Commission for Regulation of Utilities...Total Opex 239.5 267.0 257.8 252.1 241.5 1258.0 1275.6 -17.6 -1% Source: CEPA analysis GHD and CEPA | Report for Commission for Regulation

Commission for Regulation of Utilities

Consultancy Support for Electricity Transmission Revenue Controls (2016-2025)

Price Review 4 and 5 TSO and TAO Historic Opex and Capex

July 2020

GHD and CEPA | Report for Commission for Regulation of Utilities - Consultancy Support for Electricity Transmission

and Distribution Revenue Controls (2021-2025) | i

Executive Summary This report summarises GHD and CEPA’s review and analysis of Price Review 4 (PR4) forecast outturn and the forecast – Price Review 5 (PR5) capital and operating expense submissions made by:

EirGrid as Transmission System Operator (TSO) for the years 2016 – 2025.

Electricity Supply Board (ESB) as Transmission Asset Operator (TAO) for the years 2016-2025.

In this executive summary we provide the high level summaries of our PR4 assessment that shows the ex-ante allowance and our view of the recommended ex-post allowance for Opex and Capex for the TSO and TAO.

For PR5 we summarise the requested Opex and Capex allowances made by the TSO and TAO and provide our recommendations on the allowances based on our detailed review of the relevant submissions.

Our detailed review is presented in this report as follows:

Section 1 - Introduction

Section 2 - Review of PR4 Operational Expenditure of Transmission System Operator

Section 3 - Review of PR4 Capital Expenditure Transmission System Operator

Section 4 - Review of PR4 Operational Expenditure of Transmission Asset Owner

Section 5 - Review of PR4 Capital Expenditure Transmission Asset Owner

Section 6 - Review of PR5 Operational Expenditure of Transmission System Operator

Section 7 - Review of PR5 Capital Expenditure Transmission System Operator

Section 8 - Review of PR5 Operational Expenditure of Transmission Asset Owner

Section 9 - Review of PR5 Capital Expenditure Transmission Asset Owner


and Distribution Revenue Controls (2021-2025) | ii

Price Review 4: Transmission System Operator Opex

PR4 Costs (€m 2014 prices)

PR4 Allowance

Actual / Forecast

Ex-Post Allowance Comment

Controllable Costs

Staff and Staff Related Costs 147.9 138.9

Telecommunications 30.6 24.9

Premises 23.8 26.4

IT Costs 20.6 22.3

Professional Services 15.8 19.8

Contractors 9.8 6.5

Grid Maintenance & Client Engineering

5.0 3.3

Rates 3.0 2.4

Research, development & demonstration

2.2 1.8

Promotion of research 1.0 0.7

Insurance and Compensations

1.0 1.3

Selling and Advertising 0.5 8.6

Other 0.0 -0.6

Intercompany – Corporate Recharges

-18.7 -15.6

Total controllable opex 242.4 240.7 242.4 Recommend that the TSO retains the expected saving on total controllable opex.

Non-Controllable Costs

Total non-controllable 279.5 499.2 499.2 Pass-through costs.

Total opex 521.9 739.9 741.6 Source: CEPA


and Distribution Revenue Controls (2021-2025) | iii

Price Review 4: Transmission System Operator Capex


PR4 Allowance €m

Actual / Forecast €m

Ex-Post Allowance €m Comment

TSO Stage 1 Invoicing 85.98 85.58 85.58 Explanation of changes in spend provided Outturn Adjustments 1.42 1.42

Allowance Adjustments* 22.61 Total Network Capex 108.59 87.00 87.00 Total Non-Network Capex 39.58 33.48** 31.0** Changes in spend not fully

explained in all cases TSO Total 148.17 120.48 118.00 * Includes customer contributions, community gain and client engineering capex ** Includes €3.2 m of expenditure deferred to PR5


and Distribution Revenue Controls (2021-2025) | iv

Price Review 4: Transmission Asset Operator Opex

Source: CEPA analysis


Ex-Ante Allowance

Actual / Forecast

Ex-Post Allowance

Comment

Controllable Costs

Maintenance 88.50 98.95 88.50

Professional Fees 24.1 23.3 23.3

Corporate Costs 13.4 18.3 18.3

Transmission Operations

13.4 12.6 12.6

Telecom Fees 7.7 7.5 7.7

Asset Management 5.6 4.2 4.2

Pension 2.1 2.0 2.1

Insurance 1.8 2.9 2.9

Legal 0.8 1.8 1.8

Transmission Requirements

0.0 -0.3 -0.3

Total Controllable 157.4 171.3 161.2 Based on the assessment of the evidence provided for individual categories, noting that in different categories of opex the TAO has either overspent its allowance or underspent because of delivery lagging the allowance.


Total non-controllable

140.9 126.9 126.9 Pass-through costs

Total opex 298.3 298.2 288.4


and Distribution Revenue Controls (2021-2025) | v

Price Review 4: Transmission Asset Owner Capex


PR4 Allowance €m

Actual / Forecast €m

Ex-Post Allowance €m

Comment

TSO Invoiced 108.59 87.00 87.00 From Table “Price Review 4: Transmission System Operator Capex” above.

Network Gross 1032.2 803.0 778.9 Explanation of underspend provided. 3% efficiency reduction on gross capex due to evidence of inefficient design and delivery on a sample of reviewed projects

Uncapitalised LPAR 0.0 0.23 0.23 Explanation of additional expenditure provided and agreed.

Total Capex (Gross) 1032.2 803.2 779.1

IDC -54.8 -75.4 -75.4

Customer contributions -102.0 -90.7 -90.7

Other adjustments 0.0 37.8 0.0 Outline explanation of other adjustments provided, however no justification provided for its suitability with regard to treatment as capital expenditure, magnitude of expenditure, why costs were not forecasted at PR4 and why such costs are not forecasted for PR5

Total Capex (Net) 875.4 674.6 613.0


and Distribution Revenue Controls (2021-2025) | vi

Price Review 5: TSO Recommended Opex Allowance (excluding RPEs and ongoing efficiency)

TSO Opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5 Variance

F’cast F’cast F’cast F’cast F’cast F’cast Req’t F’cast – Req’t

%

Controllable Opex

Staff and related costs 33.5 33.5 33.5 33.5 33.5 167.5 175.4 -7.9 -4%

Premises 5.8 5.7 5.7 5.7 5.7 28.5 31.2 -2.7 -9%

IT Costs 6.4 7.2 8.3 9.1 9.1 40.2 43.2 -3.0 -7%

Telecom Costs 5.1 5.3 5.5 5.7 6.0 27.6 27.6 0.0 0%

Professional Services 4.2 4.2 4.2 4.2 4.2 21.1 21.7 -0.6 -3%

Selling and Advertising 2.7 2.7 2.7 2.7 2.7 13.5 15.1 -1.5 -10%

Contractors 1.7 1.7 1.7 1.7 1.7 8.4 9.5 -1.2 -12%


0.7 0.7 0.7 0.7 0.7 3.4 3.5 -0.2 -4%

Rates 0.5 0.5 0.5 0.5 0.5 2.5 3.0 -0.6 -18%

Insurance 0.3 0.3 0.3 0.3 0.3 1.5 1.5 0.0 0%

Promotion of Research 0.5 0.5 0.5 0.5 0.5 2.3 2.5 -0.1 -5%

Intercompany Recharges -3.1 -3.1 -3.1 -3.1 -3.1 -15.5 -15.5 0.0 0%

Total Controllable Opex 58.3 59.1 60.4 61.5 61.7 300.9 318.6 -17.6 -6%

Non-Controllable Opex

Inter TSO Compensation 2.1 2.1 2.1 2.1 2.1 10.5 10.5 N/A

CORESO subscription 0.6 0.6 0.6 0.6 0.6 2.8 2.8

Interconnector services 0.8 0.8 0.8 0.8 0.8 4.1 4.1

CER Levy 1.0 1.0 1.0 1.0 1.0 4.9 4.9

DUoS costs 3.2 3.2 3.2 3.2 3.2 16.2 16.2

Ancillary Services 173.6 200.3 189.7 182.9 172.1 918.6 918.6

Total Non-Controllable Opex 181.3 208.0 197.4 190.6 179.8 957.1 957.1

Total Opex 239.5 267.0 257.8 252.1 241.5 1258.0 1275.6 -17.6 -1% Source: CEPA analysis


and Distribution Revenue Controls (2021-2025) | vii

Price Review 5: TSO Recommended Capex Allowance (excluding RPEs)

TSO Capex (€m 2019 prices) PR5 Request. Recommendation.

Network Capital Expenditure (Scenario 1) 81.0 68.32

Non-Network BAU Capex (Gross) 34.53* 19.31

Non-Network Capex (PR4 Deferred) -3.20 -3.20

(1) Sustainability & Decarbonisation 21.61 10.75

(2) Operate, Develop Grid & Market 13.89 9.28

(3) Engage for Better Outcomes for All 3.75 0.00

Non-Network Capital Expenditure Total 70.58 36.14

Strategic Initiatives Funding Through Monitoring Committee

TBC

Overall PR5 Total Capital Expenditure 151.58 104.46

* Correct summated total of individual non-network BAU capex elements Source: GHD analysis


and Distribution Revenue Controls (2021-2025) | viii

Price Review 5: TAO Recommended Opex Allowance (excluding RPEs and ongoing efficiency)

TAO Opex (€m 2019 prices)

2021 2022 2023 2024 2025 PR5 Variance


%

Controllable Opex

Planned maintenance 18.3 18.5 18.8 19.0 19.0 93.6 94.3 -0.7 -1%

Unplanned maintenance 1.2 1.3 1.3 1.3 1.3 6.4 6.4 0.0 0%

Operations 2.0 2.0 2.0 2.0 2.0 10.0 10.0 0.0 0%

Wayleaves 0.5 0.5 0.5 0.5 0.5 2.5 2.5 0.0 0%

Professional fees 2.5 2.5 2.6 2.6 2.6 12.9 12.9 0.0 0%

Telecoms opex 1.5 1.5 1.5 1.5 1.5 7.6 9.3 -1.7 -18%

Corporate overheads 3.7 3.7 3.6 3.6 3.6 18.2 18.2 0.0 0%

Insurance 0.6 0.6 0.6 0.6 0.6 2.9 3.4 -0.5 -14%

Legal 0.2 0.2 0.2 0.2 0.2 1.1 1.1 0.0 0%

Pensions admin 0.4 0.4 0.4 0.4 0.4 2.0 2.2 -0.2 -10%



Rates 28.2 32.9 33.6 32.8 34.9 162.4 162.4

N/A CRU Levy 1.1 1.1 1.1 1.1 1.1 5.6 5.6

Total Non-Controllable Opex

29.3 34.1 34.7 33.9 36.1 168.0 168.0

Total Opex 60.3 65.4 66.2 65.6 67.8 325.3 328.3 -3.0 -1%


and Distribution Revenue Controls (2021-2025) | ix

Price Review 5: TAO Recommended Capex Allowance (excluding RPEs)

TAO Capex (€m 2019 prices) PR5

Request. Recommendation Ongoing Project 445.9 415.9

Under Consideration/Provisions - System Reinforcements 73.8 73.8

Under Consideration/Provisions - Shallow Connection 0.0 0.0

Under Consideration/Provisions - Asset Refurbishment 198.9 198.9 Under Consideration - DSO 30.7 10.0 Under Consideration/Provisions - Protection, Telecoms & Station Security 0.0 0.0

New Connection Project 376.3 376.3 Other Project 0.7 0.7 Unknown 0.0 0.0 Subtotal 1126.2 1075.5 Customer Contributions -100.0 -100.0 Interest During Construction -56.3 -56.3 Other Adjustments 0.0 0.0 Total 969.9 919.2


and Distribution Revenue Controls (2021-2025) | x

Scope and limitations

This report: has been prepared by GHD for Commission for Regulation of Utilities and may only be used and relied on by Commission for Regulation of Utilities for the purpose agreed between GHD and the Commission for Regulation of Utilities as set out in this report.

GHD otherwise disclaims responsibility to any person other than Commission for Regulation of Utilities arising in connection with this report. GHD also excludes implied warranties and conditions, to the extent legally permissible.

The services undertaken by GHD in connection with preparing this report were limited to those specifically detailed in the report and are subject to the scope limitations set out in the report.

The opinions, conclusions and any recommendations in this report are based on conditions encountered and information reviewed at the date of preparation of the report. GHD has no responsibility or obligation to update this report to account for events or changes occurring subsequent to the date that the report was prepared.

The opinions, conclusions and any recommendations in this report are based on assumptions made by GHD described in this report. GHD disclaims liability arising from any of the assumptions being incorrect.

GHD has prepared this report on the basis of information provided by Commission for Regulation of Utilities and others who provided information to GHD (including Government authorities)], which GHD has not independently verified or checked beyond the agreed scope of work. GHD does not accept liability in connection with such unverified information, including errors and omissions in the report which were caused by errors or omissions in that information.


and Distribution Revenue Controls (2021-2025) | I

Table of contents 1. Introduction ............................................................................................................................... 1

1.1 Process to date ............................................................................................................... 1

1.2 Structure of the report ...................................................................................................... 2

2. Review of PR4 Operating Expenditure: Transmission System Operator ..................................... 4

2.1 Introduction ..................................................................................................................... 4

2.2 Our approach .................................................................................................................. 4

2.3 Overview of PR4 opex and our recommendation ............................................................. 5

2.4 Controllable Costs ........................................................................................................... 7

2.5 Conclusion .................................................................................................................... 14

3. Review of PR4 Capital Expenditure: Transmission System Operator ....................................... 15

3.1 Introduction ................................................................................................................... 15

3.2 PR4 Background ........................................................................................................... 15

3.3 Allowed PR4 Revenues ................................................................................................. 18

3.4 Overview of PR4 Asset Delivery .................................................................................... 19

3.5 Overview of PR4 Capital Expenditure ............................................................................ 21

3.6 PR4 Network Capital Expenditure .................................................................................. 23

3.7 PR4 Non-Network Capital Expenditure .......................................................................... 46

3.8 Conclusion from Historic PR4 Capex Review ................................................................. 52

4. Review of PR4 Operating Expenditure: Transmission Asset Operator ...................................... 59

4.1 Introduction ................................................................................................................... 59

4.2 Our approach ................................................................................................................ 59

4.3 Overview of PR4 opex and our recommendation ........................................................... 60

4.4 Controllable Costs ......................................................................................................... 61 4.5 Conclusions .................................................................................................................. 69

5. Review of PR4 Capital Expenditure: Transmission Asset Owner.............................................. 71

5.1 Total Capital Expenditure .............................................................................................. 71

5.2 PR4 Challenges and Opportunities ................................................................................ 73

5.3 Variation in Project Requirements and Costs ................................................................. 77 5.4 Project Delivery Efficiency ............................................................................................. 85

5.5 Review of Project Recording and Variation Justification ................................................. 89

5.6 Variations in project delivery timescales ......................................................................... 96

5.7 Conclusion from Historic PR4 Capex Review ................................................................. 97

6. Review of PR5 Operating Expenditure: Transmission System Operator ................................. 101

6.1 Introduction ................................................................................................................. 101

6.2 Overview of the TSO’s proposal .................................................................................. 101

6.3 Base-Trend-Step methodology .................................................................................... 102

6.4 PR5 Opex Baseline Assessment ................................................................................. 106


and Distribution Revenue Controls (2021-2025) | II

6.5 PR5 Opex Step-Change Assessment .......................................................................... 113

6.6 Summary of Recommendations ................................................................................... 132

7. Review of PR5 Capital Expenditure: Transmission System Operator ..................................... 136

7.1 PR5 Review Objectives ............................................................................................... 136

7.2 PR5 Philosophy ........................................................................................................... 136

7.3 Forecast Total TSO Capital Expenditure (2020-2025) .................................................. 138

7.4 Forecast Network Capital Expenditure (2020-2025) ..................................................... 140

7.5 Forecast Non-Network Capital Expenditure ................................................................. 157

7.6 Summary and Conclusions .......................................................................................... 176

8. Review of PR5 Operating Expenditure: Transmission Asset Operator .................................... 179

8.1 Introduction ................................................................................................................. 179

8.2 Overview of the TAO’s proposal .................................................................................. 179

8.3 Base-Trend-Step Methodology .................................................................................... 180

8.4 Base-Trend-Step Opex Analysis .................................................................................. 184

8.5 Summary of Recommendations ................................................................................... 199

9. Review of PR5 Capital Expenditure: Transmission Asset Owner............................................ 203

9.1 This Section ................................................................................................................ 203

9.2 Development Scenarios............................................................................................... 203

9.3 Overview of PR5 Forecast Capital Expenditure ............................................................ 203

9.4 Specific Findings from Forecast PR5 Review ............................................................... 211

9.5 Deliverability ................................................................................................................ 212

9.6 Line Assessments ....................................................................................................... 216

9.7 Unit Cost Assessment ................................................................................................. 217

9.8 Review of Project List .................................................................................................. 220 9.9 PR5 Summary and Conclusions .................................................................................. 221


and Distribution Revenue Controls (2021-2025) | iii

Table of Figures

Figure 3-1 – Outturn PR4 Total Capital Expenditure .......................................................................... 22

Figure 3-2 – Outturn PR4 Network Capital Expenditure ..................................................................... 24

Figure 3-3 – Summary of Regional Solution Project Capital Expenditure ........................................... 37

Figure 3-4 – Non-Progressed PR4 Project by Capital Expenditure ..................................................... 41

Figure 3-5 – Top Ten Projects with Highest Un-forecast Capital Expenditure ..................................... 43

Figure 3-6 – Summary of Non-Network PR4 Capital Expenditure per Category ................................. 47

Figure 3-7 – Summary of Non-Network PR4 Outturn & Allowance ..................................................... 51

Figure 4-1 – Planned maintenance: allowed versus outturn (2011 to 2020)........................................ 63

Figure 4-2 – Unplanned maintenance: allowed versus outturn (2011 to 2020).................................... 64

Figure 5-1 – Comparison of PR4 CRU Allowance and TAO Outturn .................................................. 72

Figure 5-2 – Progressed Project Category by Number and By Value ................................................. 78

Figure 5-3 – Known Progressed Projects of Variance Greater than €2m ............................................ 81

Figure 5-4 – Non-Progressed Projects by Number and by Value ....................................................... 82

Figure 5-5 – Projects Added by Number and by Value ....................................................................... 83

Figure 5-6 – New Assets Dashboard ................................................................................................. 87

Figure 5-7 – Comparison of Capital Approval, PR4 Forecast and PR4 Outturn Expenditure ............... 91

Figure 5-8 – Comparison of Capital Approval, PR4 Forecast and PR4 Outturn Completion ................ 92

Figure 6-1 - Recommended PR5 TSO controllable opex allowance breakdown and comparison (excluding RPEs and ongoing efficiency) .................................................. 134

Figure 6-2 - Recommended PR5 controllable opex allowance and (excluding RPEs and ongoing efficiency) ...................................................................................................... 134

Figure 7-1 – Overview of Historic and Forecast Total Capital Expenditure ....................................... 139

Figure 7-2 – Overview of Historic and Forecast Network Expenditure .............................................. 143

Figure 7-3 – Investment Category Breakdown by Scenario .............................................................. 146

Figure 7-4 – Investment Category Breakdown by Number of Projects .............................................. 147

Figure 7-5 – Investment Category by Value: PR5 Spend – Scenario 1 ............................................. 149

Figure 7-6 – Investment Category by Value: – PR4 Actual & Forecast Spend .................................. 149

Figure 7-7 – Expected New Assets to Be Added over PR5 period ................................................... 151

Figure 7-8 – Historic and Forecast Network Demand and Wind Capacity ......................................... 155

Figure 8-1 – Age distribution of overhead lines (OHL) – number of circuits ...................................... 186

Figure 8-2 – Age distribution of overhead lines (OHL) – km of lines ................................................. 186

Figure 8-3: Recommended PR5 TAO controllable opex allowance breakdown and comparison (excluding RPEs and ongoing efficiency) .................................................. 201


and Distribution Revenue Controls (2021-2025) | iv

Figure 8-4: Recommended PR5 controllable opex allowance and TAO proposal (excluding RPEs and ongoing efficiency) ...................................................................................... 201

Figure 9-1 – Comparison of PR4 Outturn and PR5 Forecast ............................................................ 206

Figure 9-2 – Apportionment of Expenditure by % in PR5 Forecast and PR4 Outturn ........................ 208

Figure 9-3 – Apportionment of Projects by % of Total Capex in 2016 - 2025 .................................... 209

Figure 9-4 – Asset Dashboard ......................................................................................................... 210

Figure 9-5 – Number of Projects with Expenditure ........................................................................... 213


and Distribution Revenue Controls (2021-2025) | v

Table of Tables Table 1-1 – TSO and TAO comments log ............................................................................................ 2

Table 2-1 – Assumed Inflation Indices ................................................................................................. 4

Table 2-2 – Summary of PR4 TSO Opex Allowances .......................................................................... 6

Table 2-3 – PR4 I-SEM Incremental Opex allowance .......................................................................... 7

Table 2-4 – Staff and Related Costs, Contractor Costs and Professional Services in PR4 ................... 8

Table 2-5 – Staff Costs in PR4 ............................................................................................................ 8

Table 2-6 – Telecom Costs in PR4 ...................................................................................................... 9

Table 2-7 – Premises Costs in PR4 ................................................................................................... 10

Table 2-8 – IT Costs in PR4 .............................................................................................................. 10

Table 2-9 – Grid Maintenance and Client Engineering Costs in PR4 .................................................. 11

Table 2-10 – Rates in PR4 ................................................................................................................ 11

Table 2-11 – Research, Development and Demonstration Costs in PR4 ............................................ 11

Table 2-12 – Insurance Costs in PR4 ................................................................................................ 12

Table 2-13 – Selling and Advertising Costs in PR4 ............................................................................ 12

Table 2-14 – Intercompany Costs in PR4 .......................................................................................... 13

Table 2-15 – Other Costs in PR4 ....................................................................................................... 13

Table 2-16 – PR4 TSO Ex-Post Opex Allowance............................................................................... 14

Table 3-1 – 2006 Infrastructure Agreement Summary ........................................................................ 16

Table 3-2 – Annual HICP Rates during PR4 ...................................................................................... 18

Table 3-3 – PR4 Allowed Network Capital Expenditure 2016-2020 .................................................... 18

Table 3-4 – PR4 Allowed Non-Network Capital Expenditure 2016-2020............................................. 19

Table 3-5 – PR4 Asset Delivery Dashboard ....................................................................................... 20

Table 3-6 – PR4 Total Capital Expenditure 2016-2020 ...................................................................... 21

Table 3-7 – PR4 Network Total Capital Expenditure 2016-2020......................................................... 23

Table 3-8 – Overall Project Costs ...................................................................................................... 26

Table 3-9 – TSO CP0466 Project Costs ............................................................................................ 27

Table 3-10 – High Capex Variance Projects ...................................................................................... 28

Table 3-11 – Regional Solution Project Capital Forecasts .................................................................. 36

Table 3-12 – Non-Network PR4 Capex Outturn ................................................................................. 48

Table 3-13 – Summary of PR4 Capital Expenditure 2016-2020 ......................................................... 56

Table 4-1 – Assumed Inflation Indices ............................................................................................... 59

Table 4-2 – Summary of PR4 TAO Opex Allowances (2014 prices) ................................................... 60

Table 4-3 - PR4 TAO Controllable Opex Categories .......................................................................... 61

Table 4-4 – Maintenance Spend in PR4 ............................................................................................ 62


and Distribution Revenue Controls (2021-2025) | vi

Table 4-5 – Professional Fees Spend in PR4 .................................................................................... 65

Table 4-6 – Corporate Costs in PR4 .................................................................................................. 65

Table 4-7 – Operations Spend in PR4 ............................................................................................... 66

Table 4-8 – Telecoms Spend in PR4 ................................................................................................. 66

Table 4-9 – Asset Management Spend in PR4 .................................................................................. 67

Table 4-10 – Pension administration Spend in PR4 ........................................................................... 67

Table 4-11 – Insurance Spend in PR4 ............................................................................................... 68

Table 4-12 – Legal Spend in PR4 ...................................................................................................... 68

Table 4-13 – Transmission Retirements in PR4 ................................................................................. 69

Table 4-14 – PR4 TAO Ex-Post Opex Allowance............................................................................... 70

Table 5-1 – TAO Transmission Capital Expenditure 2016-2020 ......................................................... 71

Table 5-2 – PR4 Spend Breakdown for Major Projects ...................................................................... 73

Table 5-3 – 2006 Infrastructure Agreement Summary ........................................................................ 74

Table 5-4 – Annual HICP Rates during PR4 ...................................................................................... 77

Table 5-5 – Project Composition in 2014 Forecast and 2020 Outturn ................................................. 77

Table 5-6 – PR4 Projects with Highest Cost Variance ........................................................................ 79

Table 5-7 – Asset Summary .............................................................................................................. 88

Table 5-8 – TAO Unit Costs .............................................................................................................. 88

.Table 5-9 – Capital Approval Budget and Timings Comparison......................................................... 90

Table 5-10 – Review of Sample AEA ................................................................................................. 93

Table 5-11 – Summary of Additional Costs sought in AEA Sample .................................................... 94

Table 5-12 – End Project Report Sample Review Summary .............................................................. 95

Table 5-13 – Overarching Performance ............................................................................................. 97

Table 6-1 – Requested PR5 Opex Allowance (excluding RPEs and ongoing efficiency) ................... 102

Table 6-2 – Staff costs and staff related costs: PR5 baseline ........................................................... 107

Table 6-3 – TSO adjusted professional services baseline request ................................................... 107

Table 6-4 – Professional services: PR5 baseline ............................................................................. 108

Table 6-5 – IT opex: PR5 baseline .................................................................................................. 108

Table 6-6 – Contractor costs: PR5 baseline ..................................................................................... 109

Table 6-7 - Insurance costs: PR5 baseline ...................................................................................... 109

Table 6-8 – Grid maintenance and client engineering: PR5 baseline ................................................ 110

Table 6-9 – Premises costs: PR5 baseline ...................................................................................... 110

Table 6-10 – Promotion of research: PR5 baseline .......................................................................... 111

Table 6-11 – Telecoms opex: PR5 trend analysis ............................................................................ 111

Table 6-12 – Telecoms opex: PR5 baseline and trend ..................................................................... 112

Table 6-13 – Selling and advertising: PR5 baseline ......................................................................... 112


and Distribution Revenue Controls (2021-2025) | vii

Table 6-14 – Rates: PR5 baseline ................................................................................................... 113

Table 6-15 – Intercompany recharges: PR5 baseline....................................................................... 113

Table 6-16 – Summary of PR5 Controllable Opex Step-Changes .................................................... 115

Table 6-17 – PR5 Controllable Opex Step-Changes Mapped Against Cost Areas ............................ 115

Table 6-18 – S&D: Recommended Allowance ................................................................................. 116

Table 6-19 – Operate, Develop, and Enhance the Grid & Market: Recommended Allowance........... 120

Table 6-20 – Engage for Better Outcomes for All: Recommended Allowance .................................. 126

Table 6-21 – Education & Engagement: Requested opex by cost area ............................................ 126

Table 6-22 – Enhanced Customer Journey: Requested opex by cost area....................................... 127

Table 6-23 – Non-Network Capex BAU: Recommended Allowance ................................................. 128

Table 6-24 – Non-Network Capex BAU: Recommended Allowance ................................................. 130

Table 6-25 – Other Step-Changes: Recommended Allowance......................................................... 131

Table 6-26 – Summary of assessment of step changes ................................................................... 131

Table 6-27 – Recommended PR5 Opex Allowance (excluding RPEs and ongoing efficiency) .......... 133

Table 7-1 – Forecast Total TSO PR5 Capital Expenditure Required ................................................ 138

Table 7-2 – Forecast Network Capex Scenario 1 – Embracing Change ........................................... 141

Table 7-3 – Forecast Network Capex Scenario 2 – Business As Usual ............................................ 141

Table 7-4 – Forecast Network Capex Scenario 3 – Unconstrained Development ............................. 141

Table 7-5 – Scenario 1 Factoring Values ......................................................................................... 144

Table 7-6 – Top Ten Projects by Capital Expenditure (TSO and TAO) ............................................. 152

Table 7-7 – Projects Spend Over Three or More Price Review Periods ............................................ 153

Table 7-8 – Forecast TSO PR5 Network Expenditure – Recommendation ....................................... 156

Table 7-9 – Requested Non-Network Capex – End of Life IT Assets ................................................ 158

Table 7-10 – Requested Non-Network Capex – Transition to Cloud................................................. 161

Table 7-11 – Requested Non-Network Capex – Review of IT Operating Model ................................ 162

Table 7-12 – Requested Non-Network Capex – Simplify & Standardise IT Solutions ....................... 162

Table 7-13 – Requested Non-Network Capex – Baseline Cyber Security ......................................... 164

Table 7-14 – Recommended Non-Network Capex ........................................................................... 166

Table 7-15 – Sustainability & Decarbonisation PR5 Capex .............................................................. 168

Table 7-16 – Operate, Develop, Enhance Grid & Market Initiative PR5 Capex ................................. 169

Table 7-17 – Requested Engage for Better Outcomes Initiative PR5 Capex .................................... 172

Table 7-18 – Recommended Non-Network Capex ........................................................................... 175

Table 7-19: Forecast Total TSO PR5 Capital Expenditure – GHD Recommendation ....................... 178

Table 8-1 – Assumed Inflation Indices ............................................................................................. 179

Table 8-2 – Requested PR5 Opex Allowance (excluding RPEs and ongoing efficiency) ................... 180

Table 8-3 – Planned Maintenance: Recommended Allowance ......................................................... 184


and Distribution Revenue Controls (2021-2025) | viii

Table 8-4 – Planned maintenance CEPA trend projection ................................................................ 185

Table 8-5 – Planned maintenance: after step analysis ..................................................................... 187

Table 8-6 – Unplanned Maintenance: Recommended Allowance ..................................................... 187

Table 8-7 – Unplanned maintenance CEPA trend projection............................................................ 188

Table 8-8 – Unplanned maintenance: after step analysis ................................................................. 188

Table 8-9 – Operations: Recommended Allowance ......................................................................... 189

Table 8-10 – Operations CEPA trend projection .............................................................................. 189

Table 8-11 – Operations: after step analysis .................................................................................... 190

Table 8-12 – Wayleaves: Recommended Allowance ....................................................................... 190

Table 8-13 – Wayleaves CEPA trend projection .............................................................................. 191

Table 8-14 – Wayleaves: after step analysis .................................................................................... 191

Table 8-15: Professional Fees: Recommended Allowance .............................................................. 192

Table 8-16 – Professional services fees: after step analysis ............................................................ 193

Table 8-17: Telecom Fees: Recommended Allowance .................................................................... 193

Table 8-18 – ESB Networks PR5 Telecoms Opex Breakdown ......................................................... 194

Table 8-19 – Telecoms opex: after step analysis ............................................................................. 194

Table 8-20 – Corporate Costs: Recommended Allowance ............................................................... 195

Table 8-21 – Corporate Costs: after step analysis ........................................................................... 196

Table 8-22 – Insurance: Recommended Allowance ......................................................................... 196

Table 8-23 – Insurance: after step analysis ..................................................................................... 197

Table 8-24 – Legal: Recommended Allowance ................................................................................ 197

Table 8-25 – Legal: after step analysis ............................................................................................ 198

Table 8-26 – Pension Administration: Recommended Allowance ..................................................... 198

Table 8-27 – Pensions Administration: after step analysis ............................................................... 199

Table 8-28 – Recommended TAO PR5 Controllable Opex Allowance (before RPEs and ongoing productivity) ................................................................................................... 200

Table 9-1 – Forecast Capital Expenditure for PR5 ........................................................................... 204

Table 9-2 – Outturn Capital Expenditure for PR4 ............................................................................. 205

Table 9-3 – ‘Top 10’ Projects Summary ........................................................................................... 207

Table 9-4 – Overarching Summary .................................................................................................. 221


and Distribution Revenue Controls (2021-2025) | ix

Abbreviations Acronym Definition ABP An Bord Pleanala ACSR Aluminium Conductor Steel Reinforced Cable AEA Additional Expenditure Approvals AIS Agricultural Liaison Officers BPQ Business Plan Questionnaire CAPEX Capital Expenditure CEPA Cambridge Economic Policy Associates CER The Commission for Energy Regulation CRU Commission for Regulation of Utilities DSO Distribution System Operator EA External Affairs EPC Engineering Procurement Construction ESB Electricity Supply Board ESBI Electricity Supply Board International ESOP Employee Stock Ownership Plan EU European Union FTE Full Time Equivalent GHD Gutteridge Haskins and Davey Ltd GIS Geographic Information System HBPQ Historic Business Plan Questionnaire HICP Harmonised Index of Consumer Prices HSE Health and Safety Executive HVAC High Voltage Alternating Current HW Hardware IDC Internal Development Charges IEP Integrated Energy Planning IFA Institute of Financial Accountants IP Internet Protocol ISEM Integrated Single Electricity Market ITOMS International Transmission Operations & Maintenance Study LPAR Line Project Assessment Report MVA Mega Volt- Ampere MW Mega Watt MYDP Multi-Year Delivery Programme NCC National Control Centre NPC Net Present Cost OHL Over Head Line PA Post Application PCR Project Change Request PR Price Review QRA Qualitative Risk Assessment RIDP Remote Identity Proofing RTU Remote Terminal Unit SEM Single Electricity Market SEMO Single Electricity Market Operator SNSP System Non-Synchronous Penetration SONI System Operator for Northern Ireland


and Distribution Revenue Controls (2021-2025) | x

Acronym Definition STATCOM Static Compensator SW Software TAO Transmission Asset Owner TIME Tolerate, Invest, Migrate or Eliminate TLA Transmission Line Assessment TSO Transmission System Operator TSSPS Transmission System Security and Planning Standards UGC Underground Insulated Cable WF Windfarm XLPE Cross-linked Polyethylene


and Distribution Revenue Controls (2021-2025) | 1

1. Introduction EirGrid carries out the function of Transmission System Operator (TSO) and ESB Networks carries out the function of Transmission Asset Operator (TAO) in Ireland. This report sets out the TSO and TAO’s capital expenditure (capex) and operating expenditure (opex) over the PR4 (2016 to 2020) and PR5 (2021 to 2025) periods.

The review considers the costs, systems processes, and initiatives of the TSO and TAO over PR4 and identifies key issues to be considered in PR5. The report then reviews the TSO and TAO proposals for expenditure in PR5 and makes recommendations on the level of expenditure, outputs and incentives to be allowed by Commission for Regulation of Utilities (CRU).

1.1 Process to date

We have undertaken an exhaustive process to come up with the recommendations in this report. This included engagement with the TSO and TAO, both jointly and individually, to:

Understand the nature of their business, the challenges they face and the ambitions for PR5

Set out the expectations for the business plans, including what data was required and how data tables were to be filled in. This included sharing a comprehensive guide for filling in the data tables

Workshops in person and via video/tele-conference to discuss part of the business plans once they had been submitted

Sharing logs of clarification questions about the TSO and TAO’s business plans and data tables

The TSO and TAO were also given an opportunity to highlight any factual errors in a draft of this report

1.1.1 Data submission

The TSO and TAO were provided with the final version of the data table templates on 31st August 2019. The TSO made the following submissions:

Historic Questionnaire Submission: 31st October 2019

Forecast Questionnaire Submission: 29th November 2019

The TAO made the following submissions:

Historic Questionnaire Submission: 1st November 2019

Forecast Questionnaire Submission: 2nd December 2019

The TAO subsequently re-submitted parts of its business plan and additional information on 4th February 2020. However, for this report only material submitted as part of the first business plan (i.e. material received by 3rd February was considered. The only information from the second business plan submission that is included in this report is the actual opex and capex values for 2019, which replace forecast values from the first business plan.

The data requested is in essentially the same format that was used in PR4 and preceding Price Reviews. The TSO and TAO were advised during early engagements in 2019 that the data requested would be in the same format as previous Price Reviews, and was provided with draft



versions of the data tables and guidance document to comment on. During the review process there have been a number of changes made to the data provided by the TSO and TAO through to February 2020. 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.

1.1.2 Engagement after receiving the business plan

We held a series of meetings with the TSO and TAO after receiving their business plan submissions – both jointly and independently. These included:

A full-day workshop in Dublin on the 17th December 2019.

Numerous clarification and deep dive meetings and discussions via video/tele-conference

We also raised a series of clarification questions (171 TSO and 98 TAO) regarding the business plan submissions, to which each of the TSO and TAO was asked to respond.

1.1.3 Fact-check

The TSO and TAO were each provided with draft sections of this report:

For the TSO: sections 2 and 3, which review PR4 opex and capex: 27th March 2020 and sections 6 and 7, which assess forecast opex and capex for PR5: 24th April 2020

For the TAO: sections 4 and 5, which review PR4 opex and capex: 27th March 2020 and sections 8 and 9, which assess forecast opex and capex for PR5: 24th April 2020

Each licensee was asked to highlight any factual errors with the reports, which would then be resolved before finalising the report. The TSO and TAO’s comments on the report exceeded this fact-check, and included new information on costs and initiatives in PR4 and PR5. Subsequently, workshops were held with each of the TSO and TAO (via videoconference) to discuss any outstanding issues.

For this report only comments on factual accuracy have been processed. The TSO and TAO each have the opportunity to provide further information in response to the CRU’s draft determination. We will subsequently consider the additional information submitted as part of the fact check with this draft determination response and determine whether any of this information changes the recommendations in this report.

The table below summarises the volume of comments raised by the TSO and by the TAO, and whether they were progressed as matters of factual accuracy.

Table 1-1 – TSO and TAO comments log

TSO TAO

Sections 2 & 3 Section 6 & 7 Sections 4 & 5 Section 8 & 9

Processed as fact-check 3 70 24 9

New information, not addressed in this report

0 46 12 19

1.2 Structure of the report

This report is divided into 9 sections as follows:

Section 1 contains this introduction



Section 2 contains our review of the TSO’s actual and expected PR4 opex, and compares this to the allowances set by CRU for the same period.

Section 3 contains our review of the TSO’s actual and expected PR4 capex, and compares this to the allowances set by CRU for the same period.

Section 4 contains our review of the TAO’s actual and expected PR4 opex, and compares this to the allowances set by CRU for the same period.

Section 5 contains our review of the TAO’s actual and expected PR4 capex, and compares this to the allowances set by CRU for the same period.

Section 6 presents the TSO’s forecast opex for PR5, our review of this forecast and our proposed allowed opex for the PR5 period.

Section 7 presents the TSO’s proposed capex allowances for PR5. These proposed allowances are reviewed and subsequently we present our proposed allowed capex for the PR5 period.

Section 8 presents the TAO’s forecast opex for PR5, our review of this forecast and our proposed allowed opex for the PR5 period.

Section 9 presents the TAO’s proposed capex allowances for PR5. These proposed allowances are reviewed and subsequently we present our proposed allowed capex for the PR5 period.



2. Review of PR4 Operating Expenditure: Transmission System Operator 2.1 Introduction

This section of the report reviews the reported TSO PR4 (2016 to 2020) opex and compares this outturn against the TSO’s PR4 opex allowances, as determined by the CRU in the PR4 Decision Paper. 2016 to 2018 performance and cost data are based on actual recorded values, whilst 2019 and 2020 performance and cost data are based on the latest forecast data available.

Unless stated otherwise, our review of PR4 expenditure has prices expressed in real 2014 price levels. This allows comparison with the original CRU PR4 allowances. The conversion to these price levels was based on the inflation factors presented in Table 2-1 below. The TSO submitted actual cost data (up to 2018) in nominal terms and forecast cost data (2019 and 2020) in real 2019 price levels, which is reflected in the inflation factors below.

Table 2-1 – Assumed Inflation Indices

2014 2015 2016 2017 2018 2019 2020

HICP Adjustment Factor

1.000 1.000 1.002 1.000 0.993 0.984 0.984

Source: ec.europa.eu/Eurostat/data/database. Dataset: prc_hicp_midx. Accessed: 13/01/2020

CRU allowed costs are as set out in the CRU PR4 decision paper with annual adjustments made during the price control period by CRU for pass through items along with volume related items included as part of the PR4 settlement.

2.2 Our approach

The objective of this review is to assess the TSO’s performance in achieving the outputs required by CRU during PR4 and whether the costs incurred in achieving these outputs were reasonable.

The opex allowance set by the CRU is split into controllable and non-controllable opex. Controllable opex relate to costs that the CRU consider are within management control and can be assessed for reasonableness. Non-controllable opex relate to costs that the CRU consider are outside of management control and are, therefore, passed through to charges through the annual revenue review process.

Controllable opex is subject to benefit sharing arrangements, as stated in the PR4 final determination:

“For Opex, the TSO and TAO will be permitted to retain the annual savings made for a period of five years, provided such savings have not been made at the expense of performance/ inefficiency and quality of service or as a result of poor forecasting.”1

1 CER (2015) Decision on TSO and TAO Transmission Revenue for 2016 to 2020, CER/15/296, section 13.4



We have assessed the TSO’s opex by cost type2 – enabling us to better link costs incurred to output delivery. Our review of PR4 opex focuses on:

Comparison of actual opex against allowed opex.

Where the TSO is reporting a difference between actual and allowed opex, we have undertaken ‘deep dive’ analysis of evidence submitted by the TSO to explain any variances in outputs and costs. The aim of this is to understand whether:

o any under-spend is the result of efficiency gains or under-delivery of outputs; and

o the TSO has demonstrated that any over-spend is efficient or is the result of over-delivery of outputs.

Our recommendations are to set the ex-post allowance to outturn costs, except where under-spend is efficient or over-spend is inefficient. In this way, way the intention of the PR4 incentive arrangements (quoted above) is achieved while providing the TSO with balanced exposure to upside and downside risks.

We then take an in-the-round view on the level of controllable opex that should be reflected in the ex-post allowance, with any difference between the ex-post allowance and the TSO’s outturn opex being subject to the benefit sharing arrangements.

Within controllable opex, the TSO has had to deliver in PR4 outputs related to the introduction of the integrated single electricity market (I-SEM) that were not known when the PR4 allowance was set. Our approach to these costs is discussed further in the next section.

2.3 Overview of PR4 opex and our recommendation

Table 2-2 presents the TSO’s allowed opex for the full PR4 period and the TSO’s expected outturn for the same period, presented by cost area. The figures as allowed for PR4 include an adjustment of €14.5 million for incremental costs related to the introduction of the I-SEM – see further discussion after the table.

2 This contrasts with our review of TAO and DSO opex in PR4, where we assess costs on an activity basis.



Table 2-2 – Summary of PR4 TSO Opex Allowances

PR4 Costs Allowed Actual/ Forecast

Variance

€m % Controllable Costs Staff and Staff Related Costs 147.9 138.9 -9.0 -6% Telecommunications 30.6 24.9 -5.7 -19% Premises 23.8 26.4 2.6 11% IT Costs 20.6 22.3 1.7 8% Professional Services 15.8 19.8 4.0 25% Contractors 9.8 6.5 -3.3 -34% Grid Maintenance & Client Engineering

5.0 3.3 -1.7 -34%

Rates 3.0 2.4 -0.6 -21% Research, development & demonstration

2.2 1.8 -0.4 -18%

Promotion of research 1.0 0.7 -0.3 -29% Insurance and Compensations 1.0 1.3 0.3 32% Selling and Advertising 0.5 8.6 8.1 1617% Other 0.0 -0.6 -0.6 - Intercompany – Corporate Recharges

-18.7 -15.6 3.1 -17%

Total controllable opex 242.4 240.7 -1.7 -1% Non-controllable opex Inter TSO Compensation 6.5 7.6 1.1 17% CORESCO Subscription 4.0 1.3 -2.7 -68% Interconnector Services 5.0 3.8 -1.2 -24% CRU Levy 5.0 5.3 0.3 6% Ongoing Service Charge 6.5 1.5 -5.0 -77% DUoS Costs 6.5 12.3 5.8 89% Ancillary Services 246.0 467.4 221.4 90% Total non-controllable 279.5 499.2 219.7 79% Total opex 521.9 739.9 218.0 42%

Source: EirGrid Overall, the TSO’s expected opex outturn for PR4 is €739.9 million (including incremental I-SEM costs). This is €218.0 million (42%) above the CRU allowance of €521.9 million.

Most of this overspend is as a result of outturn non-controllable costs exceeding what was forecast during the PR4 determination. Overall, the TSO is expected to spend €499.2 million in non-controllable costs over PR4. This represents a €219.7 million (79%) overspend relative to the PR4 allowance. The majority of this overspend is driven by the TSO’s spend on ancillary services. However, the TSO’s non-controllable costs are passed through to the TSO’s allowance and as a result are not subject to an efficiency review in this report. These costs are deemed to be efficiently incurred by the CRU as they are considered outside of the TSO’s control and so are treated as pass-through costs.

In contrast, the TSO is forecast to underspend its PR4 controllable opex allowance by €1.7 million (1%). This underspend is based on our understanding of the CRU’s regulatory treatment of the costs incurred by the TSO in the operation of the I-SEM.

The I-SEM, which went live on the island of Ireland on 30 September 2018, generated a number of additional costs and activities for the TSO that were not anticipated at the time of the PR4 determination, including the operation of the I-SEM’s capacity service and additional balancing market scheduling. In June 2017, the TSO requested an additional €14.5 million opex allowance



to cover these incremental activities.3 The breakdown of this request is presented in Table 2-3. Based on the evidence that we have reviewed, which includes publications by the CRU and SEM Committee, our understanding is that the CRU accepted the need for the additional costs and that the SEM Committee assessed the request by EirGrid as reasonable.4 We interpret this position as effectively uplifting the PR4 ex-ante opex allowance (as presented in Table 2-2) by a total of €14.5 million to account for the impact of the I-SEM. As with all other costs incurred by the TSO, in this ex-post review we assess the level of outturn costs against the allowance (in this case adjusted for the TSO’s 2017 request).

Table 2-3 – PR4 I-SEM Incremental Opex allowance

Incremental I-SEM opex (€m, 2014 prices) 2016 2017 2018 2019 2020 Total

PR4

Staff and Staff Related Costs 0.0 0.0 2.4 2.7 2.8 7.9

Contractors 0.0 0.0 0.7 0.7 0.5 1.8

IT Costs 0.0 0.0 1.0 1.3 1.2 3.6

Professional Fees 0.0 0.0 0.3 0.5 0.5 1.3

Total 0.0 0.0 4.3 5.2 5.0 14.5 Source: EirGrid The following sub-sections assess the over-/under-spend for the costs that are covered by the PR4 regulatory allowance on a category-by-category basis. Taken as a whole, the TSO’s controllable opex costs are projected to fall within the PR4 allowance. As such, we recommend that the ex-ante allowance is retained for controllable opex.

2.4 Controllable Costs

2.4.1 Staff, Staff Related Costs, Contractors and Professional Services

(Allowed €173.5 million, Outturn €165.1 million) The TSO has said that during PR4 it introduced a flexible resourcing model such that a balance of permanent, fixed-term contract staff and professional services could be more efficiently used. The TSO says that this model allows it to maintain a core group of skilled staff on an ongoing basis while retaining the capacity to scale-up for peak periods, or to access scarce skills quickly for once-off or time-limited pieces of work. For example, the TSO gives the I-SEM project as a successful example of the flexible resourcing model. As such, we assess these cost categories over PR4 together.

Table 2-4 compares staff costs, staff related costs, contractors, and professional services opex against the TSO’s allowance for the PR4 period. The TSO has forecast €165.1 million in staff and related costs, contractors and professional services in comparison to an allowance of €173.5 million. This represents an underspend of €8.4 million (5%). Spend on staff costs, staff

3 EirGrid (2017) EirGrid TSO I-SEM Revenue Requirements 4 For example, the SEMO price states:

Pre-Go-Live costs represent a proportion of staff and staff related costs for I-SEM readiness which are being incurred by SEMO prior to this price control period. These costs reflect staff that are necessary to be in place prior to I-SEM Go-Live. They do not form part of the I-SEM implementation costs described in section 1.2, which will be capitalised. 20% of pre go-live operating costs related to SEMO will be recovered through the SEMO price control as Opex. They represent a reasonable level of costs that are to be treated as “operational” under applicable International Accounting Standards (IAS 16). The activities included for Pre-Go Live costs include;

• The establishment of an operational team a number of months in advance of the market golive date of May 2018; and

• IT costs (licences, support etc.) required during Market Trials. SEM Committee (2018) SEMO Price Control, Final Determination Paper, SEM-18-003, p.6



related costs, and contractors is all forecast to fall below the PR4 allowance for this category (including the additional I-SEM costs requested in 2017).

Table 2-4 – Staff and Related Costs, Contractor Costs and Professional Services in PR4

TSO Opex (€m 2014 prices)

2016 2017 2018 2019 2020 PR4 Total

Actual Actual Actual F’cast F’cast Allowed Actual/ F’cast

Variance €m %

Staff and Related Costs

26.6 25.9 27.5 28.5 30.3 147.9 138.9 -9.0 -6%

Contractors 0.9 1.2 1.1 1.9 1.4 9.8 6.5 -3.3 -34%

Professional Services

2.3 2.6 3.6 4.9 6.4 15.8 19.8 4.0 25%

Total 29.8 29.7 32.2 35.3 38.2 173.5 165.1 -8.4 -5%

Source: EirGrid As illustrated Table 2-4, the TSO has forecast an underspend in both contractor costs and staff and staff related costs. The TSO has forecast a €3.3 million (34%) underspend in contractor costs and an underspend of €9.0 million (6%) in staff and staff related costs.5

In order to better understand the TSO’s spend on staff and staff related costs, we have also looked at the evolution of full time equivalent (FTE) staff numbers and staff unit costs over PR4. These figures are presented in Table 2-5.

Table 2-5 – Staff Costs in PR4

TSO Opex (€, 2014 prices) 2016 2017 2018 2019 2020

Staff and Related Costs 26,624,321 25,865,690 27,518,267 28,499,413 30,349,513 Source: EirGrid

Over PR4, staff and staff related costs are forecast to increase by 14%, while the number of FTEs are forecast to increase by 29%. The largest increase in FTEs occurs in 2019 and 2020. Between 2018 and 2020, the number of FTEs increases by 46 (18%). Based on the information provided by the TSO, our analysis suggests that this increase is not solely driven by the introduction of the I-SEM.

The TSO has outlined a number of measures taken during PR4 that have reduced unit costs in this category:

The Defined Benefit pension scheme for new staff was discontinued in 2019 and replaced with a Defined Contribution scheme. This reduced the employer contribution from 20% to 11%.

Organisational changes were implemented during the PR4 period which sought to maximise the efficiencies from the integrated operating model across the EirGrid Group.

The annual company performance award of up to 5% of basic salary per year was discontinued in 2015.

5 We note that the TSO has forecast €5.0 million in intercompany payroll recharges over PR4. However, as recharges were treated as a single category in the PR4 determination (covering payroll, premises and corporate), we cannot determine if the outturn level of recharges over PR4 should increase or decrease outturn net payroll costs.



The TSO also argued that the level of the PR4 allowance has led to difficulties in delivering on commitments on time, or at the highest level of quality.6 However, as noted in Table 2-4, the TSO is projected to underspend its PR4 allowance for staff and staff related costs. As such, we do not consider there to be a strong causal link between the PR4 allowance and the TSO’s capacity to deliver the actions that it believes it should have done during PR4. That it decided to not do such things during PR4 appears to reflect internal business choices and decisions.

In contrast to staff and staff related costs and contractor costs, the TSO is forecast to exceed its regulatory allowance for professional services. The TSO has forecast €19.8 million in professional services costs compared to an allowance of €15.8 million. This represents an overspend of €4.0 million (25%). While we recognise that the TSO has operated a flexible working model across its staffing, contractors and professional services, we do not consider that the TSO has provided an explanation for the large increase in professional services, in particular, between 2018 and 2020.

Between 2017 and 2020, annual spend on professional services is forecast to increase by €3.8 million (151%). This is considerably higher than the total additional opex allowance of €1.3 million for professional services that the TSO submitted with regard to the introduction of the I-SEM. We also note that in the TSO’s PR5 submission (see Section 3), the TSO forecasts a 42% decline in professional services costs between 2020 and 2021 - back to 2018 levels. With no further information provided by the TSO, it is not possible to conclude that the increase in professional services costs between 2018 and 2020 should be borne by electricity customers.

Overall, we consider that the TSO has delivered opex savings across staff and related costs, contractor costs, and professional services. For the purposes of recommending an ex-post allowance we consider controllable opex in its totality.

2.4.2 Telecoms

(Allowed €30.6 million, Outturn €24.9 million) Table 2-6 compares telecom opex against the TSO’s allowance for the PR4 period. The TSO has forecast €24.9 million in telecom costs compared to an allowance of €30.6 million.7 This represents an underspend of €5.7 million (19%).

Table 2-6 – Telecom Costs in PR4


2016 2017 2018 2019 2020 PR4 Total

Actual Actual Actual Forecast Forecast Allowed Actual/ Forecast

Variance €m %

Telecom Costs

4.6 4.4 4.9 5.2 5.8 30.6 24.9 -5.7 -19%

Source: EirGrid The TSO has indicated that underspends in this category are primarily due to a lag in the delivery of three programmes:

replacement of remote telemetry unit (RTU) existing sites began behind schedule, in 2018;

transfer over to a new internet protocol (IP) network has been delayed due to cyber security provisions; and

6 The TSO has not provided an example of which commitments or outputs suffered during PR4. 7 We have taken this number from the final PR4 financial model; it is €30.7m in the CRU decision paper.



the expected replacement of the National Control Centre (NCC) Telephone System did not occur in PR4.

The TSO has also outlined some of the efficiencies in telecoms that it achieved in PR4 through its Group Operating Model - e.g. a 40% discount on servers and a 53% discount on storage. The TSO has also pointed to savings achieved in relation to its external telecoms’ provider during PR4, as well as the implementation of a new IT Assessment Framework which has identified areas where further efficiencies could be delivered.

We consider that the PR4 allowance should not be adjusted downward for the lag in delivery of the above programmes. Instead, we recommend that the TSO should report to CRU on progress to deliver these programmes, and that no further allowances should be provided for these programmes in PR5.

2.4.3 Premises

(Allowed €23.8 million, Outturn €26.4 million) Table 2-7 compares premises opex against the TSO’s allowance for the PR4 period. The TSO has forecast €26.4 million in premises costs compared to an allowance of €23.8 million. This represents an overspend of €2.6 million (11%).

Table 2-7 – Premises Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Premises 5.0 5.4 5.4 5.3 5.4 23.8 26.4 2.6 11% Source: EirGrid

According to the TSO, a rent increase during PR4 has contributed to this overspend. The TSO has said it has benchmarked its premises costs and concluded that this increase was within market rates.

2.4.4 IT Costs

(Allowed €20.6 million, Outturn €22.3 million) Table 2-8 compares IT opex against the TSO’s allowance for the PR4 period. The TSO has forecast €12.3 million in IT costs compared to an allowance of €20.6 million. This represents an overspend of €1.7 million (8%).

Table 2-8 – IT Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance

€m % IT Costs 3.0 3.4 4.4 5.4 6.0 20.6 22.3 1.7 8%

Source: EirGrid The costs in this category cover:

support for hardware and software estates;

licencing of application upgrades;

patch and security updates, and software upgrades;

coverage in the case of hardware for faults; and

support costs for the operational service desk.



The TSO has said it assessed its IT applications against a ‘TIME’ model (tolerate, invest, migrate or eliminate) and identified scope for further efficiencies in future.

2.4.5 Grid Maintenance and Client Engineering

(Allowed €5.0 million, Outturn €3.3 million) Table 2-9 compares grid maintenance and client engineering opex against the TSO’s allowance for the PR4 period. The TSO has forecast €3.3 million in grid maintenance and client engineering costs compared to an allowance of €5.0 million. This represents an underspend of €1.7 million (33%).

Table 2-9 – Grid Maintenance and Client Engineering Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Grid Maintenance 0.7 0.5 0.8 0.6 0.7 5.0 3.3 -1.7 -34%

Source: EirGrid The costs in this category are below the allowance set for PR4, which we will consider in assessing the efficient PR5 allowances for this category.

2.4.6 Rates

(Allowed €3.0 million, Outturn €2.4 million) Table 2-10 compares opex spend on rates against the TSO’s allowance for the PR4 period. The TSO has forecast €2.4 million in rates compared to an allowance of €3.0 million. This represents an underspend of €0.6 million (21%).

Table 2-10 – Rates in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Rates 0.5 0.5 0.5 0.5 0.5 3.0 2.4 -0.6 -21% Source: EirGrid

The costs in this category are below the allowance set for PR4. However, no further information was provided by the TSO. In assessing the efficient allowances for PR5 we will consider the evidence on actual expenditure in PR4.

2.4.7 Research, Development and Demonstration & Promotion of Research

(Allowed €3.2 million, Outturn €2.5 million) Table 2-11 compares research, development and demonstration, and promotion of research opex against the TSO’s allowance for the PR4 period. The TSO has underspent relative to their allowance in both categories. Overall, the TSO has forecast €2.5 million in opex costs compared to an allowance of €3.2 million. This represents an underspend of €0.7 million (21%).

Table 2-11 – Research, Development and Demonstration Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %



Research, Dev. & Demonstration

0.5 0.6 0.3 0.2 0.2 2.2 1.8 -0.4 -18%


Total 0.7 0.7 0.3 0.4 0.4 3.2 2.5 -0.7 -21% Source: EirGrid

The costs in both categories are below the allowance set for PR4, which we will consider in assessing the efficient PR5 allowances for this category.

2.4.8 Insurance

(Allowed €1 million, Outturn €1.3 million) Table 2-12 compares insurance opex against the TSO’s allowance for the PR4 period. The TSO has forecast €1.3 million in insurance costs compared to an allowance of €1 million. This represents an overspend of €0.3 million (32%).

Table 2-12 – Insurance Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Insurance 0.4 0.1 0.2 0.3 0.3 1.0 1.3 0.3 32% Source: EirGrid

The TSO has not provided evidence that would allow assessment of whether the small (in €m terms) deviation between outturn costs and allowances is likely to be reasonable.

2.4.9 Selling and Advertising

(Allowed €0.5 million, Outturn €8.6 million) Table 2-13 compares selling and advertising costs against the TSO’s allowance for the PR4 period. The TSO has forecast selling and advertising opex of €8.6 million compared to an allowance of €0.5 million. This represents an overspend of €8.1 million (1617%).

Table 2-13 – Selling and Advertising Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Selling & Advertising 1.4 1.6 1.5 2.3 1.8 0.5 8.6 8.1 1617%

Source: EirGrid In 2015, a new External Affairs (EA) Directorate was established within EirGrid that is responsible for all external communications, stakeholder engagement and public consultation.8

The TSO has outlined that the directorate was established after the PR4 submission and as such, it is not separately identifiable in the PR4 allowances. Rather than seeking additional revenue for the EA Directorate, the TSO has reallocated opex internally to cover these costs

8 Some of the activities undertaken by the EA Directorate include: representing Ireland’s interests in Europe, including through briefings with Irish MEPs; managing all media queries to EirGrid; engaging with consumers and promoting the transparency of EirGrid’s work; and managing the development and/or submission of all EirGrid’s licence and regulatory reports.



(that is, it has spent less than its allowance in other areas but more than its allowance in this area).

Current information provided by the TSO does not enable determination of the proportion of costs in this category that are associated with the EA Directorate. It is also not possible to determine from the information provided where the costs of the directorate have been reallocated from.

Our recommendation with regard to Advertising and Selling costs is based on taking an in-the-round view of outturn costs against the opex allowance. This reflects a recognition that the TSO is ultimately responsible for how it delivers the required outputs for PR4. Overspend on Advertising and Selling comes against underspends in a number of other categories.

Noting the large increase in costs for Advertising and Selling, further clarity on the outputs delivered as a result of expenditure in this category would be required for setting the PR5 allowance (see discussion in Section 6).

2.4.10 Intercompany – Recharges

(Allowed -€18.7 million, Outturn -€15.6 million) Table 2-14 compares intercompany recharges against the TSO’s allowance for the PR4 period. The TSO has forecast €15.6 million in intercompany recharges compared to an allowance of €18.7 million. This represents an under-recovery of €3.1 million (17%).

Table 2-14 – Intercompany Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Intercompany recharges

-3.3 -3.2 -3.0 -3.0 -3.0 -18.7 -15.6 3.1 -17%

Source: EirGrid The intercompany recharges consist of facilities, payroll and corporate recharges between the TSO and the other companies in the EirGrid group. The TSO states that discrepancy between allowance and outturn comes from a level 1 re-organisation in 2015.

2.4.11 Other

(Allowed €0.0 million, Outturn -€0.6 million) Table 2-15 compares all other opex against the TSO’s allowance for the PR4 period. The costs presented here consist of foreign exchange movements and the adjustment of the outstanding project balance for HICP.

Table 2-15 – Other Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance €m %

Other 0.3 -0.5 -0.4 0.0 0.0 0.3 -0.6 -0.6 - Source: EirGrid

The TSO did not have a forecast allowance for this category. Overall, the TSO had a net saving of €0.6 million in opex costs across PR4 in this category.



2.5 Conclusion

Table 2-16 presents our recommendation for the PR4 ex-post allowance for the TSO. For controllable opex (assessed in this chapter), the recommended ex-post allowance is €242.4 million compared to the PR4 allowance the CRU had set (after adjusting for the TSO’s 2017 I-SEM request) of €242.4 million.

Table 2-16 – PR4 TSO Ex-Post Opex Allowance


PR4 Allowance

Actual / Forecast

Ex-Post Allowance Comment

Controllable Costs Staff and Staff Related Costs

147.9 138.9

Telecommunications 30.6 24.9 Premises 23.8 26.4 IT Costs 20.6 22.3 Professional Services 15.8 19.8 Contractors 9.8 6.5 Grid Maintenance & Client Engineering

5.0 3.3

Rates 3.0 2.4 Research, development & demonstration

2.2 1.8

Promotion of research 1.0 0.7 Insurance and Compensations

1.0 1.3

Selling and Advertising 0.5 8.6 Other 0.0 -0.6 Intercompany – Corporate Recharges

-18.7 -15.6

Total controllable opex 242.4 240.7 242.4 Recommend that the TSO retains the expected saving on total controllable opex.

Non-Controllable Costs Total non-controllable 279.5 499.2 499.2 Pass-through costs. Total opex 521.9 739.9 741.6

Source: CEPA Taken as a whole, the TSO’s controllable opex is projected to fall within the PR4 allowance. As such, we recommend that the ex-ante allowance is retained for these costs. The levels of actual and forecast opex across the different categories, as well as insight into the factors affecting these levels, were informative in developing our views on PR5 opex (see Section 6).



3. Review of PR4 Capital Expenditure: Transmission System Operator 3.1 Introduction

This section presents GHD’s review and analysis of the historic PR4 capital expenditure submission made by EirGrid as Transmission System Operator (TSO) for the years 2016 – 2020.

The GHD review has examined the Historic Business Plan Questionnaire (HBPQ) submitted by the TSO along with the supporting cost spreadsheets for capital projects as well as the accompanying narrative documents explain the factors affecting the TSO business during PR4.

With respect to the cost data provided in the HBPQ, values provided for 2016, 2017 and 2018 are actual values, with costs for years 2019 and 2020 being forecast values based on 2019 unit costs. All values have been converted to equivalent 2014 cost values for consideration in this report and comparison with the allowed PR4 revenues, based on the Harmonised Index of Consumer Prices (HICP) experienced during the PR4 period. The explicit HICP index values used as detailed in Section 3.2.4 of this report.

3.2 PR4 Background

Prior to reviewing the outturn capital expenditure incurred by the Transmission System Operator (TSO) for the PR4 price review period (2016-2020) it is worth considering a number of aspects related to:

the roles of the TSO and TAO (Transmission Asset Owner) in relation to the planning and delivery of new transmission infrastructure

some of the challenges and opportunities that the TSO has had to deal with through the PR4 period

changes in TSO business and working practices during PR4 that have impacted on the requirements for and ability to deliver capital investment in the transmission system

These aspects are now discussed in the following sub-sections.

3.2.1 Current TSO Responsibilities

EirGrid is the licenced TSO and Market Operator for Ireland and operates and develops the electricity transmission system. EirGrid, and SONI in Northern Ireland, act as the Single Electricity Market Operator (SEMO) for the island of Ireland through a contractual joint venture. The TSO is responsible for the planning, management and operation of the electricity transmission system which must be delivered in a responsible, efficient and effective manner to deliver positive outcomes for end customers. To achieve this, it must work in close partnership with the TAO.

ESB acts as the Transmission Asset Owner (TAO) and has physical ownership (through its subsidiary ESB Networks) of the electricity transmission assets and is responsible for carrying out maintenance, repairs and construction of the transmission systems.

The roles of the TSO and TAO are set out in the Electricity Act (1999 and as amended) and are reflected in the licence of each business as well as the 2006 Infrastructure Agreement which details the legal responsibilities of the TSO and TAO. A summary of the key activities and associated responsibilities of each party are summarised in Table 3-1.



Table 3-1 – 2006 Infrastructure Agreement Summary

Activity TSO TAO Identification of Need X Provision of Standard Costs X Selection of Optimal Solution X Obtaining Planning Permission X Obtaining Wayleaves X Outage Planning X Detailed Design X Procurement of Materials X Procurement of Resources X Management of Site Works X Commissioning X

Through the PR4 period, the TSO and TAO have utilised a range of formal schemes to drive collaboration and provide full project lifecycle learning and improvement. These schemes have included:

Joint Programme Management Office – Online document library and fortnightly meetings to enhance communications, focussing on addressing programme level issues that affect multiple projects.

Client Engineer Meetings – Six regional meetings a year to allow TAO project leaders to feedback to the TSO on issues, risks, delays, mitigation and associated topics associated with project delivery. For larger scale projects, monthly site meetings are also held.

Transmission Outage Plan – TAO, TSO and DSO produce and jointly interrogate outage requirements for following year project delivery from which the TSO seeks to determine the most efficient and productive set of outages. A draft plan is produced in December and a final plan issued in February. Throughout the year, sustained engagement between the licensees continues to consider all solutions and mitigation to ensure the maximum amount of project delivery and maintenance can be completed within a robust outage period.

