ATCO Electric Ltd. - Home Alberta Utilities Commission · Alberta Utilities Commission Decision 22742-D01-2019 ATCO Electric Ltd. 2018-2019 Transmission General Tariff Application

Decision 22742-D01-2019

ATCO Electric Ltd. 2018-2019 Transmission General Tariff Application July 4, 2019

Alberta Utilities Commission

Decision 22742-D01-2019

ATCO Electric Ltd.

2018-2019 Transmission General Tariff Application

Proceeding 22742

July 4, 2019

Published by the:


Eau Claire Tower

1400, 600 Third Avenue S.W.

Calgary, Alberta T2P 0G5

Telephone: 310-4AUC (310-4282 in Alberta)

1-833-511-4AUC (1-833-511-4282 outside Alberta)

Email: [email protected]

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.

Decision 22742-D01-2019 (July 4, 2019) i

Contents

1 Decision summary ................................................................................................................. 1

2 Introduction and background .............................................................................................. 2

3 Responses to previous Commission directions ................................................................... 7

4 Terms and conditions of service .......................................................................................... 8

5 Forecasting methodology and key assumptions ................................................................. 8 5.1 Manpower ...................................................................................................................... 8

5.1.1 Full-time equivalents ........................................................................................ 8

5.1.2 Vacancy rates .................................................................................................. 16 5.1.3 Severance costs ............................................................................................... 19

5.2 Compensation ............................................................................................................... 23 5.2.1 Labour escalation ............................................................................................ 23

5.2.1.1 In-scope escalation ............................................................................. 23 5.2.1.2 Out-of-scope escalation ..................................................................... 25

5.2.2 Variable pay program ..................................................................................... 31

5.2.2.1 Reserve for VPP ................................................................................ 31 5.2.2.2 Variable pay forecast ......................................................................... 35

5.2.2.3 Treatment of VPP reserve account balance ....................................... 40 5.3 Other escalators ............................................................................................................ 41

5.3.1 Contractor and other inflation ......................................................................... 41

5.3.1.1 Contractor inflation rate ..................................................................... 42

5.3.1.2 Other inflation rate ............................................................................. 42

6 Fuel costs .............................................................................................................................. 43

7 Operating costs .................................................................................................................... 44 7.1 Forecasting accuracy .................................................................................................... 45

7.1.1 USA 561 – Transmission Operations – Control Centre .................................. 46 7.1.2 USA 563 and 569 – Overhead Line Maintenance .......................................... 46 7.1.3 USA 566 – Miscellaneous Transmission Expense ......................................... 47 7.1.4 USA 567 – Annual Structure Payments.......................................................... 48 7.1.5 Vegetation management.................................................................................. 49

7.1.5.1 Reserve for vegetation management .................................................. 49

7.1.5.2 2018-2019 Forecast vegetation management costs (USA 571.1) ...... 50

7.1.6 USA 575 – IT Support .................................................................................... 51

8 Transmission depreciation ................................................................................................. 52 8.1 Deferral account for IFRS-related depreciation rate issues ......................................... 54 8.2 Fort McMurray wildfire ............................................................................................... 56

9 Income taxes ........................................................................................................................ 57 9.1 Income tax .................................................................................................................... 57

9.1.1 Income tax - general........................................................................................ 57 9.1.2 Allowance for funds used during construction ............................................... 62

9.2 Income tax deferral accounts ....................................................................................... 69

9.2.1 Deferral accounts AET is seeking to continue ................................................ 70

9.2.1.1 Statutory rates deferral account for income tax ................................. 70 9.2.1.2 Deduction of deferrals for income taxes ............................................ 70

9.2.2 Deferral accounts AET is seeking to discontinue ........................................... 71 9.2.2.1 Capital repair costs deferral account .................................................. 71 9.2.2.2 Income tax deductible capital costs deferral account ........................ 72

10 Taxes other than income tax .............................................................................................. 75

11 Rate base .............................................................................................................................. 77 11.1 Direct assigned capital projects .................................................................................... 78 11.2 Transmission capital maintenance ............................................................................... 79 11.3 General property and equipment .................................................................................. 83

11.4 Thickwood development project .................................................................................. 86 11.5 Kearl Line (line 9L101) relocation .............................................................................. 90 11.6 Direct assigned capital deferral account .................................................................... 103

11.7 Engineering, supervision and general costs ............................................................... 106 11.8 Construction work in progress refund ........................................................................ 107

12 Necessary working capital ................................................................................................ 115

13 Isolated generation operating costs ................................................................................. 117

14 Shared services and common group costs....................................................................... 119 14.1 Shared services ........................................................................................................... 119

14.2 Shared services - productivity factor ......................................................................... 122

14.3 Common group costs ................................................................................................. 124

15 Corporate administration and general ........................................................................... 128 15.1 Office Supplies and Expenses (USA 921) ................................................................. 128

15.2 IT G&A expense (USA 934)...................................................................................... 131 15.3 Allocation of costs to Alberta PowerLine .................................................................. 133

15.4 Allocation of head office rent costs ........................................................................... 138 15.5 Reserve for injuries and damages .............................................................................. 155

16 Financing and credit metrics ........................................................................................... 156 16.1 Credit metrics ............................................................................................................. 156 16.2 Cost of debt ................................................................................................................ 159

17 Revenue offsets and recoveries from affiliates ............................................................... 164

18 Order .................................................................................................................................. 171

Appendix 1 – Proceeding participants .................................................................................... 172

Appendix 2 – Oral hearing – registered appearances ........................................................... 173

Appendix 3 – Summary of rulings and procedural requests ................................................ 174

Appendix 4 – Summary of Commission directions addressed in application ..................... 176

Appendix 5 – Summary of Commission directions to be addressed in future applications

............................................................................................................................. 179

Appendix 6 – Transcript, Volume 2, 2019-01-22 - Ruling on CCA request to mark two

exhibits ............................................................................................................... 180

Appendix 7 – Summary of Commission directions ................................................................ 181

List of tables

Table 1. Comparison of revenue requirements for 2017-2019 .............................................. 4

Table 2. Forecast capital expenditures and additions for test period ................................... 5

Table 3. Summary of opening rate base additions from 2015-2017 GTA forecast.............. 5

Table 4. Summary of the process and schedule ...................................................................... 6

Table 5. AET FTE forecast - Original application June 16, 2017 ......................................... 9

Table 6. AET FTE forecast – Omissions and updates filing November 10, 2017 ................ 9

Table 7. AET FTE forecast – Application update September 4, 2018 ................................ 10

Table 8. Summary of forecast complement for 2015-2017 test period ............................... 14

Table 9. Summary of vacancy rates 2015-2017 ..................................................................... 17

Table 10. AET severance costs (application update) .............................................................. 19

Table 11. AET severance costs ................................................................................................. 19

Table 12. Labour inflation forecast 2018-2019 ....................................................................... 23

Table 13. Recent wage settlements in the Alberta utility market (per cent increase) ......... 24

Table 14. VPP reserve account balances ................................................................................. 32

Table 15. Variable pay program costs ..................................................................................... 35

Table 16. VPP payout percentages and average VPP payout percentage ............................ 38

Table 17. Forecast inflation rates – labour, contractors and other 2018-2019 .................... 41

Table 18. Actual/Forecast fuel costs ......................................................................................... 43

Table 19. Transmission direct operating costs ........................................................................ 44

Table 20. Direct O&M costs for USA 566 ............................................................................... 47



Table 23. AET historical and forecast depreciation expense 2015-2019 .............................. 53

Table 24. Summary of income tax expense ............................................................................. 57

Table 25. Statutory tax rates..................................................................................................... 58

Table 26. AET’s forecasting accuracy for taxable temporary differences and total federal

taxable income ........................................................................................................... 59

Table 27. Calculation of income tax using AET’s current methodology for treatment of

AFUDC, based on Mr. Hoshowski’s exchange with Commission counsel .......... 65

Table 28. Calculation of income tax if AFUDC was treated the same as other capital

project costs when the asset was put into service ................................................... 67

Table 29. Calculation of income tax if AFUDC deduction was taken in year incurred but

AFUDC not added to utility earnings before tax ................................................... 68

Table 30. 2014-2017 actual and 2018-2019 forecast capital repair costs .............................. 71

Table 31. AET – 2015-2019 taxes other than income tax ....................................................... 76

Table 32. TCM and isolated generation forecast expenditures and additions ..................... 80

Table 33. Snapshot of AET assets and renewal forecast ........................................................ 81

Table 34. Summary of transmission necessary working capital ......................................... 116

Table 35. Isolated operating costs 2015-2017 ........................................................................ 118

Table 36. CCA submission on approved versus actual isolated generation operating costs

................................................................................................................................... 118

Table 37. Shared services comparison ................................................................................... 120

Table 38. Office supplies and expenses .................................................................................. 128

Table 39. Changes in general-other costs included in USA 921 .......................................... 130

Table 40. IT G&A expense ...................................................................................................... 131

Table 41. Reconciliation of changes in USA 934 for 2017-2018 .......................................... 132

Table 42. Forecast head office rent ........................................................................................ 152

Table 43. Credit metrics scenarios with and without federal FIT ...................................... 156

Table 44. Credit metrics scenarios which include federal FIT ............................................ 157

Table 45. Credit metrics scenarios which exclude federal FIT ........................................... 157

Table 46. Forecast long-term debt issues during test period ............................................... 160

Table 47. Forecast 2018 long-term debt rate ......................................................................... 160

Table 48. Forecast 2019 long-term debt rate ......................................................................... 160

Table 49. AET 2019 forecast, 2018 actual debt issue and current 30-year bond rates ..... 161

Table 50. Revenue offset forecasts by component for test years ......................................... 164

Table 51. Historical comparison of forecast and actual affiliate revenues ......................... 167

Table 52. Historical comparison of overhead recovery rates for affiliate services ............ 169

Decision 22742-D01-2019 (July 4, 2019) 1


Calgary, Alberta

ATCO Electric Ltd. Decision 22742-D01-2019

2018-2019 Transmission General Tariff Application Proceeding 22742

1 Decision summary

1. This decision reflects the Alberta Utilities Commission’s determinations following its

review of the 2018-2019 transmission general tariff application (GTA) of ATCO Electric Ltd.

(AET). The Commission found that not all of the forecast revenue requirements for the 2018-

2019 test period were reasonable and, consequently, revised or denied them.

2. The AET forecasts the Commission did not accept include:

The level of full-time equivalents (FTEs)

2019 escalation (inflation) rates

2018 severance costs

Costs and allocations with respect to ATCO Park

Cost allocations concerning Alberta PowerLine Limited Partnership (Alberta PowerLine)

Costs with respect to the Variable Pay Program (VPP)

Certain operating and maintenance (O&M) costs

Head office allocation costs and method regarding Alberta PowerLine

The Commission did not approve AET’s request to treat TCM project number 50463 for

line 9L101 (Kearl line) as a system cost

3. The Commission deferred its findings related to the Fort McMurray wildfire. It will issue

its decision contemporaneously with Proceeding 21609 for ATCO Electric Ltd. – Distribution’s

(AED) Z factor application related to the Fort McMurray wildfire. As a result, it is necessary that

certain aspects of AET’s application remain outstanding as placeholder amounts until such time

that the Commission renders its decision on matters pertaining to the Fort McMurray wildfire.

These placeholders are enumerated further in Section 8.2 of this decision.

4. The Commission directed that AET maintain certain deferral accounts including:

right-of-way payments;

debenture rate;

income tax capital repair costs and deductible capital cost deferral accounts;

2018-2019 Transmission General Tariff Application ATCO Electric Ltd.

Decision 22742-D01-2019 (July 4, 2019) 2

taxes other than income; and

direct assigned capital.

5. The Commission did not agree with all changes AET requested to existing deferral

accounts.

6. The Commission also directed that the following reserve accounts be maintained by

AET: the reserve for injuries and damages (RID), VPP, vegetation management, and the rate

case. It did not agree with all changes AET requested to existing reserve accounts.

7. The Commission found that AET has complied with a number of the directions contained

in its 2015-2017 GTA decision (Decision 20272-D01-2016),1 and other related decisions, as

identified in Appendix 4 of this decision. The Commission approved AET’s continued use of its

terms and conditions of service, as filed.

8. The Commission made certain determinations on a placeholder basis that will be adjusted

in the compliance filing in this proceeding or in the next GTA. These placeholders are:

AET’s 2019 severance costs; and

how the costs and mechanics of the variable pay program (VPP) will be applied.

9. The Commission accepted AET’s forecasts of depreciation expense, capital additions on

direct assigned projects, capital maintenance projects, and general property, plant and equipment

projects. AET’s request to maintain its treatment of construction work in progress (CWIP) was

approved by the Commission.

10. The Commission ordered AET to submit a compliance filing with respect to its 2018-

2019 Transmission GTA by August 8, 2019, to reflect the findings and directions in this

decision.

2 Introduction and background

11. On June 16, 2017, AET filed a GTA with the Commission for each of the test years 2018

and 2019.

12. Subsequent to filing its initial application, AET filed updates, starting in June 2017 and

continuing into January 2019. Information on the updates is listed below:

November 10, 2017 – omissions and updates (O&U) filing which included updates on

capital, FTE employees, property taxes, inflation, O&M costs, long-term debt,

International Financial Reporting Standards (IFRS), terms and conditions, and directions

from Commission decisions issued after the filing of the original application.

Exhibit 22742-X0342.

1 Decision 20272-D01-2016: ATCO Electric Ltd., 2015-2017 Transmission General Tariff Application,

Proceeding 20272, August 22, 2016.


Decision 22742-D01-2019 (July 4, 2019) 3

November 14, 2017 – application update to reflect new or changed information provided

in round 1 information requests (IRs) and directions from Commission decisions issued

after the filing of the original application.2 Exhibit 22472-X0001.01.

June 25, 2018 – application update incorporating 2017 actual results from AET’s 2017

Rule 0053 report that was filed May 15, 2018.4

September 4, 2018 – revisions to various parts of the application, including the

withdrawal of AET's request to refund previously collected construction work in progress

(CWIP) in-rate-base balances; removal of the productivity factor; changes to the forecasts

for capital, O&M expenses, shared services, long-term debt, and isolated generation; and

directions from Commission decisions issued after the filing of the original application.5

September 6, 2018 – application update to reflect new or changed information provided

in round 2 IRs and directions from Commission decisions issued after the filing of the

original application.6

January 14, 2019 – application revisions provided in rebuttal evidence, including updates

to AET’s common group FTEs and the business case for the 9L101 Kearl Line

Relocation (Project 50463), and a comprehensive list of responses to all three rounds of

IRs to comply with a Commission direction.7

13. As part of its application and associated updates, AET ultimately sought the following:

Commission approval for revenue requirements of $691.7 million in 2018 and

$699.5 million in 2019.

AET rates, to be paid by the Alberta Electric System Operator (AESO) for the use of

AET’s facilities over the test period, based on AET’s approved forecast revenue

requirements.

The continued use of previously approved deferral and reserve accounts during the test

period for the following costs:

o defined benefit special payments

o flow-throughs

o income taxes relating to:

(i) statutory rates

(ii) deductions of deferrals for tax purposes

o directly assigned capital

o rate case reserve

o reserve for injuries and damages

o variable pay program reserve

2 Exhibit 22742-X0001.01, later replaced on September 6, 2018, by Exhibit 22742-X0001.02. 3 Rule 005: Annual Reporting Requirements of Financial and Operational Results. 4 Exhibit 22742-X0396. 5 Exhibit 22742-X0533. 6 Exhibit 22742-X0001.02, updated application. 7 Exhibit 22742-X0618, AET rebuttal evidence.


Decision 22742-D01-2019 (July 4, 2019) 4

o effects of IFRS

The discontinuance of the following previously approved deferral and reserve accounts

for the test period:

o right-of-way payments

o income taxes relating to:

(i) capital repair costs

(ii) deductible capital costs

o debenture rates

o vegetation management

Commission approval for the use of updated depreciation parameters supported by the

depreciation study prepared for AET by Concentric Advisors Ltd. (Concentric).

The continued use of federal future income taxes (FIT) for inclusion in revenue

requirements.

The continued use of placeholders during the test period for the following:

o common group costs

o IT common matters costs (based upon GTA IT volumes)

o defined benefit plan pension costs

o line insurance costs

Commission approval, under Section 27(1) of the Isolated Generating Units and

Customer Choice Regulation, for the replacement and addition of isolated generating

units.

14. The breakdown of the 2018 and 2019 revenue requirements are shown in the table below.

The revenue requirement increases show an annual increase of 2.7 per cent in 2018 and 1.1 per

cent in 2019.

Table 1. Comparison of revenue requirements for 2017-2019

Description 2017 actual Test period

2018 2019

($ million)

Revenues

Transmission tariffs 673.8 691.7 699.5

Deferral accounts (0.3) - -

Total Revenues 673.5 691.7 699.5

Costs

Fuel 6.9 7.1 7.9

Operating costs 170.4 155.7 153.2

Depreciation 148.4 191.5 195.1

Return on rate base 341.5 311.1 311.2

Income tax expense 38.1 34.4 40.3

Revenue offsets (32.0) (8.2) (8.1)

Total costs 673.5 691.7 699.5

Transmission tariffs 691.7 699.5

Revenue at existing rates 673.8 673.8


Decision 22742-D01-2019 (July 4, 2019) 5

Description 2017 actual Test period

2018 2019

($ million)

Increase 17.9 25.7

% cumulative increase 2.7% 3.8%

% annual increase 2.7% 1.1%

Source: Based on Exhibit 22742-X0002.04, Schedule 3-1 Revenues and Costs.

15. A summary of forecast capital expenditures and capital additions for the test period is as

follows:

Table 2. Forecast capital expenditures and additions for test period

2018 forecast 2019 forecast

Expenditures Additions Expenditures Additions

($ million)

Direct assigned - system 116.7 122.1 56.5 99.5

Direct assigned - customer 14.6 25.2 79.0 30.9

Capital maintenance 83.3 83.2 88.0 93.3

Telecommunication 15.6 20.7 16.1 16.4

SCADA/EMS 3.7 2.7 2.5 5.4

Isolated generation 7.1 6.7 7.1 8.6

Direct general property, plant and equipment (PP&E)

1.1 1.3 7.9 7.8

Buildings 2.4 2.8 1.8 1.8

Software 10.3 14.5 11.5 16.3

Net salvage (6.1) (4.0)

Total 254.8 273.2 270.4 276.2

Source: Exhibit 22742-X0002.04, Schedule 10-4 Transmission Capital Expenditures.

16. AET requested Commission approval of additional opening rate base additions of $37.5

million above the amounts approved in AET’s 2015-2017 General Tariff Application, as shown

below:

Table 3. Summary of opening rate base additions from 2015-2017 GTA forecast

Category

Approved 2015-2017 GTA forecast additions (incorporating R&V

Decision 22094-D01-20178)

2015-2017 actual additions

Variance in additions to rate base

($ million)

Transmission Capital Maintenance 302.2 322.2 20.0

General Property and Equipment 15.8 33.3 17.5

Total 318.0 355.5 37.5

Source: Information derived from Exhibit 22742-X0001.02, application, Table 1.6 – PDF page 15, paragraph 28.

17. The Commission assigned Proceeding 22742 to the application and provided notice of the

application to parties on the Commission’s eFiling System on June 20, 2017. Statements of intent

to participate (SIPs) were due on July 4, 2017.

8 Decision 22094-D01-2017: Application for Review of Decision 20272-D01-2016, ATCO Electric Ltd., 2015-

2017 Transmission General Tariff Application, August 22, 2016, Proceeding 22094, March 16, 2017.


Decision 22742-D01-2019 (July 4, 2019) 6

18. The Commission received SIPs from the following parties:

AltaLink Management Ltd. (AltaLink)

Office of the Utilities Consumer Advocate (UCA)

Consumers’ Coalition of Alberta (CCA)

Industrial Power Consumers Association of Alberta (IPCAA)

Alberta Direct Connect Consumers Association (ADC)

19. IPCAA, the CCA and the UCA actively participated in the proceeding. ADC and

AltaLink were not actively involved in testing the application. Parties that registered as

interveners for this proceeding are listed in Appendix 1 to this decision. Parties that participated

in the oral hearing are listed in Appendix 2 to this decision.

20. A summary of the main process steps is provided below:

Table 4. Summary of the process and schedule

Process step Deadline

Round 1 IRs to AET August 30, 2017

Round 1 IR responses from AET September 25, 2017

Responses to outstanding IRs (Part 1) from AET October 31, 2017

Responses to outstanding IRs (Part 2) from AET November 10, 2017

Filing of undertakings by parties that wished to receive AET

confidential information February 7, 2018

AET’s delivery of confidential information to parties that signed

undertakings February 12, 2018

Further and better responses to IRs from AET May 11, 2018

Filing of AET’s Rule 005 reporting May 15, 2018

Further and better responses to IRs from AET May 18, 2018

Round 2 IRs to AET June 8, 2018

Round 2 IR responses from AET June 25, 2018

Further and better responses to IRs from AET August 10, 2018

Round 3 IRs to AET October 5, 2018

Round 3 IR responses from AET November 2, 2018

Further and better responses to IRs from AET November 21, 2018

Intervener evidence December 7, 2018

IRs on intervener evidence December 21, 2018

IR responses from interveners on intervener evidence January 4, 2019

Rebuttal evidence from AET January 14, 2019

Oral hearing – commencement January 21, 2019

Oral hearing – conclusion (seven hearing days – one-week break from

January 28 to February 1) February 6, 2019

Argument March 15, 2019

Reply argument April 5, 2019


Decision 22742-D01-2019 (July 4, 2019) 7

21. Throughout the proceeding, the Commission issued several rulings and procedural

requests in response to motions brought by AET, the CCA and the UCA. A summary of the

rulings and procedural requests in the proceeding is provided in Appendix 3.

22. On January 22, 2019, the Commission issued an oral ruling denying the CCA’s request to

mark two aids to cross-examination-related exhibits on the record of this proceeding. The

Commission ruled on the test of admissibility of an aid to cross-examination. The full ruling

from the official transcripts is attached to this decision as Appendix 6.

23. The Commission considers that the record for this proceeding (22742) closed on April 5,

2019, the date for filing reply argument.

24. The Commission is a public body and, as such, unless otherwise directed, all documents

submitted to the Commission, as well as all decisions of the Commission, are publicly available.

The Commission granted confidential treatment to a portion of the evidence on the record of this

proceeding and held a portion of the proceeding in camera. This decision reflects the

Commission’s findings from all of the evidence on the record of this proceeding, including

evidence provided in the confidential portion of this proceeding.

25. In reaching the determinations throughout this decision, the Commission has considered

all relevant materials comprising the record of this proceeding, including the evidence and

arguments provided by each party. Accordingly, references in this decision to specific parts of

the record 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 Commission did not

consider all relevant portions of the records with respect to a particular matter.

26. This decision deals with the contentious cost items forecast in the application, updates

and any matters that the Commission has otherwise determined are required to be specifically

addressed. If a matter or request for approval included in AET’s application is not addressed in

the findings, that matter or request is approved for the purposes of this GTA decision.

3 Responses to previous Commission directions

27. In its application, AET responded to 9 directions issued in Decision 20272-D01-2016 in

respect of ATCO Electric Ltd.’s 2015-2017 transmission GTA. AET also responded to one

direction from Decision 21206-D01-2017 issued in respect of the ATCO Electric 2013 and 2014

transmission deferral accounts and annual filings, one direction from Decision 22860-D01-2018

regarding the AET 2015-2017 transmission GTA second compliance filing, and one direction

from Decision 22859-D01-2018 regarding the AET common group compliance filing. In the

current decision, the Commission has reviewed the record as it pertains to all outstanding

directions. Where the Commission has identified issues or concerns with AET’s responses to a

direction, the Commission has provided reasons for its specific findings. Where no specific

finding is provided, the Commission has determined that AET’s responses comply with the

directions given and that no further action is required.

28. Where the Commission has determined that AET has complied with a direction, it is set

out in Appendix 4 of this decision. The Commission is satisfied that AET has adequately

addressed and responded to the following directions:


Decision 22742-D01-2019 (July 4, 2019) 8

directions 47, 71, 73, 84, 97(1), 97(2) and Other Matter No. 9 from Decision

20272-D01-2016;

Direction 16 from Decision 21206-D01-2017;

Direction 1 from Decision 22860-D01-2018; and

Direction 1 from Decision 22859-D01-2018.

29. Directions 18, 21 and 27 from Decision 20272-D01-2016 remain outstanding and are

intended to be considered in a future depreciation study. They are listed in Appendix 5 and are

not addressed further in this decision.

4 Terms and conditions of service

30. AET provided a copy of the terms and conditions of service (T&Cs) under which it

operates, as Attachment 3.1 of its application.9

Commission findings

31. As there are no proposed changes to AET’s T&Cs, the Commission confirms AET’s

continued use of the T&Cs approved in Decision 22073-D01-2017.

5 Forecasting methodology and key assumptions

5.1 Manpower

5.1.1 Full-time equivalents

32. In its original application, filed June 16, 2017, AET provided its FTE forecast, which was

based on its activity-based forecasting methodology. AET stated that its forecast of FTEs

remained stable throughout the test period.10 A summary of AET’s originally filed FTE forecast

is provided below:

9 Exhibit 22742-X0001.02, updated application, Attachment 3.1, ATCO Electric Ltd. Transmission Terms and

Conditions, PDF pages 129-140. 10 Exhibit 22742-X0001.01, paragraphs 40-41.


Decision 22742-D01-2019 (July 4, 2019) 9

Table 5. AET FTE forecast - Original application June 16, 2017

Schedule Description 2015

Actuals 2016

Actuals 2017

Forecast

Test period

2018 2019

Schedule 5-5

2015-17 GTA complement - 2018-19 GTA forecast - total

918.0 741.8 736.3 729.0 725.0

Vacancy (negative) indicates higher complement than applied for

-67.7 2.9 18.4 18.3 18.2

Final adjusted complement 985.6 738.9 717.9 710.7 706.7

Vacancy rate -7.4% 0.4% 2.5% 2.5% 2.5%

Schedule 25-5


273.9 202.8 161.7 159.9 158.8


67.7 71.8 4.0 4.0 4.0


Vacancy rate 24.7% 35.4% 2.5% 2.5% 2.5%

Total AET


1,191.9 944.6 898.0 888.9 883.7


0.0 74.7 22.4 22.3 22.2

Final adjusted complement 1,191.9 869.9 875.5 866.6 861.5

Vacancy rate 0.0% 7.9% 2.5% 2.5% 2.5%

Final adjusted complement by area

Total O&M 343.2 272.2 273.3 280.1 278.3

Capital 848.7 597.7 602.2 586.5 583.2

1,191.9 869.9 875.5 866.6 861.5

Source: Exhibit 22742-X0002, 00-2018-2019 GTA schedules, Sch 5-5 and Sch 25-5.

33. In its O&U filing submitted November 10, 2017, AET adjusted its FTE forecast. AET

repeated that its FTE forecast was based on its activity-based forecasting methodology and that

its overall forecast of FTEs remained stable throughout the test period.11 The table below shows

the updated forecasts for 2018 and 2019:

Table 6. AET FTE forecast – Omissions and updates filing November 10, 2017


Actuals 2016

Actuals 2017

Forecast

Test period

2018 2019

Schedule 5-5


918.0 741.8 734.5 740.9 743.0


-67.7 -0.5 30.5 18.5 18.6


Vacancy rate -7.4% -0.1% 4.2% 2.5% 2.5%

Schedule 25-5


273.9 202.8 168.3 150.3 149.2


67.7 71.8 6.4 3.8 3.7

11 Exhibit 22742-X0001.01, paragraphs 39-40.


Decision 22742-D01-2019 (July 4, 2019) 10


Actuals 2016

Actuals 2017

Forecast

Test period

2018 2019


Vacancy rate 24.7% 35.4% 3.8% 2.5% 2.5%

Total AET


1,191.9 944.6 902.8 891.2 892.3


0.0 71.2 36.9 22.3 22.3


Vacancy rate 0.0% 7.5% 4.1% 2.5% 2.5%

Final adjusted complement area

Total O&M 343.2 275.6 260.2 277.8 280.5

Capital 848.7 597.7 605.6 591.2 589.5

1,191.9 873.4 865.9 869.0 869.9

Source: Exhibit 22742-X0002.01, 00-2018-2019 GTA schedules, Schedule 5-5 and Schedule 25-5.

34. In its application update filed September 4, 2018, AET stated that it, once again, needed

to revise its FTE forecast, this time as a result of changes to its O&M and capital program

forecasts:12

Table 7. AET FTE forecast – Application update September 4, 2018


Actuals 2016

Actuals 2017

Actuals

Test period

2018 2019

Schedule 5-5


918.0 741.8 750.3 654.1 613.8


-67.7 -0.5 95.9 16.4 15.3


Vacancy rate -7.4% -0.1% 12.8% 2.5% 2.5%

Schedule 25-5


273.9 202.8 203.3 144.7 136.0


67.7 71.8 56.8 3.6 3.4


Vacancy rate 24.7% 35.4% 27.9% 2.5% 2.5%

Total AET


1,191.9 944.6 953.6 798.8 749.8


0.0 71.2 152.7 20.0 18.7


Vacancy rate 0.0% 7.5% 16.0% 2.5% 2.5%

Final adjusted complement by area

Total O&M 343.2 275.6 245.8 221.8 215.6

Capital 848.7 597.7 555.1 557.1 515.5

12 Exhibit 22742-X0533, paragraph 23.


Decision 22742-D01-2019 (July 4, 2019) 11


Actuals 2016

Actuals 2017

Actuals

Test period

2018 2019

1,191.9 873.4 800.9 778.9 731.0

Source: Exhibit 22742-X0002.04, AET GTA Schedules, Schedule 5-5 and Schedule 25-5.

35. The CCA stated in its argument that the reason AET’s FTE forecast keeps changing is

that AET is no longer incurring costs on a common group basis and has consolidated specific

department staff into the shared services groups.13

36. The CCA referenced an exchange during the oral hearing in which Mr. Goguen,14 witness

for AET, admitted that AET tracks its labour costs but not its FTEs. The CCA asserted that

AET’s FTE forecast lacked certainty and did not reflect expected efficiencies from its shared

services model. The CCA added that statements by AET that it was starting to see “synergies and

best practices”15 and “hoping for more in the coming years,”16 led the CCA to presume further

efficiencies are likely, and justified disallowing a portion of AET’s forecast labour costs.17

37. AET responded that it “does not have a system to specifically track FTEs by cost centre

or uniform system of accounts (USA)… As explained, the difficulty with the Aids-to-Cross is

that AET could not easily go back in time and reallocate FTEs to functions that are now

performed under the shared services initiative.”18 However, AET submitted that this does not

mean that it cannot accurately forecast its FTE requirements for the test years, using its activity-

based forecasting methodology that has previously been approved by the Commission. Rather,

the challenge for AET is to go back in time and recreate what the FTE situation would

previously have been, so that a historical comparison can be made between (1) the number of

FTEs performing the functions now imbedded in the shared services initiative and (2) the cost

centres with which these FTEs, or portions thereof, had formerly been associated. AET added:

As explained by AET, the difficulty in tracking FTEs over time is because the persons

occupying these positions change over time or are charged to different cost centres at

different points in time. As confirmed, the challenge is not with respect to tracking the

costs, as the employees are tracked on a timesheet basis. Rather, the challenge is with

respect to tracking the FTEs over time and in particular, going back in time, and

attempting to create an FTE picture that can now accurately be compared to an FTE

picture under the shared services model. [footnotes removed]”

…

AET submits that any suggestion that it cannot track FTEs and, therefore, cannot develop

or manage its business is simply incorrect. The challenges faced by AET during this

proceeding relate mainly to an attempt to recreate a historical FTE picture, so that it can

be directly compared to a very different, current period optic, such as where the shared

services initiative now exists. In order to develop this information, AET would have to

employ an onerous and time consuming manual process to dissect each FTE into its

various components and then follow every single employee through the last several years

to understand each position they have held, every group they have worked for and how

13 Exhibit 22742-X0722, CCA final argument, paragraph 304. 14 Transcript, Volume 6, page 975, line 12 to page 979 line 15. 15 Transcript, Volume 6, page 979, lines 8-9. 16 Transcript, Volume 6, page 979, line 10. 17 Exhibit 22742-X0722, CCA final argument, paragraph 303-305. 18 Exhibit 22742-X0725, AET final argument, paragraphs 93.


Decision 22742-D01-2019 (July 4, 2019) 12

their allocations have changed over time, on an actual and/or forecast basis over multiple

years. As noted, AET simply does not have the tools to support such a process.19

[footnotes removed]

38. In its reply argument, the CCA stated that AET’s argument was confusing and surprising

and should be afforded no weight by the Commission. The CCA offered as an example, that

while AET said it does not have a system to track FTEs by cost centre or USA, it could still

accurately forecast its FTE requirements for the test years. The CCA argued that AET could not

reasonably be certain of its future resource requirements if it does not track its historical resource

requirements.20

Commission findings

39. In its argument, AET confirmed that while it does track labour costs, as employees are

tracked on a timesheet basis, its challenge lies in tracking FTEs over time and, especially, in

trying to recreate an FTE picture from the past that can be compared to an FTE picture under the

current shared services model.

40. At the oral hearing, Mr. Hoshowski, witness for AET, explained how AET tracks its costs

by FTE and cost centre under the new shared services initiative:

So with the implementation of the shared-services initiative, there have been new cost centres

created which pulls together all of the people that have been pulled out of the respective

companies to form these functional groups. So going back in time, under ATCO Electric for those

functional groups that became shared services, those individuals would have resided previously

within a variety of different ATCO Electric cost centres.21

41. Mr. Hoshowski also pointed to the difficulty in replicating FTEs by functions under the

shared services model for 2018 and 2019, and “rewinding the clock back to the 2015, 2016 and

2017 periods [to determine] what the equivalent of those same costs based on the services

provided”22 would represent. He confirmed that he could not provide 100 per cent assurance that

the costs are identical but, rather, that any comparison would be on a best efforts basis.23

42. Additional testimony from Mr. Bothwell, witness for AET, addressed the difficulty that

AET has in tracking FTEs through the various functions or cost centres FTEs occupy at different

times within the company. Mr. Bothwell stated that AET’s systems are not set up to track

individual FTEs. Instead, they aggregate FTE positions by cost centres. As such, it is not

possible for AET to take FTEs that were formerly part of functional groups in separate ATCO

companies and reconstruct or reconstitute them for purposes of comparison in the new shared

services functions they now occupy.

43. Mr. Bothwell provided further testimony on how AET’s forecasts are derived, as follows:

… we track the positions and the cost centres. They – the FTEs all add up. It's when you

asked me to tie the position in 2017 to the way it was forecast for 2017, which is a

forecast we provided in 2015. And then on top of that we do org changes in the actuals

19 Exhibit 22742-X0725, AET final argument, paragraphs 94 and 98. 20 Exhibit 22742-X0726, CCA reply argument, paragraph 37. 21 Transcript, Volume 6, page 973, lines 7-15. 22 Transcript, Volume 6, page 983, lines 24-25 and page 984 line 1. 23 Transcript, Volume 6, page 985, lines 2-12.


Decision 22742-D01-2019 (July 4, 2019) 13

during that same period of time. That's when it starts getting – you know, that 1.0 total

that makes up one full person's FTE, that's where it ends up in five, six, seven different

lines and in different forecasts. We might have forecast it in this cost centre for these

years, but the actual might be in a totally different cost centre, depending on how we

organize our structure.24

… We can track it, but it is -- for the FTE-level information, because we don't have an

Oracle system that does FTEs for us or some other system that accounts for FTEs for us,

it is a purely manual process. And the need to -- in hindsight, the need to track people's

names to the positions to the day they -- it's not that we don't have all this information, we

just don't have this information in a system that allows us to just spit out the simple

answer whereas our accounting system can because it doesn't worry about who -- what

the person's name was that was in that position.25

44. As demonstrated in the testimony above, AET cannot provide historical comparisons of

FTEs, and was not able to validate that the historical costs26 were comparable, in part, because of

the difficulty in directly tracking these FTEs and associated costs by cost centre.

45. In Decision 22859-D01-2018,27 AET’s common group compliance filing, the

Commission set out what it expected of AET when providing comparative figures in connection

with organizational structure changes such as the common group. AET provided the following

explanation in the common group compliance filing proceeding, as noted at paragraph 44 of the

decision:

44. In response to the IR, ATCO Electric - Transmission stated:

…

AET would like to note that the overall number of FTE’s in the Common Group

Proceeding are less than the FTE’s established in the 2015-2017 GTA 2nd

Compliance filing Schedule 25-5. Given that the original placeholder included in …

AET’s 2015-2017 GTA application was developed specifically to support AET

functions, and the Common Group forecast was prepared based on the allocation of a

wider group of common ATCO Electric employees, a comparison cannot be done on

an individual FTE basis between the two applications. [footnote removed]

46. In paragraphs 45 to 49 of that decision, the Commission found AET’s IR response that it

cannot compare and explain the differences between what was approved in its 2015-2017 GTA

and the Common Group forecast was not credible. The Commission expected that at least some

form of analysis would have been undertaken to reconcile the forecast common group costs with

the placeholders approved in the 2015-2017 GTA second compliance filing. The Commission

found that AET had not provided sufficient evidence to support a finding that the requested FTEs

and dollar amounts were reasonably justified. AET was directed, on a go-forward basis, to

provide all cost-information for every ATCO affiliate, comprising the total costs and supporting

detail that substantiate and justify the costs allocated to, or from, AET’s transmission function.

24 Transcript, Volume 6, page 968, lines 12-25. 25 Transcript, Volume 6, page 969, line 25 to page 970, line 11. 26 Exhibit 22742-X0608. 27 Decision 22859-D01-2018: ATCO Electric Ltd. Transmission Common Group Compliance Filing,

Proceeding 22859, March 20, 2018.


Decision 22742-D01-2019 (July 4, 2019) 14

47. Similar to the Commission’s findings in Decision 22859-D01-2018, the Commission is

concerned with AET’s ability to properly account for its allocation of costs for the common

group and, as supported by the testimony of the AET witnesses in the oral hearing, for shared

services as well. The Commission finds that the level of detail supporting the FTEs and

associated costs that may at one time have resided in AET only, or as part of the common group,

but may now be associated in whole or in part with the shared services group, is limited.

48. As confirmed by AET, it derives its FTE requirements for the test period years using the

Commission's approved activity-based forecasting methodology. In past GTAs, the Commission

reviewed AET’s “activity-based” FTE forecasting accuracy. For example, in its 2015-2017 GTA,

AET sought approval of the following forecast FTE levels:28

Table 8. Summary of forecast complement for 2015-2017 test period

Test period

Description 2015 2016 2017

Schedule of transmission manpower (FTEs) - Schedule 5-5(1)

Complement - 2015-2017 GTA forecast - permanent 944.6 868.6 890.4

Complement - 2015-2017 GTA forecast - temporary 32.6 31.4 30.5

Complement - 2015-2017 GTA forecast - total 977.2 900 920.5(3)

Schedule of corporate manpower (FTEs) - Schedule 25-5(1)

Complement - 2015-2017 GTA forecast - permanent 276.8 254.1 255.3


GTA complement - 2015-2017 GTA forecast - total 282 260 261

Schedule of total company complement

Complement - 2015-2017 GTA forecast - permanent 1,221.40 1,122.70 1,145.70


Complement - 2015-2017 GTA forecast - total(2) 1,259.20 1,160.00 1,181.50

Source: (1)Proceeding 20272, Exhibit 20272-X1101, schedules 5-5 and 25-5. (2)Proceeding 20272, Exhibit 20272-X1069. (3)The Commission observes ATCO Electric has hard-coded this value into the referenced exhibits.

49. AET’s updated 2015-2017 GTA forecast was submitted on February 23, 2016. During

the course of that proceeding, AET provided a headcount of 941 people as of the end of

December 2015.

50. In Decision 20272-D01-2016, the Commission identified concerns about workforce

reductions in AET's 2015 forecasts of its 2016 FTEs, as follows:29

The Commission finds that ATCO Electric’s forecasted FTE requirements for 2016 are

not sufficiently justified in the wake of its 2015 workforce reductions, notwithstanding

the fact that ATCO Electric stated that it is properly staffed based on its assessment of the

newly anticipated base level of work to be completed. The Commission approves only

28 Decision 20272-D01-2016, Table 3. Summary of forecast complement for test period. 29 Decision 20272-D01-2016, paragraph 83.


Decision 22742-D01-2019 (July 4, 2019) 15

the following requested FTE additions for 2016 that are required to complete work

related to cyber security and Alberta Reliability Standards as set by the AESO.

51. In Decision 20272-D01-2016, the Commission approved an additional 3.5 FTEs in 2016,

which resulted in a total of 944.6 FTEs being allowed for 2016 (as shown in Table 5 above). The

variance between AET’s 2015-2017 applied-for GTA FTE forecast and the approved FTE

amount was 215.4 FTEs30 notwithstanding that most of the 337 positions terminated were

eliminated in the last quarter of 2015.31 In its 2015-2017 GTA argument, AET developed its FTE

requirements using the same “activity-based” budgeting approach as filed in this proceeding.32

52. In its O&U filing, AET provided an FTE forecast of 865.9 FTEs for 2017 (Table 6

above). As shown in the application update (Table 7 above), the 2017 actual total for FTEs was

800.9. The difference between these two application updates is 65 FTEs33 or eight per cent. In the

Commission’s view, this 2017 variance further demonstrates the inability of AET to adequately

forecast its FTEs for shared services, due to the uncertainties and technical challenges involved.

53. For the above reasons, the Commission finds that AET has failed to justify its requested

FTEs and associated dollar amounts in the test years. Based on the past FTE forecasts noted

above and the inability of AET to accurately track FTEs by cost centre through various

organizational changes, including the new shared services initiative, the Commission cannot

reasonably rely on the FTE forecasts filed by AET. The Commission, therefore, directs AET to

use its 2018 actual FTEs as the approved FTE complement for 2018. The 2018 FTEs are

approved as the opening 2019 FTE complement. The Commission notes that the direction for

2018 is consistent with AET’s Rule 005 reporting, which reflected 716.1 FTEs in 2018.34

54. For the purposes of this decision and the compliance filing to follow, the Commission

directs AET not to offset the impacts of the reduction to capital FTEs with an increase in

contractor costs.

55. In Decision 22860-D01-2017,35 the Commission stated the following:

25. It appears to the Commission that the average base salary (total labour dollar per

FTE) method used by ATCO Electric to adjust O&M labour dollars, as a result of

changes in O&M FTEs, differs from how ATCO Electric may be forecasting labour

dollars for O&M FTEs in its GTA. As shown in Table 3, the amounts for labour dollar

per O&M FTE and total labour dollar per FTE are not the same. Therefore, to ensure that

neither ATCO Electric nor its customers are unjustly advantaged or disadvantaged by any

variance between the forecasted labour dollar for an O&M FTE and the use of the

average base salary when O&M FTE adjustments are required, ATCO Electric is directed

in all future applications to use the amounts included in its GTA forecast for each FTE

30 Calculated as: 1,160 FTEs – 944.6 FTEs. 31 Exhibit 20272-X0735, AET-AUC-2015DEC30-012(b). 32 Exhibit 20272-X1298, ATCO Electric argument, paragraph 59. 33 Calculated as: 865.9 FTEs – 800.9 FTEs. 34 ATCO Electric - Transmission 2018 Rule 005: Annual Reporting Requirements of Financial and Operational

Results, Schedule 8. 35 Decision 22860-D01-2017: ATCO Electric Ltd. 2015-2017 Transmission General Tariff Application Second

Compliance Filing, Proceeding 22860, November 21, 2017.


Decision 22742-D01-2019 (July 4, 2019) 16

position when calculating the dollar impacts to FTE adjustments, unless specifically

directed otherwise by the Commission.36

56. Given that the Commission’s direction to reduce AET’s FTE forecast in 2019 is not a

reduction to specific identifiable positions, AET is directed to calculate the impact of its O&M

FTE reductions using the average O&M salary per FTE and its capital FTE reductions using the

average capital salary per FTE.

57. In Decision 20272-D01-2016, the Commission found that the mid-year convention

should apply to the removal of an FTE in the year of its forecast removal if the utility is not

expecting to fill the position through promotion or an external hire going forward. This treatment

shall continue to apply regardless of the underlying reason for removal.37

58. In its compliance filing to this decision, AET is directed to confirm, for the positions it

has forecast to eliminate in 2019, that they have been removed in accordance with the findings

and directions in this section, using the mid-year convention.

5.1.2 Vacancy rates

59. The vacancy rate represents a ratio of the estimated number of vacant FTE positions to

the total number of approved FTE positions for a given period, and is used to reduce the forecast

labour costs to reflect that a certain number of positions will, on average, be vacant in the

forecast period.38

60. In its application, AET proposed that a 2.5 per cent vacancy rate be applied to its forecast

labour complement (also known as full-time equivalents or FTEs) for each of 2018 and 2019. In

deriving its vacancy rate, AET stated that it had assumed a gradual recovery of the Alberta

market, which is consistent with lower levels of staff turnovers in 2016.39

61. In its evidence, Bema Enterprises Ltd. (Bema)40 stated that Alberta is going though a

period of uncertainty, as demonstrated by the Alberta Government reducing its growth forecast

from prior estimates for 2018 and 2019. Bema acknowledged that these revised growth estimates

could support a lower turnover rate, and consequently a lower vacancy rate because there may be

fewer employment options in the marketplace. However, given AET’s history of workforce

reductions, Bema submitted that it should be expected that additional vacancies will occur as

AET continues to “look for efficiencies in shared services and other areas.”41

62. Bema observed that the vacancy rate for administrative and general employees in

Schedule 25-5 of the application was 35.4 per cent in 2016, while the vacancy rate in operations

and maintenance Schedule 5-5 was -0.1 per cent in 2016, neither of which Bema considered

36 Decision 22860-D01-2017, paragraph 25. 37 Decision 20272-D01-2016, paragraph 101. 38 Decision 3539-D01-2015: EPCOR Distribution & Transmission Inc. 2015-2017 Transmission Facility Owner

Tariff Proceeding 3539, October 21, 2015, paragraph 148. 39 Exhibit 22742-X0001.02, updated application, paragraph 52. 40 The CCA retained Bema as its consultant for this proceeding. Bema submitted evidence on behalf of the CCA

during this proceeding. In this decision, when the Commission refers to the CCA, the reference is to the CCA

itself or to its consultant, Bema, as may be applicable. 41 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 462.


Decision 22742-D01-2019 (July 4, 2019) 17

consistent with the 2.5 per cent for the test years.42 Bema provided a summary of AET’s actual

vacancy rate for the period covering AET’s prior GTA period of 2015-2017, as follows:

Table 9. Summary of vacancy rates 2015-2017

2015 2016 2017

(%)

Operations and maintenance (Schedule 5-5) -7.4 -0.1 12.8

Administrative and general (Schedule 25-5) 24.7 35.4 27.9

Total 0.0 7.5 16.0

Source: Exhibit 22742-X0592, CCA - Evidence of Bema, paragraph 463.

63. Bema suggested that a more practical vacancy rate should reflect historical results. Using

the historical rates and applying its own judgment, Bema recommended that the Commission

approve a vacancy rate of five per cent for operations and maintenance staff and 10 per cent for

administration and general staff, for each of 2018 and 2019.43

64. In rebuttal evidence, AET stated that Bema’s recommended vacancy rates for 2018 and

2019, based on adjusted 2015-2017 vacancy rates, is flawed. AET submitted that its forecast

vacancy rate of 2.5 per cent, which is lower than its historical vacancy rates, is reasonable in

2018 and 2019, for the following reasons:

Material changes in the organizational structure and the significant emphasis on

increased efficiencies and cost reduction initiatives across the organization in 2016-

2017 have rendered actual vacancy rates for this period both irrelevant and unreliable

for forecasting future years.

Material workforce reductions in 2018 to right-size the workforce based on the 2018-

2019 economic outlook and to account for the significant efficiencies achieved in

2016-2017 and forecast to be achieved in 2018-2019 have already been fully

incorporated into the total gross forecast complement in the September 2018

application update, to which the 2.5% vacancy rate is applied.

The stabilization of AET’s workforce through the absence of large-scale changes,

including restructuring and workforce reductions, in combination with increased

focus on employee engagement, communication and fair market compensation.44

65. The CCA requested that the Commission discount AET’s statement that its 2018

workforce reductions have already been fully incorporated into the most recent application

update in considering AET’s forecast vacancy rate. Bema pointed out that AET made much the

same argument in the 2015-2017 GTA, specifically, that the 2015 workforce reductions would

result in lower vacancies in 2016 and 2017. Yet, as Table 9 demonstrates, the opposite occurred.

According to the CCA, the 2018 and 2019 vacancy rates should be considered conservative, as

they are generally lower than the actual vacancy rates achieved in 2016 and 2017. The CCA

urged the Commission to approve Bema’s recommended five per cent vacancy rate for

42 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 461. 43 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 474-475. 44 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 115.


Decision 22742-D01-2019 (July 4, 2019) 18

operations and maintenance staff and 10 per cent vacancy rate for administration and general

staff for each of 2018 and 2019.45

66. AET argued that it does not expect the 2016 and 2017 vacancy rates to be indicative of

the vacancy rates it will experience in 2018 and 2019, and further argued that Bema’s

recommended vacancy rate of five per cent for operations and maintenance and 10 per cent for

administrative and general staff is arbitrary and based on the “judgment”46 of Bema’s

Mr. Madsen.

Commission findings

67. In its evidence, Bema stated that a vacancy rate should reflect historical results. In

coming to its recommended vacancy rate of five per cent for operations and maintenance (O&M)

staff and 10 per cent for administration and general (A&G) staff, for 2018 and 2019, Bema used

the historical vacancy percentages from 2016 and 2017 as a guide and then applied its own

judgment.

68. However, in Decision 20272-D01-2016, the Commission recognized the economic

environment in setting vacancy rates:

The Commission finds it reasonable to expect a lower level of employee turnover in the

current economic environment and, therefore, accepts ATCO Electric’s argument in

support of a 2.5 per cent vacancy rate for 2016 and 2017. ATCO Electric’s vacancy rates

are approved as filed.47

69. Further, as argued by AET, historical vacancy rates include the reduction in FTEs

resulting from workforce reductions. By relying on historical vacancy rates in developing its

recommended vacancy rates, Bema has, in effect, built further workforce reductions into its

recommendations. Bema’s recommendations also reflect the expectation that additional

vacancies will occur as a result of AET looking “for efficiencies from its shared services and

other areas.”48

70. The Commission does not agree with the CCA’s proposal to superimpose historical

vacancy rates on forecast FTEs, as doing so would incorporate further workforce reductions. The

vacancy rate should not be used as the mechanism that adjusts for FTEs and labour forecast

dollars approved in the test period, when those adjustments are made separately in the section

dealing with FTE forecasts. The Commission finds that any FTE or position reductions should be

addressed through adjustments to staffing level requirements, that is, FTEs, in those test periods.

71. As discussed in paragraph 53 above, the Commission directed AET to use 2018 actual

FTEs as its 2018 FTE approved complement. The use of 2018 actuals reflects zero vacant FTEs

for 2018. Accordingly, a vacancy rate of zero per cent for 2018 is approved.

72. Consistent with Decision 20272-D01-2016, and AET’s explanation in its rebuttal

evidence of the factors affecting vacancy rates, the Commission finds it reasonable to expect a

lower level of employee turnover in the current economic environment and the stabilization of

45 Exhibit 22742-X0722, CCA final argument, paragraphs 446-449. 46 Exhibit 22742-X0725, AET final argument, paragraph 88. 47 Decision 20272-D01-2016, paragraph 108. 48 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 462.


Decision 22742-D01-2019 (July 4, 2019) 19

AET’s workforce in the test year. The Commission agrees with AET that these factors support a

2.5 per cent forecast vacancy rate in 2019. AET’s vacancy rate of 2.5 per cent for 2019 is

approved, as filed.

5.1.3 Severance costs

73. In its September 4, 2018 update, AET explained that it had identified efficiencies in the

manner it executes O&M work activities, and had reduced the volume of capital project work.

These two work measures resulted in reductions to AET’s workforce that, in turn, resulted in

severance costs that AET is now seeking to recover in the 2018-2019 test period. AET submitted

that the workforce reductions will result in lower costs for ratepayers in the current and future

test periods.49

74. AET stated that its workforce reductions result in an increase to revenue requirement of

$7.2 million in 2018 relative to the forecasts included in its O&U filing. AET produced the

following table showing that the total increase in severance costs in the test period was

$7.6 million in 2018, and $0.3 million in 2019.

Table 10. AET severance costs (application update)

Test Period 2018

Actuals 2019

Update

($ million)

O&U (Exhibit 22742-X0002.01, Schedule 25-5, USA 921) 0.4 0.3

Application Update (Exhibit 22742-X0002.04, Schedule 25-5, USA 921) 7.6 0.3

Total Increase/(Decrease) 7.2 0.0

Exhibit 22742-X0533, AET 2018-2019 GTA - September 4, 2018, Update, paragraph 36, Table 10: Severance.

75. In response to an undertaking provided to Commission counsel during the oral hearing,

AET provided a revised forecast of its severance costs, as follows:

Table 11. AET severance costs

Position(s) Amount

($ million)

2018 paid #1 to #129 and #132 6.0

2019 paid #130, #131 and #133 0.1

2019 forecast #134 to #155 1.5

Total 2019 1.6

Total severance #1 to #155 7.6

Source: Exhibit 22742-X0700, Undertaking 54.

76. In its evidence, Bema stated that “where an AET employee is terminated and that

employee has provided services to an affiliate, then the affiliate should bear a portion of the cost

of the severance for that employee.”50 Bema noted that AET allocated severance costs based on

49 Exhibit 22742-X0533, AET 2018-2019 GTA - September 4, 2018 Update, paragraphs 21-22. 50 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 478.


Decision 22742-D01-2019 (July 4, 2019) 20

common group allocations, but suggested that the allocations used may not be the final allocators

approved by the Commission. Bema therefore recommended that AET be directed to use the

final approved common group allocators to allocate severance costs for all common group

employees severed.51

77. Based on its review of AET’s severed positions that are not part of the allocated common

group employees, Bema determined that in each year there were additional charges to affiliates

beyond the charges included in the common groups. Bema stated that AET’s severed workers

provided affiliates with approximately 13.1 per cent of their labour time based on a three-year

average between 2014 and 2017. Therefore, 13.1 per cent of the severance costs should be

allocated to affiliates rather than AET. Based on the results of its analysis, Bema recommended

that the Commission deny $1.0 million of AET’s requested $7.9 million in severance costs.52

78. AET pointed out that Bema had incorrectly considered AED to be an affiliate in the

calculation of severance costs. This was an error because AED has an affiliate exemption. In its

rebuttal evidence, AET provided revised calculations to reflect the affiliate exemption and

removed AED in calculating the percentages of total labour provided to affiliates. Based on

AET’s calculations, the three-year average of severance costs would be 2.12 per cent, and not the

13.1 per cent calculated by Bema. Taking the 2.12 per cent figure for severance costs attributable

to affiliates results in an allocation of severance costs to affiliates of $0.2 million in 2018. AET

stated that its use of an affiliate overhead rate of 23 per cent, rather than its calculated overhead

rate of 21 per cent, adequately covers its forecast severance costs related to affiliate work of

$0.2 million in 2018 and a forecast of zero in 2019.53

79. In response to AET, the CCA noted the following exemption granted in Decision 2004-

054 by the Alberta Energy and Utilities Board (board), the Commission’s predecessor:

(1) In respect of transactions between ATCO Electric Transmission and ATCO

Electric Distribution, exemption is granted from the requirements set out in Section 3.3.1,

Shared Use of Employees, of the ATCO Group Inter-Affiliate Group Code of Conduct

solely for the purposes and in the manner described in the Application and approved by

this Decision.54

80. The CCA concluded on the basis of the above decision that AET’s claim that AED is not

an affiliate for the purposes of calculating severance cost adjustments should be rejected. The

CCA submitted that Bema’s recommended disallowance of $1.0 million of AET’s applied-for

severance costs remained valid.

81. AET argued in reply that if additional severance were to be allocated to AED based on

Bema’s evidence and the CCA’s argument, it would result in double counting. AET submitted

that its proposed method for allocating severance costs is transparent and reasonable, and that

severance costs for all other affiliates is recovered through the affiliate overhead rate.55

51 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 478-481. 52 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 482-488. 53 Exhibit 22742-X0618, AET rebuttal evidence, PDF pages 118-120 54 Decision 2004-054: ATCO Electric Ltd., Code of Conduct Exemptions, Application 1317784-1, July 28, 2004,

page 11. 55 Exhibit 22742-X0727, AET reply argument, paragraphs 98-101.


Decision 22742-D01-2019 (July 4, 2019) 21

82. No party objected to the actual amounts of severance paid in respect of each individual

position severed.

Commission findings

83. With respect to actual severance costs for 2018 and the updated forecasts provided in

response to the undertaking, the Commission finds that the actual and updated forecast amounts

awarded to severed employees by AET were reasonable in the circumstances. The remaining

required determination for the Commission is what amount of severance costs should be

recovered in rates.

84. In response to a Commission IR,56 AET provided its termination and severance policies

for both in-scope and out-of-scope employees. AET also confirmed that the termination and

severance policies for both in-scope and out-of-scope employees are common to all ATCO

companies.57 However, the in-scope termination polices do not apply on an ATCO-wide basis.

Rather, they are specific to each respective collective agreement such as that with the Canadian

Energy Workers Association (CEWA).58

85. AET witness, Mr. Goguen, confirmed that the determination of severance amounts was

based on years worked in all ATCO companies, and not just AET.59

86. AET confirmed that in allocating the forecast severance costs used in the 2018 forecast

labour allocation, AET used employees’ years of service. In some instances, there were

employees who spent time in another ATCO company, such as AED. The following exchange

provides an example of an employee who was severed and the calculation of how much time that

severed employee spent in each of AET and AED:

Q. MS. SABO: Now, moving back to Exhibit 558 again, I would like to look at Position

Number 7 on line 7, Column 7, which is the total years of service.

A. MS. GOODE: Yes.

Q. And this employee had 39 -- 31.9 years of service. Yes? And that's from Column –

A. MS. GOODE: Yes, that is what is shown here.

Q. Right. The percentage of service for this employee, and you can take this subject to

check, is approximately 97 percent of time ATCO Electric Distribution, so 30.8 divided

by 31.9. And 3 percent, which was 1.1 divided by 31.9 for ATCO Electric Transmission.

A. MS. GOODE: Yes, I can take that subject to check. I'd like to provide a little bit of

context around this for further understanding. ATCO Electric Transmission did not exist

in our Oracle HR or financial system as a standalone entity, I'll say. So what you will see

in Column G of Exhibit 558 is -- I believe it was January of 2013, subject to check -- that

ATCO Electric Transmission became its own, I'll call it, Oracle entity within our system.

So every employee will show less than five years of service with ATCO Electric

Transmission. That is not to say, however, that they were not performing transmission

56 Exhibit 22742-X0557.01, AET-AUC-2018OCT04-004. 57 Transcript, Volume 6, page 916, lines 3-7. 58 Exhibit 22742-X0688, Exhibit 22742-X0688 - Subject to Check - Goguen to Sabo. 59 Transcript, Volume 6, page 916, lines 8-24.


Decision 22742-D01-2019 (July 4, 2019) 22

services when they were part of ATCO Electric. So the remaining of their -- of all of

these employees who, by default, are showing in Column 5, entitled “ATCO Electric

Distribution” were not performing solely Distribution functions. That's just the default of

ATCO Electric prior to the creation of ATCO Electric Transmission standalone company.

Q. Okay. So those ATCO Electric Distribution numbers would be, for lack of a better

word, a blended number between -- because T&D would have been accounted for

together?

A. MS. GOODE: That is correct.

Q. Okay. So given that additional clarification, looking at the same position, Number 7

on line 7 of that exhibit, the allocation of severance was 100 percent to ATCO Electric

Transmission. Yes?

A. MS. GOODE: That is correct. I was also checking the updated attachment to

Undertaking 16, which also shows that that position was a 100 percent ATCO Electric

Transmission employee, which means that they were not in a common group providing

services.

Q. Okay. And given the Oracle system limitations, Ms. Goode, how are we assured that

that allocation should be 100 percent to ATCO Electric Transmission when the ATCO

Electric Distribution column is – you know, would be -- does not differentiate between

services for ATCO Electric Distribution compared to ATCO Electric Transmission prior

to the date you said?

A. MS. GOODE: To clarify, the cost allocators shown in Column H of Exhibit 559 is --

in 2018, that is where this employee resides and provides service. Again, with respect to

Position 7, they were a 100 percent Transmission employee in 2018, and may, in prior

years, have provided some services to other companies or been employed by another

ATCO company. However, the converse is also true, whereby ATCO Electric -- an

ATCO Electric 100 percent employee severance is allocated fully to ATCO Electric. If,

for example, there was an employee who transferred from ATCO Electric Transmission

to ATCO Power and was severed from ATCO Power, being a non-regulated, non-ATCO

company, that entity at the time of termination would bear the costs of the severance. If

you'll give me a second, I'd just like to reference one other exhibit.60

87. Ms. Goode later confirmed that the date upon which the Oracle HR system recognized

AET as its own reporting entity was January 2014 and not January 2013. For position number 7

using 2014 as the starting point, AET still allocated 1.1 years out of four years (2014-2017), or

approximately 28 per cent of that position’s time to AET. Yet, based on AET’s 2018 forecast of

that individual’s labour allocation, AET applied to recover 100 per cent of that individual’s

severance payment in this application.

88. In other words, AET severance payments are based on the total time an employee has

worked in any ATCO group company. However, AET allocated the severance payment amounts

included in its revenue requirement forecast based on where the severed position was providing

its services in 2018. The Commission does not find this to be a reasonable allocation of

severance payments.

60 Transcript, Volume 5, page 949 line 14 to page 952 line 25.


Decision 22742-D01-2019 (July 4, 2019) 23

89. The Commission finds that the allocation of 100 per cent of severance costs, as

demonstrated by the example for position number 7, is not reasonable because instead of

reflecting that employee’s years of service with AET as a percentage of total years employed

within the ATCO group of companies, it allocates the entire cost of severance to AET regardless

of that employee’s years of service with other ATCO entities. Further, there are enterprise

system limitations that require manual verification of the years an employee spent with AET in

order to determine the correct allocation of years of service between AET and other ATCO

Group companies. In particular, there is no transparency into the time allocated for severed

employees to AET’s transmission function prior to 2014.

