Decision 2014-373 AltaGas Utilities Inc. - AUC · 2018. 2. 23. · AUC Decision 2014-373 (December...

Decision 2014-373

AltaGas Utilities Inc. 2014-2015 Capital Tracker Application and 2013 Capital Tracker True-up Application December 24, 2014

The Alberta Utilities Commission

Decision 2014-373: AltaGas Utilities Inc.

2014-2015 Capital Tracker Application and 2013 Capital Tracker True-up Application

Application nos.1610446 and 1610600

Proceeding nos. 3152 and 3244

December 24, 2014

Published by


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

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Website: www.auc.ab.ca

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

AUC Decision 2014-373 (December 24, 2014) • i

Contents

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

2 Background ........................................................................................................................... 5

3 Commission process for reviewing 2013 true-up and 2014-2015 capital tracker applications ............................................................................................................................ 9

4 Summary of projects included in the 2013 capital tracker true-up application and the 2014-2015 capital tracker application ............................................................................... 10 4.1 Pipeline replacement program...................................................................................... 10 4.2 Station refurbishment program .................................................................................... 13

4.3 Gas supply program ..................................................................................................... 14

5 Grouping of projects for capital tracker purposes .......................................................... 14

6 Project assessment under Criterion 1 ............................................................................... 16 6.1 Deferred projects .......................................................................................................... 17

6.2 Project substitution ....................................................................................................... 20 6.3 Trailing costs ................................................................................................................ 22

7 Assessment of proposed programs under Criterion 1 ..................................................... 24

8 Assessment of individual projects under Criterion 1 ...................................................... 27 8.1 Projects in the pipe replacement program .................................................................... 27

8.1.1 2013 projects previously approved for capital tracker treatment in Decision

2013-435 ......................................................................................................... 28

8.1.1.1 PVC pipe ............................................................................................ 28 8.1.1.2 Non-certified PE pipe ........................................................................ 31

8.1.1.3 Pre-1957 steel pipe ............................................................................ 33 8.1.2 2013 projects not approved for capital tracker treatment in Decision 2013-435

......................................................................................................................... 36

8.1.2.1 Non-certified PE pipe ........................................................................ 37 8.1.2.2 Pre-1957 steel pipe ............................................................................ 38

8.1.3 2014-2015 forecast capital tracker projects .................................................... 39

8.1.3.1 PVC pipe ............................................................................................ 42 8.1.3.2 Non-certified PE pipe ........................................................................ 45 8.1.3.3 Pre-1957 steel pipe ............................................................................ 49

8.2 Projects in the station refurbishment program ............................................................. 54 8.2.1 2013 projects previously approved for capital tracker treatment in Decision

2013-435 ......................................................................................................... 55 8.2.2 2013 projects not approved for capital tracker treatment in Decision 2013-435

......................................................................................................................... 57 8.2.3 2014-2015 forecast capital tracker projects .................................................... 59

8.3 Projects in the gas supply program .............................................................................. 68 8.3.1 2013 projects previously approved for capital tracker treatment in Decision

2013-435 ......................................................................................................... 68 8.3.2 2014-2015 forecast capital tracker projects .................................................... 69

8.3.2.1 2014 forecast capital tracker projects ................................................ 69 8.3.2.2 2015 forecast capital tracker projects ................................................ 69

ii • AUC Decision 2014-373 (December 24, 2014)

9 Accounting test under Criterion 1 ..................................................................................... 71 9.1 General set-up of AltaGas’ accounting test model ...................................................... 71

9.2 I-X index and Q factor used in the accounting test ...................................................... 73 9.3 WACC rate ................................................................................................................... 75 9.4 Grouping of retired assets in the accounting test ......................................................... 75 9.5 Commission’s conclusions on accounting test requirements of Criterion 1 ................ 77

10 Criterion 2 – Ordinarily the project must be for replacement of existing capital assets or undertaking the project must be required by an external party ............................... 77

11 Criterion 3 – The project must have a material effect on the company’s finances....... 79

12 K factor calculation methodology and the resulting 2014 K factor and 2015 K factor 80 12.1 2013 true-up ................................................................................................................. 80

12.2 2014-2015 forecast ....................................................................................................... 81

13 Other matters ...................................................................................................................... 82 13.1 Pipeline leaks and risk assessment ............................................................................... 82 13.2 Overhead allocations .................................................................................................... 85 13.3 Reporting of capital tracker and non-capital tracker capital costs separately .............. 88

13.4 Considerations for streamlining AltaGas’ capital tracker forecasting and application review process ............................................................................................................. 88

13.5 Controls and accountability ......................................................................................... 91

14 Order .................................................................................................................................... 92

Appendix 1 – Proceeding participants ...................................................................................... 93

Appendix 2 – Oral hearing – registered appearances ............................................................. 95

Appendix 3 – Summary of Commission directions .................................................................. 96

Appendix 4 – Detailed risk assessment model ........................................................................ 100

Appendix 5 – Risk rankings for 2014 and 2015 projects ....................................................... 102

Appendix 6 – Purchase meter station detailed cost estimate ................................................ 103

Appendix 7 – Town border station detailed cost estimate .................................................... 105

Appendix 8 – Post regulator station detailed cost estimate................................................... 106

List of tables

Table 1. AltaGas risk assessment matrix ............................................................................... 11

Table 2. Deferred projects ...................................................................................................... 18

Table 3. 2013 trailing costs ...................................................................................................... 22

Table 4. 2013 PVC pipe actual vs. approved forecast .......................................................... 27

AUC Decision 2014-373 (December 24, 2014) • iii

Table 5. 2013 non certified PE pipe actual vs. approved forecast ....................................... 28

Table 6. 2013 pre-1957 steel pipe actual vs. approved forecast ........................................... 28

Table 7. Risk score for Morinville and Pincher Creek “Mole Line” – non-certified PE pipe ............................................................................................................................. 37

Table 8. Risk score for Drumheller – pre-1957 steel pipe .................................................... 38

Table 9. 2014-2017 pipe replacement program forecast ...................................................... 40

Table 10. PVC pipe replacement – 2014 forecast ................................................................... 42

Table 11. PVC pipe replacement – 2015 forecast ................................................................... 42

Table 12. 2010-2013 PVC pipe projects by area ..................................................................... 44

Table 13. Non-certified PE pipe replacement – 2014 forecast ............................................... 45

Table 14. Non-certified PE pipe replacement – 2015 forecast ............................................... 46

Table 15. 2010-2013 non-certified PE pipe projects by area ................................................. 48

Table 16. Pre-1957 steel pipe replacement – 2014 forecast .................................................... 49

Table 17. Pre-1957 steel pipe replacement – 2015 forecast .................................................... 49

Table 18. 2010-2013 pre-1957 steel pipe projects by area ...................................................... 51

Table 19. 2013 station refurbishment projects – actual vs. approved forecast .................... 54

Table 20. Forecast station refurbishments/replacements from 2014 to 2018....................... 59

Table 21. Purchase meter stations 2013 and 2014 costs by category .................................... 60

Table 22. Town border stations 2013 and 2014 costs by category ........................................ 61

Table 23. Post regulator stations 2013 and 2014 costs by category....................................... 61

Table 24. 2014 forecast - station refurbishment program ..................................................... 62

Table 25. 2015 forecast - station refurbishment program ..................................................... 63

Table 26. Cost drivers and resulting impacts – CCA example .............................................. 65

Table 27. 2013 gas supply program – actual vs. approved forecast ...................................... 68

Table 28. Gas supply program – 2015 forecast ....................................................................... 69

Table 29. Applied-for 2013-2015 capital tracker projects and Criterion 2 requirements .. 78

Table 30. 2013 K factor forecast vs. actuals ............................................................................ 81

iv • AUC Decision 2014-373 (December 24, 2014)

Table 31. AltaGas overhead rate calculations ......................................................................... 86

AUC Decision 2014-373 (December 24, 2014) • 1


Calgary, Alberta

AltaGas Utilities Inc. Decision 2014-373

2014-2015 Capital Tracker Application and Application nos. 1610446 and 1610600

2013 Capital Tracker True-up Application Proceeding nos. 3152 and 3244

1 Introduction

1. On December 6, 2013, the Alberta Utilities Commission (AUC or Commission) issued Decision 2013-4351 which dealt with the 2013 capital tracker applications for five Alberta

distribution utilities’ (collectively the Utilities) and set out the basis and requirements for future

capital tracker applications. Decision 2013-435, at paragraph 1073(a), directed each of the

distribution companies, including AltaGas Utilities Inc. (AltaGas or AUI), to file a single

application for its proposed 2014 and 2015 capital tracker project or programs on or before

March 1, 2014. Also in Decision 2013-435, at paragraph 1073(c), AltaGas was directed to file an

application by May 15, 2014 to true-up the costs of 2013 capital tracker projects or programs.