Multi Year Development Plan – 5 year look ahead of proposed projects by the TSO to understand and forward plan outage requirements for large, long term or complex projects. Outage conflicts between projects can be better resolved through the planning phase, prior to delivery.

3.2.2 PR4 Challenges and Opportunities

The electricity transmission system in Ireland has experienced a number of challenges and new developments during the PR4 regulatory period (2016-2020). This includes:

The introduction of the I-SEM (Integrated Single Electricity Market) in 2017, with the first capacity market auction being held along with three others to date.

Continued growth in wind generation, with 621 MW increase in transmission connected generation over the period 2016 – 2018 (54% increase) along with a further 598 MW of distribution system connected wind generation over the same period (46% increase).

As a result of the increase in renewable generation installed during the period the System Non-Synchronous Penetration (SNSP) has reached 65%, one of the highest levels in the world.



By the end of 2018, 17 new transmission substations have been connected along with 62 km of new overhead line transmission circuits, 149 km of new underground cable circuits, 101 km of refurbished transmission circuits and a further 242 km of uprated transmission circuits.

System demand has increased by 8.8% by the end of 2018, mostly due to the increase of large data centres. Such customers typically require transmission connections to be delivered in challenging timeframes to meet their associated business requirements.

These, as well as other aspects, have influenced and impacted on the ability of the TSO to plan, develop and operate the transmission system during the PR4 period, and are discussed further in subsequent sections of this report where relevant to understand the extent of outturn capital expenditure.

3.2.3 PR4 Improvements

Following outcomes and conclusions of the PR3 price review, the TSO was provided the opportunity to make changes and improvements in its business practices during the PR4 period. This would allow the TSO to address a range of known issues, including the planning and delivery of large capital intensive transmission plant which during the earlier periods had been subject to delays in a number of critical cases. Additionally, the further development of renewable generation during PR4 was also expected to be result in the need for new working practices and initiatives in order to facilitate the timely connection of such generation to meet national renewable ambitions. Specific improvements and changes in business working practices implemented by the TSO during PR4 include the following:

1. Improved capital expenditure monitoring – Since the start of the PR4 period, the TSO (in conjunction with the TAO) has provided an annual Network Capital Expenditure Outturn Report to update project delivery progress more regularly.

2. The TSO has increased the level of engagement with external stakeholders and members of the public through a number of initiatives including the Framework for Development of the Grid publication and additional increased engagement forums for specific projects. The aim has been to increase awareness of the requirements to develop the transmission network and reduce some of the previous difficulties faced in developing large scale projects.

3. EirGrid has appointed specific Agricultural Liaison Officers (ALOs) to work closely with local communities where new transmission plant is proposed to be developed. This has increased landowner engagement and allowed the TSO to take into consideration more fully the potential impact on farming and agricultural activities that may be affected by transmission system development projects.

4. During PR4 a Community Gain Fund was established by the TSO to make payments to affected communities, landowners and members of the public who will be impacted by the installation of new transmission infrastructure. This has impacted in resolving localised issues and disputes associated with new developments.

5. Improve cost estimates – The TAO and TSO have collaborated earlier in the project identification process during the PR4 period as part of the pre-project agreement (pre-PA) phase. This process has resulted in forecast cost estimates in the PR4 period improving significantly from previous periods.

6. In order to manage a complex multi-year programme of transmission works a clear understanding is required as to the scope, timing and outage requirements for the projects within the programme. EirGrid has developed a Multi-Year Delivery Programme



(MYDP) 19 to manage the programme of transmission projects and the pipeline of new projects that will enter the programme. EirGrid and the TAO collaborate in the development of the MYDP to ensure that project data is accurate.

3.2.4 Network Cost Impacts

Although the issue of cost impacts and potentially increases in the transmission plant unit costs is principally an issue for the TAO, it is worth noting in the context of the TSO as the party responsible for planning and developing the transmission system and evaluating alternative investment options. As part of this role the TSO must be able to appropriately cost new transmission development projects and as such it relies on the data from the TAO for this purpose. Review of the actual Harmonised Index of Consumer Prices (HICP) experienced during the PR4 period, as show in Table 3-2 which indicates that average prices have only grown by around 2.77% from the end of 2015 until forecast to the end of 2020.

Table 3-2 – Annual HICP Rates during PR4

2015 2016 2017 2018 2019 2020 HICP Annual Rate, % - -0.21 0.26 0.72 0.88 1.12 HICP Cumulative Rate, % - -0.21 0.05 0.77 1.65 2.77

Whilst it is recognised that the HICP adjustment factors can only be considered a proxy for escalation rates associated with electrical network equipment, it is nonetheless considered sufficiently representative of the general cost trends within the electricity supply industry.

Note that the HICP rates have been used to modify the data provided by the TSO with respect to their HBPQ PR4 submission in order to convert historic annual outturn costs to 2014 equivalent values.

3.3 Allowed PR4 Revenues

As per the CER Decision on TSO and TAO Transmission Revenue for 2016 to 2020, document published on the 23rd December 2015, the allowed TSO revenues for the PR4 period for network and non-network capital expenditure are shown in the following tables Table 3-3 and Table 3-4.

Note that the quoted values are in 2014 price values.

The combined total allowed PR4 capital expenditure for the TSO for the period 2016 to 2020 is €148.17 m (in 2014 price values).

Table 3-3 – PR4 Allowed Network Capital Expenditure 2016-2020

Network Capex Allowed Revenues, € m Ongoing Projects 72.46 System Reinforcements 8.34 Shallow Connections 2.64 Asset Refurbishment 1.55 Minor Capital & Conflicts 0.33 DSO 0.05 Generic Projects 0.61 Subtotal 85.98 Customer Contributions (Factored) -3.57 Community Gain (Factored) 19.67 Client Engineering Capital Expenditure 6.51 Total 108.59



Table 3-4 – PR4 Allowed Non-Network Capital Expenditure 2016-2020

Network Capex Allowed Revenues, € m IS Infrastructure (Including Desktop) 4.95 Corporate Systems 3.52 Energy Management System – All Island Operations 3.19 EDIL / RCUC / AMP 1.45 TUoS / Settlement Metering 2.83 Big Data / Data Mining 1.76 DS3 / Smart Grids 4.81 Operations Charges – Network Codes 0.75 Telecoms 15.33 Facilities 0.00 Protection, Telecoms and Station Security 0.99 Total 39.58

3.4 Overview of PR4 Asset Delivery

Prior to reviewing individual transmission capital investment project progress during PR4 it is worth reviewing the expected outturn transmission assets that are planned to be delivered over the period, and in particular how this has changed since PR3. Table 3-5 summarises the expected outturn transmission assets to be delivered during PR4 split into six major groups:

Overhead lines – new lines and those that have been uprated or refurbished

Underground cables – new onshore and subsea cables

Substation assets – new transformers and switchgear installed

For each asset category further subdivisions are made according to transmission plant voltage.

The data shown in Table 3-5 has principally been taken from the TAO HPBQ submission with the exception of overhead line up rates and refurbishment which are not detailed in the TAO HBPQ. This data, which is for the 20016-2018 period only, has been obtained from Table 1 of the TSO PR4 Lookback V1.0.pdf document provided as part of the historic submission.



Table 3-5 – PR4 Asset Delivery Dashboard

New Overhead Lines, km

PR3 PR4 OHL Uprate / Refurb, km

PR3 PR4

400 kV 0 0 400 kV 0 0 275 kV 0 0 275 kV 0 0 220 kV 364 42 220 kV 0 40 110 kV 1105 236 110 kV 0 202 Total 1469 277 Total 0 242 Underground Cables, km PR3 PR4 Subsea Cables, km PR3 PR4 400 kV 0 0 400 kV 0 0 275 kV 0 0 275 kV 0 0 220 kV 11 34 220 kV 5 8 110 kV 60 139 110 kV 0 0 Total 71 174 Total 5 8 Transformers PR3 PR4 Switchgear PR3 PR4 400/220 kV 3 0 400 kV Bay 24 0 400/275 kV 0 0 275 kV Bay 0 0 275/220 kV 0 0 220 kV Bay 70 69 220/110 kV 9 7 110 kV CB (GIS) 141 22 400/110 kV 0 0 110 kV CB - other 126 81 110/38/20/10 kV 1 3 110 kV Isolators 499 0 Total 13 10 Total 860 172

From review of Table 3-5 it is evident that: In the traditional new build transmission plant i.e. new overhead lines, transformers and

substation switchgear, there is expected to be a reduction in the expected asset volumes to be delivered during PR4 when compared with PR3. This is particularly notable with regards to new overhead lines as well as substation switchgear, with the former most likely due to the ongoing difficulties in securing planning consents and approvals for new overhead lines. This may also have had some impact on the substation switchgear volumes as fewer delivered new overhead lines will require less substation switchgear investments.

Related to the above, is the significant expected volumes of overhead line refurbishment and uprates to be delivered during PR4. This is likely a consequence of the ongoing difficulties in relation to new overhead build which has out of necessity forced re-examined and consideration of overhead line uprating and refurbishment schemes in order to maintain and increase transmission system capacity.

It is also notable the significant expected increase in underground cables planned to be installed during PR4. Again, excluding project specific reasons, there is likely to be some correlation between the expected increase in underground cable installation and the reduction in planned new overhead line build due to ongoing planning and consenting difficulties.

Summarising the above, it is evident that the outturn PR4 transmission plant expected to be delivered during PR4 is substantially different from the plant volumes delivered during PR3 when more traditional investment solutions were developed and pursued by the TSO. Thus, when reviewing the expected outturn number and type of projects and associated costs to be delivered by the end of PR4 (end 2020) it is likely that similar changes to that noted above in asset volumes and types will also be apparent within some projects given that the initial PR4 proposed transmission investment plan was compiled towards the end of 2014.



3.5 Overview of PR4 Capital Expenditure

EirGrid have provided their outturn PR4 capital expenditure submission as part of the Historic Business Plan Questionnaire (HBPQ) in two parts:

The overall HBPQ submission spreadsheet – which details outturn PR4 non-network capital expenditure

A separate spreadsheet covering HBPQ tabs 6.3 and 6.4 which detailed outturn PR4 capital expenditure for network projects.

The total outturn TSO PR4 capital expenditure, including both network and non-network expenditure as well as respective TSO PR4 allowance, is shown in Figure 3-1 and Table 3-6.

Table 3-6 – PR4 Total Capital Expenditure 2016-2020

Project 2016, € m

2017, € m

2018, € m

2019, € m

2020, € m

PR4 Total

TSO Stage 1 Invoicing 12.10 41.96 7.59 7.37 16.56 85.58 TSO Adjustments 1.00 0.14 0.28 0.00 0.00 1.42 TSO Non-Network Capex 5.01 4.28 4.35 6.06 10.59 30.28 TSO Total 18.12 46.37 12.22 13.44 27.15 117.28 TSO PR4 Total Allowance 41.21 25.03 11.10 36.31 34.52 148.17 Total Variance -23.09 21.35 1.12 -22.88 -7.36 -30.86 PR4 Network Capex Allowance 30.86 15.24 3.89 29.79 28.81 108.59

Network Capex Variance -17.75 26.86 3.98 -22.42 -12.25 -21.58 PR4 Non-Network Capex Allowance 10.35 9.79 7.21 6.52 5.71 39.58

Non-Network Capex Variance -5.34 -5.51 -2.86 -0.46 4.88 -9.30

GHD and CEPA | Report for Commission for Regulation of Utilities - Consultancy Support for Electricity Transmission and Distribution Revenue Controls (2021-2025) | 22

Figure 3-1 – Outturn PR4 Total Capital Expenditure

-75

-50

-25

0

25

50

75

100

125

150

-25

-20

-15

-10

-5

0

5

10

15

20

25

30

35

40

45

50

2016 2017 2018 2019 2020

Cum

mul

ativ

e Ex

pend

iture

, €m

Capi

tal E

xpen

ditu

re, €

m

Network Capex - TSO Invoicing Network Capex Adjustments Non-Network Capex Total Variance Non-Network Variance Cum. Net CAPEX Outturn and Forecast Cum. Net CAPEX PR4 Allowance



From review of Figure 3-1 it is evident that:

Total TSO capital expenditure over the PR4 period is forecast to be around 20.8% (-€30.86 m) less than the PR4 allowance (€148.17 m).

The TSO has underspend the PR4 total capital allowance in three of the five years (2016, and planned 2019 and 2020 expenditure), with one further year (2018) being close to the annual allowed value.

Around 40% of the PR4 capital expenditure was incurred by the TSO in 2017, representing a broadly similar sum as the total capital expenditure incurred 2016, 2018 and planned 2019 expenditure.

The most significant underspend was in 2016, where the TSO underspend in comparison with their allowance by €23.09 m, although this was closely followed by planned 2019 expenditure where the underspend is forecast to be €22.88 m.

Comparing the total annual variance in outturn capital expenditure (grey bars in Figure 3-1) against the non-network variance in capital expenditure (red bars in Figure 3-1) it is evident that under and over-spend in non-network capital expenditure is not aligned with outturn variances in network expenditure. These aspects will be examined further in the following sub-sections.

3.6 PR4 Network Capital Expenditure

Table 3-7 presents the outturn PR4 network capital expenditure for both the TSO and TAO as well as the TSO PR4 network allowance and annual outturn variation.

Table 3-7 – PR4 Network Total Capital Expenditure 2016-20209

Project 2016, € m

2017, € m

2018, € m

2019, €m

2020, € m

PR4 Total

TAO Network Capex 163.92 143.42 199.62 151.95 154.25 813.16 Customer Contributions -9.42 -20.69 -13.43 -7.58 -16.72 -67.84 Interest During Construction -20.77 -15.69 -17.50 -13.19 -7.18 -74.33 TAO Adjustments 4.79 9.74 4.55 3.84 13.77 36.69 TAO Total 138.52 116.78 173.23 135.03 144.12 707.69 TSO Invoicing 12.10 41.96 7.59 7.37 16.56 85.58 TSO Adjustments 1.00 0.14 0.28 0.00 0.00 1.42 TSO Total 13.10 42.10 7.87 7.37 16.56 87.00 Overall Total 151.63 158.88 181.11 142.40 160.68 794.70 TSO PR4 Network Allowance 30.86 15.24 3.89 29.79 28.81 108.59

Network Capex Variance -17.75 26.86 3.98 -22.42 -12.25 -21.59

Figure 3-2 shows further detail of the TSO outturn PR4 capital expenditure as well as original PR4 network capital expenditure allowance i.e. splitting this into subcategories of ongoing projects, community gain factors, client engineering capex as well as the net customer contribution payments. Also shown in Figure 3-2 is the cumulative total PR4 network capital expenditure (dark green line) as well as the CRU approved PR4 network capital allowance (light green line).

9 Note that ESBN provided updated outturn cost for 2019 in a revised submission. This has been used in the TAO sections of this report but EirGrid did not provide an update and so any TAO costs in this section are as provided by Eir Grid in their submission.


Figure 3-2 – Outturn PR4 Network Capital Expenditure

-10

0

10

20

30

40

50

60

70

80

90

100

110

120

-5

0

5

10

15

20

25

30

35

40

45

50

55

60

2016 2017 2018 2019 2020

Cum

mul

ativ

e Ex

pend

iture

, €m

Capi

tal E

xpen

ditu

re, €

m

PR4 Projects PR4 Community Gain PR4 Customer Contribution PR4 Client Eng. Capex

Outturn TOS Invoicing Outturn Adjustments Cum. Net CAPEX Outturn and Forecast Cum. Net CAPEX PR4 Allowance



From review of Figure 3-2 it is evident that the net rate of expenditure on network capital projects was below the CRU PR4 allowance in three of the five years within the period, with only year 2017 capital expenditure being significantly above forecast. Overall, the variance across PR4 has been -19.9% of the network capital expenditure allowance i.e. an underspend of €21.59 m.

In relation to other aspects of the TSO historic PR4 submission observations to date include:

In relation to the high capital expenditure incurred by the TSO in 2017 (€42.1 m against a forecast of €15.2 m), around 86% of this (€36.0 m) was associated with the North-South Interconnector project. Further commentary on this project is included in Section 3.6.1.

From review of the detailed network capital expenditure provided in HBPQ worksheet 6.3 and 6.4 GHD has identified ten projects where the outturn capital expenditure has been significantly higher or lower than forecast. Further information and analysis of these projects is detailed in Section 3.6.2. Such projects include the North-South Interconnector as highlighted above, as well as the proposed Grid Link Cork Dublin 400 kV project which has now been cancelled and replaced by seven regional projects.

Further commentary in relation to the project with high variance in actual versus forecast PR4 capital expenditure is now presented in the following sub-sections.

3.6.1 CP0466 North-South Interconnector Project

The TSO has provided an update as to the status of the CP0466 project in their Appendix 1 – Historical BPQ Narrative document in response to Question 1.3. The current status of the project can be summarised as follows:

Application for planning consent submitted by EirGrid to An Bord Pleanala (ABP) in June 2015.

ABP oral hearing convened in March-May 2016, following which this was challenged in the high court but ultimately allowed to proceed.

In December 2016 ABP granted planning consent.

During 2017 three judicial reviews were sought to prevent EirGrid from implementing ABP planning consent. All three reviews were dismissed but one appealed to Supreme Court, which was subsequently reject in February 2019.

TAO Project Agreement also requirements planning approval and consent in Northern Ireland. This was initially granted in February 2017 but due to procedural issues was withdrawn in February 2019 and re-submitted for approval. This is may occur in early 2020.

Based on the above, the project still does not have full planning consent and approval in both Ireland and Northern Ireland and as such cannot move on the Project Agreement (PA) stage with the TAO. However, whilst this process is ongoing the TAO has commenced detailed design and advanced procurement works under the bespoke accelerated delivered model approved by CRU with the aim to minimise as far as possible further delays during the implementation phase.

As highlighted above, the North-South Interconnector project has continued to be the subject of significant delays during the PR4 period, continuing a similar trend seen in the prior PR3 spend period. The overall project costs expected to be incurred during PR4 (columns 1-3) are shown in Table 3-8 for both the TSO and TAO at three specific dates as follows:



1. The first forecast was provided as part of the PR4 forecast submission made during 2014.

2. The second forecast is provided with a reference date of January 2016, essentially at the start of the PR4 period.

3. The third forecast is the latest view and has been provided as of the end of 2019 as part of this TSO HBPQ. Note that this includes actual outturn costs for 2016 to 2018, plus forecast costs for 2019 and 2020.

Table 3-8 – Overall Project Costs

1 2 3 4 5 6

CP0466 Costs TSO PR4 TAO PR4 PR4 Total PR5 Total Project Total TSO Total

PR4 Forecast (End 14)

€32,464,788 €180,000,000 €212,464,788 - €212,464,788 €32,464,788

PR4 Forecast (Jan 16)

€55,500,000 €126,000,000 €181,500,000 €54,000,000 €235,500,000 €55,500,000

PR4 Estimate (End 19)

€42,505,979 €23,370,625 €65,876,604 €174,330,000 €240,206,604 €60,200,000

Difference Jan 16 – End 19

-€12,994,021 -€156,629,375 -€115,623,396 €120,330,000 €4,706,604 €4,700,000

Table 3-8 also shows the expected total PR5 project spend (column 4), the overall project total (column 5) and the overall TSO total capital expenditure through PR3 to PR5 (column 6).

From review of Table 3-8 it is evident that:

Overall PR4 capital expenditure has dropped significantly during the PR4 period, from €181.5 m at the start of the period to €65.9 m as per the latest forecast.

The TSO’s own capital costs have also reduced from the forecast at the start of PR4, being around €13.0 m lower than anticipated.

Total TSO project costs, whilst lower to date than forecast, are nonetheless expected to continue increase such that the expected value at the start of PR4 (€55.5 m) will be exceeded by circa €4.7 m by the end of the project completion. This increase is solely responsible for the increase in overall project costs from €235.5 m at the start of PR4 to the latest current total (circa €240.2 m) shown in Table 3-8.

The TAO is currently undertaking a constructability analysis to identify any land access and construction constraints that might affect the delivery of the project which will be presented back to the TSO via the Infrastructure Agreement process and will include revised costs (if applicable). At present though there has been no material change to the technical specification or composition of the project work expected to be undertaken by the TAO and hence overall TAO project costs have remained as per the original value anticipated prior to the start of PR4 i.e. €181.0 m. That said, any subsequent changes in outturn TAO project delivery costs at completion (expected during PR5) will need to be substantiated by the TAO, including any associated changes in outturn asset unit volumes, specification or costs in comparison with those planned at the start of PR4 (and included in the total costs referenced above).

The following table (Table 3-9) shows the current expected PR4 total costs incurred by the TSO at the end of 2019 along with the different categories of project costs.



Table 3-9 – TSO CP0466 Project Costs

TSO CP0466 Costs PR4 – End 19 TSO Staff Costs €8,100,000 External Consultants, inc Planning & Legal Fees €24,200,000 Pre-Project Agreement Wayleaves €200,000 Stakeholder Communications.& Engagement Costs €2,000,000 Contingency Costs €900,000 Indirect Project Costs €9,100,000 Overheads €1,700,000 TEN-E Grant (Credit) -€3,700,000 Total €42,500,000

As can be seen from Table 3-9 more than half (57%) of the total TSO expected capital expenditure incurred during PR4 will have been spent on employing external consultants, including those related to planning and legal activities.

To support and demonstrate that such external project costs have been efficiently incurred during PR4 the TSO has provide some additional information. This has confirmed that original the CP0466 project was conceived as two projects, with each supported by a set of external consultants. These were procured by competitive tender on a fixed price basis. Subsequently during pre-planning application works with An Bord Plenala (ABP) the project was combined into a single project planning application. During the various legal challenges to the ABP planning decision EirGrid rationalised the number of consultants to a single team who were required to reduced their rates by 10% and also undertake some work elements on a fixed price basis. For time and expense work activities the consultants were required to submit month reports for work completed on the agree activities. EirGrid then reviewed the monthly reports and the consultant performance prior to approving any invoices.

Based on the above information we are of the view that the TSO has applied prudent and appropriate cost controls and project management in relation to the necessary CP0466 external consultant project costs incurred during PR4, accepting that that need for the consultant input was largely out with the TSO’s control.

3.6.2 Other Projects with High Capex Variances

In addition to the review of the North-South Interconnector project GHD has also reviewed and requested additional supporting information from the TSO in relation to a number of other capital projects that were expected to be progressed / developed during PR4 and that have a high variance in outturn versus original forecast capex. This includes projects that have a high variance in actual € value compared with forecast at 2014 (variance > €250 k) as well as projects with a high variance in % terms (>50%). The specific projects that GHD identified and where additional information was requested from the TSO to explain the high variance between expected outturn and forecast capex are detailed in Table 3-10.



Table 3-10 – High Capex Variance Projects

Project PR4 Forecast

PR4 Actual*

Variance, € m (%)

CP0726 Moneypoint-Kilpaddoge-Knockanure 220 kV cable

€2,900,000 €1,107,056 -€1.792 m (-61.8%)

CP0737 West Galway (Knockranny) substation €850,000 €1,546,178 €0.696 m (81.9%)

CP0808 Maynooth 220 kV reconfiguration €407,000 €233,460 -€0.174 m (42.6%)

CP0850 Oweninny Power 1 & 2 €260,000 €515,859 €0.256 m (98.4%)

CP0868 Knockraha-Rafeen 220 kV line refurbishment.

€20,000 €337,514 €0.338 m (1587.6%)

CP0872 Microsoft €1,505,000 €2,073,424 €0.568 m (37.8%)

CP0932 Coomataggart Wind Farm €700,000 €376,091 -€0.324 m (46.3%)

CP0945 Great Island - Kilkenny 110 kV Uprate €20,000 €1,307,487 €1.287 m (6437.4%)

CP1034 Beenanaspuck-Tobertoreen Wind Farm Modifications

€475,000 €136,864 -€0.338 m (71.2%)

CP0800 North West (RIDP) €16,236,000 €0 -€16,236,000 (100%)

* Includes estimate for 2019 and 2020 Following the GHD request to the TSO to explain the significant outturn capital expenditure variance against original PR4 forecast, the TSO provided additional information as outlined in the following sub-sections.

CP0726 – Moneypoint – Kilpaddoge - Knockanure 220 kV cable Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“TSO capital expenditure on this project is expected to be circa 40% of planned by end of PR4 despite TAO expenditure being similar to planned. Please provide commentary as to why TSO expenditure is significantly lower than forecast for PR4, including commentary on project development timelines forecast for PR4 and expected at completion.”

The response received from the TSO was as follows:

“The original estimate for TSO costs (in the PR4 2014 submission) was €2.9 million. The TSO CA was originally for an overhead line solution which would have required a planning application for Strategic Infrastructure to An Bord Pleanala. Subsequently the proposed development was determined to be ‘exempt development’ on the basis of a cable solution and did not require planning permission. This resulted in a saving of €0.8 million on pre-PA TSO costs but does not affect the post PA TAO costs in the PR4 Period.

At TAO CA the estimated energisation date was Q3 2019. Currently depending on the local county council completing works on the L110 on schedule in May 2020 (a portion of the cable is due to be laid in this road), the project is expected to be completed in November 2020”

GHD Comment:



Whilst the change in technical scope from an overhead line solution to underground cable solution is understood the extent of the TSO cost savings outlined (€0.8 m) is still significantly less than the forecast TSO underspend in PR4 (€1.8 m). However, in response to a further GHD question the TSO has provided further information which confirms that the PA project value at March 2016 agreed between the TSO and TAO was €59.2 m, with €1.4 m cost for the TSO. On this basis the expected outturn expenditure at the end of PR4 (2020) is only €0.3 m lower than forecast at PA date.

In relation to the TAO project costs, outturn TAO costs during PR4 are €44,509,341 against an original 2014 forecast of €48,166,167. Additional TSO and TAO capital costs of €201,451 and €13,410,653 respectively are also expected in PR5, giving a current total expected project cost of €59,228,501. This compares with the combined 2014 PR4 forecast total costs for TSO and TAO of €51,066,667. Again, as part of further clarification, the TSO has confirmed that the current forecasted end of PR4 total project value (€59.2 m) remains as the PA agreement value (at March 2016). The additional total project expenditure (~€8.0 m) is predominantly associated with additional underground cable costs that were not included in the original project value developed in 2013. This includes: installation of 21 km of underground cable; project specific costs of wayleaving and directional drilling, substation works including switchgear protection and cable termination and telecoms works.

Taking due account of the above, we are satisfied that the expected outturn TSO project costs are reasonable and that the bulk of the reduction in outturn costs was associated with the revised project costs identified at PA stage (down from €2.9 m to €1.4 m). Whilst the TAO is expected to incur additional overall project costs, this is a consequence of the change in project specification to an underground cable solution which has allowed the project to progress to construction – something that may not have occurred had an overhead line solution been maintained. On this basis we are also satisfied that the outturn project specification (and associated TAO delivery costs) are reasonable.

CP0737 – West Galway (Knockranny) substation Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“TSO forecast costs for PR4 are expected to be circa 80% (€700k) above original PR4 forecast, with TAO costs also around 25% higher by end of PR4 than forecast. It is recognised that this new substation is important to facilitate renewables connections. Please provide details explaining why costs are significantly higher than forecast and any impact on the renewable generation projects concerned i.e. impact on WF commissioning dates?”


“CP0737 connected circa 200 MW of wind onto the system in 2016 and 2017. The transmission assets associated with this subgroup are significant and include two stations and circa 35 km of underground cable. The majority of the additional costs were associated with ensuring the required level of quality for the 12 bay Knockranny 110 kV and 4 bay Ugool 110 kV stations and associated transmission cables which required multiple revisions in design and substantial rework by the customer. These quality issues required extensive engagement with the customer on design and onsite to ensure that the asset would be fit for purpose over the lifetime. The total costs as shown are gross costs and do not take into account customer contributions. It is expected that an element of the additional costs incurred will ultimately be offset by such contributions.”

GHD Comment:



Whilst the broad explanation for the additional capital costs incurred by the TSO and TAO is understood, the total additional incurred capital costs are 34% higher than forecast, with TSO costs 82% higher than original PR4 forecast. GHD has requested further information from the TSO in order to understand the extent of the customer contribution to final costs that may be obtained. This has been confirmed as €3 m for the total project. Whilst it is unclear what the expected customer contribution may have been associated with the original PR4 forecast project cost it is likely that some if not all of the additional project costs incurred by the TSO (and TAO) during PR4 have indeed been offset by the expected customer contribution, given the scale of this value. On this basis it is therefore considered that the additional costs incurred by the TSO on this project are reasonable.

CP0808 – Maynooth 220 kV Reconfiguration Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“TSO outturn costs for PR4 are only expected to just over half that forecast for PR4 with TAO virtually zero, indicating that there has been delays. Please provide commentary to explain why TSO (and TAO) expenditure is lower than planned, including details of any project issues that have arisen during the period and how the TSO has attempted to minimise these and deal with any concomitant risks to the transmission system during the period.”


“At the time of the PR4 Submission in 2014 this was included as a concept project. The project was added to the Ongoing Project list (PR4 programme) during 2017 as reported in the 2017 outturn report.

CP808 Maynooth is undergoing analysis to ensure that a feasible and optimal solution is progressed to meet the need for the project. The current project is to upgrade existing Air Insulated Switchgear (AIS) infrastructure; however the required sequencing and associated outages present risks which significantly impact upon the feasibility of this option. TSO are currently exploring outage sequencing to inform an analysis on feasibility, and including consideration of requirement for comparative evaluation of an alternative Gas Insulated Switchgear (GIS) option. Following this, the project will proceed to planning and consenting. No immediate risk exists to the existing substation infrastructure which is coming towards the end of its useful life.”

GHD Comment: The original project costs forecast for PR4 at 2014 were €407,000 and €27,062,000 for the TSO and TAO respectively, yielding a total PR4 capital expenditure for CP0808 of €27,469,000. Expected PR4 outturn costs are €233,460 for the TSO and €99,894 for the TAO, significantly less than originally forecast. It is unclear if the originally envisaged project scope at the time of the 2014 forecast would have been fully delivered by the end of PR4 or whether some of the capex would also be spend in PR5.

The current forecast total project expenditure by the time the project is completed during PR5 is €56,358,502 (TSO €130.8 k and TAO €55.886 m in PR5). This is more than double the original 2014 PR4 forecast, albeit as outlined it is unclear if the 2014 PR4 forecast total would have represented the full project costs.

Additional information has been sought from the TSO to understand the total overall project costs and associated works envisaged at the time of the 2014 PR4 forecast as well as the project scope and works corresponding to the latest project forecast capital expenditure. However, in their response the TSO did not provide any expenditure values i.e. full expected project cost at start of PR4, despite being asked for this and also did not provide details of the



original expected project specification and the latest view. This is disappointing as it was hoped that a relatively simple question regarding original project costs and specification at the start of PR4 could have been provided, even as a broad value. This would have allowed GHD to understand if there had been any material changes during PR4 and also allow the TSO the opportunity to explain any such variations or changes. As it stands the scale of the incurred capital expenditure by the TSO on this project is relatively small, as is the additional spend for PR5 (€31.2 k factored). As a result, any potential inefficiency associated with the TSO planning activities on this project, even if this could be confirmed, is likely to be insignificant given the overall capital spend by the TSO during PR4.

CP0850 – Oweninny Power 1 & 2 Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“TSO expected outturn costs for PR4 are nearly double that forecast (additional €250 k,) with TAO costs nearly 75% higher than forecast. Please provide commentary to explain these issues, including any actions taken by the TSO to minimise additional costs, rework, delays or impacts on the transmission system.”


“CP0850 connected 137 MW of wind onto the system in June 2019. The majority of the additional costs were associated with ensuring the required level of quality for the cable circuit between Bellacorrick 110 kV and Sranakilly 110 kV stations which required multiple revisions in design and substantial rework by the customer. The customer encountered very poor ground (deep bog) which required redesign to avoid future quality issues. This required the TSO to engage with the customer at design stage and onsite to ensure that the asset would be fit for purpose over the lifetime. The total costs as shown are gross costs and do not take into account customer contributions. It is expected that an element of the additional costs incurred will ultimately be offset by such contributions.”

GHD Comment: The original total project costs 2014 forecast for PR4 were €260,000 and €1,000,000 for the TSO and TAO respectively, yielding a total PR4 capital expenditure for CP0850 of €1,260,000. The forecast outturn expenditure following project completion during PR4 is €515,858 for the TSO and €1,745,658 for the TAO, giving an estimated total project cost of €2,261,516, more than €1.0 m higher than forecast. Given that the project is now completed there are no further costs expected during PR5.

The TSO has identified that the gross values referenced above do not take into account prospective customer contributions which may offset some of the additional costs incurred. The TSO has been requested to provide this additional information and has confirmed that the total customer contribution as of 2018 is €1.1 m. As with project CP0737, the scale of the customer contribution under CP0850 is more than the associated outturn increase in project costs. Whilst it is unclear what scale of customer contribution may have been associated within the original forecast project value (€1.26 m), it is also likely as per CP0737 that some if not all of the additional project total costs incurred have been offset in part or whole by the current customer contribution. On this basis it is therefore considered that the additional project costs incurred by the TSO are reasonable.

CP0868 – Knockraha-Rafeen 220 kV line refurbishment Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:



“TSO expected PR4 costs for this project were €20,000 at the start of PR4 yet outturn expenditure is now forecast for PR4 of circa €338 k. Please provide commentary and explanation as to why a potentially simple asset refurbishment project has incurred significantly higher planning costs than expected, including any actions taken by the TSO minimise additional costs.”


“At the time of the PR4 Submission in 2014 this was included as a concept project – only initial high level scoping had been carried out at that time. At the start of the PR4 Period this project had moved into Stage 1 (an Ongoing Project), reached Project Agreement in October 2019 and has an estimated completion date of Q3 2020.

The 220 kV line is 45 years old and a decision to refurbish the asset was taken instead of designing and building a new line as this represents best value for the TUoS Customer.

The TSO updated forecast at Jan 2016 included provision for external consultants, EirGrid costs, Legal & Planning and Wayleaving management as it was identified that we may need to move one of the towers on the line, and this and the uprate had the potential to drive the requirement for a planning application. As a result the project scope included the need to complete an environmental appropriate assessment and to complete line assessment surveys to enable EirGrid to carry out a screen exercise to ascertain if the works would fall within the scope of exempted development.”

GHD Comment: The original project costs forecast for PR4 were €20,000 and €3,750,000 for the TSO and TAO respectively, yielding a total forecast PR4 capital expenditure for CP0868 of €3,770,000. The current forecast outturn PR4 capital expenditure for this project is €3,338,437 (TSO and TAO), albeit with the TSO PR4 spend being €337,514. The forecast outturn expenditure following project completion during PR5 is now €355,925 for the TSO and €3,988,028 for the TAO. This gives an estimated total project cost of €7,682,390, more than double the 2014 forecast PR4 value however it is unclear if the PR4 forecast total would have represented the full project cost. Additional information was therefore sought from the TSO to understand the total overall project costs and associated works envisaged at the time of the PR4 forecast as well as the project scope and works corresponding to the latest project forecast capital expenditure.

The TSO has confirmed that the outlined €3.77 m PR4 project cost was an un-scoped value made in advance of the TSO capital approval which required overhead line condition information. The TSO has indicated that the overhead line in question was found to be in a worse condition than expected and hence additional scope works were undertaken. This resulted in a project scope to replace line insulations and hardware on 41 towers, painting on 46 towers, foundation assessment on 71 towers, and the submission of a potential planning application and a resultant capital approval for the project in December 2015 of €8.2 m.

The overhead line refurbishment works was then progressed through the tower foundation Qualitative Risk Assessment (QRA) programme and the work carried out in 2018 and 2019, the outcome of which was that 9 tower foundations were found to need reinforcement with 55 shear blocks replaced as part of the project scope. This significant reduction in works meant that the planning consent was not required and disruption to farming activities was minimal, hence the expected project outturn costs at completion in PR5 (€7.68 m – as above) is less than the original capital approval.

Based on the above we are satisfied that the expected final CP0868 project costs incurred by the TSO (and TAO) are reasonable.



CP0872 – Microsoft Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“TSO expected PR4 costs are more than €0.5 m higher than originally forecast for PR4, despite TAO costs almost matching exactly forecast PR4 costs. Please provide explanation of the reasons behind the additional costs and the actions taken by the TSO to minimise these.”


“Both the TSO and TAO costs in PR4 are forecast to outturn c. €0.5 m than that forecast in 2014. The overall cost for CP0872 was uplifted in 2017 to reflect site purchase costs, modifications of the scheme, detailed scoping and tendering of the works.

The TSO and TAO have also entered into a legal agreement with one of the landowners which has allowed works to progress on the project.

The original forecasted completion date for West Dublin is now approximately 2 years later than forecast. The grant of planning was challenged in a Judicial Review which delayed the start of the project and construction of the 220 kV cable circuits has delayed the project by another year.”

GHD Comment: Original 2014 PR4 forecast costs for CP0872 were €1,505,000 and €90,300,000 for the TSO and TAO, giving a forecast total cost of €91,805,000. Forecast PR4 outturn costs are €2,073,424 and €90,894,199 respectively. Review of the PR5 submission also shows further project costs for the TSO (€167,373) and TAO (€25,205,801) in addition to the expected outturn spend during PR4. This yields a forecast total project cost of €118,340,797.

The TSO has confirmed that the above total (€118.3 m) represents the current and latest view on the total project costs. However, this latest view on costs represents a circa €27 m increase in total project cost from the value forecast prior to the start of PR4 (€91.805 m). The TSO has explained that the principal reason behind the increase in total project costs is due to the use of an EPC contractor to meet the customer connection timeline as well as additional scope of work items such as 110 kV and 220 kV cable work / terminations, additional protection remote end works, retirement on a short overhead line section (4 km 220 kV double circuit OHL), plus various contingency and EPC management costs.

On first review it could be concluded that the use of an EPC contractor is largely an avoidable cost, and had the TSO and TAO properly planned the delivery phase and scope of work for the project, then potentially some or all of the expected outturn over-spend could have been avoided. However, this ignores the significant challenges to the delivery timeline associated with the project planning consent being subject to judicial review, and associated scope of work revision, which in all likelihood has forced the use of an EPC contractor to expedite the construction work to allow the project to be completed as soon as possible. On this basis it is concluded that as the planning consent being subject to legal challenge is largely an aspect out-with the TSO (and TAO) control, then the overall increase in project costs and delay in project completion date was largely unavoidable. As such it is thus recommended that the additional costs associated with this project are allowed.

CP0932 – Coomataggart Wind Farm Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:



“TSO expected PR4 costs are just over half what was forecast for PR4 with TAO costs expected to <20% of PR4 forecast. Please provide details as to any delays associated with these works and any further reasons as to why costs are lower than forecast.”


“At the time of the PR4 Submission in 2014 this was included as a concept project – and the forecast was based on a typical non-contestable transmission build. The project ultimately proceeded on a contested basis. CP0932 was energised in October 2019, there were no delays associated with the project which were caused by TSO or TAO. The customer incurred delays due to planning consent and land access in addition to quality issues during the installation of cable ducting.”

GHD Comment: On the basis of the additional information provided by the TSO the reasons behind the reduction in TSO spend, and significant reduction in TAO spend are clear.

CP0945 – Great Island – Kilkenny 110 kV Uprate Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“TSO outturn costs for PR4 are expected to be circa €1.29 m higher than forecast. It is acknowledged that this project is likely to have been affected by the cancellation of the Grid Link Cork-Dublin 400 kV project which has now been replaced by seven regional projects (or which CP0945 is one). Please provide a summary of the capital costs and benefits i.e. network capacity, additional renewable generation facilitated, etc that were originally expected for the Grid Link Cork-Dublin project as well as each of the seven regional replacement projects. Please also detail what works were originally envisioned for CP0945 at the start of PR4 vs the current expectations for this project, including assets to be installed, expected forecast capex and opex, as well as any associated benefits provided and commentary against the key changes.”


“The TSO costs for CP0945 are estimated at €1.6 m with a current spend to date of €1.25 m it is not anticipated that the project will be overspent in PR4. Project Agreement is expected in December 2019 with energisation scheduled to be on target for Q2 2021. CP0945 was developed in 2017 following the decision to reassess Grid Link. The rationale for the project was based on a need to avoid the violation of the Transmission System Security and Planning Standards (TSSPS) as under certain conditions a thermal overload of the Great Island - Kilkenny 110 kV line was modelled. A line condition assessment also indicated a large number of structures needed to be refurbished. The capital approval for the project was therefore developed in 2017 to address these issues. The scope included the reconductoring of 49 km of the line and the replacement of 158 out of 232 polesets and associated substation works in Kilkenny 110 kV and Great Island 220/110 kV station.”

GHD Comment: The expected outturn capital spend during PR4 is €1,307,487 and €8,772,978 for the TSO and TAO respectively. This compares to the original 2014 forecast for PR4 of €20,000 and €6,066,667.

Review of the PR5 submission also shows further project costs for the TSO (€46,402) and TAO (€6,065,444). This yields a forecast total project cost of €16,192,311. From review of additional information submitted by the TSO relating to the Grid Link project it is evident that the forecast



total expenditure for this project in 2016 was €17.0 m. On this basis, the expected outturn total cost at completion in PR5 is within original 2016 baseline forecast and hence reasonable.

CP1034 – Beenanaspuck – Tobertoreen Wind Farm Modifications Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“Both TSO and TAO expected PR4 capital expenditure is less than one third of forecast. Please provide commentary as to the reasons for the lower capex including any delays as well as where this may have been due to third parties / customers outside of TSO control.”


“At the time of the PR4 Submission in 2014 this was included as a concept project. The initial cost forecast has been reduced following engagement with the customer and TAO at an early stage which has meant the customers requested modification was incorporated into their designs without having an effect on the programme. The Customer submitted a request for a modification to their connection agreement to change the generation type of their connection from Wind Farm to a hybrid connection with a mixture of wind and battery. The customer executed their revised connection offers in August 2019.”

GHD Comment: The expected outturn capital spend during PR4 is €136,864 and €1,442,787 for the TSO and TAO respectively. This compares to the original 2014 forecast for PR4 of €475,000 and €5,010,000. Review of the PR5 submission also shows further project costs for the TSO of €169,136 only, yielding a forecast total project cost of €1,748,787.

The explanation provided by the TSO with regards to the reduced project scope of work is accepted.

CP0800 – North West (RIDP) Based on the outlined underspend on this project during PR4 GHD posed the following question(s) to the TSO:

“Significant capital expenditure was expected on this project by the TSO (albeit only in 2019) as well as the TAO. The latest view is that no capital expenditure is now anticipated during PR4. Please provide details as to the status of this project i.e. cancelled, deferred, etc as well as the associated reasons including if the project is still expected to be developed during PR5.”


“It was recorded in the 2016 Baseline that the project was on-hold. A re-evaluation of the need in the area is under way and we do not anticipate the project will be developed to construction during PR5. The drivers for the need include future demand, which is dependent upon economic growth, and the location and scale of renewable generators. The scale of the need created by these drivers will influence the appropriate scale of any resulting network development. Any network development identified will be progressed in accordance with our governance and 6 step process.”

GHD Comment: The above explanation provided by the TSO is explains the lack of capital expenditure incurred during PR4 in comparison with the original 2014 forecast. However, the PR5 submission does include €6,000,000 for the TSO across 2024 and 2025 and €30,000,000 for the TAO in 2025, although it is noted that EirGrid have stated the project is “On Hold” in the HBPQ 6.3 & 6.4 submission table. On this basis it is recommended that the total capital value for this project is removed from the PR5 forecast allowance.



Grid Link & Grid West Projects Projects CP0732 Grid Link and CP0721 Grid West had significant planned capital expenditure forecast for PR4 during 2014. For Grid Link the forecasted TSO capital expenditure was €35.0 m with €97.5 m forecast for the TAO. For Grid West the forecasted TSO capital expenditure was €15.0 m and €224.0 m forecast for the TAO. In both cases outturn capital expenditure during PR4 is expected to be zero.

EirGrid have provided some details in their PR4 Lookback Narrative Document of the reasons behind the effective cancellation of these two projects.

CP0732 Grid Link In the case of the Grid Link project this was subject to an Independent Expert Panel to examine potential alternative solution options. However, before the panel could report EirGrid themselves identified that a Regional Solution composed of seven localised investment projects, as outlined below, would provide a more appropriate network investment solution. One of these projects CP0945 Great Island – Kilkenny 110 kV uprate was also included in the original 2014 PR4 forecast.

Great Island Wexford 110 kV Uprate (€15 m)

Great Island Kilkenny 110 kV Uprate (€17 m)

Moneypoint 400 kV Series Capacitor (€32 m)

Dunstown 400 kV Series Capacitor (€23 m)

Oldstreet 400 kV Series Capacitor (€29 m)

Cross Shannon 400 kV Cable (€81 m)

Wexford 110 kV Busbar Uprate (€10 m)

Only three of the seven projects replacing CP0732 have progressed significantly within the PR4 period – see Table 3-11 – with the other four only expected to incur minimal expenditure by the TAO during the period. The net impact of replacing the CP0732 Grid Link project with the seven regional projects is a reduction in forecast PR4 capital expenditure of €32.12 m for the TSO and €73.62 m for the TAO, although further expenditure of €13.71 m and €155.45 m will still be required for both entities in PR5.

Table 3-11 – Regional Solution Project Capital Forecasts

Project PR4 Forecast, € PR5 Forecast, € Project Total, € TSO TAO TSO TAO

CP0844 - Great Island Wexford 110 kV Uprate

712,851 12,547,902 0 0 13,260,753

CP0945 - Great Island Kilkenny 110 kV Uprate

1,307,487 8,772,978 46,402 6,065,444 16,192,311

CP0967 - Moneypoint 400 kV Series Capacitor

0 103,256 2,332,778 29,329,511 31,765,545

CP0968 - Dunstown 400 kV Series Capacitor

0 113,751 1,701,527 20,913,809 22,729,087

CP0969 - Oldstreet 400 kV Series Capacitor

0 118,532 2,011,241 25,710,945 27,840,718

CP0970 - Cross Shannon 400 kV Cable 0 0 7,622,321 73,426,586 81,048,907

CP0972 - Wexford 110 kV Busbar Uprate

856,131 2,223,796 0 0 3,079,927


Figure 3-3 – Summary of Regional Solution Project Capital Expenditure

0

10

20

30

40

50

60

70

80

90

100

0

1

2

3

4

5

6

7

8

9

10

CP0844 - GreatIsland Wexford 110

kV Uprate

CP0945 - GreatIsland Kilkenny 110

kV Uprate

CP0967 -Moneypoint 400 kV

Series Capacitor

CP0968 - Dunstown400 kV Series

Capacitor

CP0969 - Oldstreet400 kV Series

Capacitor

CP0970 - CrossShannon 400 kV

Cable

CP0972 - Wexford110 kV Busbar

Uprate

CP0844 - GreatIsland Wexford 110

kV Uprate

CP0945 - GreatIsland Kilkenny 110

kV Uprate

CP0967 -Moneypoint 400 kV

Series Capacitor

CP0968 - Dunstown400 kV Series

Capacitor

CP0969 - Oldstreet400 kV Series

Capacitor

CP0970 - CrossShannon 400 kV

Cable

CP0972 - Wexford110 kV Busbar

Uprate

Tota

l Pro

iject

Exp

endi

ture

, € m

TSO

Cap

ital E

xpen

ditu

re, €

m

TSO - 2016 Baseline TSO PR4 & 5 Total 2016 Baseline Total PR4 & 5

30/09/2020

30/09/2021

31/12/2023

31/12/202331/12/2023

31/12/2023

31/12/2020

08/10/201907/05/2021

31/08/2022

09/09/2022

28/09/2022

31/12/2022

01/07/2020



In terms of progress to date in delivering the regional project solutions to address the original Grid Link system requirements Figure 3-3 summarises the original forecast TSO and total project capital expenditure and the outturn capital expenditure on project completion. The left hand side of Figure 3-3 shows the TSO 2016 baseline capital expenditure forecast and the expected total at completion along with the original 2016 baseline project completion dates. The right hand side of Figure 3-3 shows the total project capital expenditure (TSO and TAO) at the original 2016 baseline as well as the forecast outturn at completion. The revised project completion dates are also shown.

Reviewing Figure 3-3 it is evident that:

1. The TSO forecast capital expenditure at project completion is lower than forecast for all seven projects.

2. The project with the lowest outturn in TSO expenditure is CP0844 (now completed) which has an outturn TSO spend of around 65% of forecast, with the CP0970 (Cross Shannon 400 kV Cable) forecasted to have outturn TSO expenditure around 90% of forecast. The average under-spend is around 20%.

3. In relation to project total expenditure, six of the seven projects are forecast to have total capital expenditure at completion lower than the original 2016 baseline forecast. Of these, five projects are forecast to have an under-spend averaging circa 5%, with the sixth (CP0972 – Wexford Busbar Uprate) having an under-spend on nearly 70%. The reasons for the significant underspend on CP0972 are due to a combination of factors, including:

the project not requiring planning consent, costs for which were included in the original TSO 2016 baseline forecast costs

a reduction in the required scope of work following detailed study,

A reduction in actual work costs compared with the standard unit cost estimates used in planning.

4. Overall, given the potential complexity of a busbar uprate scheme which typically is not a work activity where an extensive library of previous costs typical exists – most work scopes will be bespoke – it is not entirely surprising the outturn costs have been significantly lower than expected. It is typically only following detailed study and investigation that the exact nature of the work requirements for the busbar uprate scheme will be known, including any plant and equipment compatibility issues or other issues that may impact on the feasibility of the uprate scheme. Certainly such aspects would not be expected to be fully known at the planning stage.

5. Of the seven regional solution projects only one, CP0970 – Cross Shannon 400 kV cable – is now expected to have a total cost at completion above the original 2016 baseline estimate. The expected over-run is however small in the context of a circa €80 m capital project (€0.5 m, around 0.7%). The project is progressing with the proposed cable route now selected, which takes account of findings from marine and archaeological surveys. As such marine and ecological surveys are very often the reason for increase subsea cable route length, installation issues and cost mitigation measures, the fact that these have been completed with minimal impact on the project work means that the project can now proceed to construction and completion with a much lower risk of cost over-runs or potential programme delays.

6. Reviewing the latest project completion dates it is evident that all seven projects are expected to be completed ahead of the original 2016 baseline completion date. Two of the uprate schemes (CP0945 and CP0972) are expected to be completed around 4-6



months earlier than forecast in the 2016 baseline with the other five projects being completed around 11-16 months sooner than originally forecast.

In relation to the CP0732 project itself, the original estimated project total (TSO and TAO) capital expenditure was €758 m, with TSO costs of €26.7 m. These were the costs as of June 2011 at Capital Approval stage10. Converting to 2014 equivalent values11 yields an expected TSO cost of circa €27.4 m. The current spend to date on CP0732 is €11.9 m, however it is not clear whether this is the summated TSO cost over the PR3 & 4 period or an equivalent value in 2014 costs. The forecast PR4 and PR5 outturn costs for the TSO for the seven regional replacement projects is €16.3 m (in 2014 costs). Adding in the current spend to date, this gives a total TSO spend on the original CP0732 project plus the seven regional projects of €28.2 m, marginally above the expected TSO costs to be incurred for the original CP0732 project. However, whilst the TSO costs are slightly above the original Grid Link project forecast (by ~€0.8 m), the actual total capital expenditure on the project is significantly reduced from around €778 m (in 2014 costs) to around €200 m for the seven regional projects. In this context, the marginal over-spend in TSO capital expenditure when combining the original CP0732 project TSO spend plus the expenditure incurred by the TSO on the seven replacement projects is considered immaterial given the extent of total project capital expenditure savings by cancelling the original approved project.

However, the above statement largely only applies if the regional solution project delivers the same or similar benefits to the original (CP0732) project otherwise it may still have been better to invest in the original project. Reviewing the Grid Link report12 to the Independent Expert Panel this states that:

“The regional option will not provide significant additional capacity on the network but rather maximise the potential of the existing grid. The regional option does not develop new transmission network in the south east of the country” It is evident from the above statement, as well as other analysis included in the IEP report, that the regional solution project will not provide the same level of capacity benefit as the original Grid Link project. However, it should also be noted that the proposed regional solution does maximise the utilisation and usage of the existing transmission infrastructure which is arguably a more important objective than simply building new infrastructure that may not be utilised fully or to the most efficient level. It is also worth noting that even if the original Grid Link project still becomes necessary to develop, on a Net Present Cost (NPC) basis it will only need to be deferred for 8 – 10 years to allow the capital expenditure on the regional solution projects to be incurred and still result a NPC no worse than investing in the Grid Link during PR4. Analysis and commentary provided by the TSO has indicated that there is no likelihood of the original Grid Link project being required in the short to medium term. On this basis it is concluded that effective cancellation of the Grid Link project and replacement with the regional project solution is effectively a no or low regret decision. This is because, even if it becomes necessary to reinitiate the Grid Link project at some point in the future, after the seven regional projects have been commissioned, the overall costs to the end customer will likely be no worse than if the Grid Link project had been implemented to begin with. Furthermore, given that there is no expectation that the Grid Link project will be required in the short to medium term, or even at all, in all likelihood the overall costs to end consumers will much lower than if the project had been implemented as per the original TSO plan. As regards the aborted TSO capital expenditure on the Grid Link project, the total planning and Stage 1 costs now envisaged for the seven regional

10 These values were obtained from the EirGrid document “200109 – PR5 Grid Link Regional Solution CRU Query.pdf” 11 Using June 2011 HICP value of 0.974 12 Grid Link – Report to IEP – Final August 2015.pdf



projects and the spend to date on the Grid Link project are broadly similar to the total Stage 1 costs envisaged for the Grid Link project back in PR3. As result, the decision to cancel the Grid Link project and replace with the seven regional projects has had a broadly neutral impact on the end cost to consumers associated with the TSO Stage 1 planning activities.

CP0721 Grid West In the case of the CP0721 Grid West project this was also subject to an Independent Expert Panel which at the time of reporting (29th April 2015) confirmed the suitability of EirGrid proposed project scheme. However, by 2017 and following a CRU decision (CER/16/284) which enabled contracted generators to hand back transmission capacity the amount of wind generation seeking connection in the North West Connaught region significantly reduced i.e. from 450 MW to 301 MW. As a result, the original CP0721 project was cancelled as the TSO identified that it was no longer necessary to build a new 400 kV overhead line and that the future system requirements could met by a single project (CP0816 North Connaught Line).

The replacement project CP0816 had itself a 2014 forecast capital cost of €3.50 m for the TSO and €16.25 m for the TAO as detailed in the HBPQ13 spreadsheet, against which actual outturn capital spend by the end of PR4 is forecast to zero. Information provided by the TSO in response to GHD queries indicates that the project did not exist at the start of PR4 as the Grid West project was still in existence until 2017. This broadly lines up with the details of the GHD review which identified that the first forecast capital expenditure by the TSO under the PR4 forecast was expected to be in 2017, although as above no actual expenditure has been incurred.

This project does however have planned capital expenditure of €14,850,000 for the TSO and €62,146,405 for the TAO during PR5. Further information from the TSO has confirmed that the project (CP0816) is in current step 4 (of the six step process) and both OHL and UGC scopes are still under review for a circuit route from Moy to Tonroe. The project scope will therefore either require a new build of a 110 kV OHL circuit (430 mm2 ACSR) with an estimated length of approximately 58 km or a new build of a 110 kV UGC circuit (1600 mm² Al XLPE) with an estimated length of approximately 58 km. In addition, the project will require for both options:

the redevelopment of the existing Tonroe 110 kV substation to AIS enhanced "C-Type" Outdoor Station (Strung Busbar) including two line, one transformer and one spare bay;

the installation of new 110kV AIS line bay in Moy 110kV substation as part of the new circuit;

the uprate of 110 kV OHL circuit from Tonroe to Flagford (430 mm2 ACSR) with a length of 32 km; and

the uprate of 110kV AIS line bay in Flagford 110kV substation as part of the associated uprate.

In a similar manner to the cancelled Grid Link project, the replacement of the Grid West project with the North Connaught line project is not expected to deliver the same overall benefits in terms of created transmission network capacity. For the original 400 kV Grid West project the Independent Expert Panel document14 indicates the created capacity would be approximately 1,580 MVA for a capital cost of €239 m, with the 220 kV options creating capacity of 600 MVA for capital costs potential up to €249 m depending on the extent of undergrounding required. In comparison, the proposed 110 kV line scheme is only likely to create additional transmission network capacity of circa 300 MVA. The expected total TSO and TAO PR5 project cost is circa

13 See project CP0816 detailed in Tab 6.3 & 6.4 in Appendix 2a – Historical BPQ (6.3 6.4).xlsx 14 Summary-of-IEP-Report-Grid-West.pdf



€77.0 m. With the handed back network capacity, the CP0816 project will effectively create 450 MW (MVA) of transmission capacity for €77.0 m, effectively 5.84 MVA / €1 m. In comparison, the original Grid West 400 kV project would have create network capacity of 6.61 MVA / €1 m, only marginally higher, and this assumes that the project could actually be delivered for this budget. If capital costs were to increase in the original Grid West project by around 13% (€32 m), for example due to the requirement for underground cable, then the resultant capacity / € ratio would be the same as the planned CP0816 project. In comparison the 220 kV options detailed in the IEP document present the least attractive options, even if considering the circa 150 MW of connection capacity freed up through the CRU review process i.e. network capacity created would be 3.0 MVA / €1 m. On this basis, the current proposed CP0816 project appears to offer the best value for money in terms of transmission network capacity created whilst also being deliverable and accepting of potential environmental constraints.

Overall then, after taking account of the planned CP0816 project capital expenditure in PR5 and anticipated project benefits, the impact of the cancellation of the CP0721 Grid West project in PR4 is a reduction in total TAO planned capital expenditure of circa €162 m. For the TSO, the forecast PR5 capital expenditure on CP0816 broadly equals the forecasted TSO expenditure on the Grid Link CP0721 project, hence the overall impact is broadly neutral.

3.6.3 Projects Not-Progressed in PR4

The following section analyses the capital projects which were forecasted for expenditure in PR4 and no expenditure has been recorded within the PR4 period. These can be considered known projects (at the start of PR4) that have not progressed during PR4. Figure 3-4 provides a summary of these 30 ‘non-progressed’ projects15 with respect to the project category assigned by the TSO. The left chart provides a breakdown by total combined TSO and TAO forecasted capital expenditure (prior to PR4) with the right chart providing a breakdown by forecast expenditure for the TSO only at the start of PR4.

Figure 3-4 – Non-Progressed PR4 Project by Capital Expenditure

With respect to the 30 project shown in Figure 3-4, broadly a third each are associated with System Reinforcement and Asset Refurbishment projects, with the remainder being associated with DSO projects or New Connections. The total value for the System Reinforcement projects (11) is €277.3 m for the combined TSO and TAO PR4 forecast capital expenditure, although this is dominated by the Grid Link and North West RIDP projects which contribute around 75% of the total i.e. €132.5 m and €74.3 m respectively. New connection projects although having the

15 Note that TAO HBPQ submission has a slightly different number (34) of projects not progressed during PR4. The additional projects classified as non-progressed in the TAO analysis are projects with TSO only PR4 expenditure.



lowest number of projects (3), contribute the second highest total combined project capital value (€242.3 m) although almost all of this capital value (€239.5 m) is associated with the CP0721 (Grid West Electricity Transmission Scheme) project.

Of the 30 known but non-progressed projects during PR4, these three schemes are most notable, accounting for €446.3 m of forecast expenditure but with no outturn expenditure. These projects are large scale 400 kV line projects and it is appreciated that the nature of the projects can be significantly affected by access constraints or changes in project drivers which can delay or defer project delivery. It is therefore important to ensure that any alternative spend (where applicable to overcome constraints) or deferred spend is considered in the context of achieving the necessary goals in a timely and efficient manner.

With respect to CP0732 (Grid Link 400 kV), during the course of PR4 this project was replaced by seven regional solutions which included 110 kV circuit uprates, 400 kV series compensation and 400 kV subsea cable installation. One project (CP0945 – Great Island – Kilkenny 110kV Uprate) was forecasted and progressed as planned, with six new projects added. The outturn expenditure of these projects is currently €26.7 m (TSO €2.8 m) with all projects categorised as ongoing. Further expenditure of €13.7 m for the TSO and €155.4 m for the TAO is forecast for these seven regional projects in PR5.

Similarly, with respect to CP0721 (Grid West), this has been replaced by CP0816 (North Connaught Line) which was a forecast project, as a reduction in expected wind generation was experienced, allowing the smaller scale project in isolation to be sufficient. As detailed in the previous sub-section, no expenditure has been incurred on CP0721 (Grid West) by either the TSO or TAO prior to the change in project, limiting any inefficient expenditure that could have occurred.

3.6.4 Projects with Zero Forecast Spend

Reviewing the submitted TSO HBPQ submission there are a 108 projects where there was no planned TSO capital expenditure expected during the period, but there is planned outturn expenditure of €15.39 m for the TSO and €108.8 m for the TAO. The top ten highest value projects, which have a combined TSO forecast PR4 capital expenditure of €14.89 m are shown in Figure 3-5, in descending order of PR4 capital expenditure incurred by the TSO.


Figure 3-5 – Top Ten Projects with Highest Un-forecast Capital Expenditure

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

5,500,000

6,000,000

CP0844 Great Island -Wexford 110 kV Uprate

CP0606 KnockacummerWF Permenant

Connection

CP0747 Maynooth -Ryebrook 110kV line

uprate

CP0197 Cushaling-Thornsberry 110kV Line -

New 110kV Line

CP0972 Wexford 110kVBusbar Uprate

CP0883 BallyvouskilKnockanure 220kV Line

Uprate

CP0596 Kinnegad -Mullingar 110kV Circuit

CP0501 Clashavoon-Dunmanway 110kV Line -

New Line

CP1029 Intel 220 kVCP0585 Laois Kilkenny (Coolnabacky) 400kV

Station – New Station & Associated Lines & Station

Works

Proj

ect

Capi

tal E

xpen

ditu

re, €



In relation to the projects shown in Figure 3-5: Of the top ten projects which were added or had zero forecast TSO expenditure in PR4,

three (CP0585 Laois - Kilkenny, CP1029 Intel 220 kV and CP0501 Clashavoon – Dunmanway 110 kV line) have accounted for around 3/5 of the total TSO spend on these projects.

The CP0585 Laois – Kilkenny project is commented on within the TSO PR4 BPQ submission. The project was originally granted Planning Permission in April 2014, however this was then subject to Judicial Review in late 2014 which was dismissed in early 2015. At this point it would have been expected that TSO Stage 1 input would largely cease following the commencement of the Infrastructure Agreement process undertaken with the TAO. This process commenced in June 2016, following which the original Planning Permission was amended to facilitate an overhead line diversion for a key substation. There were also delays and land access issues with the Coolnabacky 400 / 110 kV substation which results in additional stakeholder engagement activities by the TSO (in conjunction with the TAO) which has continued into 2019.

Although the CP0585 project is forecast to incur TSO capital expenditure that was not forecast at the time of the PR4 submission, on commencement of the PR4 period (January 2016) revised forecast costs for the project were developed of €6.8 m for the TSO and €98.8 m for the TAO, giving €105.6 m in total. Of this the total, €80.9 m was expected to be spent in PR4 and €24.7 m in PR5. Reviewing the latest forecast project information as of October 2019, the expected PR4 expenditure is €5.4 m for the TSO and €15.9 m for the TAO. Expected additional PR5 expenditure is now €1.2 m for the TSO and €82.4 m for the TAO. This gives an expected final project total over PR4 & 5 of €104.9 m. Thus, despite the delays faced by this project which has resulted in forecast PR4 and PR5 spend essentially swapping i.e. now €21.3 m in PR4 and €83.6 m in PR5 vs €80.9 m in PR4 and €24.7 m in PR5 originally, the overall project total is actually forecast to marginally reduce by €0.7 m.

In summary, the notional un-forecast TSO capital expenditure shown in Figure 3-5 for this project was largely as a result of significant uncertainty surrounding this project during late 2014 when the initial forecast was developed. However, by the start of the PR4 period (2016) the uncertainty surrounding project planning and consenting issues had been addressed and as such comparing the expected project total expenditure at this time with the latest outturn the overall totals are almost identical. There has however been delays and slippage against the forecast delivery programme during PR4 – as detailed above – which has resulted in the completion of the project being delayed further into PR5. These delays are arguably a legacy of the historic processes adopted by both the TSO and TAO in relation to infrastructure planning, development and stakeholder interactions and as such are considered less likely to occur in future projects as a result of the new processes put in place by the TSO.

The CP1029 Intel 220 kV project is a customer connection driven project that required a new 220 kV connection with underground cables to be developed in ambitious timescales and was not known about at the time of the original PR4 forecast, developed in 2014.

The CP0501 Clashavoon – Dunmanway 110 kV overhead line project received Capital Approval in 2006 to address the connection of 1300 MW of renewable connections in the South West and reinforce security of supply in N-1 scenarios. The project also resolves overload issues in the area under specific conditions. The TSO has confirmed that the construction is essentially complete for the full overhead line, however the project has been delayed due to continued land access issues with one landowner. The TSO is



continuing to engage with all parties to resolve the issue. Assuming agreement energisation could complete in early 2020.

For the CP0596 Kinnegad – Mullingar 110 kV circuit this project was energised in March 2017 and the project involved 24 km of 110 kV overhead line and 1 km of underground cable. The project spanned 65 separate land holdings. The project is expected to reach financial close by Quarter 2020 as land easements are being finalised and agreed with landowners.

The CP0883 Ballyvouskil Knockanure 220 kV line project is an uprate of 60 km of 220 kV overhead line on the mid-section of the existing Clahavoon- Tarbert 220kV line. The project involves two local authorities and crosses 3 areas of Special Areas of Conservation under the EU habitats directive. Capital Approval was obtained in June 2014 the need for which was to accommodate the renewable generation in Co Kerry and Co Cork which was facilitated by the connection of the Knockanure, Ballynahulla and Ballyvouskill 220/110kV substations. Project Agreement was reached in 2018 and construction works began in August 2019. An agreement was reached with the IFA to compensate landowners. The project was expected to be energised in 2017 however due to land access issues the project is now expected to complete in November 2021.

