Decision 23571-D01-2019
EPCOR Distribution & Transmission Inc.
2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One
April 12, 2019
Alberta Utilities Commission Decision 23571-D01-2019 EPCOR Distribution & Transmission Inc. 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One Proceeding 23571
April 12, 2019
Published by the: Alberta Utilities Commission Eau Claire Tower, 1400, 600 Third Avenue S.W. Calgary, Alberta T2P 0G5
Telephone: 403-592-8845 Fax: 403-592-4406
Website: www.auc.ab.ca
The Commission may, within 30 days of the date of this decision and without notice, correct typographical, spelling and calculation errors and other similar types of errors and post the corrected decision on its website.
Contents
1 Decision summary ...... 1
2 Introduction and procedural background ...... 1
3 Background ...... 3
4 Commission process for reviewing the 2017 capital tracker true-up application ...... 3
5 Overview of programs and projects included in the 2016 capital tracker true-up application ...... 5
6 Grouping of projects for capital tracker purposes ...... 8
7 Project assessment under Criterion 1 – the project must be outside the normal course of the company’s ongoing operations ...... 9 7.1 Common issues ...... 9 7.1.1 Allocated overhead ...... 9 7.1.2 Affiliate transactions ...... 11 7.1.2.1 Evaluation of EPCOR’s affiliate transactions ...... 14 7.1.2.2 Engineering and drafting technology services ...... 17 7.1.2.3 Civil construction services for cable replacement ...... 20 7.1.2.4 Construction, maintenance and repair of security lighting systems and pole replacement work ...... 23 7.1.2.5 Hydro-excavation dispatch and dewatering services and directional drilling services ...... 25 7.1.2.6 Power base and/or pedestal repair and other jobbing services (thumping, fibre installation and streetlight installation and repairs) 27 7.1.3 Asset usage fees ...... 29 7.1.4 Controls and accountability ...... 29 7.2 Capital tracker programs or projects for which no issues were raised ...... 30 7.2.1 Third-Party Driven Relocations Program ...... 30 7.2.2 Capitalized Underground System Damage Project...... 31 7.2.3 New Underground and Aerial Service Connections for Commercial, Industrial, Multi-Family and Miscellaneous Customers ...... 32 7.2.4 Underground Residential Distribution Servicing - Rebates, Acceptance Inspections and Terminations ...... 33 7.2.5 Poundmaker Feeders ...... 33 7.2.6 Outage Management System/Distribution Management System Life Cycle Replacement ...... 34 7.2.7 Underground Industrial Distribution Servicing – Rebates, Acceptance Inspections and Terminations ...... 34 7.2.8 Replacement of Faulted Distribution PILC Cables ...... 35 7.2.9 Neighbourhood Renewal ...... 35 7.2.10 Customer Revenue Metering ...... 36 7.2.11 IT Hardware Lifecycle Replacements and Additions ...... 38 7.2.12 Manhole Rebuilds and Life Cycle Replacements ...... 38 7.2.13 Network Reconfigurations ...... 39
Decision 23571-D01-2019 (April 12, 2019) • i
7.2.14 Street Light Service Connections and Security Lighting Addition and Capital Replacement ...... 40 7.2.15 Commission findings on EPCOR’s capital tracker programs or projects for which no issues were raised ...... 41 7.3 New 15-kV and 25-kV Circuit Additions ...... 41 7.4 New Underground Cable and Aerial Line Reconfigurations and Extensions to Meet Customer Growth ...... 45 7.5 Capital Tools and Instrument Purchases ...... 50 7.6 Capitalized Aerial System Damage ...... 51 7.7 Service Centre Redevelopment and Life Cycle Replacements ...... 54 7.8 Vehicles – Growth and Life Cycle Replacement Project ...... 58 7.8.1 Compliance with Direction 8 of Decision 22672-D01-2018 ...... 59 7.8.2 Vehicles – Growth and Life Cycle Replacement Project for 2017 ...... 60 7.8.2.1 Fleet additions to account for growth ...... 61 7.8.2.2 Life cycle replacements of vehicles ...... 62 7.8.2.3 Purchase of hired fleet vehicles ...... 64 7.9 Replacement of Aerial Ground Rod and Underground Distribution Equipment Ground Grid ...... 69
8 Accounting test under Criterion 1 – the project must be outside of the normal course of the company’s ongoing operations, and Commission conclusion on Criterion 1 ...... 73 8.1 Accounting test for the 2017 true-up ...... 73 8.1.1 Accounting test model adjustments ...... 73 8.1.2 Accounting test assumptions...... 74 8.1.2.1 Cost of debt ...... 75 8.2 Commission’s conclusions on Criterion 1 ...... 81
9 Criterion 2 – ordinarily the project must be for replacement of existing capital assets or undertaking the project must be required by an external party ...... 81
10 Criterion 3 – the project must have a material effect on the company’s finances ...... 83
11 EPCOR’s compliance with Commission directions ...... 84
12 2017 true-up application K factor calculations ...... 84
13 Service quality and asset monitoring ...... 85
14 Order ...... 87
Appendix 1 – Proceeding participants ...... 89
Appendix 2 – Summary of Commission directions ...... 90
Appendix 3 – EPCOR’s prior capital tracker-related decisions ...... 92
List of tables
Table 1. Applied-for 2017 K factor true-up adjustments ...... 5
Table 2. 2017 capital tracker programs or projects capital additions ...... 7 ii • Decision 23571-D01-2019 (April 12, 2019)
Table 3. EPCOR’s capital overhead pool 2012-2017 ...... 10
Table 4. EPCOR distribution functions capital overhead rate 2012-2017 ...... 11
Table 5. EPCOR’s affiliate services ...... 12
Table 6. Detailed breakdown of EPCOR’s affiliate services ...... 13
Table 7. 2017 AUF forecast compared to actual ...... 29
Table 8. 2017 new 15-kV and 25-kV circuit additions ...... 42
Table 9. 2017 third-party damages recovered under capitalized aerial system damage .. 53
Table 10. 2015-2017 costs incurred due to third-party system damages ...... 53
Table 11. Service Centre Redevelopment Project 2015-2017 capital additions ...... 56
Table 12. Cost breakdown of multi-purpose area ...... 57
Table 13. Distribution fleet (vehicles and related equipment) 2017 forecast and actual capital additions ...... 60
Table 14. 2017 capital additions new distribution fleet vehicles and related fleet equipment ...... 61
Table 15. 2017 forecast and actual capital additions distribution fleet vehicles and related equipment life cycle replacements ...... 63
Table 16. 2017 hired fleet capital additions ...... 65
Table 17. Total number of rental vehicles and vehicles converted to purchased units EDTI’s distribution function 2013-2017 ...... 66
Table 18. EPCOR’s 2017 capital tracker true-up accounting test assumptions ...... 74
Table 19. Interest rates EPCOR considered in determining its credit risk premium ...... 76
Table 20. Calculation of EPCOR’s embedded interest rate on its 2017 promissory notes . 76
Table 21. Applied-for 2017 capital tracker programs or projects and Criterion 2 requirements ...... 82
Decision 23571-D01-2019 (April 12, 2019) • iii
Alberta Utilities Commission Calgary, Alberta
EPCOR Distribution & Transmission Inc. 2017 Performance-Based Regulation Capital Tracker True-Up Decision 23571-D01-2019 Module One Proceeding 23571
1 Decision summary
1. This decision provides the Alberta Utilities Commission’s determination of EPCOR Distribution & Transmission Inc.’s (EPCOR or EDTI) 2017 capital tracker true-up for Module One of Proceeding 23571. For the reasons outlined in this decision, the Commission has determined that:
EPCOR’s proposed grouping of projects into programs is reasonable. The need for the capital tracker projects or programs included in the 2017 true-up has previously been confirmed in prior capital tracker decisions. The actual scope, level, timing and costs of each of the projects or programs included in the 2017 true-up was prudent with the exception of the following: o Vehicles – Growth and Life Cycle Replacements Project; and o Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project. EPCOR must recalculate its 2017 embedded cost of debt using Commission-approved comparator companies’ credit risk premiums and must recalculate its 2017 weighted average cost of capital (WACC), its accounting test and K factor true-up for 2017, based on these revisions. A reassessment of whether the capital tracker projects or programs included in EPCOR’s 2017 true-up satisfy the accounting test requirement of Criterion 1 is required. The previously approved capital tracker projects or programs included in EPCOR’s 2017 true-up continue to satisfy the requirements of Criterion 2. A reassessment of whether the capital tracker projects or programs included in EPCOR’s 2017 true-up satisfy the two-tiered materiality test requirement of Criterion 3 is required.
2. Based on the above findings, the Commission has directed EPCOR to revise its accounting test for 2017 in a compliance filing.
2 Introduction and procedural background
3. On May 17, 2018, EPCOR filed an application with the Commission requesting approval of its 2017 capital tracker true-up amount and associated K factor adjustment to be reflected in its distribution rates under performance-based regulation (PBR). EPCOR also requested approval
Decision 23571-D01-2019 (April 12, 2019) • 1 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
for two projects on an actual basis for 2017. In Decision 2012-2371 and in Decision 2013-435,2 the Commission indicated that a company may choose to undertake a capital investment prior to applying for capital tracker treatment. In other words, capital tracker treatment may be granted on the basis of actual capital expenditures, without prior approval of capital forecasts for a project. These two projects were:
Vehicles – Growth and Life Cycle Replacements Project.
Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project.
4. The Commission assigned Proceeding 23571 to the application and on May 22, 2017, the Commission issued a notice of application that required interested parties to submit a statement of intent to participate (SIP) by May 28, 2018. The Commission received SIPs from the Consumers’ Coalition of Alberta (CCA) and the Office of the Utilities Consumer Advocate (UCA), both of whom requested an opportunity to test EPCOR’s application with a round of information requests (IRs) before commenting on the need for further process.
5. Included in EPCOR’s application was a request for approval “to include the costs associated with the METSCO [Energy Solutions Inc.] Framework and Models as capital additions in projects with respect to which EDTI has used and in the future will use the METSCO Framework and Models as a key component of its asset management and capital planning process.”3 On July 17, 2018, the Commission issued a ruling bifurcating Proceeding 23571 into two modules: non-METSCO-related matters (Module One) and METSCO-related matters (Module Two).4 This decision comprises the Commission’s determinations with respect to Module One.
6. The Commission also issued procedural rulings concerning confidential treatment of some documents5 and rulings concerning further responses to information requests.6
7. All parties submitted argument and reply argument on January 10, 2019, and January 18, 2019, respectively, with the latter date constituting the close of record for this proceeding.
8. In reaching the determinations set out within this decision, the Commission has considered all relevant materials comprising the record of this proceeding, as well as relevant portions of the records considered by the Commission in prior EPCOR capital tracker proceedings as referenced throughout this decision. Accordingly, references in this decision to specific parts of the records are intended to assist the reader in understanding the Commission’s reasoning relating to a particular matter and should not be taken as an indication that the
1 Decision 2012-237, paragraphs 614-615. 2 Decision 2013-435, paragraph 48. 3 Proceeding 23571, Exhibit 23571-X0002.01, paragraph 108. 4 Proceeding 23102, Commission-Initiated Proceeding Concerning METSCO’s Risk-Based Asset Management Framework for ENMAX and EPCOR. 5 Exhibit 23571-X0123, AUC letter – Ruling on motion for confidential treatment of information and further process, August 10, 2018. 6 Exhibit 23571-X0198, AUC letter – Ruling on EPCOR’s motion to compel full and adequate responses, and process schedule update, December 11, 2018.
2 • Decision 23571-D01-2019 (April 12, 2019) 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
Commission did not consider all relevant portions of the records with respect to a particular matter.
3 Background
9. On September 12, 2012, the Commission issued Decision 2012-237,7 which set out the PBR framework and approved PBR plans for the distribution utility services of certain Alberta electric and gas companies (collectively, the distribution utilities), including EPCOR. Within these PBR plans, the Commission approved a rate adjustment mechanism to fund certain capital- related costs. This supplemental funding mechanism was referred to in Decision 2012-237 as a “capital tracker” with the revenue requirement associated with approved amounts to be collected from ratepayers by way of a “K factor” adjustment to the annual PBR rate-setting formula.
10. At paragraph 592 of Decision 2012-237, the Commission set out the criteria that a capital project or program would have to satisfy in order to receive capital tracker treatment approval. The implementation and application of these criteria and the K factor calculation methodology were considered in a 2013 capital tracker proceeding, leading to Decision 2013-435.8 The implementation methodology established in Decision 2013-435 is, and has been, used to evaluate the capital tracker projects or programs proposed by the distribution utilities throughout the five- year PBR term over the 2013 to 2017 time period.
11. Subsequent to the release of Decision 2013-435, each distribution utility has filed separate capital tracker applications on an annual basis for its specific capital trackers. Section 2.1 of Decision 20407-D01-2016,9 which addressed EPCOR’s 2014 capital tracker true-up and 2016-2017 capital tracker forecast, provides a comprehensive overview of the capital tracker approach under PBR. EPCOR’s last application was filed in 2017 and led to the release of Decision 22672-D01-2018,10 dealing with EPCOR’s 2016 capital tracker true-up. A summary of EPCOR’s prior capital tracker-related decisions and resulting approved K factor amounts is attached as Appendix 3 to this decision.
4 Commission process for reviewing the 2017 capital tracker true-up application
12. The Commission’s process for reviewing the 2017 capital tracker true-up application followed the same steps as those set out in Section 3 of Decision 20407-D01-2016. The three criteria that must be satisfied in order for each project or program to receive capital tracker treatment are:
Criterion 1 – The project must be outside the normal course of the company’s ongoing operations.
7 Decision 2012-237: Rate Regulation Initiative, Distribution Performance-Based Regulation, Proceeding 566, Application 1606029-1, September 12, 2012. 8 Decision 2013-435: Distribution Performance-Based Regulation 2013 Capital Tracker Applications, Proceeding 2131, Application 1608827-1, December 6, 2013. 9 Decision 20407-D01-2016: EPCOR Distribution & Transmission Inc., 2014 PBR Capital Tracker True-Up and 2016-2017 PBR Capital Tracker Forecast, Proceeding 20407, February 7, 2016. 10 Decision 22672-D01-2018: EPCOR Distribution & Transmission Inc., 2016 Performance-Based Regulation Capital Tracker True-Up, Proceeding 22672, January 4, 2018.
Decision 23571-D01-2019 (April 12, 2019) • 3 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
Criterion 2 – Ordinarily the project must be for replacement of existing capital assets or undertaking the project must be required by an external party.
Criterion 3 – The project must have a material effect on the company’s finances.
13. The Commission indicated it would generally undertake assessments with respect to all three criteria for capital tracker treatment for all capital projects or programs that the Commission has not considered in prior capital tracker decisions. In this decision, the Commission undertook this assessment for EPCOR’s:
Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project
Vehicles – Growth and Life Cycle Replacements Project because they were not approved previously for capital tracker treatment.
14. For previously approved capital tracker projects or programs, the Commission did not undertake a reassessment of need under Criterion 1 in the absence of evidence that the project or program was no longer required. However, the Commission did assess the scope, level and timing of each project or program for prudence, and whether the actual costs of the project or program were prudently incurred, as required by the second part of the project assessment under Criterion 1.
15. Finally, EPCOR included in the 2017 K factor calculations, capital tracker programs or projects that have been completed (e.g., Poundmaker Feeders) or suspended (e.g., Neighbourhood Renewal), for which the Commission has previously approved actual costs in 2013 or 2014. For such projects, the Commission did not re-evaluate either the need for the project, or the prudence of the scope, level and timing of the project and associated costs as part of the project assessment under Criterion 1. Similarly, the Commission did not repeat the assessment under Criterion 2. However, the Commission did assess the accounting test component of Criterion 1, as well as materiality under capital tracker Criterion 3. The Commission will undertake a project assessment for any capital tracker project, for which the actual costs were not previously approved by the Commission, and at the time a suspended project is resumed.
16. The remaining sections of this decision are organized as follows:
Section 5 of this decision provides an overview of the programs or projects for which EPCOR has sought capital tracker true-up in 2017 on an actual basis.
The evaluation of EPCOR’s proposed capital project groupings is set out in Section 6.
The assessment of EPCOR’s programs or projects proposed for capital tracker treatment under Criterion 1 is set out in sections 7 and 8 dealing with the project assessment and the accounting test, respectively.
The Commission’s assessment under Criterion 2 is undertaken in Section 9 and the assessment under Criterion 3 is set out in Section 10.
4 • Decision 23571-D01-2019 (April 12, 2019) 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
Section 11 deals with EPCOR’s compliance with Commission directions.
Finally, Section 12 deals with the K factor calculation methodology and the K factor true-up for 2017.
5 Overview of programs and projects included in the 2016 capital tracker true-up application
17. As part of the 2017 capital tracker true-up, EPCOR applied for the true-up of 25 programs or projects approved by the Commission for capital tracker treatment on a forecast basis in Decision 20407-D01-2016, with subsequent updates approved in the compliance filing Decision 21430-D01-2016.11 As noted above, EPCOR also applied for the true-up of the following programs and projects in this application, on the basis that they satisfy all capital tracker criteria for 2017 on an actual basis:12
Vehicles – Growth and Life Cycle Replacements Project.
Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project.
18. Further details of these projects are provided in Section 7.8 and Section 7.9 of this decision, respectively.
19. The projects and programs included in the 2017 capital tracker true-up (2017 actual K factor) and the variance from the approved forecast (2017 decision K factor), resulting in a proposed K factor true-up for 2017, are set out in Table 1. Some of these proposed amounts are subject to change as a result of the Commission’s directions within this decision, as set out in the subsequent sections.
Table 1. Applied-for 2017 K factor true-up adjustments 2017 approved 2017 applied- Program/Project name forecast for actual Variance K factor13 K factor14 ($ million) 1 Third-Party Driven Relocations 4.09 3.55 (0.54) 2 Life Cycle Replacement and Extension of Underground Distribution Cable* 2.97 4.01 1.03 3 New 15-kilovolt (kV) and 25-kV Circuit Additions 1.81 1.89 0.09 New Underground Cable and Aerial Line Reconfigurations and 4 1.72 2.22 0.50 Extensions to Meet Customer Growth 5 Distribution Pole and Aerial Line Life Cycle Replacements* 0.54 0.97 0.43 Aerial and Underground Distribution Transformers - New Services 6 1.00 1.11 0.11 and Life Cycle Replacement* 7 Capitalized Underground System Damage 0.94 1.43 0.50
11 Decision 21430-D01-2016: EPCOR Distribution & Transmission Inc., 2014 True-Up and 2016-2017 Forecast PBR Capital Trackers Compliance Filing, Proceeding 21430, July 12, 2016. 12 Exhibit 23571-X0002.01, application, paragraph 19. 13 Decision 21430-D01-2016, Table 7. 14 Exhibit 23571-X0002.01, application, paragraph 25, Table 2.1.4-1.
Decision 23571-D01-2019 (April 12, 2019) • 5 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
2017 approved 2017 applied- Program/Project name forecast for actual Variance K factor13 K factor14 New Underground and Aerial Service Connections for Commercial, 8 2.42 3.14 0.72 Industrial, Multi-Family and Misc. Customers Underground Residential Distribution (URD) Servicing - Rebates, 9 5.51 5.21 (0.30) Acceptance Inspections & Terminations 10 Capital Tools and Instrument Purchases 0.22 0.35 0.13 11 Poundmaker Feeders 0.40 0.38 (0.02) OMS/DMS (Outage Management System/Distribution Management 12 1.79 1.63 (016) System)Life Cycle Replacement 13 Capitalized Aerial System Damage 0.32 0.30 (0.02) Underground Industrial Distribution (UID) Servicing - Rebates, Acceptance 14 0.44 0.80 0.36 Inspections & Terminations Replacement of Faulted Distribution PILC [paper-insulated lead-covered] 15 0.39 0.36 (0.03) Cables 16 Neighbourhood Renewal Program 0.24 0.04 (0.20) 17 Life Cycle Replacement of Network Transformers* 0.54 0.77 0.23 18 Life Cycle Replacement of PILC Cable Systems* 0.54 0.67 0.12 Customer Revenue Metering Program 19 Customer Revenue Metering - Growth & Life Cycle Replacements 1.11 1.26 (0.01) Advanced Metering Infrastructure 5.90 7.82 1.92 20 IT Hardware Lifecycle Replacements and Additions 0.27 0.33 0.06 Service Centre Redevelopment and Life Cycle Replacements Work Centre Redevelopment 2.49 4.28 1.79 21 North and South Service Centre Building Life Cycle (0.25) (0.23) 0.02 Service Centre Consolidation (0.15) (0.14) 0.00 Furniture Life Cycle Replacement 0.06 0.02 (0.04) Manhole Rebuilds and Life Cycle Replacements 22 Distribution Manhole Rebuilds 0.05 0.01 (0.04) Rebuild and/or Replace Civil Work for Downtown Vaults and Manholes 0.27 0.18 (0.09) 23 Vehicles – Growth and Life Cycle Replacements 0.00 0.34 0.34 24 Switching Cubicle Life Cycle Replacement* 0.13 0.17 0.03 25 Network Reconfigurations 0.32 0.16 (0.16) Street Light Service Connections and Security Lighting Addition and 26 0.12 0.15 0.02 Capital Replacement Replacement of Aerial Ground Rods and Underground Distribution 27 0.00 0.15 0.15 Equipment Ground Grids 2017 K factor total 36.21 43.30 7.10
Note: Totals may not add up due to rounding. *denotes projects to be addressed in Module Two of this proceeding.
20. Table 2 shows the 2017 actual capital additions on which the 2017 capital tracker true-up is based and the 2017 forecast capital additions approved in Decision 20407-D01-2016 or in the compliance filing Decision 21430-D01-2016. All programs or projects received capital tracker treatment approval on a forecast basis in Decision 21430-D01-2016, with the exception of the Vehicles – Growth and Life Cycle Replacements Project and the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project.
6 • Decision 23571-D01-2019 (April 12, 2019) 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
Table 2. 2017 capital tracker programs or projects capital additions Capital additions Program/Project name 2017 approved 2017 actual Variance forecast ($ million) Third-Party Driven Relocations 10.67 9.45 (1.22) Life Cycle Replacement and Extension of Underground Distribution Cable* 10.16 14.5 4.34 New 15-kilovolt (kV) and 25-kV Circuit Additions 12.41 15.07 2.66 New Underground Cable and Aerial Line Reconfigurations and Extensions to 6.14 14.05 7.91 Meet Customer Growth Distribution Pole and Aerial Line Life Cycle Replacements* 4.07 7.46 3.39 Aerial and Underground Distribution Transformers - New Services and Life 5.62 6.40 0.78 Cycle Replacement* Capitalized Underground System Damage 3.49 5.55 2.06 New Underground and Aerial Service Connections for Commercial, Industrial, 11.34 12.47 1.13 Multi-Family and Misc. Customers Underground Residential Distribution (URD) Servicing - Rebates, Acceptance 18.51 11.32 (7.19) Inspections & Terminations Capital Tools and Instrument Purchases 0.58 1.43 0.85 Poundmaker Feeders 0.00 0.01 0.01 OMS/DMS Life Cycle Replacement 5.38 4.66 (0.72) Capitalized Aerial System Damage 1.53 1.94 0.41 Underground Industrial Distribution (UID) Servicing - Rebates, 2.26 1.90 (0.36) Acceptance Inspections & Terminations Replacement of Faulted Distribution PILC Cables 1.38 0.79 (0.59) Neighbourhood Renewal Program 0.00 (0.01) (0.01) Life Cycle Replacement of Network Transformers* 2.57 3.16 0.59 Life Cycle Replacement of PILC Cable Systems* 2.25 1.95 (0.30) Customer Revenue Metering Program 0.00 Customer Revenue Metering - Growth & Life Cycle Replacements 2.84 3.14 0.30 Advanced Metering Infrastructure 26.04 24.82 (1.22) IT Hardware Lifecycle Replacements and Additions 0.41 0.64 0.23 Service Centre Redevelopment and Life Cycle Replacements 0.00 Work Centre Redevelopment 20.62 60.63 40.01 North and South Service Centre Building Life Cycle 0.18 0.37 0.19 Service Centre Consolidation 0.00 0.00 0.00 Furniture Life Cycle Replacement 0.19 0.05 (0.14) Manhole Rebuilds and Life Cycle Replacements 0.00 Distribution Manhole Rebuilds 0.20 0.18 (0.02) Rebuild and/or Replace Civil Work for Downtown Vaults and Manholes 1.23 0.85 (0.38) Vehicles - Growth and Life Cycle Replacements 8.48 8.48 Switching Cubicle Life Cycle Replacement* 1.49 1.57 0.08 Network Reconfigurations 3.53 1.23 (2.30) Street Light Service Connections and Security Lighting Addition and Capital 0.36 0.82^ 0.26 Replacement Replacement of Aerial Ground Rods and Underground Distribution Equipment 0.42 1.55 1.13 Ground Grids Total 159.47 216.43 56.76 Note: Totals may not add up due to rounding. *denotes projects to be addressed in Module Two of this proceeding. ^This amount was corrected from $0.62 million to $0.82 million, as per paragraph 164 below.
Decision 23571-D01-2019 (April 12, 2019) • 7 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
6 Grouping of projects for capital tracker purposes
21. In Decision 2013-435, the Commission determined that the accounting test and the first tier of the materiality test would be applied to the approved groupings (i.e., either at a project or at a program level). When necessary, however, the Commission would consider the individual component projects comprising the approved groupings in order to assess the need for the capital expenditures and the reasonableness of the forecast costs. The second tier of the materiality test is applied at the level of all capital tracker projects, in the aggregate.15 The Commission also determined that the reasonableness of the grouping of capital projects would be assessed on a case-by-case basis for each company.16
22. The grouping of capital tracker projects was generally approved in Decision 2013-435,17 with certain exceptions, the particulars of which were further set out in Decision 3100-D01- 201518 and in Decision 20407-D01-2016.19 In this application, EPCOR used the same approach to grouping that it had used in its previous capital tracker applications, as well as giving effect to any changes directed by the Commission.
23. EPCOR also included, as directed in paragraph 50 and Appendix 3 of Decision 3558- D01-2015,20 a description of its 2017 non-capital tracker projects and programs, showing the 2017 forecast and 2017 actual capital additions, to provide a better understanding of its proposed groupings of the capital projects and programs for which it sought capital tracker treatment.21
Commission findings 24. Consistent with the approach set out in previous capital tracker decisions,22 to the extent that the groupings in the present 2017 true-up capital tracker application are the same as those approved in Decision 3100-D01-2015, Decision 20407-D01-2016 and Decision 22672-D01- 2017, the Commission did not re-evaluate the groupings in this decision.
25. The Commission has reviewed EPCOR’s description of the nature, scope and timing of its non-capital tracker projects, as provided for better understanding of the proposed grouping of capital projects and programs for capital tracker treatment, in accordance with the Commission’s direction at paragraph 50 of Decision 3558-D01-2015, and finds that EPCOR has complied with this direction.
26. For the purpose of this decision, the Commission accepts EPCOR’s grouping of projects and programs, as proposed in this application.
15 Decision 2013-435, paragraph 407. 16 Decision 2013-435, paragraph 406. 17 Decision 2013-435, paragraphs 837-841. 18 Decision 3100-D01-2015: EPCOR Distribution & Transmission Inc., 2013 PBR Capital Tracker True-Up and 2014-2015 PBR Capital Tracker Forecast, Proceedings 3216 and 3100, Applications 1610565-1 and 1610362-1, January 25, 2015, paragraph 83. 19 Decision 20407-D01-2016, paragraphs 67, 90 and 104. 20 Decision 3558-D01-2015: Distribution Performance-Based Regulation Commission-Initiated Proceeding to Consider Modifications to the Minimum Filing Requirements for Capital Tracker Applications, Proceeding 3558, Application 1611054-1, April 8, 2015. 21 Exhibit 23571-X0002.01, application, paragraph 36, Table 2.2.7-1. 22 See for example, Decision 3558-D01-2015, paragraph 51.
8 • Decision 23571-D01-2019 (April 12, 2019) 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
7 Project assessment under Criterion 1 – the project must be outside the normal course of the company’s ongoing operations
27. As discussed in Section 4 of this decision, each of EPCOR’s programs or projects included in the 2017 true-up was evaluated against the second part of the project assessment requirements of Criterion 1, which is, specifically, whether the actual scope, level, timing and costs of the project are prudent. For the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project, which was not approved previously for capital tracker treatment in 2016, the Commission also assessed the need for this project under Criterion 1.
28. The Commission evaluated EPCOR’s business cases, engineering studies, cost-related information, and related evidence and argument, against each of the project assessment minimum filing requirements. In this decision, the Commission commented only on those aspects of the minimum filing requirements that it considered were not sufficiently addressed by EPCOR’s evidence or were otherwise raised as an issue in the proceeding.
29. The balance of this section is organized as follows:
Section 7.1 addresses common issues related to the project assessment of EPCOR’s projects, such as overhead allocations, affiliate transactions, asset usage fees (AUFs), cost of debt, and the company’s internal cost controls and accountability mechanisms with respect to quality, safety and cost for capital projects approved for capital tracker treatment. Section 7.2 sets out the Commission’s project assessment under Criterion 1 of EPCOR’s programs or projects previously approved for capital tracker treatment in Decision 2013- 435, Decision 20407-D01-2016 or Decision 22672-D01-2017 and for which there were no issues raised. Sections 7.3 through 7.9 set out the Commission’s review and findings on capital tracker projects for which there were issues raised through the course of this proceeding.
7.1 Common issues 7.1.1 Allocated overhead 30. The costs included in EPCOR’s capital overhead pool and descriptions of those costs for years 2012 to 2017 are summarized below in Table 3.
Decision 23571-D01-2019 (April 12, 2019) • 9 2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
Table 3. EPCOR’s capital overhead pool 2012-2017
A B C D E F Allocated overhead category 2012 2013 2014 2015 2016 2017 actual actual actual actual actual actual ($ million) 1. Support and supervisor of capital programs 10.04 10.77 11.98 13.90 14.36 14.72 2. Total (including capitalized short-term incentive 10.04 10.77 11.98 13.90 14.36 14.72 pay (STIP)) 3. Adjustment for disallowed capitalized STIP - - 1.31 1.11 1.11 1.12 4. Adjusted total 10.04 10.77 10.67 12.79 13.25 13.58 5. Allocation to Distribution 7.26 7.22 8.34 10.19 9.89 10.05 6. Allocation to Transmission 2.78 3.55 2.33 2.60 3.36 3.53 7. Total 10.04 10.77 10.67 12.79 13.25 13.58 Source: Exhibit 23571-X0002.01, application, Table 2.3.5-1.
31. EPCOR explained that its capital overhead pool is composed of labour and salary costs that are considered directly attributable to capital projects, and includes labour and salaries related to both its distribution and transmission functions.23
32. In Decision 20407-D01-2016, the Commission denied the inclusion of capitalized short- term incentive pay (STIP) in the costs of EPCOR’s proposed capital tracker projects in the 2013- 2017 PBR term.24 EPCOR stated that it removed STIP from the capital overhead pool for 2014, 2015, 2016 and 2017, resulting in a removal of $1.12 million from the capital overhead pool in 2017 as reflected in row 3 of Table 3.