2. By letter dated February 14, 2014, AltaGas requested an extension from March 1, 2014 to March 17, 2014 in order to file its 2014-2015 capital tracker application.2 AltaGas subsequently

requested a further extension to March 31, 2014.3

3. By letters dated February 18, 20144 and March 13, 2014,5 the Commission granted the requested extensions.

4. On March 31, 2014, AltaGas filed with the Commission its 2014-2015 capital tracker application.6

5. The Commission issued a notice of the 2014-2015 capital tracker application on April 2, 2014 with statements of intent to participate (SIPS) due April 11, 2014.7

6. The Commission received SIPs by the specified deadline date from the following parties:

AltaLink Management Ltd.

ATCO Electric Ltd.

ATCO Gas, a division of ATCO Gas and Pipelines Ltd.

EPCOR Distribution & Transmission Inc.

FortisAlberta Inc.

the Consumers’ Coalition of Alberta (CCA)

1 Decision 2013-435: Distribution Performance-Based Regulation, 2013 Capital Tracker Applications,

Application No. 1608827, Proceeding ID No. 2131, December 6, 2013. 2 Proceeding No. 2131, Exhibit No. 287.01.

3 Proceeding No. 2131, Exhibit No. 289.01.



6 Proceeding No. 3152, Exhibit No. 1 (application), Exhibit No. 2 (2014-2015 capital tracker schedules) and

Exhibit No. 3 (2010 to 2013 detailed schedules). 7 Proceeding No. 3152, Exhibit No. 7.01.

http://www.auc.ab.ca/applications/decisions/Decisions/2013/2013-435.pdf

2014-2015 Capital Tracker Application and 2013 Capital Tracker True-up Application AltaGas Utilities Inc.

2 • AUC Decision 2014-373 (December 24, 2014)

7. On April 15, 2014, the Office of the Utilities Consumer Advocate (UCA) submitted a SIP.

8. On April 11, 2014, the Commission issued a process letter and determined that the 2014-2015 capital tracker application would be conducted by way of a full written process proceeding,

as outlined in Commission Bulletin 2010-16,8 with a possible oral hearing, pending submissions

from parties. The process letter included a schedule and the following statement:

8.Specifically, with respect to AUI, in accordance with the Commission’s directions at

paragraph 1073(c) of Decision 2013-435, AUI is expected to file its 2013 capital tracker

true-up application on or before May 15, 2014. The Commission anticipates that the

issues in the 2014-2015 capital tracker application and in the 2013 capital tracker true-up

proceeding will be similar in nature, given that AUI’s approved 2013 capital tracker

projects have also been proposed for 2014 and 2015. This commonality of issues

provides an opportunity to achieve efficiencies in processing the applications. The

Commission therefore considers that, to the extent possible given the different filing

dates of the two applications, concurrent written evidentiary portions of the proceedings,

combined proceeding records and a joint oral hearing (if a hearing for one or both

proceedings is necessary) will result in regulatory efficiencies with respect to time

commitment, effort and cost for all parties.9

9. By letter dated May 14, 2014, AltaGas requested an extension from May 15, 2014 to May 23, 2014 to file its 2013 capital tracker true-up application. In the letter, AltaGas also

requested an extension from May 23, 2014 to May 30, 2014 to file its 2014-2015 capital tracker

information request responses.10 By letter dated May 16, 2014, the Commission granted the

extension requests.11

10. On May 23, 2014, AltaGas filed its 2013 capital tracker true-up application.12

11. The Commission issued a notice of the 2013 capital tracker true-up application on May 26, 2014 with SIPS due May 30, 2014.13

12. The Commission received SIPs by the specified deadline date from the following parties:

ATCO Gas, a division of ATCO Gas and Pipelines Ltd.

FortisAlberta Inc.

the CCA

the UCA

13. By letter dated June 17, 2014, the CCA requested an extension from June 20, 2014 to June 30, 2014 to file intervener evidence on the 2014-2015 capital tracker application.14 By letter

dated June 20, 2014, the Commission granted the extension request.15

8 AUC Bulletin 2010-16, Performance Standards for Processing Rate-Related Applications, April 26, 2010.

9 Proceeding No. 3152, Exhibit No. 14.01, paragraph 8.



12 Proceeding No. 3244, Exhibit No. 1 (application), Exhibit No. 2 (2013 true-up schedules), Exhibit No. 3 (AUC

directive responses). 13

Proceeding No.3244, Exhibit No. 7.01.

http://www.auc.ab.ca/news-room/bulletins/Bulletins/2010/Bulletin%202010-16.pdf



14. On June 20, 2014, the UCA filed evidence on the 2014-2015 capital tracker application.16

15. By letter dated July 4, 2014, AltaGas requested an extension to July 11, 2014 to file submissions on the need for an oral hearing.17 By letter dated July 7, 2014, the Commission

granted the extension request.18 As a result of the Commission’s July 7, 2014 letter and earlier

correspondence, the following procedural schedule was established:

Process step for

2014-2015 capital

tracker application

Deadline

Process step for

2013 capital tracker

true-up application

Deadline

Application filed March 31, 2014 Application is filed May 23, 2014

SIPs due April 11, 2014 SIPs due May 30, 2014

IRs to AltaGas May 2, 2014 IRs to AltaGas June 13, 2014

AltaGas IR responses May 30, 2014 AltaGas IR responses June 27, 2014

Intervener evidence July 7, 2014 Intervener evidence July 9, 2014

Submissions from

parties on need for oral

hearing for 2013

capital tracker true-up

and/or 2014-2015

capital tracker

application

July 11, 2014

Submissions from

parties on need for

oral hearing for 2013

capital tracker true-up

and/or 2014-2015

capital tracker

application

July 11, 2014

IRs to interveners July 21, 2014 IRs to interveners July 21, 2014

Intervener IR

responses August 1, 2014

Intervener IR

responses August 1, 2014

Rebuttal evidence August 13, 2014 Rebuttal evidence August 13, 2014

Combined oral hearing

(if necessary)

August 19, 2014 to

August 22, 2014

Combined oral

hearing (if necessary)

August 19, 2014 to

August 22, 2014

Argument September 5, 2014 Argument September 5, 2014

Reply argument September 12, 2014 Reply argument September 12, 2014

16. On July 7, 2014, the CCA filed evidence on the 2014-2015 capital tracker application.19

17. On July 11, 2014, AltaGas, the UCA and the CCA filed submissions on the need for an oral hearing. AltaGas’ position was that no oral hearing was required. The UCA requested a

14

Proceeding No. 3152, Exhibit No. 28.01. 15

Proceeding No. 3152, Exhibit No. 29.01; Proceeding No. 3244, Exhibit No.17.01. 16

Proceeding No. 3152, exhibit nos. 30.01 to 30.03. 17

Proceeding No. 3152, Exhibit No. 31.01; Proceeding No. 3244, Exhibit No. 22.01. 18


Proceeding No. 3152, Exhibit No. 33.01.



short, combined oral hearing for proceeding nos. 3152 and 3144. The CCA agreed with the

UCA’s position on the merit of an oral hearing.20

18. By letter dated July 22, 2014, the Commission advised parties that it would hold a short, combined, oral hearing to assist the Commission and parties to complete the evidentiary portion

of the record of both proceedings. In the letter, the Commission indicated that it would conduct a

roundtable hearing, with the goal of increased interaction amongst parties and streamlining the

oral hearing process. The Commission also attached to its July 22, 2014 letter a round of all-

party (AltaGas, the CCA and the UCA) information requests that focused on exploring other

possible methods of streamlining the forecasting and application review process for future

AltaGas capital tracker applications, given the on-going nature of AltaGas’ capital projects or

programs.21

19. The UCA and the CCA, by letters dated July 29, 2014 and July 31, 2014 respectively,22 expressed concerns with the Commission’s July 22, 2014 letter. The concerns were related to a

perceived broad scope of the Commission’s streamlining initiative and clarification was

requested.