The CP0197 Cushaling – Thornsberry 110 kV New Line project has incurred capital expenditure during PR3 and PR4. This project obtained capital approval in 2004 for 31 km of 110 kV overhead line. A 13 km section of the line was energised in 2013 when Mount Lucas 110 kV windfarm was commissioned, leaving 18 km of the line to be completed.

The project has been delayed due to poor ground (peat) conditions, challenges agreeing land access, High court proceedings and a requirement to redesign a section of the line to use underground cable to accommodate a request from 6 landowners. Full access to all lands was achieved in July 2018 with the remaining construction works currently underway. Energisation is expected in April 2020. This project is a system reinforcement for the area and key drivers associated include the Mount Lucas Windfarm which was energised in 2013.

The CP0747 Maynooth – Ryebrook 110 kV overhead line upgrade was energised in August 2015 following legal proceedings, the costs for which have not been resolved. The project is expected to reach financial close in Quarter 1 2020.

For the CP0606 Knockacummer WF Permanent Connection project the Knockacummer Windfarm (100MW) was energised on 27/10/18 with completion of the contestable 19 km 110 kV cable from Ballynahulla 220 kV Station to Glenlara 110 kV Station. Associated non-contestable works were also undertaken at Glenlara, Ballynahulla and Knockacummer Stations. On energisation the existing Knockacummer 110 kV Station, existing Glenlara-Knockacummer 110 kV cable and existing Glenlara 110 kV Station transferred from DSO to TSO operational control, with Knockacummer Windfarm Ltd. also transferring from being a DSO to a TSO Customer. This project is currently in the Pass-through Settlement and Asset Transfer phase. The project is expected to reach financial close in Q2 2020.

Two of the projects, CP0972 Wexford 110 kV Busbar Uprate and CP0844 Great Island – Wexford 110 kV Uprate are part of the replacement projects for the Grid Link project and have already been discussed.

From review of the above information it is evident that all of the reviewed projects have justifiable reasons explaining why there was not expected to be any PR4 capital expenditure but



such expenditure has nevertheless been incurred and should be allowed. In some cases this is because the projects are new (CP1029) or were substitutions for other projects (CP0972 and CP0844), however in most cases this was because of delays in completing projects due to land access, construction or legal issues, or a combination of all three. Particularly notable is the CP0197 project where original capital approval was given in 2004 and which is expected to be energised in 2020, taking effectively 16 years to build 31 km of 110 kV overhead line (it is noted that 13 km was energised in 2013).

Going forwards, whilst the reasons behind project delays have to some extent been discussed, noted and commented on in previous price review periods, it is perhaps most relevant that the TSO has introduced new working practices and procedures in PR4, including the introduction of ALO’s and CLO’s which aim to streamline planning, consenting and development issues in PR5. Given the scale of the national renewable energy targets it will be essential for these revised processes and procedures to deliver a step change in infrastructure development timescales if the ambitious renewable targets are to be met.

3.7 PR4 Non-Network Capital Expenditure

The following figure (Figure 3-6) presents the outturn PR4 non-network capital expenditure for IT systems and facilities costs incurred by the TSO, split into the main non-network expenditure categories. Also shown in Figure 3-6 is the cumulative total PR4 non-network capital expenditure (brown line) as well as the CRU approved PR4 non-network capital allowance (red line).


Figure 3-6 – Summary of Non-Network PR4 Capital Expenditure per Category

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2016 2017 2018 2019 2020 PR4 Total

Cum

mul

ativ

e Ex

pend

iture

, €m

PR4

Out

turn

, €m

IS infrastructure (€m) Corporate systems (€m)DS3/smart grids (€m) Energy management systems - all island operations (€m)EDIL, RCUC and AMP (€m) TuOS / settlement / metering (€m)Big data and data mining (€m) European network codes (€m)Facilities Non-network telecoms (€m)PR4 Outturn PR4 AllowanceAnnual PR4 Allowance



From review of Figure 3-6 it is evident that TSO Non-Network capital expenditure during PR4 is expected to outturn €9.30 m or 23.5% lower than the original PR4 allowance (€39.58 m). Spend has been broadly similar across most years of PR4 i.e. between €4.2 m and €6.1 m per annum during 2016 to 2019, with only forecast 2020 costs standing out. In the case of the final year of PR4 (2020) the forecast outturn costs are expected to be more than double (€10.59 m) what has been spent in the individual years 2016 – 2018.

Table 3-12 below shows the outturn PR4 non-network capital expenditure by category as well as the expected variance at the end of the period in comparison with the original PR4 allowance. Note that the TSO also has similar table in their PR4 Lookback narrative document (Figure 6 on page 101) however that table has costs that are shown as actual outturn values with the stated allowance values having been converted from 2014 values based on HICP.

Table 3-12 – Non-Network PR4 Capex Outturn

Work Area PR4 Allowance, € m

PR4 Actual, € m

Variance, € m

IS infrastructure 4.950 5.907 0.957 Corporate systems 3.520 2.956 -0.564 Protection, telecoms and station security

0.990 - 0.990

DS3/smart grids 3.850 3.443 -0.407 DS3/smart grids 0.960 - 0.960 Energy management systems - all island operations

3.190 0.888 -2.302

EDIL, RCUC and AMP 1.450 0.566 -0.884 TuOS / settlement / metering 2.830 0.249 -2.581 Big data and data mining 1.760 0.975 -0.785 European network codes 0.750 0.73 -0.020 Facilities 0.000 4.946 4.946 Non-network telecoms 15.330 9.621 -5.709 Total 39.580 30.280

(33.48)* -9.30 (-6.10)*

* These values include the €3.2 m deferred to PR5 included in the EirGrid HBPQ submission Reviewing Figure 3-6 and Table 3-12 together the following observations are made:

1. Of the expected outturn PR4 expenditure (€30.28 m) nearly a third (€9.62 m) is associated with non-network telecoms. However, given delays in the installation of associated equipment i.e. new / replacement RTUs, migration to IP based network, etc actual outturn PR4 expenditure is around €5.71 m lower than originally forecast. An example of the reduced delivery within this category is replacement RTUs, where 2 were replaced in 2018, 6 were expected to be replaced in 2019 following which the TSO stated that the replacement programme will continue “at the rate of at least seven RTUs per year”. However, this will equate to 15 (2 + 6 +7) of the PR4 period against the 25 that were anticipated to be replaced. Additional capital expenditure of €7.9 m is included in the TSO’s PR5 submission for further non-network telecoms work including further RTU replacements (eight per annum). However, given the delays in replacing RTU’s to date it is unclear whether this proposed further PR5 expenditure (and associated work volumes) is actually deliverable or will prove equally challenging in PR5. Also, it is unclear what has happened to the 10 further RTUs that were expected to be replaced during PR4 from a



capex perspective as no carry-over costs have been netted off of the PR5 non-network capital request for non-network telecoms (as per the EMS expenditure see below).

2. The underspend on non-network telecoms has been largely offset by increased spend on facilities, where €4.95 m was spent against a category that had zero allowance. Of this €4.95 m more than half (€2.8 m) was spend on refurbishment of the Oval Head Office, with the remaining spend on “various other critical projects which were required due to equipment coming to end of life, replacement cycles, etc.”

3. In relation to the head office refurbishment the TSO has outlined how the work was procured through its Facilities Management Vendor to ensure value for money. A breakdown of the high level work scope has been provided which broadly covers the office redesign and fit-out on specific floors. However, the driver for undertaking the works is still unclear i.e. was this driven by a need to free up additional floor space for additional staff, as a result of any statutory / legal obligations related to employee HSE or poor condition office assets at end of life, etc.

4. For the other critical projects which were required, the TSO has provided further information in a response to a specific GHD query. The works included works in general office equipment, datacentre & IT systems, as well as building works e.g. HVAC systems, lift works, etc. The total itemised costs for these works is circa €0.71 m. Whilst this goes someway to explain the additional €2.15 m of capital expenditure for these works, this still leaves €1.44 m which has not been explained.

5. Without further information from the TSO to explain the need for both the office refurbishment and “other critical projects” it is difficult to determine if the associated capital costs have been efficiently incurred. It is therefore recommended that a notional proportion of the capital expenditure under Facilities is disallowed until such time as the TSO can fully explain the underlying need for the works. This is suggested to be 50% of the current €4.95 m spend, that is €2.48 m should be disallowed from the current TSO PR4 capital expenditure. To support the outturn PR4 costs the TSO needs to clearly articulate the underlying drivers behind this investment and provide a more detailed breakdown of the expected costs incurred through PR4 with clear linkage to statutory, legal, HSE, or building lease requirements that mandate this work to be undertaken.

6. There is also forecast to be a large under-spend against All Island Energy Management System expenditure during PR4 i.e. an underspend of €2.30 m against an original allowance of €3.19 m. Review of the EirGrid PR4 Lookback document has identified that the TSO paused some work items during I-SEM activities where the full scope of works was not known at the start of PR4. Whilst this is considered a prudent approach and ensures that capital expenditure is only incurred when underlying requirements are fully known, it also means that not all of the outlined underspend can be considered as an efficiency saving as some is likely to be required in PR5. The TSO has themselves considered this as they have identified a separate “Deferred to PR5” line item (€3.2 m) in their own Non-Network Capex summary table16 which is largely composed of the €2.3 m underspend in the planned EMS expenditure during PR4. The TSO has confirmed that this expenditure has been netted off of the PR5 request.

7. Similarly, there is also forecast to be a large under-spend against the TUoS / Settlement / Metering investment categories i.e. €2.58 m underspend against an original allowance of €2.83 m. Again, review of the EirGrid PR4 Lookback document has identified that the full scope of works was not known at the start of PR4 and a number of work items were

16 Figure 6 on page 101 of the PR4 Lookback Narrative Document



deferred until the final I-SEM changes and DS3 programmes were known. Similarly to the underspend with the EMS the TSO has indicated that €0.4 m associated with metering underspend will be required during PR5 and has been netted off of the PR5 request.

8. As regards the remaining ~€2.18 m underspend in this category, the TSO has confirmed that none of this has been deferred to PR5 and hence the original works associated with this spend is no longer required due to the reasons outlined above.

9. In addition to the deferred capital expenditure for EMS and Metering the TSO has confirmed that €0.5 m originally allocated to replace the Reserve Constrained Unit Commitment (RCUC) software would occur during PR4. The need to replace this software has been negated by I-SEM systems and hence the €0.5 m allocated for this has been netted off of the PR5 request.

Following the outlined review a summary is presented in Figure 3-7 of the outturn TSO non-network capital expenditure for PR4. This includes each non-network expenditure item, capex items deferred to PR5 as well as the proposed reductions in allowed expenditure. Taking account of the outlined “Deferred to PR5” category included in the TSO’s own PR4 Lookback Document16, the overall underspend in Non-Network capital expenditure is approximately €6.1 m. Some expenditure has been documented as deferred by the TSO to PR5 (for EMS, metering, RCUC software etc) and for other under-spent investment categories the TSO has confirmed that none of this will be carried forward into PR5.

The significant unplanned capital expenditure on Facilities has been reviewed, including the supplementary information provided by the TSO. Review of this additional information has identified some details of where the expenditure has been incurred and also how the works have been procured to demonstrate efficient procurement. Whilst the procurement process is understood, the principal issue associated with this expenditure is that it is still unclear what the underlying driver(s) for undertaking the work were, and whether these are aspects that network customers should be expected to fund. At the present time as it is still not clear as to the underlying need for the works it is recommended that a notional proportion of the incurred capital expenditure on Facilities during PR4 is disallowed (€2.48 m) until such time as the TSO can demonstrate a justifiable need for this investment.

As regards the wider noted underspend of €6.1 m17, as set out on the Section 13.4 Benefit Retention of the PR4 decision paper18 “revenue earned on Capex not spent will be clawed back, except where the TSO and TAO can show that the avoided spend is due to efficiencies on their own part”. Reviewing the explanations and justiications provided by the TSO as part of the PR4 review we have seen some reasons for noted underspends however it remains unclear whether these underspends in individual non-network expenditure categories are due to efficiencies achieved by the TSO or in whole or part due to reduced delivered volumes i.e. as per replacement RTUs. As such, there may be a case that at least some of this overall underspend has not been achieved entirely through efficiency savings made by the TSO during PR4 and should also be subject to some element of clawback through the current review process. Further detail and supporting information is needed from the TSO for each work activity expenditure listed in Table 3-12. This should substantiate and justify that noted expenditure underspends against forecast have been achieved through genuine efficiency gains made by the TSO i.e. by delivering the same volume / scope of work cheaper, rather than simply through late starting work activities and lower delivered volumes.

17 This would increase to €8.58 m if the recommended disallowed €2.48 m for unjustified Faciltiies works is excluded, unless the total PR4 allowance was reduced by the same amount i.e. from €39.58 m to €37.1 m. 18 https://www.cru.ie/wp-content/uploads/2015/07/CER15296-Decision-on-TSO-and-TAO-Transmission-Revenue-for-2016-to-2020-1.pdf


Figure 3-7 – Summary of Non-Network PR4 Outturn & Allowance



3.8 Conclusion from Historic PR4 Capex Review

3.8.1 General Observations

Net outturn total capital expenditure is expected to be €117.29 m, an underspend of €30.86 m or 20.8% of the CRU PR4 allowance, noting that the 2019 and 2020 outturn is forecasted. Annual outturn total expenditure has varied in comparison with the CRU PR4 allowance, being significantly below the CRU PR4 allowance in 2016 and 2019 (by around €23 m in each year) but significantly above allowance in 2017 (by around €21 m). Only in one year (2018) has the TSO spend close to the PR4 annual allowance.

Outturn PR4 network capital expenditure is forecast to be €87.00 m (2019 & 2020 forecast values), an underspend of €21.58 m or 19.9% of the CRU PR4 allowance. Network capital expenditure has seen a significant annual variation ranging from €7.37 m (2019 forecasted value) to €41.96 m in 2017. The high capital spend in 2017 was a result of the CP0466 North-South Interconnector project reaching Stage 1 invoicing milestones, with €36.0 m of network capital expenditure invoiced to the TAO representing ~86% of the 2017 total. Annual network capital expenditure variation against allowance ranges from a forecast underspend of €22.4 in 2019 to a €26.9 m overspend in 2017 – again driven by the CP0466 project Stage 1 invoicing.

The significant variance in annual outturn network capital expenditure experienced by the TSO during the PR4 period, and in comparison with the original PR4 forecast, is illustrative of the ongoing challenges that the TSO is still experiencing relating to obtaining planning consents and reaching Stage 1 invoicing milestones as per the IA, particularly for legacy projects. The TSO has however through PR4 introduced revised processes, particularly in relation to stakeholder engagement i.e. through new ALO’s and CLO’s. It is expected that this may help streamline the planning, consenting, environment assessment and stakeholder engagement process in future years such that more transmission projects can be developed and implemented in timescales closer to original forecasts and expectations. As it currently stands though, the delays to date in PR4 in delivering a number of the high capital value legacy projects will now see much of this capital spend occurring in PR5. Given the potential increase in transmission system infrastructure development required in PR5 on order to achieve national renewable targets this pose some deliverability questions for the TAO which will need to deliver both the ongoing and legacy projects as well as the new projects required to achieve renewable targets.

During the PR4 period two significant 400 kV transmission projects have been effectively cancelled, the Grid Link and Grid West Projects. In the case of the former, the project has effectively been replaced by a regional investment solution composed of seven individual projects with a reduced total capital expenditure value of circa €207 m in comparison with €758 m for the original project. In the case of the Grid West project this was effectively cancelled following a CRU decision which enabled contracted generators to hand back transmission capacity which was then available for other generators to connect, and allowed the overall system needs to be met by a single project (CP0816 North Connaught Overhead Line). The removal of the Grid West project has resulted in a reduction in planned PR4 capital expenditure of €15.0 m for the TSO and €224.0 m for the TAO.

Non-network PR4 capital expenditure forecast to be €30.28 m, and underspend of €9.30 m or 23.5% of the CRU PR4 allowance, although the underspend reduces to €6.10 (15.4%) if the €3.2 m that EirGrid have indicated is “Deferred to PR5” is included in the outturn non-network capital expenditure total. Non-network capital expenditure has also



varied through each year of PR4, particularly when compared with the annual PR4 allowance. The outturn non-network capital expenditure is forecast to range from an under-spend of €5.51 m in 2017, principally due to underspend in non-network telecoms (-€1.90 m) through to a forecasted 2020 over-spend of €5.01 m due in part to un-forecasted Facilities refurbishment expenditure of €2.9 m (additional Facilities refurbishment in other years additionally) for which there was no allowance.

From review of the TSO HBPQ spreadsheet there were 145 projects included in the original PR4 forecast with planned capital expenditure19 during the period (this excludes projects with zero forecast PR4 spend) totalling €115.74 m for the TSO and €1,481.32 m for the TAO. Of these projects 30 were cancelled or deferred representing a planned forecast capital expenditure of €73.60 m for the TSO and €561.01 m for the TAO. The bulk of this reduction in forecast expenditure for the 30 cancelled / deferred projects was the cancellation / replacement of the Grid Link, Grid West and North West RIDP project (forecast TSO capital spend €66.74 m). Of the 115 original forecast projects that proceeded during PR4 these have an outturn capital expenditure of €70.65 m and €699.83 m against original forecast values of €42.14 m and €920.32 m.

During PR4 a total of 206 projects are expected to have either TSO or TAO expenditure19, or both. The actual outturn is forecast to be €86.0520 m for the TSO and €791.41 m for the TAO. Of these projects 108 had no original PR4 forecast but have an expected outturn expenditure of €15.38 m for the TSO and €108.76 m for the TAO. This includes two of the regional solution projects replacing the Grid Link project (CP0844 and CP0972) with TSO PR4 forecast expenditure of €1.57 m, two significant uprating schemes (CP0789 and CP0883) with TSO forecast PR4 expenditure of €1.32 m, plus the Intel 220 kV connection at €2.272 m. Collectively these five new projects equate to more than a third of the forecast TSO expenditure that was not included in the original PR4 forecast.

The TSO has implemented a number of formal schemes with the TAO to improve collaboration and full project lifecycle feedback loops and planning. This includes the MYDP to manage the programme of transmission projects and allow for improved outage visibility and management. The TSO has also increased the level of stakeholder engagement routinely deployed on new transmission projects during PR4. This includes appointing dedicated ALO’s and CLO’s to engage directly with landowners and community groups to better understand their requirements, issues and concerns related to new transmission project developments. As an ongoing initiative this is expected to reduce and minimise the extent of potential objections raised by local landowners and community groups for new projects and should provide demonstrable benefits in streamlining project planning consenting and approval during PR5.

Land access and planning issues have continued to be a key issue during project delivery of PR4, particularly for the larger and more controversial transmission projects. Of the projects reviewed as part of this PR4 lookback this includes the CP0466 North-South Interconnector, CP0932 Microsoft, CP0932 Coomataggart WF (resulted in customer delays), CP0585 Laois – Kilkenny, CP0501 Clashavoon – Dunmanway 110 kV OHL, CP0197 Cushaling – Thornsbury 110 kV OHL and CP0747 Maynooth – Ryebrook 110 kV OHL Delays to these, and potentially other projects, has had an impact on the projects

19 Note that original PR4 forecast values are in 2014 prices whereas outturn values are actuals for years 2016 – 2018 and 2019 prices for forecast years 2019 and 2020. However, for broad comparison purposes in this and the following paragraph the different price base has been ignored. 20 This value excludes adjustments applicable to the TSO that are included in the overall summated totals referred to in the first paragraphs.



that are able to be delivered by the TAO during the period, and consequently has resulted in lower TAO PR4 capital expenditure than forecast.

Cost pressures have been generally low over the period with average prices growing only 2.77% from 2015 to 2020. As a result, any changes in expected total project cost to completion have largely been driven by other aspects i.e. additional planning and legal costs and pre-project delivery works undertaken by the TSO, or changes to the end project specification or extent of work required in comparison with original forecast i.e. outturn busbar uprate scheme costs being lower than standard planning unit costs.

3.8.2 Specific Findings

A review of outturn PR4 capital expenditure and specific reasons for deviations from the original forecast was performed. This included the North-South Interconnector project, the top ten projects with the highest variance in forecast versus actual spend as well as the Grid Link and Grid West Projects. The review illustrated that a number of the larger capital projects have continued to experience some major issues / changes during PR4, including the continued legal challenges facing the North-South Interconnector, now resolved within the Republic of Ireland but still ongoing in Northern Ireland, and the cancellation of the Grid Link and Grid West projects and replacement with alternative lower cost regional solutions. This has meant in these projects the planned TSO (and TAO) capital expenditure in PR4 has been lower than forecast. Additionally, in the case of the Grid Link and Grid West projects the change in actual project scope has actually yielded an expected permanent reduction in total costs to the end consumer, although in the case of the former once the abortive TSO Stage 1 costs are allocated across the seven regional replacement projects the outturn total TSO Stage 1 costs are expected to be marginally higher than the original forecast for the full Grid Link project.

Following our review, we are satisfied that with respect to the North-South Interconnector, Grid Link and Grid West projects that the most appropriate outcomes and end result for consumers have been obtained, even if the exact circumstances by which these outcomes have arisen have largely evolved over a period of time rather than been planned from the outset. The recent changes in planning, consenting and stakeholder engagement introduced by the TSO should ensure that should further large capital intensive transmission projects be proposed in the future that the processes applied by the TSO should result in more streamlined delivery outcomes with fewer delays.

Detailed review for the top ten projects with the highest variance in forecast capex (at 2014) versus actual outturn spend also identified that in many cases the reasons for notable project under- or over-spends in comparison with original forecast were associated with:

use of high level costs for concept or pipeline projects that had not been fully scoped;

project works that end up being planning exempt requiring less input from the TSO than anticipated;

changes to project scope / works driven by changing customer requests;

legal / planning consent challenges and revisions that required more TSO than anticipated; and

Cancellation / deferral of project following review of project need.

Overall, following review of the reasons underpinning each studied project we are satisfied that in broad terms the reasons provided by the TSO to explain outturn variations in planned forecast versus actual capital expenditure are credible. Additionally,



although we have not reviewed all projects as part of this review we are of the opinion that a similar conclusion would be reached if further projects were also reviewed in detail.

Further review was also performed of projects which had no forecast TSO capital expenditure (at 2014) but are now expected to have outturn expenditure during the PR4 period. Reviewing the reasoning and details provided by the TSO these ranged from new customer driven projects not known at the time of the 2014 PR4 forecast, replacement projects resulting from the cancellation of the Grid Link project, and projects that were subject to further TSO Stage 1 planning inputs, including those where further legal or consenting challenges have arisen. Again, notwithstanding that the recently introduced new processes and initiatives introduced by the TSO may have led to expedited completion of Stage 1 activities (in some cases) if implemented previously, the TSO has been transparent in detailing the broad reasoning behind any delays / changes and basis for additional costs where thus incurred.

In relation to outturn non-network capital expenditure during PR4, the TSO is expecting to under-spend the original PR4 allowance by €9.3 m, although this reduces to €6.1 m if the additional €3.2 m of non-network capital expenditure deferred to PR5 (principally for All Island EMS work activities paused during I-SEM commissioning) is considered. Examination of the individual work activities within the non-network expenditure category has revealed that the outturn variance between forecasted PR4 spend and original PR4 allowance is within ± €1.0 m with the exception of four categories. These are:

1. All Island EMS: outturn variance -€2.30 m (under-spend) – as described above.

2. TUoS / Settlement / Metering: outturn variance: -€2.58 m – full scope of works was not known at start of PR4 and some works (metering) deferred to PR5.

3. Facilities: outturn variance €4.95 m – this includes refurbishment of the EirGrid head office at the Oval plus “various other critical projects”.

4. Non-network telecoms: outturn variance -€5.71 m – there have been delays in the installation of some equipment (new and replacement RTUs), and roll-out of new systems (IP based network), etc.

In relation to the above the TSO has confirmed that that work areas that have capex included in the “deferred to PR5” spend category under PR4 have been netted off of the PR5 capital request, such that EirGrid are not being funded twice for the same work. For the other work areas with under-spends, principally non-network telecoms, the TSO has indicated in their PR4 Narrative document that they plan to ramp-up elements of the work activity in relation to RTU replacement over the coming years (in 2020 and beyond). Thus, in this regard the deferred replacement to later years should represent a more efficient capital expenditure assuming that the future replacements can be delivered for the same unit costs as expected during PR4.

This leaves the apparent over-spend in Facilities costs during PR4 as the most evident variation particularly given that this work area had no original allowance for the PR4 period and was not requested by the TSO in the original PR4 submission. A capital spend of €2.8 m is forecast for routine refurbishment of the Oval head office along with a further €2.1 m which has been spent “across various other critical projects which were required due to equipment coming end of life, replacement cycles, etc”. The TSO has indicated that the Oval office refurbishment “was tendered via our facilities management vendor to ensure value for money was achieved as part of this works”. Whilst it is recognised that tendering the work activities may lead to an efficient cost for undertaking the final work scope, the need to undertake the works in the first instance is still not clear and further



information was requested from the TSO to substantiate the requirement to undertake this work. However, whilst some clarifications were received from the TSO they do not fully substantiate the requirement to undertake the head office refurbishment or the other critical project asset replacements. It is thus recommended that the cost of the head office refurbishment (€2.48 m) is disallowed until this, and other critical project replacement works, have been justified by the TSO.

Reviewing the explanations and justiications provided by the TSO as part of the PR4 review we have seen some reasons for noted underspends in non-network capital expenditure. However, it remains unclear whether these underspends in individual non-network expenditure categories are due to efficiencies achieved by the TSO or in whole or part due to reduced delivered volumes i.e. as per replacement RTUs. Further detail and supporting information is needed from the TSO to substantiate and justify noted expenditure underspends against forecast and demonstrate that these have been achieved through genuine efficiency gains made by the TSO.

3.8.3 Efficient PR4 Capital Expenditure

Based on the observations and specific findings from the GHD review outlined in the previous sub-sections a summary is provided in Table 3-13 below of the overall GHD view of efficient TSO capital expenditure for the PR4 period.

Table 3-13 – Summary of PR4 Capital Expenditure 2016-2020

Project PR4 Total, € m TSO Network Capex (Stage 1 & Adjustments) 87.00 TSO Non-Network Capex* 33.48 TSO Total 120.48 Efficient PR4 Network Capex 87.00 Efficient PR4 Non-Network Capex 31.00 Efficient PR4 Total Capex 118.00 Variation -2.48

* Includes €3.2 m indicated by the TSO as Deferred to PR5: €2.3 for Energy Management System, €0.4 TUOS & Metering, €0.5 for Reserve Constrained Unit Commitment software In broad terms following the review undertaken we are of the opinion that the expected PR4 capital expenditure incurred by the TSO is reasonable. Where changes and deviations in comparison with the original PR4 forecast have occurred these have been found to have acceptable justification and reasoning. The exception is in relation to non-network capital expenditure items where information provided by the TSO to support outturn costs has not been provided, or has not fully explained the outturn costs or how these have varied in comparison with the original forecast. Specifically, €4.95 m is expected to be spent by the TSO for Facilities expenditure, where there was no allowance provided for PR4. In response to GHD questions some information has been provided to confirm the works undertaken for the head office refurbishment and also how such works were procured efficiently. Whilst this is acknowledged, the underlying question remains as to the actual need to undertake the works, both the head office refurbishment and other facility works. In the absence of such information to robustly demonstrate the need for such investment it is recommended that a notional 50% deduction in the expected PR4 expenditure is made, that is a reduction of the €2.48 m.

Additionally, for a further deductions in relation to the PR5 capital allowance requested by the TSO are recommended is recommended for the CP0800 – North West (RIDP) project. Information received during the PR4 review process has identified that the project is on-hold and the TSO does not expect the project will be developed to construction during PR5. It is



therefore recommended that the €6 m and €30 m included in the PR5 Scenario 1 expenditure for the TSO and TAO respectively is removed from the PR5 allowance.

3.8.4 Considerations for PR5

The following provides some key considerations for the PR5 period following this review of the PR4 outturn:

Reviewing the outturn project capital expenditure variations experienced across the PR4 period it is evident that in a number of cases the forecast capital costs used in planning activities have not been representative of the outturn costs that are expected to be incurred. This includes a number of uprating schemes for overhead lines and busbars. Whilst it is accepted that the nature of these projects are likely to require some bespoke work activities for which no standard unit costs are readily available, it is suggested that it may be prudent to conduct a high level review of the potential substations and transmission circuits that may require similar such uprating during PR5 and PR6 at an early stage given that such activities are likely to become more commonplace in future years as an alternative to new build transmission plant. This will help not only with EirGrid internal planning and budgeting but also any future revenue reset activity forecasting. Inputs and coordination with the TAO, as asset owner, will however be necessary in order to facilitate such improved costing forecasts.

Through the PR4 period the TSO has typically engaged at an earlier stage in the planning process with the TAO than during PR3. This has helped provide information to understand the full scale of work activities required for individual transmission investment projects, particularly those that involve upgrades and replacements of existing assets. Given the potential complexities of future transmission investment work activities which are likely to see more projects targeting the uprating, replacement or modification of existing transmission assets this improved and ongoing communication with the TAO will need to not only be maintained but potentially increased during PR5. This will be necessary in order to share knowledge of individual asset characteristics, data and performance between the two parties to facilitate improved planning decision making, outage management and project delivery activities. This will require proactive assessment and reviews and potentially ahead of conducting fully scoped out individual project work activities in order to provide timely and better quality information to input to the planning decision process and reduce the potential for project delays seen during PR4.

The outturn capital expenditure for non-network work activities during PR4 has broadly been around ¾ of the original PR4 forecast. The underspend has, in a number of cases, been as a result of delays during implementation where it has taken longer than planned to fully scope out, execute and deliver the required works. Whilst the quantum of capex requested by the TSO for non-network work activities during PR5 is broadly similar to the actual outturn experienced during PR4, it is recommended that forward planning activities to adequately scope out the underlying work and equipment requirements are undertaken as soon as possible in order to minimise the delays that have impacted outturn PR4 expenditure in this area.

The TSO has introduced new processes and procedures in relation to stakeholder engagement during PR4, including the introduction of ALO’s and CLO’s, and has indicated that initial outcomes of such approaches are beneficial and have been welcomed by community groups. The TSO should therefore, at an appropriate point, review the success of these and the other consenting and stakeholder engagement activities undertaken during PR4 to understand where further direct engagement and



proactive community discussion may be beneficial to help disseminate knowledge of planned transmission system infrastructure developments.



4. Review of PR4 Operating Expenditure: Transmission Asset Operator 4.1 Introduction

This section of the report reviews the reported TAO PR4 (2016 to 2020) opex and compares this outturn against the TAO’s PR4 opex allowances, as determined by CRU in its CRU PR4 Decision Paper.21 2016 to 2019 performance and cost data is based on actual recorded values, whilst 2020 performance and cost data is based on the latest forecast data provided by the TAO.

Unless stated otherwise, our review of PR4 expenditure, has prices expressed in real 2014 price levels. This allows comparison with the original CRU PR4 allowances. The conversion to these price levels was based on the inflation factors presented in Table 4-1.


2014 2015 2016 2017 2018 2019 2020 HICP Adjustment Factor 1.000 1.000 1.002 1.000 0.993 0.984 0.973

Source: ec.europa.eu/Eurostat/data/database. Dataset: prc_hicp_midx. Accessed: 13/01/2020 CRU allowed costs are as set out in the CRU PR4 decision paper with annual adjustments made during the price control period by CRU for pass through items along with volume related items included as part of the PR4 settlement.

4.2 Our approach

The objective of this review is to assess the TAO’s performance in achieving the outputs required by CRU during PR4 and whether the costs incurred in achieving these outputs were reasonable.

The opex allowance set by the CRU is split into controllable and non-controllable opex. Controllable opex relate to costs that the CRU consider are within management control and can be assessed for reasonableness. Non-controllable opex relate to costs that the CRU consider are outside of management control and are therefore treated as pass-through costs which are adjusted year-on-year through the annual revenue review process.

Controllable opex is subject to benefit sharing arrangements, as stated in the PR4 final determination:

“For Opex, the TSO and TAO will be permitted to retain the annual savings made for a period of five years, provided such savings have not been made at the expense of performance/ inefficiency and quality of service or as a result of poor forecasting.”22

We have assessed the TAO’s opex at activity level – enabling us to link costs incurred to output delivery. Our review of PR4 opex focuses on:

Comparison of actual opex against allowed opex.

21 CER, 2015. Decision on TSO and TAO Transmission Revenue for 2016 to 2020. CER/15/296. 22 CER, 2015, Decision on TSO and TAO Transmission Revenue for 2016 to 2020, CER/15/296, section 13.4



Where the TAO is reporting a difference between actual and allowed opex, we have undertaken ‘deep dive’ analysis of evidence submitted by the TAO to explain any variances in outputs and costs. The aim of this is to understand whether:

o any under-spend is the result of efficiency gains or under-delivery of outputs; and

o the TAO has demonstrated that any over-spend is efficient or is the result of over-delivery of outputs.

Our recommendations are to set the ex-post allowance to outturn costs, except where under-spend is efficient or over-spend is inefficient. In this way, the intention of the PR4 incentive arrangements (quoted above) is achieved while providing the TAO with balanced exposure to upside and downside risks.

We then take an in-the-round view on the level of controllable opex that should be reflected in the ex-post allowance, with any difference between the ex-post allowance and the TAO’s outturn opex being subject to the benefit sharing arrangements.

4.3 Overview of PR4 opex and our recommendation

Table 4-2 presents the TAO’s allowed opex for the full PR4 period and the TAO’s expected outturn for the same period.23 The uncontrollable cost allowance has been adjusted to reflect the year-on-year adjustments that have / will be made through the annual revenue review process (i.e. pass-through). As requested by the CRU, and in keeping with the ex-post assessment of PR3, we reviewed opex on a category-by-category basis.

Table 4-2 – Summary of PR4 TAO Opex Allowances (2014 prices)

PR4 Costs Allowed (€m) Actual / forecast (€m)

Variance €m %

Controllable opex Maintenance 88.5 98.9 10.4 12% Professional Fees 24.1 23.3 -0.8 -3% Corporate Costs24 13.4 18.3 4.9 37% Operations Allowance 13.4 12.6 -0.8 -6% Telecom Fees 7.7 7.5 -0.2 -3% Asset Management 5.6 4.2 -1.4 -25% Pension 2.1 2.0 -0.1 -6% Insurance 1.8 2.9 1.1 60% Legal 0.8 1.8 1.0 122% Transmission Retirements 0.0 -0.3 -0.3 N/A Total Controllable Costs 157.4 171.3 13.9 8.8% Non-controllable opex Rates 135.0 121.4 -13.6 -10% CRU Levy 5.9 5.5 -0.4 -7% Total Non-controllable Costs 140.9 126.9 -14.0 -10% Total Opex 298.3 298.2 -0.1 0%

Source: ESB Networks Overall, the TAO’s expected opex outturn for PR4 is €298.2 million. This is €0.1 million (0%) lower than the CRU allowance of €298.3 million. This outcome has been delivered through an

23 The TAO also listed €18.9 million of costs under ‘miscellaneous’ relating to accounting provisions and adjustments. The TAO informed us that they do not request an allowance for these provisions until actual settlements are paid. We, therefore, do not capture these costs in this review. 24 Corporate Costs denotes company-wide costs and corporate charges.



overspend on controllable opex of €13.9 million and an underspend on non-controllable opex of €14.0 million.

The expected overspend on controllable opex is driven largely by two activities:

Maintenance (forecast overspend of €10.4 million), which the TAO says was due to higher volumes of activity compared to PR3.

Corporate costs (forecast overspend of €4.9 million), which the TAO says was the result of additional safety management, procurement, employee stock ownership plan (ESOP) and group of union activities.

The expected underspend on non-controllable opex is mostly as a result of rates expenditure being €14.0 million (10%) lower than forecast at the start of PR4.

Across our review, we have identified cases the evidence provided by the TAO was not sufficient to demonstrate that the overspend incurred was reasonable. Where that has been the case, we have recommended that the CRU’s revised allowance does not include the unexplained overspend.

4.4 Controllable Costs

In this sub-section we review the TAO’s outturn opex against allowance for each of the activity areas listed in Table 4-2. Table 4-3 briefly describes the nine key activity areas that make up PR4 controllable opex.

Table 4-3 - PR4 TAO Controllable Opex Categories

Cost Category Definition

Maintenance Management of the assets to ensure that the assets continue to function as designed and is split between planned and unplanned (fault) maintenance.

Professional Fees The cost of contracted services for intermittent support in the operation, maintenance and management of transmission assets.

Corporate Costs Covers centrally provided services including head office, human resources, finance and regulation.

Operations Allowance

The cost of the daily operation of the Transmission Network, including activities such as monitoring, switching and investigations.

Telecom Costs The cost of IT and telecommunications systems and equipment, which are used exclusively in the real time management of network assets.

Asset Management

Covers the costs relating to the development and review of technical and engineering policies; programme and project management; wayleave and forestry management; and managing and operating stores.

Pension The administrative costs for the operation of a pension scheme.

Insurance The cost of managing the insurance function and insurance premiums and claims paid out.

Legal The cost of all legal services, whether in-house or external, excluding those relating to wayleaves / servitudes / easements.

4.4.1 Maintenance

(Allowed €88.5 million, Outturn €98.9 million)

Table 4-4 presents a comparison of planned and unplanned maintenance allowances against the TAO’s forecast outturn maintenance expenditure for the PR4 period.



The TAO forecasts total maintenance expenditure of €98.9 million compared to an allowance of €88.5 million, which represents an overspend of €10.4 million (12%).

Table 4-4 – Maintenance Spend in PR4


2016 2017 2018 2019 2020 PR4 Total

Actual Actual Actual Actual Forecast Allowed Actual/ Forecast

Variance

€m %

Planned Maintenance

16.9 15.6 17.1 19.4 19.0 80.5 88.0 7.5 9%

Unplanned Maintenance

1.8 2.2 2.1 2.0 2.8 8.0 10.9 2.9 36%

Total 18.7 17.8 19.2 21.5 21.8 88.5 98.9 10.4 12% Source: ESB Networks

The subsections below assess the TAO’s planned and unplanned expenditure in more detail.

Planned maintenance The TAO divide planned maintenance into:

Preventive/routine maintenance – the frequencies of these activities are pre-determined in line with maintenance standard set by the TSO in consultation with the TAO. We acknowledge that the TSO has sole discretion over the maintenance standard and the TAO must follow the maintenance standard set by the TSO. However, we do think that the TAO can input its views over the maintenance standard that is set through the consultation process. The TAO also claims that there has been continued and enhanced collaboration between the TAO and TSO throughout PR4, which should increase its influence over the maintenance standard further.

Statutory maintenance – maintenance that is carried out to ensure compliance with safety and environmental requirements - for example, pressure vessel inspections and bund inspections. The volume of such activities is highly predictable based on the requirements, and the TAO’s asset types, volumes, and condition/age.

The TAO forecasts planned maintenance expenditure of €88.0 million compared to an allowance of €80.5 million, which represents an overspend of €7.5 million (9%). Over PR4, the TAO is expected to spend more than its planned maintenance allowance in four out of five years of PR4. In fact, the TAO has consistently overspent its planned maintenance allowance in eight of the past ten years, with the largest overspend occurring in the final years of PR3 and PR4.25 This is demonstrated in Figure 4-1 that presents expected versus allowed planned maintenance expenditure over the period 2011 to 2020.

25 For example, between 2016 and 2018, the TAO has overspent is planned maintenance allowance by €1.3 million. In comparison, in 2019 and 2020, the TAO is expected to overspend its allowance by €6.2 million.



Figure 4-1 – Planned maintenance: allowed versus outturn (2011 to 2020)


The TAO has stated that the increase in costs over PR4 is solely due to the higher volume of planned maintenance work undertaken in PR4. Between PR3 and PR4, the average number of delivered planned maintenance units has increased by 14% - this compares to a 16% increase in the allowance for planned maintenance between the two periods.

While we acknowledge that this is an uplift on what was delivered during PR3, it remains the case that the TAO’s outturn delivery in PR4 has lagged the forward transmission maintenance plan set out by the TSO. In fact, the PR4 gap between scheduled and delivered maintenance is expected to be 80% (i.e. delivered planned maintenance lags the forward plan by 20%), which is larger than the PR3 maintenance gap of around 84% (i.e.a 16% lag). Given that the TAO’s delivery has lagged the TSO’s maintenance plan suggests that the overspend shown in Figure 4-1 is not a function of the TAO delivering outputs in excess of those envisaged when the PR4 allowance was set. In addition, as Figure 3.1 illustrates, the PR4 allowance already included an expected increase in planned maintenance spend in PR4.

According to the TAO, higher utilisation of the transmission system is making it more challenging to undertake planned maintenance work. It has also stated that it has taken some steps to reduce maintenance costs through policy changes made during PR4. However, the TAO has not quantified what impact maintenance policy changes have had on its PR4 maintenance expenditure relative to the forecasts made for the PR4 business plan.

The introduction of foot patrols in place of climbing patrols does appear to have led to cost efficiency savings based on the disaggregated unit cost information presented by the TAO. The TAO also states that the use of Airborne Light Detection and Ranging (LiDar) inspections instead of sag inspections to identify conductor hotspots on overhead lines has led to efficiency savings, but we have been unable to verify this through the TAO’s submission.

The TAO also stated that its maintenance cost efficiency and service quality benchmark well against the 2017 International Transmission Operations & Maintenance Study (ITOMS).26 We have reviewed the findings of this study and consider the evidence is inconclusive. Much of the analysis is conducted on a circuit kilometre basis, which may distort some of the conclusions when comparing companies that operate in densely populated areas to those with more expansive networks (such as the TAO). The study also only captures a small range of service

26 Source: ESB Networks, PR5 business plan, Annex TH03 UMS ITOMS Benchmarking Report 2017.



quality measures, and we note that ESB Networks is omitted from a number of the benchmarks analysed as it is deemed to be an anomaly.

Our own analysis of unit cost data provided in the TAO’s historical submission effectively benchmarked the TAO against itself, which is arguably less stretching than comparing its cost performance with other companies. Our analysis found that maintenance unit costs have not changed significantly between 2015 and 2018, which suggests that the TAO has either become more or less efficient over the course of PR4.

Overall, the TAO has taken steps to improve transmission maintenance policy during the price control period in collaboration with the TSO. However, the information and evidence available to us has shown the TAO to consistently overspend its planned maintenance allowance whilst also not meeting the forward transmission plan set by the TSO. As a result, we recommend that the overspend is not included in the CRU’s revised allowance for PR4.

Unplanned maintenance The TAO forecasts unplanned maintenance expenditure of €10.9 million compared to an allowance of €8.0 million, which represents an overspend of €2.9 million (36%).

Figure 4-2 presents expected versus allowed unplanned maintenance expenditure over the period 2011 to 2020.

Figure 4-2 – Unplanned maintenance: allowed versus outturn (2011 to 2020)

Source: CEPA

Transmission faults are typically low frequency, unpredictable and can have a large impact on consumers / the electricity system when they do occur. This is reflected in the figure above, which shows that unplanned maintenance spend is relatively low compared to planned maintenance.

Average unplanned maintenance expenditure over the first four years of PR4 (2016 to 2019) was approximately equal to the average unplanned maintenance expenditure incurred during PR3. The TAO has also overspent on its fault maintenance allowance in every year between 2011 and 2020. The evidence provided does not, by itself, raise concern that the TAO is not maintaining the condition of its assets appropriately, as that would typically be accompanied by increased incidence of faults.

The TAO has stated that the increase in planned maintenance has resulted in increased levels of unplanned maintenance as a follow-on to corrective or faults work. However, we consider that



the increase in unplanned maintenance that may have been generated by higher levels of planned maintenance is already accounted for in the TAO’s PR4 unplanned maintenance allowance. For example, we note that the TAO’s unplanned maintenance allowance increased by 40% between PR3 and PR4 whereas the TAO’s planned maintenance allowance only increased by 16% between PR3 and PR4. On this basis, we do not consider that the TAO has demonstrated that the overspend in this category over PR4 should be reflected in a revision to the PR4 allowance.

4.4.2 Professional Fees


Table 4-5 compares allowed opex for professional fees against the TAO’s forecast professional fees opex for the PR4 period.

The TAO forecasts professional fees of €23.3 million compared to an allowance of €24.1 million, which represents an underspend of €0.8 million (3%).

Table 4-5 – Professional Fees Spend in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance

€m %

Professional fees 5.0 5.0 4.2 5.9 3.2 24.1 23.3 -0.8 -3%

Source: ESB Networks Professional services fees comprise of ESB International (ESBI) support for operation, maintenance and management of transmission assets, in addition to TSO fees, technical and other professional fees. The TAO says it uses ESBI as it provides access to a flexible resources pool with international experience. However, the TSO has not outlined how it ensures that the rates set by ESBI are competitive with market rates. Going forward, we recommend that the TAO report annually to CRU to outline how it has ensured a competitive procurement of professional services at the best price for Irish consumers.

Overall, these activities are forecast to be delivered with an underspend of €0.8 million, occurring primarily in 2020.

4.4.3 Corporate Costs


The TAO forecasts corporate costs of €18.3 million compared to an allowance of €13.4 million, which represents an overspend of €4.9 million (37%). It also represents a significant increase on corporate costs incurred in PR3 (€11.5 million). Table 4-6 compares allowed opex on corporate costs against the TAO’s forecast corporate costs for the PR4 period.

Table 4-6 – Corporate Costs in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance

€m %

Corporate costs 3.1 3.6 3.8 3.6 4.3 13.4 18.3 4.9 37% Source: ESB Networks

Corporate costs include corporate charges and company-wide costs. Corporate charges include chief executive, group finance, corporate affairs, regulatory and human resources. Company-



wide costs include employee stock ownership plan (ESOP) costs, sports and social subsidies, group of union costs, industrial council costs and pension supplements.

The TAO explains that the expected overspend on corporate costs is the result of:

an increase of €0.6 million per annum associated with additional safety management and procurement activities; and

additional costs associated with increased ESOP and group of union activities.

Going forward, we recommend that the TAO should provide evidence as to how it has ensured that these costs are efficient.

4.4.4 Operations Allowance


Table 4-7 compares allowed opex on operations activities against the TAO’s forecast operations opex for the PR4 period.

The TAO forecasts operations opex of €12.6 million compared to an allowance of €13.4 million, which represents an underspend of €0.8 million (6%).

Table 4-7 – Operations Spend in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance

€m %

Operations 2.9 2.6 2.6 2.3 2.2 13.4 12.6 -0.8 -6% Source: ESB Networks

The operations opex allowance covers the cost of the daily operation of the transmission network, including activities such as monitoring, switching and investigations. Forecast operations spend in PR4 is slightly below operations spend in PR3 and is expected to be delivered under the PR4 allowance.

4.4.5 Telecoms


Table 4-8 compares allowed opex on telecoms against the TAO’s forecast telecoms opex for the PR4 period.

The TAO forecasts operations opex of €7.5 million compared to an allowance of €7.7 million, which represents an underspend of €0.2 million (3%).

Table 4-8 – Telecoms Spend in PR4


2016 2017 2018 2019 2020 PR4 Total

Actual Actual Actual Forecast Forecast Allowed Actual/Forecast Variance

€m %

Telecoms 1.5 1.5 1.0 1.4 2.1 7.7 7.5 -0.2 -3% Source: ESB Networks

Expected telecoms opex in PR4 of €7.5 million also reflects a decrease of €0.3 million compared with telecoms opex in PR3 (€7.8 million), which suggests that the TAO has achieved cost efficiencies in this area. As a result, we recommend that the ex-post allowance is set equal to the PR4 ex-ante allowance so that the TAO can benefit from the efficiency savings.



4.4.6 Asset Management


Table 4-9 compares allowed opex on asset management against the TAO’s forecast asset management opex for the PR4 period.

The TAO forecasts asset management opex of €4.2 million compared to an allowance of €5.6 million, which represents an underspend of €1.4 million (25%).

Table 4-9 – Asset Management Spend in PR4


2016 2017 2018 2019 2020 PR4 Total


Variance

€m %

Asset management 1.0 0.8 0.8 0.8 0.9 5.6 4.2 -1.4 -25%

Source: ESB Networks Asset management opex includes the compensation costs for mast interference and forestry payments (wayleaves).

Outturn expenditure is expected to be below the allowance, our review of the evidence suggests that expectations expressed at the time of setting the PR4 allowances of increased activity from farming and other representative groups has not materialised. This suggests there is a degree of uncertainty around the efficient level of asset management opex that we have considered when assessing the costs for PR5 (see Section 8).

4.4.7 Pension administration


Table 4-10 compares allowed pension administration opex against the TAO’s forecast pension administration opex for the PR4 period.

The TAO forecasts pension administration opex of €2.0 million compared to an allowance of €2.1 million, which represents an underspend of €0.1 million (6%).

Table 4-10 – Pension administration Spend in PR4


2016 2017 2018 2019 2020 PR4 Total Actual Actual Actual Actual Forecast Allowed Actual/

Forecast Variance €m %

Pension administration 0.4 0.4 0.4 0.4 0.5 2.1 2.0 -0.1 -6%

Source: ESB Networks Pension administration costs are associated with the running and management of pension funds and include items such as actuary fees and manpower costs associated with the day to day management of the pension arrangements.

Expected pensions administration opex in PR4 of €2.0 million reflects a decrease of €0.1 million (7%) compared with pensions administration opex in PR3 (€2.1 million). This suggests that the TAO has achieved cost efficiencies in this area. As a result, we recommend that the ex-post allowance is set equal to the PR4 ex-ante allowance so that the TAO can benefit from the efficiency savings.



4.4.8 Insurance


Table 4-11 compares insurance opex against the TAO’s forecast insurance opex for the PR4 period.

The TAO forecasts insurance opex of €2.9 million compared to an allowance of €1.8 million, which represents an overspend of €1.1 million (60%).

Table 4-11 – Insurance Spend in PR4




Insurance 0.5 0.5 0.6 0.6 0.7 1.8 2.9 + 1.1 + 60%

Source: ESB Networks ESB Networks says that total insurance costs for the DSO and TAO have remained flat at €12.5 million over PR4, but that it allocated these costs between the DSO and TAO differently to the proportions used by the CRU for PR4:

ESB Networks has used a split of 77% distribution and 23% transmission.

The CRU had previously used a split of 85% distribution and 15% transmission.

We note that if ESB Networks had allocated 15% of insurance costs to the TAO, this would result in an outturn spend of €1.9 million. This represents an overspend of €0.1 million (4%).

We recommend that ESB Networks develop and submit to the CRU a methodology for allocating costs, such as insurance, that span the TAO and DSO. Once reviewed by the CRU, ESB Networks should be required to explain any departures from the methodology (e.g. as part of future ex-post reviews).

4.4.9 Legal


Table 4-12 compares legal opex against the TAO’s forecast legal opex for the PR4 period.

Table 4-12 – Legal Spend in PR4




Legal 0.2 0.2 0.5 0.3 0.5 0.8 1.8 1.0 122%

Source: ESB Networks The TAO forecasts legal opex of €1.8 million compared to an allowance of €0.8 million, which represents an overspend of €1.0 million (122%). This is largely the result of two atypical legal spend years in 2018 and 2020.

The TAO has set out that the increased expenditure compared to the ex-ante allowance was due to increased activity in the area of land access disputes, site acquisition and acquiring easements due to increased construction activities. For this reason, we recommend that the ex-post allowance reflects outturn expenditure.



4.4.10 Transmission retirements

(Allowed €0.0 million, Outturn -€0.3 million)

The TAO has forecast a net saving of €0.3 million relating to transmission retirements, which was not captured within the PR4 ex-ante opex allowance, as shown in Table 4-13 below.27

Table 4-13 – Transmission Retirements in PR4




Transmission Retirements

0.0 0.0 -0.3 0.0 0.0 0.0 -0.3 -0.3 N/A

Total 0.0 0.0 -0.3 0.0 0.0 0.0 -0.3 -0.3 N/A Source: ESB Networks

4.5 Conclusions

Table 4-14 presents our recommendation for the PR4 ex-post allowance for the TAO. For controllable opex (assessed in this chapter), the recommended ex-post allowance is €161.2 million compared to the ex-ante allowance the CRU had set of €157.4 million. This difference is primarily owing to overspend on corporate costs and insurance, which has been explained by the TAO.

27 The TAO also listed €18.9 million of costs under ‘miscellaneous’ relating to accounting provisions and adjustments. The TAO have informed us that they do not request an allowance for these provisions until actual settlements are paid. We therefore do not capture these costs in this review.



Table 4-14 – PR4 TAO Ex-Post Opex Allowance


Ex-Ante Allowance

Actual / Forecast

Ex-Post Allowance

Comment

Controllable Costs

Maintenance 88.50 98.95 88.50

Professional Fees 24.1 23.3 23.3

Corporate Costs 13.4 18.3 18.3

Transmission Operations 13.4 12.6 12.6

Telecom Fees 7.7 7.5 7.7

Asset Management 5.6 4.2 4.2

Pension 2.1 2.0 2.1

Insurance 1.8 2.9 2.9

Legal 0.8 1.8 1.8

Transmission Retirements 0.0 -0.3 -0.3

Total Controllable 157.4 171.3 161.2 Based on the assessment of the evidence provided for individual categories, noting that in different categories of opex the TAO has either overspent its allowance or underspent because of delivery lagging the allowance.


Total non-controllable 140.9 126.9 126.9 Pass-through costs

Total opex 298.3 298.2 288.4 Source: CEPA analysis

In the round, we consider it is appropriate to set the ex-post PR4 controllable opex allowance €3.8m higher than the ex-ante allowance. For most cost categories we are recommending that the CRU’s ex-post allowance reflects outturn opex (for example, where the TAO has underspent its allowance, but has not provided sufficient evidence to demonstrate that the costs are reasonable). For telecoms and pensions administration the TAO has demonstrated efficiency savings, so the recommended ex-post allowance reflects no change from the ex-ante allowance (i.e. the TAO retains the benefit of efficient underspend). Where the TAO has demonstrated that overspends within a category were efficient, this has been incorporated into our in-the-round recommendation. On balance, this results in a slight increase from the ex-ante allowance, but below the TAOs’ outturn costs.

Planned maintenance is a key area of overspend where we do not consider that the TAO has provided sufficient justification and explanation and, therefore, we have proposed the overspend should not be reflected in the ex-post allowance. The evidence available to us has shown the TAO to overspend its planned maintenance allowance whilst the gap between delivered maintenance and the forward transmission plan set by the TSO has not improved over time (even though the TAO is delivering a larger volume of work in this area).

The levels of actual and forecast opex across the different categories, as well as insight into the factors affecting these levels, were informative in developing our views on PR5 opex (see Section 8).



5. Review of PR4 Capital Expenditure: Transmission Asset Owner 5.1 Total Capital Expenditure

A high level summary of the TAO PR4 capital expenditure allowance by the CRU and actual outturn expenditure to 2019 by the TAO, with a forecast for 2020, are presented in Table 5-1 and graphically in Figure 5-1. The TAO submitted an updated HBPQ on the 5th February 2020 to provide actual 2019 outturn data which this report has included.

CRU allowance values for the years 2016 to 2020 are presented in 2014 costs. The actual spend by the TAO has been deflated to 2014 costs from the nominal costs for the year incurred as presented in the TAO’s Historic Business Plan Questionnaire (HBPQ), by utilising the HICP data, see Table 3-2 for reference.

Table 5-1 – TAO Transmission Capital Expenditure 2016-2020

Item Party 2016 2017 2018 2019 2020 PR4 Total

Network Gross PR4 Allowance

CRU 241.7 216.3 208.2 194.2 171.8 1032.2

Network Gross PR4 Outturn and Forecast

TAO 163.9 143.4 199.6 143.4 152.6 803.0

Variance -77.8 -72.9 -8.5 -50.8 -19.2 -229.3

IDC PR4 Allowance CRU -12.0 -11.5 -10.9 -10.9 -9.6 -54.8

IDC PR4 Outturn and Forecast

TAO -20.8 -15.7 -17.5 -14.3 -7.1 -75.4

Variance -8.8 -4.2 -6.6 -3.4 2.5 -20.6

Customer Contributions PR4 Allowance

CRU -57.9 -35.9 -7.0 -0.9 -0.3 -102.0

Customer Contributions PR4 Outturn and Forecast

TAO -9.42 -20.7 -13.4 -30.6 -16.5 -90.7

Variance 48.5 15.2 -6.4 -29.7 -16.3 11.3

Other Adjustments PR4 Allowance

CRU 0.0 0.0 0.0 0.0 0.0 0.0

Other Adjustments PR4 Outturn and Forecast

TAO 4.8 9.7 4.6 5.1 13.6 36.5

Variance 4.8 9.7 4.6 5.1 13.6 36.5

Network Net Capitalised PR4 Allowance

CRU 171.8 168.9 190.3 182.4 161.9 875.4

Network Net Capitalised PR4 Outturn and Forecast

TAO 138.5 116.7 173.3 103.6 142.5 674.6

Variance -33.3 -52.2 -17.0 -78.8 -19.4 -200.8

Variance (as % of Allowance) 81% 69% 91% 57% 88% 77%


Figure 5-1 – Comparison of PR4 CRU Allowance and TAO Outturn



In summary, it can be seen from Table 5-1 and Figure 5-1 that the net rate of expenditure on capital projects was below the CRU PR4 allowance throughout the five year period. In total, the net outturn variance has been 77% of the CRU PR4 allowance. With respect to spend profile, net TAO outturn expenditure has generally tracked CRU PR4 allowance with exception to 2017 and 2019 where notable reduced expenditures are identified.

From further inspection, the TAO gross outturn expenditure has consistently been below the CRU PR4 allowance with significant variation in years 2016 and 2017 of over €70 m. Similarly, the Interest During Construction (IDC) has been notably higher in 2016, 2017 and 2018 than the CRU PR4 allowance, although this is forecast to be less than the allowance in 2020. Conversely, the level of customer contributions to the TAO outturn is significantly lower than the CRU PR4 allowance for 2016 and 2017. A number of other adjustments have been included in the outturn which were not included in the allowance. Further consideration of these costs are included in Section 5.3.6.

The primary driver for reduced net spend over the PR4 period, including the early PR4 years analysis, can be attributed to the cancellation and re-scoping or delay of three major 400 kV projects which were forecast from the PR3 to the PR4 periods. These three projects accounted for an anticipated €491.5 m in the TAO PR4 forecast but have resulted in only €20.1 m of outturn expenditure, a variance of -€471.4 m as presented in Table 5-2.

Table 5-2 – PR4 Spend Breakdown for Major Projects

Year CP0721 – Grid West CP0466 – North South CP0732 – Grid Link Forecast Outturn Forecast Outturn Forecast Outturn

2016 0.0 0.0 40.0 0.1 0.0 0.0

2017 32.0 0.0 40.0 11.3 0.0 0.0

2018 64.0 0.0 40.0 2.4 0.0 0.0

2019 64.0 0.0 40.0 2.1 0.0 0.0

2020 64.0 0.0 10.0 4.3 97.5 0.0

Total 224.0 0.0 170.0 20.1 97.5 0.0

Variance -224.0 -149.9 -97.5

It is appreciated that the drivers for these projects and other issues have resulted in delivery delay or alternate, less capital intensive, delivery solutions. Further inspection of project delivery and variance is presented in Section 5.3 to explore these aspects associated with these projects and others.

5.2 PR4 Challenges and Opportunities

5.2.1 Outline of current responsibilities

The TAO is responsible for the safe and reliable maintenance of the transmission system and its development through construction of new transmission system works. To conduct this role in an efficient and timely manner, it must work in close partnership with the TSO.

The 2006 Infrastructure Agreement details the legal responsibilities of the TSO and TAO and a summary of the key activities and associated responsibilities are summarised in Table 5-3.



Table 5-3 – 2006 Infrastructure Agreement Summary

Activity TSO TAO Identification of Need X Provision of Standard Costs X Selection of Optimal Solution X Obtaining Planning Permission X Obtaining Wayleaves X Outage Planning X Detailed Design X Procurement of Materials X Procurement of Resources X Management of Site Works X Commissioning X

5.2.2 Collaboration with TSO

Through the PR4 period, the TSO and TAO have utilised a range of formal schemes to drive collaboration and provide full project lifecycle learning and improvement. These schemes have included:

Joint Programme Management Office – Online document library and fortnightly meetings to enhance communications, focussing on addressing programme level issues that affect multiple projects.

Client Engineer Meetings – Six regional meetings a year to allow TAO project leaders to feedback to the TSO on issues, risks, delays, mitigation and associated topics associated with project delivery. For larger scale projects, monthly site meetings are also held.

Transmission Outage Plan – TAO, TSO and DSO produce and jointly interrogate outage requirements for following year project delivery from which the TSO seeks to determine the most efficient and productive set of outages. A draft plan is produced in December and a final plan issued in February. Throughout the year, sustained engagement between the licensees continues to consider all solutions and mitigation to ensure the maximum amount of project delivery and maintenance can be completed within a robust outage period.

Multi Year Development Plan – 5 year look ahead of proposed projects by the TSO to understand and forward plan outage requirements for large, long term or complex projects. Outage conflicts between projects can be better resolved through the planning phase, prior to delivery.

5.2.3 Improvements from PR3 Period

The CRU provided a number of opportunities for improvement to the TAO based on its conclusion to the PR3 review. The TAO has considered and acted upon those opportunities for improvement though the PR4 period including:

Validation of unit costs – the TAO joined the International Transmission Operations and Maintenance Study (ITOMS) to compare performance against industry best practice.

Improved expenditure monitoring – Since the start of the PR4 period, the TAO (in conjunction with the TSO) has provided an annual Network Capital Expenditure Outturn Report to update project delivery progress more regularly.



Improve cost estimates – The TAO and TSO have collaborated earlier in the project identification process during the PR4 period as part of the pre-project agreement (pre-PA) phase. This process has resulted in forecast cost estimates in the PR4 period improving significantly from previous periods, as evidenced by the reduction in Additional Expenditure Approvals (AEAs), in volume and value. For example, only 6 AEAs have been issued on projects that commenced in PR4 to a value of €11 m in comparison to 43 which were issued in PR3 to a cost of €128 m. Further consideration of a review of a sample of AEAs is provided in Section 5.5.

Project change requests – A project change request process has been introduced such that all changes to time, scope or budget after a scope of works has been approved, is formally considered and approved by both the TSO and TAO before being acted upon. Further consideration of a review of a sample of project change requests is provided in Section 5.5.

Project close out reports – The TAO has implemented a standardised process to formalise end stage and end project reporting. Reports are produced by the owners engineer or lead project manager for all projects greater than €0.5 m within 6 months of PA (for pre-CA reports) and within 6 months of final energisation/completion (for end stage reports). The documents consider the success criteria of safety, scope, time, finance, quality and benefits. These documents, alongside other improvements in the PR4 period are captured in an enhanced lessons learned process.

Centralised data store – All project change request and AEA documentation is now centrally stored and updated through the life of the project for access to the TAO and TSO.

5.2.4 Specific Challenges in PR4 Programme Delivery

The TAO has outlined the following factors as challenges to delivering projects which have become more prevalent in PR4 as the period has progressed.

Scope Complexity

In the PR4 planning process, greater emphasis was placed by the TSO on increasing the utilisation of the existing grid and reducing the need to build new transmission infrastructure, resulting in an increase in ‘online’ uprate and refurbishment projects for the TAO to deliver. There are a number of benefits to this approach including overcoming land access issues (covered below), minimising environmental impact and maximising the utilisation of existing transmission infrastructure, however this means that the scope for delivering such projects is more complex for the TAO who must develop on more ‘brownfield’ sites.

Issues associated with working on live sites, gaining outages, bespoke design, control and protection during phased transition and other factors are more prominent in this design approach.

To overcome this so far as possible, the TAO has collaborated with the TSO early in the planning process to resolve issues and mitigate potential impacts to delivery early in the process.

Outage Constraints

As a result of upgrading existing assets and maintaining security of supply during construction, the ability to obtain sufficient outages for the TAO to delivery projects is becoming more challenging.



The TAO is proactively working with the TSO to plan outages and construction in as efficient a manner as possible which is reflected by a number of the improvements from the PR3 period noted in Section 5.2.3. This also includes consideration for reducing outage requirements such as relocating works, changing scope of works or changing transfer sequence orders.

Land Access Issues

Land access has been a continued concern. As noted in the PR3 historic capital expenditure report, issues with land access were noted as a cause of increased project costs during the PR2 period and were an ongoing issue in the PR3 period. A range of new initiatives were employed by the TSO in PR3 and no specific issues were identified with regard to cost escalations associated with transmission development as part of the PR3 historic report.

In relation to PR4, the TAO has noted that gaining land access has become more challenging as landowners seek greater detail and engagement early in the project development. Environmental consent requirements are also requiring consideration of alternate construction methods. Furthermore, large scale projects such as the North South interconnector have been subject to judicial review post award of planning permission which has had a direct impact on the time and effort spent by the TAO and associated early project development expenditure. Further inspection of the North South Interconnector project is provided in Section 5.3.

While the TSO has formal responsibility to achieve development consent, the TAO has stated its commitment to supporting the stakeholder engagement as required, noting that the relationships built during this period are crucial to successful delivery of the project by the TAO.

Recovery of Costs Associated with Deferred or Cancelled Capital Investment

Through the PR4 period there has been a significant increase in collaboration between the TAO and TSO which have been discussed above, specifically early in project development to improve aspects such as:

Outage planning

Project cost forecasts

Project scope refinements

Stakeholder engagement

Lessons learned

The TAO’s involvement and support to the TSO in this early planning stage has, in some instances, resulted in a project being cancelled or deferred as a result of the greater level of detailed information available, for which any costs incurred by the TAO cannot be capitalised. A review of how such costs in the PR4 period should be treated is provided in Section 5.3.5.

5.2.5 Cost Pressures

The TAO has not indicated that undue cost pressures have been experienced to date or are expected in the remainder of the PR4 period which will adversely impact on transmission project capital expenditure. This is supported by a review of the actual Harmonised Index of Consumer Prices (HICP) experienced during the PR4 period, as show in Table 5-4 which indicates that average prices have only grown by around 2.75% from the end of 2015 until forecast to the end of 2020.



