2,100. For PR4, the DSO is forecasting the unit cost will increase to €2,217 per km, representing an
increase of more than 5%.We recommend allowances for PR4 based on unit costs achieved during PR3
(2011 to 2014).
This reduction results in a recommended PR4 capex of €78.1m, a reduction of €4.1m compared to the
DSO revised forecast of €82.2m.
The DSO proposes a zero capex associated with the renewal of MV cables as no planned capital activities
are proposed for MV cable assets. PR3 allowed capex was €2.6m, with PR3 expected outturn of €1.8m.
For a number of the sub-programmes associated with MV Station Asset Renewals, we have applied
reduction to the proposed unit costs that the DSO has used in its PR4 forecast. These result in a
recommended PR4 capex of €38.2m, a reduction of €8.2m compared to the DSO revised forecast of
€33.2m.
The DSO is proposing to refurbish 17,500 spans (typically 25 spans/km) of Urban LV overhead network
(dating pre-1950) at a unit cost of more than €60,000 per km. During PR3, the DSO is forecasting to
complete the refurbishment of approximately 15,700 spans of network at an expected unit cost of more
than €51,500 per km. In support of its higher cost (>€60,000), the DSO has explained that the works are
planned to be delivered mainly by contractor resources and the contractor costs are driving up the unit
costs. The DSO has stated that the proposed networks that will be refurbished in PR4 are the same
vintage as networks refurbished in PR3 and the PR4 programme will mainly consist of networks not
completed in PR3. We remain of the view that there is insufficient justification to support a 20% increase in
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unit costs for this work and we recommend PR4 allowances based on the expected outturn unit costs for
PR3. This reduction results in a recommended PR4 capex of €38.2m, a reduction of €8.2m compared to
the DSO’s revised forecast of €46.4m.
The DSO is proposing to refurbish 11,350 bare LV rural groups and commence an additional programme to
inspect and complete remedial works on LV rural networks that have not been addressed since the mid-
late-1990s (a further 5,900 groups). We recommend allowances for these works based on the DSO
expected outturn unit costs during PR3. This reduction will result in a recommended PR4 capex of €78.5m,
a reduction of €6.0m compared to the DSO forecast of €84.5m.
In relation to the renewal programme associated with LV cables and associated items, the DSO proposed
works for PR4 are mainly a continuation of PR3 programmes. We recommend allowances for these works
based on the DSO expected outturn unit costs during PR3. This reduction will result in a recommended
PR4 capex of €15.7m, a reduction of €0.5m compared to the DSO’s revised forecast of €16.2m.
We have proposed adjustments to the DSO PR4 forecast capex of €14.1m associated with meter
replacement. We have adjusted for the CT metering to be replaced during PR4 (80%) and PR5 (20%)
rather than funding the replacement of the full population during PR4. We have also recommended a
reduction in capex associated with the funding for pilot communication project only (GPRS) for quarter
hourly data collection. We have proposed an allowance of €1m rather than the €2m proposed by the DSO
relating to a broad scale upgrade of the communications system. We have not been provided with detailed
cost information to support the €2m project and we would also expect the DSO to prepare a business case
to support the wider scale investment. These adjustments reduce the PR4 forecast capex from €14.1m to
€10.8m, a reduction of €3.3m.
The DSO is expecting to complete replacement of 30,000 cut-outs during PR3 at a total cost of €4.1m,
representing a unit cost of €140 in PR3. The PR4 programme proposed by the DSO is to increase the
replacement volumes to 40,000 although its proposed unit cost of €357 is considerably higher than
expected PR3 outturn. We recommend PR4 allowances based on the proposed DSO volumes and the
PR3 expected outturn unit costs in the absence of evidence from the DSO to support the higher proposed
unit cost. This results in a recommended PR4 capex of €5.6m, a reduction of €8.7m compared to the DSO
forecast of €14.3m.
For each of the proposed continuity improvement programmes, the DSO has carried out cost-benefit
analysis, which has been used to prioritise its investment plans. We recommend that the proposed DSO
PR4 capex of €13.5m relating to its Continuity Improvement programme is allowed. This allowance
includes €1.4m associated with a continuity programme to improve supplies to the DSO’s worst served
customers. In its response to the proposed Incentives for PR4 (Document DR07) the DSO has presented
two separate scenarios to address worst served customers, based on available information from UK DNOs
(the UK RIIO ED1 decision documents). Once CER has finalised the DSO PR4 incentive framework
(including allowances, targets, penalties etc – there may be a requirement to make an adjustment to theses
recommended allowances for DSO continuity capex.
We agree with the DSO proposed Response Capex for PR4 for all categories, other than for costs relating
to failed transformers. In addition, whilst we accept that there will be a need for the DSO to take action to
address the theft of copper conductor from its overhead line network, we note that this is a new category of
reactive work for which the DSO has based PR4 forecast on a nominal €2m per year, this being the
forecast costs for 2015 to address 4 specific circuits that have been subject to repeated thefts. The DSO
PR4 forecast is based on an assumption that similar quantities and works will be required on an annual
basis for the PR4 period. However, in the absence of any detailed risk analysis, we cannot conclude if
these figures are reasonable. We therefore recommend a PR4 allowance of €5m in total. This reduces
PR4 continuity capex by €6.6m to €54.6m.
We recommend PR4 funding relating to SCADA and Control Centre Infrastructure – at a total capex of
€9.7m. This represents a reduction of €3.0m compared to the aggregate total expenditure of €12.7m for
PR4.
In relation to the IVADN project, the DSO has forecast €7.1m in PR4. However it is unclear what capex is
proposed by the DSO during PR4 and what the project deliverables and benefits will be. There appears to
be significant uncertainty regarding how this R&D project will proceed and what it will cost (both capex and
opex).
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We therefore recommend that the DSO is allowed the capex costs associated with the reactive power work
stream (of €3.5m) as these are well advanced.
In the absence of detailed plans for the other work streams, we recommend additional total allowance of
€1m. We also suggest that the DSO continues to engage with the CER during PR4 once details of the
particular projects, including timing, cost, expected benefits etc. are known in more detail. Our recommend
allowance is therefore €4.5m, which is €2.6m lower than the DSO proposed PR4 forecast of €7.1m.
The NAGZ has a total project cost of €106m – with the costs split between the DSO (€70m) and NIE
(€36m). The DSO PR4 capex forecast includes for €87.6m associated with the NAGZ project, which has
also recently received grant funding of €31.75m from the EC. These facts suggest that the proposed DSO
PR4 capex forecast relating to the NAGZ is higher than necessary.
We also note that the NAGZ main capex cost components include works for which allowances have been
separately assessed (e.g. PR4 20kV conversion programme and upgraded protection schemes within the
DSO PR4 Continuity Improvement) and for which capex allowances will be made for PR4. There is a
potential risk of duplicating capex allowances as it is not clear that the overall network assessment has
explicitly excluded network assets within the NAGZ. The DSO has advised that all of the 20kV conversion
work undertaken during PR4 will be outside the NAGZ.
We recommend that the CER provides gross capex allowances for the NAGZ during PR4 of €70m – the
DSO proportion of the NAGZ total cost, with a further reduction if the NAGZ project receives funding under
the Connecting Europe Fund.
Non-Network Capex:
The DSO has forecast a total Non-network capex of €172.2m by end of PR4 – this is €33.4m higher than
the actual expenditure of €138.9m in PR3.
There are a number of areas where there is justification for maintaining and increasing expenditure,
however there are other areas where there are proposed significant increases where there has not been
sufficient justification and a demonstrated business case showing need, options and risk associated with
the proposed increases.
Total PR4 forecast expenditure on Refurbishment and Fixtures and Fittings reflects an increase over PR3
of €4.2m, but is €2.8m less than the PR3 allowance. Given the capex constraints in PR3, it seems
reasonable that there would be an increase over the PR3 outturn to ensure the buildings are maintained
and secure. We therefore recommend allowances of €15.5m in line with the forecast.
Total PR4 forecast expenditure on Vehicles at €30m was based on a forecast outturn in PR3 of €17.2m.
Since December 2014 the forecast outturn for PR3 has increased to €35.1m. We have therefore adjusted
the PR4 allowance based on the increased expenditure in 2014 and 2015. Wewe do not believe the
forecast fully exploits improved utilisation and vehicle reduction based on savings driven by the Mobile
Workforce Management system, recommended allowance is therefore €22.75m75m.
The forecast PR4 capex for tools is €10m; this has been reduced from the PR3 total of €14.8m and
represents good progress in developing efficiencies. The proposal is to allow the €10m.
Total PR4 forecast expenditure on Mobile Workforce Management reflects an increase over PR3 of
€14.2m. Given the potential benefits of this, it would be expected that a detailed business case driven by
the efficiency and cost benefit would be apparent. Some information has been provided which suggests
significant opex and capex savings within the business. However this saving is not reflected in the
submission in those areas. It is therefore proposed that the programme in PR4 should be €15m, a
reduction of €5m from the DSO forecast. We would comment that we fully support the full implementation
of this initiative which should not be constrained by the allowance. The allowance reflects that savings
elsewhere not provided at this time will make the initiative self-financing.
Total PR4 forecast expenditure on the Document Management System reflects an increase from €0.94m in
PR3 (all forecast in 2014 and 2015) to €8.1m in PR4. Given the potential benefits of this, it would be
expected that a detailed business case driven by the efficiency and cost benefit would be apparent. As this
is not the case, then it is proposed to reduce the value proposed by €1.2m to €6.9m.
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Total PR4 forecast expenditure on Environment is €4m compared to €1.9m in PR3. There has been some
information provide identifying where the additional expenditure is needed therefore it is recommended that
this is allowed at €4m.
Total PR4 forecast expenditure on Control and Telecoms is €53.9m compared to €32.6m in PR3. The
business case for the expenditure has not been clearly demonstrated and it is believed that there should be
opportunities for driving efficiencies from this budget. It is therefore recommended that the proposed
allowance should be reduced by €5.4m giving the PR4 allowance as €48.5m. It is also recommended that
the expenditure allowance is dependent on delivery of the Core & Aggregation IP Network and National
Radio Access Communication Network.
The DSO PR4 forecast for capex associated with smart metering is €22.9m with these costs expected to
be incurred in 2016 (€12.5m) and in 2017 up to end June 2017 (€10.3m). Capex during PR3 is €12.9m.
The DSO has only provided details of the €22.9m split by year, with no indication of planned capex relating
to each of the work streams and the capex deliverables necessary to facilitate the roll-out of the smart
metering program. Without a clear understanding of how the proposed capex is to be invested, what
physical assets are being delivered, we are not able to recommend full allowances.
In the absence of supporting justification, we recommend PR4 allowances set at PR3 outturn levels -
€12.9m representing a reduction of €10.0m compared to the DSO PR4 submission.
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Important note about your report
The sole purpose of this report and the associated services performed by Jacobs is to support the Client
(Commission for Energy Regulation - CER) in setting the allowed revenues for the Distribution System Operator
(DSO), the Transmission System Operator (TSO) and the Transmission Asset Owner (TAO) (the ‘Companies’)
as part of the 4th Price Control Review Process in accordance with the scope of services set out in the contract
between Jacobs and the Client. That scope of services, as described in this report, was developed with the
Client.
In preparing this report, Jacobs has relied upon, and presumed accurate, any information (or confirmation of the
absence thereof) provided by the Client, the Companies and/or from other sources. Except as otherwise stated
in the report, Jacobs has not attempted to verify the accuracy or completeness of any such information. If the
information is subsequently determined to be false, inaccurate or incomplete then it is possible that our
observations and conclusions as expressed in this report may change.
Jacobs derived the data in this report from information sourced from the Client (if any), the Companies and/or
available in the public domain at the time or times outlined in this report. The passage of time, manifestation of
latent conditions or impacts of future events may require further examination of the project and subsequent data
analysis, and re-evaluation of the data, findings, observations and conclusions expressed in this report.
Jacobs has prepared this report in accordance with the usual care and thoroughness of the consulting
profession, for the sole purpose described above and by reference to applicable standards, guidelines,
procedures and practices at the date of issue of this report. For the reasons outlined above, however, no other
warranty or guarantee, whether expressed or implied, is made as to the data, observations and findings
expressed in this report, to the extent permitted by law.
This report should be read in full and no excerpts are to be taken as representative of the findings. No
responsibility is accepted by Jacobs for use of any part of this report in any other context.
The findings of this Interim Report are based on the data made available to Jacobs by the Client and the
Companies prior to the agreed submission deadline.
This report has been prepared on behalf of, and for the exclusive use of, Jacobs’s Client, and is subject to, and
issued in accordance with, the provisions of the contract between Jacobs and the Client. Jacobs accepts no
liability or responsibility whatsoever for, or in respect of, any use of, or reliance upon, this report by any third
party.
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1. Introduction
The Commission for Energy Regulation (CER) is Ireland’s independent energy regulator, responsible for
overseeing the liberalisation of Irelands Energy Sector. The CER was established and granted powers over the
electricity market in 1999 (under the Electricity Regulation Act, 1999). Regulatory responsibilities in the Gas,
Petroleum Exploration and Extraction and Water sectors followed in 2002, 2010 and 2013 respectively.
Consequently, CER has a wide range of economic, customer protection and safety responsibilities in the energy
sector of Ireland. CER’s mission is to act in the interests of consumers to ensure that:
the lights stay on,
the gas continues to flow,
the prices charged are fair and reasonable,
the environment is protected, and,
energy is supplied safely.
CER regulates to the highest international standards
The CER’s primary economic responsibilities in the electricity sector are to regulate electricity generation, the
electricity networks and electricity supply activities. The overall aim of the CER is to protect the interests of
electrical customers, maintain security of supply, and to promote competition in the generation and supply of
electricity.
Under section 36 of the Electricity Regulation Act, 1999, and Statutory Instrument 445 of 2000 (as amended),
CER approves charges for the use of the electricity distribution and transmission systems. CER is also required
to examine the costs and revenues underlying such charges. As such, CER approves revenues for:
ESB Networks as Distribution System Operator (DSO)
ESB Networks as Transmission Asset Owner (TAO); and
EirGrid as Transmission System Operator (TSO).
These revenues are determined every five years for the following five year period. CER has previously
determined transmission and distribution revenue controls for the periods 2001 to 2005, 2006 to 2010 and 2011
to 2015 inclusive. CER issued an Invitation to Tender (ITT) requesting consultancy support to provide technical
and financial advice in regard to the fourth set of transmission and distribution revenue controls to cover the
next 5 year period from 2016 to 2020 (PC4).
Jacobs were appointed as technical consultants to support CER in setting the allowed revenues for the DSO,
TSO and TAO businesses in PC4.
1.1 This Report
This report sets out Jacobs’ opinion on the DSOs capital expenditure (capex) and operating expenditure (opex)
over the PR3 period (2011 to 2015) and PR4 (2016 to 2020). The report considers the costs, systems
processes, and initiatives of the DSO over PR3 and identifies key issues to be considered in PR4. The report
then reviews the DSO’s proposals for expenditure in PR4 and makes recommendations on the level of
expenditure, outputs and incentives to be allowed by CER.
This report also presents Jacobs’ benchmarking and incentives analysis relative to the DSO in addition to smart
metering and asset lives and depreciation.
This report is divided into 6 sections and 4 appendices. The report sections are structured as follows:
Section 1 contains this introduction
Section 2 contains our review of the DSO’s actual and expected PR3 operating expenditure (opex) and
compares this to the DSO allowances as outlined by the CER for the same period.
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In Section 3 presents the DSO’s proposed opex allowances for PR4. These proposed allowances are
reviewed and subsequently we present the Jacobs’ proposed allowed opex for the PR4 period.
Section 4 contains our review of the DSO’s actual and expected PR3 capital expenditure (capex) and
compares this to the DSO allowances as outlined by the CER for the same period.
In Section 5 presents the DSO’s proposed capex allowances for PR4. These proposed allowances are
reviewed and subsequently we present the Jacobs’ proposed allowed capex for the PR4 period.
Section 6 provides a summary of the allowed opex and capex as discussed and presented in Sections 3
and 5.
The report appendices are structured as follows:
Appendix A provides a benchmarking assessment of the DSO and TAO.
Appendix B contains a review of the effectiveness of the incentives placed on the DSO in PR3 and the
DSO performance against these incentives. This section also discusses the ongoing suitability of the DSO
PR3 incentives for application during PR4.
Appendix C discusses the impact of smart meters and smart grids on the DSO.
Appendix D reviews the assumed asset lives and depreciation assumptions with a view for application in
PR4.
1.2 Data Sources and Assumptions
The review has been informed by the companies’ response to the questionnaire on historic operating and
capital costs and associated information papers and network plans, together with further data provided by the
companies at meetings and from supplementary questions raised by CER and consultants.
The review takes into account provisional outturn costs and performance for 2014 and 2015.
CER has also provided a significant amount of background information on previous price reviews and updated
information.
Unless stated otherwise, our review of PR3 expenditure, detailed within Section 2 and Section 4 of this report,
has prices expressed as real prices at 2009 price levels. This allows comparison with the original CER PR3
allowances. Our review of planned PR4 expenditure (Section 3 and Section 5) has prices stated in real prices at
2014 price levels. The conversion to these price levels was based on the inflation factors presented in Table 1.1
below.
Table 1.1 : HICP Adjustment Factors
2009 2010 2011 2012 2013 2014
HICP Adjustment
Factor 1.000 0.984 0.996 1.015 1.020 1.024
CER allowed costs are as set out in the CER PR3 decision paper with annual adjustments made during the
price control period by CER for pass through items along with volume related items included as part of the PR3
settlement.
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2. Review of PR3 Operating Expenditure
In this section of the report we review the PR3 (‘historic’) opex of the DSO (covering the years 2011 to 2015)
against the PR3 DSO allowances, as determined by CER for an efficient company operating in Ireland.
The objective of CER in setting allowed operating costs is to ensure that expenditures funded by electricity
consumers through the DUoS tariff are as efficient as possible and that efficiency improvements within the DSO
continue to be made, to the benefit of customers. This should result in setting the companies challenging but
realistic and achievable targets and incentives, all the while moving closer to international best practice. The
objective of this review is to assess the DSO’s performance in achieving the outputs required by CER during
PR3 within the CER allowed costs. The review identifies any changes in circumstances put forward by the DSO
and CER to explain variances in outputs and costs.
Our review of PR3 opex assesses:
Historic trends in opex
Comparison of actual opex against allowed opex
The data presented, analysed and commented on in this report has been provided by the DSO to the CER and
Jacobs via:
Regular workshops hosted by the CER between April 2014 and October 2014,
The return of Questionnaires issued by the CER in July 2014,
Ongoing communications with Jacobs and the CER following the submission of the historical PR3 data at
the end of October 2014.
It should be noted that 2011 to 2013 performance and cost data is based on actual recorded values. 2014
performance and cost data is based on unaudited actuals whilst 2015 performance and cost data is based on
the latest forecast data available.
2.1 Overview
The CER decision paper (CER/10/198) set out the DSO’s original annual allowed opex for the PR3 price control
period. The opex costs outlined in the decision paper were split into controllable and non-controllable costs.
Controllable costs are categorised as:
Network O&M – The day to day System Control covering the Distribution Control Centres in Cork And
Dublin, along with planned and fault maintenance of the Network Assets.
Asset Management – The development of Policies and Asset strategies, along with payments for
wayleaves, forestry and mast interference payments.
Metering – The DSO provides a range of services related to metering to all stakeholders including,
electricity supply companies and customers. These services include the management of these assets,
collection and aggregation of metering data and revenue protection services.
Customer Service – Included within this category are the costs of the Customer Care Centre, Scheduling
Support Centre, customer relations and area operations.
Provision of Information – These costs are associated with DUoS billing and accounts receivable, Meter
Registration System Operator, Market System support costs.
Corporate costs – Costs from corporate centre, for services such as CEO, Group Finance, Corporate
affairs.
Sustainability and R&D – This category relates to initiatives to carry out sustainability and R&D activities.
Other – This category includes items such as Insurance, Legal, Environmental, and Health and Safety.
Non controllable costs are categorised as:
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Network Rates
CER levy
Table 2.1 below presents the initial allowed opex for the full PR3 period and also presents the most recent
projection (expectation) of opex by the DSO over the same period3. This data indicates that the DSO expects to
spend around €50m (or 6%) more on controllable opex than originally allowed and approximately €3m (or 2%)
more on non-controllable opex than originally allowed.
Table 2.1 : DSO PR3 Original Cost Allowance v DSO Forecast Outturn
The price control mechanism allows for a number of adjustments to be applied to the initial opex allowances set
out by the CER and presented in Table 2.1 above4. The opex allowances of some of the opex sub-categories
above have been adjusted during the PR3 period. The adjustments allowed are presented below in Table 2.2
and have been substantiated and verified following additional information from the DSO. The individual
adjustments outlined in Table 2.2 are discussed and explained in the sub-sections below5.
Table 2.2 : Adjustments to PR3 Operating Cost Allowances
Operating Cost Adjustments
CER Determination 1086.9
Allowed Adjustments
Metering 26.7
Storm Darwin 23.7
Non Controllable Costs Pass Through 3.3
3 The DSO expenditure for the years 2011 to 2013 data is based on actual values, 2014 based on unaudited actuals and 2015 data reflects the most
recent forecast available 4 For example, the allowance can be altered depending on customer numbers etc. 5 The fault maintenance adjustment (“Storm Darwin”) is discussed in Section 2.2.4 the Metering adjustment is discussed in Section 2.2.6, the
Customer Service adjustment is discussed in Section 2.2.7, the Provision of Information adjustment is discussed in Section 2.2.8 and the Non Controllable Costs adjustment is discussed in Section 2.3.
DSO Operating Costs
(€m 2009 Prices) allowed forecast variance %
Network O & M Total 445.6 493.4 47.7 11%
Asset Management 60.2 64.7 4.5 8%
Metering 100.5 130.8 30.3 30%
Customer Service 82.3 74.0 -8.3 -10%
Provision Of Information 74.8 52.6 -22.2 -30%
Corporate Costs 64.3 54.0 -10.3 -16%
Telecoms 0.0 0.0 0.0 -
Sustainability & R & D 18.2 8.0 -10.2 -56%
Other 51.0 69.7 18.7 37%
Controllable total 896.9 947.1 50.2 6%
Network Rates 180.5 183.4 2.9 2%
Cer Levy 9.5 9.9 0.4 4%
Non Controllable 190.0 193.3 3.3 2%
Total (Excl Commercial and Depn) 1086.9 1140.4 53.5 5%
PR3 Total
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Operating Cost Adjustments
Provision of Information -0.7
Customer Service -1.1
Revised PR3 Allowance 1138.8
Table 2.3 provides a revised summary of the DSOs performance against the adjusted PR3 allowances, along
with the high level efficiencies requested by CER as part of the PR3 settlement process.
Table 2.3 : Final Allowance Table for the DSO for PR3
This data indicates that, prior to any adjustments for high level efficiencies; the DSO is broadly operating within
the PR3 allowances with an expected expenditure on controllable and non-controllable items of €1140.4m
against an adjusted allowance of €1138.8m. The most significant overspend is on Network Operations and
Maintenance (€24.0m), with the main underspend being on the Provision of Information (€21.5m). Owing to the
pass through nature of non-controllable opex, PR3 allowance is expected to equal actual expenditure.
Taking into account the efficiency driver (€-31.3 million) which the DSO acknowledge was not achieved
(DH01 – Section 8), the DSO Total Costs are overspent by €32.9m (or 3% of total allowed expenditure).
The sub-sections below provide further details of the over/under spend on a category by category basis.
2.2 Controllable Costs
2.2.1 Network Operations and Maintenance
(Allowed € 469.3m Outturn € 493.4m)
DSO Operating Costs
(€m 2009 Prices) allowed forecast variance %
Network O & M Total 469.3 493.4 24.0 5%
Asset Management 60.2 64.7 4.5 8%
Metering 127.2 130.8 3.6 3%
Customer Service 81.2 74.0 -7.2 -9%
Provision Of Information 74.1 52.6 -21.5 -29%
Corporate Costs 64.3 54.0 -10.3 -16%
Telecoms 0.0 0.0 0.0 -
Sustainability & R & D 18.2 8.0 -10.2 -56%
Other 51.0 69.7 18.7 37%
Controllable total 945.5 947.1 1.6 0%
Network Rates 183.4 183.4 0.0 0%
Cer Levy 9.9 9.9 0.0 0%
Non Controllable 193.3 193.3 0.0 0%
Total (excl Depreciation) 1138.8 1140.4 1.6 0%
Less High Level Efficiencies -31.3 0.0 31.3
Total (excl Depreciation) 1107.5 1140.4 32.9 3%
PR3 Total
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Table 2.4 presents a year on year comparison between allowed and actual/forecast expenditure on Network
Operations and Maintenance opex during PR3. This category includes planned maintenance, system control
and fault maintenance activities.
Table 2.4 : Network Operations spend in PR3
Overall, the Network Operations and Maintenance activity is forecast to be overspent over the PR3 period by
€24.0m (5%). This overspend is predominantly driven by planned maintenance which is expected to incur a
20% overspend during PR3 (€39.1m) due to significant expenditure on Tree cutting over and above the
allowance. This is partially negated by an underspend of €20.5m on fault maintenance.
System Control
(Allowed € 70.1m Outturn € 75.5m)
Table 2.5 presents a year on year comparison between allowed and actual/forecast expenditure on System
Control opex during PR3.
Table 2.5 : System Control spend in PR3
The System Control activity covers the control centres in Cork and Dublin. The costs to date are running ahead
of target due to long term illnesses and resultant increases in overtime (around 40% higher than expected
during the Price setting process to cover the resource shortage). The DSO has indicated in its questionnaire
responses6 that structural changes are in the process of being implemented and the full year impact of these
structural changes to reduce the rate of spend going forward will be seen in 2015. The forecast expenditure for
2015 does not appear to reflect this change in approach as forecast expenditure in 2015 is higher than the
actual expenditure in 2014 and a further €2.1m over and above the allowed expenditure for the same year.
Planned maintenance
(Allowed € 198.0m Outturn € 237.1m)
Table 2.6 presents a year on year comparison between allowed and actual/forecast expenditure on Planned
Maintenance opex during PR3. The Planned Maintenance activity is forecast to be overspent over the PR3
period by €39.1m (20%).
Table 2.6 : Planned Maintenance spend in PR3
One of the most significant activities within this category is Tree Cutting, which accounts for around 48% of the
DSO expenditure on Planned Maintenance.
In the DSO submission for Timber Cutting they are forecasting for PR3 an expenditure of €111.8m against an
allowance of €84.7m, which will result in an overspend of €27.1m over the PR3 period.
6 DH01 PR3 Overview p27
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
System control 14.7 16.1 14.4 13.6 14.0 15.2 13.7 15.2 13.3 15.4 70.1 75.5 5.5 8%
Planned maintenance 41.0 46.0 40.3 53.3 39.6 42.7 38.9 50.4 38.2 44.7 198.0 237.1 39.1 20%
Fault maintenance 37.3 31.6 36.4 28.6 35.5 34.1 58.3 57.4 33.7 29.0 201.2 180.7 -20.5 -10%
Network O & M Total 93.1 93.8 91.1 95.5 89.1 92.0 110.8 123.0 85.2 89.2 469.3 493.4 24.0 6%
PR3 Total2014 20152011 2012 2013
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
System control 14.7 16.1 14.4 13.6 14.0 15.2 13.7 15.2 13.3 15.4 70.1 75.5 5.5 8%
2011 2012 2013 2014 2015 PR3 Total
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Planned maintenance 41.0 46.0 40.3 53.3 39.6 42.7 38.9 50.4 38.2 44.7 198.0 237.1 39.1 20%
2011 2012 2013 2014 2015 PR3 Total
DSO
Page 26
The DSO are of the opinion that the allowance set for PR3 was too low to provide an effective level of tree
cutting activity, and have deliberately overspent this allowance as it is their opinion that this is one of the most
cost effective ways to provide an acceptable level of service to customers. In the early part of the PR3 period
the LV tree cutting was curtailed by 25% against planned levels but the DSO management took the decision to
revert back to the original schedule in order to improve service levels.
Table 2.7 sourced from document ‘PR03 Timber Cutting Costs’ indicates annually derived unit costs for the
years 2011 to 2014. Due to the methods that the DSO use to allocate the work (in groups rather than by length)
and collect the data there is a level of uncertainty over the actual lengths of line where tree cutting has been
undertaken, hence the unit rates should be considered as indicative only.
Table 2.7 : Timber Cutting Unit Costs
The 110kV line cut frequency was reduced in 2011 from every 3 years to every 4 years. There is a balance
between the frequency of cut and the depth of the cut to meet required reliability standards (e.g. ESBN would
need to cut more wood to maintain a 4 year frequency than a 3 year frequency). We would expect the balance
on depth and frequency of cut to be mainly driven by cost to provide a given level of reliability and would expect
ESBN to provide justification on that basis. No cost benefit of the changed policy has been provided. Due to the
year on year natural variations it is not possible to determine if the curtailing of tree cutting was beneficial or not.
Where there is no high level assessment by the DSO of the Asset Health of the portfolio of assets under DSO
control, the approach taken by the DSO would restrict a determination of whether the planned maintenance is
sufficient to maintain an appropriate level of serviceability and if the asset class is deteriorating or if excessive
maintenance is being carried out and the customer is paying more than is needed. The DSO has not provided
evidence of the business processes in place to determine this information. It is reasonable to expect that, for a
company that has been PAS55 certified7 for its Asset Management System and approach for seven years, this
information would be utilised by the business to inform its maintenance regime and methodologies. This does
not need be a complex system, for example, a 5 point condition scale could be utilised, as illustrated below in
Table 2.8.
7 PAS55 – A Specification for the Management of Physical Assets, this has been superseded by ISO55000.
2011 2012 2013 2014
Cost €m
110kV/38kV 0.8 1 0.8 1.3
MV & LV Rural 16.3 16.7 17.5 18.5
LV Urban 2.6 1.6 5 2.8
Total 19.7 19.4 23.3 22.6
Volumes (Exact Recorded)
110kV/38kV (km) 2740 2046 1215 2378
Rural MV & LV (Groups) 38676 22730 21214 23081
Rural MV Only 12887 17623 16723 9196
LV Urban (Blocks) 118 110 145 64
Volumes (Approximate km)
110kV/38kV 2740 2046 1215 2378
MV & LV Rural 34707 30447 28691 22221
LV Urban 1686 1830 2421 1331
Total 36393 32277 31112 23552
Unit Rate €/km
110kV/38KV 289 510 651 542
MV & LV Rural 468 549 611 833
LV Urban 1571 873 2067 2087
Average 541 600 750 959
DSO
Page 27
Table 2.8 : Sample Table of Asset Condition Categories
Grade Condition Remaining Life
1 Excellent – as installed 95%
2 Good 75%
3 Fair 50%
4 Poor 30%
5 Bad – must be replaced immediately 5%
By assessing the condition of the assets at a company level it may be possible to identify potential areas of
significant changes in maintenance/ asset replacement requirements going forward, and thus the impact on
associated funding requirements. This can then be used to rate asset health by asset class over a period and
inform the priorities in an asset replacement programme, or change to maintenance frequency and activity. It
should also be possible to articulate the changes that could be seen in asset condition as a result of the
proposed investment and maintenance plans.
During the current PR3 period there have been two significant Health and Safety incidents. The findings from
the resultant investigations have entailed a full review and revision of working practices when dealing with
operational plant and machinery. The DSO has indicated that there is a significant change in the practices and
processes required to address the additional safety regimes. These have increased costs at the end of PR3 and
into PR4
There has been a significant increase in timber cutting costs over the PR3 period over and above the
allowance. The DSO believe that the increased activity level which has been procured by competitive
tendering is more appropriate in providing a satisfactory level of service to the customer and the
continued safety of the overhead network.
Fault Maintenance
(Allowed € 201.2m Outturn € 180.7m)
Table 2.9 presents a year on year comparison between allowed and actual/forecast expenditure on Fault
Maintenance opex during PR3. Overall fault maintenance expenditure is below the allowance for PR3
(€180.7m actual/forecast against €201.2m allowance).
Table 2.9 : Fault Maintenance spend in PR3
During 2013 and 2014 the DSO have stated there has been a significant increase in the level of storm and near
storm classification events, with the resultant knock on post storm costs ranging from relatively benign levels of
€2.0m in 2011 and 2012 to a level in excess of €17.0m in 2014 with associated performance impacts (e.g.
increasing customer contacts). The expenditure peak in 2014 of €57.4m is mainly due to ‘Storm Darwin’. An
adjustment has been made to allow €23.7m of expenditure for Storm Darwin to be added to allowed
expenditure.
Table 2.10 presents fault numbers for 2009 to 2013 taken from the PR03 Historic Questionnaire table 4.9.1.
The data that has been submitted for the period from 2009 indicates that the number of faults in 2013 was
higher than the previous three years. From information provided in workshops held between Jacobs, the CER
and the DSO, the latest predictions of the DSO expect the number of faults in 2014 to be even higher than 2013
levels, although 2014 activity numbers have not been supplied at the time of writing this report.
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Fault maintenance 37.3 31.6 36.4 28.6 35.5 34.1 58.3 57.4 33.7 29.0 201.2 180.7 -20.6 -10%
PR3 Total2011 2012 2013 2014 2015
DSO
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Table 2.10 : Fault Numbers 2009 to 2013
Fault nos. 2009 2010 2011 2012 2013
110kV Cables 2 3 0 1 0
110 kV Lines 3 1 4 1 16
110 kV Stations 15 11 14 13 1
38kV Cables 16 8 13 8 2
38kV Lines 73 41 57 40 81
38kV Stations 37 34 19 37 35
Total 146 98 107 100 135
The average cost per fault is analysed in Table 2.11 below, and indicates some significant volatility. This
volatility was raised with the DSO who advised us that the costs included not only direct fault costs but also
costs associated with plant failures which had been detected before interruptions had occurred and required
immediate remedial activity. This approach by the DSO and their responses indicate that they are unable to
provide meaningful unit cost analysis as costs are included under the fault headings which may not be directly
associated with post fault rectification but activities that are required to be carried out urgently in order to avoid
faults occurring. The table below has been provided for completeness. It is highly recommended that for PR4
there should be detailed unit costs for all faults, and differentiates the costs associated with attending alarms,
from actual faulted equipment. There should also be clear recording of costs to remedy a fault irrespective if the
costs are subsequently classed as capex. This inability to provide this analysis reference DSO.056.HOP, would
indicate there is little internal analysis carried out post fault to determine opportunities for more efficient fault
management.
Table 2.11 : Average Cost per Fault (2009 to 2013)
€ per fault
(2009 prices)
2009 2010 2011 2012 2013
110kV Cables 64,758 41,200 0 163,538 0
110 kV Lines 22,378 5,286 8,210 3,473 202
110 kV Stations 32,516 46,216 49,863 50,695 780,341
38kV Cables 19,576 46,246 31,792 56,421 179,442
38kV Lines 4,157 6,545 3,373 4,096 6,057
38kV Stations 82,307 67,450 255,765 86,527 47,369
For voltages below 38kV it is not possible to provide voltage specific unit fault costs, these can only be provided
at a summary level, as shown in Table 2.12 below for the years 2011 to 2013. This provides inadequate
granularity to manage fault costs in a meaningful way and identify efficient/ inefficient fault management, and
should be rectified going forward. 2014 data is not yet available from the DSO.
DSO
Page 29
Table 2.12 : MV/LV Fault Cost and Volumes (2011 to 2013 only)
The lack of clear cost monitoring and control of fault maintenance at a detailed level would indicate
there is little internal analysis carried out post fault to assess the efficiency of current fault
management or to determine opportunities for more efficient fault management. This results in an
inability to provide year on year comparisons as with the 110 kV and 38kV data and the inability to
generate unit costs for the lower voltages.
2.2.2 Asset Management
(Allowed € 60.2m Outturn € 64.7m)
Table 2.13 presents a year on year comparison between allowed and actual/forecast expenditure on Asset
Management opex during PR3. This activity comprises of Asset Management (asset managers and their teams
with responsibility for the development of policies and management of the various asset classes) and Forestry
and Wayleaves payments to landholders for compensation due to restrictions on land use due to overhead
lines. Overall expenditure on Asset Management in PR3 is forecast to exceed allowance by €4.5m (8%).
Table 2.13 : Asset Management spend in PR3
Expenditure on Asset Management strategy and policy development activities is forecast to exceed allowance
by €9.1m (a variance of 24%).
Although the DSO expects to spend less than the allowance on Forestry and Wayleaves (by around €4.6m),
there appears to be an increasing trend in the level of payments to landowners. The DSO has indicated that
farming and other environmental groups have become more vocal affecting these payments. This trend is
Fault Costs Table 5.2 €k 2011 2012 2013
MV / LV Fault Recovery 10362 9123 8589
MV / LV Unplanned Maintenance 93 98 197
MV / LV Fault Recovery - UG 6777 7641 6819
MV / LV Meter Installation Fault 564 583 472
OH MV Fault Recovery 5021 4648 4912
Underground Fault Repair 357 228 358
Total MV / LV Fault Costs 23175 22321 21347
Fault Numbers Table 4.9
OH Lines
20 KV 4304 4444 6249
10 kV 3381 3048 4139
LV Ex Services 15433 13132 15715
LV Services 1958 1446 1582
Total 25076 22070 27685
Underground Cables
20kV 18 21 26
10kV 208 243 154
LV Services 1334 1088 1095
Total 3133 2705 2734
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Asset Management 7.8 8.3 7.5 9.6 7.3 9.4 7.2 9.5 7.1 9.3 37.0 46.1 9.1 25%
Forestry & Wayleaves 4.6 3.0 4.7 3.0 4.7 4.2 4.6 3.9 4.6 4.4 23.1 18.5 -4.6 -20%
Asset Management 12.4 11.3 12.2 12.6 12.0 13.7 11.8 13.4 11.7 13.7 60.2 64.7 4.5 8%
2011 2012 2013 2014 2015 PR3 Total
DSO
Page 30
similar across both Transmission and Distribution elements of the Network. Consideration should be given to
renaming this classification of cost items as the term Asset Management could be misleading. Overall we would
consider these landowner payments as reasonable costs to the DSO.
2.2.3 Metering
(Allowed € 127.2m Outturn € 130.8m)
Table 2.14 presents a year on year comparison between allowed and actual/forecast expenditure on Metering
opex during PR3. Overall expenditure on metering in PR3 is forecast to exceed allowance by €3.7m (3%).
Table 2.14 : Metering spend in PR3
There has been an overall reduction in the Metering allowance of €1.6m to cater for the difference in actual
Connections from those assumed within the Final Determination, reducing the allowance from €128.8m to a
revised value of €127.2m. This reduction has been applied via the PCust mechanism. Table 2.15 below shows
the differences in Connections between the PR3 assumptions and actual performance. This data is taken from
the DSO document ‘DR05 Attachment B Allowance.xls’.
Table 2.15 : Connections PR3 Allowance v Actual Performance
2011 2012 2013 2014 2015 Total
PR3 assumption 28,027 29,682 31,330 32,976 34,622 156,637
PR3 actual (2014 and 2015 estimates) 15,121 12,800 15,285 16,191 15,285 74,682
Difference -12,906 -16,882 16,045 -16,785 -19,337 -81,955
Conversely, there has been an additional allowance for the installation of keypad/token meters of €28.2m. This
allowance will be adjusted to fully fund this activity. The keypad/token meter allowance was introduced to
facilitate the introduction of prepayment metering as a result of the economic issues that faced customers, this
resulted in approximately 63,000 keypad/token meters being installed.
Meter reading expenditure is 5% below allowance (€-3.0m), .
The benefits of the implementation of the contract meter readers has been reduced by the additional resources
required to process a significant increase in the number of meter readings being provided directly to the
company by customers. In some cases, manual intervention is required to validate incorrect / missing
information provided through Interactive Voice recognition (IVR) or other automated processes to supplement
the meter readings that are being collected by the meter reading contractors. There are still a significant
number of meter readings that require validation (some 156,000 in 2013 as per DSO document DH12 section
2.4).
It is expected that as the processes mature then there will be a reduced requirement for these resources
especially once the Smart metering programme is implemented.
Going forward, SMART metering has the potential to significantly reduce manual intervention in terms of the
handling of the meter reads as well as the validation of erroneous reads. This will obviously depend upon the
capability of the SMART meters and their connectivity to the respective data collection systems.
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Meter Reading 12.4 12.4 12.2 11.0 11.9 11.1 11.6 10.7 11.4 11.4 59.6 56.6 -3.0 -5%
QH Data 1.5 1.3 1.5 1.3 1.5 1.4 1.4 1.3 1.4 1.4 7.4 6.6 -0.7 -10%
Data Aggregation 4.4 4.9 4.3 4.7 4.2 5.0 4.1 4.9 3.9 5.1 20.9 24.6 3.7 17%
Customer Meter Operation 2.3 2.9 2.3 3.4 2.2 2.5 2.2 3.0 2.1 3.0 11.1 14.8 3.7 34%
Keypad / Token Meter 0.1 0.1 4.6 4.6 8.3 8.3 6.9 6.9 8.3 8.3 28.2 28.2 0.0 0%
Metering 20.8 21.5 24.8 25.0 28.1 28.2 26.2 26.8 27.2 29.2 127.2 130.8 3.7 3%
PR3 Total2011 2012 2013 2014 2015
DSO
Page 31
The DSO has expressed concern in their document DH12 Metering, that there was insufficient allowance
provided at the setting of PR3 to cover for the increase in Revenue Protection work that was not foreseen at the
time. The Data Aggregation cost increase of €3.7m is also caused by the increased level of revenue protection
work being undertaken.
The following table (Table 2.16 - taken from the DSO document DF05 Response Report) shows the levels of
activity for Calls and Interference cases detected.
Table 2.16 : Revenue Protection activity8
2009 2011 2012 2013 2014 (ytd May)
Revenue Protection Calls 9,705 11,936* 8,885 8,247
Interference Cases Detected 609 1,226 1,574* 1,457 1,459
*2012 includes revenue protection pilot calls
The number of cases being dealt with has increased during the period but not along a linear relationship. 2009
data is provided by the DSO to give some context to the level of activity at the setting of PR3 allowances. This
has resulted in consequential increases in operating costs. The effectiveness of Revenue Protection extends
beyond just the cases that are discovered and recovery actions taken. A high profile Revenue Protection activity
can deter people from going down that route, if they know that there is a high likelihood that severe action will
be taken as opposed to knowing that nothing will happen if they try to tamper with their meter. We would expect
that the implementation of SMART meters, which requires a visit to each property and installation of meters with
anti-tamper facilities, should significantly reduce this, once these meters have a critical mass.
Given the economic conditions that have been prevalent over the last 5-6 years, the costs that the DSO are
incurring for its Metering revenue protection and Long Term No Access (LTNA ) related activities do not appear
excessive. The economic climate has resulted in increased financial pressure on customers which has in turn
increased perceived benefits of tampering with meters and thus an increased level of activity in pursuance of
the offenders.
2.2.4 Customer Service
(Allowed € 81.2m Outturn € 74.0m)
Table 2.17 presents a year on year comparison between allowed and actual/forecast expenditure on Customer
Service opex during PR3. This category includes Call Centre operations, Area Operations and Customer
Relations activities. Overall expenditure on Customer Service activities is forecast to be below the PR3
allowance by €7.2m (9%).
Table 2.17 : Customer Service spend in PR3
There has been an overall reduction in the Customer Service allowance of €1.1m from €83.3 to €81.2m to cater
for the difference in actual Connections from those assumed within the Final Determination (as previously
discussed in Section 2.2.3). This reduction has been applied through the PCust mechanism.
During the PR3 period there have been a number of significant changes impacting on the level of Customer
Services provided by the DSO. There has been a significant downturn in the level of new connections and
construction activity in general due to the economic downturn. There has been a significant increase in the
8 2010 data not available
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Call Centre 6.9 7.2 6.6 5.2 6.4 5.0 6.2 5.6 6.0 5.6 32.2 28.6 -3.6 -11%
Area Operations 9.5 9.6 9.3 8.0 9.0 8.3 8.7 8.6 8.5 8.6 45.0 43.1 -1.9 -4%
Customer Relations 0.8 0.3 0.8 0.4 0.8 0.6 0.8 0.6 0.7 0.4 4.0 2.3 -1.7 -43%
Customer Service 17.2 17.2 16.7 13.6 16.2 13.9 15.7 14.7 15.3 14.6 81.2 74.0 -7.2 -9%
2011 2012 2013 2014 2015 PR3 Total
DSO
Page 32
number of customer contacts due to weather related incidents, including an unusually high level of storm and
near storm category events at the end of 2013 and beginning of 2014. During the PR3 period there is a target
of speed of call answering of 83% and to date ESBN have achieved the target.
For the Area Operations element of this category, an underspending of €1.9m (4%) was primarily due to the
reduced connections activity.
For the customer relations activity there is also underspending against the PR3 allowance of €1.7m (43%).
During this time the company have continued to meet their customer service targets, summarised in Table 2.18
and Table 2.19 (as taken from the DSO document ‘DH19 Customer Service’).
Table 2.18 : DSO Customer Service Targets
Customer Service Area Service Target Measurement Process
Speed of telephone response 80% % of calls answered in 20secs inc IVR
Calls Abandoned <5% % of calls abandoned
Mystery shopper 80% External Survey Agency
Customer callback 80% External Survey Agency
Table 2.19 : DSO Customer Service Performance
Performance against Regulatory targets – NCCC Incentive mechanism
Year 2011 2012 2013 2014 2015
Targets
Speed of tel
response
83% 83% 83% 83% 83%
Abandonment Rate 5% 5% 5% 5% 5%
Mystery Caller 80% 80% 80% 80% 80%
Callback Survey 80% 80% 80% 80% 80%
Outcome Forecast
Speed of tel
response
90% 89% 89% 85% 80%
Abandonment Rate 5% 3% 4% 5% 5%
Mystery Caller 85% 83% 82% 80% 80%
Callback Survey 86% 86% 91% 91% 80%
There has been an underspending on the Customer Service activity, it is not possible to quantify with any
certainty if the reduced cost is due to efficiencies or reduced activity due to the economic slow down and
reduced connections activity.
2.2.5 Provision of Information
(Allowed € 74.1m Outturn € 52.6m)
Table 2.20 presents a year on year comparison between allowed and actual/forecast expenditure on Provision
of Information opex during PR3. This category consists of DUoS Billing and Accounts, Market Retail Sector
Operation (MRSO) and Market Opening activities. Overall expenditure on Provision of Information activities is
forecast to be below the PR3 allowance by €21.5m (29%).
DSO
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Table 2.20 : Provision of Information spend in PR3
There has been a reduction in the Provision of Information allowance to cater for the difference in actual
Connections (as previously discussed in Section 2.2.3) from those assumed within the Final Determination.
This has been applied through the PCust facility and amounts to around €0.7m.
A significant portion of Provision of Information expenditure is charged from the Business Support Centre. A
change of pricing mechanism for IT Services was agreed in 2011 moving to a cost recovery mechanism rather
than market price cost. This contributed to lower costs for the DSO. The most significant element to this
reduction is the efficiencies associated with Market Opening activities. A number of strategies were employed
to provide cost reductions, such as headcount reductions, offshoring work where practicable, development of
longer term contracts to drive cost reductions, implementation of new technologies, such as cloud hosting, as
identified in the DSO document ‘DR05- TAO-DSO Historic Opex Interim Report’9.
2.2.6 Corporate charges
(Allowed € 64.3m Outturn € 54.0m)
Table 2.21 presents a year on year comparison between allowed and actual/forecast expenditure on Corporate
Charges opex during PR3. This category includes Company Wide Costs and Corporate Charges and Affairs.
Table 2.21 : Corporate Charges spend in PR3
Overall expenditure on Corporate Charges is forecast to be below the PR3 allowance by €10.3m (16%).
There are a number of central activities (corporate charges and affairs) that are carried out on behalf of the
DSO and recharged to the company. These costs are charged to the TAO and DSO on the basis of a 17:83
ratio. Initiatives to reduce these costs have resulted in an underspend of €10.3m (16%). It is not possible to
reliably compare these costs with other companies due to the different corporate structures/governance and
charging regimes that exist.
2.2.7 Sustainability and R&D
(Allowed € 18.2m Outturn € 8.0m)
Table 2.22 presents a year on year comparison between allowed and actual/forecast expenditure on
Sustainability and R&D opex during PR3.
Table 2.22 : Sustainability and R&D spend in PR3
9 Page 32
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Duos Billing & Accounts 1.3 1.3 1.3 1.3 1.2 1.1 1.2 1.2 1.2 1.3 6.2 6.1 -0.1 -2%
MRSO 1.9 1.4 1.9 1.2 1.9 1.4 1.8 1.2 1.8 1.7 9.3 7.0 -2.4 -26%
Market Opening 12.2 8.8 11.9 7.6 11.7 7.4 11.5 7.8 11.3 7.9 58.6 39.6 -19.0 -32%
Provision Of Information 15.4 11.5 15.1 10.1 14.8 10.0 14.6 10.2 14.3 10.9 74.1 52.6 -21.5 -29%
PR3 Total2011 2012 2013 2014 2015
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Company Wide Costs 1.9 2.4 1.9 2.4 1.8 2.2 1.8 1.7 1.7 2.0 9.2 10.6 1.4 15%
Corporate Charges & Affairs 11.6 9.2 11.3 8.6 11.0 8.0 10.7 8.5 10.5 9.0 55.2 43.4 -11.7 -21%
Corporate Costs 13.5 11.6 13.2 11.0 12.9 10.2 12.5 10.2 12.2 11.0 64.3 54.0 -10.3 -16%
2011 2012 2013 2014 2015 PR3 Total
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Sustainability 3.0 0.9 3.0 2.0 3.0 1.1 3.0 1.5 3.0 2.5 14.8 8.0 -6.8 -46%
R & D 0.7 0.0 0.7 0.0 0.7 0.0 0.7 0.0 0.7 0.0 3.4 0.0 -3.4 -100%
Sustainability & R & D 3.6 0.9 3.6 2.0 3.6 1.1 3.6 1.5 3.6 2.5 18.2 8.0 -10.2 -56%
PR3 Total2011 2012 2013 2014 2015
DSO
Page 34
Overall expenditure on sustainability and R&D is forecast to be below the PR3 allowance by €10.2m (56%
below allowance). The DSO have indicated that the CER in their document (CER 14/057) have allocated €6.0m
of the total allowance of €18.2m towards an Electric vehicles pilot project. We understand that internally ESBN
have allocated this to ESBN Innovation.. We have not been provided with any information of the level of
expenditure on this project. As the decision paper from the CER was on 5th March 2014 we conclude that the
expenditure on this project is minimal. We consider that these underspends could therefore be classed as a
windfall gain as the intended activities have not been carried out.
2.2.8 Other
(Allowed € 51.0m Outturn € 69.7m)
Table 2.23 presents a year on year comparison between allowed and actual/forecast expenditure on Other opex
during PR3.
Table 2.23 : Other spend in PR3
Overall expenditure on Other opex items is forecast to exceed the PR3 allowance by €18.7m (37%).
There are several factors which impact on the variance in ‘Other’ expenditure. The DSO have indicated in a
number of discussions that costs for Network Assets and Employers/ Public Liability Insurance is passed from
Corporate centre and relates to increases in the Network Asset base. This does not sufficiently account for the
increases and subsequent decreases in the charges during the PR3 period.
The legal costs have risen over the period with an 11% overall increase over allowed revenue, which may be
expected to rise given the increased legal workload associated with the increased revenue protection work that
the DSO is experiencing as customers find themselves under economic pressure.
The increase in Health and Safety costs is due to the recent severe safety incidents that have occurred within
the DSO activities. Following a full review of the Health and Safety processes and procedures a significant
increase in the level of expenditure (which is over and above the PR3 allowance) was required to ensure that
the processes and procedures and staff training / education are fit for purpose. This increase is expected to
continue into PR4.
2.3 Non Controllable Costs
Table 2.24 presents a year on year comparison between allowed and actual/forecast expenditure on Non-
Controllable opex during PR3.
Table 2.24 : Non Controllable spend in PR3
This category includes pass-through costs such as network rates and the CER Levy. The DSO has little/no
control over these costs. The actual values for these two items are factored into the DUoS calculations, hence
the allowance is adjusted in line with the actual/expected spend.
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Insurance 2.5 1.8 2.5 5.0 2.5 3.4 2.5 4.2 2.5 3.4 12.5 17.8 5.3 42%
Legal 2.3 2.1 2.3 2.2 2.3 2.6 2.3 2.9 2.3 2.9 11.3 12.6 1.3 11%
Pension 1.7 2.7 1.6 1.7 1.6 2.0 1.5 2.0 1.5 1.4 7.9 9.7 1.8 23%
Environmental 1.1 1.6 1.1 1.2 1.1 1.3 1.1 1.2 1.1 1.2 5.5 6.4 0.9 16%
Health & Safety 2.9 1.7 2.8 1.8 2.7 2.4 2.7 5.2 2.6 8.3 13.7 19.4 5.7 41%
Misc 0.0 0.9 0.0 1.6 0.0 0.1 0.0 1.0 0.0 0.3 0.0 3.8 3.8
Other 10.5 10.7 10.3 13.4 10.2 11.8 10.1 16.4 10.0 17.4 51.0 69.7 18.7 37%
2011 2012 2013 2014 2015 PR3 Total
DSO Operating Costs
(€m 2009 Prices) allowed actual allowed actual allowed actual allowed actual allowed actual allowed forecast variance %
Network Rates 35.3 35.3 34.2 34.2 34.1 34.1 37.6 37.6 42.1 42.1 183.4 183.4 0.0 0%
Cer Levy 1.6 1.6 1.9 1.9 2.2 2.2 2.0 2.0 2.1 2.1 9.9 9.9 0.0 0%
Non Controllable 36.9 36.9 36.1 36.1 36.4 36.4 39.6 39.6 44.2 44.2 193.3 193.3 0.0 0%
PR3 Total2011 2012 2013 2014 2015
DSO
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2.4 Conclusions and Findings
The overspend on Network Operations and Maintenance is predominantly driven by planned maintenance
which is expected to incur a 20% overspend during PR3 (€39.1m) due to significant expenditure on Tree cutting
over and above the allowance. This is partially negated by an underspend of €20.5m on fault maintenance.
A significant portion of Provision of Information expenditure is charged from the Business Support Centre. A
change of pricing mechanism for IT Services was agreed in 2011 moving to a cost recovery mechanism rather
than market price cost. This contributed to lower costs for the DSO. The most significant element to this
reduction is the efficiencies associated with Market Opening activities. A number of strategies were employed
to provide cost reductions, such as headcount reductions, offshoring work where practicable, development of
longer term contracts to drive cost reductions, implementation of new technologies such as cloud hosting.
Overall expenditure on other opex items is forecast to exceed the PR3 allowance by €18.7m (37%). There are
several factors which impact on the variance in ‘Other’ expenditure:
The DSO have indicated in a number of discussions that costs for Network Assets and Employers/ Public
Liability Insurance are passed from Corporate centre and relate to increases in the Network Asset base.
This does not sufficiently account for the increases and subsequent decreases in the charges during the
PR3 period.
The legal costs would be expected to rise given the increased revenue protection work that the DSO is
experiencing as customers find themselves under economic pressure.
The increase in Health and Safety costs is due to the recent severe safety incidents that have occurred
within the DSO activities. There has been a full review of the Health and Safety processes and procedures
necessitating a significant increase in the level of expenditure (which is over and above the PR3 allowance)
in order to put the requisite changes in place to ensure that the processes and procedures and staff
training / education are in place are fit for purpose from a Health and Safety perspective. This increase is
expected to continue into PR4.
The DSO has faced some major challenges during PR3, particularly the economic downturn and the significant
increase in severe weather events, neither of which could be foreseen at the setting of the PR3 determination.
The DSO has not provided a view of their Asset condition at a company-wide level. This is a concern and
should be addressed during PR4. The high level view will allow the DSO to understand the long term effect of
maintenance levels on their asset condition and allow it to take a more informed long term approach to
maintenance and Capex replacement programmes.
The DSO has achieved the cost targets set out in the CER decision paper however we are of the opinion that it
has not achieved the additional cost efficiencies required by the CER. It is our view that the company has
received windfall gains of €10.2m on Sustainability and R&D activities.
DSO
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3. Review of PR4 Operating Expenditure
The objective of the CER in setting allowed opex is to ensure that expenditure is efficient and that efficiency
improvements within the DSO continue to be made, to the benefit of customers. This should result in setting the
companies challenging but realistic and achievable targets and incentives, all the while moving closer to
international best practice. In this section of the report we review the DSO’s proposed opex for the PR4 period
and advise on any adjustments that we believe are necessary in order to allow the CER to determine the
appropriate opex allowances for the PR4 period covering the years 2016 to 2020 for an efficient company
operating in Ireland.
The data presented, analysed and commented on in this report is based on data provided by the DSO to the
CER and Jacobs via:
The return of Questionnaires issued by the CER in July 2014 and associated information papers and
network plans
Ongoing communications with Jacobs and the CER following the submission of the forecast PR4 data in
November 2014.
Background information from CER on previous price reviews
It should be noted that 2011 to 2013 performance and cost data is based on actual recorded values. Unless
stated otherwise, the 2014 and 2015 performance and cost data is based on the original forecast data
submitted at the time of the initial forecast submission. Where updated 2014 and 2015 information has been
made available by the DSO and this information differs significantly from the initial forecast submission this
information been taken into consideration when outlining our proposed allowances.
3.1 General / Overview
Excluding Commercial Costs, the DSO has proposed a total opex allowance for PR4 of €1506.0m, which
represents an increase of €332.3m (28%) from PR3 forecast outturn.
The total proposed opex allowance is broken down as follows:
Proposed controllable opex of €1219.9 (an increase of €245.0m - 25% - from PR3 outturn)
Proposed non-controllable opex of €286.1m (an increase of €87.2m - 44% - from PR3 outturn)
A breakdown of the DSO’s proposed expenditure is provided below in Table 3.1. Commercial Costs are
included in this table for completeness but are not discussed further in this report due to their non-controllable
nature.
Table 3.1 : DSO Proposed Opex Allowances for PR4
DSO
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* The PR3 outturn presented above is different from that reported in Section 2 of this report due to a change in
price base from 2009 to 2014 utilising HICP rates.
The DSO has provided a significant amount of narrative on the proposed PR4 forecast operating costs. We
have reviewed the submissions provided and in some cases requested additional information, to clarify
justifications or provide additional supporting information. As a result of our reviews, we have recommended a
reduction of €143.9m to the level of operating expenditure proposed by the DSO. All of our recommended
€143.9m reduction to the DSO’s opex allowance is identified in controllable costs only.
Table 3.2 below provides an annual view of our proposed allowances.
Table 3.2 : High level comparison of DSO Opex Allowances for PR4
Table 3.3 provides a summary of our proposed DSO opex allowance for PR4 compared to the DSO’s original
proposition.
Proposed Operating Costs
(€ 2014 Prices)
Network O&M Allowance 507.8 94.3 114.4 117.9 116.0 116.7 116.1 581.1 73.3 14%
Asset Management Allowance 66.6 13.7 14.0 14.2 14.4 14.7 15.0 72.3 5.7 9%
Metering Allowance 134.6 29.0 40.4 38.0 34.2 33.9 33.6 180.1 45.5 34%
Customer Service Allowance 76.2 14.2 18.4 17.8 17.8 18.1 18.2 90.2 14.1 18%
Provision of Information Allowance 54.2 10.2 12.4 12.4 12.9 12.8 12.8 63.3 9.1 17%
Corporate Costs Allowance 55.6 10.5 10.3 10.3 10.3 10.3 10.3 51.4 -4.2 -7%
Telecoms Allowance 0.0 0.0 13.2 13.5 13.6 13.7 13.8 67.7 67.7 -
Sustainability & R&D Allowance 8.2 1.1 2.3 2.6 3.4 3.7 3.6 15.6 7.4 91%
Other Allowance 71.7 12.1 22.7 21.7 18.9 17.8 17.1 98.2 26.5 37%
Controllable Allowance 974.8 185.1 248.1 248.2 241.4 241.5 240.5 1,219.9 245.0 25%
Network Rates 188.7 35.0 46.9 51.0 55.0 59.1 63.1 275.1 86.4 46%
CER Levy 10.2 2.3 2.2 2.2 2.2 2.2 2.2 11.0 0.8 8%
Non Controllable Allowance 198.9 37.3 49.1 53.2 57.2 61.3 65.3 286.1 87.2 44%
Total Allowance (excl. Depreciation) 1,173.7 222.4 297.3 301.4 298.7 302.8 305.8 1,506.0 332.3 28%
DSO Proposed Operating Costs
PR3 2013 2016 2017 2018Variance
%2019 2020 PR4
Variance
PR4-PR3
Propsed Operating Costs
(€ 2014 Prices)
Network O&M Allowance 507.8 94.3 114.4 117.9 116.0 116.7 116.1 581.1 73.3 14% -43.4 537.7 -7%
Asset Management Allowance 66.6 13.7 14.0 14.2 14.4 14.7 15.0 72.3 5.7 9% 0.0 72.3 0%
Metering Allowance 134.6 29.0 40.4 38.0 34.2 33.9 33.6 180.1 45.5 34% -21.3 158.8 -12%
Customer Service Allowance 76.2 14.2 18.4 17.8 17.8 18.1 18.2 90.2 14.1 18% -3.2 87.0 -4%
Provision of Information Allowance 54.2 10.2 12.4 12.4 12.9 12.8 12.8 63.3 9.1 17% -2.9 60.4 -5%
Corporate Costs Allowance 55.6 10.5 10.3 10.3 10.3 10.3 10.3 51.4 -4.2 -7% -3.0 48.4 -6%
Telecoms Allowance 0.0 0.0 13.2 13.5 13.6 13.7 13.8 67.7 67.7 - -48.4 19.3 -71%
Sustainability & R&D Allowance 8.2 1.1 2.3 2.6 3.4 3.7 3.6 15.6 7.4 91% -4.5 11.1 -29%
Other Allowance 71.7 12.1 22.7 21.7 18.9 17.8 17.1 98.2 26.5 37% -17.2 81.0 -18%
Controllable Allowance 974.8 185.1 248.1 248.2 241.4 241.5 240.5 1,219.9 245.0 25% -143.9 1,076.0 -12%
Network Rates 188.7 35.0 46.9 51.0 55.0 59.1 63.1 275.1 86.4 46% 0.0 275.1 0%
CER Levy 10.2 2.3 2.2 2.2 2.2 2.2 2.2 11.0 0.8 8% 0.0 11.0 0%
Non Controllable Allowance 198.9 37.3 49.1 53.2 57.2 61.3 65.3 286.1 87.2 44% 0.0 286.1 0%
Total Allowance (excl. Depreciation) 1,173.7 222.4 297.3 301.4 298.7 302.8 305.8 1,506.0 332.3 28% -143.9 1,362.1 -10%
DSO Proposed Operating Costs
2019 2020 PR4Variance
PR4-PR3PR3 2013 2016 2017 2018
Variance
%
Jacobs Proposed Operating
Costs
Variance
to PR3
PR4
Allowed
PR4
Changes
DSO
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Table 3.3 : Jacobs Proposed DSO Opex Adjustments for PR4
The rationale behind the DSO’s proposed allowances and our adjustments to those proposals is provided within
each sub-section below.
3.2 Controllable Costs
Controllable costs are categorised as follows:
Network O&M – The day to day System Control covering the Distribution Control Centres in Cork and
Dublin, along with planned and fault maintenance of the Network Assets.
Asset Management – The development of Policies and Asset strategies, along with payments for
wayleaves, forestry and mast interference payments.
Metering – The DSO provides a range of services related to metering to all stakeholders including
electricity supply companies and customers. These services include the management of these assets,
collection and aggregation of metering data and revenue protection services.
Customer Service – Included within this category are the costs of the Customer Care Centre, Scheduling
Support Centre, Customer Relations and Area Operations.
Provision of Information – The costs in this category are associated with DUoS billing and accounts
receivable, Meter Registration System Operator, Market System Support Costs.
Corporate costs – The costs within this category are from Corporate Centre for services such as CEO,
Group Finance, Corporate affairs.
Telecomm – The provision of telecomms equipment to monitor and operate the DSO Network remotely.
Sustainability and R&D – The costs in this category relate to initiatives to carry out sustainability and R&D
activities.
Other – This includes items such as Insurance, Legal, Environmental, and Health and Safety.
We address each of these categories in the sub-sections below after a brief section on Manpower.
3.2.1 Overall Manpower
The company has identified the following manpower related costs in its submissions.
Table 3.4 provides a comparison between the headcounts for PR3 and PR4. The DSO is forecasting a total of
108 additional staff over the PR4 period compared to the position at the end of PR3. We can see from this table
that the DSO are forecasting for PR4 to keep the cost rate per full time employee (FTE) in line with the levels of
Proposed Operating Costs
(€ 2014 Prices)
Network O&M Allowance 507.8 94.3 105.8 109.2 107.3 108.0 107.4 537.7 29.9 6%
Asset Management Allowance 66.6 13.7 14.0 14.2 14.4 14.7 15.0 72.3 5.7 9%
Metering Allowance 134.6 29.0 32.7 33.0 30.9 31.0 31.2 158.8 24.2 18%
Customer Service Allowance 76.2 14.2 17.3 17.5 17.4 17.4 17.5 87.0 10.9 14%
Provision of Information Allowance 54.2 10.2 12.3 12.4 12.0 11.9 11.8 60.4 6.2 11%
Corporate Costs Allowance 55.6 10.5 9.7 9.7 9.7 9.7 9.7 48.4 -7.2 -13%
Telecoms Allowance 0.0 0.0 3.5 3.8 3.9 4.0 4.1 19.3 19.3 -
Sustainability & R&D Allowance 8.2 1.1 2.3 2.6 1.9 2.2 2.1 11.1 2.9 36%
Other Allowance 71.7 12.1 20.2 18.7 15.5 13.9 12.7 81.0 9.3 13%
Controllable Allowance 974.8 185.1 217.9 221.0 213.0 212.6 211.6 1,076.0 101.2 10%
Network Rates 188.7 35.0 46.9 51.0 55.0 59.1 63.1 275.1 86.4 46%
CER Levy 10.2 2.3 2.2 2.2 2.2 2.2 2.2 11.0 0.8 8%
Non Controllable Allowance 198.9 37.3 49.1 53.2 57.2 61.3 65.3 286.1 87.2 44%
Total Allowance (excl. Depreciation) 1,173.7 222.4 267.0 274.2 270.2 273.9 276.9 1,362.1 188.4 16%
2016PR3 2013
Jacobs Proposed Operating Costs
Variance
PR4-PR3
Variance
%PR42020201920182017
DSO
Page 39
PR3. This table would lead us to conclude that the DSO is managing the costs of its staff. These numbers also
include 105 FTE saving10 that will be achieved due to the implementation of IT driven solutions in front line and
back office staff.
Table 3.4 : Comparison of Headcount Costs (PR3 v PR4) (TAO and DSO combined)
PR3 PR4
2011 2012 2013 2014 2015 Average 2016 2017 2018 2019 2020 Average
Payroll €m (Table 3.4.1)
281 341 248 256 251 275 274 275 271 269 264 271
Headcount (Table 4.8.1)
3391 3273 3049 3062 3145 3184 3299 3329 3300 3276 3257 3292
Costs per FTE €k 83 104 81 83 80 86 83 83 82 82 81 82
n.b. This table includes DSO and TAO Staff and Costs – on the understanding that there is no significant
difference between the staff on DSO and TAO duties (this was verbally confirmed with DSO/TAO during
workshops).
In discussions and workshops with the DSO and the regulator, the DSO have indicated that there will be
additional resources used from Contractors, where appropriate, to carry out activities to support the in- house
staff.
3.2.2 Network Operations and Maintenance
DSO requested €581.1m, Recommended reduction €-43.4m, Allowance recommended €537.7m
Table 3.5 presents a year on year comparison between the DSO’s proposed Network Operations and
Maintenance opex allowance for PR4 and Jacobs proposed opex allowance for PR4.
The DSO has proposed a total allowance of €581.1m over the PR4 period for Network Operations and
Maintenance opex. This is €73.3m in excess of the spend in PR3, partly due to changes in practices and partly
due to intentional deferrals from PR3 as a cost saving measure. This increase is predominantly driven by
increased Planned Maintenance expenditure on HV stations. We have made reductions of €41.5m in this
activity and a reduction of €1.9m in system control, as shown in table 3.5 below, reducing the total allowance to
€537.7m.
Table 3.5 : Summary of Jacobs Proposed Network O&M Opex Allowance for PR4
The DSO has proposed a total allowance of €83.0m over the PR4 period for System Control opex. This is
€5.3m in excess of the spend in PR3. Within System Control, the DSO have identified a number of capex
10 DF06 DSO forecast Capex response Table11
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed System Control 77.7 15.6 16.4 16.6 16.7 16.7 16.7 83.0 5.3 7%
Jacobs Proposed Changes -0.3 -0.4 -0.4 -0.4 -0.4 -1.9 -1.9
Jacobs Proposed System Control Allowance 77.7 15.6 16.1 16.2 16.3 16.3 16.3 81.1 3.4 4%
DSO Proposed Planned Maintenance 244.2 43.8 64.9 67.7 66.0 66.7 66.0 331.4 87.2 36%
Jacobs Proposed Changes -8.3 -8.3 -8.3 -8.3 -8.3 -41.5 -41.5
Jacobs Proposed Planned Maintenance Allowance 244.2 43.8 56.6 59.4 57.7 58.4 57.7 289.9 45.7 19%
DSO Proposed Fault Maintenance 185.8 35.0 33.1 33.5 33.3 33.3 33.5 166.7 -19.1 -10%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Fault Maintenance Allowance 185.8 35.0 33.1 33.5 33.3 33.3 33.5 166.7 -19.1 -10%
DSO Proposed Network O&M Total 507.8 94.3 114.4 117.9 116.0 116.7 116.1 581.1 73.3 14%
Jacobs Proposed Changes -8.6 -8.7 -8.7 -8.7 -8.7 -43.4 -43.4
Jacobs Proposed Network O&M Allowance 507.8 94.3 105.8 109.2 107.3 108.0 107.4 537.7 29.9 6%
PR4
Variance
PR4-PR3
Variance
%PR3 2013 2016 2017 2018 2019 2020
DSO
Page 40
investments that will be required to infrastructure systems based upon 3 components; SCADA, OMS and
Control Centre. The DSO has also identified a need for LV system mapping that is currently not available. We
have considered the request and have proposed an increase of €3.4m in excess of the PR3 expenditure as we
would expect that the company will have reductions in some of the redundant systems and be incentivised to
seek efficiencies.
The DSO has proposed a total allowance of €331.4m over the PR4 period for Planned Maintenance. The DSO
are seeking €87.2m greater allowance for Planned Maintenance in PR4 compared to PR3. The key contributor
to this increase is Station Maintenance, accounting for €72m of the increase and comprising of €43m for HV
station maintenance and €29.0m for MV/LV substation/minipillar inspections and follow ups. This increase is
justified by the DSO on the basis that:
Additional work in the form of condition monitoring and recording, to support the introduction of condition
based strategies, will result in more optimum maintenance in the longer term.
Additional overhauls that were not carried out in PR3 due to insufficient funding will be required in PR4
In papers DF03 and presentations made by the company, information was provided on the approach and costs
of major changes to the planned maintenance with changes to the frequency of inspections and testing and
major overhauls of some equipment like the Magnefix units which have had a number of failures. Following the
failures there has been discharge testing carried out to identify possible future failures. The report indicates that
93% were in good condition, with 55 units needing overhaul and 40 units in poor condition and needing to be
replaced (this is following a period where the units were monitored from 2006). Based on this there appears to
be a condition based approach recently introduced which manages the population reasonably well identifying
the condition and where there is a need for replacement or overhaul. However the company have stated11 that
they are moving away from Condition Based Maintenance for their Magnefix MV switchgear and back to
cyclical, which is a reversion from their policy in 2006. The cost of the Magnefix overhauls in the submission is
€16.5m. They have 2200 units on the system and plan to replace 400 in PR4 reducing the population to 1800.
With a 4 year overhaul that equates to around €7500 per unit in PR4. The switchgear is encased epoxy resin
and the failures appear to be due to tracking due to surface dirt and moisture building up over time, and also
contact resistance causing burning to insulation, again over a long period of time. Both of these can and have
been targeted in the discharge testing and could also be monitored using thermal imaging equipment.
The costs implied in this programme seem excessive and the monitoring approach would ensure only targeted
actions would be required. In addition the €7,500 per unit seems extremely high as some units will only require
cleaning of surface contamination and checking contacts for corrosion and cleaning.
Within DF03 there is reference to benchmarking to GB DNO’s which was also stated in the PR3 submission in
2009, and as stated in the 2009 SKM report this would be expected to reduce overall costs not increase them.
The requested allowance for PR3 €247m, and the allowance was recommended as €198m, partially due to an
underspend on allowances in PR2 on substation maintenance by €18m. The outturn planned maintenance in
PR3 is €244m, broadly in line with the PR3 requested allowance and well in excess of the allowed revenue.
The DSO are proposing the development of Condition Based Maintenance (CBM), whilst we recognise the need
and benefits of CBM strategies (which in themselves are usually justified as a cost reduction mechanism). The
DSO are only proposing a pilot study at Distribution Level citing that there is ‘not yet a firm business case or
technological maturity’12. Given that Condition Based Maintenance methodology has been in existence for some
time, it is surprising to find that the DSO consider this new technology. The submission indicates that in moving
to condition based maintenance there will be considerably higher costs on top of the existing cyclic
maintenance. The cost increases being driven by the increased data management and identifying appropriate
systems that the new methodology will require. The normal approach is to analyse the condition failure
mechanisms and target the monitoring of those areas where the information is gathered more efficiently. In
addition, some aspects of condition monitoring remove the need to remove plant from service and carry out
detailed intrusive overhaul. Overall the approach taken does not appear to justify the major increases in costs
11 DR05 – TAO-DSO Forecast interim report p33 12 DR05 – TAO-DSO Forecast interim report p37
DSO
Page 41
for this activity. This inconsistency of strategy and approach has led us to believe that there is an inconsistent
and uncoordinated overall approach to this activity.
