Decision 2012-272 EPCOR Distribution & …...The Alberta Utilities Commission Decision 2012-272: EPCOR Distribution & Transmission Inc. 2012 Phase I and II Distribution Tariff 2012

Decision 2012-272

EPCOR Distribution & Transmission Inc.

2012 Phase I and II Distribution Tariff 2012 Transmission Facility Owner Tariff

October 5, 2012

The Alberta Utilities Commission

Decision 2012-272: EPCOR Distribution & Transmission Inc.

2012 Phase I and II Distribution Tariff

2012 Transmission Facility Owner Tariff

Application No. 1607944

Proceeding ID No. 1596

October 5, 2012

Published by


Fifth Avenue Place, Fourth Floor, 425 First Street S.W.

Calgary, Alberta

T2P 3L8

Telephone: 403-592-8845

Fax: 403-592-4406

Website: www.auc.ab.ca

http://www.auc.ab.ca/

AUC Decision 2012-272 (October 5, 2012) • i

Contents

1 Introduction ........................................................................................................................... 1

2 Compliance with previous directions .................................................................................. 4

3 Issues common to distribution and transmission ............................................................. 10 3.1 FTE forecasts ............................................................................................................... 10 3.2 Vacancy levels ............................................................................................................. 16 3.3 Salary escalations ......................................................................................................... 21 3.4 Cost escalations ............................................................................................................ 24 3.5 Short-term incentive program ...................................................................................... 25

3.6 Mid-term incentive program ........................................................................................ 28 3.7 Cost of debt .................................................................................................................. 30

3.7.1 The DBRS letter ................................................................................................ 31 3.7.2 Indicative corporate bond spread for EDTI ....................................................... 33 3.7.3 Government of Canada bond yield .................................................................... 34 3.7.4 Access to ACFA financing ................................................................................ 34

3.8 Property, business and linear tax deferral account ....................................................... 37

3.9 Self-insurance reserve account ..................................................................................... 38 3.10 Depreciation ................................................................................................................. 40

3.11 International Financial Reporting Standards ................................................................ 42 3.12 Updating for 2011 actual amounts ............................................................................... 44

3.12.1 Updating of categories other than operating expenses ................................... 44

3.12.2 Updating of operating expenses ...................................................................... 45 3.13 Operating expenses ...................................................................................................... 48

3.13.1 Forecasting of distribution and transmission repair costs ............................... 48 3.13.2 Cost control metrics ........................................................................................ 50

3.13.3 Inspection of customer service connections on private property .................... 51 3.13.4 Specialized rental equipment .......................................................................... 52

4 Distribution issues ............................................................................................................... 53 4.1 Distribution rate base ................................................................................................... 53

4.1.1 Distribution opening rate base ........................................................................... 53

4.1.2 Distribution 2012 capital additions ................................................................... 56 4.2 House service connection upgrades and relocates ....................................................... 57

5 Transmission issues ............................................................................................................. 58 5.1 Transmission rate base ................................................................................................. 58

5.1.1 Transmission opening rate base ........................................................................ 58

5.1.2 Transmission 2012 capital additions ................................................................. 62 5.1.3 Other issues related to transmission capital additions ....................................... 63

5.1.3.1 Age as a criteria in EDTI‟s asset replacement strategy ...................... 63 5.1.3.2 Capacity to complete forecast capital work ........................................ 64 5.1.3.3 Heartland 500 kV transmission project............................................... 66

5.1.3.4 AESO-directed projects ...................................................................... 68 5.1.3.5 Process improvement initiatives ......................................................... 70

5.2 One-off projects ........................................................................................................... 74

6 Corporate services costs ..................................................................................................... 75

ii • AUC Decision 2012-272 (October 5, 2012)

6.1 Legal and regulatory framework .................................................................................. 77 6.2 Corporate services costs allocated from EPCOR Utilities Inc. .................................... 81

6.2.1 Are the costs related to the provision of corporate services from EUI to EDTI

and EEAI necessary for EDTI and EEAI to provide utility service? ................ 81 6.2.1.1 Total corporate services costs to be allocated ..................................... 81 6.2.1.2 Short-term incentive payments allocated to the utilities by EUI ........ 85 6.2.1.3 Mid-term incentive payments allocated to the utilities by EUI .......... 86

6.2.1.4 Community relations and EPCOR community essentials council ...... 87 6.2.1.5 Other corporate services costs ............................................................ 87 6.2.1.6 Business development costs ................................................................ 88

6.2.2 Are the corporate services costs allocated correctly? ........................................ 89 6.2.2.1 Labour component of the composite cost causation allocator ............ 91

6.2.2.2 Revenue component of the composite cost causation allocator .......... 92 6.2.2.3 Capital expenditure component of the composite cost causation

allocator............................................................................................... 94 6.2.2.4 Should some corporate services costs be allocated to EUI itself for its

management of its investment in CPC, or for its management of the

funds remaining from its partial sale of CPC? .................................... 95

6.2.2.5 Has EUI acquired any new businesses to which it should allocate some

of its corporate services costs? ............................................................ 96

6.2.3 Would it be less expensive for EDTI and EEAI to provide the corporate

services or seek a different third-party provider on a stand-alone basis? ......... 98

7 Other issues ........................................................................................................................ 100 7.1 Phase II cost of service study ..................................................................................... 100

7.1.1 Distribution access service cost of service study and rates ............................. 100

7.2 Billing determinants forecast – transmission and distribution ................................... 102 7.3 Inclusion of volume variances in the TCDA.............................................................. 104

7.4 2012 system access service (SAS) rates .................................................................... 109 7.4.1 EDTI‟s proposed 2012 SAS rates ................................................................... 109

7.4.2 SAS operating reserve charge ......................................................................... 110 7.5 Maximum investment level ........................................................................................ 113 7.6 Deferral accounts ....................................................................................................... 116

7.7 Areas not individually addressed ............................................................................... 117 7.8 PBR and going-in rates .............................................................................................. 117

8 Order .................................................................................................................................. 119

9 Dissenting reasons of Commission Member Bill Lyttle regarding EDTI’s cost of debt...

............................................................................................................................................. 120

Appendix 1 – Proceeding participants .................................................................................... 129

Appendix 2 – Summary of Commission directions ................................................................ 131

List of Tables

Table 1. Major components of the 2012 distribution revenue requirement ........................ 2

AUC Decision 2012-272 (October 5, 2012) • iii

Table 2. Major components of the 2012 transmission revenue requirement ....................... 2

Table 3. Distribution FTE 2007-2012 trend .......................................................................... 11

Table 4. Transmission FTE 2007-2012 trend ........................................................................ 11

Table 5. Distribution capital expenditures 2007-2012 trend ($ millions) ........................... 12

Table 6. Transmission capital expenditures 2007-2012 trend ($ millions) ......................... 12

Table 7. Distribution capital expenditures completed by EDTI resources vs. contractors –

Table AUC-EDTI-69-1 ............................................................................................. 13

Table 8. Transmission capital expenditures completed by EDTI resources vs. contractors

– Table AUC-EDTI-69-2 .......................................................................................... 13

Table 9. Distribution FTE forecast accuracy ........................................................................ 14

Table 10. Distribution FTE forecast accuracy by category ................................................... 14

Table 11. Transmission FTE forecast accuracy ...................................................................... 14

Table 12. Transmission FTE forecast accuracy by category ................................................. 15

Table 13. Distribution vacancy information by type (FTEs) ................................................. 19

Table 14. Transmission vacancy information by type (FTEs) ............................................... 20

Table 15. Summary of escalators ............................................................................................. 24

Table 16. Estimated ED/ET 2012 stand-alone 2012 cost of long-term debt ......................... 30

Table 17. Distribution and transmission property, business and linear taxes 2009-2012 ... 37

Table 18. Distribution self-insurance reserve accounts.......................................................... 38

Table 19. Transmission self-insurance reserve accounts ....................................................... 38

Table 20. Depreciation expense by asset function 2011-2012 ($ millions) ............................ 40

Table 21. Distribution operating expenditures 2009-2012 – Table AUC-EDTI-69-3

($ millions) ................................................................................................................. 46

Table 22. Transmission operating expenditures 2009-2012 – Table AUC-EDTI-69-4

($ millions) ................................................................................................................. 47

Table 23. 2011 backcast – comparison of three-year average calculation methodologies –

Table CCA-EDTI-91-1 ($ millions) ......................................................................... 49

Table 24. Inspection of customer service connections on private property 2009-2012, Table

4.8.1-1 ($ millions) ..................................................................................................... 52

iv • AUC Decision 2012-272 (October 5, 2012)

Table 25. Distribution rate base (less working capital) – actual vs. decision ....................... 53

Table 26. EDTI distribution function capital additions ($ millions) ..................................... 54

Table 27. Distribution capital additions summary 2009-2012 ............................................... 57

Table 28. House service connection upgrades and relocates 2009-2012 – Table 4.7.2-5 ($

millions) ...................................................................................................................... 57

Table 29. Transmission rate base (less working capital) – actual vs. decision ..................... 59

Table 30. EDTI transmission function capital additions ($ million) ..................................... 59

Table 31. EDTI transmission function capital expenditures and capital additions excluding

Heartland ($ million) ................................................................................................ 60

Table 32. Heartland 500 kV transmission ($ millions) ........................................................... 60

Table 33. Transmission capital additions summary 2009-2012............................................. 62

Table 34. 2009-2012 transmission and distribution capital expenditures ($ million) ......... 65

Table 35. Forecast costs for the Heartland project 2011-2012 ($ millions) .......................... 66

Table 36. AESO-directed projects included in Section 13.2.1.13 .......................................... 69

Table 37. 2012 Process improvement initiatives ($ millions) ................................................. 70

Table 38. Transmission substation apparatus maintenance and repair 2009-2012

($ millions) ................................................................................................................. 74

Table 39. 2010-2012 corporate services costs by utility ($ millions) ..................................... 76

Table 40. 2012 corporate services costs by method ($ millions) ............................................ 82

Table 41. 2010-2012 EUI corporate services costs ($ millions) .............................................. 84

Table 42. Costs allocated by the composite cost causation allocator (2012 $ millions) ....... 90

Table 43. EPCOR Utilities Inc. – business information ($ millions) ..................................... 93

Table 44. 2012 U.S. water corporate services costs allocated by the composite cost

causation allocator ($ millions) ................................................................................ 98

Table 45. Number of customers and energy forecast – forecast accuracy table ................ 102

Table 46. Number of customers and energy – trend table ................................................... 103

Table 47. Number of customers – trend table ....................................................................... 103

Table 48. Energy sales – trend table ...................................................................................... 103

AUC Decision 2012-272 (October 5, 2012) • v

Table 49. Volume-related variances 2007-2011 ($ millions) ................................................ 105

Table 50. Major components of the 2012 distribution revenue requirement .................... 117

Table 51. Major components of the 2012 transmission revenue requirement ................... 117

Table 52. Average historical cost of debt (from AUC Rule 005 filings).............................. 124

AUC Decision 2012-272 (October 5, 2012) • 1


Calgary, Alberta

EPCOR Distribution & Transmission Inc. Decision 2012-272

2012 Phase I and II Distribution Tariff Application No. 1607944

2012 Transmission Facility Owner Tariff Proceeding ID No. 1596

1 Introduction

1. On November 30, 2011, the Alberta Utilities Commission (the AUC or the Commission)

received Application No. 1607944, entered as Proceeding ID No. 1596 (the application) from

EPCOR Distribution & Transmission Inc. (EDTI). The application requested approval of EDTI‟s

2012 Phase I and II distribution tariff and its 2012 transmission facility owner (TFO) tariff.

Specifically, EDTI requested approval of its:

forecast distribution function revenue requirement for the 2012 test year

forecast transmission function revenue requirement for the 2012 test year

rates for distribution access service (DAS) and related fees

rates for system access service (SAS)

transmission rates to be paid by the Alberta Electric System Operator (AESO) for the use

of EDTI‟s transmission facilities over the 2012 test year

terms and conditions for DAS, distribution connection services and distribution tariff

policies

TFO terms and conditions of service

distribution function and transmission function reserve and deferral accounts

transmission charge deferral account modifications

2. In addition, EDTI requested that the Commission direct that (with the exception of

EDTI‟s SAS rates and riders) the 2012 distribution tariff and TFO tariff, ultimately approved by

the Commission on a final basis, be continued into 2013 as EDTI‟s 2013 interim distribution

tariff and TFO tariff, pending

(i) approval by the Commission of EDTI‟s first annual rate adjustment filing under EDTI‟s

performance-based regulation plan (if approved by the Commission); or

(ii) any further order from the Commission in respect of EDTI‟s 2013 tariffs.

3. EDTI‟s forecast distribution function revenue requirement for 2012 is $149.40 million,

an increase of 14 per cent over EDTI‟s 2011 actual distribution revenue. Furthermore, EDTI‟s

2012 forecast transmission function revenue requirement is $68.64 million, which represents a

17 per cent increase over EDTI‟s 2011 actual transmission revenue.

4. The following tables summarize the 2012 forecast revenue requirement for distribution

and transmission as requested by EDTI.1 Unless otherwise noted, all dollar figures in these tables

are in millions:

1 Exhibit 3, application, page 5, Table 1.2.2.1-1 and page 11, Table 1.2.2.2-1.

2012 Phase I and II Distribution Tariff 2012 Transmission Facility Owner Tariff EPCOR Distribution & Transmission Inc.

2 • AUC Decision 2012-272 (October 5, 2012)

Table 1. Major components of the 2012 distribution revenue requirement

2012 ($ millions)

Per cent of total (%)

Return on debt and equity 43.79 29

Operating expenses 33.11 22

Depreciation 27.46 18

Corporate 23.24 16

Customer accounts 7.17 5

Property taxes 6.70 4

Administrative (net of capitalized amounts) 4.17 3

Deferred and reserve 3.76 3

Total 149.40 100

Table 2. Major components of the 2012 transmission revenue requirement

2012

($ millions) Per cent of total

(%)

Return on debt and equity 24.55 36


Operating expenses 13.54 20

Property taxes 6.89 10

Corporate 6.26 9

Deferred and reserve 2.04 3


Total 68.63 100

5. The corporate costs in the above tables exclude corporate costs that were directly

assigned or which are embedded in other cost categories, or capitalized.

6. On December 5, 2011, the Commission issued a notice of application requiring interested

parties to submit a statement of intent to participate (SIP) by December 23, 2011. A number of

interested parties registered to participate in this proceeding including the University of Alberta

(University), the Office of the Utilities Consumer Advocate (UCA), and the Consumers‟

Coalition of Alberta (CCA). A complete list of registered parties is set out in Appendix 1.

7. On December 13, 2011, the AUC issued a letter setting out the schedule for this

proceeding. In the letter the Commission set out an initial schedule stating that it had determined

that the application should be considered by way of a full process that included an oral hearing,

which was to be held in Calgary.

8. EDTI submitted a letter, dated December 16, 2011, requesting that the 2012 corporate

service matters for both EDTI and EPCOR Energy Alberta Inc. (EEAI) be determined in this

proceeding. EDTI further submitted that all of the information related to 2012 corporate service

matters for both EEAI and EDTI had been filed in this proceeding.

9. Noting the efficiencies that would be gained in adopting a common approach respecting

corporate service matters, on December 20, 2011, the Commission issued a letter stating that

2012 corporate service matters for EDTI and EEAI would be determined in Proceeding ID

No. 1596. Furthermore, the Commission requested that parties that would be prejudiced by this



common matters approach with regards to EEAI‟s 2012 corporate service costs should advise the

Commission by December 30, 2011.

10. The Commission, upon reviewing the application, considered that it may be possible to

process the application by way of a written proceeding. Therefore, on January 18, 2012, the

Commission issued a letter requesting interested parties to provide comments by February 8,

2012 as to whether an oral hearing was required and the reasons as to why an oral hearing may

be required. Furthermore, given that information requests to the applicant were due on

January 20, 2012, should the proceeding be done in writing, interested parties were asked to

provide comments as to whether or not a second round of information requests to the applicant

was required, in lieu of a hearing, as well as any other additional scheduling changes that may be

required.

11. On February 6, 2012, responding to EDTI‟s requests for a three-day extension of the

deadline to respond to information requests and the deadline for the filing of intervener evidence,

the Commission adjusted the requested deadlines and adjusted the deadline for submissions

regarding the need for an oral hearing to February 13, 2012.

12. Based on the submissions of parties, the Commission determined that there were no

compelling reasons that were presented as to why the issues in respect of this application

required testing at an oral hearing. Accordingly, the Commission in its letter, dated February 16,

2012, concluded that a written proceeding was suitable for testing this application and that the

oral hearing would be cancelled. Accordingly, the Commission established a written schedule,

which included a second round of information requests (IRs).

13. On March 22, 2012, the Commission issued a letter revising the schedule to allow for a

third round of IRs in order to test EDTI‟s 2011 actual financial information and for clarification

of previous information responses, if required, given that no oral hearing was scheduled for this

proceeding.

14. The following table outlines the process steps which were utilized to consider the

application.

Process step Deadline date

Statement of intent to participate 4 p.m., December 23, 2011

Information requests (Round 1) to applicant 4 p.m., January 20, 2012

Information responses (Round 1) from applicant 4 p.m., February 9, 2012

Information requests (Round 2) to applicant 4 p.m., March 7, 2012

Information responses (Round 2) from applicant 4 p.m., March 21, 2012

Information requests (Round 3) to applicant 4 p.m., April 11, 2012

Information responses (Round 3) from applicant 4 p.m., May 4, 2012

Intervener evidence (Round 1) 4 p.m., May 16, 2012

Information requests (Round 1) to interveners 4 p.m., May 25, 2012

Information responses (Round 1) from interveners 4 p.m., June 4, 2012

Rebuttal evidence (Round 1) 4 p.m., June 11, 2012

Argument 4 p.m., June 25, 2012

Reply argument 4 p.m., July 10, 2012



15. The Commission considers that the record for this proceeding closed on July 10, 2012.

16. In this decision, the Commission has specifically identified and provided findings and

determinations for areas of issue or concern in the application raised by either the Commission or

interested parties. The Commission has reviewed all information provided by EDTI in the

application during the proceeding, including items that were not specifically addressed by parties

to consider whether the information appears reasonable.

17. In reaching the determinations set out within this decision the Commission has

considered all relevant materials comprising the record of this proceeding, including the

evidence and argument provided by each party. Accordingly, reference 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 record with respect to a particular

matter.

2 Compliance with previous directions

18. The following table sets out those directions in previous decisions that were not identified

as contentious matters by interested parties in argument or reply and for which Commission is

satisfied that the directions have been complied with. The table also contains an explanation of

why the Commission is satisfied with EDTI‟s responses to the direction.

Application

section

Direction from Decision 2004-0672

Compliance to direction

2.2 Direction No. 17 - The Alberta Energy and

Utilities Board (board) directed EDTI to

provide appropriate business cases for capital

expenditures in excess of $500,000 clearly

showing:

The reasons/need for the proposed

expenditure; the alternatives examined; the

incremental capital and operating costs

associated with each alternative examined for

a minimum 10-year period; the discount or

investment rate used to compare alternatives

and the basis for its use; the rationale for

choosing a specific alternative, including any

qualitative considerations used in choosing

the alternative; and the date of preparation

and the date of approval.

After reviewing the business cases

attached as Appendix E, the

Commission finds that EDTI has

complied with this direction.

2 Decision 2004-067: EPCOR Distribution Inc., 2004 Distribution Tariff Application, Part B: 2004 Final

Distribution Tariff, Application No. 1306821, August 13, 2004.

http://www.auc.ab.ca/applications/decisions/Decisions/2004/2004-067.pdf



Application

section

Directions from Decision 2006-0543


2.3 Direction No. 10 - The board directed

EPCOR Distribution Inc. (EDI)/ EPCOR

Transmission Inc. (ETI) to provide actual and

forecast full-time equivalent (FTEs)

information for succession planning purposes

in future general tariff applications (GTAs).

The Commission finds that EDTI

has complied with this direction

after reviewing its succession

planning FTE‟s as set out in tables

1.4-1 and 1.4-2.

2.4 Direction No. 12 - Provide business cases for

any capital projects from EPCOR Utilities

Inc. (EUI) or other EPCOR affiliates where

the allocation is $500,000 or more in total

capital expenditure to either EDI or ETI or

both.

The Commission is satisfied with

EDTI‟s response attached as

Appendix E and finds that it has

complied with the direction.

2.6 Direction No. 28 - The board directed EDTI

to provide variance reporting of EDI capital

projects and ETI capital projects with a

minimum approved project forecast cost of

$500,000 and a variance from the approved

forecast of greater than 10 per cent.

The Commission has reviewed

Appendix E of the application and

is satisfied with EDTI‟s response to

this direction. The Commission

finds that EDTI has complied with

this direction.

2.7 Direction No. 32 - The board directed EDI, in

the next GTA, to consolidate projects that

may last longer than one year that are

seemingly the same project, such as the North

Service Centre Interior Replacements, and, if

the project is greater than $500,000, to

provide a business case.

Upon reviewing the groupings for

capital projects used by EDTI for

its 2012 application as set out in

Table 12.2-1 for distribution

projects and Table 13.2-1 for

transmission projects the


complied with this direction

Application

section



2.12 Direction No. 6 - The Commission directed

EDTI to provide paid overtime numbers for

meter readers as a part of its next GTA.

Upon reviewing its submissions for

its paid overtime numbers for meter

readers in MFR-Schedule 15-8 the


complied with this direction.

3 Decision 2006-054: EPCOR Transmission Inc., 2005/2006 Transmission Facility Owner Tariff, Application

No. 1389884 and EPCOR Distribution Inc., 2005/2006 Distribution Tariff – Phase I, Application No. 1389885,

June 15, 2006. 4 Decision 2010-505: EPCOR Distribution & Transmission Inc., 2010-2011 Phase I Distribution Tariff, 2010-

2011 Transmission Facility Owner Tariff, Application No. 1605759, Proceeding ID. 437, October 28, 2010.





2.14 Paragraph 140 - The Commission directed

EDTI in future GTAs to clearly identify and

explain any variance in its depreciation

expense from forecast that is caused by

reasons other than forecast variances in

capital account balances.

EDTI did not change any

depreciation or amortization rates

during 2010 and 2011. It has

applied for a number of changes to

asset lives in this application. These

are discussed in Section 16 of the

application. The Commission finds

that EDTI has complied with this

direction.


EDTI to recalculate the actual debt rate costs

for 2007, 2008 and 2009 by (a) applying the

actual indicative corporate bond spread of

FortisAlberta Inc. (Fortis) on the date the debt

was issued in each of those years, (b)

corresponding the debt to the 20-year debt

terms EDTI issued for 2007 and 2008 and the

30-year debt term EDTI issued in 2009 and

(c) adding a transaction cost of five basis

points.


EDTI‟s calculations of cost of debt

in MFR schedules 28-1D, 28-2D,

28-1T and 28-2T and finds that

EDTI has complied with this

direction.


EDTI to use the mid-year convention in

calculating interest on notes payable in future

tariff applications.

The Commission finds that EDTI

has complied with this direction as

evidenced in its cost of debt

calculations contained in MFR

Schedule 28-2D and 28-2T.


EDTI in its next GTA to advise the

Commission on whether the City of

Edmonton (the City) would make available

Alberta Capital Financing Authority (ACFA)

financing, and what it would cost relative to

issuing debt approved in this GTA.

Having read the letter provided by

the City on its position on securing

ACFA financing for EDTI, attached

as Appendix G-4 of the application,

the Commission finds that EDTI

has complied with this direction.

The Commission is also satisfied

that EDTI has provided information

on the cost of ACFA financing but

finds that there was only limited

information on the comparative

cost of issuing debt. Nonetheless,

the Commission finds that EDTI

has essentially complied with this

direction.


EDTI to establish a deferral account to

capture any approved short term incentive

amounts in revenue requirement that are not

actually paid out, with these unpaid amounts

to be returned to the benefit of customers.


Section 11.2.9 of this application

and is satisfied that EDTI has

complied with the direction.




EDTI to reduce the weighting of the earnings

component of its short-term incentive

program from 20 per cent to 10 per cent for

2011.

The Commission is satisfied that

the proposed short term incentive

program complies with this

direction.


EDTI to create a deferral account for any

adjustments resulting from the transition to

International Financial Reporting Standards

(IFRS) compliance, given that the impacts

may be material and not have balance impacts

on the parties.


EDTI‟s submission regarding this

direction in Section 11.2.10 of the

application and is satisfied that

EDTI has complied with the

direction.


EDTI, in future applications, to provide

business cases that break out forecast costs

into categories including, but not limited to,

capitalized customer and public consultation

costs, salvage proceeds if applicable,

materials, labour, engineering, contractors,

vehicles and allocated overhead.

Upon reviewing the business cases,

the Commission is satisfied that


direction.


EDTI in the preparation of all future business

cases to clearly describe the steps EDTI has

taken to ensure safety is not compromised

when projects are delayed which were

originally justified, in whole or in part, on the

basis of safety concerns.

Upon reviewing the business cases,

the Commission is satisfied that


direction.

2.24 Paragraph 417 - For each of distribution and

transmission, EDTI is directed to provide a

summary of the percentage growth of rate

base in physical measures including but not

limited to number of services, and kilometres

of conductor.

The Commission has reviewed the

information provided in

Section 2.24 of the application and

is satisfied that EDTI has complied

with this direction.


EDTI to reflect this 25 per cent premium in

costs for the new office tower by reflecting

only 80 per cent of the lease costs of the

Station Lands building in its revenue

requirement until the expiry or renegotiation

of its current 20-year lease.


calculation in Table 2.25-1 showing

the disallowed amounts and is

satisfied that EDTI has complied

with this direction.





EDTI to provide confirmation and details of

disposal of certain substation land (Plan B3,

Block 4, lots 193 and 194) at its next GTA.


details of the transaction provided

in sections 9.3.3 and 9.10.6 of this

application and is satisfied that


direction.

19. The table below sets out a list of prior directions on vacancy calculations that EDTI has

responded to in this application that will be addressed in Section 3.2 on Vacancy rates.

Application

section


2.1 Direction No. 6 - The board directed EDI to commence tracking vacancy rates,

commencing in the 2004 test year, for use in future GTAs.


2.8 Paragraph 128 - The Commission directed EDTI to continue the practice of

tracking monthly data on FTE vacancies, excluding the impact of transfers,

overtime and contractor backfills

2.9 Direction No. 4 - The Commission directed EDTI to exclude transfers between

EDTI and EUI from its vacancy calculation.

2.11 Direction No. 5 - The Commission directed EDTI to exclude unpaid management

overtime from the historical vacancy rate calculation.

2.13 Direction No. 7 - The Commission directed EDTI to recalculate its average

historical vacancy rate for 2007-2009, with the unpaid overtime and transfers

between EDTI and EUI excluded from the vacancy calculation in future EDTI

GTA applications.

20. The directions below have been raised as contentious matters by interested parties or, for

other reasons, require further consideration by the Commission.

Application Section 2.5 – Direction No. 27 from Decision 2004-067

21. In this direction, the board asked EDTI to provide business cases in the form and content

described above in Direction 2.2 in respect of all capital expenditures in excess of $500,000.

22. EDTI submitted in its application that it complied with the direction and that in

Column K of Tables 12.2-1 and 13.2-1 it identified the capital project for which business cases

have been prepared for the distribution and transmission functions respectively.6

23. Upon reviewing the application, the Commission finds that EDTI has complied with the

direction. However, the Commission did not find the presentation of the information in

tables 2.2-1 and 13.2-1 helpful. The Commission asked an information request for clarification

5 Decision 2011-211: EPCOR Distribution &Transmission Inc., Disposal of Substation Land, Application

No. 1607037, Proceeding ID No. 1091, May 17, 2011. 6 Exhibit 3, application, page 185, paragraph 489.




and found the format of the continuity schedules provided as AUC-EDTI-68(b) attachments 1

and 2 to be much easier to follow.7 The Commission directs EDTI, in future filings for its

transmission function, to file continuity schedules for at least three years prior to the forecast test

year or years in a format similar to AUC-EDTI-68(b) attachments 1 and 2, and to continue

submitting business cases for capital expenditures that are greater than $500,000. Further, the

Commission reminds EDTI, as per Direction 32 in Decision 2006-054, to continue preparing

business cases for capital expenditures that may last longer than one year and are in excess of

$500,000. For EDTI‟s distribution function, the Commission may request EDTI to provide this

information at the end of the performance-based regulation (PBR) term for each year of the PBR

term.

Application Section 2.10 – Direction paragraph 131 from Decision 2010-505

24. The Commission directed EDTI to provide supporting information in its historical

vacancy comparison which demonstrates that, in any area that experiences a vacancy backfilled

through paid overtime or through the use of contractors, EDTI used the approved labour dollars

for the intended workload.

25. EDTI submitted in the application that it could not comply with this direction because, by

the time it was in receipt of this direction (October 28, 2010), it was too late to implement a

formalized system for tracking this information in 2010. EDTI further added, “EDTI also

believes that even if time allowed for such a system to be put in place there is no reasonable way

for EDTI to differentiate, outside of how it currently estimates these backfills, that overtime was

incurred specifically as a result of a vacancy versus needs required by higher than forecast

workload. It is also difficult to prove the same comparison for contractors.”8

26. The UCA raised issue with EDTI‟s response in its argument9 by saying that EDTI had not

provided sufficient supporting evidence to justify the use of contractor backfills in its vacancy

rate. It stated:

Unless and until EDTI is able to provide adequate supporting data whether or not it is

tracked data or some other form of data, such as requested by the UCA for 2011 and

comply with the Commission Direction, the UCA recommends that contractor backfills

should be eliminated from the vacancy calculation if the future. [footnotes removed]

27. The Commission agrees with the UCA that EDTI has not provided sufficient supporting

evidence to justify the use of contractor backfills in its vacancy rate and finds that the direction

has not been complied with. The Commission notes that the number of new positions created is

not considered in the calculation of vacancy rates. The Commission directs EDTI for its

transmission function to develop a system to better track vacancies which takes into account

newly created positions.

Application Section 2.18 – Direction No. 13 from Decision 2010-505

28. In Decision 2010-505, the Commission directed EDTI to provide separate employee

compensation market competitiveness studies for each of EDTI, EEAI and EUI at the time of its

next rate application. While EDTI did not provide separate studies for each of EDTI, EEAI and

7 Exhibit 186.04, AUC-EDTI 68 b) Attachment 1 and Exhibit 186.05, AUC-EDTI 68 b) Attachment 2.

8 Exhibit 3, application, page 188, paragraph 494.

9 Exhibit 204.02, UCA argument, page 29, paragraph 124.



EUI, the Towers Watson study did provide employee compensation information separately for

each of EDTI, EEAI and EUI. EDTI noted that the primary comparator group, as selected by

Towers Watson, included companies in comparable industries (e.g. gas and electric distribution

and transmission utilities) with similar geographic scope and complexity to EDTI and that a

study using only EDTI comparators would yield comparable results. EDTI submitted that it has

met the Commission direction from Decision 2010-505.10

29. While EDTI did not provide separate employee compensation studies for EUI, EDTI and

EEAI as directed by the Commission in Decision 2010-505, EDTI did provide separate

employee compensation information and data for each of the three companies. The Commission

considers that the separate employee compensation data provided in the application is sufficient

to satisfy the requirements of the Commission‟s direction in Decision 2010-505.

3 Issues common to distribution and transmission

30. This section addresses areas of the application where issues were raised by the

Commission or interested parties which relate to both distribution and transmission. Areas which

only relate to distribution or transmission are addressed in sections 4 and 5 respectively.

3.1 FTE forecasts

31. EDTI has applied for 797.9 full-time equivalent employees (FTEs) which represents an

increase of 55.6 FTEs over the number of FTEs approved in Decision 2010-505. Of the proposed

55.6 FTE increase, EDTI submitted that 25.3 FTEs, being approximately 45 per cent of the

additional FTEs, were added prior to the beginning of 2012 at EDTI‟s expense. EDTI argued that

this supported the need for the FTEs. Of the additional 30.4 FTEs requested by EDTI for 2012

beyond the 2011 actual level, 15.9 relate to distribution; arising from an increase of 23.7 for

capital and an offsetting reduction of 7.9 for operating. For transmission, the increase in the 2012

FTE forecast is 14.5 FTEs higher than the 2011 actual level, with 5.5 for capital and nine for

operating.

32. EDTI submitted that the forecast FTE increases in its application are required for the

following reasons:11

increased forecast workload related to growth of EDTI‟s system leading to higher levels

of operating, maintenance and repair work

higher levels of capital life cycle replacement work due to a significant increase in the

volume of required aging infrastructure replacement

33. EDTI explained that it had prepared a detailed bottom up forecast to derive the number of

FTEs that were required to meet the forecast level of work for the test period. EDTI also

explained that, given the overlapping skill sets of the employees that were needed, there was

some transfer of staff between operating and capital functions as well as between business units

10

Exhibit 208.02, EDTI argument, page 36, paragraph 110. 11

Exhibit 208.02, EDTI argument, page 9, paragraph 23.



based on operational requirements.12 Further, given the cyclical nature of capital projects, EDTI

has been making greater use of contractors.

34. Tables 3 and 4 below display the overall trend of the proposed FTE increases for

distribution and transmission as compared to historical information. Since the 2011 actual levels

already include the proposed 2012 FTE increases for EDTI prior to 2012, the increases shown in

the two tables below for 2012 reflect the remaining 30.4 FTEs.13

Table 3. Distribution FTE 2007-2012 trend14

2007 (A) 2008 (A) 2009 (A) 2010 (A) 2011 (A) 2012 (F)

Operating 357.8 357.6 388.8 413.0 353.7 345.8

Capital 143.4 165.0 169.1 191.2 276.1 299.8

Total actual (A) or forecast (F) 501.2 522.6 557.9 604.2 629.7 645.6

Increase 21.4 35.3 46.3 25.5 15.9

% Increase 4.3% 6.8% 8.3% 4.2% 2.5%

Legend: (A) actual, (F) forecast

Table 4. Transmission FTE 2007-2012 trend15

2007 (A) 2008 (A) 2009 (A) 2010 (A) 2011 (A) 2012 (F)

Operating 70.8 77.4 76.3 79.6 68.0 77.0

Capital 56.3 47.6 51.3 55.4 69.8 75.3

Total actual (A) or forecast (F) 127.1 125.0 127.6 135.0 137.8 152.3

Increase (2.1) 2.6 7.4 2.8 14.5

% Increase (1.7%) 2.1% 5.8% 2.1% 10.5%

35. The revenue requirement impacts related to FTE increases for 2012 in comparison to the

2011 decision amounts were summarized as follows by EDTI:16

i. distribution: $3.5 million of the overall total $17 million increase

ii. transmission: $1.9 million of the overall total $9 million increase

36. None of the interested parties raised concerns with regard to the combined 55.6 FTE

increase for distribution and transmission proposed in the application for 2012.

Commission findings

37. EDTI has explained the increase in FTEs as being due to increases in workload related to

growth of its system and higher levels of capital life cycle replacement work.

12

Exhibit 203.02, EDTI rebuttal evidence, page 14, lines 2-6. 13

Distribution 15.9 FTEs + transmission 14.5 FTEs.

14 Exhibit 208.02, EDTI argument, page 8; Exhibit 186.06, information response AUC-EDTI-70, Attachment 1,

Schedules 5-5 and 15-9, and Decision 2010-505, pages 19-20, Tables 4-7. 15

Ibid. 16

Exhibit 167.03, information response AUC-EDTI-16, attachments 1 and 2.



38. To allow comparability of workload from year to year, distribution capital expenditures

shown in the table below have been adjusted downward to account for distribution work

performed by the transmission function.

Table 5. Distribution capital expenditures 2007-2012 trend ($ millions)17

2007 (A) 2008 (A) 2009 (A) 2010 (A) 2011 (D) 2011 (A) 2012 (F)

Distribution capital expenditures 41.1 52.4 52.4 86.2 68.1 92.9 89.1

Less: distribution to transmission contributions

0.5 13.6 12.5 8.2 4.9

Adjusted distribution capital expenditures*

41.1 52.4 51.9 72.6 55.6 84.7 84.2

*Life cycle capital expenditures included in above total

12.1 20.4 21.3 29.7 26.2

Legend: (A) actual, (D) decision, (F) forecast

39. The adjusted distribution capital expenditures displayed in the table above show

increasing capital expenditures from 2007 to 2011 with a slight decrease in 2012.

40. Transmission capital expenditures shown in the table below have been adjusted to allow

comparability of workload from year to year. The Heartland project, an AESO-directed project

for which EDTI is an owner but has limited participation has been removed, and customer

contributions have been added back to the total provided on EDTI‟s schedule because these

contributions reduced the capital expenditures shown.

Table 6. Transmission capital expenditures 2007-2012 trend ($ millions)18

2007 (A) 2008 (A) 2009 (A) 2010 (A) 2011 (D) 2011 (A) 2012 (F)

Transmission capital expenditures 59.4 59.1 32.0 35.0 24.2 58.6 14.6

Less: Heartland project 7.5 5.3 3.5 28.1 (43.7)

Add: Customer contributions 8.2 9.6 6.6 22.7 4.9

Adjusted transmission capital expenditures*

59.4 59.1 32.7 39.3 27.3 53.2 63.1

*Life cycle capital expenditures included in above total

13.4 11.7 9.7 14.9 16.6


41. The adjusted transmission capital expenditures set out in the table above decrease in 2009

and 2010 and increase in each of 2011 and 2012.

42. Recognizing that EDTI‟s FTEs are impacted by the use of contractors, the Commission

examined the extent to which EDTI has used and expects to use contractors in performing its

capital work.

17

Exhibit 186.04/05, information response AUC-EDTI-68 (b), attachments 1 -2 and Exhibit 186.07/09,

information response AUC-EDTI-71, attachments 1 and 3. 18

Ibid.



43. In response to an information request on FTE levels in relation to capital activity, EDTI

provided the following tables indicating the proportion of work done by contractors and internal

resources:19

Table 7. Distribution capital expenditures completed by EDTI resources vs. contractors – Table AUC-EDTI-69-1

A 2009 (A)

B 2010 (A)

C 2011 (A)

D 2012 (F)

1 % of contractor expenses 16.55 24.40 31.24 26.14

2 % of internal expenses 83.45 75.60 68.76 73.86

3 Total 100.00 100.00 100.00 100.00

Table 8. Transmission capital expenditures completed by EDTI resources vs. contractors – Table AUC-EDTI-69-2

A 2009 (A)

B 2010 (A)

C 2011 (A)

D 2012 (F)

1 % of contractor expenses 27.99 43.44 52.06 58.95

2 % of internal expenses 72.01 56.56 47.94 41.05

3 Total 100.00 100.00 100.00 100.00

44. As the tables are based on assumptions, the Commission considers the data to be

approximate. The general trend for distribution shows that approximately three quarters of

distribution capital is constructed using internal resources, i.e. capital FTEs. For transmission

capital, the trend from 2009 to the present shows an increasing reliance on the use of contractors.

45. The Commission also considered the possible impact on FTEs from the change in

accounting to IFRS in 2011. As noted in Decision 2010-505,20 there was a shift of approximately

60 operating FTEs to capital for distribution and 14 operating FTEs to capital for transmission,

as a result of this accounting change. Although FTEs from 2007 to 2010 are presented on a

different basis, data for 2011 and 2012 was prepared in accordance with IFRS making these two

years comparable.

46. An additional perspective from which to consider the forecast FTE numbers is to

examine past experience and the forecasting accuracy of EDTI. Summaries and comparisons of

EDTI‟s historical and proposed FTEs for distribution and transmission are shown in the

following tables:

19

Exhibit 186.02, information request AUC-EDTI-69(c). 20

Decision 2010-505, page 21, paragraph 113.



Table 9. Distribution FTE forecast accuracy

2007 2008 2009 2010 2011

Operating 361.4 377.1 384.4 417.8 356.4

Capital 158.6 161.5 152.0 188.9 251.6

Total decision 520.0 538.6 536.4 606.7 608.0

Operating 357.8 357.6 388.8 413.0 353.7

Capital 143.4 165.0 169.1 191.2 276.1

Total actual 501.2 522.6 557.9 604.2 629.7

Total over (under) (18.8) (16.0) 21.5 (2.5) 21.7

% Total over (under) (3.6%) (3.0%) 4.0% (0.4%) 3.6%

47. Table 9 above shows that the actual number of distribution FTEs hired was lower in

2007, 2008 and 2010 than was approved in the respective decisions, but higher for 2009 and

2011. Table 10 below identifies separately the distribution FTEs as operating and capital. For

distribution, with the exception of 2009, actual operating FTEs have been lower than the level

approved while actual capital FTEs, with the exception of 2007, have been higher than approved.

Table 10. Distribution FTE forecast accuracy by category

2007 2008 2009 2010 2011

Operating - approved 361.4 377.1 384.4 417.8 356.4

Operating - actual 357.8 357.6 388.8 413.0 353.7

Total operating over (under) (3.6) (19.5) 4.4 (4.8) (2.7)

Capital – approved 158.6 161.5 152.0 188.9 251.6

Capital – actual 143.4 165.0 169.1 191.2 276.1

Total capital over (under) (15.2) 3.5 17.1 2.3 24.5

Table 11. Transmission FTE forecast accuracy

2007 2008 2009 2010 2011

Operating 77.6 78.9 78.4 87.8 70.4

Capital 60.4 56.3 45.6 50.0 63.7

Total decision 138.0 135.2 124.0 137.8 134.3

Operating 70.8 77.4 76.3 79.6 68.0

Capital 56.3 47.6 51.3 55.4 69.8

Total actual 127.1 125.0 127.6 135.0 137.8

Total over (under) (10.9) (10.2) 3.6 (2.8) 3.6

% Total over (under) (7.9%) (7.5%) 2.9% (2.0%) 2.7%

48. Table 11 above shows that the actual number of transmission FTEs hired was lower in

2007, 2008 and 2010 than was approved in the respective decisions, but higher for 2009 and

2011. Table 12 below identifies separately the transmission FTEs as operating and capital for

each year. For transmission, actual operating FTEs have been lower than the level approved in

each of the five years while actual capital FTEs, with the exception of 2007 and 2008, have been

higher than approved.