33. EPCOR revised its methodology for allocating overhead to capital projects, from one based on total capital expenditures charged to each project to a new one based on labour costs directly attributable to each capital project.25 The Commission accepted the use of this capital allocation methodology in Decision 22672-D01-2018.26
34. EPCOR utilized the new methodology approved in Decision 22672-D01-2018 in this application. Capitalized labour decreased by $1.26 million in 2017 primarily due to lower internal labour costs for life cycle cable replacement work, which resulted in a higher overhead rate in 2017. Historical and 2017 forecast and actual distribution overhead rates are shown in Table 4 below.
35. In an IR, the Commission asked EPCOR to provide additional information regarding the distribution variance of $1.22 million shown in Table 4 below.27 In its response, EPCOR stated that the variance was a result of higher than anticipated capital expenditures in 2017.28 EPCOR provided further analysis showing overhead costs as a function of total capital expenditure between 2014 and 2017. EPCOR explained that between 2014 and 2017, capital overhead, as a percentage of total capital expenditures, ranged from 7.0 per cent in 2015 to 7.9 per cent in 2016,
23 Exhibit 23571-X0002.01, application, paragraph 97. 24 Decision 20407-D01-2016, paragraph 177. 25 Decision 22672-D01-2018, paragraph 38. 26 Decision 22672-D01-2018, paragraph 43. 27 Exhibit X0107.01, EDTI-AUC-2018JUN22-002. 28 Exhibit X0107.01, EDTI-AUC-2018JUN22-002.
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whereas the 2017 per cent of capital overhead compared to overall capital expenditure was 7.7 per cent.
Table 4. EPCOR distribution functions capital overhead rate 2012-2017 A B C D E F G 2012 2013 2014 2015 2016 2017 2017 actual actual actual actual actual forecast actual 1. Capital overhead pool – 1% projects - - 0.09 0.20 - 0.37 - 2. Capital overhead pool – other projects 7.26 7.22 8.28 9.98 - 8.46 - 3. Distribution share of capital overhead pool 7.26 7.22 8.37 10.18 9.89 8.83 10.05 4. Capital expenditures – 1% projects - - 8.90 20.39 - 36.63 - 5. Capital expenditure – other projects 103.29 88.32 112.14 146.28 - 111.95 - 6. Capitalized labour - - - - 20.65 - 19.36 7. Capital overhead rate – 1% project - - 1% 1% - 1% - 8. Capital overhead rate (other projects) 7.0% 8.2% 7.4% 6.8% - 7.6% - 9. Capital overhead rate – (regular labour) - - - - 47.9% - 51.9% Source: Exhibit 23571-X0002.01, application, Table 2.3.5-2.
Commission findings 36. EPCOR calculated its 2017 capital overhead pool costs, as shown in Table 3, using the same methodology as it did in its 2016 capital tracker true-up application, approved by the Commission in Decision 22672-D01-2018. The Commission has reviewed the information in support of EPCOR’s 2017 actual capital overhead pool costs, as shown in Table 4, and finds that the 2017 actual capital overhead pool costs reflect the methodology approved for EPCOR’s transmission function in Decision 3539-D01-201529 and previous Commission directions; i.e., it reflects adjustment for disallowed capitalized STIP. The Commission also finds that EPCOR has explained sufficiently the variance between the 2016 and 2017 actual capital overhead costs and finds this variance to be reasonable. Accordingly, the Commission finds that the total 2017 actual capital overhead costs, allocated to projects or programs included in the 2017 capital tracker true-up, were prudent.
7.1.2 Affiliate transactions 37. In Decision 3558-D01-2015, the Commission concluded that the identification of any affiliate-related costs included in the forecast or actual costs of a proposed capital tracker project or program would be useful in assessing those projects or programs. Accordingly, at paragraph 80 of Decision 3558-D01-2015, the Commission directed the distribution utilities, including EPCOR, “to include in their business cases a summary of the services provided by or to an affiliate, the related costs and an explanation of how those amounts were determined.”
38. To comply with this direction in the application, EPCOR detailed the services provided to its affiliates or by its affiliates, including the costs of those services and the manner in which those costs were reflected in its capital tracker projects or programs. EPCOR provided the following table summarizing its affiliate services.
29 Decision 3539-D01-2015: EPCOR Distribution & Transmission Inc., 2015-2017 Transmission Facility Owner Tariff, Proceeding 3539, Application 1611027-1, October 21, 2015.
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Table 5. EPCOR’s affiliate services Service Affiliate Engineering services for design and as-built drawings EPCOR Technologies Inc. Hydro-excavation services (hydrovac) including soil & water dumping services EPCOR Technologies Inc. (dewatering hydro-excavation trucks) Directional drilling (smaller diameter pipe) EPCOR Technologies Inc. Civil construction services for cable replacement EPCOR Technologies Inc. Construction, maintenance and repair of security lighting systems EPCOR Technologies Inc. Pole replacement work EPCOR Technologies Inc. Power base pedestal replacement EPCOR Technologies Inc. Other jobbing services (including thumping & fibre installation) EPCOR Technologies Inc. Information technology (IT) support EPCOR Utilities Inc. Work centre redevelopment EPCOR Water Services Inc.
Source: Exhibit 23571-X0002.01, application, paragraph 49, Table 2.2.8-1.
39. The terms and conditions regarding the provision of affiliate services to EPCOR are set out in separate service level agreements (SLAs) with EPCOR Utilities Inc. (EUI), EPCOR Technologies Inc. (ETECH) and EPCOR Water Services Inc. (EWSI). The SLA between EPCOR and EUI details work for IT software and hardware related to the OMS/DMS (outage management system/distribution management system) Life Cycle Replacement, AMI (advanced metering infrastructure), IT Hardware and Life Cycle Replacements and Additions, and Work Centre Redevelopment projects or programs. The SLA between EPCOR and ETECH is for contracted work on “an as available basis.”30 EPCOR stated that in 2017 it used EWSI “for a one-time project to construct an additional water service connection as part of the Work Centre Redevelopment project.”31
40. EPCOR explained that for capital tracker projects, ETECH is only involved after the determination has been made that a third party is needed to complete the work. An external party is typically engaged when EPCOR does not have the internal resources or specialized equipment to complete the work in a cost-effective manner or to manage workflow peaks.32
41. In Decision 22672-D01-2018, the Commission directed EPCOR to continue to “include a table outlining the breakdown of the actual capital additions for each of its capital tracker projects or programs, split out between each affiliate service provider and non-affiliated third party, in its 2017 true-up capital tracker application.”33
42. To comply with this direction in the application, EPCOR provided the breakdown reproduced as Table 6 below.
30 Exhibit 23571-X0002.01, application, paragraph 49. 31 Exhibit 23571-X0002.01, application, paragraph 49. 32 Exhibit 23571-X0002.01, application, paragraph 52. 33 Decision 22672-D01-2018, paragraph 50.
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Table 6. Detailed breakdown of EPCOR’s affiliate services 2017 Non- Actual affiliate Capital tracker ETECH EWSI EUI TOTAL capital third additions party ($ million) Southeast LRT [light rail transit] Expansion Distribution System 2.86 0.18 - - 0.18 0.96 Franchise Agreement Driven Relocations Franchise Agreement Driven Relocations and Conversions 4.51 0.34 - - 0.34 2.22 Walterdale Bridge Replacement Franchise Relocations 2.08 0.01 - - 0.01 1.49 Life Cycle Replacement and Extension of Underground 14.5 2.38 - - 2.38 4.61 Distribution Cable New 15kV and 25kV Circuit Additions 15.07 0.33 - - 0.33 5.76 New Underground and Aerial Service Connections for 12.47 1.32 - - 1.32 3.92 Commercial, Industrial, Multifamily and Misc. Customers Distribution Pole and Aerial Line Life Cycle Replacements 7.46 0.86 - - 0.86 0.66 Aerial and Underground Distribution Transformers - New Services 6.4 0.43 - - 0.43 0.4 and Life Cycle Replacement Capitalized Underground System Damage 5.55 0.81 - - 0.81 0.78 New Underground Cable and Aerial Line Reconfigurations and 14.05 1.53 - - 1.53 5.62 Extensions to Meet Customer Growth Underground Residential Distribution (URD) Servicing - Rebates, 11.32 0.57 - - 0.57 8.55 Acceptance Inspections and Terminations Capitalized Aerial System Damage 1.94 0.12 - - 0.12 0.13 Underground Industrial Distribution (UID) Servicing - Rebates, 1.9 0.04 - - 0.04 1.61 Acceptance Inspections and Terminations Replacement of Faulted Distribution PILC Cables 0.79 0.03 - - 0.03 0.01 Life Cycle Replacement of PILC Cable 1.95 0.04 - - 0.04 0.55 Network Transformer Lifecycle Replacement 3.16 0.17 - - 0.17 0.61 Rebuild and/or Replace Civil Work for Downtown Vaults and 0.85 0.01 - - 0.01 0.48 Manholes Network Reconfigurations 1.23 0.06 - - 0.06 0.91 Street Light Service Connections and Security Lighting Addition 0.82 0.53 - - 0.53 - and Capital Replacement Switching Cubicle Life Cycle Replacement 1.57 0.2 - - 0.2 0.05 West LRT Distribution System Relocation - 0.01 - - 0.01 0.27 Work Centre Redevelopment Project 60.63 - 0.23 - 0.23 34.13 Advanced Meter Infrastructure 24.82 - - 0.02 0.02 3.23 IT Hardware Life Cycle Replacements and Additions Distribution 0.64 - - 0.35 0.35 - OMS/DMS Lifecycle Replacement 4.66 - - 1.37 1.37 0.02 TOTAL 201.2 9.97 0.23 1.74 11.94 76.97
Source: Exhibit 23571-X0002.01, application, paragraph 51, Table 2.2.8-3. Note: The services provided by ETECH shown in Table 4 are spread across the capital tracker projects shown in Table 5. EPCOR provided the relationship between ETECH’s services and capital tracker projects in Table 2.2.8.1-1, which is not reproduced in this decision.
43. In an IR, the Commission asked EPCOR to provide an analysis to support EPCOR’s assertions that the rates it pays to affiliates, in comparison to rates paid to other third-party service providers or to the internal costs of doing the same work, were comparable to competitive market prices.
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44. In response, EPCOR provided details on its use of ETECH, and the rates it pays, in relation to the following services:
Engineering and drafting Hydro-excavation services including soil and water dumping services (dewatering hydro- excavation trucks) Directional drilling (smaller diameter pipe) Civil construction services for cable replacement Construction, maintenance and repair of security lighting systems Pole replacement work Power base and/or pedestal repair Other jobbing services (including thumping, genset and fibre installation)
7.1.2.1 Evaluation of EPCOR’s affiliate transactions 45. Mr. Bell, on behalf of the UCA, filed evidence asserting that EPCOR failed to provide sufficient evidence to meet the Commission’s test of prudence in contracting with affiliates:34
The AUC has well established criteria that it has previously applied to test the rates paid to affiliates. These principles require the utility to show that it is obtaining services from the lowest cost alternative commensurate with providing safe and reliable service. This lowest cost alternative test requires EDTI to examine the alternative structures for various services, including the possibility of providing the services internally.
Generally, EDTI has not provided a comprehensive justification for the use of an affiliate, and further, it has not demonstrated that it has used the least cost alternative in selecting an affiliate, and in some cases, it appears to have blindly adopted an affiliate because its parent, the City of Edmonton (City) selected the EDTI affiliate.
46. Mr. Bell referred to previous decisions by the Commission that addressed a regulated utility’s use of an unregulated affiliate. Mr. Bell cited Decision 2002-069 concerning an application filed by ATCO Electric Ltd. and ATCO Gas and Pipelines Ltd. (collectively, ATCO) for approval of long-term master service agreements (MSAs) for IT services between ATCO and ATCO I-Tek, an unregulated affiliate. Mr. Bell identified three criteria that the Alberta Energy and Utilities Board (the board), the Commission’s predecessor, referenced in that proceeding:35
Does the decision to acquire goods or services from the affiliate affect the utility’s ability to operate safely and reliably? Is the affiliate the least cost alternative that meets the requirements of the utility? Was the purchase of goods or services by the utility at the lesser of fair market value, or the cost it would take for the utility to provide similar goods or services itself?
47. Mr. Bell also referenced Decision 2014-169 (Errata), which examined a similar issue, where the Commission stated:
The Commission has consistently examined the provision of these [IT] services to customers and tested costs based on the no harm to customers principle. The condition of
34 Exhibit 23571-X0174.01, evidence of Mr. Bell, PDF page 3. 35 Decision 2002-069: ATCO Group, Affiliate Transactions and Code of Conduct Proceeding, Part A: Asset Transfer, Outsourcing Arrangements, and GRA Issues, Application 1237673-1, July 26, 2002, page 47.
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having the services provided in-house if they were cheaper than through an affiliate or having the contract awarded to the lowest competitive tenderer or by testing the affiliate transaction as having the ratepayers paying no more than fair market value, were all highlighted in previous decisions. All tests related to the Commission’s rate setting mandate and afforded utilities the opportunity to structure their operations for the benefit of shareholders while still protecting utility customers based on the no harm principle.36
48. Relying on the criteria set out in these decisions, Mr. Bell stated that EPCOR has not demonstrated that ETECH was “the lowest cost option from a customer perspective that would provide safe and reliable service.”37 Mr. Bell further stated that “it is not enough to demonstrate fair market value – the utility, and its management, must also demonstrate that the chosen option is the least cost alternative.”38
49. In further support of his position that the lowest cost alternative was the test that EPCOR had to meet, Mr. Bell referred to EPCOR’s 2017 Annual Compliance Report, which stated that there “must contain adequate evidence … to conclude that the decision to out-source is the lowest cost option for customers, and that the For Profit Affiliate Services have been acquired at a price which is no more than Fair Market Value.”39
50. The UCA argued that the burden of proof rests with EPCOR to demonstrate that its expenditures were prudent, and that “it is not incumbent on interveners to show actual expenditures by a utility are unfair or unreasonable.” The UCA asserted that if a utility fails to provide sufficient evidence to prove costs are just and reasonable, the inclusion of the costs for incremental funding as a capital tracker should be denied by the Commission.40
51. In response, EPCOR stated that it must consider factors other than hourly rates when considering any contractor, whether affiliated with EPCOR or not, to provide services or perform work. Consideration must also be given to total cost, availability, expertise, experience, safety record, and capability (which may include an ability to complete more than one facet of the scope of work):
To begin with, as noted in EDTI’s Application and responses to information requests, there are numerous relevant factors beyond mere cost that must be considered in selecting among potential external service providers, including third party versus affiliated service providers. These include but are not limited to the capability of each contractor to complete the required work.
Contractors often differ in their capability to complete work required by EDTI, both in terms of the types of work they are competent to complete and the volumes of work that they have the capacity to undertake. The latter can be affected by EDTI’s required timing of work vis-à-vis the contractor’s available resources to complete the work on the required timeline.41
36 Decision 2014-169 (Errata): ATCO Utilities (ATCO Gas, ATCO Pipelines and ATCO Electric Ltd.), 2010 Evergreen Proceeding for Provision of Information Technology and Customer Care and Billing Services Post 2009 (2010 Evergreen Application), Proceeding 240, February 6, 2015, paragraph 463. 37 Exhibit 23571-X0174.01, evidence of Mr. Bell, PDF page 10. 38 Exhibit 23571-X0174.01, evidence of Mr. Bell, PDF page 10. 39 Exhibit 23571-X0174.01, evidence of Mr. Bell, PDF page 9. 40 Exhibit 23571-X0202, UCA argument, paragraphs 3-4. 41 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF page 5.
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Commission findings 52. In 2002, following the completion of an “Affiliate Proceeding,” the board issued Decision 2002-069, which, in part, included a review of the standards and conditions for interaction between the regulated and non-regulated affiliates within the ATCO group of companies. Coincident with the Affiliate Proceeding, the board was also considering a similar proceeding from EPCOR Transmission Inc.42 Given the parallel proceedings that were before the board, it considered, then rejected, holding a generic proceeding to address the acquisition of goods and services from an unregulated affiliate by a utility. Rather, it decided to release its decision to establish a code of conduct for ATCO first with the understanding that it would “where appropriate, reflect those findings in subsequent decisions.”43
53. In considering this issue, the Commission notes that in Decision 2002-069, after the three criteria cited by Mr. Bell, the board went on to state that it was incumbent on the board to consider the circumstances at the time and factors other than price:
With respect to the prudence of the business decision to transfer the operations of [Canadian Utilities Limited Information Systems] to [ATCO] I-Tek, the Board must determine if this decision was reasonable in light of the circumstances at the time. The Board is of the view that there may be factors other than price that should be considered for this decision.44
54. EPCOR’s Inter-Affiliate Code of Conduct was approved in Decision 2004-010,45 where the board approved that EPCOR’s affiliate transactions should be no more than the fair market value, that it is up to EPCOR to show that it has met this standard and that EPCOR has the discretion to determine the manner in which it wishes to make its case:46
4.2.1 When a Utility acquires For Profit Affiliate Services it shall pay no more than the Fair Market Value of such services. The onus is on the Utility to demonstrate that the For Profit Affiliate Services have been acquired at a price that is no more than the Fair Market Value of such services. … 4.5 In demonstrating that Fair Market Value was paid or received pursuant to a For Profit Affiliate Service arrangement or a transaction contemplated by sections 4.1, 4.2 and 4.4 hereof, the Utility, subject to any prior or contrary direction by the EUB, may utilize any method to determine Fair Market Value that it believes appropriate in the circumstances. These methods may include, without limitation: competitive tendering, competitive quotes, bench-marking studies, catalogue pricing, replacement cost comparisons or recent market transactions. The Utility shall bear the onus of demonstrating that the methodology or methodologies utilized in determining the Fair Market Value of the subject goods or services was appropriate in the circumstances. [emphasis added]
55. The Commission also takes guidance from Decision 2014-169 (Errata), noted above and also referenced by Mr. Bell, where it stated that a utility’s Inter-Affiliate Code of Conduct can be
42 Decision 2003-040 at page 2. 43 Decision 2002-069 at page 3. 44 Decision 2002-069, page 47. 45 Decision 2004-010: EPCOR Utilities Inc., Code of Conduct and Exemption Application, Application 1316005-1, February 3, 2004. 46 Decision 2004-010, Appendix 1, PDF page 23.
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used as a tool to assess non-arm’s-length transactions with an affiliate (also known as transfer pricing):
A properly carried out competitive process would result in a fair market value price. In addition, if the Commission were to find that the services could be provided at a lower cost if provided “in-house,” the Commission has the authority to order that these lower prices be reflected in the rates charged by the utility to consumers. Provision of these services “in house” would also allow the Commission to examine the costs of the services directly. It is because neither of these two courses of action are available to the Commission in this case, that recourse must be had to the guidance provided by the Code of Conduct.47
56. The Commission notes that the text Mr. Bell quoted from EPCOR’s 2017 Annual Compliance Report is similar in nature to EPCOR’s Project Management Controls and Accountability Policies and Procedures filed as part of its application for this proceeding:48
Affiliate related costs are in accordance with EDTI’s Inter-Affiliate Code of Conduct requirements and consistent with market rates (including the affiliate’s selection of external contractors utilized on EDTI capital projects). EDTI periodically reviews the hourly rates charged by its affiliate (for example, engineering and specialized services such as directional drilling and hydrovac services) and ensures that the rates are comparable to competitive market prices.
57. Based on these guiding documents, EPCOR must demonstrate that its inter-affiliate transactions adhere to its Inter-Affiliate Code of Conduct requirements, namely, that it has paid no more than fair market value, based on whatever mechanism it believes most appropriate, taking into account whatever factors it considers relevant.
7.1.2.2 Engineering and drafting technology services 58. With respect to EPCOR’s use of ETECH to perform drafting services, the UCA argued that EPCOR should only be allowed to recover the least cost alternative as a capital tracker.49 In his evidence, Mr. Bell stated that EPCOR had not provided clear evidence that the costs of affiliates were the lowest, including lower than the cost of providing the services internally. Mr. Bell further submitted that EPCOR did not provide any quantitative analysis regarding the cost of using affiliates in 2017.50
59. EPCOR stated that, with respect to engineering and drafting technology services, competitive rates paid to ETECH can be lower, the same or higher in comparison to rates paid to non-affiliate third-party service providers or internal costs, and that hourly rates are not necessarily determinative of prudence. Instead, EPCOR compares the total engineering and drafting costs for the type of work being provided by the consultant and ETECH:51
Contractor rates can vary widely in some cases, based on skill and experience levels. Comparing consultants simply based on the hourly rate does not always result in the lowest costs. For example, a consultant with a lower rate may take more hours to
47 Decision 2014-169 (Errata), paragraph 427. 48 Exhibit 23571-X0003, Appendix A, PDF page 35. 49 Exhibit 23571-X0202, UCA argument, paragraph 2. 50 Exhibit 23571-X0174.01, confidential evidence of Mr. Bell, PDF page 17. 51 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF pages 4-5.
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complete a task or the consultant’s work may require more rework (i.e., be of poorer quality), resulting in an effective cost that is higher than would be the case with a more experienced consultant who charges a higher hourly rate but completes the task in a shorter amount of time at a higher quality level.
60. EPCOR stated that to measure whether it is receiving competitive rates from ETECH and non-affiliate third party consultants, EPCOR regularly conducts a competitive request for proposals (RFP) process. For engineering services, EPCOR held an RFP in late 2017, which required consultants and ETECH to provide the resources and resumes of the staff they proposed to use on certain projects, the hourly rate of each resource, their relevant experience in regards to previous work performed and references that could be contacted to confirm their performance.52
61. EPCOR stated further that its internal engineers have established manpower models for the various types of work required, based on the average of actual engineering costs incurred by EPCOR on past projects, the associated time to engineer those projects and the resources that were required. EPCOR then uses these models to compare third-party, affiliate and internal rate estimates to ensure they are comparable to competitive market prices:53
These models are updated annually. As projects come along, EDTI requires the consultants and ETECH to provide estimates for time required to engineer the project, to identify the resources they plan on using and calculate the total engineering cost for all work to be assigned. This is then compared against EDTI’s manpower models to ensure the estimates provided by the consultants and ETECH are reasonable. If an estimate is not reasonable, EDTI would either inform the consultant / ETECH and provide them the opportunity to revise their estimate, or the consultant / ETECH would not be selected for that type of work. In addition, at the end of each project the actual engineering hours invoiced to EDTI by each consultant / ETECH are compared to the estimates to ensure the hours invoiced are reasonable and consistent with EDTI’s manpower models.
62. EPCOR provided the 2017 hourly rates for engineering and drafting technology services from six non-affiliate consultants, ETECH and EPCOR’s internal hourly rate, with the latter two being provided confidentially.54
63. In 2017, EPCOR used ETECH or non-affiliate consultants when EDTI’s internal engineering staff did not have the capacity or specialized skill set to complete the work. EPCOR selected ETECH to perform engineering services on the basis that they were among the lowest in comparison to all the consultants’ rates.
64. For drafting technology services, EPCOR explained that only two out of the six non- affiliate consultants were capable of providing these services, and ETECH’s hourly rate was above the average of the two non-affiliate consultants’ rates.55 EPCOR selected ETECH’s drafting technologists in 2017 “primarily to update its system records and asset information to reflect the distribution system assets that were replaced in 2017.” EPCOR submitted that its decision was reasonable on the basis of ETECH’s familiarity with EPCOR’s asset recording and drawing management system and its distribution engineering and construction practices and
52 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 5. 53 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 5. 54 Exhibit 23571-X0107.01, CONF-EDTI-AUC-2018JUN22-001, PDF page 5. 55 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 6.
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standards, “thereby ensuring that the quantity of hours required to complete the work (i.e., associated costs) were minimized.”56
65. EPCOR further explained that “ETECH was only awarded other work for drafting technologist services when the other two consultants who were capable of providing this work to EDTI did not have the capacity to complete the required work to meet EDTI project timelines.”57 EPCOR further clarified its decision-making process in awarding work to ETECH versus non- affiliate consultants:58
EDTI does not award work to ETECH first and then resort to non-affiliate providers only where ETECH does not have capacity to do the work. The consultants and ETECH are awarded work depending on their cost, varying levels of expertise, experience and capacity to carry out engineering work to meet EDTI project timelines. More specifically, for EDTI’s 2017 capital engineering requirements, non-affiliate consultants were awarded engineering work for 65% of cable replacement projects, 73% of transformer replacement projects and 98% of pole replacement projects because of cost, previous experience with these types of projects (i.e., engineering staff who are familiar with EDTI’s engineering and construction standards thereby ensuring the quantity of hours required to complete the work are minimized) and capacity to carry out the work to meet EDTI’s prescribed project timelines. Further, EDTI notes that in 2017, ETECH was not awarded any engineering work for switching cubicle replacements or new circuit design projects.
Commission findings 66. The determination of fair market value is a relative concept and should not be reduced to a simple comparison of hourly rates. Although hourly rates are a factor in determining market pricing, other factors, such as experience, familiarity with a particular party’s systems or processes, and available resources to complete work within a defined schedule, also contribute to the evaluation of a fair market value for the services acquired. As stated by the Alberta Energy and Utilities Board in Decision 2003-106, “it is the overall cost to customers, … that should be considered when assessing fair market value.”59 Further, as stated by the board in Decision 2005- 105, “judgment is usually involved in determination of FMV [fair market value].”60
67. For the following reasons, the Commission finds EPCOR’s use of ETECH to perform engineering and drafting technology services in 2017 to be reasonable.
68. In arriving at this decision, the Commission has relied on the following evidence:
EPCOR had recently performed an RFP, which required consultants and ETECH to provide the resources and resumes of the staff they proposed to use on certain projects, the hourly rate of each resource, their relevant experience in regard to previous work performed and references that could be contacted to confirm their performance.
56 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 7. 57 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 7. 58 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 8. 59 Decision 2003-106: Direct Energy Regulated Services, Electric Regulated Rate Tariff and Gas Default Rate Tariff, Application 1302109-1, December 18, 2003, page 86. 60 Decision 2005-105, Direct Energy Regulated Services, Benchmarking Study of Customer Care Services, Application 1361950-1, September 13, 2005, page 24.
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EPCOR verified that the actual engineering hours invoiced to it by each non-affiliate consultant and ETECH were compared to the estimates to ensure the hours invoiced were reasonable and consistent with EPCOR’s manpower models, which are updated annually.61
EPCOR was guided by the objective to minimize total project costs, and not just hourly rates. This meant in some limited circumstances (for example, updating its system records and asset information to reflect the distribution system assets that were replaced in 2017), EPCOR contracted ETECH to perform this work, although its hourly rates were higher than other non-affiliate consultants, because ETECH’s experience and expertise would help ensure that the quantity of hours required to complete the work were minimized.62
EPCOR did not use ETECH’s services if EPCOR or other non-affiliate consultants had the capacity to perform the work in the required timelines.63
EPCOR does not award work to ETECH first and then resort to non-affiliate providers only where ETECH does not have capacity to do the work. EPCOR provided a number of examples where work was not awarded to ETECH, even though it had capacity.64 This is further illustrated in Table 6, which shows the amount paid to ETECH compared to non-affiliate consultants.
7.1.2.3 Civil construction services for cable replacement 69. EPCOR stated that, with respect to civil construction services for cable replacement, competitive rates paid to ETECH can be lower, the same or higher in comparison to rates paid to non-affiliate third-party service providers or internal costs, and that hourly rates are not necessarily determinative of prudence. Instead, EPCOR compares the total cost of the project for the civil construction services being provided by the consultant and ETECH. EPCOR also noted that in 2017 no single contractor would have been capable of providing the full scope of work on its own, in the designated timeframe.65
70. EPCOR explained its process in selecting affiliate and non-affiliate contractors to perform civil construction services for cable replacement:66
To account for differences in how each contractor sets its annual rates for individual line unit items, and, to measure whether EDTI is receiving competitive rates from ETECH and non-affiliate contractors, EDTI uses sample projects with estimated construction quantities to carry out a comparative analysis of the proposed contractor rates. In March of 2017, EDTI applied the contractors’ proposed 2017 rates to each of three sample projects (small, medium, large) to create an estimate of the construction cost per sample project. These estimates were then compared to confirm that the rates from ETECH were competitive with the non-affiliate contractor rates prior to accepting ETECH’s proposed rates. For 2017, ETECH’s total estimated cost for the three sample projects was within
61 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 5. 62 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 7. 63 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 7. 64 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 8. 65 Exhibit 23571-X0203, EPCOR argument, paragraph 34. 66 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF pages 11-12.
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[redacted] of the average of the non-affiliate contractors’ total estimated costs for the same sample projects.
Further, following completion of the civil construction work on EDTI’s 2017 cable replacement program, EDTI carried out a similar analysis, but this time used three actual sample projects to accurately reflect the typical scope of work completed in 2017. The 2017 sample projects represented variations in project size as well as construction techniques and were completed by different contractors. Under this comparison, ETECH’s total cost for the three sample projects was [redacted] lower compared to the average total cost of the non-affiliate contractors for the same projects.
Finally, to account for differences in field production levels and force account rates (i.e., unexpected items that can vary significantly such as ground conditions and which are not reflected in standard unit rates), EDTI carried out a comparison of ETECH’s and each non-affiliated contractor’s overall average actual cost per kilometer in respect of the civil construction work carried out in 2017 in EDTI’s cable replacement program. ETECH’s 2017 average cost per kilometer was within [redacted] of the non-affiliate contractors’ average actual cost per kilometer.
71. Based on the results of the process quoted above, EPCOR awarded the non-affiliate contractor with the lowest actual cost per kilometre (km) the largest volume of civil construction work with respect to EPCOR’s 2017 Cable Replacement Program. Since this contractor did not have the capacity to perform all the work required in 2017, EPCOR awarded the remaining work to the contractor with the next lowest actual cost per km, based on available capacity in 2017 to meet EPCOR’s project timelines:67
For civil construction services work in this cost category, neither ETECH nor the non- affiliated contractors are required to bid on individual projects, as EDTI uses the [Master Services Agreement’s] unit rates (determined by a competitive RFP process) to determine project work assignments. Project work is assigned throughout the year based on contractor capability, availability and cost. EDTI will first assess which contractors are qualified to complete the specific work based on historical performance, experience and equipment. If multiple contractors are qualified, EDTI will then determine which contractors are available to meet its required project timelines. If multiple contractors are available, EDTI will assign the work to the contractor with the lowest overall cost for the scope of work required, as reflected in Table EDTI-AUC-2018JUN22-001-4. EDTI will assign work to ETECH on the same basis on which it judges all external civil construction non-affiliated contractors: on the basis of cost, expertise and the ability to meet EDTI’s project timelines.
72. With respect to EPCOR’s use of ETECH to perform civil construction services for cable replacement, the UCA argued that EPCOR should only be allowed to recover the least cost alternative as a capital tracker.68
73. In his evidence, Mr. Bell stated that EPCOR had not provided decisive evidence that the costs of affiliates are the least cost alternative, including lower than the cost of providing the
67 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF pages 13-14. 68 Exhibit 23571-X0202, UCA argument, paragraph 2.