We would expect that there would be savings from reduced maintenance during the pilot and expected rollout.
There has been little evidence in the PR4 proposed allowances of the potential savings that would be expected
to arise from this activity. We would also expect to see significant changes to the levels of maintenance carried
out in PR5 through condition based maintenance and a better understanding of the overall condition of the
assets.
As a result of this we have recommended a reduction in Planned Maintenance Allowance by €41.5m, giving an
allowance of €289.9m.
The Tree cutting activity is also a significant contribution to the Planned Maintenance activity, with a PR4
forecast of €112.8m against a spend of €110.8 (2014 prices) in PR3. The PR3 spend is in excess of the PR3
allowance and is discussed in the Historic Opex report. We have proposed no change to the level of tree
cutting allowance in PR4 from the submission provided by the DSO, however we would recommend that
additional reporting metrics are developed in PR4 to determine what the unit rates are for the work carried out
(in €/km, rather than per “block”), in order to gain a better understanding of the efficiency or the service being
provided.
The DSO has proposed a total allowance of €166.7m over the PR4 period for Fault Maintenance. This equates
to €19.1m less than the PR3 expected outturn. The fault costs proposed are broadly in line with the expected
spend in PR3 after adjusting for Storm Darwin costs of €23.7m.
3.2.3 Asset Management
DSO requested €72.3m, Recommended reduction €0.0m, Allowance recommended €72.3m
Table 3.6 presents a year on year comparison between the DSO’s proposed Asset Management opex
allowance for PR4 and Jacobs proposed opex allowance for PR4.
The DSO has proposed a total allowance of €72.3m over the PR4 period for Asset Management opex. This is
€5.7m in excess of the spend in PR3.
Table 3.6 : Jacobs Proposed Asset Management Opex Allowance for PR4
The costs incurred in this category are for the costs of the Asset managers and their teams, who have the
responsibility for the determination of policies and management of the various assets under DSO control. The
PR4 costs for the Asset Management Teams seem reasonable and are in line with the annual costs for the
latter part of PR3. We therefore do not propose any changes to the DSO proposed values. The Forestry and
Wayleave costs have been allowed in full as we recognise that there is pressure from environmental lobby
groups and we consider the level of allowance going forward is appropriate.
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Asset Management 47.5 9.7 9.4 9.6 9.6 9.6 9.7 47.9 0.4 1%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Asset Management Allowance 47.5 9.7 9.4 9.6 9.6 9.6 9.7 47.9 0.4 1%
DSO Proposed Forestry & Wayleaves 19.1 4.0 4.5 4.7 4.8 5.0 5.3 24.4 5.3 28%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Forestry and Wayleaves Allowance 19.1 4.0 4.5 4.7 4.8 5.0 5.3 24.4 5.3 28%
DSO Proposed Asset Management 66.6 13.7 14.0 14.2 14.4 14.7 15.0 72.3 5.7 9%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
66.6 13.7 14.0 14.2 14.4 14.7 15.0 72.3 5.7 9%Jacobs Proposed Asset Management and Forestry
Allowance
PR4
Variance
PR4-PR3
Variance
%PR3 2013 2016 2017 2018 2019 2020
DSO
Page 42
3.2.4 Metering
DSO requested €180.1m, Recommended reduction €21.3m, Allowance recommended €158.8m
Table 3.7 presents a year on year comparison between the DSO’s proposed Metering opex allowance for PR4
and Jacobs’ proposed opex allowance for PR4. Overall, the DSO are requesting an increase in metering costs
of €45.5m (34%) over the costs forecast for PR3, raising the PR4 allowance to €180.1m.
Table 3.7 : Jacobs Proposed Metering Opex Allowance for PR4
For Meter Reading, Quarter Hourly (QH) data and Data Aggregation, the recommendation is to carry forward
the allowance in line with the DSO proposals. The DSO is forecasting a consistent growth in the number of QH
Meters being installed in PR4 as shown in Table 3.8 below. Currently within PR3 there is a mechanism to
correct for actual meter installation and customer numbers. The expectation is that this will continue and any
such changes in the forecast connections and meter numbers within PR4 will be corrected and the above
allowances adjusted.
Table 3.8 : QH meters installed forecast13
2014 2015 2016 2017 2018 2019 2020
Total QH meters installed 13,750 14,600 14,968 15,328 15,688 16,048 16,048
The main driver for the increase in Metering expenditure (compared to PR3) is due to Customer Meter
Operation (an increase of €13.5m) and Keypad/Token meters (an increase of €26.4m).
The Customer Meter Operation includes Revenue Protection activities. There has been increased activity in
this area in PR3 (see Table 2.16) and we consider that this is likely to continue in PR4. The DSO have also
identified that there will be a significant increase in the Major Meter Testing (MMT) activity in PR4 compared to
the 33% of the targeted activity in PR3 as there is now a requirement to manage and install Power Quality
Meters on all Distribution connected generator sites. We have accepted the DSO’s proposed opex allowance
for Customer Meter Operation on this basis.
For the additional metering costs, the DSO has indicated that the latest meters with their anti-tampering
capabilities are significantly more expensive than the current meters. However when reviewing the current unit
costs as illustrated in Table 3.9 below, it can be seen that there are significant increases in unit costs in PR4
without the increased costs of the new keypad/token meters. The DSO has proposed an expenditure of €55.3m
on keypad/token meters during PR3. Our PR4 proposed allowance has been based on revised volumes and a
13 DH12 – Metering.pdf p10 and DF12 Metering.pdf p7
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Meter Reading 58.3 11.3 11.6 11.7 11.6 11.6 11.7 58.2 -0.1 0%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Meter Reading Allowance 58.3 11.3 11.6 11.7 11.6 11.6 11.7 58.2 -0.1 0%
DSO Proposed QH Data 6.8 1.4 1.8 1.8 1.8 1.8 1.9 9.2 2.3 34%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed QH Data Allowance 6.8 1.4 1.8 1.8 1.8 1.8 1.9 9.2 2.3 34%
DSO Proposed Data Aggregation 25.3 5.1 5.5 5.7 5.8 5.8 5.9 28.6 3.3 13%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Data Aggregation Allowance 25.3 5.1 5.5 5.7 5.8 5.8 5.9 28.6 3.3 13%
DSO Proposed Customer Meter Operation 15.3 2.5 5.8 5.8 5.6 5.7 5.8 28.8 13.5 88%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Customer Meter Operation Allowance 15.3 2.5 5.8 5.8 5.6 5.7 5.8 28.8 13.5 88%
DSO Proposed Keypad/Token Allowance 28.9 8.5 15.7 13.0 9.3 8.9 8.4 55.3 26.4 91%
Jacobs Proposed Changes -7.7 -5.0 -3.3 -2.9 -2.4 -21.3 -21.3
Jacobs Proposed Keypad/Token Allowance 28.9 8.5 8.0 8.0 6.0 6.0 6.0 34.0 5.1 18%
DSO Proposed Metering 134.6 29.0 40.4 38.0 34.2 33.9 33.6 180.1 45.5 34%
Jacobs Proposed Changes -7.7 -5.0 -3.3 -2.9 -2.4 -21.3 -21.3
Jacobs Proposed Metering Allowance 134.6 29.0 32.7 33.0 30.9 31.0 31.2 158.8 24.2 18%
PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR4-PR3
Variance
%
DSO
Page 43
unit cost of €400 per keypad/token meter installation, during workshop discussions with the DSO. This results
in a total expenditure of €34.0m, a reduction of €21.3m.
Table 3.9 : Keypad / Token Meter Unit Costs (PR3 v PR4) all in 2014 prices.
DSO view
PR3 PR4
2011 2012 2013 2014 2015 Total 2016 2017 2018 2019 2020 Total
Meters (000) 0.7 14.7 26.6 20.8 17.5 80.3 25 22 15 15 15 92.5
DSO Cost €m 0.1 4.7 8.5 7.1 8.6 29.0 15.7 13 9.3 ‘8.9 8.4 55.3
€ per meter 137.8 318.7 317.9 341.3 493.0 360.7 615.7 590.9 620 593.3 560 597.8
Jacobs view
Revised volumes of meters (000s)
20.0 20.0 15.0 15.0 15.0 85
Allowance at €400 per meter
8.0 8.0 6.0 6.0 6.0 34
3.2.5 Customer Service
DSO requested €90.2m, Recommended reduction €-3.2m, Allowance recommended €87.0m.
Table 3.10 presents a year on year comparison between the DSO’s proposed Customer Service opex
allowance for PR4 and Jacobs’ proposed opex allowance for PR4.
Table 3.10 : Jacobs Proposed Customer Service Opex Allowance for PR4
The DSO has proposed a total allowance of €90.2m over the PR4 period, an increase of €14.1m (18%) on the
expected outturn spend in PR3.
The DSO has indicated14 that there will be additional expenditure within the Call Centre activity in order to
facilitate additional online services for customers, such as improved websites and development of social media
communications. This shows excellent awareness of customer trends and preferences, however the increase in
costs does not seem proportionate to the increase in services15. We are proposing an increase in allowance
over PR3 actual expenditure levels of 4% (i.e €1.2m) for this increase in services. This resultant allowance is in
excess of the current rate of expenditure for 2013/14 and forecast for 2015.
14 DF19 Customer Service 15 The increase in services is likely to be marginal as the website is already developed and it is understood to require only minor tweaks.
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Call Centre 29.4 5.1 6.3 6.4 6.4 6.5 6.5 32.1 2.7 9%
Jacobs Proposed Changes -0.3 -0.3 -0.3 -0.3 -0.3 -1.5 -1.5
Jacobs Proposed Call Centre Allowance 29.4 5.1 6.0 6.1 6.1 6.2 6.2 30.6 1.2 4%
DSO Proposed Area Operations 44.4 8.5 8.8 8.9 8.9 8.9 8.9 44.4 0.0 0%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Area Operations Allowance 44.4 8.5 8.8 8.9 8.9 8.9 8.9 44.4 0.0 0%
DSO Proposed Customer Relations 2.3 0.6 3.2 2.4 2.5 2.8 2.8 13.7 11.4 487%
Jacobs Proposed Changes -0.8 0.0 -0.1 -0.4 -0.4 -1.7 -1.7
Jacobs Proposed Customer Relations Allowance 2.3 0.6 2.4 2.4 2.4 2.4 2.4 12.0 9.7 414%
DSO Proposed Customer Service 76.2 14.2 18.4 17.8 17.8 18.1 18.2 90.2 14.1 18%
Jacobs Proposed Changes -1.1 -0.3 -0.4 -0.7 -0.7 -3.2 -3.2
Jacobs Proposed Customer Service Allowance 76.2 14.2 17.3 17.5 17.4 17.4 17.5 87.0 10.9 14%
2020 PR4
Variance
PR4-PR3
Variance
%PR3 2013 2016 2017 2018 2019
DSO
Page 44
The DSO has proposed an allowance of €44.4m for the Area Operations activity. This proposed allowance is
based upon current projections and is in line with PR3 levels of expenditure. We have accepted this proposal
with no changes.
The DSO has proposed an allowance of €13.7m for the Customer Relations activity, which is €11.4m (487%)
higher than PR3. The rationale for the increase is to cover for increased awareness and media campaigns for
public safety, power outages, vulnerable customers etc. The DSO have not identified what the benefits to the
company are for this level of expenditure (i.e. less customer calls, third party damage, thefts etc.). We propose
that the allowance is reduced to €2.4m per annum. This is still a significant increase over the expenditure in
PR3 and includes additional costs for an increased activity level for A18 transaction charges for repeat visits,
typically due to:-
no adults being present,
no access
and continued process with agreed appointments.
The DSO are also developing social media communications within the Call centre activity and we believe there
is an opportunity for synergies between the two activities to develop joint initiatives.
3.2.6 Provision of Information
DSO requested €63.3m, Recommended reduction €-2.9m, Allowance recommended €60.4m.
Table 3.11 presents a year on year comparison between the DSOs proposed Provision of Information opex
allowance for PR4 and Jacobs proposed opex allowance for PR4.
Table 3.11 : Jacobs Proposed Provision of Information Opex Allowance for PR4
The DSO has proposed a total PR4 allowance of €7.2m for DUoS billing (an increase of €0.9m or 15% on PR3)
and €9.2m for MRSO (an increase of €2.0m or 28% on PR3). These increases have been justified by the DSO
on the basis of the interactions between themselves and the suppliers in terms of Trading and Settlement
activities and seem reasonable given the historical performance and the supporting narrative provided by the
company.
The DSO has proposed a total PR4 allowance of €47.0m (an increase of €6.2m or 15% on PR3) for Market
Opening activities. The company have identified the cost increases going forward for retail Market Design
Services in PR4 but not in sufficient detail to warrant an additional allowance over and above the current level of
expenditure. The increase over PR3 expenditure has not been clearly justified whilst there may be increased
activity in this area, we are not minded to accept that this will lead to an increase in the costs that the DSO has
identified and as we have reduced the PR4 allowed expenditure by a total of €2.9m over the PR4 period.( This
includes additional costs that will be incurred in PR4 in relation to schema releases that have not been part of
the PR3 activity.
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Duos Billing 6.3 1.1 1.4 1.4 1.4 1.4 1.5 7.2 0.9 15%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Duos Billing Allowance 6.3 1.1 1.4 1.4 1.4 1.4 1.5 7.2 0.9 15%
DSO Proposed MRSO 7.2 1.5 1.8 1.8 1.9 1.8 1.8 9.2 2.0 28%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed MRSO Allowance 7.2 1.5 1.8 1.8 1.9 1.8 1.8 9.2 2.0 28%
DSO Proposed Market Opening 40.8 7.6 9.2 9.1 9.5 9.5 9.6 47.0 6.2 15%
Jacobs Proposed Changes -0.1 0.0 -0.9 -0.9 -1.0 -2.9 -2.9
Jacobs Proposed Market Opening Allowance 40.8 7.6 9.1 9.1 8.6 8.6 8.6 44.1 3.3 8%
DSO Proposed Provision of Information 54.2 10.2 12.4 12.4 12.9 12.8 12.8 63.3 9.1 17%
Jacobs Proposed Changes -0.1 0.0 -0.9 -0.9 -1.0 -2.9 -2.9
Jacobs Proposed Provision of Information Allowance 54.2 10.2 12.3 12.4 12.0 11.9 11.8 60.4 6.2 11%
Variance
%PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR4-PR3
DSO
Page 45
It should also be noted that within this category, the DSO have made no provision for the effect of Smart
metering. Once that is initiated it will have an impact on the costs of this activity, however we expect that this will
have a more significant impact on PR5 rather than PR4 as it is unlikely a critical mass will be delivered during
PR4.
3.2.7 Telecoms
DSO requested €67.7m, Recommended reduction €-48.4m, Allowance recommended €19.3m.
Table 3.12 presents a year on year comparison between the DSOs proposed Telecoms opex allowance for PR4
and Jacobs proposed opex allowance for PR4.
Table 3.12 : Jacobs Proposed Telecoms Opex Allowance for PR4
The costs incurred by the DSO for Telecoms activities in the PR3 period are not sufficiently transparent.
Supplementary questions have been issued to the DSO and details have been provided by the, however this
has not sufficiently clarified the information to our satisfaction. On this basis it is not possible to determine how
these costs have changed from PR3 to PR4.
The DSO has indicated16 that there will be external revenue generated from this business activity, which will be
passed on to the customer. The DSO’s projection of revenue from Telecoms activities is detailed in Table 3.13
below.
Table 3.13 : DSO Forecast External Revenue from Telecoms Activities17
2016 2017 2018 2019 2020 Total
External Revenue (€m) 9.67 9.67 9.67 9.67 9.67 48.4
It is our view that this income should be netted off the operating costs and the allowance should be the net costs
of operating the service. We have therefore reduced the proposed expenditure allowance on Telecoms by the
expected level of revenue from Telecoms activities (€48.4m). In discussions with the DSO they have indicated
that they wish to class the external income as ‘Miscellaneous Telecoms Income’. Whilst we accept that for
accounting purposes this may be more convenient, we consider that for Regulatory purposes there should be
clarity on the operating costs that the customer is expected to pay in the provision of this activity for operation of
the regulated business. Any variations in the level of external income should be taken into account in assessing
the performance of this activity during PR4. In assessing PR4 efficiency at the end of the period, the level of
expenditure and income should be reviewed. Any under recovery should be borne by the business and any
over-recovery should be passed to the customer.
3.2.8 Sustainability and R&D
DSO requested €15.6m, Recommended reduction €4.5m, Allowance recommended €11.1m.
Table 3.14 presents a year on year comparison between the DSOs proposed Sustainability and R&D opex
allowance for PR4 and Jacobs proposed opex allowance for PR4.
16Telecoms PR4 comparison of charges’ 17 Telecoms PR4 comparison of charges
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Telecoms 0.0 0.0 13.2 13.5 13.6 13.7 13.8 67.7 67.7 -
Jacobs Proposed Changes -9.7 -9.7 -9.7 -9.7 -9.7 -48.4 -48.4
Jacobs Proposed Telecoms Allowance 0.0 0.0 3.5 3.8 3.9 4.0 4.1 19.3 19.3 -
2020 PR4
Variance
PR4-PR3
Variance
%PR3 2013 2016 2017 2018 2019
DSO
Page 46
Table 3.14 : Jacobs Proposed Sustainability and R&D Opex Allowance for PR4
The DSO has not proposed an allowance under the sustainability heading. We have accepted this proposal.
The DSO has proposed a total PR4 allowance of €15.6m (an increase of €7.4m – 91% - on PR3) for R&D
activities. The DSO has provided details of the areas that they wish to research, including18:
Distributed storage €400k
Demand response €400k
Distribution Large scale storage €1000k
evolvDSO €240k
MV/LV substation monitoring €2300k
MV/LV control and automation €1750k
North Atlantic Green Zone €2050k
Servo €450k
Solar Photovoltaic Trial €170k
Variable access trial €1075k
International Collaboration fees €875k
Future Technologies €4500k
The ‘Future Technologies’ research area has no supporting evidence as to the intentions or benefits of this
allowance. On this basis, the R&D allowance has been reduced by €4.5m over the PR4 period, which is
equivalent to the ‘Future Technologies ‘ line.
We suggest that the CER may wish to consider annual reporting of the R&D expenditure in order to review the
previous year and to be informed of the following periods activity and expectations. If there is need for
significantly greater investment than this allowance, we recommend that the DSO engage with the Regulator to
ensure funding is available for these activities by way of a suitably justified business case. This allowance is
provided on the basis of ‘use it or lose it’. Any underspending on this activity should not be considered an
efficiency but returned to the customers.
3.2.9 Corporate charges
DSO requested €51.4m, Recommended reduction €-3.0m, Allowance recommended €48.4m.
Table 3.15 presents a year on year comparison between the DSOs proposed Corporate Charges opex
allowance for PR4 and Jacobs proposed opex allowance for PR4. 18 DF09 Smart Netwoks RandD(final) p38
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Sustainability 8.2 1.1 0.0 0.0 0.0 0.0 0.0 0.0 -8.2
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Sustainability Allowance 8.2 1.1 0.0 0.0 0.0 0.0 0.0 0.0 -8.2
DSO Proposed R&D 0.0 0.0 2.3 2.6 3.4 3.7 3.6 15.6 15.6
Jacobs Proposed Changes 0.0 0.0 -1.5 -1.5 -1.5 -4.5 -4.5
Jacobs Proposed R&D Allowance 0.0 0.0 2.3 2.6 1.9 2.2 2.1 11.1 11.1
DSO Proposed Sustainability and R&D 8.2 1.1 2.3 2.6 3.4 3.7 3.6 15.6 7.4 91%
Jacobs Proposed Changes 0.0 0.0 -1.5 -1.5 -1.5 -4.5 -4.5
Jacobs Proposed Sustainability and R&D Allowance8.2 1.1 2.3 2.6 1.9 2.2 2.1 11.1 2.9 36%
2020 PR4
Variance
PR4-PR3
Variance
%PR3 2013 2016 2017 2018 2019
DSO
Page 47
Table 3.15 : Jacobs Proposed Corporate Opex Allowance for PR4
There are a number of charges that the DSO incurs for the likes of the CEO, Finance etc that are passed down
from Corporate Centre. The DSO have advised that the costs are split between Transmission and Distribution
activities in the ratio of 17:83 in PR3 but this is being revised in PR4 to a 23:77 split. We have based our
allowance on this split across the business based upon the cost currently being incurred in 2013-14. The
corporate charges have been allowed in line with the proposed percentage allocation. The Company wide costs
have been reduced to ensure continued focus on corporate costs. Overall the Costs allowed for Corporate and
Company costs across the TAO and DSO are broadly in line with current levels of expenditure. .
3.2.10 Insurance
DSO requested €18.7m, Recommended reduction €-1.2m, Allowance recommended €17.5m
Table 3.16 presents a year on year comparison between the DSOs proposed Insurance opex allowance for
PR4 and Jacobs proposed opex allowance.
Table 3.16 : Jacobs Proposed Insurance Opex Allowance for PR4
The DSO has proposed an increase in expenditure on Insurance from PR3 to PR4 of €0.4m. The increase has
been explained by the DSO that the insurance costs are linked to the value of their assets, this does not appear
to be the case historically in PR3 and as a result the Insurance costs have been pegged at the average for
2011-2013 inclusive rolled forward for 5 years. This approach provides a total allowance of €17.5m over the
PR4 period.
3.2.11 Legal
DSO requested €14.9m, Recommended reduction €0m, Allowance recommended €14.9m
Table 3.17 presents a year on year comparison between the DSOs proposed Legal opex allowance for PR4
and Jacobs proposed opex allowance.
Table 3.17 : Jacobs Proposed Legal Opex Allowance for PR4
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Corporate Charges & Affairs 44.7 8.2 8.4 8.4 8.4 8.4 8.4 42.1 -2.6 -6%
Jacobs Proposed Changes -0.3 -0.3 -0.3 -0.3 -0.3 -1.5 -1.5
Jacobs Proposed Corporate and Affairs 44.7 8.2 8.1 8.1 8.1 8.1 8.1 40.6 -4.1 -9%
DSO Proposed Company Wide Costs 10.9 2.2 1.9 1.9 1.9 1.9 1.9 9.3 -1.6 -15%
Jacobs Proposed Changes -0.3 -0.3 -0.3 -0.3 -0.3 -1.5 -1.5
Jacobs Proposed Company Wide Cost Allowance 10.9 2.2 1.6 1.6 1.6 1.6 1.6 7.8 -3.1 -29%
DSO Proposed Corporate Costs 55.6 10.5 10.3 10.3 10.3 10.3 10.3 51.4 -4.2 -7%
Jacobs Proposed Changes -0.6 -0.6 -0.6 -0.6 -0.6 -3.0 -3.0
Jacobs Proposed Corporate Costs Allowance 55.6 10.5 9.7 9.7 9.7 9.7 9.7 48.4 -7.2 -13%
PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR3 - PR4
Variance
%
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Insurance 18.3 3.5 3.8 3.8 3.7 3.7 3.7 18.7 0.4 2%
Jacobs Proposed Changes -0.3 -0.3 -0.2 -0.2 -0.2 -1.2 -1.2
Jacobs Proposed Insurance Allowance 18.3 3.5 3.5 3.5 3.5 3.5 3.5 17.5 -0.8 -5%
Variance
%PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR4-PR3
DSO
Page 48
The company have proposed an allowance for Legal expenditure of €14.9m over the PR4 period, with annual
expenditure of around €3.0m per annum. This represents an increase of €1.9m over and above the expenditure
in PR3. Given the expected increased Revenue Protection activities and the associated legal implications we
consider that this increase is reasonable.
3.2.12 Pensions
DSO requested €7.2m, Recommended reduction €0.0m, Allowance recommended €7.2m
Table 3.18 presents a year on year comparison between the DSOs proposed Pension allowance for PR4 and
Jacobs proposed opex allowance.
Table 3.18 : Jacobs Proposed Pension Opex Allowance for PR4
The DSO have proposed an allowance of €7.2m, representing a reduction on the outturn for PR3 of €2.8m
(28%). We have accepted this reduced cost for the administration of the pension fund when considering the
additional staff that are forecast to be recruited over the period.
3.2.13 Environmental
DSO requested €18.6m, Recommended reduction €-11.0m, Allowance recommended €7.6m
Table 3.19 presents a year on year comparison between the DSOs proposed Environmental allowance for PR4
and Jacobs proposed opex allowance.
Table 3.19 : Jacobs Proposed Environmental Opex Allowance for PR4
The DSO have proposed an allowance of €18.6m for environmental activities over the PR4 period. This
represents a €12.1m (183%) increase over expenditure in PR3. The DSO has not identified any new legislation
that is not currently in force and therefore there should be no additional compliance requirements in PR4. We
consider that the company should have no additional allowances when there is no increase in legislative
requirements and the company is complying with the current requirements. As the DSO has not provided clear
explanations of the individual cost increases requested we have proposed that the PR4 allowance be reduced
by €11.0m to match the levels of expenditure expected at the end of PR3, this is still an increase over total PR3
levels of 16%.
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Legal 12.9 2.6 3.0 3.0 3.0 3.0 2.9 14.9 1.9 15%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Legal Allowance 12.9 2.6 3.0 3.0 3.0 3.0 2.9 14.9 1.9 15%
PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR4-PR3
Variance
%
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Pension 10.0 2.0 1.3 1.4 1.4 1.5 1.5 7.2 -2.8 -28%
Jacobs Proposed Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Jacobs Proposed Pension Allowance 10.0 2.0 1.3 1.4 1.4 1.5 1.5 7.2 -2.8 -28%
PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR4-PR3
Variance
%
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Environmental 6.6 1.3 3.7 3.7 3.7 3.7 3.7 18.6 12.1 183%
Jacobs Proposed Changes -2.2 -2.2 -2.2 -2.2 -2.2 -11.0 -11.0
Jacobs Proposed Environmental Allowance 6.6 1.3 1.5 1.5 1.5 1.5 1.5 7.6 1.1 16%
PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR3 - PR4
Variance
%
DSO
Page 49
3.2.14 Health and Safety
DSO requested €38.8m, Recommended reduction €5.0m, Allowance recommended €33.8m
Table 3.20 presents a year on year comparison between the DSO’s proposed Health & Safety allowance for
PR4 and Jacobs proposed opex allowance.
Table 3.20 : Jacobs Proposed Health and Safety Opex Allowance for PR4
The DSO have proposed a PR4 allowance on Health and Safety of €38.8m which equates to an increase of
€18.9m (95%) on PR3 expenditure. It should be noted that the circumstances currently facing the DSO are not
the same as those at the start of PR3 as a result of recent severe safety incidents that have occurred within the
Company Operations. The company has carried out a full review of its Health and Safety processes and
procedures. The resultant corrective actions have resulted in the above expenditure profile. The company have
provided a number of initiatives in order to correct the deficiencies in their systems:
Technical development €5.9m
Workplace Safety €7.6m
Legal €1.5m
Engagement €1.5m
Public Safety €2.1m
Enterprise Content Management €0.8m
Shield €0.8m
Behaviours €6.1m
Assurance €10.9m
Approvals €1.5m
We are supportive of these actions and the accelerated profile of expenditure. We do believe however that the
approach to the improvement in health and safety should be able to deliver the benefits more speedily and have
shown a reduction in the increase in the later years of PR4. Since the submission of the PR3 forecast position
for Health and Safety expenditure the DSO has provided and updated expenditure profile for PR4 as shown in
table 3.20. With the acceleration of spend in PR3 brining the activities forward, we consider that there is a
reduced requirement in PR4, as a result we recommend a reduction of €5.0m giving an allowance of €33.8m
which is 70% higher than in PR3.
3.2.15 Non controllable costs
Table 3.21 presents a year on year comparison between the DSOs proposed non-controllable opex allowance
for PR4 and Jacobs proposed opex allowance for PR4.
Table 3.21 : Non-Controllable Opex Allowance for PR4
Proposed Operating Costs
(€m 2014 Prices)
DSO Proposed Health & Safety 19.9 2.5 10.9 9.8 7.0 5.9 5.2 38.8 18.9 95%
Jacobs Proposed Changes 0.0 -0.5 -1.0 -1.5 -2.0 -5.0 0.0
Jacobs Proposed Health and Safety Allowance 19.9 2.5 10.9 9.3 6.0 4.4 3.2 33.8 13.9 70%
2017 2018 2019 2020 PR4
Variance
PR4-PR3
Variance
%PR3 2013 2016
DSO
Page 50
The DSO is forecasting significant increases in the Network Rates going forward. These are largely outside of
the control of the DSO and this is recognised by the Regulator. The Network Rates and CER levy costs are
accepted on a pass through basis for the annual DUoS charges. The proposed costs seem reasonable given
the evidence provided by the DSO19.
3.3 Report Findings
The DSO has proposed a total opex allowance for PR4 of €1652.7m, including Commercial Costs but excluding
Depreciation20. The total proposed opex allowance is broken down as follows:
Proposed controllable opex of €1219.9 (an increase of €245.0m - 25% - from PR3 outturn)
Proposed non-controllable opex of €286.1m (an increase of €87.2m - 44% - from PR3 outturn)
Excluding Commercial Costs, the DSO has proposed a total opex allowance for PR4 of €1506.0m, which
represents an increase of €332.3m (28%) from PR3 forecast outturn21.
The DSO has proposed a total PR4 opex allowance (excluding commercial costs and Depreciation) of
€1506.0m. We have reviewed the submission and consider that a reduced allowance of €1362.1m would be an
appropriate allowance for PR4.
Key changes to the DSO proposed costs are;
A reduction in O&M allowance from €581.1m proposed to €537.7m a reduction of €43.4m, mainly in the
planned maintenance activity, where the DSO was seeking a 36% increase over PR3.
A reduction in Metering allowance from €180.1m proposed to €158.8mm, a reduction of €21.3m in
token/keypad meters based on a reduction in unit costs which appear high.
A reduction in Telecoms allowance from €67.7m proposed to €19.3m, a reduction of €48.4m. This
recognises the change in the Telecoms business moving in-house in PR3, but there has not been
sufficient explanation to justify such a high level of cost, and we have proposed netting off the
anticipated revenue to ensure focus is maintained on managing the net cost
Other reductions have been made in customer service €5.2m, provision of information €9.4m, Corporate costs
€3.0m, R&D €4.5m, €11m on environmental and €1.2m on insurance, and €5m on Health and Safety.
We have suggested that the DSO develop an appropriate method to understand the asset heath of its asset
portfolio, in order to understand the overall level of maintenance required and to inform future Asset
Maintenance and Replacement Programmes. We have also allowed, a significant increase in, the Health and
Safety Allowance in order to provide the DSO staff and the public with a safe operating environment.
19 DF61 Rates 20 Document ‘D05 Attachment A’, 21 The PR3 outturn is different from that reported in Section 2 of this report due to a change in price base from 2009 to 2014.
Proposed Operating Costs
(€m 2014 Prices)
Network Rates 188.7 35.0 46.9 51.0 55.0 59.1 63.1 275.1 86.4 46%
Car Levy 10.2 2.3 2.2 2.2 2.2 2.2 2.2 11.0 0.8 8%
Non Controllable 198.9 37.3 49.1 53.2 57.2 61.3 65.3 286.1 87.2 44%
Variance
%PR3 2013 2016 2017 2018 2019 2020 PR4
Variance
PR4-PR3
DSO
Page 51
4. Review of PR3 Capital Expenditure
This section reviews the DSO’s projected capital expenditure over the PR3 period 2011 to 2015 compared with
the expenditure allowed by CER in the PR3 decision paper
The purpose of our review is to assess and compare the levels and appropriateness of the DSO capital
expenditure against network operational and investment needs and to analyse, comment on and make
recommendations on efficient expenditure, and project and asset delivery in line with industry best practice. It is
not associated with confirming the accuracy with respect to monies spent and received as would be undertaken
by Independent Auditors in line with normal Company Law and also regulatory requirements as appropriate.
Our role involves a review of and advising on the processes employed by DSO in its delivery of capex i.e. where
delivery is inefficient, the reason behind this inefficiency and changes which could be made to management and
delivery processes to improve efficiency.
A further important element of the review of PR3 actual/forecast outturns is a comparison agaichemenst the
original forecast and allowed expenditures and the determination of the reasons behind any significant
deviations as this will inform views with respect to the ability of the businesses to forecast expenditure
requirements and also to manage the delivery of such expenditure and associated operational efficiencies.
From the DSO, we have been provided with, through the questionnaire, a line by line and year by year Capex
expenditure submission in the same format as the final allowances from the previous price control. We note
2011-14 to be actual costs and 2015 to be latest best estimates (LBE). We have reviewed data and the
narrative responses provided by the DSO and requested additional clarifications from the DSO to assist in our
review and to further explain specific variances.
We would normally expect Capex variances to fall mainly into the categorisation of:
Volume
Asset Replacement (deferment or acceleration of programme/asset replacement)
Load Related (deferment or acceleration due to demand variance, project churn)
Unit Costs (delivery efficiency, procurement initiatives, commodity price impacts)
We would normally expect capitalised faults to be an aspect of the historic capex and policy changes relating to
capitalisation and the impacts of major incidents may impact on the outturn. Again we have reviewed these
issues and comment whether they are likely to affect the 2016-2020 forecast period.
We consider whether the 2015 LBE forecast expenditure is realistic based on the actual Capex and we have
sought further explanation from the DSO to justify this forecast both in terms of comparison with previous
delivery rates and the staffing forecasts. We have also sought to make sure that the LBEs include the delivery
of commissioned assets and not advance procurement of major assets that will form part of the 2016-2020
programmes. We will use this information to determine if any variance on the 2011-2015 controls impact on the
forecast Capex for the 2016-2020 price control.
As part of this historic Capex review we expected to see an explanation of the DSO investment appraisal and
approval process and selected example documentation that was used to justify any significant projects that
were not included in the current submission.
4.1 General
This section reviews the DSO’s projected capital expenditure over the PR3 period (2011 to 2015) compared
with the expenditure allowed by CER in the PR3 decision paper22.
22 CER/10/198 - Decision on 2011 to 2015 distribution revenue for ESB Networks Ltd
DSO
Page 52
During the PR3 period, there are a number of significant factors that need to be considered when assessing
DSO outturn capex v CER allowed costs. In consultation with the CER, ESBN Networks reduced the PR3
Capex delivery programme for distribution and transmission in two stages from the original CER allowed value
of €4,200m23 (see column “CER Allowed Capex for ESBN” in Table 4.1). The first stage resulted in a
reduction to €2,956m (See Table 4.1 column “Adjusted PR3”). This reduction was driven by the following
items:
• Capex associated with both demand and generator connections was significantly below expected levels
• Capex associated with Smart Metering (€500m) was not expected to be incurred until the PR4 period;
• Expenditure relating to the new ESBN HQ in Carrickmines was to be deferred.
The second stage of reduction was driven by the prioritisation and deferral of capex relating to load
reinforcement, asset replacement and non-network investment categories. This was considered necessary to
manage the freeze in the corporate debt markets as part of the global financial crisis and also to reduce the
impact of DUoS prices on ESBN customers and reduced the expenditure further from €2,956m to €2,400m, as
detailed in column “ESBN Proposal24
”.
Focussing only on distribution expenditure, and excluding the capital expenditure relating to Smart Metering, the
programme was reduced from €2101m to €1,708m and then to €1,179m.
Table 4.1 : DSO: Re-alignment of Distribution Capital Programme (€m – Gross 2009 prices)
Capex Investment Category CER Allowed Capex
for ESBN Adjusted PR3 ESBN Proposal
New Business – Demand Connections to DSO network 452.7 252 252
New Business - Generation Connections to DSO network 162.5 70 69
Line Diversions – relocation of DSO network assets necessary
to allow new development 51.8 52 52
Smart Metering – installation of latest technology “smart”
meters for domestic customers 500.0 51 50
Transmission Network Related Expenditure (not DSO)
1,599.2 *
1,197 1,171
Carrickmines Building Relating Expenditure for new ESBN
Head Office - -
Load Related Reinforcement expenditure of DSO distribution
network 632.6 533 277
Asset Replacement 622.1 622 433
Non Network 179.1 179 96
Total - ESBN 4,200 2,956 2,400
Total – ESBN – DSO Only (Excluding Transmission Capex
and Smart Metering Capex) 2100.8 1,708 1,179
* Number assumed based on gross total for ESBN of €4.2b
Note 1- Source – ESBN – PR4 Submission: Document Reference DH01 PR3 Distribution Overview
Note 2 – “Asset Replacement” Costs include costs associated with the retirement of assets
This compares with CER PR3 DSO allowed gross capex of €2,101m and latest DSO forecast (gross) of
€1,199m (as presented in Figure 4.1 and itemised in Table 4.2).
23 ESBN Transmission and Distribution Total Capital Expenditure 24
ESBN Proposal was submitted to CER in December 2012 – and these revised capex values are considered as the agreed rebased values against which we also provide an assessment of outturn v rebased forecast
DSO
Page 53
In headline terms, during PR3 the DSO has invested gross €1,284.3m on network and non-network
assets, which is €816.5m (39%) lower than the CER allowed capital expenditure of €2,101m (excluding
Smart Metering and Electric Vehicles). It is €105.3m higher (8.9%) than the DSO Revised Capex
Proposal of December 2012.
Due to the unique circumstances that were faced by the DSO in the period and resulting in its revised capex plans in 2012, it is considered appropriate to use the rebased 2012 capex forecast for comparison throughout this report wherever possible, although, for completeness, reference is also made to CER allowed values.
However, the DSO has been asked for more detailed breakdown of costs associated with the 2012 revised capex plan broken down into an annual expenditure profile for each of the work programmes for which CER had made allowances for the PR3 period - it is our understanding that this information is not available.
We received the following statement from the DSO…“It is important to appreciate that whilst a lower level of CAPEX was agreed with CER at this time, there was no single point of decision where detailed work programmes commensurate with the revised budget amount was decided on - Instead the process was that annual work programmes were decided on for 2012 and 2013 and as the borrowing positon eased, 2 year work programmes were agreed for 2014 – 15. As is evident from the description, these decisions are informed by an understanding of the benefit to cost analysis that ESBN had done in advance of PR3 and indeed for earlier price controls”.
Consequently we have not been able to carry out a comparable analysis of DSO forecast v rebased
2012 capex at a work programme level and such analysis has therefore been carried out relative to
CER allowed capex for each defined category of capex.
Whilst a PR3 allowance of €500m for expenditure associated with smart metering was provided by CER, the
DSO has only incurred €14.6m of costs. It should be noted that the allowed capex for smart metering was
removed on an annual basis throughout PR3 such that the DSO customers were not charged for these costs.
Figure 4.1 : DSO PR3 Capex Summary (excluding costs associated with smart metering) – Gross Costs (€m 2009 prices)
2,101
1,1791,284
0
500
1000
1500
2000
2500
5 Year Total
€m
CER Allowed Capex ESBN Proposal (2012) DSO Actual / Forecast
DSO
Page 54
Table 4.2 : DSO PR3 Capex Summary by Investment Category (£m – 2009 prices) 25
Capex Investment Category
CER Allowed
Capex
(GROSS)
Revised
DSO
Proposal
(2012)
DSO
Forecast
(GROSS) -
2014
Variance – DSO Forecast
to CER Allowed Capex
Variance – DSO Forecast
(2014) to DSO Revised
Proposal (2012)
€m % €m %
New Business 452.7 252.0 235.5 -217.2 -48.0% -16.5 -6.6%
Generation Connections 162.5 70.0 86.7 -75.8 -46.6% 17.7 25.7%
Line Diversions 51.8 52.0 47.1 -4.7 -9.0% -4.9 -9.4%
Distribution Reinforcement 632.6 277.0 316.9 -315.7 -49.9% 39.9 14.4%
Asset Replacement 622.1 433.0 462.4 -159.7 -25.7% 29.4 6.8%
Non Network 179.1 96.0 135.6 -43.5 -24.3% 39.6 41.2%
Total – DSO Excluding Smart
Metering 2,100.8 1,179.0 1284.3 -816.5 -38.9% 105.3 8.9%
Note – “Asset Replacement” Costs include costs associated with the retirement of assets (costs for period from 2011-2013 obtained from
Opex Table 5.1 and costs for period 2014/15 are from Capex Table 6.3)
The DSO actual net capex26 for the period 2011 to 2013, together with its forecast for the 2014 and 2015 period
is presented in Table 4.3 and is illustrated in graphical format in Figure 4.2 below, compared to CER allowances
for PR3 period. Annual comparison of DSO actual/forecast for PR3 with its rebased 2012 plan is not possible as
the annual capex totals are not available.
Table 4.3 : PR3 Net Capital Expenditure – DSO Actual/Forecast v PR3 Allowances (€m - 2009 Prices)27
2011
(Actual)
2012
(Actual)
2013
(Actual)
2014
(Forecast)
2015
(Forecast)
5 Year Total
(2011 – 2015)
CER Allowed Net Capex (€m) 344.6 343.1 340.8 342.4 341.3 1712.2
Actual Capex (Net) - €m 283.8 177.3 166.1 201.6 246.5 1075.3
Variance to CER Allowances €m -60.8 -165.8 -174.7 -140.8 -94.8 -636.9
% Variance -18% -48% -51% -41% -28% -37%
25 DSO Forecast for PR3 is based on data provided by the DSO within its Business Plan Questionnaire Table 6.3 (revised – dated March 2015). 26 Net of customer contributions and Interest during Construction (IDC) Charges 27 Excludes costs associated with Smart Metering
DSO
Page 55
Figure 4.2 : PR3 Net Capital Expenditure – DSO Actual/Forecast v PR3 Allowances (€m – 2009 prices)
In headline terms, during PR3 the DSO is forecasting to invest net €1,075.3m on network and non-network
assets, which is €91.3m (9.3%) higher than its 2012 revised capex total of €984m 28(excluding Smart Metering
and R&D costs associated with studying impact of Electric Vehicles).
Its latest forecast is €637m (37%) lower than the CER allowed capital expenditure of €1,712m.
Each of the capex categories presented in Table 4.2 are considered in further detail within the sections below.
Capex relating to New Business, Generation Connections, Line Diversions and Distribution Reinforcement are
discussed in Section 4.2 whilst capex relating to Asset Replacement is discussed in Section 4.3. Non network
related capex is discussed in Section 4.4.
4.2 Network Related Expenditure
4.2.1 New Demand Connections
The DSO capex between 2011 and 2015 relating to new (demand) connections is summarised in Table 4.4
below. Expenditure is presented both in gross terms and also net of customer contributions.
Table 4.4 : New Connections Capex (Demand Connections) - Comparison of PR3 Costs v CER Allowances (€m – 2009 prices)
Capex Category 2011
(Actual)
2012
(Actual)
2013
(Actual)
2014
(Actual)
2015
(Forecast) 5 Year Total
Gross
CER Allowed Capex 85.4 88.1 90.6 93.1 95.5 452.7
DSO Actual Capex 52.5 46.4 41.0 48.45 47.24 235.5
DSO Revised Capex (2012) 252.0
Variance (DSO Actual to CER Allowed
Capex) -32.9 -41.7 -49.6 -44.7 -48.3 -217.2
% Difference -38.6% -47.4% -54.8% -48.0% -50.5% -48.0%
Variance (DSO Actual to DSO Revised
Capex – 2012) -16.5
28
Calculated based on assuming 50% contribution target for demand connections and 100% for generator connections
0
50
100
150
200
250
300
350
400
2011 2012 2013 2014 2015
€m
CER Allowed Net Capex (€m) Actual Capex (Net) - €m
DSO
Page 56
Capex Category 2011
(Actual)
2012
(Actual)
2013
(Actual)
2014
(Actual)
2015
(Forecast) 5 Year Total
% Difference -6.6%
Net
CER Allowed Capex 42.7 44.1 45.3 46.6 47.8 226.4
DSO Actual Capex 28.4 24.5 17.6 24.3 28.5 123.2
DSO Revised Capex (2012) 126.0
Variance (DSO Actual to CER Allowed
Capex) -14.3 -19.6 -27.7 -22.3 -19.3 -103.1
% Difference -33.6% -44.5% -61.1% -47.8% -40.4% -45.6%
Variance (DSO Actual to DSO Revised
Capex – 2012) -2.8
% Difference 2.2%
Contributions
CER Allowed Contributions -42.7 -44.1 -45.3 -46.6 -47.8 -226.4
DSO Contributions – Demand Connections -24.1 -21.9 -23.3 -24.2 -18.8 -112.3
Note 1- CER Contributions – these values are based on a contribution ratio of 50% as per CER Decision Paper CER/1/198
Note 2 – DSO Contributions (Actual) – values have been calculated based on total contributions (DSO Questionnaire Table 6.3) less
contributions relating to generator connections (Table 6.4)
The total DSO Actual Capex (Gross) over the PR3 period is forecast to outturn at €235.5m, this is €217.2m
(48%) less than the CER Allowed capex. It is also €16.5m (6.6%) less than the DSO Revised Capex Proposal of
2012 (€252.0m).
The total DSO Actual Capex (Net) over the PR3 period is forecast to outturn at €123.2m, this is €103.1m
(45.6%) less than the CER Allowed capex, although it is only €2.8m (2.2%) less than the DSO Revised Capex
Proposal of 2012 (€126.0m).
Customer contributions are based on standard costs for each type of connection and metering, the customer
being charged 50% of the standard costs. Customer contributions of €112.3m for a gross expenditure on
demand connections of €235.5m (gross) resulted in a contribution ratio of 48% compared with the agreed rate
of 50%.
The main driver for this significantly lower capex, compared to the CER allowances, is the reduced
number of customer connections that have been requested to be provided by the DSO over the PR3
period. For the first three years of PR3 the total actual number of connections provided is 41,749. This
is some 53.1% lower than the PR3 forecast connection volumes for the same 3-year period (89,039).
The DSO may need to revise the Basis for Customer Connection Charges for future recovery of the
agreed rate of 50% of total connection charges, although we would expect any revision to be
presented to the CER for review and approval.
The lower volume of connection volumes during PR3 is detailed more fully in Table 4.5 below.
Table 4.5 : PR3 Connection Volumes (Actual) v Forecast
Capex Category
PR3 Forecast
Connection Volumes
PR3 Actual Connection
Volumes
Variance –
Actual 2011 -
2013
Variance –
Actual 2011 -
2015
2011-
2013
Actual
2014-
2015
Forecast
5
Year
Total
2011-
2013
Actual
2014-
2015
Forecast
5
Year
Total
No’s % No’s %
DSO
Page 57
Capex Category
PR3 Forecast
Connection Volumes
PR3 Actual Connection
Volumes
Variance –
Actual 2011 -
2013
Variance –
Actual 2011 -
2015
2011-
2013
Actual
2014-
2015
Forecast
5
Year
Total
2011-
2013
Actual
2014-
2015
Forecast
5
Year
Total
No’s % No’s %
G1 Scheme Housing 34,081 28,622 62,703 10,735 11,028 21,763 -23,346 -68.5% -40,940 -65.3%
G2 Non Scheme
Housing 31,055 21,916 52,971 16,379 9,754 26,133 -14,676 -47.3% -26,838 -50.7%
G3 Non Domestic 23,903 17,060 40,963 14,635 7,886 22,521 -9,268 -38.8% -18,442 -45.0%
Total 89,039 67,598 156,637 41,749 28,668 70,417 -47,290 -53.1% -86,220 -55.0%
Note 1 – PR3 Forecast connection volumes from SKM Report “SKM DSO Capex costs 2006 to 2015”
Note 2 – Actual Numbers for 2011 to 2013 from DSO PR4 Submission Document Reference DH05
The following observations can be made from the above table:
For the first three years of PR3 the total actual number of connections provided is 41,749. This is some
53.1% lower than the PR3 forecast connection volumes for the same 3-year period (89,039).
Based on the DSO latest forecast for 2014 and 2015, it is anticipated by the DSO that the 5-year total will
outturn at 70,417. This is more than 86,000 (i.e. 55%) lower than the PR3 forecast connection volumes for
the full 5-year period.
The most significant variance in connection volumes relates to G1 Scheme Housing connections (actual
variance of 68.5% lower than PR3 predicted levels for the 2011-2013 period)..
The number of connection volumes for both Non-Scheme Housing (G2) and Non-Domestic Connections
(G3) are also significantly lower than the PR3 forecast connection volumes (actual variance of 50.7% and
45% lower than PR3 predicted level respectively over the 5 year period).
The DSO forecast for 2014 and 2015 is based on a continuation of the lower rate of connection volumes
experienced during the first three years of PR3, with some recovery evident in the forecast for G1 housing
schemes.
The original forecast for PR3 was based on the expectation that there would be a gradual recovery from the
economic recession, manifested by a slight increase in construction activities year by year as shown by the red
line in Figure 4.3.This has clearly not been the case and the downward trend in connection volumes
experienced in the period 2007 to 2010 (blue line in Figure 4.3) has continued, with an expectation that there
will be a minor increase in annual volumes by 2015 (green line in Figure 4.3).
DSO
Page 58
Figure 4.3 : New Connections made to DSO Network over period 2006 to 2015
4.2.1.1 New Demand Connections Unit Costs
Another potential driver on the lower forecast outturn capex during PR3 period relates to the unit costs 29for
each of the different connections. The unit costs allowed by CER for PR3 together with the DSO actual unit
costs for each type of connection are detailed in Table 4.6 and Figure 4.4.
Table 4.6 : Connections: Comparison of DSO Actual Unit Costs v CER Allowances (€ - 2009 prices)
Note 1– CER Allowed Unit Costs from SKM Report "SKM DSO Capex Costs 2006 to 2015"
Note 2 – DSO Actual Unit Costs from ESBN PR4 Submission document Reference DH05 – New Connections
29 We agree with the DSO that the unit costs presented in the table (and in DSO narrative document DH05) are derived from the total expenditure
incurred in each category for any given year divided by the volume of connections completed in the year 30 In its response (DSO Report DR01) to our PR3 Capex IR, the DSO provided updated 2014 actual costs but not updated 2014 volumes.
Consequently 2014 actual unit costs are based on DSO submission of 5th December 2014. 31 DSO response DR01 provided revised 2015 forecast costs and forecast volumes for each of the G1/G2/G3 connections. Based on data provided,
the unit costs were €856 (G1) €3,214 (G2) and €4,951 (G3).
0
20,000
40,000
60,000
80,000
100,000
120,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Nu
mb
er
of
Co
nn
ec
tio
ns
Actual (to 2010) PR3 Forecast (2009) PR3 Actual Connections
Category of
Connection
CER Allowed Unit Costs DSO Actual Unit Costs
2011 2012 2013 2014 2015 2011 2012 2013 201430 201531
G1 Scheme Housing 1,185 1,174 1,162 1,150 1,139 700 646 618 1,150 856
G2 Non Scheme
Housing 3,093 3,062 3,031 3,001 2,971 3,195 3,343 3,155 3,002 3,214
G3 Non Domestic 5,165 5,113 5,062 5,012 4,961 5,392 5,461 3,851 5,013 4,951
DSO
Page 59
Figure 4.4 : Connections: Comparison of DSO Actual Unit Costs v CER Allowances (€ - 2009 prices)
The unit costs for G1 New Scheme Housing have reduced during PR3 such that by 2013 the outturn unit cost of
€618 was 47% lower than the unit cost allowed by CER. The DSO has explained this variance is due to sunk
costs in scheme housing projects being experienced in the early time periods of developments, together with
the completion or partial completion of Ghost Estates. The DSO has explained that many housing
developments were placed on hold during PR2 with the main connection infrastructure (MV substations, MV
and LV circuits) having been established during the PR2 period. Consequently small numbers of incremental
connections have been provided during PR3 period without necessarily having to establish additional
infrastructure.
We have validated this explanation from the DSO by analysing the average quantity of assets installed
per customer over the 5-year PR2 period against the average quantities installed per customer during
the first three years of PR3. For the main asset categories (MV substations, MV and LV circuits) we have
observed a noticeable reduction in the average number of assets installed per customer during PR3 (to
end of 2013). For LV cables, the average length installed per customer is 41% lower in the first three
years of PR3 compared to the average length per customer in PR2. For MV cables, the average length is
88% lower.
The average number of MV/LV 3-phase pole-mounted transformers and ground mounted transformers
per customer are also noticeably lower, 20% and 10% lower respectively, than the PR2 average values.
Our review of the DSO forecast PR4 capex for the different categories of demand connections assesses
appropriate unit costs, taking account of outturn costs during PR2 and PR3, together with any other relevant
factors.
DSO actual unit costs for G2 Non-Scheme houses are broadly in line with the allowed PR3 unit costs, albeit
marginally higher. The DSO cites a number of contributory factors, resulting in upwards pressure on unit costs,
including:
reduced opportunity to achieve economies of scale because of lower connection volumes,
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2011 2012 2013 2014 2015
G1 Scheme Housing G2 Non Scheme Housing G3 Non Domestic
Note: Solid line = Actual/forecast; Dashed line = CER allowed
DSO
Page 60
increased use of live-line techniques in providing connections;
an increase in the number of special connections associated with farm automation requiring capacity
increases from 20 kVA to 29 KVA. (These are driven by legislation requiring on site storage chilling of milk)
and geothermal heating connections. The average number of these special connections over PR3 period is
over 230 – this is 46% higher than 2010 volumes.
DSO actual unit costs for G3 Commercial / Industrial Connections are noticeably lower in 2013 compared to the
allowances set by CER, with an outturn unit cost of €3,851 being 24% lower. The DSO cites the recent
Telecommunications roll-out of the “E-Fibre” to the cabinet with significant volumes in 2012 and more so in 2013
impacting on unit costs. These cabinets are being installed primarily in urban locations with civil works being
completed by the customer. These connections are unmetered and are currently undergoing an intensive
“peak” of installations in urban areas. The unit costs for these types of connection are much lower than the
average G3 connection. Table 4.7 shows the annual number of these connections provided during PR3. It is
clear that the significant number of connections provided to the E-Fibre cabinets in 2013 (42% of the total
number of G3 connections) has contributed to the significant reduction in the unit cost for G3 connections.
Table 4.7 : Analysis of the number of E-Fibre connections
2011 2012 2013
Number of E-Fibre Cabinet Connections 0 825 2,325
Number of G3 Connections 4,714 4,378 5,543
Number of E-Fibre Connections as percentage of G3 total 0 18.8% 41.9%
4.2.1.2 Analysis of PR3 Meter Costs
CER allowances for PR3 period were based on a unit cost of €85 for whole current metering. This cost was
based on an assumption of 33% of connections being non-metered and 6% of non-domestic connections being
three phase supplies. A PR3 allowance of €12.2m was subsequently approved by the CER. The DSO actual
metering costs for PR3 compared to this allowance are presented in Table 4.8 below.
Table 4.8 : Meters: Comparison of DSO Actual Costs v CER Allowances (€m - 2009 prices)
2011 2012 2013 2014 2015 5 Year Total
CER Allowed Capex 2.2 2.3 2.4 2.6 2.7 12.2
DSO Actual / Forecast 3.5 3.1 2.5 2.5 2.7 14.4
Variance 1.3 0.8 0.1 -0.1 -0.0 2.2
% Difference 61.1% 36.0% 4.4% -4.8% -12.0% 17.9%
Note the 2012 Revised Capex for DSO did not provide detailed assessment of revised meter costs
It is observed that the DSO total meter costs for PR3 period are 17.9% higher than the CER allowed costs. This
is despite a forecast reduction in connection volumes of 55% over the PR3 period.
The average meter unit cost (over the 2011 to 2013 period) has a 3-year actual average unit cost of €165 per
meter32. This is significantly higher than the unit cost of €85 used in determining PR3 allowances and the DSO
original unit cost of €150 that the DSO proposed in its forecast CAPEX for PR3. The DSO has provided a
detailed explanation to explain this apparent adverse variance.
Specifically the closing of cost accounts relating to dormant connection projects, to prevent misallocation of
costs, has resulted in final connection cost and the metering cost both being allocated to the metering cost
code. This has obviously resulted in the identified increase in metering costs. The DSO explanation has been
32 Excluding meter volumes and costs associated with the replacement of faulty meters- as this is provisioned within the DSO Response capex
category.
DSO
Page 61
supported by analysis33 of the time and material cost movement for G1 metering cost components over the
period 2006 to 2013, showing a significant increase in both over this period (relative to 2006) whilst there has
been a corresponding reduction in the time and material costs (relative to 2006) for the G1 connection cost
component.
Similar analysis carried out by the DSO for G2 and G3 connections also shows an increase in material costs
due to the allocation of service cable connection costs to the metering cost allocation code.
The analysis provided by the DSO supports the higher metering capex costs incurred during PR3. It is
important that the assessment of PR4 allowed revenues for connections and metering takes due
account of the fact that a proportion of G1-G3 connections costs have been allocated to metering
capex during PR3.
4.2.2 Generator Connections
The DSO capex related generator connections is summarised in Table 4.9 below. Expenditure is presented
both in gross terms and also net of customer contributions.
Table 4.9 : New Connections Capex (Generator Connections) - Comparison of PR3 Costs v CER Allowances (€m – 2009 prices)
2011 2012 2013 2014 2015 5 Year Total
Gross
CER Allowed Capex 7.2 40.2 31.8 16.5 66.8 162.5
DSO Actual Capex 17.5 10.4 16.9 8.0 34.0 86.7
DSO Revised Capex (2012) 69.0
Variance (DSO Actual to CER Allowed
Capex) 10.3 -29.8 -14.9 -8.5 -32.8 -75.8
% Difference 143% -74% -47% -52% -49% -47%
Variance (DSO Actual to DSO Revised
Capex – 2012) 17.7
% Difference 25.7%
Net
CER Allowed Capex - Net -0.1 0.0 0.0 0.0 0.0 0.0
DSO Capex - Net -2.8 2.6 -9.6 -9.0 8.8 -10.0
Contributions
CER Allowance Contributions 7.3 40.2 31.8 16.5 66.8 162.5
DSO Actual Contributions 20.3 7.8 26.5 17.0 25.2 96.7
A comparison of gross expenditure is shown in Figure 4.5 below.
33 Supporting analysis provided in Document Reference DR01 DSO Capex Final.pdf
DSO
Page 62
Figure 4.5 : Generator Connections – Comparison of PR3 Costs v CER Allowances
The DSO is forecasting to incur gross generation connections costs of €86.7m during PR3, representing an
underspend of €75.8m compared with the CER allowed gross capex of €162.5m. This DSO forecast is €17.7m
(25.7%) higher than the DSO Revised Capex Proposal of 2012
The lower level of generation connections is due to the timing of new generation projects which are linked to the
Gate2 - Gate 3 grouped process for coordinating generation connections. The DSO has explained that most of
the Gate 3 projects have accepted their connection offers in the summer of 2013, although their original offers
had been provided in the 2009-2011 period. The CER approved a suspension of the expiry dates on the issued
Gate 3 connection offers until issues regarding constraints and curtailment of wind were fully resolved. This
resolution came in the form of a SEM decision in March 2013, and all applicants were provided with constraint
and curtailment levels applicable to their projects.
The DSO expects to make significant progression during 2014 and 2015 in the design and scoping of Gate 3
wind connections and the commencement of substantial construction activity. This is reflected in the profile of
customer contributions for generation connections. These are forecast to be €96.7m, equivalent to a
contribution ratio (or recovery rate) of 112% compared with the allowed recovery rate of 100%. This over-
recovery is partly due to the timing of contributions expected for 2015 with the resulting impact of higher levels
of related expenditure to be incurred during PR4. The DSO has cited a further large tranche of Gate 3 wind
projects, totalling approximately 2,000 MW that have been offered and accepted their connection offers. The
0
10
20
30
40
50
60
70
80
2011 2012 2013 2014 2015
€m
CER Allowed Capex - Gross DSO Actual Capex - Gross
162.5
6987
0
20
40
60
80
100
120
140
160
180
5 Year Total
€m
CER Allowed Capex - Gross ESBN Proposal (2012) DSO Actual Capex - Gross
DSO
Page 63
over recovery forecast in PR3 relates to the generator connections that are expected to move through the
design stage and into construction stage in final years of PR3 and early years of PR4 resulting in higher cash
outflows during PR4.
This over-recovery of connection costs in PR3 will undoubtedly result in DSO net cash outflows during
the early years of PR4 period and this will need further consideration when reviewing the proposed
DSO forecast capex for PR4.
4.2.3 Load Related Reinforcement
The DSO load-related capex for the PR3 period is shown in Table 4.10 below.
Table 4.10 : Comparison of PR3 Costs v CER Allowances – Load Related Reinforcement (€m 2009 prices)
Category 2011 2012 2013 2014 2015 5 Year Total
CER Allowed Capex 130.8 127.7 125.8 124.8 123.5 632.6
DSO Actual / Forecast 92.8 55.0 57.1 49.7 62.3 316.9
Variance -38.0 -72.7 -68.7 -75.1 -61.2 -315.7
% Difference -29.0% -56.9% -54.6% -60.2% -49.5% -49.9%
The DSO forecast a total capex of €316.9m by end of PR3 – this is €315.7m lower than the CER allowed load-
related reinforcement capex of €632.6m – representing a variance of 50%. This DSO forecast is approximately
€39.9m higher than the revised proposal of ESBN (€277m) submitted to CER in 2012 – see Figure 4.6 below.
Figure 4.6 : Comparison of DSO PR3 Costs – Load Related Reinforcement
Table 4.11 below provides an itemised breakdown of the DSO load related capex over PR3 period, compared to
the CER allowed capex for each of the categories.
It should be noted that the ESBN Proposed revisions to the capex were provided at an aggregated level
(totalling €277m) and were not broken down into the individual categories shown below.
633
277 317
0
100
200
300
400
500
600
700
5 Year Total
€m
CER Allowed Capex ESBN Proposal (2012) DSO Actual / Forecast
DSO
Page 64
Table 4.11 : Load Related Reinforcement – Comparison of Capex by Category (€m – 2009 prices)
Category CER Allowed
Capex
DSO Actual /
Forecast Variance €m Variance %
Transmission Connection Costs 25.7 0.0 -25.7 -100%
110kV 230.5 140.9 -89.6 -39%
38kV 210.1 84.4 -125.7 -60%
MVLV System Improvements 69.1 33.6 -35.5 -51%
IFTs associated with 20kV Conversion 16.2 22.4 6.2 38%
20kV Conversion 81.0 35.6 -45.4 -56%
Total 632.6 316.9 -315.7 -50%
The main drivers on load-related reinforcement expenditure are the growth in peak demand and energy
delivered (GWh). The graph below (Figure 4.7) shows the actual total GWh units distributed by the DSO
(including 110kV) since 2005, together with its forecast for the remainder of the PR3 period. The original PR3
forecast (derived in 2009) is also plotted. It is noticeable that from a total of circa 24,000 GWh in 2008, the DSO
has experienced a reduction to 23,000 GWh units in 2010, followed by a further reduction in actual GWh units to
circa 22,100 by 2013. This represents a total reduction in units distributed of approximately 6.4% over the
course of five years. A modest increase in units distributed is forecast by 2015. The actual annual units
distributed between 2011 and 2015 are significantly different to the expected annual units required for
distribution at the time of PR3.
Figure 4.7 : Total Units Distributed (GWh) from 2005 to 2015)
Similarly, the system peak demand has not increased in line with the DSO forecast for PR3. This is illustrated in
Figure 4.8 below. The left-side figure shows the system demand (historic together with the forecast for PR3
period) whilst the right-side figure shows the system demand (actual to 2013). The peak in 2007/08 was 4,914
MW and the peak in 2013/14 has reduced to 4,523 MW.
Given the reduction in peak demand during the PR3 period, together with the borrowing constraints faced by
ESBN and the pressure to reduce potential increases on DUoS charges, the DSO considered it appropriate to
critically review the network requirements and the related project portfolio, allowing for deferment of
reinforcement projects where the resultant risks were considered acceptable to do so.
19000
20000
21000
22000
23000
24000
25000
26000
27000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Un
its
Dis
trib
ute
d (
GW
h)
Actual (to 2010) PR3 Forecast (2009) PR3 Actual Units
DSO
Page 65
Figure 4.8 : System Demand – PR3 Forecast v PR3 Actual
Most global distribution companies use either a deterministic or probabilistic approach to assess network
security when planning the network. A deterministic approach is based on the absolute requirement that for a
given event (e.g. a network outage) the network supplying the group demand has to be secure (i.e. meet the
security standards). Using this absolute approach, there is no consideration of the risk/probability of such an
event, whereas a probabilistic approach to network planning will make an assessment of the likelihood/impact of
events occurring as a driver for network reinforcement.
GB DNOs all use a deterministic approach to network planning although we understand that they are
considering a future update to the Network Planning Standard and this may address probabilistic techniques in
addition to the deterministic criteria set out in the current standard. The DSO continues to use a deterministic
approach to network planning, with the security standards detailed in Table 4.12 below being used as a driver
for reinforcement.
We consider that the current methodology continues to be appropriate for the DSO – it is in line with
international practice and provides a good baseline against which investment needs can be assessed.
Table 4.12 : DSO Security of Supply Standards
Due to the reduction in units distributed and reduction in peak demand from 2011 onwards, the original PR3
Distribution Reinforcement programme was scaled back by the DSO in 2012 from €633m to €277m, although
the DSO latest forecast for PR3 period is €316.9m.
34
GD is restored when either fault is repaired or the plant being maintained is switched back in.
Group Demand (GD) Standby Provision Restore at least within
60 secs 15 mins 3 hours Repair Time
0 – 1 MVA None GD
>1 – 10 MVA N-1 GD – 1 MVA GD
>10 – 30 MVA N-1 GD – 10 MVA GD
>30 – 100 MVA N-1 GD – 30 MVA GD
>100 MVA
N-1 GD
N-1-1 2/3 GD GD restored as soon as possible34
DSO
Page 66
HV load related expenditure has been limited by the DSO during PR3 to the following categories of expenditure:
Projects carried over from PR2;
New projects required to address significant overload and / or major breeches in security standards;
New HV and MV connections to major industrial and commercial customers; and
Ongoing programme to replace obsolete Siemens 38kV substations.
The PR3 programme for network reinforcement was based on the Dublin and Country network plans, which set
out a programme of work to maintain system loading and security within network capacity and planning
standards.
ESBN's Network security standards are similar to international practice with n-1 security provided at primary
transformer stations taking into account transfer capacity. The DSO typically uses ONAN35
ONAF transformers;
typically rated at 15 MVA when naturally cooled (ONAN) and 20 MVA when cooling is supplemented by fans
(ONAF36
). Such units are operated at a short time overload rating of 180% of installed capacity for up to 30
minutes in which time the demand is reduced to within ONAF rating by demand transfer where available. This
compares with current GB practice where transformers are equipped with oil pumps as well as fans (OFAF37
)
and operate with a higher normal demand but have a lower short time overload rating of 130%. Overall there is
little difference between security standards in GB and Ireland. However the sparse network in parts of Ireland
means that for many rural substations there is limited post fault transfer capacity available to adjacent
substations.
Review of 110kV and 38kV (Major Projects)
As part of its response to the Business Plan Questionnaire, the DSO was requested to provide a breakdown of
planned v actual cost details of the major projects (38kV and above) that have been progressed during PR3.
This would have allowed us to carry out a more detailed analysis of a sample number of projects completed
during PR3. The purpose of carrying out a detailed analysis of a representative sample of individual projects is
to assess the reasonableness of costs incurred compared to planned/allowed costs, the reasonableness of the
DSO project delivery process and hence to determine the efficiency of the DSO project delivery and resulting
capex.
However, in its original submission submitted on 31st October 2014, this cost information relating to individual
major projects was not provided. In its revised submission of 5th December 2014 this cost information relating to
individual major projects was not provided.
On 18th December 2014, we received a list of individual 38kV and 110kV major projects. The list provided the
total capex incurred on 81 reinforcement projects over the period of 2011 to 2013. It did not provide any
information relating to the forecast capex during PR3 (and beyond) to complete each of these individual
projects. It did not provide any information of actual costs incurred on these projects during PR2 nor did it
provide any information on the total planned/approved capex for each of the projects. This lack of information
restricted our ability to carry out any detailed analysis.
On 16th February 2015, we received further detailed cost information in relation to a sample of 11 major 38kV
and 110kV reinforcement projects that are expected to be completed in PR3 period (hence no forecast costs
beyond 2015) and we have analysed the information provided. Both the delays in providing the required
information and the fact that information was only provided for a small sample of projects rather than all major
projects is disappointing. We would have expected the project information requested to be generally available
within the DSO and find the prolonged delay in providing this information to be a concern. This is standard
information that we would expect the project managers to be using on a routine basis to manage and control
project delivery and associated costs. Given the time the DSO has had to provide such information, we consider
that their inability to provide such information to the CER in a timely manner to be an area of weakness that
requires improvement during PR4.
35
ONAN – Oil Natural-Air Natural cooling system for transformer 36 ONAF – Oil Natural – Air Forced cooling system for transformer
37 OFAF - Oil Forced-Air Forced cooling system for the transformer
DSO
Page 67
Table 4.13 below summarises the major project information provided.
Table 4.13 : Summary of DSO Major Reinforcement Projects
DSO Reinforcement Major Projects – Summary Data
Total Number of 38kV and 110kV Reinforcement Projects 81
Total Capex (2011-2013) on these projects (2009 Prices) €137.4m
Total Forecast Capex (PR3) on these projects (2009 prices) €219.4m
Sample Projects – Summary Data % of PR3 total
projects
Total Number of Sample Projects (selected by ESBN) 11 13.6%
Total Capex (2011-2013) on these projects (2009 prices) €45.3m 32.9%
Total Forecast Capex (PR3) on these projects (2009 prices) €58.1m 26.5%
Proportion of capex to be incurred in 2014 & 2015 22.0%
Proportion of capex to be incurred in 2015 only 6.7%
The DSO has provided details for a representative sample of projects in terms of the number of projects (13.6%
of total number) and their proportionate contribution to PR3 capex (32.9% of actual capex over period 2011 to
2013, 26.5% over the full PR3 period). It should be noted that the sample projects for which information has
been provided, were selected by the DSO.
The DSO is forecasting to complete all 11 projects within PR3 with 93% of costs fully incurred by end 2014 -
2015 forecast capex is relatively low, suggesting that the majority of costs have already been incurred. Details
of the 11 projects are presented in Table 4.14 below.
Table 4.14 : DSO Sample Reinforcement Projects- Analysis of Capex
Project Project Name
Actual Total
Spend PR2
PR3 Total
Spend
Grand Total
IA Cost
Forecast for Price Review
Cost
Capital Approval Amount ex IDC
Variance: Grand Total to Capital
Approval Amount excluding IDC
€M €M €M €M €M €M €M %
N-D-0952 Longford 38kV Stn Uprate 4.8 0.4 5.2 2.6 0.0 5.3 -0.1 -1.6%
H-I-0630 Caherdavin 38kv Stn uprate 2.7 0.4 3.1 1.2 4.6 3.2 -0.1 -3.9%
N-D-1401 Purcells Inch 38kV Station Uprate 1.9 0.6 2.5 1.5 0.0 3.0 -0.5 -17.6%
N-D-1461 Uprate Oakfield 38kV stn 2.3 0.6 3.0 2.3 0.0 3.2 -0.3 -8.3%
N-D-1118 Uprate Bushfield 38kV Station 2.2 0.9 3.1 2.4 0.0 3.2 -0.1 -2.5%
H-I-0707 Cong to Ballinrobe 38kV line 0.0 1.1 1.1 0.6 1.9 1.2 -0.1 -9.1%
N-D-1405 Uprate Blessington 38kV Station 1.9 1.3 3.2 1.6 0.0 3.2 0.0 -0.8%
N-D-1150 Inchicore 220kV Stn T2106 7.4 4.7 12.0 7.4 0.0 12.4 -0.4 -3.2%
N-D-0754/ H-I-0577
Connemara 110kV Reinforcement Project/Screeb
4.1 46.3 50.4 33.2 36.7 51.3 -0.8 -1.6%
H-I-1083 Doon 110kV station 0.7 0.7 1.4 1.1 0.0 1.6 -0.2 -11.1%
N-D-1027 College Park 3rd 110/MV trafo 1.1 1.1 2.2 0.9 0.0 1.3 1.0 78.6%
DSO
Page 68
TOTAL 29.1 58.1 87.2 54.7 43.2 88.8 -1.6 -1.8%
It should be noted that we have not been able to present the capex figures in the above table in 2009 prices as
the costs provided by the DSO did not readily allow for the application of appropriate inflation adjustments. For
example:
The PR2 total capex is the sum of PR2 capex in nominal terms – we do not have yearly breakdown to
which we could apply inflation adjustments to convert to 2009 prices.
The Investment Appraisal (IA) Costs are Prime Costs and are stated in whichever year the IA was
prepared. The DSO states it is likely that for most of the projects the year will be 2007/08 although we have
not been provided with details of which year is appropriate for each project and hence we have not
adjusted to 2009 prices.
The Capital Approval (CA) costs are Gross Costs and these are stated in the year in which the CA was
prepared. The DSO indicates this would vary between 2006 and 2011 although we have not been provided
with details of which year for which project and hence we have not adjusted to 2009 prices.
The DSO has provided annual capex for each project during PR3 and so we have converted to 2009 prices
For 10 of the 11 projects, we have observed that the DSO is forecasting total costs (PR2 and PR3) that are
lower than the Capital Approval Amount – with variances in the range of €0.1m to €0.8m.
