AltaLink Management Ltd. - AUC · The Alberta Utilities Commission Decision 3585-D03-2016: AltaLink...

Decision 3585-D03-2016

AltaLink Management Ltd. 2012 and 2013 Deferral Accounts Reconciliation Application June 6, 2016

The Alberta Utilities Commission

Decision 3585-D03-2016: AltaLink Management Ltd.

2012 and 2013 Deferral Accounts Reconciliation Application

Proceeding 3585

Application 1611090-1

June 6, 2016

Published by


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

Calgary, Alberta

T2P 3L8

Telephone: 403-592-8845

Fax: 403-592-4406

Website: www.auc.ab.ca

Decision 3585-D03-2016 (June 6, 2016) • i

Contents

1 Decision .................................................................................................................................. 1

2 Introduction, procedural schedules and motions ............................................................... 2

3 Background to the application and structure of the decision ........................................... 4

4 Direct assign capital deferral account ................................................................................. 8 4.1 Common matters ............................................................................................................ 8

4.1.1 Inclusion of partially completed projects .......................................................... 8 4.1.2 Accuracy and purpose of baseline estimates .................................................. 10 4.1.3 Rate impact to customers ................................................................................ 13

4.1.4 Impact of disallowance ................................................................................... 15

4.1.5 Prudence test and burden of proof .................................................................. 19 4.1.6 Roles and responsibilities of the AESO, TFOs and Commission ................... 24

4.1.7 In-service date targets ..................................................................................... 30

4.1.8 Timing of DACDA and general tariff applications ........................................ 35 4.1.9 Filing requirements ......................................................................................... 39 4.1.10 Cost and performance audits ........................................................................... 51

4.1.11 Project cost escalation and related allowances ............................................... 57 4.1.12 Treatment of contingency allowances ............................................................ 63

4.1.13 Capitalized labour and E&S costs ................................................................... 65 4.1.14 EPCM agreement matters ............................................................................... 68

4.1.14.1 EPCM labour pricing under original SNC-ATP MSA ................. 69

4.1.14.2 EPCM costs and competitive procurement processes .................. 70

4.1.14.3 Risk Reward mechanism............................................................... 79 4.1.14.4 EPCM service provider obligation to provide fixed price ............ 82 4.1.14.5 Enforcement of EPCM contractual obligations ............................ 87

4.1.14.6 EPCM agreement contracted material/contracted labour surcharges

....................................................................................................... 91

4.1.15 Treatment of accruals ...................................................................................... 94 4.1.16 Line optimization and design issues ............................................................... 96

4.1.16.1 Professional practice requirements ............................................... 97

4.1.16.2 Tower selection and tower utilization ......................................... 100 4.1.17 Use of rig mats .............................................................................................. 114 4.1.18 Use of helicopters ......................................................................................... 119

4.1.19 ADC proposal ............................................................................................... 123 4.1.20 Other matters ................................................................................................. 124

4.1.20.1 Customer contributions ............................................................... 124 4.1.20.2 Land compensation ..................................................................... 125

4.2 System projects .......................................................................................................... 127 4.2.1 D.0305 – Cassils to Bowmanton (CB) .......................................................... 127

4.2.1.1 Recovery requested ..................................................................... 127

4.2.1.2 Project overview ......................................................................... 128 4.2.1.3 Key project variances .................................................................. 129 4.2.1.4 In-service date ............................................................................. 130

4.2.1.5 Use of rig mats ............................................................................ 132 4.2.1.6 Use of helicopters ....................................................................... 133 4.2.1.7 Pipeline mitigation ...................................................................... 134

ii • Decision 3585-D03-2016 (June 6, 2016)

4.2.1.8 Analysis of change notices .......................................................... 138 4.2.1.9 Summary of findings................................................................... 139

4.2.2 D.0371 – Heartland ....................................................................................... 140 4.2.2.1 Recovery requested ..................................................................... 140 4.2.2.2 Project overview ......................................................................... 140 4.2.2.3 Key project variances .................................................................. 141 4.2.2.4 Inclusion of 2014 costs ............................................................... 143

4.2.2.5 Transmission line design............................................................. 146 4.2.2.6 EDTI charges .............................................................................. 150 4.2.2.7 Use of rig mats ............................................................................ 151 4.2.2.8 Use of helicopters ....................................................................... 151 4.2.2.9 Pipeline mitigation ...................................................................... 152

4.2.2.10 Delays attributed to monopole section ruling ............................. 161 4.2.2.11 12S substation project delays ...................................................... 164

4.2.2.12 Graham construction ................................................................... 167 4.2.2.13 Analysis of change notices .......................................................... 173 4.2.2.14 Land acquisition issues ............................................................... 175 4.2.2.15 Request for cost and performance audit ...................................... 178

4.2.2.16 Summary of findings................................................................... 179 4.2.3 Other major system projects ......................................................................... 180

4.2.3.1 D.0030.01 – Yellowhead Area Transmission Development Hinton-

Edson Development .................................................................... 180 4.2.3.1.1 Recovery requested ..................................................................... 180

4.2.3.1.2 Project overview ......................................................................... 181 4.2.3.1.3 Key project variances .................................................................. 182

4.2.3.2 D.0030.03 – Yellowhead Area Transmission Development

Cherhill Area Development ........................................................ 184

4.2.3.2.1 Recovery requested ..................................................................... 184 4.2.3.2.2 Project overview ......................................................................... 184

4.2.3.2.3 Key project variances .................................................................. 185 4.2.3.3 D.0108 – SE Development – Brooks Area ................................. 186 4.2.3.3.1 Recovery requested ..................................................................... 186

4.2.3.3.2 Project overview ......................................................................... 187 4.2.3.3.3 Key project variances .................................................................. 188 4.2.3.4 D.0213 – Edmonton Region 240-kV Lines Upgrades ................ 189 4.2.3.4.1 Recovery requested ..................................................................... 189

4.2.3.4.2 Project overview ......................................................................... 189 4.2.3.4.3 Key project variances .................................................................. 190

4.2.3.5 D.0238 – Athabasca Area Telecom Development ...................... 191 4.2.3.5.1 Recovery requested ..................................................................... 191 4.2.3.5.2 Project overview ......................................................................... 192 4.2.3.5.3 Key project variances .................................................................. 193 4.2.3.6 Hanna Region transmission system development projects ......... 194

4.2.3.6.1 D.0353 – Hanna Area Transmission – Nilrem............................ 197 4.2.3.6.1.1 Recovery requested ..................................................................... 197 4.2.3.6.1.2 Project overview ......................................................................... 198 4.2.3.6.1.3 Key project variances .................................................................. 200 4.2.3.6.2 D.0354 – Hanna Area Transmission – Hansman Lake ............... 202 4.2.3.6.2.1 Recovery requested ..................................................................... 202 4.2.3.6.2.2 Project overview ......................................................................... 203

Decision 3585-D03-2016 (June 6, 2016) • iii

4.2.3.6.2.3 Key project variances .................................................................. 204 4.2.3.6.3 D.0355 – Hanna Area Transmission – Ware Junction and D.0316

Southern Alberta Transmission Reinforcement – Ware In/Out .. 206 4.2.3.6.3.1 Recovery requested ..................................................................... 206 4.2.3.6.3.2 Projects overview ........................................................................ 208 4.2.3.6.3.3 Key project variances .................................................................. 209 4.2.3.7 D.0377 – Christina Lake Area Development – Black Spruce 154S

..................................................................................................... 212 4.2.3.7.1 Recovery requested ..................................................................... 212 4.2.3.7.2 Project overview ......................................................................... 213 4.2.3.7.2.1 Key project variances .................................................................. 215 4.2.3.8 D.0409 – ENMAX No. 65 Interconnection ................................ 218

4.2.3.8.1 Recovery requested ..................................................................... 218 4.2.3.8.2 Project overview ......................................................................... 219

4.2.3.8.3 Key project variances .................................................................. 221 4.2.3.9 D.0414 – Western Alberta Transmission Line ........................... 222 4.2.3.9.1 Recovery requested ..................................................................... 222 4.2.3.9.2 Project overview ......................................................................... 223

4.2.3.9.3 Key project variances .................................................................. 226 4.2.3.10 D.0458 – East HVDC Converter Station Interface ..................... 227

4.2.3.10.1 Recovery requested ..................................................................... 227 4.2.3.10.2 Project overview ......................................................................... 228 4.2.3.10.3 Key project variances .................................................................. 230

4.2.3.11 Red Deer Area Transmission project .......................................... 232 4.2.3.11.1 D.0459 – Red Deer Area Transmission – Split 768L & 778L.... 233

4.2.3.11.1.1 Recovery requested ................................................................ 233

4.2.3.11.1.2 Project overview ..................................................................... 234

4.2.3.11.1.3 Key project variances ............................................................. 234 4.2.3.11.2 D.0460 – Red Deer Area Transmission – TX add at Benalto 17S

..................................................................................................... 236 4.2.3.11.2.1 Recovery requested ................................................................ 236 4.2.3.11.2.2 Project overview ..................................................................... 237

4.2.3.11.2.3 Key project variances ............................................................. 237 4.2.3.11.3 D.0461 – Red Deer Area Transmission – Capbank at Joffre 535S

..................................................................................................... 239 4.2.3.11.3.1 Recovery requested ................................................................ 239

4.2.3.11.3.2 Project overview ..................................................................... 239 4.2.3.11.3.3 Key project variances ............................................................. 240

4.2.3.11.4 D.0462 – Red Deer Area Transmission - Capbank at Prentiss 276S

..................................................................................................... 241 4.2.3.11.4.1 Recovery requested ................................................................ 241 4.2.3.11.4.2 Project overview ..................................................................... 242 4.2.3.11.4.3 Key project variances ............................................................. 242

4.2.3.11.5 D.0463 – Red Deer Area Transmission – Capbank at Ellis 332S

..................................................................................................... 244 4.2.3.11.5.1 Recovery requested ................................................................ 244 4.2.3.11.5.2 Project overview ..................................................................... 245 4.2.3.11.5.3 Key project variances ............................................................. 245

4.2.4 Minor projects ............................................................................................... 247 4.3 Customer projects....................................................................................................... 250

iv • Decision 3585-D03-2016 (June 6, 2016)

4.3.1 Fortis projects................................................................................................ 250 4.3.1.1 Prudence assessment ................................................................... 250

4.3.1.2 Contributions and capital trackers .............................................. 254 4.3.1.2.1 Contribution on D.0179 – Kirby 651S New Substation (D.0179)

..................................................................................................... 259 4.3.1.3 Fortis non direct assign projects ................................................. 261

4.3.2 Non-Fortis connection projects ..................................................................... 263

4.3.2.1 Non-Fortis direct assign projects ................................................ 263 4.3.2.2 Non-Fortis customer projects ...................................................... 266

4.4 Cancelled projects ...................................................................................................... 268 4.5 Trailing costs .............................................................................................................. 272

5 Other deferral accounts .................................................................................................... 274 5.1 2012 and 2013 long-term debt deferral accounts ....................................................... 274

5.2 Other costs associated with short-term debt .............................................................. 274

5.3 Taxes other than income taxes ................................................................................... 275 5.4 Annual structure payments ......................................................................................... 275

6 Responses to Commission directives ............................................................................... 275

7 Reconciliation .................................................................................................................... 276 7.1 Refund of CWIP in rate base amounts ....................................................................... 276 7.2 Compliance filing ....................................................................................................... 277

8 Order .................................................................................................................................. 278

Appendix 1 – Proceeding participants .................................................................................... 279

Appendix 2 – Oral hearing – registered appearances ........................................................... 280

Appendix 3 – Motions and procedural rulings ...................................................................... 281

Appendix 4 – Project proceedings and approvals .................................................................. 285

Appendix 5 – Use of jurisdiction adjustment in assessing competitiveness of rates ........... 300

Appendix 6 – Summary of Commission directions ................................................................ 304

Appendix 7 – Abbreviations ..................................................................................................... 311

Decision 3585-D03-2016 (June 6, 2016) • v

List of tables

Table 1. Intervener evidence disallowance requests ............................................................. 16

Table 2. Summary of Round Hill project contingency allowance updates ........................ 65

Table 3. Forecast versus actual FTEs .................................................................................... 67

Table 4. AltaLink actual versus forecast labour costs.......................................................... 67

Table 5. RPG evidence of tower utilization for R22 tower family .................................... 108

Table 6. RPG summary of general ledger costs for access roads and rig mats ............... 114

Table 7. AltaLink easement costs included in 2012-2013 DACDA application projects 125

Table 8. Cassils to Bowmanton cost breakdown ................................................................. 128

Table 9. CB change notices ................................................................................................... 130

Table 10. Heartland Transmission project (D.0371) cost breakdown ................................ 140

Table 11. Heartland change notices ....................................................................................... 142

Table 12. Tower type mix identified in the PPS .................................................................... 148

Table 13. Subcontract amendments supporting disallowance ............................................ 174

Table 14. Yellowhead Hinton-Edson Development project (D.0030.01) cost breakdown 180

Table 15. Project D.0030.01 key cost variance events .......................................................... 182

Table 16. Yellowhead - Cherhill Areas development cost breakdown ............................... 184

Table 17. Project D.0030.03 key cost variance events .......................................................... 185

Table 18. SE Development project – Brooks Area cost breakdown ................................... 186

Table 19. Project D.0108 key cost variance events ............................................................... 188

Table 20. Edmonton Region 240-kV Transmission Line Upgrades - 902L cost breakdown

................................................................................................................................... 189

Table 21. Athabasca Area Telecom Development cost breakdown .................................... 192


Table 23. Hanna Regional Transmission Development (HRTD) Nilrem cost breakdown 198


Table 25. HRTD Hansman Lake cost breakdown ................................................................ 203

vi • Decision 3585-D03-2016 (June 6, 2016)


Table 27. SATR Ware cost breakdown ................................................................................. 207

Table 28. HRTD Ware cost breakdown ................................................................................ 207

Table 29. Key cost variance events ......................................................................................... 210

Table 30. Christina Lake – Black Spruce 154S cost breakdown ......................................... 212

Table 31. Christina Lake Development Phases and NID stage cost estimates ................... 214


Table 33. ENMAX No. 65 Interconnection cost breakdown ............................................... 218


Table 35. WATL 240-kV line modifications cost breakdown ............................................. 222

Table 36. Western Alberta Transmission Line – total project cost breakdown ................ 222

Table 37. East HVDC Link cost breakdown ......................................................................... 227

Table 38. East HVDC Converter Station Interface – total project cost breakdown ......... 227


Table 40. Red Deer Area – Split 768L & 778L cost breakdown ......................................... 233


Table 42. Red Deer Area – Benalto 17S cost breakdown ..................................................... 236


Table 44. Red Deer Area – Capbank at Joffre 535SS cost breakdown .............................. 239


Table 46. Red Deer Area – Capbank at Prentiss 276S cost breakdown ............................. 242


Table 48. Red Deer Area – Capbank at Ellis 332S cost breakdown ................................... 244


Table 50. Minor direct assigned system projects costs ......................................................... 247

Table 51. Fortis connection projects costs ............................................................................. 251

Table 52. Summary of Fortis direct assigned project capital addition adjustments ......... 253

Decision 3585-D03-2016 (June 6, 2016) • vii

Table 53. Contributions and DTS contract levels on Fortis direct assign connection

projects ..................................................................................................................... 257

Table 54. Fortis non-direct assigned projects costs .............................................................. 262

Table 55. Non-Fortis direct assigned connection project costs............................................ 264

Table 56. Non-Fortis direct assigned connection projects cost variance events ................ 265

Table 57. Non-Fortis customer project costs ......................................................................... 267

Table 58. Summary of cancelled projects .............................................................................. 269

Table 59. Directive responses.................................................................................................. 276

Decision 3585-D03-2016 (June 6, 2016) • 1


Calgary, Alberta

Decision 3585-D03-2016

AltaLink Management Ltd. Proceeding 3585

2012 and 2013 Deferral Accounts Reconciliation Application Application 1611090-1

1 Decision

1. The Alberta Utilities Commission (AUC or Commission) found that some of the costs

regarding AltaLink Management Ltd.’s (AltaLink or AML) applied-for deferral account

reconciliation, were not reasonable and, therefore, all of the rate base capital additions applied-

for were not approved.

2. In this application, AltaLink requested final cost approval for 103 transmission capital

projects, which, net of customer contributions, would result in gross capital additions to its rate

base of approximately $1.977 billion. The Commission found AltaLink to have prudently

planned and executed the majority of these capital projects. These findings included approval of

the majority of costs for AltaLink’s major system projects, including the Cassils to Bowmanton

project and the Heartland project, which were completed to the point of energization at a cost of

approximately $345 million and $697 million, respectively.

3. The Commission did not approve costs in the Cassils to Bowmanton (CB) project related

to remediation charges for supplied crates and, based on insufficient support, only approved a

placeholder for pipeline mitigation costs. Regarding the Heartland project, the Commission also

found that there was insufficient evidence to support the pipeline mitigation costs and only a

placeholder for these costs was approved. The Commission also disallowed certain costs arising

from Graham Construction’s performance on the Heartland project. As well, the Commission has

deferred collection of the land acquisition costs in the Heartland project to a future proceeding to

allow for the completion of the anticipated resale of some of the properties acquired.

4. The total amount of costs disallowed for the CB and Heartland capital projects was less

than $7 million.

5. The Commission also directed placeholder treatment for the recovery of costs requested

for completed portions of the Western Alberta Transmission (WATL) project to the end of 2013.

The Commission indicated it would evaluate the costs for the entire WATL project in a future

application once all of the project costs, for this forecast $1.7 billion project are known.

6. The forecast costs for these capital projects were approved in Decision 2013-023,1

Decision 2012-221,2 Decision 2011-453,3 Decision 2011-474,4 Decision 2013-4075 and

1 Decision 2013-023: AltaLink Management Ltd., Second Refiling Pursuant to Decision 2012-221, Decision

2011-453 and Decision 2011-474, Proceeding 2138, Application 1608831-1, January 30, 2013. 2 Decision 2012-221: AltaLink Management Ltd., Refiling Pursuant to Decision 2011-453 and

Decision 2011-474, Proceeding 1734, Application 1608178-1, August 17, 2012.

2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.

2 • Decision 3585-D03-2016 (June 6, 2016)

Decision 2014-2586 and have been reflected in the Alberta Electric System Operator (AESO)

tariff. Therefore, the final costs approved by the Commission in this decision will result in an

additional charge of approximately $30 million to the AESO.

7. The Commission ordered AltaLink to refile its 2012 and 2013 deferral accounts

reconciliation application to reflect the findings, conclusions and directions set out in this

decision by August 15, 2016.

2 Introduction, procedural schedules and motions

8. On December 17, 2014, AltaLink filed an application (the application) with the

Commission for approval of its 2012 and 2013 deferral account balances as well as the direct

assign capital deferral account (DACDA) balance pertaining to 2014 additions for the Heartland

project.

9. The Commission assigned Proceeding 3585 to the application and issued notice on

December 18, 2014.7 In response to the notice, statements of intention to participate (SIPs) were

received on or before December 29, 2014 from the following parties:

ATCO Electric Ltd. (ATCO)

Alberta Electric System Operator (AESO)

Alberta Direct Connect Consumers Association (ADC)

Consumers’ Coalition of Alberta (CCA)

EPCOR Distribution & Transmission Inc. (EDTI)

Industrial Power Consumers Association of Alberta (IPCAA)

Office of the Utilities Consumer Advocate (UCA).

10. The ADC, the CCA and IPCAA participated and presented evidence or testimony on

their own behalf and jointly as members of the Ratepayer Group (RPG).

11. During the process leading up to the oral hearing, the Commission issued nine procedural

and evidential rulings in response to requests and motions from both the applicant and the

intervener parties. Included were rulings granting confidential treatment of certain evidence.

Particulars of the motions and rulings have been summarized and provided in Appendix 3 to this

decision.

12. An oral hearing was held at the Commission’s hearing room in Calgary from

November 9, 2015 to November 20, 2015. During that time, the Commission held a session of

the oral hearing on a confidential basis between November 18 and 20, 2015, which confined

3 Decision 2011-453: AltaLink Management Ltd., 2011-2013 General Tariff Application, Proceeding 1021,

Application 1606895-1, November 18, 2011. 4 Decision 2011-474: 2011 Generic Cost of Capital, Proceeding 833, Application 1606549-1, December 8,

2011. 5 Decision 2013-407: AltaLink Management Ltd., 2013-2014 General Tariff Application, Proceeding 2044,

Application 1608711-1, November 12, 2013. 6 Decision 2014-258: AltaLink Management Ltd., Refiling Pursuant to Decision 2013-407 and Decision

2013-459, Proceeding 3024, Application 1610245-1, September 8, 2014. 7 Exhibit 0219.01.AUC-3585.


Decision 3585-D03-2016 (June 6, 2016) • 3

attendance to parties who had signed confidentiality undertakings. By the close of day on

November 20, 2015, the appearance of the AltaLink witness panel had been completed, but the

witness panels for interveners had not been started. Accordingly, on that date, the chair of the

Commission panel advised parties that the schedule for the resumption of the oral hearing would

be finalized in separate Commission correspondence.8

13. On November 23, 2015, the Commission issued correspondence9 that provided additional

clarification on an undertaking to be prepared by AltaLink witness Mr. Dorsey in response to a

request made by the Commission during the public portion of the oral hearing held on

November 20, 2015.

14. On December 1, 2015, the Commission advised parties10 that it anticipated that three

sitting days would be required to complete the remaining portion of the oral hearing, and

proposed that the resumption of the oral hearing should occur in Calgary from January 27, 2016

to January 29, 2016. After considering correspondence filed by AltaLink and the CCA, the

Commission confirmed in correspondence dated January 8, 201611 that the oral hearing would

resume on January 27, 2016.

15. Also in the Commission’s January 8, 2016 letter, the Commission set out a schedule for

parties to file questions relating to written undertaking responses that were filed after the

November 20, 2015 adjournment of the oral hearing. This schedule required those questions to

be filed on or before January 13, 2016; the schedule also required AltaLink to file any responses

to such questions on or before January 20, 2016.

16. The oral hearing for Proceeding 3585 was resumed in Calgary on January 27, 2016. A

confidential module of the oral hearing was held on January 28, 2016, and the oral hearing

concluded on January 28, 2016. At the close of the oral hearing on January 28, 2016, the chair of

the Commission panel advised parties that a final outline for argument would be provided.

However, the chair of the Commission panel also made it clear that parties were requested, but

not required, to follow this outline when organizing their argument and reply submissions. The

Commission circulated a draft outline for argument on January 29, 2016.

17. As discussed in correspondence issued on January 29, 2016,12 a certain number of

responses to undertakings remained outstanding at the close of the oral hearing. The Commission

directed that all outstanding undertakings be filed on or before February 3, 2016, any questions

on those undertakings should be filed on February 5, 2016, and responses on those undertakings

should be filed by February 9, 2016. On the same day, the Commission issued correspondence13

directing AltaLink to provide responses on or before February 4, 2016, on supplementary

questions prepared by the Commission.

18. The Commission received written public and confidential argument from AltaLink and

the RPG, and received public argument only from the ADC and from ATCO on February 22,

8 Transcript, Volume 8, page 1453.

9 Exhibit 3585-X0808.

10 Exhibit 3585-X0809.

11 Exhibit 3585-X0816.

12 Exhibit 3585-X0841.

13 Exhibit 3585-X0844.


4 • Decision 3585-D03-2016 (June 6, 2016)

2016. The Commission received public and confidential reply argument from AltaLink and the

RPG on March 8, 2016 and received reply argument, in public form only, from the ADC and

ATCO on March 8, 2016.

19. The Commission considers the record for Proceeding 3585 to have closed on March 8,

2016.

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

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

As noted above, the Commission granted confidential treatment to a discrete portion of the

evidence on the record of this proceeding. This decision reflects the Commission’s findings from

all of the evidence on the record of this proceeding, including those issues that were addressed in

further detail in the confidential portion of this proceeding. No separate confidential decision will

be issued.

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

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

evidence, argument and reply 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 that

matter.

3 Background to the application and structure of the decision

22. A large transmission build has been underway in Alberta over the past several years.

These transmission projects are now either completed or in their final stages of completion. As a

consequence, the Alberta transmission utilities which have been responsible for building this

new transmission are now bringing forward applications to the Commission for approval to

recover their actual project costs for these projects. Noting that the Heartland project capital

additions during 2014 are included, AltaLink’s 2012-2013 DACDA application is near the peak

of Alberta’s large transmission build. The peak year appears to be 2015, a year in which

AltaLink forecasts gross capital additions of approximately $2.8 billion.14

23. In this application, AltaLink has requested final cost approval for 103 transmission

capital projects, which would result in gross capital additions to its rate base of approximately

$1.977 billion. This gross addition amount is offset by customer contributions in the amount of

$275.1 million in aggregate. After taking these contributions into account, AltaLink’s proposed

net capital additions are approximately $1.702 billion. Among the projects included in its

application were the CB project, which was completed at a cost of approximately $345 million

and the Heartland project, which was completed at a cost of approximately $697 million. Both of

these projects were highly complex projects, whose execution spanned several years.

24. As set out in detail below in Section 4.1.5, in a deferral account reconciliation

proceeding, the Commission must determine whether the actual costs incurred by AltaLink were

prudently incurred. To do so, the Commission assesses the reasonableness of decisions made by

14

Exhibit 3585-X0839.


Decision 3585-D03-2016 (June 6, 2016) • 5

AltaLink at the time the decisions were being made. Consequently, the Commission reviewed, in

detail, the supporting documentation associated with the projects while the projects were

progressing through their design, construction and energization phases.

25. The number of projects included in this application, along with the corresponding

substantial capital addition costs applied-for, necessitated an extraordinarily voluminous record.

The Commission directed AltaLink to provide considerable detailed cost information, much of

which was redacted on the public record and filed on a confidential basis to protect the integrity

of the competitive tendering process, which, according to AltaLink, accounts for 70 to 80 per

cent of the costs of a transmission project.15

26. The record in this proceeding included the following categories of supporting

documentation in relation to the projects:

(a) AESO reporting documents including proposals to provide service (PPS) forms,

monthly reports, change orders and other directives and correspondence exchanged

between the AESO and AltaLink as required by Independent System Operator (ISO)

Rule 9.1.

(b) Contractual documentation (master services agreement and amending agreements

collectively, MSA) regarding the provision of engineering procurement and

construction management (EPCM) services to AltaLink from SNC-Lavalin ATP Inc.

(SNC-ATP).

(c) Competitive procurement documentation including:

(i) Requests for proposal (RFP) and requests for quotation (RFQ): RFPs and RFQs

were solicitation documents posted to elicit potential contractors or subcontractors

to submit bids in a competitive process. RFPs contained details of the type of

service or products for purchase and instructions to interested bidders on how to

submit their bids.

(ii) Response to RFPs: Responses to RFPs were the contractors’ or subcontractors’

bids in response to the competitive process. Responses to RFPs generally

contained details on how the bidder proposed to carry out the project, including

information on the scope of the work required, work schedules, and costs.

Responses to RFPs may have also contained proprietary engineering information.

(iii) Bid opening form (BOF): BOFs included information on the project name, the bid

opening date and time, the invitation to bid closing date, the project budget, the

number of bids requested and the number of bids received, bidder names, and

bidders’ unevaluated prices.

(iv) Requisition enhancement form (REF): REFs were used to explain when the

procurement rules were not being followed and proposed an alternative solution.

REFs also indicated whether the work was contracted through a competitive

tendering process or sole sourced.

15

Exhibit 3585-X0704, paragraph 100.


6 • Decision 3585-D03-2016 (June 6, 2016)

(v) SoleSource Justification and Approval Forms (SoleSource Form): These were

standard forms that must be completed when material and/or services were

obtained from a specific supplier instead of by way of a tendering process.

Included in the SoleSource Forms were the supplier’s name; the estimated service

or material cost; the type of commodity; and project number, facility number and

RFP number. SoleSource Forms also included a checklist with reasons why the

material or service has to be obtained from a specific supplier.

(vi) Bid analysis and recommendation (BAR): Documents in this category included

information regarding the evaluation of tenders received from subcontractors and

recommendations to award the tender to the winning bidder.

(d) Commercial agreements for the performance of services or provision of materials from

subcontractors and vendors including:

(i) Standard request form for service (RFS) and commitment approval forms (CAF):

These included standard agreements for service between SNC-ATP and

subcontractors or vendors. RFSs contained information indicating the

subcontractor’s or the vendor’s name, the project name, the scope of the services

to be provided, the services’ estimated prices, and project start dates. RFS’s were

usually accompanied by a CAF containing information similar to that contained in

the related RFS.

(ii) Subcontract agreements (SC): SCs were agreements executed between SNC-ATP

and subcontractors regarding work carried out by the subcontractor.

(iii) Lease and accommodation agreements: Leases were contracts between the lessor

and the lessee (SNC-ATP) that allowed SNC-ATP rights to the use of the

property owned or managed by the lessor for a period of time. Standard leases

included the name of the lessor; information on the compensation amount for the

use of the property; and the terms and conditions of the lease such as rental

period, payment method, use of equipment and warranties.

(e) Documentation regarding the submission and payment of costs during the execution of

the project including invoices, purchase orders, costs for mobilization and

demobilization of construction crews (CMDC), change notices (CN) and change orders.

(f) Procedural manual between SNC-ATP and AltaLink, which set out the policies and

procedures to be followed for the review, approval, processing and payment of invoices

submitted by SNC-ATP to AltaLink.

27. The Commission carefully examined the information provided on the record to

understand the circumstances during which project decisions were being made and costs were

being incurred as a consequence of those decisions. It considered the economic conditions

prevalent in the market at the time the projects were executed and the reasonableness of the

decisions made by AltaLink throughout the project’s lifecycle. The Commission was particularly

interested in determining whether AltaLink had met its onus to demonstrate the prudence of

project cost variances or changes to its project schedules and budgets and assigned significant


Decision 3585-D03-2016 (June 6, 2016) • 7

weight to the documentation that was created at the time critical decisions were being made,

since these documents provided insight into the challenges AltaLink faced and the measures it

took to address these challenges as these projects moved through their execution cycles.

28. Further, the Commission also considered the legislative framework under which AltaLink

must operate, including the requirement to comply with ISO rules and directions. ISO Rule 9.1

establishes the reporting requirements expected of a transmission facility owner (TFO) by the

AESO with respect to both project reporting and project procurement practices including

provisions governing:

The determination of TFO service territories and directions to TFOs to prepare facility

applications for new transmission projects.

Obligations on TFOs to provide cost estimates and PPS.

Project cost reporting, including:

o monthly project reporting

o duties of TFOs to notify the AESO in the event of changes in the expected project in-

service dates (ISDs) or material changes in project cost forecasts

Obligations on TFOs to prepare project change proposals to address project delays, cost

trends, or scope changes and obligations imposed on the AESO to review and approve

such reports.

Obligations on TFOs to prepare final cost reports.

Duties of TFOs and the AESO in respect of the competitive procurement of major project

components defined as any project cost component that is expected to exceed $50,000.16

Structure of the decision

29. In Section 4.1, the Commission provides its findings in relation to common issues that

arose regarding AltaLink’s prudent execution of the capital projects in this proceeding. This

section also includes the Commission’s findings in response to policy issues raised by parties and

the test applied by the Commission to assess prudence. Further, this section provides the

Commission directions regarding future filing requirements and the timing of further

applications.

30. In Section 4.2, the Commission sets out its prudence findings for each of the system

projects included in this application. The section first provides the Commission’s prudence

assessment of the major system projects, beginning with the CB and the Heartland projects and

follows with the Commission’s prudence findings for AltaLink’s minor system projects.

31. In Section 4.3, the Commission provides its findings for each of the connection projects

included in this application. This section also includes the Commission’s observations regarding

the relationship between customer contributions and the treatment of these connection project

costs in FortisAlberta Inc.’s (Fortis) tariff as a capital tracker.

32. In Section 4.4, the Commission provides its findings regarding cancelled projects and, in

Section 4.5, its findings regarding trailing costs.

16

ISO Rule 9.1.5.


8 • Decision 3585-D03-2016 (June 6, 2016)

33. In Section 5, the Commission sets out its findings in relation to all other deferral accounts

and, in Section 6, its findings regarding AltaLink’s compliance with Commission directives.

34. In Section 7, the Commission discusses the manner in which its findings shall be

implemented and has also established a date for refiling.

4 Direct assign capital deferral account

4.1 Common matters

4.1.1 Inclusion of partially completed projects

35. Six of the 103 projects for which AltaLink was seeking approval for additions to rate

base were only partially completed by the end of 2013. These projects represented requested

gross capital additions of $79.6 million and net capital additions of $51.2 million. The six

projects partially completed by the end of 2013 are:

D.0213 – Edmonton Region 240-kV lines

D.0414 –WATL

D.0458 – East High-Voltage, Direct Current (HVDC) Converter Interface

D.0410 – East Calgary Transmission project/Shepard Energy Centre Interconnection

D.0434 – Greengate – Blackspring Ridge Wind Farm Interconnection

D.0395 – Whitecourt Industrial 364S Substation Upgrade

36. In argument, AltaLink submitted that the Commission’s long standing practice has been

to approve for inclusion into rate base, the energized portions of partially completed projects.

AltaLink also noted that each of these six partially completed projects have discrete portions that

are energized and form part of the Alberta Integrated Electric System (AIES).

37. AltaLink’s witness, Mr. Fedorchuk, explained that the depreciation of assets in service

commences when facilities are energized,17 and submitted that the Commission’s practice of

including additions on partially complete projects allows the Commission’s review to be

conducted as close as possible to the actual date of energization.

38. The Commission questioned whether the WATL project, due to its size, may be more

efficiently examined in a single proceeding. AltaLink submitted that if the Commission

considered it would be more efficient to do this, it would not object to having the WATL project

examined in a later proceeding, but if so, a placeholder in the amount of the requested partial

addition should be approved in the current proceeding.18

39. The RPG submitted in its argument that it had no general objection to inclusion of

partially completed projects in rate base, subject to following caveats:

The portion of a project to be added needs to have been energized and to be used and

required to be used.

17

Transcript, Volume 5, page 979, cited at Exhibit 3585-X0859, paragraph 20. 18



Decision 3585-D03-2016 (June 6, 2016) • 9

The attribution of costs to the partially completed portion of a project and to the

remainder of that project must be clearly identified and separated.

Any allocation of common costs between partially completed portions of a project and

the remainder of that project must be fully disclosed to allow testing of the allocation.

Any trailing costs must be fully identified.19

40. In reply, AltaLink submitted that the RPG’s proposed caveats on the inclusion into rate

base of the costs of portions of partially completed projects are unnecessary because the RPG’s

proposed caveats seek information that AltaLink already provides when it requests approval for

the inclusion of these costs into rate base.20

41. In its reply, the RPG generally agreed with AltaLink’s position that projects must be

energized and form part of the AIES before the costs associated with these projects are added to

rate base. In addition, the RPG agreed with AltaLink that if all WATL project costs are examined

in a single proceeding, it would be reasonable to allow placeholder treatment for the costs to be

included in rate base for the relevant portions of the partially completed projects identified in the

current proceeding.21

Commission findings

42. The Commission has previously established that TFO’s do not have to wait for all

expenditures on a project to be completed before requesting that expenditures on direct assigned

projects be added to rate base on a final basis. In particular, the Commission has determined that

while many direct assigned projects may still have material trailing costs that are expected to be

incurred after the year a project is energized, these costs do not preclude the TFO from including

costs incurred to the point of energization in a DACDA application.22

43. The six projects that AltaLink identified as partially completed by the end of 2013 are

different from the remaining projects in the DACDA application. The latter projects are

substantially completed but for trailing costs, by the end of 2013, whereas the six partially

completed projects represent the completion of only a portion of a larger unfinished project.

Notwithstanding this difference, if the facilities whose value AltaLink proposes to add to rate

base, have been energized and are effectively in use to the benefit of current rate payers, then, as

in the case of complete projects with outstanding trailing costs, it is reasonable for AltaLink to be

allowed to recover allowances for depreciation and tax expenses, and to earn a return, on its

invested capital.

44. With the exception of the WATL project, the Commission has been able to determine

from the evidence on the record whether the expenditures on facilities completed during the

2012-2013 DACDA test period for these projects were prudent. Accordingly, for these five

partial addition projects, the Commission prudence determination of the costs of these partially

completed facilities is final.

19

Exhibit 3585-X0860, paragraph 25. 20



See for example Decision 2013-407, AltaLink 2013-2014 GTA at PDF page 266 and Decision 2014-283

Decision 2014-283: ATCO Electric Ltd., 2012 Transmission Deferral Account and Annual Filing for

Adjustment Balances, Proceeding 2683, Application 1609720-1, October 2, 2014, PDF page 167.


10 • Decision 3585-D03-2016 (June 6, 2016)

45. However, as discussed further in Section 4.2.3.9, AltaLink’s evidence was not sufficient

for the Commission to make a definitive determination as to whether AltaLink’s actual

expenditures on the specific facilities that AltaLink brought into service before the end of 2013

for WATL were prudently incurred. Accordingly, while the Commission will allow AltaLink to

use the amount of the 2013 addition it requested as the basis for revenue requirement

reconciliation calculations for the DACDA test period for this project, the Commission has

treated this addition as a placeholder only. All of the WATL project costs will be examined in a

future DACDA application proceeding.

46. Last, although the Commission has made a final determination of the prudence of the

costs for the expenditures on the East HVDC Converter Interface project (D.0458), for the

reasons set out in section 4.3.3.10 of the decision, the Commission has determined that

expenditures on this project should remain as part of construction work in progress (CWIP) and

should be considered for addition to rate base when the project is complete.

4.1.2 Accuracy and purpose of baseline estimates

47. In Section 7.3 of the application, AltaLink described the purpose of cost estimates

prepared at various stages of the life cycle of a direct assigned project. In this explanation,

AltaLink discussed the effect that limitations of information available to it at various stages have

on its ability to prepare an estimate that will be accurate in relation to the final cost of a direct

assign project.

48. AltaLink noted that while it provided estimates for the AESO needs identification

document (NID) application stage,23 the PPS estimate stage,24 and the PPS update stage (also

sometimes referred to as the +/-10 per cent or 180-day stage),25 the more reliable estimate is at

the PPS update stage. At this stage, AltaLink has much better information to refine the cost

estimate of a project that it is directed to build. The PPS update stage estimates incorporate:

Any AESO changes to project scope or functional specification changes.

Any changes to routing, tower design or other elements ordered by the Commission in its

facility proceeding decision.

A better understanding of the effect of consultation and other commitments on schedule

delays.

A better ability to gauge accurately the effect of market conditions on project material

and labour costs.26

49. Consequently, AltaLink submitted that the PPS update stage estimate is the most relevant

and useful comparator against final costs for the direct assign projects included in the

application.27

50. In its evidence, the RPG submitted that variances from projected costs are a likely

indicator of imprudence, and submitted that AltaLink’s common reference to “market escalation”

23

Exhibit 0002.00.AML-3585, paragraph 64. 24




Exhibit 0002.00.AML-3585, paragraph 76.


Decision 3585-D03-2016 (June 6, 2016) • 11

as the cause for variances did not provide a meaningful context to explain project cost

variances.28

51. In its rebuttal evidwence, AltaLink submitted that while the RPG typically refers to any

excess of actual costs over the PPS stage estimate as a cost overrun and makes the assertion that

variances from projected costs are a likely indicator of imprudence,29 variances from the PPS

stage estimate should not be considered as an indication of imprudence because:

PPS stage estimates are point-in-time estimates that do not reflect a review of actual

expenditures in view of the circumstances experienced on specific projects.30

The escalation from baseline forecasts that occurs on specific projects generally reflects

the actual increase in the cost of competitively procured labour and materials that has

occurred due to market conditions.31

In Decision 2014-283 in respect of the 2012 DACDA to ATCO Electric, the Commission

found that the role of baseline estimates was to identify variances for further

investigation.32

Variances for matters outside of the TFO’s control such as adverse weather, landowner

impacts and environmental/wildlife impacts, can never be fully costed.33

52. AltaLink submitted the above noted considerations reinforce the view stated in the

application that the PPS Update stage estimate is a more reliable cost comparator than the PPS

stage estimates.34 However, even the PPS Update stage forecast is subject to significant variance,

particularly for large projects spanning several years, because project design may have to change

as project field conditions or other initial assumptions are disproved.35

53. In its argument, the RPG submitted that the accuracy of baseline estimates such as the

PPS stage estimate is of concern and the PPS Stage estimate is far too inaccurate to be used as a

baseline for assessing prudence because:

An inflated PPS stage estimate can mask poor performance.

The PPS stage estimate is only scrutinized by the AESO, who is only interested in the

estimate for its planning purposes.36

54. The RPG also questioned the use of PPS Update stage estimates as a basis for

determining prudence. In particular, the RPG submitted that while there is some merit to

assessing costs after permit and licence (P&L) when major decisions such as routing have been

determined, it is also important to recognize that potentially imprudent decisions with respect to

28





Decision 2014-283, paragraph 77, cited at Exhibit 3585-X0704, paragraph 88. 33






12 • Decision 3585-D03-2016 (June 6, 2016)

the selection of subcontractors and the adoption of improper terms of agreements may occur in

advance of the PPS update stage estimate.37

55. Given the above noted limitations of PPS stage estimates, the RPG submitted that the

primary value of review of the PPS stage estimate is at the sub-category level. In this regard, the

RPG submitted that examination of actual variances against sub-categories of the PPS stage

estimate can be used as a flag for investigation of potential imprudence.38

56. In argument, AltaLink submitted that the role and purpose of the PPS estimate has been

well established by the Commission and that there is no need or basis for further debate on the

role and purpose of baseline estimates within DACDA proceedings. ATCO submitted that it was

notable that while the RPG appears to understand that many of the underlying cost drivers, and

information supporting these drivers, is unavailable at the PPS stage,39 the RPG continues to

suggest that “questionable” costs above these estimates require a disallowance, or at least some

further review or audits. ATCO submitted that PPS stage estimates were never meant to operate

as triggers for these actions.40

57. The RPG noted in its reply argument that the Commission expects an accurate PPS stage

estimate given the information at the time. If the PPS stage estimate accurately reflects the

information available at the time, then variations should be an accurate indication that some

change has occurred.

58. In reply, AltaLink argued that the RPG’s allegation in argument that AltaLink’s PPS

Stage estimates are inflated to mask performance on project execution is inflammatory, baseless,

and insulting. It submitted that the uncontradicted evidence in the proceeding is that PPS stage

estimates provided in response to direct assignment by the AESO, reflect the cost of meeting the

AESO’s functional specification on the basis of information known at the time.41

59. In its reply, ATCO also objected to the RPG’s characterization of line item variances as

“red flags for imprudence.” Given the purpose of a PPS stage estimate as a mechanism to

manage and report on projects in accordance with the ISO rules, the RPG’s attempt to convert

the PPS stage estimate into a threshold indicator for imprudence was improper. The applicable

ISO rules (9.1.2.4 and 9.13.2) direct TFOs to prepare and explain variances based on the total

amount of the PPS estimate. ATCO submitted that the requirement in the rule is appropriate and

sufficient to assess project changes. Conversely, ATCO submitted that adopting the RPG’s

suggested approach would add further administrative burdens to the process with no

demonstrated benefit.42

Commission findings

60. The Commission recognizes that PPS stage estimates can be significantly affected by

later information, such as Commission rulings on line routings that may differ from the

assumptions used at the time the PPS stage estimate was prepared. However, not all costs on

37



Exhibit 3585-X0857, paragraph 14, citing Transcript, Volume 9, pages 1518-1520. 40





Decision 3585-D03-2016 (June 6, 2016) • 13

direct assign projects reflect decisions made after the facility application decision is issued.

Therefore, the Commission rejects AltaLink’s submission that the estimate prepared 180 days

after the issuance of a P&L should be the baseline from which variances of actuals to forecast are

examined.

61. In Decision 2014-283 the Commission addressed ATCO Electric’s application to

approve, as final, its direct assign project costs for 2012. This decision reflected the first

Commission deferral account decision following the repeal of the statutory presumption of

prudence in the Transmission Regulation. In this ATCO Electric proceeding, issues regarding the

use of PPS estimates as a baseline for analysis were extensively canvassed by the proceeding

participants.

62. The Commission stated:

77. However, a variance from a baseline estimate prepared at the PPS stage is not, in

and of itself, an indication of imprudence. Rather, the purpose of the comparison of

actual results to the baseline estimate is to identify areas of significant variance for

further investigation as to the cause and reasonableness of the related decisions made by

ATCO, as critical pieces of information became known. This being said, it is important

that the baseline estimates be as accurate as possible, and that they reflect ATCO’s best

estimate of what a project is expected to cost at the time the PPS stage estimate is

prepared, given the information available at that time. [emphasis added]

63. The Commission reaffirms this finding.

4.1.3 Rate impact to customers

64. In Section II C of its main evidence, the RPG submitted that the Commission needs to

place intervener concerns regarding cost increases into their proper context.

65. The RPG noted that AESO forecasts show that significant rate increases are occurring for

all rate classes. In this regard, the RPG noted that the AESO had presented a rate impact model

to the Transmission Facilities Cost Monitoring Committee (TFCMC) indicating that average

transmission costs will be approximately $47.50 per megawatt hour by 2021.43 The RPG noted

that this forecast is subject to further change when the AESO updates its long-term plan.44

However, the RPG submitted that even this increase in transmission rates may be understated

due to:

Reductions in the load forecast caused by changes in oil prices.

The limited opportunity to defer projects already well into construction.

An increased incentive for large industrials to switch to behind the fence generation.

66. The RPG submitted that while its contextual concerns are largely AESO planning related

and are not of direct concern for the current DACDA, the above noted contextual concerns

increase the need to ensure all costs evaluated in the DACDA are prudent.45

43





14 • Decision 3585-D03-2016 (June 6, 2016)

67. In argument, AltaLink noted that DACDA proceedings are significant because both a

review of the prudency of the expenditures for direct assign projects takes place and a

reconciliation of forecast capital expenditures to actual capital expenditures takes place.46

68. AltaLink noted that in Decision 2013-407, in the Commission’s findings in respect of

expenditures on the Southwest 240-kilovolt (kV) project, the Commission took note of the fact

that the current process is backward looking, and comes with the difficulty of denying a major

investment after it has occurred.47 As such, AltaLink submitted that because a disallowance in the

current DACDA proceeding would also be an after-the-fact, backwards looking disallowance,

the RPG’s observation that a disallowance would be mathematically small must be weighed

against the effect that the disallowance would have on the market’s perception of the risk of the

regulatory environment.48

69. In its argument, the RPG submitted that legislative protections that were created to

protect ratepayers from the excesses of a monopoly have been rendered largely ineffective. The

RPG submitted that while this would be a significant concern if only moderate growth in

transmission facilities and costs were occurring, the reduction in consumer protection has

occurred during a time of unprecedented transmission growth.49 It again stressed the importance

of ensuring all costs incurred for projects in the 2012-2013 period are prudent in light of its

contextual concerns.50

70. In reply, AltaLink reiterated the view it expressed in argument that a disallowance that is

apparently small in relation to AltaLink’s revenue requirement may have a significant effect on

AltaLink’s cost of capital. AltaLink submitted that the RPG’s suggestions regarding the potential

for customers to opt out of the transmission system are purely speculative, and irrelevant to

consideration of actual project costs within the DACDA application proceeding. As such, when

assessing prudency, the Commission must not make its prudence determinations through the lens

of changes in the load forecast or the potential for opting out of the system.51

Commission findings

71. The forecast costs of the projects included in this application have been approved in

previous Commission GTA decisions. If AltaLink’s application is approved as filed, its applied-

for costs would result in an additional charge to the AESO of $30.3 million, which represents the

difference between the forecast amounts already collected by the AESO for AltaLink’s tariffs

and what would be the final costs for these projects.

72. As set out in sections 121 and 122 of the Electric Utilities Act, the Commission must

ensure that a tariff is just and reasonable, not unduly preferential, arbitrary, unjustly

discriminatory or inconsistent with the law and, in so determining, must, “provide the owner of

an electric utility with a reasonable opportunity to recover the costs and expenses associated with

capital related to the owner’s investment in the electric utility.”

46


Decision 2013-407, paragraph 1191, cited at Exhibit 3585-X0859, paragraph 34. 48






Decision 3585-D03-2016 (June 6, 2016) • 15

73. The Commission has done so on the basis of the evidence presented.

4.1.4 Impact of disallowance

74. In its evidence, the RPG submitted that the Commission should not be unduly influenced

by allegations that disallowances based on imprudence will be of concern to the investment

community because:

Even a major disallowance, for example, in the range of $100 million, would be a small

proportion of revenue requirement (only 1.9 per cent of 2016 revenue associated with rate

base and only 1.56 per cent of total 2016 revenue requirement).52

The SNC-ATP MSA provides that SNC-ATP billing is adjusted to reflect disallowed

amounts.53

AltaLink can pursue contractual relief where disallowances relate to findings that

contractual obligations have not been met.54

75. In its rebuttal evidence, AltaLink submitted that the large disallowance requests sought

by interveners in the range of $300 million reflects an approach similar to the one the RPG took

in ATCO Electric’s 2012 DACDA application proceeding, where disallowances of $97 million

were sought and ultimately found not to have merit.55

76. AltaLink submitted that while interveners appear to have a view that they have nothing to

lose by asking for a large disallowance,56 a large disallowance would cause significant financial

and reputational harm to AltaLink.57

77. In light of recent Commission decisions, AltaLink submitted that the investment

community is watching Alberta. In response to an information request posed by the Commission

in AltaLink’s 2015-2016 GTA proceeding, AltaLink calculated that a credit rating downgrade

from an A rating to a BBB rating would increase the cost of debt by $154,577,403, calculated on

a net present value basis.58 Moreover, AltaLink noted that this net present value calculation

reflected an assumption that the credit rating could be restored within five years; however, if

such an assumption proved to be incorrect, the harm to ratepayers would be even greater.59

78. In its argument, the RPG provided a summary (reproduced, in part, below) that identified

the potential disallowance sought in its evidence:

52







Exhibit 3524-X0429, AML-AUC-2015JAN20-027 (October 16, 2015 update), cited at paragraph 644 of

Exhibit 3585-X0704. 59



16 • Decision 3585-D03-2016 (June 6, 2016)

Table 1. Intervener evidence disallowance requests

Source Potential disallowance

Grid Power report $100 million

FTI Consulting, Inc. (FTI) report $127 million

RPG main evidence Up to $106.1 million

Source: Exhibit 3585-X0860, paragraph 48.

79. The RPG submitted that AltaLink’s characterization of the effect of disallowance

amounts represents a “lose/lose scenario” for customers, since customers would either have to

pay for imprudent costs, or pay a greater cost of capital as a result of a disallowance. However,

the RPG submitted that it was unlikely that the Alberta legislature contemplated that the

Commission would not make a disallowance on the basis of fear that customers would pay an

increased cost of capital.60

80. The RPG submitted that the simple solution to the apparent dilemma of a downgrade

raising the cost of debt is to deem the cost of debt that would otherwise have been in place

without the downgrade.61 The RPG noted the Commission questioned Mr. Levson about the

potential for a “knock-on” or “multiplier” effect from the combination of a disallowance and the

deeming of debt costs because AltaLink could be perceived to be subject to more risk.62

However, the RPG noted that Mr. Levson explained that while there is always a potential for a

knock-on effect, since Alberta TFO’s regularly earn more than their allowed rates of return, it is

debatable that a disallowance would be seen as significant to AltaLink’s shareholders.

81. In any event, IPCAA’s witness, Ms. Bellissimo, whose constituents represent a large

proportion of Alberta’s load, indicated that from the perspective of her customers, the prudence

of the costs examined was more important than the potential knock-on consequences.63

82. Further, the RPG observed that a clause dealing with disallowances was included in the

agreement for the purchase of AltaLink from SNC-Lavalin Inc. by Berkshire Hathaway Energy.

The RPG noted that while AltaLink was declining to answer questions on these provisions on the

basis that these provisions were a matter for its shareholder rather than a matter for AltaLink,64

AltaLink was also expressing concerns about a potential downgrade, which is also a matter for

its shareholder. Accordingly, the RPG submitted that AltaLink’s position on these two matters is

inconsistent, and AltaLink should not be able to “have it both ways.”65

83. In argument, AltaLink submitted it is apparent that the interveners have adopted the

approach that there is nothing to lose by making excessive demands for disallowances.66

AltaLink argued that the RPG has adopted this approach to disallowances despite the fact that

the RPG has appeared to recognize that if Alberta utilities are subjected to significantly increased

60




Exhibit 3585-X0860, paragraph 55, citing Transcript, Volume 10, page 1844. 64

Transcript, Volume 1, page 70, cited at Exhibit 3585-X0860, paragraph 56. 65




Decision 3585-D03-2016 (June 6, 2016) • 17

disallowances, and the cost of debt increases, the possibility of credit downgrades becomes a

significant risk that would harm ratepayers.67

84. AltaLink submitted that it is important to take note that it was the RPG, and not AltaLink,

who raised the issue about the potential effect of disallowances on the regulatory environment

and on rate payers generally.68

85. AltaLink submitted that while it has fully acknowledged the fact that it is subject to the

established prudency standard,69 the RPG seeks to elevate this standard to perfection, which is

beyond its proper scope of reasonableness.70

86. AltaLink submitted that it is inherent to the nature of decision making for an adjudicator

to consider the effects of its decisions,71 and submitted that the recognition that a prudency

disallowance has significant effects is at the basis of Commission determinations that have

recognized the difficulty of denying the recovery of actual incurred costs.72 The RPG’s attempt to

downplay the effect of a disallowance by converting a capital disallowance to a revenue

requirement effect, and then assessing this lower amount in relation to the size of AltaLink’s

overall revenue requirement shows a lack of understanding of finance. Under International

Financial Reporting Standards (IFRS) requirements, AltaLink has no choice but to charge the

entire amount of the disallowance against current net income.73 Given these requirements,

AltaLink noted that a $100 million disallowance would eliminate almost $100 million of

AltaLink’s projected 2016 net income, and a disallowance of $330 million would eradicate

AltaLink’s net income completely.74

87. In its reply, the RPG submitted that who first raised the effect of disallowances is

irrelevant.75 Given the extent to which AltaLink has played up concern as to the potential effect

of disallowances on the cost of capital, the RPG submitted that AltaLink’s suggestion that they

would not have mentioned this if not for the RPG is disingenuous.76

88. The RPG submitted that AltaLink’s suggestion that a disallowance would “necessarily”

affect all regulated utilities in Alberta is a very wide statement, which the RPG disagreed with

because:

Interveners have been requesting disallowances for several years, so raising

disallowances in the current proceeding is unlikely to have any effect on the investment

community.77

AltaLink staff are not in a position to give an expert or impartial assessment of the likely

reaction of the investment community.78

67













18 • Decision 3585-D03-2016 (June 6, 2016)

AltaLink overestimates its own importance when it suggests that a disallowance of its

costs will affect all regulated utilities in Alberta.79

The claim that harm to AltaLink must result in harm to ratepayers is inconsistent with the

view of the Supreme Court of Canada (SCC) as to whether customers should be harmed

if the TFO fails to prove its case.80

89. In reply, AltaLink repeated its assertions that any disallowance will have industry-wide

effects, so a provision dealing with the allocation of disallowances will not reduce these

industry-wide effects. In any event, AltaLink submitted that how commercial parties choose to

allocate risks is irrelevant to the prudency of AltaLink’s costs.81

Commission findings

90. In Decision 2044-D01-2016,82 the Commission made the following findings in respect of

concerns raised by AltaLink in Proceeding 2044 about the potential harm that could arise from a

disallowance:

242. However, it is the utility that bears the burden of demonstrating that its tariff

is just and reasonable.

243. A disallowance of costs incurred because of a finding of imprudence is based

upon evidence that is clear and substantive. Such evidence must be examined fairly

and objectively, giving consideration to only those circumstances that a utility knew

or could reasonably be expected to have knowledge of at the time a decision is made.

The Commission will make its decision on that evidence alone.

91. The Commission confirms these findings in this decision. The burden of proof on a TFO

to demonstrate that its tariff is just and reasonable, and the corresponding risk that a failure to do

so can result in a disallowance of costs is a key element in the legislative design used to motivate

a TFO to act prudently so that the Commission is not required to direct or micro-manage the

TFO’s day to day operations.

92. The Commission would not and has not approved imprudent costs out of concern that a

disallowance would have a potentially adverse effect on AltaLink’s credit rating. Any

disallowances relative to amounts that AltaLink requested have been made on the basis of clear

and substantive evidence.

93. Should AltaLink be subject to an adverse rating solely as a direct consequence of any

disallowance in this decision, AltaLink may bring forward an application to determine who

should bear the consequences of such an action.

78



Exhibit 3585-X0865, paragraph 32, citing Exhibit 3585-X0860,paragraph 70. 81


Decision 2044-D01-2016: AltaLink Management Ltd., 2010-2011 Direct Assign Capital Deferral Account,

Audit of Southwest Transmission Project, Proceeding 2044, Application 1608711-1, January 20, 2016.


Decision 3585-D03-2016 (June 6, 2016) • 19

4.1.5 Prudence test and burden of proof

94. In its general evidence, the RPG stated that the onus is on a TFO to demonstrate the

prudence of its incurred costs. They also provided details regarding the characteristics of the

evidence that should be required to be provided in order to demonstrate to the Commission that

costs have been prudently incurred. The RPG considered that the evidence must be

comprehensive, coherent and convincing. The RPG defined each of those terms as follows:

Comprehensive evidence requires the disclosure of all costs incurred paying

particular attention to anomalous costs with support from originating documents

which may include invoices, contracts, purchase orders, approval documents, budget

estimates, rule and regulations, directives and other relevant documents.

Coherent evidence requires explanations which are understandable to the

Commission and interveners, are in plain language where possible and consistent

such that similar circumstances or projects will have similar explanations or

inconsistencies explained.

Convincing evidence is defined as a factual background which explains “what,

where, when and how” events and issues arose, why cost overruns were incurred and

what information was known or ought to have been known at the time.83

95. The RPG provided an appendix to its main evidence that elaborated on the definition of

prudence as set out in various Commission decisions and civil court cases, the tests that it

proposed a TFO must satisfy in order to demonstrate prudence of incurred costs and

recommendations for AltaLink to address the RPG’s concerns. Specifically, the RPG expressed

concern that TFOs produced general documentation of expenditures, usually did not include

source documentation and provided insufficient explanations of cost overruns. The RPG

explained that a continuing concern in this proceeding and other complex rate proceedings was

the volume and relevance of documentation provided.84 In its view, relying on small or negative

variances from an original estimate, relying on AESO change orders without additional

information, relying on high level explanations to explain large variances from original estimates

and relying on a variance explanation to be addressed in a future proceeding (for example, where

only a portion of a project is proposed to be added to rate base in the current proceeding) were all

insufficient practices to demonstrate prudence.85

96. In its rebuttal evidence, AltaLink argued that the RPG’s proposed prudency test appears

“to set a standard of perfection that can never be met by any TFO or any regulated utility.”

AltaLink stated that a deferral account proceeding must examine after-the-fact costs in

recognition that project decisions are made in real time and those decisions must balance scope,

schedule and cost in light of the circumstances. The RPG’s suggestion that decisions must be

made to mitigate cost increases and defer and reduce the costs of the projects as much as possible

is not in line with the test of reasonableness to be applied in this proceeding.86

83

Exhibit 3585-X0666, PDF pages 11-12. 84

Exhibit 3585-X0666, PDF page 71. 85

Exhibit 3585-X0666, Appendix 1, PDF pages 73-74. 86

Exhibit 3585-X0704, PDF pages 24-25.


20 • Decision 3585-D03-2016 (June 6, 2016)

97. AltaLink also disputed the RPG’s assertion that insufficient source documentation was

provided and noted that it provided in excess of 70,000 pages of material on the public record

and 95,000 pages of material on the confidential record. AltaLink considered filing this volume

of material to be “unnecessary, unduly burdensome and inefficient”87 and submitted that the

RPG’s “inability to find evidence to substantiate its views of AltaLink’s performance is not

AltaLink failing to meet its onus [to demonstrate prudence].”88

98. The witnesses for AltaLink and the RPG agreed during questioning that it is solely the

Commission’s mandate to examine prudence (i.e., no other organisation or body has a mandate

to determine prudence for Alberta utilities)89 90 and that the onus is on the applicant to

demonstrate that costs were prudently incurred.91 92

99. During the hearing, Ms. Picard-Thompson, a witness for AltaLink, elaborated on the

definition of prudence stating:

…prudency is about reasonableness of the actions that we've taken, and that's clearly the

main component of executing in an imperfect world, is the reasonable and judgment you

use to make decisions.93

…

I think that we have provided a significant amount of data to demonstrate that we've

made reasonable decisions and that that, ultimately, is, for us, the definition of prudency,

sir, is that the things that we've done, as we've exercised good judgment at the moment

that the decisions had to be made, that they were reasonable decisions…94

100. AltaLink’s witness reiterated that the documents on the record of this proceeding

demonstrate that AltaLink gave consideration to numerous competing factors in executing

projects. The decisions made by AltaLink and contractors are recorded in a variety of different

documents,95 especially the monthly reports,96 which demonstrate the prudence of those

decisions.

101. In its argument, the RPG argued that AltaLink’s explanations and documentation were

insufficient to demonstrate prudency and that a voluminous record does not necessarily mean

that a TFO has discharged its onus.97

102. The RPG submitted that a recent SCC decision defines prudence as reasonableness: costs

and expenses must be wise and sound. That same SCC decision stated that the onus is on the

87



Transcript, Volume 1, page 187, line 8-10. 90

Transcript, Volume 9, page 1658, lines 8-11. 91





Transcript, Volume 2, pages 332-333, lines 23-25, 1-4 and 15-18. 96

Transcript, Volume 3, pages 428-429, lines 21-25 and 1-8. 97

Exhibit 3585-X0860, PDF page 24.


Decision 3585-D03-2016 (June 6, 2016) • 21

utility to establish that costs are prudent and the Commission is free to determine whether costs

are prudent (or reasonable).98

103. The RPG pointed to its evidence, which noted several instances where, in its view,

AltaLink had not provided sufficient explanations for cost overruns, which may indicate

potential imprudence and recommended that the Commission communicate clearly to AltaLink

its obligation to demonstrate prudence in the application, not in response to information requests

or during oral testimony.99

104. In argument, AltaLink submitted that the definition of prudence, or reasonableness, as

applied to a review of incurred costs is analogous to the business judgement rule applied in civil

courts:

The court looks to see that the directors made a reasonable decision not a perfect

decision. Provided the decision taken is within a range of reasonableness, the court ought

not to substitute its opinion for that of the board even though subsequent events may have

cast doubt on the board’s determination. As long as the directors have selected one of

several reasonable alternatives, deference is accorded to the board’s decision. This

formulation of deference to the decision of the Board is known as the “business judgment

rule.”100 [footnote removed]

105. In AltaLink’s view, there should be a reliance on management to make prudent decisions

and the Commission should very rarely, if ever, second guess those decisions and should

recognize that there is a range of acceptable decisions that can be made that result in acceptable

outcomes.101 AltaLink took exception to the RPG’s submission that AltaLink has failed to meet

the onus to demonstrate that costs under examination in this proceeding were prudently incurred.

AltaLink maintained that there is a “presumption of prudence” unless interveners can provide

evidence that shows imprudence. Despite the amendment to Section 46(1) of the Transmission

Regulation,102 which removed the presumption of prudence, AltaLink maintained that the

presumption of prudence existed in law prior to the amendment and is still applied by the

Commission since the amendments. AltaLink stated that the interveners have not provided any

evidence demonstrating that any of its incurred costs were imprudent.103

106. In its reply argument, the RPG asserted that in an absence of a presumption of prudence,

the onus and burden of demonstrating prudence is on AltaLink. Prudence is established using the

prudence test as set out in Decision 2013-358:104

In summary, a utility will be found prudent if it exercises good judgment and makes

decisions which are reasonable at the time they are made, based on information the owner

of the utility knew or ought to have known at the time the decision was made. In making

98





Alberta Regulation 86/2007, Transmission Regulation, Section 46(1). 103


Decision 2013-358: ATCO Electric Ltd., 2013-2014 Transmission General Tariff Application,

Proceeding 1989, Application 1608610-1, September 24, 2013, paragraph 393.


22 • Decision 3585-D03-2016 (June 6, 2016)

decisions, a utility must take into account the best interests of its customers, while still

being entitled to a fair return.105 [footnote removed]

107. The RPG objected to AltaLink’s comparison of the prudence test to the business

judgment rule, noting that the business judgment rule exists in common law to protect directors

from being found personally liable for losses resulting from their business decisions. In this case,

AltaLink’s directors are not personally responsible for any disallowances resulting from a

Commission decision; therefore, the business judgement rule is not applicable.106 Furthermore,

the business judgment rule is applied to the directors’ responsibility to the corporation, whereas

AltaLink has a responsibility to numerous stakeholders, including ratepayers.107

108. With respect to AltaLink’s argument that there must still be a presumption of prudence,

the RPG stated that legislation overrides common law, which, in this case, with the repeal of the

presumption of prudence, means that the Commission can make disallowances where it does not

find that AltaLink has provided sufficient evidence to demonstrate prudence.108

109. In AltaLink’s reply argument, AltaLink agreed that it bears the onus of proof in a

DACDA application, but continued to assert that it is entitled to have its costs presumed prudent

in the absence of any evidence to the contrary. AltaLink noted that it provided extensive

evidence, including purchase orders, contract detail reports, subcontract agreements, change

order logs, trade order logs, trade back charge logs, engineering analysis and transmission lines

costs, sworn testimony in addition to the minimum filing requirements, which showed what

AltaLink did, why it did it and the costs that resulted.109

Commission findings

110. The Commission previously defined the test for prudence or reasonableness of costs in

Decision 2001-110:110

In summary, a utility will be found prudent if it exercises good judgment and makes

decisions which are reasonable at the time they are made, based on information the owner

of the utility knew or ought to have known at the time the decision was made. In making

decisions, a utility must take into account the best interests of its customers, while still

being entitled to a fair return.111

111. The Electric Utilities Act states the following with respect to the burden of proof and the

considerations of the Commission when evaluating an application:

(2) When considering whether to approve a tariff application the Commission must

ensure that

105




Exhibit 3585-X0865, PDF pages 15 and 18. 109


Decision 2001-110: Methodology for Managing Gas Supply Portfolios and Determining Gas Cost Recovery

Rates Proceeding and Gas Rate Unbundling Proceeding, Part B-1: Deferred Gas Account Reconciliation for

ATCO Gas, December 13, 2001, 111

Decision 2001-110, page 10, Section 3.3


Decision 3585-D03-2016 (June 6, 2016) • 23

(a) the tariff is just and reasonable,

[…]

(4) The burden of proof to show that a tariff is just and reasonable is on the person

seeking approval of the tariff.112

112. Further, when Section 46(1) of the Transmission Regulation was amended, effective

July 25, 2013, the amendment removed the legislative presumption of prudence for project costs

incurred by the TFOs.113

113. This is the legislative and legal framework within which the Commission assesses

whether costs incurred by a TFO, in this case AltaLink, were prudent. The Commission does not

consider that there is any need to revisit or recast this traditional prudence test, by way of a wider

consultation with stakeholders, or otherwise.

114. Recently, the SCC, in two parallel decisions, one involving the Ontario Energy Board and

one involving this Commission provided guidance regarding the role of the tribunal in

determining prudence and the burden of proof. Justice Rothstein, writing for the court, in ATCO

Gas and Pipelines Ltd v. Alberta (Utilities Commission), commenting on the Alberta legislative

scheme, stated:

The prudence requirement is to be understood in the sense of the ordinary meaning of the

word: for the listed costs and expenses to warrant a reasonable opportunity of recovery,

they must be wise or sound; in other words, they must be reasonable. Nothing in the

ordinary meaning of the word “prudent” or the use of this word in the statute as a stand-

alone condition says anything about the time at which prudence must be evaluated. Thus,

neither the ordinary meaning of “prudent” nor the statutory language indicate that the

Commission is bound by the legislative provisions to apply a no-hindsight approach to

the costs at issue, nor is a presumption of prudence statutorily imposed in these

circumstances. In the context of utilities regulation, there is no difference between the

ordinary meaning of a “prudent” cost and a cost that could be said to be reasonable. It

would not be imprudent to incur a reasonable cost, nor would it be prudent to incur an

unreasonable cost. Further, the burden of establishing that the proposed tariffs are just

and reasonable falls on public utilities, which necessarily imposes on them the burden of

establishing that the costs are prudent.114

115. The burden of proof to establish prudence is on the applicant. The Commission has no

obligation to presume prudence when no evidence is provided to the contrary and must evaluate

all costs on the merits of the evidence (or lack of evidence) before it.

116. In a recent decision of the Ontario Energy Board (OEB), the OEB commented on the

burden of proof in the context of prudence reviews respecting this same presumption of prudence

argument stating:

112

Electric Utilities Act, Statues of Alberta 2003, Chapter E-5.1, Section 121. 113

Alberta Regulation 145/2013. 114

ATCO Gas and Pipelines Ltd and ATCO Electric Ltd. vs Alberta Utilities Commission and the Office of the

Utilities Consumer Advocate of Alberta, 2015 SCC 45, page 2.


24 • Decision 3585-D03-2016 (June 6, 2016)

Under section 36 of the OEB Act, all rates approved by the OEB must be just and

reasonable. In situations where the OEB determines that costs have been imprudently

incurred by a distributor, the OEB has a responsibility to disallow the recovery of those

costs from ratepayers. The OEB recognizes that it is conducting an “after the fact”

analysis of NRG’s actions. After the fact reviews are sometimes referred to as “prudence

reviews”; however the Supreme Court has recently confirmed that “prudence” in this

context has essentially the same meaning as “reasonable” as taken from the wording of

section 36 of the OEB Act.51 In making its decision, the OEB has considered only what

NRG knew, or reasonably ought to have known, at the time its gas procurement decisions

(or lack thereof) were made.

[…]

NRG also argued that the evidence it filed with regard to the prudence its gas supply

procurement during the 2013-2014 winter is uncontested. NRG noted that no party filed

evidence to the contrary nor did any party cross-examine on NRG’s evidence. NRG

argued that since no party cross examined NRG on its evidence, all of NRG’s evidence

must be accepted and that the prudence of NRG’s actions cannot be questioned.

The OEB does not agree. Prudence is not a “fact” that can be sworn to in an affidavit.

Prudence (or imprudence) is a conclusion arrived at after reviewing the facts. Clearly a

utility (or any party) cannot “prove” prudence simply by stating that it was prudent. It is

not the role of a party to a proceeding to determine prudence; it is the role of the OEB. As

described in detail above, the OEB reviewed the evidence in this proceeding and

determined that NRG did not act in a prudent manner.115 [emphasis added]

117. The Commission agrees with this view. The Commission must examine each project’s

costs with consideration to the decisions that were made by the applicant and parties it was

responsible for, directly or indirectly, given the information that was known or should have been

known at the time the decisions were being made. If there is insufficient information to

determine that the decision was reasonable, the Commission has the discretion to direct

disallowances.

4.1.6 Roles and responsibilities of the AESO, TFOs and Commission

118. In its main evidence, the RPG noted that while the AESO oversees the execution of direct

assign projects, the AESO’s oversight is subject to important limitations. In this regard, the RPG

noted that while the AESO may notify the Commission of any concern it has with respect to a

direct assign project cost, it is not required to do so. In addition, the RPG noted that, pursuant to

Section 41(2) of the Transmission Regulation, the Commission must not require the AESO to

make any statement with respect to a TFO’s prudence in incurring a cost.116

119. In its rebuttal evidence, AltaLink submitted that the RPG’s main evidence ignored the

breadth of its interactions with the AESO.117 Its interactions with the AESO were set out in detail

in its response to AML-CCA-2015-MAR05-024.118 In addition to ongoing meetings between

115

Ontario Energy Board, Decision and Order, EB-2014-0053, EB-2014-0361 and EB-2015-0044 dated

January 14, 2016 at PDF pages 21, 25 and 26. 116



Exhibit 3585-X0045, cited at paragraph 110 of Exhibit 3585-X0704.