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services internally. Mr. Bell further alleged that EPCOR did not provide any quantitative analysis regarding the cost of using affiliates in 2017.69
74. Mr. Bell also took issue with EPCOR having awarded the most work to ETECH in 2015 and 2016. In these years, ETECH was the highest and second highest cost service provider, respectively. Mr. Bell noted that EPCOR also awarded the most work over the period 2013- 2017. During this period, ETECH was, on average, the highest cost provider on a cost per km basis. Mr. Bell recommended that EDTI should only be allowed to recover costs at a level equivalent to the lowest cost contractor.70
Commission findings 75. As set out in paragraph 66 above, the Commission has not restricted its determination of fair market value for the provision of civil construction services solely to an evaluation of hourly rates.
76. For the following reasons, the Commission finds EPCOR’s use of ETECH to perform civil construction services for cable replacement in 2017 to be reasonable.
77. In arriving at this decision, the Commission finds the following evidence to be persuasive:
EPCOR used sample construction project estimates to determine whether ETECH provided a competitive rate for these services, in terms of a total cost and not an hourly rate. For 2017, ETECH’s total estimated cost for the three sample projects was within a reasonable range of the average of the non-affiliate contractors’ total estimated costs for the same sample projects.
Following completion of the civil construction work on EPCOR’s 2017 Cable Replacement Program, EPCOR carried out a similar analysis, but this time used three actual projects to prepare comparative cost estimates. Under this comparison, ETECH’s total cost for the three comparison projects was lower than the average total cost of the non-affiliate contractors for the same projects.71
ETECH was not awarded the most work for civil construction services for cable replacement. ETECH was awarded work when it offered the lowest cost and was available.
EPCOR aligned its approach with the Master Services Agreement set with its contractors and established through a competitive RFP process. EPCOR explained that it assigned project work throughout the year guided by this agreement and based on contractor capability, availability and cost.
69 Exhibit 23571-X0174.01, confidential evidence of Mr. Bell, PDF pages 17-18. 70 Exhibit 23571-X0203, EPCOR argument, paragraph 38. 71 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001, PDF page 12.
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7.1.2.4 Construction, maintenance and repair of security lighting systems and pole replacement work 78. While the construction, maintenance and repair of security lighting systems and the pole replacement work are separate services for which EPCOR relied on ETECH to fulfill, the nature and issues surrounding these two projects are similar. Therefore, the Commission has considered both of these services in this section.
79. EPCOR’s pole replacement work is composed of “installing, replacing or removing existing poles that are outside the limits of approach of energized primary lines. This includes streetlight poles which are welded to their bases. Due to the lower safety risk associated with this work, EDTI uses contractors to supplement its internal aerial and materials support crews so that internal resources can be dedicated to work on energized lines. Additionally, ETECH transfers streetlight light laterals from old pole to new pole locations.”72
80. EPCOR explained that in 2017 ETECH handled all work related to security lighting systems on EPCOR’s system. EPCOR does not provide these services internally and does not use any non-affiliated service providers.
81. EPCOR does not set the rate it pays to ETECH for work related to its security lighting systems. ETECH provides similar services to the City of Edmonton (the City) for street lighting installation work, which is very similar in scope to security lighting work and involves the same labour skill set and equipment requirements. ETECH charged EPCOR the same rate it charged the City, which was negotiated by the City in 2013. The City has subsequently tested the rate it pays for ongoing competitiveness through an annual benchmarking exercise. Based on a favourable analysis of the competiveness of ETECH’s rate, the street lighting contract was extended by the City of Edmonton for an additional three-year period to the end of 2017:
ETECH provides service to the City of Edmonton for Streetlight installation and maintenance. In 2013, The City of Edmonton conducted direct negotiations with ETECH and awarded ETECH initially, a two year contract with a possible three year extension provided ETECH was able to demonstrate that they could meet defined performance measures and competitive pricing. In order to test the ongoing competitiveness of ETECH’s pricing, the City of Edmonton conducts an annual benchmarking exercise by taking a number of projects every year and going out to RFP for similar work and having ETECH prepare cost estimates for the same work so that the City of Edmonton can compare ETECH’s costs with the costs of other contractors and confirm the continued competitiveness of ETECH’s costs. At the end of 2013 ETECH did meet the City of Edmonton’s performance targets so the contract was extended for the additional three years (i.e., to the end of 2017), and ETECH’s costs have remained competitive to the City’s satisfaction. ETECH charges EDTI the same rates for work on EDTI security lighting systems as those charged to the City of Edmonton for the Streetlight installation as the knowledge and skills required to complete this work is similar to the services that ETECH provides to the City of Edmonton.73
82. In response to an IR from the UCA, EPCOR explained that it had no involvement in the RFP process the City ran in 2013, the negotiation of rates or extension of the contract between ETECH and the City. EPCOR was unable to provide documents related to these, nor did it have
72 Exhibit 23571-X0002.01, application, paragraph 64. 73 Exhibit 23571-X0002.01, application, paragraph 63.
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any correspondence with the parties in that regard.74 EPCOR did provide publicly available materials concerning the City’s review of ETECH’s performance results that led the City to extend the contract with ETECH to 2017.75
83. EPCOR also explained in its application that in 2017 EPCOR compared ETECH’s rates to its internal costs to complete the same work and that work done by ETECH is in line with the SLA:
EDTI ensured that the agreed to ETECH rates were consistent with the applicable internal EDTI costs. In addition, as described in the terms and conditions of EDTI’s SLA with ETECH, before proceeding with any work, ETECH provides EDTI with a high level estimate of cost and effort involved and will only proceed with the work upon written EDTI approval of the estimate. EDTI is notified immediately in the event that any pole replacement work being performed by ETECH will exceed 20% of the approved estimate and written approval must be obtained from EDTI in advance of ETECH continuing work.76
84. Given the inability to fully test the rates paid to ETECH by EPCOR, the UCA recommended that all costs related to ETECH performing work related to the construction, maintenance and repair of security lighting systems be denied capital tracker treatment and removed from rate base.77
85. EPCOR disputed the UCA’s recommendation, stating that the need for this project has been established in previous capital tracker decisions, and that the UCA had not provided evidence to support its recommendation that the costs incurred under the project should be deemed to be zero. EPCOR argued that due to the variable nature of the work, it is more cost- effective to outsource it to a qualified service provided that is already performing the work for the City:78
In making his assertions, Mr. Bell ignores other factors that are relevant in determining whether to externally procure a service versus providing it internally. For example, as noted in EDTI’s filed materials, EDTI does not have internal resources or the specialized equipment to cost effectively complete the outsourced work. The work related to the construction, maintenance and repair of security lighting systems is intermittent and varies year over year as reflected in the table below. The annual capital additions for this work over 2014-2017 has ranged from $0.04 million to $0.47 million. EDTI’s evidence is that given both the large variation and the relatively small level of the annual capital additions for this work, and since the construction, maintenance and repair of security lighting systems is not in any sense a core function of EDTI, it is not cost effective for EDTI to maintain the required internal resources and specialized equipment to complete the work internally.
Unlike EDTI, given that ETECH performs this type of work for the City, ETECH is both qualified and appropriately staffed to carry out the work required to accommodate EDTI’s necessary construction activities and meet the City’s and developer’s time sensitive requirements for the completion of this work.
74 Exhibit 23571-X0150.01, EDTI-UCA-2018AUG24-001(b) and (c). 75 Exhibit 23571-X0151.01, EDTI-UCA-2018AUG24-001 Attachment 1. 76 Exhibit 23571-X0002.01, application, paragraph 66. 77 Exhibit 23571-X0202, UCA argument, paragraph 2. 78 Exhibit 23571-X0199, EPCOR rebuttal evidence, A12.
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Finally, EDTI explained in its Application and responses to information requests that unlike EDTI, ETECH employees [sic] signal technicians that are qualified to perform low voltage work, and that if EDTI were to carry out this work internally, it would have to use its powerline technicians at a higher cost.
Commission findings 86. As noted by EPCOR, the need for this capital tracker project has already been approved. Consequently, it is not reasonable to assume that none of the work performed was necessary and therefore, all of the costs for this capital tracker disallowed in their entirety, as advocated by the UCA. Rather, the Commission considers that EPCOR must demonstrate that its inter-affiliate transactions adhere to its Inter-Affiliate Code of Conduct requirements, namely, that it has paid no more than fair market value for ETECH’s services.
87. For the following reasons, the Commission finds EPCOR’s use of ETECH to construct, maintain and repair its security lighting systems and execute its pole replacement work in 2017 to be reasonable.
88. In arriving at this decision, the Commission finds the following evidence to be persuasive:
Although the Commission has no oversight into the City’s operations, the City of Edmonton is a public body with processes, controls and independent audits, and is an organization accountable to its citizens. In this limited circumstance, given the process that it ran, the Commission finds it reasonable that EPCOR relied on the City’s procurement process. It has been established over multiple proceedings, most recently in the 2018 Generic Cost of Capital (GCOC) proceeding,79 that the City treats EPCOR as an arm’s-length party and has no direct influence on its day-to-day operations. There is nothing on the record of this proceeding to indicate that this is not the case.
EPCOR pays ETECH the same rate that is charged to the City for the equivalent services. Again, relying on the City’s RFP process in this limited circumstance, this establishes the fair market value for these services and, therefore, EPCOR paid no more than the fair market value for them.
EPCOR’s rationale for not performing this work itself is supported by the fact that ETECH, as the service provider for both the City and EPCOR, would have economies of scale and cost efficiencies that EPCOR would not have if it chose to perform the work internally.
7.1.2.5 Hydro-excavation dispatch and dewatering services and directional drilling services 89. While hydro-excavation (hydrovac) dispatch and dewatering services and directional drilling services are separate services for which EPCOR relied on ETECH to provide, the nature and issues surrounding these two projects are similar. Therefore, the Commission has considered ETECH’s services under these projects jointly in this section.
79 Decision 22570-D01-2018: 2018 Generic Cost of Capital, Proceeding 22570, August 2, 2018.
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90. EPCOR explained that it has no hydrovac or directional drilling capability internally. ETECH is responsible for providing hydrovac services to the entire EPCOR group of companies.80 EPCOR argued that, compared to providing these services internally, ETECH is able to leverage economies of scale and cost efficiencies due to the higher volume of work ETECH provides to all the EPCOR group of companies.81
91. EPCOR explained that it contacts ETECH and advises it of the date, time and locations where hydrovac services will be required. ETECH provides the required hydrovac service to EPCOR directly, using one of its own hydrovac units if available, or ETECH will make arrangements with one of 15 external hydrovac contractors pre-qualified through a competitive RFP process in 2016 to perform the service.82 When ETECH dispatches a non-affiliated hydrovac contractor, EPCOR is charged a straight flow-through rate, without mark-up from ETECH.83 In 2017, non-affiliated hydrovac contractors were dispatched for just over 50 per cent of EPCOR’s total hydrovac service requirements.
92. In response to a Commission IR, EPCOR stated:
Competitive rates paid to ETECH in respect of hydrovac services in comparison to rates paid to non-affiliate third-party hydrovac service providers can be lower, the same or higher. Competitive is measured by comparing the total estimated costs on a project by project basis for the hydrovac services being provided by ETECH and the non-affiliate hydrovac service providers. Comparing hydrovac services simply based on the hourly rate does not always result in the lowest project costs, as hydrovac service project costs can vary based on factors such as the skill and experience levels of the hydrovac operators, and the availability (often on short notice) of hydrovac service providers to meet EDTI’s prescribed project timelines. For example, a hydrovac service provider with a lower hourly rate may take more hours to complete work on an EDTI project resulting in an effective cost that is higher than would be the case with a hydrovac service provider with more experienced operators familiar with EDTI’s construction standards and specific work task requirements who charges a higher hourly rate but completes the task in a shorter amount of time; or, a hydrovac service provider with a lower hourly rate may not have the capacity (i.e., hydrovac unit availability) to meet EDTI’s project timeline.84
93. EPCOR further explained its rationale in selecting ETECH to manage its hydrovac needs as follows:
… due to the nature of hydrovac work (short duration, planned and emergency work, varying workloads on a daily basis), ETECH is not required to bid on individual projects to provide hydrovac services. Instead, EDTI has awarded ETECH full responsibility to ensure that competitive hydrovac services are available to EDTI at all times through the use of ETECH’s internal fleet or by dispatching a non-affiliated hydrovac contractor. When EDTI requires hydrovac services, EDTI contacts ETECH and advises the ETECH dispatcher of the date, time and location(s) where hydrovac services will be required to support EDTI’s construction crews. This approach minimizes EDTI’s non-wrench time (and associated project management costs) in checking the availability of hydrovac units and making arrangements with external hydrovac contractors in respect to the various
80 Exhibit 23571-X0002.01, application, paragraph 56. 81 Exhibit 23571-X0203, EPCOR argument, paragraph 54. 82 Exhibit 23571-X0002.01, application, paragraph 56. 83 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001(c). 84 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001(a).
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jobsites requiring hydrovac services; and minimizes construction delays on EDTI projects requiring hydrovac services.85
94. EPCOR also uses ETECH’s dewatering site for EPCOR’s hydrovac requirements. EPCOR confirmed that ETECH’s dewatering fee (i.e., disposal of the hydrovac materials) is the lowest price of which it is aware.86
95. For directional drilling services, EPCOR explained that neither it, nor ETECH, have the skilled crews or the specialized equipment required to carry out directional drilling work due to the specialized nature of this work:
As such, EPCOR uses only non-affiliated contractors to carry out its directional drilling work requirements. Similar to its hydrovac service requirements described above, EPCOR has awarded ETECH full responsibility to ensure that competitive directional drilling services are available to EDTI at all times by dispatching non-affiliated directional drilling contractors to meet EDTI’s project timelines. The 2017 directional drilling rates provided by non-affiliate contractors to ETECH (garnered though a competitive RFP process) are the same rates that ETECH charges to EDTI (i.e., a straight flow through of the rates without mark-up).87
96. The UCA argued that all ETECH costs for managing services should be denied capital tracker treatment and removed from EPCOR’s rate base.88 Relying on the evidence of Mr. Bell, the UCA asserted that EPCOR had not shown that ETECH’s services were the lowest cost alternative.
Commission findings 97. EPCOR must demonstrate that its inter-affiliate transactions adhere to its Inter-Affiliate Code of Conduct requirements, namely, that it has paid no more than fair market value for ETECH’s services. The Commission finds EPCOR’s use of ETECH to provide hydrovac services to be reasonable.
98. In support of this determination, the Commission finds that although ETECH’s hydrovac service hourly rates were not always at the lowest hourly rate, overall, the market value paid by EPCOR was fair when additional factors such as the other services that EPCOR receives from ETECH at little or no charge, namely, dispatch services of non-affiliated hydrovac contractors if ETECH is unavailable, and the provision of non-affiliated directional drilling contractors, on a flow through basis, are considered. Further, the Commission accepts EPCOR’s evidence that the rates it pays for dewatering services are the lowest price available.
7.1.2.6 Power base and/or pedestal repair and other jobbing services (thumping, fibre installation and streetlight installation and repairs) 99. For power base and/or pedestal repair, EPCOR uses ETECH to install, replace or repair existing power bases and pedestals as part of EDTI planned projects or in response to damaged assets.
85 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001(c). 86 Exhibit 23571-X0150.01, CONF-EDTI-UCA-2018AUG24-003(c). 87 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001. 88 Exhibit 23571-X0202, UCA argument, paragraph 2.
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100. EPCOR explained that because the need to replace damaged power bases or pedestals is sporadic in nature, EPCOR cannot guarantee a minimum level of work to non-affiliate contractors or ETECH. Moreover, this type of work usually requires immediate attention to ensure public safety and non-affiliate contractors, unlike ETECH, are unable to commit to EPCOR’s required response timelines. As such, EDTI does not use non-affiliate contractors for the replacement of damaged power bases or pedestals.89
101. EPCOR also does not provide this service internally. EPCOR stated that in 2017, it compared ETECH’s proposed rates with EPCOR’s internal costs to complete the same work and found that ETECH could complete this work at a lower cost than EPCOR.90
102. In 2017, ETECH’s invoiced costs associated with power base and/or pedestal repair were less than $10,000.
103. With respect to other jobbing services, this category of work consists of a combination of thumping (identification of faulted cable locations), fibre communication cable installation, the provision of generators for intersection traffic light outages, and, Light Rail Transit (LRT) power feed switching to accommodate work by EPCOR. EPCOR does not perform this work internally and ETECH was the only contractor pre-qualified to complete much of this scope of work.91
104. For identification of faulted cable locations, EPCOR used ETECH as well as a non- affiliate contractor to locate cable faults on secondary residential services. EPCOR stated that in 2017, ETECH’s residential thump rate was higher than the non-affiliated rate and, therefore, ETECH was only awarded a single project out of a total of 150 projects when the non-affiliate contractor was not available to carry out the cable fault location work.92
105. For fibre communication cable installations, EPCOR explained that it does not currently have any non-affiliate cable-pulling contractors who have been qualified by EPCOR to complete this scope of work. As such, EPCOR was unable to provide a direct cost comparison between ETECH and non-affiliate contractors for carrying out this type of work. EPCOR further explained that since ETECH and EPCOR share common union agreements, the direct hourly labour rates charged by ETECH to EPCOR are the same as the rates EPCOR would incur if it used internal resources to carry out this work.93
106. For streetlight installation and repairs, EPCOR explained that, to an extent, it relied on the City’s procurement processes in selecting ETECH. However, although the City uses non- affiliated contractors to perform some of this work, EPCOR did not. It explained that this was because ETECH was the only contractor on the City’s pre-qualified list that met EPCOR’s minimum safety requirements.94
107. The UCA took no position with respect to EPCOR’s use of ETECH for power base and/or pedestal repair and other jobbing services.
89 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001. 90 Exhibit 23571-X0002.01, application, paragraph 68. 91 Exhibit 23571-X0002.01, application, paragraph 69. 92 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001(a). 93 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001(a). 94 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-001(a).
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Commission findings 108. The Commission finds that EPCOR’s use of ETECH and other non-affiliated resources to provide these services was reasonable considering ETECH’s and other non-affiliated resources’ rates, experience, safety record and availability. Further, the Commission accepts EPCOR’s evidence that it could not have provided these services internally at a lower cost.
7.1.3 Asset usage fees 109. An asset usage fee (AUF) occurs when one of EPCOR’s functions (i.e., the distribution function or the transmission function) pays capital costs to the other function for the joint use of an asset owned by the function that receives the AUF. Double-counting could arise if EPCOR’s distribution function is applying for a K factor amount for a project, as determined by the accounting test, while also receiving an AUF from EPCOR’s transmission function that is intended to, in part, provide funding to EPCOR’s distribution function for EPCOR’s transmission function’s involvement in the project.
110. In Decision 20407-D01-2016, the Commission directed EPCOR “in its future capital tracker true up applications, to include a table outlining the variance in AUFs between forecast and actual amounts, as well as the actual K factor amounts before and after the AUF is applied.”95
111. In its application, EPCOR included an AUF K factor adjustment for the Work Centre Redevelopment and OMS/DMS Life Cycle Replacement projects.96 The K factors associated with the two projects, before and after the AUF adjustment, are displayed in Table 7 below. With the inclusion of an AUF, both project’s K factor adjustments decreased.
Table 7. 2017 AUF forecast compared to actual A B C D Project 2017 forecast 2017 actual 2017 actual K factor 2017 actual K factor before AUF after AUF is applied (C-B) ($ million) 1. Work centre redevelopment 1.71 1.44 5.78 4.28 2. OMS/DMS Life Cycle 0.04 0.29 1.92 1.63 Replacement projects Source: Exhibit 23571-X0002.01, application, paragraph 41, Table 2.2.6-1.
Commission findings 112. The Commission reviewed the variance in AUFs between the 2017 forecast and 2017 actual amounts, as well as the 2017 actual K factor amounts before and after the AUF was applied, and finds that the double-counting concern has been addressed. Further, the Commission finds that EPCOR has complied with the direction set out in Decision 20407-D01-2016.
7.1.4 Controls and accountability 113. In Decision 21592-D01-2017,97 the Commission stated:
95 Decision 20407-D01-2016, paragraph 241. 96 Exhibit 23571-X0002.01, application, paragraph 43. 97 Decision 21592-D01-2017, paragraph 57.
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57. The Commission reviewed EPCOR’s updated project management controls and accountability policies and procedures and finds that EPCOR has complied with the directions set out in paragraph 217 of Decision 20407-D01-2016. The Commission directs EPCOR to continue to confirm that these policies and procedures continue to be in place and to advi[s]e the Commission of improvements and modifications to these policies and procedures in future capital tracker applications.
114. To comply with this direction, EPCOR stated that the referenced policies and procedures continue to be in place.98 EPCOR noted that minor improvements and modifications were implemented in 2017 and provided updated project management guidelines in Appendix A, Section A-4, of its application.99
Commission findings 115. The Commission reviewed EPCOR’s updated project management controls and accountability policies and procedures and finds that EPCOR has complied with the direction set out at paragraph 57 of Decision 21592-D01-2017.
7.2 Capital tracker programs or projects for which no issues were raised 116. This section addresses the true-up of 2017 actual expenditures for the group of EPCOR’s programs or projects that raised no issues with the Commission or intervening parties. The Commission’s findings on these projects are set out in Section 7.2.15.
7.2.1 Third-Party Driven Relocations Program 117. The Third-Party Driven Relocations Program involves the relocation of existing distribution facilities upon request from third parties. For the 2017 capital tracker true-up, this program was composed of five individual projects required by the City of Edmonton. These projects were: the Southeast and West LRT Expansion Distribution System Relocation; the Franchise Agreement Driven Relocations and Conversions (ongoing); the Walterdale Bridge Replacement Distribution System Relocation; the Queen Elizabeth II Highway (QEII) and 41 Avenue SW Interchange Distribution System Relocations; and the North LRT Distribution System Relocations. Relocations that are required by the City are completed under the terms of EPCOR’s franchise agreement with the City.100 The need for this program as part of project assessment, under capital tracker Criterion 1, was approved in Decision 2013-435101 for 2013, in Decision 3100-D01-2015102 for 2014 and 2015, and in Decision 20407-D01-2016103 for 2016 and 2017.
118. EPCOR explained that it included projects that were completed in years prior to 2016, namely, the QEII and 41 Avenue SW Interchange Distribution System Relocations and the North LRT Distribution System Relocations projects in its 2017 capital tracker true-up application, in order to ascertain that the Third-Party Driven Relocations Program met the accounting test and the first tier of the materiality test.104
98 Exhibit 23571-X0002.01, application, paragraph 29. 99 Exhibit 23571-X0003, Appendix A, Appendix A-4 Project Management Policies and Procedures. 100 Exhibit 23571-X0002.01, application, paragraph 127. 101 Decision 2013-435, paragraphs 851 and 858. 102 Decision 3100-D01-2015, paragraph 192. 103 Decision 20407-D01-2016, paragraph 271. 104 Exhibit 23571-X0002.01, application, paragraphs 288 and 291.
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119. The 2017 approved forecast capital additions for this program were $10.67 million and the actual 2017 capital additions were $9.45 million, resulting in a $1.22 million negative variance.
120. EPCOR explained that the primary cause of this variance was a $4.84 million decrease from forecast to actual additions related to the Southeast and West LRT Expansion Distribution System Relocation Project where the decrease was mainly attributable to EPCOR being unable to complete and place into service a large number of its planned utility relocations in 2017 primarily for reasons beyond its control. This decrease was partially offset by a $1.54 million increase in capital additions between its 2017 forecast and actual costs, related to more underground relocations and aerial to underground relocations being completed in 2017 than forecast under the Franchise Agreement Driven Relocations and Conversions Projects. A variance of $2.08 million was also attributed to the Walterdale Bridge Replacement Distribution System Franchise Relocations Project because EPCOR, believing that the project would be completed prior to 2017, had not forecast any expenditure for the project.
7.2.2 Capitalized Underground System Damage Project 121. The Capitalized Underground System Damage Project consists of the replacement of underground distribution infrastructure, such as switching cubicles, underground cables, transformers and manhole covers that have been damaged or that have failed or are about to fail. The need for this project was approved in Decision 2013-435105 for 2013, in Decision 3100-D01-2015106 for 2014 and 2015, and in Decision 20407-D01-2016107 for 2016 and 2017.
122. The 2017 approved forecast capital additions for this project were $3.49 million and the actual 2017 capital additions were $5.55 million, resulting in a $2.06 million positive variance.108
123. EPCOR explained that the $2.06 million positive variance was primarily made up of a $0.90 million increase due to inadvertent errors made by EPCOR. The remaining $1.16 million variance was due to $0.45 million from more switching cubicles and underground manhole/vaults needing to be replaced than forecast, $0.29 million because more damaged and failed duct banks had to be replaced than forecasted, $0.24 million increase due to work being carried over from 2016 to 2017, and $0.18 million due to changes in EPCOR’s capital overhead policies.
124. After having confirmed the actual values for each capital tracker project, EPCOR discovered two errors relating to this project. First, EPCOR noted that in its 2016 capital tracker true-up application it had inadvertently included $0.26 million in closing construction work in progress (CWIP) for this project that should have been recorded as a 2016 capital addition.109 EPCOR corrected this error in the compliance filing to the 2016 capital tracker true-up. However, upon review of this application, EPCOR stated that the 2017 capital additions for this program included the $0.26 million in CWIP that was corrected as 2016 capital additions. The
105 Decision 2013-435, paragraph 908. 106 Decision 3100-D01-2015, paragraph 321. 107 Decision 20407-D01-2016, paragraph 273. 108 Exhibit 23571-X0002.01, application, paragraph 554, Table 3.1.8-1. 109 Exhibit 23571-X0002.01, application, paragraph 556.
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second error related to the mistaken capitalization to this project of $0.64 million in costs related to the replacement of faulted secondary underground cables.110
125. In order to rectify these errors EPCOR has proposed to reduce its 2017 actual capital additions related to this program by $0.26 million related to CWIP and $0.64 million related to the capitalization of secondary cable faults in its compliance filing. This reduction in capital additions will lead to a K factor reduction of approximately $0.04 million.
126. In a Commission IR, EPCOR was asked why it had not addressed the errors prior to EPCOR’s submission of the application.111 EPCOR replied that it had not realized the errors until very close to the submission of the application and had it addressed the errors prior to the submission of the application, its submission would have been delayed two to three weeks because EPCOR would have had to rerun all of its models and schedules to revise the application.112
127. The CCA examined the costs incurred by EPCOR for unanticipated duct bank replacement work that comprised 14 per cent or $.029 million of the variance between the approved forecast and actual expenditures incurred under this project in 2017. In a CCA IR, EPCOR was asked to explain its forecast methodology, why work on duct banks was unusual in 2017 based on past years, and when the duct work was identified to be completed. EPCOR responded by stating that using a forecast methodology of average historical costs, reflecting actual work conducted for a life cycle replacement project represented a reasonable basis for future expenditures. EPCOR stated that the replacements of duct banks were unanticipated because there had been no expenditures related to this equipment in the last three years; therefore, no forecast capital additions were related to this type of work. EPCOR provided the additional actual capital additions related to 2015, 2016 and 2017, as well as noting that the work related to the duct banks was completed between March and October 2017. 113
7.2.3 New Underground and Aerial Service Connections for Commercial, Industrial, Multi-Family and Miscellaneous Customers 128. The New Underground and Aerial Service Connections for Commercial, Industrial, Multi-Family and Miscellaneous Customers Project is an ongoing growth project and consists of the engineering and installation of the distribution facilities necessary to connect new industrial, commercial, multi-family, unmetered secondary and rural customers to EPCOR’s distribution system. This project also includes increasing the capacity of, and upgrading, existing service connections when requested by these types of customers. The need for this program was approved in Decision 2013-435114 for 2013, in Decision 3100-D01-2015115 for 2014 and 2015, and in Decision 20407-D01-2016116 for 2016 and 2017.
110 Exhibit 23571-X0002.01, application, paragraph 557. 111 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-004. 112 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-004. 113 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-019. 114 Decision 2013-435, paragraph 919. 115 Decision 3100-D01-2015, paragraph 356. 116 Decision 21430-D01-2016, paragraph 16.
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129. The 2017 approved forecast capital additions for this project were $11.34 million117 and the actual 2017 capital additions were $12.47 million,118 resulting in a positive variance of $1.13 million.
130. EPCOR explained that the $1.13 million increase in capital additions in 2017 was primarily due to a $4.17 million increase reflecting the complex nature of the work offset by a $3.04 million decrease reflecting a lower than forecast volume of customer connections being requested in 2017.119 While fewer customers were connected than forecast for underground projects, a higher than average number of those projects were in the downtown network, including the new Stantec Tower, the new Delta Hotel, and the Norquest College service connections.120
7.2.4 Underground Residential Distribution Servicing - Rebates, Acceptance Inspections and Terminations 131. The Underground Residential Distribution (URD) Servicing - Rebates, Acceptance Inspections and Terminations Project includes development rebates, acceptance inspections, terminations, and distribution work performed by EPCOR with respect to URD servicing. The need for this project was approved in Decision 2013-435121 for 2013, in Decision 3100-D01- 2015122 for 2014 and 2015, and in Decision 20407-D01-2016123 for 2016 and 2017.
132. The 2017 approved forecast capital additions for this project were $18.51 million, and the actual 2017 capital additions were $11.32 million, resulting in a $7.19 million negative variance.
133. EPCOR explained that the negative variance was primarily due to a $6.82 million decrease in URD rebates paid to developers due to $5.99 million in fewer and smaller developments being designed and built by developers and a $0.81 million decrease due to a change to EPCOR’s allocation methodology for capital overhead related to URD rebates, as discussed earlier in Section 7.1.1 of this decision. The variance was also due to a $0.30 million decrease in URD work and inspections and terminations, due to the decreased volume of work undertaken and a $0.07 million decrease in URD work by EDTI due to the decreased volume of work undertaken relative to its forecast.124
7.2.5 Poundmaker Feeders 134. The Poundmaker Feeder Project, approved by the Commission in Decision 2012-272,125 involved the construction of four feeders from EPCOR’s Poundmaker substation, a point of delivery (POD) located in west Edmonton. This project was completed over the 2011 to 2013 period. The need for this project was approved in Decision 2013-435.126 In Decision 3100-D01- 2015, the Commission determined that the actual scope, level and timing of the work for the
117 Decision 21430-D01-2016, paragraph 74. 118 Exhibit 23571-X0002.01, application, paragraph 467. 119 Exhibit 23571-X0002.01, application, paragraph 484. 120 Exhibit 23571-X0002.01, application, paragraph 487. 121 Decision 2013-435, paragraph 923. 122 Decision 3100-D01-2015, paragraph 378. 123 Decision 20407-D01-2016, paragraph 273. 124 Exhibit 23571-X0002.01, application, paragraph 647. 125 Decision 2012-272: EPCOR Distribution & Transmission Inc., 2012 Phase I and II Distribution Tariff, 2012 Transmission Facility Owner Tariff, Proceeding 1596, Application 1607944-1, October 5, 2012. 126 Decision 2013-435, paragraph 935.