For the remaining major project (N-D-1027), we observe that the DSO is forecasting a total cost (PR2 and PR3)
which is higher than the Capital Approval amount by €1.0m.
However as the lack of cost granularity has limited our assessment on a constant 2009 price base, conclusions
made from any comparison of projects costs need to recognise this cost base inconsistency. We have not
investigated the reasons behind any variance in total costs v CA costs nor has the DSO provided any variance.
It was also our intention to request a sample number of post investment appraisal document for a
selection of completed major projects. The DSO has advised us that they do not presently carry out a
formal post investment review of individual projects and hence no documentation was available for us
to review.
We consider this gap to be an area for improvement within the DSO project delivery process – this has
been recognised by the DSO, who has stated their plans to introduce this improvement over the
coming months.
However, the DSO has provided a supporting narrative document (DH02 – PR3 Load Driven Programme) that
provides detailed commentary of investment during PR3 – this has allowed us to make a quantitative
assessment of non-financial project outputs.
Many of the projects identified for delivery during PR3 have been deferred due to the negative load growth.
Some of the projects completed by the DSO during PR3 are those projects that were carried over from PR2.
There were also four additional 110kV projects that had not been identified by the DSO at the time of their PR3
submission, each relating to a separate major commercial data centre in the Dublin area.
The total transformer capacity (MVA) and HV circuit lengths (km) added during PR3 period, compared to the
CER allowed values (PR3 forecast) is shown in Table 4.15 below.
Table 4.15 : DSO Reinforcement: Summary of PR3 Additional Capacity / Assets added to Distribution System
Asset Type Unit PR3 Forecast
Volumes
PR3 Actual
Volumes Variance %
220/110kV Transformers MVA 500 500 0.0%
110/38kV Transformers MVA 378 346.5 -8.3%
DSO
Page 69
Asset Type Unit PR3 Forecast
Volumes
PR3 Actual
Volumes Variance %
110/MV Transformers MVA 451.5 323 -28.5%
110kV lines km 107 96 -10.3%
110kV cables km 47 25.9 -44.9%
38kV/MV transformers MVA 427 417.8 -2.2%
38kV lines km 272 128.2 -52.9%
38kV cables km 26 22.7 -12.7%
Convert 10kV network to 20kV
operation km 15000 10000 -33.3%
Analysis of the above volumes, together with the variance in capex for 110kV reinforcement projects / assets is
presented in Figure 4.9 below.
Figure 4.9 : 110kV Reinforcement Work Volumes – Variance Analysis – DSO Actual for PR3 compared to CER Allowances
The DSO forecast capex for 110KV reinforcement projects is 39% lower than CER allowed costs. The variance
in transformer capacity commissioned during PR3 period is in the range of 0% to 28.5% lower whilst the
variance in 110kV lines and cable kilometres is 10.3% and 44.9% lower respectively.
This analysis suggests that the reduction in DSO forecast capex for 110kV reinforcement projects is
higher than the equivalent volume reductions in transformer capacity or circuit km commissioned
(other than 110kV cable).
This disparity will be partly due to a number of projects being completed in PR3 that commenced in
PR2 period; with the costs incurred on these projects during PR2 being added to the DSO RAB during
PR2.
0.0%
-8.3%
-28.5%
-10.3%
-44.9%
-39%
-50.0%
-45.0%
-40.0%
-35.0%
-30.0%
-25.0%
-20.0%
-15.0%
-10.0%
-5.0%
0.0%
220/110kVTransformers
110/38kVTransformers
110/MVTransformers 110kV lines 110kV cables 110kV Capex
DSO
Page 70
We have carried out a similar analysis of variance in DSO volumes/capex for 38kV projects. This is illustrated in
Figure 4.10 below.
Figure 4.10 : 38kV Reinforcement Works – Variance Analysis – DSO Actual for PR3 compared to CER Allowances
The DSO forecast capex for 38kV reinforcement projects is 60% lower than CER allowed costs. The variance in
38kV transformer capacity commissioned during PR3 period is only 2.2% lower whilst the variance in 38kV lines
and 38kV cables is 52.9% and 12.7% lower respectively.
The analysis suggests that the reduction in DSO forecast capex for 38kV reinforcement projects is
higher than the equivalent volume reductions in transformer capacity or circuit km commissioned.
Again, this disparity will be partly due to a number of projects being completed in PR3 that
commenced in PR2 period; with the costs incurred on these projects during PR2 being added to the
DSO RAB during PR2.
Since 2010, the GB DNO’s have been reporting on substation loading by using a set of Load Indices, allowing
the companies to demonstrate the network risks and the effectiveness of their investments to manage peak
loading at its major substations. We consider the use of Load Indices to be good practice. Although the DSO
does not presently use Load Indices to track movement in peak demand on its major substations resulting from
its capex investment, during our meeting with the DSO in early December 2014, they have explained they are
considering adopting the use of load indices – we would support such an improvement.
However, the DSO has provided details that summarise the historic trend regarding the overloading of its
population of 38kV substations. This is provided in Table 4.16 below.
Table 4.16 : Historic Trend of 38kV Overloaded Substations
Indicator 2000 2005 2010 2015 (Forecast)
38kV Substations normally overloaded 68 65 72 32
38kV Substations normally loaded above 75% 213 190 150 75
It is noted that the reported numbers are derived based on the nameplate rating of the substation transformers.
Using the Planning policy (which permits 180% loading of single transformer nameplate rating under
N-1 conditions for dual transformer stations), the DSO has forecast that a total of 48 of their population
of 38kV stations will be outside Planning Standards by the end of PR3 (rather than 32 loaded above
-2.2%
-52.9%
-12.7%
-60%
-70.0%
-60.0%
-50.0%
-40.0%
-30.0%
-20.0%
-10.0%
0.0%38kV/MV transformers 38kV lines 38kV cables 38kV Capex
DSO
Page 71
nameplate rating).
These stations will require further attention during PR4 and will be a consideration within the review of
DSO forecast capex.
The DSO network planning standard relating to security of supply is not aligned with the GB DNO Security
Standards (Engineering Recommendation P2/6) with respect to load bands and the amount of load that could
be disconnected for a period following an (n-1) fault although the format and principles applied are the same.
The application of a short duration emergency rating of 180% by the DSO is more onerous than typical ratings
applied in UK (~130%) and consequently reduces the DSO reinforcement need and resulting capex.
The capacity margin of a substation is defined as the excess of capacity over demand taking the capacity of a
substation to be 180% of the installed name plate transformer rating. Capacity margin is a measure of the spare
capacity that is available at individual substations and on the network overall. Analysis of transformer utilisation
and capacity margin over PR3 period is detailed in Table 4.17 below.
Table 4.17 : PR3 Movement in Capacity Margin at DSO Substations
110/38kV Stations 2010-11 2011-12 2012-13 2013-14 2014-15 5-year Change
MVA %
Aggregated Demand (MVA) 4326 3867 3801 3669 3698 -628 -15%
Aggregated transformer capacity (MVA) 6806 6900 6932 6932 7058 252 4%
Utilisation 63.6% 56.0% 54.8% 52.9% 52.4%
Capacity Margin 57% 78% 82% 89% 91%
110/MV Stations
Aggregated Demand (MVA) 782 738 759 738 738 -44 -6%
Aggregated transformer capacity (MVA) 1681 1761 1761 1841 1921 240 14%
Utilisation 46.5% 41.9% 43.1% 40.1% 38.4%
Capacity Margin 115% 139% 132% 149% 160%
38/MV Stations
Aggregated Demand (MVA) 3841 4237 3662 3405 3430 -411 -11%
Aggregated transformer capacity (MVA) 5496 5601 5618 5658 5822 326 6%
Utilisation 69.9% 75.6% 65.2% 60.2% 58.9%
Capacity Margin 43% 32% 53% 66% 70%
Note 1: The capacity figures exclude transformer installed and exclusively used for renewable generation.
Note 2: The aggregate capacity shown is the actual capacity installed. The change from year to year is inclusive of new capacity installed net of capacity retired.
Note 3: There are now a number of transformers on the system that are shared between load and generation and that have been changed to larger unit sizes to accommodate generation. This has the effect of showing a reduced load utilisation. The quantity of such transformers is relatively small at present but is growing with the increased level of renewable penetration.
It is observed that the DSO investment made over PR3 period to reinforce those parts of the network which
were already non-compliant with the Planning Standards, coupled with reduction in system peak demands has
resulted in a reduction in utilisation across all voltage levels.
DSO
Page 72
For 110/38kV Stations, there has been a 15% reduction in aggregate demand over PR3 with a 4% net
increase in aggregated transformer capacity, thus resulting in an overall reduction in transformer utilisation
and increased capacity margin.
For 110/MV stations, there has been a smaller reduction in aggregate demand over PR3 of 6% with a 14%
net increase in aggregate transformer capacity.
For 38kV/MV stations, the reduction in aggregate demand is 11% with a 6% increase in aggregate
transformer capacity.
The 5-year net change in aggregated demand on the stations, together with net change in aggregate
transformer capacity is illustrated below in Figure 4.11.
Figure 4.11 : PR3 Net Change in Aggregate Station Demand v Capacity
Review of DSO 20kV Conversion Programme
The DSO has continued its programme to convert its 10kV network to 20kV operation, albeit at lower volumes.
Conversion of the networks to 20kV has benefits, specifically the capacity of an uprated line is increased by a
factor of 4 and for the same capacity the losses are reduced to one quarter.
In PR1, a total of 18,000 km had been converted to 20kV operation. By the end of PR2, a further 19,000 km
was converted to 20kV. As detailed in Table 4.15, the PR3 forecast volume for this activity was 15,000km. The
DSO has reported that by the end of PR3 a total of 10,000km will be converted to 20kV, resulting in a
cumulative total of 47,000 km of network converted.
We have satisfied ourselves that the DSO has in place an appropriate cost-benefit and prioritisation process,
with the CBA considering the impact of losses on the network, together with improved network voltage. 90% of
the network conversions have been required due to voltage deficiencies of the network.
Analysis of the PR3 volumes, together with the variance in capex for the 20kV conversion programme is
presented in Figure 4.12 below.
-628
252
-44
240
-411
326
-800
-600
-400
-200
0
200
400
Total MVA Demand (MVA)Total transformer capacity
(MVA)
110/38kV Stations 110/MV Stations 38/MV Stations
-15%
4%
-6%
14%
-11%
6%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
Total MVA Demand (MVA)Total transformer capacity
(MVA)
110/38kV Stations 110/MV Stations 38/MV Stations
DSO
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Figure 4.12 : 20kV Conversion Works – Variance Analysis – DSO Actual for PR3 compared to CER Allowances
The reduction in capex associated with the 20kV conversion programme is consistent with the reduced
circuit lengths converted during PR3 and it appears to be efficiently incurred.
MV/LV System Reinforcements
The DSO is forecasting that capex associated with other MV/LV System improvements during PR3 will outturn
at €35.5m. This is approximately 51% less than the CER allowed capex of €69.1m for this programme of work.
The DSO cites the reduction in demand since 2008 combined with the major investments made in previous
price control periods in the MV and LV renewal programmes as both contributing to the continued reduction in
the scale of investment observed during PR2 and PR3.
The scale of reduction in DSO capex during PR3 for MV/LV system improvements is consistent with
the overall reduction in PR3 load related reinforcement expenditure (being 50% of CER allowed capex)
4.2.4 Dismantling Costs
In relation to dismantling (retirement) costs, CER allowance for PR3 period was €57.4m. This value was derived
based on an a priori assumption that dismantling costs were directly proportional to the gross cost of load driven
reinforcement and non-load related network capex. The PR3 allowed costs were based on 4.8% of this gross
value.
ESBN’s accounting practice for dismantling costs historically has been to treat these as opex, with costs
included within the Income Statement. However, the CER has previously proposed a change to the regulatory
treatment of dismantling costs to treat these costs as Capex rather than opex – this change was made at PR2
determination and capital expenditure in PR3 was allowed on this basis.
The DSO has continued its practice of charging dismantling costs to its Income Statement for years 2011 to
2013 and proposes a change in Accounting Practice for the remaining two years of PR3 such that the costs are
allocated to capital. Our analysis of DSO dismantling costs has been carried out on a total cost basis, as shown
in Table 4.18.
-33.3%
-39%
-40.0%
-39.0%
-38.0%
-37.0%
-36.0%
-35.0%
-34.0%
-33.0%
-32.0%
-31.0%
-30.0%
Convert 10kV network to 20kV operation -Volume Variance (Circuit km)
20kV Conversion (including IFTs) - CAPEXVARIANCE (%)
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Table 4.18 : Comparison of DSO Dismantling Costs (€m 2009 prices)
2011 2012 2013 2014 2015
5 Year
Total
CER Allowed Capex 11.8 11.6 11.5 11.3 11.2 57.4
DSO Actual / Forecast (See Note 1) 9.1 9.7 18.7
DSO Actual / Forecast (See Note 2) 11.6 8.8 7.9 28.4
Total DSO Actual (Dismantling) 11.6 8.8 7.9 9.1 9.7 47.1
Variance % -1.3% -23.8% -31.3% -19.9% -13.7% -17.9%
DSO Actual / Forecast of Load Related Reinforcement and Non-
Load Related Capex 213.5 113.4 119.9
135.6 149.8 732.2
Dismantling as % of Load Related Reinforcement and Non-load
related capex 5.5% 7.8% 6.6%
6.7% 6.5% 6.4%
Note 1 – Source data from Table 6.3 (ESBN Distribution – Planned & Forecast Capex)
Note 2 – Source data from Table 5.1 (ESBN Distribution- Breakdown of Actual & Forecast OPEX)
Based on the above, the following observations can be made:
Total dismantling cost over the PR3 period is forecast at €47.1mm, 17.9% less than the CER allowed
capex of €57.4m
This reduction is much less than the corresponding DSO reduction in capex relating to reinforcement and
non-load related capex.
The actual dismantling costs as a proportion of the reinforcement plus non-load related capex for years
2011 to 2013 are higher than the percentage allocation basis of 4.8% used in the setting of allowances for
PR3, with annual values in the range 5.5% to 7.8% and a three year average of 6.4%. The DSO has
provided further details to support this increase and these are itemised below.
The DSO has introduced revised project costing procedures (Integrated Work Management Module) within their
SAP application from 2009 onwards. This has allowed the DSO to allocate dismantling costs more directly to
the work activity that has driven the need for the dismantling to be carried out. A summary of this cost allocation
provided by the DSO is presented in Table 4.19 below.
Table 4.19 : Allocation of DSO Dismantling Costs over period 2011 to 2013(€m – Nominal)
Note – Source ESBN PR4 Submission – document DH29 PR3 Dismantling/Retirements (Table 4.2)
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The DSO made the following points relating to the above analysis38:
It is reasonable to expect the level of dismantling driven spend to vary across different program types
depending on the nature of the asset and the work involved. This is borne out by the various ratios where non-
load capex and line diversions drive significantly more dismantling spend than reinforcement, and new
business.
New Business and reinforcement which account for 2.5% of dismantling costs are down from a combined 65%
of total CAPEX spend in PR2, to 53% in PR3.
On the other hand, non-load capex which drives a further 6.1% of dismantling costs is up from 28% to 36%.
Within that average one would expect that overhead line replacement activities would drive higher dismantling
spend that station refurbishment activities.
In 3 years to date 30% (8.8m) of dismantling cost arose from activities that are not part of the current formula,
particularly New Business and Line Diversions.
We would generally agree with the DSO that the proportion of dismantling costs is likely to vary across each of
the work activities. The change in the DSO cost allocation procedures has provided improved visibility of the
drivers on the dismantling activity and associated costs.
We would expect the DSO dismantling costs over the PR3 period to be charged to capex for the full
five years, this being consistent with CER allowances. This will result in a transfer of €28.4m of costs
from opex (2009 prices) to capex covering the years 2011 to 2013.
4.2.5 Non-Repayable Line Diversion Costs
During PR3, the DSO has allocated the costs of line diversions to capital allocation codes39 in line with agreed
outcome at the PR3 settlement where the CER allowed costs relating to non-rechargeable line diversions for a
total of €51.8m.
Line diversion costs have historically been proportional to capital expenditure in the category of “gross new
demand connections”. For the PR3 period, this allowance was set at a value equivalent to 11.4% of the PR3
forecast capex for new connections. The DSO actual costs for 2011 to 2013, together with forecast to 2015 are
shown below in Table 4.20.
Table 4.20 : Comparison of DSO Line Diversion Costs (€m 2009 prices)
2011 2012 2013 2014 2015
5 Year
Total
CER Allowed Capex 9.8 10.1 10.4 10.6 10.9 51.8
DSO Actual / Forecast 10.6 8.9 8.6 9.6 9.5 47.1
Variance to CER allowed capex (€m) 0.8 -1.2 -1.8 -0.5 1.7 -1.0
Variance to CER allowed capex (%) 8.1% -11.9% -17.1% -9.9% -13.1% -9.0%
Capex as a proportion of New Connections
Capex (Gross) 20.2% 19.2% 21.0% 19.7% 20.0% 20.0%
As described in Section 4.2.1 there has been a significant reduction in new connections capex during PR3
period, although it is evident that the rate of expenditure associated with asset diversions has not reduced to the
38 Document DH29 – PR3 Dismantling / Retirements 39 During previous PC periods, the costs associated with line diversions had been treated by the DSO as an operating cost.
DSO
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same levels. The actual diversion costs over 2011 to 2013 are in the range of 19.2% to 21% of the gross
connections capex over the same period.
The DSO cites this higher rate being driven by an underlying “bank” of diversion works that is required, which
has become more clearly evident with the connections expenditure reducing to the current outturn levels. The
DSO has carried out regression analysis over the PR2 and PR3 period to identify more accurately the
relationship between connections capex and diversions capex.
In its response (DSO report DR01) to our Interim Report, provided the DSO revised forecast of line
diversions capex for the remaining two years of the PR3 period suggests costs in the range of 20% for
the remainder of PR3- these values are broadly consistent with the first three years of PR3 and are
considered reasonable.
4.3 Non Load Related Capex
The DSO non-load-related capex for the PR3 period is shown in Table 4.21 below.
Table 4.21 : Comparison of PR3 Costs v CER Allowances Non- Load Related Capex (€m 2009 prices)
Category 2011 2012 2013 2014 2015 5 Year Total
CER Allowed Non-load
related Capex 115.8 114.3 112.9 111.5 110.2 564.7
DSO Actual / Forecast 120.7 58.4 62.8 85.9 87.5 415.3
Variance 4.9 -55.9 -50.1 -25.6 -22.7 -149.4
% Difference 4% -49% -44% -23% -21% -26%
The DSO expects a total non-load related capex of €415.3m by end of PR3 – this is €149.4mm lower than the
CER allowed non- load-related capex of €564.7m – representing a variance of 26%. This DSO forecast is
€29.4m higher than the revised proposal of ESBN (€387m40) submitted to CER in 2012 (see Figure 4.13 below)
but it should be noted that this forecast includes for a one-off capex of €26.8m in 2014 associated with Storm
Darwin and it also includes a significant increase in capex for year 2015 (relative to 2012 and 2013).
40 €433m less forecast retirement costs (considered separately) of €46m
DSO
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Figure 4.13 : Summary of PR3 Non Load Related Capex
Table 4.22 below provides an itemised breakdown of the DSO non-load related capex over PR3 period,
compared to the CER allowed capex for each of the categories. It should be noted that the ESBN Proposed
revisions to the capex in 2012 were provided at an aggregated level (totalling €387m) and were not
broken down into the individual categories shown below.
Table 4.22 : Comparison of PR3 Non-Load Related Investment (€m 2009 prices) by Category
Investment Category CER Allowed DSO Actual Variance
PR3 TOTAL PR3 TOTAL €m %
Renewal Programme - 110kV & 38kV Lines 16.3 15.1 -1.2 -7%
Renewal Programme – 110kV & 38kV Cables 20.5 6.0 -14.5 -71%
Renewal Programme - HV Substation 117.5 75.3 -42.2 -36%
Renewal Programme - MV Overhead Lines 69.0 59.5 -9.5 -14%
Renewal Programme - MV Cables 2.5 1.9 -0.6 -23%
Renewal Programme - MV Substations 24.1 30.5 6.4 27%
Renewal Programme - Urban LV Renewal 62.8 35.3 -27.5 -44%
Renewal Programme - Rural LV Network 93.5 82.1 -11.4 -12%
Renewal Programme - LV cables and associated items 16.8 6.1 -10.7 -64%
Renewal Programme - Cutouts 5.7 5.7 3.9 -1.8
Continuity Improvement 22.3 22.3 13.7 -8.6
Response capex 98.7 98.7 55.1 -43.6
System Control 15.0 15.0 3.8 -11.2
Storm Darwin Rectification Project 0.0 26.8 26.8
Total 564.7 415.3 -149.4 -26%
It is noted from Table 4.21 above that the DSO non-load related expenditure in 2011 was broadly consistent
with CER allowed costs for the year, albeit slightly higher.
However from 2012 onwards it is evident that there is a significant negative variance with CER allowed capex
for the PR3 period. This reduction in expenditure was proposed by the DSO to CER in 2012 as part of its overall
plan to reduce its capital expenditure given the difficulty in bond funding at the time, and the impact of DUoS
564.7
386 415
0
100
200
300
400
500
600
5 Year Total
€m
CER Allowed Capex ESBN Proposal (2012) DSO Actual / Forecast
DSO
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charges that would otherwise be experienced by its customers resulting from the reduction in consumption over
the PR3 period.
The reduced expenditure was only achievable by deferring large proportions of planned asset renewal works
with the reduced forecast being derived by the DSO following a detailed and prioritised assessment of key
criteria, including safety, environmental impact, probability of plant failure, asset criticality and practicability of
deferring works.
The DSO’s revised PR3 forecast of 2012 for non-load related expenditure was €385.9m. Its latest PR3
forecast of €415.3m is broadly consistent with its revised 2012 forecast of €385.9m if the 2014 costs
associated with Storm Darwin, at €26.8m, are netted off. It should be noted that the PR3 forecast
proposes for a significant increase in capex for year 2015, relative to previous years 2012 to 2014.
Certain asset replacement projects were deferred in whole or were scaled down based on the DSO’s
prioritisation process. Additional commentary relating to each of the main categories itemised within the above
Table 4.22 is provided in the sub-sections below:
4.3.1 Renewal Programme
4.3.1.1 110kV & 38kV Lines
CER PR3 allowed capex of €16.3m, although the DSO current forecast for this programme is €15.1m
representing a reduction of 7%.
38kV line refurbishment: In PR3 a nine-year 38 kV overhead line refurbishment cycle was approved. The work
involves inspection and refurbishment of the 38 kV network, with the cycle aligned to the hazard patrols, tree
cutting cycles and the MV overhead cyclical refurbishment programme.
The 5-year PR3 target for this programme was 2,321km, however by Q3-2014 the DSO has completed
approximately 52% of this target (~1,220km). By the end of PR3, the DSO is targeting completion of a further
1,000km using a mix of internal resources (300km) and contractor resources (700km), increasing the total km
during PR3 period to 2,221km (representing 96% of the original PR3 target).
There is a significant risk that this volume of work associated with the 38kV OCR programme is not
delivered in 2015 – it represents a significant increase in volumes previously delivered and is heavily
dependent on contractor resources being in place and fully operational. Whilst the DSO also
acknowledges the 2015 volumes represent a significant increase in the rate of delivery, it considers its
2015 forecast to be reasonable, citing contractor resource availability to deliver the majority of the
work programmes.
110kV line refurbishment: The original PR3 programme also included for the re-conductoring of four 110kV
circuits (23.7 km) within the greater Dublin area. The DSO deferred this programme in full during PR3 period
due to an engineering issue and initiated annual helicopter flying patrols of the four lines and periodic IR
imaging.
The PR3 programme associated with the 110kV lines outside of the Dublin area catered for minor refurbishment
of four 110kV circuits (total length 33km). The DSO deferred this programme in full during PR3 period and
initiated ongoing hazard patrols of these circuits.
38kV line – Covered Conductor: The PR3 programme for the use of covered conductor on 38kV line was
targeted to replace 20km of bare conductor. The DSO has modified this from a proactive programme of
replacements, to a fully developed standard technical solution to address problem 38kV feeders on a reactive
basis. Consequently only a small number of pilot projects have been completed during PR3.
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38kV Copper Overhead Line Replacements: The DSO is reporting a further €1.9m of capex associated with
the replacement of 38kV copper overhead lines that was largely completed during PR2 period.
For PR3, the allowed capex for HV Overhead Line Replacements was €16.3m and the DSO latest
forecast is €15.1m, representing 93% of allowed capex.
The DSO states that the 38kV OCP programme will be substantially completed, although this is
dependent on the delivery of 1,000km during Q4, 2014 and end of 2015.
The reduction in capex by deferring 110kV line works has been largely offset by the additional capex
associated with 38kV copper overhead line replacements.
Generally, the PR3 costs are broadly consistent with the PR3 volumes delivered.
4.3.1.2 110kV & 38kV Cables
CER PR3 allowed capex of €20.5m, although the DSO current forecast for this programme is €6.0m,
representing a reduction of 71%.
During PR3, the 110kV fluid-filled cable replacement programme was originally focused on the replacement of
the Inchicore – Francis St circuit (total circuit length of 5.6km, of which 3,8km runs alongside the Grand Canal).
The DSO has deferred replacement works for this circuit until PR4. Replacement of this cable has been
previously justified partly to address the number of oil leaks from the cable.
Deferment of the programme therefore has introduced environmental and network reliability risks that the DSO
has addressed by the introduction of the use of perfluorocarbon tracing (PFT) gas technology to find leaks in a
much quicker and more efficient manner.
The programme associated with the replacement of 9 km of gas compression 110 kV cables supplying Milltown
in Dublin has been deferred. The works were previously deemed necessary to address deterioration and
leakage of the cable pipeline. The DSO has made further use of the PFT technology to manage cable leaks and
reduce outage periods.
The programme for the replacement of 38kV Fluid-Filled Replacement during PR3 period has been significantly
deferred by the DSO. The original programme was to replace a total of 10% of the total 38kV fluid-filled cable
population of 80km. However, works completed during the PR3 period has been restricted to the completion of
projects that commenced in PR2 period.
The programme relating to the replacement of 15 sets of defective oil filled 110KV and 38kV cable terminations
has been deferred with no works completed during PR3.
The PR3 programme for the replacement of 38kV cable consisted of four circuits with total length of 17km.
These circuits supply critical Dublin City substations. Works were completed during PR3 on the two Kimmage
circuits (total length of 8.9km).
For the other two 38kV circuits, limited progress has been made during PR3 with remaining works proposed for
completion during PR4. For the Leeson St – Milltown circuit, the ducting and cabling has been completed, but
no jointing has been progressed. For the Merrion Sq – Milltown circuit, the cable route has been partially ducted
and cabled, although no jointing completed.
A project to replace a section of 110kV XLPE cable that is routed through private property and close to the
foundations of houses along the Taney – Central Park 110kV feeder route involved the installation of 600m of
cable rerouted in a safer location has been progressed by the DSO and it is forecasting completion by the end
of 2015.
DSO
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The DSO has deferred significant capex during PR3 associated with 110kV and 38kV cable
replacement projects. The reductions in work volumes stated by the DSO are broadly consistent with
the reduced capex.
4.3.1.3 HV Substation
CER PR3 allowed capex of €117.5m, although the DSO current forecast for this programme is €75.3m,
representing a reduction of 36%.
Siemens 38kV station replacements: the planned replacement of five Siemens 38kV substations during PR3
has been significantly deferred, with only two of the five now forecast to be fully completed by end of 2015.
Works are in progress at all five stations, summarised below:
Cloonbanin – originally deferred, although subsequently reinstated into the renewal programme; civil works
commenced in early 2014 and scheduled for completion by end 2015;
Newtown St Alban – originally deferred, although subsequently reinstated into the renewal programme;
work is in progress but will not be completed until PR4 period (2016)
Garryowen – originally deferred, although subsequently reinstated into the renewal programme; scheduled
for completion by end 2015;
Mount Misery - originally deferred, although subsequently reinstated into the renewal programme; some
work completed in 2013 although subsequently de-prioritised – now scheduled for completion in PR4
period (2016);
Lake – this station is being retired with load transferred to Dunmanway 110kV station. Project is in
progress, with scheduled completion date of mid 2016
The DSO continues to have operational restrictions in place for these types of station such that the 38kV
line disconnectors within the station must not be operated live.
Replacement of Convoy ‘Wood Pole’ 38kV Station: Originally scheduled for PR3, the DSO has deferred this
project completely and work is not scheduled to start by the end of PR3 period. The DSO has provided
explanation on additional mitigation actions carried out to assess the degree of rot appertaining to the wood
pole supports within the station. Based on the specialist pole testing carried out in 2013, the DSO has been able
to make an informed decision to defer works.
Pembroke 38kV Station – MV Switchgear Replacement: The replacement of the compressed air operated
switchgear was originally scheduled for PR3, the DSO has deferred this project completely and work is not
scheduled to start by the end of PR3 period. Asset Risk Management Plans are in place for this substation to
address the ongoing risks until the equipment is replaced.
Bedford Row Station – 38kV and MV Switchgear Replacement: The station is now over 80 years old and the
switchgear is based on long outdated technology. The replacement of the switchgear was originally scheduled
for PR3, the DSO has deferred this project completely and work is not scheduled to start by the end of PR3
period. Asset Risk Management Plans are in place for this substation to address the ongoing risks until the
equipment is replaced.
Kilbarry – 38kV Switchgear Replacement: During PR3, it was proposed to replace the existing 38kV
switchgear and associated control and protection with a GIS module with integrated protection and modern
substation control system. The DSO has deferred this project completely and in late 2014 has reinstated this
project into the replacement programme, although it is unlikely that detailed works will be progressed on site.
Asset Risk Management Plans are in place for this substation to address the ongoing risks until the equipment
is replaced.
Ardnacrusha Station – 38kV Switchgear Replacement: During PR3, it was proposed to replace the existing
38kV switchgear and associated control and protection with a GIS module with integrated protection and
modern substation control system. The DSO deferred works at this station for a short period as it was decided
that the risks associated with this station could be managed for a short period of deferral. Work is not scheduled
DSO
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to start by the end of PR3 period. Asset Risk Management Plans are in place for this substation to address the
ongoing risks until the equipment is replaced.
38kV & 10kV CB Replacements: The majority of the DSO sub-transmission and distribution substations
comprise of outdoor air insulated switchgear. A programme of replacement was allowed for during the PR3
period. However, the total volume of CB replacements during PR3 has been reduced significantly, with the
exception of like-for-like 38kV CB replacements (with no protection relays included in replacement scope). This
can be seen in Table 4.23 below.
Table 4.23 : HV Substation Allowed and Forecast Replacement works
Activity PR3 allowed PR3 Forecast
38kV Outdoor / Indoor CBs only -like for like 10 41
38kV Outdoor / Indoor CBs & EM Relays 70 18
10kV Outdoor / Indoor CBs & EM Relays 100 13
A prioritised programme of replacement has been progressed by the DSO, with an integrated scope being
established for each station, taking due account of asset replacement, protection upgrades, fabric works and
other related station works being deemed necessary.
Replacement of Reyrolle Type ‘C’ 10kV Switchgear: Four switchboards were scheduled for replacement
during PR3. A decision was taken early in PR3 to defer works at these four stations. Although no on-site works
have been progressed at any of the four stations, the DSO has identified that there is a considerable risk with
two of the stations if the replacement works do not get completed in the near future.
The DSO is progressing replacement works at Marrowbone Lane and Glasnevin. It is expected that
Marrowbone Lane will be completed between mid-2015 and the end of 2016. Glasnevin is likely to follow a
similar timescale.
Protection Upgrades: Work was originally prioritised into two specific categories:
Priority 1, inadequate primary earth fault protection
Priority 2, slow or unreliable fault protection
The DSO has reported that the volume of protection relay replacements completed in PR3 is significantly lower
than the programme put forward for PR3. Compared to PR3 planned volumes, approximately12% of the priority
1 protection upgrades and 8% of the priority 2 upgrades have been completed in PR3. The replacement
programme completed during PR3 has been based on a prioritised programme of work. The shortfall in volumes
delivered during PR3 will need to be addressed during PR4.
Battery Replacement at HV Stations: During PR3 it was planned to replace battery equipment at 15 of their
major substations. The DSO reports that during PR3, four 220V batteries and five 110V have been replaced
and forecast that all batteries will be replaced by the end of PR3 period.
In addition a large scale programme of replacement of 24V batteries, housed in outdoor cubicles was scheduled
for PR3 period. The DSO is forecasting to complete this programme in full by the end of PR3.
Replacement of HV Transformers: The original PR3 programme catered for the replacement of three 110kV
transformers and 69 x 38kV/MV transformers (of capacity less than 3.2 MVA).
In relation to the 110kV transformers replacement, the DSO adopted a reactive based programme during PR3.
This initially deferred planned works and subsequently resulted in a change in the specific sites that
replacement works were carried out. The DSO decided to replace transformers at both Francis St T-142 and
Blake T-142, thus deferring Dungarvan T-141 and Thornsberry T-142. The replacement of Drumline T-142 is
still included within the DSO programme.
DSO
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The justification for the revised programme would appear to be reasonable and the DSO has made use of a
31.5MVA transformer at Blake that has been recovered from the system (ex Carlow station), demonstrating
efficient use of retired assets. Further, the DSO plans to make use of a recovered transformer for redeployment
at Drumline T-142 although plans are not yet firmed up regarding specific site form which the unit will be
recovered. This uncertainty adds some doubt to this planned scenario materialising during PR3.
Replacement works at Blake were completed in 2012/13; works at Francis St T-142 is scheduled for completion
in 2014/15.
The programme to replace the 69 No. 38kV/MV low capacity transformers has been significantly deferred during
PR3. A total of 15 units are forecast to be replaced by the end of PR3. The DSO has implemented a risk based
prioritisation tool to allow the candidate transformer replacement projects under this program to be ranked and
tracked.
Transformer Bunding retrofit to contain oil leakage: At the beginning of PR3 there was still a large quantity
of legacy transformers that remained unbunded.
The PR3 target was to install 250 retrofit bunds to transformers in 38kV stations and the DSO is forecasting that
197 will be completed by the end of PR3.
For 110kV stations, the PR3 target was to install 30 retrofit bunds to transformers stations and the DSO is
forecasting that 10 will be delivered.
In conjunction with an external supplier, the DSO has developed an alternative bunding solution, using a plastic
bund wall (manufactured using High Density Polyethylene HDPE)
Ground Potential Rise (GPR) Mitigation: The DSO reports that the programme to mitigate risks associated
with GPR has been only partially delivered during PR3.For efficiency reasons, the remedial measures are
generally undertaken in conjunction with other station works (e.g. station upgrades or security fence
replacements).Consequently, the deferral of other station renewal works has impacted on the GPR mitigation
programme, with a reduced volume of works being completed within PR3.
Replacement of 38kV and 10kV ‘Doulton’ Insulator Busbar Supports: The DSO is expecting to complete a
total of 16 units during PR3 out of an allowed total of 30. These works are usually replaced in conjunction with
other station works. The general deferral of station projects has contributed to the reduced volume of
replacement works associated with this activity.
Improved Station Security Programmes: the PR3 programme consisted of works at 70 stations to replace
existing chain-link fencing with palisade fencing. This consisted of 41 distribution sites with the balance at
transmission sites. The DSO has reported that 47 stations have been completed by end 2013, and is
forecasting completion of the full programme (of 70 stations) by the end of PR3.
A programme to install security monitoring systems during PR3 at stations was also planned by the DSO. The
design of security system to be installed has been dependent on the level of risk determined for each location.
The DSO reports that there are now over 50 stations (distribution and transmission) equipped with externally
monitored CCTV systems installed, although it is not clear if the full PR3 programme has been delivered. These
systems have been rented third party systems (opex cost) rather than a DSO owned CCTV systems (capex).
This arrangement was adopted by the DSO as it represented the lower short term cost. However, this short term
approach will need to be re-assessed when considering appropriate allowances for PR4.
The DSO programme to replace station locks during PR3 has been completed.
The programme to replace 110kV and 38kV station wood doors with high security, multi-point locking steel
doors has only been partially completed, with only 20 doors replaced out of PR3 target of 150.
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Installation of Emergency Lighting in HV Stations: The programme of works during PR3 has not been
progressed, the DSO having modified its approach to emergency lighting by concentrating in the current period
on the repairs to existing lighting systems.
Renovation of existing HV Substation Control Rooms: The PR3 target was to replace 10 control rooms and
the DSO is forecasting that 7 will be completed. To reduce installation risks and associated costs, the DSO has
developed a prefabricated, floorless, standard control room.
Flood protection in HV Stations: The flood defence programme, originally planned for PR3 period, has not
been progressed by the DSO who reports that work has been progressed during PR3 in developing its strategy
for flood management.
Analysis of the variances detailed above relating to the various components of the HV station renewal
programme, together with the variance in capex for HV station renewal is presented in Figure 4.14.
It is clear that in response to the borrowing constraints during PR3, the DSO has deferred a number of
the higher cost HV station replacement projects / programmes completely, whilst at the same time
focussing on the substantial completion of various safety driven and security driven programmes of
work, typically of a much lower cost.
These two factors contribute to an overall underspend of PR3 capex of 36% relating to the HV Station
renewal programme.
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Figure 4.14 : HV Station Renewal Works – Variance Analysis – DSO Actual for PR3 compared to CER Allowances
4.3.1.4 MV Overhead Lines
CER PR3 allowed capex of €69.0m, although the DSO current forecast for this programme is €59.5m
(representing an underspend of 14%).
MV Overhead Cyclic Refurbishment (OCR) Programme: For the PR3 period, the DSO proposed to
commence in 2011 a 9 year cycle of overhead line refurbishment, completing 9,000 km per year (PR3 total of
45,000km) and anticipating a pole replacement rate of 4.8%. This 9 year cycle is the same as for 38 kV and 110
kV lines. The refurbishment programme has been based on a nine year cycle and with the delivery of blocks
coordinated with other maintenance programmes - the 3 year rural MV public safety (hazard) programme and
the MV timber cutting programme.
The DSO reports that the original 9-year cycle is being amended to a 12 year cycle with this change in policy
being risk-assessed. The benefits of previous refurbishment works are resulting in lower volumes of defects
being identified on networks previously refurbished. The change to a 12 year cycle would reduce target volumes
for PR3 period to about 34,500km.
-60%
-100%
-60%
-100%
0% 0%
-78%
-26%
0%
-47%
0%
-100%
-30%
-100%
-36%
-120%
-100%
-80%
-60%
-40%
-20%
0%
DSO
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The DSO reports that delivery has been below target in PR3 to date, largely due to the challenges associated
with pushing out a new initiative with new standards, documentation and procedures on a national basis. (This
is evidenced by the circuit km refurnished in 2011 of only 5-6% of the five-year programme target).
The DSO also reports its concern about accelerated deterioration of wood poles that were installed on networks
from the late 1990’s. This issue of premature pole rot appears to be specific to Scantrepo poles creosoted
between 1998 and 2003. The DSO has communicated with Swedish utility companies who report similar cases
of premature decay in wood poles sourced from Scandinavia.
The DSO has revised its standard for MV OCR Standard in September 2014 to allow for a more detailed
inspection of certain poles that requires an extra switch-out. This is likely to increase costs for pole inspections
for 2015 and into PR4.
The DSO is reporting that the pole replacement rate is approximately 30 poles per 100km
For the MV OCR programme, the DSO is forecasting the completion of 33,000 km by end of PR3 (i.e.
73% of the original target (45,000km) upon which allowances were made, although it forecasts a spend
of 86% of the PR3 allowance. This increase in unit costs is being driven by higher labour costs being
forecast in 2014 and 2015 - associated with more stringent pole testing procedures.
The forecast includes a target of 14,500km being delivered in 2015 alone, predominantly by using
contract resources, this being subject to completion of the tendering and contract procedures.
Achieving the 2015 target volumes is therefore considered to be a significant challenge to the DSO.
4.3.1.5 MV Cables
CER PR3 allowed capex of €2.5m, although the DSO current forecast for this programme is €1.9m
(representing an underspend of 23%).
The original PR3 programme was based on the replacement of 15km of fault prone XLPE cable. This
programme is inherently reactive with strict criteria being applied by the DSO before an individual cable section
is progressed for replacement.
The DSO is forecasting that approximately 10km of MV cable to be replaced by 2015 – representing an
under-delivery of about 33%, broadly in line with the forecast underspend.
4.3.1.6 MV Substations
CER PR3 allowed capex of €24.1m, although the DSO current forecast for this programme is €30.5m
(representing an overspend of 27%).
Replacement of Indoor Oil-Filled MV RMUs: The PR3 approved replacement programme was to remove all
remaining 305 indoor oil-filled ring main units in indoor substations. The DSO is forecasting that more than 180
units will be replaced by the end of 2015 representing approximately 60% of the programme 5-year target.
The DSO has observed difficulties arising with the replacement works at locations where access to the
substations is difficult and has provided examples of some of the practical challenges they have faced. It is not
uncommon with a large scale station replacement programme in urban areas that some of the more challenging
locations are deferred towards the end of the programme period.
The reduced volume of works has necessitated a prioritised programme of replacements to be established by
the DSO, together with additional hazard patrols being carried out.
Replacement of Open-Cubicle Switchgear in Indoor MV Substations: The PR3 approved replacement
programme was to remove all remaining 369 open-cubicle switchgear in indoor substations for safety and
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operational reasons. The DSO is forecasting to complete approximately 300 by the end of PR3, representing
approximately 82% of the PR3 target with a forecast capex of €6.6m, 18% higher than PR3 allowed capex.
Whilst the DSO has reported that a number of the open-cubicle indoor substations with complex configurations
and multiple feeders have been deferred beyond PR3, it also identifies that a large proportion of the stations
have been progressed during PR3 period but at a higher unit cost.
Some of these practical considerations cited include:
Use of mobile generation;
Road Opening Licenses (for cable access and jointing);
Traffic Management;
Relocation of cable joint bays
Temporary Jointing
Site management;
Extensive plant rearrangement
Generator Hire
Crane Hire
Replacement of MV/LV Transformers in Association with Switchgear Replacement: This programme was
approved for PR3 focusing on the replacement of the older population of high loss transformers in stations
where it is proposed to replace MV switchgear (for instance indoor oil RMU or open cubicle switchgear).
A total of 113 station transformers were planned for replacement – in conjunction with the MV switchgear
replacement.
This programme is fully-linked with the replacement programmes for indoor oil-filled and open-cubicle
switchgear. Consequently, a reduced programme of delivery for these switchgear replacement programmes has
also resulted in reduced number of transformers replaced during PR3.
The DSO forecasts approximately 74 units will be replaced by the end of PR3, representing 65% of the PR3
target.
Replacement of Magnefix Cast-Resin type Switchgear: The PR3 approved programme volume was for the
replacement of 100 units. The DSO is forecasting that more than 220 units will be replaced during PR3 period,
representing 223% of the PR3 target.
This additional volume will be carried out during PR3 following reprioritisation by the DSO to address safety
concerns with the Magnefix switchgear and displaced a number of RGB cast resin units originally scheduled for
replacement in PR3.
Replacement of RGB Cast-Resin type Switchgear: The PR3 approved programme volume was for the
replacement of the remaining population of 180 ring main units (RMUs). The DSO is forecasting that
approximately 130 units will be replaced during PR3, representing 73% of the planned programme.
Replacement of Timber Substation Doors: At commencement of PR3, there were approximately 2,500
stations with timber doors in service, in varying states of repair. The current MV substation specification requires
ESB standard galvanised steel doors be fitted to all new stations. The DSO is forecasting full delivery of the
planned volume of substation door replacements by the end of 2015.
Oil bunding of permanent 20 kV interface transformer sites: The transformers located at 20kV/10kV
interface sites are presently unbunded. In order to address environmental risks, the DSO proposed and the
CER allowed expenditure during PR3 to install appropriate bunding to mitigate risk of oil leaking.
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However, the DSO has not yet been able to establish a solution that is feasible or acceptable for the exposed
rural station locations, all situated outdoors. These tend to be on land that is privately owned, and controlled
with livestock and vegetation in close proximity to the sites. In addition, the bunding solution will require a
drainages system to allow for water entering the bunded area to be released.
The DSO continues to explore permanent solutions and until such time, the DSO carries out regular inspection
of the interface transformer sites, to identify and rectify impact of any leaks or potential leaks.
Shrouding of LV Panels: The DSO has a number of older distribution substations that have LV panels
consisting of unshrouded LV busbars that present a safety risk to staff working within the stations. The planned
programme for PR3 consisted of shrouding being added to a total of 200 LV substation panels.
Due to the high priority nature of these works to mitigate these safety risks, the DSO has continued with the
programme during PR3 and expects the programme to be substantially delivered.
Substation upgrades with evidence of trespass and illegal dumping: Under this programme, the DSO is
undertaking pro-active works at distribution substation sites to minimise or eliminate the potential for illegal
dumping. The DSO selects sites for inclusion in this programme on a reactive basis, based on defects, condition
or reported hazards during the substation Hazard Patrol programme. The DSO is forecasting that approximately
250 sites will have been subject to various upgrade works during PR3 period, although this is below the
originally planned volume of 500.
Replacement of Underground Residential Distribution (URD) Transformers: The DSO programme to
replace the low kVA capacity single phase distribution transformers has continued in PR3. A total of 102 URD
transformers existed on the system at the start of PR3 period.
The DSO reports that the scope of replacements during PR3 period has been extended such that the
replacement works also include for replacement of the associated LV service vaults because of an inherent
safety risk. This added requirement has increased the complexity and cost of the replacement works. The DSO
has also faced the challenge of having to address the more complex locations as many of the URD
transformers replaced in the previous PR2 period were more straightforward to replace.
The DSO is forecasting that by the end of 2015, approximately 67 URD transformers will be replaced (~66%).
Analysis of the variances detailed above relating to the various components of the MV station renewal
programme, together with the variance in capex for MV station renewal is presented in Figure 4.15.
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Figure 4.15 : MV Station Renewal Works – Variance Analysis – DSO Actual for PR3 compared to CER Allowances41
Whilst the majority of programmes have been subject to reduced volumes in PR3, the exception to this has
been in the works associated with:
The replacement of timber station doors and the shrouding of bare LV panels, both of which will be
substantially completed
The replacement of Magnefix cast resin switchgear – where the DSO is forecasting the completion of 223%
of the original PR3 target.
In relation to the MV Station Renewal Programme, the DSO is forecasting an overspend in this
category of 19%.
Any expected reductions in capex due to the reduction in volumes for many of the categories have
been largely offset by increased costs associated with the higher volume of work associated with the
Magnefix Cast Resin Switchgear programme.
4.3.1.7 Urban LV Renewal
CER PR3 allowed capex of €62.8m, although the DSO current forecast for this programme is €35.3m
(representing an underspend of 44%).
The plan for PR3 period was to refurbish 35,000 spans of LV urban networks. This programme was a
continuation of works commenced previously during PR2. The DSO has prioritised PR3 works, focussing on
networks pre-dating the 1950s.
41 Excludes Station upgrades due to trespass and illegal dumping
-40% -18%
-35%
123%
-27%
6%
-100%
-19% -22%
27%
-150%
-100%
-50%
0%
50%
100%
150%
Indoor Oil-Filled MVRMUs
Open-CubicleSwitchgear
Replace MV/LVTransformers inAssociation with
SWGR
Magnefix Cast-Resin typeSwitchgear
RGB Cast-Resintype Switchgear
Timber SubstationDoors
Oil bunding ofpermanent 20 kV
IFTsitesShrouding of LV
PanelsReplace URDTransformers Capex Variance %
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The DSO is forecasting that less than 50% (~17,000km) of the programme will be completed during PR3 period.
The percentage reduction in capex for the Urban LV Renewal programme is broadly consistent with
the equivalent reduction in work volumes.
4.3.1.8 Rural LV Network
CER PR3 allowed capex of €93.5m, although the DSO current forecast for this programme is €82.1m
(representing an underspend of 12%).
The DSO has approximately 50,000 km of single phase rural low voltage overhead lines. 16% of these lines
were refurbished in the period 1996 – 2002 as part of the rural network renewal programme. A programme to
refurbish the outstanding 84% of the rural low voltage lines commenced in 2006. 42% were completed in PR2
and it was planned to complete the remaining lines in PR3 (21,000km).
The DSO is forecasting approximately 80% of the original programme will be delivered by the end of PR3. This
forecast is based on a challenging target for 2015, representing approximately 35% of the original 5-year
programme being delivered in one year. These works are being delivered by DSO internal resource with a
significant number of external contractor resources having been stood down in 2012 when it became necessary
to reduce work volumes.
For the Rural LV Network Renewal Programme, the reduction in the volume of works compared to PR3
programme (approximately 20%) is higher than the reduction in the Capex (6%) suggesting an increase
in unit costs.
Of the 20,000+ Groups refurbished during PR3, the DSO has selected more than 1,800 Groups that
were prioritised and selected for refurbishment in conjunction with other works to improve network
performance and power quality, with significantly higher unit costs than the basic fabric only
refurbishment works.
4.3.1.9 LV Cables and Associated Items
CER PR3 allowed capex of €16.8m, although the DSO current forecast for this programme is €6.1m
(representing an underspend of 64%).
During PR3, the LV cable programmes have been subject to a significant reduction in order to reduce impact on
DUoS charges. To achieve this, the DSO has applied strict prioritisation, and action to ensure that a careful
strategy is adhered to, ensure that the safety of these LV assets is not compromised. The sub-sections below
provide further commentary on PR3 programme
Replacement of Painted Steel Mini-pillars: The PR3 programme to address the condition of minipillars was a
continuation of the mini-pillar replacement programme undertaken previously, with the replacement of 600 cast-
iron mini-pillars and 1,000 painted steel mini-pillars.
The current DSO forecast is for the completion of 200-250 painted steel minipillar replacements by the end of
PR3. Prioritisation of replacement works has been based on the mini-pillar hazard patrol programme. This is
significantly lower than planned volumes of 1,000 and the DSO has addressed the resulting risks associated
with dangerously degrading pillar doors in the short term. Consequently the DSO has increased the number of
minipillar doors replaced during PR3 – approximately 1,500 (based on DSO reporting of 1,100 actual by August
2014). (Note that in 2010, the DSO replaced only 56).
Replacement of Cast Iron Mini-pillars: The DSO is forecasting that between 400 and 500 of these pillars will
be replaced by end of PR3 period (target of 600). Prioritisation of replacement works has been based on the
mini-pillar hazard patrol programme.
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Concentric Cable Replacement: This programme is delivered in response to recurrent faults and customer
complaints. To date only one project has been undertaken.
Aging Link box Replacement Programme: The DSO forecasts that approximately 50 link boxes will be
replaced by end of PR3.
Replacement of Sub-standard Copper Services: The PR3 programme is based on the replacement of
approximately 1,000 of the small 6mm2 copper services in the Dublin area (estimated total population of 2,500).
Due to reduced capex spending, the programme has been reactively driven with only 80 replacement services
being forecast by the DSO during PR3.
4.3.1.10 Cutouts
CER PR3 allowed capex of €5.7m, although the DSO current forecast for this programme is €3.9m
(representing an underspend of 32%).
The PR3 programme consisted of the planned replacement of 40,000 pre 1976 indoor cut-outs. This is a
continuation of works from PR2 cut-out replacement programme. The DSO is forecasting to replace up to
30,000 cut-outs by the end of 2015. (75% of the original target)
4.3.2 Response Capex
CER PR3 allowed capex of €98.7m, although the DSO current forecast for this programme is €55.1m
(representing an underspend of 44%).
The DSO has provided a narrative commentary and detailed breakdown of actual costs against each of the nine
categories of investment within the Response work programme. The breakdown of PR3 costs compared to the
CER allowed capex in each of these categories is shown in Table 4.24 below. The table also shows the DSO
revised PR3 forecast, provided in its response42 (report DR01-dated Feb 2015) to our interim PR3 capex report
(showing a minor variance of €0.3m compared to the DSO original PR3 forecast of €52.7m provided in Dec
2014.
Table 4.24 : PR3 Response Capex – Comparison of DSO Actual v CER Allowances for PR3 (€m – 2009 Prices)
Category PR3 Allowed
Capex
DSO PR3
Actual
Variance to
CER
allowances
Variance
to CER
allowances
%
Voltage Complaints 29.6 13.2 -16.4 -55%
25mm SCA OH Conductor
Replacement 9.3 3.0 -6.3 -68%
MV/LV UG Cable Replacement. 8.6 2.8 -5.8 -67%
Metering Replacement 7.7 6.6 -1.1 -14%
Time-switch Replacement. 5.0 4.9 -0.1 -2%
Failed Transformer Replacement 11.9 14.2 2.3 19%
38kV Cable Replacement 5.6 0.9 -4.7 -84%
Undergrounding MV & LV OH lines 16.1 6.8 -9.3 -58%
Advance Ducting 5.0 0.6 -4.4 -88%
Totals 98.7 53.0 -45.8 -46%
38kV Copper Line - Theft
Response 0.0 2.0 2.0
42 Document title DR01 ESBN Response to DSO Historic Capex – dated 06-02-2015
DSO
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Category PR3 Allowed
Capex
DSO PR3
Actual
Variance to
CER
allowances
Variance
to CER
allowances
%
Revised Total 98.7 55.1 -43.8 -44%
Note – Source data for DSO PR3 Actual – Document Reference DH07 – PR3 Response Capex (Table 1) – converted to 2009 prices
Significant underspend is observed in all but one of these categories (Failed Transformer Replacement). The
area of largest underspend relates to voltage complaints4. The reduced investment in this category over PR3
period is likely due to a number of factors, such as:
reduced demand,
impact of MV and LV network renewal,
20kV conversion programmes and
replacement of small capacity transformers in rural areas.
A total of 2,748 validated43 voltage complaints were resolved during PR3 period up to the end of 2014. This is
noticeably less than the 9,570 voltage complaints resolved during PR2.
Reactive activities that are primarily related to construction activities have been subject to notable reductions
(undergrounding of existing lines, advance installation of ducts). The DSO has observed an increasing number
of thefts of overhead line conductor during PR3.
The number of 38kV cable faults has reduced during PR3 period in overall terms, contributing to the major 61%
reduction in capex associated with the replacement of faulty 38kV cables.
An increase in capex (material cost only) relating to the replacement of faulted station equipment (transformers) is observed over the PR3 period.We would not expect the short term deferral of asset replacement works to result in an increase in reported fault rates and hence higher replacement costs for PR3. We have checked the reported DSO fault rates for faulted station equipment although we have not observed any noticeable increase in fault rates for PR3 period when compared to average for PR2 (2009 and 2010 only). The DSO reports (DH03) a programme to monitor the causes of increased transformer faulting and increased application of condition monitoring activities to identify the leading indicators of faults in these transformers.
In its response44 to our PR4 capex IR, the DSO explained the need for urgent works that are scheduled for 2015 to address risks associated with the theft of 50mm
2 Copper conductor from 4 x 38kV overhead line circuits. The
works involved replacement of the copper conductor with aluminium conductor (of equivalent rating) and the estimated capex for this new work programme is €2.0m in 2015. (Note this value is not included within the PR3 forecast capex detailed within Table 4.24).
4.3.3 Continuity Capex
The DSO is forecasting capex relating to the Continuity programme of €13.7m, which is approximately 39% less
than the CER allowed costs of €22.3m. The actual costs for each year of PR3 are shown in Table 4.25 below.
Table 4.25 : PR3 Continuity Capex – Comparison of DSO Actual v CER Allowances for PR3 (€m – 2009 Prices)
2011 2012 2013 2014 2015 5 Year Total
CER Allowed Capex 4.5 4.5 4.5 4.4 4.4 22.3
DSO Actual / Forecast 2.8 3.5 2.5 2.0 2.9 13.7
Variance €m -1.7 -1.0 -2.0 -2.4 -1.5 -8.6
43 The actual number of voltage complaints each year is much higher than the validated complaints. Validation is carried out by ESBN connecting a
voltage recording device to assess the actual voltage at the premises. 44 Document DR06 – DSO Forecast Capex – Interim Report; ESB Networks Response – dated 09-03-2015
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Variance % -38.2% -22.8% -44.5% -55.6% -34.1% -38.7%
This programme primarily consists of the installation of automatic and remote control switches and other
measures to improve the performance of the network. The DSO determined that the continuity improvement
projects intended for delivery in PR3 would be largely deferred and priority given to core capex activities that
addressed higher priority safety issues.
Distribution Automation: The original programme for the PR3 period consisted of the installation of 500
devices on the MV system as part of a widespread distribution remote control initiative. These devices were
planned to be installed by the DSO within a number of network schemes, located and set up to minimise the
length of network without supply in a fault situation.
The DSO reports that by late 2014 a total of 64 devices have been installed within the scope of 13 fully
operation integrated network schemes. In addition a further 184 devices have been installed in non-scheme
locations on the network. Although these do not provide automated sectionalising and back-feed within 3
minutes (in the event of a fault), they do provide the functionality that was planned at PR3 – in terms of more
network sectionalisation and remote control, thus reducing CI and CML respectively. Further schemes are in
progress and the DSO expects 50 more devices to be in operation by end of 2015. Prioritisation of network
schemes has been carried out by the DSO in order to derive maximum benefit from the significantly reduced
scale of this improvement programme. The DSO has observed an increased scope of works being necessary to
accommodate the automation devices. Additional switches have to be installed on either side of the vacuum
interrupters in order to provide points of isolation, increasing the unit cost of each device. The DSO also reports
additional time required to install and fully commission each of these devices.
The DSO has also installed a total of 27 remote controlled switches on the 38kV network.
Single Phase Reclosers: The DSO has reported that a very small quantity of single phase reclosers has been
installed on the MV network during PR3 approximately 130 forecast against a planned volume of 1,000. They
have also replaced approximately 65 obsolete reclosers (Type F4C).
Changes to 20kV neutral earthing system: The DSO programme to install arc suppression coils, whereby the
20kv transformer neutral point is earthed through a self-tuning arc suppression coil has continued during PR3.
The DSO reports that there are three 20kV arc suppression systems that are fully operational with a further two
constructed but not yet fully operational.
Worst Served Customers: Typically these customers are supplied on rural single phase overhead networks
and experience >=5 interruptions in the previous 12 month period and >=15 interruptions in the previous 3
years. In PR3 the DSO has introduced an initiative to address the “worst served customers”. The initiative
consists of necessary remediation works following line patrols and identification of root causes. Targeted
investments have been made to improve network continuity for 380 customers during PR3.
4.3.4 System Control Network Capex
The DSO has forecast a capex spend of €4.0m over PR3 period compared to CER allowances of €15.0m. This
represents a variance of 73%.The majority of expenditure relating to System Control is included within Non-
Network Capex – see Section 4.4.5
Network related expenditure for System control has been significantly deferred with the DSO indicating that the
deferred work will need to be progressed during PR4. This will be reviewed as part of the assessment of DSO
forecast capex.
4.4 Non Network Related Expenditure
The DSO non-network capex for the PR3 period is shown in Table 4.26 below.
DSO
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Table 4.26 : Comparison of PR3 Costs v CER Allowances –Non- Network Capex (€m 2009 prices)
Category 2011 2012 2013 2014 2015 5 Year Total
CER Allowed Capex 33.6 35.3 34.9 37.6 37.7 179.1
DSO Actual / Forecast 22.4 19.1 21.7 32.1 40.3 135.6
Variance -11.2 -16.2 -13.2 -5.5 2.6 -43.5
% Difference -33% -46% -38% -14.7% 6.9% -24.3%
The DSO has forecast a total capex of €135.6m by end of PR3 – this is €43.5mm lower than the CER allowed
Non-Network capex of €179.1m, representing a reduction of 24.3%.
The detailed breakdown of the Non Network Capex is shown below in Table 4.27.
In general the DSO has deferred expenditures in all areas, and has reprioritised expenditure in areas
necessary to maintain customer service, operations and legislative requirements. In most cases this
can be viewed as efficiency and indeed represents a lower than allowed expenditure while maintaining
network performance.
It is likely that there will some elements of catching up with the DSO capex submission for PR4.
Table 4.27 : Detailed Breakdown of PR3 Non-Network Capex (€m 2009 prices) by Category
Actual Spending Actual Allowed
2009 Prices PR3 PR3
2011 2012 2013 2014 2015 Total (5 year) Total (5 year)
€m €m €m €m €m €m €m
New Accommodation -
Accommodation Refurbishment 1.8 0.7 4.2 2.3 1.9 10.9 18.3
Fixture & Fittings 0.03 0.01 0.03 0.0 0.0 0.1 1.5
Office Equipment 0.01 0.00 0.00 0.0 0.0 0.0 0.5
Vehicles 2.3 0.7 0.3 11.5 19.5 34.2 35.0
Tools 3.0 2.6 4.1 3.6 1.9 15.2 15.6
Distribution Assets Management
7.6 8.9 8.4 8.3 8.1 41.3 69.6 Distribution Control / Operation
IT Infrastructure
Enterprise Applications
Environment 0.6 0.3 0.4 0.1 0.5 1.9 7.0
Telecoms & System Control 3.2 2.9 1.9 3.0 5.6 16.6 31.6
Non Rab Telecoms 3.8 3.2 2.5 3.1 2.7 15.3 -
Total 22.4 19.1 21.7 32.1 40.3 135.6 179.1
4.4.1 Accommodation Fixtures and Fittings and Office Equipment
The major emphasis during PR3 was to build on the work carried out during PR2 and focus on reducing costs
by the rationalisation of the number of depots and at the same time manage the ongoing maintenance of
existing depots in the Estate. A big emphasis was also placed on a consolidation process to reduce and
streamline the number of contractors who carry out maintenance work in the depots. Following the consolidation
process which is nearing completion the newly appointed contractors are carrying out safety risk assessments
DSO
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which will require significant capital expenditure to bring standards up to the required regulatory safety
standards. The allowed PR3 capex was €18.3 million and this is expected to outturn at €10.6 million.
4.4.2 Vehicles
As part of the allowances in PR3, the DSO proposed to reduce the fleet from 2,300 to 2,000 vehicles and
extend vehicle life to between 10 and 15 years, depending on vehicle model. This was expected to reduce the
number of vehicles replaced from 200 per year at €35m to 165 per year at a capital cost of €16.8m. Based on
historic costs this reduction appears to be reasonable. The extremely low expenditure in the first 3 years of the
review was due to funding constraints. Initial forecasts for PR3 within the DSO November 2014 submission
showed a forecast €16.8m for the PR3 period. This has subsequently been increased to €34.2m after
publication of the interim reports showing PR4 allowances. This major increase in spend forecast in 2014 and
2015 could be viewed as accelerated PR4 spend.
4.4.3 IT Systems
The IT programme was reprioritised to deliver the projects that provided the strongest customer and business
benefit. The main impact of this was the deferral of certain aspects of the Mobile Working programme
(€10.5m). This programme has been partially delivered in PR3 with further developments planned for the PR4
period.
The other main area of reduced expenditure related to planned upgrades to SAP and other Enterprise
applications with a forecast reduction of around € 11.3m. A decision was taken to defer the SAP ISU Upgrade
until the Smart Metering project requirements are finalised. The Customer Charter system upgrade has also
been deferred to PR4.
4.4.4 Environment
The total PR3 allowed expenditure was €7.0m. The total PR3 actual expenditure is forecast to be €1.9m giving
an associated under expenditure of €5.1m. This is primarily due to either zero or much lower expenditure in the
following areas:
1) Wood pole storage facilities - Nationally
2) Wood pole storage facility - Kilteel
3) Depot drainage infrastructural improvements
4) Oil filled equipment storage requirements at HV Stations
Capital rationing also had a significant effect on the PR3 outturn expenditure, as the Non Network related
expenditure was cut back during the period. The DSO believes that the impact of these reduced expenditures
will not have an adverse effect.
4.4.5 System Control and Telecoms
The significant approved expenditure areas in PR3 for System Control were OMS and DMS upgrades at
approximately €5m and RTU replacement at approximately €6m. It is likely that the majority of the OMS
upgrade project will be completed in PR3 with some Smart Networks enabling functionality deferred to PR4.
The PR3 RTU replacement programme will remain unspent in PR3 and will be submitted to CER for
consideration as a PR4 programme as part of the future submission.
Although the Allowed Expenditure in PR3 was €31.6 million, and the actual reported was €16.6 million, there
was also a reported €14.6 million expenditure on Non RAB Telecomm Expenditure. This was not defined as a
separate allowance in the initial review, but it is recognised that the Telecoms function provides a service across
all licensed businesses and the corporate functions of the group business.
DSO
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4.4.6 Smart Metering Expenditure
In the process of setting its allowances for the PR3 period, the CER requested the DSO to estimate the costs
that would be incurred during PR3 if the smart metering project was proved to be worthwhile. The DSO
estimated that a sum of €500m would be prudent. The CER subsequently included €500m as a provisional
amount for profiling purposes to ensure that if the smart metering project were progressed that there would be
no step change in the DuoS tariff.
DSO discussions with CER at the end of 2012 confirmed that the bulk of expenditure on the smart metering
project was likely to occur during PR4 period (and beyond). Consequently, the DSO is forecasting expenditure
during PR3 period that is significantly below the €500m provisional sum allowed for by CER.
The actual capex on Smart Metering for PR3 period is summarised in Table 4.28 below.
Table 4.28 : Smart Metering – DSO Capex during PR3 (€m – 2009 prices)
2011 2012 2013 2014 2015 PR3 Total
1.2 1.1 2.7 2.4 4.8 12.2
For PR3 the DSO Smart Metering project focus has been on defining the business, process, technical and
performance requirements, as well as strategies for sourcing delivery of its part of the overall National Smart
Metering Program.
The DSO has reported the following key activities progressed during PR3 period:
Development of strategy and approach to deliver and operate smart metering
Development of business and functional requirements for smart metering
Development of technical and security requirements for smart metering
Technology Trials and Studies
Conduct Networks Workshops and agree changes to Market Design
Prepare, Design and Conduct Major Procurements for Smart Metering – this activity will be the primary
focus for 2015.
Total PR3 smart meter capex of €12.2m is significantly below the original €500m provisioned by CER
and also substantially less than the €50m that the DSO had forecast in 2012 as part of the overall
capex re-profiling exercise carried out in consultation with CER. PR3 capex relates to the design and
procurement activity carried out by the DSO. These activities would generally fall into the
classification of enabling works associated with the roll-out of the Smart Metering capex programme.
4.5 Summary & Conclusions
4.5.1 Capex Overview
During the PR3 period, there are a number of significant factors that need to be considered when
assessing DSO outturn capex v CER allowed costs.
In consultation with the CER, ESBN Networks reduced the PR3 Gross Capex delivery programme in two
stages from the original CER allowed value of €4,200m to €2,400m (including Transmission Projects).
Given the reduction in peak demand during the PR3 period, together with pressure to reduce potential
increases on DUoS charges, the DSO considered it appropriate to critically review the network
requirements and the related project portfolio, allowing for deferment of reinforcement projects where the
resultant risks were considered acceptable to do so.
In headline terms, during PR3 the DSO is forecasting to invest net €1,075.3m on network and non-network
assets, which is €91.3m (9.3%)higher than its 2012 revised capex total of €984m (excluding Smart
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Metering and R&D costs associated with studying the impact of Electric Vehicles). Its latest forecast is
€637m (37%) lower than the CER allowed capital expenditure of €1,712m.
Due to the unique circumstances that were faced by the DSO in the period leading up and resulting in its
revised capex plans in 2012, it is considered appropriate to use the rebased 2012 capex forecast for
comparison throughout this report wherever possible, although, for completeness, reference is also made
to CER allowed values.
The DSO has been asked for more detailed breakdown of costs associated with the 2012 revised capex
plan broken down into an annual expenditure profile for each of the work programmes for which CER had
made allowances for the PR3 period. However, it is our understanding that this information is not available
due to the progressive and incremental nature of Capex assessment and reprioritisation over the 2012-
2015 period.
Consequently we have not been able to carry out a comparable analysis of DSO forecast v rebased 2012
capex at a work programme level and such analysis has therefore been carried out relative to CER allowed
capex for each defined category of capex.
4.5.2 Demand Connections
For Demand Connections, the total DSO Actual Capex (Gross) over the PR3 period is forecast to outturn at
€235.5m, this is €217.2m (48%) less than the CER Allowed capex. It is also €16.5m (6.6%) less than the
DSO Revised Capex Proposal of 2012.
The total DSO Actual Capex (Net) over the PR3 period is forecast to outturn at €123.2m, this is €103.1m
(45.6%) less than the CER Allowed capex.
Customer contributions of €112.3m for a gross expenditure on demand connections of €235.5m (gross)
resulted in a contribution ratio of 48% compared with the agreed rate of 50%. The DSO may need to revise
the Basis for Customer Connection Charges for future recovery of the agreed rate of 50% of total
connection charges, although we would expect any revision to be presented to the CER for review and
approval.
The main driver for this significantly lower capex, compared to the CER allowances, is the reduced number
of customer connections that have requested to be provided by the DSO over the PR3 period. Based on
the DSO latest forecast for 2014 and 2015, it is anticipated by the DSO that the 5-year total will outturn at
70,417. This is more than 86,000 (i.e. 55%) lower than the PR3 forecast connection volumes for the full 5-
year period.
CER should review the outturn costs for 2014 before finalising its allowances for PR3 period.
It is observed that the DSO total meter costs for PR3 period are 17.9% higher than the CER allowed costs.
This is despite a forecast reduction in connection volumes of 55% over the PR3 period. The DSO has
provided a detailed explanation to explain this apparent adverse variance. The closing of cost accounts
relating to dormant connection projects, to prevent misallocation of costs, has resulted in final connection
cost and the metering cost both being allocated to the metering cost code.
The analysis provided by the DSO supports the higher metering capex costs incurred during PR3. It is
important however that the assessment of PR4 allowed revenues for connections and metering takes due
account of the fact that a proportion of G1-G3 connections costs have been allocated to metering capex
during PR3.
4.5.3 Generator Connections
The DSO is forecasting to incur gross generation connections costs of €86.7m during PR3, representing an
underspend of €75.8m compared with the CER allowed gross capex of €162.5m. This DSO forecast is
€17.7m (25.7%) higher than the DSO Revised Capex Proposal of 2012.
Customer contributions for generation connections are forecast to be €96.7m, equivalent to a contribution
ratio (or recovery rate) of 112% compared with the allowed recovery rate of 100%.
This over-recovery of connection costs in PR3 will undoubtedly result in DSO net cash outflows during the
early years of PR4 period and this will need further consideration when reviewing the proposed DSO
forecast capex for PR4.
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4.5.4 Load Related Reinforcement
For load related reinforcement, the DSO forecasts a total capex of €316.9m by end of PR3 – this is
€315.7m lower than the CER allowed load-related reinforcement capex of €632.6m – representing a
variance of 50%.
This DSO forecast is approximately €39.9m higher than the revised proposal of ESBN (€277m) submitted
to CER in 2012.
The main drivers on load-related reinforcement expenditure are the growth in peak demand and energy
delivered (GWh). It is noticeable that from a total of circa 24,000 units in 2008, the DSO has experienced a
reduction to 23,000 GWh units in 2010, followed by a further reduction in actual units to circa 22,100 GWh
by 2013.
Similarly, the system peak demand has not increased in line with the DSO forecast for PR3. The peak in
2007/08 was 4,914 MW and the peak in 2013/14 has reduced to 4,523 MW.
As part of its response to the Business Plan Questionnaire, the DSO was requested to provide a
breakdown of planned v actual cost details of the major projects (38kV and above) that have been
progressed during PR3. This would have allowed us to carry out a more detailed analysis of a sample
number of projects completed during PR3. The purpose of carrying out a detailed analysis of a
representative sample of individual projects is to assess the reasonableness of costs incurred compared to
planned/allowed costs, the reasonableness of the DSO project delivery process and hence to determine
the efficiency of the DSO project delivery and resulting capex.
We have experienced significant delay in receiving the requested information for a sample of 11 major
projects expected to be completed during PR3. Both the delays in providing the required information and
the fact that information was only provided for a small sample of projects rather than all major projects is
disappointing. We would have expected the project information requested to be generally available within
the DSO and find the prolonged delay in providing this information to be a concern. – it is standard
information that we would expect the project managers and the DSO senior management team to be using
on a routine basis to manage and control project delivery and associated costs.
Given the time the DSO has had to provide such information, we consider that their inability to provide such
information to the CER in a timely manner to be an area of weakness that requires improvement during
PR4.
For 10 of the 11 projects, we have observed that the DSO is forecasting total costs (PR2 and PR3) that are
lower than the Capital Approval Amount – with variances in the range of €0.1m to €0.8m. For the remaining
major project (N-D-1027), we observe that the DSO is forecasting a total cost (PR2 and PR3) which is
higher than the Capital Approval amount by €1.0m.However as the lack of cost granularity has limited our
assessment on a constant 2009 price base, conclusions made from any comparison of projects costs need
to recognise this cost base inconsistency. We have not investigated the reasons behind any variance in
total costs v CA costs nor has the DSO provided any variance
It was also our intention to request a sample number of post investment appraisal document for a selection
of completed major projects. The DSO has advised us that they do not presently carry out a formal post
investment review of individual projects and hence no documentation was available for us to review.
We consider this gap to be an area for improvement within the DSO project delivery process – this has
been recognised by the DSO, who has stated their plans to introduce this improvement over the coming
months.
However, the DSO has provided a supporting narrative document (DH02 – PR3 Load Driven Programme)
that provides detailed commentary of investment during PR3 – this has allowed us to make a quantitative
assessment of non-financial project outputs.