Table 5-4 – Annual HICP Rates during PR428

2015 2016 2017 2018 2019 2020

HICP Annual Rate, % - -0.21 0.26 0.72 0.88 1.10

HICP Cumulative Rate, % - -0.21 0.05 0.77 1.65 2.75

Whilst it is recognised that the HICP adjustment factors can only be considered a proxy for escalation rates associated with electrical network equipment, it is nonetheless considered sufficiently representative of the general cost trends within the electricity supply industry.

5.3 Variation in Project Requirements and Costs

5.3.1 Current Status of PR4 Projects

It is expected that the forecast view of what projects were expected to be delivered in PR4 at the PR4 outset may be somewhat different from those projects actually delivered. However an understanding of the variation between planned/forecast projects and the outturn is necessary to evaluate project delivery requirements and efficiency. This variation in project requirements and costs presentation is made on the basis of the PR4 forecast as presented at the time of the PR4 submission in 2014 and as included in the TAO’s business plan submission.

An initial summary of project composition is presented in Table 5-5 which compares the number of projects and forecast expenditure in the PR4 forecast, against those in the outturn. This is broken down in to those projects which have progressed (forecast expenditure in 2014 and outturn expenditure by 2020), those that have not progressed (forecast expenditure in 2014 and no outturn expenditure by 2020) and new projects (no forecast expenditure in 2014 but some outturn expenditure by 2020). For completeness, there are a further 254 projects included within the TAO HBPQ submission which have no forecast or outturn expenditure associated and are therefore not included.

Table 5-5 – Project Composition in 2014 Forecast and 2020 Outturn

Project State No. of Projects Forecast Gross Expenditure in 2014

Outturn Gross Expenditure to 2020

Progressed 111 895.5 688.2

Not Progressed / Deferred / Delayed 3429 585.9 0.0

New 108 0.0 114.8

Total 253 1,481.4 803.0

The total forecasted gross cost of the original 145 projects in 2014 was €1,481.4 m on which a gross allowance of €1,032.2 m was provided and on which a gross outturn of €688.2 m has been recorded for known projects which have progressed. In addition, a further 108 projects have been added to the budget since the 2014 forecast which account for a spend of €114.8 m not previously forecasted. The majority of these additional projects are relatively low expenditure new connection projects (which are expected not to be fully known at the time of the PR4 forecast), line refurbishment works, protection works and STATCOM and series capacitor works.

28 As provided in TAO HBPQ updated 5th February 2020 to account for actual 2019 outturn 29 The TSO review indicates 30 non-progressed projects. The discrepancy is due to five projects which had TSO spend but not TAO spend and one project which had TAO spend but not TSO spend in the PR4 period.



Of interest is that approximately 25% of projects forecasted in 2014 were not progressed (34 of 145), however these not progressed projects reflect 40% of forecasted expenditure (€585.9 m of €1,481.4 m) and there are a similar number of new projects to known projects that have progressed (108 against 111), although the expenditure of new projects is significantly lower. This indicates that larger projects (by capital expenditure) have generally not progressed or are being delayed/deferred with a larger number of small projects (by capital expenditure) being progressed, some of which supersede larger projects.

5.3.2 Progressed Projects during PR4

The following section analyses the capital projects which were forecasted for expenditure in PR4 and outturn expenditure has been recorded within the PR4 period. These can be considered known projects that have progressed during PR4. Figure 5-2 provides a summary of these 111 ‘progressed’ projects with respect to the project category assigned by the TAO. The left chart provides a breakdown by number of projects, the centre chart providing a breakdown by capital outturn expenditure in PR4 with the right chart providing a breakdown by forecast expenditure.

Figure 5-2 – Progressed Project Category by Number and By Value

Figure 5-2 shows that nearly 50% of progressed projects relate to system reinforcements, which in turn account for approximately 75% of capital expenditure. Approximately 25% of projects by number relate to asset refurbishment with the remaining 25% associated with protection upgrades, DSO supporting projects, new connections and other activities. This breakdown is similar to the PR3 expenditure profile and is considered a comparable trend within the electrical transmission industry where network transition and growth is occurring within a constrained environment, resulting in a high proportion of capital expenditure intensive system reinforcement works.

With respect to capital expenditure associated with these projects, although the outturn expenditure (€688.2 m) is notably less than forecast (€895.5 m), the proportion of expenditure has broadly aligned between the forecast and outturn project categories. This indicates that although individual projects may have been delayed, underspent or overspent in the PR4 period to result in the outturn underspend from the forecast, the TAO has delivered a broadly proportionate capital expenditure to what was forecasted. I.e. there has not been a notable shift in the types of projects delivered between the outturn and forecast.

Based on the TAO’s categorisation in the submission, only 4 of the 111 ‘progressed’ projects (4%) are considered complete with an outturn capital expenditure in PR4 of €27.5 m. The remaining 107 projects are categorised as ongoing with an outturn capital expenditure in PR4 of €660.7 m. It is concerning that so few forecasted projects, many of which were already ongoing from PR3, have been completed within the PR4 period. A review of the PR4 forecast illustrates that only 13 of the 111 projects had expenditure still forecast in 2020, with the remaining 98



projects having no further expenditure forecast after 2019, suggesting they were expected to be completed within the PR4 period.

This lack of completed projects would suggest that further expenditure will be required in the PR5 period to complete these ongoing projects and is therefore difficult to understand the overall capital efficiency in delivery of these projects which are not yet completed. A review of the 107 classified ‘ongoing’ projects suggests that 74 of these projects have no anticipated expenditure in 2020 or earlier in the PR4 period which would suggests these additional projects will also be completed in the PR4 period.

Project Level High Cost Variance

Table 5-6 provides a summary of the top 5 positive and negative project level cost variances seen in PR4 for projects which were known in the PR4 forecast and have progressed (outturn expenditure in PR4 seen). Current significant forecast underspends are likely due to the project being delayed and additional expenditure will be required in the PR5 period to finalise the project, this will be commented upon in the forecast report. Concern is raised where significant overspends are already being recorded and the project is not yet completed, indicating that further overspend will be necessary.

Table 5-6 – PR4 Projects with Highest Cost Variance

Project No.

Project Name Project Phase

PR4 Forecast [€m]

PR4 Outturn [€m]

Variance €m

CP0399 Moneypoint-Tarbert 220kV cable – New cable

Post PA

8.3 26.7 18.3

CP0824 Moneypoint – Oldstreet 400kV line refurbishment

Post PA

6.1 21.6 15.5

CP0437 Dublin North Fringe (Bellcamp) 220kV Project – new 220kV station

Post PA

27.6 41.8 14.1

CP0501 Clashavoon-Dunmanway 110kV line – New line

Post PA

10.6 24.5 13.9

CP0647 Kilpaddoge 220/110kV station Post PA

4.5 16.4 11.9

CP0816 North Connaught line (Moy – Tonrow 110kV Line – New line)

Pre CPP Issue

16.3 0.004 -16.2

CP0799 Louth 220kV station refurbishment/upgrade Post PA

27.0 2.4 -24.6

CP0808 Maynooth 220kV station reconfiguration Pre CPP Issue

27.1 -0.05 -27.1

CP0585 Laois Kilkenny (Coolnabacky) 400kV Station – New station & associated lines and station works

Post PA

58.8 16.5 -40.3

CP0466 North South 400kV Interconnector CPP-PA

170.0 20.1 -149.9

Depending on the maturity of the project (project phase) the cost and scope accuracy varies as follows:



• Pre CPP Issue – These projects are not yet in the development phase and are the responsibility of the TSO. They have no formal TAO involvement. Scope and costs are therefore not yet fully developed and are based on initial assessments

• CPP-PA – These projects are assigned to the TAO to develop but remain the responsibility of the TSO until PA. Scope and costs will be approved at the end of this phase at PA, however until this time, they may change from CPP estimates.

• Post PA – These projects are in the delivery phase and are the responsibility of the TAO. These projects have developed and approved scope and costs and any changes in scope or cost are subject to project management governance.

Further inspection of Table 5-6 illustrates two projects that were also identified on the PR3 historic highest cost variance review, namely CP0799 (Louth 220 kV station refurbishment/upgrade) and CP0399 (Moneypoint-Tarbert 220 kV cable-new cable). In the case of CP0799, this showed as a €22.3 m underspend in the historic PR3 review and continues as a €24.6 m underspend in this review of PR4 outturn expenditure, illustrating a notable delay in the project delivery but with expenditure to date of €5.4 m across the periods. In the case of CP0399, this project was also shown as a high underspend in the PR3 outturn review of €48.0 m, however, the PR4 outturn now shows this project as one of the highest cost overspends of €18.3 m. Further details provided by the TAO have illustrated that the variation on this project was driven by delays resulting from the unavailability of a busbar connection due to a switchgear failure which was unforeseeable and therefore give reasoning for the significant swing in variance across the periods which could not be captured in PR4 forecasting. Project scheme papers have been received for these projects and a review of these documents is provided in Section 5.5.

Further inspection of known projects (forecast expenditure) which have progressed (expenditure in the outturn) has been provided in Figure 5-3. Of the 111 progressed projects, 56 (half) have experienced cost variance greater than €2 m which are illustrated in Figure 5-3. The average project variation across the 111 known progressed projects is an underspend in the order of €1.8 m, however this can be significantly skewed by the small number of significant over/underspends. Therefore, if the top 5 over/underspend projects are removed from the analysis (as detailed in Table 5-6), the average project variation across the remaining 101 known progressed projects is an underspend in the order of €0.2 m.


Figure 5-3 – Known Progressed Projects of Variance Greater than €2m



The analysis suggests that a small number of projects experience extremes in expenditure variance, half experienced expenditure with less than €2 m of variance and on average, excluding outliers, an underspend of €0.2 m is seen across known progressed projects.

Project scheme papers for those projects with high spend variance and a sample of other projects is provided in Section 5.5 to further analyse the reasons and actions taken by the TAO to manage high spend variance.

5.3.3 Non-progressed / Delayed / Deferred Projects during PR4

The following section analyses the capital projects which were forecasted for expenditure in PR4 and no expenditure has been recorded within the PR4 period. These can be considered known projects (at the start of PR4) that have not progressed during PR4 and may include projects which have been delayed or deferred. Figure 5-4 provides a summary of these 34 ‘non-progressed’ projects with respect to the project category assigned by the TAO. The left chart provides a breakdown by number of projects, the right chart providing a breakdown by forecast expenditure at the start of PR4.

Figure 5-4 – Non-Progressed Projects by Number and by Value

Figure 5-4 illustrates that the 34 non-progressed projects are split across approximately 33% system reinforcement projects, 33% asset refurbishment projects and 33% DSO and new connection projects. Although new connection projects relate to the lowest number of projects, they attribute to the highest proportion of non-progressed forecast expenditure which is dominated by CP0721 (Grid West Electricity Transmission Scheme) which accounts for €224.0 m of new connection category non-progressed forecast expenditure. Similarly, in the system reinforcement category two schemes dominate, namely CP0732 (Grid Link 400 kV) and CP0800 (North West Project) with forecast expenditure of €97.5 m and €58.1 m respectively.

Of the 34 known but non-progressed projects during PR4, these three schemes are most notable, accounting for €379.6 m of forecast expenditure but with no outturn expenditure. These projects are large scale 400 kV line projects and it is appreciated that the nature of the projects can be significantly affected by access constraints or changes in project drivers which can delay or defer project delivery.

The impact of these projects is significant on the overall PR4 allowance, with two non-progressed projects referenced in Table 5-2. It is therefore important to ensure that any alternative spend (where applicable to overcome constraints) or deferred spend is considered in the context of achieving the necessary goals in a timely and efficient manner.



With respect to CP0732 (Grid Link 400 kV), during the course of PR4 this project was replaced by 7 regional solutions which included 110 kV circuit uprates, 400 kV series compensation and 400 kV subsea cable installation. One project (CP0945 – Great Island – Kilkenny 110 kV Uprate) was forecasted and progressed as planned, with six new projects added. The outturn expenditure of these projects is currently €23.9 m with all projects categorised as ongoing. As there has been no TAO expenditure associated with the original Grid Link 400 kV project it is concluded that no inefficient TAO expenditure was incurred as result of a potentially semi-progressed project which has been abandoned. Alternate projects, under the direction of the TSO, have been progressed.

Similarly, with respect to CP0721 (Grid West), this has been replaced by CP0816 (North Connaught Line) which was a forecast project, as a reduction in expected wind generation was experienced, allowing the smaller scale project in isolation to be sufficient. As with CP0732 (Grid Link 400 kV), no expenditure was incurred on CP0721 (Grid West) prior to the change in project, limiting any inefficient expenditure that could have occurred.

5.3.4 Projects Added in PR4

The PR4 outturn provides data for 108 projects which did not have any forecast expenditure at the start of PR4 and therefore were not directly considered in the PR4 TAO allowance. These projects represent an additional PR4 outturn total capital expenditure of €114.8 m.

Figure 5-5 provides a summary of the project drivers for these projects added during the course of PR4.

Figure 5-5 – Projects Added by Number and by Value

A large proportion of added projects are related to new connections which is to be expected as these are driven by external factors, particularly new data centre connections, and are dealt with as required during the PR4 period. The largest expenditure category is system reinforcements. A review of these projects illustrates that over half were ongoing projects from PR3 (spend seen in PR3) with limited spend seen in PR4 to close out the projects which had not been forecasted for. The largest expenditure in this category is as a result of the new projects to replace CP0732 (Grid Link 400 kV) as discussed in Section 5.3.3.

5.3.5 Early TSO Engagement Non-Capitalised Costs

The TAO has implemented a collection of new processes in the PR4 period to aid the TSO in project development and decision making through the Line Project Assessment Report (LPAR), Qualitative Risk Assessment (QRA) and Transmission Line Assessment (TLA) processes.



Each of these processes provide further details on existing overhead lines to allow a more informed and refined project definition and delivery process for overhead line upgrades, uprates and refurbishment projects. The TAO has provided evidence for a number of projects where these processes have been employed which have resulted in a reduction in the works required (estimated saving of €38.2 m across a selection of four projects), reduction in outage requirements (complete the works quicker) and in some cases deferred capital investment with constraints being managed through maintenance only. For reference, using a sample of four projects (110 kV, 220 kV, long and short line lengths), the indicative average unit cost for these processes is €5,700/km (LPAR), €6,200/km (QRA) and €19,300/km (TLA).

Where the information from these processes results in a project agreement, the costs incurred can be capitalised against the project. However, where capital investment is deferred as a result of these processes, the TAO expenditure to that point cannot currently be capitalised. The TAO has noted that these conditions have only occurred in a small number of instances during PR4, however where they have occurred, the TAO seeks for these costs to be approved in the PR4 ex-post process.

It is appreciated that the LPAR, QRA and TLA processes may not provide direct cost savings in all cases, however the additional knowledge of the assets is beneficial and allows for a more efficient delivery of line uprates/upgrades/refurbishments as well as supporting the TSO in its network development decision making. Furthermore, in cases where capital investment is deferred, although the costs of LPAR/QRA/TLA are incurred, the results of the works are beneficial through efficiently identifying the required solution and mitigating larger scale, potentially unnecessary capital investment.

The TAO should therefore not be dis-incentivised from conducting such works as a result of the regulatory mechanics, particularly where the costs for the processes are relatively low and in most cases will be capitalised within a project which advances. It is only in cases where the process allows a full deferral of a capital project, that an alternate recovery scheme is required as the costs cannot be capitalised and recovered by the TAO.

With respect to this historic assessment, the TAO had requested €3 m costs within the initial submission which were incurred on an LPAR (CP0865 – Cashla Salthill 110 kV line uprate) which resulted in the identification of only maintenance works being required (line uprate deferred), should be allowed through this ex-post process. A follow up query with the TAO clarified that the costs sought were not €3 m (this was the forecast cost had the line uprate progressed) but were €0.227 m associated with the LPAR only (the information for which deferred the line uprate capital investment). Considering the €0.227 m expenditure on the LPAR resulted in the deferral of capital investment many orders of magnitude greater (forecast as €3 m), it is proposed that such costs are allowed in the outturn expenditure.

The TAO has highlighted that 11 projects are currently in the pre-project agreement phase (to a forecast value of €9.3 m) and there is the possibility of any of these projects resulting in a scenario similar to CP0865. Consideration for a method for recovering such costs going forward will be included within the forecast assessment.

5.3.6 Other Adjustments

The PR4 outturn includes €37.8 m of other adjustments, post capital expenditure which were not included in the PR4 forecast. Upon initial questioning, the TAO has noted that in 2018, the TAO recognised a provision of €15.4 m in relation to future claims of development loss due to deemed restrictions from the placement of transmission assets. This was capitalised in 2018 and will be utilised as future claims are made and settlements awarded. Allowances are only



sought when actual settlements are paid. These other adjustments are accounting adjustments and calculated in line with relevant accounting standards.

The TAO provided further information regarding these ‘other adjustments’ associated with loss of development following requests for further clarity. The TAO notes that as of the end of 2019 there are approximately 200 outstanding claims associated with loss of development which are claims settled either by the TAO reaching agreement with a landowner or following the appointment of an independent property arbitrator. The TAO provided examples of claims incurred in 2016 and 2017 which did not however align with the ‘other adjustments’ for those years. Furthermore, a breakdown of the TAO settlement/award vs the costs claimed by claimants illustrated a significant disjoint with average settlement of €70,000 and average claimant cost of €145,000, suggesting an unclear ‘market rate’ or agreeable level of compensation between the TAO and landowners. Landowners have a statutory entitlement to compensation, however the TAO is endeavouring to limit its exposure to future claims through the following approaches:

Setting valid claims at an early stage to limit the costs

Making Unconditional Offers (formal offers) when a negotiated settlement cannot be reached. This gives the TAO some costs protection in the event that a claim proceeds to Arbitration. I.e. if the award does not exceed the Unconditional Offer, the Claimant should not recover costs after the date on which the Unconditional Offer was made and the TAO should recover the costs that it incurred after that date.

Seeking set off of payments already made to landowners

Contending that if claims are not brought within six years they are too late. The TAO expect this issue to be referred to the High Court in 2020.

Challenging in the High Court certain decisions of some Arbitrators, which the TAO considers to be flawed decisions

Seeking reform of the Arbitration process, including making a submission to the Law Reform Commission, to reduce the costs associated with the Arbitration process

Although the TAO has provided further details on the loss of development claims as a process and proposed management approaches, it is still not clear precisely how these future claims of development loss are considered within the ‘other adjustments’ of the submission. In review of project scheme papers (see Section 5.5) where projects have been affected by arbitration or additional land access costs, these have been captured within the capital cost of the project and therefore these additional adjustments remain unclear. It is also unclear why the ‘other adjustments’ are anticipated to increase substantially in 2020 and why no such adjustments have been included in the PR5 forecast.

Further clarification is sought from the TAO with respect to these other adjustments to ensure no double counting of development loss and costs has occurred, to ensure the reasonableness of the other adjustments and to understand how this will be dealt with in the remaining years of PR4 and into PR5. The TAO, at the time of writing, has been requested to provide further clarification, and in the absence of such clarification, it is not possible to conclude if these other adjustments are appropriate and efficient.

5.4 Project Delivery Efficiency

5.4.1 Capital Forecasting

Capital forecasting analysis is limited to those projects which were forecast and have progressed. This analysis is conducted in Section 5.3.2 and summarised that a small number of



projects experience extremes in expenditure variance, half experienced expenditure with less than €2 m of variance and on average, excluding outliers, an underspend of €0.2 m is seen across known progressed projects. This suggests that for the most part, capital forecasting is sufficient even at a concept stage, with the majority of progressed projects being delivered for expenditure similar to the forecast value.

Further details for the outlier high overspend projects has been requested and is assessed in Section 5.5 to understand if the driver for overspend was in part due to refined forecasting or project delivery related issues.

5.4.2 Asset Delivery

Figure 5-6 provides a dashboard of charts illustrating new assets installed in the PR4 period and compared to the new assets installed in the PR3 period. This is broken down into the asset classes of overhead lines, underground cables, subsea cables, switchgear and transformers (including reactors). The final chart in the dashboard illustrates the percentage apportionment of new assets (and new outturn) across the PR3 and PR4 period. As an example, of all switchgear installed over the PR3 and PR4 period, 82% was installed in PR3 and 18% was installed in PR4.

This analysis is provided appreciating that the forecast projects in PR4 and those which have been constructed have changed significantly (see Section 5.3) therefore the ability to compare asset delivery from forecast to outturn is not achievable. The analysis conducted therefore compares expenditure in PR3 and PR4 versus assets installed in PR3 and PR4 to gain an indication relative cost for assets delivered across the periods.



Figure 5-6 – New Assets Dashboard

Review of Figure 5-6 illustrates that the number of overhead line and switchgear assets installed in PR3 was significantly greater than PR4. However the number of cables (both underground and subsea) were greater in PR4 than PR3. The number of new transformers has been similar. The increase in underground cabling would support the recognition taken at the start of PR4 that to achieve project delivery in a timely manner by mitigating environmental and planning constraints, a larger proportion of underground cabling will be required compared to overhead lines. Furthermore, these new asset numbers do not include line uprates and refurbishments, further recognising the move as noted by the TAO in PR4 to maximise the use of existing assets before new assets are installed.

Across both periods, new assets have been primarily at 110 kV and 220 kV with only a small number of 400 kV assets in substations (transformers and switchgear). This reflects the delay or re-scoping of the large 400 kV developments which have not been developed due to planning and land access issues as discussed in Section 5.1.

Table 5-7 provides a summary of the assets installed in PR3 and PR4 by asset class and the net capital expenditure outturn as allowed by the CRU in PR3 and as provided by the TAO in PR4.



Table 5-7 – Asset Summary

PR3 PR430 % Change

Overhead Lines (km) 1468.8 277.4 -81%

Underground Cables (km) 71.3 173.6 144%

Subsea Cables (km) 5.0 8.4 66%

Switchgear (No.) 350 172 -52%

Transformers (No.) 13 10 -23%

Net Outturn (€m) 982.3 674.6 -31%

The net outturn expenditure between PR3 and PR4 has decreased by 31% and this is reflected in the significant reduction in assets installed between the two periods. It is appreciated that different assets have different unit costs (e.g. cable is higher expenditure per km than overhead line) and that the assets installed do not account for line uprates and refurbishments of which there are understood to have been more of in PR4.

5.4.3 Asset Unit Costs

The TAO has provided a range of average unit costs for 2019 as used to forecast project costs. A selection of these costs is summarised, alongside 2011 and 2014 costs as provided by the TAO in previous business plan submissions with a variance between 2014 and 2019 costs shown in Table 5-8. Costs in Table 5-8 are nominal for the year detailed and are not on a common base.

Table 5-8 – TAO Unit Costs

Equipment 2011, €m 2014, €m 2019, €m Variance 220/110 kV 250 MVA Transformer 6.00 4.60 4.17 -9% 400/220 kV 500 MVA Transformer 9.04 7.45 6.65 -11% 400/110 kV 500 MVA Transformer 8.64* 7.10 6.32 -11% 400 kV Circuit Bay 1.83 1.71 1.53 -11% 220 kV Circuit Bay - 1.21 1.17 -4% 110 kV 430 mm2 ACSR Line New Build - 0.46 0.29 -38% 220 kV 600 mm2 ACSR Line New Build - 0.98 0.60 -39% 400 kV 2 x 600 mm2 ACSR Line New Build 1.53 1.76 1.05 -40% 220 kV XLPE Cable 2.24 2.04 1.18 -42% 2 x 110 kV XLPE Cable Circuits 1.62 1.35 1.24 -8%

Table 5-8 shows that all unit costs compared have reduced between 2014 and 2019. Typically this is in the order of 5-10%, however, new line costs have significantly reduced by 40% over the period on a per km basis. Looking further back to 2011, it can be seen that all costs with exception of 400 kV new line build have consistently reduced in cost from 2011, through 2014 to 2019.

It is appreciated that the asset composition of any project will include a mix of the equipment included in Table 5-8, plus other equipment. Furthermore, procurement for projects with long lead times will have resulted in costs incurred on 2014 basis rather than a 2019 basis through the PR4 period. It is nonetheless considered that overall project costs in the PR4 period will

30 In the TAO’s submission, installed assets to the end of the PR4 period were provided (including forecasts for 2019 and 2020) resulting in a discrepancy with the TSO submission as presented in Table 3-5.



have benefited from falling unit costs over the period compared to the forecast, in the order of 5-10% for most projects and gives some evidence to support some cost under-runs identified in Section 5.3.2. However, it also gives rise to questions on why the three largest known and progressed overspend projects are line and cable projects which have suggested a 40% reduction in unit costs between 2014 and 2019. This is further considered in Section 5.5.

It is unclear whether the wholesale reduction in asset unit costs continues to be obtained through enhanced asset procurement strategies, more efficient project management and delivery, reduced materials costs or a combination of these factors.

5.5 Review of Project Recording and Variation Justification

As stated in Section 5.2.3, the TAO has made a number of improvements following the PR3 determination, specifically with respect to standardised project documentation and monitoring of project delivery. The following section provides a review of a selection of project delivery documents including capital approval documents, additional expenditure approvals, project change requests and end project reports. The samples reviewed are for those projects with the greatest cost variances between PR4 forecast and outturn, those with potential project delay (based on PR4 forecast and outturn spend profile variance) and other projects of interest through the course of the review.

5.5.1 Capital Approval Documents

The TAO has provided 14 capital approval documents for review. The capital approval documents outline the scope, justification, timing and necessary budget to deliver a project for internal board approval. A comparison of the budget and timings outlined in the capital approval document, the PR4 forecast (as provided in 2014) and PR4 outturn are provided in Table 5-9.

The following aspects should be considered when reviewing Table 5-9:

• As many of these projects span the latter part of PR3, the outturn expenditure in 2014 & 2015 has been included for reference as the capital approval budget considers total project delivery cost requirements and is not isolated into regulatory period expenditure.

• It should be noted that PR4 forecast costs are ‘factored’ in that individual project costs may have been de-rated to account for the risk of their progressing or not over the PR4 period and therefore do not neccessarily reflect the full project forecast cost.

• The CA completion date is on basis of clear project duration and do not consider pauses, delays or deferrals that may occur during the project delivery such as delays due to land access or outage restrictions which are not known at this stage.

• The PR4 forecast completion date is the best estimate by the TSO for each project at the time of the PR4 forecast (2014). It is acknowledged that many of these projects are in early concept phase so the accuracy of the forecast is limited. As with the CA forecast completion date, it is not possible to include for delays such as outage constraints and land access delays at this stage of forecasting. It should be noted that if a project has progressed to CA by the time of the PR4 forecast, then the CA forecast completion date is used for the PR4 forecast completion date.

• PR4 forecast and outturn completion years are assumed based on the last year of the spend profile associated with the project. In some cases project completion may occur 1 year prior to the outturn completion year as a result of minor final costs which may arise after construction and energisation



.Table 5-9 – Capital Approval Budget and Timings Comparison

Project No.

Capital Approval Budget (€m)

2014/15 Outturn Spend (€m)

PR4 Forecast Spend (€m)

PR4 Outturn Spend (€m)

Capital Approval

Completion

PR4 Forecast Complete

PR4 Outturn Complete

CP0322L 2.8 0.3 0.0 0.08 2013 2015 2017 CP0399 69.7 44.7 8.3 26.7 2016 2016 2019 CP0437 55.7 4.5 27.6 41.8 2017 2018 2019 CP0647 75 31.5 4.5 16.4 2015 2016 2020 CP0650 65.4 26.2 4.9 3.8 2015 2016 2019 CP0773 1.2 0.4 0.9 -0.03 2013 2016 2017 CP0755 9.7 0.4 1.1 8 2015 2016 2019 CP0824 23.4 0.0 6.1 21.6 2020 2019 2020 CP0834 2.3 0.5 0.05 1.7 2016 2016 2019 CP0840 4.6 0.0 0.3 4.3 2016 2016 2019 CP0847 7.2 0.1 6.6 5.4 2016 2017 2018 CP0859 5.8 0.6 0.75 4.8 2015 2016 2018 CP0880 2 0.5 0.07 1.2 2015 2017 2018 CP0991 0.9 0 0 0.9 2018 - 2019

A visual comparison of expenditure is summarised in Figure 5-7. PR4 forecast and PR4 outturn are presented with 2014/15 actual expenditure added to allow a direct comparison with capital approval values.



Figure 5-7 – Comparison of Capital Approval, PR4 Forecast and PR4 Outturn Expenditure

Figure 5-7 shows that although these projects were identified as high variance between PR4 forecast and PR4 outturn costs suggesting notable overspend/overspend, the variance between outturn costs and capital approval are within budget (with exception to CP399 with a minimal overspend). This illustrates that based on this sample of projects, project outturn expenditure is broadly in line with capital approval forecasts, indicating that capital forecasting is appropriate and project delivery is within internally approved budgets.

However, this trend also illustrates that forecasts included in the PR4 submission were, in some cases, significantly under forecasted and it is unclear why this was the case when the majority of projects considered within this sample were ongoing from PR3 and capital approval was in place. Further clarity from the TAO was sought which noted that in a number of cases the scope was notably revised post PR4 forecast submission or that costs from the time between PR3 and PR4 may not have been accurately recorded during the submissions (i.e. end of PR3 costs which are not outturn at the time of PR4 submission). Limited reasoning has been provided and although not of primary concern to the outturn assessment (as outturn costs have been within capital approved forecasts) it is of consideration to the PR5 forecast costs to ensure such variance is minimised where possible for the purposes of the price control going forward.

A visual comparison of project completion years is summarised in Figure 5-8. PR4 forecast and PR4 outturn completion dates are assumed based on the final year of expenditure as included in the TAO submission.



Figure 5-8 – Comparison of Capital Approval, PR4 Forecast and PR4 Outturn Completion

Figure 5-8 illustrates that under all cases, with the exception of CP0824, outturn expenditure has continued to be incurred significantly after the expected completion date included in the capital approval documents. In many cases outturn expenditure has been recorded three to five years after project completion should have been achieved based on the capital approval documentation. It is also worth noting that in the majority of cases, forecast expenditure was included in the PR4 submission which was after the capital approval completion year and generally limited to the first year of PR4 (2016). This suggests that the TAO anticipated in its PR4 forecast that any completion not achieved by the end of PR3 would be achieved early in the following period, however outturn expenditure has continued late into the PR4 period (2018 and 2019 primarily).

This trend illustrates, for this sample of projects, that project completion has delayed significantly from the forecast included in the capital approval documentation and PR4 forecasts, or certainly that expenditure has been recorded a number of years after proposed completion. However, as total expenditure has been broadly in line with forecast expenditure in the capital approval documents (Figure 5-7), this suggests that although delays have occurred, they have not resulted in notable additional expenditure beyond the capital approval budget.

From this sample of projects, it can be concluded that the TAO has effective cost control with respect to internal capital approval budget and outturn expenditure however PR4 forecasting for these projects was inaccurate (high variance) and expenditure has occurred many years after proposed completion.

5.5.2 Project Change Requests (PCR)

The PCR has been introduced in PR4 to formally agree a change to the project time, scope or budget, jointly by the TAO and TSO, post capital approval. PCR forms for CP0991 (Kelwin Power Shallow Connection Works) and CP1015 (Bandon 110 kV Station – Protection Works) were provided by the TAO and reviewed. In the case of CP0991 additional TSO costs and potential additional civil works to the TAO were identified and captured in a supporting PCR



document. A subsequent AEA as a result of the PCR was produced and is considered in Section 5.5.3.

In the case of CP1015, the PCR recorded a minor change in design which was not foreseen to impact on time, resource, outages or safety at the time.

The documentation illustrates a positive project management process between the TSO and TAO to jointly agree scope changes and understand, at an early stage, any impacts such a change may have on the deliverability of the project. This allows any follow up actions, such as AEAs to be enacted in a timely manner.

5.5.3 Additional Expenditure Approvals (AEA)

AEA documents are produced to justify additional expenditure requirements beyond the capital approval budget. The TAO has noted that only six AEA documents have been issued on projects that commenced in PR4 to date, to a total value of €11 m in comparison to 43 which were issued in PR3 to a total value of €128 m. This reduction in AEAs illustrates an improvement in project forecasting (at capital approval) and project delivery to budget over the PR4 period which is supported by the analysis presented in Section 5.3.2 and Section 5.5.1. It is appreciated that a number of ongoing projects not yet completed in PR4 have a PCR and may require an AEA before the end of PR4 and into PR5, however the TAO has presented a worst case assumption that if all the PCRs resulted in AEAs, this would result in an additional €16.5m, significantly less than the overall number and value of AEAs over the PR3 period.

Four AEA documents have been provided by the TAO for review, namely CP0399 (Kilpaddoge – Moneypoint 220 kV cable), CP0501 (Clashavoon Dunmanaway new 110 kV Circuit), CP0991 (Kelwin Power Shallow Connection Works) and CP1015 (Bandon 110 kV Station – Protection Works). A summary of the original capital approval budget and forecast completion date alongside the AEA and revised completion date is provided in Table 5-10.

Table 5-10 – Review of Sample AEA

Project No. Capital Approval Budget (€m) AEA (€m) Capital Approval

Completion AEA Revised Completion

CP0399 68.7 18.7 2016 2018 CP0501 30.1 7.0 2015 2017 CP0991 0.9 0.9 2018 2018 CP1015 1.3 0.7 2019 2019

A review of the sample AEA documentation provided illustrates that the primary driver for the AEA is due to aspects which were insufficiently scoped at the capital approval stage, largely as a result of detailed design identifying additional requirements or in the case of customer connections, the timing and scope of works being affected by other parties such as completion of contestable works. In most cases, the AEA seeks additional budget to cover the previously un-scoped items, however this is then further impacted by additional design and contracting costs, overhead and IDC charges due to the delay in delivery. These costs are summarised Table 5-11.



Table 5-11 – Summary of Additional Costs sought in AEA Sample

CP0399 CP0501 CP0991 CP1015 Additional Contractor / Design / Materials Costs 8.4 3.5 0.4 0.35 Overheads 5.4 2.2 0.3 0.0 IDC 4.4 1.3 0.0 0.3 Other 1.2 2.3 0.0 0.06 Net Cost Savings 0.0 -2.2 0.0 0.0

It is appreciated that unforeseen circumstances occur during the delivery of a project and the AEA process is a formal approach to monitor and control expenditure when such circumstances occur. However, a closer review notes that some additional costs could have been avoided through diligent design, such as €0.7 m of additional expenditure required on CP0399 due to a design issue leading to a failure of a successful install of the 220 kV cable in the duct which required additional works to resolve the issue. Furthermore, the delay in project delivery results in further additional costs not originally scoped and may not be accrued (or not to the same level) if all works were sufficiently scoped prior to works starting. Additional overheads and IDC alone as a result of delays to completion of the works on these four projects is €13.9 m as a result of the projects being already underway and part completed at the time of the AEA. These costs account for approximately 10% of the total capital approval plus AEA value of these projects.

Certainly for CP0399 and CP1015, the delay is as a result of factors in the TAOs control. It is appreciated that delays in CP0501 and CP0991 are primarily as a result of third parties (land access and customer contestable works respectively) and the TAO can only manage these risks so far as possible.

5.5.4 End Project Reports

Seven end project reports were provided by the TAO for review. The end project reports provide a look back of project delivery on the basis of key aspects including safety, scope, timelines, cost, quality and benefits. Importantly, the documents provide lessons learned as a result of any challenges or successes which were experienced and the recommended action for the business to consider going forward.

Table 5-12 provides a summary of the end project reports sampled across the key project delivery aspects and the TAOs RAG assessment.



Table 5-12 – End Project Report Sample Review Summary

Project No. Safety Scope Timeline Cost Quality Benefits CP0859 CP0847 CP0755 CP0731 CP0650 CP0322L CP0991

The sample of end project reports have highlighted that safety, timeliness and cost were consistent issues. Scope, quality and benefits were succeeded in all cases. With respect to safety, in the majority of cases, this has been marked down as a red or amber risk due to protracted completion of as-built drawings post energisation. It is not clear why such delays have been occurring. In addition a number of contractor incidents/near misses have occurred.

CP0755 was delayed by 23 months from target date due to land access issues. A further 5 month delay occurred due to a damaged fibre joint and need to extend earthing resistance for one tower footing. Irrespective of the delays, the full project scope was delivered for €1.3 m less than capital approval, even with €1.0 m of landowner access payments not included in the capital approval. Similarly CP0859 was delivered 10 months late due to land access not being agreed prior to commencement. Full project scope was again delivered within capital approval budget even with €1.0 m of costs not included in the capital approval. These projects illustrate that where project delays have occurred, the TAO is generally able to deliver the project within capital approval forecasts, however there are additional costs incurred and it may have been possible for the TAO to deliver the projects for even less, if delays had not occurred. It is appreciated that the primary driver for delay is land access which is within the TSO scope, however, the TAO should have ensured such access was in place prior to commencement to prevent costs arising during delivery (i.e. delay start of delivery until access is achieved). Furthermore, secondary drivers for delays are due to aspects more within the TAO’s control, such as mobilisation of civil works to bring contractor up to adequate competence levels and repairs to fibre optics damaged during construction.

CP0731 exemplifies the impact that insufficient preparation for planning and access issues can have once the TAO has commenced delivery. For this project the TAO commenced delivery and was stopped for 4 years due to planning and legal processes and a further 1 year due to land access issues. The extensive delays and requirement for post-planning approval environmental controls resulted in the project going through two AEA processes and a final expenditure of €16.3 m against original capital approval of €9.3 m (although within the final AEA budget). It is appreciated that many of these costs were due to environmental requirements not accounted for at the time of capital approval, however it is likely that had those environmental requirements been suitably known and planned for pre-commencement, then the delivery costs would not have been so extensive.

5.5.5 Summary

The review of a sample of project documentation has broadly supported the high level analysis. In general the TAO has delivered projects within capital approval budget levels which reflects the TAOs ability to control and mange project delivery. The sample documentation has highlighted that project completion is, in most cases, notably later than forecast, however again, in the main, this does not affect capital expenditure. A review of AEAs has however illustrated



that project delays in some cases do result in potentially avoidable costs, borne by insufficient scoping or design and a subsequent need to extend the scope during project delivery, resulting in additional associated costs such as contractors, overheads and IDC.

A selection of end project reports have supported this view, highlighting that where projects have been delayed, although final outturn costs may still be within capital approval budget, there have been additional costs incurred. This suggests such projects could have been delivered for less had sufficient scoping and planning of the project delivery been conducted prior to commencement.

It can therefore be concluded from the above analysis that where delays have occurred, it is likely inefficient expenditure has occurred due to continued accrued cost to develop/construct the project beyond the initially proposed completion date. Direct inefficient costs have also occurred where insufficient design has resulted in doubling of works on site to rectify issues. Considering the direct delay costs of the reviewed AEA documents in the order of €13.9 m, the delay costs seen on CP0731 of €7.0 m and potential further savings of €1.0 m on CP0755 and CP859 respectively if delays hadn’t occurred, then the total potential cost of delay for these projects reviewed is €22.9 m.

It is appreciated that not all of these costs reviewed could be fully avoidable and that project changes do occur which the TAO is, in general, appropriately managing and documenting. However it is also appreciated that these conclusions come only from a sample of project documentation and it is likely that delays to completion on other projects not reviewed in detail will have resulted in a small proportion of less efficient expenditure as seen by this sample also.

It is therefore proposed that a 3% efficiency reduction be applied to the outturn gross expenditure (equivalent to €24.1 m) to reflect this trend of notable project delays during the period (see Figure 5-8) and associated inefficient expenditure required with achieving project completion following a delay.

5.6 Variations in project delivery timescales

The challenges in the PR4 delivery environment are largely detailed in Section 5.2.4 with the outstanding message being that a number of large scale projects have been delayed or re-scoped as a result of planning and land access issues which has resulted in the notable reduction in outturn expenditure against forecast. Other issues such as outage constraints and scope complexity have also been identified as challenges in the PR4 delivery environment.

It is appreciated that the TAO has been proactive in the PR4 period in managing key challenges to delivery. This has included year ahead transmission outage plans and multi-year development plans to mitigate increasing outage constraints and scope complexity as a result of projects being more ‘brownfield’.

Although it is the TSO’s formal responsibility to achieve development consent (on which a number of large scale projects have been delayed), the TAO has provided early development support to aid stakeholder engagement.

It is therefore appreciated that the TAO has implemented a number of processes over the PR4 period with the TSO and within its own business to better manage and control project delivery compared to the PR3 period. However, there have been a number of projects, as reviewed in Section 5.5, where project delays have occurred which could have been better managed by the TAO through improved diligence at the scoping and pre-commencement stage which in turn could have minimised delays and associated costs.



5.7 Conclusion from Historic PR4 Capex Review

The purpose of this review has been to assess and compare the levels and appropriateness of the TAO capital expenditure through the PR4 period, focussing on efficient project and asset delivery. The submission data and information provided by the TAO has been used to inform this assessment. Where further clarity has been sought, questions have been asked of the TAO to provide further evidence and justification. Where this has been provided, this has been included in the assessment and where queries are outstanding, this has been highlighted as an uncertainty in the conclusions.


The overarching TAO performance over PR4, in 2014 costs, is provided in Table 5-13.

Table 5-13 – Overarching Performance

PR4 Gross Forecast Expenditure (€m)

CRU Gross Allowance (€m)

PR4 Net Outturn Expenditure (€m)

CRU Net Allowance (€m)

1,481.4 1,032.2 674.6 875.4

The following summarises the general observations from the TAO historic PR4 capital expenditure review:

Net outturn expenditure is expected to be 77% (-€200.8 m) of the CRU PR4 allowance, noting that 2020 outturn is forecasted. Gross annual outturn expenditure has consistently been below the CRU PR4 allowance throughout the period.

Three 400 kV projects dominate the reduction in expenditure due to delay, re-scoping and cancellation, with a variance from the forecast of -€471.4 m.

The TAO has implemented a number of formal schemes with the TSO to improve collaboration and full project lifecycle feedback loops and planning. Specifically the transmission outage plan and multi-year development plan allow for improved outage visibility and management. The TAO has also developed layered transmission line assessments (LPAR, QRA and TLA) to support the TSO in project decision making and inform project requirements for the TAO. These schemes have saved or deferred capital investment (such as wholesale line uprates) by reducing the works required to achieve a network performance outcome.

Following guidance from the CRU PR3 conclusion which highlighted concerns regarding project delivery and variance management documentation, the TAO has implemented a number of formal processes to evidence and justify project variance. This includes project close out reports to summarise project success and for lessons learned purposes, project change requests to manage any project changes between the TSO/TAO and additional expenditure approvals to request, justify and approve additional expenditure beyond capital approval, where required. A sample of these documents have been reviewed as part of this assessment.

Land access and planning issues have continued to be a key issue during project delivery of PR4 and this has had an impact on the projects delivered by the TAO, specifically large scale 400 kV projects.

Cost pressures have been generally low over the period with average prices growing only 2.75% from 2015 to 2020.

Of the 266 projects included in the PR4 forecast, 111 have progressed with a outturn expenditure of €688.2 m, 34 were not progressed which deferred €585.9 m of expenditure



(dominated by cancelled, delayed or re-scoped 400 kV projects) and 108 projects were added with an outturn expenditure of €114.8 m.

Of the 111 progressed projects, half experienced a cost variance greater than €2 m, with an average underspend of €1.8 m. However, this average is dominated by the top 5 over/underspends, particularly the delay/deferral of large 400 kV projects. Extracting those projects from the analysis presents an average underspend on progressed projects of €0.2 m.

Added projects in the period have largely been as a result of new connections and ongoing system reinforcements from PR3 with limited finalisation expenditure in the early years of PR4. Largest expenditure in new projects is as a result of the new regional projects which replaced the Grid Link 400 kV scheme.

PR4 has seen an increase in the volume of underground and subsea cables compared to PR3 which in turn has increased installation costs per km compared to new overhead line which has reduced. Data regarding line uprates has been requested of the TAO but has not been received at the time of writing. New switchgear and transformer installations is also reduced in comparison to PR3. This asset delivery profile reflects the reduced expenditure in PR4 compared to PR3 and a change in the types of assets delivered (underground cables and line uprates vs new lines) to overcome planning and land access issues.

Asset unit costs have broadly reduced by 10% over the PR4 period (2014 to 2019), with a general trend of continued reductions from 2011. Cable and line costs have reduced by approximately 40% on a per km basis from 2014 to 2019.

Timely project delivery has again been a challenge in the PR4 period (as was seen in the PR3 period) driven primarily by planning and land access issues. It is appreciated that the TAO has implemented a range of new and improved processes with the TSO and its own business to better manage and control project delivery based on challenges in the delivery environment. However, there have been examples as reviewed in project delivery documents, where greater diligence from the TAO, particularly in the scoping and pre-commencement stage could have further controlled the delivery delay and associated costs.


A review of project delivery documents for projects illustrating the highest overspend cost variance from PR4 forecast to PR4 outturn was conducted. The review illustrated that in the majority of cases the capital approval forecast was significantly greater than the PR4 forecast and therefore projects were being delivered within capital approval budget. This supports the general view that the TAO has delivered projects within capital approval budget, however discrepancies in PR4 forecasting existed. The TAO provided some limited reasoning to these discrepancies with respect to additional scope being added post PR4 submission, or inaccuracies in the way both PR3 and PR4 expenditure was reported in previous submissions for projects which spanned both periods. To provide clarity on discrepancies in future, it is suggested that the TAO include price control forecasts into capital approval documents and where there is variance, this is evidenced such that an understanding internally and to the CRU can be maintained on project costs from concept forecasting through capital approval and outturn.

A review of project documents illustrated that in a number of cases, projects were delayed due to planning or land access issues. Although these issues are outside the direct control of the TAO, it was shown that the projects had commenced prior to such



issues being fully addressed. Further diligence from the TAO pre-commencement should have ensured such issues were mitigated prior to commencement, to prevent or better plan for costs being incurred during project delivery stage to overcome constraints. Similarly, a number of project delays and additional costs were incurred on projects due to insufficient scoping by the TAO at the capital approval stage, resulting in additional works during project delivery to address or overcome issues. In some cases, damage caused during construction had to be rectified. In each of these cases, where a project delay has occurred, the additional costs for materials are required, however additional costs are also borne as a direct result of the delay including contractor costs (particularly if delivery moves into a new year and new contractor rates apply), overheads and IDC. Although the TAO has kept visibility to such costs and delays through documentation and formal approvals, it is clear that a proportion of this expenditure is inefficient when dealt with during project delivery (rather than planned for during scoping) and particularly additional associated costs directly attributable to a project delay or costs associated with rectifying damage during construction. The assessment proposes a 3% efficiency reduction on the gross outturn (equivalent to €24.1 m) to reflect these findings, using the evidence from a review of a sample of documents as a basis.

The TAO’s LPAR/QRA/TLA processes have proven to be beneficial and it is agreed that the TAO should not be dis-incentivised to conduct such works if there is a risk that as a result of the works a project does not progress with capital investment and therefore costs cannot be capitalised and recovered. It is therefore proposed that the €0.227 m of costs associated with CP0865 LPAR assessment be allowed within the outturn expenditure.

The TAO has included €37.8 m of other adjustments, post gross capital expenditure which were not included in the PR4 forecast. The TAO has noted that such costs relate to future claims of development loss due to deemed restrictions from the placement of transmission assets. Further information on the issue of loss of development has been provided by the TAO, however evidence and justification of how this ‘other adjustment’ expenditure relates to loss of development has been requested as this is remains unclear and has not been provided at the time of writing. It is therefore not possible to understand if such costs are appropriate and efficient and suggest they are excluded until sufficient justification is provided on the suitability of the costs.

5.7.3 Considerations for PR5

The following provides some key considerations for the PR5 period following this review of the PR4 outturn:

The TAO has shown progression and pro-activeness in a number of processes with the TSO, and internally, to manage project delays and costs. The TAO should continue with these processes as a matter of business as usual as the benefits have been illustrated within the PR4 period. The TAO should consider the diligence employed at scoping and pre-commencement stages of project delivery to ensure scopes are sufficient, planning and access is in place and potential risks are understood (and mitigation measures in place). Improved diligence at this stage will minimise risks to project completion during delivery to overcome delays and costs as evidenced in PR4.

The TAO has shown improved documentation with respect to project scope, cost and timescale control through PCRs and AEAs which have assisted in evidencing why delays or overspends have occurred and appropriate justification. The TAO should continue these processes as part of business as usual. The TAO should consider the inclusion of any price control forecasts within capital approval documentation to illustrate any variance



that may have occurred internally and to the CRU, including of evidence why variance may have occurred.

LPAR/QRA/TLA processes have been shown to be beneficial and the TAO should not be dis-incentivised to conduct such works pre-project agreement at the risk of such costs not being capitalised if the outcome results in a capital project deferral. A mechanism in PR5 should be provided to support the TAO’s appropriate use of these processes. It is likely that such a mechanism would require reporting, potentially at the PR5 outturn assessment, to fully detail the cost/benefit of the process when it has been applied.



6. Review of PR5 Operating Expenditure: Transmission System Operator 6.1 Introduction

The objective of the CRU in setting allowed opex is to ensure that the TSO can deliver the outputs that are required by customers while challenging the licensee to perform at an efficient level. This should result in setting the TSO challenging but realistic targets and incentives. In this section of the report, we review the TSO’s proposed opex for the PR5 period and develop independent proposals for the opex allowance for the period from 2021 to 2025.

Unless stated otherwise, our review has prices expressed in real 2019 price levels. The TSO submitted actual cost data (up to 2018) in nominal terms and forecast cost data (2019 to 2025) in real 2019 price levels. We have adjusted 2018 costs to 2019 prices using a conversion factor of 1.009. We have made no further base price adjustment to the TSO forecasts.

The remainder of this chapter is structured as follows:

• In Section 6.2 we compare the opex that the TSO has requested for PR5 against PR4 outturn costs.

• In Section 6.3 we outline the analytical approach taken to develop our recommendations for PR5.

• In Section 6.4 we provide a detailed assessment of the TSO’s PR5 baseline for each cost area.

• In Section 6.5 we provide a detailed assessment of the opex step-changes included in the TSO’s PR5 business plan.

• In Section 6.6 we summarise our recommendations for PR5 opex, and compare this to the TSO’s request.

6.2 Overview of the TSO’s proposal

The opex requested by the TSO for PR5 is presented in Table 6-1. The TSO requested €1,275.5 million in total opex for PR5 compared with an outturn of €750.9 million in PR4. This is equivalent to an increase of €524.6 million (70%). The majority of this increase (€443.6 million) is due to a forecast increase in the cost of ancillary services, which are treated as a pass-through. For controllable opex, the TSO forecasts an increase of €73.3 million (30%) from PR4 to PR5. The majority of this increase is due to staff and related costs and IT costs.

The TSO also forecasts 1.0% per annum in RPEs net of ongoing efficiency, which amounts to a further €11.7 million opex during PR5 (i.e. total controllable opex of €330.3 million in PR5).



Table 6-1 – Requested PR5 Opex Allowance (excluding RPEs and ongoing efficiency)

TSO Opex (€m 2019 prices) PR4 PR5 Variation Outturn Requested PR5 – PR4 %

Controllable Opex

Staff and related costs 141.1 175.4 34.2 24%

Premises 26.9 31.2 4.4 16%

IT Costs 22.7 43.1 20.4 90%

Telecom Costs 25.3 27.6 2.3 9%

Professional Services31 20.1 21.7 1.6 8%

Selling and Advertising 8.7 15.1 6.3 72%

Contractors 6.6 9.5 2.9 44%


3.4 3.5 0.1 4%

Rates 2.4 3.0 0.6 24%

Insurance 1.3 1.5 0.2 12%

Promotion of Research 2.6 2.5 -0.1 -5%

Intercompany Recharges -15.8 -15.5 0.3 -2%

Total Controllable Opex 245.2 318.5 73.3 30%


Inter TSO Compensation 7.7 10.5 2.8 36%

CORESO subscription 1.3 2.8 1.5 113%

Interconnector services 3.9 4.1 0.2 6%

CER Levy 5.4 4.9 -0.5 -9%

DUoS costs 12.5 16.2 3.7 30%

Ancillary Services 475.0 918.6 443.6 93%

Total Non-Controllable Opex 505.7 957.1 451.3 89%

Total Opex 750.9 1275.5 524.6 70%

Source: EirGrid

The TSO’s request consists of €275.0 million for baseline / business-as-usual activities (€29.8 million (12%) above PR4 outturn), in part due to additional responsibilities associated with operating the I-SEM) and €43.5 million for a number of new initiatives planned for PR5.

Both of these requests are discussed in more detailed in the following sub-sections of this chapter. We do not assess non-controllable opex, as these costs are treated as a pass-through.

6.3 Base-Trend-Step methodology

This section of the report sets out the cost assessment methodology we have applied to estimate the efficient controllable opex for PR5. Our approach is based on a well-established and transparent methodology that accounts for the specific challenges of assessing the efficient costs of Ireland’s electricity licensees:

31 The professional services request includes ENTSO-E fees. The TSO requested that these fees be treated as non-controllable costs (i.e. pass-through) in PR5. However, based on our assessment (Section 6.4.2), we have continued to treat these costs as controllable and have included a recommended allowance for them.



• The TSO does not have any direct domestic comparators against which its costs could be benchmarked.

• The separation of responsibilities between the TSO and TAO is relatively unique by international standards.32

• In principle, the TSO could be benchmarked against international comparators. However, such international comparators typically operate under quite different regulatory, governance and operational environments, which means that it is currently difficult to place much weight on the results of such benchmarking to set the TSO’s cost allowance. For example, the electricity system operator (ESO) in Great Britain was established as an independent entity within the National Grid group in April 2019. However, there are important differences between the EirGrid TSO and GB ESO roles, and how they are remunerated under the regulatory regime. Independent system operators exist in other countries (e.g. parts of the USA and Australia) but they tend to be publicly owned and/or regulated on a not-for-profit basis.

Based on the above, we consider that a top-down benchmarking approach would be difficult to implement at present and could give misleading results. As a result, we have set out an approach that builds upon the bottom-up assessment that was taken in PR4. For each cost category (e.g. staff costs), we have applied an analytical approach that is commonly known as base-trend-step.33 As the name suggests, the approach consists of three analytical steps:

• identifying an efficient base level of opex that forms the starting point for future costs;

• projecting a forward trend in costs based on cost drivers and other assumptions; and

• Identifying any step changes to scope that would result in changes to costs (positive or negative) that are additional to the trend.

Each of these steps is discussed further in the subsections which follow.

A key strength of the base-trend-step approach is that it makes it very clear what customers would be funding in terms of new outputs and deliverables above business-as-usual costs. Taken together with our assessment of ongoing efficiency and real price effects (RPEs),34 this approach gives us the greatest confidence that our recommendations set challenging but achievable opex allowances for the TSO, and that they do so transparently.

6.3.1 Step 1: Approach to setting the TSO PR5 baseline

This step establishes an efficient starting point for the PR5 opex allowance. Establishing an efficient cost baseline is important to ensure that outturn inefficiencies or forecasting uncertainties for the latter years of PR4 are not implicitly rolled over into the PR5 control period.

OurThere are a number of challenges involved in setting the baseline for the TSO. In its PR5 submission, the TSO has outlined a number of transformational changes to its business that occurred since 2018. Most notably, the introduction of the I-SEM in 2018 resulted in a step-change in the operational responsibilities of the TSO in terms of additional IT support and development, operating the I-SEM capacity service; and balancing market scheduling. The TSO has requested that the baseline is set on the average forecast cost level for 2019 and 2020,

32 This arrangement exists in Northern Ireland, where the TSO and TAO are also owned by the EirGrid and ESB groups, respectively 33 For example, the approach is used by the Australian Energy Regulator in its regulatory cost assessments. See: AER, Expenditure forecast assessment guideline for electricity distribution and AER, Expenditure forecast assessment guideline for electricity transmission. 34 CEPA, Real Price Effects and Ongoing Efficiency Improvements for PR5 – report for the CRU



based on the notion that these are the only calendar years which are comparable to the TSO’s business-as-usual operational costs for PR5.

Our preferred approach is typically to set the baseline on actual costs incurred by the licensee and adjust for new volumes of activity and new outputs via the trend and steps. However, we recognise that the context of the TSO in PR4 presents a challenge to our preferred approach. Based on the evidence submitted, we consider that in this case using 2019 and 2020 figures to set the baseline would be a more transparent approach than using 2018 figures with adjustments for activities taken in 2019 and 2020. In making this decision we have considered the following:

• Due to the introduction of the I-SEM, outturn costs between 2016 and 2018 are not representative of the TSO’s PR5 opex business-as-usual activities. The first full year of operating the I-SEM was in 2019.

• We understand that the TSO’s outturn costs for 2019 are close to forecast costs submitted for 2019. So, by using an average of 2019 and 2020 we are anchoring the baseline to outturn costs while accounting for the increasing level of activity (as reflected in 2020 forecasts).

• Given the inherent uncertainty on setting the baseline on forecast costs, we consider that the average of 2019 and 2020 represents a more robust baseline compared to setting the baseline just on 2019 or on 2020 cost forecasts. For example, The TSO has forecast cost variation between 2019 and 2020 – e.g. contractor costs are forecast to decline between 2019 and 2020 while staff costs are forecast to increase. Faced with this uncertainty, we consider that setting the baseline on any single forecast year risks under- or over-estimating the true baseline for the TSO.

On a case-by-case basis, we have adjusted our default approach to setting the baseline where there is evidence to suggest that the approach set out above could represent an inappropriate baseline for PR5. This has been informed by our ex-post review of the TSO’s opex over PR4 (see section 1). However, there are important differences between the ex-post assessment and setting the baseline – the latter excludes atypical and one-off costs that may be allowed as part of the ex-post review. A detailed description of the rationale and impact of the cases where we have made such adjustments to our approach is outlined in Section 6.4.

In order to compare our baseline forecast, we have estimated the TSO’s baseline request by subtracting the costs associated with each of the step-changes from the total requested cost level. For example, the TSO has requested €175.4 million in total staff and related costs over PR5. Of this total, the TSO has requested €21.0 million in staff and related costs associated with a series of step-changes and initiatives. By subtracting the €21.0 million from €175.4 million, we assume that the TSO’s baseline request for staff and staff related costs is equal to €154.3 million. We welcome any further information that the TSO can provide on this approach in its response to the CRU’s draft determination to allow us to further validate that our proposed baseline provides an achievable level of opex in PR5.

6.3.2 Step 2: Applying a trend projection

After setting the baseline, we forecast how efficient costs may evolve over PR5 (up to and including 2025).

The projection of costs across PR5 could be based on the identification of relevant cost drivers for each cost category. The nature of the TSO’s business means that costs are not, for example, typically directly related to energy volumes or the number of connected customers. This conclusion is supported by the TSO’s PR5 submission, which highlighted that it considers



telecoms, premises, IT, insurance, grid maintenance and rates as fixed relative to the continuing operation of the company.35

Notwithstanding this view, and based on our review of the TSO’s PR5 forecasts and discussions with the TSO, we consider that telecoms costs are likely to be influenced by the number of new connection sites over PR5. We include this analysis within our assessment of the PR5 opex baseline assessment in Section 6.4.9.

for individual cost categories exclude any RPEs or ongoing efficiency. Our approach and analysis of RPEs and ongoing productivity for all three licensees is presented in a separate paper.36

6.3.3 Step 3: Identifying “step changes” in scope

The final step in our approach is to identify whether there are any changes in the outputs the TSO is expected to deliver in PR5 that are not captured by the trends projected in the previous step. In general, step-changes will account for new initiatives and requirements faced by the TSO during PR5. For example, a one-off change in regulatory scope may increase or decrease opex. Similarly, the decision to switch from funding a network activity through an opex solution rather than a capex solution could be accounted for in a step change. Step changes can be positive (i.e. increase efficient opex) or negative (i.e. reduce efficient opex).

This step in our approach is based on our evaluation of the TSO’s business plan against the following criteria / gateways:

• Need – is there clear evidence that there is expected to be a change in the activities or costs incurred by the TSO? Have the aims and objectives of the step-change been set out? Has it been clearly aligned to the strategic objectives the CRU has set out for PR5?37 We apply a pass / fail criterion to this gateway.

• Mapping to the business plan questionnaire (BPQ) submission – has the TSO clearly mapped the step-change to its BPQ? We apply a pass / fail criterion to this gateway.

• Additionality – has it been clearly demonstrated that the costs associated with the proposed step-change are additional relative to the base level of opex? This question is not equivalent to asking whether the initiative / project is new or unique. For example, a brand-new IT application could replace an existing application in such a way that there is no additional cost to the consumer. Therefore, we assess whether the TSO demonstrated that existing resources are fully exhausted / utilised and additional resources are required to deliver the proposed step-change. A cost challenge of up to 25 percent is applied if we conclude that the TSO has not demonstrated additionality.

• Cost efficiency and customer value – has it been clearly demonstrated that the costs associated with the step-change are efficient? Have other options been explored that could achieve the same outcome? What metrics have been used to test that the requested costs are efficient? Has the TSO provided evidence that costs have been market-tested or benchmarked? Is there a clear demonstration of customer value associated with the outcomes of the step-change? Was a range of options considered? A qualitative judgement is required in cases where there is a lack of benchmarking data

35 EirGrid (2019) Appendix 1 – Historical BPQ Narrative, Section 1.1 Q8. 36 CEPA, Real Price Effects and Ongoing Efficiency Improvements for PR5 – report for the CRU 37 Note that step-changes do not necessarily have to be linked to the CRU’s strategic objectives – they could be the result of other external factors or initiated by the TSO. Likewise, a step-change could be linked to the PR5 strategic objectives but still be challenged on additionality and efficiency grounds.



available to assess cost efficiency - for example, if the activity has not been delivered by the TSO before and/or comparators are not available. A cost challenge of up to 25 percent is applied in these cases where we conclude that the TSO has not demonstrated cost efficiency and customer value of the step-change.

The first two gateways are pass / fail. This means that if we do not consider that the need for a step-change has been clearly set out, or if the TSO has not clearly mapped the step-change to the BPQ, our recommendation is that the step-change is not included in the allowance the CRU sets. The latter two gateways can have a partial pass, with up to a 25 percent cost challenge applied at each gateway (meaning a maximum cumulative efficiency challenge of 50 percent challenge on any step-change that passes the first two gateways).

Deciding the level of the cost challenge that should be applied for additionality and/or efficiency is inherently a judgement call. That judgement is necessarily informed by the information provided (or not provided) by the TSO. In addition to the specific types of evidence listed above, we have based that judgement on general considerations such as:

• The completeness, clarity and consistency of the supporting information provided for the proposed step-change.

• The level of detail provided to support the cost forecast for the step-change (relative to the monetary level of the step-change).

• Whether the TSO has demonstrated that the costs of the proposed step-change are proportionate to the customer benefit.

We summarise the judgement calls on the proposed step changes using a ‘traffic light’ assessment, which is presented in section 6.5.7.

It is important to recognise that in the context of a price review, the obligation is on the TSO to demonstrate the need, additionality and efficient level of forecast step changes in expenditure.

The adjustments we make in the final two gateways, however, should also not be viewed purely as an efficiency challenge. Rather than a binary pass-fail system for these gateways, the adjustments we have applied are intended to signal to the TSO during the PR5 consultation process, step changes where it has demonstrated the need for expenditure in its BPQ, but further information and evidence is needed to establish the additional level of funded expenditure above the baseline. This means that where sufficient evidence and information can be provided by the TSO as part of its response to the PR5 consultation, we may revisit the adjustments we have made in these two final gateways.

We also envisage that all step changes will be linked to price control deliverables - we explore this further in a separate stand-alone paper on the regulatory framework.38

6.4 PR5 Opex Baseline Assessment

his section outlines our PR5 opex baseline assessment for each controllable opex category listed in the TSO’s BPQ.

6.4.1 Staff and staff related costs: PR5 baseline

We set the PR5 baseline for staff and staff related costs by the following three steps:

• identify an appropriate baseline in terms of FTEs;

• identify an appropriate baseline in terms of FTE unit-costs; and

38 CEPA and GHD, Regulatory framework for PR5 – report for the CRU



• Construct the staff and staff related cost baseline as a product of the FTE and FTE unit-cost baselines.

This approach gives us the flexibility to separately identify trends in FTEs and in FTE unit-costs in order to construct an appropriate PR5 baseline for the TSO. Based on the evidence provided, we set the baseline number of FTEs equal to the average level forecast by the TSO for 2019 and 2020. We have followed our default approach to set the baseline on the average 2019 and 2020 levels. We estimate the cost baseline by multiplying baseline FTE numbers by the 2019 unit cost per-FTE. We note that the 2019 FTE unit-cost is close to the FTE unit-cost forecast by the TSO for PR5.

The baseline staff and staff related cost level The baseline staff and staff related cost level isis then set as a product of the baseline number of FTEs and the baseline unit-cost. This gives a staff cost and staff related cost baseline of €30.5 million.

Table 6-2 presents a year-on-year comparison between our recommended opex baseline for staff costs and staff related costs and the TSO’s request (excluding costs attributable to PR5 step changes). The TSO has forecast €154.3 million in baseline staff costs and staff related costs (with additional costs for new initiatives – discussed in Section 6.5) compared to our forecast of €152.3 million. This represents a difference of €2 million (1%).

Table 6-2 – Staff costs and staff related costs: PR5 baseline

TSO opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5 CEPA forecast 30.5 30.5 30.5 30.5 30.5 152.3

TSO Submission 30.7 30.7 30.7 31.1 31.1 154.3

Difference -0.2 -0.2 -0.2 -0.6 -0.6 -2.0 Source: CEPA analysis

Note that FTEs are used as a proxy for expenditure units in this analysis. It is up to the company to use the allowance in line with its business plan to deliver required outputs and this report should not be taken as sanctioning any level of FTEs or base FTE cost.

6.4.2 Professional Services: PR5 baseline

Before setting our PR5 baseline for professional services, we have made an adjustment to the TSO’s request in order to account for European Network of Transmission System Operators for Electricity (ENTSO-E) fees. The TSO requested that the €0.5 million annual cost in professional fees associated with their membership of ENTSO-E be treated as non-controllable opex in PR5 (they are treated as controllable opex in PR4).

We do not consider that the TSO has justified this proposed change. As a result, we have added the €0.5 million annual ENTSO-E costs back into the TSO’s baseline professional services. However, we welcome further information from the TSO on this area in response to the CRU’s draft determination. This adjustment is outlined in Table 6-3 below.

