direct energy regulated services - auc2 • decision 2957-d01-2015 (july 7, 2015) 8. in a letter...

Decision 2957-D01-2015

Direct Energy Regulated Services 2012-2016 Default Rate Tariff and Regulated Rate Tariff July 7, 2015

Alberta Utilities Commission


Direct Energy Regulated Services

2012-2016 Default Rate Tariff and Regulated Rate Tariff

Proceeding 2957

Application 1610155-1

July 7, 2015

Published by the:


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/

Decision 2957-D01-2015 (July 7, 2015) • i

Contents

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

2 Background ........................................................................................................................... 2

3 Response to past Commission directions ............................................................................ 3

4 Revenue requirement ............................................................................................................ 5 4.1 Inflation .......................................................................................................................... 5 4.2 Forecast amounts for the years 2012, 2013 and 2014 .................................................... 7 4.3 Overall forecast reductions and site counts for 2015 and 2016 ................................... 17 4.4 Customer care and billing costs ................................................................................... 20

4.5 Vendor selection costs.................................................................................................. 34 4.6 Corporate costs ............................................................................................................. 40

4.7 Postal costs ................................................................................................................... 51 4.8 Remuneration ............................................................................................................... 52

4.9 Customer education and awareness ............................................................................. 57 4.10 Cost of working capital ................................................................................................ 60 4.11 Bad debt and penalty revenue ...................................................................................... 64

4.12 Unbillable revenues ...................................................................................................... 72 4.13 Other administration costs ........................................................................................... 75

4.14 Merchant fees ............................................................................................................... 76

5 Allocation methodology ...................................................................................................... 79 5.1 Allocation of certain labour costs between the DRT and the RRT .............................. 80

5.2 Allocation of amounts in the “Merchant Fees” cost category between rate classes .... 81

5.3 Allocation of RRT costs to the lighting rate class........................................................ 82

6 Rate design ........................................................................................................................... 85 6.1 Mid-use rate class ......................................................................................................... 85

6.2 Idle sites ....................................................................................................................... 86 6.3 Prior period adjustment ................................................................................................ 88

7 Other .................................................................................................................................... 90 7.1 Inter-affiliate code of conduct ...................................................................................... 90 7.2 DRT and RRT terms and conditions ............................................................................ 93 7.3 Internal energy price setting plan development costs .................................................. 97 7.4 Minimum filing requirements ...................................................................................... 98

8 Order .................................................................................................................................. 100

Appendix 1 – Proceeding participants .................................................................................... 101

Appendix 2 – Oral hearing – registered appearances ........................................................... 102

Appendix 3 – Summary of Commission directions ................................................................ 103

Appendix 4 – Default Rate Tariff Terms and Conditions ..................................................... 110

Appendix 5 – Regulated Rate Tariff Terms and Conditions ................................................ 111

ii • Decision 2957-D01-2015 (July 7, 2015)

List of tables

Table 1. Consumer price index annual average per cent change* ........................................ 6

Table 2. Summary of recommended reductions for 2015 and 2016 prepared by Mr. Russ

Bell .............................................................................................................................. 20

Table 3. Customer care and billing costs ............................................................................... 21

Table 4. Customer care and billing costs on a per site basis................................................ 24

Table 5. Comparison of CC&B FMV buildup ...................................................................... 27

Table 6. Applied-for vendor selection costs* ......................................................................... 35

Table 7. Corporate costs ($000s) ............................................................................................ 40

Table 8. Direct and indirect corporate costs allocators adapted from CCA-DERS-031 .. 41

Table 9. DERS’ back-casted corporate costs allocations ..................................................... 41

Table 10. Details of forecast labour costs for 2015 and 2016 ................................................. 53

Table 11. Variance analysis of “Labour by Department” costs for the DRT on a cost per

site basis ..................................................................................................................... 54

Table 12. DERS customer education and awareness costs ($000s) ....................................... 58

Table 13. Forecast costs for working capital for 2015 and 2016 ........................................... 61

Table 14. Variance analysis of “Working Capital” costs for the non-energy operation of

the DRT on a cost per site basis ............................................................................... 62

Table 15. Forecast costs in the “Bad Debt” cost category for 2015 and 2016 ...................... 64

Table 16. Forecast amounts in the “Penalty Revenue” category for 2015 and 2016 ........... 66

Table 17. Variance analysis of “Bad Debt” costs for the DRT on a cost per site basis ....... 67

Table 18. Forecast unbillable revenue for 2015 and 2016 ...................................................... 72

Table 19. Variance analysis of “Unbillable Revenue” costs for the DRT and the RRT on a

cost per site basis ....................................................................................................... 73

Table 20. Other administration costs forecasts for 2015 and 2016 ....................................... 75

Table 21. Forecast merchant fees costs for 2015 and 2016 .................................................... 77

Table 22. Variance analysis of “Merchant Fees” costs for the RRT on a cost per site basis

..................................................................................................................................... 78

Table 23. Prior-period revenue adjustment ($000s) ............................................................... 89

Decision 2957-D01-2015 (July 7, 2015) • 1


Calgary, Alberta


Direct Energy Regulated Services Proceeding 2957

2012-2016 Default Rate Tariff and Regulated Rate Tariff Application 1610155-1

1 Introduction

1. Direct Energy Regulated Services (DERS) filed an application with the Alberta Utilities

Commission on December 6, 2013, requesting approval of a default rate tariff (DRT), including

a reasonable return for DRT service and a regulated rate tariff (RRT) for a five-year test period

from January 1, 2012 to December 31, 2016. DERS specified in the application that it was only

applying for the customer care and billing (CC&B) costs, as well as any related secondary

effects, for 2015 and 2016 on an interim placeholder basis since it will be engaging a new CC&B

provider after 2014.

2. The Commission issued a notice of application on December 9, 2013. On December 16,

2013, the notice of application was published in the Edmonton Journal, the Edmonton Sun, the

Calgary Herald, and the Calgary Sun. The notice of application required that any party who

wished to participate in the proceeding submit a statement of intent to participate (SIP) to the

Commission by December 30, 2013.

3. The Commission received SIPs from the Consumers’ Coalition of Alberta (CCA) and the

Office of the Utilities Consumer Advocate (UCA). Both the CCA and the UCA actively

participated in this proceeding.1,2

4. The Commission established a process schedule for this proceeding.3

5. In a letter dated May 27, 2014, DERS stated that it would be filing a separate application

to deal with the CC&B services for 2015 and 2016 in the first week of June and that it would be

most efficient for both the current application and the forthcoming CC&B application to be heard

together. Accordingly, DERS requested that the Commission suspend the process schedule and

establish a new process schedule following DERS’ filing of its CC&B application.4

6. In a letter dated June 5, 2014, the Commission suspended the proceeding and noted that

the proceeding would resume following receipt of DERS’ new CC&B application.5

7. On June 16, 2014, DERS filed an amended application that included a request for final

CC&B costs for 2015 and 2016, as well as a request for increases in postal costs and other

ancillary impacts from the new CC&B arrangement.6

1 Exhibit 0010.01.CCA-2957, CCA SIP.

2 Exhibit 0012.01.UCA-2957, UCA SIP.

3 Exhibit 0014.01.AUC-2957, AUC letter – schedule and process, January 23, 2013.

4 Exhibit 0068.01.DEML-2957, DERS letter to AUC regarding suspension.

5 Exhibit 0073.01.AUC-2957, AUC letter – notice of suspension.

6 Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application.

2012-2016 Default Rate Tariff and Regulated Rate Tariff Direct Energy Regulated Services

2 • Decision 2957-D01-2015 (July 7, 2015)

8. In a letter dated July 21, 2014, the Commission resumed the proceeding and provided

parties with a revised process schedule with tentative hearing dates.7

9. On November 3, 2014, DERS submitted a letter and supplemental evidence in the form

of a fair market value (FMV) benchmark study.8

10. In a letter dated November 6, 2014, the Commission amended the process schedule to

accommodate additional process for interveners to test DERS’ supplemental evidence and

rescheduled the hearing dates to February 4, 2015.

11. The major steps in this proceeding have included the following:

information requests to the applicant;

intervener evidence;

information requests on the intervener evidence;

rebuttal evidence;

a second round of information requests to the applicant on corporate costs;

supplemental intervener evidence on corporate costs;

rebuttal evidence on supplemental intervener evidence on corporate costs;

confidential information requests to the applicant on CC&B materials;

confidential supplemental intervener evidence on CC&B materials;

confidential information requests on supplemental intervener evidence on CC&B

materials;

confidential second supplemental intervener evidence on CC&B materials;

confidential information requests on the second supplemental intervener evidence on

CC&B materials;

confidential rebuttal evidence on intervener evidence on CC&B materials;

an oral hearing held in Calgary from February 4 to February 11, 2015;

public and confidential argument; and,

public and confidential reply argument.

12. The Commission has briefly summarized the major process steps in this decision. For a

complete list of all procedural matters, please consult the record of this proceeding.

13. The Commission considers the record of this proceeding closed as of April 8, 2015, with

the submission of Exhibit 2957-X0103.

2 Background

14. DERS previously filed an application with the Commission on September 23, 2011, for

its 2012-2014 DRT and RRT, which was processed under Proceeding 1454. During the course of

Proceeding 1454, DERS filed a fully executed negotiated settlement agreement (NSA). This

NSA was rejected by the Commission in Decision 2012-343.9

7 Exhibit 0087.01.AUC-2957, AUC letter – resumption of proceeding and new process schedule.

8 Exhibit 0127.01.DEML-2957, DERS cover letter proposed proceeding schedule and supplementary evidence.

9 Decision 2012-343: Direct Energy Regulated Services, 2012-2014 Default Rate Tariff and Regulated Rate

Tariff, Proceeding 1454, Application 1607696-1, December 21, 2012.

http://www.auc.ab.ca/applications/decisions/Decisions/2012/2012-343.pdf


Decision 2957-D01-2015 (July 7, 2015) • 3

15. On February 5, 2013, DERS filed Application 1609270-1 with the Commission seeking

approval of its 2012-2014 DRT and RRT. In its application, DERS stated that it had prepared a

compliance filing that was based on the NSA and that it had also responded to the individual

issues and directions set out by the Commission in Decision 2012-343. This application was

processed under Proceeding 2406.10

16. In a letter dated March 28, 2013, the Commission found Application 1609270-1 to be

incomplete and closed Proceeding 2406. More specifically, the Commission found the

application deficient because it referred to the NSA as evidence, but neither the NSA from

Proceeding 1454 nor a fully executed amended NSA was included in DERS’ application. The

application could not be considered as a compliance filing because the NSA was rejected by the

Commission, and DERS’ 2012-2014 DRT and RRT rates were not approved in Decision 2012-

343.11

17. In this application, DERS stated that it had updated its 2012-2014 forecast and included

the 2015 and 2016 revenue requirements.

18. With the exception of material protected under a confidentiality order, all documents

submitted to the Commission in a proceeding, as well as the decisions of the Commission, are on

the public record and available to the public.

19. The Commission granted confidential treatment to a discrete portion of the evidence on

the record of this proceeding. The Commission avoided reference to these confidential materials

to forgo the need for portions of this decision being redacted. This will increase transparency for

readers not privy to the confidential materials and ensure DERS’ future rate proceedings benefit

from the arguments put forward in this proceeding. This does not, however, mean that the

confidential material was not considered. In reaching the determinations set out within this

decision, the Commission has considered all relevant materials comprising both the public and

confidential record of this proceeding, including the evidence and argument provided by each

party. Accordingly, references in this decision to specific parts of the record are intended to

assist the reader in understanding the Commission’s reasoning relating to a particular matter and

should not be taken as an indication that the Commission did not consider all relevant portions of

the record with respect to a particular matter.

3 Response to past Commission directions

20. In Section 2 of the application, DERS included responses to outstanding directions from

Decision 2012-343.12 The following table sets out those directions that the Commission finds

DERS has complied with, and the reasons for its findings.

10

Proceeding 2406, Application 1609270-1. 11

Proceeding 2406, Application 1609270-1, AUC letter of disposition, March 28, 2013. 12

Decision 2012-343.


4 • Decision 2957-D01-2015 (July 7, 2015)

Direction from Decision 2012-343 Compliance to direction

Direction 1 - The Commission approves the following

AIP (annual incentive plan) amounts for inclusion in the

non-energy revenue requirements for DERS for the years

2012-2014: DRT – $516,000 for 2012, $536,000 for 2013

and $558,000 in 2014; RRT – $335,000 for 2012,

$349,000 for 2013 and $362,000 for 2014. The

Commission directs DERS to reflect these figures in its

subsequent 2012 to 2014 non-energy revenue requirement

application filed with the Commission.

The Commission has reviewed

DERS’ response to AUC-DERS-

028 and the attachment to the

response to AUC-DERS-030.13

DERS has incorporated the AIP

amounts set out in Direction 1.

The Commission finds that DERS

has complied with this direction.

Direction 2 - For the above reasons, the Commission

denies the inclusion of LTIS (long-term incentive scheme)

costs in the non-energy revenue requirements of DERS for

the years 2012 to 2014. The Commission directs DERS to

remove any LTIS costs in its subsequent 2012 to 2014

non-energy revenue requirement application filed with the

Commission.



025(a) and the attachment to that

response, along with the

attachment to the response to

AUC-DERS-030.14 DERS has

deleted the LTIS costs referred to

in Direction 2. The Commission

finds that DERS has complied

with this direction.

Direction 4 - The Commission directs DERS to use the

following language in Section 6.7 of its terms and

conditions (T&Cs) in respect of its late payment penalty

charge: The amount due shown on a bill is owing to

DERS on the statement date. If a Customer does not pay a

bill in full within seventeen (17) calendar days after the

statement date specified on the bill, subject to disputed

charges as outlined in Article 8, a late payment charge

may be applied. The outstanding unpaid amount,

including the late payment charge, shall be applied to the

charges that become due and payable in the next bill.

DERS will disclose the late payment fee in its Fee

Schedule.


DERS’ T&Cs filed in this

application. DERS has used the

language specified in the

Commission’s Direction 4. For

additional detail, the reader is

referred to Section 7.2 of this

decision. The Commission finds

that DERS has complied with this

direction.

Direction 5 - Consistent with the Commission’s findings,

the Commission directs DERS to change page one of its

DRT and RRT bills by removing the words “Current

Charges Due Date” and replace them with “Late Payment

Penalty Date.” The Commission also directs DERS to

change page two of its DRT and RRT bills in the section

identified as “Paying your bill on time” by removing the

words “current charges Due Date” and “Due Date” and

replace them with “Late Payment Penalty Date.”



042.15 DERS has changed the

wording as directed. The

Commission finds that DERS has

complied with this direction.

13

Exhibit 0020.01.DEML-2957, AUC-DERS-028. 14


Exhibit 0020.01.DEML-2957, AUC-DERS-042.


Decision 2957-D01-2015 (July 7, 2015) • 5

Direction from Decision 2012-343 Compliance to direction

Direction 6 - The Commission directs that the changes

required [on] page one and page two of DERS’ DRT and

RRT bills as set out in this decision at paragraph 171 be

implemented and filed for acknowledgement with the

Commission no later than March 1, 2013. On the date of

implementation, the statement date will be identified as

the date that payment is owing and the changes to the bill

will clarify that the customer will have until the late

payment penalty date to avoid payment of interest.



042.16 DERS has made the changes

identified in Direction 6. The

Commission finds that DERS has

complied with this direction.

Direction 7 - The Commission directs DERS to prepare a

revised set of T&Cs incorporating the directions set out in

this decision at paragraphs 102, 114 and 168 and file them

for acknowledgement with the Commission no later than

February 10, 2013.


DERS’ T&Cs. DERS has prepared

revised T&Cs incorporating the

directions referred to in

Direction 7. The Commission

finds that DERS has complied

with this direction. For additional

detail the reader is referred to

Section 7.2 of this decision.

21. The Commission also provided the following instruction in Direction 3 of Decision 2012-

343:

The following SAS (share award scheme) incentive amounts are approved for inclusion

in the non-energy revenue requirements for DERS for the years 2012 to 2014: DRT –

$176,400 for 2012, $180,300 for 2013 and $184,200 in 2014; RRT – $44,100 for 2012,

$45,100 for 2013 and $46,100 for 2014. The Commission directs DERS to reflect these

figures in its subsequent 2012 to 2014 non-energy revenue requirement application filed

with the Commission.17

22. The Commission has reviewed DERS’ response to AUC-DERS-025(a) and the

attachment to that response. The 2012 SAS amounts are as per the Commission’s direction;

however, the SAS amounts for 2013 and 2014 are not as directed. The Commission, therefore,

directs DERS, in its compliance filing, to make the necessary corrections to ensure that the SAS

amounts for 2013 and 2014 reflect Direction 3 in Decision 2012-343.

4 Revenue requirement

4.1 Inflation

23. In each of the years 2015 and 2016, DERS applied an inflation factor of 2.75 per cent to

the following cost categories: “Labour (Gas Procurement),” “Labour by Department,” “Other

Administration Costs,” and “Corporate Costs.”18 DERS stated that the 2.75 per cent inflation

16


Decision 2012-343, page 45. 18

Exhibit 0001.00.DEML-2957, 2012-2016 DRT and RRT application, page 38.


6 • Decision 2957-D01-2015 (July 7, 2015)

factor was taken from Schedule 3.2 of an application from ATCO Gas,19 and was calculated

using the Alberta Weekly Earnings and Alberta Consumer Price Index (CPI) data.

24. In response to an undertaking, DERS submitted a report by TD Economics entitled

“Provincial Economic Forecast Update” dated January 26, 2015, that provided actual CPI data

from 2012 to 2014 and updated forecasts of CPI for 2015 and 2016.20

Table 1. Consumer price index annual average per cent change*

2012

actual 2013

actual 2014

actual 2015

forecast 2016

forecast

Canada 1.5 0.9 1.9 0.4 2.3

Alberta 1.1 1.4 2.6 0.1 2.4

*Adapted from Provincial Economic Forecast Update released by TD Economics on January 26, 2015.

25. The CCA considers that there has been a major change in economic circumstances in

Alberta since the filing of DERS’ application, and indicated that it would be appropriate to adjust

the forecast for economic assumptions such as inflation. As such, it submitted that the

Commission adopt a 0.1 per cent inflation rate for 2015 and a 2.4 per cent inflation rate for 2016,

based on the most current external inflation information available for both costs and labour.21

The UCA made a similar recommendation.22

26. DERS disagreed with the recommendations made by the CCA and the UCA. It argued

that it is generally inappropriate to select a single factor, such as a potential drop in the inflation

rate for 2015, as a reason to reduce DERS’ costs. DERS indicated that it has accepted all

economic risk in this application and has done so since the beginning of 2012 in good faith.

DERS added that it has accepted the risks of a downturn in the Alberta economy on bad debt and

unbillable revenue for each of the years 2012 through 2016.23

27. DERS submitted that the drop in inflation forecast by TD is premised on the expected

drop in consumer expenditures on gasoline. DERS stated that it does not purchase gasoline to

any meaningful extent, if at all, for the purpose of delivering services to regulated customers, so

this drop in crude prices does not decrease DERS’ year over year expenses. DERS added that

wage inflation will continue and that it is more impacted by persistent wage inflation than

gasoline or a number of other costs. It submitted that even with layoffs in Alberta, those who

continue to be employed can still be expected to receive annual increases and non-gasoline

commodities will still increase in price.24

19

Proceeding 2826, Application 1609915-1, ATCO Gas and Pipelines Ltd., 2014 Annual Performance-based

Regulation Rate Adjustment Filing. Decision 2013-460 was issued on December 19, 2013 with respect to this

application. 20

Exhibit 2957-X0036.1, DERS attachment to undertaking 16 – TD Provincial Economic Forecast Update,

page 3. 21

Exhibit 2957-X0094, CCA public argument, paragraphs 5 and 7. 22

Exhibit 2957-X0097, UCA public argument, paragraph 231. 23

Exhibit 2957-X0103, DERS public reply argument, paragraph 180. 24

Exhibit 2957-X0103, DERS public reply argument, paragraph 181.



Decision 2957-D01-2015 (July 7, 2015) • 7

Commission findings

28. The Commission considers that it is not reasonable to apply an inflation forecast that is

partially based on a forecast increase in Alberta Weekly Earnings to the “Other Administration

Costs” cost category, because there are no direct labour costs in that cost category. The

Commission therefore finds that a more accurate forecast of inflation for this cost category

would be Alberta CPI. In Section 4.2 of this decision, the Commission has discussed its views

with respect to DERS’ submissions about accepting risk during the test period, and the

Commission’s preference to use the most recent information on the record in the context of

approving forecasts. The Commission considers that the forecast for Alberta CPI prepared by

TD Economics should be used as the forecast for Alberta CPI for 2015 and 2016 for the purposes

of this proceeding. Therefore, the Commission directs DERS, in its compliance filing, to apply

inflation to the “Other Administration Costs” cost category forecasts for 2015 and 2016 at the

rates of 0.1 per cent for 2015 and 2.4 per cent for 2016.

29. The Commission accepts DERS’ methodology for forecasting inflation for the “Labour

(Gas Procurement),” and “Labour by Department” cost categories. The Commission considers

that it is reasonable to use a combination of data with respect to Alberta CPI and Alberta Weekly

Earnings when forecasting costs for categories that are primarily comprised of labour. No party

raised any issues with respect to this methodology. The Commission reviewed Schedule 3.2 of

the ATCO Gas application from which DERS sourced its forecast inflation rate of 2.75 per cent

and notes that in the calculation, the Alberta CPI figure is given a weighting of 45 per cent, and

the Alberta Weekly Earnings data is given a weighting of 55 per cent. For the reasons previously

discussed in this section of the decision, the Commission finds that the Alberta CPI component

should be updated to use the most recent information on the record.

30. The most recent forecast on the record of the proceeding with regard to the percentage

increase in Alberta Weekly Earnings is 3.4 per cent for both 2015 and 2016.25 Once again, the

Commission considers that this more recent information should be incorporated into the forecast.

31. Using the updated Alberta CPI and Alberta Weekly Earnings data, the Commission has

calculated a forecast inflation rate of 1.92 per cent26 to be applied to these cost categories for

2015, and a forecast inflation rate of 2.95 per cent27 to be applied to these cost categories for

2016. The Commission directs DERS, as part of its compliance filing, to use a forecast inflation

rate of 1.92 per cent in determining the 2015 forecasts for the “Labour (Gas Procurement),” and

“Labour by Department” cost categories. The Commission directs DERS, as part of its

compliance filing, to use a forecast inflation rate of 2.95 per cent in determining the 2016

forecasts for the “Labour (Gas Procurement),” and “Labour by Department” cost categories.

4.2 Forecast amounts for the years 2012, 2013 and 2014

32. DERS filed its first application for the 2012-2014 DRT and RRT on September 23,

2011.28 In the first application, the revenue requirements for each of the three years 2012, 2013

25

Exhibit 0019.01.DEML-2957, UCA-DERS-001 to UCA-DERS-029, Attachment to the response to UCA-

DERS-016(b), 2013 Alberta Budget Economic Outlook, page 82. The same document is included in Exhibit

0018.01.DEML-2957, CCA-DERS-001 to CCA-DERS-017, Attachment to the response to CCA-DERS-009(b). 26

Alberta CPI forecast of 0.1 per cent weighted at 45 per cent, change in Alberta Weekly Earnings of 3.4 per cent

weighted at 55 per cent. ((0.1 * 45) + (3.4 * 55))/100. 27

Alberta CPI forecast of 2.4 per cent weighted at 45 per cent, change in Alberta Weekly Earnings of 3.4 per cent

weighted at 55 per cent. ((2.4 * 45) + (3.4 * 55))/100. 28

Exhibit 0001.00.DEML-1454 of Proceeding 1454.


8 • Decision 2957-D01-2015 (July 7, 2015)

and 2014 were prepared on a forecast basis. Subsequent to the Commission rejecting the NSA

that DERS reached with customer groups as part of the process for the first application,29 DERS

filed its second application for the 2012-2014 DRT and RRT on February 5, 2013.30 On March

18, 2013, the Commission issued a letter that closed the second application because the second

application was incomplete.31

33. DERS filed the current application on December 9, 2013, and expanded the scope of the

application to include 2015 and 2016. DERS stated the following with respect to the five test

years:

This Application relates to the 2012-2016 timeframe. 2012 and the majority of 2013 have

passed, whereby DERS finds itself in the unusual position of knowing 2012 and YTD

(year to date) 2013 actual costs. DERS has incorporated that knowledge in the

development of this Application based on a forecast test period. DERS has updated its

2012-2014 forecast and included 2015 and 2016 revenue requirements within this

Application. DERS understands that prospective rate making is an underlying principle

established in the Alberta regulatory framework and has structured its Application in

accordance with this principle.32

34. As part of the current application, DERS included forecast revenue requirements for each

of 2012, 2013, 2014, 2015 and 2016. DERS also included actual information for 2012, and it

referred to this information as the “2012 adjusted actuals.”33 DERS also included forecast year-

end estimates for 2013, which it labelled as “2013 Estimate.” DERS explained34 that for four cost

categories of the DRT, and three cost categories of the RRT, there were differences between the

2012 adjusted actuals included as part of the application and the 2012 actual amounts reported as

part of its Rule 005: Annual Reporting Requirements of Financial and Operational Results,

filing.35 For these cost categories, the 2012 adjusted actuals for the DRT were $1.5 million

greater than the 2012 amounts reported for the DRT in Rule 005.36 On the RRT side, the 2012

adjusted actuals for these cost categories were $0.4 million greater than the 2012 actuals reported

for the RRT in Rule 005.37

29

Decision 2012-343, paragraph 34. 30

Exhibit 0001.00.DEML-2406 of Proceeding 2406. 31

Proceeding 2406, Document description is as follows: AUC letter of disposition – Direct Energy Regulated

Services Application in Proceeding ID No. 2406 – March 18, 2013. 32

Exhibit 0001.00.DEML-2957, 2012-2016 DRT and RRT application, page 10. 33


Exhibit 0006.00.DEML-2957, 2012-2016 DRT and RRT application, Attachments 1-19, Attachment 11. More

information was provided in response to information request UCA-DERS-002 (Exhibit 0019.01.DEML-2957,

pages 2-4). 35

DERS’ Rule 005 submission relating to the results for 2012 was assigned to Application 1609547-1. 36

Exhibit 0006.00.DEML-2957, 2012-2016 DRT and RRT application, Attachments 1-19, Attachment 11 shows

a difference of $1.4 million. In the response to information request AUC-DERS-036 (Exhibit 0020.01.DEML-

2957, page 38), DERS indicated that there was an additional difference of $0.1 million. 37

Exhibit 0006.00.DEML-2957, 2012-2016 DRT and RRT application, attachments 1-19, Attachment 11.

http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Documents/Rule005.pdf


Decision 2957-D01-2015 (July 7, 2015) • 9

35. DERS added the following regarding its 2012 adjusted actuals:

For comparative purposes DERS considers the adjusted 2012 actuals appropriate as they

reflect the costs that were required to serve the regulated customer base throughout 2012.

DERS considers this issue of adjustments to the actuals to be confined only to the 2012

results and is of the view that the appropriate costs have been captured and are reflected

correctly in 2013 as well as years prior to 2012 as reported.38

36. In response to an information request from the Commission, DERS updated and

resubmitted all applicable schedules from Exhibit 0002.00.DEML-295739 and

Exhibit 0003.00.DEML-295740 by removing the 2013 information labelled as “2013 Estimate”

and replacing it with the 2013 actuals.

37. During the course of the hearing, DERS submitted the 2014 actual amounts for certain

schedules from Exhibit 0002.00.DEML-2957 and Exhibit 0003.00.DEML-2957.41

38. DERS indicated that the Commission effectively summarized the principle of prospective

ratemaking in Decision 2000-82,42 and DERS included quotes from page 15 of that decision as

part of its application.43

39. DERS stated that the Commission has also made it clear that available actuals should be

properly taken into account in the context of reducing initial forecast risk. DERS included a

quote from Decision 2006-00444 as part of its application.45

40. Referencing page five of Decision 2006-024,46 DERS stated that the use and

consideration of updated actual information is not a one-sided process targeted to reducing a

utility’s revenue requirement, and that the Commission has made clear that a utility is also able

to update its application and its forecast to reflect unforeseen increases in costs.

41. DERS submitted that it recognizes that the 2012 and 2013 actual results should not be

ignored and it has attempted to recognize the results in the updated 2012 and 2013 forecasts.

DERS indicated that it back cast the 2012 and 2013 revenue requirements and included an

updated forecast for the 2014 to 2016 timeframe. It stated that it has taken risk on the various

38

Exhibit 0006.00.DEML-2957, 2012-2016 DRT and RRT application, attachments 1-19, Attachment 11. 39

DRT supporting schedules. 40

RRT supporting schedules. 41

This information was submitted in Exhibit 2957-X0041.1, and consisted of the following schedules: 3.1.1 (DRT

Forecast Sites); 4.1 (DRT Capital); 5.1 (DRT Summary); 5.1.1 (DRT Customer Care Costs); 5.1.3 (DRT

Working Capital); 5.1.14 (DRT Return); 5.1.16 (DRT Vendor Selection Costs); 3.2.1 (RRT Forecast Sites);

4.2 (RRT Capital); 5.2 (RRT Summary); 5.2.1 (RRT Customer Care Costs); 5.2.3 (RRT Working Capital);

5.2.16 (RRT Vendor Selection Costs). 42

Decision 2000-82: Canadian Western Natural Gas Company Limited, Request to Withdraw the 1999 General

Rate Application, and Assessment of the Need for a 2000 General Rate Application, Application 990208,

December 21, 2000. 43

DERS included two quotes from page 15 of Decision 2000-82. The first quote was the first paragraph under the

“Board Findings” heading. The second quote was the last paragraph on page 15. 44

Decision 2006-004: ATCO Gas, 2005-2007 General Rate Application Phase I, Application 1400690-1,

January 27, 2006. 45

DERS included a quote from pages 3-4 of Decision 2006-004. The quote starts at the last paragraph on page 3

and finishes on page 4. 46

Decision 2006-024: ATCO Electric Ltd., 2005-2006 General Tariff Application, Application 1399997-1,

March 17, 2006.





10 • Decision 2957-D01-2015 (July 7, 2015)

elements of its revenue requirements and therefore it continues to be appropriate for the

Commission to approve DERS’ revenue requirements on a forecast basis.47

42. In response to an undertaking given to the Commission during the hearing, DERS

confirmed that it is requesting forecast costs for each of 2012, 2013, 2014, 2015 and 2016.48 In

argument, DERS submitted that it continues to adhere to the principles of prospective ratemaking

and strongly believes that the Commission should apply them in this case.49 To apply hindsight

and second guess DERS’ decisions after the fact, based on information that was not available to

DERS at the time the forecasts were made, would be both unfair and inappropriate. After-the-

fact ratemaking serves as a disincentive to utilities taking on risk in a prospective ratemaking

regime and it blunts the incentive to manage those risks.50

43. DERS added that the forecasts underlying its rates are reasonable based on the

information known at the time they were made, and continue to be reasonable today, resulting in

an overall accuracy of 96 per cent on its forecast revenue requirement for 2012 to 2014.51

Throughout the test period, DERS had accepted significant risks, some of which have been of

significant benefit to customers.52 These risks are as follows: site count risk, bad debt risk,

electricity and natural gas commodity price risk, unbillable revenue risk, penalty revenue risk,

average consumption per site risk, inflation risk, crude price risk and its impact on the Alberta

economy, corporate cost risk and transmission and distribution risk for both ATCO Electric Ltd.

and ATCO Gas.53

44. DERS argued that low gas prices are a current reality of the Alberta economy, but the full

impact of the prolonged, low crude prices has yet to be reflected in the Alberta economy. It

added that historically, poor economic performance results in higher bad debt, higher unbillable

revenue and higher collection costs, none of which have been included in the forecast for 2015

and 2016.54 DERS submitted that its acceptance of these significant risks on behalf of regulated

customers demonstrates that the use of DERS’ forecasts is both fair and reasonable.55

45. Noting that it has departed from the use of deferral accounts for a number of cost items

that have traditionally been granted deferral treatment, DERS submitted that its approach to

accepting risk is different from some of the other retailers in Alberta. This means that it should

not be treated the same as regulated retailers who may have a different approach to the level of

risk they are prepared to undertake.56

46. Referring to Decision 2014-30357 for EPCOR Energy Alberta GP Inc. (EEA), DERS

noted EEA’s submission that the level of risk compensation EEA would require in the absence of

a bad debt deferral account would be approximately $0.92 million in 2014 and $0.90 million in

47

Exhibit 0001.00.DEML-2957, 2012-2016 DRT and RRT application, pages 11-12. 48

Exhibit 2957-X0067, response to undertaking at Transcript, Volume 2, page 262. 49

Exhibit 2957-X0095, DERS public argument, paragraph 18. 50


Exhibit 2957-X0095, DERS public argument, paragraphs 12 and 17. 52






Decision 2014-303: EPCOR Energy Alberta GP Inc., 2014-2015 Non-energy Regulated Rate Tariffs,

Proceeding 2986, Application 1610188-1, November 4, 2014.



Decision 2957-D01-2015 (July 7, 2015) • 11

2015. DERS indicated that this amount is significantly larger than DERS’ three-year variance to

forecast of $0.016 million for bad debts for the three-year period of 2012-2014.58

47. Citing paragraph 173 of Decision 2014-303, in which the Commission denied EEA’s

request for the continuance of a deferral account for bad debt expenses, DERS stated that it is

clear from Decision 2014-303 that the Commission supports prospective ratemaking through the

use of forecasts, and accepts that there is a level of risk that RRT and DRT providers take on in

not relying on deferral accounts.59

48. It noted that it is the only regulated rate option (RRO) provider in Alberta that did not

open up its energy price setting plan (EPSP) in order to allow for the past recovery of uplift

charges. DERS indicated that it has not requested recovery of the $0.45 million actual additional

costs that it faced in 2014 due to the unexpected large increase in postage fees. It added that

these are clear examples of the risks that DERS has accepted under the prospective ratemaking

principles that normally apply to the forward test year approach, and which DERS believes

ultimately benefit its regulated customers.60

49. DERS submitted that the provision of actuals should not be used to simply reduce an

applicant’s revenue requirement, because there will be years when actuals are higher than

forecast. The actuals provide the Commission with an additional tool to validate the forecasts.

DERS reiterated that it has borne the risk on the various elements of its revenue requirements for

the first three years of the test period and as such it is appropriate for the Commission to approve

DERS’ revenue requirements on a prospective basis.61

50. On behalf of the UCA, Mr. Russ Bell submitted evidence regarding the use of actuals for

2012 and 2013. Mr. Bell stated that the 2012 and 2013 forecasts, which include actual

experience, demonstrate a pattern of material over forecasting. He submitted that, as such, the

Commission should use the 2012 and 2013 actual results as the approved forecasts for 2012 and

2013. Mr. Bell indicated that this is entirely consistent with the treatment used by AltaGas

Utilities Inc. (AUI) in its 2010-2012 general tariff application, when it incorporated 2010 actual

results.62

51. To counter the submissions of DERS regarding Decision 2000-82 and Decision 2006-

004, Mr. Bell indicated that in Decision 2009-151,63 the Commission directed that the cost rate

for a 2009 debt issue that occurred prior to the close of record be included in the 2009 forecast

costs.64 Mr. Bell also submitted that in Decision 2009-176,65 the Commission considered the

2008 actual costs for betterments when ruling on the 2008 forecast.66

58





Exhibit 0029.02.UCA-2957, UCA evidence, page 2. 63

Decision 2009-151: AltaLink Management Ltd. and TransAlta Corporation, 2009 and 2010 Transmission

Facility Owner Tariffs, Proceeding 102, Applications 1587092 and 1594573, October 2, 2009. 64

Mr. Bell quoted paragraph 632 of Decision 2009-151. 65

Decision 2009-176: AltaGas Utilities Inc., 2008-2009 General Rate Application Phase I, Proceeding 88,

Application 1579247-1, October 29, 2009. 66

Mr. Bell quoted paragraph 52 of Decision 2009-176.




12 • Decision 2957-D01-2015 (July 7, 2015)

52. Mr. Bell stated that in paragraph 12 of Decision 2012-091,67 the Commission

acknowledged that AUI had updated its 2010 forecast to actual results. Mr. Bell quoted the

following response to an information request that had been asked by the UCA during the

proceeding,68 that resulted in Decision 2012-091:

The use of 2010 Actual results in the Application is in keeping with the Commission’s

expectation the applicant provides the most current and reliable data available to it. In

doing so, the result was a reduction in AUI‟s applied-for revenue requirement for 2010.

Similar risks exist regardless of whether AUI does or does not incorporate actual results

in its application forecasts. The fact remains, for 2010, AUI does not have final rates,

does not have final debt costs and does not have approval of any of its expenditures,

operating or capital. It is arguable the presence of actuals has increased risk for 2010, as

timing no longer allows AUI to adjust for the outcome of this proceeding. AUI has

provided a detailed explanation for the timing of the Application in response to

UCA.AUI-1(j).69

53. Mr. Bell added that in Decision 2013-362,70 the Commission also addressed the use of

actual results.71 He added that similarly, in paragraphs 146 and 147 of Decision 2013-362, the

Commission directed the use of actual costs of long term debt. He indicated that the

circumstances in this current application are similar to the ones in the TransAlta 2011-2012

general tariff application (GTA).72

54. Mr. Bell stated that while generally related to the year prior to the test period, the

Commission has repeatedly preferred the best information available to assess forecasts. Citing

page 110 of Decision 2003-071,73 Mr. Bell submitted that in assessing the forecasting accuracy

of DERS, there is nothing better than the actual costs that correspond to the forecasts prepared by

DERS.74 Referencing page 5 of Decision 2006-004 and pages 5-6 of Decision 2006-024,

Mr. Bell indicated that the use of actual results for 2012 and 2013 is extremely relevant to the

assessment of the 2012 and 2013 forecast results, as well as the forecasts for 2014, 2015 and

2016.75

55. Mr. Bell cited page 18 of Decision 2003-100,76 and stated that in assessing the DERS

forecasts for 2012 and 2013, the evidence does not appear to support the large variances between

the actual results and the forecasts for 2012 and 2013.77 Citing paragraphs 17 and 18 of Decision

2009-087,78 Mr. Bell submitted that the onus is on DERS to show that its tariff is just and

67

Decision 2012-091: AltaGas Utilities Inc., 2010-2012 General Rate Application - Phase I, Proceeding 904,

Application 1606694-1, April 9, 2012. 68

Proceeding 904. 69

Proceeding 904, Exhibit 0050.01.AUI-904, response to UCA-AUI-1(l), page 7. 70

Decision 2013-362: TransAlta Corporation, as manager of the TransAlta Generation Partnership, 2011-2012

General Tariff Application, Proceeding 2437, Application 1609303-1, September 27, 2013. 71

Mr. Bell quoted paragraph 98 of Decision 2013-362. 72


Decision 2003-071: ATCO Electric Ltd., 2003-2004 General Tariff Application, Rate Case Deferrals

Application, 2001 Deferral Application, Applications 1275494-1, 1275539-1, 1275540-1, October 2, 2003. 74



Decision 2003-100: ATCO Pipelines, 2003/2004 General Rate Application – Phase I, Application 1292783-1,

December 2, 2003. 77


Decision 2009-087: ATCO Electric Ltd., 2009-2010 General Tariff Application - Phase I, Proceeding 86,

Application 1578371-1, July 2, 2009.







Decision 2957-D01-2015 (July 7, 2015) • 13

reasonable, and in light of the actual results for 2012 and 2013, the proposed forecast will result

in tariffs that are neither just nor reasonable.79

56. Mr. Bell presented information comparing the forecast numbers for 2012 and 2013 for

both the DRT and the RRT to the actual amounts for these years.80 He also adjusted the

comparison to eliminate the impact of differences in site counts, and it resulted in the 2012

forecast for the DRT being 8.3 per cent greater than actual, the 2012 forecast for the RRT being

6.1 per cent greater than actual, the 2013 forecast for the DRT being 3.7 per cent greater than

actual, and the 2013 forecast for the RRT being 4.7 per cent greater than actual. Mr. Bell

submitted that these are material differences, and would result in incremental earnings of

$3.2 million for the DRT in 2012, $0.7 million for the RRT in 2012, $1.4 million for the DRT in

2013 and $0.5 million for the RRT in 2013. Mr. Bell added that for the DRT, the incremental

earnings for 2012 represent 100 per cent of the 2012 actual return margin, and the incremental

earnings for 2013 represent 47 per cent of the 2013 actual return margin.81

57. In addition to the prior decisions referenced by Mr. Bell, which indicate a clear

preference for the Commission to rely on the most up-to-date information in setting rates, the

UCA referred to Decision 2014-13882 as an additional relevant decision. The UCA emphasized

the following sentences from Decision 2014-138:

… The Commission, however, has consistently stated that it will rely on the most up-to-

date information in making such determinations.83

… Providing the Board with the best available information at the time it must make its

decision, assists the Board in determining a revenue requirement for the utility that most

closely matches current expectations and conditions. Properly considered, this should

reduce the initial forecasting risk to the utility and reduce the possibility of overpayment

by ratepayers.84

Given that EEC’s 2012 to 2014 non-energy application relates to a test period, which for

the most part has already occurred, the Commission considers that, to the extent possible,

EEC’s 2012 test year non-energy revenue requirement in this application should be based

on actuals.85

58. The CCA supported the use of the actuals for 2012, 2013 and 2014 as proposed by

Mr. Bell, and it considered that this was the most accurate and best information available at the

time of the hearing relating to the costs of DERS for those three test years.86

59. Referring to Decision 2012-343, in which the Commission approved forecast amounts for

annual incentive plan (AIP) and SAS costs for each of 2012, 2013 and 2014,87 the CCA

recommended that the Commission update these findings. The CCA submitted that, in order to

79




Decision 2014-138: ENMAX Energy Corporation, 2012-2014 Regulated Rate Option Non-energy Tariff,

Proceeding 2069, Application 1608745-1, May 23, 2014. 83


Decision 2014-138, paragraph 48, quoted from page 6 of Decision 2006-024. 85


Exhibit 2957-X0094, CCA public argument, paragraph 46. 87

Decision 2012-343, paragraphs 78 and 92.



14 • Decision 2957-D01-2015 (July 7, 2015)

remain consistent with the use of actuals for 2012-2014, the approved AIP amounts should be 50

per cent of the actual AIP costs for each of the years 2012, 2013 and 2014. It further submitted

that the approved SAS costs for 2012, 2013 and 2014 should be the actuals for these years. For

the 2015 and 2016 forecasts for these costs, escalation should be applied to the 2014 actuals,

using the CCA’s recommended inflation rate.88

60. The CCA stated that it is “somewhat of an oxymoron” that knowledge of the actuals for

2012 and 2013 was incorporated into DERS’ forecasts for these years, but did not in fact result in

the actuals. If the revised forecasts are not the same as actuals, then some part of the knowledge

of actuals is missing from the forecasts, which does not make any sense.89

61. In reply to DERS’ submissions, the UCA indicated that the Alberta Court of Appeal

recently commented90 on the principle of retroactive ratemaking. Citing certain passages from

this Alberta Court of Appeal decision, the UCA stated that the critical element in determining

whether the regulator is engaging in retroactive ratemaking is whether the affected parties were

aware that the rates were subject to change. It added that since final rates have not yet been set

for 2012, 2013 or 2014, it is clear that all parties ought to have been aware that the forecasted

rates, as set out by DERS in its application, were subject to change. On this basis, any revisions

to the forecasts put forth by DERS cannot constitute retroactive ratemaking.91 The UCA

submitted that the Commission itself has recognized that prospectivity effectively starts from the

close of the proceeding, rather than at the time of the application.92

62. The UCA stated that the Alberta Court of Appeal has recognized that deferral accounts

are “created in response to uncertainty.”93 The UCA submitted that in this application, there is no

issue with uncertainty of costs, and in fact the converse is true, since actual financial data is

available for three of the five test years in question.