Table 12. Transmission FTE forecast accuracy by category

2007 2008 2009 2010 2011

Operating – approved 77.6 78.9 78.4 87.8 70.4

Operating - actual 70.8 77.4 76.3 79.6 68.0

Total decision over (under) (6.8) (1.5) (2.1) (8.2) (2.4)

Capital - approved 60.4 56.3 45.6 50.0 63.7

Capital – actual 56.3 47.6 51.3 55.4 69.8

Total actual over (under) (4.1) (8.7) 5.7 5.4 6.1

49. The primary reasons provided by EDTI for the FTE increases were related to increased

workload arising from the growth of EDTI‟s system and higher levels of capital life cycle

replacement related to aging infrastructure. The Commission does not consider the fact that

EDTI hired more FTEs in 2011 than had been approved to be determinative of the need for the

FTEs. Therefore, the Commission will consider the proposed increase in FTEs using a two-step

process, from the 2011 approved level to the 2011 actual level, and from the 2011 actual level to

the 2012 forecast level that EDTI has proposed.

50. In the first step of the two step process, the Commission has reviewed the actual adjusted

capital expenditure levels for both distribution and transmission for 2011 as shown in tables 5

and 6 above. These tables show that distribution and transmission adjusted capital expenditures

were higher than the approved levels by $29.1 million21 and $25.9 million22 respectively. The

related higher-than-forecast distribution and transmission capital additions for 2011 have been

allowed as opening rate base adjustments for 2012, in sections 4.1.1 and 5.1.1 of this decision.

The 25.3 FTEs in excess of the approved 2011 levels as presented in tables 9 and 11 were capital

FTEs.

51. For these reasons, the Commission will accept the actual 2011 FTEs as the starting point

for step two of the assessment.

52. For distribution, the Commission notes that distribution capital expenditures forecast for

2012 are lower than 2011 actual levels, both in aggregate and for the capital expenditures life

cycle replacement projects. Further, as shown in Table 7 above, generally three quarters of

distribution capital expenditures are constructed using internal resources. As distribution capital

expenditures are forecast to decrease and there is a similar forecast decrease in the use of

contractors, the Commission finds no support for the forecast increase in distribution capital FTE

levels. The Commission is not persuaded that distribution capital FTE increases beyond 2011

actual levels, as forecast by EDTI, are required and therefore, the Commission directs that the

2012 distribution capital FTEs be held to the 2011 actual levels.

53. For transmission, the proposed FTE increase in the 2012 FTE forecast is 14.5 FTEs

higher than the 2011 actual level, with 5.5 forecast for capital FTEs and nine forecast for

operating FTEs.

54. The 2012 adjusted forecast capital expenditures for transmission shown in Table 6 above

exceeds the level of 2011 actual expenditures; however, construction of capital expenditures by

21

$29.1 = distribution adjusted actual capital expenditures $84.7 million - $55.6 million approved. 22

$25.9 = transmission adjusted actual capital expenditures $53.2 million - $27.3 million approved.



internal resources as shown in Table 8 is forecast to decrease, somewhat mitigating the need for

increased capital FTEs. However, the Commission finds that the forecast percentage increase in

capital FTEs of 7.9 per cent23 is reasonable in view of the 18.624 per cent forecast increase in

capital expenditures.

55. With regard to the operating FTEs requested by EDTI, relative to the 2011 FTEs as

shown in tables 3 and 4, the Commission considers that the relative size and offsetting nature of

the reduction in distribution operating FTEs compensates to some extent for the proposed

increase in transmission operating FTEs, given the transfer of staff between business units based

on operational requirements as stated by EDTI.25

56. For all of the reasons provided above, the Commission finds that capital FTE levels for

distribution in the 2012 test year shall be reduced by 23.7 FTEs and, instead, be based on the

2011 actual levels. The Commission directs EDTI to reflect this reduction in distribution capital

FTEs along with all related costs in the compliance application and to provide a schedule with all

resulting adjustments.

3.2 Vacancy levels

57. The vacancy rate represents a ratio of the number of vacant FTE positions compared to

the total approved FTEs for a given period, and it is applied as a reduction against the forecast

labour expenses to reflect that a certain number of positions will be vacant in the given period,

thereby reducing the forecast labour expenses. The higher the vacancy rate used in the forecast

period, the greater the reduction applied against the total potential labour dollars for the proposed

FTE level.

58. In the application, EDTI applied a 2.5 per cent vacancy rate for its salaried employees,

with the exception of the meter reading staff, and a zero per cent vacancy rate for all labour staff.

EDTI stated that it calculated the 2.5 per cent vacancy rate used for both distribution and

transmission functions based on an average because these business functions were highly

integrated with staff being transferred between business units based on operational

requirements.26 For (hourly) labour, EDTI stated that it did not apply a vacancy rate because it

forecast its labour requirements on a gross basis using a bottom up calculation based on its

forecast operating and capital work requirements. EDTI submitted it did not apply a vacancy rate

for meter reader staff because it used a detailed bottom up calculation of the “net” FTEs required

to perform its meter reading function.

59. EDTI stated its zero per cent vacancy rate approach for labour and meter reader staff

reflects the nature of their work. EDTI indicated that labour and meter reader staff must complete

the forecast work level and, if a particular employee is unable to fulfill his or her function, then

EDTI has no choice but to backfill that employee to ensure that the work levels are maintained.

23

7.8% = transmission capital 2012 FTE forecast increase of 5.5 / transmission 2011 capital FTE actual total

of 69.8. 24

18.6 % = transmission 2012 adjusted capital expenditure increase of $9.9 million / transmission 2011 adjusted

capital expenditures actual total of $53.2 million. 25

Exhibit 203.02, EDTI rebuttal evidence, page 14, lines 2-6. 26

Exhibit 203.02, EDTI rebuttal evidence, page 14, lines 2-6.



60. EDTI‟s proposed 2.5 per cent vacancy rate was based on a three-year average of both the

transmission and distribution functions using 2008-2010 actuals, as shown in tables 13 and 14

below for distribution and transmission respectively. EDTI did not propose to recalculate its

three-year average of vacancy rates to reflect 2011 actual information, which had become

available during the course of the proceeding, to remain consistent with its approach with regard

to all of its forecasts in the application.

61. The vacancy rate calculations reflected backfilling by contractors and paid overtime. It

was EDTI‟s position that the FTE increases included in the 2012 test year mitigated a portion of

the negative and small vacancies experienced in 2009 and 2010; thereby supporting the use of

the blended 2.5 per cent vacancy rate.27

62. EDTI indicated that there was no reasonable way to differentiate between overtime and

contractor costs incurred as a result of a vacancy as opposed to overtime and contractor costs

incurred to meet higher than forecast workload.28 It was EDTI‟s position that the estimates of

paid overtime and contractor backfill were conservative, and that they significantly understated

the actual level of backfill. EDTI explained its view of vacancies as follows:

[170]….EDTI notes that when it experiences higher than forecast work levels, it uses

paid overtime and contractors to meet those work levels. What is relevant on an actual

basis is not solely the work that EDTI had forecast and the FTEs necessary to accomplish

that work, but the actual work demand it is faced with and the total number of FTEs

actually necessary to meet that work demand. In a very real sense, higher than forecast

workload results in “vacancy”, as EDTI does not have the resources to accomplish the

additional workload. By using paid overtime and hiring contractors (in addition to hiring

additional staff), EDTI “backfills” the entire “vacancy” amount, which includes not only

any shortfall in manpower vis-à-vis EDTI‟s original FTE forecast, but also EDTI‟s

shortfall in resources necessary to meet the higher than forecast workload.29

63. EDTI stated that, while it had used the same approach to calculate backfills for 2012 as in

its previous application, it had taken steps to improve the calculation where possible. For

example, EDTI reviewed contractor use to try to determine which contractors had been used to

backfill vacancies (e.g., engineering contractors to backfill work of salaried engineering staff).

Conservative estimates of 25 per cent of paid overtime for salaried engineering staff were used

as vacancy backfill given that a precise number cannot be determined. EDTI confirmed that, in

accordance with directions 4 and 5 from Decision 2010-505, all unpaid management overtime

and transfers of staff with EUI had been excluded from the backfill calculations.

64. The UCA argued that the blended vacancy rate developed by EDTI was not calculated

based on the correct three-year historical average of vacancy rates and that not enough

supporting information had been provided by EDTI to allow backfilling by contractors and

overtime to be reflected in the vacancy rate calculations. The UCA submitted that historical

vacancy information and forecast work demand were distinct in purpose, and backfills related to

incorrect forecasts of work demand should not be included in the historical vacancy information.

27

Exhibit 3, application, page 72, paragraph 186. 28


Exhibit 3, application, pages 64-65, paragraph 170.



Eliminating contractor backfills and overtime from the vacancy calculations would also simplify

the tracking and reporting of vacancy calculations.30

65. The UCA recommended that separate vacancy rates should be used for distribution and

transmission as they had separate revenue requirements and this practice was used by AltaLink

Management Ltd. (AltaLink), ATCO Electric Ltd. (ATCO Electric), ATCO Gas, and AltaGas

Utilities Inc. (AltaGas). The UCA estimated that the distribution vacancy rate should be

3.9 per cent instead of the 3.4 per cent calculated by EDTI. With regard to transmission, the

UCA proposed that the 2.5 per cent included in the application should be used.

66. EDTI rejected the UCA‟s calculation of vacancy rates with regard to the exclusion of

contractor backfills and overtime, arguing that it had used the calculation which was accepted by

the Commission in recent decisions. EDTI stated that it had followed Commission directions

from Decision 2010-505 to track and support specific vacancy information to the extent possible

given the timing of the decision and that it was not possible to retroactively track data from

previous years.

67. EDTI challenged the UCA position that historical vacancy information and work demand

are one sided since the vacancy calculation began with a calculation of the difference between

approved and actual amounts, which captures all changes in FTEs regardless of the reason. For

this reason, EDTI argued that all decreases in FTEs should be considered as well as the

increases.

68. EDTI submitted that use of a blended distribution and transmission vacancy rate was

reasonable due to the integrated nature of the two functions, but if the UCA proposal to use

3.9 per cent was accepted for distribution, then the negative 2.09 per cent vacancy rate for

transmission should be used, resulting in a blended rate of 0.91 per cent which is much lower

than the vacancy rate proposed by EDTI of 2.5 per cent.

Commission findings

69. The Commission has prepared the following tables and analysis to better understand the

forecast vacancy rates proposed in the application

70. Tables 13 and 14 below present the approved and actual number of FTEs by type of

employee within each of distribution and transmission. Each table also shows the variance by

type of employee resulting in the vacancy factor before any backfilling is included as an

adjustment. Each table includes the vacancy factor after backfilling is considered, as provided by

EDTI, along with the three-year historical vacancy factor.

30

Exhibit 189.02, UCA intervener evidence – Radway, page 28, A34.



Table 13. Distribution vacancy information by type (FTEs)31

2008 2009 2010 2011 2012 (F)

Salary - meter readers 70.6 73.4 73.8 71.9

Salary - other 171.7 172.3 190.6 190.2

Labour 296.3 290.7 342.3 345.9

Total decision FTEs 538.6 536.4 606.7 608.0

Salary - meter readers 72.1 72.5 72.0 69.6 73.9

Salary - other 151.1 166.2 185.8 198.4 207.5

Labour 299.4 320.0 346.3 361.7 364.2

Total actual FTEs 522.6 558.7 604.2 629.7 645.6

Salary - meter readers (over)under (1.5) 0.9 1.8 2.3

Salary - other (over)under 20.6 6.1 4.8 (8.2)

Labour (over)under (3.1) (29.3) (4.0) (15.8)

Total (over) under 16.0 (22.3) 2.5 (21.7)

% Total (over) under 3.0% (4.2%) 0.4% (3.6%)

vacancy factors before backfill

Salary - meter readers (2.1%) 1.2% 2.4% 3.2%

Salary - other 12.0% 3.5% 2.5% (4.3%)

Labour (1.0%) (10.1%) (1.2%) (4.6%)

Vacancy factors after backfill

Salary - meter readers not used not used not used not used

Salary - other 6.1% 3.1% 0.8% (4.9%)

Labour not used not used not used not used

EDTI 3-year historical factor 3.4%

71. Table 13 above (using 2011 actual information) shows that, of 630 FTEs for distribution

(forecast 608 FTEs), only the salary – other employee type (which includes approximately

200 FTEs) had a vacancy rate of 2.5 per cent applied by EDTI in the application. The table

section displaying vacancy factors by employee type before backfill shows that, for each year

being compared, the labour category had a negative vacancy rate, but the remaining two

categories experienced positive or negative vacancy rates depending on the year.

72. Table 14 below (using 2011 actual information) shows that, of 138 FTEs for transmission

only, the salary employee type (which includes about 50 FTEs) had a vacancy rate of 2.5 per

cent applied by EDTI in the application. The table section displaying vacancy factors by

employee type before backfill shows that, for each year being compared, the labour category had

a positive vacancy rate, but the remaining category experienced positive or negative vacancy

rates depending on the year. In 2011, the negative vacancy rates are due in part to the hiring of

22 additional FTEs.

31

Exhibit 208.02, EDTI argument, page 8; Exhibit 186.06, information response AUC-EDTI-70, Attachment 1,

schedules 5-5 and 15-9; and Decision 2010-505, pages 19-20, Tables 4-7.



Table 14. Transmission vacancy information by type (FTEs)32

2008 2009 2010 2011 2012 (F)

Salary 44.6 42.6 48.1 46.8

Labour 90.6 81.4 89.7 87.4

Total decision FTEs 135.2 124.0 137.8 134.3

Salary 42.8 46.2 46.1 53.4 61.3

Labour 82.2 80.6 88.9 84.5 91.0

Total actual FTEs 125.0 126.8 135.0 137.9 152.3

Salary (over) under 1.8 (3.6) 2.0 (6.6)

Labour (over) under 8.4 0.8 0.8 2.9

Total over (under) 10.2 (2.8) 2.8 (3.6)

% Total over (under) 7.5% (2.2%) 2.0% (2.7%)

vacancy factors before backfill

Salary 4.0% (8.5%) 4.0% (14.1%)

Labour 9.3% 1.0% 0.9% 3.3%

Vacancy factors after backfill

Salary 3.8% (10.1%) 0% (14.6%)

Labour not used not used not used not used

EDTI 3-year historical factor (2.1%)

73. The Commission has reviewed the relative sizes of the salaried employee groups to

which EDTI has applied a blended vacancy factor of 2.5 per cent for both distribution and

transmission. The number of distribution salary – other FTEs is approximately four times larger

than the transmission salary FTEs, using 2011 actual information, based on the tables shown

above.

74. The vacancy factors before backfills shown in the tables above display a trend where

distribution has a negative vacancy factor for labour FTEs but transmission has a positive

vacancy factor for the same category. Further, the salary FTE categories for each of distribution

and transmission experience significantly different vacancy factors, before backfills, in the same

historical year and across years.

75. The Commission, after considering the above analysis, accepts the UCA‟s position that

separate vacancy factors should be applied to each of distribution and transmission, as is the

practice for other Alberta utilities such as AltaLink, ATCO Electric, ATCO Gas, and AltaGas,

because separate revenue requirements are approved for distribution and transmission.

76. For the above reasons, the Commission finds that EDTI should apply a separate vacancy

rate for distribution and transmission rather than use a blended overall rate, as proposed in the

application. In addition, the Commission has considered whether the vacancy rates should be on

a gross or net basis.

77. With respect to the issue of whether the vacancy rate should be gross or net, the

Commission recognizes the complexity and subjective nature of backfill calculations being

applied against the “gross” vacancy rates to derive “net” vacancy rates which are then used to

32

Ibid.



forecast vacancies. The UCA argued that EDTI had not adequately supported the contractor and

overtime backfills used in the application. The UCA submitted that eliminating the backfill

calculations would simplify tracking and reporting of vacancy calculations. Further, while EDTI

explained that it had taken additional steps to improve backfill calculations where possible, it

stated there was no reasonable way to differentiate contractor costs and overtime resulting from

vacancies rather than higher-than-forecast workload.

78. To address the subjective nature of approximating “net” vacancy rates, and in

consideration of the inability to differentiate backfill information between vacancy related

backfills and higher forecast workload, the Commission finds that gross vacancy rates shall be

used instead. Gross vacancy rates can be calculated for historical comparison, as shown in

tables 13and 14, and comparison between approved FTEs and actual FTEs then becomes a

straightforward calculation. The Commission notes that the existing vacancy calculation does not

take into account the number of actual new positions hired during the period, which were not

part of the approved forecast FTE level, and that this has the effect of understating the actual

vacancy rate.

79. Accordingly, for distribution, the Commission directs that a gross vacancy rate of 3.4 per

cent33 is to be applied to the salary – other category, based on calculating the four year average of

the vacancy factors before backfills, as shown in Table 13 above. For transmission, the

Commission directs that no vacancy rate shall be applied to the salary category for the 2012 test

year, because in the Commission‟s view use of a negative vacancy factor would provide more

than 100 per cent of salary for each FTE to which it is applied. Additionally, the Commission

does not agree with EDTI‟s calculation of its negative vacancy factor because it fails to take into

account FTEs in excess of the approved forecast amount.

80. With regard to Section 2.8 of the application on the tracking of monthly FTE vacancy

data, the Commission disagrees with EDTI‟s position that it has complied with this direction.

Tables 1.4.3-3 and 1.4.3-6 for distribution and transmission vacancy respectively provide

monthly information for salaried employees but do not provide any information on the labour

FTE category, which is the dominant FTE category for both business units. The Commission

finds that EDTI has complied with the directions shown in sections 2.9, 2.11 and 2.13 of the

application. However, EDTI has only partially complied with directions in sections 2.1 and 2.8

of the application, having only tracked vacancy rates for salaried employees. For transmission,

EDTI is directed to track monthly data on each FTE category as shown in Table 14 above, and to

provide this information as part of future filings. EDTI is also directed to track new positions that

are hired but were not part of the approved FTE level and to reflect these in the vacancy

calculations. For EDTI‟s distribution function, the Commission may request EDTI to provide

this information at the end of the PBR term for each year of the PBR term.

3.3 Salary escalations

81. EDTI provided details with respect to employee compensation in Section 1.6.1 of the

application. In the application, EDTI included a salary escalation factor of four per cent for non-

union employees and three per cent for all of its union employees.

82. Consistent with previous applications, EDTI retained Towers Watson to provide an

assessment of the market competitiveness of EPCOR‟s compensation and benefits. EDTI stated

33

3.4% = (12% + 3.5% + 2.5% - 4.3%)/4 years.



that the methodology for the Towers Watson review in the application was consistent with the

reviews conducted in 2004, 2006 and 2009.34 EDTI noted that Towers Watson defines market

competitiveness as +/- 10 per cent of the market 50th percentile.35

83. EDTI stated that as an overall objective the EPCOR group seeks to ensure that total

employee compensation is competitive and targets mid-market, or 50th percentile, for total

employee compensation.36

84. EDTI noted that the Towers Watson analysis showed that, on an overall basis, EPCOR‟s

non-union positions are five per cent below the market median for target total direct

compensation. Based on this, Towers Watson recommended a range of escalation for non-union

salaries of 3.5 per cent to 4.5 per cent. EDTI‟s forecast reflects the escalation of all non-union

salaries at 4.0 per cent, the mid-point of Towers Watson‟s recommended range. EDTI stated that

the proposed salary escalation of four per cent for non-union employees will ensure these

positions do not fall further behind the market median.37

85. EDTI stated that EPCOR completed its negotiations for a new three year collective

agreement with the Civic Service Union (CSU) on October 11, 2011. Based on the terms of the

collective agreement, the actual salary and labour escalators for CSU 52 unionized employees

were 2.75 per cent, 3.00 per cent and 3.50 per cent for 2011, 2012 and 2013 respectively.

Accordingly, EDTI applied a 3.00 per cent salary escalation to the base salaries for all CSU

employees for 2012.38

86. EDTI stated that it had successfully concluded negotiations for a new three year

collective agreement with the International Brotherhood of Electrical Workers (IBEW) on

April 21, 2010. Based on the terms of this agreement, the actual salary escalator for IBEW

unionized employees was 3.00 per cent for each of 2010, 2011 and 2012. Accordingly, EDTI

applied a 3.00 per cent salary escalation to the base salaries for all IBEW employees for 2012.39

87. EDTI also stated that it was working with the IBEW to reclassify some positions as set

out in a letter of understanding. EDTI stated that it will reclassify approximately 60 employees

over eight different job classes and will adjust the compensation levels to address specific

instances where the current compensation levels do not adequately reflect the scope of the

position under the new job class.40 EDTI stated that it has included a $0.25 million increase in its

total compensation to reflect that 2012 pay levels for some positions are likely to rise under the

reclassification process.41 EDTI stated that the benefits of developing the job reclassification

descriptions are not quantified because the benefit of being able to use employees within a labour

class interchangeably is already reflected in its forecasting methods. EDTI also stated that the

34

Exhibit 208, EDTI argument, page 35, paragraph 105. 35



Exhibit 208, EDTI argument, page 37, paragraphs 112 and 113. 38




Exhibit 208, EDTI argument, page 39, paragraph 120.



reclassification effort will better align EDTI‟s actual staffing flexibility with that already

assumed in its budgeting process.42

88. The UCA argued that as noted in the Towers Watson report, the total target cash for EUI

union positions is 10 per cent over market for stratum two, nine per cent over market for stratum

one and nine per cent over market in total for all EUI union positions. The UCA stated that given

that Towers Watson defines market competitiveness as +/- 10 per cent of the market 50th

percentile and that union positions are already at the upper end for market competitiveness, there

should be no increases in union wages included in 2012 revenue requirement.43

89. EDTI responded to this issue in reply argument. EDTI stated that the escalation rate of

3.0 per cent should be approved because:

it reflects actual wage increases in Canada as the Conference Board of Canada is

forecasting a 3.2 per cent growth in wages and salaries per employee in Alberta

based on the terms of the CSU and IBEW agreements, it will be reflected in what EDTI

actually pays its employees in 2012

the evidence shows that EDTI‟s 2011 union wages are within 10 per cent of the market

median in 2011 and applying the 3 per cent escalator will not bring union wages outside

the range but keep it in a similar position, as the escalator reflects the expected general

escalation of wages in Canada

applying no escalation would result in a reduction in wages on a real dollar basis44

90. The UCA also addressed the issue of the reclassification of some union positions set out

in the letter of understanding with the IBEW. The UCA stated that, since EDTI did not include

any of the benefits of this agreement in its application, the $0.5 million cost should be excluded

from EDTI‟s revenue requirement. The UCA also stated that it was not appropriate to include

this cost in EDTI‟s revenue requirement in 2012 given that 2012 rates will form the going-in

rates for PBR for EDTI.

91. EDTI noted that the UCA incorrectly cited $0.5 million as the cost included in the

application and stated that the increase to EDTI is actually $0.25 million. EDTI also stated that it

had outlined the intangible benefits of the reclassification and that these intangible benefits were

already included in the application. EDTI argued that the $0.25 million cost reflects EDTI‟s

actual labour expense, that it was prudently incurred and there is no reason why known labour

costs should not be in the 2012 revenue requirement. Finally, EDTI stated that the fact that 2012

is the going-in year for rates is not a justification to make “random” reductions in forecast costs

and would be contrary to the Commission‟s statutory obligation to approve just and reasonable

rates based on EDTI‟s prudent costs.45

Commission findings

92. The Towers Watson analysis showed that, on an overall basis, EDTI‟s non-union

positions are five per cent below the market median for target total direct compensation. The

42

Exhibit 208, EDTI argument, page 39, paragraph 121 43

Exhibit 204, UCA argument, page 9, paragraphs 24, 26 and 27. 44

Exhibit 211, EDTI reply argument, pages 19 and 20, paragraphs 58 to 62. 45

Exhibit 211, EDTI reply argument, page 18, paragraph 55.



Commission approves the escalation factor of four per cent for EDTI s non-union employees for

2012.

93. While the UCA stated that the Towers Watson report showed that the target total cash for

all EUI union positions is nine per cent over market, the Commission‟s review of the Towers

Watson report shows that the target total cash for all EDTI union positions is five per cent over

market.46 Applying a three per cent escalation in 2012 will still keep the target total cash for the

average EDTI union position within 10 per cent of the market median. The Commission finds the

salary escalation of three per cent for both CSU and IBEW union employees for 2012 to be

reasonable and approves the three per cent escalation factor rate as filed.

94. With respect to the $0.25 million salary adjustment for IBEW employees, the

Commission accepts EDTI‟s submission that the reclassification effort will give EDTI the

benefit of being able to use employees within a labour class interchangeably and this will be of

benefit to customers. The Commission approves the $0.25 million increase in total compensation

for 2012.

3.4 Cost escalations

95. As in previous EDTI GTA‟s, EDTI retained Dr. David Ryan of the University of Alberta

to provide forecast escalators to be used in the application. EDTI provided Dr. Ryan‟s Forecast

Values for Escalators for 2012 report in Appendix G-4 of the application. The following table

provides a summary of the historical and forecast values for the various escalators that were

recommended by Dr. Ryan:

Table 15. Summary of escalators

2008 (A) 2009 (A) 2010 (A) 2011 (F) 2012 (F)

Contractor costs 5.0% -3.2% 5.8% 4.0% 3.2%

Other costs 3.1% -0.1% 1.0% 2.2% 2.2%

Material costs 1.3% 2.7% -2.1% 1.2% 3.2%

Legend: (A) actual, (F) forecast

96. Dr. Ryan‟s recommended 2012 escalation factor of 3.2 per cent for contractor costs was

based on the Conference Board of Canada‟s medium-term forecast, as at July 19, 2011, for

growth in wages and salaries per employee in Alberta.

97. In developing the recommended escalation factor of 2.2 per cent for other costs, Dr. Ryan

calculated an average of the most recent forecast of the inflation rate for 2012 for Alberta from

the Conference Board of Canada, the Bank of Montreal, the TD Bank Financial Group, the Royal

Bank of Canada and the Canadian Imperial Bank of Commerce.

98. In developing the recommended forecast escalator for material costs, Dr. Ryan ran a

regression on the industrial price index for industrial electrical equipment (Statistics Canada

series number V53434263) and the consumer price index for Canada (Statistics Canada CanSIM

II Series V41693271) using actual data for the period 1997 to 2010. Dr. Ryan stated that there

was a strong and statistically significant relationship between these two Statistics Canada series.

Using this estimated relationship and a forecast of the consumer price index for Canada (from

46

Exhibit 78, Appendix G-2, 2011 Competitive Compensation and Benefits Analysis, Towers Watson, page 18.



the Conference Board of Canada‟s July 19, 2011 forecast) Dr. Ryan developed a forecast of the

industrial price index for 2011 and 2012. The growth in the forecast industrial price index from

2011 to 2012 was 3.2 per cent, which is Dr. Ryan‟s recommended escalation factor for material

costs.

99. While the interveners requested further information through information requests, none

of the interveners addressed any of the proposed escalators in either argument or reply argument.

Commission findings

100. The Commission has reviewed the report developed by Dr. Ryan and considers the

methodology utilized by Dr. Ryan and the recommended escalation factors for contractor,

material and other costs to be reasonable. The Commission approves the forecast escalation

factors for contractor, material and other costs as filed by EDTI.

3.5 Short-term incentive program

101. EDTI provided details of its short-term incentive (STI) program in sections 1.6.1.1.1 and

1.6.1.1.2 of the application.

102. In Decision 2010-505, EDTI was directed to reduce the financial performance measure of

its STI program from 20 per cent to 10 per cent. The Commission directed EDTI to reduce the

financial performance measure to 10 per cent in order to be consistent with previous directions

for other Alberta utilities. EDTI complied with this direction in the application and has based its

STI program on a 10 per cent relative weighting for the financial performance measure with the

remaining 90 per cent accounted for in EDTI‟s specific performance measures.47 EDTI stated

that the specific financial performance target is corporate net income, which is comprised of net

income measured at the EUI level.48

103. EDTI stated that, in accordance with Direction 14 in Decision 2010-505, any approved

STI amounts included in revenue requirement but not paid out to employees will be captured in a

STI deferral account and refunded back to customers.49

104. EDTI included $2.35 million in STI program costs in the distribution function revenue

requirement and $0.63 million in the transmission function revenue requirement.50

105. EDTI stated that employees are also eligible for supplemental STI incentives for

performance that achieves or exceeds pre-set stretch target financial performance. EDTI stated

that it did not include a forecast of any supplemental STI payouts in its revenue requirement and

that all supplemental STI payout amounts will be borne by EDTI‟s shareholder.51 EDTI also

refers to these supplemental STI incentive payments as “pool B payments.”52

106. Interveners addressed several concerns with EDTI‟s STI program in argument and reply

argument.

47




Exhibit 3, application, page 169, Table 1.6.3.4-2 and page 170, Table 1.6.3.4-3. 51


Exhibit 169, UCA-EDTI-113 (a).



107. The UCA stated that in previous decisions the Commission has ruled that the earnings

component of STI programs be based on the earnings of the utility and not the parent or

affiliates.53 In particular, the UCA noted Commission directions in Direct Energy Regulated

Services‟ (DERS) 2009/10/11 Default Rate Tariff application (Decision 2009-23854) and ATCO

Electric‟s 2011/12 GTA (Decision 2011-13455).56 The UCA went on to state that the 10 per cent

of EDTI‟s STI program related to EUI earnings is contrary to the principle that the earnings

measure of a STI program should be based on the earnings of the utility and that there is no

direct benefit to the regulated utility nor to the customers of the regulated utility. The UCA

submitted that STI costs related to the 10 per cent earnings component of the program should be

denied.57

108. In response, EDTI stated that its STI program does not raise the same concerns as the

ATCO Electric and DERS incentive plans because:

The net income component for EDTI‟s non-union staff at all levels is based on the same

10 per cent weighting.

Unlike ATCO Electric, individuals within EUI and EDTI management, including the

CEO of EUI, do not exercise discretion over the payouts for the STI program.

Over 90 per cent of EUI revenues are derived from regulated business.

109. EDTI also stated that the earnings component of its STI program should be based on

EUI‟s earnings because the STI program is EPCOR-wide and thus ensures that all EPCOR

employees are incented to find cost savings and performance improvements across all business

units. The financial performance measure does not bias the STI program towards any single

business unit, which would occur if the program was based on individual business unit

performance.58

110. EDTI stated that its STI program is consistent with previous Commission approvals

respecting EDTI‟s STI program under which the earnings measure has explicitly been based on

EUI‟s overall net income.59 EDTI went on to state that while the Commission directed EDTI to

reduce the weightings of the earnings component for 2011 in Decision 2010-505, it did not direct

EDTI to change the earnings measure from an EUI financial performance measure to an EDTI

measure.60 EDTI also stated that, consistent with the Commission‟s conclusions in paragraph 202

of Decision 2010-505, it would be unfair to change the STI program for the 2012 test year, given

that 2012 will almost be over by the time a decision is issued in this proceeding.61

111. In its reply argument, the UCA stated that, while EDTI attempted to differentiate itself

from the circumstances of DERS and ATCO Electric, the UCA noted that the Commission had

53

Exhibit 204, UCA argument, page 5, paragraph 9. 54

Decision 2009-238: Direct Energy Regulated Services, 2009/2010/2011 Default Rate Tariffs and Regulated

Rate Tariffs, Application No. 1600749, Proceeding ID. 149, December 3, 2009. 55

Decision 2011-134: ATCO Electric Ltd., 2011-2012 Phase I Distribution Tariff, 2011-2012 Transmission

Facility Owner Tariff, Application No. 1606228, Proceeding ID No. 650, April 13, 2011. 56

Exhibit 190, UCA evidence of Russ Bell, A11, lines 15-21. 57




Exhibit 211, EDTI reply argument, page 13, paragraph 40. 61






ordered that only financial goals related to the regulated business unit be included in DERS‟

incentive plan62 and that the Commission had ordered that the ATCO Electric variable pay

program be based solely on the financial results of ATCO Electric.63 The UCA submitted that,

because increased earnings of affiliates benefits shareholders of those companies but not the

regulated customers, any incentive plan that is based on corporate earnings should be funded by

the shareholder and not the customer.64

112. In respect of the pool B payments, the UCA submitted that, while EDTI confirmed that it

has not included any pool B payments in revenue requirement, it was concerned that EDTI will

include pool B payments in the actual results in determining utility return on equity (ROE) in

2012 and subsequent years. The UCA recommended that the Commission direct EDTI to

exclude all actual pool B payments from utility costs and the calculation of ROE in 2012 and

subsequent years.65

113. In response EDTI stated that it is unreasonable to exclude certain incentive costs from the

calculation of actual return as it would make the calculation of returns less meaningful because it

would no longer represent the actual return to the shareholder. Further, EDTI argued that the

UCA‟s recommendation would run counter to and would blunt the incentives that EDTI is

intended to have under PBR to find and implement efficiencies and cost savings.66

Commission findings

114. EDTI has complied with Commission directions from Decision 2010-505 by limiting the

financial component of its STI program to 10 per cent and by setting up a deferral account to

capture any forecast STI payments not actually paid out to employees.

115. The Commission acknowledges that EDTI‟s employees have been working to achieve the

performance measures in EDTI‟s STI program throughout 2012 and the year is almost over. The

Commission finds that it would be unfair to alter the terms of the STI program at this time.

Hence, for the purposes of this decision, the Commission approves the STI program and the STI

amounts included in revenue requirement for 2012.

116. However, the Commission notes that in previous decisions in respect of variable pay

programs, DERS and ATCO Electric have been directed to tie the net income component of their

respective variable pay programs to the net income of the utility itself and not to corporate net

income. The Commission considers that the findings in the ATCO Electric and DERS decisions

apply equally to EDTI.

117. The Commission also considers that an EDTI STI program based on the earnings of EUI

may violate the spirit and intent of EPCOR‟s Inter-Affiliate Code of Conduct. EPCOR‟s Inter-

Affiliate Code of Conduct “…attempts to anticipate and adjust for the potential misalignment of

interest between shareholders and Utility customers occasioned by Affiliate transactions...”67

62

Exhibit 209, UCA reply argument, page 4, paragraph 7. 63



Exhibit 204, UCA argument, pages 7 and 8, paragraphs 18 and 20. 66


Decision 2004-010: EPCOR Utilities Inc., Code of Conduct and Exemption Application, Application

No. 1316005, February 3, 2004, Appendix 1, EPCOR Group Inter-Affiliate Code of Conduct, Section 1.1.




EPCOR‟s Code of Conduct also requires utilities to demonstrate “...respect for the spirit and

intent behind the words by those individuals to whom the Code applies.”68

118. Accordingly, the Commission directs EDTI transmission to base the financial component

of its STI program for the purposes of its regulatory applications on the net income of EDTI for

2013 onward. EDTI distribution is not limited or restricted by the Commission in its

compensation practices, during the PBR term, including the terms of its STI program. Therefore,

this direction will not apply to EDTI‟s distribution function as its distribution function is now

under a performance based regulation regime beginning in 2013. However, the direction will still

apply to the transmission function and the Commission directs that the STI program for

transmission will be based on the net income of EDTI at the time of EDTI‟s next transmission

general tariff application.

119. In respect of the pool B payments, the Commission considers that any actual pool B

payments made to EDTI employees in 2012 and beyond should be treated as disallowed costs

and directs EDTI to deduct any pool B payments from EDTI‟s expenses when determining

EDTI‟s return on equity in 2012 for distribution and transmission, and for 2013 and beyond for

transmission.

3.6 Mid-term incentive program

120. EDTI provided details of the proposed mid-term incentive (MTI) program in

Section 1.6.1.1.3 of the application. EDTI stated that the MTI program is a new program,

established mid-2010, that was designed to foster alignment with EPCOR‟s long term business

strategy and objectives of reinvesting proceeds from the “sell down” of Capital Power

Corporation (CPC).69

121. EDTI stated that the MTI program only applies to its senior management and is set as a

percentage of base salary with target payouts ranging from 20 per cent to 100 per cent of base

salary for director, vice president and executive positions.70 EDTI included $340,000 in MTI

program costs in its distribution revenue requirement and $80,000 in its transmission revenue

requirement.71 EDTI stated that there is only one metric in the program: a compounded property,

plant and equipment (PP&E) growth metric that is a composite measure of the period to period

changes in net PP&E, additions of intangible assets, long term receivables and lease assets.72

122. Interveners raised a number of issues with EDTI‟s proposed MTI program in argument

and reply argument.

123. The UCA stated that there is no reference to any operational performance metrics or to

effective or efficient capital spending or that growth in PP&E is a customer focused goal. The

UCA submitted that the proposed MTI program incents behavior that is consistent with the

Averch-Johnson (or “gold plating”) effect, which is to simply increase investment in assets.73

The UCA also pointed out that the MTI program was based on EUI assets, not EDTI assets.

68

Decision 2004-010, Appendix 1, EPCOR Group Inter-Affiliate Code of Conduct, Section 1.1. 69



Exhibit 3, application, page 171, tables 1.6.4-2 and 1.6.4-3 72


Exhibit 204, UCA argument, page 6, paragraph 14.



Thus, there was no indication that customers benefit from the MTI program and the primary

beneficiary of the program was EDTI‟s shareholder, not customers.74 The UCA also submitted

that EDTI‟s proposed MTI program violated previous rulings on incentive compensation in that

there was no operational benefit included in the program and the program was based on EUI

performance and not EDTI performance.75 For those reasons the UCA recommended that the

costs of the MTI program be removed from revenue requirement.

124. The CCA stated that it shared the UCA‟s concerns respecting the MTI program providing

incentives to increase investment in assets and with the MTI program being based on growth in

EUI capital not EDTI capital. In addition, the CCA submitted that any MTI associated with

reinvestment of proceeds from the sale of CPC assets should be part of the transaction costs of

such investments and should not be included in EDTI‟s 2012 revenue requirement. Further, the

CCA stated that, in the absence of any reference to efficient capital spending in the formulation

of the MTI program, any MTI costs that are based on the growth of EDTI‟s assets should be

disallowed since such payments would not benefit EDTI‟s customers.76

125. EDTI submitted that the MTI program provides an incentive for management to invest in

capital to achieve the following benefits for customers:

assist in regaining the benefits of scale economies that customers enjoyed prior to the

CPC transaction

increase the borrowing capacity and access to capital available to EDTI (and EUI‟s other

subsidiaries)

allow for sharing of best practices among employees of the EPCOR group

126. EDTI stated that the MTI program is an important component of its compensation that is

required to keep compensation levels competitive and retain employees and, without it, EDTI‟s

total direct compensation for officers and senior management would be significantly below

market median and uncompetitive. EDTI stated that the MTI program is an essential component

of the overall compensation paid to executive and key leadership employees.77

127. In response to the UCA‟s concerns, EDTI stated that any incentive to place capital

unnecessarily and imprudently is mitigated by its strong governance processes.78 EDTI also

stated that there are many measures and processes in place to ensure that there is no Averch-

Johnson effect; not the least of which is the regulatory risk that capital expenditures will be

found to be imprudent by the Commission.79

Commission findings

128. The Commission is concerned with the structure of the new MTI program proposed by

EDTI. Specifically, because the MTI program is based on assets, and there is no assurance that

the assets will be required for the provision of utility service, the Commission finds that the MTI

program creates an incentive to invest in assets that may not be required for the provision of

74



Exhibit 207, CCA argument, pages 32 and 33, paragraphs 123 to 126. 77






utility service. The Commission discusses additional concerns with EDTI‟s MTI program in

Section 6.2.1.3 of this decision. For all of these reasons, the Commission directs EDTI to remove

the MTI costs from its 2012 revenue requirement in its compliance filing.

129. Should EDTI choose to implement the MTI program and make incentive payments to

eligible employees in 2012, the Commission directs EDTI to remove the cost of those payments

from its actual 2012 expenses when determining its actual return on equity for 2012.

3.7 Cost of debt

130. The Commission advises parties that Section 9 of this decision contains a dissent with

respect to the majority‟s findings on cost of debt.

131. In the application, EDTI applied for approval of its 2012 cost of new long-term debt,

which it estimated to be 4.45 per cent for its distribution function and 5.25 per cent for its

transmission function. For each of its distribution and transmission functions, EDTI is

forecasting to issue $35 million in long-term debt for 2012.80

132. In its application, EDTI submitted its cost of new long-term debt calculations attached as

Appendix G-10. In AUC-EDTI-54-Attachment 1, EDTI updated its cost of new long-term debt

calculations to reflect changes in capital market conditions, interest rate expectations and credit

quality considerations. Table 16 shows the derivation of the estimated 2012 cost of new long-

term debt for distribution (ED) and transmission (ET) based on the updated information, as filed

by EDTI.81

Table 16. Estimated ED/ET 2012 stand-alone 2012 cost of long-term debt

ED ET

Yield on ten-year Government of Canada Bond 2.30% 2.30%

Plus: maturity premium 0.60 0.60

Plus: credit risk premium 1.50 2.30

Plus: financing cost .05 .05

Estimated 2012 stand-alone costs of new long-term debt 4.45% 5.25%

133. The first component of EDTI‟s calculation, the forecast yield on the 2012 10-year

Government of Canada bonds, has been established by reference to data from Consensus

Forecasts (Consensus). The second and third components are maturity and credit risk premiums.