20. By letter dated July 31, 2014, the Commission responded, explaining that the intent was to limit the initiative to AltaGas’ present capital tracker proceedings and that the Commission is

exploring similar opportunities for future proceedings.23

21. Responses from the UCA and the CCA to the Commission’s July 22, 2014 information requests were received by the due date of August 15, 2014. AltaGas’ responses were received on

August 16, 2014.24

22. On August 13, 2014, AltaGas filed rebuttal evidence on its 2014-2015 capital tracker application.25

23. The roundtable hearing was held from August 19 to August 20, 2014 in the Commission’s Edmonton offices. The division of the Commission presiding over these

proceedings was Mark Kolesar (Vice-Chair), Neil Jamieson and Henry van Egteren.

24. During the course of the hearing, several undertakings resulted from parties’ cross-examinations. At the end of the hearing, the parties consulted and the Commission accepted the

following proposed schedule for the remainder of the proceeding:

20

Proceeding No. 3152, exhibit nos. 34.01, 35.01 and 36.01; Proceeding No. 3244, exhibit nos. 25.01, 26.01 and

27.01. 21


Proceeding No. 3152, exhibit nos. 48.01 and 51.01; Proceeding No. 3244, exhibit nos. 29.01 and 31.01. 23


Proceeding No. 3152, exhibit nos. 62.01, 63.01 and 64.01. 25

Proceeding No. 3152, Exhibit No. 61.01.



Process step Deadline

Undertaking responses August 27, 2014

Questions from the counsel that requested the

undertakings on the undertaking responses September 2, 2014

Responses to the questions on the undertakings September 9, 2014

Combined Argument September 16, 2014

Combined Reply argument September 29, 2014

25. Combined argument and reply argument for both proceedings were received on September 16, 2014 and September 29, 2014, respectively.26 The Commission considers the

record for this proceeding to have closed on September 29, 2014.

26. In reaching the determinations set out within this decision, the Commission has considered all relevant materials comprising the records of the 2014-2015 capital tracker

application proceeding and the 2013 capital tracker true-up application proceeding, including the

evidence and argument provided by each party. Accordingly, references in this decision to

specific parts of the records are intended to assist the reader in understanding the Commission’s

reasoning relating to a particular matter and should not be taken as an indication that the

Commission did not consider all relevant portions of the records with respect to that matter.

2 Background

27. On September 12, 2012, the Commission issued Decision 2012-237,27 approving performance-based regulation (PBR) plans for the distribution utility services of certain Alberta

electric and gas companies, including AltaGas. The PBR plans were approved for a five-year

term commencing January 1, 2013. PBR replaces traditional cost-of-service regulation as the

annual rate-setting mechanism for distribution utility rates.

28. As set out in Decision 2012-237, the PBR framework provides a formula mechanism for the annual adjustment of rates. In general, AltaGas’ rates are adjusted annually by means of an

indexing mechanism that tracks the rate of inflation (I) relevant to the prices of inputs the

companies use less an offset (X) to reflect the productivity improvements the company can be

expected to achieve during the PBR plan period. As a result, with the exception of specified

adjustments, a utility’s revenues are no longer linked to its costs. Companies subject to a PBR

regime must manage their businesses and service obligations with the revenues derived under the

PBR indexing mechanism and adjustments provided for in the formula. The PBR framework is

intended to provide incentives for productivity increases and cost savings similar to those

operating in competitive markets.

29. In accordance with the provisions of the PBR plan approved for AltaGas in Decision 2012-237, the company’s distribution rates for each year, which are adjusted annually

according to the formula I-X, also may include an adjustment to fund necessary capital

expenditures (a K factor), an adjustment for certain flow-through costs that should be recovered

26

Proceeding nos. 3152 and 3244, exhibit nos. 73.01, 74.01, 75.01, 76.01, 77.01 and 78.01. 27

Decision 2012-237: Rate Regulation Initiative, Distribution Performance-Based Regulation, Application

No. 1606029, Proceeding ID No. 566, September 12, 2012.




from, or refunded to, customers directly (a Y factor), or an adjustment to account for the effect of

material, exogenous events for which the company has no other reasonable cost recovery or

refund mechanism within the PBR plan (a Z factor).

30. In Decision 2012-237, the Commission determined that a mechanism to fund certain capital-related costs may be required for some of the approved PBR plans.28 This supplemental

funding mechanism was referred to in Decision 2012-237 as a “capital tracker” with the revenue

requirement associated with approved amounts to be collected from ratepayers by way of a

“K factor” adjustment to the annual PBR rate setting formula.

31. At paragraph 592 of Decision 2012-237, the Commission set out three criteria that any capital project or program would have to satisfy in order to receive capital tracker treatment:

(1) The project must be outside of the normal course of the company’s on-going operations.

(2) Ordinarily the project must be for replacement of existing capital assets or undertaking the project must be required by an external party.

(3) The project must have a material effect on the company’s finances.

32. Further, at paragraph 593 of Decision 2012-237, the Commission indicated that the party recommending the capital tracker must demonstrate that all of the criteria have been satisfied in

order for a capital project or program to be approved as a capital tracker.

33. The implementation and application of the above capital tracker criteria were considered as part of the 2013 capital trackers, Proceeding No. 2131, leading to Decision 2013-435. The

Commission indicated that the implementation methodology established in that decision will be

used not only to evaluate the capital tracker projects or programs proposed by the parties for

2013, but also for subsequent capital tracker applications throughout the PBR term.29

34. With respect to the first capital tracker criterion, the Commission concluded that, in general, in order for a capital project or program to be considered outside of the normal course of

the company’s on-going operations, the increase in associated revenue provided under the I-X

mechanism would not be sufficient to recover the entire revenue requirement associated with the

prudent capital expenditures for this project or program. Accordingly, the Commission found

that the concept of normal course is mainly a financial and accounting consideration, rather than

strictly an engineering consideration. The Commission referred to this comparison of revenues as

the “accounting test” under Criterion 1. At the same time, the Commission indicated an

engineering study and a business case will aid the Commission in assessing whether a project

proposed for capital tracker treatment is (i) required to provide utility service at adequate levels

and, if so, (ii) that the scope, level and timing of the project are prudent, and the forecast or

actual costs of the project are reasonable. The Commission referred to this assessment as the

“project assessment” under Criterion 1. Therefore, the applicant must satisfy the Commission’s

requirements for both the accounting test and the project assessment in order to satisfy the

requirements of Criterion 1.30

28

Decision 2012-237, paragraph 586. 29


Decision 2013-435, paragraphs 149-150.



35. Regarding the accounting test component of Criterion 1, the Commission determined that this test should be based on the project net cost approach, under which the revenue generated

under the I-X mechanism for each capital project (or capital program or project category) is

compared to the forecast revenue requirement associated with that capital project (or capital

program or project category) in a PBR year. No consideration of operating and maintenance

costs or savings, or potential productivity offsets above those implied by the approved X factor,

are required for the accounting test.