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Poundmaker Feeders Project and the actual costs in each of 2011, 2012 and 2013, totalling $11.47 million, were prudent.127
135. As explained in Decision 2013-435, the Poundmaker Feeders Project is a Category 3128 project that requires capital tracker treatment because of the application of the mid-year convention. The application of the mid-year convention calculation in the determination of return and depreciation with respect to projects going into service in the year prior to the commencement of PBR, may cause a shortfall in capital funding under the PBR formula.129 As such, although there were no capital additions for the Poundmaker Feeders Project in 2017, EPCOR included the Poundmaker Feeders Project in the 2017 capital tracker true-up.
7.2.6 Outage Management System/Distribution Management System Life Cycle Replacement 136. The Outage Management System/Distribution Management System (OMS/DMS) Life Cycle Replacement Project is a multi-year project (2011 to 2017) that consists of replacing the obsolete technology and systems used in EPCOR’s Control Operations centre. The need for this project was approved for 2015 in Decision 3100-D01-2015,130 and for 2016 and 2017 in Decision 20407-D01-2016.131
137. EPCOR explained that it completed all work associated with this project in 2017, which included integrating geographic information system (GIS) data and the field work order fulfillment system with the OMS/DMS system testing and roll out, and setup of the overall control system backup system.132 Actual capital additions for this project were $0.72 million less than the approved forecast amount.133
7.2.7 Underground Industrial Distribution Servicing – Rebates, Acceptance Inspections and Terminations 138. The Underground Industrial Distribution (UID) Servicing – Rebates, Acceptance Inspections and Terminations Project consists of installing new underground 15-kV and 25-kV primary cables, switching cubicles, and ancillary equipment in order to connect new industrial lots in EPCOR’s service area to the distribution system, and carrying out modifications to correct
127 Decision 3100-D01-2015, paragraph 425. 128 Category 3 projects receive capital tracker treatment when the revenue provided under the I-X mechanism is not sufficient to recover the entire revenue requirement associated with the prudent capital expenditure for this project. For a completed Category 3 project, the K factor amount associated with such a project becomes a function of the accounting test and materiality test calculations. The Commission verifies that the revenue requirement calculations for a Category 3 project in the accounting test are based on the approved actual capital additions for the project. The Commission undertakes a project assessment for any Category 3 project in which the actual costs are not approved by the Commission. Once Category 3 projects are approved as satisfying Criterion 2 in a given year, no further Criterion 2 approvals are required to continue the project as a capital tracker. Criterion 3 requirements, however, must be satisfied for each forecast year and in each true-up application. 129 Decision 2013-435, paragraph 932. 130 Decision 3100-D01-2015, paragraph 444. 131 Decision 20407-D01-2016, paragraph 357. 132 Exhibit 23571-X0002.01, application, paragraph 667. 133 Exhibit 23571-X0002.01, application, paragraph 676.
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wiring issues. The need for this project was approved in Decision 3100-D01-2015134 for 2013, 2014 and 2015, and in Decision 20407-D01-2016135 for 2016 and 2017.
139. The 2017 approved forecast capital additions for this project were $2.26 million, and the actual 2017 capital additions were $1.90 million, resulting in a $0.36 million negative variance. EPCOR explained that the primary cause of this variance was the completion of 85 per cent fewer hectares than forecast and significantly less feeder work being required to support the new lots. EPCOR explained that several lots serviced in 2017 were existing lots that were subdivided, but did not account for any additional hectares as these hectares were accounted for in a previous year when initially serviced.136
7.2.8 Replacement of Faulted Distribution PILC Cables 140. The Replacement of Faulted Distribution Paper Insulated Lead Covered (PILC) Cables Project consists of the replacement of faulted distribution PILC cable and cable accessories as cable faults occur. The need for this project as part of the project assessment under capital tracker Criterion 1 was approved in Decision 3100-D01-2015137 for 2014 and 2015, and in Decision 20407-D01-2016138 for 2016 and 2017.
141. The 2017 approved forecast capital additions for this project were $1.38 million,139 and the actual 2017 capital additions were $0.79 million, resulting in a $0.59 million negative variance.140 EPCOR explained that the decrease in capital additions from forecast was primarily due to a lower number of faulted PILC cables that required replacing, as well as a lower actual average repair cost for each PILC cable.141
7.2.9 Neighbourhood Renewal 142. The Neighbourhood Renewal Program comprises the replacement of a large portion of EPCOR’s electric distribution infrastructure within identified aging neighbourhoods. The need for this program as part of the project assessment under capital tracker Criterion 1 was approved in Decision 3100-D01-2015142 for 2014 and 2015.
143. EPCOR incurred negative $0.01 million in capital additions for this program in 2017, compared to a forecast of $0.00 for the year. This decrease was the result of an allocated credit from a purchase order true-up in 2017 for payments made prior to 2017.143
134 Decision 3100-D01-2015, paragraphs 469 and 472. 135 Decision 20407-D01-2016, paragraph 273. 136 Exhibit 23571-X0002.01, application, paragraph 722. 137 Decision 3100-D01-2015, paragraph 489. 138 Decision 20407-D01-2016, paragraph 273. 139 Decision 21430-D01-2016, paragraph 16. 140 Exhibit 23571-X0002.01, application, paragraph 727, Table 3.1.17-1. The Commission has incorporated the change in the 2017 D, which is the approved forecast, from $1.38 million to $1.40 million, consistent with the approved amount in paragraph 273 of Decision 20407-D01-2016. 141 Exhibit 23571-X0002.01, application, paragraph 748. 142 Decision 3100-D01-2015, paragraph 501. 143 Exhibit 23571-X0002.01, application, paragraphs 750-754.
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7.2.10 Customer Revenue Metering 144. As directed by the Commission in Decision 20407-D01-2016,144 EPCOR grouped two projects, Customer Revenue Metering – Growth and Life Cycle Replacements and advanced metering infrastructure (AMI), into the Customer Revenue Metering Program for capital tracker treatment. As discussed in that decision, during the 2015-2017 period, the type of meter to be installed under each of these projects was to be an AMI meter. Starting in September 2015, EPCOR began installing AMI meters for both growth and normal course replacement purposes under the Customer Revenue Metering – Growth and Life Cycle Replacement projects. The mass replacement of existing meters with AMI meters began in 2015 and was to be completed in 2017 as part of the AMI Project, which is discussed further below.
Customer Revenue Metering – Growth and Life Cycle Replacements 145. This ongoing project consists of installing revenue meters at new sites and replacing meters at existing sites that are no longer compliant with Measurement Canada requirements.145 The need for this project was approved in Decision 3100-D01-2016146 for 2013, 2014 and 2015, and in Decision 20407-D01-2016147 for 2016 and 2017.
146. The 2017 approved forecast capital additions for this project were $2.84 million, while the actual 2017 capital additions were $3.144 million, resulting in a $0.30 million positive variance. EPCOR explained that it replaced fewer meters compared to years prior to 2015, reflecting Measurement Canada’s approval of a temporary dispensation due to EPCOR’s AMI Project.
147. In an IR, the Commission asked EPCOR whether Measurement Canada had given specific instructions that identify meter groups that do not qualify for dispensation, or was the change, which resulted in an understating of the need for meter replacements, a result of EPCOR reviewing Measurement Canada’s documentation and drawing its own conclusion. In response, EPCOR stated:
In the course of EDTI’s detailed meter population review for its dispensation application to Measurement Canada in 2015, EDTI determined that a number of meters would not meet the requirements for dispensation based on EDTI’s detailed review and evaluation of its historical test results. As such, EDTI identified them in its application as not qualifying for dispensation. Measurement Canada, in assessing EDTI’s dispensation application, agreed with EDTI’s detailed evaluation, and in its dispensation decision required EDTI to replace the meters listed in EDTI’s dispensation application.148
148. The Commission also asked which meter groups did not qualify for dispensation and for EPCOR to provide an example. In response, EPCOR stated residential, network, polyphase and commercial demand meter groups did not qualify for dispensation. EPCOR stated these meter groups did not qualify because the meters did not have historical test results strong enough to
144 Decision 20407-D01-2016, paragraph 67. 145 Proceeding 3100, Exhibit 0080.00.EDTI-3100, 2014-2015 forecast application, paragraph 433. 146 Decision 3100-D01-2015, paragraphs 516 and 518. 147 Decision 20407-D01-2016, paragraph 564. 148 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-003, response (a).
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assure Measurement Canada that their accuracy would be maintained throughout the dispensation period.149
Advanced Metering Infrastructure 149. This multi-year project involves the installation of an AMI system consisting of AMI meters and networking infrastructure that will fully automate EPCOR’s meter reading function. The AMI technology (including the installation of AMI meters, also known as “smart meters”) will replace currently used manual processes for reading and energizing or de-energizing meters, and enable more efficient access to end-user information, such as usage, voltage, tamper detection, and service interruption and restoration indications. It will also remotely manage functions such as service connections, service disconnections, load limiting and firmware upgrades.
150. The AMI Project was implemented in two distinct phases. Phase I consisted of constructing and testing AMI network infrastructure, including collectors and all computer hardware and software necessary to process all meter reading data as well as the installation of approximately 10,000 meters to test the system. Phase II consisted of deploying all meters over a period of two years. Phase I was substantially completed in 2015 and the remainder was completed in 2016. Phase II meter installations were completed in 2017.150
151. In Decision 20407-D01-2016, the Commission approved the need for the AMI Project for the 2016-2017 forecast period.151 The 2017 approved forecast capital additions for this project were $26.04 million, while the actual 2017 capital additions were $24.82 million, resulting in a $1.22 million negative variance.
152. EPCOR stated that the $1.22 million negative variance was mostly due to $2.70 million less expenditures reflecting lower than forecast number of installations, which were partially offset by a $1.50 million increase in costs due to higher than forecast actual exchange rates incurred on U.S. dollar purchases of $9.64 million. The remaining variance amounts are explained by changes to installation costs from the forecast.
153. EPCOR installed 118,155 meters during 2017, which was 44,633 less than its forecast of 162,788 meters. Between 2015 and 2017, 3,309 fewer meters than forecast were installed. Fewer meters were installed for several reasons: (i) by the end of 2017, 781 customers opted out of EPCOR’s standard meter; (ii) 146 residential meters could not be replaced due to EPCOR’s inability to gain access to the customer’s site; (iii) 86 commercial/industrial meters could not be exchanged at locations where radio frequency signals could not penetrate walls to reach an AMI meter; (iv) 2,544 meters that were exchanged under this program were required as part of EPCOR’s Measurement Canada compliance program; and (v) 248 additional meters, reflecting the difference between the forecast number of meters originally forecast as part of the program in 2015, were placed into service.152
149 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-003, response (b). 150 Exhibit 23571-X0002.01. application, paragraph 320. 151 Decision 20407-D01-2016, paragraph 656. 152 Exhibit 23571-X0002.01, application, paragraph 330.
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7.2.11 IT Hardware Lifecycle Replacements and Additions 154. The IT Hardware Lifecycle Replacements and Additions Program is composed of two projects: the Desktop Evergreen Project, and the Server Hardware/Software Re-Platform Project. The Desktop Evergreen Project is an ongoing project consisting of replacing and upgrading obsolete desktop computers, laptops, mobile devices and printers. The Server Hardware/Software Re-Platform Project is a one-year project to re-platform the servers used to support key applications onto a new operating system. The need for this program as part of the project assessment under capital tracker Criterion 1 was approved in Decision 20407-D01- 2016153 on a forecast basis for 2016 and 2017.
155. The 2017 approved forecast of capital additions for the Desktop Evergreen Project was $0.41 million. There was no 2017 forecast for the Server Hardware/Software Re-Platform Project. The actual 2017 capital additions for the Desktop Evergreen and Server Hardware/Software Re-Platform projects were $0.51 million and $0.13 million, respectively, for a total of $0.64 million.154
156. The Desktop Evergreen Project had a positive variance of $0.10 million. In 2017, EPCOR replaced 178 desktop computers, 111 laptops and mobile devices, and two plotters as part of the Desktop Evergreen Project. EPCOR replaced 81 more laptops and mobile devices than forecast to complete the roll-out of simplified work applications to field employees, which started in 2016. EPCOR explained that a greater number of laptops and mobile devices met the replacement criteria as they were no longer capable of meeting the software requirements because they did not support the mobile applications required. Offsetting the additional computers and devices, EPCOR did not replace any of the 13 forecast multifunction printers, by implementing a shared network printer solution, as an alternative to individual printers in multiple offices.155
157. The Server Hardware/Software Re-Platform Project had a positive variance of $0.13 million. EPCOR explained that the variance was due to a timing difference in transferring approximately 30 per cent of the applications to the new servers, which were originally planned for 2016 but completed in 2017. EPCOR further explained that the delay did not result in any difference in the overall cost of completing the work versus the forecast.156
7.2.12 Manhole Rebuilds and Life Cycle Replacements 158. This program consists of two projects: the Distribution Manhole Rebuilds Project, and the Rebuild and/or Replace Civil Work for Downtown Vaults and Manholes Project. The first project is a life cycle replacement program consisting of repairing or replacing all or some components in distribution manholes to the extent determined to be necessary based on the results of EPCOR’s inspections program. The second project is an ongoing life cycle project that involves completing civil rebuilds and replacements of vaults and manholes in EPCOR’s downtown underground network. The need for these projects as part of the project assessment
153 Decision 20407-D01-2016, paragraph 482. 154 Exhibit 23571-X0002.01, application, paragraph 850, Table 3.1.21-3. 155 Exhibit 23571-X0002.01, application, paragraph 851. 156 Exhibit 23571-X0002.01, application, paragraph 859.
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under capital tracker Criterion 1 was approved in Decision 20407-D01-2016.157 In that decision, the Commission also directed EPCOR to group these two projects together in one program.158
159. For the Distribution Manhole Rebuilds Project, the 2017 approved forecast capital additions for this project were $0.20 million, and the actual 2017 capital additions were $0.18 million, resulting in a $0.02 million negative variance. EPCOR explained that $0.10 million of this variance was due to the deferral of one roof adjustment and lid adjustments for two manholes being deferred to 2018. The repairs were deferred due to engineering resource constraints. EPCOR confirmed that the deferral of the manhole repair and lid adjustments work has not resulted in any safety issues.159 The variance was partially offset by a $0.08 million increase related to work that was completed as immediate civil repair of distribution manholes and vaults not anticipated in 2017.160
160. For the Rebuild and/or Replace Civil Work for Downtown Vaults and Manholes Project, the 2017 approved forecast capital additions were $1.23 million, and the actual 2017 capital additions were $0.85 million, resulting in a $0.38 million negative variance. EPCOR explained that this variance was primarily driven by a $0.42 million decrease in costs related to savings realized by using new work methods. A $0.05 million decrease was due to the deferral of vault lighting for one of the three network vault rebuilds anticipated to be completed in 2017. EPCOR anticipated completing this work in 2018.161 The decreases were partially offset by a $0.09 million increase related to the completion of work in 2017 that was not completed in 2016.162
7.2.13 Network Reconfigurations 161. The Network Reconfigurations project is a multi-year project consisting of the reconfiguration of EPCOR’s 208-volt and 600-volt downtown underground networks, with work commencing in 2016. EPCOR received capital tracker treatment approval for this project on a forecast basis in Decision 20407-D01-2016,163 where the need for this project as part of the project assessment under capital tracker Criterion 1 was tested. Although work on this project commenced in 2016, EPCOR did not apply for capital tracker treatment at that time because the program did not meet the first tier of materiality threshold for 2016.
162. EPCOR provided a project description including a Business Case and Engineering Study,164 noting that the Network Reconfigurations project was started in 2013 based on a study by Quanta Technology, LLC. The project is related to safety and reliability in order to reduce fault levels at substations, on all network circuits and at network transformers, as well as to replace its existing network protectors to increase safety for employees working in proximity to
157 Decision 20407-D01-2016, paragraph 106. 158 Decision 20407-D01-2016, paragraph 104. 159 Exhibit 23571-X0002.01, application, paragraphs 1036 and 1055. 160 Exhibit 23571-X0002.01, application, paragraph 1056. 161 Exhibit 23571-X0002.01, application, paragraph 1085. 162 Exhibit 23571-X0002.01, application, paragraph 1086. 163 Decision 20407-D01-2016, paragraph 529. 164 Exhibit 23571-X0077, Appendix C-29.
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this equipment.165 EPCOR provided the original Quanta Technology report as an appendix to its Business Case and Engineering Study.166
163. The 2017 approved forecast capital additions for this project were $3.53 million,167 and the actual 2017 capital additions were $1.23 million,168 resulting in a $2.30 million negative variance. EPCOR explained that the decrease was primarily due to its inability to complete planned work for: two network transformer reconfigurations in the NV35 circuit; savings from the V2X/V3X ductbank; the V41N circuit not being completed due to its dependence on the NV35 circuit; lower than forecast costs on the NV181 and NV325 circuit transfers off of the V41N circuit; lower than forecast costs in disconnecting its transformer from the R21N circuit; and the removal of a vault on the NV58 circuit.169 EPCOR also noted that the decrease was partially offset by an increase in capital spending related to NV135N and NV135S transformer refeeds on the V41N circuit and rerouting scope changes on the R21N circuit at the Rossdale substation.170
7.2.14 Street Light Service Connections and Security Lighting Addition and Capital Replacement 164. This project consists of ensuring that EPCOR’s street lighting, signal and security lighting customers are provided with adequate, safe and reliable service connections. Additionally, costs included in completing capitalized repairs or additions to EPCOR-owned security lighting systems are included in this project.171 The need for this project as part of the project assessment under capital tracker Criterion 1, was approved in Decision 20407-D01- 2016.172
165. As part of EPCOR’s 2019 PBR Annual Rate Adjustment filing, the Commission asked EPCOR in an IR to provide the correct amount of capital additions for this project. In Table 3.2.5-1 to this application, EPCOR had stated its 2017 capital additions for this project were $0.62 million. In the application update to its 2019 PBR rate adjustment filing, the capital additions for this project were $0.82 million. EPCOR explained that the correct capital additions for this project were $0.82 million. EPCOR subsequently confirmed that the correct capital additions amount of $0.82 million was used within the 2017 capital tracker model.173 The 2017 approved forecast capital additions for this project were $0.36 million, resulting in a $0.46 million positive variance.
166. EPCOR explained that the variance was primarily driven by higher than historical average repair costs reflected in EPCOR’s 2017 forecast which was based on a three-year average from 2012 to 2014. Further, it explained that in 2017 a number of repairs were
165 Exhibit 23571-X0002.01, application, paragraph 1148. 166 Exhibit 23571-X0077, Appendix C-29, PDF page 14. 167 Decision 21430-D01-2016, paragraph 16. 168 Exhibit 23571-X0002.01, application, paragraph 1120, Table 3.2.4-1. 169 Exhibit 23571-X0002.01, application, paragraph 1148. 170 Exhibit 23571-X0002.01, application, paragraph 1149. 171 Exhibit 23571-X0002.01, application, paragraph 1151. 172 Decision 20407-D01-2016, paragraph 543. 173 Exhibit 23896-X0050, EDTI-AUC-2018NOV02-001, page 1-2.
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completed in which EPCOR had difficulty locating underground cable faults which resulted in higher labour and associated costs.174
7.2.15 Commission findings on EPCOR’s capital tracker programs or projects for which no issues were raised 167. With respect to the true up of 2017 actual costs for projects or programs for which the Commission has previously confirmed the need under the project assessment component of Criterion 1 in prior capital tracker decisions, as noted in Section 4, if there is no evidence on the record of the true-up proceeding demonstrating that a project was not required in 2017, EPCOR is not required to demonstrate that a project was needed in order to provide utility service at adequate levels in 2017, as would otherwise be required under the project assessment component of Criterion 1. Because the Commission has previously determined that each of the programs or projects reviewed in this section satisfied the project assessment requirement of capital tracker Criterion 1 in one or more previous years, the Commission finds no evidence on the record of this proceeding to indicate that any of these programs or projects reviewed in this section were not required in 2017.
168. With respect to the scope, level and timing of each of the programs or projects reviewed in this section (Section 7.2) and carried out in 2017, the Commission reviewed EPCOR’s 2017 actual capital additions associated with each of these programs or projects and finds that the capital additions are generally consistent with the scope, level and timing of the work outlined in the business cases for these capital trackers and approved in Decision 20407-D01-2016.
169. The Commission has also reviewed the 2017 actual capital additions for each of these programs or projects, and in light of the evidence supporting these costs, the associated procurement and construction practices and the evidence explaining the differences between approved forecast and actual costs, the Commission finds the actual costs to be prudent.
170. In the remainder of Section 7, the Commission provides its findings regarding the prudency of prior-approved EPCOR capital tracker projects and programs for which issues were raised by interveners or the Commission.
7.3 New 15-kV and 25-kV Circuit Additions 171. The New 15-kV and 25-kV Circuit Additions Project is an ongoing project consisting of the construction of new distribution circuits needed to maintain reliability and to provide sufficient capacity for EPCOR’s distribution system. The need for this project was approved in Decision 2013-435175 for 2013 and in Decision 3100-D01-2015176 for 2014 and 2015, and in Decision 20407-D01-2016177 for 2016 and 2017.
172. In 2017, EPCOR worked on eight subprojects as part of this project and completed construction of circuits V29 and V48, 24C, 13E, V42, 23PM, 24SU and R49 as previously forecast in either its 2016 or 2017 years from its 2016 and 2017 capital tracker application, its 2016 capital tracker true-up application, and the R49 business case and engineering study. In addition, EPCOR completed as-built drawings for the utility right-of-way and Transportation
174 Exhibit 23571-X0002.01, application, paragraph 1167. 175 Decision 2013-435, paragraph 879. 176 Decision 3100-D01-2015, paragraph 253. 177 Decision 20407-D01-2016, paragraph 310.
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Utility Corridor (TUC) for Circuit 33PM in 2017. The 2017 approved forecast capital additions for this project were $12.41 million178 and the actual 2017 capital additions were $15.07 million, resulting in a $2.66 million positive variance.179 EPCOR did not complete additions for circuits 14C and V58 in 2017 as originally forecast.180 A list of these subprojects and their contributions to the variance are provided in Table 8.
Table 8. 2017 new 15-kV and 25-kV circuit additions Description 2017 D 2017 A Variance ($ million) Circuits V29 and V48 - 0.88 0.88 Circuit 24C - 4.76 4.76 Circuit 13E - 0.80 0.80 Circuits V42 and V58 0.83 0.36 (0.47) Circuit 14C 1.81 - (1.81) Circuit 23PM 5.07 3.65 (1.42) Circuits 24SU 4.7 3.77 (0.93) Circuit R49 - 0.81 0.81 Circuit 33PM - 0.04 0.04 Total 12.41 15.07 2.66
Source: Exhibit 23571-X0002.01, Table 3.1.4-3
173. EPCOR explained that the variance included a $4.76 million increase related to the deferral of the Circuit 24C addition subproject. Circuit 24C was delayed from its proposed timing in EPCOR’s 2016 capital tracker true-up application, because customer loads in the area surrounding Circuit 24C were not materializing as quickly as forecast. It attributed $2.08 million of the $4.76 million for this subproject to that deferral.181
174. EPCOR added that the remaining $2.68 million increase in the Circuit 24C subproject cost was the result of (i) $1.7 million for a new six-way ductline across a TUC;182 (ii) $0.41 million related to soil conditions not anticipated in the forecast; (iii) $0.26 million related to higher than forecast underground utility congestion; (iv) $0.17 million due to a change in conductor for the project; and (v) $0.14 million related to a creek crossing that required additional labour charges.183
175. EPCOR explained that the new six-way ductline reflected a change from its forecast single-duct configuration. During detailed design EPCOR determined that a six-way ductline would help accommodate three future circuits (14C, 11C and 21C) in that area, and that such an option would minimize future civil construction costs and leverage existing approvals within the TUC. EPCOR stated that there was limited unencumbered land within the TUC for additional feeders, and that securing the alignment and installing additional duct space would allow future projects to proceed in a timely and cost-effective manner.184 EPCOR provided a net present value
178 Decision 21430-D01-2016, paragraph 16. 179 Exhibit 23571-X0002.01, application, paragraph 409, Table 3.1.4-1. 180 Exhibit 23571-X0002.01, application, paragraph 412. 181 Exhibit 23571-X0002.01, application, paragraph 462. 182 Exhibit 23571-X0002.01, application, paragraph 416. 183 Exhibit 23571-X0002.01, application, paragraph 462. 184 Exhibit 23571-X0002.01, application, paragraphs 415-417.
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(NPV) calculation of both alternatives. Using 2027 as the year for comparison of both alternatives, its calculation showed a $0.12 million benefit to ratepayers by undertaking the six- way ductline in 2017 as opposed to the originally forecast year.185 186
176. EPCOR also explained that it incurred a $0.88 million cost increase for the circuits V29 and V48 subproject composed of a $0.81 million increase in costs due to a delay in energizing facilities that were completed in 2016 but fully energized after customers completed work in 2017, a $0.07 million increase in costs for a system neutral line, one custom racking system, and one City of Edmonton requirement. Additional subprojects with increased costs included $0.81 million for Circuit R49 due to customer delays; $0.80 million for Circuit 13E due to the future widening of 17 Street changing the scope of the subproject; $0.04 million related to as- built drawings for Circuit 33PM, as well as registering of the utility right-of-way within the TUC.187
177. Relative to its original forecast, EPCOR’s cost variances were: a $1.81 million decrease related to deferring the Circuit 14C subproject from 2017 to 2018; a $1.42 million decrease in the cost of the Circuit 23PM subproject due to project scope and total new circuit length; a $0.93 million decrease in the cost of the Circuit 24SU subproject due to a decrease in project scope and total new circuit length; and a $0.47 million decrease related to the circuits V42 and V58 subproject due to Circuit V58 being deferred and Circuit V42 being completed one year in advance.188
178. The CCA asked for clarification about the increases to the Circuit 24C subproject in an IR. The CCA questioned the $1.7 million in costs related to the six-way ductline across the TUC, why 2027 was the year in which the expanded capacity for the ductline would be required, and the $0.17 million increase due to the conductor change for the circuit.189
179. In response, EPCOR stated that it chose a 10 year projected standard for both alternatives in order to get a consistent cost comparison and not because those circuits would be required in 2027.190 EPCOR explained that cables and ductline are long-term assets. Because the assets are included as part of EPCOR’s rebasing revenue requirement, customers bear these costs irrespective of the fact that funding is capped in the 2018-2022 PBR term. EPCOR asserted that higher costs would have been incurred if it had installed assets as forecast and then upgraded from the smaller configuration to the six-way ductline in the future.191
180. EPCOR explained that the incremental increase of $0.17 million for the cable cost was due to its installation of a 750 MCM192 copper cable instead of the planned 500 MCM aluminum cable. In order to accommodate future growth in the area, EPCOR would have been required to
185 Exhibit 23571-X0002.01, application, paragraph 418. 186 Exhibit 23571-X0010, Appendix B-6-1. 187 Exhibit 23571-X0010, Appendix B-6-1. 188 Exhibit 23571-X0002.01, application, paragraph 463. 189 Exhibit 23571-X0096, CCA-EDTI-2018JUN15-016. 190 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-016(d). 191 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-016(c). 192 MCM means 1,000 circular mils, which is a unit used to measure the area of the circular cross-section of a wire.
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install either another 500 MCM aluminum cable, or replace the existing 500 MCM aluminum cable with a 750 MCM copper cable by approximately 2023. Due to the imminent upgrade, EPCOR decided to install the 750 MCM copper cable, which has the additional capacity required to accommodate future expected load growth.193
181. In a second round of IRs, the CCA asked EPCOR to provide an estimate of when future costs would be incurred for Circuit 24C, details of the cost forecast for 2027, as well as a sensitivity analysis.194 EPCOR responded that its engineering estimate for when additional costs would be incurred would be sometime after the year 2027. It explained that the Clover Bar substation, where Circuit 24C and the six-way ductline are installed, is located close to a developing industrial park. Its System Planning group had received preliminary inquiries for an estimated 20 to 100 megavolt amperes (MVA) of new load in the area, but until those customers actually committed to take service, it does not design or construct any new distribution feeders.195 EPCOR also showed five- and 15-year alternatives to the 2027 forecast that showed the NPV across all three options favoured ratepayers.196
182. In its argument, the CCA took issue with the fact that EPCOR’s engineering estimates put additional costs incurred sometime after the year 2027, yet the NPV was chosen to be for 2027. The CCA considered the decision to install the six-way ductline to be speculative, and argued that had EPCOR delayed the project into the future, it would be included in EPCOR’s K-bar funding. The CCA asserted that undertaking the subproject now as opposed to in the future has the potential to cost EPCOR consumers the incremental capital funding at stake in the current capital tracker true-up application.197
183. The CCA concluded that EPCOR spent in advance of its engineering forecast and oversized the six-way ductline and, therefore, the $1.7 million should not be included in rate base, as it is not currently required for utility service. The CCA also submitted that the incremental $1.7 million for the oversized ductline should be denied.198
184. In reply argument, EPCOR asserted that its decision-making was effective and prudent, given the use of the TUC that was involved in this subproject. EPCOR noted that of the six-way duct bank that was constructed out of its Clover Bar POD, one duct is used for the new Circuit 24C distribution feeder, one is used for a system neutral cable, three ducts are for three future Clover Bar feeders, and one duct is set aside as a spare duct for emergency cable replacements.199
185. In addition to its concerns regarding the six-way ductline, the CCA also raised concerns in argument with EPCOR’s Aurum aerial circuit, which is part of the Circuit 24C subproject. It proposed that to the extent the line is partially used, it should be put into Plant Held for Future Use until the line is used at some point in the future.200
186. In its application, EPCOR stated that “proposed land development in the Aurum area was not completed as forecast and, as a result of this, 1 km of aerial 336.4 MCM aluminum conductor
193 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-016(e) and (f). 194 Exhibit 23571-X0143, EDTI-CCA-2018AUG24-028. 195 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-028(a) and (b). 196 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-028(c). 197 Exhibit 23571-X0200, CCA argument, paragraph 76. 198 Exhibit 23571-X0200, CCA argument, paragraphs 74, 79 and 82. 199 Exhibit 23571-X0206, EPCOR reply argument, paragraphs 58-61. 200 Exhibit 23571-X0200, CCA argument, paragraph 86.
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steel-reinforced (ACSR) cable was installed versus the forecast 0.9 km of 500 MCM aluminum cable in direct buried conduit.”201
187. In reply argument, EPCOR clarified that the Aurum area is in staged development, and that the line discussed as part of Circuit 24C was energized and placed into service in 2017.202
Commission findings 188. In Decision 2013-417,203 the Commission set out the test for determining which assets should be in rate base, in paragraph 326 as follows: “In the Commission’s view, assets used in an ‘operational sense’ means assets that are presently used, reasonably used or likely to be used in the future to provide utility services.”