Our analysis suggests that the reduction in DSO forecast capex for 110kV reinforcement projects is higher
than the equivalent volume reductions in transformer capacity or circuit km commissioned. It is expected
that this disparity will be partly due to a number of projects being completed in PR3 that commenced in
PR2 period; with the costs incurred on these projects during PR2 being added to the DSO RAB during
PR2.
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Further analysis of 38kV reinforcement projects suggests that the reduction in DSO forecast capex is
higher than the equivalent volume reductions in transformer capacity or circuit km commissioned. Similar to
110kV projects, it is expected that this disparity will be partly due to a number of projects being completed
in PR3 that commenced in PR2 period; the costs incurred on these projects during PR2 being added to the
DSO RAB during PR2.
Using the Planning policy (which permits 180% loading of single transformer nameplate rating under N-1
conditions for dual transformer stations), the DSO has forecast that a total of 48 of their population of 38kV
stations will be outside Planning Standards by the end of PR3 (rather than 32 loaded above nameplate
rating).
These stations will require further attention during PR4 and will be a consideration within the review of DSO
forecast capex.
The DSO has continued its programme to convert its 10kV network to 20kV operation, albeit at lower
volumes. The PR3 forecast volume for this activity was 15,000km. The DSO has reported that by the end
of PR3 a total of 10,000km will be converted to 20kV. The reduction in capex associated with the 20kV
conversion programme is consistent with the reduced circuit lengths converted during PR3 and it appears
to be efficiently incurred.
The DSO is forecasting that capex associated with other MV/LV System improvements during PR3 will
outturn at €33.6m. This is approximately 51% less than the CER allowed capex of €69.1m. The scale of
reduction in DSO capex during PR3 for MV/LV system improvements is consistent with the overall
reduction in PR3 load related reinforcement expenditure (being 50% of CER allowed capex).
4.5.5 Retirements (Dismantling) Capex
The DSO has continued its practice of charging dismantling costs to its Income Statement for years 2011
to 2013 and proposes a change in Accounting Practice for the remaining two years of PR3 such that the
costs are allocated to capital. Our analysis of DSO dismantling costs has been carried out on a total cost
basis. Total dismantling cost over the PR3 period is forecast at €47.1m, 17.9% less than the CER allowed
capex of €57.4m.
The DSO has introduced revised project costing procedures (Integrated Work Management Module) within
their SAP application from 2009 onwards. This has allowed the DSO to allocate dismantling costs more
directly to the work activity that has driven the need for the dismantling to be carried out.
We would generally agree with the DSO that the proportion of dismantling costs is likely to vary across
each of the work activities. The change in the DSO cost allocation procedures has provided improved
visibility of the drivers on the dismantling activity and associated costs
We would expect the DSO dismantling costs over the PR3 period to be charged to capex for the full five
years, this being consistent with CER allowances. This will result in a transfer of €28.4m of costs from opex
(2009 prices) to capex covering the years 2011 to 2013.
4.5.6 Diversions
Line diversion costs have historically been proportional to capital expenditure in the category of “gross new
demand connections”. For the PR3 period, this allowance was set at a value equivalent to 11.4% of the
PR3 forecast capex for new connections. The actual diversion costs over 2011 to 2013 are in the range of
19.2% to 21% of the gross connections capex over the same period. The DSO has provided an
explanation for this % increase in percentage costs experienced during PR3 and we consider this to be
reasonable.
In its response (DSO report DR01) to our Interim Report, the DSO provided the DSO revised forecast of
line diversions capex for the remaining two years of the PR3 period suggesting line diversion suggests
costs in the range of 20% for the remainder of PR3- these values are broadly consistent with the first three
years of PR3 and are considered reasonable.
4.5.7 Non-Load Related Capex
For non-load related capex, the DSO has forecast a total capex of €415.3m by end of PR3 – this is
€149.4m lower than the CER allowed load-related reinforcement capex of €564.7m – representing a
DSO
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variance of 26%. This DSO forecast is €29.4m higher than the revised proposal of ESBN (€387m45)
submitted to CER in 2012
It should be noted that this forecast includes for a one-off capex of €26.8m in 2014 associated with Storm
Darwin and it also includes a significant increase in capex for year 2015 (relative to 2012 and 2013).
Certain asset replacement projects were deferred in whole or were scaled down based on the DSO’s
prioritisation process.
For PR3, the allowed capex for HV Overhead Line Replacements was €16.3m and the DSO latest forecast
is €15.1m, representing 93% of allowed capex.
The DSO states that the 38kV OCR programme will be substantially completed, although this is dependent
on the delivery of 1,000km during Q4, 2014 and end of 2015. There is a significant risk that this volume of
work associated with the 38kV OCR programme is not delivered in 2015 – it represents a significant
increase in volumes previously delivered and is heavily dependent on contractor resources being in place
and fully operational. Whilst the DSO also acknowledges the 2015 volumes represent a significant increase
in the rate of delivery, it considers its 2015 forecast to be reasonable, citing contractor resource availability
to deliver the majority of the work programmes.
The reduction in capex by deferring 110kV line works has been largely offset by the additional capex
associated with 38kV copper overhead line replacements. Generally, the reduced costs in PR3 are broadly
consistent with the reduced PR3 volumes delivered
The DSO has deferred significant capex during PR3 associated with 110kV and 38kV cable replacement
projects. The reductions in work volumes stated by the DSO are broadly consistent with the reduced
capex.
The DSO has deferred a number of the higher cost HV station replacement projects / programmes
completely, whilst at the same time focussing on the substantial completion of various safety driven and
security driven programmes of work, typically of a much lower cost. These two factors contribute to an
overall underspend of PR3 capex of 36% relating to the HV Station renewal programme.
For the MV OCR programme, the DSO is forecasting the completion of 33,000 km by end of PR3 (i.e. 73%
of the original target (45,000km) upon which allowances were made, .although it forecasts a spend of 86%
of the PR3 allowance. This increase in unit costs is being driven by higher labour costs being forecast in
2014 and 2015 - associated with more stringent pole testing procedures.
The forecast includes a target of 14,500km being delivered in 2015 alone, predominantly by using contract
resources, this being subject to completion of the tendering and contract procedures. Achieving the 2015
target volumes is therefore considered to be a significant challenge to the DSO.
The DSO is forecasting that approximately 10km of MV cable to be replaced by 2015 – representing an
under-delivery of about 33%, broadly in line with the forecast underspend.
In relation to the MV Station Renewal Programme, the DSO is forecasting an overspend in this category of
27%. Any expected reductions in capex due to the reduction in volumes for many of the categories have
been largely offset by increased costs associated with the higher volume of work associated with the
Magnefix Cast Resin Switchgear programme.
The plan for PR3 period was to refurbish 35,000 spans of LV urban networks. The DSO is forecasting that
less than 50% (~17,000km) of the programme will be completed during PR3 period. The percentage
reduction in capex for the Urban LV Renewal programme is broadly consistent with the equivalent
reduction in work volumes.
For the Rural LV Network Renewal Programme, the reduction in the volume of works compared to PR3
programme (approximately 20%) is higher than the reduction in the Capex (6%) suggesting increase in unit
costs. Of the 20,000+ Groups refurbished during PR3, the DSO has selected more than 1,800 Groups that
were prioritised and selected for refurbishment in conjunction with other works to improve network
performance and power quality, with significantly higher unit costs than the basic fabric only refurbishment
works.
45 €433m less forecast retirement costs (considered separately) of €46m
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For the LV Cable Renewal Programme - the DSO current forecast for this programme is €6.1m against the
CER PR3 allowed capex of €16.8m. During PR3, the LV cable programmes have been subject to a
significant reduction in order to reduce impact on DUoS charges.
For the Renewal Programme associated with cutouts, the PR3 programme consisted of the planned
replacement of 40,000 pre 1976 indoor cut-outs. This is a continuation of works from PR2 cut-out
replacement programme. The DSO is forecasting to replace up to 30,000 cut-outs by the end of 2015.
(75% of the original target)
For Response Capex, CER PR3 allowed capex of €98.7m, although the DSO forecast for this programme
is €53.055.1m (representing an underspend of 44%). The area of largest underspend relates to voltage
complaints where the DSO is forecasting a €16.4m variance to CER allowances. The reduced investment
in this category over PR3 period is likely due to a number of factors, such as reduced demand, impact of
MV and LV network renewal, 20kV conversion programmes and replacement of small capacity
transformers in rural areas. A total of 2,748 voltage complaints were resolved during PR3 period up to the
end of 2014. This is noticeably less than the 9,570 voltage complaints resolved during PR2.
In its response to our PR4 capex IR, the DSO explained the need for urgent works that are scheduled for
2015 to address risks associated with the theft of 50mm2 Copper conductor from 4 x 38kV overhead line
circuits. The works involved replacement of the copper conductor with aluminium conductor (of equivalent
rating) and the estimated capex for this new work programme is €2.0m in 2015.
The DSO is forecasting capex relating to the Continuity programme of €13.7m, which is approximately 39%
less than the CER allowed costs of €22.3m. This programme primarily consists of the installation of
automatic and remote control switches and other measures to improve the performance of the network,
The DSO determined that the continuity improvement projects intended for delivery in PR3 would be
largely deferred and priority given to core capex activities that addressed higher priority safety issues.
4.5.8 Non-Network Capex
For non-network capex, the DSO has forecast a total non-network capex of €135.6m by end of PR3 – this
is €43.5m lower than the CER allowed Non-Network capex of €179.1m, representing a variance of 24.3%.
In general the DSO has deferred expenditures in all areas, and has reprioritised expenditure in areas
necessary to maintain customer service, operations and legislative requirements.
In most cases this can be viewed as efficiency and indeed represents a lower than allowed expenditure
while maintaining network performance. It is likely that there will some elements of catching up with the
DSO capex submission for PR4.
Total PR3 smart meter capex of €12.2m is significantly below the original €500m provisioned by CER and
also substantially less than the €50m that the DSO had forecast in 2012 as part of the overall capex re-
profiling exercise carried out in consultation with CER. PR3 capex relates to the design and procurement
activity carried out by the DSO. These activities would generally fall into the classification of enabling
works associated with the roll-out of the Smart Metering capex programme.
DSO
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5. Review of PR4 Capital Expenditure
This section reviews the DSO’s proposed capital expenditure for the PR4 period (2016 to 2020) compared
with the PR3 (2011 to 2015) expenditure allowed by CER in the PR3 decision paper46, the rebased PR3 plan
from 2012 and the DSO forecast expenditure for the PR3 period47.
Table 5.1 below details the DSO’s proposed capex for each of the defined capex categories whilst Figure 5.1
presents the PR4 totals in graphical format. For completeness, the table shows the DSO original forecast for
PR4 capex submitted in November 2014, together with its updated PR4 forecast capex – issued in March
2015. This updated forecast was issued in response to our DSO Forecast Capex Interim Report.
Table 5.1 : DSO PR4 Capex Summary by Expenditure Category (€m – 2014 prices)
Capex
Investment
Category
PR3
Allowed48
PR3
Revised
Proposal
(2012)
PR3
Actual49
PR4
Proposed50
Revised
PR4
Proposed51
Variance: Revised
PR4 Proposed v
PR3 Allowed
Variance: Revised
PR4 Proposed v
PR3
Actual/Forecast
€m % €m %
Load Related
Capex 1390.4 665.9 751.3 894.8 853.1 -537.3 -38.6% 101.8 13.6%
Non-Load Related
Capex 578.5 443.6 425.4 694.4 671.0 92.5 16.0% 245.6 57.7%
Non-Network
Capex 183.5 98.4 138.9 172.4 172.2 -11.2 -6.1% 33.4 24.0%
Other Capex –
Smart Metering - 51.2 12.9 22.9 22.9 22.9 - 10.0 77.5%
Customer
Contributions -398.3 -199.8 -198.5 -240.1 -238.2 160.1 -40.2% -39.7 20.0%
TOTAL NET
CAPEX 1754.1 1059.3 1130.1 1544.3 1481.0 -273.1 -15.6% 351.0 31.1%
46 CER/10/198 - Decision on 2011 to 2015 distribution revenue for ESB Networks Ltd 47 Actual Expenditure in 2011 to 2014 and forecast expenditure in 2015. 48 Excluding Smart Metering Capex of €500m (2009 prices) 49 Includes €29.1m Dismantling Costs for period 2011 to 2013 allocated by DSO as Capital Driven Opex ; Excludes Interest During Construction
(IDC) Charges 50 DSO Proposal for PR4 Capex received by Jacobs on 21st November 2014 - Excludes IDC Charges 51 DSO Revised Proposal for PR4 Capex received by Jacobs on 25th March 2015 – Excludes IDC Charges
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Figure 5.1 : DSO PR4 Capex Summary – Net Costs (€m 2014 prices)
The DSO’s revised PR4 forecast can be described in headline terms by the following characteristics:
With regard to Demand Connections, the DSO is forecasting a total number of connections in PR4 of
108,000. This represents an increase of 53% compared to the total of 70,417 during PR3, but is still
only 33% of the total number of connections made during PR2.
The DSO is forecasting 0% cumulative growth in peak demand during PR4. Reinforcement expenditure
during PR4 is focused on addressing parts of the system which do not presently comply with the
Planning Standards.
Capex (gross) associated with generator connections is forecast to increase by 23% from €88.9m in
PR3 to €109.5m in order to connect a total of 1,250 MW of renewable generation over the PR4 period
(compared to 1,200 MW expected by the end of PR3).
Capex associated with non-load related projects and programmes is the category where the DSO is
forecasting the largest increase in capex in PR4 compared to PR3 with a variance of €245.6m (around
57.7%). The renewal programmes for which the DSO has forecast the largest increases in capex in PR4
relate to HV Station works and HV and MV overhead line works. The DSO’s plans are focused on the
replacement of aging and defective assets. The DSO advises that much of this work has been carried
over as financially deferred work from PR3.
In addition, the DSO has included €87.6m of PR4 capex relating to the North Atlantic Green Zone
(NAGZ) smart grid initiative.
The forecast increase in PR4 non-network capex (of 24%) is driven by increased expenditure on
vehicles, Distribution Asset Management (including IT infrastructure), Telecoms and System Control.
In relation to the Smart Metering project, the DSO submission for PR4 includes for further development
and project costs necessary to take the project to the next major milestone in 2017. It does not include
capex associated with a country-wide roll out programme as the final investment decision has not yet
been taken.
In headline terms, the DSO is forecasting a total gross expenditure of €1.72bn. This is €433m (20%)
lower than PR3 allowed capex and €391m (29%) higher than PR3 actual/forecast capex.
Net of customer contributions, the DSO is forecasting total PR4 capex of €1.48bn – this is €273m lower
than PR3 allowed capex and €351m higher than PR3 actual/forecast capex.
1,754
1,059
1,130
1,481
0
500
1000
1500
2000
5 Year Total
€m
PR3 Allowed 2012 Rebased Plan PR3 Actual PR4 Revised Forecast (April 2015)
DSO
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Figure 5.2 below presents the DSO net capex for PR4 on an annual basis (excluding IDC). It is noted that
the financial situation in PR3 reduced capex in the 2012-2014 period, with the DSO forecasting an increase
in net capex in the final year of PR3 due to somewhat more relaxed financial markets. Capex in 2016 is
forecast to increase to above €300m, some 5% higher than 2011 levels. Capex during PR4 is forecast to be
fairly consistent, although falling slightly over the period.
Figure 5.2 : DSO Annual Capex Profile (Net - €m – 2014 prices)
Each of the capex categories itemised above is considered in further detail within the following sections of
the report. Capex relating to New Business, Generation Connections, Line Diversions and Distribution
Reinforcement is discussed in Section 5.1 whilst capex relating to Non-load related and Asset Replacement
is discussed in Section 5.2. Non network related capex is discussed in Section 5.3.
5.1 Load Related Expenditure
A breakdown of the DSO’s total Load Related Capex for the PR4 period is presented below in Table 5.2.
Table 5.2 : DSO PR4 Load Related Capex - Gross (€m – 2014 prices)
Category
PR3 Allowed
PR3 Actual
PR4 Requested
Revised PR4
Requested
Variance Revised PR4
Requested v PR3 allowed
Variance Revised PR4
Requested v PR3 actual/forecast
€m €m €m €m €m % €m %
(G1) New housing Schemes 74.6 16.7 46.5 44.2 -30.4 -40.8% 27.5 164.5%
(G2) Non-scheme Houses 164.4 89.0 106.1 107.7 -56.7 -34.5% 18.7 21.0%
(G3) Commercial/Industrial Supplies
212.5 120.8 128.5 129.8 -82.7 -38.9% 9.0 7.4%
Whole Current Metering 12.5 14.7 24.1 19.5 7.0 56.3% 4.8 32.6%
New Business – Demand Connections
464.0 241.2 305.2 301.2 -162.8 -35.1% 60.0 24.9%
Transmission Connection Costs
26.3 0.0 15.2 15.2 -11.1 -42.3% 15.2 -
110kV reinforcements 236.1 144.4 150.4 150.4 -85.7 -36.3% 6.0 4.2%
38kV reinforcements 215.2 86.5 85.9 85.9 -129.4 -60.1% -0.6 -0.7%
292
183173
217
265
305 303297
283293
0
100
200
300
400
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
€m
PR3 Actual PR4 Revised Forecast (April 2015)
DSO
Page 104
Category
PR3 Allowed
PR3 Actual
PR4 Requested
Revised PR4
Requested
Variance Revised PR4
Requested v PR3 allowed
Variance Revised PR4
Requested v PR3 actual/forecast
€m €m €m €m €m % €m %
MVLV System Improvements 70.8 34.5 40.9 40.9 -29.8 -42.2% 6.5 18.8%
IFTs associated with 20kV Conversion
16.6 22.9 0.0 11.1 -5.5 -33.1% -11.8 -51.6%
20kV Conversion 83.0 36.5 25.4 14.3 -68.7 -82.8% -22.2 -60.8%
Reinforcements 648.1 324.7 317.8 317.8 -330.3 -51.0% -6.9 -2.1%
Generation Connections 166.5 88.9 109.5 109.5 -57.0 -34.2% 20.6 23.2%
Dismantling 58.8 48.3 70.2 64.4 5.6 9.6% 16.2 35.5%
Non-Repayable Line Diversions
53.1 48.3 92.1 60.2 7.1 13.4% 11.9 24.6%
Total Load Related CAPEX - GROSS
1390.4 751.3 894.8 853.1 -537.3 -35.6% 101.8 19.1%
Each of the categories presented in the table above is reviewed in detail below.
5.1.1 PR4 New Demand Connections
The DSO PR4 forecast capex relating to new demand connections is presented below in Table 5.3.
Table 5.3 : DSO Capex – Demand Connections: comparison of PR4 Capex with PR3 (€m – 2014 prices)
PR3 Allowed
PR3 Actual
PR4 Requested
Revised PR4
Requested
Variance Revised PR4
Requested v PR3 allowed
Variance Revised PR4
Requested v PR3 actual/forecast
€m €m €m €m €m % €m %
(G1) New housing Schemes 74.6 16.7 46.5 44.2 -30.4 -40.8% 27.5 164.5%
(G2) Non-scheme Houses 164.4 89.0 106.1 107.7 -56.7 -34.5% 18.7 21.0%
(G3) Commercial/Industrial Supplies
212.5 120.8 128.5 129.8 -82.7 -38.9% 9.0 7.4%
Whole Current Metering 12.5 14.7 24.1 19.5 7.0 56.3% 4.8 32.6%
New Business – Demand Connections
464.0 241.2 305.2 301.2 -162.8 -34.2% 60.0 24.9%
Customer Contributions - Demand Connections
-232.0 -104.6 -152.6 -150.652 81.4 -35.1% -46.0 44.0%
Demand Connections Capex - NET
232.0 136.7 152.6 150.6 -81.4 -35.1% 14.0 10.2%
The DSO PR4 forecast capex (gross) is €301.2m. This is €60.0m (25%) higher than the expected PR3
outturn total capex of €241.2m. Net of customer contributions, the DSO PR4 forecast capex is €150.6m,
some €14.0m (10%) higher than expected PR3 outturn. Customer contributions are based on standard
costs for each type of connection and metering, with the customer being charged 50% of the standard costs.
Recovery of contributions during PR3 period was 45%.
The increase in gross capex as forecast by the DSO for the PR4 period is based on an increased number of
connections for each of G1/G2/G3 categories.
Details of the DSO forecast connection volumes are presented below in Table 5.4 and Figure 5.3. The DSO
forecast is based on a slow recovery within the Irish Economy, and growth projections based on increases in
population, declining emigration and Government support in financing programmes for the construction of
52 DSO has submitted a supplementary report “titled DR06 Addendum Contributions” – this identifies €150.6m of contributions relating to demand
connections for PR4, based on 50% of new demand connection costs of €301.2m. It further identifies €62.0m of contributions relating to generator connections and €22.2m of Grants relating to the NAGZ. This results in total contributions during PR4 of €234.9m. However, we note Table 6.3 (April 2015 version) states total PR4 contributions of €238.2m.
DSO
Page 105
affordable housing, in line with recent announcements53. Steady connection growth during PR4 is forecast by
the DSO and a total of 108,000 connections are expected to be made over this period, representing a 53%
increase on the total number of connections throughout PR3.
Table 5.4 : Connections made to DSO Network over period 2006 to 2020
Figure 5.3 : Connections to DSO Network over period 2006 to 2020
In order to evaluate the reasonableness of the DSO forecast of connection volumes for PR4, we have
carried out an econometric assessment of the data by connection category (G1, G2 and G3) against various
combinations of GDP and Population data (taken from the World Bank and IMF databases) covering the
historic period 2006 to 2015, with forecasts covering 2016 to 2020.
This analysis indicates that under all reasonably identifiable relationships, the forecast number of new
connections by the DSO appears to be on the lower side when compared to outputs from our analysis,
maybe representative of being conservative but not unreasonable.
The GDP and population growth forecasts for the period 2016 to 2020 that we have used in our assessment
are presented below in Table 5.5.
Table 5.5 : IMF / World Bank Econometric Growth Indicators54
Category 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Population (Millions) 4.58 4.59 4.78 4.81 4.83 4.88 4.92 4.97 5.01 5.05
Population % Growth 0.4% 0.2% 4.2% 0.6% 0.6% 0.9% 0.9% 0.9% 0.9% 0.8%
GDP (€b – 2014 Prices) 173.3 172.8 173.1 179.3 184.8 189.5 194.5 199.4 204.5 210.3
GDP % growth 2.8% -0.3% 0.2% 3.6% 3.0% 2.5% 2.6% 2.5% 2.5% 2.8%
The number of new connections (residential in particular - G1 and G2) can be linked to other factors such as
Government policy and house prices (as indicated in the ESBN document ‘DH05 New Connections’, page 6)
and these factors have not been considered in our econometric analysis. Nevertheless, the IMF and World
53 Government Announcement of 14 Oct 2014 that €2.2bn of funding is to be made available for major social housing development. 54 International Monetary Fund, World Economic Outlook Database, October 2014
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
G1 69,406 59,297 33,800 14,224 9,000 3,913 3,267 3,555 5,091 5,937 7,000 8,500 9,500 11,500 13,500
G2 21,959 19,802 17,596 12,257 9,867 6,494 5,155 4,730 4,877 4,877 5,500 6,000 6,500 7,000 7,500
G3 13,762 15,301 13,654 8,370 7,473 4,714 4,378 5,543 3,894 3,992 4,500 4,500 5,000 5,500 6,000
Total Connections 105,127 94,400 65,050 34,851 26,340 15,121 12,800 13,828 13,862 14,806 17,000 19,000 21,000 24,000 27,000
5 Year PR Total 108,000325,768 70,417
Connection
Category
Actual * Forecast
PR2 PR3 PR4
0
20,000
40,000
60,000
80,000
100,000
120,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Nu
mb
er
of
Co
nn
ec
tio
ns
PR2 Actual PR3 Actual PR4 Forecast
325,768
70,417108,000
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000N
um
be
r o
f C
on
ne
cti
on
s
5-year PR2 total 5-year PR3 total 5-year PR4 forecast
DSO
Page 106
Bank are expecting an upturn in fortunes for the Irish economy (and population growth) and the DSO
forecast connections volumes do not seem to fully reflect this expected up-turn in recovery/growth.
The connection numbers in each category do however, increase year on year through PR4 (G1 increasing
from 7,000 connections in 2016 to 13,500 in 2020; G2 increasing from 5,500 connections in 2016 to 7,500 in
2020; G3 increasing from 4,500 connections in 2016 to 6,000 in 2020), reflecting the increased confidence
associated with a sustained economic recovery.
Based on the above analysis, we consider that the DSO PR4 forecast of new connections of 108,000
is a reasonable assumption for tariff purposes, recognising that CER will make adjustments for
higher or lower connections based on allowed unit costs.
5.1.1.1 New Demand Connections - Unit Costs
In its original PR4 forecast submission, the DSO has proposed standard unit costs for each of the G1/G2/G3
connections. These unit costs proposed for PR4 period are presented below in Table 5.6.
Table 5.6 : Connections: Originally Proposed DSO PR4 Units Costs (€ - 2014 prices)
Connection Category 2016 2017 2018 2019 2020
G1 - Scheme Housing 905 904 926 947 947
G2 - Non Scheme Housing 3,174 3,166 3,256 3,340 3,339
G3 - Non Domestic 4,935 4,925 5,027 5,125 5,127
The following assumptions have been applied by the DSO in establishing these unit costs:
To address lower PR3 outliers and higher PR2 outliers in the range of historic unit costs, the DSO has
taken the long term average as the basis for deriving unit costs in the submission, using average prime
costs over the period 2006 to 2013.
The application of company overheads to establish gross unit costs
Smart meter penetration in PR4 connections has been assumed to be 0% in years 2016 and 2017, 50%
in 2018 and 100% in 2019 and 2020.
Average additional unit cost (prime) per G1/G2 smart meter is €80.50 plus 10% on-cost and €38.00 per
G3 smart meter (these are estimated values in advance of tender/procurement process).
Within the DSO response to a subsequent query (DSO.016.FCA), the DSO provided a revised set of unit
costs (excluding smart metering) and these are itemised in Table 5.7 below.
Table 5.7 : Connections: Revised Proposed DSO PR4 Units Costs (€ - 2014 prices)
Connection Category Cost (€)
G1 Scheme Housing 883
G2 Non Scheme Housing 3,315
G3 Non Domestic 5,090
The DSO stated that the unit costs would not vary over the PR4 period year on year but did not provide
explanation of the changes in unit costs from its original submission (as per Table 5.6) and its revised unit
costs (as per Table 5.7). In such absence, we have carried out our analysis relative to the unit costs
presented in Table 5.6.
We have reviewed unit costs for each of the G1-G3 connections over the PR2/PR3 period and analysed the
movement in costs over the period. We considered a number of different approaches including the use of
median values, rather than simple average values in order to assess impact of outliers over the assessment
period. However, this approach did not result in any reductions to unit costs.
DSO
Page 107
We have concluded that the proposed DSO unit costs for 2016 and 2017 are reasonable. However
we recommend that the additional costs that the DSO has factored in to its original unit cost
calculation from 2018 onwards should be removed, this being consistent with the DSO a priori
assumption that its forecast does not include for the introduction of smart metering. In its response
to our Interim Report, the DSO agreed with this approach
We therefore propose to adjust the DSO unit costs presented in Table 5.6 from 2017 onwards to:
Remove the additional unit costs associated with smart metering
Apply incremental reduction to the gross costs from 2018 to 2020 on the same basis as applied by the
DSO in its adjustment to gross unit costs between 2016 and 2017.
These adjustments result in proposed unit costs set out in Table 5.8 below.
Table 5.8 : Recommended Unit Costs for PR4 compared to DSO Unit Costs (€ - 2014 prices)
Category DSO Unit Costs Recommended Unit Costs
2016 2017 2018 2019 2020 2016 2017 2018 2019 2020
G1 Scheme Housing 905 904 926 947 947 905 904 903 902 901
G2 Non Scheme
Housing 3,174 3,166 3,256 3,340 3,339 3,174 3,166 3,158 3,150 3,142
G3 Non Domestic 4,935 4,925 5,027 5,125 5,127 4,935 4,925 4,915 4,905 4,895
Applying the unit costs provided in table 5.7 to the DSO forecast connection volumes will result in the revised
capex shown in Table 5.9 below.
Table 5.9 : Demand Connections – Recommended Capex (€m – 2014 prices))
2016 2017 2018 2019 2020
TOTAL - PR4
Recommended
PR4 - DSO
Forecast
PR4 – Revised
DSO Forecast
G1 Scheme Housing 6.3 7.7 8.6 10.4 12.2 45.1 46.5 44.2
G2 Non Scheme
Housing 17.5 19.0 20.5 22.1 23.6 102.6 106.1 107.7
G3 Non Domestic 22.2 22.2 24.6 27.0 29.4 125.3 128.5 129.8
Total Expenditure 46.0 48.8 53.7 59.4 65.1 273.0 281.1 281.7
A reduction in allowed PR4 gross capex of €8.7m (relative to the DSO’s revised forecast) is
recommended for PR4 demand connections, based on the exclusion of the DSO’s provision for roll
out of smart meters within the connections activity.
5.1.1.2 Analysis of PR4 meter costs
For PR4 the DSO is forecasting total metering capex of €19.5m. This is €4.8m (32.6%) higher than PR3
expected outturn costs and €7m (56.3%) higher than PR3 allowed costs. A comparison of DSO metering
costs is provided below in Table 5.10. The proposed increase in capex for PR4 is the result of the DSO’s
forecast increase in connection volumes.
Table 5.10 : DSO PR4 Forecast Metering Costs (€m – 2014 prices)
Category PR3 Allowed PR3 Actual
DSO Original
PR4 Proposed
DSO Revised PR4
Proposed
Metering – G1 Domestic - Scheme 5.2 Not itemised
DSO
Page 108
Category PR3 Allowed PR3 Actual
DSO Original
PR4 Proposed
DSO Revised PR4
Proposed
Metering – G2 Domestic Non-Scheme 15.3
Metering – G3 Non-Domestic 3.5
Total Metering 12.5 14.7 24.1 19.5
The CER allowed metering costs in PR3 were based on an average unit cost of €87 (2014 prices) for whole
current metering.
Our review of PR3 capex identified that actual metering costs over the period 2011 to 2013 resulted in
average costs that were significantly higher than the CER allowed costs, with average metering costs in the
range of €178 to €218. The DSO provided a detailed explanation to explain this apparent adverse variance
and this was reviewed during our assessment of DSO historic capex. Specifically, the closing of cost
accounts relating to dormant connection projects, to prevent misallocation of costs, has resulted in final
connection cost and the metering cost both being allocated to the metering cost code, resulting in an
increase in metering costs.
We concluded that the analysis provided by the DSO supports the higher metering capex costs incurred
during PR3. We also stated the importance that the assessment of PR4 allowed revenues for connections
and metering takes due account of the fact that a proportion of G1-G3 connections costs have been
allocated to metering capex during PR3. The lack of transparency in metering costs during PR3 has resulted
in PR4 forecast metering capex including an element of connection costs within the totals.
In its response to our Interim Report relating to PR4 forecast expenditure, the DSO has stated:
“While ESBN is undertaking a project at present to better identify the specific costs associated with metering
as opposed to other works, it is important that any reduction in the PR4 allowed metering cost (on the
premise of metering only being allowed in the proposed unit cost) would be accompanied by corresponding
increases in the allowed cost of new connections such that the total allowed expenditure is based on the
complete costs of previous years. Alternatively, an allowed unit cost based on the historical information used
and provided by ESBN is appropriate, on the premise that under certain circumstances final connection
works are completed as part of an integrated project cost”.
The DSO PR3 metering costs of €14.7m equates to 6.5% of the PR3 gross capex of €226.5m relating to
G1/G2/G3 connections. For PR4 period, the DSO proposed metering costs of €19.5m equates to 6.9% of
the PR4 gross capex of €281.7m relating to G1/G2/G3 connections.
We recommend allowances for PR4 period based on 6.5% of our recommended PR4 gross capex
for G1/G2/G3 connections of €273m.
This results in a recommended allowance for metering of €17.8m representing a reduction of €1.8m
compared to DSO revised PR4 proposed capex of €19.5m.
We would encourage the DSO to complete the project relating to the more accurate allocation of
costs associated with metering. This should be completed as a matter of priority early in the PR4
period.
5.1.2 Generator Connections55
For generator connections the DSO is forecasting gross capex in PR4 of, in headline terms, €109.5m (as
shown below in Table 5.11). This represents an increase of 24.4% compared to expected PR3 outturn.
Table 5.11 : New Connections Capex (Generator Connections) – Comparison of PR3 v PR4 Forecast (€m – 2014 prices)
Category PR3 PR3 DSO PR4 Variance PR4
Requested v PR3
Variance PR4
Requested v PR3
55 Note for Capex associated with Generator Connections, The DSO revised capex (issued March 2015)for the PR4 period is the same as its
original capex (issued in November 2014)
DSO
Page 109
Allowed Actual Proposed allowed actual/forecast
€m % €m %
Generation Connections – Gross Capex 166.5 88.9 109.5 -57.0 -34.2% 20.6 23.2%
During PR3, approximately 1,200 MW of renewable generation was connected to the DSO distribution
system. During the PR3 period, the CER approved a suspension of the expiry dates on the issued Gate 3
connection offers until issues regarding constraints and curtailment of wind were fully resolved. This
resolution came in the form of a SEM decision in March 2013, and all applicants were provided with
constraint and curtailment levels applicable to their projects.
Consequently most of the Gate 3 offers were accepted during the summer of 2013 and the DSO expects
significant activity in the latter part of PR3 and into PR4. Gate 3 projects entered design and scoping phase
during 2014-2015 and this is forecast to continue into 2015 and the DSO expects construction works to
commence from 2016 on large numbers of these projects. Capex during PR4 will therefore be focused on
these Gate 3 projects that have contracted since mid-2013. The DSO is estimating that a total of 1,250 MW
is to be connected to the distribution system during PR4, a similar magnitude to the capacity connected
during PR3 (1,200 MW). The estimated PR4 aggregate capacity is less than the current level of contracted
generation as the DSO is not expecting all contracted Gate 2 / Gate 3 connections will progress to
completion and there is some uncertainty about which projects will proceed to completion by 2020.
The developer for a proposed wind farm also has the option to follow a contestable path relating to the
connection to the DSO network (excluding non-contestable works). This choice is available to the developer
until the latter stages of the overall connection process (but always pre-construction commencement) and
such late decisions can impact on project scope, cost and timescales. This situation makes a simplified
comparison of the PR3 Actual and PR4 proposed costs/MW somewhat inappropriate at the present time.
The DSO forecast has taken into account the projects which are contestable and also those where
contestability is anticipated (e.g. where a modification to the connection application is in progress). Of the
Gate 3 projects in progress, the DSO has advised that approximately 60% are being contested (i.e. shallow
works) and for each project, some element of work, classed as non-contestable will be necessary.
The high volume of accepted connection offers in the summer of 2013, coupled with the requirement to meet
the REFIT56 deadline for completed connections by end of 2017, results in the forecast capex/ contributions
presented below in Table 5.12 and Figure 5.4.
Table 5.12 : New Business (Generator connections) – PR4 forecast cash flow (€m – 2014 prices)
Generator Connections 2016 2017 2018 2019 2020 PR4 Total
Gross Capex 49.4 32.9 8.8 8.8 9.6 109.5
Customer Contributions57 -27.9 -18.6 -5.0 -5.0 -5.6 -62.0
Net Capex 21.5 14.3 3.8 3.8 4.0 47.4
56 REFIT II – Renewable Energy Feed In Tariff – Incentive to promote development of renewable energy projects which provides price
guarantees for 15 years. Criteria includes requirement for connection by end of 2017. 57 DSO Supplementary Report titled “DR06 Addendum Contributions” confirms €62.0m of contributions relating to generator connections – this
figure being consistent with Table 6.4 of the DSO FBPQ
DSO
Page 110
Figure 5.4 : New Business (Generator connections) – PR4 forecast cash flow (€m – 2014 prices)
The DSO forecast has been compiled based on the likely progression of accepted offers, and is consistent
with the high level of expenditure forecast for 2015. Due to the profiling of customer contributions versus
capital expenditure it should be noted that there was a level of over-recovery in PR3 which is reflected in a
degree of under-recovery being forecast for PR4.
As expected in our review of DSO historic capex, the over-recovery of connection costs in later years
of PR3 is resulting in net positive cash flows throughout the PR4 period, with a total net capex over
PR4 period of €47.4m.
We recommend acceptance of the DSO proposal for gross capex of €109.5m
5.1.3 Load Related Reinforcement
The DSO load-related reinforcement capex for the PR4 period is shown in Figure 5.5 below showing a total
PR4 reinforcement capex of €317.8m. Although this is significantly below the PR3 allowed capex of
€648.1m, it is only €6.9m (2.1%) lower than DSO expected outturn (€324.7m) for the PR3 period.
Table 5.13 details capex for each of the defined reinforcement categories.
49.4
32.9
8.8 8.8 9.6
-27.9
-18.6
-5.0 -5.0 -5.6
-40.0
-30.0
-20.0
-10.0
0.0
10.0
20.0
30.0
40.0
50.0
60.0
2016 2017 2018 2019 2020
Gross Capex Customer Contributions Net Capex
DSO
Page 111
Figure 5.5 : PR4 DSO Reinforcement Capex compared to PR3 (€m – 2014 prices)
Table 5.13 : Comparison of PR4 Forecast v PR3 Capex – Load Related Reinforcement (€m 2014 prices)
PR3
Allowed
PR3
Actual
DSO
Original
PR4
Proposed
DSO
Revised
PR4
Proposed
Variance Revised
PR4 Proposed v
PR3 allowed
Variance Revised
PR4 Proposed v
PR3
actual/forecast
€m % €m %
Transmission Connection
Costs 26.3 0.0 15.2 15.2 -11.1 -42.3% 15.2 -
110kV Reinforcements 236.1 144.4 150.4 150.4 -85.7 -36.3% 6.0 4.2%
38kV Reinforcements 215.2 86.5 85.9 85.9 -129.4 -60.1% -0.6 -0.7%
MVLV System Improvements 70.8 34.5 40.9 40.9 -29.8 -42.2% 6.5 18.8%
IFTs associated with 20kV
Conversion 16.6 22.9 0.0 11.1 -5.5 -33.1% -11.8 -51.6%
20kV Conversion 83.0 36.5 25.4 14.3 -68.7 -82.8% -22.2 -60.8%
Total Reinforcements 648.1 324.7 317.8 317.8 -330.3 -51.0% -6.9 -2.1%
The main drivers for reinforcement expenditure relate to growth in peak demand and the requirement of the
DSO to comply with the Planning Standards for Security and Voltage. The DSO’s proposed PR4
reinforcement capex forecast has been prepared on a zero cumulative load growth forecast for peak demand
from 2013 to 2020. Factors cited by the DSO which will contribute to this zero growth scenario include:
648
325 318
0
200
400
600
800
5 Year Total
€m
PR3 Allowed PR3 Actual PR4 Revised Forecast (April 2015)
DSO
Page 112
Smart Metering rollout should divert load from peak time to less expensive lower demand periods with
an associated reduction in the longer term drivers for network reinforcement58.
Increasing trend in the production of energy efficient appliances will also contribute to the containment
of peak growth.
20kV conversion plan will reduce losses on the network, most significantly at time of peak but will not
impact on end user consumption.
The recorded system peak demand over the period to 2013 is shown below in Figure 5.6. The peak demand
in 2007/08 was 4,914 MW whilst the peak in 2013/14 had reduced to 4,523 MW.
Figure 5.6 : System Peak Demand (MVA) to 2013
The DSO has made significant investments to reinforce the network during previous price controls. However,
there are still many parts of the network that do not comply with the Planning Standard. This is evidenced in
Table 5.14 below. This table identifies the number of substations (110kV and 38kV) that were loaded outside
the requirements of the DSO Planning Standard. For 38kV substations, the number of stations that do not
comply with the Planning Standards has reduced from 105 to 32 during PR3, whilst for 110kV stations, a
reduction from 16 to 5 has been achieved.
Despite investment throughout PR2 and PR3 (albeit reduced in PR3), it is clearly evident that further
reinforcement is required, even with an assumed zero percentage growth in peak demand. However, there
is little evidence of the DSO considering ‘smart solutions’.
Table 5.14 : HV Station Loading -Summary
Year
38kV Substations
loaded above
Planning Criteria
38kV Substations
normally loaded
above 75%
110kV Substations
loaded above
Planning Criteria
110kV Substations
normally loaded
above 75%
2000 68 213 5 16
2005 65 190 16 35
2010 105 187 16 38
2015 32 75 5 19
58 Although it should be noted that Smart Metering rollout is not expected to be complete until 2019 or 2020 and significant reduction in peak
demand is not expected until Time of Use tariffs are introduced which may take a further 1 – 2 years, i.e. outside the PR4 period.
DSO
Page 113
Although growth in peak demand on the network has been assumed to be zero, the DSO does forecast an
increase in energy consumption during PR4. This is illustrated in Figure 5.7 below. Unit sales (GWh) during
PR4 are forecast to grow at approximately 2.2% per year. We undertook regression analysis to determine a
reasonable relationship between unit sales and various combinations of both GDP and population. The
strongest relationship identified was a positive one with related unit sales to GDP. The DSO’s proposed
growth in unit sales is considered to be reasonable when compared to the sound relationships identified
through regression analysis. The DSO has assumed that that the unit sales growth does not result in peak
demand growth.
Figure 5.7 : Total Units Distributed (GWh) – 2005 to 2020
The DSO’s forecast of zero load growth coupled with related growth of other econometric indicators (such as
GDP and population) suggests a conservative approach has been taken by the DSO in developing its PR4
reinforcement forecast (i.e. there is an increased likelihood of a cost overrun in PR4 outturn). We have also
observed that the DSO’s assessment of peak loadings in order to identify, prioritise and schedule
reinforcement projects also takes account of potential impact on peak demand following the roll-out of smart
meters. The DSO has assumed that introduction of Smart Meters will reduce the contribution of domestic
load to system peak by 8%59.
On the basis that domestic load comprises approximately 50% of the total load, the DSO has assumed that
the total peak is expected to be reduced by 4%. Consequently only the stations that remain overloaded after
their current loading have been adjusted for the introduction of Smart Meters in the PR4 Submission.
Both of these assumptions (zero load growth and peak demand reduction due to smart metering impact) act
to suppress the capex forecast requirements for PR4 relative to previous price controls.
We sought assurance from the DSO that it had carried out sensitivity analysis to determine the capex
requirements for reinforcement assuming zero smart meter impact, compared to their proposed PR4
programme. The DSO has confirmed that sensitivity analysis has been carried out which confirmed that if no
allowance was made for Smart Meters an additional five HV reinforcement projects would need to be
included in the PR4 programme, comprising three additional substation uprating projects and two load
transfer projects.
59 This information came from a report that was published by the CER entitled " Electricity Smart Metering Customer Behaviour Trials (CBT) Final
Report, CER11080(a), 16th May 2011". The report states that the outcome of the Residential Trial was that Smart Meters would reduce the overall electricity usage by 2.5% and peak usage by 8.8%.
19,000
20,000
21,000
22,000
23,000
24,000
25,000
26,000
27,000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Un
its
Dis
trib
ute
d (
GW
h)
Actual (to 2013) PR3 Forecast (2009) PR3 Actual Units PR4 Forecast
DSO
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The DSO PR4 programme is therefore based on addressing network deficiencies that will remain after
accounting for the impact of Smart Meters. Such deficiencies will encompass existing major breaches of
planning and safety standards have been identified. These breaches include:-
Plant Overloading
Non-Compliance with Voltage Standards
Safety standards (Short Circuit Deficiencies)
To address these deficiencies, the DSO proposes investment on an annual basis as shown below in Figure
5.8, and Table 5.15.
Figure 5.8 : PR4 DSO Proposed Reinforcement Capex Plan (€m – 2014 prices)
Table 5.15 : PR4 DSO Reinforcement Capex by Category
2016 2017 2018 2019 2020 PR4 Total
110kV (including Transmission Connection
Costs) 25.3 28.1 33 38 41.3 165.7
38kV 13.1 14.5 17.1 19.7 21.4 85.8
MV LV System Improvements 6.3 6.9 8.2 9.4 10.2 41.0
IFTs associated with 20kV Conversion
including 20kV network conversion 3.8 4.3 5.1 5.8 6.3 25.3
Total 48.5 53.8 63.4 72.9 79.2 317.8
Within the scope of the reinforcement plan for PR4, the DSO proposes to install the following infrastructure
projects and volumes (Table 5.16 and Table 5.17).
Table 5.16 : PR4 Summary of Reinforcement Projects
Project Driver Network Item Quantity
Infrastructure Installed to address plant
overloads
New 110kV/MV Substations 5
Uprated 110/38kV Substations 5
110kV/MV installations in existing 110kV Substations 5
New 38kV/MV Substation 1
48.553.8
63.472.9
79.2
0
10
20
30
40
50
60
70
80
90
2016 2017 2018 2019 2020
€m
DSO
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Project Driver Network Item Quantity
Uprated 38kV/MV Substations or additional 38kV/MV
capacity in 110kV Substations
22
Load transfers at MV to defer new/uprated Substations 3
New 110kV Circuits 1
New 38kV Circuits 8
Infrastructure installed to address
Voltage Compliance Issues
New 110/38kV Substations 1
New 38kV/MV Substations 2
Infrastructure installed to address Short
Circuit Level Deficiencies
Replacement of inadequately rated 110kV busbars 2
Table 5.17 : PR4 Reinforcement Infrastructure Volumes
Plant Unit of
Measure
Projected Capacity to be
installed in PR4
110/38kV Transformers MVA 220.5
110kV/MV Transformers MVA 311.5
38kV/MV Transformers MVA 163
110kV Lines km 35
New and Reconstructed 38kV Lines km 150.2
110kV Cables km 19
38kV Cables km 1
In relation to the proposed 38kV lines, the DSO has also included a provision for €5.6m during PR4 relating
to land access payments. This provision relates to ongoing negotiations with the Irish Farmers Association
(IFA) that are nearing completion and relate to set access payment arrangements for the construction of
single pole 38kV 150mm2 AAAC circuits, using average payments per km of line as opposed to payments
based on number/type of structures positioned within landowner’s property. This “Flexibility of Access
Payment” is estimated to be €45k/km at 38kV.
5.1.3.1 Assessment of the DSO Reinforcement HV (110kV and 38kV) Investment Plans for PR4
The load related network investment requirements for the DSO network are set out in two plans:
a) HV Network Investment Plan 2014-2024, November 2014 - Covers the entire 38kV network,
excluding Greater Dublin, divided into 26 Zones.
b) HV Network Investment Plan-Dublin 2014-2024, October 2014 - Covers the 38kV and 110kV
network in Greater Dublin divided into 5 Zones.
The methodology employed by the DSO in undertaking these load related investment plans is set out below:
Load Growth
The load growth for both investment plans is based on winter 2013 demands taken from substation
recorders complemented by SCADA load profiles where available. A blanket 2% per annum growth rate is
applied to the demands throughout the network including Greater Dublin. Substation demands are adjusted
by the demand of known committed large developments. It is noted that only a single 2% growth scenario
was studied within these investment plans, with the DSO citing that such a scenario would allow for optimum
reinforcement solutions to be identified and developed when the need arises rather than taking a more
narrow view which could lead to sub-optimal development.
DSO
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The PR4 HV/LV Reinforcement Programme both Nationally and for Dublin, has been formulated on zero
growth scenarios (i.e. no reinforcements are driven by the 2% growth scenario detailed above).
Network Performance Review
For each year of the plans the performance of the network is analysed and reviewed against the Planning
and Security of Supply Criteria60, under intact (N) and contingency (N-1) network conditions. The review
identifies:
a) Non-firm overhead line, cable and substation transformer capacity.
b) Network voltage levels below the standard.
c) Short circuit levels approaching switchgear ratings.
A project is identified to overcome any non-compliance with the Planning Standard and an Investment
Appraisal (IA) document is prepared to determine the outline design and Prime Cost61 of the project.
Schedule of Investment Requirements
Each investment plan includes a schedule of projects for each zone that states Gross Costs62 and the year in
which the project is required to be in service.
Adequacy of Investment Plans
The process employed by the DSO in developing load related investment plans reflects Good Industry
Practice as undertaken by Distribution Companies in many regulated jurisdictions.
Investment Appraisals (IA)
An IA document is prepared for each project identified in the Network Investment Plans. Because of the
recent economic downturn most of the projects identified in the previous investment plans have not
materialised therefore the IAs prepared in 2011 are still valid. Accordingly the IAs submitted for PR4
comprise the 2011 IA with a 2014 Addendum.
5.1.3.2 Investment Appraisal Methodology for HV Reinforcement Projects
The methodology employed by the DSO in undertaking IAs is set out below.
Project Divers
The IA identifies the non-compliance with the relevant Planning Standard(s) that is the driver for the project.
Options
Options to overcome the non-compliance are identified and generally can include the following:
a) Do nothing
b) Transfer demand to adjacent substations
c) Uprate or refurbish substations with larger transformer capacity
d) Build/Develop a new substation
e) Reinforce or replace overhead lines and cables circuits
60 Dated 7 June 2007 61 Time + Material + Other +ESBI Costs. 62 Sometimes itemised but not defined in IAs.
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The options should take into account the condition of plant and equipment and other development projects
that have an interacting impact on network performance.
Technical and Financial Appraisal of options
Outline designs of each viable option are developed which subsequently identify the principle items of plant
and equipment required for the project. Prime Cost estimates are then prepared using Base Planning Object
Costs (2nd Generation edition, November 2014).
A technical and financial appraisal of each option is undertaken, including the capitalisation (NPV) of losses
where these are significant, and the Least Cost Technically Acceptable (LCTA) option is selected.
Adequacy of Investment Plans
The process employed by the DSO in developing investment appraisals for planned capex investment
projects reflects historic Good Industry Practice as undertaken by Distribution Companies in many regulated
jurisdictions albeit that investigation of ‘smart’ alternatives are now being investigated in a number of
jurisdictions.
Gross Costs
The 2014 addendums to the IAs include a cost (stated as an NPV) that is not defined as prime or gross but
generally corresponds to the project Gross Costs set out in the Network Investment Plans. The uplift factor
applied to Prime Costs to give Gross Costs varies from project to project.
5.1.3.3 Sample Review of IAs
IAs for eight projects selected by the DSO have been reviewed and a summary of the outcome is set out in
Table 5.18.
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Table 5.18 : IA Review Summary
ID Project Project Driver All
Options
Preferred Option LCTA 2011
Prime
Cost (€M)
63
2014
Prime
Cost (€M)
2014
Gross
Cost (€M) 64
2014 NPV
(€)
Apparent
Overhead
Factor65
Comment
SD301 Abbeyliex
Substation
Abbeyliex MV voltage
below Standard during
normal and standby
feeder arrangements
Yes New 1x5MVA 38kV/MV
substation at Abbeyliex
Yes 2.746 Not Stated 4.661 8.6466
1.697
KP0109 Bagenalstown
Substation
Existing 2x5MVA
38/10kV TXs non-firm
throughout year under
N-1 conditions &
overloaded during winter
peaks under N
conditions
Yes Refurbish Bagenalstown
to 2x10MVA 38/20kV
with 2x20/10kV TXs to
feed retained 10kV
network
Yes 2.557 Not Stated 2.740 1.96 ? Addendum to the 2011 IA states that a
cost reduction is applicable to 2011
costs as no 38kV work required to
uprate to 2x10MVA but this does not
appear to have been reflected in the
Gross Cost in the Investment Plan
PB042 Ballygar
Substation
Existing 1x5MVA
38/10kV TXs overloaded
during winter peaks
Yes Install additional 5MVA
38/10kV TX
Yes 1.024 Not Stated 2.161 0.8166
2.110 Addendum to 2011 IA states NPV of
0.81 which does not appear consistent
with Prime or Gross costs?
TM0055 Baroda
Substation
Existing 2x10MVA &
2x5MVA 38kV/MV
substations feeding
Newbridge Town non-
firm under N-1 winter
peaks
Yes New 2x20MVA
110kv/MV substation at
Baroda
Yes 5.407 Not Stated 7.166 10.766 1.325
63 2011 Investment Appraisal (IA) 64
Appendix A HV Network Investment Plan 2014-2024, November 2014 65 Based on 2011 Prime Cost 66 Includes capitalised losses
DSO
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BF0003 Kinsale
Substation
Existing 2x5MVA
38kV/MV substation
non-firm under N-1
winter peaks
Yes Uprate Kinsale to
2x10VA 38kV/MV TXs
Yes 2.459 Not Stated 1.998 1.99 ? Addendum to 2011 IA states NPV of
1.99 as costs have been reduced – not
clear whether NPV is Prime or Gross?
CY021A Oranmore
Substation
Existing 2x5MVA
38kV/10kV substation
non-firm under N-1
winter peaks
yes Uprate Oranmore to
2x10VA 38kV/10kV TXs
Yes 1.138 Not Stated 1.998 1.99 1.756
CC0012 Trabeg
Substation
Existing 2x31.5MVA
110/38kV TXs non-firm
throughout year under
N-1 conditions &
overloaded during winter
peaks under N
conditions
Yes Uprate Trabeg to
2x63MVA 110/38kV TXs
Yes 2.899 Not Stated 3.466 4.5866
1.196
DH094 Drynam
Substation
Three 2x10MVA
38kV/MV substations
serving Swords non-firm
under winter peak N-1
conditions
Yes New 2x20MVA
100kv/MV substation at
Drynam
Yes 11.807 Not Stated 18.60067 13.70 1.575
67 HV Network Investment Plan-Dublin 2014-2024, October 2014
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The general issues arising from the review are:
1) Uplift on Prime Costs to give Gross Costs as uplift varies from project to project.
2) The 2014 Addendums do not indicate whether costs are Prime or Gross. Also some 2011 IAs cost
comparisons are based on Prime Costs whereas others are based on Gross Costs.
3) There are some minor numerical differences between comparable 2011 and 2014 costs.
4) Appendix A to the HV Investment Plan indicates that the majority of projects are required by 2016
whereas logistically it is questioned whether the implementation by this date is realistic. It is also not
consistent with the annual PR4 capex plan illustrated in Figure 5.8 above.
Some project specific issues arising from the review are:
1) Project ID KP0109 - the reduced 2014 NPV cost does not appear to have been carried forward to
Appendix A of the HV Network Investment Plan.
2) Project PB042 – the 2014 NPV cost does not appear to be consistent with the Prime or Gross costs.
3) Project BF0003 - the reduced 2014 NPV cost and Gross Cost to account for a different control room
construction is significantly less than the 2011 Prime Cost which seems inconsistent with the cost
saving due to control room construction.
5.1.3.4 Unit Costs for System Reinforcement Projects
The DSO has provided a report detailing an independent study carried out to benchmark its unit costs for
new build works for both connections and system reinforcements. The comparison has been carried out
relative to GB DNO’s. The biggest challenge with carrying out such benchmarking studies is to ensure that
the comparisons are made on a like for like basis. Items such as design costs, engineering management,
transport and associated civil work costs are not always included in such comparisons.
Because of such difficulties, Ofgem has previously separated out direct and indirect costs (DPCR5) and
benchmarked DNO direct costs only. More recently, RIIO-ED1 comparison of unit costs excluded civil costs.
The independent study commissioned by the DSO has been carried out on direct costs excluding civil works.
As part of its Questionnaire submission, the DSO provided a set of asset unit costs (Table 4.3 of PR4
Distribution Future Questionnaire) which were then subject to adjustments prior to being used in the
benchmarking study. The following adjustments were made to the DSO unit costs provided in its
Questionnaire response:
Labour Costs in Table 4.3 were subject to an additional surcharge in the range of 1.38 – 1.60 to account
for certain labour related costs included in DNO labour costs but not in the DSO unit costs (Annual
Leave, travel time, sick leave, personal protective equipment).
Design Fees were subtracted from the unit costs (as they were not included in the comparison data
costs).
Civil works costs for major HV station works were removed.
For underground cables a proportion of civil works costs were applied.
We are familiar with the benchmarking approach that has been carried out. The results of the benchmarking
study generally indicate that the DSO unit costs compare favourably with the UK DNO unit costs. However
there are a number of uncertainties with the exercise that need to be borne in mind when analysing the study
results:
The DSO unit costs relate to new build/system reinforcement whilst the DNO unit costs relate to asset
replacement works, which tend to be higher than the corresponding unit cost for new build.
DSO unit costs relate to the in-house delivery of projects, whilst DNO costs may include costs from
external service providers – the extent of this is unknown.
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The DSO has applied Purchasing Power Parity (PPI) Index to convert its in-house labour costs to £
sterling at a value of 0.84.
For some assets (such as transformers) with different sizes/specifications, only a single DNO unit cost
has been published – this is likely to be an average cost across the range of costs within such an asset
category. This means that comparison of this average published DNO unit cost has to be made across
the range of the DSO unit costs.
Given the uncertainty with the above and although the results of the independent study show that the DSO
costs compare favourably with DNO unit costs and are not unreasonable, they should be considered with
appropriate caution. Where possible we have also made assessment of DSO outturn unit costs for PR3 and
compared with the planned unit costs for PR4 work programmes. This is considered more fully within our
assessment of the DSO’s forecast for non-load related capex.
We are satisfied that the DSO has established good practice relating to its preparation of
investment plans for its 110kV and 38kV network development and undertaking project investment
appraisals before seeking technical and financial approval and subsequent commitment of capex to
a project.
Notwithstanding some errors and/or inconsistencies with the consolidated list of HV reinforcement
projects compared to individual project IAs, these are not considered to be material and we
conclude that the DSO proposed PR4 reinforcement capex for 110kV and 38kV projects to be
reasonable.
5.1.3.5 MV/LV Reinforcements
The DSO has proposed a total of €40.9m of reinforcement capex relating to the MV and LV network. This
investment is proposed to target known network deficiencies and projects will involve one or more of the
following:
Increased Three phase Medium Voltage Capacity additional or uprated MV/LV station capacity.
Reinforcement of MV Circuits by installation of additional MV Circuits.
Reconductoring MV and LV overhead Network to increase MV/LV capacity and reduce volt drop.
Installation of MV boosters to improve voltage on normal and standby operation.
Installation of reclosers to bring protection of the network within standard.
Installation of new sections of MV cables or overhead lines to loop network where the load has
increased above 1MVA.
Conversion of single phase network to 3 phase network to address voltage problems or address
unbalance problems on the network.
Rebalancing network.
We have not observed any investigation/planned use of smart grid technologies or “Smart” solutions by the
DSO within its PR4 capex plans to address network reinforcement requirements. The proposed PR4 capex
(€40.9m) represents a 18.8% increase compared to expected costs for PR3 (€34.5m), although considerably
less than PR3 allowed costs of €70.8m.
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We generally agree with this work being necessary although we would recommend allowances for
PR4 such that PR3 actual and PR4 forecast capex is consistent with the PR3 allowed capex of
€70.8m – this was allowed to address known network deficiencies and is considered adequate for
the DSO’s zero growth scenario.
In addition we would expect the ongoing 20kV conversion programme to continue to improve the
network and reduce reinforcement requirements.
This will reduce PR4 allowances for MV/LV System reinforcements by €4.6m to €36.3m.
5.1.3.6 20kV Conversion Programme
DSO PR4 forecast capex relating to its ongoing 20kV conversion programme is €14.3m with a further
€11.1m of capex relating to the installation of Interface Transformers (IFTs) – giving a total of €25.4m. This
total expenditure will be targeted towards converting approximately 4,000km of existing 10kV network to
20kV operation. The DSO estimates that more than 90% of the 20kV conversion required in PR4 is required
due to current network being outside voltage standards based on 2012 loads.
In the 1990’s, the DSO embarked on a programme to convert most of its 10 kV MV network to 20 kV. The
DSO is able to convert parts of its network to 20 kV by changing pole transformers and maintaining the
existing line insulation which was designed for an unearthed 10 kV system, but converting to an earthed
20 kV system.
The capacity of an uprated line is increased by a factor of 4 and for the same capacity the losses are
reduced to one quarter.
Uprating has some disadvantages in that the fault rate can increase in the early years after uprating as the
line operates at higher stresses and incipient defaults are discovered.
In addition to the network capacity gains achieved through conversion to 20kV, the financial justification for
this programme is augmented by the losses savings achieved.
At the end of PR1 18,500km of the MV network was operating at 20kV and a further 30,000km of overhead
network had been refurbished to 20kV standard.
During 2006-2010 an additional 19,000km of network was converted to 20kV operation.
The DSO’s latest forecast for PR3 includes the uprating of a further 15,000 km of overhead line at a cost of
€102m.
The proposal for the conversion programme in PR3 was based on an MV network study that was carried out
in 2009. This resulted in a plan to convert 15,000km of network that were outside standard. The PR3 plan to
convert 15,000km was adjusted and the latest DSO forecast is that 10,500km will be converted to 20kV
operation by the end of PR3. The resulting balance of network deferred from PR3 is the planned target for
PR4.
We agree there are strong benefits in continuing with the conversion programme. We have satisfied
ourselves that the DSO has in place an appropriate cost-benefit and prioritisation process, with the CBA
considering the impact of losses on the network, together with improved network voltage.
The DSO expected PR3 volumes (10,500km) and capex (€36.5m) result in a unit cost per km
converted of approximately €3,475/km. The DSO proposed PR4 programme is based on converting
4,000km at the same unit cost, giving a total cost of €13.9m.
Further IFT works at costs comparable with PR3 are also proposed.
We consider these to be reasonable costs and consequently we recommend PR4 allowance of
€25.0m.
DSO
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5.1.4 Dismantling Costs
DSO forecast capex associated with dismantling (or “retirements”) for the PR4 period is shown in Table 5.19
below.
Table 5.19 : Comparison of PR4 Dismantling Costs (€m – 2014 prices)
PR3 Allowed PR3 Actual68 DSO Original PR4
Proposed
DSO Revised PR4
Proposed
Variance of PR4
revised forecast
to PR3 Allowed
Variance of PR4
revised forecast
to PR3 Actual
58.8 48.3 70.2 64.4 5.6 16.2
PR3 allowed capex was based on an ‘a priori’ assumption that dismantling costs were directly proportional to
the gross cost of load related and non-load related network capex. The PR3 allowed costs were based on
4.8% of this gross value, although the actual dismantling costs incurred during PR3 are expected to be 4.1%
of the PR3 gross value.
The DSO introduced revised project costing procedures (Integrated Work Management Module) within their
SAP application from 2009 onwards. This allowed the DSO to allocate dismantling costs more directly to the
work activity that has driven the need for the dismantling to be carried out. Allocation of dismantling costs
over the period 2011 to 2013 identified that 30% of dismantling cost arose from activities that are not part of
the formula used to determine PR3 allowances, in particular New Business and Line Diversions.
We concluded in our review of DSO PR3 capex that the change in the DSO cost allocation procedures has
provided improved visibility of the drivers on the dismantling activity and associated costs
The DSO forecast for PR4 dismantling cost allocation has been derived based on the application of the
outturn percentage allocations during 2011-2013 to each relevant category of its PR4 forecast, as itemised in
Table 5.20 below.
Table 5.20 : PR4 Dismantling Cost Allocation
Capex Category % Allocation applied to
Gross Cost
New Business 2.5%
Generator Connections 0.8%
Diversions 11.8%
Reinforcement 2.5%
Non-Load Related 6.1%
Application of this approach resulted in the DSO PR4 original forecast for Dismantling of €70.2m, equivalent
to 4.4% of the DSO’s gross PR4 network-related capex. Its PR4 revised forecast of €64.4m is equivalent to
4.2% of its revised PR4 forecast gross capex of €1.52bn.
We tested this approach against PR2 gross capital expenditure and our analysis calculated a hypothetical
PR2 dismantling cost of €97m although the PR2 outturn was significantly less at €67.7m. This differential
demonstrates the sensitivity of the results to the overall capex disaggregated into the different capex
categories.
The PR2 outturn dismantling costs were 2.7% of gross costs whilst the PR3 outturn dismantling costs are
expected to be 4.1% of gross network capex costs.
We therefore recommend PR4 allowances for dismantling which are derived as a proportion of our
68 Includes €29.1m (2014 prices) of dismantling costs over the period 2011 to 2013 that were allocated by ESBN to their Income Statement
DSO
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recommended PR4 gross network capex – with allowances set at 4.1% of this gross value - this
results in a recommended PR4 capex for dismantling of €55.1m, representing a reduction of €9.3m
compared to the DSO revised forecast of €64.4m.
The DSO has also provided commentary in its submission relating to the future treatment of dismantling
costs. They present two options for consideration by, and agreement with, the CER. The two options are:
1) Maintain the dismantling (retirement) cost line as a separate heading within its capex reporting
framework; or
2) Record the dismantling costs against the activity that is the main driver to the dismantling requirement.
The DSO’s stated preference is to implement option 2 in order to simplify the current basis for determining
capital and dismantling allowances to the mutual benefit of CER and the DSO. The preferred approach is
normal practice within many utilities in other jurisdictions. Whilst we agree with the DSO that it provides more
accurate allocation of costs and better understanding of costs for the main work driver, this benefit is
countered by a resulting loss of transparency of costs at this detailed level. On balance, Jacobs would
support adopting option 2.
5.1.5 Non-Repayable Line Diversion Costs
DSO forecast capex associated with line diversions for the PR4 period is shown in Table 5.21.
Table 5.21 : Comparison of PR4 Line Diversion Costs (€m – 2014 prices)
PR3 Allowed PR3 Actual DSO Original
PR4 Proposed
DSO Revised PR4
Proposed
Variance of PR4
revised forecast to
PR3 Allowed
Variance of PR4
revised forecast
to PR3 Actual
53.1 48.3 92.1 60.2 7.1 11.9
Line diversion costs have historically been proportional to capital expenditure in the category of “gross new
demand connections”. For the PR3 period, this allowance was set at a value equivalent to 11.4% of the PR3
forecast capex for new connections.
Despite significant reduction in new connections capex during PR3 period, the rate of expenditure
associated with asset diversions has not reduced to the same levels. The actual diversion costs over 2011 to
2013 are in the range of 19.2% to 21% of the gross connections capex over the same period.
The DSO derived its original PR4 forecast (of €92.1) based on linear regression of actual costs (prime) over
the 2006 to 2013 period. The defined relationship was then applied by the DSO to PR4 new business
forecast gross capex and this resulted in a PR4 capex requirement for diversions equating to 30.2% of gross
new business forecast capex. In its response to our Interim Report, the DSO has confirmed that its original
submission included an erroneous miscalculation and confirmed its agreement that the historical relationship
(or correlation) between new business and line diversion costs is an appropriate basis upon which PR4
forecast and hence allowances should be made.
We have analysed the historical relationship (of gross costs) from 2006 to 2013 and also analysed the DSO
PR4 revised forecast of €60.2m. The results are presented in Figure 5.9 below. This figure presents new
business costs (x axis) against the cost of diversions (y axis) for the years 2006 to 2013 (as shown by the
Historic Data points in blue) and the years 2014 to 2020 (as shown by the forecast data points in red -
representative of the DSO’s revised PR4 forecast).
DSO
Page 125
Figure 5.9 : PR4 Forecast Diversion Costs – Comparison with Historic Performance (€m – 2014 prices)
It is observed that there is a strong historic relationship (R2 of 0.9581) between new business gross costs
and diversion gross costs. However, the DSO PR4 revised forecast is not consistent with this historic
relationship.
We therefore recommend PR4 allowances for diversion works that are consistent with the historic
relationship between new business and diversion gross costs. We have applied this to our
recommended allowances for New Business gross capex.
This results in a PR4 forecast capex for diversions of €50.6m, representing 17.4% of PR4 gross new
business capex. This is €9.6m (16%) lower than the DSO revised forecast of €60.2m and €42.5m
lower than the DSO original forecast of €92.1m.
5.2 Non Load Related Capex
5.2.1 Non Load Related Capex – Overview
The DSO non load-related (NLR) capex for the PR4 period is summarised in Figure 5.10 below and shows a
total PR4 NLR capex of €671m. This is significantly above the expected PR3 outturn capex of €425.4m
(57.7% higher) although only €92.5m (16%) higher than the CER allowed NLR capex during PR3.
y = 0.111x + 3.6446R² = 0.9581
0
5
10
15
20
25
30
35
40
0 50 100 150 200 250 300
Div
ers
ion
s
New Business
Historic Data DSO Revised Forecast Linear (Historic Data)
DSO
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Figure 5.10 : PR4 DSO Non Load Related Capex compared to PR3 (€m – 2014 prices)
The main drivers for the proposed PR4 works are to:
address safety risks,
ensure compliance with health & safety and environmental obligations, and
to maintain continuity of supply.
Replacement works are driven by the condition and performance of particular asset categories.
The DSO NLR PR4 programme consists of the following projects/programmes:
Completion of major 110kV and 38kV HV Station replacement projects originally planned for completion
in PR3 but subsequently deferred due to the prevailing financial situation at the time;
Continuation of existing HV & MV asset renewal and security programmes to mitigate safety risk to the
public and the DSO workforce;
Continuation of cyclical refurbishment of the 38kV & MV overhead lines, together with a project to
rebuild a number of 110kV double circuit tower lines in the Dublin area;
Commencement of a small number of targeted asset renewal/refurbishment programmes;
NAGZ is a major smart grid investment initiative aimed at addressing impact caused by increasing
levels of renewable generation. The project will look to combine intelligent smart grid networks, high
speed communications and IT, linked with increased cross-border connectivity;
The proposed plans also include for a small number of relatively low cost pilot projects to allow for
assessment of emerging/different technologies before any decision is made regarding roll out of such
technologies on a wider scale. The costs of these are presently incorporated within the DSO’s main
asset renewal programme categories but these could be ring-fenced within the DSO PR4 R&D forecast
expenditure category.
Table 5.22 below details capex for each of the defined asset renewal or refurbishment categories.
579
425
671
0
200
400
600
800
5 Year Total
€m
PR3 Allowed PR3 Actual PR4 Revised Forecast (April 2015)
DSO
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Table 5.22 : Comparison of PR4 Forecast v PR3: Non Load Related Capex (€m 2014 prices)
PR3
Allowed
PR3
Actual
DSO
Original
PR4
Proposed
DSO
Revised
PR4
Proposed
Variance of PR4
revised forecast to
PR3 Allowed
Variance of PR4
revised forecast to
PR3 Actual
€m % €m %
Renewal Programme -
110kV & 38kV Lines 16.7 15.5 46.5 38.4 21.7 129.7% 22.9 147.6%
Renewal Programme -
110 & 38kV Cables 21.0 6.2 24.5 28.6 7.6 36.2% 22.4 362.4%
Renewal Programme -
HV Substation 120.4 77.1 126.4 126.5 6.2 5.1% 49.4 64.0%
Renewal Programme -
MV Overhead Lines 70.7 61.0 131.9 82.2 11.5 16.3% 21.2 34.8%
Renewal Programme -
MV Cables 2.6 2.0 0.0 0.2 -2.4 -91.9% -1.8 -89.5%
Renewal Programme -
MV Substations 24.7 31.2 23.3 33.2 8.5 34.6% 2.0 6.4%
Renewal Programme -
Urban LV Renewal 64.3 36.2 46.5 46.4 -17.9 -27.8% 10.2 28.3%
Renewal Programme -
Rural LV Network 95.8 84.1 74.8 84.5 -11.3 -11.8% 0.4 0.5%
Storm Rectification
Project 0.0 27.4 27.4 - -27.4 -
Renewal Programme -
LV cables and
associated items
17.2 6.2 16.2 16.4 -0.8 -4.5% 10.2 163.4%
Renewal Programme -
Meters and Time
Switches
0.0 0.0 14.0 14.1 14.1 - 14.1 -
Renewal Programme -
Cut-outs 5.8 4.0 14.3 14.3 8.4 144.7% 10.3 257.6%
Continuity Improvement 22.8 14.0 4.2 4.2 -18.6 -81.4% -9.8 -69.7%
Response capex 101.1 56.5 51.3 61.4 -39.8 -39.3% 4.9 8.7%
System Control 15.4 3.9 16.5 16.5 1.1 7.5% 12.6 319.1%
IVADN (Integrated
Vision for an Active
Distribution Network)
Project
0.0 0.0 7.1 7.2 7.2 7.2 -
NAGZ 0.0 0.0 87.6 87.6 87.6 87.6 -
Other (specify) – relates
to Continuity
Improvement
0.0 0.0 9.3 9.3 9.3 9.3 -
NRP/ Bulk Supply 0.0 0.0 0.0 0.0 0.0 0.0 -
Total Non-Load
Related CAPEX 578.5 425.4 694.4 671.0 92.5 20.0% 245.6 57.7%
The PR4 capex includes a total of €87.6m relating to the NAGZ project, which is subject to European funding
of €31.75m and is described further in Section 5.2.7. Capex relating to the NAGZ is expected to occur
DSO
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during the early years of PR4 and the annual NLR capex over PR4 is also shown in Figure 5.11. For
comparison purposes, if the €87.6m of capex relating to the NAGZ is excluded from the DSO PR4 total, the
NLR capex reduces to €606.8m for PR4, which is comparable (~5% higher) with CER allowances of €579m
for PR3.
Figure 5.11 : PR4 Non-Load Related Capex – Annual Investment including NAGZ (€m – 2014 prices)
As part of our assessment of the DSO NLR capex, we have undertaken a modelling exercise as a top-down
assessment of asset replacement requirements. This assessment methodology based on the Survivor model
– which uses a Poisson distribution for replacement of asset types, based on a mean asset life.
Replacement profiles are essentially distribution profiles that allow for assets to be replaced around the
assumed technical life (using standard deviations) and not on the exact assumed technical life. Standard
deviations define the percentage of assets that will be replaced within an age range, based around the
assumed asset life. For example, 68% of all assets will be replaced within 1 standard deviation of the
assumed asset life, whilst 95% of all assets will be replaced within 2 standard deviations of the assumed
asset life.