Decision 3585-D03-2016 (June 6, 2016) • 25

AltaLink and the AESO at both the project management level and the executive level, AltaLink

fully complied with ISO Rule 9.1 reporting requirements.119 AltaLink also explained that both

AESO and AltaLink project managers communicate informally throughout a project’s life

cycle.120

120. AltaLink submitted that the RPG’s suggestions amount to an expectation that it should

take on the role of the AESO. However, AltaLink noted that the AESO, and not the TFOs, has

the responsibility to be the planner of the transmission system.121 Within this planning role, the

AESO defines the requirements for each project and sets the functional specification that is relied

upon for proposals to provide service prepared by the TFO. AltaLink noted that the AESO

directs the TFOs to file a facility application after it has approved the proposal to provide

service.122

121. In its argument, the RPG submitted that while it agrees with AltaLink’s observation that

the AESO is the system planner and has the authority to initiate direct assign projects, it is also

important to recognize that the AESO has no legislated responsibility to determine the prudence

of expenditures. There is a substantial difference between cost monitoring within the AESO’s

mandate, and testing the prudence of AltaLink’s costs. Specifically, the RPG submitted that

while the AESO monitors costs to insure its original plan for new facilities is still needed and

that the ISD remains appropriate, this is a far cry from testing the prudence of costs.123

Furthermore, the RPG submitted that while the AESO is responsible for compliance audits

pursuant to ISO Rule 9.1.5, the bar for compliance is low.124

122. The RPG also argued that any suggestion by AltaLink that it should be able to rely on the

finality of Commission facility decisions is absurd, since it would imply that any decision that

AltaLink makes with respect to engineering design, line optimization, or landowner

commitments, is prudent so long as a P&L has been obtained.125

123. The RPG further submitted that it would not be appropriate to turn every facility

proceeding into a DACDA style proceeding with respect to every decision made by the TFO

prior to issuance of P&L. In this regard, the RPG submitted that while it appreciates that

interveners with rate concerns can participate in facility proceedings, interveners concerned with

rate effects may not have sufficient resources to participate. In addition, to the extent the current

DACDA application is dealing with 2012 and 2013 direct assign projects, it should be noted that

these projects were completed prior to the issuance of Decision 2014-283.126

124. In argument, AltaLink submitted that because the Commission has addressed roles and

responsibilities of the AESO, TFOs, and the Commission several times, the Commission should

reject repetitive argument that blurs these roles and causes irrelevant matters to be considered in

119

Exhibit 3585-X0704, paragraphs 112-113. 120









26 • Decision 3585-D03-2016 (June 6, 2016)

a DACDA proceeding.127 AltaLink noted that the roles of the AESO and the TFOs were most

recently addressed in the Commission’s decision on the Southwest 240-kV project audit.128

125. AltaLink noted that the AESO, and not AltaLink, has the responsibility under the Electric

Utilities Act to ensure the safe, reliable and economic operation of the AEIS, and has the

authority to assess need and make arrangements for enhancements to the transmission system.129

The AESO provides the functional specifications that AltaLink relies on to prepare its PPS, and

then the AESO directs the filing of a facility application after it has approved the PPS.130 In any

event, AltaLink submitted that it has neither the information nor the resources to plan the electric

system.131

126. In addition, AltaLink noted that the Commission made the following finding in Decision

2044-D01-2016:132

It is clear that the AESO does not have a mandate to assess the prudence of project costs.

This mandate falls squarely within the Commission’s statutory authority to set just and

reasonable rates. However, on a practical level, the Commission recognizes that, at key

points in the cycle of project development and execution, major decisions by the AESO

and TFO, and the cost consequences of these decisions, may become irreversible.

Consequently, given the planning mandate of the AESO and its involvement with the

TFO during the facility process from needs identification document (NID) through to

energization, it follows that decisions made and actions taken by the AESO will have a

bearing – and, quite possibly, a very significant bearing – on the Commission’s

assessment of the prudence of the TFO’s execution of a project.133

127. AltaLink submitted that the Southwest 240-kV project audit decision also reflected the

fact that, with very limited exceptions, TFO’s are required to comply with AESO directions.134

AltaLink submitted that evidence within this proceeding has overwhelmingly demonstrated that

AltaLink met all of its reporting requirements and kept the AESO informed on the issues it

addressed for all projects.135

128. In its argument, ATCO submitted that interveners continue to misstate and misinterpret

the roles and responsibilities of the AESO, TFOs and Commission in the current proceeding. In

particular, ATCO submitted that the CCA and the RPG have deliberately blurred the lines of

authority and applicable statutory requirements in order to advance their cases.136 These

interpretations have been previously presented in other proceedings and rejected by the

Commission.137

127






Decision 2044-D01-2016: AltaLink Management Ltd., 2010-2011 Direct Assign Capital Deferral Account,

Audit of Southwest Transmission Project, Proceeding 2044, Application 1608711-1, January 20, 2016. 133

Decision 2044-D01-2016, paragraph 17, referenced at Exhibit 3585-X0859, paragraph 84. 134

Exhibit 3585-X0859, paragraphs 86-87, referencing paragraphs 114-115 of Decision 2044-D01-2016. 135



Exhibit 3585-X0857, paragraph 5, citing Decision 2014-283, paragraphs 323 to 332.


Decision 3585-D03-2016 (June 6, 2016) • 27

129. In its reply, the RPG noted that there is broad agreement amongst the parties in the

current proceeding that:

The AESO plays the role of system planner.

TFO are required to follow ISO rules.

The AESO is not responsible for determining prudence.138

130. However, the RPG submitted that following AESO mandated rules and maintaining

communication with the AESO on project developments does not provide visibility into whether

costs were prudently incurred. If it did, a DACDA application proceeding would not be

required.139

131. The RPG submitted that while AltaLink routinely points to the obligations of the AESO

within the legislative framework, it is important to note that TFOs must also comply with

sections 39(1) and 39(2) of the Electric Utilities Act, as set out below:140

39(1) Each owner of a transmission facility must operate and maintain the transmission

facility in a manner that is consistent with the safe, reliable and economic operation of the

interconnected electric system.

39(2) Each owner of a transmission facility must, in a timely manner, assist the

Independent System Operator in any manner to enable the Independent System Operator

to carry out its duties, responsibilities and functions. [Emphasis added by the RPG]

132. Having regard for Section 39(1), the RPG submitted that AltaLink cannot operate and

maintain transmission facilities in a manner consistent with safe, reliable and economic operation

of the AIES if its direct assign projects are not the product of prudent decision making.141 In

addition, having regard for Section 39(2) of the Electric Utilities Act, the RPG submitted that

AltaLink is not fulfilling its duty to assist the AESO in the provision of safe, reliable and

economic operation of the AIES if it withholds information about opportunities to save costs of

which it is aware.142 Accordingly, the RPG submitted that it is clear from Section 39 of the

Electric Utilities Act that the responsibilities of the AESO and TFOs to ensure the economic

operation of the AIES necessarily overlap. This reflects the fact that the AIES exists to serve the

needs of customers, not the interests of AltaLink or the AESO.143

133. The RPG also disagreed with ATCO’s suggestion that the functional specification comes

from the AESO with no advice from a TFO. In reality, the RPG asserted that functional

specification revisions go back and forth between the AESO and the TFOs. Several projects

included in the DACDA application had multiple revisions in their functional specifications.144

As such, the RPG submitted that a TFO that is concerned about capital costs has multiple

opportunities to advise the AESO regarding changes to its functional specifications, and has an

138









28 • Decision 3585-D03-2016 (June 6, 2016)

obligation to pursue such opportunities as part of its duty to demonstrate that it acted

prudently.145

134. The RPG also submitted that the Commission is not in a position to determine, at the

facilities stage, that a particular tower design is prudent. The RPG argued that expecting the

Commission to make such determinations at the facility application stage would turn every

facility application into a DACDA application proceeding and even if interveners had both the

permission and resources to participate in facility proceedings, this sort of participation in facility

proceedings would be highly inefficient.146

135. In reply, AltaLink submitted that while the RPG downplays the scope of the AESO’s cost

monitoring function, it is notable that in its decision on the Southwest 240-kV project audit, the

Commission stated that the AESO’s actions can have a significant bearing on the Commission’s

assessment of prudence.147 AltaLink submitted that, as was the case in the Southwest 240-kV

project audit proceeding, the AESO was informed about major developments throughout the

execution phase for projects under consideration in the current proceeding.148

136. Responding to the RPG’s suggestion that AltaLink should not be able to rely on the

finality of facility application decisions, AltaLink submitted that after the Commission’s ruling

in a facility application proceeding, AltaLink is obligated to build the facilities approved.

Conversely, AltaLink submitted that the RPG’s position would turn DACDA proceedings into a

ground-up reconstruction of every prior regulatory proceeding until project close out.149

137. In its reply, ATCO submitted that the RPG continues to confuse the respective roles of

the Commission, the AESO, and the TFOs as they exist in Alberta. In particular, ATCO

submitted that the RPG holds a distorted view of the framework that challenges the AESO’s

planning and cost approval role and the Commission’s facility approval process.150 ATCO

submitted that it is not “absurd” for a TFO to comply with the Commission’s facilities approvals

and permits and licenses. To the contrary, the TFO is required to comply, and must govern itself

accordingly.151 Rather than focusing on the individual projects filed by the TFO, the RPG instead

improperly turns each DACDA application proceeding into a repeated policy debate. ATCO

asserted that each of the RPG’s arguments, proposals and recommendations that were previously

rejected by the Commission in Decision 2014-283 must also be rejected in the current

proceeding, since they have no foundation in law, regulatory compact principles, or established

Alberta regulatory practice.152

Commission findings

138. The respective responsibilities of the AESO and TFOs in the planning and execution of

direct assigned capital projects has been set out by the Commission in numerous decisions, the

most recent of which was Decision 2044-D01-2016. In that decision, the Commission referred to

145



Exhibit 3585-X0863, paragraph 111, referencing Decision 2044-D01-2016 at paragraph 17. 148







Decision 3585-D03-2016 (June 6, 2016) • 29

its findings in Decision 2013-407 in which it provided an overview of the legislative scheme as it

relates to the establishment of TFO rates, the prudence test to be applied and the role of the

AESO in this process, and concluded that:

17. It is clear that the AESO does not have a mandate to assess the prudence of project

costs. This mandate falls squarely within the Commission’s statutory authority to set just

and reasonable rates. However, on a practical level, the Commission recognizes that, at

key points in the cycle of project development and execution, major decisions by the

AESO and TFO, and the cost consequences of these decisions, may become irreversible.

Consequently, given the planning mandate of the AESO and its involvement with the

TFO during the facility process from needs identification document (NID) through to

energization, it follows that decisions made and actions taken by the AESO will have a

bearing – and, quite possibly, a very significant bearing – on the Commission’s

assessment of the prudence of the TFO’s execution of a project.

139. It has been suggested that, because Section 25(5) of the Transmission Regulation,

restricts the Commission from requiring the AESO to comment on a TFO’s prudence in

managing a transmission project, it then follows that the AESO’s failure to comment results in a

de facto determination of prudence. The Commission does not agree. Although the Commission

cannot compel the AESO to comment, the AESO is not precluded from doing so because

Section 25(5) of the Transmission Regulation also expressly provides the AESO with a choice to

comment. Because the AESO’s role in commenting on project costs is voluntary, the

Commission does not draw any conclusions regarding the AESO’s consideration of project costs

from the fact that the AESO did not provide any notification of concern or issue to the

Commission respecting the costs for any of the projects in this proceeding.

140. In its argument and reply submissions, AltaLink referenced the Commission’s findings in

Decision 2044-D01-2016, and in several instances replicated Commission findings in that

decision, which referenced documentation that AltaLink had provided to the AESO in change

proposals or monthly project reports. The Commission wishes to be clear that its prudence

findings in that decision reflected the specific facts and circumstances of that project’s execution.

In that decision, the Commission assigned significant weight to the evidence regarding the

ongoing reporting between the AESO and AltaLink through monthly reports because the ISD

target that the AESO clearly hoped to achieve was never changed by the AESO in the subsequent

months and years despite ongoing reporting and discussions with the AESO as to blockades and

other disruptions that were affecting the execution schedule. The Commission’s findings in

Decision 2044-D01-2016 do not establish a precedent or principle that the act of providing

monthly reports can, of itself, demonstrate prudence.

141. With respect to the submission of the RPG regarding the TFO’s obligations under

Section 39 of the Electric Utilities Act, the Commission agrees that inherent in the TFO’s duty

under Section 39(1) of the Electric Utilities Act to provide safe, reliable and economic operation

of the AIES is the TFO’s duty to make prudent decisions. The Commission also recognizes that

the obligation to assist the AESO under Section 39(2) of the Electric Utilities Act is an obligation

to “assist the AESO in any manner “to enable the AESO to carry out its duties. Recognizing that

the AESO has the statutory responsibility to plan the transmission system and determine what

facilities are necessary and when they will be required, a TFO must assist the AESO by

providing information, such as cost implications of viable alternatives or trade-offs between

costs and ISD targets for consideration by the AESO. That is, the TFO’s responsibility is an

active one and if evidence demonstrates that a TFO failed to provide this assistance, the TFO


30 • Decision 3585-D03-2016 (June 6, 2016)

could not simply rely on the AESO’s decisions as justification for pursuing a course of action

and incurring the resultant costs of doing so.

142. With respect to functional specifications of direct assign projects, the Commission

understands that functional specifications are generally the product of extensive interaction

between the TFO and the AESO. However, as the Commission found in Decision 2014-283, the

AESO, in its role as system planner, sets the functional specifications for direct assign projects

and once set, the TFO is required to reflect the AESO’s functional specification in the

development of its proposal to provide service and subsequent project development steps.153

143. With respect to the assertion from the RPG that the Commission is not in a position at the

facility application stage to make rulings on design decisions, it should be noted that, in Decision

2014-283, in respect of the 2012 DACDA application of ATCO Electric, the Commission found

that:

188 …at key points in the cycle of project development and execution, major

decisions of the AESO and the TFO become irreversible. Consequently, given the

planning mandate of the AESO and its involvement with the TFOs during the facility

process from NID through to energization, the actions of the AESO must have a

bearing on the Commission’s assessment of the prudence of ATCO’s execution of the

project.

… 190. In the previous section, the Commission indicated that, on a practical level,

decisions made at key points in the cycle of a project’s development and execution, such

as the design and functional specifications approved as part of facility applications,

impact subsequent decisions in the execution of that project and can become irreversible.

As such, the Commission intends to review the cost-related evidence and consider cost-

related issues in facilities proceedings, and considers that participation by interveners

who are focussed primarily on issues of cost and design, should be permitted in facility

proceedings.

144. The Commission considers the above finding to be equally applicable to the AltaLink

direct assigned projects included in the current application. Because many key decisions become

irreversible after the facility application decision has been issued, facility applications are the

venue in which design-related issues should be addressed. For example, in the Heartland facility

proceeding, design-related issues regarding the use of monopole structures for a portion of the

Heartland project were extensively examined and as a consequence of that proceeding, the

Commission directed the use of monopoles for a portion of that line. Once a facility application

is approved and the associated P&L has been issued, then design decisions are set unless

intervening circumstances subsequently arise.

4.1.7 In-service date targets

145. In its main evidence, the RPG submitted that the onus is on AltaLink to do all within its

ability to defer or reduce the costs of projects, including having serious discussions with the

AESO about:

153

Decision 2014-283 at paragraphs 233-238.


Decision 3585-D03-2016 (June 6, 2016) • 31

ISD targets154

project scope

exemptions from ISO standards

the need to revise unnecessary functional specifications155

146. The RPG submitted that the current build-up of the transmission system should not be

treated as an opportunity to build at any cost. Instead, the RPG submitted that, in addition to

having serious discussions with the AESO about ISD targets, the RPG expected AltaLink to

monitor ISDs constantly to ensure that no opportunity is missed to defer work and take pressure

off the strained labour markets for transmission construction.156

147. In its rebuttal evidence, AltaLink confirmed it has had “serious discussion with the AESO

about ISDs.”157 AltaLink noted that the AESO has practices and processes in place to determine

ISDs within a two- to five-year time horizon, which considers multiple factors, such as:

Potential extensions or advancements of the planned need date.

Extensions or advancements arising from customer requested ISD changes.

Increased congestion on the transmission system.

Mitigation plans to address system performance criteria violations.158

148. AltaLink submitted that it is incorrect for the RPG to suggest that it must do all it can

within its ability to mitigate cost increases, including deferring projects through ISD changes.

AltaLink asserted that the RPG has misapplied the established DACDA proceeding test to do

“what is reasonable within the industry framework.”159

149. In its argument, the RPG noted that in Decision 2013-407 in respect of AltaLink’s 2013-

2014 GTA, the Commission was critical of the efforts of AltaLink and the AESO to achieve

targeted ISDs “at virtually any cost” without regard to the cost consequences of aggressive

schedules.160 These concerns led the Commission to prescribe Directive 24 from Decision 2013-

407, which required AltaLink to request the AESO to review the ISD targets for projects

included in its 2013-2014 GTA direct assign projects forecasts and to provide the results of such

consultations in AltaLink’s refiling application.161

150. The RPG stated that in its finding in respect of Directive 24, the Commission clarified

that the intention of the directive was to determine what, if any, cost mitigation opportunities

might be available from the deferral of projects. In addition, the RPG noted that the Commission

indicated that pursuing cost mitigation by investigating opportunities to defer ISD targets

remained a significant concern.162

154



Exhibit 3585-X0666, paragraph 35 157




Exhibit 3585-X0860, paragraph 133, referencing Decision 2013-407, paragraph 440. 161

Exhibit 3585-X0860, paragraph 134, referencing Decision 2013-407, paragraph 382. 162

Exhibit 3585-X0860, paragraph 135, referencing Decision 2014-258, paragraph 57.


32 • Decision 3585-D03-2016 (June 6, 2016)

151. The RPG also submitted that, while the AESO is responsible for setting ISD targets,

AltaLink could have contributed to the setting of more realistic ISD targets by taking advantage

of its knowledge of:

flows on its transmission lines

line capacities

customer activity163

152. While recognizing the formal legislated role of the AESO to determine ISD targets, the

RPG stated that there are opportunities for AltaLink to work with the AESO by communicating

the cost consequences of the AESO not moving an ISD target to a later time and submitted also

that the CB project represented a prime example of a missed opportunity to reduce cost.164

153. In argument, AltaLink submitted that the obligation of the TFO with respect to ISDs is to

make commercially reasonable efforts to meet the ISD target and to keep the AESO informed of

developments that may affect the ISD target.165

154. AltaLink submitted that the AESO has the practices and processes required to consider

ISD targets, and noted that the AESO considers multiple factors when determining ISD targets,

including:

customer connection requests

customer driven changes to connection requests

changes in load growth forecasts

changes to forecast generation dispatch patterns

changes to transmission development timelines166

155. AltaLink submitted that, consistent with its obligation to meet the ISD target set by the

AESO, it works with the AESO on many matters, including cost, to meet the forecast or

expected ISD targets. However, due to the high level of transmission construction activity across

North America, there would not have been an optimal period to delay work to, since further

delaying projects would only have pushed work into periods of time that also experienced

constrained construction markets.167

156. In reply, the RPG submitted that during the oral hearing, its witness, Mr. Levson, agreed

in principle that the AESO is supposed to set ISD targets, but that this does not occur all of the

time. In particular, Mr. Levson noted that for one of the largest transmission projects in Alberta,

the Eastern Alberta Transmission Line (EATL) project, the ISD target was indicated as “TBD”

(to be determined) because ATCO did not provide a date.168 Accordingly, despite the general

agreement among the parties that the AESO has the ultimate responsibility to set ISD targets, the

reality is that the determination of the targets does not occur in a “black and white manner.”169

163

Exhibit 3585-X0860, paragraph 137, referencing Exhibit 3585-X0689, CCA-AUC-2015SEP24-011(a). 164








Decision 3585-D03-2016 (June 6, 2016) • 33

The simple reason for this is that the AESO cannot set ISD targets in isolation from the TFO that

needs to be committed to delivering the project by a promised date.170

157. The RPG submitted that, as the matter at hand in the current proceeding is to determine

whether costs incurred to meet a targeted ISD are the result of prudent decisions, it is the

obligation of the applicant TFO in a DACDA proceeding to provide clear and specific evidence

of the options its explored, and the costs and benefits of either extending or advancing ISD date

targets.171

158. In response to AltaLink’s claim that further delay of projects would only have pushed

work into similarly constrained markets for construction materials and labour, the RPG

submitted that AltaLink produced no evidence that the market for transmission line suppliers

would have been as heated in 2016 as it was in the period from 2012 to 2014. As such, the RPG

submitted that AltaLink’s suggestion that market conditions would have been similar if the

completion of its projects were to have been pushed into a later period is pure speculation.172

159. The RPG submitted that as the big build is now largely over, the CB project provides a

clear counter example to the proposition that a later ISD would have experienced similar market

conditions with respect to inputs. In that case, AltaLink continued with both the CB and the

Bowmanton to Whitla lines, despite the loss of the main anchor load before construction

began.173

160. In reply, AltaLink submitted that the RPG’s argument referencing findings in Decision

2013-407 that AltaLink has not met its obligation to seek opportunities to reduce costs by

deferring ISD targets again ignores the evidence in the current proceeding about the extensive

and on-going interaction between AltaLink and the AESO.174

Commission findings

161. In Decision 2044-D01-2016, the Commission commented on the respective

responsibilities of the AESO and a TFO to establish ISDs:

113. During the oral hearing, Commission counsel questioned the Midgard witness

regarding his understanding of who was responsible for establishing the ISD for this

project. The exchange was as follows:

In your view, who do you consider to be establishing the ISD?

A. We would have assumed the AESO would have established the ISD. They

assign the PPS.

Q. Do you make a distinction between planning to achieve an ISD and

determining the ISD then?

A. The ISD, I would call the determination of ISD is the instructions that are

given. Here's your project, here's your ISD. I'm not sure if that's a proper legal

term for it, but...

Q. And I'm not asking you for legal opinions.

170





Exhibit 3585-X0863, paragraph 118, citing several Proceeding 3585 exhibits.


34 • Decision 3585-D03-2016 (June 6, 2016)

A. No.

Q. I'm trying to reconcile these two statements. The one statement saying that

AltaLink planned to achieve a project ISD and the other statement that talks

about how the ISD seems to have been determined from the top down -- from

load customers rather than from a construction, this is what it's going to take to

build this.

So I'm trying to understand your view of where the responsibility lies?

A. Well, we consider TFOs to be responsible entities. In other words, if a TFO is

asked to bring the moon down to earth, they should say, no, that won't be

possible, we couldn't do that.

So if a TFO is given an in-service date that's not physically achievable, there's

sort of an onus to say we can try for best earliest, we can -- within these

constraints we will attempt to achieve that, but you must know going in -- and

I've had these discussions with clients -- it's not professionally responsible not to

say, what you're asking is impossible, it can't happen.

I've had to give bad news to clients this way.

114. The Commission agrees that, for projects that are assigned to a TFO by the

AESO, the TFO has a responsibility to ensure that the AESO is kept informed of issues

that are likely to affect the siting, timing and cost of those projects materially, as the TFO

becomes aware of them. This includes providing the AESO with its own assessment of

the feasibility of meeting an AESO-requested ISD as soon as reasonably possible after

the AESO first advises the TFO of the proposed ISD. When issuing a direction to proceed

with a project, the AESO is entrusting the completion of the project to the TFO on time

and in accordance with the TFO’s PPS. Accordingly, the Commission does not consider

it unreasonable to hold the TFO responsible for ensuring that the AESO is informed on a

timely basis of any issue that is likely to jeopardize, in any material way, the timing,

routing or estimated cost of a project that the TFO has been assigned.

115. However, the Commission does not consider this obligation to be without limits.

The Commission considers the AESO to be a sophisticated party with experience and

knowledge of the issues that can arise in the siting and construction of a transmission

project. It is the Alberta system planner. Moreover, the legislative scheme requires the

TFO to comply with the direction of the AESO unless doing so would put its facilities or

the safety of the TFO’s employees or the public at risk.

162. The Commission’s findings with respect to the responsibilities of the AESO and AltaLink

to establish ISD targets in Decision 2044-D01-2016 are equally applicable to the projects in this

proceeding.

163. The RPG has questioned whether AltaLink explored options with the AESO to extend

ISDs or take other steps to defer completion of projects given the heated market for construction

labour and materials.

164. The Commission accepts the evidence of AltaLink that throughout 2012 to 2014, the

market for transmission project labour and materials reflected a large demand and limited supply

and therefore, for the projects included in this DACDA application, if a significant number of

these projects were to have been targeted early in their lifecycles for completion at a later time, it

is reasonable to expect that the time period that these projects would have been shifted to would

also have experienced resource constraints.


Decision 3585-D03-2016 (June 6, 2016) • 35

165. The Commission also accepts the evidence of AltaLink that it had discussions with the

AESO regarding both the establishment and the requirement to continue to meet the ISDs targets

set by the AESO. As further discussed in Section 4.1.11, the AESO, as the system planner,

would, therefore, be well aware of the demands in the market as it was directing these

transmission capital projects to be built, not just by AltaLink but by all of the TFOs in the

province. It could have directed AltaLink to slow down its capital program, but did not do so. In

these circumstances, the Commission does not find that AltaLink failed to act prudently in the

execution of its projects by failing to seek opportunities to defer ISD targets.

166. The RPG has also asserted that AltaLink failed to provide evidence that 2016 would have

been a heated market in response to its proposal that the ISDs could have been moved to this

period. The Commission accepts the evidence of AltaLink that the period for which the AESO

would have considered moving projects would have been restricted to one or two years. As such,

it was reasonable for AltaLink not to provide this evidence. Further, at the time a discussion with

the AESO regarding ISDs would have taken place, it would have been reasonable for all parties

to assume that for subsequent years the market would continue to be heated. The collapse of the

oil prices did not happen until late 2014 or early 2015.

167. The Commission discusses the relationship between ISD targets and the prudence of

AltaLink’s expenditures on the CB project separately, in Section 4.2.1.4 below.

4.1.8 Timing of DACDA and general tariff applications

168. In Decision 2013-407, which considered both AltaLink’s GTA for 2013-2014 and an

application for the approval of the reconciliation of certain deferral accounts, including

AltaLink’s DACDA for the years 2010-2011, the Commission made the following finding:

1363. Finally, in Section 6.1.1 of the decision, the Commission addressed concerns

raised by AltaLink regarding the scope of this proceeding and determined that the broad

scope of matters addressed within this proceeding also reflects AltaLink’s decision to

include, for the first time, a DACDA application with its GTA. As well, throughout this

decision, the Commission has endeavored to provide direction to both AltaLink and

stakeholders regarding the issues that it will be considering in future DACDA

proceedings. The complexity of issues and the size of the capital projects that will be

submitted for cost approval in future DACDA proceedings dictates that future DACDA

filings be made on a stand-alone basis and not as part of a GTA. Consequently, the

Commission directs AltaLink to file all future DACDA applications as separate stand-

alone proceedings.175

169. AltaLink filed its 2015-2016 GTA application on November 19, 2014. AltaLink filed the

current application in respect of the reconciliation of 2012 and 2013 deferral accounts, 28 days

later, on December 17, 2014.

170. The Commission is concerned about the timing of these applications given its direction

and during the oral hearing, the Commission questioned parties regarding measures that could be

considered to improve the efficiency of future DACDA proceedings. AltaLink provided its views

175

Decision 2013-407, paragraph 1363, also set out as Decision 2013-407, Directive 46.


36 • Decision 3585-D03-2016 (June 6, 2016)

in the hearing176 and on February 2, 2016, the RPG provided an undertaking response177 in

response to the question.

171. In its undertaking response on this issue,178 the RPG continued to support the idea of

splitting the GTAs from the deferral account applications, but recommended that there be a

minimum of six months between the application processes, regardless of when they are filed.179

In addition, the RPG recommended that, due to the similarity of issues, the GTAs of the two

largest TFOs (ATCO and AltaLink) and the deferral account applications of the two largest

TFOs should be scheduled to fall within six months of each other. However, the RPG submitted

that if the Commission accepts the 2017 test year as part of ATCO’s current GTA, and if both

ATCO and AltaLink file future GTAs on a two-year test period basis, then the GTAs of ATCO

and AltaLink will be in different years, thereby assisting to even out the workload.180

172. With respect to the question posed by Commission counsel regarding the priority in

scheduling for DACDA applications versus GTAs, the RPG explained that GTAs have an

immediate effect on customer rates, while DACDA applications, because they rely on actual

costs, not forecast costs, are able to lag behind GTAs.181 Given this, the RPG recommended that

GTAs should have a higher priority than DACDAs for scheduling purposes.182

173. Finally, the RPG explained in its undertaking response that thorough reviews of DACDA

applications may be unachievable if TFOs continue to be permitted to provide limited

information and intervener resources remain constrained. The RPG submitted that, as a practical

matter, unless the Commission allows for greater intervener funding, and increases the filing

requirements for DACDAs, significant portions of DACDA applications will go un-reviewed.

Accordingly, unless these concerns are addressed, the goal of achieving greater participation by

having DACDA applications be more “bite sized” may be frustrated.183

174. In argument, AltaLink commented on the undertaking response prepared by the RPG.

AltaLink submitted that as the scope and legal tests for a DACDA application and GTA are

different, regulatory efficiency can be improved by ensuring that the scope of each type of

proceeding is limited to the nature of that proceeding.184

175. AltaLink submitted that as it has concerns about the regulatory lags that exist with respect

to DACDA applications, GTAs and generic cost of capital applications, it opposed any process

that would result in delays in filing applications. AltaLink submitted that while many factors

may be the cause of the regulatory lags that have occurred, the only way to reduce lag is to file

applications on a timely basis so that timely decisions can be made.185 In this regard, AltaLink

176

Transcript, Volume 6, pages 1244-1246. 177

Exhibit 3585-X0847. 178



Exhibit 3585-X0860, paragraph 181, citing Exhibit 3585-X0847, PDF page 1. 181







Decision 3585-D03-2016 (June 6, 2016) • 37

noted that it made it clear during the oral hearing that it intends to file its DACDA application for

2014 and 2015 in either June or July of 2016.186

176. AltaLink submitted that directing audits, proposals to split applications into smaller

pieces, or proposals to file GTAs and DACDAs in alternate years would drastically extend the

time required to settle deferral accounts. AltaLink supported other steps to improve the

efficiency of DACDA proceedings processes including the use of a written process, as allowed

for in a recent ATCO deferral account application, and by defining the scope of materially

relevant documentation at the outset of the process, rather than defining scope through

motions.187

177. In its argument, the RPG submitted that it understood that the Commission directed

AltaLink to split the deferral account applications from the GTAs in order to provide some

schedule relief. However, in practice, AltaLink’s 2015-2016 GTA and the current deferral

accounts application were filed sufficiently close together to be, effectively, running on a parallel

track.188 As a result, the RPG noted that any schedule relief benefits from filing the deferral

accounts application and GTA separately were limited.

178. The RPG noted that a potential concern arising from deferred DACDA applications is

that, if a TFO owes a significant refund to customers, it may be motivated to postpone DACDA

applications for too great a period. However, the RPG submitted that this concern could be

addressed by requiring TFOs to disclose the amount of the refund or charge associated with a

DACDA that has not yet been filed. If such information were to be provided, the RPG submitted

that customers could bring forward a motion to have the TFO file a DACDA application within a

reasonable time.189

179. In reply, AltaLink submitted that the harm created by the unprecedented disallowances

sought by interveners has been compounded by additional regulatory lag.190 It agreed that certain

steps are required to improve the current regulatory process and submitted that the goal of

improved regulatory efficiency is supported by limiting the scope of each type of proceeding to

reflect the nature of the application under consideration.191

180. AltaLink submitted that in addition to supporting the use of a written process for

DACDA applications, as was recently done for ATCO’s deferral account application,192 the

scope of materially relevant documentation should be determined at the outset of the process.

Under this proposal, AltaLink stated that once the scope is set, information outside that scope

would not be required to be produced unless the Commission overturns its decision on scope.

AltaLink submitted that the adoption of this recommendation would allow for more concise

filings and more productive oral hearings, if an oral hearing is required.193

186

Transcript, Volume 6, page 1246, referenced at Exhibit 3585-X0859, paragraph 115. 187






Exhibit 21206-X0145. 193



38 • Decision 3585-D03-2016 (June 6, 2016)

Commission findings

181. The Commission’s finding and Directive 46 as set out at paragraph 1363 of Decision

2013-407 reflected the Commission’s concern that AltaLink GTAs typically contain a large

volume of evidence and highly complex matters to assess and, considering the issues that would

be examined in future DACDA proceedings, that it would be unreasonable to consider the GTA

and DACDA in the same proceeding.

182. The Commission finds that AltaLink, in filing its 2012-2013 DACDA application which

requested the approval of 103 capital projects, including Heartland, within 28 days of filing its

2015-2016 GTA, which requested revenue requirement approval for the years 2015 and 2016 in

the amounts of $810.5 million and $1,001.6 million, respectively, complied with the letter but

not with the spirit of Directive 46 from Decision 2013-407.

183. The Commission agrees with the submission of the RPG that as compared to GTAs, the

time sensitivity of DACDA decisions is less because DACDA applications only reflect the

differences between the revenue requirement already in effect and the actual prudent additions.

The Commission acknowledges AltaLink’s view that delays in the issuance of DACDA

decisions prolong the period over which rating agencies may perceive that AltaLink is subject to

disallowance risk; however, there is no evidence to suggest that any period of delay would result

in a financing action taken by a rating agency. Rather, the evidence suggests that it would be a

disallowance that is perceived to be unexplained or unsupported by the regulator that would

cause a rating agency to be concerned about the supportive regulatory environment in Alberta.

184. As a consequence of AltaLink’s past actions, the Commission has been more prescriptive

in its directions with respect to the future timing of AltaLink DACDA applications in relation to

GTAs.

185. Pursuant to Section 23(1) of the Alberta Utilities Commission Act, the Commission may

order any person:

(a) to do any act, matter or thing, forthwith or within or at a specified time and in any

manner directed by the Commission, that the person is or may be required to do

under this Act or any other enactment or pursuant to any decision, order or rule of the

Commission,

(b) to cease doing any act, matter or thing, forthwith or within or at a specified time, that

is in contravention of this Act or any other enactment or any decision, order or rule of the

Commission,

186. AltaLink is a person as that term is defined in subsection1(1)(kk) the Electric Utilities Act

and under Section 119 of this act, it must prepare a tariff for approval by the Commission.

187. Further to the above, the Commission directs AltaLink to ensure that there is no less than

six months separation between the filing of its GTA and its DACDA applications.


Decision 3585-D03-2016 (June 6, 2016) • 39

188. AltaLink filed its 2017-2018 GTA on February 16, 2016, almost three months before the

Commission issued Decision 3524-D01-2016.194 The Commission assigned Proceeding 21341 to

this application and following the close of registration for interested parties, issued a letter

suspending further processing of that application until after the release of Decision 3524-D01-

2016. Decision 3524-D01-2016 which was issued May 9, 2016, included several findings that

required adjustments to AltaLink’s 2017-2018 GTA application. Consequently, AltaLink may

not file its next DACDA application until at least six months have elapsed from the date that

AltaLink files changes or updates to its 2017-2018 GTA and the Commission has advised that

Proceeding 21341 has resumed.

189. In this proceeding, AltaLink stated its intention to file a combined DACDA application

for the years 2014 and 2015 as early as June 2016.195 Apart from the above direction regarding

the timing for filing its next DACDA vis-a-vis the filing of its next GTA, the Commission was

also concerned about the scope of this next DACDA. During the oral hearing, AltaLink’s

witnesses were asked to comment on a Commission cross examination aid prepared from an

exhibit filed by AltaLink within its 2015-2016 GTA proceeding that outlined the specific

projects that AltaLink forecast for completion and addition to rate base in each of the years 2014

and 2015.196 Based on this examination, the Commission finds that due to the number of large

projects and the very high overall dollar value of the projects that AltaLink is requesting to add

to rate base in 2015, the examination of both 2014 and 2015 projects in a single proceeding

would be unduly burdensome and administratively unfair. Therefore, the Commission directs

AltaLink to file its 2014 and 2015 DACDA applications separately and in full accordance with

additional time restrictions set out above.

190. As noted in Section 4.1.8 below, the Commission has directed AltaLink to undertake

consultations with intervener groups that have been active in DACDA application proceedings

for the purposes of examining proposals designed to limit the size of the record and promote the

efficiency of future DACDA proceedings. The Commission expects that this consultation

process will take time. Because there are a smaller number of projects expected for 2014,

AltaLink is not required to wait for the conclusion of these discussions before filing its 2014

DACDA so long as it complies with the Commission’s minimum six months separation between

the filing of its 2017-2018 GTA and its 2014 DACDA application. The Commission expects that

AltaLink’s 2015 DACDA will follow the outcome of the consultation process and any

procedural Commission direction resulting from the conclusion of that process.

4.1.9 Filing requirements

191. In Bulletin 2006-25,197 the Alberta Energy and Utilities Board (EUB or board) established

the form and content of consensus Uniform System of Accounts (USA) and Minimum Filing

194

Decision 3524-D01-2016: AltaLink Management Ltd., 2015-2016 General Tariff Application, Proceeding

3524, Application 1611000-1, May 9, 2016. 195

Transcript, Volume 6, page 1246. 196

Exhibit 3585-X0839, prepared from Exhibit 3524-X0407. 197

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.


40 • Decision 3585-D03-2016 (June 6, 2016)

Requirements (MFR) for regulated electric utility companies in Alberta. The USA and MFR

schedules were subsequently implemented in accordance with Decision 2007-017.198

192. The EUB adopted the MFR to “improve the consistency and completeness of

applications.”199 However, since that time, there has been continued tension between the TFOs

and interveners regarding the extent to which additional information beyond the MFR should be

filed in both GTA and deferral account proceedings. This proceeding was no exception and, as

discussed in Section 3 above, the record in this proceeding was voluminous.

193. Both AltaLink and the interveners expressed their dissatisfaction with the manner in

which this deferral account application unfolded and offered suggestions for improvement.

Issues raised included: (1) the quantity and quality of evidence, (2) a request for decision

registers, (3) a request for a price-quantity analysis, (4) suggested improvements to the

proceeding process such as a pre-filing or discovery process, and (5) the filing of final cost

reports.

Quantity and quality of evidence

194. In its evidence, FTI submitted that AltaLink’s method and format for responding to

information requests and other aspects of its application evidence greatly added to the regulatory

burden required to assess the application. Specific matters identified by FTI included:

The lengthy chain of cross references used in IR responses.

AltaLink’s failure to provide certain exhibits.

The fact that many scanned documents were blurry or illegible.

The fact that password protections on certain electronic files impeded data

manipulation.

The fact that certain electronic files were provided as image only, thereby preventing

searching.

The fact that electronically provided files in the confidential record did not have OCR200

capabilities.

The fact that the naming convention for files and folders did not provide for efficient

identification or location of critical documents.

The splitting of single documents between several files.

The fact that documents in the confidential record contained redactions that covered up

or omitted important data.

The fact that project contracts, changes and amendments to AltaLink/SNC-ATP

agreements for CB and Heartland projects were not provided.201

198

Decision 2007-017: EUB Proceeding, Implementation of the Uniform System of Accounts and Minimum

Filing Requirements for Alberta’s Electric Transmission and Distribution Utilities, Application 1468565-1,

March 6, 2007. 199

Bulletin 2006-25 dated July 12, 2006. 200

Optical character recognition (OCR) is the electronic conversion of images of text into machine-encoded text.

It is a common method of digitising printed texts so that it can be electronically edited, searched, stored more

compactly, displayed on-line, and used in machine processes such as cognitive computing, machine

translation, text-to-speech, key data and text mining. 201



Decision 3585-D03-2016 (June 6, 2016) • 41

195. In its rebuttal evidence, AltaLink indicated that the Commission significantly expanded

the minimum filing requirements for DACDA applications in Decision 2013-407 and that its

application significantly exceeded these requirements. AltaLink stated that the record for

Proceeding 3585 included more than 70,000 pages of documents on the public record and more

than 95,000 pages of documents on the confidential record, most of which were provided in

response to information requests (IRs). Given these numbers of pages of evidence, AltaLink

disagreed with the suggestion that the minimum filing requirements should be expanded, and

submitted that the requirement to file more than 165,000 pages of evidence is unnecessary,

unduly burdensome, and inefficient.202 To illustrate the extensiveness of its filings, AltaLink

provided a table203 that summarized various types of documents filed on public and confidential

record as either part of the original application or as IR responses.

196. AltaLink submitted that where the Commission has made rulings on IR responses, the

RPG cannot claim it was denied access to relevant information.204 Instead, AltaLink submitted

that the RPG complaints about the quality of evidence represents an attempt to disguise its own

failure to provide relevant evidence. Instead of relevant evidence, AltaLink suggested that the

RPG had provided unsubstantiated speculation.205

197. In response to concerns expressed within the FTI evidence about the quality of its

application evidence, AltaLink submitted that it diligently followed each Commission ruling to

the best of its ability and tried to balance the high volume of information requested by

interveners with various Commission filing requirements.

198. AltaLink submitted that FTI’s concern about “splitting documents across several files”

arises because it must comply with the electronic document requirements of the Commission’s

user guide.206 AltaLink also submitted that FTI’s claim that IRs reflected a “lengthy chain”

reflected the way the Commission organized its ruling on the confidentiality motions.207

199. In its argument, the RPG submitted that it has been advocating for four years that

AltaLink and ATCO should be required to provide sufficient relevant information within their

DACDA applications to allow the Commission and interveners to assess the prudence of costs

incurred on direct assign projects efficiently and effectively.208 However, the RPG noted that the

Commission and its predecessor have had this concern much longer. In this regard, the RPG

noted that in Decision 2005-120, the Commission’s predecessor expressed concern that

interveners may be placed in an information deficiency position that should be avoided.209

200. However, the RPG submitted that despite the massive record in the current DACDA

application proceeding, much of the crucial information was missing, and an information

deficiency still exists.210 The RPG submitted that, as with AltaLink, the massive record in the

current proceeding is also a concern for the RPG because a significant portion of this record has

202


Exhibit 3585-X0704, Table 1, pages 8-13. 204






Exhibit 3585-X0860, paragraph 146, citing Decision 2005-120, pages 3-4. 210



42 • Decision 3585-D03-2016 (June 6, 2016)

little value and does not get to the heart of the key issues. The RPG is also concerned that the

production of such a large record creates costs that will ultimately be borne by ratepayers.211

201. The RPG considers that requiring AltaLink to provide a register of key decisions would

provide an opportunity to reduce the volume of DACDA application information while getting to

the matters at the heart of the application.212

202. In addition to the above, the RPG submitted that, subject to the test of relevance and

value added, the Commission should restore intervener funding to adequate levels and should

encourage full or partial negotiated settlements, where possible.213

203. In argument, AltaLink submitted that it has fully complied with the Commission’s

minimum filing requirements. Contrary to the submission of the RPG that the form of

information should be consistent between TFOs, AltaLink noted that the filing requirements

outlined by the Commission do not require it to file information in the same format as other

TFOs. Accordingly, while having consistent information between TFOs may assist interveners

with their participation in the regulatory process, the RPG ignores the fact that the documents

listed in the minimum filing requirements are the source documents used in project execution

and, therefore, will be specific to each TFO.214

204. AltaLink submitted that as the volume of information filed in the current proceeding far

exceeds the level of detail previously found acceptable by the Commission in the context of

deferral account applications, there is no need to expand the filing requirements further.

205. AltaLink submitted that in Decision 2014-283, the Commission expressed concern about

the balance between the needs of interveners to obtain sufficient information and the need to

create a process that is less burdensome for both the applicant and interveners.215 However,

AltaLink submitted that the RPG’s request for more information, either in the form of additional

cost and performance audits or endless discovery is unnecessary.216 In this regard, AltaLink

submitted that while interveners have a critical role to play in the regulatory process, that role

should not be extended to the point where interveners become the auditors of the utility.217

Decision registers

206. In its evidence, FTI expressed concern that AltaLink did not provide a decision matrix

and decision analysis report. As a result, FTI submitted that in formulating its evidence, FTI was

required to base its assessment of AltaLink decisions on the existing record, and on what FTI

could deduce from the face value of the documents that AltaLink filed.218

207. The RPG expressed concern in its evidence that while the volume of documentation

AltaLink provided has increased, the volume of relevant information continues to be low, since

211





Exhibit 3585-X0859, paragraph 100, citing Decision 2014-283, paragraph 107. 216





Decision 3585-D03-2016 (June 6, 2016) • 43

key decisions are often undocumented or undisclosed.219 In light of this concern, the RPG

submitted that the onus should be put on the TFO to provide the evidence necessary to

demonstrate that the decision making that generated its costs was reasonable and in so doing

demonstrate that its costs have been prudently incurred.

208. In argument, AltaLink noted that it provided project summary forms for 14 projects that

explained AltaLink’s variances and decision making. AltaLink submitted that, while in a

different form than requested by the RPG, the information they sought was available to them.

However, AltaLink noted that this information was not challenged.220

209. In its argument, the RPG submitted that requiring AltaLink to provide a decision register

or equivalent has the potential to reduce the volume of information that must be considered in a

DACDA by getting to the heart of the most important issues.221 The RPG explained that a

decision register documents the key decisions made during project development, identifies the

costs, benefits and risks of each option considered, and provides the reasons for selection of the

option that is chosen.222

210. The RPG noted that in the ATCO 2012 DACDA proceeding, the Commission took note

of several concerns expressed by the RPG about evidence in that proceeding,223 and expressed

interest in further examination of decision registers. The Commission directed ATCO to develop

a proposal for a key decision matrix and fully describe that proposal in either its next GTA or

next DACDA application, whichever came first.224 The RPG also submitted that in setting out the

scope for the audit of AltaLink’s Southwest 240-kVproject, which directed the examination of

key milestones and potential turning points in the execution of the project,225 the Commission

was essentially requesting the same information that RPG recommends to be included in a

decision register.226

211. The RPG further submitted that establishing a requirement to provide decision registers is

supported further by comparisons with the business case requirements for capital maintenance

projects. In this regard, the RPG noted that utilities are required to file business cases for

proposed capital projects over $500,000, including the reasons for the proposed expenditure, the

alternatives examined, incremental capital and operating costs, and other assumption.227 The RPG

submitted that because these extensive business case requirements were established for projects

costing $500,000 or more, and the projects in the DACDA are generally an order of magnitude

more expensive, there should be a need for explicit documentation of similar decisions in

DADCA proceedings that are an order of magnitude higher.228

212. The RPG noted that Commission counsel asked why the long list of documents cited in

AltaLink rebuttal evidence did not get to the heart of the issues of concern to the RPG. The RPG

219









Exhibit 3585-X0860, paragraph 157, citing Decision 2007-071, page 32. 228



44 • Decision 3585-D03-2016 (June 6, 2016)

explained that the primary matter at issue in DACDA proceedings is to determine what the

applicant knew or ought to have known at the time of key decisions affecting costs, what options

the applicant considered at those key decision points, and the rationale for the decision the

applicant made.229

213. The RPG submitted that if AltaLink does not yet have a decision register or similar

documentation for key cost-related decisions, the Commission cannot be assured that key

decisions with cost effects were reasonably made and resulted in prudently incurred costs.

Accordingly, while AltaLink cites its process and the professional judgement of its managers, it

is unreasonable to expect that these processes and its professional judgement will always result

in reasonable decisions and prudently incurred costs. In this regard, the RPG noted that AltaLink

indicated that it makes “millions of decisions”230 and that in the DACDA application, it is

seeking approval of expenditures on 103 projects totalling $1.684 billion.231

214. In reply, AltaLink submitted that the RPG’s recommendation that AltaLink should be

required to document its decisions in a decision register disregards the fact that actual source

documents were provided on the record, which the RPG largely ignored. AltaLink submitted that

the RPG’s concern about the massive volume of source documentation ignores the fact that the

large volume of information on the record arose directly as a result of the expansive, unfocused

“shot gun approach” that interveners took during the IR process and in subsequent requests for

more documentation.232

215. In its reply, as set out in its argument,233 the RPG submitted that the Commission’s

assessment on prudence must reflect an understanding of whether the TFO considered other cost

options and also an assessment of the TFOs explanation of why the selected option was chosen.

In short, the RPG submitted that application data must show what a TFO knew at the time, and

how it made a particular decision.234

Price-Quantity analysis

216. In its evidence, the RPG noted that in Proceeding 2683, which considered the DACDA

application of ATCO Electric Ltd., the CCA requested that ATCO Electric provide a detailed

table to record supporting information for input quantities and prices used from major

components of the PPS stage estimate. The RPG submitted that the Commission should augment

the minimum filing requirements to make it a requirement for TFOs to provide a table of this sort

for all direct assign projects with a cost greater than $5 million.

217. In its rebuttal evidence, AltaLink disagreed with the suggestion of the RPG that it should

be required to provide a cost reporting table in the form suggested by the RPG. AltaLink

submitted that it has complied with the applicable minimum filing requirement and provided all

information necessary to process the application.235 Additionally, AltaLink submitted that it

would not be appropriate to apply retroactively a requirement to populate the reporting table

229

Exhibit 3585-X0860, paragraph 159, citing Transcript. Volume 10, page 1723. 230

Transcript. Volume 2, page 317, cited in Exhibit 3585-X0860, paragraph 162. 231

Exhibit 0002.00.AML-3585, Table 7.2-1, PDF page 38, cited in Exhibit 3585-X0860, paragraph 162. 232






Decision 3585-D03-2016 (June 6, 2016) • 45

requested by the RPG, since the existing reporting requirements are not designed for this.236

AltaLink submitted that the reporting that it provided in the application reflects the uniqueness of

each project. In any event, AltaLink submitted that any changes in the Commission’s minimum

filing requirements would be of broad industry interest and should be done through a generic

process where all interested parties would be able to provide input.237

218. In its argument, the RPG submitted that the price-quantity analysis that it recommended

in its evidence could be used as a screening tool to focus concerns on areas in which costs have

potentially risen more than reasonably and need a more thorough review for prudence. As such,

the RPG submitted that price-quantity analysis has the potential to reduce the need to focus on

certain areas of project development and, hence, it will improve the overall efficiency of the

deferral account process.238

219. In reply, AltaLink submitted that the Commission’s findings in Decision 2014-283 have

already recognized that the PPS stage estimate plays the role that the RPG envisions for the

price-quantity analysis it is seeking. That is, AltaLink argued that the price-quantity analysis

being sought by the RPG was meant to act as a screening tool to focus areas of concern, but the

Commission had already found that the purpose of the PPS stage estimate is to identify areas of

significant variance for further investigation.239

Pre-filing discovery process and data room

220. In evidence, the RPG submitted that for future DACDA applications, the Commission

should require TFOs to provide a list of documents relevant to the direct assign projects included

in DACDA applications. The RPG proposed that this document list be supported by a physical or

electronic data room containing the source documents referenced in the documents list. The RPG

submitted that because the TFO is generally capable of identifying documents that support its

main conclusions, the provision of a documents list along with the establishment of a virtual or

physical data room would assist parties in focussing on the relevant documents, thereby reducing

the extent to which interveners will have to make disclosure requests after the TFO’s application

has been filed.240

221. In argument, AltaLink submitted that instead of providing evidence supporting its claims,

the RPG proposed a significant expansion in the use of cost and performance audits, a

requirement that AltaLink provide a documents list similar to an affidavit of records, and a

physical or electronic data room of the actual documents outlined on the documents list.

222. AltaLink asserted that these RPG proposals will not improve regulatory efficiency and its

request for a data room reflects the fact that the RPG sees itself as the auditor of a utility. This

depth of examination goes far beyond the role of an intervener, which is not to reconstruct a

project from the ground up, nor to micromanage the utility.241

236





Exhibit 3585-X0666, Appendix 1, paragraph 24. 241



46 • Decision 3585-D03-2016 (June 6, 2016)

223. AltaLink submitted that it strongly opposed the RPG’s proposal to require it to provide a

data room because the purpose of discovery is not a “fishing expedition” or an audit conducted in

the name of discovery. AltaLink submitted that the documentation required for a DACDA

application review must be materially relevant. Instead, AltaLink submitted that the RPG’s

proposal would only create an even greater volume of information to review.242

224. In reply, the RPG disagreed with AltaLink’s contention that the RPG is seeking greater

access to project-related data through a data room because the RPG sees itself as the auditor of a

utility. Instead, the RPG submitted that it has requested the establishment of a data room to

counteract AltaLink’s asymmetric information advantage. The RPG submitted that the present

process requires interveners to ask precisely the correct question to determine key decision

points. Therefore, the RPG submitted that requiring a data room provides a means to level the

playing field with an entity that uses its asymmetric information advantage to make it

exceptionally difficult to identify what it knew or ought to have known when key cost-related

decisions were being made.243

Final cost reports

225. In its argument, the RPG expressed concern that a number of major projects were

included in the current DACDA for which no final cost report was available at the time of filing.

The RPG noted that the Heartland, CB, Hanna-Nilrem, Hanna Ware Junction In-Out, and Hanna-

Hansman Lake projects were included without final cost reports.244

226. The RPG submitted that final cost reports often contain a level of detail that could

facilitate a more efficient review by the Commission and interveners.245 However, in light of its

concern that final cost reports were not filed for these major capital projects, the RPG

recommended that the Commission direct TFOs to provide a final cost report as a precondition

for the inclusion of a project in a DACDA proceeding.

227. In reply, AltaLink opposed the RPG’s proposal because the final cost report is an ISO

rule obligation, the reports are not the basis for actual costs in a period and may include estimates

of trailing costs that could cause confusion as to the actual costs incurred in the DACDA test

years.246 AltaLink responded that it has set out its actual costs at the lowest level of detail in

Exhibit 3585-X0043 and final cost reports would not add anything to the substantial record that

has already been provided.247

Commission findings

Quantity and quality of evidence

228. Directions in recent Commission decisions, including Decision 2013-407 and Decision

2014-283, have significantly increased the amount of information that must be filed as part of a

TFO’s capital deferral account application.

242








Decision 3585-D03-2016 (June 6, 2016) • 47

229. In particular, the Commission issued Directive 45 in Decision 2013-407, which specified

particular DACDA filing requirements for AltaLink based on the Commission’s acceptance of

the arguments of interveners that AltaLink should be made subject to the same filing

requirements that had previously been prescribed for ATCO in Decision 2013-358. The

Commission finds that the direct assign project information that AltaLink filed for the current

application has, for the most part, complied with Directive 45 from Decision 2013-407. Some of

the projects included in the DACDA application had no supporting documentation other than

cost breakdowns.

230. However, as stated in Decision 2014-283, a balance should be struck between the

information necessary to examine the capital project costs and the burden placed on the TFO to

provide that information:

107. In a transmission project deferral account reconciliation application, it is the

Commission’s task to review the actual costs of the transmission projects and decide

whether the actions of the utility, in its design and execution of that transmission project,

were reasonable at the time the actions were taken, and, consequently, the costs which

flowed from those actions were prudently incurred and could be included in the rate base

of the utility. This review and approval is final in nature. As such, the Commission must

balance the need to obtain sufficient information respecting the transmission projects to

assess the reasonableness of the utility’s actions without creating an unduly burdensome

process for both the applicant and intervener parties, who, on behalf of ratepayers, are

also reviewing these costs.

231. The majority of the project-related information that AltaLink was directed to provide in

this proceeding included documents that AltaLink was already obligated to provide to either the

Commission as part of other proceedings or to the AESO as part of its obligations to prepare

documentation and exchange documentation with the AESO in the normal course of its project

planning or execution processes. Given the large number of projects that AltaLink included in

the current application, it was not surprising that the number of pages of documentation required

to comply with Directive 45 from Decision 2013-407 was substantial. However, the assembly of

this information for filing should not have been unduly onerous because much of the

documentation includes existing reports that should have been readily available.

232. However, with regard to the quality of the information filed, the processing of the current

application was made more complicated by information that was not included in the initial

application and by the manner in which filed information was presented.

233. There were 29 projects included in the DACDA application248 for which AltaLink

provided no supplementary information other than the cost breakdown found in the applicable

project tab of the Exhibit 0006.00.AML-3585 excel spreadsheet. AltaLink had adopted a new

system that assigned a project identification “D” number to its projects and had also adopted

different names for some of the projects in its application. This change made it difficult for the

Commission to match each project to projects that the Commission had previously considered in

NID application and facility application proceedings. To sort this out, the Commission cross-

referenced its own records to prepare an IR that attempted to match AltaLink’s project identifiers

to the Commission’s record of relevant NID and facility proceedings, decisions, and associated

248

Exhibit 3585-X0042, AML-AUC-2015MAR05-004.


48 • Decision 3585-D03-2016 (June 6, 2016)

permits and licenses. Despite this extensive review, AltaLink’s response to that IR identified a

number of matching errors. As the prudence review of capital projects in a DACDA requires an

assessment of the reasonableness of past decisions, it is critical that the Commission be able to

match these projects to all of the preceding regulatory decisions and processes as part of this

analysis and AltaLink, not the Commission, should have prepared this cross reference and

included it in its application. Further, it was only as a result of requesting basic information

necessary to identify projects where AltaLink had only provided its name, a cost breakdown, and

a project identifier that AltaLink indicated that two projects, representing an aggregate addition

to rate base in the amount of $346,500, were determined by AltaLink in the course of its research

into an IR to have been included in the application in error.

234. Accordingly, AltaLink is directed to provide a comparable cross reference table

containing all of the same information that it provided in AML-AUC-2015MAR05-002,249 in its

future DACDA applications.

235. Because the provision of information in this form identifies where relevant project

information can be found in the Commission’s electronic records, the Commission will no longer

require AltaLink to file on the record of the future DACDA proceedings, copies of information

such as PPS, functional specifications, facility and NID application documents that have already

been filed with the Commission. Parties may refer to these documents as if they had been filed

on the record of the DACDA proceeding. This direction does not reflect a decision by the

Commission to incorporate, by reference, the entire record of these other proceedings. Rather, it

is intended to obviate the need for AltaLink to file project documents that have already been filed

in prior Commission proceedings. The Commission expects that the adoption of this change

should significantly reduce the size of the public record that AltaLink is required to assemble for

future applications.

236. In the Exhibit 0006.00.AML-3585 spreadsheet filed with the application, AltaLink

included a tab with the title “Energizations,” which provided a cross reference between

AltaLink’s project identification number and name and each project’s energization date or dates.

This information is of assistance when a project has a single listed energization date; however,

the presentation of this information is less helpful when a project has multiple energization dates

since there is no indication regarding what facilities were brought into service on each date. This

information is particularly critical for projects for which AltaLink is only proposing to add a

portion of the expected final cost of a project in a specific DACDA year. Accordingly, for future

applications, for those projects where more than one energization date is shown, the Commission

directs AltaLink to provide an additional description of the specific project facilities brought into

service on each date shown.

237. The individual project cost breakdowns that AltaLink provided in separate tabs of the

Exhibit 0006.00.AML-3585 excel spreadsheet contained most of the project cost line items

included in the report format used for reporting to the AESO pursuant to ISO Rule 9.1.2.

However, AltaLink’s initial cost breakdowns in Exhibit 0006.00.AML-3585 tabs did not

breakdown owner costs and distributed costs by their respective component parts. AltaLink

provided this information in response to IRs from the Commission. As the component line-item

details of owner costs (PPS, facility applications, land rights – easements, land – damage claims,

249

Exhibit 3585-X0042.


Decision 3585-D03-2016 (June 6, 2016) • 49

land – acquisitions) and distributed costs (procurement, project management, construction

management, escalation, contingency) are of interest to the Commission, AltaLink is directed to

include breakdowns at this level of detail in future DACDA applications.

238. The Commission is also concerned that it only became apparent at the time AltaLink

provided its responses to the initial set of IRs that a number of projects that AltaLink included in

the application were not direct assign projects. AltaLink is directed to distinguish clearly

between direct assign projects and non-direct assign projects in future applications.

239. The Commission found the project summary reports AltaLink prepared for a subset of the

projects in the application to be beneficial and directs AltaLink to continue to provide these

reports. However, the content of these reports could be improved. Presently, the project

summaries provide an overview of information such as summaries of key change proposals,

facility applications, functional specifications, proposals to provide service and other documents

that AltaLink filed as separate exhibits. However, for the most part, the project summaries did

not provide the information necessary to identify the analysis made at key decision points in the

project development life cycle on the basis of the information that AltaLink had available, or

ought to have had available at that time. Accordingly, the Commission has commented on this

deficiency in its findings regarding decision registers and price/quantity reports discussed below.

Decision registers and risk registers

240. The auditor’s report on AltaLink’s Southwest 240-kVproject which was assessed in

Decision 2044-D01-2016 relied extensively on an analysis of a risk register that AltaLink had

established for that project.250 In Section 4.1.8, the Commission has directed AltaLink to file its

2014 and 2015 DACDA applications as separate proceedings. To the extent that AltaLink has

prepared similar risk registers for the direct assign projects it includes in its 2014 DACDA

application, AltaLink is directed to provide the similar risk registers with that application.

Because AltaLink has historically used a risk register on at least one direct assign project, for any

project included in AltaLink’s 2014 DACDA application for which no risk register was set up or

maintained, AltaLink is directed to provide an explanation as to why a choice not to set up or to

maintain a risk register was made for that project.

241. On a go forward basis, the Commission considers that including a key decision matrix

and risk register in future applications may assist the applicants, the interveners and the

Commission in managing and focussing on the documentation necessary for testing future

transmission project deferral account reconciliation applications. The Commission directs

AltaLink to develop a proposal for a key decision matrix, and to review its risk register practices

and to fully describe such proposal and review in either its next GTA or in its next transmission

deferral account application, whichever comes first.

Price-Quantity analysis

242. In its evidence, the RPG provided a snapshot of a sample project price-quantity reporting

table that could be used in a DACDA proceeding.251 The Commission has reviewed the snapshot

of the proposed project price-quantity reporting table and considers that providing such a report

250


Exhibit 3585-X0666 at page 61.


50 • Decision 3585-D03-2016 (June 6, 2016)

could help to focus attention on key cost drivers and decisions while reducing “fishing

expedition” IRs.

243. However, there is no evidence on the record regarding what level of effort on the part of

AltaLink would be required to produce these reports or the costs of doing so and the Commission

considers that the minimum cost threshold for requiring AltaLink to provide a comparable report

should be significantly higher than the $5 million threshold proposed by the RPG.

244. Accordingly, for its 2014 DACDA, AltaLink is directed to provide a report similar to that

provided by the RPG at page 61 of its evidence for all projects where AltaLink’s requested

addition to rate base for 2014 is at least $25 million.

Pre-filing discovery process and data room

245. In Decision 2005-120,252 the EUB identified the potential for interveners to be in a

disadvantaged position in relation to utility applicants as a result of the asymmetrical access that

the applicant and interveners have to project cost and other information.

246. This asymmetrical access to project information may place interveners in the position

where they must first obtain access to source documentation and then spend time and resources

to scrutinize this information in order to determine if they have a concern with the costs

requested.

247. Understandably the applicant is frustrated with this process since it has the burden of

demonstrating the prudence of its costs, not interveners.

248. The volume of the material on the record for Proceeding 3585 created significant burdens

for all parties, including AltaLink. Further, the process that led to the creation of this large

record, including numerous contested motions that required extensive rulings, contributed

significantly to regulatory process inefficiency and delays.

249. As discussed above, the Commission has determined that AltaLink’s next DACDA

should be limited to projects brought into service during 2014. Due to the comparatively smaller

size of the 2014 DACDA, and concerns about minimizing regulatory lags, the Commission will

not require AltaLink and interveners to adopt any of the proposals for documents lists or other

pre-filing discovery processes that were discussed during the proceeding as filing requirements

for the 2014 DACDA application.

250. However, the Commission has a genuine interest in examining whether further

development of tools such as document lists and virtual or physical data rooms can be used to

make the size and analysis of the record for AltaLink’s 2015 DACDA more manageable and to

allow the 2015 DACDA proceeding processes to be more timely and efficient.

251. Although the Commission raised the possibility of an industry-wide round table to

advance potential improvements in DACDA proceeding processes for all TFOs, the Commission

considers that the size of the record in the current proceeding is, in large part, due AltaLink’s

outsourcing of EPC/EPCM services for the majority of its direct assign projects, which is a

252

Decision 2005-120: AltaLink Management Ltd., Reconciliation of Direct Assigned Project Capital Deferral

Accounts for the May 1, 2002 to April 30, 2004 Period, Application 1359518-1, November 22, 2005.


Decision 3585-D03-2016 (June 6, 2016) • 51

practice that is undertaken only by AltaLink. Therefore, consultations regarding potential process

changes in anticipation of AltaLink’s 2015 DACDA application are limited to AltaLink and the

intervener groups that have been active in AltaLink DACDA proceedings.

252. Accordingly, AltaLink is directed to establish a consultative process with representatives

from intervener groups active in AltaLink DACDA application proceedings to try to arrive at a

workable and mutually acceptable set of filing requirements and pre-filing discovery processes to

be followed for AltaLink’s 2015 DACDA application. AltaLink may conduct the consultation

process in whatever manner it considers will be the most effective however, as a starting point

for this process, AltaLink is directed to identify specific proposals or recommendations for

possible solutions such as the use of virtual or physical data rooms or the creation of an agreed

upon list of application documents.

253. AltaLink is directed to file a report with the Commission regarding the outcome of this

consultation process on or before October 3, 2016, regardless of whether any consensus on any

proposals has been achieved. The report should include a full description of the nature of the

proposals considered and should identify any matters on which a consensus of the parties has

been achieved. The Commission will provide further direction respecting the filing requirements

for AltaLink’s 2015 DACDA application following its review of this report.

Final cost reports

254. As AltaLink had to prepare these reports for the AESO pursuant to ISO Rule 9.1.3.6,253

AltaLink is directed to file each of the final cost reports it has prepared for each direct assign

project it includes in its 2014 DACDA application. In the event that AltaLink is unable to

provide a final cost report for any direct assign projects included in its 2014 DACDA

application, AltaLink is directed to provide a full explanation as to why a final cost report cannot

be filed.

4.1.10 Cost and performance audits

255. FTI submitted in its evidence that the proceeding record supports the need for specific

audits on the CB and Heartland projects, and more generally supports the need for audits of other

direct assign projects to determine AltaLink’s compliance with Commission directives.254 It

requested the Commission direct full scale cost and performance audits on all AltaLink direct

assign projects in excess of $100 million.255

256. The RPG supported FTI’s view. In its evidence, the RPG submitted that the Grid Power

report identified $100 million of imprudently incurred costs on the CB and Hanna projects and

the FTI report identified $127 million of questionable unsupported costs. Therefore, unless the

Commission disallows the full amount identified by the RPG as imprudent, uncertainty with

respect to the prudence of these costs will remain.256 Consequently, the RPG submitted that it

expected AltaLink to embrace audits in order to verify the prudence of the cost of its projects,

253

ISO Rule 9.1.3.6 was removed effective April 29, 2016. 254

Exhibit 3585-X0667, page 4. 255

Exhibit 3585-X0667, page 105. 256

Exhibit 3585-X0666, paragraphs 2-3.


52 • Decision 3585-D03-2016 (June 6, 2016)

ensure the ongoing efficiency of its projects, eliminate inefficient practices for future projects,

and provide discipline to suppliers and contractors to use best cost control practices.257

257. The RPG noted that the Commission recognized the benefit of audits in Decision 2013-

407258 and Decision 2013-358,259 and submitted that audits may address concerns regarding the

resource disparity between TFOs,(who are funded by customer rates) and interveners (who do

not have access to cost recovery under AUC Rule 022: Rules on Costs in Utility Rate

Proceedings).260 Further, in Appendix 1 to its evidence, the RPG recommended the Commission

establish guidelines for the regular use of cost and performance audits, including a requirement

that Commission-sponsored auditors be allowed unfettered access to TFO records.

258. The RPG recommended an audit be performed for the following specific matters:

Heartland project audits: The RPG sought a cost and performance audit on the Heartland

project in respect of transmission construction costs and AC mitigation costs.261

Helicopter use audit: The RPG requested a cost and performance audit to compare the

cost of tower erection using helicopter versus using cranes for:

o CB project

o Hanna-Nilrem

o Hanna-Hansman Lake projects

o 240-kV section of Heartland project.262

Rig mat use audit: The RPG requested cost and performance audits to examine the use of

rig mats in light of the significant rig mat expenditures on the CB, Hanna Nilrem, Hanna

Hansman Lake, Hanna Ware Junction, and Heartland projects.263

Line design audit: The RPG requested a cost and performance audit in respect of

transmission line design in light of its evidence on underutilized lattice tower capacity.264

Market escalation audit: The RPG requested a cost and performance audit in respect of

variances attributed to “market escalation.”265

259. In its rebuttal evidence, AltaLink submitted that while the Commission has stated that

cost and performance audits may be beneficial when significant areas of uncertainty or concern

have been identified, the RPG’s position appears to be that audits are justified any time project

costs exceed the PPS stage estimate.266 Allowing the RPG’s suggested audit approach would

have the effect of turning every DACDA proceeding into a ground-up reconstruction of each

257


Exhibit 3585-X0666, Appendix 1, paragraph 21, PDF page 72, citing Decision 2013-407, paragraph 567. 259

Exhibit 3585-X0666, Appendix 1, paragraph 22, PDF page 72, citing Decision 2013-358, paragraph 398. 260

Exhibit 3585-X0666, Appendix 1, paragraph 23, PDF page 72. 261


Exhibit 3585-X0666, paragraph 127 and paragraph 154. 263

Exhibit 3585-X0666, paragraph 158 and paragraph 170. 264





Decision 3585-D03-2016 (June 6, 2016) • 53

project and such an outcome would be inconsistent with the approach taken by Midgard

Consulting Ltd. (Midgard), the Commission appointed auditor of the Southwest 240-kV project.

Under cross-examination in Proceeding 2044, the auditor for Midgard noted that chasing small

variance is time misspent.267 Furthermore, AltaLink submitted that it is notable that Midgard

concluded that AltaLink’s project execution decisions for the Southwest 240-kV project were

reasonable.268

260. AltaLink further submitted that the RPG’s request for additional information and

oversight ignored the fact that the Commission had issued prior rulings denying certain types of

information sought by the RPG (e.g., invoices) and that other information the RPG said it

required had already been provided in the course of this proceeding.269

261. AltaLink submitted that the current regulatory oversight processes of the Commission,

the AESO, and industry already provide sufficient oversight and audit scrutiny. As a result,

additional audit processes would be duplicative, inefficient, expensive and unnecessary. Further,

AltaLink expressed concern that interveners were ignoring the findings in Decision 2013-407, in

which the Commission rejected a request for the mandatory audit of projects above $100 million,

concluding that audits may only be necessary if the DACDA review discloses areas of

uncertainty, requiring additional cost scrutiny before the Commission can approve final costs.

262. Finally, AltaLink stated that the RPG’s request for additional audits on the basis of the

“resource disparity between TFOs and interveners” is an attempt to circumvent established

intervener funding limitations set out in AUC Rule 022.270

263. In its argument, the RPG expressed concern with the parameters set by the Commission

for the performance of the audit. In the RPG’s view, an independent auditor is either not

permitted or does not choose to obtain project information other than what is provided by the

TFO. In the RPG’s submissions, this was an issue in the audit of AltaLink’s Southwest 240-kV

project.271 The RPG submitted that any cost and performance audits directed by the Commission

should give the auditor unfettered access to the TFO records, otherwise the examination that is

conducted is not a true audit. The RPG submitted further that the determination of the auditor

should be final or, if a subsequent process is ordered, the process should provide for a level

playing field between AltaLink and customer representatives.