90. For the above reasons, AET is directed to provide in its compliance filing a recalculation

of its 2018 severance costs based on the proportion of years of service each severed position

provided to the transmission function, as identified in Exhibit 22742-X0698.

91. In response to Undertaking 53, AET updated, for positions severed or forecast to be

severed, the years of service based on ATCO company information. For positions #134 to #155,

AET did not provide the years of service, as they were forecast to be eliminated during 2019, and

numbers were not available at the close of record. AET forecast $1.5 million of severance for

those positions in 2019. Given the above findings, the Commission approves AET’s 2019

severance costs of $1.5 million on a placeholder basis. The placeholder amount is limited to the

22 positions identified by AET in Undertaking 53 and Undertaking 54 (exhibits 22742-X0697 to

22742-X0700), which are forecast to be eliminated in 2019. The Commission will review the

historical service years within ATCO companies to determine the final approved amounts in

AET’s next GTA.

5.2 Compensation

5.2.1 Labour escalation

92. AET has applied for the following labour inflation rates for the 2018-2019 test period:

Table 12. Labour inflation forecast 2018-2019

2018 2019

Test Year Test Year

(%)

Inflation

Labour – In-scope 2.0 2.0

Labour – Out-of-scope 2.7 3.0

Source: Exhibit 22742-X0001.02, updated application, PDF page 20.

93. The Commission will address the in-scope and the out-of-scope inflation rates separately

in the subsections below.

5.2.1.1 In-scope escalation

94. AET explained that the in-scope inflation increase reflects the overall average increases

for employees belonging to the Canadian Energy Workers Association (CEWA), as well as

increases for the remaining employees not in CEWA. AET explained that its current agreement

with CEWA was ratified on July 12, 2017 and covers the years 2017 and 2018. The agreement


Decision 22742-D01-2019 (July 4, 2019) 24

called for inflation increases of 1.75 per cent in 2017 and 2.00 per cent in 2018. AET applied for

in-scope labour inflation increases of 2.0 per cent in each of 2018 and 2019.61

95. In response to a Commission IR,62 Bema recommended that the Commission deny AET’s

2017 actual in-scope labour escalation of 1.75 per cent and direct AET to adjust base salaries to

use the approved zero per cent in-scope labour escalation rate. Bema also recommended that the

Commission deny AET’s applied for in-scope labour escalation rates in 2018 and 2019 and

approve zero per cent for both years. The combined effect of removing the inflationary increases

would be a reduction in salaries of 5.86 per cent. As further support for its recommendations,

Bema referred to the Alberta government’s November 30, 2018 Economic Outlook and to the

price differential between West Texas Intermediate (WTI) and Western Canadian Select (WCS)

to suggest that:

Alberta is entering a period of significant uncertainty. To the extent the oil price discount

remains high and WTI remains low, there may very well be additional layoffs in Alberta.

Certainly, absent significant changes to the supply constraints in Alberta for oil and gas,

it is highly unlikely that significant growth will occur in Alberta in the forecast test

period.63

96. Bema stated that AET had not accounted for the impact of the price differential or the

recent downturn in economic forecasts.64

97. AET opposed Bema’s recommendations for in-scope compensation in 2018 and 2019. In

rebuttal evidence, AET highlighted that the collective agreement with CEWA contains

provisions for contract arbitration. AET explained that contract arbitration is final and binding

upon the parties, making it unworkable for AET to negotiate a zero per cent wage increase in

2018 or 2019, even in a weakened Alberta economy. AET submitted that its applied-for, in-

scope inflation rates of 2.0 per cent for each of 2018 and 2019, are representative of economic

conditions in Alberta and that these percentages factor in market comparators. AET provided the

following table depicting recent wage settlements for Alberta utilities:65

Table 13. Recent wage settlements in the Alberta utility market (per cent increase)

Company Union 2013 2014 2015 2016 2017 2018 2019

ATCO Gas NGEA 3.5 3.5 3.5 3.75 Note 1 1.75

ATCO Pipelines NGEA 3.0 3.5 3.5 2.75 Note 1 2

ATCO Electric CEWA 3.5 3.5 3.5 3.75 1.75 2.0

ATCO Electric Yukon CEWA 3.5 3.5 3.5 3.25 1.75 2.0 2.0

Northland (NWT) CEWA 3.5 3.5 3.5 2.5 1.5 2.0

Northland (YK) CEWA 3.5 3.5 3.0 3.0 1.75 2.0 2.0

AltaGas CEP 1947 2.0 3.0 3.0 2.0 2.0 2.0

AltaLink UUWA 3.5 3.5 4.0 2.5 2.5 2.35 3.0

AltaLink IBEW 3.5 3.5 4.0 3.5 2.35 2.35

Capital Power IBEW 3.75 3.5 3.5 2.5 2.0 2.0

61 Exhibit 22742-X0001.02, updated application, paragraphs 45-46. 62 Exhibit 22742-X0612, CCA-AUC-2018DEC19-009. 63 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 424. 64 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 424. 65 Exhibit 22742-X0618, AET rebuttal evidence, pages 182-183.


Decision 22742-D01-2019 (July 4, 2019) 25

Company Union 2013 2014 2015 2016 2017 2018 2019

Capital Power CEP 1947 3.75 3.5 3.75 3.75 2.0 2.0

Capital Power CSU 3.75 3.5 2.5 2.0 2.0 2.5

Medicine Hat Power IBEW 3.5 3.5 3.5 3.0 0.0 2.0 2.0

ENMAX CUPE38 3.0 3.5 3.5 3.5 1.25 2.25 3

ENMAX IBEW 3.0 4.0 3.5 3.5 3.75

EPCOR IBEW 3.75 3.5 3.5 2.5 2.5 2.35

EPCOR CSU52 3.5 3.5 3.0 2.25 2.15 2.35 2.75

FortisAlberta UUWA 4.0 3.25 3.5 3.5 3.75 1.5 2.25

Milner Power UUWA 3.0 3.5 3.75 4.0

TransAlta IBEW254 3.75 3.5 3.5 3.75 0 1.5 1.75

TransAlta UUWA100 3 3 3.0 0.0 0.0 0.0

Average including ATCO 3.4 3.5 3.4 3.0 1.8 1.9 2.3

Average excluding ATCO 3.4 3.5 3.4 2.8 1.9 1.9 2.5

Note 1: For 2017 ATCO Gas and ATCO Pipelines settlements included a lump sum payment.

98. AET argued that the 2.0 per cent in-scope labour inflation rate for 2018 is not a forecast

and is not subject to uncertainty. The collective agreement with CEWA was ratified in 2016 and

resulted in an increase for 2018 of 2.0 per cent. Further, the agreed upon 2.0 per cent labour

inflation rate is in line with the industry comparator average.66

Commission findings

99. The Commission accepts the 2.0 per cent in-scope labour inflation rate for 2018 that was

negotiated and reflected in the agreement with CEWA. AET confirmed in argument that “The

2.0% In-Scope Labour inflation for 2018 is not a forecast and is not subject to uncertainty.”67

In addition, the Commission finds that the evidence supports this amount because it is similar to

inflation rates for other Alberta utilities in 2018, as shown in Table 13.

100. Based on a review of the 2019 comparative data in Table 13, which is somewhat less

comprehensive than that for 2018, the Commission finds that a 2.0 per cent increase for in-scope

employees is consistent with the 2019 wage settlements of Alberta utilities and is reasonable in

light of the current economic outlook. For these reasons, the Commission approves AET’s

2.0 per cent in-scope labour inflation rate, as filed, for each of 2018 and 2019.

5.2.1.2 Out-of-scope escalation

101. In its application, AET forecast a 2.7 per cent labour inflation rate in 2018, and 3.0 per

cent labour inflation rate in 2019, for out-of-scope employees. AET stated that its requested

increases were consistent with salary increases projected by Mercer Canada Ltd. (Mercer).

Mercer’s 2017 “Total Compensation Review” was included in the application.68 An August 2018

update was included as Attachment 1.4(a) of the updated application filed by AET on

September 4, 2018.

66 Exhibit 22742-X0725, AET final argument, paragraph 77. 67 Exhibit 22742-X0725, AET final argument, paragraph 77. 68 Exhibit 22742-X0001.02, updated application, Attachment 1.4.


Decision 22742-D01-2019 (July 4, 2019) 26

102. In AET’s proposed labour escalators for out-of-scope employees, AET also took into

consideration incremental adjustments and promotional increases that are related to employee

progression and compression.69

103. AET submitted that Mercer’s total compensation review analysis demonstrates that

AET’s out-of-scope employees’ compensation level is 10 per cent below the market midpoint.

AET stated that its objective was to be at the mid-point of the market.70

104. In argument, the CCA adopted the evidence of Bema, and asserted that the Commission

should approve an out-of-scope compensation escalation rate of 2.25 per cent in 2018 and zero

per cent in 2019. The CCA insisted that the Commission prorate AET’s approved salary inflation

amounts to account for the fact that AET’s labour inflation increases are not effective January 1

of any particular year. The CCA summarized its arguments for a lower compensation escalation

rate, some of which are broadly applicable to total compensation, as follows:71

AET’s existing salaries are entirely reasonable and sufficient to compensate AET’s

employees during the test period. In fact, AET’s employees may be over compensated

from the perspective of base salary;

AET’s 2018 workforce reductions further limit the need for salary increases in the test

period;

AET’s bias towards paying base salary increases but not paying VPP has resulted in

over compensation of base salary and is inappropriate;

AET’s salary expectations remain unadjusted despite subdued economic growth in

Alberta both in 2018 and 2019; and

The ATCO group of companies' CEO has overall discretion to determine the pay

components for employees including out-of-scope escalation and thus there is a risk

that any amounts approved beyond the already approved 2018 salary increases will

not actually be implemented.72

105. The CCA also submitted that weight should not be afforded to the Mercer report as

support for AET’s proposed out-of-scope labour increases because it relies on outdated

information that is also based on arbitrarily determined parameters and is inconsistent from year-

to-year. The first study was completed in March 2015 and filed in AET’s 2015-2017 GTA and

the second study was completed in February 2017 and filed in the original application. The CCA

asserted that the data points from these two studies are very outdated and cannot be

representative of salary expectations in 2018 and 2019.73 Further, the companies considered to be

AET peer groups in the 2014 Mercer Total Compensation Study (MTCS) differed from those in

the 2018 MTCS update. The CCA argued that the difference in peer groups is arbitrary and does

not support reliance on the information between the two total compensation studies.74

69 Exhibit 22742-X0001.02, updated application, paragraph 47. 70 Exhibit 22742-X0001.02, updated application, paragraph 48. 71 Exhibit 22742-X0722, CCA final argument, paragraphs 442-443. 72 Exhibit 22742-X0722, CCA final argument, paragraph 442. 73 Exhibit 22742-X0722, CCA final argument, paragraphs 409-410. 74 Exhibit 22742-X0722, CCA final argument, paragraph 425.


Decision 22742-D01-2019 (July 4, 2019) 27

106. As explained by AET in its argument, Mercer provides analyses of salary escalation

projections provided by companies with jobs similar to those of AET's out-of-scope employees.

These analyses also reflect the current and near term economic environment in Alberta. AET

provided the following explanations of the two components of the Mercer study – salary

escalation projections and total remuneration review:

2018-2019 Salary Escalation Projections

… Mercer’s 2018-2019 Salary Escalation Projections provides base salary actual and

projected increases information for 2018 and 2019. Mercer initially provided base salary

increase projection information in the original Application, which was updated in the

Application Update. In his Expert Testimony, Mr. Yung provided an update to the 2018-

2019 Salary Escalation Projections. The updated 2018-2019 Salary Escalation Projections

demonstrate that AET's peer group 2018 actual salary increase budget was 2.8% at the

median. This information was not subject to debate and reflects actual 2018 data. For

comparison, AET's actual out-of-scope inflation adjustment in 2018 was 2.65%, which is

lower than the median of 2.8% for AET's peers. Furthermore, Mercer's updated analyses,

which should be considered very reliable given it was updated in December 2018,

demonstrates a median 2019 projected salary increase budget of 2.7% for AET's Peer

Group.75

Total Remuneration Review

… the Mercer 2017 Total Remuneration Review benchmarks AET’s out-of-scope

employees' total compensation against AET's peers in the marketplace. The Total

Remuneration Review provides an analysis on AET's competitive position on total

remuneration. The Total Remuneration Review is based on using target compensation, as

opposed to actual compensation for purposes of assessing incentive compensation. Actual

compensation may vary depending on factors such as overall business results and

individual employee performance, and therefore, would provide a less accurate view of

the intended compensation level for employee positions.76 [footnotes removed]

107. AET stated that Mercer’s analysis, based on survey data from April 2018, shows that

AET’s compensation level is, on average:

(a) seven per cent below P50 on total remuneration;

(b) one per cent below P50 on base salary; and

(c) two per cent below P50 on target total cash (includes base salary and target short-

term incentives).77

108. AET disputed the CCA’s argument on the lack of comparators that have participated in

Mercer’s 2015 peer group study and in its current 2018 study. AET provided the following

argument:

If one were to rely on the “old peer group” from 2015 to assess AET’s competitiveness,

as suggested by Bema, all that would be shown is how AET compares to the companies

that it competed with in the marketplace in 2015. It would not be indicative of the

companies that AET currently competes with for employee talent. Of course, there will

be some overlap year-over-year with respect to AET's competitors for employee talent.

However, for the competitive benchmarking to be a valid and reliable indicator of AET’s

75 Exhibit 22742-X0725, AET final argument, paragraph 60. 76 Exhibit 22742-X0725, AET final argument, paragraph 61. 77 Exhibit 22742-X0725, AET final argument, paragraph 62.


Decision 22742-D01-2019 (July 4, 2019) 28

current positioning, the peer group must be appropriately updated to reflect changes in

AET’s peers based on current information. Mercer has explained the changes made to the

AET peer group, including the reasons for adding and removing specific organizations. In

this regard, the Mercer updated AET peer group includes a greater percentage of Utility

organizations, as compared to the 2015 peer group.78 [footnotes removed]

109. AET re-confirmed that its ability to rely on other internal factors to gauge its market

competitiveness is limited79 and, therefore, AET must rely on industry compensation

professionals such as Mercer to maintain its competitiveness.80

110. In reply argument, the UCA observed that while AET was requesting 2.7 per cent and 3.0

per cent for out-of-scope labour inflation for 2018, and 2019, respectively, AET’s witness, Mr.

Goguen, stated that actual inflation for out-of-scope labour in 2018 was 2.65 per cent.81 The

UCA advocated that the best available information should be used for the 2018 out-of-scope

inflation rate, which is 2.65 per cent.82

111. AET stated that data collected to calculate the median projected salary increase of 2.7 per

cent for AET’s peer group, was collected in the fourth quarter of 2018 by Mercer. AET asserted

that its peer companies would have taken into consideration any "economic uncertainty" in

determining their projected salary increase budgets for 2019.83

112. The UCA submitted that for future GTAs, the Commission should exclude the

incremental costs of promotions from any future estimates of budgeted salary increases. The

UCA’s rationale was “that although a promoted person is likely earning more money than he or

she did in their previous position, they may well be earning less than the person who was in the

same job before them. The salary of the person they are replacing would already be accounted

for in the budget, and therefore there is no incremental cost stemming from the promotion.”84

Commission findings

113. AET witness, Mr. Goguen, confirmed that the Mercer study is the only empirical

evidence AET has advanced to justify its proposed out-of-scope labour inflation.85 In an

exchange with CCA counsel, Mr. Yung of Mercer acknowledged that its studies are limited to

those companies that choose to pay to participate in the MTCS:

Q. Thank you. And are you able to explain why some companies respond to the survey in

one year and then do not respond in other years?

A. MR. YUNG: I can give you a few more likely reasons anyways. I can't say these are

the only reasons that apply, but it could include things like, first, the company might not

be around anymore. For example, I can highlight that there are a few companies within

the 17 group, they just got taken out by another company in terms of corporate

transaction. They don't exist, so they can't really participate. And second, it could be

78 Exhibit 22742-X0725, AET final argument, paragraph 68. 79 Exhibit 22742-X0657, Undertaking 13. 80 Exhibit 22742-X0725, AET final argument, paragraph 72. 81 Transcript, Volume 1, page 150, lines 2-5. 82 Exhibit 22742-X0729, UCA reply argument, paragraphs 3-6. 83 Exhibit 22742-X0727, AET reply argument, paragraph 42. 84 Exhibit 22742-X0729, UCA reply argument, paragraph 7. 85 Transcript, Volume 2, page 309 lines 1 to line 17.


Decision 22742-D01-2019 (July 4, 2019) 29

because they have -- they're trying to save survey participation fees, and, as a result, they

might not choose to participate. So there are many possible reasons. But the one thing I

do want to highlight is the sample we used in the ATCO Electric studies have been

representative in both cases. So there shouldn't be any questioning of how reliable the

sample is 86

114. Mr. Yung, using “ATCO Electric’s Competitive Positioning” table in its application,87

explained how P50 was calculated:

Q. Yes. I think we were here not that long ago. And I was trying to understand your

discussion with Ms. Sabo about the median -- averages of medians. So the example you

used was business support services, and it says, number of ATCO matches in the next

column. And am I correct in saying that by that, we mean number of ATCO matches of

benchmarks? So there's eight companies that we can draw data from for this row?

A. MR. YUNG: So perhaps I will use that number, the eight as the example. So there are

eight ATCO Electric Transmission employees where we're able to find benchmark

position -- benchmark data within the peer group, and we compiled the median 25, 70

percentile, so on and so forth. So there are eight AET jobs included in that average

calculation for that level.

Q. And you took their -- so where does the median come from?

A. MR. YUNG: So the median would be -- think of it as -- because there are eight jobs,

there would be a median for each of the eight benchmark positions –

Q. Mm-hm.

A. MR. YUNG: -- from within the peer group. So there are eight medians. And the

$71,000 at the P50 column –

Q. Is the average.

A. MR. YUNG: -- would be the average of those eight medians.88

115. Mr. Goguen explained how AET uses the Mercer survey information to determine its out-

of-scope employees' salary adjustments.

Q. Thank you. So given that response, Mr. Goguen or Mr. Palladino, how does ATCO

Electric weigh the survey results in determining salaries for, say, that same level,

business support services, you know, with salaries targeted at $71,000 at P50?

A. MR. GOGUEN: So back to our desire to reach the P50. When we are reviewing base

pay adjustments annually, the data that we have is actually obviously each individual

within groups, et cetera. And that includes where they are at relative to the P50 for that

said position, be it business support, technical, or otherwise. We talked about earlier that

we have a budget that we assign accordingly, and we, depending on the role,

performance, et cetera, would adjust accordingly, with the aim, ultimately, to try to get

everybody close to that P50, realizing there's a delta here that's significant for the eight

86 Transcript, Volume 1, page 118 line 13 to page 119 line 6. 87 Exhibit 22742-X0001.02, updated application, PDF page 55. 88 Transcript, Volume 2, page 301 line 21 to page 310 line 24.


Decision 22742-D01-2019 (July 4, 2019) 30

positions that we've talked about. But that's how we would look at it and adjust

accordingly. And ultimately we'll have individuals that will be above P50 and some

below, again, depending on tenure in the role, experience, et cetera, et cetera. [emphasis

added]

116. Mr. Goguen confirmed that in determining salaries AET uses the MCTS and Total

Compensation Review data and considers AET’s budget and individual performance and roles.

AET has employees who are above or below P50, based on these items.89 The Commission

considers that while the MCTS and the Total Compensation Review provide information on

whether AET’s compensation is competitive at the 50th percentile, AET still retains discretion on

salary increases and labour inflation given that it also considers its budget and individual

performance.

117. The Commission also agrees with the recent findings in ATCO Pipelines’ 2019-2020

General Rate Application in Decision 23793-D01-2019, where that Commission panel found:

The Commission has reviewed the Mercer report and finds that it is only one factor in

assessing the level of required wage increases. The Mercer report does not supplant

management judgement and other economic factors that must be considered before

determining the salary level required to attract and retain talent. The Commission

considers that it is very difficult for any study to incorporate intangible factors such as the

economic climate in Alberta, risk of job loss, labour productivity and the unemployment

rate.

Target total compensation includes items such as variable pay, perquisites, long-term

incentive pay, pension and savings, and health and group benefits. Although some of

these items are not included for recovery in ATCO Pipelines’ revenue requirement, the

Commission considers that it is incumbent upon ATCO Pipelines’ management to review

whether these forms of compensation are required to retain and attract employees. ATCO

Pipelines can and should vary these items to meet its objectives with respect to total

compensation. The target total compensation data from Mercer is only one measure that

the Commission uses in approving out of-scope labour forecasts.90 [footnote removed]

118. AET confirmed that it awarded 2.65 per cent salary inflation to its out-of-scope

employees91 in 2018. The Commission finds that this actual 2018 amount is reasonable given that

it is based on the most up-to-date information on the record for 2018. The Commission approves

a 2.65 per cent inflation increase, and determines that it is reasonable to approve this as final for

2018.

119. AET submitted that its in-scope inflation rate forecast of 2.0 per cent for 2019 was

representative of economic conditions in Alberta and that this percentage takes into account

market comparators.92 The Commission is not persuaded that the current Alberta economic

climate supports an out-of-scope labour escalation rate of 3.0 per cent in 2019. Rather, the

Commission finds that an out-of-scope labour escalation rate of 2.0 per cent for 2019 better

89 Transcript, Volume 2, page 271 line 12 to page 272 line 4. 90 Decision 23793-D01-2019, ATCO Pipelines 2019-2020 General Rate Application, Proceeding 23793, June 25,

2019, paragraphs 221-222. 91 Exhibit 22742-X0727, AET reply argument, paragraph 49. 92 Exhibit 22742-X0618, AET rebuttal evidence, pages 182-183.


Decision 22742-D01-2019 (July 4, 2019) 31

reflects current labour inflation rates, similar to what the Commission approved for AET’s in-

scope inflation rate.

120. For the above reasons, AET is directed to incorporate out-of-scope inflation rates of 2.65

per cent for 2018 and 2.0 per cent for 2019 in its compliance filing to this decision.

121. In its submissions, the CCA asserted that AET’s labour forecasts do not appear to prorate

the out-of-scope inflation, and recommended that the Commission direct AET to prorate the

annual salary inflation by three-quarters.93 At the oral hearing, AET commented that:

A. [the] latter part of the first quarter is usually when we see our salary adjustments for

out-of-scope individuals, and usually they take effect at that point in time. He added that

the labour forecasts assume an April 1st effective day for wage increases.94

…

A. MR. GOGUEN: Roughly April 1st, yeah.

Q. Okay. And did your labour forecasts assume an April 1st effective date for wage

increases for the out of scope?

A. MR. GOGUEN: Subject to check, yes, I believe our forecasts would take that into

account.95

122. For confirmation purposes, AET is directed to demonstrate in its compliance filing, with

calculations, that it has prorated its out-of-scope labour inflation to reflect increases awarded on

April 1 of each year.

5.2.2 Variable pay program

123. In this section, the Commission makes three broad findings, two with respect to the

mechanics of the Variable pay program reserve account and one addressing the associated

forecast.

5.2.2.1 Reserve for VPP

124. AET is seeking the continuation of the VPP reserve account. However, it has requested

that the mechanics of the reserve account be altered to be symmetrical in nature. The VPP

reserve mechanics are designed to work in the following manner, as stated in Decision 20272-

D01-2016:

The Commission directs ATCO Electric to set up a VPP reserve account in its no cost

capital schedules in Section 29 of ATCO Electric’s revenue requirement schedules.

Regarding the mechanics of the reserve account, ATCO Electric will not be eligible to

recover costs in excess of the approved VPP forecast amounts for a given year, and will

not be permitted to carry over unused VPP funds for use in future years of the current

application. Approved, but unused, VPP amounts in any given GTA test period will be

added to the VPP reserve account for the next GTA test period. In the Commission’s

view, this approach will address the legitimate need to maintain funding for ATCO

Electric’s VPP in support of its recruitment, retention and operational performance goals,

93 Exhibit 22742-X0722, CCA final argument, paragraph 438. 94 Transcript, Volume 1, page 147 line 21 to page 148 line 15. 95 Transcript, Volume 1, page 148 lines 10-15.


Decision 22742-D01-2019 (July 4, 2019) 32

while insuring that any incentive to withhold VPP amounts otherwise payable to eligible

employees based on their performance, in order to increase the utility’s retained earnings,

is removed.96

125. AET proposed that approved, but unused, VPP amounts be carried forward and added to

the next test year’s VPP reserve account. Additionally, AET proposed that any VPP payments

made in excess of the approved forecast for any given test year be recovered through the reserve

in a future test year. AET suggested that the symmetrical treatment would allow AET to react to

changes in the marketplace that occur during the test period.97 AET claimed that the VPP reserve

account ensures that customers are not harmed by the inclusion of the VPP amounts requested by

AET in its revenue requirement.98

126. The VPP reserve account balance was provided by AET, and is reproduced in the table

below:

Table 14. VPP reserve account balances

Cross-reference 2015

Actual 2016

Actual 2017

Actual

Test Period

2018 2019

Opening balance - - 4.6 5.8 8.2

Approved / Applied-for expenditure

Sch 25-11, Line 19 - 4.6 5.0 5.3 5.4

Reserve adjustment - -

Actual / Forecast expenditure Sch 25-11, Line 19 - - (3.8) (2.9) (5.3)

Closing balance - 4.6 5.8 8.2 8.3

Mid-year Balance S. 29-1 - 2.3 5.2 7.0 8.2

Source: Exhibit 22742-X0002.04, MFR Schedule 29-5.

127. In its evidence, Bema recommended that the Commission deny AET’s requested change

to the reserve account mechanics and instead that the Commission maintain the existing reserve

account for the 2018-2019 test period.99 Bema provided a number of reasons in support of

continuing the existing reserve account mechanics, the three primary reasons being:

AET’s requested “symmetrical” treatment in the reserve account would not be

symmetrical from the perspective of ratepayers, as ratepayers already paid the full VPP in

past years and now AET is requesting that ratepayers be fully exposed if AET decided to

pay out more VPP than forecast in an attempt to retain its employees.100

96 Decision 20272-D01-2016, paragraph 192. 97 Exhibit 22742-X0001.02, AET updated application, paragraph 603. 98 Exhibit 22742-X0727, AET reply argument, paragraph 303. 99 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 91. 100 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 74.


Decision 22742-D01-2019 (July 4, 2019) 33

In Bema’s opinion, it is not in the public interest for ratepayers to reimburse AET’s

shareholders for a decision to compensate employees above the 100 per cent target

payout.101

AET continues to not pay 100 per cent of the approved VPP. Bema noted that in 2016,

AET paid 82 per cent of its approved VPP amount, and in 2017, AET paid only 58 per

cent of the approved VPP amount.102

128. Bema recommended that the Commission direct AET to refund the reserve balances in

2018 and 2019, to bring the closing balance of the reserve account to zero dollars on a forecast

basis in each year.103

129. In its rebuttal evidence, AET rejected Bema’s recommendation to make the closing

reserve account balance zero dollars on a forecast basis in each year. AET pointed out that

Bema’s recommendation ignores the payment lag that occurs as a result of VPP payments

“occurring in the year following the year in which they are awarded (i.e., VPP awarded for 2017

performance is paid in 2018).”104 AET added that the reserve account adjustments advanced by

Bema are not required and are flawed. According to AET, the reserve account is operating as

intended and customers are receiving a benefit tied to the accumulated positive reserve account

balance.105

130. The CCA submitted that it seeks to preserve the status quo in terms of how the reserve

account works, given that nothing has changed with AET’s VPP to warrant a change to the

reserve account mechanics. The CCA adopted, and requested that the Commission approve,

Bema’s recommendations provided in evidence, because:

Other Alberta utilities are not permitted to recover costs above 100 per cent of the

approved target payout from ratepayers, as this excess payout has been properly

considered to be a shareholder cost by the Commission;

AET itself exacerbated the risk of employees leaving the company because of the non-

payment of VPP to employees, which it then refuted in the oral hearing. It is thus AET,

not ratepayers, that should bear the costs of paying VPP above the target payout of 100

per cent. Additionally, given that the past non-payment of VPP resulted in improved

earnings for AET’s shareholders, it would be inappropriate for ratepayers to compensate

AET’s shareholders now if they are truly required to pay VPP above the 100 per cent

target payout;

ATCO Ltd.’s CEO retains 100 per cent discretion and veto power on the payment of

VPP;

AET’s VPP, despite the implementation of a reserve account in the 2015- 2017 test

period, still does not pay a target level of VPP to its employees, and further the VPP

does not clearly align with ratepayer interests; and

101 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 76. 102 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 92. 103 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 97. 104 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 14 105 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 14.


Decision 22742-D01-2019 (July 4, 2019) 34

AET’s payment history demonstrates a consistent payment of VPP well below the target level.

Therefore, modifying the reserve account to allow for symmetrical treatment and, thus, payments

above 100 per cent target would not be reasonable.106

131. The CCA noted that the VPP reserve account is accumulating a balance that will not be

refunded to ratepayers based on the current VPP reserve mechanics. The CCA recommended that

the Commission deny AET’s request for symmetrical treatment of the VPP reserve account and

require AET to refund the balance that has accumulated in the reserve account.

132. AET argued that its request to be able to carry approved, but unused, VPP amounts

forward in any year is fair and reasonable and does not operate to the disadvantage of customers.

AET submitted, “Rather, customers are fully protected by the existence of the Reserve and the

fact that AET must still demonstrate the reasonableness of the amounts incurred.”107

Commission findings

133. In Decision 20272-D01-2016, the Commission also found:

It remains unclear to the Commission, based on the above exchange, whether ATCO

Electric will pay VPP amounts in 2016 and 2017. Mr. DeChamplain confirmed that all

decisions with respect to VPP payment amounts at ATCO Electric “are subject to [the

ATCO Ltd.] CEO’s approval” based on economic conditions, apparently even if all of the

utility’s internal performance criteria are otherwise met. This suggests to the Commission

that, were it to approve ATCO Electric’s forecast expenditures for VPP in 2016 and

2017, there is no assurance that VPP payments will actually be made even if employees

achieve or exceed all their performance targets. The result is that, unlike other forecast

expenditures which may or may not be incurred because of external factors outside of

ATCO Electric’s control, VPP amounts, which are fully within ATCO Electric’s control

to pay, can be withheld from employees to the benefit of shareholders (and the cost of

ratepayers) based on directions received from the CEO of ATCO Electric’s ultimate

parent company.108

134. In this proceeding, both AET and the CCA agree that the VPP reserve account is

operating as intended. The Commission agrees. Moreover, the reasons the reserve account was

approved in Decision 20272-D01-2016 remain valid, and the structure of the VPP has not

materially changed since the inception of the VPP reserve account.

135. In directing AET to set up the VPP reserve account in the last GTA, the Commission

provided explicit directions on the mechanics of the VPP reserve account. In Decision 20272-

D01-2016, the Commission gave the following direction for AET to establish an asymmetrical

VPP reserve account:

The Commission directs ATCO Electric to set up a VPP reserve account in its no cost

capital schedules in Section 29 of ATCO Electric’s revenue requirement schedules.

Regarding the mechanics of the reserve account, ATCO Electric will not be eligible to

recover costs in excess of the approved VPP forecast amounts for a given year, and will

not be permitted to carry over unused VPP funds for use in future years of the current

application. Approved, but unused, VPP amounts in any given GTA test period will be

106 Exhibit 22742-X0722, CCA final argument, paragraph 40. 107 Exhibit 22742-X0725, AET final argument, paragraph 49. 108 Decision 20272-D01-2016, paragraph 189.


Decision 22742-D01-2019 (July 4, 2019) 35

added to the VPP reserve account for the next GTA test period. In the Commission’s

view, this approach will address the legitimate need to maintain funding for ATCO

Electric’s VPP in support of its recruitment, retention and operational performance goals,

while insuring that any incentive to withhold VPP amounts otherwise payable to eligible

employees based on their performance, in order to increase the utility’s retained earnings,

is removed.109

136. These VPP reserve account mechanics are deliberately asymmetrical. They are not

intended to operate in the same manner as the VPP deferral account the Commission removed in

Decision 2013-358. To grant AET’s request would, in effect, allow the VPP reserve account to

act as a deferral account. The Commission previously explained in Decision 2013-358,110 why it

removed deferral account treatment for AET’s VPP and these concerns have not changed.

137. For these reasons, the Commission denies AET’s request to amend the mechanics of the

VPP reserve account to be symmetrical in nature.

5.2.2.2 Variable pay forecast

138. AET has a VPP for its out-of-scope employees as part of its total compensation package.

Over time, AET has developed and refined its VPP based on market requirements, and on AET’s

overall corporate objectives and corporate metrics. In the current application, AET applied for

VPP in the amounts identified in the table below:

Table 15. Variable pay program costs

Description

2015 2016 2017 Test period

Actuals Actuals Actuals 2018 2019

($ million)

Transmission direct O&M - 566 - 1.0 0.5 0.8 0.8

Direct assigned capital - 1.1 1.0 2.4 2.5

Non-direct assigned capital - 1.3 1.2 1.4 1.4

Transmission 3.3 2.6 4.5 4.6

Isolated generation O&M - 557 - 0.0 0.0 0.0 0.0

Isolated generation - 0.0 0.0 0.0 0.0

Corporate O&M - 920 - 0.5 0.3 0.7 0.8

Corporate - 0.5 0.3 0.7 0.8

Total 3.8 2.9 5.3 5.4

Summary

Transmission O&M VPP - 1.5 0.8 1.5 1.6

Transmission direct assigned capital VPP - 1.1 1.0 2.4 2.5

Transmission non-direct assigned capital VPP - 1.3 1.2 1.4 1.4

Total transmission VPP - 3.8 2.9 5.3 5.4


109 Decision 20272-D01-2016, paragraph 192. 110 Decision 2013-358, paragraphs 72-73.


Decision 22742-D01-2019 (July 4, 2019) 36

139. Bema submitted that a variable pay compensation program should align payment with the

interests of ratepayers. Bema asserted that because ratepayers pay the forecast variable

compensation on AET’s behalf, through their rates, AET employees should be incented by way

of the compensation they receive to act in ratepayers’ interests. Bema stated that AET did not

provide enough information to allow Bema to adequately assess whether ratepayers' interests are

being served by AET’s VPP.111

140. Bema suggested that AET should amend its VPP to remove veto power from ATCO

Ltd.’s CEO, and recommended that AET be directed to re-design its VPP using AltaLink’s short-

term incentive plan program as a model. Bema proposed that AET’s VPP should be awarded

based on the following:112

30 per cent weighting to reliability,

20 per cent weighting to safety,

30 per cent weighting to economic/operational savings, and

20 per cent weighting to individual goals.

141. AET, in its rebuttal evidence, disputed Bema’s assertion that AET’s VPP is not aligned

with ratepayer interests, stating:

… To provide additional clarity, all AET employees have a duty of care to the safe,

reliable and economic operation of the interconnected electric system. This is factored

into each individual employee’s performance plan set each year. AET’s VPP is an

individual-based structured plan as opposed to a prescribed formulaic plan that is broad

in nature. Bema’s notion that the VPP program does not meet the needs of customers and

employees is ill-informed and completely incorrect. All employee goals - including those

related to safety, reliability, customer, and financial goals - are to the benefit of customers

when they are achieved.113

142. AET explained that “the amount of VPP paid out in a year is driven not only by the

performance of AET’s employees, but also based on the actual economic circumstances that

exists at the time of payout.”114 AET further stated that the ATCO Ltd. CEO is in the best

position to consider economic factors that extend beyond those affecting only AET.

AET indicated that its VPP does not strictly focus on individual performance, but includes other

factors such as a work team’s performance, and organization-wide performance.115

143. In argument, the CCA stated that examples of common goals provided by AET were

selective and subjective, since they could not be quantified.116 The CCA stated:

If a goal is not quantifiable, and instead is open to a great deal of subjectivity, it becomes

almost impossible to determine how that goal may benefit ratepayers. Accordingly, the

CCA submits that based on the limited evidence available on the record of the

111 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 151-152. 112 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 163-165. 113 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 27. 114 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 29. 115 Exhibit 22742-X0618, AET rebuttal evidence, PDF pages 29-30. 116 Exhibit 22742-X0722, CCA final argument, paragraph 165.


Decision 22742-D01-2019 (July 4, 2019) 37

proceeding, AET’s goals are not clearly aligned with ratepayer interests and thus it

appears to be inappropriate for ratepayers to fund AET’s VPP.117

144. The CCA recommended that the Commission direct AET, in its next GTA, to undertake a

comprehensive review of its VPP. However, the CCA also suggested that there is sufficient

evidence to “deny AET’s VPP program payments from inclusion in revenue requirement for

2018 and 2019 in their entirety.”118 The CCA stated that if the Commission considers it

appropriate for AET to recover its VPP costs in its revenue requirement, then it agreed with

Bema’s recommendation that AET’s forecast VPP payments be approved at between 60 and 80

per cent of the target payout.119

145. In argument, AET stated:

… the role of the Commission in this proceeding is to determine the reasonableness of

the quantum of its VPP forecast for the Test Years. It is the responsibility of AET’s

management to structure the overall compensation plan for the company and, with

respect, it is not the role of the Commission to dictate the manner in which a company

structures its compensation for its employees. While the CCA urged the Commission to

adopt certain actions in its initially filed Evidence, it acknowledged in its IR responses to

the Commission, that the relief it was requesting was beyond the Commission’s

jurisdiction.120 [footnotes removed]

146. AET added that VPP is an integral part of AET's total compensation package and it

assists in attracting and retaining skilled employees.121 AET explained that its VPP is structured

to take into account the individual objectives which would be set for each employee. The plan

for each individual includes aspects related to the achievement of corporate metrics as well as

individual goals. The payout under the plan can be influenced by prevailing market conditions.

As noted, AET's VPP is not a “formula-based” plan; but rather is designed around the individual

and is set based on interactions between the specific employee and that employee's leader.122

147. In reply argument, the CCA agreed with AET that the Commission should not manage

AET’s VPP, but added that the Commission has the authority to determine whether AET’s own

management of its VPP is reasonable, and to determine the amount of VPP that should be

included in AET’s revenue requirement.123 It submitted that AET’s VPP payout is arbitrary, and

does not incent employee behaviour that provides benefits to ratepayers.124

148. In reply argument, AET explained that VPP is not a guaranteed payment but, rather, one

that is based on a solid plan considering various aspects of company performance, including

operational, management, customer and safety matters. AET indicated that it establishes

appropriate goals on an individual basis for all employees eligible for VPP and appropriately

assesses employees’ performance against such objectives and pays VPP accordingly.125

117 Exhibit 22742-X0722, CCA final argument, paragraph 166. 118 Exhibit 22742-X0722, CCA final argument, paragraph 169. 119 Exhibit 22742-X0722, CCA final argument, paragraph 170. 120 Exhibit 22742-X0725, AET final argument, paragraph 412. 121 Exhibit 22742-X0725, AET final argument, paragraph 409. 122 Exhibit 22742-X0725, AET final argument, paragraph 410. 123 Exhibit 22742-X0726, CCA reply argument, paragraph 237. 124 Exhibit 22742-X0726, CCA reply argument, paragraph 239. 125 Exhibit 22742-X0727, AET reply argument, paragraph 300.


Decision 22742-D01-2019 (July 4, 2019) 38

Commission findings

149. In Decision 20272-D01-2016, the Commission approved AET’s VPP forecast and stated,

“ATCO Electric has not exceeded an actual payout of 83 per cent of its forecast VPP amount

since the deferral account treatment was removed. Its VPP forecasts for 2016 and 2017 are

approved at 80 per cent of the eligible employee payout amounts.”126

150. In a Commission IR, AET was asked to provide the number of employees that received

VPP payouts in percentage ranges requested by the Commission, and to provide the average VPP

payout percentage. In response, AET provided the following:127

Table 16. VPP payout percentages and average VPP payout percentage

VPP payout percentage (%)

2013 2014 2015 2016 2017

0 10 278 477 356 42 24

11 20 0 17 0 0 1

21 30 0 37 0 0 10

31 40 1 97 0 9 16

41 50 3 33 0 105 176

51 60 2 27 0 99 33

61 70 6 11 0 22 41

71 80 17 24 0 14 27

81 90 39 11 0 5 4

91 100 73 0 0 30 5

101 110 103 1 0 22 5

111 120 72 0 0 7 0

121 130 44 0 0 1 1

131 140 20 0 0 1 1

141 150 40 0 0 1 0

Total 699 735 356 361 346

Average VPP payout percentage (%)

66 15 0 59 51

151. Based on the response from AET above, the average VPP payout percentage was 55 per

cent128 for 2016 and 2017. AET is responsible for demonstrating the reasonableness of its

forecast amounts and the above table shows that the actual payouts are not consistent with the

historical forecasts prepared by AET. Further, it is unrealistic for the Commission to assume that

all of the employees eligible for VPP will meet 100 per cent of the targets set for them, and that

all FTEs eligible for VPP will be with AET when the VPP payouts are made in the test period.

152. In response to a Commission IR, AET stated that “It is of the view that AUC and

interveners have the opportunity to test the reasonableness of the variable pay payout through

information requests and oral hearing questioning as is the case for all other costs presented in a

126 Decision 20272-D01-2016, paragraph 191. 127 Exhibit 22742-X0417.01, AET-AUC-2018JUN08-039(d). 128 Calculated as: (59% + 51%)/2.


Decision 22742-D01-2019 (July 4, 2019) 39

general tariff application.”129 In the hearing, Mr. Palladino explained how corporate and

individual objectives are set as follows:

So the point I was making there, and this is a -- when you have an organization that is this

large and this complex in terms of the various functions that we undertake as an

organization, the objectives that Mr. Goguen has, ideally we'd like to be able to translate

those right down to the field base level and say, “The work that you do here, this is how it

impacts the overall organization.”

Often what we find, though, is that when you get down to the frontline field-based group

of employees where -- their primary function is to ensure the safe, reliable, and economic

delivery of the system. So what does that mean at the end of the day? It means keeping

the lights on, building new extensions, in a safe and quick manner. That's what their

primary focus is.

So when they think, "Well, the work that I do, how does that impact Mr. Goguen’s

overall objectives?" And that's a challenge that we have ultimately, is translating those

overall -- overarching objectives right down to the level of the frontline teams where they

can see how my work impacts the overall organization. And that's often the -- the

difficulties that we have.130

153. AET’s Mr. Goguen explained how the company assesses an individual’s performance:

A. MR. GOGUEN: Well, the assessment of the payout, if I can use that term, which is

done obviously after the year, would be assessed based on the role of the individual. If

they spent part of their year supporting an affiliate and part of the year the utility, we

would essentially get feedback from all parties to understand the performance, if you

will. We would then assess accordingly, calibrate accordingly, and ultimately the payout,

as with any other element, would be allocated appropriately as per the affiliate code and

our allocation methodologies.

Q. So when you're talking about assessing the role of the individual in that answer, I'm

taking that to mean an ATCO Electric Transmission employee. And does ATCO Electric

Transmission, in assessing its employees' performance, utilize a more broad, company-

wide goal rather than a transmission-specific goal?

A. MR. GOGUEN: As I mentioned, they're very individualistic. So each employee would

set up goals at the beginning of the year with their supervisor, their leaders, and

ultimately that's what they are measured on from their performance perspective. And then

as we calibrate and look at the company as a whole, that's when, again, the calibration

happens between the various individuals.

Q. So has AET provided on the record of this proceeding a comprehensive list of all the

employee goals that are included within the forecast VPP for 2018 and 2019?

A. MR. GOGUEN: We have not. That would amount to a tremendous amount of -- each

employee, Mr. Wachowich, as I mentioned, have their own performance plan,

essentially.131

129 Exhibit 22742-X0417.01, AET-AUC-2018JUN08-038(c), PDF pages 145-146. 130 Transcript, Volume 2, page 300, line 22 to page 301, line 19. 131 Transcript, Volume 1, page 29, line 16 to page 31, line 4


Decision 22742-D01-2019 (July 4, 2019) 40

154. Based on this testimony, AET assesses performance and determines VPP payout amounts

on an individualistic basis. The Commission finds it difficult to assess the basis for VPP payouts

without reviewing individual performance against goals prescribed for each individual. In

addition, there is significant discretion in the organization to deny or to significantly reduce VPP

payments based on corporate goals, economic conditions and other criteria. It is therefore

difficult for the Commission to rely with any confidence on AET’s VPP forecasts.

155. There is also a clear trend of AET underpaying VPP relative to the approved VPP

amounts in any given year. Although the mechanics of the VPP account as currently structured

allow AET to carry over unused VPP payment amounts, as pointed out by Bema, “AET

continues to not pay 100 per cent of the approved VPP.”132 Bema noted that in 2016, “AET paid

82 per cent of its approved VPP amount, and in 2017, AET paid only 58 per cent of the approved

VPP amount.”133

156. In light of the evidence and testimony on the record, AET’s VPP forecasts are approved

at 80 per cent of the eligible employee payout amounts. This determination is consistent with the

Commission’s previous VPP approval in Decision 20272-D01-2016. In its compliance filing to

this decision, AET is directed to reflect the Commission’s findings and directions regarding

VPP, including those findings with respect to FTEs and labour inflation rates, which affect

eligible employee payout amounts. In implementing this direction, AET is to take into account

the mechanics of the reserve account detailed in Section 5.2.2.3 Treatment of VPP reserve

account balance below.

5.2.2.3 Treatment of VPP reserve account balance

157. The Commission observes that, to the end of 2018, AET has accumulated $2.9 million134

in the VPP reserve account that relates to VPP amounts that were approved but not paid out in

2016 and 2017. In effect, any additional funding of VPP through revenue requirement in 2018

would further inflate the reserve balance because of the lag between 2018 VPP

obligations/accruals and 2019 VPP payments made in respect thereof. Similarly, the 2019 VPP

funding would inflate the reserve balance because 2019 VPP will not be paid until 2020.

158. In response to a CCA IR, AET confirmed:

AET does not consider that it would be more appropriate to first utilize the rolled forward

opening balance to fund applied for expenditures before seeking additional funding. AET

is of the view that forecast 2018 and 2019 VPP costs relate to these test periods and as

such should be incorporated and collected as part of the applied for tariffs; as opposed to

deferring the collection of these costs. AET would also like to highlight that the

referenced closing balance of $8.3 million for 2019 does not consider the 2019 VPP

payment, which due to timing would be paid in 2020, and be applied against the opening

2020 reserve balance. Therefore, due to timing the closing 2019 reserve balance is higher

than it otherwise would be.135

159. In its evidence, Bema recommended that the Commission direct AET to bring the closing

balance of the VPP reserve account to zero dollars on a forecast basis in each year. Bema

132 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 92. 133 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 92. 134 Calculated as: (4.6 – 3.8) + (5.0 – 2.9). 135 Exhibit 22742-X0572.02, AET-CCA-2018OCT05-014, PDF page 27


Decision 22742-D01-2019 (July 4, 2019) 41

suggested that the required adjustments be reflected as a reduction to AET’s applied for

operating costs.136 The Commission notes that even if the reserve account was drawn down to

zero, the reserve balance would begin to accumulate again because of the lag in VPP payouts

relative to approved VPP amounts for any given year.

160. The Commission has denied AET’s request to amend the mechanics of the VPP reserve

account to be symmetrical in nature, as detailed above. The Commission also agrees with the

CCA that the VPP reserve account balance should be targeted to be as close to zero by the end of

the GTA test periods as possible. The Commission notes in this regard, that there is no benefit to

AET shareholders, ratepayers or employees in maintaining a positive balance in the VPP reserve

account as any positive balance is designated as zero cost capital. On the other hand, requiring

ratepayers to provide VPP funds projected to be spent, but that may not be spent not only for a

period of one or more years after those VPP funds are collected, but for one or more successive

test periods, is prima facie harmful to customers. In its compliance filing AET is directed to

provide options on how it could best operate the VPP reserve account to avoid an increasing

accumulated balance i.e. the VPP reserve account balance should trend as close to zero as

possible.

5.3 Other escalators

5.3.1 Contractor and other inflation

161. In its application, AET provided a summary of key assumptions with respect to its

forecasting methodology. From that information, the Commission has prepared the following

table which details the inflation rates forecast for labour, contractors and other categories of

costs:

Table 17. Forecast inflation rates – labour, contractors and other 2018-2019

2018 Forecast 2019 Forecast

(%)

Labour – in scope 2.0 2.0

Labour – out of scope 2.7 3.0

Contractors 2.2 2.3

Other 2.1 2.1

Source: Extracted from Exhibit 22742-X0001.02, Table 1.9 Key Assumptions, PDF page 20.

162. Evidence filed by Bema, on behalf of the CCA, provided a review of the economic

environment in Alberta concluding that there was a relationship, albeit a simplistic one, between

the forecast of West Texas Intermediate (WTI) and the impact that WTI forecast should have on

AET’s applied-for inflation rates. Bema stated that the Alberta economy has changed since the

filing of AET’s application. Bema supported this assertion by providing opinions from the

Alberta Government website indicating that the government itself was anticipating weaker

economic growth for the province.137

163. Given that Alberta has entered a period of significant uncertainty, Bema recommended

that the Commission should consider the discussions it presented on the recent downturn in

economic forecast for 2019 and the fact that AET has not fully incorporated these changes in its

136 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 97. 137 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 407, 410, 422.


Decision 22742-D01-2019 (July 4, 2019) 42

forecasts. Bema noted that AET had not revised its forecast inflation rates even after reflecting

the workforce reductions in 2018.138

164. AET did not agree with the assertions made by Bema with respect to the impact of the

uncertainty in Alberta’s economy and the correlation of oil prices to forecast salary adjustments.

5.3.1.1 Contractor inflation rate

165. AET applied for forecast contractor inflation rates of 2.2 per cent and 2.3 per cent for the

years 2018 and 2019, respectively. The contractor inflation rate is calculated using a composite

of other inflation rate, and the inflation rates used for both in- and out-of-scope labour (discussed

in Section 5.2.1 above). The calculation of the applied-for contractor inflation rate was provided

in response to a Commission IR,139 and subsequently updated during the oral hearing by way of

undertaking. In response to the undertaking, AET used the same labour inflation rates as those

applied-for but incorporated more recent Alberta CPI information. This resulted in contractor

inflation rates of 2.4 per cent and 2.2 per cent for the years 2018 and 2019, respectively.140

5.3.1.2 Other inflation rate

166. AET’s forecast inflation rate applicable to all other categories of costs was determined

using an average of Alberta CPI forecast rates from a number of government and financial

institutions as of January 30, 2017,141 and resulted in an applied-for other inflation rate of 2.1 per

cent for both 2018 and 2019.

167. The calculation of the other inflation rate was provided in response to a Commission IR,

and subsequently updated during the oral hearing by way of undertaking. Using more recent

Alberta CPI information, as of January 2019, resulted in other inflation rates of 2.4 per cent and

2.0 per cent for the years 2018 and 2019, respectively.142

168. AET argued that the results included in the undertaking were consistent with the

contractor inflation rates used in AET’s application and submitted that the applied-for contractor

and other inflation rates were reasonable and should be approved as filed.143

169. The CCA had “no extensive reply to AET’s argument in relation to contractor and other

inflation,” other than to note that, should the CCA’s recommendations for reductions to AET’s

forecast labour inflation rates be accepted by the Commission, it would lead to a reduction in

AET’s forecast contractor inflation rates.144

Commission findings

170. Based on the information provided by AET in response to IRs and undertakings, the

Commission finds AET’s applied-for forecast contractor inflation rates of 2.4 per cent for 2018

and 2.2 per cent for 2019 to be reasonable. Based on AET’s explanation in the undertaking,145 the

138 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 407. 139 Exhibit 22742-X0217.01, AET-AUC-2017AUG30-010, PDF pages 5-6. 140 Exhibit 22742-X0675, Undertaking 39, Attachment 1. 141 Exhibit 22742-X0217.01, AET-AUC-2017AUG30-010, PDF pages 5-6. 142 Exhibit 22742-X0675, Undertaking 39, Attachment 1. 143 Exhibit 22742-X0725, PDF pages 30-31. 144 Exhibit 22742-X0726, CCA reply argument, paragraph 31. 145 Exhibit 22742-X0675, Undertaking 39, Attachment 1.


Decision 22742-D01-2019 (July 4, 2019) 43

Commission approves other inflation rates of 2.4 per cent for 2018, and 2.0 per cent for 2019.

The forecast contractor inflation rates and other inflation rates are approved, subject to any

applicable findings and directions elsewhere in this decision; specifically, Commission findings

on inflation rates used for both in- and out-of-scope labour.

6 Fuel costs

171. In its application, AET mentioned that it owns and operates eight generation plants

serving isolated communities. It stated that diesel fuel powers six of those plants, while the two

remaining plants serving Jasper are powered by natural gas and diesel (Jasper Palisades) and

hydro (Astoria Hydro). In addition to isolated community plants, AET owns 66 isolated

generating plants for substation and telecommunication power supply backup and four isolated

plants for primary telecommunication power supply. Most of those plants operate on propane

and three operate on diesel. AET provided its actual and forecast fuel costs in Table 4-1 of the

application, as reproduced below:146

Table 18. Actual/Forecast fuel costs

2015 2016 2017 2018 2019

Actuals Actuals Actuals Test period

($ million)

Isolated generation fuel 6.0 5.0 7.2 7.0 7.8

Transmission plants and propane fuel 0.0 0.0 0.0 0.1 0.1

Total 6.0 5.0 7.2 7.1 7.9

Increases/(Decreases) in test period 0.0 (1.0) 2.2 (0.1) 0.8

Impact of price 0.0 (1.2) 0.2 0.2 1.2

Impact of volume 0.0 0.2 0.9 0.9 (0.4)

Impact of carbon levy 0.0 0.0 1.2 0.6 0.0

Source: Exhibit 22742-X0001.02, updated application, Table 4-1, PDF page 141.

172. AET stated that, for the test period, it is pursuing the interconnection of the Garden River

isolated community site to the Alberta electrical grid and is reconfiguring the Indian Cabins and

Fawcett River microgeneration plants into renewable hybrid plants. These projects led to a

decreased diesel fuel consumption forecast for the test period.

173. AET argued that despite overall fuel volume reductions, it is forecasting increased fuel

costs due to the carbon levy and increased commodity pricing. AET stated the September 2018

update reflects the most up-to-date information available on the record147 and observed that the

fuel forecast had not been the subject of intervener evidence, nor questioning at the oral hearing.

Therefore, the forecasts should be approved as filed.

174. The CCA advised the Commission that it had no reply to AET’s arguments in relation to

fuel costs.

146 Exhibit 22742-X0001.02, updated application, Table 4-1, PDF page 141, footnotes removed. 147 Exhibit 22742-X0725, AET final argument, paragraph 111.


Decision 22742-D01-2019 (July 4, 2019) 44

Commission findings

175. The Commission has reviewed the fuel cost forecast provided by AET. Table 4.2 in the

application provides details on AET’s fuel cost calculation and forecast. Given Table 4.2, the

Commission finds the price and volume assumptions used by AET for its natural gas, propane

and diesel forecasts to be reasonable.

176. However, the Commission notes that the Alberta provincial government repealed the

carbon tax effective June 4, 2019.148 The Commission takes notice of this repeal and directs AET,

in its compliance filing to this decision, to remove the effects of the repeal of the carbon tax from

its fuel cost forecast for the months in 2019 that are affected by this legislative change. The

Commission accepts AET’s 2018 fuel cost forecast, as filed in its updated application.

7 Operating costs

177. In its application, AET stated that it has forecast operating costs consistent with the

previously approved activity-based forecast methodology. AET further described its process in

developing activity-based forecasts as follows:

Functional areas within AET perform an annual assessment of resources to ensure that

activities performed in each area are relevant and required to fulfill legislative and

regulatory obligations, provide ongoing safe and reliable transmission services to

customers, and meet business needs during the Test Period.149

178. The following table summarizes AET’s direct operating costs:

Table 19. Transmission direct operating costs150

2015 2016 2017 2018 2019

USA account Actuals Actuals Actuals Test period

($ million)

USA 560 – Supervision & Engineering 5.0 3.6 3.5 3.4 3.5

USA 561 – Control Centre 3.2 3.6 3.4 4.1 4.3

USA 562 – Station Maintenance 13.6 11.3 11.4 8.4 9.0

USA 563/569 – Overhead Line Maintenance 4.1 3.5 3.6 2.5 2.6

USA 567 – Annual Structure Payments 8.6 6.6 6.7 6.9 7.3

USA 571.1 – Vegetation Management 9.3 9.1 6.7 10.9 11.1

USA 575 – IT Support 3.4 3.1 3.0 3.0 2.9

Subtotal 47.2 40.8 38.3 39.2 40.7

USA 566 – Miscellaneous Transmission Expense non-Affiliate

15.1 12.7 12.3 12.2 12.2

Net Direct O&M 62.3 53.4 50.5 51.4 52.9

USA 566 – Miscellaneous Transmission Expense Affiliate

24.4 22.6 26.1 3.3 3.3

Total direct O&M 86.6 76.0 76.6 54.7 56.3

148 Bill 1: the Carbon Tax Repeal Act received Royal Assent on June 4, 2019. 149 Exhibit 22742-X0001.02, updated application, paragraph 97. 150 Exhibit 22742-X0001.02, updated application, paragraph 98, Table 5.1.


Decision 22742-D01-2019 (July 4, 2019) 45

7.1 Forecasting accuracy

179. Bema, on behalf of the CCA, provided several comments on AET’s operating costs and

forecasting accuracy, describing its process as follows:

The Bema evidence began by first reviewing AET’s historical forecasting accuracy for

each USA account. However, Bema’s evidence did not simply stop there and propose a

generalized reduction to AET’s forecast costs based only on the forecasting accuracy

analysis. Rather, Bema then specifically reviewed the evidence available to support

AET’s forecast costs, which included the core evidence in AET’s application,

information provided in information responses, AET’s GTA schedules and other analysis

relied upon by Bema. Based on this combined evidence, Bema recommended

adjustments to some of AET’s forecast operating costs. Accordingly, the Bema evidence

was not simply an isolated analysis of AET’s forecasting accuracy as AET attempted to

have the Commission believe.151

…

Additionally, to ensure improved accuracy in preparing its evidence, Bema specifically

excluded certain costs where they were the subject of deferral accounts, reserve accounts,

other Bema analysis or if they were affiliate in nature and required to be offset. These

types of transactions can skew the results of an analysis of past forecasting accuracy. For

example, including AET’s flow through affiliate transactions that have a revenue offset

would improperly suggest that the actual costs are higher, which would be misleading.

Accordingly, the CCA submits that significant weight should be given to the

recommendations of Bema in relation to AET’s forecast operating costs.152

180. To support its position, the CCA provided a table comparing approved ROE ($ and %)

and actual ROE ($ and %) for the years 2008-2017. The CCA identified that, for that period,

actual ROE tended to exceed approved ROE, and it concluded that the positive variances could

only come from items without deferral account treatment, such as operating costs, income taxes,

revenue offsets and non-direct assigned capital.153

181. AET responded to the CCA's position as follows:

Contrary to the submissions of the CCA, AET has provided detailed information, not

only with respect to its historic forecasting accuracy, but also variance explanations

which allow the Commission to understand the variance experienced from forecast to

actual, including specifically information associated with the efficiency gains achieved

by AET over the last Test Period, which are now embedded and reflected in the 2018 and

2019 Test Year forecasts. As noted, the benefits of AET adopting various initiatives

during this time period are now being passed on to customers in the form of reduced

rates.154

Commission findings

182. For purposes of this section, the Commission will not take a global approach to its

determinations. Instead, it will only consider the issues related to non-labour costs. The

Commission considers that a high-level analysis of forecasting accuracy has value only to the

151 Exhibit 22742-X0722, CCA final argument, paragraph 186. 152 Exhibit 22742-X0722, CCA final argument, paragraph 193. 153 Exhibit 22742-X0722, CCA final argument, paragraphs 202-204. 154 Exhibit 22742-X0727, AET reply argument, paragraph 104.


Decision 22742-D01-2019 (July 4, 2019) 46

extent that it shows a consistent trend of under spending relative to its forecasts, that cannot be

reasonably explained by specific cost drivers. The Commission views that it should, where

possible, evaluate forecast accuracy for each of the specific cost categories, where cost category

information and support for increases is available, to determine the reasonableness of the

applied-for amounts. Accordingly, the Commission has reviewed, in other sections of this

decision, the forecasts for AET’s labour costs derived from FTEs and labour rates affected by

escalation factors. Therefore, in the subsection below, the Commission will limit its findings to

those accounts where non-labour issues have been identified.

7.1.1 USA 561 – Transmission Operations – Control Centre

183. AET stated that most of the cost increases for this account for the test period were

associated with the reallocation of network services and operations costs from USA 562 to

USA 561.155

184. The CCA recommended a disallowance of $200,000 for 2018 and $400,000 for 2019. It

was the CCA’s position that AET did not adequately explain several items, including why new

Alberta Reliability Standards (ARS) require increased O&M costs and why there were increases

in SCADA (System Control and Data Acquisition) service agreement costs.156

185. AET responded that the CCA ignored the full-year impact of the 11 new ARS

implemented in October 2017 and the oral testimony regarding SCADA-related software and

service agreements.

Commission findings

186. As this section pertains to non-labour issues, the Commission will confine itself to

SCADA-related software and service agreements. All other issues identified with this account

are labour-related. The AET testimony of Mr. Bothwell was that the increased SCADA licence

costs are due to the increase in SCADA locations, that is, the increase in volume of use.157

187. The Commission accepts the evidence on why there were increases in SCADA costs, that

is, because of volume of use, and approves the forecast for non-labour costs for this account for

each of the test years, as filed.

7.1.2 USA 563 and 569 – Overhead Line Maintenance

188. The CCA questioned why the forecast for general operating expenses increased by

$100,000 for each of 2018 and 2019. The CCA recommended that costs for this account be

reduced by $100,000 for 2018 and $200,000 for 2019.158

189. AET stated that increases in the general operating expenses category of these USA

accounts are associated with increases in the aerial (fixed wing and helicopter) program as part

of its maintenance optimization initiatives. AET added:

Specifically, AET has incorporated the use of ultraviolet, infrared and high-resolution

imagery captured from aircraft and the use of helicopter-assisted climbing inspections on

155 Exhibit 22742-X0001.02, updated application, paragraph 150. 156 Exhibit 22742-X0722, CCA final argument, paragraphs 224-226. 157 Transcript, Volume 3, page 450, line 19 to page 451, line 1. 158 Exhibit 22742-X0722, CCA final argument, paragraphs 244-248.