63. The UCA submitted that where unusual circumstances exist such that actual data is

available for three of the test years in question, continuing to rely on prospective forecasts is

inconsistent with the Commission’s mandate in setting just and reasonable rates, regardless of

whether the forecasts could be said to have been prudent at the time they were made.94

64. The UCA contended that DERS’ claim of having a 96 per cent accuracy rate on its

forecasted revenue requirements is misleading. The UCA indicated that the analysis presented by

DERS in support of the 96 per cent figure is a combined variance analysis for the DRT and the

RRT over the three-year period of 2012-2014. This allows significant over-forecasting in certain

test periods to be balanced out by under-forecasting in other periods. The UCA argued that this is

not representative of the underlying forecast variance within each cost component. The UCA

added that it is not appropriate to undertake a combined analysis for the DRT and the RRT, given

88

Exhibit 2957-X0101, CCA public reply argument, paragraph 18. 89


Exhibit 2957-X0095, UCA public reply argument, paragraph 10. The UCA referenced ATCO Gas and Pipelines

Ltd v Alberta Utilities Commission, 2014 ABCA 28 at paragraphs 54-57. 91

Exhibit 2957-X0102, UCA public reply argument, paragraphs 10-12. 92

Exhibit 2957-X0102, UCA public reply argument, paragraph 13. The UCA referenced page 16 of

Decision 2008-113: ATCO Gas, 2008-2009 General Rate Application Phase I, Proceeding 11,

Application 1553052-1, November 13, 2008. 93

Exhibit 2957-X0095, UCA public reply argument, paragraph 15. The UCA referenced EPCOR Generation Inc.

v Alberta (Energy & Utilities Board), 2003 ABCA 374 at paragraph 18. 94

Exhibit 2957-X0095, UCA public reply argument, paragraph 22.



Decision 2957-D01-2015 (July 7, 2015) • 15

that the costs associated with the DRT and the RRT are distinct and incurred on behalf of

different subsets of customers.95

Commission findings

65. In accordance with the principles of prospective-ratemaking, the Commission sets rates

on the basis of forecast test years. It is required to assess the forecasts provided in support of rate

applications. However, for the years for which the actual results are available, in this case those

years being 2012, 2013 and 2014, the Commission may approve the forecast revenue

requirements that DERS has submitted for each of these three years, or approve the actual results

for each of these years as the forecast revenue requirement.

66. The Commission has reviewed the decisions cited by the parties on this issue.

67. In Decision 2006-024, the Alberta Energy and Utilities Board (the board), the

predecessor of the Commission, set out the following principles regarding the use of actuals in

determining revenue requirement:

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. Providing the Board with the best available information at the time it must

make its decision, assists the Board in determining a revenue requirement for the utility

that most closely matches current expectations and conditions. Properly considered, this

should reduce the initial forecasting risk to the utility and reduce the possibility of

overpayment by ratepayers. This does not mean, however, that an applicant must wait

until the year prior to the first test year has ended before it can file an application.

Depending on the circumstances, an applicant may be required to provide updated actual

information whenever the processing of an application straddles the end of a fiscal year

and the time that the actual results become available prior to the close of the evidentiary

portion of the proceeding. Further, partial year results may also be required when an

application is processed over an extended period of time, provided the utility is offered

the opportunity to put such partial results in the proper context and to describe the

limitations applicable to partial actual information.96

68. In subsequent decisions, the Commission has consistently applied these principles.97

Recently, the Commission was presented with similar circumstances to those in this proceeding

when an RRO provider requested approval of non-energy revenue requirements for 2012, 2013

and 2014 and filed forecasts in support of its application, but actuals became available during the

latter stages of that proceeding.98 In the resulting decision, Decision 2014-138, the Commission

stated:

47. Because the Commission sets rates on the basis of forecast test years, it is

required to assess the forecasts provided in support of rate applications. The Commission,

however, has consistently stated that it will rely on the most up-to-date information in

making such determinations.

…

95

Exhibit 2957-X0095, UCA public reply argument, paragraphs 28-30. 96

Decision 2006-024, page 6. 97

See Decision 2014-138 and Decision 2000-82. 98

Decision 2014-138, paragraph 1.


16 • Decision 2957-D01-2015 (July 7, 2015)

49. Given that EEC’s 2012 to 2014 non-energy application relates to a test period,

which for the most part has already occurred, the Commission considers that, to the

extent possible, EEC’s 2012 test year non-energy revenue requirement in this application

should be based on actuals. Section 123 of the Electric Utilities Act allows the

Commission, when it is considering whether to approve a tariff that is to have effect prior

to its consideration of the tariff application, to take into account evidence relating to

revenues received and costs and expenses incurred by the applicant in the year in which

the application was made.99

69. The Commission sets rates on a prospective basis; however, situations of regulatory lag

arise, where approvals of revenue requirements for certain years of a test period are made after

those years have passed. In this proceeding, full year actuals for 2012, 2013 and 2014 are

available. In determining the revenue requirement for each of these years, and, with the

exception of the AIP, LTIS and SAS amounts, the Commission has considered these actual

results in assessing the applied-for forecast amounts.

70. Given that DERS’ 2012 to 2016 non-energy application relates to a test period, for which

the actual results for 2012 through 2014 are already known, the Commission considers that, to

the extent possible, DERS’ 2012-2014 non-energy revenue requirements in this application

should be based on actuals.

71. DERS argued that the forecast revenue requirements for 2012, 2013 and 2014 should be

approved as the forecast amounts, because the company assumed the forecast risk associated

with those forecasts. Forecast risk is the risk that there will be a difference between the forecast

amounts approved and the actual amounts incurred. In setting the approved revenue requirement

for the years 2012, 2013 and 2014 equal to the actual results for those years, with the exception

of the amounts for AIP, LTIS, and SAS, the Commission considers that it has eliminated any

forecast risk for DERS for these three years. The reasons for treating AIP, LTIS and SAS

amounts differently are set out below.

72. No parties have raised any issues with respect to the prudence of costs actually incurred

in 2012, 2013 and 2014 and no evidence has been provided that any of the actual costs incurred

for 2012, 2013 and 2014 were imprudent.

73. Accordingly, with the exception of the amounts for AIP, LTIS, and SAS, the

Commission finds that the revenue requirements for the years 2012, 2013 and 2014 should be

equal to the actual results for those years.

74. Regarding the AIP component of the “Labour by Department” cost category, and the

LTIS and the SAS components of the “Corporate Costs,” these components were approved in

Decision 2012-343 as part of the first application that DERS submitted for the 2012-2014 DRT

and RRT. The relevant approvals are included below.

78. The Commission approves the following AIP amounts for inclusion in the non-

energy revenue requirements for DERS for the years 2012 to 2014: DRT – $516,000 for

2012, $536,000 for 2013 and $558,000 in 2014; RRT – $335,000 for 2012, $349,000 for

2013 and $362,000 for 2014. The Commission directs DERS to reflect these figures in its

99

Decision 2014-138, paragraphs 47 and 49.


Decision 2957-D01-2015 (July 7, 2015) • 17

subsequent 2012 to 2014 non-energy revenue requirement application filed with the

Commission.100

84. For the above reasons, the Commission denies the inclusion of LTIS costs in the

non-energy revenue requirements of DERS for the years 2012 to 2014. The Commission

directs DERS to remove any LTIS costs in its subsequent 2012 to 2014 non-energy

revenue requirement application filed with the Commission.101

92. The following SAS incentive amounts are approved for inclusion in the non-

energy revenue requirements for DERS for the years 2012 to 2014: DRT – $176,400 for

2012, $180,300 for 2013 and $184,200 in 2014; RRT – $44,100 for 2012, $45,100 for

2013 and $46,100 for 2014. The Commission directs DERS to reflect these figures in its

subsequent 2012 to 2014 non-energy revenue requirement application filed with the

Commission.102

75. As discussed in Section 3 of this decision, the Commission has found that in preparing

the current application, DERS fully complied with the directions included in paragraphs 78 and

84 of Decision 2012-343. However, DERS has been directed to fully comply with the direction

in paragraph 92 of Decision 2012-343 as part of the compliance filing to this decision.

76. The UCA did not address whether these previously approved amounts for AIP, LTIS and

SAS should be included in the forecast revenue requirements for 2012, 2013 and 2014. The CCA

submitted that the Commission should update the findings with respect to the AIP and the SAS

amounts.

77. The Commission is not prepared to update the findings made in Decision 2012-343 with

respect to the AIP and the SAS amounts for 2012, 2013 and 2014. No persuasive reason was

advanced by the CCA for changing the amounts approved in Decision 2012-243 and the

Commission considers that it would not be fair to DERS to adjust the previously approved

amounts for AIP and SAS for 2012, 2013 and 2014.

78. As a result of the above findings, the Commission directs DERS, in the compliance

filing, to use the actual amounts for 2012, 2013 and 2014, with the exception of the amounts for

AIP, LTIS and SAS. DERS has been previously directed in this decision as to which amounts to

include for 2012, 2013 and 2014 for AIP, LTIS and SAS.

4.3 Overall forecast reductions and site counts for 2015 and 2016

79. Mr. Bell stated that had the forecast revenue requirements for 2012 and 2013 been

approved, the 2015 and 2016 forecasts would now be examined in light of the significant

forecast errors related to 2012 and 2013. He added that one must examine the 2015 and 2016

forecasts in light of the actual experience for 2012 and 2013.103 Mr. Bell presented such an

analysis in his evidence.

80. In Mr. Bell’s analysis, he normalized the difference related to site counts by calculating a

cost per site for the areas where there are material differences between the forecasts and actuals

in 2012 and 2013. Mr. Bell’s analysis shows the following average differences, on a cost per site

100




Exhibit 0029.02.UCA-2957, UCA evidence, page 10.


18 • Decision 2957-D01-2015 (July 7, 2015)

basis, between forecasts and actuals for 2012 and 2013 combined, for the following cost areas of

the DRT: 26.03 per cent for bad debt – energy; 14.98 per cent for working capital, 21.00 per cent

for bad debt – non-energy, 55.47 per cent for unbillable revenue, and 6.82 per cent for labour by

department.104 Further information regarding the analysis is included in the response to

information request DERS-UCA-001105 and the responses to the Commission’s information

requests on Mr. Bell’s evidence.106

81. Mr. Bell’s analysis shows the following average differences, on a cost per site basis,

between forecasts and actuals for 2012 and 2013 combined, for the following cost areas of the

RRT: 27.90 per cent for merchant fees and 55.38 per cent for unbillable revenue.107

82. Mr. Bell stated that there is clearly a pattern of over forecasting. He submitted that as

DERS had indicated that it incorporated knowledge of the 2012 actuals and the 2013 year to date

amounts into its forecast, this constant forecast error is of specific concern. Mr. Bell further

submitted that this casts doubt on the forecasts for 2014, 2015 and 2016, which do not have any

actual results incorporated into them. He added that in keeping with the Commission’s desire to

use the best information available, it is entirely appropriate to use the 2012 and 2013 forecasts

and actual results, and the resulting variances, as a test of the accuracy of the 2014, 2015 and

2016 forecasts.108

83. Mr. Bell applied the average differences he calculated on a cost per site basis for the

specific cost areas of the DRT and the RRT as described previously, to the forecast amounts for

these specific cost areas for 2014, 2015 and 2016, as the basis for his recommendation that the

Commission reduce the DRT forecast for 2014 by $3.383 million, 2015 by $3.354 million and

2016 by $3.368 million. He also recommended that the Commission reduce the RRT forecast for

2014 by $0.567 million, 2015 by $0.552 million and 2016 by $0.576 million.109

84. During the oral hearing. Mr. Bell advised that he had a revision to his evidence. Mr. Bell

stated:

As time has passed, certain things have changed. As an example, the 2014 actual results

were made available recently and my evidence talks about a 2014 forecast. So to be

consistent with my evidence, subject to any IRs or questions we might have on that

undertaking, I would suggest that the 2014 actual results be used instead of the forecast

which was consistent with my recommendations for 2012 and 2013. As well, there may

be some second order impacts as that information makes its way through into my

calculations of forecast error, and that I'll have to work through. But that also would be

an update subject to -- or based on the new information we have.110

85. Mr. Bell updated his initial analysis set out above to calculate the average differences

over 2012, 2013 and 2014. Mr. Bell’s revised analysis shows the following average differences,

on a cost per site basis, between forecasts and actuals for the years 2012, 2013 and 2014

104


Exhibit 0045.02.UCA-2957, DERS-UCA-001 to DERS-UCA-002, response to DERS-UCA-001. 106

Exhibit 0046.02.UCA-2957, AUC-UCA-001 to AUC-UCA-004; Exhibit 0046.03.UCA-2957;

Exhibit 0046.04.UCA-2957; Exhibit 0046.05.UCA-2957; Exhibit 0046.06.UCA-2957. 107




Transcript, Volume 5, page 754.


Decision 2957-D01-2015 (July 7, 2015) • 19

combined, for the following cost areas of the DRT: 4.47 per cent for bad debt – energy; 10.32

per cent for working capital, 1.21 per cent for bad debt – non-energy, 46.47 per cent for

unbillable revenue, and 1.75 per cent for labour by department.111

86. Mr. Bell’s revised analysis shows the following average differences, on a cost per site

basis, between forecasts and actuals for 2012, 2013 and 2014 combined, for the following cost

areas of the RRT: 13.19 per cent for merchant fees and 56.22 per cent for unbillable revenue.112

87. Mr. Bell applied the revised average differences he calculated on a cost per site basis for

the specific cost areas of the DRT and the RRT as described previously, to the forecast amounts

for these specific cost areas for 2015 and 2016. Mr. Bell, on behalf of the UCA, recommended

that the Commission reduce the DRT forecast for 2015 by $1.406 million and for 2016 by

$1.417 million, and reduce the RRT forecast for 2015 by $0.523 million and for 2016 by

$0.548 million.113

88. The UCA stated that the Commission’s preference for utilizing the most up-to-date

information also extends to assessing DERS’ forecast costs for 2015 and 2016. The CCA also

supported the reductions for 2015 and 2016 recommended by Mr. Bell, based on his revised

analysis.114

89. In response to Mr. Bell’s evidence about DERS’ forecast errors for the 2012 to 2014

period, DERS contended that Mr. Bell cherry-picked certain cost items, while disregarding

significant items which demonstrated that actual costs were higher than the forecast costs. In

support of its position that it accurately forecast its revenue requirement, DERS presented an

analysis of the entire non-energy revenue requirement cost categories for 2012, 2013 and 2014.115

90. DERS added that customer care costs and unbillable revenue are the two cost

components that contributed to the four per cent total forecast error over the 2012 to 2014 test

period. Customer care costs, which made up over 67 per cent of the revenue requirement from

2012 to 2014, were forecast with 98 per cent accuracy. Actual unbillable revenue was lower than

forecast over the 2012-2014 period primarily due to higher than expected success of the

relatively new and largely unproven recovery efforts.116

Commission findings

91. The Commission considers that a reasonable forecast does not obviate the use of a more

accurate forecast of site counts if information becomes available during the course of a

proceeding. To the extent that updated site count information becomes available, the

Commission considers that such information should be reflected in the forecast ultimately

approved by the Commission. The Commission considers that the best starting point for the

preparation of the 2015 and 2016 forecast sites is the actual number of sites at the end of 2014,

and therefore the Commission directs DERS to do so as part of the compliance filing.

111

Exhibit 2957-X0075, Undertaking of Russ Bell at Transcript, Volume 5, page 756, lines 18-20. 112





Exhibit 2957-X0095, DERS public argument, paragraphs 21-23.


20 • Decision 2957-D01-2015 (July 7, 2015)

92. Regarding the forecast revenue requirements for 2015 and 2016, the UCA and CCA

recommended that the forecast revenue requirements be reduced based on the updated analysis

prepared by Mr. Bell.117 The Commission has reviewed this analysis, and considers that it is not

an overall revenue requirement reduction proposed for the years 2015 and 2016, but instead it

relates to particular cost categories for 2015 and 2016, as set out in the following table.

Table 2. Summary of recommended reductions for 2015 and 2016 prepared by Mr. Russ Bell118

Cost category 2015 reduction

($000s) 2016 reduction

($000s)

DRT

Bad debt – energy 164.72 164.02

Working capital 172.61 193.74

Bad debt – non-energy 45.76 45.57

Unbillable revenue 967.46 956.15

Labour by department 55.64 57.17

Total DRT 1,406.19 1,416.65

RRT

Merchant fees 33.98 33.82

Unbillable revenue 489.04 514.35

Total RRT 523.02 548.17

93. The Commission considers that its understanding is confirmed by the following wording

included in the updated analysis of Mr. Bell.

As such, Mr. Bell recommends reductions to the DRT forecast of $1.406 million in 2015

and $1.417 million in 2016 related to the accounts identified in the table.119

94. Though Mr. Bell did not specify that the recommended reductions to the RRT are related

to the accounts identified in the table, the Commission considers that the same reasoning applies.

95. The Commission will consider each of Mr. Bell’s recommendations listed above in areas

of this decision dealing with the relevant cost categories.

4.4 Customer care and billing costs

96. In the original application, DERS requested interim approval for the 2015 and 2016

CC&B costs based on the ATCO I-Tek Business Services Ltd. (ATCO I-Tek) arrangement,

adjusted for inflation. DERS submitted that it would update the 2015 and 2016 CC&B costs and

any related secondary effects in a subsequent application once they had been finalized.120

117

As included in Exhibit 2957-X0075, Undertaking of Russ Bell at Transcript, Volume 5, page 756, lines 18-20. 118


Exhibit 2957-X0075, Undertaking of Russ Bell at Transcript, Volume 5, page 756, lines 18-20, page 2. 120

Exhibit 0001.00.DEML-2957, DRT and RRT application 2012 to 2016, page 16.


Decision 2957-D01-2015 (July 7, 2015) • 21

97. In the amended application, DERS submitted that starting in 2015, CC&B costs would

be incurred through new arrangements with HCL America Inc. and HCL Axon Technologies

Inc. (collectively referred to as HCL), and DERS’ American affiliate, Direct Energy Limited

Partnership (DELP). DERS added that it had also outsourced bill printing and remittance

services to Symcor Inc. (Symcor) and RR Donnelley & Sons Company (RR Donnelley),

respectively.121

98. The effect of the new CC&B arrangement on the DRT and RRT revenue requirements

are summarized in Table 3 below.122,123 DERS is seeking recovery of these costs on a final basis.

Table 3. Customer care and billing costs

Default rate tariff Regulated rate tariff

2015 2016 2015 2016

Original application forecast (millions) $35.0 $33.9 $7.2 $6.7

Amended application forecast (millions) $41.1 $40.7 $8.4 $8.1

Percentage increase 17.5% 20.1% 16.7% 20.9%

Background

99. DERS submitted that it takes its obligation to serve regulated electric and gas customers

seriously. Even though the regulated customer base is declining, DERS expects to bear the

obligation to serve these customers indefinitely. DERS referenced the Government’s rejection of

the recommendations made by the Retail Market Review Committee as support for its

expectation.124

100. Since its entry into the Alberta market in 2004, DERS has contracted with ATCO I-Tek

for CC&B services. DERS initially contracted with ATCO I-Tek for a 10-year period (i.e., 2004

to 2014) under a master services agreement (ATCO MSA). No renewal terms were defined in the

ATCO MSA, which expired on December 31, 2014.125 Prior to the expiry of the ATCO MSA,

DERS, with the assistance of Five Point Partners LLC (Five Point), completed a request for

proposal (RFP) process to assess its CC&B service requirements and options for providing

CC&B services after 2014.126

Request for proposal process

101. DERS and Five Point identified and ranked DERS’ CC&B business processes and

information technology (IT) requirements on a scale from “critical” to “not required,” arriving at

2,527 discrete requirements, which formed the basis of the supplier solicitation process. Twenty-

two organizations, which included an internal business unit of a DERS affiliate, received a

request for information in regard to their potential ability to provide one or both of the business

121

Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application, page 5. 122





Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application, page 16.


22 • Decision 2957-D01-2015 (July 7, 2015)

process outsourcing (BPO) and/or customer information system (CIS) requirements. Eleven of

these organizations were considered suitable and received an RFP.127

102. Eight proposals were received in response to the RFP. The five proposals that offered

both BPO and CIS were short-listed for further analysis. Four suppliers advanced to Phase 2 of

the RFP process while the internal supplier did not.128,129 DERS elaborated in the hearing why it

decided to eliminate BPO-only solutions.

A. MR. PEREKOPPI: Just to add to that, the RFP process is a learning process for all

of the parties involved, including Direct Energy. What we saw – when we went into the

RFP process we purposely built a document that was very open to enable a full selection

of -- or a full potential for a breadth of suppliers to respond: IT-only firms, BPO-only

firms, integrated solutions.

What we saw, as we went through the first phase of the evaluation, was that we did not

believe that we would have the capability to co-ordinate the complexities between a

BPO-only firm and an IT-only firm. And that's why you see as we move forward to the

second phase that we really only had integrated firms at that point in time. Because

through the RFP process we came to understand that we really needed that level of

support. So they could not have actually really succeeded in the second phase.130

103. Following the review of the four short-listed suppliers, Five Point recommended that

DERS engage in further discussions with HCL to finalize the service agreement requirements.

Five Point assisted in these discussions until negotiations with HCL concluded.

104. Although HCL would provide the BPO, HCL “made it clear that they weren’t interested

in long-term ownership.”131 DERS decided that in order to facilitate the flexibility necessary to

switch BPO providers in a short time frame if necessary, a Direct Energy entity needed to own

the CIS and call center infrastructure. DERS clarified the circumstances that led to DELP

owning the CIS and call center infrastructure (CIS infrastructure) during the hearing.

A. MR. NEWCOMBE: I'm not so sure either, Mr. McCreary, that DELP was

necessarily selected, per se, as opposed to it ended up being owned by DELP as a result

of all of the decisions that were taken along the way. And a lot of the rationale, as you

say, is described on page 19.

We understood very early in the process that component costs would be more expensive

if they were delivered to Canada, that the construction costs would be more expensive if

it was done in Canada, because most of the HCL expertise required to build and develop

the system was resident in the US, and specifically in Houston. So our construction costs

would have been lower.

There were, as I understand it, certain assets that ultimately would be resident in the US

irrespective, such as some data centres and disaster recovery centres, so we were going to

run into tax issues if a Canadian entity, being Direct Energy Marketing Limited (DEML),

owned assets in the US.

127

Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application, pages 17-18. 128

Exhibit 0006.01.DEML-2957, Five Point Supplier Evaluation and Selection Report, page 12. 129

Transcript, Volume 2, page 337. 130

Transcript, Volume 2, pages 342-343. 131



Decision 2957-D01-2015 (July 7, 2015) • 23

And for me personally, there was the overarching concern that if the CIS system was

owned by DEML, and DEML and DERS being one in the same -- DERS is simply a

business unit or a function within DEML -- that that would lead to a rate base recovery,

and I certainly was not comfortable having the cost of a new CIS system put on to a

declining regulated customer base. So I was pushing for that not to happen. I didn't want

to see that decline in the customer base lead to ever-increasing unit costs for the regulated

customers in Alberta.

So there was a confluence of commercial decisions and regulatory considerations which

led us to the decision that the assets should be housed in the US. I don't believe that any

one person stuck their hand up and said, "It will be in DELP."

Once the decision was made that the best for the customers was to house the asset in the

US, I think the appropriate entity to own it just became DELP.132

Overview of new arrangement

105. DERS, through DEML, entered into a five-year agreement with HCL and a 10-year

agreement with DELP. At a high level, DELP provides the capital for the infrastructure required

to provide the CC&B functions, and HCL provides the labour and skill to perform and manage

those functions.133 Specifically, the responsibilities and relationships of each party (i.e., DEML,

DELP, and HCL) are governed by the following contractual agreements:

1. MSA between DELP and HCL (DELP-HCL MSA);

2. Statement of work E between DELP and HCL (SOW E);

3. MSA between DEML and DELP (DEML-DELP MSA) along with SOW Part 1 and

SOW Part 2;

4. SOW D and F between DEML and HCL (SOW D&F); and,

5. agreements with Symcor and RR Donnelley for bill printing and remittance services.

106. The DELP-HCL MSA allows SOWs to be entered into between affiliates of HCL and

DELP. DEML and HCL have entered into two SOWs, namely SOW D and SOW F. Under SOW

D, titled “BPO Run,” HCL agreed to operate the CC&B business processes that will be provided

to DEML. Under SOW F, titled “Application Run,” HCL agreed to operate the software

applications required to perform the CC&B processes. In both cases, HCL’s services are in

consideration of certain fees to be paid to it by DEML.

107. Under the DEML-DELP MSA, DELP agreed to build, or acquire, the necessary IT

hardware, software, call centre infrastructure and CC&B business processes, as well as maintain

these assets. The DEML-DELP MSA also outlines DEML’s right to access and use these

systems for a 10 year period. In accordance with this MSA, DELP will also be responsible for

any cost overruns of the system build. DELP’s acquisitions and services are in consideration of

certain fees to be paid to it by DEML.134

108. DERS stated that, with the exception of pass-through charges, customers will pay a fixed

FMV amount for all services regardless of the actual costs incurred by DELP or HCL.

Specifically, in accordance with the DEML-DELP MSA, DEML will pay DELP the residual

between FMV and the cost of the combined HCL and third party contracts (i.e., Symcor and RR

132



Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application, pages 21-27.


24 • Decision 2957-D01-2015 (July 7, 2015)

Donnelly).135 Items such as postage and long distance will remain as pass-through charges, as

they have been under the arrangements in the ATCO MSA.136 DERS elaborated on this

arrangement during the hearing.

Q. MR. MCCREARY: All right. Perhaps we'll save that and talk to people on Panel 4

about that. Can you tell me -- and you may have to also move this to the Panel 4

confidential module, but can you tell me whether or not DEML has a fair market value

contract with DELP and HCL? If you can't answer that now we'll come back to it.

A. MR. NEWCOMBE: No, I can answer that now, sir. So we have a -- DEML has a

contract with HCL for the provision of the BPO-run services. And that's the call centre

and other stuff associated with that. That contract is expressed in US dollars. So it's not

an FMV-type contract.

The contract that DEML has with DELP is -- I'll call it a residual fair market value

contract. So it is priced to provide to DELP a payment of the fair market value, as

determined by the benchmark; less what we pay HCL, in US dollars; less what we pay

for our pass-through services, our postage costs, our printing costs, mailing costs, some

lockbox costs, and some remittance costs. So we have contracts with a few other sort of

ancillary vendors to do some of those things.

So the payment to DELP is expressed -- from DEML to DELP is expressed in Canadian

dollars and it's set at FMV minus payments to HCL, minus payments to these other third-

party vendors.137

109. Table 4 illustrates the arrangement described above with a numerical example.

Specifically, excluding other pass-through charges, customers will pay $4.66 per site per month

for CC&B services. This amount consists of a charge of $1.20 paid to HCL, as well as a $0.13

charge paid to Symcor and RR Donnelley for print and remittance services. In this example,

DELP will receive $3.33, which is the difference between the estimated FMV and the charges

paid to the other vendors; however, the amount to DELP may vary depending on the exchange

rate between the Canadian and American dollar and the other benchmarks that affect the amounts

paid to HCL, Symcor, and RR Donnelley.138

Table 4. Customer care and billing costs on a per site basis

2015

forecast 2016

forecast

Monthly ($/site) Annual ($/site) Monthly ($/site) Annual ($/site)

DELP 3.33 39.96 3.52 42.24

HCL 1.20 14.45 1.12 13.44

Print and remittance 0.13 1.51 0.13 1.56

Total costs including CIS 4.66 55.92 4.77 57.24

Source: Adapted from Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application, page 33, Table 7-A and Exhibit 0111.01.DEML-2957, DERS cover letter.

135




Exhibit 2957-X0069, Undertaking 38.


Decision 2957-D01-2015 (July 7, 2015) • 25

Proposed benefits of the new arrangement

110. In its application, DERS submitted that the new arrangements are less expensive for

regulated customers than if DERS were looking to recover the cost of the new system through

the traditional method of amortizing a regulated customer-owned CIS system over a 10-year

period. Specifically, DERS provided a pro forma analysis that showed that customers saved

roughly $7.45 per site per year under the new arrangements compared to the traditional rate base

cost of service model.139,140

111. DERS elaborated in its application that customers also benefit under the new arrangement

in the following ways:

(1) FMV is maintained for customers over the lifetime of the agreements due to

benchmarking provisions in the DEML-DELP MSA which take into account all

services including those provided by HCL and the third parties.

(2) DELP takes on a significant portion of customer attrition risk. Specifically, higher

CC&B costs will not result for individual customers as long as the total number of

competitive and regulated customers remain above 950,000.

(3) All transition costs until December 31, 2014 and any potential transition costs past

January 1, 2015 are to be covered by DELP. Furthermore, the documentation and

development of all processes and training materials, along with the call centre build-

outs (including facility costs, hiring, and training), as well as the long term

maintenance and support of all the hardware and software required to support

customers has been included in the per site fee attributable to DELP.

(4) The SAP platform is not proprietary to the vendor and is well known and utilized

across the industry, so that other service providers could readily step in if necessary.

(5) HCL services multiple clients throughout the world and can draw on this experience

in providing expertise to DERS and its customers.

(6) All DELP proprietary materials, derivative works, and intellectual property belong to

DELP, and competitive development intellectual property rights will be determined

through the change control process. DELP will also own all assets and licenses to all

products and intellectual property associated therewith.

(7) New and improved functionality to serve customers better, including on-line account

management and enhanced interactive voice response and self-service capabilities.

(8) Costs for rule changes and unforeseen market changes could potentially be reduced

due to the enhancement pool of hours, which covers 10,000 hours per year after

year 1, as detailed in SOW F.

112. During the hearing, DERS elaborated on its submission respecting the 950,000 customer

threshold.

139

Exhibit 0074.08.DEML-2957, Attachment 24, traditional cost of capital vs amended costs. 140



26 • Decision 2957-D01-2015 (July 7, 2015)

A. MR. NEWCOMBE: And so anything above that, any change is to the account of

DELP. So if we were to go from a million and 50,000 customers down to 951,000

customers, DELP would see the erosion of 100,000 -- yeah, 100,000 sites, or the revenue

from 100,000 sites …

… If it's below that, we will be pay as if we have 950,000.141

113. In further questioning from the panel Chair, DERS testified that it had not put much

thought into how it would bill customers if the total number of customers fell below 950,000

over the 10-year period.

Q. MR. KOLESAR: But what I'm interested in is how does that then get divvied up

-- that additional cost get divvied up as between regulated service customers and

competitive service if that were to come to pass?

A. MR. NEWCOMBE: There will probably be a couple of ways that someone could

look at that. If the trends continue as they are today, one could say: Well, the competitive

customers base has been growing steadily. The regulated base is the one that is shrinking,

so maybe regulated customers should bear it all.

Another way of looking at it would be when we do cross that threshold to look at the

relative ratio at that time of regulated versus competitive customers, and maybe it's 60/40

or 50/50, something like that.

Another way of looking at is: Well, that was a contractual matter between DEML and

DELP, and that should be to the account of the DEML shareholder, and the regulated

customers should just continue to just pay the per-site charges.

As I said, we haven't given it a lot of thought. We're hoping to stay above that threshold

throughout the ten-year agreement. But I think there's a couple of bookends and there's

probably some different things in between that we can look at that time.

Q. So there isn't anything specified as of today with respect to how that additional cost

might be shared?

A. MR. NEWCOMBE: No, there isn't.142

Fair market value

114. Over the course of this proceeding, DERS submitted two FMV reports. The first report

was conducted by Desert Sky Group, LLC (Desert Sky) and was used as the basis for the CC&B

costs applied-for in the amended application.143 The second report was conducted by First

Quartile Consulting, LLC (First Quartile).144 DERS submitted that it felt a second independent

evaluation of the FMV from a different expert, using a different methodology, was required

given the concerns brought up in the ATCO Evergreen proceeding.145,146

141



Exhibit 0074.04.DEML-2957, Desert Sky benchmark report. 144

Exhibit 0127.03.DEML-2957, DERS supplemental evidence, First Quartile benchmark study. 145

Exhibit 0134.02.DEML-2957, AUC-DERS-067(b).


Decision 2957-D01-2015 (July 7, 2015) • 27

115. The Desert Sky report found that the FMV for all services received under the new

arrangements, except the flow-through elements, is $4.63 per month per site for 2015 and $4.74

per month per site for 2016.147 DERS later revised the CIS component that went into its FMV

from $1.02 to $1.05 per site. Although DERS submitted that it would seek an adjustment in final

argument, this revision was not brought up in final argument.148

116. The First Quartile report found that the FMV for all services received under the new

arrangements, excepting the flow-through elements, is $4.91 per month per site for 2015 and

$5.0 per month per site for 2016.149 A comparison of the two reports is included in Table 5

below.

Table 5. Comparison of CC&B FMV buildup

Desert Sky First Quartile

2015 2016 2015 2016

Contact centre $1.200 $1.230 $1.182 $1.204

Billing 1.680 1.710 1.365 1.390

Print 0.130 0.130

Remittance 0.140 0.140

Market interaction 0.260 0.270

Bundled hours 0.110 0.150

Streetlights 0.004 0.004

Credit 1.018 1.038

CIS 1.020 1.020 0.748 0.763

CIS adjustment 0.030 0.030

CIS maintenance 0.090 0.090 0.598 0.609

Monthly total $4.664 $4.774 $4.912 $5.003

Source: Adapted from Exhibit 0074.01.DEML-2957, DERS amended DRT and RRT application, page 31, Table 6-A; Exhibit 0127.03.DEML-2957, DERS supplemental evidence, First Quartile benchmark study, pages 4-5; and Exhibit 0111.01.DEML-2957, DERS cover letter.

117. DERS clarified during the hearing that it would look to update the FMV amounts in

2016, 2019, and 2022 for rate-making purposes.

A. MR. NEWCOMBE: Yes. I believe that's contained in Exhibit 97.07. Exhibit 2.6,

Section 4 of that exhibit. Yes. So there's to be a benchmark in 2016 for prices effective

January 1, 2017; another in 2019 for prices effective January 1, 2020; and a benchmark in

2022 for prices to be effective January 1, 2023.150

Views of the parties

118. Both DERS and the UCA filed evidence on the public record as well as the confidential

record. However, their argument and reply argument were filed on the public record. Redactions

were made where each party addressed material exclusive to the confidential record. This portion

of the decision does not reference data protected under confidentiality. This does not, however,

146

ATCO Utilities (ATCO Gas, ATCO Pipelines and ATCO Electric Ltd.), Proceeding 240,

Application 1605338-1. 147


Exhibit 0111.01.DEML-2957, DERS cover letter. 149

Exhibit 0127.03.DEML-2957, DERS supplemental evidence, First Quartile benchmark study, pages 4-5. 150

Transcript, Volume 3, pages 547.


28 • Decision 2957-D01-2015 (July 7, 2015)

mean that the confidential material was not considered. In this manner, this decision is more

transparent and DERS’ future rate proceedings may benefit from the arguments considered in

this proceeding.

Failure to assess alternative options

119. The UCA argued that DERS failed to support its decision to fully outsource CC&B

services. Specifically, the UCA submitted that there is no evidence that DERS attempted to

renegotiate with ATCO I-Tek151 and that the only evidence on the record supporting a decision to

go to a fully outsourced CC&B solution was prepared after the fact.152 In contrast, the UCA

submitted that, in the ATCO Evergreen proceeding, the Commission found that the ATCO

Utilities insufficiently addressed alternatives for providing CC&B services despite filing two

businesses cases, as well as a FMV study.153,154

120. DERS responded that a business case was not required given that DERS has always

outsourced its CC&B services to ATCO I-Tek; however, due to the system upgrades required,

ATCO I-Tek could not maintain current service levels or costs. DERS added that in Decision

2014-347, the Commission found that utilities only need to compare the costs of outsourcing

versus self-provision for services that the utility otherwise provides for itself.155,156

Lack of transparency

121. The UCA argued that despite being granted confidentiality, DERS refused to provide the

results of individual RFP bids and without the individual responses, the UCA was not able to

assess the reasonableness of the RFP process. The UCA added that Five Point’s involvement in

the RFP process did not increase transparency.157

122. DERS responded that confidentiality was necessary, given that disclosure of the

individual respondents’ commercial information could expose the respondents to undue

competitive harm and financial loss. DERS added that the Five Point report provided all the

information required to evaluate the RFP process and the ultimate selection of HCL as the

CC&B service provider.158 DERS also noted that the Five Point representative, Mr. Richard

Charles, was made available for questioning during the hearing.159

Pricing had no weight in request for proposal

123. The UCA submitted that pricing had no weight in the RFP evaluation and that there is no

evidence that ranks the pricing of the individual proposals. In support of its submission, the UCA

referenced testimony given by the Five Point representative, Mr. Charles, that price was only

151

Exhibit 2957-X0097, UCA public argument, page 17. 152



Decision 2014-169 (Errata), ATCO Utilities (ATCO Gas, ATCO Pipelines and ATCO Electric Ltd.), 2010

Evergreen Proceeding for Provision of Information Technology and Customer Care and Billing Services Post

2009 (2010 Evergreen Application), Proceeding 240, Application 1605338-1, paragraph 227. 155

Exhibit 2957-X0103, DERS public reply argument, pages 19-21. 156

Decision 2014-347, ENMAX Power Corporate, 2014 Phase I Distribution Tariff Application, 2014-2015

Transmission General Tariff Application, Proceeding 2739, Application 1609784-1, December 16, 2014,

paragraph 126. 157


Exhibit 2957-X0103, DERS public reply argument, page 21. 159

Exhibit 2957-X0103, DERS public reply argument, page 14.



Decision 2957-D01-2015 (July 7, 2015) • 29

used in Phase I of the RFP process as a “means for further dialogue and explanation” in the case

of outliers, and “was not scored in Phase II.”160

124. DERS responded that it would be irresponsible to base the selection of its CC&B service

provider solely on the lowest price offered. DERS added that the UCA had confused an RFP

with a tender. DERS elaborated that tenders are driven by prices whereas RFPs are not, due to

their open nature.161

Customer care and billing arrangement restructured after-the-fact

125. The UCA submitted that the RFP allowed respondents to bid on the entire CC&B

solution or individual pieces (i.e., CIS or BPO services); however, given DERS’ preference for a

single service provider, only proposals offering a complete solution advanced into Phase 2 of the

RFP process. The UCA argued that DERS ultimately selected a solution that relied on two

service providers – DELP for the CIS and HCL for the BPO services. The UCA argued that the

RFP proposals that were eliminated in Phase 1 for not offering a complete solution might have

been more attractive considering that DELP would be the CIS provider.162

126. DERS responded that it does not matter who owns the CIS assets given that HCL retains

full responsibility and liability for operating the CIS and providing the BPO services. DELP only

mitigates the risk for DERS and consumers in Alberta.163

Benchmarking

127. The UCA also took issue with the use of benchmarks to set prices. The UCA argued that

benchmarking is imprecise and that results can change significantly, based on the discretion of

the expert with respect to sample selection and data normalization. The UCA added that

benchmarking studies are used to estimate what to expect in negotiations. FMV is what arises

from actual negotiations between arms-length parties. Arms-length negotiations did not take

place between DERS and DELP. The UCA submitted that DERS and DELP did not even have

separate legal counsel when they negotiated the DEML-DELP MSA.164

128. DERS submitted that despite the UCA’s criticism, the UCA did not provide contrary

statistical evidence to challenge the Desert Sky or First Quartile reports. DERS added that it

purposely kept the DEML-DELP MSA similar to the DELP-HCL MSA because the DELP-HCL

MSA was negotiated between two arms-length-parties. Therefore, the effects of these

negotiations would be replicated into the DEML-DELP MSA. DERS elaborated that the risks

and benefits that HCL accepted in its MSA with DELP would be replicated in the DEML MSA

with DELP.165

129. With respect to the UCA’s criticism that benchmarking studies lack transparency, DERS

submitted that it commissioned two independent benchmarking reports that arrived at an estimate

of FMV that were within six per cent of each other. DERS added that both experts were made

available for cross-examination.

160



Exhibit 2957-X0097, UCA public argument, pages 30-31. 163



Exhibit 2957-X0103, DERS public reply argument, pages 28-39.


30 • Decision 2957-D01-2015 (July 7, 2015)

No customer input

130. The UCA argued there is no evidence that ATCO I-Tek provided unsatisfactory service.

Specifically, the UCA submitted that in the Five Point report, the current CIS under ATCO I-Tek

scored 71 per cent with respect to total fit compared to 90 per cent for the majority of the other

systems ranked. The UCA added there is no evidence that regulated customers were willing to

pay millions to gain 19 per cent more functionality. The UCA argued that the new CIS and

additional functionalities are aimed at the competitive business.166

131. DERS submitted that the rate increase with respect to CC&B services requested between

2014 and 2015 for DERS’ largest customer segment, regulated residential gas customers, equates

to approximately $0.70 per month per customer. In DERS’ view, the increase in cost is modest

when compared to the overall upgrade in service, reliability and platform.167

132. DERS added in reply argument that the increase in CC&B costs is due to the

implementation of a new CIS system, which increases cost, and is not due solely to the added

functionalities. DERS submitted that several other North American utilities, such as Enbridge,

have implemented new CISs that resulted in similar cost increases.168

133. DERS argued that the UCA’s speculation that the new CIS is designed for the

competitive business is untrue, and completely contrary to DERS’ testimony and evidence.169

Inter-affiliate relationship between DELP and DEML

134. The UCA submitted that there is no dividing line between DELP and DERS and that

DERS’ interests, and those of regulated customers, are being subverted to those of DELP. The

UCA contended that DERS’ regulated customers are being asked to pay for a new CIS that will

eventually be rolled out to DELP’s competitive businesses elsewhere. The UCA submitted that it

still does not have an answer as to what DELP is getting out of this arrangement.170

135. DERS responded that in negotiations with HCL, it became clear that a Direct Energy

entity needed to own the assets. Specifically, since the assets were to be housed in the United

States, it made sense for that entity to be DELP. With respect to “what’s in it for DELP,” DERS

submitted that it has an obligation to serve regulated customers in the most effective and reliable

manner.171

Lower of cost or fair market value

136. The UCA submitted that in Decision 2002-069,172 the board provided guidance on the

assessment of the cost of goods and services provided by an unregulated affiliate to a regulated

utility. Specifically, the UCA referenced the board’s criteria that the affiliate be the least cost

alternative, and that the purchase of the goods and services be the lesser of FMV or the cost for

the utility to provide similar goods or services internally. The UCA submitted that DERS failed

166


Exhibit 2957-X0095, DERS public argument, page 29. 168





Decision 2002-069: ATCO Group, Affiliate Transactions and Code of Conduct Proceeding Part A: Asset

Transfer, Outsourcing Arrangements, and GRA Issues, Application 1237673-1, July 26, 2002.



Decision 2957-D01-2015 (July 7, 2015) • 31

to demonstrate that the arrangement with DELP was the least cost alternative or that it is a lowest

cost option than if DERS self-supplied.173

137. DERS responded that the Commission recently rejected the same UCA argument in

Decision 2014-347.174 Specifically, DERS submitted that utilities only need to compare the costs

of outsourcing to providing services internally for services that the utility would otherwise

provide for itself.175

UCA recommendation with respect to customer care and billing costs

138. In its argument, the UCA recommended three alternatives for pricing 2015 and 2016

CC&B costs. First, the UCA proposed that the Commission allow DERS to charge only the

benchmark cost for the lowest comparator in the First Quartile report (i.e., $41.85 per site),

escalated by inflation. Second, the UCA proposed that the Commission allow DERS to recover

an amount that does not exceed the value for the lowest confidence interval for the First Quartile

benchmarking exercise. The UCA submitted that these recommendations are based on the logic

that the obligations of utility management are to provide services at the lowest costs. Third, the

UCA proposed that the Commission use the five-year average (i.e., 2010-2014) ATCO I-Tek

rates adjusted for inflation in 2015 and 2016. The UCA added that a five-year average is fair

given that 2014 ATCO I-Tek rates are over inflated due to transition costs.176

139. The UCA submitted that in the absence of sufficient evidence to properly apply the test

for inter-affiliate transactions, its recommendations constitute the most reasonable determination

of FMV based on the evidence on the record of this proceeding. The UCA added that although

these recommendations represent a significant reduction to the costs requested by DERS, they

are warranted given DERS’ failure to adequately canvas the available options for the provision

of CC&B services, making it impossible to assess whether the new CC&B arrangements result in

the lowest cost alternative for customers, consistent with a reasonable level of service.

140. DERS argued that the UCA proposed a number of options for the pricing of CC&B

services but did not submit any independent evidence to support these proposals. DERS argued

that the UCA’s recommendations are entirely arbitrary and without any evidentiary support.177

Commission findings

141. With respect to the UCA’s concern that DERS did not adequately assess alternatives

other than fully outsourcing CC&B services, the Commission observes that unlike in the ATCO

Evergreen proceeding, a comprehensive RFP process was conducted. Therefore, the Commission

disagrees with the UCA that alternative options were not adequately assessed. The Commission

acknowledges that the RFP allowed DERS to consider many different alternatives available in

the competitive market at the time.