264. In its argument, AltaLink reiterated its objections to the RPG’s request for cost and

performance audits, maintaining that audits are unnecessary, duplicative, and inefficient.272 It

submitted that any increased use of cost and performance audits would create additional

uncertainty, as it would contribute to the perception of a less predictable and supportive

regulatory environment.273

267


Exhibit 3585-X0704, paragraph 36 citing Transcript, Proceeding 2044, Volume 1 (October transcript)

PDF pages 177-178. 269

AltaLink supports this statement with footnote to paragraph 39 of its rebuttal evidence (Exhibit 3585-X0704)

which contains exhibit numbers that takes up half a page. 270






54 • Decision 3585-D03-2016 (June 6, 2016)

265. In its reply argument, the RPG submitted that AltaLink’s suggestion that other processes

avoid the need for cost and performance audits ignored the fact that none of these initiatives

involves a review of the prudence of costs.274 The RPG noted that in a DACDA application

proceeding, the Commission has the option of disallowing costs outright or ordering

supplementary audits. The RPG acknowledged that while cost and performance audits take

additional time and resources, and may prolong uncertainty, it should be noted that an audit

process provides an additional venue for the TFOs to demonstrate that their costs were prudently

incurred.275

266. In reply argument, AltaLink addressed the RPG’s issues regarding the Commission’s

decision on the audit of the Southwest 240-kV project. It stated that the concerns the RPG raised

with respect to the audit of the Southwest 240-kV project, have already been heard and rejected

by the Commission in that proceeding.276

267. AltaLink submitted that the RPG’s request for additional audits actually represents an

attempt by the RPG to obscure the fact that it did not provide facts and evidence to the current

proceeding.277 It submitted that additional cost and performance audits would not uncover

additional evidence to support the RPG’s claims or positions. Instead, AltaLink submitted that

audits would be an exercise in “re-ploughing old ground.”278 AltaLink noted that this concern

was raised with the RPG panel though cross examination by Commission counsel.279

268. In its reply, ATCO submitted that the Commission should reject the RPG’s

recommendation to undertake costly and time-consuming audits throughout AltaLink’s entire

project portfolio. ATCO submitted that audits are not a primary function of the deferral account

process and should be used sparingly by the Commission. ATCO submitted that audits should

only be ordered in limited circumstances where a clear benefit is likely to occur. ATCO

submitted that this is not the case in AltaLink’s current DACDA application proceeding.280

Commission findings

269. In the proceeding leading to Decision 2013-407, the RPG requested the Commission to

direct mandatory audits for all capital projects that had a cost in excess of $100 million. The

Commission rejected this proposal stating:

576. However, the Commission is currently of the view that undertaking audits of

AltaLink’s completed projects may be beneficial in certain circumstances. The

Commission is not prepared, to make such audits mandatory for all capital projects that

have a cost in excess of $100 million as requested by the RPG. Rather, the Commission

considers that it may be necessary to direct an after-the-fact audit in the course of a

DACDA review if the Commission has identified significant areas of uncertainty or

concern that require additional investigation before the Commission can approve final

costs for that project.

274









Decision 3585-D03-2016 (June 6, 2016) • 55

270. Both AltaLink and interveners have commented on the size of the record in this

proceeding and given the size of this record, the Commission questioned an RPG witness

respecting what he considered a cost and performance audit would reveal. The exchange was as

follows:

Q.… Given all the documentation that's in this proceeding, and also the oral testimony

that we've had, can you explain how a cost and performance audit will address the issues

with respect to the one you've requested on Heartland, and the issues and the reasons that

you've listed in your evidence? Are you able to help me out there?

[…]

A. MR. LEVSON: Yeah, it could be an undertaking. But just like in general to -- the

sense is that, as I've said earlier today, that in the wheelbarrows full

of paper --

Q. Right.

A. MR. LEVSON: -- information, you know, is there the -- the key decisions, like I've

said repeatedly, are they there? Can you see them, the choices that were made, you know,

when they were crossing these critical junctures in the -- in the project, and so –

Q. Sure. And my understanding is that -- and I've heard this -- that, you know, we

basically have every scrap of paper on this Heartland project on the record in front of us,

so what would a cost and performance audit achieve? They would -- would they not just

be looking at the same -- every scrap of paper that we already have on our record?

A. MR. LEVSON: No. Well, let's start with the performance side of it. What a

performance audit could do is to say if you'd had a qualified constructor building this line

and you looked at what are normal construction periods to build a 500 kV line double

circuit and a 240 kV line, which you can find from looking at other projects in Alberta or

elsewhere, so they would come up with what the cost would be incurred under, you

know, presumably the similar labour rates and so on, and you'd come up with a number

as to what that cost would be, and that would be then compared with the cost that was

actually incurred.

Q. So you're talking more like a benchmarking exercise, it sounds like?

A. MR. LEVSON: It would be. Now, in terms of, like, the paper that's on the

record, if AltaLink has actually documented the choices that they made, you know, in the

way that I described it, we don't see it. If it's there and could be put on

the record, fine, entertain it. But if they haven't -- if the truth here is that AltaLink does

not have a practice of doing as we've suggested, of documenting the decisions that they're

making, then we're – then the Commission is in a difficult position to --

Q. Are we talking about a difference between form over what you actually have? I know

you have a preference of form as to how you'd like to see this laid out. Is that the issue

here? That it might be here in the volume of information, but you're not seeing it because

it's not familiar -- it's not coming in a form familiar to you?

A. MR. LEVSON: Well, that's possible, but I would have thought, like, in rebuttal they

would have said, "Oh, no, you've made a big mistake. We have documented


56 • Decision 3585-D03-2016 (June 6, 2016)

every key decision that we've made, here's the choices that we had, here's the cost that we

selected among, and here's the reasons why." I mean it's pretty

straightforward.

[…]

Q. Okay. And with respect to the other is helicopters, use of rig mats, same explanation,

same problems?

A. MR. LEVSON: Yeah. The circumstances in each of them are somewhat different.

Whether the issue is more of a cost issue versus a performance issue, you know, whether

the decision was in the preliminary design stage or whether it was in execution, you

know, those are all things that will play into each one of those.

Like, the request for a cost performance audit is a sort of a decision of the Commission

that they can make. To me, if the Commission is not satisfied that they have an adequate

explanation that these costs are prudent, it's one of the tools available. We've mentioned

that another tool is just to disallow it, and there may be other options available.

We, having come through the Southwest audit, I think there are some things that have

been learned. We know that is probably -- we haven't seen the tab, but we suspect it's

fairly expensive and this is ultimately customer money normally, although there's the

option of charging the shareholder of the TFO, but normally this is going to be our

money that's spent, so we don't want to waste it either if it isn't going to produce a result,

but...

So the circumstances are all different. I suspect that the Commission will look at this and

if they agree that there's a problem, then they have to decide how they want to proceed

forward.281

271. The Commission considers that there is sufficient information provided on the record of

this proceeding to enable it to make a prudence determination without directing a cost and

performance audit. As recognized by the RPG in the above exchange, a cost and performance

audit is expensive and in the absence of any findings of significant areas of uncertainty or

concern that require additional investigation, directing an audit, for its own sake, would be

inefficient and unnecessarily duplicative as it is the Commission, and not the auditor, who must

make final determinations of prudence.

272. The Commission agrees with AltaLink’s submission that if and when an audit is ordered

by the Commission, additional Commission processes will generally be required before any audit

findings that might suggest imprudence (or the converse) could be ruled upon by the

Commission. The Commission also agrees with AltaLink’s observation that because of the time

taken to conduct the audit and the need for supplementary processes after audit findings are

released, the addition of an audit process to the regulatory process to complete the Commission’s

initial examination of a DACDA application could cause an unacceptable amount of regulatory

lag.

273. Directing an audit is an exceptional exercise and is not a substitute for the Commission’s

own examination of project costs in a DACDA.

281

Transcript, Volume 10, page 1782, lines 14-20; page 1783, line 3 to page 1785, line 7; page 1786, line 14 to

page 1787, line 17.


Decision 3585-D03-2016 (June 6, 2016) • 57

274. The RPG and FTI requests for audits, and in particular, cost and performance audits, in

the current proceeding are excessive and unwarranted. The request for audits is denied.

Consequently, the Commission also declines to establish formal guidelines for the regular use of

cost and performance audits.

4.1.11 Project cost escalation and related allowances

275. In Section 7.5.1 of its application, AltaLink discussed the effect of market conditions on

project cost escalation. AltaLink noted that during 2012, the economic growth rate of Alberta

(3.4 per cent) was significantly higher than the national growth rate (1.8 per cent).282 AltaLink

also submitted that the demand for construction contractor work did not relate solely to

AltaLink’s projects. A graph provided in its application283 showed numerous other competing

demands on construction resources and demands for transmission projects in Alberta which were

small relative to the much larger north American transmission build and the pull of resources

from other industries.284

276. AltaLink explained that the majority of the projects included in the application were

affected by the market escalation in construction labour rates. Further, while market escalation

was an identified risk in its PPS stage forecasts, AltaLink failed to anticipate the extent of the

market escalation effect on pricing when the PPS stage forecasts were being prepared.285

277. Since 2012, AltaLink has engaged the services of PowerAdvocate to develop project

escalation estimates. These estimates were designed to reflect market movement for three

distinct asset types: transmission lines, substations and telecommunications. PowerAdvocate’s

customized cost models were designed to take into consideration AltaLink’s planned capital

spend, the most common equipment and project types, Alberta’s market dynamics, and trends in

construction processes. In addition, AltaLink stated that its escalation rate was “calibrated on an

annual basis to provide an on-going current assessment.”286

278. In its evidence, the RPG questioned the frequency with which AltaLink referred to

“market escalation” as the cause of project cost increases. It prepared a table in which project

cost variances totalling $216 million were attributed, at least in part, to market escalation. Of this

total, variances of $20.9 million were attributed by AltaLink solely to market escalation, without

any additional clarification or justification.287

279. The RPG submitted that AltaLink should be directed to provide a schedule similar to one

prepared by ATCO in its 2012 DACDA proceeding (Proceeding 2683), which shows the

quantity and price of costs at the PPS and final costs stage and the variance for each cost item.

The RPG submitted that such a schedule should be provided for all projects.288 In addition, the

282


Exhibit 0002.00.AML-3585, Figure 7.5-1, PDF page 46. 284







58 • Decision 3585-D03-2016 (June 6, 2016)

RPG recommended that the Commission initiate a cost and performance audit on some or all of

the market escalation items identified in the schedule it provided in its evidence.289

280. In its rebuttal evidence, AltaLink referred to Section 7.5.1 of the application, which

explains the role of market conditions on the escalation that has occurred. It stated that the

American Association of Cost Engineering defines escalation as “changes in price levels driven

by underlying economic conditions.”290 As 70 to 80 per cent of all project costs are competitively

procured, the market sets the escalation that occurs between the PPS stage estimate and the final

cost of each project.291

281. AltaLink submitted that the following key factors should be considered when assessing

the escalation that has occurred in its direct assign projects:

AltaLink is obligated to build projects approved at the facility stage (which may be

changed at that stage).

Significant time may elapse between the PPS stage estimate and procurement of materials

and labour.

Escalation is the market price increase of materials and labour measured at the time the

materials and labour are procured and includes inflation and market supply and demand

conditions.

AltaLink has been found to have complied with all AESO procurement audits.292

282. As well, AltaLink explained that Alberta has had no trough periods for construction over

the last five years, as shown in Table 4 of its rebuttal evidence. As such, there was no optimal

time to build. Any deferral of projects would only have pushed projects into a different period of

heavy construction.

283. AltaLink further submitted that it has taken several steps to mitigate the effect of

escalation on project costs, which it had enumerated in AML-AUC-2015MAR05-026.293

284. In argument, AltaLink expressed concern that, throughout its evidence, the RPG referred

to any expenditures above the PPS stage estimate as a cost overrun,294 and suggested that

variances above projected costs are “a likely indicator of imprudence.”295

285. AltaLink referenced its evidence that it procured materials and services for its direct

assign projects in accordance with mandatory ISO rules and that the market set the escalation

between the PPS stage estimate and final costs. Further, it asserted that several projects identified

by the RPG were subjected to competitive procurement audits, pursuant to ISO Rule 9.1.5 and

except for one instance, the AESO audits found AltaLink to be compliant. For the one exception,

289



Exhibit 3585-X0704, paragraphs 100 and 101. 292



Exhibit 3585-X0666, paragraph 6, footnote 4, cited in Exhibit 3585-X0859, paragraph 118. 295

Exhibit 3585-X0666, paragraph 204, cited in Exhibit 3585-X0859, paragraph 118.


Decision 3585-D03-2016 (June 6, 2016) • 59

the AESO referred the matter to the Market Surveillance Administrator, who found no

contravention of the ISO rules.296

286. AltaLink also referred to the Commission’s findings in Decision 2013-407 in which the

Commission, describing a concern raised by the RPG that AltaLink and other TFOs could be

affecting the marketplace by trying to complete a large volume of direct assign projects within a

short period of time, stated that, in light of its system planning responsibilities under Section 17

of the Electric Utilities Act, it fell to the AESO to deal with concerns about how the volume of

projects affected the level of pricing obtained through competitive procurement.297

287. AltaLink argued that market escalation was a reasonable and legitimate explanation to

account for a variance between the PPS stage forecast and a project’s final cost.298 In addition to

the fact that costs increased due to market pricing obtained through competitive procurement that

was found to be compliant with ISO Rule 9.1.5, objective data confirmed that the market

experienced significant escalation in prices during 2012 and 2013.299 Information it provided in

response to information requests showed significant increases in North American wide

transmission facility construction that was forecast to peak in 2017,300 and a growth rate of

construction and engineering expenditures in Alberta well in excess of the Canadian average

over the period between 2009 and 2013.301

288. The RPG did not address escalation in argument, but provided a number of comments in

response to AltaLink’s argument on escalation related matters in its reply. It submitted that,

notwithstanding repetitive arguments about the extent to which its costs are competitively

procured and AltaLink’s explanations about the role of the AESO and the Market Surveillance

Administrator in the oversight of these costs,302 AltaLink had not provided sufficient evidence to

demonstrate that market escalation explains the deviations from PPS stage estimates that have

occurred.

289. The RPG noted that AltaLink’s reference to a passage from Decision 2013-407 in support

of its position, is referring to a suggestion made by the RPG in that proceeding that a market

survey should be undertaken. The RPG submitted that this recommendation is similar to an RPG

recommendation in the current proceeding that AltaLink should provide an accounting of the

prices and quantities components of observed variances between the PPS stage estimate and final

costs. The RPG submitted that it is reasonable to assume that AltaLink has access to this

information. Conversely, general attribution of cost variances to market escalation provided little

information about what has occurred.303

290. The RPG questioned AltaLink’s reliance on the competitive process. It noted that for

some projects, the response to specific tenders was very limited, and often the price difference

between the lowest priced tender and next lowest priced tender was significant. Given the large

spreads between bids received for some projects, there was cause to call into question whether

296


Exhibit 3585-X0859, paragraph 124, referencing Decision 2013-407, paragraphs 555-556. 298








60 • Decision 3585-D03-2016 (June 6, 2016)

there really was a competitive market for certain types of services acquired for specific

projects.304

291. The RPG that submitted an overheated market was just one plausible explanation for high

variances between forecasts and actuals. Another plausible explanation was that the market was

not working properly.305 Further, the AESO’s procurement rules only set a minimum standard but

do not establish a valid basis for concluding that a market procurement process was sufficiently

competitive to be used to conclude that the outcomes of the market can be deemed to be

prudent.306

292. The RPG further argued that AltaLink’s argument pointing to the state of the broader

markets within Alberta, Canada, and North America does not address whether specific project

variances can be attributed to market escalation.307

293. Given the above, the RPG again proposed a cost and performance audit on these cost

increases as a reasonable option for the Commission to consider. Alternatively, consistent with

the RPG’s view that the TFO bears the responsibility to justify the prudence of its decisions,

another valid option was to deny such costs, or a portion thereof.308

Commission findings

294. The Commission recognizes that the economic environment that prevailed in Alberta

during the 2012 and 2013 period was one is which there was rapid growth, and that this growth

was accompanied by various shortages and rapid price escalation. The transmission sector was

not immune to these effects, so it is not surprising that AltaLink would have experienced

significant price escalation within its sphere of operations.

295. The RPG raises several issues concerning such price escalation. These issues focus on

two main concerns. The first of these is that there is not enough evidence to conclude that the

increased costs that AltaLink experienced can be ascribed to market escalation. The second is

that markets were either not competitive or not working properly.

296. In terms of the market escalation concern, the question to be considered is why

AltaLink’s costs increased between the PPS stage estimates and final costs. Three possible

explanations are: (i) prices increased, (ii) quantities increased, or (iii) the particular commodities

or services that were purchased changed, which can be restated as “quality” increased.

Combinations of these three factors could also be an explanation of the observed cost increases.

297. The evidence does not indicate that either quantities or quality significantly increased.

The specifications for purchases identify quantity and quality, and these specifications are

reviewed by the AESO, included in the facility applications before the Commission, and any

subsequent changes are reported to the AESO as the project unfolds. For example, in the PPS

that was prepared by AltaLink for the AESO and that formed part of the facility application for

Heartland, AltaLink specified the number and types of towers that it proposed would be needed.

304







Decision 3585-D03-2016 (June 6, 2016) • 61

Although changes in these factors occurred in AltaLink’s transmission projects, in the

Commission’s view, these changes are insufficient to account for the extent of the cost increases.

298. The remaining factor to account for these increased costs is price increases, that is,

market escalation. The Commission accepts AltaLink’s explanation that price escalation was the

primary explanation for the cost increases that were observed, and does not require further

information to substantiate this conclusion.

299. A related concern is whether AltaLink and PowerAdvocate’s failure to fully recognize

and accurately anticipate the magnitude of the market escalation played any role in the eventual

size of the cost increases that were experienced. For example, faced with a higher degree of

uncertainty concerning the extent of price escalation, or in expectation of rapidly increasing

prices, AltaLink may have chosen to consider, and try to enter into, different types of contracts

for certain types of expenditures. Theoretically, such behaviour could help to ameliorate these

kinds of cost increases. Secondly, higher cost estimates at the PPS stage, that would likely have

resulted from better informed expectations of market escalation, could have led the AESO to

reconsider its decisions to proceed with particular projects, or to alter the proposed timeline for

project completion, again potentially lessening the cost increases that were ultimately

experienced. However, there is no reason to believe that AltaLink or PowerAdvocate had some

special ability during this period to predict price increases significantly better than other

organizations that faced the same challenges.

300. Turning to the concern that markets were either not competitive or not working properly,

it is not clear what evidence would support such a finding. The fact that market prices are high

does not mean that the market is not working properly or is not competitive. The market reflects

supply and demand, and if at any particular price the quantity demanded exceeds the quantity

supplied, then prices will rise. There is upward pressure on prices, usually culminating in price

increases. As noted previously, the period during which the construction was occurring was one

with very high demand and short supply, and in such an environment, prices would be expected

to increase quite dramatically regardless of the state of competitiveness of the market.

301. It is certainly possible, and indeed likely, that in a heated market, there are few suppliers,

or perhaps even only a single supplier, that are prepared to bid on a certain project. In such a

case, it is to be expected that there would be an absence of the pricing discipline that might be

expected to be evident with many competing suppliers. In this context, it is reasonable to

conclude that the market is not competitive. However, in such situations there is likely to be no

simple remedy that can quickly restore competitiveness. Rather, it is necessary to rely on, and

actively enforce, ISO rules concerning procurement practices that are in place to ensure

competition to the best extent possible in the circumstances, and for the procurer to make best

efforts to attract more bids. There is no evidence to suggest that these procedures were not

followed, and indeed evidence suggests that AltaLink made repeated efforts to generate more

competition.309 The majority of the labour and materials provided on a project were the result of a

tendering process that reflected unit price bids. In the event that AltaLink was unable to meet the

AESO’s tendering requirements of a minimum of three arm’s length suppliers, ISO Rule 9.1.5

required AltaLink to obtain an exemption from the AESO. Ultimately, the market procurement

309

Examples of this can be found in Exhibit X0327-WJ2, Exhibit X0327-BS4 and Exhibit X0327-Hansmans2,

all found on the confidential record.


62 • Decision 3585-D03-2016 (June 6, 2016)

process itself can be viewed as being as competitive as was possible in the circumstances, even

though this level of competitiveness might fall short of what would be ideal or even desirable.

The prices were reflective of this market. It is not possible to conclude therefore from the

outcomes of this process, and in particular from costs that embodied a higher than expected

degree of escalation, that the resulting expenditures were not prudently incurred.

302. An additional issue related to escalation concerns AltaLink’s reporting of cost changes to

the AESO. In comparison to accruing an allowance for escalation only in its PPS stage forecast,

and then subsequently only drawing down from this accrued balance as actual project costs are

incurred, AltaLink employs a different practice. In its response to AML-AUC-2015MAR-006(e),

AltaLink explained that in its reporting of project cost changes to the AESO, its practice is to

draw down from its estimated cost escalation before drawing down any amounts from each

project’s allowance for other contingencies or applying an upward revision to any other line item

of its project cost reports.310 AltaLink also indicated in its response to AML-AUC-2015MAR-

006(f), that it progressively updated its project cost escalation allowances.311

303. AltaLink’s practice, as described above, may hinder the AESO’s awareness of the extent

to which project costs are escalating. In the Commission’s assessment of prudence, this

consideration affects the weight that the Commission assigns to the oversight role that the AESO

carries out as part of the Commission’s prudence assessment.

304. The PowerAdvocate methodology adopted by AltaLink forecast a higher rate of project

cost change than earlier escalation forecasts derived using the Handy Whitman index.312

Accordingly, the transition from the Handy Whitman to the PowerAdvocate methodology would

have created a step change in the forecasts of projects that used the newer methodology. Making

a subsequent update to its allowance for project cost escalation changed the way in which project

cost changes would be reported to the AESO in accordance with processes outlined in ISO

Rule 9.1. Specifically, pursuant to ISO rules 9.1.3.2 and 9.1.3.4, TFO’s are required to provide a

change proposal to the AESO as and when the forecast cost of a direct assign project increases

by 10 per cent from the previously authorized project budget. Through its decision to make

ongoing updates to its project escalation allowances and applying the higher forecast provided by

PowerAdvocate, AltaLink would generally trigger a need for a change in the authorized budget

earlier than it would have if the escalation allowance is only populated initially and subsequently

drawn down. Conversely, after the effect of the escalation update is made, if it triggers the need

for a change proposal at that time, it follows that the need to make subsequent change proposals

triggered by 10 per cent changes from previously authorized budgets would be delayed, or may

not occur at all.

305. Last, the higher escalation rate produced by the PowerAdvocate methodology as

compared to the Handy Whitman methodology reflects, in part, the fact that the PowerAdvocate

methodology attempted to reflect factors driving the cost of transmission project inputs at a more

granular level. The Commission notes in particular, that the PowerAdvocate forecasts reflect an

310

Exhibit 3585-X0042, AML-AUC-2015MAR-006(e). 311

Exhibit 3585-X0042, AML-AUC-2015MAR-006(f). 312

Per AltaLink’s response to AML-AUC-2015MAR-006(a), which references an extract from AltaLink’s 2011-

2013, AltaLink forecast a blended escalation for capital projects of four per cent for 2013 and 2014. The

PowerAdvocate methodology utilized a methodology that resulted in a forecast compounded average growth

rate of 5.8 per cent.


Decision 3585-D03-2016 (June 6, 2016) • 63

explicit consideration of the effect of the constrained labour market within Alberta on the

expected cost of constructing transmission projects.313

306. In the Commission’s review of all of the change orders and monthly reporting included in

the current DACDA application, there is essentially no evidence that ISD targets were changed

to a later date at the instigation of the AESO. Given this, and given that the step change in the

escalation forecast represented by the switch to the PowerAdvocate methodology reflected an

assessment of the state of the Alberta market and was communicated to the AESO through

monthly reporting processes, it is reasonable to conclude that in not taking action to slow down

any of AltaLink’s projects, the AESO made a conscious decision to keep AltaLink’s direct

assign program moving ahead, notwithstanding the concern that the pace of the program may, in

part, be driving the market for project inputs.

307. Given the above, the Commission does not consider there to be a need to direct a cost and

performance audit as requested by the RPG.

4.1.12 Treatment of contingency allowances

308. AltaLink described the role of contingency allowances in Section 7.3.3 of the application

as follows:

Contingency is an amount added to an estimate to allow for conditions or events for

which the state, occurrence, or effect is uncertain and that experience shows will likely

result, in aggregate, in additional costs. Typically contingency is estimated using

statistical analysis and on project experience. The estimated contingency is similar to any

of the other line items that make up a cost estimate, budget or forecast, as they are

planned expenditures derived from the assessment of the project risks and similar to any

other line item are expected to be expended.

309. In its evidence, FTI submitted that contingency and escalation funds should have been

used to compensate SNC-ATP and its subcontractors for the foreseeable risks and tendered costs

in excess of PPS forecast amounts.314 FTI noted that the combined amount of contingency

allowances and escalation allowances for the CB and Heartland projects totalled $88 million and

$78.8 million, respectively. However, in accordance with FTI’s view that various iterations of

AltaLink’s Amended and Restated Exclusive Appointment Agreements with SNC-ATP required

it to offer a turn-key fixed price quote to AltaLink, FTI submitted that there was no justification

for AltaLink to approve change notices for cost increases well above the significant contingency

and escalation allowances built into the PPS stage estimates of total cost for the CB and

Heartland projects.

310. In its rebuttal evidence, AltaLink submitted that intervener claims with respect to

contingency allowances do not take into account the relationship between estimated

contingencies and actual costs. AltaLink explained how it calculated contingencies in response to

313




64 • Decision 3585-D03-2016 (June 6, 2016)

an IR.315 Regardless, discussions of contingency allowances were largely beside the point for a

DACDA proceeding, since any unused contingency does not become an actual cost.316

311. In argument, AltaLink submitted that as the matter at issue within a DACDA application

proceeding is the reasonableness of costs actually incurred, an estimate of a contingency that

may or may not be actually spent is irrelevant. If contingency funds are drawn, AltaLink noted

that the reasonableness of the drawdown will be considered within the assessment of actual

costs.317 Conversely, AltaLink noted that if contingency funds are not used, they do not become

an actual cost.318

Commission findings

312. FTI’s recommendation to limit the prudent amount of costs for the CB and Heartland

projects to the combined amount of allowances for escalation and contingencies set for each of

these projects is premised on its assertion that a fixed price obligation exists between AltaLink

and SNC-ATP. In Section 4.1.14.4, the Commission has rejected this premise. Accordingly, the

Commission also rejects FTI’s suggestion that the prudent amount of overages on the CB and

Heartland projects must be capped at the amount of the forecast escalation and contingency

allowances.

313. Notwithstanding the Commission’s finding above, in the course of the Commission’s

review of evidence in the current proceeding, the Commission observed that rather than establish

a contingency allowance at the outset, AltaLink routinely updates its contingency allowance

amounts during the execution of its projects, and includes the updated allowances as part of the

amounts of the increases in budget authorizations it has requested from the AESO in change

proposals.

314. To the extent that the updating of contingency allowance amounts has occurred,

AltaLink’s practice affects the visibility that the AESO may have regarding the overall project.

AltaLink’s Round Hill project (D.0267) represents an extreme example of this effect. Round Hill

was completed in a period of 10 months between the issuance of P&L.319 The initial contingency

was set at $5,219,000 in AltaLink’s PPS forecast. The contingency allowance was subsequently

increased by $856,527.320 In each case, the contingency allowance appears to have been based on

an allowance of 10 per cent of AltaLink’s forecast of incremental direct costs.

315

Exhibit 3585-X0042, response to AML-AUC-2015MAR05-014, cited at paragraph 106 of Exhibit 3585-

X0704. 316




Exhibit 3585-X0043, energizations Tab and Proceeding 1298, Permit and Licenses U2011-333, U2011-334,

U2011-346 and U2011-347 dated October 10, 2011. 320

Exhibit 0206.00.AML-3585, PDF page 44.


Decision 3585-D03-2016 (June 6, 2016) • 65

Table 2. Summary of Round Hill project contingency allowance updates

TCA# Change Proposal Date Contingency

Update Amount ($) Approved by

AESO

TCA01 September 29, 2011 200,815 Yes

TCA02 March 23, 2012 127,530 Yes

TCA03 March 23, 2012 334,259 Yes

TCA04 March 23, 2012 11,391 Yes

TCA05 March 23, 2012 0 Yes

TCA06 March 23, 2012 182,532 Yes

TCA07 March 29, 2012 (ISD) 0 Yes

Total 856,527

Source: Exhibit 0206.00.AML-3585, PDF pages 163, 167, 175, 179, 183, 186 and 380.

315. AltaLink’s monthly report to the AESO for the Round Hill project for November 2012

lists the authorized budget and forecast final cost for the project at $51,379,220 and $51,350,145

respectively. These figures are both well above the actual costs for the project as reported in

AltaLink’s revised final cost report dated November 6, 2013, which records actual costs of

$46,443,247.321

316. Because the forecast final cost of the project did not change to an amount approximating

the actual project’s costs until AltaLink’s January 2013 monthly report,322 it is reasonable to

conclude that the AESO may not have had a clear view of the overall project costs and approved

contingency allowance increase that may not have been necessary.

317. When assessing the prudence of a TFO’s capital project costs, one of the factors that the

Commission considers is the role that the AESO played during the project. Therefore, it is

important that the AESO have clear visibility regarding the project.

318. The Commission anticipates that, for future projects, AltaLink’s contingency allowance

forecasts can be improved by integrating them with further development of risk registers, as

discussed in Section 4.1.9 above. The Commission considers it to be a best practice to record

contingency allowance amounts separately from escalation allowances, and to include an

evaluation of risks and the potential effect on costs with the allowances requested. The

Commission further considers that the amount of the contingency allowance should be adjusted

over the life of the project as it becomes clear that identified risks, and associated cost effects are

no longer at risk of occurring.

4.1.13 Capitalized labour and E&S costs

319. The Commission, in Decision 2013-407, stated that it would test the prudence of labour

expenditures in AltaLink’s DACDA proceedings. In response to this direction, AltaLink

provided the following attachments in its application related to capitalized labour and

engineering and supervision (E&S) and general costs:

Attachment 2 – A Internal labour allocations for 2012 and 2013

Attachment 2 – B E&S Costs Allocated to Capital Projects

321

Exhibit 3585-X0043, Totals tab. 322



66 • Decision 3585-D03-2016 (June 6, 2016)

Attachment 2 – D 2011 Study of Directly Attributable Indirectly Charged (DAIC) Costs

320. AltaLink indicated that it was not seeking the approval for a specific number of full-time

equivalents (FTEs) but for further approval of its costs incurred.323

321. Intervener parties did not provide comments on the capitalized labour and E&S costs in

their argument or reply argument submissions.

Commission findings

322. In Decision 2013-407 the Commission stated:

86. AltaLink’s capital FTE levels for either 2013 or 2014 are not approved on either

a final or preliminary basis in this decision. The Commission tests the prudence of labour

expenditures recovered through direct assign projects in the context of future DACDA

proceedings. For all other types of capital expenditures undertaken by AltaLink, the

Commission tests the prudence of capitalized labour costs at the time final closing

balances for 2013 and 2014 capital additions are presented in the context of a future

AltaLink GTA.324

323. FTEs represent the allocation of one person’s or the accumulated allocation of many

persons charged time to a capital project, and forms the basis for AltaLink’s internal capital

labour costs charged to its capital projects. One measure of the prudence of capital labour costs

incurred on a project is the evaluation of the number of FTEs allocated to a project. The number

and types of FTEs, as well as the corresponding allocation of labour dollars and overheads may

indicate an under or over resourcing of a given project, which, in turn may assist the Commission

in the determination of whether the labour costs incurred are prudent.

324. Accordingly, AltaLink must support the FTE’s that make up the labour expenditures to

projects.

325. AltaLink in Attachment 2-D provided the purpose, methodology used, and the findings

from its DAIC study. When asked to provide the DAIC study in an information request,

AltaLink responded:

The “2011 DAIC Study” consists of a compilation of raw data, consisting of raw

numbers, internal nomenclature and abbreviated terms in an unformatted structure. To

convert the document for external use would require extensive rework. AltaLink is not

able to produce the information without significant effort from staff. As per paragraph

105 and 106 of AUC Decision 2011-453, AltaLink engaged in a thorough capital activity

review that was reviewed and approved by AltaLink’s external auditors. The Commission

agreed that AltaLink should be directed to file the results of any study at the time of the

Deferral Accounts Reconciliation Application proceeding. The results were provided as

Attachment 2-D.

326. During the oral hearing, AltaLink undertook to provide additional detail of its DAIC

study. In its undertaking response, AltaLink provided the raw data summary that was provided to

323

Exhibit 3585-X0859, page 37. 324

Decision 2013-407, paragraph 86 and Transcript, Volume 6, pages 1106-1107.


Decision 3585-D03-2016 (June 6, 2016) • 67

its auditors relating to the 36 employees used in the 2011 DAIC study. In addition, AltaLink

provided the number of FTE’s that were allocated to each direct assigned project.

327. In response to an IR to its undertaking response, AltaLink further acknowledged that the

auditors’ review was restricted to the DAIC methodology and process. It explained that this

process was accepted by the auditors, and they did not comment on the reasonableness of the

number of FTEs or costs that were charged to the E&S pool.325

328. The Commission finds that with the additional data provided relating to the DAIC study

in Attachment 2-D, AltaLink has now complied with the Commission directives set out in

Decision 2008-076326 and Decision 2011-453.

329. With regard to the Commission’s prudence assessment of the labour charges, the

Commission notes that AltaLink’s actual capital FTE’s, for 2012 and 2013, were lower than its

2012 and 2013 GTA forecasts, as shown in Table 3, and that its capital labour charges were in

line with the GTA forecasted amounts in 2012 and 2013, as shown in Table 4.

Table 3. Forecast versus actual FTEs

Forecast Actual

2012 (1) 2013 (2) 2012 (2) 2013 (3)

S.5-5 376.1 385.2 308.9 363.7

S.25-5 104.9 135.3 129.8 129.9

481.0 520.5 438.7 493.6

Source: (1) Decision 2013-023, schedules 5-5 and 25-5, (2) Decision 2014-258, schedules 5-5 and 25-5 and (3) Exhibit 0004.00.AML-3524

Table 4. AltaLink actual versus forecast labour costs

($ million)

ALP O&M

Labour

ALP

Capital Labour

ALP

Total Labour

Labour

included in DAIC

DAIC

labour as a % of capital labour

Total DA

CAPEX

DAIC

Labour as a % of DA

CAPEX

2011 GTA 33.5 56.6 90.1 24.7 43.7% 554 4.5%

2011 Actual 29.4 52.4 81.8 16.6 31.6% 578 2.9%

2012 GTA 35.0 60.4 95.4 28.1 46.6% 839 3.3%

2012 Actual 35.6 62.4 97.9 22.7 36.4% 867 2.6%

2013 GTA 40.1 71.3 111.4 26.8 37.6% 1464 1.8%

2013 Actual 39.9 74.0 113.9 27.8 37.6% 1682 1.7%

2014 GTA 44.5 80.2 124.7 30.4 37.9% 1672 1.8%

2014 MU 43.0 75.6 118.6 31.1 41.1% 1675 1.9%

Source: Exhibit 3585-0042, AML-AUC-2015MAR05-027(f).

325

Exhibit 3585-X0819, AML-AUC-2016JAN13-008. 326

Decision 2008-076: AltaLink Management Ltd., Reconciliation of Deferral Accounts, May 1, 2004 –

December 31, 2006, Proceeding 17, Application 1561334-1, August 26, 2008.


68 • Decision 3585-D03-2016 (June 6, 2016)

330. On the basis of this evidence, the Commission does not consider AltaLink’s labour

charged capital to be imprudent and approves AltaLink’s capitalized labour charges to direct

assigned projects as filed.

331. AltaLink, in response to an information request, stated that DAIC studies are performed

every two years in conjunction with AltaLink’s GTA.327 The Commission directs AltaLink to file

the DAIC study and underlying data in its 2017-2018 GTA filing.

4.1.14 EPCM agreement matters

332. In 2002, AltaLink entered into a 10-year agreement (the Master Services Agreement or

MSA) with its affiliate SNC-Lavalin ATP Inc. (SNC-ATP) whereby the affiliate became the sole

supplier of EPCM services to AltaLink for the direct assigned projects allocated to AltaLink by

the AESO. The MSA expired on April 30, 2012.328

333. Beginning with Decision 2007-012329 and continuing in Decision 2009-151330 and

Decision 2011-453, the Commission directed AltaLink to plan for the expiration of the MSA

and, in the event that AltaLink proceeded to continue to out-source its EPCM services, to ensure

that the process it followed resulted in prudent costs.

334. In Decision 2011-453, the Commission approved AltaLink’s proposal to use the pricing

in the MSA for projects that were underway through to project completion with inflation driven

costs to be escalated at the Alberta consumer price index.331

335. Further, the Commission stated in Decision 2011-453:

617. The Commission notes the comments of the CCA that the true competitiveness of

the CPP cannot be based only on the final result and that the fairness advisor must

confirm that based on criteria and standards used in the industry, that the process for

tendering, short listing and selection of an EPCM provider is competitive and that the

ranking of bids is fair, just and reasonable to ensure the transparency of the CPP. The

Commission considers that AltaLink must demonstrate that the competitive procurement

process and timing will be fair, open and transparent to the proponents and that the

resulting costs are prudent. Accordingly, the Commission considers that the prudence of

the CPP including the deliberations of the fairness advisor, the form of RFQ and RFP, the

transition provisions and costs and the costs resulting from the CPP will be assessed in

AltaLink’s next GTA.

327

Exhibit 3585-X0042, AML-AUC-2015MAR05-027(i). 328

The Commission recognizes that there are several documents ( the Exclusive Appointment of EPC/EPCM

Contractor Agreement between AltaLink and SNC-Lavalin Inc. (SLI), original, second and third restated, and

the Master Services Agreement, original and restated and the schedules to the Master Services Agreement)

that comprise the contractual relationship between AltaLink and SNC-ATP however, for ease of reference,

unless otherwise specified, these documents are collectively referenced as the MSA. 329

Decision 2007-012: AltaLink Management Ltd. / TransAlta Utilities Corporation, 2007/2008 TFO Tariff

Application, Application 1456797-1; AltaLink Management Ltd., Settlement of Self Insurance Reserve

Account for the Period, May 1, 2004 to December 31, 2005, Application 1468229-1, February 16, 2007. 330

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

Facility Owner Tariffs, Proceeding 102, Application 587092-1, Application 1594573-1, October 2, 2009. 331

Decision 2011-453, at paragraph 594.


Decision 3585-D03-2016 (June 6, 2016) • 69

336. AltaLink designed and conducted a three-stage competitive procurement process (CPP)

consisting of an RFQ, RFP, and negotiation phase that led to executing five-year contracts, with

a five year renewal, with two EPCM service providers, SNC-ATP and Burns and McDonnell

Canada Ltd. (B&M).

337. AltaLink’s CPP for its successor EPCM services was examined in AltaLink’s 2013-2014

GTA. In Decision 2013-407, the Commission found that AltaLink had not demonstrated the CPP

it followed had resulted in competitive rates but left it open to AltaLink in a subsequent DACDA

to provide further evidence to demonstrate that this was the case.

4.1.14.1 EPCM labour pricing under original SNC-ATP MSA

338. As stated above, the Commission approved the continued use of the MSA pricing for

projects during the transition period.

339. In this application, AltaLink has indicated that there are only five projects for which the

labour rates resulting from the CPP conducted by AltaLink for the EPCM services that were to

be provided by SNC-ATP and B&M were used. The other projects were charged under the terms

of the MSA.332

340. In its evidence, FTI noted that in Decision 2013-407, the Commission reaffirmed the use

of a two times multiplier as the basis for SNC-ATP labour charges.333 FTI further indicated that

as AltaLink had engaged an outside auditor to look at certain activities, and, as a consequence of

the auditor’s findings, FTI recommended that the Commission direct full scale cost and

performance audits, including an audit on the two times multiplier, on AltaLink’s direct assigned

projects in excess of $100 million.334

341. AltaLink filed confidential rebuttal evidence opposing FTI’s request on the basis that an

audit was unnecessary.

Commission findings

342. The Commission’s review of the audit suggests that the entire 2013 year was not audited

nor were the 2014 billings for the Heartland project. In the audit report, recommendations and

management responses were given. The completion dates for these recommendations were either

to be completed in 2014 or to be identified as requiring ongoing monitoring.

343. The Commission directs AltaLink to confirm in its compliance filing:

(a) Whether the audit included the entire 2013 year.

(b) Whether all billings related to the Heartland project in 2014 were audited.

344. The Commission further directs AltaLink to provide any audit follow-up reviews

performed to confirm whether these audit recommendations have been implemented, when they

were implemented, and what recommendations are still outstanding. AltaLink should also

332

Exhibit 3585-X0042, PDF379. 333

Exhibit 3585-X0667, PDF page 105, citing Decision 2013-407, paragraph 731. 334

The details regarding the audit and audit findings can be found on the confidential record.


70 • Decision 3585-D03-2016 (June 6, 2016)

identify any billing error amounts, whether any over or under billing amounts had been collected

from or paid to SNC and been applied to any of the projects in this application.

4.1.14.2 EPCM costs and competitive procurement processes

Introduction

345. As noted above, in Decision 2013-407 the Commission did not approve the labour rates

resulting from the CPP conducted by AltaLink but allowed AltaLink to file further evidence

demonstrating that the rates used reflected market competitive rates in its next DACDA. The

Commission stated:

733. The Commission expects that the expenditures made in furtherance of all these

projects will be subject to a future DACDA proceeding. At that time, AltaLink can

present further evidence with respect to what it considers market competitive rates. For

example, AltaLink could consider obtaining certification that the rates it negotiated with

B&M and SNC-ATP, respectively, are equal to or lower than the lowest rates each of

these EPCM providers offers to any other EPCM customer in North America, possibly

excluding regional or local jurisdictions with labour markets bearing little resemblance to

that of Alberta (viz., certification of AltaLink being offered “most favoured” or “most

preferred” customer pricing by each of its two EPCM providers). Alternatively, it

remains open to AltaLink, at any time, to design and conduct another competitive

procurement process taking care to avoid the shortcomings the Commission has

identified with the most recent CPP.335

346. In this proceeding AltaLink filed additional evidence to demonstrate that the rates

negotiated in the CPP were market competitive. It filed evidence prepared by PowerAdvocate

and RV & Associates (the Venerus evidence).336 AltaLink also filed undertaking responses

prepared by PowerAdvocate337 as well as an undertaking response containing letters from both

SNC-ATP and B&M with respect to their rates.338

347. The evidence of Mr. Venerus, a lawyer, whom AltaLink presented as an expert in

competitive bidding and procurement processes, often engaged by clients to design and evaluate

procurement processes, concluded that:339

(a) AltaLink designed and executed a CPP process pursuant to the applicable Canadian

procurement law and that the process chosen was optimal given the context, including the

aim of achieving competitive market rates.340

(b) The CPP reflected well understood standard procurement practices in Canada; including

the use of a multiple-step process that progressed from RFQ to RFP, through a

negotiation process.341

335

Decision 2013-407, paragraph 733. 336

Exhibit 3585-X0017, full report of RV & Associates and a redacted version of the PowerAdvocate report 337

Exhibits 3585-X0769 and 3585-X0792. 338

Exhibit 3585-X0770. 339


Exhibit 3585-X0017, paragraph 51, PDF page 52. 341

Exhibit 3585-X0017, paragraph 10, PDF page 42-43.


Decision 3585-D03-2016 (June 6, 2016) • 71

(c) Even though AltaLink’s process was non-binding, the CPP process met the stringent

common law requirements of fairness and openness/transparency.342

(d) Because the process was so well-designed, it had a high probability of leading to an

optimal supplier selection decision including finding the supplier that offered the best

value at market competitive rates.343

348. The Venerus evidence also considered whether AltaLink should have proceeded by way

of a binding tender process. In this regard, Mr. Venerus opined that “a tender process is too

inflexible and cumbersome to use in situations where requirements and the related evaluation

criteria are varied and complex (e.g. the acquisition of complex professional services.)” Rather,

“the flexible approach of non-binding RFP and negotiation processes is much better suited to

such circumstances.”344 In particular, the report determined that “the professional services that

were the subject of AltaLink’s CPP were far too complex (or in the case of future services,

simply too variable) to accurately describe in a tender.”345

349. The Venerus evidence specifically addressed the incumbent issue identified by the

Commission in Decision 2013-407 pointing out that a great many CPPs involve incumbents and

while incumbents may have a natural advantage given the additional information that they will

have as compared to their unfamiliar competitors, that did not automatically equate to unfairness

or bias.346 He also stated that a CPP should not be expressly designed to militate against

incumbent success as this would result in a blatant form of process bias impugnable by

incumbents.347 Rather, in assessing whether a pro-incumbent advantage exists, one is to look for

instances of “intentional unfairness” (as opposed to mere natural advantage).

350. Finally, in an IR response, Mr. Venerus confirmed that he found nothing to suggest any

unfairness in the CPP. Specifically, there was no suggestion that any proponent was denied

access to participate in the competition. Also all proponents appear to have received equal

information. Further there was nothing to suggest that AltaLink might have accepted some

proponent meetings and denied others, or responded to some proponent IRs and denied others.348

351. PowerAdvocate was engaged to perform a third-party analysis of the SNC-ATP and

B&M rates relative to the North American EPC market. In order to conduct that analysis,

PowerAdvocate analyzed the B&M and SNC-ATP rates individually by classification,

comparing each classification’s rate to the average North American rate.349 That resulted in a

percent difference between the contractor’s hourly rate and the average market rate for the

comparable classification. PowerAdvocate then aggregated these percentage differences into a

weighted average that would allow a comprehensive view of how the EPC rates compare to the

North American market as a whole.

342






Exhibit 3585-X0017 paragraph 72, PDF page 57. 348




72 • Decision 3585-D03-2016 (June 6, 2016)

352. Based on its analysis PowerAdvocate determined in its report that:

(a) The AltaLink rates are market competitive in Alberta.350

(b) The weighted average of both contractors’ rates were below the market average by

1.7 per cent.351

(c) None of the rates were above market norms on an analysis of the most billed

classifications (specifically 84 per cent of the total billed hours).352

(d) Two of SNC-ATP’s rates, (engineer and senior engineer) were significantly below

market average.353

(e) Eighty-two per cent of the total billed hours were at market rates, while 14 per cent of the

billed hours were below market rates. Only 4.1 per cent of total billed hours were above

market rates.354

(f) One hundred per cent of the engineering classifications, which account for a large bulk of

the billed hours and were the most expensive positions to hire, were within or lower than

market norms.355

(g) The EPCM rates negotiated by AltaLink were reasonable and market competitive.356

353. The PowerAdvocate report considered AltaLink’s relative position in the North American

market place as it was their opinion that “AltaLink must compete within this entire North

American market for EPCM contractors with the largest utilities on the continent.”357 In this

North American market place, PowerAdvocate concluded that AltaLink’s own capital

expenditure program accounts for less than two per cent of the market.358 In light of its relative

size, PowerAdvocate concluded that it would be difficult for AltaLink to negotiate work-volume

discount when in competition for services with much larger utilities with high volumes of

projects.359 In particular, PowerAdvocate stated:

With the size of the overall market dwarfing AltaLink’s own capital expenditures, in my

opinion it would be unreasonable to expect AltaLink to receive rates below market

average, as contractors can bid high when they do not need the work. My determination

is that market competitiveness in AltaLink’s case would be rates that are at market

average levels.360

350







Exhibit 3585-X0017. PDF page 3. 357




Exhibit 3585-X0017. PDF page 7.


Decision 3585-D03-2016 (June 6, 2016) • 73

354. PowerAdvocate explained in an IR response that the use of normalized market billing

rates allowed PowerAdvocate to compare AltaLink’s rates to a significantly higher number of

benchmark data points that better approximates the market conditions under which AltaLink

negotiated its EPCM contractor rates. PowerAdvocate ensured AltaLink’s rates were compared

to all other rates on a like to like basis by applying standardized classifications, jurisdiction and

time period adjustment factors and currency conversion.361

355. PowerAdvocate provided more detail on the jurisdictional adjustment factor that it

applied to the dataset used in its analysis. PowerAdvocate confirmed that the jurisdictional

adjustment factor accounts for the reality that construction firms work continentally; however,

they tailor their prices to charge local rates in order to account for variations in costs of doing

business in different locales.362 Further, PowerAdvocate provided all applicable jurisdiction

adjustment factors in the confidential module.363

356. In his oral testimony, Mr. Dorsey confirmed the scope of PowerAdvocate’s proprietary

database. Specifically, the PowerAdvocate database contains over 34,000 bid events with bids

from over 47,000 suppliers. Further, he explained that PowerAdvocate used 1,316 data points

across the different classifications364 and in his opinion, that was a sufficient sample size to use in

the analysis,365 and was “well beyond any areas of concern” on sample size.366 Mr. Dorsey also

confirmed in cross-examination that all data relied upon by PowerAdvocate in its analysis was

the result of competitive processes.367

357. Mr. Dorsey was questioned by the Commission about PowerAdvocate's choice to rely

upon billable hours for its market analysis by classification. He explained that the analysis could

be done based on expenditures of different classifications but that doing so would not be

consistent with PowerAdvocate’s common practice for market-rate analyses.368 As

PowerAdvocate was asked to determine the comparative rates, not the comparative expenditures,

expenditure weighting introduced a less relevant variable with which to weight the analysis

with.369

358. PowerAdvocate provided a confidential undertaking response in which it tested the

sensitivity of its analysis to changes in the level of the jurisdiction adjustment factor.

PowerAdvocate stated in the unredacted undertaking “this confirms our original conclusion that

AltaLink has obtained market competitive rates as a result of the CPP. Even in the extreme case

of 0% [jurisdiction adjustment factor], 76% of all classifications have rates at or below

market.”370

361

Exhibit 3585-X0517, AML-CCA-2015MAR05-031 (d)(ii). 362


Exhibit 3585-X0264-CONF. 364



Transcript, Volume 6, page 1059, line 5. 367

Transcript, Volume 6, page 1084, line 13. 368


Transcript, Volume, 6 page 1062. 370



74 • Decision 3585-D03-2016 (June 6, 2016)

359. PowerAdvocate also provided an analysis on an expenditure basis in response to a

confidential undertaking and that analysis had virtually no effect on the results.371

360. The RPG did not file any intervener evidence with respect to this issue nor did it

comment on this issue in either argument or reply.

361. In argument AltaLink explained that tenders are not viewed as the best process for

procurement of professional services or complex combinations of materials and services, where

the issuer tends to need more participation and creative input from suppliers in making the

optimal selection decision.372 AltaLink stated that in his report, Mr. Venerus addressed the

appropriateness of the process that AltaLink selected.

362. AltaLink maintained that a contract to provide EPC services must be assessed on the

same standard as any other contract or expenditure under consideration in a DACDA proceeding.

The Commission’s role remains to assess whether the rates obtained under the CPP are “just and

reasonable (i.e., prudent).”373 The focus of the inquiry is not whether the CPP resulted in the

lowest rates available, rather the question for consideration was whether the resulting rates are

market competitive.374

363. AltaLink explained that PowerAdvocate was recognized across North America as a

leading provider of market and cost intelligence to energy companies. PowerAdvocate maintains

a vast proprietary database compiled through customer engagements and bid processes to

provide accurate and unique analysis to its customers. That database includes labour rates for

capital projects in the energy sector. AltaLink noted that the Commission questioned whether the

application of the jurisdictional adjustment factor would eliminate cost advantages that should

exist.375 AltaLink stated Mr. Dorsey firmly rejected that assertion, confirming that firms will bid

what firms will bid based on local costs, home office costs, workloads, regulations: essentially

all costs including opportunity costs, risks and profit.376 As an example, a firm headquartered in

Kansas will not have a cost advantage over a firm in Alberta if the project is in Alberta because

the project cost drivers are tied to the Alberta (project) market and not the firm’s headquarter

jurisdiction.

364. In conclusion, AltaLink stated that it has done what the Commission requested of it. It

has provided expert evidence demonstrating that the rates AltaLink procured through its best

practice CPP are market competitive and in some cases below market.377

Commission findings

365. In Decision 2013-407, the Commission reviewed the CPP used by AltaLink to obtain

EPCM services from a new supplier(s) following the expiration of its 10 year exclusive service

agreement with SNC-ATP. The Commission examined the three phases of the process, RFQ,

RFP and negotiation phase, and heard testimony from AltaLink witnesses, including the fairness

371

Exhibit 3585-X0769-CONF, PDF page 1. 372

Exhibit 3585-0017, paragraph 20, PDF page 5. 373




Transcript, Volume 8, page 1368, line19 to page 1369, line 6. 377



Decision 3585-D03-2016 (June 6, 2016) • 75

advisor, KPMG, that AltaLink engaged to act as an independent advisor to the AltaLink CPP

team.

366. While the Commission determined that many issues raised by interveners respecting the

CPP followed were unsubstantiated, the Commission concluded that “there was insufficient

attention paid by AltaLink in being, and being seen to be, sufficiently objective and even-handed

in how it evaluated each participant on the merits as a potential future EPCM supplier at each

stage of the CPP process to dispel any reasonable apprehension that the CPP was not fair.”378

367. Specific matters that the Commission identified as problematic were:

The scoring mechanism was vague and allowed for overly subjective decisions on the

part of the evaluators.379

The failure to incorporate a greater degree of independent third-party evaluation.380

The process materially limited the number of viable, non-affiliated respondents.381

The scope and degree of external advisor participation was insufficient.382

Flaws in the negotiation process that reduced the incentive to make its best possible price

offer.383

368. The Venerus evidence principally focussed on the choice of process used by AltaLink.

For example, Mr. Venerus concluded that the CPP process reflected well understood standard

procurement processes that were compliant with Canadian procurement law requirements. While

the Commission does not question Mr. Venerus’ qualifications to provide this opinion, or his

findings that the CPP process followed legal competitive procurement requirements, the

Commission’s concerns with the CPP process followed by AltaLink were not focussed on

whether the CPP process met Canadian procurement law requirements or that it used a three

stage process of RFQ, RFP and negotiation rather than a tender process. The choice to use the

three stage process was never found by the Commission to be improper.

369. Rather, the Commission’s findings were based on its determination that the manner in

which the CPP process unfolded did not, in and of itself, demonstrate that market competitive

rates would necessarily result. Mr. Venerus’s evidence did not address the specific flaws

identified by the Commission in the decision. In testimony, Mr. Venerus acknowledged that:

You said " You said "many reasons and Commission requires them to do so." Were you

aware of any previous concerns the Commission had with the CPP process and

relationship agreements?

A. MR. VENERUS: Previous to what? The general tariff application?

Q. Previous to your involvement in this matter, sir?

378


Ibid., paragraph 682. 380

Ibid., paragraphs 689, 693 and710. 381



Ibid., paragraph 716.


76 • Decision 3585-D03-2016 (June 6, 2016)

A. MR. VENERUS: No.

…

Q. And in paragraph 6 of your record report, sir, it says your report does not address other

subjects including -- and I'm going to skip a few, to the last one -- health, safety, and

environment (HS&E) subject matter.

A. MR. VENERUS: I'm here as a procurement expert and not an expert in reservoir

models, nor pricing, nor construction project management, nor health and safety.

…

Q. And, sir, I note at the bottom you have paragraph 6, confidential rebuttal evidence of

KPMG filed in Proceeding 2044. Did you review any other confidential documents or

any part of the confidential record of that proceeding?

A. MR. VENERUS: I don't believe so, no.

…

Q. Just conceptually about the use of a flexible CPP process, is it your view that -- or

your understanding that the Commission was opposed to using such a process?

A. MR. VENERUS: Well, I did notice in the Commission's decision that the use of the

word "tender" occurred quite a lot, so I thought there might be a

predisposition or experience with tendering processes, as they are common with respect

to construction and utility work.

…

Q. All right. Expression aside, have you had much experience dealing with incumbents

who are also an affiliate and who are also, by virtue of them being affiliates, owned by

the same parent?

A. MR. VENERUS: No. But I would say that has nothing to do with the CPP process. It

should still run the same way.

Q. Okay.

A. MR. VENERUS: The key is consistency in the process. It's absolutely necessary for

fairness. You must have consistency.384

370. Mr. Venerus also opined that there was nothing wrong with including an incumbent in

the process. Again, the Commission never found that SNC-ATP should not have participated in

the process. To the contrary, the Commission stated:

734. The Commission would like to make a final observation. There was nothing

wrong or improper in having AltaLink’s affiliate, SNC-ATP, participate in the CPP

process or to be selected as one of the successful vendors. However, as AltaLink was

very much aware, the very fact of SNC-ATP’s participation in the CPP and emergence as

one of the winning vendors required that AltaLink demonstrate that the process was fair,

open and transparent to proponents and led to competitive market pricing. This was a

384

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Decision 3585-D03-2016 (June 6, 2016) • 77

demanding, but far from impossible, evidentiary burden. The Commission has concluded

that AltaLink has failed to meet this burden.

371. Considering the above limitations to the evidence presented by Mr. Venerus, the

Commission finds that this evidence is of little assistance in demonstrating that the rates

AltaLink negotiated with B&M and SNC-ATP are market competitive.

372. In terms of the EPCM report produced by PowerAdvocate, in general, the primary

purpose of the market-rate analysis that forms the basis of such reports is not to determine

whether particular rates are competitive in a wider market, but to help customers understand

where there are opportunities to generate savings. As Mr. Dorsey, the witness for

PowerAdvocate, stated:385

Again I think it’s important for me to clarify here when we typically do these market-rate

analyses, it’s to help our customers understand where there’s opportunity to drive

savings. It helps them prioritize their savings opportunities. And they rely on it.

373. In this context, the need for and use of jurisdiction adjustment factors is well understood.

As stated in the PowerAdvocate EPCM report, “PowerAdvocate’s market rate analysis compares

contractor rates to the North American market using aggregated and normalized billing rate

data.”386 Jurisdiction adjustments therefore allow contractors in one jurisdiction to understand

what they can bid in another jurisdiction and be competitive. As summarized by PowerAdvocate

in an undertaking response:387

It may help to think about the Jurisdictional Adjustment Factor as a ‘local currency’ for

each jurisdiction, to understand why it is imperative that this adjustment is performed. A

qualified bidder from a different jurisdiction with lower costs will not enter a higher cost

market and bid prices down to the lower cost associated with their home jurisdiction.

Rather they will bid as they consider appropriate to the pricing in the ‘local currency’ to

obtain and perform the work in that jurisdiction.

374. In terms of determining whether AltaLink’s EPCM contractor rates are competitive

within the North American market, the reason for, or usefulness of, a jurisdiction adjustment is

not as clear. Analysis conducted by the Commission, summarized in Appendix 5, indicates that

with the jurisdiction adjustment included, a comparison of billing rates in Alberta to other North

American jurisdictions hinges on two factors. The first of these factors is the percentage markup

or markdown of the wage for a particular job classification relative to the average engineering

wage in Alberta compared to other jurisdictions. Differences in this markup between

jurisdictions could, in large measure, be due to reasons other than competitiveness. Resolution of

this issue would require jurisdiction adjustments that differ for different job classifications, but

the PowerAdvocate jurisdiction adjustment is the same for all job classifications.

375. The second factor is the percentage loading that is applied to the wage rate to yield the

billing rate in Alberta compared to other North American jurisdictions. Again, differences in this

loading between jurisdictions could, in part, reflect reasons other than competitiveness, including

various mandatory employer payments in Canada, such as Employment Insurance premiums,

385

Transcript, Volume 8, page1394, lines 10-14. 386

Exhibit 3524-X0017, PDF page4. 387



78 • Decision 3585-D03-2016 (June 6, 2016)

Canada Pension Plan contributions, and Workers Compensation insurance premiums that may

differ within Canadian provinces and between the requirements in non-Canadian jurisdictions.

Resolution of this issue would require a different type of jurisdiction adjustment that would

apply to the loading factor, but such an adjustment could not be based simply on a ratio of the

loading factor in Alberta to the loading factor in another jurisdiction, as this would just have the

effect of removing the loading factors from the billing rate comparison, leading to a comparison

of wage rates instead. It is not immediately apparent how such a jurisdiction-based adjustment to

the loading factors, to account for the differences they embody that are not due to

competitiveness factors, could be determined.

376. With the jurisdiction adjustment excluded, a comparison of billing rates in Alberta to

other jurisdictions also hinges on two factors. The first of these factors is the wage rate for the

same job classification in the different jurisdictions. A lower wage rate in other jurisdictions

compared to Alberta would be indicative of a lack of competitiveness of the negotiated Alberta

rates. The second factor is the same as previously, that is, the percentage loading that is applied

to the wage rate to yield the billing rate.

377. A comparison of billing rates without the jurisdiction adjustment factor therefore suffers

from only one of the two drawbacks that accompanies a comparison using billing rates with the

jurisdiction adjustment included. However, there are two reasons why this drawback, namely

that differences in the loading applied to the wage rate to yield the billing rate could differ

between jurisdictions in part for reasons other than competitiveness, may not significantly

undermine the relative competitiveness comparison. First, certain components of the loading

factor that constitute mandatory employer payments in Canadian jurisdictions, such as

Employment Insurance and Canada Pension Plan contributions, are capped at maximum annual

amounts, although such caps may not apply to all other mandatory employer payments such as

Workers Compensation insurance premiums. Nevertheless, overall these components might be

expected to represent a relatively small share of the overall loading factor. Second, to the extent

that mandatory employer payments included in loading factors are expected to be higher in

Alberta than in U.S. jurisdictions, billing rates in other jurisdictions that are on average greater

than, or not significantly less than, billing rates in Alberta, would tend to provide persuasive

evidence that Alberta rates are competitive. On this basis, use of the billing rate comparison that

excludes the PowerAdvocate jurisdiction adjustment can be a helpful means of assessing the

relative competitiveness of AltaLink’s EPCM contractor rates within the North American

market.

378. PowerAdvocate has interpreted rates for any job classification to be market competitive if

they fall within one standard deviation of the average North American rate for that job

classification.388 In terms of the billing rate comparison that excludes the jurisdictional

adjustment, PowerAdvocate found that 76 per cent of all job classifications have rates at or

below market rates, that is, that they are market competitive.389 In view of the considerations and

limitations involved in a jurisdiction-adjustment-excluded billing rate comparison, as described

above, the Commission considers AltaLink’s EPCM contractor rates would be competitive

overall provided (i) that its rates are within one standard deviation of the North American

average for a large majority of job classifications, and (ii) that the overall weighted average of its

388

Exhibit 3524-X0017, PDF page8. 389



Decision 3585-D03-2016 (June 6, 2016) • 79

rates across job classifications are either below, or no more than 10 per cent above, the North

American average. Confidential analysis undertaken by PowerAdvocate in response to a

Commission request confirmed that these conditions are met.390

379. Last, the Commission has also taken into consideration the letters provided by B&M and

SNC-ATP on the confidential record which confirmed that AltaLink “has their lowest rates

amongst their client group”391 in response to the Commission’s suggestion in Decision 2013-407

that AltaLink “could consider obtaining certification that the rates it negotiated with B&M and

SNC-ATP, respectively, are equal to or lower than the lowest rates each of these EPCM

providers offers to any other EPCM customer in North America, possibly excluding regional or

local jurisdictions with labour markets bearing little resemblance to that of Alberta (viz.,

certification of AltaLink being offered “most favoured” or “most preferred” customer pricing by

each of its two EPCM providers)”392 and confirm that this is the case.

380. Having reviewed all of the further evidence presented by AltaLink, the Commission is

persuaded that the rates it negotiated with B&M and SNC-ATP reflect market competitive rates

for its EPCM services.

4.1.14.3 Risk Reward mechanism

381. In Decision 2013-407, the Commission found that AltaLink had not demonstrated the

reasonableness of including the costs of its risk reward mechanism in capital costs included in its

2013-2014 GTA, and directed AltaLink to remove any effect of the risk reward mechanism in its

refiling application pursuant to that decision.393

382. In Section 7.11.1 of the application,394 AltaLink sought the approval of the actions it

undertook with respect to the risk reward mechanism following the issuance of Decision

2013-407. Specifically, AltaLink sought the Commission’s approval of the following:

AltaLink discontinued the use of the risk and reward model on direct assign projects

commenced after the issuance of Decision 2013-407.

AltaLink continued to use the risk and reward mechanism to completion on projects

where it was agreed prior to Decision 2013-407.

AltaLink offered the use of the risk reward mechanism as an option to customers on a

project by project basis, and applied the risk reward mechanism if supported and agreed

to by the customer.

383. Further to above, AltaLink sought approval to continue using the risk reward

compensation scheme for the following projects included in its 2012-2013 DACDA:

Cherhill

Whitecourt

Black Spruce

390

Exhibit 3524-X0792 CONF, pages 7 and 16. 391




Exhibit 0002.00.AML-3585, paragraphs 134-137.


80 • Decision 3585-D03-2016 (June 6, 2016)

Tilley

Bruderheim395

384. In its evidence, the RPG submitted that beyond stating that it would be reasonable to

continue to apply the risk reward mechanism to projects that used this approach prior to the

issuance of Decision 2013-407, AltaLink did not otherwise justify this decision.396 The RPG

submitted that, given that the Commission found that the risk reward payment was not

reasonable, the fact that AltaLink initiated this program ahead of a Commission decision is not a

valid reason for why the costs incurred under this program should be considered prudent.397

385. Further, the RPG expressed concern that AltaLink had failed to provide visibility of its

actual payments for specific projects.398 Accordingly, the RPG submitted that the Commission

should require AltaLink to identify risk reward payments for each project where payment has

been made, and deduct any amounts so identified from its requested rate base addition

amounts.399

386. AltaLink addressed the RPG’s comments on its risk reward mechanism proposals in

Section XIII D of its rebuttal evidence.400 AltaLink submitted that the RPG’s interpretation of

Decision 2013-407 is incorrect. In particular, AltaLink noted that Commission findings on the

risk reward mechanism in that decision found that AltaLink should not include risk reward

mechanism payments in its 2013-2014 GTA direct assign capital forecast and that AltaLink was

directed, if necessary, to remove any effect of the mechanism within its 2013-2014 GTA refiling

application. AltaLink submitted that it had complied with the relevant Decision 2013-407

findings, both with respect to the 2013-2014 GTA refiling application, and with respect to its risk

reward forecast within its 2015-2016 GTA.401

387. AltaLink also explained that it had identified the projects using the risk reward

mechanism prior to the issuance of Decision 2013-407 in response to a Commission IR. It stated

that it has not included any risk reward mechanism payments for projects identified within the

2012-2013 DACDA. Instead, any risk reward mechanism payments will be included in future

DACDA applications as part of trailing costs for the projects identified in the current

application.402

388. In its argument,403 the RPG expressed concern that AltaLink had provided very little

visibility into the amounts of risk reward mechanism payments apart from indicating that it had

embedded the costs in contingency allowance amounts. The RPG submitted that as the total

395

Exhibit 0002.00.AML-3585, paragraph 136. In its response to AML-AUC-2015MAR05-023 (Exhibit 3585-

X0042), AltaLink clarified that the AltaLink project identified numbers to which the risk reward mechanism

has been applied are D.0435 (Cherhill 338S Substation), Project D.0395 (Whitecourt Industrial 364S

Substation Upgrade), Project D.0377 (Christina Lake Area Development - Black Spruce 154S), Project

D.0388 (Tilley 489S Transformer Upgrade Project); Project D.0393 (Bruderheim 127S Upgrade). 396





Exhibit 3585-X0704, pages 191-192. 401



The RPG addressed risk reward mechanism payments as part of its argument on trailing costs.


Decision 3585-D03-2016 (June 6, 2016) • 81

forecast contingency amount for the five risk reward mechanism projects identified by AltaLink

was approximately $4.9 million, the amount could be regarded as the maximum amount of the

disallowance that should be applied for risk reward mechanism payments.404 The RPG submitted

that the Commission should disallow these risk reward payments and submitted that they should

not be paid as trailing costs in a future DACDA application.405

389. In argument, AltaLink again stated that while it had used the risk reward mechanism on

five projects commenced prior to the issuance of Decision 2013-407, it has not included any risk

reward mechanism payments in the 2012-2013 DACDA application. AltaLink disagreed with the

suggestion in the RPG’s evidence that Decision 2013-407 findings mean that any costs AltaLink

has incurred for risk reward mechanism payments are necessarily imprudent. AltaLink submitted

that there was no finding of imprudence in that decision, nor could there have been.406

390. In its reply, the RPG again submitted that the inclusion of risk reward mechanism

payments within trailing costs is inappropriate. However, if AltaLink seeks reimbursement for

trailing costs, risk reward mechanism payments should be made explicit by including them in a

separate category of trailing costs, and should be fully supported.407

391. In reply, AltaLink again confirmed that any actual risk reward mechanism payments for

the five projects identified as being under that mechanism will be submitted as trailing costs

within a future DACDA application and expected that this matter will be addressed fully in

AltaLink’s next DACDA application proceeding.408

Commission findings

392. AltaLink’s initial presentation of its risk reward mechanism payments within the

contingency allowance line item for the projects, created some confusion among interveners in

this proceeding.

393. AltaLink subsequently clarified that no part of the requested capital additions amounts for

the designated risk reward mechanism projects included allowances for trailing costs.409

Accordingly, the Commission does not share the concern of the RPG in its intervener evidence

that AltaLink failed to provide visibility of its actual risk reward mechanism payments for

specific projects.410

394. In AltaLink’s 2013-2014 GTA proceeding, AltaLink indicated that because the risk

reward mechanism was meant to be implemented in conjunction with its CPP, it was not seeking

formal Commission approval of its mechanism. Notwithstanding, in Decision 2013-407, the

Commission provided its views regarding the risk reward mechanism in the event that AltaLink

may have wanted to incorporate it into future contractual negotiations.411 In these views, the

Commission explored the underlying rationale for the risk reward mechanism which, AltaLink

404








Decision 2013-407 paragraph 737.


82 • Decision 3585-D03-2016 (June 6, 2016)

had argued, was implemented in response to the request of customers to provide certainty around

target price and schedule. The Commission observed, however, that no customers or

representatives of customers supported the risk reward mechanism and that customer groups

appeared to oppose it.412 The Commission also determined that AltaLink failed to have

considered any other risk reward mechanism options prior to proposing the model in question.413

395. In the present proceeding, the Commission notes that while AltaLink has included a

stipulation that the customer must have supported and agreed to the use of the risk reward

mechanism, for all but one of the five projects identified, the only customer that has agreed to the

use of the mechanism is Fortis. As further discussed in Section 4.3.1, the Commission has

expressed concern that, due to the ability to flow through contributions on direct assign projects,

Fortis may not have the same incentive to control the cost of its direct assign connection projects

as might a direct connect customer of the AESO, because the direct connect customer may not be

able to pass on all or even some of these costs on to its customers. Accordingly, the Commission

has assigned little weight to AltaLink’s representation that the continued application of the risk

reward mechanism was supported by the customer where, in four out of the five cases, the

customer was Fortis.

396. In the present proceeding, apart from customer support, AltaLink’s only other rationale to

support its application of the risk reward mechanisms for the five projects AltaLink has

identified was that this arrangement had already started to apply before Decision 2013-407 had

been issued. This is not an acceptable reason to include these costs.