36. For purposes of the project assessment, the Commission determined that each project or program proposed for capital tracker treatment must generally be supported by a business case

and an engineering study. However, the Commission recognized that in some circumstances an

engineering study may not be required. In Section 10.2 of Decision 2013-435, the Commission

found that for the purpose of the project assessment, a project or program proposed for capital

tracker treatment typically should address the following:

a. The rationale for the project, including the nature, scope, location, timing and cost of the project.

b. Any context for the project, which may include related past, present and future plans (e.g., for multi-year capital expenditures).

c. Evidence demonstrating that in the absence of the proposed capital expenditures, deterioration in service quality and safety would result.

d. Qualitative and, to the extent possible, quantitative descriptions of the service quality and safety risks addressed by the project.

e. Evidence that the capital project could not have been undertaken in the past as part of a prudent capital maintenance and replacement program.

f. A discussion of any reasonable alternatives, including the rationale for recommending the proposed solution.

g. A detailed forecast of costs for the project or project components, in sufficient detail to allow an evaluation of the reasonableness of the forecast.

h. A comparison of actual expenditures to forecast expenditures on similar projects over at least the previous five years, if available, including an explanation of any

differences.

i. With respect to proposed capital trackers, an explanation of any differences between the forecast costs of projects proposed for capital tracker treatment and the actual or

updated forecast costs of similar projects undertaken in the prior year. This

explanation should provide a breakdown of the project costs that includes both units

and costs-per-unit on a forecast and actual or updated forecast basis.

j. With respect to the true-up of capital tracker projects, an explanation of any differences between the forecast costs of projects approved for capital tracker

treatment and the actual cost of these projects undertaken in the prior year. This

explanation should provide a breakdown of the project costs that includes both units

and costs-per-unit on a forecast and actual basis.31

37. At paragraph 615 of Decision 2012-237, the Commission indicated that a company may choose to undertake a capital investment, prior to applying for capital tracker treatment in the

subsequent annual capital tracker filing. The Commission further clarified at paragraph 48 of

Decision 2013-435:

31

Decision 2013-435, paragraph 1092.



48.It was acknowledged by the Commission that superior incentives for capital trackers

would result if the companies were required to spend money on capital expenditures prior

to receiving approval for capital tracker recovery of the expenditures. However, given the

lack of experience with the capital tracker mechanism, for the first generation PBR plans,

it was determined that the companies will be permitted to apply for capital trackers on a

forecast basis. The approved forecast cost of a capital tracker project will be included in

rates on an interim basis and will be subject to a true-up to prudently incurred actual

expenditures, after the project is completed. The true-up process will test the prudence of

the actual capital expenditures and imprudent expenditures will be subject to

disallowance. As a result, the capital tracker mechanism retains some efficiency

incentives due to the risk of regulatory disallowances in the true-up process if

expenditures are not prudently incurred. The true-up mechanism with a prudence review

also mitigates somewhat the incentive for companies to overstate the initial capital

tracker forecasts. Nonetheless, the companies remained free to incur expenditures prior to

applying for capital tracker approval. [footnotes removed]

38. With respect to Criterion 2, the Commission clarified that, in addition to asset replacement projects and projects required by an external party, in principle, a growth-related

project will satisfy the requirements of Criterion 2 where it can be demonstrated that customer

contributions, together with incremental revenues allocated to the project on some reasonable

basis, when added to the revenue provided under the I-X mechanism, are insufficient to offset

the revenue requirement associated with the project in a PBR year. Criterion 2 also permits

consideration of certain projects for capital tracker treatment that do not fall into any of the

growth-related, asset replacement or external party related categories.

39. Under Criterion 3, the Commission determined that applying the materiality threshold to that portion of the revenue requirement for a project that is not funded under the I-X mechanism

is warranted. The Commission established a two-tier materiality threshold. The first tier of the

materiality threshold, a “four basis point threshold” is to be applied at a project level (grouped in

the manner approved by the Commission). The second tier of the materiality threshold, a

“40 basis point threshold” is to be applied to the aggregate revenue requirement proposed to be

recovered by way of all capital trackers.

40. Additionally, the Commission recognized the significance of the grouping of projects proposed for capital tracker treatment when it stated in paragraph 601 of Decision 2012-237:

601.… The Commission also considers that it would not be suitable to group together

several dissimilar projects into a single large project to give the appearance of materiality.

However, a number of smaller related items required as part of a larger project might

qualify for capital tracker treatment.

41. In Decision 2013-435, the Commission further elaborated that grouping of projects will require close scrutiny, since it will have a direct effect on the results of the accounting test and

the project assessment under Criterion 1, as well as the assessment of materiality under

Criterion 3. The Commission determined that the reasonableness of the grouping of capital

projects is best assessed on a case-by-case basis for each individual company. The Commission



indicated that it will require each company to provide a justification for its grouping of projects

proposed for capital tracker treatment.32

42. Finally, in Section 4.4 of Decision 2013-435, the Commission set out the K factor calculation methodology. The Commission determined that basing the K factor calculations on

the incremental revenue requirement amounts (i.e., above the amounts provided under the I-X

mechanism) for each project or program proposed for capital tracker treatment, as is done under

the project net cost approach, is commensurate with the Commission’s definition of outside the

normal course of the company’s on-going operations. Specific elements of the approved K factor

calculation methodology are discussed further in sections 9 and 12 of this decision, which deal

with AltaGas’ 2014 and 2015 K factor calculations.

3 Commission process for reviewing 2013 true-up and 2014-2015 capital tracker applications

43. In the following sections of this decision, the Commission assesses the company’s 2013 true-up and 2014-2015 forecast capital tracker requests. With respect to the 2013 true-up of

capital tracker projects or programs previously approved, the Commission stated following:

975.…[T]he March 1st capital tracker application shall true-up the costs of projects that

have been completed since the prior year‘s capital tracker filing together with sufficient

information to permit a prudence review of these completed projects. To facilitate a

prudence review of a project, the company must submit information showing that it has

completed the project in the most cost effective manner possible. This information will

include the results of competitive bidding processes, comparisons of in-house resources

to external resources, and any other evidence that may be of assistance in demonstrating

the prudence of the expenditures.33

44. Consistent with these determinations, the Commission considers that for the purposes of the true-up of capital tracker projects previously approved for 2013, if there is no evidence on the

record of the true-up proceeding demonstrating that a project is not required, then there is no

need to demonstrate that a project is needed in order to provide utility service at adequate levels,

which constitutes the assessment of need under Criterion 1. However, the second part of the

project assessment under Criterion 1 is still required so that the Commission can be satisfied that

the scope, level and timing of each project is prudent, and the actual costs of the project are

reasonable.

45. The Commission also considers that for the purposes of the true-up of capital tracker projects or programs previously approved, unless the driver for the project or program has

changed, there is no need to undertake a reassessment against the Criterion 2 requirements.

However, to the extent that costs have changed from the original approved forecast, the

Commission will undertake an assessment with respect to Criterion 3.

46. For any new projects in 2013 not previously approved, the Commission will undertake assessments with respect to all three criteria for capital tracker treatment.

32

Decision 2013-435, paragraphs 403 and 406. 33




47. With respect to forecast capital projects for 2014 and 2015 for which the company is seeking capital tracker treatment, the Commission will generally undertake assessments with

respect to all three criteria for capital tracker treatment. However, in those instances where a

project or program is part of an on-going multi-year program, or if a project or program is of an

annual recurring nature (e.g., relocations) that has been previously approved by the Commission

for capital tracker treatment, in the absence of evidence that the on-going or recurring project or

program is no longer required, the Commission will not undertake a re-assessment of need under

Criterion 1. However, the Commission will undertake assessments with respect to all remaining

aspects of the three criteria for capital tracker treatment.