A. MR. PEREKOPPI: Just to add to that, the RFP process is a learning process for all

of the parties involved, including Direct Energy. What we saw – when we went into the

RFP process we purposely built a document that was very open to enable a full selection

173


Decision 2014-347: ENMAX Power Corporation, 2014 Phase I Distribution Tariff Application, 2014-2015

Transmission General Tariff Application, Proceeding 2739, Application 1609784-1, December 16, 2014. 175






32 • Decision 2957-D01-2015 (July 7, 2015)

of -- or a full potential for a breadth of suppliers to respond: IT-only firms, BPO-only

firms, integrated solutions.

What we saw, as we went through the first phase of the evaluation, was that we did not

believe that we would have the capability to co-ordinate the complexities between a

BPO-only firm and an IT-only firm. And that's why you see as we move forward to the

second phase that we really only had integrated firms at that point in time. Because

through the RFP process we came to understand that we really needed that level of

support. So they could not have actually really succeeded in the second phase.178

142. Further, the Commission recognizes that the ATCO MSA did not include an extension

clause. The Commission cannot, therefore, assume that DERS could have continued utilizing the

services of ATCO I-Tek on the same terms and at the same prices. Given that an RFP was

conducted, in which ATCO I-Tek participated, the Commission finds that it is not pertinent that

DERS did not attempt to renegotiate with ATCO I-Tek.

143. The Commission acknowledges the UCA’s reference to the inter-affiliate test set out in

Decision 2002-069 and specifically, criterion three of the test that asks “was the purchase of

goods or services by the utility at the lesser of FMV, or the cost it would take for the utility to

provide similar goods or services itself?”179 The Commission, however, disagrees with the UCA

that this test applies under the current circumstances for two reasons. First, DERS is not subject

to an inter-affiliate code of conduct (IACC), as was the case for the ATCO Utilities. Although

the Commission would expect DERS’ IACC, which is to be filed by December 31, 2015 for the

Commission’s approval, to leverage many of the same principles adopted in Decision 2002-069,

there is no requirement for DERS to do so in this proceeding. Second, the Commission finds that

the UCA has misunderstood the test. The purpose of this test is to guard against a utility

outsourcing an internal service to an affiliate who would in turn charge the utility more for the

same service. The Commission accepts DERS’ testimony that it has always outsourced CC&B

services to ATCO I-Tek and does not have the capability to provide CC&B services on its

own.180 In this proceeding, DERS’ costs of providing CC&B are also the prices it is being

charged for CC&B. Given that regulated customers will pay FMV for CC&B services under this

arrangement, the Commission must assess whether DERS’ estimates of FMV for CC&B services

for 2015 and 2016 are reasonable based on the benchmarking evidence on the record.

144. The Commission acknowledges the UCA’s concerns with respect to benchmarking

studies. As DERS’ representative, Mr. Gary Newcombe, testified during the hearing “there was a

lack of visibility into some of the methodologies behind benchmarking studies, that maybe

benchmark studies were, I don’t know, being viewed as a bit of a black art.”181 Given the lack of

transparency, the Commission is concerned about any discretion that may be exercised by

individual experts when normalizing results or selecting samples. The Commission, however,

recognizes that two separate, and independent, benchmarking studies conducted by two different

experts, using different methodologies, arrived at estimates of FMV that were within six per cent

of each other. This outcome alleviates the Commission’s concerns respecting any potential

subjectivity in the methodologies exercised by the individual experts.

178


Decision 2002-069, ATCO Group, Affiliate Transactions and Code of Conduct Proceeding Part A: Asset

Transfer, Outsourcing, Arrangements, and GRA Issues, Application 1237673-1, July 26, 2002, page 47. 180




Decision 2957-D01-2015 (July 7, 2015) • 33

A. MR. NEWCOMBE: I'll try. My understanding of -- the methodology in both of

them, and particularly the statistical analysis, is fairly limited. But I guess it wasn't quite,

in my view anyway, an attempt to provide more insight into the specific methodology,

but by employing what we understood to be two vastly different -- or two differently

methodologies – I guess I don't know if they're vastly different or not -- that that should

validate the results of both.

In other words, if you come at things in two different ways, in my view you don't

necessarily need to know the two different ways, but if you both arrive at essentially the

same point, there must be some validity in either way of doing things.

145. The Commission does not agree with the UCA that using either the lowest comparator, or

the lowest confidence interval, in the First Quartile report provides a more accurate estimate of

FMV. Specifically, the Commission agrees with the testimony provided by the First Quartile

representative, Mr. Ken Buckstaff, that FMV is more likely closer to the point estimate (i.e.,

average of the sample) than at the lower or upper ranges of the confidence interval.

Q. MS. BENTIVEGNA: All right. Thank you. Now, going to your report, Mr.

Buckstaff, given that the $4.35 per site cost is within your 95 percent confidence interval,

is it reasonable that the true fair market value in 2013 for C&B costs is closer to $4.35

than $4.75?

A. MR. BUCKSTAFF: Actually, I don't believe so. I think it's more likely that it is at

the 4.75. That's the point estimate and that's the most likely, but it's possible that it's

closer. I believe it's more likely to be at the 4.75.

Q. Just so I understand your answer, you said it's possible that it could be 4.35, but --

A. MR. BUCKSTAFF: It's possible that it could be, but the probability is it's not. The

probability is the best estimate we have is 4.75.

146. The Commission also disagrees with the UCA that using historical ATCO I-Tek rates

escalated by inflation represents a more accurate price for 2015 and 2016 CC&B services. In this

proceeding, the Commission is assessing the estimate of FMV for the CC&B services that

regulated customers will receive in 2015 and 2016 under the new arrangement. In the

Commission’s view, inflating the old ATCO I-Tek rates does not provide a good estimate for the

price of services in 2015 and 2016, particularly given that ATCO I-Tek was itself a respondent to

the RFP process. The Commission finds the following testimony by the Desert Sky

representative, Mr. Jon Brock, relevant:

A. MR. BROCK: I could argue the fact that the old pricing was on I-Tek. I-Tek is

running ATCO's CIS. I'm not at ATCO. I don't know what their plans are, but my guess

is that CIS is on its last legs. It will need to be replaced.

When ATCO replaces their CIS, you're going to see a similar, if not larger, jump. They

will either pick -- if they're going into the market, they will probably look at Oracle and

SAP as well. And when they do so, you will see them have their large CIS jump. It

happens to all utilities. Whether you're outsourced or whether you're in-house, at some

point you're replacing your CIS. That's going to happen.

147. Although the Desert Sky report utilized a standard reference group with only four

comparators to arrive at FMV estimates of $3.52 per site and $3.63 per site for 2015 and 2016,


34 • Decision 2957-D01-2015 (July 7, 2015)

respectively, the Commission recognizes that this sample was drawn from a database containing

approximately 75 North American utilities and that these four utilities were the most comparable

to DERS based on scope, quality, complexity, geography, and regulatory environment. The

Commission also accepts Desert Sky’s methodology for recovering the CIS implementation and

transition costs over the test period through a monthly charge of $1.05 per site. While this

analysis was based on a sample of only three other North American utilities, the Commission

recognizes that these three utilities also recently implemented similar CIS systems. The only

other benchmarking evidence proffered in this proceeding was the First Quartile report that

estimated FMV, including CIS costs, of $4.91 per site and $5.00 per site in 2015 and 2016,

respectively. The Commission has compared these two reports and found that Desert Sky’s FMV

estimates of $4.66 per site and $4.77 per site for 2015 and 2016, respectively, fall within the

lower range of First Quartile’s 95th per cent confidence interval. The results of these two reports

are consistent with each other. Given that First Quartile relied on a comparison panel with 46

North American utilities, the Commission finds that the First Quartile report adds depth to the

Desert Sky report and DERS’ CC&B forecast. Accordingly, the Commission accepts DERS’

CC&B costs of $4.66 and $4.77 on a per site per month basis for 2015 and 2016, respectively,

and directs DERS to reflect updated customer site counts in its forecasts of total 2015 and 2016

CC&B costs in the compliance filing.

148. With respect to the UCA’s inquiries about “what’s in it for DELP,” the Commission need

not consider the inter-affiliate relationship in this case because it is relying on FMV to assess the

reasonableness of the forecasts for CC&B costs. Further, the Commission has not been asked to

approve the DEML-DELP MSA or the DELP-HCL MSA. The Commission considers that any

risks arising from these agreements remain with DEML, and DELP, and not the regulated

customers. This is a particularly salient point given that regulated customers will pay FMV for

CC&B services.

149. The Commission agrees with some of the concerns put forward by the UCA with respect

to the RFP process and has addressed these deficiencies with respect to DERS’ vendor selection

costs in Section 4.5. The Commission however was disappointed with the appearance of minimal

ranking in the vendor selection process concerning the pricing of services. DERS and other

utilities may use these vendor selection processes as they see fit, however if utilities intend to use

these processes as support for vendor selection costs in an application or as evidence to justify

prices within an application before the Commission then pricing must receive an important and

more transparent role within the ultimate vendor selection criteria.

4.5 Vendor selection costs

150. Under a 10-year MSA, ATCO I-Tek provided CC&B services for DERS’ regulated and

non-regulated customers since May 2004. The MSA expired on December 31, 2014.182

151. Anticipating the expiration of the ATCO I-Tek MSA, DERS retained Five Point to assess

its CC&B service requirements and the different options available for meeting those

requirements. DERS submitted that Five Point was selected based on its industry-leading

processes, methodologies, and record of assisting utility companies procure CC&B outsourcing

182

Exhibit 0001.00.DEML-2957, Default rate tariff and regulated rate tariff application 2012 to 2016, pages 45-48.


Decision 2957-D01-2015 (July 7, 2015) • 35

arrangements, in both regulated and restructured environments. Specifically, DERS noted that

Five Point had completed two prior CIS evaluations on behalf of ATCO I-Tek.183

152. DERS submitted that the services of Five Point were necessary due to the magnitude of

the required review, the desire to ensure an independent and unbiased outcome, the need to

prudently acquire CC&B services, and the increased scrutiny and oversight required due to it

being a regulated service provider.184

153. In its application, DERS requested approval to recover $750,000 in its 2015 and 2016

revenue requirements for the external consulting, legal, and travel costs expended on the CC&B

RFP process conducted by Five Point. These costs (vendor selection costs) are allocated on an 80

to 20 per cent basis between DRT and RRT, respectively.185,186,187

Table 6. Applied-for vendor selection costs*

2015 forecast 2016 forecast

Default rate tariff 300,000 300,000

Regulated rate tariff 75,000 75,000

*Adapted from DRT and RRT schedules.

154. In response to UCA-DERS-008(a), DERS reiterated that it is “seeking 100 percent

recovery of these costs since this process is similar to the collaborative benchmark process and

the fair market value (FMV) studies DERS has performed on behalf of the regulated customers

(AUC Decision 2006-027 and 2011-247). In these studies 100 percent of the reasonable and

prudent costs were eligible for recovery from the regulated customers. DERS undertook this RFP

solely to support its regulatory business activities. DERS would not have taken this approach or

incurred these costs if it did not operate the regulated business.”188

155. DERS provided additional clarification during the hearing on its rationale for recovering

the entire RFP costs from regulated customers and Five Point’s role in the RFP.

A. MR. PEREKOPPI: So it would not be normal processes or procedures for Direct

Energy to engage outside consultants to support our fee processes. We would normally

do that sort of activity with our in-house procurement organization. However, in this

scenario, we recognized the added rigor that was going to be required because of the

regulated part of this process. Therefore, we thought it would be significantly beneficial

for all to engage Five Point. So we believe we would not have hired an outside firm and,

therefore, the incremental cost of that outside firm should be burdened onto the regulated

customer base.189

…

A. MR. PEREKOPPI: I'm not saying we may not have ever hired Five Point to maybe

help with requirements in just a stand-alone CC&B solution, but what we really needed --

if we were only doing it for a competitive business. Their requirement process is great.

183


Exhibit 0001.00.DEML-2957, Default rate tariff and regulated rate tariff application 2012 to 2016, pages 45-48. 185

Exhibit 0001.00.DEML-2957, Default rate tariff and regulated rate tariff application 2012 to 2016, pages 45-48. 186

Exhibit 0002.00.DEML-2957, DRT supporting schedules. 187

Exhibit 0003.00.DEML-2957, RRT supporting schedules. 188

Exhibit 0019.01.DEML-2957, UCA-DERS-8(a). 189



36 • Decision 2957-D01-2015 (July 7, 2015)

It's really helpful. But the sheer scope of their involvement in this process would be -- we

wouldn't undertake in any solution except where we had the expectation of having to

appear before a regulator and describe our evaluation process and our decision process

and how we got to where we are today.190

…

A. MR. NEWCOMBE: Well, I think a lot of the work that Five Point did, though, was

in assisting our folks in identifying and categorizing all of the required -- the business

requirements for the new system. We relied on their expertise in understanding systems

and CIS systems that were going to work in this environment for helping us evaluate the

different alternatives and understand what the proposals actually meant and helping us all

come to the right business partner that's going to be serving quite well all of our

customers, including regulated customers.191

156. DERS and the Five Point representative, Mr. Charles, elaborated during the hearing that

in addition to the RFP, Five Point was also instrumental in contract negotiations between the

successful RFP respondent HCL, and DELP.

Q. MR. MCCREARY: And given Five Point's expressed expertise in contract

negotiations relating to information technology, was Five Point involved in the contract

negotiations regarding any aspect of the MSA between DELP and HCL America Inc.?

I'm assuming you would be, but correct me if I'm wrong.

A. MR. CHARLES: Yes, sir. We were involved in helping support the negotiations,

predominantly around the final statements of work.192

…

A. MS. ARMSTRONG: Absolutely. I think also Five Point had the benefit of

experience with us through our RFP process -- or through the RFP process and due

diligence, as I said, to understand from our SMEs, our subject matter experts, what it is

that we thought was acceptable from an SLA perspective in our environment.

Q. When you're saying SLA perspective, is that the same as the MSA, the service level

agreement or is that --

A. MS. ARMSTRONG: Service level agreement, that's right. So they captured, for

example, the Rule 3 requirements and wanted to make sure that our contract lived up to

those Rule 3 requirements from an SLA perspective.

Q. And then it also indicated "identify conflicts and confirm appropriate linkages in the

MSA and the SOW." It says that just on the top of page 20. So that's something else Five

Point did?

A. MS. ARMSTRONG: Absolutely, yes. I think all of us were trying to do that as

much as possible. It's a complicated set of documents.

Q. And I think I'm correct, DEML was paying Five Point's costs for this work; correct?

190





Decision 2957-D01-2015 (July 7, 2015) • 37

A. MS. ARMSTRONG: Yes.

Q. And I take it that Five Point was also involved in the contract negotiations between

DELP and DEML or not?

A. MS. ARMSTRONG: I think to a lesser extent on that one because we largely used

the agreements from the HCL to DELP contract. We certainly, you know, asked

questions when required and had them do a little bit of work for us, but, for the most part,

we didn't need assistance in that.

Q. So who was providing the requisite expertise to DEML to negotiate the CC&B

arrangements with DELP?

A. MS. ARMSTRONG: So as I mentioned, a significant portion of the agreement was

just a copy paste from the HCL to DELP agreement. So I think all the technical

requirements and data were copied from that agreement. The parts I think that were

modified we had internal expertise that we felt comfortable using to supplement.193

157. In response to questions posed by the panel Chair, DERS stated that if “the competitive

and regulated businesses were unrelated, we would do everything we could to get as much

revenue out of those competitive customers and flow that back to regulated customers as we

could.”194 DERS also accepted that a 70/30 split between regulated and competitive customers

would be reasonable.

Q. MR. KOLESAR: If the Commission were to make a determination that some of the

cost of the Five Point contract should have been borne by the competitive side, would

that same 70/30 split be a reasonable way to do that?

A. MR. NEWCOMBE: I think it would be. It's the split that we've used. It's got

some rationale, however valid that rationale still is today. But it's got some rationale

behind it. It's got some history. It's easy to understand and it's been accepted in the

past.195

158. The UCA objected to DERS’ request to recover the entirety of the vendor selection costs

from regulated customers. The UCA recommended that the Commission either deny the entire

amount or apportion a maximum of 25 per cent of those costs to regulated customers. The UCA

based its recommendation on the consideration that engaging Five Point did not add transparency

to the RFP process, as suggested by DERS, or assist in setting a competitive CC&B price for

regulated customers.

159. With respect to the transparency issue, the UCA argued that unlike the collaborative

benchmarking process which DERS referenced, customers did not have any input into the RFP

process conducted by Five Point. Also, customers, or the Commission, were not allowed to

review the bids, or the pricing of those bids. The UCA also argued that DERS’ reluctance to

produce its service agreement with Five Point did not inspire confidence that Five Point’s

involvement fostered objectivity, independence or transparency.

193



Transcript, Volume 2, page 391, line 23.


38 • Decision 2957-D01-2015 (July 7, 2015)

160. The UCA added that under DERS’ proposed CC&B arrangements, regulated customers

would pay the FMV for CC&B services based on a benchmarking report that was developed

independent of the Five Point RFP. Therefore, regulated customers did not have the benefit of

the prices which Five Point helped negotiate with HCL. The UCA argued that the majority of

Five Point’s contribution to the contractual negotiations was with respect to the service

agreement between DELP and HCL and therefore benefited DELP, not DERS or the regulated

customers it represents.196

161. The CCA argued that there is uncertainty as to whether regulated customers have and

will benefit from the engagement of Five Point given that under the current proposal, regulated

customers will pay FMV for CC&B services.

162. The CCA submitted that it is inappropriate for regulated customers to bear the entire cost

of the Five Point engagement. The CCA recommended that the vendor selection costs be

allocated between regulated and non-regulated customers using a 70/30 ratio, such as that used to

allocate capital projects between regulated and non-regulated customers.197

163. In reply argument, DERS reiterated that it only engaged Five Point to satisfy the

requirements of providing regulated services. DERS argued that it would not have incurred these

cost if it did not have the regulated business and therefore, the regulated customer should bear

the entirety of these costs. DERS added that the CCA contradicted itself by stating that it would

like customers to benefit from the involvement of an expert third party in the RFP but also

argued that customers should not pay for it. DERS argued that the CCA’s position is illogical

and should be rejected.198

164. In response to the UCA’s position that the Five Point RFP lacked transparency, DERS

submitted that it hired an independent consultant, Five Point, in order to specifically ensure a

structured and unbiased outcome. DERS added that a Five Point representative, Mr. Charles, was

made available for cross-examination. DERS also noted that to ensure there was a sufficient

number of respondents, DERS needed to protect the RFP respondents’ requests for

confidentiality.199

Commission findings

165. The Commission disagrees with DERS that regulated customers should bear the entirety

of the vendor selection costs. Specifically, DERS’ argument that it would not have engaged Five

Point if not for the regulated business is not supported, given the outcomes of the engagement.

Regardless of DERS’ initial intention, both regulated and competitive customers will benefit

from Five Point’s involvement in the RFP process, which ultimately led to a more

comprehensive and better-specified CC&B solution that serves both regulated and unregulated

customers.

166. However, as discussed in paragraph 149 above, it appears that pricing had minimal

ranking in the RFP evaluation. Therefore it is questionable to what degree ratepayers should

participate in funding vendor selection costs. The Commission agrees with the UCA that any

savings that may have resulted from the RFP evaluation process or the participation of Five Point

196


Exhibit 2957-X0094, CCA public argument, pages 16-17. 198




Decision 2957-D01-2015 (July 7, 2015) • 39

in negotiating the service agreement between DELP and HCL are not available to regulated

customers because DERS has substituted a FMV analysis to establish pricing that is entirely

independent of the Five Point engagement. Any benefit to regulated customers is essentially

limited to the comprehensive CC&B solution that came out of the Five Point engagement, which

benefits both regulated and unregulated customers. Accordingly, the Commission will evaluate

the contribution to the Five Point costs that should be reasonably borne by regulated customers

with this benefit in mind.

167. The Commission disagrees with the UCA that regulated customers should not pay any of

the vendor selection costs. The Commission considers that regulated customers will benefit from

Five Point’s involvement in the CC&B RFP process. Specifically, the Commission finds that

DERS has included a number of functionalities in its CC&B system, ostensibly to serve the

needs of regulated customers.

A. MS. ARMSTRONG: …So we did enable -- or the technology is enabled to do chat

functionality. We have not staffed for that currently, but in the event that we decided

that's beneficial to customers or something they would want, we can certainly enable the

technology. Call blasting was another one. So the ability to contact our customers by a

call blast. And then there's another tool that HCL has built. It's proprietary as well, that is

for exceptions handling. So it essentially does some analytics and figures out -- I guess

there's often times where one exception might -- if you clear that one, it clears a whole

bunch at the same time. And so it identifies which one you should clear first. Rather than

just the first exception in, it clears the one that is sort of tying up the rest of the system.

It's sort of more sophisticated around that. There's other examples around the dunning

processes that are improved. So every night it goes in and recalculates the customer’s

internal credit score basically. Scott can speak if I’m representing this incorrectly, but my

understanding is it recalculates the credit scores so you have more information about that

customer rather than doing it once periodically.200

168. The Commission observes that regulated customers were not asked about what additional

functionalities would assist them in their dealings with DERS.

MS. ARMSTRONG: I guess also I can't say we've done a survey or anything specific

like that, but the SMEs that were involved in defining the requirements for this project

were long-term Alberta operations people. They had worked with this customer base for

several years and certainly knew it well. I think it was all of our objectives to bring some

of these technologies, the ones that are improving the customer experience to our

customer base …201

169. The Commission finds that DERS has not adequately supported the need for these

additional functionalities to serve regulated customers and, accordingly, a portion of the Five

Point costs that relate to the requirements of the CC&B system should not be borne by regulated

customers. The UCA argued that none, or a maximum of 25 per cent (i.e., $187,500), of the

vendor selection costs should be allowed whereas the CCA argued for a 70 per cent allocation

(i.e., $525,000). The Commission finds that a $525,000 cost award is not justified and that a

$187,500 award undervalues the benefit that regulated customers received from the more

comprehensive and better-specified CC&B solution. Given a lack of persuasive evidence in

support of either position, the Commission finds that the mid-point of this range is reasonable.

200


Transcript, Volume 4, pages 695-696.


40 • Decision 2957-D01-2015 (July 7, 2015)

The Commission, therefore, directs DERS to reflect a reduction in vendor selection costs from

$750,000 to $356,250 in its compliance filing.

4.6 Corporate costs

Background

170. Table 7 provides DERS’ applied-for corporate costs for the 2012 through 2016 test

period. Total corporate costs are allocated between DRT and RRT on an 80 per cent to

20 per cent basis, respectively.202

Table 7. Corporate costs ($000s)

2012 2013 2014 2015 2016

Total corporate costs 4,106 4,219 4,335 4,454 4,576

Corporate costs allocated to DRT 3,285 3,375 3,468 3,563 3,661

Corporate costs allocated to RRT 821 844 867 891 915

171. In Exhibit 62.01, DERS stated that it used the methodology approved in 2010 to develop

corporate costs in this application. Specifically, DERS referenced its response to CCA-DERS-

014(a), in which it stated:

In 2010, the AUC approved DERS corporate cost methodology and the costs contained

therein for the year 2009. The AUC also approved increases in these costs of 2.5% for

2010 and 2011. As these were the approved amounts by the AUC, those approved

amounts were allocated to DERS through the intercompany allocation process. This is the

same treatment employed in previous DERS non-energy applications.203

172. For the purposes of this application, DERS developed a forecast for 2012 using

centralized corporate service costs for each business function based on the planned costs

identified by each functional department supporting DERS. This information was provided by

corporate finance, which operates under DELP.204 DERS then applied the allocators described in

information response CCA-DERS-031 to derive the 2012 corporate costs allocations for DERS.

An inflation factor of 2.75 per cent was then applied to the 2012 amounts to arrive at each of the

amounts for the test years from 2013 to 2016.

202


Exhibit 0018.01.DEML-2957, CCA-DERS-014(a). 204

Exhibit 0067.03.DEML-2957, CCA-DERS-024(a).


Decision 2957-D01-2015 (July 7, 2015) • 41

Table 8. Direct and indirect corporate costs allocators adapted from CCA-DERS-031205

Department Allocation methodology Allocation

Communications Staff efforts and third party spend 3.2% (staff efforts) 5.0% (third party spend)

Finance – accounts payable Number of transactions processed 1.1%

Finance – payroll Full-time equivalent (FTE) count in the business 1.0%

Finance – bank reconciliation Number of transactions processed 1.1%

Human resources FTE count in the business 1.0%

Information systems Headcount and service usage 4.8%

IS depreciation allocation Headcount and service usage 4.8%

Indirect allocations* Gross margin earned by DERS relative to the total gross margins of the business units

7.0%

*Indirect corporate costs were also subject to an adjustment called the DERS Factor (i.e., DERS estimate (indirect costs) x DERS’ percentage of DEML gross margin).

173. In order to provide corporate costs information for testing, DERS conducted SAP data

queries to identify the corporate costs for each year at a Direct Energy North America level and

then applied the base year historical allocator percentages to derive the comparator numbers by

year.206 DERS clarified that these are not the corporate costs that were actually “booked” in

DERS’ account. In 2013, Direct Energy North America remapped the corporate cost centres

across the company and therefore, DERS could not reconstruct the 2013 data in the time

allowed.207

Table 9. DERS’ back-casted corporate costs allocations

Allocation methodology 2010

actuals 2011

actuals 2012

actuals 2013

actuals

Site count allocation 6,620 6,395 5,050 4,890

Gross revenues allocation 7,147 6,904 5,453 5,279

Historical driver percentage allocation 4,013 5,096 4,828 -

Application allocation 3,738 3,832 4,106 4,225

Source: Adapted from Exhibit 0062.02.DEML-2957, DERS Appendix A: corporate costs testing.

174. In addition to providing the back-casted corporate costs allocations using historical

allocator percentages, DERS also provided corporate costs allocations based on site count and

gross revenues. DERS’ analysis showed that allocating corporate costs based on site count and

gross revenues leads to much higher corporate costs allocations to DERS.

175. DERS stated that the methodology employed in this proceeding is fair, reasonable, cost

efficient and consistent with DERS’ historical practice in Alberta. Specifically, DERS submitted

that DERS’ corporate costs represent only 5.6 per cent of its total revenue requirement whereas

shared services represent 6.1 per cent of ENMAX Energy Corporation’s (EEC) total revenue

205

Exhibit 0067.03.DEML-2957, CCA-DERS-031(b). 206

Exhibit 0052.01.AUC-2957, AUC letter dated April 25, 2015, pages 3-4. 207

Exhibit 0062.01.DEML-2957, Provision of information for corporate costs testing, pages 2-3.


42 • Decision 2957-D01-2015 (July 7, 2015)

requirement and 9.2 per cent of EEA’s total revenue requirement. DERS stated that customers

benefit from both the scope and scale of services provided by the Direct Energy North America

corporate office.

176. DERS added that it is prepared to discuss alternative allocation methodologies for the

period starting in 2017, with a preference for simple allocation methodologies that can be easily

applied and monitored, such as an allocation based on site counts or revenues. For the current

2012 to 2016 application, however, DERS submitted that the applied-for corporate costs should

be approved.208

177. Although the CCA put the entirety of its argument and reply argument under

confidentiality protection “out of an abundance of caution,” the arguments the CCA put forward

with respect to DERS’ corporate costs allocations contained “textual references only to material

which was marked confidential, which the CCA does not consider should be confidential.”209

These arguments are included below because the submissions did not contain confidential

information on corporate costs.

Terminology and provision of information

178. The CCA took issue with the manner in which DERS used the terms “actuals,”

“forecasts,” and “approved amounts” in relation to the corporate costs. It stated that in Alberta,

there is general agreement on the use of terms such as actuals, forecasts, and approved amounts.

DERS, however, had over the course of this proceeding used actuals to mean either actuals,

forecasts or approved costs. The CCA submitted that it eventually realized that when DERS

referred to ‘actual corporate costs’ it really meant Board/Commission approved amounts.

Specifically, the CCA referenced an exchange during the oral hearing where DERS submitted

that it would book one dollar of corporate costs if the Commission approved one dollar for

corporate costs.

Q. MR. WACHOWICH: So if we continue that practice and the Commission in this

proceeding approved an intercorporate cost amount of $1, DERS would show or report

actual intercorporate costs of $1 based on that logic?

A. MR. FAUVILLE: The logic is correct, but I would like to add that if you look at --

that's why we actually applied again Exhibit 62(b) to show the creation of the corporate

costs or the -- is booked starting in 2012 based on the test period. Those are costs that

actually came from the corporate group. Those are allocated to DERS based on the

allocators there at that time, and then they were inflated for inflation. So that's -- that

seems like a reasonable approach.

And, Mr. Wachowich, I would like to say that we would then reset that amount going

into the 2017 test period, as it was reset in the 2009-11 test period.210

208

Exhibit 0062.01.DEML-2957, Provision of information for corporate costs testing, page 3. 209

Confidential Exhibit 83, CCA confidential argument, page 3. 210



Decision 2957-D01-2015 (July 7, 2015) • 43

179. The CCA argued that this practice did not make sense and recommended that for

consistency with other utilities and regulatory efficiency, the Commission direct DERS to cease

the practice of using “actuals” to refer to any amount other than actual expenditures incurred.211

180. In response, DERS submitted that it has clearly explained its use of actuals with respect

to corporate costs. Specifically, DERS repeated that the “actual” corporate costs in its financial

schedules reflect the actual corporate costs amounts booked to DERS and therefore, the use of

the word “actual” is valid. DERS added that it has consistently applied this method, even though

it leads to lower corporate costs allocations than DERS should have incurred, which benefits

regulated customers.

181. DERS added that it has provided evidence to support its corporate costs. Specifically,

DERS noted that, in Confidential Exhibit 70, it provided the actual functional amounts incurred

by Direct Energy North America, the amount allocated to the competitive business in Canada,

and the portion attributable to DERS from 2010 through to 2013. Therefore, DERS disagreed

with the CCA that it has not provided adequate information to justify its corporate costs.212

Corporate costs risks

182. In response to DERS submission that it takes on risk with respect to corporate costs, the

CCA submitted that DERS does not track or know the actual amount of corporate costs incurred

and therefore, cannot claim to be accepting risk with respect to its corporate costs on behalf of

regulated customers. The CCA added that, if anything, its evidence demonstrates that DERS is

overcharging customers.213

Comparison to other regulated providers

183. In response to DERS comparison to the other regulated providers, the CCA responded

that the Commission should not give any weight to DERS’ comparison to EEC and EEA, given

that none of this information was referenced, provided in evidence, or tested as part of this

proceeding. Therefore, there is no way for parties to evaluate DERS’ assertions.214

Back-cast of actuals

184. The CCA challenged the back-casted historical actual corporate costs data DERS

provided in Exhibit 62.02. Specifically, the CCA submitted that DERS had testified during the

hearing that the back-casting exercise was a “miss” and that the back-casted data were

“guess[es].” The CCA questioned whether DERS’ back-casted data should be given any weight

at all. The reference cited by the CCA is reproduced below.215

A. MR. FAUVILLE: So, again, I think in Exhibit 62.01, the letter to the AUC on

corporate provisions we've mentioned, do we want to go over the whole -- how we derive

it again?

It's a calculation based on -- our test year is 2012. The allocators are based on 2011. You

apply those allocators to 2012 by department, direct and indirect. We've identified that in

CCA-DERS-31 and AUC-DERS-25. You apply the allocators, you come up with a

211



Confidential Exhibit 88, CCA confidential reply argument, pages 3-4. 214

Confidential Exhibit 88, CCA confidential reply argument, page 6. 215

Confidential Exhibit 83, CCA confidential argument, pages 14-18.


44 • Decision 2957-D01-2015 (July 7, 2015)

number by department, you add that up and there is the allocation for DERS, the one-off

determination.

So, again, we just wanted to provide that assurance, if you want, of where we are right

now – or back in May. But we could not provide that assurance because of that removal

of the mapping of being able to map direct and indirect. Now, I can say that since then we

have told them that we have filings and we have to have this information. So they

actually are working on that. So it was like a miss, if you want to call it. I would call it a

miss. So they are working on having that ready for the next test period. Of course we've

already filed with our projections here.216

…

MR. FAUVILLE: I think the -- this is where we get hung up on allocation. The DERS

estimate is what has been recorded at the DERS this DERS factor, DERS estimate. So

there's never been a direct level. So you would never be able to compare that to what I

would say would be the actual amount as opposed to what was forecasted. That's

something that has not been done. That's something we've attempted to do, and we did do

when we provided that exhibit to the AUC, where we actually backcast based on the

allocations for '10, '11, and '12 to see what the actuals would be. That's the first time that

I'm aware that we've ever done that.217

185. The CCA further submitted that DERS’ responses to undertakings given during the

hearing contradicted evidence and testimony already on the record.218

186. The CCA submitted that due to DERS’ mixed and confusing testimony, the CCA is

unclear as to what method was utilized to calculate DERS’ corporate costs, what the allocators

are and what actual numbers were used to calculate DERS’ estimate.

187. DERS responded that the CCA took the testimony of its representative, Mr. John

Fauville, out of context to advance its own argument. Specifically, DERS argued that in the

quote referenced by the CCA, Mr. Fauville was responding to a question regarding whether a

ledger was kept to record differences in corporate costs as approved by the Commission versus

the total allocated corporate costs. Mr. Fauville explained that the only time an attempt was made

to record fully allocated corporate costs was in Exhibit 62.02.219 Mr. Fauville was not explaining

how DERS determines historical actual costs.220

188. DERS further argued that Mr. Fauville’s testimony was taken out of context in

paragraphs 46 and 47 of the CCA’s argument in order to suggest that the back-cast provided in

Exhibit 62.02 was a “guess.” DERS explained that Mr. Fauville was giving information on the

corporate restructuring in 2013 which led Direct Energy North America to remove the tagging of

costs as direct or indirect and that this was “a miss” on the part of Direct Energy North America,

since DERS became unable to map corporate costs for 2013 using the same approach as the other

years. DERS stated that Mr. Fauville was not implying that the back-cast figures are incorrect.

216




Exhibit 0062.02.DEML-2957, DERS appendix A: corporate cost testing. 220



Decision 2957-D01-2015 (July 7, 2015) • 45

189. Overall, DERS submitted that the CCA’s corporate costs determinations appear

simplistic and based on generalities that are not directly applicable to the DERS business and

should be fully dismissed by the Commission.

Gross margins as an indirect allocator for corporate costs

190. The CCA argued that gross margins do not make sense as an allocator for items such as

human resources, finance, facilities or health, safety and environment. First, no logical link

between gross margins and the functions that drive corporate costs exists. For example, gross

margins do not drive human resource costs. Second, gross margins is a profitability measure and

therefore, companies with unregulated and regulated businesses are encouraged to push costs to

the regulated business since they can be recovered through rates under a cost of service regime.

Third, gross margins are based on the “DERS estimate” and do not appear to be based on actual

gross margins. This makes it very easy for DERS to move costs by adjusting its estimates. The

CCA argued that indirect allocations make up roughly seventy per cent of the corporate costs

allocated to DERS and is a substantial amount to be based on such a flawed allocation method.221

191. Although the CCA acknowledged DERS’ position that the gross margin earned by DERS

relative to Direct Energy North America may be a reasonable proxy for its relative size and

therefore, its relative resource requirements, the CCA disagreed with the logic. The CCA added

that gross margin is not even a good proxy for relative size. The CCA proposed that more

reasonable proxies would be sales, net assets, staff or square footage. These all provide some

measure of size as opposed to gross margin. The CCA submitted that under the current

methodology, DERS would be paid to receive corporate services if its gross margin became

negative. The CCA recommended that the Commission direct DERS to revise this aspect of its

allocation method for the next proceeding and to develop more logical allocators.222

192. The CCA also recommended that for future applications, DERS should be required to

provide the actual originator costs, the volumes of work that it provides (as measured by the

corporate costs allocators) and the volumes of work received by DERS (as measured by the

allocators).223

193. DERS defended its use of gross margins as an allocator for indirect corporate costs.

DERS agreed with the CCA that sales, net assets, staff and square footage are valid allocators for

certain costs and stated that DERS does use these alternative allocators where appropriate;

however, when these alternative allocators do not apply, gross margins are appropriate since they

provide a reasonable proxy for the relative size of the business units in relation to the overall

corporation. DERS elaborated that it only uses gross margins to allocate indirect corporate costs

– direct costs are allocated using direct allocators. For example, DERS cited that with respect to

its finance costs, accounts payable is allocated based on the number of transactions and payroll is

allocated using the number of FTEs in the business. Finance departments such as “Control” are

allocated on the basis of gross margins since “Control” completes work that benefits the entire

organization.224

221


Confidential Exhibit 83, CCA confidential argument, pages 9-10. 223




46 • Decision 2957-D01-2015 (July 7, 2015)

194. DERS rejected the CCA’s assertion that gross margins are used to allocate indirect costs

to allocate more costs to the regulated business. Specifically, DERS explained that a “DERS

factor” is applied to total corporate costs allocations where DERS deems the allocations to be

inappropriate or where the services do not add value to regulated customers. The “DERS factor”

reduces the corporate costs allocation to the appropriate level for regulated customers. The

magnitude of the factor can vary, but the concept is consistent.

195. DERS added that in response to a CCA request, it had recalculated its corporate costs

based on Direct Energy North America’s corporate actuals and, based on this analysis, regulated

customers would have been burdened with higher costs. DERS stated that DEML absorbed the

corporate costs not passed on to regulated customers.225

Static allocators

196. The CCA submitted in evidence that, based on the acquisitions noted in Centrica’s 2013

annual report, DERS should experience a “reduction in the amount of capital costs allocated to

DERS either due to a smaller cost pool or reflecting the fact that there are more customers and

businesses to spread the costs around.”226 The CCA stated that due to DERS’ refusal to provide

the relevant information, it is not possible to calculate this reduction. Directionally, however, the

CCA submitted that corporate costs allocations should go down.227

197. The CCA referenced the following discussion from the hearing to support its position.228

A. MR. NEWCOMBE: So Direct Energy in North America grew very quickly through

the -- I don't know – first 10 to 11 years of its history, and a lot of that growth was

fuelled by- fuelled by acquisitions. So every time the company acquired a new

energy retailer or a new digital platform, or whatever they acquired, they typically

bought the whole company -- systems, people, everything -- and there was really a

focus on growth as opposed to any sort of integration. So with a slowdown in the

acquisitive growth, the company sort of took a breath and said: Okay. Now we've

got, you know, a hundred of these little companies we've purchased. We've integrated

them with respect to brand and corporate entity, but we haven't integrated any of the

systems. So we're operating a myriad of all sorts of different systems, little call

centres here and there. So there was a focus on trying to reduce costs by going

through a consolidation and integration process there.229

198. The CCA argued that it does not make sense that DERS’ allocators would be static over

the past years and remain static until 2017 given that acquisitions, which would drive costs up,

and consolidations, which would drive costs down, appear to be continuing elsewhere in the

corporate structure. The CCA further argued that DERS’ gross margin relative to the overall

corporate organization should have varied and most likely declined, as other non-DERS

regulated businesses were added. However, the CCA pointed out that this is not the case.230

199. DERS rejected the CCA’s recommendation that its corporate allocations should be

reduced given that its parent, Direct Energy North America, was growing. DERS stated that

225


Exhibit 0142.01.CCA-2957, CCA corporate cost evidence, page 10. 227

Exhibit 0142.01.CCA-2957, CCA corporate cost evidence, pages 11-12. 228



Confidential Exhibit 83, CCA confidential argument, pages 10-11.


Decision 2957-D01-2015 (July 7, 2015) • 47

Direct Energy North America has made both acquisitions and dispositions and therefore, the

overall size (and gross margin percentage) of DERS relative to Direct Energy North America has

remained relatively close and would not have significantly impacted DERS’ corporate

allocations. DERS added that the general statements made in the annual reports, without context

specific to DERS, cannot be used to make calculations affecting DERS’ revenue requirement.231

Lack of incentives to cut costs

200. The CCA submitted that under DERS’ current approach for allocating corporate costs,

there are no incentives for DERS to cut costs or mechanisms to flow savings to customers.

Specifically, the CCA referenced the following exchange from the hearing in support of its

submission.232

Q. MR. WACHOWICH: So I want to go back. Does Direct Energy North America post

internal targets for all its operations?

A. MR. NEWCOMBE: Well, like any -- any company, they put together an annual

operating plan to the extent that that has forecast numbers in it. I guess by de facto they

become targets, yes.

Q. Okay. So if there are de facto targets for Direct Energy North America, are there

internal targets for the Direct Energy Alberta operations? And by that I mean all Alberta

operations, regulated and unregulated?

A. MR. NEWCOMBE: Yes, I expect there would be. The difference in Alberta is that the

competitive operations are done under Direct Energy Partnership as opposed to Direct

Energy Marketing Limited.

Q. And, sir, specific to Direct Energy Regulated Services, are there internal targets for the

operations?

A. MR. NEWCOMBE: No. So for Direct Energy Regulated Services, we have

applications and we have decisions, and those become our targets, sir.233

201. DERS responded that the CCA’s position was based on a few comments from the

transcript and are not representative of DERS’ corporate costs approach.

Recommendation with respect to direct allocations

202. In its corporate costs evidence, the CCA submitted that based on Centrica’s 2013 annual

report, Direct Energy North America had an average of 6,027 employees in 2012 whereas based

on DERS’ application, DERS only had 34.86 FTEs in 2012.234,235 The CCA calculated that

DERS’ FTEs only accounted for about 0.58 per cent of the total number of Direct Energy North

America employees and therefore, direct corporate costs that are allocated using FTE count (i.e.,

one per cent) are overstated by two-thirds. The CCA added that since DERS provided no other

support for its costs, the CCA can only assume that the allocations for all of the other direct

231





Exhibit 0067.02. DEML-2957, Centrica Annual Report and Accounts 2013, page 104.


48 • Decision 2957-D01-2015 (July 7, 2015)

allocated corporate costs are similarly overstated. The CCA, therefore, recommended that all

direct corporate cost allocations be reduced by 42 per cent (or $318,000).236

203. With respect to the direct allocations, DERS responded that direct allocations come from

more departments than the two that the CCA used in its calculation. Specifically, directly

allocated corporate costs come from Information Systems, Human Resources, Finance –

Accounts Payable, Finance – Payroll, Risk Management, Information Systems Depreciation,

Legal, and Communication. DERS reiterated that each department has diverse functions and

therefore, unique drivers including headcount, server usage, staff effort, number of transactions,

and third party spend.237

204. DERS argued that the CCA’s corporate cost determinations appear simplistic and based

on generalities that are not directly applicable to DERS’ business and should be fully

dismissed.238

Recommendation with respect to indirect allocations

205. In its corporate costs evidence, the CCA noted concerns with DERS’ indirect allocations.

Specifically, the CCA submitted that Centrica reported an operating profit of $493 million (i.e.,

£310 million) in 2012, while DERS reported a net income of $13.122 million in 2012. The CCA

calculated that DERS’ net income only accounted for 2.6 per cent of Direct Energy North

America’s operating profit and therefore, by using a 7 per cent indirect allocator, DERS was

overstating its indirect corporate costs by 269 per cent (or $1.7 million).239

206. In rebuttal evidence, DERS submitted that the CCA’s evidence failed to recognize that

the Suncor acquisition, which the CCA’s position relies on, is being made by Centrica Energy –

Gas and does not impact the Direct Energy business. DERS added that the CCA’s analysis also

failed to recognize that Direct Energy is divesting its home and small commercial services

business in Ontario. DERS submitted that the loss of this business increased the percentage of

corporate costs that need to be borne by DERS.

207. With respect to the analysis that resulted in the CCA’s position that indirect corporate

costs were overstated by 269 per cent, DERS submitted that the CCA confused net income,

operating profit, and gross margins because, in its calculation, the CCA used DERS’ net income

as the numerator but Direct Energy’s operating profit as the denominator. DERS stated that these

are different classifications of income and cannot be combined with each other. DERS added that

its indirect corporate costs allocator is based on gross margins – not net income or operating

profit.240

208. Based on DERS’ rebuttal evidence, the CCA revised its initial estimate of DERS’

operating profit relative to Direct Energy North America from 2.6 per cent to 3.3 per cent.

Specifically, the CCA reduced its estimate of DERS’ indirect corporate costs overstatement from

$1.7 million to $664,000.

236





Exhibit 2957-X0016, DERS rebuttal evidence on corporate costs, pages 2-3.