397. Accordingly, AltaLink’s request to be allowed to continue to use the risk and reward

mechanism to completion on projects where it was agreed prior to Decision 2013-407 is denied.

4.1.14.4 EPCM service provider obligation to provide fixed price

398. In the intervener evidence prepared by FTI414 (also referred to as the Tusa evidence),

Mr. Tusa assessed the nature of AltaLink’s MSA that established SNC-ATP, an affiliate of

SNC-Lavalin Inc.(SLI), as the exclusive provider of EPCM services for AltaLink.

399. Mr. Tusa found it remarkable that the initial MSA obligated SNC-ATP to provide

AltaLink with turn-key fixed price offers for performance of the work.415 He further claimed that

the second and third amended and restated agreements also required SNC-ATP to provide turn-

key fixed-price offers and submitted that AltaLink has not enforced these provisions nor has

AltaLink held SNC-ATP accountable to meet project unit prices as estimated by SNC-ATP and

presented to the AESO in AltaLink’s PPS filings.416

400. He further asserted that the CB and Heartland projects provided numerous examples

illustrating how AltaLink and SNC-ATP construed, administered and operated under the MSA

and other referenced contract documents to the detriment of ratepayers.417 Mr. Tusa claimed that

the PPS estimates, which according to his interpretation of the MSA terms, should have been

412



Exhibit 3585-X0667. 415





Decision 3585-D03-2016 (June 6, 2016) • 83

turn-key fixed-price offers, included large allowances for contingency and escalation for the CB

and Heartland projects and submitted AltaLink had not adequately justified why it approved

change notices for foreseeable risks that may have been encountered or for costs associated with

bid prices being above those estimated by SNC-ATP when SNC-ATP prepared the PPS.418

401. AltaLink addressed Mr. Tusa’s claim that the EPCM services were to be provided as a

turn-key fixed price in its rebuttal evidence. AltaLink explained that the process of deregulation

began in 1996 culminating in the passage of the Electric Utilities Act in substantially its current

form in 2003. During this development period, it was envisioned that transmission would be

competitively procured rather than direct assigned, as it is today. Under this premise, fixed price

bids would be required as the process contemplated was one of competitive fixed-price bids

where ownership of transmission lines would be determined through successful bids, as analyzed

by the Transmission Administrator.

402. The AESO, the direct assign process and the requirement of the provision of a PPS

estimate were not even in existence when the exclusive appointment agreement was first entered

into. Rather, the exclusive appointment agreement between AltaLink and SLI contemplated both

the provision of EPC services and the provision of a fixed price offer to respond to any bid

process initiated by the Transmission Administrator. However, on August 7, 2002, the

Government of Alberta decided to “suspend the competitive procurement process.”419 Shortly

thereafter, the AESO was created and the direct assign process established with the passage of

the 2003 Electric Utilities Act.

403. AltaLink stated that on April 30, 2002, it entered into the first MSA with SNC-ATP. The

provisions of the MSA provide for remuneration based on time and materials and did not require

a “fixed price offer.” AltaLink, since that time, has operated under an outsourcing model for

EPCM services and this outsourcing model for EPCM services has been explicitly before the

Commission and its predecessors on multiple occasions and to the best of AltaLink’s knowledge,

no party prior to FTI had ever advanced the erroneous interpretation now being asserted by Mr.

Tusa.

404. In argument, the RPG asserted that FTI had demonstrated in its evidence that the contract

documents impose an unreasonably low standard “for cost efficiency, cost control and

performance”420 that “virtually eliminates SNC-ATP’s obligation to control costs and greatly

reduces SNC-ATP’s responsibility”421 to perform work for a set price. The RPG also stated that,

as demonstrated by FTI, this state of affairs was contrary to the express terms of the initial and

various amended and restated exclusive appointment agreements between AML and SNC-

ATP/SLI, which originally provided that SLI, through SNC-ATP, would provide AML “with a

turn-key fixed price offer” when AML is making a submission (PPS) to the ISO.422

405. The RPG argued that the turn-key fixed-price provision first appeared in the initial

Exclusive Appointment Agreement dated December 8, 2001 and that this provision (Section 2.4)

appeared in both the Second Amended Exclusive Appointment Agreement and the Third (and

418


Proceeding 13898, Application 1336421-1, AltaLink argument refiling November 22, 2004, PDF page 138. 420





84 • Decision 3585-D03-2016 (June 6, 2016)

current) Amended and Restated Exclusive Appointment Agreement.423 The RPG argued that this

third agreement referred to the AESO, not the Transmission Administrator and, thus,

acknowledged the statutory changes made by the enactment of the Electric Utilities Act and the

Transmission Regulation. Further, the RPG noted that the Second Amended and Restated

Engineer, Procure and Construct Master Agreement referenced and incorporated, as a “Contract

Document,” the Exclusive Appointment Agreement. Therefore, the turn-key fixed-price

provision in the Exclusive Appointment Agreement was incorporated by reference in the MSA.424

406. In reply, AltaLink claimed that against the background of an agreement that is well

known to the Commission and changes that have been approved by the Commission several

times, the RPG in this proceeding raised, for the first time, an argument that a PPS was a ‘fixed

price’ estimate, to which AltaLink is required to hold SNC-ATP. AltaLink submitted this was

directly contrary to the multiple decisions of the Commission confirming the prudence of costs

incurred under the MSA on a time and materials basis. More importantly, the RPG had ignored

the actual words of the Exclusive Appointment, which provides alternatives, of which a

competitive bid process is but one.425 Where alternatives exist, AltaLink maintained it cannot be

mandatory that SLI, through SNC-ATP, provide only a turn-key fixed-price offer.

407. In reply, the RPG maintained that AltaLink never explained how the turn-key fixed-price

provision was inconsistent with the direct assign transmission model in Alberta. Nor did

AltaLink ever explain why, if it was superseded, it remained in the Exclusive Appointment

Agreement. The RPG suggested AltaLink was characterizing this issue as the Commission

having to choose between the turn-key fixed-price model and the time and materials model and

submitted the Commission was not required to make any such choice and that AltaLink had

completely overblown this dispute.

408. RPG stated that, what Mr. Tusa was effectively saying, was that, when a contract

(whether characterized as being turn-key fixed-price or time and materials) is awarded, there is a

contract price and construction contracts provide that the contract price cannot be exceeded

unless a change order is submitted and approved. Based on his review of all the documents, Mr.

Tusa concluded that there has been a failure on the part of SNC-ATP and AML to enforce their

contracts rigorously in the sense of properly assessing whether requested changes are in fact

eligible under the contracts. The RPG maintained the characterization of the contract was not the

point. The point was whether the particular changes should have been approved by AltaLink in

all the circumstances.

Commission findings

409. In his evidence, Mr. Tusa was asserting that the MSA obligated SLI to provide turn-key

fixed-price offers. However, in its rebuttal argument, the RPG appears to have backed away from

this position and is now asserting that Mr. Tusa’s concern was that, from his review of the

contractual provisions, he did not consider AltaLink to have demonstrated adequately why it had

approved the various change notices submitted by SNC-ATP. The Commission has addressed

this latter assertion in its findings in Section 4.1.14.5 below.

423





Decision 3585-D03-2016 (June 6, 2016) • 85

410. Turning to the question regarding whether there was an obligation for SNC-ATP to

“provide AML with turn-key fixed price offers to be included in AML’s submittals (e.g.) AML’s

Proposals to Provide Service) to the AESO in respect of any work program required by the ISO

relating to Facilities (e.g. direct assign projects),”426 the Commission concludes that there was no

obligation to do so.

411. The Commission, in arriving at this determination has done so considering the guidance

provided by the Alberta Court of Appeal in Omers Energy Inc. v. Alberta (Energy Resources

Conservation Board)427 in which the court stated at paragraphs 34 and 35:

[34] The search for the parties’ intentions is conducted on an objective basis. What the

parties believe their rights to be is not important, but what a reasonable person would

infer them to be from the words used: ATCO Electric Ltd v Alberta (Energy and Utilities

Board), 2004 ABCA 215 (CanLII), 361 AR 1. In ATCO, at para 77, Fraser CJA adopted

the language of Lord Hoffman in Jumbo King Ltd v Faithful Properties Ltd, [1999]

HKCFAR 279:

The construction of a document is not a game with words. It is an attempt to

discover what a reasonable person would have understood the parties to mean.

And this involves having regard, not merely to the individual words they have

used, but to the agreement as a whole, the factual and legal background against

which it was concluded and the practical objectives which it was intended to

achieve.

[35] Similarly, in Toll (FGCT) Pty Ltd v Alphapharm Pty Ltd, [2004] HCA 52,

(2004), 79 ALJR 129 the principle of objectivity by which the rights and liabilities of the

parties are to be determined was described at para 40 as follows:

It is not the subjective beliefs or understandings of the parties about their rights

and liabilities that govern their contractual relations. What matters is what each

party by words and conduct would have led a reasonable person in the position of

the other party to believe. References to the common intention of the parties to a

contract are to be understood as referring to what a reasonable person would

understand by the language in which the parties have expressed their agreement.

The meaning of the terms of a contractual document is to be determined by what

a reasonable person would have understood them to mean. That, normally,

requires consideration not only of the text, but also of the surrounding

circumstances known to the parties, and the purpose and object of the transaction.

412. The Commission accepts the evidence of AltaLink that at the time the Exclusive

Appointment agreement was entered into, the provisions for turn-key pricing found in the

agreement reflected an expectation that, at that time, transmission projects could have been

competitively tendered. With the passage of the Electric Utilities Act and the creation of the

direct assignment process, including the development of ISO rules and the regulatory NID and

facility processes, interpreting the contract in this manner; i.e., as if the MSA obligated SNC-

ATP to provide AltaLink with turn-key fixed-price offers for performance of the work, as

426


Omers Energy Inc. v. Alberta (Energy Resources Conservation Board) 2011 ABCA 251.


86 • Decision 3585-D03-2016 (June 6, 2016)

Mr. Tusa has done, would have produced an absurd result, which the Alberta Court of Appeal

has consistently indicated should be avoided when interpreting contracts.428

413. As well, the contractual terms in this agreement also permitted services to be provided

based on market rates in accordance with the MSA entered into between AltaLink and SNC-

ATP. It has been this latter MSA that has been relied upon by the parties to govern their

contractual relationship to provide services over the 10 years in which SNC-ATP was providing

these services.

414. The extent to which Mr. Tusa was qualified to make the assertions he did in his evidence

regarding the contractual relationship between AltaLink and its service provider and further, his

understanding of specific contractual provisions that he read in the contracts, and the weight to

be assigned to the consideration of his evidence was also a consideration in the Commission’s

findings on this issue.

415. Prior to the oral hearing, the Commission advised parties that it would not require parties

to qualify their witnesses as experts but that it remained open to parties to question the

qualifications of witnesses insofar as those qualifications would affect the weight to be assigned

to a particular witness’ opinion evidence.

416. During the oral hearing, counsel for AltaLink challenged Mr. Tusa on his qualifications

to assert the opinions he offered in his evidence regarding the contractual terms between

AltaLink and its EPCM provider. Mr. Tusa candidly admitted that he was not a lawyer, nor was

he qualified to provide a legal opinion regarding the contractual provisions he was opining about.

Rather, his qualifications to opine on the contractual relationship between AltaLink and SNC-

ATP were explained as follows:

Q: […] FTI has proposed a number of disallowances on the basis of its review of the

agreements entered into between SNC and various subcontractors and suppliers. AltaLink

takes issue with, one, FTI's qualifications to interpret these provisions. And we had

discussed a little bit the -- I have not, but Mr. Block has discussed with you this morning.

And two, FTI's failure to recognize a thorough legal analysis of the contractual terms, a

complete knowledge of the facts at the time, and the application of reasonable judgment.

And I do understand you have already testified that you're not a lawyer, but what I'd like

to know is -- can you please comment on your qualifications to

interpret these provisions.

A. MR. TUSA: Sure. I have worked in the field for -- I want to say -- 10, 15 years doing

technical analysis and project management on not only federal government jobs but other

private jobs that required reviews of change orders, multiple reviews of contract terms

and conditions over, you know, periods of time and multiple contracts that give me the

experience to look at these type of change and see if it meets the technical requirements

to perform a -- to undertake a technical analysis and come up with an answer as to

whether the cost associated with the scope change that's being asked for and its relevance

to the terms and conditions of the contract are actually applicable and reasonable to

increasing the contract price or incorporating that work.

428

See for example, Tien Lung Taekwon-Do Club v Lloyd's Underwriters, 2015 ABCA 46 at paragraph 23

discussing ambiguous language in an insurance policy.


Decision 3585-D03-2016 (June 6, 2016) • 87

So, for example, to conduct a technical analysis, what I've done in the past, and over my

career, is first examine the scope change that's being requested in the -- in the change

order; second, see how that description of work or justification of scope change meets the

terms and conditions of the contract; and then, lastly, evaluate the schedule and the cost

associated with the work to be done if it's in accordance with market prices or other types

of forward-priced agreements that may exist.429

417. The Commission agrees with the position of AltaLink that interpreting contractual

provisions under Canadian law is an exercise that requires the consideration of factors beyond

reference to specific provisions included in the contracts.

418. To the extent that FTI’s evidence relies on Mr. Tusa’s interpretation of contractual

provisions, the Commission finds that Mr. Tusa did not have the qualifications and background

to provide this type of interpretation.

419. For all of the above reasons, the Commission rejects the RPG’s assertion that SNC-

ATP/SLI were obligated to provide a fixed-price contract.

4.1.14.5 Enforcement of EPCM contractual obligations

420. In FTI’s evidence, Mr. Tusa suggested that in addition to not applying fixed-price offer

provisions in the MSA, AltaLink and SNC-ATP also deliberately set out to relax or eliminate

obligations imposed on SNC-ATP in the initial contracts that had been designed to constrain

costs to an agreed upon Project Contract Price. In this regard, FTI submitted AltaLink and SNC-

ATP had mutually agreed to lower SNC’s performance obligations through changes to

contractual provisions that were designed to place accountability on SNC-ATP to control costs in

accordance with PPS estimates.

421. Mr. Tusa submitted that to the extent that (1) the definition of Project Contract Price

permits the contract price to be exceeded without a change order, and to the extent that (2) a

clause in Attachment A1 to the template contract expressly clarifies that the Estimated Contract

Price is not a guarantee, as a starting point, the First Amended and Restated Engineer, Procure

and Construct Master Agreement could be regarded as a fairly loose agreement from the

standpoint of the EPC contractor. However, changes made to the Second Amended and Restated

Agreement further improved the position of SNC-ATP through (1) the addition of contract terms

that clarified that the initial project cost estimate would not be held as binding against SNC-ATP,

and (2) the fact that contract provisions governing changes to the contract price provides that if,

for any reason, the contractor believes that the forecast cost will exceed the Project Contract

Price, the contractor:

Must provide notice as soon as the change becomes known and at least 30 days before the

contract price will be exceeded.

Is obliged to continue work.

Cannot be paid beyond the Project Contract Price until it has complied with the article

governing amendments to the Project Contract Price.

429

Transcript, Volume 10, pages 1726-1727.


88 • Decision 3585-D03-2016 (June 6, 2016)

422. Mr. Tusa submitted that there are several instances where interactions between AltaLink

and SNC-ATP under the Second Amended agreement during the CB and Heartland projects

were applied to the detriment of ratepayers. In particular, he was concerned that:

Costs, especially in substation and transmission line labour categories, greatly exceeded

the initial cost estimates prepared by SNC-ATP.

AltaLink has generally only enforced the notice period obligations in the contract but has

not generally challenged the rationale for changes that SNC-ATP provided.

AltaLink had accepted change notices outside the required notice period in some

instances.

423. In addition, Mr. Tusa submitted that, in practice, AltaLink was applying a lower standard

for cost efficiency, cost control, and performance than the MSA permitted it to require from

SNC-ATP. He noted that these lower standards in the relationship between AltaLink and SNC-

ATP conflict with the fact that in the subcontracts SNC-ATP entered into with its service

providers, SNC-ATP subcontractors were held to higher standards. As an example of this, he

referred to a clause in a subcontract agreement that provided that, in the case of ambiguity, the

higher standard of performance would apply.

424. Mr. Tusa concluded that the contract documents had the effect of providing SNC-ATP

with an unreasonable latitude to amend the Project Contract Price though changes orders, change

notices and price adjustments. In particular, the arrangement effectively allowed the project

contract price to be a constantly evolving moving target. He submitted that the contractual

arrangements between SNC-ATP virtually eliminated SNC-ATP’s obligation to control costs. As

long as SNC-ATP provided timely notice, SNC-ATP could return to AltaLink with price

adjustments on an ongoing basis. He indicated that unlike this arrangement, typical industry

terms and conditions generally have provisions designed to create finality and cost certainty.

425. Mr. Tusa advised that his analysis concentrated on change notices and that he had

conducted an extensive review of the change notices for the CB and Heartland projects. He

submitted that based on his review of several contract agreements between SNC-ATP and its

subcontractors, there was evidence that AltaLink had approved a number of SNC-ATP change

notices for ineligible subcontractor costs that should be subject to back charges. He identified

several examples of contract or subcontract provisions that provided recourse to contractors that

he considered were not properly enforced, to the detriment of rate payers.

426. In its rebuttal evidence, AltaLink submitted that Mr. Tusa was not qualified to provide

legal opinions on the scope of contracts, and submitted that his legal arguments about both the

master services agreement and various subcontracts that SNC-ATP had entered into are

incorrect. AltaLink submitted that while there is no “correct” form of subcontract, regardless of

contract form, contractual terms are always inextricably linked to purchase price, with the effect

that transference of risk inevitably results in higher prices in compensation for risk.

427. AltaLink provided a response to each of the change notices430 assessed by Mr. Tusa in its

confidential evidence and submitted that Mr. Tusa’s analysis of back charges and contractual

430

Exhibit 3585-X0704, tabs 6 and 10.


Decision 3585-D03-2016 (June 6, 2016) • 89

remedies does not reflect a thorough legal analysis of contractual terms, a complete knowledge

of the facts in effect at the time of contract execution or reasonable judgment. Instead, AltaLink

submitted that Mr. Tusa used impermissible hindsight assessments to assert that certain costs or

charges were unjustified without understanding the particular facts in play at the time each

specific issue arose.

428. In argument, the RPG noted that, in general, Mr. Tusa concluded that the majority of the

changes giving rise to AltaLink’s increased costs were not supported by the contract documents

between SNC-ATP and its trade contractors and “were either not justified …, were not

accurately quantified, or not sufficiently supported by source documentation.”

429. The RPG stated that in all the thousands of pages of documents produced by AltaLink,

what was missing were original source documents that provided the necessary detail clearly

describing and explaining the amounts of the variances, the reasons for the variances and, most

importantly, why these variances (cost increases) should be accepted by AltaLink (and

subsequently passed on to ratepayers) instead of being the responsibility of AltaLink’s EPCM

service provider or its subcontractors. As was set out in FTI’s Confidential Report, the

fundamental, underlying problem with AltaLink’s application was that there was no evidence

that AltaLink ever critically appraised and questioned the cost increases that it was asked to

approve. Rather, it seemed to RPG that AltaLink unquestioningly approved whatever change

orders were placed before it, apparently to ensure that work on the project continued and to not

alienate or upset its EPCM service provider (and affiliate) SNC-ATP.

430. In argument, AltaLink stated it was not appropriate to fixate on a single matter and isolate

it from the broader context of project execution. There are a wide range of decisions that must be

made during project execution including contractual performance requirements, taking steps to

enforce contracts, whether or not change notices are appropriate, adjusting construction

schedules, making compromises in contested and potentially litigious situations, collecting or

settling outstanding claims for additional compensation and back charges, and assessing the

requirement of meeting an ISD for important system projects. AltaLink maintained none of this

is unusual nor was it unreasonable.

431. In addition, in its reply argument, AltaLink rejected claims that the majority of the

changes were not adequately justified or supported by source documents, noting it had filed on

the record the original change notices that specifically detailed the changes proposed, the basis

for those changes, and the costs involved in those changes. As well, it had provided on the

confidential record, among other things, RFP documents, bid analysis recommendations,

requests for proposals and purchase orders to support its costs. It further disputed Mr. Tusa’s

statement that there were no emails included in the change notices. It referred to the numerous

emails included in the change notice records, including Exhibit 3585-X0380c-3-CONF, PDF

page 94 and Exhibit 3585-X0380c-CONF, PDF page 200 which included emails that provided

context around the change notices being advanced. Similarly, there were a number of instances

in the record of the bottom-up detail that Mr. Tusa indicated he had not seen in relation to the

change notices. A number of change notices had attached invoices, standby logs, field tickets and

daily timesheets, among other things. AltaLink stated that this was the most granular level of

bottom-up detail available and was available to Mr. Tusa had he chosen to review all the records.


90 • Decision 3585-D03-2016 (June 6, 2016)

Commission findings

432. Mr. Tusa asserted in his evidence that AltaLink and SNC-ATP have deliberately entered

into contractual arrangements that have eliminated any cost consequences to SNC-ATP and

further, that based upon his review of the change notices for the CB and Heartland projects,

AltaLink has failed to enforce the contractual remedies that it did have available as against SNC-

ATP and instead, simply managed the project to ensure that change notices were submitted in a

timely fashion in accordance with the contractual terms.

433. With regard to the assertion that AltaLink has deliberately altered the provisions of the

EPCM agreements with SNC-ATP to minimize or eliminate any cost responsibilities of SNC-

ATP, the Commission does not find, based on its review of the amendments to the MSAs that

there is any evidence to support this assertion.

434. With regard to the assertion made that AltaLink has not provided evidence to justify the

change notices that it approved, the Commission does not agree. The evidence in question runs

into the thousands of pages and the Commission has reviewed all of it. In its review, the

Commission came across numerous cases where the change was supported by extra work

requests, labour, equipment and material, time sheets, correspondence from subcontractors,

emails or other items detailing the need for the change.

435. The RPG has also stated that there is no evidence to indicate that AltaLink ever

questioned any of the proposed changes. Again, the Commission does not agree. In its review of

the evidence, the Commission came across instances where there were email chains questioning

the need and/or the proposed cost of the change.431

436. The Commission has also identified certain flaws arising from Mr. Tusa’s analysis and

exclusive reliance on change notices. A change notice does not necessarily translate into a

payment to a contractor. For example, a change notice related to a subcontract amendment

included an incentive amount.432 The incentive payment was not paid as documented in the

subcontract amendment. Mr. Tusa’s evidence requested a disallowance for the entire amount of

the initial change notice, which is not supported since the incentive amount was not paid. In

addition, Mr. Tusa’s focus on change notices did not capture other changes in costs identified on

subcontract amendments when these changes were not processed through a change notice. This

was the case, for example, in several large amendments processed for RS Line on the CB

project.433

437. As well, AltaLink provided the purchase order/contract logs for the CB and Heartland

projects. In most cases, the amounts shown on these documents appear to tie into the amounts

actually paid to vendors, but not always.

438. In the Commission’s view, the only reliable way to ensure that all payments to

contractors are examined is to review the subcontract amendments. For the CB and Heartland

projects, these were supplied in response to IR CCA-AML-038(a)17. The Commission has

431

Examples include: Exhibit 3585-X0380-c3 CONF, pages 91-98, pages 388-393, pages 440-445 and Exhibit

3585-X0380-c CONF pages 195-204. 432

CN 112 in Exhibit 3585-X0380-d-1 CONF, page 177 ties to Subcontract Amendments 6 and 9 in Exhibit

3585-X0382 CONF documents 396 and 399 in folder C 35. 433

Exhibit 3585-X0382, IR response CCA-AML-038(a)17.


Decision 3585-D03-2016 (June 6, 2016) • 91

reviewed them all and its specific findings regarding the prudence of these costs for the CB and

Heartland projects are set out in its analysis of the specific projects in Section 4.2 of this

decision.

439. The extent to which Mr. Tusa was qualified to make the assertions he did in his evidence

regarding his understanding of specific contractual provisions that he read, including the

contractual enforcement provisions and the weight to be assigned to his evidence, was also a

consideration in the Commission’s findings on this issue.

440. To the extent that FTI’s evidence on these matters relies on Mr. Tusa’s understanding of

the legal operation of the contractual relationship, the Commission finds that Mr. Tusa did not

have the relevant qualifications and background to provide this type of interpretation.

441. For all of the above reasons, the Commission rejects the RPG’s assertions that AltaLink

has deliberately altered its contractual provisions to avoid controlling costs or that based on

Mr. Tusa’s review of the change notices for the CB and Heartland projects, AltaLink has

generally failed to enforce contractual remedies available to it.

4.1.14.6 EPCM agreement contracted material/contracted labour surcharges

442. Under the terms of AltaLink’s MSA, SNC-ATP is authorized to charge four per cent on

subcontracted labour and three per cent on materials.

443. The Commission questioned AltaLink regarding the nature of the relationship AltaLink

had with SNC-ATP and the services that SNC-ATP provided to AltaLink to support this charge.

As part of this questioning, AltaLink was provided with past evidence that it had provided to the

Commission regarding the nature of this relationship. These materials were identified as AUC

aid to examination No. 1 and aid to examination No. 2.

444. Aid to examination No. 1 was an extract from Decision 2013-407 in respect of

AltaLink’s 2013-2014 GTA and 2010-2011 DACDA application (Proceeding 2044) and is

reproduced, in part, below:

1292. In particular, the Commission notes that there were 80 instances of band member

intervention on the First Nations portion of the route, with an estimated cost of $8 million

for standby charges. In addition to this, the EPCM contractor was paid a four per cent fee

during the period that the construction crews were not working. The Commission would

expect that any management time spent in planning the re-allocation of crews would be

compensated for in the charges for such management time. The following exchange is

informative.

Q. -- rounding around and so times the $100,000 by 80, the

14 $8 million figure is more accurate. SNC would have received

15 4 percent of that $8 million, and that would be a cost on top

16 of the 8 million?

17 A. MS. PICARD-THOMPSON: It would be appear that we

18 can't do engineering math that quickly. But SNC would have

19 gotten the markup on that. That's correct. And I believe

20 it's in the order of $32,000. I was having my figures

21 checked just in case.

22 Q. So I can -- you know, I guess I can see that there might

23 have been ongoing construction management at the time of


92 • Decision 3585-D03-2016 (June 6, 2016)

24 these shutdowns, but I guess I have to question what

25 construction was going on at the time of the shutdowns?

00423

1 A. MS. PICARD-THOMPSON: In actual fact, sir, that is

2 actually when there is more activity because clearly the

3 construction managers are trying to figure out how to

4 reposition the crews, trying to look for alternatives. So

5 you kind of work doubly hard when you actually have a

6 slowdown or something that's occurring. You're trying to

7 manage and mitigate the risks.

8 Q. And that's why you get paid --

9 A. MS. PICARD-THOMPSON: To manage the contract.

10 Q. -- for every hour you spend doing construction

11 management.

12 My question is: Why would you get a markup on

13 construction labour when there is no construction labour

14 because there's a shutdown?

15 A. MS. PICARD-THOMPSON: Again, sir, it is the terms of

16 the contract, and that is the way the contract is designed.

17 Q. Actually, then, the more the work crews literally spin

18 their wheels in the mud, the more SNC makes; yes?

19 A. MS. PICARD-THOMPSON: Sir, I don't believe that that

20 inference is a proper inference.[emphasis added]

445. AUC aid to examination No. 2434 was an extract from AltaLink’s reply argument from the

proceeding that considered AltaLink’s 2007-2008 GTA.435 In that proceeding, IPCAA, through

its witness, Mr. Devine, had challenged the appropriateness and need for these charges.

446. In response to questioning, AltaLink’s witnesses testified:

A. MS. PICARD-THOMPSON: Yes. What I was saying is that -- and I appreciate after

reading it after the fact that perhaps people really didn't get a full appreciation of what the

EPC contract structure is. However, there is a component in the EPC contract for

construction management fees, and it is exactly that, that the work that SNC endeavours

to do as our construction managers is what it is we're paying them to do.

So in this case, I guess some level of confusion relative to well, if people weren't

working, why are they getting paid? And what I was endeavouring to say is well, it is

because they are actually managing this event. That is actual work that they're doing to

try to work around and schedule the construction crews to work around this issue that

occurred. So it is truly their management work and time to deal with the issue that we're

paying.

…

A. MS. PICARD-THOMPSON: And I think you see that if you look at the aid to cross

No. 2, which I think you'll come to next, which there is a management fee for the work

that is done to manage construction, there's a management fee for the work that is done to

procure the material, and that is -- in that, of course, is the risk they take to do those roles.

434

Exhibit 3585-X0757. 435

Proceeding 15584, Application 1468229-1.


Decision 3585-D03-2016 (June 6, 2016) • 93

And then, of course, they would have then their billable hours in the case of the MSA as

well.

Q. Right. So I'm just trying to make sure I understand this: It's an automatic surcharge,

right, on the labour contracts, for specific contracts, is a 4 percent on top of the labour

contracts?

A. MS. PICARD-THOMPSON: That's correct.

Q. Right.

A. MS. PICARD-THOMPSON: Because they're taking the contract and taking the risk

on managing the contract.

Q. Right. So any labour contract, it's 4 percent on whatever that is?

A. MR. FEDORCHUK: Yes, Ms. Wall, specific to the construction portion of the

subcontracts.

…

A. MR. FEDORCHUK: Yeah. So, in this case, SNC has a subcontract for ... whatever,

'X', and it's at $100 for that subcontracted amount, there's 4 percent applied to the $100.

A. MS. PICARD-THOMPSON: And that is pretty typical, Ms. Wall. Like, there's no --

there's no uniqueness here, that's actually quite industry standard in terms

of having a management fee on construction and one on procurement as well, and then

the engineering is dealt with separately.

Q. Right. Now, when AltaLink is looking at the charges they're getting from SNC -- and

I'm just talking about this management charge, not the actual engineering work that's

charged differently -- do you look and see, okay -- are you looking at the level or quality

of performance of SNC and how they're managing it or is it just, okay, that's the deal, 4

percent and it's just added on?

A. MS. PICARD-THOMPSON: Yeah, I would say it's definitely not a rubber stamp, it's

not just a "take it for granted." There is definitely a review of the work

that they do and there is definitely a questioning of the work or the invoicing that occurs

if we're not satisfied with a certain element of the invoice.436

447. As a follow-up to this questioning, AltaLink gave an undertaking to provide an example

illustrating where AltaLink has questioned the four per cent management fee. The undertaking

response437 indicated:

AltaLink either accepts or rejects change orders from EPCs, as indicated in the transcript.

With respect to construction work if AltaLink declines a change order, the EPC does not

receive a construction management fee.

436

Transcript, Volume 6, page 1088, lines 6-22; page 1089, lines 2-22; page 1090, line 7 to page 1091, line 5. 437

Exhibit 3585-X0771.


94 • Decision 3585-D03-2016 (June 6, 2016)

There is no example on the record where the EPC was not paid the 4 percent management

fee for the construction work completed within the contracted construction scope of the

project.

448. In its argument, AltaLink submitted that management fees should be considered

reasonable because they reflect the fact that, by entering into contracts with subcontractors,

SNC-ATP takes on all associated material, safety, environmental, legal, and carrying cost

risks.438

Commission findings

449. In addition to out-sourcing the engineering requirements for its direct assigned capital

projects, AltaLink has also chosen to out-source the management of the execution of these

projects in respect of the procurement of labour and materials. The price charged for this service

is a percentage markup on every invoice submitted to AltaLink by SNC-ATP for payment. This

is a management decision that AltaLink is entitled to make.

450. It was AltaLink’s evidence that it examines the work performed by SNC-ATP to justify

the management charge on the invoices. However it was unable to produce evidence

demonstrating an example of not accepting the automatic percentage markup following its

review of the work performed.

451. Regardless of the contractual arrangement between AltaLink and SNC-ATP, AltaLink

remains responsible for ensuring that all the costs incurred on a project are prudent. When

services are out-sourced, AltaLink must demonstrate that adequate services are being provided

for the charges AltaLink is approving. In its review of the costs incurred on the projects in this

proceeding. the Commission has considered both the services provided by SNC-ATP and

whether it was reasonable, in all circumstances, to apply the management fee automatically to

every invoice that AltaLink processed.

452. The Commission’s specific findings regarding the prudence of the management fee

services for the CB and Heartland projects are set out in its analysis of these specific projects in

Section 4.2 of this decision.

4.1.15 Treatment of accruals

453. In the intervener evidence submitted by FTI, Mr. Tusa stated that he had examined the

transactions listed in AltaLink’s accrued cost report as produced in response to AML-CCA-

2015MAR05-006 and compared the reported accrued cost transactions with the cost accrual

transactions listed in AltaLink’s general ledgers for the CB and Heartland projects. He explained

that FTI had converted AltaLink’s hardcopy response into a functioning excel spreadsheet for

purposes of its review and analysis.

454. FTI provided tables illustrating the results of its analysis of the general ledger datasets for

the CB and Heartland projects, as well as a table listing the accrual amounts for the other projects

being examined in the proceeding. Mr. Tusa stated that while AltaLink had confirmed that none

of the amounts in the accruals were estimates, he remained concerned that the accruals were

overstated and, for the CB project, may have belonged to another project. He also noted

438



Decision 3585-D03-2016 (June 6, 2016) • 95

significant accrued amounts were not fully reversed out of the Heartland accrual account.

Consequently, relying on the Commission’s ruling in Decision 2014-283 that accruals should not

be allowed, he submitted that all accrued amounts outstanding at the end of 2013 be deducted

from rate base.

455. In its rebuttal evidence, AltaLink explained that with respect to the amounts in its accrual

accounts that the work has been done, the project managers are aware of the work that has been

done and an estimate of the associated costs had been prepared and reviewed by knowledgeable

individuals. In addition, AltaLink stated it had provided evidence that the costs incurred have

been paid in the subsequent period.

456. AltaLink maintained that actual costs of $42,262,738 were incurred in 2013 and properly

recorded in AltaLink’s accounting records in that year in accordance with external financial

reporting requirements (IFRS), as well as regulatory accounting principles that have been

accepted by this Commission and its predecessor in prior DACDA decisions. AltaLink also

stated that for the purpose of calculating allowance for funds used during construction (AFUDC),

and its temporary replacement, construction work in progress (CWIP) in rate base, AltaLink

followed the specific directions of the Commission and deducted accruals when calculating these

revenue items.

457. In argument, the RPG reiterated its concerns that significant estimated costs remained in

the accrual accounts for the projects being examined and the RPG continued to request their

removal from rate base.

458. In argument, AltaLink asserted that it had provided evidence that the costs incurred have

been paid in the subsequent period and maintained that it was appropriate to include the actual

costs incurred, which includes accruals, given the fundamental accounting principle (the

matching principle) of recognizing and recording expenses contemporaneously with the period in

which they were incurred.

459. In reply the RPG noted that AltaLink claimed that cost accounting required costs to be

recognized when they were incurred, not paid. RPG continued to question why, however, the

costs continued to appear in AltaLink’s accrual account if the costs had been incurred.

Commission findings

460. The Commission understands AltaLink’s position to be that the amounts in the accrual

accounts represent invoices from subcontractors for work completed prior to the end of 2013 or

2014, but which were received after the close of AltaLink’s accounts payable system for the

respective fiscal year. Because AltaLink is not able to post the invoices to the accounts payable

system, it has posted the invoices to accrual accounts. AltaLink has further asserted that the

invoices were actually paid in the following fiscal year.

461. The Commission accepts that it is a common accounting practice for invoices to be

received after the close of the accounts payable system during a fiscal year end. These invoices

are then recorded in an accrual account. The only way to verify completely that the amounts in

question are actuals related to the fiscal year in question would be to perform an audit of the

accruals and the documents supporting the individual accruals. The Commission considers this

would be unnecessary and impractical. The accruals would have been audited by AltaLink’s

external auditor as part of the year end audits in question. The Commission is therefore willing to


96 • Decision 3585-D03-2016 (June 6, 2016)

accept the auditor’s reports and AltaLink’s assertion in the IR response that the accruals recorded

related to actual expenses incurred in that year as sufficient evidence as to their accuracy.

462. For reassurance to the RPG and the Commission that the accruals in question do relate to

actual expenses for the fiscal year in which they have been recorded, the Commission directs

AltaLink to provide a certification, signed by its chief financial officer, stating that the accruals

recorded for the years ending December 31, 2012, December 31, 2013, and December 31, 2014,

related to expenses actually incurred in the respective year they were recorded and did not

represent estimates. As it would be a serious breach of the chief financial officer’s professional

ethics to sign a document he did not believe to be true the Commission considers such a

certification would provide satisfactory evidence as to the accuracy of the accrual amounts. The

Commission also notes that the accruals would have been subject to review by AltaLink’s

external auditors during the conduct of the year-end audit.

4.1.16 Line optimization and design issues

463. AltaLink’s application requested approval of the costs of five 240-kV projects: CB,

Hanna-Nilrem, Hanna Region Hansman Lake, Hanna Region Ware, and the Castle Rock Ridge

Wind Farm Interconnection all of which used the new 240-kV double circuit tower family

designed to meet ISO Rule 502.2.

464. At the time these projects were commenced, the functional specifications for these 240-

kV projects did not list ISO Rule 502.2 as a standard but rather required that the designs meet the

Technical Requirement (Part 3) for Connecting Transmission Facilities (dated December 2,

1999)439 440 with the exception of Castle Rock Ridge Wind Farm Interconnection which was

revised on July 19, 2011. to include ISO Rule 502.2 External Consultation Draft Version 3.0

(dated April 28, 2011).

465. In addition, the functional specifications for the CB, Hanna – Nilrem, Hanna –Hasman

Lake and Hanna – Ware Junction specified the bundled conductors that were to be used for the

projects441 and, in the PPS submissions for the 240-kV projects, AltaLink stated that its intention

to use the new 240-kV double circuit tower family under development (which was designed to

meet the proposed ISO Rule 502.2) to carry the specified conductors.442

466. The CCA and the RPG filed the Grid Power report,443 objecting to AltaLink’s decision to

use the R22 double circuit lattice tower families for these five 240-kV projects on the basis that

439

ESBI Technical Requirements for Connecting to the Alberta Interconnected Electric (IES) Transmission

System: Part 3 Technical Requirements for Connecting Transmission Facilities. 440

This standard is listed in the functional specifications found in the following exhibits: CB in Exhibit

0023.00.AML-3585 at PDF page 7, Hanna Area Transmission Development projects (Hansman, Ware and

Nilrem) in Exhibit 0046.00.SML-3585 at PDF page 8. The standards listed in the functional specification for

the Castle Rock Ridge project can be found in Exhibit 0035.00.AML-3585 at PDF page 8. 441

Exhibit 3585-X0665, PDF page 7, Table 1. 442

The proposed structure type that AltaLink intended to use can be found in the following exhibits: Exhibit

0018.00.AML-3585 at PDF page 16 (Cassils-Bowmanton), Exhibit 0030.00.AML-3585 at PDF page 13

(Castle Rock Ridge Wind Farm Interconnection), Exhibit 0041.00.AML-3585 at PDF page 10 (Hanna Region

– Hansman Lake), Exhibit 0052.00.AML-3585 at PDF page 15 (Hanna Region – Nilrem) and Exhibit

0064.00.AML-3585 at PDF page 13 (Hanna Region – Ware). 443

Exhibit 3585-X0665.


Decision 3585-D03-2016 (June 6, 2016) • 97

AltaLink failed to follow “optimal” design in its tower selection. As well, the RPG filed

additional evidence regarding underutilized lattice tower capacity.

467. AltaLink responded to the Grid Power report evidence in its rebuttal evidence and, in

addition, engaged Mr. Jon Kell of Manitoba Hydro to provide an independent evaluation of the

Grid Power report.

468. The RPG, in its argument, requested the Commission to assign no weight to Mr. Kell’s

evidence on the basis that AltaLink had failed to follow the intentions of the APEGA444

Guideline for Ethical Practice.

469. The Commission has addressed this latter issue in the subsection below. Its findings on

tower selection and tower utilization matters follow.

4.1.16.1 Professional practice requirements

470. The obligations of a professional engineer in reviewing another engineer’s work were

raised in the oral hearing by the RPG. Mr. Kell, the witness from Manitoba Hydro who appeared

in order to speak to his evidence on the Grid Power report, was questioned on his understanding

of those obligations:

Q. Do you have any professional obligation to contact Mr. Cline when you were tasked

with reviewing his report which bears his stamp?

A. MR. KELL: I did. And I contacted BLG with that concern. And what they indicated

was that under privilege or under expert witness, that that was not required.

...

Q. Okay. Gentlemen on the panel who are engineers, are you familiar with that similar

obligation for an engineer in Alberta under the APEGA code of conduct, that you're to

contact an individual if you're called upon to review their work?

A. MR. TOWNSEND: Just to add here -- and we can bring up the APEGA legislation, if

you want, but I believe there's clauses in there that exempt that requirement for a judicial

and -- this type of scenario.

Q. Mr. Kell, are you a member of APEGA?

A. MR. KELL: I am not a member of APEGA.

Q. Are you a member of the Manitoba --

A. MR. KELL: I am.

Q. Does it have a similar exemption?

A. It does have a -- I'll need to check on the APEGM clause. The reason why I asked it

was specifically to your point, was that APEGM has a requirement to notify other

professional engineers when undertaking review of their work. I brought this up with

444

The Association of Professional Engineers and Geoscientists of Alberta.


98 • Decision 3585-D03-2016 (June 6, 2016)

BLG. And the comment back -- or the direction back was that APEGA did have an

exemption under this type of proceeding.445

471. In argument, the RPG stated that AltaLink withheld information (the functional

specifications, the 240-kV projects line designs and all information responses from the RPG)

from Mr. Kell and instructed him not to contact Mr. Cline who could have informed Mr. Kell’s

analysis of the Grid Power report. The RPG asserted that by doing so, AltaLink has failed to

follow the intentions of the APEGA Guideline for Ethical Practice. The RPG considered the

Manitoba Hydro report to be “distorted” and recommended that the Commission give no weight

to the conclusions of the Manitoba Hydro report.446

472. In reply argument, AltaLink stated that RPG’s accusation that AltaLink has not followed

the requirement of its APEGA Permit to Practice is serious and made without foundation.

AltaLink noted that the APEGA Guideline for Ethical Practice provides that an engineer may

review the work of another engineer without consulting the engineer where the work is

performed at the request of a lawyer. Mr. Kell specifically mentioned this clause in the Guideline

for Ethical Practice when questioned on the matter during the hearing. AltaLink It concluded that

the RPG had appeared “to deliberately omit the very ethical guideline that Mr. Kell specifically

referred to when questioned on the matter during the hearing.”447

Commission findings

473. The relevant section of the APEGA Guideline for Ethical Practice is provided below for

context:

Professionals should undertake an assignment to critique the work of another professional

engineer or geoscientist that calls into question the professional conduct or technical

competence of that individual only with the knowledge of and after communication with

that individual such that the reviewer is fully apprised of all relevant information.

Professional engineers and geoscientists are entitled to review and evaluate the

work of other professionals when so required by their employment duties. When

asked to review the work of another professional, it is a normal courtesy and a

required obligation to contact and advise that professional accordingly. Open

communication should exist between the two professionals so that the reviewing

professional understands underlying assumptions and so that the professional

being reviewed has an opportunity to respond to any comments or criticisms.

A review of, and a report on, another professional’s work that is performed at the

request of a lawyer is protected by solicitor-client privilege and may be done

without advising the other professional. Such a report is considered to be part of

the lawyer’s work product and would remain privileged unless the privilege is

waived by the lawyer’s client or used by the client in some way.

...

445





Decision 3585-D03-2016 (June 6, 2016) • 99

A professional should not call into question the professional conduct or technical

competence of another professional member without first consulting that member

to attempt to determine the relevant facts.

If a member determines, or has reasonable and probable grounds to believe that

the professional conduct or the technical competence of another professional

member is in serious question, he or she has a clear and definite duty to inform

APEGA accordingly. (Refer to Appendix C, APEGA Discipline Process.)448

[emphasis added]

474. The allegation levelled against Mr. Kell by the RPG is a serious allegation. The

determination of whether or not an APEGA permit holder has acted unethically is beyond the

Commission’s jurisdiction.

475. Mr. Kell is a practicing professional engineer registered with the Association of

Professional Engineers and Geoscientists of the Province of Manitoba (APEGM) and has many

years of experience in the structural design of transmission lines. Mr. Kell’s competence is not in

question. Mr. Kell is bound by a Code of Ethics and an obligation to the profession and to the

public. The APEGM Code of Ethics for the Practice of Professional Engineering and

Professional Geoscience states the following with respect to acting as an expert witness:

Each practitioner shall obey the laws of the land.

Specifically, and without limiting the generality of this statement, each

practitioner shall: …

1.2 be open and honest when engaged as an expert witness and give

opinions conscientiously, only after an adequate study of the matter

under review449

476. Mr. Kell’s testimony was that he is aware of his professional obligations and that he has

acted in accordance with those obligations. Although the Commission can make no finding about

whether AltaLink and Mr. Kell have met their respective ethical requirements, because this is a

matter for their respective professional associations to determine, the Commission does not

consider the actions of either AltaLink or Mr. Kell to be contrary to the provisions quoted above

from the APEGM Code of Ethics.

477. With regard to the RPG’s assertions in its argument that “the Manitoba Hydro report is

not just irrelevant for the matters under consideration in this proceeding but is, in fact misleading

and therefore unhelpful to the Commission” and that “due to the distorted nature of the Manitoba

Hydro report, the Commission should give no weight in this proceeding to the conclusions of this

report.”450 The Commission does not agree. Mr. Kell, in his report and further in his testimony,

candidly and clearly explained the materials he reviewed, the analysis he performed and the

conclusions he drew from the analysis, including identifying any caveats or conditions to the

conclusions drawn.

448

APEGA Guideline for Ethical Practice v2.2, February 2013, Section 4.5.3, retrieved from

http://www.apega.ca/assets/PDFs/ethical-practice.pdf. 449

APEGM Code of Ethics for the Practice of Professional Engineering and Professional Geoscience, retrieved

from http://www.apegm.mb.ca/pdf/ethics00.pdf. 450

Exhibit 3585-X0860, paragraphs 231 and 236, respectively.


100 • Decision 3585-D03-2016 (June 6, 2016)

478. Based on these considerations, the RPG’s request is denied.

4.1.16.2 Tower selection and tower utilization

Tower selection

479. As stated above, Mr. Cline, on behalf of the CCA and the RPG, submitted evidence in the

Grid Power report objecting to AltaLink’s decision to use the R22 double circuit lattice tower

families for five 240-kV projects. He asserted that the effect of AltaLink’s decision to design its

240-kV lines to meet the requirements of ISO Rule 502.2 was fundamental in the tower type

selection and consequently affected the final project costs. He explained that the new ISO rule

contains major changes to how transmission lines are to be designed. For example, the new ISO

rule introduced changes to the specific requirements of heavy wind and wet snow loading,

galloping with 12.5 millimetres of ice load, unbalanced wet snow loading, and anti-cascading

line design. These changes, in turn, significantly affected the structure types, span lengths and

conductor types that can be used. Further, these changes, combined with the continued use of

bundled conductors, have resulted in wider, taller and heavier towers, which when combined

with recent higher labour costs in Alberta led to higher costs.

480. The Grid Power report concluded that AltaLink missed opportunities at the engineering

design stage to consider structure type alternatives in order to reduce the cost of the 240-kV

projects. Mr. Cline calculated that the increased cost as a result of these missed opportunities was

approximately $101 million451based on an analysis of the design and associated costs of the 240-

kV projects, a study of conductor alternatives and possible structure alternatives based on a

preliminary structural analysis. The RPG recommended reduction to AltaLink’s applied-for

costs, including the $101 million identified in the Grid Power report.452

481. Mr. Cline stated that given the changes to the ISO rules regarding transmission line

design requirements, line optimization should be done to determine what tower type is most

appropriate, as opposed to relying on previous best practices.453 He defined line optimization as a

comprehensive cost-benefit analysis of the conductor and structure type alternatives used to

identify the least cost design, taking into consideration factors such as local construction

conditions, tower materials and foundation alternatives.454

482. The Grid Power report indicated that, as a result of the ISO Rule 502.2 heavy wind and

wet snow requirements, utilization of a twin bundled conductor (such as those used in the five

240-kV projects) significantly increases the loading on towers and foundations and consequently,

the design cost. For this reason, a TFO should evaluate whether a single conductor, such as a

larger aluminum conductor steel reinforced (ACSR) or aluminum conductor steel supported

(ACSS), could be used and still meet the specified rating.455 Mr. Cline alternatively suggested

that AltaLink could have requested an exemption from the AESO for the calm air condition

specified in ISO Rule 502.2 because the 240-kV project lines would be loaded only “if there is

sufficient wind for the wind farms in the area to operate.” Using air movement when calculating

451







Decision 3585-D03-2016 (June 6, 2016) • 101

the static rating will increase the rating for a conductor and decrease the size of conductor

required.456

483. Mr. Cline further indicated that the new loading, galloping and anti-cascading

requirements of ISO Rule 502.2 resulted in the previously used lattice LL tower family being

inadequate for the 240-kV projects and the structure types that may be considered for high-

voltage line projects are the new lattice families (R-series), H-frames or guyed structure

designs.457 AltaLink questioned Mr. Cline about his statement that the LL tower family became

inadequate only after ISO Rule 502.2 was enacted and in response to an IR, Mr. Cline confirmed

that the LL tower family would not have met the wind and vertical loading requirements of the

Technical Requirements (Part 3) for Connecting Transmission Facilities standard with the

specified conductor for the 240-kV projects, which was the existing standard for these five

projects.458

484. Mr. Cline also conducted a limited analysis of tangent towers for three possible structure

types (steel pole rigid X braced H-frame, steel pole X tied H-frame and V guyed H-frame), using

2x1033 kilo circular mils (kcmil) bundled conductors consistent with the final design for the

240-kV projects in order to estimate the potential for cost reduction through design

optimization.459 The Grid Power report outlined the following ranking for each of the structure

types based on cost per kilometre (km) (from most to least costly): RB22A, X braced H-frame, X

tied H-frame, V guyed H-frame.

485. Consequently, Mr. Cline concluded that AltaLink missed approximately $101 million in

savings by not selecting a double steel H-frame design, such as those used in his analysis, for the

240-kV projects. Grid Power noted that the estimated savings did not include reduced owners

costs, reduced construction supervision, span optimization for structures, alternative foundation

designs, reduced structure weights where full extensions are not required, nor conductor

optimization.460

486. In rebuttal evidence, AltaLink challenged Mr. Cline’s analysis and conclusions. It noted

that the previous standard, Technical Requirements (Part 3) for Connecting Transmission

Facilities, which was specified in the functional specifications for the 240-kV projects, already

included requirements for galloping and anti-cascading461 but, more significantly, the AESO was

in the process of developing new standards during the same period that these projects were

commencing.

487. AltaLink submitted that the 240/500-kV Alternating Current/High-Voltage, Direct

Current (AC/HVDC) Tower Development project was initiated by the AESO to meet the

requirements of ISO Rule 502.2 and to reduce the project cycle for upcoming projects462 and that

AltaLink had provided more clarity with regards to the AESO project in response to an IR. The

goal of the project leading to ISO Rule 502.2 was to develop a new suite of towers that would be

456



Exhibit 3585-X0696, CCA-AML-2015SEP24-010, PDF page 16. 459


Exhibit 3585-X0665, PDF pages 26 and 28. 461




102 • Decision 3585-D03-2016 (June 6, 2016)

optimized to meet the requirements of upcoming projects. The initial project scope was limited

to lattice towers as they were considered industry best practice in North America, but the scope

was later expanded to review tubular pole and double delta tower options in response to

stakeholder concerns about visual effects. AltaLink was directed463 to manage the design and

testing for the RA, RB, RC and NSB tower families.

488. AltaLink recognized that ISO Rule 502.2 came into effect after the commencement of

several projects included in this application. However, it explained that it was reasonable to

apply the requirements of the draft rule as AltaLink was a participant at all stages of the rule

development prior to the commencement of these projects.464

489. In response to the Grid Power report on the requirement for line optimization studies,

AML stated that the type of study contemplated by the Grid Power report would add one to two

years to a project due to changes required to the consultation process and the need for detailed

engineering design to be completed prior to line optimization. Further, the line optimization

would either have to be completed on all proposed routes prior to a facility application, or would

have to be postponed until after the P&L were obtained.

490. Conversely, AltaLink completed the tower design and line layout processes in parallel for

the five 240-kV projects which reduced project delivery time while regulatory processes were

underway.465 AltaLink explained that a line layout optimization is different than a line

optimization study – line layout optimization is essentially the facility application. This process

is where the routing and structure placement decisions are analyzed and documented. AltaLink

stated that it is comfortable that this process meets AUC Rule 007: Applications for Power

Plants, Substations, Transmission Lines, Industrial System Designations and Hydro

Developments.

491. AltaLink indicated further that many transmission line projects would not have a line

optimization study completed because the line length is too short to produce material benefits

from line optimization, which is why ISO Rule 502.2 specifies that the minimum length for a

line optimization study is 50 km. Based on this specified minimum line length, only CB would

have required a line optimization whereas the other 240-kV projects would have only required a

conductor optimization study. However, line and conductor optimization studies are used as a

basis to select the optimal conductor but are not required when, as with the 240-kV projects, the

AESO specifies the conductor to be used.466

492. AltaLink stated that it did not perform project specific tower optimization studies since

the purpose of the AESO 240/500-kV AC/HVDC Transmission Tower Development project was

to develop tower families to be used in these projects. AltaLink also stated, in response to an IR

that requested the assumptions used in a line layout optimization, that tower locations are not

determined using only a least cost approach, the line layout process seeks to optimize numerous

considerations over the entire project (not on a tower-by-tower basis) such as cost, foundation

463

The direction letter from the AESO is found in Exhibit 3585-X0045, AML-CCA-2015MAR05-032

Attachment 1, PDF page 338. 464

Exhibit 3585-X0045, AML-CCA-2015MAR05-032, PDF pages 332-333. 465




Decision 3585-D03-2016 (June 6, 2016) • 103

requirements, soil types, visual impacts, environmental impact, landowner concerns, topography

and obstructions while meeting the design criteria.467 468

493. With regards to the Grid Power report evidence on conductor selection and the possibility

of applying to the AESO for an exemption on the air speed requirement, AltaLink noted that the

large geographical area in which lines are built made it difficult to predict air speeds at different

parts of the line because they are in different terrain or shelter. Using a higher air speed could

result in higher actual conductor temperatures and greater conductor sag than designed for,

which could then result in inadequate clearance, violating the Alberta Electric Utility Code and

potentially resulting in premature aging or damage to the conductor. Premature aging or damage

to the conductor, AltaLink explained, may lead to earlier than planned replacement or unplanned

maintenance.

494. AltaLink also addressed Mr. Cline’s suggestion that a single ACSS conductor could be

used. It explained that the conductor would need to be operated at a much higher temperature to

meet the rating requirements which is not a suitable alternative. Furthermore, the ACSS

conductor would require pre-tensioning prior to being installed which can be a safety concern

and which requires specialised equipment and training. Additionally, ACSS conductors are

currently not allowed under ISO Rule 502.2.469

495. In response to the structure types proposed in the Grid Power report evidence, AltaLink

submitted that these are less suitable because they would create difficulties for meeting ISO Rule

502.2 requirements for live line maintenance on the top two phases. AltaLink also submitted that

the Grid Power report evidence contained design errors. AltaLink attempted to model the

proposed design for the purposes of preparing rebuttal evidence and determined that the

proposed design was not viable for the following reasons: it would fail under the wet snow and

moderate wind loadings; the assumed hollow structural section (HSS) costs for steel are for

standard steel stock but would need to be custom procured, resulting in a higher price; the

foundation proposed would be insufficient for the forces from the structure and therefore, the

cost for H-frame foundations would be at least as high as for a lattice tower; it did not include

costs for anti-cascading structures; and, the structure labour cost used was from an unrelated

project.470

496. AltaLink explained further that the foundations are selected once geotechnical data about

the tower location is known, which can only be determined after access to the land is granted.

The initial design is completed on the expected soil type(s) in that area. Several foundation types

(e.g., grillage or screw pile) are designed and then a specific type is selected based on the

conditions actually encountered at a location. The foundation selected is “optimal” for the

conditions in each location, which is typically also the lowest cost solution. The construction

contracts are tendered using a unit price contracting methodology, meaning that bidders submit

pricing for each foundation type, based on an initial estimate of the required units of each type

for a specific project. Once the foundation type is selected for a location, the unit price for that

type is set. In this way, AltaLink can manage the risks associated with unknown geotechnical

467

Exhibit 3585-X0045, AML-CCA-2015MAR05-032(a)(i-ii), PDF page 334-335. 468

Transcript, Volume 1, page 73, lines 18-24 and page 75, lines 2-10. 469




104 • Decision 3585-D03-2016 (June 6, 2016)

conditions and land access issues and achieve a market competitive cost for foundation

installation.471

497. Finally, AltaLink noted that the Grid Power report submitted in this proceeding was

similar to that filed in the ATCO Electric 2012 deferral account proceeding (Proceeding 2683) to

which ATCO Electric had already responded and with respect to which the Commission had

already issued a decision.472

498. In addition to filing its own rebuttal evidence based on its internal analysis of the Grid

Power report evidence, AltaLink also retained Mr. Jon Kell of Manitoba Hydro to provide an

independent evaluation of the Grid Power report and, in particular, the proposed H-frame tangent

structures. Mr. Kell concluded that the Grid Power report was optimistic in regards to what the

proposed structures could support and found that lattice towers were the most economical

structure for the conditions analyzed (loading conditions consistent with the requirements of ISO

Rule 502.2).473

499. Mr. Kell modelled the rigid X braced H-frame tangent structure and concluded that it

would fail under the ISO Rule 502.2 loading and the ruling span specified by AltaLink and in the

Grid Power report. In order to be compliant with ISO Rule 502.2 and the ruling span specified by

AltaLink, the proposed H-frame structure could be modified to have a shorter ruling span.

However, this modification would result in an increased number of structures per km when

compared to the structures per km assumed by Grid Power. The structures proposed by Grid

Power could also be modified to use larger steel sections at the same ruling span. However, that

would have the effect of increasing the structure weight. Manitoba Hydro presented a table

similar to that in the Grid Power report, in which it ranked the RB22 structure and modified X

braced H-frames based on the cost per km (from most to least costly): tapered steel pole,

fabricated HSS (50 kilopounds per square inch (ksi), fabricated HSS (65 ksi), RB22A. Manitoba

Hydro’s analysis concluded that the lattice towers used in the 240-kV projects were the most cost

effective for the loading conditions specified in ISO Rule 502.2.474

500. Mr. Kell indicated that Grid Power’s assertion that standard hollow structural steel

sections can be used for H-frame tangent structures was incorrect – in order to match the long

spans and large loads supported by lattice steel structures the tubular sections would be non-

standard sizes which would be more costly. Additionally, using large diameter round steel pipe is

not common in the industry; multi-sided tapered tubular steel sections are typically used. He

agreed that assembly and erection of large diameter tubular steel poles is more time efficient than

lattice towers however, it requires more specialised construction methods.475

501. He examined the unit cost assumptions in the Grid Power report and, based on experience

as well as blended rates provided by AltaLink, Mr. Kell concluded that the costs for steel were

reasonable but that the assembly and erection costs assumed for lattice tower structures were

high.

471

Transcript, Volume 1, pages 93-94, lines 7-22 and 8-9 and page 97, lines 17-20. 472


Exhibit 3585-X0708, Manitoba Hydro report, PDF page 2. 474

Exhibit 3585-X0708, Manitoba Hydro, PDF pages 6-11. 475

Exhibit 3585-X0708, Manitoba Hydro report, PDF pages 3-5.


Decision 3585-D03-2016 (June 6, 2016) • 105

502. Finally, with respect to foundations, Mr. Kell agreed that for shorter spans with small

loads, tubular structures can use direct embedment which has a cost advantage. However, with

larger loads and longer spans, direct embedment is no longer feasible and, in his experience,

foundations for large tubular structures tend to be one to three time more costly than those for

lattice towers.476

503. The RPG questioned Mr. Kell in the oral hearing regarding his analysis and conclusions.

In testimony, Mr. Kell clarified that the conductor (bundled 1033 kcmil Curlew) used in his

analysis of the proposed Grid Power structure was based on the tower package received from

AltaLink’s counsel and the Grid Power report; the smaller conductors used on other projects

were not considered in the analysis. Mr. Kell indicated that the smaller conductors would result

in a smaller load on the tower.477 He also clarified that the structures in the Grid Power report

were modelled using ISO Rule 502.2 requirements in order to compare them with the R22 lattice

towers, but that the specific project design information from the 240-kV projects was not

provided for the purposes of the analysis. If the ice shedding and broken wire loading conditions

were removed, as proposed in the Grid Power report, then the lattice towers would have to be

designed with those conditions in mind and the result would be to compare Grid Power’s

proposed structures to a lighter lattice structure.478

504. Mr. Kell further explained that his reference to specialised construction methods was to

the larger equipment that would be required to erect a tubular pole compared to lattice towers,

which can be erected in pieces and uses smaller equipment. Another consideration for the tower

type is transportation to the tower location; tubular structures are not as easily broken down into

smaller components if access is difficult or restricted.479 Based on Manitoba Hydro’s experience,

the assumption for the costs of assembly and erection for tubular steel is low.

505. Mr. Kell also addressed the concept of failure containment, which is the trade-off that

must be evaluated between costs associated with designing towers to resist longitudinal loads

[broken wire loading], or designing a line with anti-cascading structures and the costs of

restoration after failure. ISO Rule 502.2 requires that lines be designed to manage broken wire

loading or with anti-cascading structures. There are costs, potential savings, risks and

opportunities inherent with all design decisions so the risks and costs need to be balanced as

appropriate for the project,480 meaning different lines will have different requirements and

different thresholds for failure.481 In Manitoba Hydro’s experience, the most cost effective way of

providing anti-cascading properties is to build longitudinal capacity [broken wire load resistance]

into tangent structures.482

506. AltaLink also challenged the Grid Power report in the oral hearing and questioned the

expertise of Mr. Cline to provide the opinions and evidence, given the fact that he had not

worked for any transmission company during the time of the projects included in this application

476

Exhibit 3585-X0708, Manitoba Hydro report, PDF pages 5-6. 477


Transcript, Volume 3, pages 531-532 and 535. 479

Transcript, Volume 4, page 606, line 22 to page 607, page 11. 480

Transcript, Volume 3, page 482, line 6 to page 483, line 20. 481


Transcript, Volume 3, page 530, lines 10-13.


106 • Decision 3585-D03-2016 (June 6, 2016)

nor had he appeared in any facility application hearings for the 240-kV project nor been a

participant in the development of ISO Rule 502.2.483

507. In testimony, Mr. Cline stated that prior to ISO Rule 502.2 being implemented, the most

cost effective towers for the 240-kV transmission system were steel lattice. Some notable

conditions that led to this were: these lines had smaller conductor, and fabricated steel pole

structures were not widely used when the existing 240-kV lines were built. The implementation

of ISO Rule 502.2, changes in the labour market, and the availability of fabricated steel now

means that steel lattice towers may not be the most cost effective choice for high voltage

transmission lines and TFOs have a responsibility to examine all the alternatives.484 In contrast,

the Manitoba Hydro evidence stated that, in its experience, tubular structures are only used

where environmental or property issues dictate the structure selection as they are more costly

(compared to lattice structures).485 This is because lattice structures can be used to maximize span

lengths.486 In the example of St. Vital provided as an aid-to-cross examination during the oral

hearing, Mr. Kell noted that where tubular structures are used, the reliability of those structures

can be decreased because they would be built in an area that is easily accessible in the event of a

tower failure.487 This shows that there is a balance between the future cost of failure and the cost

of designing the structure to resist that failure, over the life of the transmission line.488

508. Mr. Cline stated that different considerations such as route selection, tower type

selection, conductor selection, and commitments to landowners, are parameters that a TFO

would have to work within to determine the least cost alternative. Essentially, considerations

such as those listed by Mr. Cline above should be examined in terms of the cost consequences of

the alternatives available. In Mr. Cline’s view, these decisions and the costs associated with each

alternative examined should be documented.489

509. In argument, AltaLink submitted that components of the project design and approval

process lie with the AESO and with the Commission. AltaLink is obligated to prepare a PPS that

meets the AESO’s functional specification, to comply with conditions and commitments set out

in the facility application approval, and to construct the transmission line on the centreline using

the structures set out in the facility application. AltaLink submitted facility applications for the

240-kV projects which stated AltaLink’s intention to use steel lattice tower structures, the

dimensions of which were provided in the application.490

510. In argument, the RPG stated that the Manitoba Hydro report incorrectly found that the

tower proposed by Grid Power would fail under the loading conditions provided by AltaLink.

The RPG maintained that the proposed tower was not intended to meet those loading conditions,

but rather the minimum requirements to meet the capacity required for the 240-kV projects. The

RPG restated its position that the use of broken wire loading conditions in AltaLink’s design, as

opposed to using anti-cascading structures, significantly increased the size of the structures

483

Exhibit 3585-X0859, PDF pages 78 and 80-81. 484


Exhibit 3585-X0708, Manitoba Hydro report, PDF page 3. 486







Decision 3585-D03-2016 (June 6, 2016) • 107

required and the number of angle and dead-end structures, which had a corresponding impact on

the project costs. The RPG reiterated its recommendation that a minimum of $101 million be

disallowed from rate base for the 240-kV projects or that a cost and performance audit be

ordered for the 240-kV projects.491

511. In its reply argument, AltaLink clarified that Mr. Kell of Manitoba Hydro tested not only

for broken wire containment loading but for all ISO Rule 502.2 loading requirements.492 It noted

that ISO Rule 502.2 requires failure containment, which can be done by designing towers to

withstand broken wire loading or by using anti-cascading structures. AltaLink asserted that the

proposed design in the Grid Power report did not include either failure containment alternative.493

512. In reply argument, the RPG argued that the responsibility for tower selection lay entirely

with AltaLink and that the development of the R-series tower family was also AltaLink’s

responsibility. Therefore, AltaLink had the opportunity to optimise the structure design and

structure type selection for the 240-kV projects and failed to do so.494

Tower utilization

513. The evidence submitted by Grid Power was supplemented by evidence submitted by the

RPG, also prepared by Mr. Trevor Cline, regarding underutilized lattice tower capacity.

514. The RPG stated that transmission lines should be designed to near 100 per cent utilization

of their structural capacity with optimal span lengths that will result in minimized cost.495 In

response to an IR, the RPG acknowledged that structure placement has many other

considerations and design limitations, such as land use, conductor tension limits and air gap

limits.496 An underutilized tower is essentially overbuilt for its purposes.

515. The RPG recognized that it is impractical and uneconomical to design an infinite

selection of towers, especially for lattice towers. However, the RPG asserted that “Typically a

tower family will be targeted to be economically optimal for a specific metrological region and

for a specific conductor size.” If a tower is not at its design angle or weight span limit, the spans

can be lengthened to utilize surplus capacity and improve economic efficiency.497

516. The RPG evaluated the tower utilization for the 240-kV projects for the tangent through

medium angle structures which make up the majority of the towers in these projects. For the

analysis, the RPG defined utilization of tower strength as the ratio of the structure-specific

compressive force in the main tower chord at the bottom of the tower waist compared to the

maximum allowable compressive force based on the tower design loading for wet snow and

wind loading condition.498 The RPG cautioned that the results overstate the utilization because

they are not based on the actual tower capacities, but rather on the target wind and weight spans

491






Exhibit 3585-X0699, RPG-AML-2015SEP24-020(a), PDF page 30. 497


Exhibit 3585-X0689, CCA-AUC-2015SEP24-009(b), PDF page 24.


108 • Decision 3585-D03-2016 (June 6, 2016)

stated on the tower drawings provided by AltaLink. The results of the analysis for all towers

were provided in a table as shown below:

Table 5. RPG evidence of tower utilization for R22 tower family

Tower Type Number of towers Average utilization

RA22A 43 57%

RA22B 58 52%

RA22C 34 56%

RB22A 326 62%

RC22A 97 71%

RC22B 12 56%

Total 570 62%

Source: 3585-X0689, CCA-AUC-2015SEP24-009, PDF page 22.

517. In order to improve the utilization of the R22 tower, a redesign would be required to

accommodate longer spans which in turn would require higher strength steel conductors and

higher structures. In essence, in the RPG’s view, the R22 towers could not achieve close to

100 per cent utilization in any realistic scenarios.499

518. The RPG concluded that the R22 family of towers is underutilized in the 240-kV double

circuit line projects in which it was used. The RPG suggested that a more economical design of

transmission towers could have been selected during the detailed line design. The RPG

recommended that a cost and performance audit be undertaken for the transmission line design of

southern Alberta 240-kV double circuit line projects.500

519. In rebuttal evidence, AltaLink submitted that there were errors in the RPG methodology

for assessing tower design capacity and utilization: namely:

The tower waist widths used were incorrect – the RPG did not request the waist widths

and the drawings provided by AltaLink were not to scale

The methodology was simplistic and ignored loading conditions other than wet snow and

wind, which may govern the design of different tower members

The RPG did not include conditions such as wind on the tower, weight of the tower,

weight of the hardware, weight of conductor accessories and other tower maintenance

loads that do not change span length and will skew the effect of span length on tower

utilization

The conclusion reached by the RPG that tower tests indicate a 25 per cent overload

capacity was incorrect. No conclusions can be made on the strength of the tower under

the other loading conditions other than it passed at 100 per cent loading.501

499

Exhibit 3585-X0689, CCA-AUC-2015SEP24-010(c), PDF pages 26-28. 500




Decision 3585-D03-2016 (June 6, 2016) • 109

520. In testimony, the AltaLink witness estimated that the error in the RPG’s tower utilization

calculation due to the incorrect waist width would be in the range of one to 10 per cent,

depending on the tower. The RPG updated the utilization calculation using the correct waist

width and determined that the utilization for the RA22A tower would be 60.78 per cent.502

521. The tower design drawings, which include a summary of the individual member

utilization under various load conditions, were provided on the confidential record in response to

an undertaking.503 AltaLink’s witness confirmed in testimony that one tower design (RB22A

tangent), which was different from the suite of towers that were tested, was modelled by

AltaLink for the purposes of replying to the RPG evidence. With a zero body extension and zero

leg extension, under the wet snow and wind loading condition for Zone B, the model showed a

90 per cent utilization for certain members.504 The results of AltaLink’s model were also

provided in response to an undertaking505 and the member utilization information which was

input into the model was also provided in response to an undertaking on the confidential

record.506

Commission findings

The consideration of design decisions in a DACDA

522. The reasonableness of the design decisions and the resulting costs from those decisions

are assessed in a deferral account proceeding. However, as stated in Decision 2014-283: “on a

practical level, decisions made at key points in the cycle of a project’s development and

execution, such as the design and functional specifications approved as part of facility

applications, impact subsequent decisions in the execution of that project and can become

irreversible.”507 This is because at this stage, all previous project phases (planning, design and

engineering, construction, commissioning and testing, energization and close-out) have been

completed.

523. Recognizing this, in Decision 2014-283, the Commission stated:

190. …the Commission intends to review the cost-related evidence and consider cost-

related issues in facilities proceedings, and considers that participation by interveners

who are focussed primarily on issues of cost and design, should be permitted in facility

proceedings.

191. The Commission recognizes that expanding the scope of facility proceedings

beyond the primary focus on the selection of the optimal route may complicate future

facility proceedings. Accordingly, beyond recognizing the need in principle for there to

be greater consideration of facility design and related cost issues in facility proceedings,

the Commission will not make specific recommendations on the nature of the changes

that could be made to the scope of participation and issues to be examined in facility

proceedings within this decision. Issues of scope and participation are better determined

by the Commission panel deciding that particular facility application before it.