48. In particular, Section 4 of the decision provides an overview of the programs for which AltaGas is seeking capital tracker treatment in 2013, 2014 and 2015. The evaluation of AltaGas’

proposed capital project groupings is set out in Section 5. The assessment of how AltaGas’

projects or programs proposed for capital tracker treatment satisfy Criterion 1 is set out in

Sections 6 and 7. In Section 8, the Commission reviews individual projects in each of the three

capital programs. In Section 9, the Commission reviews the accounting test requirements to

satisfy Criterion 1. The assessment under Criterion 2 is undertaken in Section 10 and the

assessment under Criterion 3 is set out in Section 11. Section 12 deals with the K factor

calculation methodology and the resulting approved K factor true-up for 2013, as well as

approved K factor forecasts for 2014 and 2015. Finally, Section 13 deals with other matters

raised throughout the proceeding.

4 Summary of projects included in the 2013 capital tracker true-up application and the 2014-2015 capital tracker application

49. AltaGas applied for capital tracker treatment for three programs; pipeline replacements, station refurbishments and gas supply.

4.1 Pipeline replacement program

50. The pipeline replacement program is a multi-year initiative. It was approved in Decision 2012-09134 for the 2010-2012 test period, and approved for 2013 as a capital tracker program in

Decision 2013-435.

51. AltaGas’ pipe replacement program provides for the replacement of three types of pipe: polyvinylchloride (PVC) pipe, non-certified and interim-certified polyethylene (PE) (collectively

referred to as non-certified PE) pipe35 and pre-1957 steel pipe. For each of the three types of pipe,

individual projects were provided and differentiated by geographic type (i.e., downtown, town,

village, hamlet, rural subdivision and rural).

52. AltaGas’ natural gas distribution system currently includes approximately 20,600 kilometres (km) of pipe of various types and ages. AltaGas indicated that all PVC, non-

certified PE and pre-1957 steel pipe needs to be replaced. This is because these pipe segments

34

Decision 2012-091: AltaGas Utilities Inc., 2010-2012 General Rate Application – Phase I, Application No.

1606694, Proceeding ID No. 904, April 9, 2012. 35

Both non-certified and interim certified PE pipe pose identical risks and their replacement is managed in the

same way. AltaGas refers to this pipe, collectively, as “non-certified PE.”




are at, or past, their useful lives, have high leak frequencies and exceed AltaGas’ risk tolerance

threshold in terms of the likelihood and potential harm from failures.36

53. AltaGas described the key steps in its multi-stage project prioritization and staging process for its pipe replacement program as including risk assessment, reconnaissance, pre-

engineering and design, contractor selection and construction.37 Under its risk assessment process

steps, AltaGas provided a risk assessment matrix to give a more tangible analysis of the overall

levels of risk associated with the three types of pipe that are proposed to be replaced, based on

the likelihood of an incident occurring and the severity of an incident if it occurs.

Table 1. AltaGas risk assessment matrix38

54. AltaGas provided a detailed risk assessment to prioritize segments of pipeline replacement based on the type and age of pipe, population density, ground cover, leak history

and whether the pipe is locatable by tracer wire. The project prioritization process also explicitly

considered the extent to which each project would coincide with municipal works and other

capital projects being done in the vicinity. AltaGas’ detailed risk assessment model, including

risk factors, likelihood and impact explanations, weights and scores is set out in Appendix 4.

55. AltaGas also provided risk scores for each of its planned 2014 and 2015 projects in the 2014-2015 capital tracker application. These risk scores can be found in Appendix 5.

56. For all three pipe replacement programs, AltaGas indicated that the benefits of replacement of PVC, non-certified PE and pre-1957 steel pipe include improved public and

worker safety, improved service reliability to customers and reduced greenhouse gas emissions

and unaccounted for gas losses into the atmosphere.

57. When the PVC pipe replacement program began in 2010, AltaGas had approximately 625 km of PVC pipe (three per cent) in its system. During 2010 to 2013, AltaGas replaced

36

Proceeding No. 3152, Exhibit No. 1, application, paragraph 52. 37


Proceeding No. 3152, Exhibit No. 1, application, paragraph 48, Figure 2.



approximately 143 km or 23 per cent of this pipe, at a cost of $9.9 million. In 2013, PVC

projects were focused on completion of projects remaining in the town and rural subdivision

areas, as well as rural areas, where the majority of remaining pipe to be replaced is located. In

the 2014-2015 capital tracker application, AltaGas submitted a business case in support of its

proposal to replace approximately 76.5 km of PVC pipe in 2014, at a total cost of $4.0 million,

and to replace approximately 51.0 km of PVC pipe in 2015, at a total cost of $3.6 million.

AltaGas is expected to continue this program throughout the 2014-2017 PBR term, with

complete replacement expected by 2021.39

58. When the non-certified PE pipe replacement program began in 2010, AltaGas had approximately 3,270 km of non-certified PE pipe (15.9 per cent) in its system. During 2010 to

2013, AltaGas replaced approximately 63 km or two per cent of this pipe, at a cost of

$6.7 million. In 2013, non-certified PE projects were focused on rural areas, hamlets and rural

subdivisions. Overall, lower actual costs and lengths installed for rural projects were essentially

offset by higher actual costs and lengths installed for rural subdivision projects as compared to

the approved forecast. Actual costs and lengths installed for hamlet projects were within the

approved forecast. In the 2014-2015 capital tracker application, AltaGas submitted a business

case in support of its proposal to replace approximately 26.7 km of non-certified PE pipe in

2014, at a total cost of $5.6 million, and to replace approximately 34.1 km of non-certified PE

pipe, at a total cost of $6.1 million. AltaGas expects to continue this program throughout the

2014-2017 PBR term, with complete replacement expected by 2037.40

59. When the pre-1957 steel pipe replacement program began in 2010, there was approximately 275 km of pre-1957 steel pipe (1.3 per cent) in AltaGas’ system. During 2010 to

2013, AltaGas replaced approximately 50.0 km or 18 per cent of this pipe, at a cost of

$9.4 million. In 2013, pre-1957 steel pipe replacement projects were focused on downtown and

town areas. Overall, actual costs were $0.5 million higher than forecast and the actual lengths

installed were 5.8 km lower than forecast. In its 2014-2015 capital tracker application, AltaGas

submitted a business case in support of its proposal to replace approximately 17.4 km of pre-

1957 steel pipe in 2014, at a total cost of $4.9 million, and to replace approximately 27.0 km of

pre-1957 pipe in 2015, at a total cost of $7.7 million. AltaGas is expected to continue this

program throughout the 2014-2017 PBR term, with complete replacement expected by 2021.41

60. Section 8.1 below considers all pipeline replacement projects that were approved in Decision 2013-435 and constructed in 2013, projects that were approved in Decision 2013-435

but deferred for construction to a future year, projects that were not forecast and approved in

Decision 2013-435 but were undertaken in 2013, and all projects forecast for 2014 and 2015. In

some instances, projects that were started in 2013 were not completely finished in 2013. These

costs are examples of what AltaGas refers to as trailing costs. Six pipeline projects (Leduc-Millet

rural, Westlock rural, Irvine rural, Drumheller near Station 005 rural, Bonnyville town, and

Athabasca town) that were forecast to be completed in 2013 were deferred to 2014, 2015 and

2016. Four projects (Drumheller downtown, Morinville rural, Picher Creek “mole line” and

Stettler town) that were not approved for 2013 but were undertaken in 2013.

39

Proceeding No. 3152, Exhibit No. 1, application, pages 1-3 and 14 of PVC pipe business case. 40

Proceeding No. 3152, Exhibit No. 1, application, pages 1-3 and 11 of non-certified PE pipe business case. 41

Proceeding No. 3152, Exhibit No. 1, application, pages 1-3 and 15 of pre-1957 steel pipe business case.



4.2 Station refurbishment program

61. The station refurbishment program is a multi-year initiative. It was approved in Decision 2012-091 for the 2010-2012 test period and, for 2013, it was approved as a capital tracker

program in Decision 2013-435.