Decision 2957-D01-2015 (July 7, 2015) • 49

209. The CCA added that “DERS has provided no information to suggest that gross margins

on regulated business are double that of other businesses. In other words, to get from the 3.3%

regulated share of operating profit which DERS calculated, to the 7% which DERS uses as an

allocator, the gross margin on the regulated business would have to more than double to reach

7%. This seems implausible. The DERS correction from using net income to operating profit

only moved the calculation from 2.6% to 3.3%.”241 The CCA, therefore, recommended that the

Commission direct DERS to reduce indirectly allocated corporate costs by $664,000.242

210. In reply argument, DERS responded that net income is not a good proxy for gross margin

for a number of reasons, and that the purpose of the calculations was to point out that the CCA’s

calculation was incorrect.243

211. DERS also commented that “it is not only completely plausible but a reality that gross

margin is higher than operating profit. The difference between gross margin and operating profit

is made up of the operating expenses incurred (labour, staff related expenses, CC&B, bad debt

expense, depreciation, allocations, professional services, etc.) which total millions of dollars.”244

212. In argument, the UCA repeated many of the concerns presented in the CCA’s evidence

relating to corporate costs. Specifically, the UCA cited a lack of transparency with respect to

how DERS uses the term “actuals,” how corporate costs are allocated, and how the “DERS

factor” works. The UCA also questioned why DERS’ corporate costs were not declining despite

evidence presented during the hearing that Direct Energy North America was engaging in cost

cutting initiatives. The UCA argued that given the concerns raised by the CCA, there is

insufficient evidence on which to approve the corporate costs as applied for by DERS. The UCA

recommended that the Commission award no more than the actual amounts incurred for 2012,

2013 and 2014 and reduce DERS’ forecast corporate costs to the five-year average amounts of

$3,243,100 for DRT and $803,760 for RRT, for each of 2015 and 2016.245

213. In reply argument, the UCA submitted that despite generating considerable discussion

throughout the hearing, DERS had provided little discussion on its applied-for corporate costs in

argument. The UCA argued that the Commission and interveners are left with little more than

assurances from DERS that “customers receive fair value for the services provided by DERS’

corporate office.”246 The UCA reiterated that DERS has not met its burden to show that the

applied-for corporate costs allocations are reasonable.

Commission findings

214. Given that DERS’ allocation methodology for corporate costs has been accepted in the

past and is the only developed methodology on the record, the Commission finds that using this

allocation methodology in this proceeding is acceptable.

215. However, the Commission considers that the allocation methodology has numerous

shortcomings which were highlighted in the evidence and submissions of the interveners. The

Commission finds that an alternative corporate costs allocation methodology, and updated

241






Exhibit 2957-X0095, DERS argument at paragraph 49.


50 • Decision 2957-D01-2015 (July 7, 2015)

allocators, are needed in future proceedings. The Commission agrees with the CCA that DERS’

practice of booking Board/Commission approved amounts as actuals does not comply with

industry practice and caused substantial confusion and delay over the course of this proceeding.

Second, it is unlikely that the drivers, as a percentage of Direct Energy North America, on which

DERS’ corporate costs allocators are derived have remained constant since 2009 and will remain

constant in the future.

216. The Commission, therefore, directs DERS in its next non-energy rate application to file a

new corporate costs allocation methodology. The application should include actual data from the

entity providing the service, rationale to support the corporate costs allocators for each service,

the volume of work that this entity provides (as measured by the allocators) and the volumes of

work received by DERS (as measured by the allocators). The proposed methodology is to

include a mechanism for tracking actual corporate costs incurred by DERS and variances

between actuals and forecasts. DERS is also to cease the practice of booking Board/Commission

approved amounts as actuals.

217. The Commission finds that DERS has not presented persuasive evidence that a 1.0 per

cent allocation for all corporate costs directly allocated based on FTE count is reasonable. The

Commission is persuaded by the CCA’s evidence and submissions that, based on Centrica’s

2013 annual report, DERS’ 2012 FTE count relative to Direct Energy North America’s 2012

average employee count was only 0.58 per cent and not one percent. On this basis, the

Commission accepts the CCA’s argument that corporate costs directly allocated based on FTE

count appears to be overstated by 42 per cent. The Commission, however, disagrees with the

CCA that this condition extends to all directly allocated corporate costs because drivers other

than FTE counts (i.e., third party spend, number of transactions, staff efforts, head count and

service usage) are used to directly allocate corporate costs. Accordingly, the Commission directs

DERS to use a 0.58 per cent allocation instead of the 1.0 per cent allocation for corporate costs

directly allocated based on FTE counts into its 2012 corporate costs forecast. DERS is to reflect

this reduction in its compliance filing.

218. The Commission accepts DERS submissions that the CCA has confused net income,

operating profit, and gross margin. Operating profit, upon which the CCA’s analysis is based,

and gross margin are not directly comparable or correlated. The Commission considers that the

derivation of operating profit depends on the level of corporate allocations and therefore, it is not

reasonable to use operating profit as a driver in the determination of allocations. This would be

circular. The Commission, therefore, rejects the CCA’s recommendation with respect to DERS’

indirectly allocated corporate costs.

219. Regarding the UCA’s recommendations, although 2012, 2013 and 2014 have passed, the

actual corporate costs presented in this proceeding for those years are not “actual” corporate

costs incurred by DERS but simply the forecasted costs that were originally applied-for.247 The

Commission finds that the adoption of the UCA’s submission would not lead to more accurate

corporate costs allocations and, therefore, rejects the UCA’s recommendations.

220. The Commission understands that DERS’ forecasts of corporate costs over the 2012 to

2016 test period were developed using a forecasted inflation rate of 2.75 per cent. Based on the

record of this proceeding, “actual” corporate costs for 2013 and 2014 are not costs incurred by

247

Exhibit 2957-X0031, DERS opening statement, Attachment 1 - 2014 unaudited actuals.


Decision 2957-D01-2015 (July 7, 2015) • 51

DERS but forecasts of 2012 corporate costs inflated annually by 2.75 per cent through to 2016.

Given that actual 2013 and 2014 inflation data and updated forecast 2015 and 2016 inflation data

were provided in this proceeding and discussed in further detail in Section 4.1, the Commission

directs DERS to reflect the updated Alberta CPI data, consistent with those in Table 1, into its

2013 to 2016 corporate costs allocations in place of the 2.75 per cent originally forecasted.248 For

example, DERS’ 2013 corporate costs allocation will be its 2012 corporate costs allocation, after

the reductions directed in paragraph 217, inflated by 1.4 per cent. Consistent with the

Commission’s findings in sections 4.2 and 4.8 with respect to the 2013 and 2014 SAS amounts,

DERS is to exclude corporate costs related to SAS from the above adjustment and to incorporate

the SAS amounts as approved in Decision 2012-343 into its 2013 and 2014 corporate cost

allocations. DERS is to reflect these adjustments for 2013, 2014, 2015, and 2016 into its

compliance filing.

221. With the exception of the reductions and adjustments directed above, the Commission

approves DERS’ applied-for corporate costs for the 2012 to 2016 test period.

4.7 Postal costs

222. On March 31, 2014, Canada Post introduced a new tiered pricing structure, which

increased the incentive letter mail pricing for commercial pre-sort customers by 15 per cent to

$0.69. Canada Post indicated that this was a “one-time strategic adjustment”249 and that, in 2015,

annual adjustments are expected to be similar to what has been seen in the past.250

223. DERS did not propose to recover the shortfall of more than $450,000 resulting from the

Canada Post increase because it had already applied for and assumed any risk on the 2014

postage costs. However, DERS provided updated postage rate forecasts based on the average of

the last five years of standard lettermail postage increases.251 Specifically, DERS forecast that

further Canada Post increases would impact DERS’ postal costs by $1.1 million and $1.4 million

in 2015 and 2016, respectively.

224. In response to undertaking 40, DERS updated its forecast postage cost increases based on

Canada Post’s incentive pre-sort lettermail, instead of standard lettermail prices.252 In a follow-up

information request to undertaking 40, DERS submitted that the actual price for Canada Post

incentive pre-sort lettermail in 2015 is $0.71 per item.253 This was only a 2.9 per cent increase

and not the 5.8 per cent increase DERS had forecasted in undertaking 40. Based on this

information, DERS further revised the impact of postal cost increases in 2015 and 2016 to

$0.74 million and $0.85 million, respectively.254

225. In argument, the CCA submitted that the methodology used by DERS in the attachment

to the information requests on the undertaking response (i.e., Exhibit 2957-X0089) is a more

248

Exhibit 2957-X0036.1, DERS attachment to undertaking 16 – TD Provincial Economic Forecast Update,

page 3. 249

Exhibit 0074.06.DEML-2957, Canada Post price and service changes, page 1. 250

Exhibit 0074.01.DEML-2957, amended DRT and RRT application, pages 34-35. 251

Exhibit 0074.01.DEML-2957, amended DRT and RRT application, page 35. 252

Exhibit 2957-X0066.1, DERS attachment undertaking 40 AUC-DERS-050(a). 253

Exhibit 2957-X0085, AUC-DERS-001 2015FEB20. 254

Exhibit 2957-X0089, Attachment AUC-DERS-001 2015FEB20.


52 • Decision 2957-D01-2015 (July 7, 2015)

accurate forecast because it uses actual postage rates expected to be incurred by DERS and that

DERS’ postage cost forecast should be updated to reflect the change in pre-sort postage costs.255

226. In its reply argument, DERS stated that it agreed that the forecasts provided in the

attachment to the undertaking response (i.e., Exhibit 2957-X0066.1) is a more refined postage

forecast for 2015 and 2016, and stated that it would reflect that change in its compliance filing.256

Commission findings

227. The Commission agrees with the CCA that the analysis conducted in Exhibit 2957-

X0089 provides a more accurate forecast for DERS’ 2015 and 2016 postage cost increases

because they reflect Canada Post’s actual 2015 pre-sort rates, whereas the analysis in

Exhibit 2957-X0066.1 does not. Additionally, the Commission recognizes that despite 2014

actuals being available, DERS’ analysis in Exhibit 2957-X0089 does not reflect updated site

count forecasts for 2015 and 2016. Accordingly, the Commission directs DERS, in its

compliance filing, to update its 2015 and 2016 postage cost forecasts using the methodology and

prices in Exhibit 2957-X0089 with updated 2015 and 2016 site count forecasts.

4.8 Remuneration

228. Remuneration for the DRT operations of DERS is mainly composed of the costs included

in the cost categories of “Labour (Gas Procurement)” and “Labour by Department.”

Remuneration for the RRT operations of DERS is mainly composed of the costs included in the

cost category of “Labour by Department.” There are also remuneration costs for the SAS and

these are included in the cost category of “Corporate Costs.”

229. Included in the cost categories of “Labour (Gas Procurement)” and “Labour by

Department” are salaries, benefits and the costs for the AIP. DERS provided the following

breakdown of these three components between “Labour (Gas Procurement)” and “Labour by

Department” for each of the DRT and the RRT:

255




Decision 2957-D01-2015 (July 7, 2015) • 53

Table 10. Details of forecast labour costs for 2015 and 2016257

Cost category 2015 forecast

($000s) 2016 forecast

($000s)

DRT

Salaries 2,684.0 2,757.8

Benefits 418.2 429.7

AIP 573.3 589.1

Total DRT 3,675.5 3,776.6

Comprised of

Labour (Gas Procurement) 489.0 502.5

Labour by Department 3,186.5 3,274.1

3,675.5 3,776.6

RRT

Salaries 1,438.3 1,477.8

Benefits 231.3 237.6

AIP 372.0 382.2

Total RRT 2,041.6 2,097.6

Comprised of

Labour by Department (Note 1) 2,041.5 2,097.6

Note 1: The 0.1 difference in 2015 is due to rounding.

230. The forecast SAS costs for 2015 that are included in the “Corporate Costs” cost category

are $191,300 for the DRT and $47,800 for the RRT. The forecast SAS costs for 2016 that are

included in the “Corporate Costs” cost category are $196,600 for the DRT and $49,200 for the

RRT.258

231. The forecast costs for 2015 for each of the remuneration components described above

were arrived at by applying an inflation factor of 2.75 per cent to the 2014 forecast amounts. The

forecast costs for 2016 for each of the remuneration components described above were arrived at

by applying an inflation factor of 2.75 per cent to the 2015 forecast amounts. DERS forecast

35.76 FTEs for each of 2013, 2014, 2015 and 2016.259 DERS stated that the 2.75 per cent

inflation factor was taken from Schedule 3.2 of an application from ATCO Gas,260 and was

calculated using the Alberta Weekly Earnings and Alberta CPI data.

232. On behalf of the UCA, Mr. Bell presented evidence in which he compared, on a cost per

site basis, the actual costs for the “Labour by Department” cost category for the DRT, for each of

257

Exhibit 0020.14.DEML-2957, Attachment to the response to AUC-DERS-030. 258

Exhibit 0020.12.DEML-2957, Attachment to the response to AUC-DERS-025(a). 259

Exhibit 0074.09.DEML-2957, DERS amended DRT revenue requirement schedules, Schedule 5.1.8. 260

Proceeding 2826, Application 1609915-1, ATCO Gas and Pipelines Ltd., 2014 Annual Performance-based

Regulation Rate Adjustment Filing. Decision 2013-460 was issued on December 19, 2013, with respect to this

application.



54 • Decision 2957-D01-2015 (July 7, 2015)

2012 and 2013, to the corresponding forecast costs for each of 2012 and 2013.261 During the

course of the proceeding, Mr. Bell updated his analysis to include a comparison, on a cost per

site basis, of the 2014 actual costs to the 2014 forecast costs for the “Labour by Department” cost

category for the DRT.262

233. Mr. Bell’s analysis is presented in the following table.

Table 11. Variance analysis of “Labour by Department” costs for the DRT on a cost per site basis263

Cost per site

2012 Forecast $0.3691

2012 Actual $0.3472

Difference ($) $0.0219

Difference (%) 5.95%

2013 Forecast $0.3708

2013 Actual $0.3423



2014 Forecast $0.3988

2014 Actual $0.4294

Difference ($) ($0.0306)

Difference (%) -7.66%

2012-2014

Forecast $1.1387

Actual $1.1189



234. Based on this analysis, Mr. Bell recommended that the 2015 forecast for “Labour by

Department” for the DRT of $3,186,500 be reduced by 1.75 per cent, which is a reduction of

$55,764. Mr. Bell also recommended that the 2016 forecast for “Labour by Department” for the

DRT of $3,274,100 be reduced by 1.75 per cent, which is a reduction of $57,297.264 The CCA

supported these reductions.265

235. Using the actual costs for 2010, 2011, 2012, 2013 and 2014, the UCA calculated that the

annual average costs over this five-year period for the “Labour (Gas Procurement)” cost category

261

Exhibit 0029.02.DEML-2957, UCA evidence. 262




Exhibit 2957-X0094, CCA public argument, paragraph 46.


Decision 2957-D01-2015 (July 7, 2015) • 55

for the DRT are $494,600. The annual average costs over the same five-year period for the

“Labour by Department” cost category are $2,679,200 for the DRT and $1,924,300 for the

RRT.266

236. The UCA submitted that in light of the economic climate and a declining customer base,

a reasonable forecast for the “Labour (Gas Procurement)” cost category for the DRT for 2015

and 2016 should be no more than $494,600 for each year. For the same reasons, the UCA

submitted that a reasonable forecast for the “Labour by Department” cost category for the DRT

for 2015 and 2016 should be no more than $2,679,200 for each year. Similarly, a reasonable

forecast for the “Labour by Department” cost category for the RRT for 2015 and 2016 should be

no more than $1,924,300 for each year.

237. The CCA submitted evidence regarding labour costs. Noting that DERS did not forecast a

vacancy rate for the 2012-2016 test period, even though DERS had vacancies in each of 2010

and 2011, the CCA indicated that the actual FTEs in 2010 were 2.38 per cent less than approved,

which is 100 per cent more than the 1.2 FTEs unfilled in 2011. The CCA recommended a change

in the vacancy rate from zero per cent to 4.9 per cent, which it stated was the average of the

vacancy rates for 2010 and 2011. The CCA also recommended that the 2012 actual costs should

be used in place of the forecast amounts for the “Labour (Gas Procurement)” and “Labour by

Department” cost categories, and that subsequent increases should be limited to the Commission

determined labour inflation increase for 2013, 2014, 2015 and 2016.267 The CCA indicated that

DERS shows declining labour costs into 2013 and then is forecasting increasing labour costs

thereafter, despite the fact that DERS is forecasting customer attrition.268

238. DERS submitted that it cannot operate with less than the applied-for FTEs, and that the

CCA’s rationale that forecast reductions in customers should result in reductions in labour does

not hold true. DERS stated that its labour levels are generally driven by function, not by

customer numbers. It added that having fewer sites does not reduce the number of finance,

settlement, procurement, compliance or regulatory personnel that are required to run the

business. While economies of scale dictate that a broader scope can be encompassed by existing

roles to a certain point, the basic business of DERS and its basic staffing requirements do not

change if there are 600,000 sites versus 800,000 sites.269

239. DERS submitted that the vacancy reduction recommended by the CCA is unjust and

punitive and should not be considered by the Commission. Given its relatively small number of

FTEs, DERS stated that the recommended blanket FTE reduction is not practical or possible for

DERS to implement. DERS added that its total FTE component is mainly made up of individual

FTEs or allocated portions of FTEs. In some cases, single FTEs are responsible for entire

business functions. There are no large teams of personnel that can be reduced by full or partial

FTEs. DERS indicated that as such, practically implementing a reduction of 1.8 FTEs is simply

not possible without compromising certain business functions.270

266

Exhibit 2957-X0097, UCA public argument, paragraphs 251 and 256. 267

Exhibit 0035.02.CCA-2957, CCA evidence, pages 13-14. 268

Exhibit 2957-X0094, CCA public argument, paragraphs 10-11. 269




56 • Decision 2957-D01-2015 (July 7, 2015)

Commission findings

240. Given the Commission’s findings in Section 4.2 of this decision that DERS should use

the actuals for 2012, 2013 and 2014, the Commission considers that the DERS forecast

methodology of applying inflation to the 2014 forecasts to arrive at the forecasts for 2015 and

2016 is not acceptable in this case. The 2014 forecast included by DERS has been replaced with

the actuals for 2014, and the Commission considers that an effective forecasting methodology

would be based on actuals.

241. The Commission finds that it is reasonable for DERS to base its forecast labour costs for

2015 and 2016 on the average of the actual costs for the three years from 2012 to 2014. The

Commission considers that the three-year period from 2012 to 2014 better recognizes the

economic climate and DERS’ declining customer base.

242. The Commission did not accept the CCA recommendations regarding “Labour (Gas

Procurement)” and “Labour by Department” because the Commission did not fully understand

the CCA’s recommendations. The CCA requested that forecast labour costs for 2013 and 2014

be calculated using the 2012 actual amounts plus inflation, while at the same time supporting the

use of actual labour costs for 2013 and 2014, with the exception of the AIP amounts, which

should be 50 per cent of the actuals. These recommendations do not appear consistent. In

addition, the Commission does not understand how it would be possible for DERS to apply a

vacancy rate but also use actual labour costs at the same time, with the exception of the AIP

amounts. The actual labour costs for 2012, 2013 and 2014 would incorporate the impact of any

vacancy rates that were actually experienced in those years.

243. Further, there is a direct relationship between vacancy rates and labour costs.

Specifically, labour costs are based on FTEs, so if the number of FTEs is reduced because of an

increase in the forecast vacancy rate, then there would also be a corresponding reduction in

forecast labour costs.

244. In Section 4.1 of this decision, the Commission approved forecast inflation rates of 1.92

per cent for 2015 and 2.95 per cent for 2016. DERS included forecast inflation for the “Labour

(Gas Procurement)” and “Labour by Department” cost categories for 2015 and 2016 as part of its

application. Both the UCA and the CCA recommended that inflation be applied to labour costs.

The Commission agrees and considers that it is reasonable to apply forecast inflation to these

cost categories.

245. In Decision 2012-343, the Commission approved the portion of the forecast AIP costs for

2012, 2013 and 2014 that related to achieving objectives other than financial objectives.271 No

information was provided during the proceeding to verify that the actual AIP costs included by

DERS as part of the “Labour (Gas Procurement)” and “Labour by Department” cost categories

for 2012, 2013 and 2014 only included payments that were related to objectives other than

financial objectives.

246. The Commission directs DERS, as part of the compliance filing, to submit information

similar in format to the attachment to the response to AUC-DERS-030,272 which showed the

components of the labour costs by department. The information to be provided must include the

271


Exhibit 0020.14.DEML-2957.


Decision 2957-D01-2015 (July 7, 2015) • 57

actual amounts for each of the DRT and the RRT for 2012, 2013 and 2014, shown separately by

year. The actuals for 2012, 2013 and 2014 AIP to be included must only be for achieving

objectives other than financial objectives. The Commission also directs DERS, as part of this

submission, to show the three-year average for the years from 2012 to 2014 for each component

and department. The Commission directs DERS to inflate the resulting three-year average

amounts for the years from 2012 to 2014 by 1.92 per cent and show the results separately for the

DRT and the RRT in columns entitled “2015 Forecast.” The Commission directs DERS to inflate

the figures in the columns entitled “2015 forecast” by 2.95 per cent and show the results

separately for the DRT and the RRT in columns entitled “2016 Forecast.” The Commission

directs DERS to include the resulting total costs in the “2015 Forecast” and “2016 Forecast”

columns as the forecast amounts for labour costs, allocated appropriately between the “Labour

(Gas Procurement)” and “Labour by Department” cost categories for the DRT and in the

“Labour by Department” cost category for the RRT.

247. In Section 4.2 of this decision, the Commission denied the CCA’s request that the

Commission revise its findings with respect to the AIP forecasts for 2012, 2013 and 2014 that

were approved in Decision 2012-343. Consequently, the forecast approved AIP amounts for

2012, 2013 and 2014 are as included in paragraph 78 of Decision 2012-343. These amounts are

as follows: DRT – $516,000 for 2012, $536,000 for 2013 and $558,000 in 2014; RRT –

$335,000 for 2012, $349,000 for 2013 and $362,000 for 2014. DERS reflected these amounts in

the attachment to the response to AUC-DERS-030.

248. In Section 4.2 of this decision, the Commission approved the use of the actuals for the

years 2012, 2013 and 2014, with the exception of the costs for AIP, LTIS and SAS.

249. The Commission directs DERS, as part of the compliance filing, to submit a second

separate attachment similar in format to the attachment to the response to AUC-DERS-030. The

information to be provided must include the actual amounts for salaries and benefits for each of

2012, 2013 and 2014, shown separately by year and shown separately for each department for

the DRT and the RRT. In addition, the information must include the forecast approved amounts

for the AIP for each of 2012, 2013 and 2014, as included on the attachment to the response to

AUC-DERS-030. The Commission directs DERS to include the resulting total costs for 2012,

2013 and 2014, allocated appropriately between the “Labour (Gas Procurement)” and “Labour

by Department” cost categories for the DRT and in the “Labour by Department” cost category

for the RRT.

4.9 Customer education and awareness

250. In its application, DERS stated that there continues to be a need to provide customers

with information and education with respect to the market. DERS proposed combined DRT and

RRT customer education and energy awareness expenditures of $50,000 per year in 2012 and

2013, and $250,000 per year in 2014, 2015 and 2016.273

251. In response to undertaking 32, DERS provided 2014 actuals of $24,000 for customer

education and energy awareness.

252. The CCA submitted evidence setting out DERS’ forecast, estimated and actual customer

education and awareness costs for 2009 to 2016, recreated in Table 12 below:

273



58 • Decision 2957-D01-2015 (July 7, 2015)

Table 12. DERS customer education and awareness costs ($000s)

2009 2010 2011 2012 2013 2014 2015 2016

DERS forecast (2009-2011)

1,800 1,900 2,000


500 500 500


50 51.4 250 250 250

Estimate 0.0

Actual 93.8 86.3 199 65 0.0

AUC forecast 223.5 229.1 234.8

Source: Exhibit 0035.02.CCA-2957, CCA evidence, page 1.

253. The CCA stated that DERS has a history of over-forecasting customer education and

awareness costs and that DERS forecast an expenditure for 2013 even though it had none.

254. The CCA quoted Decision 2009-238, in which the Commission stated:

129. With regard to the costs for website/other/phone directories, the Commission

considers that these are generally acceptable. However, the Commission finds that DERS

has not explained why the 2009 forecasted amounts have increased so much from the

2008 approved figures. The Commission takes note of the 2008 actual amounts for this

cost item, as provided in the attachment to UCA-DERS-001(a), and notes that the actual

expenditures for the DRT in 2008 were approximately $176,000 and the actual

expenditures for the RRT in 2008 were approximately $41,000. The Commission finds

that these figures, along with the non-labour inflation rates approved in Section 4.3.1 of

this Decision, would be a good basis for the 2009-2011 forecasts.274

255. The CCA submitted that if the methodology from Decision 2009-238 is used in the

current proceeding, the result would be to allow DERS $65,000 for 2012 as an actual amount and

$0 for 2013 as an estimate and actual amount. As the 2013 amount is the latest actual amount,

the inflated amount for 2014 through 2016 would also be $0.275

256. The CCA initially submitted that DERS should be allowed $65,000 for 2012, $0 for 2013

and $50,000 for each year from 2014 through 2016, and stated that the CCA does not consider

that DERS is the appropriate party to undertake a customer education program.276 However, in its

argument, the CCA updated its submission to account for the $24,000 of actual expenditures in

2014 and submitted that DERS should be allowed $65,000 for 2012, $0 for 2013 and $24,000 for

each of 2014 through 2016.277

257. The UCA pointed out that DERS’ actual expenditures were $65,000, $0 and $24,200 for

2012, 2013 and 2014, respectively. The UCA recommended that the Commission use these

actual expenditures to determine DERS’ revenue requirement for those years. The UCA noted

274

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

Rate Tariffs, Proceeding 149, Application 1600749-1, December 3, 2009. 275

Exhibit 0035.02.CCA-2957, CCA evidence, page 2. 276





Decision 2957-D01-2015 (July 7, 2015) • 59

that DERS is seeking to recover more for each of 2015 and 2016 than it spent in the first three

years combined, and in 2014, DERS spent only $24,200 of its $250,000 forecast.278

258. The UCA further stated that DERS made significant expenditures of $86,000 and

$199,000 in this category in 2010 and 2011, respectively. However, the approved forecasts for

those years were still much higher at $229,100 and $234,800, respectively.279

259. The UCA also stated that DERS indicated, during the oral hearing, it does not have any

specific programs that it will implement in 2015 and 2016. The UCA argued that this, along with

DERS’ history of over-forecasting customer education expenses, suggests that the forecast

amounts of $250,000 for each of 2015 and 2016 is entirely unreasonable and completely

unnecessary.280

260. Lastly, the UCA argued that part of its mandate under the Government Organization Act

is to “inform and educate consumers about electricity and natural gas issues” and that there is,

therefore, no need for consumers to pay DERS to educate and inform them. In the absence of a

definitive program which clearly shows the benefit to customers, the UCA submitted that DERS

should not be entitled to recover any amount for customer education for the years 2015 and

2016.281

261. In its reply argument, DERS stated that:

In paragraphs 32 through 39 of its Argument the CCA argues that it wants DERS on full

deferral for costs, by resetting each year exactly to actuals. DERS has forecast its

customer education costs based on the best information it had available to it at the time

and finds this proposal by the CCA is highly regressive. As such, DERS requests that the

Commission approve $50,000 for 2012 through 2016 and not the actuals as requested by

the CCA.282

Commission findings

262. DERS did not provide any analysis or justification to support the initial forecasts of

$50,000 for each year, 2012 and 2013, and $250,000 for each year, 2014, 2015 and 2016; or the

updated forecast of $50,000 for each year, 2012 through 2016. In addition, during the oral

hearing, DERS could not identify any specific programs that it would implement to account for

these forecast costs.283

263. For 2012, 2013 and 2014, the Commission discussed approval of forecast versus actual

amounts in Section 4.2 of this decision. For the reasons highlighted in that section, and given

DERS’ failure to justify its requested $50,000 forecasts, the Commission directs DERS, in the

compliance filing, to update its customer education and energy awareness amounts to the actual

amounts incurred in 2012, 2013 and 2014.

264. The Commission also finds that there is insufficient evidence to support approval of

DERS’ requested forecast costs for customer education and awareness for the years 2015 and

278

Exhibit 2957-X0097, UCA public argument, paragraphs 242-243. 279







60 • Decision 2957-D01-2015 (July 7, 2015)

2016. Accordingly, the Commission finds, for the purposes of this decision, that the average of

the previous years’ actuals is the best predictor of costs in the final two test years, for the

purposes of this decision. Accordingly, the Commission directs DERS, in the compliance filing,

to update its forecast amounts in each of 2015 and 2016 to be equal to the average actual costs

from 2012, 2013 and 2014.

4.10 Cost of working capital

265. The need for working capital is a result of the lag between the receipt of revenue from

customers and the payment of expenses to suppliers. DERS defined its working capital revenue

requirements as “… the carrying costs required to fund DERS’ daily operations.”284

266. In determining the working capital revenue requirements DERS has separated the

calculations into two categories, cash working capital and working capital adjustments. Cash

working capital is comprised of the cash deficit forecast from the cash expenses exceeding the

cash receipts. Working capital adjustments include the cash balances or deficits related to the

budget payment plan (BPP), capital expenditures and hearing costs.285

267. DERS applied a rate of return to the cash working capital and working capital

adjustments in order to calculate its forecast working capital costs. In 2015 and 2016, DERS

based the rate of return on a debt/equity ratio of 61 per cent/39 per cent, a return on equity of

8.75 per cent, and a debt rate of 4.95 per cent.286

268. DERS determined the working capital ratios using the same lead-lag methodology as

previously utilized and accepted by the Commission. DERS updated the revenue lag information

for 2015 and 2016 with actual billing and payment data on all customer billings during the July

2012 to June 2013 period.287 Further information on the lead-lag process was provided during the

course of the proceeding.288

269. The forecast amounts for working capital for 2015 and 2016 are included in the following

table.

284





Exhibit 0018.01.DEML-2957, CCA-DERS-001 to CCA-DERS-017, Response to CCA-DERS-003, pages 4-6.


Decision 2957-D01-2015 (July 7, 2015) • 61

Table 13. Forecast costs for working capital for 2015 and 2016289

2015 forecast


($000s)

DRT: energy 860.4 839.1

DRT: non-energy 1,672.1 1,876.8

Total DRT 2,532.5 2,715.9

RRT: energy 53.7 51.2

RRT: non-energy 560.1 572.3

Total RRT 613.8 623.5


site basis, the actual costs for the “Working Capital” cost category for the non-energy operation

of the DRT for each of 2012 and 2013, to the corresponding forecast costs for each of 2012 and

2013.290 During the course of the proceeding, Mr. Bell updated his analysis to include a

comparison, on a cost per site basis, of the 2014 actual costs to the 2014 forecast costs for the

“Working Capital” cost category of the non-energy operation of the DRT.291


289

Sources are Exhibit X0074.09.DEML-2957, DERS amended DRT revenue requirement schedules,

Schedule 5.1, and Exhibit X0074.10.DEML-2957, DERS amended RRT revenue requirement schedules,

Schedule 5.2. 290


Exhibit 2957-X0075, Undertaking of Russ Bell at Transcript, Volume 5, page 756, lines 18-20.


62 • Decision 2957-D01-2015 (July 7, 2015)

Table 14. Variance analysis of “Working Capital” costs for the non-energy operation of the DRT on a cost per site basis292

Cost per site (DRT)

2012 Forecast $0.1711

2012 Actual $0.1164



2013 Forecast $0.2606

2013 Actual $0.2505



2014 Forecast $0.2490

2014 Actual $0.2434



2012-2014

Forecast $0.6807

Actual $0.6103



272. Based on this analysis, Mr. Bell, on behalf of the UCA, recommended that the 2015

forecast for “Working Capital” for the non-energy operation of the DRT of $1,672,100 be

reduced by 10.32 per cent, which is a reduction of $172,561. Mr. Bell also recommended that the

2016 forecast for “Working Capital” for the non-energy operation of the DRT of $1,876,800 be

reduced by 10.32 per cent, which is a reduction of $193,686. The CCA supported these

reductions.293

273. Noting that during the proceeding, DERS provided updates to the forecast electricity and

natural gas prices for 2015 and 2016, the CCA submitted that the BPP aspect of working capital

for 2015 and 2016 should be revised to reflect these updated forecasts, in order to use the most

up to date information.294 The UCA recommended that all relevant aspects of working capital for

2015 and 2016 be adjusted to reflect the updated forecast electricity and natural gas prices for

2015 and 2016.295

292




Exhibit 2957-X0097, UCA public argument, paragraph 240.


Decision 2957-D01-2015 (July 7, 2015) • 63

274. DERS stated that updating its working capital forecasts for 2015 and 2016 in the manner

suggested by the CCA and the UCA is retroactive ratemaking. It added that it has not used

deferral accounts since 2008 and it should not be treated as if it has.296

Commission findings

275. The Commission approves the results of the lead lag study and the resulting lag days that

are included in the amended application.297 No parties objected to the resulting lag days. The

Commission considers that the methodology DERS used to forecast its working capital is

reasonable and well established in the utility industry in Alberta.

276. While the analysis prepared by Mr. Bell accounts for the differences between the forecast

and actual number of sites in each of 2012, 2013 and 2014, there are other factors that come into

play when considering the differences between the actual working capital costs and the forecast

working capital costs. The supporting information provided by DERS for the forecast working

capital costs demonstrates that the factors involved in preparing the forecast include not only the

number of sites, but also estimates of the total gas costs and electricity costs for each year, the

total distribution tariffs for each year, and the estimated budget payment plan balances for each

year, to name a few.298 The Commission considers that a proper variance analysis should account

for the differences between the actuals and forecasts for each of the factors that determine the

working capital costs, in order to focus in on what is causing the forecasting error.

277. The Commission does not accept Mr. Bell’s recommendation for a 10.32 per cent

reduction to the 2015 and 2016 forecast amounts for working capital costs for the DRT because

Mr. Bell did not provide any detailed variance analysis for 2012, 2013 and 2014.

278. However, the Commission finds that more recent information is available which changes

the forecasts for 2015 and 2016. Accordingly, the Commission directs DERS to update the

forecasts for 2015 and 2016 by incorporating not only the more recent information on the record

of this proceeding, but also the revisions to the other applicable factors that are used in the

forecast of working capital. This includes updating the forecast gas and electricity prices to

incorporate the information provided during the oral hearing.299 The Commission considers that

requiring DERS to update this information is not retroactive ratemaking, for the reasons set out

in Section 4.2 of this decision. With regard to DERS’ comment that it should not be treated as if

it has deferral accounts, the Commission considers that DERS did not offer any explanation as to

why this comment is relevant in this situation. DERS has not demonstrated any relationship

between deferral accounts and the requirement to update forecasts.

279. The Commission considers that the rate of return and debt/equity ratios used by DERS in

its calculation of the forecast working capital costs for 2015 and 2016 should also be updated to

reflect the recent Commission decision on the 2013 generic cost of capital, that being

296


Exhibit 0074.09.DEML-2957, DERS amended DRT revenue requirement schedules, Schedule 5.1.4. and

Exhibit 0074.10.DEML-2957, DERS amended RRT revenue requirement schedules, Schedule 5.2.4. 298

Exhibit 0074.09.DEML-2957, DERS amended DRT revenue requirement schedules, Schedule 5.1.3. and

Exhibit 0074.10.DEML-2957, DERS amended RRT revenue requirement schedules, Schedule 5.2.3. 299

This information was provided in response to an undertaking during the oral hearing. It was submitted under the

confidentiality module and was assigned confidential exhibit number 67.


64 • Decision 2957-D01-2015 (July 7, 2015)

Decision 2191-D01-2015.300 This will enable DERS to reflect the actual rate of return and

debt/equity structure for 2015, and to use those figures as the most recent forecast for 2016.

280. The Commission therefore directs DERS, in its compliance filing, to update the forecasts

for working capital costs for 2015 and 2016 to incorporate all other applicable updated forecasts

for 2015 and 2016, to incorporate the monthly natural gas and electricity prices for 2015 and

2016, as set out in the information provided as part of confidential exhibit number 67, and to

update the rate of return and debt/equity figures as approved in Decision 2191-D01-2015. The

Commission further directs DERS to include, as part of its compliance filing, supporting

calculations for the weighted average cost of capital figure it uses for 2015 and 2016.

4.11 Bad debt and penalty revenue

281. DERS’ bad debt exposure encompasses all aspects of a customer’s bill, including the

commodity costs, energy and non-energy administration charges and distribution tariff costs.301

DERS tracks and forecasts three cost components under the “Bad Debt” cost category for the

DRT, being bad debt expense, cut-off for non-payment and commissions paid to external

collection agencies. The two cost components for the RRT are bad debt expense and the

commissions paid to external collection agencies.

282. The forecast amounts for the “Bad Debt” cost category for 2015 and 2016 are included in

the following table.

Table 15. Forecast costs in the “Bad Debt” cost category for 2015 and 2016302

2015 forecast


($000s)

DRT: energy 3,688.8 3,673.1

DRT: non-energy 3,793.6 3,777.5

Total DRT 7,482.4 7,450.6

RRT: energy 1,027.8 1,077.7

RRT: non-energy 1,644.6 1,724.3

Total RRT 2,672.4 2,802.0

283. The first cost component is bad debt expense. DERS derived the forecast bad debt

expense component using the historical percentages of revenue data from 2009 to 2013.303 The

annual average over this five-year period was 0.61 per cent for the DRT and 0.71 per cent for the

RRT. DERS added a 0.05 per cent risk adjustment to these averages to account for the expected

attrition over the test period, which resulted in the forecast percentages for 2015 and 2016 being

0.66 per cent for the DRT and 0.76 for the RRT.304

300

Decision 2191-D01-2015: 2013 Generic Cost of Capital, Proceeding 2191, Application 1608918-1, March 23,

2015. 301


Exhibit X0074.09.DEML-2957, DERS amended DRT revenue requirement schedules, Schedule 5.1, and

Exhibit X0074.10.DEML-2957, DERS amended RRT revenue requirement schedules, Schedule 5.2. 303


Exhibit 0020.01.DEML-2957, AUC-DERS-001 to AUC-DERS-042, response to AUC-DERS-021, page 23.

http://www.auc.ab.ca/applications/decisions/Decisions/2015/2191-D01-2015.pdfl


Decision 2957-D01-2015 (July 7, 2015) • 65

284. DERS indicated that the 2012 actual bad debt expense level was somewhat of an

anomaly, and there were factors that contributed to the actual bad debt expense for 2012 being

lower than forecast. These factors include a significant reduction in site counts during the year,

lower than anticipated gas prices which resulted in lower average billings, a strong economy and

one-time benefits associated with the collection of historical bad debts for the years from 2009 to

2011.305

285. The cut-off for non-payment cost component for the DRT are costs paid to ATCO Gas to

perform additional gas site cut-offs for non-payment. DERS pays for additional capacity to

ensure accounts that fall into a particular credit state are treated accordingly.

286. The remaining component is the commissions paid to external collection agencies. DERS

employs collection agencies forty five days after a final bill has been issued to ensure payment

and management of these accounts. With the continued switching behaviour in the market,

DERS stated that it expects to incur collection agency fees similar to the actual experience in

2012 and year to date 2013.306

287. The forecast cost of the commissions paid to external collection agencies for 2014, 2015

and 2016 is the average of the 2012 actual costs, the 2013 estimated costs, the 2012 forecast

costs, and the 2013 forecast costs, to which DERS applied an inflation factor in each of 2014,

2015 and 2016 of 2.75 per cent.307

288. Both bad debt (which DERS described as defaulted payments) and penalty revenue

(which DERS described as delayed payments) reflect the customer’s inability or unwillingness to

pay on a timely basis. As a result, the customer’s accounts receivable balance is now in arrears.

While the accounts receivable balance ages, DERS stated that it will charge the customer penalty

revenue on the outstanding balance due. DERS added that if the customer finally defaults on the

payment, the charged amount for penalty revenue plus the original in the arrears accounts

receivable balance will be written off as bad debt. DERS cautioned that delay of payment does

not necessarily mean default of payment, as in the case where a customer pays a balance in full,

including any penalty revenue that has been added.308

289. DERS derived its penalty revenue forecast consistent with the approach used to forecast

bad debts, utilizing the five-year average.309 The resulting forecast percentage of revenue figures

are -0.35 per cent for the DRT and -0.45 per cent for the RRT.310

290. The forecast amounts for the “Penalty Revenue” category for 2015 and 2016 are included

in the following table.

305



Exhibit 0019.01.DEML-2957, UCA-DERS-001 to UCA-DERS-029, response to UCA-DERS-020(f), page 39. 308





66 • Decision 2957-D01-2015 (July 7, 2015)

Table 16. Forecast amounts in the “Penalty Revenue” category for 2015 and 2016311

2015 forecast


($000s)

DRT: energy (1,582.2) (1,563.7)

DRT: non-energy (1,627.2) (1,608.2)

Total DRT (3,209.4) (3,171.9)

RRT: energy (530.0) (557.4)

RRT: non-energy (848.0) (891.9)

Total RRT (1,378.0) (1,449.3)


site basis, the actual costs for the “Bad Debt” cost category for both the energy and non-energy

operations of the DRT for each of 2012 and 2013, to the corresponding forecast costs for each of

2012 and 2013.312 During the course of the proceeding, Mr. Bell updated his analysis to include a

comparison, on a cost per site basis, of the 2014 actual costs to the 2014 forecast costs for the

“Bad Debt” cost category for both the energy and non-energy operations of the DRT.313


311

Sources are Exhibit X0074.09.DEML-2957, DERS amended DRT revenue requirement schedules,

Schedule 5.1, and Exhibit X0074.10.DEML-2957, DERS amended RRT revenue requirement schedules,

Schedule 5.2. 312




Decision 2957-D01-2015 (July 7, 2015) • 67

Table 17. Variance analysis of “Bad Debt” costs for the DRT on a cost per site basis314

Cost per site (DRT): energy Cost per site (DRT): non-energy

2012 Forecast $0.4205 $0.4325

2012 Actual $0.2366 $0.2892

Difference ($) $0.1839 $0.1433

Difference (%) 43.74% 33.14%

2013 Forecast $0.4671 $0.4804

2013 Actual $0.4200 $0.4319

Difference ($) $0.0471 $0.0485

Difference (%) 10.08% 10.08%

2014 Forecast $0.4794 $0.4930

2014 Actual $0.6494 $0.6678

Difference ($) ($0.1700) ($0.1748)

Difference (%) -35.45% -35.45%

2012-2014

Forecast $1.3670 $1.4059

Actual $1.3060 $1.3889

Difference ($) $0.0610 $0.0170

Difference (%) 4.47% 1.21%

293. Based on this analysis, Mr. Bell, on behalf of the UCA, recommended that the 2015

forecast of $3,688,800 for the “Bad Debt” cost category for the energy operations of the DRT be

reduced by 4.47 per cent, which is a reduction of $164,889. Mr. Bell also recommended that the

2016 forecast of $3,673,100 for the “Bad Debt” cost category for the energy operations of the

DRT be reduced by 4.47 per cent, which is a reduction of $164,188. Also based on this analysis,

Mr. Bell recommended that the 2015 forecast of $3,793,600 for the “Bad Debt” cost category for

the non-energy operations of the DRT be reduced by 1.21 per cent, which is a reduction of

$45,903. Mr. Bell also recommended that the 2016 forecast of $3,777,500 for the “Bad Debt”

cost category for the non-energy operations of the DRT be reduced by 1.21 per cent, which is a

reduction of $45,708.315 The CCA supported these proposed reductions.316

294. In its evidence, the CCA argued that the 0.05 per cent risk adjustment that DERS added

to its bad debt expense forecast methodology is not reasonable. It stated that DERS is already

compensated for risk through the equity ratio and the allowed rate of return. It added that DERS

has not provided any support or justification for the 0.05 per cent, and that the revenue

314





68 • Decision 2957-D01-2015 (July 7, 2015)

requirement already reflects possible attrition through customer number forecasts and bad

debts.317

295. The CCA stated that in past decisions the Commission has clearly set out that utility

specific risks are adjusted through the equity ratio. The CCA cited material from Decision 2004-

052318 and Decision 2011-474319 in support of its statement. The CCA submitted that adding risk

factors in addition to the return on sales that DERS currently receives would be double

counting.320

296. The CCA indicated that DERS provided no information respecting the calculation or

derivation of the 0.05 per cent risk adjustment. It added that DERS did not provide any examples

of such a measure being used in other proceedings or jurisdictions. Finally, the CCA submitted

that DERS provided no explanation of how this 0.05 per cent adjustment relates to or varies with

customer attrition.321 The UCA agreed with the conclusions of the CCA with regard to the 0.05

per cent risk adjustment factor being unsupported, and the UCA recommended that the

Commission deny this adjustment factor.322

297. The CCA disagreed with the methodology DERS used to forecast the commissions paid

to external collection agencies. The CCA stated that receivables are amounts owing, irrespective

of the year billed. It added that therefore, the commissions paid during the one time cleanup in

2012 are more than likely due to multiple years of accounts in arrears. The CCA recommended

that either the 2011 approved forecast percentage or the 2011 actual percentage be used to

forecast the commissions paid to external collection agencies. The CCA submitted that DERS

made this same submission, and the CCA included the following as support:

DERS has previously explained that 2012 is an anomaly in terms of bad debt collections,

due to the large receivables initiative that was successfully implemented in 2012. This

one time cleanup of old receivables cannot be replicated into the future. In order to

compare 2013 performance before and after the increase in collection agency fees, 2011

is the best year to examine.323

298. Noting that during the proceeding DERS provided updates to the forecast electricity and

natural gas prices for 2015 and 2016, the CCA submitted that the bad debt forecasts and the

penalty revenue forecasts for 2015 and 2016 should be revised to reflect these updated forecasts,

in order to use the most up to date information.324 The UCA made the same recommendation,

stating that this updated information takes into account the new reality of the Alberta economy.325

299. DERS responded that the 0.05 per cent risk adjustment factor accounts for the fact that

the credit quality of the customers that remain on the regulated rate diminishes over time, since

317


Decision 2004-052: Generic Cost of Capital, AltaGas Utilities Inc., AltaLink Management Ltd, ATCO Electric

Ltd. (Distribution), ATCO Electric Ltd. (Transmission), ATCO Gas, ATCO Pipelines, ENMAX Power

Corporation (Distribution), EPCOR Distribution Inc., EPCOR Transmission Inc., FortisAlberta (formerly

Aquila Networks), NOVA Gas Transmission Ltd., Application 1271597-1, July 2, 2004. 319

Decision 2011-474: 2011 Generic Cost of Capital, Proceeding 833, Application 1606549-1, December 8, 2011. 320




Exhibit 0019.01.DEML-2957, UCA-DERS-001 to UCA-DERS-029, response to UCA-DERS-020(e), page 39. 324

Exhibit 2957-X0094, CCA public argument, paragraphs 20 and 30. 325






Decision 2957-D01-2015 (July 7, 2015) • 69

these customers encompass those who cannot choose a competitive retailer for credit reasons.