502


Exhibit 3585-X0734a-CONF, Exhibit 3585-X0734b-CONF and Exhibit 3585-X0734c-CONF. 504


Exhibit 3585-X0735. 506

Exhibit 3585-X0742-CONF. 507

Decision 2014-283, paragraph 190.


110 • Decision 3585-D03-2016 (June 6, 2016)

524. The Commission reviews and approves transmission line designs including transmission

line specifications as part of its assessment in its facility proceedings. Section 19 of the Hydro

and Energy Act authorizes the Commission to approve, deny or require changes to transmission

lines:

19(1) On an application for an approval, permit or licence under this Part, or for an

amendment of an approval, permit or licence, the Commission may grant the approval,

permit, licence or amendment subject to any terms and conditions that it prescribes or

may deny the application.

…

(2) Without restricting the generality of subsection (1), the Commission may do one or

more of the following:

(a) require changes in the plans and specifications of a hydro development,

power plant or transmission line;508

525. The AESO’s authority to direct a TFO to submit a facilities application to the

Commission for approval is found in Section 35 of the Electric Utilities Act. At the direction of

the AESO, the TFO must comply with the AESO’s direction unless doing so would cause a real

and substantial risk of damage to its facilities or safety to its employees or the public or risk of

injury to the environment. As part of that obligation, Section 35(3) requires the TFO to “prepare

an application that meets the requirements or objectives of the direction.”

526. Once PPS approval is received, the TFO is directed by the AESO to submit a facility

application to the Commission. The AESO’s direction letter to the TFO approving the PPS

includes a clause that states the project will be designed and constructed in accordance with the

PPS and the AESO’s final project functional specification.509 The facility application submitted

to the Commission includes information on the project design, routing, stakeholder consultation,

environmental impacts and other considerations.

527. The approval of a facility application and issuance of P&Ls serves as the direction to the

TFO to begin construction activities. The P&L is typically issued with a condition that the

structures shall be constructed of materials as specified in the facility application and other

previous approvals pertaining to the transmission line.510 The design of a project will have largely

been completed in the design and engineering phase with some minor field design changes

during construction to account for the conditions actually encountered.

528. The RPG maintained that AltaLink was not required to comply with the requirements of

new ISO Rule 502.2 and that a more economical design of transmission tower families could

have been selected during the detailed line design. Overdesign of a project, meaning one that

508

Hydro and Energy Act 409/83, Statutes of Alberta 2000, Chapter H-16, Section 119. 509

Examples of this wording can be found in Exhibit 3585-X0834 at PDF page 3, Exhibit 3585-X0835 at PDF

page 2 and Exhibit 3585-X0836 at PDF page 3. 510

Examples of this wording (for the 240-kV projects) can be found in Exhibit 0022.00.AML-3585 at PDF

pages 3, 9, 15, 20, 26, 29, 32 and 38; Exhibit 0034.00.AML-3585 at PDF pages 2, 5, 10, 13; Exhibit

0045.00.AML-3585 at PDF page 6; Exhibit 0056.00.AML-3585 at PDF pages 5, 8, 13,16, 23, 26, 30, 37, 41,

45, 48, 54 and 57; and Exhibit 0068.00.AML-3585 at PDF pages 6, 9, 12, 15, 20, 23, 26, 29, 32, 35 and 38.


Decision 3585-D03-2016 (June 6, 2016) • 111

exceeds the requirements of the functional specification and all relevant standards and rules, can

generally be said to not be in the public interest and is of concern to the Commission.

529. However, the Commission, in reviewing the reasonableness of the design selected by the

TFO, is mindful that design decisions are made in response to the AESO’s determinations and to

meet a functional specification pursuant to the Electric Utilities Act.

Application of ISO Rule 502.2 requirements in advance of the rule coming into effect

530. The AESO filed ISO Rule 502.2 with the Commission on June 27, 2011, pursuant to

Section 20.2(1) of the Electric Utilities Act. No objections to the new rule were received and the

Commission issued a Notice of Disposition on July 15, 2011 stating that ISO Rule 502.2 would

be effective January 1, 2012.511 ISO Rule 502.2 Section 2(2) indicates that lines with a functional

specification approved prior to the effective date are not required to apply ISO Rule 502.2.512

531. All of the functional specifications for the 240-kV projects were approved prior to

January 1, 2012.513

532. In Decision 2014-283, the Commission provided its findings in response to an ATCO

project that was designed and built in compliance with ISO Rule 502.2, despite the fact that the

rule had not yet come into effect. The Commission found ATCO’s decision to do so to be

reasonable stating:

240. Assessing ATCO’s selection of conductor involves determining whether ATCO’s

decision was reasonable at the time it made its decision, knowing what it knew, or should

have known, at the time. Although it was not necessary for ATCO to meet the

requirements of ISO Rule 502.2, it was reasonable for ATCO to take the development of

this new rule into consideration given its awareness of the new requirements through its

involvement in the rule development process and its understanding of the nature of the

transmission line prescribed by the AESO in its functional specifications.

533. Similarly, in this proceeding, the Commission finds that AltaLink’s decision to apply

Rule 502.2 requirements to the five 240-kV projects in advance of the rule coming into effect

was also reasonable given its awareness of the new requirements through its involvement in the

AESO’s rule development process.

Application of ISO Rule 502.2 to the five 240-kV projects

534. Having found that it was reasonable for AltaLink to apply ISO Rule 502.2 requirements

to the five 240-kV projects, the Commission considered whether the alternative towers proposed

by the RPG could have satisfied the requirements of this rule.

511

Disposition letter re: Proceeding 18804, Application 1607445-1, new ISO rules definition “bulk transmission

line” and new ISO rule Section 502.2 – Bulk Transmission Line Technical Requirements, July 15, 2011. 512

ISO rules, Part 500 Facilities, Division 502 Technical Requirements, Section 502.2 Bulk Transmission

Technical Requirements. 513

The functional specification approval dates for the 240-kV project are as follows: CB was approved on

May 28, 2010, the Hanna projects were approved on November 3, 2010, and Castle Rock Ridge was approved

on July 19, 2011.


112 • Decision 3585-D03-2016 (June 6, 2016)

535. The adoption of ISO Rule 502.2 requirements and the conductor selection has a

significant influence on the available selection of towers.

536. For projects where the conductor is not specified, the AESO specifies the summer and

winter ratings for the conductor, which limits the pool of suitable conductors that can be used to

meet those requirements. ISO Rule 502.2 currently does not allow ACSS conductors, further

limiting the options for conductor selection.

537. The evidence on the record regarding the five 240-kV projects reveals that the conductor

was specified by the AESO in the functional specification. As AltaLink is required by the

Electric Utilities Act to comply with the AESO’s functional specification, it was required to

design the 240-kV projects with the specified conductor.

538. Mr. Cline proposed that AltaLink could have requested an exemption to air speed

requirements or for the conductors specified in the functional specifications for the 240-kV

projects. The Commission accepts AltaLink’s evidence that these exemptions, in a large

geographical area would make it difficult to predict air speeds at different parts of the line since

they are in more than one terrain or shelter and, using a higher air speed could result in higher

actual conductor temperatures and greater conductor sag than designed, which could then result

in inadequate clearance: violating the Alberta Electric Utility Code and potentially resulting in

premature aging or damage to the conductor. The Commission also accepts AltaLink’s evidence

that premature aging or damage to the conductor may lead to earlier than planned replacement or

unplanned maintenance. For these reasons, the Commission does not find AltaLink’s failure to

seek an exemption to be unreasonable.

539. Mr. Cline recommended that AltaLink should have conducted line optimization and

conductor optimization studies to determine the optimal conductor and tower types for a project,

using a least cost approach. However, for the five 240-kV projects, the Commission has

determined that it was reasonable for AltaLink to comply with ISO Rule 502.2, which specifies

that the minimum length for a line optimization study is 50 km. In addition, if the AESO

specifies the conductor to be used, a line and conductor optimization study is not required.

AltaLink did not complete conductor optimization studies because the conductor was specified

by the AESO and there would have been little benefit achieved from the studies. For these

reasons, the Commission finds that it was reasonable for AltaLink to proceed with its design for

the five 240-kV projects without conducting line and conductor optimization studies.

540. Nonetheless, the Commission recognizes that there can be value in conducting line and

conductor optimization studies. In this regard, the Commission considers that there must be a

balance between the costs associated with an extended design process and the savings that can be

achieved from a line or conductor optimization study. Accordingly, in the event a line

optimization study is not required under ISO Rule 502.2,514 the Commission expects a TFO, in its

deferral account application, to provide an explanation as to why it was reasonable to avoid

conducting a line optimization study. The Commission also expects that any conductor or line

optimization studies completed on projects included in a DACDA will be filed with the

application.

514

Rule 502.2 requires that between 10 and 50km, the TFO may complete either a conductor optimization or a

line optimization study.


Decision 3585-D03-2016 (June 6, 2016) • 113

541. Mr. Cline proposed that AltaLink could have used towers other than those from the R22

tower family. However, the AltaLink rebuttal evidence and the Manitoba Hydro report found

that the Grid Power H-frame structures would fail under ISO Rule 502.2 loading conditions.

Further, Mr. Cline agreed that the L tower family, which was previously the tower of choice for

240-kV projects, would not meet ISO Rule 502.2 loading requirements.

542. Although the Commission understands that the towers Mr. Cline was proposing were not

intended to meet ISO Rule 502.2, but were towers that allegedly could have met the minimum

capacity requirements of the 240-kV projects, once a decision was made to design to the

requirements of ISO Rule 502.2, a larger tower family was required. Given the Commission’s

findings above that it was reasonable for AltaLink to design the 240-kV projects to satisfy the

requirements of ISO Rule 502.2 and to use the conductor specified by the AESO in the

functional specification, the Commission finds that the towers proposed by Mr. Cline could not

have been used for the 240-kV projects.

543. In addition, specifically with regard to the towers AltaLink used in the five 240-kV

projects, the Commission understands that the R-series towers were developed, at the direction

of the AESO, with the intention that they be used on 240-kV projects which must satisfy the

loading requirements set out in ISO Rule 502.2. It was understood from the PPS and the facility

applications that AltaLink intended to use the new lattice tower family for those projects. The

AESO approved the PPS and the Commission approved the facility applications.

544. Given these approvals and the conditions set out in the P&L, which require the TFO to

construct the line with the materials specified in the facility application, and given the inability

for the alternative towers proposed to satisfy the functional requirements specified, it was

reasonable for AltaLink to have constructed the 240-kV projects using the R22 tower family.

545. The Commission has received conflicting evidence as between the evidence submitted by

Grid Power and that submitted by AltaLink, respecting whether lattice towers or steel H-frames

are the most economical choice for high voltage transmission lines. Although it is the AESO’s

preference to use the R22 tower family for its transmission towers, there may be reasons to use a

different tower under certain circumstances., Consequently, the Commission understands that

there is no “one-size-fits-all” tower for high-voltage transmission lines.

546. Where there are multiple alternatives that would meet the project schedule, construction

requirements, environmental concerns, landowner and other stakeholder concerns, while still

meeting the minimum design requirements set out in the AESO’s functional specification, as

well as all applicable standards, codes and rules, the Commission expects that TFOs will

evaluate relevant tower options, including but not limited to monopole, lattice and steel H-frame,

to determine which is most cost effective. This evaluation should be provided as part of the

evidence presented to the Commission by a TFO.

Tower utilization

547. The Commission was presented with conflicting evidence regarding the percentage

utilization of the towers for the five 240-kV projects. The member utilization as provided by

AltaLink was different than the average utilization provided by the RPG. The average utilization

provided by the RPG considered the tower utilization over the length of the 240-kV projects

transmission lines.


114 • Decision 3585-D03-2016 (June 6, 2016)

548. Mr. Cline, in his evidence, has asserted that the R22 family of towers are underutilized in

the 240-kV double circuit line projects in which they were used and that a more economical

transmission tower family design could have been selected. AltaLink, through an IR to the RPG,

obtained the calculations used515 and conducted its own analysis and, from that analysis, AltaLink

concluded that Mr. Cline’s calculations contained errors. Mr. Cline subsequently corrected for

the waist width error but remained of the view that the towers were underutilized.

549. The R22 towers were designed to satisfy ISO Rule 502.2 loading requirements with the

understanding that this tower family could be used on different transmission line projects

throughout the province. Despite design differences in the tower family for different weather

loading zones, the towers are expected to be used in a wide range of conditions. Logically then, it

will not be possible to achieve 100 per cent utilization under all conditions, for all transmission

lines.

550. Consistent with the Commission’s findings above that AltaLink’s decision to apply ISO

Rule 502.2 loading requirements and to design the line using the conductors specified by the

AESO, with the understanding that the R22 towers were anticipated, even at the tower

development stage, the Commission finds that the line optimization results for the five 240-kV

projects are reasonable.

551. Accordingly, the RPG’s request for a cost and performance audit on the tower selection

for the 240-kV projects is denied.

4.1.17 Use of rig mats

552. In its intervener evidence, the RPG maintained that AltaLink failed to justify the

prudence of its expenditures on rig mats (sometimes referred to as access mats) for its capital

projects. The RPG claimed AltaLink incurred significant cost overruns due to its extensive use of

rig mats, which far exceeded that of other utilities undertaking capital projects in the same

geographic area.

553. The RPG provided the following table516 to illustrate the expenditures on mats for the CB,

Nilrem, Hansman Lake, Ware Junction and Heartland projects:

Table 6. RPG summary of general ledger costs for access roads and rig mats

D.0305 Cassils to Bowmanton

D.0353 Hanna Area Transmission –

Nilrem

D.0354 Hanna Area Transmission – Hansman Lake

D.0355 Hanna Area Transmission – Ware Junction

D.0371 Heartland

$32,894,273 $1,545,488 $5,737,901 $5,477,299 $22,000,000

554. The RPG stated that AltaLink’s expenditures on rig mats were significant, particularly in

the CB and Heartland projects, and suggested that they be subject to a cost and performance

audit.

515

Exhibit 3585-X0687, CCA-AUC-2015SEP24-009 Attachment 1. 516



Decision 3585-D03-2016 (June 6, 2016) • 115

555. The RPG noted that although it raised similar concerns with respect to AltaLink’s costs

for rig mat use in Proceeding 2044, AltaLink made no specific effort in this proceeding to

address such concerns, other than suggesting it faced unseasonably wet weather conditions.517

556. The RPG asked AltaLink in AML-CCA-2015MAR05-056 to provide supporting

documentation for the access mats that were used in the CB project. In response AltaLink

referred to the CB facility application it had previously filed and provided a document entitled

“Transmission Line Project Mat Installation Standard” (Attachment 1 to AML-CCA-

2015MAR05-056). The RPG found it implausible that the mat installation standard document

was relevant to AltaLink’s decision-making process on the extensive use of mats in the CB

project since the document was developed on June 6, 2013,518 and, according to the “June 2013

Progress Report Cassils to Bowmanton,” transmission line construction was 90 % complete at

that stage.

557. In rebuttal evidence, AltaLink stated that it exercised reasonable judgment on a project by

project basis in deciding whether to use rig matting. The decision to use rig mats could not be

reduced to a simplistic assessment of the cost of matting, because other factors must also be

considered. AltaLink explained that access mats are utilized in transmission line construction for

a variety of reasons. Access matting mitigates environmental impacts of transmission line

construction, allows for access to the construction right-of-way in wet or non-frozen conditions,

allows for efficient work flow and often mitigates and allays landowner concerns. In the southern

part of the province, land conditions frequently and quickly change from dry to wet to frozen to

thawing; all of which requires an adaptive matting approach to meet project commitments and to

maintain construction access throughout the year. In more northern portions of the province,

access matting allows for construction access in non-frozen and wet conditions.519 AltaLink

argued that although costs were an important factor, they were not the sole factor to be assessed

in the exercise of reasonable judgment.

558. AltaLink stated that the RPG overlooked that AltaLink, as part of the facility application

for each project, fully considered and undertook an environmental evaluation that had input from

Alberta Environment and Sustainable Resource Development (AESRD), landowners, facility

owners, and stakeholders. The use of access mats as a potential mitigation measure to reduce soil

compaction, admixing, rutting and to protect rare plants520 was contemplated in the facility

application that was brought before the Commission as part of the P&L process. Following

receipt of the P&L, AltaLink continued to interact with AESRD, landowners and stakeholders

and, as required, adjusted the use of access mats on the basis of new information and available

right-of-way access.

559. AltaLink claimed it provided evidence that its use of mats was prudent by showing the

need for matting on the CB project, and how matting requirements were optimized.521 With

respect to the CB project in particular, AltaLink employed a full time site representative whose

517

Exhibit 3585-X0666, paragraph 162, PDF page 50, refers to Exhibit 0002.00.AML-3585, paragraph 105. 518

Exhibit 3585-X0098, PDF page 245, AML-CCA-2015MAR05-056 Attachment 1. 519

Exhibit 3585-X0704, paragraphs 125-126, PDF page 41. 520

Filed in the CB proceeding (Proceeding 748) as Exhibit 0013.00.AML-748. See TAB 1 - CB Environmental

Evaluation, Appendix J, Section 7. 521

Exhibit 3585-X0704, paragraph 565 refers to AML-CCA-2015MAR05-056 Attachment 2, Exhibit 3585-

X0098, PDF page 25.


116 • Decision 3585-D03-2016 (June 6, 2016)

role included review of EPC mat plans. AltaLink’s EPC firm, SNC-ATP, also used a mat

coordinator to monitor independently the mat installations and moves claimed by subcontractors.

A mat tracker tool recorded mat use and listed reasons for mats at tower locations, off right-of-

way accesses and helicopter assembly yards. The tracker included a look-ahead plan for efficient

use of future mat placements to ensure access to construction sites when needed so that crew

moves, standby and demobilization charges could be avoided. The cost of mat moves was not

incurred until mats were required at a new location or a move was required for environmental

reasons.522

560. In argument, the RPG stated AltaLink had not provided any evidence constituting a cost-

benefit analysis for the many decisions it had made throughout each project life-cycle to use

mats. The RPG disputed AltaLink’s assertion that the measures used in the CB projects

demonstrated prudence and dismissed the tracker tool as a list of organizing the use of mats

rather than an analysis to determine the most prudent deployment of mats.

561. The RPG asserted that AltaLink should have provided an cost-benefit analysis of the use

of rig mats versus other methods of mitigation to address construction effects on the rights-of-

way. However, when AltaLink was faced with changed circumstance following the facility

application decision on the CB project, its response was to indicate that the change required more

matting on the preferred route523 and referenced “AML-CCA-2015MAR05-056 Attachment 4, a

planning tool to help estimate mat inventory required for the project.”524

562. The RPG also took issue with AltaLink’s explanation that weather and the environment

had an effect on the use of rig mats. Referring to the CB project, the RPG stated that for the

construction of the CB transmission line,525 the project execution included summer work.526

Since

AltaLink could not complete the project in this time period, the RPG expected to see evidence

that AltaLink undertook a cost-benefit analysis of splitting the project up between two

contractors, as had been done in other instances.527 There was also no evidence that AltaLink

minimized the use of mats when on non-agricultural lands.528 The RPG also maintained the

environmental guideline itself, which was big, complicated and developed by AltaLink, was

clearly a major cost driver. However, the RPG submitted that AltaLink provided no evidence

suggesting that the guideline was ever evaluated on a cost-benefit basis, thus creating a situation

where a number of decisions hidden inside the guideline may be inappropriately driving

unnecessary mat costs.529

563. In argument, AltaLink submitted that its utilization of access mats to support construction

of transmission facilities was reasonable and that the standard is reasonableness, not perfection.

AltaLink did not accept that on a prudency review, the Commission should be called upon to

count the number of access mats and the days on which they were employed. AltaLink

522


Exhibit 3585-X0860, page 62, refers to Exhibit 3585-X0704, paragraph 560. 524





Transcript, Volume 10, page 1793, line 24 to page 1794, line 2. 529

Transcript, Volume 10, page 1794, lines 5-23.


Decision 3585-D03-2016 (June 6, 2016) • 117

maintained there was no evidence in this proceeding that the access mats were not required for

the construction of the projects subject to the DACDA.530

564. In reply argument, the RPG noted AltaLink claimed it is well accepted that matting is

used to “provide access in wet conditions and mitigate construction impacts to the lands and

other environmental impacts.”531 In the RPG’s view, this did not support AltaLink’s position for

its excessive use of mats since, while mats are used in some cases for these purposes, they should

still be used prudently. When working in seasons where wet conditions are not an issue, access

mats were not required. Furthermore, ATCO Electric Transmission did not use mats to the same

extent as AltaLink, so AltaLink’s practices are not well-accepted, in the RPG’s view.532

565. The RPG also noted that AltaLink claimed that it must use matting to the extent it did

because it mitigates the concerns of landowners.533 However, the RPG noted with respect to the

CB project, the mitigating measure suggested before AltaLink changed its matting plan534 was to

build only in frozen conditions, consistent with Decision 2011-250.535 536

566. In reply argument, AltaLink claimed that the RPG ignored the evidence on the record and

again, reviewed the factors that arose in the CB project that affected the use of rig mats. With

respect to the use of mats on the CB project, AltaLink stated the initial estimates for matting did

not account for the increased number of matting moves required due to weather, unanticipated

site access restrictions or change, and adherence to the environmental plan. The existence of

sensitive grassland and numerous pipeline crossings further complicated management of the

matting requirements.537 AltaLink also noted the evidence provided in its rebuttal with respect to

its mat management processes that allow it to avoid the alternatives of standby charges, crew

move charges, and demobilization charges.538

567. AltaLink maintained the RPG failed to understand some fundamental points about the use

of matting to protect ground conditions. While the RPG asserted that AltaLink should have

minimized the use of mats on non-agricultural lands, AltaLink explained that native grasslands

have only a sod layer or thin topsoil as compared to cultivated land. The matting guidelines and

wet weather protocol demonstrate that cultivated land can withstand more effects before work

modification is required.539 Nonetheless, AltaLink may be required to use matting on cultivated

land to avoid effects.540

568. AltaLink argued that the RPG also failed to consider that AltaLink was required to make

commitments to landowners, pipeline companies and agencies to use mats in order to obtain

530



Exhibit 3585-X0666, paragraphs 163-164, PDF page 52. 533



Decision 2011-250: AltaLink Management Ltd., Cassils 324S – Bowmanton 244S – Whitla 251S Substations

and Associated 240-kV Transmission Lines, Proceeding 748, Applications 1606402-1 and 1606403-1, June 8,

2011. 536

Exhibit 3585-X0860, PDF pages 62-63, paragraphs 249-250. 537

Exhibit 3585-X0704, confidential rebuttal, paragraph 498. 538


Exhibit 3585-X0863, paragraph 231 refers to Exhibit 3585-X0098, PDF page 245; Exhibit 3585-X0098, PDF

page 253. 540

Exhibit 3585-X0863, paragraph 231 refers to Exhibit 3585-X0704, paragraph 559; Exhibit 3585-X0098.


118 • Decision 3585-D03-2016 (June 6, 2016)

access to the land. In these cases, there was no alternative that could be set out in a cost-benefit

analysis. AltaLink explained that doing long-term environmental damage to the land is not

permitted. The alternative in those cases would be not to build parts of the transmission line.

569. With respect to the RPG’s contention that AltaLink did not provide evidence regarding

the possibility of splitting up the CB project work between two contractors to avoid summer

work, AltaLink stated the RPG incorrectly assumed that the subcontractor did not have capacity

to complete the work in the winter. AltaLink submitted the issue, however, was access.

570. AltaLink noted that the RPG had also asserted AltaLink could have avoided costly

matting if they worked aggressively in frozen ground conditions.541 Again, AltaLink claimed the

RPG ignored the evidence on the record. In the southern part of Alberta, land conditions change

from dry to wet to frozen to thawing frequently and quickly. Despite this, the RPG suggested

AltaLink should mobilize more crews and incur an increased risk of standby and demobilization

and mobilization costs that will occur when chinooks, rain or wet snow cause land to become

wet and inaccessible without mats. The RPG also seemed to suggest that AltaLink should

comply with a landowner request to work only in frozen conditions without consideration of the

cost involved in that alternative.542

571. Finally, AltaLink noted that the RPG referred to ATCO and its use of matting as an

indicator of the imprudence of AltaLink’s matting practices.543 AltaLink submitted the RPG made

this claim with no evidence and no attempt to normalize between the projects being compared.

Instead, the RPG relied on the same assertion it advanced in Proceeding 2044, that “ATCO

Electric Transmission does not use matting to the same extent as AltaLink.”544

Commission findings

572. The Commission acknowledges that the costs incurred for matting, specifically with

respect to the Heartland and CB projects, were significant. However, the Commission does not

agree that a cost and performance audit is warranted. The Commission is satisfied that there is

sufficient information on the record of the proceeding to allow the Commission to make its final

determination.

573. The Commission accepts AltaLink’s evidence that the use of access mats is a standard

practice for mitigation of the environmental effects of transmission line construction and to allow

access to the construction right-of-way in wet or non-frozen conditions. The Commission also

accepts AltaLink’s evidence that the use of mats must be considered on a project by project

basis. Therefore, comparison among utilities of the total costs incurred for access mats with

respect to different construction projects is of limited assistance in the assessment of prudence.

Rather, the Commission finds that the use of rig mats and related costs cannot be standardized

across utilities. The evaluation of prudence must necessarily take into account the specific

circumstances of each project, such as weather conditions, project deadlines, market conditions

and the specific geographic area where the transmission line is located. The particular

circumstances of each project will usually dictate the extent of mitigation measures required and

541




Exhibit 3585-X0704, paragraph 253, PDF page 63.


Decision 3585-D03-2016 (June 6, 2016) • 119

thus, the magnitude of the costs for access mats alone, even if material, are not indicative of

imprudence.545

574. The RPG claimed that AltaLink has not undertaken a cost/benefit analysis of alternatives

to the use of rig mats. The Commission disagrees. AltaLink’s decision to use rig mats on specific

project locations was based on the results of its environmental evaluation, which considered

input from landowners, facility owners and stakeholders. AltaLink explained that, as the

construction progressed, its initial assessment for the need for rig mats was adjusted, depending

on further consultation with stakeholders and landowners and on updated information of

available right-of-way access. The Commission finds that AltaLink’s description of its practice

to determine whether to use rig mats is, essentially a form of a cost-benefit analysis.

575. In its evidence, the RPG did not provide examples of potential alternatives to the use of

rig mats AltaLink could have explored in a cost/benefit analysis, other than suggesting that

construction be restricted to winter seasons. The original schedule for CB and Heartland projects

called for winter construction primarily, but this was not always possible and the Commission

finds that AltaLink made reasonable efforts to meet requested ISDs. Further, the Commission

accepts AltaLink’s evidence that land conditions in the southern part of the Province change

from dry to wet to frozen to thawing frequently and quickly, in which case mitigation measures,

such as the use of matting, was essential for AltaLink to meet its project commitments and to

maintain construction access throughout the year.

576. The Commission’s specific findings regarding the prudence of the rig mat costs for the

CB and Heartland projects are set out in its analysis of the specific projects in Section 4.2 of this

decision.

4.1.18 Use of helicopters

577. In its intervener evidence, the RPG claimed AltaLink had provided no evidence to

demonstrate that the costs for the use helicopters for tower erection in certain transmission

projects were prudently incurred. Given the magnitude of AltaLink’s expenditures on the use of

helicopters and the absence of information establishing prudence, the RPG recommended that

Commission disallow these costs subject to a detailed cost and performance audit.546

578. The RPG explained that it does not take issue with the use of helicopters for stringing

conductor or for erecting towers in truly inaccessible places, such as steep mountainous areas

with no road access for cranes. However, AltaLink did not offer any compelling justification in

its application for the use of helicopters for the Hansman Lake, Nilrem, CB, and Heartland

projects. Rather, the reasons that AltaLink offered for using helicopters were varied, flawed, and

did not demonstrate prudence.

579. In particular, the RPG asserted that AltaLink failed to explain why there was a high

probability of access restrictions for the Hansman Lake and Nilrem projects requiring the use of

helicopters. Nor did AltaLink explain what the probability referred to. There was no evidence

that the Nilrem and Hansman Lake projects were located in mountainous areas or areas with

access problems or that the projects faced the type of access restrictions or extenuating

545




120 • Decision 3585-D03-2016 (June 6, 2016)

circumstances faced on the Southwest 240-kV project (i.e., landowners’ refusal to sign

easements and subsequent blockades, with effects on construction timing) that would justify the

use of helicopters and their associated costs in this case.547

580. The RPG claimed that AltaLink failed to identify any actual risks to the construction

schedule, the probability of delays, the length of any potential delays, the consequences of delay,

or any mitigating measures that might have been available to support its decision to use

helicopters. Instead, it appeared that AltaLink considered no options other than helicopters.

Further, AltaLink had no cross-project standards for determining when the use of helicopters was

required.548

581. With respect to the use of helicopters for the CB project, the RPG recognized that

AltaLink explained that landowner objections and time constraints required it to resort to

alternative tower erection techniques. Nevertheless, the cost effectiveness of using helicopters

for this project was still of concern. The CB project took place on grasslands, which are not

inaccessible to cranes and other vehicles549 and ATCO Electric does not use helicopters for tower

erection on flat accessible land.

582. The RPG also questioned the use of helicopters for tower erection on the 240-kV portion

of the Heartland project. The RPG stated that many parts of that transmission line have excellent

access from nearby roads for a significant portion of the line. In support of this submission, the

RPG included extractions of maps for the Heartland project, focusing on the 240-kV portion of

the line.550 The RPG maintained that the maps show that many of the line segments are close to

major roads and a significant portion of the preferred route is close and accessible from township

road 564.

583. The RPG noted that part of AltaLink’s support for its use of helicopters relied on a cost

comparison between the forecast cost of erecting towers with cranes and the forecast cost of

using helicopters for the Hanna-Hansman Lake and Hanna-Nilrem projects, and a separate

comparison done for the CB project in the filing of AltaLink’s confidential rebuttal evidence.

The cost comparison was based on unit prices of cost items such as helicopter yards rental, barb

wire fence removal and mobilization/demobilization. A cost comparison was provided for each

of Phase 1 and Phase 2 of the projects. The RPG claimed that it had identified several flaws with

these cost comparisons and, therefore, the comparisons were unreliable.

584. The RPG recommended a multi-step analysis to determine whether the use of helicopters

was justified on a particular project.551 Due to the absence of compelling justification for

helicopter use in the CB, Nilrem, Hansman Lake projects, and the 240-kV portion of the

Heartland project, the overly redacted cost comparison presented by AltaLink, and the numerous

defects in the cost comparisons made available, the RPG proposed it was unreasonable to accept

that helicopter use was the most cost effective method of tower erection for these projects.

547


Exhibit 3585-X0045, AML IR responses to CCA (1-32), PDF page 226. 549

Exhibit 0197.01.AML-2044, PDF page 2 550

Exhibit 0239.01.AML-457, PDF pages 6-7. 551

Exhibit 3585-X0666, paragraph 152, PDF page 46.


Decision 3585-D03-2016 (June 6, 2016) • 121

585. In rebuttal evidence, AltaLink stated that the decision to use helicopters for tower

erection depends on many factors including: transmission line length, tower weights, tower

geometry, access availability, environmental restrictions, number and cost of crew

mobilizations/demobilizations and crew moves, land use, and availability of suitable land bank

and terrain. Accordingly, terrain was only one factor.552 Cranes continue to be used and are

necessary for the erection of asymmetric structures (light-angles, heavy-angles).

586. AltaLink stated that tower erection may have many benefits, including: lower

competitively tendered unit rates; lower overall construction costs after taking into account

savings on access roads, matting, mobilization/demobilization and crew moves, and assistance

with recovering construction schedule. Helicopters can also have less heavy-vehicle traffic

effects in environmentally sensitive or restricted access areas.

587. In argument, the RPG agreed with AltaLink that helicopter use is a common industry

practice for a range of transmission line activities,553 but strongly disagreed that it is the standard

for the erection of transmission towers that can be accessed by cranes. The RPG stated that

AltaLink provided no evidence to contradict the RPG’s position, but simply made an

unsubstantiated assertion. On the other hand, the RPG had provided statements from both ATCO

Electric and BC Hydro that they use cranes whenever they can.554 In the RPG’s view, as ATCO

Electric and BC Hydro are two large, local and sophisticated utilities, their experience should be

given significant weight.

588. The RPG argued that the default standard for tower erection should be the use of cranes

and that the benefits of helicopters were not “obvious,” as AltaLink stated.555 The RPG submitted

when AltaLink deviated from the norm of the industry, wherein the rest of the industry avoids

helicopters for tower erection because of excessive costs, AltaLink should have presented highly

credible, reasonable evidence that they thoroughly investigated this practice. Instead, AltaLink’s

crane-to-helicopter cost comparison was flawed and simply described how they will use

helicopters. Further, AltaLink provided no credible analysis on the record to address the

concerns over helicopter use for tower erection. Consequently, it continued to recommend that a

cost and performance audit be conducted regarding the use of helicopters in these projects.

589. In argument, AltaLink continued to defend its use of helicopters, stating that the RPG had

not filed any evidence that was capable of being relied upon. AltaLink noted that when

questioned about its analysis, the RPG stated “The Ratepayer Group did not assume a crane

weight/size as part of its analysis”556 in its comparison of the costs and benefits of cranes versus

helicopter erection for RC22 and RB22 tower erection.

590. AltaLink argued that the use of helicopters in the construction of electricity transmission

lines is well established and widespread in North America by transmission facility owners and

constructors and that the appropriate use of helicopters in the construction of transmission lines

552



Exhibit 3585-X0666, paragraph 129, PDF pages 37-38; Transcript, Volume 10, page 1800, lines 8-13, and

page 1797, lines 15-22. 555




122 • Decision 3585-D03-2016 (June 6, 2016)

is good industry practice. Helicopters have been used for conductor stringing, material and crew

deployment at site and onto towers, for tower erection, tower inspections and tower maintenance.

591. In reply argument, AltaLink rejected the RPG’s claim that its costs comparison was

flawed and stated that this assertion was directly contrary to the evidence before the

Commission. AltaLink maintained that the RPG’s logic was flawed due to a lack of

understanding of the construction differences between crane and helicopter erection. In reference

to matting in place, AltaLink noted RPG stated that matting “could be used for cranes.”557 This

was incorrect. Access matting for lighter equipment used to bolt up towers after a helicopter lift

is not the same as the matting that would be required for a crane. Further, if no crane is to be set

up at a site, then matting is not required to protect the native grassland under the crane.

592. AltaLink also maintained that the RPG ignored the qualitative aspects of the analysis and

recommendation including schedule improvement/support, better utilization of the limited skilled

resources available and proactively mitigating landowner and environmental concerns with

respect to land usage and stewardship. AltaLink stated siting and constructing transmission lines

was not “a matter of only dollars and cents represented in a sterile business case.”558 AltaLink

submitted the business cases presented for Hanna and CB demonstrated reasonable decisions by

AltaLink that balanced all of the factors required to site and construct transmission lines.

Commission findings

593. The RPG has taken issue with AltaLink’s decision to use helicopters in the construction

of some of its transmission projects. Specifically, the RPG disputes the cost advantages of

AltaLink’s decision to use helicopters for tower erection instead of cranes in the CB, Nilrem

Lake, and Hansman Lake projects, and in the 240-kV portion of the Heartland project. The RPG

maintained that AltaLink has not provided sufficient evidence to demonstrate the prudence of the

costs incurred for the use of helicopters and requests that the Commission direct a cost and

performance audit of these costs.

594. The Commission disagrees with the RPG’s submission that a cost and performance audit

is needed for each of the projects referred to above to test the prudence of the costs incurred for

helicopter use. The Commission acknowledges that the costs were material, but finds that

sufficient information was provided on the record of this proceeding to allow the Commission to

make its determination. Therefore, the RPG’s request for a cost and performance audit is denied.

595. The Commission also disagrees with the RPG that the evidence provided by AltaLink in

support of its decision to use helicopters is insufficient or flawed. The Commission accepts in

principle, AltaLink’s evidence that numerous benefits can be achieved with the use of

helicopters, including: lower competitively tendered unit rates; lower overall construction costs

after taking into account savings on access roads, matting, mobilization/demobilization and crew

moves; schedule improvements; and effective mitigation of environmental issues.

596. The Commission is supportive of AltaLink’s efforts to take into consideration alternative

construction methods, such as the use of helicopters, when there are clear benefits of resorting to

557




Decision 3585-D03-2016 (June 6, 2016) • 123

an alternative approach. The benefits of utilizing helicopters, instead of cranes, for tower erection

must be determined on a project specific basis.

597. It appears to the Commission that the RPG’s main criticism against AltaLink’s use of

helicopters is that local terrain conditions did not justify the use of helicopters. Pursuant to the

RPG’s evidence, helicopter use for stringing and tower erection is only required for inaccessible

places, such as steep mountainous areas with no road access for cranes. The Commission does

not agree. The Commission accepts AltaLink’s submission that the decision to use helicopters

for tower erection is not limited to consideration of terrain conditions, but involves an analysis of

many factors, including transmission line length, tower weights, tower geometry, access

availability, and environmental restrictions. Further, the Commission accepts AltaLink’s

evidence that, in some project areas, the terrain was steep and uneven, justifying the use of

helicopters.

598. The Commission’s review of the use of helicopters on these projects was assisted by the

business cases provided by AltaLink. AltaLink is directed to continue its present practice of

preparing a business case for those projects where the use of helicopters is proposed.

599. The Commission’s specific findings regarding the prudence of the helicopter costs for the

CB, Heartland, and Hanna transmission projects are set out in its analysis of these specific

projects in Section 4.2 of this decision.

4.1.19 ADC proposal

600. In its evidence, the ADC submitted that AltaLink’s proposed reconciliation charges for

2012 and 2013 should be rejected on the basis that AltaLink had not shown that the forecasted

revenue requirement approved in its 2012 and 2013 GTA was insufficient to recover its actual

costs of service in those years, that its proposed deferral amounts did not reflect all costs that

could not be reasonably controlled, and that the potential forecast-to-actual cost variance was

material.

601. The ADC provided calculations to demonstrate that the amounts AltaLink had collected

through its revenue requirement in 2012 and 2013 exceeded the actual costs AltaLink incurred

for those same years. Based on its calculation, in 2012 AltaLink had a surplus revenue

requirement of $14.6 million, and in 2013 it had under-recovered $8.9 million. Combined,

AltaLink recovered a net revenue surplus of $5.7 million for those two years.

602. In argument, AltaLink referenced Decision 2013-407 in which the Commission rejected

the proposition that AltaLink should not be allowed deferral account recovery if there was a

positive difference between the forecast and actual return in any year.

Commission findings

603. The deferral account for AltaLink’s direct assigned capital projects was first established

in Decision 2003-061,559 which was AltaLink’s first GTA. It has always been understood that the

operation of this deferral account requires AltaLink to bring forward its actual capital project

559

Decision 2003-061: AltaLink Management Ltd. and TransAlta Utilities Corporation Transmission Tariff for

May 1, 2002 – April 30, 2004 TransAlta Utilities Corporation Transmission Tariff for January 1, 2002 – April

30, 2002,


124 • Decision 3585-D03-2016 (June 6, 2016)

costs to be tested by the Commission for prudence, and, if found prudent, the capital project

costs would be recovered in full. As a forecast for those projects would have already been

approved, AltaLink would be required to true-up the difference between the forecast and the

final approved costs. This was the arrangement in place for the capital projects that are the

subject of this proceeding.

604. The ADC’s proposal would have the effect of changing the basis for recovery of DACDA

amounts. The Commission finds that making this change in a deferral account proceeding would

be procedurally unfair to the applicant. If a party would like to propose a change in the manner in

which a deferral account operates or contest whether a deferral account should continue to be

used, then the acceptable forum to bring forward such requests is in a GTA.

605. The proposal put forward by the ADC is denied.

4.1.20 Other matters

4.1.20.1 Customer contributions

606. AltaLink provided the details of the customer contributions associated with projects

included in the application in Schedule 7-4 of its project summary schedules (excel document).560

An update to Schedule 7-4 was filed on April 2, 2015.561 As shown in Schedule 7-4, any

customer contribution to the capital addition amounts (customer contribution addition) for each

of the years 2012 and 2013 are deducted from the gross capital addition amounts to produce the

net capital addition amount for each project for each year.

607. In its response to AML-AUC-MAR05-004,562 AltaLink clarified that some of the projects

identified as customer projects in Schedule 7-4 were not direct assign projects. Accordingly, for

these projects, the customer contribution addition amount indicated in Schedule 7-4 reflects

payments made for the modification of facilities on behalf of the applicable customer rather than

the contribution arising from the application of the AESO’s contribution policy to a direct assign

customer connection project.

608. At the request of the Commission, AltaLink also provided copies of the customer

contribution decisions prepared by the AESO for the direct assign connection projects included

in the 2012-2013 DACDA application.563 As well, it submitted a reconciliation of the

contribution amounts for Fortis direct assign projects as set out in the application and the

compensation amounts for contributions requested by Fortis in various Fortis capital tracker and

capital tracker true-up proceedings.564

Commission findings

609. The amounts of the customer contribution additions for the direct assign projects included

in Schedule 7-4 typically appear to correspond to the latest customer contribution decision in

effect that AltaLink had at the time of the application.

560

Exhibit 0006.00.AML-3585, “Totals” tab. 561

Exhibit 3585-X0043, “Totals” tab. 562

Exhibit 3585-X0042, AML-AUC-MAR05-004. 563

Exhibit 3585-X0777, Exhibit 3585-X0778, Exhibit 3585-X0779, Exhibit 3585-X0780 and Exhibit 3585-

X0806. 564

Exhibit 3585-X0772.


Decision 3585-D03-2016 (June 6, 2016) • 125

610. Because a full true-up of customer contribution amounts to AltaLink’s final direct assign

connection project costs will occur by the time all trailing costs are considered, the Commission

will not require AltaLink to ensure that the customer contribution amounts are completely

reconciled with the gross addition amount requested in each DACDA year.

611. As further discussed in Section 4.3.1, because Fortis contribution amounts are assessed in

Fortis capital tracker and capital tracker true-up proceedings, the Commission must understand

the basis for the customer contribution amounts for Fortis projects. In this regard, the

Commission found AltaLink’s undertaking response in Exhibit 3585-X0772 to have been

helpful. AltaLink is directed to provide a similar reconciliation as between AltaLink and Fortis

contributions amounts in its future DACDA applications. As well, for future DACDA

applications, in order to ensure that the customer contribution amounts on AltaLink’s records

correspond to the accounting for customer contribution amounts on the records of Fortis,

AltaLink is directed to identify the AESO contribution decision that it has used in its schedule of

customer contribution additions and to file a copy of the customer contribution decision that it

has relied on for each direct assign connection project.

4.1.20.2 Land compensation

612. As set out in Section 2 of the application, AltaLink was required to provide certain

specified information related to land compensation programs arising from directives issued in

prior Commission decisions.

613. In Decision 2011-453, the Commission directed AltaLink to provide a complete schedule

showing the amounts of each type of easement program paid with respect to specific projects in

its next DACDA application and in all future DACDA applications.565 The Commission

reaffirmed this direction in Decision 2013-407.566 AltaLink provided the information pursuant to

these directions in Table 2-5, found in Attachment 2-E of the application. The total amount of

easement program costs is set out below:

Table 7. AltaLink easement costs included in 2012-2013 DACDA application projects

Easements Damages General Expenses Labour Total

($ millions)

37.5 2.5 0.3 14.3 54.5

Source: Exhibit 0002.00.AML-3585, Table 2-5, PDF page 23.

614. In argument, AltaLink noted that, with the exception of small projects located on

AltaLink-owned land, it must acquire land and compensate landowners for that use. AltaLink

noted that while its preferred method of acquiring land is through negotiation in pursuit of

easements for a right-of-way, or outright purchase of land (often required for substations), if

negotiation fails, AltaLink may be required to obtain land access through a right-of-entry order

from the Surface Rights Board (SRB).567 AltaLink noted that acquisition of land through SRB

processes generally takes more time than acquisition through negotiation.

565

Directive 21, Decision 2011-453, paragraph 1112. 566

Directive 20, Decision 2013-407, paragraph 257. 567

Exhibit 3585-X0704, paragraph. 255, cited at Exhibit 3585-X0859, paragraph 135.


126 • Decision 3585-D03-2016 (June 6, 2016)

615. AltaLink indicated that, in addition to the acquisition of rights-of-way or land, it pays

compensation in the form of annual structure payments. AltaLink also makes damage payments

for certain projects to compensate for potential damage to livestock, fences, crops, pastures, or

shelter belts that may occur during construction, buys out some nearby residences and provides

early access payments.568 The amount of land-related compensation its pays is uncertain, and may

be affected by the final approved route and the positions of individual land owners.569

616. In the oral hearing, AltaLink explained that it uses early access payments to gain early

access to lands to perform various types of environmental and geotechnical surveys so that

construction can begin immediately upon the granting of the P&L.570 AltaLink also starts

acquiring land as soon as a preferred route has been selected and filed within the facility

application for the project.571

617. AltaLink explained that early access payments create better relationships with

landowners, allow for better geotechnical information to be obtained which improves the

accuracy of its cost estimates and facilitates and improves the sequencing of construction

activities.572

618. In response to a Commission IR, AltaLink provided a list that indicated the projects in

which early access payments were made but for which AltaLink did not receive approval on the

preferred route.573 AltaLink explained that when these costs are considered on a portfolio basis,

its practice of offering early access payments leads to lower costs on an overall basis.574

619. AltaLink also asserted in its argument that in addition to the fact that no intervener

challenged AltaLink’s approach to land compensation costs, or the resulting costs, questioning

by RPG counsel suggested early access payments improve the information provided in project

procurement processes.575 As such, AltaLink submitted that the costs associated with its land

compensation and early access payment programs should be approved as filed.576

Commission findings

620. The Commission has reviewed AltaLink’s proposed compliance with directives 20 and

21 from Decision 2013-407, as set out in Attachment 2-E of Section 2 of the application and

finds that AltaLink has complied with these directives. AltaLink is directed to provide

comparable information in future DACDA applications.

621. The Commission’s prudence assessment of the compensation paid to landowners is

subject to Section 46(2) of the Transmission Regulation, reproduced below:

568



Transcript, Volume 5, pages 1024-1025, cited at Exhibit 3585-X0859, paragraph 138. 571



Exhibit 3585-X0042, AML-AUC-2015MAR05-028, cited at Exhibit 3585-X0859, paragraph 140. 574


Exhibit 3585-X0859, paragraph 141, referencing Transcript, Volume 1, pages 97-98. 576



Decision 3585-D03-2016 (June 6, 2016) • 127

(2) The Commission must consider that payments that are included in a TFO’s tariff

made by a TFO to an owner or occupant of land pursuant to any agreement between the

TFO and the owner or occupant that

(a) grants the TFO the right of entry in respect of the surface of the land, or

(b) provides for compensation resulting from or related to the use of the land for the

purposes of locating transmission facilities on it,

are prudent unless an interested person satisfies the Commission that the payments are

not prudent.

622. The compensation that AltaLink outlined in its responses to directives 20 and 21 from

Decision 2013-407 are subject to Section 46(2) of the Transmission Regulation. As no interested

persons raised land payment concerns in relation to either AltaLink’s responses to directives 20

or 21, or in relation to land owner payments of various types included in the rate base addition

amounts for the direct assign projects included in the current application, the Commission

approves AltaLink’s expenditures on such payments, subject to the findings below.

623. First, as further discussed in Section 4.2.2.14, the Commission has found that AltaLink

has not yet fully completed the acquisition and subsequent sale of lands for the Heartland project.

As a consequence, the land acquisition costs in amount of $28.3 million are not approved at this

time and should be brought forward for consideration in a future AltaLink application for the

recovery of trailing costs for the Heartland project, once the land acquisition and sale process is

completed.

624. Second, as set out in Section 4.2.3.9, the Commission has approved, on a placeholder

basis only, additions to rate base in the amount of approximately $16.3 million for WATL

project facilities brought into service during the 2012-2013 DACDA test period. Accordingly,

the Commission has made no determination on payments to land owners in relation to the

WATL project, including those described in AML-AUC-2015MAR05-028.577

4.2 System projects

4.2.1 D.0305 – Cassils to Bowmanton (CB)

4.2.1.1 Recovery requested

625. AltaLink is seeking recovery of the $34.1 million in 2012 and $311.4 million in 2013 in

respect of the CB project.

577

Exhibit 3585-X0042.


128 • Decision 3585-D03-2016 (June 6, 2016)

626. A detailed breakdown of the CB project costs at major stages is provided in Table 8

below:

Table 8. Cassils to Bowmanton cost breakdown

PPS +/- 10% update Jun 29, 2012

Additions to Dec 31, 2013(6)

Estimated Final Costs

Transmission line materials 59,031,000 54,664,000 51,821,622 50,988,062

Transmission line labour 119,851,000 165,385,000 181,432,124 204,501,727

Substation materials 10,799,000 16,221,000 14,295,575 14,277,514

Substation labour 14,346,000 33,940,000 35,319,509 35,972,077

Telecommunication materials 255,000 565,000 290,210 290,210

Telecommunication labour 553,000 647,000 640,705 661,317

O:(1) proposal to provide service 596,000 700,000 600,000 Not provided

O: facility applications 11,449,000 12,500,000 13,900,000 Not provided

O: land-rights - easements 10,361,000 7,700,000 7,800,000 Not provided

O: land-rights – damage claims 844,000 1,500,000 500,000 Not provided

O: land - acquisitions 0 100,000 0 Not provided

O: ROW(2) Costs 0 0 Not provided

Total owner costs 23,250,000 22,360,000 22,866,664 23,848,106

D:(3) procurement 393,000 5,500,000 2,600,000 Not provided

D: project management 12,296,000 12,300,000 11,700,000 Not provided

D: construction management 11,569,000 22,800,000 11,200,000 Not provided

D: Escalation 32,048,000 600,000 0 Not provided

D: contingency 55,988,000 23,100,000 0 Not provided

Total distributed costs 112,294,000 64,192,000 25,507,283 32,469,648

OT:(4) ES&G 18,475,000 21,446,000 12,352,042 13,530,126

OT: AFUDC 49,035,000 990,000 1,008,802 1,008,802

Total project costs(5) 407,889,000 380,410,000 345,534,536 377,547,589

Source: PPS Exhibit 0018.00.AML-3585, PDF page 37; Exhibit 0026.00.AML-2585; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 94.

(1) Owner costs. (2) Right-of-way. (3) Distributed costs. (4) Other costs. (5) Total project costs do not include salvage. (6) Some numbers may not add up due to difference between exhibits in significant digits used.

4.2.1.2 Project overview

627. On September 8, 2009, the Commission approved the NID application of the AESO for

the Southern Alberta Transmission System Reinforcement (SATR) project.578 The AESO

explained in its NID application that the SATR project was driven by a need to connect between

2,000 and 3,900 megawatts(MW) of wind-powered generation forecast for southern Alberta.579

The SATR NID was approved in Decision 2009-126.

628. At the direction of the AESO, AltaLink prepared a PPS for the CB project that estimated

costs of $407.9 million and a forecast ISD of March 2014.

629. AltaLink filed a facility application for the CB project in June 2010. The scope of the

project included construction of two 240-kV substations, the Cassils 324S substation, to be

578

Decision 2009-126. 579



Decision 3585-D03-2016 (June 6, 2016) • 129

located in the vicinity of Brooks and the Bowmanton 244S substation, to be located to the N.E.

of Medicine Hat and the connection of these two substation with a high-capacity double-circuit

240-kV transmission line of approximately 130 km in length.580 The Commission approved this

facility application in Decision 2011-250 on June 8, 2011.

630. On June 6, 2012, AltaLink filed two applications, 1606402 and 4606403, to amend two

of the permits and licenses issued in conjunction with Decision 2011-250 to reflect route changes

on the CB and Bowmanton to Whitla projects to reflect certain issues AltaLink became aware of

after additional consultation with local stakeholders including landowners and oil and gas

industry participants. Specifically, in respect of the CB project, AltaLink proposed the following

adjustments:

Route alignment changes to accommodate a new pipeline constructed by AltaGas

Utilities Inc.

A change to the alignment of the South Saskatchewan River crossing to avoid soils prone

to erosion.

Route adjustments to accommodate oil and gas facilities belonging to Canadian Natural

Resources Ltd., Cenovus Energy Inc., and Imperial Oil Ltd.581

631. The Commission approved the requested route changes in Decision 2012-336582 in

December 2012. A table listing the proceedings, decisions and associated approvals issued by the

Commission in respect of the CB project is in Appendix 4.

632. The project was energized in November 2013, approximately three months ahead of the

initial ISD schedule of March 2014. The final cost of the project was $377.5 million.583

4.2.1.3 Key project variances

633. AltaLink identified the following change notices filed with the AESO as representative of

key events that affected the schedule, scope or cost of the CB project:584

580


Exhibit 0021.00.AML-3585, page 2. 582

Decision 2012-336: AltaLink Management Ltd., Amendments to Cassils to Bowmanton to Whitla 240-kV

Transmission Lines 1034L/1035L, 964L/983L and 1073L/1074L, Proceeding 2004, Application 1608625-1,

December 13, 2012. 583

The PPS included AFUDC of approximately $48.5 million bringing the PPS net of AFUDC to $359 million.

AFUDC was subsequently removed by Commission Decisions 2011-453 and 2013-407. 584

Exhibit 0017.AML.3585, page 7.


130 • Decision 3585-D03-2016 (June 6, 2016)

Table 9. CB change notices

Impact Analysis

Summary of Requested Change

Cost

Impact

$M

# Months

ISD Shifted

Date

Submitted

Change

Notice Status S

cope

Sch

edul

e

Cos

t CP

AFUDC1

X AFUDC reconciliation (48.3) - Nov 2012 Approved

CP AFUDC2

X AFUDC reconciliation (0.2) - May 2013 Approved

CP3

X Project proceeding ahead of

schedule - -4 Oct 2013 Approved

CP4

X AFUDC correction to coding

0.5 - Nov 2013 Approved

CP5

X

Delay FCR to include accurate AC mitigation costs – YE 2014

-

-

May 2014

Acknowledged

CP6 X Pipeline AC mitigation 19.9 - Jul 2014 Approved

CP7

X

Delay FCR to include accurate AC mitigation costs – June 2015

-

-

Nov 2014

Acknowledged

634. The RPG, relying on FTI’s evidence, has recommended that the Commission disallow

$56.6 million from the CB project costs on the basis that AltaLink has failed to support the costs

it incurred for transmission line labour and substation labour during the execution of this

project.585 In particular, the RPG was critical of AltaLink’s costs associated with weather and

land acquisition delays, the use of rig mats, the use of helicopters and pipeline mitigation costs.

The Commission has addressed these issues in the subsections that follow.

4.2.1.4 In-service date

635. In its intervener evidence, the RPG maintained that a project that comes into service three

months ahead of schedule, with $126 million dollars in costs that were unanticipated, should not

have a final forecast cost for the total project that is under both the original budget and under the

authorized budget unless the original estimate was grossly overstated.

636. AltaLink responded to the RPG in its rebuttal evidence, explaining that as of July 25,

2011, the project had 48 per cent of easements acquired, 202 of 389 structures (52 per cent)

requiring SRB action, 50 per cent of crossing agreements in place and 73 per cent of Water Act

applications filed. By December 16, 2011 the project had 58 per cent of easements acquired, 43

per cent structures remaining for SRB action, 71 per cent Water Act approved, 50 per cent

historical resource clearances received and 45 per cent traditional land use clearances received.

AltaLink maintained these delays resulted in appropriate and reasonable mitigative measures

being undertaken by AltaLink.

585

Exhibit 3585-X0860, paragraph 286, page 71.


Decision 3585-D03-2016 (June 6, 2016) • 131

637. For the first spring and summer of work, AltaLink noted it filed the helicopter business

case, which identified the reasons and cost benefits of a change in project plan. For the second

spring and summer of work, AltaLink noted it filed Exhibit 3585-X0380c-3-CONF (Change

Orders 61 through 98) in which Change Order 68 described the business case supporting the

revised plan to complete stringing of both the CB and Bowmanton to Whitla (BW) projects in

the most cost effective way during the spring and summer of 2013. AltaLink explained a key

execution strategy of the CB project was to execute it at the same time as the BW project so that

both projects could benefit from one team running two large projects in the same area. Crews

could be moved between projects rather than incur the cost of demobilization or lost time in the

schedule. Continuing to construct through the spring and summer of 2013 was assessed by

AltaLink to be both cost effective and a means to maintain schedule.

638. In argument the RPG maintained there were opportunities for AltaLink to work with the

AESO to provide some relief in the form of reduced costs and to communicate to the AESO the

cost consequences of not moving an ISD to a later time. The RPG claimed this project

represented a missed opportunity and asserting that “with a little bit of thought [that project]

could have been moved, particularly when the main anchor for it on the far end of the line

cancelled the project well in advance of the project.”

639. In argument AltaLink stated that it had the obligation to meet the forecast or expected

ISD as established by the AESO and that it had engaged with the AESO on many matters

including cost to meet forecast or expected ISDs.

Commission findings

640. The concern of the RPG is two-fold.

641. First, the RPG had argued that AltaLink should have been able to provide information to

the AESO that would have resulted in the AESO either moving or cancelling the project.

642. The Commission recognizes that the AESO establishes the ISD for a project and the TFO

must comply with the direction of the AESO unless doing so would put its facilities or the safety

of the TFO’s employees or the public at risk. However, the AESO does not operate in a vacuum

and there is an expectation that the TFO will keep the AESO informed of issues as they arise and

that it provide information to the AESO to assist it in making decisions regarding the setting

and/or adjustment of the ISD. The evidence on this record demonstrates that this was done.

643. The AESO, as the system planner, would have been well-aware of the fact that the wind

generator proponent had cancelled the project. It was not dependent on AltaLink to provide this

information. As AltaLink was providing cost updates and monthly reports throughout the

execution of this project, it is reasonable to conclude that the AESO would have been aware of

the costs to cancel or delay the project. It chose not to do either, and consequently, there was

nothing unreasonable about the fact that AltaLink continued to execute the project. It was

legislatively obligated to do so.

644. The second concern raised by the RPG was that the decisions made by AltaLink to incur

costs to make up delays in the schedule were unreasonable as evidenced by the fact that the CB

project was brought in to service early.


132 • Decision 3585-D03-2016 (June 6, 2016)

645. The Commission accepts AltaLink’s evidence that significant access issues emerged

early in the construction process. These access issues required revisions to the construction plan

to meet the ISD, notably the decision to continue construction in the summer season, which

entailed the use of matting and the use of helicopters to erect towers. The use, and cost of

matting and helicopters, has been addressed in the sections below.

646. It was the decision to continue construction in the summer periods, to make up time lost

to access issues, that allowed the project to be completed early. The use of helicopters allowed

construction to proceed at such a pace that more schedule time was made up than would

otherwise have been lost to the delays caused by access problems. The Commission also notes

that Change Proposal 3 indicated that no species appeared in the vicinity of the construction

during bird breeding season, avoiding further shutdowns that might otherwise have occurred.

647. The Commission considers the mitigation measures taken by AltaLink, particularly to

execute it at the same time as the BW project so that both projects could benefit from one team

running two large projects in the same area and reduce or avoid the cost of demobilization or lost

time in the schedule to be reasonable.

4.2.1.5 Use of rig mats

648. As more particularly detailed in Section 4.1.16 of this decision, the RPG was critical of

AltaLink’s use of rig mats and in particular considered that for the CB project, AltaLink failed to

justify what it considered to be an excessive use of these rig mats.

Commission findings

649. As required by ISO Rule 9.1.5, the provision of rig mats was secured through a tender

process.

650. The initial contract with RS Line, the subcontractor retained for the construction of the

240-kV line, stipulated the requirement for a certain number of access mats and contemplated

that additional mats might be necessary. Pursuant to the contract agreement, the rental of crane

and rig mats was permitted for two tranches of the project. Additionally, the contract provided

for the rental or purchase of sufficient cinch mats for an additional period of time.586 These

documents provide a clear indication that the original planning for the CB project contemplated

significant requirements for matting.

651. At the time the PPS estimate for this project, which included a forecast cost for rig mats,

was developed, AltaLink assumed that it would have full and unfettered access to the right-of-

way from its proposed starting date of September 2011. However, AltaLink experienced

substantial access issues during the execution of the CB project. As indicated in AltaLink’s

rebuttal evidence, as of January 2012, three months after the planned start of construction, only

58 per cent of land access had been acquired and for 167 sites, access was only secured through

right of entry orders obtained from the SRB.587

586

RS Line contract, Section 5, IR response Conf. 038-17, document 399. References to specific contractual

numbers have been omitted in the decision but are available on the confidential record. 587



Decision 3585-D03-2016 (June 6, 2016) • 133

652. Site access restriction delayed the project construction schedule and AltaLink, having

reported this matter to the AESO and having received change order approval, amended its work

plan to work in the summer season to meet the requested in-service date. The requirement to

complete construction in the summer resulted in a greater use of matting than initially

contemplated. AltaLink retained a coordinator to review and track the use of mats for the CB

project.

653. Expenditures incurred by RS Line, including those for matting, are accounted for by the

subcontract amendments contained in IR response CCA-AML-038(a)17 Conf., Exhibit 3585-

X0382. The Commission has reviewed each of the amendments and finds them to be reasonable.

654. In summary, the Commission accepts AltaLink’s evidence as to the increased need for rig

mats beyond initially contemplated. The Commission also finds that, as the AESO was aware of

the schedule change and the effect of this change on the cost, the steps taken by AltaLink to

manage the use of the rig mats on the project through the coordinator were also reasonable under

the circumstances.588 Further, the price for rig matting was on a unit basis and as a result of a

competitive tendering process, and there is no evidence that this tendering process was

conducted unfairly or that the tender was awarded unfairly. For all of these reasons, the

Commission does not find AltaLink to have incurred rig mat costs unreasonably on the CB

project.

4.2.1.6 Use of helicopters


AltaLink’s use of helicopters and considered that AltaLink had failed to justify its use of

helicopters on this project. In particular, the RPG was critical of the cost comparison AltaLink

prepared for the CB project and maintained that AltaLink’s redaction of the unit prices for each

cost category made it nearly impossible to analyze the cost comparison in any meaningful way to

assess the prudence of the helicopter costs.

656. In response, AltaLink referred to Exhibit 0025.00.AML-3585, in which it provided the

CB AESO reports for the period July 2011 to April 2012. These reports revealed that delays in

access due to landowner and agency approvals were clearly identified within the emerging issues

section. Further exhibits, such as Exhibit 3585-X0158, which included the SNC MER reports

indicated that access was an issue. Page 4 of the August reports stated:

Lines right of way prep activities commenced on August 22nd. Delays in receiving

schedule A’s, crossing agreements and water act approvals have limited progress

page 5 of the September 2011 MER report stated:

Access issues with towers T71 – T11 causing delays with right-of-way preparation. Lines

subcontractor moved to BW line until access issues have been resolved

and page 5 of the November report stated:

WAA [Water Act approval], access issues and pending route amendments impeding

progress on committed CB plan.

588

The AESO’s awareness of this issue was set out in the month-end reports and change proposals.


134 • Decision 3585-D03-2016 (June 6, 2016)

657. As well, the CB helicopter business case589 clearly referred to the increased environmental

constraint of the bird nesting season, which is approximately April 15 to July 31.

658. AltaLink explained that its use of helicopters and assembly yards during the time of

increased environmental constraints was a mitigation method in response to the risk of

construction delays. Further, AltaLink maintained that the RPG did not provide any calculations,

assumptions employed or source data to support its allegation that the use of helicopters involved

a higher cost than the use of cranes.

659. Finally, AltaLink asserted that the RPG’s argument that the cost of helicopters was

subsumed into the unit price in the RS Line contract was incorrect. Section 9.2 of the RS Line

contract pertained to the use of helicopter for stringing conductor, not the use of helicopters for

the erection of steel lattice towers. There was no provision within the RS Line contract pertaining

to the use of helicopters for tower erection. AltaLink explained this was addressed through an

amendment to the RS Line contract, Exhibit 3585-X0380C-1CONF, based upon the helicopter

business case.

Commission findings

660. The Commission accepts the crane versus helicopter analysis provided by AltaLink in

rebuttal evidence.590 The Commission has reviewed AltaLink’s analysis and considers it to be

reasonable and supportive of AltaLink’s decision to utilize helicopters.

661. In particular, the Commission is satisfied with the reliability of the sources on which

AltaLink based its analysis. The estimated production rates for helicopter erection were based

upon the actuals achieved in AltaLink’s Southwest 240-kV project. The values used for cost

comparison purposes were the direct unit costs submitted in the RS Line tender proposal. The

unit quantity estimates were based on AltaLink’s experience from similar projects. Therefore, the

Commission finds that the RPG’s concerns with AltaLink’s analysis are not justified. The

Commission also finds the analysis clearly showing that the costs associated with the use of

helicopters for tower erection are more than offset by the costs AltaLink would have incurred for

mobilization and demobilization associated with crane erection.591

662. Given the above evidence the Commission considers AltaLink’s expenditures on

helicopters in the CB project to be reasonable.

4.2.1.7 Pipeline mitigation

663. A transmission line can cause induction of currents and voltages in a metallic object that

is within about 200 metres of and parallel to the line (such as a pipeline). AC interference can

cause corrosion on the pipe, pipeline damage due to transmission line to ground faults and touch

voltages (electric shock), which are a safety hazard. A number of factors may affect the extent of

AC interference, such as proximity of a transmission line to a pipeline, soil resistivity, length of

the line which parallels a pipeline and the phasing arrangement of the transmission line.

589

Exhibit 3585-X0704, rebuttal, Tab 1. 590

Exhibit 3585-X0704, Tab 1. 591

Exhibit 3585-X0704, Tab 1, pages 7 and 10.


Decision 3585-D03-2016 (June 6, 2016) • 135

664. AltaLink has a standard for grounding metallic objects in close proximity to its

transmission lines and will install mitigation to reduce induced current and voltage.592 Typically

it is the responsibility of the new facilities owner to pay for the costs of mitigating negative

impacts, in this case AC interference, on existing infrastructure.

665. AltaLink’s goal is typically to select routes, for the Commission’s consideration, which

reduce effects, avoid obstacles and takes into consideration information from stakeholder

consultation. The goal of avoiding existing oil and gas wells, pipelines and compressors and

processing facilities is taken into account when developing the preferred route. AltaLink obtains

necessary crossing agreements for pipelines crossings prior to construction and, where induction

mitigation measures are required, AltaLink works with the pipeline companies to address the

issues and develop appropriate mitigation measures.593

666. In the project execution plan, AltaLink stated that baseline data would be provided to

pipeline owners to complete an induction study for its facilities. Mitigation measures developed

by the pipeline companies would be reviewed by AltaLink for reasonability and to compare to

the expected mitigations. The pipeline companies would be responsible for installation of the

mitigation measures prior to energization and AltaLink would pay for all reasonable costs for the

studies and mitigation measures.594

667. AltaLink forecast $2 million for pipeline induction studies and mitigation measures in the

PPS, based on its assumption from other projects that 210 pipelines along the right-of-way would

require studies and of these, mitigation would be required for some of them.595 After AltaLink’s

applied-for preferred route was approved, the actual number of pipeline crossings turned out to

be 1,159.596

668. AltaLink first notified the AESO of issues with pipeline mitigation in its November 2013

monthly report: “Some pipeline companies have not completed their induction mitigation

studies. Remaining design/mitigation scope and costs to be confirmed in Q1 2014.”597 In the

December 2013 monthly report, AltaLink revised the unplanned/emerging issue to note that

“Based on preliminary estimates from pipeline companies, expecting to exceed budgeted

amounts for mitigation.”598

669. AltaLink provided an updated estimate of pipeline induction mitigation in a change order

to the AESO on July 23, 2014. The change order estimated an increase in pipeline mitigation

costs of $19,922,700 for total pipeline mitigation costs of $20,803,000, which included a

contingency amount of $2,384,000. AltaLink explained that pipeline companies were notified in

the fall of 2011 of the need to implement induction mitigation by December 2013. However, by

September 2013, only two facility owners had completed induction studies, 10 had studies in

progress, five were deciding if studies were needed and seven had not replied to AltaLink’s

592

Exhibit 0020.00.AML-3585, PDF page 191. 593


Exhibit 3585-X0098, AML-CCA-2015MAR05-067 Attachment 1, PDF page 331. 595






136 • Decision 3585-D03-2016 (June 6, 2016)

correspondence.599 After completion of the AC mitigation studies, 314 sites required mitigation

and 27 sites required corrosion monitoring.600

670. Although the CB project was energized at 240 kV on November 26, 2013, project close-

out was not complete at the time of filing due to ongoing pipeline mitigation issues.601 The

remaining forecast costs (outside the 2012-2013 deferral account application period) are for

pipeline induction mitigation and were incurred in 2014 and 2015.602

671. The RPG claimed that AltaLink failed to develop any sort of mitigation strategy to

manage these pipeline mitigation costs. In the RPG’s view, AltaLink should have known the CB

project was in an area with pipeline operation and, therefore, AltaLink should have known that

pipeline mitigation would be required. The RPG stated that AltaLink should have also known to

locate a transmission line further from pipelines to minimize AC induction effects.

Consequently, the RPG recommended that the Commission only approve the original PPS

estimate for AC mitigation costs and that any amounts above that should be reviewed in a cost

and performance audit.603

672. In rebuttal evidence, AltaLink stated that the density of gas wells and associated pipeline

network is similar throughout the project area where the transmission line routes were

considered. In AltaLink’s submission, locating a transmission line to minimize the number of

affected oil and gas facilities is not possible in this part of Alberta. It does not conduct AC

induction mitigation studies in advance of P&L because the approve route information is a

necessary input into the AC induction mitigation study. Additionally, AltaLink disagreed with

the RPG’s statement that no mitigation strategy had been developed. It worked with pipeline

owners to find low cost solutions to AC mitigation and also reviewed the studies, designs and

mitigation installation costs to test the reasonableness of the costs and to propose lower cost

options.604

Commission findings

673. AltaLink is required to mitigate the negative effects from its new facilities on existing

facilities. When the Commission approved the final route for this project in Decision 2011-250,

it approved the preferred route applied-for by AltaLink. It is reasonable to conclude that

AltaLink would have known or should have known at the time that the CB project area had a

high density of existing oil and gas and pipelines facilities which would have required significant

AC mitigation measures.

674. The Commission understands that AltaLink estimated $2 million for pipeline mitigation

in its PPS estimate but that the final costs for pipeline mitigation are now estimated to be

$20,803,000. Of the $20,803,000, some portion of those costs were incurred outside of the 2012-

2013 period of this application.

599




Exhibit 3585-X0042, AML-AUC-2015MAR05-038(a), PDF page 450. 603




Decision 3585-D03-2016 (June 6, 2016) • 137

675. The Commission finds that there was insufficient information on the record of this

proceeding to determine prudence for the following reasons:

There is no evidence on the record to show that AltaLink considered alternatives to

manage the cost increases in pipeline mitigation costs. The Commission accepts that

AltaLink has a process in place for pipeline mitigation that includes consultation with

pipeline companies, review of the proposed mitigation measures and review of the

invoices for installation of the mitigation measures. However, apart from AltaLink’s

assertion in its reply argument that it submitted five route amendments as a result of new

information regarding pipeline facilities,605 there is no evidence to show that at any point,

AltaLink rejected or proposed alternatives to the pipeline mitigation measures submitted

by the pipeline companies. By comparison, AltaLink filed evidence that showed it

attempted to reduce the cost effects of pipeline mitigation on the Heartland project by

recalculating the 10 year loading parameters.