62. AltaGas currently maintains and operates approximately 700 stations throughout Alberta, of which approximately 30 per cent were installed in the 1950s, 1960s and 1970s and are

currently equipped with obsolete parts or do not conform to the new pipe configurations. The

objective of AltaGas’ station refurbishment program is to replace and refurbish station facilities

presenting the greatest risk, which is determined by considering the risks associated with worker

safety issues and failure, and obsolescence to AltaGas’ design standards to ensure the equipment

is supported by the manufacturer.

63. AltaGas’ station refurbishment program provides for the replacement or refurbishment of three station types – purchase meter stations (PMS), town border stations (TBS) and post

regulator stations (PRS). PMS are the largest and most complex stations that AltaGas operates.

These sites have metering, odourization, line heaters, automatic meter reading and other

specialized equipment. TBS are mid-size stations and have sophisticated equipment, such as

alarms, line heaters and, in some cases, custom buildings to suit municipal requirements. PRS are

smaller scale pressure regulating sites.

64. AltaGas provided examples of issues encountered with older stations. For instance, AltaGas explained that many older facilities have in-line regulators that require splitting of pipe

runs for routine maintenance, which can be hazardous to workers. AltaGas also gave examples of

equipment that was prevalent in the 1950s and 1960s but has now become obsolete.

Consequently, spare parts for such equipment are very difficult, if not impossible, to procure

creating critical shortages during emergencies and limiting the company’s ability to conduct

required maintenance or repair.42

65. AltaGas also submitted that, in order to bring its stations up to AltaGas’ design standards and to ensure the equipment is supported by the manufacturer, replacement or refurbishment is

the only alternative for station facilities presenting the greatest risk, which is determined by

considering the risks associated with worker safety, failure and obsolescence. No other

reasonable alternative exists.43

66. Section 8.2 considers all station refurbishment projects that were approved in Decision 2013-435 and constructed in 2013, projects that were approved in Decision 2013-435

but deferred for construction to a future year, projects that were not forecast or approved in

Decision 2013-435 but were undertaken in 2013, and all projects forecast for 2014 and 2015. In

some instances, projects that were started in 2013 were not completely finished in 2013. Five

station refurbishment projects (PMS-LE081, TBS-DR016, TBS-DR009, PRS-LE310 and

LE060) that were forecast to be completed in 2013 were deferred to 2014. Three projects (PMS-

MN017, PRS-LE069 and PRS-MN032) that were not approved for 2013 were undertaken in

2013.

42

Proceeding No. 3152, Exhibit No. 1, Application, Station refurbishment business case, PDF pages 186-188 of

255. 43

Proceeding No. 3152, Exhibit No. 26, AUC-AUI-1, PDF page 9 of 19.



4.3 Gas supply program

67. AltaGas explained that, due to the unique nature of each gas supply project, it manages this program on a project-by-project basis. Depending on the project, work requirements may

include pipe construction/installation, station work and/or ancillary work, including connections

to gas supply lines such as NOVA Gas Transmission Ltd. (NGTL). Within a gas supply project,

typically, work on pipe construction/installation is negotiated with existing contractors, station

work is provided by AltaGas’ specially trained crews and welding and painting work is provided

by contractors, similar to the approach used for the station refurbishment program. The main

challenge in completing gas supply projects is making the arrangements with external suppliers

of natural gas: gas pipeline companies typically have long delivery schedules and high costs

associated with work such as “connections or tie-ins” to their existing pipelines.44

68. For 2014, AltaGas has identified St. Paul as the only non-growth gas supply project. This project addresses a permanent gas pressure reduction arising from NGTL’s installation of a new

downstream gas compression facility and the associated loss of this supply to AltaGas’

customers in the St. Paul area.

69. AltaGas stated that it has no supply facilities or pipelines in the area and must find a third party gas supply source to maintain safe and reliable service for its customers on the St. Paul

system and provide a cost-effective solution to overcome the lower gas supply pressures

resulting from NGTL’s new downstream compressor.

70. For 2015, AltaGas anticipates it will need to address gas supply issues, such as deteriorating supply or quality issues from the termination of third party suppliers. Some of these

gas supply projects are known in advance and some arise at short notice with associated

significant risks to service quality and safety.45

71. AltaGas stated that, when possible, gas supply projects will be identified for the upcoming year in sufficient time to provide project specific costs as part of its capital tracker

application. However, since the current application includes the year 2015, the use of a forecast

amount is considered reasonable, particularly as AltaGas’ experience indicates at least one gas

supply project is likely to arise in any given year.46

72. AltaGas has forecast a 2015 gas supply amount of $531,000, consisting of forecast direct costs of about $500,000 plus 6.2 per cent overhead for 2015. The forecast is based on the average

cost of gas supply projects completed since 2010.47

5 Grouping of projects for capital tracker purposes

73. In Decision 2013-435, the Commission determined that the accounting test and the first tier of the materiality test will generally be applied to the approved level of grouping (i.e., either

at a project or at a program level). The Commission also indicated that, while the project

assessment will generally be applied at the level of an approved grouping of projects, the

44

Proceeding No. 3244, Exhibit No. 1, application, paragraphs 31-34. 45


Proceeding No. 3152, Exhibit No. 21.01, AUC-AUI-14(c). 47

Proceeding No. 3152, Exhibit No. 9, application, paragraph 95.



Commission will, where necessary, consider the individual component projects comprising the

approved groupings in order to assess the need for the capital expenditures and the

reasonableness of the forecast costs. The second tier of the materiality test will be applied at the

level of all capital tracker projects, in aggregate.48 The Commission also determined that the

reasonableness of the grouping of capital projects is best assessed on a case-by-case basis for

each individual company.49

74. In support of its proposed grouping of projects into programs for the purposes of the accounting test and the first tier of the materiality test, AltaGas quoted from paragraph 402 of

Decision 2013-435:

… it is not the specific number of capital tracker programs (or the number of projects

that make up a capital tracker program) that matters. Rather, it is whether or not a

proposed capital project or a combination of properly grouped projects satisfies the

Commission’s criteria.

75. Based on the above, AltaGas submitted that, because its program groupings are consistent with those approved in Decision 2013-435, they satisfy the Commission’s criteria for the

grouping of projects for capital tracker treatment.

76. The UCA did not object to the grouping of projects proposed by AltaGas in this proceeding for either the 2014-2015 capital tracker application or the 2013 capital tracker true-up

application.

77. Referring to AltaGas’ proposed grouping of projects for the purposes of the accounting test, the CCA proposed that, with respect to replacement programs it is necessary to consider not

only the cost and revenues of replacement projects, but also the costs and revenues associated

with the assets that are being retired, and, the retirements for those assets, and their associated

revenue requirement, should be included in the accounting test for the proposed capital tracker.

The Commission considers that this issue is a matter of the allocation of depreciation and

revenues for the purposes of the accounting test, and not a matter relevant to the grouping of

projects into programs. Accordingly, the Commission has considered this issue in Section 9.4

below, as part of its accounting test assessment.

Commission findings

78. In Decision 2013-435, the Commission found:

512. The Commission has reviewed the grouping of the components of certain projects

into individual projects and the grouping of projects into programs, as proposed by

AltaGas for capital tracker treatment. In the Commission’s view, the projects, as grouped,

are consistent with AltaGas’ past practice in general rate applications. The Commission

also notes that AltaGas has grouped its pipe replacement projects into three like

categories under a single program. Each of the three categories includes projects for the

replacement of pipe of a similar asset type with a relatively common vintage. It is the

asset type and vintage characteristics of each type of pipe that give rise to the requirement

for replacement. With respect to the station refurbishment program, the Commission

notes that the projects in this program are for a common facility type of a similar vintage

48





and again it is the asset type and vintage that gives rise to the requirement for

replacement. Finally, with respect to the gas supply program, AltaGas has included two

projects of a like nature in a single program. The Commission finds this grouping of

projects by asset type, facility type and vintage characteristics, to be reasonable. For these

reasons, the Commission does not share the concerns of the UCA with respect to the

grouping proposed by AltaGas. The grouping of projects into programs for capital tracker

treatment is approved as filed.50

79. The Commission finds that AltaGas’ proposed grouping of projects into programs is consistent with the grouping approved by the Commission in Decision 2013-435. The

Commission is satisfied that this grouping remains reasonable for the purposes of the accounting

test under Criterion 1 and the materiality assessment in Criterion 3. The groupings are approved,

as proposed.