Table 6-3 – TSO adjusted professional services baseline request

TSO opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5 TSO baseline request 3.3 3.3 3.3 3.3 3.3 16.5

ENTSO-E fees 0.5 0.5 0.5 0.5 0.5 2.5

Adjusted TSO baseline 3.8 3.8 3.8 3.8 3.8 19.0 Source: CEPA analysis

Our review of PR4 costs found that spend on professional services increased significantly over the period, from €2.3 million in 2016 to €6.6 million in 2020. The TSO said that the introduction



of the I-SEM in 2018 led to a large increase in the requirements for professional services. Between 2017 and 2018, professional services costs increased by €1.0 million (39%). The TSO said that further increases in professional services costs in 2019 and 2020 are as a result of increased legal services due to disputes and support for the PR5 process, neither of which are expected to continue into PR5.

Based on the above, we do not consider that our default approach to setting the baseline on the average of 2019 and 2020 forecast costs represents an appropriate baseline for PR5. The average forecast cost level for 2019 and 2020 is €5.8 million. This is €2 million (51%) above the average level of professional services that is requested by the TSO over PR5 outside of the planned new initiatives39. As a result, we have set our recommended baseline at €3.8 million, equal to the level requested by the TSO for PR5. This is summarised in Table 6-4 (excluding costs attributable to PR5 step changes).

Table 6-4 – Professional services: PR5 baseline

TSO opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5

CEPA forecast 3.8 3.8 3.8 3.8 3.8 19.0

TSO Submission 3.8 3.8 3.8 3.8 3.8 19.0

Difference - - - - - - - - - - - - Source: CEPA analysis

6.4.3 Information Technology (IT) opex: PR5 baseline

Our review of PR4 costs found that IT opex increased significantly from €3.1 million in 2016 to €6.1 million in 2020. The TSO said that the increase in costs is due to the introduction of the I-SEM. As a result, we have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020.

Table 6-5 presents a year-on-year comparison between our recommended baseline for IT opex and the TSO’s requested IT opex (excluding costs attributable to PR5 step changes). The TSO has forecast €30.3 million in IT opex compared to our forecast baseline of €29.1 million. This represents a difference of 1.2 million (4%).

Table 6-5 – IT opex: PR5 baseline

IT opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5

CEPA forecast 5.8 5.8 5.8 5.8 5.8 29.1

TSO Submission40 6.3 6.6 5.9 5.7 5.8 30.3

Difference -0.5 -0.7 -0.1 0.1 0.0 -1.2 Source: CEPA analysis

The difference between our recommended allowance and what has been requested by the TSO is primarily due to an increase in IT costs from €6.1 million in 2020 to €6.6 million in 2022 which we understand is not associated with any of the new initiatives proposed by the TSO for PR5. The TSO has forecast that baseline costs will decline over the second half of PR5 back to our recommended baseline level. We welcome any further information that the TSO can provide that would explain this change in costs in its response to the CRU’s draft determination.

39 As noted above, we have defined the ‘baseline’ request for professional services as the total forecast for professional services net of the identified costs for the new strategic initiatives discussed in Section 4.5. 40 Note that these costs exclude those associated with moving certain applications to the cloud and enhancements to the IT operating model. Costs associated with these initiatives are discussed separately in our step-change analysis in Section 6.5.



6.4.4 Contractors: PR5 baseline

Our review of PR4 costs found large variation in the year-on-year outturn spend on contractors. Outturn costs range from €0.9 million in 2016 to €1.9 million in 2019. The TSO said that the increase in costs over time is due to the introduction of the I-SEM in 2018 as well as Contract Managed Services for the provision of IT services under the I-SEM. As a result, we have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020.

Table 6-6 presents a year-on-year comparison between our recommended baseline for contractors and the TSO’s requested contractors opex (excluding costs attributable to PR5 step changes). The TSO has forecast €9.5 million in contractor costs compared to our forecast baseline of €8.4 million. This represents a difference of 1.2 million (12%).

Table 6-6 – Contractor costs: PR5 baseline


CEPA forecast 1.7 1.7 1.7 1.7 1.7 8.4

TSO Submission 1.9 1.9 1.9 1.9 1.9 9.5


The difference between our recommended allowance and what has been requested by the TSO is primarily due to a forecast decrease in contractor costs from €1.9 million in 2019 to €1.4 million in 2020. As our baseline is set on the average of these years, the forecast decline in costs in 2020 results in a lower PR5 baseline. We welcome any further information that the TSO can provide that would explain this change in costs in its response to the CRU’s draft determination.

6.4.5 Insurance: PR5 baseline

Outturn costs range from €0.1 million in 2017 to €0.4 million in 2016. We also note that the TSO has forecast insurance costs falling (by less than €0.Our review of PR4 expenditure did not find evidence of inefficiency in outturn spend on insurance. The TSO forecasts €1.3 million of insurance expenditure compared to an allowance of €1.01 million per annum) between the average forecast level in 2019 and 2020 and the average level requested for PR5. Based on this decline, our default approach to setting the baseline on the average of 2019 and 2020 costs would have resulted in too high a baseline for PR5.

As a result, we have set our recommended baseline at €0.3 million, equal to the level requested by the TSO for PR5. Table 6-7 presents a year-on-year comparison between our recommended baseline for insurance and the TSO’s request (excluding costs attributable to PR5 step changes).

Table 6-7 - Insurance costs: PR5 baseline

TSO opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5 CEPA forecast 0.3 0.3 0.3 0.3 0.3 1.5

TSO Submission 0.3 0.3 0.3 0.3 0.3 1.5

Difference -0.0 -0.0 -0.0 -0.0 -0.0 - - Source: CEPA analysis



6.4.6 Grid Maintenance and Client Engineering: PR5 baseline

Here is some variation in the year-on-year outturn spend on grid maintenance and client engineering. We have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020 for the reasons set out above.

Table 6-8 presents a year-by-year comparison between our recommended baseline for grid maintenance and client engineering and the TSO’s request (excluding costs attributable to PR5 step changes). The TSO has forecast €3.5 million in grid maintenance and client engineering opex compared to our forecast baseline of €3.4 million.

Table 6-8 – Grid maintenance and client engineering: PR5 baseline


CEPA forecast 0.7 0.7 0.7 0.7 0.7 3.4

TSO Submission 0.7 0.7 0.7 0.7 0.7 3.5

Difference41 -0.0 -0.0 -0.0 -0.0 -0.0 -0.2 Source: CEPA analysis

6.4.7 Premises: PR5 baseline

Our review of PR4 premises expenditure showed that the TSO forecasts to spend €26.9 million compared to an allowance of €24.2 million. We have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020.

Table 6-9 presents a year-on-year comparison between our recommended baseline for premises opex and the TSO’s request (excluding costs attributable to PR5 step changes). The TSO has forecast €29.2 million in premises opex compared to our forecast baseline of €27.2 million. This represents a difference of €2.1 million (7%).

Table 6-9 – Premises costs: PR5 baseline


CEPA forecast 5.4 5.4 5.4 5.4 5.4 27.2 TSO Submission 5.6 6.0 5.9 5.9 5.9 29.3


The difference between our baseline forecast and what has been requested by the TSO is due to a requested baseline increase in premises costs from €5.5 million in 2020 to €6.0 million in 2022. We do not consider that the TSO’s submission has evidenced what is driving the increase between these years. The TSO has stated that a rent review in 2022 on its premises in The Oval, Dublin is expected to increase costs by €0.4 million per annum. However, this requested increase is dealt with separately as a step-change in Section 6.5.6. As such, we do not consider that this explains the requested increase in costs.

We welcome any further information that the TSO can provide on this in its response to the CRU’s draft determination.

6.4.8 Promotion of research: PR5 baseline

Our review of PR4 opex indicates that the TSO has reallocated costs from ‘research, development and demonstration’ to ‘promotion of research’ within its PR5 business plan. As a

41 Differences are not shown due to rounding



result, we consider these two categories together when setting the promotion of research opex baseline.

Total outturn costs across both these cost areas vary across PR4. Average outturn spend between 2016 and 2018 was €0.6 million, with forecast average spend of €0.4 million for 2019 and 2020. We have followed our default approach to set the baseline equal to the average forecast costs for both of these categories in 2019 and 2020. This sets the baseline equal to €0.4 million.

The TSO has forecast €1.5 million in promotion of research opex after excluding costs attributable to PR5 step changes, which is below our forecast baseline based on PR4 expenditure. As a result, we accept the TSO’s requested promotion of research opex (excluding costs attributable to PR5 step changes), as demonstrated in Table 6-10.

Table 6-10 – Promotion of research: PR5 baseline

TSO promotion of research (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

CEPA forecast 0.3 0.3 0.3 0.3 0.3 1.5 TSO Submission 0.3 0.3 0.3 0.3 0.3 1.5

Difference - - - - - - Source: CEPA analysis

6.4.9 Telecoms opex: PR5 baseline and trend analysis

Our review of PR4 expenditure found that the TSO expects to underspend its PR4 telecoms opex allowance by €5.8 million (19%), which is driven by a lag in the delivery of some of its telecoms programme across PR4. We recommend that the under-delivered programmes are not funded again in PR5, as we expect the TSO to deliver the programmes with its PR4 allowance.

We have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020. This gives a baseline of €5.6 million per annum.

The TSO has forecast that the number of connections are expected to increase from 22 in 2019 to 30 in 2025 – a 36% increase. The TSO said that its PR5 estimate is based on the assumption of a constant unit-cost rate which is set by ESB Telecoms, with the increase in costs due solely to the volume of installations.

Based on this information, we consider that a cost trend projection for telecom costs over PR5 is appropriate. We have forecast the increase in costs over PR5 under the assumption that the unit-cost of each connection is unchanged from 2019 levels. This gives a unit-cost of €0.24 million. Table 6-11 summarises the projection of telecoms costs under this unit-cost assumption.

Table 6-11 – Telecoms opex: PR5 trend analysis Telecoms opex (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

Baseline 5.6 5.6 5.6 5.6 5.6 28.0

Additional connections per annum

2 2 2 2 0 -

Unit-cost (€ million) 0.2 0.2 0.2 0.2 0.2 -

Cumulative trend (€ million) 0.5 1.0 1.4 1.9 1.9 6.8

Baseline + Trend projection 6.1 6.6 7.0 7.5 7.5 34.7 Source: CEPA analysis

The impact of our default baseline and trend projection gives a recommended baseline of €34.7 million. This is €7.1 million (26%) above the TSO’s requested baseline of €27.6 million.



The TSO has said that IP enabling works that was completed during PR4 will generate savings of €1.0 million per annum during PR5. Non-network capex investments in end of life replacement and connecting new infrastructure are also expected to generate savings over PR5. Based on our understanding of these efficiency savings and given the TSO’s forecast baseline falls within our base + trend projection, we accept the TSO’s own forecast.

Our recommended forecast (excluding any step changes) is presented in Table 6-12.

Table 6-12 – Telecoms opex: PR5 baseline and trend

Telecoms opex (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

CEPA forecast 5.1 5.3 5.5 5.7 6.0 27.6

TSO Submission 5.1 5.3 5.5 5.7 6.0 27.6

Difference 0.0 0.0 0.0 0.0 0.0 0.0 Source: CEPA analysis

6.4.10 Selling and Advertising: PR5 baseline

Our review of PR4 opex notes that the TSO has established a new directorate for selling and advertising, with additional funds apparently reallocated from other cost categories. We recognise that it may be a necessary function in a complex stakeholder environment to help ensure that transmission projects are not unnecessarily held up through the planning process. However, the TSO’s business plan does not set out what outputs would be delivered as a result of the increased investment (both historical and proposed for PR5) in this category. We welcome any further information that the TSO can provide on this in its response to the CRU’s draft determination.

We have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020. Table 6-13 presents a year-on-year comparison between our recommended baseline for selling and advertising opex and the TSO’s request (excluding those costs attributable to PR5 step changes, which are discussed in Section 6.5). The TSO has forecast €11.0 million in selling and advertising opex compared to our forecast baseline of €10.3 million. This represents a difference of €0.7 million (6%).

Table 6-13 – Selling and advertising: PR5 baseline

Selling & advertising opex (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

CEPA forecast 2.1 2.1 2.1 2.1 2.1 10.3

TSO Submission 2.2 2.2 2.2 2.2 2.2 11.0


The difference between our recommended allowance and what has been requested by the TSO is primarily due to a forecast decrease in selling and advertising costs from €2.3 million in 2019 to €1.8 million in 2020. As our baseline is set on the average of these years, the forecast decline in costs in 2020 results in a lower PR5 baseline. We welcome any further information that the TSO can provide that would explain this change in costs in its response to the CRU’s draft determination.

6.4.11 Rates: PR5 baseline

Expenditure on rates is expected to be largely unchanged over PR4. We have followed our default approach to setting the baseline on the average forecast cost level for 2019 and 2020.



Table 6-14 presents a year-on-year comparison between our recommended baseline for rates opex and the TSO’s request (excluding costs attributable to PR5 step changes). The TSO has forecast €3.0 million in expenditure on rates compared to our forecast baseline of €2.5 million. This represents a difference of €0.6 million (18%).

Table 6-14 – Rates: PR5 baseline

Rates opex (€m 2019 prices) 2021 2022 2023 2024 2025 PR5

CEPA forecast 0.5 0.5 0.5 0.5 0.5 2.5

TSO Submission 0.6 0.6 0.6 0.6 0.6 3.0


We note that in comments on an earlier version of this report, the TSO said that subsequent to its submission in November 2019, the Valuations Office undertook a Global Asset Valuation which resulted in a 96% increase in this element of rates for the period 2020 to 2024. As this is new information submitted after the business plan, it is not reflected within this report. We welcome any further information that the TSO can provide on this in its response to the CRU’s draft determination.

6.4.12 Intercompany recharges: PR5 baseline

The intercompany recharges consist of facilities, payroll and corporate recharges between the TSO and the other companies in the EirGrid group. The TSO is not forecasting significant changes in intercompany charges between PR4 and PR5. We, therefore, use the TSO’s proposal for PR5 intercompany recharges in our baseline, which is reflected in Table 6-15.

Table 6-15 – Intercompany recharges: PR5 baseline

Intercompany recharges (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

CEPA forecast -3.1 -3.1 -3.1 -3.1 -3.1 -15.5

TSO Submission -3.1 -3.1 -3.1 -3.1 -3.1 -15.5


6.5 PR5 Opex Step-Change Assessment

This section outlines our PR5 opex step-change assessment for the TSO. As discussed in Section 6.3.3, our assessment of step changes will account for new costs, requirements and initiatives that are not captured in the baseline. The majority of the steps that we review in this section account for 20 new initiatives that the TSO has proposed in its PR5 submission for which a requested step-change in opex allowance was identified. These initiatives are grouped within five themes:

• Sustainability and Decarbonisation.

• Operate, Develop, and Enhance the Grid & Market.

• Engage for Better Outcomes for All.

• Non-Network Capex Business as Usual (BAU).42

42 The TSO has proposed that costs in this category associated with cloud adoption and the IT operating model should be considered as part of the PR5 baseline. However, as these costs are additional to what we have assessed in our opex baseline, we consider these costs within our step-change assessment.



• Transmission System Development and Maintenance.

The TSO followed a number of steps to assess the inclusion of opex within each initiative:

• The TSO ran a series of internal challenge sessions where initiatives were presented to a panel of senior staff from the TSO and its advisors. The panel challenged each initiative on the case of need, choice of solution and cost estimate.

• To test there was no double counting of costs between new initiatives and business-as-usual activities, each initiative was recorded on a cost tool and assessed by the TSOs’ advisors.

• The TSO dropped a number of initiatives as it was determined that these should be absorbed through the baseline allowance.

• The TSO says that a number of initiatives did not meet its standards for inclusion in the ex-ante revenue allowance and were earmarked as potential PR5 re-openers.43

• The TSO has also proposed that a number of projects included in the ex-ante revenue submission would be subject to potential PR5 re-openers.44

In addition to the 20 initiatives proposed by the TSO, we have also considered the case for other step-changes in premises costs over PR5. This change is assessed in Section 6.5.5.

The step-changes requested by the TSO’s changes totals €43.5 million over PR5.45 This represents a 18% increase over total controllable opex outturn in PR4.

We have reviewed each of the initiatives within the four themes on a case-by-case basis using the step-change assessment gateways detailed in Section 6.3.3. In a number of places we have made efficiency and/or additionality challenges. One reason we think these are justified is because individual initiatives likely overlap. So, while we think the need is there in certain cases, we also think the scale of incremental expenditure means there will be opportunities for rationalisation and savings when the business looks at the incremental expenditure programme in the round.

In forming this view, we note that the TSO has said that it followed a process with its independent advisors to minimise the risk of double counting between initiatives and business as usual costs. The TSO has told us that this process resulted in eight projects totalling €4.6 million in opex costs being included in baseline opex forecast rather than being submitted as step-changes in costs.46 While the TSO has detailed the process it followed in order to decide on step changes, it was not always clear from its submission what evidence was used during the process to conclude that the proposed costs are additional and efficient. As such, we consider that the evidence provided by the TSO does not suggest that all opportunities for

43 The TSO earmarked four projects as potential PR5 reopeners for which an ex-ante opex allowance is not requested. The projects are: Clean Energy Package, Data Science, Electricity Balancing Guidelines, and Multi-NEMO Arrangements in the SEM. As there is limited detail on the potential opex impact of these initiatives over PR5, they are not discussed in further detail here. The treatment of uncertain costs is covered in our report on the regulatory framework for PR5. See: CEPA and GHD, Regulatory framework for PR5 – report for the CRU 44 The TSO has proposed that the DS3+ and Control Centre Tools initiatives will also be subject to a PR5 reopener. The treatment of uncertain costs is covered in our report on the regulatory framework for PR5. See: CEPA and GHD, Regulatory framework for PR5 – report for the CRU 45 This value refers to costs that are allocated to EirGrid TSO only. A number of the initiatives proposed by the TSO have cost implications for SONI and SEMO. For example, 16 FTEs have been forecast for SONI as part of the initiatives that we have reviewed. We have not reviewed any of the costs that are allocated to SONI and SEMO in this report, and all costs referenced in this report relate to costs allocated to EirGrid TSO only. 46 The TSO has not provided further detail on these initiatives within their PR5 submission and, as such, we have not reviewed these initiatives for this report.



efficiency savings between initiatives and BAU costs are already accounted for in the estimates that have been submitted.

Table 6-16 outlines the level of opex that we have recommended for each theme and compares this to what has been requested by the TSO. The difference between our recommendation and the TSO’s request (amounting to €9.8 million (22%)) is due to insufficient information provided so far, which if provided would enable us to assess the efficiency and additionality of the TSO’s requests.

Table 6-16 – Summary of PR5 Controllable Opex Step-Changes

Step-Change Theme CEPA Forecast

TSO Requested

Difference

€ million %

Sustainability and Decarbonisation 13.2 15.4 -2.2 -14%

Operate, Develop and Enhance the Grid and Market 10.8 14.3 -3.5 -25%

Engage for Better Outcomes for All 3.6 7.0 -3.4 -48%

Non-Network Capex Business as Usual (BAU) 5.2 5.8 -0.6 -10%

Transmission System Development and Maintenance

1.3 1.5 -0.1 -10%

Premises -0.4 -0.4 20.0 -0%

Total 33.8 43.6 -9.8 -22% Source: CEPA analysis

Table 6-17 maps the PR5 initiatives to the opex cost categories discussed in this report (e.g. staff and staff related costs). These step changes are additive to our assessment of PR5 baseline opex in Section 6.4.

Table 6-17 – PR5 Controllable Opex Step-Changes Mapped Against Cost Areas

Cost Area CEPA Forecast

TSO Requested

Difference

€ million %

Staff and related costs 15.2 21.0 -5.9 -28%

Premises 1.3 21.9 -0.6 -30%

IT Costs 11.1 12.9 -1.8 -14%

Professional Services 2.1 2.7 -0.6 1-22%

Selling and Advertising 3.2 4.1 -0.8 -20%

Promotion of Research 0.8 0.9 -0.1 -14%


The subsections below outline our assessment for the opex step-change initiatives proposed by the TSO.

6.5.1 Sustainability and Decarbonisation

The Sustainability and Decarbonisation (S&D) business case sets out the TSO’s proposed initiatives for enabling a low carbon future that can accommodate an increase in renewable energy generation. The TSO says that, in order to achieve the Irish Government Climate Action Plan target of having 70% of electricity being generated from renewable sources by 2030, a step-increase in opex is required in PR5.



The TSO proposed five initiatives as part of the S&D business plan that include a request for an additional opex:

• Renewables Strategy and Implementation Programme (DS3+) – €12.3 million requested

• System Planning – €1.8 million requested

• Control Centre Tools – €0.7 million requested

• Promoting Change – €0.4 million requested

• Outage Management – €0.2 million requested

The TSO mapped this group of initiatives as a whole to the cost categories discussed in Section 6.4. The subsections below assess the opex related to the five initiatives against our step-change assessment framework.

Table 6-18 compares the TSOs requested step-increase in opex costs for S&D for PR5 against our recommended allowance. The TSO has requested €15.4 million for the S&D business plan compared to our recommended allowance of €13.2 million. This represents a difference of €2.2 million (14%).

Table 6-18 – S&D: Recommended Allowance

Initiative CEPA Forecast

TSO Requested

Difference

€ million %

DS3+ 11.1 12.3 -1.2 -10%

System Planning 1.5 1.8 -0.3 -15%

Control Centre Tools 0.6 0.7 -0.1 -15%

Promoting Change 0.0 0.4 -0.4 -100%

Smarter Outage Management 0.0 0.2 -0.2 -100%


The TSO forecast 18.347 FTEs for the initiatives under the S&D business plan. This represents a 6% increase on our PR5 FTE baseline. We note that the TSO has proposed to establish a Monitoring Committee for PR5 that would approve costs that are currently deemed uncertain, which includes the S&D initiatives. Our assessment here only covers the costs as reported in the TSO’s business plan, and we make no recommendations as to how these costs should be treated under a Monitoring Committee (or similar) arrangement. Separately, our work on the regulatory framework for PR5 explores how the regulatory framework could best address the uncertainty associated with these costs.48

Renewables Strategy and Implementation Programme (DS3+) (€12.3 million requested) The DS3+ initiative aims to build upon the outcomes delivered through the Secure, Sustainable Electricity System (DS3) programme which was developed to deliver on Ireland’s 2020 electricity targets of 40% of energy coming from renewable generation in 2020. It is important to note that the activities outlined by the TSO appear to be similar to those carried out under their DS3 programme. In particular, the TSO has specified that the DS3+ programme will:

• Identify operational challenges associated with high levels of RES generation;

47 The TSO has requested an additional 0.6 FTEs to be recovered through the capex allowance 48 CEPA and GHD, Regulatory framework for PR5 – report for the CRU



• Develop a set of feasible solutions to solve these challenges, including through the development of new processes, polices and tools;

• Undertake a review of System Services;

• Bring together the CRU, TAO, and DSO to develop a fit-for-purpose connection process; and

• Ensure the market remains competitive and investment is encouraged.

Given the technical challenge of implementing the Climate Action Plan’s ambition for 70% of electricity to be generated by renewable sources by 2030, we consider that the TSO has established that there is a need for continued investment in this area during PR5. The TSO forecasts 13.5 FTEs as part of this initiative over PR5.

However, the TSO’s submission is not sufficient to establish the additionality or cost efficiency of the TSO’s request for additional resources. The TSO acknowledges the difficulty of forecasting what actions will be required as part of this programme during PR5. For example, the TSO says that there is limited scope to follow the developments undertaken in other electricity jurisdictions as part of the DS3+ programme. As a result, the TSO acknowledges that there is uncertainty surrounding what the opex requested for the DS3+ programme will ultimately be spent on. Similarly, the TSO notes that it is difficult to obtain evidence to back up its resource requirements for network planning. We note that the TSO has also requested that this initiative be considered as a PR5 reopener.49

In this context, we are unable to confirm that the TSO’s ex-ante request for additional opex is cost efficient. We are also unable to determine the extent to which future actions that might be required as part of this programme may be able to be covered by existing resources. For example, we consider that there are likely to be efficiencies savings between resources that are presently engaged as part of the DS3 programme. As a result, we have included the S&D programme as a step change within our PR5 recommended allowance after applying a 10% challenge for additionality and efficiency.

System planning (€1.8 million requested) The TSO has proposed this initiative to review the needs of the transmission system in light of expected changes in PR5. In particular, the TSO has said that expected growth in new technologies and RES creates added complexity for the appraisal process. For example, more dynamic system analysis requires more detailed parameters, models, tools, and a higher operator skill level relative to a steady state analysis. The TSO has said that over PR5 it will need to understand the challenge of:

• Traditional technical phenomena such as power flow and voltage.

• A range of a complex issues, such as harmonic analysis, transient over voltages, dynamic stability, and sub-synchronous interactions.

• Additional issues around cabling and HVDC technologies.

The TSO forecasts 3.75 FTEs to support these challenges across system, access and scenario planning. Given the challenge associated with implementing the Climate Action Plan’s ambition for 70% of electricity to be generated by renewable sources by 2030, we consider that the TSO has established that there is a need for continued investment in this area during PR5.

49 The treatment of uncertain costs is covered in our report on the regulatory framework for PR5. See: CEPA and GHD, Regulatory framework for PR5 – report for the CRU



The TSO states that in the past much of the work associated with the planning of the system has been outsourced to consultants at a premium rate. As such, bringing this role in-house could result in a decrease in professional fees and a decrease in overall opex. The TSO has not evidenced where these saving are captured elsewhere within its business plan.

Based on the above, we have not accepted the TSO’s request in full. In particular, the TSO has not identified the level of cost savings that will be made from no longer outsourcing work to external consultants, so we have accounted for this in our downward adjustment for additionality. As a result, we have included the proposed step change in system planning within our PR5 recommended allowance after applying a 15% challenge for additionality and efficiency.

Control Centre Tools (€0.7 million requested) The TSO proposed this initiative to develop a suite of control centre tools to oversee, control and manage the system at the National Control Centre (NCC). The TSO said that in order to continue to integrate further RES generation and to facilitate a continuing increase in demand-side participation over PR5, new tools and functionality will be required. The TSO has said that there will need to be an initial ask to design and identify the specific areas for investment but anticipates that significant enhancements are required for:

• Common Dispatch Mechanism and Communications Design and Implementation covering RES, demand side unit (DSU), small scale generation and storage control management;

• Control centre data store;

• System services scheduling for RES, DSU and storage;

• Enhanced demand forecasting;

• Enhanced RES forecasting; and

• Additional forecasting data sources.

Given the technical challenge of implementing the Climate Action Plan’s ambition for 70% of electricity to be generated by renewable sources by 2030, we consider that the TSO has established that there is a need for continued investment in this area during PR5.

However, we consider that the TSO has not fully demonstrated the cost efficiency of their request. For example, the TSO said that its cost estimates for this initiative are based on experience in developing and delivering solutions within its control centre, such as the wind penetration secure level assessment tool but that the proposed initiatives are still to be scoped out and designed. As such, we consider that there is a degree of uncertainty surrounding the opex costs requested as part of this initiative.

In addition, we note that the drivers behind this initiative (e.g. increasing demand side participation and further RES integration) are the same issues as what the TSO has faced during PR4 (albeit the pace and scale of change may be greater in PR5). That is, we consider that some of the processes and tools required to manage changes in the electricity network are likely to already be in place from PR4. For example, the TSO says it already invested in new tools to enable Grid Controllers to operate the power system with increasing levels of RES and new technologies in PR4. In this context, we do not consider that the TSO has demonstrated the additionality of the opex costs requested for this initiative.

BWe included this step change after applying a 15% challenge for additionality and efficiency within our PR5 recommended allowance, for the reasons set out above.



Promoting Change (€0.4 million requested) The TSO proposes this initiative to establish a specific Policy and Sustainability staff role that would develop and execute organisation-wide strategic sustainability initiatives. This role would have responsibilities for developing strategy, policy, communications and implementation plans as well as collaborating internally and externally with stakeholders. The TSO has forecast one FTE, to be shared between SONI and EirGrid TSO, to deliver the required activities.

While we consider that a clear focus on sustainability is important, we have found the TSO’s claim that this is a truly new and additional cost not to have been evidenced. For example, the TSO says that, without this initiative they would have little focus on sustainability. We consider that the TSO has not clearly evidenced that the lack of additional resources is the reason it had not, to date, established a culture in which sustainability plays a central role.

As a result, we do not include this initiative within our PR5 recommended allowance.

Smarter Outage Management (€0.2 million requested) The TSO proposes the development of a new approach to outage management to reduce the total costs associated with planned and unplanned outages.

Based on the TSO’s submission, it appears that there is a degree of uncertainty surrounding the cost of this initiative. For example, the TSO said that the first step of its preferred delivery approach is to identify the target processes including interface requirements. It also said that the opex costs are for ‘solution implementation and validation’ without providing any other explanation.

Overall, we consider that this initiative appears to be a development of existing functions undertaken by the TSO. We consider that the TSO has not evidenced that these costs are required, additional and efficient. As a result, we do not include the initiative within our PR5 recommended allowance.

6.5.2 Operate, Develop, and Enhance the Grid & Market

The TSO sets out this business case as a broad package of initiatives, which it says would enable the TSO to operate, develop, and enhance the grid and market over PR5. The TSO says that this group of initiatives have been established in response to specific changes in the external environment, including the TSO’s role in the wholesale market and the requirements to meet emerging changes in the legal framework under which the TSO operates.

The TSO proposed nine initiatives under this group for which a request for an additional opex allowance has been made:50,51

• Cyber security – €3.8 million requested

• Physical security – €2.3 million requested

• Capacity Market Secondary Trading – €2.0 million requested

• State Aid Cross Border Capacity – €1.4 million requested

• Operational Support for IT Projects – €1.5 million requested

50 In addition, we note that the TSO has included two other initiatives within this business plan which it requested be subject to a re-opener. The TSO estimated that the opex costs associated with these two initiatives (Electricity Balancing Guideline and the Multi-NEMO Arrangements in the SEM) may come to over €3.0 million during PR5. 51 We note that the sum of costs requested by the TSO for each initiative does not equal to the TSO’s total request for opex costs associated with this business plan.



• Enduring access planning & connection management – €0.9 million requested

• Governance, Risk Management, and Compliance – €0.7 million requested

• Mixed Integer Programming Solver – €0.6 million requested

• European Network Codes – €0.5 million requested

• Metering System – €0.3 million requested

he TSO mapped this group of initiatives as a whole to the cost categories discussed in Section . The subsections below assess the opex related to the nine initiatives against our step-change assessment framework.

Table 6-19 compares the TSO’s request against our recommended allowance. The TSO has requested €14.3 million in opex compared to our recommended allowance of €10.8 million. This represents a difference of €3.5 million (25%).

Table 6-19 – Operate, Develop, and Enhance the Grid & Market: Recommended Allowance


TSO Requested

Difference

€ million %

Cyber security 3.9 3.8 0.0 0%

Physical security technology 2.3 2.3 0.0 0%

Capacity market secondary trading 1.8 2.0 -0.2 -10%

State aid cross border capacity 0.0 1.4 -1.4 -100%

Operation support for IT projects 0.0 1.5 -1.5 -100%

Enduring access planning 0.8 0.9 -0.1 -10%

Governance, risk management and compliance 0.6 0.7 -0.1 -10%

Implementing a MIP solver 0.5 0.6 -0.1 -15%

European network codes 0.5 0.5 -0.1 -10%

Metering system 0.3 0.3 -0.0 -100%


Cyber Security (€3.8 million requested) The TSO proposed this initiative to enhance its cyber security capabilities. The proposal is informed by an independent assessment of the TSO’s current cyber security capabilities.53 In addition, the TSO notes guidance from the National Cyber Security Centre Ireland (NCSC-IE) of the increase in the nature and scale of cyber- attacks against operators of essential services (OES) such as the TSO.

We are satisfied that the TSO has demonstrated the need of the enhancement to its cyber security capabilities. For example, we note that the TSO has been benchmarked against European power and utility companies, and identified opportunities to adopt best practice.

We also accept the TSO’s submission that it ensured there is no double counting between the cyber security business-as-usual request and this cyber security enhancement request. Hence,

52 The TSO has submitted costs on an initiative-by-initiative basis as well as on a cost category basis. There is a small discrepancy between these costs which means that the TSO’s total request (which is equal to the TSO’s total request by cost category) does not equal to the sum of the costs requested for each initiative. We have conducted all of our analysis on a cost category basis. 53 We have not reviewed this report and so are unable to independently verify this conclusion.



we consider that the TSO has justified the additionality of the investment. The TSO has also said that it is in an advanced stage of the procurement process, which has allowed them to attain more accurate operating cost estimates. Based on the evidence provided, we recommend that the initiative is included in the cost allowance.

Physical Security Technology: Replacement and Enhancement (€2.3 million requested) The TSO proposed this initiative to enhance the physical security of its infrastructure. The TSO says that the proposals are informed by three key factors:

• the Security of Network & Information Systems Regulations (NIS Regulations) directive, which was enacted in May 2018;

• an external review found gaps in the TSO’s suit of physical security structures, technology and equipment in 2018; and

• Consideration of the level of security investments by UK TSOs. The TSO notes National Grid’s plan to substantially invest in its physical security infrastructure in 2018.

The TSO proposed five ongoing initiatives as part of this plan: external auditing, staff training, maintenance of existing equipment, maintenance of new equipment, the ongoing provision of security guards.

We are satisfied that the TSO has demonstrated the need of the enhancement to the physical security of its infrastructure. We also recognise that the TSO has estimated its cost request based on like-for-like purchasing of security technology and equipment within the United Kingdom and Irish marketplaces and verified costs by leading physical security consultants.

Based on the evidence provided, we recommend that the initiative is included in the cost allowance.

Capacity Market Secondary Trading (€2.0 million requested) As part of the introduction of the I-SEM, EirGrid as TSO was allocated the role of operating the Capacity Market. Under the current I-SEM arrangements, if participants are unable to provide energy that they are contracted to deliver, they can submit an ‘Active’ Interim Secondary Trading Notification (ISTN) to System Operators, indicating a negative quantity of Awarded Capacity. EirGrid can then add a register entry to the Capacity and Trade Register with the quantity specified in the ISTN at the Capacity Auction Price of the primary auction for the relevant period. Ultimately the risk of non-delivery is moved to the market.

During the design of the Capacity Market, it was envisaged that a more comprehensive set of Secondary Trading arrangements would be developed over time to address these issues and the rules of this would be written into the Capacity Market Code. These enduring Secondary Trading arrangements would involve the running of regular secondary trading auctions for secondary products covering part of the Capacity Year (e.g. weekly or monthly). Thus, the current interim process is not aligned to the originally proposed Capacity Market model.

The purpose of this initiative is to design and implement a market for secondary trading that allows generators to trade between one another in the event they are not able to deliver the energy they have contracted for a specified time. The TSO proposes to design, implement and operate an online secondary trading market. This option was chosen rather than to continue using ISTN arrangements where the market bears the risk of non-delivery or to allow participants to contact each other (directly, or through a broker) and to enter into a secondary trade at an agreed price.



The TSO forecasts that four FTEs would be required to deal with implementing the market for secondary trading including the: design, rules modification, process and system implementation and stakeholder management and training.

We are satisfied that the TSO has demonstrated the need of the initiative to design and implement a market for secondary trading.

owever, we do not think the TSO has demonstrated that these costs are additional relative to its current activities and responsibilities given that existing resources could potentially be reallocated to deliver this programme. Based on the information provided by the TSO, we are unable to conclude the needs case for the four FTEs once the programme ends. We welcome further information from the TSO on this matter as part of its response to the CRU’s draft determination.

We also do not consider that the TSO has provided sufficient evidence on the efficiency of these costs. The TSO says that costs have been estimated based on experience from the I-SEM project and other recently completed capacity market activities. However, no further evidence has been provided that would have enabled us to make comparisons with existing staff costs. The TSO has also not demonstrated external benchmarking of its proposed costs nor that its proposed costs were verified by an independent third party.

As a result, we include this step change after applying a 10% challenge for additionality and cost efficiency.

State Aid Cross Border Capacity (€1.4 million requested) As the operator of the Capacity Market in Ireland, EirGrid is subject to the European Commission’s State Aid requirements. The TSO set out this initiative to develop the resources and capabilities to prepare and implement the ability for foreign generators to participate in Ireland’s capacity market (indirectly, through interconnectors’ bids).

The key actions required are:

• Calculate the maximum entry capacity for cross-border participation;

• Determine the process for sharing of revenues;

• Determine the process for carrying out of availability checks;

• Determine the process for determining when a non-availability payment is due;

• Determine the process for operation of the qualification registry of foreign capacity for the I-SEM capacity market; and

• Determine the process for identifying capacity eligible to participate in the Capacity Market.

The TSO forecasts three FTEs to provide ongoing support to this initiative across PR5.

Overall, we do not consider that the TSO has demonstrated the need for this initiative. The driver of costs in this area is providers from other European jurisdictions inputting into their capacity market model. At present, participation of foreign capacity is only possible indirectly from GB through the interconnectors (it is only the generator itself that can participate in capacity market auctions under current roles; foreign generators cannot bid for the I-SEM capacity market), though this situation may change pending the outcome of ongoing negotiations between the UK and EU. Further connection would be possible following the construction of the Celtic interconnector, which is not due to be operational until 2026. The TSO itself does not expect participation of foreign capacity in the Capacity Market until the end of the price control period.



As a result, we consider that the TSO has not demonstrated the needs case for an ex ante allowance for these costs to be included for PR5. For these reasons, we do not include the opex associated within this initiative within our recommended allowance.54

Operation Support for IT Projects (€1.5 million requested) Under the TSO’s cost allocation policy, staff meet the threshold for their costs to be capitalised to a project if they spend more than 50% of their time on that project. As such, the TSO says that it is likely that a number of teams will be required to provide input on an ad-hoc basis, which would not be directly captured within cost estimates of that specific initiative. The TSO has proposed this initiative as a means of recovering the costs, which it says were not directly listed as part of the delivery costs within the associated IT projects elsewhere in its business plan.

The TSO forecasts three FTEs for this initiative in PR5. The TSO says that additional resources are only needed to support project delivery over the PR5 period and are not enduring roles.

We consider that the TSO has not demonstrated the needs case for this initiative. Therefore, we do not include this initiative as a step-change within our recommended allowance. If the TSO requires additional staffing resources to deal with activities associated with other initiatives, then a request for those resources should be made directly. We do not consider that it is appropriate to recommend providing an ex ante allowance for uncertain future costs, particularly where such costs may be influenced by the TSO’s own cost allocation decisions.

Enduring Access Planning & Connection Management (€0.9 million requested) The TSO says that in order to achieve the Climate Action Plan target of 70% renewable generation by 2030, installed renewable capacity will have to almost double. In order for this capacity to be successfully installed by 2030, a growing number of connection offers would need to be completed within the PR5 period.

This initiative focuses on the need to revise the TSO’s approach to connections, including the associated modelling and network planning activities, as connecting parties respond to policy intervention schemes introduced as part of the Climate Action Plan. In particular, the TSO forecasts an additional two FTEs to deal with the increased workload, which would result in the number of FTEs staff employed in this area rising from four to six.

We are satisfied that the TSO has demonstrated the need of the initiative as we acknowledge that the increase in connection offers is likely to lead to increasing resource requirements for the TSO.

The TSO has also explored three different options for this business case, which has given us confidence that the selected option is the best option available. We are also reasonably confident that the costs requested are additional given that the TSO has determined the FTE increase that is required to fulfil the requirements of the initiative.

However, we do not consider that the TSO has demonstrated the cost efficiency of their request. For example, the TSO has not provided external cost benchmarking to determine the appropriate cost estimate nor demonstrated that its proposed costs were verified by an independent third party. We apply a 10% efficiency challenge to requested costs.

54 We have reached this consideration based on the evidence provided by the TSO in the PR5 submission. We welcome further information from the TSO on this matter as part of its response to the CRU’s draft determination.



Market Related TSO Governance, Risk Management and Compliance (€0.7 million requested) The TSO has set out that as a result of new responsibilities and increasingly complex codes legislation, its operational compliance team will be responsible for new activities, including:

• Compliance of additional capacity auctions;

• Operational compliance;

• Pan-European TSO compliance initiatives;

• Code specific operational audits;

• The establishment, population and operation of a TSO audit and compliance library and reporting; and

• Managing and supporting the TSO operational compliance areas within the wider Group COSO framework program.

The TSO says that hiring an additional two FTEs who would share tasks across SONI and the EirGrid TSO, with 75% of the costs allocated to EirGrid TSO, would be needed to enhance its governance, risk management and compliance capability.

We are satisfied that the TSO has demonstrated the need for the initiative. However, we consider that the TSO has not demonstrated the additionality of its request. For example, the TSO expects synergies for delivering this initiative alongside similar market operator requirements, using existing operational processes and tools. But it has not detailed the level of cost savings that are expected through these operational synergies.

In addition, we do not consider that the TSO has demonstrated the cost efficiency of its request. For example, the TSO has not provided external benchmarking to determine the efficient level of staff required for this initiative nor demonstrated that its proposed costs were verified by an independent third party. As a result, we apply a 10% cost challenge for additionality and efficiency to requested costs.

Implementing a Mixed Integer Programming Solver (€0.6 million requested) The aim of this initiative is to design and implement the next form of auction algorithm approaches to be used in the Capacity Market: ‘Auction Format D’, or a Mixed Integer Programming (MIP) optimisation approach. The opex related to the initiative comprise ongoing licence support once MIP optimisation approach has been implemented.

During the detailed design of the Capacity Market, the CRU and the Northern Ireland Utility Regulator considered a number of auction algorithm approaches to be applied to the Capacity Auctions. At present, the TSO administers the Capacity Market using Auction Format C. The TSO says that while this option is viable (subject to it being State Aid compliant), it is not consistent with the long-term design of the Capacity Market.

Overall, we are satisfied that the TSO has demonstrated the need of the initiative and the benefits of moving to a MIP approach. For example, the TSO has demonstrated that the switch to the MIP approach would enable it to comply with changes to the regulatory and legal environment. However, there is significant uncertainty around the need for the ongoing licence support as it depends on successful delivery of the MIP optimisation approach. We are also unable to confirm the additionality of the associated opex. For example, it is unclear whether the opex request is additional to the opex associated with Auction Format B and Auction C. For these reasons, we apply a 15% cost challenge for additionality and efficiency to requested costs.



European Network Codes (€0.5 million requested) The European Union is adopting a common set of rules known as the European Network Codes which enable electricity network operators, generators, suppliers and consumers to operate more effectively within the European electricity market. The TSO was actively involved in the development of the European Network Codes.

The TSO says existing resources would not be able to meet the increase in workload. The TSO’s preferred option is to hire an additional FTE who would be responsible for reviewing, updating, developing and ensuring compliance within the European Network Codes. The TSO considers this to be an enduring role to carry on beyond PR5.

We acknowledge the importance for the TSO to comply with European Network Codes and appreciate that the TSO has assessed a number of options before deciding on the preferred option. However, the information submitted by the TSO is not sufficient for us to conclude that the additional resources requested are, in fact, additional, since the TSO could potentially use resources from other areas of the business. The TSO acknowledges that options of both internal and external recruitment will be considered. We also do not consider that the TSO has demonstrated the cost efficiency of their request. For example, the TSO has not provided external benchmarking to determine the staffing requirement for this initiative. For these reasons, we apply a 10% additionality and efficiency cost challenge to the requested costs.

Metering System (€0.3 million requested) The Metering Code for the Single Electricity Market requires High Accurate Revenue Class Energy Meters to be installed for connection points to the Transmission System. The purpose of the metering system is to remotely collect, validate, substitute and aggregate Revenue Meter Data for provision of the SEM (imbalance market), Transmission Use of System (TUoS), and System Services for billing and revenue purposes. The TSO proposes to decommission the existing metering system and invest in a new All-Island metering system for both SONI and the EirGrid TSO.

The opex related to the initiative comprise ongoing licence support once the new All-Island metering system is implemented.

verall, we are satisfied that the TSO has demonstrated the need of the initiative and the potential benefits of moving to the new metering system. The TSO has said that the new application will be operated in parallel with the pre-existing system until it is decommissioned in 2024. Based on the TSO’s PR5 submission, we query the additionality and efficiency of this request. For example, the TSO has not outlined why the two operations will need to operate in parallel until 2024 or whether the decommissioning of the existing metering system in 2024 will result in opex cost savings.55 For these reasons, we apply a 10% additionality and efficiency cost challenge to the requested costs.

6.5.3 Engage for Better Outcomes for All

The TSO sets out this business case as a means to ensure that the public is fully engaged in the decarbonisation drive and are cognisant of the TSO’s role in that process. In particular, the TSO proposes a number of initiatives to reach out and engage with stakeholders in order to gain increased acceptance for new grid development projects over PR5 and beyond. The initiatives for which the TSO requests an additional opex allowance are as follows:

55 We welcome further information from the TSO on this matter as part of its response to the CRU’s draft determination



• Education & Engagement Campaign - €4.6 million requested

• Enhanced Customer Journey - €2.5 million requested

The TSO mapped each of the initiatives listed above to the cost categories from Section 2.3 so we have assessed each initiative separately.

Table 6-20 compares the TSO’s requested step-increase in opex costs for this business case against our recommended allowance. The TSO has requested €7.0 million in opex compared to our recommended allowance of €3.6 million. This represents a difference of €3.4 million (48%).

Table 6-20 – Engage for Better Outcomes for All: Recommended Allowance


TSO Requested

Difference

€ million %

Education & Engagement Campaign 3.6 4.6 -0.9 -20%

Customer Journey 0.0 2.5 -2.5 -100%


Education & Engagement Campaign (€4.6 million requested) This initiative aims to introduce proactive engagement with stakeholders to ensure that the EirGrid brand is known and trusted across Ireland. The TSO says that it would use a variety of channels to engage with the public and to inform it on the role that it is playing in supporting the decarbonisation of the electricity system. The TSO gives examples including a media advertising campaign, website improvements and a 3D modelling initiative to enable the public to visualise projects and to provide feedback.

The TSO’s request for additional opex by cost area is set out in Table 6-21.

Table 6-21 – Education & Engagement: Requested opex by cost area

Education & Engagement (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

Staff Costs 0.1 0.1 0.1 0.1 0.1 0.5

Selling and Advertising 0.8 0.8 0.8 0.8 0.8 4.1

Total 0.9 0.9 0.9 0.9 0.9 4.6 Source: EirGrid

Overall, while we consider that more stakeholder education and engagement is positive, we consider that more investment in this area should only be considered justified if:

• it enables faster and/or less costly grid development processes, resulting in cost savings and/or earlier benefits for consumers; and

• it encourages consumer participation in the energy sector (e.g. by getting a smart meter and/or buying a distributed energy resource) that reduces that total cost of the system and supports the achievement of the Climate Action Plan.

As such, we consider that the need for this initiative is justified if the TSO can demonstrate that it delivered improvements grid development and consumer participation in the energy sector.

Based on the need to deliver on the Climate Action Plan and on transformational change expected in the energy sector over PR5, we recommend including an allowance, in part, for this initiative. We recommend that the TSO report, backed by quantitative evidence where possible,



on how this initiative has helped to deliver on grid development and system cost savings over PR5 (we discuss this issue further in our regulatory framework report).56

However, we consider that the TSO has not sufficiently demonstrated the efficiency or additionality of its request. In particular, we note that the TSO has incurred a large step-change relative to selling and advertising spend in PR3 (€8.1 million, or 1618% of the original ex-ante allowance for selling and advertising during PR4). As outlined in Section 1, we have recommended that this expenditure is allowed in full within the TSO’s PR4 ex-post allowance. A considerable increase in sales and advertising spend in 2019 and 2020, compared to earlier years in PR4, is also reflected in our baseline. Given the large step-increase in spend in PR4, we would query the additionality of the costs associated with this new initiative in PR5.

For these reasons, we apply a 20% additionality and efficiency challenge to the requested costs.

Enhanced Customer Journey (€2.5 million requested) The TSO says it wants to ensure that prospective connecting parties, and other stakeholders, can easily find relevant information related to the planning, development and operation of the transmission system. In line with this goal, the TSO has proposed five areas where it can improve the customer journey as follows:

• Pre-Application Process: the TSO proposes to introduce a structured pre-application process for new and existing customers. This will involve the development, implementation and publication of a defined pre-application process for customers. The TSO says this will generate efficiencies for the customer, as well as for the TAO and TSO.

• Early Customer Feasibility Studies: the TSO proposes to introduce assessments of the practicality of a customer’s proposed plan or method of connection prior to submitting a formal application.

• Sprint Approach to Offer Process for Strategic Connections: the TSO proposes to trial the use of a ‘sprint approach’ to prepare connection offers in a more efficient way.57 The TSO says that this will initially be only for strategic or high priority projects.

• Improved System Information for Future Connections: the TSO proposes to develop and make available online heat maps with up-to-date information on system capacity and location for consumers.

• Customer Relationship Management (CRM) Tool: the TSO proposes to roll out a CRM tool across the EirGrid Group which it says will enhance the customer experience.

The TSO’s request for additional opex by cost category is set out in Table 6-22.

Table 6-22 – Enhanced Customer Journey: Requested opex by cost area

Enhanced Customer Journey (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

Staff Costs 0.5 0.5 0.5 0.5 0.5 2.5 Source: EirGrid

Overall, we find a number of issues with the TSO’s request for opex associated with this initiative. The TSO’s proposal for early customer feasibility studies would imply that the TSO will incur costs for connection requests that are not ultimately made. This would mean that

56 CEPA and GHD, Regulatory framework for PR5 – report for the CRU 57 The TSO said that the sprint approach is for when all internal groups required to process connection offers will come together into one room, and that this would compress timelines in half.



electricity consumers as a whole would underwrite what is effectively a private benefit (the information to the connecting customer regarding connection costs).

With regard to the proposed heat map, we note that the DSO has proposed a similar scheme. The TSO’s submission is unclear as to whether its proposal is a joint one with the DSO or a separate one. Clearly, the greatest benefit to consumers would be from a single service covering both the transmission and distribution networks.

In addition to the above, we consider that the TSO has not demonstrated the additionality of its request. For example, the TSO has not demonstrated that its proposed costs for a new CRM tool are net of the costs of any current system. It is also unclear how the costs of this group-wide system were allocated to the TSO. Similarly, the TSO has not explained what would be the costs of its proposed ‘sprint approach’ – on the face of it, this initiative should result in net savings.

We also consider that the TSO has not demonstrated the cost efficiency of its request. For example, the TSO has not provided independent evidence to justify the staffing requirements or other non-pay costs for this initiative. For these reasons, we do not include this initiative as a step-change within our recommended allowance as we do not consider the TSO has sufficiently demonstrated the need, additionality or cost efficiency of the initiative.

6.5.4 Non-Network Capex BAU

We have identified two initiatives for which the TSO has requested opex within the non-network capex BAU section of its PR5 business plan:

• Transition to cloud – € 3.1 million requested; and

• IT operating model – €2.7 million requested.

Table 6-23 compares the TSO’s requested step-increase in opex costs for the non-network capex BAU initiatives against our recommended allowance. The TSO has requested €5.8 million for these initiatives compared to our recommended allowance of €5.2 million - a difference of €0.6 million (10%).

Table 6-23 – Non-Network Capex BAU: Recommended Allowance


TSO Requested

Difference

€ million %

Cloud Adoption 2.8 3.1 -0.3 -10%

IT Operating Model 2.4 2.7 -0.3 -10%


We note that additional capex costs are not recommended for these initiatives on the basis that both initiatives are expected to generate cost savings and should, therefore, be funded through capex BAU (see section 6.51). However, as we recognise that a certain level of opex will be required to operate both initiatives, we have included a positive opex step-change in our recommended forecast allowance.

Transition to Cloud (€3.1 million requested) The TSO has set out a plan to transition certain packages to cloud-based services over PR5. It says that this will provide flexibility that is required to adapt to the greater digitisation of the industry. The TSO says that this plan will include:

• The relocation of servers that will not be moved to co-located data centres to cloud service providers to co-located data centres to cloud service providers;



• Transition to cloud-based applications rather than installing on-premises versions; and

• Deployment of new cloud-based services such as advanced analytics.

The TSO says that the move will introduce a switch from capex to opex funding as large upfront capital investments are replaced with predictable ongoing opex subscription costs.

The TSO also says that the transition to the cloud will save €17 million in costs over the remaining life span (5 years) of its physical server assets. This calculation is based on a comparison of the indicative costs of running a physical or cloud-based server over a 5-year period. The TSO also considers the transition to cloud-hosting of infrastructure and corporate systems include security improvements and improved team productivity.

Overall, we are satisfied that the TSO has demonstrated the need for the initiative and the potential benefits of moving applications to the cloud. According to the TSO, this initiative should lead to a reduction in overall costs and we would expect this initiative to enable transformational change at the TSO.

However, we do not consider that the TSO has justified the additionality and efficiency of these costs. For example, the TSO has not demonstrated that it accounted for the expected €17 million savings elsewhere in its estimates costs for PR5. Typically, IT projects can generate cost savings and end up being self-funding, so may not require additional funding when considered over a 5-year or longer payback period.

Based on the information provided, we recommend that the TSO report the savings this project has resulted in by the end of PR5. We apply a 10% additionality and efficiency cost challenge to the requested costs.

IT Operating Model (€2.7 million requested) The TSO integrated its IT organisation during PR4 to take advantage of economies of scale and to standardise best practices. This initiative proposes a further evolution of the TSO’s IT operating model for centralised IT services. The TSO says that this will embed efficiencies across the group, optimise the commercial management of major IT contracts and support EirGrid’s teams to operate as a single IT infrastructure system.

The TSO’s programme of work as part of this initiative will include:

• An initial assessment of the existing model;

• Strategy and design of new model including change management planning;

• Planning of transition project;

• Risk assessment and final approvals; and

• Implementation.

The TSO says it identified efficiencies in its physical data centre footprint, as well as the adoption of an agile service delivery and vendor management, as areas for improvement in PR5.

Overall, we are satisfied that the TSO has qualitatively set out the potential benefits of the proposed further evolution of the TSO’s operating model for centralised IT services. To enable continued transformational change of the TSO’s IT operating model across PR5, we consider that the need for this initiative has been justified.



However, we do not consider that the TSO justified the additionality and efficiency of the requested costs.58 Similar to the transition to the cloud, the TSO has not identified the cost savings that it expects to be generate from this project in the PR5 submission. We apply a 10% additionality and efficiency cost challenge to the requested costs.

6.5.5 Transmission System Development and Maintenance

We have identified one initiative for which the TSO has requested opex within the transmission system development and maintenance plan:

• Transmission Asset Management and Maintenance – €1.5 million.

Table 6-24 compares the TSO’s requested step-increase in opex costs for the non-network capex BAU initiatives against our recommended allowance. The TSO has requested €1.5 million for this initiative compared to our recommended allowance of €1.3 million - a difference of €0.1 million (10%).

Table 6-24 – Non-Network Capex BAU: Recommended Allowance


TSO Requested

Difference

€ million %

Cloud Adoption 1.5 1.3 -0.1 -10%


The TSO says that the additional dedicated resources are required within its Asset Management function in order to deliver on its PR5 commitments including:

• supporting opportunities to better share information, systems and data management between the TSO and TAO;

• implementing ISO 55001; and

• co-ordinating planning, maintenance and expansion of the network.

To help deliver on the commitments listed above, the TSO has requested three additional FTEs.

The TSO has set out in detail the function and role of the Asset Management team, including how it engages with the TAO. We also note that the TSO has pointed out that over the PR4 period, the transmission system has been developed to accommodate the connection of renewable and conventional generation and transmission demand. The TSO say that this has necessitated the uprating of existing assets and the construction of additional transmission stations and circuits. Based on the need to deliver continued transformational change across PR5 to help deliver on the Irish Government’s Climate Action Plan, we recommend including an allowance, in part, for this initiative.

THowever, we do not consider that the TSO justified the additionality and efficiency of the requested costs. The TSO has not provided information to explain why three additional FTEs are required to fulfil the commitments listed above. In addition, we do not consider that the TSO has demonstrated that some of the commitments listed above could not be delivered with existing resources. We apply a 10% additionality and efficiency cost challenge to the requested costs.

58 For example, the TSO’s business plan does not include details on how the proposed changes to the IT operating model were costed.



6.5.6 Premises

In addition to the initiatives outlined above, the TSO has proposed a small downward step-change in premises costs during PR5 of €0.1 million per annum between 2022 and 2025 (€0.4 million over PR5) due to portfolio changes and rent reviews.

Table 6-25 compares the TSOs requested step changes in opex costs for these two areas against our recommended allowance. As a result, we have included the negative step change within our forecasts.

Table 6-25 – Other Step-Changes: Recommended Allowance

Other Step-Changes (€m 2019 prices)

2021 2022 2023 2024 2025 PR5

Recommended Allowance 0.0 -0.1 -0.1 -0.1 -0.1 -0.4 TSO Request 0.0 -0.1 -0.1 -0.1 -0.1 -0.4


6.5.7 Summary of assessment of step-changes

Table 6-26 summarises our assessment of the step changes proposed by the TSO for PR5. We present a ‘traffic light’ for each step in our assessment, in which:

The ‘Need’ gateway is shown as either GREEN or RED, reflecting this gateway being pass or fail, respectively. Step changes that do not pass the ‘Need’ gateway are not assessed for additionality or efficiency.

Each of the ‘Additionality’ and ‘Efficiency’ gateways are rated: GREEN if we recommend the costs being included in full, YELLOW if we recommend up to a 10% challenge (individually for each gateway), or RED if we recommend a cost challenge of more than 10% (individually for each gateway).

Table 6-26 – Summary of assessment of step changes

Step change Gateway assessment TSO request CEPA recommendation

Need Additionality Efficiency (€m 2019 prices)

(€m 2019 prices)

Sustainability and Decarbonisation

DS3+ 12.3 11.1

System Planning 1.8 1.5

Control Centre Tools 0.7 0.6 Promoting Change 0.4 0.0

Smarter Outage Management 0.2 0.0

Operate, Develop, and Enhance the Grid and Market Cyber security 3.8 3.9 Physical security technology 2.3 2.3 Capacity market secondary trading

2.0 1.8

State aid cross border capacity

1.4 0.0

Operation support for IT projects

1.5 0.0



Step change Gateway assessment TSO request CEPA recommendation

Need Additionality Efficiency (€m 2019 prices)

(€m 2019 prices)

Enduring access planning 0.9 0.8

Governance, risk management and compliance

0.7 0.6

Implementing a MIP solver 0.6 0.5

European network codes 0.5 0.5

Metering system 0.3 0.3 Engage for Better Outcomes for All Education & Engagement Campaign

4.6 3.6

Customer Journey 2.5 0.0

Non-Network Capex BAU Cloud Adoption 3.1 2.8

IT Operating Model 2.6 2.4

Transmission System Development and Maintenance Asset maintenance 1.5 1.3 Other

Premises -0.4 -0.4

Total 43.659 33.8 Source: CEPA analysis

6.6 Summary of Recommendations

6.6.1 Opex allowance

Table 6-27 presents a view of the internal opex forecasts for PR5 before the application of Real Price Effects (RPEs) and ongoing efficiency. The TSO requested €318.5 million in controllable opex costs over PR5 compared with our recommended allowance of €300.9 million. This is equivalent to a difference of €17.6 million (6%).

59 The TSO has submitted costs on an initiative-by-initiative basis as well as on a cost category basis. There is a small discrepancy between these costs which means that the TSO’s total request (which is equal to the TSO’s total request by cost category) does not equal to the sum of the costs requested for each initiative. We have conducted all of our analysis on a cost category basis.



Table 6-27 – Recommended PR5 Opex Allowance (excluding RPEs and ongoing efficiency)


2021 2022 2023 2024 2025 PR5 Variance F’cast F’cast F’cast F’cast F’cast F’cast Req’t F’cast –

Req’t %

Controllable Opex Staff and related costs 33.5 33.5 33.5 33.5 33.5 167.5 175.4 -7.9 -4%

Premises 5.8 5.7 5.7 5.7 5.7 28.5 31.2 -2.7 -9%

IT Costs 6.4 7.2 8.3 9.1 9.1 40.2 43.2 -3.0 -7%

Telecom Costs 5.1 5.3 5.5 5.7 6.0 27.6 27.6 0.0 0%

Professional Services 4.2 4.2 4.2 4.2 4.2 21.1 21.7 -0.6 -3%

Selling and Advertising 2.7 2.7 2.7 2.7 2.7 13.5 15.1 -1.5 -10%

Contractors 1.7 1.7 1.7 1.7 1.7 8.4 9.5 -1.2 -12%


0.7 0.7 0.7 0.7 0.7 3.4 3.5 -0.2 -4%

Rates 0.5 0.5 0.5 0.5 0.5 2.5 3.0 -0.6 -18%

Insurance 0.3 0.3 0.3 0.3 0.3 1.5 1.5 0.0 0%


Intercompany Recharges -3.1 -3.1 -3.1 -3.1 -3.1 -15.5 -15.5 0.0 0%



Inter TSO Compensation 2.1 2.1 2.1 2.1 2.1 10.5 10.5

N/A

CORESO subscription 0.6 0.6 0.6 0.6 0.6 2.8 2.8

Interconnector services 0.8 0.8 0.8 0.8 0.8 4.1 4.1

CER Levy 1.0 1.0 1.0 1.0 1.0 4.9 4.9

DUoS costs 3.2 3.2 3.2 3.2 3.2 16.2 16.2

Ancillary Services 173.6 200.3 189.7 182.9 172.1 918.6 918.6


181.3 208.0 197.4 190.6 179.8 957.1 957.1


The TSO requested a baseline PR5 controllable opex allowance of €275.0 million, which compares to our recommended baseline opex allowance of €267.1 million. This represents a difference of €7.8 million (3%).

Opex step-changes are for output and business transformation changes that will be delivered by the TSO in PR5 and are not captured in the opex baseline. The TSO requested €43.6 million in opex step-change for PR5, which compares to our recommended allowance of €33.8 million. This represents a difference of €9.8 million (22%).

In addition to Figure 6-1 presents the make-up of our recommended allowance against PR4 outturn / forecast controllable opex and the TSO’s request of controllable opex. The figure shows that our base and trend recommendation (before RPEs and ongoing efficiency) would represent a €22.5 million step up from the TSO’s forecast expenditure in PR4. Our recommendation is €17.6 million (6%) lower than the TSO’s request for PR5 (before RPEs and ongoing efficiency). This difference is largely the result of cost challenges that have been applied to the TSO’s requested step-change initiatives.



The TSO also forecasts 1.0% per annum in RPEs net of ongoing efficiency, which amounts to a further €11.7 million during PR5 beyond the figures shown below.

Figure 6-1 - Recommended PR5 TSO controllable opex allowance breakdown and comparison (excluding RPEs and ongoing efficiency)


Figure 6-2 presents our recommended PR5 controllable opex allowance against the TSO’s proposal on a year-by-year basis (excluding RPEs and ongoing efficiency).

Figure 6-2 - Recommended PR5 controllable opex allowance and (excluding

RPEs and ongoing efficiency)


6.6.2 Qualitative recommendations

We also make the following qualitative recommendation:

Output delivery - the TSO has proposed a significant number of new initiatives for PR5 – primarily aimed at enabling the objectives of the Climate Action Plan, as well as meeting the strategic objectives set by the CRU. The regulatory framework would need to adapt to support this greater focus on the outputs delivered by the TSO. As such, the TSO should



report on the delivery of these initiatives and the benefits delivered to customers and/or the wider electricity system. Where possible, the impact of the new initiatives should be quantified. The regulatory framework should also set out clear guidance for how under-/over-delivery of outputs would be treated as part of any ex post review. We explore the options for doing so further in our report on the PR5 regulatory framework.60




7. Review of PR5 Capital Expenditure: Transmission System Operator This section reviews the forecast TSO (and TAO) capital expenditure over the PR5 period 2021 to 2025 including comparison with the historic expenditure seen in the previous PR4 period. The review has been informed by the TSO’s response to the original FBPQ on forecast capital expenditure and associated information papers and network plans, together with further data provided by both the TSO and TAO at meetings and from supplementary questions raised.

7.1 PR5 Review Objectives

As part of the PR5 assessment process GHD has reviewed the forecast PR5 capital expenditure proposed by EirGrid as TSO. Specifically, GHD has:

Reviewed the forecast network and non-network capital investment proposed by the TSO for the 2021-2025 period. This includes consideration of aspects related to forecasted demand growth and new connections, including renewable generation.

Provided advice on the efficient level of network capital investment expected to be required in the TSO (and TAO) businesses over the period 2020-2021, and also for non-network capital expenditure for the TSO over the same period.

This report provides an analysis of both network and non-network capital expenditure investments forecasted by the TSO (EirGrid) in the 2020-2025 period. The review includes an appraisal of the forecasted issues that may drive the development of projects in the PR5 period.

7.2 PR5 Philosophy

Before detailing the specific activities and analysis undertaken as part of the PR5 capital expenditure review it is worth considering some of the changes made by the TSO with regards to quality and completeness of their PR4 historic submission, in comparison with earlier PR reviews. These improvements and changes have impacted on the extent of analysis and assessment able to be performed by GHD and have enabled GHD to more fully understand the reasons behind changes in planned versus actual PR4 capital expenditure. Going forwards into PR5, reflecting on the extent of completeness of the current PR4 historic submission can provide a useful input to guide not only the underlying recommendations with respect to PR5 capital expenditure but also the approval governance and framework mechanism that overarches regulation of the businesses during the forthcoming regulatory period. Specific aspects worthy of commentary include:

1. In previous PR review period (pre-PR4) there was a consideration by the transmission businesses of the agreed allowance being something of a guide, and to be used at a high level only, with no expectation that this would be reviewed in detail at a project level at the end of PR review period in order to make determinations of outturn efficiency. With respect to the current PR4 review, the TSO has proactively provided detailed information and reasoning to support changes to forecast project capital expenditure and has provided further supporting information in response to questions raised by GHD during the review process.