Decision 22742-D01-2019 (July 4, 2019) 47

(primarily) lattice tower transmission lines to largely replace maintenance activities that

previously required technicians to climb structures to collect the same information. While

the costs in the General Operating Expenses category have increased since 2015, they are

more than offset through labour and contractor cost savings …159

190. The CCA argued that AET did not explain why the aerial program costs have increased

since 2016 and pointed out that the magnitude of the increases exceeded inflation.160

191. In its reply argument, AET stated that increased utilization, increased capabilities and

new technology have resulted in modest increases in aircraft costs, but have offset labour costs

which otherwise would have been charged to this account.161

Commission findings

192. The Commission accepts the submission from AET that the increasing use of the aerial

program replaces certain maintenance practices, which reduce labour and contractor costs. For

this reason, the Commission approves AET’s forecast costs for this account for each of the test

years.

7.1.3 USA 566 – Miscellaneous Transmission Expense

193. AET described the costs for this account as follows:

AET captures the costs associated with the following activities in USA 566: salary

continuance (such as sick and bereavement leave), safety initiatives such as safety

meetings and safety-specific training, technical training, variable pay, relocation costs

and administrative activities. These costs are incurred by the FTEs assigned to the other

direct transmission O&M accounts, including engineering, operations, and station and

overhead line maintenance.162

…

This account includes labour costs of the Cyber Security Office, Asset Management

Office, staff for vegetation management program and work methods specialist. This

account also contains costs relating to facilities that are owned by AED and occupied by

AET staff. A portion of the capital costs associated with these buildings was previously

included in AET’s rate base, but ownership has been fully transferred to AED.163

194. AET provided the following table to illustrate its forecast costs for this account:

Table 20. Direct O&M costs for USA 566164

2015 2016 2017 2018 2019

Actuals Actuals Actuals Test Period

($ million)

Direct O&M cost 39.4 35.2 38.4 15.5 15.6

Affiliate and affiliate cost of goods sold 24.4 22.6 26.1 3.3 3.3

Non-affiliate 15.1 12.7 12.3 12.2 12.2

159 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 47. 160 Exhibit 22742-X0722, CCA final argument, paragraph 249. 161 Exhibit 22742-X0727, AET reply argument, paragraph 118. 162 Exhibit 22742-X0001.02, updated application, paragraph 226. 163 Exhibit 22742-X0001.02, updated application, paragraphs 227-228. 164 Exhibit 22742-X0001.02, updated application, paragraph 226, Table 5.14.


Decision 22742-D01-2019 (July 4, 2019) 48

195. In argument, the CCA submitted that AET had not demonstrated the need for an increase

in general operating expenses after moving the building facility costs back into general operating

expenses in 2018 and 2019. The CCA recommended a disallowance of $500,000 for each of the

test years.165

196. In its rebuttal evidence, AET explained that the General Operating Expense category

increase in 2018 was due to increased costs associated with Crown dispositions for facilities on

Crown land, and for road use payments.166 The increase in external contractor charges was due to

building facility charges being captured under this category.167

197. The CCA argued that Crown dispositions and road use cost increases account for only

$300,000 of AET’s proposed cost increases and that therefore at least $200,000 of the cost

increase in general operating expenses had yet to be explained.168

198. In its reply argument, AET stated that it “provided detailed information with respect to

the cost variance, being mainly due to services to outside parties cost of sales, which appears as

a revenue offset.”169

Commission findings

199. The Commission accepts AET’s explanation that increases for external contractor

charges and general operating expenses were due to building facility costs and crown

dispositions. The Commission also accepts the submission from AET that the cost variance due

to services to outside parties has a revenue offset. Therefore, the Commission accepts AET’s

forecast costs for USA 566.

7.1.4 USA 567 – Annual Structure Payments

200. AET is required by the Surface Rights Act to pay annual compensation to landowners for

transmission structures located on their property. These costs are recorded in USA 567. Among

the costs included in this account are the annual structure payments and any costs relating to

Surface Rights Board (SRB) proceedings. AET provided the following evidence of direct O&M

costs for USA 567, which included a forecast increase in compensation applications to the SRB:


2015 2016 2017 2018 2019


($ million)

Direct O&M cost 8.6 6.6 6.7 6.9 7.3


201. With the completion of the Eastern Alberta Transmission Line (EATL) and the Central

East Transmission Development (CETD), and the elimination of uncertainty regarding annual

165 Exhibit 22742-X0722, CCA final argument, paragraph 266. 166 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 50. 167 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 50. 168 Exhibit 22742-X0722, CCA final argument, paragraphs 259-261. 169 Exhibit 22742-X0727, AET reply argument, paragraph 120.


Decision 22742-D01-2019 (July 4, 2019) 49

structure payments for those projects, AET is proposing to discontinue the deferral account for

annual structure payments.170

202. The CCA noted that AET’s forecasting accuracy for this account was within one per cent

of the approved forecast in the most recent two years and equal to the approved forecast in the

most recent five years. The CCA supported AET’s request to remove the annual structure

payments deferral account.171 However, the CCA argued that absent base increases from the

addition of new transmission facilities, there should not be notable increases in costs,172 and it

recommended that the Commission disallow $100,000 and $400,000 in costs in 2018 and 2019,

respectively.173 The CCA stated that its request was reasonable as AET confirmed, in its rebuttal

evidence, that 2018 forecast SRB costs were less than the applied-for amounts but AET still

expected the 2019 SRB costs to be consistent with its forecast.174

203. In reply argument, AET noted that the increased costs for SRB hearings related to

renewal agreements for the EATL, CETD and Hanna Region Transmission Development

(HRTD).175

Commission findings

204. Although there may be more certainty regarding actual annual structure payments, the

Commission agrees that there is uncertainty regarding SRB costs consistent with AET’s

$200,000 reduction in its forecast costs for 2018.

205. Given the uncertainty with SRB costs, the Commission denies AET’s request to

discontinue the existing deferral account for annual structure payments. AET is directed to

reflect, in its compliance filing to this decision, the $200,000 reduction for the 2018 test year.

The Commission also accepts the CCA arguments regarding the 2019 forecast and directs AET

to reduce the 2019 forecast by $200,000.

7.1.5 Vegetation management

7.1.5.1 Reserve for vegetation management

206. In Section 1.4 of the application,176 AET requested discontinuance of the reserve for

vegetation management. The reserve was established in Decision 20272-D01-2016, pursuant to

which the Commission directed AET to set off amounts spent in excess of the approved forecast

for a given test year against amounts included in the approved forecast(s) for subsequent years

within the specific test period. Approved but unused amounts within any given test period would

be added to the reserve account balance for start of the next test period.177

207. AET described past challenges in securing contractors to execute its planned vegetation

management program. It submitted that these challenges have now been addressed through

diversification of contractors and other changes in its approach to vegetation management. AET

170 Exhibit 22742-X0001.02, updated application, paragraph 195. 171 Exhibit 22742-X0722, CCA final argument, paragraphs 268-269. 172 Exhibit 22742-X0722, CCA final argument, paragraph 270. 173 Exhibit 22742-X0722, CCA final argument, paragraph 272. 174 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 54. On PDF page 55, AET stated that costs associated

with SRB proceedings are expected to be $0.2 million less than originally forecast in 2018. 175 Exhibit 22742-X0727, AET reply argument, paragraph 34. 176 Exhibit 22742-X0001.02, updated application, paragraph 10, Table 1.4. 177 Exhibit 22742-X0001.02, updated application, paragraph 604.


Decision 22742-D01-2019 (July 4, 2019) 50

indicated that, with its comprehensive forecast for vegetation management for the test period and

the availability of contractor resources, the uncertainty regarding the vegetation management

account is substantially reduced and the reserve account is no longer required.

208. The CCA challenged AET’s assertions on forecasting accuracy, in particular, pointing

out that AET’s accuracy with respect to 2015 was due entirely to the Commission having

approved only actual costs for that year. Further, the CCA observed that the Commission

directed a 25 per cent reduction in forecast relative to applied-for costs for 2016 and 2017 and

that, in those years, AET achieved the reduced costs approved by the Commission. The CCA

asserted that, had applied-for costs been approved, AET’s forecasting accuracy would have been

as consistently poor as it has been in prior years.178

Commission findings

209. The Commission directs AET to maintain its reserve for vegetation management. As

noted by the CCA, the variance for 2015 was limited because the Commission accepted actual

results rather than forecasts for that year.

210. AET has stated that:

Evidence provided by AET herein confirms that AET’s forecasting accuracy has been

very high from 2015 to 2018, particularly given that the mechanics of the Reserve

Account that applied during the 2016 and 2017 period permitted AET to advance

treatments from 2017 to 2016.179

211. AET’s statement shows that the vegetation management reserve account has supported

stability and AET’s management of its forecast costs. As a result, there is merit in maintaining

this reserve account. The Commission finds that the reserve account should be continued and

therefore directs AET to maintain the use of the vegetation management reserve account.

7.1.5.2 2018-2019 Forecast vegetation management costs (USA 571.1)

212. AET provided the following direct O&M costs for USA 571.1 (Vegetation management):


2015 2016 2017 2018 2019


($ million)

Direct O&M Cost 9.3 9.1 6.7 10.9 11.1

213. AET stated that the forecast increases for 2018 and 2019 for vegetation management

relate to an escalation in its mechanical programs in preparation for conversion to herbicide

treatments.

214. In evidence and argument, AET claimed that its ability to achieve substantial cost savings

in the execution of its vegetation management program relies on its aggressive approach to

mechanical treatments that are to be followed by herbicide treatments. AET indicated that any

178 Exhibit 22742-X0722, CCA final argument, paragraphs 108-109. 179 Exhibit 22742-X0725, AET final argument, paragraph 52. 180 Exhibit 22742-X0001.02, updated application, paragraph 198, Table 5.10.


Decision 22742-D01-2019 (July 4, 2019) 51

deferral with respect to its programs in the test years would delay the achievement of cost

savings from the herbicide treatments.181 AET added that 2018 actuals were tracking to meet

forecast costs, as shown in its updated application.182

215. The CCA submitted that AET is forecasting its highest ever vegetation management costs

for the 2018-2019 test period183 and, therefore, it recommended a 25 per cent reduction in AET’s

forecast costs for each of the two test years.184 As an alternative to the 25 per cent reduction, the

CCA recommended that the use of 2018 actual costs would be reasonable. The CCA added that

if AET’s 2018 actual costs are close to the forecast, then AET should not be opposed to this

alternative for 2018. The CCA would, however, continue to propose a 25 per cent reduction to

the 2019 forecast costs.185

216. AET replied that, based on the best information to date, 2018 actuals were on track to

meet the forecast expenditure provided in the application update.186 It added that it is on track to

complete the conversion of its rights-of-way to herbicide treatment by 2020, and thereafter to

deliver to ratepayers the benefits associated with such conversion.

Commission findings

217. The Commission shares some of the concerns expressed by the CCA regarding the level

of vegetation management costs. However, the Commission does not agree with the CCA that a

25 per cent reduction in 2018-2019 vegetation management expenditures is reasonable. For

2018, the Commission accepts the evidence of AET that 2018 actual expenditures were tracking

close to forecast and approves AET’s 2018 forecast. For 2019, the Commission agrees with the

CCA that a reduction is warranted because there is insufficient support that the forecast work for

vegetation management must be completed in 2019. Accordingly, the Commission directs that

AET reduce the forecast vegetation management costs for 2019 by 10 per cent in its compliance

filing to this decision.

218. Further, the Commission directs AET to provide, in its next GTA, a detailed breakdown

of the savings and lower forecast expenses realized as a result of the transition by AET from a

primarily mechanically based vegetation management program to one that is primarily based on

the application of herbicides.

7.1.6 USA 575 – IT Support

219. AET is forecasting a modest cost decrease of $100,000 to USA 575 during the test

period. The reductions from 2018 to 2019 are largely associated with lower distributed

applications and support resulting from the implementation of cloud-based technology, lowering

the requirements for maintenance costs, storage and application hosting.187

220. The CCA recommended a reduction in this account of $300,000 in each of the test years.

In its rebuttal evidence, AET showed that only 37 per cent of the costs in this account vary with

the number of IT users, and the CCA accepted the premise that costs were not 100 per cent

181 Exhibit 22742-X0722, CCA final argument, paragraph 108. 182 Exhibit 22742-X0725, AET final argument, paragraph 127. 183 Exhibit 22742-X0722, CCA final argument, paragraph 105. 184 Exhibit 22742-X0722, CCA final argument, paragraph 108. 185 Exhibit 22742-X0722, CCA final argument, paragraphs 112-113. 186 Exhibit 22742-X0727, AET reply argument, paragraph 128. 187 Exhibit 22742-X0001.02, updated application, paragraph 225.


Decision 22742-D01-2019 (July 4, 2019) 52

correlated with the number of users. However, the CCA questioned the calculation of the

forecast number of users. While noting AET’s revised calculations suggesting a reduction to this

account of $100,000 for 2018 and $200,000 for 2019,188 the CCA submitted that additional

reductions may be warranted if the Commission directs reductions in AET’s FTE forecast.189

221. AET replied that it incorporated the changes in IT users and equipment in its forecast, as

demonstrated in its rebuttal evidence, and that the costs for this account should be approved as

filed.190

Commission findings

222. The Commission accepts the submission of AET that its forecast for expenses in this

account reflects a reduced number of IT users. However, the Commission directs AET to adjust

its forecast for this account based on the Commission’s determinations regarding forecast FTEs

in Section 5.1.1 of this decision.

223. Further, on June 5, 2019, the Commission issued Decision 20514-D02-2019191 regarding

the ATCO Utilities IT common matters proceeding. AET is directed to reflect any changes

arising from the directions in that decision in its compliance filing to this decision. AET is

further directed to provide schedules detailing how the determinations from Decision 20514-

D02-2019 are reflected in its compliance filing.

8 Transmission depreciation

224. In support of its forecast 2018-2019 depreciation expense calculations, AET submitted a

technical update to its depreciation rates, as of December 31, 2017. The technical update was

prepared by Larry Kennedy of Concentric Advisors ULC (Concentric)192 and used the most

recently approved depreciation parameters of average service life, Iowa curve and dispersion,

and net salvage percentages approved by the Commission in Decision 20272-D01-2016.193 These

three depreciation parameters were applied to actual December 31, 2017, plant in-service

balances for the purpose of updating AET’s depreciation rates and to derive the 2018-2019

forecast depreciation expense. Additionally, AET’s amortization of accumulated depreciation

differences amount is the same amount approved in Decision 20272-D01-2016.

225. The Commission has summarized AET’s historical and forecast depreciation expense in

the following table:

188 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 57, Table 3. 189 Exhibit 22742-X0722, CCA final argument, paragraphs 283-288. 190 Exhibit 22742-X0722, AET reply argument, paragraphs 128-131. 191 Decision 20514-D02-2019: The ATCO Utilities (ATCO Gas and Pipelines Ltd. And ATCO Electric Ltd.)

Information Technology Common Matters Proceeding, Proceeding 20514, June 5, 2019. 192 Exhibit 22742-X0001.02, updated application, Attachment 31.1, PDF pages 1047-1174. 193 Decision 20272-D01-2016, ATCO Electric Ltd. 2015-2017 Transmission General Tariff Application.


Decision 22742-D01-2019 (July 4, 2019) 53

Table 23. AET historical and forecast depreciation expense 2015-2019

2015 Actual 2016 Actual 2017 Actual 2018 Forecast 2019 Forecast

($ million)

Transmission 112.6 160.3 174.9 178.2 180.1

Amortization of reserve differences – transmission

5.3 5.4 5.4 5.3 5.3

Direct general PP&E 28.7 29.3 17.7 20.1 22.0

Farm, irrigation transmission 1.1 1.3 1.7 1.5 1.6

Total gross provision 147.7 196.4 199.7 205.2 209.1

Vehicle depreciation capitalized (3.6) (3.6) (3.1) (3.6) (3.6)

Amortization of contributions (7.8) (9.3) (9.8) (10.1) (10.4)

Total depreciation expense 136.3 183.5 186.8 191.5 195.1

Collection (refund) of previously collected capitalized pension contributions

6.2 4.0 (38.4) - -

Total depreciation expense 142.5 187.5 148.4 191.5 195.1

Source: Extracted from Exhibit 22742-X0002.04, MFR schedules 6-1 and 6-2.

226. AET stated that the increase in 2018 depreciation expense over 2017, is due to the one-

time refund of previously collected capitalized pension costs.194 195 During the years 2018 and

2019, the forecast increase in depreciation expense is due primarily to anticipated growth in rate

base.196

227. Neither the UCA nor the CCA commented on AET’s technical update or the calculation

of depreciation expense.

228. There was discussion on whether it would be reasonable for AET to change its

capitalization of salvage costs by adopting a methodology similar to that used by EPCOR

Distribution & Transmission Inc (EPCOR). AET and the CCA shared the view that such a

determination should not be made within the context of a single GTA and is best explored within

a generic-type proceeding where corollary issues such as intergenerational equity may be

examined from the viewpoint of all Alberta utilities.

229. In argument, AET addressed Alberta PowerLine’s (APL) treatment of net salvage as it

relates to the West Fort McMurray 500-kV Transmission (WFMAC) Project. AET confirmed

that APL’s commercial arrangement with the AESO precludes the collection of funds for future

net salvage costs during the 35-year contract. While the CCA submitted that this arrangement is

not in the public interest, it agreed with AET that the “treatment of the cost of salvage for the

194 Exhibit 22742-X0001.02, updated application, Attachment 3.2, Analysis of Transmission Rate Increase,

Schedule 3-2, lines 4-5 and 18-19, PDF page 126. 195 Exhibit 22742-X0001.02, updated application, paragraph 601: “… In Decision 20272-D01-2016 (para. 1311),

the AUC also directed AET to propose a method in the 2015-17 GTA Compliance Filing to refund the

accumulated difference resulting from the change in accounting treatment of capital pension costs, including

related income tax impacts. In AET’s Compliance Filing to Decision 20272-D01-2016 (Proceeding ID 22050),

the accumulated capitalized pension costs was proposed to be refunded as part of AET’s approved 2017 tariff.

On June 19, 2017, the AUC issued Decision 22050-D01-2017, which in Appendix 2, approved AET’s proposed

refund for the accumulated capitalized pension costs.” 196 Exhibit 22742-X0001.02, updated application, paragraph 67.


Decision 22742-D01-2019 (July 4, 2019) 54

WFMAC Project should be given no weight regarding how the cost of salvage should be

recovered for AET assets” particularly as the terms of the agreement were set in a competitive

process.197

Commission findings

230. The Commission has examined AET’s technical update and observes that AET has

continued to rely on the depreciation parameters and the amortization of reserve differences

amount approved in Decision 20272-D01-2016. Accordingly, and given the application and

other information on the record, the Commission finds the resulting depreciation rates and

depreciation expense calculations to be reasonable. AET’s depreciation expense is approved,

subject to any applicable findings and directions included elsewhere in this decision.

231. The Commission has examined parties’ evidence with respect to the salvage

methodologies used by EPCOR and APL. While the Commission will make no change to AET’s

depreciation methodology or depreciation rates in this proceeding, the Commission directs AET,

as part of its next depreciation study, to compare AET’s average service lives and net salvage

percentages for its five largest plant accounts (on a dollar amount basis) to those of other electric

transmission utilities in the province.

8.1 Deferral account for IFRS-related depreciation rate issues

232. AET stated that under International Financial Reporting Standards (IFRS), it is required

to review its depreciation rates annually, and to implement new depreciation rates for IFRS

purposes, if necessary. For this reason, AET requested the “ability to file an application with the

Commission seeking approval of new depreciation rates”198 through a deferral account, should

such circumstances arise.

233. When asked in an IR whether it had ever been required to update its depreciation rates (as

a result of the Commission-approved depreciation parameters) under IFRS reporting

requirements, AET responded that “There have been no years since the implementation of IFRS

where AET has not found its depreciation rates, as resulting from Commission–approved

depreciation parameters, to be in accordance with IFRS.”199

234. According to AET, an example of a circumstance that would prompt it to file an

application to seek a new depreciation rate would be a legislative change directing it to retire

diesel generation units by a certain year. This would necessitate a change in the estimated service

life of the asset and would meet the deferral account criterion of a factor affecting the forecast

that would not be under the control of the company. Such circumstances would also not be

reasonably forecastable and the resulting variance in forecast depreciation could produce a loss

or gain of significant magnitude. AET submitted that if such an instance were to occur within the

test period, it would seek approval to flow the change in depreciation expense through its IFRS

deferral account and file an updated depreciation study for the assets as part of the annual

deferral account application.200

197 Exhibit 22742-X0725, AET final argument, paragraph 159, and Exhibit 22742-X0726, CCA reply argument,

paragraphs 101-103. 198 Exhibit 22742-X0001.02, updated application, paragraph 238. 199 Exhibit 22742-X0200.02, AET-AUC-2017AUG30-002, PDF pages 2-3. 200 Exhibit 22742-X0200.02, AET-AUC-2017AUG30-002, PDF pages 2-3.


Decision 22742-D01-2019 (July 4, 2019) 55

235. During the oral hearing, AET witness, Mr. Hoshowski, confirmed that in a case where

“there would be a fundamental change in the underlying lives of those assets that would require

us to record different depreciation and review those changes in asset lives, then the utility would

seek to have deferral account treatment afforded to consider that.”201 Mr. Hoshowski did not

provide an example of circumstances that would necessitate deferral treatment beyond that

provided in AET’s IR response, but he clarified that “certainly it would be something of a

substantial nature that wouldn’t have been considered in the underlying study that was provided

in the context of the GTA or the technical update …”202

236. AET further clarified that the request to include changes to depreciation rates under IFRS

requirements would be an expansion in the scope of AET’s existing IFRS deferral account and

not the creation of a new IFRS-related deferral account.

237. Mr. Hoshowski acknowledged that the Commission had previously denied deferral

account treatment for IFRS-related changes in depreciation rates in AET’s 2013-2014 GTA.

However, he stated that there still exists an underlying need for the deferral account

notwithstanding the extensive regulatory process currently afforded to the examination of

depreciation parameters and the fact that there had been no instances of IFRS-required changes

requested in relation to depreciation rates.203

238. The Commission requested Bema’s opinion with respect to AET’s proposal for IFRS-

related deferral treatment related to the implementation of new depreciation rates, as follows:

… would a retirement “from causes not reasonably assumed to have been anticipated or

contemplated in prior depreciation or amortization provisions” include the circumstances ATCO

Electric stated it anticipates could lead to a requirement under IFRS “for its approved

depreciation parameters (and, as a result, depreciation rates) to be updated within the test period

due to a significant change in the estimated life of assets” by virtue of, for example, “a legislative

change directing AET to retire its diesel generation units by a certain year”?204

239. Bema considered there were two questions at issue: “First, does IFRS require AET to

update its approved depreciation rates used for regulatory purposes for a change such as that

contemplated in AET’s response? Second, is the Commission required to reflect such a change

for regulatory purposes through AET’s revenue requirement?”205

240. With respect to the first question, Bema stated that, based on its experience, there were

various approved methodologies for capital recovery through depreciation among Alberta

electric utilities. However, it was not aware that any utilities had identified a difference between

IFRS and regulatory accounting as it pertained to depreciation. Bema submitted that while IFRS

requires an entity to update its depreciation estimate every year, the detailed nature of a

regulatory depreciation study is adequate to meet the requirements of IFRS for a two-year test

period.

201 Transcript, Volume 5, page 818, lines 20-25. 202 Transcript, Volume 5, page 819, lines 4-9. 203 Transcript, Volume 5, pages 817-818. 204 Exhibit 22742-X0612, CCA-AUC-2018DEC19-003, PDF pages 7-9. 205 Exhibit 22742-X0612, CCA-AUC-2018DEC19-003, PDF page 8.


Decision 22742-D01-2019 (July 4, 2019) 56

241. With respect to the second question, Bema stated that, under Rule 026,206 the Commission

is not bound to reflect such a change for regulatory purposes through AET’s revenue

requirement.207

242. In argument, the CCA concluded that the Commission should deny AET’s request to

flow certain changes in depreciation rates through a deferral account within a test period. This

was based on the CCA’s view that the depreciation rates approved by the Commission are not

required to align with IFRS. The CCA stated that it appeared that “AET may also be trying to

permit changes related to extraordinary retirements that occur in a current period to be flowed

through the [IFRS-related] deferral account.”208

243. In reply argument, AET clarified that it was “not requesting a deferral account for IFRS

to deal with changes in depreciation rates,” but “requesting an extension of the current IFRS

deferral account to include changes in depreciation rates.” AET submitted that changes in

depreciation rates as a result of IFRS do meet the criterion established for the creation of a

deferral account and, therefore, its requested extension of the current IFRS deferral account was

reasonable in the circumstances and should be approved, as filed.209

Commission findings

244. In this section, the Commission makes a finding specific to AET's request to expand the

scope of its existing IFRS deferral account that would allow it to seek approval of new

depreciation rates as a result of IFRS requirements. The Commission makes no finding in this

section with respect to the operation of, or the amounts currently included in, AET’s existing

IFRS deferral account.

245. AET, in its written evidence and oral testimony during the hearing, described various

scenarios and outcomes that might precipitate an IFRS-related change to a depreciation rate. The

Commission is not persuaded that a requirement under IFRS that AET review its depreciation

rates annually is, in and of itself, sufficient to support an expansion of the existing deferral

account notwithstanding AET's claims that such requirement creates greater uncertainty in

depreciation rates.

246. Accordingly, the Commission denies AET’s request to expand the scope of its existing

IFRS deferral account to permit it to seek approval of new depreciation rates through that

account, simply because IFRS requires AET to review depreciation rates annually.

247. Having made this finding, the Commission does not need to address the evidence of AET

or the CCA with respect to whether the Commission, under Rule 026, is required to align the

depreciation rates it approves for regulatory purposes, with those reported under IFRS.

8.2 Fort McMurray wildfire

248. The Commission deferred its findings related to the Fort McMurray wildfire. As a result,

it is necessary that certain aspects of AET’s application remain outstanding as placeholder

206 Rule 026: Regulatory Account Procedures Pertaining to the Implementation of the International Financial

Reporting Standards. 207 Exhibit 22742-X0612, CCA-AUC-2018DEC19-003, PDF pages 7-9. 208 Exhibit 22742-X0722, CCA final argument, paragraph 775. 209 Exhibit 22742-X0727, AET reply argument, paragraphs 304-305.


Decision 22742-D01-2019 (July 4, 2019) 57

amounts until such time as the Commission renders its decision on matters pertaining to the Fort

McMurray wildfire. The Commission identifies the following placeholders:

(a) The proposed capital addition in 2017 of TCM Project 00073: Fort McMurray

Wildfire Transmission Asset Restoration in the amount of $7.6 million for assets

damaged and requiring restoration as a result of the wildfire.

(b) The proposed retirement of the original historical cost of AET’s asset Account 453

– Poles and fixtures destroyed and retired from service in the amount of $1.899

million.

(c) The proposed recovery of $0.664 million through AET’s amortization of reserve

differences mechanism, of the net book value of AET’s asset Account 453 – Poles

and fixtures destroyed and retired from service.

(d) The recovery of $0.321 million through AET’s RID account, for power restoration

efforts related to damage caused by the Fort McMurray wildfire.

249. Furthermore, the Commission has similarly made no finding with respect to the issue

raised by the UCA of cross-subsidization of Fort McMurray wildfire-related expenditures

between ATCO Electric Ltd.’s distribution and transmission functions.

9 Income taxes

9.1 Income tax

9.1.1 Income tax - general

250. AET uses the future income tax (FIT) method for federal income taxes and the flow-

through method for provincial income taxes. AET did not request any changes to the income tax

method used in the test period. AET stated the reason for the continuation of the calculation of

FIT for federal income tax is to support AET’s credit metrics and AET’s proposed FFO-to-debt

ratio of nine to 13 per cent.210

251. AET’s summary of the income tax expense it is seeking to recover for 2018 and 2019, as

well as the source of the observed year-over-year tax expense variance is reproduced in the table

below:

Table 24. Summary of income tax expense

2016 Actual

2017 Actual

2018 Test year

2019 Test year

($ million)

Income tax expense 36.2 38.1 34.4 40.3

Increases/(Decreases) in test period (3.7) 5.9

210 Exhibit 22742-X0001.02, updated application, paragraphs 246-247.


Decision 22742-D01-2019 (July 4, 2019) 58

2016 Actual

2017 Actual

2018 Test year

2019 Test year

($ million)

Due to:

Collection of Future Taxes on Temporary Differences

(5.3) (5.4)

Increase/(Decrease) in utility earnings (8.1) 1.6

Impact of lower/(higher) tax deductions 9.8 9.7

Increases/(Decreases) in test period (3.7) 5.9

Source: Exhibit 22742-X0001.02, updated application, Table 7.4 – Tax Expense, paragraph 266.

252. AET calculated its tax expense using the applicable federal and provincial tax rates at the

time it filed its application. The tax rates used in the calculation of income tax expense are

included in the table provided below:

Table 25. Statutory tax rates

2018 2019

(%)

Federal income tax 15.00 15.00

Provincial income tax 12.00 12.00

Source: Exhibit 22742-X0001.02, AET 2018-2019 General Tariff Application, Table 7.1 – Tax Rates, paragraph 248.

253. Temporary tax differences occur when the reporting of a revenue or expense for financial

reporting purposes differs from the reporting of the revenue or expense for income tax purposes.

For the purposes of AET’s revenue requirement, forecast temporary tax differences are included

in AET’s forecast of income tax during the test period. The temporary tax differences, if they

relate to a deferral account, would be a true-up by AET in a DACDA proceeding.

254. Bema's evidence included an analysis of AET's forecasting accuracy for taxable

temporary differences and total federal taxable income. The results of Bema’s analysis are

provided in the table below:211

211 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 628-629


Decision 22742-D01-2019 (July 4, 2019) 59

Table 26. AET’s forecasting accuracy for taxable temporary differences and total federal taxable income

AET’s historical forecasting accuracy for temporary differences

Year Variance

2013 $49.3M in higher taxable temporary differences, resulting in a variance of 38% from approved





Total $223.3M of higher taxable temporary differences, resulting in a variance of 25% from approved

AET’s historical forecasting accuracy for federal taxable income

Year Variance

2013 $38.7M lower taxable income, resulting in a variance of 241% from approved



2016 $21.0M higher taxable income, resulting in a variance of 256% from approved


Total $178.8M lower taxable income, resulting in a variance of 1,301% from approved

Source: Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 628-629.

255. Bema described AET’s historical forecasting accuracy for taxable temporary differences

and taxable income as “very low,” and noted that for every year, except 2016, the variance from

approved was to the benefit of AET.212

256. Bema conceded that a portion of the variances included in the table above would be

subject to deferral account treatment. It added, however, that it was unable to determine how

much of the variances have been, or are still to be, settled in a DACDA as a result of AET not

having up-to-date deferral account applications.213 However, Bema observed that a significant

portion of the forecast temporary tax differences are not associated with direct assigned capital

additions and, therefore, are not subject to a deferral account true-up.214

257. In Bema’s estimation, three of AET’s tax deductions are understated: stock handling,

isolated overhauls and removal and abandonment.215

258. Based on its analysis, Bema requested the Commission to direct AET to make the

following adjustments to the test years’ forecast temporary difference tax deductions:

(i) Increase stock handling by $0.5 million in both 2018 and 2019;

(ii) Increase isolated overhauls by $0.4 million in 2018 and $0.1 million in 2019; and

212 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 630. 213 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 631. 214 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 633-634. 215 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 635-636.


Decision 22742-D01-2019 (July 4, 2019) 60

(iii) Increase removal and abandonment by $2.0 million in both 2018 and 2019.216

259. In its rebuttal evidence, AET argued that Bema failed to explain why 2017 should be

used as a benchmark for the 2018 and 2019 forecast stock handling, isolated overhauls and

removal and abandonment deductions. Based on its 2013 to 2017 actual tax deductions for stock

handling, isolated overhauls and removal abandonment, AET stated that there is no year-over-

year pattern that should lead to basing the tax deductions for stock handling, isolated overhauls

and removal and abandonment on any specific year. AET explained how it developed its stock

handling, isolated overhaul, and removal and abandonment forecasts, and why 2017 actual

results have no bearing on corresponding amounts in 2018 and 2019:

• Stock Handling - Stock handling charges relate to overhead costs of procurement,

handling and warehousing of inventory. The forecast is dependent on the capital

program forecasted each year. As the capital program differs from year to year (i.e.

planning, engineering, or construction), so does the deduction for stock handling,

therefore 2017 actuals are unlikely to appropriately reflect a reasonable estimate for

the 2018 and 2019 forecasts.

• Isolated Overhauls – Isolated overhauls relate to the refurbishment of isolated

generation units. The forecast is based on the determination of asset condition and

regulatory compliance of the isolated generation assets. The isolated generation

assets that were determined to require refurbishment in 2017 are not necessarily the

same assets identified in the 2018 and 2019 forecasts. Therefore, the forecasts for

2018 and 2019 are developed independently. An illustrative example of why prior

periods can not be used as a basis for the current period forecast are the isolated

overhauls for Jasper Palisades generating units. With the interconnection of Jasper

occurring in 2019, AET is not forecasting isolated overhauls at Jasper Palisades in

2018 or 2019. However, AET completed required isolated overhauls in prior periods

at Jasper Palisades and reflected the income tax deduction. Please refer to the

business case filed in Exhibit 22742-X0171.03 for Project 90130: 2018-2019

Refurbish/Replace Engines for details of the forecasted isolated overhauls for 2018

and 2019.

• Removal and Abandonment – Removal and abandonment relates to the costs incurred

for the demolishing, dismantling, tearing down or removing of an asset from its

original location or position. The deduction is based on the estimated cost of

retirement forecast for capital assets that are coming to an end of their useful life. The

capital assets in 2017 that came to an end of their useful life would not be the same

assets that are coming to an end of their useful life in 2018 or 2019. Therefore, the

forecasts for 2018 and 2019 are developed independently of 2017 actuals.217

260. The CCA argued that the increased stock handling, isolated overhauls and removal and

abandonment tax deductions, as recommended in Bema’s evidence, are reasonable given that

AET has failed in its onus to show that “its forecast is reasonable and not understated.”218 219 The

CCA also noted that there were upcoming provincial and federal elections that may result in

216 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 637. 217 Exhibit 22742-X0618, AET rebuttal evidence to CCA and UCA, PDF pages 174-175. 218 Exhibit 22742-X0722, CCA final argument, paragraph 702. 219 Exhibit 22742-X0722, CCA final argument, paragraphs 701-704.


Decision 22742-D01-2019 (July 4, 2019) 61

changes to income tax rates. It recommended that the Commission direct AET to update its

income tax rates to the statutory rates in place at the time of its compliance filing.220

261. AET, in reply argument, stated that it has clearly demonstrated that its income tax

forecast “is activity-based and is tied to the underlying Capital Program that is driving the

various forecast income tax deductions.”221

Commission findings

262. In response to a Commission IR, Bema calculated the impact of its recommended

adjustments to the stock handling, isolated overhauls and removal and abandonment tax

deductions to be a reduction of $0.3 million per year to AET’s revenue requirement.222 The CCA

acknowledged that the revenue requirement impact of its recommendation is not as great as that

of other recommendations it has made, however, it submitted that “it remains inappropriate for

AET to continuously and consistently over earn above its approved income taxes” and that “[t]he

Commission is required to ensure that all forecast costs are just and reasonable and this includes

AET’s income taxes.”223

263. The Commission notes AET’s forecasts of the stock handling, isolated overhauls and

removal and abandonment tax deductions are based on its forecast capital work. As described in

Section 11 – capital projects, the Commission found AET’s capital forecasts to be reasonable.

Included in those approved capital project costs are expenses such as stock handling, isolated

overhauls and removal and abandonment. The Commission finds there is no need to alter these

expenses as it cannot divorce the review of these expenses from the corresponding tax

deductions. As a result, the Commission denies the CCA’s recommendations.

264. In its forecast, AET used a 15 per cent tax rate for federal income taxes and a 12 per cent

tax rate for provincial income taxes for both 2018 and 2019. The Commission approves the 2018

applied-for tax rate of 15 per cent for federal income tax and 12 per cent for provincial income

tax. The Alberta government, in Bill 3: Job Creation Tax Cut (Alberta Corporate Tax

Amendment) Act,224 reduced the general provincial corporate tax rate from 12 per cent to 11 per

cent. Bill 3 came into force on June 28, 2019 and amends sections 21 and 22 of the Alberta

Corporate Tax Act, changing the provincial tax rate as of July 1, 2019. The Commission takes

notice of the Legislative Assembly of Alberta’s passing of Bill 3 and directs AET, in its

compliance filing, to adjust for any changes in its provincial tax rate.

265. Given that AET’s request to maintain federal FIT is related to maintaining support for its

credit metrics, the Commission’s determination on AET’s continued use of FIT will be made in

the credit metric portion of this decision.

220 Exhibit 22742-X0726, CCA reply argument, paragraphs 112-113. 221 Exhibit 22742-X0727, AET reply argument, paragraph 157. 222 Exhibit 22742- X0612, CCA-AUC-2018DEC19-013, PDF page 35. 223 Exhibit 22742-X0722, CCA final argument, paragraph 698 224 https://open.alberta.ca/dataset/8597b610-1826-43d5-bdb1-3f5ba938875d/resource/7fce8356-f05f-4fd5-a84e-

cc7364f43c77/download/special-notice-ct-vol-5-no-52-job-creation-tax-cut.pdf


Decision 22742-D01-2019 (July 4, 2019) 62

9.1.2 Allowance for funds used during construction

266. The financing or interest cost of a capital investment that occurs during the construction

of a capital project is accumulated and capitalized. This financing or interest cost is called an

allowance for funds used during construction (AFUDC).

267. AFUDC is discussed in this section because it is included in the calculation of income tax

expense. It would appear from the examples and calculations provided in the tables in this

section, in turn, that AET's current treatment of AFUDC for the purposes of calculating its

income tax expense, involves either:

Charging customers current tax expense by adding AFUDC to the total utility earnings

before tax, as exhibited by the differences in current tax expense in the “Build”

columns [(33.2) in Table 29 compared to 0.0 in Table 27 for each “Build” year]; or

Removing AFUDC from its undepreciated capital cost pool and charging customers

current tax expenses over the asset's service life, as demonstrated by the differences in

the current tax expense total [0.0 in Table 28 compared to 66.5 in Table 27].

268. An AET witness, Mr. Hoshowski, was questioned about the AFUDC amounts included in

the calculation of AET’s income tax expense in schedules 7-3 “Determination of Federal

Taxable Income” and 7.4 “Schedule of Transmission Capital Cost Allowance” of the application

found at Exhibit 2.04 and a corresponding IR response at Exhibit 417 (IR 12).225 With respect to

IR 12:

Q. My general understanding of utility earnings before tax is it is regulated revenue

minus operating expenses. Is that right?

A. MR. HOSHOWSKI: Yes, I would agree with that characterization.

Q. How is AFUDC regulated revenue?

A. MR. HOSHOWSKI: It's a regulated revenue in the sense that at some future point,

that will be collected from customers when those balances are being applied to the

underlying capital projects that they're attributable to. So this is recognizing in the period

for which AFUDC arose that it's appropriately added to the utility earnings.

Q. Moving down to the "add/deduct" section on line 70 which is titled "AFUDC," why

has ATCO Electric deducted 11.7 million of AFUDC in the calculation of taxable

income?

A. MR. HOSHOWSKI: So in terms of the deduction, the AFUDC is recognized as an

overhead cost to the capitalized item. So it's deducted in the current period given that it's

overhead in nature.

A. MR. HOSHOWSKI: But -- sorry. Regardless, on our CCA schedules, when this -- in

the 2019 period, when this deduct is taken in the aforementioned line 70 and recognized

that it's a current period expense and the deduction is taken there, the equivalent offset to

the CCA amount that's being claimed in that period is also adjusted for that AFUDC

225 Transcript, Volume 5, page 807, line 8 to page 813, line 5, and Transcript, Volume 6, page 877, line 6 to

page 878, line 24.


Decision 22742-D01-2019 (July 4, 2019) 63

amount, recognizing that it was already taken as a deduction in the current period. So the

UCC balance, moving forward, would reflect that.

269. Commission counsel then referred Mr. Hoshowski to Schedule 7.4, the schedule for

transmission capital cost allowance, and he explained the difference between schedules 7.3 and

7.4 in terms of the recording of CWIP and AFUDC:

A. MR. HOSHOWSKI: No, these are different amounts, and I'll walk you through the

difference in terms of what's reflected on Schedule 7-3 versus this 7-4 schedule for

AFUDC. So the amount being considered within Schedule 7-3 is the AFUDC that arises

and applied to those projects in the current period that may or may not be going into

service. So that represents the amount of AFUDC that is I'll call it or characterize it as

created when we look at the underlying projects that have construction work in progress

balances for that test period. The amount that shows up on Schedule 7-4 is the actual

amount of AFUDC that has been capitalized to these projects that have gone into service

in 2018 -- sorry, in 2019. So that's the differentiation. It's reflective, I guess, of when

those assets go into service. So recognizing that some assets might go into service the

year that that work commences or that some assets might go into service over a longer

two-year timeframe. Once those assets go into service and we claim the CCA tied to

those assets, the AFUDC that's taken and reflected on this schedule is the amount that's

gone into service for that project in its entirety.

Q. And if we could go back to Schedule 7.7-3 [sic; Schedule 7.3] under the 2019 test

period. Line 71 is titled "CCA-Federal" with CCA, of course, referring to capital cost

allowance. The amount deducted for CCA on line 71, which is 304.3 million, does not

include amounts related to AFUDC because these amounts are previously removed from

the UCC pool; is that right?

A. MR. HOSHOWSKI: That's correct.

Q. ATCO Electric adds the accumulated AFUDC costs incurred on a project to the costs

of a project; correct?

A. MR. HOSHOWSKI: Correct.

Q. And then AFUDC gets added to ATCO Electric's rate base, and it is eventually

recovered through depreciation.

A. MR. HOSHOWSKI: It's recovered through both depreciation and return, yes.

Q. And staying on Schedule 7-3, line 69 is titled "Depreciation/Amortization of

Contributions." That depreciation amount would include some portion of capitalized

AFUDC that was added to the costs of a project; correct?

A. MR. HOSHOWSKI: Yes, that's correct.

Q. So based on our discussion, it appears that ATCO Electric adds AFUDC twice for the

purposes of adjusting income for tax -- sorry, twice for the purposes of adjusting income

for tax purposes: first when the amount of AFUDC is added to utility earnings before tax,

and second, on an annual basis for the portion of AFUDC that is being depreciated

through the life of an asset. However, ATCO Electric only deducts AFUDC once in the

year the cost's incurred, which creates a tax expense payable from which ATCO Electric

collects its revenue requirement. Is that right?


Decision 22742-D01-2019 (July 4, 2019) 64

A. MR. HOSHOWSKI: There's a bit to digest there, Ms. Graham. And without perhaps

further thinking this process through in terms of how AFUDC flows from the onset or its

creation all the way to this end point and how it's factored into the determination of our

various add-backs and deducts within the test period, I'll take your assertion as being

accurate subject to check. …

Transcript Volume 6, page 877, line 6 to page 878, line 24:

A. MR. HOSHOWSKI: Good morning. I just have a couple of transcript corrections I just wanted

to provide on the record for clarity. And that I would just like to, subsequent to that, address a

subject to check following a discussion on Friday that I had with Ms. Graham.

…..

The subject to check that I would like to discuss as contained in the transcripts, Volume

5, at page 813, this was a discussion that I was having with Ms. Graham on the topic of

AFUDC and the underlying tax treatment. The question posed to me by Ms. Graham

starts at line 13 of 812 of the transcripts, and it is as follows:

So based on our discussion, it appears that ATCO Electric adds AFUDC twice for the

purposes of adjusting income for tax -- sorry, twice for the purposes of adjusting income

for tax purposes: first when the amount of AFUDC is added to utility earnings before tax,

and second, on an annual basis for the portion of AFUDC that is being depreciated

through the life of an asset. However, ATCO Electric only deducts AFUDC once in the

year the cost's incurred, which creates a tax expense payable from which ATCO Electric

collects its revenue requirement. Is that right?"

So after reviewing the transcripts and reviewing our historical treatment of AFUDC, I

would disagree that it creates a tax payable, and the disagreement comes as the other

deduction occurs when depreciation expense is included in utility earnings before tax.

Thank you.”

270. In its argument, AET summarized its discussion with Commission counsel regarding the

treatment of AFUDC as follows:

AFUDC is included in the calculated total of utility earnings, before tax, to ensure that

there is no impact on utility earnings or revenue requirement from the corresponding tax

deduction, as AFUDC is a form of a non-cash capitalized interest and it is deductible for

income tax purposes. This ensures that the AFUDC deduction has a corresponding

addition to net the tax impact to zero, as AFUDC not collected when incurred, but rather

over the life of the asset when the project is included in Rate Base. Likewise, when

calculating future taxes, the revenue (or utility earnings before tax) directly attributable to

AFUDC is not a component of the future income tax calculations and, as such, the

AFUDC revenue line item is not included, even though it is identified as a temporary

item on Schedule 7-3. AET submits that this is not a new practice and has been applied

similarly in past revenue requirement calculations. [footnotes removed]226

271. Based on the discussion between the AET witness and Commission counsel, provided

above, the Commission has prepared an illustrative calculation of income tax using AET’s

current methodology for treatment of AFUDC:

226 Exhibit 22742-X0725, AET final argument, paragraph 165.


Decision 22742-D01-2019 (July 4, 2019) 65

Table 27. Calculation of income tax using AET’s current methodology for treatment of AFUDC, based on Mr. Hoshowski’s exchange with Commission counsel

Build In-service Total Yr-2 Yr-1 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10

Revenue 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Depreciation (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (246.2)

Net income - - - - - - - - - - - - -

AFUDC 123.1 123.1 - - - - - - - - - - 246.2

Utility earnings before tax

123.1 123.1 - - - - - - - - - - 246.2

Add/Deduct

Depreciation - - 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Capital cost allowance - - - - - - - - - - - - -

AFUDC (123.1) (123.1) - - - - - - - - - - (246.2)

Taxable income - - 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Current tax [(Taxable income * 15% federal tax rate) + (taxable income * 12% provincial tax rate)]

- - 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 66.5

Future income tax expense (Taxable income * -15% federal tax rate)

18.5 18.5 (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) -

Assumptions used for calculations: Rate base = 246.2 AFUDC from ATCO Electric's originally proposed CWIP-in-rate base refund. 10-year asset for depreciation, no mid-year convention used for simplicity. Eight-year asset for tax deduction purposes (capital cost allowance), no mid-year used for simplicity. Revenue = the recovery of depreciation component in revenue requirement. WACC = 0% to remove impacts of return.

272. In its argument, AET stated that “AFUDC is included in the calculated total of utility

earnings, before tax, to ensure that there is no impact on utility earnings or revenue requirement

from the corresponding tax deduction, as AFUDC is a form of a non-cash capitalized interest and

it is deductible for income tax purposes.”227 The Commission has reflected this statement in the

“Build” columns of the Table 27.

273. As confirmed by the AET witness, AFUDC is included in the cost of a capitalized project

and, as a result, forms a portion of AET’s depreciation expense.228 AET, through its revenue

requirement, receives amounts to compensate it for this expense. These amounts have been

reflected in the “Revenue” and “Depreciation” lines in calculating the “Net Income” and “Utility

Earnings Before Tax” totals in Table 27.

274. Depreciation expense is subtracted from revenue to arrive at a net income for financial

reporting purposes. However, for the purposes of calculating a company’s income to determine

227 Exhibit 22742-X0725, AET final argument, paragraph 165. 228 Transcript, Volume 5, page 811, line 25 to page 812, line 12.


Decision 22742-D01-2019 (July 4, 2019) 66

its taxes payable, depreciation expense is not permitted to be deducted. Instead, the federal and

provincial governments permit a company to deduct a “capital cost allowance” for the purposes

of calculating taxable income. In Table 27 above, the Commission has added back AET’s

depreciation expense to arrive at the “Taxable Income” from which the federal and provincial tax

rates are then applied. As confirmed by the AET witness, amounts related to AFUDC do not

accumulate in the UCC pool. Therefore, a capital cost allowance deduction is not taken because

the AFUDC deduction has already been taken (as reflected in the “Build” columns).229

275. The Commission used the same information, as described above, but instead of adding

AFUDC to the “Utility Earnings Before Tax” and deducting AFUDC in the year the capitalized

interest was incurred (the “Build” period), the Commission assumed that the AFUDC amount

was added to the undepreciated capital cost (UCC) pool along with the rest of the project costs at

the time the asset was placed in service, and amortized over a theoretical eight-year period

(capital cost allowance). As demonstrated in Table 28 below, the addback of depreciation and

deduction of the capital cost allowance related to the AFUDC, over the life of the asset, results in

a current tax expense total of zero and a future income tax expense total of zero.

229 Transcript, Volume 5, page 809, line 8 to page 811, line 24.


Decision 22742-D01-2019 (July 4, 2019) 67

Table 28. Calculation of income tax if AFUDC was treated the same as other capital project costs when the asset was put into service

Build In-service

Total Yr-2 Yr-1 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10

Revenue 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Depreciation (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (246.2)

Net income - - - - - - - - - - - - -

AFUDC - - - - - - - - - - -

Utility earnings before tax

- - - - - - - - - - - - -

Add/Deduct

Depreciation - - 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Capital cost allowance related to AFUDC

- - (30.8) (30.8) (30.8) (30.8) (30.8) (30.8) (30.8) (30.8) - - (246.2)

AFUDC - - - - - - - - - - -

Taxable income - - (6.2) (6.2) (6.2) (6.2) (6.2) (6.2) (6.2) (6.2) 24.6 24.6 -

Current tax [(Taxable income * 15% federal tax rate) + (Taxable income * 12% provincial tax rate)]

- - (1.7) (1.7) (1.7) (1.7) (1.7) (1.7) (1.7) (1.7) 6.6 6.6 -


- - 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 (3.7) (3.7) -


276. The same outcome, where the total current tax and total future income tax expenses equal

zero as was the case in Table 28, can be similarly achieved with AET’s practice of deducting

AFUDC in the year the capitalized interest occurs, by removing the AFUDC amount that AET

adds to its “Utility Earnings Before Tax,” as demonstrated in Table 29 below:


Decision 22742-D01-2019 (July 4, 2019) 68

Table 29. Calculation of income tax if AFUDC deduction was taken in year incurred but AFUDC not added to utility earnings before tax

Build In-service Total

Yr-2 Yr-1 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10

Revenue 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Depreciation (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (24.6) (246.2)

Net income - - - - - - - - - - - - -

AFUDC - - - - - - - - - - -

Utility earnings before tax - - - - - - - - - - - - -

Add/Deduct

Depreciation - - 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 246.2

Capital cost allowance - - - - -

AFUDC (123.1) (123.1) - - - - - - - - - - (246.2)

Taxable income (123.1) (123.1) 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 -

Current tax [(Taxable income * 15% federal tax rate) + (Taxable income * 12% provincial tax rate)]

(33.2) (33.2) 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 -


18.5 18.5 (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) (3.7) -


277. It would appear from the explanation provided in paragraphs 268 and 269 above, and

based on the examples and calculations provided by the Commission in tables 27, 28 and 29, that

there may be an error in AET’s treatment of AFUDC for the purposes of calculating its income

tax expense.

Commission findings

278. In the CCA’s reply argument, it acknowledged that it had not reviewed AET’s method

for calculating AFUDC in its income taxes, and recommended that the Commission allow for

further review of AET’s accounting of AFUDC in its income taxes in the compliance filing.230

The Commission sees merit in the CCA’s request. AET is directed to demonstrate in its

compliance filing to this decision, using the information that is currently available on the record

of this proceeding, that its treatment of AFUDC in its calculation of income tax expense does not

involve either of the two potential errors described in paragraph 267 above.

230 Exhibit 22742-X0726, CCA reply argument, paragraphs 110-111.


Decision 22742-D01-2019 (July 4, 2019) 69

279. In its argument, AET stated that it has treated AFUDC similarly in the past.231 AET is

directed, in its compliance filing to this decision, to provide a proposal to correct any prior

AFUDC-related errors in its calculation of income taxes, which were subsequently collected

through revenue requirement in prior years.

9.2 Income tax deferral accounts

280. AET requested continuance of two income tax deferral accounts - statutory tax rates and

deductions of deferral for tax purposes. AET requested discontinuance of two income tax

deferral accounts - capital repair costs and deductible capital costs.

281. In Decision 2010-189,232 the Commission considered the following criteria when

evaluating the need for a deferral account:

materiality of the forecast amounts

uncertainty regarding the accuracy and ability to forecast the amounts

whether or not the factors affecting the forecasts are beyond a utility’s control, and

whether or not the utility is typically at risk with respect to the forecast amounts.233

282. In addition, the Commission has also considered a symmetry factor, as described below:

In another Board decision, also referenced in Decision 2003-100, the Board, when

examining the merits of an application for a deferral account on the facts of that

proceeding, took the view that “deferral accounts should not be for the sole benefit of

either the company or the customers.” Deferral accounts, rather, should “provide a degree

of protection to both the Company and the customers from circumstances beyond their

control,” and hence “[s]ymmetry must exist between costs and benefits for both the

Company and its customers.” The Board also noted that it expected that “the individual

mechanisms involved in the use of each deferral account should be applied in a consistent

and fair manner in both test years and non-test years”.234

283. In Decision 22570-D01-2018, the 2018 Generic Cost of Capital decision, the

Commission commented on the evaluation of income tax deferral accounts, as follows:

The Commission finds that the five criteria listed by the ATCO Utilities should form the

basis upon which any deferral accounts for income taxes for the transmission utilities

should be decided. In addition, the Commission considers that the symmetry factor

detailed in paragraphs 71-74 of Decision 2010-189 should also be considered, as

“symmetry must exist between costs and benefits for both the Company and its

customers.” However, the Commission will not make any specific findings with respect

to income tax deferral accounts for the transmission utilities in this decision. The

Commission considers that determinations with respect to tax deferral accounts for the

transmission utilities are best made on the basis of a utility’s specific circumstances and

on a case-by-case basis, and considering the criteria articulated in this decision.235

231 Exhibit 22742-X0725, AET final argument, paragraph 165. 232 Decision 2010-189: ATCO Utilities, Pension Common Matters, Proceeding 226, Application 1605254-1,

April 30, 2010. 233 Decision 2010-189, paragraph 72. 234 Decision 2010-189, paragraph 73. 235 Decision 22570-D01-2018: 2018 Generic Cost of Capital, Proceeding 22570, August 2, 2018, paragraph 116.


Decision 22742-D01-2019 (July 4, 2019) 70

284. The Commission will address AET’s deferral accounts in the subsections that follow in

accordance with the above deferral account test.

9.2.1 Deferral accounts AET is seeking to continue

9.2.1.1 Statutory rates deferral account for income tax

285. In testimony, Mr. Hoshowski confirmed that the intention of this deferral account is

purely to account for the statutory income tax rates levied both at the provincial and the federal

level.236 As shown in Table 2 above, AET used the statutory tax rates of 15 per cent in both 2018

and 2019 for federal income tax and 12 per cent for provincial income tax. AET stated that it

would apply carrying costs for income tax to adjustments recorded in the deferral account, in

accordance with Rule 023.237 AET requested that it be allowed to continue the statutory rate

deferral account, as income tax rates are subject to change.238

Commission findings

286. The Commission accepts AET’s submissions that the statutory rates deferral account for

federal income tax and provincial income tax, are subject to change, are beyond the utility’s

control, the forecast amounts can be material, there is uncertainty regarding the ability to forecast

the amounts and the utility is at risk for forecast income tax amounts. Also, the symmetry test is

satisfied because this account provides a degree of protection to both the utility and the

customers from circumstances beyond their control i.e., statutory tax rates. For these reasons, the

Commission approves the continuation of AET’s statutory rates deferral account.

9.2.1.2 Deduction of deferrals for income taxes

287. In its application, AET described the genesis of the deduction of deferrals for income

taxes:

The deducting of deferrals for income tax purposes stems from Commission Decision

2001-93 on the 2000 Pool Price Deferral Accounts proceeding. In that decision, the

Commission directed ATCO Electric to calculate the loss carry forward and the effect on

income tax payable in 2001 to 2002 taking into account the collection of revenues in

2002. That decision, in essence, instructed ATCO Electric to pursue the tax treatment of

deferrals so that any deferrals not collected during the year could be used as an income

tax deduction. Once these deferrals were collected in future years, they would be added to

taxable income. As a result of deducting the 2000 deferrals for income tax purposes, AET

now is required to apply this tax treatment to deferrals on an ongoing basis.239

288. No party objected to the continuation of this deferral account.

Commission findings

289. The Commission agrees with AET that this deferral account is still required. This account

continues to meet the five deferral account criteria specified in Decision 2010-189. Accordingly,

the Commission approves AET's request to continue the deduction of deferral for income taxes

account.

236 Transcript, Volume 5, page 806 line 20 to page 807 line 7. 237 Exhibit 22742-X0001.02, updated application, paragraph 254. 238 Exhibit 22742-X0001.02, updated application, paragraph 253. 239 Exhibit 22742-X0001.02, updated application, paragraph 255.


Decision 22742-D01-2019 (July 4, 2019) 71

9.2.2 Deferral accounts AET is seeking to discontinue

290. In its application, AET claimed that the probability of significant benefit accruing to, or

significant harm befalling, itself or its customers from the removal of two deferral accounts (one

for capital repair costs and one for deductible capital costs), was low. Therefore, it requested that

these deferral accounts be discontinued.240 Both of these accounts adjust for capital costs; capital

repair costs are a subset of deductible capital costs. Because these accounts are interrelated, the

Commission has described and included argument on these accounts separately in the

subsections below but the Commission findings jointly address these accounts.

9.2.2.1 Capital repair costs deferral account

291. In terms of AET’s deferral account for capital repair costs, AET explained that capital

repair costs are capital expenditures that are permitted to be deducted in the year they are

incurred.241 The capital repair cost deferral account refunds or collects the differences between

the capital repair amounts forecast to be claimed, as tax deductions, in the test period and the

actual amounts claimed, as tax deductions.242

292. AET prepared the following breakdown of historical and forecast capital repair costs:243

Table 30. 2014-2017 actual and 2018-2019 forecast capital repair costs

Line 2014 2015 2016 2017 2018 2019

No. Type of capital repair Actual Actual Actual Actual Forecast Forecast

($ Million)

1 Capital Maintenance

2 Life Extension 0 1.3 0.7 6.2 2.6 2.8

3 Replacement - - - - 0.5 0.3

4 Safety/Environment 4.4 3.3 1.9 1.9 4.1 0.4

5 Mitigate Equipment Problems - - - - - -

6 Pole Treatment 0.3 0.5 0.1 0.1 - -

7 Cathodic Protection 0 0.1 - 0 - -

8 Study 0 0 2.4 0.1 0.2 0.2

9 Total Capital Repair Costs 4.7 5.1 5.1 8.3 7.4 3.7

Source: Exhibit 22742-X0001.02, updated application, paragraph 263, Table 7.2 – Capital Repair Costs.

293. AET stated that the prior four years of true-up balances were immaterial. There was a

2014 refund of $100,000, a 2015 refund of $700,000, a 2016 refund of $200,000 and a 2017

refund of $800,000.244

240 Exhibit 22742-X0001.02, updated application, paragraph 265. 241 As outlined in Rainbow Pipe Line Co v Canada, [1999] TCJ No 604 and Rainbow Pipe Line v Canada, [2002]

FCJ No 92. 242 Exhibit 22742-X0001.02, updated application, paragraph 262. 243 Exhibit 22742-X0001.02, updated application, paragraph 263. 244 Exhibit 22742-X0001.02, updated application, paragraph 264.


Decision 22742-D01-2019 (July 4, 2019) 72

294. Bema noted that the total refund to customers from 2014-2017 was a cumulative $1.8

million and recommended that the deferral account treatment for capital repair costs be

continued. Bema supported the continuance of this deferral account based on the following:

(i) AET’s historical forecasting accuracy for these costs is poor and suggests that AET has

minimal control over the actual costs that are incurred;

(ii) In the last four years, there have been consistent refunds to customers, which suggests

that removing the deferral account may result in increased risks of ratepayers paying a

greater amount of costs than are truly required;

(iii) AET’s 2018 and 2019 forecast of costs do not appear reasonable in comparison to the

actual costs incurred from 2014 to 2017, with the 2019 forecast particularly

appearing to be understated. This fact supports the conclusion that continued

uncertainty exists in the forecast costs; and

(iv) The refunds under the deferral account have not been immaterial.245

295. AET stated that during the past ten years, the capital repair cost deferral account has

resulted in $1.0 million being collected from customers, which works out to $0.1 million per year

on average. AET pointed out that its capital repair cost income tax deductions represent an

impact on revenue requirement of $1.3 million and $0.7 million for the 2018- and 2019 test

years, respectively. AET stated that the revenue requirement impact of its capital repair costs, as

a percentage of total forecast revenue requirement, is substantially lower than the equivalent

percentages for fuel that led to the removal of its fuel deferral account in Decision 2013-358.246

AET argued that it fully justified its request to discontinue the “Capital Repair Costs” deferral

account as the amounts are immaterial and the amounts can be forecast with certainty.

296. The CCA referred to Bema’s revised position contained in its response to a Commission

IR247 that variances in the approved versus actual costs are likely due less to AET’s lack of

control and due more to poor forecasting on the part of AET. The CCA stated that “if the

Commission removes the deferral account treatment, the forecast for capital repair costs, in 2018

and 2019, should be at least equal to the 2017 capital repair costs of $8.3M or equal to 9.1% (the

2017 percentage of capital maintenance costs) of the 2018 and 2019 forecast capital maintenance

dollars, which would be $9.3M and $9.7M.”248

9.2.2.2 Income tax deductible capital costs deferral account

297. AET explained that the income tax deductible capital cost deferral account is in place to

address any changes in how various items (which are listed below) are treated in the test period

245 Exhibit 22742-X0592, paragraphs 106-112. 246 Decision 2013-358: ATCO Electric Ltd. 2013-2014 Transmission General Tariff Application, Application

1608610-1 Proceeding 1989, September 24, 2013, paragraph 38, where the forecast fuel costs representing

approximately 1.3 per cent of the total forecast revenue requirement and in 2014 the corresponding figure is

approximately 1.1 per cent, where these percentages were not found to be significant. 247 Exhibit 22742-X0612, CCA-AUC-2018DEC19-007(b), PDF page 18. 248 Exhibit 22742-X0722, CCA final argument, paragraph 98.