DERS added that when customers on a competitive contract default on their payments, the

customer is deselected by the competitive retailer and moved back to the regulated retailer, and

the customer then becomes a bad debt risk for DERS to manage. DERS stated that the

0.05 per cent risk adjustment factor is equal to approximately half of the standard deviation seen

in the bad debt percentages over the five-year historical period from 2009 to 2013.326

300. DERS submitted that its return on equity is deducted from its overall return, and therefore

the substantial business risk inherent in bad debt volatility has not been included in its allowed

return, which means that requesting a risk adjustment factor of 0.05 per cent is not double

counting.327

301. DERS contended that the updated commodity costs should not be incorporated into the

bad debt forecasts and the penalty revenue forecasts. DERS added that it has accepted the risk on

commodity curve price movements, and accepting the CCA’s submission would set a dangerous

precedent that could lead to future demands that entire regulated forecasts be recalculated at the

last possible minute, thereby rendering irrelevant the months of proceedings required to generate

proper rates for customers.328

302. DERS argued that the CCA’s suggestion that the commissions paid to external collection

agencies should be managed to the levels in 2011 is unreasonable. It added that with a few

exceptions, it has maintained a largely consistent collections practice year over year. DERS

explained that the reason why the collection agency fees have increased is because of increases

in the dollar amount of the unpaid bills that have been assigned to the collection agencies. DERS

stated that the higher the commissions, the greater the amount of collections that are occurring,

which helps to reduce bad debts.329

Commission findings

303. The Commission rejects the forecast methodology proposed by DERS for the bad debt

expense component of the “Bad Debt” cost category. DERS’ use of a five-year average of 2009,

2010, 2011, 2012 and 2013 does not accurately represent more recent experience, especially

given the efforts undertaken by DERS in 2012 to reduce the old receivable amounts. In addition,

the information used by DERS for 2013 was not complete year actual data, but included two

months of estimates.330 Further, the use of data from 2009, 2010 and 2011 does not incorporate

the concerns raised by DERS about increased bad debt credit risk due to the expected attrition

over the test period.

304. The Commission considers that a more reasonable forecasting methodology for the bad

debt expense component of the “Bad Debt” cost category is to base this forecast on the actual

experience for the years 2012, 2013 and 2014. This will permit any concerns with respect to

increased bad debt credit risk to be addressed, and would eliminate the need for the separate

forecast risk adjustment factor of 0.05 per cent. The Commission considers that if there is

increased bad debt risk, it will be demonstrated in the actual bad debt percentages for 2012, 2013

and 2014. Consequently, the Commission directs DERS, as part of its compliance filing, to

326



Exhibit 2957-X0103, DERS public reply argument, paragraphs 191 and 198. 329

Exhibit 2957-X0103, DERS public reply argument, paragraphs 194-197. 330

Exhibit 0020.01.DEML-2957, AUC-DERS-001 to AUC-DERS-042, response to AUC-DERS-021, page 23.


70 • Decision 2957-D01-2015 (July 7, 2015)

forecast the bad debt percentages for the DRT and the RRT for 2015 and 2016, using the actual

weighted average percentage for the years 2012, 2013 and 2014. The Commission further directs

DERS, as part of the compliance filing, to include supporting details for the forecast bad debt

expense percentages included for 2015 and 2016.

305. The Commission does not agree with the methodology DERS used to forecast

commissions paid to external collection agencies for 2015 and 2016. Specifically, the

methodology averages 2012 actual, 2013 estimate (i.e., annualized January 2013 to October 2013

actuals), 2012 forecast, and 2013 forecast commissions paid, and then inflates the result by 2.75

per cent to arrive at forecasts for 2015 and 2016. The Commission considers that DERS has not

explained why the use of any information besides 2012 actual and 2013 estimate should be used

– averaging actual with forecast amounts from the same period does not make sense given that

actual data supersedes forecast data.

306. The Commission agrees with the CCA that a better way to forecast the commissions paid

to external collection agencies is to use a percentage of revenue approach. While there may not

be a direct relationship between the total revenues and the commissions paid to external

collection agencies, DERS itself indicated that one of the reasons why the actual costs have

increased is because of the dollar amount of unpaid bills that DERS assigns to external collection

agencies. The Commission considers that the dollar amount of unpaid bills is dependent

somewhat on the total amount of the bills. The greater the total amount of the bills the greater the

dollar amount of unpaid bills, assuming the percentage remains constant. Using a percentage of

revenue approach as the forecast methodology will reflect this partial dependence.

307. In addition, the use of a percentage of revenue approach to forecast the commissions paid

to external collection agencies is consistent with the methodology that is used to forecast bad

debt expense. The amounts collected by the external collection agencies are offset against the

bad debt expense, so the Commission considers that it follows that the commissions paid to the

external collection agencies, which are based on the amounts collected, should be forecast using

the same methodology used to forecast bad debt expense.

308. The Commission does not agree with the CCA that the approved percentage should be

based on either the 2011 approved percentage or the 2011 actual percentage because it is

unreasonable to expect DERS to manage the commissions paid to external collection agencies

for the years 2015 and 2016 at the levels experienced four to five years previously. Basing the

forecasts for 2015 and 2016 on levels from 2011 does not permit DERS to incorporate the latest

information that is available, and is not in keeping with the Commission’s findings in Section 4.2

of this decision.

309. The Commission considers that a reasonable methodology for forecasting the

commissions paid to external collection agencies for 2015 and 2016 is to base this forecast on the

actual experience for 2012, 2013 and 2014. Consequently, the Commission directs DERS, as part

of its compliance filing, to forecast the commissions paid to external collection agencies for the

DRT and the RRT for 2015 and 2016, using the actual weighted average percentage that these

costs are of the total revenues for the years 2012, 2013 and 2014. The Commission further

directs DERS, as part of the compliance filing, to include supporting details for the forecast

percentages included for 2015 and 2016.


Decision 2957-D01-2015 (July 7, 2015) • 71

310. Mr. Bell’s analysis focused on the variance between the actual costs and the forecast

costs for the entire “Bad Debt” cost category, but did not focus on the differences in the

percentage factors, or the separate cost components that make up the costs in the “Bad Debt”

cost category. While Mr. Bell recommended specific dollar amount reductions in 2015 and 2016

for the entire “Bad Debt” cost category, the Commission considers that the revisions it has

directed DERS to make to the methodologies for forecasting bad debt expense and the

commissions paid to external collection agencies will result in more representative forecasts for

2015 and 2016.

311. With respect to the penalty revenue, the Commission agrees with DERS that the forecast

methodology for this cost category should be consistent with the approach used to forecast bad

debt expense. Consequently, the Commission directs DERS, as part of its compliance filing, to

forecast the penalty revenue percentages for the DRT and the RRT for 2015 and 2016, using the

actual weighted average percentage for the years 2012, 2013 and 2014. The Commission further

directs DERS, as part of the compliance filing, to include supporting details for the forecast

percentages included for 2015 and 2016.

312. Regarding the submissions of the UCA and the CCA to update the bad debt expense and

the penalty revenue forecasts to incorporate the updated monthly natural gas and electricity price

forecasts for 2015 and 2016, the Commission agrees that this information should be

incorporated, not only for the bad debt expense and the penalty revenue, but also the

commissions paid to external collection agencies. In Section 4.10 of this decision, the

Commission has directed DERS to update the working capital forecasts for 2015 and 2016 to

incorporate the latest forward price index forecasts that are on the record of this proceeding.331

This will have an impact on the forecast total revenues for 2015 and 2016 that DERS applies its

forecast bad debt percentages against, applies its forecast commissions paid to external collection

agencies percentages against, and applies its forecast penalty revenue percentages against.

313. In addition, in Section 4.3 of this decision, the Commission has directed DERS to update

the site forecasts for 2015 and 2016 to use the 2014 actuals as a starting point. This will result in

a revision to the forecast number of sites for 2015 and 2016 which will also result in a revision to

the forecast total revenues for 2015 and 2016 that DERS applies its forecast bad debt percentages

against, applies its forecast commissions paid to external collection agencies percentages against,

and applies its forecast penalty revenue percentages against.

314. The Commission therefore directs DERS, as part of the compliance filing, to update the

forecast costs for bad debt expense for 2015 and 2016, to update the forecast costs for the

commissions paid to external collection agencies for 2015 and 2016, and to update the forecast

penalty revenue for 2015 and 2016, to incorporate the updated forward price index forecasts for

2015 and 2016, to incorporate the updated number of forecast sites for 2015 and 2016, and to

incorporate the percentage factors directed previously. This information should be included as

part of the updated schedules 5.1.12 and 5.2.12 that DERS will submit as part of the compliance

filing.

331

Confidential Exhibit 67, NGX forward curves provided in response to undertakings 17, 18 and 19.


72 • Decision 2957-D01-2015 (July 7, 2015)

4.12 Unbillable revenues

315. Historically DERS has included unbillable revenue in the “Revenue Offsets” costs

category, but for this application DERS chose to disclose unbilled revenue as a separate cost

category. DERS described unbillable revenue as follows:

Unbillable revenue arises when utility services are provided to a premise but the site has

no identifiable customer(s) that can be billed for services provided.332

316. DERS indicated that this situation can occur when a location/address is vacated or sold

and there is a gap in time between the former customer ending service and the new customer

being enrolled. Unbillable revenue will vary based on the frequency of customers changing site

locations and the associated revenues per site. DERS stated that it forecast unbillable revenues

for 2012-2016 based on the historical five-year trend from 2009 through 2013.333 DERS added

that, considering the large volatility experienced in the historical actuals for unbillable revenue

and a five-year test period that DERS is proposing, utilizing a five-year average is appropriate.334

317. DERS submitted that it had conducted an analysis to identify the process, reporting and

operational changes that may assist it in locating the responsible customers for billing purposes

to help ensure that disconnection of vacant sites is dealt with appropriately. It added that this

program was completed within the 2012 time frame, which resulted in a significant variance in

the 2012 actual unbillable levels when compared to the levels from previous years.335

318. DERS provided details of the calculations it made to arrive at the forecast percentages for

unbilled revenue of 0.23 per cent for the DRT and 0.29 per cent for the RRT.336

319. The forecast amounts for unbillable revenue for 2015 and 2016 are included in the

following table.

Table 18. Forecast unbillable revenue for 2015 and 2016337

2015 forecast ($000s) 2016 forecast ($000s)

DRT 2,081.8 2,057.5

RRT 869.8 914.8

Total 2,951.6 2,972.3


site basis, the actual costs for the “Unbillable Revenue” cost category for both the DRT and the

RRT for each of 2012 and 2013, to the corresponding forecast costs for each of 2012 and 2013.338

During the course of the proceeding, Mr. Bell updated his analysis to include a comparison, on a

332



Exhibit 0020.01.DEML-2957, AUC-DERS-001 to AUC-DERS-042, response to AUC-DERS-023, page 25. 335



Exhibit X0074.09.DEML-2957, DERS amended DRT revenue requirement schedules, Schedule 5.1, and

Exhibit X0074.10.DEML-2957, DERS amended RRT revenue requirement schedules, Schedule 5.2. 338

Exhibit 0029.02.DEML-2957, UCA evidence.


Decision 2957-D01-2015 (July 7, 2015) • 73

cost per site basis, of the 2014 actual costs to the 2014 forecast costs for the “Unbillable

Revenue” cost category for both the DRT and the RRT.339


Table 19. Variance analysis of “Unbillable Revenue” costs for the DRT and the RRT on a cost per site basis340

Cost per site (DRT) Cost per site (RRT)

2012 Forecast $0.2323 $0.4934

2012 Actual $0.1057 $0.2339

Difference ($) $0.1266 $0.2595

Difference (%) 54.52% 52.60%

2013 Forecast $0.2622 $0.5260

2013 Actual $0.1145 $0.2210

Difference ($) $0.1477 $0.3050

Difference (%) 56.31% 57.98%

2014 Forecast $0.2717 $0.5492

2014 Actual $0.1899 $0.2318

Difference ($) $0.0818 $0.3174

Difference (%) 30.10% 57.80%

2012-2014

Forecast $0.7662 $1.5686

Actual $0.4101 $0.6867

Difference ($) $0.3561 $0.8819

Difference (%) 46.47% 56.22%

322. Based on this analysis, Mr. Bell recommended that the 2015 forecast for “Unbillable

Revenue” for the DRT of $2,081,800 be reduced by 46.47 per cent, which is a reduction of

$967,412. Mr. Bell also recommended that the 2016 forecast for “Unbillable Revenue” for the

DRT of $2,057,500 be reduced by 46.47 per cent, which is a reduction of $956,120. Also based

on this analysis, Mr. Bell recommended that the 2015 forecast for “Unbillable Revenue” for the

RRT of $869,800 be reduced by 56.22 per cent, which is a reduction of $489,002. Mr. Bell also

recommended that the 2016 forecast for “Unbillable Revenue” for the RRT of $914,800 be

reduced by 56.22 per cent, which is a reduction of $514,301.341 The CCA supported these

reductions342 and the UCA recommended the same reductions.343

339







74 • Decision 2957-D01-2015 (July 7, 2015)

Commission findings

323. The Commission rejects the forecast methodology proposed by DERS for the following

reasons. DERS’ use of a five-year average does not adequately account for more recent

experience, especially given the efforts undertaken by DERS in 2012 to reduce unbillable

revenue. Further, the forecast methodology DERS used does not allow for the preparation of any

variance explanations with respect to either of the two factors advanced by DERS, being the

frequency with which customers change site locations, and the associated revenues per site. No

other methodology was put forward.

324. The Commission considers that a more reasonable forecasting methodology for

unbillable revenue, based on historical actuals, should consider the actual number of sites that

were unable to be billed during the course of a year, the associated period for which the site was

unable to be billed, and the associated revenue. Using this information as the basis for the

forecast would permit DERS to forecast these components, and then compare the actual results

for each component to the corresponding forecast.

325. Mr. Bell’s analysis supports the Commission’s findings with respect to DERS’ forecast

methodology, because it demonstrates that there were significant differences between the

forecast and actual unbillable revenues for 2012, 2013 and 2014. The actual amounts for each of

2012, 2013 and 2014 were much less than the forecast amounts for these years, which means that

the percentage factors that DERS used to forecast unbillable revenue for 2012, 2013 and 2014

were too high. The Commission finds that these percentages should be reduced in determining

the unbillable revenue forecasts for 2015 and 2016.

326. Applying Mr. Bell’s recommended reduction of 46.47 per cent to the 0.23 per cent factor

used by DERS in its forecast of unbillable revenue for DRT results in a factor of 0.12 per cent

for the DRT. Applying Mr. Bell’s recommended reduction of 56.22 per cent to the 0.29 per cent

factor used by DERS in its forecast for unbillable revenue for RRT results in a factor of 0.13 per

cent for the RRT. While no information is available on the record about the actual percentages

for 2014, the actual information for 2012 and 2013 is on the record. The actual percentage of

unbillable revenue to total revenue for 2012 and 2013 for the DRT was 0.11 per cent for 2012

and 0.10 per cent for 2013.344 The actual percentage of unbillable revenue to total revenue for

2012 and 2013 for the RRT was 0.13 per cent for 2012 and 0.12 per cent for 2013.345


costs, but did not focus on the differences in the percentage factors. The annual average

percentage factor for the DRT for 2012 and 2013, based on actuals, is 0.11 per cent346 while the

corresponding factor for the RRT is 0.13 per cent.347 The Commission directs DERS to use these

factors in forecasting its unbillable revenue for 2015 and 2016.

328. While Mr. Bell recommended specific dollar amount reductions in 2015 and 2016, the

Commission considers that a better approach is for DERS to update the forecasts for 2015 and

2016 and incorporate the more recent information on the record of this proceeding. In Section

4.10 of this decision, the Commission has directed DERS to update the working capital forecasts

344

Exhibit 0074.09.DEML-2957, DERS amended DRT revenue requirement schedules, Schedule 5.1.12, line 20. 345

Exhibit 0074.10.DEML-2957, DERS amended RRT revenue requirement schedules, Schedule 5.2.12, line 20. 346

Average of the 2012 actual amount of 0.11 and the 2013 actual amount of 0.10 per cent, rounded up. 347

Average of the 2012 actual amount of 0.13 and the 2013 actual amount of 0.12 per cent, rounded up.


Decision 2957-D01-2015 (July 7, 2015) • 75

for 2015 and 2016 with the latest forward price index forecasts on the record of this proceeding.

The Commission considers that this will have an impact on the forecast total revenues for 2015

and 2016 to which DERS applies its forecast unbillable revenue percentage.



a revision to the forecast number of sites for 2015 and 2016, which will also result in a revision

to the forecast total revenues for 2015 and 2016 to which DERS applies its forecast unbillable

revenue percentage.


forecasts for the “Unbillable Revenue” cost category for 2015 and 2016, to incorporate the

updated forward price index forecasts for 2015 and 2016, the updated number of forecast sites

for 2015 and 2016, a percentage factor of 0.11 per cent for the DRT and a percentage factor of

0.13 per cent for the RRT. This information should be included as part of the updated schedules

5.1.12 and 5.2.12 that DERS will submit as part of the compliance filing.

4.13 Other administration costs

331. This cost category includes all bank charges, office supplies, facility costs, travel and

expense items, training and development costs, memberships, professional dues, consulting

costs, auditing and compliance reporting requirements, as well as annual operating costs

associated with certain capital projects. DERS develops other administration costs for each

department.348 Inflation of 2.75 per cent was applied in 2015 and 2016 to all areas of other

administration costs except for bank charges and rent.349 DERS submitted material explaining the

reasons for the forecast increases in 2014, 2015 and 2016.350

332. The forecast amounts for 2015 and 2016 are as follows:

Table 20. Other administration costs forecasts for 2015 and 2016351


DRT 2,208.2 2,265.8

RRT 923.3 948.0

Total 3,131.5 3,213.8

333. Using the actual costs for 2010, 2011, 2012, 2013 and 2014, the UCA calculated that the

annual average costs over this five-year period for the “Other Administration Costs” category are

$1,865,900 for the DRT and $817,800 for the RRT.352

334. The UCA submitted that in light of the economic climate and a declining customer base,

a reasonable forecast for this cost category for the DRT for 2015 and 2016 should be no more

than $1,858,700 for each year.353 For the same reasons, the UCA submitted that a reasonable

348




Source is Exhibit X0001.00.DEML-2957, 2012-2016 DRT and RRT application, page 73. 352

Exhibit 2957-X0097, UCA public argument, paragraphs 251 and 256. 353



76 • Decision 2957-D01-2015 (July 7, 2015)

forecast for this cost category for the RRT for 2015 and 2016 should be no more than $817,400

for each year.354 The UCA added that this cost category should not be increasing given current

economic circumstances in Alberta.355

Commission findings

335. While the UCA recommended approving no more than $1,858,700 in each of 2015 and

2016 for the DRT, and no more than $817,400 in each of 2015 and 2016 for the RRT, it also

recommended that inflation for 2015 be set at 0.1 per cent and that inflation for 2016 be set at

2.4 per cent, and that these inflation values be used in determining the forecast costs for 2015

and 2016, including the costs in the “Other Administration Costs” cost category.356

336. In Section 4.1 of this decision, the Commission directed DERS to use forecast inflation

rates of 0.1 per cent for 2015 and 2.4 per cent for 2016 for the costs in the “Other Administration

Costs” cost category.

337. The Commission considers that the forecast methodology for this cost category

recommended by the UCA is not adequately representative of the economic climate and the

declining customer base that the UCA references. Using actuals for the five years from 2010 to

2014 as the basis for the 2015 and 2016 forecasts would not be as representative of the current

economic climate and trends with respect to customer retention as the use of actuals from a more

recent time period. The Commission finds that it is reasonable for DERS to base its forecast

costs for the “Other Administration Costs” for 2015 and 2016 on the average of the actual costs

for the three years from 2012 to 2014.

338. The UCA recommended that the actuals for 2012, 2013 and 2014 be approved as forecast

amounts for those years, and has not recommended any disallowances of 2012, 2013 or 2014

actual costs. In addition, the UCA did not provide any reason as to why a five-year average

should be used, as opposed to a three-year average. The Commission considers that the three-

year period from 2012 to 2014 is more representative of the recent economic climate and the

declining customer base that the UCA refers to, as opposed to the five-year period from 2010 to

2014.

339. The Commission directs DERS, as part of the compliance filing, to calculate the forecast

costs for 2015 for the “Other Administration Costs” cost category using the average of the actual

annual costs for this cost category for the three years 2012, 2013 and 2014, separately for the

DRT and the RRT, and applying inflation of 0.1 per cent. The Commission directs DERS, as part

of the compliance filing, to calculate the forecast costs for 2016 for the “Other Administration

Costs” cost category by using the 2015 forecast amounts and applying inflation of 2.4 per cent.

The Commission further directs DERS, as part of the compliance filing, to provide the necessary

documentation that supports the calculated forecast amounts for 2015 and 2016.

4.14 Merchant fees

340. DERS also refers to merchant fees as credit card transaction fees. It added that it

continues to offer the use of credit cards as a payment option, and has found that there is an

expectation that credit cards be accepted as a form of payment. DERS considers that this is an

354





Decision 2957-D01-2015 (July 7, 2015) • 77

important payment alternative for customers. It submitted that this additional payment flexibility

is a valuable option for vulnerable customers and may also help third parties to make payments

on behalf of customers who will have service disconnected due to non-payment.357

341. DERS stated that in 2011, approximately 5.5 per cent of total DRT and RRT customers

chose the credit card payment option. DERS added that it expects continued interest in this

payment option for both DRT and RRT customers, and it forecast a modest increase of five per

cent over the 2011 levels for each of 2012, 2013, 2014, 2015 and 2016. It added that the dollar

value of the merchant fees costs decreases over the test period due to the expected decline in the

number of sites.358

342. DERS provided details of the calculations it made to arrive at the forecast amounts for

merchant fees for 2014, 2015 and 2016.359 In conjunction with providing the details of the

calculations, DERS advised that it had identified an error in the DRT merchant fee forecasts for

2014, 2015 and 2016.360 The forecast amounts for 2015 and 2016 for merchant fees, including the

revised DRT amounts for 2015 and 2016, are included in the following table.

Table 21. Forecast merchant fees costs for 2015 and 2016361


DRT 1,075.1 1,091.5

RRT 257.5 256.3

Total 1,332.6 1,347.8


site basis, the actual costs for the “Merchant Fees” cost category for the RRT for each of 2012

and 2013, to the corresponding forecast costs for each of 2012 and 2013.362 During the course of

the proceeding, Mr. Bell updated his analysis to include a comparison, on a cost per site basis, of

the 2014 actual costs to the 2014 forecast costs for the “Merchant Fees” cost category for the

RRT.363


357





Exhibit X0001.00.DEML-2957, 2012-2016 DRT and RRT application, page 51, and Exhibit 0020.01.DEML-

2957, AUC-DERS-001 to AUC-DERS-042, response to AUC-DERS-041, page 47. 362




78 • Decision 2957-D01-2015 (July 7, 2015)

Table 22. Variance analysis of “Merchant Fees” costs for the RRT on a cost per site basis364

Cost per site

2012 Forecast $0.1771

2012 Actual $0.1207



2013 Forecast $0.1798

2013 Actual $0.1367



2014 Forecast $0.1740

2014 Actual $0.2036

Difference ($) ($0.0296)

Difference (%) -16.98%

2012-2014

Forecast $0.5309

Actual $0.4610



Based on this analysis, Mr. Bell, on behalf of the UCA, recommended that the 2015 forecast for

“Merchant Fees” for the RRT of $257,500 be reduced by 13.19 per cent, which is a reduction of

$33,964. Mr. Bell also recommended that the 2016 forecast for “Merchant Fees” for the RRT of

$256,300 be reduced by 13.19 per cent, which is a reduction of $33,806.365 The CCA supported

these reductions.366

Commission findings

345. While the analysis prepared by Mr. Bell accounts for the differences between the forecast

and actual number of sites in each of 2012, 2013 and 2014, there are other factors that come into

play when discussing the differences between the actual merchant fees costs and the forecast

merchant fees costs. The supporting information provided by DERS for the forecast merchant

fees costs demonstrates that the factors involved in preparing the forecast include not only the

number of sites, but also an estimate of the percentage of sites where the credit card payment

option will be used, the estimated average annual bill and the forecast merchant fee rate.367 The

Commission considers that a proper variance analysis should account for the differences between

364




Exhibit 0020.16.DEML-2957, Attachment to the response to AUC-DERS-041.


Decision 2957-D01-2015 (July 7, 2015) • 79

the actuals and forecasts for each of these factors, in order to focus in on what is causing the

forecasting error. The Commission does not accept Mr. Bell’s recommendation for a

13.19 per cent reduction to the 2015 and 2016 forecast amounts for merchant fees because it

does not contain any detailed variance analysis for 2012, 2013 and 2014.

346. However, the Commission notes that more recent information is available which changes

the forecasts for 2015 and 2016. In Section 4.10 of this decision, the Commission has directed

DERS to update the working capital forecasts for 2015 and 2016 to incorporate the latest forward

price index forecasts that are on the record of this proceeding. The Commission considers that

this will have an impact on the estimated average annual bill forecast for 2015 and 2016 that is

used in the forecast of the merchant fees.



a revision to the forecast number of sites to which the estimated percentage of sites using the

credit card payment option will be applied for 2015 and 2016. Finally, DERS will have actual

information for 2014 with respect to the percentage of sites where the credit card payment option

was used. This information is to be used as the starting point for the estimate of the percentage of

sites in 2015 and 2016 where the credit card payment option will be used, with increases to this

starting level of five per cent in each of 2015 and 2016.

348. No information was presented during the proceeding that cast any doubt on the use of the

five per cent annual increase DERS used in its application. The Commission considers that this

annual increase appears to be reasonable based on the information filed by DERS. As a result,

the Commission allows the use of the five per cent annual increase for 2015 and 2016. No

concerns were raised with the forecast merchant fee rate of 1.8243 per cent368 which appears to

be reasonable and the Commission is prepared to approve it for 2015 and 2016. A variance

analysis would have identified any issues with respect to the forecasting accuracy of DERS for

these two areas, but no such analysis was submitted on the record of the proceeding.


forecasts for the “Merchant Fees” cost category for 2015 and 2016, to reflect the updated

forward price index forecasts for 2015 and 2016 and the updated number of forecast sites for

2015 and 2016. The Commission also directs DERS to use the actual percentage of sites for 2014

where the credit card payment option was used as the basis for the 2015 and 2016 forecasts, and

to inflate this percentage by five per cent in each of 2015 and 2016. The Commission also directs

DERS to use a forecast merchant fee rate of 1.8243 per cent for 2015 and 2016. Finally, the

Commission directs DERS, as part of the compliance filing, to include details of how the

supporting forecasts for 2015 and 2016 for the “Merchant Fees” cost category for the DRT and

the RRT were calculated. This information should be similar to what was provided during the

proceeding in the attachment to the response to information request AUC-DERS-041.

5 Allocation methodology

350. The CCA raised three issues with respect to the allocation of costs. One issue was with

respect to the allocation of certain labour costs between the DRT and the RRT. Another issue

was with respect to how the amounts in the “Merchant Fees” cost category are allocated to the

368



80 • Decision 2957-D01-2015 (July 7, 2015)

various rate classes. The third issue is with respect to how RRT costs are allocated to the lighting

rate class.

5.1 Allocation of certain labour costs between the DRT and the RRT

351. Included in the “Labour by Department” cost category are costs for a department entitled

“Credit and Collection.” DERS advised that it allocated the costs associated with this department

on a 50/50 basis between the DRT and the RRT, and added that this allocation was consistent

with previous applications.369

352. Noting that DERS identified that the allocation of credit and collection labour between

the regulated and non-regulated operations tracks the number of customers served, the CCA

submitted that it would be appropriate to allocate the labour costs for the credit and collection

department between the DRT and the RRT on the basis of the number of customers. The CCA

stated that the current allocation methodology overcharges the RRT and undercharges the

DRT.370

353. DERS stated that the Commission should deny the CCA’s recommended allocation

methodology since it does not reflect the way in which collection costs are practically applied. It

added that both the gas and electric sides of the regulated business require similar efforts from

the credit and collections staff.371

Commission findings

354. The Commission considers that the best information with regard to the nature of the

labour costs for the credit and collection department was presented during the hearing, as part of

the following exchange between Mr. Jim Turner, a witness for DERS, and Mr. Wachowich,

counsel for the CCA.

Q. Sir, let me just cast this scenario to you. If there was a mass attrition on the electric

side for some reason and Direct Energy Regulated Services had few, if any, electrical

customers but was static in its gas number of customers, you could no longer split it

50/50, you would then want to collect it all from gas. Isn't that fair?

A. MR. TURNER: I don't believe that's necessarily fair. As long as we have an

electric business, we would still be supporting that business. The same would go for any

of our other fixed costs essentially that they've -- they're there because we've got a gas

and electric business. And I think in this case it makes sense to continue to split them on

a 50/50 basis.372

355. Mr. Turner indicated that the labour costs for the credit and collection department are

fixed costs, and the CCA has not presented any information that counters this. The Commission

accepts the testimony of Mr. Turner on this matter. The Commission considers that the allocation

methodology continues to be reasonable. Accordingly, the Commission finds that allocating

these fixed costs on a 50/50 basis between the DRT and the RRT is reasonable and the

Commission denies the CCA’s recommendation.

369

Exhibit 0018.01.DEML-2957, CCA-DERS-001 to CCA-DERS-017, response to CCA-DERS-006, page 11. 370



Transcript, Volume 1, page 134, lines 7-20.


Decision 2957-D01-2015 (July 7, 2015) • 81

5.2 Allocation of amounts in the “Merchant Fees” cost category between rate classes

356. DERS stated that the basis for allocating costs to the various rate classes has not changed

from previous years with the exception of merchant fees, which are now allocated to each rate

class independently of customer care costs.373 DERS allocated the amounts in the “Merchant

Fees” costs category to the various rate classes based on the number of bills after

consolidation.374

357. The CCA disagreed with the proposed allocation basis for these costs and recommended

that the allocation basis be changed. It submitted that credit card merchant fees are typically

charged as a percentage of the amount billed to, or charged to, the credit card; which means that

the greater the bill, the higher the merchant fee. The CCA stated that therefore, it is not

reasonable to allocate these costs on the basis DERS has proposed.375

358. Stating that the amount of merchant fees correlates much more closely to the amount

charged to credit cards than to a bill count, the CCA recommended that the amounts included in

the “Merchant Fees” cost category first be allocated between energy and non-energy based on

total billed amounts, and then be allocated to the various rate classes on the basis of energy.376

359. DERS replied that while merchant fees are calculated based on the percentage of the bill,

the CCA provided no evidence to show that customer classes with higher average bills have

higher credit card usage. The CCA has not demonstrated that its allocation proposal would

actually result in a fairer distribution of merchant fee costs. DERS submitted that it is counter

intuitive to believe that larger customers use credit card payments more than smaller

customers.377 The UCA stated that without stronger evidentiary support, it cannot support the

CCA’s recommendation to change the allocation methodology.378

Commission findings

360. In previous applications, merchant fees were treated as pass-through costs from ATCO I-

Tek, and were included as a component of the “Customer Care Costs” cost category. In Decision

2010-317,379 it is clear that the approved amounts in the “Customer Care Costs” cost category

were allocated on the basis of the number of bills after consolidation.380 Now that DERS has

decided to present the forecast costs for merchant fees as a separate cost category, the

Commission considers that it is reasonable to question the allocation methodology for these

costs.

361. The Commission considers that a logical starting point to determine the allocation

methodology for these costs would be to examine how the actual costs are incurred. The actual

merchant fees are incurred as a percentage of the payment that a customer makes using a credit

card. While the actual merchant costs incurred in each of 2012, 2013 and 2014 is on the record of

the proceeding, there is no information on the record that shows the breakdown of these actual

373








Rate Tariffs Compliance Filing, Proceeding 468, Application 1605840-1, July 8, 2010. 380

Decision 2010-317, Appendix 3, Schedule 6.1. Decision 2010-317, Appendix 4, Schedule 6.2.



82 • Decision 2957-D01-2015 (July 7, 2015)

merchant costs by rate class. Consequently, there is no basis on which to make any kind of

finding with respect to the number of customers by rate class who use credit cards. The

Commission agrees with DERS that the CCA provided no evidence to show that customer

classes with higher average bills have higher credit card usage.

362. Absent the availability of actual merchant costs incurred by the individual rate classes,

the Commission considers that it is reasonable to examine how the forecast costs were

developed. DERS provided this information during the course of the proceeding.381 Examining

this information, it is clear that the forecast was not developed by rate class, but instead was

developed using an overall percentage of all customers, and the resulting number was applied to

an estimated average annual bill. No backup was provided by DERS about how the average

annual bill was calculated, so it is not known whether this figure represents the average annual

bill across all rate classes, or whether it is specific to an individual rate class.

363. Considering that DERS used the average number of customers/sites as the starting point

for developing the forecasts for 2015 and 2016 merchant fees, the Commission finds that the

allocation to rate classes should be done on the same basis, which would be based on the number

of sites. Therefore, the Commission directs DERS, as part of the compliance filing, to allocate

the amounts in the “Merchant Fees” cost category using the number of sites as the allocator. The

Commission considers that while the allocator used by DERS, that being the number of bills

after consolidation, may not result in any significant differences by rate class compared to

allocating based on the number of sites, using the number of sites better reflects how the forecast

costs were developed.

364. The Commission considers that the CCA’s recommendation to first allocate a portion of

the merchant fees to energy is not valid because allowing payment of bills by credit card has

nothing to do with the direct procurement of the energy itself. Using a credit card to pay a bill is

more in line with the customer care aspect of the operation, which is properly recovered through

the non-energy, or administration charge. Consequently, the Commission denies the CCA’s

recommendation. The CCA also recommended that energy should be used to allocate the

merchant fee costs to the various rate classes. While the Commission considers that, all else

being equal, a customer with greater energy usage who paid via credit card would incur a higher

merchant fee cost than a customer with less energy usage who paid via credit card, the CCA has

not provided any evidence that demonstrates there is a relationship between the number of

customers who pay via credit card and their energy usage. Without such information, the CCA’s

recommended methodology falls short. Consequently, the Commission denies the CCA’s

recommendation in this regard.

5.3 Allocation of RRT costs to the lighting rate class

365. In its first 2012-2014 DRT and RRT application, DERS provided the following update

with regard to the matter of streetlights and the examination of this matter by the Commission’s

streetlight working group.

DERS has been involved in the streetlight working group project initiated by the AUC.

As part of this initiative DERS has been notified by ATCO Electric that they have

completed the system changes required to facilitate the grouping of streetlights in

accordance with section 7.10 of the System Settlement Code. ATCO Electric has

381



Decision 2957-D01-2015 (July 7, 2015) • 83

approached all street lighting customers to determine the needs and wants of each

customer with respect to their consolidation or grouping of the streetlight accounts. As

this time DERS has been notified by ATCO Electric of only two customers that have

requested their streetlights be grouped. There are approximately 40 sites that will be

consolidated to two master accounts. Considering this accounts for less than 1% of all

streetlight sites. DERS has not made any changes in this Application to the previously

approved allocation or rate design methodology employed.382

366. DERS reiterated some of this information as part of the current application and stated that

considering the immaterial level of consolidation, it has not made any changes to the previously

approved allocation methodology, and it has allocated costs to the lighting rate class consistent

with the methodology383 approved in Decision 2009-238.384

367. DERS indicated that it allocates all costs to the lighting rate class on the basis of the

number of customers after consolidation prior to allocating the costs to the remaining rate

classes. It stated that in its forecast of streetlight sites, no grouping was considered. DERS

advised that the cost effect of a streetlight customer that grouped multiple streetlights would be a

reduction in retail administration charges at the retailer level.385 More information about this

process and the impact on the customer’s streetlight charges was provided during the hearing.386

368. During the course of the proceeding, DERS provided an update on the amount of

grouping that has been undertaken by its street lighting customers. DERS advised that from

January, 2014 to the end of January, 2015,387 there have been 2,369 sites consolidated between

14 customers.388

369. DERS submitted that it receives customer care and billing charges based on the number

of consolidated sites for streetlights, so it bears the risk of under-collection in the same way it

bears the risk that site counts overall will be lower than forecast amounts. DERS stated that it

will examine the allocation methodology for streetlights in its next DRT and RRT application, to

determine if the current allocation methodology should be continued, based on the consolidation

that occurs during 2015. It added that streetlight customers represent only 0.2 per cent of load

and 0.7 per cent of bills, so the impact of these customers on overall rates is minimal. DERS

requested that the Commission approve the allocation methodology for the lighting rate class as

filed.389

370. The CCA suggested that streetlight customers are not grouping their sites because there is

no price signal for them to do so. It added that all customers should be allocated costs on a

similar basis, and if streetlights are billed on a site basis and only allocated costs based on the

number of bills basis, then there is a subsidy from all other customers to the street lighting group.

The CCA recommended that the allocation methodology for the lighting rate class should be

382

Proceeding 1454, Exhibit 0001.00.DEML-1454, 2012-2014 DRT and RRT application, page 27. 383



Rate Tariffs, Proceeding 149, Application 1600749-1, December 3, 2009. 385

Exhibit 0018.01.DEML-2957, CCA-DERS-001 to CCA-DERS-017, response to CCA-DERS-016(d), (e)

and (g). 386

Transcript, Volume 2, page 248, line 19 to page 258, line 12. 387


Exhibit 2957-X0037, DERS response to undertaking 21 from February 4, 2015. 389

Exhibit 2957-X0095, DERS public argument, paragraph 57.



84 • Decision 2957-D01-2015 (July 7, 2015)

changed so that, for any costs that are allocated based on the number of sites, the allocation

should be based on the number of sites for all rate classes, including the lighting rate class.390

371. DERS stated that streetlights are generally low maintenance in terms of billing and

customer care requirements, so the current level of cost allocation is appropriate for the low load

and low percentage of bills that are generated for these customers. It added that whereas each

residential customer may contact DERS individually, streetlight customers contact DERS as a

consolidated unit representing a large group of streetlights, which means fewer calls and lower

costs to serve.391

Commission findings

372. The Commission considers that some history regarding the allocation of costs to the

lighting rate class would help in providing context to this issue.

373. This issue first arose during the processing of the 2005-2006 DRT and RRT application

from DERS. In its decision on that application, the Commission included the following:

The Board agrees with DERS that the Lighting Service class should pay its direct cost of

service and a certain portion of other non-energy and energy-related revenue

requirements. Accordingly, the Board considers it appropriate to allocate RRT non-

energy revenue requirement costs that are not directly charged costs, to the Lighting

Service class on a different basis than how these costs are assigned to other classes (the

Special Allocation Method). The Board considers this modified approach to be

appropriate while the street light assignment to site issue remains unchanged as discussed

further in Section 8.2.392

374. The Commission agrees with the CCA that the special allocation method set out in

Decision 2006-044 was a temporary measure until the streetlight assignment to site issue was

resolved. This special allocation method was put in place to try and offset the fact that every

streetlight was treated as a site, and incurred a customer care and billing charge from ATCO I-

Tek, even though each streetlight site was generally considered low maintenance from a

customer care and billing perspective.

375. Rule 021: Settlement System Code Rules now has a provision393 which permits the

grouping of streetlights. The Commission considers that each rate class should pay its fair share

of costs, and the streetlight customers can now work with the distribution utility, ATCO Electric

Ltd., in order to group their streetlights and reduce their non-energy charges. This will also

impact DERS as it will reduce the customer care and billing charges for customers who choose

to group their streetlights.

376. Each streetlight customer now has an option which will help it control its non-energy

charges, so the Commission finds that there is no longer a need for the special allocation method

that was approved in Decision 2006-044. Consequently, the Commission rejects the

methodology that DERS has proposed to allocate costs to the lighting rate class of the RRT for

390



Decision 2006-044: Direct Energy Regulated Services, 2005/2006 Default Rate Tariffs and Regulated Rate

Tariffs, Application 1399611-1, May 17, 2006, page 48. 393

Section 7.10.1.




Decision 2957-D01-2015 (July 7, 2015) • 85

2015 and 2016. The Commission directs DERS, as part of its compliance filing, to allocate costs

to the lighting rate class of the RRT on the same basis as costs are allocated to the other rate

classes.

377. Considering that this change in the allocation methodology may encourage more

customers to group their streetlights, and that DERS did not request the change, the Commission

considers that it is reasonable to permit DERS to revise its forecast for streetlight sites for 2015

and 2016 to reflect the adoption of this new methodology. The Commission therefore directs

DERS, as part of its compliance filing, to revise its forecasts for streetlight sites for 2015 and

2016 to reflect the expected impact arising as a result of the change in allocation methodology

for the lighting rate class. The Commission also directs DERS, as part of the compliance filing,

to update all other applicable areas of its RRT revenue requirements for 2015 and 2016, such as

customer care costs, to reflect the change in forecasted streetlight sites.

6 Rate design

6.1 Mid-use rate class

378. DERS referred to ATCO Gas, which introduced the mid-use rate group concept, effective

January 1, 2011, pursuant to Decision 2010-291,394 and submitted that it had not separately

forecast customers of the mid-use rate groups from the low-use rate group in this application. In

support of its submission, DERS stated that the majority of DERS’ costs are incurred at the site

level and do not vary by rate class, and as such there is no specific allocation or rate design

reason for DERS to separate out mid-use customers into a separate rate class at this time.395

379. DERS elaborated during the hearing that there was no future allocation or rate design

reasons that might require it to separate out mid-use customers.

Q. MR. WACHOWICH: We just wanted to get a sense of what would be the

allocation or rate design reasons that might require them to be separated, whether there

was a dollar threshold in terms of admin charge or something else.