The final component represents the allowance made for financing costs.82

134. With respect to EDTI‟s proposed cost of new long-term debt to be included in revenue

requirement, various issues were raised by interested parties and the Commission. The views of

the parties and Commission findings, with respect to EDTI‟s cost of new long-term debt, will be

discussed in the decision as follows:

80

Exhibit 3, application, page 1472, paragraphs 4978 and 4981. 81

Exhibit 167.13, AUC-EDTI-54, Attachment 1. 82

Exhibit 167.13, AUC-EDTI-54, Attachment 1.



the impact of the letter from Dominion Bond Rating Service (DBRS) on the credit rating

of transmission

the indicative corporate bond spread that should be used by distribution and transmission

the use of Consensus Forecasts as opposed to actual Government of Canada bond yield

the impact of Alberta Capital Financing Authority (ACFA)

3.7.1 The DBRS letter

135. EDTI provided letters from DBRS dated December 13, 2011 that assigned an “indicative

long term credit rating of A (low) for ED [distribution] and BBB (high) for ET [transmission].”83

The letters are not actual credit ratings and reflect risks of the stand-alone operations for

distribution and transmission and assume no guarantee of debt or explicit credit support from

EPCOR Utilities Inc. or the City. The ratings represented a downgrade for transmission from

A (low) to BBB (high) but the rating for distribution remained the same at A (low) as provided

by DBRS at the time EDTI‟s application was filed.84 EDTI proposed that this raised the cost of

debt for transmission vis-à-vis distribution.

136. The CCA raised concerns with transmission‟s bond rating downgrade on several counts.

The proposed downgrade was triggered by the Heartland project, which is eventually going to be

transferred to an affiliate and the CCA did not consider it fair that EDTI‟s customers should bear

the costs of a temporary downgrade due to an affiliate project being held temporarily in EDTI‟s

books.85 The CCA based its position on EDTI‟s response to AUC-EDTI-61,86 where EDTI said

that the Heartland project was currently being treated in a manner similar to other EDTI AESO-

directed capital projects, but it will eventually be transferred to a new TFO that will own and

operate the Heartland facilities and be regulated by the Commission. In its response, EDTI also

expressed its view that the downgrade was temporary and expected some improvement once the

Heartland project is transferred to the new TFO that will own and operate it.

137. To make its argument, the CCA further relied on the response to CCA-EDTI-10187 stating

that it is not clear from the DBRS letter that DBRS understood that Heartland will be transferred

from transmission‟s books to an affiliate and that any deterioration in credit is temporary. It also

argued that DBRS does not seem to have looked at transmission‟s credit beyond the date at

which the assessment was made because no pro forma financial statements had been provided by

EDTI beyond 2012.88 Refuting the CCA‟s position, EDTI quoted from the DBRS letter:

The magnitude and size of potential transmission projects, such as the recently approved

Heartland Transmission project, could further expose the entity to both construction and

execution risk and is likely to put significant pressure on the credit metrics and

potentially the credit rating in the future, depending on the size of the expenditures and

how they are financed.89 (emphasis added by EDTI)

83

Exhibit 150.10, CCA-EDTI-22, Attachment 5. 84

Exhibit 87, application, Appendix G-11 for distribution and Exhibit 88, Appendix G12 for transmission. 85

Exhibit 191.00, CCA argument, page 29, paragraph 108. 86

Exhibit 186, AUC-EDTI-61. 87

Exhibit 188, CCA-EDTI-101. 88

Exhibit 191, CCA evidence, page 5, paragraph 5. 89




138. Based upon the letter, EDTI argued that projects like Heartland could be a concern in the

future, but are not a reason for, or a contributing factor to, the “downgrade” that occurred in

December 2011. Since the rating considers the risks and returns of the transmission function, it is

relevant to consider the stand-alone BBB (high) credit rating of transmission.

139. The CCA countered this argument in its reply stating:90

CCA submits there is no evidence that DBRS considered any other large scale

transmission projects when it triggered the credit downgrade for ET. Although EDTI is

urging the Commission to speculate that DBRS may have considered other large scale,

transmission projects in addition to Heartland, based on the vague language in the DBRS

letter, there is no evidence of ET's plans to embark on any other large scale transmission

projects.

140. EDTI also argued that the CCA provided no evidence to support its argument that EDTI

knew that a downgrade was a possibility or the steps it could have taken to forestall the

downgrade.

Commission findings

141. With respect to the CCA‟s submission that customers should not pay the costs of a

temporary “downgrade” because EDTI has claimed that the Heartland assets will eventually be

transferred to a new TFO, the Commission considers that, because no such transfer has occurred

at this time, the Commission will assess the Heartland project like any other AESO-directed

capital project. Costs related to the Heartland project, deemed fair and reasonable, will be taken

into account in the calculation of EDTI‟s cost of debt and will not be considered temporary in

nature.

142. In keeping with past Commission decisions, for the purposes of this decision, the

Commission has considered the cost of debt for distribution and transmission on a stand-alone

basis. EDTI submitted letters from DBRS providing credit ratings for distribution and

transmission on a stand-alone basis. With respect to transmission, the letter from DBRS

indicated that transmission would be “downgraded” from an A (low) to BBB (high). As such,

EDTI submitted its cost of debt should be increased to recognize transmission‟s higher credit

risk.

143. The Commission has reviewed the letters from DBRS. Having reviewed the response to

CCA-EDTI-101, the Commission finds that the letters do not constitute a full credit rating

assessment because DBRS did not have access to EDTI‟s pro forma financial statements beyond

2012. The Commission also finds that the letter with respect to transmission is vague with

regards to the causes of the “downgrade” and has noted an inconsistency in EDTI‟s argument

with regards to Heartland‟s role in the “downgrade.” Specifically, during the course of the

proceeding, EDTI indicated that transmission‟s credit rating would improve once the Heartland

assets are transferred to a new TFO that will own and operate it. However, in argument, EDTI

indicated that Heartland could cause a further “downgrade” in the future and is not a cause for

the current “downgrade.”91

90

Exhibit 210, CCA reply, page 7, paragraph 26. 91

Exhibit 186, AUC-EDTI-61 d) & Exhibit 0208, EDTI final argument, page 143, paragraph 147.



144. Moreover, in the last Generic Cost of Capital proceeding Decision 2011-474,92 the

Commission set the equity ratios for utilities so as to ensure an A-range credit rating. Given the

lack of persuasive information in the DBRS letter, the Commission does not consider that there

is sufficient evidence to indicate that the equity thickness established for transmission and

distribution in Decision 2011-474 would not be sufficient to ensure an A-range credit rating.

Further, the Commission notes that, at the time of Decision 2011-474, the Heartland project was

well known and EDTI could have addressed the impact of it on its credit rating at that time.

145. Consequently, the Commission does not find the credit rating provided in the DBRS

letter for transmission sufficient to justify a “downgrade” to the stand-alone credit rating of

transmission as proposed by EDTI.

146. For all of these reasons, the Commission will not approve transmission‟s cost of debt

based upon the credit rating proposed in the letter from DBRS. For the purposes of this decision,

the Commission will continue to apply the credit rating of A (low) for transmission; the rating

issued by DBRS prior to the “downgrade.” The Commission accepts distribution‟s credit rating

of A (low) as proposed in the application.

3.7.2 Indicative corporate bond spread for EDTI

147. In the application, EDTI calculated the cost of debt for its 2007, 2008, 2009, 2010 and

2011 issues using the spread for Fortis for its credit risk premium as directed by the

Commission.93 However, in accordance with a proposal by the Commission in Decision

2010-50594 for its 2012 cost of debt, EDTI used the average spread of a group of comparable

utilities. For its calculations, EDTI used the long-term credit risk premiums estimated by the

National Bank and TD Securities for a group of operating companies defined by them as utilities

or pipelines and which have DBRS ratings of A (low) and BBB (high). EDTI submitted a

proposed credit spread of 150 basis points for distribution and 230 basis points for

transmission.95

148. EDTI expressed its preference for this method because estimation using single data points

can be problematic as individual observations are more likely to be materially skewed by

individual company or issue-specific circumstances.96

149. In CCA-EDTI-81,97 the CCA presented information regarding the Fortis credit spread.

EDTI responded that it had relied on the approach suggested by the Commission in using the

credit spread of a group of comparable utilities and, furthermore, the CCA data on the Fortis

credit spread was not reliable.

92

Decision 2011-474: 2011 Generic Cost of Capital, Application No. 1606549, Proceeding ID No. 833,

December 8, 2011, page 35, paragraph 194 and Decision 2009-216: 2009 Generic Cost of Capital, Application

No. 1578571, Proceeding ID. 85, November 12, 2009page 88, paragraph 334. 93

Decision 2010-505, page 33, paragraph 179. 94

Exhibit 168.01, CCA-EDTI-81. 95

Exhibit 167.13, AUC-EDTI-54, Attachment 1, page 4. 96

Exhibit 168.01, CCA-EDTI-81. 97

Exhibit 168.01, CCA-EDTI-81.





Commission findings

150. While the CCA explored the credit spread for Fortis, which was previously used as a

proxy credit spread for EDTI, the Commission prefers a credit spread based on the credit spreads

for a group of comparative companies of equivalent risk.

151. However, while the Commission accepts the methodology for estimating the credit

spread, it does not accept the credit spread calculated for transmission because it was calculated

using the credit spread of utilities with BBB (high) ratings. Given that the Commission did not

accept the credit rating “downgrade” for transmission, as proposed by EDTI, the Commission

finds that it would be inconsistent to use a credit spread that was based on utilities with BBB

(high) ratings.

152. The Commission accepts EDTI‟s proposal that the credit spread for distribution be 150

basis points, based on its analysis of comparative companies with an A (low) credit rating. Given

the Commission‟s finding with respect to the credit spread for transmission, the Commission

directs EDTI to use the 150 basis point credit spread for transmission.

3.7.3 Government of Canada bond yield

153. EDTI submitted information on the Consensus forecast bond yield for a 10-year bond.

The Commission has assessed the Consensus forecasts used by EDTI by comparing it to actual

Government of Canada long-term bond yields. In AUC-EDTI-54 Attachment 1, EDTI submitted

the Consensus forecasts of June 2012 (2.1 per cent) and March 2013 (2.5 per cent).

Commission findings

154. As 2012 is nearing its end, the Commission considers that it is more reliable to use the

actual Government of Canada long-term bond yields as opposed to the Consensus forecasts. In

keeping with the Commission‟s practice of using the mid-year convention98 for EDTI‟s debt

matters, the Commission has compared the June 2012 Consensus Forecasts bond yield with the

actual Government of Canada long-term bond yield. In June 2012, the actual Government of

Canada long-term bond yield was 2.32 per cent. Using the Consensus forecast bond yield for

June 2012 with a maturity premium added in, EDTI‟s yield on a long-term bond would be

2.90 per cent. The Commission finds that the Consensus forecast overstates the bond yield by

58 basis points. Based on the evidence in this proceeding, the Commission considers that the

Consensus forecasts relied on by EDTI are not a reasonable predictor of the actual Government

of Canada bond yield in this case.

155. The Commission directs EDTI, in its compliance filing, to calculate the cost of its 2012

debt issues using the Government of Canada long-term bond yield for the month of June 2012

(2.32 per cent) which includes the maturity premium.

3.7.4 Access to ACFA financing

156. EDTI is owned by the City of Edmonton (the City). The City is eligible to access

financing through ACFA. This source of financing is cheaper than obtaining debt from the

marketplace because it takes advantage of the province of Alberta‟s AAA credit rating. EDTI has

98




previously submitted that it cannot obtain ACFA financing because the City declined to provide

it to EDTI.99

157. In Decision 2010-505,100 the Commission directed EDTI to advise the Commission on

whether the City of Edmonton would make available ACFA financing in its next general tariff

application. In the application, EDTI submitted a letter from the City,101 which conveyed that the

City‟s position has not changed and outlined three reasons why the City is not prepared to

provide ACFA funding to EDTI.

158. First, the City stated that EUI was established as an independent company and if the City

were to procure ACFA financing on EUI‟s behalf, city council would be forced to become

actively involved in the management of EUI. Second, the City voiced its concerns about the

effect the additional debt would have on the City‟s bond and credit rating and the consequent

adverse impact on the City and Edmonton taxpayers. Third, the City discussed the additional

administrative burden that would be created for the City if it were to borrow on EUI‟s behalf.

159. The UCA stated that, “[c]ustomers should not be required to pay the higher cost of debt

simply because EDTI‟s sole shareholder, the City has chosen not to allow EDTI access to ACFA

financing.”102

160. The UCA argued further that EDTI has a non-taxable status because of its municipal

ownership as a result of which it was awarded a two per cent increase in common equity.103 Since

customers are paying the cost of an increased common equity ratio arising from EDTI‟s non

taxable status by paying higher rates, customers should also benefit from lower debt rates by

having access to the AAA credit rating that ACFA financing provides.

161. The UCA compared EDTI with ENMAX, noting that its sole shareholder, the City of

Calgary, provides ENMAX with access to ACFA financing, thereby enabling it to obtain debt at

lower rates than if it had issued debt on its own.

162. The UCA acknowledged the Commission cannot direct EDTI to secure its debt financing

from a specific source, but asserts that the Commission can determine the costs related to debt to

be included in just and reasonable rates. There is a 1.75 per cent spread between ACFA financing

and the cost of debt EDTI sources in the market. ENMAX pays a 25 basis point premium to The

City of Calgary for providing it with access to ACFA financing. Based upon these

considerations, the UCA recommended that the average cost of debt for EDTI be reduced by

1.50 per cent to approximate the impact of ACFA financing.104

163. In its argument, the UCA recommended that for purposes of consistency all items arising

from municipal ownership should be included in rates, including the impact of ACFA

financing.105

99



Exhibit 86, application, Appendix G-4, 102



Exhibit 190.02, evidence of Russ Bell, A19. 105

Exhibit 204, UCA argument, page 11, paragraph 40.



164. EDTI refuted the UCA‟s proposed 1.50 per cent downward adjustment on the grounds

that the recommendation would constitute retroactive ratemaking and confuses the cost of new

debt with the average cost of total debt. EDTI also argued that basing debt on the ACFA rate

violated the stand-alone principle which dictates that EDTI be treated as an entity entirely

separate from its parent or any other activities of the entity or corporation.106 In its rebuttal

evidence, EDTI stated:107

...In order for him [Mr. Bell] to logically sustain the position that ACFA cost rates should

be deemed to the distribution and transmission operations of EDTI, Mr. Bell would have

to “look upstream” through multiple layers of ownership. The proposition that ACFA

cost rates which cannot even be accessed by either EUI or EDTI should be deemed to be

available to the stand-alone distribution and transmission functions of EDTI is therefore

an obvious violation of the stand-alone concept.

165. In response to the UCA‟s argument that EDTI only enjoys the benefit of municipal

ownership by enjoying a higher common equity ratio, EDTI discussed the benefit to EDTI‟s

customers of lower rates because its revenue requirement does not include an allowance for

income taxes.

Commission findings

166. The UCA recommended that EDTI‟s average cost of debt be reduced by 1.50 per cent to

reflect the spread between EDTI‟s cost of debt and ACFA financing, net of an adjustment for

financing costs. The recommendation involves two issues; whether the ACFA financing rate

should be used as a reference for EDTI‟s interest rates and if so, whether the 1.50 per cent

reduction proposed by the UCA is a reasonable adjustment.

167. Although the Commission can deem a lower cost of debt on a go forward basis on newly

issued debt, the Commission does not consider it reasonable to do so. The Commission has

reviewed the letter from the City regarding its reasons for not providing ACFA financing to

EDTI. The Commission acknowledges the City‟s reasons for not providing ACFA funding to

EDTI, and recognizes that the City has made a policy decision on behalf of its constituents. The

Commission does not have sufficient evidence to conclude that the City‟s reasons for denying

ACFA funding to EDTI are unreasonable. If the City had chosen to provide ACFA funding to

EDTI (as The City of Calgary has done for ENMAX) the Commission would recognize the

lower rate in EDTI‟s revenue requirement, because the City would have made a policy decision

to fund its investment at a rate lower than the rate applicable to a utility with A (low) credit

rating. However, the Commission is not prepared to deem a lower cost of debt, simply because

the City may provide ACFA funding.

168. The Commission considers that the UCA‟s recommendation would be contrary to the

stand-alone principle. With respect to other aspects of EDTI‟s cost of debt, the Commission has

assessed distribution and transmission‟s cost of debt on a stand-alone basis.

169. As the Commission has determined that the ACFA financing rate should be not be used

as a reference for EDTI‟s cost of debt, the Commission will not direct a 1.50 per cent reduction

to EDTI‟s cost of debt as requested by the UCA.

106

Exhibit 203.05, rebuttal evidence of Dr. Evans, page 3 and 4. 107

Exhibit 203.05, rebuttal evidence of Dr. Evans, page 5.



3.8 Property, business and linear tax deferral account

170. The deferral account for property, business and linear taxes was approved in Decision

2008-125108 because the City was in the process of implementing significant changes to its tax

regime, and as a result, significant fluctuations in mill rates and assessment values were

expected.

171. This deferral account captures variances between forecast and actual property, linear and

business taxes. With the changes in the tax regime, the city intended to eliminate business tax

revenue and recover an equal amount of revenue from the non-residential property tax base. As a

result, EDTI‟s business tax decreased over the 2008 to 2011 period, to nil in 2012, while its

property taxes and linear taxes increased significantly.

172. In its application, EDTI noted that the City has now completed its property and business

transition plan.109

173. Table 17 below sets out a summary of EDTI‟s historical and forecast property, business

and linear taxes in respect of its distribution and transmission functions.

Table 17. Distribution and transmission property, business and linear taxes 2009-2012110

Sec A 2009 (A)

B 2010 (D)

C 2010 (A)

D 2011 (D)

E 2011 (UF)

F 2012 (F)

1 11.1.1 Distribution-property, business and linear taxes

4.44 4.74 5.09 5.25 5.82 6.69

2 11.1.2 Transmission-property, business and linear taxes

3.96 4.18 4.74 5.04 5.72 6.89

Legend: (A) actual, (D) decision, (UF) updated forecast, (F) forecast

174. EDTI submitted111 that the historical forecast-to-actual variances demonstrate that there

remains a substantial level of uncertainty in this cost area. Accordingly, it requested a

continuation of EDTI‟s distribution and transmission property, business and linear tax deferral

accounts for the 2012 test period, on the basis approved in Decision 2008-125.112

Commission findings

175. The variances discussed by EDTI are for the years 2009 to 2011; a period where

uncertainty was expected due to the City‟s transition plans. The City has completed its transition

plans in its tax regimes. The Commission finds that the variances cited by EDTI do not make a

compelling case for the continuation of the deferral account, now that the transition has ended.

Consequently, the Commission finds that this deferral account is no longer warranted.

176. The Commission finds the forecast distribution and transmission property, business, and

linear taxes to be reasonable and approves the 2012 forecast as filed.

108

Decision 2008-125: EPCOR Distribution & Transmission Inc., 2007-2009 Distribution Tariff, 2007-2009

Transmission Facility Owners Tariff, Code of Conduct Exemption, Application No. 1558686, Proceeding

ID. 14, December 3, 2008, page 15. 109


Exhibit 3, application, page 952, Table 11.1-1. 111


Decision 2008-125, page 12, Section 4.4.1




3.9 Self-insurance reserve account

177. In the application, EDTI is requesting approval for the continuation of its distribution and

transmission self-insurance reserve account (SIR) for the 2012 test period. By way of its SIR,

EDTI is seeking approval for those costs that meet the criteria set out in EDTI‟s Procedure for

Claims against Self-Insurance Reserve approved by the Commission in decisions 2004-067113

and 2006-054,114 copies of which are attached as Appendix C-5 and Appendix C-6 in the

application.

178. The tables below summarize EDTI‟s distribution and transmission self-insurance reserve

accounts.

Table 18. Distribution self-insurance reserve accounts

Deferral account A

2009 (A) B

2010 (D) C

2010 (A) D

2011 (D) E

2011 (UF) F

2012 (F)

1 SIR forecast - - - - - -

2 SIR actual - - 0.11 - (0.11) -

3 SIR true-up - (0.11) 0.11 -

4 Total - - - - - -


Table 19. Transmission self-insurance reserve accounts

Deferral account A

2009 (A) B

2010 (D) C

2010 (A) D

2011 (D) E

2011 (UF) F

2012 (F)

1 SIR forecast - - - - - -

2 SIR actual - - 0.11 - 0.35 -

3 SIR true-up - (0.11) (0.35) 0.46

4 Total - - - - - 0.46


179. The balance for the distribution SIR account for 2012 was zero and EDTI made no

forecasts for the 2012 test period.

180. EDTI submitted that it had experienced three incidents that qualified to be claimed

against its transmission SIR account for 2012. They were a CV-5 Cable termination failure, the

Victoria Substation Insulated Bus Failure and the Rossdale Capacitor Bank Failure.

181. With regards to the CV-5 cable termination, EDTI incurred $0.11 million in costs in

2010, of which $0.04 million was an expenditure on capital repair which will be capitalized. As

such, in its compliance filing EDTI stated it would reduce the 2010 SIR claim to $0.07 million. It

forecasted an additional $0.06 million for 2011 in costs relating to further repair and

113

Decision 2004-067: EPCOR Distribution Inc., 2004 Distribution Tariff Application, Part B: 2004 Final

Distribution Tariff, Application No. 1306821, August 13, 2004 114

Decision 2006-054: EPCOR Transmission Inc., 2005/2006 Transmission Facility Owner Tariff, Application

No. 1389884 and EPCOR Distribution Inc., 2005/2006 Distribution Tariff – Phase I, Application No. 1389885,

June 15, 2006.



investigation of the failure. It also incurred $0.33 million in additional capital repair costs of

which an insurance claim of $0.10 million has been made. If successful, this amount will be

included in the SIR on an actual basis.

182. The Victoria Substation Insulated Bus Failure cost EDTI $0.18 million in 2011 and EDTI

plans to pursue “cost recovery” against the original project consultants and contractors because

the bus failed prematurely.115 The Rossdale Capacitor Bank Failure cost EDTI $0.11 million in

repair activities.116 The CCA raised issue with $0.19 million of the $0.46 million included as SIR

claims in EDTI‟s transmission reserve account because they are internal costs comprised of

salary, vehicle and labour costs and should be removed from the SIR recovery process to prevent

double counting. The CCA argued that, as the definition of costs in EDTI‟s SIR policy does not

specifically exclude the inclusion of internal costs such as labour costs,117 these costs would be

recovered twice: once through its O&M expense in the revenue requirement and again through

the SIR. The CCA recommended that EDTI‟s SIR policy be amended to specifically state that

only incremental operating costs directly associated with the SIR event should be included for

recovery through the SIR mechanism and internal costs (labour, material), which normally form

part of the revenue requirement, should not be a part of the SIR claim.118

183. EDTI refuted the CCA‟s position by stating that “CCA‟s position is based upon a

fundamental misunderstanding about the costs embedded in rates.”119 EDTI also argued that the

fact that it does not differentiate between internal and any other costs does not mean that EDTI is

recovering costs through its SIR claim that are already included in its revenue requirement. In its

argument, EDTI elaborated:

EDTI‟s repair costs included in its revenue requirement are based on a three-year

historical average forecasting approach, and no SIR claim related costs are included in

the historical amounts on which the forecast is based. There are no costs embedded in the

2012 Forecast for SIR expenses, whether internal or external. The costs of any internal

labour time spent on a SIR event in any given year would be incurred in that year, but no

allowance has been made in the Revenue Requirement for that expense. Where there is a

SIR event, EDTI incurs costs in addition to those forecast in the Revenue Requirement

and EDTI will have to find ways to offset the need to divert internal resources to address

the SIR event, such as by hiring contractors or incurring overtime. The SIR expense is

ultimately recovered through the SIR process.120

184. EDTI further emphasized that, without the SIR process, EDTI would have to attempt to

forecast repair costs related to unforeseeable events, which would result in a higher forecast of

repair costs than currently reflected in EDTI‟s application. Therefore, the SIR process is

necessary and reasonable.

115



Exhibit 207, CCA argument, page 19, paragraph 68. 118

Exhibit 207, CCA argument, page 19, paragraph 69. 119





Commission findings

185. The Commission is satisfied with EDTI‟s assertion that it does not double count self-

insurance costs. In reaching its conclusion, the Commission accepts the explanation in response

to CCA-EDTI-100(b) quoted below.

… There is no double counting of internal costs if EDTI proposes to collect these costs

through the SIR account. If a SIR claim is recorded the costs are transferred from the

associated repair cost category into the SIR claim and are therefore not included in the

Actual costs in the particular repair cost category. This also ensures that any repair

forecasts that are based on the use of a 3 year average do not include these costs in

EDTI‟s average based repair cost forecasts (as described in section 1.5.3.1), which would

result in a higher Forecast of repair costs for the test years during which those incident

costs are included in the average.”

186. The Commission approves the continuation of EDTI‟s SIR account for 2012 and will not

require EDTI to amend its SIR policy at this time.

3.10 Depreciation

187. In the application, EDTI stated that it prepared the application using the direct life

method (DLM) for depreciation first approved for use by the distribution and transmission

functions in Decision 2006-054 (respecting assets other than vehicles) and Decision 2008-125

(respecting vehicles). The applied for depreciation amounts for distribution and transmission are

summarized in the table below:

Table 20. Depreciation expense by asset function 2011-2012 ($ millions)

Asset function 2011(D) 2011 (UF) 2012 (F)

Distribution function

Wires 19.00 19.43 21.20

Substation 1.15 1.23 1.58

Misc. 1.76 1.83 1.90

Administration 4.34 4.42 3.87

Customer contributions (3.28) (3.57) (3.58)

Reserve imbalance 0.39 0.39 0.39

Vehicles (mobile equipment) 2.04 2.01 2.10

Total 25.40 25.73 27.46

Transmission function

Transmission 4.08 4.12 4.69

Substation 9.26 9.57 10.58

Administration 0.10 0.10 0.16

Contributed capital (0.73) (1.02) (1.46)

Reserve imbalance (0.34) (0.34) (0.34)

Vehicles 0.23 0.21 0.27

Total 12.59 12.62 13.91

Legend: (D) decision, (UF) updated forecast (F) forecast Source: Application, Table 16.0-1 (distribution), Table 16.0-2 (transmission)



188. EDTI further submitted that:121

Under DLM, changes in annual depreciation expense in a given asset category are due

solely to additions and planned (as opposed to actual, physical) retirements in that

category. For all years up to and including 2011, consistent with one of the fundamental

premises of DLM, the service lives for all assets have not been changed from those

approved by the Commission in Decision 2008-125.

and

In 2011, EDTI conducted a review of the reasonableness of asset service lives used to

calculate depreciation and as a result of this review, EDTI is proposing to adjust the

useful lives associated with a number of asset categories. EDTI engaged an external

depreciation expert from Gannet Fleming to review and advise on the appropriateness of

the asset lives of all of its distribution and transmission asset categories included in

EDTI‟s depreciation model.

189. EDTI proposed to implement the recommended changes to asset service lives on a

prospective basis by applying the adjusted depreciation rates for 2012 and future asset additions.

EDTI stated that implementing the changes on a retroactive basis would be administratively

complex and in an effort to minimize the level of effort required to implement the changes, chose

the prospective approach.

190. In AUC-EDTI-05, the Commission asked why the new rates were being applied only to

new assets when at the time of the original adoption of the DLM method the record had indicated

that extraordinary events, such as changes in useful lives, would be applied prospectively and

asked what the impact on revenue requirement would be.122

191. In response to the Commission‟s request, EDTI clarified that the proposed

implementation for new assets is simpler and that the impact on return is minor for both

distribution ($0.04 million increase for 2012) and transmission ($0.00 million increase for 2012).

However, for the distribution function, EDTI stated that retroactive application of the new

service lives would have reduced the amount of depreciation collected each year by

$1.01 million and would have extended the overall collection period.

192. The Commission also enquired in AUC-EDTI-56 about the additional work that had been

done with respect to the transition of asset values to IFRS and the possibility of changing the

basis of depreciation for regulatory purposes. EDTI responded:

On a go forward basis a portion of the retirement data generated for IFRS reporting of

capital assets could be used to record retirements for regulatory purposes if there were to

be a change in the depreciation method used by EDTI in the future. The fact that an

actual retirement has occurred and the vintage of the actual asset retired could be used by

EDTI to record an actual retirement for regulatory purposes.123

121

Exhibit 3, application paragraph 4956 and 4957. 122

Exhibit 148.02, AUC-EDTI-5(b). 123

Exhibit 167.02, AUC-EDTI-56(c).



Commission findings

193. The Commission has reviewed the changes in depreciation rates and the affected asset

classes. For asset classes, such as meters where there has been a change in technology such that

useful lives differ, the Commission finds that it is reasonable to adjust the asset lives on a

prospective basis by creating a new asset class. Given the affected asset classes and the small

impact on revenue requirement, the Commission accepts the implementation of the change in

asset service lives on a prospective basis as proposed by EDTI. The Commission cautions EDTI

that should extraordinary events, such as the need to change the useful life of assets, occur in the

future a change from the DLM may be necessary.

3.11 International Financial Reporting Standards

194. In Decision 2010-505, the Commission approved the 2011 implementation of

International Financial Reporting Standards (IFRS) along with the creation of a related deferral

account as follows:

261. … The Commission recognizes that the final IFRS requirements may not be yet

determined and for this reason a deferral account would allow the impacts from any

unforeseen adjustments to be collected, reviewed and addressed. Given that the impacts

may be material and not have balance impacts on the parties, the Commission directs that

a deferral account should be created for any adjustments resulting from the transition to

IFRS compliance.

262. The Commission approves EDTI‟s proposed adoption of IFRS in 2011. If EDTI

does not adopt IFRS on January 1, 2011, then the impact on revenue requirement of the

retention of Canadian GAPP account shall be included in the IFRS deferral account, with

its disposition to be addressed in a future EDTI application.124

195. EDTI stated that it had prepared its 2011 updated forecast and 2012 test year forecast in

accordance with AUC Rule 026: Rule Regarding Regulatory Account Procedures Pertaining to

the Implementation of the International Financial Reporting Standards.

196. The CCA indicated that the Canadian Accounting Standards Board had delayed the

deadline for implementation of IFRS for entities with rate-regulated activities from January 1,

2012 to January1, 2013. The CCA suggested that further changes to IFRS for rate-regulated

entities may be imminent.

197. The CCA submitted that the existing IFRS deferral account would capture any

differences arising from the yet-to-be finalized IFRS applicable to entities with rate-regulated

operations; however this would only apply to 2011 as EDTI should be directed to re-file its 2012

test year to reflect the revised IFRS standards.125 The CCA argued that IFRS impacts were

significant and the International Accounting Standards Board (IASB) may allow rate-regulated

entities to continue pre-changeover accounting practices so that the impacts on affected accounts

could be reversed.126

124

Decision 2010-505, pages 45 - 46, paragraphs 262 – 262. 125

Exhibit 191.01, CCA intervener evidence, pages 25-27, paragraphs 67-71. 126

Exhibit 201.01, CCA argument, page 39, paragraphs 146-149.

http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Documents/Rule026.pdf



198. EDTI challenged the CCA‟s recommendation, arguing there was no evidence on the

record that the IASB has finalized IFRS for rate-regulated entities and that transition to IFRS had

only resulted in a non-material change to capital overhead and revenue requirement. For these

reasons, EDTI argued there was no need to maintain a deferral account or require a complete

refiling of EDTI‟s 2012 forecast.127

Commission findings

199. EDTI adopted IFRS on January 1, 2011 in accordance with the standards then in effect.

The deferral accounts created in Decision 2010-505 were created due to uncertainty with respect

to the initial adoption of IFRS to capture “any adjustments resulting from the transition to IFRS

compliance.” As the transition to IFRS was completed in 2011, the deferral accounts for

distribution and transmission are no longer needed.

200. The Commission is of the view that future changes to IFRS will be addressed as

accounting changes should they arise.

201. The Commission rejects the CCA proposal that, should the IASB defer the mandatory

adoption date for IFRS, EDTI should be directed to re-file its 2012 test year to reflect the revised

IFRS standards because EDTI has already adopted IFRS.

202. The Commission notes that IASB IFRS requirements were not finalized at the time of the

2010 and 2011 GTA application upon which Decision 2010-505 was based. That decision

approved implementation of IFRS to be effective January 1, 2011. The Commission does not

accept the CCA proposal that IFRS implementation should be reversed one year after

implementation due to the IFRS requirements not yet being finalized given the revised deadline

for IFRS implementation of January 1, 2013 is approaching quickly.

203. Additionally, in Decision 2012-237,128 the Commission addressed the IFRS deferral

account for distribution utilities, determining that further accounting changes due to IFRS shall

be assessed as a Z factor as discussed below:

689. Fortis and AltaGas requested Y factor treatment for accounting changes. The

Commission considers that impacts associated with major changes to accounting

standards, whether it is the initial adoption of IFRS or any other modifications to

accounting standards, should be infrequent. Other than the initial adoption of IFRS, it is

unforeseeable when subsequent major changes to accounting standards will occur. In

addition, Fortis recognized that the majority of the AUC Rule 026 changes it would need

to make are required for financial reporting purposes, and that regulatory reporting would

likely not be affected. As a result, the Commission determines that because of the

infrequent and unforeseeable nature of accounting changes, they should be assessed as Z

factors.129 (footnotes removed)

204. For the above reasons, the Commission shall dispense with the IFRS deferral accounts for

both distribution and transmission.

127

Exhibit 208.02, EDTI argument, page 20, paragraphs 51-55. 128

Decision 2012-237: Rate Regulation Initiative, Distribution Performance-Based Regulation, Application

No. 1606029, Proceeding ID No. 566, September 12, 2012. 129



http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Pages/Rule026.aspx



3.12 Updating for 2011 actual amounts

3.12.1 Updating of categories other than operating expenses

205. In the compliance filing required by order of this decision, EDTI proposed to adjust its

2012 forecast for 2011 actual results consistent with the approach approved in

Decision 2010-505.

206. EDTI stated adjustments would be made for 2012 opening rate base and construction

work in progress which would also impact 2012 forecast return on rate base. The 2012 forecast

depreciation expense would be adjusted, and the actual costs of long term debt placed in 2011

would be reflected. This long-term debt adjustment would also impact the weighted average cost

of debt as well as the weighted average cost of capital for the 2012 forecast.130

207. The CCA proposed that EDTI update its 2012 revenue requirement to reflect all actual

asset and liability continuity balances as at December 31, 2011 in place of the forecast amounts

used. The CCA clarified which balances would be included under its proposal.131

208. The CCA also submitted that actual customer numbers as at December 31, 2011 should

be used in place of forecast numbers. The CCA submitted that, since EDTI intends to update the

opening balance of 2012 rate base to reflect 2011 actual capital additions, then 2011 actual

customer numbers should also be used for the determination of 2012 revenue requirement, which

will be re-based for use in the PBR period of 2013-2017.132

Commission findings

209. In Decision 2010-505,133 the Commission addressed the topic of updating forecast

information with actual results in the context of the 2010-2011 GTA as follows:

23. The Commission confirms that it requires the best available information at the

time it makes its decision and confirms its views from Decision 2008-113. There, the

Commission adopted the Board‟s views on the use of updated information in a

prospective rate-setting environment as set out in Decision 2006-004:

In recent years, when confronted with the question of whether or not to

consider events that have occurred after the preparation of revenue

requirement forecasts, the Board has usually taken the position that such

information will be used in assessing the reasonableness and accuracy of

the forecasts and the methodology utilized in preparing the forecasts. The

Board has not, however, substituted the forecasts with the updated

information, except with respect to certain specific forecast items. For

example, the Board has updated interest rate forecasts in determining the

cost of capital, income tax rates, opening balances for plant property and

equipment and has excluded amounts forecast for capital projects that did

not proceed. The Board has determined that the use of updated

information in these particular types of categories was in the overall

public interest and had as its objective an appropriate revenue stream

without undue benefit or detriment to the regulated utility. The utility has

130

Exhibit 186.02, information response AUC-EDTI-58(a). 131

Exhibit 201.01, information response AUC-CCA-2(a). 132

Exhibit 191.01, CCA intervener evidence, page 14-16, paragraphs 35-41. 133

Decision 2010-505, pages 4-5, paragraphs 23 and 30.



also always been able to update its application and its forecasts to reflect

any unforeseen increases in costs. The Board continues to be of the view

that this is the appropriate use of information that becomes available

subsequent to the preparation of the forecasts underpinning an

application.

…

30. The Commission has traditionally required that a utility‟s revenue requirement

schedules be updated for any year-end actual rate base figures that become available prior

to close of record. These updates, for example, may affect the return on capital and any

associated income taxes. The Commission believes that such updates should apply to

figures that will be, more or less, automatically recalculated in the revenue requirement

model when the year-end actual figures are input. In contrast to this, updating for actuals

in any year does not require an update to forecast items such as the load forecast, capital

spending and operating and maintenance expenses.

210. The Commission retains its views on this matter as set out in Decision 2010-505. With

regard to the CCA‟s proposal to update the forecast customer numbers (which were not

addressed in Decision 2010-505) with 2011 actual amounts, the Commission considers that

unless there is a history of forecasting errors, forecast customer numbers should not be updated.

The Commission has reviewed the forecast accuracy of the actual customer numbers to the

approved numbers.134 As shown in Section 7.2 of this decision, the difference between approved

and actual customer numbers for 2010 and 2011 has only been approximately one per cent,

indicating the forecasts are reasonable.

211. In an attempt to strike a balance between materiality and the prospective nature of

applications, the Commission accepts EDTI‟s proposed adjustments for updating of 2011 actual

results as reasonable for the non-operating expense categories.

212. Consistent with the above, EDTI, in its compliance filing, is directed to reflect all

changes to the 2012 revenue requirement consistent with the approach determined in

Decision 2010-505, when the 2011 actual figures are input into EDTI‟s revenue requirement

model.

3.12.2 Updating of operating expenses

213. The UCA stated that 2011 actual results were $1.07 million lower than the updated 2011

forecast for distribution operating expenses, which included savings for both operations and

maintenance and customer accounting costs of $0.74 million and $0.33 million respectively. The

UCA argued that this was an efficiency gain which should be reflected as a reduction to the 2012

forecast as EDTI‟s 2012 forecast would form the basis of the 2013 going-in rates for PBR.

214. The UCA submitted that the distribution forecasts for 2012 showed increasing levels of

supervision and engineering as well as higher customer accounting costs, driven by meter

reading costs where there was little growth in the number of standard meters as most new meters

were AMR meters. These increases were in contrast to the savings between the 2011 forecast and

actual amounts, which included supervision and engineering cost savings of $0.55 million for

distribution.

134

Exhibit 186.06, information response AUC-EDTI-70, Attachment 1, Schedule 13-1.



215. With regard to transmission direct operations and maintenance, the UCA argued that

actual savings for 2011 of $0.42 million from the 2011 updated forecast represented efficiencies

achieved which should be reflected in the 2012 forecast.

216. The CCA submitted that the 2011actual distribution revenue requirement was

$1.18 million or 0.9 per cent lower than the 2011 approved amount and that the 2011 actual

transmission revenue requirement was $0.88 million or 1.5 per cent lower than the approved

amount. The CCA argued that to the extent that the 2012 forecast was based on the 2011 forecast

amount, the respective 2012 revenue requirements could be overstated. The CCA submitted that

the 2012 O&M expenses should therefore be adjusted to reflect the lower 2011 actual results.

217. EDTI dismissed the UCA‟s concerns regarding the increasing levels of supervision and

engineering for both distribution and transmission because, once the impact of the level of

capital activity was taken into consideration, the forecast levels were reasonable. EDTI stated

that as levels of operating and capital work increase, supervision and engineering costs increase.

218. With regard to customer accounting costs, EDTI argued that, once revenues that were

associated with some of the expenditures included in this category were considered, such as the

revenues recovered from EPCOR Water Services Inc. (EWSI) for provision of meter reading

services, the upward trend identified by the UCA was offset and reasonable.

Commission findings

219. The Commission has reviewed the forecasting accuracy of the operating expense

categories for both transmission and distribution in comparison to the approved amounts. The

Commission notes that the forecast 2012 costs were generally based on the 2008 to 2010 actual

costs so any errors in the 2011 updated forecast would not have impacted the 2012 forecast.

220. Table 21 for distribution and Table 22 for transmission below show comparisons of three

years of operating expense actual results to approved. The differences shown are not material

and do not show a trend of over forecasting.

Table 21. Distribution operating expenditures 2009-2012 – Table AUC-EDTI-69-3 ($ millions)

Source

A 2009 (D)

B 2009 (A)

C 2010 (D)

D 2010 (A)

E 2011 (D)

B 2011 (A)

G 2012 (F)

1 Distribution operating costs net

Table 1.2.1-1 29.08 31.67 33.83 32.31 33.84 33.00 35.17

2 Distribution work for others net

Table 1.2.1-1 (0.91) (1.07) (1.64) (1.22) (2.05) (1.64) (2.18)

3 EDTI admin & general – net

Table 1.2.1-1 3.71 1.94 2.99 3.53 2.45 3.01 4.17

Total 31.88 32.54 35.18 34.62 34.24 34.37 37.16

Variance 0.66 (0.56) 0.13 2.79




Table 22. Transmission operating expenditures 2009-2012 – Table AUC-EDTI-69-4 ($ millions)

Source

A 2009 (D)

B 2009 (A)

C 2010 (D)

D 2010 (A)

E 2011 (D)

F 2011 (A)

G 2012 (F)

1 Distribution operating costs net

Table 1.2.1-1 9.87 10.3 11.53 11.79 11.62 12.15 13.64

2 Distribution work for others net

Table 1.2.1-1 (0.27) (0.20) (0.09) (0.04) (0.09) (0.06) (0.10)

3 EDTI admin & general – net

Table 1.2.1-1 1.54 1.01 1.55 1.36 1.82 1.66 1.44

Total 11.14 11.11 12.99 13.11 13.35 13.75 14.98

Variance (0.03) 0.12 0.40 1.23

221. As acknowledged by the CCA and the UCA, the differences are relatively small in

comparison to the total expenses and some categories also having offsetting revenues.

222. As discussed in the Commission findings in the Section 3.12.1 above, for the updates

from 2011 actual results for categories other than operating expenses, the Commission does not

typically adjust operating expense forecasts for actual results, unless the forecast methodology

used or the forecasting accuracy were in question.