Decision 22742-D01-2019 (July 4, 2019) 73

as a result of a federal tax filing with the Canada Revenue Agency (CRA). Any future changes

would be captured in this deferral account.249

298. The items that are currently included in this deferral account are:

Gross Additions;

AFUDC;

Increase in Extension Contributions;

Depreciation on Automotive Equipment;

Meals and Expenses;

Engineering, supervision and general (ES&G) Running Costs;

Stock Handling Costs;

Easement Costs (Rights of Way);

Capital Repair Costs;

Isolated Overhauls Capitalized; and

Dismantling Costs (Removal and Abandonment).250

299. In justifying its request for the removal of this deferral account, AET stated, “Since the

inception of this deferral account in 2009, no deferral balances have arisen over the period, up to

and including 2017 as there have been no changes in how the above referenced items were

treated from those as advanced in the various approved test periods.”251 AET further stated that

given there has been no change in the treatment of these items by AET and no changes are

anticipated in the test period, it was seeking to discontinue this deferral account.

300. Bema recommended that the Commission deny AET’s request to discontinue the deferral

account for deductible capital costs. Bema stated that AET “cannot control whether the

Government of Canada implements changes or whether the CRA’s interpretation of the tax

treatments changes over time.”252 253

Commission findings

301. The capital repair costs deferral account is a subset of the income tax deductible capital

costs deferral account, and the Commission considers that both deferral accounts are still

required. In Decision 2009-215,254 the Commission made the following determinations:

67. AE’s current Capital Repair Cost deferral account, referenced in AE’s Argument,

captures part of a broader category of costs which may be capitalized for accounting

purposes but deducted as an expense for income tax purposes (referred to hereinafter as

249 Exhibit 22742-X0001.02, updated application, paragraph 259. 250 Exhibit 22742-X0001.02, updated application, paragraph 260. 251 Exhibit 22742-X0001.02, updated application, paragraph 261. 252 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 144. 253 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 143-146. 254 Decision 2009-215: ATCO Electric Ltd., 2009-2010 General Tariff Application – Regulatory Treatment of

Income Tax Refund, Proceeding 86, Application 1578371-1, November 12, 2009.


Decision 22742-D01-2019 (July 4, 2019) 74

“Income Tax Deductible Capital Costs”). The Rainbow Pipeline and Canderel decisions

addressed examples of costs that fall within this broader category. Since the flow-through

income tax method is used by AE, this requires AE to evaluate these types of potential

deductions.

68. The Commission notes the conflicting incentives and imbalance that arise

between shareholders and customers when customer rates are finalized but income tax

reassessments and refunds may be requested and received by a utility outside of the test

years. While the income tax legislation and its regulations allow for retroactive changes

to be made in the calculation of income tax expense resulting in an income tax refund to

the benefit of shareholders, the Commission must adhere to the principle against

retroactive ratemaking, the prospectivity principle and the principle of regulatory

certainty.

69. The Commission considers that, without an expansion of the scope of AE’s

Capital Repair Cost deferral account, similar circumstances may arise in the test years

and in the future wherein capitalized costs may be permitted to be expensed for income

tax purposes, similar to the circumstances in which the Additional Deductions were

taken, and with a similar result…

70. The Commission finds that the use of the Income Tax Deductible Capital Cost

deferral account will allow AE to continue to pursue income tax deductions for use with

the flow-through income tax method and mitigate the risk that the CRA might disallow

these deductions. As was recommended by the UCA, the Income Tax Deductible Capital

Cost deferral account will address substantive changes for this broader group of income

tax deductions while not delaying their implementation until the next GTA application.

ATCO Electric Ltd. amend the scope and change the name of its existing Capital

Repair.255 [footnotes removed]

302. In that decision, the Commission also ordered ATCO Electric Ltd. to amend the scope

and change the name of its existing capital repair cost deferral account to include all income tax

deductible capital costs, effective January 1, 2009.256

303. During the hearing in the current proceeding, Mr. Hoshowski provided testimony

regarding income tax legislation and its regulations allowing retroactive changes to be made in

the calculation of income tax expense and the logistics associated with retroactive adjustments:

A. MR. HOSHOWSKI: Yes, that provision remains unchanged with the ability of the

taxable entity to go back and file or refile a tax return for a certain period with the

underlying consideration for a reassessment of certain line items.

Q. And do you know how many years you can go back?

A. MR. HOSHOWSKI: My understanding is seven, subject to check.

Q. Do conflicting incentives and imbalances arise between shareholders and customers

when customer rates are finalized but income tax reassessments and refunds may be

requested and received by a utility outside of the test years?

A. MR. HOSHOWSKI: Certainly those were the considerations before the Commission

previously, which brought the inception of this deductible capital cost deferral account

255 Decision 2009-215, paragraphs 67-70. 256 Decision 2009-215, paragraphs 72.


Decision 22742-D01-2019 (July 4, 2019) 75

back in the 2009 period and issued under AUC Decision 2009-215. It has been our

experience over this timeframe that ATCO Electric, subject to check, has not sought

reassessments with regards to the filed positions for income tax deductions since that

deferral account arose.

Q. So do those conflicting incentive and imbalances still remain, or are you saying it just

hasn't -- because it hasn't happened since the deferrals were put in place, those are

minimized?

A. MR. HOSHOWSKI: So, yes, as we -- as we sit here today, there hasn't been anything

in terms of us going back as a result of new findings with regards to the various

deductions that we take for tax purposes. And I'm not aware of anything going forward.

Certainly in terms of the context of the test period that's before us, once again, I'm not

aware of any changes in positions or new tax rulings that are out there with regards to the

deductions that we have. Once -- or if a case arises where there is a new deduction that

arises, certainly on a go-forward basis, we would take that deduction and reflect that in

our income tax for that current period and then move forward, carrying forward with that

same deduction into future test periods. So to the extent that, yes, a utility could find new

deductions or new deductions arise in the test period, the utility would be incented to find

those with, of course, the future benefits of that accruing to -- accruing to customers

thereafter.257

304. Part of the Commission’s rationale for implementing the income tax deductible capital

cost deferral account, which includes capital repair costs, was based on concerns relating to

conflicting incentives and imbalances that arise between shareholders and customers when

customer rates are finalized but income tax reassessments and refunds may be requested and

received by a utility outside of the test years. The Commission is not persuaded that the historical

trend of deferral account balances should determine whether this account is still required. As

confirmed by Mr. Hoshowski, the status quo does not indicate that there will not be changes “in

positions or new tax rulings” regarding deductions. Therefore, it is not unreasonable to expect

that there could be changes in deductions or reassessments that could affect up to seven years of

returns. There could be a material difference between a prior period’s forecast and the actual

amounts if a new tax ruling or assessment were to occur. The Commission, therefore, finds that

these deferral accounts are still required and AET’s request to discontinue these deferral

accounts is denied.

305. The Commission approves, subject to directions issued in other sections of this decision,

the forecast amounts AET included in each of these deferral accounts for the test years.

10 Taxes other than income tax

306. AET forecast expenses related to taxes other than income tax (other taxes) in the amounts

of $47.1 million and $50.2 million for the years 2018 and 2019, respectively.

307. In its application, AET identified the sections of the Alberta Municipal Government Act

under which its property is assessed. Tax assessments must be reported to Alberta Municipal

Affairs as of December 31 each year. AET also described the methods and guidelines used to

arrive at linear property assessed values for various facilities e.g., machinery and equipment for

257 Transcript, Volume 5, page 813, line 6 to page 815, line 8.


Decision 22742-D01-2019 (July 4, 2019) 76

substations and communications. After the assessments are reviewed by Municipal Affairs, AET

reviews the categories of linear assessments for completeness. Once this information is

disseminated by Alberta Municipal Affairs to the municipalities, the municipalities issue the tax

notices for payment.

308. Historical actual and forecast amounts are summarized in the following table:

Table 31. AET – 2015-2019 taxes other than income tax

2015 Actual

2015 Approved

2016 Actual

2016 Approved

2017 Actual

2017 Approved

2018 Forecast

2019 Forecast

($ million)

33.7 33.7 37.8 39.0 45.7 52.0 47.1 50.2


309. AET stated that expenses for other taxes, primarily related to property tax, increased

during the period 2015-2019 due to inflation and growth in its transmission system. However,

2017 property taxes were lower than approved amounts because of a new regulated rate for

direct current (DC) lines that resulted in lower assessment values for new transmission lines and

substations.258

310. The CCA stated that it did not consider any adjustments were necessary for AET’s

forecasts of other taxes. However, the CCA noted that costs for other taxes have steadily

increased since 2013. For AET’s next GTA, the CCA recommended that the Commission direct

AET to identify potential incentives and cost saving measures that could be implemented going

forward to mitigate the overall costs for other taxes.259

311. The CCA pointed to a commitment AltaLink Management, Inc. made in its 2017-2018

negotiated settlement agreement to “explore if there are acceptable ways to reduce the amount of

property taxes that it is required to pay and to file the results of its review in the 2019-2020 GTA

application.”260

312. AET outlined its ongoing cost saving strategies261 to manage taxes other than income

taxes it is paying to municipalities as follows:

Reviewing annual assessments for accuracy and appealing where appropriate.

Reporting non-assessable costs for new substation and communication equipment.

Evaluating the need to renegotiate property tax amounts (which was observed by

AET for other oil and gas companies as having a very low likelihood of success).

258 Exhibit 22742-X0001.02, updated application, paragraphs 66 and 233-237. 259 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraphs 307-308. 260 Exhibit 22742-X0612, CCA-AUC-2018DEC19-004, PDF pages 10-11, which referenced Exhibit 21341-

X0210, AML 2017-18 GTA Negotiated Settlement Agreement, paragraph 16, PDF page 14. 261 Exhibit 22742-X0618, AET rebuttal evidence, PDF pages 58-59.


Decision 22742-D01-2019 (July 4, 2019) 77

313. AET concluded that since it has established measures in place that it uses on an ongoing

basis to mitigate taxes other than income taxes, there was no need for a direction from the

Commission to identify further tax mitigation measures in AET’s next GTA.

314. In argument, the CCA pointed to an exchange between Commission counsel and the

Bema witness that explored other cost-saving practices, such as the timing of when an asset goes

into service as that can affect the year in which the asset is first included in the valuation for

property taxes.262

315. The CCA maintained its recommendation that, since property tax represents

approximately 30 per cent of AET’s applied for operating expenses over the test years, the

Commission should direct AET to “identify potential cost savings measures that have been and

those that may be able to be implemented going forward.”263

Commission findings

316. AET has identified the strategies it uses on an ongoing basis to evaluate the

reasonableness of both its assessed property values and taxes other than income tax expense.

Other taxes payable are difficult to forecast, in part, because they are not entirely within the

control of AET. For these reasons, Bema's recommendation that AET report in its next GTA on

future tax mitigation measures it is considering implementing is unnecessary at this time.

Nonetheless, AET’s responsibility to report and explain variances between actual and forecast

other taxes remains unchanged as this information is very useful to the Commission and

interveners. No change to AET's filing for GTA purposes is required.

317. The Commission, however, remains interested in a specific scenario raised by the Bema

witness during the oral hearing. The scenario deals with when an asset is placed into utility

service and the corresponding impact to the asset valuation used for property tax purposes.

Accordingly, AET is directed to explore the timing of the capitalization of its assets as an

acceptable method to potentially reduce the amount of property taxes it would otherwise be

required to pay, and to report, at the time of its next GTA, whether such timing can or should be

taken into account on a go-forward basis.

318. AET’s taxes other than income taxes are approved as filed, subject to any applicable

findings and directions elsewhere in this decision.

11 Rate base

319. In the application, AET explained that its capital forecast for the 2018-2019 test period is

informed by the AESO’s Long-Term Transmission Plan published in late December 2017. This

capital forecast includes capital maintenance plans due to aging infrastructure, growth within the

service area, and customer connections determined through direct customer interaction.

Customer projects to support interconnection with renewable generation are also included in the

forecast.264

262 Exhibit 22742-X0722, CCA final argument, PDF pages 85-86. 263 Exhibit 22742-X0722, CCA final argument, PDF page 86. 264 Exhibit 22742-X0001.02, updated application, PDF page 322.


Decision 22742-D01-2019 (July 4, 2019) 78

320. Large system capital projects have been identified as part of the AESO’s Long-Term

Transmission Plan and are included in the forecast based on the AESO’s current requirements

and directions. These projects are in the early stages of development and AET’s capital

expenditures forecast for the 2018-2019 test period mainly covers costs associated with

completing the facility applications, detailed engineering and procurement of materials. To

accommodate the priorities that have been identified by the AESO, the Central East Transfer Out

Plan interconnection from the Red Deer area to Tinchebray has taken precedence over the

Grande Prairie area reinforcement plan in the test period.

321. A number of customer renewable projects including large scale solar, wind, and battery

storage development projects, are proposed within AET’s service area. These renewable projects

have typically gone through an initial estimation stage with customers to provide indicative

pricing to assist in narrowing the scope of alternatives. Most of these projects are at an early

stage of development.

322. AET stated that it applies a consistent, process driven approach to the management of

capital projects, both direct assigned and capital maintenance. This approach includes continuous

improvement of processes to ensure that learnings from existing projects, regulatory

advancements and changes to AESO rules are implemented within projects consistently and

effectively. In accordance with minimum filing requirements (MFR), AET provided business

cases in support of its capital forecast. These business cases are accompanied by financial

analyses where competing alternatives are being evaluated based on their relative economic

merits.

11.1 Direct assigned capital projects

323. AET detailed its forecast direct assigned capital project expenditures and additions

through the test period in the application.265 AET explained that, for direct assigned projects, the

AESO is responsible for submitting a Need Identification Document (NID) to the AUC for

approval. To assist in the review of forecast expenditures for direct assigned projects in this

application, business cases were provided for direct assigned capital projects over $500,000.

These business cases provide information regarding the current status of the project, including

the AESO’s NID submission to the AUC. A schedule of project milestone dates and capital

expenditure forecasts for direct assigned projects over $5 million was also provided.266

324. AET further explained that the direct assigned capital expenditure forecast consists of

distinct project types including system, customer, and renewable projects. Renewable projects

are made up of wind, solar and battery storage customer requests in the project queue located

within AET’s service territory. The forecast capital expenditures for direct assigned capital

projects increased from 2017 through the test period due to delays in the Jasper Interconnection

project, and to expected expenditures on several large projects that are in progress, with

construction activities scheduled through the test period.

325. In argument, AET stated that direct assigned capital forecast expenditures are $131.3

million in 2018 and $135.6 million in 2019. Although these expenditures are lower than during

265 Exhibit 22742-X0001.02, updated application, PDF page 363. 266 Exhibit 22742-X0009, Attachment 10.2, Schedule of DA Projects.


Decision 22742-D01-2019 (July 4, 2019) 79

the height of system expansion, AET nonetheless acknowledged that they are material in nature

and higher than actual expenditures in 2016 and 2017.267

326. AET explained that the most significant expenditures through the test period are

associated with major transmission system development identified by the AESO: Project 54904:

Jasper Transmission Interconnection; and Project 55737: Thickwood Hills Transmission

Development.

327. With the exception of the Thickwood project, which is addressed elsewhere by the

Commission in this decision, AET maintained that the balance of the direct assigned capital

projects included in AET's forecast were not subject to material questioning. AET stated that it

filed business cases268 to support each of these direct assigned projects, in accordance with the

Commission’s direction 92 in Decision 2013-358. AET submitted that its forecasts for direct

assigned capital project expenditures and additions for the test period should be approved, as

filed.

Commission findings

328. The Commission notes that AET has filed numerous exhibits supporting the direct

assigned projects under review in this application. These exhibits include, among other things,

information relating to the NID, facility application, PPS (Proposal to Provide Service) estimate,

monthly reports and customer contribution decisions for the relevant projects.269 AET's forecast

was also supported by correspondence from the AESO.270

329. Direct assigned capital projects are subject to a deferral account. Consequently, the actual

expenditures on these projects will be subject to a detailed prudence review in future direct

assigned capital deferral account (DACDA) applications prior to final acceptance of these costs.

330. Given the above evidence, the Commission approves AET’s forecast with respect to

direct assigned capital projects.

11.2 Transmission capital maintenance

331. AET stated that the transmission capital maintenance (TCM) program supports asset

renewal activities, which are funded from capital investment. The TCM program is designed

to:271

• Manage transmission assets in accordance with life cycle asset strategies; and

• Prioritize asset replacement and maintenance requirements through capital investment.

332. TCM activities range from small asset improvements to major asset replacements and

major facility rebuilds. AET’s forecast expenditures and additions shown in Table 32 below

include the TCM and Isolated Generation programs:

267 Exhibit 22742-X0725, AET final argument, page 88. 268 Exhibit 22742-X0013.02. 269 Exhibits 22742-X0014 to 22742-X0170. 270 Exhibit 22742-X0001.02, updated application, PDF pages 460-461. 271 Exhibit 22742-X0001.02, updated application, PDF page 328.


Decision 22742-D01-2019 (July 4, 2019) 80

Table 32. TCM and isolated generation forecast expenditures and additions

2015 Actuals 2016 Actuals 2017 Actuals 2018 Test period 2019 Test period

($ million)

Expenditures 99.2 113.5 101.0 109.7 113.47

Additions 105.0 93.3 123.9 113.3 123.47

Source: Exhibit 22742-X0001.02, updated application, Table 10.2.

333. AET explained that it used an asset management framework, which is aligned with the

ISO 55000 international standard for asset management, to ensure a holistic and effective TCM

program. This approach reviews asset status and performance through its entire life cycle from

cradle to grave, enabling AET to consider the trade-off between existing risks, performance

(reliability) and costs. The asset management framework enables AET to better refine and focus

required TCM activities.272

334. AET stated that the major drivers for TCM projects can be classified into the following

four primary groupings:

Safety/Environment: This project driver relates to managing hazards and risks to

employees, the general public and the environment;

Regulatory: This driver enables AET to meet regulatory requirements. These regulatory

requirements are often intended to protect public safety or preserve the integrity of the

electric system;

Technical: This driver enables AET to manage asset risks. The risks could arise from

reliability, asset condition, asset compatibility issues, capacity increase, performance

improvement and emergency restoration; and

Productivity: This driver relates to projects that enhance productivity or provide

economic savings.

335. AET explained that it is facing a growing stock of aging assets. It further explained that

as part of its asset management program, an asset management framework was developed to

better manage challenges with the aging fleet of assets, including safety, regulatory and

operational needs. The framework utilizes inputs, such as asset condition, performance, system

impact, load flow studies and the AESO Long-Term Plan, to develop a risk-based, prioritized

short and long-term forecast for AET’s TCM program.273

336. According to AET, at a high level, given the volume of aging transmission assets and

asset renewal needs, its Table 10.4274 (reproduced below) showed stable renewal rates for a

selection of key transmission assets. AET submitted that this demonstrated that it is appropriately

using its asset management framework to target asset renewals, based on risk, and that these

renewal rates are reasonable and sustainable.

272 Exhibit 22742-X0001.02, updated application, PDF page 331. 273 Exhibit 22742-X0001.02, updated application, PDF pages 332-334. 274 Exhibit 22742-X0001.02, updated application, PDF page 335.


Decision 22742-D01-2019 (July 4, 2019) 81

Table 33. Snapshot of AET assets and renewal forecast

Transformer 72-240 kV breaker

Transmission line

Protection relays

Telecom Tower

Automation & monitoring

Control building

RTU PLC

Inventory

Inventory 252 693 11,004

km 3,553 157 113 114 194

Age

Life expectancy (LE) in years

40-45 35-50 55-80 20-35 45 15 15 35

% at or above LE

16% 9% 8% 8% 3% 4% 37% 13%

At or within 5 years of LE

25% 15% 14% 21% 6% 19% 40% 26%

At or within 10 years of LE

33% 20% 27% 37% 9% 58% 100% 38%

Forecast conclusions

10-year renewal rate baseline

5/yr 10/yr 150 km/yr 175/yr 3/yr 12-20

/yr 12-20 /yr 4/yr

2018-2019 (2 year) TCM program renewal volume

10 replacements/ refurbishments (7 to be retired)

16 replacements, 2 new additions (4 to be retired)

93 km (rebuild project

2018-2025)

252 (multiple

relays to be replaced

with single devices)

4 11 16

4 replacements,

4 major refurbishment

s

Source: Exhibit 22742-X0001.02, updated application, PDF page 319..

337. AET’s actual/forecast TCM expenditures and additions for the 2015-2017 period, as well

as the forecast for 2018-2019 were shown in Table 10.6 of the application.275 Details with respect

to the forecast were provided in related sections as well as in the business cases provided in

appendices.276

338. AET stated that it had substantially completed the capital maintenance work forecast that

was approved in Decision 20272-D01-2016. In this application, AET sought approval of the

actual capital additions in 2015-17 to be included in the 2018 opening rate base. Consistent with

paragraph 872 of Decision 20272-D01-2016, AET provided business cases for any projects

completed in 2015-2017 with forecast costs over $500,000 which were not contemplated in the

2015-2017 GTA. As well, consistent with paragraph 873 of Decision 20272-D01-2016, AET

provided an analysis in this application of the variance between the forecast capital additions

approved in the 2015-2017 GTA and the 2015-16 actual and 2017 updated forecast capital

additions.277

275 Exhibit 22742-X0001.02, updated application, PDF pages 343-344. 276 Exhibits 22742-X0171 and 22742-X0172. 277 Exhibit 22742-X0001.02, updated application, PDF pages 398-430, Appendix 10.A.


Decision 22742-D01-2019 (July 4, 2019) 82

339. The CCA did not comment on AET’s forecast TCM program in its intervener evidence.

However, it did express concerns with respect to the Thickwood project and the Kearl line

relocation, both of which are dealt with elsewhere in this decision.

340. In argument, the CCA noted that it had issued several information requests to AET about

its forecast costs. After reviewing AET’s responses to those requests, the CCA advised that it

considered the record to be sufficient for the Commission to rule on the reasonableness of AET’s

applied for capital maintenance expenditures.

341. In its argument, AET stated that it was requesting approval of the actual non-direct

assigned capital additions in 2015-17 to be included in its 2018 opening rate base. AET noted

that it had provided detailed variance explanations in its application for the projects contributing

to the $20.0 million variance.278

342. AET further noted that none of the interveners presented any evidence to refute the

factual drivers for AET's TCM program or the risks to system safety and reliability that the

forecast TCM program is intended to address. AET's TCM program was also subject to little

questioning at the hearing. AET supplied additional information respecting the various sub-

programs in further support of its forecast.279

343. Interveners submitted no evidence with respect to AET’s TCM forecast.

Commission findings

344. Concerns raised with the Thickwood and Kearl line projects are addressed in

sections 11.4 and 11.5 of this decision.

345. AET discussed and supported its TCM forecast in the application280 through numerous

business cases,281 as well as in response to numerous information requests submitted by both the

interveners and the Commission. In considering and reviewing this evidence, the Commission

finds AET’s TCM forecast to be reasonable and it is approved.

346. In its next GTA, however, AET is directed to file variance analyses reflecting the actual

expenditures, explanations for variance from forecast and the current status of projects not

completed. As previously directed in Decision 20272-D01-2016,282 AET is also directed to file

business cases, at the time of filing its next GTA, for projects with a forecast value greater than

$500,000 that are planned to be completed in the test period but not forecast in the current

application.

347. The Commission also examined the proposed adjustments to opening rate base. AET

supplied variance analyses in the application283 as well as further detail in the business cases.284

278 Exhibit 22742-X0725, AET final argument, PDF page 62 refers to 22742-X0001, Table 10.14, pages 357-359

and Appendix 10.A, pages 398-429. 279 Exhibit 22742-X0725, AET final argument, PDF pages 68-84. 280 Exhibit 22742-X0001, PDF pages 327-362. 281 Exhibit 22742-X0171. 282 Decision 20272-D01-2016, paragraph 872. 283 Exhibit 22742-X0001.02, updated application, PDF pages 358-362 and 397-428. 284 Exhibit 22742-X0171.


Decision 22742-D01-2019 (July 4, 2019) 83

The Commission considers this evidence to be persuasive and AET’s proposed adjustments to

opening rate base are approved.

11.3 General property and equipment

348. AET explained that general property and equipment (GP&E) consists of software, tools,

equipment, vehicles and building capital projects necessary for AET to support safe and reliable

transmission service. GP&E is grouped into two categories, GP&E-Software285 and GP&E-

Other,286 which were detailed in the application.

349. AET’s forecast expenditures for GP&E-Other consisted of:

Direct general property, plant and equipment (PP&E), which is further broken down as:

o tools, instruments and equipment

o transportation equipment

Land, buildings and structures.

350. Tools, instruments and equipment include the replacement or addition of items required

for staff to complete their assigned tasks safely and effectively. As discussed in the 2015-2017

GTA compliance filing,287 AET’s forecast for the 2018-2019 test period reflects the 2015 and

2018 workforce reductions since tools, instruments and equipment for employees affected by

those workforce reductions were returned to stores. AET subsequently redistributed these items

as required by utilizing stores and reducing purchases going forward.288

351. Transportation equipment includes the normal replacement of vehicles and heavy

equipment as units reach end-of-life. Replacements of vehicles and heavy equipment are based

on mileage, condition and the age of the vehicle. Similar to the 2018-2019 forecast for tools,

instruments and equipment, AET’s 2018-2019 transportation equipment forecast reflects the

2015 and 2018 workforce reductions.289 Vehicles for employees affected by 2015 workforce

reductions were returned and inventoried. AET subsequently redistributed these items as

required by utilizing the inventoried assets and reducing purchases going forward. While, in

most cases, units returned from the 2015 workforce reduction were used as replacements for

backfills, it was determined in 2017 that vehicles which were not suitable for backfill

replacements or for which repairs were not financially reasonable would be sold at auction.

Vehicles for employees affected by 2018 workforce reductions were returned and inventoried.

AET indicated that it will subsequently redistribute these items, on an as-required basis, by

utilizing inventoried assets and reducing purchases going forward.290

352. With respect to the GP&E-other portion of its GP&E forecast, AET noted that it had filed

business cases for tools and equipment, transportation equipment and lands, buildings and

structures.291

285 Exhibit 22742-X0001.02, updated application, PDF page 380. 286 Exhibit 22742-X0001.02, updated application, PDF page 386. 287 Exhibit 22050-X0143, paragraph 28. 288 Exhibit 22742-X0001.02, updated application, PDF page 387. 289 Exhibit 22742-X0001.02, updated application, PDF page 387. 290 Exhibit 22742-X0001.02, updated application, PDF page 387. 291 Exhibit 22742-X0171.03.


Decision 22742-D01-2019 (July 4, 2019) 84

353. AET stated that it had substantially completed the GP&E capital work forecast approved

in the 2015-2017 GTA and was seeking approval for the actual capital additions in 2015-2017 to

be included in the 2018 opening rate base. Consistent with paragraph 872 of Decision 20272-

D01-2016, AET provided business cases for any projects completed in 2015-2017 with costs

over $500,000 which were not contemplated in the 2015-2017 GTA.292 As well, consistent with

paragraph 873 of Decision 20272-D01-2016, AET provided an analysis of the variance between

the forecast capital additions approved in the 2015-2017 GTA and the 2015-2016 actual and

2017 updated forecast capital additions.293

354. In its argument with respect to the GP&E opening rate base, AET noted an error in Table

10.B.2294 of the application. The 2015-2017 actuals in that table are expenditures, as opposed to

actual software additions.295 For clarity, AET supplied corrected amounts to reflect the actual

software additions. AET referenced the variance analyses and business cases supplied in support

of the actual 2015-2017 software additions.296

355. With respect to the GP&E-software portion of the GP&E forecast, AET submitted that it

had provided full and complete business cases to support the proposed projects with expenditures

of more than $500,000.297 AET noted that no party submitted evidence addressing AET's forecast

GP&E-software project expenditures. Given the limited questioning on AET's GP&E-software

projects, AET submitted that the forecast GP&E-software expenditures and additions should be

approved, as filed.298

356. With respect to its transmission asset management program (which is also part of AET's

GP&E-software), AET noted that in Direction 71 of Decision 20272-D01-2016, the Commission

directed AET to file a comprehensive asset management program business case, itemizing

historical and go-forward work and cost requirements. In response, AET stated that a business

case299 had been filed and sought approval for additions from 2013-2017 as well as expenditures

in the test period to enhance AET's asset management systems and processes, while ensuring

alignment with industry best practices.

357. AET maintained that there were no material issues raised and that no intervener

submitted evidence regarding AET's asset management program scope, opening rate base and

forecast costs, nor were there any questions on this program at the oral hearing. As such, AET

requested that the asset management program scope, opening rate base and forecast costs

included in its application be approved, as filed.

358. In argument, the CCA stated that it had reviewed AET’s GP&E forecast, and, in

particular, the information technology and vehicle cost items. The CCA was concerned with

AET’s forecast capital expenditures of $10.3 million and $11.5 million on the GP&E-software

portion of GP&E in 2018 and 2019, respectively, given historical capital expenditures were $4.2

292 Exhibit 22742-X0001.02, updated application, Appendix 10.B, pages 430-432. 293 Exhibit 22742-X0001.02, updated application, PDF page 389. 294 Exhibit 22742-X0001.02, updated application, PDF page 430. 295 Expenditures refers to the cash spent on an item or project in a given year while additions is the dollar amount

added to rate base in a year. 296 Exhibit 22742-X0725, AET final argument, page 63 refers to Exhibit 172.03. 297 Exhibit 22742-X0725, AET final argument, page 85 refers to Exhibit X0172.03. 298 Exhibit 22742-X0725, AET final argument, page 86. 299 Exhibit 22742-X0172.03, PDF pages 61-112.


Decision 22742-D01-2019 (July 4, 2019) 85

million in 2015 and $7.9 million in 2016.300 While AET’s costs increased in 2017 to $15.8

million,301 the CCA maintained there was no adequate explanation for the sustained increase over

the 2015 and 2016 levels.

359. The CCA was also concerned with 2019 vehicle capital expenditures of $4.1 million

given the historical levels of $1.2 million in 2016 and ($1.0) million in 2017.302 In particular, the

CCA was concerned that AET may not be properly considering leasing vehicles as a lower cost

option to purchasing them outright. In this regard, the CCA submitted that a regulated utility

would have an inherent bias towards adding capital to its rate base and thus would be naturally

opposed to leasing.

360. In reply argument, AET noted that the CCA chose not to address AET's IT forecast in

evidence, nor at the hearing. As such, AET submitted that the CCA comment that "there is no

adequate explanation for AET's forecast IT capital expenditures”303 should be ignored. AET

added that it had provided comprehensive business cases for all of the IT expenditures over

$500,000 in the test period.304 AET maintained that the CCA chose not to comment on the

substance of the business cases.

361. AET noted that the CCA expressed similar vague concerns regarding AET's

transportation equipment project305 forecast expenditures and whether AET had adequately

considered leasing as an option. AET pointed out that the leasing option was, in fact, considered

within its business case.306

Commission findings

362. The Commission notes that the interveners expressed some general concern with GP&E

forecast expenditures but did not submit any evidence on this issue. The CCA did suggest, with

respect to GP&E-other, that leasing should have been considered as an alternative to purchasing

vehicles.

363. The Commission notes that AET supplied a lease versus purchase analysis in its business

case.307 AET explained that the lease/rental of equipment is problematic primarily because of

limited equipment availability. Given this is typically specialized equipment, it is not available

for use on a casual basis and long term contracts are normally required. Rental equipment is also

unlikely to be available in emergencies. In AET’s view, equipment rental will always be costlier

than purchase because rental companies cannot control their assets ‘in-the-field.’ Therefore,

rental companies set rental/lease rates based on the least favorable life-expectancy, damage

projection, expected use, and resale value. A risk premium and a profit margin is added to that

300 Exhibit 22742-X0722, CCA final argument, page 221 refers to Exhibit 22742-X0002.04, AET GTA Schedules,

Schedule 10-4. 301 Exhibit 22742-X0722, CCA final argument, page 221 refers to Exhibit 22742-X0002.04, AET GTA Schedules,

Schedule 10-4. 302 Exhibit 22742-X0722, CCA final argument, page 221 refers to Exhibit 22742-X0002.04, AET GTA Schedules,

Schedule 10-4. 303 Exhibit 22742-X0722, CCA final argument, paragraph 764. 304 Exhibit 22742-X0171.03. 305 Exhibit 22742-X0172.03, Tab 4-3, PDF pages 220-238. 306 Exhibit 22742-X0172.03, PDF pages 223-224. 307 Exhibit 22742-X0172.03, pages 244-248.


Decision 22742-D01-2019 (July 4, 2019) 86

cost. AET maintained that lease or rental is a short term solution as costs can easily exceed cost

of ownership by mid-life of the equipment.308

364. The Commission also notes that AET's criteria for light duty vehicles included keeping

the vehicle for seven years or 250,000 kilometers.309 The Commission has considered AET’s

submissions in the business case as well as its responses to information requests and finds them

to be reasonable. In particular, the Commission does not consider leasing light duty vehicles to

be a viable option given the service life expectations of AET.

365. The Commission also examined AET’s GP&E-software forecasts, and, in particular, the

Oracle E-Business upgrade program and the asset management program. The Commission notes

that, in the Oracle business case, AET stated that premier vendor support for AET’s Oracle EBS

system has ended and an upgrade was required.310 AET further explained:311

Oracle’s Premier level of support is required because it is the only level of support that

ensures certification with new versions of third party vendor software such as operating

system software and applications that E-Business integrates with. Without the upgrade,

product fixes and security patches for these third party systems may need to be suspended

which would impact overall availability, reliability, and protection against security

vulnerabilities.

366. Similarly, and as directed in Decision 20272-D01-2016, AET filed a business case for the

asset management program.312

367. The Commission and interveners submitted numerous information requests to AET with

respect to these programs as well as the other forecast expenditures. The Commission finds the

evidence filed regarding AET’s forecast GP&E expenditures to be reasonable and sufficient, and

the proposed programs necessary. They are approved as filed. In its next GTA, AET is directed

to file variance analyses reflecting the actual capital expenditures, explanations for variance from

forecast and the current status of projects not completed.

368. The Commission also examined the proposed adjustments to opening rate base. AET

supplied a variance analysis in the application313 as well as further detail in the business cases,314

in particular, the asset management business case. The Commission considers this evidence to be

persuasive and the adjustments to opening rate base are approved.

11.4 Thickwood development project

369. In its evidence, the CCA noted that AET’s September 2018 application update315 included

a materially revised forecast of 2018 and 2019 direct assigned capital additions and expenditures.

2018 direct assigned capital additions increased by $107.9 million and 2019 direct assigned

capital additions decreased by $198.1 million. The CCA stated that the primary driver for this

308 Exhibit 22742-X0172.03, page 230. 309 Exhibit 22742-X0172.03, page 231. 310 Exhibit 22742-X0172.03, page 2. 311 Exhibit 22742-X0172.03, page 3. 312 Exhibit 22742-X0172.03, pages 60 – 112. 313 Exhibit 22742-X0001.02, updated application, PDF pages 430-432. 314 Exhibit 22742-X0172.03. 315 Exhibit 22742-X0533, 2018-2019 GTA September 4 2018 Update.


Decision 22742-D01-2019 (July 4, 2019) 87

change was AET’s transfer of $102.4 million of the Thickwood development project capital

additions from 2019 into 2018.316

370. The CCA also noted that the decision to advance the in-service date from 2019 to 2018

was AET’s, and not the AESO’s, even though AET had to secure the AESO's approval for the

in-service date change before it could take effect.317

371. In this regard, AET confirmed the following in response to a CCA information request:318

There were no identified negative consequences to the safe and reliable operation of the

transmission system that would have been encountered if the in service date was

maintained in January 2019.

372. According to the CCA, as there was no pressing reliability or safety-based need to

advance the in-service date to 2018 for the Thickwood development project, it appears that the

decision to do so was based entirely on economic considerations.319 AET stated that accelerating

the in-service schedule would allow for the saving of AFUDC costs.320 The CCA did not dispute

this. However, as AET confirmed in response to the CCA’s information request, shifting the

costs into 2018 simply replaced the AFUDC that would have been incurred in 2019 with return

on capital in 2018.321 AET determined that the AFUDC that was saved was $6.6 million, and that

this amount was offset by return on capital in 2018.322 Finally, the CCA noted that, by

accelerating the in-service date, AET triggered an additional $0.4 million of depreciation charges

which consists of $0.2 million in 2018 and $0.2 million in 2019.

373. The CCA stated that there was no safety or reliability-based need to accelerate the in-

service date, and the savings cited by AET in relation to AFUDC were not, in fact, true savings

given the return on capital included in revenue requirement. In the CCA's view,323 AET’s

decision had inter-generational equity implications as it was requiring current customers to pay a

cost that future customers would have otherwise incurred.

374. The CCA noted that in Decision 20272-D01-2016, the Commission considered a similar

scenario, albeit for a much larger asset, specifically EATL (Eastern Alberta Transmission Line).

However, in that case, AET sought to transfer $37 million of EATL-related depreciation expense

into 2016 from 2015, given that the asset was energized in December 2015.324 The Commission

denied AET’s request and directed that the depreciation be included in 2015.325

375. While acknowledging that the circumstances in Proceeding 20272 were unique, the CCA

considered that they were instructive. In the CCA’s opinion, absent a reasonable justification

based on system reliability or safety, AET should not have accelerated the in-service date for the

Thickwood development project solely to reduce AFUDC. Accordingly, the CCA recommended

316 Exhibit 22742-X0533, 2018-2019 GTA September 4 2018 Update – Narrative, PDF page 11, Table 1b. 317 Exhibit 22742-X0570.01, AET, AET-CCA-2018OCT05-004(c), PDF page 13. 318 Exhibit 22742-X0570.01, AET, AET-CCA-2018OCT05-004(e), PDF page 14. 319 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 185, refers to above footnote and IR

response. 320 Exhibit 22742-X0570.01, AET, AET-CCA-2018OCT05-004(d), PDF page 14. 321 Exhibit 22742-X0570.01, AET, AET-CCA-2018OCT05-004(f), PDF pages 13 and 14. 322 Exhibit 22742-X0570.01, AET, AET-CCA-2018OCT05-004(f), PDF page 14. 323 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, pages 185 and 186. 324 AUC Decision 20272-D01-2016, PDF page 93, paragraph 409. 325 AUC Decision 20272-D01-2016, PDF page 93, paragraph 412.


Decision 22742-D01-2019 (July 4, 2019) 88

that the Commission direct AET to revise its 2018 and 2019 revenue requirements and capital

additions to reflect the addition of the Thickwood development project in 2019 rather than 2018.

376. In its rebuttal evidence, AET maintained the CCA's assertion that AET “transferred the

addition of Thickwood into 2018 for no reason other than to reduce AFUDC”326 was false. In its

September 2018 application update, AET provided an updated Thickwood development project

forecast, driven by the in-service date being advanced from January 2019 to November 2018.

This resulted in an increase in 2018 capital additions of $107.9 million and a decrease of capital

additions of $198.1 million in 2019. However, AET asserted that this change was not undertaken

to “reduce AFUDC.” Rather, this change was to accurately reflect the project’s completion and

energization in 2018. AET submitted that its reference to reducing AFUDC was made simply to

highlight some of the financial implications of the change and not as a justification for advancing

the in-service date.

377. AET submitted that it did not incur additional costs on the project to complete it in

November 2018 as opposed to January 2019. According to AET, the early completion of the

project was a consequence of successful project execution, not an increase in labour and

execution costs to achieve an earlier in-service date. This was clearly indicated within the

monthly project reports filed in the application, and within the approved change orders filed with

the AESO.327

378. AET also stressed that the term “acceleration” as used by the CCA was inaccurate – the

project was executed on budget and ahead of schedule. An acceleration, as the CCA implied,

would imply that an additional capital expense would be required to complete the project ahead

of schedule. This was simply not the case and the completion of the project in 2018 was a result

of good construction practice and risk management, limiting potential project delays.

379. AET further argued that the reference made by the CCA to Decision 20272-D01-2016 for

the EATL project was not, as the CCA has indicated “…a similar scenario, albeit for a larger

asset.” In the case of the Thickwood development project, the scenario was the complete

opposite of what was being sought in the EATL case. In the latter, AET sought to shift

depreciation expense into future years from the year of project capitalization. The Commission

denied this adjustment. As noted by the CCA, the Commission “…directed that depreciation be

included in 2015.”328 AET maintained that AUC Decision 20272-D01-2016 actually supports

AET’s current position in that by advancing the in-service date for the Thickwood development

project as part of its September 2018 application update, depreciation expense would be incurred

in 2018, based on the complete capitalization of the asset in 2018, as opposed to being deferred

to 2019.

380. In summary, AET stated that it did not incur additional costs to achieve a 2018 in-service

date on this project and has throughout the project process advised the AESO of project forecasts

and schedule updates through a series of change orders. AET submitted that it managed this

project appropriately, and the adjustment of the in-service date is accurate as it aligns with the

project energization and results in a decrease in total capital cost from the originally filed

forecast.

326 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, PDF page 186, paragraph 603. 327 Exhibit 22742-X0570.01, AET-CCA-2018OCT05-004(b) Attachment 1, PDF pages 15-29. 328 Exhibit 22742-0592, CCA - Evidence of Bema Enterprises, paragraph 602, PDF page 186.


Decision 22742-D01-2019 (July 4, 2019) 89

381. In its argument, the CCA noted that whether or not additional costs were incurred to

advance the in-service date of the Thickwood development project was only one factor to be

considered. Another factor for the Commission to consider is whether advancing the in-service

date of an asset so that it becomes part of the regulated rate base earlier than would otherwise be

the case has consequences from the perspective of intergenerational equity.

382. The CCA submitted that its recommendation addressed this concern and resulted in the

removal of costs that should not be recovered in rates in 2018. The CCA further claimed that its

recommendation would not harm AET as it would essentially restore AET to where it otherwise

would have been had the Thickwood development project been energized in early 2019 as

originally planned.

Commission findings

383. The CCA has argued that AET unreasonably and unnecessarily advanced the in-service

date of this project, causing an increase in return and depreciation in 2018 in spite of there being

no pressing reliability or safety-based need for an earlier in-service date. The CCA also

maintained that there was an element of intergenerational inequity attending this change. That is,

ratepayers in 2018 would be adversely affected in having to begin paying for an asset that is not

yet required to be in service.

384. AET explained that it did not incur additional costs on the project to complete it in

November 2018 as opposed to January 2019. AET also pointed out that customers saved $6.6

million in AFUDC costs that would otherwise have been incurred if the project was not

capitalized until 2019. AET explained that the early completion of the project was a consequence

of successful project execution, not an increase in labour and execution costs to achieve an

earlier in-service date.

385. The Commission accepts the explanations of AET. The Commission acknowledges that

capitalizing the project in 2018 did lead to an increase in return and depreciation. However, as

AET has noted, this was largely offset by a decrease in AFUDC. The Commission also notes that

the current increase in return and depreciation will be further offset by decreases in future return

and depreciation. The Commission expects that the financial impacts of such variances will tend

to cancel each other out over time provided that the time value of money is taken into

consideration.

386. Regarding the request for relief on the basis of intergenerational inequity, the

Commission notes that large capital programs almost always involve some degree of

intergenerational inequity because the optimum timing for constructing a transmission asset

seldom matches the current need. Consistent with the mid-year convention and over the course

of a given year, some projects will be completed and capitalized earlier than forecast, while

others will be completed later than forecast. It should be noted that Thickwood Development

project is also a direct assigned project and actual capital expenditures will be adjusted in the

next DACDA proceeding. For these reasons, the CCA's recommendation is rejected.

387. As directed in paragraph 317 above, AET is to explore the timing of the capitalization of

assets as it affects municipal tax assessments and forecasts. In the case of the Thickwood

Development project, this timing may affect capital additions to rate base.


Decision 22742-D01-2019 (July 4, 2019) 90

11.5 Kearl Line (line 9L101) relocation

388. In the application, AET filed a business case supporting the relocation of the 240-kV line

9L101 Kearl line329 (Kearl line) as requested by Fort Hills Energy (FHELP) to accommodate its

oilsands expansion project. The Kearl line is part of transmission line L9900, which AET

purchased from Imperial Oil Resources Ventures Limited (IORVL or Imperial) in 2012.

389. AET explained that, in past decisions,330 the Commission approved the purchase of the

Kearl line by AET and accepted the line as a system asset, forming part of the North Fort

McMurray Transmission Development.

390. AET stated that it is obligated to relocate this line, under the FHELP Power Line

Encroachment and Consent Agreement that was assigned to AET as part of the purchase of the

Kearl line from Imperial. AET requested confirmation that the costs associated with relocating

the Kearl line continue to be system costs, and that approval of the Kearl line relocation be

forecast as a system cost.

391. AET maintained that the project met the requirements of the 2003 relocation principles

set out by the Commission’s predecessor in board Decision 2003-043. AET submitted that the

current relocation project is in the public interest because it avoids the sterilization of mine

resources, was a prerequisite to achieving landowner consent at the time of construction, and that

the relocation risks were known at the outset, when approval was given for the purchase and

systemization of the Kearl line in Decision 2012-193.331

392. AET’s business case, later updated, included an analysis of four alternatives, A, B, C and

D, for the relocation of the Kearl line. A detailed description of the facilities associated with each

of these alternatives, along with the proposed life cycle for each alternative was provided in

AET's business case.

393. AET recommended Alternative A because:

Alternative A presented the lowest initial project cost to meet the relocation

requirement.

Based on updated routing assumptions and refined estimates, the economic analysis

indicated that the CPV (Cumulative Present Value) of revenue requirement for

Alternatives A and B were effectively the same.

Alternative A had the least overall impact to land use and environmental features, the

greatest stakeholder and agency acceptance, the greatest use of disturbed/developed

areas and the lowest initial project cost requirement.332

394. The CCA submitted evidence recommending Alternative C and requesting that AET

perform additional work to further explore Alternative C and to assess whether the risks

identified by AET333 could be addressed. It submitted that AET's preferred alternative could

329 Exhibit 22742-X0171, pages 825-849. 330 Decision 2011-276, Approval of AESO NID; 2012-193, Approval of AET purchase and systemization of line;

2012-283, Addition of asset to AET rate base. 331 Exhibit 22742-X0171, page 826. 332 Exhibit 22742-X0171, page 837. 333 Exhibit 22742-X0171, page 834, AET business case describes Alterative C.


Decision 22742-D01-2019 (July 4, 2019) 91

result in significant additional line relocations and duplication of effort in the future.334 Further, it

noted that the Kearl line had previously been a customer-specific asset and is now a system asset.

The CCA stated that all Alberta ratepayers are paying for relocation costs that would have

otherwise been paid by the customer connected to the line had it remained a customer-specific

asset.335

395. The CCA observed that the cost of AET’s Alternative C is $38.0 million (or 324 per cent)

higher than Alternative A and $12.9 million (or 35 per cent) higher than Alternative B. The CCA

submitted that the benefit of Alternative C, however, is that it may extend the life of the assets,336

and is greater than the six year life of Alternative A and 24 year life of Alternative B.

396. In rebuttal evidence, AET explained that it took a conservative approach to uncertainty in

the business case and throughout the economic analysis of the alternatives. This included

considering worst-case scenarios for the year of future relocation (applying a 2027 in-service-

date for the future re-route in Alternative A and a 2045 in-service-date for the future re-route in

Alternative B). With these risk-based, worst-case scenarios applied, AET stated that the result

continues to be lower initial capital investment for Alternative A, which results in a lower CPV

of revenue requirement for this project.337 AET indicated that the difference between the CPV

values of revenue requirement for Alternative A and Alternative B are effectively equivalent

over the lifecycle of the asset.338

397. In argument, the CCA noted AET’s acknowledgement that there was significant

uncertainty with respect to the mine development.339 The CCA maintained that since AET

proposed that the costs of these new and replacement lines were to be borne by ratepayers, the

mine owner has no cost responsibility related to any changes required to the transmission line.

Consequently, the mine owner has no price signal to guide its behaviour for substantial costs

borne by others. The CCA argued that by introducing a price signal to the mine owner, it would

be compelled to take into account the costs to ratepayers and thereby optimize social costs. The

CCA acknowledged that the existing line has been purchased by AET and forms part of AET’s

rate base. However, the CCA submitted that the costs of the transmission line relocations need to

be examined under the specific circumstances of the proposed project.340

398. The CCA noted that AET had conceded that costs specifically related to the requirements

of the participant might not be designated as system related:

MR. PALLADINO: I suppose we can get into discussion depending on the relocation

requirements and how they relate to the system facilities in that area. To the extent that a

system line or a portion of a system line may be deemed to be specifically related to the

requirements of the participant seeking the relocation, and if it's deemed not to be in the

public interest to consider that portion to be a system line but, rather, one that is more

334 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 186. 335 Exhibit 22742-X0171.03, TCM Business Cases, PDF pages 827 and 828. 336 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 192, assets would have service lives of 60 to

65 years. 337 Exhibit 22742-X0570.01, PDF page 30, AET-CCA-2018OCT05-005. 338 Exhibit 22742-X0618, AET rebuttal evidence, page 162. 339 Exhibit 22742-X0722, CCA final argument, page 197, refers to Exhibit 22742-X0618, AET Rebuttal Evidence

to CCA and UCA, PDF page 162. 340 Exhibit 22742-X0722, CCA final argument, page 198.


Decision 22742-D01-2019 (July 4, 2019) 92

participant related, I suppose the Commission could have that as part of its consideration

when a relocation is under -- is looked at.341

399. The CCA submitted that the Commission has the jurisdiction to determine whether the

costs of line relocations are primarily and specifically related to the mine owner. Based on the

record, the CCA argued that it appeared that no benefits to other customers or ratepayers arise

from the relocation of the Kearl line. As such, the CCA concluded that the costs associated with

the Kearl line relocation could be designated as participant related.

400. The CCA said that if one assumed that the double circuit 240 kV lines are capable of

serving hundreds of Megavolt-Amperes, it is possible that the lines are relatively lightly loaded,

and that the value of the loop itself is accordingly diminished.

401. The CCA also submitted that it is possible that the lines comprising the North Fort

McMurray Transmission Development may have been overbuilt to supply the required load.342

Referring to the single line diagram provided by AET to the CCA in an undertaking,343 the CCA

suggested that if the loads on the Kearl line can have adequate reliability using radial lines served

from Joslyn 849S to Secord 2005S and from Black Fly 934S to McClelland 957S, this could

obviate the need to incur substantial, potentially duplicative costs to keep moving the

transmission line to keep the loop closed.344

402. The CCA further stated that if the reliability of a radial line was inadequate for the mine

owner, the mine could pay a contribution to have the transmission line relocated and rebuilt. The

CCA argued that such an arrangement would restore a price signal to the mine owner by

motivating it to take into account the cost of moving transmission lines in its mining

development plans. The CCA submitted that having price signals in place that drive optimal

societal behaviour and the allocation of limited resources is in the public interest.345

403. In argument, AET continued to support Alternative A on the basis that it presented the

best opportunity to defer project capital costs346 and is the lowest cost option for customers. AET

added that Alternative A allows AET to identify shorter, long-term routes based on the dynamic

mining development plan and continued discussions with the mine owner.347

404. AET also noted that during the hearing it had clarified the various line relocations that

had occurred in the past on components of the 240 kV line from McClelland to Joslyn (9L101

and 9L32) with Commission counsel.348 In so doing, AET pointed out that the 240 kV lines in the

area349 are located on oilsands development leases where large scale oil development is

occurring, resulting in a high probability that relocation would be required to allow for orderly

341 Transcript, Volume 4, page 578, line 16 to page 579, line 2, Mr. Palladino to Mr. Wachowich. 342 Exhibit 22742-X0722, CCA final argument, page 200. 343 Exhibit 22742-X0650, Undertaking 32 Palladino to Wachowich, PDF page 2. 344 Exhibit 22742-X0722, CCA final argument, page 200. 345 Exhibit 22742-X0722, CCA final argument, page 200. 346 Exhibit 22742-X0171.04, page 837. 347 Exhibit 22742-X0725, AET final argument, page 79, also refers to Exhibit 22742-X0618, pages 162-170. 348 Transcript, Volume 6, pages 1004-1008. 349 Exhibit 22742-X0650.


Decision 22742-D01-2019 (July 4, 2019) 93

and prudent development of oilsands activity in the area. The 240 kV lines that form part of the

backbone transmission system in the area are all considered to be system assets.350

405. AET maintained that the rationale for treating the Kearl relocation costs as system is

consistent with the board’s previously developed relocation principles as articulated in Decision

2003-043. AET noted that, in that proceeding, both AET and the Transmission Administrator351

agreed that, where a line will clearly need to be moved to enable orderly and economic mining

activities identified prior to the decision to locate the line, the leaseholder should not have to

fund the move.352 AET further noted that the board, in the decision, considered it would be more

appropriate to defer the consideration of line relocation costs to a point in time in the future, if

and when it was required to move the transmission line. The board did, however, set down the

relocation principles to guide the determination of responsibility for relocation costs.353

406. With respect to the public interest, AET noted that in Decision 21306-D01-2016 the

Commission stated that it will generally weigh the benefits of a proposed project against the

costs to be incurred by customers.354 To properly measure the benefits of the proposed relocation,

AET submitted that the Commission must take into account the broader public interest in the

efficient development of oilsands resources. AET explained the vast nature of system lines in

northeast Alberta that are located on oilfield lands355 and indicated that the extraction of a

significant amount of mineable ore might only be possible by relocating system transmission

facilities. AET maintained that applicable legislation was in place to protect the public interest in

the development of oilsands activity356 and that the requested relocation was not a purely private

benefit to the mine owner but also has considerable benefits in the public interest.

407. Additionally, AET stated that the Kearl system facilities are similar to many of the

transmission system lines that form part of the North-East Loop that traverse oilsands mining

areas. AET argued that a determination that participants must pay the cost of relocating a system

line to accommodate active oilsands operations may make siting future transmission

development more challenging.357

408. AET also provided arguments distinguishing the current application from that in

Proceeding 2901 (Decision 2014-009) and in Proceeding 21306 (Decision 21306-D01-2016).

409. In its reply argument, the CCA stated that AET had co-mingled the public interest issue

with the system versus participant issue, which the CCA submitted are separate issues. The CCA

said that the Commission should first decide if the proposed Kearl line relocation is in the public

interest and then decide who is responsible for the costs. The CCA noted that AET had relied on

the Oil Sands Conservation Act to support its position that the proposed Kearl line relocation is

350 Transcript, Volume 6, page 1010. 351 The predecessor to the AESO. 352 Decision 2003-043, page 13. 353 Exhibit 22742-X0725, AET final argument, page 80, refers to Decision 2003-043, page 14. 354 Decision 21306-D01-2016 at para 112. 355 Transcript, Volume 6, pages 1009-1010. 356 Transcript, Volume 6, pages 1014-1015. 357 Exhibit 22742-X0725, AET final argument, page 82.


Decision 22742-D01-2019 (July 4, 2019) 94

in the public interest.358 The CCA argued that the relocation may be in the public interest at some

point in time, but the real issue is who should pay for it.359

410. The CCA noted that AET relied on relocation principles from Decision 2003-043.360 The

last principle states that the “cost of relocating a local transmission line required to serve the

party requesting the relocation should be the responsibility of that party.”361 The CCA submitted

that the relocation principles set out in Decision 2003-043 need to be considered in context. At

the time of the decision, Alberta transmission system costs were relatively low compared to

today and might arguably have contributed to electricity rates that were highly competitive with

other jurisdictions in Canada. The CCA stated that today, Alberta has become one of the highest

transmission cost jurisdictions in the world and that the threat of customers seeking to bypass the

transmission system or leave the system entirely has become a real threat to the system’s

economic viability. This, the CCA argued, creates a strong case to send price signals to those

entities, including customers, that trigger further substantial cost increases on the transmission

system with little or no benefit to other customers.362

411. In its reply argument, AET suggested that the CCA was speculating in its evidence that

the looped system, of which the Kearl line is a part, “may not be necessary” and that customer

loads could be met with “radial lines” and the use of “portable generation.”363 AET claimed the

CCA’s speculation was in reality a collateral attack on Decision 2011-276.364 AET explained that

the looped system serves not only the Fort Hills mine but is part of the larger Fort McMurray

looped system and serves the needs of multiple customers. The construction of L9900 by

Imperial, its subsequent systemization, and construction of the looped system were independent

of the Fort Hills mine. AET argued that any speculation as to whether FHELP could operate

adequately with or without the looped system365 is both without basis and irrelevant as it does not

consider the overall reliability needs of the Fort McMurray system and all affected customers.

Commission findings

412. The Commission is required to make two decisions with respect to the Kearl line

relocation:

(1) were approval to be granted for the Kearl line relocation in Proceeding 24246, from

whom should the capital expenditures for the line relocation be recovered: the

owner of the Fort Hills mine (customer) or the system’s customers? and

(2) if the Kearl line relocation costs are to be recovered from the system’s customers,

what quantum of AET’s forecast capital expenditures for TCM project number

50463, 9L101 Kearl Line Relocation Project should be approved?366

358 Exhibit 22742-X0725, AET final argument, PDF page 79, paragraph 256 to PDF page 82, paragraph 262. 359 Exhibit 22742-X0726, CCA reply argument, page 30. 360 Exhibit 22742-X0725, AET final argument, PDF page 80, paragraph 257. 361 Exhibit 22742-X0725, AET final argument, PDF page 81, second bullet. 362 Exhibit 22742-X0726, CCA reply argument, page 32. 363 Exhibit 22742-X0722, CCA final argument, paragraphs 680-685. 364 Exhibit 22742-X0171.04, PDF pages 827-828. 365 Exhibit 22742-X0722, CCA final argument, paragraphs 684-686. 366 See Exhibit 24246-X0039 and Exhibit 22742-X0730 for the scoping letter of the facilities and rates

proceedings.


Decision 22742-D01-2019 (July 4, 2019) 95

413. The Commission addresses each of these questions below.

(1) Allocation of line relocation costs

414. An overview of the origins of the Kearl line and its past regulatory treatment leading to

the purchase of this line by AET is set out in Decision 2014-283. Some of this history has been

provided in this section to assist in understanding the Commission’s determination regarding

AET’s request to have the Kearl line relocation costs classified as system costs and therefore

paid for by the system’s customers.

415. Imperial received a permit and license to construct the Kearl line in 2009.367 The Kearl

line was part of the Kearl Oil Sands Industrial Site Designation (ISD).368 While Imperial

constructed the line initially, Imperial was aware of the possibility that it would be selling the

asset as a system requirement.

416. In Decision 2009-154, the Commission approved the addition of a second conductor. In

the decision, the Commission stated:

19. Alberta Electric System Operator (AESO) has requested that IORVL add a

second conductor to the Transmission Line so that this Line is built to serve as a system

facility, if and when AESO determines that such service is required.

20. IORVL believes it is in the public interest to initially construct the transmission

facility to meet the potential future system access service requirement contemplated by

AESO.

21. IORVL is prepared to assume responsibility for the costs and risks associated

with the alteration given that a future transfer of the transmission facility to a system

facility is not decided at this time. IORVL acknowledges that any such transfer would be

subject to a future need determination by AESO and approval by the Commission.

22. Although IORVL is prepared to assume all of the costs associated with the

second conductor, it expects that should the 240-kV line be required in the future as a

system asset by AESO, it would seek the opportunity to recover reasonable costs incurred

by it at that time.

417. In 2010, the AESO filed a needs identification document application with the

Commission, which recommended utilizing Imperial’s transmission line L9900 to create a 240-

kV loop in the area. In Decision 2011-276, the Commission approved the need as applied for.369

In that decision, the proposed project was described as follows:

The transmission facilities proposed to meet the need include construction of a new

double circuit 240-kilovolt (kV) transmission line with a single side strung from Salt

Creek 977S substation to a new substation designated as Black Fly 934S substation,

continuing north and terminating at a new substation designated as McClelland 957S

substation on transmission line L9900. Transmission line L9900 is under construction by

Imperial Oil Resources Ventures Limited. With a connection to transmission line L9900,

367 Decision 2012-193 refers to approvals U2009-055 and U2009-394. 368 Decision 2012-193 refers to Approval U2009-039. 369 Proceeding 774, North Fort McMurray Transmission Development.


Decision 22742-D01-2019 (July 4, 2019) 96

a looped 240-kV electric system would provide reliable service to the north Fort

McMurray area.370

418. AET received approval to purchase the line and systemize the asset in Decision 2012-

193. In the decision, the Commission stated:

6. … The applied for transfer and alterations reflect what was granted in the

aforementioned need approval. The AESO has directed ATCO to submit the current

application to meet the specifications outlined in the AESO Functional Specifications, in

accordance with Section 35 of the Electric Utilities Act.

…

8. ATCO and Imperial have reached an agreement whereby ATCO will purchase

and operate transmission line L9900 (the transmission line). This will allow ATCO to

integrate the transmission line into ATCO’s electrical system and to utilize the

transmission line as part of the AIES. A looped transmission system will then be created

to enhance transmission system reliability in the Fort McMurray area, as discussed in

Decision 2011-276.

419. Approval to add the purchase to AET’s rate base was granted in Decision 2014-283.

420. AET has now been requested by the owner of the Fort Hills mine to move the Kearl line

that forms part of the looped transmission system in the Fort McMurray area. The CCA has

submitted that this proposed line relocation should be a customer cost on the basis that the

relocation is intended only for the benefit of the customer.

421. Section 17 of the Hydro and Electric Energy Act authorizes the Commission to determine

compensation to be paid under an application to relocate a transmission line. Section 17 states:

17(1) The Commission may, on any terms and conditions it considers proper, direct a

permittee or licensee to alter or relocate any part of the permittee’s or licensee’s

transmission line if in the Commission’s opinion the alteration or relocation would be in

the public interest.

(2) The Commission may, in an order under subsection (1), provide for the payment of

compensation and prescribe the persons by whom and to whom the compensation is

payable.

(3) When an order under this section provides for the payment of compensation, the

Commission may at any time provide that if agreement on the amount of compensation

cannot be reached between the parties, the amount is to be determined by the Alberta

Utilities Commission on the application of either party.

422. The Commission considers that the following factors must be addressed in determining

this matter:

(a) Does the relocation of this Kearl line change the nature of the looped 240-kV

system for which the need and purchase of this line was approved?