The estimated costs for final pipeline mitigation costs are 10 times the costs estimated at

the PPS stage whereas the number of pipeline crossings is 5.5 times greater. There is no

evidence on the record that explains this disconnect nor why the PPS estimate was not

within the +20/-10 per cent accuracy requirement.

AltaLink has not adequately explained why a delay on the part of pipeline owners to

complete mitigation studies contributed to the increase in pipeline mitigation costs nor

what measures it took to discuss with the pipeline owners the effect of this delay.

Finally, the Commission issued its Decision on the facility application on June 8, 2011

and construction began in September 2011,606 but AltaLink did not notify the AESO of

delays with the pipeline mitigation studies until the end of 2013 when the transmission

line was energized. There is no explanation for this delay in notification when the

evidence on the record suggests that pipeline mitigation measures are typically installed

during construction.

676. The Commission is prepared to approve, as a placeholder for purposes of this application,

the entire pipeline mitigation amount of $20.8 million. The Commission will consider this

amount for final approval in AltaLink’s next DACDA.

677. AltaLink is therefore directed to include in its compliance filing, for purposes of rate base

and return calculations, the actual amount of pipeline mitigation costs.

678. AltaLink is also directed to include the pipeline mitigation amount in trailing costs in

AltaLink’s next DACDA where it will be reviewed for final approval. AltaLink can supply full

supporting documentation for the claimed amount at that time.

679. As discussed in Section 4.1.10 of this decision, the Commission denies the RPG’s request

for a cost and performance audit of pipeline mitigation costs for CB. The Commission has

determined that directing an audit would be inefficient and unnecessarily duplicative as it is the

605




138 • Decision 3585-D03-2016 (June 6, 2016)

Commission, and not the auditor who must make final determinations of prudence. Pipeline

mitigation costs for CB will be examined in a future DACDA.

4.2.1.8 Analysis of change notices

680. The FTI evidence, prepared on behalf of the RPG, provided an analysis of certain change

notices in the CB project.607 FTI concluded that a number of change notices were not adequately

justified and, therefore, should be disallowed.608 The list of change notices recommended for

disallowance, included in Appendix 1 to the FTI evidence, totalled $56.6 million.

681. In confidential argument, the RPG referred to specific change notices, maintaining that

they contained inconsistencies and inadequate explanations for the costs in the change notices.609

682. In reply argument, AltaLink stated that it had filed on the record of the proceeding, the

original change notices that specifically detail the changes proposed, the basis for those changes,

and the costs involved in those changes.610 AltaLink questioned whether the RPG or its experts

made use of the source documents available to them.

Commission findings

683. The prudence of a particular expense cannot be determined based on the examination of

change notices alone. The Commission, in addition to its review of the change notices, also

examined all the subcontract amendments with respect to the CB project.611 In its review, the

Commission noted some matters of concern.

684. EPC Change Order Request 46, which was provided on the confidential record, is for

costs to perform environmental remediation on crates supplied by KEC.612 As explained in the

change order, KEC had been supplying crates with visible moulding. All of SNC-ATP’s efforts

to fix this problem with KEC were to no avail. The Commission understands that AltaLink

incurred costs to remediate the problem and accepts that it was necessary to incur these costs to

do so. However, the Commission does not consider it to be reasonable for AltaLink to have

included these costs for recovery from ratepayers. Rather, the Commission finds that it would

have been reasonable for AltaLink to have recovered these remediation costs from either KEC,

as the party responsible for the requirement to incur these remediation costs, or from SNC-ATP,

as the contract manager on the project. As stated in Section 4.1.13. 16, AltaLink stated that SNC-

ATP was earning its management fee because it was taking the risk on managing the contract.

685. The Commission has reviewed Tab 10 of AltaLink’s rebuttal evidence613 and can find no

indication that this amount was ever charged back. The Commission also reviewed the

PO/contract log614 and could find no evidence that a credit was processed against KEC. AltaLink

is directed, therefore, to deduct the total amount of this change order from its compliance filing.

607

Exhibit 3585-X0667, pages 20-31. 608

Exhibit 3585-X0667, Appendix 1, PDF pages 109-112. 609

Exhibit 3585-X0860-CONF, page 76. 610

Exhibit 3585-X0380c-1-CONF, Exhibit 3585-X0380c-2-CONF and Exhibit 3585-X0380c-3-CONF. 611

Exhibit 3585-X0382, AML-CCA-038(a)17, approximately 80 separate folders. 612

Exhibit 3585-X0380c-2-CONF, page 6. 613

Exhibit 3585-X0704. 614

Exhibit 3585-X0526.


Decision 3585-D03-2016 (June 6, 2016) • 139

AltaLink is also directed to deduct from its costs any management surcharge amount it may have

paid to SNC-ATP to manage this change order.

686. In arriving at this finding, the Commission is not determining whether AltaLink or SNC-

ATP have a contractual remedy available, nor is the Commission determining what the costs of

pursuing this remedy might be. The Commission recognizes that there is a commercial cost to

pursuing contractual remedies and also recognizes that, the first step in resolving a dispute does

not necessarily involve bringing a legal action. The remedies available and whether to pursue

these remedies are business decisions to be made by AltaLink.

687. The Commission notes that in AltaLink’s confidential rebuttal evidence, AltaLink filed

details of a settlement reached between it and SNC-ATP with respect to non-compliant materials

procured by SNC-ATP. AltaLink indicated litigation was ongoing between the supplier and

SNC-ATP but that AltaLink did not pay for the replacement of these materials. As AltaLink has

indicated that there may be additional funds paid to AltaLink pending the outcome of this dispute

between SNC-ATP and the supplier, AltaLink is directed to file an update as to the status of this

issue in its compliance filing.

688. The Commission also paid particular attention to the expenditures and subcontract

amendments related to the work performed by RS Line, Iconic Electric and Wheatland

Contractors as the RPG had singled out change notices related to work performed by these

subcontractors. The Commission finds them to be in order.

4.2.1.9 Summary of findings

689. The Commission has made a number of findings with respect to the CB project and

considers that a summary may be helpful. In summary, the Commission has found the following

with respect to the CB project:

The measures taken by AltaLink to meet the scheduled in-service date were reasonable

and prudent.

The use of matting on the project and the consequential costs were reasonable and

prudent.

The use of helicopters for the erection of towers on the project, and the consequential

costs were reasonable and prudent.

The inclusion of costs incurred relating to the remediation of the crates supplied by KEC

including any costs for any management surcharge amount it may have paid to SNC-ATP

was not reasonable and these costs are directed to be removed.

The costs for pipeline mitigation were significantly higher than the PPS estimate. The

Commission has approved a placeholder for the requested amount, approximately

$20.8 million. AltaLink is directed to supply further support for the claimed expenditure

when filing its next DACDA.


140 • Decision 3585-D03-2016 (June 6, 2016)

4.2.2 D.0371 – Heartland

4.2.2.1 Recovery requested

690. AltaLink is seeking recovery of $602.3 million in 2013 and $94.8 million in 2014 in

respect of the Heartland project. The Heartland project is a joint venture between AltaLink and

EDTI. Accordingly, a portion of the capital addition to December 31, 2014 will be added to the

rate base of EDTI after a reconciliation.

691. A detailed breakdown of the Heartland project costs at major stages is provided in Table

10 below:

Table 10. Heartland Transmission project (D.0371) cost breakdown

PPS +/- 10%

Oct 12, 2012 Additions to Dec 31, 2014

Estimated Final Cost






Telecommunication labour 829,037 830,869 1,188,990 1,147,241

O: proposal to provide service 13,569,380 12,200,000 12,000,000 Not provided

O: facility applications 37,313,391 45,900,000 45,600,000 Not provided O: land-rights - easements 20,248,662 18,500,000 22,800,000 Not provided O: land-rights – damage claims 1,045,000 300,000 800,000 Not provided O: land - acquisitions 3,923,444 11,100,000 28,300,000 Not provided O: ROW Costs - - - Not provided Total owner costs 76,099,877 88,055,019 109,599,143 104,772,228

D: procurement 1,980,000 4,100,000 5,000,000 Not provided D: project management 10,747,807 18,300,000 24,900,000 Not provided D: construction management 6,616,386 9,200,000 18,300,000 Not provided D: escalation(2) 39,212,057 18,300,000 0 Not provided D: contingency 39,624,201 38,500,000 0 Not provided Total distributed costs 98,180,451 88,350,463 48,283,625 52,351,284

OT: ES&G 31,410,680 27,882,347 17,440,694 17,710,925

OT: AFUDC 45,875,122 10,064,105 14,212,560 14,212,548


(1) Total project costs do not include salvage. (2) Escalation was included in “ other costs” not “distributed costs” in the PPS estimate. Source: Exhibit 0087.00.AML-3585 (PDF 36); Exhibit 0096.00.AML-3585 (PDF 2); Exhibit 3585-X0043; Exhibit 3585-X0043 (AML-AUC-2015MAR05-003 Attachment, PDF page 99).

4.2.2.2 Project overview

692. The Heartland project was initiated address a critical need for transmission in Alberta and

was designated by the Province of Alberta as critical transmission infrastructure.615 The

Heartland project is a joint project between AltaLink and EDTI.

693. At the direction of the AESO, AltaLink prepared a PPS for the Heartland project that

estimated costs of $579.6 million and a forecast ISD of March 2013.

615

Under the Electric Statutes Amendment Act, 2009 (also known as Bill 50), the Government of Alberta approved the need

for four CTI projects including the Heartland project.


Decision 3585-D03-2016 (June 6, 2016) • 141

694. AltaLink filed a facility application for the Heartland project in September 2010. The

scope of the project included construction of 65 km of 500-kV line from the Ellerslie substation

south of Edmonton to the new Heartland 012S substation north of Heartland. Another 22 km of

240-kV line was constructed from the new substation to interconnect with the AIES. EDTI and

AltaLink share ownership of the 500-kV transmission line while AltaLink owns the substations

and 240-kV line.

695. The facility application proceeded to a hearing. During the hearing, certain stakeholders

raised concerns about the routing in the transportation utility corridor (TUC) near Sherwood

Park. As a result, AltaLink and EDTI proposed repositioning a section of the route 100-200

metres west within the TUC and filed an amended facility application on April 26, 2011,

reflecting that routing change. The Commission approved the amended facility application in

Decision 2011-436616 on November 1, 2011.

696. The AUC approved the east TUC overhead route with the modifications proposed in the

amended facility application. The AUC also approved a modification to use monopoles for

approximately 9.5 km of the route to mitigate visual effects on that section of the route.

Additional conditions were also imposed on AltaLink including:

To ensure tower heights meet minimum clearance requirements near a heliport.

Conduct comprehensive sound level surveys for Ellerslie 89S and Heartland 012S

substations.

measure electric and magnetic field readings in and around an elementary school and

investigate alternative routing around the school.

work with stakeholders to explore the possibility of moving Tower 175 and 176.

697. AltaLink investigated the alternative route options near the elementary school as directed

by the Commission but there were no further amendments to the route. AltaLink also worked to

investigate relocation of structures T175 and T176. In July of 2012, AltaLink filed an

amendment to move the structures. In March of 2013, the Commission approved AltaLink’s

amendment to move T175 and T176.

698. A table listing the proceedings, decisions and associated approvals issued by the

Commission in respect of the Heartland project is in Appendix 4.

699. The project was partially energized on December 28, 2013 and fully energized on July

24, 2014, 16 months later than originally forecast. AltaLink has forecast the final cost of the

project to be $712.4 million.617

4.2.2.3 Key project variances

700. AltaLink identified the following change notices filed with the AESO as representative of

key events that impacted the schedule, scope or cost of the Heartland project:618

616

Decision 2011-436: AltaLink Management Ltd. and EPCOR Distribution & Transmission Inc., Heartland

Transmission Project, Proceeding 457, Application 1606609-1, November 1, 2011. 617

Exhibit 3585-X0794, AML-AUC- 2015MAR05-042 Attachment, Tab D.0371 618

Exhibit 0017.AML.3585, page 7.


142 • Decision 3585-D03-2016 (June 6, 2016)

Table 11. Heartland change notices

AESO Change

Notice No. (TCA or

CP)

Impact Analysis

Summary of Requested Change

Cost Impact

#

Months ISD

Shifted

Date

Submitted

Change

Notice Status

Sco

pe

Sch

edul

e

Cos

t

TCA1

X

X Bannerman project delay resulted in additional scope

$61,000

-

Dec. 2011

Rejected

TCA2 X X X Reconcile to AUC Decision

$41,177,888 6 Dec 2011 Acknowledged

TCA3 X X Redesign 240-kV yard electrical scheme

$279,939 - Mar 2012 Approved

CP4 X Remove AFUDC ($33,514,531) - Nov 2012 Approved

CP5

X

X

Bannerman project delay resulted in additional scope

$519,985

-

Apr 2013

Approved

CP6 X Subcontractor re- contracting

- 2 Apr 2013 Approved

CP7

X

True-up to PPS Update Estimate (+/- 10%)

$12,568,409

-

Oct 2013

Approved

CP8

X

X

Bannerman project delay resulted in reduction in scope

($617,400)

-

Oct 2013

Approved

CP9

X

X

X

Temporary energization at 240 kV

$4,917,567

-

Nov 2013

Approved

CP10 X Additional construction costs

$56,737,229 - Feb 2014 Rejected

CP11 X Increased cost of AC Mitigation

$50,652,640 - Feb 2014 Approved

CP12

X X Complete energization at 500 kV

$2,788,678

7.5

Jan 2014

Approved

701. The RPG, relying on FTI’s evidence, has recommended that the Commission disallow

$61.7 million from the Heartland project costs on the basis that AltaLink has failed to support the

costs it incurred for transmission line labour and substation labour during the execution of this

project.619 In particular, the RPG was critical of AltaLink’s costs associated with weather and

land acquisition delays, the use of helicopters and pipeline mitigation costs, AltaLink’s selection

of Graham Construction as the main subcontractor for the construction of the 500-kV

transmission line, and land acquisition costs. The RPG requested that a cost and performance

audit be performed with respect to a number of this matters. The RPG also objected to the

619

Exhibit 3585-X0860, paragraph 286, page 71.


Decision 3585-D03-2016 (June 6, 2016) • 143

inclusion of Heartland’s 2014 project costs as part of this DACDA application. The Commission

has addressed these issues in the subsections that follow.

4.2.2.4 Inclusion of 2014 costs

702. AltaLink included as part of the application, the Heartland project costs consisting of

actual costs incurred up to November 30, 2014. It indicated that the balance of any future project

costs will be included as trailing costs.620 AltaLink submitted that the life-to-date project costs for

Heartland have been included in this application in order for the Commission to assess the

reasonableness of the overall Heartland project costs in a single application, thereby achieving

regulatory efficiency.621

703. In its evidence, the RPG maintained that although the Heartland project was energized at

240 kV on December 28, 2013, with full energization at 500 kV occurring on July 24, 2014, this

project had since experienced some setbacks and, as a result, incurred some unusual costs in

2014 and 2015 and may continue to incur costs into 2016. The RPG asserted that the

Commission should not allow costs from 2014 or later in the current proceeding. Instead, the

RPG submitted that AltaLink should be required to demonstrate the prudence of its 2014 and

2015 costs for the Heartland project in a future proceeding.622

704. The RPG opposed the consideration of 2014 Heartland project costs within the current

proceeding because:

AltaLink’s departure from normal practices to include costs from the next calendar year

for a project along with all costs incurred in prior years creates concerns that AltaLink is

cherry-picking a particular project where the increase in the revenue requirement

requested for this project is offset by a reduction in revenue requirement from other

projects in that calendar year, masking the true impact of its cost overruns.623

Any potential regulatory efficiency gains in the current DACDA proceeding will be

offset by an increased regulatory burden in a future DACDA proceeding.

An adoption of this practice as a normal practice in future application will result in a

piecemeal approach to DACDA applications; and increased opportunities for TFOs to

advance applications for portion of projects that increase the revenue requirement, while

ignoring projects that reduce the rate base.624

705. In its rebuttal evidence, AltaLink noted that it had explained its reasons for including

2014 Heartland project costs within its current DACDA application in a number of IRs, and

noted in particular its response to AML-IPCAA-2015-MAR05-002.625 In that response, AltaLink

noted that the Heartland project has significant additions in both 2013 and 2014, and AltaLink

determined that it would be more efficient for the Commission and interveners to assess the

entirety of the Heartland project as part of a single application. The IR response further noted

620

Exhibit 0002.00.AML-3858, Table 7.2-1, PDF page 38. 621



Exhibit 3585-X0666, paragraph 53a. 624

Exhibit 3585-X0666, paragraph 53c. 625

Exhibit 3585-X0044, AML-IPCAA-2015MAR05-002, cited at Exhibit 3585-X0704, paragraph 410.


144 • Decision 3585-D03-2016 (June 6, 2016)

that while AltaLink had intended to complete the Heartland project at 500 kV prior to year-end

2013, only partial energization occurred during that year.626

706. In argument, the RPG submitted that while oral hearing testimony in the current

proceeding forecasts Heartland project capital additions of $3.2 million for 2015, information

filed in AltaLink’s 2015-2016 GTA proceeding shows that estimates of final costs for the project

have been in significant flux. The RPG further noted that by November 2015, the forecast final

cost of the project had dropped by $13.9 million.627

707. The RPG claimed that in addition to the instability of the final project cost forecasts there

were also a number of unresolved issues that will carry on. For example, significant land appeal

is still before the SRB for consideration, AC mitigation activities will continue on into 2016, and

AltaLink expects to sell a tower to ATCO. Further, the RPG noted that, as of October 2015, 15

properties that had been purchased for this project remained to be sold, and that potential credits

against land purchase costs could be substantial.628 The RPG maintained that given the Alberta’s

current economic condition, it is not appropriate to be adding significant costs to rate base that

are expected to be reversed, at least in part, through property sales and the sale of the tower to

ATCO.629

708. The RPG acknowledged that during the hearing it had stated that including the Heartland

project’s 2014 costs in this application was not a major issue. However, the RPG indicated that it

is still concerned with the remaining complexity of matters to be resolved and the potential of

setting a precedent of this practice for future applications.630

709. Given the foregoing, the RPG restated its opposition to including 2014 Heartland project

costs into rate base at this time. The RPG submitted that, alternatively, the Commission could

approve the addition in rate base for 2014, but not determine the prudence of these costs until a

future application.631 The RPG further requested that the Commission direct AltaLink not to

engage in the practice of including a project that falls outside the primary DACDA proceeding

test years for future DACDA applications without prior Commission approval.632

710. In argument, AltaLink assured that while the RPG’s written evidence opposed the

inclusion of 2014 Heartland project costs within the current proceeding, the RPG appeared to

have largely backed away from this position in response to questioning from AltaLink and the

Commission during the oral hearing.633

711. AltaLink submitted that it is obviously logical and more efficient to address the

overwhelming bulk of the Heartland project costs within a single application. AltaLink noted that

Ms. Chekerda and Ms. Bellissimo, who testified on behalf of the ADC and IPCAA, respectively,

both supported the efficiency of considering Heartland project costs in a single proceeding.634 In

626









Exhibit 3585-X0859, paragraph 525, citing Transcript, Volume 9, pages 1597-1598.


Decision 3585-D03-2016 (June 6, 2016) • 145

addition, during cross examination, Mr. Levson acknowledged that AltaLink’s next anticipated

DACDA application will consider capital additions expected to be $979.2 million for 2014 and

$2.783 billion for 2015. AltaLink noted that the Heartland project capital additions for 2014

($66.9 million) would be small relative to the total additions for AltaLink’s next DACDA,635 and

noted the Mr. Levson stated the RPG’s position on inclusion of 2014 Heartland costs was

primarily a matter of principle, but was probably “not a hill to die on.”636

712. AltaLink submitted that it is incorrect to claim that there will be substantial costs for the

Heartland project in 2015, it is forecasting capital expenditures and capital additions for 2014

and 2015 of $2.8 million and $3.2 million, respectively.637

713. In reply argument, AltaLink disagreed with the RPG’s suggestion that the Heartland costs

are in significant flux and with the RPG’s suggestion that allowing 2014 costs in this proceeding

will encourage TFO’s to add projects into future DACDAs selectively, in order to get more

favourable treatment. AltaLink submitted that this suggestion is purely speculative, and not

supported by the facts in evidence.638 In any event, AltaLink submitted that in light of the RPG’s

admission that the matter was not critical, “principle and practice”639 must be outweighed by the

Commission’s interest in regulatory efficiency.640

Commission findings

714. The Commission accepts AltaLink’s submission that it is more efficient to consider the

prudence of the majority of Heartland project’s costs in a single proceeding.

715. The Commission finds that AltaLink’s rationale for including 2014 additions to rate base,

along with earlier additions, in the current DACDA proceeding to be reasonable. The

Commission does not share the RPG’s concern that allowing consideration of costs outside their

respective DACDA calendar test years, could set a negative precedent for other TFOs, who could

take this opportunity and strategically select projects that should be included in a particular

DACDA in an attempt to “mask” the true effect of its cost overruns.

716. While the RPG is concerned that the inclusion of the 2014 Heartland project costs in this

DACDA will result in large trailing costs, the Commission accepts AltaLink’s evidence that this

will likely not be the case. The Commission notes, however, that with respect to “land

acquisition costs,” there are still a number of properties acquired by AltaLink for this project that

have yet to be resold. Therefore, it is possible that the trailing costs in a future DACDA

application regarding land acquisition costs could have a substantial “negative cost” component,

reflecting the amounts to be recovered from these properties’ sale. Accordingly, as further

discussed in Section 4.2.2.14, the Commission has not accepted any land acquisition costs at this

time and has determined instead that they should be reviewed entirely as part of trailing costs in

a future application.

635








146 • Decision 3585-D03-2016 (June 6, 2016)

717. Based on the above, the Commission finds that it is appropriate to review the majority of

the Heartland project’s costs in the current proceeding and approves AltaLink’s to include, as

part of this DACDA application, the Heartland project costs consisting of actual costs incurred

up to November 30, 2014.

4.2.2.5 Transmission line design

718. The line design component reflects approximately 64 per cent of the total project costs,

whereas the substation and telecommunication components of the project correspond to

approximately 10 per cent of the project costs.

719. Heartland, as a critical transmission infrastructure (CTI) project, was designed to meet

the following requirement, as set out in Bill 50:641

One double circuit 500 kV alternating current transmission facility connecting to the 500

kV transmission system on the south side of the City of Edmonton and to a new

substation to be built in the Gibbons - Redwater region.642

720. The AESO issued a functional specification for the Heartland project on July 13, 2010,

which was revised on August 13, 2010, to include an underground transmission option. The

functional specification directed AltaLink and EDTI to design and construct the Heartland

project. The functional specification identified a preferred route option (the preferred east option)

and an alternative route option; the east option included consideration of an underground

section.643

721. The final route selection was determined following a facility application to the

Commission. Both route options specified that the 500-kV transmission line was to be

constructed on double circuit structures, both sides strung. The functional specification also

stated that both the Technical Requirements (Part 3) for Connection Transmission Facilities

(December 2, 1999) and the AESO Transmission Line Standard Draft (April 24, 2007) standards

should be met.644 In addition to those standards, the AESO specified that the 500-kV lines be

designed to a minimum continuous capacity of no less than 3000 MVA (3464A at 500 kV); that

the transmission line structures for the 500-kV lines be designed with 100-year return wind gust

and 100-year return combined wet snow and wind pressure; and that the transmission lines have

optical fibre composite overhead ground wire.645

722. The AESO specified the following for the 240-kV lines: the minimum continuous

capacity should be no less than the thermal capacity of a 240-kV transmission line with twin

ACSR 1033 MCM conductors; and the transmission line structures should be designed with

100-year return wind gust and 100- year return combined wet snow and wind pressure.646

641

The Legislative Assembly of Alberta: Bill 50: Electric Statutes Amendment Act 2009. 642

Ibid., at Section 13(2). 643


Exhibit 0092.00.AML-3585, PDF pages 7 and 10. 645




Decision 3585-D03-2016 (June 6, 2016) • 147

723. The functional specification also required that the TFO complete transmission line

routing, structure design, line optimization, insulation, grounding, protection and communication

studies as necessary to accommodate the proposed system additions and modifications.647

724. AltaLink submitted the line optimization study for the 500-kV lines in Exhibit

0098.00.AML-3585. The line optimization study was conducted by SNC-ATP Inc. on behalf of

AltaLink and determined the most economical conductor configuration, support structure and

span length combination. The study concluded that a the 3-bundle conductors configuration was

more economical than 4-bundle and that the optimal 3-bundle conductor was 1431 kcmil ACSR

(Plover) with an optimal span length of 350m.648 However, AltaLink chose to go with another

design in its PPS649 and in its facility application, which specified 3-bundle 1590 MCM ACSR

(Falcon) conductor with 330m span lengths within the TUC and 365 span lengths outside the

TUC.

725. AltaLink explained that 3-bundle 1590 MCM (Falcon) was chosen by considering factors

additional to those considered in the line optimization study namely it is a standard AltaLink

conductor that could result in savings for maintenance and emergency sparing, storage and other

charges; it is a standard industry conductor that is readily available/manufactured by multiple

vendors; and smaller conductors such as the 1431 MCM ACSR (Plover) may lead to increased

risk of corona effects and associated interference (television, radio and audible noise in fair

weather).650

726. The PPS and facility application specified a 2-bundle 1033 kcmil ACSR conductor for

the 240-kV lines on RC22 tower family structures.651 652

727. The AESO initially asked AltaLink to design a delta type tower for this project. However,

AltaLink persuaded the AESO that the P52 tower family was more cost effective.653 Thus, the

PPS put forward in the facility application used the P52 vertical [steel] lattice tower family for

the 500-kV lines which was the family of towers originally developed for the cancelled north-

south 500-kV Genesee to Langdon transmission line project.654 AltaLink assumed, for the

purposes of the PPS cost estimate, a mix of foundation types based on a desktop geotechnical

study (38 per cent footings and 62 per cent caissons). The estimated tower mix that formed part

of the basis of the PPS cost estimate was as follows:

647










148 • Decision 3585-D03-2016 (June 6, 2016)

Table 12. Tower type mix identified in the PPS

Tower Type Quantity

P52A Tangent 122

P52B Light Angle 13

P52C Heavy Angle 29

P52E Light Dead-End 16

P52F Heavy Dead-End 12

P51E Light Dead-End (single circuit) 2

Total Towers 194

Source: Exhibit 0087.00.AML-3585, PDF page 33.

728. AltaLink’s PPS also proposed a procurement strategy for towers. AltaLink proposed to

sole source the 500-kV tower supply from KEC based on the competitively bid contract from the

previous north-south 500-kV project. AltaLink stated that this was a favourable contract for

tower steel pricing based on recent contracted prices for steel on other projects.655

729. In the Heartland project execution plan AltaLink stated that the monopole design would

be completed in advance of P&L so the monopole towers could be competitively tendered and

conditionally awarded as a hedge against a Commission decision to install monopoles.656

730. In the facility application, AltaLink provided the tower types for indicative tower

locations in maps included in appendices.657 AltaLink indicated that the overhead transmission

line design using lattice towers was recommended over the monopole and underground options

because it would meet the AESO functional specification requirements at the lowest installed

cost.658

731. As stated above, the Commission approved the preferred east route (but did not approve

the underground option) in AltaLink’s facility application, as well as the proposed design subject

to a number of conditions. One of these conditions required AltaLink to construct the monopole

option from a location near the intersection of Anthony Henday Drive and Highway 14 to south

of Baseline Road (to structure M68/T61 as proposed in the route amendment).659 AltaLink

submitted a change notice to the AESO on December 2, 2011, following the Commission’s

decision which quantified the schedule and cost effects of meeting that condition. The estimated

cost effect represented an increase of $41,177,888 to the original project estimate and an increase

in the forecast ISD by six months (from March 29, 2013 to September 30, 2013). The AESO

acknowledged the change notice on December 16, 2011.660

732. In response to an IR, AltaLink provided further details of the variance between the PPS

for transmission line labour (which includes engineering) and the actuals at December 31, 2014.

Variances due to design, aside from the Commission’s direction to use monopoles, were as

follows:

655


Exhibit 3585-X0098, AML-CCA-2015MAR05-048 Attachment 1, PDF page 55. 657

Note: the appendices were not included in this proceeding. 658



Exhibit 0093.00.AML-3585, PDF pages 7-8.


Decision 3585-D03-2016 (June 6, 2016) • 149

Scope changes of $11.5 million, captured in change notices 7, 9 and 10. The changes

included additional bird diverters; 240-kV bypass lines for energization of the Heartland

substation prior to transformers being successfully commissioned; sheet piles required at

tower 2 due to local storm water pond; and an increase in quantities of foundations,

accessories, rider poles and traffic control;

Trend/market changes that included $3.36 million for 500-kV lines which required

modifications for clearance over 240-kV and 130-kV lines and required flattening from

double circuit to single circuit structures for road and rail crossings; and $2.6 million for

structure re-work for design changes on site.661

733. In its updated risk register, AltaLink noted that the soil conditions were worse than

anticipated. Issues with soil conditions were partially mitigated by the use of screw piles;

however, the concrete foundations (caissons) were more expensive than anticipated.662

734. AltaLink explained that each tower was “stick built” beside the foundation in pieces

logical for erection depending on the contractors’ method and choice of crane. All members of a

500-kV lattice tower required mechanical means of handling. AltaLink stated that the tower used

for the 500-kV portion of the Heartland were the largest ever used in Alberta at that time.663

735. In summary, AltaLink indicated that it was obliged to build the Heartland project as

approved by the Commission. This includes the route approved by the Commission. AltaLink

had submitted a preferred route that did not include monopoles and the approval for Heartland

included changes to routing, structure type and imposed conditions that affected tower placement

and routing. An amended route through a portion of the TUC was also approved and this route

was different from any of the route alternatives included in the facility application. Another

condition that affected the route was with regards to Tower 176 AltaLink was required to work

with a landowner to reposition a structure to the landowner’s satisfaction which led to a hearing

and out of sequence construction.664 All of these factors contributed to the variance in cost from

the PPS estimate.665

736. AltaLink’s design decisions for Heartland were not addressed by interveners in evidence,

nor in argument and reply.

Commission findings

737. The Commission has recognized in previous decisions that design decisions can have a

significant effect on a project’s costs. While the design is reviewed and approved at the facility

application stage, the prudence of design decisions is reviewed in a DACDA proceeding.

Prudence of design decisions is evaluated in light of what the TFO knew or ought to have known

at the time and in light of the AESO’s and Commission’s directions.

738. Significant variances in forecast to final costs in the Heartland project, were attributable

to design changes. The Commission has considered AltaLink’s decision processes, design

661

Exhibit 3585-X0042, AML-AUC-2015MAR05-045(a-b) Part 3, PDF pages 468-469. 662

Exhibit 3585-X0042, AML-AUC-2015MAR05-045 (c) Attachment, PDF page 472. 663





150 • Decision 3585-D03-2016 (June 6, 2016)

decision justifications provided in the PPS and the facility application and the effect of

Commission’s decision on the Heartland facility application on design and finds that AltaLink

has acted reasonably. AltaLink is required to construct the transmission line as approved by the

Commission such that it also meets all applicable standards, codes and rules. The evidence on

the record demonstrates that AltaLink has met this requirement.

739. Based on the above, the Commission approves the costs related to transmission line

design as applied for by AltaLink.

4.2.2.6 EDTI charges

740. In intervener evidence, the RPG requested a full and transparent accounting of the

Heartland project’s capital costs to understand how these costs were apportioned between

AltaLink and EDTI.

741. The RPG noted that ownership of the Heartland project changed during its construction

and observed that this change in ownership posed unique administrative challenges to identify

how additional capital costs and operations and maintenance costs are to be assigned or allocated

between AltaLink and EDTI. Although it sought clarification, the RPG stated that AltaLink’s

response to one of its IRs did not provide enough detail to confirm the apportionment of capital

costs.

742. In rebuttal evidence, AltaLink stated that the RPG’s claim that AltaLink is

misrepresenting the total expenditures on the project was incorrect. AltaLink referred to the

actual projects costs for the projects on behalf of AltaLink and EDTI in Exhibit 3585-X0042

AML-AUC-2015MAR05-005, Exhibit 3585-X0045, Exhibit AML-CCA-2015MAR05-002,

Exhibit 3585-X0045, and Exhibit AML-CCA- 2015MAR05-010 to support its position. AltaLink

further stated that in response to IR AUC.AML‐018 a‐d (Round 2 IRs, Proceeding 1734) and IR

AUC.AML-024 a-c (Proceeding 2044), it described to the Commission how AltaLink intended

to account for Heartland costs and showed that they had been properly apportioned between

AltaLink and EDTI. AltaLink stated it had followed this practice throughout the life of this

construction project.666

743. In argument, the RPG recommended that to ensure costs are not being double counted in

AltaLink and EDTI deferral account applications, at a minimum, AltaLink should be required to

produce a full accounting of all capital costs, including how they have been apportioned between

AltaLink and EDTI, along with an annual update to reflect additional capital expenditures in

2014 and beyond.

Commission findings

744. The Commission acknowledges the concerns of the RPG and does not find their

recommendation to be unreasonable.

745. As a result of findings in Section 4.2.2.9 in this decision, the Commission expects that the

amounts added to rate base for the Heartland project will change. To address this issue and the

666

See TAB 5 – Heartland Financial Statements December 31, 2014, which is an extract from the quarterly

financial statement provided to the Management Committee that was charged with the oversight of this

construction project.


Decision 3585-D03-2016 (June 6, 2016) • 151

RPG’s expressed concerns, AltaLink is directed to provide, as part of its compliance filing, a

reconciliation showing all approved expenditures in the Heartland project and how those

expenditures are allocated between the AltaLink and EDTI rate bases, along with appropriate

supporting documentation.

4.2.2.7 Use of rig mats


AltaLink’s use of rig mats and asserted that AltaLink had failed to justify its excessive use of

these rig mats.

Commission findings

747. As required by ISO Rule 9.1.5, the provision of rig mats was secured through a tender

process.

748. The execution of the Heartland project encountered a series of events that added

incremental cost. These included the late start and early break up in the winter construction

season of 2012, the conflicts in the TUC with the concurrent construction undertaken by the

North East Anthony Henday Drive P3 work and new pipelines, the schedule adjustments

necessary for Tower 176, and the extreme weather conditions in 2013, including high snowfall,

followed by melt, flooding and wet weather through to mid-Sept of 2013.

749. The Commission considers that at the time AltaLink prepared its PPS to the Heartland

project, it could not have reasonably anticipated the occurrence of a number of the events listed

above, all of which required additional mitigation measures that affected the costs incurred for

rig mats. Further, the Commission is not persuaded by the RPG’s claim that AltaLink had

alternatives to the use of additional matting. The RPG’s only suggestion was to restrict

construction during dry or frozen conditions. However, as explained by AltaLink, additional

costs would necessarily be incurred if AltaLink was required to mobilize and demobilize crews

whenever chinooks, rain or wet snow caused land to become wet and inaccessible. The

Commission accepts AltaLink’s evidence that the use of access mats was the only alternative

available in such extreme weather conditions, which AltaLink faced throughout the construction

of the Heartland transmission line.

750. In the Heartland project, Chinook Pipeline and Lakeland Vegetation were the

subcontractors originally retained for right-of-way preparation and maintenance. The subcontract

with Chinook Pipeline was eventually terminated and Lakeland Vegetation was retained to

complete the remainder of this work. Additional matting requirements primarily flowed through

Lakeland. Expenditures made to Lakeland are accounted for by the subcontract amendments

contained in IR response CCA-AML-038(a)17, Heartland subfolder C5, which is part of Exhibit

3585-X0382. The Commission reviewed each of these amendments and, while it agrees that the

expenditures were significant, it does not consider they were made needlessly.

751. Given the above evidence, the Commission considers AltaLink’s expenditures on matting

to be reasonable and they are approved.

4.2.2.8 Use of helicopters

752. In their intervener evidence, the RPG claimed that AltaLink offered no compelling

justification for the use of helicopters on the 240-kV portion of the Heartland project. In the


152 • Decision 3585-D03-2016 (June 6, 2016)

RPG’s view, a significant portion of that transmission line had excellent access from nearby

roads and thus helicopters were not needed. In particular, a significant portion of the preferred

route was close and accessible via township road 564.667

753. The RPG recommended that a cost and performance audit be conducted on the use of

helicopters for this project as well.

Commission findings

754. An analysis regarding the use of helicopters was prepared by RS Line for the 240-kV

portion of the line.668

755. While not specifically referenced by either the RPG or AltaLink, the Commission

reviewed the analysis prepared by RS Line, and found it to be reasonable and to provide

adequate justification for the use of helicopters on this project.

756. In particular, the analysis explained that the use of helicopters would accelerate the

project and reduce costs in the following ways:

Material issues would be identified sooner, as the use of helicopters allows for earlier

material hauling without the need to wait for foundation construction to be complete.

Standby charges due to material issues, would be minimized.

The number of access mats required to keep resources working during spring break up, in

order to maintain the schedule, would be minimized.

The transfer of resources to reinforce crews working on E and F towers would be

expedited.

757. In addition to the benefits identified above, the financial analysis shows that the use of

helicopters allows for costs savings with matting and mobilization of crews.

758. Given the above evidence, the Commission considers AltaLink’s expenditures on

helicopters in the Heartland project to be reasonable.

4.2.2.9 Pipeline mitigation

759. Pipeline mitigation is one of the issues raised by the interveners with respect to the

Heartland project. As set out in Section 4.2.1.7 pipeline mitigation is the term used to describe

the method of protecting pipelines from alternating current (AC) interference (electric and

magnetic fields produced) from transmission lines.

760. In support of its DACDA application, AltaLink filed the facility application for the

Heartland project. In the facility application, AltaLink indicated that it had retained Corrpro

Canada Inc., an engineering company with expertise in pipeline corrosion prevention and

mitigation to evaluate the impact of AC interference on existing pipeline infrastructure inside the

667

Exhibit 3585-X00666, page 41. 668

Exhibit 3585-X00382conf, AML-CCA-038(a)17, folder C31, SCA02.


Decision 3585-D03-2016 (June 6, 2016) • 153

Preferred East TUC route. Corrpro concluded that all of the identified AC interference could be

mitigated using standard mitigation schemes.669 670 Similar standard mitigation schemes could

also be used on monopoles.671

761. Pipeline mitigation cost estimates for Heartland were first considered in the PPS because,

at the time the comparative cost report was prepared, AltaLink did not consider that pipeline

mitigation would be required for the project.672 Appendix A of the PPS estimated pipeline

mitigation construction costs at $12.5 million. The PPS estimate included an additional $0.6

million for “Owners Costs,” which was attributed to Phase 1 pipeline mitigation.673AltaLink had

not included this estimate in the comparative cost report674

762. In the PPS, pipeline mitigation was listed as a project risk with a 25 per cent cost

sensitivity (or uncertainty).675 Appendix F of the PPS also noted pipeline crossings (specifically,

encountering more than expected or the mitigation effort being greater than “normal”) as a

project risk and stated that the cost associated with this risk was covered in the contingency. The

schedule effect of the risks associated with pipeline crossings, however, was anticipated to be

minimal. In the facility application, AltaLink included a risk mitigation strategy that proposed

preparing crossing drawings for agreement discussions prior to P&L.676 The initial estimate for

pipeline mitigation assumed that 206 mitigation sites would be required.677

763. The project summary schedule and variance explanations for Heartland filed in support of

the DACDA application, indicated that owner costs increased by $18.7 million from the original

PPS estimate. This increase was attributed to: “Larger than estimated legal, regulatory and

intervener costs as well as increased complexity of project execution/coordination. Costs

escalation attributed to AC mitigation due to increased complexity of pipeline scope within the

transportation utility corridor.”678 In response to an IR, AltaLink clarified that the AC mitigation

explanation was included in owner costs in error and the explanation actually related to

transmission line costs (which had increased by $186.7 million from the PPS estimate).

764. Specifically regarding AC mitigation, the project summary schedule and variance

explanations indicated an increase of $9.6 million from the original PPS estimate.679 In the

updated project summary schedule and variance explanations for Heartland, the distributed costs

showed a decrease from the PPS estimate of $49.9 million, which was attributed to “PMPC

increase due to AUC Monopole decision, re-contracting, increased supervision to address

669

Exhibit 0089.00.AML-3585, PDF page 74. Note that “standard mitigation schemes” was not defined in the

facility application. 670

Decision 2011-436 in Exhibit 0089.00.AML-3585 at PDF page 779. 671




This was not provided on the record of this proceeding. 675




Exhibit 0006.00.AML-3585, Tab D.0371. 679

Exhibit 3585-X0042, AML-AUC-2015MAR05-045(a-b), PDF pages 465 and 468.


154 • Decision 3585-D03-2016 (June 6, 2016)

multiple contractors on site, 240-kV by-pass, AC Mitigation, and ISD Extension;

Contingency/Escalation used to offset labour cost increases.”680

765. AltaLink submitted a change notice to the AESO on January 31, 2014 (CN 11) for a

$50,652,640 increase to the estimated project costs due to an increase in the scope of work for

AC mitigation.681 This estimate included a $7,891,070 contingency that AltaLink clarified was an

internally derived percentage-based estimate to cover risks associated with the cost estimate

being generated by AltaLink and not pipeline companies, detailed studies not being complete for

all owners, effects from the private public partnership (P3) (Anthony Henday Ring Road project)

working within the TUC, and unseasonably wet conditions in 2014. This contingency estimate is

in addition to the original contingency estimate developed in the PPS using a Monte Carlo

method, which was thought to be sufficient at the time. An attachment to the change notice

showed total forecast costs for pipeline mitigation equal to $56,155,382.682

766. In the description section of CN 11, AltaLink indicated that the pipeline mitigation work

had begun early in the project, with pipeline owners notified in 2010 and 2011. However, due to

pipeline owner and consultant resource constraints, the majority of the work was not completed

until 2013. Additionally, AltaLink stated that it significantly underestimated the complexity of

the existing pipeline facilities and their interactions within the TUC, which resulted in rework

and delays in completing the reports required to define the scope of mitigation efforts.683 In the

hearing, the AltaLink panel explained that with multiple parallel pipelines, there are induction

effects from pipeline to pipeline, requiring that they be modelled together to determine how one

pipeline affects an adjacent one, which in turn affects the AC mitigation required.684

767. In the description section of CN 11, AltaLink also indicated that additional resources

were required to coordinate the work between approximately 20 pipeline owners. Further, as it

became clear to AltaLink that the final AC mitigation scope would not be completed to meet the

project ISD, temporary mitigation measures were implemented to accommodate the line’s

temporary energization at 240 kV. As of the date of CN 11, permanent mitigation was not fully

engineered and was estimated to be complete in Q2 2014.

768. The options considered by AltaLink and documents in CN 11 to address the issue

indicated that it attempted to reduce the pipeline mitigation cost increases by issuing revised (and

reduced) 10 year horizon loading parameters for both the 500-kV and 240-kV portions of the

project, which reduced the required mitigations for affected pipelines.685 At the hearing, an

AltaLink witness testified that the revised loading parameters deferred approximately

$25 million in pipeline mitigation costs.686

769. The AESO approved CN 11 on February 21, 2014, with the following comment:

“Although there is a lack of historical or benchmarking data available, the scope and efforts of

680

Exhibit 3585-X0043, Tab D.0371. 681

Exhibit 0093.00.AML-3585, change notice 11, PDF page 121. 682

Exhibit 0093.00.AML-3585, change notice 11, PDF pages 127, 137 and 138. 683

Exhibit 0093.00.AML-3585, change notice 11, PDF page 122. 684

Transcript, Volume 6, page 1161, line 24 to page 1162, line12. 685

Exhibit 0093.00.AML-3585, change notice 11, PDF pages 122-123. 686

Transcript, Volume 1, page 364.


Decision 3585-D03-2016 (June 6, 2016) • 155

AC Mitigation with the various Pipeline Facility Owners, put forward by AltaLink, seem

reasonable.”687

770. In response to an IR, AltaLink stated that the costs incurred to date were $26.3 million.688

As the trailing costs for pipeline mitigation (i.e., costs incurred after December 31, 2014) are

forecast to be $16.7 million,689 the total forecast costs would be $43 million. This is inconsistent

with the $50,652,640 amount included in the change notice.

771. The RPG in its evidence, claimed that AltaLink should have investigated the possibility

of locating the transmission line elsewhere within the designated area for transmission lines in

the TUC, in an attempt to reduce the AC mitigation measures required. In the RPG’s view, to

accommodate landowners’ concerns, AltaLink chose to move the transmission line away from

residences, which resulted in locating it too close to existing pipelines. The RPG asserted that if

the transmission line was kept even a small distance further away from the pipelines, a

substantial portion of the AC mitigation costs could have been avoided. The RPG maintained

that AltaLink was imprudent, as it knew or should have known that there were numerous

pipelines in the TUC and that locating the transmission line in such close proximity to pipelines

would inevitably increase AC mitigation costs.

772. The RPG stated that AltaLink has provided no evidence to suggest that it examined the

trade-offs, particularly with regard to AC mitigation costs, of locating the transmission line

further away from pipelines and closer to landowners.690 In support of its submission, the RPG

provided a map of the TUC that showed that structures 55 to 60 of the transmission line have as

little as 37 metres setback from the pipeline, but 360 metres setback from the TUC (and

residences). The RPG stated that, for those structures, AltaLink could have maintained a 100

metre setback from the nearest pipeline, while only minimally increasing the visual effect to the

residences.691 The RPG noted that the magnetic field from the transmission line at 100 metres

distance is only 17 per cent of the level at 50 metres, which supported its view that a larger

distance from the transmission line to the pipelines would have resulted in a substantial reduction

in AC mitigation costs.692 In the hearing, the RPG clarified that to minimize AC mitigation costs,

AltaLink could have elected to move the transmission line route within the designated area of the

TUC at a “micro level,” or in the range of 20 to 30 metres.693

773. During the hearing, the RPG acknowledged that the transmission line route is approved

by the Commission and that the line must be built along the approved route.694 The RPG also

acknowledged that there was a hearing required to deal with a request to move one tower (Tower

176) “a matter of meters” and that, in theory, moving towers off an approved centreline could

trigger buy-outs, but noted that the right-of-way is 300 metres wide and the change in centreline

proposed by the RPG is as small as 15 metres.695

687

Exhibit 0093.00.AML-3585, change notice 11, PDF pages 124-125. 688

Exhibit 3585-X0042, AML-AUC-2015MAR05-055(c), PDF page 489. 689

Exhibit 3585-X0042, AML-AUC-2015MAR05-045, PDF page 468. 690


Exhibit 3585-X0689, CCA-AUC-2015SEP24-006, PDF pages 13-15. 692

Exhibit 3585-X0689, CCA-AUC-2015SEP-24-006, PDF page 16. 693





156 • Decision 3585-D03-2016 (June 6, 2016)

774. In response to an undertaking, the RPG provided marked up maps of the TUC and the

transmission centreline with proposed changes to tower locations and to the centreline which it

claimed could have minimized AC mitigation costs. The RPG estimated that a tower foundation

setback of 50 metres from pipelines was sufficient to limit the voltage generated across the

pipeline for most soil types. This setback would have eliminated the need for certain mitigations

measures. A setback of 100 metres from the transmission line to the pipelines would have

decreased the magnetic field strength and the induced current in the pipeline by a factor of 10.

The RPG noted in the undertaking response that AltaLink appears to have negotiated the linear

infrastructure allocation with Alberta Infrastructure because the right-of-way appears to fall

outside of the power line allocation in some locations.696

775. The RPG recognised AltaLink’s efforts to mitigate high AC interference mitigation costs

but noted that these efforts are only helpful in the short run as additional costs will be incurred in

the future when the load parameters require further upgrades to AC mitigation measures.697

776. The RPG recommended that the Commission disallow AltaLink’s AC mitigation costs in

excess of the original PPS estimate or require AltaLink to conduct a cost and performance

audit.698

777. In rebuttal evidence, AltaLink maintained that the RPG’s suggestion that the transmission

line should have been built elsewhere within the TUC and that by doing so pipeline mitigation

costs would have been less is incorrect and not supported by evidence.

778. AltaLink stated that the proper siting of a high voltage transmission line requires the

assessment of a multitude of factors. AltaLink considers and balances all effects on people,

landowners, the environment, and other infrastructure owners. The least affected route is then

determined and put forward for consideration and approval by the Commission in a facility

application. This includes AC mitigation commitments to pipeline owners to keep them whole

with respect to safety and/or asset degradation.

779. AltaLink further explained that consideration was given to obtaining input from pipeline

companies regarding the cost estimate. However, this was not possible because many pipeline

owners believed that the project was contentious and unlikely to be approved. The estimate was

done with the knowledge that detailed engineering of the mitigation methods would be

completed by the pipeline owners once the precise route was known.699

780. AltaLink listed the steps it took in each of the project phases to address AC mitigation as

follows:

During the development of the PPS, AltaLink assessed electrical effects to adjacent

infrastructure and the estimated costs for mitigation. All reasonable attempts are made to

engage asset owner (however, typically the asset owner does not engage until the facility

is approved and construction is certain).

696

Exhibits 3585-X0848, X0849 and X0850. 697



Exhibit 3585-X0042, AML-AUC-2015MAR05-055(b), PDF page 488.


Decision 3585-D03-2016 (June 6, 2016) • 157

After P&L, AltaLink re-engaged the asset owner to have an interference study completed,

which included an estimated cost for the work. Subsequently, a funding agreement was

negotiated with the owner.

In some cases, the interference study shows no effect so the matter with that asset owner

in closed. In cases where there is an effect, the asset owner performs an engineering study

for detailed engineering of a solution. It is the asset owners responsibility to monitor the

asset condition and manage safety and integrity

AltaLink reviews the engineering study for reasonableness and, if approved, further

negotiates an extension of funding.

Throughout all phases, AltaLink monitors the invoices and back up provided by the asset

owner.

Following completion of the interference study of construction, AltaLink obtains a

release from the asset owner that electrical effects have been adequately reviewed and/or

mitigated and absolves AltaLink from further liability.700

781. AltaLink asserted that it followed this practice for this project. AltaLink also explained

that Alberta Infrastructure was the authority charged with long-term planning of the TUC. It

established defined areas within the TUC for the location of different infrastructure types (i.e.,

roads, rail lines, transmission lines, pipelines, and municipal services). The transmission line was

required to be constructed within the lands allocated in the TUC for transmission line linear

infrastructure. In this designated area, there are pipelines on either side of it.701 Consequently,

conflict with pre-existing pipelines would have been inevitable wherever the transmission line

was located within its component area of the TUC.

782. Furthermore, AltaLink stated, it was required to construct the project on the route

approved by the Commission.702 AltaLink indicated that the amendment to the preferred route on

the Heartland project moved the line further from existing residences, which was an important

factor in the ultimate siting of the transmission line.

783. In argument, the RPG reiterated its position that AltaLink could have reduced AC

mitigation costs by increasing the tower setback and centreline setback from pipelines. The RPG

stated that AltaLink knew or should have known the following at the time of transmission line

design: the current and forecast AC levels in the 500-kV and 240-kV transmission lines, that the

TUC has numerous existing pipelines in the corridor, and that locating the transmission line

close to pipelines would increase the required AC mitigation effort and, therefore, the costs for

mitigation. By choosing not to evaluate the trade-offs between proximity of the line to pipelines

compared to proximity of the line to residences, AltaLink acted imprudently and should not

recover costs above the original estimate for AC mitigation.703

784. In argument, AltaLink stated that the RPG’s suggestion that the transmission line should

have gone elsewhere is mere speculation. The transmission line was approved to be built on land

700


Exhibit 3585-X0689, RPG-AML-2015SEP24-009(a) and 010(A), PDF pages 13 and 15. 702




158 • Decision 3585-D03-2016 (June 6, 2016)

with extensive existing pipelines and oil and gas facilities. Because the purpose of the TUC is to

congregate facilities to minimize effects on the broader community, it was inevitable that

pipeline mitigation would be required on the Heartland project. The Commission must consider

the effects of the proposed transmission line on existing facilities, among numerous other

considerations, and selects the route that minimizes the overall effects to all stakeholders. The

RPG seeks to elevate costs above all other considerations.

785. AltaLink also noted that a pipeline breach has significant cost and environmental

consequences. The costs are initially borne by the pipeline owner however, if the breach is

determined to be caused by AltaLink’s transmission line, AltaLink would be brought into

compensation discussions and possibly litigation. Therefore, mitigation measures are appropriate

and reasonable.

786. AltaLink noted that the RPG appeared to focus on AC mitigation within the TUC

(approximately 31 km), whereas AC mitigation was required for the entire length of the line.

787. Finally, AltaLink argued that the assertion from the RPG that minor changes to the

setback would reduce the induced current by a factor of 10 is not supported by evidence.704

788. In reply argument, the RPG rejected AltaLink’s assertion that design and construction of

a transmission line in the TUC is complex; in the RPG’s view, AltaLink knew that the

transmission line would be located in the TUC and that the line would be in close proximity to

other linear infrastructure such as highways and pipelines.705

789. In reply to AltaLink’s argument that the RPG had not provided evidence of a reduction in

induced current levels by a factor of ten, the RPG stated that the estimated reduction in the

induced current with distance came directly from the AltaLink magnetic field calculations filed

in the facility application. The RPG reiterated that, in its view, AltaLink has provided no

evidence that any assessment of the impacts on AC mitigation due to route selection were ever

performed.706

790. In reply argument, AltaLink noted that it had advanced three route options in its facility

application and each one considered the requirement for AC mitigation. The Commission

determined that the amended east route was in the public interest and AltaLink was required to

build that route. Further, in Decision 2011-436, at paragraph 650, the Commission recognised

that the amended east route required additional AC mitigation measures as it paralleled pipeline

facilities for a longer distance.707

Commission findings

791. The RPG claims that AltaLink acted imprudently as it did not investigate the possibility

of placing the transmission line further away from existing pipelines within the TUC, which

could have reduced costs incurred for AC mitigation. Therefore, the RPG recommended that the

Commission disallow AltaLink’s AC mitigation costs in excess of the original PPS estimate or

704






Decision 3585-D03-2016 (June 6, 2016) • 159

direct a cost and performance audit on AltaLink’s AC mitigation expenditures. The Commission

disagrees.

792. The Commission finds that the location of the transmission line and related potential

effects to stakeholders have already been considered at length in the facility application

proceeding for the Heartland project. In the facility application, AltaLink proposed both a

preferred east route, utilizing the existing TUC, and an alternate west route. The Commission

ultimately approved the preferred east route, with amendments. In arriving at its decision, the

Commission considered all issues identified by potentially affected stakeholders. Over the course

of the hearing, the Commission heard testimony from more than 170 witnesses. Pipeline

mitigation issues within the TUC were carefully considered by the Commission, as evidenced in

the following passage from the Decision 2011-436:708

663. The Commission also observes that while the majority of the expert evidence

concerned pipeline interference within the transportation and utility corridor on the

preferred east route, if the alternate route were selected, pipeline mitigation would still be

required. The applicants stated that that they would also be able to mitigate pipeline

interference on the alternate route. This evidence was not challenged by any party.

793. Aside from pipeline mitigation, consideration of key concerns raised by landowners, such

as property value, visual and business effects, also influenced the Commission’s approval of the

preferred route. As it is clear from the passages of Decision 2011-436 reproduced below, the

specific distance of the transmission line to landowners was an important factor in the

Commission’s determination of the final route:

775. Beginning at the Ellerslie substation, the first 20 kilometres of the preferred east

route is in a transportation and utility corridor that borders densely populated areas on

both sides. The first part of this 20-kilometre section of the route also passes between

Anthony Henday Drive and two existing double-circuit transmission lines already located

in the transportation and utility corridor. The distance from the proposed transmission

line to the nearest residences on the north side of the transportation and utility corridor is

approximately 400 metres…

776. On this same stretch of the route, the distance to the nearest residences on the

south side of the transportation and utility corridor is approximately 180 metres.

777. The Commission is satisfied that, because of the presence of the existing Ellerslie

substation and two 240-kilovolt transmission lines, the relative incremental visual impact

of the transmission line along this portion of the preferred east route would be less than

the incremental visual impacts on both routes where no transmission lines are currently in

place and monopoles would not provide the same degree of mitigation of visual impacts

as they would elsewhere.

778. The incremental visual impacts of the proposed transmission line on the portion

of the preferred east route where it turns north in the transportation and utility corridor

and passes beside existing housing developments will be greater than the incremental

visual impacts along the south 20-kilometre portion of the preferred route in the

transportation and utility corridor. Similarly, the visual impacts through the remainder of

the corridor and north of the corridor, where no transmission lines are currently in place,

708



160 • Decision 3585-D03-2016 (June 6, 2016)

will also be greater than the visual impacts along the south 20-kilometre portion of the

preferred east route in the transportation and utility corridor.709

794. Therefore, the Commission considers that the location of the transmission line within the

TUC was adequately addressed during the facility application proceeding and does not need to

be revisited in this proceeding. AUC Rule 007 does not address line relocations or changes to an

approved transmission line route. However, the guideline for AUC Rule 007 for transmission

lines710 states: “a change to an approved transmission line’s centre line or substation location

requires a facility application or LOE [letter of enquiry].” The TFO is obligated to construct the

route approved by the Commission. As acknowledged by the RPG, once the Commission

approved the route, AltaLink was required to build the transmission line as directed by the

Commission, which it did.

795. Having found that AltaLink acted prudently in the selection of the location of the

transmission line within the TUC, the Commission assessed the prudence of AltaLink’s actual

pipeline mitigation costs.

796. As referenced above, AltaLink’s original estimate for pipeline mitigation is significantly

lower than the forecast final costs. AltaLink explained that once it was further into the project

and had a better understanding of the pipeline mitigation required, a change order was submitted

to the AESO to account for the estimate in increased costs. As previously discussed by the

Commission in this decision, cost variances from the original PPS estimate are not necessarily an

indication of imprudence. However, after reviewing AltaLink’s explanation from CN 11 in

support of the additional costs incurred for pipeline mitigation, the Commission considers that it

requires further information to make a determination on the prudence of these costs. Particularly,

the Commission would like additional explanation for AltaLink’s decision to avoid cost

increases by deferring mitigation measures by revising the 10-year loading parameters.

797. Further, as indicated above, the record is not clear with regards to the total final forecast

costs for pipeline mitigation. In response to an IR, AltaLink stated that the costs incurred to date

are $26.3 million.711 The trailing costs for pipeline mitigation are forecast to be $16.7 million.712

Therefore, the Commission calculates the total forecast costs to be $43 million, which is

inconsistent with the $50,652,640 amount included in CN 11.

798. The Commission is prepared to approve, as a placeholder for purposes of this application,

the entire pipeline mitigation amount of $43 million. The Commission will consider this amount

for final approval in AltaLink’s next DACDA.

799. AltaLink is directed, therefore, to include in its compliance filing, for purposes of rate

base and return calculations, the actual amount of pipeline mitigation costs.

800. AltaLink is also directed to include the pipeline mitigation amount in AltaLink’s next

DACDA where it will be reviewed for final approval. AltaLink can supply full supporting

documentation for the claimed amount at that time, including an explanation of the discrepancy

709

Decision 2011-436, paragraphs 775-778. 710

Electric Transmission Facilities Process Guidelines, February 1, 2016. 711

Exhibit 3585-X0042, AML-AUC-2015MAR05-055(c), PDF page 489. 712

Exhibit 3585-X0042, AML-AUC-2015MAR05-045, PDF page 468.


Decision 3585-D03-2016 (June 6, 2016) • 161

between the $43 million and $50.1 million estimates for final costs. Further, the Commission

directs AltaLink to provide evidence to demonstrate the net present value of deferred pipeline

mitigation costs due to the reduction in 10-year loading parameters.

4.2.2.10 Delays attributed to monopole section ruling

801. In FTI’s evidence, FTI maintained that project management and construction

management (PMCM) costs are time related elements of direct assign project costs. FTI

submitted that when PMCM costs arise from a change in work scope, which affects the project

schedule, AltaLink must demonstrate that the incremental costs were not self-inflicted.713 FTI

claimed that the additional PMCM cost in the Heartland project associated with delays to

accommodate the Commission’s direction to use monopoles on 9.5 km of the transmission line is

an example of self-inflicted costs and should be disallowed. In support of its submission, FTI

noted that the evidence on the record shows that:

AltaLink anticipated the possibility that a 20 km portion of the preferred east TUC route

for the Heartland project would require either underground construction or the use of

monopole towers in its facility application.

AltaLink and SNC developed strategic options designed to maintain the initially targeted

ISD for the Heartland project (March 29, 2013) in case the Commission directed the use

of monopole towers.

Graham prepared a strategic plan to meet the planned ISD.714

802. FTI submitted that AltaLink had prepared a strategic plan to deal with the potential

requirement to use monopoles on a portion of the transmission line, but failed to implement it.

As a result, FTI submitted, a six-month extension in the ISD was required, from March 29, 2013

to September 30, 2013, to complete the project. In FTI’s view, the PMCM costs resulting from

the extension of the ISD could have been avoided.715

803. In its rebuttal evidence, AltaLink submitted that FTI ignored the fact that the Heartland

project change orders, including those dealing with schedule extensions, clearly laid out the

rationale and legitimacy of the extensions that were requested.716 AltaLink made specific

reference to TCA #2,717 which reconciled the cost and schedule effects, as they were understood

at the time, with an ISD of September 30, 2013.

804. AltaLink further submitted that having a PPS estimate for alternative options does not

imply they are construction ready.718 Additionally, the Commission’s decision was a modification

for the monopole PPS. AltaLink was directed to employ monopoles within a portion of the TUC,

which was not contemplated in the PPS estimates. Therefore, to suggest that AltaLink had, or

should have had, the required work completed at the time of PPS preparation is incorrect.719

713







Exhibit 3585-X0704, paragraphs 247-248.


162 • Decision 3585-D03-2016 (June 6, 2016)

805. AltaLink also explained that it was required to investigate alternative routing near

Colchester school. This condition required AltaLink to conduct what amounted to a separate

routing and consultation exercise. The location of Colchester school and the direction to

investigate alternative routing affected both monopole and lattice structures in the area. The

potential alternative routing overlapped the monopole section of the project, resulting in the

delay of the monopole construction as all towers in this area were placed on hold until final

routing was determined and the condition removed.

806. In argument, the RPG reiterated that a delay of six months attributed to the need of using

monopoles was unnecessary. First, the original PPS for Heartland included a schedule float for

AltaLink not receiving P&L until December 2011, which is in fact when P&L was issued;

second, the project execution plan for Heartland already contemplated the use of monopoles:

As a hedge to the reasonable likelihood that monopole may be approved for the 20 km

segment in the TUC, … bids for supply of poles and foundation engineering will be

completed such that poles are ready to award upon receipt of AUC decision and

construction bids contain either of lattice or monopole installation.

807. The RPG further noted that although the Commission’s decision directing the use of

monopoles was issued on November 1, 2011, the purchase order for the monopoles was not

awarded until much later.

808. The RPG noted that FTI had conducted an analysis of the contractor’s schedule forecast

and concluded that the Commission’s direction to use monopoles should have resulted in less

than one month delay to the project schedule. The RPG also noted that, based on the contractor’s

schedule, monopoles were forecast to be completed more than one moth prior to the planned

commencement of another installation activity. As a result, the RPG submitted that “it is entirely

conceivable that the total impact [of the direction to use monopoles] could have been offset to

achieve the original ISD date of March 29, 2013.”720

809. In argument, AltaLink submitted that the allegation that AltaLink failed to implement a

strategic plan to offset the Commission’s decision to use monopoles is based on hindsight,

ignores relevant facts, and ignores key aspects of the Commission’s decision.721 AltaLink argued

that FTI’s evidence implies that AltaLink or any TFO should have been prepared to construct all

possible routes, which is simply incorrect.722

810. In reply argument, the RPG observed that the Commission’s direction to use monopoles

on a 9.5 km section of the TUC should have been reasonably anticipated. In fact, during the

facility hearing for the Heartland project, the Commission asked AltaLink to provide cost

estimates for shorter distances of monopoles. AltaLink provided a cost estimate for a monopole

option for 9.5 km of the route. Similarly, the RPG noted the issue of the proximity of the

preferred east TUC route to Colchester school was discussed at length during the hearing and,

therefore, the amended route ordered by the Commission to accommodate this matter should not

have been a surprise to AltaLink.

720


Exhibit 3585-X0859, paragraph74. 722



Decision 3585-D03-2016 (June 6, 2016) • 163

811. In reply argument, AltaLink maintained that the RPG continues to ignore the evidence of

the actual circumstances in which the Heartland project was executed in asserting that the

monopole ruling should have added less than one month delay to the project schedule. The fact

that AltaLink had prepared PPS estimates for alternatives including a monopole option does not

change the fact that it was still required to wait for approval of the ultimate route before

proceeding with the project.723

812. AltaLink also asserted that the evidence clearly demonstrates that the original PPS did

not contemplate construction of monopoles in the specific section of the TUC where the

Commission ordered replacement of lattice towers with monopoles.724

Commission findings

813. The RPG requested that the Commission disallow the PMCM costs resulting from an

extension of the project ISD to accommodate the Commission’s direction to replace 9.5 km of

lattice towers with monopoles. In summary, the RPG claimed that AltaLink had anticipated the

possibility of having to use monopoles for a portion of the transmission line and, therefore, the

schedule delay was not justified.

814. The Commission has reviewed the parties’ submissions on this matter and does not

accept the RPG’s claim. The Commission acknowledges that AltaLink’s original PPS estimate

contemplated the use of monopoles for 20 km of the transmission line within the TUC. However,

the Commission agrees with AltaLink that having a PPS estimate for alternative options does not

imply that “they are construction ready.”725 Once the final route was approved by the

Commission and the determination of the use of monopoles made, AltaLink was still required to

execute the project, which included procurement of required materials and services.

815. The Commission accepts AltaLink’s evidence that the requirement to investigate

alternative routing around Colchester school affected advancement of the monopole construction

as all towers in that area were put on hold until a determination on the final routing was made

(affecting tower placement, geotechnical work and final tower procurement). The Commission

notes that the consultation activities to explore options around Colchester school are also cited in

TCA #2 as one of the reasons in support of the request to extend the ISD date from March 29,

2013 to September 30, 2013. Therefore, the need to address the Commission’s direction to use

monopoles was not the sole driver for the ISD extension request, as the RPG appears to suggest.

816. The Commission disagrees with the RPG’s claim that AltaLink failed to implement its

PPS contingency plan for the requirement to use monopoles on a portion of the transmission line.

In fact, the Commission notes that even at the facility application stage for the Heartland project,

AltaLink already anticipated having a later ISD, expected to be December 2013, if the preferred

route with the monopole option was ultimately approved.726 This confirms that AltaLink had all

along anticipated the requirement to revise the ISD in case the Commission directed the use of

monopoles, contradicting the RPG’s claim that AltaLink changed, or failed to implement, its

plan.

723






164 • Decision 3585-D03-2016 (June 6, 2016)

817. Similarly, in the risk analysis of the Heartland project execution plan, it is clearly stated

that if the Commission were to approve one of the non-preferred options, the execution plan and

strategy would need to be revised. The specific location where the Commission ultimately

directed the use of monopoles was not contemplated in AltaLink’s preferred route option, or at

all. Therefore, AltaLink’s adjustment of the project schedule appears to be consistent with its

original plan.

818. Given the above, the Commission considers that a revised ISD of September 2013 was

reasonable. The Commission rejects the arguments of the RPG that the costs incurred as a result

of this ISD extension should be disallowed.

4.2.2.11 12S substation project delays

819. In August of 2013, AltaLink advised the AESO that the first of its 500/240-kV

transformers at the Heartland 12S substation had failed testing. Remediation would require

substantial disassembly of the unit and, therefore, AltaLink opted to utilize a system spare for the

project instead of waiting for repairs. Subsequently, two additional transformers were tested and

also presented issues. Because the temporary transformers being used in WATL would be

available before the time required for remediation of the failed transformers, nine to 10 months,

AltaLink decided to cancel the contract for the transformers and use the WATL transformers

instead.

820. The issues with the transformers delayed the construction work at the 12S substation as

AltaLink proposed a partial energization of the 500-kV lines at 240 kV for the 1206L and the

1212L out of the Ellerslie 89S substation, but bypassing the Heartland transformers. Minor

modifications were required for the partial energization, including 900 metres of new temporary

240-kV transmission line at Ellerslie and 160 metres of new transmission line at Heartland 12S.

Both lines were salvaged after final project energization.

821. In its evidence, FTI submitted that had SNC-ATP not incurred delays in finalizing the

tendering and contract award for the 12S substation, it would have been able to identify the

transformer failures sooner and, consequently, avoid having to extend the ISD from December 7,

2013 to July 31, 2014.

822. FTI noted that transformer failure is the main reason provided in change proposal number

12 (CP12) in support of the request for an ISD extension to January 31, 2014. However, FTI

submitted, while the failure in testing was not predictable, the resulting 7.5 month project delay

could have been avoided if not for delays in making tender awards and delays in completing the

transformer pads for the substation. FTI further noted:

AML’s self-inflicted problems, and resulting delays, eliminates early detection of the

transformer failures and significantly reduced AML’s options such as repairing the

transformers. ..Since identification of the failure of the transformer is related to the need

date and scheduled delivery of the transformer, AML tender award delays and prolonged

construction activities had a direct impact on identifying the failure of the transformers

required for the 12S substation, therefore the AML substation is without merit.727

727



Decision 3585-D03-2016 (June 6, 2016) • 165

823. FTI also questioned the reasonableness of AltaLink’s decision not to pursue liquidated

damages or other contractual remedies against the transformer suppliers in order to mitigate the

additional costs caused by the transformer failures.728 Based on FTI’s evidence, the RPG

requested that the costs associated with the delay, including related PMPC costs, be disallowed.

824. In its rebuttal evidence, AltaLink refuted the RPG’s claim that the costs associated with

the transformer failures arose solely because of AltaLink or SNC-ATP actions. AltaLink noted

that the supplier was experienced and a known supplier of this type of transformer, having

previously supplied AltaLink and other utilities.

825. AltaLink explained that it did not pay for the failed transformers. Instead, an efficient and

temporary solution (energization at 240 kV) was implemented.729 The partial energization was

approved by both the AESO and the Commission (through the Commission’s approval of time

extension Decision DA2013-259).730 731 AltaLink noted that SNC-ATP held the supplier to be

contractually responsible and no additional funds were paid to the supplier for the repair of the

faulty transformers. AltaLink further noted that Heartland was deemed a CTI project; therefore,

meeting the targeted ISD was important.

826. In argument, the RPG noted that CP12 for the Heartland project, which was submitted to

the AESO with the title “complete energization at 500kV,” stated as follows:

This change proposal addresses additional costs to energize the Heartland project as per

original approved AESO functional specification, Rev 7 (July 13, 2010), including:

- Transportation and installation of 3 500kV transformers from Temp Bennet to

Heartland 12S

- Relocation of ABB spare (previously from 320p) at 12S to temporary pad

within the Heartland substation. This cold spare will be left at 12S until further

notice.

- Remobilization costs of substation crews to complete commissioning of

transformers and necessary P&C modifications.

- PMPC costs as a result of an ISD extension to July 31, 2014.732

827. The RPG asserted that prior to the submission of CP12, the ISD for the Heartland project

was December 7, 2013. As such, CP12 represented a delay of the project of almost eight

months.733

828. The RPG further noted that FTI’s report concluded that the transformers were to be

delivered by the end of May 2012, for commencement of installation by August 23, 2012.