223. Further, both the UCA and the CCA argued that 2012 rates will be used as going-in rates

for distribution PBR. Decision 2012-237 addressed adjustments to PBR going-in rates as

follows:

88. … The Commission confirms the findings in Decision 2009-035 that adjustments

to going-in rates should not be made to reflect actual results. Further, adjustments should

not be made selectively but, rather, should only be made in the context of a full rate case.

Adjustments may be made in exceptional situations, however, like the case of the short

term incentive plan adjustment approved in the ENMAX decision.

89. Accordingly, the Commission will consider adjustments that are in the nature of

a correction to the going-in rates, and which are not rate adjustments made after-the-fact

to reflect actual results. ….135

224. The Commission does not accept the UCA and the CCA positions that the operating

expense forecast for 2012 should be adjusted for 2011 actual results, consistent with previous

Commission decisions, specifically Decision 2010-505 and 2008-113,136 and given that the

forecasting accuracy on a total basis appears reasonable. Further, with respect to the going-in

rates for the PBR term, adjustments will not be made for actual results consistent with

Decision 2012-237.

135

Decision 2012-237: Rate Regulation Initiative – Distribution Performance-Based Regulation, Application

1606029, Proceeding ID No. 566, September 12, 2012, page 20, paragraphs 88 – 89. 136

Decision 2008-113: ATCO Gas 2008-2009 General Rate Application Phase I, Application No. 1553052,

Proceeding ID. 11, November 13, 2008.




3.13 Operating expenses

3.13.1 Forecasting of distribution and transmission repair costs

225. EDTI has developed and used an updated methodology for forecasting its distribution and

transmission repair costs which is based on a three year average of EDTI‟s actual repair costs by

expense type for 2008 through 2010.137 Actual repair costs have exceeded forecast repair costs in

each of 2008 to 2010.

226. The updated methodology uses the following steps:

actual repair costs for each year are broken down into their expense types

each expense type is then individually adjusted for actual cost escalation for those years

an average cost for each expense type is then calculated for 2008 to 2010 in 2010 dollars

each expense type is inflated using 2011 approved escalation rates from

Decision 2010-505

all expense types are then inflated to 2012 using the proposed 2012 escalation factors

the proposed employee fringe benefit rates are finally applied to all labour costs

227. The previous forecast method took an average of the total actual repair costs for the

previous three years; then adjusted the average total for inflation for the applicable test year

using EDTI‟s common escalation factors; and adjusted for expected increases or decreases in

overall work requirements.

228. The CCA expressed concern that the resulting forecast using the revised methodology is

significantly higher than previous actual results from 2008 to 2010; possibly due to double

counting of escalation. In response to a CCA information request for backcasting information to

assess the accuracy of 2009 and 2010 actual results under the proposed methodology, EDTI

responded that it did not have sufficient time available to prepare the requested information

under the IR process timelines.

229. The CCA argued that the revised methodology should be denied until further examination

can take place at EDTI‟s next GTA because sufficient evidence was not provided as part of this

proceeding. It was the CCA‟s position that the revised methodology produced exaggerated

forecast results.138

230. EDTI responded that the previous forecast method produced unreasonably low forecast

costs compared to actuals. EDTI argued that it had provided various information in response to

IRs including a backcast of 2011 costs which compared the old and proposed methods139 that

demonstrated the refined method provided a more reliable forecast.140

231. EDTI argued that the CCA analysis was flawed and that no double counting of escalation

for any of the expense types occurred. EDTI stated that the 2011 backcast that it had provided

137

Exhibit 3, application, pages 84-86, paragraphs 204-209. 138

Exhibit 201.01, CCA argument, pages 8-10, paragraphs 31-44. 139

Exhibit 168.09, information response CCA-EDTI-91, Attachment 1. 140

Exhibit 208.02, EDTI argument, pages 21-22, paragraphs 56-63.



showed the refined methodology had produced a forecast which was lower than 2011 actuals that

was contrary to the CCA‟s claim of exaggerated forecasts.141

Commission findings

232. The Commission has reviewed the refined methodology calculation along with the

comparison to the previous method, as provided by EDTI and as shown in Table 23 below.

Based on this review, the Commission finds that the refined methodology does not double count

escalation but rather adjusts the historical dollars to a relatively constant dollar basis, which is

then escalated using a two step process to forecast the adjusted average amounts into 2012

dollars.

233. The Commission finds the refined methodology as proposed by EDTI for use in

forecasting both distribution and transmission repair costs to be reasonable, given the under-

forecasting that has been experienced by EDTI for 2008 through 2010.

Table 23. 2011 backcast – comparison of three-year average calculation methodologies – Table CCA-EDTI-91-1 ($ millions)

A B C D E F

2011 forecast calculation

Section reference

Description

Escalated 3-year actual

average 2007-2009 A

Previous method

Refined 3-year average method

(2007-2009 A)

2011 actuals

Distribution function

1 5.1-3 High load move services for external parties

0.05 0.05 0.06 0.06

2 5.1-3 Installation of temporary service connections

0.46 0.47 0.51 0.42

3 4.3.1 Distribution 5 kV and 25 kV substation repair

0.03 0.03 0.03 0.03

4 4.4.3 Distribution aerial repair and aerial system damage

0.20 0.20 0.22 0.15

5 4.5.4 Distribution network repair 0.03 0.03 0.04 0.06

6 4.5.5 Distribution underground repair and unrecoverable damage costs

0.83 0.86 0.94 1.08

7 4.7.3 Meter repair 0.04 0.04 0.05 0.04

8 4.11.1 Distribution aerial transformer repair

0.09 0.09 0.10 0.08

9 4.11.2 Distribution aerial transformer repair

0.10 0.10 0.11 0.11

10 Total distribution 1.83 1.88 2.05 2.04

141

Exhibit 211.02, EDTI reply argument, pages 35-37, paragraphs 93-100.



A B C D E F

2011 forecast calculation

Section reference

Description

Escalated 3-year actual

average 2007-2009 A

Previous method

Refined 3-year average method

(2007-2009 A)

2011 actuals

Transmission function

11 6.3.3.1 Transmission substation apparatus 0.34 0.35 0.38 0.39

12 6.3.3.2 Transmission substation relaying 0.11 0.12 0.13 0.21

13 6.3.3.3 Transmission substation SCADA, telecontrol and communication system repair

0.07 0.07 0.08 0.06

14 6.3.3.4 Transmission substation buildings and switchyards

0.24 0.25 0.28 0.38

15 6.4 Transmission aerial repair 0.05 0.05 0.05 0.03

16 6.5 Transmission underground cable repair

0.09 0.10 0.11 0.21

17 Total transmission 0.90 0.93 1.02 1.27

18 Total distribution + transmission 2.73 2.81 3.08 3.30

19 20

Distribution variance 2011 actual – previous method 2011 actual – refined method

0.16

(0.02)

21 22

Transmission variance 2011 actual – previous method 2011 actual – refined method

0.34

0.25

234. The Commission rejects the CCA‟s proposal to deny use of the refined methodology and

accepts the forecast methodology and resulting forecasts for both distribution and transmission

repair costs as filed.

3.13.2 Cost control metrics

235. The CCA submitted that because EDTI will commence PBR in 2013, the Commission‟s

determination of costs for the 2012 GTA should be considered in the context of what EDTI has

been able to achieve in prior years relative to the rapidly escalating costs since 2008.142

236. The CCA introduced a metric into this proceeding referred to as “controllable operating

cost per customer” (COCC). EDTI defined controllable operating cost in an information

response143 as follows:

….those costs under the reasonable control of EDTI that reflect the underlying year over

year recurring costs. EDTI understands non-controllable costs to mean those costs subject

to reserves, deferrals, flow through operating costs and costs that have offsetting

revenues, such as work for others.

237. The CCA submitted that the COCC metric for EDTI distribution showed a rapid increase

from 2009 through to 2011, followed by a slight increase in 2012. The COCC metric for EDTI

transmission showed a steady increase from 2009 to 2012.

142

Exhibit 201.01, CCA argument, page 23, paragraph 91. 143

Exhibit 150.01, information response CCA-EDTI-28(b).



238. The CCA argued that the COCC was a useful tool to assess the productivity gains or

losses achieved by EDTI. For this reason, EDTI should be directed to file this metric in future

proceedings as well as a detailed assessment of the rationale underlying the changes in this

metric.

239. EDTI responded that the CCA had overstated the increase in the COCC metric while

ignoring the drivers behind these trends, which EDTI had provided.

240. EDTI argued that, while COCC may contribute to an overall picture of productivity

within an organization, it should be considered with other important measures related to

reliability, safety, and customer satisfaction. For this reason, COCC should not be used as a basis

for assessing forecast costs but instead the utility must provide evidence to justify its forecast

costs.

241. While EDTI was not opposed to filing the controllable cost per customer measure, it

could see little point in making it a filing requirement for future tariff applications.

Commission findings

242. The Commission recently issued Decision 2012-237. Elements of that proceeding set out

the measures and reporting that are required under PBR. The Commission rejects the CCA

proposal to make the controllable operating cost per customer a requirement for future

proceedings for distribution.

243. For regulation of transmission utilities, under the current regulatory framework,

interveners can continue to participate in testing of the application and raise issues such as trends

in controllable operating cost per customer.

3.13.3 Inspection of customer service connections on private property

244. EDTI uses contractors to inspect customer-owned facilities on private property to ensure

compliance with EDTI‟s Customer Connection Guide and the Alberta Safety Codes Act, RSA

2000, c. S-1. The contractor advises EDTI when the facilities are safe to energize and also

provides inspectors to assist EDTI‟s engineers in assessing a customer‟s service requirements

and investigating power quality, code and safety issues relating to customer-owned facilities on

private property.144

245. Prior to 2011, a qualified contractor, The Inspections Group Inc., had been given the

exclusive rights by the City to issue electrical permits and perform electrical inspections within

the city boundaries. In 2011, the City took over the role of issuing electrical permits within city

boundaries. For this application, EDTI averaged the historical cost per inspection of

approximately $77 with the rate proposed by the City of $150 to develop its forecast using

$113.50 per inspection. The table below shows the historical and forecast costs for this category.

The $0.37 million increase is primarily due to the increased unit rate per inspection.

144

Exhibit 3, application, page 399, paragraphs 1074-1076.



Table 24. Inspection of customer service connections on private property 2009-2012 – Table 4.8.1-1 ($ millions)

A

2009 (A) B

2010 (D) C

2010 (A) D

2011 (D) E

2011 (UF) F

2012 (F)

1 0.60 0.40 0.73 0.47 0.57 0.94

2 Variance 0.33 0.10 0.37


246. The CCA argued that the increase in 2012 costs was not reasonable now that the City will

take over the role of issuing electrical permits, performing inspections, and managing all relevant

site information at a cost significantly higher than the independent contractor previously used by

EDTI.

247. The CCA initially recommended that the proposed increase be denied and instead that the

2011 updated forecast should be escalated by the 3.2 per cent proposed in the application for

EDTI contractors to $0.59 million resulting in a proposed reduction of $0.35 million.145

248. EDTI responded that electrical permitting and inspections under the Safety Codes Act in

Edmonton is under the authority of the City. EDTI indicated it had negotiated an inspection price

of $110 per inspection, and that EDTI and the City were still working on a final draft of the

agreement which will include the $110 per inspection rate, as other matters in the contract

remain to be finalized.146

249. The CCA replied that EDTI should be directed to reflect the negotiated $110 per

inspection price, and to provide details of all other matters in the contract which remain to be

finalized as part of the compliance filing.

Commission findings

250. The Commission observes that the issue raised by the parties was the rate per inspection

and not the volume to which the rate was applied. While the CCA concluded that the forecast

should be recalculated downwards for a reduction of $150 to $110 per inspection, the

Commission notes that, in its application, EDTI indicated it had used a rate of $113.50 per

inspection.

251. The Commission rejects the CCA proposal to reduce the forecast by using the negotiated

$110 rate per inspection, as the resulting adjustment would not be material.

252. The Commission rejects the CCA‟s proposal regarding all other matters in the contract

which remain to be finalized because the Commission has accepted EDTI‟s forecast of its

inspection costs as reasonable.

3.13.4 Specialized rental equipment

253. Costs related to specialized rental equipment are included in fleet costs for both

distribution and transmission which are allocated to various operating cost categories and capital

projects that the fleet is used to support.

145


Exhibit 208.02, EDTI argument, page 52, paragraph 164.



254. The CCA argued that, since forecast costs vary significantly year to year for specialized

rental equipment, EDTI had not provided sufficient evidence to justify the 2012 forecast of

$1.31 million. The CCA submitted that, to address this volatility, the Commission should direct

EDTI to base the 2012 forecast on a methodology that used the average of three years of actual

results, and that the resulting average should be reduced by all rental costs associated with the

North LRT for an overall reduction of $0.13 million.

255. EDTI acknowledged that actual costs for specialized rental equipment will vary from

year to year depending on the nature and number of capital projects being forecast and projected

operational work activities. EDTI submitted that use of a three-year forecast methodology would

not result in a reliable forecast.147

Commission findings

256. The Commission accepts EDTI‟s submission that the specialized rental equipment varies

year over year based on operational and capital needs and that a forecast based on three years of

data would not necessarily result in a reasonable forecast for this cost area. The Commission

rejects the CCA‟s proposal for a change in forecasting methodology and a forecast reduction of

$0.13 million. Accordingly, the Commission accepts EDTI‟s forecast as filed.

4 Distribution issues

4.1 Distribution rate base

257. EDTI has requested approval of its opening distribution rate base of $548.1 million148 and

forecast additions to rate base of $100.3 million.149

4.1.1 Distribution opening rate base

258. This section addresses EDTI‟s 2010 and 2011 capital additions which are part of the 2012

distribution function opening rate base. In the application, EDTI submitted post implementation

reviews for previously approved business cases and provided explanations for cost variances.

259. A comparison of decision approved rate base amounts to the actual amounts for 2009 to

2011 indicates that the closing rate base amounts were very close to the approved amounts.

Table 25. Distribution rate base (less working capital) – actual vs. decision

2009 2010 2011

Decision 411.9 465.5 511.8

Actual 421.2 461.6 521.7

$ Increase 9.3 (3.9) 9.8

% Over (under) 2.3% -0.8% 1.9%

Source: Based on Decision 2010-505 and Exhibit 186.06

147

Exhibit 211.02, EDTI reply argument, pages 39-40, paragraphs 108-111. 148

Exhibit 186.06, AUC-EDTI-70, Attachment 1, Schedule 19-1. 149

Exhibit 186.04, AUC-EDTI-68 b), Attachment 1.



260. Interveners did not express concerns with EDTI‟s capital additions over the 2010 to 2011

period. The Commission assessed the reasonableness of EDTI‟s proposed 2012 opening rate

base in the following analysis of capital activity during the 2010 to 2011 period.

261. In order to assess the reasonableness of capital additions to rate base, the Commission

examined the approved forecast capital additions and actual capital activity during the period.

Projects may not be completed in the time period anticipated, resulting in variances between

capital additions and either opening or closing construction work in process (CWIP). Moreover,

projects not approved may be undertaken and actual costs incurred could be over or under the

forecast amounts. In the following analysis, changes in CWIP due to the timing of completion

for projects were considered as well as significant variances in costs incurred. The following

schedule reflects EDTI‟s capital activity for the period from 2009 to 2012.

Table 26. EDTI distribution function capital additions ($ millions)

2009 (D) 2009 (A) 2010 (D) 2010 (A) 2011 (D) 2011 (A) 2012 (F)

Opening CWIP balance 0.7 5.2 21.8 8.1 2.0 15.3 15.7

Capital Expenditures 39.3 52.4 66.2 86.1 68.1 92.9 89.0

Subtotal 40.0 57.6 88.0 94.3 70.0 108.2 104.8

Closing CWIP balance 0.6 8.1 2.0 16.0 13.7 16.4 4.5

Total additions to rate base 39.4 49.5 86.0 78.3 56.4 91.7 100.3

Variance in capital additions 10.1 (7.7) 35.4 8.6

Source: Based on Exhibit 186.04, AUC-EDTI-68 (b), Attachment 1 Legend: (D) decision, (A) actual, (F) forecast

262. As shown in Table 26, 2010 actual capital additions were $7.7 million less than forecast,

capital expenditures exceeded the amount approved in Decision 2010-505 by $19.9 million and

the closing CWIP balance was $14.0 million greater than forecast due to projects that were not

completed when expected. The 2010 opening CWIP balance was $13.7 million less than forecast

due primarily to the postponement of EDTI‟s distribution function Summerside substation

contribution payment because of project delays.

263. The delay of projects from 2009 to 2010 and from 2010 to 2011 explain, to a large extent,

the discrepancy between approved and actual capital additions and the increased closing CWIP

balance for 2010 as compared to the decision amounts in the above table. Some projects had cost

overruns and others cost less than forecast. The combined impact of the change in timing of

projects plus the variances from forecasts, as analyzed below, account for the majority of the

$7.7 million discrepancy in 2010 capital additions.

264. The following three projects were not completed in 2010 as originally forecast:

The life-cycle replacement and extension of underground distribution cable project was

originally forecast to be completed at a cost of $5.6 million, however $1.8 million of

$5.9 million of this capital expenditure remains in CWIP.

The new 15 kV and 25 kV circuit additions (growth project) was originally forecast to be

completed at a cost of $3.2 million; however $3.4 million of the $3.7 million of this

capital expenditure remains in CWIP.



The North light rail transit (NLRT) distribution system relocate (growth project) was

originally forecast to be completed at a cost of $7.5 million; $7.1 million of capital

expenditures were incurred and all amounts remained in CWIP.

265. The following projects included in capital additions had costs which were at least

$2.0 million greater or less than the 2010 forecast:

Underground residential rebates were $2.1 million greater than the 2010 forecast.

New underground and aerial service connections for commercial industrial, multi-family

and miscellaneous customers were $3.0 million greater than the 2010 forecast.

The Summerside feeders (growth project) was $2.0 million less than the 2010 forecast.

266. For 2011, capital additions were $35.4 million greater than forecast while capital

expenditures exceeded forecast amounts by $24.8 million. Due to the delay in completing some

projects in 2010, the opening CWIP balance was $13.3 million higher than forecast but, by the

end of the year, the variance from forecast had decreased to $2.7 million.

267. EDTI explained that approximately half of the $35.4 million (63 per cent) increase in

2011 capital additions (decision versus actual amounts) was related to capital projects not

completed as planned in 2010. As indicated in the analysis for 2010 above, there was

$12.3 million related to three projects in opening CWIP. The relocation of distribution facilities

to accommodate the northern extension of the City of Edmonton Light Rail Transportation

system, an unanticipated project, accounted for $14.55 million of the 2011 capital additions.150

Also contributing to the increase in capital additions were net cost overruns.

268. EDTI provided detailed explanations151 respecting 2011 project variances. The following

projects included in capital additions had costs which were at least $1.0 million greater or less

than forecast:

Franchise agreement driven relocations and conversions were $4.1 million greater than

forecast.

Underground residential distribution (URD) servicing expenses were $3.7 million greater

than forecast.

Capitalized underground system damage was $2.7 million greater than forecast.

New underground and aerial line reconfigurations and extensions to meet customer

growth were $2.7 million greater than forecast.

The life cycle replacement of extension of underground distribution cable was

$2.3 million greater than forecast.

New underground and aerial service connections for commercial, industrial, multifamily

and miscellaneous customers were $1.5 million greater than forecast.

New 15 kV and 25 kV circuit additions were $1.0 million less than forecast.

Replacement of faulted distribution paper-insulated lead-cased (PILC) cables was

$1.0 million less than forecast.

150

Exhibit 167.02, AUC-EDTI-17. 151

Exhibit 167.06, AUC-EDTI-17 Attachment 3.



Distribution pole and aerial line life cycle replacements were $1.1 million less than

forecast.

Contributions to EDTI‟s transmission function were $1.3 million less than forecast.

Commission findings

269. With respect to Table 26 above, the Commission notes a discrepancy between the 2010

actual closing CWIP balance of $16.0 million and the 2011 actual opening CWIP balance of

$15.3 million The Commission directs EDTI in its compliance filing to correct the discrepancy

and to reflect this change in the 2012 opening and closing forecast CWIP balances.

270. The Commission has reviewed the cost variance analyses and explanations regarding

project delays in the application, capital business cases, the 33 distribution related post

implementation reviews (D-PIR)152 and IR responses related to the 2010 and 2011 capital

additions. Although the actual capital expenditures differed from the amounts approved on an

individual basis, some higher and some lower, the explanations provided by EDTI were

reasonable. Reasonable explanations were also provided for the introduction of projects which

had not been anticipated and projects which were cancelled. The Commission notes that

interveners did not raise concerns regarding individual projects or the opening rate base amounts.

Based on its review and analysis of the post implementation reviews and other explanations

provided in the application, and subject to the direction above regarding CWIP balances, the

Commission approves the opening distribution rate base as filed.

4.1.2 Distribution 2012 capital additions

271. EDTI applied for approval of $100.3 million of distribution capital additions for 2012. In

its application, EDTI classified its 2012 forecast and previous years‟ capital additions into major

cost categories, generally following uniform system of accounts/minimum filing requirements

(USA/MFR) numbering for distribution capital.153 Within each major category, similar projects

were grouped into sub-categories consistent with directions arising from Decision 2006-054.

EDTI also indicated whether the projects were growth driven, life-cycle replacement or process

improvement.154

272. As can be seen from the following table provided by EDTI, growth projects have been

and continue to be the primary driver of EDTI‟s distribution capital program for the 2012 test

year. The most volatile component of capital additions is EDTI‟s distribution function

contributions for transmission assets, which EDTI explained is related to the timing of the

completion of AESO-directed transmission projects.155

152

Exhibit 55, Appendix E-1-D-PIR. 153

Exhibit 3, application, paragraph 3124. 154

Exhibit 206.02, argument. 155

Exhibit 3, application, page 1199.



Table 27. Distribution capital additions summary 2009-2012

TOTALS 2009 (A) 2010 (A) 2011 (A) 2012 (F)

Life-cycle projects 12.4 18.6 28.4 26.5

Performance improvement projects 2.5 2.1 3.3 3.5

Growth projects 24.1 27.8 51.0 41.2

Multi-category 9.0 15.8 9.5 12.7

Subtotal 48.0 64.3 92.2 83.9

Contributions 1.5 13.8 (0.4) 16.4

Grand Totals 49.4 78.3 91.7 100.3

Source: Table 12.2-1; Exhibit 167.06, Attachment 3

273. EDTI submitted that major growth related projects included:

a. Increased capital additions associated with underground residential distribution (URD)

servicing and related activities, including lot rebates.

b. The addition and modification of distribution infrastructure in response to strong

economic growth in the City of Edmonton over the past few years, such as the new

feeders from the Poundmaker Substation.

c. Life cycle replacement spending.

274. Pursuant to Commission directions arising from Decision 2006-054, EDTI provided a

total of 31 distribution capital project business cases (D-CBC).156 Interveners did not express

concerns with EDTI‟s 2012 forecast distribution capital additions.

Commission findings

275. The Commission has reviewed all the business cases and found the projects to be justified

and the cost estimates reasonable. The Commission approves EDTI‟s distribution function

forecast capital additions as filed.

4.2 House service connection upgrades and relocates

276. House service connection upgrades and relocates include labour, vehicle, and material

costs associated with customer requests for upgrades to, or relocations of, their aerial service

connections. The following table157 summarizes the expense forecasts and actual results for this

category:

Table 28. House service connection upgrades and relocates 2009-2012 – Table 4.7.2-5 ($ millions)

A

2009 (A) B

2010 (D) C

2010 (A) D

2011 (D) E

2011 (UF) F

2012 (F)

1 0.45 0.36 0.39 0.39 0.40 0.41

2 Variance 0.03 0.01 0.01


156

Exhibit 54, Appendix E-1-D-CBC. 157

Exhibit 3, application, page 393, paragraph 1051.



277. EDTI has modified its methodology to prepare the 2012 forecast based on a three-year

annual average of actual service changeover requests from 2008 to 2010. EDTI‟s previous

forecast methodology was based on the number of energized residential sites in its service area

and the latest year‟s actual service changeover requests.

278. While the CCA did not oppose the use of the proposed three year average, it considered

the 2010 actual number of changeover requests to be unusually high. For this reason, the CCA

recommended that a four-year average be used instead.158

279. EDTI rejected the CCA proposal because the use of the three-year average already

addressed the volatility that resulted from a high year, and it also allowed for a higher than usual

year to be included when calculating the average.

Commission findings

280. The Commission finds that the forecasting method based on the average of three years

proposed by EDTI better addresses the volatility than the previous methodology. The

Commission is not persuaded by the CCA that a four-year period is warranted based on 2010

data, as typically three years of data are used to address volatility and a three-year forecast

methodology has been utilized elsewhere in the application.

5 Transmission issues

5.1 Transmission rate base

281. EDTI has requested approval of its opening transmission rate base of $311.5 million,159

and forecast additions to rate base of $46.4 million.160

5.1.1 Transmission opening rate base

282. This section addresses EDTI‟s 2010 and 2011 capital additions which were included in

the 2012 transmission function opening rate base. In the application, EDTI submitted 30 post-

implementation reviews for previously approved business cases and provided explanations for

cost variances.

283. As shown in the following table, closing rate base amounts for the period from 2009 to

2011 were between 2.4 per cent and 3.1 per cent less than the amounts approved in

Decision 2010-505.

158


Exhibit 186.06. AUC-EDTI-70, Attachment 1, Schedule 9-1. 160

Exhibit 186.05. AUC-EDTI-68 b), Attachment 2.



Table 29. Transmission rate base (less working capital) – actual vs. decision

2009 2010 2011

Decision 289.0 304.6 324.2

Actual 282.1 296.9 313.9

$ Increase (6.9) (7.7) (10.2)

% Over (Under) -2.4% -2.5% -3.1%

Source: Based on Decision 2010-505; Exhibit 186.06

284. In order to assess the reasonableness of capital additions, the Commission has examined

the actual capital activity during the period. Projects may not be completed in the time period

anticipated, resulting in variances between capital additions and either opening or closing CWIP.

Moreover, projects not approved may be undertaken and actual costs incurred could be over or

under the forecast amounts. In the following analysis, changes in CWIP due to the timing of

completion of projects will be considered as well as significant variances in costs incurred. The

following schedule sets out EDTI‟s capital activity for the period from 2009 to 2012.

Table 30. EDTI transmission function capital additions ($ millions)

2009 (D) 2009 (A) 2010 (D) 2010 (A) 2011 (D) 2011 (A) 2012 (F)


Capital Expenditures 25.6 32.0 46.8 35.0 24.2 58.6 14.5

Subtotal 29.1 41.8 69.5 57.7 45.2 83.4 69.4



Variance 5.3 (15.6) 10.1 21.3

Source: Based on Exhibit 186.05, AUC-EDTI-68 (b), Attachment 2

285. As discussed in Section 13.2.1.10, the Heartland project is a joint venture with AltaLink

and the majority of EDTI‟s Heartland related expenditures are transfers to EDTI from AltaLink.

To better understand the capital activity presented in the above table, the Commission

constructed the following table, which excludes Heartland related expenditures.



Table 31. EDTI transmission function capital expenditures and capital additions excluding Heartland ($ millions)

2009 (D) 2009 (A) 2010 (D) 2010 (A) 2011 (D) 2011 (A) 2012 (F)


Capital expenditures 24.2 24.5 40.9 29.7 20.7 30.5 58.2

Subtotal 24.9 32.7 54.5 43.2 26.7 40.8 69.4



Variance 5.3 (15.6) 10.1 21.3

Source: Exhibit 186.05, AUC-EDTI-68 (b), Attachment 2

Table 32. Heartland 500 kV transmission ($ millions)

2009 (D) 2009 (A) 2010 (D) 2010 (A) 2011 (D) 2011 (A) 2012 (F)


Capital expenditures (transfer to partnership)

1.4 7.5 5.8 5.3 3.5 28.1 (43.7)

Subtotal 4.2 9.1 15.0 14.5 18.5 42.6 -

Closing CWIP balance 4.2 9.1 15.0 14.5 18.5 42.6 -

Total additions to rate base - -

- - - - -

Source: Exhibit 186.05, AUC-EDTI-68 (b), Attachment 2

286. As shown in Table 31, 2010 actual capital expenditures and additions to rate base were

$11.3 million and $15.6 million respectively lower than forecast, while closing 2010 CWIP was

$4.3 million greater than forecast. The 2010 variances were primarily due to the following

projects not being completed in 2010:

904L line de-bottlenecking growth project – due to delays and increases in the scope of

work, capital expenditures and additions to rate base were respectively $5.8 and

$8.0 million less than forecast leading to a closing CWIP balance which was $2.2 million

greater than forecast.

The transmission cable forced oil cooling system (FOCS) programmable logic controllers

(PLCs) life cycle replacement project – due to delays, capital expenditures and additions

to rate base were respectively $2.9 and $4.1 million less than forecast, contributing to a

closing CWIP balance that was $1.2 million greater than forecast.

The cable barrier splice performance improvement project – due to delays in construction

work, capital expenditures and additions to rate base were respectively $4.9 and

$6.5 million less than forecast, which led to a closing CWIP balance that was

$1.6 million greater than forecast.

287. As shown in Table 31, for 2011, actual capital expenditures and additions to rate base

were $9.8 and $10.1 million respectively greater than forecast.



288. Opening CWIP was $4.3 million greater than forecast while closing CWIP was

$4.0 million greater than forecast. The $15.6 million reduction in forecast capital additions in

2010 was offset by the $9.8 million additions in excess of forecast in 2011 and the $4 million

higher-than-forecast balance in ending CWIP.

289. EDTI provided explanations for the transmission capital cost variances in the application

including 30 post-implementation reviews (PIRs).161 Additional details were provided by EDTI

in response to IRs.

290. Major contributors to the increase in capital additions included the completion of the

transmission cable FOCS system PLCs life cycle replacement project at $2.7 million greater than

forecast, and the 904L line de-bottlenecking growth project at a cost of $2.8 million greater than

forecast. Further, there was very little progress made on the cable barrier splice performance

improvement project and therefore $0.3 million was added to CWIP.

291. The increase in closing CWIP was primarily due to the Poundmaker substation POD

addition growth project, which has a forecast in-service date of September 1, 2012,162 for which

EDTI incurred expenditures net of customer contributions in 2011 that were $2.4 million greater

than forecast.

292. The above increases were offset by EDTI‟s limited progress on its system planning load

and sustainability study, which was approved in Decision 2010-505 with a forecast cost of

$1.94 million. Should the planning load and sustainability study identify the need for further life

cycle replacement projects, EDTI proposed that the cost of the engineering study should be

moved to rate base from CWIP in conjunction with the addition to rate base of the expenditures

associated with the replacement projects identified. Furthermore, EDTI submitted that these

projects and their associated costs will be included in future capital forecasts for approval by the

Commission.163

293. Interveners did not raise concerns with EDTI‟s opening transmission function capital rate

base amounts.

Commission findings

294. The opening rate base for 2010 was $6.9 million less than approved in Decision

2010-505. During 2010 and 2011, the discrepancy increased to $10.2 million by an amount

approximately equal to the $4 million increase in CWIP, primarily due to the timing of the

completion of projects. Hence, capital additions during the 2010 to 2011 period were

$5.5 million less than approved in Decision 2010-505 (see Table 31) with the negative variance

in capital additions offset primarily due to the timing of projects, as reflected in the $4 million

higher than approved ending CWIP balance.

295. The Commission has reviewed the analyses of individual project variances provided in

the application including the 30 post implementation reviews provided.164 The Commission finds

that the capital additions are reasonable and accordingly approves EDTI‟s transmission function

161

Exhibit 57, Appendix E-2-T-PIR. 162



Exhibit 57, Appendix E-2-T-PIR.



2012 opening rate base as filed, subject to the following direction regarding CWIP balances. The

Commission directs EDTI to correct the $4.6 million discrepancy between 2011 actual closing

CWIP and 2012 forecast opening CWIP and to reflect this correction in 2012 opening and

closing CWIP balances in the compliance filing.

296. The Commission agrees in principle with EDTI‟s proposal to transfer the costs of the

system planning load and sustainability study to rate base in conjunction with the addition to rate

base of life-cycle expenditures that arise out of the study. As EDTI is not transferring the costs to

rate base at this time, a review of the project costs incurred will be made at the time the request

for transfer to rate base is submitted.

5.1.2 Transmission 2012 capital additions

297. EDTI has applied for approval of $46.4 million of 2012 transmission capital additions.

298. In the application, EDTI grouped its transmission capital additions into major cost

categories including AESO direct-assigned projects, transmission substation equipment, and

underground transmission equipment. Within each major category, all similar projects were

grouped into sub-categories consistent with directions 31, 32, and 33 from Decision 2006-054.

EDTI also classified its capital projects as being either growth driven, life-cycle replacement or

process improvement. The data in the following table indicates that growth-driven projects are

the primary driver of EDTI‟s 2012 transmission capital program.

Table 33. Transmission capital additions summary 2009-2012

TOTALS 2009 (A) 2010 (A) 2011 (A) 2012 (F)

Life-cycle projects 13.9 11.3 15.0 18.6

Performance improvement projects 1.5 3.4 4.8 5.8

Growth projects 6.1 38.4 21.1 38.4

Insert subtotals 21.6 53.1 40.9 62.8

Contributions -2.4 -20.2 -15.8 -16.4

Grand Totals 19.2 32.9 25.1 46.4

Source: Based on Table 13.2-1; Exhibit 167.07, AUC-EDTI-17 Attachment 4

299. The largest projects in EDTI‟s forecast transmission capital program for the 2012 test

year are the Poundmaker Substation ($24.66 million) and the Genesee interface to the new

HVDC converter station ($12.91 million). Life-cycle spending is forecast to be $3.6 million

higher than 2011 actual additions, primarily in response to the need to replace aging medium

voltage switchgear infrastructure.165 The Heartland project, as discussed in Section 13.2.1.10 of

the application, is forecast to be transferred from CWIP to a partnership.

Commission findings

300. In the application, EDTI provided a total of eighteen transmission capital project business

cases (T-CBC).166 The Commission has reviewed the documentation related to each of the capital

165


Exhibit 56, Appendix E-2-T-CBC.



projects and, subject findings in Section 5.1.3, the Commission approves the forecast

$46.4 million capital additions as filed.

5.1.3 Other issues related to transmission capital additions

301. Interveners expressed concerns regarding the following factors which are related to the

transmission capital additions forecast. These are examined individually in the following

sections.

age as a criteria in EDTI‟s asset replacement strategy

capacity to complete forecast capital work

the Heartland project

AESO direct-assigned projects

process improvement initiatives

5.1.3.1 Age as a criteria in EDTI’s asset replacement strategy

302. EDTI submitted that its aging infrastructure was causing problems including reliability

and security of supply, public and employee safety, stranded capacity, operational difficulties,

environmental concerns and an inability to handle anticipated load growth.

303. EDTI‟s approach to replacing aging infrastructure assets is to proactively monitor the

condition of the assets and to replace deteriorating assets on an as-needed basis. EDTI provided

an overview of its aging infrastructure, including the age profile of a number of types of assets in

Section 1.2.3 of the application. EDTI also provided information respecting various projects in

Section 13 of the application and further details were provided in EDTI‟s responses to

information requests.

304. The UCA submitted in its evidence that, “EDTI‟s assessment of assets for replacement

appears to be based largely on the age of the asset and not on the condition of the assets.”167

Consequently, the UCA recommended that EDTI‟s 2012 forecast transmission life cycle

expenditures be set at 2011 actual transmission capital addition amounts.

305. In argument, EDTI clarified that, as explained in its application, it does not simply

replace assets when they reach a predetermined age but actively monitors the condition of its

assets, performs condition based maintenance and refurbishes equipment, and only replaces

deteriorating assets on an as-needed basis when further refurbishment is no longer technically

and/or economically feasible.168 EDTI noted that the UCA had mischaracterized its assessment of

transmission assets for life-cycle replacement, based solely on EDTI‟s response to UCA-EDTI-

38169 regarding the prioritization of the replacement of the assets selected for inclusion in EDTI‟s

transmission function protective relay and control (P+C) equipment devices life-cycle

replacement program.

167

Exhibit 190.02, UCA evidence, A42. 168

Exhibit 206.02, EDTI argument, paragraph 337. 169

Exhibit 151.



306. In reply argument, the UCA repeated its earlier submission that the analysis provided in

UCA-EDTI-38 “clearly demonstrated that age was the predominant factor in prioritizing

projects” and that the proposed increase in lifecycle projects should be denied.170

Commission findings

307. The Commission has reviewed EDTI‟s transmission function business cases and IRs

respecting EDTI‟s life-cycle replacement programs. In particular the Commission notes EDTI's

submission that it determines when an asset has reached the end of its useful life “through

condition assessments of the particular asset in question, which include a combination of time-

based inspections, testing, failure investigations, compliance with structural and electrical code

requirements, industry life-cycle practices, and other condition assessments as required.”171

308. Moreover, the Commission has reviewed EDTI‟s response to UCA-EDTI-38 and notes

that the weighted factor assessment tool was used only to determine the prioritization of assets

selected for replacement. Accordingly, the Commission finds that the UCA has mischaracterized

EDTI‟s assessment of transmission assets for life-cycle replacement and consequently rejects the

UCA‟s proposal to deny the increase in lifecycle projects.

5.1.3.2 Capacity to complete forecast capital work

309. EDTI indicated that engineering and labour FTEs directly involved in the delivery of

capital projects and operating activities are forecast using EDTI‟s detailed bottom-up budgeting

approach, which produces reasonable and reliable FTE forecasts. The UCA, in the preamble to

UCA-EDTI-96, noted that EDTI has in the past had difficulty completing some forecast work

due to time and resource constraints. EDTI noted in argument that the UCA sought assurances

that EDTI would be able to complete all planned work in 2012.172

310. In response to the UCA-EDTI-96, EDTI noted that it was taking prudent steps to ensure

that it would complete the level of work reflected in its forecast but identified a number of

important reasons, apart from resource constraints, as to why certain types of work may not be

completed in a given year. For example, projects could be delayed due to factors which EDTI

cannot control including safety considerations, delays in obtaining approvals or outage

constraints. EDTI also noted in its responses to UCA-EDTI-96, as well as its response to

AUC-EDTI-69, that it had been successful in completing the levels of work forecast over the

2010-2011 period. Specifically, on an aggregate basis, EDTI‟s capital expenditures over the

2010-2011 test period exceeded the total decision amounts. As stated in AUC-EDTI-69, the

higher than forecast levels of capital work completed by both the distribution and transmission

functions shows that, despite fluctuations in the specific types of work completed, EDTI has

demonstrated its ability to complete its forecast levels of capital work.

311. In addition, in response to AUC-EDTI-69 concerning EDTI‟s ability to deliver on both

capital and operating work when volumes of different types of work fluctuate, EDTI stated that it

had improved its ability to complete its forecast levels of operating work in conjunction with

growing levels of capital work despite operating costs being higher for both the distribution and

transmission functions, over the period from 2009 to 2011. Moreover, EDTI submitted that it is

170

Exhibit 209.02, UCA reply argument, paragraph 37. 171

Exhibit 152, UCA-EDTI-96 d). 172

Exhibit 206.02, EDTI argument. paragraph 31.



not systematically under spending its operating costs to deliver forecast levels of capital

expenditures.173

312. In response to AUC-EDTI-08 and AUC-EDTI-19, EDTI provided a detailed explanation

of the method it uses to determine the number of FTEs required in relation to the forecast levels

of work in a test period. EDTI submitted that the detailed process not only ensures that EDTI‟s

forecast reflects the correct level of resources necessary to complete its anticipated workload, it

also ensures that EDTI is not overstaffed.174

Commission findings

313. The Commission acknowledges EDTI‟s submissions that it has consistently spent more

than its forecast operating expenses for each of its transmission and distribution functions during

the period from 2009 to 2011. As presented in the following table, during the 2009 to 2011

period, with the exception of 2010 for distribution, EDTI also spent more on capital expenditures

than forecast and, in aggregate during the three year period, actual expenditures exceeded

forecasts.175 Forecast capital expenditures for 2012 are $84.1 million for distribution (excluding

contributions) and $63.2 million for transmission (excluding Heartland and contributions)

compared to 2011 actuals of $84.6 million for distribution (excluding contributions) and

$53.2 million for transmission (excluding Heartland and contributions).

Table 34. 2009-2012 transmission and distribution capital expenditures ($ million)

2009 2010 2011 2012

Project type (D) (A) (D) (A) (D) (A) (F)

Transmission totals excluding contributions

25.9 40.3 57.1 44.6 30.7 81.3 19.5

Distribution totals excluding contributions

39.3 51.9 65.3 72.5 55.6 84.6 84.1

Total capital expenditures excluding contributions

65.2 92.1 122.4 117.1 86.3 165.9 103.6

Heartland totals 1.4 7.5 5.8 5.3 3.5 28.2 (43.7)

Total capital expenditures excluding contributions and Heartland

63.8 84.6 116.5 111.7 82.8 137.8 147.3

Source: Based on Exhibit 186.04, AUC-EDTI-68 b) Attachment 1, and Exhibit 186.05, AUC-EDTI-68 b), Attachment 2.

314. The Commission notes that there is no monitoring of the labour component of the

forecast operating work and the capital projects and that the information provided regarding the

extent to which work was performed by EDTI staff compared to contractors was an estimate

based on the function.

315. The fact that EDTI has spent more money than forecast does not necessarily mean the

forecast work has been completed. However, having reviewed the capital projects, it appears that

although there have been some delays in projects and new projects added, the capital program

has proceeded largely as forecast. In Section 3.1, the Commission has examined the forecast

number of FTEs and included in that section an analysis respecting the use of contractors. The

173



Exhibit 186.04, AUC-EDTI-68.



Commission is satisfied that EDTI has the ability to manage ongoing operating needs as well as

the proposed capital projects.