Historically it has been typical to assign normal distribution profiles to asset types. This process requires
assumptions relating to both a technical life of an asset and an assessment of its standard deviation (in
years). In recent years, some regulators (including Ofgem in the UK) have moved towards using Poisson
distributions in their price control assessments. The benefit of utilising Poisson distribution profiles is that the
standard deviation is inherently assumed within the distribution profile and therefore an estimate of an assets
standard deviation is not required.
Using the DSO age profile data for the main asset categories, the model output results in a replacement
profile (and hence volumes of replacement during PR4) for each asset class that is derived based on age
profile, assumed asset life and a Poisson distribution of replacement. In the modelling exercise we have
used the technical asset lives as proposed in Appendix D together with DSO age profile data.
Our modelling indicated that in general the PR4 renewal volumes proposed by DSO were less than
modelling indicated, suggesting longer asset lives being used by the DSO with an implied higher risk being
adopted. We concluded that the proposed DSO asset replacement volumes in PR4 are therefore not
unreasonable.
The model is not appropriate for a wide range of activities – such as security driven programmes, flood
mitigation, cyclical overhead refurbishment programme – this latter point was recognised by Ofgem in the
previous DPCR5 for certain DNO’s and the asset category was removed from Ofgem’s modelling
assessment.
We also carried out a bottom-up analysis of each of the sub-programmes of work that are included within
each of the main asset renewal programmes. This allowed us to assess DSO forecasts at a much greater
118.0 116.5 115.5 116.7 116.7
29.6 28.9 29.10.0 0.0
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
2016 2017 2018 2019 2020
Total Non-Load Related CAPEX - Excluding NAGZ NAGZ
DSO
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level of detail than the top-down modelling methodology briefly described above. The results of the bottom-
up assessment are presented in the following sub-sections.
5.2.2 Renewal Programmes
The DSO has structured its asset renewal programmes into a series of defined categories of work to address
assets at a specific location or to address a particular set of assets across the DSO network as part of a
broader work programme. Many of the proposed works during PR4 fall into one of the following categories:
Progressing works that were originally planned for PR3 but deferred in full until PR4 due to financial
constraints prevailing at the time.
Continuation of work programmes previously established and progressed during PR3.
Commencement of new programmes of work to address identified risks with a specific type of asset.
The DSO has provided a detailed narrative document69 that provides significant detail of the proposed asset
renewal plans for PR4. The document is divided into 10 separate chapters, with each chapter focusing on a
specific asset class. Within each chapter, the document describes the various network risks for sub-
components within the broad asset class that need to be addressed during PR4. Details are provided of the
proposed PR4 volumes of work and the proposed PR4 capex at this sub-programme level. The document
gives good visibility of the DSO asset management plans during PR4.
In general, we consider the justification for the various PR4 works proposed by the DSO is proven and in
many cases, we agree with the proposed volumes of work. However, our review has identified a number of
significant increases in the DSO PR4 planned costs, compared to PR3 planned costs (for deferred works) or
PR3 expected outturn costs (for works progressed during PR3). We have therefore proposed adjustments to
the proposed DSO PR4 capex to account for such differences where the DSO has been unable to provide
further justification supporting such increases in planned costs for its major projects and its planned unit
costs for its asset renewal work programmes.
The following sub-sections provide a summary of our review for each of the DSO asset renewal
programmes.
69 Document DF03 – Asset Replacement and Maintenance Final.pdf
DSO
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5.2.2.1 110kV & 38kV Lines
DSO proposed PR4 capex is €38.4m70, CER PR3 allowed capex of €16.7m, DSO current forecast for PR3 is €15.5m.
The proposed PR4 works associated with 110kV and 38kV lines are summarised in Table 5.23 below.
Table 5.23 : Summary of PR4 capex relating to 110kV and 38kV Lines (€m – 2014 prices, unless stated otherwise)
HV Overhead
Lines – Sub
Category
Background
DSO PR4 Forecast PR4 Recommended Variance to
DSO PR4
Capex (€m)
PR4
Revised
Capex (€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit
Cost (€)
PR4 Capex
(€m)
38kV Overhead
Cyclical
Refurbishment
Continuation of approved PR3 programme to inspect 5/9ths of the 38kV
overhead network excluding parts of the network under 15 yrs old and
refurbish those assets which fall outside ESBN’s condition standard for that
asset. Expected to extend life of assets and maintain fault rate while reducing
risk to public and staff safety.
9 year OCR programme started in PR3.
20.0 3,169 6,313 PR3 Outturn 6,300 20.0 -0.0
Refurbishment
of 110kV double
circuits in Dublin
Major refurbishment/rebuild is proposed for four 110kV circuits within the
greater Dublin area. Originally planned for refurbishment due to age (50yrs +)
and location of these lines (dense residential, industrial areas and near major
roads) and results of conductor sampling showing significant signs of
deterioration.
Programme deferred from PR3.
17.7 15 Scheme
Cost
Lowest Cost
Technically
Acceptable
Scheme
6.8 --10.9
Refurbishment
of 110kV circuits
outside of Dublin
Painting and sheer block repairs are to take place for up to 33km in addition to
reinforcement work to uprate the capacity of the line in order to return these
circuits to a minimum standard considered necessary to prevent hazards from
the public and environmental issues such as corrosion.
Programme deferred from PR3.
0.7 33 21,212 DSO PR4
proposed 21,212 0.7 -
TOTAL 38.4 27.5 -10.9
70 Revised March 2015
DSO
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In relation to the 38kV Overhead Cyclical Refurbishment Programme, the DSO revised forecast for PR4 is based on a unit cost which is consistent with
outturn cost in PR3. We recommend allowances for PR4 that are consistent with the PR3 outturn unit costs.
In relation to the re-conductoring of 110kV double circuit tower lines in the Dublin area, it is our understanding that there has not yet been any detailed
line survey and analysis to inform the assessment of the potential costs and that the DSO has not yet fully developed its proposed investment case. The
DSO PR4 forecast is therefore based on a middle-ground cost scenario. However, taking a low cost based on a line refurbishment using existing towers,
and a high cost based on fully undergrounding and stating that a half way position is part underground, part tower replacement and part fittings
replacement does not constitute a planned investment. We would however agree that the requirement to carry out the lowest cost practical solution at
this time seems reasonable and therefore would recommend this cost of €6.8m. We do recognise the risk associated with this cost uncertainty and
therefore once the DSO has developed its planned investment for these circuits, this should be reviewed to assess the efficiency of their proposed
investment during PR4..
The proposed changes result in PR4 recommended capex of €27.5m for 110kV and 38kV lines (with capex reduced by €10.9m).
DSO
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5.2.2.2 110kV & 38kV Cables
DSO revised proposed PR4 capex is €28.6m71, CER PR3 allowed capex of €21.0m, DSO current forecast for PR3 is €6.2m.
The proposed PR4 works associated with 110kV and 38kV cables are summarised in Table 5.24 below.
Table 5.24 : Summary of PR4 capex relating to 110kV and 38kV Cables (€m – 2014 prices, unless stated otherwise)
HV Cables –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Revised
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit
Cost (€)
PR4
Capex
(€m)
Replacement of
Pfisterer 110kV
Terminations
Three failures in PR3 to date which have come prematurely on terminations installed pre 2009.
Based on survey results, it is required to replace all pre-2009 manufactured terminations on the
system.
0.8 22 36,364 DSO PR4
proposed 36,364 0.8 -
Replace 110kV
and 38kV Indoor
Fluid-filled
Terminations
Replacement of 4 sets of 38kV and 1 set of 110kV due to potential fatality risk arising from
explosions, potential leakage and in prior cases of explosions.
Programme deferred from PR3.
Work involves installing short length of XLPE cable, transition joint between XLPE cable and oil
filled cable and new dry terminations for XLPE cable.
0.8 5 160,000 DSO PR4
proposed 160,000 2.0
0.0
Replacement of
Pre 1940s 38kV
Paper Cables
16.7km of paper cables will be 77 yrs of age by 2015. Due to high fault rates on paper cables (30-
49 times higher) than modern XLPE cables and the high number of customers that depend upon
them. Capacity of new cable will increase from 20MVA to 40MVA and improve operational
flexibility.
Significant works already completed prior to PR4 - 65% of route already trenched, 12km of cable
already procured.
Programme deferred from PR3.
7.6 16.7 455,090 DSO PR4
proposed 455,090 7.6 -
Replacement of
110kV Pipe
Type Gas
Expected rapid deterioration in the upcoming years on two cables. Costly pumping exercises will
also be reduced and the risk of supply interruptions also. Also believed that losses will reduce with
new XPLE cables.
4.1 8.9 460,674 DSO PR4
proposed 460,674 4.1 -
71 Table 6.3 (April 2015 version) states €28.6m – however it is noted that the DSO response to our Interim Report stated total capex of €28.0m
DSO
Page 133
HV Cables –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Revised
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit
Cost (€)
PR4
Capex
(€m)
Compression
Cables –
It is proposed to retrofit the Milltown circuits only with City Cable – a 3 core XLPE type cable used
to replace cables in piped installations, particularly in urban areas. This means effectively removing
the old cable from within the pipe, and reinserting a new compact XLPE insulated 110kV cable. As
the new cables are pulled through the existing pipework, excavation will be restricted to the
existing joint positions. This results in less costly and disruptive works.
Programme deferred from PR3.
Replacement of
Inchicore to
Francis St.
110kV Fluid-
Filled Cable.
along Grand
Canal route
Replacement of a leaky circuit with high leak rates in an area close to the city canal and nearby
congested areas.
Programme deferred from PR3.
5.5 5.7 964,912 DSO PR4
proposed 964,912 5.5 -
Replacement of
further 5% of
population of
38kV fluid-filled
cables.
Replacement of leakiest circuits to reduce the leakage rate with the same as above justifications
and the inclusion of cable faults reducing with replacement. 3 6 500,000
DSO PR4
proposed 500,000 3.0 -
Tag 110kV/38kV
fluid-filled cables
with PFT tracer
Gas Pump PFT
gas impregnated
oil into 50
circuits
Condition assessment based work will be carried out to replace existing insulating cable fluid with
PFT tagged cable fluid. This is due to ESB networks comparing unfavourably to other utilities with
regards to cable leakage and to the environment agency standards. The PFT gear will also reduce
repair and planned outage times as well as reducing costs.
6.2
65km of
3c cable;
15km of
single core
cable
38.2k (3-
core)
95.7k (3 x
single core)
Applied
Reduction to
PR4 unit costs
4.0 -2.2
TOTAL 28.0 25.8 - 2.2
DSO
Page 134
DSO Revised Table 6.3 Forecast of €28.6m relating to HV Cable Replacements, although summation of the capex associated with the individual sub-programmes
is €28.0m (which is also stated by DSO in its narrative response to the Jacobs Forecast Capex Interim Report).
With the adjustments proposed above, our recommended PR4 capex allowances for 110kV and 38kV cable asset renewal works is €25.8m – a reduction of €2.2m.
In its response to our Interim Report, the DSO were seeking to increase the cost for the PFT tagging programme from €2.2m to €6.2m. This technique will provide improved
monitoring of the cables, however the estimated costs seem high with the relative difference between 3 core and single core containing the same oil volume per metre, which
is the major determining factor for the time taken to tag the cables. We would therefore expect costs to be around €4m, which is greater than the DSO initial forecast (of
November 2014) but below its revised forecast (March 2015).
DSO
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5.2.2.3 HV Substation
DSO revised proposed PR4 capex is €126.5m72, CER PR3 allowed capex of €120.4m, DSO current forecast for PR3 is €77.1m.
The proposed PR4 works associated with HV Stations (110kV and 38kV) are summarised in Table 5.25 below.
Table 5.25 : Summary of PR4 capex relating to HV Stations (€m – 2014 prices, unless stated otherwise)
HV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Reyrolle Class
'C'
Replacements
There are four switchboards remaining in Dublin city centre stations, namely East Wall Road,
Glasnevin, Granby Row and Marrowbone Lane totalling 39 cubicles.
Short circuit rating of this type of switchgear is well below IEC standard levels and as a result
increased rate of risk with severe consequences. As a result of risk assessments, replacement of
the 4 remaining class c assets are to be replaced for MV GIS and protection.
Work deferred from PR3 - previously allowed by CER - now planned for completion in PR4 by the
DSO.
8.5 4 2,100,000
Adjustment to
DSO PR4
submitted
costs
1,610,000 6.4 -2.1
ASEA NRB 38kV
Disconnect
Replacements
These switches are triple pole, pedestal mounted, outdoor disconnects and were installed from the
1960s. They are rated for 52kV and are used on the 38kV system in 110kV substations. They are
manually operated at ground level by rotating a lever through 180 degrees.
The total population of 67 disconnects are installed in 11 110kV stations and have been in service
for 51 years. Of this population, individual testing completed in 2013 / 2014 revealed 16 units to
require immediate remedial work due to indication of immediate mechanical failure.
0.5 30 16,667 DSO PR4
proposed 16,667 0.5 -
10kV FPE LBFM
Switch
Replacements
(Kyle Cooper)
Load break fault make (LBFM) switches manufactured by Kyle Cooper are used in the DSO
faulted phase earthing (FPE) cubicles to earth faulted phases.
There are approximately 1000 units in total on the system at present, in FPE cubicles, on 20 kV
transformer neutrals and in interface sites close to feeding stations. The FPE system is the earth
fault treatment for 10kV isolated neutral networks across the country; therefore its reliability is
extremely important for staff and public safety. The Kyle Cooper LBFM switches mechanism
1 100 10,000 DSO PR4
proposed 10,000 1.0 -
72 As per updated Table 6.3
DSO
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HV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
boxes are prone to water ingress which leads to failure of the unit. Approximately 681 of these
switches are installed in outdoor FPE cubicles. These failures are attributed to a design flaw which
applies to all units and is not limited to a particular batch or age range. The sealing of the
mechanism box is sub standard leading to water ingress.
DSO proposes to replace 100 switches with a modern circuit breaker.
110kV Sprecher
and Schuh circuit
breaker
replacement (oil
filled CBs with
spring close
mechanism)
These circuit breakers were installed in the 1970’s. Transmission System experienced similar
problems and have replacement programme in place over previous 15 years.5 failures on
transmission system and 1 failure on Distribution system where broken drive insulators were
identified. There are also issues with the cement joints on most units. DSO also cites international
experience is similar, justifying replacement programme. Elsewhere, porcelain insulators of the
Sprecher & Schuh switchgear were found to fail at 30+ years in service.
For PR4, the DSO proposes to replace all 25 units, due to failure rate at 30+ yrs age of asset and
the risk of failure. The proposed approach is consistent with transmission system practices.
1.6 25 64,000 DSO PR4
proposed 64,000 1.6 -
Balteau CT
Replacement
Oil filled Balteau current transformers (CTs) are installed at 38 kV and 110 kV - 20 units at 110kV
and further units at 38kV. These CTs were installed at 110kV between 1953 and 1980, and at
38kV between 1970 and 1981. Recently they have been found to contain high levels of moisture.
This is attributed to a design flaw – the rubber bellows degrade and lose their seal, allowing
moisture into the oil, eventually leading to internal flashover.
In late 2009, such moisture ingress leads to a catastrophic failure in Hollyhill 38 kV station. Testing
of units on the transmission system have confirmed that a high occurrence of this issue. Similar
testing on the distribution system is ongoing.
DS proposes replacement of 20 110kV units and 175 38kV units within PR4.
3.6 195 18,462 DSO PR4
proposed 18,462 3.6 -
Earth fault
protection
PR3 programme established to upgrade existing protection systems. Priority 1 works focusing on
primary earth fault protection was progressed during PR3. The priority 2 works originally planned
for PR3 related to slow or unreliable fault protection although these works were largely deferred.
For PR4, the DSO has proposed a reduction in scope of work from PR3 as it only focuses on
areas where there is an absence of earth fault protection. 739 units have been identified from
implementation to address absence of adequate earth fault protection. This will increase safety to
public/staff, reduce operational costs and allow accurate fault location data to be provided quicker.
15.9 739 + 7
ASC 21,516
PR3 expected
outturn costs
17,811
(Relays) 15.9 0.0
DSO
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HV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
In addition the DSO proposes the installation of 7 x MV Arc Suppression Coils (ASC) at various
locations in order to improve the earth fault protection on its rural 10kV network
38kV & 10kV
Switchgear
replacement
Continuation of programme allowed for during PR3 to replace outdoor 38kV and 10kv CBs. ESB
have identified a population of ‘at-risk’ 10kV and 38kV Circuit breakers require replacement due to
performance issues, including that of insufficient short circuit rating.
PR 3 allowed 180 units to be replaced although only 72 are forecast for replacement by 2015. The
DSO is targeting a further 100 units for replacement during PR4.
8.6 100 86,000 PR3 expected
outturn costs 51,921 5.2 - 3.4
Replacement of
Doulton Insulator
Busbar Supports
During PR3 a programme of replacements was allowed, which is completed based on the
discovery of these supports in HV stations when other activities are being carried out. Works were
largely deferred in PR3.
DSO proposes that this programme be completed in PR4 so that the risks associated with these
supports are removed completely.
0.6 30 20,000
DSO proposed
PR4 unit costs
-
20,000 0.6 -
Siemens
Stations
Replacements
Replacement works at 3 - 85 year old stations, which present fire, continuity and safety risks.
Work deferred from PR3 - previously allowed by CER - now planned for completion in PR4 - works
at Newtown St Alban and Mount Misery. Lake Station being retired completely with load
transferred to Dunmanway 110kV station.
These are the last remaining Siemens stations on the DSO network. .
9.9 3 3,300,000 DSO PR4
proposed 3,300,000 9.9 -
Convoy Wood
Pole station
replacement
Replacement originally scheduled for replacement during PR3 and Capex allowed by CER - now
planned for PR4. 5 1 5,000,000
DSO PR4
proposed 5,000,000 5.0 -
Pembroke 10kV
Sw'gear
replacement
The replacement of the compressed air operated switchgear was originally scheduled for PR3 and
Capex allowed by CER - now planned for PR4. 3.9 1 3,900,000
Increased PR3
costs 3,600,000 3.6 - 0.3
Bedford Row -
38kV and 10kV
Sw'gear
replacement
The station is now over 80 years old and the switchgear is based on long outdated technology.
The replacement of the switchgear was originally scheduled for PR3 and Capex allowed by CER -
now planned for PR4.
7.0 1 7,000,000 DSO PR4
proposed 7,000,000 7.0 -
DSO
Page 138
HV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Kilbarry - 38kV
Sw'gear
replacement
During PR3, it was proposed to replace the existing 38kV switchgear and associated control and
protection with a GIS module with integrated protection and modern substation control system.
Originally scheduled for replacement during PR3 and Capex allowed by CER - now planned for
PR4.
4.4 1 4,400,000 Increase to
PR3 costs 3,500,000 3.5 -0.9
Ardnacrusha -
38kV Sw'gear
replacement
During PR3, it was proposed to replace the existing 38kV switchgear and associated control and
protection with a GIS module with integrated protection and modern substation control system.
Replacement originally scheduled for replacement during PR3 and Capex allowed by CER - now
planned for PR4.
6.1 1 6,100,000 Increase to
PR3 costs 5,500,000 5.5 -0.6
Remedial
measures to
mitigate GPR
The earth grids of many older 38kV stations have deteriorated over their lifetime.
During PR3 a programme of remedial works was initiated, under which one or more of a range of
measures identified are put in place to mitigate risks associated with a rise in ground potential.
The DSO propose to continue this programme in PR4, to ensure the safety of staff, and to prevent
damage to plant in the station compound or neighbouring third party premises.
2.8 205 13,700
DSO proposed
PR4 unit costs
-
13,700 2.8 -
Flood Defence in
vulnerable
locations
This programme is proposed by DSO to mitigate risk of flooding to its HV stations. The proposed
works will involve the introduction of possible station relocations, low walls and sealing cables to
prevent water damage. This is due to previous history of flooding and the environmental, safety
and continuity risks presented by flooding.
0.6 1 600,000
DSO proposed
PR4 unit costs
-
600,000 0.6 -
Air quality
monitoring
Partial discharge was found in 55% of 40 stations tested and 5% had unacceptable ozone levels.
It is proposed that air quality and partial discharge survey of all 150 indoor type stations be
completed to establish the quality of the air.
The DSO PR4 capex plan is for ozone detectors to be installed in 100 HV station locations to
assist in the future detection of ozone gas in stations or within cable boxes.
1.1 100 11,000
Applied
Reduction to
DSO PR4 unit
costs
7,700 0.8 -0.3
Storage facility
for used and oil
filled HV
equipment
Storage of usable spares and second hand equipment needs to be stored in a secure and
independent location which ensures no further damage of deterioration which may harm the
possible return to service of the equipment.
DSO has not yet finalised plans of either new site or extension to existing property is most
effective option - process still ongoing to assess options.
0.5 1 500,000
DSO proposed
PR4 unit costs
-
500,000 0.5 -
DSO
Page 139
HV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Bunding of
Transformers
near waterways
A large quantity of legacy transformers remain unbunded, this was addressed partly in PR3 when
a programme of installing bunding retrospectively was undertake in order to reduce the risk of
damaging the Environment.
It is proposed to continue with this programme in PR4 with a combination of either new retrofit
bunding of 38kV transformers (86) or upgrading of existing binding (150 locations).
4.2 236 17,797
DSO proposed
PR4 unit costs
-
17,797 4.2 -
Upgrade of
existing battery
systems
Programme of battery replacements at DSO stations was progressed in PR3. It is proposed to
continue this programme in PR4 with work focused on 24V systems at 250 locations where the Ni
Cad batteries and associated systems installed in period 1990 - 1993 have significantly
deteriorated to 45% of their design capacity and require replacement due to the dependency of
SCADA and protection on these assets.
Battery upgrades are also proposed for 50 major 110kV and 220kV stations.
4.8 300 16,000
DSO proposed
PR4 unit costs
-
16,000 4.8 -
Replacement of
110/38kV
Transformers
Replacement of 3 transformers that were installed between 1950 and 1960. Transformers of same
installation period have been associated with tap-changer and transformer faults.
Dungarvan T141, Manufacturer ACEC, 1953
Drumline T142, Manufacturer - METRO VICKERS, 1950
Thornsberry T142, Manufacturer – ACEC, 1965
5.5 3 1,833,333
DSO proposed
PR4 unit costs
-
1,833,333 5.5 -
Transformer Oil
Regeneration
Oil regeneration of 30 transformers during PR4, to extend the life of transformers that have acidity
approaching 0.1mg KOH/g to defer replacement work costs and fault/repair costs. 3.6 40 90,000
DSO proposed
PR4 unit costs 90,000 3.6 -
Roof repairs Replacement/refurbishment of 30 substation roofs based on station specific needs. Driven by poor
condition leading to increased moisture levels that can cause discharge of components. 1.4 30 46,667
Applied
reduction to
DSO proposed
PR4 unit costs
35,897 1.1 -0.3
Condition
Monitoring
Transformer condition monitoring plant has been used on DSO and TSO transformers since early
1990s, There are currently 3 units installed in -Mc Dermot, Crane and Dunmanway stations. DSO
proposes installation of 15 units on transformers that are at most risk of failure to allow constant
monitoring and early detection, which will allow corrective measures to be implemented.
0.7 15 33,333
Applied
reduction to
DSO proposed
PR4 unit costs
46,667 0.7 -
DSO
Page 140
HV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Station fence
upgrades
Increase in metal prices has been linked to a steady increase in the theft and break ins to HV
stations. DSO has progressed a programme during PR3 to replace chain-link fences with Palisade
fencing.
During PR4, the DSO proposes to upgrade 70 station fences to palisade (20 x 110kv; 50 x 38kV)
and 10 power fence installations based on prior history of break ins and existing condition of
fences.
10.3 70 147,143 Expected PR3
outturn costs
190,000
Power
Fence
115,000
Upgrade
10.0 - 0.4
Station
monitoring
The DSO proposes to improve station security at a number of its HV stations due to the cost
effective advantage over on-site guards to deter theft and allow possible action to be taken swiftly.
An installation comprising of a combination of either intruder alarms or CCTV system is proposed
by the DSO
9.2
High risk –
200 Fixed
CCTV
Medium
risk – 20
270
Intruder
alarms
198,000
(H)
121,000
(M)
13,000 (L)
DSO proposed
PR4 unit costs 9.2 -
Station
emergency
lighting
Programme deferred from PR3.
Installation in 544 HV stations (394 at 38kV; and 150 at 110kV) due to the need to compile with
regulations and many stations have out of date lighting.
2.9 544 5,331
Applied
reduction to
DSO proposed
PR4 unit costs
4,101 2.2 - 0.7
Door and lock
replacements
Continuation of programme associated with the replacement of wooden doors with high security,
multi point locking steel doors is proposed with the replacement of 200 deteriorating doors that
are proving a security risk to stations.
DSO also proposes a pilot scheme of locks with programmable keys - the introduction of 150 locks
that are programmable to personnel/time to deter future theft.
1.7 350 4,857 DSO proposed
PR4 unit costs 4,857 1.7 -
TOTAL 125.973 116.9 -9.0
73 Table 6.3 states €126.5m PR4 capex relating to HV Station Asset Renewal Programme
DSO
Page 141
In its response to our Interim Report, the DSO provided further details relating to a number of the sub work programmes, these details have been considered when
determining recommended allowances and resulted in increased capex compared to our Interim Report.
For a number of the sub-programmes associated with HV Station Asset Renewals, we have applied a reduction to the proposed unit costs that the DSO has
used in its PR4 forecast.
We have allowed the DSO’s proposed capex for flood mitigation, however the DSO has not provided a robust case that this is sufficient to provide
appropriate continuity.
These result in a recommended PR4 capex of €116.9m, a reduction of €9.0m compared to the detailed DSO forecast of €125.9m.
DSO
Page 142
5.2.2.4 MV Overhead Lines
DSO (revised) proposed PR4 capex is €82.2m, CER PR3 allowed capex of €70.7m, DSO current forecast for PR3 is €61.0m.
The proposed PR4 works associated with MV Overhead Lines are summarised in Table 5.26 below.
Table 5.26 : Summary of PR4 capex relating to MV Overhead Lines (€m – 2014 prices, unless stated otherwise)
MV Overhead
Lines – Sub
Category
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
Revised
PR4
Capex
(€m)
PR4
Revised
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
MV Overhead
Cyclical
Refurbishment
(OCR)
For PR4, DSO proposes to extend the 9 year MV overhead refurbishment programme (established
in PR3) to a12 year cycle. This decision is based on DSO risk assessment and decision informed
by relatively low volume of major defects encountered per km of line and the scope and standards
of OCR programme remain unchanged.
76.5 34,500 2,217 PR3 outturn
costs 2,100 72.5 -4.1
S and C spring
assisted fuse
tubes to
increase
reliability
An overhead fuse consists of a fuse base, a fuse tube and a replaceable fuse element. There are
100,000 fuse locations on the overhead networks There have been a number of mal-operations
encountered by the DSO with fuse tubes not dropping out, when the fuse blows Manufacturers
have developed fuse tubes, which incorporate an additional spring, to assist the fuse tube to open
when the fuse blows. It is proposed that this solution be applied for 1,000 fuses. This will reduce
safety risk and also help reduce the risk of fault hunting (extended outages).
0.3 1000 300 DSO proposed
PR4 unit costs 300 0.3 0.0
Triple pole
Switch TPS
replacement
The population of approx. 3,500 triple pole switches have been installed on the 20kV system since
the early 1990s. They are a means of ensuring triple pole switching at 20kV, as the previous
practice of single pole switching on overhead networks via single fuse cut-outs results in mal-
tripping of 20kV protective devices under a sensitive earth fault condition. DSO has experienced a
number of instances of deterioration of these switches, especially in coastal areas. The nature of
the problem is significant. Deterioration of the metal fixings and cement at the base of the 9 post
insulators on the assembly may result in metal/rust expansion that cracks the ceramic insulator.
When the device is being operated the cracked insulator fails and shatters. Operator is exposed to
the risk of falling ceramic shards and the electrical risk of a failed switch.
On inspection of the failed switches, investigations confirmed that the cement used to secure the
pins into the insulators was absorbing salts from the atmosphere and holding the salt in contact
with the pin, which was attacking the galvanised coating and subsequently the cast iron of the pin
0.6 100 6,000 DSO proposed
PR4 unit costs 6,000 0.6 0.0
DSO
Page 143
MV Overhead
Lines – Sub
Category
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
Revised
PR4
Capex
(€m)
PR4
Revised
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
itself.
Ongoing condition surveys are in place (2014) to determine scale of replacements required and
pending full survey results, the DSO has proposed replacement of 100 units during PR4.
MV Conductor
assessment and
replacement
Replacement of 100km of ACSR conductor on circuits that were constructed pre 1960 based on
condition assessments. Results of torsion tests from where line drops occur on aluminium strands
showed failure significantly below minimum acceptable level
3.1 100 31,000 DSO proposed
PR4 unit costs 31,000 3.1 0.0
Storm
Resilience
programme
Introduction of a pilot programme through targeted cutting of trees, use of covered conductor, line
diversions and potential undergrounding of network is proposed. 0.7 100 7,000
DSO proposed
PR4 unit costs 7,000 0.7 0.0
Creosote poles
alternative pilot
Pilot study of using alternative pole technologies such as: concrete, wood, galvanised steel, glass
reinforced fibre and alternative products to the wooden stay block. This will comply with the law of
phasing out creosote poles
1 1 1,000,000 DSO proposed
PR4 unit costs 1,000,000 1.0 0.0
TOTAL 82.2 78.1 -4.1
The DSO is proposing to inspect and refurbish where required, 34,500km of MV OHL as part of a 12 year cyclical refurbishment programme at a unit cost of more
than €2,200 per km. During PR3 period 2011 to 2014, the DSO has completed the refurbishment of approximately 18,400km at an expected unit cost of €2,100.
For PR4, the DSO is forecasting the unit cost will increase to €2,217 per km, representing an increase of more than 5%.We recommend allowances for PR4 based
on unit costs achieved during PR3 (2011 to 2014).
This reduction results in a recommended PR4 capex of €78.1m, a reduction of €4.1m compared to the DSO revised forecast of €82.2m.
In the DSO response to our Interim Report, the DSO also asserts the existence of a “principle” that PR3 outturn costs be recommended for PR4 unit costs.
Jacobs has not simply accepted the DSO’s PR3 outturn costs as being efficient and therefore acceptable for PR4. The PR3 capex has been subject to detailed
assessment and review to inform our opinion on appropriate allowances for PR4 – covering all of the DSO capex activities.
DSO
Page 144
5.2.2.5 MV Cables
The DSO proposes a zero capex associated with the renewal of MV cables as no planned capital activities are proposed for MV cable assets. PR3 allowed capex
was €2.6m, with PR3 expected outturn of €2.0m.
DSO
Page 145
5.2.2.6 MV Substations
DSO revised proposed PR4 capex is €33.2m, CER PR3 allowed capex of €24.7m, DSO current forecast for PR3 is €31.2m.
The proposed PR4 works associated with MV Stations are summarised in Table 5.27 below.
Table 5.27 : Summary of PR4 capex relating to MV Stations (€m – 2014 prices, unless stated otherwise)
MV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
Revised
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Replacement of
Indoor Oil-Filled
MV RMUs
No installation of these assets has been carried out in over 30 years and is now proving difficult to
source spare parts. After a number of explosive failures of RMUs at outdoor installations, the
necessity of replacements has been highlighted. It is proposed to remove all 130 units during PR4
Programme commenced in PR3 and proposed for completion in PR4
5.2
130
22,128
PR3 outturn
costs 21,840 2.8
0.0 Replacement of
Open-Cubicle
Switchgear in
Indoor MV
Substations
Proposed to remove the remaining 105 units during PR4. These units exhibit explosive failures and
other potentially dangerous failures. This will also reduce maintenance cost in future due to the
nature of the new equipment. Through the replacement this also allows the future conversion of the
10kV network to 20kV.
PR3 programme was to replace remaining units – although this was not completed. It is now
proposed to be completed during PR4
105 PR3 outturn
costs 24,200 2.5
Replacement of
MV/LV
Transformers in
Association with
Switchgear
Replacement
Planned to replace 43 units during PR4, through a continuation of the PR3 programme that was
approved. These units are no longer deemed safe or functional. In addition to this it is also
expected that the new low losses type transformers that will be put in their place will help reduce
losses overall
The PR4 replacement programme is a continuation of the PR3 programme
0.6 40 15,000
DSO
proposed PR4
unit costs
15,000 0.6 0.0
Replacement of
Magnefix Cast-
Resin Type
Switchgear
There are approximately 2200 Magnefix switches on the ESB system in 2014
In less than 18 months, there have been 16 Magnefix failures which resulted in fires leading to
units being burnt severely in many cases. After undertaking a survey of 200+ units it was found
that 55 units required urgent overhauls, while 40 units required immediate replacement.
20.5 400 51,250
Applied
Reduction to
DSO PR4 unit
costs
47,040 18.8 -1.7
DSO
Page 146
MV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
Revised
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
It is proposed to remove 400 units in PR4 which is an increase compared to the PR3 planned
volumes
PR4 replacement is part of 15-20 year programme to completely remove the asset population from
ESB network expectation
Replace RGB
Cast-Resin type
Switchgear
RGB switchgear has been subject to a programme of removal throughout PR3 such that only a
very small residual population is expected to remain at the beginning of 2016 – in the region of 60
units in total.
It is propose that the programme of removal from PR3 will be continued until they have been
completely removed from the system by the end of PR4.
1.1 60 18,333
DSO
proposed PR4
unit costs
18,333 1.1 0.0
Replace URD
Transformers
Over PR2 and PR3, many URD transformers have been removed and replaced with modern
ground mounted installations.
By the beginning of 2016 it is expected that only 34 units will remain. The PR4 replacement
programme plans to complete the removal of these URD transformers. This will reduce the risk of
failure as well as reducing the cost of maintenance as the need for annual inspections is removed.
1.9 34 55,882
Applied
reduction to
DSO
proposed PR4
unit costs
50,802 1.7 -0.2
Replace URD
LV Vaults
A survey of 40 units in the Tallaght area has shown that 25-30% of units required immediate
replacements for safety purposes.
DSO plans to replace 250 of these vaults and overhaul of a further 4,000 within PR4
1.3 250 5,200
DSO
proposed PR4
unit costs
5,200 1.3 0.0
Replace
Substation
Doors
Entirely based on the condition of the existing door, it is estimated that 200 wooden doors will
require replacement during PR4. These new steel doors will increase the safety to public as holes
in doors and unauthorised access will be eliminated and reduce the regular maintenance costs that
wooden doors require
Continuation of programme commenced during PR3
1.4 200 7,000
Applied
reduction to
DSO
proposed PR4
unit costs
5,385 1.1 -0.3
Shrouding of LV
Panels
Proposed addition of shrouding to 200 LV indoor and unit substation panels. Condition and
performance of unshrouded LV panels is acceptable and electrical faults are uncommon, however
a serious safety risk in relation to exposed live conductors present where unshrouded panels are
common
0.3 100 3,000
DSO
proposed PR4
unit costs
3,000 0.3 0.0
DSO
Page 147
MV Stations –
Sub Category Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
Revised
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Continuation of programme commenced during PR3
Station Civil
Upgrade works
Areas where substations are installed can become subject to illegal dumping which affects the
ventilation. Proposed steel caging or landscaping of a substation proves effective and is to be used
to upgrade 200 substations, however this will be site specific. This will reduce the risk of substation
failure and the clean-up cost of dumping is reduced which is a legal necessity for ESBN
1.0 200 5,000
Applied
reduction to
DSO
proposed PR4
unit costs
3,846 0.8 -0.2
TOTAL 33.2 31.1 -2.1
In its response to our Interim Report, the DSO has identified additional capex relating to the replacement of Magenfix Substations rather than Magnefix kiosks. We
have made an appropriate allowance for this.
For a number of the sub-programmes associated with MV Station Asset Renewals, we have applied a reduction to the proposed unit costs that the DSO has used in
its PR4 forecast.
These result in a recommended PR4 capex of €31.1m, a reduction of €2.1m compared to the DSO revised forecast of €33.2m.
DSO
Page 148
5.2.2.7 Urban LV Renewal
DSO revised proposed PR4 capex is €46.4m, CER PR3 allowed capex of €64.3m, DSO current forecast for PR3 is €36.2m.
The proposed PR4 works associated with Urban LV Overhead Line Renewal is summarised in Table 5.28 below.
Table 5.28 : Summary of PR4 capex relating to Urban LV Overhead Line Renewal (€m – 2014 prices, unless stated otherwise)
LV Urban
Renewal
Category
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Revised
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
LV Network
Renewal
The LV Urban overhead line programme addresses the refurbishment of bare LV network in urban
centres.
This programme is a continuation of a PR3 programme.
It is proposed that 14,000 spans of pre-1950 LV urban network be addressed in PR4. This
refurbishment work is essential to maintaining the safety and operability of these networks.
42.1 17,500 60,14374 PR3 outturn
costs 51,652 36.2 -5.9
Public lighting
Interface
Separation
Works
The DSO identified requirement for this work in its March 2015 response to our Interim Report. The
DSO states this sub programme is an immediate requirement to ensure the safety of the public
interface. No other details have been provided
4.3 €400,000 per
year 2.0 -2.3
TOTAL 46.4 38.2 -8.2
In its response to our Interim Report, the DSO clarified it is proposing to refurbish 17,500 spans of Urban LV overhead network (dating pre-1950) at a unit cost of
more than €60,000 per km.
During PR3, the DSO has completed the refurbishment of approximately 15,700 spans of network at an expected unit cost of more than €51,500 per km.
In support of its higher unit cost (>€60,000), the DSO has explained that the works are planned to be delivered mainly by contractor resources and the contractor
costs are driving up unit costs. The DSO has stated that the proposed networks that will be refurbished in PR4 are the same vintage as networks refurbished in
74 Unit Cost per km based on refurbishment of 17,500 spans and 25 spans per km of network
DSO
Page 149
PR3 and the PR4 programme will mainly consist of networks not completed in PR3
We remain of the view that there is insufficient justification to support a 20% increase in unit costs for this work and we recommend PR4 allowances based on the
expected outturn unit costs for PR3.
This reduction results in a recommended PR4 capex of €38.2m, a reduction of €8.2m compared to the DSO’s revised forecast of €46.4m.
In its response to our Interim Report, the DSO has also identified a new sub programme, not previously proposed. This sub programme relates to the separation of public
lighting from the DSO LV network. The DSO has not provided any further details about this newly described sub programme and consequently we cannot recommend full
allowances. We have suggested an allowance of €400,000 per year over PR4 period to commence this programme. We would expect the DSO to fully assess the network
risks and associated mitigations required during PR4.
DSO
Page 150
5.2.2.8 Rural LV Network
DSO revised proposed PR4 capex is €84.5m, CER PR3 allowed capex of €95.8m, DSO current forecast for PR3 is €84.1m.
The proposed PR4 works associated with Rural LV Overhead Line Renewal is summarised in Table 5.29 below.
Table 5.29 : Summary of PR4 capex relating to Rural LV Overhead Line Renewal (€m – 2014 prices, unless stated otherwise)
LV Rural Overhead
Lines Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Low Voltage Rural
Refurbishment (LVR)
DSO proposes continuation of LVR programme that commenced in PR2 focusing work on
the bare LV rural groups with intention to bring these rural networks back to a minimum
acceptable standard.
55.6 11,350 4,900 PR3 outturn
costs 4,550 51.6 -4.0
Programme to inspect
and complete remedial
works on networks not
included in PR2/PR3
programme
In addition to LVR programme, the DSO proposes a programme in PR4 to inspect and
complete remedial works on a risk basis on networks which were not included in the
PR2/PR3 programme. This will include bare networks which were last inspected during the
period 1996 – 2002, thus 20 years since last patrolled and remedial works completed. As
such, the condition of assets – particularly wood poles – which two decades ago had not
deteriorated to the point which warranted replacement may no longer be in fit condition for
continued service.
28.9 5,900 4,900 PR3 outturn
costs 4,550 26.8 -2.1
TOTAL 84.5 78.5 -6.0
The DSO is proposing to refurbish 11,350 bare LV rural groups and commence an additional programme to inspect and complete remedial works on LV rural
networks that have not been addressed since the mid-late-1990s (a further 5,900 groups).
In its response to our Interim report, the DSO has provided further information relating to PR3 outturn costs. The original submission implied a unit cost of €4,100
per LV group, although the DSO latest PR3 forecast suggests €4,550 per LV group.
The DSO has assumed an increase in PR4 unit costs driven by increased defect rates and contract costs. Having observed a 10% increase in PR3 unit costs from its
original submission to its revised submission we do not agree that a further 10% increase in PR4 is justified.
We recommend allowances for these works based on the DSO expected outturn unit costs during PR3. This reduction will result in a recommended PR4 capex of
DSO
Page 151
€78.5m, a reduction of €6.0m compared to the DSO revised forecast of €84.5m.
DSO
Page 152
5.2.2.9 LV Cables and associated items
DSO revised proposed PR4 capex is €16.4m75, CER PR3 allowed capex of €17.2m, DSO current forecast for PR3 is €6.2m.
The proposed PR4 works associated with LV cables and associated items is summarised in Table 5.30 below.
Table 5.30 : Summary of PR4 capex relating to LV cables and associated items (€m – 2014 prices, unless stated otherwise)
LV Cables and
Associated Items –
Work Categories
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Replace Painted Steel
Mini Pillars
DSO proposes a continuation of PR3 programme (affected by reduced volumes) relating to
the replacement of various types of mini pillar, dating from the 1970’s. Prioritisation of
replacement works will be based on the mini-pillar hazard patrol programme.
DSO also proposes to address the risks associated with dangerously degrading pillar
doors during PR4.
13 2000 6,500
Applied
reduction to
DSO proposed
PR4 unit costs
6,273 12.5 -0.5
Replace Cast Iron Mini
Pillars 1.3 200 6,500
Applied
reduction to
DSO proposed
PR4 unit costs
6,273 1.3 0.0
Replace Mini Pillar
Doors 0.4 1000 400
Applied
reduction to
DSO proposed
PR4 unit costs
386 0.4 0.0
Replace LV Link Boxes
DSO proposes further replacement of LV link boxes into PR4 – continuing the programme
from PR3. The main driver for this work is the age/condition of these items, (some >80
years old) with some models no longer having spare parts available.
0.3 100 3,000
Applied
reduction to
DSO proposed
PR4 unit costs
2,895 0.3 0.0
Replace 6mm2 Copper
Services
These are small cross-section service cables having a reduced rating. They are routed
within the interior of houses and pose a significant fire risk to the house and its occupants. 1.0 100 10,000
DSO proposed
PR4 unit costs 10,000 1.00 0.0
75 Updated Table 6.3 states PR4 capex of €16.4m. Previous PR4 capex was €16.4m. Within its response to our Interim Report, the DSO has identified a €0.2m reduction to its previous total of €16.4m and hence there is an obvious
inconsistency between Table 6.3 and the DSO response.
DSO
Page 153
LV Cables and
Associated Items –
Work Categories
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Ongoing replacement programme will reduce the risk to the public and also improve
continuity through the introduction of a single customer underground service cable rather
than the current looped service.
Replace LV 4-core
XLPE pole top
terminations
DSO proposes a programme in PR4 to replace 200 faulty pole-top terminations. These 200
cases are where there is no UV resistant material over the exposed cores where water can
flow into and react with the aluminium causing severe corrosion at ground level.
This is estimated to be less than 0.5% of the total population of LV terminations.
0.2 200 1,000 DSO proposed
PR4 unit costs 1,000 0.2 0.0
TOTAL 16.2 15.7 - 0.5
In relation to the renewal programme associated with LV cables and associated items, the DSO proposed works for PR4 are mainly a continuation of PR3
programmes.
We recommend allowances for these works based on the DSO expected outturn unit costs during PR3. This reduction will result in a recommended PR4 capex of
€15.7m, a reduction of €0.5m compared to the DSO forecast of €16.2m76.
In relation to Minipillars, minipillar doors and LV link box replacement programmes, the DSO response suggests that our minor unit cost reductions will be difficult to achieve during PR4. As the PR4 unit costs proposed in our Interim Report were based on our assessment of reasonable costs incurred by the DSO during PR3, we believe these costs are appropriate to set allowances for PR4 capex.
76 €16.4m in updated Table 6.3
DSO
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5.2.2.10 Meters and Time Switches
DSO proposed PR4 capex is €14.1m, CER PR3 allowed capex of €0.0m, DSO current forecast for PR3 is €0.0m.
In PR3, the DSO did not carry out any planned meter replacements – this was to avoid any potential duplication of work or inefficient investment related to a potential roll-out
of smart metering programme. The DSO has identified a large group of meters in need of replacement, which are unlikely to be part of any smart metering rollout and which
are suggested to be in need of replacement by the end of PR4. The smart metering programme, when implemented, will cater for replacement of meters for domestic
customers and smaller commercial customers. The population of profile meters, using CTs, will not be covered by the smart meter programme – the total population of meters
exceeds 36,000.
The proposed PR4 works associated with Metering and Time Switch Renewal is summarised in Table 5.31 below.
Table 5.31 : Summary of PR4 capex relating to Metering and Time Switch Renewal (€m – 2014 prices, unless stated otherwise)
Metering and Time Switch replacements
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4 Capex
(€m)
PR4 Volumes
PR4 Unit costs (€)
Unit Cost Assumptions
Unit Cost (€)
PR4 Capex
(€m)
CT Planned Meter
Replacement
DSO proposes to replace the external time switch meters with digital meters and these
replacements will ensure that the meter population will continue to operate to an
acceptable level.
The DSO PR4 programme caters for the replacement of 4,710 external time switch meters
and 12,507 digital meters (~55%).
11.3 17,217 654
DSO
Proposed PR4
costs
654 9.0 -2.3
Load Research Work
Program
CER has previously approved the installation of 1,800 load research recorders, allowing
representative sample data to be collected on customer behaviour across different
customer profiles.
Since then a number of the customers have been de-energised and changes in
consumption behaviour have depleted the quantity of sample meters.
The DSO proposes that 50 meters a year will be required in the PR4 period to ensure that
previous meters will not degrade and become unusable.
0.1 250 520
DSO
Proposed PR4
costs
520 0.1 -
DSO
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Metering and Time Switch replacements
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4 Capex
(€m)
PR4 Volumes
PR4 Unit costs (€)
Unit Cost Assumptions
Unit Cost (€)
PR4 Capex
(€m)
Non Quarter Hourly to
Quarter Hourly meter
replacements
CER determined that sites which consume over 300,000 kWh p.a must become quarter-
hourly sites.
The DSO estimates that 200 sites will become eligible for quarter-hourly metering during
each year of PR4 and as a result ESB is obliged to comply with the meter replacements.
0.5 1,000 500
DSO
Proposed PR4
costs
500 0.5 -
Replacement of Power
Quality Meters
Due to the 20 year service life of these meters and their importance, the DSO proposes to
replace 150 PQ meters during PR4. 0.1 150 933
DSO
Proposed PR4
costs
933 0.1 -
Communications Project
The quarter hourly data collection unit (Profile Data Services) is responsible for the
collection, validation and distribution of quarter hourly data for the market that covers
approximately 40% of DUoS billing.
Due to service level agreements with the market to provide quarter hourly information, this
is currently being done via SIM card using GSM.
Movement towards a more cost effective and technologically current solution (GPRS) is
being looked at with the introduction of a pilot study to see the benefits over the GSM
which has been in place for the last 10-15 years and will become increasingly difficult to
source materials and communications support for the older communications.
30% of sites polled by MV90 comms system will require replacement of both meter and
modem and 70% modem only.
Completion of these works will be informed by a pilot which is scheduled for 2015, after the
MV90 upgrade has been completed.
DSO will only undertake the broader scale upgrade works if the 2015 pilot project proves
successful*.
2.0 1 2,020,000
DSO
Proposed PR4
costs
1.0 -1.0
DSO
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Metering and Time Switch replacements
Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4 Capex
(€m)
PR4 Volumes
PR4 Unit costs (€)
Unit Cost Assumptions
Unit Cost (€)
PR4 Capex
(€m)
TOTAL 14.1 10.8 -3.3
We have made adjustments to the DSO PR4 forecast capex of €14.1m associated with meter replacement. We have adjusted for the CT metering to be replaced
during PR4 (80%) and PR5 (20%) rather than funding the replacement of the full population during PR4.
We have also recommended a reduction in capex associated with the funding for a pilot communication project only (GPRS) for quarter hourly data collection.
We have proposed an allowance of €1m rather than the €2m proposed by the DSO relating to a broad scale upgrade of the communications system, .We have
not been provided with detailed cost information to support the €2m project and we would also expect the DSO to prepare a business case to support the wider
scale investment.
These adjustments reduce the DSO PR4 forecast capex from €14.1m to €10.8m, a reduction of €3.3m
DSO
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5.2.2.11 Cut-outs
DSO proposed PR4 capex is €14.3m, CER PR3 allowed capex of €5.8m, DSO current forecast for PR3 is €4.0m.
The proposed PR4 works associated with cut-out replacements is summarised in Table 5.32 below.
Table 5.32 : Summary of PR4 capex relating to Cut-out replacements (€m – 2014 prices, unless stated otherwise)
Cut-out replacements Background
DSO PR4 Forecast PR4 Recommended Variance
to DSO
PR4
Capex
(€m)
PR4
Capex
(€m)
PR4
Volumes
PR4 Unit
costs (€)
Unit Cost
Assumptions
Unit Cost
(€)
PR4
Capex
(€m)
Replacement of pre
1976 Cut outs
The DSO is proposing to continue with cut-out replacement programme during PR4
focusing on pre 1976 Cut outs. These are generally located in hallways etc., compared to
modern cut outs that are installed outside of premises in metal containers. Their location
represents a fire risk to the premises.
DSO estimates there are as many as165,000 pre 1976 cut outs, of which 97,000 have
been investigated and replaced where necessary during PR2 and PR3.
14.3 40,000 357.5 PR3 outturn
costs 140 5.6 -8.7
The DSO is expecting to complete replacement of 30,000 cut-outs during PR3 at a total cost of €4.1m (unit cost of €140). The PR4 programme is to increase the
replacement volume to 40,000 although its proposed unit cost (€357) is considerably higher than expected PR3 outturn. We recommend PR4 allowances based
on the proposed DSO volumes and the PR3 expected outturn unit costs in the absence of ESBN evidence to support the higher proposed unit cost.
This results in a recommended PR4 capex of €5.6m, a reduction of €8.7m compared to the DSO forecast of €14.3m.
DSO
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5.2.3 Continuity Capex
DSO proposed PR4 capex is €13.5m77, CER PR3 allowed capex of €22.8m, DSO current forecast for PR3
is €14.0m.
This programme primarily consists of the installation of automatic and remote control switches and other
measures to improve the performance of the network. The various programmes are summarised in Table 5.33
below.
Table 5.33 : Summary of PR4 capex relating to Continuity Improvement (€m – 2014 prices, unless stated otherwise)
Improvement Programme Unit Volume Total
Cost €m Unit Cost € DSO BCR
Loop Automation Schemes 50 8.5 170,000 7.3
Single Phase Reclosers Spurs 150 0.6 4,000 2.1
Fault Passage Indicators Units 1,150 1.1 957 7.8
Worst Served Customers Customer 6,000 1.4 233 0.9
Remote Control of RMU's (PILOT Project) Unit 30 0.3 10,000
38kV Switch Automation Unit 30 1.3 43,333
Wildlife diverters in HV Stations Unit 300 0.3 1,000
MV Arc Suppression (Reinforcement Expenditure) Station 17 0 -
Total Capex
13.5
For PR4, the DSO proposes to further progress a number of continuity improvement programmes that
commenced in PR3 but were curtailed due to financing constraints and requirement to focus on safety driven
investments. Such programmes include further installation of:
Loop automation schemes – these comprise two interconnected MV networks with sufficient capacity to
provide backup supply to each other in the event of a fault on one of the interconnecting feeders. Typically,
five reclosers per two interconnecting feeders will be required.
Single Phase Reclosers – installation of reclosers on single phase spurs to address customer interruptions
due to transient faults, installed only on spurs where the calculated benefit is greatest.
Fault passage indicators – higher accuracy units (based on actual current measurements provided by
CT’s), indicating passage of fault current remotely. These units also communicate via GPRS and can be
integrated with the DSO SCADA system.
Improvements to worst served customers.
Smaller scale continuity improvements are also proposed by the DSO, including:
the fitting of ultrasonic bird diverters in HV stations.
installation of 30 remotely operable line switches on the 38kV network.
pilot project for urban RMU automation (deferred from PR3).
For each of the proposed continuity improvement programmes, the DSO has carried out cost-benefit analysis,
which has been used to prioritise its investment plans.
We recommend that the proposed DSO PR4 capex of €13.5m relating to its Continuity Improvement
programme is allowed.
This allowance includes €1.4m associated with a continuity programme to improve supplies to the
77 This incorporates €4.2m as per Table 6.3 Continuity Improvement Capex item plus a further €9.3m that the DSO categorised as ‘Other (specify)’
which the DSO has confirmed also relates to the Continuity Improvement capex work programme.
DSO
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DSO’s worst served customers. In its response to the proposed Incentives for PR4 (Document DR07)
the DSO has presented two separate scenarios to address worst served customers, based on available
information from UK DNOs (the UK RIIO ED1 decision documents). Once CER has finalised the DSO
PR4 incentive framework (including allowances, targets, penalties etc – there may be a requirement to
make an adjustment to theses recommended allowances for DSO continuity capex.
The CML/CI benefits associated with its Continuity Programme that have been identified by the DSO will be fully
assessed when determining appropriate network performance incentive targets for the DSO during PR4.
5.2.4 Response Capex
DSO PR4 revised proposed capex is €61.2m78; CER PR3 allowed capex of €101.1m, DSO PR3 forecast is
€56.5m.
This is a reactive work programme, generally driven by third parties or unplanned events. There are 9 existing
categories of reactive work against which the DSO allocates and monitors expenditure. Within its response to
our Interim Report, the DSO has identified a further category of reactive work associated with the theft of 38kV
Copper overhead lines The DSO proposed capex for each of these categories is summarised in Table 5.34
below and compared the equivalent expenditure and allowance in PR3.
Table 5.34 : PR4 Response Capex – Comparison of DSO Forecast v PR3 (€m – 2014 Prices)
Category CER PR3
Allowed
DSO PR3
Outturn
DSO Original
PR4 Proposed
DSO Revised
PR4 Proposed
Recommended
DSO PR4
Voltage Complaints 30.3 13.9 14.2 14.2 14.2
25mm SCA OH Conductor Replacement 9.5 4.0 4.2 4.2 4.2
MV/LV UG Cable Replacement. 8.8 2.3 2.0 2.0 2.0
Metering Replacement 7.9 4.8 2.6 2.6 2.6
Time-switch Replacement. 5.1 3.0 1.6 1.6 1.6
Failed Transformer Replacement 12.2 16.9 18.4 18.4 16.8
38kV Cable Replacement 5.7 2.2 0.9 0.9 0.9
Undergrounding MV & LV OH lines 16.5 6.5 6.6 6.6 6.6
Advance Ducting 5.1 0.8 0.7 0.7 0.7
38kV Copper Line - Theft Response 0.0 2.0 0.0 10.0 5.0
Totals 101.1 56.3 51.2 61.2 54.6
Note – Source data for DSO PR3 Outturn – Document Reference DH07 – PR3 Response Capex (Table 1) – converted to 2014 prices
In its response to our PR4 capex IR, the DSO explained the need for urgent works that are scheduled for 2015
to address risks associated with the theft of 50mm2 Copper conductor from 4 x 38kV overhead line circuits. The
works involved replacement of the copper conductor with aluminium conductor (of equivalent rating) and the
estimated capex for this new work programme is €2.0m in 2015.
We agree with the DSO proposed Response Capex for PR4 for the majority of the existing categories, other than for costs relating to failed transformers.
For this category, the DSO proposed a 10% increase on PR3 capex. We have not observed an increase in transformer failure rates during PR3 to justify this cost increase and therefore we have recommended a reduction for this category to the PR3 run-rate.
In addition, whilst we accept that there will be a need for the DSO to take action to address the theft of copper conductor from its overhead line network, we note this is a new category of reactive work for
78 Note – DSO Table 6.3 (April 2015) states €61.4m, whilst the DSO response to our Interim Report states €61.2m
DSO
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which the DSO has based PR4 forecast on a nominal €2m per year, this being the forecast costs for 2015 to address 4 specific circuits that have been subject to repeated thefts.
The DSO PR4 forecast is based on an assumption that similar quantities and works will be required on an annual basis for the PR4 period. However, in the absence of any detailed risk analysis, we cannot conclude if these figures are reasonable. We therefore recommend a PR4 allowance of €5.05m in total
This reduces PR4 continuity capex by €6.6m to €54.6m.
5.2.5 System Control Network Capex
DSO PR4 proposed capex is €16.5m; CER PR3 allowed capex of €15.4m, DSO PR3 forecast is €3.9m.
The DSO has identified a number of proposed system control projects79 that may be undertaken during PR4.
These fall into three main categories and are summarised below in Table 5.35, together with the DSO forecast
PR4 capex of each project.
Table 5.35 : PR4 System Control Expenditure for PR4 (€m – 2014 prices)
Expenditure Item Capex
(m)
OMS Related
OMS Upgrade 3.5
Mobile Interface 1.2
AMS Interface 1
Sub-Total 5.7
SCADA related
RTU Replacements 4.3
SCADA NM7 upgrade 0.8
Server Replacements 0.7
Sub-Total 5.8
Control Centre Infrastructure
Emergency Control Room 0.7
Back up Cello Station alarm (GSA) 0.5
Sub-Total 1.2
GRAND TOTAL 12.7
We have observed from the above table that the grand total of PR4 capex relating to the identified projects is
€12.7m, although the DSO has submitted a PR4 capex forecast of €16.5m. The DSO has acknowledged that
the correct amount sought was €12.7m. Generally, the DSO has not provided sufficient justification to support
the planned investment.
OMS has been upgraded in PR3; the DSO is proposing further upgrade in PR4 at a cost of €3.5m – with no
business case to support this investment. It is unlikely that within the 5 years there would be such a change in
the hardware and software for an operational system such as this, there may however be a need to carry out
some upgrading which is as yet not specified and provision of €1.5m would allow maintaining the system rather
than provisioning for an unknown requirement.
79 Identified within Narrative Document DF11 -
DSO
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There is also no business case for the proposed mobile interface with OMS, the DSO has however identified the
operational advantages and initiatives to provide facilities such as switching instructions direct to the mobile
transport and real time network updates and would therefore allow the mobile interface of €1.2m.
Regarding AMR interface, we recommend this should be considered separately within the context of the smart
meter roll out programme, this being consistent with DSO PR4 submission excluding smart metering.
We recommend PR4 funding relating to SCADA and Control Centre Infrastructure at a total capex of
€9.7m. This represents a reduction of €3.0m compared to aggregate total of €12.7m80.
5.2.6 Integrated Vision for an Active Distribution Network (IVADN)
The DSO has proposed PR4 capex of €7.1m in relation to its R&D project titled “Integrated Vision for an Active
Distribution Network” (IVADN). The DSO narrative document ‘DF09a IVADN’ provides background information
relating to this project.
Key focus areas for the project will be:
Setting out the revised vision for the planning and operation of the Distribution System in an optimised
manner which is fit for purpose to 2025.
Reviewing European Codes to ensure impacts on system planning and operations are fully understood.
The transposition of Network Code non-exhaustive requirements into the Distribution Code.
Engagement with the TSO within DS381 to ensure that the Distribution System operates in a manner which
can facilitate achieving 75% System Non-Synchronous Penetration (SNSP) target, whilst maintaining
Distribution standards and DSO license obligations
The project involves a number of study work streams to analyse network subjects such as MV Regulator issues,
38kV Regulator issues, Reactive Power studies and Distribution System Management.
The DSO has identified a number of workstreams within the scope of the IVADN project and provided estimated
costs for each workstream. The capital costs can be summarised as follows:
Reactive Power Workstreams - €3.5m
Rate of Change of Frequency (ROCOF) Protection Alternative - €2.0m
Remote Control of MV Boosters €0.4m
Power Quality (PQ) Recorder Replacement €1.2m
Sub Total €7.1m82
Although the DSO has forecast €7.1m in PR4, it is unclear what the specific project deliverables and
benefits will be. There appears to be significant uncertainty regarding how this R&D project will
proceed and what it will cost (both capex and opex).
We therefore recommend that the DSO is allowed the capex costs associated with the reactive power
work stream (of €3.5m) as these are well advanced.
In the absence of detailed plans for the other work streams we recommend additional total allowance
of €1m. We also suggest that the DSO continues to engage with the CER during PR4 once details of
the particular projects, including timing, cost, expected benefits, etc. are known in more detail.
Our total recommended allowance is therefore €4.5m which is €2.6m lower than the DSO proposed
PR4 forecast of €7.1m.
80 A reduction of €6.8m compared to the DSO forecast of €16.5m for PR4 (within Table 6.3) 81
DS3 - Delivering a Secure Sustainable Electricity System (DS3) – Eirgrid /Soni Programme (http://www.eirgrid.com/operations/ds3/) 82 In addition, there is a further €3.6m identified relating to OMS upgrades (considered separately within System Control Capex)
DSO
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5.2.7 North Atlantic Green Zone (NAGZ)
The DSO PR4 capex forecast includes €87.6m associated with the NAGZ project. The DSO is the project co-
ordinator of this project which will, subject to acquisition of the necessary grant funding, implement a Smart Grid
on an infrastructural scale in the North-West of Ireland. The project partners in this consortium are:
1) ESBN
2) Northern Ireland Electricity
3) EirGrid
4) SONI
The NAGZ project aims to address the challenges faced by network system operators across Europe as the
penetration of renewable generation increases to unprecedented levels. This project is intended to marry
intelligent electricity networks, high-speed communications and IT, coupled with increased cross-border
connectivity, with the objective of achieving operational excellence and ensure the involvement of all users. It
will be the blueprint for future network deployment on the island of Ireland and across Europe.
Project elements include:
20kV conversion from medium voltage networks – 12,000km
Dynamic Active Distribution System Management
Network automation and upgraded protection systems (part of PR3 and will form part of work programmes
for PR4 & PR5). This consists of a combination of the following:
- Three Phase Reclosers (102)
- Switches (167)
- Fault Passage Indicators (279)
- Single Phase Reclosers (186)
- Widespread Arc Suppression protection systems will be deployed - to all the 20kV networks in the
North Atlantic Green Zone – 23 station installations.
Cross Border Interconnection - Interconnection is a crucial part of the NAGZ project. As this is a first for
both DSOs at MV level, it will require significant discussions and development from both a planning and
operational perspective, as well as involving EirGrid and SONI. Route corridors have been identified from
the initial European Commission submission stage but now detailed surveys are required.
Advanced Communications (Optical fibre network) - optical fibre network deployed on the 38kV system
connect all of the 38kV stations to the backbone communications network. This will entail the fibre
wrapping and sub-ducting of approximately 377km of 38kV network. In addition to the deployment of fibre,
NAGZ also involves the deployment of an advanced WiMax wireless mobile field area network to connect
all medium voltage down-line sensors and devices.
The total benefits stated in the NAGZ CBA report are €246.2m with the net benefits standing at €130.7m over
20 years. The NAGZ has a total project cost of €106m – with the costs split between ESB Networks (€70m) and
NIE (€36m).
The main capex cost components include:
Deployment of ASC Systems: €16.2m
20kV Conversion: €14.9m
Fibre & WiMax communications: €16.6m
Network Automation and DMS: €16.3m
Interconnection with NI: €4.1m
DSO
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The NAGZ project received an award of €31.75m in grant funding from the European Commission in November
2014.The funding provided to the DSO is expected to be €22.2m83 and this will need to be netted off the gross
capex requirements for PR4.
The NAGZ has a total project cost of €106m – with the costs split - DSO: €70m, NIE: €36m. The DSO
PR4 capex forecast includes for €87.6m associated with the NAGZ project, which has also recently
received grant funding of €31.75m from the EC, with the expectation that the DSO will receive €22.2m
of this grant.
These facts suggest that the proposed DSO PR4 capex forecast of €87.6m relating to the NAGZ is
higher than necessary.
We also note that the NAGZ main capex cost components include works for which allowances have
been separately assessed (e.g. PR4 20kV conversion programme and upgraded protection schemes
within the DSO PR4 Continuity Improvement) and for which capex allowances will be made for PR4.
There is a potential risk of duplicating capex allowances as it is not clear that the overall network
assessment has explicitly excluded network assets within the NAGZ.
In its response to our Interim Report, the DSO has advised that all of the 20kV conversion work
undertaken during PR4 will be outside the NAGZ.
We recommend that the CER provides gross capex allowances for the NAGZ during PR4 of €70m – the
DSO proportion of the NAGZ total cost, netted off by the amount of CEF funding of €47.8M.
5.2.8 Non Load Related Expenditure – Summary of Allowances
The previous sub-sections have detailed the DSO’s proposed PR4 capex relating to its asset renewal
programmes and its other non-load related capex plans. For each category, we have made recommendations
on proposed capex allowances for PR4 period and these recommendations are summarised below in Table
5.36. Based on the information available from the DSO at the time of writing this report, we recommend that the
PR4 NLR Capex is reduced from €694.3m to €564.0m, a reduction of €105.1.
Table 5.36 : PR4 – Non Load Related Capex – Summary (€m – 2014 prices)
Category of work DSO Original PR4
Proposed
DSO Revised PR4
Proposed
Revised
Recommended PR4
PR4 Variance PR4
Recommended v
DSO Revised
Forecast
Renewal Programme - 110kV &
38kV Lines 46.5 38.4 27.5 -10.9
Renewal Programme - 110 &
38kV Cables 24.5 28.0 25.8 -2.2
Renewal Programme - HV
Substation 126.4 125.9 116.9 -9.6
Renewal Programme - MV
Overhead Lines 131.9 82.2 78.2 -4.1
Renewal Programme - MV
Cables 0.0 0.0 0.0 0.0
Renewal Programme - MV
Substations 23.3 33.2 31.1 -2.1
Renewal Programme - Urban LV 46.5 46.4 38.2 -8.3
83 DR06 Addendum contributions
DSO
Page 164
Category of work DSO Original PR4
Proposed
DSO Revised PR4
Proposed
Revised
Recommended PR4
PR4 Variance PR4
Recommended v
DSO Revised
Forecast
Renewal
Renewal Programme - Rural LV
Network 74.8 84.5 78.5 -6.0
Storm Rectification Project 0.0 0.0 0.0 0.0
Renewal Programme - LV cables
and associated items 16.2 16.2 15.7 -0.5
Renewal Programme - Meters
and Time Switches 14.0 14.1 10.8 -3.3
Renewal Programme - Cut-outs 14.3 14.3 5.6 -8.7
Continuity Improvement 13.5 13.5 13.5 0.0
Response capex 51.2 61.2 54.6 -6.8
System Control 16.5 16.584 9.7 -6.8
IVADN (Integrated Vision for an
Active Distribution Network)
Project
7.1 7.1 4.5 -2.6
NAGZ 87.6 87.6 70.0 -17.6
Other (specify) - Included in
CONTINUITY Programme above 0.0
TOTAL 694.4 669.1 580.5 -90.6
5.3 Non Network Related Expenditure
The DSO has forecast a total non-network related capex of €172.2m in PR4. This is €33.4m higher than the
actual Non-Network capex of €138.9m in PR3, representing an increase of 24%.
The detailed breakdown of the Non Network Capex is shown below in Table 5.37 (as submitted in the initial
forecast questionnaire).
Table 5.37 : Detailed Breakdown of PR4 Forecast Non-Network Capex (€m 2014 prices) by Category
Category PR4 Forecast PR3 Actual
2016 2017 2018 2019 2020 Total Total
New Accommodation - - - - - - -
Accommodation Refurbishment 2.96 2.96 2.96 2.96 2.96 14.8 11.2
Fixture & Fittings 0.14 0.14 0.14 0.14 0.14 0.7 0.1
Office Equipment - - - - - - 0.0
Vehicles 6.0 6.0 6.0 6.0 6.0 30.0 35.1
Tools 2.0 2.0 2.0 2.0 2.0 10.0 15.6
Distribution Assets Management
Distribution Control / Operation 17.7 12.5 9.5 11.5 7.7 58.9 42.3
IT Infrastructure
84 As per DSO FBPQ Table 6.3 dated 5th Dec 2014
DSO
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Enterprise Applications
Environment 0.8 0.8 0.8 0.8 0.8 4.0 1.9
Telecoms & System Control 11.3 12.6 11.6 9.3 9.2 53.9 17.0
Non Rab Telecoms - - - - - - 15.7
Total 40.9 36.9 33 32.6 28.8 172.2 138.9
In general the DSO has increased expenditures in all areas excluding Tools, and has prioritised significant
increases in areas of Vehicles, Accommodation, Enterprise Applications and Telecoms. Although there are
significant increases in some areas there was an underspend against the PR3 allowances due to financial
constraints within the business. It is likely that there will be some element of catching up with the DSO capex
expenditure in PR3.
We discuss the proposed PR4 expenditures in the sub-sections below.
5.3.1 Accommodation Fixtures and Fittings and Office equipment
The DSO has forecast that the capital expenditure for PR4 on refurbishment will be €2.96m per year and an
additional €0.14m per year on fixtures and fitting giving a total forecast of €15.5m over PR4. This is in
comparison with an average of €2.0m per year in PR2 and €2.3m per year in PR3.
This increase has been put down to the fact that during PR3 capital restrictions were in place and only
necessary refurbishment took place. The plan for PR4 is that general coordinated refurbishment will continue
due to the expectation that gaining capital will be less of an issue. 60% of the DSO buildings are currently over
20 years of age and as a result were not designed to meet current accommodation standards. This therefore
appears to be a reasonable justification for an increase in expenditure due to the age and condition of buildings.
In supporting documentation submitted by the DSO the requested €15.5m was split as shown in Table 5.38, the
only difference being to segregate out the budget to include Safety and Security as part of the overall
refurbishment and fixtures and fittings budget.
Table 5.38 : Forecast Building Expenditure PR4 (€m – 2014 prices)
Years 2016 2017 2018 2019 2020 Totals
Refurbishment €2.3m €2.3m €2.3m €2.3m €2.3m €11.3m
Safety €0.5m €0.5m €0.5m €0.5m €0.5m €2.5m
Security €0.5m €0.2m €0.2m €0.2m €0.2m €1.0m
Furniture & Fittings €0.1m €0.1m €0.1m €0.1m €0.1m €0.7m
Office Equipment €0.1m €0.0m €0.0m €0.0m €0.0m €0.0m
Totals €3.1m €3.1m €3.1m €3.1m €3.1m €15.5m
The expenditure in safety and security equates to €3.5m in PR4, of which €1m of this is forecast for upgrading
security systems due to the number of successful break-in attempts during PR3 at a cost of €0.2m per year.
ESBN have stated that €0.5m per annum is to be spent on the safety aspect of refurbishment and is expected
to be an output from a number of initiatives. These initiatives are:
Documentation including risk assessment updates appropriate to the location, updates to documented safe
methods of work, safety audits and local emergency plans.
Survey/Inspection/Audit particularly updates to premises survey and audits (including asbestos) particularly
those locations where there are high staff concentrations, building inspections with findings classified and
implemented according to whether they are emergency, urgent or best practice and radon testing (which is
a requirement for all premises).
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Implementation of Group-wide standards and Best Practices - Electrical (e.g. RCD and Portable Appliance
Testing), Mechanical (e.g. Lifts, Air Handling and Plumbing) and Structural.
The decommissioning of HVAC units that contain R22 Gas has to be completed within the next five years
per a recent clarification from the EPA on the subject.
Water quality standards also require annual testing for legionella and appropriate risk mitigation actions will
be required to ensure compliance with safety standards.
Total PR4 forecast expenditure on Refurbishment and Fixtures and Fittings reflects an increase over
PR3 of €4.2m, but is €2.8m less than the PR3 allowance.
Given the capex constraints in PR3 it seems reasonable that there would be an increase over the PR3
outturn to ensure the buildings are maintained and secure. We therefore recommend allowances of
the full €15.5m.
5.3.2 Vehicles
The total expenditure forecast for PR4 is €30.0m, with expenditure incurred at a rate of €6.0m per annum. The
profile of vehicular expenditure is shown below in Figure 5.12.
Figure 5.12 : DSO Vehicles – Annual Expenditure Profile (€m)
The DSO reports that they are re-commencing capex expenditure on the fleet vehicles beginning in 2014 and
2015 and continuing throughout PR4 at a rate of €6m per year. In the submission in November 2014 (Ref DF32)
the forecast for Vehicles was for an outturn of €17.2m for PR3 and a proposed expenditure of €30m in PR4 to
satisfy the business requirements.
An updated forecast issued by the DSO in March 2015 shows a significant change in the outturn for PR3
increasing from the €17.2m to €35.1m (effectively doubling the expenditure expected in PR3 from the forecast
in November 2014. This change was reportedly due to incorrect forecasting of the later years of PR3. The
0
5
10
15
20
25
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
An
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Exp
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(ém
)
DSO Forecast Mar 2015 DSO Forecast Dec 2014
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previous submission stated that the increase in expenditure in 2014 and 2015 was the start of the increase
planned through to 2020, with a total expenditure over the seven years of €44.0m.
The latest forecast shows an expenditure of €31.8m in 2014 and 2015 whilst still maintaining an expenditure of
€30m for the 5 years of PR4 to 2020, increasing the total expenditure between 2014 and 2020 to €61.8m
compared to the €44.0m expected in the earlier forecast.