2. In previous reviews there was an apparent difficulty in providing data at the end of the PR period relating to project costs and requirements at the start of the period to assist with outturn evaluations. As detailed above, in the current PR4 review some of this information



has been proactively provided by the TSO as part of their submission and in other cases in response to GHD supplementary questions.

3. In previous periods there has been a lack of transparency and limited documentation provided by the TSO detailing reasons behind projects being removed / added during the period, or adequate explanations for project delays and significant cost variations. During PR4 the TSO has been much more forthcoming providing such explanations and supporting cost data, and in many cases the supporting information has provided sufficient and suitable explanation behind necessary project cost and programme changes.

4. Through PR4 the TSO has introduced a number of new technologies or alternative project solution options following successful trials i.e. Distributed Series Reactors, SSSC Power Flow Controller, voltage uprating of overhead line, etc. The PR4 Lookback narrative document plus review of the ongoing transmission project list has identified that the TSO is now applying such new technologies / solution options on a proactive basis as an alternative to new build transmission plant. Critically, such options appear to be now selected from the outset of identifying a particular transmission investment driver rather than being identified or considered only after transmission reinforcement solution options are discounted.

5. As with previous reviews, no specific detailed outputs or metrics (e.g. number of projects, volume of equipment, generation capacity / connections to be connected, etc.) were set at the start of the PR4 period to enable expected end PR4 transmission projects and capital expenditure to be measured against. Going forwards into PR5, and giving consideration to the national renewable energy targets to be achieved by 2025 and 2030, there is clearly benefit in establishing a set of technical, performance and quality output metrics now that can be tracked and monitored during PR5. Not only will this provided a baseline by which to assess future PR5 outturn capital expenditure, and variations therein, but this will also provide a historic trend in output data that can be used if at a later stage specific financial incentives are introduced.

Collectively the above, plus other observations developed during the course of the PR4 review, are sufficient to suggest that in order to balance network development risks, associated costs and financial impacts more evenly between both the transmission businesses and end consumers, some further revision to the overarching PR5 regulatory review process is required. Such revisions are recommended in order to review TSO (and TAO) delivery progress against key output and deliverability metrics within PR5. In this regard it is recommended that a set of key output and performance metrics should be agreed between the CRU and transmission businesses at the start of PR5 to enable monitoring and progression, including capital expenditure tracking, throughout PR5. There may also be benefit in allowing the TSO to bring forward additional capital expenditure funding requests for new transmission investments that are not currently known about following the PR5 determination, in a similar manner to the process introduced in PR4 for large capital projects. This could be useful where such additional projects may have a significant impact on assisting to deliver renewable energy generation targets, rather than waiting until the PR6 submission before making a further capital funding request.

It is expected that any further funding requests within the period would be supported by detailed capital expenditure proposals, including supporting business cases documenting fully the needs case for specific investments, including costs and risks, potential available investment options, detailed financial analysis including lifetime costing and operation expenditure impacts as appropriate.



Whilst the above approach may appear to present an additional burden on the transmission businesses, it would allow them collectively to develop the transmission system in Ireland in a manner that enables them to respond to new challenges and variations in underlying project development drivers on an ongoing basis. It would also mean that where new projects are identified, particularly those that may help facilitate national renewable energy targets that were not originally forecast, additional funding / timescales could be granted subject to such projects variations being deemed necessary and incremental capital costs being considered efficient.

It is acknowledged that a number of the suggested processes outlined above for PR5 do not reflect the current regulatory mechanisms in place. However, GHD is of the view that such potential revisions are worthy of consideration for PR5 in order to provide a fair and balanced regulatory funding process that allows the TSO to respond appropriately to changing future network requirements whilst also providing sufficient challenge and oversight of key aspects during the PR5 period.

7.3 Forecast Total TSO Capital Expenditure (2020-2025)

The total capital expenditure requested by the TSO for the PR5 regulatory period is summarised in Table 7-1 and also in Figure 7-1. This includes both requested PR5 network capital expenditure based on Scenario 1 (see Section 7.4 for further details) and requested PR5 non-network capital expenditure. For the latter expenditure, both a Business As Usual cost is included as well as additional expenditure corresponding to three further non-network expenditure categories, including: Sustainability and Development; Operate, Develop and Enhance the Grid and Market; and Engage for Better Outcomes for All.

Table 7-1 – Forecast Total TSO PR5 Capital Expenditure Required

2021 2022 2023 2024 2025 PR5 Total (€ m)

Network Capital Expenditure (Scenario 1)

19.3 21.1 15.4 16.3 8.9 81.0

Non-Network BAU Capex (Gross) 6.69 7.29 6.69 6.46 5.64 32.77* Non-Network Capex (PR4 Deferred) -0.64 -0.64 -0.64 -0.64 -0.64 -3.20 (1) Sustainability & Decarbonisation 3.70 4.89 5.44 5.59 1.99 21.61 (2) Operate, Develop Grid & Market 3.55 4.41 3.68 1.16 1.09 13.89 (3) Engage for Better Outcomes for All

0.75 0.75 0.75 0.75 0.75 3.75

Non-Network Capital Expenditure Total

14.05 16.70 15.92 13.32 8.83 68.82

Overall PR5 Total Capital Expenditure

33.35 37.80 31.32 29.62 17.73 149.82

* Correct summated total of individual non-network BAU capex elements €34.53 m


Figure 7-1 – Overview of Historic and Forecast Total Capital Expenditure

0

15

30

45

60

75

90

105

120

135

150

0

5

10

15

20

25

30

35

40

45

50

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Cum

ulat

ive E

xpen

ditu

re, €

m

Capi

tal E

xpen

ditu

re, €

m

PR4 Network Capex PR4 Network Capex Adjustments PR4 Non-Network Capex PR5 Network Capex PR5 BAU Non-Network Capex

Sustainability & Development Operate, Develop Grid & Market Engage for Better Outcomes Cum. Net PR4 Expenditure Cum. Net PR5 Expenditure




The total requested TSO (network and non-network) PR5 capital expenditure (€149.8 m) is higher than the outturn spend during PR4 by around €34.0 m (29%).

The first four years of PR5 forecast capital expenditure are all individually higher than the per annum outturn values in PR4, with the exception of 2017 which was driven by high capital expenditure on the North-South Interconnector project due to the project reaching TSO Stage 1 invoicing.

Total Business As Usual (BAU) non-network capital expenditure in PR5 (€29.6 m) is expected to be similar to the outturn values for PR4 (€30.33 m).

As part of the TSO’s PR5 submission the three incentive development themes have also been requested with additional non-network capital expenditure totalling €39.25 m. This is more than the quantum of capital expenditure requested for ongoing BAU non-network activities during PR5 or indeed that has been spent during PR4.

If the additional non-network capital expenditure themes are excluded, the total requested PR5 capital expenditure (€110.6 m) is broadly in line with the total spent during PR4 (€115.9 m)

Following the above high level review the following sub-sections will now review the network and non-network capital expenditure requested by the TSO for the PR5 period, including investigating further the reasons for the inclusion of individual capital projects as well as comparing the PR5 request with historic outturn values.

7.4 Forecast Network Capital Expenditure (2020-2025)

In response to the PR5 Price Review Questionnaire, EirGrid submitted three transmission network capital expenditure projections in the FBPQ spreadsheet noted as Scenario 1, 2 and 3. Scenario 1, which forms the basis of main TSO PR5 submission, assumes an Embracing Change philosophy where consideration is given to:

The ability to build and deliver new transmission infrastructure across the Republic of Ireland, including dealing within planning and consenting issues;

Providing a balanced view of the likelihood of deliverability and progression of the portfolio of projects included in the PR5 submission, recognising that the drivers underpinning many of the proposed investments are not all fully certain or known at the present time; and

Focusses on investment projects that will explicitly assist in connecting additional renewable generation to aid in achieving national renewable targets.

In contrast to the above, Scenario 2 assumes a Business as Usual approach to transmission network development across the PR5 period largely continuing development policies as per PR3 and PR4. Focus is given to a low risk set of portfolio projects that continue the range and type of transmission investments developed over previous periods. It is noted that the Scenario 2 allowance would not allow the scale of national renewable ambitions to be achieved. Scenario 3 is a development of Scenario 1, but assumes that transmission development restrictions, including those related to planning and consenting issues as well as capital funding are minimal and / or ignored. This scenario would deliver additional transmission infrastructure, at a higher total costs than Scenario 1, but would facilitate the connection of significant additional renewable generation capacity.



Each of the three scenarios are summarised in the following tables Table 7-2 to Table 7-4 which show the respective TSO and TAO network capital expenditure request for PR5 along with other relevant capital contributions (TAO only). The estimated capacity of renewable generation that is expected to be facilitated by the development of each scenario is also shown for reference.

Note that the TAO values shown in Table 7-2 to Table 7-4 may differ slightly from those presented in the main TAO PR5 submission and discussed in Section 9. The TAO values shown here are for reference only.

Table 7-2 – Forecast Network Capex Scenario 1 – Embracing Change

2021 2022 2023 2024 2025 PR5 Total (€ m)

Gross PR5 Capex Requirement

EirGrid 19.3 21.1 15.4 16.3 8.9 81.0 ESBN 280.4 236.1 208.4 210.4 218.3 1,153.6 Total 299.6 257.2 223.9 226.8 227.2 1,234.6

Customer Contribution

ESBN -22.0 -22.0 -22.0 -22.0 -22.0 -110.0

IDC (5% of TAO Spend)

ESBN -14.0 -11.8 -10.4 -10.5 -10.9 -57.7

Net PR5 Capex Requirement

EirGrid 19.3 21.1 15.4 16.3 8.9 81.0 ESBN 244.3 202.3 176.0 177.9 185.4 985.9 Total 263.6 223.4 191.4 194.2 194.3 1,067.0

Estimated Renewables Connected

2,900 MW

Table 7-3 – Forecast Network Capex Scenario 2 – Business As Usual

2021 2022 2023 2024 2025 PR5 Total (€ m)



Customer Contribution

ESBN -10.0 -10.0 -10.0 -10.0 -10.0 -50.0


ESBN -30.4 -25.3 -21.4 -17.1 -15.2 -109.4

Net PR5 Capex (Unfactored)


Net PR5 Capex (Factored)

EirGrid 15.0 15.0 16.0 14.0 14.0 74.0 ESBN 178.0 190.0 180.0 165.0 157.0 870.0 Total 193.0 205.0 196.0 179.0 171.0 944.0


1,500 MW

Table 7-4 – Forecast Network Capex Scenario 3 – Unconstrained Development

2021 2022 2023 2024 2025 PR5 Total (€ m)


EirGrid 41.8 39.4 27.0 21.6 11.9 141.7 ESBN 608.0 505.7 428.0 342.0 304.8 2,188.5



2021 2022 2023 2024 2025 PR5 Total (€ m)

Total 649.8 545.2 455.0 363.6 316.7 2,330.2 Customer Contribution

ESBN -39.6 -39.6 -39.6 -39.6 -39.6 -198.0


ESBN -30.4 -25.3 -21.4 -17.1 -15.2 -109.4

Net PR5 Capex Requirement



5,900 MW

In developing the outlined scenarios EirGrid has adopted a factored approach which considers the project status, project type, outage availability and overall deliverability in assessing the likelihood of the project proceeding and/or completing during the PR5 period. The factored approach undertaken by EirGrid recognises that not all of the projects identified within the period will be fully developed/constructed (with all associated costs) within that period. Greater certainty of expenditure is given for those projects which are to be developed in the near term or are most likely to advance and the majority of the projected capital expenditure will be assigned. For projects with less certainty of advancing, a factor of the total expenditure will be applied to reflect this uncertainty. The factored approach gives a more practical view of the deliverability and uncertainty of project development within the period; however it is expected that as project needs evolve over the period, the factored level of expenditure for individual projects will likely change.

Note that Scenario 1 and 2 have been developed using the factoring approach whilst Scenario 3 has not. Additionally, the factored approach has also been adopted for historic transmission capital expenditure including years 2019 and 2020 of the PR4 outturn.

In relation to the three capital expenditure scenarios presented by EirGrid for PR5, as outlined above Scenario 1 corresponds to the TSO adopted scenario within the FBPQ and business planning documentation. GHD has however reviewed all three scenarios as part of this PR5 forecast review with a view to determining whether the TSO approach to forecasting required capital expenditure for the 2021 – 2025 period will deliver the necessary transmission infrastructure at the most efficient and optimal cost for consumers. Further considerations include taking account of the industry model for transmission system development and remaining conscious of the difficulties associated with delivery of large scale network infrastructure from previous review periods.

Figure 7-2 provides a summary of the historic network capital expenditure for the TSO and TAO over the PR3 and PR4 periods as well as the annual forecast network capital expenditure for Scenario 1, 2 and Scenario 3 in the PR5 period. Also shown are the applicable CRU network capital expenditure allowance for each of the PR3 and PR4 periods as well as the average annual spend during each regulatory period shown with reference to the three PR5 scenarios. Note that all values are in 2019 prices and the 2019 / 20 figures are forecast values (from the HBPQ). Additionally, both the outturn and forecast capital values shown in the chart are net figures, which includes the impact of TAO interest during construction (IDC) and customer contributions (factored for forecast).


Figure 7-2 – Overview of Historic and Forecast Network Expenditure

0

100

200

300

400

500

600

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Expe

nditu

re, €

m

Outturn TSO & TAO Spend PR5 Scenario 1 - TSO PR5 Scenario 1 - TAO PR5 Scenario 2 (low risk) - TSO

PR5 Scenario 2 (low risk) - TAO PR5 Scenario 3 - TSO PR5 Scenario 3 - TAO PR3 Average Spend

PR4 Average Spend PR3 Regulatory Allowance PR4 Regulatory Allowance

PR3 - Spend (Actual) PR4 - Spend (Actual & Forecast for 2019/20)

PR5 - Spend (Forecast)



From review of Figure 7-2 it is evident that: Scenario 1 would see an increase in annual capital expenditure during PR5 in

comparison with PR4, with the lowest forecast annual spend (€191.4 m in 2023) being slightly above the highest annual spend experienced during PR4 (€185.3 m in 2018). The 2021 network capital expenditure at the start of PR5 would also represent a significant increase in comparison with the final year of PR4 of around 61% (circa €100 m), potentially posing some deliverability challenges. Some of this significant increase in forecast 2021 planned spend is due to projects that were not sufficiently progressed during PR4, including a number of legacy projects.

On a per annum basis, the proposed Scenario 1 PR5 capital expenditure is similar to that delivered during PR3, with the average spend in PR5 being only 4% higher than during PR3. Given that these levels of capital expenditure have already been delivered (during PR3) then both the TSO and TAO organisations should be geared up for such a level of project development and delivery, notwithstanding the comment made above regarding the step change in 2020 and 2021 potential spend.

Scenario 1 also has a relatively flat forecast capital expenditure during the final three years of PR5. This is in contrast to the variations in outturn capital expenditure during the final three years of PR3 and PR4, which varied by €49.9 m and €40.6 m respectively in each period. This is suggests that some degree of tapering may have been adopted with respect to the factored scenario weighting, particularly as the full project portfolio capital value (unfactored) as shown in Scenario 3 actually decreases from 2024 to 2025. This is confirmed by review of the average factoring weights applied to forecast annual project capital expenditure through PR5, as shown in Table 7-5 below. This confirms that the factoring values applied to projects under Scenario 1 does increase in the final two years of PR5.

Table 7-5 – Scenario 1 Factoring Values

2021 2022 2023 2024 2025 Average based on number of projects 0.88 0.59 0.56 0.60 0.62 Average based on project spend in year 0.51 0.53 0.47 0.48 0.57

In relation to increase in factoring weightings applied in 2024 and 2025, if these are adjusted to the average of the 2022-2023 values, total expected Scenario 1 spend decreases marginally, broadly in the order of single digit € millions. As this represents <1% of total network spending during PR5, it is suggested that these factoring values remain unadjusted as the impact is minimal.

In comparison, Scenario 2 is only focussed on a sub-set of 150 low risk projects and assumes similar delivery constraints and model as PR4. This would result in a slightly lower factored spend through PR5 of €944 m. However, the TSO expects that the focus on more business as usual investment projects and activities would lead to a lower expected connection of future renewable generation than Scenario 1, by around a half i.e. 1500 MW rather than 2900 MW.

Scenario 3 would require a level of transmission infrastructure development and project expenditure over PR5 on an unprecedented scale, having an annual capital spend significantly above the outturn annual values in PR4 and also being higher than any annual spend through the PR3 period. Given the project delivery challenges already faced by both the TSO and TAO during PR3 and PR4 periods, it is considered extremely unlikely that such high levels of capital expenditure (and associated project delivery) could actually be delivered by either organisation.



This analysis has provided a brief overview of the headline TSO and TAO forecast expenditure in the PR5 period (in relation to historic spend in the PR3 and PR4 periods). The following sections further inspect the breakdown of this forecast.

7.4.1 Scenario Overview

The overview of the PR5 forecast capital expenditure has been provided in the previous sub-section and has included comparison with the outturn network capital expenditure during PR3 and PR4. This section now summarises the content and composition of the scenarios and provides

Figure 7-3 provides a summary of the make-up of each scenario based on the following investment project categories:

System Reinforcement

Asset Refurbishment

New Connections

Ongoing Projects

DSO Projects

Other Projects

Note that the “Other Projects” category includes those projects listed by EirGrid with this explicit project description as well as a further set of uncategorised projects (four). This affects Scenario 1 and 3 only. Also, for Scenario 2 the factored values for individual projects have been determined based on the ratio of forecast total factored TSO and TAO capital expenditure (€74 m and €870 m respectively) to the total un-factored values (€93.3 m and €1,311.4 m)


Figure 7-3 – Investment Category Breakdown by Scenario

0

200

400

600

800

1000

1200

System ReinforcementProjects

Asset RefurbishmentProjects

New Connection Projects Ongoing Projects DSO Projects Other Projects

Fore

cast

Exp

endi

ture

, € m

Scenario 1 - Embracing Change (Factored) Scenario 2 - Low Risk Projects (Factored) Scenario 3 - Unconstrained Development



From review of Figure 7-3 it is evident that: The bulk of the forecast PR5 capital expenditure is associated with Ongoing Projects

under all three scenarios – circa 40% for Scenarios 1 and 3 and nearly 2/3 of expenditure under Scenario 2 which is more focussed on ongoing low risk projects.

Asset Refurbishment and New Connection projects have broadly similar proportions of total capital expenditure under Scenario 1 and 3 (circa 20%), with the latter category slightly higher.

Under Scenario 2 System Reinforcement projects have the most notable proportionate difference when compared to the other two scenarios, comprising <1% of total Scenario 2 expenditure.

The overall proportions of capital expenditure across the outlined categories are broadly similar for Scenario 1 and 3 varying by less than 3% for 5 out of 6 investment categories (excluding Ongoing Projects), and by less than 6% for the Ongoing Projects category. This indicates that the factoring weighting values applied by EirGrid to develop Scenario 1 (from the unconstrained project list under Scenario 3) have been applied fairly evenly across all investment categories.

In the following sub-sections of this report further consideration is given to Scenarios 1 and 3 to better understand the project composition and capital expenditure requirements during PR5.

7.4.2 PR5 Scenario Analysis

The following figure (Figure 7-1) provides a breakdown of the composition of projects making up the PR5 submission for Scenarios 1 and 3 in comparison with the expected PR4 outturn.

Figure 7-4 – Investment Category Breakdown by Number of Projects

When comparing the number of projects undertaken in like for like categories in PR5 compared to expected PR4 outturn, it is clear that the total numbers of expected projects are expected to

0 50 100 150 200 250

System Reinforcement Project

Asset Refurbishment Project

New Connection Project

DSO Project

Other/Uncategorised

Number of Projects

Proj

ect

Cate

gorie

s

PR5 PR4



decline over the period in all significant categories. Work allocated to “ongoing projects” makes up the majority of the difference in the overall number of projects worked on, with 230 projects allocated for spending in PR5 compared to 255 in PR4. However, the extent of the decline in project numbers is not proportional to the decline in spending in each category, with higher spending per new project over the PR5 period.

• In the new connections project category, the number of projects undertaken are expected to decline by ~39%, however total spending on new connections is expected to increase by ~31% in Scenario 1, or by ~130% in Scenario 3. The average cost of a project to connect a new customer is therefore expected to increase substantially. However, it is noted that higher spend in PR5 allocated to New Connection projects suggests that existing capacity has been effectively used during previous connections, with more significant projects now required to facilitate new connections, which include the prospective offshore wind connections (~1/4 of the spending in Scenario 1 is associated with the connection of offshore) which tend to have higher connection capital costs than onshore projects. In the unconstrained Scenario 3, substantially more connections work is forecasted to take place in the PR5 period, with more projects having allocated spend.

In the system reinforcement project category, the number of projects undertaken are expected to decline by ~85%, however the total decline in spending on reinforcement is only expected to be ~53% in Scenario 1, or ~41% in Scenario 3. Reinforcement projects in PR5 are therefore expected to be of significantly higher value than in PR4 on average. However, a decline is registered in both factored and unconstrained scenarios showing the expectation that significantly less reinforcement work by value will be carried out going forward, with more focus on utilisation of existing sites and assets.

In the asset refurbishment project category, the number of projects undertaken are expected to decline by ~64%, however total spending in the category is expected to increase by ~104% in Scenario 1, or ~301% in Scenario 3. There are several extremely high spend projects allocated to this category over the period, with 9 projects alone in Scenario 1 accounting for expenditure exceeding the previous spend in the category in PR4. These projects are primarily large cable and overhead line replacements, although significant spend has also been allocated to tower painting and acquiring strategic spares.

7.4.3 Scenario 1 Review

Figure 7-5 provides a summary of forecasted project spend within the PR5 Scenario 1 outlook. In this factored scenario, the largest single categorised spend is on Ongoing Projects, which represent long term projects established during previous price control periods, and projects which were delayed from PR461. The largest spend on new projects required within the period is expected to be to facilitate New Connections, in line with the expected increase in wind generation capacity throughout the period. Both Reinforcement Projects and Asset Refurbishment projects are expected to have roughly equivalent spending, with smaller remaining funds diverted to DSO Projects and Others categorised projects.

Figure 7-6 provides a comparative summary of PR4 project categorisation for reference.

61 Delayed projects represented 6% of the total projects completed in PR4 and in general are the largest and most contentious projects, where delays are outside the control of the TSO and TAO such as planning consent, land access and legal challenges in the form of judicial reviews.



Figure 7-5 – Investment Category by Value: PR5 Spend – Scenario 1

Figure 7-6 – Investment Category by Value: – PR4 Actual & Forecast Spend

A comparison of the Figure 7-5 and Figure 7-6 charts shows a broad change in spending patterns over the two price control periods. When comparing the PR5 projected spending to the spend over the PR4 period:



The PR5 period has a significantly lower spend, both by value and as a proportion of total spend on System Reinforcement Projects. That said, the PR5 project categorisation includes an Ongoing Project category which was not included in the PR4 categorisation and which would be expected to be composed of around 2/3 of system reinforcement projects based on Figure 7-6. However, even allowing for this the total expected capital expenditure of PR5 System Reinforcement plus 2/3 PR5 Ongoing Projects is still expected to be lower than the outturn System Reinforcement project costs in PR4.

The above comment regarding the lower proportion of System Reinforcement projects is also reflected in TAO provided figures, which show that anticipated volumes of new equipment purchases are expected to decline significantly during the PR5 period. Scenario 1 for PR5 therefore reflects that the TSO expects reinforcement spending to significantly decline compared to the last two price control periods.

The PR5 period has a significantly higher spend, by both value and as a proportion of spend on Asset Refurbishment Projects. Scenario 1 therefore suggests that the TSO expects to make more use of existing assets, and rely less on network buildout. The decline in total spend on both system reinforcement and asset refurbishment projects between price control period suggests savings will be realised as a result of this approach.

The PR5 period has a significantly higher spend than PR4 allocated to New Connection projects by ~31%. However, the forecasted increase in wind capacity62 over the period (1,055 MW) is expected to be a reduction when compared to PR4 (1,406 MW). This increase in spend suggests that existing capacity has been effectively used during previous connections, with more significant projects now required to facilitate new connections, which could include the prospective offshore wind connections which tend to have higher connection capital costs than onshore projects.

Spending on DSO projects in the PR5 period is expected to increase significantly when compared to the PR4 period, albeit from a relatively low value. This increase in spending is attributed primarily due to planned Pipeline Projects planned to be undertaken between 2022-2025. Having reviewed the TSO PR5 narrative document, there is little reference to DSO spending beyond the complexity of interfaces required, therefore it is unclear the extent of work which may be required in PR5 to support such projects.

Providing further illustration of the expected difference in outturn projects being development in PR5 in comparison with PR4 is Figure 7-7. This shows the expected outturn volume of assets that will be delivered by Scenario 1 over PR5 in comparison with the expected outturn for PR4.

62 Values taken from the 2019 All-Island Generation Capacity Statement



Figure 7-7 – Expected New Assets to Be Added over PR5 period


The volumes of new overhead line projects through PR5 are expected to continue the trend seen during PR4, which is significantly lower than experienced during PR4. At the same time overhead line refurbishment and uprating schemes are expected to increase further. This is likely as a result of the difficulties associated with planning, consenting and constructing new transmission overhead lines during past price review periods.

The volume of new transformers and switchgear is also expected to decrease over the PR5 period, continuing a trend seen from PR3.

Volumes of subsea cable expected to be installed across PR5 continues to remain low in comparison with onshore underground cables, although even the latter is expected to reduce during PR5.



7.4.4 Project Analysis – High Capex Projects

Reviewing the expected project composition within the PR5 forecast the top ten project with the highest forecast expenditure are shown in Table 7-6. Note that outlined project costs are the un-factored values.

Table 7-6 – Top Ten Projects by Capital Expenditure (TSO and TAO)

CP Number Project Name Total PR5, € TSO, € TAO, € CP0466 North South 400kV Interconnector 80,670,528 8,187,309 72,483,219 CP1029 Intel 220 kV 65,855,218 866,858 64,988,359 CP0966 Dunstown - Woodland 61,710,000 900,000 60,810,000 CP0816 "North Connaught Line

(Moy - Tonroe 110kV Line - New Line)" 37,514,657 6,887,794 30,626,863

CP0800 North West Project (RIDP) 36,000,000 6,000,000 30,000,000 Pipeline Project

Offshore Wind 1 progressing under enduring policy

35,743,750 213,750 35,530,000

DSO - Pipeline Projects

DSO Projects - programme of work (placeholder)

35,500,000 8,000,000 27,500,000

CP0585 Laois Kilkenny (Coolnabacky) 400kV Station – New Station & Associated Lines & Station Works

32,733,169 462,764 32,270,405

Pipeline Project

Offshore Wind 2 progressing under enduring policy

32,513,750 213,750 32,300,000

CP1021 North Dublin Reinforcement 31,554,000 620,000 30,934,000 In relation to the projects shown in the Table 7-6:

CP0466: This project has been commented on in the PR4 review – reasons for project delays have been detailed, and project value appears to have been relatively unchanged

CP1029: This is a customer driven project to connect a large expansion of a facility by Intel which was not forecast during PR4, but is now planned to be delivered within the PR5 period.

CP0966: This project is commented on in Section 7.4.5 – this is a previously planned reinforcement project concerned with facilitating transmission of power from renewable generation in the South-West to Dublin.

CP0800: This project was comment on in the PR4 review – this project is currently on hold.

CP0585: This project was commented on in the PR4 review. It is expected that this project will progress, after access and consenting issues are addressed, however forecasts for expenditure remain below the original budget when the project was planned.

DSO pipeline projects – commented on in Section 7.4.3, but currently with limited information presented to fully explain the expected need for the projects during PR5.

CP1021 - commented on in Section 7.4.5 – this is a previously planned reinforcement project concerned with facilitating transmission of power from renewable generation in the South-West to Dublin.

7.4.5 Project Analysis – Ongoing and Delayed Projects

From review of the composition of projects within Scenario 1 there are 57 projects categorised as Ongoing during PR5 which have begun in earlier price control periods, there are also an additional 43 new projects with project numbers established in PR4. The majority of these



projects have relatively minor or no spend over PR4, despite being established in this period. These projects include generation connections, asset refurbishment and system reinforcement projects, some of which were planned to begin in PR5, but with others subject to delays in their delivery.

In total, eight projects are expected to span three or more price control periods, with projects established in PR3 or PR4 with finish dates estimated beyond PR5. These are shown in Table 7-7, with outlined costs including TSO and TAO.

Table 7-7 – Projects Spend Over Three or More Price Review Periods

Project PR4 Spend

2021 2022 2023 2024 2025 Est. End Date

CP0966 0 0 0 21.0 20.4 20.4 2027 CP0841 0.2 0 0.2 1.0 1.0 1.0 2027 CP0624 8.0 1.9 1.9 3.0 3.8 4.3 2027 CP1021 0 0 0 0 16.1 15.5 2028 CP0800 0 0 0 0 4.9 31.1 2027 CP1023 ~0.01 0 3.9 3.6 3.7 3.4 2027 CP0799 2.9 2.2 2.0 2.0 2.3 2.3 2026 CP0907 0 0 0 0 0 2.0 2030

In relation to the eight projects shown in Table 7-7: Two of the projects (CP0624 and CP0799) have significant spending in the PR4 period,

however this spending is substantially below forecast. These projects are substation refurbishment projects, which now have the bulk of their spending allocated to PR5 after significant delays in PR4.

The CP0800 (RIDP) project was forecast to begin in PR4, with ~€75 m in spending over the period. The project is currently on hold, however still has spending allocated (~€35 m) during the PR5 period, although is not forecasted for completion. Based on information from the TSO which states that the project is “On Hold” in the HBPQ submission (spreadsheet tabs 6.3 & 6.4) it is recommended that all funding for this project is removed from the PR5 allowance given that in the view of the TSO it is unlikely to be developed to construction during the PR5 period. If the project does actually proceed during PR5 then the costs for this project can be assessed at the end of PR5 in a similar manner to projects that were not originally forecast for PR4 but have nevertheless incurred capital expenditure during PR4.

CP0907 follows a similar pattern of expenditure to the RIDP project, with the project driven by the connection of North West Wind, and delayed until the end of PR5 despite originally having forecasted spending for PR4. It is uncertain whether this project will be commenced during PR5, however the expected total project capital expenditure is only €2.0 m, with the TSO PR5 expenditure €325 k.

The CP1021 North Dublin reinforcement project, and the CP0966 Dunstown-Woodland project were included in PR4, with spending forecast for PR5. These works have been accelerated to accommodate the transmission of additional renewable generation to the load centre of Dublin.

The remaining projects on the list (CP0841 and CP1023) have little to no spending in PR4 despite their forecasted requirements, due to delays in implementation.



7.4.6 Network Needs and Generation Connections

Historic network demand has been relatively flat over the PR4 period, however an increase in demand has been forecasted for 2019 and onwards with further demand increases forecasted to continue over the PR5 period, as shown in Figure 7-8. Some of this demand growth is attributable to planned customer connections of data centres, with interest expressed in large connections and a large customer connection of an Intel data centre at 220 kV accounting for €66 m over the PR5 period. A review of the reinforcement projects planned for the period shows that of projects with planned spending, 13 projects with €56 m in spending is allotted to 110 kV line up rates. Highest spending projects for system reinforcement are the long planned North Dublin reinforcement work and the Dunstown-Woodland project.

Figure 7-8 also notes the historical and forecast installed wind capacity (forecast values obtained from the 2019 Generation Capacity Statement (GCS). Wind capacity growth is expected to continue at a slower rate throughout the PR5 period when compared to the PR4 period and the total incremental PR5 capacity (~1.0 GW) outlined is significantly lower than the notional 2.9 GW of additional renewable generation indicated by EirGrid to be facilitated by their proposed Embracing Change Scenario 1. It is unclear why there is a significant variation between the two figures, although the TSO has confirmed that the proposed Scenario 1 capacity value (2.9 GW) includes prospective connections where offers are either contracted or are in the offer process. Nonetheless, the potential scale of the additional renewable generation that is envisaged by the TSO to be developed over PR5 is significant in comparison with historic outturns, broadly representing the same total value to be installed over PR5 as all wind generation connected up to around 2016. On this basis, the delivery of proposed transmission investment infrastructure through PR5 will be critical to achieving outturn renewable generation capacities of this scale.


Figure 7-8 – Historic and Forecast Network Demand and Wind Capacity



7.4.7 Summary and Conclusions

GHD has reviewed the PR5 submission of the TSO in relation to network capital expenditure, assessing the needs likely to arise over the PR5 period, as well as the viability of the developed scenarios put forward for assessment by the TSO.

It is clear to GHD that the most credible and appropriate scenario developed for the purpose for the governance and investment in the Irish transmission network over PR5 is Scenario 1 – “Embracing Change, Delivering Targets”, and as such the recommendations and analysis in this report have been made primarily on that basis.

Analysis of the method used to factor projects in Scenario 1 has been judged to be appropriate for determining expenditure over the PR5 period, but has increased doubt over the viability of the assumptions used to establish the “unconstrained” Scenario 3. As factoring appears to be used in Scenario 1 to take into account external factors like consenting delays and risk, GHD therefore believe the spending profile in the unfactored Scenario 3 is clearly unrealistic and not deliverable. That said, the unfactored project costs from Scenario 3 have been a useful source of data to understand over total project costs at completion, including those projects that started in PR4 or earlier periods.

The low risk “Business as Usual” Scenario 2, while accounting for lower spending, is agreed to not represent an appropriate plan for network investment. This view has been reached when considering the expected role of the TSO over PR5 (and PR6) in meeting climate change targets as well as forecast demand growth over the PR5 period, which represents a broad change from previous price control forecasts.

Broadly, the spending in Scenario 1 is considered appropriate, with a greater focus on use of existing assets including land, with considerably more spending on asset refurbishment and renewal than in previous price control periods, and a drop in reinforcement spending forecast. However, analysis of some of the proposed projects through PR5 has identified capital expenditure that is not currently or appropriately justified. GHD therefore recommends that efficient funding be allowed for network spending under Scenario 1 as shown in Table 7-8, with the following deviations.

Table 7-8 – Forecast TSO PR5 Network Expenditure – Recommendation

Network Capital Expenditure Request (€m)

2021 2022 2023 2024 2025 Total (€ m)

System Reinforcement 6.652 0.000 0.485 0.650 2.186 3.331 6.652 Asset Refurbishment 8.384 0.738 2.343 2.111 1.973 1.221 8.384

New Connections 23.81 8.355 6.624 4.800 2.825 1.207 23.81

Ongoing Projects 32.118 9.334 8.370 5.534 2.007 0.254 25.499

DSO Projects 8.071 0.400 0.400 0.400 0.400 0.400 2.000

Other & Undefined Projects 1.984 0.784 0.250 0.350 0.300 0.300 1.984

Overall PR5 Total 81.02 22.54 22.70 17.70 10.292 6.731 68.32

Forecast spending in the category “DSO Projects” has increased by over 300% from the PR4. This is singly due to forecast generic “DSO Pipeline Projects” of a total value of €35.5 m over the PR5 period (TSO €8.0 m). GHD does not consider that the proposed increase in spending has been adequately supported by documentation provided by the TSO, and therefore suggests that this be reduced to bring total allowance in the category



of DSO Projects to €12 m (TSO €2.0 m). This would give the proposed “DSO Pipeline Projects” a total allowance of €7,365,041 over PR5 (TSO €1.93 m), while leaving spending on the other two specified projects in the category as per the Scenario 1 forecast (TSO €70 k). The total efficient TSO PR5 allowance for DSO Projects would therefore reduce to €2.0 m, with €10 m being the PR5 allowance for the TAO. The proposed reduction in TSO PR5 allowance is €6.071 m.

The RIDP project was originally forecast to begin during the PR4 period, but was put on hold after delays, and now has no anticipated expenditure over the period. A re-evaluation of the project need is now underway, however the project still has €36 m in anticipated expenditure allocated during PR5. GHD recommends that this expenditure is removed from the PR5 allowance for Ongoing Projects (TSO €6 m63, TAO €30 m) given the status of the project. If the project subsequent re-materialises then it can be reviewed at the end of PR5 in a similar manner to any new projects that appear during PR5 that are not known at the current time. The proposed reduction in TSO PR5 allowance is €6.0 m.

The TSO forecast capital expenditure file provided to GHD contained an allowance for the Dunstown 400 kV Series Compensation project of €37.06 m in Scenario 1 (TSO €1.13 m). This was flagged as excessive and considered to be an error after determining that the unconstrained Scenario 3 had a smaller allowance for the project. Additionally, review of other similar projects within Scenario 1 also identified that the outlined value was questionable as was further confirmed by review of the TAO PR5 submission which, included a different, substantially lower total value of €6.82 m, with TSO expenditure of €0.51 m for PR5 (€505 k in 2021 and €5 k in 2022). The proposed reduction in TSO PR5 allowance is €0.62 m.

In a response to a question raised by GHD with regards to the Dunstown series compensation project EirGrid has indicated that the original stated Scenario 1 values for the Dunstown and the similar Moneypoint series compensation projects do not reflect the accelerated status of development of these projects as agreed with CRU. EirGrid further state that the Scenario 3 values for the projects (unfactored total of €54.23 m) actually reflect the most appropriate view of expected project costs in PR5, and is €3.71 m higher than the incorrect factored total of €50.52 m under Scenario 1. Whilst this statement is recognised, the use of the outlined TSO stated value is at odds with the value included in the TAO submission as well as other similar projects within their own Scenario 1 submission i.e. Oldstreet series capacitor. As a result, until such time as the TSO (and TAO) can collectively review and update the stated capital expenditure value for this and similar related projects GHD is of the view that the TAO value is the more appropriate of the two to be included in Scenario 1, and hence included in the provisional PR5 allowance.

7.5 Forecast Non-Network Capital Expenditure

The TSO has provided their non-network PR5 capital expenditure request as part of the FBPQ submission. This is composed of four distinct components, as follows:

1. A Business As Usual non-network expenditure request covering capital spend on existing IT assets and systems, including control centre, EMS etc.

2. Three new PR5 initiative groups covering: Sustainability & Decarbonisation; Operate, Develop and Enhance the Grid & Market, and Engage for Better Outcomes. For each of these new initiatives a capital expenditure request is made.

63 €4.926 m in 2024 and €1.073 m in 2025.



GHD has reviewed the information provided by the TSO with respect to the outlined non-network capital expenditure areas and provided commentary on the adequacy of the information submitted to substantiate the broad need and capital costs of each investment category. The following sub-sections presents the summary of our analysis and recommendations for each of the four principal non-network capital expenditure categories requested by the TSO for PR5.

7.5.1 Business as Usual PR5 Capital Expenditure

The proposed PR5 Business as Usual Non-Network Capital Expenditure is split into the following initiative categories:

1. IT Assets Reaching End of Life

2. Transition to Cloud

3. Review of IT Operating Model

4. Simplify and Standardise IT Solutions

5. Cyber Security

6. Workplace Assets Reaching End of Life

Initiative 1: IT Assets Reaching End of Life The following table (Table 7-9) summarises the EirGrid requested capital expenditure included in their PR5 forecast submission in relation to replacing IT assets that are reaching end of life. Note that the actual requested total non-network capital expenditure for this investment category is shown in the last line of Table 7-9, which is slightly lower than the summated total of individual line items due to rounding.

Table 7-9 – Requested Non-Network Capex – End of Life IT Assets

Category 2021 2022 2023 2024 2025 Total (a) Telecoms Refresh 1.71 1.47 1.51 1.56 1.61 7.86 (b) Desktop Equipment Refresh 0.07 0.07 0.07 0.07 0.07 0.35 (c) VMware / Citrix Upgrades 0.00 0.05 0.06 0.00 0.05 0.16 (d) Server OS Upgrades 0.08 0.19 0.19 0.06 0.02 0.54 (e) Oracle Vault Refresh 0.00 0.08 0.00 0.00 0.00 0.08 (f) Data Centre Switching Upgrade 0.08 0.08 0.08 0.08 0.04 0.36 (g) Floor Access Switching Upgrade 0.08 0.08 0.08 0.08 0.04 0.36 (h) Wireless IS Upgrade 0.11 0.11 0.11 0.00 0.00 0.33 (i) Server & Storage Expansion 0.00 0.08 0.08 0.08 0.08 0.32 (j) Storage Area Networks (SANs) 0.53 0.3 0.00 0.00 0.00 0.83 (k) Oracle Database Refresh 0.06 0.11 0.11 0.04 0.02 0.34 (l) Dynamic AX Upgrade 0.38 0.38 0.00 0.00 0.00 0.76 (m) CSB Standing Data Automation 0.00 0.00 0.00 0.23 0.00 0.23 (n) Private Communication Network 0.15 0.00 0.00 0.00 0.00 0.15 (o) Data Centre Consolidation 0.01 0.02 0.02 0.02 0.02 0.09 (p) Replacement AV Equipment 0.00 0.08 0.08 0.00 0.00 0.16 (q) Additional Business Projects 0.39 0.39 0.36 0.24 0.24 1.62 (r) Office Upgrade Changes 0.08 0.08 0.08 0.08 0.08 0.40 (s) Guarantees of Origin Tender 0.00 0.00 0.00 0.23 0.00 0.23 (t) Website Tender Replacement 0.00 0.00 0.00 0.00 0.38 0.38 (u) Oracle Upgrade Application Changes 0.00 0.00 0.00 0.08 0.08 0.16 (v) Control Centre Equipment Refresh 0.05 0.05 0.05 0.05 0.05 0.25



Category 2021 2022 2023 2024 2025 Total (w) EMS Refresh 0.95 0.95 0.95 0.95 0.95 4.75 Summated Total (Above), € m 4.73 4.57 3.83 3.85 3.73 20.71 Requested TSO Total, € m 4.69 4.52 3.79 3.79 3.72 20.51

Commentary against the specific investment category line items included in Table 7-9, in particularly the need for the investment and whether the costs appear reasonable is now provided.

1. Category (a) – the need to replace telecommunications equipment when this has reached notional end of life is understood and we agree that typical asset lifetimes of 10-15 years are appropriate. However, this investment represents the single highest expenditure within both the End of Life IT Assets category as well as the total BAU non-network capital expenditure requested for PR5 and hence further data and supporting information i.e. number of expect assets to be replaced during PR5, expected asset age prior to replacement, etc. is required to demonstrate the need for this investment.

Recommendation: Whilst the need for investment is generally understood, given the scale of potential capital expenditure involved it is incumbent on the TSO to provide supporting information to substantiate their claimed end of life asset replacement expectations during PR5. As such supporting information has not been provided by the TSO to satisfactorily demonstrate the requirement for investment it is recommended that a notional 50% allowance should be given for this investment category.

2. Categories (b) to (h), (j), (k), (m), (n), (p), (r), (u) – the need for the individual investments under each expenditure line item have been reviewed. In all cases the TSO has clearly stated why the investment is needed, how it relates to current or existing asset replacement / investment policy, and in some cases software / hardware upgrade and obsolescence requirements that will occur during PR5. Costs are generally referenced to existing / recent similar works meaning that current estimates appear reasonable.

Recommendation: The costs for these investment categories should be allowed in full.

3. Category (i) – The outlined server expansion cost item appears to be a placeholder for potential expenditure during PR5 and is by the TSO’s admission potentially “offset as cloud adoption grows in the organisation”, as moving server capacity to the cloud will reduce the need for further server hardware investments,

Recommendation: Needs, scope and timing not clear and requirement appears to be offset by other investment items. Recommended to disallow this investment.

4. Category (l) – EirGrid have outlined how the Dynamics AX software is used within the organisation for managing a suite of financial systems on their corporate network. Routine upgrades of such systems are common on a periodic basis and this is what EirGrid are proposing here, However, whilst we accept that there is a broad need for a system such as Dynamics AX within the EirGrid business, it does seem somewhat unreasonable to spend €0.76 m over two years (2021 and 2022) if the planned transition to cloud services in 2023 occurs.

Recommendation: Unless the TSO can demonstrate that this expenditure is essential i.e. related to statutory, legal or security obligations then it is recommended that this investment is disallowed.

5. Category (o) – the need for this investment seems questionable, as it appears to have some duplication with category (i) Server & Storage Expansion and (j) Storage Areas Networks. In particular the statement is made that “EirGrid is pursuing a programme of data centre consolidation” which seems at odds with the investment items above.



Recommendation: The TSO needs to demonstrate that this investment is not mutually exclusive with the other investments under the End of Life Assets category i.e. this investment is needed as well as the others outlined. Until such time it is recommended to disallow this investment.

6. Category (q) – this investment category is also a placeholder for potential expenditure that is “unknown at this stage” and is the third highest individual expenditure items under the IT Assets Reaching End of Life category.

Recommendation: As this is a placeholder category with unknown scope, requirements and costs it is recommended to be disallowed as part of the PR5 allowance. EirGrid can however claim the costs of these works at the end of PR5 subject to providing suitable business cases / demonstration of investment need as well as how they have managed and procured the work to deliver efficient outturn costs.

7. Categories (s) and (t) – these investment categories are also placeholders for potential future expenditure which does not have a defined need or cost at this time, other than being a provisional to allow a future retender.

Recommendation: As this expenditure is basically a placeholder amount and is anticipated to occur towards the end of PR5 it is recommended that it is disallowed within the PR5 allowance at this time. EirGrid can however claim the costs of these works at the end of PR5 subject to providing suitable business cases / demonstration of investment need as well as how they have managed and procured the work to deliver efficient outturn costs.

8. Category (v) – Whilst the criticality of control centre equipment to system operations is understood it is unclear exactly how or why the equipment must be replaced on an annual basis versus some other period i.e. 18 / 24 months, and whether the EirGrid proposal relates to a subset of equipment or all equipment. It is also worth noting that with respect to IS equipment if this can operate successfully for the first year and not experience any issues then in all likelihood it should be able to continue operating reliably until the end of the warranty period i.e. for 2 or 3 years. Replacing the same equipment on an annual basis, if that is what EirGrid is proposing, actually introduces its own risks due to new equipment failures that, if they do occur, typically do so within the first year. EirGrid have not demonstrated that their proposed replacement strategy is the most effective and efficiency use of funding through a detailed business case that examines the pros, cons and risks associated with an annual replacement versus replacement on another basis i.e. at 18 months, 24 months etc.

Recommendation: Based on GHD’s experience we would typically expect control centre equipment to be replaced on a longer timeframe i.e. three to five years, than the per annum basis that EirGrid have proposed for this initiative. As such, whilst it is considered reasonable to replace some control centre equipment within the five years of PR5 we do not believe that the full expenditure outlined by EirGrid is reasonable and hence recommend to allow 50% of the requested expenditure.

9. Category (w) – It is our understanding the existing EMS system was commissioned in 2016, EirGrid state the core EMS will be replaced every 5 years. It is our experience that industry best practice for the replacement of EMS is 8-12 years, suggesting that proposed investment may be slightly ahead of need. However, in response to queries raised by GHD EirGrid have provided details of anticipated EMS core end of lifetime and extended warranty periods as well as anticipated implementation programme, On this basis it appears that there is a need for the replacement of the EMS system during PR5.

However, there are complexities in the development of tools for the scheduling and dispatch of distributed energy resources embedded within the distribution network.



These include knowledge of operational, thermal, voltage and fault level restrictions within the distribution network to ensure safe operation of the network and compliance with licence regulatory conditions. It is not apparent how these constraints in the network are considered in the dispatch tools.

As highlighted by EirGrid, these are complex software packages requiring detailed specification and testing to ensure they operate satisfactorily. The proposal from EirGrid has not presented anything more than a conceptual design and a list of potential developments with the first task being the preparation of solution roadmap and programme for the development. We would agree the adoption of new technologies and the increase in distributed energy resources embedded in the distribution network requires the development of new tools to assist the network operation. However, EirGrid have not provided sufficient justification of the costs, or demonstrated they will be able to meet the programme to complete the work during PR5.

Recommendation: As above, we agree that the EMS is a critical system and that it will require upgrading and augmentation in order to cater for new functions and interfaces to be added during PR5. However, the remains a number of potential questions with respect to the current EirGrid proposal, including the exact extent of functionality and interface requirements, as well as prospective costs. As a result, it is recommended that 90% of the requested value is provided.

Initiative 2: Transition to Cloud EirGrid, as an IT intensive business are investigating ways to build long-term resilience into their existing systems and processes. One of these mechanisms is moving away from the business owning and maintaining their own servers and purchasing cloud-hosting software systems. This initiative is already underway in that a certain number of services have been migrated to cloud services so the business can gain knowledge and experience in areas such as security and authentication, and identify the skills and resources needed to support the organisation in its future state.

This initiative continues to build on current knowledge of cloud-based services and migrate additional services to cloud based servers. EirGrid provides a 5-year plan including details on the type of servers to be transitioned. The TSO proposed capital and operating expenditure requested for PR5 for this initiative is presented in Table 7-10.

Table 7-10 – Requested Non-Network Capex – Transition to Cloud

Category 2021 2022 2023 2024 2025 Total Capital Expenditure Requested, € m 0.22 0.22 0.98 0.83 0.25 2.50

GHD is of the view that the use of cloud services is becoming a standard industry practice and EirGrid approach of staged entry is appropriate as the potential risk for governance and security management need to be addressed – EirGrid acknowledge the need for security management.

EirGrid has provided an estimate of the potential financial savings by moving away from business owned assets to cloud based services. During PR5 EirGrid plans to move 300 servers to cloud hosting software with a further 200 during PR6. The potential cost saving of moving the 300 servers to cloud hosting software during PR5 could yield operation cost savings of €1.2 m per annum. It is acknowledged that the transition would not allow all potential servers that can be moved to cloud hosting software to be moved in the first year of PR5, there will be a gradual transition. Nevertheless given the broad capital and operating costs expected to be invested alongside the potential cost savings realisable the proposed investment appears broadly self-funding, i.e. opex savings of €1.2 m p.a. should offset the requested capex and opex costs within the PR5 period. On this basis, whilst there does appear to be a need for investigating and



further adoption of cloud services it is recommended that the requested funding is disallowed due to the self-funding nature of the works.

Initiative 3: Review of IT Operating Model The TSO proposed capital and operating expenditure requested for PR5 for the review of the existing IT operating model is presented in Table 7-11.

Table 7-11 – Requested Non-Network Capex – Review of IT Operating Model

Category 2021 2022 2023 2024 2025 Total Capital Expenditure Requested, € m 0.30 0.40 0.00 0.10 0.00 0.80

With respect to the scope of the IT operating model, review of the TSO provided documentation has identified that proposal and associated business case appears to be in its infancy. That is the scope includes consultation, design and managed implementation. As result, given the initial stages of the current thinking and proposal it is not clear how realistic the proposed costs are. There is also no breakdown of the costs and how they were established.

In summary, we see that there is a need to ensure that the IT operating model is correct for the business. However, this proposed initiative does not appear to have progressed with sufficient detail to understand fully what is required. Additionally, if the initiative is expected to yield efficiency savings as the TSO claims then it is expected that the TSO would fund this initiative through baseline expenditure and hence no separate allowance should be needed during PR5.

Initiative 4: Simplify and Standardise IT Solutions The following table (Table 7-12) summarises the EirGrid requested capital expenditure included in their PR5 forecast submission to standardise and simplify existing IT solutions. Note that the actual requested total non-network capital expenditure for this investment category is shown in the last line of Table 7-12, which is slightly lower than the summated total of individual line items due to rounding.

Table 7-12 – Requested Non-Network Capex – Simplify & Standardise IT Solutions

Category 2021 2022 2023 2024 2025 Total (a) Application Rationalisation 0.18 0.18 0.18 0.18 0.18 0.90 (b) Application Upgrades & Changes 0.24 0.24 0.24 0.24 0.24 1.20 (c) Remit / ENTSO-E Transparency 0.08 0.08 0.08 0.08 0.08 0.40 (d) Linux Management Tools 0.08 0.00 0.00 0.00 0.00 0.08 (e) Capacity Market Platform (CMP) 0.11 0.11 0.11 0.11 0.11 0.55 (f) Customer Relationship Management (CRM) 0.15 0.15 0.15 0.15 0.15 0.75

(g) Middleware Changes (OSB & GDX) 0.08 0.08 0.08 0.08 0.08 0.40 Summated Total (Above), € m 0.92 0.84 0.84 0.84 0.84 4.28 Requested TSO Total, € m 0.91 0.83 0.83 0.83 0.83 4.24

Commentary against the specific investment category line items included in Table 7-12, in particularly the need for the investment and whether the costs appear reasonable is now provided.

1. Category (a) – This initiative focusses on reducing the number of business solutions within EirGrid. The business case identifies that it will save money due to reduced information technology infrastructure and licencing, however it does not identify the scale of the financial saving that is to be made.



Recommendation: It is unclear what the requested capital expenditure would actually cover and in any case we would expect that the savings made by reducing licence requirements and infrastructure would largely outweigh any associated “costs”. On this basis we recommend that this allowance request is disallowed.

2. Category (b) – This is a group of initiatives that relate to small sets of changes to IT solutions where EirGrid are of the view that they do not merit individual projects to implement the changes, and is expected to cover mandatory application updates, security vulnerability risks and application changes to comply with new regulations.

In relation to mandatory application upgrades to BAU systems, we would have expected these costs to have been largely captured in the individual application projects when that project was originally undertaken. Consequently, it is unclear when and how additional expenditure is required.

In relation to security, EirGrid has already identified a Cyber Security initiative to address emerging security risks. Therefore, the associated costs appear to already be covered / allocated to other projects.

Finally, in relation to potential application and business process changes it is unclear if there is an overlap between this initiative and others within this and other non-network BAU capital expenditure categories i.e. End of Life IT Assets.

Recommendation: As the TSO has not demonstrated that the outlined applications changes and associated capital expenditure requirement is not included in other non-network expenditure categories it is recommended that a zero allowance is provided.

1. Categories (c) and (d) – the need for the individual investments under each expenditure line item are understood and the works accepted.


2. Category (e) – The capacity market platform is a core IT system for the Capacity Market. There is an ongoing requirement to make changes to the platform to accommodate changes to industry requirements. GHD understands that this expenditure item relates to the capacity market platform and not the functionality that EirGrid need internally from the capacity market platform. However, we would expect that the Single Electricity Market Operator (SEMO) would facilitate any platform based upgrades as needed, with the associated costs split between EirGrid and SONI on the normal cost allocation basis. It is unclear if the costs proposed for this expenditure line item relation to just the EirGrid contribution or the full project cost.

Recommendation: The requirement for platform upgrades is understood however the basis for the quoted costs is unclear, including that these relate to EirGrid costs only. As a result, it is recommended that an allowance of 50% of the requested value is provided.

3. Category (f) – EirGrid currently manage details and contacts using multiple disparate solutions and are looking to develop a cloud based customer and stakeholder management system. We agree that the need for a single CRM solution is likely to be needed to ensure full compliance with GDPR and other cyber security restrictions. However, little detail or information has been provided to substantiate the quoted costs and we note that this project and expenditure is contingent on the outcomes of Initiative 2 Transition to Cloud which is expected to trial a cloud based CRM solution.

Recommendation: It is unclear how the costs for this expenditure line item have been derived, and this expenditure is also contingent on undertaking Initiative 2 Cloud Based Transition. As a result, given the potential uncertainty related to the timing and scale of the potential costs



associated with this investment it is recommended that an allowance of 50% of the requested value is provided. This will allow sufficient time for the Initiative 2 Cloud Based Transition to be completed within the first few years of PR5 before deciding whether to roll out the full CRM solution to the wider business in the latter years of PR5.

4. Category (g) – EirGrid currently use two middleware products (OSB and GDX) to link various business systems and is planning to transition those current managed by GDX to OSB which was implemented as part of I-SEM. Whilst there are expected to be costs involved in the transition there would also be expected to be some benefits through using a single middleware product to interlink and manage interactions between various business systems. This includes cost savings by eliminating the use of GDX throughout the organisation (or at least significantly reducing the requirement for it) as well as potential additional benefits through enhanced functionality and easier data exchange / integration between end business systems as all will be using a common middleware product. These aspects have not been documented as part of this expenditure proposal.

Recommendation: It is unclear how the proposed costs for this expenditure item have been derived and also if the proposed investment will generate any costs savings and other benefits which may be pertinent to evaluating the overall business case. Given these outstanding issues it is recommended that zero allowance is given for this investment line item.

Initiative 5: Cyber Security The following table (Table 7-13) summarises the EirGrid requested capital expenditure included in their PR5 forecast submission for baseline cyber security aspects, i.e. replacement of existing systems / assets as they reach end of life. Note that the actual requested total non-network capital expenditure for this investment category is shown in the last line of Table 7-13, which is around half of the summated total of individual line items. It is believed that this is an error and appears to be due to EirGrid failing to include the cost for expenditure line item (b) Enterprise Refresh in the overall Baseline Cyber Security Total.

Table 7-13 – Requested Non-Network Capex – Baseline Cyber Security

Category 2021 2022 2023 2024 2025 Total (a) Enterprise Backup Enhancements 0.06 0.08 0.02 0.02 0.02 0.20 (b) Enterprise Refresh 0.38 0.38 0.38 0.38 0.38 1.90 (c) Firewalls 0.11 0.19 0.19 0.08 0.00 0.57 (d) Email and Web Protection 0.04 0.04 0.04 0.04 0.00 0.16 (e) Intrusion Prevention / Detection Systems

0.08 0.08 0.08 0.04 0.04 0.32

(f) Cyber Security Awareness Training 0.06 0.06 0.06 0.06 0.06 0.30 Summated Total (Above), € m 0.73 0.83 0.77 0.62 0.5 3.45 Requested TSO Total, € m 0.38 0.47 0.42 0.27 0.15 1.69

Commentary against the specific investment category line items included in Table 7-13, in particular the need for the investment and whether the costs appear reasonable is now provided.

1. Category (a) – EirGrid have made clear that this expenditure line item is related to existing systems only, and not the separate Cyber Security Initiative that they have also outlined as required. However, there also appears to be some overlap between this proposed capital expenditure the Review of IT Operating Model investment and also the Transition to Cloud initiative which will also provide a means by which to security enterprise wide back-up solutions. The narrative document provided by the TSO indicates as much, and also that EirGrid is investigating such solutions. Consequently, whilst we



agree that there is a need for investment in enterprise back-ups and enhancements it is unclear how much potential overlap there is between other BAU initiatives and whether there is any element of double counting as regards proposed costs.

Recommendation: Whilst the broad need is understood, EirGrid have not demonstrated that the proposed expenditure under this investment line item is not already included as part of other BAU initiatives. Additionally, the TSO has not demonstrated the potential interactions and relationship between the various security and cyber initiatives and how the costs have been determined and allocated, including that there is no overlap. As a result, it is recommended that 50% of the requested allowance is provided.

2. Category (b) to (f) – the need for the individual investments under each expenditure line item are understood i.e. asset replacements at five years, which is considered to conform to normal industry practice, hence the outlined works are accepted. The referenced costs are also largely based on current / existing cost estimates hence appear reasonable.


Initiative 6: Workplace Assets Reaching End of Life EirGrid proposed capital investment for PR5 for end of life workplace assets and redevelopment is:

Routine Building Plan Replacement: €1.03 m – for replacement of building HVAC systems, etc.

Workplace Redevelopment: €2.00 m – to redevelop other floors within the Oval (floors 1 and 4 have already been refurbished) including to free-up space from redundant servers.

Having reviewed the information provided by EirGrid it is evident that:

The routine building plan replacement expenditure is necessary to maintain compliance with the EirGrid lease. Additionally, the assets in questions will have been in service for nearly twenty years by the end of PR5 and are noted by EirGrid to reaching the end of their manufacturer recommended lifespan. On this basis, the requested allowance is accepted.

As regards the workplace refurbishment, the potential need to refurbish office space to make full usage of the space made available removing redundant servers is understood. However, the Oval has already undergone a €2.8 m capital expenditure refurbishment during PR4, the exact scope of which is unclear as is the need for a significant further refurbishment. We note the potential operating cost savings that are expected to arise though the combined effect of portfolio reduction and rent reviews giving a net operating cost saving of €0.1 m p.a. These operating cost savings will to some extent offset the capital costs incurred with the office refurbishment, however there are still outstanding questions related to the need for the works undertaken during PR4 and how the proposed similar PR5 works relate to this.

Recommendation: For the routine building equipment replacement it is recommended that requested allowance is allowed in full.

For the workplace refurbishment given the outstanding questions related to the PR4 expenditure it is recommended to provide an allowance of 50% of the requested value for PR5.

BAU Summary Following the above outlined review Table 7-14 presents the summary of the non-network capital expenditure requested by the TSO for PR5, including capital expenditure for replacing



end of life IT assets, transition to cloud hosting services, review of IT operating model, simplification and standardisation of IT systems, cyber security as well as workplace assets reaching end of life. Table 7-14 also shows the individual capital expenditure line items are recommended GHD allowance, including overall total.

Table 7-14 – Recommended Non-Network Capex

Category TSO Requested GHD Recommendation End of Life IT Assets (a) Telecoms Refresh 7.86 3.93 (b) Desktop Equipment Refresh 0.35 0.35 (c) VMware / Citrix Upgrades 0.16 0.16 (d) Server OS Upgrades 0.54 0.54 (e) Oracle Vault Refresh 0.08 0.08 (f) Data Centre Switching Upgrade 0.36 0.36 (g) Floor Access Switching Upgrade 0.36 0.36 (h) Wireless IS Upgrade 0.33 0.33 (i) Server & Storage Expansion 0.32 0.00 (j) Storage Area Networks (SANs) 0.83 0.83 (k) Oracle Database Refresh 0.34 0.34 (l) Dynamic AX Upgrade 0.76 0.00 (m) CSB Standing Data Automation 0.23 0.23 (n) Private Communication Network 0.15 0.15 (o) Data Centre Consolidation 0.09 0.00 (p) Replacement AV Equipment 0.16 0.16 (q) Additional Business Projects 1.62 0.00 (r) Office Upgrade Changes 0.40 0.40 (s) Guarantees of Origin Tender 0.23 0.00 (t) Website Tender Replacement 0.38 0.00 (u) Oracle Upgrade Application Changes 0.16 0.16 (v) Control Centre Equipment Refresh 0.25 0.13 (w) EMS Refresh 4.75 4.28 Summated (Requested) Total 20.71 (20.51) 12.79 Transition to Cloud 2.50 0.00 Review of IT Operating Model 0.8 0.00 Simplify and Standardise IT Solutions (a) Application Rationalisation 0.90 0.00 (b) Application Upgrades & Changes 1.20 0.00 (c) Remit / ENTSO-E Transparency 0.40 0.40 (d) MMS Environment 0.08 0.08 (e) Capacity Market Platform (CMP) 0.55 0.28 (f) Customer Relationship Management (CRM)

0.75 0.38

(g) Middleware Changes (OSB & GDX) 0.40 0.00 Summated (Requested)Total 4.28 (4.24) 1.14 Cyber Security (a) Enterprise Backup Enhancements 0.20 0.10 (b) Enterprise Refresh 1.90 1.90 (c) Firewalls 0.57 0.57 (d) Email and Web Protection 0.16 0.16



Category TSO Requested GHD Recommendation (e) Intrusion Prevention / Detection Systems 0.32 0.32 (f) Cyber Security Awareness Training 0.30 0.30 Summated (Requested)Total 3.45 (1.69) 3.35 Workplace Assets Reaching End of Life Routine Building Replacement Work 1.03 1.03 Workplace Redevelopment 2.00 1.00 Summated Total 3.03 2.03 PR5 Total BAU 32.77 19.31 Minus Deferred from PR4 -3.20 -3.20 Grand Total for PR5 29.57 16.11

From review of Table 7-14 and the overall totals, it is evident that, when accounting for the capital costs deferred from PR4, the GHD recommended PR5 allowance for business as usual non-network capital expenditure is €16.11 m, around €13.5 m less than the TSO request.

7.5.2 Sustainability & Decarbonisation Initiative Summary

As detailed in Section 7.5, as part of their PR5 submission the TSO has presented three new initiative groups with additional requested capital expenditure over and above their Business As Usual activities. This sub-section reviews the EirGrid proposal for the Sustainability and Decarbonisation initiative group, which broadly encompasses:

Establishing New Process & Tools (including these related to Renewable Strategy, Control Centre Tools and Outage Management and the Clean Energy Package)

Strengthen Data and Communication (including Digital Telecoms and Data Services)

Promoting Informed Choices (including Network Planning and Promoting Change)

The detailed individual expenditure items corresponding to the above are presented in Appendix B with a summary of the total requested capital costs presented in Table 7-15. This table also presents a summary of our assessment review, which aligns with the approached adopted for the operating costs assessment detailed in Section 7.2. In terms of specific application here the following explanation is provided in order to understand the recommended allowance for each category

Need – pass / fail assessment based on clear evidence being presented that demonstrates that the activity represents new or additional work not covered under the BAU initiative.

Additionality – has clear evidence / statements been provided to demonstrate that the costs associated with individual items are genuinely in addition to BAU work activities rather than simply being some work that can be done as an alternative to BAU works? A cost challenge of 25% is applied if we conclude that the licensee has not demonstrated additionality.

Cost Efficiency – has clear evidence been presented to demonstrate that alternative options have been considered, how the proposed costs presented are efficient, independent i.e. do not overlap with similar BAU works, and there is a clear demonstration of expected consumer value that will result from the expenditure. A cost challenge of 25% is applied in these cases where we conclude that the TSO has not demonstrated cost efficiency and consumer value of the step-change.

Interpreting the above, if a proposed expenditure has a clear and demonstrable need or reason for being included, can be demonstrated to be in addition or additive to, and not a replacement



for other BAU works, and sufficient evidence is presented to substantiate proposed costs, output value / metrics, then each category is rated Green and the full requested value is recommended to be included in nominal PR5 allowance. Where the Need is clearly demonstrated (rated Green) but either the Additionally criteria or Cost Efficient criteria has not been satisfied (rated Red) then 75% of the requested allowance is recommended, and where only the Need is demonstrated (both Additionallity and Cost Efficiency rated Red) then 50% of the requested allowance is recommended.

In cases where there are minor deviations / questions related to either Additionallity or Cost Efficiency, then these criteria are rated Amber and a 15% reduction in allowance is recommended (per criteria).