189. The issue raised by the CCA in its argument concerns the full utilization of particular distribution assets. The Commission notes that the issue of asset utilization has also arisen in electric transmission proceedings204 and in each of these proceedings, the Commission has deferred its consideration of this issue within the context of a single proceeding. Rather, the Commission indicated that a generic process would be required to address this issue.
190. In this proceeding, the Commission accepts EPCOR’s evidence that the $1.7 million of capital additions on Circuit 24C related to the six-way ductline, was a prudent decision. At the time EPCOR made its decision, with the information it had at the time and keeping in mind the interests of its customers, the Commission finds that it was reasonable for EPCOR to incur the additional costs to install the six-way ductline. In reaching this determination, the Commission has considered the fact that it is challenging to secure approvals to work within the TUC; that this option would minimize future civil construction costs and leverage existing approvals within the TUC; that there was limited unencumbered land within the TUC for additional feeders; and that securing the alignment and installing additional duct space would allow future projects to proceed in a timely and cost-effective manner. Moreover, given the fact that this project is located close to a developing industrial park along with the preliminary inquiries received by its System Planning group, the Commission considers it to be reasonable for EPCOR to expect that there will be future load growth in this area that will necessitate this additional capacity.
191. With regard to the Aurum aerial circuit, the Commission accepts EPCOR’s statement that the circuit is in use, and also approves these costs as prudent.
192. The Commission has also reviewed the 2017 actual capital additions for all other circuits listed in this program. In light of the evidence supporting these costs, the Commission finds the actual costs in 2017 to be prudent.
7.4 New Underground Cable and Aerial Line Reconfigurations and Extensions to Meet Customer Growth 193. The New Underground Cable and Aerial Line Reconfigurations and Extensions to Meet Customer Growth Project consists of expansions and modifications to EPCOR’s distribution system to meet load growth and maintain reliability in its service area. It consists of specific,
201 Exhibit 23571-X0002.02, application, paragraph 420. 202 Exhibit 23571-X0206, EPCOR reply argument, paragraph 63. 203 Decision 2013-417: Utility Asset Disposition, Proceeding 20, Application 1566373-1, November 26, 2013. 204 See, for example, proceedings 22542, 22393 and 23848.
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defined-scope projects, such as a circuit reconfiguration and an annual recurring set of projects, and identified as-needed projects, such as general aerial line reconfigurations. The need for this project was approved in Decision 2013-435205 for 2013, in Decision 3100-D01-2015206 for 2014 and 2015, and in Decision 20407-D01-2016207 for 2016 and 2017.
194. The 2017 approved forecast capital additions for this project were $6.14 million and the actual 2017 capital additions were $14.05 million, resulting in a $7.91 million positive variance. In the application, EPCOR provided detailed variance explanations. The primary driver for the variance included an increase of $7.57 million related to upgrades to EPCOR’s aerial system required to accommodate installation of telecommunications facilities on EPCOR poles due to the TELUS PureFibre project.208
195. EPCOR explained that in 2017 demand for third party requests to complete aerial construction for the TELUS PureFibre (fibre to the home) project significantly exceeded EPCOR’s original forecast as TELUS increased project requests beyond what it had originally indicated to EPCOR at the time of EPCOR’s 2016-2017 forecast capital tracker application. EPCOR stated that it was not able to defer this work because the terms of the Joint Use Agreement it has with TELUS requires it to accommodate this increase, upgrade its distribution facilities and perform any other work respecting its distribution facilities as may be required in order to accommodate third party communication infrastructure.209
196. EPCOR provided further explanation of its Joint Use Agreement with TELUS in its argument submission. It explained that under the agreement, TELUS pays one-half of the cost of all pole replacements within the geographical boundaries defined by the agreement, including pole-specific construction and associated engineering costs. EPCOR referred to its IR response to the UCA that with respect to TELUS’s attachment requests, in approximately three-quarters of the cases, the poles replaced would have been replaced under EPCOR’s life cycle replacement program anyway due to poor conditions or clearance requirements and that the remaining quarter required replacement because the poles were insufficient to support TELUS’s infrastructure.210 EPCOR further submitted that in 2013, TELUS requested that the parties consider renegotiating the agreement. However, both parties agreed that the agreement was beneficial so no changes were made to the agreement. EPCOR stated that although it has not regularly conducted internal reviews of the agreement, it expected to in the near future as a result of the proposed annexation of Leduc County by the City of Edmonton.211 EPCOR concluded that the agreement benefits customers for a variety of reasons, including the 50-50 cost-sharing arrangement for pole installations/replacement; the avoidance of significant administrative burden by not having to negotiate access rights and costs on a pole-by-pole basis; there is a fixed percentage allocation of costs, as opposed to a dollar amount, allowing EPCOR to recover a fair portion of its costs, regardless of any inflationary effects, technological changes or other cost factors without the need for cyclical renegotiation; the agreement also covers maintenance programs for poles and
205 Decision 2013-435, paragraph 883. 206 Decision 3100-D01-2015, paragraph 269. 207 Decision 20407-D01-2016, paragraph 271. 208 Exhibit 23571-X0002, application, paragraph 620. 209 Exhibit 23571-X0002.01, application, paragraph 616. 210 Exhibit 23571-X0203, EPCOR argument, paragraphs 183-184. 211 Exhibit 23571-X0203, EPCOR argument, paragraph 185.
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power bases/pedestals including tree trimming, inspections and painting; and finally, having to coordinate with one telecommunications company (TELUS) for any issues or requests.212
197. In argument, the CCA raised concerns with the TELUS PureFibre project and the Joint Use Agreement. The CCA argued that TELUS PureFibre is outside of the scope of the original arrangement between EPCOR and TELUS. It claimed that fibre optics is a new technology for home and business use as compared to what was provided for service when the agreement was negotiated in the 1990s. The CCA also submitted that the project required EPCOR to procure new tools and additional vehicles and substantially increased work volumes. As a result, the CCA was of the view that EPCOR’s customers were subsidizing TELUS.213
198. The CCA argued that EPCOR did not take steps to protect customers and that EPCOR should have negotiated a change to the agreement with TELUS to control the significant increase in costs due to the TELUS PureFibre project rather than applying to pass the increased costs on to customers in the current proceeding. The CCA referenced an IR where it asked EPCOR to share its views on whether the agreement, given the technological advances that have transpired over the past 24 years particularly in the telecom industry, was still beneficial.214 In response, EPCOR explained that “… any technological change that gives rise to safety, engineering, or operational concerns that is not adequately addressed in the Joint Use Agreement is addressed as appropriate through separate ‘side’ agreements between EDTI and TELUS referred to as Letters of Intent.”215 EPCOR went on to explain that the nature of the TELUS PureFibre project is similar to a standard TELUS attachment request and therefore included the same safety, engineering and operational concerns as the technology contemplated in the Joint Use Agreement and did not necessitate a separate Letter of Intent.216 The CCA argued that while it “agrees that it is important to have provisions to protect EDTI’s equipment and staff, it is also important to have agreements to protect EDTI’s customers from costs outside of the original agreement.”217
199. The CCA claimed that EPCOR had no incentive to renegotiate the agreement because any costs that are approved increase EPCOR’s return. It also argued that EPCOR management had no incentive to renegotiate due to its mid-term incentive program (MTI), which uses net income and the compounded annual growth rate for property, plant and equipment to determine incentive payments to management. The CCA argued that if EPCOR renegotiated the agreement to reduce its share of the TELUS PureFibre project it would reduce regulated net income (via return on the rate base) and reduce the compound annual growth rate of assets and, therefore, reduce incentive payments to management under the MTI.218
200. The CCA submitted that EPCOR should have re-opened the agreement with TELUS with respect to these costs. Additionally, it was of the view that since this project goes beyond 2017 and EPCOR is covered by K-bar funding during the 2018-2022 PBR term, EPCOR may apply at some future date to have the accumulated costs included in rate base in rebasing. Consequently,
212 Exhibit 23571-X0203, EPCOR argument, paragraph 186. 213 Exhibit 23571-X0200, CCA argument, paragraph 30. 214 Exhibit 23571-X0200, CCA argument, paragraphs 34-37. 215 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-002(b). 216 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-002(b). 217 Exhibit 23571-X0200, CCA argument, paragraph 38. 218 Exhibit 23571-X0200, CCA argument, paragraph 44.
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the CCA recommended the Commission disallow the inclusion of the $35 million total project costs for the TELUS PureFibre project into EPCOR’s rate base.219
201. EPCOR disputed the CCA’s assertions in its reply argument. EPCOR rejected the CCA’s claim that customers are being asked to subsidize TELUS. It stated that the Joint Use Agreement does not address the costs associated with fibre optic and other facilities installed by TELUS to provide services to its customers. Rather, it explained that the agreement addresses the cost of EPCOR poles that must be replaced within the Joint Use Area. EPCOR noted that the agreement makes it clear that irrespective of the reason why a pole is replaced, and regardless of whether TELUS has any infrastructure attached to the pole, TELUS pays half the cost. Consequently, EPCOR argued that its customers gain substantial benefits from the Joint Use Agreement.220
202. EDTI also rejected the CCA’s claim that fibre optics was a new technology for home and business use that was not contemplated or within the scope of the agreement. EPCOR referred to Section 1.1.12 of the Joint Use Agreement, which explicitly contemplates fibre optics through the use of the term “fibre optical cables.” EPCOR stated that the nature of TELUS facilities involved in the project are no different than those involved over the years in a standard TELUS attachment request.221
203. With respect to the CCA’s claim that EPCOR has no incentive to address costs, EPCOR argued that its costs in this category are subject to rigorous review by the Commission and that the CCA failed to address EPCOR’s evidence that it acted prudently in completing this work.222
204. In its reply argument, the CCA reiterated its argument that EPCOR did nothing to protect customers from the increased costs from a new area of service and business that TELUS, not EPCOR, was embarking on. The CCA continued to argue that the Joint Use Agreement from 1994 was signed long before it was economical to use fibre optics for home use and long before TELUS’s business expansion plan. As a result, it continued to submit that EPCOR was subsidizing TELUS’s business venture.223 The CCA also disagreed with EPCOR’s assertion that “in approximately three quarters of the cases, the poles that are replaced as a result of a TELUS attachment request would have been replaced under EDTI’s lifecycle replacement program anyway….” It argued that unless the poles were scheduled for replacement in the current year, the early replacement is simply bringing forward an expenditure from 2018-2022 which would have been capped under the K-bar into the uncapped 2017 program. The CCA also claimed that the 75 per cent figure may not be taking into account the expanded volumes and locations required by TELUS PureFibre.224
205. The CCA continued to assert that the financial effect of TELUS’s new line of business should have necessitated the renegotiation of the agreement and questioned why a review could be triggered by the proposed annexation of Leduc County by the City of Edmonton but not when “… TELUS comes up with a new business plan and business model which changes the qualitative nature of the equipment and lines of business of the new companies.”225
219 Exhibit 23571-X0200, CCA argument, paragraph 43. 220 Exhibit 23571-X0206, EPCOR reply argument, paragraphs 42-44. 221 Exhibit 23571-X0206, EPCOR reply argument, paragraph 45. 222 Exhibit 23571-X0206, EPCOR reply argument, paragraph 46. 223 Exhibit 23571-X0207, CCA reply argument, paragraphs 46-50. 224 Exhibit 23571-X0207, CCA reply argument, paragraphs 67-76. 225 Exhibit 23571-X0207, CCA reply argument, paragraphs 58-59.
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Commission findings 206. The upgrades to EPCOR’s aerial system required to accommodate installation of telecommunications facilities on EPCOR’s poles due to the TELUS PureFibre project and as required to comply with the terms of EPCOR’s and TELUS’s Joint Use Agreement is the main driver of the positive variance in this project. The Commission accepts EPCOR’s explanation that the project significantly exceeded the forecast in 2017 as TELUS had originally indicated to EPCOR at the time the 2017 forecast was created for the 2016-2017 forecast capital tracker application.
207. In assessing the prudence of this program’s expenditures, which, as noted above, are primarily driven by the terms of the Joint Use Agreement with TELUS, the Commission has assessed whether it was reasonable for EPCOR to continue with the Joint Use Agreement at the time the expenditures were required, knowing what it did at that time, or whether it would have been reasonable to try to renegotiate a new agreement.
208. In accordance with the provisions of the Joint Use Agreement, the agreement has no set end date, but a continuing term subject to the termination provisions set out in Part XIX.226 At a general level, and assuming that TELUS does not intend to abandon its facilities, cease to be licensed by the CRTC, wind up its operations, enter into bankruptcy or otherwise be unable to carry on business, the termination provisions provide, in part, that the agreement can terminate (i) on mutual agreement; or (ii) upon 12 months’ notice. Further, even in that event, TELUS has continuing rights to use the poles so long as it pays for all costs of ongoing maintenance.227
209. It was EPCOR’s evidence that it and TELUS looked at renegotiating this agreement but both determined that it was not beneficial to do so. Consequently, absent mutual agreement, if EPCOR had determined that it did not want to continue with the agreement, it would have had to provide TELUS with 12 months’ notice. Once the agreement terminated, TELUS would continue to have rights to use the poles and no obligation to renegotiate a new agreement with EPCOR. The CCA did not address these provisions in its argument submission nor did the CCA present any evidence to suggest that terminating this agreement under the terms of these provisions would benefit customers. Consequently, the Commission finds the CCA’s argument that EPCOR did not take steps to protect customers by renegotiating the agreement to control the significant increase in costs due to the TELUS PureFibre project to be without merit.
210. The Commission finds that it was prudent for EPCOR to continue to operate under the terms of the Joint Use Agreement notwithstanding that the TELUS PureFibre project resulted in increased costs beyond those contemplated in its forecast. The Commission finds that the continuation of EPCOR’s 50-50 cost-sharing agreement for pole installations/replacement provides numerous benefits to its customers as it reduces administrative burden and also addresses the maintenance of poles. In addition, as stated by EPCOR, the agreement makes it clear that irrespective of the reason why a pole is replaced, and regardless of whether TELUS has any infrastructure attached to the pole, TELUS pays half the cost.
211. The Commission also rejects the CCA’s argument that fibre optics use in homes and businesses was not contemplated in the original agreement. The Commission agrees with
226 Exhibit 23571-X0107.01, Section 2.1, PDF page 117. 227 Exhibit 23571-X0107.01, Part XIX, PDF page 151.
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EPCOR’s assertion that fibre optics were contemplated in the original agreement as it was defined in Section 1.1.12 of the Joint Use Agreement.
212. For all the above reasons, the Commission rejects the CCA’s proposal to remove the costs related to upgrades to EPCOR’s aerial system required to accommodate installation of telecommunications facilities on EPCOR’s poles due to the TELUS PureFibre project.
213. With respect to capital tracker treatment of the New Underground Cable and Aerial Line Reconfigurations and Extensions to Meet Customer Growth Project for 2017, the Commission approves the requested capital addition of $14.05 million and the resulting K factor true-up adjustment of $0.50 million. The Criterion 1 need for this project in 2017 was approved in Decision 20407-D01-2016. With respect to the scope, level and timing of this project carried out in 2017, the Commission reviewed EPCOR’s 2017 associated actual capital additions and finds that the capital additions are generally consistent with the scope, level and timing of the work outlined in the business case for this capital tracker and approved in Decision 20407-D01-2016. EPCOR provided evidence explaining the differences between approved forecast and actual costs, and the Commission finds the actual costs to be prudent.
7.5 Capital Tools and Instrument Purchases 214. The Capital Tools and Instrument Purchases Project consists of refurbishing, replacing and upgrading EPCOR’s distribution function tools and instruments that are required by EPCOR personnel for the safe construction, operation, inspection, maintenance and repair of EPCOR’s distribution aerial and underground facilities. The need for this project was approved in Decision 2013-435228 for 2013, Decision 3100-D01-2015229 for 2014 and 2015 and Decision 20407-D01- 2016230 for 2016 and 2017.
215. The 2017 approved forecast capital additions for this project were $0.58 million and the actual 2017 capital additions were $1.43 million, resulting in a $0.85 million positive variance. EPCOR explained that the primary reasons for this variance were the $0.36 million cost for the purchase of equipment for EPCOR’s Cable Test Lab project, and the $0.20 million cost for tools purchased to equip five growth vehicles. Included in this latter cost was a $0.09 million cost to equip an additional aerial bucket truck to enable it to complete the TELUS Falcon project. There was also a $0.33 million increase in distribution tools and equipment costs. This increase was driven by a $0.15 million increase related to an accounting error in the calculation of the three- year average and in a $0.11 million increase for an Omnicron relay test set and a sulphur hexafluoride (SF6) meter due to a 50 per cent increase in the installation of distribution automation devices, $0.04 million to replace a Trimble S5 Robotic Total station, and $0.03 million for the replacement of a cable spooler. There was a $0.01 million increase due to slightly higher than forecast health and safety tool costs. These increases were partially offset by a $0.03 million decrease reflecting lower than forecast metering tool and instrument costs and a $0.02 million decrease due to lower rubber costs.
216. In its argument, EPCOR referred to its response to a Commission IR231 in which it explained that the Omnicron relay test set was purchased because it expected to install an
228 Decision 2013-435, paragraph 927. 229 Decision 3100-D01-2015, paragraph 398. 230 Decision 20407-D01-2016, paragraph 273. 231 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-009.
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increased number of data acquisition devices between 2016 and 2017. The data acquisition devices, consisting of supervisory control and data acquisition (SCADA) communication systems, were required to remotely operate the new vista switches and monitor the conditions of the new network transformers and vista switches. However, between 2014 and 2016, EPCOR was not able to install the number of SCADA communications devices anticipated due to the reprioritization of construction resources to more time sensitive projects.232 EPCOR also referred to the CCA’s IR with respect to capital additions associated with the TELUS PureFibre project explaining that because the tools purchased to complete the TELUS PureFibre project will be required by EPCOR and utilized on a continual basis, it decided to purchase rather than lease the tools.233
217. In its reply argument, the CCA noted that there was an addition of tools for the TELUS PureFibre project and for the reasons argued in its submissions regarding the provision of services to TELUS, it submitted that these additional tool costs should be recovered from TELUS’s and not EPCOR’s ratepayers.234
Commission findings 218. The need for this project in 2017 was approved in Decision 20407-D01-2016. With respect to the scope, level and timing of this project carried out in 2017, the Commission reviewed EPCOR’s 2017 actual capital additions and finds that the capital additions are generally consistent with the scope, level and timing of the work outlined in the business case for this capital tracker and approved in Decision 20407-D01-2016. EPCOR provided evidence explaining the differences between approved forecast and actual costs, and the Commission accepts EPCOR’s explanations that tools and instruments were required for the new Cable Test Lab, tools were purchased to equip growth vehicles and the aerial bucket truck for the TELUS Falcon project and finally an increase in the purchase of relay test sets and SF6 meter was required due to the timing of the installation of data acquisition devices. Therefore, the Commission finds the actual costs for this project to be prudent.
219. With respect to the capital additions of $0.09 million related to the purchase of tools to equip an aerial bucket truck for the TELUS PureFibre project, the Commission accepts EPCOR’s evidence that it will continue to use the tools on a continuous basis and finds EPCOR’s decision to purchase rather than lease these tools to be reasonable.
7.6 Capitalized Aerial System Damage 220. The Capitalized Aerial System Damage Project consists of the replacement of EPCOR’s aerial distribution facilities that have been damaged, have failed, or are about to fail. In its application, EPCOR explained that the project consists of repairs to its aerial distribution facilities following damage by third parties, weather-related forces, as well as deterioration caused by aging. The project restores damaged facilities to a safe and functional state, and is necessary for system reliability.235
232 Exhibit 23571-X0203, EPCOR argument, paragraphs 197-198. 233 Exhibit 23571-X0203, EPCOR argument, paragraph 200. 234 Exhibit 23571-X0203, CCA reply argument, paragraph 79. 235 Exhibit 23571-X0002.01, application, paragraph 678.
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221. The need for this project as part of the project assessment under capital tracker Criterion 1, was approved in Decision 3100-D01-2015236 for 2014 and 2015 and Decision 20407- D01-2016237 for 2016 and 2017.
222. The 2017 approved forecast capital additions for this project were $1.53 million,238 and the actual 2017 capital additions were $1.94 million, resulting in a $0.41 million positive variance. EPCOR explained that the primary causes attributable to this variance were a higher than forecast cost of capital to address damage repair in 2017 in the amount of $0.56 million and $0.04 million in higher engineering costs. These costs were partially offset by a $0.15 million decrease due to higher external recoveries than the three-year historical average, and a $0.04 million error in applying the forecast to allocated overhead.239 EPCOR also outlined that the higher 2017 aerial damages were a result of higher weather-related and deteriorated-to-failure damages.
223. In IRs, the UCA asked EPCOR to provide a more detailed breakdown by capital tracker project of costs incurred due to third parties and the amounts recovered. The UCA asked for circumstances in which costs could not be recovered, the reasons for delay or lack of collection, as well as a three-year historical average of costs incurred due to third-party damage.240
224. EPCOR explained that costs both incurred and recovered from third party damage are reflected in two capital tracker projects: Capitalized Underground System Damage, treated in Section 7.2.2 above, and the current project, Capitalized Aerial System Damage.
225. EPCOR noted that the UCA had referenced paragraph 701 of its application in which EPCOR stated that it had recovered $0.38 million after pursuing third parties for compensation. It explained that this amount only pertained to cost recovery under the Capitalized Aerial System Damage capital tracker project and that the amount included both recovery from third parties responsible for the damage and TELUS contributions to joint pole structures. The split of those funds was $0.07 million from TELUS and $0.31 million from third parties responsible for damage to EPCOR’s facilities.241
226. EPCOR submitted that when parties cause damage, it worked with the City of Edmonton Police Department to identify them. If a third party can be identified, EPCOR pursues and invoices it for payment. If parties are unable to be identified, EPCOR cannot recover any of its costs.242 EPCOR added that recovery amounts are recorded against a project when an invoice is issued. However, depending on the time it takes to conclude the police investigation, contact the third party and the third-party’s insurer where possible, and complete asset replacement work, actual recovery may not occur in the year in which the damage occurred. As an example, EPCOR noted that the recovery in 2017 for Capitalized Aerial System Damages included invoiced amounts for damages that occurred in 2016 and 2017.243 EPCOR provided the following table showing a breakdown of the $0.31 million recovered from third parties in 2017:
236 Decision 3100-D01-2015, paragraph 454. 237 Decision 20407-D01-2016, paragraph 273. 238 Decision 21430-D01-2016, paragraph 16. 239 Exhibit 22672-X0079, paragraph 667. 240 Exhibit 23571-X0098, EDTI-UCA-2018JUN22-016. 241 Exhibit 23571-X0112.01, EDTI-UCA-2018JUN22-016(a). 242 Exhibit 23571-X0112.01, EDTI-UCA-2018JUN22-016(a). 243 Exhibit 23571-X0112.01, EDTI-UCA-2018JUN22-016(a).
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Table 9. 2017 third-party damages recovered under capitalized aerial system damage 2017 A ($ million) 1 Total Recovery for third-party damages (R2+R3) 0.31 2 Recovery for third-party damage incurred in 2016 0.08 3 Recovery for third-party damage incurred in 2017 0.23 4 Third-party damages incurred in 2017 0.45 Third-party damages not recovered for repair/replacement expenditures 5 0.22 incurred in 2017 (R4-R3) Source: Exhibit 23571-X0112.01, Table EDTI-UCA-2018JUN22-016-1.
227. EPCOR also responded to the UCA’s IR by providing the costs incurred over the three- year period from 2015 to 2017.244 These are shown in Table 10.
Table 10. 2015-2017 costs incurred due to third-party system damages
2015 2016 2017 2015-2017 Average ($ million) 1 Capitalized Aerial System Damage 0.64 0.34 0.45 0.49 2 Capitalized Underground System Damage 0.39 1.02 0.73 0.71 3 Total 1.03 1.36 1.18 1.19 Source: Exhibit 23571-X0112.01, Table EDTI-UCA-2018JUN22-016-3.
228. The CCA asked EPCOR to provide actual capital additions in the program for 2015 and 2016. EPCOR responded that these were $1.30 million and $1.40 million, respectively.245
229. As well, the CCA asked which weather concerns in 2017 caused “higher weather related and deteriorated to failure damages”. EPCOR explained that relative to the 2012-2014 three-year average used as the basis for the forecast, the weather in 2017 was particularly severe. On May 24, 2017, EPCOR experienced a Major Event Day, which EPCOR calculated in accordance with the methodology prescribed in Rule 002: Service Quality and Reliability Performance Monitoring for Owners of Electric Distribution Systems and for Gas Distributors, related to a severe wind and rain storm resulting in customer outages on 17 different distribution feeders. As well, EPCOR noted that the winter of 2017/2018 was one of the longest and coldest on record, with Edmonton experiencing 177 consecutive days where the daily low temperature did not exceed zero degrees Celsius.246
230. Neither the UCA nor the CCA filed argument with respect to this project.
Commission findings 231. With respect to the scope, level and timing of the actual capital additions associated with the Capitalized Aerial System Damage Project in 2017, the Commission has reviewed EPCOR’s 2017 actual capital additions associated with this project, and finds that the capital additions are consistent with the scope, level and timing of the work outlined in the project completion summary for this capital tracker. The Commission has also reviewed the 2017 actual capital
244 Exhibit 23571-X0112.01, EDTI-UCA-2018JUN22-016(b). 245 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-022. 246 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-022.
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additions for this project in light of the evidence supporting these costs, the associated procurement and construction practices and the evidence explaining the differences between approved forecast and actual costs, and finds the actual costs to be prudent.
7.7 Service Centre Redevelopment and Life Cycle Replacements 232. The Service Centre Redevelopment and Life Cycle Replacements Program consists of four projects: Work Centre Redevelopment, Furniture Life Cycle Replacement, North and South Service Centre Building Life Cycle, and Service Centre Consolidation. The need for these projects as part of the project assessment under capital tracker Criterion 1 was approved for 2017 in Decision 20407-D01-2016.247 Decision 20407-D01-2016 also directed EPCOR to group the four projects under one program.248
233. The Work Centre Redevelopment Project involves the expansion and redevelopment of EPCOR’s North Service Centre (NSC). This project also includes the planned consolidation of EPCOR departments currently located in EPCOR Tower, St. Albert Trail Service Centre and South Training Centre (STC) to a combination of the redeveloped NSC and EPCOR’s South Service Centre (SSC). Also included is moving classroom-based training to the redeveloped NSC, field-based training from the STC to a new site, and the relocation of some employees between the SSC and the redeveloped NSC.249
234. In EPCOR’s 2016-2017 capital tracker application, the total cost for this project was forecast to be $85.09 million. These costs were composed of 2015 approved forecast capital additions of $26.38 million, 2016 approved forecast capital additions of $38.45 million, and 2017 approved forecast capital additions of $20.27 million.250
235. Total project capital additions at the end of 2017 were $99.21 million, resulting in an overall positive project variance of $14.19 million. Total program capital additions are composed of 2016 actual capital additions of $38.58 million and 2017 actual capital additions of $60.63 million.251 EPCOR explained that while the overall program variance was $14.19 million, the 2017 variance from the approved forecast was $40.40 million, the majority of this amount was a result of deferred expenditures from the 2016 approved forecast. EPCOR also forecast $1.26 million in capital expenditures for 2018 related to carry-over work from 2017 to 2018.
236. In EPCOR’s original business case for this project, the company stated that the “forecast total project cost is accurate to +/- 20% and will likely be refined as detailed design is completed and the project progresses.”252 EPCOR noted that there were several items that were not included in the original business case that were required to ensure the project would meet existing building codes. EPCOR explained that it had to add a person-lift for handicap access to the mezzanine level of the multi-purpose area, an elevator had to be added to the multi-purpose area
247 Decision 20407-D01-2016, paragraph 91. 248 Decision 20407-D01-2016, paragraph 90. 249 Exhibit 23571-X0002.01, application, paragraph 866. 250 Decision 20407-D01-2016, paragraph 404. 251 Exhibit 23571-X0002.01, application, paragraph 971. 252 Exhibit 20407-X0075, 2014 True-Up and 2016-2017 Forecast Capital Tracker Application, Appendix A-22, PDF page 11.
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to accommodate staff movement in Building 2, and a larger fire separator between the new garage and the existing building was required.253
237. EPCOR noted that the construction of the project was affected by unforeseen renovation issues. The costliest of these unforeseen issues arose from the uncovering of contaminated and unusable soil along the foundations of the new garage and the multi-purpose area. After testing, it was discovered that the contaminated soil had to be removed from the site and replaced. The work related to the contaminated soil delayed the completion of the garage to 2017 and delayed the construction and final installation of the multi-propose area.254 The contaminated soil contributed to approximately $1.88 million of the overall variance of this program, $1.33 million related to the NSC vehicle garage, $0.28 million to the parking facility/yard optimization and $0.22 million related to the multi-purpose area.255
238. EPCOR explained that approximately $27.53 million of the 2017 variance associated with the program is associated with differences in the timing of when work was completed.256 The remaining variance amount, approximately $12.87 million, was due to higher than forecast costs associated with completing the projects within the program.257
239. The variance associated with the difference in timing was broken down among the following program components: the multi-purpose area ($1.46 million), the NSC vehicle garage ($8.42 million), meter operations ($0.16 million), Building 1 office and shops ($15.73 million) and the SSC ($1.76 million).258
240. An additional $4.17 million cost variance related to the multi-purpose area phase of the project was primarily due to final design changes between the initial forecast and what was finally completed in the amount of $2.71 million. The original design and forecast was based on a design of a single-storey open-office addition. The final design of the multi-purpose area provided a mezzanine space for additional meeting space, additional storage space and EPCOR’s relocated food service area. The space also includes additional washrooms and relocates EPCOR’s security desk. The remaining $1.46 million variance was a result of unforeseen structural issues and expenditures related to additional design considerations.259
241. The NSC vehicle garage program had an additional positive variance of $3.76 million. EPCOR explained that $1.61 million of this variance was associated with mechanical and electrical changes in the new and existing garage, the remainder of the variance was attributed to EPCOR having to expand its scope of work to ensure compliance with building codes and having to remediate contaminated soil, as mentioned above in paragraph 237.
242. The total variance of each program component between 2015 and 2017 is detailed in Table 11 below:260
253 Exhibit 23571-X0002.01, application, paragraph 914. 254 Exhibit 23571-X0002.01, application, paragraph 912. 255 Exhibit 23571-X0002.01, application, paragraphs 921, 924 and 926. 256 Exhibit 23571-X0002.01, application, paragraphs 973-983. 257 Exhibit 23571-X0002.01, application, paragraphs 973-983. 258 Exhibit 23571-X0002.01, application, paragraphs 973-983. 259 Exhibit 23571-X0002.01, application, paragraph 921. 260 Exhibit 23571-X0002.01, application, paragraph 971.