370 Decision 2011-276 refers to Approval U2011-216.


Decision 22742-D01-2019 (July 4, 2019) 97

(b) If the answer is no, are there any other factors which would suggest to whom these

relocation costs should be allocated?

(a) Does the relocation change the nature of the looped 240-kV system?

423. The AESO is the system planner and in this role, it has the jurisdiction and legislative

responsibility to plan the transmission system including the alleviation of system constraints.371

As well, the AESO is required to submit for Commission approval a tariff that sets out rates to be

charged for system access service and the terms and conditions that apply to each class of

service.372 Under Section 8 of the current AESO tariff, the AESO sets out the manner in which it

classifies participant and system-related costs for the purposes of a connection project. This

provision states, in part, as follows:

3(1) All costs of a connection project will be classified as either participant-related or

system-related.

(2) Participant-related costs will be those costs related to a contiguous connection project

including costs associated with:

…

(d) line moves or burials of existing transmission line;

…

(h) salvage labour required to remove existing transmission facilities to allow the

installation of new or replacement facilities for a connection project, except where the

cost of the removed facilities is treated as a capital maintenance cost by the owner of the

transmission facility;

(3) System-related costs will be those costs related to a connection project including non

contiguous components of the project and any costs associated with:

(a) looped transmission facilities, which are facilities that increase the number of

electrical paths between any two (2) substations, excluding the substation serving the

market participant and which exclude any new radial transmission line;

(b) radial transmission facilities which, within five (5) years of commercial operation, are

planned to become looped as part of a critical transmission development or regional

transmission system project:

(i) in the ISO’s most recent long-term transmission system plan;

(ii) in a needs identification document filed with the Commission; or

(iii) as the ISO reasonably expects will be required in the future;

424. As noted above, the AESO determined that the Kearl line was required as part of a

looped system and it was on this basis that the Commission approved the purchase of this line by

AET from Imperial and indicated that these line costs should be systemized and therefore

recovered from the system’s customers.

371 Sections 33 and 34 of the Electric Utilities Act. 372 Section 30 of the Electric Utilities Act.


Decision 22742-D01-2019 (July 4, 2019) 98

425. There is no evidence on the record to suggest that any of the proposed alternatives set out

in the business case would result in the 240-kV system no longer being a looped system.

Although these alternatives and approval of the relocated Kearl line is yet to be determined in

Proceeding 24246, no evidence has been put forward to suggest that the line, if relocated, would

no longer form part of a looped system.

(b) Are there any other factors which would suggest to whom these costs should be

allocated?

426. Parties have referred to Decision 2003-043 wherein the Commission’s predecessor, the

board, enumerated certain principles that could be considered in assessing cost responsibility for

relocation of transmission lines. The board stated:

Notwithstanding that the Board considers relocation costs to be better dealt with in [sic.]

the future, the Board considers that it would be appropriate to set down some broad

principles that would generally guide the Board in determining cost responsibility for

relocation costs. These principles may assist parties in coming to commercial agreements

should they so desire:

The Board must be satisfied as to the balance between the public interest and the

interest of any affected party.

• The sterilization of mineable ore, and direct and unavoidable conflict with the

infrastructure and development required to mine the ore, is a reasonable cause for

the relocation of a transmission line.

• A valid mineral lease and an applied for/approved mine plan should exist at the

time the move is requested.

• The TA’s customers should be required to incur relocation costs, as a system

cost, when there is a reasonable cause to move a system transmission line,

provided that:

o A valid mineral lease existed prior to the construction of the

transmission line; o A practical alternative route is available; and

o There are no unusual negative impacts on the AIES that cannot be

reasonably addressed.

The cost of relocating a local transmission line required to serve the party

requesting the relocation should be the responsibility of that party.373

[emphasis in original]

427. The Commission further addressed these principles in Decision 21306-D01-2016 where it

was asked to determine how to allocate the costs of a transmission line that had already been

moved. The Commission stated:

Based on its review of the prior decisions cited by the parties, the Commission finds that

these decisions do not specify that in each instance where a transmission line move is

proposed to avoid sterilization, the cost of the transmission line move would necessarily

be borne by ratepayers.

…

The Commission has discretion under Section 17(1) of the Hydro and Electric Energy

Act to direct a permittee or licensee to alter or relocate the permittee’s or licensee’s

373 Decision 2003-043, PDF page 18.


Decision 22742-D01-2019 (July 4, 2019) 99

transmission line on any terms and conditions it considers proper. The Commission’s

prerogative to impose conditions could include a requirement that the altered or the

relocated transmission facilities have different characteristics or specifications than

originally proposed. Section 17(2) of that same act provides authority for the

Commission to determine compensation under an application by either party. For

example, the Commission could order the party requesting the relocation to pay some or

all of the costs.374

428. The Commission also stated:

The discussion of the 2003 relocation principles in the proceeding leading to

Decision 2011-520 came about due to the desire of some participants to obtain certainty

with respect to compensation for future transmission line moves proposed to avoid

sterilization of mineable ore. Significantly, consistent with the findings of the board in

Decision 2003-043, the Commission, likewise, only indicated that the 2003 relocation

principles would be considered as and when future applications pursuant to Section 17 of

the Hydro and Electric Energy Act were received.

…

It is accordingly notable that subsequent to Decision 2011-520, in Decision 2014-242, in

respect of the AESO’s 2014 tariff application, the Commission rejected certain changes

proposed by the AESO with respect to the criteria for classifying certain types of

transmission facility projects as system-related costs for the purposes of the AESO’s

contribution policy. Furthermore, in Decision 3473-D02-2015, in respect of the AESO’s

compliance filing application, pursuant to Decision 2014-242, the Commission

established a Commission-initiated proceeding that will include investigation into the

principles to be applied in determining whether the costs of transmission projects should

be classified as system-related.

In the Commission’s view, the forthcoming review of system-related costs in the

aforementioned Commission-initiated proceeding, is a further indication that the 2003

relocation principles may be modified in future applications for a transmission line move

where a transmission line would sterilize mineable ore. The Commission, therefore, finds

the 2003 relocation principles may evolve or change over time.375 [footnotes removed]

429. Notwithstanding these comments, the Commission proceeded to evaluate the allocation

of costs on the basis of the principles set out in Decision 2003-043 along with other arguments

presented, namely the fact that the parties had entered into a cost allocation agreement. It was the

existence of this agreement that led to the determination that CNRL should be responsible for

paying the relocation costs. The Commission stated:

123. Given that no evidence has been provided to show that the relocation of the

transmission facilities exceeded ATCO’s estimated cost of performing this service and

given that CNRL agreed to pay the full costs of the 9L66/9L32 line move project, the

Commission finds no basis to warrant interference with the terms of the agreement. For

the reasons given above, the Commission finds that CNRL has not demonstrated that the

agreement pertaining to the 9L66/9L32 line move project results in a rate, toll or charge

that is insufficient, excessive, unjust or unreasonable in the circumstances. Accordingly,

the Commission will not employ the provisions of Section 81 of the Public Utilities Act

374 Decision 21306-D01-2016, paragraphs 44 and 46. 375 Decision 21306-D01-2016, paragraphs 55, 57 and 58.


Decision 22742-D01-2019 (July 4, 2019) 100

to alter the terms of the agreement including the rate charged to CNRL for the 9L66/9L32

line move project.376

430. Parties have directed the Commission’s attention to other decisions as well. They have

referred to Decision 2014-009. This decision is brief and does not deal with the issue of cost

allocations.

431. With respect to the specific principles enumerated in Decision 2003-043, the board, when

it established these principles, did so on the understanding that when balancing the public

interest and the interest of an affected party, that, provided there is a reasonable cause to move a

system transmission line, the costs for the relocation should be systemized provided that “a valid

mineral lease existed prior to the construction of the transmission line; a practical alternative

route is available; and there are no unusual negative impacts on the AIES that cannot be

reasonably addressed.”377

432. In this proceeding, the Commission has been asked to provide a finding regarding the

allocation of costs associated with a proposed relocation of a portion of a transmission system

line and it is within these restricted circumstances that the Commission has made its

determination.

433. As set out in Decision 2003-043, the board established several principles to provide

guidance when determining who should be responsible for the payment of relocation costs. In

this proceeding, because there is a proposed move of a portion of a transmission system line, the

following facts contribute to a finding that these relocation costs could be allocated to the

system’s customers:

(a) The relocated line is expected to continue to be part of a looped system;

(b) A valid mineral lease exists and existed prior to the construction of the line; and

(c) Practical alternative routes are available, but are to be tested in Proceeding 24246.

These are the alternatives described in the business case as A, B, C and D.

434. The remaining factor identified by the board is whether there are “unusual negative

impacts on the AIES that cannot be reasonably addressed.” The board did not elaborate on what

it meant by this principle. However, this factor appears to address physical issues rather than cost

issues regarding a transmission line relocation.

435. As stated above, when it established these factors, the board did so on the basis that these

factors are demonstrative of a “reasonable cause” to support moving a system transmission line

and the attributed costs of the move to the system’s customers. An example provided by the

board of a reasonable cause was “the sterilization of mineable ore, and direct and unavoidable

conflict with the infrastructure and development required to mine the ore.”

436. AET has asserted that the Kearl line prevents the owner of the Fort Hills mine from

accessing some of the mineable ore and on that basis, has asserted that this resource is sterilized.

In the present case, the Commission finds that AET has not demonstrated that the public interest

376 Decision 2003-043, paragraph 123. 377 Decision 2003-043, PDF page 18.


Decision 22742-D01-2019 (July 4, 2019) 101

balance weighs in favour of assigning all of the costs of the relocation to the system’s customers

simply on the basis that the owner of the Fort Hills mine has claimed that access to mineable

resources will be prevented in this area. In the oral hearing, the Commission asked AET directly

about this matter and AET’s response was:

The rationale that -- from Fort Hills' perspective is that if we don't move the line, the

sterilization of the mineable ore in that area would prevent them from getting access to

anywhere between 500 million to 750 million barrels of recoverable bitumen.378

437. This response and the evidence on the record, including the business case discusses the

impact on the owner of the Fort Hills mine but fails to examine the financial benefits to the

public of extracting this bitumen.

438. Although not filed as evidence in this proceeding, the Commission nonetheless also

reviewed AET’s response to IRs in Proceeding 24246, the related facility application, which is

currently before the Commission.

ATCO-AUC-2019FEB26-004

Preamble: The Commission acknowledges that the transmission line must be relocated to

gain access to recoverable bitumen. However, the Commission would like to understand

what, if any, analysis was undertaken by ATCO or the mine owner to demonstrate that

the resource would in fact be sterilized if some or all of the relocation cost was

determined to be participant-related rather than system-related

Request:

a) Is it ATCO’s position that the mine owner may withdraw its request to relocate the

line if the mine owner is required to pay the cost of the relocation, and therefore

sterilize the resource?

b) If the answer to (a) is no, on what basis does ATCO conclude there will be resource

sterilization?

c) If an economic analysis was undertaken to assess whether recovery of the

approximately 500 to 750 million barrels of recoverable bitumen is uneconomic when

factoring in the cost of the line relocation, please provide the analysis.

AET RESPONSE

a) It is ATCO Electric’s understanding that this relocation is required by the mine

owner, FHELP, to accommodate ongoing development of the Fort Hills mine.

However, ATCO recognizes that any party that has requested a line relocation, or any

electric project for that matter, may withdraw its request prior to commencement of

the project for various reasons. However, in ATCO’s view this has no bearing on the

potential sterilization of resources in the current circumstances.

b) Failure to relocate the line will result in the mine operator being unable to access and

recover the mineable bitumen, resulting in resource sterilization. ATCO relies on the

assessment by the mine owner that failure to relocate the line would result in the

sterilization of as much as approximately 500 million to 750 million barrels of

recoverable bitumen [Exhibit 24246-X0018, pages 5-6].

378 Transcript, Volume 6, page 1015.


Decision 22742-D01-2019 (July 4, 2019) 102

The Commission's question appears to suggest that resource sterilization occurs when

resource extraction becomes uneconomic because the mine owner must bear the cost

of relocation. AET submits that this characterization of the relocation criteria is not

correct. Resource sterilization occurs where access to the resource is impeded by the

current location of a transmission line. Resource sterilization is not contingent on

whether relocation costs are classified as a system or participant cost. In this case,

failure to relocate the line would result in resource sterilization because the mine

owner would be unable to access mineable bitumen.

If the Commission is to adopt an economic test for resource sterilization that "there is

sterilization only where the line cannot economically be relocated’, the Commission

would paradoxically be stating that a line relocation is only eligible for systemization

of associated costs where "the applicant cannot economically justify the relocation".

ATCO submits that this cannot be a correct application of the 2003 relocation

criteria, and further, is not consistent with the Commission’s obligation, when

assessing whether relocation costs should be system costs, to “weigh the benefits of a

proposed project against the costs to be incurred by ratepayers” (Decision 21306-

D01-2016, para. 112).

c) See responses to 004(a) and (b). No such analysis was undertaken, as this is not

required in order to determine the case for resource sterilization.

ATCO-AUC-2019FEB26-005

a) In Table 2.0-1, ATCO has applied the 2003 relocation principles from Decision

2003-043 to the circumstances in this case in order to support its position that the

relocation costs are properly considered system-related. Please comment on what

other factors, if any, should be considered when assessing whether the line relocation

as a cost to ratepayers is in the public interest.

AET RESPONSE

a) In Decision 21306-D01-2016, the Commission stated that when assessing the public

interest, the Commission will generally weigh the benefits of a proposed project

against the costs to be incurred by ratepayers.

…

In this Proceeding, the benefits of relocating the systemized 9L101 line include the

extraction of a significant quantity of additional mineable ore that would otherwise

be sterilized were the line to remain in this location. Continued mining in the area

will only be possible by relocation of the transmission line and will provide

additional economic opportunities to individuals in Alberta, generate a number of

construction and operational jobs, and provide a significant financial benefit to

municipal, provincial and federal governments. To characterize the relocation as a

private benefit to only the mine owner would ignore the considerable benefits in the

public interest of both the continued benefit of mining the ore.

…

439. The Commission disagrees with AET’s assertion that an inquiry into whether a mineral

resource becomes sterilized should be undertaken without regard for consideration of the costs to

relocate the line and who would bear such costs. It is the weighing of these costs relative to the

benefits of relocation that could lead the Commission to determine that it is in the public interest

to allocate the relocation costs of a transmission system line to the system’s customers. However,


Decision 22742-D01-2019 (July 4, 2019) 103

apart from AET’s broad assertions, AET has failed to meet its onus in demonstrating to the

Commission that it is in the public interest to assign the relocation costs to the system’s

customers.

440. Moreover, the Commission agrees with the CCA that given the high costs of transmission

in Alberta, it is in the public interest to send price signals to customers for the costs they cause.

441. In Decision 21306-D01-2016, the Commission also considered whether there was a

contractual arrangement that allocated relocation costs. The Commission notes that AET has

claimed that it is obligated to relocate the line as part of the purchase agreement entered into with

Imperial.379 The asset purchase and sales agreement was provided on the confidential record of

this proceeding.380 The Commission has reviewed the agreement and does not consider there to

be any contractual basis compelling AET to recover relocation costs from the system’s

customers. Consequently, unlike factors weighed by the Commission in Decision 21306-D01-

2016, in these specific circumstances, it cannot consider the provisions of the agreement as

determining who should pay relocation costs.

442. After careful consideration of the above factors, and provided that AET receives an order

from the Commission in Proceeding 24246 to relocate the Kearl line pursuant to Section 17(1) of

the Hydro and Electric Energy Act, the Commission finds that the costs of the relocation should

be the responsibility of the owner of the Fort Hills mine.

443. Nothing in this decision restricts a panel of the Commission from determining a future

relocation of the Kearl line or the costs associated with that relocation.

(2) Forecast capital expenditures for Kearl line

444. Given the above finding the forecast capital expenditures381 in the amount of $1.0 million

and $3.0 million in 2018 and 2019, respectively, are denied.

11.6 Direct assigned capital deferral account

445. The direct assigned capital deferral account (DACDA) is a deferral account designed to

mitigate the risk to both AET and its customers flowing from capital projects that are directly

assigned by the AESO to a transmission utility. The direct assigned capital projects are typically

large and entail execution risks382 in terms of cost and time that are difficult for the utility to

forecast. The account captures the actual costs relative to the forecast costs. As the individual

projects are closed, the utility files an application to true up the actual to forecast costs and adjust

rate base for approved differences.

446. In its evidence, Bema observed that the DACDA has removed significant volatility in

revenue requirements since it was approved by the Commission. Additionally, absent the

DACDA, ratepayers would have paid substantially more for the assets than necessary.383

However, Bema questioned whether the DACDA, in its current design, is necessary going

forward. Bema noted that in 2018 and 2019, AET’s forecast direct assigned capital additions are

379 Exhibit 22742-X0171. 380 Exhibit 22742-X0171, Conf-01. 381 Exhibit 22742-X0171.04, 2-0 TCM business case, PDF page 826. 382 Such risks can include landowner issues, weather and regulatory delay. 383 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 13.


Decision 22742-D01-2019 (July 4, 2019) 104

$147.4 million and $130.5 million, respectively, which are either less than or generally

consistent with the actual/forecast non-direct assigned capital additions in 2018 and 2019 of

$131.9 million and $149.7 million, respectively. There is no deferral account for non-direct

assigned capital additions. Bema noted that non-direct assigned capital additions are trued up as

part of an opening rate base adjustment within AET’s next GTA.384

447. Bema suggested that AET’s future direct assigned capital additions are likely to be in the

range of $30 million to $50 million per year ignoring the potential for future system projects. In

Bema’s opinion, this base level of direct assigned capital should be well within AET’s control to

manage on a forecast basis absent a deferral account.385 It was Bema’s understanding that, prior

to the implementation of the original performance-based regulation regime and capital trackers,

distribution utility owners often had their entire capital program subject to forecast risk.386

448. Bema recommended that the Commission adjust the DACDA process to include specific

criteria for the 2018 and 2019 forecast test periods. According to Bema, only those projects that

meet the following criteria should qualify for deferral account treatment:

(a) Any direct assigned capital project with a combined increase in net rate base (after

considering customer contributions) of greater than $50 million;

(b) Any direct assigned capital project with a combined increase in net rate base (after

considering customer contributions) of greater than $25 million but less than $50

million, that has a variance from the PPS (Proposal to Provide Service) estimate of

greater than 20 per cent; or

(c) Any direct assigned capital project with a combined increase in net rate base (after

considering customer contributions) of greater than $10 million but less than

$50 million that has had its capital additions shift into a different year from that

originally forecast.387

449. In the CCA’s view, all other direct assigned capital additions should be subject to normal

forecast risk given the comparatively modest impact those additions are likely to have on the

forecast revenue requirement.

450. In rebuttal evidence, AET did not support the changes to its DACDA recommended by

Bema. AET stated that the deferral account in its current form served its intended purpose by

mitigating risk to both AET and customers. AET stated that a reduction in the total amount of

direct assigned projects does not equate to an increase in AET’s ability to control the timing and

cost of these projects.388

451. AET noted that its direct assigned capital represents 54 per cent and 47 per cent of its

total capital program in 2018 and 2019, respectively, which AET considered significant in terms

of its ability to control its overall capital program. It added that despite the reduced scale of the

direct assigned capital program in the test period compared to 2015, for example, the fact

384 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 14. 385 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 15. 386 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 16. 387 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 51. 388 Exhibit 22742-X0618, AET rebuttal evidence, page 8.


Decision 22742-D01-2019 (July 4, 2019) 105

remained that the quantum, timing and cost of direct assigned projects remain out of AET’s

control and, instead, are largely subject to directions from AESO NID applications and decisions

from the AUC (NID and facility applications to establish the need for projects as well as scope,

for example, routing considerations).389

452. AET submitted that it has a significantly higher level of control of the factors and

considerations it takes into account when developing its non-direct assigned project GTA

forecasts. The same level of control is not available for direct assigned projects given the

directions and decisions from the AESO, the AUC and the government of Alberta.

453. AET supplied a list of projects from the current and previous test period that, in its view,

highlighted the appropriateness of deferral account treatment. AET stated that its opinion was

informed by the Commission’s findings in Decision 2010-189390 containing the four factors that

are highlighted by Bema’s evidence, namely the:391

(a) Materiality of the forecast amounts;

(b) Uncertainty regarding the accuracy and ability of forecast the amounts;

(c) Whether or not the factors affecting the forecasts are beyond the utility’s control;

and

(d) Whether or not the utility is typically at risk with respect to the forecast amounts.

454. The fifth factor in Decision 2010-189 is symmetry and was not referenced by the CCA.

Commission findings

455. The Commission acknowledges the CCA’s submissions with respect to amending the

criteria to evaluate when DACDAs should be relied upon. The Commission observes that all

transmission utilities have an account that is similar to or the same as AET’s and these accounts

have been in existence for several years to reconcile direct assigned capital forecasts and actual

amounts that are subject to the decisions of the AESO for AET’s direct assigned projects. The

Commission finds that it is reasonable, absent compelling grounds to the contrary or a change in

circumstances that would suggest the DACDA would not meet the factors in Decision 2010-189,

not to modify the AET DACDA in this proceeding.

456. The symmetry factor found in Decision 2010-189 states:



proceeding, took the view that “deferral accounts should not be for the sole benefit of

either the company or the customers.” Deferral accounts, rather, should “provide a degree


control,” and hence “Symmetry must exist between costs and benefits for both the

Company and its customers.” The Board also noted that it expected that “the individual


and fair manner in both test years and non-test years.” This will be referred to as the

symmetry factor. [footnotes removed]

389 Exhibit 22742-X0618, AET rebuttal evidence, page 9. 390 Decision 2010-189: ATCO Utilities Pension Common Matters, Proceeding 226, Application 1605254-1,

April 30, 2010. 391 Exhibit 22742-X0618, AET rebuttal evidence, page 10, refers to Exhibit 22742-X0592, paragraph 25.


Decision 22742-D01-2019 (July 4, 2019) 106

457. Applying the symmetry factor, the Commission also considers that the current structure

has worked well to protect the interests of both AET and its customers for both the costs and

benefits of utility service, a fact acknowledged by the CCA itself.392

11.7 Engineering, supervision and general costs

458. AET’s engineering, supervision and general (ES&G) costs were detailed in the

application.393 This category of costs is separate from supervision and engineering costs to

support O&M. Those costs are included in USA 560.394

459. Consistent with previous applications, AET’s policy, based on International Accounting

Standards (IAS) 16 property, plant and equipment395 is to include in capital all costs that relate to

the construction of a capital project. The ES&G accounting policy was provided as an

attachment to the application. AET provided a brief explanation of the costs typically included in

ES&G.396

460. AET explained that ES&G costs decreased from 2015 to 2016 due to staff reductions

attributable to fewer capital project-related activities. The forecast ES&G costs for the 2018-

2019 test period remained consistent with the 2016 actuals and 2017 forecast. The ES&G rate is

calculated by dividing ES&G costs by capital expenditures. However, AET explained that the

relationship between ES&G costs and capital expenditures is not linear and the workload of

many of the functional groups (such as Accounts Payable, Human Resources, Fixed Assets

groups) included in ES&G does not directly correspond to capital expenditures.397

461. For 2017 and for the 2018-2019 test period, the ES&G rate decreased from 2016 due

mainly to capital expenditures being higher in 2017 and in the 2018-2019 test period relative to

2016.398

462. In argument, AET noted that it explained in its direct evidence399 that it updated the

values in Schedule 10-6, Schedule of Transmission ES&G, to correct for some costs that were

inadvertently excluded in the application update400 and indicated that it would reflect the required

changes in its compliance filing. As no significant issues were raised regarding ES&G, AET

submitted that its ES&G forecast for the test period should be approved, as filed.401

463. In reply argument, the CCA stated that ultimately all forecast ES&G costs would be

assessed for reasonableness either in a future DACDA application or in AET’s opening rate base

at the time of its next GTA.

392 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 33. 393 Exhibit 22742-X0001.02, Schedule 10-6 and Table 10.25. 394 Exhibit 22742-X0001.02, updated application, PDF page 391. 395 Exhibit 22742-X0001.02, updated application, PDF page 391, refers to International Financial Reporting

Standards, International Accounting Standard 16 for property, plant and equipment. 396 Exhibit 22742-X0001.02, PDF page 392. 397 Exhibit 22742-X0001.02, PDF page 393. 398 Exhibit 22742-X0001.02, PDF page 393. 399 Transcript, Volume 2 pages 355-347. 400 Exhibit 22742-X0533, the application update dated September 4, 2018. 401 Exhibit 22742-X0725, AET final argument, page 89.


Decision 22742-D01-2019 (July 4, 2019) 107

Commission findings

464. The Commission has examined the evidence in the application, in particular

Schedule 10-6,402 as well as the responses to IRs. Given this evidence, the forecast ES&G

amounts are approved as filed, subject to any changes necessary due to findings or directions

elsewhere in this decision.

465. The Commission agrees with the observation of the CCA that ES&G costs will be

reviewed either in a future DACDA application or as part of AET’s next opening rate base when

actuals are known and can be assessed for reasonableness.

11.8 Construction work in progress refund

466. In its original application, AET proposed to refund previously collected revenues related

to the construction work-in progress (CWIP)-in-rate base accounting treatment for AESO direct

assigned capital projects in the 2013-2016 period. It was AET's intention to refund

$130.8 million in each of 2018 and 2019 ($261.6 million total), including return on the CWIP

balances and income tax amounts collected in revenue requirement. In return, AET proposed to

add $123.1 million of AFUDC to rate base in each of 2018 and 2019 ($246.2 million total).403

467. In its September 4, 2018 application update, AET withdrew its CWIP-in rate-base refund

proposal. AET explained that since it prepared and filed its original application in the first half of

2017, its parent companies had experienced changes in circumstances, including a credit rating

downgrade issued by Standard & Poor's (S&P) in July 2017.404

468. Mr. Bell, on behalf of the UCA, supported AET’s initial proposal for the CWIP-in-rate

base refund. In his evidence, Mr. Bell stated that the collection of CWIP-in-rate base had resulted

in higher than necessary costs, with the result that customers paid higher than necessary rates for

the services they received. This is because CWIP-in-rate base allows for the collection of return

and income tax related to CWIP balances, effectively pre-funding the construction costs of new

assets. In Mr. Bell’s view, this pre-funding of assets created intergenerational inequities. That is,

during the “big build,” customers paid costs that were properly “due to”405 future customers.

Mr. Bell asserted that the refund of CWIP in-rate-base amounts, as initially proposed by AET,

would have put current customers in the same position they would have been in had the CWIP-

in-rate base credit metric relief not been granted.

469. Mr. Bell submitted that the S&P downgrade was largely a result of the pressure on credit

metrics caused by the Edmonton to Fort McMurray transmission line. He argued that this line

was not an AET asset and maintained that AET’s regulated customers should not be forced to

subsidize the credit metrics of one or more unregulated ATCO entities. He added that, for the

same time period, DBRS Limited (DBRS) issued no similar credit downgrade to AET’s parent

companies.406

402 Exhibit 22742-X0001.02, PDF pages 447-449. 403 Exhibit 22742-X0001.02, updated application, Section 3.8, page 117. 404 Exhibit 22742-X0533, paragraph 5. 405 Exhibit 22742-X0599, page 8. 406 Exhibit 22742-X0599, page 9.


Decision 22742-D01-2019 (July 4, 2019) 108

470. The UCA also noted that in the updated application, AET referred to “prevailing”

economic conditions407 as a reason to withdraw its offer to refund CWIP balances. The UCA

understood this to mean the “poor” economic conditions. The UCA submitted that, if this is what

AET actually meant, then those very same prevailing economic conditions dictate that a refund

of CWIP-in-rate base be issued to provide economic relief to present day customers.

471. Finally, the UCA noted that while the aim of including CWIP-in-rate base was to

improve credit metrics for AET, which may benefit customers, the UCA claimed it also

benefitted all of the ATCO group of companies. The UCA submitted that AET's customers

deserve to be reimbursed for having paid more than $200 million in higher than necessary rates

to provide AET with a source of financing for CWIP. The UCA proposed, pursuant to Rule 023:

Rules Respecting Payment of Interest, that customers be refunded an additional $31.5 million in

carrying costs on the $261.2 million refund.408

472. In rebuttal evidence, AET submitted that the UCA's claim that “the collection of funds

related to CWIP-in-rate base results in customers paying costs in excess of what would normally

be incurred” was factually incorrect and inconsistent with the findings provided in the AUC’s

Decision 2011-134409 on AET’s 2011-2012 GTA. In particular, AET noted, the Commission

stated as follows:410

532. The Commission also notes that by suspending the current construction work in

progress accounting procedures, in the long run, the overall cost to customers for new

assets is less than what it would be under the current … AFUDC accounting practice.

This is because it is always more expensive to postpone payment of an asset due to the

interest or return cost associated with postponing payments. As a simple analogy,

suspending this relief is similar to financing a home by putting a larger down payment on

a home at the outset. The home is less costly in the long run because the down payment

has reduced the amount of interest paid over the life of the mortgage. Therefore, in the

long run, the suspension of current construction work in progress accounting measures

[i.e., AFUDC] reduces the total cost of an asset because it reduces the amount of return

customers pay to the utility.

473. AET also maintained that there were no findings in Decision 2011-134 supporting the

UCA’s claims that customers were “forced to subsidize AET and ATCO” or that there was any

cross-subsidization occurring between AET and its affiliates as result of AET receiving approval

of the CWIP-in-rate base treatment during the 2011-2016 period. AET noted that the

Commission's decision to allow CWIP-in-rate base during the “big build” was made with

customers’ interests in mind. If no credit relief had been provided, CU Inc. may have

experienced a credit rating downgrade which would have led to higher borrowing costs for the

utility and, in turn, higher rates for customers.

474. AET stated that the UCA’s assertion that S&P provided a credit rating downgrade based

on the Fort McMurray transmission line ignored the evidence on the record and the clear

statement from S&P in the downgrade report that, “Over the past few years, these metrics have

407 Exhibit 22742-X0533, paragraph 5. 408 Exhibit 22742-X0599, page 12. 409 Decision 2011-134: ATCO Electric Ltd. 2011-2012 Phase I Distribution Tariff 2011-2012 Transmission

Facility Owner Tariff Application 1606228-1 Proceeding 650, April 13, 2011. 410 Decision 2011-134, paragraph 532.


Decision 22742-D01-2019 (July 4, 2019) 109

declined as the company411 embarked on a significant capital program.”412 AET claimed that this

statement suggested the “big build” had an impact on its parents’ credit rating. AET added that in

its most recent credit ratings report dated September 27, 2018, S&P clearly stated that the Fort

McMurray transmission line is excluded from its credit metric calculations.413

475. AET also responded to the UCA’s suggestion that customers have been “out of pocket for

over $200 million,”414 and deserved to be compensated for having financed CWIP. AET

submitted that this statement failed to recognize the inherent trade off between the CWIP-in-rate

base treatment and the AFUDC treatment. AET noted that in paragraph 532 of AUC Decision

2011-134 (reproduced above), the Commission explained that, in the long run, the overall cost to

customers for new assets was less than what it would be under the traditional AFUDC method.

476. AET submitted that no accumulated CWIP-in-rate base balance exists to which carrying

costs should be applied.415 AET explained that, under the traditional AFUDC method, the utility

internally funds the debt and equity obligations, as these are required (annually, at a minimum),

for its capital program prior to the asset going into service. As the utility funds the costs for these

obligations, the utility is then permitted to capitalize these costs and recover these financing costs

through return, depreciation and income tax over the life of the asset. As these financing costs

were funded through customer rates, AET did not capitalize any of these costs as it would have

done under the traditional AFUDC method. Since AET used the funds received from its

approved tariffs to meet its financing obligations as they arose, AET was left with no residual

funds provided by customers. As such, AET submitted that there was no basis to support

applying carrying charges to the amounts funded though CWIP-in-rate base.

477. In argument, ADC and IPCAA submitted that the Commission should approve AET’s

originally proposed refund in the 2018-2019 test period of $261.3 million in CWIP, collected

between 2013 and 2016.

478. ADC and IPCAA noted that the S&P credit report stated, in part:

A significant contributor to the stressed credit metrics is construction of the Edmonton to

Fort McMurray transmission line, which will continue to pressure credit metrics in the

medium term … Because we consider CU Ltd. and CU Inc. core to ATCO under our

group rating methodology criteria, we have equalized the ratings on the subsidiaries with

those on the parent.416

479. ADC and IPCAA argued that the reason for the S&P downgrade was largely a result of

the pressure on credit metrics caused by the Edmonton to Fort McMurray transmission line. As

this was not an AET asset, AET customers should not be asked to subsidize credit metrics for

AET’s parent. As such, it was the view of ADC and IPCAA that the S&P credit downgrade to

411 In the Commission’s view, the company in this context means ATCO Ltd. based on the following: “S&P Global

Ratings lowered its long-term corporate credit and senior unsecure debt ratings on Calgary, Alta.-based ATCO

Ltd. (ATCO), and its subsidiaries Canadian Utilities Ltd. (CU Ltd.) and CU Inc., to ‘A-’ from ‘A’.” See Exhibit

X22742-X0264.01, response to AET-UCA-2017AUG30-016(b), Attachment 10, page 2 of 7. 412 Exhibit 22742-X0264.01, AET-UCA-2017AUG30-016(b) Attachment 10. 413 Exhibit 22742-X0618, AET rebuttal evidence, Appendix A. 414 Exhibit 22742-X0599, Bell evidence on behalf of UCA, PDF page 11. 415 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 200. 416 Exhibit 22742-X0721, ADC IPCAA final argument, paragraph 13.


Decision 22742-D01-2019 (July 4, 2019) 110

AET's parent companies was irrelevant and, thus, provided no basis for withdrawing the earlier-

proposed refund.

480. ADC and IPCAA also stated that the need for CWIP-in-rate base to support the “big

build” has ended. They submitted that the associated balances must be refunded and doing so

now would not only minimize any intergenerational inequity, but would meet a pressing need for

lower rates for industrial electricity customers in the face of Alberta’s challenging economic

climate.

481. In its argument, the CCA opposed the CWIP in-rate base refund for the following

reasons:417

(i) Many of the reasons and conditions that supported a refund in AltaLink

Management Ltd.’s (AltaLink) 2015-2016 GTA are not present in the current

AET 2018-2019 GTA;

(ii) The refund of previously collected CWIP-in-rate base will result in a rate shock

for ratepayers of as much as 20 per cent in 2020 relative to 2019418 when base

rates no longer include the one-time refund;

(iii) The base rates going forward will be permanently higher for future ratepayers

beginning in 2020, which is not in the public interest; and

(iv) A refund is not needed to offset current forecast increases in the 2018 and 2019

test periods, both in the context of AET’s application and in the broader context

of regulated revenues for Alberta’s electric distribution and transmission utilities.

482. In its argument, the UCA continued to support the refund, stating that the customers of

today should not be required to prepay costs that are rightly attributable to customers of the

future, with the sole benefit being to potentially reduce rates in the future.419

483. The UCA noted that while AET relied upon different credit rating agency reports to

support its decision to remove the CWIP refund from its application, no witness from either of

the agencies that prepared those reports appeared during the oral hearing. In the absence of a

rating agency witness capable of speaking to any of the credit ratings reports filed on the record

of this proceeding, the UCA maintained that all parties and the Commission were required to rely

solely on information provided on the face of the documents.420

484. The UCA submitted that based upon a review of the credit ratings reports filed in this

proceeding, it was apparent that the pressure on ATCO Ltd.’s credit ratings, and the credit

downgrade for AET's parents in the July 25, 2017 S&P report, was overwhelmingly the result of

unregulated activities, rather than those of a regulated entity like AET. The UCA pointed out that

S&P expressly stated that the Edmonton to Fort McMurray transmission line was a “significant

contributor to the stressed credit metrics.”421

417 Exhibit 22742-X0613, CCA-AUC-2018DEC19-012 Attachment 1, Sections 2.1-2.3. 418 Exhibit 22742-X0722, CCA final argument, paragraph 175. 419 Exhibit 22742-X0599, page 8. 420 Transcript, Volume 4, page 619, lines 13-18. 421 Exhibit 22742-X0724, UCA final argument, page 11.


Decision 22742-D01-2019 (July 4, 2019) 111

485. The UCA also noted that S&P stated that it has “equalized the ratings on the subsidiaries

with those on the parent.”422 The UCA submitted423 that this seemed to imply that the parents’

ratings have been weighted down because of the unregulated activities of the ATCO group of

companies. In the absence of evidence to the contrary, it appeared to the UCA that customers of

regulated entities were being asked to provide support to the credit metrics of unregulated

entities. The UCA considered this inappropriate and unfair.424

486. The UCA noted that the Commission has ruled on the issue of refunding previously

collected CWIP-in-rate base amounts before, such as in Decision 3524-D01-2016 dealing with

AltaLink’s 2015-2016 GTA.425 The UCA further noted that there were similarities between

AltaLink’s proposed refund of CWIP balances and the CWIP refund that was initially proposed

by AET in this proceeding.

487. In light of the similarities between this proceeding and Proceeding 3524 for AltaLink, the

UCA submitted that the CWIP refund is in the public interest. Specifically, the evidence on the

record provides that the CWIP refund would not result in intergenerational inequities426 and

the resulting FFO-to-debt ratio would be sufficient to maintain a credit rating in the lower “A”

range. The CWIP refund is further supported by the fact that AET ratepayers continue to face

the economic challenges in Alberta that were present when AET initially proposed the CWIP

refund.427

488. The UCA referred to Commission counsel's questioning of Mr. Bell on whether the

refund should be treated as no-cost capital.428 Mr. Bell stated on the question of carrying costs

versus no cost capital that: “They to me are two ways to try to get to the same thing, to

compensate customers for the fact that the utility had those funds at their disposal in the

intervening year. And so I see either as acceptable. I prefer the Rule 23, but either would be

acceptable.”429

489. AET commented on the UCA's recommendation that the CWIP refund occur over the

2018-2019 period, given the prevailing economic conditions. In this regard, AET noted that

in each of the Commission's past three decisions dealing, respectively, with AET's 2011-

2012, 2013-2014 and 2015-2017 test periods, where the CWIP-in-rate base treatment was

approved, there was no stipulation or expectation expressed that a refund to customers

would occur once AET returned to the traditional AFUDC method or, indeed, at any point in

the future. AET submitted that it has provided strong support for not implementing a refund

of the CWIP-in-rate base due to both the credit rating downgrade by S&P in July 2017, as

well as the current economic circumstances in Alberta. In its rebuttal evidence, AET

included the most recent S&P credit rating report, dated September 27, 2018. In this report,

S&P noted the removal of the initially proposed CWIP-in-rate base refund and reflected this

422 Exhibit 22742-X0611, PDF page 6, UCA-AET-2018DEC21-001(b). 423 Exhibit 22742-X0264.01, AET-UCA-2017AUG30-16(b), Attachment 10, PDF pages 98-99. Also noted in

Exhibit 22742-X0721, ADC and IPCAA final argument, paragraph 13. 424 Exhibit 22742-X0724, UCA final argument, paragraph 29. 425 Decision 3524-D01-2016, AltaLink Management Ltd.’s (“AML”) 2015 – 2016 General Tariff Application. 426 Exhibit 22742-X0202, PDF page 77, AET-CCA-2017AUG30-132 (b). 427 Exhibit 22742-X0599, page 22. 428 Transcript, Volume 7, page 1297-1300. 429 Transcript, Volume 7, page 1300, lines 12-16.


Decision 22742-D01-2019 (July 4, 2019) 112

in its "base case" scenario.430 As such, AET submitted that the request included in its

application update be approved, as filed.

490. In its reply argument, the UCA noted that in decisions 2011-453 and 2013-407, in which

the Commission approved CWIP-in-rate base treatment for AltaLink, the Commission made no

reference to a future refund of CWIP once AltaLink returned to the AFUDC method or at any

other point in the future. Nevertheless, the Commission approved the refund of previously

collected CWIP-in-rate base amounts in Decision 3524-D01-2016.13

491. AET noted that, in their argument,431 ADC and IPCAA maintained that it was appropriate

to return to ratepayers the temporary relief provided to AET. AET disagreed with this assertion

and noted that ADC and IPCAA provided no evidence to support why such a course of action is

required or appropriate. AET made it clear that it was under no obligation to bring forward a

proposal to refund past CWIP-in-rate base amounts.

492. AET challenged the UCA's insistence on attributing the credit rating downgrade in July

2017 to non-regulated activities.432 According to AET, this selective view of the S&P reports

ignores the comments actually made by S&P, namely, that: “Over the past few years, these

metrics have declined as the company embarked upon a significant Capital Program.”433

493. Finally, AET observed that in approving AET's original request to include CWIP-in-rate

base treatment, the Commission, in Decision 2011-134,434 confirmed that it must have regard to

the impact its decision will have on the financial health of the utility it regulates. AET submitted

that the same considerations apply in the circumstances of this application. AET stated that it had

valid and legitimate concerns regarding the potential for a further credit rating downgrade, based

on the observations made by S&P in its September 2018 report.

Commission findings

494. In Decision 3524-D01-2016,435 associated with a refund of CWIP in AltaLink’s 2015-

2016 GTA, the Commission made the following determinations:

For the above reasons, the Commission finds it to be in the public interest to approve

AltaLink’s proposed refund of the previously collected CWIP-in-rate base amounts,

subject to the following adjustments:

AltaLink is permitted to refund the CWIP-in-rate base amounts collected for

DACDA projects, with the exception of those projects that have been finalized in

Decision 2013-407 or in Decision 2044-D01-2016.

The amount of the accumulated return, depreciation and taxes accruing to AltaLink

on the AFUDC portion of capital additions that would have been added to rate base

in the years 2012 to 2014 will be accounted for in the DACDA proceedings for each

430 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 213. 431 Exhibit 22742-X0721, ADC and IPCAA final argument, page 1. 432 Exhibit 22742-X0724, UCA final argument, pages 8-9. 433 Exhibit 22742-X0264, page 98. 434 Decision 2011-134: ATCO Electric Ltd. 2011-2012 Phase I Distribution Tariff 2011-2012 Transmission

Facility Owner Tariff, Application 1606228,-1 Proceeding 650, April 13, 2011. 435 Decision 3524-D01-2016: AltaLink Management Ltd. 2015-2016 General Tariff Application, Proceeding 3524,

Application 1611000-1, May 9, 2016.


Decision 22742-D01-2019 (July 4, 2019) 113

of the relevant projects. AltaLink is to adjust all DACDA projects not approved on a

final basis in Decision 2013-407 or in Decision 2044-D01-2016 to include AFUDC

in accordance with normal historic regulatory accounting practices in its compliance

filing and file an update that includes the relevant AFUDC-related amounts in

Proceeding 3585.

Customers and AltaLink are to be kept revenue neutral from any adjustment made to

the above DACDA projects in AltaLink’s applications, by refunding the accumulated

return on CWIP balances that were paid to AltaLink, in addition to any return earned

on those amounts, calculated based on the WACC for the period from the date on

which the amounts were received, and accounting for any other impacts.436

495. The principle, which was espoused in Decision 3524-D01-2016 for AltaLink dealing with

the application for a refund of CWIP-in-rate base, was that customers and the utility are to be

kept revenue neutral from any adjustment made to capital projects, by refunding the accumulated

return on CWIP balances paid. In addition to any balances paid, adjustments are made to returns

earned on those amounts, calculated based on the weighted average cost of capital for the period

from the date on which the amounts were received, and accounting for any other impacts.437 The

adjustment of CWIP accounts for customers effectively contributing funds in excess of what

would have been required through AltaLink's revenue requirement under AFUDC.438

496. In its September 2018 application update, AET’s original proposal to refund accumulated

return on CWIP balances was withdrawn by AET. Mr. Bell, on behalf of the UCA, stated that

AET’s original proposal to refund accumulated return on CWIP-in-rate base, puts customers on a

level playing field because “during the period of the big build, customers were effectively

required to pre-fund construction costs of assets in rates in support of utility credit metrics.”439

The UCA accepted this position of Mr. Bell and recommended that the CWIP amount of

$261.2 million be refunded to customers.440

497. AET stated that it withdrew its request for a CWIP-in-rate base refund because its parent

experienced changes in circumstances, including a credit rating downgrade in 2017. The UCA

opposed AET’s withdrawal of its request and argued that AET should be required to refund its

previously collected CWIP-in-rate base amounts and re-apply the capitalized interest (which is

AFUDC) in accordance with normal historical regulatory accounting practices.

498. Parties registered in the proceeding are split in their views as to whether AET should

refund previously collected CWIP-in-rate base amounts. The UCA, ADC, and IPCAA requested

that the Commission direct AET to refund the CWIP-in-rate base amounts, while the CCA and

AET are opposed to any suggestion that AET be required to refund these amounts.

499. The UCA, as acknowledged by its witness, Mr. Bell, did not review AET’s original

proposal in detail:

Q. Okay. And did you review ATCO Electric's calculations of its proposed refund for the

CWIP in rate base?

436 Decision 3524-D01-3524, paragraph 953. 437 Decision 3524-D01-2016, paragraph 953. 438 Decision 21827-D01-2016, paragraph 81. 439 Exhibit 22742-X0599, Bell evidence on behalf of the UCA, page 8. 440 Exhibit 22742-X0724, UCA final argument, paragraph 64.


Decision 22742-D01-2019 (July 4, 2019) 114

A. I reviewed them in general, and -- but I didn't do any detailed calculations to validate

them.441

500. The UCA’s primary ground for requesting that AET be directed to refund previously

collected CWIP-in-rate base amounts, relates to intergenerational inequity. In the UCA’s view,

“customers of today should not be required to prepay costs that are rightly attributed to

customers of the future, with the sole benefit being to potentially reduce rates in the future.”442

501. With respect to financing the costs of capital assets, in Decision 2011-134, the

Commission stated the following:

549. The Commission, pursuant to Section 122 of the Electric Utilities Act, when

approving a tariff, must have regard to the impact that its decision will have on the

financial health of the utility it regulates. As well, the Commission must also ensure that

it minimizes the effects on consumer rates. In circumstances where capital expenditures

are forecast to be much higher than in the past, the traditional rate regulatory accounting

approach may not allow the Commission to effectively carry out those tasks. Therefore,

the Commission must respond. In this proceeding, the Commission has chosen to respond

by allowing the utility to recover the financing costs of the assets (but not the costs of the

assets) through rates today so that the utility can maintain its financial health and keep its

interest costs and other financing costs down during the construction period. Further,

customers are not burdened by higher interest and other financing costs today and

customers ultimately pay less overall for the new assets that may be approved and

constructed.443

502. In past decisions approving AET’s request for collecting CWIP-in-rate base to support its

credit metrics during what has been referred to as the “big build” period, the Commission took

into account that AET’s credit metric relief from CWIP-in-rate base would reduce the financing

costs, which would be passed onto customers through lower future rates. AET was allowed to

include CWIP-in-rate base in its revenue requirement from 2011 to 2016, with the Commission

determining that credit metric support from CWIP-in-rate base was no longer required in 2017.444

503. In this proceeding, the Commission must determine whether refunding the accumulated

return on CWIP balances paid by AET’s ratepayers assists in preserving the financial integrity of

the utility and/or avoids causing it financial hardship. Consistent with earlier established

principles, the Commission also considers that customers and the utility must be kept revenue

neutral from any adjustments made to capital projects, should a refund of the accumulated return

on CWIP balances be ordered. The Commission finds insufficient evidence on the record of this

proceeding to support the recommendation of the UCA, ADC and IPCAA for AET to issue a

refund of CWIP-in-rate base. In particular, there is no evidence to suggest that such a refund

would be revenue neutral, nor have any calculations of the proposed refund been verified or

subjected to critical scrutiny.

504. The Commission accepts AET’s position that no CWIP-in-rate base refund is required or

was ever a condition of granting CWIP-in-rate base at first instance. The Commission is also not

441 Transcript Volume 7, page 1298, lines 3-6. 442 Exhibit 22742-X0724, UCA final argument, paragraph 19. 443 Decision 2011-134, paragraph 549. 444 Decision 20272-D01-2016, paragraph 1310.


Decision 22742-D01-2019 (July 4, 2019) 115

persuaded in the circumstances of this proceeding that a claim of intergenerational inequity or

concerns about the FFO-to-debt ratio alone are sufficient to require a CWIP refund.

505. Parties extensively commented on the circumstances of a previous AltaLink refund of

CWIP-in-rate base. The Commission notes that the AltaLink CWIP-in-rate base refund that was

ultimately approved by the Commission in Decision 22930-D01-2017445 was related to a broader

proposal for credit relief. This is illustrated in paragraph 2 of Decision 3524-D01-2016, dealing

with AltaLink’s 2015-2016 GTA, where the Commission accepted the tariff relief and credit

metric support for:

The use of subordinated debt.

The discontinuance of the collection of CWIP-in-rate base amounts and the return to

AFUDC accounting effective January 1, 2015.

The refund to customers of the CWIP-in-rate base amounts for capital projects for the

years 2012 to 2014.

The application of the future income tax method for calculating income taxes for 2015

and the flow-through method for calculating income taxes for 2016.

506. The circumstances for a CWIP refund for AET are not comparable to those in the

AltaLink proceeding. The Commission accepts that AET has withdrawn its CWIP-in-rate base

proposal because of the credit rating downgrade.

507. For these reasons, the Commission denies the UCA’s proposal to direct AET to refund

previously collected CWIP-in-rate base amounts.

12 Necessary working capital

508. Necessary working capital is added to total rate base when payment of expenses occurs in

advance of the receipt of revenues.

509. In Decision 20272-D01-2016, the Commission directed AET to “prepare and file an

updated comprehensive lead/lag study as part of its next GTA application.”446 AET complied

with this direction by filing its 2016 lead/lag study in the current application. AET submitted that

the methodology used to prepare its study was consistent with its “previously approved 2013

study.” The 2016 study resulted in a change of lead/lag days from 212.81 to 223.10, mainly due

to “an increase in the operating expense lag for flow-through property tax payments to AED.”447

510. AET stated that the 2016 lead/lag days were applied to the 2016 actual revenues and

operating expenses to determine the net transmission operating expense lag. The updated

weighted revenue lag days, based on the 2016 actual revenues, were then applied to the 2016

445 Decision 22930-D01-2017: AltaLink Management Ltd., 2015-2016 General Tariff Application Third

Compliance Filing, Proceeding 22930, December 22, 2017. 446 Decision 20272-D01-2016, paragraph 1231, Direction 84. 447 Exhibit 22742-X0001.02, updated application, paragraphs 487-490.


Decision 22742-D01-2019 (July 4, 2019) 116

lead lag results for income tax, depreciation, interest expense, preferred equity and common

equity to determine the net lag days for these components of working capital.

511. A summary of the proposed necessary working capital by component is shown in the

table below:

Table 34. Summary of transmission necessary working capital

Description

2015 Actuals

2016 Actuals

2017 Actuals

Test period

2018 2019

($ million)

Operating expense 12.9 11.4 12.2 8.7 8.6

Income tax expense (1.9) 0.4 0.2 0.4 1.3

Materials & Supplies inventory 3.7 3.7 3.2 2.9 2.5

Rate case expense 1.9 1.0 0.2 (0.3) (0.2)

Goods & services tax 0.4 0.3 0.3 0.1 0.1

Depreciation expense 16.8 22.6 23.0 23.6 24.0

Unamortized debt costs 16.3 16.6 15.9 15.5 15.3

Unamortized preferred share costs 0.2 0.0 0.0 0.0 -

Interest expense (19.3) (19.4) (18.8) (18.4) (18.4)

Preferred equity (0.0) (0.0) (0.0) (0.0) (0.0)

Common equity (retained earnings component) 9.3 11.0 11.6 9.9 9.9

Common equity (dividend component) (0.1) (0.1) (0.2) (0.1) (0.1)

Total necessary working capital 40.2 47.3 47.7 42.2 43.0

Source Exhibit 22742-X0002.04, GTA schedules, Schedule 11-1

512. The CCA submitted that AET’s working capital calculation does not properly reflect the

timing of its VPP payment because “AET [ATCO Electric - Transmission] is receiving the

revenues well in advance of requiring a payment of VPP.”448 Specifically, the CCA stated, “AET

receives revenues in its revenue requirement for the payment of VPP but does not actually pay

VPP until the following year, often at the end of the first quarter….”449

513. Similarly, the CCA argued that the timing of AET’s base salary increases was delayed to

the beginning of the second quarter, resulting in a delay of when actual payments were made

compared to when forecast payments were to be received.450

514. As a result, the CCA requested that the Commission direct AET to revise its working

capital calculations to properly reflect the timing of the VPP payments and the base pay salary

increases.

515. AET rejected the CCA’s assertion that an adjustment was required to its necessary

working capital calculations for VPP payments. It pointed out that during the oral hearing,

448 Exhibit 22742-X0722, CCA final argument, paragraph 769. 449 Exhibit 22742-X0722, CCA final argument, paragraph 768. 450 Exhibit 22742-X0722, CCA final argument, paragraph 770.


Decision 22742-D01-2019 (July 4, 2019) 117

AET’s witness, Mr. Hoshowski, “outlined where the lag in the VPP payments is reflected in the

GTA schedules and the lead/lag study.”451

516. AET also challenged the CCA submission that an adjustment to necessary working

capital was required to account for the timing of base pay salary increases. It explained as

follows:

… The referenced increase in base salary and the associated delay is only applicable to

out-of-scope employees, whose salary increases typically occur on April 1, versus in-

scope employees whose increases occur effective January 1 each year. AET submits that

no adjustment is required, given that AET develops its O&M/A&G labour forecast for

out-of-scope labour based on the labour costs that properly consider the economic

increase in labour costs on April 1 and properly reflects this over the remaining nine

months of the year …452

Commission findings

517. The Commission observes that the majority of the decrease in necessary working capital

for the test period relative to 2016 and 2017 actuals, as shown in Table 34 above, results from an

increase in the operating expense lag for flow-through property tax payments to AED. This then

lowers the number of net lag days being used for the operating expense working capital

calculation from 30.2 days to 20.1 days.

518. The Commission has reviewed the 2016 lead/lag study included in the application. The

Commission finds that AET has complied with Direction 84 from Decision 20272-D01-2016,

which required the filing of an updated comprehensive lead/lag study.

519. After reviewing the responses provided by AET to the CCA’s proposed adjustments to

necessary working capital based on the timing of VPP payments and base pay salary increases,

the Commission finds that the concerns underlying the CCA's proposed adjustments were

without foundation. AET has adequately responded to the CCA’s request for adjustments to

necessary working capital by explaining that the lag in VPP is reflected in its schedules and with

the reasons why an increase to account for base pay salary increases is not required. The

Commission therefore rejects the CCA’s recommendations.

520. The Commission approves the necessary working capital test period forecasts as filed

subject to any adjustments that may be required based on the direction above. The Commission

directs AET, in the compliance filing, to reflect all findings and determinations in this decision

that affect the necessary working capital calculations.

13 Isolated generation operating costs

521. AET included isolated generation operating costs in Section 22 of its application. The

updated forecast isolated generation operating costs for 2018-2019, are reflected in the table

below:

451 Exhibit 22742-X0727, AET reply argument, paragraph 186. 452 Exhibit 22742-X0727, AET reply argument, paragraph 188.


Decision 22742-D01-2019 (July 4, 2019) 118

Table 35. Isolated operating costs 2015-2017

2015 2016 2017 2018 2019

Actuals Actuals Actuals Test year Test year

($ million)

Operating costs 7.1 5.7 5.5 5.4 5.3

Increases (Decreases) in Forecast/Test period (1.4) (0.2) (0.1) (0.1)

Due to:

Combustion engines/Turbine operations (0.6) (0.1) (0.1) 0.0

Combustion engines/Turbine maintenance (0.5) (0.1) 0.1 (0.1)

Other expenses (0.2) 0.0 (0.1) (0.1)

Source: Exhibit 22742-X0001.02, updated application, Table 22.2 – Isolated Operating Costs, PDF page 515.

522. AET explained that it owned and operated eight generation plants serving isolated

communities, one plant serving an industrial customer and a fleet of eight mobile generator sets

for emergency backup services. In addition, AET maintains 66 isolated generating plants for

telecommunication and substation backup generation, four isolated generating plants for main

supply to isolated telecommunication sites and one synchronous condenser at the Arcenciel

substation.453

523. AET stated that forecasts of decreased costs reflected the interconnection of the Garden

River site in December 2017 and were partially offset by contingency requirements at Jasper

Palisades because of the delay in the Jasper interconnection project.454

524. In final argument, AET submitted that no material issues arose regarding forecast isolated

generation operating costs. AET requested that the amounts for the test years be approved, as

filed.455

525. The CCA provided the following table regarding past isolated generation operating costs:

Table 36. CCA submission on approved versus actual isolated generation operating costs

Year Approved456 Actual Variance

(Approved – Actual)

($ million)

2015 6.3 7.1 (0.8)

2016 7.8 5.7 2.1

2017 8.1 5.5 2.6

Total 3.9

Source: Exhibit 22742-X0726, CCA reply argument, paragraph 144.

526. The CCA argued that the combined variance (where actuals are less than the approved

amounts) over the previous three-year test period of 2015-2017 was 17.6 per cent in AET’s

favour. The CCA stated that the variance is material and reflects low forecasting accuracy for

those costs. Further, given the removal of isolated generation operating costs for communities

like Jasper and the potential for further efficiencies, the CCA recommended that AET’s forecast

453 Exhibit 22742-X0001.02, updated application, paragraphs 493-494. 454 Exhibit 22742-X0001.02, updated application, paragraph 497. 455 Exhibit 22742-X0725, AET final argument, paragraph 304. 456 Exhibit 22742-X0726, CCA reply argument, paragraph 144, derived from Proceeding 22860, Exhibit 22860-

X0006.01 (ATCO Electric Transmission Second Compliance Filing to Decision 22050-D01-2017),

Attachment 4, Schedule 5.1.


Decision 22742-D01-2019 (July 4, 2019) 119

for operating costs be reduced by five per cent in addition to any other adjustments, such as

escalation rates, FTEs and vacancy rates.457

Commission findings

527. The Commission notes that the CCA’s submissions on isolated generation operating costs

were brought forward only in reply argument. The CCA chose not to address this issue in its

evidence (Exhibit 22742-X0595), during the oral hearing, or in final argument. By advancing the

issue only in reply argument, the CCA has provided AET with no opportunity to respond. The

Commission weighs the CCA’s submissions on this matter accordingly.

528. In its application, AET elaborated upon its forecast as follows:

Decreases during the Test Period are primarily associated with reduced labour

requirements as a result of role consolidation and reduced maintenance requirements due

to the interconnection of Garden River in December 2017. These cost reductions are

offset by contingency requirements at Jasper Palisades because of the delay in the Jasper

Interconnection project. Based on a risk assessment, the resulting delays require an

updated contingency plan for the 16 months of operation remaining until Jasper is

interconnected. This plan involves renting, installing and removing a temporary natural

gas engine if a large (greater than 2.8MW) engine were to fail while Astoria Hydro is not

able to generate sufficient capacity. This updated contingency plan is required to ensure

the reliability of the isolated system prior to interconnection.458 [emphasis added]

529. According to Table 22.1459 of AET’s updated application, the Jasper Interconnection

Project is expected to be completed on December 30, 2019. It appears to the Commission that

any benefits from the Jasper Interconnection Project will not be realized until 2020. In addition,

the Commission notes that forecast isolated operating costs are projected to marginally decline in

each of the test years relative to 2016 and 2017 actuals. The Commission finds this consistent

with the delay for the Jasper Interconnection Project.

530. The Commission accepts the submissions from AET regarding the timing of the Jasper

Interconnection Project. Further, the Commission considers that the CCA was not specific as to

what further potential efficiencies are available to AET, nor how it derived the five per cent

reduction in operating costs it recommended. The CCA’s requested reduction to the forecast

costs is denied.

531. Therefore, subject to Commission determinations in other parts of this decision, the

Commission approves AET’s isolated generation operating costs as filed.

14 Shared services and common group costs

14.1 Shared services

532. In the application, AET stated that as part of its ongoing efforts for continuous

improvement, AET and the ATCO group of companies have been developing a comprehensive

457 Exhibit 22742-X0726, CCA reply argument, paragraphs 144-147. 458 Exhibit 22742-X0001.02, updated application, paragraph 497. 459 Exhibit 22742-X0001.02, updated application, paragraph 495.


Decision 22742-D01-2019 (July 4, 2019) 120

ATCO-wide460 shared services model for certain common functions. This model will bring

together similar work functions to provide standardized internal services on a cost recovery basis

consistent with the ATCO Group Inter-Affiliate Code of Conduct. Examples of these functional

areas include financial services, treasury, regulatory, human resources, fleet and facilities

management, and supply chain. Some of these functions currently reside within ATCO’s

corporate office, some reside within the individual ATCO companies and operating divisions,

and some are currently performed and allocated to a common group function.461 Common group

functions are those performed at an ATCO Electric group level with the costs being allocated to

the operating divisions, AET and AED.

533. In its application update,462 AET explained that it had updated its forecasts to include

2018 actual common costs up to July 2018. The remaining 2018 forecasts were based on the

approved activity-based forecasting methodology, including the updated cost factors known as of

July 2018 (e.g., workforce reductions). Considering that the updated forecast included

efficiencies gained in the first half of 2018 through the re-evaluation of work and staffing

requirements, including shared service groups, AET stated that the reductions that were intended

to be captured by the productivity factor initially proposed and later withdrawn, were now

embedded in the updated revenue requirements for 2018 and 2019.

534. AET also presented an analysis that captured the forecast costs to be allocated to AET for

the functions outlined under the shared services model,463 and compared this to the forecast costs

included in the application update for the same functions. AET stated that the table below shows

the costs were not materially different from each other:

Table 37. Shared services comparison

Operating costs 2018 comparison 2019 comparison

($ million)

GTA forecast costs – related to shared service functions 7.2 6.6

Shared services costs – allocated to AET 7.0 6.9

535. In AET’s view, the comparison in the table demonstrates that the activities and functions

result in costs that need to be incurred regardless of whether they are directly embedded in

AET’s forecast or allocated through the shared services model.

536. Given the lack of information about AET’s forecast shared services allocations, the CCA

recommended that the Commission either consider the shared services initiative and related

allocations as part of a future AET GTA or in a generic proceeding to consider the impact of the

shared services allocations on all of the ATCO subsidiaries. The CCA identified a list of issues

with respect to AET’s shared services allocation that it maintained were not adequately

explained.464

460 Refers to ATCO Ltd. This is a corporate-wide initiative. 461 Exhibit 22742-X0001.02, updated application, page 10. 462 Exhibit 22742-X0533, page 30. 463 Exhibit 22742-X0417, page 6. 464 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, pages 180-181.