Table 7-15 – Sustainability & Decarbonisation PR5 Capex

Category Request Need Additionality Efficient Costs

Recommendation

Renewables Strategy DS3+ €12.0 m

€8.4 m

Control Centre Tools €4.4 m

€2.2 m Outage Management Systems €1.7 m

€0 m

Clean Energy Package €0.4 m

€0 m

IP Migration €2.9 m

€0 m Data Services €0.3 m

€0.15 m Capital Expenditure Total

€21.7 m - - - €10.75 m

Commentary in relation to the resultant criteria ratings shown in Table 7-15 is as follows:

DS3 – Need is understood and accepted, works are largely additive although some elements could be argued to be covered under BAU or other initiatives (EU-SysFlex), and whilst cost breakdown is provided the exact output scope has yet to be fully defined.

Control Centre Tools – Need understood, option detail and scope at early stage, some tools may be impacted by changes / upgrades to other systems i.e. EMS, therefore costs uncertain and potentially could change significantly. Deliverability within PR5 timeframe may also be challenging to introduce all of the proposed new tools.

Outage Management – Whilst the requirements for improved outage management is understood we are the view that such improvements would be expected to form part of ongoing business as usual efficiency improvements and work practices that the TSO is already funded for.

Clean Energy – The legislative requirements and obligations on the TSO are understood however these form the backdrop to the PR5 regulatory period and on which the main TSO PR5 business case and funding request should have been developed. Hence, we do not see that this is additive to the baseline Business As Usual activities during PR5.

IP Migration – As the existing non-IP telecommunications equipment is anticipated to be partially or entirely phased out over the PR5 period this work is considered to constitute a baseline work activity that should have been included in the main TSO PR5 business case and funding request. Hence, we do not see that this work is additive to the baseline Business As Usual activities during PR5 and hence the Need, as an incremental strategic initiative, has been rated red



Data Services – Broad need understood and the work is related to functions / tools that are in addition to current / normal functions. However, the work is essentially a scoping / review exercise and hence final costs, outputs and potential customer values are uncertain.

In addition to the above specific comments there are a number of broad issues that are apparent with respect to the individual requested expenditure items as currently presented. This includes proposed expenditure item costs, where EirGrid has attempted to justify how proposed costs have been determined. Whilst it is recognised that at such an early stage providing a detailed cost estimate is likely to be difficult in many cases, nonetheless the potential end costs that could be incurred through developing the full set of underlying initiatives could potential increase. Additionally, although some details of potential interactions between initiatives and business as usual activities has been provided by the TSO, no timeline or work delivery programme is presented for the detailed initiatives or the collective programme. Without visibility of when within PR5 the individual initiatives are expected to be undertaken and completed there is a potential risk that delays in delivering some within the early years of PR5 could have a significant knock-on impact on dependent initiatives. As a result, it is extremely unclear whether even if the need for the funding was accepted at the requested levels proposed by EirGrid, that the TSO could actually deliver all of these individual initiatives and underlying activities and outputs within the PR5 period.

7.5.3 Operate, Develop & Enhance Grid & Market Initiative Summary

As detailed in Section 7.5, as part of their PR5 submission the TSO has presented three new initiative groups with additional requested capital expenditure over and above their Business As Usual activities. This sub-section reviews the EirGrid proposal for the Operate, Develop & Enhance Grid & Market initiative group, which broadly encompasses:

Developing New Processes & Tools – including those related to access planning and connection management, developing a metering system, a mixed integer planning solver,

Improving System and Market Standards and Practises – including those related to European network codes, capacity market secondary trading, DSU compliance with state aid, the electricity balancing guideline, and multi-NEMO arrangements in the SEM,

Improving Support Systems and Security – including physical security, cyber security, operational IT support and control centre training.

The detailed individual expenditure items corresponding to the above are summarised in Appendix C with a summary of the total requested capital costs presented in Table 7-16. This tables also presents a summary of our assessment review, with the methodology and rating criteria following that outlined for the Sustainability & Decarbonisation Initiative presented in Section 7.5.2.

Table 7-16 – Operate, Develop, Enhance Grid & Market Initiative PR5 Capex


Recommendation

Control Centre Training €2.9 m

€1.45 m Physical Security €1.7 m

€1.7 m Cyber Security €0.5 m

€0.43 m Capacity Market Secondary Trading

€1.5 m

€1.12 m

DSU Compliance €2.8 m

€2.1 m MIP Solver €0.9 m

€0.68 m




Recommendation

State Aid Cross Border Capacity

€0.8 m

€0 m

Metering Systems €3.0 m

€1.8 m Electricity Balancing Guideline (EBGL)

€26.5 m - - - -

Multi-NEMO Arrangements in the SEM

€10.5 m - - - -

Capital Expenditure Total

€13.8 (€50.8)* m

- - - €9.28 m

* Including costs for EBGL and Multi-NEMO in SEM Commentary in relation to the resultant criteria ratings shown in Table 7-15 is as follows:

Control Centre Training – as with control centre tools, the need for control centre training is understood however the proposal is also at an early stage of development and some elements could also be argued should be covered under BAU or other initiatives. As a result there is clearly some question mark over exactly what outputs, and associated efficient costs, will be delivered over PR5.

Physical Security – the need for this investment is driven by legal and statutory requirements and the capital costs have been split into twelve individual items and associated costs benchmarked by external inputs / market testing.

Cyber Security – EirGrid already have included a Cyber Security investment initiative within BAU. They have however confirmed that this initiative here, which relates primarily to operating costs for subscription services currently under procurement, does not overlap with BAU activities. As quoted costs are based on existing supplier provided information and external verification they appear to have undergone internal review and challenge however the exact hardware / capital assets to be purchased remains unclear.

Capacity Market Secondary Trading – the need for secondary capacity market trading is understood however based on the EirGrid provided data the specific design options and working have yet to be determined. As a result, whether the associated costs are clearly additional, i.e. not something that would be expected to be cover under BAU, the full extent of the work and prospective outputs is clearly subject to revision and change over the course of PR5.

DSU Compliance – need understood and linked to known market issues associated with DSU and state aid compliance decision. However, there is clearly significant work to do to define and specify the systems needed for calculating and monitoring DSU metered quantifies and comparing with reference profiles which may take some time to implement. Therefore, whilst need and additionality are satisfied the potential costs could vary significant over PR5, particularly if the work takes longer than expected to be delivered and runs into PR6.

MIP Solver – as with other market tools and functions the need is understood and the proposed tool is clearly additional. However, given the time take to implement the proposed solution, noted by the TSO, and the early stage of the initial proposals it is unclear exactly what will be delivered, when and how the current proposed costs can be demonstrated as efficient.

State Aid Cross Border Capacity – the broad requirement for this investment is understood however it is not currently clear how and when the fully State Aid



requirements will mandate this, particularly after Brexit. Additionally, the current TSO proposal is largely a placeholder to secure funding later within the PR5 period and that or may not be required, and the costs and outputs of any such work cannot be sufficient detailed at this time.

Metering Systems – The potential need for additional metering systems and interfaces is understood however currently there are a number of different options that could be adopted, and the associated and costs and technical benefits of each have not been provided. It is also not clear whether some elements of the metering costs would be expected to be covered under BAU activities and, additionally, of the requested capital expenditure (€3.0 m) €1.8 m is listed as “Other” where it is no details is provided as to what this includes.

Additional commentary is also provided with respect to two specific high cost items as follows:

Electricity Balancing Guideline – this came into force in December 2017 and will require Ireland (and through the TSO) to access service provision for system balancing from a wider market area than just their own immediate area. The Balancing Platforms will be set-up within a central platform to which TSO’s submit their needs for balancing energy. The potential capital and operating costs associated with the required tools and platforms are significant i.e. joining fee costs of €19.5 m (within the €26.5 m outlined in Table 7-16). EirGrid have themselves proposed that given the significant uncertainties surrounding the exact need, scope and implementation costs that this item is subject to a re-opener during PR5 when more details are fully known. Given the potential scale of the costs involved GHD concurs with this approach.

Multi-Nemo Arrangements – a guideline for cross-zonal capacity and congestion management (CACM) entered force on August 2015 through which cross-border traded power flows are instructed based on price differentials between European markets, with designated Nominated Electricity Market Operators (NEMO) designated in individual countries. Multi-NEMO arrangements are allowed in the same jurisdictions to prevent monopoly behaviour. Whilst multi-NEMO approaches can be integrated within the I-SEM there are a number of different design options, with potentially different timelines, dependencies and costs (a provisional sum of €11.9 m is included by EirGrid) in their submission. Again, EirGrid themselves have highlighted the significant uncertainties surrounding the exact scope, timing and implementation costs and further recommended that this item is subject to a re-opener during PR5 when more details are fully known. Given the potential scale of the costs involved GHD concurs with this approach.

7.5.4 Engage for Better Outcomes Initiative Summary

As detailed in Section 7.5, as part of their PR5 submission the TSO has presented three new initiative groups with additional requested capital expenditure over and above their Business As Usual activities. This sub-section reviews the EirGrid proposal for the Engage for Better Outcomes initiative group, which broadly encompasses:

Education & Engagement

Enhanced Customer Journey

Developing The Grid Framework

The detailed individual expenditure items corresponding to the above are summarised in Appendix D, with a summary of the total requested capital costs presented in Table 7-17. This tables also presents a summary of our assessment review, with the methodology and rating



criteria following that outlined for the other two initiative groups presented in Section 7.5.2 and 7.5.3.

Note that the Education & Engagement and Enhanced Customer Journey have only operating costs and hence are not included in this section.

Table 7-17 – Requested Engage for Better Outcomes Initiative PR5 Capex


Recommendation

Developing the Grid Framework

€3.7 m

€0.0 m

Capital Expenditure Total

€3.7 m - - - €0.0 m

In relation to the resultant criteria ratings shown in Table 7-17 for the Developing the Grid Framework, reviewing the supporting information provided by EirGrid for this initiative we agree with the TSO that there is a need for ongoing and continued engagement with stakeholders, customers and members of the public in relation to current, proposed and future network development plans and associated activities. This engagement through PR5 may also require potential revisions to existing information disaggregation methods and channels, application processes and engagement platforms in order to keep relevant customers and stakeholders suitably informed. However, whilst we accept there is a broad need for some investment during PR5 in this area the current proposed plans by the TSO are still not sufficiently developed to the point where there is a clearly defined need and robustly demonstrated investment option with a quantifiable set of defined expected outputs. On this basis it is recommended that a zero allowance is provided and that EirGrid submits a detailed business case through the Monitoring Committee at a time when the specific need, scope of work, prospective outputs, costs and benefits can be fully quantified and demonstrated.

7.5.5 Strategic Initiative Monitoring Committee & Recommendations

As part of the strategic initiative proposals put forward by the TSO they have suggested that many of the individual expenditure items detailed under each of the three initiatives are subject to review by a proposed Monitoring Committee. This has been proposed by EirGrid in order to review individual projects that have a high degree of uncertainty around need, scope, costs or outputs, with a view to providing a mechanism to challenge and review and ultimately allow justifiable individual projects to progress and costs to be recovered. In principal, GHD agrees with the broad proposal made by the TSO as part of their PR5 submission with respect to the monitoring committee, although clearly the specific details of how the committee works and operates will need to be developed before the commencement of PR5. Some specific considerations include:

The TSO has as part of their submission paper detailed the broad issues and benefits / limitations of both ex-ante and ex-post style regulatory reviews, and has detailed the potential challenges in remaining with a heavily ex-ante based approach during PR5. Whilst we agree with many of the limitations and issues outlined in the TSO paper, we are of the view that it remains in the interest of the CRU (and therein on behalf of network customers) to retain the ability to conduct a retrospective review at the end of PR5 to determine if the outturn costs and benefits delivered by individual investment projects progressed through the Monitoring Committee process actually delivered value to end customers.

With respect to funding the innovation and strategic initiatives outlined by the TSO in their PR5 submission, GHD has reviewed the current proposals and information provided by



the TSO for each group of initiatives. For the majority a recommendation has been provided in terms of a PR5 allowance, either as a proportion of or the full amount requested by the TSO. However, for some other initiatives fundamental questions still exist with regards to the need for the investment or the potential overlap between the other strategic initiatives or BAU expenditures, hence a zero allowance is recommended. For these cases we would expect that EirGrid would be able to make a submission to the Monitoring Committee when sufficient information exists to develop a suitably robust business case, including detailing with sufficient accuracy expected costs, benefits and outputs. The Monitoring Committee would also serve as a mechanism by which to progress further strategic initiatives that have not been submitted as part of this PR5 forecast review, but which are considered to generate sufficient benefits to end customers that they warrant funding during PR5.

Given the nature of the types of projects that make up the strategic initiatives presented by the TSO in their PR5 submission, and further may be proposed during PR5, it is likely that the optimal option that provides best value for each investment item will undoubtedly include a mix of capital and operating costs, or potentially one cost group of the other. The current TSO PR5 proposal already demonstrates this. As such, GHD is of the view that although notional individual capital and operating cost values have been identified for each individual initiative, it is assumed that these values would be inter-changeable to some degree by the TSO within the agreed total value to allow further refinement and optimisation of each proposed solution closer to actual delivery. The alternative is that the TSO has to operate within the fixed capital and operating cost allowances identified here for the strategic initiatives, regardless of whether future work requirements, investment decisions and wider considerations suggest that a change of solution design or scope may actually provide additional benefits but would mean that one allowance element (capex or opex) exceeded the notional allowance.

Any capital (and operating) expenditure that is agreed through the Monitoring Committee cost recovery path should be ring fenced, particularly staff operating costs which have the potential to be relatively short-term in nature for some of the strategic initiative activities. This will ensure that such initiatives do not form part of or otherwise cross-fund activities already included in within business as usual expenditure.

7.5.6 Non-Network Summary & Recommendations

BAU Conclusions The Business as Usual Non-Network Capital Expenditure submission for PR5 was primarily focussed on the maintenance, renewal and upgrade of existing IT systems and assets within the business, along with expenditure on physical assets including office space. The Business As Usual case was set out into six different categories, of which the main conclusions are set out below.

IT Assets Reaching End of Life – The majority of line items within this category represent justifiable expenditure on replacing aging assets as a normal part of business operations. GHD have recommended that where insufficient detail has been put forward for analysis to determine whether an allowance is appropriate, i.e. for the refresh of telecoms equipment, more detail should be provided. In the event that no additional details can be provided, GHD has recommended that allowances be reduced for these individual line items. GHD has also recommended that several of the more speculative items requested in this category have their allowances removed, due to the technology required likely to be superseded by other initiatives (Dynamic AX upgrade) or a lack of sufficient detail in plans provided to implement the item (Website Tender Replacement). GHD have also



reviewed industry best practices to determine where allowances are excessive compared to requirements (EMS refresh).

Transition to Cloud – This initiative corresponds to the cost of the ongoing migration of TSO data and services to cloud based services and away from locally owned and maintained servers, which the TSO has outlined will result in a net saving to the business. Having reviewed the proposed costs this initiative investment appears broadly self-funding, i.e. operating costs savings of €1.2 m p.a. should off self the requested capital and operating costs within the PR5 period. As a result, it is recommended that the requested funding is disallowed due to the self-funding nature of the works.

Review of IT Operating Model – The proposal for a review of the TSO IT operating model and its associated business case has identified that the proposed plans are at a very early stage of development. No breakdown of costs has been provided, or explanation for how the current costs were established. It is also unclear what is included, or excluded from the scope. Additionally, if the initiative is expected to yield efficiency savings as the TSO claims then it is expected that the TSO would fund this initiative through baseline expenditure and hence no separate allowance should be needed during PR5.

Simplify and Standardise IT Solutions – Some of the line items included in this initiative have been disallowed due to insufficient detail provided to explain why the associated funding was requested i.e. Application Rationalisation, or where it was unclear whether expenditure would be covered in other categories regardless i.e. Application Upgrades and Changes. Where clear drivers and sufficient detail exists for line items the full allowance requested has been allowed, but other allowances have been reduced where timing or responsibilities are unclear, for example when responsibility is split between SONI and EirGrid and associated costs to each are uncertain.

Cyber Security – The TSO have specified that the requested expenditure for this category does not specifically overlap with the separate “cyber security” strategic initiative. However, some of the scope defined does appear to overlap with other initiatives proposed including the “Review of IT Operating Model”. GHD have therefore recommended that spend on individual line item A be reduced where there appears to be overlap. On the other line items regarding more specific programs the full expenditure has been allowed.

Workplace Assets Reaching End of Life – The TSO have provided details of non-IT assets requiring replacement, including a building plan replacement required to maintain compliance with EirGrid’s lease, which has been accepted. Refurbishment works required to make better use of existing space have also been accepted at a reduced (50%) allowance compared to the PR5 request. This is because the TSO has also incurred expenditure in PR4 for similar office refurbishments and has not fully demonstrated the need for the PR4 investment hence it is unclear how the proposed PR5 investment relates to the works already undertaken.

The overall figure GHD have allowed for the business as usual PR5 non-network capex business as usual case is significantly (€15.36 m) less than the TSO request – as shown below in Table 7-18.



Table 7-18 – Recommended Non-Network Capex

Category TSO Request GHD Recommendation End of Life IT Assets – BAU 20.51 12.79 Transition to Cloud – BAU 2.50 0.00 Review of IT Operating Model – BAU 0.8 0.00 Simplify and Standardise IT Solutions – BAU 4.24 1.14

Cyber Security – BAU 3.45 (1.69) 3.35 Workplace Assets Reaching End of Life - BAU 3.03 2.03

PR5 Total 32.77 19.31 Minus Deferred from PR4 -3.20 -3.20 Grand Total for PR5 29.57 16.11

Strategic Initiative Conclusions Reviewing the individual expenditure line items summarised in Table 7-15 to Table 7-17 as well as the supporting information provided by the TSO as part of their PR5 submission, it is evident that there are a variety of potential research and innovation areas that may require funding in PR5. In addition to this, some of the requested funding to undertake work to improve operational processes, comply with additional European legislation and improve customer and stakeholder relations may be necessary.

However, whilst we agree that revision of existing tools, process and systems is likely to be necessary, the individual investment line items presented in these tables appear as something of a wish-list for future expenditure and in all cases do not have clearly defined project delivery outputs or other measures which could reasonably be set now and against which TSO output performance could be measured at the end of PR5. Some of the issues noted with the detail in the submissions are as follows:

Treatment of “professional fees” appears ill defined, and they are treated interchangeably as both capital and operating costs, depending on the specific initiative. Examples include Metering Systems within the Operate, Develop and Enhance Grid and Market initiative group where Professional Fees are listed as capital expenditure and under Cyber Security within the same initiative group where they are listed as operating expenditure.

Many initiatives overlap in potential scope with other proposed initiatives or projects, both between strategic initiatives and within the Business As Usual case. An example of this occurring is cyber security which has expenditure requested under the Sustainability and Decarbonisation Initiative, which appears to overlap in scope with the non-network Business as Usual Case. EirGrid have stated that there is no overlap between the two initiatives, but without a defined scope and a clear means of differentiation between outputs between the two items, it is difficult to be absolutely certain of this.

Many initiatives rely on the successful implementation of others in order to be implemented themselves. These inter-dependencies have not been identified by the TSO and as such there is a risk that a delay in implementing a number of the key initiatives would result in others being deferred such that part or all of the proposed expenditure does not actually occur in PR5. In other cases the expected work associated within individual initiatives is not scheduled to occur until the later years of PR5. Consequently any delay in delivery in early years is likely to push some of the initiative start (and completion) into PR6, resulting in a lower capital spend than requested for PR5.



Some initiatives do not have expenditure broken into individual categories. While it is appreciated that at this stage the TSO does not currently feel able to provide this level of detail for all of the initiatives under consideration, it also leaves relatively little information to judge if the projected allowances for expenditure are appropriate.

Overall though, we recognise the effort and attempts by the TSO to provide as much clarity as possible as regards the potential areas where future capital expenditure in these predominantly research led activities are concerned. As such, we have reviewed the specific supporting information provided by the TSO and have provided our recommendations with respect to capital expenditure funding allowances for PR5. In some cases the requested capital expenditure is recommended to be allowed in full, in other cases a partial allowance is recommended based on the current development status of the EirGrid proposals, and in a number of cases no allowance is recommended. The summated capital expenditure value of the three strategic initiative groups (€20.03 m) is recommended to be added to the TSO’s capital expenditure allowance for PR5, with any additional funding being required over and above this value being progressed through the Monitoring Committee pathway where it can be subject to review and challenge before progressing. This can be the case for any further strategic initiatives that may arise during PR5 but which have not been considered or included in this current PR5 submission review. The details of the Monitoring Committee working mechanism will need to be refined and agreed prior to the start of the PR5 period.

For the two large capital cost items included under the Operate, Enhance, Develop Grid & Market Initiative (EBGL and Multi-NEMO), we agreed with the TSO that these are of sufficient scale such that they should be subject to a re-opener or further funding request to CRU once they have progressed sufficiently such that there is a clear and demonstrable need for investment, supported by a robust business case.

7.6 Summary and Conclusions

This document has reviewed the forecast capital expenditure over the PR5 period 2021 to 2025 for the Transmission System Operator in Ireland, EirGrid. The review has included comparisons with previous price control periods, particularly PR4, and has focussed on the following areas:

Network development scenarios

TSO capitalised expenditure trends and ongoing projects from the PR4 period

Network needs, new network reinforcements and associated new technologies

Non-network expenditure needs

In relation to the proposed network development scenarios, the TSO presented three scenarios, based on low risk “Business as Usual” operation, a factored “Embracing Change” scenario aimed at facilitating renewable generation and meeting network needs, and an unfactored “Unconstrained” scenario with significantly higher spending on planned projects throughout the PR5 period. After reviewing each of the proposed scenario’s GHD have determined that the “Embracing Change” scenario is appropriate for the PR5 period, given the need for EirGrid to facilitate renewable generation connections to allow Ireland to meet climate change targets, and in order to meet a forecasted growth in system demand, which represents a potentially more significant driver than in previous price control periods where electricity demand has remained relatively flat. The recommendations on deviations from forecast PR5 capital expenditure in this report have therefore been made with regards to Scenario 1. The recommended amendments are:

GHD recommends that the allowance for generic “DSO Pipeline Projects” be reduced to bring total allowance in the category of DSO Projects to €12 m. This would give the proposed “DSO Pipeline Projects” a total allowance of circa €7.37 m over PR5, while



leaving spending on the other two specified projects within in the DSO Projects category as forecast.

GHD recommends that the allowance for the “RIDP” Project is removed, due to the current status of the project which is under review and currently on hold. If the need for the project re-materialises during PR5 then it can be progressed in a similar manner to any new projects identified during the PR5 period that were not originally included in the Scenario 1 project list.

The TSO forecast capital expenditure file provided to GHD contained an allowance for the Dunstown 400 kV Series Compensation project of €37.06 m in Scenario 1. This was flagged as excessive and considered to be an error after determining that the unconstrained Scenario 3 had a smaller allowance for the project as did several other series compensation projects expected to be progressed over the same period. After review and clarification from the TSO GHD determined that the TAO allowance for the project in Scenario 1 was also different (€6.8 m PR5 total, TSO €0.51 m), but was considered to be the more appropriate value to include in Scenario 1 given further outstanding questions relating to the Scenario 1 and 3 capital expenditure values for this and other related series compensation projects.

The changes made to the Scenario 1 forecast expenditure represent a reduction in TSO network expenditure over the PR5 period of ~€12.7 m compared with the original Scenario 1 TSO forecast.

With regards to the non-network capex forecast, GHD conducted a full review of the Business as Usual case submission, as well as the three “strategic initiatives” set out by EirGrid as part of their transformation program. EirGrid included the Business As Usual case for normal non-network spending, which set out its program for IT hardware and systems replacement, renewal and redesign, and office refurbishment. EirGrid also included funding for additional strategic initiatives to improve operations, to assist in implementing European level legislation, and for marketing purposes. The main conclusions from the review of the non-network capex are as detailed below.

The “Business as Usual” case is broadly appropriate for EirGrid’s normal day to day operations of business, however some refurbishments and claims are insufficiently supported, or appear to be ahead of need. For example telecoms refurbishment, while justifiable in general terms, is not fully supported with a list of equipment required to be replaced, and the expected office refurbishment costs have not been fully supported, particularly so given significant forecasted expenditure for such work undertaken in PR4. As a result of these and other unsupported cost items GHD is of the view that the proposed PR5 non-network BAU capital expenditure has not been fully justified, and hence our recommended allowance is significantly lower than requested at a net value of €16.11 m (a reduction of €13.46 m).

For the strategic initiatives, GHD recognises that many of the aims pursued by individual initiatives have merit and value in funding. However, the strategic initiatives included many diffuse aims, with a broad and sometimes uncertain scope, and in some cases lacked specific project delivery outputs or targets to determine whether individual activity funding can be demonstrated as efficient, justified and of benefit to end customers. There is also uncertainty about the potential overlap with the existing Business As Usual case or between individual strategic initiatives, including whether the outlined expenditure item values are appropriate for individual initiatives, and whether EirGrid is capable of completing and implementing all initiatives within the PR5 period.

As a result of this, GHD has provided individual strategic initiative recommended allowances following a staged review process focussing on the need for investment, whether it is additive to



the Business As Usual case, and where the proposed costs are sufficient detailed and can be demonstrated as efficient. Following this line by line review we have determined an overall PR5 capital expenditure allowance for non-network expenditure. Additionally, we also agree in general terms with the proposed Monitoring Committee to review and progress further innovation and strategic projects during PR5, subject to a number of caveats outlined related to the development of the process pathway.

The final recommended allowable PR5 capital expenditure for the TSO is shown in Table 7-19.

Table 7-19: Forecast Total TSO PR5 Capital Expenditure – GHD Recommendation

2021 2022 2023 2024 2025

PR5 Total (€ m)

Network Capital Expenditure 19.22 18.82 13.94 9.66 6.68 68.32 Non-Network BAU Capex (Gross) 4.05 4.54 3.87 3.55 3.30 19.31 Non-Network Capex (PR4 Deferred) -0.64 -0.64 -0.64 -0.64 -0.64 -3.20

(1) Sustainability & Decarbonisation 1.84 2.43 2.71 2.78 0.99 10.75 (2) Operate, Develop Grid & Market 2.37 2.95 2.46 0.78 0.73 9.28 (3) Engage for Better Outcomes for All 0.00 0.00 0.00 0.00 0.00 0.00

Non-Network Capital Expenditure Total 7.62 9.28 8.39 6.47 4.38 36.14

Overall PR5 Total Capital Expenditure 26.84 28.10 22.33 16.13 11.06 104.46



8. Review of PR5 Operating Expenditure: Transmission Asset Operator 8.1 Introduction

The objective of the CRU in setting allowed opex is to ensure that the TAO can deliver the outputs that are required by customers while challenging the licensee to perform at an efficient level. This should result in setting the TAO challenging but realistic targets and incentives. In this section of the report, we review the TAO’s proposed opex for PR5 and develop independent proposals for an appropriate opex allowance for the period from 2021 to 2025.

It is important to note that our assessment is based on the submission by the TAO dated 12th December 2019 and the accompanying narrative. We have not reflected a subsequent partial resubmission of the business plan for PR5 made on the 5th February 2020, as the TAO has not fully explained how this change aligns with the narrative.64

Unless stated otherwise, our review has prices expressed in real 2019 price levels65. The conversion to these price levels was based on the inflation factors presented in Table 8-1 below.


2019 2020 2021 2022 2023 2024 2025

HICP Adjustment Factor

1.000 0.989 0.975 0.962 0.949 0.936 0.923

Source: ec.europa.eu/Eurostat/data/database. Dataset: prc_hicp_midx. Accessed: 13/01/2020 Central Bank of Ireland (2019), Q4 Bulletin. ‘Deal’ Brexit Scenario. Accessed: 14/01/2020

The remainder of this section is structured as follows:

In Section 8.2 we compare the opex that the TAO has requested for PR5 against PR4 outturn.

In Section 8.3 we outline the analytical approach that we have taken to develop our recommended PR5 opex recommendations.

In Section 8.4 we provide a detailed assessment of PR5 opex by cost category.

In Section 8.5 we summarise our recommendation of efficient opex for PR5, and compare this against the TAO’s request.

8.2 Overview of the TAO’s proposal

The opex requested by the TAO for PR5 is presented in Table 8-2. The TAO requested €328.3 million in total opex for PR5 compared with an outturn of €322.2 million in PR4. This is equivalent to an increase of €6.1 million (2%). This increase is mainly due to a €39.0 million (32%) forecast increase in rates, which are treated as pass-through costs. For controllable

64 Our overall approach has been to accept the changes made in this submission to PR4 costs and outputs on the basis that these changes reflect forecast error only. We have not reflected any changes to PR5 costs and outputs as the TAO has not explained how these changes aligns with its narrative. 65 The 2019 HICP index value was provisional at the time of writing this report and will be updated ahead of the final determination.



opex, the TAO forecasts a €14.0 (7%) fall between PR4 and PR5. This is mainly due to a €10.8 million drop in forecast professional fees.66

The TAO also forecasts 0.9% in ongoing productivity gains, which amounts to -€8.4 million during PR5 (i.e. the total controllable opex request is €151.9 million over PR5).

Table 8-2 – Requested PR5 Opex Allowance (excluding RPEs and ongoing efficiency)

TAO Opex (€m 2019 prices) PR4 PR5 Variation

Outturn Requested PR5 – PR4 %

Controllable Opex

Planned maintenance 89.5 94.3 4.8 5%

Unplanned maintenance 11.1 6.4 -4.7 -42%

Operations 12.8 10.0 -2.8 -22%

Asset management 4.3 2.5 -1.8 -42%

Professional fees 23.7 12.9 -10.8 -46%

Telecoms opex 7.6 9.3 1.7 22%

Corporate overheads 18.6 18.2 -0.4 -2%

Insurance 2.9 3.4 0.5 17%

Legal 1.8 1.1 -0.7 -37%

Pensions admin 2.0 2.2 0.2 11%

Total Controllable Opex 174.3 160.3 -14.0 -8%

Non-controllable

Rates 123.4 162.4 39.0 32%

CRU Levy 5.6 5.6 0.1 1%

Total Non-Controllable Opex 129.0 168.0 39.0 30%

Total Opex 303.3 328.3 25.0 8% Source: ESB Networks

The TAO’s requested controllable opex for PR5 is discussed in more detail in the following sub-sections. We do not assess non-controllable opex, as these costs are treated as a pass-through.

8.3 Base-Trend-Step Methodology

This section of the report sets out the cost assessment methodology we have applied to estimate the efficient controllable opex for PR5. Our approach is based on a well-established and transparent methodology that accounts for the specific challenges of assessing the efficient costs of Ireland’s electricity networks. Specifically:

The TAO does not have any direct domestic comparators against which its costs could be benchmarked. International benchmarking options are available, but differences in companies’ operating environments and outputs means that the results of such an exercise can be difficult to translate directly to a cost allowance.

66 The other key difference between the PR5 forecast of controllable opex and PR4 outturn is the ‘miscellaneous and other’ category, for which the TAO has not made a forecast for PR5. In PR4 this category reflected changes in accounting treatment (see our assessment of PR4 opex).



The separation of responsibilities between the TSO and TAO is relatively unique by international standards.67 Great Britain does have transmission asset owners that are separate from the system operator (this distinction was strengthened in April 2019 when the electricity system operator was established as an independent entity within the National Grid group). However, there are likely to be some challenges in mapping of costs between the GB and Irish entities on a like-for-like basis (e.g. the TAO also operates the 110 kV network in Ireland but in GB this is part of the distribution system, and GB transmission network operators have typically had greater responsibility for the design of their networks than the TAO).

Based on the above, we consider that a top-down benchmarking approach would be difficult to implement at present and could give misleading results. As a result, we have set out an approach that builds upon the bottom-up assessment that was taken in PR4.68 For costs in each activity area (e.g. planned maintenance), we have applied an analytical approach that is commonly known as base-trend-step.69 As the name suggests, the approach consists of three analytical steps:

identifying an efficient base level of opex that forms the starting point for future costs;

projecting a forward trend in costs based on cost drivers and other assumptions; and

Identifying any step changes to scope that would result in changes to costs (positive or negative) that are additional to the trend.

Each of these steps is discussed further in the subsections which follow.

A key strength of the base-trend-step approach is that it makes it very clear what customers would be funding in terms of new outputs and deliverables above business-as-usual costs. Taken together with our assessment of ongoing efficiency and real price effects (RPEs),70 this approach gives us the greatest confidence that our recommendations set challenging but achievable opex allowances for the TAO, and that they do so transparently.

8.3.1 Step 1: Approach to setting the TAO PR5 baseline

This step establishes an efficient starting point for the PR5 opex allowance. Establishing an efficient cost baseline is important to ensure that outturn inefficiencies or forecasting uncertainties for the latter years of PR4 are not implicitly rolled over into the PR5 control period.

Our preferred approach is to set the baseline using opex incurred in 2018, as this is the last year of outturn data we have for all three licensees. This is in line with the long-established regulatory approach of setting future allowances on the basis of the latest available evidence on actual costs. As such, it is important to establish that outturn opex for 2018 is efficient and suitable for use as a baseline. We do this by assessing whether costs reported in 2018 should be adjusted for atypical costs (i.e. incremental costs that are not expected to continue) and/or inefficiency. For cost categories that exhibit considerable volatility over PR4, our default approach is to set the baseline equal to the average cost over PR4 and then test whether further adjustments should be made to set an efficiency challenge.

67 This arrangement exists in Northern Ireland, where the TSO and TAO are also owned by the EirGrid and ESB groups, respectively 68 We note that ESB Network’s consultants have included costs related to the TAO’s 110kV network in benchmarking the DSO against GB distribution network operators. We discuss this further in the distribution report. 69 For example, the approach is used by the Australian Energy Regulator in its regulatory cost assessments. See: AER, Expenditure forecast assessment guideline for electricity distribution and AER, Expenditure forecast assessment guideline for electricity transmission. 70 CEPA, Real Price Effects and Ongoing Efficiency Improvements for PR5 – report for the CRU



Our assessment in setting the PR5 baseline is informed by on our ex-post review of the TAO’s opex over PR4 (see Section 4). However, there are important differences between the ex-post assessment and setting the baseline – the latter excludes atypical and one-off costs that may be allowed as part of the ex-post review. For example, an increase in opex in 2018 due to an atypical or one-off cost may not necessarily represent inefficiency. However, if this increase is not expected to continue over PR5 then for the purposes of setting the baseline this cost increase should be excluded. This question is considered on a case-by-case basis for each cost area.

8.3.2 Step 2: Applying a trend projection

After setting the baseline, we forecast how efficient costs may evolve over PR5 (up to and including 2025).

Our projection of costs across PR5 is based on the identification of relevant cost drivers for each cost area, as relevant. For example, we have identified transmission network length and customer numbers as relevant cost drivers for TAO costs across PR5. Projections for the cost drivers are informed by the TAO and TSO’s submissions, and our assessment of economic and engineering factors.

t is important to note that our trend projection for individual cost categories excludes any RPEs or ongoing efficiency. Our approach to RPEs and ongoing productivity for all three licensees is presented in a separate paper.71

8.3.3 Step 3: Identifying “step changes” in scope

The final step in our approach is to identify whether there are any changes in the outputs the TAO is expected to deliver in PR5 that are not captured by the trends projected in the previous step. In general, step-changes will account for new initiatives and requirements faced by the TAO during PR5. For example, a one-off change in regulatory scope may increase or decrease opex. Similarly, the decision to switch from funding a network activity through an opex solution rather than a capex solution could be accounted for in a step change. Step changes can be positive (i.e. increase efficient opex) or negative (i.e. reduce efficient opex).

This step in our approach is based on our evaluation of the TAO’s business plan against the following criteria / gateways:

Need – is there clear evidence that there is expected to be a change in the activities or costs incurred by the TAO? Have the aims and objectives of the step-change been set out? Has it been clearly aligned to the strategic objectives the CRU has set out for PR5?72 We apply a pass / fail criterion to this gateway.

Mapping to the business plan questionnaire (BPQ) submission – has the TAO clearly mapped the step-change to its BPQ? We apply a pass / fail criterion to this gateway.

Additionality – has it been clearly demonstrated that the costs associated with the proposed step-change are additional relative to the base level of opex? This question is not equivalent to asking whether the initiative / project is new or unique. For example, a brand-new IT application could replace an existing application in such a way that there is no additional cost to the consumer. Therefore, we assess whether the licensee has

71 CEPA, Real Price Effects and Ongoing Efficiency Improvements for PR5 – report for the CRU 72 Note that step-changes do not necessarily have to be linked to the CRU’s strategic objectives – they could be the result of other external factors or initiated by the TAO. Likewise, a step-change could be linked to the PR5 strategic objectives but still be challenged on additionality and efficiency grounds.



demonstrated that existing resources are fully exhausted / utilised and additional resources are required to deliver the proposed step-change / initiative. A cost challenge of up to 25 percent is applied if we conclude that the TAO has not demonstrated additionality.

Cost efficiency and customer value – has it been clearly demonstrated that the costs associated with the step-change are efficient? Have other options been explored that could achieve the same outcome? What metrics have been used to test that the requested costs are efficient? Has the TAO provided evidence that costs have been market-tested or benchmarked? Is there a clear demonstration of customer value associated with the outcomes of the step-change? Was a range of options considered? A qualitative judgement is required in cases where there is a lack of benchmarking data available to assess cost efficiency – for example, if the activity has not been delivered by the licensee before and/or comparators are not available. A cost challenge of up to 25 percent is applied in these cases where we conclude that the TAO has not demonstrated cost efficiency and customer value of the step-change.

The first two gateways are pass / fail. This means that if we do not consider that the need for a step-change has been clearly set out, or if the TAO has not clearly mapped the step-change to the BPQ, our recommendations is that the step change is not included in the allowance the CRU sets. The latter two gateways can have a partial pass, with up to a 25 percent cost challenge applied at each gateway (meaning a maximum cumulative efficiency challenge of 50 percent challenge on any step-change that passes the first two gateways).

Deciding the level of the cost challenge that should be applied for additionality and/or efficiency is inherently a judgement call. That judgement is necessarily informed by the information provided (or not provided) by the TAO. In addition to the specific types of evidence listed above, we have based that judgement on general considerations such as:

The completeness, clarity and consistency of the supporting information provided for the proposed step-change.

The level of detail provided to support the cost forecast for the step-change (relative to the monetary level of the step-change).

Whether the TAO has demonstrated that the costs of the proposed step-change are proportionate to the customer benefit.

It is important recognise that in the context of a price review, the obligation is on the TAO to demonstrate the need, additionality and efficient level of forecast step changes in expenditure.

The adjustments we make in the final two gateways, however, should also not be viewed purely as an efficiency challenge. Rather than a binary pass-fail system for these gateways, the adjustments we have applied are intended to signal to the TAO during the PR5 consultation process the step changes where it has demonstrated the need for expenditure in its BPQ, but where further information and evidence is needed to establish the additional level of funded expenditure above the baseline. This means that where sufficient evidence and information can be provided by the TAO as part of its response to the PR5 consultation, we may revisit the adjustments we have made in these two final gateways.

We also envisage that all step changes will be linked to price control deliverables - we explore this further in a separate stand-alone paper on the regulatory framework.73




8.4 Base-Trend-Step Opex Analysis

This section of the report outlines the proposed PR5 (2021 to 2025) opex for the TAO and forms a judgement on the efficiency of this request using the base-trend-step evaluation approach as set out in Section 8.3 of this report.

8.4.1 Planned maintenance

(TAO requested €94.3 million; recommended allowance €93.6 million).

Planned maintenance relates to: Preventive/routine maintenance. The frequencies of these activities are pre-determined in

line with the maintenance standard set by the TSO in consultation with the TAO.

Statutory maintenance. Maintenance that is carried out to ensure compliance with safety and environmental requirements.

Table 8-3 compares the TAO’s forecast planned maintenance for PR5 against our recommended allowance. The TAO has requested €94.3 million in planned maintenance compared to our recommended PR5 allowance of €93.6 million. This represents a difference of €0.7 million (1%).

Table 8-3 – Planned Maintenance: Recommended Allowance

Planned Maintenance 2021 2022 2023 2024 2025 PR5 Total

Recommended allowance

€m 2019 prices 18.3 18.5 18.8 19.0 19.0 93.6

TAO requested €m 2019 prices 18.4 18.7 18.6 19.0 19.5 94.3

Variance €m 2019 prices -0.1 -0.2 0.2 0.0 -0.6 -0.7

% 0% -1% 1% 0% -3% -1% Source: CEPA analysis

We outline the base-trend-step analysis we have undertaken to arrive at our recommended planned maintenance allowance below.

Baseline

Is 2018 a typical planned maintenance expenditure year?

In 2018, the TAO spent €17.4 million on planned maintenance, which was slightly lower than the forecast average annual expenditure on planned maintenance during PR4 of €17.9 million. To reflect the step-up in PR4 maintenance activity in 2019 and 2020, we propose adjust the baseline to the PR4 average annual expenditure.

Are any adjustments for inefficiency required?

he PR4 ex-post review of planned maintenance showed that the TAO overspent its planned maintenance allowance; and whilst the TAO has delivered a larger volume of planned maintenance work in PR4 compared to PR3, the gap between scheduled and delivered maintenance widened to 20% (from 16% in PR3).

that there has been a lag between delivered and scheduled maintenance in PR4, we take a conservative approach and do not adjust the baseline downwards. This leads to a PR5 baseline of €89.5 million, however, this allowance is premised on an expectation that the TAO will continue to maintain the step up in delivered maintenance activity it has forecast in 2019 and 2020.



Trends

We consider that total transmission network length is the most appropriate cost driver to forecast the planned maintenance trend projection. The scale of planned maintenance required is likely to be closely linked to the size of the TAO’s network.

Therefore, we base our projection on the TAO’s forecast change in network length in PR5 alongside the baseline unit cost of €2,591 per km of network length.74

Table 8-4 – Planned maintenance CEPA trend projection

Planned maintenance 2021 2022 2023 2024 2025

Baseline (€m 2019) 17.9 17.9 17.9 17.9 17.9

TAO network length 7,074 7,157 7,260 7,318 7,318

Baseline unit cost (€ 2019) 2,591 2,591 2,591 2,591 2,591

Cumulative trend (€m 2019) 0.4 0.7 0.9 1.1 1.1

Base + Trend (€m 2019) 18.3 18.5 18.8 19.0 19.0 Source: CEPA analysis

After applying the trend, our estimate of PR5 planned maintenance increases from €89.5 million to €93.6 million (€4.1 million).

Step Changes

The TAO forecasts €94.3 million in planned maintenance costs for PR5, increasing from €89.5 million in PR4. This represents a €4.8 million (5%) increase in planned maintenance expenditure in PR5 relative to what is expected to be spent in PR4.

In part, these costs reflects the maintenance standard set by the TSO.75 The TSO notes that the existing transmission system asset base continues to age (see Figure 8-1 and Figure 8-2) and, as a result, it expects the quantity of maintenance activity to increase going forward.76

74 The unit cost is calculated as the 2018 baseline costs divided by total transmission network length in 2018. 75 Source: Eirgrid PR5 Forecast Submission – Part 2. Appendix A – Transmission System Development & Maintenance. 77 The unit cost is calculated as the 2018 baseline costs divided by total transmission network length in 2018.



Figure 8-1 – Age distribution of overhead lines (OHL) – number of circuits

Source: EirGrid PR5 Forecast Submission – Part 2 – Figure A.24

Figure 8-2 – Age distribution of overhead lines (OHL) – km of lines

Source: EirGrid PR5 Forecast Submission – Part 2 – Figure A.25

The TSO also says that it has worked with the TAO to create efficiencies in planned maintenance through the maintenance policy, which is demonstrated in policy changes that were put in place during PR4 (e.g. use of LiDar inspections instead of sag inspections to identify conductor hotspots on overhead lines). However, the TSO says that these efficiencies cannot offset the underlying growth in the asset base, continued ageing of existing assets and the resulting demand on asset maintenance.

Overall, we accept the need for increased delivery of planned maintenance during PR5 due to the gap between scheduled and delivered planned maintenance in PR4 (79%), and the growth



in the asset base. However, we consider that the baseline plus trend allowance already reflects a volume of planned maintenance activity consistent with the maintenance plan. This is based on:

using a baseline that is not adjusted downward for outturn planned maintenance in PR4 being lower than the transmission maintenance plan; and

applying a trend projection to reflect the forecast growth in network length during PR5.

Additionally, our review of PR4 opex recommended that the TAO be allowed to retain its planned maintenance allowance despite, a gap with the TSO’s specified maintenance plan. Taken together, we consider that the recommended funding would be sufficient for the TAO to close the delivery lag that was identified in PR4.

Table 8-5 – Planned maintenance: after step analysis

Planned maintenance 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 18.3 18.5 18.8 19.0 19.0 93.6

Step adjustments 0.0 0.0 0.0 0.0 0.0 0.0

Base + Trend + Step (€m 2019)

18.3 18.5 18.8 19.0 19.0 93.6


8.4.2 Unplanned maintenance


Unplanned maintenance relates to expenditure required to respond to faults on the transmission network. Transmission faults are typically low frequency, unpredictable and may have a large impact on consumers / the electricity system when they do occur.

Table 8-6 compares the TAO’s forecast unplanned maintenance for PR5 against our recommended allowance. The TAO has requested €6.4 million in unplanned maintenance, which we have used as it represents a downward step-change in unplanned maintenance the TAO is forecasting for PR5.

Table 8-6 – Unplanned Maintenance: Recommended Allowance

Unplanned Maintenance 2021 2022 2023 2024 2025 PR5 Total

Recommended allowance €m 2019 prices 1.2 1.3 1.3 1.3 1.3 6.4


Variance €m 2019 prices 0.0 0.0 0.0 0.0 0.0 0.0

% 0% 0% 0% 0% 0% 0% Source: CEPA analysis

We outline the base-trend-step analysis we have undertaken to arrive at our recommended unplanned maintenance allowance below.

Baseline

Is 2018 a typical unplanned maintenance expenditure year?

As perhaps expected, unplanned maintenance expenditure is relatively volatile, ranging from €1.8 million to €2.8 million across the PR4 period. Unplanned maintenance expenditure in 2018 falls in the middle of the range at €2.1 million and is also approximately in line with the forecast average annual expenditure on unplanned maintenance during PR4 (€2.2 million). As a result,



we are confident that 2018 represents a sensible baseline with no adjustments for atypical expenditure required.

Are any adjustments for inefficiency required? he PR4 ex-post review of planned maintenance showed that the TAO has overspent on its unplanned maintenance allowance in every year between 2011 and 2020. As a result, we have adjusted the baseline to the initial annual average PR4 unplanned maintenance allowance of €1.6 million. This leads to a PR5 baseline of €8.1 million.

Trends

We have considered a number of cost drivers for unplanned maintenance over PR5. Fault maintenance is likely to be linked to asset health, weather and network length. However, as asset health is endogenously related to the TAO’s maintenance programme and weather cannot be forecasted over the PR5 period. As a consequence, we consider that total transmission network length is the most appropriate cost driver to use in forecasting the trend in unplanned maintenance expenditure. The scale of unplanned maintenance is likely to be closely linked to the size of the TAO’s network.

Therefore, we base our projection on the TAO’s forecast change in network length in PR5 alongside the baseline unit cost of €305 per km of network length.77

Table 8-7 – Unplanned maintenance CEPA trend projection

Unplanned maintenance 2021 2022 2023 2024 2025

Baseline (€m 2019) 2.1 2.1 2.1 2.1 2.1


Baseline unit cost (€ 2019) 305 305 305 305 305



Step Changes

The TAO forecast a significant decrease in unplanned maintenance expenditure between PR4 (€10.6 million) and PR5 (€6.4 million). We include the TAO’s proposed downwards step-change in unplanned maintenance in our recommended forecasts.

Table 8-8 – Unplanned maintenance: after step analysis

Unplanned maintenance 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 2.2 2.2 2.2 2.2 2.2 11.0

Step adjustments -0.9 -0.9 -1.0 -0.9 -0.9 -4.6

Base + Trend + Step (€m 2019) 1.2 1.3 1.3 1.3 1.3 6.4 Source: CEPA analysis

8.4.3 Operations


The operations opex allowance covers the cost of the daily operation of the transmission network, including activities such as monitoring, switching and investigations.

77 The unit cost is calculated as the 2018 baseline costs divided by total transmission network length in 2018.



Table 8-9 compares the TAO’s forecast operations expenditure for PR5 against our recommended allowance. The TAO has requested €10.0 million in operations opex, which we have included in our PR5 forecasts due to the downwards step-change the TAO is forecasting for PR5.

Table 8-9 – Operations: Recommended Allowance

Operations 2021 2022 2023 2024 2025 PR5 Total





We outline the base-trend-step analysis we have undertaken to arrive at our operations opex allowance below.

Baseline

Is 2018 a typical operations expenditure year?

Operations expenditure in 2018 was €2.7 million, which is approximately in line with the forecast average annual expenditure on operations during PR4. As a result, we are confident that 2018 represents a sensible baseline with no adjustments for atypical expenditure required.


The PR4 ex-post review showed that forecast operations in PR4 is slightly below operations spend in PR3 and is expected to be delivered within the PR4 allowance. As a result, we do not make any adjustments for inefficiency.

Trends

We consider that operations are likely to be driven by the size of the TAO’s network. Therefore, we consider that total transmission network length is the most appropriate cost driver to forecast the operations opex trend projection.

We base our projection on the TAO’s forecast change in network length between 2018 and 2025 alongside the baseline unit cost of €383 per km of network length.78

Table 8-10 – Operations CEPA trend projection

Operations 2021 2022 2023 2024 2025

Baseline (€m 2019) 2.7 2.7 2.7 2.7 2.7


Baseline unit cost (€ 2019) 383 383 383 383 383



78 The unit cost is calculated as the 2018 baseline costs divided by total transmission network length in 2018.



Step Changes

The TAO forecast that operations opex will decrease from €12.8 million in PR4 to €10.0 million in PR5.79 This represents a decrease of €2.8 million (22%). We have included this full request within our PR5 recommended allowance.

Table 8-11 – Operations: after step analysis

Operations 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 2.7 2.7 2.8 2.8 2.8 13.8



8.4.4 Wayleaves

(TAO requested €2.5 million; recommended allowance €2.5 million). Wayleaves refer to the compensation costs for mast interference and forestry payments.80 Table 8-12 compares the TAO’s forecast wayleaves expenditure for PR5 against our recommended allowance. The TAO has requested €2.5 million in wayleaves opex, which we have included due to the downwards step-change the TAO is forecasting for PR5.

Table 8-12 – Wayleaves: Recommended Allowance

Wayleaves 2021 2022 2023 2024 2025 PR5 Total





We outline the base-trend-step analysis we have undertaken to arrive at our wayleaves opex allowance below.

Baseline

Is 2018 a typical wayleaves expenditure year?

Wayleaves expenditure in 2018 was €0.8 million, which is more than 5% below the forecast average annual expenditure on wayleaves during PR4 (€0.9 million). As a result, we set the baseline equal to the forecast average annual expenditure on wayleaves during PR4.


The PR4 ex-post review showed that outturn wayleaves expenditure during PR4 is expected to fall below the allowance. As a result, we do not make any adjustments for inefficiency.

Trends

Based on engineering rationale, wayleaves costs are likely to be related to the size of the TAO’s overhead line (OHL) network. Therefore, we consider that total OHL transmission network length is the most appropriate cost driver to forecast the wayleaves opex trend projection.

79 We note that this decrease is projected by the TAO despite the expected growth of the network. 80 This category was previously labelled as asset management in PR4 but we have re-labelled to better describe the nature of the activity.



We base our projection on the TAO’s forecast change in OHL transmission network length between 2018 and 2025 alongside the baseline unit cost of €132 per km of OHL network.81

Table 8-13 – Wayleaves CEPA trend projection

Wayleaves 2021 2022 2023 2024 2025

Baseline (€m 2019) 0.9 0.9 0.9 0.9 0.9

TAO OHL network (km) 6,547 6,576 6,679 6,679 6,679

Average PR4 unit cost (€ 2019) 132 132 132 132 132



Step Changes

The TAO forecast that wayleaves opex will decrease from €4.3 million in PR4 to €2.5 million in PR5. This represents a decrease of €1.8 million (42%). We include the TAO’s proposed downwards step-change in wayleaves opex in our PR5 recommended allowance.82

HWe note that wayleave costs are relatively more uncertain than other opex categories, as we found in the PR4 ex-post review where the TAO underspent its wayleaves allowance by €1.4 million because expected increased activity from farming and other representative groups did not materialise. Given the relatively low level of opex associated with wayleaves, we consider that the variability in costs is sufficiently addressed through any ex-post review of opex that may apply for PR5. However, there may be value in the TAO reporting on the volume and cost of this activity annually during PR5.

Table 8-14 – Wayleaves: after step analysis

Wayleaves 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 0.9 0.9 0.9 0.9 0.9 4.4



8.4.5 Professional fees

(TAO requested €12.9 million; recommended allowance €12.9 million). Professional fees comprise of ESB International support for operation, maintenance and management of transmission assets, in addition to TSO fees, technical and other professional fees.

Table 8-15 compares the TAO’s forecast professional fees expenditure for PR5 against our recommended allowance. The TAO has requested €12.9 million in professional fees opex, which we have included due to the downwards step-change the TAO is forecasting for PR5.

81 The unit cost is calculated as the 2018 baseline costs divided by total transmission network length in 2018. 82 We note that the TAO’s business plan does not elaborate on why the forecast for PR5 is lower than allowed and actual costs from PR4.



Table 8-15: Professional Fees: Recommended Allowance

Professional Services Fees 2021 2022 2023 2024 2025 PR5 Total





We outline the base-trend-step analysis we have undertaken to arrive at our professional fees opex allowance below.

Baseline

Is 2018 a typical professional services fees opex year?

Overall, professional services fees opex is relatively variable over time with an expected range of between €3.2 and €6.0 million over the course of PR4. The TAO has not provided an explanation for this outturn volatility over PR4.

Professional fees expenditure in 2018 was €4.3 million and is more than 5% below the forecast average annual expenditure on professional fees during PR4 (€4.7 million). Therefore, we set the baseline equal to the forecast average annual expenditure on professional services fees during PR4.

The TAO forecasts a noticeable downward step change in professional services opex in 2020, which is forecast by the TAO to be maintained during PR5. We take this forecast step-change into account in the step changes discussion below.


The PR4 ex-post review showed that outturn professional services fees expenditure during PR4 is expected to fall below the allowance. As a result, we do not make further adjustments for inefficiency.

Trends

In our review of the TAO’s PR5 submission, we have not found evidence of a volume driver for professional services fees opex. This is reflected in the TAO’s forecast PR5 professional services fees, which does not follow any noticeable trend. As such, we have forecast no change in professional services fees opex from our baseline across PR5.

Step Changes

The TAO forecasts that professional services fees will decrease from €23.7 million in PR4 to €12.9 million in PR5. This represents a decrease of €10.8 million (46%). The TAO has not explained what is driving this decrease (e.g. whether it plans to change its delivery model or was able to negotiate more favourable terms with contractors for PR5).

We include the TAO’s proposed downwards step-change in professional services fees opex between PR4 and PR5 in our recommended allowance for PR5.



Table 8-16 – Professional services fees: after step analysis

Professional Services Fees 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 4.7 4.7 4.7 4.7 4.7 23.7



8.4.6 Telecoms opex

(TAO requested €9.3 million; recommended allowance €7.6 million). Telecoms opex relate to the costs associated with the telecommunications equipment need to operate and manage the network assets.

Table 8-17 compares the TAO’s forecast telecoms opex for PR5 against our recommended allowance. The TAO has requested €9.3 million in telecoms opex compared to our recommended PR5 allowance of €7.6 million - a difference of €1.7 million (18%).

Table 8-17: Telecom Fees: Recommended Allowance

Telecom Fees 2021 2022 2023 2024 2025 PR5 Total



Variance €m 2019 prices -0.3 -0.3 -0.3 -0.3 -0.4 -1.7

% -16% -17% -18% -18% -20% -18% Source: CEPA analysis

We outline the base-trend-step analysis we have undertaken to arrive at our telecom fees opex allowance below.

Baseline

Is 2018 a typical telecoms opex year?

Telecoms opex is relatively variable over time with an expected range of between €1.0 and €2.1 million over the course of PR4. Telecoms opex in 2018 was €1.0 million, which is at the lower end of the range, and 32% lower than average annual expenditure expected over PR4 (€1.5 million). The TAO have not provided us with an explanation for the volatility in these costs over PR4.

As a result of the significant variability over the PR4 period, we consider it is appropriate to set the baseline equal to the average annual expenditure expected over PR4 of €1.5 million per annum.


The PR4 ex-post review showed that outturn telecoms opex during PR4 is expected to fall below the allowance. As a result, we do not make further adjustments for inefficiency.

Trends

In our review of the TAO’s PR5 submission, we have not found evidence of a volume driver for telecoms opex. This is reflected in the TAO’s forecast PR5 telecoms opex, which does not follow any noticeable trend. As such, we have forecast no change in telecoms opex from our baseline across PR5.



Step Changes

The TAO forecast that telecoms opex will increase from €7.6 million in PR4 to €9.3 million in PR5. This represents an increase of €1.7 million (22%).

ESB Networks forecasts telecoms opex of €93.8 million for PR5, of which approximately 10% is allocated to the TAO. This is broken down into different components as summarised in Table 8-18.83

Table 8-18 – ESB Networks PR5 Telecoms Opex Breakdown

Cost type Requested Description

Payroll €30.0 million ESB Networks considers this level of payroll is necessary to deliver the outputs attributable to the telecoms opex allowance.

Video and voice €4.0 million Recurring annual costs that are made up of either annual licenses or support / maintenance charges. Service rentals €9.5 million

Wide area network (WAN) Costs

€7.0 million

Contractors and consultants

€2.0 million ESB Networks says contractors and consultants costs will rise significantly as it takes on the Long Term Evolution (LTE) license rollout and also further develop the (Internet Protocol) IP Network.

Circuit rentals €9.5 million No further details provided.

General maintenance and expenses

€5.4 million ESB Networks says general maintenance and expenses costs will rise significantly as it takes on the LTE license rollout and also further develop the IP Network.

Retail Market Services €7.0 million The cost of linking a Profile Meter with the Retail Market Services MV90 IT System. This facilitates the collection of data from Import/Export Meters for 16,000 meters in 2019 which are assigned to the largest customers. Proposed costs also includes growth in the population of such meters over the coming years through normal market conditions (600 meters per annum), the improvement in data quality for 4,400 other larger customers (Max Demand) and a contingency to cover initiatives linked to the Clean Energy Package and Climate Action Plan.

Overhead / Contingency €20.0 million No further details provided.

Total costs €93.8 million Source: CEPA analysis

The information provided by ESB Networks does not specify what percentage of the telecoms opex forecast relates to business as usual activities and what percentage relates to new outputs or activities. ESB Networks has also not explained why €20.0 million are forecast as contingency for PR5 (this is equal to 27% of forecast telecoms opex excluding the contingency). For these reasons, we do not consider that ESB Networks has sufficiently demonstrated the need for a step-change adjustment for the TAO.

Table 8-19 – Telecoms opex: after step analysis

Telecoms opex 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 1.5 1.5 1.5 1.5 1.5 7.6


Base + Trend + Step (€m 2019) 1.5 1.5 1.5 1.5 1.5 7.6 Source: CEPA analysis 83 Source: ESB Networks, PR5 business plan, Annex DF06 Telecommunications.



8.4.7 Corporate costs

(TAO requested €18.2 million; recommended allowance €18.2 million). Corporate costs include corporate charges and company-wide costs. Corporate charges include chief executive, group finance, corporate affairs, regulatory and human resources. Company-wide costs include employee stock ownership plan (ESOP) costs, sports and social subsidies, group of union costs, industrial council costs and pension supplements.

Table 8-19 compares the TAO’s forecast corporate costs for PR5 against our recommended allowance. We have included the TAO’s requested €18.2 million in corporate costs as our recommended forecast.

Table 8-20 – Corporate Costs: Recommended Allowance

Corporate Costs 2021 2022 2023 2024 2025 PR5 Total





We outline the base-trend-step analysis we have undertaken to arrive at our corporate costs opex allowance below.

Baseline

Is 2018 a typical corporate costs year?

Corporate costs are expected to range from €3.1 and €4.4 million over the course of PR4. Corporate costs in 2018 were €3.9 million, which were less than 5% above the annual average corporate costs incurred over the PR4 period (€3.7 million). As a result, we are confident that 2018 represents a sensible baseline with no adjustments for atypical expenditure required.


The PR4 ex-post review showed that the TAO is expected to overspend its corporate costs allowance by €4.9 million. The TAO provides two reasons for the overspend:

• Additional costs associated with increased ESOP and group of union activities.

• An increase of €0.6 million per annum associated with additional safety management and procurement activities.

We acknowledge that costs associated with ESOP and group of union activities are to some extent outside the control of the TAO, so we do not make an adjustment to the baseline for the overspend related to these activities. In addition, we do not make an adjustment for the additional safety and management and procurement activities.

Trends

In our review of the TAO’s PR5 submission, we have not found evidence of a volume driver for corporate costs. This is reflected in the TAO’s forecast PR5 corporate costs, which does not follow any noticeable trend. As such, we have forecast no change in corporate costs from our baseline across PR5.



Step Changes

The TAO forecasts a PR5 corporate costs of €18.2 million, which is €0.4 million (2%) below outturn expenditure in PR4. We include the TAO’s proposed downwards step-change in corporate costs in our recommended forecasts.

Table 8-21 – Corporate Costs: after step analysis

Corporate Costs 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 3.9 3.9 3.9 3.9 3.9 19.3



8.4.8 Insurance

(TAO requested €3.4 million; Recommended allowance €2.9 million). Table 8-22 compares the TAO’s forecast insurance opex for PR5 against our recommended allowance. The TAO has requested €3.4 million in insurance opex compared to our recommended PR5 allowance of €2.9 million – a difference of €0.5 million (14%).

Table 8-22 – Insurance: Recommended Allowance

Insurance 2021 2022 2023 2024 2025 PR5 Total



Variance €m 2019 prices -0.1 -0.1 -0.1 -0.1 -0.1 -0.5


We outline the base-trend-step analysis we have undertaken to arrive at our insurance opex allowance below.

Baseline

Is 2018 a typical insurance expenditure year?

Insurance opex in 2018 was €0.6 million, which was 1% lower than the forecast average annual insurance opex during PR4. As a result, we do not make any adjustments to the 2018 baseline.


The TAO overspent its insurance opex allowance by 51% during PR4. However, this was due to change in the allocation of insurance opex between the TAO and DSO. Therefore, we consider that no adjustments for inefficiency are required. We recommend that the CRU monitor this allocation at future reviews.

Trends

In our review of the TAO’s PR5 submission, we have not found evidence of a volume driver for insurance costs. This is reflected in the TAO’s forecast PR5 insurance opex, which does not follow any noticeable trend. As such, we have forecast no change in insurance opex from our baseline across PR5.



Step Changes

The TAO forecast that insurance opex will increase from €2.9 million in PR4 to €3.4 million in PR5. This represents an increase of €0.5 million (17%).

The TAO says there has been a “hardening” of the insurance market,84 which has led to higher premiums in 2020.85 The TAO did not provide evidence to support this claim. Absent such evidence, we are unable to conclude the extent to which any increase in insurance premia is the result of external factors rather than of the TAO’s own actions. Under most circumstances, step-changes are only considered for exogenous changes in circumstances and outputs. As a result, we consider that the TAO has not demonstrated the need of the step-change and do not include the step-change in our recommended insurance opex allowance.

Table 8-23 – Insurance: after step analysis

Insurance 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 0.6 0.6 0.6 0.6 0.6 2.9



8.4.9 Legal

(TAO requested €1.1 million; recommended allowance €1.1 million). Table 8-24 compares the TAO’s forecast legal expenditure for PR5 against our recommended allowance. The TAO has requested €1.1 million in legal opex, which we have included in our recommended allowance due to the downwards step-change the TAO is forecasting for PR5.

Table 8-24 – Legal: Recommended Allowance

Legal 2021 2022 2023 2024 2025 PR5 Total





We outline the base-trend-step analysis we have undertaken to arrive at our legal opex allowance below.

Baseline

Is 2018 a typical legal expenditure year?

In the ex-post review, we identified 2018 and 2020 as atypical legal spend years that are not reflective of typical annual spend on legal services. The TAO explained that these atypical spend years were the result of increased activity in the area of land access disputes, site acquisition and acquiring easements due to increased construction activities.

As a result, we set the baseline at the forecast average annual legal opex based on 2016, 2017 and 2019 data, leading to a baseline of €0.3 million per annum.


84 i.e. high demand for coverage and reduced supply. 85 Source: ESB Networks, PR5 business plan, Annex DF01-09 Support Charges.



The TAO overspent its legal opex allowance by 119% during PR4, which was largely the result of two atypical legal spend years in 2018 and 2020. We have set the baseline excluding these atypical years and, therefore, consider no adjustments are required for inefficiency.

Trends

In our review of the TAO’s PR5 submission, we have not found evidence of a volume driver for legal costs. This is reflected in the TAO’s forecast PR5 legal opex, which does not follow any noticeable trend. As such, we have forecast no change in legal opex from our baseline across PR5.

Step Changes

The TAO forecasts a small downwards step-change in legal opex within its PR5 forecasts (differences in the table below are due to rounding).

Table 8-25 – Legal: after step analysis

Legal 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 0.3 0.3 0.3 0.3 0.3 1.3

Step adjustments 0.0 0.0 0.0 0.0 0.0 -0.2


8.4.10 Pensions administration

(TAO requested €2.2 million; recommended allowance €2.0 million). Table 8-26 compares the TAO’s forecast pensions administration expenditure for PR5 against our recommended allowance. The TAO has requested €2.2 million in pensions administration opex compared to our recommended PR5 allowance of €2.0 million. This represents a recommended difference of €0.2 million (10%).

Table 8-26 – Pension Administration: Recommended Allowance

Pensions Administration 2021 2022 2023 2024 2025 PR5 Total



Variance €m 2019 prices -0.1 -0.1 0.0 0.0 0.0 -0.2


We outline the base-trend-step analysis we have undertaken to arrive at our pensions administration opex allowance below.

Baseline

Is 2018 a typical pensions administration expenditure year?