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Table 11. Service Centre Redevelopment Project 2015-2017 capital additions Total 2017 A minus Descriptions 2015 F 2015 A 2016 D 2016 A 2017 D 2017 A Project 2017 D Variance ($ million) Building 3 Pre-2014 Project 0.33 - - 0.33 - - - - Consulting Costs Building Purchase 8.40 - - 8.40 - - - - Warehouse 2.21 - - 2.16 - - - (0.05) Office & Shops (excluding Multi- 9.81 - 3.32 2.16 - - - (0.43) purpose area) Multi-purpose Area - - 1.46 - - 5.63 5.63 4.17 Building 3 Total 20.74 - 4.78 23.59 - 5.63 5.63 3.70 Meter Operations - - 0.16 - - 0.16 0.16 - NSC Vehicles Garage - - 8.42 - - 12.19 12.19 3.76 Parking Facility / Yard - - - - 6.11 6.86 0.74 0.74 Optimization Building 2 - - - - 6.97 7.89 0.92 0.92 Building 1 - Control Room 1.80 - - 1.68 - - - (0.12) Building 1 Office & - - 18.48 2.75 - 14.63 14.63 (1.10) Shops Building 1 Total 1.80 - 18.48 4.43 - 14.63 14.63 (1.21) Exterior - - - - 1.92 3.43 1.51 1.51 South Service Centre - - 1.76 - 2.53 5.38 2.85 1.10 STC/New Outdoor 1.82 - - 2.89 - 0.13 0.13 1.20 Training Architecture & Design, Engineering & 1.33 - 4.57 5.82 2.23 2.81 0.59 0.52 Project Management NSC Solar - - - - - 0.40 0.40 0.40 AFUDC Cost 0.70 - 0.28 1.84 0.52 1.14 0.62 1.47 Subtotal 26.38 - 38.44 38.58 20.27 60.63 40.36 14.14 Direction 7 Adjustment - - (0.40) - (0.40) - 0.04 0.07 Total 26.38 - 38.41 38.58 20.23 60.63 40.40 14.19 Source: Exhibit 23571-X0002.01, application, Table 3.2.1.1-6.
243. Through IRs, the Commission asked EPCOR to provide additional information to support the business need for the multi-purpose area that expanded the scope of the designs beyond the initial forecast. EPCOR explained that the change in design provided greater functionality and usability of the space, and provided additional meeting space that had not been accounted for in the initial forecast. EPCOR also stated that the original forecast for the multi-purpose area did not account for the design challenges of tying the original NSC building into the newly purchased Building 3 and newly constructed parking garage using the multi-purpose area.
244. Table 12 provides a breakdown of the variance that was incurred due to the changes in scope and additions that were previously not forecast.
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Table 12. Cost breakdown of multi-purpose area A B C Breakdown of total cost (column A) into original scope and expanded scope
Description Cost related to Cost related to expanded Total cost to construction of original scope (mezzanine level construct multi- scope and expanded washrooms) purpose area ($ million) 1. Constructed Price (multi-purpose area components) following 4.17 3.19 0.98 detailed engineering and design 2. Unforeseen structural issues 0.55 0.55 - 3. Plaza footprint increase 0.18 0.18 - 4. Architectural and design changes 0.08 - 0.08 related to mezzanine 5. Expansion of washrooms 0.08 - 0.08 6. Mechanical and electrical changes 0.27 0.16 0.11 7. Additional building code 0.26 0.19 0.07 requirements 8. Other changes 0.04 0.04 - Total 5.63 4.31 1.32 Source: Exhibit 23571-X0107.01, Table EDTI-AUC-2018JUN22-007-1.
245. The UCA asked EPCOR, in an IR, why an updated business case was not submitted regarding the increase in scope of the project and if one had been written during the filing process. In response, EPCOR stated that an updated business case was not submitted because information was displayed in the application and EPCOR stated that the additional information provided in response to Commission IRs was equivalent to information often provided in capital tracker business cases.261
246. The Furniture Life Cycle Replacement Project consists of the purchase and replacement of office furniture such as chairs, tables, workstations and filing cabinets.262 The 2017 approved forecast capital additions for this project were $0.19 million, and the actual 2017 capital additions were $0.05 million, resulting in a $0.14 million negative variance. EPCOR explained that the variance is mainly due to a lower need to replace furniture than forecast because furniture is already being replaced under the Work Centre Redevelopment Project.263
247. The North and South Service Centre Building Life Cycle Replacement Project consists of the replacement of architectural, structural, electrical and mechanical components of EPCOR’s service centre buildings, as well as capital improvements that address the changing operational demands of EPCOR’s service centres.264 The 2017 approved forecast capital additions for this project were $0.18 million, and the actual 2017 capital additions were $0.37 million, resulting in a $0.19 million positive variance.
248. EPCOR explained that the overall variance for the North and South Service Centre Building Life Cycle Replacement Project was a result of higher than forecast expenditures
261 Exhibit 23571-X0148, EDTI-UCA-2018AUG24-003. 262 Exhibit 23571-X0002.01, application, paragraph 995. 263 Exhibit 23571-X0002.01, application, paragraph 1006. 264 Exhibit 23571-X0002.01, application, paragraph 1008.
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related to EPCOR’s cable test lab ($0.14 million) and EPCOR’s control centre universal power supply room ($0.09 million).265 The cable test lab is related to EPCOR’s contract with METSCO and will be further examined in Module Two of this proceeding. EPCOR explained that the variance increases were partially offset by a $0.04 million decrease due to the reduced scope of critical paving repairs at the South Service Centre compared to what was initially forecast.266
249. The Service Centre Consolidation Project is a completed project from 2006 that consisted of the purchase of Building 2 and a portion of the current NSC garage space from TELUS, as well as renovations to the garage space, to accommodate EPCOR vehicles and staff. EPCOR noted that there were no capital additions forecast in 2017 associated with this project and none were incurred.267
Commission findings 250. In Decision 20407-D01-2016, the Commission approved EPCOR’s forecast cost for the Service Centre Redevelopment and Life Cycle Replacements Program for capital tracker treatment for 2017. The Commission finds no evidence on the record of this proceeding to indicate that the Service Centre Redevelopment and Life Cycle Replacements Program was not required in 2017.
251. With respect to the scope, level and timing of the program carried out in 2017, the Commission reviewed the net capital additions of $60.63 million and finds that they are generally consistent with the scope, level and timing of the work outlined in the business case for this capital tracker and approved in Decision 20407-D01-2016. The Commission accepts EPCOR’s explanations for the variance of $40.40 million in actual capital additions above the approved forecast noting that the variance was mostly due to carry-over amounts from 2016, with some additional expenditures incurred due to unforeseen structural issues.
252. Regarding EPCOR’s decision to adjust the design of the multi-purpose area phase of this program to include, among other things, a mezzanine space for additional meeting space, additional storage space, a relocated food service area (to the mezzanine) as well as additional design to tie the original NSC building into the newly purchased Building 3 and a newly constructed parking garage using the multi-purpose area, the Commission accepts EPCOR’s evidence that this expansion of scope was necessary and would enhance the efficient use of the facilities beyond that initially contemplated in the initial design. On this basis, the Commission finds that these costs were prudently incurred by EPCOR.
253. Given the above considerations, the Commission finds that the Service Centre Redevelopment and Life Cycle Replacements Program satisfied the project assessment requirement of Criterion 1 in 2017.
7.8 Vehicles – Growth and Life Cycle Replacement Project 254. This project consists of the purchase of new distribution vehicles and fleet equipment required for growth, the replacement of existing distribution vehicles and fleet equipment that have reached the end of their service lives, and the purchase of distribution function vehicles and fleet equipment to replace previously rented vehicles. EPCOR explained that it relies on its
265 Exhibit 23571-X0002.01, application, paragraph 1021. 266 Exhibit 23571-X0002.01, application, paragraph 1022. 267 Exhibit 23571-X0002.01, application, paragraph 1023.
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distribution fleet of vehicles and related equipment to build, operate, maintain and repair its distribution system. As a result, the availability and dependability of its vehicles are necessary to ensure its distribution system is operated and maintained in a safe and reliable manner. EPCOR provided a business case and an engineering study for the Vehicles – Growth and Life Cycle Replacements Project in Appendix B-8 to its application.268
255. The need for this project as part of the project assessment under capital tracker Criterion 1 was approved in Decision 2013-435269 for 2013 and in Decision 3100-D01-2015270 for 2014 and 2015. The Vehicles – Growth and Life Cycle Replacements Project did not qualify for capital tracker treatment on a forecast basis for 2016 and 2017.271 In its 2016 capital tracker true- up application, EPCOR requested capital tracker treatment of this project for 2016 on an actual basis, which was approved by the Commission in Decision 22672-D01-2018.272
7.8.1 Compliance with Direction 8 of Decision 22672-D01-2018 256. In 2016, EPCOR sold three diggers that it had purchased from ALTEC (the Altec diggers). It sold these diggers because they presented safety hazards to operators, as they were configured differently than its existing fleet of diggers.273 The diggers were sold at a loss, and the Commission gave EPCOR the following direction in Decision 22672-D01-2018:274
With respect to the capital additions related to the Altec diggers, as was proposed in the application, the Commission directs EPCOR to remove the remaining net book value (representing the net loss on the sale of the diggers in the amount of $0.28 million) from its 2017 opening rate base in its 2017 capital tracker true-up application, as well as reflect this change in any compliance or updated filing to the PBR rebasing Proceeding 22394. [footnotes removed]
257. In its application in this proceeding, EPCOR stated it had complied with this direction; however, it noted a difference in the adjustment. Due to the lapse of time between the issuance of Decision 22672-D01-2018 and its filing for Proceeding 22394, EPCOR was unable to remove the remaining net book value (NBV) from the 2017 opening rate base and could only remove it from the 2017 closing rate base. EPCOR stated that the impact of this change would amount to a decrease of $0.22 million rather than the directed $0.28 million. EPCOR proposed making a negative K factor adjustment of $0.06 million to the Vehicles – Growth and Life Cycle Replacements Project capital tracker in the K-bar model to account for the difference.275
258. In the first round of IRs, the Commission asked EPCOR to provide supporting schedules to demonstrate how EPCOR arrived at its split of $0.28 million into the $0.22 million and $0.06 million above. EPCOR provided an Excel spreadsheet, showing its proposed calculation, and revised its split to a $0.24 million removal from its 2017 closing rate base and a $0.04 million negative K factor adjustment.276
268 Exhibit 23571-X0009, Appendix B-8. 269 Decision 2013-435, paragraph 915. 270 Decision 3100-D01-2015, paragraph 338. 271 Decision 20407-D01-2016, paragraph 48, Table 2, row 8. 272 Decision 22672-D01-2018, paragraphs 149 and 154. 273 Decision 22672-D01-2018, paragraph 147. 274 Decision 22672-D01-2018, paragraph 153. 275 Exhibit 23571-X0002.01, application, paragraph 84. 276 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-010(a).
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259. In the second round of IRs, the Commission asked EPCOR if it had considered the ramifications to the 2017 mid-year rate base in its proposal for compliance with the Commission’s direction. EPCOR responded by updating its Excel spreadsheet, outlining that its new proposed split took into account impacts to the 2017 mid-year rate base. EPCOR updated its proposal to include a one-off negative K factor adjustment of $0.03 million to account for one year of depreciation, and return and removal of the remaining NBV in 2017.277
Commission findings 260. The Commission finds that based on the update received after the second round of IRs, EPCOR’s proposal for the removal of the remaining assets from the 2017 closing rate base as well as its one-off negative K factor adjustment of $0.03 million is compliant with respect to Direction 8 of Decision 22672-D01-2018.
7.8.2 Vehicles – Growth and Life Cycle Replacement Project for 2017 261. In its application in this proceeding, EPCOR explained that the reason the Vehicles – Growth and Life Cycle Replacements Project did not meet capital tracker status for 2016 and 2017 on a forecast basis was because of double-counting of vehicle depreciation.278 For 2017 actual capital additions, EPCOR stated that it ensured that the associated depreciation expense had been removed from the 2017 K factor, and that the 2017 actual capital additions for this project now qualify for capital tracker treatment in 2017.279
262. In EPCOR’s 2016 capital tracker true-up application, the Vehicles – Growth and Life Cycle Replacements Project consisted of two project categories: (i) fleet additions to account for growth; and (ii) life cycle replacement of vehicles.280 In this application for its 2017 capital tracker true-up, the Vehicles – Growth and Life Cycle Replacements Project includes an additional (i.e., third) category: (iii) the purchase of previously rented vehicles.281 282
263. EPCOR provided the forecast and actual capital additions across each of the three project categories within the vehicles program, which are reproduced as Table 13. The three sections that follow examine each of these three project categories individually.
Table 13. Distribution fleet (vehicles and related equipment) 2017 forecast and actual capital additions Project category 2017 F 2017 A ($ million) 1 Additions to EDTI’s Fleet 0.00 0.79 2 Life Cycle Replacement Vehicles 3.99 5.76 3 Purchase of Hired Fleet Vehicles 0.00 1.93 4 Total 3.99 8.48 Source: Exhibit 23571-X0009, Appendix B-5, Table 2.1-1.
277 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-003(b). 278 Exhibit 23571-X0002.01, application, paragraph 1089. 279 Exhibit 23571-X0002.01, application, paragraph 1091. 280 Decision 22672-D01-2018, paragraph 144. 281 Exhibit 23571-X0002.01, application, paragraph 1088. 282 For the purposes of the vehicles program within this decision, the terms hired and rented will be treated as synonyms.
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7.8.2.1 Fleet additions to account for growth 264. In its application, EPCOR explained that this project category consists of the addition of new vehicles and related equipment to its distribution function fleet required to support its operations and capital projects. EPCOR purchased two vehicles totalling $0.79 million in this project category: one underground cable puller, and one underground cable splice van.283 These amounts are shown in Table 14.
Table 14. 2017 capital additions new distribution fleet vehicles and related fleet equipment A B C D E Forecast cost Actual cost (includes Life cycle Description Quantity (includes base cost base cost & capital Unit number (years) & capital overhead) overhead)
($ million) 2017 Growth Vehicles 1 Y3444 Cable Puller 1 10 0.00 0.63 2 X3302 14’ UG Cable Splice Van 1 12 0.00 0.16 3 Total Growth Vehicles 0.00 0.79
Source: Exhibit 23571-X0009, Appendix B-5, Table 2.1-2.
265. EPCOR explained that it added the underground cable puller to support its cable and excavation operations and capital projects. In 2015, EPCOR added a temporary cable crew to handle its forecast capital cable projects. As work continued, the temporary crew was converted into a permanent crew in 2016; however, EPCOR continued to operate a day crew and a night crew with one underground cable puller. Both crews shared the use of a single underground cable puller, behaviour that EPCOR indicated would not be sustainable over the long term due to the vehicle not being designed to operate for 24-hour periods, safety risks for the night crew and delays in work if the cable puller was down for maintenance.284
266. In response to an IR from the CCA, EPCOR explained that each cable-pulling crew consists of five staff: three utility workers, and two equipment operators. The CCA also asked whether cable pullers were available for short term lease or rent, as well as how often cable pullers are down for maintenance. EPCOR responded that the daytime crew typically runs between 7:30 a.m. and 4 p.m., and that it also operates a cable crew during a night shift to accommodate customer requests. EPCOR further noted that the vehicle it purchased is of a heavy duty and very specialized nature, and that it was unaware of the availability of cable pullers for short-term lease or rent. EPCOR stated that in 2016, the cable puller was down for maintenance and repairs for approximately 11.4 per cent of the time.285
267. EPCOR purchased the underground cable splice van to support EDTI’s underground distribution system operations and capital projects. EPCOR relies on one underground cable splice van that is equipped to handle system repair services (SRS). Since 2015, EPCOR submitted that its manhole work has increased and that it has been supplementing the work requirements in SRS with crews from capital construction, leading to problems with scheduling and completion of its work. The addition of one underground cable splice van would alleviate the
283 Exhibit 23571-X0009, Appendix B, paragraphs 7-8. 284 Exhibit 23571-X0009, Appendix B, paragraph 9. 285 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-023(a)-(c).
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SRS crew’s dependency on capital construction crews to complete manhole work in 2017 as well as over the long term. EPCOR also noted that the timing of adding one underground cable splice van in 2017 coincided with a trades-person-in-training who was capable of handling SRS work independently.286
268. In response to an IR from the CCA, EPCOR clarified that it would not be hiring additional SRS staff to support work activities, but rather that workers were trained and certified in advance of purchasing the vehicles and are currently operating the vehicles.287
7.8.2.2 Life cycle replacements of vehicles 269. EPCOR explained that its life cycle replacements of vehicles project includes capital additions related to the replacement of vehicles in its distribution function fleet that were at or beyond the end of their service lives in 2017, as well as vehicles in its distribution function fleet that were being replaced prior to the end of their service lives for other reasons, such as safety concerns or insurance write offs from accidents.288
270. EPCOR provided a list of all of the vehicles purchased under this program, and the list is reproduced as Table 15.
286 Exhibit 23571-X0009, Appendix B-5, paragraph 11. 287 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-023(e). 288 Exhibit 23571-X0002.01, application, paragraph 1100.
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Table 15. 2017 forecast and actual capital additions distribution fleet vehicles and related equipment life cycle replacements A B C D E F G Forecast cost Actual cost Service Age of unit (includes base (includes base Unit Unit number Reason for life of Description being cost & salvage cost & salvage number being replaced replacement unit replaced & capital & capital (years) overhead) overhead) ($ million) Z3323 55′ Double Bucket Replaces F3820 12 Service Life 12 0.38 0.40 Z3324 55′ Double Bucket Replaces F3821 12 Service Life 12 0.38 0.40 Z3325 55′ Double Bucket Replaces G3875 12 Service Life 12 0.38 0.40 Z3326 55′ Double Bucket Replaces G3876 12 Service Life 12 0.38 0.37 Z3322 50′ Single Bucket Replaces R3009 5 Service Life 5 0.31 0.35 Y3443 Cable Puller Replaces H3926 10 Service Life 10 0.35 0.49 Y3474 14′ Cable Splice Van Replaces H3886 12 Service Life 12 0.18 0.16 Y3475 14′ Cable Splice Van Replaces H3887 12 Service Life 12 0.18 0.17 Z3422 18′ Construction Van Replaces F3794 12 Service Life 12 0.18 0.26 Y3472 14′ Construction Van Replaces G3872 12 Service Life 12 0.16 0.19 Y3473 14′ Construction Van Replaces G3873 12 Service Life 12 0.16 0.16 Y3469 14′ Cube Van Replaces F3808 12 Service Life 12 0.16 0.18 Y3470 14′ Cube Van Replaces F3809 12 Service Life 12 0.16 0.18 Y3471 14′ Cube Van Replaces F3810 12 Service Life 12 0.16 0.18 Z3421 Dump Truck Replaces H3927 11 Service Life 11 0.11 0.15 Y4729 Forklift Replaces D4800 15 Service Life 15 0.10 0.11 N/A Compact Truck Replaces H2331 11 Service Life 11 0.04 0.00 N/A Car Replaces M1107 7 Service Life 7 0.00 0.00 N/A SUV Replaces M2069 7 Service Life 7 0.03 (0.01) N/A SUV Replaces M2070 7 Service Life 7 0.03 0.00 N/A SUV Replaces M2071 7 Service Life 7 0.03 0.00 N/A SUV Replaces M2072 7 Service Life 7 0.03 0.00 N/A SUV Replaces M2096 7 Service Life 7 0.03 0.00 Y2836 SUV Replaces M2067 7 Service Life 7 0.03 0.04 Y2238 SUV Replaces M2068 7 Service Life 7 0.03 0.03 W2544 Mini Dump convert Modifications N/A Modified N/A 0.00 0.05 Early Y4712 Backhoe Replaces M4109 6 7 0.00 0.13 Replacement Z2888 ½ Ton Pickup 4x4 Replaces J2108 11 Service Life 7 0.00 0.05 Y2995 ½ Ton Pickup 4x4 Replaces J2107 11 Service Life 7 0.00 0.04 P3068 14’ Cube Van Modifications Modified 12 0.00 0.02 T3236 Flatdeck c/w crane Replaces F3813 12 Service Life 12 0.00 0.26 W3448 55’ Digger Replaces F3812 12 Service Life 11 0.00 0.48 Y4713 Backhoe Replaces L4210 8 Service Life 7 0.00 0.18 Y4714 Backhoe Replaces L4211 8 Service Life 7 0.00 0.19 X3388 Digger Replaces V3117 11 Service Life 11 0.00 0.43 N/A Proceeds (2016 vehicles sold in 2017) 0.00 (0.30) Total Additions 3.99 5.76
Source: Exhibit 23571-X0009, Appendix B-5, paragraph 14, Table 2.1-3.
271. Through IRs, the Commission asked EPCOR to explain the service lives for several of its vehicle types shown in Table 15, including its 50-foot single bucket truck, car, compact truck, SUV and “1/2 Ton Pickup 4x4” vehicles. EPCOR responded that it takes input from its managers and operators respecting the level and type of use of its vehicles, the performance and longevity
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of the vehicles, as well as how these factors have affected service lives in the past. EPCOR also stated that in 2013 it had contracted Mercury Associates, Inc. to perform a life-cycle cost analysis, which identified that EPCOR’s service lives for vehicles were reasonable.289
272. Specifically, for its 50-foot single bucket truck (row 5 of Table 15 above), the Commission asked EPCOR to reconcile its service life of five years with the service lives of its double bucket trucks, and the Mercury Associates report recommendation of a service life of eight years.290 EPCOR explained that this single bucket truck is one of EPCOR’s distribution power trouble trucks, which operates 24 hours a day, seven days a week, often in adverse weather conditions to respond to power outages and emergencies. EPCOR submitted that its distribution power trouble trucks often accumulate more than 40,000 km per year, that these vehicles experience higher mechanical wear, and have shorter average service lives as a result.291
273. EPCOR elaborated that of the 27 single bucket trucks evaluated by the Mercury Associates report, eight were EPCOR’s distribution function vehicles. For depreciation purposes, its single bucket trucks are categorized into two fleet classifications: “Aerial Bucket Trucks” with an average service life of 12 years, and “Distribution Trouble Aerial Trucks”292 with an average service life of five years. EPCOR noted that it does not use a replacement cycle of eight years for its single bucket trucks, as recommended by the Mercury Associates report, but rather a five-year replacement cycle for its distribution power trouble trucks. EPCOR pointed to the recommended replacement cycle in the Mercury Associates report that corresponded to a mileage reading of 154,256 km, whereas EPCOR’s distribution power trouble trucks would have accumulated a forecast mileage of 252,840 km after five years of service, which is 100,000 km above the recommendation in the study.293
274. The Commission also asked EPCOR whether all of its vehicle life cycle replacement strategies originate from the Mercury Associates report. EPCOR stated that its life cycle replacement strategies do not originate from the Mercury Associates report, but that the report was part of a larger study of the EPCOR group’s overall fleet management practices. EPCOR explained that the Mercury Associates report included detailed optimal replacement cycle analyses on a small sample of vehicles to test the effectiveness of EPCOR’s fleet replacement practices. Explaining further, EPCOR stated that the scope of the Mercury Associates engagement was not to provide a comprehensive review of each vehicle category in EPCOR’s fleet or recommend average service lives for depreciation purposes, but rather to review its overall program to ensure it follows recognized industry best management practices and recommend potential areas for improvement.294
7.8.2.3 Purchase of hired fleet vehicles 275. The purchase of hired fleet vehicles project related to the purchase of distribution function vehicles and fleet equipment to replace previously rented vehicles that were used to
289 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-010(e); Exhibit 23571-X0009, Appendix B, Attachment 1, Fleet Replacement Plan for EPCOR, February 2013, Mercury Associates, Inc. 290 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-004(a)-(b). 291 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-010(b). 292 The Commission understands EPCOR’s reference of its “Distribution Trouble Aerial Trucks” in Exhibit 23571- X0145 to be the same as its reference to “distribution power trouble trucks” in Exhibit 23571-X0107.01. 293 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-004(a). 294 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-004(b).
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supplement existing distribution function vehicles and fleet equipment.295 In 2017, EPCOR purchased 31 vehicles, which are listed in Table 16.
Table 16. 2017 hired fleet capital additions A B C Unit 2016 A Actual cost (includes base cost Description Rental costs & capital overhead)
($ million) 1 W7862 1 Ton Van (Sprinter) 0.02 0.04 2 W7863 1 Ton Van (Sprinter) 0.02 0.04 3 V7870 ½ Ton Pickup 4x4 0.01 0.05 4 W7877 ½ Ton Pickup 4x4 0.01 0.05 5 X7804 ½ Ton Pickup 4x4 0.01 0.05 6 W7880 ½ Ton Pickup 4x4 0.01 0.05 7 W7864 ½ Ton Pickup 4x4 0.01 0.04 8 W7865 ½ Ton Pickup 4x4 0.01 0.04 9 V7869 ½ Ton Pickup 4x4 0.01 0.04 10 X7878 ½ Ton Pickup 4x4 0.02 0.04 11 V7891 ½ Ton Pickup 4x4 0.01 0.04 12 X7879 ½ Ton Pickup 4x4 0.02 0.04 13 X7869 ½ Ton Pickup 4x4 0.01 0.04 14 T7878 ½ Ton Pickup 4x4 0.01 0.04 15 V7854 ½ Ton Pickup 4x4 0.01 0.05 16 W7849 ½ Ton Pickup 4x4 0.01 0.05 17 X7806 ½ Ton Pickup 4x4 0.02 0.05 18 Y7853 ½ Ton Pickup 4x4 0.06 0.04 19 X7811 ½ Ton Pickup 4x4 0.01 0.04 20 V7872 1 Ton Pickup 4x4 0.01 0.06 21 W7801 1 Ton Pickup 4x4 0.01 0.06 22 X7808 1 Ton Pickup 4x4 0.02 0.06 23 X7810 1 Ton Pickup 4x4 0.02 0.06 24 V7890 1 Ton Pickup 4x4 0.01 0.06 25 X7807 1 Ton Pickup 4x4 0.01 0.06 26 X7813 1 Ton Pickup 4x4 0.02 0.06 27 Y7850 2 Ton mini dump 0.001 0.09 28 W7873 2 Ton mini dump 0.03 0.09 29 W7870 2 Ton mini dump 0.03 0.09 30 V7878 2 Ton mini dump 0.02 0.09 31 Y7803 Digger 0.002 0.32 32 Total 2017 Hired Fleet Additions 0.46 1.93 1Rental costs started in 2017 for $0.01 million. 2Rental costs started in 2017 for $0.05 million. Source: Exhibit 23571-X0009, Appendix B-5, paragraph 17, Table 2.1-4.
276. EPCOR stated it carried out a review of its hired equipment practices, including a review of its historic and current usage of hired fleet vehicles and its longer term forecast total fleet requirements based on its forecast workload. EPCOR submitted that the purchase of distribution function vehicles and fleet equipment has rebasing implications for, namely, operating costs. EPCOR pointed to Decision 22394-D01-2018 where the Commission determined that utilities would use the lowest cost year from 2013 to 2016 to determine the operating component of the notional revenue requirement. EPCOR pointed out that its lowest cost year is 2016 and that, included in that lowest cost year were $0.06 million of vehicle lease costs that EPCOR has now
295 Exhibit 23571-X0002.01, application, paragraph 1088.
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replaced with owned vehicles. EPCOR explained that these costs will continue to be included in EPCOR’s revenue requirement in the 2018-2022 PBR term until the next PBR rebasing.296
277. EPCOR explained that for capital costs, EPCOR’s purchase of these vehicles in 2017 results in a lower revenue requirement over the course of the 2018-2022 PBR term than would have been the case if the vehicles had been purchased during the 2013-2017 PBR term prior to 2017 (i.e., during 2013-2016). EPCOR stated that, as a result of the supplemental capital funding mechanism of K-bar for the 2018-2022 PBR term, including these vehicle capital additions in any year prior to 2017 would have resulted in a commensurate increase in the notional 2017 capital additions used to calculate K-bar. EPCOR estimated that, if it had proceeded with the vehicle capital additions in 2016 instead of 2017, its 2018-2022 PBR term revenue requirement would have increased by approximately $0.08 million in each year of the term.297
278. In IRs, the Commission asked EPCOR how many vehicles it rented in 2016 that led to an acquisition of 31 vehicles total, and whether or not the evaluation period for the rental vehicles’ conversion to purchase was in line with EPCOR’s historical timelines for moving from a rental to an acquisition. In its response, EPCOR stated that in 2016, it had, on average, 60 rented vehicles. EPCOR also submitted that the evaluation period for the rental vehicles’ conversion to purchase was in line with EPCOR’s historical timelines for moving from rental to acquisition and that the expected use of a rental unit would be required for a minimum of three years.298
279. The CCA asked EPCOR to provide the number of rental units for each year from 2013 to 2017, as well as the number of rental units converted to purchased units. These amounts are shown in Table 17.
Table 17. Total number of rental vehicles and vehicles converted to purchased units EDTI’s distribution function 2013-2017 A B Year Annualized equivalent rental vehicles Converted to purchased units 1 2013 48.2 0 2 2014 46.6 0 3 2015 56.1 0 4 2016 56.7 0 5 2017 47.8 31 Source: Exhibit 23571-X0147, EDTI-CCA-2018AUG24-032-1.
280. The CCA argued that because EPCOR has a three-year period of renting before determining whether to purchase a unit, and its vehicle life cycles have not changed, it is not clear what would have led to such a high level of conversion of vehicle rentals.299 The CCA contended that it is unlikely that in past years, EPCOR had a shortfall of vehicles that had to be replaced in 2017 such that EPCOR needed to more than double its forecast additions and triple the level of historical actual additions.300
281. The CCA also contended in its argument that the change in treatment for capital outside of the I-X incentives when moving from capital trackers under the 2013-2017 PBR plan to K-bar
296 Exhibit 23571-X0002.01, application, paragraphs 1102-1104. 297 Exhibit 23571-X0002.01, application, paragraph 1105. 298 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-010(c). 299 Exhibit 23571-X0200, CCA argument, paragraph 62. 300 Exhibit 23571-X0200, CCA argument, paragraph 66.
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under the 2018-2022 PBR plan, provides an incentive to distribution utilities to accelerate capital programs and, to the extent that they are able to do so, to bring future planned capital expenditures into 2017.301 In particular, the CCA argued that EPCOR’s past capital expenditures for vehicle rental conversions can only be explained by this incentive to accelerate capital expenditures in advance of 2018.
282. In reply argument, EPCOR pointed out that the CCA acknowledges EPCOR’s extensive NPV analyses on a vehicle-by-vehicle basis demonstrating the cost savings that would be achieved over time with the conversions. EPCOR submitted that this analysis is evidence that it engaged in utility decision-making in accordance with what PBR is intended to encourage, namely, to engage in decision-making that lowers its operating and capital costs, and that its 2017 actual capital additions reflect an appropriate response to PBR incentives.302
Commission findings 283. For the purposes of EPCOR’s 2017 capital tracker true-up application, the Commission considers the Vehicles – Growth and Life Cycle Replacement Project to be composed of three separate projects: (i) the fleet additions to account for growth; (ii) life cycle replacement of vehicles; and (iii) the purchase of previously rented vehicles. The Commission will consider each of these three projects individually; thus, each project must satisfy all of the capital tracker criteria in order to be afforded capital tracker treatment.