6 Project assessment under Criterion 1

80. As discussed in Section 2 of this decision, consistent with paragraph 841 of Decision 2013-435, each of AltaGas’ projects or programs proposed for capital tracker treatment will be

evaluated against the project assessment requirements of Criterion 1. The Commission will

review AltaGas’ capital tracker programs, and corresponding projects that comprise the program.

In Section 7, the Commission will assess the continuing need for each of the company’s

programs, previously approved in Decision 2013-435. The Commission will then:

a) assess 2013 projects previously approved for capital tracker treatment in Decision 2013-435, in Section 8.1.1;

b) assess 2013 projects not previously approved for capital tracker treatment in Decision 2013-435, in Section 8.1.2;

c) assess 2014-2015 forecast capital tracker projects, including projects previously approved in 2012 and 2013 but deferred to either 2014 or 2015, in Section 8.1.3.

81. As also noted in Section 2, in assessing the prudence of a capital tracker project or program that has been previously approved on a forecast basis for capital tracker treatment in

2013 and is now put forward for a true-up to actual 2013 costs, the Commission will not reassess

the need for the project or program. The Commission will, however, consider whether the actual

scope, level, timing and costs of the project or program were prudent, considering any

modifications or additions to the project or program since it was approved.

82. With respect to projects or programs proposed for capital tracker treatment in 2014 or 2015 on a forecast basis, the Commission determined, in Decision 2013-435, that the applicant

must satisfy the Commission’s requirements for both the accounting test and the project

assessment in order to satisfy the requirements of Criterion 1. The purpose of the project

assessment is to demonstrate that a project proposed for capital tracker treatment is (i) required

to provide utility service at adequate levels and, if so, (ii) the scope, level and timing of the

project are prudent, and the forecast or actual costs of the project are reasonable.51 To that end, a

50





business case and an engineering study will generally aid the Commission in conducting project

assessments under Criterion 1. Where a forecast project or program is part of a multi-year on-

going project or program, or if the project or program is of an annual recurring nature, that has

previously been approved for capital tracker treatment, in the absence of evidence that the on-

going program is no longer required, the need for the project will not be reassessed with each

new capital tracker application.

83. AltaGas provided a business case together with an engineering study (where AltaGas considered either document to be applicable) for each of its projects or programs proposed for

capital tracker treatment in 2014 or 2015. In its business cases and supplemented by other

evidence filed in the proceeding, AltaGas has generally provided an assessment of proposed

capital tracker projects consistent with the minimum filing requirements guidelines set out in

Section 10.2 of Decision 2013-435.52

84. The Commission has evaluated AltaGas’ business cases, engineering studies and related evidence and argument against each of the project assessment minimum filing requirements.

However, for the purposes of this decision, the Commission has commented only on those

aspects of the minimum filing requirements that the Commission considers are insufficiently

addressed by AltaGas’ evidence or were otherwise raised as an issue in the proceedings. In future

capital tracker applications, AltaGas should continue to provide similar information with respect

to each of the minimum filing requirements, including cost information by cost category in

sufficient detail to allow an evaluation of the reasonableness of the forecast.

85. AltaGas submitted that each of its three capital tracker programs satisfy the project assessment criteria set out in Decision 2013-435, because its ability to provide safe, reliable

service would be compromised in the absence of each of these projects, and the projects could

not have been undertaken previously.53

86. With respect to each of its programs, AltaGas proposed that its evidence indicates the pipe replacement program is required to prevent deterioration in safety and service quality. In

AltaGas’ view, the risks outlined from the outset of this program will continue to exist until these

replacements are complete. Station refurbishments are required as those stations scheduled for

refurbishment have now aged to the point where maintenance performed in the normal course of

business is not possible or no longer effective. Consequently, large scale refurbishments or

complete station replacements are required to maintain station operability and serviceability

within acceptable safety parameters. Finally, with respect to AltaGas’ gas supply projects, the

company argued that they arise as a result of the actions of third party suppliers (e.g. termination

of supply) or deterioration of the volume or quality of supply that would compromise safety and

service quality, if the program is not undertaken.54

6.1 Deferred projects

87. In the 2013 capital tracker true-up proceeding, AltaGas applied to have capital tracker treatment deferred for projects that were previously approved. Specifically, AltaGas requested

approval for the following projects, all of which were originally approved for implementation by

the Commission in Decision 2013-435:

52

Proceeding No. 3152, Exhibit No. 1, application; Decision 2013-435, paragraph 1092. 53

Proceeding No. 3152, Exhibit No. 26.02, AUC-AUI-1(a). 54

Proceeding nos. 3152 and 3244, Exhibit No. 74.01, AltaGas argument, paragraphs 18, 20 and 21.



Table 2. Deferred projects

Program Project name

Pipeline replacement:

PVC Leduc-Millet (rural)

Non-certified PE Westlock (rural)

Non-certified PE Irvine (rural)

Non-certified PE Drumheller (rural) area near Station 005

Pre-1957 Steel Bonnyville (town)

Pre-1957 Steel Athabasca (town)

Station refurbishment: PMS-LE081

TBS-DR016

TBS-DR009

PRS-LE310

PRS-LE060

88. Mr. Shymanski, on behalf of the UCA, raised an issue that previously approved projects deferred to a future year should not qualify for capital tracker treatment under Commission

capital tracker Criterion 1. He focused on the pipeline replacement program and recommended

that costs for any capital tracker projects that have been carried over from 2012 or 2013 into

2014 or later be denied capital tracker treatment.

89. Mr. Shymanski provided examples of the reasons given by AltaGas in the application for project deferrals, including projects that were deferred to accommodate higher than estimated

costs, funding constraints and resource constraints (both internal and external). He cited

Criterion 1 from paragraph 592 of Decision 2012-237 and paragraph 42 of Decision 2013-435,

which states “the project must be outside of the normal course of the company’s [on-going]

operations.”

90. Mr. Shymanski referred to paragraph 1092 of Decision 2013-435 in which the Commission provided a list of issues (minimum filing requirements) that a utility should address

in order to satisfy Criterion 1. Mr. Shymanski pointed to item c from that list which requires

“[e]vidence demonstrating that in the absence of the proposed capital expenditures, deterioration

in service quality and safety would result.” Mr. Shymanski referred to AltaGas’ response to

UCA-AUI-5(f) regarding a request for “…copies of any studies conducted by AUI or an external

consultant hired by AUI that evaluated and quantified the decrease in safety, quality of service

and increase in risk to AUI employees and AUI customers of not completing the forecast number

of kilometers of pipeline replacement in each of 2010-2013,” AltaGas’ response indicated “AUI

has not conducted any study on the risk related to pipe advanced or deferred between years.”

91. In Mr. Shymanski’s view, there is no evidence that the deferred projects were previously required to be completed, nor is there evidence that they are required to be completed in the

2013 to 2015 period. In response to a Commission information request asking if the UCA

considers that the safety and service quality risks purported by AltaGas are overstated,

Mr. Shymanski stated:

… To the extent that these pipeline replacements not being completed in 2012 – 2013 do

not affect the service levels or safety or that any effect cannot be or has not been



measured, the replacements could be determined to be premature in terms of timing.