However, the contract for the substation was not awarded until a number of months later than

planned. Consequently, construction work at 12S substation was pushed into a period of adverse

weather. The RPG noted that preparation work and the construction of concrete transformer pads

728



Decision DA2013-259: AltaLink Management Ltd., Heartland Transmission Project Time Extension and

Temporary Arrangement, Proceeding 2905, Application 1610052-1, November 18, 2013. 731


Exhibit 3585-X0860, paragraph 342, citing Exhibit 0093.00.AML-3585, PDF pages 140-157. 733



166 • Decision 3585-D03-2016 (June 6, 2016)

were not completed until June 2013. Installation and testing occurred in August of 2013, when

AltaLink reported the transformer failure.

829. Accordingly, the RPG submitted that absent delays in site preparation and construction of

transformer pads, the installation and testing would have occurred sooner.734 The RPG also

observed that even assuming a late start for commencement of construction of the pads,

November 2012, a reasonable date for installation of the transformers would have been

April 2013, given that AltaLink’s PPS had estimated three months for the completion of the

concrete pads.735

830. Clearly, the RPG claimed, the root cause of the ISD extension of almost eight months in

CP12 was not the failure of the transformers. Rather, it was that the project was behind schedule,

and one delay had a cascading effect on the next.736

831. In argument, AltaLink asserted that in July of 2013, the City of Edmonton and the area

north-east of Edmonton experienced rotating blackouts due to the failure of a 500-kV

transformer bank at Ellerslie. The Heartland project had already been designated a CTI project.

The events of the summer of 2013 only served to reinforce the need to have the project in service

prior to the winter peak period. Moreover, the AESO was fully informed of each and every step

taken by AltaLink to meet the ISD and energize the Heartland project.

832. AltaLink restated that no additional funds were paid to the supplier for repair of the faulty

transformers and that the supplier paid for the relocation of the Keephills 240-kV transformer.

833. In reply argument, AltaLink submitted that reference to CP12 is irrelevant to substation

project delays. The referenced section of the CP12 is for costs attributable to the transformer

delay, which are entirely separate from substation project delays.737

834. AltaLink submitted that the RPG’s assumption that if there had not been any delays in

site preparation, installation and testing of the transformers would have occurred sooner is

incorrect. Whether the site at 12S was complete is irrelevant because the transformers failed

testing in the factory in Winnipeg. AltaLink then chose not to take delivery of the failed

transformers, instead utilizing the transformers from the WATL project, which had passed

factory testing.738

Commission findings

835. In essence, the RPG claimed that absent delays for tendering and contract award for the

construction of the 12S substation, AltaLink and SNC-ATP would have been able to identify the

transformer failures sooner and, consequently, avoid the extension of the project ISD from

December 7, 2013 to July 31, 2014, which was approved by the AESO in CP12. The RPG

argued that the costs associated with the delay in completing the 12S substation were imprudent

and should be disallowed by the Commission.

734







Decision 3585-D03-2016 (June 6, 2016) • 167

836. The Commission notes that the costs associated with CP12, which requested extension of

the ISD to July 31, 2014, are entirely for mitigation measures to address the transformer failures.

Therefore, even if construction of substation 12S had been completed sooner, AltaLink would

still have required additional time to complete the installation of the transformers and incurred

the same costs to implement a viable solution. Although the project ISD might have been earlier

had the transformer failures been identified sooner, the Commission does not find that it would

have affected the costs associated with the mitigation measures required to address these failures.

837. Further, the Commission does not accept FTI’s evidence that AltaLink’s options to

address the problem with the transformers, such as repairing them, were significantly reduced by

not detecting the transformer failures sooner. The Commission is satisfied that the mitigation

measures undertaken by AltaLink and SNC-ATP were reasonable and efficient in the

circumstances. AltaLink chose not to take delivery of the failed transformers, instead utilizing

the transformers from the WATL project, which it knew had already passed factory testing.

Further, AltaLink indicated that repair of the original transformers was estimated to take nine to

10 months to complete and the RPG did not provide any evidence demonstrating that repair of

the transformers would have cost less than the solution employed by AltaLink.739 Therefore, the

Commission does not find that AltaLink could have pursued a better option had it learned sooner

of the transformer failures.

838. Finally, the Commission accepts AltaLink’s evidence that in focusing on delays with

respect to the construction of substation 12S, the RPG failed to appreciate that the priority in the

Heartland project was the construction of the critical path items as explained by AltaLink in

rebuttal evidence:

It is incorrect to assert “delay” without appreciating the logical sequence of construction

of transmission lines and, further, how critical path items are dealt with in the highest

priority. AltaLink always recognized that the construction of the 500 kV line portion of

the Heartland Project was the critical path item for the entire Heartland Project and

therefore made reasonable decisions to achieve the critical path. FTI fails to appreciate

that the 240 kV line, the Heartland substation and the modifications at Ellerslie were all

non-critical path activities.740

839. Based on the above, the Commission dismisses the RPG’s request to disallow the costs in

CP12 associated with the mitigation measures undertaken by AltaLink to address the failure of

the transformers for substation S12.

4.2.2.12 Graham construction

840. In 2011, AltaLink sought bids for the construction of the 500-kV transmission line of the

Heartland project. AltaLink received proposals from three bidders in November of 2011.

Subsequent to a commercial evaluation of the bids, the lowest bidder, Graham, was awarded the

contract subject to Henkels & McCoy (H&M), a specialized line contractor, being responsible

for completing stringing and for supervising Graham’s work on tower erection and foundation.

Graham started working on the project in early 2012.

739

Exhibit 3585-0086, Heartland Project Summary report, paragraph 26. 740



168 • Decision 3585-D03-2016 (June 6, 2016)

841. In July 2012, problems started to emerge with Graham’s work, including concerns with

its safety practices and productivity. SNC and AltaLink took remedial measures to avoid further

schedule delays and to meet the ISD. In December 2012, because problems with Graham’s

work persisted, SNC-ATP and AltaLink decided to bring in additional subcontractors to safely

complete the construction work.741 Graham was retained to continue to work on the installation

of tower foundations and to conclude erection of the 500-kV lattice towers already in progress.

842. Bids for the construction and installation of the remaining Heartland 500-kV towers

were sought in January, 2013. Rokstad Power Corporation (Rokstad) was retained for the

construction and erection of the remaining lattice towers. HB White was retained for the

construction and erection of the monopole towers. Stringing of the towers was assigned to SNC-

ATP.

843. The RPG strongly criticized AltaLink’s selection of Graham to provide foundation, tower

erection and stringing work for the 500-kV portion of the Heartland project. The RPG

maintained that AltaLink’s decision to retain Graham was imprudent, and may have contributed

to the significant cost overruns in this project. The RPG recommended that a cost and

performance audit be undertaken to determine the prudence of the Heartland project’s costs.

Otherwise, all costs associated with the construction delays caused by Graham’s inability to

complete the project should be disallowed from rate base.

844. In intervener evidence, the RPG asserted that Graham had no prior experience with

transmission line projects of the magnitude of Heartland, and that AltaLink failed to monitor

Graham’s work adequately given its lack of relevant experience.

845. The RPG stated that efficient construction of a transmission line involves a linear

sequential process. However, it noted that in several field trips to the Heartland project, with two

month gaps between the trips, the RPG observed that tower construction was not being advanced

in a linear sequential manner. The RPG asserted there could be a number of reasons for this,

including lack of experience or lack of proper equipment to construct the towers efficiently. In its

field trips, the RPG also observed that the project was advancing very slowly compared to

schedule and the expected ISD, another sign that the construction crews were inadequately

staffed, deployed or trained.

846. The RPG further noted that SNC-Lavalin has a 50 per cent share of a Joint Venture with

Graham and that it has been reported that Lafarge Canada was suing the consortium of SNC-

Lavalin and Graham for work Lafarge conducted on the west leg of Calgary’s LRT line. Lafarge

said it had tried to collect for more than a year but had been unsuccessful so filed a lawsuit. The

RPG claims that this intertwining of relationships between AltaLink and SNC-Lavalin and SNC-

Lavalin and Graham showed a potential conflict of interest that caused concern when it appeared

that there may be contractual non-performance as between the parties in the Heartland project.

847. In rebuttal evidence, AltaLink maintained that the reasonableness to retain Graham was

overwhelmingly demonstrated by the evidence provided on the record of this proceeding. In

support of its submissions, AltaLink noted it had used Graham in the past, and that Graham was

and is one of the largest construction companies in Canada and a leading provider of

infrastructure construction services in Western Canada. Further, Graham had significant

741

Exhibit 3585-X0707, pages 68-70 and 80-84.


Decision 3585-D03-2016 (June 6, 2016) • 169

experience in complex commercial, industrial, and infrastructure projects within urban

environments. Along with Graham’s known credentials, the fact that Graham had contracted

H&M for dressing and stringing of towers provided additional reasonable comfort to AltaLink

that the combined skill set and equipment available was capable of completing the project.

848. AltaLink further submitted that Graham’s experience with construction in high density

urban environments was considered an asset for the line construction in the East Edmonton TUC.

In addition, AltaLink considered that the entry of another qualified contractor for transmission

line construction services would expand the available pool of contractors and expand

competition in the construction and erection of transmission towers.

849. Further, AltaLink indicated that Graham was the lowest price bidder742 and, save for

limited exceptions, Rule 9.1.5.5 requires selection of the lowest priced compliant bid.743

850. AltaLink explained that the execution of the Heartland project encountered a series of

events that resulted in incremental increases in cost and time, but that these events would have

been faced by any contractor. The events included the late start and early break up in the winter

construction season of 2012, the conflicts in the TUC with the concurrent construction

undertaken for the North East Anthony Henday Drive P3 project, the schedule adjustments

necessary for Tower 176, and the extreme weather conditions in 2013, which included high

snowfall, followed by melt, flooding and wet weather through to mid-September of 2013.744

851. In argument, the RPG stated that AltaLink’s confidential evidence unequivocally

demonstrated that, prior to awarding the contract, AltaLink knew of the risk of Graham not being

able to carry out the project successfully. In fact, the RPG argued, due to “the lack of [Graham’s]

direct experience in the construction of transmission lines,” acceptance of Graham’s bid was

made conditional to having H&M supervise foundation installation and tower assembly and

erection.745

852. The RPG stated that SNC’s concern about Graham’s lack of experience and ability to

complete the project is further supported by the fact that the contract between SNC-ATP and

Graham contained a liquidated damages provision for delay caused by Graham.

Notwithstanding, there was no evidence on either the public or confidential record that SNC-

ATP enforced this provision when the risk of delay became a reality.

853. The RPG supported FTI’s evidence that SNC-ATP chose not to require additional

performance guarantees from Graham in the contract. SNC-ATP also chose not to back charge

any items to Graham.746 Apparently, the RPG claimed, this was because AltaLink’s

“commercially reasonable” interpretation of the contract documents is that “you’re not going to

chase every little put and take” with your contractor.747 Consequently, the RPG agreed with FTI’s

conclusion that AltaLink should be solely responsible for the costs arising from the delays

caused by Graham’s inability to execute the Heartland project successfully. The RPG claimed

742

Exhibit 3585-X0372-HLLbtd23-CONF. 743

ISO Rule 9.1 Transmission Facility Projects, at 9.1.5.5 and 9.1.5.6.; Exhibit 3585-X0042, PDF page 246. 744



Confidential Transcript, Volume 1, page 17, line 7 to page 18, line 13. 747

Confidential Transcript, Volume 1, page 18, line 16 to page 19, line 5.


170 • Decision 3585-D03-2016 (June 6, 2016)

that AltaLink knew of the risk of retaining Graham, but “rolled the dice”748 because Graham was

the lowest bidder by a substantial margin. AltaLink took a bet and lost. However, the RPG

submitted, ratepayers should not suffer the consequences of AltaLink’s lost bet.

854. In argument, AltaLink reiterated that retention of Graham was reasonable and restated its

submissions from rebuttal evidence. AltaLink also indicated that in executing the Heartland

project Graham was competent, well-managed and in many respects progressive in the way it

performed construction services. Further, within Alberta, Graham had a proven track record.

855. AltaLink refuted the RPG’s allegations of a conflict of interest between SNC-ATP and

AltaLink, maintaining the clear facts are that Graham was reasonably awarded work on the

Heartland project because of its qualifications and its successful participation in the competitive

bid process.

856. AltaLink argued that the hiring of additional contractors was required given the expanded

complexity and scope of the Heartland project. AltaLink wanted to avoid additional delays and

ensure the project would be completed for the 2013 winter. Further, over time, AltaLink became

concerned with Graham’s safety record.

857. AltaLink contested the allegations that Graham should have been held to its contract

through injunctive relief or been sued for delay damages. AltaLink asserted that successfully

achieving an injunction to force a party to do something can be extraordinarily difficult.

Moreover, AltaLink could not have simultaneously threatened to sue Graham and, yet, have it

kept working on the project to achieve the ISD. As for damages, the provisions of the

subcontract agreement with Graham expressly limit damages for delay, which it asserted was a

commercially reasonable provision to agree to when the size of the project far exceeds the

contractual scope of work.

858. For reasons explained in confidential argument, AltaLink claimed that the RPG’s

contention that a performance bond should have been secured from Graham also lacks merit.

859. The RPG provided further comments in reply argument. The RPG noted that in the

Project Summary Report, AltaLink clearly indicated that it spent time and effort managing

Graham’s project execution and progress to ensure acceptable performance, and that by

December 2012 it was apparent that Graham was not able to overcome performance issues.749 In

addition, AltaLink delayed its decision to “de-scope” Graham until December 2012, giving up all

the cost advantages of winter construction at the expense of ratepayers.

860. The RPG asserted that the crux of AltaLink’s argument is that the project’s complexities

required additional contractors and that AltaLink made reasonable decisions to respond to

changed circumstances. However, the RPG maintained AltaLink should have anticipated the

concurrence of the construction of the North East Anthony Henday Drive P3 project in the TUC.

Similarly, AltaLink should have known of the construction of the Enbridge pipeline.

861. The RPG disputed AltaLink’s suggestion that AltaLink should have sued Graham. The

RPG termed this a mischaracterization and stated that its actual suggestion was that AltaLink

748


Exhibit 0086.00.AML-3585.


Decision 3585-D03-2016 (June 6, 2016) • 171

should enforce its contract. The RPG repeated its suggestion that AltaLink could have secured a

performance bond for Graham’s work.

862. In reply argument, AltaLink restated that even though the cost of the Heartland project

increased significantly from the original budget, all other possible options would have resulted in

costs similar to, or higher than, what AltaLink actually achieved.

863. AltaLink also indicated that by the time it received P&L, the road building contract for

the North East Anthony Henday Drive P3 project had not yet been awarded. Further, even as of

April 2012, the Anthony Henday Drive was only 30 per cent complete in engineering. Therefore,

given the timing of the road building project, AltaLink could not have anticipated the execution

plan or its effect on the Heartland project.

Commission findings

864. There are two main issues concerning Graham. The first issue is the reasonableness of

AltaLink’s decision to select Graham as the main subcontractor for the construction of the 500-

kV transmission line. The second issue is the reasonableness of AltaLink’s decision to continue

to work with Graham even after Graham’s inability to complete the project within the expected

timeline had been confirmed.

865. With respect to the first issue, the Commission notes that AltaLink, by its own admission,

was well aware at the time the contract was awarded to Graham that Graham had no previous

experience with construction of transmission lines. The Commission agrees with the RPG that

this should have raised concerns, particularly given the magnitude of the Heartland project.

Indeed, as stated by AltaLink, “The scope and complexity of the Heartland project was

unprecedented as the first critical transmission infrastructure project in Alberta,”750 and towers

used for the 500-kV portion of the Heartland project were the largest ever used in Alberta at that

time.751

866. The Commission is of the view, however, that Graham’s lack of experience with

transmission line projects does not constitute sufficient reason for outright rejection of its bid

proposal, but it was a factor that needed to be addressed. The Commission accepts AltaLink’s

evidence that the following factors weighed in favour of awarding the contract to Graham,

despite its inexperience with constructing transmission lines:

(a) Graham had contracted H&M for the dressing and stringing, which provided additional

reasonable comfort that the combined skill set and equipment available was capable of

completing the project.

(b) Graham was one of the largest construction companies in Canada and a leading

provider of infrastructure construction services in Western Canada.

(c) Graham had significant experience in complex commercial, industrial, and

infrastructure projects within urban environments, which would likely prove useful for

the line construction within the TUC.

750




172 • Decision 3585-D03-2016 (June 6, 2016)

(d) AltaLink had previously retained Graham and Graham had a proven track record.

867. However, the Commission finds that the most compelling reason justifying AltaLink’s

selection of Graham was that Graham provided the lowest bid by a considerable amount, and yet

within the range of the SNC-ATP budget for the project. Given the significant difference

between Graham’s bid and the second lowest bid, even had AltaLink allowed for a margin of

inexperience and anticipated the possibility of Graham incurring additional costs to complete the

project, it was reasonable to conclude that Graham could meet the tender scope qualification, and

the project work tendered to Graham could be completed at a cost below that of the next highest

bidder.

868. In this regard, the Commission notes that if AltaLink had instead awarded the contact to

the second lowest bidder, the final project costs would still have exceeded AltaLink’s total costs

to complete the project, including the costs for retaining three additional subcontractors.752

Moreover, it is likely that the second lowest bidder would also have incurred additional costs

when confronted with some of the project challenges that were not originally contemplated in the

bid proposal, and that would inevitably further drive up costs, ultimately being recovered from

AltaLink. While the Commission concedes that the second lowest bidder might have been

marginally more efficient in 2012, this would only offset a fraction of the cost difference.

Accordingly, the Commission finds that AltaLink’s choice to award Graham the 500-kV

transmission line contract was prudent.

869. With respect to the second issue, the Commission notes that difficulties with Graham first

became noticeable around July 2012. Graham’s scope of work was not amended until December

2012 (scope amendment). As part of the scope amendment, AltaLink retained Graham to

complete the foundation work and the tower erections it had already started. The evidence on the

confidential record753 shows that the unit pricing of the contractors brought in to complete tower

erection was considerably higher than that of Graham.754 The Commission acknowledges that at

the time AltaLink decided to keep Graham in the project, it had not yet sought bids for the

construction and installation of the remaining towers and, therefore, would not have been able to

know the exact difference in unit prices. However, given that Graham’s initial bid for the project

was considerably lower than the other bids, AltaLink could have reasonably assumed that

keeping Graham for the work it was to complete would have been less costly.

870. The Commission also considers that terminating Graham and retaining a different

subcontractor to complete the installation of foundations and the erection of towers already in

progress, would have potentially resulted in further schedule delays. Retaining Graham allowed

for work continuity. In addition, the Commission accepts AltaLink’s evidence that Graham was

experienced in foundations work and, up until then, the installation of foundations in the

Heartland project was satisfactory. Given these facts, the Commission considers that it was

reasonable to continue to retain Graham even after concerns with Graham’s work arose.

871. The Commission does not accept AltaLink’s evidence that Graham’s work product was

entirely satisfactory and that the project delays were due to no fault of Graham, but solely

752

Exhibit 3585-X0819c. 753

Exhibit 3585-X0819c. 754

Information of the actual unit prices for these contractors were provided on the confidential record.


Decision 3585-D03-2016 (June 6, 2016) • 173

because of project complexities and unexpected weather conditions.755 Nevertheless, the

Commission finds that AltaLink could not have reasonably anticipated the extent of the problems

with Graham. Even if it did, for the reasons discussed above, it would still have been reasonable

for AltaLink to retain Graham. Furthermore, the Commission considers that the steps taken by

AltaLink to address concerns with Graham, such as retaining additional subcontractors to

complete the project, were reasonable in the circumstances and timely, given the AESO’s

concern respecting rolling blackouts in the region and its desire for this project to be completed

as soon as possible.

872. The RPG’s concerns with AltaLink’s enforcement of the contractual agreement with

Graham are addressed by the Commission in Section 4.2.2.13 of this decision.

4.2.2.13 Analysis of change notices

873. The FTI evidence, prepared on behalf of the RPG, provided an analysis of certain change

notices related to the Heartland project. The FTI concluded that a number of change notices were

not adequately justified and, therefore, should be disallowed. The change notices recommended

for disallowance, contained in Appendix 2 to the FTI evidence, totalled $61.7 million.756

874. In confidential argument, the RPG referred to specific change notices, maintaining that

they contained inconsistencies and inadequate explanations of the costs.757 In reply argument, the

RPG claimed that AltaLink attempted to justify what the RPG termed “huge cost overruns” in

the Heartland project, by claiming that the project was “incredibly complex.”758 However, the

RPG stated, the project was always planned to be constructed in the TUC. Therefore, AltaLink

should have anticipated complexities associated with constructing a transmission line in close

proximity to other linear infrastructures, such as highways and pipelines. In addition, the RPG

stated, one of the reasons Graham was retained in the first place was its experience in complex

urban environments. AltaLink “is trying to have it both ways.”759

875. In reply argument, AltaLink referred to Tab 6 of its rebuttal evidence in which it

addressed the change notices challenged by the RPG and questioned whether the RPG or its

experts made use of the source documents available to them.760

Commission findings

876. The Commission examined all the subcontract amendments with respect to the Heartland

project.761

877. The Commission paid particular attention to the expenditures in the Heartland project

related to the subcontract agreement with Graham. The Commission understands that after the

scope amendment to Graham’s work, Graham became responsible for installation of the

foundations and for completing the work already in progress for erection of towers.762 However,

755

Exhibit 3585-X0380d1, pages 78-84. 756

Exhibit 3585-X0667, Appendix 2. 757

Exhibit 3585-X0860, PDF page 91 refers to FTI evidence pages 60-65. 758

Exhibit 3585-X0865, page 56. 759

Exhibit 3585-X0865, page 57. 760

Exhibit 3585-X0042, page 469. 761

Exhibit 3585-X0382, AML-CCA-038(a)17, 17 subfolders containing hundreds of documents. 762

Exhibit 3585-X0382, IR AML-CCA-038(a)17, folder C41, document 344 and Exhibit 3585-X0819a, IR 004.


174 • Decision 3585-D03-2016 (June 6, 2016)

in the Commission’s review of the record,763 it has found evidence of additional contractors being

retained to either complete the work assigned to Graham or to perform quality control on

Graham’s work after the scope amendment. These are summarized in the following table:

Table 13. Subcontract amendments supporting disallowance

Contractor Subcontract Amendment/Exhibit No./Document No.

Description

Rokstad Subcontract amendment 1, Exhibit 382, document 371 in subfolder C44

Quality control on towers to determine deficiencies and repairs needed

Rokstad Subcontract amendment 7, Exhibit 382, document 377 in subfolder C44

Completion of towers started by Graham

Rokstad Subcontract amendment 8, Exhibit 382, document 378, page 25 of 40, EWR 28, Rev 5

Quality control of Graham towers

Henkels & McCoy Subcontract amendment 7, Exhibit 382, document 390 in subfolder C35

Completion of Graham towers

878. The Commission does not consider it reasonable for AltaLink to have included these

costs for recovery from ratepayers. Rather, the Commission finds that it would have been

reasonable for AltaLink to have recovered these costs from either Graham, as the party

responsible for satisfactorily completing erection of towers and installation of foundations, or

from SNC-ATP, as the contract manager on the project. Ratepayers should not pay for the same

service twice.

879. The Commission reviewed the PO/contract log764 and could find no evidence that a credit

was processed against Graham. AltaLink is, therefore, directed to deduct the total amount of

these subcontract amendments from its compliance filing. AltaLink is also directed to deduct

from its costs any management surcharge amount it may have paid to SNC-ATP related to these

subcontract amendments.

880. The Commission notes that Subcontract Amendment 5 to Graham’s subcontract

agreement includes a charge for “additional management resources.” The Commission does not

consider that the entirety of the costs for additional management resources are justified.

Although access and weather issues might have required more resources, when Graham signed

the subcontract agreement on March 16, 2012,765 it should have known that the ISD was being

extended to September, 2013, and that, consequently, it would require additional management

resources to accommodate that schedule extension. In the Commission’s view, Graham did not

adequately plan for the resources to complete the project, even though it already knew the scope

of the project, and ratepayers should not be responsible for this cost. The Commission considers

a disallowance of one third of this amount766 to be reasonable. AltaLink is, therefore, directed to

deduct one third of the amount for additional management resources in Subcontract

Amendment 5 from its compliance filing. AltaLink is also directed to deduct from its costs one-

third of any management surcharge amount it may have paid to SNC-ATP related to the costs for

additional management resources.

763

Exhibit 33585-X0382, IR AML-CCA-038(a)17, folders C44 and 35. 764

Exhibit 3585-X0526. 765


This amount is shown in Exhibit 3585-X0819b, PDF page 8, item 3 of the 5 items list.


Decision 3585-D03-2016 (June 6, 2016) • 175

881. The Commission questioned the amounts paid to Graham for “tower settlement,” as

indicated in Subcontract Amendment 8-5.767 When asked by the Commission to provide

additional information regarding the nature of these costs, AltaLink explained that these

payments “reflected an overall settlement of outstanding matters that had arisen due to the

increased complexity of the project.”768 The Commission notes that, as a result of the scope

amendment, Graham lost a substantial portion of the 500-kV transmission line contract work

and, consequently, the revenue associated with this work. The Commission recognizes that as

part of the consideration for Graham to continue to perform the reduced work on the project, at

the originally contracted unit prices, AltaLink agreed to pay Graham a settlement amount; the

“tower settlement.” The Commission previously found it was reasonable for AltaLink to retain

Graham to complete the work already in progress given that Graham’s unit prices were

considerably lower than other subcontractors and because the retention of Graham would

minimize further project delays. Therefore, the Commission is satisfied that it was commercially

reasonable for AltaLink to incur this additional expense. The Commission, however, considers

that the settlement amount agreed to appears excessive given the total cost of the outstanding

work to be completed by Graham. Accordingly, the Commission finds that a 20 per cent

reduction to the amount associated with the “tower settlement” to be reasonable.

882. The Commission also examined Subcontract Amendment 2, regarding additional

compensation paid to H&M for increased manpower and acceleration, and Subcontract

Amendment 6, also for payment to H&M, with respect to an acceleration incentive plan. Both of

these subcontract amendments represented a considerable cost increase to the original contract

amount. Upon the Commission’s request, AltaLink provided additional information in support of

these cost items.769 The Commission is satisfied with the additional explanation provided by

AltaLink and finds the costs included in these subcontract amendments to have been reasonably

incurred.

883. The Commission has not identified any other concerns with respect to the change notices

or subcontract amendments for the Heartland project.

884. Similar to the Commission’s finding regarding change notices with respect to the CB

project, in arriving at this finding, the Commission is not determining whether AltaLink or SNC-

ATP have a contractual remedy available against Graham, nor is the Commission determining

what the costs of pursuing this remedy might be. These matters to be considered by AltaLink.

4.2.2.14 Land acquisition issues

885. In Section 7.2.3. of the Commission’s decision on AltaLink’s facility application for the

Heartland project (Decision 2011-436), the Commission addressed AltaLink’s guidelines for

buyouts of landowners. As part of its findings, the Commission stated:

390. The Commission will not examine the purchase and sale of property acquired by

the applicants under their land acquisition policy within this proceeding, or the prudence

of the applicants’ policy to resell all of the properties required as a result of their buyout

policy no later than the first day of the sixth full month after energizing the project and

767

Exhibit 3585-X0819b-CONF, page 15. Two identified as Tower Settlement (#17479) and Tower Settlement

(Invoice#17480). 768

Exhibit 3585-X0853b, page 1. 769

Exhibit 3585-X00853a.


176 • Decision 3585-D03-2016 (June 6, 2016)

include the cost differential (positive or negative) as part of the project capital costs.

Examination of these matters is properly considered within the scope of a rate

application.

886. During the oral hearing, Mr. Watson, an AltaLink witness, explained that the amount

shown in the DACDA application for land acquisitions for the full project to December 31, 2014

($28.3 million),770 included acquisitions related to the buyout policy.771

887. Mr. Watson explained that, as of the date of his testimony, a total of 25 properties had

been purchased at a cost of $26.6 million in accordance with the Heartland buyout criteria. Of

the 25 properties, Mr. Watson explained that 12 had been sold, resulting in $5.4 million being

netted back to the project.772

888. In argument, AltaLink explained that because the Heartland project was complex and was

actively opposed by many interveners, the Commission panel in the facility application

proceeding asked AltaLink to put forward a list of exceptions or criteria that could be applied to

its buyout policy. After reviewing its buyout policy, AltaLink decided to increase the buyout

option to landowners within 200 metres, as opposed to the 150 metres, of the centreline of the

Heartland transmission line and to other affected persons falling within the parameters set forth

in Undertaking 82, which was given during the hearing of the Heartland proceeding. The

Commission found that the new exceptions were warranted and that the process was reasonable

and would be fair to landowners.773

889. AltaLink indicated that, as a result of the new exceptions to its policy, it incurred

additional costs of $24.3 million as compared to the PPS estimate for land acquisitions. This

amount includes offsets for sales concluded to February 28, 2015. AltaLink explained that it

expects that approximately $10 million will be achieved through future sales to further Heartland

project land acquisition costs. AltaLink also indicated it expects to incur a cost of approximately

$2 million to manage these futures sales. AltaLink noted that these cost adjustments will be

reflected as trailing costs.774

890. AltaLink also noted that, because the land compensation determined by the SRB was

higher than anticipated in the PPS estimate, it had incurred an additional $2.3 million to acquire

land easements. Further, as not all of the land compensation decisions have been received from

the SRB, compensation amounts ordered in those proceedings will be filed as trailing costs.775

891. In light of these explanations, AltaLink submitted that its costs for land acquisition are

reasonable and fully in compliance with commitments made to the Commission in the Heartland

facility application proceeding.776

892. In its argument, the RPG submitted that the $24.3 million variance attributed to land

acquisitions represents a significant overrun.777 The RPG submitted that AltaLink failed to

770









Decision 3585-D03-2016 (June 6, 2016) • 177

provide information to explain why a change from 150 metres to 200 metres in AltaLink’s

buyout policy for the Heartland project resulted in such a large variance. The RPG noted that it is

not evident how many additional properties AltaLink purchased due to the change in the policy,

nor the cumulative value of such purchases.778

Commission findings

893. The Commission notes that despite the findings in paragraph 390 of Decision 2011-436,

AltaLink has not explained in its DACDA application, why its buyout policy was prudent.

894. AltaLink energized the project at 240 kV, on December 28, 2013.779 Accordingly, the first

day of the sixth full month after energization is June 1, 2014. However, to date, AltaLink

indicated that it has only resold 12 of the 25 properties purchased. AltaLink did not offer an

explanation as to why it did not resell all properties purchased by the deadline of June 1, 2014.

895. The Commission also notes that it was difficult to understand the nature and allocation of

the costs incurred by AltaLink as a result of its land acquisition policy. The Commission

identified the following issues with AltaLink’s application:

AltaLink did not separately report the component of owner costs for the project in tab

“D.0371” of Exhibit 0006.00.AML-3585.

AltaLink did not provide a breakdown of owner and distributed costs for its DACDA

application projects, including the Heartland project, in response to AML-AUC-

2015MAR05-003.780

AltaLink did not mention land acquisitions in the Project Summary for the Heartland

project.781

896. The Commission further notes that while Mr. Watson explained in his testimony that

12 of the 25 purchased properties have already been sold, the number of properties sold and the

respective proceed amounts are unclear in AltaLink’s requested additions to November 30, 2014

for this project.

897. At this point, the Commission is unclear as to what amount of land sales offset is

included in the $28.3 million for land acquisition cost to November 30, 2014. Given that the land

acquisition costs reflect primarily a “gross” purchase amount, future trailing costs include a

significant “negative trailing cost” for expected land sales. Therefore, the Commission has

determined that the full $28.3 million should be excluded from AltaLink’s approved addition to

rate base at this time. For clarity, the Commission expects that AltaLink will request the approval

of its Heartland projects land acquisition costs, net of offsets for land sales and associated costs,

in AltaLink’s Heartland project trailing cost application.

777







178 • Decision 3585-D03-2016 (June 6, 2016)

898. The Commission directs AltaLink, in the trailing cost application, to make submissions in

support of the prudence of its policy to “resell all of the properties required as a result of its

buyout policy no later than the first day of the sixth full month after energizing the project and

include the cost differential (positive or negative) as part of the project capital costs,” and to

justify deviation from its policy to resell all of the purchased properties within six months

following energization.

4.2.2.15 Request for cost and performance audit

899. As noted in Section 4.1.10 of this decision, FTI submitted in its evidence that the

proceeding record supports the need for a cost and performance audit of the Heartland project.

The RPG supported FTI’s view, maintaining that AltaLink failed to act prudently in incurring

costs in the Heartland project.

900. The RPG submitted that AltaLink failed to provide adequate evidence regarding key

decisions in the project that contributed to large cost increases. Instead, the RPG submitted,

AltaLink largely relied on the IR process and, thus, put the burden on interveners and the

Commission to determine where key decisions were made and why AltaLink’s decisions resulted

in prudent costs.

901. In argument, AltaLink submitted it fully addressed the RPG’s request for a cost and

performance audit of the Heartland project in its general comments on audits. AltaLink reiterated

that a cost and performance audit for the Heartland project is unnecessary as there is extensive

evidence on the record of this proceeding to allow the Commission to make a final determination

on the prudence of its costs.

902. In its reply argument, the RPG claimed the cost overruns related to the Heartland project

were massive and not adequately justified by AltaLink. The RPG stated if the Commission is not

prepared to disallow some or all of the overruns, the Commission should order a cost and

performance audit.

Commission findings

903. In Section 4.1.10 of this decision, the Commission found that there is sufficient

information provided on the record of this proceeding to enable it to make a prudence

determination with respect to AltaLink’s costs without the requirement of a cost and

performance audit. Therefore, the Commission concluded that in the absence of findings of

significant areas of uncertainty or concern requiring further investigation, directing an audit is

not necessary.

904. After reviewing the parties’ submissions, the Commission is not convinced that there are

significant areas of concern with respect to the Heartland project, justifying the requirement for

an audit. While the Commission recognizes that given the voluminous record of this proceeding,

it was a cumbersome task for both the interveners and the Commission to review AltaLink’s

evidence, the Commission is satisfied that it was able to make determinations respecting the

prudence of AltaLink’s costs based on its own examination of the record.

905. Accordingly, further to the Commission’s general findings with respect to the RPG’s and

FTI’s request for a cost and performance audit, the Commission will not direct an audit of the

Heartland project expenditures at this time.


Decision 3585-D03-2016 (June 6, 2016) • 179

4.2.2.16 Summary of findings

906. The Commission has made a number of findings with respect to the Heartland project and

considers that a summary may be helpful. In summary, the Commission has found the following

with respect to the Heartland project:

It was reasonable to include the 2014 Heartland project costs as part of this proceeding.

The transmission line design and associated costs were reasonable and prudent.

A reconciliation of the allocation of the approved expenditures as between AltaLink and

EDTI must be provided in the compliance filing.

The use of matting on the project and the consequential costs were reasonable and

prudent.

The use of helicopters for the erection of towers on the project and the consequential

costs were reasonable and prudent.

The location of the transmission line within the TUC was reasonable.

The costs for pipeline mitigation were significantly higher than the PPS estimate. The

Commission has approved a placeholder for the requested amount, approximately

$43 million. AltaLink is directed to supply further support for the claimed expenditure of

requested pipeline mitigation expenditures when filing its next DACDA.

The extension of the project ISD, and associated costs, to accommodate the

Commission’s direction to use monopoles for 9.5 km of the transmission line was

reasonable and prudent.

The extension of the project ISD, and associated costs, to implement mitigation measures

to address transformer failures in substation S12 were reasonable and prudent.

The selection of Graham as the main subcontractor for the construction of the 500-kV

transmission line, as well as the decision to retain Graham to complete a re-scoped part of

the work, was reasonable and prudent.

The inclusion of costs incurred relating to quality control, repair, and completion of work

originally assigned to Graham, including any costs for any management surcharge

amount it may have paid to SNC-ATP, was not reasonable and these costs are directed to

be removed.

The total costs incurred for “additional management resources” in Subcontract

Amendment 5 to Graham’s subcontract agreement are not reasonable. One-third of these

costs, including one-third of any management surcharge amount it may have paid to

SNC-ATP, are directed to be removed.

The total costs paid as a “tower settlement” in Subcontract Amendment 8-5 to Graham’s

subcontract agreement are not reasonable and 20 per cent of these costs, including


180 • Decision 3585-D03-2016 (June 6, 2016)

20 per cent of any management surcharge amount it may have paid to SNC-ATP, are

directed to be removed.

The costs associated with land acquisition are to be excluded from the additions to rate

base and will be assessed as part of the application for the project’s trailing costs once the

proposed resale of excess land is completed.

The total amount of costs disallowed for the Heartland project is approximately

$5.5 million.

4.2.3 Other major system projects

4.2.3.1 D.0030.01 – Yellowhead Area Transmission Development Hinton-Edson

Development

4.2.3.1.1 Recovery requested

907. AltaLink is seeking recovery of requested additions to rate base in the amount of $72.1

million for the project.782 In conjunction with an addition in the amount of $9.2 million approved

in a prior application,783 capital additions before salvage for the Yellowhead Hinton-Edson

development project totalled $ 70.1 million to the end of 2013, representing a variance of

approximately $22.8 million in relation to the project cost, excluding salvage forecast by

AltaLink at the PPS stage.

908. A detailed breakdown of Yellowhead Hinton-Edson development project costs at major

stages is provided in Table 14 below:

Table 14. Yellowhead Hinton-Edson Development project (D.0030.01) cost breakdown

PPS

Mar 23, 2010 +/- 10% update

Nov 7, 2011 Addition to

Dec 31, 2013(3) Final Cost Report(3)



Substation materials 738,000 824,028 819,319 819,319




O: proposal to provide service 746,000 Not provided 200,000 200,000

O: facility applications 500,000 Not provided 900,000 900,000

O: land-rights - easements 1,000,000 Not provided 1,400,000 1,400,000

O: land-rights – damage claims 0 Not provided 100,000 100,000

O: land - acquisitions 0 Not provided 0 0


782

Exhibit 0184.00.AML-3585. 783

Exhibit 0174.00.AML-3585, PDF page 7, paragraph 15.


Decision 3585-D03-2016 (June 6, 2016) • 181

PPS

Mar 23, 2010 +/- 10% update

Nov 7, 2011 Addition to


D: procurement 221,000 Not provided 800,000 900,000

D: project management 2,760,000 Not provided 5,200,000 6,900,000

D: construction management 1,075,000 Not provided 2,300,000 2,200,000

D: escalation(1) 0 Not provided - -

D: contingency 6,917,000 Not provided - -


OT: ES&G 2,658,000 2,356,166 3,257,980 3,100,753

OT: AFUDC 851,000 2,173,183 292,508 292,507

Total project costs(2) 47,368,000 43,580,956 70,138,203(4) 72,061,509

Source: Exhibit 0175.00.AML-3585 (PPS); Exhibit 0183.00.AML-3585 (update); Exhibit 184.00.AML-3585 (final); Exhibit 3585-X0043; and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 89. Note: 1) Escalation line item was not included in the PPS estimate.

2) Total project costs do not include salvage. 3) Some numbers may not add up due to differences between exhibits in significant digits used.

4) Includes $9,200,000 which was approved to be added to rate base in a previous application.

4.2.3.1.2 Project overview

909. On May 12, 2010, the Commission approved the NID application of the AESO for the

Yellowhead Area Transmission System Development, which considered transmission

development proposals prepared by the AESO in respect of its Wabamun, Drayton Valley, and

Hinton/Edson transmission planning areas.784 For the Hinton/Edson transmission planning area,

the Commission approved an AESO proposal involving the rebuild and reconfiguration of

transmission line 745L and the addition of a capacitor bank at the Cold Creek 602S substation.

The NID was approved in Decision 2010-208.785

910. At the direction of the AESO, AltaLink prepared a PPS for the Yellowhead Hinton-Edson

development project, which estimated costs of $47.4 million and a forecast ISD of November

2011.786

911. AltaLink filed a facility application to meet the Hinton/Edson transmission planning area

need considered in Decision 2010-208 in August 2010. The scope of the project included the

construction of new 138-kV transmission lines connecting its Edson 58S substation and Cold

Creek 602S substation to its Bickerdike 39S substation and included the replacement and

alteration of approximately 84 km of the existing single‐circuit 138-kV transmission line 745L

between Cold Creek 602S substation and Edson 58S substation.787 The Commission approved

this facility application in Decision 2011-188 on April 29, 2011.

784


Decision 2010-208: Alberta Electric System Operator, Needs Identification Document Application,

Yellowhead Area Transmission System Development, Proceeding 270, Application 1605154-1, May 12,

2010. 786

Exhibit 0174.AMl-3585, page 3. 787

Exhibit 0174.AMl-3585, page 4 and Decision 2011-188, paragraph 4.


182 • Decision 3585-D03-2016 (June 6, 2016)

912. In conjunction with Decision 2011-188,788 the Commission issued a number of P&Ls or

approvals. In Decision DA2012-185,789 the Commission approved a time extension in respect of

approved alterations to transmission line 745L from July 31, 2012 to December 31, 2012.790


Commission in respect of AltaLink project D.0030.01 is in Appendix 4.

914. The project was energized on October 31, 2012.791

4.2.3.1.3 Key project variances

915. The key trends and changes that drove project cost variances as set out in AltaLink’s

initial application evidence, are summarized in Table 15 below:

Table 15. Project D.0030.01 key cost variance events

Change report identifier Reason or Need

Cost Impact ($)

TCA #3 Additional costs associated with right-of-way clearing and management. 1,320,481

TCA #4 Land owner commitments and pipeline mitigation not included in original PPS 77,306

TCA #5 Additional rig mat rental not identified in PPS. 4,430,519

TCA #6 Additional pipeline, stream, access road crossings not identified in original PPS. 2,231,905

TCA #7 Costs associated with required environmental mitigation: additional tracked vehicles, additional subcontractor hours, and additional project management, construction management and procurement management costs.

15,398,424

CP-AFUDC AFUDC Reconciliation (558,493)


916. AltaLink provided a further breakdown of the largest change notice, TCA 7, which

increased the project budget by $15,398,424. The contributing factors for the increase were:

Rental of tracked construction equipment to mitigate environmental impacts.

Access mats required to mitigate environmental impacts.

Transmission line construction during non-frozen ground conditions due to construction

delays.

Construction suspension, due to environmental restrictions.

Additional project and construction management costs associated with schedule delays.

Pipeline AC mitigation costs, which were not anticipated in the PPS.792

917. The contingency draw down amount for this project was $5,980,067 to offset

transmission line labour cost increases related to right-of-way access for tree clearing and road

788

Decision 2011-188: AltaLink Management Ltd., Yellowhead Area Transmission Reinforcement, Edson to

Hinton, Proceeding 766, Application 1606438-1, April 29, 2011. 789

Decision DA2012-185: AltaLink Management Ltd., Yellowhead Area Transmission Reinforcement,

Proceeding 1980, Application 1608599-1, July 18, 2012. 790

Permit and Licence U2012-339. 791


Exhibit 3585-X0042, AML-AUC-2015MAR05-029(b), PDF pages 428-430.


Decision 3585-D03-2016 (June 6, 2016) • 183

construction, extended subcontractor schedule and manpower for lines construction, brushing

easements, and access mats and delays due to adverse weather.793

918. One of the challenges AltaLink faced was coordinating with the distribution facility

owner (DFO) to relocate the existing underbuild on the 745L line, which was being salvaged

prior to construction of the new line. The DFO experienced challenges with railway crossing

approvals and environmental restrictions that negatively affected the schedule which, in turn,

negatively affected the transmission line construction schedule.794 For this reason, AltaLink

sought and was granted a time extension of the in-service date from the AESO to May 2012.795

919. Schedule delays moved the construction schedule from two winters to one and resulted in

some construction occurring in non-frozen conditions. AltaLink indicated that it consulted with

the AESO regarding schedule delays and implemented a risk mitigation strategy.796 The options

of suspending construction to wait for frozen ground conditions versus continuing during non-

frozen conditions and mitigating environmental issues were examined and the costs to delay

construction were found to exceed the costs to proceed. The option to continue was pursued in

order to minimize costs and improve system reliability.797

920. In argument, AltaLink submitted that it was in regular communication with the AESO

throughout the project to keep the AESO apprised of challenges as they arose. The AESO

continued to indicate that the in-service date was of “critical importance.” The AESO did not

identify any contraventions of ISO Rule 9.1.5 during the compliance monitoring audit for

material procurement.

921. The Yellowhead Hinton-Edson project was not specifically addressed by interveners in

evidence, nor in argument and reply.

Commission findings

922. The Commission has reviewed AltaLink’s evidence and submissions in support of its

expenditures on the Yellowhead Hinton-Edson project, and considers that the actions of

AltaLink in response to the direction it was receiving from the AESO to maintain the in-service

date was reasonable. Further to the Commission’s findings in Section 4.1.6 above, the

Commission considers that the TFO, in this case AltaLink, has a duty to carry out directions

received from the AESO. To the extent that increased expenditures were primarily required to

ensure that the project was executed in a manner to minimize disruptions to the Hinton area at

the direction of the AESO,798 the Commission is satisfied with the explanations provided for

variances from the initial project forecast costs. Accordingly, the Commission finds that the

requested capital amounts for 2012 and 2013 of $60,938,203 were prudent and AltaLink is

authorized to add this amount to its rate base.

793

Exhibit 3585-X0045, AML-CCA-2015MAR05-015(e), PDF page 221. 794

Exhibit 3585-X0042, AML-AUC-2015MAR05-029(a), PDF Page 426. 795


Exhibit 3585-X0045, AML-CCA-2015MAR05-024(g), PDF page 259. 797

Exhibit 0185.00.AML-3585, TFCMC presentation, PDF pages 9, 10, 18 and 20. 798



184 • Decision 3585-D03-2016 (June 6, 2016)

4.2.3.2 D.0030.03 – Yellowhead Area Transmission Development Cherhill Area

Development


923. In the application, AltaLink requested additions to rate base in the amount of

$19.8 million for 2012 and $1.4 million for 2013.799 In conjunction with an addition in the

amount of $0.6 million approved in a prior application, capital additions for the Yellowhead

Cherhill Area Development project totalled $21.8 million to the end of 2013, which was

$2.8 million less than the project cost forecast at the PPS stage. AltaLink’s final cost report,800

reported a final cost, excluding salvage, of $22.0 million for the project.

924. A detailed breakdown of Yellowhead Cherhill development project costs at major stages

is provided in Table 16 below:

Table 16. Yellowhead - Cherhill Areas development cost breakdown

PPS +/-10% update

Nov 7, 2011 Additions to

Dec 31, 2013(2) Final report

Feb 18, 2014(2)

Transmission line materials 568,000 321,106 330,997 330,057






O: proposal to provide service 227,000 Not provided 0 0


O: land-rights - easements 200,000 Not provided 100,000 100,000


O: land - acquisitions 0 Not provided 200.000 200.000

O: ROW Costs Not provided 0 0

Total owner costs 677,000 998,550 1,118,549 1,119,269




D: escalation Not provided 0 -

D: escalation contingency (cont) 4,737,000 Not provided 0 -


OT: ES&G 1,143,000 1,470,366 971,363 979,582

OT: AFUDC 974,000 326,220 193,740 194,090

Total project costs(1) 24,624,000 25,278,577 21,805,600(3) 22,047,609

Source: Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 90 and Exhibit 0215.00.AML-3585, PDF page 482. Note: 1) Total project costs do not include salvage.

2) Some numbers may not add up due to differences between exhibits in significant digits used. 3) This includes $646,437, which was approved to be added to rate base in a previous application.


925. On May 12, 2010, the Commission approved the NID application of the AESO for the

Yellowhead Area Transmission System Development, which considered transmission

development proposals prepared by the AESO in respect of its Wabamun, Drayton Valley, and

799

Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 800



Decision 3585-D03-2016 (June 6, 2016) • 185

Hinton/Edson transmission planning areas.801 The AESO explained that this project was required

to support customer load growth in the Alberta Beach area and to address infrastructure nearing

the end of its useful life. An upgrade to the existing 69-kV transmission lines and substations in

the Alberta Beach region was required to increase transfer capability and mitigate potential

reliability issues.802 The Yellowhead Area NID was approved in Decision 2010-208.

926. At the direction of the AESO, AltaLink prepared a PPS for the Cherhill substation that

estimated costs of $24.6 million and a target ISD of March 28, 2011.803

927. AltaLink filed a facility application on July 26, 2010. The scope of the project included

construction of a new 240/25-kV substation, designated as Cherhill 338S, the construction of

approximately 100 m of two single‐circuit 240-kV transmission lines and the decommissioning

and salvaging of existing 69-kV transmission lines.804 The Commission approved the facility

application in Decision 2011-161 on April 21, 2011.

928. In conjunction with Decision 2011-161, the Commission issued a number of P&Ls or

approvals. In Decision DA2013-53,805 the Commission approved a request to extend three P&Ls

from June 30, 2012 to December 31, 2013, regarding the decommissioning and salvaging of

some transmission lines.806


Commission in respect of the Yellowhead Cherhill project is in Appendix 4.

930. The project was energized on April 2, 2012.807


931. AltaLink identified the following key trends and changes as affecting project cost

variances as set out in AltaLink’s initial application evidence:

Table 17. Project D.0030.03 key cost variance events


Cost Impact ($)

TCA #3 Change in scope 7L230 - improve the line rating to 114/143 MVA

10,000

CP-AFUDC AFUDC reconciliation ($779,910)

Source: Exhibit 0215.00.AML-3585, AESO change notices, PDF pages 146 and 155-157.

801




Decision 2011-161: AltaLink Management Ltd. and TransAlta Corporation, Yellowhead Area Transmission

Reinforcement: Alberta Beach Area (Cherhill 338S Substation), Proceeding 762, Application 1606397-1,

April 21, 2011, paragraphs 14-15. 805

Decision DA2013-53: AltaLink Management Ltd., Salvage of Transmission Lines 104L, 104BL and 104EL,

Proceeding 2433, Application 1609299-1, February 20, 2013. 806


AESO transmission System Projects – Quarterly Report – Q3 2012 (retrieved from

http://www.aeso.ca/downloads/2012_Q3_Tx_System_Quarterly_Report_R1.pdf).


186 • Decision 3585-D03-2016 (June 6, 2016)

932. These procurement practices, as required by the AESO pursuant to ISO Rule 9 – Market

Participant – Transmission for material procurement, were audited by the AESO. No

contraventions of ISO Rule 9.1.5 were identified.808

933. The Yellowhead Cherhill project was not addressed by interveners in evidence, nor in

argument and reply.

Commission findings

934. The Yellowhead Cherhill project was completed under budget relative to initial PPS

estimates. This was largely due to the reconciliation of AFUDC. In consideration of the AFUDC

reconciliation and other supporting evidence and submissions of AltaLink’s expenditures on the

Yellowhead Cherhill project, the Commission considers that the requested capital amounts for

2012 and 2013 of $21,159,163 were prudent. AltaLink is authorized to add this amount to its rate

base.

4.2.3.3 D.0108 – SE Development – Brooks Area


935. In the application, AltaLink requested additions to rate base in the amount of

$10.6 million for 2012, which represented the total requested capital additions for the SE

Development project – Brooks project. These costs represented a variance of approximately

$2.7 million in relation to the project cost forecast by AltaLink at the PPS stage.809 AltaLink also

filed its final cost report on October 1, 2012,810 which reported a final cost, excluding salvage, of

$10.6 million for the project.

936. A detailed breakdown of the SE Development Brooks project costs at major stages is

provided in Table 20 below:

Table 18. SE Development project – Brooks Area cost breakdown

PPS

June 5, 2008 +/- 10 update

September 2011 Additions to


Oct 1, 2012(2)




Substation labour 657,000 1,091,379 1,049,015 1,049,014



O: proposal to provide service 30,000 Not provided 200,000 0

O: facility applications 130,000 Not provided 0 100,000

O: land-rights - easements 301,000 Not provided 100,000 100,000


O: land - acquisitions 0 Not provided 0 0

O: ROW Costs Not provided 0 0

Total owner costs 461,000 268,661 277,044 277,044

808





Decision 3585-D03-2016 (June 6, 2016) • 187

PPS

June 5, 2008 +/- 10 update

September 2011 Additions to


Oct 1, 2012(2)


D: project management 803,000 Not provided 1,500,000 1,500,000

D: construction management 357,000 Not provided 400,000 300,000

D: escalation 0 Not provided - -



OT: ES&G 515,000 556,957 432,118 432,972

OT: AFUDC 38,000 454,467 311,734 311,745


Source: Exhibit 0154.00.AML-3585, PPS, PDF page 31; Exhibit 0162.00.AML-3585, Final Cost Report, PDF 2; and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment 2, PDF page 91.

Note: 1) Total project costs do not include salvage. 2) Some numbers may not add up due to differences between exhibits in significant digits used.


937. On July 11, 2008, the Commission approved the NID application of the AESO for the

Southeast Alberta Transmission Development, which considered transmission area

reinforcement proposals prepared by the AESO for the Lethbridge, Brooks, Empress, Vauxhall

and Medicine Hat areas. The NID was approved in Decision U2008-232.811

938. At the direction of the AESO, AltaLink prepared a PPS for the Southeast Area Brooks

project, which estimated costs of $8.0 million and a target ISD of November 2009, assuming

receipt of a P&L by the end of May 2009. The AESO had requested a target ISD of March 1,

2010.812

939. On May 8, 2009, AltaLink filed a facility application for the Southeast Area Brooks

project. The scope of the project included the construction of a new 12.2 km 138-kV

transmission line, alterations to an existing transmission line, the replacement of two

transformers at West Brooks 28S substation and the addition of one new capacitor bank and

circuit breaker at Tilley 498S substation breaker.813 Due to objections from the City of Brooks, an

amendment was filed to the facility application on August 2009. A further amendment was

required to address objections to the proposed new route that had been accepted by the City of

Brooks. This was filed in April 2010.814 The Commission approved the facility application in

Decision 2011-001 on January 6, 2011.


Commission in respect of the Southeast Area Brooks project is in Appendix 4.

811

Need Assessment Approval U2008-232: Alberta Electric System Operator, Southeast Alberta Transmission

Development, Application 1545328-1, July 11, 2008. 812


Decision 2011-001: AltaLink Management Ltd., New 138-kV Transmission Line 666L and Alterations to

Transmission Line 100L, Brooks 121S Substation and West Brooks 28S Substation, Proceeding 220,

Application 1605068-1, January 6, 2011, paragraph 16. 814

Exhibit 3585-X0042, AML-AUC-2015MAR05-032(a), PDF page 435.


188 • Decision 3585-D03-2016 (June 6, 2016)

941. The project was energized in January 2012, two years after forecast, at a total project cost

of $10.7 million (as outlined in the 150-day final cost report).815




Table 19. Project D.0108 key cost variance events


Cost Impact ($)

TCA #2 666L Incremental Scope of Work Longer regulatory process, changes to the Project based on the City of Brooks objections, alignment with Fortis Circuits, expansion of the TWP Road 184, and wetlands.

$ 549,000

TCA #3 Project costs estimated in 2008, but project executed in 2011 Longer regulatory process extended the Project life cycle by one year, escalation in construction, materials, and project management.

$1,310,000

Source: Exhibit 0159.00.AML-3585, AESO change notices.

943. The costs in TCA #2 were included in the amended facility application. No portion of the

costs was assessed against the City of Brooks as the project was approved by the Commission

without an apportionment to the City of Brooks.816

944. Additional variances that were not included in change notices to the AESO were for:

strengthening of screw pile foundations based on soil conditions, extended safety road flagging

due to heavy traffic, additional man hours to accommodate changes along the right-of-way,

access mats, project management and project controls costs due to a longer project timeline, less

land easements and lower actual E&S rates.817

945. In argument, AltaLink noted that the SE Development Brooks project involved a number

of route changes to address stakeholder objections, which delayed the project and resulted in

additional costs. The additional costs for those changes were included in the amended facility

application, which was approved by the Commission. AltaLink argued that it complied with ISO

Rule 9.1.5., and sourced its materials and labour competitively and that it was in regular

communications with the AESO regarding project progress.

946. The SE Development Brooks project was not specifically addressed by interveners in


Commission findings


expenditures on the SE Development Brooks project, and is satisfied with the explanations

provided for the variances observed in respect of this project from initial forecasts costs. The

Commission considers that the requested capital amounts for 2012 and 2013 of $10,621,290

were prudent. AltaLink is authorized to add this amount to its rate base.

815


Exhibit 3585-X0042, AML-AUC-2015MAR05-033(c-d), PDF page 441. 817

Exhibit 3585-X0042, AML-AUC-2015MAR05-032(b), PDF pages 436-437.


Decision 3585-D03-2016 (June 6, 2016) • 189

4.2.3.4 D.0213 – Edmonton Region 240-kV Lines Upgrades


948. In the application, AltaLink requested additions to rate base in the amount of $3.5 million

for 2012 and $5.9 million in 2013 resulting in total requested capital additions of $9.4 million to

the end of 2013. This amount represented a variance of approximately $2.4 million in relation to

the project cost forecast by AltaLink at the PPS stage.818

949. A breakdown of the costs, for the 902L development project, which forms part of the

Edmonton Region line upgrades, is provided in Table 20 below:

Table 20. Edmonton Region 240-kV Transmission Line Upgrades - 902L cost breakdown

PPS

June 30, 2009 Actuals to date

Transmission line materials 1,211,239 1,274,177

Transmission line labour 2,270,884 5,390,460

Substation materials N/A N/A

Substation labour N/A N/A

Telecommunication materials N/A N/A

Telecommunication labour N/A N/A

O: proposal to provide service 71,859 75,444

O: facility applications 177,172 185,261

O: land-rights - easements N/A N/A

O: land-rights – damage claims 56,023 61,278

O: land - acquisitions N/A N/A

O: ROW Costs 0 0

Total owner costs 305,054 321,983

D: procurement 36,882 85,471

D: project management 222,213 530,737

D: construction management 94,369 133,568

D: escalation 331,419 0

D: contingency 535,873 0

Total distributed costs 1,220,756 749,776

OT: ES&G 418,052 266,792

OT: AFUDC 88,899 61,979

Total other costs 506,951 328,771

Total project costs(1) 5,514,884 8,065,167

Source: Exhibit 3585-X0042, AML-AUC-2015MAR05-037(c), PDF page 448. Note: 1) Total project costs do not include salvage.


950. On February 24, 2009, the Commission approved the NID application of the AESO for

the Edmonton Region 240-kV Transmission System Upgrades.819 The AESO amended the NID

application on February 5, 2010 to correct a discrepancy between the single line diagram in the

approved NID and the functional specification.820 The AESO amended the NID again on June 16,

2010 to include additional scope for termination of existing the 240-kV transmission line 909L

818


Need Assessment Approval U2009-62: Alberta Electric System Operator, Edmonton Region 240-kV

Transmission System Updates, Application 1584342-1, February 24, 2009. 820



190 • Decision 3585-D03-2016 (June 6, 2016)

from Keephills 320P substation back to Sundance 310P substation.821 Of the proposed upgrades

included in the NID, only the 902L small conductor replacement project in the Wabamun Lake

area is included in the scope of this proceeding. The remaining scope of the Edmonton Region

240-kV Transmission System Upgrades have either been considered in prior applications or have

not been energized.822 The NID was approved in Decision 2011-340.

951. At the direction of the AESO, AltaLink prepared a PPS for the Edmonton Region

Upgrade project, which estimated total project costs of $101.3 million and a target ISD for the

entire scope of the project of April 2, 2011.823 The project costs for this portion were $5.8 million

including salvage.

952. AltaLink filed a facilities application in August 2011. The scope of the application

included re-stringing approximately four km of 902L out of the Wabamun 19S substation that

was strung with single ACSR 1033 MCM conductors and re-stringing approximately 4.4 km of

902L out of Sundance 310P substation that was currently strung with single ACSR 1033 MCM

conductors.824 The Commission approved the facility application in Decision 2012-293 on

October 31, 2012.


Commission in respect of the scope of this project, is in Appendix 4.

954. The newly restrung 902L was energized on April 15, 2013.825


955. AltaLink indicated that for the entire Edmonton Region 240-kV Upgrades project

“Additions to date are 24% of total project. Variance explanations to be provided when project is

completed.”826

956. In response to an IR, AltaLink clarified the variances for 902L were due to an:

Increase in transmission labour costs, due to higher construction tenders received,

additional access mats requirements for wet ground and prolonged wet weather.

Increase in project management, due to extended project duration.827

957. The 902L project was not specifically addressed by interveners in evidence, nor in

argument and reply.

821





AESO transmission System Projects – Quarterly Report – Q4 2013 (retrieved from

http://www.aeso.ca/downloads/Q4_2013-Transmission_System_Projects_Quarterly_Report.pdf). 826

Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, Tab D.0213. 827

Exhibit 3585-X0042, AML-AUC-2015MAR05-037(c), PDF page 449.


Decision 3585-D03-2016 (June 6, 2016) • 191

Commission findings

958. Consistent with Section 4.1.1 of this decision, the Commission finds that the evidence on

the record was sufficient to enable the Commission to test the costs incurred and reach a

determination regarding the prudence of these costs.

959. There is conflicting cost information between the updated IR response AML-AUC-

2015MAR05-043 Attachment which shows 2012 and 2013 requested capital additions of $9.4

million and the cost breakdown provided in another IR response, which shows actual final costs

for 902L of $8.1 million excluding salvage. AltaLink is directed to provide an explanation for

this variance at the time of its compliance filing.

960. The Commission recognizes that the majority of the costs incurred are as a result of

competitive tendering and accepts AltaLink’s evidence that the costs increased due to higher

labour costs and an increase in the length of time required to complete the project necessitated by

the advent of adverse weather condition. AltaLink is authorized to add the amount of $8,065,167

to its rate base.

961. The Commission may consider a further addition to rate base in 2012/2013 to reflect the

explanation of the discrepancy between the final costs provided in the IR responses at the time of

AltaLink’s compliance filing.

4.2.3.5 D.0238 – Athabasca Area Telecom Development


962. In the application, AltaLink requested additions to rate base in the amount of $15.7

million for 2012 and $0.4 million for 2013828 for total requested capital additions before salvage

of $16.1 million to the end of 2013. This cost was approximately $2.8 million less than the

project cost forecast by AltaLink at the PPS stage. AltaLink filed its final cost report on July 15,

2013,829 which reported a final cost of $17.2 million for the project, excluding salvage, all of

which is attributed to the customer portion.

963. A detailed breakdown of the Athabasca Area Telecom Upgrade project costs at major

stages is provided in Table 21 below:

828




192 • Decision 3585-D03-2016 (June 6, 2016)

Table 21. Athabasca Area Telecom Development cost breakdown

PPS

Mar 3, 2010 +/- 10 update Aug 31, 2012


Final report July 15, 2013(2)

Transmission line materials - - - - Transmission line labour - - - - Substation materials - - - - Substation labour - - -412 -

Telecommunication materials 4,626,000 3,284,558 2,750,689 2,762,116

Telecommunication labour 7,798,000 7,676,630 7,585,048 8,268,340

O: proposal to provide service 30,000 Not provided 300,000 300,000


O: land-rights - easements 100,000 Not provided 0 0

O: land-rights – damage claims 0 Not provided 0 0

O: land - acquisitions 150,000 Not provided 200,000 200,000

O: ROW Costs - Not provided 0 0

Total owner costs 710,000 904,988 1,117,031 1,299,402




D: escalation 500,000 Not provided - -



OT: ES&G 1,054,000 870,000 694,973 707,187

OT: AFUDC 843,000 63,882 63,882 63,882


Source: Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 93. Note: 1) Total project costs do not include salvage.

2) Some numbers may not add up due to differences between exhibits in significant digits used.


964. On January 17, 2012, the Commission approved the NID application of the AESO for the

Athabasca Area Telecommunications Upgrades, which considered telecommunication upgrades

to provide reliable service for substations in the Athabasca area.830 The NID was approved in

Decision 2012-023.

965. At the direction of the AESO, AltaLink prepared a PPS for the project that estimated

costs of $20 million and a forecast ISD of December 31, 2011.831

966. AltaLink filed a facility application in September 2010. The scope of the project included

the construction of new radio sites adjacent to existing substations, construction of new radio

sites, alterations to the associated existing substations and radio sites and the decommissioning

and salvage of the existing telecommunications towers at the certain substations in the Athabasca

area.832 The Commission approved the facility application in Decision 2012-064 on March 8,

2012.

830



Decision 2012-064, paragraphs 5-7.


Decision 3585-D03-2016 (June 6, 2016) • 193


approvals. In Decision DA2012-240,833 the Commission approved a time extension from

September 30, 2012 to December 31, 2012. In Decision DA2013-44,834 the Commission

approved a further time extension from December 31, 2012 to April 30, 2013.


Commission in respect of this project is in Appendix 4.

969. The project was completed in 2013.



initial application evidence are summarized in Table 22 below:


Change report identifier

Description of Trends and Changes Reason or Need

Cost Impact ($)

CP-AFUDC AFUDC Reconciliation (779,118)

Source: Exhibit 0186.00.AML-3585, July monthly progress report, PDF page 460.

971. AltaLink stated that the regulatory process was more complex than anticipated. It

amended its facility application to request a staged approach to the project that would allow eight

of the sites where there were no objections to proceed and then amended the facility application a

second time to propose an alternate site for the Weasel Creek radio site that was acceptable to all

stakeholders. The costs for the delay in approval were offset by a decrease in material costs

compared to the estimate.835

972. In the hearing, Ms. Picard-Thompson clarified that telecommunications projects do not

increase system capacity and as such, do not require a NID application. Ms. Picard-Thompson

indicated that, for telecommunications projects such as this, which are at the direction of the

AESO, AltaLink includes the projects in DACDAs, as opposed to general tariff applications.836

973. The Athabasca Area Telecom Development project was not addressed by interveners in


Commission findings


expenditures on the Athabasca Area Telecom Development project, and is satisfied with the

explanations provided for the variances observed in respect of this project from initial forecasts.

The Commission considers that the requested capital amounts for 2012 and 2013 of $16,056,463

were prudent and AltaLink is authorized to add this amount to its rate base.

833

Decision DA2012-240: AltaLink Management Ltd., Athabasca Area Telecommunications Upgrades, Time

Extension, Proceeding 2076, Application 1608749-1, August 31, 2012. 834

Decision DA2013-44: AltaLink Management Ltd., Athabasca Area Telecommunications Upgrade,

Proceeding 2372, Application 1609223-1, February 12, 2013. 835




194 • Decision 3585-D03-2016 (June 6, 2016)

4.2.3.6 Hanna Region transmission system development projects

975. On August 14, 2009, the AESO applied for approval of the need for transmission system

upgrades in the Hanna region.837 The AESO’s application indicated that it had identified the need

for reinforcements and enhancements of the transmission system in southeastern Alberta in

proximity to the communities of Wainwright, Hardisty, Castor, Provost, Stettler, Drumheller,

Hanna, Monitor, Oyen, Empress, Ware Junction and Brooks, including the AESO transmission

planning areas of Hanna (Area 42), Wainwright (Area 32), Alliance/Battle River (Area 36),

Provost (Area 37), and Sheerness (Area 43).838 In its application, the AESO indicated that its

Hanna region project should be completed in two stages, with the first stage to proceed

immediately, and the second stage to be required by 2017.839 At the time of its application, the

AESO estimated that the cost of its preferred alternative for Stage I projects was $849 million in

2009 dollars, and the cost of its preferred alternative for stage II projects was $157 million in

2009 dollars.840

976. In the executive summary to its Hanna region project NID application, the AESO

indicated that the proposed reinforcements and enhancements would be required because of

significant forecast increases in regional load and significant forecast increases in wind

generation projects.841 The Commission approved the AESO’s Hanna Region project NID

application on April 29, 2010, through the issuance of Decision 2010-188. NID Approval

U2010-135842 was issued on the same date, and provides a summary of the projects identified as

needed in Stage I (identified need in 2012) and Stage II (identified need in 2017). The majority

of the projects identified in NID Approval U2010-135 are located in the service territory of

ATCO Electric.

977. Prior to the anticipated filing of facility applications by ATCO Electric and AltaLink, on

August 4, 2010, the AESO filed Application 1606434-1843 for amendment to NID Approval

U2010-135. All of the proposed amendments related to projects expected to be part of Stage I of

the Hanna Region project, and the majority related to projects assigned to ATCO Electric. The

Commission approved Application 1606434-1 on December 17, 2010 through the issuance of

Decision 2010-592. NID Approval U2010-435 was issued on the same date, thereby causing

NID Approval U2010-135 to be rescinded.

978. On September 1, 2010, the AESO filed applications to amend portion of each of the

SATR NID and Hanna NID approvals. On March 15, 2011, the AESO’s application for

amendment of the Hanna NID approval was approved with the issuance of Decision 2011-102.

On June 7, 2011, the Commission approved NID Approval 2011-114 as Appendix 1 to that

decision, rescinding NID Approval U2010-435.844

837

Application 1605359. 838





Need Identification Document Approval U2010-135: Appendix E to Decision 2010-188, Alberta Electric

System Operator, Hanna Region Transmission System Development, Proceeding 278, Application 1605359-1,

April 29, 2010. 843

Exhibit 0001.00.AESO-768, Proceeding 768. 844

An errata to Approval 2011-114 (Approval U2011-114 (Errata)) was subsequently issued on June 24, 2011.


Decision 3585-D03-2016 (June 6, 2016) • 195

979. In its current application, AltaLink filed requests for approval for capital additions in

2012 or 2013 in respect of three Hanna region projects assigned to AltaLink, as follows:

Project D.0353 – Hanna Area Transmission – Nilrem

Project D.0354 – Hanna Area Transmission – Hansman Lake

Project D.0355 – Hanna Area Transmission – Ware Junction

980. Project D.0316 – Southern Alberta Transmission Reinforcement 933L In/Out at Ware

Junction 132S was executed with the Hanna -–Ware Junction project845 and will be discussed in

that subsection.

981. Concerns regarding the transmission line design of the Hanna Area Transmission

projects were raised by the CCA in evidence, argument and reply. These concerns were

addressed in the common matters – line optimization and design issues section of this decision

(Section 4.1.16).

982. The RPG raised concerns regarding AltaLink’s use of helicopters on both the Nilrem

and Hansman Lake projects. The use of helicopters for these two projects is addressed below.

Findings specific to each Hanna project are discussed in sections 4.2.3.6.1 through 4.2.3.6.3 that

follow.

Use of helicopters

983. The RPG observed several significant inconsistencies in the cost comparisons between

the Nilrem and Hansman Lake projects. For both of these projects, the cost comparisons in the

financial analysis showed that one-third of the tower erection work using cranes was done in

Phase 1 (Hansman – “item 5,” Nilrem – “item 4”). The RPG totalled the costs for both projects

for Phase 1 crane costs and phase 2 crane costs and indicated that Hansman Lake appeared to

have an approximate 50/50 ratio between Phase 1 and 2 costs, while Nilrem appeared to have

two-thirds of the costs in Phase 1 and one-third in Phase 2 (the opposite ratios of the work being

done).

984. The RPG also maintained that the unit price comparison for Hansman Lake showed

nearly identical crane costs in Phase 1 and Phase 2 for line items 1 to 4 (i.e., specific tower site

grading as specified by contractor, construction access road, mob assembly/erection, and demob

assembly/erection). The only difference in crane costs between Phase 1 and 2 was for line item

5 (i.e., on-site assembly). Similarly, for the Nilrem project, there were identical crane costs

between Phase 1 and 2 for line items 2 and 3 (i.e., mob assembly/erection and demob

assembly/erection).

985. The RPG stated that given AltaLink has claimed that the scope of each phase, when

using cranes, was significantly different, one would expect to see these scope differences

reflected in the costs between Phase 1 and 2 but that was not the case. The RPG also expressed

concerns with certain costs in Phase 1 and 2 for both projects, as they appeared to have just

been copied from either column instead of thoroughly investigated. Without an accurate picture

of unit prices for different category of costs between Phase 1 and Phase 2, the RPG suggested it

was impossible to do a proper comparison of crane versus helicopter costs.