Pensions administration expenditure in 2018 is more than 5% below the forecast average annual pensions administration spend during PR4. As a result, we set the baseline at the forecast average annual pensions administration opex during PR4, leading to a baseline of €0.4 million per annum.

Are any adjustments for inefficiency required? The TAO underspent its pensions administration opex allowance during PR4. Therefore, we consider that no further adjustments for inefficiency are required.



Trends

In our review of the TAO’s PR5 submission, we have not found evidence of a volume driver for pensions administration opex. This is reflected in the TAO’s forecast PR5 pensions administration opex, which does not follow any noticeable trend. As such, we have forecast no change in pensions administration opex from our baseline across PR5.

We invite the TAO to provide data on the outturn / forecast volume of retirements between 2016 and 2025 in its consultation response and we will consider this for the final determination.

Step Changes

The TAO forecasts that pensions administration opex will increase from €2.0 million in PR4 to €2.2 million in PR5. This represents an increase of €0.2 million (11%).

The TAO has not sufficiently justified the need for the step change in pensions administration opex. As a result, we do not include the step-change in our recommended pensions admin opex allowance.

Table 8-27 – Pensions Administration: after step analysis

Pensions Administration 2021 2022 2023 2024 2025 PR5 Total

Base + Trend (€m 2019) 0.4 0.4 0.4 0.4 0.4 2.0



8.5 Summary of Recommendations

8.5.1 Opex allowance

Table 8-28 compares our recommended TAO opex allowance to the TAO’s request for PR5 before applying RPEs and ongoing productivity. Our recommended opex allowance is €325.3 million, which is €3 million (1%) below the TAO’s requested opex allowance of €328.3 million. The differences are in planned maintenance, telecoms, insurance and pensions administration. We have primarily taken a different view to the TAO where it has not demonstrated the need, additionality and cost efficiency of the proposed steps-changes.



Table 8-28 – Recommended TAO PR5 Controllable Opex Allowance (before RPEs and ongoing productivity)


2021 2022 2023 2024 2025 PR5 Variance


%

Controllable Opex

Planned maintenance 18.3 18.5 18.8 19.0 19.0 93.6 94.3 -0.7 -1%

Unplanned maintenance 1.2 1.3 1.3 1.3 1.3 6.4 6.4 0.0 0%

Operations 2.0 2.0 2.0 2.0 2.0 10.0 10.0 0.0 0%

Wayleaves 0.5 0.5 0.5 0.5 0.5 2.5 2.5 0.0 0%

Professional fees 2.5 2.5 2.6 2.6 2.6 12.9 12.9 0.0 0%

Telecoms opex 1.5 1.5 1.5 1.5 1.5 7.6 9.3 -1.7 -18%

Corporate overheads 3.7 3.7 3.6 3.6 3.6 18.2 18.2 0.0 0%

Insurance 0.6 0.6 0.6 0.6 0.6 2.9 3.4 -0.5 -14%

Legal 0.2 0.2 0.2 0.2 0.2 1.1 1.1 0.0 0%

Pensions admin 0.4 0.4 0.4 0.4 0.4 2.0 2.2 -0.2 -10%



Rates 28.2 32.9 33.6 32.8 34.9 162.4 162.4

N/A CRU Levy 1.1 1.1 1.1 1.1 1.1 5.6 5.6


29.3 34.1 34.7 33.9 36.1 168.0 168.0


Figure 8-3 presents the make-up of our recommended allowance against PR4 outturn / forecast controllable opex and the TAO’s request of controllable opex. The figure shows that our recommendation (before RPEs and ongoing efficiency) is €17.1 million (10%) lower than PR4 outturn / forecast controllable opex, which is largely the result of the TAO forecasting downwards step-changes for a number of controllable opex categories.

TThe TAO also forecasts 0.9% per annum in ongoing productivity gains,86 which amounts to a €8.4 million reduction in controllable opex during PR5 beyond the figures shown below. As the figures shown here are before RPEs and ongoing efficiency, we stress that the CRU’s allowance for controllable opex for PR5 should be capped at the TAO’s request.

86 The TAO’s business plan does not specify what level of RPEs (if non-zero) is used in the cost forecasts.



Figure 8-3: Recommended PR5 TAO controllable opex allowance breakdown and comparison (excluding RPEs and ongoing efficiency)


TAO Figure 8-4 presents our recommended PR5 controllable opex allowance against the TAO’s proposal on a year-by-year basis.

Figure 8-4: Recommended PR5 controllable opex allowance and TAO proposal (excluding RPEs and ongoing efficiency)


8.5.2 Qualitative recommendations

We also make the following qualitative recommendation: Opex allocations - the TAO has said that there are cases where expenditure has been

reallocated between opex categories and/or between the TAO and DSO, but it has not always been possible to verify this statement. To avoid such issues in future, we recommend that the TAO develop and submit to the CRU a detailed cost allocation methodology. This should be submitted before any ex-post review of PR5.





9. Review of PR5 Capital Expenditure: Transmission Asset Owner 9.1 This Section

As part of GHDs support to the Commission for Regulation of Utilities, a review has been performed of the forecast PR5 capital expenditure proposed by ESB Networks in their roles as Transmission Asset Owner (TAO). This document reviews the forecast capital expenditure over the PR5 Period 2021 to 2025, for the TAO and includes comparison with the historic expenditure seen in the previous PR4 period.

The objective of this review of forecast capital expenditure is to assess the TAO proposed efficiency in achieving the required outputs during the PR5 period and advise on allowances to be provided for the upcoming period. The review includes an appraisal of the forecasted issues that may drive the development of projects in the PR5 period.

9.2 Development Scenarios

The TSO has submitted three scenarios for consideration in the PR5 period. The three scenarios are a collection of projects both ongoing and forecasted which are factored to produce three spend profiles which are forecast to achieve a set of outputs for that level of expenditure. The TSO scenarios, with brief description are noted below:

3. Business as usual – forecast expenditure is constrained to levels seen in PR4, delivering a similar level of output as previously seen.

4. Embracing change and delivering targets – forecast expenditure is at a level required to achieve output targets within the PR5 period, particularly with regard to renewable energy connections

5. Unconstrained – forecast expenditure is unconstrained by deliverability or other factors allowing all projects identified to be delivered

The TAO’s submission is based on the scenario ‘embracing change and delivering targets’ as the recommended approach. This scenario recognises constraints which limit the ability to achieve an unconstrained investment approach whilst also recognising that business as usual in the PR5 period is unlikely to provide the necessary investment to achieve 2025 targets and a sufficient basis going in to PR6 to achieve 2030 targets.

This assessment of the TAO PR5 submission is therefore focussed on the expenditure proposed under the ‘embracing change and delivering targets’ scenario

9.3 Overview of PR5 Forecast Capital Expenditure

9.3.1 Total Forecast Capital Expenditure

The forecast capital expenditure for each project type within the PR5 period, as provided in the TAO submission, is as shown in Table 9-1.



Table 9-1 – Forecast Capital Expenditure for PR5

Project Type PR5 Forecast Capex €m Total in

the PR5 Period 2021 2022 2023 2024 2025

Ongoing Project 150.8 116.9 85.0 53.1 40.1 445.9 Under Consideration/Provisions - System Reinforcements

16.3 19.3 9.7 11.6 16.9 73.8

Under Consideration/Provisions - Shallow Connection

0.0 0.0 0.0 0.0 0.0 0.0

Under Consideration/Provisions - Asset Refurbishment

23.7 46.2 48.8 41.8 38.4 198.9

Under Consideration - DSO 2.0 5.2 8.0 8.0 7.5 30.7

Under Consideration/Provisions - Protection, Telecoms & Station Security

0.0 0.0 0.0 0.0 0.0 0.0

New Connection Project 72.0 69.4 68.3 78.9 87.7 376.3 Other Project 0.2 0.2 0.3 0.0 0.0 0.7 Unknown 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal 264.9 257.2 220.2 193.4 190.6 1126.2 Customer Contributions -20.0 -20.0 -20.0 -20.0 -20.0 -100.0 Interest During Construction -13.2 -12.9 -11.0 -9.7 -9.5 -56.3

Other Adjustments 0.0 0.0 0.0 0.0 0.0 0.0 Total 231.7 224.3 189.1 163.7 161.0 969.9

For comparison, the outturn capital expenditure for the PR4 period is given in Table 9-2.



Table 9-2 – Outturn Capital Expenditure for PR4

Project Type PR4 Actual Capex €m Outturn in

the PR4 Period 2016 2017 2018 2019 2020

Ongoing Project 148.5 116.3 122.1 105.9 120.3 613.0 Under Consideration/Provisions - System Reinforcements 1.8 3.6 3.6 0.2 0.0 9.2

Under Consideration/Provisions - Shallow Connection 5.9 0.5 0.6 1.7 0.0 8.7

Under Consideration/Provisions - Asset Refurbishment 0.5 0.2 0.2 2.9 2.9 6.6

Under Consideration - DSO 0.0 0.0 0.0 0.0 0.0 0.1 Under Consideration/Provisions - Protection, Telecoms & Station Security

0.0 0.0 0.0 0.0 0.0 0.0

New Connection Project 2.7 6.2 60.0 22.4 26.5 117.8 Other Project 0.0 0.0 0.0 0.0 0.0 0.0 Unknown 4.2 16.7 14.7 21.4 7.1 64.0 Subtotal 163.6 143.5 201.2 154.5 156.8 819.5 Customer Contributions -9.4 -20.7 -13.5 -7.7 -17.0 -68.3 Interest During Construction -20.7 -15.7 -17.6 -13.4 -7.3 -74.8 Other Adjustments 5.8 9.9 4.9 3.9 14.0 38.4 Total 139.2 117.0 174.8 137.3 146.5 714.8

Figure 9-1 provides a visual comparison of the PR4 outturn expenditure and the PR5 forecast expenditure including net average expenditure over the periods.


Figure 9-1 – Comparison of PR4 Outturn and PR5 Forecast



Comparison of Table 9-1 and Table 9-2 (as summarised Figure 9-1) highlights a proposed step change in capital expenditure for the forecast PR5 period when compared with the outturn capital expenditure in PR4. The total net expenditure over the periods is forecast to increase by 35.7% (€255.1m), from €714.8m in the PR4 outturn to €969.9m in the PR5 forecast. The proposed expenditure profile in PR5 also illustrates a significant increase in annual expenditure in the early years of the PR5 period (2021 and 2022 specifically) is anticipated. The TAO’s capability and capacity to deliver this increased expenditure profile is a key consideration and is discussed in detail in Section 9.5.

9.3.2 ‘Top 10’ Projects

Inspection of the project list and associated forecast expenditure has identified that ten projects dominate, with approximately 40% of total gross expenditure in the period. Table 9-3 provides a summary of these ten projects and their associated expenditure.

Table 9-3 – ‘Top 10’ Projects Summary

Project No. Project Name Forecast Expenditure

CP0466 North South 400kV Interconnector €90.42m

CP0585 Laois Kilkenny (Coolnabacky) 400kV Station – New Station & Associated Lines & Station Works €34.50m

CP0800 North West Project (RIDP) €30.00m

CP0816 North Connaught Line (Moy - Tonroe 110kV Line - New Line) €30.63m

CP0970 Cross Shannon 400kV Cable €42.22m CP1029 Intel 220 kV €66.15m DSO - Pipeline Projects DSO Projects - programme of work (placeholder) €27.50m

Pipeline Project Offshore Wind 1 progressing under enduring policy €37.52m Pipeline Project Offshore Wind 2 progressing under enduring policy €44.93m Pipeline Project Protection Projects Pipeline - Cumulative €45.05m TOTAL €448.90m

The efficient delivery of committed projects (CP) within this top 10 list are of key importance to the successful delivery of PR5. Inefficiencies arise when substitutions and delays result in additional works as was identified in some cases in the PR4 outturn review. Many of these CP projects are ongoing from PR4 and have been delayed as a result of land access, planning and other associated issues. It is understood that many of these issues have now been overcome by the TSO to allow the TAO to deliver these projects early in the PR5 period. The TAO has acknowledged the importance of these projects and early expenditure in the PR5 period (step change in 2012/22) reflects the anticipated delivery timescale for a large proportion of these works.

It is appreciated that additional pipeline projects, which are currently unknown in scope, will be required within the PR5 period to continue to support the connection of renewables and accommodate system reinforcements and new demand connections as they develop during the period. However, significant levels of forecast expenditure have been included for some of these undefined pipeline projects and are included in the top 10 list in Table 9-3. Further consideration regarding these projects is discussed in Section 9.8.



9.3.3 Capital Expenditure Apportionment

Figure 9-2 provides a summary of the apportionment of expenditure across project categories for the PR5 forecast and the PR4 outturn. It is noted that a number of projects associated with the PR4 outturn (€64m of expenditure) were not given a specific project type within submission data and have therefore been classified as ‘unknown’ project category.

Figure 9-2 – Apportionment of Expenditure by % in PR5 Forecast and PR4 Outturn

Figure 9-2 suggests notable changes to expenditure apportionment across each of the periods, particularly in the areas of ongoing projects, asset refurbishment and new connections. With respect to ongoing projects, the proportion of expenditure is significantly reducing from 75% in PR4 to 39% in PR5. This reflects the ongoing expenditure on long term projects that occurred in the previous price control period and were affected by delays and other constraints to delivery resulting in them not being completed within the PR4 period from PR3. The reduction in PR5 ongoing project expenditure reflects the addressing of issues which have delayed some of the large scale projects and the indication that these are coming to a close in the latter part of PR4 with more limited expenditure in PR5. Further inspection illustrates there are 57 ongoing projects from previous periods with a spend forecast in the PR5 period, of which a total of 6 projects are forecast to still require expenditure in 2025 (the end of the PR5 period). These projects represent large scale developments such as the Killonan, Inchicore and Louth 220kV substation refurbishment (CP0624, CP0692 and CP0799 respectively).

With respect to new connections, rising from €117.8m (14.4%) in PR4 to €376.3m (33.4%), it is to be expected to see a much larger proportion of expenditure in this area for PR5 as new renewables and demand customers are likely to dominate the period to achieve the goals and targets of the climate action plan.

Another key area of change is with respect to asset refurbishment, rising from €6.6m (0.8%) to €198m (17.6%). It is not clear why asset refurbishment was so low in PR4 with respect to both expenditure and its percentage of the overall expenditure. It is considered that naming of the project categories may not have been consistent between the two periods and some level of ‘unknown’ projects likely are assigned to asset refurbishment. It is also likely that some



proportion of ongoing projects could be sub-categorised into asset refurbishment works. Furthermore, in the PR5 period, there is forecast to be a significant increase in the volume of line refurbishment works which will be a primary driver for the increase in expenditure in this category.

Figure 9-3 provides further analysis of capital expenditure apportionment by project category on a per annum basis, including PR4 outturn and PR5 forecast.

Figure 9-3 – Apportionment of Projects by % of Total Capex in 2016 - 2025

As summarised within Figure 9-2, the curtailment of ongoing projects in PR5 as a proportion of overall expenditure is highlighted in Figure 9-3. It can be seen that ongoing project expenditure is forecast to fall away from a peak level in 2021 of approximately €150 m down to approximately €40 m in 2025. This is to be expected as ongoing projects which are already in construction or pre-construction are completed early in the period. This trend, along with the adverse trend in PR4 where ongoing project spend fluctuated, supports the earlier analysis that large scale ongoing projects from PR3 and PR4 have now addressed planning and access limitations, allowing delivery to be completed early in the PR5 period. The ongoing project expenditure is the driving force for the spend profile and the step change in expenditure from 2020 to 2021. The fall away of expenditure over the PR5 period is dominated by the associated fall away of ongoing project expenditure as such projects are completed. It is therefore noted that any delay in ongoing projects is likely to have a direct and notable impact on the expenditure profile over the PR5 period.

In contrast, new connection project expenditure is high throughout the PR5 period (in comparison to PR4) and increases over time from €72 m in 2021 to €87.7 m in 2025. This reflects the anticipated environment of PR5 in new renewable and demand connections to achieve climate targets and continued economic development. This also reflects the assumption that new renewable connection opportunities, such as offshore wind farm developments, will begin to materialise in the latter parts of the PR5 period resulting in a slight rise in expenditure levels.



With respect to other primary project categories (DSO, system reinforcement and asset refurbishment), the levels of expenditure are broadly consistent over the PR5 period, although notably greater than the PR4 period reflecting the step up in works required to achieve desired PR5 outcomes.

9.3.4 Asset Delivery

Figure 9-4 provides a dashboard of charts illustrating assets installed in the PR3 and PR4 periods and assets forecast within the PR5 period. This is broken down in to the asset classes of overhead lines, underground cables, subsea cables, switchgear, transformers and line up-rates/refurbishments. Data for line uprates/refurbishments in PR3 is not available in the submission. A request for this data has been provided to the TAO.

Figure 9-4 – Asset Dashboard



Review of Figure 9-4 illustrates that in most asset categories, the quantity of assets proposed to be delivered in PR5 is less than those delivered in PR4 and PR3. However, the composition of the assets is notably different, particularly the inclusion of notable quantities of 400 kV assets in PR5 which were not delivered in PR4 and PR3. This reflects the key 400 kV projects which have been highlighted within the top 10 projects in Table 9-3, some of which have been delayed from the PR4 period due to access and planning issues.

Although the data is incomplete for PR3 line up rates, a general trend can be seen with respect to the fall in new overhead line and rise in new underground cable and line up rates between PR3 and PR4/5. This trend would reflect the evolving planning and land access environment in which the TAO is operating whereby the construction of new overhead lines is likely to result in high planning and access risk. In comparison, the use of underground cable to mitigate visual impacts or line uprates/refurbishments to make best use of existing assets is becoming more prominent. Although beneficial in terms of minimising planning risks and subsequent project delays, the prevalence of line uprates/refurbishments is complex with respect to securing outage periods and will be a key risk to the delivery of the PR5 programme. Furthermore, the use of QRA and TLA processes to maximise the efficiency of this extensive programme of line uprates / refurbishments will be a key factor. Further consideration of these aspects is detailed in Section 0.

9.4 Specific Findings from Forecast PR5 Review

9.4.1 Land Access and Planning

Land access and planning has been a key challenge for previous price control periods and has resulted in the lengthy of delay strategic projects, particularly the North-South Interconnector which is the highest forecast expenditure project in the PR5 forecast. Delivery of the PR5 forecast in a timely manner is critical for efficient expenditure, achieving targets by 2025 and providing a foundation for PR6 period and 2030 targets.



Planning consent is principally the TSO responsibility, however through the PR4 period, improved TSO processes for planning consent, tied with close involvement from the TAO where required, has begun to suggest an improvement in the efficiency of planning consent process. This momentum needs to be continued to deliver the PR5 forecast and although it is appreciated that developing landowner and community relationships is an ongoing process, progress is being seen.

It is recognised that the TAOs national agreement with the Irish Farmer’s Association (IFA) is a significant step in reducing the risk of delays in reaching agreements with landowners through consistent approaches to land access.

Land access and planning remains a key challenge for PR5, however improved processes by the TAO and TSO in this regard will aid in minimising these external risks.

9.4.2 Outage Constraints and Scope Complexity

Figure 9-4 illustrated that the PR5 programme of works is likely to include a significant increase in line uprate and refurbishment works compared to offline Greenfield developments. This is a trend that was starting to be seen in PR4 as the existing network is looked to be improved in the first instance (for example to mitigate land access and planning issues and minimise costs) before new build solutions are considered. This trend is supported for the primary benefits noted, however it is appreciated that this does introduce additional scope complexity (potentially working in live sites and interacting with existing assets) and outage constraints (outage required for the period of works) with respect to deliverability.

Mitigation of the risks is best achieved through close collaboration between the TSO and TAO as operator and owner respectively. The creation of the Multi-Year Development Plan (MYDP) and Transmission Outage Plan (TOP) allows for clear vision for long range outage planning and project management. This includes the ability to analyse the risk of outage availability to the programme of projects and develop mitigation to risks years in advance. However, such plans require clear delivery timescales to then align with the available outage times, which further emphasises the key mitigation to a successful PR5 period will be the timely delivery of projects.

9.5 Deliverability

9.5.1 Project Quantity and Value

The PR5 forecast represents a step change of 37.4% in gross expenditure from PR4 outturn levels. However, a review of the project composition illustrates that although the expenditure is significantly higher, the number of projects included in the forecast with some level of expenditure (220) is less than the number of projects in the PR4 period with some level of expenditure (233). A further breakdown of number of projects with expenditure in the PR5 forecast and PR4 outturn is presented in Figure 9-5.



Figure 9-5 – Number of Projects with Expenditure

Figure 9-5 illustrates that although the number of projects with expenditure in the PR4 outturn was greater than the number of projects included in the PR5 forecast, the proportion of projects with low expenditure (less than €0.1m) was significantly higher. Conversely, the expenditure for each project in PR5 is anticipated to be higher than in PR4 with a greater proportion of projects with expenditure greater than €0.1m. For example, the average project spend in the PR4 outturn was €3.6m whilst in PR5 this increases to €5.1m, a percentage increase of 41.6%. This trend suggests that the number of projects to be delivered in PR5 is likely to be similar in quantity to PR4, however the value of each of those projects is on average likely to be greater.

This trend has been reflected in the PR4 outturn report which noted that a number of large expenditure strategic projects had been delayed and were in turn replaced by a number of smaller expenditure local projects. In PR5, the understanding is that many of those delaying factors which affected those projects in PR4 have now been overcome, to allow the large ongoing projects to progress in PR5. Therefore the principle projects for delivery in PR5 will require high levels of expenditure on a per project basis given the nature of the projects, such as large scale 400 kV strategic reinforcement works as illustrated in the Top 10 projects (see Section 9.3.2) which represent 40% of the proposed PR5 expenditure. This view is further supported by the changing blend of assets to be installed in the PR5 period as described in Section 9.3.4 which sees more costly assets being installed (e.g. 400 kV assets and greater quantities of cable) compared to PR4.

The implication on the TAO is therefore not on an additional deliverability workload in terms of project numbers (potentially less projects by number compared to PR4), but the ability to deliver a similar quantity of projects with greater expenditure requirements.

9.5.2 Deliverability Assurance

The TAO has conducted a deliverability assurance assessment of 86 projects agreed by both the TAO and TSO. These 86 projects were selected due to their maturity and deemed to have sufficient information available to complete the deliverability assessment. The 86 projects included a mix of asset types (line, station, cable and new connections), project type (new



cable/line, uprate/refurb and brownfield/greenfield) and geographic location to provide a broad understanding of deliverability capability.

The TAO’s deliverability assessment included considerations for aspects and key risks including:

Route selection, planning permission and land access

Outage availability

Customer Requirements / Timelines

Progressing projects to Committed Project Parameters (CPP) Stage and Project Agreement (PA) stage

Risks associated with the top 10 projects

The TAO has also acknowledged through the assessment that to achieve the step up in project delivery, a key enabler is the consideration of other contracting models not previously utilised including Design and Build (D&B) and Engineer, Procure, Construct (EPC). The inclusion of these contracting models will allow for the project delivery capacity of the TAO to expand to meet the needs of the PR5 programme.

Through the deliverability assessment, the TAO divided project delivery into those projects likely to be delivered internally and those likely to be delivered as a major project to understand capacity and capability. The TAO summarised that of the 86 projects reviewed, 38 would likely be delivered internally to a project value of €92m with the remaining 48 projects delivered through major project processes to a value of €1,060m.

This assurance assessment illustrates a stress test on the capabilities of the TAO to deliver the PR5 programme, in addition to pragmatic consideration for key risks that exist, some of which are externally influenced. The assessment has indicated how the project delivery in PR5 is likely to be apportioned between different delivery models and the level of expenditure that can be reasonably achieved in the period based on a subset of sufficiently defined projects within the wider project list. The 86 projects assessed in the stress test relate to approximately €700-€800m of expenditure, similar to PR4 outturn levels, with the remaining headroom to €1.15bn identified as available flexibility to step up delivery of additional (factored) projects considering deliverability mitigation factors such as additional contracting options.

This level of notional ‘delivery capacity’ as a result of the assurance assessment has been fed back to the TSO to include in the factoring applied to the PR5 final submission and the derivation of the ‘Embracing Change and Delivering Targets’ scenario.

The deliverability assurance conducted by the TAO has represented both a bottom up and top down view of the current deliverability capability of the business, the additional capability that can be developed internally and externally and the likely project mix to be delivered over the PR5 period. The TAO has taken due consideration for those projects which are more appropriately delivered internally (such as those which are on brownfield sites or complex integration with DSO or existing assets) and those which can reasonably be delivered by external contractors and new contracting models (such as Greenfield projects). As a result, the deliverability assurance assessment presents a pragmatic and reasonable view of a level of expenditure and project deliverability for the PR5 period.

9.5.3 Deliverability Models

As highlighted in Section 9.3, the scale of projects to be delivered in PR5 are likely to be greater in value per project than those in previous price control periods. In order to achieve the step up in deliverability, the TAO has identified and are developing the Design and Build (D&B) and



Engineering Procurement Construction (EPC) markets to support the PR5 programme. The D&B and EPC contracting strategies are suited to large scale, primarily Greenfield projects with standard solutions where the works can be efficiently delivered by external contractors. A number of the top 10 projects and others within the project list are suited to this form of contracting which would offload resources required by the TAO to deliver the more bespoke projects which have close integration with existing assets, are smaller scale and therefore more efficiently developed by the TAO’s in house knowledge.

The EPC market in particular is in its infancy in Ireland, however, the TAO is looking to expand the capacity and EPC is in use of a number of existing projects including CP0872 (West Dublin 220kV Station), CP1029 (Kellystown 220kV station), CP0933 (Thurles 110kV Statcom), CP0934 (Ballynahulla 220kV Statcom) and CP0925 (Ballyvouskill 220kV Statcom). The TAO’s experience from these projects to date has supported the view that EPC has benefits, but these are best seen for standardised solutions. With respect to D&B, the increase in contestable works for new connections has developed this capability in the Irish market which the TAO can look to utilise.

The addition of further delivery models such as EPC and D&B is a pragmatic mitigation by the TAO to achieve the step up in expenditure forecast in PR5 from previous years and is supported.

The TAO has also outlined its flexibility to adapt to non-standard ways of working to fit specific project needs where benefits outweigh the associated risks. An example has been provided for CP0646 (Finglas 110 kV GIS) which outlines a highly complex and interconnected scheme of works involving the DSO, TSO and TAO to ensure security of supply during the project. Early in the project development, it was identified that the standard approach to project development (project definition and planning by the TSO, delivery by the TAO) would present a high number of risks in terms of timely delivery due to the scope complexity, outage requirements and long lead materials. Therefore, for this project, the TAO became involved in the engineering and design works prior to planning permission to develop the optimum solution. This approach mitigated risks by addressing:

Planning Risk – standard development process would have required the TSO to decide on the design and apply for planning permission without sufficient input from the TAO and DSO. There was a high risk that subsequent detailed design would require a planning permission amendment or resubmission.

Outage Requirements – standard development process would have resulted in the TAO completing the scoping process without sufficient input from the TSO and DSO regarding forecast outage availability.

Long Lead Materials – standard development process does not allow for materials to be ordered until the scope of works is agreed (to protect customers and efficiency). However, as timing and sequencing was critical on this project (due to outage requirements and scope complexity) long lead materials such as switchgear and transformers were procured early in the project development to mitigate against delays.

The standard development process reflects the best balance of risk and protection for the customer for the vast majority of projects. However, this project illustrates the TAO’s ability and authority to be flexible and adapt in its delivery of projects where the need arises and where the risks/benefits support an alternate development process to ensure deliverability of critical projects. Such case studies give confidence to the TAO’s ability to deliver a range of project types, including those of high scope complexity in a timely manner, through being flexible whilst acknowledging the risk profile to the customer and managing appropriately.



9.5.4 Organisational Structure

The TAO has outlined that in order to support the necessary levels of deliverability a number of organisational structures and processes have been implemented including:

Establishment of a major projects delivery team in 2018 which offer experienced capacity to the increased use of EPC and D&B models. Furthermore, this structural and resourcing change has released capacity within the pre-existing project and customer delivery teams to focus on delivering more complex works in embedded brownfield sites.

Programme management and governance systems have been updated in line with international best practice to aid in project lifecycle planning and resource planning

Process improvements to enhance speed and certainty across the project lifecycle including formal project close out reports with associated lessons learned processes, batching of similar kings of work, increasing the number of standardised designs, use of modularised solutions and ‘lean’ project development processes. Such improvements are shortening the time from initiation to completion of projects, with particular prioritisation of the lean approaches to renewable projects to shorten connection time frames and support delivery of the climate action plan.

9.5.5 Summary

The TAO has illustrated confidence in deliverability through an understanding of the key risks, mitigation measures to address those risks so far as possible and stress testing of reasonably defined subset of projects to understand capacity and capability to achieve the PR5 programme. This has included an appreciation for the need for additional project delivery models such as D&B and EPC to support the TAO’s delivery capacity and evidence of historic flexible development and delivery approaches which can be utilised as necessary to deliver the most complex projects in a timely manner, whilst managing the risk profile to the customer appropriately. The TAO has also implemented a number of organisational changes to prepare for the deliverability challenges of PR5. The outcomes of this analysis has informed the factoring of the TSO’s project programme to an expenditure level which the TAO has shown confidence is able to deliver.

As a result, the deliverability assurance assessment presents a pragmatic and reasonable view of a level of expenditure and project deliverability for the PR5 period.

9.6 Line Assessments

During the PR4 period, the TAO has implemented layered overhead line investigations to better understand works required for line up rates and line refurbishments, typically resulting in the reduction or deferral of capital costs. These processes were namely the QRA (Qualitative Risk Assessment) which is focussed on foundations and the TLA (Transmission Line Assessment) which provides wider transmission line considerations beyond the foundations only.

The QRA process has resulted in reductions of overall project costs by €38.2m in PR4 to date and the TAO proposes to include the QRA process as part of business as usual in PR5. As an example, the original committed project parameters for CP0867 (Flagford Louth Line Refurbishment) provided an estimated cost of €36m to conduct the necessary works to extend the line life by 20 years. This was informed by an initial LPAR sample assessment which identified only 1 of 71 towers sampled had the required foundation strength. However, following a subsequent QRA which identified that only 187 of the 321 foundations required strengthening or other remedial works, the committed project parameters were revised to an estimated cost of



€16.3m. The result of the QRA represents a €20m saving in expenditure to achieve the required project outcomes as a result of the QRA process.

The TLA process is to be piloted in 2020 and, assuming benefits are seen, will also be implemented as business as usual in PR5.

The evidence has shown that the QRA process provides notable tangible benefits with respect to minimising project development costs and outage timescales. Similarly it is expected that the TLA process will provide similar benefits. The TAO should therefore be supported in conducting such processes as part of business as usual.

The TAO is advised that as part of bringing such processes into business as usual, the TAO should consider a post QRA/TLA note as a matter of standard documentation, which outlines the benefits gained by the assessment. This documentation will evidence the benefits of the process in a clear manner to internal and external stakeholders. Furthermore, where any projects do not proceed to capitalisation, post QRA/TLA, such documentation will allow evidence as to the appropriateness of the expenditure to support remuneration of any QRA/TLA costs that have not been capitalised.

9.7 Unit Cost Assessment

A high level benchmarking exercise has been carried out in order to assess the reasonableness of the unit costs in the Transmission BPQ; Section 4 – Performance Indicators; Table 4.2 Average Unit Costs. It is acknowledged that the TAO has engaged an external consultant (WSP) to critique and benchmark its costs and this assessment provides a further opinion on the reasonableness of those costs for the purposes of PR5 forecast costing.

9.7.1 Methodology

The benchmarking exercise has been carried out based on a comparison of the TAO unit costs against appropriate similar asset costs in the GHD database. Underlying assumptions and general basis of GHD unit costs is as follows:

GHD cost data is drawn from previous projects covering UK and international utilities, contractors and developers. Data is from a range of stages of planning and development including final project delivery costs, detailed quotations, and developer and utility budget costs.

UK utility data has been prioritised where possible due to the likely high comparability of the supply and installation conditions.

Project final costs and detailed quote data has been prioritised over budget costs.

All costs are as of mid-2019. Costs within the GHD database have been inflated to a 2019 basis from the source year via the use of material and product indexes and general inflation as appropriate to the specific asset considered.

For each benchmarked asset, as many comparable cost examples as possible have been identified within the GHD database and used to define a “reasonable” cost range, eliminating outlier values based on professional judgement.

The following assumptions and caveats have been applied in selecting and manipulating GHD database costs for benchmarking purposes:

Details of the assumptions and technical specifics underlying each unit cost from the TAO has not been provided. As such, the WSP report “TF01 AP03 Independent Expert Transmission Capex Unit Cost Benchmarking Report.pdf” has been used to supplement



the data contained within the BPQ table in order to tailor the GHD benchmarking cost data and provide a more robust benchmarking exercise.

Only total unit costs have been benchmarked, breakdown by material, employee, capitalised overhead and other has not been considered.

110kV unit costs have been benchmarked against 132kV equipment. The impact of this is not considered material.

In order to provide directly comparable costs, where necessary, uplift factors to account for items or aspects not included in the source data have been included. This is most commonly utilised to include capitalised overheads based on a 15% uplift.

Where necessary, due to limited availability of directly comparable costs, some extrapolation has been carried out from existing data based on professional judgement and experience. Examples where this is likely to be applied is to match a particular cable cross section or transformer capacity.

TAO unit costs have been compared to the identified reasonable cost range. Where the TAO unit cost falls within the range, the cost has been considered reasonable. Where the TAO cost falls outside the identified range, the reasonable margin of error and any specific factors which may skew the results have been considered as far as possible with the available data. All anomalous results have been reported in the below results section.

A detailed unit cost benchmarking exercise has been carried out by WSP and is reported in “TF01 AP03 Independent Expert Transmission Capex Unit Cost Benchmarking Report”. GHD benchmarking has been carried out on as great a proportion of the unit costs as reasonably possible and subsequently used to support or challenge the outcome of the WSP benchmarking exercise.

9.7.2 Results

Benchmarking results are summarised in Appendix A. TAO total average unit cost is shown for each asset type for information. The upper and lower boundaries of the GHD benchmark examples range is provided as a percentage of the TAO in house unit cost. The WSP benchmark result87 is likewise presented as a percentage of the TAO in house unit cost.

A number of rows which are present in the BPQ table but are not necessary for the benchmarking exercise have been removed from the table in order to simplify the presented results and reduce the overall table size. Lines removed from the table include;

Average transformer costs which is addressed through benchmarking of the specific transformer units.

Grass and night cable civil works costs for specific cable cross sections. These values are benchmarked as average values which are included in the table.

9.7.3 Discussion

Benchmarking for 77 of 87 unit costs has been conducted, where a suitable number of comparable costs are available to provide meaningful benchmarking analysis.

As shown in Appendix A the significant majority of the costs benchmarked fall within the reasonable benchmarking range. A small minority of costs have been identified as being worthy of note as follows:

87 TF01 AP03 Independent Expert Transmission Capex Unit Cost Benchmarking Report



400kV cable cost

TAO 400kV cable type is not defined in the BPQ table however, is assumed to be 2500mm2 Cu on the basis of the WSP benchmarking report. On this basis the TAO 400kV cable cost benchmarks notably lower than the expected range and the WSP benchmark analysis.

While the cost is notably lower it is not in itself a serious concern however, the TAO 400kV cable supply cost is reported as equal to the cost of 220kV 2500mm2 cable. 400kV cable would logically be expected to be greater cost per unit than 220kV cable and there is no obvious justification for the discrepancy.

Although there is an apparent inconsistency with this unit cost, only 2km of new 400 kV cable is proposed within the PR5 forecast (see Section 9.3.4), therefore the materiality of any discrepancy in this unit cost will not manifest as a significant impact on the forecast expenditure. The TAO should however consider reviewing the 400 kV cable cost in light of WSP and GHD feedback for future budget cost exercises.

110kV - 1000mm2 Cu Double Circuit (Xbond Trefoil, 165-187MVA) cost

The TAO cost is low compared to both the GHD and WSP benchmarking. One contributing factor to this is that the GHD benchmarking range is small due to a co-incidental high alignment of the source costs in this specific instance. A range of ±10-15% would be reasonable for 110kV cable supply and installation and would substantially reduce the TAO cost variance.

110kV - 1000mm2 Cu Double Circuit (Xbond Trefoil, 165-187MVA) & 110kV and 1000mm2 Cu XLPE cable Double Circuit (Xbond Trefoil, 165-187MVA) have been benchmarked against the same source examples due to a lack of fine granularity in specific cable construction in GHDs source data.

The variance is therefore not considered to be material and the costs are assessed as reasonable.

110kV - 1600mm2 Cu Double Circuit (SP bond Flat, 244-276MVA)

The TAO cost is high compared to both GHD and WSP benchmarking. Similarly to the above comment, one contributing factor to this is that the GHD benchmarking range is small. A typical distribution of comparable examples would substantially reduce the TAO cost variance.

The variance is therefore not considered to be material and the costs are assessed as reasonable.

Limitations to the GHD benchmarking exercise and notable observations ae summarised below:

Underground Cables

Only overall installed (road, day) cable costs have been benchmarked directly for all voltages and cross sections.

Average grass and roadway night costs have been benchmarked as a proportion of average roadway day installation costs for each voltage level.

EHV cable supply and installation costs are highly variable. Cable supply costs are significantly impacted by the buying power of the party with large orders or high volume customer’s able to negotiate significant per unit discounts. Cable installation costs are significantly influenced by local factors which result in difficulty benchmarking against



data taken from different countries. These factors are considered in the assessment of the reasonableness of unit costs.

Overhead lines

GHD benchmarking is based on a limited number of examples largely from outside of the UK. As a result the margin for error is relatively large. However, a reasonable correlation with the results of the WSP benchmarking is observable.

9.7.4 Conclusion of Assessment

On the basis of the sample benchmarked, it is reasonable to conclude the WSP benchmarking exercise to be reliable.

The WSP report concludes that “On average across all items benchmarked, the costs borne by the TAO are 101.3% of the WSP cost.”

The most notable variances identified within the WSP report are as follows:

110kV and 220kV 1600mm2 and 2500mm2 copper cable costs

TAO costs for copper cables (fully installed) is reported as between 25% and 33% greater than the WSP benchmark. This is reflected but to a lesser extent in the GHD benchmarking. As previously discussed, the unit cost of cable supply and installation is highly variable and while this trend is notable it is not necessarily evidence of an error.

Overhead lines

TAO are in a number of cases benchmarked above the WSP baseline by up to 30% in the worst case.

It is notable that overhead line unit costs are sensitive to volumes delivered and length of continuous line delivered and as such variance is not unexpected in unit costs based on averaging historic delivery costs.

As the quantity of new overhead line is forecast to be small in the PR5 period (see Section 9.3.4), the materiality of a higher overhead line unit cost is limited. Therefore, while this trend is noted, it is not anticipated to have a material impact on the PR5 forecasting.

Following this analysis, although some discrepancies have been identified by both GHD and WSP such as 400 kV unit costs, the materiality of those discrepancies is very limited within the PR5 budget forecast due to the insignificant quantity of affected assets within the PR5 programme. The unit costs used by the TAO (and TSO) are therefore considered to be reasonable for the purposes of PR5 budget pricing.

9.8 Review of Project List

It is the TSO’s responsibility to define the necessary projects to develop the network, with the TAO tasked with constructing those projects. The review of the project list from a TSO perspective has resulted in some conclusions which will have an impact on the TAO forecast expenditure. A summary of this review and its implications on the TAO forecast is:

CP0800 (North West Project (RIDP)) – This project is marked as on hold, however the TSO still has funding allocated against it in the final 2 years of PR5. This forecast expenditure is to be removed as the project has been effectively superseded. This results in a reduction of €30m from the TAO forecast expenditure



DSO Projects – DSO project spending over the PR5 period is forecast to increase from ~€10m to ~€40m from PR4 levels, the majority due to DSO pipeline projects. Justification for the forecast expenditure or what the likely requirements are have not been provided by the TSO. In the absence of justification at this time, a similar allowance to PR4 levels is proposed. This results in a reduction of €20.7m from the TAO forecast expenditure.

9.9 PR5 Summary and Conclusions

The purpose of this review has been to consider the levels and appropriateness of the TAO capital expenditure forecasted through the PR5 period, focussing on the ability to deliver efficient project and asset delivery. The submission data and information provided by the TAO has been used to inform this assessment. Where further clarity has been sought, questions have been asked of the TAO to provide further evidence and justification including, videoconferencing to explore and understand a number of key considerations.

The overarching TAO summary for PR5, in 2019 costs, is provided in Table 5-13.

Table 9-4 – Overarching Summary

PR5 Gross Forecast Expenditure (€m)

Proposed Gross Allowance (€m)

PR5 Net Forecast Expenditure (€m)

Proposed Net Allowance (€m)

1,126.2 1,075.5 969.9 919.2


The following summarises the general observations from the TAO forecast PR5 capital expenditure review:

PR5 net expenditure is forecast to increase by 35.7% (€255.1m), from €714.8m in the PR4 outturn to €969.9m in the PR5 forecast. The forecast expenditure profile anticipates a significant increase in expenditure in 2021 and 2022, greater than €250.0m (gross) per annum. Average annual expenditure increases from PR4 outturn of €143.0m to €194.0m in the PR5 forecast.

10 projects (of the 220 with forecast expenditure) dominate the PR5 forecast expenditure, forming approximately 40% of total gross expenditure in the period. These projects are large scale 400 kV projects, some of which have been subject to extensive delays over the PR4 period, in addition to a number of broader undefined projects particularly with respect to potential offshore wind associated developments.

The apportionment of expenditure against project categories suggests a significant reduction in ongoing projects from PR4 to PR5 (36% reduction) an increase in the number of new connections (up ~20%) and increase in asset refurbishment (up 17%). Ongoing project expenditure dominates the early years of the PR5 period, falling away as the period advances, illustrating the forecast completion of ongoing projects early in the period, particularly high value 400 kV projects. This trend in ongoing project expenditure gives reasoning to the overall step change in expenditure level early in the period (particularly 2021 and 2022) followed by a fall away in overall expenditure spend. Other project categories remain relatively consistent over the period in terms of level of expenditure, reflecting the anticipated consistent nature of new connections and asset refurbishment.

There are less individual projects forecast to be delivered in PR5 compared to PR4. However the value of individual projects is significantly higher. The number of projects with outturn expenditure in PR4 was 233, however the number of projects with proposed



expenditure in PR5 is 220. The average project spend in the PR4 outturn was €3.6m whilst in PR5 this increases to €5.1m (41.6% increase).

The quantity of new assets proposed to be delivered in the PR5 period is less than in PR4. However the profile of assets proposed to be delivered is changing, with a higher proportion of 400 kV works compared to 110 kV in previous periods. This reflects the assumed completion of key 400 kV projects in the PR5 period, some of which have been delayed from PR4. Furthermore, the TAO has noted that there will be an increase in overhead lines work on existing circuits (line refurbishment, uprates and cable replacements) in PR5 compared to PR4. Data from PR3 has been requested of the TAO but has not been received at the time of writing to further understand the acceleration of this trend from constructing new lines to refurbishing and uprating existing lines.

The TAO has implemented a number of formal schemes with the TSO to improve collaboration and full project lifecycle feedback loops and planning. Specifically the transmission outage plan and multi-year development plan allow for improved outage visibility and management. This will be a key mitigation feature in PR5 due to increased line uprates/refurbishments compared to previous years.

The TAO has conducted a deliverability assurance assessment on 86 sufficiently defined projects within the PR5 programme. The assessment considered key risks and the capacity of the TAO to deliver a step change in expenditure from PR4. Through this assessment, the TAO has exhibited a confidence in a level of deliverability in the order of €1.15bn and acknowledges that to achieve this step change, new contractor models such as D&B and EPC will be required to meet resourcing requirements. The TAO has also implemented organisational changes in preparation to the step change of deliverability and has evidenced how, when appropriate, the TAO can work flexibly, outside the standard development process, to the overall benefit of the customer by delivering complex projects timely and efficiently.

A review of asset unit costs, including a benchmarking exercise, has supported the suitability of the TAO unit costs for project costing purposes.

The TAO has developed layered transmission line assessments (LPAR, QRA and TLA) to support the TSO in project decision making and inform project requirements for the TAO. These schemes have been shown to save or defer capital investment (such as wholesale line up rates) in the PR4 period by reducing the works required to achieve a network performance outcome including a specific example on CP0867 (Flagford Louth Line Refurbishment) which resulted in a reduction in capital expenditure requirements of €20m. The application of these processes should therefore continue in PR5.


A review of forecast expenditure appropriateness, primarily driven by the review of the TSO submission, has identified some proposed changes which impact on the TAO forecast expenditure. In total, €50.7m is proposed to be removed from the TAO forecast expenditure, owing to insufficient justification of DSO projects and the superseding of the North West (RIDP) project. This would result in a TAO forecast expenditure (net) of €919.2m, an approximate 5% reduction from the initial submission.

The TAO’s LPAR/QRA/TLA processes have proven to be beneficial and it is agreed that the TAO should not be dis-incentivised to conduct such works if there is a risk that as a result of the works a project does not progress with capital investment and therefore costs cannot be capitalised and recovered. It is also understood that such occurrences are likely to be rare and the LPAR/QRA/TLA expenditure relatively low/ It is therefore



proposed that the TAO put in place robust documentation following a LPAR/QRA/TLA to support and justify expenditure which did not result in a capital project progressing and which can then be recovered.


Appendix A – Unit Cost Benchmarking Assessment

Asset

TAO Total average unit cost €k

Ratios for Benchmark

GHD Benchmark Range %

WSP Benchmark %

Notes

Low High

Overhead lines - circuit (kms) 400kV lines - single circuit SC 2*600mm2 ACSR (1km); 3.1-3.4 Towers per kM; Op Temp 80ºC 1,048.15

97.9

SC 2*996mm2 AAAC (1km); 3.1-3.4 Towers per kM; Op Temp 80ºC 1,207.21

99.5 400kV lines - double circuit

DC 2*600mm2 ACSR (1km); 3.1-3.4 Towers per kM; Op Temp 80ºC 1,831.66

93 93 84.5 DC 2*996mm2 AAAC (1km); 3.1-3.4 Towers per kM; Op Temp 80ºC 2,110.02

81 81 87.1

275kV lines - single circuit 1,024.07

77.2 220kV lines - single circuit SC 600mm2 ACSR (1km); 3.2-3.4 Towers per kM; Op Temp 80ºC 598.16

120 120 102.9 Non UK

benchmarking source

SC 996mm2 AAAC (1km); 3.1-3.4 Towers per kM; Op Temp 80ºC 852.75

80.3 220kV lines - double circuit DC 600mm2 ACSR (1km); 3.2-3.4 Towers per kM; Op Temp 80ºC 765.16

126 126 104.8 Non UK

benchmarking source

DC 996mm2 AAAC (1km); 3.1-3.4 Towers per kM; Op Temp 80ºC 1,035.68

101.4 110kV lines - single circuit SC 300mm2 ACSR (1km); 4.7-9.1 Woodpoles per kM; Op Temp 80ºC 268.37

85 85 98.8 Non UK

benchmarking source


Asset




WSP Benchmark %

Notes

Low High

SC 430mm2 ACSR (1km); 5.2-10 Woodpoles per kM; Op Temp 80ºC 287.29

94 94 115.7 Non UK benchmarking source

SC 300mm2 AAAC (1km); 4.7-9.1 Woodpoles per kM; Op Temp 80ºC 313.92


110kV lines - double circuit DC 430mm2 ACSR (1km); 5.9-6.2 Towers per kM; Op Temp 80ºC 661.93

78 84 100.4 Non UK

benchmarking source

DC 300mm2 ACSR (1km); 5.9-6.2 Towers per kM; Op Temp 80ºC 591.35


Underground cables - circuit (kms) 400kV XLPE cable Single Circuit - Cable Cost Only 1,305.86

Civil Costs Only - Grass 358.14 =0.51 x Road 98 118

Civil Costs Only - Roadway Day 703.06

Total Roadway Day Supply + Install for GHD Benchmarking 2,008.92

117 120 116.8 TAO cost notably low compared to GHD and WSP benchmarking.

Civil Costs Only - Roadway Night 1,102.72 =1.57 x Day 92 102

220kV SINGLE CIRCUIT - AVERAGE CABLE COSTS 1,179.18

220kV SINGLE CIRCUIT - AVERAGE CIVILS COSTS - Grass 332.88 =0.55 x Road 90 108

220kV SINGLE CIRCUIT - AVERAGE CIVILS COSTS - Road Day 601.35

220kV SINGLE CIRCUIT - AVERAGE CIVILS COSTS - Road Night 905.88 =1.51 x Day 96 106


Asset




WSP Benchmark %

Notes

Low High

220kV - 1600mm2 Cu SC (563-635 MVA) - Cable Cost Only 1,051.44


Total for Benchmarking 1,567.51

99 104 89.8 220kV - 2500mm2 Cu XLPE cable SC (740-835 MVA ) -Cable Cost Only 1,306.92



100 103 83.8

220kV DOUBLE CIRCUIT - AVERAGE CABLE COSTS 2,282.24

220kV DOUBLE CIRCUIT - AVERAGE CIVILS COSTS - Grass 687.23 =0.51 x Road 98 117

220kV DOUBLE CIRCUIT - AVERAGE CIVILS COSTS - Road Day 1,344.21

220kV DOUBLE CIRCUIT - AVERAGE CIVILS COSTS - Road Night 2,016.53 =1.5 x Day 97 107

220kV - 1600mm2 Cu cable DC (478-539 MVA ) -Cable Cost Only 2,025.54

Civil Costs Only - Roadway Day 1,334.89


87 93 77.5 220kV - 2500mm2 Cu XLPE cable DC (629-709 MVA ) -Cable Cost Only 2,538.93

Civil Costs Only - Roadway Day 1,353.53


97 104 80.8

110kV SINGLE CIRCUIT - AVERAGE CABLE COSTS 590.25

110kV SINGLE CIRCUIT - AVERAGE CIVILS COSTS - Grass 223.40 =0.65 x Road 77 92

110kV SINGLE CIRCUIT - AVERAGE CIVILS COSTS - Road Day 342.37

110kV SINGLE CIRCUIT - AVERAGE CIVILS COSTS - Road Night 498.47 =1.46 x Day 100 110

110kV - 1000mm2 Al Single Circuit (Xbond Trefoil, 160-181MVA)- Cable Cost Only 379.48


Total for Benchmarking 687.09

78 109 125.9 110kV - 1000mm2 Cu Single Circuit (Xbond Trefoil, 195-221MVA) 599.65



Asset




WSP Benchmark %

Notes

Low High


107 119 118.5 110kV - 1600mm2 Cu Single Circuit (SP bond Flat, 288-325MVA) - Cable Only 940.89



90 97 79.5

110kV - 1600mm2 Al XLPE cable Single Circuit (Xbond Trefoil, 195-221MVA) - Cable Only 494.33



78 101 114.0 110kV - 1000mm2 Cu XLPE cable Single Circuit (Xbond Trefoil, 195-221MVA) - Cable Only 747.65



92 103 118.5

110kV - 1000mm2 Al XLPE cable Single Circuit (Xbond Trefoil, 163-181MVA) - Cable Only 379.49



78 109 125.9 110kV DOUBLE CIRCUIT - AVERAGE CABLE COSTS 1,238.40

110kV DOUBLE CIRCUIT - AVERAGE CIVILS COSTS - Grass 354.75 =0.62 x Road 81 97

110kV DOUBLE CIRCUIT - AVERAGE CIVILS COSTS - Road Day 575.85

110kV DOUBLE CIRCUIT - AVERAGE CIVILS COSTS - Road Night 834.33 =1.45 x Day 100 110

110kV - 1000mm2 Al Double Circuit (Xbond Trefoil, 136-153MVA) 681.65



91 109 133.7

110kV - 1000mm2 Cu Double Circuit (Xbond Trefoil, 165-187MVA) 1,121.99



119 121 121.4 TAO cost notably low compared to GHD and


Asset




WSP Benchmark %

Notes

Low High

WSP benchmarking.

110kV - 1600mm2 Cu Double Circuit (SP bond Flat, 244-276MVA) 1,804.47



90 91 75.2 TAO cost notably high compared to GHD and WSP benchmarking.

110kV - 1000mm2 Cu XLPE cable Double Circuit (Xbond Trefoil, 165-187MVA) 1,345.50



104 105 118.2 Switchgear (units) New 400kV Line Bay AVERAGE AIS-GIS 2,016.00

New 400kV Line Bay in existing 400kV AIS DBB OD Stn. (Strung/Tubular Busbar) 1,527.28

111.0 New 400kV Line Bay in existing 400kV GIS DBB ID Stn. (Strung/Tubular Busbar) 2,504.72

61 104 103.4

New 220kV Substation Bay AVERAGE AIS & GIS 220kV Bays 1,167.62

New 220kV Substation Bay AVERAGE AIS ONLY 220kV Bays 1,021.56

105.8

New 220kV Substation Bay AVERAGE GIS ONLY 220kV Bays 1,313.68

84 118 103.1 Install New 110kV AIS Circuit Breaker excluding Civil works 113.52

119.6

Transformers (per unit) - incl. tap changers & reactors 400/220kV 500MVA Transformer 6,652.01

78 121 100.8

275/220kV 500MVA Transformer (TSDC S275-2) 6,398.02

97.6 220kV/110kV 250MVA Transformer 4,174.05

90 113 105.6

220/110kV 500MVA Transformer 6,026.44

92 132 88.2


Asset




WSP Benchmark %

Notes

Low High

400/110kV 250MVA Transformer 5,681.27

80 102 94.4 400/110kV 500MVA Transformer 6,319.27

74 104 102.6

Transformer 31.5 MVA 100/38kV excl Civils (TSDC STSC-45) 1,179.82

79 102 104.8



Appendix B – Sustainability & Decarbonisation Initiative Detail

As detailed in Section 7.5, as part of their PR5 submission the TSO has presented three new initiative groups with additional requested capital expenditure over and above their Business As Usual activities. This sub-section reviews the EirGrid proposal for the Sustainability and Decarbonisation initiative group, which broadly encompasses:

• Establishing New Process & Tools (including these related to Renewable Strategy, Control Centre Tools and Outage Management and the Clean Energy Package)

• Strengthen Data and Communication (including Digital Telecoms and Data Services)

• Promoting Informed Choices (including Network Planning and Promoting Change)

A summary of the requested capital and operating expenditure for these individual initiatives within the Sustainability & Decarbonisation group is now presented.

Renewables Strategy DS3+ The TSO has outlined their proposed submission in relation to facilitating further renewable generation integration and system operation, including potential impacts on DS3 system services in Table C.2 of their PR5 submission.

Table B.1 – Requested Renewables DS3+ Non-Network Capex

Category Capex, €m Payroll Staff Costs (13.5 FTE’s) Professional Fees IT Development Costs Research Costs Scheduling Systems Services With New Technologies

1.5

Digital Performance Monitoring 1.5 RES Telecommunications LAB 0.8 DSM at Residential Level - Pilot 1.5 (DSM at Residential Level – Roll Out 2.3 TSO-DSO Interface 3.0 Settlement System 1.5 Capital Expenditure Total 12.0*

* EirGrid values – slightly lower than summated values due to rounding

Control Centre Tools The TSO has outlined their proposed submission in relation to funding new and upgraded control centre tools and functionality which they indicated will be required to oversee, control and optimally manage the electricity transmission system during PR5 and into PR6 in order to facilitate further renewable generation. The specific individual investments for control centre tools are presented by the TSO in Table C.5 of their PR5 submission.

Table B.2 - Requested Control Centre Tools Non-Network Capex

Category Capex, €m Payroll Costs



Category Capex, €m Ongoing License Support Programme Design & High Level Solution Design 0.2 Common Dispatch Mechanism and Comms. Design

0.7

Control Centre Data Store 0.3 Renewable Energy Sources Dispatch 0.4 Small Scale Generation Aggregation / Dispatch 0.4 Demand Side Unit Dispatch 0.4 Storage Control Management 0.4 System Services Scheduling for Renewable Energy Systems

0.4

Enhanced RES Forecasting 0.6 Enhanced Demand Forecasting 0.7 Additional Forecasting Data Sources 0.2 Capital Expenditure Total 4.4*


Outage Management Systems The TSO has outlined their proposed submission in relation to funding new and upgraded outage management systems and functionality which they indicated will be required to oversee, control and optimally manage the electricity transmission system during PR5 and into PR6 in order to facilitate further renewable generation. The specific individual investments for outage management systems is presented by the TSO in Table C.8 of their PR5 submission.

Table B.3 – Requested Outage Management Systems Non-Network Capex

Category Capex, €m Solution Implementation and Validation Payroll Costs Analysis and Solution Specification 0.1 Procurement and Supplier Selection 0.1 Solution Implementation and Validation 1.1 Hypercare During Initial Period of Operation 0.1 Capital Expenditure Total 1.4*


**Originally entered as capex (assumed error)

Clean Energy Package The TSO has outlined their proposed submission in relation to facilitating measures proposed in new EU legislation, which they indicated will be required to remain in compliance with this directive during PR5 and into PR6. The specific individual investments to implement this framework are yet to be identified, this work is expected to identify measures to implement this directive. The investment required is presented by the TSO in Table C.11 of their PR5 submission.

Table B.4 – Requested Clean Energy Package Non-Network Capex

Category Capex, €m Professional Fees 0.4 Capital Expenditure Total 0.4



IP Migration The TSO has outlined their proposed submission in relation to funding new and upgraded telecommunications services and functionality through an operational IP model, which they indicated will be required to oversee, control and optimally manage the electricity transmission system during PR5 and into PR6 in order to facilitate network buildout, further renewable generation and smart grid technologies. The specific individual investments for telecommunications services and functionality is presented by the TSO in Table C.12 of their PR5 submission.

Table B.5 – Requested IP Migration Non-Network Capex

Category Capex, €m System IP Migration 2.9 Capital Expenditure Total 2.9*


Data Science The TSO has outlined their proposed submission in relation to facilitating further renewable generation integration and system operation through enhanced data services, including more complex power systems analysis studies in Table C.14 of their PR5 submission.

Table B.6 – Requested Data Science Non-Network Capex

Category Capex, €m Data Strategy Development 0.1 Detailed Business and Data Requirements Documented

0.1

Data Warehouse Design and Data Extraction Tools Analysis

0.1

Analytic Tools Assessment 0.1 Capital Expenditure Total 0.4*




Appendix C – Operate, Develop & Enhance Grid & Market Initiative Detail

As detailed in Section 7.5, as part of their PR5 submission the TSO has presented three new initiative groups with additional requested capital expenditure over and above their Business As Usual activities. This sub-section reviews the EirGrid proposal for the Operate, Develop & Enhance Grid & Market initiative group, which broadly encompasses:

• Developing New Processes & Tools – including those related to access planning and connection management, developing a metering system, a mixed integer planning solver,

• Improving System and Market Standards and Practises – including those related to European network codes, capacity market secondary trading, DSU compliance with state aid, the electricity balancing guideline, and multi-NEMO arrangements in the SEM,

• Improving Support Systems and Security – including physical security, cyber security, operational IT support and control centre training.

A summary of the requested capital and operating expenditure for these individual initiatives within the Operate, Develop and Enhance Grid and Market group is now presented.

Control Centre Training The TSO has outlined their proposed submission in relation to improving and modernising control centre training, which they indicated will be required to oversee, control and optimally manage the electricity transmission system during PR5 and into PR6, in Table D.7 of their PR5 submission.

Table C.1 – Requested Control Centre Training Non-Network Capex

Category Capex, €m Professional Fees 0.7 Software Licencing Cost 0.6 Systems Implementation 1.5 Capital Expenditure Total 2.8

Physical Security Technology Replacement and Enhancement The TSO has outlined their proposed submission in relation to implementing and improving existing physical security infrastructure systems, which they indicated will be required to securely and safely operate the electricity transmission system during PR5 and into PR6, in Table D.11 of their PR5 submission.

Table C.2 – Requested Physical Security Technology Replacement and Enhancement Non-Network Capex

Category Capex, €m Capital Equipment 1.1 Systems Implementation 0.6 Capital Expenditure Total 1.7

Cyber Security The TSO has outlined their proposed submission in relation to implementing and improving existing cyber security infrastructure systems, which they indicated will be required to securely



and safely operate the electricity transmission system during PR5 and into PR6, in Table D.11 of their PR5 submission.

Table C.3 – Requested Cyber Security Non-Network Capex

Category Capex, €m Capital Equipment 0.5 Capital Expenditure Total 0.5

Capacity Market Secondary Trading The TSO has outlined their proposed submission in relation to developing and implementing a market for secondary trading of awarded capacity between generators, in Table D.21 of their PR5 submission.

Table C.4 – Requested Capacity Market Secondary Trading Non-Network Capex

Category Capex, €m Professional Fees 0.3 Systems Implementation 0.9 Other 0.3 Capital Expenditure Total 1.5

Demand Side Unit (DSU) Compliance with State Aid The TSO has outlined their proposed submission in relation to redesigning the Demand Side Unit capacity market, which they indicated will be required to remain in compliance with a state aid decision taken by the European Commission, is set out in Table D.24 of their PR5 submission.

Table C.5 – Requested Demand Side Unit Non-Network Capex

Category Capex, €m Licences 0.2 Systems Implementation 1.7 Other 0.9 Capital Expenditure Total 2.8

Implementing a Mixed Integer Programming Solver The TSO has outlined their proposed submission in relation to implementing a Mixed Integer Programming Solver, which they indicated will be required to reform their auction methodology in the capacity market in order to improve outcomes from capacity auctions and Net Social Welfare, is set out in Table D.28 of their PR5 submission.

Table C.6 – Requested Mixed Integer Programming Solver Non-Network Capex




State Aid Cross Border Capacity The TSO has outlined their proposed submission in relation to implementing European legislation to liberalise energy markets, with the aim of creating a liberalised single energy market. This approach is set out in Table D.31 of their PR5 submission.

Table C.7 – Requested State Aid Cross Border Non-Network Capex


It is not clear to what extent this initiative relies on the implementation of other initiatives laid out in the Operate, Develop and Enhance market, but given that the DSU market also requires reform to comply with European state aid rules, it may seem appropriate to treat these work packages as one to ensure consistency when market rules are written.

Metering System The TSO has outlined their proposed submission in relation to implementing a new metering system across the transmission system, which they indicated will be required to oversee and optimally manage the transmission system during PR5 and into PR6. This approach is set out in Table D.39 of their PR5 submission.

Table C.8 – Requested Metering System Non-Network Capex

Category Capex, €m Professional Fees 0.2 Hardware / Software 0.2 Licences 0.8 Other 1.8 Capital Expenditure Total 3.0

Electricity Balancing Guideline The TSO has outlined their proposed submission in relation to implementing a specific part of the European Network Codes – the electricity balancing guideline, which sets out rules for the integration of European balancing markets and through the harmonisation of electricity balancing rules. The costs of this are subject to reopener, but the general approach is set out in section 14.5 of their PR5 submission.

Table C.9 – Requested Electricity Balancing Guideline Non-Network Capex

Category Capex, €m Capital Expenditure Total 26.5

The specific costs required to implement the EBGL have not been broken down, aside from a reference to costs estimated by the UK National Grid for implementation which are broadly similar. It is likely that the implementation of the EBGL will come at significant expense, and it is unclear if the benefits from early implementation will be worth the costs required to do so while uncertainty remains about the UK’s future in the wider European energy market.

Multi NEMO Arrangements The TSO has outlined their proposed submission in relation to allocation of cross-zonal capacity and congestion management, which require the development, implementation and maintenance of algorithms, systems and procedures required of markets coupled under the multi NEMO



framework. The costs of this are subject to reopener, but the general approach is set out in section D.14.4 of their PR5 submission.

Table C.10 – Requested Multi NEMO Arrangements Non-Network Capex

Category Capex, €m Capital Expenditure Total 10.5

The specific costs required to implement multi-NEMO arrangements have not been broken down. Similarly to the EBGL it is likely that the implementation of the Multi-NEMO framework will come at significant expense, and it is unclear if the benefits from early implementation will be worth the costs required to do so while uncertainty remains about the UK’s future in the wider European energy market.



Appendix D – Engage for Better Outcomes Initiative Detail

As detailed in Section 7.5, as part of their PR5 submission the TSO has presented three new initiative groups with additional requested capital expenditure over and above their Business As Usual activities. This sub-section reviews the EirGrid proposal for the Engage for Better Outcomes initiative group, which broadly encompasses:

• Education & Engagement

• Enhanced Customer Journey

• Developing The Grid Framework

A summary of the requested capital and operating expenditure for these individual initiatives within the Engage for Better Outcomes group is now presented.

Developing the Grid Framework The TSO has outlined their proposed submission in relation to the improvement of internal EirGrid processes related to guiding principles for consultation, ensuring consistency of information and managing feedback and complaints. The costs of this approach is set out in Table E.8 of their PR5 submission.

Table D.1 – Requested “Developing the Grid Framework” Non-Network Capex

Category Capex, €m Payroll Costs 1.7* Professional Fees 0.3 Licences 1.1 Hardware / Software 0.7 Capital Expenditure Total 3.8**

*This expenditure was all designated as capex, this is assumed to be an error

**Different total to EirGrid calculation due to rounding up rather than down.

The objectives sought by this work package are justifiable and important going forward, however it is unclear whether the amount of expenditure justified is reasonable, as most of these objectives should be able to be developed and implemented during the normal course of business by existing personnel.



GHD

Level 1 49-51 Grey Street Newcastle Upon Tyne NE1 6EE T: 44 191 731 6100 E: [email protected]

© GHD 2020

This document is and shall remain the property of GHD. The document may only be used for the purpose for which it was commissioned and in accordance with the Terms of Engagement for the commission. Unauthorised use of this document in any form whatsoever is prohibited.

Document Status

Rev. Author Reviewer Approved for Issue Name Signature Name Signature Date

Final V0

CEPA/GHD R. Clark

R. Clark

22/06/20

Final V1

CEPA/GHD R. Clark

R. Clark

01/07/20

Final V1.1

CEPA/GHD R. Clark

R. Clark

14/07/20

Final V1.2

CEPA/GHD R. Clark

R. Clark

21/07/20

www.ghd.com www.ghd.com