In addition, we recognise that the initial forecast in PR3 was well below expenditure in PR2 and was due to
unavailability of funds. We understand the need to ensure vehicles are properly managed and accept that the
expenditure increase in 2014 and 2015 will recover the underspend in 2011 2012 1nd 2013. It is evident that the
forecast for PR4 does not fully reflect the efficiencies being driven by the introduction of the Mobile Workforce
Management system. In addition the issues raised in the PA Consulting Transport review( ref ESBN document
DF 32) identified many issues relating to under-usage of vehicles and there should be further opportunities to
reduce the fleet rather than replace based on utilisation, avoiding dedicated vehicles and increase use of shared
vehicles. The costs identified in the company response of increasing maintenance costs for HGV vehicles would
suggest that the priority be given to advancing the HGV replacement while deferring the vans and cars, where
with relatively lower mileages, the maintenance costs would be considerably lower. The case put in DR06 would
have been significantly higher than the proposed requirements in DF32, and some of the points raised are
indeed identifying potential opex savings..
Due to the significant increase in expenditure in 2014 and 2015, we would anticipate that there should
be an opportunity to defer some expenditure pending a thorough review of the utilisation and volume
requirements following efficiencies driven by Mobile Workforce Management systems.
We have therefore proposed an allowance of €23.75m compared to the €30m DSO forecast over PR4,
a reduction of €6.25m.
5.3.3 Tools
The forecast PR4 capex for tools is €10m; this has been reduced from the PR3 total of €14.8m and
represents good progress in developing efficiencies. The proposal is to allow the €10m.
5.3.4 IT associated with Asset Management, Control/Operations, IT Infrastructure and Enterprise
Applications
The forecast IT expenditure on Non Network Capex is shown below in Table 5.39 and equates to €58.9m over
the PR4 period. This indicates an increase of 39% over the PR3 outturn of €42.3m.
Table 5.39 : DSO PR4 Forecast Non Network IT Expenditure
IT Capex 2016 2017 2018 2019 2020 Totals
Mobile Workforce Management €4.1m €4.1m €4.1m €4.5m €3.8m €20.6m
Document Management System €5.5m €2.4m €0.0m €0.2m €0.0m €8.1m
Web & SW Development €3.9m €4.0m €2.3m €2.9m €2.4m €15.9m
PC Hardware & Accessories €1.3m €0.8m €0.2m €0.7m €0.4m €3.4m
Upgrades €2.9m €1.3m €2.8m €3.2m €0.7m €10.8m
Total €17.7m €12.5m €9.4m €11.5m €7.7m €58.9m
The table above comes from the ESBN pdf ‘DF 15 IT Projects’. The assessment of these programmes is
provided below.
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Mobile Workforce Management
The DSO has identified a €20.6m programme covering mobile applications for inspections, reacting to faults,
timesheet reporting and forms for completing in the field. The documentation states there are substantial
quantifiable benefits of implementing this programme. The DSO states that “these benefits will be refined during
the scope and design stage of each project as it is initiated”. This is a substantial investment and could
potentially drive benefits, however to approve such funds in advance of submission of associated business
cases will likely result either in an underspend or in potentially wasteful costs.
We would expect to see an operational initiative defining a forecast efficiency in delivery of operations resulting
in opex and capex efficiency with a net benefit for this investment. Some additional information has been
provided identifying potential savings of 105 FTE’s both back office and field staff. The forecast headcount
within ESBN over the period of the introduction of this system is shown below in Figure 5.13. Although there
are numerous areas where there may be a requirement to increase headcount, the potential reduction of 105
FTE’s would be expected to show a larger impact on the overall headcount and flow through as reduced opex in
the maintenance and restoration activities, and reduced unit costs in the capex activities. Neither of these are
evident in the submission.
Figure 5.13 : DSO Headcount
There are obvious benefits to utilising Mobile Workforce Solutions and we would expect this to be progressively
developed with break points reflecting on the delivered benefits, the additional information provided has
indicated a sound business case and would be supported, however the forecast opex and capex costs do not
appear to reflect the benefits, we are therefore not inclined to change our view that €12.5m, averaging €2.5m a
year to be justifiable unless there is a demonstrated saving identified in costs in line with the business case
figures provided. The DSO have presented the case for this expenditure and we fully support the potential
benefits , however we maintain that the increase in cost in this area should have been offset by at least an
equivalent amount within PR4 and going forward in PR5.
Total PR4 forecast expenditure on Mobile Workforce Management reflects an increase over PR3 of
€14.2m. Given the potential benefits of this, it would be expected that a detailed business case driven
by the efficiency and cost benefit would be apparent. There has been information suggesting that the
business case justifies this, however this does not seem to be reflected in the submission for capex
and opex in the areas suggested within the business case.
It is therefore proposed that the programme in PR4 should be €15.0m, a reduction of €5.0m from the
DSO forecast. We would however emphasise that we are not constraining this initiative which we fully
support and would encourage the DSO to progress this rapidly to ensure the benefits are delivered
early. The additional costs will be offset by the benefits and make this self-financing.
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Document Management System
In Document DF15 there is a list of benefits associated with the Document Management System, but these do
not have any tangible quantified benefit listed. We would expect the DSO to identify benefits leading to future
efficiencies. The document management system is proposed at a cost of €8.1m in PR4 years 2016 and 2017
after an initial €0.94m of expenditure in PR3 with the majority being forecast for 2015 (Tab 6.2 Historic
Questionnaire). We would not expect the expenditure to be incurred mainly in 2016 when a clear business case
with tangible benefits are not presented with options for reducing expenditure where delivered benefits are not
being achieved. ESBN has provided further information listing deliverables and restating the €8.1m, however
the document also states;
“This project is required to deliver a fit for purpose document management system to contribute to an overall fit
for purpose Safety Management System. The existing document management systems have been found to be
not appropriate and this project must proceed. This project does not have a traditional business case supporting
the expenditure for these reasons.”
The driver may be clear cut and the need stated relates to safety and viewed in that light. We would fully
support efforts to improve safety and deliver systems which would achieve this, however the need does not
detract from the necessity to carry out a detailed business case, which is essential in clearly defining the need,
identifying a number of potential solutions with each approach and option delivering a range of benefits at a
range of costs. This would then be challenged to ensure the need is satisfied at the optimum cost. The danger
in not taking this approach would be to incur costs inefficiently and we would recommend carrying out the
business case urgently to determine opportunities to scope the project more efficiently. We would therefore
suggest reducing the amount to €6.9 m.
Total PR4 forecast expenditure on the Document Management System reflects an increase from
€0.94m in PR3 (all forecast in 2014 and 2015) to €8.1m in PR4. Given the potential benefits of this, it
would be expected that a detailed business case driven by the efficiency and cost-benefit would be
apparent. As this is not the case, then it is proposed to reduce the value proposed by €1.2m to €6.9m
5.3.5 Environment
The forecast DSO PR4 Environmental capex figures show a relatively significant increase when compared with
both PR2 and PR3. The average annual expenditure that the DSO has forecast for the PR4 period is €0.8million
as shown in Figure 5.14 below.
Figure 5.14 : DSO Non Network Capex Environment Expenditure PR2 to PR4 (€m – 2014 prices)
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Within the PR2 period, the average expenditure on this category was €0.1million with very low and in some
cases, zero expenditure. Within PR3, the average expenditure of €0.4million was half the DSO forecast for PR4.
The DSO justification for this increase in expenditure in PR4 has been based on a number of services. The
largest component of the expenditure is related to wood pole storage, which is forecast for an increase and a
total expenditure of €1.4million. The rationale for this is that many of the DSO’s storage facilities are currently
not up to best practice standard and require upgrading to prevent any further contamination to wood poles.
The DSO has also stated that there will be a forecast increase in oil management, depot drainage infrastructure
improvements, waste management and energy efficiency with regards to buildings nationwide in PR4.
The DSO has identified a number of specific projects where there is a requirement for remedial action to
improve the storage areas for poles and reduce potential contamination. We recommend that the allowance is
in line with their proposal of €4m.
Total PR4 forecast expenditure on Environment is €4m compared to €1.9m in PR3, there are a number
of projects specified which require remedial action particularly associated with pole storage. It is
recommended that the proposal of €4m is allowed. .
5.3.6 System Control and Telecoms
The forecast expenditure on System Control and Telecoms is €53.9m. In PR3 the expenditure was €17.0m on
System Control and Telecoms plus €15.7m on Non RAB Telecoms. These are now amalgamated with the
assets being added to the RAB. The projects which account for the forecast expenditure are as shown in Table
5.40 below.
Table 5.40 : Forecast PR4 Capex - System Control and Telecoms (€m – 2014 prices)
Project Title Project Costs
3.2.1 Provision of Telecommunications Connectivity for HV Locations
3.2.1.1 WAN Expansion of Operational Fibre Network into HV Stations €4.0 m
3.2.1.2 Expansion of Services of Existing Operational WAN €1.7 m
3.2.1.3 Microwave Radio Expansion & Network Enhancement €2.7 m
3.2.1.4 Reinforcement & Growth of Satellite Network €1.5 m
3.2.1.5 New Protection Schemes – Network Distribution €1.2 m
3.2.1.6 Provision of Connectivity for Migration of Teleprotection Services off 3rd Party Circuits €0.2 m
3.2.2 Telecommunications Network Infrastructure Replacement
3.2.2.1 Polling Radio Replacement €2.9 m
3.2.2.2 Replacement of Microwave Radio Network €2.1 m
3.2.2.3 Replacement of Obsolete Add/Drop Equipment €0.4 m
3.2.2.4 Pilot Cable Termination Replacement €0.3 m
3.2.3 Substation SCADA Infrastructure
3.2.3.1 Transducer/HV Telemetering €0.9 m
3.2.3.2 RTU Flash Upgrade €0.6 m
3.2.4 Operational Voice and Telephony Services
3.2.4.1 NCCC Upgrade €4.7 m
3.2.4.2 OpTel Replacement €1.1 m
3.2.4.3 IPT Network Access Infrastructure €1.4 m
3.2.4.4 Voice & Video €0.6 m
3.2.5 Critical Supporting Infrastructure and Systems
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3.2.5.1 Power Systems €3.2 m
3.2.5.2 Air Conditioning €1.0 m
3.2.5.3 Network, Service & Work Management Systems €0.7 m
3.2.5.4 Network Management Infrastructure €0.4 m
3.2.5.5 ConnectMaster €1.1 m
3.2.6 Telecommunications Network Expansion & Technology Developments
3.2.6.1 Core & Aggregation IP Network €11.9 m
3.2.6.2 National Radio Access Communications Network €5.3 m
3.2.6.3 New Telecom Projects & Trials €4.0 m
Total €53.9 m
The supporting documentation lists the various systems and provides some explanation of the capabilities of the
equipment and the potential functionality, however there is no clear quantitative assessment of the business
case with explanation of need and options to justify the cost and selected option and scale.
There is limited explanation of the impact of not progressing these activities, or the options to reduce the scale
and timing of the delivery programme to ensure the need is clearly defined and the projects scaled to meet the
defined need. If the investment in all of these areas does not proceed there needs to be a clear understanding
of the impact and the mitigation to minimise the impact.
Figure 5.15 shows the DSO historic expenditure and the forecast for PR4.
Figure 5.15 : PR3 and PR4 Forecast Telecoms and Control Expenditure (2014 prices)
The major expenditures of Core & Aggregation IP Network, National Radio Access Communication Network and
New Telecoms projects and Trials (unspecified) represents €21m of the Total Forecast. These are all geared to
an unspecified growth in sensors on the network and described as:
-
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4
6
8
10
12
14
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
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“an enabler in efficiently meeting the evolving energy needs of electricity customers…This single
consolidated new generation network will be a fundamental building block in fulfilling the existing and future
communications requirements of the electricity network. This core network will also provide a platform for
replacing legacy technologies and systems that are approaching end of life. In addition it will act as a key
enabler of smart network operations.”
This seems to be geared to building new infrastructure against a need that is not quantitatively defined and
without defining the constraints within the existing infrastructure. There has been additional information provided
but not a standard business case with explanation of drivers, relating to quantitative measures which would
allow an assessment of the appropriate timing and appropriateness of this investment and an impact evaluation
of mitigating approaches to the investment. The key amounts from Table 5.39 relating to core and aggregation
IP Network and National Radio Access Network are major changes in infrastructure which were viewed as ‘Non
RAB’ expenditure and provide services for the networks business but also provide services to third parties,
which generates an income. It seems inappropriate to fund capex entirely from the regulated business with the
capital allowed revenues, and then have services provided to 3rd
parties, which are not linked to the investment.
It is recognised that income is offset in the regulated business but if fully funded and guaranteed, there appears
to be no major driver to maximise the potential revenue from third parties to ensure the regulated electricity
customer is benefiting from the investment. Mixing regulated and unregulated expenditures can also be seen as
a potential issue for the competition in these unregulated areas. It is proposed to accept the need for the
expenditure on the Core & Aggregation IP Network and National Radio Access Communication Network, but
there should be the opportunity to recover this investment if these projects don’t proceed preventing the
expenditure being used in other areas which will not generate additional income.
As there has been a significant increase in the proposed budget and insufficient detail provided to show
optimum cost effective solutions have been provided then it is proposed to apply a 10% efficiency target
equating to €5.4m.
Total PR4 forecast expenditure on Control and Telecoms is €53.9m compared to €32.6m in PR3. The
business case for the expenditure has not been clearly demonstrated and it is believed that there
should be opportunities for driving efficiencies from this budget. It is therefore recommended that the
proposed allowance should be reduced by €5.4m giving the PR4 allowance as €48.5m. It is also
recommended that the expenditure allowance is dependent on delivery of the Core & Aggregation IP
Network and National Radio Access Communication Network.
5.3.7 Non-Network Capex – Recommendations and Conclusions on Proposed Allowances
In conclusion there are a number of areas where there is justification for maintaining and increasing
expenditure, however there are other areas where there are proposed significant increases where there has not
been sufficient justification and a demonstrated business case showing need, options and risk associated with
the proposed increases. Table 5.41 shows the aggregate allowance for Non Network Capex for the PR4
period.
Table 5.41 : Summary of DSO Proposed Non Network Capex PR4 (€m – 2014 prices)
Non Network Capex - Category Actual PR3 DSO Forecast PR4 Recommended PR4
New Accommodation - - -
Accommodation Refurbishment 11.2 14.8 14.8
Fixture & Fittings 0.1 0.7 0.7
Office Equipment 0.0 - -
Vehicles 35.1 30.0 23.75
Tools 15.6 10.0 10.0
Distribution Assets Management 42.3 58.9 52.5
Distribution Control / Operation
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IT Infrastructure
Enterprise Applications
Environment 1.9 4.0 4.0
Telecoms & System Control 17.0 53.9 48.5
Non RAB Telecoms 15.7 - -
Total 138.9 172.3 154.3
5.3.8 Smart Metering Expenditure
The DSO PR4 forecast for capex associated with smart metering is €22.9m with these costs expected to
be incurred in 2016 (€12.5m) and in 2017 up to end June 2017 (€10.3m). Outturn Capex during PR3 is
€12.9m.
The PR4 forecast costs are proposed by the DSO to deliver its responsibilities in the National Smart Metering
Program (NSMP) until mid-2017, recognising the gated approach that the CER has adopted.
The final decision to award contracts arising from the procurement project rests with the NSMP following
reassessment of an updated CBA. At this point in Q2 2017 it is expected that CER will be in a position with
sufficient cost information to enable a final decision on how to proceed.
The staged nature of the overall NSMP is reflected in the DSO PR4 submission which states total costs that are
likely to be incurred up to that CER decision point and these costs are sought as a CAPEX allowance.
The DSO has identified a number of work streams necessary up to this gate position:
Project Management and stakeholder engagement - The ongoing management and control of the program
including networks work-stream and engagement with stakeholders including program at CER.
Deliver key smart metering procurements - This activity will be focused on the procurement of
communications services, meters and the meter Data Management System products and services.
Design and Delivery of Critical Backend IT upgrades.
Full rollout phase planning and preparation.
The DSO has only provided details of the €22.9m split by year, with no indication of planned capex
relating to each of the work streams and the capex deliverables necessary to facilitate the roll-out of
the smart metering program. Without a clear understanding of how the proposed capex is to be
invested, what physical assets are being delivered, we are not able to recommend full allowances.
In the absence of detailed supporting justification, we recommend PR4 allowances set at PR3 outturn
levels - €12.9m representing a reduction of €10.0m compared to the DSO PR4 submission.
5.4 Summary & Conclusions
5.4.1 Capex Overview
In headline terms, the DSO is forecasting a total gross expenditure of €1.7bn for PR4. This is €433m (25%)
lower than PR3 allowed capex of €2.15bn and €391m higher than PR3 actual/forecast capex of €1.33bn.
Net of customer contributions, the DSO is forecasting total PR4 capex of €1.48bn. This is €273m lower
than PR3 allowed capex and €351m higher than PR3 actual/forecast capex of €1.13bn.
The DSO PR4 forecast can be described in headline terms by the following characteristics:
- Demand Connections – DSO is forecasting a total number of connections in PR4 of 108,000 – this
represents an increase of 53% compared to the total of 70,417 during PR3, but is still only 33% of the
total number of connections made during PR2;
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- The DSO is forecasting 0% cumulative growth in peak demand during PR4 – reinforcement
expenditure during PR4 is focused on addressing parts of the system which do not presently comply
with the Planning Standards;
- Capex (gross) associated with generator connections is forecast to increase by 23% from €88.9m in
PR3 to €109.5m to connect a total of 1,250 MW of renewable generation over PR4 period (compared
to 1,200 MW expected by the end of PR3);
- Capex associated with non-load related projects and programmes is the category where the DSO is
forecasting the largest increase in capex in PR4 compared to PR3 – with a variance of €245.6m
(around 58%). The renewal programmes for which the DSO has forecast the largest increases in
capex in PR4 relate to HV Station works and HV and MV overhead line works. The DSO’s plans are
focused on the replacement of aging and defective assets. Non-load related Capex was the area
most affected during PR3 by capital funding constraints, so a larger catch-up allowance is to be
expected.
- In addition, the DSO has included €87.6m of PR4 capex relating to the North Atlantic Green Zone
(NAGZ) smart grid initiative;
- The forecast increase in PR4 non-network capex (of 24%) is driven by increased expenditure on
vehicles, Distribution Asset Management (including IT infrastructure), Telecomms and System Control;
- In relation to the Smart Metering project, the DSO submission for PR4 includes for further
development and project costs necessary to take the project to the next major milestone in 2017. It
does not include capex associated with a country-wide roll out programme as the final investment
decision has not yet been taken.
We have carried out an assessment of the DSO’s proposed capex plan and we have identified a number of
recommended adjustments to the allowed capex for PR4 – these are explained in more detail within the
preceding sections of the report.
Following our assessment, we recommend PR4 net capex allowance of €1336.78m – representing a
reduction of €144.381m. The PR4 capex proposed by DSO, together with our recommended allowances
are itemised below.
Table 5.42 : DSO PR4 Capex Summary (€m – 2014 Prices)
SUMMARY OF ALLOWANCES PR3
Allowed
PR3
Actual
PR4
Requested
(Table 6.3)
Revised PR4
Requested
(Table 6.3)
PR4
Recommended
Variance
(Recommended
to Revised
Request)
(G1) New housing Schemes 74.6 16.7 46.5 44.2 45.1 0.9
(G2) Non-scheme Houses 164.4 89.0 106.1 107.7 102.6 -5.1
(G3) Commercial/Industrial Supplies 212.5 120.8 128.5 129.8 125.3 -4.5
Whole Current Metering 12.5 14.7 24.1 19.5 17.8 -1.8
New Business 464.0 241.2 305.2 301.2 290.8 -10.4
Transmission Connection Costs 26.3 0.0 15.2 15.2 15.2 0.0
110kV 236.1 144.4 150.4 150.4 150.4 0.0
38kV 215.2 86.5 85.9 85.9 85.9 0.0
MVLV System Improvements 70.8 34.5 40.9 40.9 36.3 -4.6
IFTs associated with 20kV
Conversion 16.6 22.9 0.0 11.1 11.1 0.0
20kV Conversion 83.0 36.5 25.4 14.3 13.9 -0.4
Reinforcements 648.1 324.7 317.8 317.8 312.8 -5.0
Generation Connections 166.5 88.9 109.5 109.5 109.5 0.0
Dismantling 58.8 48.3 70.2 64.4 55.1 3
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SUMMARY OF ALLOWANCES PR3
Allowed
PR3
Actual
PR4
Requested
(Table 6.3)
Revised PR4
Requested
(Table 6.3)
PR4
Recommended
Variance
(Recommended
to Revised
Request)
Non-Repayable Line Diversions 53.1 48.3 92.1 60.2 50.6 -9.6
Total Load Related CAPEX 1390.4 751.3 894.8 853.1 818.7 -34.4
Renew Prog - 110kV & 38kV Lines 16.7 15.5 46.5 38.4 27.5 -10.9
Renew Prog - 110 & 38kV Cables 21.0 6.2 24.5 28.6 25.8 -2.8
Renew Prog - HV Substation 120.4 77.1 126.4 126.5 116.9 -9.6
Renew Prog - MV Overhead Lines 70.7 61.0 131.9 82.2 78.2 -4.1
Renew Prog - MV Cables 2.6 2.0 0.0 0.0 0.0 0.0
Renew Prog - MV Substations 24.7 31.2 23.3 33.2 31.1 -2.1
Renew Prog - Urban LV Renewal 64.3 36.2 46.5 46.4 38.2 -8.3
Renew Prog - Rural LV Network 95.8 84.1 74.8 84.5 78.5 -6.0
Storm Rectification Project 0.0 27.4 0.0 0.0 0.0 0.0
Renew Prog - LV cables and
associated items 17.2 6.2 16.2 16.4 15.7 -0.8
Meters and Time Switches 0.0 0.0 14.0 14.1 10.8 -3.3
Renew Prog - Cut-outs 5.8 4.0 14.3 14.3 5.6 -8.7
Continuity Improvement 22.8 14.0 13.5 13.5 13.5 0.0
Response capex 101.1 56.5 51.3 61.4 54.6 -6.8
System Control 15.4 3.9 16.5 16.5 9.7 -6.8
IVADN 0.0 0.0 7.1 7.2 4.5 -2.6
NAGZ 0.0 0.0 87.6 87.6 70.0 -17.6
Other (specify)85 0.0 0.0 0.0 0.0 0.0 0.0
NRP/ Bulk Supply 0.0 0.0 0.0 0.0 0.0 0.0
Total Non-Load Related CAPEX 578.5 425.4 694.4 671.0 580.5 -90.6
Capex - Non Network 183.5 138.9 172.2 172.2 154.3 -18.0
Other (Smart Metering) 0.0 12.9 22.9 22.9 12.9 -10.0
Contributions -398.3 -198.5 -200.1 -238.2 -229.8 8.4
TOTAL NET CAPEX 1754.1 1130.1 1544.3 1481.0 1336.9 144.2
5.4.2 Demand Connections
The DSO PR4 forecast capex (gross) is €301.2m, this is €60.0m (25%) higher than the expected PR3
outturn total capex of €241.2m. Net of customer contributions, the DSO PR4 forecast capex is €150.6m,
some €14.0m higher than expected PR3 outturn.
The increase in gross capex as forecast by the DSO for PR4 period is based on an increased number of
connections for each of G1/G2/G3 categories. Steady growth during PR4 is forecast by the DSO and a
total of 108,000 connections are expected to be made over this period, representing a 53% increase to
PR3 volumes.
85 Included within the Continuity Work Programme
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We consider that the DSO PR4 forecast of new connections of 108,000 is a reasonable assumption for
tariff purposes, recognising that CER will make adjustments for higher or lower connections based on
allowed unit costs.
The DSO has proposed standard unit costs for each of the G1/G2/G3 connections. We have concluded
that the proposed DSO unit costs for 2016 and 2017 are reasonable. However we recommend that the
additional costs that the DSO has factored in to its unit cost calculation from 2018 onwards should be
removed, this being consistent with the DSO a priori assumption that its forecast does not include for the
introduction of smart metering.
A reduction in allowed PR4 gross capex of €8.7m is recommended for PR4 demand connections, based on
difference in unit costs for G1/G2/G3 connections.
For PR4, the DSO is forecasting total metering capex of €19.5m – this is €4.8m (32.6%) higher than PR3
expected outturn costs and €7.0m (56.3%) higher than PR3 allowed costs.
We recommend allowances for PR4 period based on 6.5% of our recommended PR4 gross capex for
G1/G2/G3 connections of €273m. This results in a recommended allowance for metering of €17.8m
representing a reduction of €1.8m compared to the DSO revised PR4 proposed capex of €19.5m.
5.4.3 Generator Connections
For generator connections, the DSO is forecasting gross capex in PR4 of €109.5m. This represents an
increase of 24.4% compared to expected PR3 outturn.
Capex during PR4 will therefore be focused on these Gate 3 projects that have contracted since mid-2013.
The DSO is estimating that a total of 1,250 MW is to be connected to the distribution system during PR4.
As expected in our review of DSO historic capex, the over-recovery of connection costs in later years of
PR3 is resulting in net positive cash flows throughout the PR4 period, with a total net capex over the PR4
period of €47.4m.
We recommend acceptance of the DSO proposed gross capex of €109.5m.
5.4.4 Load Related Reinforcement
The DSO load-related reinforcement capex for the PR4 period is €317.8m. Although this is significantly
below the PR3 allowed capex of €648.1m, it is only €6.9m (2.1%) lower than DSO expected outturn
(€324.7m) for the PR3 period.
The DSO’s proposed PR4 reinforcement capex forecast has been prepared on a zero cumulative load
growth forecast for peak demand from 2013 - 2020. The DSO has made significant investment to reinforce
the network during previous price controls. However, there are still many parts of the network that do not
comply with the Planning Standard.
Unit sales (GWh) during PR4 are forecast to grow at approximately 2.2% per year. The DSO has assumed
that that the unit sales growth does not result in peak demand growth.
Zero load growth and peak demand reduction due to smart metering impact act to suppress the capex
forecast requirements for PR4 relative to previous price controls.
We are satisfied that the DSO has established good practice relating to its preparation of investment plans
for its 110kV and 38kV network development and undertaking project investment appraisals before seeking
technical and financial approval and subsequent commitment of capex to a project.
Notwithstanding some errors and/or inconsistencies with the consolidated list of HV reinforcement projects
compared to individual projects and which are not considered to be material, we conclude that the DSO
proposed PR4 reinforcement capex for 110kV and 38kV is reasonable.
The DSO has proposed a total of €40.9m of reinforcement capex relating to the MV and LV network. The
proposed PR4 capex (€40.9m) represents a 18.8% increase compared to expected costs for PR3
(€34.5m), although considerably less than PR3 allowed costs of €70.8m.
We generally agree with this work being necessary although we would recommend allowances for PR4
such that PR3 actual and PR4 forecast capex is consistent with the PR3 allowed capex of €70.8m – this
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was allowed to address known network deficiencies and is considered adequate for the DSO’s zero growth
scenario. In addition we would expect the ongoing 20kV conversion programme to improve the network
and reduce reinforcement requirements.
This will reduce PR4 allowances for MV/LV System reinforcements by €4.6m to €36.3m (a reduction of
11%).
With regard to the 20kV conversion programme, the DSO expected PR3 volumes (10,500km) and capex
(€36.5m) result in a unit cost per km converted of approximately €3,475/km. The DSO proposed PR4
programme is based on converting 4,000km at the same unit cost, giving a total cost of €13.9m. Further
IFT works at cost comparable with PR3 are also proposed. We consider these to be reasonable costs and
consequently we recommend PR4 allowance of €25.0m.
5.4.5 Retirements (Dismantling) Capex
We recommend PR4 allowances for dismantling which are derived as a proportion of our recommended
PR4 gross network capex – with allowances set at 4.1% of this gross value - this results in a recommended
PR4 capex for dismantling of €55.17m, representing a reduction of €9.39m compared to the DSO forecast
of €64.4m.
5.4.6 Diversions
It is observed that there is a strong historic relationship between new business gross costs and diversion
gross costs. However, the DSO forecast is not consistent with this historic relationship. We therefore
recommend PR4 allowances for diversion works that are consistent with the historic relationship between
new business and diversion gross costs. We have applied this to our recommended allowances for New
Business gross capex.
This results in a PR4 forecast capex for diversions of €50.6m, representing 17.4% of PR4 gross new
business capex. This is €9.6m (16%) lower than the DSO revised forecast of €60.2m and €42.5m (45%)
lower than the DSO original forecast of €92.1m.
5.4.7 Non-Load Related Capex
The DSO’s revised non load-related (NLR) capex for the PR4 period is €669.1m. This is significantly above
the expected PR3 outturn capex of €425.4m, although only €92.5m higher than the CER allowed capex for
non-load related capex during PR3.
The main drivers for the proposed PR4 works are to address safety risks, ensure compliance with health &
safety and environmental obligations and to maintain continuity of supply. Replacement works are driven
by the condition and performance of particular asset categories. The DSO NLR PR4 programme consists
of the following projects/programmes:
- Completion of major 110kV and 38kV HV Station replacement projects originally planned for
completion in PR3 but subsequently deferred due to prevailing financial situation at the time;
- Continuation of existing HV & MV asset renewal and security programmes to mitigate safety risk to the
public and the DSO workforce;
- Continuation of cyclical refurbishment of the 38kV & MV overhead lines, together with a project to
rebuild a number of 110kV double circuit tower lines in the Dublin area;
- Commencement of a small number of targeted asset renewal/ refurbishment programmes
- NAGZ is a major smart grid investment initiative aimed at addressing the impact caused by increasing
levels of renewable generation. The project will look to combine intelligent smart grid networks, high
speed communications and IT, linked with increased cross-border connectivity
- The proposed plans also include for a small number of relatively low cost pilot projects to allow for
assessment of emerging/ different technologies before any decision is made regarding roll out of such
technologies on a wider scale. The costs of these are presently incorporated within the DSO’s main
asset renewal programme categories but these could be ring-fenced within the DSO PR4 R&D
forecast expenditure category
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In general, we consider the justification for the various PR4 works proposed by the DSO is proven and in
many cases, we agree with the proposed volumes of work. However, our review has identified a number of
significant increases in the DSO PR4 planned costs, compared to PR3 planned costs (for deferred works)
or PR3 expected outturn costs (for works progressed during PR3).
We have therefore made proposed adjustments to the proposed DSO PR4 non-load related capex to
account for such differences where the DSO has been unable to provide further justification supporting
such increases in planned costs for its major projects and its planned unit costs for its asset renewal work
programmes.
In relation to the 38kV Overhead Cyclical Refurbishment Programme, the DSO revised forecast for PR4 is
based on a unit cost which is consistent with outturn cost in PR3. We recommend allowances for PR4 that
are consistent with the PR3 outturn unit costs.
In relation to the re-conductoring of 110kV double circuit tower lines in the Dublin area, it is our
understanding that there has not yet been any detailed line survey and analysis to inform the assessment
of the potential costs and that the DSO has not yet fully developed its proposed investment case. The DSO
PR4 forecast is therefore based on a middle-ground cost scenario. However, taking a low cost based on a
line refurbishment using existing towers, and a high cost based on fully undergrounding and stating that a
half way position is part underground, part tower replacement and part fittings replacement does not
constitute a planned investment.. We would however agree that the requirement to carry out the lowest
cost practical solution at this time seems reasonable and therefore would recommend this cost of €6.8m.
We do recognise the risk associated with this cost uncertainty and therefore once the DSO has developed
its planned investment for these circuits, this should be reviewed to assess the efficiency of their proposed
investment during PR4.
The proposed changes result in PR4 recommended capex of €27.5m for 110kV and 38kV lines (with capex
reduced by €10.9m).
Our recommended PR4 capex allowances for 110kV and 38kV cable asset renewal works is €25.8m
broadly in line with DSO original capex submission of €24.5m within Table 6.3 of Forecast Business Plan
Questionnaire, but some €2.2m less than the DSO’s revised capex submission of €28.0m.
For a number of the sub-programmes associated with HV Station Asset Renewals, we have applied a
reduction to the proposed unit costs that the DSO has used in its PR4 forecast. These result in a
recommended PR4 capex of €116.9m, a reduction of €9.0m compared to the DSO forecast of €125.9m.
The DSO is proposing to inspect and refurbish where required, 34,500km of MV OHL as part of a 12 year
cyclical refurbishment programme at a unit cost of more than €2,200 per km. During PR3 period 2011 to
2014, the DSO has completed the refurbishment of approximately 18,400km at an expected unit cost of
€2,100. For PR4, the DSO is forecasting the unit cost will increase to €2,217 per km, representing an
increase of more than 5%.We recommend allowances for PR4 based on unit costs achieved during PR3
(2011 to 2014).
This reduction results in a recommended PR4 capex of €78.1m, a reduction of €4.1m compared to the
DSO revised forecast of €82.2m.
The DSO proposes a zero capex associated with the renewal of MV cables as no planned capital activities
are proposed for MV cable assets. PR3 allowed capex was €2.6m, with PR3 expected outturn of €1.8m.
For a number of the sub-programmes associated with MV Station Asset Renewals, we have applied
reduction to the proposed unit costs that the DSO has used in its PR4 forecast. These result in a
recommended PR4 capex of €31.1m, a reduction of €2.1m compared to the DSO revised forecast of
€33.2m.
The DSO is proposing to refurbish 17,500 spans of Urban LV overhead network (dating pre-1950) at a unit
cost of more than €60,000 per km. During PR3, the DSO is forecasting to complete the refurbishment of
approximately 15,700 spans of network at an expected unit cost of more than €51,500. In support of its
higher cost (>€60,000), the DSO has explained that the works are planned to be delivered mainly by
contractor resources and the contractor costs are driving up the unit costs. The DSO has stated that the
proposed networks that will be refurbished in PR4 are the same vintage as networks refurbished in PR3
and the PR4 programme will mainly consist of networks not completed in PR3. We remain of the view that
there is insufficient justification to support a 20% increase in unit costs for this work and we recommend
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PR4 allowances based on the expected outturn unit costs for PR3. This reduction results in a
recommended PR4 capex of €38.2m, a reduction of €8.2m compared to the DSO’s revised forecast of
€46.4m.
The DSO is proposing to refurbish 11,350 bare LV rural groups and commence an additional programme to
inspect and complete remedial works on LV rural networks that have not been addressed since the mid-
late-1990s (a further 5,900 groups). We recommend allowances for these works based on the DSO
expected outturn unit costs during PR3. This reduction will result in a recommended PR4 capex of €78.5m,
a reduction of €6.0m compared to the DSO forecast of €84.5m.
In relation to the renewal programme associated with LV cables and associated items, the DSO proposed
works for PR4 are mainly a continuation of PR3 programmes. We recommend allowances for these works
based on the DSO expected outturn unit costs during PR3. This reduction will result in a recommended
PR4 capex of €15.7m, a reduction of €0.5m compared to the DSO’s revised forecast of €16.2m.
We have made adjustments to the DSO PR4 forecast capex of €14.1m associated with meter replacement.
We have adjusted for the CT metering to be replaced during PR4 (80%) and PR5 (20%) rather than
funding the replacement of the full population during PR4. We have also recommended a reduction in
capex associated with the funding for pilot communication project only (GPRS) for quarter hourly data
collection. We have proposed an allowance of €1m rather than the €2m proposed by the DSO relating to a
broad scale upgrade of the communications system. We have not been provided with detailed cost
information to support the €2m project and we would also expect the DSO to prepare a business case to
support the wider scale investment. These adjustments reduce the PR4 forecast capex from €14.1m to
€10.8m, a reduction of €3.3m.
The DSO is expecting to complete replacement of 30,000 cut-outs during PR3 at a total cost of €4.1m (unit
cost of €140) in PR3. The PR4 programme is to increase the replacement volume to 40,000 although its
proposed unit cost (€357) is considerably higher than expected PR3 outturn. We recommend PR4
allowances based on the proposed DSO volumes and the PR3 expected outturn unit costs in the absence
of evidence from the DSO to support the higher proposed unit cost. This results in a recommended PR4
capex of €5.6m, a reduction of €8.7m compared to the DSO forecast of €14.3m.
For each of the proposed continuity improvement programmes, the DSO has carried out cost-benefit
analysis, which has been used to prioritise its investment plans. We recommend that the proposed DSO
PR4 capex of €13.5m relating to its Continuity Improvement programme is allowed. This allowance
includes €1.4m associated with a continuity programme to improve supplies to the DSO’s worst served
customers. In its response to the proposed Incentives for PR4 (Document DR07) the DSO has presented
two separate scenarios to address worst served customers, based on available information from UK DNOs
(the UK RIIO ED1 decision documents). Once CER has finalised the DSO PR4 incentive framework
(including allowances, targets, penalties etc – there may be a requirement to make an adjustment to theses
recommended allowances for DSO continuity capex.
We agree with the DSO proposed Response Capex for PR4 for all categories, other than for costs relating
to failed transformers. In addition, whilst we accept that there will be a need for the DSO to take action to
address the theft of copper conductor from its overhead line network, we note that this is a new category of
reactive work for which the DSO has based PR4 forecast on a nominal €2m per year, this being the
forecast costs for 2015 to address 4 specific circuits that have been subject to repeated thefts. The DSO
PR4 forecast is based on an assumption that similar quantities and works will be required on an annual
basis for the PR4 period. However, in the absence of any detailed risk analysis, we cannot conclude if
these figures are reasonable. We therefore recommend a PR4 allowance of €5m in total. This reduces
PR4 continuity capex by €6.6m to €54.6m.
We recommend PR4 funding relating to SCADA and Control Centre Infrastructure – at a total capex of
€9.7m. This represents a reduction of €3.0m compared to the aggregate total expenditure of €12.7m80 for
PR4.
In relation to the IVADN project, the DSO has forecast €7.1m in PR4. However it is unclear what capex is
proposed by the DSO during PR4 and what the project deliverables and benefits will be. There appears to
be significant uncertainty regarding how this R&D project will proceed and what it will cost (both capex and
opex).
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We therefore recommend that the DSO is allowed the capex costs associated with the reactive power work
stream (of €3.5m) as these are well advanced.
In the absence of detailed plans for the other work streams, we recommend additional total allowance of
€1m. We also suggest that the DSO continues to engage with the CER during PR4 once details of the
particular projects, including timing, cost, expected benefits etc. are known in more detail. Our recommend
allowance is therefore €4.5m, which is €2.6m lower than the DSO proposed PR4 forecast of €7.1m.
The NAGZ has a total project cost of €106m – with the costs split between the DSO (€70m) and NIE
(€36m). The DSO PR4 capex forecast includes for €87.6m associated with the NAGZ project, which has
also recently received grant funding of €31.75m from the EC. These facts suggest that the proposed DSO
PR4 capex forecast relating to the NAGZ is higher than necessary.
We also note that the NAGZ main capex cost components include works for which allowances have been
separately assessed (e.g. PR4 20kV conversion programme and upgraded protection schemes within the
DSO PR4 Continuity Improvement) and for which capex allowances will be made for PR4. There is a
potential risk of duplicating capex allowances as it is not clear that the overall network assessment has
explicitly excluded network assets within the NAGZ. The DSO has advised that all of the 20kV conversion
work undertaken during PR4 will be outside the NAGZ.
We recommend that the CER provides gross capex allowances for the NAGZ during PR4 of €70m – the
DSO proportion of the NAGZ total cost.
5.4.8 Non-Network Capex
The DSO has forecast a total capex of €172.2m by end of PR4 – this is €33.4m higher than the actual Non-
Network capex of €138.9m in PR3.
There are a number of areas where there is justification for maintaining and increasing expenditure,
however there are other areas where there are proposed significant increases where there has not been
sufficient justification and a demonstrated business case showing need, options and risk associated with
the proposed increases.
Total PR4 forecast expenditure on Refurbishment and Fixtures and Fittings reflects an increase over PR3
of €4.2m, but is €2.8m less than the PR3 allowance. Given the capex constraints in PR3, it seems
reasonable that there would be an increase over the PR3 outturn to ensure the buildings are maintained
and secure. We therefore recommend allowances of €15.5m in line with the forecast.
Total PR4 forecast expenditure on Vehicles at €30m was based on a forecast outturn in PR3 of €17.2m.
Since December 2014 the forecast outturn for PR3 has increased to €35.1m. We have therefore adjusted
the PR4 allowance based on the increased expenditure in 2014 and 2015. We do not believe the forecast
fully exploits improved utilisation and vehicle reduction based on savings driven by the Mobile Workforce
Management system, recommended allowance is therefore €22.75m.
The forecast PR4 capex for tools is €10m; this has been reduced from the PR3 total of €14.8m and
represents good progress in developing efficiencies. The proposal is to allow the €10m.
Total PR4 forecast expenditure on Mobile Workforce Management reflects an increase over PR3 of
€14.2m. Given the potential benefits of this, it would be expected that a detailed business case driven by
the efficiency and cost benefit would be apparent. Some information has been provided which suggests
significant opex and capex savings within the business. However this saving is not reflected in the
submission in those areas. It is therefore proposed that the programme in PR4 should be €15m, a
reduction of €5m from the DSO forecast. We would comment that we fully support the full implementation
of this initiative which should not be constrained by the allowance. The allowance reflects that savings
elsewhere not provided at this time will make the initiative self-financing.
Total PR4 forecast expenditure on the Document Management System reflects an increase from €0.94m in
PR3 (all forecast in 2014 and 2015) to €8. 1m in PR4. Given the potential benefits of this, it would be
expected that a detailed business case driven by the efficiency and cost benefit would be apparent. As this
is not the case, then it is proposed to reduce the value proposed by €1.2m to €6.9m.
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Total PR4 forecast expenditure on Environment is €4m compared to €1.9m in PR3. There has been some
information provided identifying where the additional expenditure is needed therefore it is recommended
that this is allowed at €4m.
Total PR4 forecast expenditure on Control and Telecoms is €53.9m compared to €32.6m in PR3. The
business case for the expenditure has not been clearly demonstrated and it is believed that there should be
opportunities for driving efficiencies from this budget. It is therefore recommended that the proposed
allowance should be reduced by €5.4m giving the PR4 allowance as €48.5m. It is also recommended that
the expenditure allowance is dependent on delivery of the Core & Aggregation IP Network and National
Radio Access Communication Network.
The DSO PR4 forecast for capex associated with smart metering is €22.9m with these costs expected to
be incurred in 2016 (€12.5m) and in 2017 up to end June 2017 (€10.3m). Capex during PR3 is €12.9m.
The DSO has only provided details of the €22.9m split by year, with no indication of planned capex relating
to each of the work streams and the capex deliverables necessary to facilitate the roll-out of the smart
metering program. Without a clear understanding of how the proposed capex is to be invested, what
physical assets are being delivered, we are not able to recommend full allowances.
In the absence of supporting justification, we recommend PR4 allowances set at PR3 outturn levels - €12.9m
representing a reduction of €10.0m compared to the DSO PR4 submission.
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6. Conclusions
The DSO has proposed a total PR4 opex allowance (excluding commercial costs and Depreciation) of
€1506.0m. We have reviewed each line item and consider that a reduced allowance of €1399.1m is sufficient
for an efficient DSO to operate.
We have suggested that the DSO develops an appropriate method to understand the asset heath of its asset
portfolio, in order to understand the overall level of maintenance required and to inform future Asset
Maintenance and Replacement Programmes. We have also allowed, in full, the Health and Safety Allowance in
order to provide the DSO staff and the public with a safe operating environment.
With regard to capex, in headline terms, the DSO is forecasting a total gross expenditure of €1.72bn. This is
€433m (25%) lower than PR3 allowed capex of €2.15bn and €391m higher than PR3 actual/forecast capex of
€1.33bn. Net of customer contributions, the DSO is forecasting total PR4 capex of €1.48bn. This is €273m lower
than PR3 allowed capex and €351m higher than PR3 actual/forecast capex.
We have carried out an assessment of the DSO’s proposed capex plan and we have identified a number of
recommended adjustments to the allowed capex for PR4. Following our assessment, we recommend PR4 net
capex allowance of €1336.9m – representing a reduction of €144.2m..
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Table 6.1 : DSO Allowed Opex Revenue for PR4
DSO Proposed PR4 Jacobs Proposed PR4
Variance % 2016 2017 2018 2019 2020 Total 2016 2017 2018 2019 2020 Total
OPEX
Capital Driven Opex
Network O&M Total 114.4 117.9 116 116.7 116.1 581.1 105.8 109.2 107.3 108.0 107.4 537.7 -43.4 -7%
Asset Management 14.0 14.2 14.4 14.7 15.0 72.3 14.0 14.2 14.4 14.7 15.0 72.3 0.0 0%
Metering 40.4 38.0 34.2 33.9 33.6 180.1 34.7 35.0 32.4 32.5 32.7 167.2 -12.9 -7%
Customer Service 18.4 17.8 17.8 18.1 18.2 90.2 16.9 17.1 17.0 17.0 17.1 85.0 -5.2 -6%
Provision of Information 12.4 12.4 12.9 12.8 12.8 63.3 10.7 10.8 10.9 10.8 10.7 53.9 -9.4 -15%
Corporate Costs 10.3 10.3 10.3 10.3 10.3 51.4 9.7 9.7 9.7 9.7 9.7 48.4 -3.0 -6%
Telecoms 13.2 13.5 13.6 13.7 13.8 67.7 3.5 3.8 3.9 4.0 4.1 19.3 -48.4 -71%
Sustainability R & D 2.3 2.6 3.4 3.7 3.6 15.6 2.3 2.6 1.9 2.2 2.1 11.1 -4.5 -29%
Other 19.5 19.6 19.6 19.6 19.7 98.2 20.2 18.7 15.5 13.9 12.7 80.9 -17.3 -18%
Controllable Total 244.9 246.2 242.2 243.4 243.2 1219.8 217.8 221.0 213.0 212.6 211.6 1076.0 -143.9 -12%
Network Rates 46.9 51.0 55.0 59.1 63.1 275.1 46.9 51.0 55.0 59.1 63.1 275.1 0.0 0%
Car Levy 2.2 2.2 2.2 2.2 2.2 11.0 2.2 2.2 2.2 2.2 2.2 11.0 0.0 0%
Non Controllable 49.1 53.2 57.2 61.3 65.3 286.1 49.1 53.2 57.2 61.3 65.3 286.1 0.0 0%
TOTAL 294.1 299.4 299.4 304.6 308.5 1506 266.9 274.2 270.2 273.9 276.9 1362.0 -143.9 -10%
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Table 6.2 : DSO Allowed Capex Revenue for PR4
DSO Proposed PR4 Jacobs Proposed PR4
Variance % 2016 2017 2018 2019 2020 Total 2016 2017 2018 2019 2020 Total
CAPEX
New Business 48.9 52.1 59.1 67.2 74.0 301.2 290.8 -10.4 -3.5%
Reinforcements 48.5 53.9 63.3 73.0 79.2 317.8 312.8 -5.0 -1.6%
Generation Connections 49.4 32.9 8.8 8.8 9.6 109.5 109.5 0.0 0.0%
Dismantling 12.8 13.1 13.3 12.3 12.9 64.4 55.1 -9.3 -14.5%
Non-Repayable Line
Diversions 8.4 11.1 11.1 13.5 16.1 60.2 50.6 -9.6 -16.0%
Load Related Capex 168.0 163.1 155.6 174.7 191.8 853.1 818.7 -34.4 -4.0%
Non-Load Related
Capex 147.6 145.4 144.6 116.7 116.7 671.086 580.6 -90.6 -13.5%
Non-Network Capex 40.9 36.9 33.0 32.6 28.8 172.2 154.3 -18.0 -10.4%
Other (Smart Metering) 12.5 10.3 0.0 0.0 0.0 22.9 12.9 -10.0 -43.7%
Contributions -63.9 -52.4 -36.6 -40.6 -44.7 -238.2 -229.8 8.6 3.6%
Total Net Capex 305.1 303.3 296.6 283.4 292.6 1481.0 1336.9 -144.2 -9.7%
86 It should be noted that assessment of the DSO’s detailed non-load related capex suggests a total proposed capex of €669.1m, as shown in the summary tables of Section 5.
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Appendix A. Benchmarking
This appendix sets out the methodology and results of benchmarking ESBN’s distribution and 110kV
transmission costs in PR2, PR3 and PR4 by using Great Britain Distribution Network Operators (GB DNOs) as a
reference set.
Benchmarking exercises are often undertaken by businesses, regulators and academics in a variety of fields to
identify practices which lead to efficiency gains. Efficiency gains are most often analysed with respect to cost
reductions whilst maintaining the same level of output but can also include improvements in innovation, service
quality or other areas a business deems important to their goals.
This benchmarking study focusses on identifying relative changes within ESBN in their operating costs and non
network capital costs in delivering the same volume of services during the PR3 period and whether the
forecasts proposed in PR4 represent appropriate increases or decreases in expenditure. Within the context of
this study, volume of services and quality of services are two distinct concepts with different meaning and
interpretation. This study does not aim to analyse the efficiency of the quality of service delivered by ESBN; for
example we will use the volume and cost of faults in the study but we do not adjust for whether the faults are
being restored in a shorter or longer time.
A top down approach to opex and opex plus non-network capex (NN capex) has been undertaken to make the
comparison. The top down figures have been adjusted and normalised to generate data sets that are
comparable to published GB DNO data. More detailed assessment of unit costs has been undertaken in the
body of this report and is based on a bottom-up approach.
The data for the benchmarking assessment has been gathered from the TAO and DSO up to 24 November
2014. The review has been informed by the companies’ responses to the questionnaires on historic and
forecast costs, and associated information papers and network plans. Data provided by the companies at
meetings and supplementary questions raised by CER and their consultants has also been used to inform the
analysis. For this reason, the results presented for ESBN in 2007 may differ from those presented in the 2009
report as the 2009 study was completed using the data submitted at the time.
Jacobs has reduced the 2014 fault maintenance costs by €23.4m to account for the increased cost caused by
the Darwin storm. It is Jacobs’ opinion that this is reasonable due to the atypical nature of the event as stated in
our report87.
As advised by the companies, this study assumes that data presented in the PR4 Submission Questionnaires
uses the following price bases:
2007 to 2014: Nominal
2015: 2014 prices
2015 to 2020: 2014 prices
Based on this assumption, data has been adjusted to 2007 prices using the adjustment factors shown in Table
A.1 below. All cost data presented in this study is shown in 2007 prices to allow for a like-for-like comparison
between PR2, PR3 and PR4.
Table A.1 : Inflation Adjustment Factors
Inflation Adjustments 2007 2008 2009 2010 2011 2012 2013 2014
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Inflation Adjustments 2007 2008 2009 2010 2011 2012 2013 2014
HICP Average
Annual Inflation Rate 2.87% 3.11% -1.69% -1.57% 1.17% 1.93% 0.53% 0.40%
2007 Adjustment
Factor 1.000 0.972 0.943 0.959 0.974 0.963 0.945 0.940
No further information has been used in the production of this study.
Operating and non-network capital costs for GB DNOs are reported in financial years and in Great British Pound
(GBP). To compare these costs to ESBN’s, an exchange rate has been applied to the original data. The
exchange rate used is the average exchange rate between 1 April 2007 and 31 March 2008 (i.e. the rate
prevailing in the period from which the GB DNO data is taken) according to data collected from Oanda
(http://www.oanda.com/). Table A.2 outlines the exchange rate used in this study.
Table A.2 : Exchange Rates
Exchange Rate FY2007/08
EUR/GBP 1.42
Data for the GB DNOs is from Ofgem’s ‘Electricity Distribution Cost Review 2007-2008 – Activity Costs’88 report,
and is the same data used in SKM’s 2009 PR3 benchmarking review. The Scottish DNOs (Scottish Hydro
Electric Power and SP Distribution) have been excluded from the GB DNO group as they do not manage the
132kV network in the region, and as such, do not have an equivalent EHV network to ESBN’s 110kV network.
This group of GB DNOs is consistent with the group used in SKM’s 2009 PR3 benchmarking review.
A.1 Methodology
The Office of Gas and Electricity Markets (Ofgem) has developed a number of benchmarking techniques over
the last four price control reviews for GB. Ofgem’s methodology normalises operating expenditure by using a
Composite Scale Variable (CSV). Further details for each CSV calculation developed by Ofgem can be seen in
Section A.1.4 below. For the purposes of this study, benchmarking has been undertaken using linear
regression analysis adopted by Ofgem for the GB Distribution Price Control Review 4 (DPCR4) period 2005/06
– 2009/10. The benchmarking technique used in DPCR4 was chosen as the methodology used in this study
due to two factors:
1) Availability of high quality data; and,
2) Relative benefit of sophisticated econometric techniques.
In DPCR5 (2010/11 – 2014/15) Ofgem’s approach to benchmarking became increasingly complex, using
advanced econometric methods and onerous data requirements to complete the study. To overcome these
burdens, amongst other reasons, Ofgem has restructured its approach to benchmarking for the incoming RIIO-
ED1 price control review period 2015/16 – 2022/23. The focus in RIIO-ED1 has been on total expenditure
(“totex”) using modern equivalent asset value (MEAV) and customer numbers as the normalising factors (i.e.
cost drivers). Standardised and accurate MEAV information on GB DNOs is not readily available in the public
domain and therefore was excluded as an option in this study.
A.1.1 Totex or Opex
The choice between totex (opex plus capex) and opex as the level at which a benchmark is conducted is an
issue which requires consideration of the advantages and disadvantages of each option in the circumstances it
will be applied to. A discussion between Jacobs, CER and the companies at the beginning of this consultation
period covered this issue, which led to the use of opex and opex plus NN capex as the measure to be used for
88 https://www.ofgem.gov.uk/publications-and-updates/electricity-distribution-cost-review-2007-2008
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this benchmarking study rather than totex. However for clarity, the following section presents Jacobs’ views on
its use in this study.
Network investment (i.e. capex) is largely driven by the economic climate in which the network operator
operates in (i.e. load driven) and the investment cycle of the network (asset management). Therefore capex
delivery is more sensitive to peaks and troughs of an economy as the availability of credit changes and load-
growth on the network responds to reduced demand. As a result of the global financial crisis in 2007, Europe
experienced a significant economic recession and low availability of credit to fund investments. The impact on
Ireland due to this crisis was far more severe than that seen in the UK, as shown by Figure A.1 below, which led
to the downgrading of ESBN’s capex programme during PR3. The impact this issue had on ESBN’s capex
during PR3 is evidenced by ESBN’s revised 2012 capex plan and covered in more detail in section 4 of this
report. This has led to a disparity being created between GB DNOs and ESBN investment horizons as GB DNO
capex was less affected, and the path to network upgrade has largely continued as planned.
Figure A.1 : Annual GDP Growth for Ireland and United Kingdom (2005 – 2013)89
On the other hand, opex is less correlated with changes in macroeconomic influences. The key output of opex
is to maintain and operate a safe and reliable network, which needs a minimum level of expenditure to achieve
on an on-going basis, exclusive of any external factors such as economic growth. Figure A.2 below
demonstrates this relationship between opex and capex using the DSO’s reported90 figures. As expected, opex
is relatively stable over the nine year period however capex is much more volatile, due to the reasons
mentioned above. The standard deviation for opex in this sample was €67.4m whereas the standard deviation
for capex was €122.5m. The sample period is largest possible based on the historical data provided by ESBN.
Jacobs notes that ESBN’s consultants propose using average capex over a number of years to even out the
peaks and troughs. Jacobs agrees that this technique may lead to a more useful measure of capex over the
period, however due to the long-term impact of such a large economic and financial crisis, capex would need to
be examined across multiple review periods and therefore render the analysis inadequate for the purposes of
this study.
Therefore to mitigate the issue of macroeconomic impacts, including credit availability, Jacobs has continued
with the approach of benchmarking at an opex and non-network capex level.
89 Source: World Bank 90 PR4 Forecast Questionnaire Submission; Gross capex is line 74 of Table 6.3, Opex is line 72 of Table 5.1, NN capex is line 160 of Table 6.1
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Figure A.2 : DSO Capex, opex and NN Capex (2006 – 2015, nominal prices)
A.1.2 Data Choice
The data used to derive the relationship between network size and expenditure is based on GB DNO data from
2007/08. Although there are more recent examples of high-level opex data91 available in the public domain, this
is the most recent set of publicly available data with the level of granularity required for normalising to produce a
like for like comparison to ESBN expenditure.
Public data for RIIO-ED1 determinations in GB has only been provided as totex and therefore is not suitable for
comparison opex. ESBN’s consultants have suggested using RIIO-ED1 totex data and adjusting this data using
a straight line factor of 52% derived from historic actuals. As stated above, capex is much more volatile than
opex and therefore it is Jacobs’ opinion that applying a single adjustment factor across all years would be
negligent and unreasonable.
This point is emphasised by Figure A.3 below which shows DSO opex and capex as a percentage of totex
between 2006 and 2015, as reported in the forecast questionnaire submission. The yellow line represents totex
across the period. The figure demonstrates that opex has varied between 50.2% in 2006, to a peak of 74.6% in
2012 before dropping to 64.7% in the forecasted 2015 period. Observing the totex line shows how the
relationship between opex as a percentage of totex and totex is, as expected, inversely proportional. The
implications of this are that when a percentage factor is applied to a volatile totex figure, opex will be perceived
as relatively more volatile than it actually is.
91 Ofgem (2012), Electricity Distribution Annual Report for 2010-11, <https://www.ofgem.gov.uk/ofgem-
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Figure A.3 : Opex and Capex as a Percentage of Totex (excludes non-network capex)
A.1.3 Benchmarking Technique
The benchmarking technique used in this study is Corrected Ordinary Least Squares (COLS). COLS is an
extension of the regular ordinary least squares (OLS) technique. Regular OLS estimates the average
performance of the group of firms by fitting a line of minimum deviation from the average in graph of Opex
versus the CSV (as described in Section A.1.4), whereas COLS shifts the OLS benchmarking line from the
average towards the best performing, or more efficient, firms. The slope of the benchmarking line remains the
same, or in other words, the relationship between the scalar dependent variable, in this case costs, and the
explanatory variable, in this case the CSV, is held constant.
For the purpose of this study, two COLS benchmarks, in addition to the original OLS (i.e. GB Average), have
been developed based on the ‘upper quartile’ and ‘most efficient’ of the GB DNOs. As the benchmarks are only
to derive the relationship between expenditure and network size in this study, the relative position of ESBN to all
three lines in irrelevant. Only a single line has been used to measure the relative change of ESBN against itself.
In this case the line used is the upper quartile since this line demonstrates ESBN’s performance with the most
clarity. The other benchmarks have been kept in the graphs to aid the visual interpretation of the changes
between price review periods.
A.1.4 Cost Drivers Used by Ofgem in DPCR3, DPCR4, DPCR5 and RIIO-ED1
As discussed above Ofgem have used a number of different cost drivers to benchmark GB DNOs in the past 15
years. The calculation of each of these costs is presented below, including the CSV for DPCR 4 which was
used in this study.
Computation of the CSV for DPCR 3:
𝐶𝑆𝑉𝐷𝑃𝐶𝑅3 = (1 +𝑑𝑈
𝑈+
𝑑𝐿
𝐿) × 𝐶
Where;
dU
U = Proportional deviation in units distributed from the overall average
dL
L = Proportional deviation in network length from the overall average
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C = Customer Numbers (millions)
Computation of the CSV for DPCR 4:
𝐶𝑆𝑉𝐷𝑃𝐶𝑅4 = 𝐴0.5 × 𝐵0.25 × 𝐶0.25
Where;
A = Length of Network (‘000 km)
B = Units Distributed before losses (GWh)
C = Customer Numbers (millions)
Computation of the CSV for DPCR 5:
Ofgem adopted more direct modelling of individual direct and indirect costs against specific drivers such as
number of faults and network length. This is described in ‘Ofgem DPCR5 Initial Proposals 3 Allowed
Revenue and Cost Assessment’ and the associated appendix ‘Ofgem DPCR5 Initial Proposals 3 Allowed
Revenue and Cost Assessment Appendix’.
Computation of the CSV for RIIO-ED1:
𝐶𝑆𝑉𝑅𝐼𝐼𝑂−𝐸𝐷1 = 𝑀𝐸𝐴𝑉0.87 × 𝐶0.13
Where;
MEAV = Modern Equivalent Asset Value
C = Customer Numbers (millions)
A.1.5 Normalisation of ESBN and GB DNO Data
GB DNO and ESBN’s costs must be normalised to ensure that only comparable activities and costs are
benchmarked and to take account of differences in capitalisation policies. Table A.3 presents ESBN’s
Comparable Controllable Operating Expenditure and Non-Network Capital Expenditure for the PR4 period.
Table A.3 : ESBN Comparable Controllable Operating Expenditure and Non-Network Capital Expenditure (€m, 2014 prices)
Activity 2016 2017 2018 2019 2020
DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO
DSO:
System control 16.4 16.6 16.7 16.7 16.7
Planned maintenance 64.9 67.7 66 66.7 66
Fault maintenance 33.1 33.5 33.3 33.3 33.5
Other 0 0 0 0 0
Asset Management 14 14.2 14.4 14.7 15
Area Operations 8.8 8.9 8.9 8.9 8.9
Customer relations 3.2 2.4 2.5 2.8 2.8
DUoS Billing 1.4 1.4 1.4 1.4 1.5
MRSO 1.8 1.8 1.9 1.8 1.8
Market Opening 9.2 9.1 9.5 9.5 9.6
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Activity 2016 2017 2018 2019 2020
DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO
Insurance 3.8 3.8 3.7 3.7 3.7
Pension 1.3 1.4 1.4 1.5 1.5
Corporate Charges 8.4 8.4 8.4 8.4 8.4
Safety 7.7 7.7 7.8 7.8 7.8
Environmental 3.7 3.7 3.7 3.7 3.7
Telecoms 13.2 13.5 13.6 13.7 13.8
TAO/TSO:
Transmission
Operations 1.3 1.3 1.3 1.3 1.3
Transmission Repairs
And Maintenance 9.5 9.5 9.5 9.5 9.5
Transmission
Retirements 0 0 0 0 0
Asset Management 0.5 0.5 0.5 0.6 0.6
Corporate Charges 1.2 1.2 1.2 1.2 1.2
Insurance 0.3 0.3 0.3 0.3 0.3
Pension 0.2 0.2 0.2 0.2 0.2
Health & Safety 0 0 0 0 0
Telecom Fees 0.7 0.7 0.7 0.7 0.8
Total Controllable
Comparable Opex 191 13.8 194.3 13.9 193.3 13.9 194.6 13.9 194.6 14
DSO + 110 kV TAO
Controllable Opex 204.8 208.2 207.2 208.5 208.6
DSO:
Total Head Office 11.9 11.9 11.9 11.9 11.9
Total Distribution Asset
Management 3.9 4.1 4.7 4.1 3.9
Total Control/Operations
(EMS) 0 0 0 0.6 0
Total IT Infrastructure 0 0 0 0 0
Total Enterprise
Applications 13.8 8.3 4.8 6.7 3.8
Total Telecoms 11.3 12.6 11.6 9.3 9.1
Total Non-network Capex 40.9 36.9 33 32.6 28.8 -
Total Controllable Opex +
NN Capex 231.9 13.8 231.2 13.9 226.3 13.9 227.2 13.9 223.4 14
DSO + 110 kV TAO
Controllable Opex + NN
Capex
245.7 245.1 240.2 241.1 237.4
ESBN distribution and transmission costs for 2007 to 2014 are shown in Table A.4. These costs are shown in
outturn prices, except for 2015 which is reported in 2014 prices. Table A.5 presents the GB (excluding Scottish
DNOs) Distribution Company Activity Costs in 2007/08 nominal prices. DNOs report activity costs as direct
costs only and these costs have been adjusted to include appropriate indirect costs based on information from
Ofgem’s rules for cost reporting. GB DNOs capitalise more costs than ESBN, particularly fault costs and a
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proportion of support activities. ESBN has retained a more traditional capitalisation policy and we have
confirmed these practices through a questionnaire.
ESBN report operating costs on an activity basis, and these costs include indirect costs fully absorbed into the
main activity headings. GB DNO’s costs are normalised to the DSO’s costs taking account of the following.
DNO capitalise 23.5% of operating costs but these normally capitalised costs are retained in operating
costs in this analysis as these costs are not capitalised by ESBN.
DNOs would capitalise part of System Control costs and Health and safety costs and these are all included
in operating costs, since such costs do not appear to be capitalised by ESBN.
ESBN costs exclude line diversions as these are capitalised in GB.
All ESBN and DNO metering costs are excluded from the benchmarking. ESBN has full meter operator
obligations, whereas the DNO remaining meter operations are separately regulated.
DNO call centres take mainly no supply calls whereas ESBN call centres handle meter reading calls and
no supply calls. Customer Call Centre costs are therefore excluded from benchmarking. Other ESBN and
DNO customer service costs are included.
ESBN and DNOs both have responsibility for DUoS billing and meter point registration so DUoS and
MRSO costs are included.
ESBN market systems IT costs are included at 25% of total costs, which is an estimate of those IT costs
supporting the MRSO meter registration activity, which is the proportion adopted by DSO in its
benchmarking.
Corporate costs, Safety, Environment, Insurance costs and Pension administration costs are included.
ESI/licence fees, network rates and commercial excluded services costs are excluded from benchmarking.
ESBN 110 kV costs (transmission and distribution) are equivalent to DNO 132 kV costs. TAO 110 kV fault
and planned maintenance costs are included. Other transmission operating costs relate to 400 kV 220 kV
and 110 kV costs and are included in proportion to the 110 kV maintenance costs.
Table A.6 and Table A.7 present ESBNs historic and forecast network characteristics respectively. These
characteristics are required to calculate the DPCR4 CSV for each year.
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Table A.4 : ESBN Comparable Controllable Operating Expenditure and Non-network Capital Expenditure (€m outturn prices, except 2015 as 2014 prices)
Activity 2007 2008 2009 2010 2011 2012 2013 2014 2015
DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO DSO TAO
DSO:
System control 18.6 19.7 16.4 16.1 16.1 13.8 15.5 16.0 15.8
Planned maintenance 44.6 48.6 47.8 39.1 45.8 54.1 43.6 49.9 45.8
Fault maintenance 44.5 37.6 39.4 38.8 31.5 29.0 34.8 38.7* 29.7
Other 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Asset Management 12.5 10.8 12.6 11.2 11.3 12.8 13.9 14.1 14.0
Area Operations 10.4 11.1 8.7 9.8 9.6 8.1 8.5 8.3 8.0
Customer relations 2.4 2.1 1.5 0.6 0.3 0.4 0.6 0.4 0.5
DUoS Billing 1.3 1.7 1.3 1.2 1.3 1.3 1.1 1.3 1.3
MRSO 1.3 1.5 1.1 1.4 1.4 1.2 1.5 1.8 1.8
Market Opening 13.2 14.3 12.0 10.3 8.8 6.9 6.8 7.3 7.6
Insurance 4.2 3.6 1.9 3.2 1.8 5.1 3.5 3.5 3.5
Pension 1.1 2.5 2.5 3.2 2.7 1.7 2.0 1.8 1.4
Corporate Charges 12.0 13.1 11.9 10.9 9.2 8.8 8.2 8.7 9.2
Safety 3.8 3.3 3.0 2.0 1.7 1.8 2.5 4.0 3.9
Environmental 0.4 0.2 0.7 1.7 1.5 1.2 1.3 0.7 0.7
Telecoms 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
TAO/TSO:
Transmission Operations 0.5 0.9 1.4 0.7 1.5 1.6 1.5 1.3 1.3
Transmission Repairs And Maintenance 4.0 6.1 7.2 6.1 8.9 9.0 8.0 7.8 8.0
Transmission Retirements 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Asset Management 0.2 0.3 0.5 0.3 0.4 0.4 0.5 0.5 0.5
Corporate Charges 0.8 1.4 1.6 1.6 1.1 1.0 0.9 0.9 0.9
Insurance 0.1 0.1 0.4 0.3 0.1 0.2 0.1 0.2 0.2
Pension 0.1 0.0 0.0 0.0 0.3 0.2 0.2 0.2 0.1
Health & Safety 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Telecom Fees 0.3 0.6 1.0 2.9 0.7 0.7 0.8 0.8 0.8
Total Controllable Comparable Opex 170.3 6.0 170.1 9.4 160.7 12.1 149.5 12.0 142.8 13.0 146.3 13.1 143.7 12.1 156.8 11.8 143.3 11.9
DSO + 110 kV TAO Controllable Opex 176.2 179.6 172.9 161.4 155.8 159.4 155.8 168.6 155.2
DSO:
Total Head Office 15.2 19.2 17.6 15.4 7.8 4.3 9.1 11.5 12.4
Total Distribution Asset Management 9.4 14.4 6.7 0.8 - 0.7 0.6 1.9 3.3
Total Control/Operations (EMS) 2.4 4.2 9.0 3.7 0.2 3.0 4.6 3.1 1.2
Total IT Infrastructure - - - - 0.2 0.2 0.3 0.5 0.2
Total Enterprise Applications 6.0 2.2 1.1 4.7 7.1 5.1 3.1 2.3 3.6
Total Telecoms 1.9 0.9 1.0 0.2 7.0 6.1 4.4 5.3 8.5
Total Non-network Capex 34.9 - 40.9 - 35.3 - 24.9 - 22.3 - 19.4 - 22.1 - 24.6 - 29.2 -
Total Controllable Opex + NN Capex 205.2 6.0 211.0 9.4 196.0 12.1 174.3 12.0 165.1 13.0 165.7 13.1 165.8 12.1 181.4 11.8 172.4 11.9
DSO + 110 kV TAO Controllable Opex + NN Capex
211.1 220.5 208.2 186.3 178.1 178.8 177.9 193.2 184.3
*€23.4m removed for Darwin Storm repairs
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Table A.5 : GB (excluding Scottish DNOs) Distribution Company Activity Costs (£m 2007/08 nominal prices)
DNO A DNO B DNO C DNO D DNO E DNO F DNO G DNO H DNO I DNO J DNO K DNO L
Direct Activities 142 154 102 88 105 53 88 110 113 194 140 104
Load Related New Connections Net 11 46 10 12 2 -1 1 18 8 35 36 5
Non load related non fault and replacement 87 63 64 43 55 32 45 51 63 80 52 68
Non operational capex 2 2 4 4 4 3 15 8 7 19 8 3
Faults 24 27 16 17 29 8 14 23 22 40 23 13
Inspection and Maintenance 12 12 5 5 7 6 7 10 8 12 14 6
Tree Cutting 5 3 2 6 7 4 5 0 5 8 7 8
Network Policy and R & D 1 1 1 1 1 1 1 0 0 0 0 1
Indirect Activities 76 67 71 43 50 41 49 67 60 101 79 56
Network Design and Engineering 6 5 9 4 4 4 5 7 4 7 3 6
Project Management 4 2 4 2 4 3 5 6 4 8 7 5
Engineering Management and Clerical Support 23 17 15 9 11 7 10 15 14 27 20 11
Control Centre 4 4 3 2 3 2 2 3 3 5 3 2
System mapping and cartography 2 2 1 1 2 1 1 2 1 2 1 1
Customer Call Centre inc compensation claims 1 1 1 1 2 1 1 1 2 3 3 1
Stores and procurement 1 2 1 1 1 1 1 2 2 3 2 1
Vehicles and transport 5 6 2 3 3 3 4 3 4 7 12 5
IT and telecoms 11 10 13 7 7 7 7 9 8 12 8 8
Property management 6 5 7 2 3 2 3 6 6 8 4 4
HR and non op training 1 1 3 2 2 1 1 3 3 4 3 2
Health and Safety and Op training 2 2 1 1 1 1 1 1 1 2 2 2
Finance and Regulation 8 8 9 6 6 6 6 8 7 11 9 6
CEO Group Legal secretary and community 2 2 2 2 1 2 2 1 1 2 2 2
Total Activity Costs 80 92 103 88 102 69 106 84 72 118 207 103
Atypical cash costs 2 1 15 0 5 4 7 2 3 3 3 1
Pension deficit payments 8 10 0 22 6 13 21 15 16 4 27 0
Metering (separate price control) 1 1 1 3 5 2 6 2 3 6 13 12
Excluded services and de minimus activities 12 10 15 13 11 9 25 45 10 31 27 9
Distributed Generation less contributions 0 0 0 0 0 0 0 0 0 0 0 1
IFIs (Innovation Incentives) 1 1 1 0 1 0 0 2 1 2 1 0
Disallowed related party margins -5 4 12 3 2 0 1 0 0 1 4 10
Statutory depreciation 39 42 59 32 47 25 34 42 40 56 68 36
Network Rates 20 27 17 14 18 15 18 23 10 26 38 16
Transmission Exit Charges 8 4 9 5 10 4 5 12 8 9 10 12
Pension deficit payments - related parties -8 -10 0 0 0 0 0 0 0 0 -27 0
Non activity costs and reconciliation 2 2 -26 -4 -3 -3 -11 -59 -19 -20 43 6
Total annual opex and capex per Reg Accounts 298 313 276 219 257 163 243 261 245 413 426 263
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Table A.6 : Historic Network Characteristics for ESBN
Characteristic ESBN 2007 ESBN 2009 ESBN 2010 ESBN 2011 ESBN 2012 ESBN 2013 ESBN 2014 ESBN 2015
Number of Customers 2,151,285 2,227,521 2,237,232 2,239,507 2,237,138 2,233,276 2,237,097 2,245,755
Length of Circuit (km) 162,203 167,498 168,970 170,063 171,128 171,858 171,997 172,376
Length of Circuit (m/customer) 75.4 75.2 75.5 75.9 76.5 77.0 76.9 76.8
Units Distributed (GWh) 23,456.6 22,953.4 22,927.7 22,578.4 22,323.6 22,113.4 22,503.5 22,746.3
Units/Customer 10.9 10.3 10.2 10.1 10.0 9.9 10.1 10.1
CSV Ofgem DPCR4 33.9 34.6 34.8 34.8 34.8 34.8 34.9 35.1
Table A.7 : Future Network Characteristics for ESBN
Characteristic ESBN 2016 ESBN 2017 ESBN 2018 ESBN 2019 ESBN 2020
Number of Customers 2,258,679 2,275,282 2,296,538 2,322,684 2,354,321
Length of Circuit (km) 179,250.7 180,484.2 181,810.6 183,268.8 184,861.2
Length of Circuit (km/customer) 0.0794 0.0793 0.0792 0.0789 0.0785
Units Distributed (GWh) 22,669.2 23,051.6 23,523.1 23,826.3 24,241.0
Units/Customer 10.037 10.131 10.243 10.258 10.296
CSV Ofgem DPCR4 35.81 36.15 36.56 36.92 37.37
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A.1.6 Treatment of TAO and TSO Costs
The TAO has provided standalone planned and fault maintenance costs for the 110 kV network which (as
described above) is considered equivalent to the GB DNO’s 132 kV network. These costs have been included in
the operating costs benchmarking study and then used to proportion other TAO and TSO costs. Other
transmission operating costs are proportioned based on the ratio between the 110 kV maintenance costs and
the total maintenance costs for the 110 kV, 220 kV and 400 kV networks collectively. The Opex Ratio of costs
attributable to the 110 kV portion of the network is calculated as:
𝑂𝑟𝑎𝑡𝑖𝑜 = 𝑀110𝑘𝑉
𝑀𝑇𝐴𝑂
Where;
Oratio = Ratio of 110 kV operating costs to entire transmission network operating costs
M110kV = Sum of Planned Maintenance and Fault Maintenance on the 110kV Network
MTAO = Sum of Planned Maintenance and Fault Maintenance for the whole transmission
network (i.e. 110 kV, 220 kV and 400 kV)
To proportion a TAO operating cost, the Opex Ratio is then applied as follows;
𝑂𝑝𝑒𝑥 𝐶𝑜𝑠𝑡 𝐶𝑎𝑡 ′𝑋′110𝑘𝑉 = 𝑂𝑝𝑒𝑥 𝐶𝑜𝑠𝑡 𝐶𝑎𝑡 ′𝑋′𝑇𝐴𝑂 × 𝑂𝑟𝑎𝑡𝑖𝑜
Where;
Opex Cost Cat ‘ X’110kV = The portion of the TAO/TSO cost category ‘X’ attributed to the
110kV network
Opex Cost Cat ‘X’TAO = The total cost for transmission network operating cost category ‘X’
A detailed summary of how each cost category presented in the distribution and transmission questionnaires
has been treated is provide below in Table A.8.