A. MR. NEWCOMBE: No, we don’t have any particular dollar threshold,

Mr. Wachowich. As I said, if we were to incur a different [charge] for a particular rate

class from our CC&B provider, then we would reflect that in our rate design.396

380. DERS also accepted the CCA’s estimate that implementing an additional rate class would

cost between $10,000 and $100,000.397

381. The CCA stated that it had raised the issue of the creation of a mid-use rate class in order

to reflect the changes in ATCO Gas’ rate structure and submitted that DERS was not able to

provide a reasonable estimate of the cost of implementing the mid use rate class. The CCA

394

Decision 2010-291: ATCO Gas 2008-2009 General Rate Application – Phase II Negotiated Settlement,

Proceeding 184, Application 1604944-1, June 25, 2010. 395






86 • Decision 2957-D01-2015 (July 7, 2015)

submitted its preference for a mid-use rate class and requested that DERS be directed to provide

a forecast of the cost to implement a mid-use rate at the filing of its next DRT application.398

382. DERS replied that it could investigate the cost of implementing a mid-use rate class for

its next application as suggested by the CCA.399

Commission findings

383. The Commission accepts DERS’ submission that the introduction of the mid-use rate

class by ATCO Gas did not require DERS to do anything differently and it did not impact the

costs from the CC&B provider.400 As a result, the Commission does not consider that directing

DERS to provide the cost of implementing a mid-use rate class in its next DRT application is

warranted. Moreover, when and if a mid-use rate class is required, the costs will be examined at

that time. Accordingly, the CCA request is denied.

6.2 Idle sites

384. DERS included the following information about de-energized sites:

In its rate design DERS has accounted for and adjusted the site forecast for the impact of

de-energized sites. These are sites that are included in DERS’ site forecast shown on

Schedules 3.1.1 (DRT) and 3.2.1 (RRT) but are not billed on a monthly basis. Therefore,

in determining the appropriate site number to derive rates, DERS has applied the

historical factor to the forecast site counts shown on Schedules 3.1.1 and 3.2.1. After

13 months of a site being de-energized, ATCO Electric or ATCO Gas will assume

responsibility of these sites and they are no longer served by DERS and DERS will no

longer incur charges related to the site until the site has been re-energized or opened for

service. As shown on Schedules 7.1 and 7.2, the proportion of sites that fall into this

category is less than 1%.401

385. DERS provided more information about de-energized sites during the course of the

proceeding, stating the following:

De-energized sites are sites that have been physically disconnected by the distributor.

DERS implemented a process with ATCO Gas in 2011 whereby any de-energized site

that bills as an idle site for 13 months will be de-selected by DERS. DERS will submit a

de-select transaction to the distributor where once completed the site will no longer be

enrolled to DERS.402

386. DERS indicated that de-energizing is simply turning the site off, so the power goes off,

with the result being the site is treated as being idle. DERS stated that idle sites still attract

transmission and distribution charges from the distribution utility, and these charges are included

in unbillable revenue. DERS added that it would also incur a charge for these idle sites from the

customer care and billing provider.403

398





Exhibit 0018.01.DEML-2957, CCA-DERS-001 to CCA-DERS-017, response to CCA-DERS-012(g), page 22. 403

Transcript, Volume 1, page 139, line 22 to page 141, line 12.


Decision 2957-D01-2015 (July 7, 2015) • 87

387. DERS stated that the time period of 13 months was settled on due to seasonality. It added

that there are customers that only activate their sites during specific times of the year, such as

irrigation sites. DERS indicated that if it did not wait for at least a 12 month period, these sites

would have been de-enrolled (or deselected), and then would have to be enrolled and energized

again once the customer required it.404

388. DERS stated that for a site to be deselected due to it being continually idle, the site must

meet all of the following criteria, according to ATCO Electric or ATCO Gas:

Site must have been enrolled with DERS for a minimum of 12 months

Site must be disconnected (no usage) for a minimum of 12 months

Meter must be removed

No pending DERS-requested orders

No new updated customer information in the past 3 months

No new permit information (indicating customer is getting ready to have meter re-

installed) in the past 3 months.405

389. Therefore, DERS submitted that not every site that has been de-energized for 13 months

could be immediately and successfully de-enrolled (or deselected) from DERS.406

390. The CCA submitted that the 13 month waiting period between when a site is de-

energized and when it is de-selected is excessive, and was not adequately supported by DERS. It

added that the assets associated with de-energized sites are physically disconnected and therefore

not used and useful. The CCA submitted that de-energized sites should immediately be de-

selected.407 It added that this process increases the costs of the operations of DERS and these

costs are imposed on all customers of DERS.408

391. The CCA stated that seasonal customers should have a specific rate design that recovers

their costs over the period of time they are connected to the system each year. It submitted that

until this issue is resolved, DERS should not be allowed to recover more than three consecutive

months of charges pertaining to a de-energized site, and the list of conditions that ATCO Electric

or ATCO Gas wishes to impose should not be allowed.409 Subsequently, based on DERS’

characterization of the total annual charges associated with idle sites as being relatively small,

the CCA submitted that idle site charges should be excluded from the revenue requirement.410

392. DERS suggested that the CCA redirect its proposal to the applicable distribution utilities.

It added that should the Commission find merit in the CCA’s proposal, DERS would be willing

to work with all parties to spread these costs out to all distribution customers. DERS submitted

that the CCA’s proposal unfairly attempts to reduce legitimate costs incurred by DERS in

providing regulated services and as such, the Commission should reject the CCA’s proposal.411

404

Exhibit 2957-X0056, DERS response to undertaking 27 from February 5, 2015, page 1. 405







Exhibit 2957-X0095, DERS public argument, paragraph 55.


88 • Decision 2957-D01-2015 (July 7, 2015)

Commission findings

393. The Commission rejects the CCA’s recommendations because they are unsupported. The

CCA provided no basis for why the 13-month waiting period is excessive or why a three-month

period is reasonable. The Commission considers that a reasonable analysis would have compared

the current 13-month waiting period to what was previously in place for DERS, and also to the

waiting periods for the other two regulated rate option providers in Alberta.412 This would have

permitted a better assessment to be made with respect to whether the 13-month period is

excessive. The CCA did not offer any reasons why the conditions agreed to between DERS and

ATCO were unreasonable, unfair, or in violation of any terms and conditions or legislation.

394. When DERS explained the reason for the 13-month period as being due to seasonality,

the CCA countered that seasonal customers should have a specific rate design. The CCA

submitted no evidence with respect to how this specific rate design would function, nor was there

any evidence provided about how seasonal customers are treated by the other two regulated rate

option providers in Alberta.

395. The CCA submitted that this 13-month waiting period process adds costs to the

operations of DERS, but the CCA did not identify the magnitude of these costs. The Commission

did not consider the information about the amount of the idle site charges filed by DERS in its

written argument because this information was not tested in the proceeding. Consequently, the

Commission is unable to determine if the issue in question is even material from a cost

perspective.

396. As a result, for the purpose of this decision, the Commission accepts DERS’ proposed

treatment of de-energized sites, the resulting idle site charges for 13 months, and the subsequent

de-selection of these sites after 13 months according to the criteria set out by ATCO Gas and

ATCO Electric, as being reasonable steps to try and reduce the amount of unbillable revenue.

The Commission notes that these steps had a positive impact on reducing the actual amounts of

unbillable revenue in each of 2012, 2013 and 2014, compared to the actual levels from years

prior to 2012.

6.3 Prior period adjustment

397. DERS submitted that it had included various adjustments to the applied-for revenue

requirements for the 2012-2014 test period, which included the following:

(1) Code of conduct (COC) audit cost refund of $101,500 plus interest as directed by the

Commission in Decision 2009-071413 and Decision 2010-282;414

(2) 2007/08 goods and services tax (GST) refund that was received by DERS with

respect to GST components of bad debt and unbillable revenues. These amounts were

previously included in DERS’ deferral account applications in 2007 and 2008 and

recovered from customers as well as refunded by the government in 2010 to DERS.

412

Those being ENMAX Energy Corporation and EPCOR Energy Alberta GP Inc. 413

Decision 2009-071: Direct Energy Regulated Services and Direct Energy Partnership, Gas Code of Conduct

Regulation Audit Exemption Request, Application 1604973-1, May 29, 2009. 414

Decision 2010-282: Direct Energy Regulated Services and Direct Energy Partnership, Gas Code of Conduct

Regulation Audit Exemption, Proceeding 614, Application 1606123-1, June 17, 2010.




Decision 2957-D01-2015 (July 7, 2015) • 89

398. DERS proposed to refund the above adjustments back to customers over the 2012-2014

time periods according to the following schedule:

Table 23. Prior-period revenue adjustment ($000s)

2012 forecast 2013 forecast 2014 forecast

DRT

2007/2008 GST refund 360.5 360.5 360.5

2008/2009 COC exemption 18.5 18.5 18.5

Subtotal 379.0 379.0 379.0

RRT

2007/2008 GST refund 77.5 77.5 77.5

2008/2009 COC exemption 18.5 18.5 18.5

Subtotal 96.0 96.0 96.0

Total 475.0 475.0 475.0

Source: Exhibit 0001.00.DEML-2957, 2012-2016 DRT and RRT application, page 79.

399. Given that the 2012-2014 period has already passed, the CCA proposed that the amounts

be refunded in 2015 and 2016. The CCA also submitted that interest should accrue to customers

from the date DERS received the associated funds until the amounts are refunded to customers.415

400. DERS submitted that it would refund these prior period adjustments in 2015 and 2016,

and the financial schedules would be updated to reflect this in the compliance filing.416

Commission findings

401. The Commission agrees with the CCA that DERS should refund the prior period

adjustment amounts in 2015 and 2016, and that interest should accrue to customers. The

Commission, therefore, directs DERS to refund the prior period totals to customers in 2015 and

2016.

402. When considering the payment of interest, sections (2) (d) and (2) (e) of Rule 023: Rules

Respecting Payment of Interest, state that:

(d) interest will be calculated from the date on which the rate adjustment becomes

effective;

(e) interest will be calculated using a rate equal to the Bank of Canada’s Bank Rate plus

1½ per cent, subject to any previously approved Commission procedure for awarding

interest.417

403. Accordingly, the interest accruing to customers, throughout the period from the date

DERS received the funds until the amounts are refunded to customers, are to be based on the

Bank of Canada rates plus 1.5 per cent. The Commission directs that DERS provide supporting

calculations in its compliance filing.

415

Exhibit 2957-X0091, CCA public argument, paragraphs 52 to 53. 416


Rule 023: Rules respecting payment of interest, January 2, 2008.



90 • Decision 2957-D01-2015 (July 7, 2015)

7 Other

7.1 Inter-affiliate code of conduct

Gas code of conduct

404. The purpose of the Code of Conduct Regulation (enacted pursuant to the Gas Utilities

Act) is to ensure that gas distributors, default supply providers and retailers conduct themselves

in a manner that supports the competitive operation of the retail natural gas market and that their

conduct does not distort that market by offering unfair advantages to retailers.

405. After entering the Alberta retail energy market as a regulated rate provider, a default

supply provider and a competitive retailer, DEML was required to file compliance plans with the

board under the Code of Conduct Regulation (gas code of conduct). One plan was for DEML’s

provision of the default supply gas function, and the other plan was for its affiliated competitive

energy retail function. Subsequently, on February 27, 2004, the board issued decisions 2004-019

and 2004-020 approving, respectively, for DERS and Direct Energy Partnership (DEP), the

affiliated competitive retailer of DERS, Code of Conduct Compliance Plans (compliance plans

or plans) under the gas code of conduct.418,419

406. DEML was also required to file compliance plans with the Market Surveillance

Administrator under the Code of Conduct Regulation enacted pursuant to the Electric Utilities

Act (electric code of conduct) because it is a regulated rate provider of electricity services and a

competitive retailer in Alberta. The purpose of the electric code of conduct is to ensure that

distribution companies, regulated rate providers and retailers conduct themselves in a manner

that supports the competitive operation of the retail electricity market and that their conduct does

not distort that market by offering unfair advantages to retailers. The Market Surveillance

Administrator approved the plans under the electric code of conduct.

407. The Commission approved amendments to DERS’ and DEP’s compliance plans to reflect

organizational changes and process improvements in Decision 2009-034.420 In Decision 2014-

324, the Commission further approved amendments to the DERS and DEP compliance plans to

replace references to “ATCO-I-Tek” with “HCL,” which is defined as “HCL Axon Technologies

Inc.”421

Inter-affiliate code of conduct

408. In 2003, the board issued Decision 2003-040422 in which it approved an IACC for the

ATCO group and subsequently, the board approved IACCs for other utilities. The purpose of an

IACC is:

418

Decision 2004-019: Direct Energy Regulated Services, Gas Code of Conduct Regulation Compliance Plan,

Application 1318247-1, February 27, 2004. 419

Decision 2004-020: Direct Energy Partnership, Gas Code of Conduct Regulation Compliance Plan,

Application 1319537-1, February 27, 2004. 420

Decision 2009-034: Direct Energy Marketing Limited, Direct Energy Regulated Services, Direct Energy

Partnership, Gas Code of Conduct Compliance Plans, Application 1600905-1, March 19, 2009. 421

Decision 2014-324: Direct Energy Regulated Services and Direct Energy Partnership, Amendment of Gas and

Electric Compliance Plans, Proceeding 3367, Application 1610774-1, November 26, 2014. 422

Decision 2003-040: ATCO Group, Affiliate Transactions and Code of Conduct Proceeding, Part B: Code of

Conduct, Application 1237673-1, May 22, 2003.








Decision 2957-D01-2015 (July 7, 2015) • 91

to address the possibility that interactions between regulated and unregulated affiliated

companies could be conducted in a manner that results in rates for a regulated utility

being too high or the unregulated affiliate having an unfair competitive advantage in the

market in which it operates.423

409. DERS currently does not have an IACC.

DERS’ request

410. In its amended application, DERS submitted that it draws on resources in both the United

States and Canada to operate the regulated business in Alberta. DERS added that this

arrangement has been in place since 2004 and that DERS recovers allocated shared corporate

service costs in accordance with AUC decisions.424

411. Given that DELP does not operate in Alberta, DERS submitted that there is no reason for

an IACC to apply to the DEML-DELP MSA or to the services provided in accordance with the

DEML-DELP MSA. DERS added that pursuant to the MSA, DELP simply provides access to

the infrastructure it owns (i.e., hardware and software) and provides certain related services for a

fee. The aggregate costs for the CC&B services is FMV.

412. DERS submitted that its existing compliance plan under the gas code of conduct and the

electric code of conduct is adequate. Specifically, DERS submitted that its compliance plan

already provides the following protections:

(i) equality of treatment of customers;

(ii) confidentiality of customer information;

(iii) equality of treatment of retailers;

(iv) business practices of the RRT provider and the DRT provider;

(v) prevention of any unfair competitive advantage to affiliates of the RRT and DRT

provider;

(vi) maintenance of separate records and accounts;

(vii) development of a compliance plan and ongoing compliance reports; and,

(viii) compliance audits.

413. DERS submitted that the introduction of the DEML-DELP MSA does not raise any

issues with respect to DELP. Specifically, DERS submitted that there is no concern with DELP:

(i) accessing customer information for its own uses since DELP does not operate in

Canada;

(ii) accessing regulated utility services for its own uses;

(iii) competing for customers in Alberta; or,

(iv) being the recipient of a cross-subsidy from regulated customers.425

414. DERS added that all DELP and DEML employees that have or may have contact with the

regulated business receive training in accordance with the compliance plan in order to protect

regulated customer information. This results in a clearly defined set of rules that enhance inter-

affiliate transparency and senior management accountability with respect to inter-affiliate

423

Bulletin 2010-30, Review of utilities’ inter-affiliate codes of conduct, November 8, 2010. 424




92 • Decision 2957-D01-2015 (July 7, 2015)

transactions impacting the regulated business. DERS submitted that DELP and DEML

employees will continue to abide by the obligations set out in the compliance plan.

415. DERS further added that there is no overlap of any directors or officers between DEML

and DELP. With respect to the DEML-DELP MSA, DERS noted that Tanis Kozak, DEML’s

Vice President and General Manager, will manage the DEML-DELP MSA on behalf of DEML,

and John Varkey, DELP’s Vice President IT Operations, will manage the DEML-DELP MSA on

behalf of DELP.

416. In response to information request AUC-DERS-043(b), DERS elaborated that under the

new arrangement for the provision of CC&B services as set out in the amended application, HCL

will deliver business BPO services directly to customers, which will require it to access customer

data in order to provide service and billing. DELP will provide CIS facilities and an SAP

framework to enable HCL to provide BPO services. DERS submitted that this is similar to

DERS’ current corporate shared services cost arrangements, which enable DERS to use and

access existing business services, computers and software and personnel on a shared services

basis with corporate assets based in North America. DERS added in that response that there is no

change in the number of shared employees between DEML and its affiliates arising from the new

arrangements.426

417. DERS reiterated that the existing compliance plan is sufficient to address the changes

resulting from the new CC&B arrangement since the obligation to protect customer information

remains the same regardless of who owns or is providing the actual CC&B service. Specifically,

access to, treatment of, and sharing of DERS’ customer information is detailed within the

existing compliance plan, which outlines the responsibilities and appropriate behaviour of

employees, contractors, and employees of contractors who support the DERS business.427

418. DERS further discussed why it believes that the compliance plan is already adequate to

meet any changes arising from its new CC&B arrangement.

Q. MR. KOLESAR: Do you have an interaffiliate code of conduct, sir?

A. MR. NEWCOMBE: We don't have a formal interaffiliate code of conduct. We are

governed by the code of conduct regulation with respect to equality of treatment of all

customers, protection of customers, everything else. And my understanding is our code of

conduct is -- I've heard it referred to as the gold-plated standard for codes of conduct in

Alberta -- our compliance plan, I should say, not the code of conduct.

As well, when we contemplated or first started kicking around this idea of the potential

for an affiliate to have some ownership, we looked at the interaffiliate code of conduct

that was in place, and we developed an internal I'll call it memo or code of behaviour, and

we made certain that everyone who was involved in this project understood it, and it

basically followed or included a lot of the items that are in the interaffiliate code.428

Commission findings

419. DERS requested that the Commission not direct that the IACC be binding on DERS in

consequence of the new CC&B arrangements for the same reason the Commission declined to

426

Exhibit 0111.02, AUC-DERS-043(b), page 2. 427

Exhibit 0111.02.DEML-2957, AUC-DERS-043(b). 428

Transcript, Volume 2, pages 389-390.


Decision 2957-D01-2015 (July 7, 2015) • 93

make them binding on EEC in Decision 2004-066.429 In considering this request, the Commission

reviewed the evidence on the corporate structure under which DERS now operates. The entities

within the corporate structure are divided along geographic lines.430 An employee may be

considered a DELP or DEML employee depending on which entity signs their paycheques and

where the employee is geographically located. The reporting relationships do not appear to be

related to the functions performed by employees.

A. MR. NEWCOMBE: And I don't think nowhere did that come home more so

than when we moved our head office from Toronto to Houston a few years ago. We had a

number of employees who were employed by DEML at the time, or their paycheques

said DEML on them. They were transferred down to the Houston office. Same job, same

responsibilities, same focus area, but the next month their paycheque would have said

DELP on it. So, again, it's just a geographic happenstance.431

420. Although DERS submitted that its existing compliance plan under the gas code of

conduct and the electric code of conduct is adequate, the Commission notes that the current gas

code of conduct and electric code of conduct only govern the relationship between DEP and

DEML, the managing partner of DEP and DERS. These codes of conduct do not govern the

relationships among DERS, DEML and DELP.

421. DERS submitted that DERS, DEML and DELP have an internal inter-affiliate code that

governs the inter-affiliate relationships among the three entities. However, this inter-affiliate

code is not on the public record and has not been approved by the Commission.

422. Given the above findings and recognizing the interrelationships among DELP, DEML

and DERS, and the fact that DEML business units provide both regulated and unregulated

services, the Commission directs DERS to develop an IACC to ensure that interactions between

regulated and unregulated affiliated companies are conducted in a manner consistent with the

principles set out in Decision 2002-069432 and Decision 2003-040.433 The Commission directs

DERS to file an IACC by December 31, 2015. The current internal IACC that governs the inter-

affiliate relationships among the three entities may suffice, if it is consistent with the principles

set out in Decision 2002-069 and Decision 2003-040.

7.2 DRT and RRT terms and conditions

423. The current T&Cs for the RRT for DERS were approved in the errata to Decision 2011-

053.434 The current T&Cs for the DRT for DERS were approved in Decision 2011-318.435 In

429

Decision 2004-066, ENMAX Power Corporation, 2004 Distribution Tariff Application Part B: 2004 Final

Distribution Tariff, Application 1306819-1, August 13, 2004. 430



Decision 2002-069, ATCO Group, Affiliate Transactions and Code of Conduct Proceeding Part A: Asset

Transfer, Outsourcing Arrangements, and GRA Issues, Application 1237673, July 26, 2002. 433

Decision 2003-040, ATCO Group, Affiliate Transactions and Code of Conduct Proceeding Part B: Code of

Conduct, Application 1237673-1, May 22, 2003. 434

Decision 2011-053 (Errata): Direct Energy Regulated Services, Default Rate Tariff and Regulated Rate Tariff

Revised Terms and Conditions, Proceeding 996, Application 1606846-1, February 23, 2011. The T&Cs for the

RRT are included in Appendix 3 of Decision 2011-053 (Errata). 435

Decision 2011-318: Direct Energy Regulated Services, Amended Terms and Conditions of Service –

Disconnection of Gas Services, Proceeding 1271, Application 1607382-1, July 26, 2011. The T&Cs for the

DRT are included in Appendix 2 of Decision 2011-318.




http://www.auc.ab.ca/applications/decisions/Decisions/2011/2011-053_Errata.pdf

http://www.auc.ab.ca/applications/decisions/Decisions/2011/2011-053_Errata.pdf



94 • Decision 2957-D01-2015 (July 7, 2015)

Decision 2012-343,436 which addressed the first application DERS filed for its 2012-2014 DRT

and RRT, the Commission directed DERS to prepare a revised set of T&Cs incorporating the

findings and directions set out in paragraphs 102, 114 and 168 of Decision 2012-343, and to file

them for acknowledgement with the Commission by no later than February 10, 2013.

424. DERS included the revised set of T&Cs as part of its second application for its 2012-

2014 DRT and RRT, which was filed on February 5, 2013. Application 1609270-1437 was

assigned to the second application DERS filed for its 2012-2014 DRT and RRT. On March 18,

2013, the Commission issued a letter that closed the second application because the second

application was incomplete.438

425. During the processing of the current application, DERS indicated that because the second

application was closed, and the Commission did not explicitly acknowledge the changes to the

T&Cs included in the second application, it is unclear to DERS whether the changes directed by

the Commission in paragraphs 102, 114 and 168 of Decision 2012-343 received

acknowledgement by the Commission. DERS requested that the Commission acknowledge

acceptance of these changes. It added that the T&Cs filed as attachments 16 and 17439 of the

current application included the changes directed by the Commission in Decision 2012-343.440

426. DERS stated that it is seeking final approval of the T&Cs included in the current

application. Referring to the Commission’s statement in Decision 2012-343 that the Commission

is contemplating a future generic proceeding to deal with T&Cs, DERS stated that therefore it

has not proposed any further changes at this time.441

427. In response to an information request from the UCA, DERS provided a black lined

version of the revised T&Cs that highlighted the changes from the currently approved T&Cs.442

Commission findings

428. The Commission compared the revised T&Cs that were submitted as part of the current

application to the currently approved T&Cs. With the exception of the wording changes

approved in Decision 2012-343, no other changes have been made by DERS. There was also a

renumbering change approved in Decision 2012-343 that was not incorporated into the revised

T&Cs. The Commission will now address each of the changes that were directed to be made in

Decision 2012-343, and whether or not DERS complied with them.

429. As part of the first application DERS filed for its 2012-2014 DRT and RRT, it had

proposed to renumber certain sections of the T&Cs for both the DRT and the RRT. In the current

application, DERS has not renumbered any of the sections of the revised T&Cs. The

Commission finds that this is acceptable. In Decision 2012-343, the Commission did not

specifically direct DERS to renumber certain sections of the T&Cs for both the DRT and the

436

Decision 2012-343: Direct Energy Regulated Services, 2012-2014 Default Rate Tariff and Regulated Rate

Tariff, Proceeding 1454, Application 1607696-1, December 21, 2012. 437

Proceeding 2406. 438

Proceeding 2406, document description is as follows: AUC letter of disposition – Direct Energy Regulated

Services Application in Proceeding 2406 – March 18, 2013. 439

Exhibit 0006.00.DEML-2957, attachments 1-19. 440

Exhibit 0085.01.DEML-2957, DERS acknowledgement request, pages 1-2. 441


Exhibit 0019.01.DEML-2957, UCA-DERS-001 to UCA-DERS-029, response to UCA-DERS-029, page 54.



Decision 2957-D01-2015 (July 7, 2015) • 95

RRT, and the Commission considers that it is reasonable for DERS to keep the section

numbering intact.

430. In paragraph 102 of Decision 2012-343, the Commission stated that it had no concerns

with the proposed changes to Section 2.4443 and Section 6.1444 of the currently approved T&Cs for

both the DRT and the RRT. It was proposed that Section 2.4 would be renumbered to Section 1.4

and that Section 6.1 would be renumbered to Section 10.1. In addition, DERS proposed that the

word “visa” in Section 2.4 would be deleted and replaced with the word “vice.” As previously

stated, the Commission has found that it is acceptable for DERS not to renumber the sections.

The Commission reviewed Section 2.4 of the revised T&Cs for both the DRT and the RRT and

notes that the word “visa” has been deleted and replaced with the word “vice.”

431. In paragraph 114 of Decision 2012-343, the Commission accepted DERS’ proposed

changes to Section 4.3445 of the currently approved T&Cs. It was proposed that Section 4.3 would

be renumbered to Section 3.2. In addition, DERS proposed the following wording for this

section.

1. DERS may, at any time, request from a Customer, such information as DERS

considers reasonably necessary to determine the Customer’s credit and credit risk.

Such information may include:

1. the customers full name, address, telephone numbers (home, work and cellular),

and birthdates to allow DERS to determine a Customer’s credit rating, and/or

2. demonstration of the Customer’s credit history with another regulated utility,

and/or

3. other personal information sufficient to identify the prospective Customer and

determine the Customer’s credit history and credit risk.

2. DERS may at any time exchange the information provided by a Customer with a

Canadian Credit Bureaus [sic] with respect to customer payments and/or non-

payments.446

432. The Commission reviewed Section 4.3 of the revised T&Cs for both the DRT and the

RRT and has identified some inconsistencies between the wording included in Section 4.3 of the

revised T&Cs and the proposed wording approved in Decision 2012-343. The wording included

in the revised T&Cs for the DRT is included below, with the inconsistencies identified.

DERS may, at any time, request from a Customer, such information that DERS considers

reasonably necessary to determine the Customer’s credit history and credit risk. Such

information may include:

1. the Customer’s full name, address, telephone numbers (home, work and

cellular), and birthdate to allow DERS to determine a Customer’s credit rating,

and/or

443

Section 2.4 – Extended Meanings. 444

Section 6.1 – Notice to Close an Account. 445

Section 4.3 – Credit Information. 446

Decision 2012-343, paragraph 105.


96 • Decision 2957-D01-2015 (July 7, 2015)


and/or



DERS may at any time exchange the information provided by a Customer with

Canadian Credit Bureaus with respect to Customer payments and/or non-payments.447

433. There are also a couple of inconsistencies between the wording in Section 4.3 of the

revised T&Cs for the DRT and the wording in Section 4.3 of the revised T&Cs for the RRT. The

wording included in the revised T&Cs for the RRT is included below, with the inconsistencies

identified.

DERS may, at any time, request from a Customer, such information as DERS considers

reasonably necessary to determine the Customer’s credit history and credit risk. Such


1. the Customer’s full name, address, telephone numbers (home, work and cellular),

and birthdate to allow DERS to determine a Customer’s credit rating, and/or


and/or



DERS may at any time exchange the information provided by a Customer with the

Canadian Credit Bureaus with respect to Customer payments and/or non-payments.448

434. As stated previously in this section of the decision, the Commission has found that it is

acceptable for DERS to keep the current section numbering intact. With respect to the

inconsistencies identified between the wording approved in Decision 2012-343 and the revised

wording included by DERS in the current application, the Commission considers that these

inconsistencies are inconsequential and the Commission has no concerns with them. With

respect to the inconsistencies between the wording included in the revised T&Cs for the DRT

and the wording included in the revised T&Cs for the RRT, the Commission considers that even

though these inconsistencies are also inconsequential, it is important for the T&Cs to be

consistent. The Commission finds that the wording included in Section 4.3 of the revised T&Cs

for the RRT is more reflective of the wording approved in Decision 2012-343.

435. In paragraph 168 of Decision 2012-343, the Commission directed DERS to use the

following language in Section 6.7 of the T&Cs.

The amount due shown on a bill is owing to DERS on the statement date. If a Customer

does not pay a bill in full within seventeen (17) calendar days after the statement date

specified on the bill, subject to disputed charges as outlined in Article 8, a late payment

447

Exhibit 0006.00.DEML-2957, attachments 1-19, Attachment 16, page 10. 448

Exhibit 0006.00.DEML-2957, attachments 1-19, Attachment 17, pages 10-11.


Decision 2957-D01-2015 (July 7, 2015) • 97

charge may be applied. The outstanding unpaid amount, including the late payment

charge, shall be applied to the charges that become due and payable in the next bill.

DERS will disclose the late payment fee in its Fee Schedule.

436. Section 8.5 was proposed to be renumbered as Section 6.7449 of the currently approved

T&Cs. As discussed previously in this section of the decision, DERS did not do any

renumbering, and the Commission finds that acceptable. The Commission reviewed Section 8.5

of the revised T&Cs for both the DRT and the RRT and notes that DERS has used the wording

included in paragraph 168 of Decision 2012-343, with the following exception. Instead of using

the words “Article 8,” DERS used the words “Section 10.” This is logical because Section 10

was proposed to be renumbered as Article 8 of the T&Cs. Since DERS has chosen not to

renumber the T&Cs, it needs to use the words “Section 10” to make sure the proper section

reference is included for disputed charges.

437. Based on the reasons as set out in this section of the decision, the Commission finds that

DERS has complied with the directions included in paragraphs 168 and 176 of Decision 2012-

343. The Commission approves the revised T&Cs for both the DRT and the RRT, and has

attached them as appendices to this decision. The Commission has changed the wording in

Section 4.3 of the approved T&Cs for the DRT that is attached to this decision to correct the

inconsistencies discussed previously. The revised T&Cs are approved effective August 1, 2015.

7.3 Internal energy price setting plan development costs

438. In its argument, DERS stated that in Decision 2941-D01-2015, the Commission directed

DERS to include its internal EPSP costs in this proceeding. DERS stated that it will include, in

its compliance filing, the $57,200 per month beginning with the month in which the new EPSP is

anticipated to be in place.450

439. The UCA argued that there was no evidence on the record of this proceeding to support

these additional costs, nor was any such evidence imported from the generic RRO proceeding,

proceeding 2941. Without such evidence, the UCA submitted that it would be inappropriate to

allow DERS to include these costs without sufficient testing.451

440. The UCA therefore recommended that the Commission deny DERS’ request to include

these costs in the compliance filing and suggested that DERS could seek to recover these costs in

its subsequent non-energy application, where they can be fully tested by the Commission and

interveners.452

449

Section 8.5 – Late Payment Charge. 450


Exhibit 2957-X0102, UCA public reply argument, paragraph 111. 452

Exhibit 2957-X0102, UCA public reply argument, paragraph 112.


98 • Decision 2957-D01-2015 (July 7, 2015)

Commission findings

441. Paragraph 1601 of Decision 2941-D01-2015 states:

The Commission directs DERS, as part of its compliance filing, to exclude any internal

costs associated with the administration of its EPSP and to exclude any internal costs

associated with the development and implementation of its EPSP. These costs should be

reflected in DERS’ non-energy application.453

442. In Decision 2941-D01-2015, the Commission did not rule on the reasonableness of

DERS’ requested internal EPSP costs. As such, these numbers have not yet been approved by the

Commission.

443. Without supporting evidence in this proceeding, the Commission cannot approve the

requested $57,200 per month. However, the Commission recognizes that the timing of the

release of Decision 2941-D01-2015 did not provide sufficient time for these costs to be fully

tested in this proceeding. The Commission considers that it would be unreasonable to require

DERS to wait until its next non-energy application to seek approval of these costs and that these

costs can be tested within the compliance filing.

444. Accordingly, the Commission directs DERS to include in its compliance filing the

necessary supporting evidence and analysis to allow for full and thorough testing of its proposed

internal EPSP costs.

7.4 Minimum filing requirements

445. Bulletin 2006-25 issued on July 12, 2006, announced the approval, in principle, of the

form and content of a uniform system of accounts (USA) and minimum filing requirements

(MFR) for Alberta electric utilities.454 By letter dated August 29, 2006, the board, the

Commission’s predecessor, initiated Proceeding 1468565 to address whether implementation of

the USA and MFR would be in the public interest. In Decision 2007-017, the board directed the

regulated electric transmission and distribution utilities in Alberta to proceed with

implementation of the USA and MFR.455

446. In evidence, the CCA submitted that DERS does not follow the MFR set out in Decision

2007-017. The CCA elaborated that with respect to corporate costs, DERS does not provide an

explanation about its indirect allocation methodology, why the costs are required by the utility,

or the data used in its calculations. The CCA also cited confusion caused by DERS’ use of

“actuals.” The CCA recommended that DERS should be directed to provide information as

outlined in the MFR including the values for the allocators used (such as headcount, staff effort)

and the pro-rata share of each of the Direct Energy subsidiaries for all corporate cost allocations,

including both direct and indirect allocations.456

453

Decision 2941-D01-2015, Direct Energy Regulated Services, ENMAX Energy Corporation and EPCOR Energy

Alberta GP Inc., Proceeding 2941, Application 1610120-1, paragraph 1601. 454

Bulletin 2006-25, Announcing the Approval in Principle of the Form and Content of a Uniform System of

Accounts and Minimum Filing Requirements for Alberta Electric Utilities, July 12, 2006. 455

Decision 2007-017, EUB Proceeding, Implementation of the Uniform System of Accounts and Minimum Filing

Requirements for Alberta’s Electric Transmission and Distribution Utilities, Proceeding 1468565, March 6,

2007. 456

Exhibit 0035.02.CCA-2957, CCA evidence, page 12.

http://www.auc.ab.ca/news-room/bulletins/Bulletins/2006/Bulletin%202006-25.pdf



Decision 2957-D01-2015 (July 7, 2015) • 99

447. In response to an information request, the CCA stated that neither the USA nor the MFR

apply to DERS in its capacity as a DRT/RRT provider. The CCA elaborated that in practice,

however, the Commission requires actuals in proceedings which is consistent with the USA and

the MFR.457

448. In argument, the CCA repeated its recommendation that DERS should be subject to the

MFR for a distributor of electricity and the Uniform System of Accounting for Natural Gas

Utilities AR 546/1963 for a distributor of gas, whether DERS is considered a utility or not,

because it would make future hearings more efficient. The CCA added that the MFR should be

limited to those items related to the retail function performed by DERS.458

449. In reply argument, DERS submitted that the MFR does not apply to DERS as a regulated

retailer and no direction has been provided by the Commission otherwise. DERS stated,

however, that it would comply with all filing requirements of the Commission under the relevant

statutory regime that applies to it as a retailer and provider of regulated services.459

Commission findings

450. The Commission agrees with the CCA that DERS’ use of “actuals” caused confusion

over the course of this proceeding and has provided direction with respect to this matter in

Section 4.6 dealing with DERS’ corporate costs.

451. The MFR as set out in Decision 2007-017 was developed for electric transmission and

distribution utilities. At this time, the Commission does not apply MFR to RRO providers

including DERS or the Uniform System of Accounting for Natural Gas Utilities to default gas

providers. As a result, the Commission denies the CCA’s recommendation.

457

Exhibit 0050.01.CCA-2957, AUC-DERS-009. 458

Exhibit 2957-X0094, CCA public argument, page 23. 459



100 • Decision 2957-D01-2015 (July 7, 2015)

8 Order

452. It is hereby ordered that:

(1) Direct Energy Regulated Services shall submit a compliance filing which reflects

the findings, conclusions and directions of the Commission on or before

August 21, 2015. The compliance filing shall include corrections for errors and

omissions as identified on the record of the proceeding, including updated tables

and schedules reflecting all changes made, in order for Direct Energy Regulated

Services to comply with the directions of this decision.

(2) Direct Energy Regulated Services shall revise its 2012-2016 non-energy default

rate tariff and regulated rate tariff application and corresponding schedules on or

before August 21, 2015, incorporating the findings and directions in this decision.

(3) Direct Energy Regulated Services shall in its compliance filing, provide a

summary that sets out a detailed reconciliation of the revenue requirement for

each of the 2012, 2013, 2014, 2015 and 2016 test years to reflect the

Commission’s findings, directions and conclusions in this decision.

Dated on July 7, 2015.


(original signed by)

Mark Kolesar

Vice-Chair


Neil Jamieson

Commission Member


Bill Lyttle

Commission Member


Decision 2957-D01-2015 (July 7, 2015) • 101

Appendix 1 – Proceeding participants

Name of organization (abbreviation) counsel or representative

Direct Energy Regulated Services (DERS)

Lawson Lundell Barristers & Solicitors

AltaGas Utilities Inc. (AUI)

ATCO Gas

Consumers’ Coalition of Alberta (CCA)

Wachowich & Company

EPCOR Energy Alberta Inc. (EEAI)

Office of the Utilities Consumer Advocate (UCA)

Reynolds, Mirth, Richards & Farmer LLP

Alberta Utilities Commission Commission Panel M. Kolesar, Vice-Chair N. Jamieson, Commission Member B. Lyttle, Commission Member Commission Staff

G. Bentivegna (Commission counsel) C. Pham D. Mitchell C. Arnot B. Clarke


102 • Decision 2957-D01-2015 (July 7, 2015)

Appendix 2 – Oral hearing – registered appearances

Name of organization (abbreviation) counsel or representative

Witnesses

Direct Energy Regulated Services (DERS)

L. Manning J. Christian S. Dhalla

DERS panel 1 S. Turner J. Fauville G. Newcombe N. Black D. Brooks DERS panel 2 B. Perekoppi L. Armstrong R. Charles G. Newcombe J. Fauville DERS panel 3 J. Brock K. Buckstaff G. Newcombe DERS panel 4 S. Turner J. Fauville J. Wasserman S. Cheung G. Newcombe B. Perekoppi L. Armstrong

Consumers’ Coalition of Alberta (CCA)

J. A. Wachowich B. McConnell

CCA panel J. A. Jodoin J. Thygesen

Office of the Utilities Consumer Advocate (UCA)

C. R. McCreary B. Schwanak

UCA panel R. Bell


Decision 2957-D01-2015 (July 7, 2015) • 103

Appendix 3 – Summary of Commission directions

This section is provided for the convenience of readers. In the event of any difference between

the directions in this section and those in the main body of the decision, the wording in the main

body of the decision shall prevail.

1. The Commission has reviewed DERS’ response to AUC-DERS-025(a) and the

attachment to that response. The 2012 SAS amounts are as per the Commission’s

direction; however, the SAS amounts for 2013 and 2014 are not as directed. The

Commission, therefore, directs DERS, in its compliance filing, to make the necessary

corrections to ensure that the SAS amounts for 2013 and 2014 reflect Direction 3 in

Decision 2012-343 ........................................................................................... Paragraph 22

2. The Commission considers that it is not reasonable to apply an inflation forecast that is

partially based on a forecast increase in Alberta Weekly Earnings to the “Other

Administration Costs” cost category, because there are no direct labour costs in that cost

category. The Commission therefore finds that a more accurate forecast of inflation for

this cost category would be Alberta CPI. In Section 4.2 of this decision, the Commission

has discussed its views with respect to DERS’ submissions about accepting risk during

the test period, and the Commission’s preference to use the most recent information on

the record in the context of approving forecasts. The Commission considers that the

forecast for Alberta CPI prepared by TD Economics should be used as the forecast for

Alberta CPI for 2015 and 2016 for the purposes of this proceeding. Therefore, the

Commission directs DERS, in its compliance filing, to apply inflation to the “Other

Administration Costs” cost category forecasts for 2015 and 2016 at the rates of

0.1 per cent for 2015 and 2.4 per cent for 2016. .............................................. Paragraph 28

3. Using the updated Alberta CPI and Alberta Weekly Earnings data, the Commission has

calculated a forecast inflation rate of 1.92 per cent to be applied to these cost categories

for 2015, and a forecast inflation rate of 2.95 per cent to be applied to these cost

categories for 2016. The Commission directs DERS, as part of its compliance filing, to

use a forecast inflation rate of 1.92 per cent in determining the 2015 forecasts for the

“Labour (Gas Procurement),” and “Labour by Department” cost categories. The

Commission directs DERS, as part of its compliance filing, to use a forecast inflation rate

of 2.95 per cent in determining the 2016 forecasts for the “Labour (Gas Procurement),”

and “Labour by Department” cost categories. ................................................. Paragraph 31

4. As a result of the above findings, the Commission directs DERS, in the compliance

filing, to use the actual amounts for 2012, 2013 and 2014, with the exception of the

amounts for AIP, LTIS and SAS. DERS has been previously directed in this decision as

to which amounts to include for 2012, 2013 and 2014 for AIP, LTIS and SAS.

.......................................................................................................................... Paragraph 78

5. The Commission considers that a reasonable forecast does not obviate the use of a more

accurate forecast of site counts if information becomes available during the course of a

proceeding. To the extent that updated site count information becomes available, the

Commission considers that such information should be reflected in the forecast ultimately

approved by the Commission. The Commission considers that the best starting point for

the preparation of the 2015 and 2016 forecast sites is the actual number of sites at the end


104 • Decision 2957-D01-2015 (July 7, 2015)

of 2014, and therefore the Commission directs DERS to do so as part of the compliance

filing. ................................................................................................................ Paragraph 91

6. Although the Desert Sky report utilized a standard reference group with only four

comparators to arrive at FMV estimates of $3.52 per site and $3.63 per site for 2015 and

2016, respectively, the Commission recognizes that this sample was drawn from a

database containing approximately 75 North American utilities and that these four

utilities were the most comparable to DERS based on scope, quality, complexity,

geography, and regulatory environment. The Commission also accepts Desert Sky’s

methodology for recovering the CIS implementation and transition costs over the test

period through a monthly charge of $1.05 per site. While this analysis was based on a

sample of only three other North American utilities, the Commission recognizes that

these three utilities also recently implemented similar CIS systems. The only other

benchmarking evidence proffered in this proceeding was the First Quartile report that

estimated FMV, including CIS costs, of $4.91 per site and $5.00 per site in 2015 and

2016, respectively. The Commission has compared these two reports and found that

Desert Sky’s FMV estimates of $4.66 per site and $4.77 per site for 2015 and 2016,

respectively, fall within the lower range of First Quartile’s 95th per cent confidence

interval. The results of these two reports are consistent with each other. Given that First

Quartile relied on a comparison panel with 46 North American utilities, the Commission

finds that the First Quartile report adds depth to the Desert Sky report and DERS’ CC&B

forecast. Accordingly, the Commission accepts DERS’ CC&B costs of $4.66 and $4.77

on a per site per month basis for 2015 and 2016, respectively, and directs DERS to reflect

updated customer site counts in its forecasts of total 2015 and 2016 CC&B costs in the

compliance filing. .......................................................................................... Paragraph 147

7. The Commission finds that DERS has not adequately supported the need for these

additional functionalities to serve regulated customers and, accordingly, a portion of the

Five Point costs that relate to the requirements of the CC&B system should not be borne

by regulated customers. The UCA argued that none, or a maximum of 25 per cent (i.e.,

$187,500), of the vendor selection costs should be allowed whereas the CCA argued for a

70 per cent allocation (i.e., $525,000). The Commission finds that a $525,000 cost award

is not justified and that a $187,500 award undervalues the benefit that regulated

customers received from the more comprehensive and better-specified CC&B solution.

Given a lack of persuasive evidence in support of either position, the Commission finds

that the mid-point of this range is reasonable. The Commission, therefore, directs DERS

to reflect a reduction in vendor selection costs from $750,000 to $356,250 in its


8. The Commission, therefore, directs DERS in its next non-energy rate application to file a

new corporate costs allocation methodology. The application should include actual data

from the entity providing the service, rationale to support the corporate costs allocators

for each service, the volume of work that this entity provides (as measured by the

allocators) and the volumes of work received by DERS (as measured by the allocators).