Decision 22742-D01-2019 (July 4, 2019) 121

537. AET concurred with the CCA that the new shared services model should be tested as part

of AET’s next GTA indicating that testing the new methodology in the current GTA would not

be feasible, nor would it promote regulatory efficiency.465

538. In its argument, AET noted that in response to AET-AUC-2018JUN08-002,466 it provided

an update on the shared services initiative, including the operating model of the shared services

functions. AET added:

During the course of questioning by Commission Counsel, an Aid-to-Cross (Ex. X0648),

was introduced and questions posed to AET regarding the use of a KPMG report for

purposes of determining allocation factors under the shared services methodology. This

Aid-to-Cross is a KPMG report filed in the ATCO Pipelines GRA, that is currently

before the Commission. AET acknowledged that it was aware of the KPMG report, but

did not file it in this case, as it was not relying upon it for purposes of supporting the

reasonableness of the amounts allocated to AET for the 2018 and 2019 Test Years.

Rather, as detailed in its Application Update, AET continues to rely upon costs based on

the approved activity-based forecasting methodology. AET has confirmed, as outlined

above, that there was no material difference in the forecast cost derived under either

methodology. Therefore, it was not appropriate to file the KPMG report in this

proceeding (4T707-711).

In the end result, AET submits that the amounts included in its 2018-2019 GTA forecasts

properly reflect the costs associated with the shared services that AET will utilize during

the Test Period. This is based on an assessment of the most recent information available

and supports the quantum of costs included in AET’s Application for approval. As noted,

AET's allocation methodology for shared services costs will be explored in greater detail

in its next GTA.467

539. The CCA acknowledged AET’s argument that there was no material difference between

the costs it was proposing based on its September 2018 updated application and those proposed

in the KPMG report468 filed in ATCO Pipelines’ 2019-2020 GRA proceeding (Proceeding

23793). However, the CCA countered that the information from the KPMG report had not been

vetted in this proceeding and therefore cannot be assigned any weight as evidence. The CCA

maintained that the Commission should approve the cost reductions it had proposed for

individual O&M accounts.469

Commission findings

540. The Commission notes that AET’s application relies on operating cost forecasts based on

the existing activity-based forecasting methodology. The shared services initiative has not been

fully implemented nor has AET requested that the Commission approve the new methodology in

the current proceeding. The Commission considers that further review of the shared services

initiative should be deferred to a future proceeding where it can be thoroughly examined. The

shared services initiative and approval of a new shared services methodology was a live issue in

465 Exhibit 22742-X0618, AET rebuttal evidence, page 156. 466 Exhibit 22742-X0417. 467 Exhibit 22742-X0725, AET final argument, paragraphs 144-145. 468 Exhibit 22742-X0648. 469 Exhibit 22742-X0726, CCA reply argument, paragraphs 84-85.


Decision 22742-D01-2019 (July 4, 2019) 122

the ATCO Pipelines’ proceeding (Proceeding 23793). In Decision 23793-D01-2019470 issued on

June 25, 2019, the Commission directed ATCO Pipelines to coordinate with AET to ensure

consistent information on the shared services initiative in each of their next GRA and GTA,

respectively. The Commission went on to enumerate the nature of the information required,

including the filing of cost information for all ATCO affiliates to substantiate the costs allocated

to all regulated ATCO entities. The Commission in the current proceeding similarly directs AET

to coordinate with ATCO Pipelines to ensure that both utilities provide the same or substantially

similar information in the same format in support of the shared services in their next respective

GRA and GTA, preferably filing common documents wherever possible. The information should

include evidence supporting the functions created, justifying total FTEs and costs before

allocation to the participating ATCO companies (AET and all other regulated and non-regulated

ATCO entities), and include any analysis, studies and calculations that explain and support the

reasonableness and accuracy of the allocation methodologies. The Commission finds that it

would also be beneficial to show all calculations that demonstrate the split between O&M and

capital under the shared services initiative in the next GRA and GTA. This common information

will allow for a proper testing of the shared services and for the provision of company specific

information to support shared services costs included in the proposed revenue requirements.

Accordingly, the Commission directs AET to provide the evidence, analyses, studies and

calculations noted above as well as any underlying assumptions for the split between O&M and

capital in its next GTA.

541. The Commission acknowledges that of the ATCO companies, AED and ATCO Gas are

under performance-based regulation and are subject only to minimum filing requirement

schedules. However, further information about common costs are required to support the costs

allocated to AET. As such, AET is directed, on a go-forward basis, to provide all cost

information for every ATCO affiliate, comprising the total costs and supporting detail that

substantiate and justify the costs allocated to AET relative to the other regulated and non-

regulated ATCO companies under the shared services initiative.

542. The forecast operating costs are addressed in other areas of this decision, specifically, in

Section 7 (O&M) and Section 15 (Corporate administration and general).

14.2 Shared services - productivity factor

543. In its original application, AET proposed that a productivity factor of 0.3 per cent be

applied against the 2018 and 2019 operating and capital maintenance forecasts to reflect the

potential savings from its shared services initiative (discussed in Section 14.1). In AET’s

September 2018 application update, the productivity factor was withdrawn and AET stated:

AET has updated the forecast to include 2018 actuals up until July 2018 and factored

those components into costs for the remaining 2018 period based on the approved

activity-based forecasting methodology, including efficiencies such as workforce

reductions. It is important to note that these activities and functions result in costs that

need to be incurred regardless of whether they are directly imbedded in AET or allocated

through the shared service model.471

470 Decision 23793-D01-2019: ATCO Pipelines, 2019-2020 General Rate Application, Proceeding 23793, June 25,

2019. 471 Exhibit 22742-X0001.02, updated application, paragraph 25.


Decision 22742-D01-2019 (July 4, 2019) 123

544. Bema recommended that the Commission approve a 0.3 per cent productivity factor,

based on total operating and capital maintenance costs to adjust for likely efficiencies that may

be gained as AET’s shared services initiative continues to mature.472 The CCA argued the

following based on Bema’s recommendations with respect to the productivity factor:

Accordingly, while Bema has proposed a productivity factor of 0.3%, it is important to

emphasize a few important considerations. First and foremost, the proposed productivity

factor should not be taken as an alternative to the other proposed operating costs

reductions proposed by Bema. To the contrary, this productivity factor is an additional

reduction applied only after AET’s forecast operating costs reflect known efficiencies

that should be gained or otherwise are adjusted for unsupported or unreasonable costs. In

other words, the 0.3% productivity factor reflects the potential further efficiencies that

AET should be expected to achieve after the proposed reductions are implemented as

Bema recommends.473

545. In its argument, the CCA acknowledged that there was no analytical or statistical basis

for the 0.3 per cent productivity factor it was recommending.474

546. In its rebuttal evidence, AET reiterated its opposition to including the productivity factor,

explaining that it was introduced over a year and a half ago when AET was still considering how

to deal with shared services. AET stated that it now has included efficiencies such as workforce

reductions into the forecast, making the productivity factor no longer relevant or appropriate.475 It

added that:

… Including known and likely costs in a forecast is supported in Bema’s evidence, where

they state “AET’s forecast costs should include all known or likely efficiencies to ensure

that the costs approved by the Commission have a reasonable chance of reflecting actual

costs.” In the September update, given the length of time since the original Application,

AET has included “known or likely efficiencies” in the forecast. As a result, it would be

inappropriate to apply an additional productivity factor to the forecast, as this would

constitute double counting of these savings that are know [sic] embedded in the new

forecasts. [footnote and emphasis removed]476

547. The CCA emphasized that the productivity factor is not intended to adjust for known

efficiencies. Rather, it is intended to adjust for unknown but likely efficiencies. According to the

CCA, it is clear that AET’s forecast has only adjusted for known efficiencies, not unknown but

likely efficiencies.477 As a result, including the productivity factor would not result in double

counting.478

472 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 581. 473 Exhibit 22742-X0722, CCA final argument, paragraphs 626-628 and Transcript, Volume 7, page 1214, line 1 to

page 1216, line 5. 474 Exhibit 22742-X0612, CCA-AUC-2018Dec19-015, PDF pages 40-41. 475 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 153. 476 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 153. 477 Exhibit 22742-X0722, CCA final argument, paragraph 630. 478 Exhibit 22742-X0722, CCA final argument, page 186.


Decision 22742-D01-2019 (July 4, 2019) 124

Commission findings

548. In its updated application, AET stated that it considered actual amounts to the end of

July 2018 and used the activity-based forecasting methodology to determine its forecast

operating amounts. The forecast amounts contain known or likely efficiencies.

549. The CCA, by its own admission, acknowledged that the 0.3 per cent productivity factor is

not analytically or statistically based. The CCA stated it did not conduct a thorough review of

different productivity factors that may be appropriate for AET. In response to questioning from

Commission counsel, the CCA reiterated its position that an additional productivity factor

adjustment was required to reflect an incentive to achieve further efficiencies beyond known or

likely efficiencies.479

550. The Commission is not persuaded by the CCA’s argument given that AET has included

in its updated application forecast operating costs incorporating known or likely efficiencies. In

the Commission’s view, the CCA has failed to provide sufficient analytical or statistical evidence

to reasonably support a 0.3 per cent productivity factor to account for unknown efficiencies that

might arise from AET’s shared services during the test period. Without such evidence to support

the CCA’s position, it is impossible for the Commission to determine whether double counting

would result if a 0.3 per cent productivity factor was approved. Therefore, the Commission

denies the CCA’s request to have a 0.3 per cent productivity factor applied to the shared services

included in AET’s operating and capital maintenance forecasts for 2018 and 2019.

14.3 Common group costs

551. AET stated that the allocators used in this application are consistent with those allocators

approved in Decision 21701-D01-2017480 for the ATCO Electric Transmission Division

Common Group Application.481 AET explained that the allocation of the common group costs

within ATCO Electric Ltd., both the transmission and distribution divisions, was planned to

continue while the overall shared services initiative outlined in the application continues to take

shape.482

552. In addition to the common groups483 included in the common group application, AET also

included key customer accounts and forestry operations in this application. AET stated that the

combination of the key customer accounts and forestry operations groups streamlined and

provided operational efficiencies in these areas.484 AET also explained that ATCO outsourced its

payroll function to a non-related third party, Automatic Data Processing (ADP). The costs for the

payroll services provided to AET are directly billed and have been recorded in USA 921.

553. AET provided an overview of the allocation methodologies and percentages that have

been used to quantify the impact of the common groups on the transmission costs in the

application. In particular, Appendix 3 provided a summary of cost allocators, the allocation

percentages to AET, and the amount allocated under each method for the 2018-2019 test period

479 Transcript, Volume 7, starting at page 1213, line 16 and ending at page 1217, line 10. 480 Decision 21701-D01-2017: ATCO Electric Ltd,. Transmission Common Group Application, Proceeding 21701,

July 4, 2017. 481 Exhibit 22742-X0001.02, updated application, page 9. 482 Exhibit 22742-X0001.02, updated application, page 569. 483 Exhibit 22742-X0001.02, updated application, page 570, paragraphs 530-531 contain list of common groups. 484 Exhibit 22742-X0001.02, updated application, page 570.


Decision 22742-D01-2019 (July 4, 2019) 125

as compared to the allocators submitted as part of the common group application.

Appendixes 4.1 and 4.2 provided a detailed breakdown of ATCO Electric Ltd.’s485 2018 and

2019 forecast total common group costs and FTEs by each functional group that apply to both

transmission and distribution. These functional groups were also discussed in detail as part of the

Common Group Study, Attachment 27.1. The summary identified those common group costs

which are allocated to AET and AED as well as those FTEs and associated costs forecast to

support ATCO affiliates.486

Inclusion of deferral account revenue in net revenue calculation

554. In its evidence, Bema raised a concern with the calculation of net revenues, which affects

the common group cost allocators. Bema recommended that AET include its deferral account

revenues in the calculation of the net revenue amount used in its allocations. Bema stated that

deferral accounts are an essential component of regulatory accounting and that the Commission

has concluded they will be recorded as regulatory assets and liabilities for regulatory accounting

purposes whether or not they are recorded under IFRS.487 Accordingly, Bema submitted that

AET’s approach to ignoring the regulatory accounting impacts of deferral accounts in its

reported regulated revenue requirement was inappropriate. Further, it was Bema’s view that

AET’s simple reliance on its IFRS reported revenue ignored that AET was required to reconcile

under Rule 005: Annual Reporting Requirements of Financial and Operational Results, all

adjustments between IFRS and AET’s regulatory accounting.488

555. The CCA asserted that AET’s argument for the exclusion of deferral revenues in the net

revenue calculation was inconsistent with its argument for the inclusion of CWIP in the net

property plant and equipment (PP&E) calculation.489

556. In rebuttal evidence, on the issue of deferral account revenues, AET pointed to an IR

response490 from the common group proceeding (Proceeding 21701), to illustrate that it was

being consistent in its exclusion of such revenues and was not “cherry picking” the results. AET

also submitted that the current approach was administratively simple.491

557. AET noted that including deferral revenues in the calculation of net revenue would not

have a material impact on the 2018-2019 GTA application. AET reproduced a table from its IR

responses to CCA492 which illustrated that including deferral revenues results in an increase in

allocated costs to AET of just $0.1 million for each of 2018 and 2019.

558. The CCA insisted that deferral account revenues are just as much a component of a

utility’s revenue requirement as any other element such as operating costs and income taxes. In

fact, deferral accounts often are used to true up amounts related to items such as operating costs

and income taxes. Accordingly, the CCA maintained its recommendation that deferral account

485 Exhibit 22742-X0001.02, updated application, page 580, refers to total ATCO Electric common costs, both

transmission and distribution. 486 Exhibit 22742-X0001.02, updated application, page 580. 487 Exhibit 22742-X0592, page 173. 488 Exhibit 22742-X0592, page 173. 489 Exhibit 22742-X0592, page 175. 490 Proceeding 22859, Exhibit 22859-X0052, AET-CCA-2017NOV03-005. 491 Exhibit 22742-X0417.01, AET-AUC-2018JUN08-031(a). 492 Exhibit 22742-X0456.


Decision 22742-D01-2019 (July 4, 2019) 126

revenues be included in net revenues. In its view, if net revenues are to be a cost allocator, then

all revenues affecting the calculation of net revenues should be considered by the Commission.493

Inclusion of CWIP in net PP&E

559. Another issue raised by Bema was AET’s proposal to include CWIP in the calculation of

net PP&E. Bema submitted that CWIP should be excluded.494 It also challenged AET’s claim that

its proposal was consistent with past practice. The CCA noted that the Commission discontinued

CWIP-in-rate base in 2017 per Decision 20272-D01-2016, but approved it in 2016.495 According

to AET’s 2016 Rule 005 filing, Schedule 4.1-T, AET included $220.0 million of CWIP in its

opening January 1, 2016 net PP&E and $178.9 million of CWIP in its closing December 31,

2016 balance.

560. Bema considered that these balances are material and will increase the costs being

allocated to AET relative to AED. Bema stated that, from the perspective of consistency, it is

unclear whether AED included CWIP in its net PP&E calculations for cost allocation purposes in

the 2018-2019 test years. Bema further observed that AET has not consistently included CWIP

in net PP&E, as confirmed by AET in Proceeding 22859, the common group compliance

filing.496

561. The CCA maintained that the traditional AFUDC method was the usual means employed

by the Commission and was also the method most recently approved for use by AED and AET in

2017. Therefore, the principle of consistency strongly supported the exclusion of CWIP from net

PP&E in the cost allocation method.497

562. With respect to regulatory accounting treatment, the CCA noted that the Commission has

accepted two different approaches to regulatory accounting over time. The CCA pointed out,

however, that CWIP has not been approved by the Commission for inclusion in the rate base for

the current forecast test period. Accordingly, the principle of consistency in regulation suggests

that the regulatory accounting treatment of actual costs should reflect the current regulatory

accounting treatment for forecast costs.498

563. Finally, under IFRS, the CCA noted IAS 16 required that an asset be in the location and

condition necessary for it to provide the service intended by management before that asset can be

capitalized to PP&E. CWIP is by its very nature an asset that is more akin to inventory, or as the

name states, “work-in-progress.” Costs incurred before an asset is placed in service do not meet

the requirement that it is in the “location and condition necessary for it to provide the service

intended by management.” Additionally, in this case, the accounting treatment under IFRS

aligned with the regulatory accounting treatment under traditional AFUDC accounting where

CWIP is not included in rate base. Therefore, the CCA submitted IFRS accounting further

supported the exclusion of CWIP from net PP&E.

493 Exhibit 22742-X0722, CCA final argument, page 181. 494 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 177. 495 Decision 20272-D01-2016, paragraphs 1307-1310. 496 Exhibit 22742-X0592, page 176, refers to Proceeding 22859 (AET Common Group Compliance filing),

Exhibit 22859-X0052, AET Information Responses to CCA, PDF pages 13-14, response to AET-

CCA2017NOV03-006(d). 497 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 177. 498 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 177.


Decision 22742-D01-2019 (July 4, 2019) 127

564. In rebuttal evidence, AET confirmed that both AET and AED did include CWIP in the

calculation of net PP&E for cost allocation purposes consistent with past practices. AET

submitted that the identical treatment of CWIP by both AED and AET should address all of

Bema’s concerns around this topic.499

565. AET added that the use of net PP&E, inclusive of CWIP, is a longstanding practice that

has been approved by the Commission on a number of occasions. The methodology for the net

PP&E component of the allocation formula was previously approved in AET’s 2013-2014 GTA

Second Compliance filing (resulting in Decision 2014-348).500 It was recently approved once

again as part of AET’s common group application in Decision 21701-D01-2017, which

determined the allocation of costs between AED and AET for the 2016-2017 period. Therefore,

AET submitted that the principle of consistency strongly supported the inclusion of CWIP in net

PP&E in the cost allocation method.501

566. Finally, AET noted that the CCA had expressed concern that including CWIP would

increase the costs being allocated to AET relative to AED.502 AET stated that it performed an

analysis503 which determined that the removal of CWIP from net PP&E had no material impact

on revenue requirement in either 2018 or 2019. As such, AET submitted that the CCA’s

argument that the costs allocated to AET relative to AED would increase, was not correct.504

Commission findings

567. The CCA has argued that the Commission recognizes deferral account balances as

regulatory assets and liabilities and that it makes sense to record all the accounting impacts of

these accounts. Also, deferral account balances are included in Rule 005 reporting. The CCA

also argued that deferral account revenues were related to regulatory costs and that shifting costs

or revenues from one period to another does not negate the fact that they affect the revenue

requirement of the entity.

568. AET argued that the current practice was administratively simple and any change would

not have a material impact.

569. The Commission finds the arguments of the CCA to be more persuasive. The

Commission considers that it would be more consistent if deferral revenues were included in the

determination of the allocation factor and with AET’s treatment of deferral revenues in Rule 005.

In the Commission’s view, these deferral revenues can still affect the revenue requirement of the

entity, and the deferral revenues of direct assigned capital are a function of, and reflect, the

actual capital invested. Therefore, AET is directed to include deferral account revenues in

calculating net revenue for purposes of the common cost group allocation methodology.

570. On the question of whether CWIP should be included in PP&E for the purpose of

determining cost allocation, the Commission finds the arguments of AET to be more persuasive.

499 Exhibit 22742-X0618, AET rebuttal evidence, page 149. 500 Decision 2014-348: ATCO Electric Ltd., 2013-2014 Transmission General Tariff Application Second

Compliance Filing, Application 1610733-1 Proceeding 3337, December 15, 2014. 501 Exhibit 22742-X0618, AET rebuttal evidence, page 149. 502 Exhibit 22742-X0618, AET rebuttal evidence, page 149 refers to Exhibit 22742-X0592, paragraph 566. 503 Exhibit 22742-X0457, in response to a Round 2 IR from the CCA, AET-CCA-2018JUN08-018(g)

Attachment 1. 504 Exhibit 22742-X0618, AET rebuttal evidence, page 150.


Decision 22742-D01-2019 (July 4, 2019) 128

In the Commission’s view, including CWIP in PP&E more accurately reflects the actual capital

invested. The Commission also accepts that it is consistent with prior practice. Therefore, AET is

directed to continue to include CWIP in the net PP&E allocator.

15 Corporate administration and general

571. Administration and general (A&G) costs include general administration, office supplies

and expenses, outside services employed, insurance premiums, injuries and damages, regulatory

expenses, miscellaneous general expenses, head office rent, information technology (IT)

operating expenses, and maintenance of company-owned houses. AET forecast $47.8 million in

2019 and $40.6 million in 2019 for its A&G costs,505 which are operating costs. The forecast for

the 2018 test year included significant changes because of severance costs related to workforce

reductions, which are addressed in Section 5.1.3 of this decision. The increase was also due to

inflation. Office rental costs, which are also part of A&G, are addressed in Section 15.4. After

removing severance costs from the analysis, the total forecast A&G costs are relatively stable

compared to prior years and over the test period. The individual accounts that make up A&G are

reviewed below.

15.1 Office Supplies and Expenses (USA 921)

572. Office supplies and expenses include supplies and expenses incurred in support of the

corporate function. Examples of such costs include fringe and employee benefits, travel

expenses, membership fees, severance costs as well as donations and licence fees. Donations and

licence fees are not included for revenue requirement purposes.506

573. AET forecast office supplies and expenses are $15.9 million and $8.7 million for the

2018 and 2019 test years, respectively. The 2018 forecast for this account included $7.6 million

in severance costs, and severance costs are addressed in Section 5.1.3 of this decision. The

increase in this forecast from 2017 to 2018 is mainly due to the payment of severance costs

related to workforce reductions. Severance costs are included in the “General Admin Other”

expense line item within this account.507 AET illustrated its forecast for this account in Table 25.3

of the application, which is reproduced below:

Table 38. Office supplies and expenses

2015

Actuals 2016

Actuals 2017

Actuals 2018

Test year 2019

Test year

($ million)

Operating costs – USA 921 20.2 8.4 7.8 15.9 8.7

Increases/(Decreases) in test period (Schedule 25-2)

(11.8) (0.6) 8.1 (7.2)


574. In its evidence, Bema submitted that the major cause of the increases in 2018 and 2019

for USA 921 appears508 to be fringe and employee benefits combined with the general-other cost

505 Exhibit 22742-X0002, Schedule 25-1. 506 Exhibit 22742-X0002, Schedule 25-2 and Exhibit 22742-X0592, page 99. 507 Exhibit 22742-X0001.02, updated application, PDF page 539, “Schedule 25-2, line 38. 508 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 100.


Decision 22742-D01-2019 (July 4, 2019) 129

category.509 Bema described AET’s explanation of the cost increases in Schedule 25-2 as “high

level,” referring only to increases in “general administrative costs ($0.4M [million]), corporate

communication related costs ($0.3M), fringe ($0.3M), and training ($0.1M).”510 Bema’s review

lead it to conclude that the costs of fringe and employee benefits would increase by $1.0 million

in 2018 and $0.9 million in 2019 over 2014 levels, and not by the $0.3 million cited by AET and

that the general-other costs would increase to $1.3 million in each of 2018 and 2019, compared

to an average of only $0.4 million per year between 2013 and 2016.

575. The CCA submitted that, based on Bema’s review of the GTA schedules, the revised

application and AET’s responses to a CCA information request, AET did not explain this

variance from earlier levels.

576. The CCA suggested that a more reasonable forecast of fringe and employee benefits in

each of 2018 and 2019 is $1.6 million, which is an average of actual costs incurred in the years

2013, 2014, 2016 and 2017 (removing 2015 due to the large severance payment) and is greater

than the $1.5 million in actual costs incurred by AET in 2017, which affords AET some inflation

in the costs. The CCA submitted that if AET considered that additional fringe and employee

benefits would be incurred for the 2018 severance costs, then it should quantify and support

those costs.

577. The CCA stated that AET does not appear to have explained any of the increase in costs

over historical 2013 to 2016 levels of general-other costs other than an increase in training costs

of $0.1 million. The CCA stated that AET had failed to explain and justify the costs incurred in

2017 and the expected costs in 2018 and 2019. The CCA calculated the historical annual average

cost for general-other from 2013 to 2016 to be $0.4 million, with 2016 actual costs of

$0.5 million. The CCA recommended a cost figure of $0.6 million in each of 2018 and 2019,

which it submitted is consistent with historical levels, but also factors in 2016 costs of

$0.5 million in addition to a $0.1 million increase for training costs.511

578. The CCA’s recommendations amounted to disallowances of $0.9 million and $0.8

million of fringe and benefits costs in 2018 and 2019, respectively, and of $0.8 million of

general-other costs in each of 2018 and 2019.

579. In rebuttal evidence, AET explained that Exhibit 22742-X0002.04, which is AET’s

schedule of impacts of inflation on operating costs, does say that there is a year-over-year

increase in fringe expense of $0.3 million between 2017 and 2018, but that the increases of

$1.0 million in 2018 and $0.9 million in 2019, respectively, as compared to 2017 are related to

fringe and employee benefits, not simply fringe benefits. The total increase of $1.0 million

includes a $0.3 million increase to fringe benefits (which mainly increased CPP/EI, employee

flex benefits and share purchases) and a $0.7 million increase because of various other benefits,

including long-service awards ($0.2 million), retirement allowances ($0.1 million), the Employee

Assistance Program ($0.1 million), and bursaries ($0.1 million).512

509 Exhibit 22742-X0237, response AET-CCA-2017AUG30-040. AET identifies General-Other as a portion of

General Operating Expenses. 510 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 105 refers to Exhibit 22742-X0002.04, AET

2018-2019 GTA MFR Schedules, Schedule 25-2. 511 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 106. 512 Exhibit 22742-X0618, AET rebuttal evidence, page 71.


Decision 22742-D01-2019 (July 4, 2019) 130

580. AET claimed that the CCA had miscalculated the average general-other costs for 2013 to

2016. AET stated that the correct average was $0.7 million, not the $0.4 million calculated by the

CCA. AET argued that correcting for this error would raise the CCA's recommended amount to

$0.9 million per year. AET also contested the CCA's assertion that it had provided no

explanation for the proposed increase in this account, outside of higher training expenses. AET

stated that it provided a variance explanation in Schedule 25-2 of Exhibit 22742-X0002.04 that

included increased general administrative costs (including bank charges, couriers, and phone

costs), increased corporate communication-related costs (mainly related to communications

focusing on health and safety issues, changes in corporate procedures, employee engagement,

and customer education), and increased training. AET also provided a table, reproduced below,

to explain the forecast over 2016 actuals:513

Table 39. Changes in general-other costs included in USA 921

($ million)

2016 Actuals 0.6

General administration costs 0.4

Corporate communications costs 0.3

Training costs 0.2

Outsourcing of payroll to ADP 0.1

Relocation expenses (0.1)

Other items less than $0.1M (0.1)

2018/2019 Forecast 1.4

Source: Exhibit 22742-X0618, page 72.

581. In argument, the CCA maintained that its calculations regarding general-other costs were

correct, explaining that it had removed the disallowed pension COLA (cost of living

adjustments) amounts. It referred to an exchange between the AET panel and the CCA counsel

that confirmed this adjustment was correct.514 The CCA also commented on Table 6 supplied by

AET, stating that simply listing cost increases does not demonstrate that those cost increases are

reasonable compared to actual 2016 costs.515

582. In reply argument, AET stated that the CCA was mistaken in removing pension cost-of-

living adjustments from general-other costs because the cost-of-living adjustment, along with all

other pension costs, are not included in “general-other” expenses but, rather, are part of “Fringe

& Employee Benefits.”516 AET submitted that the CCA had incorrectly deducted an amount for

disallowed pension COLA in the “general-other” expenses in its calculations.

Commission findings

583. The Commission accepts AET’s explanation for the increase in fringe benefits given the

inflationary pressures on the specific cost items of CPP and employee benefit premiums. With

respect to the other employee benefits identified, however, it is not clear to the Commission how

a proposed increase of $0.7 million per year is justified, given that FTEs are declining. For these

reasons, the Commission approves a marginal increase of $0.1 million and AET is directed to

513 Exhibit 22742-X0618, AET rebuttal evidence, page 72. 514 Transcript, Volume 3, page 474, lines 6-24, Ms. Goode to Mr. Wachowich. 515 Exhibit 22742-X0722, CCA final argument, page 94. 516 Exhibit 22742-X0727, AET reply argument, page 68 refers to Exhibit 22742-X0592, page 100.


Decision 22742-D01-2019 (July 4, 2019) 131

reduce its forecast spending on fringe and benefit costs by $0.6 million for each of the test years

and to reflect this reduction in its compliance filing to this decision.

584. The Commission finds that the CCA’s proposed reduction for the general-other cost

category is excessive. The Commission, however, agrees with the CCA’s comments that AET

failed to justify or explain its proposed increases and some reduction is warranted. As such, AET

is directed to reduce its forecast general-other expenses by $0.4 million for each of the test years

and to reflect this reduction in its compliance filing. Bema calculated the historical annual

average cost for general-other expenses from 2013 to 2016 to be $0.4 million, and the

Commission accepts that this calculation shows that historical trend of $0.4 million per year

provides a more reasonable forecast for general-other expenses in the test years.

585. The Commission notes that the above reductions result in an allowed forecast of

$7.7 million for each of the test years for this account, which is $0.1 million less than the 2017

actual amount. Given AET’s workforce reductions, the Commission does not consider this to be

an unreasonable result, particularly since the total office supplies and expenses forecast for 2018

was $15.9 million, the 2019 forecast was $8.7 million, and the 2017 actuals were $7.8 million.

15.2 IT G&A expense (USA 934)

586. In the application, AET explained IT services charged to operating costs include costs to

operate, maintain and distribute existing and new IT applications required by AET to manage its

financial, human resources and operational activities (e.g., Oracle and Maximo IT systems).

These services also include charges for the provision of hardware (e.g., PCs, laptops, monitors);

network, voice (telecommunications), data storage and printing management and infrastructure;

and ad hoc service requests.517 AET illustrated the forecast in the following table:

Table 40. IT G&A expense

2015

Actuals 2016

Actuals 2017

Actuals 2018

Test year 2019

Test year

($ million)

Operating costs – USA 934 3.8 4.2 3.8 3.9 3.7

Increases/(Decreases) in test period (Schedule 25-3)

0.4 0.4 0.1 0.2

587. AET explained that in its September 4, 2018 application update, the 2018 forecast for

USA 934 was reduced slightly as a result of the A&G position reductions in 2018. The forecast

for 2019 was also updated from $3.3 million to $3.7 million. This change was the result of the

deferral of the cost savings (system hosting, data storage, support and licensing) from upgrading

Oracle E-Business to a cloud-based platform because of the delay in the project in-service date

from December 2017 to October 2018, net of a decrease in IT costs as a result of the full-year

impact of the 2018 FTE reductions.

588. In its evidence, Bema noted that the costs incurred for this account were related entirely

to external contractor charges.518 Given that AET’s IT support is provided by an external third

party, the CCA maintained that the resulting charges should be relatively stable both in terms of

517 Exhibit 22742-X0001.02, updated application, page 534. 518 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 113.


Decision 22742-D01-2019 (July 4, 2019) 132

volume and rates throughout each year, absent significant usage or price changes. In the CCA’s

view, it was unusual that AET’s forecasting accuracy has been so low.519

589. The CCA recommended a reduction similar to USA 575 for IT Support,520 where it noted

that there has been a reduction in users and equipment as a result of AET’s staff terminations in

2018. The CCA considered that a similar reduction of 11 per cent in 2018 as compared to 2017

and a further 2.5 per cent reduction in 2019 over 2018 would be reasonable. The CCA calculated

that these reductions would result in forecast costs of $3.4 million in 2018, and $3.3 million in

2019, noting that the 2019 amount, as revised, would match the previously applied-for amount in

AET’s original application. In the CCA’s view, this was reasonable since AET has not supported

the increase in costs in its updated application for this account. The CCA stated that these

reductions would lower forecast expenses by $0.5 million and $0.4 million in 2018 and 2019,

respectively.

590. In rebuttal evidence, AET disputed the CCA’s claim that its forecast accuracy was low,

noting that over the period 2013-2017, actuals were only four per cent below forecast. AET

argued that there was no reasonable basis to presume that costs for IT services should be stable

over time as long as the services in question continue to be provided by a third-party supplier.

AET stated that it made management decisions in the last test period to implement cost-reduction

initiatives for this account and that actual costs in 2017 were below approved levels by

$1.5 million mainly due to lower application support services, e.g., storage, disaster recovery,

hosting and maintenance. These cost reductions were achieved by a management decision to

move to a cloud-based storage system, which was not part of the approved forecast. According to

AET, pursuing efficiencies and implementing prudent cost-savings measures throughout a test

period should not be construed as evidence of the inability to forecast costs.

591. AET stated that the expenses in this account were 80 per cent fixed and did not fluctuate

with changes in users or FTEs as the requirement for the IT applications remains. AET indicated

that IT applications for which costs are included in USA 934 include Oracle E-Business

applications and Enterprise Planning and Budgeting Cloud Service.521 AET claimed that if the

CCA’s recommendations were adjusted to apply to only the 20 per cent of expenses that are

variable, AET’s 2018 and 2019 forecast expenses for this account would be seen to be

reasonable. AET stated that its forecasts are supported as shown in the table reproduced below:

Table 41. Reconciliation of changes in USA 934 for 2017-2018

2017 Actuals (Schedule 25-1) 3.8 Temporary cost of running concurrent Oracle systems 0.3 Cost reductions due to decreased number of users and units of equipment (0.1) $3.8M x 20% variable costs x 11%

Savings in application support services (0.1) 2018 Forecast (Schedule 25-1) 3.9 Cost reductions due to decreased number of users and units of equipment (0.1) $3.8M x 20% variable costs x

(11% + 2.5%)

Savings in system hosting, data storage, support and licensing costs (0.1) 2019 Forecast (Schedule 25-1) 3.7

Source: Exhibit 22742-X0618, AET rebuttal evidence, PDF page 80,Table 7.

519 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, pages 114-116. 520 Exhibit 22742-X0722, CCA final argument, paragraphs 334-337. 521 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 78.


Decision 22742-D01-2019 (July 4, 2019) 133

592. AET acknowledged the CCA was correct in assuming that some cost savings in user fees

will be realized in the test period as a result of staff reductions, but explained that this would be

offset by increased IT application costs for 2018. AET explained that it has moved from on-

premise Oracle E-Business to a cloud-based Oracle E-Business solution, requiring that the on-

premise Oracle system be available to facilitate all financial historical reporting for the

organization, as the new cloud-based system will retain financial data from October 2018

forward. This added $0.3 million in IT costs for 2018 over and above the previous ongoing

application costs.

593. In argument, the CCA acknowledged there was some merit to AET’s position that the

bulk of its IT costs were fixed. However, it continued to claim that some reduction may be

warranted and it recommended a reduction of $0.1 million in each of 2018 and 2019.

Commission findings

594. The Commission accepts AET’s submission that its forecast expenses for this account

reflect fewer users and increased IT application expenses due to the move to a cloud-based

Oracle E-Business IT solution. However, the Commission directs AET to adjust its forecast

expenses for this account based on the Commission’s reduction in forecast FTEs found

elsewhere in this decision.

595. Further, on June 5, 2019, the Commission issued Decision 20514-D02-2019 in the ATCO

Utilities IT common matters proceeding. With respect to USA 934, AET is directed to reflect

any changes arising from the directions in that decision in its compliance filing to this decision.

AET is further directed to provide schedules detailing how the determinations in Decision

20514-D02-2019 are reflected in the compliance filing to this decision.

15.3 Allocation of costs to Alberta PowerLine

596. ATCO Ltd., through its subsidiary Canadian Utilities Limited, is a joint owner with

Quanta Services CC Canada, Ltd. of Alberta PowerLine General Partner Ltd. (Alberta

PowerLine GP). Alberta PowerLine Limited Partnership (Alberta PowerLine) is a subsidiary of

Alberta PowerLine GP. Alberta PowerLine owns 100 per cent of the Fort McMurray West 500-

Kilovolt Transmission Line Project (APL project). The development of the Fort McMurray West

facility was awarded to Alberta PowerLine under the AESO’s competitive process in May 2013.

The competitive process was approved by the Commission in Decision 2013-044522 and Alberta

PowerLine was later awarded the APL project. A September 28, 2017 project agreement

between the AESO and Alberta PowerLine specified the payment provisions, price adjustment

mechanisms, and other provisions governing the terms and conditions of service between Alberta

PowerLine and the AESO.523

597. Alberta PowerLine is an affiliate of AET. AET provides management services, O&M

services, route development and design build management services to Alberta PowerLine under

a service concession arrangement. Amounts for contracted services provided by AET to Alberta

522 Decision 2013-044: Alberta Electric System Operator, Competitive Process Pursuant to Section 24.2(2) of the

Transmission Regulation Part B: Final Determination, Proceeding 1449, Application 1607670-1, February 14,

2013. 523 Decision 23161-D01-2018: Alberta PowerLine LP, Tariff Application, Proceeding 23161, January 23, 2018.


Decision 22742-D01-2019 (July 4, 2019) 134

PowerLine are reflected in the 2018-2019 GTA as affiliate cost of goods sold. In its application,

AET stated that the transmission line is expected to be completed in 2019.

598. At issue in this decision is the methodology for allocating head office costs given that

AET provides services to Alberta PowerLine.

599. AET’s head office costs are allocated based on a formula that takes into account equal

weightings of total assets, net revenues and labour costs. AET confirmed that it is not until the

in-service date of the APL project that Alberta PowerLine would become an operating entity

within the pool and would therefore be allocated head office costs. Because of the head office

costs allocation methodology, there would be “a two-year lag regarding the inputs to the costs

that are in question.”524

600. In an IR response to the Commission, AET stated:525

There are no head office/Canadian Utilities Limited costs being directly allocated to

Alberta PowerLine in Schedules 25-8 to 25-8-3. This is because the most recent audited

numbers used to calculate the allocation percentages is 2016, and at this time Alberta

PowerLine is considered a start-up organization with only preconstruction costs being

incurred.

601. Bema noted in its evidence that AET’s head office costs are currently not allocated to

Alberta PowerLine but head office costs are allocated to all other affiliates of AET.

602. The CCA took no position on AET’s approach to accounting for Alberta PowerLine in its

financial statements. However, for regulatory purposes, the assets have a regulatory rate base

value, and thus a net PP&E value can be calculated. The CCA recommended that the

Commission direct AET to quantify the gross and net PP&E values for Alberta PowerLine on the

same basis as AET calculates its gross and net PP&E in its GTA schedules for other affiliates

and to report those values in its compliance filing. The CCA also recommended that AET be

directed to calculate its revenue and labour costs on the same basis as the costs are presented in

AET’s own GTA schedules.526

603. The CCA submitted that the Commission’s normal approach for head office cost

allocations is to rely on the actuals two years prior to the first test year. The CCA considered that

the use of the most recent 2017 actual results is more appropriate. Accordingly, the CCA

recommended that AET’s head office costs be allocated to Alberta PowerLine for both the 2018

and 2019 test years based on the 2017 values.

604. AET explained that the services provided to Alberta PowerLine were accounted for under

a service concession arrangement and that the transmission line is not recognized as PP&E but as

a long-term accounts receivable as amounts are due from the AESO.527 In particular, AET

explained that Alberta PowerLine did not record PP&E on its balance sheet but, rather, recorded

a financial asset representing the amounts due from the AESO in accordance with IFRS.528 The

testimony, of AET witness, Ms. Goode was that the total value of the transmission assets that

524 Transcript, Volume 3, page 546, lines 6-9, Mr. Hoshowski’s response to Mr. Wachowich. 525 Exhibit 22742-X0417.01, AET-AUC2018JUN08-045(b). 526 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 165. 527 Exhibit 22742-X0417.01, AETAUC-2018JUN08-045(c). 528 Exhibit 22742-X0669.


Decision 22742-D01-2019 (July 4, 2019) 135

Alberta PowerLine would record as PP&E as opposed to the costs of the asset actually recorded

are not significantly different in magnitude.529 AET maintained there was no justification for

changing the previously approved head office allocation given that the allocation formula uses

total assets and that the recording of Alberta PowerLine as a financial asset is not significantly

different from what it would record as “PP&E.”

605. In rebuttal evidence, AET objected to the CCA’s recommendation that head office costs

be allocated to Alberta PowerLine, and that AET be directed to calculate its net revenue and

labour costs, for the purposes of allocating head office costs, on the same basis as the costs are

presented in AET’s GTA schedules rather than using actual audited data.530 AET argued that the

CCA’s recommendation that head office costs for 2018 and 2019 be allocated to Alberta

PowerLine based on a single year, 2017, rather than the year that is two years prior to the test

year is not warranted. AET maintained that the Commission’s use of audited financial data from

the year that is two years prior to the first test year, in this case 2016, is supported by the

methodologies for cost allocation included in AET’s last two GTA decisions.531 AET submitted

the CCA is cherry-picking and ignoring the recent findings of the Commission with respect to

the use of actual audited data from the second prior year. AET maintained that over time, yearly

fluctuations in the inputs of the allocation formula will average out, as long as the formula

remains in place.

606. AET confirmed that the head office allocation formula is based on each company’s total

assets, not a regulatory rate base amount. In particular, Alberta PowerLine did not have a

regulatory rate base. Rather, its tariff is set out in the project agreement between Alberta

PowerLine and the AESO and is not calculated based on Alberta PowerLine’s investment in

utility assets. Additionally, AET submitted that assets normally only have regulatory rate base

value once they are put into service. As Alberta PowerLine’s assets will not be in service until

2019 and Alberta PowerLine will only begin collecting tariff revenue when the assets are put

into service, AET maintains that net PP&E should not be used.

607. AET clarified that Alberta PowerLine does not actually have labour costs as services

were provided by contractors, including AET and a non-affiliate company. AET records the fully

burdened costs charged to Alberta PowerLine by each contractor as contractor costs, not labour

costs. The ATCO companies, including AET, do not include contractor costs in the head office

allocation formula.

608. Finally, AET explained that as a start-up organization, Alberta PowerLine did not have

any tariff revenue for 2016, the year on which the head office allocation for the 2018 and 2019

test years is based and it should not be allocated any head office costs for 2018 and 2019.

However, even if 80 per cent of Alberta PowerLine’s net revenues and total assets from its

audited financial statements for 2016 were included in the head office allocation formula on

Schedule 25-8-1 of the application (equal to CUL’s ownership interest),532 the impacts on AET’s

forecast revenue requirements for 2018 and 2019 would be insignificant. AET supplied

529 Transcript, Volume 4, page 562, lines 8-16. 530 Exhibit 22742-X0618, AET rebuttal evidence, pages 137-139. 531 Decision 20272-D01-2016, paragraphs 131, 884 and 1275; and Decision 2013-358: ATCO Electric Ltd., 2013-

2014 Transmission General Tariff Application, Proceeding 1989, Application 1608610-1, September 24, 2013,

page 954. 532 Exhibit 22742-X0002.04.


Decision 22742-D01-2019 (July 4, 2019) 136

Table 14533 to illustrate these amounts, which it forecast would be $0.05 million for 2018, and

$0.06 million for 2019.

609. In argument, the CCA maintained that Alberta PowerLine is a significant asset that will

be in place during the test period and that will alter the level of actual head office resources

allocated to Alberta PowerLine. The CCA argued that although AET charges its internal labour

costs to Alberta PowerLine as contractor costs, this does not change the fundamental point that

contractor costs are similar to labour costs and are not being properly taken into account by the

current head office allocation model. To address these concerns, the CCA recommended that the

Commission consider more current information for Alberta PowerLine and alter the mechanics

of the head office allocation formula specific to Alberta PowerLine for labour costs. The CCA

submitted that the Commission should direct AET to utilize an amount for internal labour costs

based on the contracted manpower charges received from AET that are equivalent to the internal

labour that an entity like Alberta PowerLine would otherwise normally retain.534

610. In its argument, the UCA submitted that there is “… something fundamentally wrong

with the current allocation formula for head office costs, which results in no allocation of these

costs to Alberta PowerLine, another ATCO affiliate. It is difficult to accept that such an

allocation is fair or reasonable, or that it does not result in other affiliates subsidizing Alberta

PowerLine’s fair share of these costs.”535

611. In reply argument, the CCA stated that Alberta PowerLine is a new entity that was not

considered in the 2015-2017 GTA and it would not be reasonable to knowingly exclude more

recent and relevant information available to the Commission about Alberta PowerLine in

considering how to allocate head office costs. The same could not be said for other entities

included in the current calculation because they are not new entities undergoing significant

changes.536 The CCA submitted that this circumstance is also a significant change in facts that is

novel to the issues that were considered by the Commission in Decision 20272-D01-2016 and

thus warrants further attention.

Commission findings

612. In the Commission’s view there are two questions to be determined with respect to the

allocation of costs to Alberta PowerLine:

(a) For the allocation of head office costs in the 2018-2019 test years, should financial data

from two years preceding the first test year be used, or should data from more recent

year(s) be used to allocate head office costs to Alberta PowerLine?

(b) Should head office costs be allocated to Alberta PowerLine during the test years on the

basis of the labour costs incurred by AET on its behalf but which were charged out as

contractor costs?

613. With respect to the first question, the currently approved practice for allocating head

office costs is to use actual data from the second year preceding the first test year. AET has

533 Exhibit 22742-X0618, AET rebuttal evidence, page 139. 534 Exhibit 22742-X0722, CCA final argument, page 178, also refers to Madsen testimony, Transcript, Volume 7,

page 1200 line 15 to page 1201, line 4, Mr. Madsen to Ms. Sabo. 535 Exhibit 22742-X0724, UCA final argument, paragraph 89. 536 Exhibit 22742-X0726, CCA reply argument, page 51.


Decision 22742-D01-2019 (July 4, 2019) 137

argued that it would be unfair to deviate from this practice stating that, over time, yearly

fluctuations in the inputs of the allocation formula would average out, as long as the formula

remains in place. The CCA suggested that Alberta PowerLine is a new entity that was not

considered in the 2015-2017 GTA and as a new entity it was reasonable for the Commission to

consider if the findings from Decision 20272-D01-2016 should apply to Alberta PowerLine head

office costs.

614. The Commission has considered the arguments of the parties on which year to use as the

base year for determining allocations, if any, to Alberta PowerLine. In Decision 2013-211,537

Decision 2013-358,538 and Decision 20272-D01-2016,539 the Commission determined that the

actual data from the year that is two years prior to the first test year in a GTA should be used for

the corporate cost allocator and for head office costs. In the normal course of events, the head

office cost allocation would be calculated in the manner approved in these prior decisions.

However, the Commission agrees with the CCA that the use of the most recent 2016 actual

results does not reflect Alberta PowerLine because, while the labour costs are accounted for

under the service concession agreement, the current head office costs allocation does not take

account of the use of head office resources by Alberta PowerLine.

615. Additionally, the Commission takes notice that, subsequent to the close of the hearing on

June 24, 2019, Canadian Utilities Limited has sold its 100 per cent ownership interest in Alberta

PowerLine.540 During the course of the proceeding, AET confirmed that it is not until the in-

service date of the APL project that Alberta PowerLine would become an operating entity within

the pool and would therefore be allocated head office costs. AET argued that over time yearly

fluctuations in the inputs of the allocation formula will average out. The Commission considers

there is some merit to these arguments notwithstanding the sale as evidenced by the cost

allocation data provided by AET for 2018 and 2019 in Undertaking 38.541

616. The Commission is not convinced that the unique circumstances of Alberta PowerLine

require an adjustment to the allocation formula which has been consistently used in AET’s

GTAs. The use of the second year audited data in the allocation formula promotes consistency,

data reliability and avoids forecasting error. For these reasons, the Commission directs that head

office cost allocations continue to be calculated based on the actual, audited financial data of the

second year preceding the first test year of the GTA.

617. With respect to the second question, the development of a proxy for direct labour, the

Commission considers that some amount should be attributed to Alberta PowerLine. The

Commission considers it unreasonable that Alberta PowerLine should be able to avoid an

allocation of costs based on this factor solely because its labour billings from AET are recorded

as contractor costs. Alberta PowerLine clearly requires labour and that labour is being supplied

by AET. AET is therefore directed to propose, in its compliance filing, a proxy for labour,

537 Decision 2013-111: The ATCO Utilities, Corporate Costs, Proceeding 1920, Application 1608510-1, March 21,

2013, paragraph 134. 538 Decision 2013-358, paragraphs 131, 884 and 954. 539 Decision 20272-D01-2016, paragraphs 1273-1275. 540 Canadian Utilities Limited, News Release, Canadian Utilities Limited Sells Ownership Interest in Alberta

PowerLine and Offers Indigenous Communities the Opportunity to Participate, June 24, 2019,

https://ml.globenewswire.com/Resource/Download/b585ae57-66cc-4917-ab38-9b7fed620e6f. 541 Exhibit 22742-X0673, Undertaking 38.


Decision 22742-D01-2019 (July 4, 2019) 138

including its rationale and calculations, that will be used in the head office cost allocation

calculation to account for Alberta PowerLine.

15.4 Allocation of head office rent costs

618. Throughout AET’s and interveners' submissions on the allocation of head office rent

costs, various ATCO Group entities were referred to as the parent of AET. Where ATCO Ltd.,

CU Inc., and Canadian Utilities Limited are mentioned, the reference is to a “parent” of AET.

Where ATCO group of companies is used, that reference is to all ATCO companies, and not to

an AET parent company.

619. In its application update542 filed September 4, 2018, AET forecast a $1.2 million increase

in head office rent in each of the years 2018 and 2019. Head office costs are related to functions

such as corporate governance, and financial and administrative services that cannot be directly

charged to subsidiaries. Head office costs are included in corporate administration and general

expenses. The bulk of the increase in forecast head office rent in each of the test years was

attributed to the move to a new corporate head office building in southwest Calgary, called

ATCO Park. ATCO Park is considered to be a Class A building.543

620. AET explained that the forecast allocation of head office costs to AET is included in

USA 930.2544 and represents its allocated share of head office rent, including lease space at

ATCO Park for head office employees.545 AET further explained that the forecast allocation of

head office costs is shown on its MFR schedules 25-3 and 25-9 in the total amount of $12.6

million for 2018 and $12.8 million for 2019. Of those total amounts, AET stated that $1.8

million in each of 2018 and 2019 was AET's total forecast allocation of head office rent costs546

of which $1.6 million was attributable to ATCO Park.547

621. In addition to the allocation of head office rental costs through USA 930.2 AET

explained that the rental costs for space leased for AET employees are forecast in USA 931.1.548

This amount includes AET employees housed at ATCO Park. AET stated it had very few (21)

employees at ATCO Park.549 Being an affiliate transaction (whether for renting space at ATCO

Centre, as was formerly the case, or now for ATCO Park), these costs are also reflected in

Schedule 30-8 — Schedule of Corporate O&M Affiliate Costs, line 17.550 Given the small staff

complement of AET in Calgary, AET explained that with the relocation of AET employees to

ATCO Park in Calgary, AET's forecast lease costs in Calgary were unchanged at $0.1 million.551

The actual costs for USA 931.1 were $1.5 million in 2017 and were forecast to be $1.5 million in

2018 and 2019.

542 Exhibit 22742-X0533, page 25. 543 Transcript, Volume 3, page 539, lines 2-13. 544 The account is “Miscellaneous General Expense,” also shown at Exhibit 22752-X0002, Schedule 30-8. 545 Transcript, Volume 3, page 494; Exhibit 22742-X0571 and Exhibit 22742-X0578; AET-CCA-20180CT05-

013(e). 546 Exhibit 22742-X0002.04, MFR Schedule 25-9, line 21. 547 Exhibit 22742-X0578, AET-CCA-20180CT-013(a), attachment 1. 548 Exhibit 22742-X0001.02, updated application, PDF page 106, Schedule 25-3, line 106 549 Exhibit 22742-X0696. 550 Exhibit 22742-X0001.02, updated application, PDF page 740. 551 Exhibit 22742-X0434, PDF page 49.


Decision 22742-D01-2019 (July 4, 2019) 139

622. In an IR response to the Commission, AET explained the increases in head office rent, as

follows:

Overall, $1.1 million of ATCO Electric’s increase in costs in 2018 is attributable to the

move to ATCO Park.

The increase in costs is a result of two primary drivers. The first driver being increases in

rented square feet from approximately 85,000 in the ATCO Centre downtown to 155,000

square feet in ATCO Park. This increase is primarily attributable to additional meeting

space, training and development rooms, larger areas for employees to collaborate such as

breakout rooms, and space for future expansion. The second driver is the increase of

leasing rates from $20 per square feet at the ATCO Centre to $32 per square feet at

ATCO Park. In 2018, ATCO Electric’s share of these costs is 21.0% compared to 19.8%

in 2016.552

623. AET stated that the business decision to proceed with ATCO Park and to locate corporate

office staff there was made in 2013 by the ATCO Group, not AET, with the ultimate "go/no

go"553 decision residing solely with ATCO Ltd.

624. ATCO Ltd. is the tenant on the lease. The landlord is ATCO Investments Ltd., and the

lease with ATCO Ltd. was effective August 1, 2017. The lease included the first year lease cost

of $32 per sq. ft., escalating $1 per sq. ft. for each year of the 10-year lease, resulting in the tenth

year having a lease cost of $41 per sq. ft.554 The lease was based on 123,000 sq. ft. of rentable

area on four floors of ATCO Park.

625. AET confirmed on the record that it did not sign any lease or sublease for space in ATCO

Park and that the lease signed by ATCO Ltd. is not legally binding on AET. As a result, the

ATCO Ltd. lease neither confers any benefits or legal rights upon AET nor imposes any costs or

legal obligations upon it.

626. AET explained that the occupancy rate of its existing ATCO Centre in downtown

Calgary was expected to reach 98 per cent by the end of 2014 based on the projected growth rate

from 2012 to 2013. During the years leading up to 2013, AET’s efforts to address capacity issues

with its existing office space included reducing cubicle sizing, increasing the number of bullpen-

type spaces, and placing up to four persons in offices intended for one employee. While this

provided a workable solution for the short-term, a long-term solution was required that would

also allow for leasing rate predictability.555

627. As noted above, AET stated that the plan for ATCO Park was approved in 2013. In 2014,

the building design was completed, and the agreement with the general contractor was signed.

Construction started in April 2015. AET stated that in 2013, Alberta’s economy was still

expected to remain strong. In its rebuttal evidence, AET provided attachments showing the then

FMV of commercial office space, in Royal Bank of Canada (RBC) reports dated December 2013

and December 2014. These reports reflected expectations of continued vibrant economic

conditions in the province.556 AET also supplied a report from Colliers International for the first

552 Exhibit 22742-X0557, pages 153-154. 553 Exhibit 22742-X0725, AET final argument, paragraphs 334 and 352. 554 Exhibit 22742-X0571, AET response to AET-CCA-2018OCT05-013. 555 Exhibit 22742-X0618, AET rebuttal evidence, page 123. 556 Exhibit 22742-X0618, AET rebuttal evidence, pages 131-134.


Decision 22742-D01-2019 (July 4, 2019) 140

quarter of 2013 noting that while market demand for downtown Calgary office space had

softened, rental rates for Class A office space in the downtown core remained high at $39 per

square foot (sq. ft.). During the same period, vacancy rates for commercial office space were at

4.35 per cent.557

628. In correspondence issued to parties prior to the receipt of argument, the Commission

requested that parties address a number of questions respecting the legal principles that should

guide the Commission’s deliberations on the matter of determining a reasonable allocation of

head office rent to AET, and to include a discussion of the relevant jurisprudence.558 Parties’

responses to these questions, a number of which are summarized below, were helpful to the

Commission.559

629. AET submitted a number of arguments in support of the forecast head office rent costs

allocated to it, including the following:

In determining just and reasonable rates, the Commission must have regard for the costs

allocated to a utility subsidiary from a parent organization on a forecast basis.560 AET has

an obligation to pay its share of head office costs allocated to it because head office costs

and functions are necessary to provide utility service.561 A just and reasonable tariff has to

be fair to both customers and the utility.562

The appropriate test to use when assessing the reasonableness of affiliate services is

found in Section 4.2.1 of the ATCO Group Inter - Affiliate Code of Conduct (code of

conduct),563 which is no more than fair market value of such services.564 While the code of

conduct was not directly applicable to the ATCO Park lease, AET submitted that the

Commission may look to it for guidance on how to assess the reasonableness of the head

office rent costs allocated to AET.

The salient time for assessing the reasonableness of the forecast costs to be included in

head office rent costs allocated to AET should be fixed at the time the decision was made

to proceed with ATCO Park, that is, 2013. The reasonableness of the rental rate cannot be

appropriately assessed with hindsight.565 Instead, the reasonableness of forecast head

office costs should be assessed at the fair market value for rental rates in 2013.566

ATCO Ltd. was “fully entitled to enter into commercial agreements for the acquisition of

required services, such as leased space, including with its affiliates.”567 AET referred to

557 Exhibit 22742-X0618, AET rebuttal evidence, page 135. 558 Exhibit 22742-X0719. 559 The full arguments and reply arguments of AET, the CCA and the UCA are found at exhibits 22742-X0722,

22742-X0724, 22742-X0725, 22742-X0726, 22742-X0727, and 22742-X0729. 560 Exhibit 22742-X0725, AET final argument, paragraph 340. 561 Exhibit 22742-X0725, AET final argument, paragraph 356. 562 Exhibit 22742-X0727, AET reply argument, paragraph 254. 563 ATCO Group Inter-Affiliate Code of Conduct, Appendix 5 to Decision 2003-040, May 22, 2003. 564 Exhibit 22742-X0725, AET final argument, paragraph 344. 565 Exhibit 22742-X0725, AET final argument, paragraph 337. In paragraph 352 of AET’s argument, it states that

in the specific circumstances of ATCO Park, the commitment to proceeding with the building was made in

2013. The execution of the ATCO Park Lease in 2017 was merely a formalization of the commitment made in

2013 to proceed with ATCO Park. 566 Exhibit 22742-X0725, AET final argument, paragraph 358. 567 Exhibit 22742-X0725, AET final argument, paragraph 347.


Decision 22742-D01-2019 (July 4, 2019) 141

Decision 2014-169, related to the 2010 Evergreen proceeding for the provision of IT and

customer care and billing services,568 where the Commission found that FMV (Fair

Market Value) pricing should not be influenced by the nature of the affiliate

transaction.569

630. AET submitted that it is frequently the case that the term of commercial leases (and of

other types of agreements) is for a period of many years. This would particularly be the case for

a newly constructed building. AET observed that eight of the leases listed in its evidence were

for terms of 10 years or longer.570 AET submitted that the term of the ATCO Park lease was

reasonable in light of all the evidence on the record of this proceeding. Additionally, AET stated

it was not uncommon for leases to have escalation clauses. This is demonstrated by rental rates

in the comparator leases571 and over the initial seven years of an AltaLink lease.572

631. Bema’s evidence noted the increase in both the square footage and the leasing rate per sq.

ft. that AET is forecasting over the test period. Bema compared the lease rates at ATCO Park to

the lease rates that AltaLink was paying. AltaLink’s Commission-approved lease rate was $20.43

per sq. ft. through to the year 2026.573 The lease rate at ATCO Park, in contrast, started at $32 per

sq. ft. in 2018 and escalated by an additional $1 per sq. ft. each year for the next ten years. In

addition, AET’s forecast lease rate at ATCO Park was considerably higher than the $20 per sq.

ft. rate AET had been paying at ATCO Centre until just prior to the move to ATCO Park.574

632. Bema asserted that it was common knowledge that the Calgary office rental market has

been economically depressed for several years along with much of the Alberta economy.

Vacancy rates for commercial real estate have been at or near all-time highs and rental rates have

been in decline for years. Bema cited two real estate annual reports for 2016 and 2017 by Jones

Lang LaSalle (JLL) that show lease rates for prime space on 8 avenue south in Calgary had

declined by 24 per cent in 2016575 and a further 10 per cent in 2017.576

633. Further, Bema noted that the arrangement between AET and ATCO Ltd. is essentially an

affiliate rather than independent arm's length arrangement and that there are inherent risks in

affiliate-type transactions. Specifically, the question of how much profit is embedded in the lease

rate is important, yet that information is not available in this proceeding. Additionally, given that

the transaction for office space is with AET's parent, ATCO Ltd., Bema maintained that AET

faces a much greater onus to demonstrate that the costs being incurred are competitive and

represent fair market value. Given that no business case has been provided to support the

decision to move to ATCO Park, and that a business case would normally include a quantitative

568 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 Application 1605338-1, February 6, 2015. ATCO cites

paragraphs148,165, 166 and 434 of this decision. 569 Exhibit 22742-X0725, AET final argument, paragraph 334-348 570 Exhibit 22742-X0694. 571 Exhibit 22742-X0694. 572 Exhibit 22742-X0594 PDF page 14. 573 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 156. 574 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 157, refers to Attachment 2 of evidence. 575 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 158, refers to JLL’s website:

http://www.jll.ca/canada/en-ca/news/241/canadas-most-expensive-streets. 576 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 158, refers to JLL’s website:

http://www.jll.ca/canada/en-ca/news/253/bay-street-avenue-des-canadiens-de-montreal-among-the-

mostexpensive-streets-in-canada.


Decision 22742-D01-2019 (July 4, 2019) 142

and qualitative analysis of the various options that were available, Bema argued that there was no

evidence to support a finding that AET’s decision to purchase these services was reasonable,

especially at the rental rates and square footage being unilaterally allocated to AET by its parent.

Bema submitted affiliate services should be retained at the lesser of cost or market value.577

634. Bema also noted that the amount of square footage being leased at ATCO Park has

increased significantly from the old square footage under lease without any reasonable

justification for that increase. While productivity gains and improved work spaces may be

beneficial, Bema maintained that AET has not provided evidence that these benefits will be

obtained and has not fully explained why it is necessary that those benefits should be paid for by

ratepayers.578

635. Bema recommended that the Commission approve head office rent equal to the most

recent ATCO Centre rent of $20 per sq. ft. and apply that rate to the previously leased space of

85,000 sq. ft. This would reduce AET’s forecast head office rent costs by approximately $1.2

million in each of 2018 and 2019.