284. With respect to the true-up of 2017 actual costs for (i) the fleet additions to account for growth; and (ii) life cycle replacement of vehicles, the Commission has previously confirmed their need under the project assessment component of Criterion 1 in prior capital tracker decisions. As noted in Section 4, if there is no evidence on the record of the true-up proceeding demonstrating that a project was not required in 2017, EPCOR is not required to demonstrate that a project was needed in order to provide utility service at adequate levels in 2017, as would otherwise be required under the project assessment component of Criterion 1. The Commission finds no evidence on the record of this proceeding to indicate that the fleet additions to account for growth and the life cycle replacement of vehicles were not required in 2017.
285. With respect to the scope, level and timing of (i) the fleet additions to account for growth; and (ii) life cycle replacement of vehicles for 2017, the Commission considers that EPCOR has adequately explained the actual scope, level and timing of its capital additions for these two projects and the Commission finds them to be prudent.
286. Concerning the third project within the Vehicles – Growth and Life Cycle Replacement Project, (iii) the purchase of previously rented vehicles, the Commission has not assessed the need for this project in a prior decision. EPCOR explained the need for this project was to replace previously rented vehicles that were used to supplement existing distribution function vehicles and fleet equipment.303 Further, EPCOR stated that it determined that the vehicles shown in Table 16 were required over the long term to carry out its forecast workload, and that the purchase of these vehicles will ensure that EPCOR’s fleet has the necessary vehicles available for use when required.304
301 Exhibit 23571-X0200, CCA argument, paragraph 67. 302 Exhibit 23571-X0206, EDTI reply argument, paragraphs 49 and 54. 303 Exhibit 23571-X0002.01, application, paragraph 1088. 304 Exhibit 23571-X0002.01, application, paragraph 1107.
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287. The Commission notes that prior to 2017, EPCOR had access to these same vehicles through its rental contracts. While the Commission does not dispute that these vehicles were needed over the long term to carry out EPCOR’s obligation to serve, it was not necessary for EPCOR to purchase the vehicles that it was previously able to rent. However, the Commission further notes that the decision to purchase rental vehicles is a decision for EPCOR to make based on whatever criteria it considers relevant. Now that EPCOR has made the decision to purchase the rental vehicles, the Commission must evaluate whether the project meets the capital tracker criteria, including an assessment of need. Given EPCOR had access to the rental vehicles prior to their purchase, and EPCOR did not indicate that renting the vehicles was no longer an option, purchasing the vehicles was not strictly necessary. However, because the vehicles are a necessary piece of equipment used by EPCOR to fulfill its obligation to serve, whether through rental or ownership, the Commission must consider the project in terms of its scope, level and timing.
288. In response to an IR from the CCA, EPCOR submitted that the timing of the purchases of the rental vehicles in 2017 was based on an identified business need of at least three years, and a detailed analysis of the specific operational needs of these vehicles.305
289. In reply, the CCA asserted that EPCOR was facing an incentive to accelerate vehicle rental conversions in 2017 since they were economic decisions that reduced EPCOR’s overall costs. While EPCOR provided analysis of its decision to purchase the rental vehicles in 2017,306 the Commission finds that EPCOR provided no explanation as to why similar purchases were not made from 2013 to 2016 (as shown in Table 17).
290. As explained by EPCOR in response to EDTI-CCA-2018AUG24-032,307 in 2017, if its business function identified the need for a rental unit for at least three years, an analysis would be performed to determine whether it should be rented or purchased. It is not apparent to the Commission why this analysis could not have also been done in previous years when all of this equipment was rented. In the judgement of the Commission, EPCOR has not provided sufficient reasons to explain why vehicle rental conversions were not economic decisions in any year prior to 2017 but became economic decisions in 2017.
291. As part of the minimum filing requirements to establish prudent capital expenditures, EPCOR must provide evidence to demonstrate that a project being proposed for capital tracker treatment “could not have been undertaken previously as part of a prudent capital maintenance and replacement program.”308
292. The Commission finds that EPCOR has not provided persuasive evidence with respect to the scope, level and timing of the third project under the Vehicles – Growth and Life Cycle Replacement Program, (iii) the purchase of previously rented vehicles, to show that the purchase was prudent for 2017. Specifically, EPCOR did not demonstrate that the rental vehicle purchases could not have been undertaken previously as part of a prudent capital maintenance and replacement program. Accordingly, the Commission cannot extend capital tracker treatment to EPCOR’s actual 2017 costs associated with the purchase of previously rented vehicles and
305 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-032(d). 306 Exhibit 23571-X0009, Appendix B-5. 307 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-032(e). 308 Decision 3558-D01-2015, Appendix 3.
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directs EPCOR to remove the $1.93 million in capital additions and recalculate the K factor associated with this project.
7.9 Replacement of Aerial Ground Rod and Underground Distribution Equipment Ground Grid 293. This project involves the replacement of ground rods on aerial transformers, regulators, arrestors and/or switches and underground distribution equipment ground grids to ensure proper grounding of aerial and underground systems. The project is required to maintain compliance with provisions of the Alberta Electricity Utility Code (AEUC), which imposes several requirements on both aerial ground rods and underground ground grids.309
294. Asset replacement regarding this project has been done under this project in years prior to 2017; however, until 2017, expenditures did not meet the materiality threshold for the project to be treated as a capital tracker. Consequently, this project was last reviewed by the Commission in Decision 2012-272 as part of EPCOR’s 2012 tariff application.
295. In 2017, the project met the materiality threshold as EPCOR had to substantially increase the number of underground ground grids to remain compliant with the requirements of the AEUC.310 EPCOR advised that it completed 202 underground ground grid replacements in 2017 as compared to a forecast of 50.311 As a result, EPCOR incurred $1.55 million of capital additions on this project, which was $1.33 million more than it had previously forecasted.312
296. Through IRs, the Commission asked EPCOR to explain why it had increased the number of replacements from 50 to 202. The Commission also asked EPCOR to identify the number of replacements it expects in the future.313
297. In response, EPCOR stated that the increase in the number of replacements was not motivated by a major event that had occurred, neither had the testing and assessment criteria changed. Rather, in 2016, it performed a “thorough analysis” that “demonstrated EPCOR’s historical capital additions [were] insufficient in addressing the number of ground grids that exceeded the AEUC requirement of being six ohms or less.”314 EPCOR stated that approximately 1,500 ground grids were non-compliant with this standard. Consequently, in 2017, EPCOR supplemented its internal resources with those of an external contractor and was able to replace 202 ground grids. EPCOR stated that based on the backlog of ground grids and the availability of qualified contractors, it anticipated it will be replacing ground grids at 2017 actual levels for the foreseeable future.
298. Noting that the AEUC provides that “where practicable, the resistance of the interconnected neutral system shall not exceed 6 ohms,” the Commission asked EPCOR what discretion it had in determining what was “practicable” and if EPCOR used the same discretion in 2017 as it had in the past.315
309 Exhibit 23571-X0002.01, application, paragraph 1199. 310 Exhibit 23571-X0002.01, application, paragraph 1200. 311 Exhibit 23571-X0002.01, application, paragraph 1201. 312 Exhibit 23571-X0002.01, application, paragraph 1208. 313 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-005. 314 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-005(a). 315 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-006.
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299. EPCOR replied that the AEUC does not define practicable, and that it used its “discretion in complying with this requirement only as it pertains to physical constraints, such as pipelines or other utility infrastructure being directly below the grid, or where geographical features prevent the installation of ground rods to meet the six ohm resistance requirement.”316 EPCOR further stated that it was unaware of any circumstances on its system where resistance has exceeded six ohms and addressing the issue was not practicable. EPCOR also stated that it had not changed the manner in which it applied its discretion regarding the replacement of ground grids.317
300. Given EPCOR’s previous responses that there was no event or series of events that led to the increase in ground rod replacements, nor had its evaluation criteria or its use of discretion changed, the Commission asked EPCOR for the impetus of the 2016 review of ground grid inspections. The Commission also asked EPCOR to provide evidence showing that the project being proposed for capital tracker treatment “could not have been undertaken previously as part of a prudent capital maintenance and replacement program.”318 Finally, the Commission asked EPCOR to discuss any safety concerns regarding ground grids that exceed the six ohm threshold.319
301. In response, EPCOR stated that in the past, replacements related to this project were forecast using a rolling three-year average. However, since EPCOR began engaging with METSCO to assist in updating its asset management practices, EPCOR determined that using the historical average methodology may not be the optimal replacement strategy:
Although EDTI’s distribution equipment ground grid life cycle replacement program was not specifically included in METSCO’s scope of work, the process of reviewing EDTI’s overall distribution asset management practices and working with METSCO’s subject matter experts in developing a distribution asset risk based framework demonstrated how a historical average may not be the optimal assert replacement strategy. This finding was the impetus that spurred EDTI to review its historical ground grid inspection data in 2016 to determine if EDTI’s historical capital additions would be sufficient for purposes of determining EDTI’s planned level of ground grid replacements for 2017.320
302. EPCOR stated that it could not have increased the amount of work conducted on this project as part of a previous prudent capital maintenance and replacement program because it had not completed its review and, therefore, was relying on its previous replacement methodology.321
303. EPCOR also explained that the safety risk associated with having ground grids with resistance exceeding six ohms is that a proportionally larger volume of electric current will flow along the surface or through the body of an individual who comes in contact with or is in close proximity to the faulted electrical distribution system equipment. EPCOR further noted that the probability of an unsafe condition on its distribution system was extremely low and that EPCOR was not aware of any occurrence that has resulted in serious injury or fatality. However, due to there still being a risk, mitigation measures ought to be put in place. In 2017, EPCOR took into
316 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-006(a). 317 Exhibit 23571-X0107.01, EDTI-AUC-2018JUN22-006. 318 Decision 3558-D01-2015, Appendix 3. 319 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-001. 320 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-001(a). 321 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-001(b).
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consideration the risks and probability of potentially hazardous grounding grid conditions and prioritized replacements that had the highest ground resistance readings and were located in the most densely populated areas and in the vicinity of schools and public parks, followed by commercial and residential areas.322
304. In argument, the CCA recommended the Commission only allow cost recovery of 50 ground grids and that the remaining 2017 additions be disallowed. The CCA argued that because EPCOR has not changed its testing on ground grids, has not changed its discretion over which ground grids to replace and does not know of areas where the six ohm standard has been exceeded, the evidence does not justify the increased number of replacements that EPCOR undertook in 2017.323
305. In reply argument, EPCOR stated that the recommendations made by the CCA were based on the CCA misquoting and misrepresenting the evidence that EPCOR had placed on the record regarding the project and that the argument put forward by the CCA should be dismissed.324
Commission findings 306. The purpose of the capital tracker mechanism is to enable utilities to seek supplemental capital funding for certain projects not otherwise funded under the I-X mechanism of the PBR plans. The burden of establishing whether a project is eligible for capital tracker treatment rests with the utility. As noted in Section 4 above, in order to be eligible for capital tracker treatment, a project must meet the three criteria established in Decision 2012-237.
307. Criterion 1 requires that the project must be outside the normal course of the company’s ongoing operations and includes two sub-parts: an accounting test, and a project assessment test.
308. Because the Commission has not previously assessed the Aerial Ground Rod and Underground Ground Grid Lifecycle Replacement Project as a capital tracker project, the Commission must assess:
Whether the project is required to provide utility service at adequate levels; and, if so,
Whether the scope, level and timing of the project is prudent, and the forecast or actual costs of the project are reasonable.325
309. The Commission’s assessment in this case concerns actual rather than forecast costs. Accordingly, the Commission will consider whether the actual costs of the project satisfy the project assessment test.
Is the project required to provide utility service at adequate levels? 310. The Commission has reviewed EPCOR’s business case, responses to IRs and all other evidence on the record of this proceeding with respect to the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project. Based on this
322 Exhibit 23571-X0145, EDTI-AUC-2018AUG24-001(c). 323 Exhibit 23571-X0200, page 12. 324 Exhibit 23571-X0206, paragraphs 33-40. 325 Decision 2013-435, paragraph 278.
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information, the Commission finds that the lifecycle replacement of ground grids was required to provide utility service at adequate levels.
311. Specifically, the Commission understands that the AEUC states that “where practicable, the resistance of the interconnected neutral system shall not exceed 6 ohms,” and that as a result of EPCOR’s “more thorough” analysis in 2016, it found that approximately 1,500 ground grids were non-compliant with this standard. As this represents a potential safety issue and non- compliance with the AEUC, this demonstrates the need for the project.
312. The Commission approved EPCOR’s applied-for forecast revenue requirement for this project in Decision 2012-272 as part of EPCOR’s 2012 general tariff application, the last prior to PBR.326 And EPCOR has continued to perform work under this project through the course of the 2013-2017 PBR term, although capital expenditures did not meet the capital tracker requirements in prior years.327
Is the scope, level and timing, and actual costs, of the project prudent? 313. In demonstrating that the scope, level, timing and actual costs, of the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project are prudent, EPCOR must establish that its actual expenditures on ground grid replacements were prudently incurred.
314. As part of the minimum filing requirements to establish prudent capital expenditures, EPCOR must provide evidence to demonstrate that a project being proposed for capital tracker treatment “could not have been undertaken previously as part of a prudent capital maintenance and replacement program.”328 For the reasons set out below, the Commission finds that EPCOR has not provided persuasive evidence to satisfy the Commission that the capital expenditures for the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project could not have been undertaken previously as part of a prudent capital maintenance and replacement program.
315. The Commission acknowledges that the replacement of 202 ground grids in 2017 was conducted in an effort to address the backlog of approximately 1,500 ground grids no longer in compliance with AEUC standards. However, based on replacements prior to 2017, the Commission does not believe that the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project expenditures are part of a prudent capital replacement plan. An examination of the data shows that, beginning in 2013 and extending through to the end of 2017, EPCOR’s pattern of expenditures changed significantly. Between 2014 and 2016, the replacement pattern was relatively consistent compared to 2017. The Commission is not persuaded that the increase in expenditures could have only been conducted in 2017 and not in the past.
316. The Commission acknowledges EPCOR’s explanation that it was the analysis conducted in 2016 that incented EPCOR to increase the number of replacements. However, given EPCOR’s admission that no event or series of events led to the increase in ground rod replacements, nor had its evaluation criteria or its use of discretion changed, EPCOR did not provide an adequate
326 Decision 2012-272: EPCOR Distribution & Transmission Inc., 2012 Phase I and II Distribution Tariff & 2012 Transmission Facility Owner Tariff, Application 1607944, Proceeding 1596, October 5, 2012. 327 Exhibit 23571-X0008, Appendix B-4, Table 5.0-1. 328 Decision 3558-D01-2015, Appendix 3.
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explanation regarding why a continued replacement pace of 50 per annum was no longer reasonable. EPCOR has claimed it was unaware there was a backlog of required ground grid replacements; however, the Commission finds that at best, EPCOR may not have been aware of the extent of its backlog but it certainly had to be aware of some need for ongoing replacement as it had been replacing these assets every year throughout the PBR term and prior to that. Consequently, the Commission finds that EPCOR has not provided persuasive evidence to satisfy the Commission that the capital expenditures in 2017 for the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project could not have been undertaken in the past as part of a prudent capital investment and maintenance program.
317. EPCOR’s request for capital tracker treatment for the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project is denied. EPCOR is directed, in a compliance filing to this decision, to remove the $1.22 million in capital additions associated with this project in its recalculation of its 2017 K factor.
8 Accounting test under Criterion 1 – the project must be outside of the normal course of the company’s ongoing operations, and Commission conclusion on Criterion 1
8.1 Accounting test for the 2017 true-up 318. As explained in Decision 2013-435, the purpose of the accounting test is to determine whether a project or program (depending on the approved level of grouping) proposed for capital tracker treatment is outside the normal course of the company’s ongoing operations. This is achieved by demonstrating that the associated revenue provided under the I-X mechanism would not be sufficient to recover the entire revenue requirement associated with the prudent capital expenditures for the project or program.329
319. The accounting test is described in Section 7.1 of Decision 20407-D01-2016, at paragraphs 737 to 739 and 741.
320. EPCOR provided the first component of the accounting test, the calculation of revenue provided under the I-X mechanism, in Schedule 1 of its application.330 EPCOR provided its calculation of the accounting test model for its 2017 capital tracker true-up in Schedule 2 of its application.331
8.1.1 Accounting test model adjustments 321. At paragraph 240 in Decision 20407-D01-2016, the Commission directed EPCOR:
… in its future capital tracker applications, starting with the compliance filing to this decision, to include its new AUFs for the Work Centre Redevelopment project and the OMS/DMS project (and in the future, for any other capital tracker projects or programs to which new AUFs apply) in its accounting test schedules in a manner that demonstrates the amount of the AUF offset.…
329 Decision 2013-435, paragraphs 149-150. 330 Exhibit 23571-X0081, Schedule 1. 331 Exhibit 23571-X0082, Schedule 2.
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322. EPCOR included a column in Schedule 2 entitled “K Factor Adjustment” to identify these types of adjustments to its K factor, which will either be added to or subtracted from the K factor resulting from the accounting test prior to the application of the materiality threshold test.332
323. In the application, EPCOR proposed to make an adjustment to its 2017 K factor true-up amount to avoid the double recovery of certain costs relating to providing service to customers on Customer Specific (CS) rates. EPCOR calculated the K factor adjustment for each relevant project for a total adjustment of $0.24 million and incorporated this adjustment into its accounting test model in the “K Factor Adjustment” column.333
Commission findings 324. The Commission has reviewed EPCOR’s schedules with respect to the “K Factor Adjustment” column addition and finds that the addition of this column to EPCOR’s accounting test model adequately allows the avoidance of any double-counting related to CS rates. The Commission is satisfied that there is no double-counting related to CS rates, and that EPCOR has complied with the direction at paragraph 240 in Decision 20407-D01-2016.
8.1.2 Accounting test assumptions 325. For the 2017 capital tracker true-up, EPCOR used the following assumptions in its accounting test:
Table 18. EPCOR’s 2017 capital tracker true-up accounting test assumptions 2017 I-X index -1.92% 2017 Q factor 0.16% Weighted average cost of capital (WACC) rate embedded in EPCOR’s going-in rates used 6.50% in the first component of the accounting test Actual 2017 WACC rate used in the second component of the accounting test 6.25%
Source: Exhibit 23571-X0002.01, application, paragraph 91, Table 2.3.1-1 and paragraph 88, Table 2.3.1-1
326. No party raised issues with EPCOR’s 2016 I-X index and Q factor values, nor with the WACC rate used in the first component of the accounting test.
327. EPCOR’s actual 2017 WACC rate of 6.25 per cent used in the second component of the accounting test is based on the actual cost of debt of 4.93 per cent, the approved equity thickness of 37 per cent and the approved return on equity (ROE) of 8.5 per cent, as determined in the 2016 generic cost of capital Decision 20622-D01-2016.334 EPCOR’s actual 2017 cost of debt of 4.93 per cent, as reported in its 2017 Rule 005335 filing, is a blend of EPCOR’s new $140 million long-term debt issue in 2017, with a coupon rate of 3.62 per cent for $50 million and 3.75 per cent for $90 million of debt issued, and rates for 14 prior debt issues dating back to 1999.336
328. In the application, EPCOR stated that in its 2017 Rule 005 filing, it adopted the approach used in its 2016 capital tracker true-up application in calculating its embedded cost of debt. More
332 Exhibit 23571-X0823, application, Schedule 2, tab 3, column D. 333 Exhibit 23571-X0002.01, application, paragraphs 101-103. 334 Decision 20622-D01-2016: 2016 Generic Cost of Capital, Proceeding 20622, October 7, 2016. 335 Rule 005: Annual Reporting Requirements of Financial and Operational Results. 336 EPCOR’s 2017 Rule 005 filing, revised, schedules 2 and 2.3.
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specifically, EPCOR calculated its embedded cost of debt for Rule 005 reporting purposes as though new debt issued in the Rule 005 year attracted a full year of interest expense. EPCOR claimed that this approach ensures that its embedded cost of debt, and thus its WACC, accurately reflects EPCOR’s actual cost of debt in relation to new debt issues during the Rule 005 year.337
Commission findings 329. The Commission has reviewed EPCOR’s schedules that make up its accounting test analysis for the purposes of the 2017 capital tracker true-up and finds these schedules to be generally consistent with the accounting test methodology approved in Decision 2013-435. The Commission has verified EPCOR’s I-X and Q factor assumptions used in the first component of the accounting test, and finds that EPCOR used the correct values.
330. With respect to the WACC rate EPCOR used in the second component of its accounting test, the CCA opposed the manner in which EPCOR calculated its 2017 embedded cost of debt and submitted evidence on the matter. The Commission addresses the WACC rate in the next section.
8.1.2.1 Cost of debt 331. Because all of EPCOR’s debt is issued to its parent company, EUI, EPCOR’s debt is not an observable transaction in the market. To account for this, EPCOR calculates an embedded debt rate as a proxy for its actual debt rate. In 2017, EPCOR calculated its embedded debt rate based on the following inputs: The yield on 30-year Government of Canada bonds. A credit risk premium to reflect the higher risks of corporate debt. An allowance for financing costs of five basis points.
332. EPCOR explained that for the yield on 30-year Government of Canada bonds, it used the published rate on the Bank of Canada website on the business day before the promissory notes were issued. The rates on the business day before July 4, 2017, and November 1, 2017, were 2.11 per cent and 2.30 per cent, respectively.338
333. For the credit risk premium, EPCOR stated that it used the median value of the credit spread of five other companies it deemed to be comparators. The comparators EPCOR used were FortisAlberta Inc., FortisBC Inc., Nova Scotia Power Inc., Westcoast Energy Inc., and TransCanada PipeLines LP. EPCOR provided the credit spreads of these five utilities as of June 26, 2017 (National Bank), and June 23, 2017 (TD Securities), which were used to set the interest rate for the July 4, 2017 promissory note, and as of October 30, 2017 (National Bank), and October 27, 2017 (TD Securities), to set the interest rate for the November 1, 2017 promissory note.
334. The Commission reproduced these interest rates below as Table 19.
337 Exhibit 23571-X0002.01, application, paragraphs 88-89. 338 Exhibit 23571-X0109, EDTI-CCA-2018JUN22-006(a).
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Table 19. Interest rates EPCOR considered in determining its credit risk premium DBRS rating S&P rating National Bank TD Securities Average (%) Interest rates EPCOR considered for its July 4, 2017 promissory note FortisAlberta 1.38 1.35 FortisBC A (low) A- 1.40 1.43 1.40 Nova Scotia Power A (low) n/a 1.45 1.46 1.45 TransCanada PipeLines A (low) BBB+ 1.47 1.78 1.75 Westcoast Energy Inc. A (low) A- 1.80 2.03 2.00 Average A (low) BBB+ 2.05 1.62
Median (used as embedded rate) 1.46 Interest rates EPCOR considered for its November 1, 2017 promissory note FortisAlberta 1.32 FortisBC A (low) A- 1.30 1.33 1.38 Nova Scotia Power A (low) n/a 1.35 1.40 1.40 TransCanada PipeLines A (low) BBB+ 1.40 1.40 1.78 Westcoast Energy Inc. A (low) A- 1.75 1.80 1.98 Average A (low) BBB+ 1.95 2.00 1.57 Median (used as embedded rate) 1.40 Interest rates EPCOR did not use for its July 4, 2017 promissory note EPCOR Utilities Inc. A (low) A- 1.40 1.40 1.40 Interest rates EPCOR did not use for its November 1, 2017 promissory note EPCOR Utilities Inc. A (low) A- 1.30 1.31 1.31
Sources: Exhibit 23571-X0109, EDTI-CCA-2018JUN22-006(a) and Exhibit 23571-X0147, EDTI-CCA-2018AUG24-026 Attachments 1 and 2.
335. Combining these three inputs yielded embedded interest rates of 3.62 per cent and 3.75 per cent for EPCOR’s July 4, 2017 and November 1, 2017 promissory notes, respectively. This information is shown in Table 20.
Table 20. Calculation of EPCOR’s embedded interest rate on its 2017 promissory notes July 4, 2017 November 1, 2017 (%) Yield on 30-year Government of Canada Bonds 2.11 2.30 Credit spread 1.46 1.40 Financing costs 0.05 0.05 Embedded interest rate 3.62 3.75
Source: Exhibit 23571-X0109, EDTI-CCA-2018JUN22-006(a).
336. EPCOR explained that its indicative credit rating, obtained from DBRS Limited, was A (low); therefore, it selected comparators that were also A (low).339
337. Mr. Thygesen, on behalf of the CCA, filed evidence asserting that EPCOR has the incentive to overstate the interest rate on debt, and that it did so for its 2017 WACC calculation.340 The CCA summarized its position as follows: EPCOR’s debt rates are consistently higher than any other utility.
339 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-026. 340 Exhibit 23571-X0176.01, evidence of Mr. Thygesen, paragraphs 14-15.
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Even ignoring the absolute value of the coupon rate, EDTI's debt rates have not dropped as much as the other utilities. The credit spreads for EPCOR’s comparators Nova Scotia Power, WestCoast Transmission and TransCanada Pipelines are consistently at or much higher than comparable Alberta utilities.341
338. The CCA questioned the appropriateness of EPCOR’s comparators and referenced Decision 23165-D01-2018, in which the Commission determined that for the 2018 and 2019 test years, EPCOR’s deemed debt should be based on the average of FortisAlberta, FortisBC and Nova Scotia Power and should not include Westcoast Energy and TransCanada Pipelines:342
402. The Commission has considered the range of credit spreads of Westcoast and TransCanada compared with the range of credit spreads among the two Fortis companies and Nova Scotia Power (three companies), and finds that the divergence between the five companies at this time is at an unacceptable level for comparative use. For this reason, the Commission finds that Westcoast and TransCanada are not close comparators for the purposes of determining EPCOR’s credit risk premium.
339. The CCA proposed that the Commission’s findings in Decision 23165-D01-2018 should be applied to this current proceeding. It further argued that EUI should be considered as a comparator rather than Nova Scotia Power or, alternatively, as a sole comparator. The CCA submitted that EUI was a more relevant comparator now compared to prior years because EUI no longer holds generation assets, which has lowered its credit risk premium. Further, the CCA argued that EUI was a superior comparator to Nova Scotia Power because of its more similar credit ratings to EPCOR, recent restructuring of EUI’s business portfolio, and the location of its operations.343
340. The CCA acknowledged that in Decision 23165-D01-2018, the Commission had rejected the use of EUI as a comparator but explained that the Commission did so on procedural grounds and not necessarily on its merits because the CCA raised the issue during argument, and did not provide evidence on it.344
341. EPCOR submitted evidence to rebut the CCA’s position. It stated that its 2017 actual debt rates were appropriately calculated based on the approved methodology at the time and, as such, remained reasonable. Further, EPCOR submitted that changing its deemed cost of debt to be based on what Decision 23165-D01-2018 determined would only amount to a small difference (approximately 0.03 per cent), and that there was no reasonable basis for suggesting that it be subject to “after the fact” revision at this point.345 It stated:
Mr. Thygesen provides an inaccurate and misleading calculation of the impact of his suggested 6 basis point differential. Mr. Thygesen calculates the impact of a 6 basis point change as being equal to $2.52 million over the 30 year life of the notes issued in 2017.
341 Exhibit 23571-X0176.01, evidence of Mr. Thygesen, paragraph 53. 342 Decision 23165-D01-2018: EPCOR Distribution & Transmission Inc., 2018-2019 Transmission Facility Owner Tariff Application, Proceeding 23165, October 11, 2018. 343 Exhibit 23571-X0200, CCA argument, PDF pages 30-33. 344 Decision 23165-D01-2018, paragraph 399. 345 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF pages 17-18.
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Mr. Thygesen correctly calculates the total impact over 30 years, however, this greatly exaggerates impact which is less than $0.1 million annually….346 [footnote removed]
342. EPCOR also disagreed that EUI should be considered as a comparator stating:
EDTI notes that the Commission rejected the use of EUI as a comparator for EDTI in Decision 2010-505 (paras. 174-175), noting that EUI was not a pure play utility, having significant investments in unregulated power generation through Capital Power Corporation. Although EUI completed the divestiture of its interest in Capital Power in 2017, it is the case today that a significant portion of its businesses are in the US, and it is active in the very different areas of regulated and unregulated energy services and water and wastewater treatment. EDTI considers that these ongoing differences continue to make EUI inappropriate as a comparator for EDTI Distribution, as determined by the Commission in Decision 2010-505.347
343. Further, with respect to the CCA’s recommendation that EUI be used as the sole comparator for determining EPCOR’s debt rates, EPCOR stated:
EDTI considers that consistent with the Commission’s directions and approved comparators in the past, the use of market comparators is a better approach for setting interest rates. Further, mirroring down a corporate parent’s interest rate is less desirable because the corporate parent may not issue debt during a year in which the subsidiary requires the debt (leading to timing-driven mismatches between the corporate debt rate and the appropriate debt rate at the time the subsidiary issues the debt); and it is inconsistent with the stand-alone principle (e.g., the corporate parent may change its holdings or have a change in its credit rating that make it a less meaningful comparator, as acknowledged by Mr. Thygesen).348
344. With respect to the CCA’s claim that EPCOR’s cost of debt is “consistently higher than any other utility,” EPCOR stated:
While there were few debt offerings reported by Alberta utilities in their 2017 Rule 005 filings, EDTI notes that FortisAlberta issued debt on September 7, 2017 at 3.67%. The rate is higher than the 3.62% rate on EDTI’s July 4, 2017 issuance but lower than the 3.75% rate on the November 1, 2017 offering. Mr. Thygesen’s assertion that EDTI debt rates are consistently higher than any other utility is not supported by the facts.
EDTI cautions that comparison of corporate interest rates and credit spreads on debt issued at different dates is of limited value because interest rates and credit spreads can change significantly over time. Accordingly, the type of comparison that Mr. Thygesen suggests should be given little weight. Instead, the interest rates and credit risk premiums at the date of issuance should be the focus.349
Commission findings 345. The Commission recently considered EPCOR’s cost of debt in the Decision 23165-D01- 2018. In Decision 23165-D01-2018, the Commission found the following:
346 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF page 20. 347 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-026(c). 348 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF page 19. 349 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF pages 19-20.
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394. The Commission agrees with EPCOR that choosing comparator entities based on the similarity of their credit spreads, as the CCA recommended, would effectively result in a pre-determination of risk, which is contrary to the Commission’s historical practice of approving a credit spread based on the credit spreads for a group of comparative entities of equivalent risk.
395. However, the Commission considers that a review of the comparator entities used by EPCOR is beneficial, and in making its determination, the Commission is guided by previous Commission decisions on the selection of comparator utilities for the determination of EPCOR’s credit risk spreads.