5.1.3.3 Heartland 500 kV transmission project

316. EDTI described the Heartland project in its 2010-2011 application. In accordance with

the AESO‟s directions, EDTI and AltaLink jointly filed a proposal to provide service (PPS) with

the AESO in mid-2010 and the Heartland facility application with the Commission in

September 2010. The Commission held an oral public hearing on the facility application in the

spring of 2011 and approved the facility application in Decision 2011-436.176

317. As discussed below, the CCA expressed concern regarding the capital overhead rate

applied to the Heartland project. The Heartland project is also relevant to the analysis of capital

expenditures and the cost of debt as discussed in sections 5.1.2 and 3.7 of this decision.

318. EDTI submitted that it has incurred costs in respect of this project associated with such

things as engineering studies, public consultation, regulatory approvals and long lead time items

and that it will continue to accumulate these costs in its CWIP account, pending their anticipated

transfer to a limited partnership. In CCA-EDTI-78, EDTI provided the following Heartland

CWIP continuity schedules:

Table 35. Forecast costs for the Heartland project 2011-2012 ($ millions)

2011 updated

forecast 2012

forecast

Opening CWIP in EDTI 14.44 43.69

EDTI direct costs for management oversight and public consultation 0.96 0.25

AltaLink costs for project management and oversight 26.21 51.34

Capital overhead 0.01 0.52

AFUDC 2.07 1.55

Contribution from Heartland Limited Partnership - (97.35)

Closing CWIP in EDTI 43.69 -

Source: Exhibit 168.01, CCA-EDTI-78

319. EDTI submitted that it was capturing all indirect costs associated with the Heartland

project through the capital overhead applied to this project at the rate of one per cent of the total

capital expenditures, consistent with EDTI‟s approach respecting all AESO-directed projects.

This approach has been used to date and will continue to be used until the Heartland project is

transferred to a new transmission facility owner (TFO) that will be created by EDTI and

AltaLink.177

320. The CCA questioned the relatively low capital overhead rate applied to AESO-directed

projects and to the Heartland project, in particular.178 The CCA noted that EDTI charged capital

176

Decision 2011-436: AltaLink Management Ltd. and EPCOR Distribution & Transmission Inc., Heartland

Transmission Project, Application No. 1606609, Proceeding ID No. 457, November 1, 2011. 177


Exhibit 191, CCA evidence, Section 5.




overhead rates of one and six per cent, respectively for AESO-directed and non-AESO-directed

transmission projects, and nine per cent for distribution projects.

321. EDTI explained that a one per cent overhead rate is used for AESO-directed projects as

they are generally larger in scope than internal projects and rely to a greater extent on external

resources to complete. The CCA submitted that, in its view, EDTI had not demonstrated why the

overhead rates should be lower for AESO-directed projects and recommended that all

transmission projects (excluding the Heartland project) and distribution projects be charged the

same capital overhead rate in 2012.179

322. Furthermore, the CCA pointed out that EDTI justified its rate by submitting that the

Heartland project is currently an EDTI in-house project, i.e. not an affiliate transaction. Given

that the Heartland project is a significant project in EDTI‟s books that is expected to be

transferred in the future to an affiliate, the CCA recommended that the overhead rates applicable

to affiliate projects180 should be applied to Heartland for 2012 and beyond.181

323. EDTI submitted that it allocated indirect support to projects in a manner that provides a

strong causation link to the support provided to projects. EDTI applies a lower overhead rate to

AESO-directed projects as they are typically managed and constructed by contractors, have a

lower proportion of EDTI labour and salary costs than non-AESO-directed projects, and

therefore require less support to complete.182

324. In reply argument, the CCA, noting that Heartland costs were substantially made up of

contractor related expenditures, acknowledged that its recommended approach to overhead

recovery, i.e., that which is used for affiliates of EDTI, would not appropriately capture the

overhead costs associated with the Heartland project. The CCA therefore submitted that the

overhead charges for Heartland should be calculated on the same basis as for affiliates as

77 per cent of project management labour costs with an additional 20 per cent cost recovery

surcharge.183

325. EDTI argued that the corporate cost allocation method applied fully captures the costs

associated with the Heartland project. Additionally, the CCA‟s recommendation that overhead

charges for Heartland should be allocated on the basis of project management time instead of on

the basis of direct labour and salaries is unsubstantiated. EDTI pointed out that the CCA had

overlooked the fact that AltaLink, being the joint venture partner responsible for the actual

construction of the project, will have the significant direct labour charges and the majority of the

project oversight from a construction point of view. EDTI‟s responsibilities, on the other hand,

related to the public consultation process and involvement in the various regulatory proceedings.

In view of the above, EDTI submitted that the CCA recommendations regarding additional costs

should be rejected.184

179

Exhibit 191, CCA evidence, paragraph 34. 180

Exhibit 3, application, paragraph 1712. EDTI submitted that it provides services to affiliates on a cost recovery

basis. To ensure that it is recovering its reasonable costs EDTI adds an overhear charge of 77 per cent to direct

labour costs and cost recovery surcharge of 20 per cent to its direct costs of providing services. 181


Exhibit 203.02, EDTI rebuttal evidence, section 9. 183

Exhibit 207.01, CCA argument, paragraph 89. 184

Exhibit 211.02, EDTI reply argument, paragraph 182.



326. Respecting the CCA's recommendation that all transmission projects, excluding

Heartland, should be charged the same overhead rate, EDTI submitted that the allocation

methodology is not representative of the relative administrative effort that AESO-directed and

non-AESO-directed projects require on an actual basis. EDTI reiterated that its approach to

overhead allocation is based on a strong cost causation relationship and the CCA‟s

recommendation, without any evidentiary support, is not representative of actual effort and costs,

and therefore should be rejected.185

Commission findings

327. The Commission accepts the principle that the method of cost allocation should where

possible reflect cost causation and finds that EDTI has determined its allocation rates based on

this principle. The Commission recognizes that, if too little overhead is allocated to the Heartland

project, other projects would have to absorb a disproportionate share of overhead. However,

based on the record, as presented in Table 35 above, the forecast Heartland costs for 2012

include only $0.25 million of EDTI direct costs for management oversight and public

consultation. The majority of costs ($51.34 million) are transferred from AltaLink. EDTI has

recorded AFUDC on the balance in the account and overhead at the rate of one per cent on costs

incurred in the current year.

328. As it is expected that the Heartland project will be transferred to an affiliate, it could be

argued that overhead should be allocated on the basis used for affiliates. However, given the

uncertainty of the future transfer and the small amount of direct costs incurred, the Commission

considers the allocation of overhead at the one per cent rate applied to AESO-directed projects is

reasonable.

329. The Commission rejects the CCA recommendation that all transmission projects

(excluding the Heartland project) and distribution projects should be charged overhead at the

same rate. The Commission relies on EDTI‟s explanation that AESO-directed projects are

generally larger in scope than internal projects and rely to a greater extent on external resources

to complete

5.1.3.4 AESO-directed projects

330. EDTI provided descriptions of AESO-directed projects in Section 13.2.1 of the

application. In sections 13.2.1.1 to 13.2.12, EDTI described the projects currently being

undertaken.

331. Four “proposed” AESO-directed projects, “under review and discussion with the AESO,

which may proceed during the Test Period,”186 were described in Section 13.2.13. EDTI

submitted that these projects do not impact EDTI‟s 2012 forecast revenue requirement and have

been included in the application for information purposes only. The following table summarizes

the forecast costs of the four proposed AESO-directed projects, which EDTI included as

additions to rate base.

185

Exhibit 211.02, EDTI reply argument, paragraph 183. 186

Exhibit 3, paragraph 4104.



Table 36. AESO-directed projects included in Section 13.2.1.13

Project 2012 additions to rate base

($ millions)

Genesee interface to HVDC converter station 12.91

East HVDC converter station interface – RAS scheme communication 0.10

Total HVDC converter stations 13.01

Victoria substation capacity upgrade 0.51

Lambton transformers capacity upgrades 0.18

Total capacity upgrades 0.69

332. In response to AUC-EDTI-48,187 wherein EDTI was asked to clarify whether the four

projects “were included in the application for information purposes only”188 and their inclusion in

the application as capital additions,189 EDTI stated that these projects were and should have been

included in the 2012 revenue requirement. However, in argument EDTI stated that it now

expected that the majority of the work on the two HVDC projects would not be completed until

2013. Nevertheless, EDTI submitted that, for the following reasons, the Commission should

allow EDTI to include the two HVDC projects in its 2012 forecast revenue requirement as filed,

and to true-up the dollar amounts in the normal course of its AESO-directed projects deferral

account:

a. EDTI has clear direction to proceed with the projects

b. EDTI expects to incur significant expenditures on these projects

c. The AESO-directed projects deferral account will ensure that

i. customers will pay actual costs to complete the projects

ii. customer refunds or charges will occur relatively quickly with the expected filing

of EDTI‟s 2012-2013 capital application in October 2012.

d. A significant amount of work will be required to remove these projects from the 2012

forecast revenue requirement.190

Commission findings

333. The Commission acknowledges EDTI‟s submission that “EDTI now expects that the

majority of the work associated with [the Genesee Interface to HVDC Converter Station project

and the East HVDC Converter Station Interface – RAS Scheme Communications project] is

expected to be completed in 2013.”191

334. Even though EDTI has an AESO-directed projects deferral account, the majority of the

work will not be completed until 2013 and, as such, the Commission finds that EDTI should not

include these projects as capital additions in its 2012 forecast revenue requirement as filed.

Accordingly, the Commission directs EDTI to remove the Genesee Interface to HVDC

Converter Station and the East HVDC Converter Station Interface from its 2012 revenue

187



Exhibit 3, Table 13.2-1, EDTI transmission capital additions 2009-2012, page 1214. 190

Exhibit 206.02, EDTI argument, paragraphs 351 and 352. 191

Exhibit 206.02, EDTI argument, paragraph 350.



requirement. Moreover, the Commission directs EDTI in its compliance filing to reflect this

direction in EDTI‟s transmission capital additions schedule and all related schedules.

5.1.3.5 Process improvement initiatives

335. EDTI submitted that it seeks to identify and implement process improvement

opportunities and incorporate the associated cost savings into its forecasts. In Section 1.2.4,

EDTI provided a listing of process improvement initiatives distinguishing initiatives that resulted

in cost reductions and initiatives that resulted in improved reliability, safety or customer service.

The following table shows the process improvement initiatives that EDTI identified and

proposed to implement in the 2012 test year where the benefits will begin to be realized in that

year.192

Table 37. 2012 Process improvement initiatives ($ millions)

Description Savings 2012 rate base

additions

($ millions)

Process improvements that result in operating cost savings

GIS – performance improvement project 0.18 0.83

SUBTOTAL 0.18

Process improvements that result in improved reliability, safety and customer service

Installation of network current limiting fuse program 0.57

Distribution system aerial underground fault indicators and fusing 0.96

Installation of automated switches on selected 25kv circuits 1.41

Transmission substation security upgrades 0.93

Medium voltage switchgear – arc resistance upgrade 0.74

Communication system upgrade 1.93

SCADA MTU system security upgrades 0.63

Switchgear on-line monitoring installation 0.54

Transmission underground cable spares 0.77

Safety software (T,D) 0.37

Source; Based on Exhibit 3, Table 1.2.4-1

336. Respecting the GIS performance project noted in the above table, EDTI submitted that

the project was initiated to increase the flexibility and speed of making configuration changes to

its GIS tool. The proposed enhancements would allow for real-time updates of information from

the office to the field and increase the usability of the GIS system. EDTI proposed to increase the

flexibility and speed of configuration changes to EDTI‟s GIS tools through the addition of

FieldSmart Configuration Environment (FCE) and FieldSmart PLOT (PLOT) modules.193

Respecting its proposal, EDTI further clarified that “[t]here is no specific forecast decrease in

costs shown in any of EDTI‟s operating sections, as the cost associated with hiring a vendor

($0.18 million) is an avoided cost and not a reduction to current cost levels.”194

192



Exhibit 150, CCA-EDTI-31.



337. The CCA asked information requests about process improvements and submitted in

evidence that EDTI‟s projects, related to process improvements resulting in improved reliability,

safety and customer service, should result in O&M savings in the test year. “To suggest none of

the foregoing projects will avoid any costs in 2012, or provide tangible productivity savings in

2012, is not plausible.”195

338. The CCA identified four process improvement projects that the CCA submitted should

have some related O&M savings in the 2012 test year. The following bulleted subsections

describe the identified projects and provide the CCA‟s views regarding the savings that should

accrue from each of the projects:

Distribution system aerial, underground fault indicators and fusing

The purpose of this project is to improve the safety and reliability of EDTI‟s distribution

system. The primary justification for installation of fault indicators is to reduce outage

duration time. Notwithstanding, EDTI submitted that it will not realize any cost savings

as no staffing reductions will be facilitated by the reduced investigation and patrol time.196

CCA questioned EDTI‟s position that although it would undertake measures which result

in higher productivity, no cost savings were forecast for 2012. Furthermore, the CCA

stated that it is necessary for EDTI to rationalize its deployment of trouble crews in a

more efficient manner to realize the benefits of the costs associated with the productivity

initiatives.197

Installation of automated switches on selected 25 kV circuits

The purpose of this project is to improve the reliability of EDTI‟s distribution system.

EDTI submitted that reduced patrol times, a secondary benefit, may result in faster

restoration of the isolated outages as the location of the fault can be found faster. EDTI

also submitted that the time and costs to complete any repairs will be the same as this

project will not reduce EDTI‟s staffing as regards to Trouble Crews.198

CCA submitted that it is reasonable to expect that a reduction in fault investigation and

patrol times should translate to reduced costs. “There is little merit in investing in

productivity and process improvement initiatives which simply result in the same labour

component doing the same things but in less time.199

Communications system upgrade

EDTI submitted that this project consists of installing fibre optic communication cables

to remedy deficiencies in the communication system used for SCADA and teleprotection

purposes to improve the reliability and operational integrity of EDTI‟s existing

communications system. Furthermore, the project will “allow EDTI‟s unmanned

substations and transmission distribution functions to continue to reliably operate through

195





Exhibit 191, CCA evidence, paragraph 49.



communication equipment that provides adequate data and visibility of EDTI‟s

substations while meeting a number of standards and guidelines.”200

Implicitly assuming that actuals from prior years were used to generate the 2012 forecast,

the CCA submitted that EDTI‟s project, since it remedied SCADA and teleprotection

communications deficiencies, would provide EDTI more compensation than required.201

Switchgear on-line monitoring installation

The existing gas insulated switchgear at EDTI‟s Bellamy substation is 34 years old and

EDTI has recorded 25 failures on various components of this switchgear in the last 11

years. EDTI submitted that this project would not result in any cost decreases as this

work would simply give EDTI the ability to detect and help prevent insulation failures

during the period leading up to the replacement of the gas insulated switchgear at EDTI‟s

Bellamy substation.202

Noting the numerous failures on the switchgear in the last 11 years, the CCA opined that

the failures would have required O&M costs to remediate. The CCA submitted that if this

was the case and EDTI had incorporated actuals from prior years to generate the 2012

forecast of repair costs, the 2012 repair cost forecast would provide EDTI more

compensation than required.203

339. The CCA submitted that, based on the evidence filed, EDTI will implement productivity

improvements not specifically identified in the forecast. The CCA submitted that a $ 0.25 million

reduction in O&M should be directed in respect of the potential productivity savings in 2012.204

340. EDTI submitted that the productivity improvement benefits to be realized in future test

periods are in the nature of improved reliability, safety and customer service (i.e., not O&M

savings as asserted by the CCA). EDTI further stated that the projects are not new to EDTI and

“EDTI has never forecast any cost reductions related to their implementation, nor has its

experience in implementing these projects identified any cost reductions as asserted by the

CCA.”205 The purpose of the projects outlined in the first two bulleted items above is to improve

overall system reliability with the intent of reducing the number of customers impacted by

outages and the speed at which outages are restored. Further, the purpose of the communications

project identified in Section 1.1.3 is to add a redundant fibre optic cable to transmission having

only one cable routed to them.206

341. With respect to the CCA‟s recommendation to reduce operating costs by $0.25 million,

EDTI submitted that, while EDTI will continue to search for new ways to be more efficient, this

does not justify a reduction in EDTI‟s forecast operating costs. Process improvements take time

to develop and implement, after which cost savings may be realized. As the present application

has a one year test period, there is not sufficient time for EDTI to realize any material cost

200





Exhibit 191, CCA evidence, paragraph 58 205

Exhibit 203.02, EDTI rebuttal, A39. 206

Exhibit 203.02, EDTI rebuttal, A40.



savings beyond those already identified in the application. The CCA‟s recommendation is unfair

and incongruent respecting the reality of how cost savings are achieved and realized.

342. In respect of the performance improvement project issue, the CCA submitted that while

customers will pay the capital and operating costs in 2012, all savings from the aforementioned

projects will flow to EDTI over the period from 2012 to 2017. The CCA also noted EDTI‟s

evidence that initiatives identified and implemented during a test period may result in savings

that were not contemplated at the time the test period forecast was prepared. The CCA therefore

reiterated its recommendation to reduce 2012 O&M expenses by $0.25 million, arguing that the

reduction would give due recognition to the potential savings.207

343. With respect to the GIS project, the CCA stated that while it did not dispute the costs and

benefits of the project, considering that the completion date is near the end of 2012, it is doubtful

that the full extent of the touted benefits, or for that matter the projected $0.18 million of annual

cost savings, will be realized. In order to better match the project‟s capital costs and incremental

operating expenses to rate revenues, the CCA reasserted its recommendation that the project be

deferred to 2013.208

344. EDTI reasserted that the benefits associated with the forecast ten process improvement

projects will be realized in future test periods and will be in the nature of improved reliability,

safety and customer service. EDTI submitted that the CCA‟s position that EDTI‟s 2012 forecast

should be reduced to account for potential further process improvements is without merit and

should be rejected. With respect to the CCA‟s assertion that the GIS performance project be

deferred to 2013 because 2012 is the going-in year for PBR, EDTI submitted that what the

CCA‟s suggestion “amounts to is cherry picking a particular cost for adjustment, but ignoring

likely cost increases that will come over the course of the PBR term.”209 Further, there is no

reasonable basis for suggesting that the project should be deferred; based on the expected

benefits of the projects as outlined in the business case. The project is reasonable and prudent,

and the costs of the project are properly included in 2012.

Commission findings

345. The Commission has reviewed the application and the business case related to the GIS

system and notes the expected operational improvements and the expectation of avoided costs.

Considering the ongoing and continuing nature of the perceived benefits, the Commission finds

that the project is reasonable and prudent. Accordingly, the Commission approves the 2012 GIS

project costs.

346. The Commission acknowledges EDTI‟s submission that, although reduced investigation

and patrol time will result in faster restoration of the outages, as trouble crews are staffed

24 hours and seven days per week, there will be no cost reductions from the safety and reliability

projects. Therefore, the Commission rejects the CCA‟s proposal for a proposed reduction to

forecast costs of $0.25 million.

347. Notwithstanding, the Commission acknowledges the concerns of the CCA that cost

savings are not forecast for projects described as process improvements and EDTI‟s position that

207

Exhibit 207, CCA argument. 208

Exhibit 207, CCA argument. 209

Exhibit 206.02, EDTI argument.



emergency staff must be available so that there is no direct relationship between reduced times

on individual projects and forecast costs. However, given EDTI‟s method of forecasting FTEs,

benefits could be incorporated in the scheduling and forecasting process although not specifically

identified as related to a particular project. In the analysis of FTEs in Table 3 the number of

distribution operating FTEs is forecast to decrease from 353.7 in 2011 to 345.8 in 2012 and in

Table 4 the number of transmission operating FTEs is forecast to increase from 68 in 2011 to 77

in 2012. The decrease in forecast distribution operating FTEs, despite system growth, indicates

efficiencies although the source is not specifically identified. Considering the above, the CCA

has not persuaded the Commission to reduce EDTI‟s 2012 O&M expenses. Accordingly, the

Commission approves EDTI‟s 2012 process improvement initiatives as shown in Table 1.2.4-1

of the application.

5.2 One-off projects

348. In the 2012 test year, EDTI proposes to carry out a number of “one-off” substation

maintenance projects. The following table summarizes EDTI‟s 2012 forecast and prior years‟

cost respecting one-off transmission substation apparatus maintenance and repair.

Table 38. Transmission substation apparatus maintenance and repair 2009-2012 ($ millions)

2009 (A) 2010 (D) 2010 (A) 2011(D) 2011 (UF) 2012 (F)

“one-off” maintenance” 0.01 0.15 0.05 0.00 0.00 0.43

Source: Based on Exhibit 3, Table 6.3.3.1-3; CCA-EDTI-57 Legend: (A) actual, (D) decision, (UF) updated forecast, (F) forecast

349. EDTI submitted that its 2012 transmission substation apparatus maintenance and repair

forecast included the following two project expenditures:

a. $0.16 million to decommission and remove from service the 15 kV switchgear transfer

bus installed at EDTI‟s Hardisty Substation, and

b. $0.27 million to refurbish the load tap changer on one transformer located at EDTI‟s East

Industrial Substation.

350. EDTI submitted that it typically identifies one-off operating and maintenance projects

that must be completed in each test period. Moreover, responding to CCA-EDTI-57, EDTI stated

that it often identifies projects that must be completed during a test period that were not

anticipated and the associated costs were therefore not included in a tariff application.

351. EDTI confirmed that the proposed one-off substation maintenance projects would be

completed in 2012. With respect to the 15 kV switchgear transfer bus project, EDTI submitted

that it had to be decommissioned and removed from the site as EDTI could no longer safely

maintain the equipment, as its is required to under the Alberta Electrical Utility Code.

Furthermore, delays respecting the load tap changer one-off project could result in a catastrophic

failure of the transformer.210

352. The UCA voiced concerns respecting the two one-off projects and submitted that the

projects have not been justified. Furthermore, the UCA expressed a concern that EDTI has

210

Exhibit 150, CCA-EDTI-58.



forecast these costs for 2012, which happens to be the revenue requirement that will set the going

in rates for PBR.211

353. EDTI submitted in its rebuttal evidence that it had provided clear justification for the two

projects because there were no maintenance options to carrying out these projects and the

consequences of delaying these projects were not acceptable.212

354. In argument, EDTI reiterated that it has provided clear and detailed justification for the

projects in its application. Furthermore, while these are one-off projects, EDTI submitted that it

anticipated that it would carry out similar projects in the future such as the Celanese transmission

substation and East Industrial Load Tap Changer Refurbishment projects for 2013 referred to in

its application.213

Commission findings

355. The Commission acknowledges EDTI‟s determination that serious problems have been

identified and projects of a non-recurring basis, or “one-off” projects, are required to address

them. Further, as EDTI has stated, “there are not maintenance options available to EDTI by

which the risks associated with leaving the problem unaddressed could be mitigated.”214 The

Commission recognizes that a utility cannot possibly identify all of the maintenance projects that

may arise in a test period. For purposes of this application, the Commission finds that EDTI has

provided justification for the one-off projects described above. Accordingly, the Commission

approves EDTI‟s forecast costs for 2012 one-off projects.

6 Corporate services costs

356. By way of a letter dated December 16, 2011, EUI asked that the Commission consider

matters related to both EDTI and EEAI in the area of corporate services costs as part of this

proceeding. The Commission undertook to consider matters relating to corporate services costs

for both EDTI and EEAI for 2012 in this proceeding and informed parties in a letter dated

December 20, 2011.

357. In this section, references to EDTI will also incorporate EEAI and findings of the

Commission will apply to both EDTI and EEAI for the 2012 forecast period unless stated

otherwise.

358. EDTI and EEAI are members of the EPCOR group of companies. EDTI and EEAI

receive services from and provide services to other members of the EPCOR group including:

(i) services provided by EUI to EDTI and EEAI (corporate services) and (ii) services provided

by EDTI and EEAI to other EPCOR affiliates including each other (affiliate services). This

section will address the forecast EUI corporate services costs as they relate to EDTI and EEAI

for the 2012 test year.

359. Corporate services costs are recovered by EUI from EDTI and EEAI through one of three

mechanisms: direct assignment of the cost, allocation of the cost, or by way of an asset usage fee.

211

Exhibit 190.02, CCA evidence of Russ Bell, A 35; Exhibit 204.02, UCA argument. 212

Exhibit 203.02, EDTI rebuttal evidence. 213

Exhibit 206.02, EDTI argument. 214

Exhibit 206.02, EDTI argument.



The 2012 forecast EUI corporate services costs and the amounts assigned to each of EDTI and

EEAI, with the comparative 2010 and 2011 decision approved and actual expenditures, are

shown in the table below:

Table 39. 2010-2012 corporate services costs by utility ($ millions)

Corporate Services Costs 2010

approved 2010

actual 2011

approved 2011

actual 2012

forecast

EUI

Directly assigned 17.35 17.48 18.06 17.40 18.92

Allocated 61.66 55.88 65.64 58.47 69.74

Asset usage fees 13.78 13.23 15.56 17.53 17.97

Total EUI costs 92.79 86.59 99.26 93.41 106.63

EDTI


Allocated 22.02 19.95 23.50 21.49 24.25

Allocations non recoverable (1.54) (0.35) (1.38) (1.94) (0.81)

Asset usage fees 4.60 4.51 5.20 6.06 6.08

Negotiated settlement reductions (2.85) (3.17)

Total EDTI costs 26.69 29.02 28.91 30.61 34.45

EEAI


Allocated 11.10 9.38 11.72 10.80 10.49

Allocations non recoverable (0.90) (0.29) (0.80) (1.19) (0.41)

Asset usage fees 3.35 3.05 3.70 4.20 4.14

Negotiated settlement reductions (2.16) (2.33)

Total EEAI costs 20.24 20.04 21.22 21.88 23.75

Source: AUC-EDTI-70 Table 10.0-1 Revised

360. A review of the table above reveals that EUI was successful in identifying and capturing

cost savings in both 2010 and 2011. However, the costs allocated to both EDTI and EEAI are,

with the exception of the costs in 2010 for EEAI, higher than the amounts agreed to in the

negotiated settlement approved by the Commission in Decision 2011-262.215 In AUC-EDTI-33,

in responding to a Commission information request about changes to the allocators introduced

since EDTI‟s last application, EDTI identified 33 examples of changes in cost allocation

practices.216 These changes affect approximately 80 per cent of the corporate services allocated to

EDTI and EEAI.

215

Decision 2011-262: EPCOR Distribution & Transmission Inc. and EPCOR Energy Alberta Inc., 2010-2011

Corporate Costs Module – Approval of a Negotiated Settlement Agreement, Application No. 1605759,

Proceeding ID No. 437, June 21, 2011. 216

Exhibit 167.01, AUC-EDTI-33, page 62.




6.1 Legal and regulatory framework

361. In information response AUC-EDTI-11, EDTI outlined the basic legal framework under

which it considered that the Commission should assess the EDTI and EEAI applied-for corporate

services costs. EDTI submitted that the legislation requires the Commission to ensure that an

electric utility owner‟s tariff:

is just and reasonable

provides the owner with a reasonable opportunity to recover its prudent costs and

expenses that the Commission considers appropriate, including a fair allocation of the

owner‟s costs and expenses that relate to the owner‟s electric utilities

is not unduly preferential, arbitrarily or unjustly discriminatory or inconsistent with or in

contravention of the Electric Utilities Act, SA 2003, c. E-5.1 or any other enactment or

any law

362. EDTI submitted that the Commission must also exercise its discretion with a view to

ensuring that both utility and customer interests are taken into account and balanced in the rate

setting process.

363. EDTI submitted that the record demonstrates that its corporate services costs reflect

functions and activities that are necessary for the utilities to provide utility service and that those

costs are substantially lower than the costs that the utilities would incur to procure the services

on a stand-alone basis, either through self-providing them or procuring them from an arms-length

third-party service provider.

364. During this proceeding, the UCA filed evidence by Shelley Radway which addressed the

legal and regulatory framework that, in its view, the Commission should consider when

assessing EDTI and EEAI‟s corporate services costs. The UCA cited several regulatory

principles that should be considered when assessing the corporate services costs, including the

burden of proof; the no-harm principle (including its relationship to the code of conduct) and the

stand-alone principle. A brief summary of the arguments provided by the UCA on these

principles follows.

365. The UCA submitted that the EPCOR Group Inter-Affiliate Code of Conduct (Code or

Code of Conduct) is an important consideration as part of the regulatory principles. EUI has an

exemption in its Code of Conduct to allow for shared services, such as corporate services costs,

to be allocated to the utilities and EUI‟s other businesses, whether they were regulated or not, in

order to allow for efficiencies to be passed on for mutual benefit of the businesses. The UCA

submitted that there is no provision in the Code of Conduct that states that EUI has a right to

automatically pass on additional costs when it engages in transactions which cause inefficiencies

such as the so called “lost economies of scale” due to a sale of an unregulated corporate asset. In

other words, the purpose of the Code of Conduct does not allow EUI to pass on increased costs

due to inefficient transactions, but rather the utilities should be shielded from the activity of the

corporate parent due to the stand-alone principle. Under the stand-alone principle, the revenue

requirement of each of EDTI and EEAI should not be influenced by the ups or downs of the

operations of EUI or the sale of generation assets to a newly created “sister company,” such as

Capital Power Corporation (Capital Power or CPC). The UCA submitted that the stand-alone

principle is important because it shields a regulated entity from increases in costs caused by the

activity of the corporation or its affiliates. EUI is free to make decisions that benefit its



shareholder even if it makes EUI less competitive. Corporations are free to manage their

businesses in ways that allow them to be less efficient in their markets, but they are not free to

pass on these increased costs to regulated utilities.

366. Further, the UCA submitted that the additional corporate services costs allocated to the

utilities after the sale of the CPC generation assets have “harmed” the utilities‟ customers. The

UCA cited previous proceedings before the Commission, and its predecessor the board, where

the sale of regulated assets was outside of the ordinary course of business and was only approved

if there was no harm to customers. The UCA acknowledged that, while there was no requirement

for EUI to seek approval of the sale of its generation assets, the impact of the sale and any

resulting harm to the utilities‟ customers was still a matter for the Commission to decide.

367. In its rebuttal evidence, EDTI objected to the UCA‟s application of the no-harm principle

and the stand-alone principle. EDTI submitted that to accept the UCA‟s position would mean

that, under the Code of Conduct, it would be permissible for costs to decrease as economies of

scale increase, but any increase due to reductions in economies of scale would be prohibited.217

368. EDTI submitted that it has demonstrated that the shared corporate services structure

continues to be prudent for the utilities, and yield reasonable costs for these services, which are,

in fact, substantially lower costs than either EDTI or EEAI could obtain on a stand-alone basis.

Commission findings

369. Pursuant to Section 121(2) of the Electric Utilities Act when considering whether to

approve a tariff application, the Commission must ensure that:

(a) the tariff is just and reasonable,

(b) the tariff is not unduly preferential, arbitrarily or unjustly discriminatory or inconsistent

with or in contravention of this or any other enactment or any law, […]

370. As well, pursuant to Section 122(1) of the Electric Utilities Act, 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.

371. Section 121(4) of the Electric Utilities Act also states that the burden of proof to show

that a tariff is just and reasonable is on the person seeking approval of the tariff.

372. Similarly, the legislative framework governing EEAI stresses an assessment of the

prudency of EEAI‟s costs. EEAI‟s tariff is prepared under Section 103 of the Electric Utilities

Act, which requires each owner of an electric distribution system to prepare a regulated rate tariff

for the purpose of recovering the prudent costs of providing electricity services to eligible

customers. Further, under subsection 6(1)(a) of the Regulated Rate Option Regulation,

AR 262/2005, the Commission must have regard for the principle that a regulated rate tariff,

217

Exhibit 203.02, EDTI rebuttal evidence at page 3.



including the risk margin included therein, must provide the owner with a reasonable opportunity

to recover the prudent costs and expenses incurred by the owner.

373. In its argument, the UCA acknowledged that “it is for the Commission to decide whether

or not to apply the no-harm principle or some other set of criteria to evaluate the significant

increase in the quantum of corporate costs forced upon EDTI‟s and EEAI‟s customers.”218

374. The Commission finds that compliance with this legislative framework can be best

assessed through the three questions that were set out in Decision 2010-505219 where the

Commission asked parties to consider whether:

1. the costs related to the provision of services from EUI and EDTI are necessary for

EDTI and EEAI to provide utility service?

2. the costs are allocated correctly among EDTI, EEAI and EWSI?220

3. it would be less expensive for EDTI and EEAI to provide the services themselves or

seek a different third party provider on a stand alone basis?

375. As well, in Decision 2011-399,221 the Commission stated:

23. Based on the matters discussed in Section 4.3 of Decision 2010-505 and further

pursued in the corporate cost module, in addressing issues related to the quantum of lost

economies in EDTI‟s revenue requirement for 2012, the Commission expects to consider

the following:

i) whether some corporate costs should be allocated to EUI itself for its

management of its investment in Capital Power

ii) whether some corporate costs should be allocated to EUI itself for its

management of the funds remaining from its partial sale of Capital Power

iii) whether any corporate costs constitute business development costs unrelated to

EDTI and EEAI and are therefore not recoverable from customers of EDTI and

EEAI

iv) whether the costs for any remaining services provided to Capital Power are in

excess of the direct charges to Capital Power

v) whether or not EUI has adequately adjusted its corporate costs to reflect its

smaller size

vi) whether or not EUI has acquired any new businesses to which it should allocate

some of its corporate costs

vii) whether there are any legal principles that the Commission should consider in

addressing the issue of lost economies of scale

218

Exhibit 204.02, UCA argument at page 23, paragraph 99. 219

Decision 2010-505 at paragraph 100. 220

As the application filed by EPCOR only addresses the corporate services costs for EDTI and EEAI, this

decision only considers the corporate services costs related to EDTI and EEAI. 221

Decision 2011-399: EPCOR Distribution & Transmission Inc., Determination of Whether an Audit of

Corporate Costs is Required, Application No. 1605759, Proceeding ID No. 437, October 7, 2011, at

paragraph 23.




viii) whether any adjustments are required if it is determined that EUI, as opposed

to customers, should pay for any or all lost economies of scale that would

remain in 2012 and beyond222

376. The Commission considers the best starting point for its assessment of the allocated

corporate services costs is its findings in Decision 2010-505, with reference to the eight points

from Decision 2011-399 where applicable.

377. The Commission first addresses the arguments of the UCA, specifically the stand-alone

principle and the no-harm principle as submitted by the UCA.

378. The Commission considers that the UCA‟s position is inconsistent with the intent of the

Code. Previous decisions from the board have confirmed that the Code was not intended to

ensure that costs never go up but rather to protect ratepayers from a lack of transparency and the

potential for abuse through the use of affiliates.223 The UCA‟s approach would be contrary to the

legislative framework outlined above. Specifically, when approving a tariff the Commission

must provide the owner with the opportunity to recover its prudent costs and expenses.

Conversely, corporate services costs allocated from EUI to each of EDTI and EEAI will not

automatically be approved. The Commission must ensure that the corporate services costs

allocated are just and reasonable.

379. With respect to the no-harm principle, based on the facts in this proceeding, the

Commission considers that it cannot rely on the no-harm test. EUI was not, at the time of sale of

CPC a designated utility pursuant to the Public Utilities Designation Regulation, AR 194/2006.

As such, there was no requirement for EUI to seek approval of the sale of its generation assets.

Historically, when employing the no-harm test, the Commission has indicated that when a

finding of harm has occurred in the past, the Commission must assess the available evidence to

determine whether mitigation of harm is to be required on an ongoing basis.224 The issue of

whether the no-harm test should be used with respect to the sale of CPC and the corporate

services costs allocation was not addressed during EDTI and EEAI‟s last GRA as the issue of

corporate services costs was negotiated.225 Given that it is now four years after the sale of CPC

and that EUI is not currently nor was it at the time of sale a designated utility, the Commission

considers that it is incongruous to employ the no-harm test to assess the corporate services costs.

The legislative framework, coupled with the three questions from Decision 2010-505 provide the

Commission with the necessary guidance to ensure that EDTI‟s corporate services costs are just

and reasonable.

380. For all of the above reasons, in the sections that follow, the Commission will use the

three questions set out in Decision 2010-505, with reference to the eight points in Decision

2011-399 where applicable, to determine whether the allocation of corporate services costs to the

utilities is just and reasonable. In making this determination, the Commission considers that the

applicant has the onus to support its tariff application.

222


See Decision 2003-040: ATCO Group, Affiliate Transactions and Code of Conduct Proceeding, Part B: Code of

Conduct, Application No. 1237673, May 22, 2003, at page 24 and page 76. 224

Decision 2009-176: AltaGas Utilities Inc. 2008-2009 General Rate Application Phase I, Application

No. 1579247, Proceeding ID. 88, October 29, 2009, at paragraph 300. 225

See Proceeding ID No. 437.





6.2 Corporate services costs allocated from EPCOR Utilities Inc.

381. In Decision 2010-505 the Commission made the following finding:226

The Commission has concluded that it is not in a position to determine the proper

regulatory treatment for EDTI‟s and EEAI‟s allocated corporate costs considering the

effects of the corporate restructuring following the spin off of CPC from EUI. For some

items, there is some evidence that could support the allocation of portions of what EUI is

allocating to EDTI and EEAI, yet there is also some evidence favoring the UCA‟s and the

CCA‟s requests to lower those cost allocations. The Commission also recognizes that

neither CPC nor EUI are regulated companies.

382. As such, the Commission directed that a separate module be convened for the purpose of

investigating the corporate services costs in a more detailed fashion. The Commission invited

parties to consider whether all, none or some of the corporate services costs allocated to the

utilities should be allowed and outlined the “basic framework for analysis”227 which included the

three questions described above. In Decision 2011-262, the Commission approved a negotiated

settlement agreement that reflected an agreement on the quantum of corporate services costs

allocated or assigned to EDTI and EEAI but also included an outstanding matter related to the

requirement for an independent audit of the EUI corporate and shared costs. As outlined above,

the question of whether or not an audit was required was addressed in Decision 2011-399 and the

eight points the Commission expected to consider when assessing EDTI‟s corporate services

costs in EDTI‟s next GTA were introduced.

383. The three questions identified in Decision 2010-505 are discussed in the sections that

follow in the context of this application and, where appropriate, supported with references to the

eight points from Decision 2011-399.

6.2.1 Are the costs related to the provision of corporate services from EUI to EDTI and

EEAI necessary for EDTI and EEAI to provide utility service?

6.2.1.1 Total corporate services costs to be allocated

384. In support of its applied for corporate services costs, EDTI provided evidence that

outlined the basis for the 2012 corporate services costs forecast including a service by service

discussion of why each corporate service is required to enable EDTI and EEAI to provide utility

service. This evidence was supported with an assessment prepared by PA Consulting with the

assistance of Solvera Solutions on the reasonableness of the 2012 forecast (the PA report). EDTI

also filed expert evidence by Dr. Dennis Weisman addressing matters related to the role of

regulation as a proxy for competition.

385. In the application, EDTI identified the corporate services provided by EUI to EDTI and

EEAI. As presented in the table below, the costs of these corporate services are directly assigned,

allocated or charged as an asset usage fee:

226


Decision 2010-505 at paragraph 99.



Table 40. 2012 corporate services costs by method ($ millions)

Corporate services costs EUI total

EDTI dist.

EDTI trans.

EDTI total

EEAI total

Other total

Directly assigned costs

Total IS 15.60 3.98 0.64 4.62 7.31 3.68

SCM-space rent 2.59 0.00 0.00 0.00 2.15 0.44

SCM-facility 0.64 0.31 0.00 0.31 0.00 0.33

Corporate security 0.08 0.00 0.00 0.00 0.07 0.01

Total directly assigned costs 18.92 4.29 0.64 4.93 9.53 4.46

Allocated costs

Supply chain management 14.78 3.86 1.44 5.30 1.87 7.60

Human resources 6.40 1.99 0.30 2.29 0.83 3.28

Information services 10.14 2.94 0.48 3.42 1.95 4.77

Corporate finance 6.13 1.56 0.58 2.14 0.89 3.11

Executive & executive assistants 2.70 0.65 0.27 0.92 0.42 1.36

Treasury 2.38 0.47 0.31 0.78 0.13 1.48

Board costs 2.04 0.53 0.22 0.75 0.34 0.95

Incentive compensation 6.67 1.76 0.57 2.33 1.00 3.35

Public & government affairs 6.08 1.47 0.58 2.05 1.16 2.88

Legal services 2.88 0.75 0.31 1.01 0.48 1.34

Risk, assurance & advisory serv. 2.34 0.56 0.23 0.79 0.36 1.18

Business transformation 0.75 0.18 0.07 0.25 0.12 0.38

Strategic Planning 1.70 0.41 0.17 0.58 0.27 0.86

Regulatory affairs 2.83 0.68 0.28 0.96 0.22 1.21

Health, safety and environment 1.91 0.55 0.08 0.63 0.23 1.05

Total allocated costs 69.73 18.35 5.91 24.26 10.50 34.98

Asset usage fees

Leasehold assets 2.52 0.50 0.16 0.66 0.79 1.07

HRIS 1.24 0.36 0.06 0.42 0.14 0.68

IS infrastructure 10.62 3.14 0.55 3.69 2.85 4.08

Financial system 2.01 0.49 0.22 0.71 0.16 1.14

Fiber optic assets 0.16 0.06 0.01 0.07 0.00 0.09

Furniture and fixtures 1.38 0.37 0.12 0.49 0.19 0.70

Vehicle 0.04 0.01 0.00 0.01 0.01 0.02

Total asset usage fees 17.97 4.94 1.14 6.08 4.14 7.75

Total corporate services costs 106.63 27.58 7.69 34.45 23.76 47.19

Source: Directly assigned–application Table 10.2-1; Allocated costs-application Table 10.3-2; Asset usage fees application Section 10.5.

386. In evaluating the necessity of each of the services, EDTI‟s evidence relied heavily on the

PA report and the included benchmarking results. The PA report summarizes the assessment of

whether a cost is necessary as follows:

4. In determining whether the cost[s] related to the provision of each service are

necessary, we assessed the need for the service itself, and additionally, the reasonableness

of the costs at the Corporate Service cost pool level.