Table A.8 : Treatment of ESBN Distribution and Transmission Cost Categories
Company Cost Category Cost Treatment
DSO Capital Driven Opex Non Repayable Line Diversions Omitted
Dismantling Omitted
Network Operations &
Maintenance
System control Controllable and included
Planned maintenance Controllable and included
Fault maintenance Controllable and included
Asset Management Asset Management Controllable and included
Forestry & Wayleaves Controllable and included
Metering Meter Reading Omitted
QH Data Omitted
Data Aggregation Omitted
Customer Meter Operation Omitted
Keypad / Token Meter Omitted
Smart Metering Opex Smart Metering Opex No costs provided
Customer Service Call Centre Controllable and included
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Area Operations Controllable and included
Customer Relations Controllable and included
Provision Of Information Duos Billing & Accounts
Receivable
Controllable and included
MRSO Controllable and included
Market Opening Omitted
Commercial External repayable: Omitted
Transaction charges Omitted
3rd party damages Omitted
Supply repayable Omitted
Other inter ESB Omitted
Other external repayable Omitted
Other commercial Omitted
Sustainability & R & D Sustainability Controllable and included
R & D Controllable and included
Other Network Rates Non-controllable
Cer Levy Non-controllable
Company Wide Costs Omitted
Corporate Charges & Corporate
Affairs
Controllable and included
Insurance Controllable and included
Legal Omitted
Pension Controllable and included
Environmental Controllable and included
Misc Omitted
Health & Safety Controllable and included
Telecoms Controllable and proportioned at 25%
Depreciation Omitted
PSO Omitted
Restructuring costs Omitted
Market Support Costs Omitted
Manufacturing Omitted
Settlement Difference Omitted
Prior Year Adj Omitted
Pension Deficit Charge Omitted
Unabsorbed Overhead Omitted
Capitalise Pension Adjustment Omitted
Misc Omitted
TAO Transmission Operations Transmission Operations Proportioned with respect to 110kV
PM and FM
Transmission Repairs And
Maintenance
Planned Maintenance (PM) 110kV proportion included
Fault Maintenance (FM) 110kV proportion included
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Transmission Retirements Transmission Retirements Omitted
Asset Management Asset Management Proportioned with respect to 110kV
PM and FM
Other Rates Omitted
Cer Levy Omitted
Company Wide Costs Omitted
Corporate Charges Proportioned with respect to 110kV
PM and FM
Insurance Proportioned with respect to 110kV
PM and FM
Legal Omitted
Pension Proportioned with respect to 110kV
PM and FM
Health & Safety Proportioned with respect to 110kV
PM and FM
Misc Omitted
Depreciation Omitted
Professional Fees Omitted
Telecom Fees Proportioned with respect to 110kV
PM and FM
A.2 Interim Results
A top-down benchmarking study has been undertaken to examine ESBN’s performance against GB DNOs in
2007/08 with respect to operating expenditure and non-network capital expenditure. By using the same data
from SKM’s 2009 benchmarking exercise, ESBN’s improvement since the previous review can be examined
and measured. The purpose was to validate the benchmarking at a known point and effectively examine the
movement of opex costs by ESBN against that benchmarked position.
Results of the interim benchmarking study can be seen in Section A.2.1 of this report. An initial evaluation of
these results is presented in Section A.2.2.
A.2.1 Results
Two COLS models have been run to examine ESBN’s performance during PR3 and analyse their forecast
spend in PR4 relative to their position at the last price review period. To do this a benchmark has been derived
in each model from GB DNO data which explains the relationship between network size and expenditure. The
first model uses ESBN’s controllable and comparable opex, as described above, whereas the second model
also includes non-network capex. Table A.9 shows the correlation coefficient, or R2, for each of the linear
regression models. As can be seen, both models display a high correlation coefficient, indicating that the
DPCR4 CSV is a good descriptor of each of the cost sets.
It is reasonable to include non-network capex because these costs cover business support costs and are often
depreciated over short timeframes. Different companies have different approaches to managing these types of
costs, for example one company may purchase a fleet of vehicles, whereas another might lease the vehicles.
Therefore excluding these costs from the analysis entirely would mean incorrectly evaluating the total operating
costs required to deliver ESBN’s services to its customers.
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Table A.9 : Linear Regression Specification
Dependent Variable Independent Variable Correlation (R2)
Comparable & Controllable Opex DPCR 4 CSV 0.92
Comparable & Controllable Opex + NN
Capex DPCR 4 CSV 0.88
Figure A.4 and Figure A.5 demonstrate the results of the controllable opex benchmarking study. In each figure
the GB Average, GB Upper Quartile and GB Most Efficient benchmarks can be seen, along with where ESBN is
placed compared to these lines. Figure A.4 shows the overall placement of ESBN with respect to the GB DNOs
whereas Figure A.5 is a close up of the ESBN data points.
As can be seen from the overall chart, ESBN’s data points are located to the far right and clustered close
together. This is to be expected due to ESBN’s large network compared to GB DNOs, and relatively small
changes in opex compared to the range of the sample.
Figure A.6 and Figure A.7 demonstrate the results of the controllable opex and non-network capex
benchmarking study. Again, the GB Average, GB Upper Quartile and GB Most Efficient benchmarks can be
seen in each figure, with Figure A.7 providing a close up view of EBSN’s movements during PR3. Non-network
capex is often less consistent than opex and hence ESBN’s results vary more in this study.
Figure A.4 : Regression of DSO & 110kV TAO Controllable Opex versus GB DNOs – Overview (€m, 2007 prices)
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Figure A.5 : Regression of DSO & 110kV TAO Controllable Opex versus GB DNOs – ESBN Detail (€m, 2007 prices)
Figure A.6 : regression of DSO & 110kV TAO Controllable opex + Non-Network Capex versus GB DNOs – Overview (€m, 2007
prices)
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Figure A.7 : Regression of DSO & 110kV TAO Controllable Opex + Non-Network Capex versus GB DNOs – ESBN Details (€m,
2007 prices)
A.2.2 Consideration of the results
Benchmarking studies are dependent on the assumptions and data sources used and therefore should be
considered in association with other detailed qualitative analysis. This study was intended to inform and support
the analysis performed in other aspects of the price control review being undertaken. As previously stated, this
exercise aimed to examine the relative efficiency of ESBN against itself, using GB DNO 2007/08 data as a
reference point.
The reference data used in this study is from 2007/08 and as such is seven years old. Any conclusions drawn
from this study should note that the reference set has been used to derive an expenditure versus cost-drivers
relationship to account for the organic increases in costs due to a network expanding. The reference set should
not be used as a direct comparison between ESBN and GB DNOs of today.
Results from this study only examine the reported costs of the companies and do not take into account how well
ESBN delivered their services. Consideration of how efficiently ESBN provided the services required, such as
customer care, reliability and safety, is outside the scope of this benchmarking analysis. Hence a reduction in
expenditure should be examined in conjunction with broader outputs to determine a final position on the overall
efficiency of the companies during PR3.
A detailed assessment of ESBN’s performance in each of the models is discussed below. The GB upper
quartile benchmark has been used to represent ESBN’s change throughout the examined period.
A.2.2.1 Controllable Operating Expenditure
In 2007 ESBN’s annual opex was €1.2 million above the GB DNO average and €9.3 million from the upper
quartile frontier. This suggests that ESBN was performing just below average of the GB DNOs at this time.
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During PR2, ESBN has shown significant efficiency improvements in relation to operating expenditure
compared to its 2007 position. By 2010 ESBN’s annual opex was €16.1 million below upper quartile frontier. By
this time ESBN had also surpassed the most efficient GB DNO in 2007/08.
In 2014 ESBN moderately regressed, positioning itself only €8.8 million below the upper quartile frontier. This is
despite the Darwin storm costs being excluded from the analysis.
Between 2007 and 2015, ESBN has shown an overall efficiency gain, with respect to its own opex costs of,
16.5%. However under the proposed opex costs for PR4, this efficiency gain would be completely offset and by
2020 and a 1.1% efficiency loss will be observed.
A summary of the ESBNs historic controllable opex performance with respect to the GB DNO’s is summarised
in Table A.10 below.
Table A.10 : Historical ESBN Controllable Opex Summary
Opex Performance 2007 2010 2011 2012 2013 2014 2015
Distance from GB Upper Quartile (€m
2007) 9.3 -16.1 -19.1 -17.3 -24.0 -14.9 -20.6
Table A.11 presents ESBN’s proposed opex for PR4 compared to each benchmark. It is evident from these
results that the proposed PR4 opex is much greater than allowances in previous years or periods.
Table A.11 : ESBN PR4 Proposal Summary
Opex Performance 2016 2017 2018 2019 2020
Distance from GB Upper Quartile (€m
2007) 16.7 18.2 15.4 14.9 12.8
Figure A.8 : Controllable Opex Summary
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Table A.12 shows the relative performance of ESBN during each review period. Each period is calculated as the arithmetic
average of the years in that period. PR3/4 is the average of 2011 – 2020 period. As shown, the average normalised spend was
significantly lower in PR3 compared to other periods. However the average outlay across the combined PR3 and proposed
PR4 period is only €1.79m below upper quartile frontier. Table A.12 : ESBN Opex Performance Summary by Period
Opex Performance PR2 PR3 PR4 PR3/4
Distance from GB Upper Quartile
(€m 2007) -3.23 -19.18 15.59 -1.79
A.2.2.2 Controllable Operating Expenditure and Non-network Capital Expenditure
In 2007 ESBN’s annual opex and non network capex was €19.3 million above the GB DNO average and €22.9
million from the upper quartile frontier. This suggests that in efficiency terms ESBN was performing well below
average against GB DNOs at that time.
Similarly to the controllable opex study, ESBN has shown significant improvement during PR2, such that by
2010 ESBN’s annual opex was €14.1 million below the upper quartile frontier. In 2011 ESBN had reached the
same level of efficiency as the most efficient GB DNO in 2007/08.
ESBN continued to improve efficiency during the first three years of PR3, however has regressed from this
position in the last two years of the period.
Between 2007 and 2015, ESBN has shown an overall efficiency gain, with respect to its own opex and non-
network capex costs, of 18.0%. However under the proposed opex and non-network capex costs, this efficiency
gain would be reduced to 4.0% by 2020.
A summary of the ESBNs historic controllable opex performance with respect to the GB DNO’s is summarised
in Table A.13 below.
Table A.13 : Historical ESBN Controllable Opex and Non-Network Capex Summary
Opex + NN Capex Performance 2007 2010 2011 2012 2013 2014 2015
Distance from GB Upper Quartile
(€m 2007) 22.9 -14.1 -19.2 -20.5 -25.0 -13.9 -15.5
Table A.14 presents ESBN’s proposed opex and non-network capex for PR4 compared to each benchmark. It is
evident from these results that the proposed PR4 opex and non-network capex is far greater than allowances in
previous years.
Table A.14 : ESBN PR4 Proposal Summary
Opex + NN Capex Performance 2016 2017 2018 2019 2020
Distance from GB Upper Quartile
(€m 2007) 32.7 30.4 23.6 22.5 16.7
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Figure A.9 : Controllable Opex plus Non-Network Capex Summary
Table A.15 shows the relative performance of ESBN during each review period. Each period is calculated as the
arithmetic average of the years in that period. PR3/4 is the average of 2011 – 2020 period. Similarly to opex,
the average normalised spend was significantly lower in PR3 compared to other periods.
Table A.15 : ESBN Opex and Non-Network Capex Performance Summary by Period
Opex + NN Capex Performance PR2 PR3 PR4 PR3/4
Distance from GB Upper Quartile
(€m 2007) 8.06 -18.81 25.19 3.19
A.2.3 Conclusions
It should be noted that at the initial kick off meetings between ESBN, CER and the consultants in discussions on
the approach to benchmarking it was agreed that the approach would be the one taken within this report using
opex and non network capex and that the Totex approach used by Ofgem in RIIO would be inappropriate. In
response to this report ESBN has submitted reports proposing the Totex approach would demonstrate a more
positive view of efficiency for ESBN. We would accept that there are flaws to both the approach taken and the
use of Totex in this instance. The economic climate throughout PR3 impacted on the availability of investment
funds, and in both capex and opex there were severe restrictions resulting in expenditure being significantly
reduced. There has then been a change during the end of 2014 through 2015, flowing through into PR4 where
expenditure has increased significantly.
This study aimed to investigate the relative efficiency change of ESBN during PR3 with respect to operational
and non-network capital expenditure against their position in PR2. Following this analysis, the study has used
these results to examine ESBN’s proposed PR4 costs at a high-level, which can be used to supplement more
detailed findings in other Jacobs reports.
It should be kept in mind that this report only examines the cost effectiveness of ESBN and does not attempt to
determine the overall efficiency of ESBN with respect to other factors such as network reliability, customer
service quality, safety and sustainability. In other reports prepared for the CER, Jacobs demonstrates how a
number of these factors have been affected by a lack of expenditure.
Due to the difficulties in obtaining up to date data of GB expenditure with the appropriate level of detail, the
implications of choosing between opex and totex as the level of benchmark and the unprecedented economic
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climate observed in PR3 leading to disparity between GB and Ireland, Jacobs is unable to convincingly
conclude that ESBN’s performance during PR3 was either efficient or inefficient. The results of the study show
that ESBN was able to reduce their opex and non-network capex during PR3 relative to their network size;
however Jacobs is unable to distinguish between improvements in efficiency, lack of expenditure due to
external factors such as credit availability or deferred spending due to downward pressure on profits margins as
a result of poor economic factors in Ireland.
The proposed PR4 forecast opex is, on average, €34.77m p.a. higher than PR3 for a network of equivalent size.
Similarly, opex plus NN capex is, on average, €44.0m p.a. higher than PR3 for a network of equivalent size.
Jacobs acknowledges that distribution networks are currently undergoing rapid changes due to advances in
smart technology, uptake of electric cars, the wide spread deployment of intermittent renewable generation and
the increase in distributed generation however we believe that the magnitude of these increases are unjustified.
As noted earlier, opex generally remains more consistent than capex and therefore these large changes are out
of the ordinary.
Further to this the proposed PR4 levels would return ESBN to expenditure levels well above those of pre-global
financial crisis levels. While this is understandable for capex related spend, due to improving the network and
ensuring it is ready for the changes that are expected over the coming decade, the change in opex should be
significantly less impacted by these changes.
It is Jacobs’ opinion that, based on the results of this benchmarking study, non-network capex has suffered
large deferred spending cuts rather than efficiency gains. For example, ESBN was able to cut costs to €19.4m
by 2012 however now propose a 2016 non-network capex of €40.9m. In addition, the average non-network
capex during PR3 was €23.5m whereas the proposed PR4 non-network capex is €34.4m, further demonstrating
that spending has been postponed from PR3 to PR4. This conclusion is supported by the analysis described in
sections 3 and 5 of this report.
ESBN have presented a different approach to benchmarking in consultationwith Frontier Economics using a
Totex approach in which they derive the opex value from a fixed percentage of the Totex(52%) and apply this to
conclude that GB DNO’s opex costs have increased by 30% between 2007/8 and 2013/14, and using this
increase to reflect on the ESBN opex over the same period. The driver for Opex is the scale of the network and
costs are predominantly dictated by O&M, Asset Management, Metering, Customer Service and Provision of
Information, at over 85 % of controllable opex in PR3, In evaluating this within ESBN, we have determined that
opex has varied between 50.2% in 2006, to a peak of 74.6% in 2012 before dropping to 64.7% in the forecasted
2015 period. Observing the totex line shows how the relationship between opex as a percentage of totex and
totex is, as expected, inversely proportional. The implications of this are that when a percentage factor is
applied to a volatile totex figure, opex will be perceived as relatively more volatile than it actually is.
Jacobs recommends that further consultation between stakeholders is undertaken with respect to benchmarking
prior to the next price review period. Given the current state of European economies, totex benchmarking could
constitute a more appropriate measure in the future. This would also enable a wider range of data to be
collected and therefore more direct comparisons to be completed, providing more conclusive and useful
analysis. We would however comment that the detailed bottom up approach undertaken in section 2 and 3 of
this report is the basis of the proposed allowances due to the uncertainties and assumptions used throughout
the benchmarking process.
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Appendix B. Incentives
B.1 Introduction
As part of PR4, CER required Jacobs to:
“…comment on the incentives that were placed on the TAO, TSO & DSO businesses over the period 2010-
2015 and comment on their suitability for implementation over the period 2016-2020. Recommendations
should also be made on the removal or introduction of any incentive mechanism. This point relates to
incentives regarding quality of supply, Customer Minutes Lost, Customer Interruptions, Loss Adjustment
Factors, et cetera, rather than the broader incentives placed on the utilities by the form of the revenue
control. In addition, provide advice on potential new incentives for infrastructure delivery.”
This appendix sets out our comments in relation to the DSO, with respect to the above requirement.
B.2 Objectives
As part of the PR4 support, CER requires Jacobs to:
Comment on the incentives that were placed on the TSO, TAO & DSO businesses during PR3,
Advise on the extent to which the businesses have delivered against these incentives and are due any
associated payments,
Comment on the continuing suitability of these incentives for implementation over the period 2016-2020
(PR4),
Provide advice on potential new incentives for infrastructure delivery which is seen as a continuing
problematic area, and
Provide recommendations on the removal or introduction of any incentive mechanism for PR492.
In recognition of the differing functions of the three businesses, individual business specific reports have been
prepared. This report focusses on the DSO businesses.
B.3 Data Sources & Assumptions
Data and information used within this report has been provided to Jacobs by ESBN and is assumed to be
correct and accurate. Specifically, information relevant to this report has been sourced from the following
documents:
DSO Historic Questionnaire
DSO Forecast Questionnaire
DH08 Incentives Proposal (FINAL)
DF08 Incentives Proposal (FINAL)
DH30 Continuity Performance
DF30 Continuity Plan (Final)
140730 Final DUoS Revenue and Tariff.xlsx
CER Decision Paper CER/10/198
Only information provided to Jacobs prior to 1 March 2015 has been used in the analysis of DSO Incentives.
92 This point relates to incentives regarding quality of supply, Loss Adjustment Factors and Network Development, et cetera, rather than the broader
incentives placed on the utilities by the form of the revenue control.
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B.4 Incentives Applied in PR3
B.4.1 Losses
Table B.1 below shows the target losses that were set out in the PR3 determination.
Table B.1 : PR3 Losses Target
2009 2010 2011 2012 2013 2014 2015
GWh distributed 22,955 22,902 23,269 24,014 24,758 25,526 26,317
Distribution Losses 1,738 1,709 1,715 1,752 1,787 1,824 1,860
Losses as % of total GWh 7.6 7.5 7.4 7.3 7.2 7.1 7.1
CER proposed that the value of these incentives would be €65,000 per GWh, consistent with the previous PR2
determination. The maximum impact of the losses incentive was set at penalty or reward equal to ±1.5% of
annual allowed revenue per annum (€10.5m in 2009 money).
CER indicated that there was uncertainty in relation to the measurement of these losses and therefore no
incentive payment would be made until the methodology used by the DSO for the measurement of losses had
been demonstrated to be accurate. The CER also directed that it would need to be demonstrated that any
reductions in losses beyond that built into the capital programme were a direct result of actions by the DSO and
not related to underlying system conditions.
B.4.2 Continuity
ESBN is incentivised against two measures of continuity:
Customer Minutes Lost (SAIDI - System Average Interruption Duration Index) - the average duration
of interruptions for all customers during the year determined by dividing the sum of all durations of service
interruptions to customers by the total number of customers
Customer Interruptions (SAIFI - System Average Interruption Frequency Index) – the average
number of interruptions per 100 customers during the year determined by dividing the total annual number
of customer interruptions by the total number of customers served during the year and multiplying by 100.
The measures include only outages of duration greater than three minutes and are subject to adjustment on
days for which customer lost minutes (CML) is greater than 61,570. This is known as the “storm threshold”.
CER set incentivised targets for system performance for the period 2010 to 2015 and the DSO received
incentive payments for exceeding targets and was penalised where targets were not met.
The target values set for PR3 in the decision paper CER/10/198 and corresponding work volume adjusted
targets are set out in Table B.2 below.
Table B.2 : PR3 Continuity Targets
2011 2012 2013 2014 2015
Customer Interruptions per 100 Customers (CI)
Unplanned 120.5 116.9 113.3 109.6 106.0
Planned 22.6 22.6 22.6 22.6 22.7
Total 143.1 139.5 135.9 132.2 128.7
Total (adjusted) 138.5 130.9 127.1
Customer Lost Minutes (CML)
Unplanned 85.3 80.6 76.4 72.2 68.0
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2011 2012 2013 2014 2015
Planned 55.8 55.8 55.7 55.8 55.8
Total 141.1 136.4 132.1 128.0 123.8
Total (adjusted) 128.8 113.0 108.1
Penalty / incentive rates of €0.26166m/CML and €0.20646m/CI (2009 prices) apply to differences between
actual outturn and targets. Reward and penalty payments are made based on total CI and CML in any given
year.
An overall cap / floor of ±1.5% of allowed revenue applies to the CI incentive. An overall cap / floor of ±1.5% of
allowed revenue also applies to the CML incentive.
The annual continuity target for planned outages is set based on forecast levels of planned work on the
network, and is subject to adjustment each year based on the amount of planned work actually carried out
according to the factors set out in Table B.3 below. Hence if more work than planned is completed, the allowed
continuity target would increase according to these factors to reflect the increased investment in the network
and vice versa. The work programmes in this context have been subject to the capex prioritisation and deferral
processes that are set out in other areas of ESBN’s PR3 historic submission.
Table B.3 : CI and CML per Work Unit
Activity Work unit CI x 100 per work unit CML per work unit
20kV conversion km 0.000442 0.00126
MV overhead line cyclic conversion km 0.000431 0.00116
Cut-out replacement Cut-out 0.000044 0.00003
Minipillar replacement Minipillar 0.000265 0.00095
LV urban overhead line refurbishment Span 0.000177 0.00064
LV rural refurbishment Group 0.000534 0.001514
Non-scheme new connections Connections 0.000508 0.0013
Correction of voltage complaints Jobs 0.00095 0.00242
Jacobs notes that work delivered volumes for 2013 have not been provided however ESBN has made
adjustments to the 2013 planned outage targets. 2014 data has also not been made available.
B.4.3 RedC
This incentive is based on an Annual Survey/Interview with 2,500 independently sampled customers who dealt
with the DSO in the previous six months.
It measures the customers’ perception of the service provided by ESBN in six areas:
Investigation of Voltage Complaints
Unplanned Outages
Planned Outage
New Connections – Domestic Schemes
New Connections – Domestic Non-Scheme
New Connections – Business
The targets, rates of financial payments and cap / floor for this incentive are set out in Table B.4 below.
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Table B.4 : RedC Incentive Targets 2011 to 2015
Red C Poll
2011 2012 2013 2014 2015
Target 74.0% 74.0% 74.0% 74.0% 74.0%
Value applied to deviation from target,
(€m per % deviation, 2009 money) 0.7215 0.7215 0.7215 0.7215 0.7215
Cap on this incentive,
+/- €m, 2009 money +1.6 / -6.5 +1.6 / -6.6 +1.6 / -6.7 +1.6 / -6.8 +1.6 / -6.9
B.4.4 Customer Satisfaction
This incentive tracks ESBN’s performance across a number of areas relating to the overall performance of the
ESBN Contact Centre in Wilton Cork. The metrics below apply at all times including during storm events:
B.4.4.1 Speed of Telephone Response
TSF 20 (including Interactive Voice Recognition, IVR) is the percentage of calls to the call centre answered
(by an agent or IVR) within 20 seconds.
TSF 30 (excluding IVR) is the percentage of calls that are in a queue waiting to speak to an agent (after
being placed in the queue either via the IVR or by an agent) that are answered by an agent within 30
seconds
The speed of telephone response measure applies under all conditions, including storms to ensure ESBN
is continually focussed on customer interaction during outage events.
B.4.4.2 Call Abandonment Rate
This measure will record the number of calls that are abandoned while a caller is waiting in a queue to speak to
an agent.
The call abandonment rate measure applies under all conditions, including storms, to ensure ESBN is
continually focussed on customer interaction during outage events.
B.4.4.3 Customer Call-Back survey results
ESBN’s customers will be contacted within two days of calling the ESBN Contact Centre. The call-backs will be
carried out by an independent research company engaged by ESBN and reporting to both the Commission and
ESBN. The calls will be selected randomly, subject to the (reasonable) inclusion of calls by:
Time of day when call was made (morning, afternoon, evening, night).
Purpose of call (for example, supply problem, meter reading).
Handling of call (on-call resolution, requiring call-back or referral).
Customers will be asked to score their call centre experience on a scale of 1 (very dissatisfied) to 5 (very
satisfied) based on:
The politeness of the member of staff.
Their willingness to help.
The accuracy of the information given (if information was given).
The usefulness of the information given (if information was given).
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B.4.4.4 Mystery Caller survey results
This measure involves a third party, in the guise of a genuine caller, making calls to gain an assessment of
various aspects of customer service provided. Aspects of the call centre agent’s approach and disposition will
be evaluated, including helpfulness, responsiveness, tone and style of the agent.
The areas of activity that will be tested are:
New connections for a single site.
New connections for a multi-site development.
Service alterations.
Planned outages.
Moving a meter.
No supply.
Meter reading policy.
Tree cutting.
Some of the scenarios above will be selected by CER each quarter to be assessed under the survey.
Priority will be given to those queries that, if responded to effectively, provide the most benefit to customers.
B.4.4.5 First Contact/Call Referral
This is a target through which ESBN Contact Centre agents are required to meet a target of dealing with a % of
calls within one call, that is, without requiring call-backs.
The targets for each of these areas, and the overall (ESATRAT) target are set out in Table B.5 below.
Table B.5 : Customer Satisfaction Target 2011 to 2015
Component of customer satisfaction metrics
2011 2012 2013 2014 2015
KPI Weighting Target Target Target Target Target
Speed of telephone response 25% 83% 83% 83% 83% 83%
Abandonment rate 25% 5% 5% 5% 5% 5%
Mystery caller 20% 80% 80% 80% 80% 80%
Call back survey 15% 80% 80% 80% 80% 80%
Call referral rate 15% 15% 15% 15% 15% 15%
ESATRAT (performance target) 85% 85% 85% 85% 85%
A reward/penalty of €0.7215m per % deviation applies to the weighted overall target. An annual maximum
reward of €1.6m and maximum penalty of €6.5m applies for 2011 rising to €1.7m and €6.9m, respectively, by
2015.
B.4.5 Metering
ESBN is incentivised against a set of Service Level Agreements (SLAs) for the provision of certain services by
the DSO under its licence obligations. These came into force in January 2005 and are reported on by the DSO
to CER in its annual performance report. SLA number 14 is the area against which metering performance is
measured. These targets state that:
100% of premises should have a scheduled read visit 2 times per year.
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97% of premises should have a scheduled read visit 4 times per year.
80% of visits should result in an actual meter read.
98% of meters should have 1 reading (DSO or customer) per year.
99% of meters will not have back to back block estimates.
For PR3, CER introduced financial incentives for the latter two items above. These are incentivised to a value of
±€1m per year. The targets and performance for the metering incentive are set out below in Table B.6 and
Table B.7.
Table B.6 : Regulatory Targets (at least one meter reading per year)
2010 2011 2012 2013 2014 2015
Target n/a 98.0% 98.0% 98.0% 98.0% 98.0%
Dead-band within which no payments are made n/a 0.2% 0.2% 0.2% 0.2% 0.2%
Value applied to deviation from target
€m per 0.1% deviation from target, 2009 money n/a 0.1 0.1 0.1 0.1 0.1
Cap on this incentive, +/- €m, 2009 money n/a 0.50 0.50 0.50 0.50 0.50
Table B.7 : Regulatory Targets (avoiding back to back estimates)
2010 2011 2012 2013 2014 2015
Target n/a 97.9% 98.1% 98.4% 98.7% 99.0%
Value applied to deviation from target
€m per 0.1% deviation from target, 2009 money n/a 0.1 0.1 0.1 0.1 0.1
Cap on this incentive, +/- €m, 2009 money n/a 0.50 0.50 0.50 0.50 0.50
B.4.6 Generation Connections
An incentive was proposed by ESBN in their PR3 submission to incentivise connection of renewable generation
to the distribution system. The proposal focussed on:
planning stage between offer acceptance to lodging of planning application;
detailed design stage from receipt of planning approval to issue of second stage payment invoice; and
construction stage from receipt of the second stage payment to energisation of the generator.
There was on-going consultation about generation connection policy in 2010 which resulted in delays to the
progression of most Gate 3 connections. This resulted in the deferral of any incentive regime based on
generator connection due to the continued uncertainty about timelines for connection. As a result this incentive
was not progressed in PR3 by CER or ESBN.
B.4.7 Worst Served Customer
Worst Served Customers (WSC) are those customers who experience a large number of supply interruptions
over a specified period. In order to be included on the worst served customer list, both of the following criteria
must be met:
greater than or equal to five interruptions over the past year; and
greater than or equal to 15 interruptions over the past three years.
Typically the customers impacted are supplied on rural single phase overhead networks.
ESBN proposed that a fund of €10m be put in place to improve service to worst served customers over the PR3
period. The fund of €10m was not included in the DSO revenue.
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While this fund was available for approved proposals, no penalties would have applied for non-performance.
B.4.8 CAPEX Delivery
The PR3 capex proposal was agreed at €2.3bn for Distribution.
There was an incentive designed to promote delivery of agreed portions of the overall distribution capex
proposal. The intention was to focus delivery within a large capex programme of key network development work
areas specifically relating to load and non-load capex. This looked at individual unit delivery of nominated work
programmes on a nominal 20% per annum basis for the five years. The incentive metrics were set at:
Programme Delivery <50% = penalty of €7m.
Programme Delivery 50% <70% = penalty payment of between €7m and €0m. -0.35 per % <70%
Programme Delivery 70% <80% = €0 (dead band)
Programme Delivery 80% <100%= payment of between €0m and €7m. 0.35 per % >80%
Table B.8 : Capex Delivery (Actuals against Targets)
2010 2011 2012 2013 2014 2015
Target
180.198 180.198 180.198 180.198 180.198
Cap on this incentive, +/- €m, real 2009
7.00 7.00 7.00 7.00 7.00
Following discussions between CER and ESBN in 2012, where a re-profiled capex programme was agreed for
PR3, the appropriateness of this incentive was considered and the incentive was suspended in 2013.
B.4.9 Summary of PR3 incentives
Table B.9 : Summary of PR3 Incentives
Incentive Value (€m, 2009 prices)
Losses +/- €10.5m
Continuity +/- 1.5% of revenue CI ~€10.5m;
+/- 1.5% of revenue CML ~€10.5m
RedC +/-€1.6m
Customer Satisfaction +€1.6m / - €6.9m
Metering +/- €1m
Generation connections discontinued
Worst served customer €10m fund available
Capex delivery +/ - €7m - discontinued
B.5 Performance in PR3
B.5.1 Losses
The DSO believes that the performance of the business has been improving generally and losses have been
decreasing over the last number of years. The DSO reports that there have been varying levels of success in
trying to produce a consistent and reliable set of losses figures year on year (annual variances in the output
undermine confidence in the specific figures though suggest an overall trend of declining losses). The actual
losses performance of the distribution system is stated to be in the region of 7 – 8%.
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Figure B.1 shows the performance achieved by ESBN during PR2 and PR3 (subject to the uncertainties noted
above) – Method A is based on an estimated throughput at the Transmission – Distribution boundary and
Method B. is based on measurement of inputs at the interface between transmission and distribution system
Figure B.1 : Losses Calculation for 2010, 2011 and 2012
To date, ESBN has not submitted any outturn losses figures to CER for consideration under the losses
incentive.
B.5.2 Continuity
In Table B.10 the values provided were in the original data submission. This has subsequently been updated
with changes in the forecasts and the actuals in earlier years. Volumes in 2014 were significantly down on the
forecast values originally provided.
Figure B.2 and Figure B.3 below set out the fault continuity performance of the DSO against the work-adjusted
targets set over the PR3 period to date, with Table B.11 showing the corresponding data in tabular format.
Planned outage targets are adjusted annually ex ante, taking into account actual delivered work volumes in that
year. The adjustments are based on the work volumes provided in’140730 Final DUoS Revenue and Tariff.xlsx’,
which is shown in Table B.10 below. These work volumes are multiplied by the corresponding per work unit
allowances in Table 46 of the CER Decision Paper CER/10/198. Figures for 2014 and 2015 have not been
adjusted as this information was not available at the time.
Table B.10 : PR3 Actual Work Volumes
Activity Work unit 2011 2012 2013 2014* 2015*
20kV conversion km 2,252 1,877 2,579 3,000 3,000
MV overhead line cyclic conversion km 2,877 6,936 5,632 9,000 9,000
Cut-out replacement Cut-out 11,405 4,310 5,371 8,000 8,000
Minipillar replacement Minipillar 122 156 101 320 320
LV urban overhead line
refurbishment Span 7,343 3,460 2,749 7,600 7,600
LV rural refurbishment Group 7,168 528 1,482 5,000 5,000
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Activity Work unit 2011 2012 2013 2014* 2015*
Non-scheme new connections Connections 6,494 5,155 4,730 10,836 11,079
Correction of voltage complaints Jobs 922 587 370 1600 1500
* Forecast Values based on the questionnaire submitted. These values were later updated and included variations to earlier years
Figure B.2 : PR3 Customer Interruptions per 100 Customers
Figure B.3 : PR3 Customer Minutes Lost
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Table B.11 : System Performance (2011 to 2015)
2011 2012 2013 2014 2015** PR3 Average
Customer Interruptions per 100 Customers (CI)
Planned
PR3 Actual 18.1 18.5 16.6 16.7 22.3 18.4
PR3 Targets (adjusted*) 18.0 14.0 13.8 22.6 22.7 18.2
Variance (negative = good) 0.1 4.5 2.8 -5.9 -0.4 0.2
Unplanned
PR3 Actual 94.6 85.7 114.2 129.6 95.2 103.9
PR3 Targets 120.5 116.9 113.3 109.6 106.0 113.3
Variance (negative = good) -25.9 -31.2 0.9 20.0 -10.8 -9.4
Customer Lost Minutes (CML)
Planned
PR3 Actual 46.6 44.9 42.1 42.3 40.8 43.3
PR3 Targets (adjusted*) 43.5 32.4 31.7 55.8 55.8 21.5
Variance (negative = good) 3.1 12.4 10.4 -13.5 -15.0 -0.5
Unplanned
PR3 Actual 69.6 62.0 86.7 101.1 83.1 80.5
PR3 Targets 85.3 80.6 76.4 72.2 68.0 76.5
Variance (negative = good) -15.7 -18.6 10.3 28.9 15.1 4.0
Total (Planned and Unplanned)
CI
PR3 Actual 112.7 104.3 130.8 146.3 117.5 122.3
PR3 Targets (adjusted*) 138.5 130.9 127.1 132.2 128.7 131.5
Variance (negative = good) -25.8 -26.7 3.6 14.1 -11.2 -9.2
CML
PR3 Actual 116.2 106.9 128.8 143.4 123.9 123.8
PR3 Targets (adjusted*) 128.8 113.0 108.1 128.0 123.8 120.4
Variance (negative = good) -12.6 -6.1 20.7 15.4 0.0 3.5
* Adjusted targets for 2011, 2012 and 2013. Targets for 2014 and 2015 remain as original CER decision targets.
** 2015 actuals are based on current forecasts.
Table B.11 shows that, on average, the DSO has met its PR3 CI target by 9.2 interruptions per 100 customers
and fallen short, on average, of its CML target by 3.5 minutes per customer.
Outturn figures for 2012 appear to differ between the DSO Forecast Questionnaire submission and DH08
Incentives, leading to a difference in reward payments being presented. Table B.12 shows that the rewards
payment for CI and CML in 2012 should have been €5.5m and €1.6m respectively. Note that 2014 and 2015
figures are based on current forecasts.
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Table B.12 : Achieved Earnings with respect to Continuity Performance (2009 prices)
Financial Payments 2011 2012 2013 2014* 2015*
Jacobs CI (€m) 5.3 5.5 -0.8 -2.9 2.3
ESBN CI (€m) 5.3 6.1 -0.8
Jacobs CML (€m) 3.3 1.6 -5.4 -4.0 0.0
ESBN CML (€m) 3.3 2.1 -5.4
* 2014 and 2015 values based on current estimates
Targets and performance exclude exceptional storm days, which totalled 22 days from 2010 to 2015, to ensure
that performance is measured on a consistent basis over time and with comparator countries.
Outages on the MV network give rise to the majority of CI and CML. There was a sharp decrease in CI and
CML in 2011 and 2012 which the DSO attributes to benign weather, rising again in 2013 and 2014 due to an
increase in storm activity.
The underlying network performance is best represented by the performance for unplanned interruptions which
has improved between PR2 and PR3 on a yearly average basis by around 20%, as shown in Table B.13.
Table B.13 : Improvement in network Performance Unplanned Outages (2010 to 2015)
Unplanned Outages PR2 Average PR3 Average Change in Average
Customer Interruptions (CI) 131.7 103.9 -21.11%
Customer Minutes Lost (CML) 103.8 80.5 -22.45%
Figure B.4 and Figure B.5 below compare the performance in PR2 to PR3. As can be seen, 2006 and 2007 had
particularly high CI and CML compared to the other years over the last decade. It should be noted that there
was a change in definition on interruptions, with PR2 figures including all interruptions greater than 1 minute,
whereas in PR3 the definition was for interruptions over 3 minutes.
Figure B.4 : Customer Interruptions (CI) in PR2 and PR3
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Figure B.5 : Customer Minutes Lost (CML) in PR2 and PR3
B.5.3 RedC
Achieved performance during the PR3 period is set out in Table B.14. The DSO has beaten the target by a
significant margin in every year with the corresponding reward being capped at the maximum level in each year
to date. Note that information for 2015 actuals was not available at the time of writing.
Table B.14 : PR3 Performance against RedC Incentive
RedC Poll
2010 2011 2012 2013 2014 2015
Target n/a 74.0% 74.0% 74.0% 74.0% 74.0%
Actual n/a 81.0% 83.8% 82.4% 80.5%
Value applied to deviation from target, €m, 2009 n/a 0.7215 0.7215 0.7215 0.7215
Cap on this incentive, +/- €m, real 2009 n/a 1.60 1.60 1.60 1.60
Cap on this incentive, +/- €m, nominal n/a 1.59 1.62 1.63 1.64
Payment ignoring cap on this incentive, €m, real 2009 n/a 5.05 7.07 6.08 4.69
Payment ignoring cap on this incentive, €m, nominal n/a 5.02 7.17 6.20 4.80
Payment allowing cap on this incentive, €m, nominal n/a 1.59 1.62 1.63 1.64
B.5.4 Customer Satisfaction
The DSO has exceeded the target in each year of PR3 to date and has earned the maximum (i.e. capped) level
of incentive under this mechanism (Table B.15). Note that information for 2015 actuals was not available at the
time of writing.
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Table B.15 : PR3 Performance against Customer Satisfaction Incentive
Customer Satisfaction
2010 2011 2012 2013 2014 2015
Target 85.4% 85.3% 85.3% 85.3% 85.3% 85.3%
Actual 89.8% 90.4% 86.5% 89.4% 90.0%
Value applied to deviation from target, €m, 2009 0.85 0.7215 0.7215 0.7215 0.7215
Cap on this incentive, +/- €m, real 2009 1.7 1.67 1.78 1.80 1.88
Payment ignoring cap on this incentive, €m, real 2009 2.07 3.73 2.35 3.02 3.41
Payment ignoring cap on this incentive, €m, nominal 3.15 3.71 2.39 3.08 3.48
Payment allowing cap on this incentive, €m, nominal 1.7 1.87 1.78 1.80 1.88
B.5.5 Metering
In terms of the obligation to achieve at least one meter reading per annum for customers, the DSO has
exceeded the target in each year of PR3 period to date (though with the performance being within the dead-
band in the last two years and hence no reward earned. Details are provided in Table B.16. Note that
information for 2015 actuals was not available at the time of writing.
Table B.16 : Performance against objective to obtain at least one meter reading per year
At least one meter reading per year
2010 2011 2012 2013 2014 2015
Target n/a 98.0% 98.0% 98.0% 98.0% 98.0%
Actual n/a 98.5% 98.2% 98.1% 98.0%
Dead-band within which no payments are made n/a 0.2% 0.2% 0.2% 0.2%
Value applied to deviation from target, €m, 2009 n/a 0.1 0.1 0.1 0.1
Cap on this incentive, +/- €m, real 2009 n/a 0.50 0.50 0.50 0.50
Cap on this incentive, +/- €m, nominal n/a 0.50 0.51 0.51 0.51
Payment ignoring cap on this incentive, €m, real 2009 n/a 0.30 0.00 0.00 0.00
Payment ignoring cap on this incentive, €m, nominal n/a 0.30 0.00 0.00 0.00
Payment allowing cap on this incentive, €m, nominal n/a 0.30 0.00 0.00 0.00
In terms of the obligation to avoid back-to-back estimated consumption for customers, the DSO has exceeded
the target in each year of PR3 period to date. Details are provided in Table B.17.
Note that information for 2015 was not available at the time of writing.
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Table B.17 : Performance against target to avoid back-to-back estimated consumption
Avoiding back to back block estimates
2010 2011 2012 2013 2014 2015
Target n/a 97.9% 98.1% 98.4% 98.7% 99.0%
Actual n/a 99.0% 98.9% 99.2% 99.7%
Value applied to deviation from target, €m, 09 n/a 0.1 0.1 0.1 0.1
Cap on this incentive, +/- €m, real 09 n/a 0.50 0.50 0.50 0.50
Cap on this incentive, +/- €m, nominal n/a 0.50 0.51 0.51 0.51
Payment ignoring cap on this incentive, €m, real 09 n/a 1.13 0.80 0.80 1.00
Payment ignoring cap on this incentive, €m, nominal n/a 1.12 0.81 0.82 1.02
Payment allowing cap on this incentive, €m, nominal n/a 0.50 0.51 0.51 0.51
B.5.6 Generation Connections
An incentive was proposed by DSO in PR3 submission to incentivise connection of renewable generation to the
Distribution System.
There has been on-going consultation and uncertainty about the roll out of Gate 3 connections in PR3 which
has delayed the progression of most Gate 3 connections. This resulted in the deferral of any incentive regime
based on generator connection. As a result this incentive was not progressed in PR3 by CER or ESBN.
B.5.7 Worst Served Customer
In 2014 ESBN has initiated a programme of targeted investigation and remedial works to improve the continuity
of supply seen by a group of customers classified as “Worst Served Customers” (WSC) – those customers who
have seen 15 interruptions in the past three years and at least five interruptions in the past year. There are
47,400 such customers based on 2013 outturn – the last full year of recorded outturn.
To date CER have approved projects proposed by ESBN totalling approximately €25k pa over the PR3 period.
In PR3 an initiative has been undertaken to address the WSC issue. The initiative has been addressed in the
following manner.
A list of single phase spurs on the WSC list were identified
A patrol of the single phase spurs was carried out. The goal of the patrol is to identify issues, with particular
focus on a range of pre-identified root causes and assets to which continuity issues are often attributed:
- Conductors
- Stays
- Crossarms, headgear, Insulators and accessories
- Line jumpers and connectors
- Pole mounted transformers
- Surge arresters
Following patrol and identification of issues, work orders are prepared to address plant defects or to install
items of plant expected to offer targeted remediation.
Remediation works are completed.
Typical Remediation Works
The typical remediation works required can be summarised under two broad categories:
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Solutions with lower resource requirement:
- Replacement surge arresters
- Bird caps on transformers
- Insulation of jumpers and bridgings
- Timber cutting
- Boxing in of the stay wires
Resource intensive remediation options:
- Single Phase Reclosers
- Single phase to three phase conversion
The current programme involves patrolling the networks feeding an identified spur where WSC are connected,
and remedial measures being proposed based on their observations of the network. The number of
interruptions seen by WSC may be attributable to a wide range of issues, including sub-standard network
components, timber contact with lines, environmental factors including gusts of wind, lightning, birds landing on
transformers and shorting across the bushings, or livestock interfering with poles or stays. ESBN has provided
no performance measurement metric for this programme.
B.5.8 CAPEX Delivery
In PR3 there was an incentive designed to promote delivery of agreed portions of the overall Distribution capex
proposal. The intention was to focus delivery within a large capex programme of key network development
work areas specifically relating to load and non-load capex. Following discussions with CER in 2012 where
ESBN agreed a re-profiled capex programme for PR3, the appropriateness of this incentive was discussed.
CER and ESBN agreed that the incentive for capex delivery was no longer appropriate. As a result the incentive
was suspended in 2013.
ESBN does not intend to put forward a Capex Delivery Incentive for PR4.
B.6 Suitability of Incentives for PR4
The following section discusses the incentives proposed by ESBN and the suitability of these incentives PR4.
B.6.1 Losses
ESBN does not intend to put forward a losses reduction target for PR4 and intends to discuss at a later date in
PR4 how the installation of Smart Meters may be used to facilitate a reliable measurement methodology. There
may also be scope at that point to consider the value in targeting commercial or technical losses for an
incentivised reduction programme.
Given the ongoing problems in accurate measurement of losses, we would recommend incentivising the DSO
(perhaps in conjunction with suppliers) to develop a measurement methodology including appropriate basis for
calculating accruals for estimated consumption from the date of last reading to year-end. For example, this
could take the form of a requirement to deliver an agreed methodology by end 2015 and to implement
calculation and reporting by end 2016, with penalties becoming payable in the event of non-performance.
B.6.2 Continuity
ESBN state that incentivised focus on improvement of continuity has resulted in steady improvement in the
performance of the network as experienced by their customers. This is an area of incentivisation that ESBN
believes should endure.
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B.6.2.1 Review of Proposed Incentives
ESBN’s proposed continuity targets based on the proposed Continuity CAPEX plan are shown in Figure B.6,
Figure B.7 and Table B.18. The targets are based on extrapolation of performance for previous years,
excluding 2011, 2012 and 2014 which are considered by ESBN to be outliers.
ESBN has not proposed financial payment figures for deviating from the proposed targets.
In our opinion the increase in CI and CML experienced following the benign years of 2011 and 2012 is in part a
consequence of the better than expected performance in those years (i.e. events that might otherwise have
occurred in those years under average conditions are simply deferred, and occur later along with other events
that would have occurred in that later year anyway). Hence consideration should be given to deriving a target
from historic performance across all years rather than taking out the high and low years. The principal is based
on knowing that even with storm events removed there will be good and bad years, the incentive is to ensure
the business progressively improves its approach towards prevention and response to supply loss.
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Figure B.6 : Forecast Customer Interruptions
Figure B.7 : Forecast Customer Minutes Lost
Table B.18 : DSO Proposed Network Performance Targets
DSO Forecast PR2
Average
PR3
Average
Average
Change
PR2 - PR3
2016 2017 2018 2019 2020 PR4
Averag
e
Average
Change
PR3 - PR4
Unplanned CI 131.7 103.9 -21.16% 113.7 112.4 111.1 109.8 108.5 111.1 6.96%
Unplanned CML 103.8 80.5 -22.48% 84.2 82.5 80.9 79.2 77.5 80.86 0.45%
Planned CI 29.5 18.4 -37.40% 21.8 22.1 22.4 22.8 23.1 22.44 21.69%
Planned CML 106.2 43.3 -59.19% 52.3 53.1 53.9 54.8 55.8 53.98 24.56%
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The DSO has made proposals for improvement in network performance for the period 2016 to 2020 including
operational improvements, network renewal and specific continuity improvement projects. Table B.19 below
summarises the balance of improvements and degradation DSO has forecast over PR4.
Table B.19 : DSO Proposals for Network Performance Improvement
Programme Units CI CML Cost (€m)
20kV Conversion 4,000 -0.02 -1.20
Loop Automation (schemes) 50 0.10 4.88 8.5
Single Phase Reclosers (spurs) 150 0.005 0.77 0.6
Fault Passage Indicators 1,150 0.00 6.67 1.1
Worst Served Customers 6,000 0.001 0.11 1.4
38kV Switch Automation 1.3
Wildlife Diverters in HV Stations 300 0.3
Urban RMU Automation Pilot 30 0.20 0.3
MV Arc Suppression (Stations 17 0.02 1.94
The extent of the 20kV conversion programme will be much reduced in PR4 compared to that of PR3 with
4,000km planned for completion. There is expected to be a higher number of outages per km converted than in
PR3 but the total quantity of network converted to 20kV operation will be less. The overall impact of this
programme is to increase CI and CML’s and so the overall CI and CML impact of 20kV conversion will be less in
PR4 than it was in PR3.
There is also expected to be an increased number of planned outages required as part of the MV Overhead
Cyclic Refurbishment (OCR) programme in order to deal with the issue of accelerated pole rot on Scantrepo
poles. Furthermore there is a large volume of MV OCR (approx. 17,000 km) anticipated for 2015 with the
quantity then reducing to approximately 6,900 km per annum for the duration of PR4, resulting in a high CI and
CML impact in 2015.
The LV Rural Refurbishment (LVR) work programme will be ramped up in 2015 and there will be a consequent
increase in the CI and CML numbers for this programme.
In section 1 of DF 30 Continuity Plan ESBN proposes that 6,000 WSC will be benefited for a cost of €1.4m as
shown above, however in section 2 the stated number of WSC to benefit from the same expenditure is 4,000.
Jacobs recommends that the intended units for Worst Served Customers are confirmed at either 4,000
or 6,000 customers for the €1.4m fund ESBN is requesting. The outcome of this confirmation will impact
on the incentive scheme proposed for WSC in section B.5.7.
Table 2 in ESBN’s DF30 Continuity Plan report outlines the cost-benefit of the proposed continuity improvement
programmes for PR4.
The forecasts for planned outages are based on assumed levels of activities in different areas. Table B.20
shows proposed work volumes and Table B.21 shows the corresponding CI and CML adjustments per work unit
in each area.
In relation to the MV OCR programme, an increase in the allowed CI and CML per work unit is proposed. ESBN
report that the data for 2013 outturn indicates that the actual duration of outages for customers was correct,
whereas the number of outages required to complete the total work programme was higher than anticipated. A
number of factors contributed to this result with the work being completed in smaller blocks due to resource
availability and also the increasing impact of accelerated rot on Scantrepo poles. New work practises are being
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put in place to address the Scantrepo pole issue with one outage required to assess the full pole length and a
second outage required to replace the pole. An increase in the allowed CI and CML for MV OCR is proposed.
Table B.20 : DSO Proposed Work Programmes
Activity Work unit 2014 2015 2016 2017 2018 2019 2020
20kV conversion km 2,000 2,000 800 800 800 800 800
MV overhead line cyclic
conversion km 5,000 17,000 6,900 6,900 6,900 6,900 6,900
Cut-out replacement Cut-out 4,000 4,000 8,000 8,000 8,000 8,000 8,000
Minipillar replacement Minipillar 102 102 440 440 440 440 440
LV urban overhead line
refurbishment Span 2,000 2,000 3,500 3,500 3,500 3,500 3,500
LV rural refurbishment Group 4,000 9,000 3,450 3,450 3,450 3,450 3,450
Non-scheme new connections Connections 4,987 5,243 5,500 6,000 6,500 7,000 7,500
Correction of voltage
complaints Jobs 850 850 850 800 750 700 650
Table B.21 : Proposed CI and CML per Work Unit
Activity Work unit CI x 100 per work unit CML per work unit
20kV conversion km 0.000784 0.002235
MV overhead line cyclic conversion km 0.000869 0.002347
Cut-out replacement Cut-out 0.000045 0.000027
Mini-pillar replacement Mini-pillar 0.000267 0.000963
LV urban overhead line refurbishment Span 0.000178 0.000642
LV rural refurbishment Group 0.000542 0.001540
Non-scheme new connections Connections 0.000513 0.001307
Correction of voltage complaints Jobs 0.000958 0.002444
B.6.2.2 Assessment and Recommendations for Continuity Incentives in PR4
CI and CML targets are a key measure used internationally for measuring and incentivising distribution
company performance. Hence it is recommended that targets continue to be applied on this basis. We would
expect the level of targets to be set at a level consistent with a trend of continued improvement in performance.
Although ESBN’s forecast levels of CI and CML show a declining trend through the PR4 period, we note that,
because 2011, 2012 and 2014 data have been excluded from the base-line used from the forecast, the
proposed targets appear to be less onerous than those currently in place under PR3.
As well as continuing the general downward trend, the specific level of the targets should also be set taking into
account the benefits expected to arise from capex schemes and opex activities (such as tree-cutting) approved
as part of the PR4 determination.
As stated in section B.5.2 above, ESBN has, on average, outperformed its CI targets throughout PR3 while it
has underperformed, on average, with respect to CML targets based on current data. This would indicate that
CI more challenging targets can be set for PR4 in order to encourage a better service for customers on the
network. Although ESBN has missed its CML targets by 2.9%, on an average basis, this deviation is relatively
minor and therefore we believe PR4 targets should be set at levels which continue to incentivise improvements
in this area.
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Furthermore, due to the incentive scheme being centred on the aggregated planned and unplanned total for
each metric, ESBN has only exceeded the targets by relatively small amounts in the more severe weather years
of 2013 and 2014. In using the total level as the target, the DSO is not incentivised to minimise planned outages
over unplanned outages. It is our opinion that unplanned outages have a more adverse impact on customers
due to the inherent uncertainty associated with them, and therefore we would encourage a scheme that
incentivises planned outages compared to unplanned outages.
Hence we would recommend using separate targets for unplanned and planned outages, with a 50%
less weighting on planned outage financial payments.
This would encourage the DSO to be proactive in managing the causes of unplanned outages, such as timber
contact, and provide further incentives to introduce innovative asset management strategies.
We recommend that targets be set at those stated in Table B.22 below. Planned allowances have been
calculated based on the following:
Planned CI – sum-product of work volumes and CI per work unit allowances plus an additional allowance
of 6 CI for unidentified planned outages.
Planned CML – sum-product of work volumes and CML per work unit allowance plus an additional
allowance of 10.6 CML for unidentified planned outages.
Unplanned outages have been calculated based on the following methodology:
3) Calculate the average outturn of unplanned outages for 2010 – 2014, PR3ave (5 years of most recent data).
4) Retrospectively set the 2013 target (i.e. midpoint of PR3) equal to PR3ave.
5) Using the slope from the original PR3 targets, calculate new targets for 2011, 2012, 2014 and 2015 to
create ‘modified PR3 targets’.93
6) Set the recommended target for 2016 to the 2015 target from the ‘modified PR3 targets’.
7) Using the slope from the DSO proposed PR4 targets, calculate recommended targets for 2016 – 2020.
An example calculation is shown in Figure B.8 below.
93 ESBN state that in their Capex reduction programme, continuity capex was reduced to a greater extent than
other capex. We note that in the early meetings when we pointed out the poorer performance in the later years
of the review and we suggested that the lack of investment would be a factor, ESBN stated that that was not the
case. Also given the modest forecast improvements due to capital programmes that were in the original plan,
then the reduced spending will not have had a significant impact on out-turn when the avoidance planned
outages is considered.
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Figure B.8 : Unplanned Outages Example
Using the modified PR3 targets described in step 3) above, the DSO would have achieved net deviations of
+0.5 CML and -22.4 CI over the PR3 period for unplanned outages. The average annual deviations would have
been 0.1 CML and -4.5 CI during PR3. This evidence clearly demonstrates that the modified PR3 targets, upon
which the recommended PR4 unplanned targets are based, were achievable in PR3 and reflect current
operating conditions for the DSO.
ESBN has not proposed financial reward and penalty figures; therefore we would recommend that PR3
figures, adjusted to real 2014 prices, are used for PR4.
As in PR3, planned outage metrics should be adjusted ex post with regard to the outturn work volumes
completed in any given year.
Table B.22 : Recommended Network Performance Target for PR4
Target Unit 2016 2017 2018 2019 2020 PR4 change
Planned CI CI × 100 15.4 15.6 15.8 16.0 16.2 5.1%
Planned CML CML 35.6 36.1 36.6 37.1 37.6 5.6%
Unplanned CI CI × 100 101.1 99.8 98.5 97.2 95.9 -5.1%
Unplanned CML CML 71.9 70.2 68.4 66.6 64.9 -9.7%
Total CI CI × 100 116.5 115.4 114.3 113.2 112.1 -3.8%
Total CML CML 107.5 106.3 105.1 103.8 102.5 -4.6%
On average across PR4, the recommended targets for planned outages are between 30% and 33% lower than
those proposed by ESBN and between 11% and 16% lower for unplanned outages. For total customer
interruptions and customer lost minutes, the recommended targets are between 14% and 23% lower than
ESBN’s proposed PR4 targets. A detailed summary of the changes can be seen in Table B.23 below.
Table B.23 : Percent difference between ESBN Proposed and Jacobs Recommended Targets
Change from ESBN Proposal Unit 2016 2017 2018 2019 2020
Planned CI CI × 100 -30% -30% -30% -30% -30%
Planned CML CML -32% -32% -32% -32% -33%
Unplanned CI CI × 100 -11% -11% -11% -11% -12%
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Change from ESBN Proposal Unit 2016 2017 2018 2019 2020
Unplanned CML CML -15% -15% -15% -16% -16%
Total CI CI × 100 -14% -14% -14% -15% -15%
Total CML CML -21% -22% -22% -23% -23%
Financial payments have been split on a 1:2 ratio between planned and unplanned outages for both the CI and
CML metric. These payments are outlined in Table B.24 below. The average financial payment for deviating
from the CI and CML targets is shown to be same as the PR3 financial payments in 2014 prices. Capping of
financial payments should continue as implemented in PR3.
Table B.24 : Recommended Financial payments for PR4 (2014 Prices)
Financial Payments 2016 2017 2018 2019 2020
Planned CI € 141,012 € 141,012 € 141,012 € 141,012 € 141,012
Planned CML € 178,713 € 178,713 € 178,713 € 178,713 € 178,713
Unplanned CI € 282,024 € 282,024 € 282,024 € 282,024 € 282,024
Unplanned CML € 357,426 € 357,426 € 357,426 € 357,426 € 357,426
Average CI € 211,518 € 211,518 € 211,518 € 211,518 € 211,518
Average CML € 268,070 € 268,070 € 268,070 € 268,070 € 268,070
Should this weighted payment regime be implemented by CER, it will be especially important that
outage data in PR4 is independently audited when submitted to CER. It has been noted that the DSO
has provided further information relating to the impact of the planned outages which suggests that the
targeted improvements may be difficult to achieve. As we have stated there should be independently
audited performance, this should also cover the planned outage programmes to derive a better baseline
for the review and future targets.
We believe these targets are stretching but achievable while ensuring that customers continue to see an
improvement in the network service they receive from ESBN. For comparison, Figure B.9 to Figure B.14 below
show a breakdown of PR3 performance, PR3 targets, ESBN’s proposed PR4 targets and Jacobs’
recommended PR4 targets for each element of the continuity incentive scheme.
It is also noted however that ESBN have proposed a number of amendments to the calculation of continuity
metrics including:
revised definition of storm threshold;
revised adjustment factors for planned outage activities; and
smart metering.
These proposed amendments are discussed in sections B.6.2.3 to B.6.2.6. The North Atlantic Green Zone
scheme is also discussed in the context of continuity.
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Figure B.9 : Planned CI Comparison
Figure B.10 : Planned CLM Comparison
Figure B.11 : Unplanned CI Comparison Figure B.12 : Unplanned CML Comparison
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Figure B.13 : Total CI Comparison
Figure B.14 : Total CML Comparison
B.6.2.3 Revised storm threshold
ESBN have proposed that a storm threshold of 2.5 standard deviations from the mean daily level (assuming a
log-normal distribution) as per the IEEE 1366-2003 standard. For comparison, Ofgem approved RIIO-ED1
Incentives with a storm threshold set at eight times the daily average.
If ESBN’s proposal were to be accepted, it would result in a reduction in the storm threshold from 61,570CML to
49,161CML with a corresponding increase in the number of days being captured by the exclusion. This would
result in an apparent improvement in performance relative to historic figures calculated on the original basis.
Figure B.15 illustrates this point.
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Figure B.15 : Illustration of Impact of Proposed Change to Storm Threshold
Changing the storm threshold is an area the DSO and CER should consider further in consultation with other
stakeholders. Due to the time constraints at this stage of PR4 the consultation would not allow sufficient time to
retrospectively determine past performance, therefore creating inconsistency between past and future targets.
We consider that the CER support further investigation in monitoring performance and determining appropriate
targets. However there would need to be fully independently audited network performance data made available
which is consistent with most regulated businesses where financial rewards and penalties are involved.
Experience has shown that independent auditing identifies inaccuracies and errors which need to be factored
into reporting values before financial payments are confirmed.
In general the proposed changes suggested by the DSO would remove more abnormal days from consideration
reducing the CI and CML values being considered as incentivised, in which case the impact which could be
achieved during more ‘normal ‘ type fault day events would be reducing and the level of incentive would need to
be adjusted accordingly reducing potential rewards and penalties and hence the impact of the incentive.
Jacobs acknowledges that the DSO is likely to face changing weather conditions in the future but believes that
the network should be designed in such a way to mitigate these risks and provide benefit to customers through
a comprehensive cost-benefit approach.
Hence it is recommended that the storm threshold remain unchanged at present but CER should
undertake a full consultation with the DSO to determine an appropriate measure for future price
controls. There needs to be fully independently audited network performance information available to
the CER to ensure the validity of performance against any propsed changes in targets.
B.6.2.4 Revised adjustment factors
The target levels for CI and CML for planned outages are proposed based on an assumed level of activity with
respect to different work areas (20kV conversion, cyclic refurbishment, cut-out replacement, etc). Where the
volume of work completed in each of these areas differs from the original assumptions, adjustment factors are
applied to re-calculate the target accordingly.
Additional CML excluded with new lower threshold
CML excluded with current storm threshold
Illustration of impact of proposed change to storm threshold
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We note that the DSO has stated that they believe the current scheme does not allow enough flexibility in
relation to volumes of work. It is our opinion that the current scheme is suitably flexible for its purpose.
For the PR4 period, ESBN have proposed increases to the per unit CI and CML allowances for two planned
work programmes compared to PR3. The increases proposed are 77% for the 20kV conversion work
programme and 102% for the and MV overhead line cyclic conversion work programme, as shown in Table
B.25 below.
Table B.25 : Comparison of CI and CML Adjustments for Planned Work Units between PR3 and PR4
Activity Work unit
PR3 Allowances PR4 Allowances Change (%)
CI x 100 per work unit
CML per work unit
CI x 100 per work unit
CML per work unit
CI x 100 per work unit
CML per work unit
20kV conversion km 0.000442 0.00126 0.000784 0.002235 77% 77%
MV overhead line cyclic conversion
km 0.000431 0.00116 0.000869 0.002347 102% 102%
Cut-out replacement Cut-out 0.000044 0.00003 0.000045 0.000027 2% -10%
Minipillar replacement Minipillar 0.000265 0.00095 0.000267 0.000963 1% 1%
LV urban overhead line refurbishment
Span 0.000177 0.00064 0.000178 0.000642 1% 0%
LV rural refurbishment Group 0.000534 0.001514 0.000542 0.00154 1% 2%
Non-scheme new connections
Connections 0.000508 0.0013 0.000513 0.001307 1% 1%
Correction of voltage complaints
Jobs 0.00095 0.00242 0.000958 0.002444 1% 1%
This appears counter-intuitive; it would be expected that the early phases of the 20kV conversion would have
been targeted towards sections of the network with the greatest benefit (i.e. the greatest load and number of
customers). This would ensure that the maximum number of customers benefitted earlier in the programme and
the improvement in network performance would give maximum benefit to ESBN in the incentive scheme.
Hence the later phases of this programme would then be expected to be biased towards parts of the network
with lower customer density, and lower values of adjustment factor would be expected on this basis.
The ESBN submission notes that “the volume of outages required per km of 20kV conversion has proven to be
higher than was anticipated for PR3”. Some explanation has been provided in response to questions on this
including the impact of Scantrepo poles and that there has been an increase in the number of outages required.
In most instances there are lower numbers of customers affected per outage. ESBN have commented that the
20kV conversion is targeted at high load growth and poor voltage networks rather than initially high loaded
feeders, seems reasonable. This may seem to indicate that the customers affected may not reduce over time. It
would however be expected that when planning a work programme the priority would be given to the feeders
which impact most customers for voltage problems. We would generally not expect the impact to be increasing.
For comparison and consistency-checking we have normalised historic and forecast figures to identify the
underlying levels of planned outage CML that would be expected if no change was made to the per unit work
allowances (i.e. the PR3 allowances). This analysis identifies apparent anomalies in the underlying levels of
planned outage CI and CML. As shown in Figure B.16 and Figure B.17, the normalised level of planned CI and
CML has decreased from PR3 to PR4 as a result of lower work volumes being forecast, rather than
improvements in the management of outages due to planned work.
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Figure B.16 : CI Normalised with respect to PR3 planned work unit adjustment factors
Figure B.17 : CML Normalised with respect to PR3 planned work unit adjustment factors
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ESBN has provided further justification for the proposed increases in adjustment factors for 20kV
conversion and MV overhead cyclic conversion work programmes. There does not however appear to
be sufficient account taken of the approach that would target the feeders which would give the biggest
improvement early, leading to a reduced impact as the programme progresses. We do note the
concerns expressed by ESBN, and feel that this may be an area where there are opportunities for
annual reviews against audited actual values in the work programmes which give greatest concern.
In the interim, we would recommend that the proposed PR4 per work unit allowances be set at 0.95 of
the PR3 figures. Table B.26 outlines these recommended allowances.
Table B.26 : Recommended CO and CML per work unit for PR4
Activity Work unit Recommended PR4 allowances
CI x 100 per work unit CML per work unit
20kV conversion km 0.000420 0.001197
MV overhead line cyclic conversion km 0.000409 0.001102
Cut-out replacement Cut-out 0.000042 0.000029
Minipillar replacement Minipillar 0.000252 0.000903
LV urban overhead line refurbishment Span 0.000168 0.000608
LV rural refurbishment Group 0.000507 0.001438
Non-scheme new connections Connections 0.000483 0.001235
Correction of voltage complaints Jobs 0.000903 0.002299
Using the ESBN’s proposed PR4 work volumes and per work unit allowances, the level of outages in PR4
contributable to work programmes proposed have been calculated. The variance between the outages
contributable to work programmes and ESBN’s proposed planned outages varies between 7.2 and 7.9 for CI
and 13.6 and 15.0 for CML. This difference has been termed the ‘unidentified level of planned outages’ and we
recognise the importance of these outages, particularly where an increase in planned outages leads to a
decrease in unplanned outages. A summary of this information is presented in Table B.27 below.
For comparison, the level of unidentified planned outages included in the PR3 targets was constant at 6.0 for CI
and 10.6 for CML.
Table B.27 : Comparison of Calculated Planned CI and CML against Proposed CI and CML
Planned interruptions 2016 2017 2018 2019 2020
Planned CI contributable to work
programmes
14.4 14.6 14.8 15.0 15.2
Planned CML contributable to work
programmes
38.7 39.2 39.7 40.3 40.8
ESBN proposed PR4 planned CI 22.3 21.8 22.1 22.4 22.8
ESBN proposed PR4 planned CML 52.3 53.1 53.9 54.8 55.8
Unidentified planned CI 7.9 7.2 7.3 7.4 7.6
Unidentified planned CML 13.6 13.9 14.2 14.5 15.0
We recommend that the same level of unidentified planned outages in PR3 be added to the calculated
planned outages for PR4. These supplements of 6.0 and 10.6 for planned CIs and CMLs, respectively,
should be added ex post to the CI and CML per work unit allowances being approved.
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B.6.2.5 Smart Metering and Fibre to the Building
ESBN have stated that these programmes are likely to result in an increased level of planned outages to
existing customers over the period and that they believe that the continuity performance targets should be set
appropriately, with an appropriate allowance being set per unit of work delivered. We are minded to agree that
the continuity targets need to be consistent with the obligations of the smart meter programme.
We believe the cost incentive associated with the programme is sufficient incentive for ESBN to manage this
project timely and efficiently.
Hence we recommend that interruptions and outages caused directly by the smart meter programme be
reported separately from the overall CI and CML figures, and excluded from the continuity incentive
scheme entirely.
B.6.2.6 North Atlantic Green Zone
The North Atlantic Green Zone is an EU supported programme of investments in the cross-border region
between Ireland and Northern Ireland. One of the stated aims is to reduce customer interruptions by 54%. In
their submission, ESBN discuss a programme of conversion from 10kV to 20kV and automation of a large
number of overhead lines and switches. The extent (if any) to which such work overlaps within the existing
programmes of planned work in this context is unclear. ESBN have stated that there is no overlap, and that they
will not be seeking to increase continuity Capex should NAGZ not proceed.
The NAGZ programme has been deemed as independent of the existing continuity investment plans and
performance.
B.6.3 RedC
The DSO initially proposed an overall target level of 74%, with this target level fixed for each year of the control
period. Previously, the DSO also proposed that this incentive is given equal weight to the NCCC Customer
Satisfaction weighting, and therefore proposed the use of the same value per 100 basis points difference
against the target, e.g. €721,000 per percent deviance, with a maximum penalty/reward of €1.6m annually. It
proposed that equal value is given to over and under-performance against the target level.
ESBN believes that this incentive should endure and they highlight that the connection volumes are forecast to
increase and that this may impact on customer service achievement – however the forecast levels are below
historical highs. However, we would expect that the scalability and resourcing in areas for connections both in
delivery and in customer contact would comfortably manage the volumes and therefore we would not expect
deteriorating satisfaction levels due to connections levels increasing form a very low level. To suggest this
would appear to assume that as the volumes may increase then the existing resource would be used and thus
perform at a lower level.
An average performance of 82.4% has been achieved for PR3 to date. Given the ease with which the target
has been achieved to date, we believe a more challenging target should be applied to drive continued
improvement in performance.
Furthermore we note that this survey is an annual survey but based on customers who contacted the company
in the preceding six months. Hence CER may wish to consider specifying the timing of the survey so that it
would not be artificially restricted to customers contacting ESBN during the summer months, when logic would
suggest there might be fewer interruption-related enquiries.
Hence we would recommend the target be set at 82.5% to incentivise the DSO to at least maintain their
current performance level.
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B.6.4 Customer Satisfaction
ESBN believes that this this incentive should endure and has proposed targets for each area and the overall
(ESATRAT) target as set out in Table B.28 below.
Table B.28 : Customer Satisfaction Proposed Annual Targets
KPI Target
Speed of telephone response 83%
Abandonment rate 5%
Mystery caller 80%
Call back survey 80%
Call referral rate 15%
ESATRAT (performance target) 85%
In PR3 the annual reward was capped at 0.25% of revenue, while the annual penalty was collared at 1.0% of
revenue. This equated to annual maximum reward of circa €1.6m and maximum penalty of circa €6.5m. In a
similar way to the continuity incentive, ESBN would like CER to consider the definition of “Exceptional Events”
from a contact centre perspective where it is not reasonable to expect that the normal targets will be met.