636. The CCA maintained that AET’s argument that 2013579 is the appropriate time to assess

the reasonableness of rental costs for ATCO Park be dismissed in its entirety. The CCA argued

that costs, and the rates based upon those approved costs, must be just and reasonable. The CCA

also argued that it was “important to point out that in this case, ATCO Ltd., AET’s parent,

decided to enter into a long-term rental agreement with its affiliate, ATCO Investments Ltd.

through the ATCO Park Lease.”580 Accordingly, the CCA submitted that the critical

determination to be made by the Commission is whether the real estate rental rates AET is

requesting the Commission to flow through to regulated ratepayers based on non-arm’s length

transactions between AET's unregulated parent and AET are just and reasonable. In addition, the

CCA noted that AET itself did not enter into any specific contractual or binding agreement for

real estate services with any of its affiliates,581 nor is AET even a party to the lease.582 It would be

unfair for ratepayers to bear the costs of an agreement that AET had no part in negotiating.583

637. Among the other arguments made by the CCA in opposing the ATCO Park rental costs

being allocated to AET by its parent are the following:

Section 2.7 of the Code of Conduct states it is not binding on the authority of the

Commission and does not “detract from, reduce or modify in any way, the powers of

the EUB [now the AUC] to deny, vary, approve with conditions, or overturn, the

terms of any transaction or arrangement between a Utility and one or more Affiliates

that may be done in compliance with this Code.”584 Under Section 4.2.1 of the code,

the “utility shall pay no more than fair market value.” The code of conduct definition

577 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 160. 578 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, page 161. 579 Exhibit 22742-X0722, CCA final argument, paragraph 581, page 171 580 Exhibit 22742-X0722, CCA final argument, referring to Exhibit 22742-X0571, AET Reponses Round 3 to

CCA, PDF page 5. 581 Exhibit 22742-X0722, CCA final argument, paragraph 482. 582 Exhibit 22742-X0722, CCA final argument, paragraph 526. 583 Exhibit 22742-X0726, CCA reply argument, paragraph 218. 584 Exhibit 22742-X0722, CCA final argument, paragraphs 518-519.


Decision 22742-D01-2019 (July 4, 2019) 143

of FMV requires the price to be one that is at least equal to an open and unrestricted

market between informed and prudent parties, acting at arms length.585

A lease agreement is significantly different from an agreement to purchase a physical

asset. The CCA explained that when a utility purchases a physical asset, that purchase

is made at a specific point in time, based on information known or that ought to have

been known at that time. By asking the Commission to approve a long-term lease

agreement, the utility is effectively asking the Commission to accept that the utility

has made a reasonable assessment of the future costs that would be incurred in the

market and that the long-term lease agreement will be more reasonable than otherwise

subjecting itself to rental changes in each year.586 The CCA further stated that the key

determination the Commission is required to make is whether the costs AET is

requesting to pass on from its parent in each year going forward are just and

reasonable. That assessment of reasonableness can either be performed by the

Commission up front in this proceeding and be resolved for the term of the ATCO

Ltd. lease agreement or can be performed during each test period based on the

information available to the Commission in that test period.587

It was ATCO Ltd.’s choice to enter into a long-term lease for future operating costs,

and nothing prohibits the Commission from utilizing current market-based

information to assess the justness and reasonableness of forecast operating costs AET

is seeking to flow through to its customers.588

Contrary to AET’s submissions, the Commission’s findings in Decision 2014-169, do

not support AET’s position589 that “the key observation from this finding is that the

Commission confirmed that its examination of Fair Market Value pricing should not

be influenced by the affiliate nature of the transaction.”590 The CCA submitted that the

Commission’s findings in Decision 2014-169, in fact, support the CCA’s position,

where the Commission went on to state that “This is not a cost of service proceeding

for ATCO I-Tek.”591 The CCA maintained that the instant proceeding was likewise

not a cost of service proceeding for the ATCO group of companies. Instead,

Proceeding 22742 is a cost of service proceeding for AET established to test whether

the forecast costs of AET are just and reasonable.

638. The CCA recommended that the Commission approve a lease rate of $20 per sq. ft.

because that represents the FMV for similar properties in downtown Calgary, and is therefore a

just and reasonable rate to be recovered from ratepayers.592

639. In argument and reply argument, the UCA submitted that Section 121 of the Electric

Utilities Act requires the Commission to ensure that a tariff is “just and reasonable.” Section 122

(h) provides that the Commission must provide the owner of an electric utility a reasonable

585 Exhibit 22742-X0722, CCA final argument, paragraph 523. 586 Exhibit 22742-X0722, CCA final argument, paragraph 487. 587 Exhibit 22742-X0722, CCA final argument, paragraph 489. 588 Exhibit 22742-X0722, CCA final argument, paragraph 489. 589 Exhibit 22742-X0725, AET final argument, paragraph 347. 590 Exhibit 22742-X0725, AET final argument, paragraph 348. 591 Exhibit 22742-X0725, AET final argument, paragraph 347. 592 Exhibit 22742-X0722, CCA final argument, paragraph 575.


Decision 22742-D01-2019 (July 4, 2019) 144

opportunity to recover “any other prudent costs and expenses that the Commission considers

appropriate, including a fair allocation of the owner’s costs and expenses that relate to any or all

of the owner’s electric utilities.” To the extent that the Commission determines they are not, the

shareholder and not the ratepayer is responsible for those costs.

640. In determining just and reasonable rates, the UCA argued that the stand-alone principle

should be foremost in determining reasonable rental costs. Applying this principle, the

Commission should approve costs only if they can be found to be prudent as measured against a

notional separate stand-alone utility. In other words, was it reasonable or would it be prudent, for

a stand-alone utility carrying out AET’s business to incur these costs when they were incurred?

The UCA submitted that the relationship of AET to its parent, or to its parent’s parent must be

ignored. Further, the costs should not be artificially made lower or higher as a result of these

corporate relationships, than would be the case if AET were acting as a stand-alone entity.593 The

UCA asserted that AET, acting prudently as a stand-alone entity would not have made the

decision and commitment so early, and that the Commission can take the downturn into

account.594

641. The UCA noted Mr. Palladino’s admission to Commission counsel that “so the lease

space was a –was driven by ATCO, not ATCO Electric Transmission.”595 The UCA argued that

the parent took over the management of AET in this instance, and must assume management’s

responsibilities to ratepayers. The UCA further reminded the Commission that AET’s move was

not supported by a business case.596

642. The UCA stated that the relevant question to be determined by the Commission is

whether the allocation to AET of head office rental costs based on a decision made by ATCO

Ltd. in 2013 would represent market value measured at the time it would have been prudent or

necessary for AET (as a stand-alone entity) to relocate from its former location to ATCO Park.

The UCA’s answer to this question was that it would not. In its view, the year 2013 was far too

early to serve as the relevant benchmark for FMV.

643. The UCA argued that while it may or may not have made sense for ATCO Ltd. to

commit in 2013 to the future construction of ATCO Park, the question for the Commission to

determine is whether the allocation to AET of head office rental costs based on market rates in

2013 represents FMV for regulated utility rate-making purposes in 2018-2019. According to the

UCA, the Commission, in relying on the standalone principle to set just and reasonable rates for

AET, should measure the FMV of commercial office rental rates at the time it would have been

prudent or necessary for AET, as a standalone entity, to incur (that is, to legally commit itself to

paying) office space leasing costs at its new head office location. In the UCA’s view, that time

would not have been 2013 but several years later.

644. In reply argument, the UCA noted that both it and the CCA agree that, because AET is

not a party to the ATCO Park lease, the lease itself has no legal significance for AET.597 AET has

593 Exhibit 22742-X0724, UCA final argument, paragraph 73. 594 Exhibit 22742-X0724, UCA final argument, paragraph 86. 595 Transcript, Volume 6, page 896, lines 2-4. 596 Exhibit 22742-X0724, UCA final argument, paragraph 70. 597 Exhibit 22742-X0724, UCA final argument, paragraph 81; Exhibit 22742-X0722, paragraph 527; and

Transcript, Volume 6, page 1044, lines 15 to 23.


Decision 22742-D01-2019 (July 4, 2019) 145

claimed that the lease provides documentary evidence to support the quantum of rental costs.598

The UCA questioned whether it was prudent or reasonable to commit to a rental rate four years

prior to when the office space would become available.599

645. In reply argument, AET stated that the uncontroverted evidence in this proceeding is that

in 2013, the ATCO group of companies, including AET, were running out of space for their

growing number of office employees in the downtown Calgary area and needed a permanent

solution to their growing workforce requirements. Therefore, in 2013, a decision and

commitment were made to build ATCO Park taking into consideration the current and future

needs of the entire organization, including forecasts of future requirements based on information,

economic conditions, commercial real estate rental rates and vacancy rates known at that time.600

According to AET, the evidence also demonstrated that the rental rate in the ATCO Park lease

was in alignment with the FMV for comparable suburban Class A buildings at the time the

commitment to proceed with ATCO Park was made by ATCO Ltd.601

646. AET submitted that as the head office rent costs were consistent with FMV at the time

the commitment was made to proceed with the building, including those costs in AET's revenue

requirement is reasonable.

647. AET maintained that the Supreme Court of Canada602 has been clear that, whether or not

it is reasonable to assess a particular cost using hindsight, turns on the circumstances of that cost.

AET stated that a “no-hindsight assessment” of the head office rental costs included in AET's

forecast revenue requirement is a “reasonable means of striking the balance of fairness between

consumers and utilities.” AET took issue with the CCA's suggestion that because the costs in this

instance are “operating costs,” they should be assessed on “an annual basis for reasonability.”603

It noted, for example, that the Supreme Court of Canada was clear in Ontario (Energy Board) v

Ontario Power Generation Inc. (OEB decision) that a no-hindsight prudence analysis may

equally be applied to operating costs:

A no-hindsight prudence review has most frequently been applied in the context of

capital costs, but Enbridge and Nova Scotia Power (both 2005 and 2012) provide

examples of its application to decisions regarding operating costs as well. I see no reason

in principle why a regulatory board should be barred from applying the prudence test to

operating costs.604

648. AET submitted that just because head office rental costs are operating costs is not

determinative of whether a hindsight analysis should be used. Many contracts for the acquisition

of goods and services can extend beyond a single test year; and the reasonableness of the

associated operating costs is judged based on the circumstances that existed at the time the

commitment was made. The subject lease was no different.605

598 Exhibit 22742-X0725, AET final argument, paragraph 350. 599 Exhibit 22742-X0724, UCA final argument, PDF pages 29-30, paragraph 84. 600 Exhibit 22742-X0618, AET rebuttal evidence, Part 7.1, PDF pages 122-128; AET rebuttal evidence,

paragraphs 334-337. 601 Exhibit 22742-X0618, AET rebuttal evidence, Table 13. 602 Ontario (Energy Board) v Ontario Power Generation Inc., [2015] 3 SCR 147. 603 Exhibit 22742-X0722, CCA final argument, paragraph 485. 604 OEB, paragraph 102. 605 Exhibit 22742-X0727, AET reply argument, pages 81-82.


Decision 22742-D01-2019 (July 4, 2019) 146

649. There is one other preliminary matter the Commission wishes to address before turning to

its findings in this part of the decision. That is, it remains somewhat unclear to the Commission

whether AET is seeking approval of only the real estate rental costs allocated to it by ATCO Ltd.

for the 2018 and 2019 test years, or whether AET is seeking a blanket approval from the

Commission of the full schedule of rental charges set out in ATCO Ltd.’s 10 year lease,

including all 10 annual escalation charges. The Commission, notes, however, that in its reply

argument, AET stated that:

…the evidence on the record establishes that neither the term of the lease commitment,

being 10 years, nor the escalation included in the ATCO Park Lease, detract from the

reasonableness of the ATCO Park Lease rental rates...the Commission should not assess

the reasonableness of the rental forecast to be included in head office costs allocated to

AET with “hindsight.” Therefore, material changes in market rates for comparable real

estate after the point in time when the commitment was made to proceed with ATCO

Park are not relevant to the Commission's determination of fair market value of the

subject rental rates. Given that a hindsight analysis is not appropriate, the benefit or risk

of material change in the rental market does not render the ATCO Park Lease rates

unreasonable or imprudent. As such, the Commission should not penalize the shareholder

as a result of market downturns during the term of a lease, just as it would be

inappropriate to impose additional costs associated with market rental increases on

customers during the term of a lease. Both sides should be expected to honour the terms

of the agreement they have entered into, and the Commission should approve the

inclusion of the associated costs, as long as it is shown that [they] were reasonable, as is

the case here, at the time the commitment was made.606 [emphasis added]

650. Based on this detailed explanation of AET's position, the Commission will treat AET as

having applied for approval of the schedule of direct head office rental costs for the full term of

the lease, and not just those for the two years of the current test period.

Commission findings

651. AET, the CCA and the UCA all agree that head office rent will be determined by the

Commission based on its authority to set just and reasonable rates pursuant to Section 121(2)(a)

of the Electric Utilities Act. The Commission determines rates, in accordance with its legislative

mandate, which requires it to render decisions in the public interest.607 The Commission tests

rates given the Commission’s rate-setting function and recognizing its role as a specialized and

expert tribunal.608

652. The burden of proof to show that a tariff is just and reasonable lies with the party seeking

approval of the tariff.609 Section 122(1)(h) states:

606 Exhibit 22742-X0727, AET reply argument, page 80 607 Section 6(1)(a) of the Alberta Utilities Commission Act provides that Commission members “shall act honestly,

in good faith and in the public interest.” 608 ATCO Gas and Pipelines Ltd v Alberta (Utilities Commission), 2014 ABCA 397, paragraph 17, where the Court

commented, “The Commission is a specialized body with a high level of expertise in a wide range of areas:

ATCO Gas and Pipelines Ltd v Alberta (Utilities Commission), 2014 ABCA 28 at para, 26. These include:

utility regulatory reform, competition policy, strategic planning and development, wholesale markets, service

quality and compliance standards, performance-based and incentive regulation, capital structure of regulated

utilities, debt and equity markets, utility assets dispositions, utility deregulation and, of course, rate-related

regulation – along with the policy considerations involved in each.” 609 Section 121 of the Electric Utilities Act.


Decision 22742-D01-2019 (July 4, 2019) 147

When considering a tariff application, the Commission must have regard for the principle

that a tariff approved by it must provide the owner of an electric utility with a reasonable

opportunity to recover

…

(h) any other prudent costs and expenses that the Commission considers appropriate,

including a fair allocation of the owner’s costs and expenses that relate to any or all of the

owner’s electric utilities.

653. AET is an “owner” of a transmission facility as defined in Section 1(1)(jj) of the Electric

Utilities Act.

654. AET submitted that the Commission’s consideration of whether the allocated head office

rent costs constitute just and reasonable rates for head office rent during the 2018-2019 test

period should be based on whether these rent costs were consistent with FMV in 2013, that is, at

the time ATCO Ltd. made a commitment on behalf of the ATCO group of companies to proceed

with ATCO Park.610 In AET’s submission, if the Commission finds that the rental costs being

allocated to AET by ATCO Ltd. are consistent with FMV in 2013, then recovering these costs

through AET’s 2018-2019 revenue requirement is reasonable. Earlier in the proceeding,

including the hearing itself, AET had suggested that in order for the Commission to be able to

make such a determination, it must first conduct a prudency assessment of ATCO Ltd.’s decision

to build a new head office at ATCO Park for the ATCO group of companies. In AET’s

submission, were the Commission to find that ATCO Ltd.’s 2013 decision was prudent, and that

the costs of giving effect to this decision were likewise prudently incurred, based on what was or

should have been known to ATCO Ltd. at that time about conditions in the downtown and

suburban Calgary commercial property market, then the Commission must conclude that the

head office rent costs being allocated to AET by ATCO Ltd., including the increases in rent costs

during the test period, constitute FMV and, hence, are just and reasonable.611

655. As the Commission in questioning pointed out several times during the hearing, however,

the Commission's task is to set just and reasonable rates for AET, not its unregulated parent

company. Thus, whether ATCO Ltd., was prudent or imprudent in deciding in 2013 to build new

head office space for the ATCO group of companies, and whether the costs it subsequently

incurred in doing so were prudent or imprudent, has no bearing on whether the head office rental

costs that AET is seeking to recover from customers during the 2018-2019 test period are just

and reasonable.

656. AET conceded this point during argument and reply argument, acknowledging that “As

noted by the Commission, the Commission is not testing the corporate decision of ATCO Ltd. to

proceed with ATCO Park in this proceeding.”612 In the latter stages of this proceeding, therefore,

AET stepped away from its earlier request that the Commission conduct a prudency review to

satisfy itself of the reasonableness of ATCO Ltd.’s decision to proceed with the construction of a

new head office at ATCO Park. Instead, AET narrowed its focus to the evidence it submitted on

overcrowding at its then head office in the 2013-2014 period and the market-based rental rate

610 Exhibit 22742-X0727, AET reply argument, page 75. 611 Exhibit 22742-X0727, AET reply argument, paragraph 248. 612 Exhibit 22742-X0727, AET reply argument, paragraph 221.


Decision 22742-D01-2019 (July 4, 2019) 148

comparison it compiled in 2013 for commercial real estate comparable to what ATCO Ltd. had

decided to build to meet its needs in future years.

657. All parties agree that the concept of FMV can be of considerable assistance in

ascertaining whether a proposed rate for the rental of commercial real estate is just and

reasonable. Section 2.1(n) of ATCO's Affiliate Code of Conduct defines FMV as “the price

reached in an open and unrestricted market between informed and prudent parties, acting at

arm’s length and under no compulsion to act.” Similar definitions can be found in various other

dictionaries. For example, Black’s Law Dictionary613 defines FMV as “the price that a seller is

willing to accept and a buyer is willing to pay on the open market and in an arm’s length

transaction; the point at which supply and demand intersect.” The Dictionary of Legal Terms,614

meanwhile, defines market value as “the price that property would bring in a market of willing

buyers and willing sellers, in the ordinary course of trade. Market value is generally established,

if possible, on the basis of sales of similar property in the same locality. Market value is

generally synonymous with actual value, cash value, and fair market value.” A similar definition

of FMV can be found in Duhaime’s Law Dictionary: “The hypothetical most probable price that

could be obtained for a property by average, informed purchasers.”615

658. The Commission finds that there is little dispute among the parties to this proceeding on

how FMV should be defined. Far more contentious, however, is when FMV should be measured

in order to provide a benchmark or proxy for just and reasonable rates during the current test

years. In particular, should the FMV of comparable commercial real estate be measured (1) as of

2013; (2) the date the ATCO Ltd. lease was signed; (3) the time period when a stand-alone

regulated entity contemplating a head office move might have reasonably committed to a long

term rental lease; or perhaps (4) closer to the date the leased premises actually became available

for occupancy? According to AET, the FMV of head office rental costs, at least in the case of

ATCO Park, must be determined not at the time the rates are to be charged to AET (that is, the

2018-2019 test period), but at the time the decision was initially made by AET’s parent, ATCO

Ltd., to build ATCO Park. In other words, AET claims that the correct time to ascertain FMV for

its head office rental costs is four to five years before the new rates are to be charged to AET,

notwithstanding the significant and widespread collapse in real estate rental rates in the Calgary

commercial property market during the intervening years.616 As noted above, interveners were of

the view that FMV should be determined much closer to the start of the current test period.

659. The Commission does not accept AET’s submissions on the ATCO Park lease costs. It

finds that AET has failed to meet its onus to establish, on the balance of probabilities, that the

relevant time period to assess the reasonableness of AET’s proposed office space rental rates for

the 2018-2019 test period (and beyond for the remainder of ATCO Ltd.’s lease term) is in 2013

when ATCO Ltd. made an irreversible commitment to build ATCO Park. Notwithstanding

AET’s view that basing AET’s 2018-2019 revenue requirements on the FMV of comparable

commercial real estate in 2013 is just and reasonable, there is insufficient evidence before the

Commission in this proceeding to substantiate these claims.

660. In particular, no business case for the construction of ATCO Park was ever filed for

Commission approval, nor would the Commission have ever accepted an ATCO Ltd. business

613 10th ed., Bryan A. Garner ed., Thomson Reuters, 2009. 614 3rd ed., Steven H Gifis, Barron’s Educational Services Inc., 1998. 615 http://www.duhaime.org/LegalDictionary/F.aspx 616 Exhibit 22742-X0618, AET rebuttal evidence, page 122.


Decision 22742-D01-2019 (July 4, 2019) 149

case for such a review had one been filed. This is because the Commission regulates AET and

not ATCO Ltd. and AET had very little, if anything, to do with the decision to build ATCO Park

and relocate there. Moreover, AET provided the Commission no evidence of other alternatives to

committing in 2013 to a new office build and future relocation that it may have put forward for

its parent companies’ consideration. For example, there was no evidence of AET or any of its

affiliates even considering temporary office space to deal with immediate overcrowding while

the “big build” took its expected course. The only alternative discussed in this proceeding was

the all or nothing option described by AET as ATCO Ltd.’s “go/no go” decision. The

Commission notes, in this regard that, according to AET, ATCO Ltd.’s decision to build 200,000

sq. ft. of office space to accommodate 600 employees plus an allowance for future expansion and

workforce growth was “irreversible.”617 Yet, sometime after ATCO Ltd.’s “go/no go” and

“irreversible” decision the ultimate square footage of ATCO Park was reduced to 155,000 sq.

ft.618 In addition, there was no documentary evidence of a legal or commercial nature to support

AET’s claim that its parent made an “irreversible” decision to proceed with ATCO Park at

anytime in 2013.

661. Likewise, there was nothing preventing AET from presenting the Commission with its

own assessment of the alternatives it faced in 2013, its ranking of those alternatives, and how

AET addressed its most pressing future needs for office space with its parent companies,

especially in terms of the type, square footage and rental cost of office space it believed it could

reasonably justify and recover in Commission-approved rates on a going forward basis. In this

regard, AET could also have signed its own lease with ATCO Investments Ltd. on terms it

believed were just and reasonable from a regulatory perspective and at a time that it considered

was equally advantageous to customers as it was fair to its ultimate shareholders. In the absence

of such additional documentation, however, the Commission finds itself with insufficient

evidence to support AET’s position that the head office rent costs its unregulated parent, ATCO

Ltd., wants AET to recover through its rates in 2018 and 2019 (and beyond), are just and

reasonable. At the same time, the Commission reiterates that it has no jurisdiction to assess the

prudence of ATCO Ltd.’s 2013 decision to build ATCO Park and the costs it incurred as a result.

662. The Commission further notes, in this regard, that there was no witness on the AET

hearing panel who was able to provide any first-hand evidence on the deliberations undertaken

and factors considered by AET’s parent companies at the time the commitment was made to

build ATCO Park. Nor was anyone on the AET panel able to testify on how AET’s parent

companies decided what to build, how much to build, and where to build it.619 For example, in

response to Commission questions on how AET communicated to its parent companies its needs

for office space, Mr. Goguen confirmed that while there may have been some discussions, no

one on the panel was involved in any of them:

617 Exhibit 22742-X0618, AET rebuttal evidence, page 123. 618 Exhibit 22742-X0572, page 24. 619 Transcript, Volume 6, page 887, Mr. Palladino confirmed that AET was not part of the negotiation process with

respect to terms or lease rates; page 1035, Mr. Palladino stated that engagement on space requirements were at

the CEO level and Board of Directors level and that the engagement would have occurred at the more senior

level within the ATCO group of companies. Mr. Palladino confirmed he was not engaged in those discussions;

page 1035, the office space requirements were based on an open-office concept and from that perspective, the

conversation would have happened “at the ATCO level”; page 1042, Mr. Goguen confirms that he was not

involved in the signing of the lease; and page 1070, Mr. Palladino confirmed that he was not aware of the

circumstances as to why the lease was signed in 2017.


Decision 22742-D01-2019 (July 4, 2019) 150

Q. So presumably no one -- did anyone on this witness panel get involved in the

discussions regarding AET's needs for space?

A. MR. GOGUEN: So perhaps I'll weigh in. So, firstly, to your question, no, nobody on

the panel. I was in a different role at that point in time. And perhaps just to correct

Mr. Palladino’s statement just slightly, he used the term “managing director.” Managing

directors came into the fold as part of our corporate reorg in 2015. Prior to that we had

presidents of the company. And I'm surmising that the presidents would have had -- made

representations of expectations of growth, et cetera, so that there's an overall common

understanding as to where the company’s going. And that would have been part of the

dialogue, I guess, from a corporate perspective in determining what the right approach

would have been.620 [emphasis added]

663. In addition, the Commission agrees with Mr. Madsen’s testimony that there is not a full

understanding of the decisions made in the 2013 timeframe, including those relating to the long-

term lease arrangement between certain ATCO companies (not including AET) that was only

signed in 2017:

Like my first point would be that I don't think we have a fulsome understanding of all the

considerations and factors that were -- that went into informing that decision, because we

did not have an ATCO witness, nor did we have an ATCO business case. As far as

simply because they made the decision to incur rental costs for a period of ten years at a

point in time and they believed that that decision was reasonable at that point in time,

again, I would turn back to the fact that these are operating costs. The Commission

assesses the reasonableness of a forecast operating cost in each period. Decisions that

occurred in the past which, may be prudent in the past, does not define those operating

costs as being prudent in the current period from a forecast perspective, in my opinion.

I think that they still need to be assessed for reasonableness in the current period.621

664. Because AET did not have input into or direct knowledge of the decision-making process

of the parent, and in the absence of clear insight into that process, there is also very little

evidence upon which the Commission can make a finding on the justness and reasonableness of

the actual amount, nature and quality of head office space being allocated to AET by its parent

and the rental rates being charged to AET for this space. AET has failed to meet its onus to

demonstrate that the head office rent costs it is seeking to recover in rates during the 2018-2019

test period (and beyond), including the allocation of space to AET underpinning those costs, are

just and reasonable.

665. This leaves the Commission in the position of having to decide how head office rental

rates for AET should be determined as there is insufficient evidence that prevailing market rental

rates for comparable commercial properties in Calgary during the 2013 time period provide a

reasonable basis for setting rates in 2018 and 2019 (and beyond). Although Mr. Palladino stated

it would take more than 12 to 24 months622 for AET to plan a head office move, in the

circumstances of this case, there is insufficient evidence to support what a reasonable time period

would be to plan an office relocation and then lease rental space for AET. The Commission does

not have the benefit of an AET lease or sublease and AET did not provide a business case to

justify its rental costs as a stand-alone entity as part of its 2018-2019 GTA.

620 Transcript, Volume 6, page 1036, lines 4-20. 621 Transcript, Volume 7, page 1192, line 18 to page 1193 line 9. 622 Transcript, Volume 6, page 895, lines 16 to 19.


Decision 22742-D01-2019 (July 4, 2019) 151

666. Absent other material and relevant information, such as an independent, standalone

assessment by AET of the head office rent that should be attributable to the regulated business,

or the existence of a formal AET lease or sublease, the best information available to the

Commission to set the appropriate time for determining the FMV of head office rent is the

ATCO Ltd. lease, which took effect on August 1, 2017. The lease is the only legal document that

provides a starting date for the legal obligations associated with the office space in ATCO Park.

It is also the only legal document that describes the term of the rights and obligations associated

with the leased premises and the head office rental costs that are allocated to and ultimately

included in AET’s head office rent.

667. In its argument, the CCA suggested that the Commission impute a lease rate of $20 per

sq. ft., that being the current rate at ATCO Centre, along with an operating cost allowance of

$16.50 per sq. ft.623 The UCA supported the recommendations of the CCA.624

668. In considering the evidence on the record with respect to the lease rate to be allowed for

the test period, the Commission concurs with the CCA that allowing a lease rate of $20.00 per

sq. ft. for both test years is reasonable. The Commission also considers that an operating cost

allowance of $16.00 per sq. ft. for 2018 is reasonable with an allowance of $16.50 per sq. ft. for

the 2019 test year. The $16.00 per sq. ft. approved for 2018 allows for a reasonable inflationary

increase over what AET states is the current estimate at ATCO Centre of $15.27 per sq. ft.625 The

$16.50 per sq. ft. approved for 2019 allows for an inflationary increase over 2018. AET is

directed to use these amounts in its compliance filing for purposes of determining its revenue

requirement.

669. For purposes of determining lease rates, AET is directed to provide, in its compliance

filing, evidence with respect to escalation rates that might be present in 10 year leases at the time

the ATCO Ltd. lease was signed in August 2017, and the Commission will consider whether the

approval of an escalator is warranted. The Commission’s determinations with respect to the

operating cost portion of the rental costs apply only to the current test period.

670. Turning to the calculations underlying AET's forecast head office costs, the Commission

notes that the increase in head office rent costs associated with ATCO Park is the result of two

primary drivers. The first driver is an increase in rented space from approximately 85,000 sq. ft.

in the ATCO Centre in downtown Calgary to 155,000 sq. ft. in ATCO Park in southwest

Calgary. The second driver is the increase in the office rental rate from $20 per sq. ft. to $32 per

sq. ft. at ATCO Park.626 The Commission will determine whether these drivers, or inputs to the

calculation of head office rent, are reasonable.

671. AET has stated that the forecast amount of head office rent allocated to it for the office

space occupied by corporate staff providing services to AET was $1.8 million for each of the test

years. A breakdown was provided in a response to a CCA IR,627 which demonstrated that the

majority of this forecast cost, $1.6 million for each test year, related to ATCO Park and was the

623 Exhibit 22742-X0722, CCA final argument, page 173. 624 Exhibit 22742-X0724, UCA final argument, page 25. 625 Exhibit 22742-X0572, page 24. 626 Exhibit 22742-X0557.01, AET-AUC-20180CT04-011(a), PDF page 154. 627 Exhibit 22742-X0572, page 24, AET-CCA-20180CT05-013(e), Attachment 1.


Decision 22742-D01-2019 (July 4, 2019) 152

reason for the significant increase in allocated corporate office rent. The table is reproduced

below:

Table 42. Forecast head office rent628

Description

Actual 2015

Actual 2016

Actual 2017

Forecast 2018

Forecast 2019

($ million)

Office rent per Sch 25-9 (total) 3.6 3.6 4.2 8.6 8.6

Comprised of:

ATCO Centre I 2.4 2.4 2.8 - -

ATCO Park - - - 7.8 7.8

ATCO Centre Edmonton 0.5 0.5 0.7 0.6 0.6

Other 0.7 0.7 0.7 0.2 0.2

3.6 3.6 4.2 8.6 8.6

AET allocation 18.0% 19.8% 19.9% 21.0% 21.0%

Office rent per Sch 25-9 (AET share) 0.6 0.7 0.8 1.8 1.8

Comprised of:

ATCO Centre I 0.4 0.5 0.6 - -

ATCO Park - - - 1.6 1.6

ATCO Centre Edmonton 0.1 0.1 0.1 0.1 0.1

Other 0.1 0.1 0.1 0.1 0.1

0.6 0.7 0.8 1.8 1.8

672. In the Commission’s view, affiliates appear to be charged twice for the same square

footage in the calculation of the total office rent. The calculation shows AET being allocated a

portion of 100 per cent of the cost of ATCO Park rather than the portion occupied by corporate

staff. This is verified by the calculation of ATCO Park costs as $7.8 million in the 2018 and 2019

forecasts ((which was derived based on $32 per sq. ft. rent + $18 per sq. ft. operating cost)629

times 155,000 sq. ft.). AET is being charged 21 per cent630 of this amount, which comes to

$1.6 million in each year.

673. AET was clear in its argument, however, that the portion of corporate space occupied by

direct AET employees was charged through the first category of office costs, head office rent.

AET stated:631

…with respect to the first category of costs, rent for AET leased space for AET

employees, these lease costs are forecast in USA 931.1 (Ex. X0001.02, Schedule 25-3,

628 Exhibit 22742-X0572, IR response to CCA-2018OCT05-013(e), page 24. 629 Exhibit 22742-X0572, page 24. 630 Exhibit 22742-X0572.02, page 24. The percentage of corporate costs that AET is allocated per the allocation

formula. Exhibit 22742-X0002, Schedule 28-8-1 shows the calculations. 631 Exhibit 22742-X0725, AET final argument, page 100.


Decision 22742-D01-2019 (July 4, 2019) 153

line 106). USA 931.1 captures the costs of AET's leased spaced costs, including ATCO

Park.

674. Given the above statement, it is clear to the Commission that the only portion of ATCO

Park costs to be allocated to AET through Corporate office rent account, USA 930.2, is AET’s

portion of corporate staff occupying space. From the response to Undertaking 52632 there were

459 employees at ATCO Park but only 237 were related to corporate functions – 177 head office

and 60 shared service employees. In the Commission’s view, it is only the pro rata share of these

employees’ costs at ATCO Park that should be charged to AET through corporate office rent

USA 930.2. That is, 21 per cent of the costs related to the 237 corporate employees.

675. In addition, to determine AET's reasonable share of corporate rent costs, the Commission

considers it necessary to examine the total capacity at ATCO Park. As noted in AET’s rebuttal

evidence, the occupancy at ATCO Centre was 90 per cent at the end of 2013 and was forecast to

rise to 98 per cent by the end of 2014. According to AET, the ATCO group of companies

considered the space at ATCO Centre inadequate and described the situation as follows:

During the years leading up to 2013, to cope with the capacity issues, ATCO reduced the

size of cubicles, increased the number of bullpen-type spaces, and placed up to four

people in offices intended for one employee. While this provides a workable solution for

the short-term, a long-term solution was required that would also allow for leasing rate

predictability.633

676. The Commission accepts this evidence as demonstrating that the ATCO group of

companies were facing space constraints at ATCO Centre by 2013 heading into 2014. In rebuttal

evidence, AET stated that when the move to ATCO Park was initially decided, it was expected

that 200,000 sq. ft. would be needed to accommodate 600 employees, plus an allowance for

future expansion and workforce growth.634

677. The actual space in the lease for ATCO Park is 155,000 sq. ft.635 During the hearing,

Commission counsel asked AET whether there was any industry benchmark relied upon to

determine the square footage requirements. Mr. Palladino responded:

I'm not aware of an industry benchmark that they may have looked at other than the

requirements they had at the time to facilitate the growing FTE requirements that they

were forecasting.636

678. AET did not identify benchmarks for office space square footage. There is a significant

increase in total square footage at ATCO Park, 155,000 sq. ft., over that available at ATCO

Centre, 85,000 sq. ft.637 As stated in AET’s rebuttal evidence, when ATCO Group initially

planned ATCO Park it considered it would need a space of 200,000 sq. ft. to accommodate 600

employees, plus an allowance for future expansion and workforce growth. The Commission

considers that the workforce reductions within the ATCO Group and AET since 2015 offset the

need for an allocation for future growth, which was identified in the initial planning by the

632 Exhibit 22742-X0696. 633 Exhibit 22742-X0618, AET rebuttal evidence, page 123. 634 Exhibit 22742-X0618, AET rebuttal evidence, page 123. 635 Exhibit-22742-X0572, page 24. 636 Transcript, Volume 6, page 882, lines 11-14. 637 Exhibit 22742-X0618, AET rebuttal evidence, page 121.


Decision 22742-D01-2019 (July 4, 2019) 154

ATCO Group. The Commission considers the actual space per sq. ft. at ATCO Park should be

sufficient to accommodate the 600 employees identified as the initial baseline need.638 Based on

600 employees and using 155,000 sq. ft., this equates to approximately 260 sq. ft./employee.

679. The Commission notes that the actual occupancy of ATCO Park is only 459

employees.639 AET has indicated that it targets a vacancy rate of seven per cent with respect to

office space.640 Applying this factor to the actual number of employees currently housed at

ATCO Park indicates that ATCO Ltd. only requires sufficient space for approximately 500

employees,641 not the 600 capacity of ATCO Park. The Commission has concerns with respect to

this excess capacity for 100 staff. Consequently, the Commission considers that ratepayers

should not be charged for a building, meeting rooms, or other common spaces that are excess

capacity i.e., capacity that is beyond what is reasonably required for office space for current

employees and for common space.

680. Therefore, to adjust the number of employees used in the allocation of corporate staff,

and to ensure AET's regulated customers are not charged for the capacity of 100 staff identified

above, AET is directed to compute the square footage in its allocation of corporate rent for

ATCO Park on the basis of (260/600)642 x 21 per cent. The numerator is the sum of head office

employees and shared services employees identified in Undertaking 52, adjusted for the seven

per cent vacancy factor. The denominator of 600 is the total employee capacity of ATCO Park.643

The use of the total employee capacity as the denominator will ensure that AET is not charged

for the excess capacity that exists at ATCO Park and would otherwise be charged if the actual

occupancy of 459 were used.

681. The above adjustment corrects the charges to USA 930.2 for AET’s portion of corporate

head office lease costs. The Commission also notes that a similar adjustment should be made to

USA 931.1 to correct the charges to AET for the 21 direct AET employees, plus the adjustment

for the seven per cent building vacancy rate, in ATCO Park. AET is directed to make this

adjustment in its compliance filing.

682. The Commission notes that IR response AET-CCA-2018OCT05-013(e)644 indicates that

AET is also charged for space occupied by corporate staff at other locations. In its compliance

filing, AET is directed to provide the calculations supporting these charges to enable the

Commission to verify that charges for corporate staff at other locations are reasonable.

683. Separate and apart from head office rental costs, the lease costs for the amount charged in

USA 931.1, for AET employees directly occupying corporate office space, are forecast to be

$1.5 million in each of the test years. While AET has identified that $1.4 million of this is

payable to Canadian Utilities Limited645 no breakdown has been provided as to the facilities

rented or how the forecast rent expense has been calculated. To ensure that the Commission has

a thorough understanding of how the forecast has been determined, AET is directed in its

638 Exhibit 22742-X0618, AET rebuttal evidence, page 123. 639 Exhibit 22742-X0696, Undertaking 52. 640 Exhibit 22742-X0288, AET-CCA-2017AUG30-048, page 165. 641 Calculated as: 459 employees x 1.07 = 491 actual capacity needed, will be rounded up to 500. 642 Calculated as: 237 employees x 1.07 = 254. The number of corporate staff for which housing would be required

for with the vacancy factor. Rounded up to 260. 643 Exhibit 22742-X0618, AET rebuttal evidence, page 121. 644 Exhibit 22742-X0572, page 24. 645 Exhibit 22742-X0002.04, Schedule 30-8.


Decision 22742-D01-2019 (July 4, 2019) 155

compliance filing to identify the facilities leased and to provide the calculations showing how the

forecast of $1.5 million has been derived, and the Commission will test these costs further in the

compliance filing.

15.5 Reserve for injuries and damages

684. AET discussed the reserve for injuries and damages (RID) in Section 29.2 of the

application.646 For the test years, AET forecast charges to the reserve account of $700,000 in

2018 and $200,000 in 2019, noting that the decrease in charges from past years is due to lower

actual claims experienced. For 2018 and 2019, AET included a provision of $0 to move the

account towards a target balance of zero by the end of 2019. AET applied for approval to

continue to annually settle any differences between the approved amounts and actual amounts

within this reserve account as part of its Transmission Deferral Account and Annual Filing for

Adjustment Balances Application, similar to the treatment approved in Decision 20272-D01-

2016.647

685. For GTA test periods, AET includes a provision in the RID account for uninsured claims.

The provision is an estimate and does not identify specific claims made by the utility. Actual

claims regarding the RID, and draws against the reserve are reviewed as part of AET’s

application for disposition of deferral accounts and annual filing for adjustment balances

proceedings. However, for this proceeding, AET provided actual claims for the 2015-2017

period.

686. In argument, AET submitted that due to the timing of Decision 20272-D01-2016 and the

timing of the 2018-2019 GTA, actual RID claims for the 2015-2017 period were included in its

revised application. The impact of any differences between actual and approved RID claims for

2015 through 2017 is incorporated into the 2018-2019 GTA RID forecast, which ultimately

settles the balances reflected in this account. Going forward, AET requested in its 2018-2019

GTA the continuation of the ability to settle the reserve balance annually. It is AET’s intention to

true up RID amounts tied to future years in future deferral applications.648

687. The CCA took no position with respect to AET’s request for approval of amounts to be

funded within the RID.

Commission findings

688. There were no objections by interveners to AET’s forecast or its request to settle the RID

on an annual basis. The Commission notes the extended period required to process this

application and the availability of actual amounts for RID claims for the 2015-2017 period. The

Commission has reviewed the RID claims included in attachments 29.2.1 to 29.2.3 to AET’s

revised application, and finds the amounts to be reasonable. The Commission accepts and

approves AET’s forecast amounts of uninsured losses, with the exception of those costs in

respect of the Fort McMurray wildfire as noted in paragraph 3 of this decision. The Commission

accepts AET’s proposal to settle the RID account annually on a go-forward basis. AET is

directed to reflect these changes in its compliance filing to this application.

646 Exhibit 22742-X0001.02, updated application, starting at paragraph 598. 647 Exhibit 22742-X0001.02, updated application, paragraph 599. 648 Exhibit 22742-X0725, AET final argument, paragraph 326.


Decision 22742-D01-2019 (July 4, 2019) 156

16 Financing and credit metrics

689. AET’s forecast capital program over the test years is much smaller than that for the

period 2011-2014, which required temporary credit relief measures to address potential negative

impacts on AET's credit metrics. These relief measures comprised: including transmission direct

assigned capital construction work-in-progress (CWIP) balances in rate base, recovery of the

capital portion of pension costs on a cash basis, and recovery of federal future income taxes

(FIT).

690. The Commission, in Decision 20272-D01-2016, directed AET to discontinue CWIP-in-

rate base and the recovery of the capital portion of pension costs on a cash basis effective

January 1, 2017. AET continued to collect FIT in its revenue requirement as its sole credit relief

measure for 2017.

16.1 Credit metrics

691. In its application, AET sought the continued collection of federal FIT for the test period

given the following:

…it results in forecast credit metrics which are in line with those from AET’s 2016 and

2017 GTA as well as the FFO/Debt credit metric range of 9-13% for an “A” rated utility

based on S&P’s low volatility scale which originates from the 2016 Generic Cost of

Capital Proceeding and was continued in the 2018 Generic Cost of Capital Decision

(22570-D01-2018).”649 [footnotes omitted]

692. AET submitted that the continued collection of federal FIT will help maintain credit

metrics at a level that will sustain an “A” rating and minimize the risk of a credit rating

downgrade that would result in higher AET costs for new debt issues.

693. To support its credit metrics during the test period, “AET is targeting the middle to upper

part of the 9-13% FFO/Debt range.”650 AET included the following table in its application:

Table 43. Credit metrics scenarios with and without federal FIT

2018 Scenarios

Federal FIT No relief

FFO/Debt 11.4% 10.5%

FFO interest coverage 3.49 3.29

Interest coverage 2.26 2.26

2019 Scenarios

Federal FIT No relief

FFO/Debt 11.4% 10.7%



Source: Exhibit 22742-X0001.02, application, paragraph 576.

649 Exhibit 22742-X0001.02, updated application, paragraph 573. 650 Exhibit 22742-X0001.02, updated application, paragraph 577.


Decision 22742-D01-2019 (July 4, 2019) 157

694. Mr. Bell presented evidence, on behalf of the UCA, showing the credit metrics levels

with and without federal FIT.651 The following tables reflect credit metrics which include federal

FIT credit relief:

Table 44. Credit metrics scenarios which include federal FIT

2018 With refund of CWIP Without refund of CWIP

FFO/Debt 12.0% 11.4%




FFO/Debt 11.8% 11.4%



Source: Exhibit 22742-X0599, Mr. Bell evidence on behalf of the UCA, paragraph A22, PDF page 14.

695. The following tables reflect credit metrics which exclude federal FIT credit relief:

Table 45. Credit metrics scenarios which exclude federal FIT


FFO/Debt 10.5% 10.5%




FFO/Debt 10.6% 10.7%



Source: Exhibit 22742-X0599, Mr. Bell evidence on behalf of the UCA, paragraph A22, PDF page 14.

696. Mr. Bell observed that AET's credit metrics, as shown in the tables above, are well within

the Commission-prescribed ranges of 9 to 13 per cent652 established in the 2018 Generic Cost of

Capital decision,653 even with the refund of CWIP-in-rate base balances and excluding federal

FIT. Mr. Bell added, “The FFO to Debt percentages of 10.5% and 10.6% for 2018 and 2019

respectively are well above the AUC floor of 9%, and even above 10%. Further I note that the

ratios increase from 2018 to 2019.”654

697. Mr. Bell submitted655 that credit ratings agencies consider:

…the regulated utilities as low risk ventures, and any risk faced by shareholders is

largely derived from other business ventures. In fact, it is entirely possible that, on a

standalone basis, the credit ratings of the other non-regulated ATCO entities would be

much lower were it not for the support provided by the regulated ATCO entities.

651 Exhibit 22742-X0599, Mr. Bell evidence on behalf of the UCA, paragraph A22, PDF page 14. 652 Decision 22570-D01-2018, paragraph 700. 653 Decision 22570-D01-2018, paragraphs 775-776. 654 Exhibit 22742-X0599, Mr. Bell evidence on behalf of the UCA, paragraph A23, PDF page 15. 655 Exhibit 22742-X0599, Mr. Bell evidence on behalf of the UCA, paragraph A24, PDF page 16.


Decision 22742-D01-2019 (July 4, 2019) 158

698. For the above reasons, Mr. Bell recommended that the collection of federal FIT be

removed from the 2018 and 2019 revenue requirements, resulting in reductions of $29.2 million

and $23.8 million for 2018 and 2019, respectively.656

699. In its argument, the UCA submitted:

…the evidence suggests that it is not AET and its regulated activities that are responsible

for the factors that credit agencies consider to be creating pressure upon ATCO Ltd.’s

credit rating. Again, the credit rating agencies routinely view AET’s regulated activities

as posing less of a risk to credit metrics than unregulated activities do. Ultimately, AET

ratepayers should not be responsible for supporting CU Inc.’s credit ratings, to counteract

pressures placed upon them by unregulated affiliates. In the circumstances, the available

rate relief should be provided.657

700. AET challenged Mr. Bell’s position that an acceptable FFO-to-debt ratio above the

Commission floor of nine per cent or even 10 per cent is not supported.658 It argued that targeting

the middle to upper part of the Commission's approved nine to 13 per cent FFO-to-debt range is

prudent because AET and ultimately CU Inc.’s credit metrics need to remain well supported to

minimize the risk of a further credit rating downgrade.

701. In addition, AET stated:

… AET’s current forecast FFO to Debt ratio of 11.4% for each of the 2018 and 2019 Test

Periods is in-line with the AUC’s calculated 11.1% FFO to Debt ratio from the 2018

GCOC Decision. Further, the forecast 2018 and 2019 FFO to Debt ratio of 11.4% is very

close to AET’s 2017 GTA approved forecast for FFO to Debt of 11.2% which is an

appropriate comparison to AET’s 2018-2019 forecast given Federal FIT was approved by

the AUC as the sole credit relief measure for AET’s 2017 Test Period …659

[footnotes omitted]

702. Further, AET submitted that Mr. Bell had mischaracterized statements taken from S&P

credit rating reports by suggesting that the rating downgrade was directly due to unregulated

projects, such as the West Fort McMurray Transmission project.

Mr. Bell appears to use these misleading statements in an attempt to place an increased

weighting on S&P’s consideration of non-regulated projects on its determination of

ATCO Ltd.’s credit rating and imply AET’s request for credit relief of Federal FIT is

required as subsidization for ATCO Ltd. which AET submits is simply not the case.660

703. AET stated that federal FIT amounts collected through the approved revenue requirement

receive no cost capital treatment. This means that customers are compensated at AET's weighted

cost of capital for this no cost capital amount, which is treated as an offset to the return on rate

base that AET earns.

656 Exhibit 22742-X0599, Mr. Bell evidence on behalf of the UCA, paragraph A26, PDF page 17. 657 Exhibit 22742-X0724, UCA final argument, paragraph 100. 658 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 204. 659 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 204. 660 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 205.


Decision 22742-D01-2019 (July 4, 2019) 159

Commission findings

704. The Commission’s view on targeting a credit rating in the “A range” has not changed

from the 2016 GCOC or 2018 GCOC, each of which was premised upon maintaining AET's

FFO-to-debt ratio in the range of nine to 13 per cent. In the previous AET GTA, interveners

proposed an FFO-to-debt ratio of 11 per cent, while AET proposed a ratio of at least 14 per cent.

705. In the current GTA, the CCA recommends an FFO-to-debt ratio of between nine per cent

and 10 per cent, while AET requested 11.4 per cent for each of its test years, stating that it was

targeting the middle to upper part of the Commission’s accepted FFO-to-debt range to minimize

the risk of a further credit rating downgrade.

706. The Commission considers that the level of credit metrics should conform to the ranges

and minimums reviewed and established as part of the GCOC proceedings, and that the level of

support required is that which is needed to maintain a stable “A range” rating, which influences

the cost of debt available to the utility.

707. The Commission observes that AET wishes to continue the sole credit relief mechanism

approved in the last GTA for 2017, being the collection of federal FIT. For the 2018 test year,

which has now passed, CU Inc. did not experience a credit rating downgrade. Neither has this

occurred for the first half of 2019 which has now passed as well.

708. The Commission finds that the FFO-to-debt ratio currently requested by AET is close to

the midpoint of the current Commission acceptable range. Further, this level of FFO-to-debt,

which has not resulted in a credit downgrade, is reasonable and contributes to a stable credit

rating from which customers benefit through stable rates for the cost of debt.

709. The FFO-to-debt ratio level proposed by the CCA, which is based upon discontinuing

federal FIT, lies at the lower end of the range generally accepted by the Commission. The FFO-

to-debt range requested by AET, meanwhile, approximates the level approved by the

Commission during the previous GTA.

710. For the reasons above, the Commission has determined that AET may continue to collect

federal FIT for the test years, as its sole credit relief measure.

16.2 Cost of debt

711. AET’s external financing requirements, and those of ATCO Gas and Pipelines Ltd.

(operating as ATCO Gas for gas distribution and ATCO Pipelines for gas transmission), are

obtained through CU Inc.661

712. In its updated application, AET is forecasting the following long term debt issues during

the test years:

661 Exhibit 22742-X0001.02, updated application, paragraph 568.


Decision 22742-D01-2019 (July 4, 2019) 160

Table 46. Forecast long-term debt issues during test period

Issue Rate Amount ($ million) Maturity

2018 4.13% 90 2048

2019 4.43% 60 2049

Source: Based on Exhibit 22742-X0001.02, updated application, Table 28.2 Forecast Long Term Debt Issues, paragraph 579.

713. Debt issues would be mirrored down to AET through CU Inc. and are forecast to have a

30 year term to maturity. Forecast debenture rates of 4.13 per cent and 4.43 per cent for 2018 and

2019, respectively, which represent “the mid-year forecast [that] is determined using the average

of year-end forecasts from Consensus Forecasts. This methodology differs from the previous

method undertaken in the AET 2015-2017 GTA, but it provides a more stable forecast as the

Consensus report provides a larger set of data points.”662

714. AET provided the following tables to summarize the forecast debenture rates:663

Table 47. Forecast 2018 long-term debt rate

%

Consensus forecast,10-year GOC

November 2018 2.50

2018 10-year GOC proxy 2.50 2.50

10-30 year GOC bond yield differential 0.18

30-year credit spread 1.45

2018 forecast 30-year debt rate 4.13

Source: Exhibit 22742-X0001.02, updated application, paragraphs 582-583.

Table 48. Forecast 2019 long-term debt rate

%

Consensus forecast,10-year GOC

August 2019 2.80

2019 mid-year 10-year GOC proxy 2.80 2.80

10-30 year GOC bond yield differential 0.18

30-year credit spread 1.45

2019 forecast 30-year debt rate 4.43

Source: Exhibit 22742-X0001.02, Application, paragraphs 582 - 583, PDF pages 596-597.

715. AET sought to discontinue the debt rate deferral account, which had been established by

the Commission in Decision 2013-358.664 It submitted that the decline in the size of its capital

program and the significantly lower forecast of debenture issues in the current application have

reduced the risk of a material difference from forecast occurring.

716. The CCA observed that the forecast debt rate for 2018 was 4.42 per cent in AET’s

original application. Subsequently, the September 2018 application update showed a revised

forecast rate for 2018 of 4.13 per cent, while the actual debt issue by CU Inc. in late November

had an interest rate of 3.95 per cent. The CCA submitted that the actual debt issue rate of

3.95 per cent should be used, and the 2018 revenue requirement should be adjusted accordingly.

662 Exhibit 22742-X0001.02, updated application, paragraph 582. 663 Exhibit 22742-X0001.02, updated application, paragraphs 582-583. 664 Decision 2013-358, paragraphs 923-925.


Decision 22742-D01-2019 (July 4, 2019) 161

717. In its argument, the CCA presented the following table displaying a history of AET’s

debt forecasts and subsequent 30-year bond forecasts:665

Table 49. AET 2019 forecast, 2018 actual debt issue and current 30-year bond rates

AET forecast 17/06/16



Actual debt issue

late Nov. 2018

2019 forward rate 19/01/24

Current rate

19/03/12

(%)

Forecast/Actual AET debt rate

4.60 4.72 4.43 3.95

Less: credit spread 1.45 1.45 1.45 1.45

Implied/Actual 30-year bond rate

3.15 3.27 2.98 2.50 2.17 2.02

Source: Exhibit 22742-X0001, PDF page 526; Exhibit 22742-X0001.02, PDF page 622; Transcript, Volume 3, pages 429-430; and Bank of Canada V39056.

718. The CCA argued that its table demonstrates that AET’s forecasts consistently overstate

the actual interest rates that would be paid, and the table shows a falling trend in interest rates

from the original forecast 30-year Canada rate of 3.15 per cent to the current rate of 2.02 per

cent.

719. For 2019, the CCA recommended that the Commission select either the current rate of

2.02 per cent, or the forward rate of 2.17 per cent or, alternately, the average of the current and

forward rate, being 2.1 per cent, if the Commission wished to rely on more than one rate.

720. The CCA submitted that its proposed bond rates are close to the 2.3 per cent rate

established in the 2018 Generic Cost of Capital decision.666 The CCA, however, did not

recommend use of the 2.3 per cent rate given that interest rates appear to have fallen 12 to 30

basis points since the GCOC decision was issued.

721. The CCA argued that AET’s forecasts have been consistently high as they are based on

the Consensus Forecasts. Since AET is forecasting a 30-year bond rate of 2.98 per cent instead

of the current actual rate of 2.02 per cent, the CCA submitted that costs are over-estimated by

$0.4 million for 2019. The CCA’s recommendations with respect to bond rates would result in

2019 debt rates being in the range of 3.47 per cent to 3.62 per cent.

722. The CCA opposed AET’s proposal to eliminate the interest rate deferral account, instead

recommending that it be retained “out of an abundance of caution.”667 The CCA submitted that

should the Commission decide to eliminate the deferral account, the approved rate should be set

no higher than 3.62 per cent for 2019.

723. In argument, AET submitted that the 2018 actual CU Inc. debt issuance of $90 million at

a coupon rate of 3.95 per cent was in line with its 2018 forecast, and that the variance from the

665 Exhibit 22742-X0722, CCA final argument, paragraph 746, PDF page 217. 666 Exhibit 22742-X0722, CCA final argument, paragraph 751-752. 667 Exhibit 22742-X0722, CCA final argument, paragraph 761.


Decision 22742-D01-2019 (July 4, 2019) 162

forecast rate of 4.13 per cent had an immaterial impact on revenue requirement of approximately

$0.1 million and $0.2 million for 2018 and 2019, respectively.668

724. In reply argument, AET submitted that the CCA inappropriately introduced new evidence

in its argument about the 2019 debt rate based on information current as of March 12, 2019. AET

argued that it has had no opportunity to test or respond to such evidence and submitted that this

new evidence be struck from the record and be disregarded by the Commission.669

725. In response to the CCA proposal to use the Bloomberg forward curve forecast, AET

argued that the forward curve is not a forecast of what rates will be in the future. Instead, it is an

indication of rates that can be locked-in today for settlement at some point in the future. For this

reason, the forward curve is better suited for coordinating hedging contracts.

726. Lastly, with respect to the debt deferral account, AET submitted that as it no longer meets

the criteria for deferral account treatment, it should be removed.670

Commission findings

727. In Decision 2010-189,671 the Commission considered the following criteria when

evaluating the need for a deferral account:

materiality of the forecast amounts,

uncertainty regarding the accuracy and ability to forecast the amounts,

whether or not the factors affecting the forecasts are beyond a utility’s control and,

whether or not the utility is typically at risk with respect to the forecast amounts672

728. The Commission has also considered a symmetry factor, as described below:



proceeding, took the view that "deferral accounts should not be for the sole benefit of

either the company or the customers." Deferral accounts, rather, should “provide a degree


control,” and hence “[s]ymmetry must exist between costs and benefits for both the

Company and its customers." The Board also noted that it expected that "the individual


and fair manner in both test years and non-test years.673

729. In addition, the Commission’s predecessor, the Alberta Energy and Utilities Board, found

that it did “not consider there to be a definitive Board policy regarding the use of deferral

accounts. Rather, the board’s practice [has] been to evaluate the use of a deferral account on a

case-by-case basis, on its own merit.”674

668 Exhibit 22742-X0725, AET final argument, paragraph 406. 669 Exhibit 22742-X0725, AET final argument, paragraph 292. 670 Exhibit 22742-X0725, AET final argument, paragraph 295. 671 Decision 2010-189. 672 Decision 2010-189, paragraph 72. 673 Decision 2010-189, paragraph 73. 674 Decision 2003-100: ATCO Pipelines, 2003/2004 General Rate Application – Phase I, Application 1292783-1,

December 2, 2003, page 116.


Decision 22742-D01-2019 (July 4, 2019) 163

730. AET sought to have the debt rate deferral account discontinued, due to its smaller capital

program and correspondingly lower forecast debt issues, resulting in reduced risk of material

forecast differences. The CCA, however, recommended maintaining the deferral account given

AET’s forecast history, which consistently overstated the actual interest rates that would be paid.

731. The Commission observes that while the capital program in the current application has

moderated, there has been little change in the size of forecast long-term debt issues in 2016

($120 million) and 2017 ($55 million) relative to the size of forecast debt issues in the current

test period.

732. For the 2018 test year, AET forecast a long-term debt issue of $90 million using a

forecast debt rate of 4.13 per cent, which has subsequently been replaced with an actual rate of

3.95 per cent. For 2019, AET has forecast a long term debt issue of $60 million at an interest rate

of 4.43 per cent, while the CCA has recommended debt rates in the range of 3.47 per cent to

3.62 per cent. While AET’s debt rate forecasts in its application show an increasing trend, the

CCA argued that there was, instead, a falling trend in actual interest rates.

733. These debt rate forecast variances for 2019 fall between the level of three quarters to one

per cent, which the Commission considers material based upon the forecast debt issue amount of

$60 million. Further, the Commission finds that the continued use of deferral account treatment

provides a balance of protection for the utility and customers, as required by the symmetry

factor.

734. For these reasons, the Commission considers that the debt rate deferral account should

continue to be used, but in this case, only for the 2019 test year. For 2018, the Commission

directs that the actual cost of debt be used. The amount to be recorded in the 2019 deferral

account is to be determined by updating the approved “Schedule of Debt Capital Employed and

Embedded Cost” (Schedule 28-2) for 2019 to reflect the actual weighted debenture rate for 2018;

and updating the same schedule for 2019 to reflect the actual weighted debenture rates for each

of 2018 and 2019. The resulting embedded cost of debt for the applicable year will then be used

to update the “Schedule of Capital Structure and Average Cost of Capital” (Schedule 28-1) for

that year. This will result in an updated return on long-term debt for that year. The difference

between the updated return on debt and the approved return on debt for that year will be the

resulting balance in the debenture rate deferral account for that year.

735. Given the approval for the continued use of the debt rate deferral account for 2019, the

Commission needs to determine a reasonable forecast for the cost of debt to be used for the

second test year. As the actual cost of debt and the issue amount for AET’s 2018 debt issuance is

known, the Commission directs AET, in the compliance filing, to update its application in all

aspects to reflect the 2018 actual cost of debt resulting from the actual 2018 long-term debt

issues.

736. The CCA recommended three options for the 2019 debt rate: basing the debt rate on the

current Government of Canada bond rate of 2.02 per cent, the forward Government of Canada

bond rate of 2.17 per cent, or the average of these two rates, being 2.1 per cent. AET challenged

the CCA's submissions on this point because they were based on improperly adduced new

evidence, namely, the current 30-year Canada bond rate as of March 12, 2019. The Commission

agrees with AET's submission that the CCA improperly introduced new evidence in its argument

and, accordingly, will disregard the 2019 information provided in the CCA’s argument.


Decision 22742-D01-2019 (July 4, 2019) 164

737. While not in agreement with the CCA's proposed debt rate, the Commission finds AET's

forecast debt rate of 4.43 per cent to be high, particularly in light of its recent bond tender at 3.95

per cent. The Commission directs AET to use 3.95 per cent as a forecast rate for 2019 long-term

debt, especially since this forecast 2019 debt rate will be afforded deferral account treatment.

The Commission, therefore, approves a forecast 2019 debt rate of 3.95 per cent and directs AET,

in its compliance filing, to update its application in all aspects to reflect the forecast long-term

debt cost rates of 3.95 per cent for 2018 and 2019.

17 Revenue offsets and recoveries from affiliates

738. Revenue offsets that form part of revenue requirement include amounts related to facility

charges, affiliate revenues, services to outside parties and other revenue. Facility charges serve to

recover costs incurred by AET when constructing and operating facilities on sites having an

industrial system designation. Affiliate revenue results from AET personnel providing services to

AET affiliates, and the revenue includes “recovery of the direct cost of the service as well as

overhead charges in accordance with the Inter-Affiliate Code of Conduct. Affiliate revenues are

offset by affiliate cost of goods sold which are included in operations costs.”675 Services to

outside parties are performed by AET staff at the request of external parties for projects such as

road moves or work for the AESO.676

739. The table below provides a breakdown of revenue offsets by component:

Table 50. Revenue offset forecasts by component for test years

2018 2019

($ million)

Facility charges 0.5 0.5

Affiliate revenues 6.7 6.7

Services to outside parties 0.3 0.3

Revenue from leasing telemark tower to ATCO Gas 0.7 0.7

Total revenue offsets 8.2 8.1

Source Exhibit 22742-X0002.04, GTA schedules, Transmission Revenue Offsets, Schedule 8-1.