5. With exceptions noted regarding EEAI in Chapter 2, the 40 Corporate Services

provided by EUI are necessary for EDTI and EEAI to provide utility service. The

exceptions relating to EEAI are Fleet Management (section 2.3) and Inventory

Management & Warehousing (section 2.5). EEAI does not require these two services and

does not receive an allocation of costs for them.

6. EPCOR‟s proposed 2012 Corporate Services spend by service, when normalized by a

combination of revenues, net assets, and headcount is consistent with industry norms and

is reasonable.

7. EPCOR‟s use of At-Risk-Pay for its employees to participate in the cost management

process by rewarding them for achieving lower than budgeted costs is consistent with

good management practice. We conclude that the inclusion of cost management as a

factor in the At-Risk-Pay calculation makes a meaningful contribution to ensuring that

the costs of Corporate Services are reasonable.

387. A benchmarking approach was also used by Dr. Weisman in his evidence sponsored by

EDTI:

The relevant model of competition is one that essentially compares the relative

performance of two or more similarly-situated utilities. In this context, the term

“similarly-situated” refers to utilities that provide service under similar conditions,

including population density, climatic conditions, etc. The basic idea is to create a

“yardstick” by which the regulator can evaluate the relative performance of the utility

even though that utility may not face actual competition.

388. The UCA challenged the validity of the PA report in determining the reasonableness of

the corporate services costs. The UCA submitted that the sample data relied on in the

benchmarking study was not comparable to EUI as it did not contain similar companies and the

data normalization performed by PA Consulting further compromised the value of the resulting

analysis.

389. During the proceeding the Commission requested clarification of the characteristics of

the benchmarking comparator companies and data normalization process in information requests

AUC-EDTI-34, AUC-EDTI-35, AUC-EDTI-36 and AUC-EDTI-37. Further, specific corporate

services cost items were evaluated in detail and are described in the sections that follow. These

corporate services cost items include: short-term incentive payments, mid-term incentive

payments, business development costs, community relations, and the EPCOR community

essentials council. Each of these items is discussed below.

Commission findings

390. The Commission finds the PA Report did not adequately demonstrate that all of the

corporate services provided to EDTI and EEAI are necessary for the provision of utility service

or that the costs of the services charged to EDTI and EEAI are reasonable. The Commission

shares many of the concerns raised by the UCA and the CCA regarding the comparability of the

data and the normalization of this data performed in the PA Report. The Commission finds that

the benchmarking does not demonstrate the need for all of the services. The normalization,

including the implicit assumption that all of the costs are variable,228 does not support the

228




conclusion that the costs are reasonable. The Commission finds that EDTI has not adequately

demonstrated that some of the corporate services costs charged to EDTI and EEAI are necessary

to provide utility service.

391. The appropriate size has been questioned relative to lost economies of scale. In Decision

2010-505, the Commission raised the question as to whether EUI should pay for any or all lost

economies of scale that would remain in 2012 and beyond. The actual corporate services costs

after the CPC transaction indicates that costs were reduced in 2010 and 2011. In AUC-EDTI-64,

in responding to a Commission information request about the relationship between changes to

the business activity in EDTI and the corporate services costs, EDTI stated:229

PA Consulting‟s view is that as part of the CPC divestiture, EUI materially reduced its

corporate costs and redesigned its corporate activities to be reasonably scaled to provide

services to its remaining businesses and provide a platform for growth of those utility

businesses.

392. In prior proceedings, the Commission expressed concern about the lack of comparable

corporate services costs information for EDTI and EEAI after the CPC transaction in 2009.230 In

this proceeding, there are two years of comparable corporate services costs data from which the

Commission can assess the reasonableness of the corporate services costs attributed to EDTI and

EEAI. This actual historical data also provides assistance to the Commission in assessing how

the 2012 forecast reflects EUI‟s actual cost experience. The actual total corporate services costs

for 2010 and 2011 are compared to the 2012 forecast in the table below:

Table 41. 2010-2012 EUI corporate services costs ($ millions)

Category 2010 (D)

2010 (A)

2010 (D)-2010 (A)

2011 (D)

2011 (A)

2011 (D)-2011 (A)

2011 (A)-2010 (A)

2012 (F)

2012 (F)-2011 (A)

Directly assigned 17.35 17.48 0.7% 18.06 17.40 (3.7%) (0.05%) 18.92 8.7%

Allocated 61.66 55.88 (9.4%) 65.64 58.47 (10.9%) 4.6% 69.74 19.3%

Asset usage fees 13.78 13.23 (4.0%) 15.56 17.53 12.7% 32.5% 17.97 2.5%

Total EUI Costs 92.79 86.59 (6.7%) 99.26 93.10 (5.9%) 7.9% 106.63 14.2%

Source: AUC-EDTI-70 Table 10.0-1 Revised Legend: (D) decision, (A) actual, (F) forecast

393. Based on the table above, the total actual corporate services costs increased by

7.9 per cent ($6.82 million) from 2010 to 2011. For 2012, EUI is forecasting an increase of

14.2 per cent ($13.22 million) in total EUI corporate services costs. This incorporates an increase

of 19.3 per cent in the category of allocated costs. Given the general cost escalators231 used in

other parts of the application, the Commission finds the 19.3 per cent forecast increase in the

allocated category of corporate services costs to be excessive. As the corporate services required

by EDTI and EEAI do not appear to have changed significantly,232 the Commission has concerns

with the increasing allocated cost category.

229

Exhibit 186.02, AUC-EDTI-64 230

Decision 2011-399, paragraph 25. 231

Refer to Section 3.4 Cost escalations. 232




394. The corporate services in the directly assigned category appear to be within an acceptable

level of escalation. Also, when considering the impact of the Station Lands facility in 2011,233 the

asset usage category is within an acceptable level of escalation. The allocated category of costs

will be addressed in detail in this decision.

395. The corporate services costs in the allocated cost category for 2010 were 9.4 per cent less

than the approved amount and for 2011 were 10.9 per cent less than the approved amount. This

suggests a significant amount of discretion in the actual expenditures and possible forecasting

errors. Based on a review of the historical actual information, the nature of the costs included in

the allocated cost category and the lack of persuasive support for the increases in allocated

corporate services costs, the Commission considers that this forecast is excessive and would

result in unreasonable costs being allocated to EDTI and EEAI. Therefore, for the purpose of

allocating costs to EDTI and EEAI, the Commission directs EDTI to reduce the 2012 forecast

corporate services costs in the allocated category by nine per cent after any other corporate

services costs reductions identified in the application or directed in this decision are applied. The

Commission finds that a nine per cent reduction is reasonable given the reduction in

discretionary expenditures and any forecast errors reflected in the 9.4 per cent and 10.9 per cent

reductions experienced in 2010 and 2011 respectively.

396. The Commission will now examine individually specific costs included in the allocated

cost category in the following sections.

6.2.1.2 Short-term incentive payments allocated to the utilities by EUI

397. Included in the total corporate services costs allocated to EDTI and EEAI is an amount

related to the short-term incentive compensation paid to EUI corporate employees. This

incentive compensation is based on individual performance ratings as well as EUI‟s overall

annual corporate targets. For 2012, the corporate targets include an EUI earnings amount and

three additional broad categories: health and safety, operational efficiency and customer service.

398. Both the UCA and the CCA recommend that a portion of the STI amounts be excluded

from EDTI‟s revenue requirements. The UCA put forward the position that the EUI earnings

component of the program for corporate employees puts the interests of customers of the utilities

in conflict with the incentive to increase profits. The CCA adopted a similar position and

additionally questioned the resulting earnings impact from PP&E growth. In its argument the

CCA stated:234

The recommended disallowance should be in addition to the disallowance of any earnings

related STI exceeding the 10% weighting referred to in EDTI‟s rebuttal. Since EDTI has

failed to identify the portion of STI that is related to earnings driven by PP&E growth,

CCA recommends that 50% of the STI excluding the 10% already recognized by EDTI as

earnings related, be considered PP&E related and excluded from 2012 STI allocated to

EDTI.

399. EDTI argued that the positions of the UCA and the CCA are flawed in reasoning and

misapply prior Commission directions. The short-term incentive programs are corporate wide

and therefore all employees have similar targets. Customers of EDTI and EEAI will benefit from

233

The Commission approved the move to Station Lands in Decision 2010-505, pages 12-14. 234

Exhibit 207.01, CCA argument, page 35.



efficiencies found in all EPCOR business units and corporate departments and as such the

amounts related to the short term incentive program included in the allocated corporate services

costs are reasonable and should be approved. In addressing the issue of PP&E growth within the

STI program, EDTI stated:235

…EDTI cannot identify the portion of STI that is related to earnings driven by PP&E

growth because there is no direct link and there is unlikely to be any effect at all. If

anything, the portion would be a small fraction of the 10% earnings component. As such,

there is no rational basis for the CCA‟s suggestion that 50% of the STI should be

considered PP&E-related.

Commission findings

400. Consistent with the findings made in Section 3.5, the Commission accepts the forecast

2012 STI amounts included in the total allocated corporate services costs.

6.2.1.3 Mid-term incentive payments allocated to the utilities by EUI

401. In mid-2010, EDTI established a new MTI program. This program is designed to provide

an incentive to EDTI senior management to invest the proceeds from the sale of Capital Power,

and any subsequent sale of EDTI‟s remaining interest, in regulated and contracted utility

investments. Costs related to the MTI are included in the total corporate services costs allocated

to EDTI and EEAI. EDTI submitted that this plan will benefit customers of the utilities by both

regaining the lost economies of scale that resulted from the Capital Power transaction and

increasing EDTI‟s access to capital by shifting EDTI‟s portfolio toward lower risk utility

investments.

402. The UCA and the CCA both recommended that the cost of MTI should not be included in

the revenue requirement of EDTI because it is not required to provide utility service. Further, a

program that creates an incentive to invest without regard for efficient capital spending would

result in any benefit being for the benefit of the EUI shareholders and not in the best interests of

the customers of the utilities.

403. EDTI refuted the assessment of the UCA and the CCA and argued that it has sufficient

controls in place to mitigate any negative effects of the MTI program.

Commission findings

404. In addition to the findings made in Section 3.6, the Commission does not accept that the

forecast 2012 MTI amounts included in the EUI corporate services costs are required to provide

utility service. EDTI identified a net benefit to utility customers from the increased economies of

scale that will be captured through the allocation of costs to new businesses as it seeks out

growth opportunities. While there may be some possible transitory future benefit, EUI could

divest itself of the acquired businesses and leave utility customers in the position of having paid

the costs related to acquisitions and captured little or none of the benefits. The Commission

considers that the MTI program is designed in a way that any resulting benefits will accrue to the

shareholder of EUI. As the Commission is not convinced that MTI provides any benefit to utility

customers, the Commission finds that this cost should not be approved as an element of the costs

235

Exhibit 211.02, EDTI reply argument, page 47.



to be allocated to EDTI and EEAI. The Commission directs EDTI to remove all MTI amounts

from the corporate services costs allocated to EDTI and EEAI.

6.2.1.4 Community relations and EPCOR community essentials council

405. In its submissions during the proceeding, the UCA recommended that the costs allocated

to EDTI related to community relations and the community essentials council should be denied.

The UCA stated that these costs are not required for the provision of utility service. Further, any

requirement for these services would be included directly in the costs of EDTI.

406. EDTI responded to the UCA‟s position, with support from PA consulting, stating the

community relations and EPCOR community essentials council provide services that are

required and are beneficial to EDTI and EEAI customers as the face of the utility and the first

point of contact for citizens and the communities it serves. Removing these costs would have the

effect of harming these communities.

Commission findings

407. In its evidence the UCA made reference to a number of prior Commission decisions

including Decision 2010-483,236 Decision 2009-238237 and Decision 2011-450238 that address the

issue of customer communications and brand development. Each of these decisions denies costs

related to the types of activities identified by EDTI as included in community relations and the

EPCOR community essentials council services. The Commission acknowledges that EDTI has

removed certain costs such as donations from these costs but finds that the remaining costs are

not required for the provision of utility service and directs EDTI to remove these costs from the

2012 forecast corporate services costs allocated to EDTI and EEAI.

6.2.1.5 Other corporate services costs

408. The UCA also questioned the applied-for FTE additions in the corporate services costs as

unnecessary and not justified. The UCA submitted that the regulatory workload for 2012 is

relatively the same as 2010 and there is no demonstrated need for the additional positions. In

making this assertion the UCA stated:

Q27. Are there any corporate costs that are in excess of what is needed for EDTI?

A27. Yes, EDTI has included five FTEs equivalent for additional regulatory work; one

headcount equivalent is included in Legal Services and three headcount equivalent in

Regulatory Affairs and one FTE in EDTI Shared Services.

[…]

A29 I find the requested number of additional FTEs excessive, given that the number of

regulatory applications forecast for 2012 is no different than for 2010 where there was

almost the same amount of workload.

236

Decision 2010-483: ENMAX Energy Corporation, 2009-2011 Regulated Rate Option Non-Energy Tariff

Application, Part 2 – Tariff Application, Application No. 1605947, Proceeding ID. 521, October 7, 2010. 237

Decision 2009-238: Direct Energy Regulated Services, 2009/2010/2011 Default Rate Tariffs and Regulated

Rate Tariffs, Application No. 1600749, Proceeding ID. 149, December 3, 2009. 238

Decision 2011-450: ATCO Gas (a Division of ATCO Gas and Pipelines Ltd.), 2011-2012 General Rate

Application Phase I, Application No. 1606822, Proceeding ID No. 969, December 5, 2011.






409. EDTI responded to the UCA‟s claims by referring to the detailed explanations provided

within its submissions that clearly identify the need for each of the five new positions. Further,

EDTI submitted that there are several lengthy and complex initiatives underway in 2012

demonstrating that additional resources are necessary. This was supported in EDTI‟s argument

when it stated that the UCA evidence:

…ignores the fact that 2012 is panning out to be one of the busiest and most work

intensive years from a regulatory perspective for EDTI, EEAI and other utilities and

interveners in Alberta, with not only numerous tariff and facilities applications but also

novel proceedings…

Commission findings

410. The Commission acknowledges the detailed explanation provided by EDTI that

additional resources are necessary for 2012. Of the five additional positions referred to by

interveners, four positions are part of the total corporate services costs to be allocated. In

response to AUC-EDTI 63,239 EDTI indicated that additional support had been requested by

EDTI and EEAI. Given that EDTI and EEAI expressed a need for additional support the

Commission approves the allocation of the costs of these four positions to EDTI and EEAI

subject to the nine per cent reduction directed above.

6.2.1.6 Business development costs

411. In Decision 2011-399, the Commission identified business development costs as one of

the areas of interest in making an assessment of the level of corporate services costs EUI

proposed to allocate to EDTI. EDTI addressed the business development costs in Section 10.1.9

of the application. It described the types of costs incurred and the activities undertaken in pursuit

of growth within the EPCOR group of companies. EDTI estimated the corporate services costs

related to business development will range between $0.37 and $0.65 million in 2012. EDTI

further submitted that including these costs in the pool of costs allocated to EDTI and EEAI is

reasonable because the utilities will benefit from any future economies of scale that may result

from the business development activities.

412. Both the UCA and the CCA rejected the position put forward by EDTI and recommended

that all costs related to business development be excluded from the revenue requirement of

EDTI. This would include the costs identified by EUI and any additional costs that can be

reasonably estimated or identified as relating to business development activities as the amount

identified by EUI is not inclusive of all the related costs. Both the UCA and the CCA argued that

the business development activities do not relate to the provision of utility service.

Commission findings

413. The Commission agrees with the position put forward by the UCA and the CCA that

business development costs are not related to the provision of utility service. Business

development costs relate to the growth within the EPCOR group of companies not EDTI and

EEAI and therefore should not be included in the corporate services costs allocated to EDTI and

EEAI. The Commission finds that the argument for including the business development costs put

forward by EDTI that there will be potential future benefits from economies of scale

239




acknowledges that there is no current benefit from these services to EDTI and EEAI and,

therefore, the costs are not currently required for the provision of utility service.

414. Additionally, as discussed regarding MTI above, there is no assurance that future benefits

would accrue to the benefit of customers.

415. The Commission further finds that EDTI has not fully identified the costs related to

business development and the range of costs between $0.37 million and $0.65 million does not

capture the total costs forecast for these activities as it only includes the direct costs and makes

no provision for overheads or indirect costs.240

416. The Commission directs EDTI to remove $1.15 million ($0.65 million including a

77 per cent241 overhead charge) from the 2012 forecast EUI corporate services costs and to

remove the proportionate share of these business development costs from the amounts allocated

to EDTI and EEAI.

6.2.2 Are the corporate services costs allocated correctly?

417. EUI charges fees related to assets owned by the service provider that are used in

providing the corporate services. These fees are referred to as assets usage fees. In addition, EUI

assigns corporate services costs to the EPCOR business units using the following six step

process:

(1) categorize the corporate services costs as directly assignable or allocable

(2) assign the directly assignable costs to the appropriate business unit

(3) review/develop/modify/refine the allocation methods for allocable costs

(4) apply the allocation methods to the allocable costs

(5) allocate the corporate services costs to the business unit‟s master overhead pool

(6) conduct a final review for reasonableness

418. EDTI stated in the application that the cost allocation process is designed to ensure that

the allocation of corporate services costs among business units is appropriate, fair and

reasonable, cost-effective, predictable, reflects the benefit received by function, and is consistent

with the transfer pricing principles in EPCOR‟s Inter-Affiliate Code of Conduct.

419. Corporate services costs are allocated on one of two bases:

(1) using a single functional cost causation allocator where the costs can be logically

allocated using an identified cost causation driver; or

(2) using a composite cost causation allocator. The composite cost causation allocator is

used for costs of a governance nature, and it is appropriate that these types of costs be

allocated based on a combination of the business unit‟s share of EPCOR group‟s

revenues, assets, capital expenditures and headcount.

240

Exhibit 148.02, AUC-EDTI-13, page 61. 241




420. The composite cost causation allocator is used to allocate a large number of costs which

are presented in the following table:

Table 42. Costs allocated by the composite cost causation allocator (2012 $ millions)

2012 forecast corporate services costs EUI total

EDTI dist

EDTI trans

EEAI

Composite cost causation allocator – EUI Revenue, Assets, CapEx, Headcount

SCM administration 1.55 0.40 0.17 0.26

Real estate 0.54 0.14 0.06 0.09

SCM corporate services 8.19 1.97 0.82 1.28

Taxation 0.83 0.22 0.09 0.14

Corporate accounting 0.91 0.22 0.09 0.14

Consolidated reporting & analysis 1.37 0.33 0.14 0.21

Financial management training program 0.51 0.13 0.06 0.09

Audit fees 0.96 0.23 0.10 0.15

Executives & executive assistant costs 2.70 0.65 0.27 0.42

Board costs 2.04 0.53 0.22 0.34

Government relations 0.76 0.20 0.08 0.13

Public consultation 0.16 0.04 0.02 0.03

EPCOR community essentials council 0.77 0.18 0.08 0.12

Legal services 2.88 0.75 0.31 0.48

Risk, assurance and advisory services 2.34 0.56 0.23 0.36

Business transformation 0.75 0.18 0.07 0.12

Strategic planning 1.70 0.41 0.17 0.27

Regulatory affairs 2.83 0.68 0.28 0.44

Total composite cost causation allocator 31.79 7.82 3.26 5.07

100% 24.6% 10.25% 16.0%

Source: Application Table 10.1.5-1 and Table 10.3-2

421. In Section 1 of its report, PA Consulting described the use of a composite allocator as

follows:242

The use of a multi-factor formula to allocate costs that cannot be directly charged and for

which a cost causative factor cannot be identified, is a common practice in the utility

industry.

The most common is a three factor formula, with each factor equally weighted, and is

generally referred to as the Massachusetts Formula (MF), where the three components of

the factor are representative of:

- Plant

- Revenues

- Labor

As there are no universal definitions for “Plant”, “Revenues”, and “Labor”, utilities have

implemented the Massachusetts Formula using a variety of different measures

representative of the three components. For example, to represent labor some companies

use payroll expense, while others use employee headcount. Further, variations in the

formula have emerged over time, as utilities and regulators alike have modified the

242

Exhibit 81, Appendix G-5, pages 9-10.



Massachusetts Formula to address situation specific issues, resulting in so-called

Modified Massachusetts Formula (MMF) allocation formulas.

Some of the more common measures used in Massachusetts Formula or Modified

Massachusetts

Formula implementations include:

Assets: Net Plant is a common component of general allocators in the utility industry,

especially when there are no significant non-regulated affiliates; also used are Total

Assets and PP&E.

Revenue: Total Revenue; Margin (Total Operating Revenues less Cost of Fuel/Gas);

Number of Customers.

Labor: Payroll; Headcount; O&M Expenses

422. During the proceeding, the following five issues were identified with respect to the

composite cost causation allocator:

(1) whether fully-loaded payroll is a more accurate representation of labour than

headcount; (labour component)

(2) whether the revenue component of the composite allocator should be total revenue or

margin, i.e. net of commodity revenue (revenue component)

(3) whether the inclusion of capital expenditures in the composite cost causation allocator

improves the quality of the allocation

(4) whether some corporate services costs should be allocated to EUI itself for its

management of its investment in CPC, or for its management of the funds remaining

from its partial sale of CPC

(5) whether EUI has acquired any new businesses to which it should allocate some of its

corporate services costs

423. Each of these issues is addressed in the sections that follow.

6.2.2.1 Labour component of the composite cost causation allocator

424. The question of whether headcount or payroll cost is most suitable for inclusion as the

labour component of the composite cost causation allocator was discussed in responses to

information requests, specifically AUC-EDTI-15 and AUC-EDTI-30. PA Consulting provided

additional analysis that demonstrated using payroll in the place of headcount produced a similar

result but caused a shift slightly away from EEAI and toward EDTI consistent with somewhat

higher average salary levels for the EDTI workforce.

425. In AUC-EDTI-15, PA Consulting discussed the relative merits of payroll or headcount as

an allocator:

Conceptually, headcount is a good allocator for services that vary, or are driven, by the

existence of an employee. For example, payroll costs are driven by the number of

employees and the frequency with which they are paid, while the actual rate of pay for

the employees is not a driver of payroll costs. Costs for office space, desktop computing

and communications costs, and human resources support all are driven by the number of



employees, while the actual compensation or the range of compensation of those

employees is not a material driver of these types of costs.

Fully burdened labour cost, assuming that the burdening is for pension and benefits, is

administratively more complex to administer. Further, the variations that overtime pay,

short term incentive pay, and medium term incentive compensation can make fully

burdened labour a less stable allocation factor.

In selecting an allocation factor for Corporate Services costs the Company should choose

a clear driver of the cost. This approach provides a clearly understood cost driver for each

service or activity and provides transparency to the business units as to the Corporate

Services costs they will incur due to changes in their headcount or vehicle count, for

example.

Commission findings

426. The Commission accepts the position that fully burdened labour cost is administratively

more complex and as such may not be as clear or stable as headcount as an allocator.

Additionally, given the relatively minor variation in the resulting allocation demonstrated in the

analysis of the alternatives, the Commission finds that the use of headcount for the labour

component in the composite cost causation allocator is acceptable as utilized in the applied-for

allocated corporate services costs. However, given the different mix of employees in the

companies, the Commission considers there should be a review of the impact of the use of

payroll or full-time equivalents (FTEs) rather than headcount. The Commission therefore directs

EDTI and EEAI to include in any future applications that incorporate the composite cost

causation allocator, an analysis of the use of payroll and FTEs as the labour component. Should

the profile of the mix of employees in the EPCOR businesses be modified, the Commission may

determine that headcount no longer results in the most fair and reasonable allocation

6.2.2.2 Revenue component of the composite cost causation allocator

427. EDTI submitted that the use of revenue as a component in a composite allocation

indicator is widely accepted as reasonable. The question of what is included in revenue was

discussed in CCA-EDTI-79. In the information requests, the CCA questioned the inclusion of

commodity revenue in the revenue component of EPCOR‟s composite cost causation allocator.

428. In its response to the CCA information request, EDTI provided the following explanation

of why commodity revenue should be included:243

The revenue component of the composite allocator is EUI‟s proxy for cash flows. By not

including commodity revenue in the allocation process, the approximate corporate cost of

managing and governing the cash flows from this form of revenue would not be taken

into account and allocated appropriately, resulting in an allocation of corporate costs

unrepresentative of the level of service provided.

243

Exhibit 168.01, CCA-EDTI-79, page 27.



429. The Commission also expressed an interest in the revenue component in AUC-EDTI-15

when it asked:244

Please indicate whether the revenue component in the calculation includes flow through

charges and if so, comment on this practice.

430. In its response, EPCOR provided additional clarification related to the use of specific

revenue components as follows:

In responding to the Commission‟s question and in reference to the term “flow through

charges”, we assume the Commission means the electricity transmission and distribution

tariffed charges to EEAI by EDTI for the delivery of electricity. The revenue component

used in EUI‟s corporate allocation model does include these flow through charges, as

reported in each EUI subsidiaries‟ stand-alone financial statements. We believe this

approach is reasonable. The corporate allocation model‟s reliance on stand-alone

financial statement data provides for transparency, as revenue, net asset, and capital

expenditure data for each subsidiary are clear and unambiguous. Further, it avoids the

potentially very complicated definitional question of exactly what is or is not a flow

through charge.

Commission findings

431. In examining the financial statements of EPCOR Utilities Inc. for the period ending

December 31, 2011,245 the Commission observed in the Notes to the Consolidated Financial

Statements, note 37, that inter-segment revenue and electricity purchases and system access fees

are identified as amounts reducing total revenue. This information is summarized in the table

below:

Table 43. EPCOR Utilities Inc. – business information ($ millions)

Year ended December 31, 2011

Water services Dist & trans

Energy services Corporate

Intersegment elimination Cons

External revenues and other income

312 330 1,152 39 - 1,833

Inter-segment revenue - 152 11 - (163) -

Total revenue and other income

312 482 1,163 39 (163) 1,833

Portion of total revenue and other income

17% 26% 63% 2% (9%) 100%

Electricity purchases and system access fees

- (143) (1,077) - 144 (1,076)

Net revenue 312 339 86 39 (19) 757

Portion of net revenue 41% 45% 11% 5% (2%) 100%

Net Income 4 38 8 96 - 144

Portion of net income 3% 26% 6% 67% 100%

Source: EUI Financial Statements year ended December 31, 2011, note 37

432. It can be observed from the information summarized in the table above that the inclusion

or exclusion of specific revenue items can significantly alter the resulting revenue component of

244

Exhibit 148.02, AUC-EDTI-15, page 68. 245

Exhibit 167.08, AUC-EDTI-17 Attachment 5, page 55.



the composite cost causation allocator. In the case of the Energy Services segment, the segment

revenue is 63 per cent of consolidated total revenue while only 11 per cent of net revenue after

deducting electricity purchases and system access fees, and six per cent of net income.

Additionally, with the distribution and transmission segment, 32 per cent of the revenue is

related to inter-segment amounts that are eliminated on consolidation. While the Commission

acknowledges this is an approximation of the impact of commodity revenue and flow through

amounts, this analysis is of assistance in making a determination of the relative significance

when choosing to include or exclude items from the revenue component of the composite cost

causation allocator.

433. There is a distortive effect on the revenue component of the composite allocator of

including inter-company transactions and flow through amounts in revenues. As commodity

prices are not stable or predictable, the use of revenues including commodity charges does not

reflect the underlying business activity and the related burden on corporate services. Due to the

volatility of commodity prices the allocator is neither predictable nor stable.

434. The Commission, having factored in both the availability and transparency of the revenue

components, considers the exclusion of commodity and flow through items, a measure of

margin, is a better reflection of the burden each business segment has on the total corporate

services costs allocated using the composite cost causation allocator. To ensure each revenue

item is only included once in the calculation of the revenue component of the composite cost

causation allocator, the Commission directs EDTI and EEAI to include revenue net of

commodity charges, items that flow through to utility customers, and any items eliminated on

consolidation as the revenue component of the composite cost causation allocator.

6.2.2.3 Capital expenditure component of the composite cost causation allocator

435. In the application, EDTI indicated that the composite cost causation allocator is

comprised of four components: (1) total annual revenue, (2) total net assets, (3) headcount, and

(4) total annual capital expenditures.246 Each component is weighted equally.

436. In CCA-EDTI-10, the CCA expressed a concern that the components and weightings

used in the composite cost causation allocator appear to place almost three times the weighting

on the capital costs of EUI subsidiaries. This over-emphasis on capital may not be appropriate

based on the level of capital related services being provided by EUI.

437. In its response to CCA-EDTI-10, EPCOR provided the following clarification:247

When EUI modified its composite cost causation allocator in conjunction with the 2010 -

2011 General Tariff Application, it first considered what aspects of a business are most

important and therefore require a high degree of effort to manage and govern. EUI

concluded that those aspects were its assets, cash flow, investment / capital expenditure

decisions, and employees.

and

Revenue was determined to be a sound and reasonable proxy for cash flow and capital

expenditures for investment decisions.

246

Exhibit 81.0, Appendix G-5, page 10. 247

Exhibit 150.01, CCA-EDTI-10, page 48.



438. In describing the use of the composite cost causation allocator, EDTI stated that the

composite cost causation allocator is used when costs tend to be of a governance nature, and it is

appropriate that these types of costs be allocated based on a combination of the business unit‟s

share of EPCOR group revenues, assets, capital expenditures and headcount.

Commission findings

439. The Commission agrees with the assertion made by the CCA that an allocator with an

equal weighting of capital expenditures, assets, revenue and headcount places greater emphasis

on investments in capital. This puts a disproportionate emphasis in the allocation of governance

costs on those business units that have more capital expenditures. Because capital expenditures

vary from year to year, the inclusion of capital expenditures in the composite cost causation

allocator reduces the predictability and stability of the allocator.

440. For these reasons, the Commission directs EDTI to remove capital expenditures as a

component of the composite cost causation allocator for the purpose of allocating corporate

services costs to EDTI and EEAI.

6.2.2.4 Should some corporate services costs be allocated to EUI itself for its

management of its investment in CPC, or for its management of the funds

remaining from its partial sale of CPC?

441. The question of whether or not the corporate services costs are allocated correctly also

includes the question as to whether a portion of the costs should be allocated to EUI itself. In

addressing this question, the parties discussed several issues including: (i) the costs to manage

the investment in CPC, (ii) the costs to manage the other assets held by EUI including any funds

related to the sell down of its interest in CPC and (iii) the revenues related to these assets.

442. In its submissions, EDTI put forward the position that the costs related to managing the

investment in CPC and other assets outside of EPCOR‟s operating businesses were allocated to

EDTI and EEAI as part of the corporate services costs allocation process. EDTI further indicated

that it is reasonable for customers of EDTI and EEAI to pay a portion of these costs as they are

minimal248 and utility customers will benefit from the economies of scale that are captured once

the assets are converted to investments in active businesses.

443. The Commission explored the benefits to the utilities of non-controlled investments249 in

AUC-EDTI-31:250

Please confirm whether the investment income from CPC and other investments held by

EUI benefits customers of the regulated companies. If there is a benefit to customers,

please fully explain.

In its response EDTI explained:

The investment income from CPC and other investments held by EUI do not directly

benefit customers of the regulated companies in the sense that there is no revenue offset

from that investment income reducing the revenue requirement otherwise recoverable

248

Costs to manage CPC estimated at $.07 million; Exhibit 148.02, AUC-EDTI-13, page 62. 249

Non-controlled investment is an investment where EUI does not have a controlling interest. 250




from regulated customers. The fact that EUI holds investments in EDTI and other utility

businesses, however, provides significant benefits to customers of the regulated

companies in the form of economies of scale. PA Consulting conservatively estimated

that if EDTI were not part of the EUI group of companies, but instead operated on a

standalone basis, costs to be recovered from its regulated customers in 2012 would be

$6.29 million higher (see Exhibit 81, Appendix G-5, section 5).

444. Both the UCA and the CCA recommended that costs related to investment management

be excluded from the revenue requirement of the utilities because the costs are not required for

the provision of utility service. Further, the CCA submitted that no mechanism exists to capture

any future benefit to utility customers.251

Commission findings

445. The Commission finds that it is unreasonable for EDTI and EEAI to bear a portion of the

costs of managing the investments of EUI because they are not costs for the provision of utility

service. Further, the Commission does not consider that EDTI and EEAI should bear a portion of

the cost of activities related to possible future investments on the basis of a possible future

benefit from increased economies of scale. For these reasons, in addition to the directions above

that identify the removal of specific costs, the Commission finds that a portion of the EUI

corporate services costs that, in the Commission‟s view, are not required for the provision of

utility service should be removed from the costs allocated to EDTI and EEAI.

446. Accordingly, the Commission finds that, for the purposes of allocating costs to EDTI and

EEAI, the composite cost causation allocator should be calculated recognizing EUI‟s investment

in CPC or any other investments held by EUI. The Commission directs EDTI to include the

revenues (including equity income), assets and headcount associated with EUI‟s investment in

CPC and any other assets held by EUI, in the calculation of the composite cost causation

allocator.

6.2.2.5 Has EUI acquired any new businesses to which it should allocate some of its

corporate services costs?

447. EDTI identified two transactions in which EUI acquired new businesses to which it is

allocating a portion of the corporate services costs in 2012. EDTI describes the transaction as

follows:252

On May 31, 2011, EPCOR acquired 100% of the common shares of Chaparral City

Water Company (“Chaparral”) from American States Water Company with control of the

operations commencing June 1, 2011. Chaparral is a public utility company, regulated by

the Arizona Corporation Commission, engaged principally in the purchase, production,

distribution and sale of water to approximately 13,000 customers in the Town of Fountain

Hills, Arizona and a small area within Scottsdale, Arizona.

and

In January 2011, EPCOR entered into an agreement to acquire 100% of the stock of

Arizona Water and New Mexico Water, both wholly-owned subsidiaries of American

251

Exhibit 207.01, CCA argument, paragraph 150. 252

Exhibit 3, application, paragraphs 2076 and 2077.



Water Works Company, Inc. The transaction is subject to regulatory approval in both

states. Arizona Water is a utility regulated by the Arizona Corporation Commission that

provides water service to approximately 106,000 customers and wastewater services to

approximately 51,000 customers primarily located in the Phoenix area. New Mexico

Water is a utility regulated by the New Mexico Public Regulation Commission that

provides water and wastewater services to the city of Clovis in eastern New Mexico, and

in the greater Edgewood area near Albuquerque, New Mexico, serving more than 17,000

customers. The transaction is expected to be completed near the end of the first quarter of

2012.

448. EDTI submitted that the U.S. Water implementation team made an assessment of whether

or not the US water operations would be provided services by the EUI corporate services

departments.253 This determination resulted in the introduction of changes to the composite cost

causation allocator by incorporating the concept of a Canadian only calculation. Those corporate

services that will not be required by or provided to the U.S. Water Utilities will continue to be

allocated to the Canadian members of the EPCOR group using allocation methods that reflect

Canadian operations only. This is accomplished by the use of a Canadian composite cost

causation allocator as calculated in Table 10.1.5-3.

449. Of the EUI corporate services that were allocated using the composite cost causation

allocator, eight of the 18 services representing 28.5 per cent of the total costs were not allocated

to the U.S. Water operation. The table below indicates the services for which costs were

determined to be required by the U.S. Water operations and the amounts allocated:

253

Exhibit 3, application, paragraph 2080.



Table 44. 2012 U.S. water corporate services costs allocated by the composite cost causation allocator ($ millions)

2012 forecast corporate services costs Allocation EUI total

U.S. Water

SCM administration Self-provided locally in the U.S. 1.55 0.00

Real estate Self-provided locally in the U.S. 0.54 0.00

SCM corporate services Yes 8.19 0.62

Taxation Self-provided locally in the U.S. 0.83 0.00

Corporate accounting Yes 0.91 0.07

Consolidated reporting & analysis Yes 1.37 0.10

Financial management training program Applies only in Canada 0.51 0.00

Audit fees Yes 0.96 0.07

Executives & executive assistant costs Yes 2.70 0.21

Board costs Self-provided locally in the U.S. 2.04 0.00

Government relations Self-provided locally in the U.S. 0.76 0.00

Public consultation Self-provided locally in the U.S. 0.16 0.00

EPCOR community essentials council Yes 0.77 0.06

Legal services Self-provided locally in the U.S. 2.88 0.00

Risk, assurance and advisory services Yes 2.34 0.18

Business transformation Yes 0.75 0.06

Strategic planning Yes 1.70 0.13

Regulatory affairs Yes 2.83 0.22

Total composite cost causation allocator 31.79 1.5

100% 4.7%

Source: Application Table 10.1.10-1 and Table 10.3-2

Commission findings

450. The Commission has considered the submissions related to the incorporation of the

U.S. Water operation and finds EDTI has not adequately demonstrated that the governance

related costs allocated by the composite cost causation allocator should not be allocated to the

U.S. Water operation. The assertion that the governance related services will not be used is

unsupported. The three components of the corporate costs assignment include direct assignment,

fees for asset usage and cost allocation. Within cost allocation, there are functional allocations

and allocations for which a causative factor could not be identified that are allocated using a

composite allocator. Specifically, the costs allocated using the composite cost causation allocator

can not be directly assigned or allocated using a functional allocator and, as such, are remote

from the business. It is likely that any one of the group of companies could make an argument

that it did not benefit directly from certain of the governance cost groups. For the purpose of

allocating costs to EDTI and EEAI, the Commission directs EDTI to abandon the Canadian

composite cost causation allocator.

6.2.3 Would it be less expensive for EDTI and EEAI to provide the corporate services

or seek a different third-party provider on a stand-alone basis?

451. In addressing the third question of whether it would be less expensive for EDTI and

EEAI to seek an alternate provider or provide the services themselves, EPCOR relies heavily on

the PA Report. The PA Report provided a service-by-service analysis of the potential cost to



each of the utilities if it were to establish the capability to provide the necessary services

internally, or where possible, find a third party provider.

452. With respect to the utilities establishing the capacity to provide the necessary services

internally, PA made a number of assumptions including:254

…we assumed that for the self-provision alternatives, the facility costs would be the same

as would be allocated to EDTI by EUI.

…labour rates, non-labour cost, and IT support costs will be the same, as both business

units will hire from the same labour markets for the same skills and use labour volumes

that are equal to or higher than those represented by the allocations from EUI.

..we assumed that for the self-provision alternatives, information services and contractor

costs will be the same as the status quo cost.

453. With respect to the utilities establishing an alternate third party to provide the necessary

services, PA made a number of limiting assumptions or statements including:255

…there was a significant relationship aspect to the service which could not be

realistically accommodated through a third party provider.

…economic and practical realities of outsourcing a small volume of services and the

costs to manage a small contract.

…we have identified certain EUI provided services that would not be prudent to source

from third parties.

…we have considered the range of likely commercial arrangements for each service,

based on our experience and EPCOR‟s experience.

Commission findings

454. The Commission finds the PA Report addresses the question of self provisioning and

outsourcing to a third party in a very limited and restrictive way. Each service is evaluated in the

context of each of the utilities providing the services in the same manner as EUI and generally

requiring the same resources. Additionally, the PA Report does not address the possibility that

the utilities could themselves achieve economies of scale by sharing resources focused only on

the utility businesses.

455. The assumptions made by PA quoted above make it highly unlikely that the self-

provisioning option would be found to be less costly. Similarly, the limiting assumptions with

respect to the third party provisioning resulted in PA not exploring in any detail the costs

associated with third party outsourcing, either at the EUI cost pool level or at the individual

utility level for services that it considered not prudent to source from third parties.

456. For the remaining services that PA considered could potentially be sourced from third

parties, the analysis was not transparent and market price cost estimates were based on

254


Exhibit 81.0, Appendix G-5, pages 22-23.



commercial information gathered from a variety of sources, including recent EPCOR

commercial sourcing activities, existing contract pricing data, and PA market intelligence.256

457. The Commission finds that the submissions made during the proceeding provide

insufficient information to assess whether it would be less expensive for EDTI and EEAI to

provide the same corporate services or seek a different third-party provider on a stand-alone

basis and therefore makes no finding in addressing this question.

7 Other issues

7.1 Phase II cost of service study

7.1.1 Distribution access service cost of service study and rates

458. In its application, EDTI stated that it was requesting approval of its rates for both

distribution access service (DAS) and system access service (SAS). EDTI provided its applied-

for DAS and SAS rates in Schedule DT-A-1257 and Schedule DT-A-2,258 respectively.

459. EDTI also stated that it had not completed a new DAS cost of service study and proposed

to rely on its 2010-2011 DAS cost of service study for the purposes of determining its 2012 DAS

rates. EDTI proposed to calculate its 2012 DAS rates by escalating each rate component of its

2011 DAS rates by a common percentage that, using the 2012 forecast billing determinants,

would recover EDTI‟s 2012 DAS revenue requirement. This approach would result in each

component of each of EDTI‟s 2011 DAS rates being escalated by a factor of 8.6 per cent. In the

application, EDTI noted that its 2011 DAS rates were part of a refiling application currently

before the Commission and thus, at the time the application was submitted, the final 2011 DAS

rates had not yet been approved by the Commission.

460. In its argument, the University expressed concern that EDTI did not provide a full cost

allocation study to support its 2012 distribution rates or a firm commitment on the timing of the

next study. The University stated that, based on EDTI‟s response to UofA-EDTI-01, it appeared

that at least one-third of the requested increase had nothing to do with customers on a customer

specific (CS) rate schedule and that the University considered it unfair to apply the same

percentage increase to all rate classes when some rate classes contribute more than others to the

causes of the increase. The University also stated that EDTI‟s 2012 DAS rates become the

starting point for performance based regulation rates and that the inequity within the 2012 rates

will only compound throughout the five-year PBR period. The University submitted that EDTI

should complete a full cost allocation study either before PBR rates are implemented or very

early in the PBR term.