The proposed methodology is to include a mechanism for tracking actual corporate costs

incurred by DERS and variances between actuals and forecasts. DERS is also to cease the

practice of booking Board/Commission approved amounts as actuals. ........ Paragraph 216

9. The Commission finds that DERS has not presented persuasive evidence that a

1.0 per cent allocation for all corporate costs directly allocated based on FTE count is

reasonable. The Commission is persuaded by the CCA’s evidence and submissions that,


Decision 2957-D01-2015 (July 7, 2015) • 105

based on Centrica’s 2013 annual report, DERS’ 2012 FTE count relative to Direct Energy

North America’s 2012 average employee count was only 0.58 per cent and not one

percent. On this basis, the Commission accepts the CCA’s argument that corporate costs

directly allocated based on FTE count appears to be overstated by 42 per cent. The

Commission, however, disagrees with the CCA that this condition extends to all directly

allocated corporate costs because drivers other than FTE counts (i.e., third party spend,

number of transactions, staff efforts, head count and service usage) are used to directly

allocate corporate costs. Accordingly, the Commission directs DERS to use a

0.58 per cent allocation instead of the 1.0 per cent allocation for corporate costs directly

allocated based on FTE counts into its 2012 corporate costs forecast. DERS is to reflect

this reduction in its compliance filing. ........................................................... Paragraph 217

10. The Commission understands that DERS’ forecasts of corporate costs over the 2012 to

2016 test period were developed using a forecasted inflation rate of 2.75 per cent. Based

on the record of this proceeding, “actual” corporate costs for 2013 and 2014 are not costs

incurred by DERS but forecasts of 2012 corporate costs inflated annually by

2.75 per cent through to 2016. Given that actual 2013 and 2014 inflation data and

updated forecast 2015 and 2016 inflation data were provided in this proceeding and

discussed in further detail in Section 4.1, the Commission directs DERS to reflect the

updated Alberta CPI data, consistent with those in Table 1, into its 2013 to 2016

corporate costs allocations in place of the 2.75 per cent originally forecasted. For

example, DERS’ 2013 corporate costs allocation will be its 2012 corporate costs

allocation, after the reductions directed in paragraph 217, inflated by 1.4 per cent.

Consistent with the Commission’s findings in sections 4.2 and 4.8 with respect to the

2013 and 2014 SAS amounts, DERS is to exclude corporate costs related to SAS from

the above adjustment and to incorporate the SAS amounts as approved in Decision 2012-

343 into its 2013 and 2014 corporate cost allocations. DERS is to reflect these

adjustments for 2013, 2014, 2015, and 2016 into its compliance filing. ....... Paragraph 220

11. The Commission agrees with the CCA that the analysis conducted in Exhibit 2957-

X0089 provides a more accurate forecast for DERS’ 2015 and 2016 postage cost

increases because they reflect Canada Post’s actual 2015 pre-sort rates, whereas the

analysis in Exhibit 2957-X0066.1 does not. Additionally, the Commission recognizes that

despite 2014 actuals being available, DERS’ analysis in Exhibit 2957-X0089 does not

reflect updated site count forecasts for 2015 and 2016. Accordingly, the Commission

directs DERS, in its compliance filing, to update its 2015 and 2016 postage cost forecasts

using the methodology and prices in Exhibit 2957-X0089 with updated 2015 and 2016

site count forecasts. ........................................................................................ Paragraph 227

12. The Commission directs DERS, as part of the compliance filing, to submit information

similar in format to the attachment to the response to AUC-DERS-030, which showed the

components of the labour costs by department. The information to be provided must

include the actual amounts for each of the DRT and the RRT for 2012, 2013 and 2014,

shown separately by year. The actuals for 2012, 2013 and 2014 AIP to be included must

only be for achieving objectives other than financial objectives. The Commission also

directs DERS, as part of this submission, to show the three-year average for the years

from 2012 to 2014 for each component and department. The Commission directs DERS

to inflate the resulting three-year average amounts for the years from 2012 to 2014 by

1.92 per cent and show the results separately for the DRT and the RRT in columns

entitled “2015 Forecast.” The Commission directs DERS to inflate the figures in the


106 • Decision 2957-D01-2015 (July 7, 2015)

columns entitled “2015 forecast” by 2.95 per cent and show the results separately for the

DRT and the RRT in columns entitled “2016 Forecast.” The Commission directs DERS

to include the resulting total costs in the “2015 Forecast” and “2016 Forecast” columns as

the forecast amounts for labour costs, allocated appropriately between the “Labour (Gas

Procurement)” and “Labour by Department” cost categories for the DRT and in the

“Labour by Department” cost category for the RRT. .................................... Paragraph 246

13. The Commission directs DERS, as part of the compliance filing, to submit a second

separate attachment similar in format to the attachment to the response to AUC-DERS-

030. The information to be provided must include the actual amounts for salaries and

benefits for each of 2012, 2013 and 2014, shown separately by year and shown separately

for each department for the DRT and the RRT. In addition, the information must include

the forecast approved amounts for the AIP for each of 2012, 2013 and 2014, as included

on the attachment to the response to AUC-DERS-030. The Commission directs DERS to

include the resulting total costs for 2012, 2013 and 2014, allocated appropriately between

the “Labour (Gas Procurement)” and “Labour by Department” cost categories for the

DRT and in the “Labour by Department” cost category for the RRT. .......... Paragraph 249

14. For 2012, 2013 and 2014, the Commission discussed approval of forecast versus actual

amounts in Section 4.2 of this decision. For the reasons highlighted in that section, and

given DERS’ failure to justify its requested $50,000 forecasts, the Commission directs

DERS, in the compliance filing, to update its customer education and energy awareness

amounts to the actual amounts incurred in 2012, 2013 and 2014. ................. Paragraph 263

15. The Commission also finds that there is insufficient evidence to support approval of

DERS’ requested forecast costs for customer education and awareness for the years 2015

and 2016. Accordingly, the Commission finds, for the purposes of this decision, that the

average of the previous years’ actuals is the best predictor of costs in the final two test

years, for the purposes of this decision. Accordingly, the Commission directs DERS, in

the compliance filing, to update its forecast amounts in each of 2015 and 2016 to be equal

to the average actual costs from 2012, 2013 and 2014. ................................. Paragraph 264

16. However, the Commission finds that more recent information is available which changes

the forecasts for 2015 and 2016. Accordingly, the Commission directs DERS to update

the forecasts for 2015 and 2016 by incorporating not only the more recent information on

the record of this proceeding, but also the revisions to the other applicable factors that are

used in the forecast of working capital. This includes updating the forecast gas and

electricity prices to incorporate the information provided during the oral hearing. The

Commission considers that requiring DERS to update this information is not retroactive

ratemaking, for the reasons set out in Section 4.2 of this decision. With regard to DERS’

comment that it should not be treated as if it has deferral accounts, the Commission

considers that DERS did not offer any explanation as to why this comment is relevant in

this situation. DERS has not demonstrated any relationship between deferral accounts and

the requirement to update forecasts. .............................................................. Paragraph 278

17. The Commission therefore directs DERS, in its compliance filing, to update the forecasts

for working capital costs for 2015 and 2016 to incorporate all other applicable updated

forecasts for 2015 and 2016, to incorporate the monthly natural gas and electricity prices

for 2015 and 2016, as set out in the information provided as part of confidential

Exhibit 67, and to update the rate of return and debt/equity figures as approved in

Decision 2191-D01-2015. The Commission further directs DERS to include, as part of its


Decision 2957-D01-2015 (July 7, 2015) • 107

compliance filing, supporting calculations for the weighted average cost of capital figure

it uses for 2015 and 2016. .............................................................................. Paragraph 280

18. The Commission considers that a more reasonable forecasting methodology for the bad

debt expense component of the “Bad Debt” cost category is to base this forecast on the

actual experience for the years 2012, 2013 and 2014. This will permit any concerns with

respect to increased bad debt credit risk to be addressed, and would eliminate the need for

the separate forecast risk adjustment factor of 0.05 per cent. The Commission considers

that if there is increased bad debt risk, it will be demonstrated in the actual bad debt

percentages for 2012, 2013 and 2014. Consequently, the Commission directs DERS, as

part of its compliance filing, to forecast the bad debt percentages for the DRT and the

RRT for 2015 and 2016, using the actual weighted average percentage for the years 2012,

2013 and 2014. The Commission further directs DERS, as part of the compliance filing,

to include supporting details for the forecast bad debt expense percentages included for

2015 and 2016. ............................................................................................... Paragraph 304

19. The Commission considers that a reasonable methodology for forecasting the

commissions paid to external collection agencies for 2015 and 2016 is to base this

forecast on the actual experience for 2012, 2013 and 2014. Consequently, the

Commission directs DERS, as part of its compliance filing, to forecast the commissions

paid to external collection agencies for the DRT and the RRT for 2015 and 2016, using

the actual weighted average percentage that these costs are of the total revenues for the

years 2012, 2013 and 2014. The Commission further directs DERS, as part of the

compliance filing, to include supporting details for the forecast percentages included for

2015 and 2016. ............................................................................................... Paragraph 309

20. With respect to the penalty revenue, the Commission agrees with DERS that the forecast

methodology for this cost category should be consistent with the approach used to

forecast bad debt expense. Consequently, the Commission directs DERS, as part of its

compliance filing, to forecast the penalty revenue percentages for the DRT and the RRT

for 2015 and 2016, using the actual weighted average percentage for the years 2012, 2013

and 2014. The Commission further directs DERS, as part of the compliance filing, to

include supporting details for the forecast percentages included for 2015 and 2016.

........................................................................................................................ Paragraph 311


forecast costs for bad debt expense for 2015 and 2016, to update the forecast costs for the

commissions paid to external collection agencies for 2015 and 2016, and to update the

forecast penalty revenue for 2015 and 2016, to incorporate the updated forward price

index forecasts for 2015 and 2016, to incorporate the updated number of forecast sites for

2015 and 2016, and to incorporate the percentage factors directed previously. This

information should be included as part of the updated schedules 5.1.12 and 5.2.12 that

DERS will submit as part of the compliance filing. ...................................... Paragraph 314


costs, but did not focus on the differences in the percentage factors. The annual average

percentage factor for the DRT for 2012 and 2013, based on actuals, is 0.11 per cent while

the corresponding factor for the RRT is 0.13 per cent. The Commission directs DERS to

use these factors in forecasting its unbillable revenue for 2015 and 2016. ... Paragraph 327


forecasts for the “Unbillable Revenue” cost category for 2015 and 2016, to incorporate


108 • Decision 2957-D01-2015 (July 7, 2015)

the updated forward price index forecasts for 2015 and 2016, the updated number of

forecast sites for 2015 and 2016, a percentage factor of 0.11 per cent for the DRT and a

percentage factor of 0.13 per cent for the RRT. This information should be included as

part of the updated schedules 5.1.12 and 5.2.12 that DERS will submit as part of the


24. The Commission directs DERS, as part of the compliance filing, to calculate the forecast

costs for 2015 for the “Other Administration Costs” cost category using the average of

the actual annual costs for this cost category for the three years 2012, 2013 and 2014,

separately for the DRT and the RRT, and applying inflation of 0.1 per cent. The

Commission directs DERS, as part of the compliance filing, to calculate the forecast costs

for 2016 for the “Other Administration Costs” cost category by using the 2015 forecast

amounts and applying inflation of 2.4 per cent. The Commission further directs DERS, as

part of the compliance filing, to provide the necessary documentation that supports the

calculated forecast amounts for 2015 and 2016. ............................................ Paragraph 339


forecasts for the “Merchant Fees” cost category for 2015 and 2016, to reflect the updated

forward price index forecasts for 2015 and 2016 and the updated number of forecast sites

for 2015 and 2016. The Commission also directs DERS to use the actual percentage of

sites for 2014 where the credit card payment option was used as the basis for the 2015

and 2016 forecasts, and to inflate this percentage by five per cent in each of 2015 and

2016. The Commission also directs DERS to use a forecast merchant fee rate of 1.8243

per cent for 2015 and 2016. Finally, the Commission directs DERS, as part of the

compliance filing, to include details of how the supporting forecasts for 2015 and 2016

for the “Merchant Fees” cost category for the DRT and the RRT were calculated. This

information should be similar to what was provided during the proceeding in the

attachment to the response to information request AUC-DERS-041. ........... Paragraph 349

26. Considering that DERS used the average number of customers/sites as the starting point

for developing the forecasts for 2015 and 2016 merchant fees, the Commission finds that

the allocation to rate classes should be done on the same basis, which would be based on

the number of sites. Therefore, the Commission directs DERS, as part of the compliance

filing, to allocate the amounts in the “Merchant Fees” cost category using the number of

sites as the allocator. The Commission considers that while the allocator used by DERS,

that being the number of bills after consolidation, may not result in any significant

differences by rate class compared to allocating based on the number of sites, using the

number of sites better reflects how the forecast costs were developed. ........ Paragraph 363

27. Each streetlight customer now has an option which will help it control its non-energy

charges, so the Commission finds that there is no longer a need for the special allocation

method that was approved in Decision 2006-044. Consequently, the Commission rejects

the methodology that DERS has proposed to allocate costs to the lighting rate class of the

RRT for 2015 and 2016. The Commission directs DERS, as part of its compliance filing,

to allocate costs to the lighting rate class of the RRT on the same basis as costs are

allocated to the other rate classes. .................................................................. Paragraph 376

28. Considering that this change in the allocation methodology may encourage more

customers to group their streetlights, and that DERS did not request the change, the

Commission considers that it is reasonable to permit DERS to revise its forecast for

streetlight sites for 2015 and 2016 to reflect the adoption of this new methodology. The


Decision 2957-D01-2015 (July 7, 2015) • 109

Commission therefore directs DERS, as part of its compliance filing, to revise its

forecasts for streetlight sites for 2015 and 2016 to reflect the expected impact arising as a

result of the change in allocation methodology for the lighting rate class. The

Commission also directs DERS, as part of the compliance filing, to update all other

applicable areas of its RRT revenue requirements for 2015 and 2016, such as customer

care costs, to reflect the change in forecasted streetlight sites. ...................... Paragraph 377

29. The Commission agrees with the CCA that DERS should refund the prior period

adjustment amounts in 2015 and 2016, and that interest should accrue to customers. The

Commission, therefore, directs DERS to refund the prior period totals to customers in

2015 and 2016. ............................................................................................... Paragraph 401

30. Accordingly, the interest accruing to customers, throughout the period from the date

DERS received the funds until the amounts are refunded to customers, are to be based on

the Bank of Canada rates plus 1.5 per cent. The Commission directs that DERS provide

supporting calculations in its compliance filing. ........................................... Paragraph 403

31. Given the above findings and recognizing the interrelationships among DELP, DEML

and DERS, and the fact that DEML business units provide both regulated and

unregulated services, the Commission directs DERS to develop an IACC to ensure that

interactions between regulated and unregulated affiliated companies are conducted in a

manner consistent with the principles set out in Decision 2002-069 and Decision 2003-

040. The Commission directs DERS to file an IACC by December 31, 2015. The current

internal IACC that governs the inter-affiliate relationships among the three entities may

suffice, if it is consistent with the principles set out in Decision 2002-069 and Decision

2003-040. ....................................................................................................... Paragraph 422

32. Accordingly, the Commission directs DERS to include in its compliance filing the

necessary supporting evidence and analysis to allow for full and thorough testing of its

proposed internal EPSP costs......................................................................... Paragraph 444


110 • Decision 2957-D01-2015 (July 7, 2015)

Appendix 4 – Default Rate Tariff Terms and Conditions

Appendix 4 - DERS

DRT Terms and Conditions (consists of 29 pages)


Decision 2957-D01-2015 (July 7, 2015) • 111

Appendix 5 – Regulated Rate Tariff Terms and Conditions

Appendix 5 - DERS

RRT Terms and Conditions (consists of 31 pages)

Direct Energy Regulated Services DRT Terms and Conditions

Direct Energy Regulated Services Gas Default Rate Tariff

Terms and Conditions of Default Rate Service

Pursuant to the Provisions of the

Gas Utilities Act and the Default Gas Supply Regulation

EFFECTIVE AUGUST 1, 2015


Direct Energy Regulated Services Appendix 4 - Default Rate Tariff Terms and Conditions

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Approved by Decision 2957-D01-2015 Effective August 1, 2015

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Table of Contents

TERMS AND CONDITIONS OF DEFAULT RATE SERVICE ............................................ 1

ARTICLE 1 PREAMBLE ........................................................................................................... 1

ARTICLE 2 DEFINITIONS AND INTERPRETATION .......................................................... 1

2.1 DEFINITIONS ........................................................................................................ 1 2.2 CONFLICTS .......................................................................................................... 4 2.3 HEADINGS ........................................................................................................... 4 2.4 EXTENDED MEANINGS.......................................................................................... 5 2.5 CHARGES AND FEES ............................................................................................ 5

ARTICLE 3 GENERAL PROVISIONS .................................................................................... 5

3.1 EFFECTIVE DATE ................................................................................................. 5 3.2 CUSTOMERS BOUND BY TERMS AND CONDITIONS .................................................. 5 3.3 MODIFICATION OF DEFAULT RATE TARIFF ............................................................. 6 3.4 REGULATORY APPROVAL AND AMENDMENT........................................................... 6 3.5 APPLICABLE TAXES .............................................................................................. 6 3.6 LANDLORD INFORMATION ..................................................................................... 6 3.7 OWNER’S LIABILITY FOR PAYMENT ........................................................................ 7

ARTICLE 4 REGULATED RATE SERVICE .......................................................................... 8

4.1 REQUIREMENTS FOR OBTAINING DEFAULT RATE SERVICE ..................................... 8 4.2 REFUSAL OF DEFAULT RATE SERVICE................................................................... 9 4.3 CREDIT INFORMATION ........................................................................................ 10 4.4 FAILURE TO PROVIDE INFORMATION .................................................................... 10

ARTICLE 5 FINANCIAL SECURITY REQUIREMENTS.................................................... 11

5.1 REQUIREMENT FOR DEPOSIT .............................................................................. 11 5.2 WAIVER OF DEPOSIT REQUIREMENT ................................................................... 11 5.3 FEES FOR CREDIT CHECK ................................................................................... 12 5.4 MAXIMUM DEPOSIT ............................................................................................ 12 5.5 USE OF DEPOSIT FOR NON-PAYMENT ................................................................. 12 5.6 RETURN OF DEPOSIT ......................................................................................... 13 5.7 INTEREST PAYABLE ON DEPOSITS ....................................................................... 13

ARTICLE 6 CLOSING AN ACCOUNT.................................................................................. 13

6.1 NOTICE TO CLOSE AN ACCOUNT ......................................................................... 13 6.2 RELOCATION OF CUSTOMER ............................................................................... 14 6.3 CUSTOMER CHANGE OF NAME OR INFORMATION ................................................. 14



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ARTICLE 7 MEASUREMENT OF ENERGY CONSUMPTION ......................................... 14

7.1 BILLING STANDARDS .......................................................................................... 14 7.2 METER TESTING ................................................................................................ 14

ARTICLE 8 BILLINGS AND PAYMENT ............................................................................... 15

8.1 BILLING PRACTICES ........................................................................................... 15 8.2 RESPONSIBILITY FOR PAYMENT .......................................................................... 15 8.3 RESPONSIBILITY TO PAY .................................................................................... 15 8.4 ADJUSTMENTS TO BILLS ..................................................................................... 16 8.5 LATE PAYMENT CHARGE .................................................................................... 16 8.6 REMEDIES FOR NON-PAYMENT ........................................................................... 16 8.7 RESTORATION OF DEFAULT RATE SERVICE ......................................................... 17 8.8 PARTIAL PAYMENTS ........................................................................................... 17 8.9 OVER PAYMENTS ............................................................................................... 18 8.10 DISHONORED PAYMENTS ................................................................................... 18 8.11 NOVELTY PAYMENTS ......................................................................................... 18 8.12 OTHER OCCUPANTS’ LIABILITY FOR PAYMENT ..................................................... 18 8.13 DISCONNECTION FOR INSUFFICIENT INFORMATION ............................................... 19 8.14 DISCONNECTION OF GAS SERVICES ..................................................................... 19

ARTICLE 9 RESPONSIBILITY AND LIABILITY ................................................................ 19

9.1 REQUIREMENTS IN THE GAS UTILITIES ACT AND REGULATION .............................. 19 9.2 INTERRUPTION OF DEFAULT RATE SERVICE ........................................................ 20 9.3 FORCE MAJEURE ............................................................................................... 20 9.4 LIMITATION OF DERS’ LIABILITY TO CUSTOMER ................................................... 20 9.5 DISTRIBUTION TARIFF ........................................................................................ 21 9.6 INDEMNIFICATION BY CUSTOMER ........................................................................ 21 9.7 INDEMNIFICATION BY DERS ............................................................................... 22

ARTICLE 10 DISPUTE RESOLUTION ................................................................................. 22

10.1 DISPUTED CHARGES .......................................................................................... 23 10.2 RESOLUTION BY DERS AND CUSTOMERS ........................................................... 23 10.3 RESOLUTION BY A THIRD PARTY ......................................................................... 24

ARTICLE 11 MISCELLANEOUS ........................................................................................... 24

11.1 COMPLIANCE WITH APPLICABLE LEGAL AUTHORITIES ........................................... 24 11.2 SERVICE GUARANTEE CREDIT ............................................................................ 24 11.3 NO ASSIGNMENT ............................................................................................... 26 11.4 NO WAIVER ....................................................................................................... 26



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Direct Energy Regulated Services Terms and Conditions of Default Rate Service

TERMS AND CONDITIONS OF DEFAULT RATE SERVICE

ARTICLE 1

PREAMBLE

ATCO Gas and Pipelines Ltd. ("ATCO Gas") has made arrangements with Direct

Energy Regulated Services ("DERS"), a business unit of Direct Energy Marketing

Limited, to provide Default Rate Service to Customers in the service territory of ATCO

Gas. DERS provides Default Rate Service to Customers under its Default Rate Tariff

that has been approved by the Commission.

DERS' Default Rate Tariff consists of these approved Terms and Conditions and the

attached Rate and Fee Schedules that sets out the rates and fees for certain services

related to the provision of Default Rate Service.

DERS' Default Rate Tariff is available for public inspection at DERS' website

www.directenergyregulatedservices.com and during normal business hours at DERS'

Calgary business office.

ARTICLE 2

DEFINITIONS AND INTERPRETATION

2.1 Definitions

The following words and phrases, whenever used in the Default Rate Tariff, shall have

the following meanings:

"Affiliated Retailer" has the meaning ascribed to that term in the GUA.

"ATCO Gas" means ATCO Gas and Pipelines Ltd.



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http://www.directenergyregulatedservices.com/



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“ATCO Terms and Conditions” means ATCO Gas' Terms and Conditions for

Distribution Access Service and Terms and Conditions of Distribution Service

Connections, as the case may be.

“AUC” means the Albert Utilities Commission established under the Alberta Utilities

Commission Act, R.S.A., 2007, c. A-37.2, as amended from time to time.

“Business Day” means any day other than Saturday, Sunday or a holiday as defined

in the Interpretation Act, R.S.A., 2000, c. I-8.

“Commission" means the Alberta Utilities Commission.

"Customer” has the meaning ascribed to that term in the GUA.

“Customer of Record” means the Customer for whom DERS has opened an account

pursuant to Section 4.1.

“Default Rate Service” means the service that is required by the GUA to be provided

in accordance with a default rate tariff.

“Default Rate Tariff” means DERS' default rate tariff approved by the Commission

including these Terms and Conditions and the Price Schedule.

“DERS” means Direct Energy Regulated Services, a business unit of Direct Energy

Marketing Limited.

“Facilities” means physical plant including, pipes, meters, works, equipment and

machinery.

“Fee Schedule” means the schedule of service items and prices attached to the Rate

Schedules.

“Force Majeure” means circumstances not reasonably within the control of DERS,

including acts of God, strikes, lockouts or other industrial disturbances, acts of the



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public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning,

earthquakes, fires, storms, floods, high water, washouts, inclement weather, orders or

acts of civil or military authorities, civil disturbances, explosions, breakdown or accident

to equipment, mechanical breakdowns, interruption of supply, goods or services

including Gas or Gas Distribution Service, the intervention of federal, provincial, state or

local government or from any of their agencies or boards, the order or direction of any

court, and any other cause, whether of the kind herein enumerated or otherwise. Any

order or direction of the Commission is expressly excluded from this definition.

"Gas" has the meaning ascribed to that term in the GUA.

"Gas Distribution Service" has the meaning ascribed to that term in the GUA and

provided to Customers by means of the Gas Distribution System of ATCO Gas.

"Gas Distribution System" has the meaning ascribed to that term in the GUA.

"Gas Distribution Tariff" means ATCO Gas' tariff for the provision of Gas Distribution

Service approved by the Commission and as amended from time to time.

"Gas Services" has the meaning ascribed to that term in the GUA.

"GUA" means the Gas Utilities Act, R.S.A. 2000, c.G-5 -, including the regulations

enacted thereunder, as amended.

"Minor Routine changes" means necessary routine administrative changes, such as,

corrections to paragraph numbers, punctuation or grammatical errors where the

changes do not alter the meaning of the clause.

"Person" means a person, firm, partnership, corporation, organization or association,

and includes an individual member thereof.

"Rate Schedules" means the rate schedules to the Default Rate Tariff and includes the

Fee Schedule.



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"Retailer" has the meaning ascribed to that term in the GUA.

"Service Connection" means the Facilities of ATCO Gas’ Distribution System that

delivers Gas to a Site.

"Site" means the point where a Customer receives Gas by means of a Service

Connection.

"Terms and Conditions" means these Terms and Conditions of Default Rate Service,

as amended from time to time.

"UCA" means the Utilities Consumer Advocate.

2.2 Conflicts

If there is any conflict between these Terms and Conditions and a provision expressly

set out in an order of the Commission, the provision of the Commission's order shall

govern.

If there is any conflict between these Terms and Conditions and a provision of the GUA

or related Regulations, the provision of the GUA shall govern.

If there is any conflict between these Terms and Conditions and the corresponding Rate

Schedules, the Rate Schedules shall govern.

2.3 Headings

The division of these Terms and Conditions into sections, subsections and other

subdivisions and the insertion of headings are for convenience of reference only and

shall not affect the construction or interpretation of these Terms and Conditions.



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2.4 Extended Meanings

In these Terms and Conditions, words importing the singular number only shall include

the plural and vice versa, words importing the masculine gender shall include the

feminine and neutral gender and vice versa and words importing persons shall include

individuals, partnerships, associations, trusts, unincorporated organizations and

corporations.

2.5 Charges and Fees

All rates, charges and fees referred to in these Terms and Conditions are as set out in

the Rate Schedules and/or the Fee Schedule for DERS.

ARTICLE 3

GENERAL PROVISIONS

3.1 Effective Date

These Terms and Conditions have been approved by the Commission in Decision

2957-D01-2015, and are effective as of August 1, 2015.

3.2 Customers Bound by Terms and Conditions

The Default Rate Tariff and the Rate Schedules approved by the Commission apply to

each Customer. As a condition of receiving Default Rate Service, the Customer agrees

to be bound by these Term and Conditions and agrees to pay the rates and fees

applicable for such service, as prescribed in the Rate Schedules whether the Customer

signs a service agreement or not.



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3.3 Modification of Default Rate Tariff

No agent, employee or other representative of DERS is authorized to modify any

provision or rate contained in the Default Rate Tariff or to bind DERS to perform in any

manner inconsistent with the Default Rate Tariff. Any request for the waiver or alteration

of any part of the Default Rate Tariff must be filed with and approved by the

Commission. DERS may make Minor Routine changes by filing updated Terms and

Conditions with the Commission.

3.4 Regulatory Approval and Amendment

Other than Minor Routine changes as per Section 3.3 DERS may only amend these

Terms and Conditions with approval of the Commission. Whenever the Commission

approves an amendment to these Terms and Conditions or an amendment otherwise

takes effect, these Terms and Conditions will be revised to incorporate such

amendments. The Commission will acknowledge the notice of the amendment to the

Terms and Conditions within 60 days after such notice is filed or the Commission will

direct a further process to deal with the requested changes as the Commission deems

to be appropriate.

3.5 Applicable Taxes

The Customer shall pay all taxes, fees or assessments that DERS is required to collect

from time to time as required pursuant to any statute, regulation, or other governmental

directive or order or decision of the Commission that applies to Default Rate Service.

3.6 Landlord Information

DERS may require the Customer to indicate if the Customer is the owner of the premise

or a tenant. Where the Customer is a tenant, DERS may request landlord information.

The landlord information will be retained by DERS to continue service after service to



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the Customer is terminated and no new tenant has assumed service. DERS will verify

with the landlord the information provided and will notify the landlord when the service is

being transferred to the landlord, along with the reason for the transfer. The landlord

shall not be responsible for any arrears owed by the tenant unless the landlord

expressly indicates it is assuming such liability.

DERS will provide landlords with the opportunity to register all Sites that they own and

are responsible for in the case of a vacancy. This will not bind the landlord to be

responsible for past charges of a tenant unless specifically requested by the landlord.

3.7 Owner’s Liability for Payment

In circumstances where:

a) there is no Customer registered on the account records of DERS; and

b) there are no other occupants of the Site who continue to receive service

The Property Owner will be deemed to be the Customer of Record and will be liable for

payment for Services provided in accordance with the Default Rate Tariff until the date a

new Customer is determined by DERS.

RENTAL PREMISES

As option for service to rental premises, an owner or operator who wishes DERS to

consider dealing directly with a tenant or tenants may enter into a premise vacancy

agreement with DERS which provides for responsibilities of the owner or operator in

relation to payment for service used in the premises. Notwithstanding any premise

vacancy agreement DERS may, at its sole option at any time and from time to time,

either:

a) deal directly with the owner or operator of the premises as a customer

of record in respect to any and/or all services to the premises, or



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b) subject always to the provisions of any premise vacancy agreement,

deal directly with each tenant as a customer of record.

Nothing in these Terms and Conditions require a landlord to enter into such an

agreement. Should the landlord elect not to enter into a premise vacancy agreement,

DERS will deal directly with the tenant.

ARTICLE 4

REGULATED RATE SERVICE

4.1 Requirements for Obtaining Default Rate Service

Eligibility for a prospective Customer to obtain Default Rate Service shall be determined

in accordance with the GUA and Regulations. DERS may require any potential

residential Customer to provide such proof of identification, as DERS considers

appropriate in the circumstances.

A potential Customer, other than a residential Customer, who is not receiving Default

Rate Service from DERS, may be required to complete an application in writing, or via

telephone, to obtain Default Rate Service at a Site.

A residential customer may request service via telephone or other means defined by

DERS.

When an application is required, DERS will provide an application form outlining the

required information to be provided. For an existing premise or property, DERS will

open an account and commence Default Rate Service within 7 days of receiving a

completed application from a Customer. Where circumstances beyond the control of

DERS prevent DERS from opening an account and commencing Default Rate Service

within 7 days, DERS will notify the customer and will provide the customer with an

estimate of when the account will be opened.



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Expedited connection of Default Rate Service may be available at an additional charge

in accordance with the Rate Schedules.

If DERS approves a Customer’s application for Default Rate Service, DERS will open

an account for the Customer for Default Rate Service at the applied for Site and the

Customer shall be the “Customer of Record” for such Site.

Subject to Section 8.2, the Customer will be responsible to pay to DERS all amounts

charged in accordance with these Terms and Conditions and applicable Rate

Schedules to the account for services provided from the time the account is opened, or

the customer becomes responsible for charges, until the account is closed as provided

in Section 6.1, or if Default Rate Service is discontinued or disconnected as provided in

Sections 4.4 and 8.7.

4.2 Refusal of Default Rate Service

DERS reserves the right to refuse to provide Default Rate Service to a prospective

Customer when:

a) the prospective Customer cannot demonstrate a satisfactory credit rating

or credit history as outlined in Section 4.3 below and the prospective

Customer has not provided the deposit required by DERS pursuant to

Section 5.1;

b) the prospective Customer has an outstanding balance with DERS or a

regulated affiliate; or

c) the prospective Customer has not complied with the applicable provisions

of these Terms and Conditions.

DERS reserves the right to refuse to provide Default Rate Service to a prospective

Customer at a Site when a previous Customer at the Site had a history of non-payment



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and DERS has reasonable grounds to believe that the defaulting Customer would

continue to occupy the premises located at the Site.

Subject to limitations outlined in applicable regulations, and on 48 hours oral or written

notice to a Customer and without further notice, DERS may disconnect service if DERS

has not been provided with sufficient information to bill the customer or the premises or

property reasonably appears to be vacant or not occupied by the known Customer.

4.3 Credit Information

DERS may, at any time, request from a Customer, such information as DERS considers

reasonably necessary to determine the Customer's credit history and credit risk. Such


a) The Customer’s full name, address, telephone numbers (home, work and

cellular), and birthdate to allow DERS to determine a Customer’s credit

rating, and/or

b) demonstration of the Customer’s credit history with another regulated

utility, and/or

c) other personal information sufficient to identify the prospective Customer

and determine the Customer’s credit history and credit risk.


Canadian Credit Bureaus with respect to Customer payments and/or non-payments.

4.4 Failure to Provide Information

If, after notice of a deficiency, and reasonable opportunity to remedy any deficiencies, a

prospective Customer or existing Customer fails to provide information requested in

accordance with Section 4.3 and does not provide a security deposit in accordance with

Article 5, then DERS may either:



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a) refuse to provide Default Rate Service to the prospective Customer, or

b) discontinue or request a disconnection of Default Rate Service to the

existing Customer.

ARTICLE 5

FINANCIAL SECURITY REQUIREMENTS

5.1 Requirement for Deposit

DERS, may require a deposit or an increase in an existing deposit by a Customer in

circumstances it considers appropriate, including in the following circumstances:

a) if the prospective Customer making the application for service cannot

demonstrate a satisfactory credit rating to DERS as outlined in Section

4.3;

b) the existing Customer has paid two consecutive bills late in any twelve

month period or three non-consecutive bills late in any twelve month

period;

c) the Customer has issued more than one payment that has been returned

for non-sufficient funds in any six month period;

d) there has been more than a 50% increase in the Customer's average

monthly consumption of Gas over the prior six month period; or

e) the Customer makes a request for reconnection of service after having

been disconnected for non-payment.

5.2 Waiver of Deposit Requirement

DERS, may waive the requirement for a deposit by Customer:



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a) where the Customer has a previous good payment history with DERS;

b) where a result satisfactory to DERS is obtained from an external credit

check;

c) where the Customer can demonstrate that it has a previous good payment

history with another regulated utility;

d) where the Customer provides to DERS an indemnity bond or irrevocable

letter of credit from a financial institution satisfactory to DERS.

5.3 Fees for credit check

DERS may charge the cost of performing an external credit check to the customer.

5.4 Maximum Deposit

The maximum deposit DERS will require from a Customer under its Default Rate Tariff

is equal to 30% of the annual total charge payable by the Customer, as reasonably

estimated by DERS.

If the required deposit is large at the discretion of DERS, DERS may grant a Customer

request that the Company allow an initial payment for a portion of the deposit and

payment of the remainder of the deposit over a reasonable time period.

5.5 Use of Deposit for Non-Payment

A deposit provided by a Customer may be applied against any amounts owing for

unpaid bills for Default Rate Service. A new security deposit will be assessed on the

account in this case.



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5.6 Return of Deposit

A deposit made by a Customer must be returned to the Customer after a satisfactory

payment history after a period of 12 consecutive months or when the Customer’s

Default Rate Service is terminated and the Customer’s account is closed.

Where a Customer’s Default Rate Service is terminated and the Customer’s account is

closed for non-payment, prior to any refund, the deposit will be applied to the balance

owing by the Customer to DERS.

5.7 Interest Payable on Deposits

Deposits, unless otherwise applied, will be refunded with interest at a rate equivalent to

the one-year non-redeemable Royal Bank GIC rate for investments of $500 to

$99,999.99 to the Customer after the Customer establishes a satisfactory payment

record.

The interest rate applied to security deposits will be updated quarterly and will be the

one-year non-redeemable Royal Bank GIC rate for investments of $500 to $99,999.99

in effect five business days prior to the start of the quarter.

Interest shall accrue monthly beginning with the initial date of deposit. Interest will only

be payable to customers after twelve months of satisfactory payment history.

ARTICLE 6

CLOSING AN ACCOUNT

6.1 Notice to Close an Account

A Customer may close an account for Default Rate Service at a Site by giving DERS at

least three full Business Days notice to close the account. DERS may request



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reasonable proof that the Customer will no longer be responsible for the Site after that

date.

6.2 Relocation of Customer

If the Customer wishes to relocate from the Site, the customer must notify DERS at

least three full business days prior to relocation of the address of its new location.

6.3 Customer Change of Name or Information

The Customer must notify DERS as soon as reasonably possible of a change of name,

mailing address or telephone number. Such notification shall be provided in writing if

requested by DERS.

ARTICLE 7

MEASUREMENT OF ENERGY CONSUMPTION

7.1 Billing Standards

DERS shall comply with any billing standards code as published by the Commission.

7.2 Meter Testing

If a Customer believes his or her meter to be in error, the customer will arrange to have

the meter tested by ATCO Gas. The Customer will pay DERS all charges for meter

testing incurred by DERS in accordance with the ATCO Terms and Conditions.

There shall be no cost to the Customer if the meter is found to be in error.



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ARTICLE 8

BILLINGS AND PAYMENT

8.1 Billing Practices

DERS provides Default Rate Services to Customers and does not require payment in

advance, except where a deposit is required in accordance with these Terms and

Conditions. DERS will bill in accordance with related regulations or Commission

directives on billing processes and quality.

8.2 Responsibility for Payment

The Customer is responsible for payment for all Default Rate Service provided to the

Customer up to the time DERS has closed the account and, until payment for final

charges for consumption has been made.

If a Customer’s Default Rate Service is discontinued by DERS or disconnected under

the ATCO Terms and Conditions, the Customer is responsible for payment for all

Default Rate Service provided to the Customer up to the time of such discontinuation or

disconnection, and until payment for final charges for consumption has been made.

8.3 Responsibility to Pay

A bill issued to the Customer by DERS shall be paid in full by the due date specified on

the bill, such due date not to be less than 13 business days following the issuance of

the bill. If a Customer loses their bill, they shall not be relieved of their obligation to pay

the bill in full by the due date. Payments shall be without prejudice to the Customer’s

right to contest any rate or fee charged.



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8.4 Adjustments to Bills

Bills rendered by DERS shall contain the information prescribed in applicable

legislation. Bills rendered by DERS may be adjusted from time to time to, among other

things, reflect adjustments by ATCO Gas under its Gas Distribution Tariff and DERS will

issue refunds or charges as appropriate to the affected customers.

8.5 Late Payment Charge

The amount due shown on a bill is owing to DERS on the statement date. If a Customer

does not pay a bill in full within seventeen (17) calendar days after the statement date

specified on the bill, subject to disputed charge as outlined in Section 10, a late

payment charge may be applied. The outstanding unpaid amount, including the late

payment charge, shall be added to the charges that become due and payable in the

next bill. DERS will disclose the late payment fee in its Fee Schedule.

8.6 Remedies for Non-Payment

If a bill remains unpaid after the due date or grace period, DERS may require a deposit

or an increase in the amount of an existing deposit.

Subject to any restrictions under the GUA and Regulations or Section 10 of these

Terms and Conditions, failure to pay a bill may result in DERS either discontinuing the

Customer's Default Rate Service or requesting a disconnection of such service.

In addition, DERS may commence collection action. Prudent and reasonable collection

costs incurred by DERS may be added to the Customer's bill.

If a Customer's Default Rate Service is discontinued by DERS or disconnected under

the ATCO Terms and Conditions, any unpaid charges in the account may be transferred

to any other Default Rate Service account held by the same Person and any deposit

held in respect of such account may be applied against the unpaid charges.



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DERS will notify the Customer when an account is in arrears and will provide an

opportunity to resolve any arrears prior to taking action. Normal credit actions may

include, but is not limited to the following:

a) written notice and/or telephone call and/or door to door notice to the

customer indicating payment has not been received and timing for future

action if payment or other arrangements have not been made.

b) written notice and/or telephone call indicating pending notice of

disconnection and timing of disconnection action.

c) subject to limitations on disconnection outlined in legislation and

regulations, initiate disconnection.

d) the use of collection agencies.

e) legal action.

8.7 Restoration of Default Rate Service

In order for Default Rate Service to be restored after it has been discontinued or

disconnected for non-payment, the Customer must pay all outstanding bills in full,

provide a deposit to DERS and pay the reconnection fee prescribed in the Rate

Schedules. At DERS’ discretion, DERS may allow the Customer to make payment

arrangements to settle arrear amounts over a reasonable amount of time.

8.8 Partial Payments

Partial payments on an account will be applied to the unpaid amounts outstanding on

the longest outstanding bills.



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8.9 Over Payments

If the Customer pays DERS an amount in excess of what is owed to DERS, the excess

amount will be carried as a credit balance on the Customer’s account and applied to

bills for future Default Rate Services unless the Customer requests a refund. Interest

will not be paid on credit balances.

8.10 Dishonored Payments

In addition to any late payment charge under Section 8.2 of these Terms and

Conditions, a Customer whose payment is dishonored shall pay the charge as specified

in the Rate Schedules.

8.11 Novelty Payments

DERS may refuse to accept payment when the Customer attempts to make payment by

a cheque drawn on a form other than a bank cheque. DERS follows the coin

acceptance limitations specified in the Currency Act, S.C. 1985 c. C-52 as follows:

Payment in coin may be made to the maximum amount of:

Forty dollars if the denomination is two dollars or greater but does not exceed ten

dollars,

Twenty-five dollars if the denomination is one dollar,

Ten dollars if the denomination is ten cents or greater but less than one dollar,

Five dollars if the denomination is five cents, and

Twenty-five cents if the denomination is one cent.

8.12 Other Occupants’ Liability for Payment

Where a Customer of Record for a Site has defaulted on payment of a bill for Default

Rate Service and DERS reasonably believes that the occupant receiving service at the



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site is related to or associated with the previous Customer of Record, the other

occupants will be deemed the current Customer of Record.

8.13 Disconnection for Insufficient Information

If DERS has not been provided with sufficient information to bill a Customer, or the

premises or property served by a Site reasonably appears to be vacant or not occupied

by the Customer of Record, DERS may provide written notice of the deficiency to the

customer or owner or to the site location. Following a reasonable opportunity to provide

the requested information, if the Customer has not provided such information and

subject to limitations on disconnections outlined in legislation and regulations, DERS

may request ATCO Gas to disconnect service.

8.14 Disconnection of gas services

DERS will not request ATCO Gas to disconnect services to residential and commercial

residential, including multifamily sites, between November 1 to April 14 of the following

year or when the overnight temperature is forecast to drop below zero(0) degrees

Celsius in the 24 hour period immediately following the proposed disconnect unless

written request is provided by the property owner.

ARTICLE 9

RESPONSIBILITY AND LIABILITY

9.1 Requirements in the Gas Utilities Act and Regulation

In addition to any rights and obligations contained in these Terms and Conditions,

DERS is governed and bound by the GUA and Regulations.

DERS shall maintain security standards, including control of access to data and other

information, consistent with the highest standards of business practice in the industry.



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9.2 Interruption of Default Rate Service

DERS does not own or operate the Gas Distribution System and does not guarantee

continuous Default Rate Service.

DERS will endeavor at all times to provide regular and uninterrupted Default Rate

Service to Customers.

9.3 Force Majeure

DERS, is relieved of its obligations under the Default Rate Tariff including these Terms

and Conditions, and shall not be liable for any failure to perform any service under the

Default Rate Tariff or any term of these Terms and Conditions to the extent that and

when such failure is due to, or is a consequence of, any event of Force Majeure.

Should a residence or business being served be suspended or discontinued, due to fire

or any other causes beyond the control of the Customer, any services, and related fees

and charges except pass through charges from ATCO Gas, upon request by the

Customer, shall become inoperative until business is resumed, except for unbilled

amounts due to DERS for service theretofore rendered by it, at which time any service

and related fees shall again become operative. Upon resumption of service, the

Customer’s credit standing with DERS will be no worse than it was prior to the

suspension of service.

9.4 Limitation of DERS’ Liability to Customer

Except for direct physical damage, loss or injury to a Customer or a Customer's property

resulting from the negligence or willful misconduct of, or breach of these Terms and

Conditions by DERS or its employees, agents or contractors acting within the scope of

their employment, DERS shall not be liable to a Customer, whether in tort, contract,

strict liability or otherwise, for any loss, damage, expense, charge, cost or other liability

of any kind suffered or incurred by the Customer arising out of or in any way connected



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with any interruption, defect, irregularity, failure, curtailment or reduction in Default Rate

Service. Under no circumstances or for any reason shall DERS be liable to a customer

for any loss, injury or damage of an indirect, special, exemplary, punitive or

consequential nature including, without limitation, loss of revenues, loss of profits, loss

of earnings, loss of contract, loss of opportunity, cost of capital, business interruption,

claims of a Customer's customers, contractors or other third parties or any other similar

loss, damage, expense, cost or liability whatsoever, whether or not any such loss,

damage, expense, cost or liability was foreseeable.