There is no evidence from AUI that these specific carry-over pipeline replacements need

to be specifically done in the 2015 – 2017 time period. AUI has proposed pipeline

replacements over a very broad time frame ending in 2021. If the AUC considers that it

should approve a very broad time frame for this type of program, irrespective of what is

forecast, then in Mr. Shymanski’s view this approach is one of giving the utility “a

bucket of money” over the course of many years to complete the program irrespective of

service level and safety impacts in any given year. Mr. Shymanski does not consider this

approach would realize the full benefits of PBR in that the utility would not be incented

to minimize capital costs. The utility would be given broad approval to replace all the

pipe over a broad time frame with little oversight on an annual basis over whether the

pipe replacements were required in year 1 or year 9.55

92. AltaGas disagreed with the UCA, stating:

… it is clear despite issues with contractor availability, timing of municipal projects and

coordination on other urgent system projects, AUI has, with very few exceptions,

successfully completed each of its forecast projects and continually increased the

proficiency of its installation and forecasting processes. The lengths outstanding at the

end of 2013 (7.8 km) are largely due to changes in the timing, size and scope of final

projects …56

93. Responding to the UCA’s comment that AltaGas has not provided any quantitative analysis of the impact of pipeline replacement schedule changes on employee or customer safety

or quality of service, AltaGas responded that the UCA failed to reference the entire AltaGas

response to UCA-AUI-5(f), in which AltaGas also stated that these impacts are shown in the

respective risk assessments for the projects not completed in the attachment to AltaGas’ response

to AUC-AUI-9(d). AltaGas asserted that it “has in fact, identified the risk of each segment of

pipe, relative to other segments of pipe in the system. When it becomes necessary to defer any

project, the relative risk associated with that segment of pipe remains.”57

Commission findings

94. The UCA’s objection to the approval of deferred projects for capital tracker treatment is predicated on two issues. First, that AltaGas has not demonstrated that the projects were required

in a prior period to maintain service quality and safety because they were not completed in the

2010 to 2013 period. Second, there is no additional evidence that the projects are required in the

2013 to 2015 period to maintain service quality and safety.

95. In Section 10.2 of Decision 2013-435, the Commission found that for the purpose of the project assessment, a project or program proposed for capital tracker treatment should typically

be supported with evidence that the capital project could not have been undertaken in the past as

part of a prudent capital maintenance and replacement program, and evidence that in the absence

of the proposed capital expenditures, deterioration in service quality and safety would result.

96. The Commission does not consider that a project proposed for capital tracker treatment in the current year should be denied simply because it was approved in a prior year and deferred. It

55

Proceeding No. 3152, Exhibit No. 54.02, AUC-UCA-1(d). 56

Proceeding No. 3152, Exhibit No. 61.01, AltaGas rebuttal evidence, paragraph 3. 57

Proceeding No. 3152, Exhibit No. 61.01, AltaGas rebuttal evidence, paragraphs 15-16.



may be the case that the project was determined to be no longer necessary in a prior period, or

there may have been a valid business reason to defer the project, even though it was required. In

general, a previously approved project that has been deferred may qualify for capital tracker

treatment if there is sufficient evidence that the deferral was a prudent decision at the time and

given evidence of the continuing necessity to complete the proposed project to maintain service

quality and safety.

6.2 Project substitution

97. AltaGas revealed its understanding that project costs approved for capital tracker treatment could be managed at the program level, allowing the company to substitute projects

that were not specifically approved for capital tracker treatment in Decision 2013-435 for

projects that had been approved.

98. The UCA objected to what it characterized as a “bucket of costs” that could be spent by AltaGas on projects of its choosing. In Mr. Shymanski’s view, approval of a “bucket of costs”

over a long time frame (i.e., 2010 to 2021) with a schedule that might change if funds or

manpower are not available, does not seem to meet the first principle of a PBR plan as outlined

in paragraph 24 of Decision 2013-435 (taken from Bulletin 2010-2058): “A PBR plan should, to

the greatest extent possible, create the same efficiency incentives, as those experienced in a

competitive market while maintaining service quality.” A broad approval of a “bucket of costs”

over a long time frame with “off-ramps” dependent on internal considerations such as the

availability of funding and manpower, is not conducive to creating efficiency incentives. Such

incentives require more definitive and accurate forecasting on a year-by-year basis. 59

99. At the round table hearing, Commission counsel asked AltaGas’ witnesses why they consider it appropriate to manage pipeline replacement costs on a program basis, including

substituting new projects not previously included in business cases and not approved by the

Commission, for projects previously included in business cases and approved by the

Commission.

100. In response, Mr. Johnston and Mr. McKenzie, on behalf of AltaGas, provided the following reasons for AltaGas’ understanding that pipeline replacement costs may be managed

on a program basis. AltaGas needs the flexibility to manage overall pipeline risk while

responding to updated information and conditions and emerging priorities that occur over time,

such as contractor availability, construction efficiency, customer impacts and emerging risks

greater than the ones previously identified.

101. AltaGas believed that the Commission’s approval of its business cases, engineering studies, and forecast pipe replacement project and program costs in 2013 did not restrict

AltaGas’ ability to be flexible. AltaGas interpreted the spirit and intent of the true-up process to

be providing the company this flexibility within the three filed and approved pipeline

replacement business cases over the total length of the planned replacement program. In

AltaGas’ view, the existence of a true-up process determines the reasonableness of the costs

incurred on a project-by-project basis and AltaGas’ application for projects that were not

58

Bulletin 2010-20, Regulated Rate Initiative – PBR Principles, July 15, 2010. 59

Proceeding No. 3152, Exhibit 54.02, AUC-UCA-2(b).

http://www.auc.ab.ca/news-room/bulletins/Bulletins/2010/Bulletin%202010-20.pdf



included in the original 2013 capital tracker application and were executed in 2013 are included

in the 2013 capital tracker true-up application.60

102. Mr. McKenzie quoted from Decision 2012-237 and Decision 2013-435 in support of AltaGas’ position, stating that these basic principles were in their minds when they reprioritized

some of the projects.61

615.… unless a company chooses to undertake investment prior to applying for recovery

of its costs by way of a capital tracker, the company will be expected to provide a

forecast with its capital tracker application. …62

48.… The true-up mechanism with a prudence review also mitigates somewhat the

incentive for companies to overstate the initial capital tracker forecasts. Nonetheless, the

companies remained free to incur expenditures prior to applying for capital tracker

approval.63

103. Commission counsel suggested that AltaGas had not yet applied for capital tracker treatment for projects completed but not approved for capital tracker treatment in Decision

2013-435. Mr. McKenzie agreed and added that AltaGas is applying for those projects as part of

its 2013 capital tracker true-up application. Mr. McKenzie undertook to provide references to the

filed evidence that would satisfy the minimum filing requirements associated with demonstrating

these substitute projects merit capital tracker treatment in respect of the newly added projects.64

Commission findings

104. The Commission agrees with AltaGas that the companies regulated under the PBR capital tracker regime require the flexibility to manage capital programs to respond to updated

information and conditions and emerging priorities that occur over time, such as contractor

availability, construction efficiency, customer impacts and emerging risks. Indeed, the PBR

regime is intended to encourage the companies to manage their capital programs in a prudent

manner, and accordingly the companies should be able to adjust their capital programs as

circumstances require. However, because the capital tracker regime is intended to deal with the

revenue requirements associated with certain capital investments that may not be adequately

funded from revenues available from going-in rates escalated by I-X, the K factor does not

represent a “bucket of money” that can be used to fund alternative projects that arise. This is

because, for each approved project or program, the capital tracker criteria established the amount

of revenue requirement not adequately funded by the I-X mechanism for a forecast period, and

any alteration from the approved program or projects may affect the outcome of the

Commission’s assessment under the capital tracker criteria and change the amount of revenue

requirement to be funded by the K factor. This is why the Commission requires the K factor to

be trued-up.

105. To facilitate the companies’ flexibility to manage capital programs, in Decision 2012-237, the Comm

Decision 2014-373 AltaGas Utilities Inc. - AUC · 2018. 2. 23. · AUC Decision 2014-373 (December...

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