461. In response to the University‟s submissions, EDTI stated that a cost allocation study

requires considerable time, effort and cost to complete and that, other than the forecast billing

determinants, EDTI considered it highly unlikely that there would be any material changes to the

DAS cost of service study reflected in its 2010-2011 Phase II application. In regards to the

University‟s position that EDTI complete a cost of service study either before PBR rates are

implemented or very early in the PBR term, EDTI stated that the issue of if and when it should

256

Exhibit 81.0, Appendix G-5, page 23. 257

Exhibit 11. 258

Exhibit 12.



file a Phase II application during the PBR period is irrelevant to this application and should have

been raised by the University in the PBR proceeding.

462. EDTI also noted that the results of its planned geographic information system (GIS)

based rate review should be available in the second quarter of 2014.

Commission findings

463. EDTI stated that, at the time of the filing of the application, its 2011 DAS rates were part

of a refiling application that was before the Commission and had yet to be approved. EDTI‟s

2011 DAS rates were approved in Decision 2011-490.259

464. In EDTI‟s 2010-2011 Phase II distribution tariff application (Application No. 1606833,

Proceeding ID No. 980), EDTI stated that it was working towards completing its Geographical

Information System (GIS) Lifecycle Replacement Project that would allow EDTI to model the

physical flow of electricity between electrical elements (e.g. switches, transformers and meters).

EDTI stated that its next cost of service study would be based on the new GIS and EDTI

considered it likely that rate class allocations resulting from the GIS based cost of service would

be different than the current rate class cost allocations from the 2010-2011 cost of service

study.260

465. The Commission notes EDTI‟s submission that a full Phase II cost of service study takes

considerable time and cost to complete. The Commission also notes EDTI‟s submission that it

considered it highly unlikely that a new cost of service study, prior to the ability to use the data

from the GIS study, would result in any material changes to rate class cost allocations than were

already reflected in the cost of service study filed as part of EDTI‟s its 2010-2011 Phase II

application.

466. The Commission has considered the arguments put forward and does not consider it to be

prudent for EDTI to complete a cost of service study at this time given:

the time and expense required for EDTI to complete a new cost of service study

EDTI did not expect material changes in cost allocations from a new cost of service study

EDTI expected that the results of its planned GIS-based rate review should be available

in the second quarter of 2014

EDTI expected the rate class cost allocations resulting from the GIS-based cost of service

study to be different than the cost allocations based on its 2010-2011 study

467. Accordingly, the Commission will not require EDTI to complete a cost of service study

prior to the results of the GIS-based review being available and accepts EDTI‟s method of

escalating each component of its 2011 DAS rates by a common percentage for the purpose of the

compliance filing.

468. However, with respect to the issue of the completion of a cost of service study during

EDTI‟s PBR term, the Commission stated the following in Decision 2012-237 in respect of the

Rate Regulation Initiative:

259

Decision 2011-490: EPCOR Distribution & Transmission Inc. 2010-2011 Phase II Distribution Tariff Refiling,

Application No. 1607746, Proceeding ID No. 1484, December 14, 2011, paragraph 42. 260

Exhibit 3, Proceeding ID No. 980, paragraphs 12 and 13.




The Commission considers that PBR is unrelated to the requirement to periodically

update rates through a Phase II process. However, during the PBR term the companies

may file applications for Phase II adjustment to their rate design and cost allocation

methodologies and the Commission will make a determination at the time as to whether

the adjustments are warranted. For purposes of a cost of service study, the companies

shall use the revenue requirement resulting from going-in rates adjusted by the PBR

formula (including the I-X mechanism, K factors, Y factors and Z factors) and the latest

updated billing determinants.

469. The Commission notes that EDTI stated that the results of its planned GIS-based rate

review should be available in the second quarter of 2014. If EDTI determines that the changes in

cost allocation as a result of the implementation of the GIS-based rate review are significant and

files a Phase II application, the Commission will assess the merits of such an application at the

time EDTI files such an application.

7.2 Billing determinants forecast – transmission and distribution

470. EDTI retained Mr. Dana Oikawa to prepare the billing determinants forecast in the

application. In previous applications, EDTI retained Dr. Ernie Stokes, of Stokes Economic

Consulting, to prepare the billing determinants forecast. EDTI stated that Mr. Oikawa has

worked with Dr. Stokes for eight years and used the same methodology to forecast the billing

determinants in this application as Dr. Stokes has used in the past.

471. Mr. Oikawa focused on four areas: energy consumption, number of customers, on-peak

energy and billing demand. Mr. Oikawa provided details of the methodology that he utilized to

develop the billing determinants forecast in Appendix G-6 of the application, including tables

summarizing the billing determinants by rate class. From the data provided by Mr. Oikawa in

Appendix G-6, the Commission has summarized the total number of customers and energy

consumption for 2010 and 2011 in the following table. The comparison of actual to decision

amounts allows for an assessment of the historical reliability of the methodology.

Table 45. Number of customers and energy forecast – forecast accuracy table

2010

actual 2010

decision

Variance (# of

cust. or GWh)

Variance (%)

2011 actual

2011 decision

Variance (# of

cust. or GWh)

Variance (%)

Customers - average 337,885 336,487 (1,398) -0.4% 343,395 341,021 (2,374) -0.7%

Energy sales (GWh) 7,308.8 7,215.0 (93.8) -1.3% 7,393.8 7,304.5 (89.3) -1.2%

472. The following table examines the growth trend in customers and energy sales from 2009

to 2010 and from 2010 to 2011. The forecast growth rate for customers from 2011 to 2012 is

consistent with the actual growth rate from 2009 to 2011. The forecast growth rate for energy

sales for 2011 to 2012 is slightly higher than that experienced from 2009 to 2011. The increase

reflects in part a change in customer mix as shown in Table 47 and Table 48, below.



Table 46. Number of customers and energy – trend table

2009

actual 2010

actual Growth

(%) 2010

actual 2011

actual Growth

(%) 2011

actual 2012

forecast Growth

(%)

Customers - Average 332,584 337,885 1.6% 337,885 343,395 1.6% 343,395 349,290 1.7%

Energy Sales (GWh) 7,131.6 7,308.8 2.5% 7,308.8 7,393.8 1.2% 7,393.8 7,696.2 4.1%

Table 47. Number of customers – trend table

2009

actual 2010

actual

Growth (# of cust.

or GWh) Growth

(%) 2010

actual 2011

actual

Growth (# of cust.

or GWh) Growth

(%) 2011

actual 2012

forecast

Growth (# of cust.

or GWh) Growth

(%)

Residential, small/medium commercial 328,905 334,213 5,308 1.6% 334,213 339,751 5,538 1.7% 339,751 345,617 5,866 1.7%

Large commercial & industrial (Note 1) 1,813 1,847 34 1.9% 1,847 1,856 8 0.5% 1,856 1,907 51 2.8%

Lighting (Note 2) 1,866 1,825 (41) -2.2% 1,825 1,789 (36) -2.0% 1,789 1,766 (23) -1.3%

Total # of customers 332,584 337,885 5,301 1.6% 337,885 343,395 5,510 1.6% 343,395 349,290 5,895 1.7%

Note 1 – The following rate classes have been included in this grouping: Customer Specific, Customer Specific – totalized, Time of Use, Time of use Primary and Direct Connect. Note 2 – The following rate classes have been included in this grouping: Street Lighting, Lane Lighting, Traffic Lighting and Security Lighting.

Table 48. Energy sales – trend table

2009

actual 2010

actual

Growth (# of cust.

or GWh) Growth

(%) 2010

actual 2011

actual

Growth (# of cust.

or GWh) Growth

(%) 2011

actual 2012

forecast

Growth (# of cust.

or GWh) Growth

(%)

Residential, small/medium commercial 3,275 3,361 86 2.6% 3,361 3,408 47 1.4% 3,408 3,501 92 2.7%

Large commercial & industrial (Note 1) 3,774 3,864 91 2.4% 3.864 3,901 37 0.9% 3,901 4,111 210 5.4%

Lighting (Note 2) 83 83 0 0.5% 83 84 1 1.4% 84 84 0 0.2%

Total # of customers 7,132 7,309 177 2.5% 7,309 7,394 85 1.2% 7,394 7,696 302 4.1%

Note 1 – The following rate classes have been included in this grouping: Customer Specific, CustomerSspecific – totalized, Time of Use, Time of use Primary and Direct Connect. Note 2 – The following rate classes have been included in this grouping: Street Lighting, Lane Lighting, Traffic Lighting and Security Lighting.

473. Tables 47 and 48 above show that the large commercial and industrial rate classes have

only contributed to 0.9 per cent (51 / 5,895) of the total increase in the number of customers from

2011 to 2012 but have contributed to 69 per cent (210 GWh / 302 GWh) of the total increase in

energy sales.

474. Interveners did not directly address EDTI‟s billing determinant forecast methodology in

either argument or reply argument. However, in its argument, the CCA stated that EDTI should

be directed to update its 2012 forecast customer numbers based on 2011 actual customer counts.



475. While EDTI did not directly address the CCA‟s recommendation respecting use of the

2011 actual customer counts in its reply argument, EDTI did generally address the CCA‟s

recommendations respecting updating the 2012 revenue requirement to reflect 2011 actuals.

EDTI stated that updating its 2012 forecast with 2011 actual information as requested by the

CCA would be inappropriate and would be inconsistent with the Commission‟s previous

determinations respecting similar requests by the CCA in the past.

Commission findings

476. The Commission has reviewed the report developed by Mr. Oikawa and considers the

methodology utilized by Mr. Oikawa and the forecast billing determinants by rate class for 2012

to be reasonable. The Commission has noted in the tables above that the growth in 2012 forecast

energy sales is higher than the growth in the 2012 forecast number of customers, as compared to

2011 actuals. However, the Commission is satisfied that this higher growth in energy sales is due

to an increase in the number of customers in the large commercial and industrial rate classes

relative to previous years.

477. The Commission approves the forecast billing determinants by rate class as filed by

EDTI.

7.3 Inclusion of volume variances in the TCDA

478. EDTI‟s transmission charge deferral account (TCDA) tracks variances in forecast to

actual transmission charges from the AESO and Fortis to EDTI that are caused by variances in

forecast to actual transmission access rates. Balances in this account are periodically trued-up

through the use of TCDA rate riders approved by the Commission.

479. In its 2010-2011 Phase II distribution tariff application, EDTI requested that its TCDA

include forecast-to-actual variances related to both price and volume. In Decision 2011-375,261

the Commission denied EDTI‟s request, as further discussed in this section. In the current

application, EDTI proposed again that the TCDA include forecast to actual variances related to

volume as well as price commencing in the 2012 test period.

480. In support of its request, EDTI restated the reasons provided in the 2010-2011 Phase II

distribution tariff application. Specifically, EDTI pointed to the fact that in Decision 2010-309,262

the Commission approved Fortis‟s request to include variances related to both price and volume

in Fortis‟s AESO charges deferral account (ACDA).263 EDTI restated that because its

circumstances are similar to those of Fortis, and given the approval of the change in Fortis‟s

ACDA, the Commission should extend a similar treatment to EDTI‟s TCDA.264

481. As well, EDTI indicated that in its PBR application, ATCO Electric proposed to include

volume variances in its SAS deferral account (the equivalent of EDTI‟s TCDA). Accordingly,

EDTI observed that all three companies (Fortis, ATCO Electric and EDTI) have a consistent

261

Decision 2011-375: EPCOR Distribution & Transmission Inc. 2010-2011 Phase II Distribution Tariff

Application, Application No. 1606833, Proceeding ID No. 980, September 15, 2011. 262

Decision 2010-309: FortisAlberta Inc. 2010-2011 Distribution Tariff – Phase I, Application No. 1605170,

Proceeding ID. 212, July 6, 2010. 263

Decision 2010-309, paragraphs 340-344. 264

Exhibit 3, application, paragraphs 3065-3066.





view that their transmission charge deferral accounts must include variances due to volume as

well as price.265

482. In the 2010-2011 Phase II application, EDTI noted that it has seen large dollar variances

over the years related to volume variances. In this application, EDTI updated this information

with 2010 actual amounts and the 2011 year-to-date (YTD) updated forecast.

Table 49. Volume-related variances 2007-2011 ($ millions)266

2007 2008 2009 2010 2011 YTD August

SAS revenue collected 71.39 68.78 32.1 71.64 89.96

SAS expenses incurred 71.91 68.52 31.74 72.59 91.34

Net SAS revenue (expense) (0.52) 0.26 0.36 (0.95) (1.38)

483. In response to the Commission‟s information requests, EDTI provided a breakdown of

the 2010 and 2011 volume-related deficit amounts of ($0.95) million and ($1.38) million,

respectively, by AESO tariff component. EDTI indicated that the largest contributors to the

volume variances were the AESO demand charges (Bulk System-Coincident Peak and Local

System-Billing Demand) and operating reserve charges.267

484. Furthermore, EDTI explained that these deficit amounts cannot be broken down by

customer class, since the AESO and Fortis invoices are broken down by point of delivery (POD)

rather than customer class. Accordingly, EDTI indicated that because rate class volume variances

may be random rather than systematic, the company could not provide any information as to

which customer classes contribute to volume-related variances and if some customer classes

contribute to these variances more than others.268

485. In addition, EDTI noted that it cannot design its system access service rates to more

closely match the AESO‟s rates and charges:

EDTI uses its best efforts to design its SAS rates, having regard to the types of meters

and billing determinants of its customers. The types of meters used by the vast majority

of EDTI‟s customers preclude it from designing its system access service rates to more

closely match those employed by the AESO. While the AESO can base its rate design on

a complete set of 15-minute demand readings for each of its load centers, this is not the

case for EDTI. Indeed, customers representing 36 percent of EDTI‟s 2011 energy volume

were on cumulative meters which provide no demand data at all. Customers representing

an additional 10 percent of EDTI‟s energy volume were on demand meters that record

their highest demand over a given period but say nothing about when that peak was

recorded. Lastly, one percent of EDTI‟s energy volume was completely unmetered and

was billed based on estimated volumes.269

265

Exhibit 3, application, paragraphs 3073-3074. 266

Exhibit 3, application, Table 11.2.6.2.2-1, page 986. 267

Exhibit 167.02, AUC-EDTI-50(a), Table AUC-EDTI-50-2 and Exhibit 186.02, AUC-EDTI-65(a). 268

Exhibit 167.02, AUC-EDTI-50(c). 269

Exhibit 167.02, AUC-EDTI-51(a).



486. With the absence of detailed demand data for customers representing almost half of the

total 2011 energy volume, EDTI indicated that it bases its rate design on those measures of

customer volumes that are available. Moreover, EDTI stated that the absence of time-of-use data

for such a large block of customers represents a substantial gap in its understanding of the

contribution of each class of customers to the historical demands recorded at each point of

distribution (POD). This represents a substantial impediment to any effort to produce an

accurate, bottom-up forecast for each POD.270

487. EDTI explained that the company allocates the AESO‟s demand-related charges to

customers with limited or no detailed demand data (i.e. residential, small commercial, medium

commercial and the four lighting rate classes) based on the load settlement data or deemed load

shapes. In these circumstances, EDTI submitted that, while it would be possible to develop a

bottom-up forecast for each POD using load shapes for each of the rate classes without demand

data, such an approach would greatly expand the effort required to produce the POD forecast.271

488. In contrast, because actual metered and billing demand data is available on which to base

the demand forecasts for each POD, EDTI‟s preference was to continue using the current

approach to forecasting the AESO demand-related charges on a POD level, not customer level.

EDTI explained that it forecasts the monthly peak demands and the Alberta Interconnected

Electric System (AIES) coincident peaks for each individual POD based on its historical load

factors. The required load factor projections are constructed by using the corresponding load

factor from the same month in the previous year.272

489. Based on the above, EDTI submitted that the historical variances to date demonstrate the

fact that the company cannot reasonably forecast transmission volumes. As such, EDTI argued

that no reasonable efficiencies can be gained by forcing the company to accept the risk on

volume variances. In EDTI‟s view, the imposition of such risk “may simply lead to cost and

efforts at refining forecasting methods with no appreciable results.”273

490. The CCA noted that EDTI‟s request to revisit this matter appeared to have been based on

Decision 2010-309 that allowed Fortis to include volume variance in its ACDA. The CCA also

expressed its view that many of the issues related to volume variance raised by EDTI in the

current proceeding relied on the similar positions advanced by Fortis to warrant approval of

inclusion of volume variances. In that regard, the CCA pointed out that in a more recent

Decision 2012-108,274 dealing with Fortis‟s negotiated settlement agreement in respect of its

2012 Phase I application, the Commission discontinued the volume variance reconciliation in

Fortis‟s ACDA. Accordingly, based on the earlier rejection of EDTI‟s proposed inclusion of

volume variances in Decision 2011-375 and the rejection of volume variance treatment for Fortis

in Decision 2012-108, the CCA submitted that EDTI‟s proposal to revisit this matter in the

context of the current proceeding should be denied.275

270

Exhibit 167.02, AUC-EDTI-51(a). 271


Exhibit 186.02, AUC-EDTI-66(a)-(c). 273


Decision 2012-108: FortisAlberta Inc. Application for Approval of a Negotiated Settlement Agreement in

respect of 2012 Phase I Distribution Tariff Application, Application No. 1607159, Proceeding ID No. 1147,

April 18, 2012. 275

Exhibit 191, CCA evidence, pages 27-28 and Exhibit 210, CCA reply argument, paragraphs 16-17.




Commission findings

491. As observed by the CCA, EDTI‟s original reason for requesting that its TCDA include

variances related to both price and volume was based on the fact that Decision 2010-309 allowed

Fortis to reconcile forecast to actual variances related to volume as well as price in its ACDA.276

However, more recently in Decision 2012-108, the Commission directed Fortis to exclude

variances related to volume from its ACDA.277 As such, the Commission observes that, currently,

true-up differences in the transmission access charge deferral accounts of all electric distribution

companies relate to price only.

492. In support of its proposal, EDTI also relied on ATCO Electric‟s proposal to include

volume variances in its SAS deferral account as part of its PBR application. However, as the

Commission explained in Decision 2012-237,278 the considerations regarding the inclusion of

volume variances under PBR are not the same as under cost of service regulation, because of the

differences in incentives and overall regulatory framework between the two regulatory

regimes.279 In these circumstances, the Commission approved the inclusion of volume variance in

the transmission flow-through accounts of the electric distribution companies (including EDTI)

for the purposes of their PBR plans. The Commission also restated its commitment to regulating

the utilities on a consistent basis with regards to this issue.280

493. EDTI‟s current application is a cost of service application. As such, the Commission

considers that the same reasoning for denying EDTI‟s earlier request to include volume

variances in its TCDA in the 2010-2011 Phase II application, as well as discontinuing volume

variances in Fortis‟s ACDA, applies in this circumstance as well.

494. In Decision 2011-375, the Commission noted EDTI‟s submission that the company‟s

limited ability to undertake seasonal switching of loads and the specifics of the current structure

of the AESO system access rates affected its control over transmission volumes.281 However, in

Decision 2011-375, EDTI‟s request to include volume variance in its transmission charge

deferral account was rejected for two reasons: (i) EDTI has been able to reasonably forecast

transmission volumes, as evidenced by the relatively small volume-related variances in recent

years and (ii) continuation of the price-only deferral account can result in regulatory efficiencies

arising from the more rigorous forecasting of billing determinants.

495. In this proceeding, EDTI indicated that the variances related to volume have been

growing in recent years, as shown in Table 49 above, and are no longer insignificant.

Accordingly, much of the discussion in this proceeding centered on EDTI‟s ability to accurately

forecast its transmission volumes.

496. EDTI indicated that the largest contributors to the volume variances were the AESO

demand charges and operating reserve charges.282 With respect to the latter, EDTI noted that, in

its new tariff effective July 1, 2011, the AESO implemented a new method for recovering the

276

Exhibit 3, application, paragraphs 3063-3066. 277


Decision 2012-237: Rate Regulation Initiative Distribution Performance-Based Regulation, Application No.

1606029, Proceeding ID No. 566, September 12, 2012. 279




Exhibit 167.02, AUC-EDTI-50(a), Table AUC-EDTI-50-2 and Exhibit 186.02, AUC-EDTI-65(a).



operating reserve charges from market participants.283 Given this change, EDTI advised that it

did not expect that operating reserve charges will continue to contribute to its volume variance.284

497. With respect to the volume variance arising from the AESO demand charges, the

Commission accepts EDTI‟s evidence that, since 2004, there have been changes to the AESO

rate structure, with the AESO tariff becoming more heavily oriented towards demand-related

charges than energy-related charges.285 This change necessitates that more effort be put in the

forecasting of transmission billing determinants related to demand (i.e. Bulk System-Coincident

Peak and Local System-Billing Demand), as demonstrated by the fact that these types of AESO

charges contribute significantly to EDTI‟s volume variances.

498. The Commission observes that EDTI currently employs a detailed, bottom-up approach

to forecast its transmission energy volumes. For example, EDTI explained that the “POD energy

forecast is developed so that the sum of the projected energy consumption for the substations,

Direct Connect customers, and Annex tie-points for each month is constrained to equal the

monthly forecast of total rate-class energy plus distribution line losses.”286 However, with respect

to forecasting transmission volumes related to demand, EDTI currently employs a “far simpler

approach,” under which the monthly peak demands and the AIES coincident peaks for each

individual POD are forecast based on their historical load factors.287 When asked by the

Commission whether a more detailed bottom-up forecasting method can be applied to project

demand volumes, EDTI explained that due to a number of factors (the main ones being the

absence of detailed demand data for customers representing almost half of EDTI‟s total energy

volume and the absence of a readily available source for a set of economic/demographic drivers

in the PODs service areas within EDTI‟s system),288 such a method would “greatly expand the

effort required to produce the POD forecast.”289

499. In the absence of a cost-benefit analysis on the merits and disadvantages of a more

detailed approach to forecasting EDTI‟s transmission volumes related to demand, the

Commission considers that the question of whether EDTI is able to come up with a more

accurate forecast of its transmission volumes remains open.

500. In this regard, the Commission does not share EDTI‟s view that refining transmission

volume forecasts simply leads to cost and efforts “with no appreciable results.”290 As the

Commission explained in Decision 2012-108, under a cost of service regime, the distribution

revenue requirement established in Phase I applications is divided by the forecast billing

determinants for the test period to design customer rates.291 In addition, EDTI agreed that forecast

billing determinants and distribution revenue requirement may both be partially driven by the

same underlying drivers (such as customer growth, load forecast, etc.), although there is no

strong correlation between the two. Furthermore, under the current regulatory framework,

electric distribution utilities accept the risk related to the difference between the forecast and

283

The AESO‟s operating reserve charges are further discussed in Section 7.4.2 below. 284

Exhibit 186.02, AUC-EDTI-65(b). 285


Exhibit 186.02, AUC-EDTI-66(a). 287

Exhibit 186.02, AUC-EDTI-66(a) and (c). 288

Exhibit 167.02, AUC-EDTI-51(a) and AUC-EDTI-52(b). 289



Decision 2012-108, paragraphs 118-119.



actual billing determinants when recovering their approved distribution revenue requirement.292

As such, the accuracy of customer rates and the companies‟ ability to recover their approved

revenue requirement is highly dependent on the accuracy of the companies‟ billing determinants

forecast.

501. In these circumstances, the Commission determined in Decisions 2011-375 and

Decision 2012-108, that under a cost of service rate making regime, the absence of volume true-

up on transmission charges will provide a stronger financial incentive to the companies to

accurately forecast their billing determinants to ensure reasonable recovery of both the

distribution tariff revenue and transmission access charges.293 As such, the Commission reiterates

its findings that under cost of service rate making, regulatory efficiencies stemming from a more

rigorous billing determinants forecast outweigh the potential disadvantages of EDTI bearing risk

on transmission volumes.

502. In light of the above considerations, EDTI‟s request that its TCDA include forecast to

actual variances related to volume in the 2012 test year is denied.

7.4 2012 system access service (SAS) rates

7.4.1 EDTI’s proposed 2012 SAS rates

503. EDTI‟s SAS revenue requirement is based on charges paid by the company to the AESO

and Fortis for transmission services provided in relation to customers in EDTI‟s service area.

EDTI designs both its SAS revenue requirement calculations and the SAS rates based on a SAS

cost of service study to flow through to its customers the cost of transmission services.

504. EDTI proposed that its 2012 interim SAS rates, approved in Decision 2011-495,294 be

approved as the final SAS rates for 2012. EDTI proposed the following change to the 2012 SAS

rate schedule:

The term “the Transmission Contract Demand (TCD);” has been deleted and replaced

with the term “the Contracted Minimum Demand;” for all rate classes that are charged a

billing demand as to align with the term used in EDTI‟s DCS Terms and Conditions.295

505. EDTI noted that any differences between the revenue collected in 2012 through the SAS

rates and costs paid to the AESO will be trued up through EDTI‟s transmission charge deferral

account (TCDA).

Commission findings

506. With the exception of the University‟s concern with EDTI‟s method of forecasting and

recovering the AESO SAS operating reserve charge from customers, no party objected to EDTI‟s

proposal to approve its 2012 interim SAS rates as final SAS rates for 2012. As set out in the

following section of this decision, the Commission does not share the University‟s concerns with

EDTI‟s approach to dealing with operating reserve charges. The Commission has reviewed the

SAS rate schedules and approves EDTI‟s proposed 2012 final SAS rates as filed.

292

Exhibit 167.02, AUC-EDTI-53(a) and (b). 293

Decision 2011-375, paragraph 191 and Decision 2012-108, paragraphs 120-121. 294

Decision 2011-495 (Errata): EPCOR Distribution & Transmission Inc. Errata to Decision 2011-495, 2012

Interim System Access Service Tariff, Application No. 1607773, Proceeding ID No. 1497, December 21, 2011. 295

Exhibit 113, Appendix J-7, page 5 of 24.

http://www.auc.ab.ca/applications/decisions/Decisions/2011/2011-495%20Errata.pdf



507. The Commission accepts EDTI‟s change from the term “the Transmission Contract

Demand (TCD)” to the term “the Contracted Minimum Demand” in the 2012 SAS rate schedule

in Appendix J-7.

7.4.2 SAS operating reserve charge

508. The operating reserve charge is a component of the AESO tariff designed to recover costs

associated with procuring reserve generating capacity (i.e. operating reserve) to ensure that

power remains available when required to match supply and demand on the electricity

transmission system.296 In accordance with Section 47 of the Transmission Regulation,

AR 86/2007, the AESO flows through the cost of operating reserves to load market participants,

including EDTI.

509. As outlined in Decision 2011-495, in its 2012 interim SAS tariff application, EDTI

explained in detail that under the AESO‟s new tariff, which took effect on July 1, 2011, the

AESO does not forecast operating reserve costs, but simply flows through these costs to market

participants. Based on an analysis of actual operating reserve charges from the AESO as a

percentage of the actual pool price for the period from July to October 2011, EDTI proposed to

use the 7.25 operating reserve percentage in its interim SAS rates to recover these costs from

customers.297 In this proceeding, EDTI expanded this analysis to include the months of

November and December, 2011. With the inclusion of these months, the average actual operating

reserve rate for EDTI was 7.53 per cent over the period from July to December, 2011.298

EDTI proposed continuing to use the 7.25 operating reserve percentage.

510. The University expressed its concerns that EDTI did not “provide any meaningful

analysis” to support the operating reserve charge component of its final 2012 SAS rates.299 In

particular, the University was concerned that EDTI‟s reply to its information request emphasized

the efficient reconciliation of deferral account balances, while there was “little time spent

understanding how and why operating reserve costs change and how to bill distribution

customers in such a way so as to mitigate large deferral account balances from the outset.”300

511. The University recommended that EDTI be directed to investigate a more efficient way

to recover operating reserve costs that allows minimizing the use of its transmission deferral

account by finding a way to better match current rates to current costs. The University submitted

that its proposed method could be one of the possible solutions.

512. The University proposed recovering operating reserve costs through a charge to

distribution customers based on a charge per megawatt hour ($/MWh) equal to the most recent

three-month rolling average of the actual total operating reserve cost ($/MWh). For example, the

average charge from January to March in any given year would become the starting point for

calculating the operating reserve charge for April. The University submitted that EDTI could

296

In its “Ancillary Services Participant Manual”, the AESO provides the following definition (page 7). Operating

reserve – is available output from a generator that can be dispatched, or load that can be reduced, to maintain

system reliability in the event of an imbalance between supply and demand on the electricity system.

http://www.aeso.ca/downloads/Ancillary_Services_Manual_Edition_2_FINAL.pdf 297

Decision 2011-495 (Errata), paragraphs 12-14. 298

The Commission staff calculations based on data in Exhibit 149.01, Table UofA-EDTI-05-1. 299

Exhibit 205, University argument, PDF page 2. 300

Exhibit 170, UofA-EDTI-6, preamble.

http://www.aeso.ca/downloads/Ancillary_Services_Manual_Edition_2_FINAL.pdf



seek the Commission‟s approval for this calculation and submit monthly filings for information

only, similar to a monthly regulated rate option gas cost recovery rate.301

513. In the University‟s view, the proposed method is preferable to EDTI‟s current approach

of setting a base operating reserve charge rate with subsequent quarterly updates in the TCDA

true-up process. Specifically, the University argued that its proposed method has the following

benefits:302

The distribution charge focuses on actual cost and disregards the pool price that does not

necessarily correlate with operating reserve cost.

The rolling average charge is refreshed frequently to reflect current costs, but is still

developed and disclosed to distribution customers on a prospective basis.

Because the average charge reflects current costs, the monthly surplus/(deficit) tends to

self correct and balance to zero over time, without the need to reconcile deferral accounts.

Even though EDTI‟s costs remain volatile, the rolling average charge is less volatile for

customers, making it easier to forecast for periods of at least one year.

Monthly filings for information are likely to result in lower regulatory cost compared to

quarterly deferral account rider applications.

The deferral account threshold as to when to reconcile deferral account balances may be

able to be increased and perhaps even eliminated.

514. EDTI did not agree that the University‟s proposed approach of recovering operating

reserve charges from the AESO was preferable to the company‟s currently used method. EDTI

explained that because operating reserve is not the sole contributor to TCDA balance

accumulation, there would continue to be a need to reconcile deferral accounts and retain the

established deferral account threshold, as other AESO rate changes impact the TCDA account.

515. With respect to volatility, EDTI submitted that its proposed rate remains constant with

quarterly updates to the TCDA true-up rate rider. In contrast, the University‟s proposal would

change on a monthly basis and still require quarterly updates to the TCDA true-up rate rider.

516. Furthermore, EDTI pointed to costs and practical difficulties associated with the

University‟s proposed approach. EDTI noted that monthly tariff changes from the use of rolling

averages would require substantive systems recoding and testing. Additionally, the fluctuating

monthly rate changes would likely cause confusion to customers other than the University,

potentially resulting in higher call volumes to customer call centres. Finally, EDTI indicated that

monthly rate changes would also add administrative burden for the company in addition to and

not in lieu of the current quarterly TCDA true-up process already designed to true-up operating

reserve charges and other AESO price related variances.303

Commission findings

517. In Decision 2011-495 dealing with EDTI‟s 2012 interim SAS tariff, the Commission

observed that EDTI‟s proposed operating reserve rate of 7.25 per cent closely tracked the

301

Exhibit 170, UofA-EDTI-6, preamble. 302

Exhibit 170, UofA-EDTI-6, preamble. 303

Exhibit 208.02, EDTI argument, paragraphs 436-437.



operating reserve charges that the company had received from the AESO for the months from

July to October, 2011 and found this operating reserve percentage to be reasonable.304

518. The Commission agrees in principle with the University‟s view that, whenever possible,

it is preferable to design customer rates in such a way as to minimize the use of any deferral

account, or preferably, to dispense with a deferral account. However, as explained in the AESO‟s

information document quoted by EDTI, “the cost of operating reserves varies from hour to hour

based on the availability of reserves, the actual volumes included in dispatches, the volumes each

provider supplies to the system, the pool price, and the competitive offers for each type of

operating reserves procured from providers.”305 Therefore, the Commission agrees with EDTI

that the company cannot predict how the above factors interact and contribute to the trends in the

AESO‟s operating reserve costs for the purposes of an in-depth analysis. EDTI observed that the

AESO itself “is no longer attempting to forecast its operating reserve costs, but is simply passing

actual costs on to EDTI.”306

519. With respect to the alternative method of recovering operating reserve costs proposed by

the University, the Commission agrees with EDTI‟s view that this approach would result in an

unnecessary volatility and complexity of customer bills. Currently, EDTI‟s base SAS operating

reserve rate (e.g., the 7.25 per cent proposed in the application) remains constant with quarterly

updates to this estimate included as part of TCDA true-up rate rider.307 Under the approach

proposed by the University, both EDTI‟s base SAS rate and TCDA rider items on customer bills

would fluctuate. As EDTI explained, even if the operating reserve charges were to flow through

to customers on a monthly basis, there would still be a need for a quarterly TCDA to true-up

other AESO costs. Additionally, the Commission accepts EDTI‟s submission that the

University‟s proposal would require substantive changes to the billing system and additional

costs to the company.308

520. In light of the above, the Commission is not persuaded that the approach to recovering

operating reserve charges put forward by the University represents a better alternative to EDTI‟s

current method of setting a base operating reserve charge rate with subsequent quarterly updates.

521. In the Commission‟s view, the method of recovering operating reserve costs that EDTI

currently uses achieves the same results as the University‟s alternative approach without the

additional costs and practical difficulties associated with the University‟s proposal. As EDTI

explained, the proposed 7.25 base operating reserve percentage tracks closely to the AESO‟s

actual charges and thus captures the bulk of the operating reserve costs over the test period,

minimizing the use of TCDA. Furthermore, this operating reserve percentage forecast is further

refined on a quarterly basis through EDTI‟s quarterly TCDA rider process.

304

Decision 2011-495 (Errata), paragraph 31. 305

Exhibit 149.01, UofA-EDTI-6(a) quoted AESO Information Document No. 2011-004T.

http://www.aeso.ca/downloads/Operating_Reserve_Charge_Information_Document_2011-004T_(2011-10-

07).pdf 306

Exhibit 211.02, EDTI reply argument, paragraph 223. 307


Exhibit 208.02, EDTI argument, paragraph 436.

http://www.aeso.ca/downloads/Operating_Reserve_Charge_Information_Document_2011-004T_(2011-10-07).pdf

http://www.aeso.ca/downloads/Operating_Reserve_Charge_Information_Document_2011-004T_(2011-10-07).pdf



522. As outlined in Bulletin 2012-04,309 the Commission initiated a review of the electric

distribution companies‟ transmission quarterly rider mechanisms (Proceeding ID No. 1678). As

part of that review, EDTI and other distribution facility owners proposed to standardize their

respective transmission access charge rider mechanisms. The Commission considers that

Proceeding ID No. 1678 will address the types of issues identified by the University in this

proceeding.

523. In light of the above, the Commission considers that EDTI‟s methodology currently in

use to calculate the AESO operating reserve charges is reasonable. Having reviewed the updated

analysis of the average actual operating reserve rate for EDTI for the period July to December,

2011, the Commission considers that the 7.25 operating reserve percentage remains a reasonable

estimate for the purposes of EDTI‟s final 2012 SAS rates.

7.5 Maximum investment level

524. In its application, EDTI proposed to increase its maximum investment level (MIL) for

underground residential development (URD) from $1,155 to $2,487 per lot.310 EDTI submitted

that its proposed MIL increase is in conformity with the recommended methodology and

principles resulting from the working group led by Fortis to develop a common approach to

MILs, in which other utilities such as ATCO Electric and ENMAX Power Corporation

(ENMAX) participated.311

525. EDTI‟s 2012 URD MIL represents the average cost per lot (or service) for URD in its

distribution area in 2012 dollars and is based upon the average costs for the five years from 2006

to 2010. Details of the calculations used to produce the average costs per URD lot in 2012 were

provided in Appendix K-6 and Appendix K-7 of the application.

526. EDTI submitted that all of EDTI‟s rate classes will be impacted by the proposed increase

in MILs, with the percentage rate impact being 0.28 per cent, which is below the threshold of

0.5 per cent set by the working group led by Fortis.312

527. The UCA expressed concern with EDTI‟s proposal to allocate the increase in revenue

requirement across all rate classes and not just to residential customers. The revenue requirement

was not allocated to different rate classes based on cost causation principles. The UCA

considered this unfair for other rate classes, including small commercial users.313

528. In support of its position, the UCA drew upon two of the guiding principles used in

setting MILs: the consideration of the MILs of surrounding utilities and the principle of gradual

adjustment to the investment level. It stressed that Fortis, a neighbouring utility, has MILs which

are set on the basis of inflation plus 10 per cent in order to reach a target MIL. It also mentioned

ATCO Electric, for which a significant jump in MILs was approved, but noted that the increase

309

Bulletin 2012-04, Commission-initiated electric transmission quarterly rider process review, Proceeding ID

No. 1678, March 29, 2012. 310


Exhibit 119, Appendix K-6, page 2, paragraph 5. 312

Exhibit 151.01, EDTI rebuttal evidence, page 20. 313

Exhibit 189.02, evidence of Shelley Radway, page 35.

http://www.auc.ab.ca/news-room/bulletins/Bulletins/2012/Bulletin%202012-04.pdf



was limited to just residential customers, unlike EDTI‟s proposal of applying it to all rate

classes.314

529. The UCA argued that a full-year impact, if allocated to residential customers only, would

be 0.64 per cent and will exceed the 0.5 per cent threshold for each rate class.315 Since the

increase is a significant amount, the UCA recommended that the increase in MILs be limited to

inflation plus 10 per cent to transition to target MILs. The UCA submitted that the full impact of

the increase in MILs should be deferred until EDTI is able to provide an updated cost of service

study (COSS), which will not be available until 2014.316

530. EDTI refuted the UCA‟s position arguing that the UCA‟s analysis was based on an

incomplete and selective review of past decisions. It concurred with the principle of taking into

account the MILs of neighbouring utilities such as Fortis. However, it also called upon the need

to balance it with other principles of setting a MIL rate, including, for example, the principle of

starting with the current cost to connect new customers and minimizing intergenerational

inequity. It discussed Decision 2011-134, where a jump from $1,320 per site to $2,590 per site

was approved for 2011 for ATCO Electric. This increase was approved by the Commission

because it was concerned that greater inequities would arise for newer customers if rates were

not better aligned with costs. Similarly, for EDTI without the proposed increase, the MIL would

be disconnected from the current cost to connect new customers and result in significant

intergenerational inequities.317

531. In its rebuttal evidence, EDTI also argued that it would be inappropriate to allocate costs

associated with the MIL increase to only residential customers, because the underground

infrastructure will be used not only by residential customers but EDTI‟s other rate classes as

well, including small commercial, medium commercial, time of use, street light, traffic light and

security light rate class customers. EDTI also stressed that given its current CAR-DCM

approach, all rate classes will be impacted by the proposed MIL increase until 2014, when the

data from the new Geographic Information System (GIS) will be available. The new data will

allow them to identify URD assets specifically and EDTI will then be able to isolate the impact

on residential customers.318

532. Given this situation, the UCA reiterated its position in its final argument that the increase

in MILs be limited to inflation plus 10 per cent for 2012, with the final increment being deferred

until 2014.

533. The CCA submitted that EDTI‟s calculation of URD MIL provides a reasonable

representation of the average cost of investment in URD facilities, however, it was concerned

that the sudden jump in a single year could result in intergenerational inequities between prior-

year customers and 2012 customers. Accordingly, it put forth the recommendation that the

increase in URD MILs should be phased in over a period of three years in equal percentage

increases, commencing in 2012.319

314

Exhibit 189.02. evidence of Shelley Radway, page 34. 315

Exhibit 189.02, evidence of Shelley Radway, page 36. 316

Exhibit 189.02, UCA-EDTI-108. 317

Exhibit 208, EDTI argument, page 152. 318


Exhibit 207, CCA argument, page 20, paragraph 20.



534. In its reply argument, EDTI countered the CCA‟s argument by pointing out that EDTI‟s

proposed MIL would result in less intergenerational inequity compared with phasing in the

increase, as it would ensure that customers bear the costs associated with their connections when

the costs are incurred.320

Commission findings

535. The Commission has reached its determination keeping in mind the guiding principles

and methodology for setting MILs filed as Appendix O in Fortis‟s 2010 and 2011 DTA and

agreed upon in their entirety by the participating utilities, including EDTI. The Commission

recognizes the need to balance the various principles in setting MILs and observes that there is a

large disparity between the current cost of URD and the rates charged to new customers. A

similar increase in URD MILs was approved in Decision 2011-134 for ATCO Electric, where

MILs were increased from $1,320 per site in 2010 to $2,688 per site for 2012, as the

Commission was concerned that the existing MILs were unduly onerous for new customers. The

Commission also agrees with EDTI that, by ensuring that customers bear the cost associated with

their connections when the costs are incurred, EDTI is minimizing intergenerational inequity.

536. The Commission considers that Fortis‟s MIL increase of inflation plus 10 per cent

approved in Decision 2012-108 is not a reasonable comparison because this was approved in the

context of a negotiated settlement. The Commission notes that the CCA found the proposed

MILs to be a reasonable representation of the average costs of investment in URD facilities and

the UCA raised no objection to the calculation of average costs. The Commission has reviewed

and is satisfied with the calculations and therefore finds that the proposed MILs are a reasonable

representation of the current cost of connecting new customers.

537. The Commission accepts EDTI‟s position that the increase in MILs for URD facilities

should not be allocated only to residential customers because all customers use the underground

infrastructure. Further, under EDTI‟s current Capital Asset Review – Direct Cost Method (CAR-

DCM) approach for a COSS, the impact of the URD increase would have been allocated to all

rate classes as explained in UCA-EDTI-108.