Any claim by a Customer for loss, injury or damage, must be filed with DERS within two

years from the date of occurrence of the incident that is the subject of the claim, failing

which DERS shall have no liability to the Customer for any such loss, injury or damage.

9.5 Distribution Tariff

Each Customer shall be responsible for the Service Connection to a Site to permit the

Customer to receive Default Rate Service. As a condition of receiving Default Rate

Service, each Customer agrees to be bound by, and shall comply with, all provisions of

the Gas Distribution Tariff applicable to the Customer.

9.6 Indemnification by Customer

Each Customer shall indemnify and hold DERS and its employees, agents and

contractors harmless from and against any claim for any loss, damage, expense,

charge, cost, penalty or other liability of any kind suffered or incurred by DERS

(including charges or liability arising under the ATCO Gas’ Gas Distribution Tariff)

arising out of or in any way connected with any failure by the Customer or its Facilities

to comply with any of the provisions of the ATCO Gas’ Gas Distribution Tariff applicable

to the Customer or its Facilities or any legal or regulatory requirement related to Gas

Distribution Service required to be complied with by the Customer.



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Without limiting the generality of the foregoing, Customer shall be liable to compensate

DERS for any costs, expenses or liabilities that it incurs under the provisions of the

ATCO Terms and Conditions arising out of or connected with any action or inaction of

the Customer related to Default Rate Service.

9.7 Indemnification by DERS

DERS shall indemnify and hold a Customer harmless from and against direct physical

loss, injury or damage to the Customer or the Customer's property resulting from the

negligence or willful misconduct of DERS or its employees, agents or contractors acting

within the scope of their employment or breach of these Terms and Conditions. Under

no circumstances or for any reason shall DERS be liable to a Customer for any loss,

injury or damage of an indirect, special, exemplary, punitive or consequential nature

including, without limitation, loss of revenues, loss of profits, loss of earnings, loss of

contract, loss of opportunity, cost of capital, business interruption, claims of a

Customer's customers, contractors or other third parties or any other similar loss,

damage, expense, cost or liability whatsoever, whether or not any such loss, damage,

expense, cost or liability was foreseeable.

Any claim by a Customer for indemnity for loss, injury or damage, must be filed with

DERS within two years from the date of occurrence of the incident that is the subject of

the claim, failing which DERS shall have no obligation to indemnify the Customer for

any such loss, injury or damage.

ARTICLE 10

DISPUTE RESOLUTION

Without limiting any party’s right under the GUA or Regulations to make complaints to

the Commission, both parties, acting in good faith shall endeavour to resolve

differences prior to taking any action to the Commission. Consumers are encouraged to

contact DERS first with any issues prior to escalating the issue to the UCA or the AUC.



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10.1 Disputed Charges

The Customer has a right to dispute any charge shown on the Customer’s bill by

contacting DERS either in writing or by telephone. DERS will investigate all disputes

and make any adjustments DERS determines appropriate. If the dispute is within DERS’

control and is not resolved within 30 day from the notice, the Customer can escalate the

dispute as provided in Section 10.2 and 10.3 and the Customer will not be required to

pay any charges for the disputed period that are in excess of the average monthly bill of

the Customer as reasonably determined by DERS. The Customer will be responsible to

pay all past and future charges while the specific charge in dispute is being resolved.

Any outstanding disputed amount shall be due and payable within 10 business days of

resolution. No additional charges will be applied to disputed amounts.

10.2 Resolution by DERS and Customers

If any dispute between DERS and a Customer arises at any time in connection with

these Terms and Conditions, DERS and the Customer, acting reasonably and in good

faith, shall use their reasonable efforts to resolve the dispute as soon as possible in an

amicable manner. If the dispute cannot be otherwise resolved pursuant to this Section

10.2, a senior representative of DERS and the Customer shall meet to attempt to

resolve the dispute.

During the course of a dispute that has been escalated to the AUC in accordance with

Section 10.1 of these Terms and Conditions DERS shall not terminate or suspend

service for reasons of the escalated dispute, but may terminate or suspend service if a

Customer is in contravention of other aspects of these Terms and Conditions or in

violation of the ATCO Terms and Conditions.



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10.3 Resolution by a Third Party

If any dispute has not been resolved pursuant to Section 10.2 within a reasonable time,

DERS and the Customer may pursue the matter with the AUC if the matter is within the

AUC's jurisdiction or pursue in Alberta any remedies available to them under applicable

laws, including arbitration pursuant to the Arbitration Act (Alberta).

ARTICLE 11

MISCELLANEOUS

11.1 Compliance with Applicable Legal Authorities

DERS and the Customer are subject to, and shall comply with, all existing or future

applicable federal, provincial and local laws, all existing or future orders or other actions

of the AUC, or governmental authorities having applicable jurisdiction. DERS or the

Customer will not be required to violate, directly or indirectly, or become a party to a

violation of any requirement of any applicable federal, provincial or local statute,

regulation, bylaw, rule or order in order to provide or receive Default Rate Service.

DERS' obligation to provide any Default Rate Service is subject to the condition that all

requisite governmental and regulatory approvals for the provision of the Default Rate

Service will have been obtained and will be in force during the period of Default Rate

Service.

11.2 Service Guarantee Credit

(1) In accordance with AUC Rule 003, DERS must provide a credit of $75 to any

customer who is subject to one of the following errors made by DERS:

a) Customer was provided written notice of pending disconnection of service in

error;



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b) Customer was provided written notice of pending referral to a credit agency in

error;

c) Customer was referred to a credit agency in error; or

d) Customer experienced disconnection of service in error.

(2) Payment of the $75 credit is not required where no error has been made by DERS,

and in particular is not required in the following circumstances:

a) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice and the customer’s payment

crossed in the mail;

b) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice was in mail transit at the

time the customer made or attempted to make payment by visiting the

premises of an authorized payment acceptance establishment, such as bank,

trust company or credit union;

c) The electric or gas distributor disconnected a customer in error, rather than

as instructed by DERS;

d) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice was properly mailed but the

customer did not pick up the mail from locations such as a post office, super

mail box or home mail box;

e) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice was undelivered by the mail

delivery service.



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f) The customer attempted to make payment to the person dispatched by the

electric or gas distributor to disconnect the service, where such disconnection

was not made in error, but the person was not authorized to accept payment.

11.3 No Assignment

Service under the Default Rate Tariff is not assignable.

The benefits and obligations of any service contract shall begin when DERS

commences to supply Default Rate Service, and shall inure to the benefit of and be

binding upon the respective heirs, personal representatives and successors.

This limit on assignment is not intended to infringe on or limit the right of customer to

sell, remove or otherwise lawfully dispose of customer’s property, subject to the

termination clauses of these Terms and Conditions. Upon termination, any outstanding

balances will remain the obligation of the customer.

11.4 No Waiver

The failure of either party to insist on any one or more instances upon strict

performance of any provisions of these Terms and Conditions or to take advantage of

any of its rights hereunder, shall not be construed as a waiver of any such provisions or

the relinquishment of any such right or any other right hereunder or thereunder, which

shall remain in full force and effect. No provision of these Terms and Conditions shall be

deemed to have been waived and no breach excused unless such waiver or consent to

excuse is in writing and signed by the party claimed to have waived or consented to

excuses.



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Direct Energy Regulated Services RRT Terms and Conditions

Direct Energy Regulated Services Electricity Regulated Rate Tariff

Terms and Conditions of Regulated Rate Service

Pursuant to the Provisions of the

Electric Utilities Act and the Regulated Rate Option Regulation

EFFECTIVE AUGUST 1, 2015


Direct Energy Regulated Services Appendix 5 - Regulated Rate Tariff Terms and Conditions

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Table of Contents

TERMS AND CONDITIONS OF REGULATED RATE SERVICE ...................................... 1

ARTICLE 1 PREAMBLE ........................................................................................................... 1

ARTICLE 2 DEFINITIONS AND INTERPRETATION .......................................................... 1

2.1 DEFINITIONS .............................................................................................................. 1 2.2 CONFLICTS ................................................................................................................. 4 2.3 HEADINGS .................................................................................................................. 5 2.4 EXTENDED MEANINGS .............................................................................................. 5 2.5 CHARGES AND FEES ................................................................................................. 5

ARTICLE 3 GENERAL PROVISIONS .................................................................................... 5

3.1 EFFECTIVE DATE ....................................................................................................... 5 3.2 CUSTOMERS BOUND BY TERMS AND CONDITIONS ................................................. 6 3.3 MODIFICATION OF REGULATED RATE TARIFF .......................................................... 6 3.4 REGULATORY APPROVAL AND AMENDMENT ........................................................... 6 3.5 APPLICABLE TAXES ................................................................................................... 7 3.6 LANDLORD INFORMATION ......................................................................................... 7 3.7 OWNER’S LIABILITY FOR PAYMENT .......................................................................... 7

ARTICLE 4 REGULATED RATE SERVICE .......................................................................... 8

4.1 REQUIREMENTS FOR OBTAINING REGULATED RATE SERVICE .............................. 8 4.2 REFUSAL OF REGULATED RATE SERVICE ............................................................. 10 4.3 CREDIT INFORMATION ............................................................................................. 10 4.4 FAILURE TO PROVIDE INFORMATION ...................................................................... 11

ARTICLE 5 FINANCIAL SECURITY REQUIREMENTS.................................................... 12

5.1 REQUIREMENT FOR DEPOSIT ................................................................................. 12 5.2 WAIVER OF DEPOSIT REQUIREMENT ..................................................................... 12 5.3 FEES FOR CREDIT CHECK ....................................................................................... 13 5.4 MAXIMUM DEPOSIT ................................................................................................. 13 5.5 USE OF DEPOSIT FOR NON-PAYMENT ................................................................... 13 5.6 RETURN OF DEPOSIT .............................................................................................. 14 5.7 INTEREST PAYABLE ON DEPOSITS ......................................................................... 14

ARTICLE 6 CLOSING AN ACCOUNT.................................................................................. 14

6.1 NOTICE TO CLOSE AN ACCOUNT ............................................................................ 14 6.2 NOTICE TO TRANSFER TO AN UNREGULATED RETAILER ...................................... 15 6.3 RELOCATION OF CUSTOMER .................................................................................. 15 6.4 CUSTOMER CHANGE OF NAME OR INFORMATION ................................................. 15



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ARTICLE 7 MEASUREMENT OF ENERGY CONSUMPTION ......................................... 15

7.1 BILLING STANDARDS ............................................................................................... 15 7.2 METER TESTING ...................................................................................................... 15

ARTICLE 8 BILLINGS AND PAYMENT ............................................................................... 16

8.1 BILLING PRACTICES................................................................................................. 16 8.2 RESPONSIBILITY FOR PAYMENT ............................................................................. 16 8.3 RESPONSIBILITY TO PAY ......................................................................................... 16 8.4 ADJUSTMENTS TO BILLS ......................................................................................... 17 8.5 LATE PAYMENT CHARGE ........................................................................................ 17 8.6 REMEDIES FOR NON-PAYMENT .............................................................................. 17 8.7 RESTORATION OF REGULATED RATE SERVICE ..................................................... 18 8.8 PARTIAL PAYMENTS ................................................................................................ 19 8.9 OVER PAYMENTS .................................................................................................... 19 8.10 DISHONORED PAYMENTS ........................................................................................ 19 8.11 NOVELTY PAYMENTS .............................................................................................. 19 8.12 OTHER OCCUPANTS’ LIABILITY FOR PAYMENT ...................................................... 20 8.13 DISCONNECTION FOR INSUFFICIENT INFORMATION .............................................. 20

ARTICLE 9 RESPONSIBILITY AND LIABILITY ................................................................ 20

9.1 REQUIREMENTS IN THE ELECTRIC UTILITIES ACT AND REGULATIONS ................ 20 9.2 INTERRUPTION OF REGULATED RATE SERVICE .................................................... 21 9.3 FORCE MAJEURE ..................................................................................................... 21 9.4 LIMITATION OF DERS' LIABILITY TO CUSTOMER ................................................... 21 9.5 DISTRIBUTION TARIFF ............................................................................................. 22 9.6 INDEMNIFICATION BY CUSTOMER ........................................................................... 22 9.7 INDEMNIFICATION BY DERS ................................................................................... 23

ARTICLE 10 DISPUTE RESOLUTION ................................................................................. 24

10.1 DISPUTED CHARGES ............................................................................................... 24 10.2 RESOLUTION BY DERS AND CUSTOMERS ............................................................. 24 10.3 RESOLUTION BY A THIRD PARTY ............................................................................ 25

ARTICLE 11 MISCELLANEOUS ........................................................................................... 25

11.1 COMPLIANCE WITH APPLICABLE LEGAL AUTHORITIES .......................................... 25 11.2 SERVICE GUARANTEE CREDIT ............................................................................... 26 11.3 NO ASSIGNMENT ..................................................................................................... 27 11.4 NO WAIVER .............................................................................................................. 27



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Page 1 of 28 Direct Energy Regulated Services

Terms and Conditions of Regulated Rate Service

TERMS AND CONDITIONS OF REGULATED RATE SERVICE

ARTICLE 1

PREAMBLE

ATCO Electric Ltd. ("ATCO Electric") has made arrangements with Direct Energy

Regulated Services ("DERS"), a business unit of Direct Energy Marketing Limited, to

provide Regulated Rate Service to Eligible Customers in the service area of ATCO

Electric. DERS provides Regulated Rate Service to Eligible Customers under its

Regulated Rate Tariff that has been approved by the Commission.

DERS' Regulated Rate Tariff consists of these approved Terms and Conditions and the

attached Rate and Fee Schedules that sets out the rates and fees for certain services

related to the provision of Regulated Rate Service.

DERS’ Regulated Rate Tariff is available for public inspection at DERS' website

www.directenergyregulatedservices.com and during normal business hours at DERS’

business office.

ARTICLE 2

DEFINITIONS AND INTERPRETATION

2.1 Definitions

The following words and phrases, whenever used in the Regulated Rate Tariff, shall

have the following meanings:

"Affiliated Retailer" has the meaning ascribed to that term in the EUA.

"ATCO Electric" means ATCO Electric Ltd.



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Direct Energy Regulated Services Terms and Conditions of Regulated Rate Service

"ATCO Terms and Conditions" means ATCO Electric's Terms and Conditions for

Distribution Access Service and Terms and Conditions of Distribution Service

Connections, as the case may be.

“AUC” means the Alberta Utilities Commission established under the Alberta Utilities

Commission Act, R.S.A., 2007, c. A-37.2, as amended from time to time.

"Business Day" means any day other than Saturday, Sunday or a holiday as defined in

the Interpretation Act, R.S.A., 2000, c. I-8.

"Commission" means the Alberta Energy and Utilities Commission

"Customer" means an Eligible Customer who has not selected a retailer.

"Customer of Record" means the Customer for whom DERS has opened an account

pursuant to Section 4.1.

"DERS" means Direct Energy Regulated Services, a business unit of Direct Energy

Marketing Limited.

"Distribution Access Service" has the meaning ascribed to that term in the EUA and

provided to Customers by means of ATCO Electric's Distribution System.

"Distribution System" has the meaning ascribed to that term in the EUA.

"Distribution Tariff" means ATCO Electric's tariff for the provision of Distribution

Access Service approved by the Commission and as amended from time to time.

"Electricity" has the meaning ascribed to that term in the EUA, expressed in kilowatt

hours.

"Electricity Services" has the meaning ascribed to that term in the EUA.



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"Eligible Customer" has the meaning ascribed to that term in the Regulated Rate

Option Regulation, AR 262/2005, as amended.

"EUA" means the Electric Utilities Act, S.A. 2003, c.E-5.1, including the regulations

enacted thereunder, as amended.

"Facilities" means physical plant including, without limitation, transmission and

distribution lines, transformers, meters, equipment and machinery.

"Fee Schedule" means the schedule of service items and prices attached to the Rate

Schedules.

"Force Majeure" means circumstances not reasonably within the control of DERS,

including acts of God, strikes, lockouts or other industrial disturbances, acts of the

public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning,

earthquakes, fires, storms, floods, high water, washouts, inclement weather, orders or

acts of civil or military authorities, civil disturbances, explosions, breakdown or accident

to equipment, mechanical breakdowns, interruption of supply, goods or services

including Electricity or Distribution Access Service, the intervention of federal, provincial,

state or local government or from any of their agencies or boards, the order or direction

of any court, and any other cause, whether of the kind herein enumerated or otherwise.

Any order or direction of the Commission is expressly excluded from this definition.

"Independent System Operator" means the meaning ascribed to that term in the

EUA.

"Interconnected Electric System" has the meaning ascribed to that term in the EUA.

"Minor Routine changes" means necessary routine administrative changes, such as,

corrections to paragraph numbers, punctuation or grammatical errors where the

changes do not alter the meaning of the clause.



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"Person" means a person, firm, partnership, corporation, organization or association,

and includes an individual member thereof.

"Rate Schedules" means the rate schedules to the Regulated Rate Tariff and includes

the Fee Schedule.

"Regulated Rate Service" means the service that is required by the EUA to be

provided in accordance with a Regulated Rate Tariff.

"Regulated Rate Tariff" means DERS' regulated rate tariff approved by the

Commission including these Terms and Conditions and the Rate Schedules.

"Retailer" has the meaning ascribed to that term in the EUA.

"Service Connection" means the Facilities of ATCO Electric's Distribution System that

deliver Electricity to a Site.

"Site" means the point where a Customer receives Electricity by means of a Service

Connection.

"Terms and Conditions" means these Terms and Conditions of Regulated Rate

Service, as amended from time to time.

"UCA" means the Utilities Consumer Advocate.

2.2 Conflicts

If there is any conflict between these Terms and Conditions and a provision expressly

set out in an order of the Commission, the provision of the Commission's order shall

govern.

If there is any conflict between these Terms and Conditions and a provision of the EUA

or related Regulations, the provision of the EUA shall govern.



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If there is any conflict between these Terms and Conditions and the corresponding Rate

Schedules, the Rate Schedules shall govern.

2.3 Headings

The division of these Terms and Conditions into sections, subsections and other

subdivisions and the insertion of headings are for convenience of reference only and

shall not affect the construction or interpretation of these Terms and Conditions.

2.4 Extended Meanings

In these Terms and Conditions, words importing the singular number shall include the

plural and vice versa, words importing the masculine gender shall include the feminine

and neuter gender and vice versa and words importing persons shall include

individuals, partnerships, associations, trusts, unincorporated organizations and

corporations.

2.5 Charges and Fees

All rates, charges and fees referred to in these Terms and Conditions are as set out in

the Rate Schedules and/or the Fee Schedule for DERS.

ARTICLE 3

GENERAL PROVISIONS

3.1 Effective Date

These Terms and Conditions have been approved by the Commission in

Decision 2957-D01-2015, and are effective as of August 1, 2015.



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3.2 Customers Bound by Terms and Conditions

The Regulated Rate Tariff and the Rate Schedules approved by the Commission apply

to each Customer. As a condition of receiving Regulated Rate Service, the Customer

agrees to be bound by these Term and Conditions and agrees to pay the rates and fees

applicable for such service, as prescribed in the Rate Schedules whether the Customer

signs a service agreement or not.

3.3 Modification of Regulated Rate Tariff

No agent, employee or other representative of DERS is authorized to modify any

provision or rate contained in the Regulated Rate Tariff or to bind DERS to perform in

any manner inconsistent with the Regulated Rate Tariff. Any request for the waiver or

alteration of any part of the Regulated Rate Tariff must be filed with and approved by

the Commission. DERS may make Minor Routine changes by filing updated Terms and

Conditions with the Commission.

3.4 Regulatory Approval and Amendment

Other than Minor Routine changes as per Section 3.3, DERS may only amend these

Terms and Conditions with approval of the Commission. Whenever the Commission

approves an amendment to these Terms and Conditions or an amendment otherwise

takes effect, these Terms and Conditions will be revised to incorporate such

amendments. The Commission will acknowledge the notice of the amendment to the

Terms and Conditions within 60 days after such notice is filed or the Commission will

direct a further process to deal with the requested changes as the Commission deems

to be appropriate.



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3.5 Applicable Taxes

The Customer shall pay all taxes, fees or assessments that DERS is required to collect

from time to time as required pursuant to any statute, regulation, or other governmental

directive or order or decision of the Commission that applies to Regulated Rate Service.

3.6 Landlord Information

DERS may require the Customer to indicate if the Customer is the owner of the premise

or a tenant. Where the Customer is a tenant, DERS may request landlord information.

The landlord information will be retained by DERS to continue service after service to

the Customer is terminated and no new tenant has assumed service. DERS will verify

with the landlord the information provided and will notify the landlord when the service is

being transferred to the landlord, along with the reason for the transfer. The landlord

shall not be responsible for any arrears owed by the tenant unless the landlord

expressly indicates it is assuming such liability.

DERS will provide landlords with the opportunity to register all Sites that they own and

are responsible for in the case of a vacancy. This will not bind the landlord to be

responsible for past charges of a tenant unless specifically requested by the landlord.

3.7 Owner’s Liability for Payment

In circumstances where:

a) there is no Customer registered on the account records of DERS; and

b) there are no other occupants of the Site who continue to receive service

The Property Owner will be deemed to be the Customer of Record and will be liable for

payment for Services provided in accordance with the Regulated Rate Tariff until the

date a new Customer is determined by DERS.



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RENTAL PREMISES

As option for service to rental premises, an owner or operator who wishes DERS to

consider dealing directly with a tenant or tenants may enter into a premise vacancy

agreement with DERS which provides for responsibilities of the owner or operator in

relation to payment for service used in the premises. Notwithstanding any premise

vacancy agreement DERS may, at its sole option at any time and from time to time,

either:

(i) deal directly with the owner or operator of the premises as a

customer of record in respect to any and/or all services to the

premises, or

(ii) subject always to the provisions of any premise vacancy

agreement, deal directly with each tenant as a customer of record.

Nothing in these Terms and Conditions require a landlord to enter into such an

agreement. Should the landlord elect not to enter into a premise vacancy agreement,

DERS will deal directly with the tenant.

ARTICLE 4

REGULATED RATE SERVICE

4.1 Requirements for Obtaining Regulated Rate Service

Eligibility for a prospective Customer to obtain Regulated Rate Service shall be

determined in accordance with the EUA and Regulations. DERS may require any

potential residential Customer to provide such proof of identification as DERS considers

appropriate in the circumstances.



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A potential Customer, other than a residential Customer, who is not receiving Regulated

Rate Service from DERS, may be required to complete an application in writing, or via

telephone, to obtain Regulated Rate Service at a Site.

A residential customer may request service via telephone or other means defined by

DERS.

When an application is required, DERS will provide an application form outlining the

required information to be provided. For an existing premise or property, DERS will

open an account and commence Regulated Rate Service within 7 days of receiving a

completed application from a Customer. Where circumstances beyond the control of

DERS prevent DERS from opening an account and commencing Regulated Rate

Service within 7 days, DERS will notify the customer and will provide the customer with

an estimate of when the account will be opened.

Expedited connection of Regulated Rate Service may be available at an additional

charge in accordance with the Rate Schedules.

If DERS approves a Customer's application for Regulated Rate Service, DERS will open

an account for the Customer for Regulated Rate Service at the applied for Site and the

Customer shall be the "Customer of Record" for such Site.

Subject to Section 8.2, the Customer will be responsible to pay to DERS all amounts

charged in accordance with these Terms and Conditions and applicable Rate

Schedules to the account for service provided from the time the account is opened, or

the customer becomes responsible for charges, until the account is closed as provided

in Section 6.1, or if Regulated Rate Service is discontinued or disconnected as provided

in Sections 4.4 and 8.7.



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4.2 Refusal of Regulated Rate Service

DERS reserves the right to refuse to provide Regulated Rate Service to a prospective

Customer when:

(a) the prospective Customer cannot demonstrate a satisfactory credit

rating or credit history as outlined in Section 4.3 below and the

prospective Customer has not provided the deposit required by

DERS pursuant to Section 5.1;

(b) the prospective Customer has an outstanding balance with DERS

or a regulated affiliate; or

(c) the prospective Customer has not complied with the applicable

provisions of these Terms and Conditions.

DERS reserves the right to refuse to provide Regulated Rate Service to a prospective

Customer at a Site when a previous Customer at the Site had a history of non-payment

and DERS has reasonable grounds to believe that the defaulting Customer would

continue to occupy the premises located at the Site.

Subject to limitations outlined in applicable regulations, and on 48 hours oral or written

notice to a Customer and without further notice, DERS may disconnect service if DERS

has not been provided with sufficient information to bill the customer or the premises or

property reasonably appears to be vacant or not occupied by the known Customer.

4.3 Credit Information

DERS may, at any time, request from a Customer such information as DERS considers

reasonably necessary to determine the Customer's credit history and credit risk. Such




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(a) the Customer’s full name, address, telephone numbers (home,

work, and cellular), and birthdate to allow DERS to determine a

Customer’s credit rating, and/or

(b) demonstration of the Customer’s credit history with another

regulated utility, and/or

(c) other personal information sufficient to identify the prospective

Customer and determine the Customer’s credit history and credit

risk.


Canadian Credit Bureaus with respect to customer payments and/or non-payments.

4.4 Failure to Provide Information

If, after notice of a deficiency, and reasonable opportunity to remedy any deficiencies, a

prospective Customer or existing Customer fails to provide information requested in

accordance with Section 4.3 and does not provide a security deposit in accordance with

Article 5, then DERS may either:

(a) refuse to provide Regulated Rate Service to the prospective

Customer, or

(b) discontinue or request a disconnection of Regulated Rate Service

to the existing Customer.



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ARTICLE 5

FINANCIAL SECURITY REQUIREMENTS

5.1 Requirement for Deposit

DERS may require a deposit or an increase in an existing deposit by a Customer in

circumstances it considers appropriate, including in the following circumstances:

(a) if the prospective Customer making the application for service

cannot demonstrate a satisfactory credit rating to DERS as outlined

in Section 4.3;

(b) the existing Customer has paid two consecutive bills late in any

twelve month period or three non-consecutive bills late in any

twelve month period;

(c) the Customer has issued more than one payment that has been

returned for non-sufficient funds in any six month period;

(d) there has been more than a 50% increase in the Customer's

average monthly consumption of Electricity over the prior six month

period; or

(e) the Customer makes a request for reconnection of service after

having been disconnected for non-payment.

5.2 Waiver of Deposit Requirement

DERS may waive the requirement for a deposit by Customer.



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(a) where the Customer has a previous good payment history with

DERS;

(b) where a result satisfactory to DERS is obtained from an external

credit check;

(c) where the Customer can demonstrate that it has a previous good

payment history with another regulated utility;

(d) where the Customer provides to DERS an indemnity bond or

irrevocable letter of credit from a financial institution satisfactory to

DERS.

5.3 Fees for credit check

DERS may charge the cost of performing an external credit check to the customer.

5.4 Maximum Deposit

The maximum deposit DERS will require from a Customer under its Regulated Rate

Tariff is equal to 30% of the annual total charge payable by the Customer, as

reasonably estimated by DERS.

If the required deposit is large, at the discretion of DERS, DERS may grant a Customer

request that the Company allow an initial payment for a portion of the deposit and

payment of the remainder of the deposit over a reasonable time period.

5.5 Use of Deposit for Non-Payment

A deposit provided by a Customer may be applied against any amounts owing for

unpaid bills for Regulated Rate Service. A new security deposit will be assessed on

the account in this case.



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5.6 Return of Deposit

A deposit made by a Customer must be returned to the Customer after a satisfactory

payment history after a period of 12 consecutive months or when the Customer’s

Regulated Rate Service is terminated and the Customer’s account is closed.

Where a Customer’s Regulated Rate Service is terminated and the Customer’s account

is closed for non-payment, prior to any refund, the deposit will be applied to the balance

owing by the Customer to DERS.

5.7 Interest Payable on Deposits

Deposits, unless otherwise applied, will be refunded with interest at a rate equivalent to

the one-year non-redeemable Royal Bank GIC rate for investments of $500 to

$99,999.99 to the Customer after the Customer establishes a satisfactory payment

record.

The interest rate applied to security deposits will be updated quarterly and will be the

one-year non-redeemable Royal Bank GIC rate for investments of $500 to $99,999.99

in effect five business days prior to the start of the quarter.

Interest shall accrue monthly beginning with the initial date of deposit. Interest will only

be payable to customers after twelve months of satisfactory payment history.

ARTICLE 6

CLOSING AN ACCOUNT

6.1 Notice to Close an Account

A Customer may close an account for Regulated Rate Service at a Site by giving DERS

at least three full Business Days notice to close the account. DERS may request



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reasonable proof that the Customer will no longer be responsible for the Site after that

date.

6.2 Notice to Transfer to an Unregulated Retailer

A customer transferring to an unregulated retailer must provide DERS with 30 days

notice prior to the intended transfer date.

6.3 Relocation of Customer

If the Customer wishes to relocate from the Site, the customer must notify DERS at

least three full business days prior to relocation of the address of its new location.

6.4 Customer Change of Name or Information

The Customer must notify DERS as soon as reasonably possible of a change of name,

mailing address or telephone number. Such notification shall be provided in writing if

requested by DERS.

ARTICLE 7

MEASUREMENT OF ENERGY CONSUMPTION

7.1 Billing Standards

DERS shall comply with any billing standards code as published by the Commission.

7.2 Meter Testing

If a Customer believes his or her meter to be in error, the customer will arrange to have

the meter tested by ATCO Electric. The Customer will pay DERS all charges for meter

testing incurred by DERS in accordance with the ATCO Terms and Conditions.



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There shall be no cost to the Customer if the meter is found to be in error.

ARTICLE 8

BILLINGS AND PAYMENT

8.1 Billing Practices

DERS provides Regulated Rate Services to Customers and does not require payment

in advance, except where a deposit is required in accordance with these Terms and

Conditions. DERS will bill in accordance with related regulations or Commission

directives on billing processes and quality.

8.2 Responsibility for Payment

The Customer is responsible for payment for all Regulated Rate Service provided to the

Customer up to the time DERS has closed the account and, until payment for final

charges for consumption has been made.

If a Customer's Regulated Rate Service is discontinued by DERS or disconnected under

the ATCO Terms and Conditions, the Customer is responsible for payment for all

Regulated Rate Service provided to the Customer up to the time of such discontinuation

or disconnection, and until payment for final charges for consumption has been made.

8.3 Responsibility to Pay

A bill issued to the Customer by DERS shall be paid in full by the due date specified on

the bill, such due date not to be less than 13 business days following the issuance of

the bill. If a Customer loses their bill, they shall not be relieved of the obligation to pay

the bill in full by the due date. Payments shall be without prejudice to the Customer’s

right to contest any rate or fee charged.



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8.4 Adjustments to Bills

Bills rendered by DERS shall contain the information prescribed in applicable

legislation. Bills rendered by DERS may be adjusted from time to time to, among other

things, reflect adjustments by ATCO Electric under its Distribution Tariff and DERS will

issue refunds or charges as appropriate to the affected customers.

8.5 Late Payment Charge

The amount due shown on a bill is owing to DERS on the statement date. If a

Customer does not pay a bill in full within seventeen (17) calendar days after the

statement date specified on the bill, subject to disputed charges as outlined in Section

10, a late payment charge may be applied. The outstanding unpaid amount, including

the late payment charge, shall be applied to the charges that become due and payable

in the next bill. DERS will disclose the late payment fee in its Fee Schedule.

8.6 Remedies for Non-Payment

If a bill remains unpaid after the due date or grace period, DERS may require a deposit

or an increase in the amount of an existing deposit.

Subject to any restrictions under the EUA and Regulations or Section 10 of these Terms

and Conditions, failure to pay a bill may result in DERS either discontinuing the

Customer's Regulated Rate Service or requesting a disconnection of such service.

In addition, DERS may commence collection action. Prudent and reasonable collection

costs incurred by DERS may be added to the Customer's bill.

If a Customer's Regulated Rate Service is discontinued by DERS or disconnected under

the ATCO Terms and Conditions, any unpaid charges in the account may be transferred



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to any other Regulated Rate Service account held by the same Person and any deposit

held in respect of such account may be applied against the unpaid charges.

DERS will notify the Customer when an account is in arrears and will provide an

opportunity to resolve any arrears prior to taking action. Normal credit actions may

include, but is not limited to the following:

(a) written notice and/or telephone call and/or door to door notice to the

customer indicating payment has not been received and timing for

future action if payment or other arrangements have not been

made.

(b) written notice and/or telephone call indicating pending notice of

disconnection and timing of disconnection action.

(c) subject to limitations on disconnection outlined in legislation and

regulations, initiate disconnection.

(d) the use of collection agencies.

(e) legal action.

8.7 Restoration of Regulated Rate Service

In order for Regulated Rate Service to be restored after it has been discontinued or

disconnected for non-payment, the Customer must pay all outstanding bills in full,

provide a deposit to DERS and pay the reconnection fee prescribed in the Rate

Schedules. At DERS’ discretion, DERS may allow the Customer to make payment

arrangements to settle arrear amounts over a reasonable amount of time.



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8.8 Partial Payments

Partial payments on an account will be applied to the unpaid amounts outstanding on

the longest outstanding bills.

8.9 Over Payments

If the Customer pays DERS an amount in excess of what is owed to DERS, the excess

amount will be carried as a credit balance on the Customer’s account and applied to

bills for future Regulated Rate Services unless the Customer requests a refund.

Interest will not be paid on credit balances.

8.10 Dishonored Payments

In addition to any late payment charge under Section 8.2 of these Terms and

Conditions, a Customer whose payment is dishonored shall pay the charge as specified

in the Rate Schedules.

8.11 Novelty Payments

DERS may refuse to accept payment when the Customer attempts to make payment by

a cheque drawn on a form other than a bank cheque. DERS follows the coin

acceptance limitations specified in the Currency Act, S.C. 1985, c. C-52 as follows:

Payment in coin may be made to the maximum amount of:

Forty dollars if the denomination is two dollars or greater but does not exceed ten

dollars,

Twenty-five dollars if the denomination is one dollar,

Ten dollars if the denomination is ten cents or greater but less than one dollar,

Five dollars if the denomination is five cents, and

Twenty-five cents if the denomination is one cent.



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8.12 Other Occupants’ Liability for Payment

Where a Customer of Record for a Site has defaulted on payment of a bill for Regulated

Rate Service and DERS reasonably believes that the occupant receiving service at the

site is related to or associated with the previous Customer of Record, the other

occupants will be deemed the current Customer of Record.

8.13 Disconnection for Insufficient Information

If DERS has not been provided with sufficient information to bill a Customer, or the

premises or property served by a Site reasonably appears to be vacant or not occupied

by the Customer of Record, DERS may provide written notice of the deficiency to the

customer or owner or to the site location. Following a reasonable opportunity to provide

the requested information, if the Customer has not provided such information and

subject to limitations on disconnections outlined in legislation and regulations, DERS

may request ATCO Electric to disconnect service.

ARTICLE 9

RESPONSIBILITY AND LIABILITY

9.1 Requirements in the Electric Utilities Act and Regulations

In addition to any rights and obligations contained in these Terms and Conditions,

DERS is governed and bound by the EUA and Regulations.

DERS shall maintain security standards, including control of access to data and other

information, consistent with the highest standards of business practice in the industry.



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9.2 Interruption of Regulated Rate Service

DERS does not own or operate the Distribution System or any other part of the

Interconnected Electric System and does not guarantee continuous Regulated Rate

Service.

DERS will endeavor at all times to provide regular and uninterrupted Regulated Rate

Service to Customers.

9.3 Force Majeure

DERS, is relieved of its obligations under the Regulated Rate Tariff including these

Terms and Conditions, and shall not be liable for any failure to perform any service

under the Regulated Rate Tariff or any term of these Terms and Conditions to the

extent that and when such failure is due to, or is a consequence of, any event of Force

Majeure.

Should a residence or business being served be suspended or discontinued, due to fire

or any other causes beyond the control of the Customer, any services, and related fees

and charges except pass through charges from ATCO Electric, upon request by the

Customer, shall become inoperative until business is resumed, except for unbilled

amounts due to DERS for service theretofore rendered by it, at which time any service

and related fees shall again become operative. Upon resumption of service, the

Customer’s credit standing with DERS will be no worse than it was prior to the

suspension of service.

9.4 Limitation of DERS' Liability to Customer

Except for direct physical damage, loss or injury to a Customer or a Customer's property

resulting from the negligence, willful misconduct of, or breach of these Terms and

Conditions by DERS or its employees, agents or contractors acting within the scope of



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their employment, DERS shall not be liable to a Customer, whether in tort, contract,

strict liability or otherwise, for any loss, damage, expense, charge, cost or other liability

of any kind suffered or incurred by the Customer arising out of or in any way connected

with any interruption, defect, irregularity, failure, curtailment or reduction in Regulated

Rate Service. Under no circumstances or for any reason shall DERS be liable to a

customer for any loss, injury or damage of an indirect, special, exemplary, punitive or

consequential nature including, without limitation, loss of revenues, loss of profits, loss

of earnings, loss of contract, loss of opportunity, cost of capital, business interruption,

claims of a Customer's customers, contractors or other third parties or any other similar

loss, damage, expense, cost or liability whatsoever, whether or not any such loss,

damage, expense, cost or liability was foreseeable.

Any claim by a Customer for loss, injury or damage, must be filed with DERS within two

years from the date of occurrence of the incident that is the subject of the claim, failing

which DERS shall have no liability to the Customer for any such loss, injury or damage.

9.5 Distribution Tariff

Each Customer shall be responsible for the Service Connection to a Site to permit the

Customer to receive Regulated Rate Service. As a condition of receiving Regulated

Rate Service, each Customer agrees to be bound by, and shall comply with, all

provisions of the Distribution Tariff applicable to the Customer.

9.6 Indemnification by Customer

Each Customer shall indemnify and hold DERS and its employees, agents and

contractors harmless from and against any claim for any loss, damage, expense,

charge, cost, penalty or other liability of any kind suffered or incurred by DERS

(including charges or liability arising under ATCO Electric's Distribution Tariff) arising out

of or in any way connected with any failure by the Customer or its Facilities to comply



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with any of the provisions of ATCO Electric's Distribution Tariff applicable to the

Customer or its Facilities or any legal or regulatory requirement related to Distribution

Access Service required to be complied with by the Customer.

Without limiting the generality of the foregoing, Customer shall be liable to compensate

DERS for any costs, expenses or liabilities that it incurs under the provisions of the

ATCO Terms and Conditions arising out of or connected with any action or inaction of

the Customer related to Regulated Rate Service.

9.7 Indemnification by DERS

DERS shall indemnify and hold a Customer harmless from and against direct physical

loss, injury or damage to the Customer or the Customer's property resulting from the

negligence or willful misconduct of DERS or its employees, agents or contractors acting

within the scope of their employment or breach of these Terms and Conditions. Under

no circumstances or for any reason shall DERS be liable to a Customer for any loss,

injury or damage of an indirect, special, exemplary, punitive or consequential nature

including, without limitation, loss of revenues, loss of profits, loss of earnings, loss of

contract, loss of opportunity, cost of capital, business interruption, claims of a

Customer's customers, contractors or other third parties or any other similar loss,

damage, expense, cost or liability whatsoever, whether or not any such loss, damage,

expense, cost or liability was foreseeable.

Any claim by a Customer for indemnity for loss, injury or damage, must be filed with

DERS within two years from the date of occurrence of the incident that is the subject of

the claim, failing which DERS shall have no obligation to indemnify the Customer for

any such loss, injury or damage.



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ARTICLE 10

DISPUTE RESOLUTION

Without limiting any party’s right under the EUA or Regulations to make complaints to

the Commission, both parties, acting in good faith shall endeavor to resolve differences

prior to taking any action to the Commission. Customers are encouraged to contact

DERS first with any issues prior to escalating the issue to the UCA or the AUC.

10.1 Disputed Charges

The Customer has a right to dispute any charge shown on the Customer’s bill by

contacting DERS either in writing or by telephone. DERS will investigate all disputes

and make any adjustments DERS determines appropriate. If the dispute is within

DERS’ control and is not resolved within 30 days from the notice, the Customer can

escalate the dispute as provided in Section 10.2 and 10.3 and the Customer will not be

required to pay any charges for the disputed period that are in excess of the average

monthly bill of the Customer as reasonably determined by DERS. The Customer will be

responsible to pay all past and future charges while the specific charge in dispute is

being resolved. Any outstanding disputed amount shall be due and payable within 10

business days of resolution. No additional charges will be applied to disputed amounts.

10.2 Resolution by DERS and Customers

If any dispute between DERS and a Customer arises at any time in connection with

these Terms and Conditions, DERS and the Customer, acting reasonably and in good

faith, shall use their reasonable efforts to resolve the dispute as soon as possible in an

amicable manner. If the dispute cannot be otherwise resolved pursuant to this Section

10.2, a senior representative of DERS and the Customer shall meet to attempt to

resolve the dispute.



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During the course of a dispute that has been escalated to the AUC in accordance with

Section 10.1 of these Terms and Conditions DERS shall not terminate or suspend

service for reasons of the escalated dispute, but may terminate or suspend service if a

Customer is in contravention of other aspects of these Terms and Conditions or in

violation of the ATCO Terms and Conditions.

10.3 Resolution by a Third Party

If any dispute has not been resolved pursuant to Section 10.2 within a reasonable time,

DERS and the Customer may pursue the matter with the AUC if the matter is within the

AUC's jurisdiction, or pursue in Alberta any remedies available to them under applicable

laws, including arbitration pursuant to the Arbitration Act (Alberta).

ARTICLE 11

MISCELLANEOUS

11.1 Compliance with Applicable Legal Authorities

DERS and the Customer are subject to, and shall comply with, all existing or future

applicable federal, provincial and local laws, all existing or future orders or other actions

of the AUC, Independent System Operator or governmental authorities having

applicable jurisdiction. DERS or the Customer will not be required to violate, directly or

indirectly, or become a party to a violation of any requirement of the Independent

System Operator or any applicable federal, provincial or local statute, regulation, bylaw,

rule or order in order to provide or receive Regulated Rate Service. DERS' obligation to

provide any Regulated Rate Service is subject to the condition that all requisite

governmental and regulatory approvals for the provision of the Regulated Rate Service

will have been obtained and will be in force during the period of Regulated Rate

Service.



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11.2 Service Guarantee Credit

(1) In accordance with AUC Rule 003, DERS must provide a credit of $75 to any

customer who is subject to one of the following errors made by DERS:

a) Customer was provided written notice of pending disconnection of service in

error;

b) Customer was provided written notice of pending referral to a credit agency in

error;

c) Customer was referred to a credit agency in error; or

d) Customer experienced disconnection of service in error.

(2) Payment of the $75 credit is not required where no error has been made by DERS,

and in particular is not required in the following circumstances:

a) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice and the customer’s payment

crossed in the mail;

b) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice was in mail transit at the

time the customer made or attempted to make payment by visiting the

premises of an authorized payment acceptance establishment, such as

bank, trust company or credit union;

c) The electric or gas distributor disconnected a customer in error, rather than

as instructed by DERS;

d) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] as no issued in error, and such notice was properly mailed but the



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customer did not pick up the mail from locations such as a post office, super

mail box or home mail box;

e) DERS’ written notice of pending disconnection [or pending referral to a credit

agency] was not issued in error, and such notice was undelivered by the mail

delivery service.

f) The customer attempted to make payment to the person dispatched by the

electric or gas distributor to disconnect the service, where such disconnection

was not made in error, but the person was not authorized to accept payment.

11.3 No Assignment

Service under the Regulated Rate Tariff is not assignable.

The benefits and obligations of any service contract shall begin when DERS

commences to supply Regulated Rate Service, and shall inure to the benefit of and be

binding upon the respective heirs, personal representatives, and successors.

This limit on assignment is not intended to infringe on or limit the right of customer to

sell, remove or otherwise lawfully dispose of customer’s property, subject to the

termination clauses of these Terms and Conditions. Upon termination, any outstanding

balances will remain the obligation of the customer.

11.4 No Waiver

The failure of either party to insist in any one or more instances upon strict performance

of any provisions of these Terms and Conditions or to take advantage of any of its rights

hereunder, shall not be construed as a waiver of any such provisions or the

relinquishment of any such right or any other right hereunder, which shall remain in full



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force and effect. No provision of these Terms and Conditions shall be deemed to have

been waived and no breach excused unless such waiver or consent to excuse is in

writing and signed by the party claimed to have waived or consented to excuse.



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