740. Bema presented evidence, on behalf of the CCA, showing that AET’s forecasting

accuracy for revenue offsets was very low. Bema suggested that much of the variance appeared

to be due to AET’s practice of not forecasting contracted services provided to AET affiliates. It

therefore recommended that the following adjustments be made to revenue offsets to align the

test year forecasts with AET’s historical actuals:677

(a) For Alberta PowerLine a $1.2 million and $1.3 million increase in 2018 and 2019,

respectively;

(b) For ATCO Power a $0.6 million increase in each of 2018 and 2019;

(c) For Northland Utilities (Yellowknife) a $0.1 million increase in both 2018 and

2019; and

675 Exhibit 22742-X0001.02, updated application, paragraph 270, PDF page 295. 676 Exhibit 22742-X0001.02, updated application, paragraph 275, PDF page 298. 677 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 649, PDF page 204.


Decision 22742-D01-2019 (July 4, 2019) 165

(d) For ATCO Electric Yukon a $0.1 million increase in each of 2018 and 2019.

741. Bema further explained that:678

Bema is not recommending any adjustment to AET’s base operating costs for these

offsets and Bema expects there to be enough staff and resources within AET to provide

this increased level of service to its affiliates. This is supported by the observed declines

in prior years for AET’s operating costs despite steadily increasing revenue offsets to

affiliates.

742. The CCA challenged AET’s continued reliance on an activity-based approach to forecast

revenue offsets, stating “it provides for a consistent and repeated understatement of AET’s

revenue offsets year-after-year.”679

743. The CCA pointed to AET’s need to correct an “inadvertent” error (related to Alberta

PowerLine revenue offsets) as identified by AET in its rebuttal evidence as further proof that the

revenue offsets were not well supported.680

744. In reply argument, the CCA expressed concerns681 over the potential variance between

forecast and actual internal labour allocated to O&M activities that can arise due to changes in

the amount of internal labour actually needed to provide services to affiliates. When less internal

labour than forecast is used for O&M activities because more internal labour is being used to

provide services to affiliates, then ratepayers are likely paying too much based on the O&M

forecasts included in revenue requirement.

745. AET challenged Bema’s characterization of AET’s accuracy in forecasting revenue

offsets as misleading and inaccurate. AET explained that a large portion of the variance is due to

contracted services being provided to AET affiliates. AET explained that it “…does not forecast

these expenses as they are flow-throughs and have no impact on overall revenue requirement.”682

746. In response to the adjustments proposed by the CCA, AET stated:683

There is no evidence on the record that the services AET will provide during the test

period will remain at historical levels or that AET would be able to provide a higher

volume of services than it has forecast without retaining additional staff. AET has

developed its revenue offset forecast, as well as the corresponding Cost of Goods Sold

forecast, based on the best available information on the services that will be provided in

the test period and the resources that will be required to provide these services.

747. With respect to the forecast update for Alberta PowerLine, which AET had not included

in its September 4, 2018 application update, AET explained that given the stage of the

proceeding, “[AET] will flow the related impacts through 2018 and 2019 revenue requirement in

its GTA compliance filing.”684 AET stated that forecast revenue offsets for Alberta PowerLine of

678 Exhibit 22742-X0592, CCA - Evidence of Bema Enterprises, paragraph 650, PDF page 204. 679 Exhibit 22742-X0722, CCA final argument, paragraph 709, PDF page 205. 680 Exhibit 22742-X0722, CCA final argument, paragraph 711, PDF page 206. 681 Exhibit 22742-X0726, CCA reply argument, paragraphs 116-117, PDF pages 28-29. 682 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 177. 683 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 179. 684 Exhibit 22742-X0618, AET rebuttal evidence, PDF page 181.


Decision 22742-D01-2019 (July 4, 2019) 166

$2.6 million and $2.4 million for 2018 and 2019, respectively, will be updated to $4.1 million

and $4.6 million, respectively.

748. In argument, AET reiterated that the ATCO Group Inter-Affiliate Code of Conduct

allows provision of services to affiliates on a cost recovery basis, which includes the fully

burdened costs incurred by AET. AET added that “customers are kept neutral on both a forecast

and actual basis due to offsetting entries on the Costs of Goods Sold (‘COGS’) line and the

revenue offset line which yields zero cost to customers.”685

749. In response to Direction 47 of Decision 20272-D01-2016, AET performed a review of the

affiliate overhead burden rate. While the methodology used to calculate the overhead rate has not

changed, AET removed certain costs from the overhead rate calculation because they are

specifically linked and attributed to the function of AET’s utility assets and are not required to

support labour charged to affiliate projects. Further, some costs previously identified as support,

or overhead type costs for providing services to affiliates were removed from the overhead rate

calculation because these costs are being directly charged to affiliate projects by the groups

involved. AET added that:

The result of AET's affiliate overhead rate review is the calculation of a 23% overhead

rate, which has been applied in AET's forecast costs for affiliate services in 2018 and

2019. The former affiliate overhead rate applied prior to this review was calculated as

30% for O&M affiliate work, with an additional 30% burden for capital affiliate work

(for a total of 60% burden on capital affiliate work). The revenue requirement impact of

updating the overhead rate from the previous rate to 23% is approximately $0.1 million

for each of 2018 and 2019.686

750. AET further submitted that its forecast of affiliate work is not related to its forecast of

required O&M work. For this reason, if more or less affiliate work is required, this does not

increase or decrease the O&M activity level. AET stated that even if it does more affiliate work

than it has forecast over the test period, it will be required to complete its forecast O&M work

using other resources, such as capital employees or contractors.687

751. AET confirmed that it did not forecast flow-through costs as part of revenue offsets

because these costs vary widely from month to month and have no impact on overall revenue

requirement. Flow-through costs primarily comprise payments to landowners for land access,

third party contractors (mostly land agents), hearing costs, and legal fees.688

Commission findings

752. The Commission has prepared the following table that provides a historical comparison

of the forecast accuracy for affiliate revenues, which are part of the revenue offsets included in

revenue requirement:

685 Exhibit 22742-X0725, AET final argument, paragraphs 169-170, PDF pages 57-58. 686 Exhibit 22742-X0725, AET final argument, paragraphs 182, PDF pages 61. 687 Exhibit 22742-X0725, AET final argument, paragraphs 171-173, PDF pages 58-59. 688 Exhibit 22742-X0725, AET final argument, paragraphs 177-178, PDF pages 59-60.


Decision 22742-D01-2019 (July 4, 2019) 167

Table 51. Historical comparison of forecast and actual affiliate revenues

Description

2015 2016 2017 Test period

approved actual approved actual approved actual 2018 2019

Affiliate revenue ($ million)

Alberta PowerLine 5.1 9.9 10.2 13.8 11.3 19.8 2.6 2.4

ATCO Power 10.5 9.8 2.9 10.8 0.4 7.6 2.2 2.4

ATCO Energy Solutions 9.7 7.9 0.4 0.9 0.4 0.4 0.0 0.0

ATCO Structures & Logistics 0.0 0.0 0.0 0.0 0.0 0.6 0.0 0.0

ATCO Electric Distribution 2.7 1.4 2.7 1.2 2.7 1.2 1.3 1.3

ATCO Gas 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

ATCO Electric Yukon 0.0 0.1 0.1 0.0 0.0 0.3 0.2 0.2

Northland Utilities (NWT) 0.1 0.0 0.1 0.1 0.1 0.1 0.1 0.1

Northland Utilities (Yellowknife)

0.0 0.1 0.0 0.0 0.0 0.2 0.1 0.1

Other 0.0 0.0 0.0 0.0 0.0 0.4 0.0 0.0

Total affiliate revenue 28.1 29.3 16.5 27.1 15.0 30.7 6.7 6.7

Source: Based on Proceeding 20272, exhibits 20272-X1101 and 22742-X0002.04 Schedule 8-1 Transmission Revenue Offsets, and Exhibit 22742-X0288, IR response AET-CCA-2017AUG30-060, Attachment 1.

753. While the CCA argued that forecast accuracy of affiliate revenue was low and required

adjustments to approach historical levels, AET countered that adjusting these forecasts to

historical levels was not supported. In addition, AET confirmed that a large part of the variance

between forecast and actual affiliate services is due to contracted services, which are not

forecast.

754. The Commission observes that not only do the forecast and actual service levels provided

to affiliates vary significantly, but a comparison of year-over-year actuals shows that revenues

associated with the services provided by AET to a particular affiliate can also vary significantly.

For this reason, the Commission considers that the adjustments proposed by the CCA based on

historical levels are unsupported. The Commission, therefore, rejects the CCA’s recommended

adjustments to affiliate revenue.

755. In its rebuttal evidence, AET identified an update related to forecast affiliate services for

Alberta PowerLine which had been missed in its September 4, 2018 application update. It

proposed to incorporate forecast updates of revenue offsets for Alberta PowerLine increasing

from $2.6 million and $2.4 million, to $4.1 million and $4.6 million, in 2018 and 2019,

respectively, as part of the GTA compliance filing.

756. The Commission finds AET’s proposal to incorporate the Alberta PowerLine forecast

update as part of the GTA compliance filing to be reasonable. The Commission directs AET to

reflect all impacts related to the Alberta PowerLine forecast update in the GTA compliance filing

arising from the determinations in this decision. The Commission understands that this update

will include charges based upon the new 23 per cent overhead rate. In light of the Commission

findings below regarding overhead rates, AET is directed to treat these updates as placeholders

and to submit forecasts of Alberta PowerLine’s affiliate services with the historical overhead rate

of 30 per cent for O&M and 60 per cent for construction projects in its compliance filing to this

decision.


Decision 22742-D01-2019 (July 4, 2019) 168

757. The Commission acknowledges the concern raised by the CCA that changes between

forecast and actual levels of affiliate services provided by AET could change the allocations of

internal labour required to provide those services. If AET forecasts O&M activities based on a

higher level of internal labour than is actually required or used, because those O&M labour

dollars are redirected to provide a higher level of affiliate services than were forecast, the

revenue requirement includes forecast labour dollars paid by AET ratepayers but potentially

without the AET O&M work being completed. In such case, the unused O&M labour dollars

flow to utility earnings. Further, if the O&M work included in the revenue requirement forecast

is not completed in the year forecast, it would not be fair to AET ratepayers to have some portion

of this work forecast in subsequent test years, because ratepayers would then be paying for the

same work twice.

758. AET argued that forecast affiliate work is not related to forecast O&M work, so changes

to the level of required affiliate work would not change the level of O&M activity. In addition,

AET stated it would complete the forecast O&M work using other resources, including capital

employees or contractors. In the Commission's view, this is not a complete answer to the concern

being raised. The issue remains that when the level of services that AET provides to affiliates is

higher than forecast, AET labour is displaced. This, in turn, affects the utility rather than the

affiliate receiving the services. The Commission considers that AET’s claim that there is no cost

to customers from providing affiliate services is only accurate to the extent one disregards

secondary effects (such as what happens to forecast AET work that is not completed because

labour resources had to be drawn from elsewhere to backfill AET’s internal labour that has been

re-assigned to provide higher than forecast services to affiliates). To some extent, AET’s

workforce expands or contracts based on increasing levels of service provided to its affiliates,

but if a shortfall of internal labour arises for AET when providing those services, it appears that

it is AET that must redirect capital employee resources to O&M activities, or hire external

contractors rather than the affiliate or affiliates in question having to do so for themselves.

759. The Commission requires additional information to evaluate the impacts on AET’s O&M

and capital that result from AET providing fluctuating levels of services to its affiliates. If the

affiliates engaged external contractors to provide the services currently provided by AET, the

impact on AET would be limited to the availability of contractors for AET work, or potentially

higher cost O&M activities, if the resources used to backfill are not at the same cost as internal

labour.

760. For this reason, the Commission directs AET to provide the following information as part

of all future GTAs where there is a variance of $0.5 million or more between forecast and actual

affiliate revenues, for any affiliate receiving services from AET:

(a) The forecast, actual and variance amounts for affiliate revenues, broken down by:

(i) AET internal labour

(ii) Fringe benefits on internal labour

(iii) Overhead loading on AET labour-related costs

(iv) Flow-through costs

(b) For the variance in AET internal labour taken from part (a) above, identify each

group that contributed to the internal labour variance, whether the variance amount


Decision 22742-D01-2019 (July 4, 2019) 169

was for O&M or capital-related activities, and, for each variance amount, the dollar

amount and number of FTEs involved.

(c) For each group identified in part (b) above, confirm whether the work related to the

observed variance was backfilled, and provide an explanation of how and when this

was done.

761. Further, the ATCO Inter-Affiliate Code of Conduct requires the charging of “fully

burdened costs of such personnel for the time period they are used by the Affiliate, including

salary, benefits, vacation, materials, disbursements and all applicable overheads”689 for affiliate

services provided on a “cost recovery basis.”

762. In its application, AET provided its review of the affiliate overhead burden rate, in

response to Direction 47 of Decision 20272-D01-2016. The Commission finds that AET has

sufficiently responded to the direction by providing its review, however, as shown in the table

below, a comparison of overhead rates from historical actuals through the successive updates

filed in the current proceeding shows significant change, even during the course of this

proceeding.

Table 52. Historical comparison of overhead recovery rates for affiliate services

2015

actual 2016

actual 2017

forecast

2018 and 2019 test years original

2018 and 2019 test years revised

(%)

Overhead rate 40 30 30 30 23

Additional overhead rate on construction projects

30 30 30 30 0

Total overhead rate on construction projects

70 60 60 60 23

Source: Based on exhibits 22742-X0001 and 22742-X0001.02, Section 31 Affiliate Overhead Rate Review.

763. None of the intervening parties provided argument on overhead recovery for affiliates.

764. The Commission observes that the most recent update to AET’s response to Direction 47

proposes a significant change to the affiliate overhead rate. The Commission needs to satisfy

itself that the cost recovery required by the Affiliate Code of Conduct is fully met. The

Commission notes that the information filed by AET in its review of the affiliate overhead rate

includes limited supporting detail.

765. In an IR response, AET provided the following explanation for the change in the

overhead rate from 30 per cent/60 per cent to 23 per cent:690

As part of an overall review of the components within the overhead calculation, costs that

have been previously identified as support or an overhead cost, mainly salaries and wages

for groups such as engineering, construction, planning and operations were removed from

the calculation of the overhead rate. The reason for the removal of the costs is that any

involvement from these types of groups to provide services to a third-party or affiliate is

689 Decision 2003-040: ATCO Group, Affiliate Transactions and Code of Conduct Proceeding, Part B: Code of

Conduct, Application 1237673-1, May 22, 2003, Definitions, page 3. 690 Exhibit 22742-X0570, AET-CCA-2018OCT05-009, PDF pages 60-61.


Decision 22742-D01-2019 (July 4, 2019) 170

directly charged and is thus not also appropriately included again as a support or indirect

cost, that the overhead rate captures. For example, an engineer working on an affiliate

project directly charges one hour of labour to this project. On this hour of direct charged

engineering labour, fringe benefits are applied at a rate of 24% and overhead is applied at

a rate of 23%. From this simple example, it is clear that it is not necessary to include

engineering as a component of the overhead charge because engineering labour has been

directly charged to the project.

To be clear, the methodology employed to calculate the overhead rate has not changed,

rather the review focused on the components within the overhead calculation. The

overall revenue requirement impact is forecast to be approximately $0.1 million for 2018

and 2019, respectively.

766. The Commission notes that in the same IR response, AET stated that it has been applying

the 23 per cent affiliate overhead rate since January 1, 2018. The Commission considers that

AET’s use of its proposed affiliate overhead rate prior to approval for the test years is premature.

For this reason, the proposed affiliate overhead rate of 23 per cent used for 2018 and 2019 shall

be considered as a placeholder until the Commission renders its determination on the matter in

the compliance filing to this decision.

767. The Commission requires additional information to determine whether the significant

reduction to the affiliate overhead rate, along with the direct charging of costs by groups

providing services to AET affiliates, will result in the recovery of fully burdened costs for

personnel involved.

768. For this reason, the Commission directs AET, as part of its compliance filing, to provide

the following information:

(a) An expanded affiliate overhead schedule which adds columns to the current

information shown on the Transmission Overhead Rate schedule691 for each of the

2017 forecast, 2018 actuals, and 2018 and 2019 forecasts taken from the original

GTA application in this proceeding to facilitate comparison.

(b) A schedule that provides a detailed analysis of the affiliate overhead recovery

which compares the increased direct charging and the lower affiliate overhead rate

compared to the use of the previous overhead recovery rate. This comparison shall

identify individually each of the groups involved, and list each of the services that

each group is providing.

769. AET’s accounting policy for provision of services to or receipt of services from affiliates,

states that the overhead rate to be applied to labour charges is as follows:

For non-construction projects an Overhead rate of 30% will be applied to labour charges,

including payroll burden where applicable as defined above. An additional Overhead

rate of 30% will be applied to the labour charges including payroll burden for

construction projects.692

691 Exhibit 22742-X0001.02, updated application, Section 31, Transmission Overhead Rate, Attachment 31.6,

PDF page 1336. 692 Exhibit 22742-X0001.02, updated application, Section 31, Attachment 31.2, PDF page 1193.


Decision 22742-D01-2019 (July 4, 2019) 171

770. The Commission directs AET to provide an updated accounting policy for provision of

services to or receipt of services from affiliates that reflects the outcome of the Commission’s

decision on overhead rates in its compliance filing to this decision.

18 Order

771. It is hereby ordered that:

(1) ATCO Electric Ltd. shall file its 2018-2019 transmission general tariff application

compliance filing by August 8, 2019, to reflect the findings, conclusions and

directions in this decision.

Dated on July 4, 2019.


(original signed by)

Bohdan (Don) Romaniuk

Acting Commission Member


Kristi Sebalj

Commission Member


Bill Lyttle

Acting Commission Member


Decision 22742-D01-2019 (July 4, 2019) 172

Appendix 1 – Proceeding participants

Name of organization (abbreviation) Company name of counsel or representative

ATCO Electric Ltd. – Transmission (AET)

Bennett Jones LLP

AltaLink Management Ltd. (AltaLink or AML)


Brownlee LLP Consumers’ Coalition Of Alberta (CCA)

Industrial Power Consumers Association of Alberta (IPCAA)

Alberta Direct Connect Consumers Association (ADC)

Direct Energy Marketing Limited

Alberta Utilities Commission Commission panel B. Romaniuk, Acting Commission Member K. Sebalj, Commission Member B. Lyttle, Acting Commission Member Commission staff

A. Sabo (Commission counsel) D. Cherniwchan L. Mullen C. Strasser J. Cameron D. Ward A. Starkov

http://efiling.auc.ab.ca/Proceeding22742/SitePages/ViewIndividualRegisteredPartiesWebPart.aspx?RegisteredPartyID=64469

http://efiling.auc.ab.ca/Proceeding22742/SitePages/ViewIndividualRegisteredPartiesWebPart.aspx?RegisteredPartyID=64485


Decision 22742-D01-2019 (July 4, 2019) 173

Appendix 2 – Oral hearing – registered appearances

Name of organization (abbreviation) Name of counsel or representative

Witnesses

ATCO Electric Ltd. – Transmission (AET)

L. Keough D. Sheehan

Main panel: P. Goguen P. Bothwell H. Goode D. Hoshowski R. Itiveh K. Moledina N. Palladino Compensation panel: P. Goguen K. Yung N. Palladino

Consumers’ Coalition of Alberta (CCA)

J. Wachowich, QC R. Lee

D. Madsen D. Levson


T. Marriott, QC K. Rutherford

R. Bell

Alberta Utilities Commission Commission panel B. Romaniuk, Acting Commission Member K. Sebalj, Commission Member B. Lyttle, Acting Commission Member Commission staff

A. Sabo (Commission counsel) J. Graham (Commission counsel) D. Cherniwchan L. Mullen C. Strasser J. Cameron D. Ward


Decision 22742-D01-2019 (July 4, 2019) 174

Appendix 3 – Summary of rulings and procedural requests

(return to text)

The following is a summary of rulings and procedural requests addressed during the proceeding:

1. August 2, 2017: The Commission granted the CCA’s request for AET to update certain

placeholders in its GTA, such as common group allocators and pension cost-of-living

allowances, to reflect the Commission’s determinations in other decisions. The Commission

directed AET to submit an omissions and updates (O&U) filing to reflect the CCA’s requested

updates, responses to IRs and any other new information that was available. The Commission

also granted the UCA’s request for an extension of the deadline for filing IRs. Exhibit 22742-

X0187.

2. September 22, 2017: The Commission granted AET’s request for an extension of the

deadline for filing responses to IRs, and the submission of its O&U filing, both of which were

due on the same day. Exhibit 22742-X0198.

3. October 20, 2017: The Commission granted, in part, AET’s motion requesting that the

Commission not require AET to respond to certain IRs. The Commission granted full or partial

relief requested for certain IRs related to O&M balances, organization information by employee

position, vegetation management and monthly depreciation data. Exhibits 22742-X0225 and

22742-X0226.

4. October 30, 2017: The Commission granted AET’s request for an extension of the

deadline for filing responses to IRs and for the submission of its O&U filing, both of which were

due on the same day. Exhibit 22742-X0228.

5. February 2, 2018: The Commission granted AET’s request for confidential treatment of

certain responses to IRs. Exhibit 22742-X0355.

6. May 2, 2018: The Commission granted, in part, a CCA motion to compel AET to provide

full and complete IR responses to a number of CCA IRs. Exhibits 22742-X0385 and 22742-

X0386.

7. June 11, 2018: The Commission granted AET’s request for confidential treatment of

additional responses to certain IRs. Exhibits 22742-X0414 and 22742-X0415.

8. June 11, 2018: The Commission ruled on the CCA’s request for a schedule adjustment

and a revised process schedule. The Commission granted a one-week delay and updated the

proceeding schedule accordingly. Exhibit 22742-X0416.

9. July 31, 2018: The Commission granted, in part, a CCA and UCA motion to compel AET

to provide full and complete IR responses to a number of IRs. Furthermore, the Commission

directed AET to provide full and complete responses to some of the Commission’s IRs.

Exhibits 22742-X0500, 22742-X0501 and 22742-X0502.

10. September 14, 2018: The Commission granted the CCA and the UCA requests for a third

round of IRs on AET’s September 2018 application update. Exhibit 22742-X0542.


Decision 22742-D01-2019 (July 4, 2019) 175

11. October 22, 2018: The Commission granted AET’s request for an extension of the

deadline for filing responses to IRs. Exhibit 22742-X0552.

12. November 8, 2018: The Commission issued a temporary suspension of the process

schedule pending a ruling on AET’s motion requesting that the Commission not require AET to

respond to certain IRs. Exhibit 22742-X0584.

13. November 14, 2018: The Commission granted, in part, AET’s motion requesting that the

Commission not require it to respond to Round 3 IRs. The Commission did not require AET to

respond to three IRs, required it to respond to three IRs, and required it to provide alternative

information to five IRs. The Commission denied the CCA’s request for the Commission to

require AET to provide further updates to the September 2018 application update.

Exhibits 22742-X0585 and 22742-X0586.

14. November 30, 2018: The Commission granted the CCA’s request for an extension of the

deadline for filing of intervener evidence and for filing IRs on intervener evidence.

Exhibit 22742-X0590.


Decision 22742-D01-2019 (July 4, 2019) 176

Appendix 4 – Summary of Commission directions addressed in application

(return to text)

This section is provided for the convenience of readers and outlines the directions from Decision

20272-D01-2016 (ATCO Electric Ltd. 2015-2017 Transmission GTA) that the Commission

finds have been satisfied. Directions not in this appendix are either set out in the following

Appendix 5 as outstanding or have been maintained as new directions. In the event of any

difference between the directions in this section and those in the main body of Decision 20272-

D01-2016, the wording in the main body of Decision 20272-D01-2016 shall prevail.

47. For the above reasons, the Commission considers that affiliate overhead rates should be

examined as part of the next GTA proceeding to determine whether they are adequate.

The Commission directs ATCO Electric to provide a detailed assessment of affiliate

overhead burden rates comparing the current rates applied and their supporting basis, to

the forecast effective rate that results from forecast overhead costs and related forecast

activity levels. An examination of five years of historical information shall be

incorporated for comparison purposes. .......................................................... Paragraph 713

71. Given the lack of business case support provided by the utility in its application, the

Commission is not prepared to approve any of the expenditures forecast for the double

circuit project in the test period and directs ATCO Electric to remove the expenditures

from its current forecast. ATCO Electric is directed to submit a business case with the

requested level of detail in its next GTA. .................................................... Paragraph 1112

73. Given ATCO Electric’s description of asset management in the business case for project

82660 and how it should integrate with MAXIMO, CROW, Oracle, MOPS and GIS

information systems, the Commission is of the view that a comprehensive business case

treating all these components as a single project is required. This business case should

itemize all the work required, including any necessary enhancements or upgrades to the

various IT systems on an historical and go-forward basis. This business case should also

provide a cost/benefit analysis with a clear description of future cost requirements

including as much of the life cycle as can reasonably be anticipated. ATCO Electric is

directed to provide such a business case in its next GTA. ........................... Paragraph 1156

84. For the above reasons, the Commission directs ATCO Electric to prepare and file an

updated comprehensive lead/lag study as part of its next GTA application.

...................................................................................................................... Paragraph 1231

97 For these reasons, the Commission is not persuaded that the RPG’s request is reasonable

in the circumstances. However, it directs ATCO Electric to provide the following

information as part of all future GTA proceedings:

Complete descriptions of all sales or transfers of ATCO Electric transmission

assets occurring in the period covering actual information filed for comparison

use to the test years. Information regarding identified transactions must include a

description of the assets involved, a statement of the transaction value including

confirmation of whether and (if applicable) how fair market value pricing was

determined (including copies of all valuation reports relied upon).

Identification of all asset transactions between ATCO Electric and an affiliate, for

each comparison year of actuals or any portion thereof. For example, in the


Decision 22742-D01-2019 (July 4, 2019) 177

current 2015-2017 proceeding, 2012 through 2014 actuals were provided for

comparative purposes. In addition, the 2015 test year forecast included a portion

of 2015 YTD actuals. For this example, information should be provided for 2012

through 2015 YTD actuals. ............................................................. Paragraph 1385

Other Matters:

9. …The Commission, however, is concerned that certain information is excluded because a

project’s capital expenditures in the test period are less than $5.0 million. The

Commission considers that the $5.0 million threshold should apply to the estimated total

project cost, not the forecast costs in the test period, and that this guideline be strictly

adhered to in all subsequent submissions. ..................................................... Paragraph 851

This section is provided for the convenience of readers and outlines the direction from Decision

21206-D01-2017 (ATCO Electric 2013 and 2014 Transmission Deferral Accounts and Annual

Filings) that the Commission finds has been satisfied. Directions not in this appendix are either

set out in the following Appendix 5 as outstanding or have been maintained as new directions. In

the event of any difference between the direction in this section and that in the main body of

Decision 21206-D01-2017, the wording in the main body of Decision 21206-D01-2017 shall

prevail.

16. However, the Commission is concerned that there may be second order impacts to the tax

method used by ATCO Electric. ATCO Electric’s rebuttal evidence shows an entry at

line 50 that is not clear as to whether there is a second order impact on future income

taxes. Therefore, the Commission directs that this issue be addressed in ATCO Electric’s

next GTA, specifically Proceeding 22742. .................................................... Paragraph 470


22860-D01-2018 (ATCO Electric 2015-2017 Transmission GTA Second Compliance Filing)

that the Commission finds has been satisfied. Directions not in this appendix are either set out in

the following Appendix 5 as outstanding or have been maintained as new directions. In the event

of any difference between the direction in this section and that in the main body of Decision

22860-D01-2018, the wording in the main body of Decision 22860-D01-2018 shall prevail.

1. It appears to the Commission that the average base salary (total labour dollar per FTE)

method used by ATCO Electric to adjust O&M labour dollars, as a result of changes in

O&M FTEs, differs from how ATCO Electric may be forecasting labour dollars for

O&M FTEs in its GTA. As shown in Table 3, the amounts for labour dollar per O&M

FTE and total labour dollar per FTE are not the same. Therefore, to ensure that neither

ATCO Electric nor its customers are unjustly advantaged or disadvantaged by any

variance between the forecasted labour dollar for an O&M FTE and the use of the

average base salary when O&M FTE adjustments are required, ATCO Electric is directed

in all future applications to use the amounts included in its GTA forecast for each FTE

position when calculating the dollar impacts to FTE adjustments, unless specifically

directed otherwise by the Commission. .........................................................Paragraph 25


Decision 22742-D01-2019 (July 4, 2019) 178


22859-D01-2018 (ATCO Electric Transmission Common Group Compliance Filing) that the

Commission finds has been satisfied. Directions not in this appendix are either set out in the

following Appendix 5 as outstanding or have been maintained as new directions. In the event of

any difference between the direction in this section and that in the main body of Decision 22859-

D01-2018, the wording in the main body of Decision 22859-D01-2018 shall prevail.

1. As noted above, the Commission did not find credible ATCO Electric - Transmission’s

explanation that it could not reconcile its updated placeholder amounts to the requested

common group compliance filing amounts. In this regard, ATCO Electric has not met its

onus. The limited information detailing the substantive adjustments that occurred in

creating and supporting the entire pool of “common group” FTEs and costs is inadequate

in justifying the portion of costs allocated to ATCO Electric’s transmission function. The

Commission acknowledges that ATCO Electric - Distribution is under performance-

based regulation (PBR) and is only subject to minimum filing requirement (MFR)

schedules. However, further information about common costs is required in future GTAs

to support the costs allocated to ATCO Electric - Transmission. ATCO Electric Ltd. is

directed, on a go-forward basis, to provide all cost-information for every ATCO affiliate,

comprising the total costs and supporting detail, that substantiate and justify the costs

allocated to, or from, ATCO Electric’s transmission function. ....................... Paragraph 49


Decision 22742-D01-2019 (July 4, 2019) 179

Appendix 5 – Summary of Commission directions to be addressed in future applications

(return to text)

This section is provided for the convenience of readers and outlines the directions from

Decision 20272-D01-2016 that the Commission considers remain outstanding. Directions not

listed in this appendix are either listed in the preceding Appendix 4 as completed or maintained

as new directions. In the event of any difference between the directions in this section and those

in the main body of Decision 20272-D01-2016, the wording in the main body of the relevant

decision shall prevail.

Decision 20272-D01-2016

18. On the basis of the foregoing, the Commission denies ATCO Electric’s proposed use of

forecast information in its actuarial database for the purpose of developing depreciation

parameters and directs ATCO Electric in its next depreciation study to revert to its

currently approved methodology which provides for the use of forecast capital additions

solely for the purpose of determining depreciation rates. .............................. Paragraph 400

21. On that basis, ATCO Electric is directed to identify and create a subaccount category for

any USA account that now includes, and in the future will include, assets constructed to

comply with ISO Rule 502.2, including any assets or capital projects constructed before

the ISO rule came into effect, where projects have been constructed under the assumption

that ISO Rule 502.2 would be adopted. ATCO Electric is directed to comply with this

finding at the time of its next depreciation study. .......................................... Paragraph 424

27. At the same time, the Commission wishes to obtain a better understanding of why ATCO

Electric’s costs of retirement for this account appear to significantly exceed that of

industry peers and considers it would be in the public interest and of considerable benefit

to the Commission for ATCO Electric to include a detailed explanation for this in its next

depreciation study. ATCO Electric is directed to provide the noted explanation in its next

depreciation study. ......................................................................................... Paragraph 551


Decision 22742-D01-2019 (July 4, 2019) 180

Appendix 6 – Transcript, Volume 2, 2019-01-22 - Ruling on CCA request to mark two

exhibits

(return to text)

Appendix 6 -

Transcript Volume 2 2019-01-22 Ruling on CCA request to mark two exhibits

(consists of 7 pages)


Decision 22742-D01-2019 (July 4, 2019) 181

Appendix 7 – 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. For the above reasons, the Commission finds that AET has failed to justify its requested

FTEs and associated dollar amounts in the test years. Based on the past FTE forecasts

noted above and the inability of AET to accurately track FTEs by cost centre through

various organizational changes, including the new shared services initiative, the

Commission cannot reasonably rely on the FTE forecasts filed by AET. The

Commission, therefore, directs AET to use its 2018 actual FTEs as the approved FTE

complement for 2018. The 2018 FTEs are approved as the opening 2019 FTE

complement. The Commission notes that the direction for 2018 is consistent with AET’s

Rule 005 reporting, which reflected 716.1 FTEs in 2018. ............................... paragraph 53

2. For the purposes of this decision and the compliance filing to follow, the Commission

directs AET not to offset the impacts of the reduction to capital FTEs with an increase in

contractor costs. ............................................................................................... paragraph 54

3. Given that the Commission’s direction to reduce AET’s FTE forecast in 2019 is not a

reduction to specific identifiable positions, AET is directed to calculate the impact of its

O&M FTE reductions using the average O&M salary per FTE and its capital FTE

reductions using the average capital salary per FTE. ...................................... paragraph 56

4. In its compliance filing to this decision, AET is directed to confirm, for the positions it

has forecast to eliminate in 2019, that they have been removed in accordance with the

findings and directions in this section, using the mid-year convention. .......... paragraph 58

5. For the above reasons, AET is directed to provide in its compliance filing a recalculation

of its 2018 severance costs based on the proportion of years of service each severed

position provided to the transmission function, as identified in Exhibit 22742-X0698.

.......................................................................................................................... paragraph 90

6. For the above reasons, AET is directed to incorporate out-of-scope inflation rates of

2.65 per cent for 2018 and 2.0 per cent for 2019 in its compliance filing to this decision.

........................................................................................................................ paragraph 120

7. For confirmation purposes, AET is directed to demonstrate in its compliance filing, with

calculations, that it has prorated its out-of-scope labour inflation to reflect increases

awarded on April 1 of each year. ................................................................... paragraph 122

8. In light of the evidence and testimony on the record, AET’s VPP forecasts are approved

at 80 per cent of the eligible employee payout amounts. This determination is consistent

with the Commission’s previous VPP approval in Decision 20272-D01-2016. In its

compliance filing to this decision, AET is directed to reflect the Commission’s findings

and directions regarding VPP, including those findings with respect to FTEs and labour

inflation rates, which affect eligible employee payout amounts. In implementing this

direction, AET is to take into account the mechanics of the reserve account detailed in

Section 5.2.2.3 Treatment of VPP reserve account balance below. ............. paragraph 156


Decision 22742-D01-2019 (July 4, 2019) 182

9. The Commission has denied AET’s request to amend the mechanics of the VPP reserve

account to be symmetrical in nature, as detailed above. The Commission also agrees with

the CCA that the VPP reserve account balance should be targeted to be as close to zero

by the end of the GTA test periods as possible. The Commission notes in this regard, that

there is no benefit to AET shareholders, ratepayers or employees in maintaining a

positive balance in the VPP reserve account as any positive balance is designated as zero

cost capital. On the other hand, requiring ratepayers to provide VPP funds projected to be

spent, but that may not be spent not only for a period of one or more years after those

VPP funds are collected, but for one or more successive test periods, is prima facie

harmful to customers. In its compliance filing AET is directed to provide options on how

it could best operate the VPP reserve account to avoid an increasing accumulated balance

i.e., the VPP reserve account balance should trend as close to zero as possible ..................

........................................................................................................................ paragraph 160

10. However, the Commission notes that the Alberta provincial government repealed the

carbon tax effective June 4, 2019. The Commission takes notice of this repeal and directs

AET, in its compliance filing to this decision, to remove the effects of the repeal of the

carbon tax from its fuel cost forecast for the months in 2019 that are affected by this

legislative change. The Commission accepts AET’s 2018 fuel cost forecast, as filed in its

updated application. ....................................................................................... paragraph 176

11. Given the uncertainty with SRB costs, the Commission denies AET’s request to

discontinue the existing deferral account for annual structure payments. AET is directed

to reflect, in its compliance filing to this decision, the $200,000 reduction for the 2018

test year. The Commission also accepts the CCA arguments regarding the 2019 forecast

and directs AET to reduce the 2019 forecast by $200,000. ........................... paragraph 205

12. The Commission directs AET to maintain its reserve for vegetation management. As

noted by the CCA, the variance for 2015 was limited because the Commission accepted

actual results rather than forecasts for that year. ............................................ paragraph 209

13. AET’s statement shows that the vegetation management reserve account has supported

stability and AET’s management of its forecast costs. As a result, there is merit in

maintaining this reserve account. The Commission finds that the reserve account should

be continued and therefore directs AET to maintain the use of the vegetation management

reserve account............................................................................................... paragraph 211

14. The Commission shares some of the concerns expressed by the CCA regarding the level

of vegetation management costs. However, the Commission does not agree with the CCA

that a 25 per cent reduction in 2018-2019 vegetation management expenditures is

reasonable. For 2018, the Commission accepts the evidence of AET that 2018 actual

expenditures were tracking close to forecast and approves AET’s 2018 forecast. For

2019, the Commission agrees with the CCA that a reduction is warranted because there is

insufficient support that the forecast work for vegetation management must be completed

in 2019. Accordingly, the Commission directs that AET reduce the forecast vegetation

management costs for 2019 by 10 per cent in its compliance filing to this decision.

........................................................................................................................ paragraph 217

15. Further, the Commission directs AET to provide, in its next GTA, a detailed breakdown

of the savings and lower forecast expenses realized as a result of the transition by AET

from a primarily mechanically based vegetation management program to one that is

primarily based on the application of herbicides. .......................................... paragraph 218


Decision 22742-D01-2019 (July 4, 2019) 183

16. The Commission accepts the submission of AET that its forecast for expenses in this

account reflects a reduced number of IT users. However, the Commission directs AET to

adjust its forecast for this account based on the Commission’s determinations regarding

forecast FTEs in Section 5.1.1 of this decision. ............................................. paragraph 222

17. Further, on June 5, 2019, the Commission issued Decision 20514-D02-2019 regarding

the ATCO Utilities IT common matters proceeding. AET is directed to reflect any

changes arising from the directions in that decision in its compliance filing to this

decision. AET is further directed to provide schedules detailing how the determinations

from Decision 20514-D02-2019 are reflected in its compliance filing. ........ paragraph 223

18. The Commission has examined parties’ evidence with respect to the salvage

methodologies used by EPCOR and APL. While the Commission will make no change to

AET’s depreciation methodology or depreciation rates in this proceeding, the

Commission directs AET, as part of its next depreciation study, to compare AET’s

average service lives and net salvage percentages for its five largest plant accounts (on a

dollar amount basis) to those of other electric transmission utilities in the province.

........................................................................................................................ paragraph 231

19. In its forecast, AET used a 15 per cent tax rate for federal income taxes and a 12 per cent

tax rate for provincial income taxes for both 2018 and 2019. The Commission approves

the 2018 applied-for tax rate of 15 per cent for federal income tax and 12 per cent for

provincial income tax. The Alberta government, in Bill 3: Job Creation Tax Cut (Alberta

Corporate Tax Amendment) Act, reduced the general provincial corporate tax rate from

12 per cent to 11 per cent. Bill 3 came into force on June 28, 2019 and amends sections

21 and 22 of the Alberta Corporate Tax Act, changing the provincial tax rate as of July 1,

2019. The Commission takes notice of the Legislative Assembly of Alberta’s passing of

Bill 3 and directs AET, in its compliance filing, to adjust for any changes in its provincial

tax rate. .......................................................................................................... paragraph 264

20. In the CCA’s reply argument, it acknowledged that it had not reviewed AET’s method

for calculating AFUDC in its income taxes, and recommended that the Commission

allow for further review of AET’s accounting of AFUDC in its income taxes in the

compliance filing. The Commission sees merit in the CCA’s request. AET is directed to

demonstrate in its compliance filing to this decision, using the information that is

currently available on the record of this proceeding, that its treatment of AFUDC in its

calculation of income tax expense does not involve either of the two potential errors

described in paragraph 267 above.................................................................. paragraph 278

21. In its argument, AET stated that it has treated AFUDC similarly in the past. AET is

directed, in its compliance filing to this decision, to provide a proposal to correct any

prior AFUDC-related errors in its calculation of income taxes, which were subsequently

collected through revenue requirement in prior years. .................................. paragraph 279

22. The Commission, however, remains interested in a specific scenario raised by the Bema

witness during the oral hearing. The scenario deals with when an asset is placed into

utility service and the corresponding impact to the asset valuation used for property tax

purposes. Accordingly, AET is directed to explore the timing of the capitalization of its

assets as an acceptable method to potentially reduce the amount of property taxes it

would otherwise be required to pay, and to report, at the time of its next GTA, whether

such timing can or should be taken into account on a go-forward basis. ...... paragraph 317


Decision 22742-D01-2019 (July 4, 2019) 184

23. In its next GTA, however, AET is directed to file variance analyses reflecting the actual

expenditures, explanations for variance from forecast and the current status of projects

not completed. As previously directed in Decision 20272-D01-2016, AET is also

directed to file business cases, at the time of filing its next GTA, for projects with a

forecast value greater than $500,000 that are planned to be completed in the test period

but not forecast in the current application. ..................................................... paragraph 346

24. The Commission and interveners submitted numerous information requests to AET with

respect to these programs as well as the other forecast expenditures. The Commission

finds the evidence filed regarding AET’s forecast GP&E expenditures to be reasonable

and sufficient, and the proposed programs necessary. They are approved as filed. In its

next GTA, AET is directed to file variance analyses reflecting the actual capital

expenditures, explanations for variance from forecast and the current status of projects

not completed. ................................................................................................ paragraph 367

25. The Commission approves the necessary working capital test period forecasts as filed

subject to any adjustments that may be required based on the direction above. The

Commission directs AET, in the compliance filing, to reflect all findings and

determinations in this decision that affect the necessary working capital calculations.

........................................................................................................................ paragraph 520

26. The Commission notes that AET’s application relies on operating cost forecasts based on

the existing activity-based forecasting methodology. The shared services initiative has

not been fully implemented nor has AET requested that the Commission approve the new

methodology in the current proceeding. The Commission considers that further review of

the shared services initiative should be deferred to a future proceeding where it can be

thoroughly examined. The shared services initiative and approval of a new shared

services methodology was a live issue in the ATCO Pipelines’ proceeding (Proceeding

23793). In Decision 23793-D01-2019 issued on June 25, 2019, the Commission directed

ATCO Pipelines to coordinate with AET to ensure consistent information on the shared

services initiative in each of their next GRA and GTA, respectively. The Commission

went on to enumerate the nature of the information required, including the filing of cost

information for all ATCO affiliates to substantiate the costs allocated to all regulated

ATCO entities. The Commission in the current proceeding similarly directs AET to

coordinate with ATCO Pipelines to ensure that both utilities provide the same or

substantially similar information in the same format in support of the shared services in

their next respective GRA and GTA, preferably filing common documents wherever

possible. The information should include evidence supporting the functions created,

justifying total FTEs and costs before allocation to the participating ATCO companies

(AET and all other regulated and non-regulated ATCO entities), and include any analysis,

studies and calculations that explain and support the reasonableness and accuracy of the

allocation methodologies. The Commission finds that it would also be beneficial to show

all calculations that demonstrate the split between O&M and capital under the shared

services initiative in the next GRA and GTA. This common information will allow for a

proper testing of the shared services and for the provision of company specific

information to support shared services costs included in the proposed revenue

requirements. Accordingly, the Commission directs AET to provide the evidence,

analyses, studies and calculations noted above as well as any underlying assumptions for

the split between O&M and capital in its next GTA. ................................... paragraph 540


Decision 22742-D01-2019 (July 4, 2019) 185

27. The Commission acknowledges that of the ATCO companies, AED and ATCO Gas are

under performance-based regulation and are subject only to minimum filing requirement

schedules. However, further information about common costs are required to support the

costs allocated to AET. As such, AET is directed, on a go-forward basis, to provide all

cost information for every ATCO affiliate, comprising the total costs and supporting

detail that substantiate and justify the costs allocated to AET relative to the other

regulated and non-regulated ATCO companies under the shared services initiative.

........................................................................................................................ paragraph 541

28. The Commission finds the arguments of the CCA to be more persuasive. The

Commission considers that it would be more consistent if deferral revenues were

included in the determination of the allocation factor and with AET’s treatment of

deferral revenues in Rule 005. In the Commission’s view, these deferral revenues can still

affect the revenue requirement of the entity, and the deferral revenues of direct assigned

capital are a function of, and reflect, the actual capital invested. Therefore, AET is

directed to include deferral account revenues in calculating net revenue for purposes of

the common cost group allocation methodology. .......................................... paragraph 569

29. On the question of whether CWIP should be included in PP&E for the purpose of

determining cost allocation, the Commission finds the arguments of AET to be more

persuasive. In the Commission’s view, including CWIP in PP&E more accurately reflects

the actual capital invested. The Commission also accepts that it is consistent with prior

practice. Therefore, AET is directed to continue to include CWIP in the net PP&E

allocator.......................................................................................................... paragraph 570

30. The Commission accepts AET’s explanation for the increase in fringe benefits given the

inflationary pressures on the specific cost items of CPP and employee benefit premiums.

With respect to the other employee benefits identified, however, it is not clear to the

Commission how a proposed increase of $0.7 million per year is justified, given that

FTEs are declining. For these reasons, the Commission approves a marginal increase of

$0.1 million and AET is directed to reduce its forecast spending on fringe and benefit

costs by $0.6 million for each of the test years and to reflect this reduction in its

compliance filing to this decision. ................................................................. paragraph 583

31. The Commission finds that the CCA’s proposed reduction for the general-other cost

category is excessive. The Commission, however, agrees with the CCA’s comments that

AET failed to justify or explain its proposed increases and some reduction is warranted.

As such, AET is directed to reduce its forecast general-other expenses by $0.4 million for

each of the test years and to reflect this reduction in its compliance filing. Bema

calculated the historical annual average cost for general-other expenses from 2013 to

2016 to be $0.4 million, and the Commission accepts that this calculation shows that

historical trend of $0.4 million per year provides a more reasonable forecast for general-

other expenses in the test years. ..................................................................... paragraph 584

32. The Commission accepts AET’s submission that its forecast expenses for this account

reflect fewer users and increased IT application expenses due to the move to a cloud-

based Oracle E-Business IT solution. However, the Commission directs AET to adjust its

forecast expenses for this account based on the Commission’s reduction in forecast FTEs

found elsewhere in this decision. ................................................................... paragraph 594

33. Further, on June 5, 2019, the Commission issued Decision 20514-D02-2019 in the ATCO

Utilities IT common matters proceeding. With respect to USA 934, AET is directed to


Decision 22742-D01-2019 (July 4, 2019) 186

reflect any changes arising from the directions in that decision in its compliance filing to

this decision. AET is further directed to provide schedules detailing how the

determinations in Decision 20514-D02-2019 are reflected in the compliance filing to this

decision. ......................................................................................................... paragraph 595

34. The Commission is not convinced that the unique circumstances of Alberta PowerLine

require an adjustment to the allocation formula which has been consistently used in

AET’s GTAs. The use of the second year audited data in the allocation formula promotes

consistency, data reliability and avoids forecasting error. For these reasons, the

Commission directs that head office cost allocations continue to be calculated based on

the actual, audited financial data of the second year preceding the first test year of the

GTA. .............................................................................................................. paragraph 616

35. With respect to the second question, the development of a proxy for direct labour, the

Commission considers that some amount should be attributed to Alberta PowerLine. The

Commission considers it unreasonable that Alberta PowerLine should be able to avoid an

allocation of costs based on this factor solely because its labour billings from AET are

recorded as contractor costs. Alberta PowerLine clearly requires labour and that labour is

being supplied by AET. AET is therefore directed to propose, in its compliance filing, a

proxy for labour, including its rationale and calculations, that will be used in the head

office cost allocation calculation to account for Alberta PowerLine. ............ paragraph 617

36. In considering the evidence on the record with respect to the lease rate to be allowed for

the test period, the Commission concurs with the CCA that allowing a lease rate of

$20.00 per sq. ft. for both test years is reasonable. The Commission also considers that an

operating cost allowance of $16.00 per sq. ft. for 2018 is reasonable with an allowance of

$16.50 per sq. ft. for the 2019 test year. The $16.00 per sq. ft. approved for 2018 allows

for a reasonable inflationary increase over what AET states is the current estimate at

ATCO Centre of $15.27 per sq. ft. The $16.50 per sq. ft. approved for 2019 allows for an

inflationary increase over 2018. AET is directed to use these amounts in its compliance

filing for purposes of determining its revenue requirement. .......................... paragraph 668

37. For purposes of determining lease rates, AET is directed to provide, in its compliance

filing, evidence with respect to escalation rates that might be present in 10 year leases at

the time the ATCO Ltd. lease was signed in August 2017, and the Commission will

consider whether the approval of an escalator is warranted. The Commission’s

determinations with respect to the operating cost portion of the rental costs apply only to

the current test period..................................................................................... paragraph 669

38. Therefore, to adjust the number of employees used in the allocation of corporate staff,

and to ensure AET's regulated customers are not charged for the capacity of 100 staff

identified above, AET is directed to compute the square footage in its allocation of

corporate rent for ATCO Park on the basis of (260/600) x 21 per cent. The numerator is

the sum of head office employees and shared services employees identified in

Undertaking 52, adjusted for the seven per cent vacancy factor. The denominator of 600

is the total employee capacity of ATCO Park. The use of the total employee capacity as

the denominator will ensure that AET is not charged for the excess capacity that exists at

ATCO Park and would otherwise be charged if the actual occupancy of 459 were used.

........................................................................................................................ paragraph 680

39. The above adjustment corrects the charges to USA 930.2 for AET’s portion of corporate

head office lease costs. The Commission also notes that a similar adjustment should be


Decision 22742-D01-2019 (July 4, 2019) 187

made to USA 931.1 to correct the charges to AET for the 21 direct AET employees, plus

the adjustment for the seven per cent building vacancy rate, in ATCO Park. AET is

directed to make this adjustment in its compliance filing. ............................. paragraph 681

40. The Commission notes that IR response AET-CCA-2018OCT05-013(e) indicates that

AET is also charged for space occupied by corporate staff at other locations. In its

compliance filing, AET is directed to provide the calculations supporting these charges to

enable the Commission to verify that charges for corporate staff at other locations are

reasonable. ..................................................................................................... paragraph 682

41. Separate and apart from head office rental costs, the lease costs for the amount charged in

USA 931.1, for AET employees directly occupying corporate office space, are forecast to

be $1.5 million in each of the test years. While AET has identified that $1.4 million of

this is payable to Canadian Utilities Limited no breakdown has been provided as to the

facilities rented or how the forecast rent expense has been calculated. To ensure that the

Commission has a thorough understanding of how the forecast has been determined, AET

is directed in its compliance filing to identify the facilities leased and to provide the

calculations showing how the forecast of $1.5 million has been derived, and the

Commission will test these costs further in the compliance filing. ............... paragraph 683

42. There were no objections by interveners to AET’s forecast or its request to settle the RID

on an annual basis. The Commission notes the extended period required to process this

application and the availability of actual amounts for RID claims for the 2015-2017

period. The Commission has reviewed the RID claims included in attachments 29.2.1 to

29.2.3 to AET’s revised application, and finds the amounts to be reasonable. The

Commission accepts and approves AET’s forecast amounts of uninsured losses, with the

exception of those costs in respect of the Fort McMurray wildfire as noted in paragraph 3

of this decision. The Commission accepts AET’s proposal to settle the RID account

annually on a go-forward basis. AET is directed to reflect these changes in its compliance

filing to this application. ................................................................................ paragraph 688

43. For these reasons, the Commission considers that the debt rate deferral account should

continue to be used, but in this case, only for the 2019 test year. For 2018, the

Commission directs that the actual cost of debt be used. The amount to be recorded in the

2019 deferral account is to be determined by updating the approved “Schedule of Debt

Capital Employed and Embedded Cost” (Schedule 28-2) for 2019 to reflect the actual

weighted debenture rate for 2018; and updating the same schedule for 2019 to reflect the

actual weighted debenture rates for each of 2018 and 2019. The resulting embedded cost

of debt for the applicable year will then be used to update the “Schedule of Capital

Structure and Average Cost of Capital” (Schedule 28-1) for that year. This will result in

an updated return on long-term debt for that year. The difference between the updated

return on debt and the approved return on debt for that year will be the resulting balance

in the debenture rate deferral account for that year. ...................................... paragraph 734

44. Given the approval for the continued use of the debt rate deferral account for 2019, the

Commission needs to determine a reasonable forecast for the cost of debt to be used for

the second test year. As the actual cost of debt and the issue amount for AET’s 2018 debt

issuance is known, the Commission directs AET, in the compliance filing, to update its

application in all aspects to reflect the 2018 actual cost of debt resulting from the actual

2018 long-term debt issues. ........................................................................... paragraph 735


Decision 22742-D01-2019 (July 4, 2019) 188

45. While not in agreement with the CCA's proposed debt rate, the Commission finds AET's

forecast debt rate of 4.43 per cent to be high, particularly in light of its recent bond tender

at 3.95 per cent. The Commission directs AET to use 3.95 per cent as a forecast rate for

2019 long-term debt, especially since this forecast 2019 debt rate will be afforded

deferral account treatment. The Commission, therefore, approves a forecast 2019 debt

rate of 3.95 per cent and directs AET, in its compliance filing, to update its application in

all aspects to reflect the forecast long-term debt cost rates of 3.95 per cent for 2018 and

2019. .............................................................................................................. paragraph 737

46. The Commission finds AET’s proposal to incorporate the Alberta PowerLine forecast

update as part of the GTA compliance filing to be reasonable. The Commission directs

AET to reflect all impacts related to the Alberta PowerLine forecast update in the GTA

compliance filing arising from the determinations in this decision. The Commission

understands that this update will include charges based upon the new 23 per cent

overhead rate. In light of the Commission findings below regarding overhead rates, AET

is directed to treat these updates as placeholders and to submit forecasts of Alberta

PowerLine’s affiliate services with the historical overhead rate of 30 per cent for O&M

and 60 per cent for construction projects in its compliance filing to this decision.

........................................................................................................................ paragraph 756

47. For this reason, the Commission directs AET to provide the following information as part

of all future GTAs where there is a variance of $0.5 million or more between forecast and

actual affiliate revenues, for any affiliate receiving services from AET:

(a) The forecast, actual and variance amounts for affiliate revenues, broken down by:

(i) AET internal labour

(ii) Fringe benefits on internal labour

(iii) Overhead loading on AET labour-related costs

(iv) Flow-through costs

(b) For the variance in AET internal labour taken from part (a) above, identify each

group that contributed to the internal labour variance, whether the variance amount

was for O&M or capital-related activities, and, for each variance amount, the dollar

amount and number of FTEs involved.

(c) For each group identified in part (b) above, confirm whether the work related to the

observed variance was backfilled, and provide an explanation of how and when this

was done. ...............................................................................................paragraph 760

48. For this reason, the Commission directs AET, as part of its compliance filing, to provide

the following information:

(a) An expanded affiliate overhead schedule which adds columns to the current

information shown on the Transmission Overhead Rate schedule for each of the

2017 forecast, 2018 actuals, and 2018 and 2019 forecasts taken from the original

GTA application in this proceeding to facilitate comparison.

(b) A schedule that provides a detailed analysis of the affiliate overhead recovery

which compares the increased direct charging and the lower affiliate overhead rate

compared to the use of the previous overhead recovery rate. This comparison shall

identify individually each of the groups involved, and list each of the services that

each group is providing. ........................................................................paragraph 768


Decision 22742-D01-2019 (July 4, 2019) 189

49. The Commission directs AET to provide an updated accounting policy for provision of

services to or receipt of services from affiliates that reflects the outcome of the

Commission’s decision on overhead rates in its compliance filing to this decision.

........................................................................................................................ paragraph 770

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THE CHAIR: Sorry?

MR. WACHOWICH: Baseball start time was always

five minutes --

THE CHAIR: That's right. Good point.

MS. SABO: My apologies. Just one

announcement. Our staff is working on the webcast

issue. Our internet is down, and our Calgary office is

trying to reconcile that.

We hope it's back up, but if anyone has any

further issues, just let us know at baseball time

10:05.

THE CHAIR: Thanks, Ms. Sabo. We'll see

everybody in 30 minutes.

(ADJOURNMENT)

THE CHAIR: Our apologies for the delay. It

took a little longer than we had hoped or anticipated

to complete our ruling. Unless there are any

preliminary matters to be dealt with prior to our

ruling, I think I'll just proceed with reading into the

record our ruling on the dispute between the parties as

to the admissibility of CCA's first two aids to

cross-examination as exhibits. That's the issue,

whether they should be admitted as exhibits.

Here with the ruling. Yesterday the CCA requested

that three aids to cross-examination be added as

ATCO Electric Ltd.Appendix 6 - Transcript, Volume 2, 2019-01-22 - Ruling on CCA request to mark two exhibits

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Decision 22742-D01-2019 (July 4, 2019)

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exhibits on the record of this proceeding. The first

two of these aids to cross-examination are at issue

here. They are articles found on the internet relating

to variable pay. The first is titled "Make Way for

Variable Pay," and the second is titled "Employers

Offer Variable Pay and Benefits to Retain Employees."

ATCO Electric opposed the CCA's request for

several reasons and provided a January 29th, 2010,

ruling in Proceeding 226 for the ATCO Utilities pension

common matters application as support for its position.

ATCO submitted that the 2010 ruling demonstrated

that an aid to cross-examination put to a witness does

not become evidence to be marked on the record.

Rather, only witness responses to the aid to

cross-examination are evidence.

In response to ATCO Electric's objection to the

two aids to cross-examination, the CCA requested that

it be provided the opportunity to submit other rulings

that address the use of aids to cross-examination.

This morning the CCA has provided excerpts from

two transcripts: The first from Proceeding 22542,

AltaLink 2014-2015 DACDA proceeding, Volume 1,

September 13th, 2018, pages 181 to 184; the second from

Proceeding 22570, the 2018 GCOC proceeding, Volume 1,

March 12, 2018, pages 61 to 76.


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Decision 22742-D01-2019 (July 4, 2019)

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ATCO Electric also has provided the Panel with two

rulings, the first from the 2018 GCOC decision, being

Decision 22570-D01-2018, issued August 2, 2018, and the

second from Proceeding 22570, the 2018 GCOC proceeding,

Volume 1. And I think that's the Transcript Volume 1,

March 12, 2018, pages 101 to 104.

The test of admissibility of an aid to

cross-examination was adopted by the Commission in its

January 29th, 2010, proceeding -- sorry, was adopted by

the Commission on January 29th, 2010, in Proceeding 226

and can be summarized as follows.

An aid to cross-examination is a document that a

party may use or refer to while questioning a witness

about their evidence. An aid to cross-examination is

most effective if the witness being questioned has

contributed to its preparation, is familiar with its

contents, or can quickly verify the accuracy of the

contents.

Unless an aid to cross-examination is drawn

directly from the witness's direct evidence or

testimony, or prepared by that witness in another

context, or provides updated or supplementary

information to the witness's evidence, it is unfair to

require the witness to verify a substantial portion or

the entirety of the information contained in the aid.


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Decision 22742-D01-2019 (July 4, 2019)

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This test of admissibility is not intended to

exclude from consideration every potential aid to

cross-examination that does not fall squarely within

its four corners. For example, there's a difference

between being asked to, quote, "verify" close quote,

the content of an aid and being asked to comment on

that content or to adopt that content in whole or in

part as aligning with the witness's own views,

et cetera.

In addition, the Commission, being the master of

its own process, always retains the discretion to

include or exclude from the record of any proceeding

any disputed aid to cross-examination. As stated by

Sopinka, J, writing for the majority in Prassad v.

Canada (Minister of Employment and Immigration), held

as follows -- and I believe this is from paragraph 16

of the decision: (as read)

"We are dealing here with the powers of

an administrative tribunal in relation

to its procedures. As a general rule,

these tribunals are considered to be

masters in their own house. In the

absence of specific rules laid down by

statute or regulation, they control

their own procedures subject to the


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proviso that they comply with the rules

of fairness and where they exercise

judicial or quasi-judicial functions,

the rules of natural justice."

I'll omit the detailed citation here.

In the Commission's view, the principles governing

the admissibility of an aid to cross-examination are

relevance, probative value, and fairness.

In order for an aid to cross-examination to be

properly accepted on the record, counsel must be able to

demonstrate that: one, the document is relevant to the

matters at hand; two, the document is of probative value

to the decisions before the Commission; and three, the

manner in which the document is put to the witnesses is

fair.

Having said this, however, it is generally

preferable that, wherever possible, questions be put to

the witness or witnesses directly without using an aid

to cross-examination.

The Commission Panel's task here is to exercise its

discretion and evaluate ATCO's objections to the

disputed aids to cross-examination on the basis of their

relevance, probative value, and the fairness with which

they were put to the witnesses.

The Commission is also mindful of the timing issue


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related to late and extensive rebuttal evidence, which

is not the case in this proceeding, but that

circumstances could lead it to a more permissive

acceptance of aids in the interests of efficiency in

some instances.

The Commission has heard the witness's testimony in

respect of the two disputed aids to cross-examination.

The aids to cross-examination were provided at least 24

hours in advance in accordance with Section 39.1 of the

AUC Rules of Practice, and there was sufficient notice

to ATCO that each aid would be put to the witnesses.

This practice afforded fairness to the witnesses in

reviewing the documents.

The Commission reminds parties of the last passage

of paragraph 861 of the 2018 GCOC decision,

Decision 22570-D01-2018, and I quote: (as read)

"We strongly encourage parties to

revisit their planned use of aids to

cross in light of the guidance provided

and otherwise work amongst themselves

and have all the parties work amongst

themselves in an attempt to resolve some

of these matters."

The Panel notes in this regard that counsel for the CCA

provided ATCO Electric's counsel with sufficient notice


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for the parties to have identified and potentially

resolved questions regarding the admissibility of the

contested aids. Hearing time is limited and must be

used efficiently in both utility and ratepayer

interests.

With respect to the contested aids themselves, the

Commission observes that none of the witnesses authored

or contributed to the articles. The ATCO witnesses'

response to questions with respect to the first aid to

cross-examination related only very generally to

ATCO Electric's experience with its own VPP program.

With respect to the second document, only a single

paragraph of that document, the fifth paragraph, was

proffered to the witness for comment, and that same

paragraph was read into the record at Transcript

Volume 1, page 90, lines 10 to 20.

As such, the Commission does not consider there to

be probative value with respect to these two documents

beyond the witness testimony already provided on the

record. Therefore, the first two aids to

cross-examination will not be entered into the record as

exhibits.

That concludes this ruling.

MR. WACHOWICH: Thank you, Mr. Chairman.

Sir, the only remaining housekeeping matter I have


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Decision 22742-D01-2019 (July 4, 2019)

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ATCO Electric Ltd. - Home Alberta Utilities Commission · Alberta Utilities Commission Decision 22742-D01-2019 ATCO Electric Ltd. 2018-2019 Transmission General Tariff Application