346. The Commission went on to identify several previous decisions that it used as guidance on this issue, namely:
Decision 2010-505, which found that EPCOR should rely on the average spread of a group of comparable utilities to determine the cost of its debt and that FortisAlberta was the closest comparator at that time.350
Decision 2012-272, where the Commission accepted EPCOR’s methodology for determining credit risk based on a group of comparator companies, but rejected entities having anything other than a DBRS rating of A (low).351
347. Further, given the evidence on Proceeding 23165, the Commission found in Decision 23165-D01-2018 that:
399. Consistent with previous decisions, the Commission is of the view that AltaLink and CU Inc. should not be included in EPCOR’s group of comparators because their credit ratings are currently A and A (high), respectively.… … 402. The Commission has considered the range of credit spreads of Westcoast and TransCanada compared with the range of credit spreads among the two Fortis companies and Nova Scotia Power (three companies), and finds that the divergence between the five companies at this time is at an unacceptable level for comparative use. For this reason, the Commission finds that Westcoast and TransCanada are not close comparators for the purposes of determining EPCOR’s credit risk premium.352
348. For the same reasons, the Commission finds that Westcoast and TransCanada are not close comparators in 2017 when EPCOR issued debt; therefore, the Commission excludes these two companies as comparators for 2017.
349. As noted earlier, the Commission did not consider adding EUI as a comparator in Proceeding 23165, because the CCA raised the issue in argument and did not file evidence on it. The Commission denied that EUI be used as the sole comparator in Decision 2010-505,
350 Decision 2010-505: EPCOR Distribution & Transmission Inc., 2010-2011 Phase I Distribution Tariff, 2010- 2011 Transmission Facility Owner Tariff, Proceeding 437, Application 1605759-1, October 28, 2010, paragraphs 177-179. 351 Decision 2012-272: EPCOR Distribution & Transmission Inc., 2012 Phase I and II Distribution Tariff 2012 Transmission Facility Owner Tariff, Proceeding 1596, Application 1607944-1, October 5, 2012, paragraphs 147-152. 352 Decision 23165-D01-2018, paragraphs 399 and 402.
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principally due to its holdings at the time in unregulated power generation through Capital Power Corporation, which negatively affected EUI’s credit rating. Rather, the indicative corporate credit spread of more comparable utilities would be preferable.353
350. In this proceeding, the CCA provided evidence that EUI’s circumstances have changed since the Commission last considered this issue. Specifically, EUI has divested of its holding in Capital Power and its credit rating is similar to EPCOR’s indicative credit rating.354
351. EPCOR argued that using market comparators is a better approach for setting interest rates, since the corporate parent may not issue debt during a year in which the subsidiary requires the debt (leading to timing-driven mismatches between the corporate debt rate and the appropriate debt rate at the time the subsidiary issues the debt); and it is inconsistent with the stand-alone principle (e.g., the corporate parent may change its holdings or have a change in its credit rating that makes it a less meaningful comparator).355
352. Continuing to use its past decisions as a guide, the Commission continues to hold the view that EPCOR should rely on the average spread of a group of comparable utilities to determine the cost of its debt. This avoids the potential issues that EPCOR raised regarding the mirroring down of a corporate parent’s interest rate, including the timing of debt issuances and mismatches in business.356 Nevertheless, this does not preclude using EUI as a comparator.
353. EPCOR confirmed that on September 26, 2014, Standard & Poor’s Ratings Services raised EUI’s credit rating to A- from BBB+, and that EUI has always had a DBRS credit rating of A (low).357 The Commission has also reviewed EUI’s credit risk premiums compared to FortisAlberta, FortisBC and Nova Scotia Power, as shown in Table 19. Given the close credit ratings and credit risk premiums, the Commission is persuaded that they are comparable.
354. The CCA submitted that Nova Scotia Power should be excluded as a comparator, due to the location and diversity of its business. However, the CCA raised EUI as a comparator. EPCOR argued that a substantial portion of EUI’s business is outside of western Canada and outside of electric distribution. Given this, and leaving aside credit risk ratings, it appears to the Commission that the CCA’s reasoning with respect to asset mix and business operations to remove Nova Scotia Power could equally be applied to EUI, whom the CCA suggested including. Similarly, the converse is true of EPCOR’s argument to exclude EUI when it is supportive of including Nova Scotia Power.
355. For all of these reasons, the Commission concludes that FortisAlberta, FortisBC, Nova Scotia Power and EUI are relevant comparators for EPCOR’s 2017 embedded cost-of-debt calculations. As such, the Commission directs EPCOR to recalculate its 2017 embedded cost of debt using the average of these companies’ credit risk premiums. As part of its compliance filing to this decision, the Commission also directs EPCOR to refile its recalculated 2017 WACC based on these revisions.
353 Decision 2010-505, paragraphs 173-179. 354 Exhibit 23571-X0200, CCA argument, PDF pages 30-33. 355 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF page 19. 356 Exhibit 23571-X0199, EPCOR rebuttal evidence, PDF page 19. 357 Exhibit 23571-X0147, EDTI-CCA-2018AUG24-026(f).
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356. As credit ratings, credit risk premiums, company assets and business operations change from time to time, the Commission directs EPCOR to provide its calculation of its embedded cost of debt in its next annual PBR filing.
8.2 Commission’s conclusions on Criterion 1 357. In Section 7 of this decision, based on the project assessment under Criterion 1, the Commission approved the need, scope, level, timing and the prudence of actual capital additions for each project or program that EPCOR included in the 2017 true-up, subject to some adjustments and Commission directions, and with the exception of the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project and the Vehicle Growth and Life Cycle Replacements Project. Because of these adjustments, the Commission cannot make a determination in this proceeding as to whether all of EPCOR’s programs or projects included in the 2017 true-up satisfy the project assessment requirement of Criterion 1.
358. For the same reason, and also because the Commission was unable to approve the 2017 actual cost of debt as part of WACC, the Commission cannot make a determination in this proceeding as to whether all of EPCOR’s programs or projects included in the 2017 true-up satisfy the accounting test requirement of Criterion 1.
359. For these reasons, the Commission directs EPCOR, in its compliance filing to this decision, to revise its accounting test for 2017, based on directions as set out in the previous sections of this decision, and to reassess whether the capital tracker projects or programs included in the 2017 true-up satisfy the accounting test requirement of Criterion 1.
9 Criterion 2 – ordinarily the project must be for replacement of existing capital assets or undertaking the project must be required by an external party
360. With respect to Criterion 2, the Commission clarified in Decision 2013-435 that, in addition to asset replacement projects and projects required by an external party, in principle, a growth-related project will satisfy the requirements of Criterion 2 where it can be demonstrated that customer contributions, together with incremental revenues allocated to the project on some reasonable basis, when added to the revenue provided under the I-X mechanism, are insufficient to offset the revenue requirement associated with the project in a PBR year.358 Certain projects proposed for capital tracker treatment that do not fall into any of the growth-related, asset replacement or external-party-related categories might also satisfy Criterion 2 in certain circumstances, as discussed in Section 3.2.4 of Decision 2013-435.359
361. As set out in Section 4 of this decision, for the purposes of the true-up of the 2017 capital tracker programs or projects for which the Commission undertook and approved the assessment against the Criterion 2 requirements in Decision 3100-D01-2015 or Decision 20407-D01-2016, there is also no need to undertake a reassessment of the project or program against the Criterion 2 requirements unless the driver for the project or program has changed. In the application, EPCOR confirmed that there are “no changes to the drivers of any of the previously
358 Decision 2013-435, paragraph 309. 359 Decision 2013-435, paragraph 314.
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approved capital tracker projects or programs,”360 and provided a table setting out the driver for each of the projects or programs included in the 2017 true-up, as set out in Table 21 below:361
Table 21. Applied-for 2017 capital tracker programs or projects and Criterion 2 requirements
Project name Criterion 2 project type Third-Party Driven Relocations External party driven/replacement Life Cycle Replacement and Extension of Underground Distribution Cable Replacement New 15-kV and 25-kV Circuit Additions Growth/external party driven New Underground Cable and Aerial Line Reconfigurations and Extensions to Growth/external party driven Meet Customer Growth Distribution Pole and Aerial Line Life Cycle Replacements Replacement Aerial and Underground Distribution Transformers – New Services and Life Growth/external party driven, also a Cycle Replacement portion of replacement Capitalized Underground System Damage Replacement New Underground and Aerial Service Connections for Commercial, Industrial, Growth/external party driven Multi-Family and Misc. Customers Underground Residential Distribution (URD) Servicing – Rebates, Growth/external party driven Acceptance Inspections & Terminations Capital Tools and Instrument Purchases Replacement/external party driven Poundmaker Feeders Growth/external party driven OMS/DMS Life Cycle Replacement Replacement Capitalized Aerial System Damage Replacement Underground Industrial Distribution (UID) Servicing – Rebates, Acceptance Growth/external party driven Inspections & Terminations Replacement of Faulted Distribution PILC Cables Replacement Neighbourhood Renewal Program Replacement Life Cycle Replacement of Network Transformers Replacement Life Cycle Replacement of PILC Cable Systems Replacement Replacement, and a portion of growth/ Customer Revenue Metering – Growth & Life Cycle Replacements external party driven Advanced Metering Infrastructure Replacement IT Hardware Life Cycle Replacements and Additions Replacement Service Centre Redevelopment and Life Cycle Redevelopment Capital Replacement Tracker Program Manhole Rebuilds and Life Cycle Replacement Program Replacement Vehicles – Growth and Life Cycle Replacements Growth/replacement
Commission findings 362. Consistent with the determinations in Section 4 of this decision, because the driver or drivers (e.g., replacement of existing assets, external party, growth) for each project or program included in EPCOR’s 2017 capital tracker true-up application have not changed since the Commission undertook and approved proposed capital tracker projects and programs against the Criterion 2 requirements in Decision 3100-D01-2015 and in Decision 20407-D01-2016, there is no need to undertake a reassessment of these programs or projects against the Criterion 2 requirements.
360 Exhibit 23571-X0002.01, application, paragraph 31. 361 Exhibit 23572-X0002.01, application, paragraph 31, Table 2.2.3-1.
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10 Criterion 3 – the project must have a material effect on the company’s finances
363. Section 8 of this decision addressed EPCOR’s accounting test, which determines whether all of the actual expenditures for a capital project are, or a portion is, outside the normal course of the company’s ongoing operations, as required to satisfy Criterion 1. This is established by demonstrating that the associated revenue provided under the I-X mechanism would not be sufficient to recover the entire revenue requirement associated with the prudent capital expenditures for the program or project proposed for capital tracker treatment.
364. In accordance with the Commission’s determinations in Decision 2013-435, the portion of the revenue requirement for a project or program proposed for capital tracker treatment that is not funded under the I-X mechanism in a PBR year, calculated as part of the accounting test, is then assessed against the two-tiered materiality test under Criterion 3. The first tier of the materiality threshold, a “four basis point threshold,” is applied at a project level, grouped in the manner approved by the Commission. The second tier of the materiality threshold, a “40 basis point threshold,” is applied to the aggregate revenue requirement proposed to be recovered by way of all capital trackers.362
365. In Decision 2013-435, the Commission calculated the four basis point threshold and the 40 basis point threshold based on the dollar value of EPCOR’s ROE in 2012. The Commission indicated that in subsequent PBR years, the four basis point threshold and the 40 basis point threshold are to be calculated by escalating the respective 2012 amounts by I-X.363
366. Further, in Decision 3100-D01-2015, the Commission determined that the calculation of the first and second tier materiality thresholds for purposes of the capital tracker true-up application for a given year should be based on the approved I-X index for that year and directed EPCOR to follow this approach in future capital tracker true-up applications.364
367. For the 2017 capital tracker true-up application, EPCOR used the 2017 four basis point threshold of $0.104 million and the 40 basis point threshold of $1.038 million,365 calculated by escalating the respective 2012 amounts by the approved 2013, 2014, 2015, 2016 and 2017 I-X index values. EPCOR then assessed each of the capital tracker projects included in the 2017 true- up application against the two-tiered materiality test, in accordance with the requirements set out in Decision 2013-435.366 EPCOR indicated that each 2017 capital tracker true-up project or program satisfies Criterion 3.367
Commission findings 368. For its 2017 true-up calculations, EPCOR used the first and second tier materiality thresholds approved in Decision 21430-D01-2016, based on the approved 2013, 2014, 2015, 2016 and 2017 I-X index values.
369. The Commission has reviewed EPCOR’s calculations, and is generally satisfied that EPCOR has interpreted and applied the Criterion 3 two-tiered materiality test properly for the
362 Decision 2013-435, paragraphs 382-385. 363 Decision 2013-435, paragraphs 378 and 384. 364 Decision 3100-D01-2015, paragraph 632. 365 Exhibit 23571-X0002.01, application, paragraph 94, Table 2.3.3-1. 366 Exhibit 23571-X0082, Schedule 2, Tab 4 “1st Tier Test.” 367 Exhibit 23571-X0002.01, application, paragraph 95.
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purposes of its 2017 capital tracker true-up application, based on the projects and assumptions included in the application. However, as discussed earlier in this section, the two-tiered materiality test under Criterion 3 is applied to the portion of the revenue requirement for a project or program proposed for capital tracker treatment that is not funded under the I-X mechanism in a PBR year, calculated as part of the accounting test. In Section 8.2, the Commission directed EPCOR, in its compliance filing to this decision, to revise its accounting test based on approved 2017 actual capital additions. Accordingly, because EPCOR’s accounting test for 2017 needs to be revised, the Commission cannot determine in this proceeding whether any of EPCOR’s programs or projects included in the 2017 true-up application satisfy the materiality test requirement of Criterion 3.
370. Given these findings, the Commission directs EPCOR, in its compliance filing to this decision, to reassess whether its programs or projects included in the 2017 true-up application satisfy the two-tiered materiality test requirement of Criterion 3. For this reassessment, EPCOR shall use the approved 2017 threshold amounts.
11 EPCOR’s compliance with Commission directions
371. In Decision 3100-D01-2015, Decision 20407-D01-2016, Decision 21592-D01-2017 and Decision 22672-D01-2018, the Commission issued a number of directions to EPCOR that were applicable to its future capital tracker applications. In Decision 3434-D01-2015 and Decision 3558-D01-2015, the Commission also provided clarifications on the capital tracker mechanism and issued a number of related directions to distribution utilities under PBR, including EPCOR.
372. EPCOR’s response to the Commission’s directions was provided in a table of concordance in Appendix A to the application.368
Commission findings 373. In previous sections of this decision, the Commission addressed EPCOR’s compliance with certain directions from Decision 3100-D01-2015, as well as Decision 3434-D01-2015 and Decision 3558-D01-2015. No party challenged EPCOR’s compliance with Commission directions.
374. The Commission has reviewed EPCOR’s responses to the directions of the Commission not specifically addressed in the previous sections of this decision and is satisfied that EPCOR has complied with these directions in the application.
12 2017 true-up application K factor calculations
375. In Decision 21430-D01-2016, the Commission approved the 2017 forecast K factor of $36.21 million, to be recovered from EPCOR’s customers on an interim basis.369 In Decision 23355-D02-2018, the Commission directed EPCOR to update its notional 2017 revenue requirement and 2018 base K-bar amounts to reflect the 2017 applied-for actual capital tracker costs in its 2019 annual PBR filing.370 As part of the 2017 capital tracker true-up application,
368 Exhibit 23571-X0003, Appendix A, Section A-5. 369 Decision 21430-D01-2016, paragraph 85. 370 Decision 23355-D02-2018, paragraph 41.
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EPCOR calculated its actual 2017 K factor to be $43.30 million,371 resulting in a proposed 2017 K factor true-up adjustment of $7.10 million to be collected from customers, as shown in Table 1 of this decision.
376. EPCOR indicated it would file its proposal to true up the final approved amount for its 2017 K factor adjustment, as part of its compliance filing to this decision.372
Commission findings 377. The Commission has reviewed EPCOR’s calculations and finds that EPCOR’s methodology to determine the 2017 K factor true-up amount is generally consistent with the requirements set out in Decision 2012-237 and Decision 2013-435. However, as set out in previous sections of this decision, while the Commission confirmed the prudence of actual capital additions associated with EPCOR’s programs or projects included in the 2017 capital tracker true-up application, these approvals were subject to some directions and require a compliance filing.
378. The Commission directs EPCOR to file its proposal to true up the difference between its applied-for 2017 capital tracker true-up costs, approved to be collected in Decision 23896-D01- 2018 (Errata),373 and the 2017 actual K factor as part of the compliance filing to this decision. The effective date and the duration of the proposed collection period for EPCOR’s proposal should be commensurate with the Commission’s process timelines set out in Bulletin 2015-09 and take into account the effect on customer bills.
13 Service quality and asset monitoring
379. The present 2017 capital tracker true-up application is EPCOR’s last annual capital tracker application filed under the 2013-2017 PBR plan.374 In Decision 20414-D01-2016 (Errata), setting out the parameters of the 2018-2022 PBR plans, the Commission discontinued the capital tracker mechanism in its current form. The Commission provided to distribution utilities two mechanisms by which to apply for supplemental capital funding. For Type 1 capital, the Commission approved a modified capital tracker mechanism with narrow eligibility criteria. For Type 2 capital, the Commission approved a K-bar mechanism that gives distribution utilities a predetermined amount of incremental capital funding for each year, based on a prescribed historical average of net capital additions made in prior years.
380. The Commission expressed its expectation in Decision 20414-D01-2016 (Errata) that the revised approach to capital funding will ensure that the vast majority of capital will be Type 2 capital managed under K-bar and thus subject to the superior incentive properties of PBR. The amount of incremental K-bar funding received for a year is not linked to any specific project. Under the K-bar mechanism, the utility is free to manage the incremental capital funding as it sees necessary, and can allocate K-bar funding among projects or to operational expenses in managing its business.
371 Exhibit 23571-X0003, Schedule 2, tab 3, 2017 K, line 136. 372 Exhibit 23571-X0002.01, application, paragraph 1226. 373 Decision 23896-D01-2018 (Errata): 2019 Annual Performance-Based Regulation Rate Adjustment Filing, Proceeding 23896, January 4, 2019, paragraphs 16 and 19. 374 EPCOR still has to file the compliance filing to this decision, as discussed in Section 8.2 of this decision.
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381. In Decision 2012-237, the Commission recognized that the adoption of a PBR plan creates incentives to lower costs by accomplishing improvements in productivity, but the Commission also recognized that lower costs can arise at the expense of reductions in service quality.375 In order to ensure that observed cost reductions were the result of productivity improvements and not reductions in service quality, the Commission emphasized in Decision 20414-D01-2016 (Errata) that there was an ongoing need for sound management of the distribution utilities’ physical assets to ensure the continued provision of safe and reliable service during the next generation PBR term and beyond.376
382. In Decision 22394-D01-2018, the Commission reiterated the need for sound management by the distribution utilities in carrying out their statutory obligation to provide safe and reliable service, in order to prevent a deterioration in service quality and reliability, given the greater managerial flexibility provided by the introduction of the K-bar mechanism.
383. The Commission’s view has not changed since the release of the referenced decisions. The Commission expects that the distribution utilities will manage their capital programs accordingly. To this end, the Commission in Decision 20414-D01-2016 (Errata) maintained the requirement to file performance metrics reporting through Rule 002, along with asset monitoring reporting over the 2018-2022 PBR term. The distribution utilities submitted asset management reports in 2017 and 2018, which stakeholders reviewed and discussed as part of the Rule 002 annual review meetings. The Commission informed the distribution utilities of the asset management reporting requirements for 2019 on December 10, 2018, by way of an email. The Commission will continue the consultation process in 2019 to finalize the reporting format. In addition to providing the Commission and stakeholders with continued monitoring of service quality and reliability, the Commission considers that these tools will support the long-term planning and replacement activities of the distribution utilities to maintain service quality.
384. The Commission also notes that the requirement for separate asset accounting set out in paragraph 863 of Decision 2012-237 continues to apply to the distribution utilities during the 2018-2022 PBR term:
863. For a company under PBR, the requirement to file the AUC Rule 005 schedules in both its annual PBR rate adjustment filing and a separate AUC Rule 005 application, does not exempt the company from its obligation to maintain detailed accounts in accordance with the acts, regulations, Commission rules, or Commission decisions applicable to the company. Therefore, unless otherwise directed or exempted by the Commission, the companies are directed to maintain the ability to file a complete set of minimum filing requirements (MFR) and general rate application (GRA) schedules with actual results for all years within the term of the company’s PBR plan. The companies are not required, however, to file a complete set of MFR and GRA schedules annually.377
375 Decision 2012-237, paragraph 864. 376 Decision 20414-D01-2016 (Errata), paragraph 260. 377 Decision 2012-237, paragraph 863.
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14 Order
385. It is hereby ordered that:
(1) EPCOR Distribution & Transmission Inc. is directed to file a compliance filing application in accordance with the directions contained within this decision on or before 45 days after the Commission has issued its decision on Module Two of Proceeding 23571.
Dated on April 12, 2019.
Alberta Utilities Commission
(original signed by)
Henry van Egteren Panel Chair
(original signed by)
Neil Jamieson Commission Member
(original signed by)
Joanne Phillips Commission Member
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2017 Performance-Based Regulation Capital Tracker True-Up Application – Module One EPCOR Distribution & Transmission Inc.
Appendix 1 – Proceeding participants
Name of organization (abbreviation) Company name of counsel or representative
EPCOR Distribution & Transmission Inc. (EPCOR or EDTI) Borden, Ladner Gervais LLP
Consumers’ Coalition of Alberta (CCA)
Office of the Utilities Consumer Advocate (UCA) Brownlee LLP
Alberta Utilities Commission
Commission panel H. van Egteren, Panel Chair N. Jamieson, Commission Member J. Phillips, Commission Member
Commission staff C. Wall (Commission counsel) R. Lucas A. Spurrell B. Edwards G. Bourque
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Appendix 2 – Summary of Commission directions
This section is provided for the convenience of readers. In the event of any difference between the directions in this section and those in the main body of the decision, the wording in the main body of the decision shall prevail.
1. The Commission finds that EPCOR has not provided persuasive evidence with respect to the scope, level and timing of the third project under the Vehicles – Growth and Life Cycle Replacement Program, (iii) the purchase of previously rented vehicles, to show that the purchase was prudent for 2017. Specifically, EPCOR did not demonstrate that the rental vehicle purchases could not have been undertaken previously as part of a prudent capital maintenance and replacement program. Accordingly, the Commission cannot extend capital tracker treatment to EPCOR’s actual 2017 costs associated with the purchase of previously rented vehicles and directs EPCOR to remove the $1.93 million in capital additions and recalculate the K factor associated with this project...... Paragraph 292 2. EPCOR’s request for capital tracker treatment for the Replacement of Aerial Ground Rods and Underground Distribution Equipment Ground Grids Project is denied. EPCOR is directed, in a compliance filing to this decision, to remove the $1.22 million in capital additions associated with this project from its calculation of its 2017 K factor...... Paragraph 317 3. For all of these reasons, the Commission concludes that FortisAlberta, FortisBC, Nova Scotia Power and EUI are relevant comparators for EPCOR’s 2017 embedded cost-of- debt calculations. As such, the Commission directs EPCOR to recalculate its 2017 embedded cost of debt using the average of these companies’ credit risk premiums. As part of its compliance filing to this decision, the Commission also directs EPCOR to refile its recalculated 2017 WACC based on these revisions...... Paragraph 355 4. As credit ratings, credit risk premiums, company assets and business operations change from time to time, the Commission directs EPCOR to provide its calculation of its embedded cost of debt in its next annual PBR filing...... Paragraph 356 5. For these reasons, the Commission directs EPCOR, in its compliance filing to this decision, to revise its accounting test for 2017, based on directions as set out in the previous sections of this decision, and to reassess whether the capital tracker projects or programs included in the 2017 true-up satisfy the accounting test requirement of Criterion 1...... Paragraph 359 6. Given these findings, the Commission directs EPCOR, in its compliance filing to this decision, to reassess whether its programs or projects included in the 2017 true-up application satisfy the two-tiered materiality test requirement of Criterion 3. For this reassessment, EPCOR shall use the approved 2017 threshold amounts...... Paragraph 370
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7. The Commission directs EPCOR to file its proposal to true up the difference between its applied-for 2017 capital tracker true-up costs, approved to be collected in Decision 23896-D01-2018 (Errata), and the 2017 actual K factor as part of the compliance filing to this decision. The effective date and the duration of the proposed collection period for EPCOR’s proposal should be commensurate with the Commission’s process timelines set out in Bulletin 2015-09 and take into account the effect on customer bills...... Paragraph 378 8. It is hereby ordered that: (1) EPCOR Distribution & Transmission Inc. is directed to file a compliance filing application in accordance with the directions contained within this decision on or before 45 days after the Commission has issued its decision on Module Two of Proceeding 23571...... Paragraph 385
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Appendix 3 – EPCOR’s prior capital tracker-related decisions
(return to text)
Decision Commission approvals and directions Decision reference Because the 2013 capital tracker proceeding leading to Decision 2013-435 had not yet been completed at the time the Commission established 2013 interim PBR rates in Decision 2013-072,1 the Commission approved, on an interim basis, a Decision 2013- Table 1, 2013 capital tracker placeholder (K factor) for EPCOR, equal to 0722 paragraph 41 60 per cent of the applied-for K factor amount. Accordingly, EPCOR was directed to include in its 2013 PBR rates, a K factor placeholder of $3.02 million on an interim basis. The Commission approved certain EPCOR projects for capital tracker treatment on a forecast basis, resulting in a 2013 Decision 2013- Paragraph K factor forecast amount of $4.87 million to be recovered from 4353 989 customers on an interim basis, pending future true-up proceedings. The Commission approved EPCOR’s application to collect the Decision 2014- Paragraphs 8 $1.85 million difference between the 60 per cent placeholder 1744 and 29 and the approved K factor forecast amount for 2013. Interim K factor placeholders were approved by the Commission for each of 2014, 2015 and 2016. The Commission approved on an interim basis, a K factor Decision 2013- Paragraph 58 placeholder for each of 2014, 2015 and 2016, totalling in the 4625 amount of $6.8 million to be included in EPCOR’s 2014 PBR rates. The Commission approved on an interim basis, a 2015 K factor Decision 2014- placeholder in the amount of $18.108 million equal to 90 per Paragraph 44 3466 cent of the proposed 2015 K factor.
1 Decision 2013-072: 2012 Performance-Based Regulation Compliance Filings, AltaGas Utilities Inc., ATCO Electric Ltd., ATCO Gas and Pipelines Ltd., EPCOR Distribution & Transmission Inc. and FortisAlberta Inc., Proceeding 2130, Application 1608826-1, March 4, 2013. 2 Decision 2013-072. 3 Decision 2013-435: Distribution Performance-Based Regulation 2013 Capital Tracker Applications, Proceeding 2131, Application 1608827-1, December 6, 2013. 4 Decision 2014-174: EPCOR Distribution & Transmission Inc., 2013 K Factor True-Up Rider, Proceeding 3026, Application 1610244-1, June 17, 2014. 5 Decision 2013-462: EPCOR Distribution & Transmission Inc., 2014 Annual PBR Rate Adjustment Filing, Proceeding 2823, Application 1609912-1, December 20, 2013. 6 Decision 2014-346: EPCOR Distribution & Transmission Inc., 2015 Annual PBR Rate Adjustment Filing, Proceeding 3403, Application 1610834-1, December 15, 2014.
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Decision Commission approvals and directions Decision reference The Commission approved a 2013 actual K factor of $4.31 million and the associated 2013 K factor true-up refund amount of $0.56 million. The Commission also approved the Decision 20210- Paragraph 39 2014 and 2015 forecast K factors of $8.83 million and D01-20157 $17.18 million, respectively, on an interim basis pending future true-up proceedings. The Commission approved EPCOR’s application to refund the $0.56 million difference between the 2013 K factor forecast approved in Decision 2013-435 and the 2013 actual K factor approved in Decision 20210-D01-2015. In addition, in that decision, the Commission approved EPCOR’s application to refund the $0.93 million difference between the 2015 K factor placeholder, approved on an interim basis in Decision 2014- 346, and the 2015 K factor forecast approved in Decision Decision 20559- Paragraphs 20210-D01-2015. Inclusive of carrying costs, the total D01-20158 10, 14 and 23 combined refund amount for 2013 and 2015 was $1.54 million. As also set out in Decision 20559-D01-2015, to avoid an unnecessary collection followed by an expected refund, EPCOR proposed to true up the difference between the 2014 K factor placeholder and the 2014 actual K factor amount, once the final true-up amount was approved by the Commission in Proceeding 20407. The Commission accepted this proposal. The Commission approved on an interim basis, a 2016 K factor Decision 20821- placeholder in the amount of $24.81 million equal to 90 per Paragraph 41 D01-20159 cent of the proposed 2016 K factor. The Commission approved a revised 2013 actual K factor of $4.29 million and a 2014 actual K factor of $6.85 million. The Commission also approved the 2016 and 2017 forecast Decision 21430- K factors of $24.01 million and $36.21 million, respectively, on Paragraph 85 D01-201610 an interim basis pending future true-up proceedings. The associated 2013, 2014 and 2016 K factor true-up refund amount of $0.05 million was also approved by the Commission. The Commission approved on an interim basis, a 2017 K factor Decision 21979- placeholder in the amount of $36.20 million to be included in D01-2016 Paragraph 31 EPCOR’s 2017 PBR rates on a forecast basis. (Errata)11
7 Decision 20210-D01-2015: EPCOR Distribution & Transmission Inc., 2013-2015 Capital Trackers Compliance Filing, Proceeding 20210, May 29, 2015. 8 Decision 20559-D01-2015: EPCOR Distribution & Transmission Inc., 2013 and 2015 K Factor True-Up Rider, Proceeding 20559, September 24, 2015. 9 Decision 20821-D01-2015: EPCOR Distribution & Transmission Inc., 2016 Annual Performance-Based Regulation Rate Adjustment Filing, Proceeding 20821, December 15, 2015. 10 Decision 21430-D01-2016: EPCOR Distribution & Transmission Inc., 2014 True-Up and 2016-2017 Forecast PBR Capital Trackers Compliance Filing, Proceeding 21430, July 12, 2016. 11 Decision 21979-D01-2016 (Errata): EPCOR Distribution & Transmission Inc., 2017 Annual Performance- Based Regulation Rate Adjustment Filing, Proceeding 21979, January 5, 2017.
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Decision Commission approvals and directions Decision reference The Commission approved a 2015 actual K factor of $14.36 million, resulting in a 2015 K factor true-up adjustment refund amount of $2.82 million, subject to applicable carrying Decision 22392- Paragraph 42 charges of negative $0.12 million; and directed EPCOR to D01-201712 include the true-up adjustment in its Rate Rider DJ effective April 1, 2017 to June 30, 2017. The Commission approved a 2016 actual K factor of $27.25 million, resulting in a 2016 K factor true-up adjustment charge of $3.23 million, subject to applicable carrying charges of Decision 23316- Paragraph 36 $0.19 million; and directed EPCOR to include the true-up D01-201813 adjustment in its Rate Rider DJ effective October 1, 2018 to December 31, 2018.
12 Decision 22392-D01-2017: EPCOR Distribution & Transmission Inc., Compliance Filing to Decision 21592- D01-2017 2015 Capital Tracker True-Up, Proceeding 22392, March 20, 2017. 13 Decision 23316-D01-2018: EPCOR Distribution & Transmission Inc., Compliance Filing to Decision 22672- D01-2018 2016 Capital Tracker True-Up, Proceeding 23316, April 18, 2018.
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