538. Moreover, the Commission notes that the application proposed that all rate classes be

impacted by the increase in URD MILs and that the impact is within the threshold of 0.5 per cent

in a single year.321 The Commission considers that this is consistent with the common approach

to managing changes to MILs that was developed for the electric distribution companies, with

the participation of stakeholder groups. This common approach was approved for Fortis, ATCO

Electric and EDTI.322

539. For all of these reasons, the Commission approves the MILs proposed by EDTI.

320

Exhibit 211, EDTI reply argument, page 80, paragraph 227. 321

Exhibit 119, Appendix K-6, page 3, paragraph 6. 322

Decision 2010-309: FortisAlberta Inc., 2010-2011 Distribution Tariff – Phase I, Application No. 1605170,

Proceeding ID No. 212, July 6, 2010.

Decision 2011-134: ATCO Electric Ltd., 2011-2012 Phase I Distribution Tariff, Application No. 1606228,

Proceeding ID No. 650, April 13, 2011.

Decision 2010-505: EPCOR Distribution & Transmission Inc., 2010-2011 Phase I Distribution Tariff,

Application No. 1605759; Proceeding ID No. 437, October 28, 2010.






7.6 Deferral accounts

540. EDTI requested approval for the continued use of a number of reserve and deferral

accounts for its transmission and distribution business units, including the following:

Distribution reserve or deferral accounts:

hearing cost reserve

self-insurance reserve

AESO load settlement charge deferral account

AUC tariff billing and load settlement initiatives deferral account

transmission charge deferral account

property, business and linear tax deferral account

short-term incentive deferral account

transition to IFRS deferral account

Transmission reserve or deferral accounts:

hearing cost reserve

self-insurance reserve

AESO-directed projects deferral account

property, business and linear tax deferral account

short-term incentive deferral account

transition to IFRS deferral account

Commission findings

541. In Section 3.8 of this decision, the Commission found that the property, business and

linear tax deferral accounts for distribution and transmission were no longer required. In

Section 3.11, the Commission dispensed with the transition to IFRS deferral accounts for

distribution and transmission.

542. With respect to the remaining deferral and reserve accounts, the Commission finds that

EDTI‟s proposal for their continued use in the 2012 test year to be reasonable. The Commission

notes that no objections were raised by interested parties on the continued use of these accounts.



7.7 Areas not individually addressed

543. The following tables summarize the major components of EDTI‟s proposed 2012

distribution and transmission function revenue requirements as filed in its application:

Table 50. Major components of the 2012 distribution revenue requirement

2012 ($ millions)


Return on Debt and Equity 43.79 29

Operating Expenses 33.11 22


Corporate 23.24 16

Customer Accounts 7.17 5

Property Taxes 6.70 4


Deferred and Reserve 3.76 3

Total 149.40 100

Table 51. Major components of the 2012 transmission revenue requirement

2012 ($ millions)


Return on Debt and Equity 24.55 36


Operating Expenses 13.54 20

Property Taxes 6.89 10

Corporate 6.26 9

Deferred and Reserve 2.04 3


Total 68.63 100

544. In this decision, the Commission has separately identified and provided comments and

determinations regarding areas in the application where either the Commission or interested

parties raised issues or concerns. The Commission has reviewed information provided by EDTI

in the application and during the proceeding relating to items which were not specifically

addressed by parties, and considers that the information appears reasonable, and accordingly the

Commission approves the revenue requirement subject to the determinations and order set out in

this decision.

545. The Commission notes that areas of concern which were raised by the Commission or

interested parties in this decision may impact other larger category areas such as rate base,

depreciation, and cost of capital, for example. For this reason, EDTI, in its compliance filing, is

directed to update all impacted areas of its revenue requirement for the 2012 test year for all

findings and determinations made within this decision.

7.8 PBR and going-in rates

546. EDTI requested that the 2012 distribution tariff and 2012 TFO tariff when approved on a

final basis related to this application be continued into 2013 as interim rates pending

Commission approval of EDTI‟s first annual rate adjustment filing under its PBR Plan, or any



further orders with respect to 2013 tariffs. EDTI‟s proposed PBR Plan did not include SAS rates

as it intended to apply for approval of 2013 SAS rates during 2012.323

547. Decision 2012-237 addressed distribution PBR going-in rates as follows:

88. The Commission considers the second alternative is in keeping with the decision

to use 2012 approved rates rather than 2012 actual costs as the basis for going-in rates.

The 2012 rates have been tested and approved by the Commission as just and reasonable

for 2012. Accordingly, the 2012 approved rates are the correct starting point on which to

base going-in rates. The Commission confirms the findings in Decision 2009-035 that

adjustments to going-in rates should not be made to reflect actual results. Further,

adjustments should not be made selectively but, rather, should only be made in the

context of a full rate case. Adjustments may be made in exceptional situations, however,

like the case of the short term incentive plan adjustment approved in the ENMAX

decision.

89. Accordingly, the Commission will consider adjustments that are in the nature of

a correction to the going-in rates, and which are not rate adjustments made after-the-fact

to reflect actual results. This approach is consistent with the Commission‟s finding in

Section 7.4.4 that differences between placeholder amounts and final approved amounts

will be treated as Y factor adjustments or adjustments to rates that will be subject to the I-

X mechanism, depending on the circumstances of the adjustment.

90. The Commission will consider each of the proposals of the companies and

interveners to include adjustments to going-in rates.

91. Given the above findings, the Commission directs the companies to use their

respective approved 2012 distribution rates as the going-in rates for the PBR term,

subject to the specific adjustments allowed below.324

548. Current 2012 interim DAS rates for EDTI were approved initially in Decision

2011-426,325 expiring on March 31, 2012, and then continued until further ordered by Decision

2012-086.326 Current interim SAS rates and TFO tariffs were approved in Decision 2011-495 and

Decision 2011-491327 respectively.

549. EDTI requested revised 2012 interim DAS rates under Proceeding ID No. 1679 which is

currently before the Commission. On March 13, 2012, the Commission issued

Bulletin 2012-03,328 in response to a letter from the Minister of Energy dated March 8, 2012

regarding current electricity rates and charges, including rate riders to collect deferred balances,

requesting “that the AUC ensure these rates or charges do not exceed their current levels.” The

bulletin described the Commission‟s proposed approach to the Minister‟s letter.

323


Decision 2012-237: Rate Regulation Initiative – Distribution Performance-Based Regulation, Application

1606029, Proceeding ID No. 566, September 12, 2012, page 20, paragraphs 88-91. 325

Decision 2011-426: EPCOR Distribution & Transmission Inc., Revised 2011 Interim Rates for Distribution

Access Service, Application No. 1607541, Proceeding ID No. 1372, October 28, 2011. 326

Decision 2012-086: EPCOR Distribution & Transmission Inc., Revised 2012 Interim Distribution Access

Service Rates, Application No. 1608078, Proceeding ID No. 1679, March 26, 2012. 327

Decision 2011-491: EPCOR Distribution & Transmission Inc., 2012 Interim Transmission Facility Owner

Tariff Application No. 1607796, Proceeding ID No. 1516, December 16, 2011. 328

Bulletin 2012-03, Government of Alberta request regarding electricity rates, March 13, 2012.




http://www.auc.ab.ca/news-room/bulletins/Bulletins/2012/Bulletin%202012-03.pdf



550. To minimize unanticipated consequences on EDTI and potential rate shock to customers

the Commission in Decision 2012-086 directed EDTI to continue, on an interim refundable

basis, with its 2012 interim DAS rates, which would otherwise expire on March 31, 2012, until

further ordered.

Commission findings

551. The above quote from Decision 2012-237 indicates that 2012 approved rates shall be

used as the basis for going-in rates for PBR to be effective January 1, 2013. The Commission

finds that going-in rates for PBR as of January 1, 2013 shall be based on the 2012 final DAS

rates if they are available. If 2012 final DAS rates are not available for use as of December 31,

2012, then the proposed rates from the compliance filing application, required in response to this

decision, shall be used as the basis for interim going-in DAS rates as of January 1, 2013. An

adjustment to the PBR going-in rates to reflect final DAS rates, with a subsequent true-up if

necessary, will be made once the final 2012 DAS rates are approved.

8 Order

552. It is hereby ordered that:

(1) EDTI is directed to submit a compliance filing by November 2, 2012, addressing

all of the determinations and directions in this decision, correcting any errors

which it has discovered, and including a summary of all changes made as a result

of this decision.

Dated on October 5, 2012.


(original signed by)

Mark Kolesar

Vice-Chair


Kay Holgate

Commission Member



9 Dissenting reasons of Commission Member Bill Lyttle regarding EDTI’s cost of

debt

553. While I agree with the findings of my colleagues with respect to all other aspects of this

decision, I do not agree with the findings reached with respect to EDTI‟s cost of debt.

554. With respect to approval of the cost of new long-term debt I would direct EDTI in its

compliance filing to determine interest rates for EDTI‟s transmission and distribution function

based upon securing financing from the Alberta Capital Financing Authority (ACFA) for the

current year‟s debt issuance and deem that as the cost of newly issued long-term debt. I would

not apply this rate or any rate reduction to previous years‟ debt issues already approved by the

Commission on a go forward basis contrary to the UCA‟s submission.

Background

555. EUI as the direct parent of EDTI issues debt in the market on its own behalf and provides

debt financing to EDTI, as EDTI does not issue debt directly to investors. In Decision 2010-505

the Commission made the following finding:

EUI has significant investments in the unregulated power generation business through

Capital Power Corporation. EDTI acknowledged that this investment affects EUI‟s credit

rating. EDTI indicated that EUI‟s credit rating may improve if and when EUI‟s

investment in Capital Power Corporation is replaced with investments in utility

businesses. It follows then that an improved credit rating would lower EUI‟s cost of debt,

and that EUI‟s current debt costs may be higher than would be the case if EUI were a

pure play regulated utility.329

556. The Commission must find a way to determine what reasonable rate loans from EUI to

EDTI should occur for assigning a value for revenue requirements, since the debt for EDTI is not

directly observable in the market and is a non-arms length transaction.

557. In Decision 2010-505 the Commission considered both the methodology used and the

costs associated with EDTI‟s debt issuances for 2007, 2008 and 2009 during the period of the

negotiated settlement agreement and for the proposed debt issuances for 2010 and 2011. The

Commission found that “EDTI‟s approach in issuing its long-term debt at year end is not

optimal, because it does not attempt to minimize the cost of borrowing. Indeed, such a strategy

could be imprudent if EDTI consistently overprices its cost of debt relative to EUI.”330 The

Commission‟s concern was further elevated since EDTI also paid an allocated portion of EUI‟s

treasury costs.331 The Commission was also concerned with the bond spread that was applied to

the debt issued in 2007-2009 and directed EDTI to apply the actual indicative corporate bond

spread for Fortis.332 The Commission also used the Fortis bond spread when setting the 2010 and

2011 forecast debt interest rate.333 These directions reduced not only the 2007, 2008 and 2009

debt interest rates but also the 2010 and 2011 forecast debt interest rates.

329

Decision 2010-505 at paragraph 175 (original footnotes omitted). 330


Decision 2010-505 at paragraphs 166 and 167. 332





558. In the present proceeding, EDTI proposed to increase that funding spread further to the

detriment of ratepayers by introducing a letter from DBRS that indicated EDTI transmission

would be “downgraded” from A (low) to BBB (high).334 As a result, in AUC-EDTI-54-

Attachment 1, EDTI submitted that EDTI transmission‟s credit risk premium should be 80 basis

points higher than EDTI distribution‟s credit risk premium.335

559. Whether it is the timing issues as noted above, increased applied for spread rates, or

implied credit downgrading, the Commission is thrust into the position of determining the rate

for revenue requirement purposes that EUI can charge EDTI for debt financing.

ACFA funding

560. One method of determining the rate for debt financing that the Commission directed

EDI/ETI (now EDTI) to pursue in the 2006-054 decision was for EDI/ETI to provide a letter to

the City of Edmonton (Edmonton) as detailed in the quote below indicating that EDI/ETI would

appreciate it if Edmonton could provide similar financing through ACFA that The City of

Calgary provided to ENMAX Power Corporation (ENMAX). EDTI is a municipal subsidiary.

By accessing ACFA funding the debt could be flowed from Edmonton to EDTI. The problem of

assigning a just and reasonable rate for EUI to lend EDTI funds could be avoided and the

requirement for EUI to raise debt on behalf of EDTI could be reduced.

561. In Decision 2006-054 the board discussed the issue of ACFA financing; however, no

witness from Edmonton was available to discuss this issue:

The Board notes that not only are the electricity users in Calgary benefiting from this

arrangement, but further, the City of Calgary appears to consider itself to be fully

compensated by the 0.25% loan guarantee and administration charge.

The Board is somewhat surprised, that the City of Edmonton would not provide the same

service to electricity consumers within Edmonton that the City of Calgary provides in

Calgary. However, the Board recognizes that the information above was not available to

the public until the issuance of Decision 2006-002, which was after the close of the

evidentiary record of this proceeding. The Board also notes that it had no witness from

the City of Edmonton to question as to the reason why the City would not provide this

service to its citizens or to question as to whether the City of Edmonton was aware that

the City of Calgary is providing this service to electricity users in the City of Calgary.

The Board has relied solely on the views of EDI/ETI as to why this approach was taken

by the City of Edmonton.

Accordingly, the Board directs EDI/ETI, prior to the next GTA, to provide a letter to the

City of Edmonton indicating that the City of Calgary is providing ACFA based financing

to its electric utility, and that EDI/ETI would appreciate it if the City of Edmonton would

provide similar financing to EDI/ETI in the future. The letter should include reference to

this section of this Decision.

If the City declines to provide such financing, the City should provide its written reasons

for declining to provide the financing and should be prepared to provide a witness to

testify on the policy reasons for declining to provide its citizens with the low cost ACFA

334

Exhibit 150.10, CCA-EDTI-10, Attachment 5. 335




financing available for financing such infrastructure projects as electric distribution lines

at the time of EDI/ETI‟s next GRA filing.336

562. In Decision 2010-505 the Commission again directed EDTI “to advise the Commission

on whether Edmonton would make available ACFA financing.”337

563. EDTI filed two letters from Edmonton on the record of this proceeding, one from March

22, 2007 filed as Appendix G-13 of the application and the other dated October 31, 2011 filed as

Appendix G-14 of the application.

564. In the 2007 letter, Edmonton stated that EPCOR (at that time, EDI (EPCOR Distribution

Inc.) and ETI (EPCOR Transmission Inc.)) was established as a corporate entity separate from

Edmonton to allow it to independently manage its own affairs and was to follow the stand-alone

principle, and further that the generation side of EPCOR was to be on a level playing field with

other industry participants. In the 2011 letter, Edmonton submitted that many of the concerns in

2007 remain today and detailed that Edmonton continues to place a strong emphasis on the

governance relationship between Edmonton and EPCOR which is different from the relationship

The City of Calgary has with ENMAX. ACFA funding would require Edmonton to become

more involved in the management activities of EDTI related to capital expenditures.

565. I note that in Decision 2006-054 the board also stated:

The Board does not accept EDI/ETI‟s view that failure to add the fully compensatory

stand-alone premium to the ACFA rate would necessarily result in a misallocation of

civic resources. The Board considers that the ACFA financing exists to provide Albertans

with a lower rate for infrastructure financing thereby benefiting the Albertans and Alberta

businesses that use the infrastructure.338

566. I concur with the views of the board above and elaborate further below as Edmonton‟s

letters are now part of this proceeding, and the policy reasons for declining funding can be

assessed. I find that Edmonton‟s policy reasons are insufficient to justify denying infrastructure

financing advantages to EDTI ratepayers.

567. Edmonton has a 100 per cent direct ownership of EUI and subsequently EDTI. Edmonton

has the ultimate responsibility for EDTI through its ownership structure. To assume that debt

management would create some increasing responsibility other than administrative compliance

would presume that shareholders investments require less stewardship than management of an

entity‟s debt or capital expenditures. Edmonton as the ultimate shareholder has the responsibility

and risk of its equity investment and can direct its administration to facilitate the management of

its investment. Control of EDTI is not a passive investment that Edmonton has an insignificant

stake in; it has a 100 per cent ownership stake in an essential service provider. As the 100 per

cent owner of EUI, I consider that Edmonton should be willing to take on this administrative

burden so as to lower EDTI‟s cost of debt. Coincidentally, The City of Calgary appears to

336

Decision 2006-054 at page 108. 337


Decision 2006-054 at page 107.



consider itself fully compensated by the 0.25 per cent loan guarantee and administration

charge.339

568. Since the board‟s 2006 decision and 2007 letter from Edmonton, EUI has significantly

decreased its ownership of Capital Power Corporation340 so some of those level playing field

issues have dissipated. I consider it possible, through the use of separate accounts, to ensure that

ACFA funds are not available to competitive affiliates. Further, as discussed by the Commission

in Decision 2010-035, I consider that level playing field issues with respect to ACFA financing

could be explored in proceedings dealing specifically with the EPCOR Group‟s Code of

Conduct.341

569. Both the 2007 and 2011 letters from Edmonton refer to the additional debt and effects

upon credit ratings. However, one must question, as the equity owner of EUI, why Edmonton

would not wish to diversify its financing requirements of EUI by flowing through ACFA

financing to EDTI and reduce the private market demands of EUI to raise debt. The debt would

be in Edmonton‟s name; however, Edmonton would have access to an additional and offsetting

source of financing by flowing through this capital. EUI‟s debt demands would be equally

reduced as the pressure to raise funds from some or all of the requirements for EDTI would be

flowed through from the ACFA reserve. It is not readily apparent that this arrangement would

have any negative consequences to EUI‟s ratings. With regard to Edmonton‟s ratings, perhaps

the offsetting reduced requirements of EUI would significantly mitigate this issue of debt and

credit rating concerns. Edmonton in its 2011 letter states that it leverages its capital requirements

with strategic uses of debt on behalf of its taxpayers; the question needs to be asked whether it

should do so on behalf of ratepayers.

570. The UCA proposed to reduce the average cost of debt by 1.50 per cent. I do not agree

with that rate reduction for new debt nor applying it to all outstanding debt as the UCA proposed.

As detailed below I would have directed EDTI in its compliance filing to determine interest rates

for EDTI transmission and EDTI distribution based upon securing financing from ACFA for the

current year‟s debt issuance and deem that as the cost of newly issued long-term debt. The table

below compares the average historical cost of debt between ENMAX Power Corporation,

distribution and transmission and EPCOR Distribution & Transmission Inc. (EDTI distribution

and EDTI transmission) based upon the publicly available AUC Rule 005342 filings with the

Commission. Over time, accessing ACFA financing would have a substantial effect on the costs

that ratepayers pay if funding evolved in a similar manner that is shown for ENMAX below.

339

Decision 2006-054 at page 108. 340

Exhibit 3, application at paragraph 113: “As described in EDTI‟s 2010-2011 Application, on July 9, 2009 the

portion of EUI‟s operations related to power generation and associated services was sold to a newly formed

independent and stand alone company called Capital Power Corp. (“CPC”) (TSX: CPX). Following the

transaction, EUI held approximately 72.2% (through its subsidiary EPCOR Power Development Corporation)

of CPC through units in Capital Power Limited Partnership that are exchangeable on a one for one basis for

common shares of CPC. As a result of the sale of portions of its remaining interest in CPC in December 2010

and November 2011 and issuances of common shares by Capital Power, EUI currently holds approximately

39% of CPC.” 341


AUC Rule 005: Annual Reporting Requirements of Financial and Operational Results.

http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Documents/Rule005.pdf



Table 52. Average historical cost of debt (from AUC Rule 005 filings)

EDTI

distribution EDTI

transmission ENMAX

distribution ENMAX

transmission

2011 6.03%(1) 6.40%(1) 4.926% 4.926%

2010 6.12% 6.32% 5.046% 5.046%

(1) The cost of debt estimate for 2011 has been adjusted to reflect the full year’s carrying cost for ED10010 at 4.37 per cent.

571. EDTI distribution customers paid 1.074 per cent and 1.104 per cent more in interest in

2010 and 2011, respectively, than ENMAX distribution customers paid. EDTI transmission

customers paid 1.274 per cent and 1.474 per cent more in interest in 2010 and 2011, respectively,

than ENMAX transmission customers paid.

572. This 1.104 per cent and 1.474 per cent interest rate difference applied to an EDTI

distribution and EDTI transmission combined debt outstanding balance at 2011 year end of

$341,280,000, would indicate that EDTI ratepayers are remitting $3,767,731 to $5,030,467 more

in interest per year to EUI than they would if they had achieved the same ACFA funding as

ENMAX.

573. In a competitive market there is an expectation that entities will pursue efficiencies on

behalf of customers and shareholders alike. The Commission encourages these efficiencies by

allowing transactions between affiliated entities and has established the Code of Conduct to

guide decisions related to non-arms length transactions and associated conduct. Where ratepayer

efficiency is evident and being used by a similar municipally regulated utility the Commission

should question why that efficiency is not being pursued by EDTI.

The stand-alone principle

574. There are two alternative logical routes to view the stand-alone principle. Both

methodologies lead to the same conclusion that the Commission can deem ACFA funding rates

for debt for EDTI.

Route 1

575. EDTI is a municipal subsidiary in Alberta. Edmonton has access to ACFA financing

because of its standing as a municipality and infrastructure of EDTI is eligible for that financing.

Both the UCA and EDTI argued that there are special circumstances that are created that flow

through to ratepayers because of the happenstance of ownership by a municipality. The two per

cent increase in debt to equity that was awarded to non-tax paying entities in the 2011 Generic

Cost of Capital Decision (Decision 2011-474), as well as the tax free status of the municipality

are effects that result from ownership by a municipality. I view access to ACFA funding as just

another aspect of that happenstance of ownership.

576. Within the stand-alone principle, there is an argument that since Alberta municipalities

have access to ACFA funding then a utility owned by an Alberta municipality will have access to

ACFA funding and therefore be perceived to have access to AAA funding. Debt rates for

revenue requirement purposes could then be set using those rates less administrative costs.



Route 2

577. The alternative route to applying the stand-alone principle, that I prefer, was expressed

with Commission Member Yahya in our additional comments to Decision 2011-399 which cited

the Court of Appeal. Those findings supported an independence of thought for the Commission

in its assessment of the application of the stand-alone principle and the Commission should not

apply the stand-alone principles by “rote”:

43. For example, in AltaLink Management Ltd., AltaLink sought to have the Alberta

Energy and Utilities Board (board or EUB) calculate an income tax allowance

commensurate with a taxable entity. The City of Calgary objected and argued it was

inappropriate to raise the just and reasonable rate of return under the stand-alone

principle, because the stand-alone principle was developed to shield customers from

absorbing the cost of funds resulting from decisions of consolidated entities. The board

took a middle ground approach and decided to establish a tax allowance by looking at the

tax status of AltaLink‟s partners. The board stated “that in a cost of service jurisdiction

where revenue and costs are forecast on a prospective basis, a cost is recoverable in

customer rates if there is a reasonable expectation that it will be incurred.” Prior to the

hearing, interestingly, one of the partners had a tax free status but later changed it. The

board, however, made no allowance for that partner since there was “no such expectation

with respect to income taxes when the partner is initially structured as non-taxable and

later inexplicably changes its tax status with the result that customers are expected to

provide it with an income tax allowance.”

44. The courts have always affirmed the flexibility of the Commission to examine the

corporate structure of utilities and its parent organization with respect to setting rates. In

ATCO Electric Ltd. v. Alberta (Energy & Utilities Board), the Court of Appeal held that

the EUB “ha[d] the jurisdiction to segregate business functions of an integrated utility –

and determine a notional corporate organizational model – for purposes of evaluating risk

and calculating prudent carrying costs associated therewith.” The Court approved of the

board‟s actions which were in line with evidence of independent financial experts, and

noted with approval that the board followed the advice of the experts that:

… the Board should “not apply the stand-alone principle by rote. Instead the Board

should deal with the reality, utilize independence of thought, question assumptions and

think through whether an approach that has been applied in the past in different

circumstances should be applied now in new circumstances. Such an approach should

lead the Board to deal with reality and decline to apply the stand-alone principle to the

detriment of the customers of the [distribution companies].343

578. I have examined EDTI‟s application in this proceeding and decline to apply the stand-

alone principle as application of this principle in this instance is to the detriment of EDTI‟s

customers.

579. The treatment of AltaLink in Decision 2011-453344by the Commission provides further

analogous support. There, the Commission found “it reasonable to continue the current practice

of determining AltaLink‟s income tax status on a deemed stand alone basis.”345 AltaLink is a

343

Decision 2011-399 at paragraphs 43 and 44 (original footnotes omitted). 344

Decision 2011-453: AltaLink Management Ltd., 2011-2013 General Tariff Application, Application No.

1606895, Proceeding ID No. 1021, November 18, 2011. 345





non-tax paying entity and AltaLink‟s owner SNC-Lavalin is the tax paying entity. In the

proceeding, CCA submitted that “this was further evidence supporting the Commission‟s finding

that an entity, such as AltaLink, which does not pay any income taxes, „has little or no incentive

to maximize its tax deductions‟.”346

580. In reaching its findings the Commission considered that certain deductions for income tax

purposes should be taken for the benefit of customers:

The overheads in question have been deducted in the past for income tax purposes and it

would be reasonable for AltaLink to continue to deduct such costs in the future. The

Commission considers this to be a position that AltaLink should take to benefit its

customers. The Commission considers this to be similar to the expectation that AltaLink

will maximize deductions such as the Rainbow type capital maintenance expenditures for

the benefit of its customers.347

581. In its 2011-2012 GTA refiling, AltaLink further argued that this method “represented a

very aggressive position that would likely not be accepted by the Canada Review Agency in its

assessment” and proposed placeholders which were subsequently denied by the Commission.348

In my view, this finding results in the parent ultimately being responsible for the tax

consequences as the tax paying entity. The Commission deemed a revenue requirement treatment

in the subsidiary that required the parent to make the same tax deductions to keep it whole.

However the Commission was willing to consider the impact in a future GTA if any

disallowance occurred. In this instance, the Commission did not mechanically subscribe to the

stand-alone principle in its treatment of AltaLink. The Commission balanced the particular

situation and motivations of the owners with ratepayers‟ interests. I consider that this approach is

particularly relevant when evaluating ACFA financing within EDTI‟s cost of debt.

Conclusion

582. I believe based on the history of prior EDTI GTA decisions as detailed above and EDTI‟s

reluctance to actively pursue ACFA financing opportunities, Edmonton and EUI have a similar

lack of motivation in minimizing debt costs that will ultimately be borne by ratepayers. Based on

these views, with respect to approval of the cost of new long-term debt, I would have directed

EDTI in its compliance filing to determine interest rates for EDTI transmission and EDTI

distribution based upon securing financing from ACFA for the current year‟s debt issuance and

deem that as the cost of newly issued long-term debt.

346



Decision 2012-221 at paragraph 128 and 131.



583. If for some unforeseen reason, ACFA was not accessible nor financially advantageous in

a future GTA, then I would consider the impact that any cost would have, similar to what the

Commission did in the AltaLink decision referenced above with regard to a future Canada

Revenue Agency assessment. This approach recognizes the particular circumstances within the

confines of this application of not applying the stand-alone principle, which in my view

corresponds with the Commission‟s examination in EDTI‟s 2010-2011 GTA of EDTI‟s

2007-2009 debt.


Bill Lyttle

Commission Member



Appendix 1 – Proceeding participants

Name of organization (abbreviation) counsel or representative

EPCOR Distribution & Transmission Inc. (EDTI) J. Liptelo D. Gerke J. Elford D. Tenney

ATCO Electric Ltd. (ATCO Electric) L. Keough W. Wright L. Kizuk E. Gai K. Kerckhof

AltaLink Management Ltd. (AltaLink) Z. Lazic D. Fischbach

Consumers’ Coalition of Alberta (CCA) J. A. Wachowich A. P. Merani R. Retnanandan

ENMAX Power Corporation (ENMAX) K. Hildebrandt H. Johansen J. Schlauch J. Petratur J. Worsick T. Carle

Office of the Utilities Consumer Advocate (UCA) C. R. McCreary T. A. Shipley

University of Alberta (University) P. A. Smith M. Turner A. da Silva T. Nonay



The Alberta Utilities Commission Commission Panel M. Kolesar, Vice-Chair B. Lyttle, Commission Member K. Holgate, Commission Member Commission Staff S. Ramdin (Commission counsel) D. Cherniwchan J. Olsen N. Mahbub S. McCrady B. Clarke O. Vasetsky P. Dmytruk



Appendix 2 – Summary of Commission directions

This section is provided for the convenience of readers. In the event of any difference between

the directions in this section and those in the main body of the decision, the wording in the main

body of the decision shall prevail.

1. Upon reviewing the application, the Commission finds that EDTI has complied with the

direction. However, the Commission did not find the presentation of the information in

tables 2.2-1 and 13.2-1 helpful. The Commission asked an information request for

clarification and found the format of the continuity schedules provided as AUC-EDTI-

68(b) attachments 1 and 2 to be much easier to follow. The Commission directs EDTI, in

future filings for its transmission function, to file continuity schedules for at least three

years prior to the forecast test year or years in a format similar to AUC-EDTI-68(b)

attachments 1 and 2, and to continue submitting business cases for capital expenditures

that are greater than $500,000. Further, the Commission reminds EDTI, as per Direction

32 in Decision 2006-054, to continue preparing business cases for capital expenditures

that may last longer than one year and are in excess of $500,000. For EDTI‟s distribution

function, the Commission may request EDTI to provide this information at the end of the

performance-based regulation (PBR) term for each year of the PBR term. .... Paragraph 23

2. The Commission agrees with the UCA that EDTI has not provided sufficient supporting

evidence to justify the use of contractor backfills in its vacancy rate and finds that the

direction has not been complied with. The Commission notes that the number of new

positions created is not considered in the calculation of vacancy rates. The Commission

directs EDTI for its transmission function to develop a system to better track vacancies

which takes into account newly created positions. .......................................... Paragraph 27

3. For distribution, the Commission notes that distribution capital expenditures forecast for

2012 are lower than 2011 actual levels, both in aggregate and for the capital expenditures

life cycle replacement projects. Further, as shown in Table 7 above, generally three

quarters of distribution capital expenditures are constructed using internal resources. As

distribution capital expenditures are forecast to decrease and there is a similar forecast

decrease in the use of contractors, the Commission finds no support for the forecast

increase in distribution capital FTE levels. The Commission is not persuaded that

distribution capital FTE increases beyond 2011 actual levels, as forecast by EDTI, are

required and therefore, the Commission directs that the 2012 distribution capital FTEs be

held to the 2011 actual levels. .......................................................................... Paragraph 52

4. For all of the reasons provided above, the Commission finds that capital FTE levels for

distribution in the 2012 test year shall be reduced by 23.7 FTEs and, instead, be based on

the 2011 actual levels. The Commission directs EDTI to reflect this reduction in

distribution capital FTEs along with all related costs in the compliance application and to

provide a schedule with all resulting adjustments. ......................................... Paragraph 56

5. Accordingly, for distribution, the Commission directs that a gross vacancy rate of 3.4 per

cent is to be applied to the salary – other category, based on calculating the four year

average of the vacancy factors before backfills, as shown in Table 13 above. For

transmission, the Commission directs that no vacancy rate shall be applied to the salary

category for the 2012 test year, because in the Commission‟s view use of a negative

vacancy factor would provide more than 100 per cent of salary for each FTE to which it



is applied. Additionally, the Commission does not agree with EDTI‟s calculation of its

negative vacancy factor because it fails to take into account FTEs in excess of the

approved forecast amount. .............................................................................. Paragraph 79

6. With regard to Section 2.8 of the application on the tracking of monthly FTE vacancy

data, the Commission disagrees with EDTI‟s position that it has complied with this

direction. Tables 1.4.3-3 and 1.4.3-6 for distribution and transmission vacancy

respectively provide monthly information for salaried employees but do not provide any

information on the labour FTE category, which is the dominant FTE category for both

business units. The Commission finds that EDTI has complied with the directions shown

in sections 2.9, 2.11 and 2.13 of the application. However, EDTI has only partially

complied with directions in sections 2.1 and 2.8 of the application, having only tracked

vacancy rates for salaried employees. For transmission, EDTI is directed to track monthly

data on each FTE category as shown in Table 14 above, and to provide this information

as part of future filings. EDTI is also directed to track new positions that are hired but

were not part of the approved FTE level and to reflect these in the vacancy calculations.

For EDTI‟s distribution function, the Commission may request EDTI to provide this

information at the end of the PBR term for each year of the PBR term. ........ Paragraph 80

7. Accordingly, the Commission directs EDTI transmission to base the financial component

of its STI program for the purposes of its regulatory applications on the net income of

EDTI for 2013 onward. EDTI distribution is not limited or restricted by the Commission

in its compensation practices, during the PBR term, including the terms of its STI

program. Therefore, this direction will not apply to EDTI‟s distribution function as its

distribution function is now under a performance based regulation regime beginning in

2013. However, the direction will still apply to the transmission function and the

Commission directs that the STI program for transmission will be based on the net

income of EDTI at the time of EDTI‟s next transmission general tariff application.

........................................................................................................................ Paragraph 118

8. In respect of the pool B payments, the Commission considers that any actual pool B

payments made to EDTI employees in 2012 and beyond should be treated as disallowed

costs and directs EDTI to deduct any pool B payments from EDTI‟s expenses when

determining EDTI‟s return on equity in 2012 for distribution and transmission, and for

2013 and beyond for transmission. ............................................................... Paragraph 119

9. The Commission is concerned with the structure of the new MTI program proposed by

EDTI. Specifically, because the MTI program is based on assets, and there is no

assurance that the assets will be required for the provision of utility service, the

Commission finds that the MTI program creates an incentive to invest in assets that may

not be required for the provision of utility service. The Commission discusses additional

concerns with EDTI‟s MTI program in Section 6.2.1.3 of this decision. For all of these

reasons, the Commission directs EDTI to remove the MTI costs from its 2012 revenue

requirement in its compliance filing. ............................................................ Paragraph 128

10. Should EDTI choose to implement the MTI program and make incentive payments to

eligible employees in 2012, the Commission directs EDTI to remove the cost of those

payments from its actual 2012 expenses when determining its actual return on equity for

2012. .............................................................................................................. Paragraph 129

11. The Commission accepts EDTI‟s proposal that the credit spread for distribution be 150

basis points, based on its analysis of comparative companies with an A (low) credit



rating. Given the Commission‟s finding with respect to the credit spread for transmission,

the Commission directs EDTI to use the 150 basis point credit spread for transmission.

........................................................................................................................ Paragraph 152

12. The Commission directs EDTI, in its compliance filing, to calculate the cost of its 2012

debt issues using the Government of Canada long-term bond yield for the month of June

2012 (2.32 per cent) which includes the maturity premium. ........................ Paragraph 155

13. Consistent with the above, EDTI, in its compliance filing, is directed to reflect all

changes to the 2012 revenue requirement consistent with the approach determined in

Decision 2010-505, when the 2011 actual figures are input into EDTI‟s revenue

requirement model. ....................................................................................... Paragraph 212

14. With respect to Table 26 above, the Commission notes a discrepancy between the 2010

actual closing CWIP balance of $16.0 million and the 2011 actual opening CWIP balance

of $15.3 million The Commission directs EDTI in its compliance filing to correct the

discrepancy and to reflect this change in the 2012 opening and closing forecast CWIP

balances. ........................................................................................................ Paragraph 269

15. The Commission has reviewed the analyses of individual project variances provided in

the application including the 30 post implementation reviews provided. The Commission

finds that the capital additions are reasonable and accordingly approves EDTI‟s

transmission function 2012 opening rate base as filed, subject to the following direction

regarding CWIP balances. The Commission directs EDTI to correct the $4.6 million

discrepancy between 2011 actual closing CWIP and 2012 forecast opening CWIP and to

reflect this correction in 2012 opening and closing CWIP balances in the compliance

filing. ............................................................................................................. Paragraph 295

16. Even though EDTI has an AESO-directed projects deferral account, the majority of the

work will not be completed until 2013 and, as such, the Commission finds that EDTI

should not include these projects as capital additions in its 2012 forecast revenue

requirement as filed. Accordingly, the Commission directs EDTI to remove the Genesee

Interface to HVDC Converter Station and the East HVDC Converter Station Interface

from its 2012 revenue requirement. Moreover, the Commission directs EDTI in its

compliance filing to reflect this direction in EDTI‟s transmission capital additions

schedule and all related schedules. ............................................................... Paragraph 334

17. The corporate services costs in the allocated cost category for 2010 were 9.4 per cent less

than the approved amount and for 2011 were 10.9 per cent less than the approved

amount. This suggests a significant amount of discretion in the actual expenditures and

possible forecasting errors. Based on a review of the historical actual information, the

nature of the costs included in the allocated cost category and the lack of persuasive

support for the increases in allocated corporate services costs, the Commission considers

that this forecast is excessive and would result in unreasonable costs being allocated to

EDTI and EEAI. Therefore, for the purpose of allocating costs to EDTI and EEAI, the

Commission directs EDTI to reduce the 2012 forecast corporate services costs in the

allocated category by nine per cent after any other corporate services costs reductions

identified in the application or directed in this decision are applied. The Commission

finds that a nine per cent reduction is reasonable given the reduction in discretionary

expenditures and any forecast errors reflected in the 9.4 per cent and 10.9 per cent

reductions experienced in 2010 and 2011 respectively. ............................... Paragraph 395



18. In addition to the findings made in Section 3.6, the Commission does not accept that the

forecast 2012 MTI amounts included in the EUI corporate services costs are required to

provide utility service. EDTI identified a net benefit to utility customers from the

increased economies of scale that will be captured through the allocation of costs to new

businesses as it seeks out growth opportunities. While there may be some possible

transitory future benefit, EUI could divest itself of the acquired businesses and leave

utility customers in the position of having paid the costs related to acquisitions and

captured little or none of the benefits. The Commission considers that the MTI program

is designed in a way that any resulting benefits will accrue to the shareholder of EUI. As

the Commission is not convinced that MTI provides any benefit to utility customers, the

Commission finds that this cost should not be approved as an element of the costs to be

allocated to EDTI and EEAI. The Commission directs EDTI to remove all MTI amounts

from the corporate services costs allocated to EDTI and EEAI. .................. Paragraph 404

19. In its evidence the UCA made reference to a number of prior Commission decisions

including Decision 2010-483, Decision 2009-238 and Decision 2011-450 that address the

issue of customer communications and brand development. Each of these decisions

denies costs related to the types of activities identified by EDTI as included in

community relations and the EPCOR community essentials council services. The

Commission acknowledges that EDTI has removed certain costs such as donations from

these costs but finds that the remaining costs are not required for the provision of utility

service and directs EDTI to remove these costs from the 2012 forecast corporate services

costs allocated to EDTI and EEAI. ............................................................... Paragraph 407

20. The Commission directs EDTI to remove $1.15 million ($0.65 million including a 77 per

cent overhead charge) from the 2012 forecast EUI corporate services costs and to remove

the proportionate share of these business development costs from the amounts allocated

to EDTI and EEAI. ....................................................................................... Paragraph 416

21. The Commission accepts the position that fully burdened labour cost is administratively

more complex and as such may not be as clear or stable as headcount as an allocator.

Additionally, given the relatively minor variation in the resulting allocation demonstrated

in the analysis of the alternatives, the Commission finds that the use of headcount for the

labour component in the composite cost causation allocator is acceptable as utilized in the

applied-for allocated corporate services costs. However, given the different mix of

employees in the companies, the Commission considers there should be a review of the

impact of the use of payroll or full-time equivalents (FTEs) rather than headcount. The

Commission therefore directs EDTI and EEAI to include in any future applications that

incorporate the composite cost causation allocator, an analysis of the use of payroll and

FTEs as the labour component. Should the profile of the mix of employees in the EPCOR

businesses be modified, the Commission may determine that headcount no longer results

in the most fair and reasonable allocation. .................................................... Paragraph 426

22. The Commission, having factored in both the availability and transparency of the revenue

components, considers the exclusion of commodity and flow through items, a measure of

margin, is a better reflection of the burden each business segment has on the total

corporate services costs allocated using the composite cost causation allocator. To ensure

each revenue item is only included once in the calculation of the revenue component of

the composite cost causation allocator, the Commission directs EDTI and EEAI to

include revenue net of commodity charges, items that flow through to utility customers,



and any items eliminated on consolidation as the revenue component of the composite

cost causation allocator. ................................................................................ Paragraph 434

23. For these reasons, the Commission directs EDTI to remove capital expenditures as a

component of the composite cost causation allocator for the purpose of allocating

corporate services costs to EDTI and EEAI. ................................................ Paragraph 440

24. Accordingly, the Commission finds that, for the purposes of allocating costs to EDTI and

EEAI, the composite cost causation allocator should be calculated recognizing EUI‟s

investment in CPC or any other investments held by EUI. The Commission directs EDTI

to include the revenues (including equity income), assets and headcount associated with

EUI‟s investment in CPC and any other assets held by EUI, in the calculation of the

composite cost causation allocator. ............................................................... Paragraph 446

25. The Commission has considered the submissions related to the incorporation of the U.S.

Water operation and finds EDTI has not adequately demonstrated that the governance

related costs allocated by the composite cost causation allocator should not be allocated

to the U.S. Water operation. The assertion that the governance related services will not be

used is unsupported. The three components of the corporate costs assignment include

direct assignment, fees for asset usage and cost allocation. Within cost allocation, there

are functional allocations and allocations for which a causative factor could not be

identified that are allocated using a composite allocator. Specifically, the costs allocated

using the composite cost causation allocator can not be directly assigned or allocated

using a functional allocator and, as such, are remote from the business. It is likely that

any one of the group of companies could make an argument that it did not benefit directly

from certain of the governance cost groups. For the purpose of allocating costs to EDTI

and EEAI, the Commission directs EDTI to abandon the Canadian composite cost

causation allocator. ....................................................................................... Paragraph 450

26. The Commission notes that areas of concern which were raised by the Commission or

interested parties in this decision may impact other larger category areas such as rate

base, depreciation, and cost of capital, for example. For this reason, EDTI, in its

compliance filing, is directed to update all impacted areas of its revenue requirement for

the 2012 test year for all findings and determinations made within this decision.

........................................................................................................................ Paragraph 545