These days could be removed from the incentivised reporting criteria and replaced with the average of all of the
other day’s performance. ESBN is happy to work with CER to define a threshold and mechanism that is
reasonable and appropriate.
Although Exceptional Events days would result in high level of calls, this is likely to be the main (or perhaps
even the only) occasion on which some customers contact the distribution company. The DSO should therefore
have a strong incentive to deal adequately with customers and keep them informed in such circumstances.
ESBN have proposed a target of 85%, which is the same as that during PR3. Given the ease with which this
target has been achieved thus far, we believe a more challenging but achievable target should be considered.
Using the average achieved performance for years 2010, 2011 and 2013 would give a target of 89.9%. (2012
showed a marked dip in performance and was excluded as an outlier; if it were included the average would be
89% instead).
To incentivise continuing improvement in this area, we would recommend that the PR4 ESATRAT target
be set at 89%, with the same reward/penalty scheme as that in PR3 continued; adjusted to 2014 prices.
B.6.5 Metering
In PR3 ESBN was incentivised against a set of Service Level Agreements (SLAs) for the provision of metering
services as set out in the DSO licence. These are:
98% of meters should have 1 reading (DSO or customer) per year.
99% of meters will not have back to back block estimates.
These are incentivised to a value of +/- €1m per year. The targets and performance for the metering incentive
are set out below.
ESBN believes that this set of incentives should continue for the duration of PR4. Meter reading in its current
form is likely to change as Smart Metering infrastructure is rolled out over the coming years. It is appropriate to
review the continuation of the metering incentive model as decisions about Smart Metering rollout are made
over the course of PR4. In the meantime this is an important area of service provision and the ongoing
incentivisation of this activity is encouraged.
A simpler approach may be to restrict the proposed incentive to be applicable only to legacy meters (i.e. not on
smart meters).
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In the UK, the accepted industry standard is for at least one meter read per year for 97% of customers94. The
proposed standard by ESBN is a higher standard than the UK, which is generally seen as an international
benchmark.
We recommend that this incentive endure and that the mechanism is reviewed throughout the Smart
Meter rollout programme to monitor its appropriateness and design.
B.6.6 Generation Connections
This incentive was not progressed in PR3 by CER or ESBN and as a result ESBN does not propose a
Generation Connection Incentive in PR4.
B.6.7 Worst Served Customer
ESBN proposes a programme to address the continuity performance received by 4,000 Worst Served
Customers (WSC) during PR3. It is anticipated that this will cost a total of €1.4m.
As yet there is very significant uncertainty as to the extent to which it is possible to address WSC issues in full
and trials to date have not proven conclusive. Nonetheless, ESBN considers this programme to warrant delivery
in the interests of taking measures in addressing the needs of those who experience the worst network
performance.
It is noted that ESBN had 47,400 WSC connected to their network in 2013, or 2.1% of all customers. This is a
large percentage of customers, especially when compared to GB DNOs. Further to this, ESBN claimed circa
€25,000 per annum of the €10m fund available during PR3, indicating a significant underspend in this area. As
the programme by the DSO is not expected to have sufficient valid data till 2017/18 then there would be some
difficulties in determining the impact of measures and the net result of the investment. The DSO have
suggested using UK RIIO data to determine the value of improvement for each worst served customer. The
DSO has also suggested that information they have gathered between November 2014 and April 2015 gives an
indication that they would require considerably higher allowances to deliver improvements.
It should be noted that the information provided in this latest submission significantly raises the allowances
proposed. We do not consider there has been sufficient justification for this increase, and equally any
comparison to UK DNO’s neglects the fact that they have undergone extensive investment over many years in
this area, where the cost per customer has been much lower. We would not consider that the cost per customer
to improve the performance at the start of this programme would be comparable to the cost when a programme
has been in operation for many years. The improvements which can be made diminish and the costs increase
over time so the point in the cycle in which the improvement is targeted has a greater influence over the cost.
One option available to the CER would be to impose a reward/penalty based on a glide path 2020 set of targets,
with financial settlement occurring three years after the year in question on a net present value (NPV) neutral
basis. The incentive would be capped and collared either to a percentage of revenue in that year, or a nominal
amount. The WSC definition requires a three year lag in payment in order to confirm the improved performance
objective. For example, the impact of a scheme designed to reduce the number of WSC by 1,500 which is
implemented in 2016 would only be fully realised in 2019 once three years of data had been collected.
Hence we would recommend introducing an additional reward/penalty scheme of ±€500 per WSC to
incentivise ESBN to deliver on their plan to reduce the number of WSC to 43,400 by 2020. The cap and
floor for such a scheme would need to be discussed between CER and ESBN to determine appropriate
levels by which non-WSC customers are subsidising WSC. We would recommend that the floor be
greater than the proposed funding amount thereby strongly disincentivising ESBN to do nothing.
We note that there is a large degree of uncertainty when planning WSC schemes and hence would
encourage the use of an appropriate dead band either side of the target (i.e. de minimis threshold). We
would encourage further consultation with ESBN regarding the introduction of this additional element
94 http://www.elexon.co.uk/reference/market-compliance/peer-comparison-graphs/
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to the WSC incentive scheme. To determine the effectiveness of an introduced programme, ESBN
should provide evidence that customer interruptions in the targeted area have reduced by a target level,
for example 25%, which was used in DPCR5 in GB. We would again emphasise that any historic and
improved performance needs to be independently validated through an audited sample of the defined
WSC’s.
B.6.8 CAPEX Delivery
ESBN has stated that it does not intend to put forward a capex delivery incentive for PR4.
B.6.9 Potential new incentives
In addition to those incentive mechanisms already employed, we have considered potential additional
mechanisms for consideration by CER to incentivise continued improvement in ESBN’s performance. Areas to
consider in this respect would include:
Different continuity targets for urban and rural customers – given the different characteristics of rural
customers (typically low density, geographically dispersed and often on single spur connection) compared
with urban customers (higher density, geographically concentrated and with greater degrees of redundancy
in connections), consideration has been given to the possibility of setting different targets for such
customers. Rural customers typically experience a greater frequency of outages and outages of longer
duration. – This would require customers to be classified by type, which in the past stakeholders have had
difficulty agreeing on, and retrospective analysis of historical performance in order to set appropriate
performance base-lines. However classification has been achieved in other jurisdictions such as Australia,
where the Australian Energy Regulator (AER) classifies customers as CBD, urban, short rural and long
rural. If material differences were identified in service levels for rural customers compared to urban, it could
lead to pressure for discounted pricing for disadvantaged rural customers (despite the fact that such
customers are more expensive to serve than urban customers).
Load Connections – specifying a target time to provide a connection offer/quotation and target time to
connect (following acceptance of connection offer). Different targets would need to be specified according
to customer type (e.g. scheme housing, non-scheme housing, small commercial, medium commercial, etc).
Reporting of volume of customer complaints by different categories (e.g. metering, billing, new
connections, interruptions, voltage, etc). Customer satisfaction is currently assessed by call-back surveys,
mystery caller surveys and the RedC survey. Whilst these provide an indication of satisfaction levels for
the customers contacted, it does not provide any insight on the aggregate number of complaints received
by the DSO.
Compiling statistics on the basis of number of complaints received would provide information that could
guide the setting of appropriate areas for incentives in future price control periods (PR). Given the lack of
historical information, it may not be appropriate to set quantitative targets at this stage. However applying
a requirement to compile and report such statistics on an annual basis during PR4 would then provide a
base-line for quantitative targets in subsequent PRs.
Identification of vulnerable customers – an incentive to ensure the DSO maintains accurate information
on vulnerable customers connected to its network and provides assistance to such customers (for example
during planned and unplanned outages). Note: Delivery of this may require additional opex.
B.6.10 Possible new incentives to consider
Table B.29 present possible new incentives to be considered for application in PR4.
Table B.29 : Proposed Incentives for PR4
Incentive Proposed incentive PR4
Connections TBA / ESBN to propose
Reporting of customer complaint
statistics Reporting requirement only – incentive mechanism to develop PR5
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Vulnerable customers TBA / ESBN to propose
B.7 Recommendations
At this stage, our key recommendations for further work in the development of the proposed incentives are:
1) Losses – ESBN to be tasked with proposing an outline project plan and timetable for the development of a
methodology for calculation of losses (including calculation of accruals for un-metered consumption)
Planned outages – provide delivered work volumes for 2011 – 2014 in stand alone document
Continuity incentive storm threshold – remain unchanged but reviewed with independently audited data
as the baseline.
Continuity incentive – To operate to the proposed targets but allow ESBN to provide further detail to
support their proposed CI and CML adjustment factors for planned work as part of the independently
audited reporting recommended to ensure accurate data is used in determining rewards and penalties.
Worst Served Customers – reward/penalty scheme to be introduced to encourage implementation of
initiatives
Connections – ESBN to propose new incentive incorporating target times for making connection offers to
different categories of customer connections, target time for completion of connection following offer
acceptance.
Customer complaint reporting – ESBN to be requested to commence reporting of customer complaint
numbers by category of customer and category of complaint.
Recommendations to consider going forward in future price control periods include:
2) Audited continuity metrics – it is not clear whether the figures presented for interruptions and outage
durations have been independently audited. We would recommend that ESBN submit independently
audited information to the CER annually.
B.8 Findings
The interim findings of this report are set out below by incentive scheme, followed by a summary of performance
in PR3, ESBN’s proposed PR4 incentives and possible new incentives to consider.
B.8.1 Losses
ESBN believe that losses are improving however consistent reporting has been challenging. ESBN have not
applied for any rewards in relation to losses during PR3 and have not proposed a PR4 losses scheme.
Jacobs recommends that ESBN propose an outline project plan and timetable for the development of a robust
losses calculation methodology.
B.8.2 Continuity
During PR3 ESBN have, on average, met their SAIFI targets and marginally missed their SAIDI targets. Total
SAIFI has reduced by 19.3% between 2010 and 2015 (current forecast), while total SAIDI has increased by
1.3% in the same time.
ESBN has proposed adjustments to the storm threshold and per work unit allowances for planned outages in
PR4. Jacobs recommends the storm threshold remain unchanged. We believe increases in the per work unit
allowances is counter intuitive and recommend that PR4 allowances are set at 95% of PR3 allowances. There
have been a number of presentations regarding the reasons for the changes proposed by ESBN, however we
believe that the current reporting needs to be independently validated to ensure an accurate baseline, and then
the actual changes going forward due to any change in the storm threshold and unit allowance for work
programmes can be accurately tracked.
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Jacobs further recommends that planned outages are incentivised above unplanned outages. As such, we
recommend that rewards and penalties for planned outages are half that of unplanned outages. This will require
rewards and penalties to be calculated on both planned and unplanned in PR4, rather than the total sum as in
PR3.
Higher forecast work volumes in PR4 are due to increase planned outages across the network.
We agree with ESBN that the smart metering programme will lead to a large increase in planned outages.
Therefore we recommend that outages directly associated with this programme be excluded from the continuity
incentive scheme and be reported independently of other outages. This is important to safeguard the interests
and goals of the smart meter programme; most notably the quality of service and safety of installers is essential.
B.8.3 RedC
ESBN have reached the annual reward cap for each year of this incentive. We recommend the PR4 target is set
higher at 82.5%, which is approximately the average score achieved over the past five years.
B.8.4 Customer Satisfaction
ESBN have reached the annual reward cap for each year of this incentive. We recommend the PR4 target is set
higher at 89.0%, which is approximately the average score achieved over the past five years.
B.8.5 Metering
Metering targets are set at above standard levels and ESBN has been successful in achieving these throughout
PR3. We believe this incentive should endure in its current form.
B.8.6 Generation Connections
The generation connections incentive was not progressed in PR3 and ESBN has not proposed an incentive for
PR4.
We recommend that ESBN propose a new connections incentive scheme for PR4.
B.8.7 Worst Served Customers
Of the €10m fund granted to ESBN for approved worst served customer (WSC) programmes, only circa €25,000
p.a. has been spent annually. According to 2013 outturn figures, ESBN had 47,400 WSC on their network or
2.1% of total customers.
In PR4 ESBN initially proposed a €1.4m fund to alleviate 4,000 WSC from the network. We are of the opinion
that there is not enough incentive for ESBN to deliver improved service to these customers and therefore
recommend an enhanced scheme. The enhanced scheme introduces a reward and penalty payment for the
number of WSC alleviated, with payments occurring three years post-programme implementation on a NPV-
neutral basis. The payments could be capped and floored at an appropriate level to provide a disincentive to
ESBN for non-action.
B.8.8 CAPEX Delivery
The capex delivering incentive was suspended in 2013 after discussion between CER and ESBN.
ESBN has not proposed a capex delivery incentive for PR4.
B.8.9 Summary of Performance in PR3
Table B.30 provides a summary of the DSO’s PR3 performance in addition to the DSO’s proposed incentives for
PR4
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Table B.30 : Summary of PR3 Performance
Incentive Value
(€m, 2009 prices)
Incentive earned
(€m, min - max)
DSO’s proposed
incentive PR4
Losses +/- €10.5m Not claimed No proposal
Continuity +/- 1.5% of revenue CI ~€10.5m;
+/- 1.5% of revenue CML ~€10.5m €6.2m - €8.6m
+/- 1.5% of revenue CI
+/- 1.5% of revenue CML
RedC +/-€1.6m €1.6m +/- €1.6m
Customer Satisfaction +€1.6m / - €6.9m €1.6m +€1.6m / - €6.9m
Metering +/- €1m €0.5m - €0.8m +/- €1m
Generation connections Discontinued Discontinued No proposal
Worst served customer €10m fund available €25k pa claimed €1.4m fund
Capex delivery +/ - €7m - Discontinued Discontinued No proposal
B.8.10 Possible new incentives to consider
Table B.31 provides a list of possible new incentives to be considered in PR4.
Table B.31 : Possible New Incentives to Consider
Incentive Proposed incentive PR4
Connections TBA / ESBN to propose
Reporting of customer complaint
statistics Reporting requirement only – incentive mechanism to develop PR5
Vulnerable customers TBA / ESBN to propose
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Appendix C. Smart Meter Procurement
The DSO will undertake a procurement tender for smart meters in 2014/15 which will be in line with CER’s
decision on the smart metering detailed design. Therefore expected capital costs for smart metering will not be
known until 2015.
CER requires an appropriate and rigorous framework and methodology that will allow CER to assess the
following over the course of the PR4 period and future price controls:
a) capital and operational expenditure on smart metering by the DSO; and
b) the process, timing and methodology of recovery of those expenditures.
c) a review of programme expenditure and reasonable costs
In particular, CER will use the framework, and the PR4 process in general, to ensure that consumers
demonstrably gain the benefits (inter alia through DUoS charges) that the expenditures on Smart Metering will
bring to the wider operation and costs of the DSO business.
Note that expenditure on “Smart Grids” is has been addressed in the relevant business capex forecast. The
main benefit that has been incorporated into the forecasts is an assumption of peak load reduction arising from
customer behaviour changes. This assumption has the effect of reducing the peak load forecast by 4% and
consequently reducing the reinforcement expenditure that would otherwise have been initiated.
This document provides this framework.
C.1 Assumptions
At the time of writing this report the smart meter costs have not been finalised as tenders have not been
submitted. In addition revenue streams can be estimated but cannot be calculated with a high degree of
accuracy as they are inherently variable by their nature; whether it is customer take up or seasonal climatic
variations. Therefore this report will concentrate on the methodology framework of how to monitor capital and
operational costs with respect to the return on investment over the PR4 period.
The recommendations that follow are largely based upon forecast and assumptions information supplied by
CER, ESBN and PWC95 many of which are still the subject of CER decisions. Certain elements of these could
change significantly as policy decisions are formulated. CER is advised to base the templates that are issued to
the companies on the timing and programme that are agreed for use in the approved cost benefit analysis
(CBA.) The recommendations will identify the key cost components and the framework in which they can be
assessed.
C.2 Project Management Framework Methodology
The ESBN smart meter rollout is ambitious in that it has significant costs and high volume, estimated at 1.9M
electricity smart meter changes and 0.5M smart gas meter changes. As has been stated the firm capital and
revenue costs are not available at the time of writing this report. It is therefore recommended that when these
are available that there is a review the real business case and a ‘go no go’ decision by the key stakeholders is
taken. This will also be an opportunity to review the smart meter roll out timetable and revaluate whether this is
achievable bearing in mind that the resource requirement will be needed at the same time that the UK will be
also carrying out an estimated 22 million smart meter changes.
The requirement for a robust and rigorous framework for the rollout of smart metering and associated
technology would be best served by an industry standard project management system, such as Prince2, which
will give a framework that caters for all of the key elements of the ESBN smart project forecast deliverables. The
project management tool should provide a management system to capture, monitor and control the key
95 PWC report NSMP [2] (Electricity &Gas) Cost Benefit Analysis report Oct 2014
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elements of the project. The overall aim will be to minimise risk and uncertainty. We would advise that as part of
the assessment process that CER confirms that the appropriate project control structure is in planned.
C.2.1 Smart Project Streams
The ESBN commitments over the PR4 period naturally breakdown into three areas:
1. Smart Meter rollout
2. Smart Grid rollout
3. Added value benefits associated with these technologies when used in conjunction with existing business
practice and other new initiative responses by the business. This will also include the inherent benefits for
Irish energy industry. The overall benefit to the energy generation, distribution and supply industry could
then be calculated from a composite study of the three report streams.
The first area is covered in this report, point 2 is covered in the forecast capex assessment and point 3 needs to
be considered by stakeholders but will not impact DUoS.
C.2.2 Project Initiation Documents
Each of the smart projects should be recognised and broken down into their constituent parts for the evaluation
of scope, size, complexity, resources, timescales and forecast for their ability to deliver against the forecast
benefits. This should include a strong and robust business case for return on capital investment, earned value
against actual cost, cumulative savings and identify a breakeven point in time. For metering this may involve
multiple project initiation documents covering geographic areas or time based projects (e.g. Year 1 rollout)
The table below shows the scale on the proposed implementation programme and an indication of the resource
requirement. Note that the resource requirement indicated is conservative as many of the installations may be
required on evenings and weekends and therefore shift teams may be required. At present we have not been
presented with a resource plan by ESBN.
Table C.1 : Smart Meter Rollout Forecast Volumes and Resources
2017 2018 2019 2020
80% of total 1.9M 1520000 meters 10% 35% 40% 15%
Annual meter installation 152000 532000 608000 228000
Monthly meter installation (22day month) 12667 44333 50667 19000
Number of installers (assuming 4 per day/ single
working) 144 504 576 216
The resource implication should not be underestimated given that the UK is undertaking a programme ten times
the size in the same period and therefore access to appropriate staff will need to be considered in any project
initiation documents. The assumptions on labour requirements above are to indicate the scale of the project
only. The actual productivity of the installation teams should be assessed as part of the tendering process.
C.2.3 Reporting Schedule
CER require ESBN to provide robust information on the physical and financial progress of the metering
programme to justify any allowance for the expenditure. In addition CER require ESBN to identify the benefits
that are accrued to make sure that any efficiencies that cover activities that are already funded under the PR4
settlement are identified to avoid double counting of cost or benefits.
The reporting schedule needs to meet the CER’s needs as they are in a supervisory role and not a
management role and consideration of the reporting burden needs made. Therefore it is recommended that
reporting of installation progress and cost /benefit is captured on a monthly basis and summated by quarter.
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Quarterly reporting should be sufficient for the CER and the monthly granularity will enable this frequency of
reporting to be increased if required.
The proposed reporting templates are provided in Annex A-C. These provide the:
CER information requirement
Data structure to be completed
Required Narrative responses
Reporting timeframe
C.2.4 Ownership of Responsibilities
From the outset of the project clearly defined rolls, responsibilities and ownership need to be identified and
agreed between CER, ESBN, suppliers and contractors.
The CER’s role will be to allow the appropriate expenditure to ESBN to undertake the works, monitor the
performance to ensure that the programme is being undertaken efficiently and that the planned the benefits are
achieved and are passed on to customers.
ESBN will be responsible for determining the delivery method, the project management and all associated
activities in line with requirements/obligations/licence conditions as set out by CER.
This framework is intended to allow CER to have the oversight that it requires to monitor the implementation
programme and the delivery of benefits; while making sure that there is no double counting of costs/benefits
against the allowances provided for the core network activities in PR4.
C.3 Smart Meter Project Rollout
In this section we detail the aspects of capital and operating costs that we would expect to be captured to
monitor the delivery of the smart meter programme along with the expected benefits. These are intended to
provide a framework for assessing the impact on DUoS. As the metering systems will facilitate the Gas Smart
metering process then the costs need to be correctly recorded. Costs could either be recorded net of any Gas
Metering element or costs and revenues could be identified separately to allow them to be removed later. CER
indicate that the latter would be preferred as it increases transparency.
C.3.1 Smart Meter Capital and Operational Costs
This section will identify the key areas of capital and operational costs of the electricity smart meter project that
will be expected to be part of the business case and therefore monitored as part of the framework. The aim is to
provide an explanation of what would be expected in the justification documentation.
C.3.1.1 Purchase cost of electricity smart meters
The meter purchase capital cost should be recorded separately from installation as the programme may
require significant advance purchases to ensure stock is available to meet the challenging installation
programme. Alternatively a supply and install contract may be the preferred option. In this case the meter
element should be identified separately.
Any additional capital cost associated with systems to facilitate the Gas Smart metering system also need to be
captured. These are likely to be data transmitters where a single data transmitter is used to send Electricity and
Gas data. These can be separate devices or integral to the Electricity meter. An agreed cost apportionment
could be used to allocate portion of the costs to the Gas Metering system.
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C.3.1.2 Smart meter installation
The capital cost of installation is not known at this time. The Price Cooper Waterhouse (PwC) report has
offered an estimated rollout programme for smart meter installation in line with the project delivery time table.
There is a target of 80% of all smart meters to be installed by 2020. The installation schedule is: 2017 10% of
all smart meters, 2018 35%, 2019 40% and 2020 15%. This assumption may be used to forecast the delivery
schedule however ESBN should confirm prior to project commencement and this will provide the baseline for
CER to monitor progress against.
Costs of disposal of existing meters should be captured. It is not agreed if these will be treated as capital or
operating cost at this time. Normally we would expect any replacement to be wholly capital. ESBN should agree
the capitalisation policy with CER.
C.3.1.3 Communication System
The capital cost of the associated communications system should also be identified if it is separate to the Meter.
E.g telecommunications links (including GPRS charges)
C.3.1.4 Data management of smart meters
This should incorporate capital and operational costs of back office IT operations related to: migration from
the existing systems, data storage, data security availability and integrity, web portal, and customer service
integration for enquires and changes.
C.3.1.5 Electricity meter customer service interface
Capital and operational costs of dealing with the telephone and online customer enquiries and complaints (do
not include costs for the IT systems in C.3.1.3 above.
C.3.1.6 Smart meter repairs and maintenance
Repairs and maintenance operational cost associated with identification and rectification of faults on the
metering systems. We would expect replacement of faulty meters to be an operational costs in line with existing
repairs and maintenance practice. However an argument can be made for capital replacement if the whole unit
is replaced. ESBN will need to be clear in the treatment of any capital repairs.
C.3.1.7 Energy consumption by smart meters
Energy associated with the internal power requirement of the metering device. This will not be able to be
individually measured and will in practice present as system loss. However the choice of meter will drive the
energy consumption and so a typical value based on the technical specification should be recorded – this is
effectively an Operational cost. This will be based on the technical specification value and the volumes
installed.
C.3.1.8 Smart meters manual reads
This captures operational cost associated with maintaining a manual read for smart meters that are located
where there is no mobile network coverage and will therefore have to be provisioned for by traditional meter
reading visits. Note that this will be used to gauge the number of sites impacted. It would be expected that
reduction in meter read costs are a benefit arising from the smart meter programme and as we would expect
such benefit to be apportioned based on the roll out of the programme then any cost assorted with meters that
do not give the expected benefit should be captured here. If the benefits are only claimed based on actual
manual reads avoided then no additional cost is required to be monitored here. ESBN will be required to
demonstrate that residual manual reads are undertaken efficiently. It is understood that there are economies of
scale in manual meter reading however, we would expect manual reads to be required in clusters due to lack of
communication coverage which should limit the impact therefore the base efficient level will be the current cost
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on manual reads to incentivise ESBN to avoid leaving isolated individual properties. ESBN will be required to
justify any deviation from the current manual meter reads unit cost.
C.3.2 Smart Meter Savings and Benefits
This section will identify the kind of key savings of the electricity smart meter project that will be monitored. All
the values will need to be identified by ESBN as part of the project reporting.
C.3.2.1 Avoided meter readings (pavement reading)
Operational Cost saving based on manual visits no longer being required to read all customer energy meters.
The costs should accurately reflect the reduction in manual read costs. If average costs per meter installed are
used then costs of reading non- networked meters will need to be included in operational costs as in C.3.1.7
above.
C.3.2.2 Meter change deferral for 15 years
Capital Expenditure saving associated with the standard end of life change of old meters this should reflect
historic programme expenditure costs that would have been incurred. This is captured as an avoided future cost
which will be relevant for meters that would have been due for replacement soon after the smart meter roll out
however there is also an NPV cost of replacing the existing meters before the end of life which should be
factored into any business case. This can be minimised by replacing older meters earlier in the programme
subject to compliance with the overall rollout programme requirement.
C.3.2.3 Meter Fault savings
Operational Expenditure saving due to reduced fault costs due to new meters. This should be based on the
average R&M cost per meter. The costs of R&M on new meters is captured as per C.3.1.5 above.
C.3.2.4 Disconnections and reconnections
Operational savings as smart meters have the capability of be remotely switched on or off. These savings will
need to be supported by reference to the actual Disconnection/Re-connection instruction sent and evidenced by
the average cost of historic practice.
C.3.2.5 Voltage complaints
Operational saving as Smart meters monitor system voltage which can be remotely monitored and recorded.
Normally a voltage recorder would have to be installed to verify customer complaints. These savings will need to
be supported by reference to actual voltage complaints managed using smart meter data and the average cost
of traditional voltage recording less the cost of accessing the smart meter data. ESBN will be required to adjust
any direct charges to customers (where applicable) to reflect the reduced costs.
C.3.2.6 Prepayment meters
Operational saving as simplified prepayment debit arrangements will be available for customers without having
to install a separate meters. ESBN should be able to identify the prepayment meter arrangements implemented
through Smart meters and identify the historic cost of providing the same service.
C.3.2.7 Avoided theft
Operational savings as smart meters have more security features than traditional meters and should therefore
reduce theft. Identification of actual savings will difficult as a significant amount of theft is not detected therefore
the only savings that should be documented are the reductions against current monthly averages. It should be
noted that a whole system roll out will, by necessity, include visits to each premises which may identify
additional tampering. Estimates based on any theft identified during the installation process should also be
included.
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C.3.2.8 Reduced Network Investment cost
Impact of enhanced information
Smart meters can provide accurate feeder loading data so that networks can be designed so as to avoid or
defer asset reinforcement. ESBN may be able to identify planned projects that can be deferred due to more
detailed load information. e.g. load profiles of standby feeders with different peak times allowing assessment of
n-1 capability on a time of day basis. Capital expenditure savings should only include the net present value
(NPV) of any deferral.
Impact of demand reduction
Demand Side Response and ‘Time of use’ tariffs which are predominantly used to reduce peak loads and
reduce overall generation costs will have an impact on distribution systems. However, this will be very
dependent on the actual network. Savings will only be made if load related investment was imminent on a
particular part of the network and some deferral can be attributed to consumer led demand reduction. Any
capital expenditure savings will need to demonstrate that the demand reduction or peak shift is not due to
other economic factors and only include the NPV or any deferral. We note that in ESBN’s PR4 submission an
assumption of 4% load reduction due to smart metering has been made and this has led to an investment plan
being put forward based on a 0% load growth scenario. This assumption effectively obscures specific project
cost benefits and therefore to fully support a business benefit assessment ESBN would be required to provide a
counterfactual investment requirement based on no load reduction from Smart Metering.
Post implementation the 4% demand reduction assumption should be tested using a sample set of customers to
isolate the smart metering impact from general growth. This should be achievable as through the
implementation programme there will be groups of customers with and with-out smart meters, therefore the non-
smart meter demand effects can be isolated by comparing load to pre-smart meter programme levels.
C.3.2.9 Fault management benefits
Smart meters could allow identification of customers who have lost supply without customers having to make
contact with the company. This should provide benefits in fault identification and understanding of the extent of
overhead system faults; which will mean that the correct staff can be dispatched in the first instance and thus
reduce cost and duration of interruptions. This will have an operating cost reduction and SAIDI reduction.
C.3.3 Benefits to the Irish Energy Industry
In addition to the above benefits there are wider benefits to the Irish energy generators, suppliers and
customers that may be considered but will not directly impact ESBN and so will not impact DUoS.
C.4 Recovery of expenditures
As a capital programme with consequent operational costs and benefits, we would expect the DSO net Capex
and net Opex derived from the agreed Smart Metering business case to be added to the allowed PR4
revenues. This will mean that the required efficient capex/opex expenditure would be allowed but any displaced
costs that are already included in PR4 allowance will be reduced accordingly. This will remove any double
allowance.
As some of the installation and operational costs of the electricity meters will facilitate the Gas Smart Metering
system then we would expect there to be a revenue stream from the gas businesses that will offset the costs
associated with this facilitation.
We would expect expenditure on the metering installation programme and associated communication system to
be recovered as a capital addition to the regulatory asset base. We note that in PR3 smart meters were allowed
to be allocated to a separate depreciation pot with a depreciation period of 10 years while standard meters are
included in the Network Asset base at 45 years depreciation. There are also separate depreciation lives for IT
and communication assets that are appropriate for the systems to support the smart meters.
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Clearly the technical asset life of the smart meter equipment is less that the average deprecation life assigned
to distribution assets. However, the new meters replace existing meters with generally similar asset life
expectancy and so it could be argued that they could be included in the network asset base.
We provide recommendations on the appropriate technical life of assets and the impact on the regulated
deprecation period in Interim Report 8/9 – ‘Depreciation of RAB’ however the impact of the smoothing of the
costs is not discussed. With a separate depreciation pot the full impact of the smart meter programme is funded
by customers over a relatively short period. This has not been the case with conventional metering. The 45
year depreciation period (based on a weighted asset base life) smooths the costs to customers and inclusion of
the metering assets does not significantly affect the weighted asset base life; certainly not to the extent that the
weighted life approaches the 45 depreciation period. Thus including smart meters in the general network asset
base may provide a way of smoothing the up-front cost of the programme to customers.
This should therefore be considered as an option in any consultation.
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ANNEX A: Smart Metering Reporting Framework
Project management of the Smart Meter rollout should incorporate rigorous monitoring and control of the smart
meter installation and the associated capital and operating costs over the PR4 period and future price controls
including tracking of benefits to allow validation of the business case.
Below we present the recommended reporting framework templates for monitoring the installation programme,
implementation costs and accrued DUoS impacting benefits.
Smart Meter Cost Allowance
The expenditure allowance will require a detailed submission of costs proposed costs and benefits. The
definitions are detailed in Annex B. In addition, the cost submission should be accompanied by a detailed
business case and responses to the relevant narrative questions in Annex C.
Table C.2 : Smart Metering Cost Submission
Cost Reporting Area 2016 €m 2017 €m 2018 €m 2019 €m 2020 €m
Smart meter purchase cost (Capex)
Smart meter installation (Capex)
Communication System (Capex)
Communication System (Opex)
Data management (Capex)
Data management (Opex)
Customer contact centre (Capex)
Customer contact centre (Opex)
Faulty meter (Capex)
Faulty meter (Opex)
Smart meter energy cost (Opex)
Smart meter manual Reads (Opex)
Other (Capex)*
Other (Opex)*
Table C.3 : Gas Metering Facilitation
Cost Reporting Area 2016 €m 2017 €m 2018 €m 2019 €m 2020 €m
Costs for Gas metering facilitation
(Capex)
Costs for Gas metering facilitation
(Opex)
Revenue for Gas metering
facilitation
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Table C.4 : Smart Metering Benefits Submission
Cost Reporting Area 2016 €m 2017 €m 2018 €m 2019 €m 2020 €m
Meter reading (Opex)
Meter change deferral (Capex)
Meter R&M (Opex)
Dis/reconnection (Opex)
Voltage Complaint (Opex)
Prepayment Meter (Capex)
Prepayment Meter (Opex)
Theft Reduction (Opex)
Network Investment (Capex)
Fault management (Opex)
Other (Capex)*
Other (Opex)*
The efficient net Capex and Opex arising from this submission will be agreed and added to the RP4 allowances.
The Smart Meter Rollout
From a regulatory perspective quarterly update reports and an annual substantive report on implementation
progress would be recommended. The quarterly reports would give a brief explanation of any deviations for the
years plan and identify recovery actions being undertaken with an annual submission providing detailed review
of programme and unit costs with any unit cost or programme deviations explained along with any effect of the
current year’s performance on future delivery. The annual report should also provide the targets that the follow
year will be monitored against and the revised overall programme for implementation and benefit realisation
with reference back to the original Project Initiation Document business case.
The quarterly and annual report should be captured in the format below to enable CER to assess the
programme and financial progress.
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Table C.5 : ESBN Smart Meter 2017 Rollout Project Performance
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Forecast installation No.
for the month 12667 12667 12667 12667 12667 12667 12667 12667 12667 12667 12667 12667
Actual installation No. for
that month
Variance
Cumulative total No.
behind forecast
Planned Cost (Capex)
Actual Cost (Capex)
Planned Cost (Opex)
Actual Cost (Opex)
Planned Benefit (Capex)
Actual Benefit (Capex)
Planned Benefit (Opex)
Actual Benefit (Opex)
Planned Net Capex
Actual Net Opex
Planned Net Opex
Actual Net Opex
When measuring variance a RAG Red Amber Green project indicator system should be used. Green on track,
Amber <10% of forecast and Red <20% of forecast
To allow full reference back to the business case the figures in the summary sheets should be derived from
detail sheets that align to the specific cost and benefit areas as presented in Table C.5 and Table C.6 below.
Smart Meter Capital and Operating Costs
The tables below provide the supporting reporting framework where monthly and cumulative costs can be
tracked. These should be accompanied by a narrative as described in Annex C.
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Table C.5 : ESBN Smart Meter Capital and Operational Expenditure Forecast and Actual
Cost Reporting Area Month 1
Actual
Month 2
Actual
Month 3
Actual
Quarterly
Actual
Quarter
Planned
Quarter
Variance
Smart meter purchase cost (Capex)
Smart meter installation (Capex)
Communication System (Capex)
Communication System (Opex)
Data management (Capex)
Data management (Opex)
Customer contact centre (Capex)
Customer contact centre (Opex)
Faulty meter (Capex)
Faulty meter (Opex)
Smart meter energy cost (Opex)
Smart meter manual Reads (Opex)
Other (Capex)*
Other (Opex)*
*any reported costs under ‘Other’ will need a detailed explanation
Any costs and revenues associated with Gas Smart Meter facilitation can be captured in the table below if
required however these will be dependent on the overall programme and could therefore just be determined
based on the proportion of the total system costs in Table C.5 above.
Table C.6 : ESBN Gas Smart Meter facilitation cost and revenue
Cost Reporting Area Month 1
Actual
Month 2
Actual
Month 3
Actual
Quarterly
Actual
Quarter
Planned
Quarter
Variance
Costs for Gas metering facilitation
(Capex)
Costs for Gas metering facilitation
(Opex)
Revenue for Gas metering facilitation
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ESBN Smart Meter Savings and Benefits
Table C.7 : ESBN Savings and Benefits Forecast and Actual
Cost Reporting Area Month 1
Actual
Month 2
Actual
Month 3
Actual
Quarterly
Actual
Quarter
Planned
Quarter
Variance
Meter reading (Opex)
Meter change deferral (Capex)
Meter R&M (Opex)
Dis/reconnection (Opex)
Voltage Complaint (Opex)
Prepayment Meter (Capex)
Prepayment Meter (Opex)
Theft Reduction (Opex)
Network Investment (Capex)
Fault management (Opex)
Other (Capex)*
Other (Opex)*
*any reported costs under ‘Other’ will need a detailed explanation
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ANNEX B: Smart Metering Framework – Cost Definitions
Cost/Benefit Explanatory Note
Purchase cost of
electricity smart meters
The meter purchase capital cost is recorded separately from installation as the
programme may require significant advance purchases to ensure stock is
available to meet the challenging installation programme. Alternatively a supply
and install contract may be the preferred option. In this case the meter element
should be identified separately.
Smart meter installation The capital cost of installation including the associated communications
systems.
Costs of disposal of existing meters as part of the installation should be captured.
Communication Costs The capital cost and operational costs of the associated communications
system if it is separate to the Meter. E.g telecommunications links (including
GPRS charges)
Data management of
smart meters
This should incorporate capital and operational costs of back office IT
operations related to: migration from the existing systems, data storage, data
security availability and integrity, telecommunications links (including GPRS
charges), web portal, and customer service integration for enquires and changes.
Electricity meter
customer service
interface
Capital and operational costs of dealing with the telephone and online customer
enquiries and complaints (do not include costs for the IT systems in C.3.1.3
above.
Smart meter repairs and
maintenance
Repairs and maintenance operational cost associated with identification and
rectification of faults on the metering systems. We would expect replacement of
faulty meters to be an operational costs in line with existing repairs and
maintenance practice. However an argument can be made for capital
replacement if the whole unit is replaced. ESBN will need to be clear in the
treatment of any capital repairs.
Energy consumption by
smart meters
Energy associated with the internal power requirement of the metering device.
This will not be able to be individually measured and will in practice present as
system loss. However the choice of meter will drive the energy consumption and
so a typical value based on the technical specification should be recorded – this is
effectively an Operational cost. This will be based on the technical specification
value and the volumes installed. An alternative to monthly reporting could just be
notification of the ‘per Meter’ value to the CER.
Smart meters manual
reads
This captures operational cost associated with maintaining a manual read for
smart meters that are located where there is no mobile network coverage and will
therefore have to be provisioned for by traditional meter reading visits. Note that
this will be used to gauge the number of sites impacted. It would be expected that
reduction in meter read costs are a benefit arising from the smart meter
programme and as we would expect such benefit to be apportioned based on the
roll out of the programme then any cost assorted with meters that do not give the
expected benefit should be captured here. If the benefits are only claimed based
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Cost/Benefit Explanatory Note
on actual manual reads avoided then no additional cost is required to be
monitored here. ESBN will be required to demonstrate that residual manual reads
are undertaken efficiently. It is understood that there are economies of scale in
manual meter reading however, we would expect manual reads to be required in
clusters due to lack of communication coverage which should limit the impact
therefore the base efficient level will be the current cost on manual reads to
incentivise ESBN to avoid leaving isolated individual properties. ESBN will be
required to justify any deviation from the current manual meter reads cost.
Avoided meter readings
(pavement reading)
Operational Cost saving based on manual visits no longer being required to read
all customer energy meters. The costs should accurately reflect the reduction in
manual read costs. If average costs per meter installed are used then costs of
reading non- networked meters will need to be included in operational costs of
manual reads above.
Meter change deferral
for 15 years
Capital Expenditure saving associated with the standard end of life change of
old meters this should reflect historic programme expenditure costs that would
have been incurred. This is captured as an avoided future cost which will be
relevant for meters that would have been due for replacement soon after the
smart meter roll out (ESBN should state if these costs are included in the PR4
expenditure forecast) however there is also an NPV cost of replacing the existing
meters before the end of life which should be factored into any business case.
This can be minimised by replacing older meters earlier in the programme.
Meter Fault savings Operational Expenditure saving due to removed fault costs of old meters. This
should be based on the average R&M cost per meter. The costs of R&M on new
smart meters are captured separately. ESBN should indicate if these costs are
included in the Operational Cost submission in PR4.
Disconnections and
reconnections
Operational savings as smart meters have the capability of be remotely
switched on or off. These savings will need to be supported by reference to the
actual Disconnection/Re-connection instruction sent and evidenced by the
average cost of historic practice.
Voltage complaints Operational saving as Smart meters monitor system voltage which can be
remotely monitored and recorded. Normally a voltage recorder would have to be
installed to verify customer complaints. These savings will need to be supported
by reference to actual voltage complaints managed using smart meter data and
the average cost of traditional voltage recording less the cost of accessing the
smart meter data. ESBN will be required to adjust any direct charges to
customers (where applicable) to reflect the reduced costs.
Prepayment meters Operational saving as simplified prepayment debit arrangements will be
available for customers without having to install a separate meters. ESBN should
be able to identify the prepayment meter arrangements implemented through
Smart meters and identify the historic cost of providing the same service.
Avoided theft Operational savings as smart meters have more security features than
traditional meters and should therefore reduce theft. Identification of actual
savings will difficult as a significant amount of theft is not detected therefore the
only savings that should be documented are the reductions against current
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Cost/Benefit Explanatory Note
monthly averages. It should be noted that a whole system roll out will, by
necessity, include visits to each premises which may identify additional
tampering. Estimates based on any theft identified during the installation process
should also be included.
Impact of enhanced
information
Smart meters can provide accurate feeder loading data so that networks can be
designed so as to avoid or defer asset reinforcement. ESBN may be able to
identify planned projects that can be deferred due to more detailed load
information. e.g. load profiles of standby feeders with different peak times
allowing assessment of n-1 capability on a time of day basis. Capital
expenditure savings should only include the net present value (NPV) of any
deferral.
Impact of demand
reduction
Demand Side Response and ‘Time of use’ tariffs which are predominantly used to
reduce peak loads and reduce overall generation costs will have an impact on
distribution systems. However, this will be very dependent on the actual network.
Savings will only be made if load related investment was imminent on a particular
part of the network and some deferral can be attributed to consumer led demand
reduction. Any capital expenditure savings will need to demonstrate that the
demand reduction or peak shift is not due to other economic factors and only
include the NPV or any deferral.
We note that in ESBN’s PR4 submission and assumption of 4% load reduction
due to smart metering have been made and this has led to an investment plan
being put forward based on a 0% load growth scenario. To fully support a
business benefit assessment ESBN would be required to provide a counterfactual
investment requirement based on no load reduction from Smart Metering.
Fault management
benefits
Smart meters could allow identification of customers who have lost supply without
customers having to make contact with the company. This should provide benefits
in fault identification and understanding of the extent of overhead system faults;
which will mean that the correct staff can be dispatched in the first instance and
thus reduce cost and duration of interruptions. This will have an operating cost
reduction and SAIDI reduction
Costs for Gas metering
facilitation
The capital cost and operational costs of any aspect of the metering system
that is used to facilitate a Gas Smart Metering system. If these are associated
with a system element (E.g. meter or data transmitter) of the metering system that
cannot be physically identified as solely for the facilitation of Gas Smart Metering
then then the costs should be the agreed apportionment of the shared element.
Revenue for Gas
metering facilitation
Any revenues received from Gas distribution or Supply businesses for the
provision of hardware or maintenance and management services that facilitate
the Gas Smart Metering system/
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ANNEX C: Smart Metering Framework – Narrative Response
Information Narrative Response Response
Required
Project Initiation
Document
Explain the derivation of the monthly programme (quarterly and
annual totals) for the PR4 period
Method of determining resourcing plan; explain the use of existing
metering staff (Management and Field) in the resourcing of the
smart grid programme and how the costs for these staff were
include in the RP4 submission
Method of determining Target unit cost.
Provide Detailed cost benefit factoring all relevant operating and
capex costs and benefits. Use categories identified in this
framework (and referenced as Project Initiation below) – if they
are not applicable for any reason state the reason. If additional
cost or benefits are identified that are relevant to the DSO these
should be explained and the method of recording them detailed.
Project Initiation
Smart meter
installation
Explain the proposed installation mechanism (Direct
labour/Contract or mix) and the reasons for the choice.
Project initiation
(plus 1/4ly or
annual if delivery
mechanism
changes)
Purchase cost of
electricity smart
meters
Explain how the purchase of smart meters will be managed and
accounted for. E.g. are cost recorded as stock is procured or as
they are installed? Are meters to be procured by the chosen
installer if this is contracted resource?
Project initiation
(plus 1/4ly or
annual if delivery
mechanism
changes)
Communication
costs
Explain which cost elements are included as Communication cost
as distinct from the Smart meter and Data management..
Project initiation
(plus 1/4ly or
annual if delivery
mechanism
changes)
Gas Smart Meter
Facilitation
Explain which cost elements are included as Gas Smart Meter
facilitation and whether the costs in other expenditure lines are net
or gross of these costs. Also explain how the agreed revenue
payments are calculated.
Project initiation
(plus 1/4ly or
annual if delivery
mechanism
changes)
Data management
of smart meters
Explain which cost elements are included in the installed meter
cost and which will be separate costs.
Project initiation
(plus 1/4ly or
annual if delivery
mechanism
changes)
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Information Narrative Response Response
Required
Smart meter
repairs and
maintenance
Explain how smart meter R&M is separately identified and whether
such costs are treated as opex or capex (if the meter is replaced)
Project initiation
Energy
consumption by
smart meters
State the designed internal energy usage of the chosen meter type
and the anticipated annual total kwh consumption based on the
target installation plan.
Project initiation
plus annual
summary based
on actual
installed
programme.
Avoided meter
readings
(pavement reading)
Explain how the costs of the retained manual reads are calculated
and what overheads are included. Demonstrate that the overhead
is not included in the costs attributed to the smart meter
installation.
Project initiation
plus annual
summary report
Meter change
deferral for 15
years
Explain how ESB will calculate the benefit of avoiding the
replacement cost of the existing meter asset base and if the
programme will take account of the age of existing meters.
Project initiation
Disconnections
and reconnections
Provide the unit costs for existing Disconnection/Re-connection
activities.
Project initiation
Voltage complaints Provide an explanation of the average unit cost of undertaking the
data recording required to assess a voltage complaints that can be
obviated through interrogation of the smart meter
Project initiation
Prepayment meters Explain if prepayment smart meters will be used and how the any
operational savings will be realised.
Project initiation
Avoided theft Explain the number of meter tampering incidences identified
during the implementation programme and the estimate of theft
avoided.
1/4ly report
Impact on delivery
programme
Explain reasons for deviation from the planned programme and
unit cost
1/4ly report
Impact on delivery
programme
Explain reasons for deviation from the planned programme and
unit cost and impact on future programme. Reference impact on
initial business case.
Annual report
Impact of demand
reduction
Provide a sample group that can be monitored for load reduction
estimates comparing annual consumption through the programme.
The group should include customers that will not be changed until
late in the programme to isolate any non-smart meter effects
Annual report
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Appendix D. Asset Lives & Depreciation
As part of the PR4 support CER required Jacobs to:
advise on the efficient level and method of depreciation of assets in the RAB, and
to assess the appropriate depreciation level and methodology and useful asset life for:
- smart grid; and
- smart metering assets; and
to advise whether a different approach should be taken to other RAB assets.
This report provides a review of the current average regulatory 45 and 50 year asset lives of distribution and
transmission assets with regard to the requirements above.
A key building block in determining business revenue is depreciation. In the regulatory context depreciation is
used as a form of revenue profiling that reflects the way future revenue streams are profiled. The aggregate
depreciation charge for an asset is the initial capital cost of the asset, in real terms. So the choice of approach
to depreciation does not affect the total revenue raised to cover the cost of the asset, only the extent to which
the burden of the cost of the asset is borne by today’s consumersversus future consumers. One way of setting
an appropriate depreciation profile is to set charges to customers reflecting the long run incremental cost of their
use of the asset. In this way depreciation measures the reduction in the value of an asset as a result its use.
Therefore an important concept is to determine the ‘useful’ life of an asset given that a depreciation profile could
be set to allocate an asset’s cost over its useful economic life. In regulatory terms the aim is to allocate an
asset’s cost in a way that reflects the pattern its economic benefits are consumed in generating revenues. In
this way, the accruals or ‘matching’ concept is followed, whereby revenues are matched to the expenses
incurred in generating them. The allocation of this asset cost is depreciation and the purpose of calculating
depreciation is to build up funds for the replacement of assets or to recover the original investment.
An amount for depreciation of the regulatory asset base (RAB) is included within the revenue allowance for
network operators, calculated over the average assumed useful lives of the relevant assets. In Ireland the CER
PR2 decision papers increased average transmission asset lives from 40 to 50 years and distribution from 40 to
45 years. Under the existing price control the CER reiterated these asset lives. CER has also reiterated its
view that depreciation of the transmission and distribution RABs should reflect the cost of using the assets
during the period. CER documentation (CER 05/143 and CER 05/138) also stated that the depreciation method
should reflect, as fairly as possible, the pattern in which an asset’s economic benefits are consumed.
D.1 Asset lives
D.1.1 Defining asset lives
There are a number of different ways of defining the life of a network asset, in particular:
Design life
Technical life
Economic life
Each asset has a design life which is the period of time during which it is expected by its designers to work
within its specified parameters; in other words, the life expectancy of the asset. The ‘technical’ life is the
expected life of an asset from commissioning until it falls below minimum technical and/or safety performance
level. The economic life of an asset is the period of time over which it is expected to be actively used on the
network.
Through good maintenance and management, the technical life of an asset may exceed its design life. On the
other hand an asset’s economic life cannot exceed its technical life. However, depending on the pattern of
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usage of the asset, its economic life may be shorter than its technical life. Therefore the pattern of usage of an
asset is fundamental to determining its economically useful life and the most appropriate depreciation profile. In
simple terms an asset can be in excellent condition, but if it no longer performs any useful function, it has
reached the end of its economic life.
D.1.2 Experience in Great Britain
In the earlier stages of market deregulation (pioneered in GB) the asset lives assumed for networks were
relatively short (in the order of 20 years) – partly based on the need to ensure privatisation was an attractive
option for investors, also on the then age profile of the network asset base and the perceived ‘financeability’
issues of the industry. Over time the economic life of network assets has been seen to increase as longer term
regulatory perspectives are introduced and the experience of efficient network operators increases. Overall
network operators have found that much equipment, when properly specified, installed and maintained will last
longer than had previously been assumed. Performance of older assets is generally adequate, not least due to
the modest pace of technological advance in electricity networks, and the risks of purely age related failure are
considered to be low. In addition, condition monitoring has replaced age-based techniques in determining
effective asset lifetimes.
Work undertaken for Ofgem96
assessed the existing asset base of the GB electricity network and the technical
life of each asset class within the network. A single weighted technical life was determined using Modern
Equivalent Asset Value (MEAV) as the weighting. The results for electricity transmission and distribution are
shown in Table D.1, with the weighted technical life of a transmission asset 54-60 years and 60-75 years for
distribution.
Table D.1 : Summary of Asset Lives
Accounting life Technical Life
Transmission 10-80 54-60
Distribution 2-100 60-75
The study then considered the economic life of these assets – based on their expected future usefulness.
Given that the energy market is challenged by significant change driven largely by renewable and carbon
targets and aspirations, scenario modelling was undertaken to assess the impact of asset lives of a number of
key drivers. Some of the key events that influenced the scenarios and resulting analysis are shown below in
Table D.2.
Table D.2 : Asset Life Influencing Factors
Event Impact on Average Asset
Life
Rationale
Smart Grids / Information
Technology
Decrease Information Technology tends to have a short asset live.
Unlikely to be material.
New Technology Unclear The impact could go in either direction depending on the cost
benefit analysis associated with the new approach /
technology
Increase in Cost of Raw
Materials
Increase More expensive assets could justify increased maintenance
to extend the technical life or change the cost benefit
analysis underlying health and safety limits on asset lives
Policy Decisions Decrease Government decisions on decarbonisation could lead to a
wholesale change in approach or technology beyond that
suggested by a simple cost benefit analysis. Shifting
96 https://www.ofgem.gov.uk/ofgem-publications/48276/cepa-econ-lives.pdf
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Event Impact on Average Asset
Life
Rationale
between gas and electricity based space heating would be
an example that could have a significant impact on asset
lives.
Four scenarios exploring the use of the electricity network to 2050 were developed. The scenarios highlighted
some uncertainties that could either increase or decrease the economic lives of assets. The uncertainties
include the impact from technological changes with the move to a smarter grid, increases in raw material prices
and policy decisions by government affecting the speed of change. The analysis undertaken for Ofgem
concluded that, under all future scenarios evaluated, long term electricity demand grows significantly as the
economy moves to a lower carbon base, but that the pattern of use may change. The study proposed a
conservative approach to economic asset lives, with economic asset lives significantly below average technical
lives and recommended a range of 45-55 years.
Ofgem also noted that network operators currently use an expected useful economic life for their network assets
as part of their depreciation accounting policy disclosed in their statutory and regulatory accounts. Table D.3
shows that the proposed asset lives fit within the envelope used by the DNOs own accounting asset lives97.
Table D.3 : GB DNO Accounting Lives
Electricity Distribution Network Asset Type Accounting
Useful
economic Life
(Years)
CE Northern Electric DL and Yorkshire
Electricity DL
Distribution System Assets
Information Technology
45
Up to 10
Central Networks East and Central
Networks East
Distribution Network Assets 40 - 70
EDFE EPN, EDFE LPN and EDFE SPN Overhead and Underground Lines
Other Network Plant and Buildings
45 – 60
20 – 60
Electricity North West Infrastructure Assets 5 – 80
SP Distribution and SP Manweb Distribution Plant
Towers, Lines and Underground Cables
30 – 40
40 – 60
SSE Hydro Distribution Assets 10 – 40
SSE Southern Distribution Assets 10 – 80
WPD S Wales and WPD S West Overhead Lines and Poles
Underground Cables
Transformers and Switchgear
Towers and Substations
45
60
45
Up to 55
The move to a longer term view of network assets in GB is also based on the RIIO (Revenue = Incentives +
Innovation + Outputs) regulation model where the assumed depreciation lifetime better reflects likely useful
economic life. However, Ofgem also notes that the longer useful life of the assets needs to be balanced with
the cashflow requirements of the companies as longer depreciation lifetimes implies slower recovery of capital
costs. The result was that Ofgem subsequently increased the economic life of new electricity network assets
from 20 to 45 years despite their longer technical lives.
97 file:///C:/Users/lwoolhouse/Documents/CER%20Depreciation/ed-asset-lives-consultation-21000114.pdf
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D.1.3 Experience in other countries
The approach to network asset lives in other countries varies – with relatively few adopting an ‘average’ asset
life. For example:
In the Netherlands each asset type is allocated a depreciation life ranging from 5-50 years and straight line
depreciation is used.
In Norway depreciation is determined by assuming a linear profile over 30 years98
.
In Germany transmission and distribution asset lives range from 25 to 50 years99.
In Australia 35 to 51 years is used as a range for distribution assets100.
Few countries employ an ‘average’ asset life for the entire asset base, with most adopting individual asset lives
for each asset class.
A report undertaken by EURELECTRIC expert Task Force ‘DSO Investment Action Plan’ reviewed the impact of
current European regulatory frameworks on investments in the distribution network. It concluded that European
electricity network operators have to cope with demanding investment requirements driven by three main
factors:
The need to integrate renewable energy sources into the electricity system
The need to replace existing assets in order to ensure continued quality of supply, and
The development of smart grids.
The report concluded that regulated rate of return should be set in a forward-looking way and be consistent with
the long lifetime of distribution assets. The risk-free rate and debt premium should reflect the typical network
asset lifetime of 30 to 55 years101.
While the technical life of network assets has risen, the age profile of the network asset base across Europe
also indicates that additional investment will be required, not only to replace aging assets, but also to adapt to
the challenges of accommodating increasing volumes of renewable generation and smarter grids. The result
will be some uncertainty, particularly vis-à-vis asset lives and asset ‘usefulness’ as patterns of useage change.
Uncertainty surrounds the future rate of asset replacement and also the rate of investment required to
accommodate increasing renewables and smarter grids, and although it appears that overall electricity networks
will continue to be well utilised as we move towards a lower carbon future – the patterns of use is likely to
change.
Significant investment in new network assets also raises issues of intergeneration equity – assuming relatively
short assets lives may unfairly bias the allocation of costs to current consumers and is not appropriate if the
assets are expected to have a longer useful life. On the other hand, while older assets have been shown to
have a technical longer life than initially assumed, some new technologies, such as plastic cables, may have
shorter lives than older technologies, such as paper lead cables. In Ireland this is particularly relevant given the
large growth in network assets over the past 20 years using newer technologies. In addition some technologies
associated with the move to ‘smarter grids’ may have shorter asset lives that will influence the overall age of the
asset base.
We can conclude that, for regulatory purposes, it appears unlikely that the average depreciation life of the asset
base will extend to the length of the average technical life, despite the regulatory trend for adopting asset lives
that more accurately reflects their useful lives. Uncertainty over the pattern of network use, despite increasing
electricity demand and the addition of shorter lived assets into the asset base will result in the economic life of
assets reflecting a more cautionary timescale.
98 Trends in electricity distribution network regulation in North West Europe. A report for Energy Norway, August 2012 99 Issue Paper: Determination of the Regulatory Asset Base after Revaluation of License Holder’s Assets. Chart of Accounts, Energy Regulators
Regional Association, 2009 100 https://www.ofgem.gov.uk/ofgem-publications/50643/ed-asset-lives-consultation-21000114.pdf 101 http://www.eurelectric.org/media/131742/dso_investment_final-2014-030-0328-01-e.pdf
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D.2 Determining the Asset Lives and Depreciation for PR4
In Ireland the CER PR2 decision papers increased average transmission asset lives from 40 to 50 years and
distribution from 40 to 45 years. Under the existing price control the CER reiterated these average asset lives
of 50 years for transmission and 45 years for distribution network assets. The CER decision to increase asset
lives was based largely on the structure of the RAB at that time, i.e. that is predominantly made up of
switchgear, transformers and overhead lines and the experience of network operators that showed equipment
that has been correctly specified, installed and maintained will last longer than had been previously assumed.
In order to determine the appropriate asset lives to be used in PR4 we have evaluated the asset base of the
DSO and TAO and determined a single weighted technical life for each using MEAV as the weighting. Our
analysis replicates that undertaken for Ofgem in 2010 to determine the weighted average technical life of the
asset base. We also consider factors that will influence the future useage of the network and changes to the
asset base in order to determine an appropriate economic life (and therefore depreciation life) of distribution and
transmission assets that can be applied in PR4.
D.2.1 DSO
The depreciation life of the distribution asset base in Ireland is influenced by the structure of the asset base.
Figure D.1 and Figure D.2 below show the configuration of the DSO RAB in 2006 and 2013 based on
determination of the MEAV102.
Figure D.1 : Composition of DSO Network RAB in 2006 (MEAV Basis)
102 Based on unit costs used in PR3 together with Jacob’s analysis where unit costs not available
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Figure D.2 : Composition of DSO Network RAB in 2013 (MEAV Basis)
The charts show that the DSO RAB is dominated by underground cables and overhead lines (accounting for 69-
70%). Changes in the network environment in Ireland, including greater urbanisation and a move against
overhead line construction, have led to an increasing proportion of underground cables within the asset base –
with the proportion of underground cabling growing since 2006 from 41% to 44%.
Table D.4 shows the asset lives outlined in PR2. These asset lives are based on UK power industry average
weighted asset lives for each asset class. Based on these asset lives CER concluded that the existing policy of
depreciating DSO network assets over an average 40 year life should be modified. Of particular relevance to
ESBN is the predominance of relatively long lived underground cables in the asset base with expected asset
lives ranging from 71-94 years.
Table D.4 : UK Network Asset Lives
Asset Category Technical Life
PR2
Overhead lines Low Voltage 52
Overhead Lines Medium Voltage 43
Overhead Lines High Voltage 46
Overhead lines EHV 67
Underground cables LV 92
Underground cables MV 94
Underground cables HV 71
Switchgear LV 73
Switchgear HV 47
Switchgear EHV 52
Transformers 56
However, as outlined above, the asset life assessment outlined in PR2 was based on UK assets. Figure D.3
shows the relative replacement costs of the distribution and transmission networks in the UK and clearly shows
that the peak of electrification activity was undertaken in the 1950s and 1960s – and therefore the relatively high
age of the UK’s network asset base.
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Figure D.3 : Age and Replacement MEAV of UK Electricity Network103
In Ireland the age profile of the asset base is different, with a far greater proportion of investment undertaken
after 1995 – as shown in Figure D.4 – with a consequently younger asset base.
103 Consultation on strategy for the next transmission and gas distribution price controls - RIIO-T1 and GD1Financial issues. Ofgem, December 2010
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Figure D.4 : Investment in DSO Network Assets (2009 Prices) 104
Given that the DSO asset base is dominated by underground cables, the assumed technical life of these
particular assets is of fundamental importance when determining a single weighted technical life of the asset
base. Traditionally, underground cables have been proven to have relatively long lives compared to other
network components – with the UK’s network experience (and that elsewhere) providing empirical evidence that
underground cables have a relatively long technical life. However cable technology has changed since the
peak of electrification in much of Western Europe in the 1950s and 1960s. Some new cable technologies now
used, such as plastic cables, may have a shorter life than the older underground cable technologies (paper lead
cables) that make up the majority of the UK’s underground distribution network cables. In Ireland this is
particularly relevant given the large growth in the network over the past 20 years using newer cable
technologies with more limited operational experience and a subsequently smaller database of empirical
evidence regarding asset life. As a result there is a degree of uncertainty surrounding asset life with modern
cost effective cable constructions versus the traditional, long life paper/lead cables.
Therefore, given the younger age profile of much of the underground cabling in Ireland and the use of different
cabling technology, the assumed life for this asset class could be lower rather than the 71-94 years suggested
in PR2. ESBN has estimated that the actual lifetime of ‘newer’ technology cables is longer and points to some
of its LV plastic cables that are currently 40 - 50 years old and performing satisfactorily. ESB has endurance
tested some of its MV and 38kV cables that are currently 30 years old, with the tests indicating a considerable
remaining life estimated to be 20 – 40 years. Overall ESBN’s analysis suggests a technical life for its cables of
between 60-80 years. In our analysis we have adopted a conservative asset life for DSO underground cables
of 70 years, reflecting the midpoint of ESBN estimates.
On the other hand we have extended the life of medium and high voltage overhead lines to 63 years – reflecting
overhead line lives used by Ofgem105, in addition to the assumed asset life implied by ESB’s asset replacement
programme outlined for PS4.
The revised assets lives (for use in PR4) are provided alongside the asset lives assumed for PR2 in Table D.5
below.
104 ESB Networks, PR4 Submission DH02 PR3 Load Driven Programme, October 2014 105 DPCR5 – recognising that as these are treated as “perpetual assets” the concept of an actual replacement life is theoretical.
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Table D.5 : PR4 Assumed Asset Lives
Asset Category Technical Life
PR2
PR4
Overhead lines Low Voltage 52 52
Overhead Lines Medium Voltage 43 63
Overhead Lines High Voltage 46 63
Overhead lines EHV 67 67
Underground cables LV 92 70
Underground cables MV 94 70
Underground cables HV 71 70
Switchgear LV 73 73
Switchgear HV 47 47
Switchgear EHV 52 52
Transformers 56 56
Based on our revised asset lives assumed for PR4 we have determined the single weighted technical life of the
DSO asset based using MEAV as the weighting. We have calculated a technical life based on the UK asset
lives outlined in PR2 and shown in Table D.4 (71-94 years), plus unit costs provided by ESB for PR4. In
addition we have calculated a weighted average asset life based on a shorter life for underground cables of
between 50 and 70 years.
The results of our analysis are shown in Table D.6.
Table D.6 : Weighted Average Technical Life of DSO Asset Life (Years)
Technical Asset
Life
Distribution 61
The resulting weighted average technical asset life of the DSO network is some 61 years.
D.2.2 TAO
The depreciation life of the transmission asset base in Ireland is influenced by the structure of the asset base.
Figure D.5 below shows the configuration of the TAO RAB in 2013 based on determination of the MEAV106. It is
clear that overhead lines dominate the transmission network’s asset base and therefore the assumed life of
overhead line assets will have a highly influential impact on the weighted average technical life of the TSO’s
asset base.
106 Based on unit costs used in PR3 together with Jacob’s analysis where unit costs not available
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Figure D.5 : Composition of TSO Network RAB 2013 (MEAV Basis)
Unlike the underground cable technology used in the distribution network, the technology used for overhead
lines has changed relatively little since the peak of electrification in much of Western Europe in the 1950’s and
1960’s. As a result the technical life outlined in PR2 (Table D.4) is broadly applicable to the TAO’s asset base.
We have calculated a technical life based on the UK asset lives outlined in PR2 and unit costs provided by ESB
for PR4. The results of our analysis are shown in Table D.7. The weighted average technical life of the TAO
asset base is some 64 years.
Table D.7 : Weighted Average Technical Life of TAO Asset Base (Years)
Technical Asset
Life
Transmission 64
D.2.3 Economic lives
The CER has stated that depreciation of the transmission and distribution RABs reflects the cost of using the
assets during the period. The CER has also stated (CER 05/143 and CER 05/138) that the depreciation
method should reflect, as fairly as possible, the pattern in which an asset’s economic benefits are consumed.
Therefore implicit within this is the economically useful life of an asset which may be shorter than its technical
life.
As outlined above, work undertaken for Ofgem considered the economic life of network assets based on a
number of future energy scenarios over the period to 2050. Overall, as the energy networks move towards to
demands of a lower carbon economy, long term electricity demand increases, but the pattern of use of the
network may change. The uncertainties highlighted include the impact from technological changes with the
move to a smarter grid, increases in raw material prices and policy decisions by government affecting the speed
of change. Projecting forward, the mix of electricity assets is likely to change, which could mean greater
volumes of short-life technology assets for monitoring and controlling the network. On the other hand more
short lived assets may be balanced if the proportion of underground cables increases as existing infrastructure
is replaced.
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Recognising the uncertainties that still exist over the how the electricity network will develop into the future, the
work commissioned for Ofgem proposed it adopt a conservative approach to economic asset lives with the
economic asset lives set significantly below the average technical lives at between 45-55 years.
The drivers in Ireland are similar to those in the UK, in particular the move towards a lower carbon economy and
uncertainty over future patterns of energy usage and network flows – therefore we can conclude that the
economic life of ESB’s network assets will be lower than the weighted average technical life of the asset base.
However, in Ireland it appears that many of the shorter lived assets associated with smarter girds may not be
included in the overall asset base, but assessed separately. The impact of shorter lived assets in the asset
base, in particular smart meters and smarter grids, is explored below.
D.3 The impact of smart grids and smart meters
D.3.1 Smart grids
‘Smart grid’ assets vary by asset class and include conventional asset groups (breakers, transformers, switches,
etc.) with relatively long lives and also assets that are less conventional with shorter lives, such as software and
communications systems. At present, IT and telecoms equipment are assessed separately to ‘network assets’
for depreciation purposes, with lower depreciation lives (5-7 years for IT and 15 years for telecoms). Therefore
smart grid assets that can be categorised as IT or telecoms will not be included in the network asset base and
will have subsequently shorter depreciation lives.
Many ‘network’ related smart grid assets are not fundamentally different from existing network assets (breakers,
transformers, switches, etc.) and will have similar asset lives. For example an arc suppression coil is
considered as part of standard network assets in other jurisdictions and where initiatives include conversion of
lines from one voltage to another then asset lives will be the same. Therefore for the purposes depreciation,
such smart grids network assets will have a similar technical life to ones used on the ‘conventional’ network.
As a result we do not consider smart grid assets will have a material impact on the weighted technical life of the
DSO network asset base and that the existing classifications of IT, Telecoms and Network provide a suitable
mechanism for RAB deprecation.
D.3.2 Smart meters
The EU has called for 80% of citizens to be equipped with smart meters by 2020, subject to a positive national
cost benefit analysis. In May 2011 the European Commission undertook an economic assessment of long-term
costs and benefits associated with smart metering rollout in Ireland and concluded that the CBA was positive.
As a result Ireland has laid out plans for a large-scale smart metering roll-out107. The metering activity in Ireland
is regulated by the CER and the DSO is the owner and responsible party for the meter installation and for
granting third-party access to metering data. The European Commission smart grid study suggests a 17 year
life for a smart meter installed in Ireland and an a cost per unit of some €473108. Smart meter assets comprise
the meter itself, an electronic device with a technical life of around15 years, and the communications and IT
equipment that process the smart meter data, with a technical life of some 5 years. The volumes of smart
meters will be high compared to the low volumes of IT equipment.
Smart meters are currently excluded from the DSO RAB – and are evaluated based on an assumed asset life of
10 years. Conversely conventional meters are currently included in the DSO asset base, again with an asset
life of 10 years.
Going forward we have considered the impact of including smart meters within the DSO network asset base,
assuming they replace existing conventional meters in PR4. In order to do so we have adjusted the 2014 DSO
asset base to consider the impact of some 2.2m smart meters at an average cost of €500 per unit and a 10 year
107 http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52014SC0188&qid=1416241421987&from=EN 108 ibid
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economic life replacing all existing meters. We have also assessed the impact of excluding all meters from the
asset base.
The results of our analysis are shown in Table D.8. Excluding all meters from the asset base has a very
moderate impact on the weighted average life, increasing it from 61 to 62 years. Including 2.2m smart meters
reduces the weighted life of the asset base by 2.5 years to 59 years.
Table D.8 : Impact of Smart Meters on DSO Average Technical Asset Life
Technical asset
life including
conventional
meters
Technical asset
life excluding
ALL meters
With Technical
asset life
including 2.2m
replacement
smart meters
Distribution 61 62 59
In summary, the addition of shorter lived assets into the asset base will reduce the weighted average technical
life of the asset base.
The role of shorter lived assets in the RAB has also been acknowledged by Ofgem – who also use a variation of
the average asset life approach. Ofgem notes that it has allowed for the expected increasing importance of
shorter asset lives in adopting the 45 year asset lives for new investment which was at the lower end of the 45-
55 year range determined for the economic life of network asserts. Ofgem notes: ‘we have taken into account
several factors in determining the appropriate economic asset life. These include … the technical life of the
assets (54–60 years), which were not disputed by companies, and the clear expectation of increased electricity
usage in the plausible scenarios of future energy demand. In determining the economic asset life we have also
allowed for a reasonable increase in shorter life assets as networks become smarter and for some early
retirement of assets as generation locations change.’
One concern with adopting a blanket asset life is that it may reduce incentives to invest in short lived assets in
favour of longer lived assets. Ofgem suggests that its use of a weighted average asset life for all capex for
depreciation purposes removes the bias towards against capex on short life assets that would otherwise exist.
In Ireland the short lived telecoms and IT assets associated with smart meters are already excluded from the
network asset base and depreciated over a shorter life. In addition smart meters are currently also assessed as
a separate asset class with a 10 year depreciation life. ESBN has committed to rolling out smart meters to
some 80% of its customers in PR4 – if these assets are assessed as a separate class with a 10 year
depreciation life, then some €1bn of RAV will be depreciated over 10 years, rather than the current 45 years.
Ofgem adopted a depreciation life of 45 years that was at the lower end of the 45-55 year economic life
identified for network assets and it was intended to reflect the impact of shorter lived assets in the overall asset
base, together with other uncertainties. If smart meters are excluded from the asset base than all remaining
assets have weighted average technical life of 61 years. Under such circumstances it may be difficult to argue
that the technical life of the DSO asset base fundamentally differs to that of the transmission network and that
both should be depreciated over a similar life.
D.4 Conclusion
The CER’s PR2 decision papers increased average transmission asset lives from 40 to 50 years and
distribution from 40 to 45 years. Under the existing price control the CER reiterated these average asset lives.
The CER’s decision to increase asset lives was largely based on the structure of the RAB at that time, i.e. the
predominance of switchgear, transformers and overhead lines and the experience of network operators that
showed equipment that has been correctly specified, installed and maintained will last longer than had been
previously assumed.
In order to determine the appropriate asset lives to be used in PR4 we have evaluated the asset base of the
DSO and TAO and determined a single weighted technical life for each using MEAV as the weighting. Our
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analysis concludes that the weighted average technical life of the distribution network is 61 years and that of the
transmission network is slightly longer at some 64 years.
However, while the technical life of the asset base is longer than the asset lives applied in PR3, depreciation life
is intended to reflect the economically useful life of the network assets. Factors to be considered when
assessing the future economically useful life of the network include technological changes with the move to a
smarter grid, increases in raw material prices and policy decisions by government affecting the speed of
change. Such uncertainty suggests that the economic life of network assets should be lower than their
technical lives. In the UK, the increasing impact of shorter lived assets in the network asset base, particularly
those associated with smart grids, together with the substantial change from the prevailing depreciation life of
20 years, contributed to Ofgem adopting a depreciation life for network assets of 45 years, towards the lower
end of the economic life identified of 45-55 years.
In Ireland short lived smart grid assets (such as smart meters and associated telecoms) are currently assessed
as separate asset classes with a lower depreciation life. However conventional meters are included in the
network asset base – also with a low asset life. Including smart meters within the asset base will reduce the
weighted average technical life by around three years – widening the gap between the technical life of the DSO
and TAO assets. We conclude that, if smart meters are included in the DSO asset base, then it may be
appropriate to continue to have a depreciation life for the DSO network asset base that is lower than that of the
transmission asset base.
However, if smart meters are assessed as a separate asset class, along with other shorter lived assets such as
IT and telecoms, then we consider that there becomes significantly less rationale for the depreciation life of the
DSO asset base to differ to that of the transmission asset base given that the weighted average technical life is
very similar. The question then becomes whether a reasonable depreciation life for PR4 should be 45 or 50
years which will need to be determined based on current regulatory practice and financeability.
A summary of the proposed PR4 technical asset lives is provided below in Table D.9.
Table D.9 : Technical Asset Lives for PR4
Technical
weighted
average asset
lives
Technical
weighted
average asset
lives including
smart meters
Distribution 61 59
Transmission 63 64