845



196 • Decision 3585-D03-2016 (June 6, 2016)

986. Additionally, with respect to the cost comparison for the Hansman Lake project, the

RPG maintained the cost of site-specific grading (line item 1 in the cost comparison) was not

justified by any description given by AltaLink and required further examination. Furthermore,

the cost of constructing an access road for a crane is shown to be in excess of six times the cost

of constructing an access road when using helicopters, however no explanation was given by

AltaLink. This appeared to be unusually high to the RPG, given that much of the material and

labour would need to be brought by vehicle in any case (even with the use of a helicopter). The

RPG found it unlikely that the weight of a crane cannot be accommodated in the same way as

other materials in this project that are brought in by vehicle, or that making an access road

accessible for a crane requires over six times more in the way of costs.

987. In response, AltaLink stated the decision to utilize helicopters for the erection of the

tangent structures on the Hansman Lake and Nilrem projects was based on sound engineering

judgement, including:

Performing an estimate of the costs/ benefits of helicopter erection during the planning

phase on these projects.

Competitively bidding helicopter erection as part of the lines construction per ISO

Rule 9.1.5 and, in doing so, the lowest compliant bidder chose to utilize helicopters. It is,

therefore, indisputable that this was the lowest cost solution.

Including the use of helicopters as part of its overall construction mitigation strategy to

respond to AESRD and landowners concerns regarding the effect of construction

activities on the sand dunes, areas of thin top soil, and areas at risk of erosion due to

disturbance.

988. With regard to this latter concern, AltaLink explained that contrary to the RPG’s

information response in RPG-AML-2015SEP24-016 that virtually all of Alberta is “flat

accessible land,” the Nilrem and Hansman Lake projects had combinations of steep and uneven

terrain and environmentally sensitive areas such as sand dunes, areas with a thin layer of

topsoil, and areas subject to a high risk of erosion, following disturbance. AltaLink also

provided figures to illustrate some of the steep and uneven terrain and sand dunes along the

right-of-way.

989. AltaLink indicated that during the consultation phase of Hansman Lake and Nilrem, the

sand dunes, areas of thin topsoil, and areas subject to a high risk of erosion were identified by

AESRD and landowners to be environmental concerns, requiring mitigation during

construction. Helicopter erection of the tangent towers formed part of AltaLink’s overall

environmental and access risk mitigation strategy. AltaLink also explained that contrary to the

RPG’s statements in its information response RPG-AML-2015SEP24-015, traversing a 165 ton

crane down the right-of-way in these conditions posed a number of real world challenges and

issues.

990. Further, AltaLink submitted, the use of helicopters and assembly yards allowed

construction activities to proceed on Hansman Lake and Nilrem through environmentally

sensitive windows such as bird nesting season, wet conditions, SRB and AESRD land

acquisition processes that were still progressing through their respective processes and despite

land agreements still being negotiated.


Decision 3585-D03-2016 (June 6, 2016) • 197

Commission findings

Use of helicopters

991. The Commission has reviewed the cost comparison analyses between the use of

helicopter versus crane provided by AltaLink and has no concerns. In the Commission’s view,

the RPG failed to consider how the incurrence of lump sum costs (i.e. such as mobilization and

demobilization, grading, access etc.) can affect the allocation of total costs between periods. For

example, in the case of the Nilrem project the crane option represented a $1.8 million

expenditure in Phase 1 for ROW and site preparation, while only one-third of the actual erection

was to take place in Phase 1. Although this would affect the allocation of costs into period 1, the

allocation is reasonable because site preparation would necessarily take place at the beginning

of the project, irrespective of the time period in which the actual erection was scheduled to take

place.

992. Similarly, in both the Hansman Lake and Nilrem projects, the Commission notes that the

costs incurred for mobilization and demobilization, grading and access, were a lump sum and

spread evenly over the two phases, irrespective of when tower erection was scheduled to take

place.

993. In addition to the costs comparison provided with respect to the Nilrem and Hansman

Lake projects, the Commission also accepts AltaLink’s evidence that these projects had a

combination of steep and uneven terrain as well as environmentally sensitive areas, and areas

subject to a high risk of erosion following disturbance. The Commission is satisfied that all

these factors justified the use of helicopters and adequately address the RPG’s concern with

unnecessary helicopter use.

994. Given the above evidence, the Commission considers AltaLink’s expenditures on

helicopters for these two projects, to be reasonable and they are approved.

4.2.3.6.1 D.0353 – Hanna Area Transmission – Nilrem

4.2.3.6.1.1 Recovery requested


for 2012 and $89.6 million in 2013 for a total requested capital addition Hanna –Nilrem of

$93.1 million to the end of 2013. This cost was approximately $16.6 million more than the

project cost forecast by AltaLink at the PPS stage.846 AltaLink filed its final cost report on

December 1, 2014,847 which reported a final cost, excluding salvage, of $96.3 million for the

project.

846


Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 324.


198 • Decision 3585-D03-2016 (June 6, 2016)

996. A detailed breakdown of the Hanna-Nilrem project costs at major stages is provided in

Table 23 below:

Table 23. Hanna Regional Transmission Development (HRTD) Nilrem cost breakdown

PPS

Jan 5, 2010 +/- 10 update Jan 11, 2013


Final report Dec 1, 2014(2)







O: proposal to provide service 95,000 180,000 100,000 100,000

O: facility applications 551,000 2,068,000 2,200,000 2,200,000

O: land-rights - easements 2,375,000 1,761,000 1,700,000 1,900,000

O: land-rights – damage claims 0 33,000 0 200,000

O: land - acquisitions 220,000 836,000 700,000 700,000

O: ROW Costs 0 0 0 0


D: procurement 395,000 1,112,000 1,000,000 1,600,000

D: project management 3,062,000 4,307,000 5,500,000 6,100,000

D: construction management 1,110,000 2,429,000 1,900,000 4,700,000

D: escalation 2,299,000 560,000 0 0

D: contingency 7,209,000 3,752,000 0 0


OT: ES&G 4,042,000 3,708,000 3,077,333 3,020,121

OT: AFUDC 2,756,000 78,000 78,276 78,278

Total other costs 6,798,000 3,726,000 3,155,609 3,098,399


Source: Exhibit 0052.00.AML-3585, PDF page 32; Exhibit 0060.00.AML-3585, PDF page 3; Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 324; Exhibit 3585-X0043, AML-AUC-2015MAR05-042; and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment 2, PDF page 96. Note: 1) Total project costs do not include salvage. 2) Some numbers may not add up due to differences between exhibits in significant digits used.

4.2.3.6.1.2 Project overview

997. AltaLink filed a facility application for Hanna-Nilrem in November 2010. The scope of

the project included the construction of a new 240/138-kV Nilrem 574S substation, construction

of a new double-circuit 240-kV transmission line 953L/1047L, construction of a new double-

circuit 138-kV transmission line 679L/680L, alteration of existing 240-kV transmission line

953L and alteration of existing Tucuman 478S substation.

998. At the time of the facility application, the existing AltaLink 240-kV transmission line

953L connected ATCO Electric’s 240-kV transmission line 9L953 with Hansman Lake 650S

substation. After the proposed 240-kV transmission line 953L/1047L was connected to the

existing transmission line 953L, the portion of existing transmission line 953L from the

connection point east to Hansman Lake 650S substation would be renamed as line 1047. The

portion from the connection point west to ATCO Electric’s transmission line would remain as

953L.848

848

Decision 2011-445, paragraphs 20-21.


Decision 3585-D03-2016 (June 6, 2016) • 199

999. An amendment was filed to the facility application on June 2, 2011, to increase the

height of the proposed structures and to reconfigure the double circuit line crossing of existing

line 948L, where the proposed line would connect to existing line 953L, which required a

slightly larger right-of-way.849

1000. On November 10, 2011, the Commission approved the facility application in Decision

2011-445. The application approved an amended route for the 240-kV transmission line

(953L/1047L) which combined the preferred and alternate routes submitted by AltaLink.850

1001. In a separate facility application, AltaLink proposed the addition of one 138-kV 27-

MVAR capacitor bank and one 138-kV circuit breaker to the Hardisty 377S substation.851 This

application was approved by the Commission in Decision 2011-191 in May 2011.

1002. In Decision 2012-358, the Commission approved a facility application in respect of

proposed alterations to approved transmission lines 953L and 1047L to amend the location of

one structure, adjust the approved route within one quarter section, remove one dead-end

structure within the substation property and expand the Nilrem 574S substation to accommodate

maintenance activities.852

1003. In conjunction with Decision 2011-191 and Decision 2011-445, the Commission issued

a number of P&Ls or approvals. In Decision DA2012-12,853 the Commission approved a time

extension in respect of approved alterations to Hardisty 377S substation from January 31, 2012

to December 31, 2012.854 In Decision DA2013-161,855 the Commission approved a time

extension in respect of approved alterations to Nilrem 574S and Tucuman 478S substations, and

approved new transmission lines 679L, 680L, 953L and 1047L from July 31, 2013 to

November 30, 2013.856


Commission in respect of Hanna-Nilrem, is in Appendix 4.

1005. At the time of the PPS, the target in-service date for this project was July 30, 2011.857

The capacitor bank portion of the project was energized in June 2012 and the substation and

transmission lines were energized in August 2013.858

849





Decision DA2012-12: AltaLink Management Ltd., Alter Hardistry 377S Substation, Proceeding 1671,

Application 1608066-1, January 23, 2012. 854

Permit and Licence U2011-86 and U2012-26. 855

Decision DA2013-161: AltaLink Management Ltd., Time Extension for Milrem Transmission Project

Approvals, Proceeding 2688, Application 1609721-1, July 17, 2013. 856

Decision DA2013-161, AltaLink Management Ltd., Time Extension for Nilrem Project Approvals,

Application 1609721, Proceeding 2688, July 17, 2013. 857




200 • Decision 3585-D03-2016 (June 6, 2016)

4.2.3.6.1.3 Key project variances





Cost Impact ($)

TCA #1 More lengthy consultation process than expected due to recent involvement of landowner association in the area such as CAEPLA and the need to add a second round of landowner consultation.

4,787,000

TCA#2 Early land compensation package for landowner located on the preferred 240-kV line route.

368,000

TCA#6 Swap location for one new 138-kV tie-bus switch at the request of Fortis/AESO.

51,000

TCA#7/8 This change has occurred as a consequence of the recent AUC Decision on the Nilrem Project dated Nov 10, 2011. Designs will have to be developed for the alternate route problems, this will affect schedule and have a financial impact.

4,532,854

CP-AFUDC AFUDC Reconciliation (5,448,263)

CP#10 Updated Service Proposal +/-10% Estimate on 15-Jan-13 and meeting with the AESO on 22-Jan-13. CN submitted on February 8, 2013. Approved on May 7, 2013.

13,086,000

Source: Exhibit 0048.00.AML-3585, September 2014 monthly report; and Exhibit 0058.00.AML-3585, AESO change notices.

1007. The costs in TCAs #7 and #8 were as a result of the amended route approved in the

facility application. As compared to the AltaLink’s preferred route, the approved route was

two km shorter, required four less light angle structures, one less heavy angle structure, one more

light dead-end structure, four fewer heavy dead-end structures and two less tangent steel H-frame

structures, 2.4 km of additional brushing or clearing, additional length of line in environmentally

sensitive areas, crossed more native vegetation and sensitive wetland, and was supported by

fewer stakeholders.859

1008. AltaLink explained that the contingency estimate in the PPS was not drawn down as a

result of the Commission’s decision because the possibility of the preferred route not being

approved and the delay of P&L beyond the stated date in the PPS was not contemplated when

the PPS was developed.860

1009. In the facility decision, Decision 2011-445, the Commission stated that “Any difference

in the cost of the Commission approved route compared to the cost of the preferred route must

take into account that approximately 35 per cent of the approved route is part of the preferred

route and that there are fewer 90 degree dead-end structures required.”861

1010. In its change notice to the AESO, AltaLink stated that the Commission did take into

consideration the extended project duration, that some material (the 90-degree dead-end towers)

859

Exhibit 0058.00.AML-3585, change notice #7/8, PDF pages 22-23. 860

Exhibit 0058.00.AML-3585, change notice #7/8, PDF page 28. 861



Decision 3585-D03-2016 (June 6, 2016) • 201

is unique to the preferred route and already fabricated and in transit to storage facilities, which

cannot be re-allocated to another project.862 The change notice cost breakdown was as follows:

$1,872,797 transmission line labour863

$84,000 land rights – easements

$69,891 procurement

$1,301,725 project management

$348,440 construction management

$856,000 contingency864

1011. The change notice also stated that the construction duration was anticipated to extend to

13 months from six, due to construction of the 138-kV line and the new Nilrem substation

beginning in March 2012 and the 240-kV beginning in October 2012.865

1012. AltaLink submitted an additional change notice to the AESO on September 15, 2013 for

$8.2 million to “cover multiple cost increase from +/-10% until the end of construction.” It

indicated that the increases were due to labour escalations due to labour market conditions,

unseasonably wet right-of-way conditions and costs required to resolve issues that arose during

construction. This change notice was rejected by the AESO and at its direction, the costs were,

instead, reflected by AltaLink in its final cost report.866

1013. AltaLink drew down a contingency of $7,248,289 for additional funds to offset

transmission and substation labour cost increases related primarily to different soil conditions

and resultant engineering, material handling costs and rig mats.867

1014. In response to an IR, AltaLink provided an estimated breakdown of the increases in

project management and project control costs, which were due to the increased duration of

construction as follows:

$600,000 procurement

$2,400,000 project management

$700,000 construction management868

1015. The AESO audited AltaLink for compliance to its material procurement requirements as

required by ISO Rule 9.1.5. No findings of non-compliance were made.869

1016. The HRTD Nilrem project was energized in August 2013, for a total project cost of $96.3

million (as outlined in the 150-day final cost report).

862


Transmission line labour was further broken out: $566,000 for line engineering and $1,051,000 for

construction costs associated with self-supporting steel poles which is based on actual bids received. 864



Exhibit 0058.00.AML-3585, change notice #16, PDF pages 66-67. 867


Exhibit 3585-X0045, AML-CCA-2015MAR05-015(d)(iv), PDF page 220. 869



202 • Decision 3585-D03-2016 (June 6, 2016)

1017. AltaLink argued that the project cost variances were mainly due to market escalation for

construction services and the approved route, which was a combination of the preferred and

alternate routes which required re-engineering and which was more complex, due to difficult

terrain and environmentally sensitive areas. It further explained that it was in communication

with the AESO throughout the project and the AESO acknowledged or approved all but one

change notice. For the rejected change notice, AltaLink complied with the AESO’s direction to

include the cost in the final costs report.870

1018. Apart from the common matters of line design, and use of helicopters, which are

addressed in separate sections in this decision, the Hanna-Nilrem project was not specifically

addressed by interveners in evidence, nor in argument and reply.

Commission findings


expenditures on the Hanna-Nilrem project, and while the increased cost above the original

estimate is significant, the Commission concludes that the expenditures were reasonable and that

AltaLink acted prudently.

1020. The Commission notes that some of the costs incurred on this project related to materials

that AltaLink procured that were uniquely required for the preferred route, a route that was

subsequently not approved by the Commission. However, AltaLink received direction from the

AESO to acquire the steel required to build the 240-kV towers for the proposed 943UI047L lines

and was required to follow the direction of the AESO to commence early procurement.871 In

these circumstances, the Commission does not find AltaLink to have acted imprudently.

1021. The Commission also notes that the facilities application to the Commission resulted in a

two-thirds change to the 240-kV line route and a lesser change to the 138-kV line route. It is

noted that the facilities application stated that deciding upon a route other than the preferred

route could delay the project by approximately one year. No land agreements were in place and

only preliminary engineering work had been completed on the alternate route directed by the

Commission.

1022. The Commission considers the above factors to explain and mitigate the cost variances

arising in this project. The expenditures on the Hanna-Nilrem project are, therefore, approved as

filed.

4.2.3.6.2 D.0354 – Hanna Area Transmission – Hansman Lake


1023. In the application, AltaLink requested additions to rate base in the amount of $30.6

million for 2012 and $57.2 million in 2013, for a total requested capital additions for Hanna-

Hansman Lake of $87.8 million to the end of 2013. This represented a variance of approximately

$5.4 million in relation to the project cost forecast by AltaLink at the PPS stage.872 AltaLink filed

870


See Section 25.2 of the Transmission Regulation. 872

Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment.


Decision 3585-D03-2016 (June 6, 2016) • 203

its final cost report on December 1, 2014,873 which reported a final cost, excluding salvage, of

$91.6 million for the project.

1024. A detailed breakdown of the Hanna-Hansman Lake project costs at major stages is

provided in Table 25 below:

Table 25. HRTD Hansman Lake cost breakdown

PPS

Feb 9, 2010 +/- 10 update Jan 11, 2013









O: proposal to provide service 75,000 686,000 500,000 1,200,000



O: land-rights – damage claims 0 147,000 200,000 300,000

O: land - acquisitions 0 1,082,000 200,000 200,000



D: procurement 256,000 895,000 1,200,000 1,100,000


D: construction management 595,000 1,492,000 2,000,000 4,000,000

D: escalation 2,100,000 437,000 0 0

D: contingency 7,372,000 6,613,000 0 0


OT: ES&G 4,345,000 3,957,000 2,750,733 2,689,008

OT: AFUDC 8,663,000 64,000 64,949 64,949



Source: Exhibit 0041.00.AML-3585, PDF page 25; Exhibit 0049.00.AML-3585, PDF page 3; Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 322; Exhibit 3585-X0043, AML-AUC-2015MAR05-042; and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment 2, PDF page 97. Note: 1) Total project costs do not include salvage. 2) some numbers may not add up due to differences between exhibits in significant digits used.


1025. In December 2010, AltaLink filed a facilities application for the Hanna-Hansman Lake

project. The scope of the project included the construction of a new double-circuit one side

strung 240-kV transmission line 966L from the Hansman Lake 650S substation to the boundary

of the ATCO Electric service territory and the alteration of existing Hansman Lake 650S

substation.

1026. An amendment was filed to the facility application on October 7, 2011 to make a minor

amendment to the preferred route and AltaLink filed a letter on February 22, 2012 to correct an

error in a land location for temporary construction workspace.874 The Commission approved the

873

Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 326. 874



204 • Decision 3585-D03-2016 (June 6, 2016)

facility application in Decision 2012-120. AltaLink’s preferred route for its portion of the

Hansman Lake transmission line 966L was approved as filed.875

1027. In November 2010, AltaLink filed a separate facility application to make additions to the

existing Hansman Lake 650S substation. The scope of this application included the addition of

one 240-kV static var compensator (SVC) and the addition of two 240-kV circuit breakers.876 The

Commission approved this application in Decision 2011-175 on April 27, 2011.

1028. In Decision DA2012-377, the Commission approved a facility application in respect of

proposed alterations to approved transmission line 966L to adjust the centreline, structures

locations and right-of-way approximately 125 metres to the north in the vicinity of Provost in

order to directly the line to the substation.877

1029. In conjunction with Decision 2011-175 and Decision 2012-120, the Commission issued a

number of P&Ls or approvals.


Commission in respect of the Hanna-Hansman Lake project is in Appendix 4.

1031. At the time of the PPS, the target in-service date for this project was June 30, 2012.878 The

alterations to the Hansman Lake 950S substation project portion were energized in October 2012

and the 966L transmission line was energized in August 2013.879 AltaLink had communicated an

ISD for 966L of June 30, 2012 to the AESO. However, AltaLink had to delay energization to

align with ATCO Electric’s ISD.880




875


Decision 2011-175: AltaLink Management Ltd., Hansman Lake 650S Substation, Metiskow Area,

Proceeding 974, Application 1606802-1, April 27, 2011.paragraph 4. 877






Decision 3585-D03-2016 (June 6, 2016) • 205



Cost Impact ($)

TCA #3 Early land compensation package for landowner located on the preferred 240-kV line route

474,000

TCA#5 Due to late start by AUC to review the Facilities Application (FA) filed early December 2010, AltaLink anticipated at least three months delay with P&L receipt and, therefore, with ISD. Accepted by AESO with respect to ISD change. However, AESO instructed AltaLink to utilize contingency to cover the cost effect ($455,000 of contingency used)

0

TCA#9 SVC ISD change ($100,000 of contingency used) 0



24,750,000

Source: Exhibit 0048.00.AML-3585, September 2014 monthly report; and Exhibit 0047.00.AML-3585, AESO change notices.

1033. The costs in CP#11 were submitted to cover increased costs due to labour market

conditions and an increase in the complexity and scope of right-of-way preparation. AltaLink

stated that it addressed the issues by bidding the construction contracts as per the ISO rules and

selecting the lowest bidder as well as using the winter construction period as much as possible to

minimize the amount of right-of-way preparation required.881

1034. In response to an IR, AltaLink estimated that the increase in costs due to market

escalation from the PPS estimate to the actual bids for transmission line labour and substation

labour were $10.8 million and $1.5 million, respectively.882

1035. In addition to the contingency draw-downs explained in the change notices, AltaLink

drew down further contingency amounts of $3,258,150 over the entire project to offset SVC

delays to energization, and to address different soil conditions that were not known at the time of

the PPS that required material handling costs, foundation extensions and rig mats.883


required by ISO Rule 9.1.5. No findings of non-compliance were made.884

1037. AltaLink submitted the project cost variances were mainly due to market escalation for

construction services and environmental mitigations required to preserve and reclaim the sand

dune and native prairie terrain, and to mitigate disturbances to native prairie proactively as a

priority over reclamation, as directed by the Commission.885 The cost increases due to

environmentally sensitive terrain could not be mitigated by working on frozen terrain as this

would not adequately address the environmental concerns.

1038. AltaLink argued that it was in communication with the AESO regarding delays and cost

increases and the AESO, in two instances, directed AltaLink to draw down contingency funds to

881

Exhibit 0047.00.AML-3585, change notice CP#11, PDF page 26. 882

Exhibit 3585-X0042, AML-AUC-2015MAR05-040(d), PDF page 457. 883



Exhibit 0040.00.AML-3585, PDF pages 3, 4 and 7.


206 • Decision 3585-D03-2016 (June 6, 2016)

cover cost increases. AltaLink also noted that the AESO acknowledged or approved all change

notices.886

1039. Aside from the common matters of line design, and use of helicopters that are addressed

in separate sections above, the Hanna-Hansman Lake project was not specifically addressed by

interveners in evidence, nor in argument and reply.

Commission findings

1040. The majority of the variances that arose in connection with this project related to

expenditures on environmental mitigation costs that were not anticipated in the PPS estimate.

AltaLink had previous experience working in this area and was familiar with the conditions that

would be encountered but indicated that the extent of mitigation could not have been known until

the site was actually accessed. To the extent that these increased expenditures were required by

the Commission and Alberta Environment and Sustainable Resource Development,887 the

Commission considers that these regulatory requirements should be taken into account in its

overall assessment of prudence in this case.


expenditures on the Hanna-Hansman Lake project, and is satisfied with the explanations

provided for variances from the initial project forecast costs and efforts made to mitigate cost

increases. The Commission considers that the requested capital amounts for 2012 and 2013 of

$87,753,471 were prudent. AltaLink is authorized to add this amount to its rate base.

4.2.3.6.3 D.0355 – Hanna Area Transmission – Ware Junction and D.0316 Southern

Alberta Transmission Reinforcement – Ware In/Out


1042. In the application, AltaLink requested the following additions to rate base:

SATR Ware $6.0 million for 2013

HRTD or Hanna Ware $109.8 million for 2013

1043. The total requested capital additions for these projects is $115.8 million to the end of

2013, representing a variance of approximately $31.1 million in relation to the project cost

forecasts by AltaLink at the PPS stage.888

1044. AltaLink filed its final cost report for Hanna Ware on December 1, 2014, which reported

final costs, excluding salvage, of $112.8 million. Its final cost report for SATR Ware was filed

on December 11, 2014 and reported final costs, excluding salvage, of $6.6 million.889

1045. A detailed breakdown of the SATR Ware project costs at major stages is provided in

Table 27 below:

886



Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tabs D.0316 and D.0355. 889

Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF pages 328 and 330.


Decision 3585-D03-2016 (June 6, 2016) • 207

Table 27. SATR Ware cost breakdown

PPS

Sept 29, 2010 +/- 10 update Jan 11, 2013




Transmission line labour 172,000 187,000 186,204 229,126





O: proposal to provide service 60,000 9,000 Not available Not available

O: facility applications 50,000 15,000 Not available Not available

O: land-rights - easements 20,000 57,000 100,000 100,000

O: land-rights – damage claims 10,000 0 Not available Not available

O: land - acquisitions 0 56,000 100,000 100,000



D: procurement 132,000 198,000 300,000 200,000

D: project management 497,000 1,288,000 700,000 900,000

D: construction management 289,000 302,000 100,000 700,000

D: escalation 0 72,000 0 0

D: contingency 812,000 362,000 0 0


OT: ES&G 327,000 289,000 163,809 161,395

OT: AFUDC 466,000 1,000 1,032 1,032

Total other costs 793,000 290,000 164,841 162,427


Source: Exhibit 0075.00.AML-3585, PDF page 19; Exhibit 0084.00.AML-3585, PDF page 2; Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 330; Exhibit 3585-X0043, AML-AUC-2015MAR05-042; and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment 2, PDF page 95. Note: 1) Salvage has been removed from total project costs.

2) some numbers may not add up due to differences between exhibits in significant digits used.

1046. A detailed breakdown of the Hanna Ware project costs at major stages is provided in

Table 28 below:

Table 28. HRTD Ware cost breakdown

PPS

Mar 2, 2010 +/- 10 update Jan 11, 2013









O: proposal to provide service 95,000 180,000 100,000 100,000



O: land-rights – damage claims 0 33,000 100,000 100,000

O: land - acquisitions 0 836,000 100,000 100,000



D: procurement 314,000 1,112,000 700,000 600,000


D: construction management 1,182,000 2,429,000 1,000,000 3,000,000

D: escalation 0 560,000 0 0


208 • Decision 3585-D03-2016 (June 6, 2016)

PPS

Mar 2, 2010 +/- 10 update Jan 11, 2013



D: contingency 12,304,000 3,752,000 0 0


OT: ES&G 4,171,000 3,708,000 3,407,323 3,373,012

OT: AFUDC 4,106,000 78,000 23,852 23,852



Source: Exhibit 0064.00.AML-3585, PDF page 25; Exhibit 0072.00.AML-3585, PDF page 3; Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 328; Exhibit 3585-X0043, AML-AUC-2015MAR05-042; and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment 2, PDF page 98. Note: 1) Salvage has been removed from total project costs.

2) Some numbers may not add up due to differences between exhibits in significant digits used.

4.2.3.6.3.2 Projects overview

1047. On September 8, 2009, the Commission approved the NID application of the AESO for

the Southern Alberta Transmission Reinforcement (SATR). Included in this NID application

were three stages of projects required primarily to address constraints in the transmission system

in southern Alberta that would limit the accommodation of new wind generation projects. For

projects included in Stage 2, the Commission approved an AESO proposal involving the

construction of a new 240-kV in-out transmission line at Ware Junction 132S substation.890

1048. On August 14, 2009, the Commission approve the need for transmission system upgrades

in the Hanna region, which included a new 240-kV transmission line from Ware Junction 132S

substation to West Brooks 28S substation in Stage 1 of the proposed HRTD project. These

projects were also primarily required to address constraints in the transmission system in central

east Alberta that would limit the accommodation of new generation projects.891

1049. In Decision 2011-102, the Commission approved the AESO’s amended HRTD and

SATR NID applications, which revised the termination of the new 240-kV transmission line

from Ware Junction 132S substation to the new Cassils 324S substation (instead of West Brooks

28S substation which could not accommodate the proposed expansion).892

1050. In April 2011, AltaLink filed a facilities application in which it combined the scope of

work for the Hanna Ware project with that of the SATR Ware project. The combined scope

included the:

Construction of a new single-circuit 240-kV transmission line 1053L single-side strung

on double circuit structures from the existing Ware Junction 132S substation to Cassils

324S substation.

Addition of one 240-kV circuit breaker and associated substation equipment to the

Cassils 324S substation.

Addition of eight 240-kV circuit breakers and associated substation equipment to the

Ware Junction 132S substation.

890



Decision 2011-102, PDF page 7.


Decision 3585-D03-2016 (June 6, 2016) • 209

Reconfiguration of a portion of existing double-circuit 240-kV transmission lines

931L/933L to two single-circuit transmission lines to provide adequate clearance to

accommodate crossing by the new 240-kV line.

Re-termination of existing 240-kV transmission lines 931L, 944L and 951L in Ware

Junction 132S substation and

Alteration of the existing transmission line 933L by terminating it at Ware Junction 132S

substation and renaming the portion of the transmission line from West Brooks 28S

substation to Ware Junction 132S substation as 1075L.893

1051. The Commission approved the facility application in Decision 2012-043 on February 6,

2012.

1052. In Decision 2012-230, the Commission approved alterations to approved transmission

line 1053L to adjust the centreline to avoid existing facilities and alterations to approved

structures to use 240-kV dead-end single pole structures to ensure adequate space for the

approved configuration at Ware Junction 132S substation and for crossings with another

transmission line.894

1053. In Decision DA2013-83,895 the Commission approved a facility application in respect of

proposed alterations to approved transmission line 1053L to adjust the route in certain locations

to avoid existing infrastructure.

1054. In conjunction with decisions 2012-043 and 2012-230, the Commission issued a number

of P&Ls or approvals. In Decision DA2013-97,896 the Commission approved a time extension

from March 31, 2013 to December 31, 2013.


Commission in respect of Hanna Ware and SATR Ware is in Appendix 4.

1056. At the time of the PPS, the target in-service date for SATR Ware was December 15,

2012897 and the target ISD for Hanna Ware was June 30, 2012.898 The SATR Ware project was

energized October 2013 and the Hanna Ware project was energized in stages with final

energization occurring in November 2013.899


1057. The key trends and changes that drove the projects’ cost variances as set out in

AltaLink’s initial application evidence, are summarized in Table 29 below:

893

Decision 2012-043: AltaLink Management Ltd., Cassils to Ware Junction 240-kV Transmission Line,

Proceeding 1150, Application 1607171-1, February 6, 2012, paragraph 13. 894

Decision 2012-230: AltaLink Management Ltd., Amendments to Permits and Licences for Cassils to Ware

Junction 240-kV Transmission Facilities, Proceeding 1992, Application 1608604-1, August 28, 2012,

paragraphs 9 and 11. 895

Decision DA2013-83: AltaLink Management Ltd. Amendments to Transmission Line 1053L, Application

Proceeding 2485, 1609376-1, March 25, 2013. 896

Decision DA2013-97: AltaLink Management Ltd., Cassils to Ware Junction Project Time Extension,

Proceeding 2515, Application 1609420-1, April 9, 2013. 897





210 • Decision 3585-D03-2016 (June 6, 2016)

Table 29. Key cost variance events

Project Change report identifier Reason or Need

Cost Impact ($)

D.0316 CP-AFUDC AFUDC Reconciliation (466,000)

CP#2a and b +/-10% service proposal Reconciliation – ISD change related costs 939,000

D.0355 TCA#4 1.) Upgrade existing 240-kV breaker termination rather than replacing complete breaker unit. 2.) Early land compensation package for landowner located on the preferred 240 kV

(1,419,000)



35,879,000

Source: Exhibit 0083.00.AML-3585, August 2014 monthly report; Exhibit 0082.00.AML-3585, AESO change notices; Exhibit 0048.00.AML-3585, September 2014 monthly report; and Exhibit 0070.00.AML-3585, AESO change notices.

1058. CP#2a was submitted to change the ISD from September 1, 2013 to November 15, 2013

and to cover the costs associated with the delay ($553,787). The delay was explained as “being

on the availability of outages.”900

1059. CP#2b, in the amount of $385,213, was submitted to account for increased project costs

due to market conditions (largely to the substation labour costs).901

1060. In response to an IR, AltaLink indicated that the outage difficulties that could affect the

ISDs for SATR Ware and Hanna Ware were first presented to the AESO in December 2011.

AltaLink coordinated with its EPC contractor, the AESO, and Sheerness/ATCO Electric to

develop a nine-phase outage plan that was finalized in January 2013. The plan addressed the

complexities associated with seventeen outages in eight stages spanning five months and was

executed between July 2013 and November 2013.902

1061. Further complicating the outage scheduling was the ongoing work on EATL, which

parallels 1053L and then crosses over existing lines and 1053L at the converter station. This

required structures to be flattened which, in turn, required outages. Ms. Picard-Thompson stated

that AltaLink could not have known of the timing of outages and the complexity of the project at

the time of preparing the PPS estimate.903

1062. The costs in CP#12 were submitted to explain increased costs due to labour market

conditions and the increase in complexity and scope of right-of-way preparation. AltaLink stated

that it addressed the issues by bidding the construction contracts as per the ISO rules and

selecting the lowest bidder as well as using the winter construction period as much as possible to

minimize the amount of right-of-way preparation required.904

900

Exhibit 0082.00.AML-3585, change notice CP#2a, PDF pages 6, 7 and 10. 901

Exhibit 0082.00.AML-3585, change notice CP#2b, PDF pages 11, 12 and 14. 902

Exhibit 3585-X0045, AML-CCA-2015MAR05-023(b), PDF page 252. 903


Exhibit 0070.00.AML-3585, change notice CP#12, PDF page 15.


Decision 3585-D03-2016 (June 6, 2016) • 211

1063. In response to an IR, AltaLink identified $25.2 million in construction labour escalation

for the HRTD Ware project.905

1064. AltaLink submitted a change notice to the AESO on November 14, 2013, for $1,361,330

to cover costs associated with coordination of work with the East HVDC converter station

interface. Specifically, these costs related to the work to flatten structures on 933L, 931L and

1053L to avoid duplication of work and salvage of newly installed structures. The AESO

rejected this change notice and directed that these costs be reflected in the final cost report.906

1065. The contingency draw down of $7,195,731 for the entire HRTD Ware project was for

additional funds required to offset transmission and substation labour cost increases related to

primarily to line route change, different soil conditions that were not known at the time of the

PPS and resultant material handling costs, foundation extensions, implodes and rig mats

materials.907


required by ISO Rule 9.1.5. In the procurement report attached to Hanna Ware, AltaLink

identified $1,883,200 worth of contracts that were sole-sourced, out of a total value of contracts

of $93,302,410. No contracts were sole-sourced for SATR Ware.908 The AESO did not identify

any contraventions.909

1067. AltaLink explained that the project cost variances were principally the result of market

escalation, complex outage planning, additional right-of-way preparation and mitigation of

environmental concerns related to extensive wetlands along the route. AltaLink argued that it

was directed by the Commission to mitigate all environmentally sensitive areas along the route,

the challenges of which were compounded by unseasonably wet conditions that required

extensive matting and additional soil and erosion controls measures. AltaLink argued further that

it was in communication with the AESO throughout the project and the AESO acknowledged or

approved all but one change notice.910

1068. Aside from the common matters of line design, use of rig mats and use of helicopters,

which are addressed in separate sections above, the HRTD Ware Junction project was not

specifically addressed by interveners in evidence, nor in argument and reply. The SATR Ware

project was not addressed by interveners in evidence, argument or reply.

Commission findings

1069. The majority of the variances that arose in connection with this project related to

expenditures with respect to labour costs that were not anticipated in the PPS estimate. There

was a delay of around two years between the time of preparing the PPS and construction, during

which time the labour market in Alberta changed.911

905

Exhibit 3585-X0045, AML-CCA-2015MAR05-008(d), PDF page 190. 906

Exhibit 0070.00.AML-3585,cChange notice #15, PDF pages 20 and 22. 907


Exhibit 3585-X0042, AML-AUC-2015MAR05-010Attachment 1, PDF pages 329 and 331. 909





212 • Decision 3585-D03-2016 (June 6, 2016)

1070. AltaLink was in communication with the AESO throughout the project and the AESO

would have been aware of cost increases on the project. There is no evidence that the AESO at

any time, expressed concern with the projects’ costs or directed AltaLink to suspend or halt work

on the projects. AltaLink is required to construct projects directed by the AESO and works

towards meeting the AESO’s expected ISD. The actual costs reflected the costs of labour in the

Alberta market at that time. The evidence shows that AltaLink competitively tendered the

overwhelming majority of contracts in compliance with ISO Rule 9.1.5.

1071. An additional driver of project cost increases was the complexity of outages, which

needed to be managed. The Commission accepts AltaLink’s statement that this was one of the

most complex projects executed up to that time in respect of construction staging to manage

outages.912 The Commission is satisfied with the explanations provided for variances associated

with coordinating outages for the projects. Given these facts, the Commission considers the

actions of AltaLink to be reasonable in the execution of these projects.


expenditures on the SATR Ware and Hanna Ware projects, and is satisfied that the explanations

provided for variances from the initial project forecast costs are reasonable. Accordingly, the

Commission approves the 2013 capital additions of $6,027,657 and $109,848,153 for SATR

Ware and Hanna Ware, respectively for inclusion in rate base.

4.2.3.7 D.0377 – Christina Lake Area Development – Black Spruce 154S


1073. In the application, AltaLink requested additions to rate base for the Christina Lake Area

development – Black Spruce 154S in the amount of $27.5 million in 2013, representing a

variance of approximately $7.6 million in relation to the project cost forecast by AltaLink at the

PPS stage.913 AltaLink filed its final cost report on December 18, 2013,914 which reported a final

cost, excluding salvage, of $31.1 million for the project.

1074. A detailed breakdown of the Black Spruce 154S project costs at major stages, is provided

in Table 30 below:

Table 30. Christina Lake – Black Spruce 154S cost breakdown

PPS

June 11, 2012 +/- 10% update June 21, 2013


Final Cost report Dec 18, 2013(2)


Transmission line labour 686,000 2,364,000 1,829,679 1,902,106





912





Decision 3585-D03-2016 (June 6, 2016) • 213

PPS

June 11, 2012 +/- 10% update June 21, 2013



O: proposal to provide service 317,000 327,000 300,000 not provided

O: facility applications 532,000 351,000 300,000 not provided

O: land-rights - easements 50,000 51,000 0 not provided

O: land-rights – damage claims 25,000 24,000 0 not provided

O: land - acquisitions 30,000 29,000 0 not provided

O: ROW Costs 0 0 0 not provided


D: procurement 279,000 339,000 500,000 500,000


D: construction management 367,000 414,000 800,000 1,300,000

D: escalation 860,000 230,000 - -

D: contingency 2,298,000 798,000 - 1,000,000


OT: ES&G 1,080,000 1,463,000 905,126 983,245

OT: AFUDC 0 106

Total project costs(1) 19,919,000 29,857,000 27,471,452 31,067,587 Source: Exhibit 0008.00.AML-3585, PDF page 23; Exhibit 0015.00.AML-3585, PDF page 2; Exhibit 0016.00.AML-3585, PDF page 2; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 100.

Note: 1) Salvage has been removed from total project costs. 2) some numbers may not add up due to differences between exhibits in significant digits used.


1075. On October 20, 2011, the AESO submitted a NID application915 in respect of a 240-kV

system development in the Christina Lake area, located south of the City of Fort McMurray and

Northeast of the town of Lac La Biche. In the NID application, the AESO indicated that it had

received several requests for system access in the Christina Lake area with varying ISD

requirements starting as early as 2012. Based on such requests and the AESO long-term forecasts

for load and generation growth in the area, the AESO proposed a transmission system expansion

to serve the forecast demand by providing transmission access for current customer connections,

providing transmission capacity to meet near and long-term forecast load and generation growth,

resolving voltage issues on the 138-kV transmission network, and reinforce the existing 240-kV

transmission network.916

1076. The AESO’s proposed Christina Lake transmission development plan provided that the

Christina Lake system development should occur in three phases, to be completed between 2013

and 2015. The key elements of the phased developments proposed by the AESO are summarized

in Table 31 below:

915

Exhibit 0009.00.AML-3585, Proceeding 1518, Application 1607795-1. 916



214 • Decision 3585-D03-2016 (June 6, 2016)

Table 31. Christina Lake Development Phases and NID stage cost estimates

Phase / Project Name

Forecast ISD Target at NID Project Elements

NID Forecast

($ million)

Phase 1 Black Spruce 154S

Q2 2013

a new 240 kV switching substation (Black Spruce 154S substation) located between the existing Christina Lake 723S and Conklin 762S substation and near to the existing 971L transmission line

25

Phase 2 Pike 170S and associated transmission lines

Q2 2014

a new 240/138-kV substation (Pike 170S substation) to connect the future loads in the central Christina Lake area

a new 30 km double circuit, single side strung 240-kV transmission line (1115L) between the Black Spruce 154S substation and the new Pike 170S substation

105

Phase 3 Ipiatik Lake 167S and associated transmission lines

Q2 2015

a new 240/138-kV Ipiatik Lake 167S substation

a new double-circuit, single side strung, 240-kV transmission line (1116L) of approximately 30 km in length between the new Pike 170S substation and the new Ipiatik Lake 167S substation

a new double-circuit, single side strung, 240-kV transmission line (1117L) of approximately 60 km in length between the existing Heart Lake 898S substation and the new Ipiatik Lake 167S substation

addition of 138-kV transmission lines to connect existing Winefred 818S substation and Kirby 651S substation to Ipiatik Lake 167S substation

alterations to the Christina Lake 723S substation

266

Phase 3 Heart lake 898S

Q2 2015 a project (assigned to ATCO Electric Ltd) to connect transmission line 1117L inside of ATCO Electric’s Heart Lake 898S substation

12

Source: Exhibit 0009.00.AML-3585, PDF pages 8 -10 and 15-17.

1077. Phase 1, Black Spruce 154S, is the component of the Christina Lake Area Development

Plan included in this application.917

1078. The Commission approved the NID on April 24, 2012 in Decision 2012-112.918

1079. At the direction of the AESO, AltaLink prepared a PPS for the Black Spruce 154S

project, which estimated costs of $20 million and a forecast ISD of June 28, 2013.919

1080. AltaLink filed a facility application on July 23, 2012. The scope of the project included:

Construction of a new 240-kV switching station, Black Spruce 154S.

Construction of approximately 150 metres each of two new single-circuit 240-kV

transmission line to the proposed Black Spruce 154S substation (971L/1099L).

Alteration of the existing 971L transmission line to facilitate interconnection of the

proposed in/out 971L/1099L.

917


Decision 2012-112: Alberta Electric System Operator, Christina Lake Area 240-kV Transmission System

Development Needs Identification Document, Proceeding 1518, Application 1607795-1, April 24, 2012. 919



Decision 3585-D03-2016 (June 6, 2016) • 215

Renumber a portion of the line from the Jackfish 698S substation to the proposed Black

Spruce 154S substation as 1099L.920

1081. The Commission approved the facility application on December 24, 2012, in Decision

2012-356.921 A table listing the proceedings, decisions and associated approvals for project

D.0377 (Black Spruce 154S) is in Appendix 4.

1082. The Sunday Creek 539S connection project NID (AltaLink project D.0407, discussed in

Section 4.3.2.1 below) was also approved in Decision 2012-356. Completion of the Black Spruce

154S project was required to allow the Sunday Creek 539S substation to connect to the Alberta

electric system.

1083. The project was energized on July 23, 2013.922


1084. The key trends and changes that drove the projects’ cost variances as set out in




Cost Impact ($)

CP#2 Geotechnical Survey and Report Variance in PPS Budget to Actual Costs

41,000

CP#3 Brushing and Clearing Contract Variance in PPS Budget to Actual Costs

128,000

CP#4 Civil Contract Variance in PPS Budget to Actual Costs

3,783,000

CP#5 Screw Piles Contract Variance in PPS Budget to Actual Costs

901,000

CP#6 Electrical, P&C, SCADA(1) and Telecom Contract Variance in PPS Budget to Actual Costs

2,339,000

CP#7 Lines Installation Contract Variance in PPS Budget to Actual Costs

676,000

CP#8 Telecom Installation Contract Variance in PPS Budget to Actual Costs

186,000

CP#9 Access Mats for In/Out within ROW Scope Change required for work to be completed within ROW above a pipeline

1,128,000

CP#10 Substation Materials cost Variance Variance in PPS Budget to Actual Costs

1,852,000

CP#11 Station Service Transformer Required to add back up redundancy to station, distribution solution was cost prohibitive.

737,000

Source: Exhibit 0014.00.AML-3585, PDF page 204 and Exhibit 0013.00.AML-3585, AESO change notices. Note (1) Supervisory control and data acquisition.

920


Decision 2012-356: Alberta Electric System Operator, Sunday Creek 539S Substation Interconnection Needs

Identification Document; AltaLink Management Ltd., Black Spruce 154S Substation and Sunday Creek 539S

Substation Interconnection; Cenovus FCCL Ltd., Interconnection of the Christina Lake Industrial System,

Proceeding 2010, Applications. 1608493-1, 1608667-1, 1608668-1 and 1608718-1, December 24, 2012. 922



216 • Decision 3585-D03-2016 (June 6, 2016)

1085. CP#2 to CP#8 were submitted to the AESO in late May of 2013, and CP#9 and CP#10

were submitted in early June of 2013. The CPs were submitted to the AESO either after the work

was complete or while the work was still in progress.

1086. In CP#2, AltaLink explained that the work was completed ahead of submitting the

change notice to the AESO because the approval from the AESRD was delayed and, without the

change, the winter construction window would have been missed due to delays in engineering.923

In CP#3, CP#4, CP#5, CP#6 and CP#7, the explanation for why the work was initiated before an

AESO review of the change proposal was the delay in producing change notices from a third

party.924 No explanation was provided in CP#8, CP#9 and CP#10 for why the work was initiated

before an AESO review of the change proposal.925 The AESO noted that the cost decisions for

CP#2 and CP#3 were made in December 2012, but it was not notified until April 2013.926

Similarly, the AESO noted that AltaLink was aware of the change for CP#4 in February 2013,

aware of the change for CP#5 in March 2013, and aware of the change for CP#6 in April 2013

but it was not notified of these changes until April 2013.927 In response to an IR, AltaLink stated

that it notified the AESO as soon as it became aware of the changes. AltaLink explained that

SNC-Lavalin ATP notified AltaLink of the changes after the costs were committed. AltaLink

undertook a review of the changes prior to approving the costs and submitting them to the

AESO.928

1087. In the updated Black Spruce 154S project schedule, AltaLink identified the following

major reasons for cost variances between the PPS and the additions to December 31, 2013:

Transmission line labour variance of $1.1 million: Market escalation in construction

labour rates. Access matting required.

Substation material variance of $2.1 million: Additional 240-kV transformer required and

market escalation.

Substation labour variance of $6.9 million: Market escalation in construction labour rates.

Foundation field modifications due to actual geotechnical conditions.

Telecommunication labour variance of $0.2 million: Live line work required additional

engineering; intricate protection scheme required a contractor with a good understanding

of the hot work required.

Owner costs variance of -$0.3 million: Synergies with other green zone projects.

Distributed costs variance of -$2.3 million: Contingency/escalation used to offset the

labour cost increases. Additional scope and complexity increased PMPC costs.

923


Exhibit 0013.00.AML-3585, PDF pages 13, 18, 23, 28 and 33. 925

Exhibit 0013.00.AML-3585, PDF pages 38-39, 44-45 and 48-49. 926


Exhibit 0013.00.AML-3585, PDF page 20, 25 and 30. 928

Exhibit 3585-X0098, AML-CCA-2015MAR05-077(g)(iii and iv), PDF page 426.


Decision 3585-D03-2016 (June 6, 2016) • 217

E&S costs variance of -$0.2 million: Actual E&S rates applied were less than estimated

in the PPS.929

1088. AltaLink provided a more detailed explanation of these variances in response to an IR.

AltaLink indicated that the substation labour variance was due to labour contracts that came in

higher than the PPS estimate for geotechnical, brushing and clearing, civil platform, screw piles

and electrical scopes of work; warmer winter conditions that required frost pounding to uphold

conditions; and directional drilling requirements to install conduits on the existing 971L line to

link the fiber route to the control building and to route the fiber under a pipeline. The substation

material variance was due to market bid pricing for line construction that was higher than the

PPS due to market conditions, and a requirement to use rig mats for work over an existing

pipeline and to protect the environment in wet weather conditions.930 The distributed costs

reflected a draw-down of contingency, which AltaLink expanded on in an IR responses, stating

that, in addition to offsetting labour cost increases, the contingency draw-down covered the risk

and reward performance payment and a project management/engineering labour dispute

settlement.931

1089. The procurement practices as required by the AESO pursuant to ISO Rule 9.1.5, were

audited by the AESO. No contraventions of ISO Rule 9.1.5 for material procurement were

identified.932

1090. Unlike the majority of projects that were executed under the MSA, this project was

executed under the relationship agreement (RA) with SNC-ATP Inc.933 The project also

continued the risk reward mechanism to completion.934 The Commission’s findings on the risk

reward mechanism are discussed above in Section 4.1.14.3 of this decision.

1091. AltaLink argued that the labour and materials contracts were competitively bid and cost

increases were due to prevailing market rates. It explained that this project was located in

northern Alberta where construction can generally only occur in winter. This project area also

saw several projects under construction during the same period. These forces drove competition

for resources and put upward pressure on rates.

1092. AltaLink stated that it communicated with the AESO throughout the project and that the

AESO approved all change notices. AltaLink argued that it responded reasonably to the

challenges it faced during the execution of the project and that it executed the project efficiently.

For these reason, AltaLink submitted that its costs should be approved as filed.935

1093. The Black Spruce 154S project was not specifically addressed by interveners in evidence,

nor in argument and reply.

929

Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0377. 930

Exhibit 3585-X0098, AML-CCA-2015MAR05-077(b) and (c), PDF page 424. 931



Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379. 934


Exhibit 3585-X0859, PDF pages 179 and 181.


218 • Decision 3585-D03-2016 (June 6, 2016)

Commission findings

1094. Consistent with the Commission’s findings in Section 4.1.14.3 above, the risk reward

mechanism costs for projects where an arrangement had already been made prior to Decision

2013-407, are not approved for inclusion in the project costs for these DACDA projects.

Accordingly, AltaLink is directed to remove the risk reward mechanism costs from the applied-

for additions for the Black Spruce 154S project in the compliance filing.

1095. The Commission acknowledges that substantial portions of the variances that arose in

connection with escalation of labour and material costs were not anticipated in the PPS estimate.

However, while the Commission is concerned that AltaLink was not notified by its EPC provider

of cost increases until after the costs had been committed, the evidence, nonetheless,

demonstrates that the majority of material and labour contracts were competitively bid,936 in

compliance with ISO Rule 9.1.5. Therefore, the Commission is satisfied that the actual costs

reflected the market price at the time.


expenditures on the Black Spruce 154S project and is satisfied that the explanations provided for

variances from the initial project forecast costs are reasonable. Accordingly, the Commission

approves the 2013 capital additions excluding the costs associated with the risk reward

mechanism.

4.2.3.8 D.0409 – ENMAX No. 65 Interconnection


1097. In the application, AltaLink requested additions to rate base for D.049 - ENMAX No. 65

Interconnection project in the amount of $7.7 million in 2013, representing a variance of

approximately $0.8 million in relation to the project cost forecast by AltaLink at the PPS stage.937

AltaLink filed its final cost report on March 7, 2014,938 which reported a final cost, excluding

salvage, of $7.8 million for the project.

1098. A detailed breakdown of the D.049 - ENMAX No. 65 Interconnection project costs at

major stages, is provided in Table 33 below:

Table 33. ENMAX No. 65 Interconnection cost breakdown

PPS

Jan 19, 2011 +/- 10% update

Sep 25/12 Additions to


Transmission line materials 907,000 1,180,000 1,100,323 1,100,323


Substation materials 0 14,000 47,230 47,230

Substation labour 0 79,000 279,965 290,354



936

Exhibit 0016.00.AML-3585, PDF page 3 shows that, of project contracts totaling $21,253,903, $19,780,390

were competitively bid. 937


Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF Page 349.


Decision 3585-D03-2016 (June 6, 2016) • 219

PPS

Jan 19, 2011 +/- 10% update

Sep 25/12 Additions to


O: proposal to provide service 50,000 50,000 2,100,000 200,000

O: facility applications 107,000 107,000 100,000 100,000

O: land-rights - easements 7,000 7,000 0 0

O: land-rights – damage claims 0 0 0 0

O: land - acquisitions 2,080,000 2,080,000 0 1,800,000



D: procurement 38,000 38,000 100,000 100,000

D: project management 304,000 648,000 1,000,000 700,000


D: escalation 232,000 233,000 - -

D: contingency 610,000 610,000 - -


OT: ES&G 342,000 342,000 259,805 257,981

OT: AFUDC 621,000 621,000 0 9,240


Total project costs(1) 6,897,000 8,153,000 7,707,433 7,768,359 Source: Exhibit 0195.00.AML-3585, PDF pages 28 and 523; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 101; and Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment.

Note: 1) Salvage has been removed from total project costs. 2) Some numbers may not add up due to differences between exhibits in significant digits used.


1099. In its PPS, dated January 2011,939 AltaLink explained that the scope of project D.0409

was to engineer, procure, construct and commission the interconnection of ENMAX No. 65

substation with AltaLink’s existing transmission line 911L. As the ENMAX No. 65

Interconnection project was a CTI project, there was no NID application for approval. In its

facility application for its part of the ENMAX No. 65 interconnection project, AltaLink noted

that:

Section 3 of the Schedule to the Electric Utilities Act described as CTI: “A new 240 kV

substation to be built in the southeast area of the City of Calgary.”

The preamble to the Schedule of the Electric Utilities Act states: “Each of the critical

transmission infrastructure described in this Schedule includes all associated facilities

required to interconnect a transmission facility described in this Schedule to the

interconnected electric system.”940

1100. Based on the above, AltaLink considered that facilities required to connect the ENMAX

No. 65 substation would be included in the CTI designation.

1101. At the direction of the AESO, AltaLink prepared a PPS for the ENMAX No. 65

Interconnection project that estimated costs of $6.9 million and a target ISD of December

2012.941

939

Exhibit 0195.00.AML-3585, PDF pages 3 to 30. 940




220 • Decision 3585-D03-2016 (June 6, 2016)

1102. AltaLink submitted a facility application on February 16, 2011, in which AltaLink

proposed the following to meet its scope of the CTI:

Alteration of the existing 240-kV transmission lines 911L and 850L to swap positions on

the lines on double circuit structures.

Re-numbering of 911L so that the transmission line between Peigan 59S and the

proposed ENMAX No. 65 substation would remain designated as 911L, while the

transmission line between the proposed ENMAX No. 65 substation and Janet 74S

substation would be renumbered to 1080L.

Construction of approximately 400m of double circuit 240-kV transmission line on

existing line 911L for an in-out configuration into the proposed ENMAX substation

No. 65.942

1103. The Commission approved the facility application on November 3, 2011 in Decision

2011-435.

1104. Subsequent to the Commission’s approval, AltaLink submitted an application to request

a connection order. This application was submitted to correct an error in AltaLink’s original

facility application, which missed a request for a connection order to connect 911L/1080L to

ENMAX’s No. 65 substation.943 The Commission approved the application on March 27, 2013

in Decision 2013-121.

1105. AltaLink filed a further letter of enquiry on July 2, 2013 requesting Commission

approval to alter the line rating on 911L/1080L from 965MVA to 489MVA for each circuit to

be consistent with the capacity ratings of the existing segments of transmission lines 911L and

850L.944 The Commission approved the application on August 26, 2013 in Decision 2013-313.

1106. In conjunction with decisions 2011-435, 2013-121 and 2013-313, the Commission issued

a number of P&Ls or approvals. In Decision DA2013-99, the Commission approved a time

extension in respect of the approved interconnection to the ENMAX No. 65 substation from

March 31, 2013 to November 30, 2013.945


Commission in respect of the ENMAX No. 65 Interconnection project is in Appendix 4.

1108. The project was energized in September 30, 2013.946

942

Decision 2011-435, ENMAX Power Corporation and AltaLink Management Ltd., No. 65 Substation and

Interconnection, Application nos. 1606861 and 1607033, Proceeding 1007, November 3, 2011, paragraphs 32,

34 and 35. 943


Decision DA2013-99 (Errata): AltaLink Management Ltd., ENMAX No. 65 Substation Interconnection, Time

Extension, Proceeding 2516, Application 1609419-1, April 11, 2013; Errata issued April 24, 2013,

paragraphs 4-5. 945

Decision DA2013-99 Errata, AltaLink Management Ltd., ENMAX No. 65 Substation Interconnection, Time

Extension. Application 1609419, Proceeding 2516, April 24, 2013. 946



Decision 3585-D03-2016 (June 6, 2016) • 221






Cost Impact ($)

TCA#1 Revised Cost Estimate Update Cost Estimate – Steel Quantity, Protection

1,265,000

CP#2 AFUDC Reconciliation AUC decision for approval of CWIP in rate base.

(611,760)

CP#5 Change of foundations Adverse soil conditions were encountered resulting in additional foundation costs. Submitted September 26, 2013.

240,000


1110. TCA#1 included costs related to protection changes required at remote substations and

additional steel required for the tubular steel structures. The quantity of steel included in the

original estimate contained errors. The breakdown of costs was as follows:

transmission line material: $230,000

transmission line labour: $370,000

substation labour: $253,000

telecommunication materials: $7,000

telecommunication labour: $16,000

distributed costs: $389,000947

1111. AltaLink submitted that the project variances were primarily due to a delay caused by the

unavailability of the ENMAX No. 65 substation for the interconnection and due to increased

material costs. Procurement for the project was completed in compliance with Market Participant

– Transmission ISO Rule 9.1.5.948

1112. The ENMAX No. 65 Interconnection project was not specifically addressed by


Commission findings


expenditures on the D.0409 -ENMAX No. 65 Interconnection project, and is satisfied with the

explanations AltaLink provided for the variances observed in respect of this project from initial

forecasts. The Commission considers that the requested capital amounts for 2013 of $7,707,433

were prudent. AltaLink is authorized to add this amount to its rate base.

947


Exhibit 3585-0859, PDF page 182.


222 • Decision 3585-D03-2016 (June 6, 2016)

4.2.3.9 D.0414 – Western Alberta Transmission Line


1114. In the application, AltaLink requested additions to rate base for D.014 –WATL in the

amount of $16.3 million in 2013, representing a variance of approximately $13.9 million in

relation to the prorated project cost forecast by AltaLink at the PPS stage.949 A final cost report is

not available for this project.950

1115. A detailed breakdown of the costs of the completed portion of the WATL project (WATL

240-kV line modifications), is provided in Table 35 below:

Table 35. WATL 240-kV line modifications cost breakdown

Prorated PPS Jan 20, 2011

Additions to Dec 31, 2013

Transmission line materials 954,293 1,720,361


Substation materials 0 0

Substation labour 0 0

Telecommunication materials 0 0

Telecommunication labour 0 0

Total owner costs(1) 0 0

Total distributed costs(1) 0 0

OT: ES&G 96,444 327,590

OT: AFUDC 5,043 0

Total other costs 101,487 327,590

Total project costs 2,351,180 16,294,319

Source: Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0414. Note: 1) A detailed breakdown of owner and distributed costs is not available.

1116. Additions of the entire project to date are one per cent of the total project.951 For

comparison, a detailed breakdown of the entire WATL project, costs at major stages is provided

in Table 36 below:

Table 36. Western Alberta Transmission Line – total project cost breakdown

PPS

Jan 20, 2011 +/- 10 update May 28, 2013



Substation materials 420,652,184 273,239,855

Substation labour 78,282,716 262,372,031

Telecommunication materials 5,498,171 6,475,092

Telecommunication labour 3,660,086 9,450,835

O: proposal to provide service 11,930,143 12,844,852

O: facility applications 35,148,524 41,901,298

O: land-rights - easements 39,807,200 48,007,039

O: land-rights – damage claims 2,753,450 2,257,300

O: land - acquisitions 16,635,000 13,141,326

O: ROW Costs 0 0

949



Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0414.


Decision 3585-D03-2016 (June 6, 2016) • 223

PPS

Jan 20, 2011 +/- 10 update May 28, 2013

Total owner costs 106,274,317 118,151,815

D: procurement 3,479,546 9,882,389

D: project management 22,244,257 56,470,932

D: construction management 29,443,124 69,494,111

D: Escalation 65,277,447 5,628,601

D: contingency 95,805,726 70,959,202

Total distributed costs 216,250,100 212,435,235

OT: ES&G 54,777,292 51,032,674

OT: AFUDC 3,004,677 2,980,467

Total other costs 57,781,969 54,013,141

Total project costs(1) 1,394,452,650 1,644,155,168

Source: Exhibit 0211.00.AML-3585, PDF pages 48 and 1365and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 102. Note: 1) Salvage has been removed from total project costs. *Final cost report not available for entire project.


1117. The WATL project involved the construction of 347km of 500-kV HVDC line from the

new Sunnybrook 510S substation, which would contain the north converter station, to the new

Crossing 511S substation, which would contain the south converter station. In addition, two new

240-kV lines would be constructed from Sunnybrook 510S substation to Genesee 330P

substation, and line 1201L would be re-terminated into the new 500-kV AC Bennett 520S

substation.952

1118. As the WATL project was designated as a CTI project, no Commission proceeding was

convened to consider an AESO NID application in respect of the project.953 Specifically, in its

facility application for the WATL project, AltaLink noted that:

The Electric Utilities Act determines the project scope and significance to Albertans by

establishing the project to be CTI.

The Electric Utilities Act further provides that the construction, connection and

operations of a transmission or part of a transmission line that is designated as CTI is

required to the meet the needs of Alberta and is in the public interest.954

1119. At the direction of the AESO, AltaLink prepared a PPS for the WATL project which

estimated costs of $1.4 billion and a target ISD of October 14, 2014.955

1120. AltaLink filed a facility application on February 28, 2011, and proposed the following to

meet the scope of the CTI:

Construction of a new 500-kV AC / 500-kV DC Sunnybrook 510S substation.

Construction of a new 500-kV AC / 500-kV DC Crossings 511S substation.

952

Exhibit 211.00.AML-3585, January 2012 monthly progress report, project scope, PDF page 1019. 953





224 • Decision 3585-D03-2016 (June 6, 2016)

Construction of a 500-kV DC transmission line designated 1325L from Sunnybrook 510S

substation to Crossings 511S substation.

Construction of a new 500-kV AC Bennett 520S substation.

Modification of the existing Langdon 102S substation.

Modification of the transmission line 1201L to terminate into the new Bennett 520S

substation.

Modification of the transmission line 924L/927L to terminate into a new bay in the

Langdon 102S substation.

Modification of the transmission line 936L/937L to terminate into a new bay in the

Langdon 102S substation.

Modification of the transmission line 809L/8L09 to create an in/out configuration to

Sunnybrook 510S substation.

Modification of the transmission lines 1203L and 1209L at the Genesee E330P substation

to integrate the new Sunnybrook 510S substation.

Construction of two new 500-kV AC lines (1238L and 1239L from the Sunnybrook 510S

DC substation to the existing Genesee E330P substation.

Modification of the Genesee E330P substation.956

1121. Updates were filed to the facility application on August 25, 2011, October 18, 2011, and

April 5, 2012, to update the proposed route as a result of ongoing discussions with

stakeholders.957 In addition to the route changes, filed on April 5, 2012, AltaLink also filed

updates with respect to the Bennett 520S substation, Langdon area focus maps and the project

ISD,958 AltaLink also filed an errata to its facility application on August 26, 2011, October 18,

2011 and June 6, 2012, to correct minor errors in the facility application.959

1122. The Commission approved the facility application, with certain conditions, on December

6, 2012 in Decision 2012-327.

1123. Subsequent to the Commission’s approval, the Commission directed AltaLink to file an

application to amend a portion of the approved route. AltaLink complied with this direction on

March 15, 2013 and filed a request to amend P&L U2012-634. The Commission approved an

alternate route option proposed in the application on August 13, 2013 in

Decision 2013-298.960 961

1124. AltaLink filed letters of enquiry on May 15, 2013, July 18, 2013, July 19, 2013,

February 20, 2014 and June 13, 2014 requesting approval to re-align the right-of-way and

certain structures for a portion of the approved 1325L route to remove or reduce line jogs

(straighten the line) due to detailed engineering and further landowner consultation.962 The

956





Decision 2013-298: AltaLink Management Ltd., Amendment to a portion of the Western Alberta

Transmission Line from km marker 264 to route marker A63, Proceeding 2500, Application 1609390-1,

August 13, 2013. 961


Exhibit 0211.00.AML-3585, PDF page 734-735, 738-739, 741-742, 767-769 and 785-786.


Decision 3585-D03-2016 (June 6, 2016) • 225

Commission approved the applications on May 30, 2013 in Decision DA2013-132,963 on July

24, 2013 in Decision DA2013-173,964 on July 24, 2013 in Decision DA2013-174,965 on March

11, 2014 in Decision DA2014-61,966 and on June 24, 2014 in Decision DA2014-149.967

1125. AltaLink also filed a letter of enquiry on August 8, 2013 requesting approval to alter

certain sections of the transmission lines 906L/928L and 918L. AltaLink stated that it had

advised the Commission of the realignment during the WATL hearing but did not update the

approvals requested, so it did not receive the necessary permits.968 The Commission approved

the application on August 29, 2013 in Decision DA2013-197.969

1126. AltaLink filed another letter of enquiry on May 15, 2014, requesting approval for two

minor route adjustments and the relocation of a repeater station on the approved 1325L

transmission line. The route adjustments were as a result of ongoing landowner consultation and

the change in the location of the repeater station was required as a result of the route approved

by the Commission.970 The Commission approved the application on June 4, 2014 in Decision

DA2014-133.

1127. Subsequent to the Commission’s approval, AltaLink filed an application requesting an

amendment to the P&L for transmission line 1325L. The amendment requested included

modification to a route for oil and gas facilities, due to completion of geotechnical work and

detailed engineering and due to further landowner consultations.971 The Commission approved

the application on December 18, 2013 in Decision DA2013-293.

1128. Only the work related to the WATL project that was completed and energized in 2012 or

2013 is included in the scope of this proceeding. This work includes: alterations to 925L, 929L,

928L and 918L (for reference purposes, WATL 240-kV line modification is a reference to the

transmission facilities included in this DACDA. Reference to WATL is a reference to the entire

WATL project). The remaining scope of the WATL project was proposed to be considered in a

future application.972 The components that are energized can begin to depreciate and AltaLink

explained that these components of the project are included in this application consistent with

past practices.973

963

Decision DA2013-132: AltaLink Management Ltd., Transmission Line 1325L, Letter of Enquiry Approval,

Proceeding 2610, Application 1609594-1, May 30, 2013. 964





Decision DA2014-61: AltaLink Management Ltd., Minor Route Adjustments for the Western Alberta

Transmission Line, Proceeding 3088, Application 1610330-1, March 11, 2014. 967

Decision 2014-149: AltaLink Management Ltd., Minor Route Adjustment for the Western Alberta

Transmission Line, Proceeding 3292, Application 1610665-1, June 24, 2014. 968

Exhibit 0211.00.AML-3585, PDF Pages 745-746. 969

Decision DA2013-197: AltaLink Management Ltd., Realignment of a Portion of Transmission Lines

906L/928L and 918L, Proceeding 2788, Application 1609845-1, August 29, 2013. 970

Exhibit 0211.00.AML-3585, PDF pages 772-774 971


Exhibit 3585-X0042, AML-AUC-2015MAR05-005, Table 1, PDF page 146. 973

Exhibit 3585-X0042, AML-AUC-2015MAR05-005(a), PDF page 144.


226 • Decision 3585-D03-2016 (June 6, 2016)

1129. A table of the proceeding numbers related to decisions and associated approvals issued

by the Commission in respect of the WATL 240-kV line modifications is in Appendix 4.

1130. The components of the project that are included in this application were energized as

follows:

1201L/Langdon (work at existing Langdon substation) on May 12, 2013

Temporary Bennett substation (station service) on May 30, 2013

Temporary Langdon and Bennett substations on June 4, 2013

1201L into temporary Bennett substation on June 11, 2013

928L modification of structures on September 28, 2013

929L modification of structures on October 24, 2013

925L modification of structures on November 13, 2013974


1131. All of the change notices for the WATL project were provided in Exhibit 0211.00.AML-

3585. In the project schedules submitted with the application, AltaLink stated “Additions to date

are 1% of total project. Variance explanations to be provided when project is completed.”975

1132. The procurement practices for the WATL HVDC converter stations were audited by the

AESO, pursuant to ISO Rule 9 – Market Participation – Transmission. No contraventions of ISO

Rule Section 9.1.5 for material procurement were identified.976

1133. In argument, AltaLink stated that the procurement for the entire project (including the

scope in this proceeding) adhered to ISO Rule 9.1.5.977 The WATL 240-kV line modifications

project was not addressed by interveners in evidence, nor in argument and reply.

Commission findings

1134. As the Commission previously indicated in its finding in Section 4.1.1, AltaLink did not

include a project summary or overview document for this project. Without a project summary or

project overview, the Commission had difficulty identifying which specific facilities were

energized during the current DACDA application test period, including whether the requested

addition amount of almost $16.3 million was reasonable relative to the PPS cost estimate or to

the 180 day stage forecasts for the specific facilities that AltaLink energized during the DACDA

period. The entry for the WATL project on the “energizations” tab of Exhibit 0006.00.AML-

3585 lists 24 separate energization dates, including six entries for energization dates during

2013, but there is no information as to which facilities were energized on each of these dates.

1135. As set out in its findings in Section 4.1.1, the Commission will allow AltaLink to use the

amount of the 2013 addition it requested as the basis for revenue requirement reconciliation

calculations for the DACDA test period for this project, but this addition is a placeholder only. A

final determination on WATL project costs will be undertaken in a future DACDA proceeding

application.

974


Exhibit 0006.00.AML-3585, tab D.0414. 976




Decision 3585-D03-2016 (June 6, 2016) • 227

4.2.3.10 D.0458 – East HVDC Converter Station Interface


1136. In the application, AltaLink requested additions to rate base for the D.0458 – East HVDC

Converter Station Interface project in the amount of $13.6 million in 2013, representing a

variance of approximately $7.2 million in relation to the prorated project cost forecast prepared

by AltaLink at the PPS stage.978 A final cost report is not available for this project.979

1137. A detailed breakdown of the costs of the completed portion of the East HVDC Converter

Station Interface project (the East HVDC Link project) is provided in Table 37 below:

Table 37. East HVDC Link cost breakdown

Prorated PPS* Mar 11, 2011




Substation materials 0 0

Substation labour 0 0

Telecommunication materials 0 0

Telecommunication labour 0 0

Total owner costs(1) 0 0

Total distributed costs(1) 877,832 0

OT: ES&G 368,086 399,200

OT: AFUDC 0 0

Total project costs(2) 6,454,042 13,626,700

Source: Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0458. Note: 1) A detailed breakdown of owner and distributed costs is not available. 2) Total project costs do not include salvage. * AltaLink provided an explanation of how the prorated PPS was determined in Exhibit 3585-X0059, AML-CCA-2015MAR05-019 Attachment.

1138. Additions of the entire project to date are 35 per cent of the total project.980 For

comparison, a detailed breakdown of the entire East HVDC Converter Station Interface project

costs at major stages, is provided in Table 38 below:

Table 38. East HVDC Converter Station Interface – total project cost breakdown

PPS

Mar 11, 2011 +20/-10 in FA May 9, 2012

+/-10 update Oct 10 2013

Transmission line materials 2,229,808 4,774,151 6,685,583

Transmission line labour 7,388,422 17,236,046 31,878,347

Substation materials 5,638,325 6,650,317 7,238,232

Substation labour 5,896,225 8,302,792 17,943,734

Telecommunication materials 2,065,204 1,624,984 1,227,446

Telecommunication labour 2,622,023 2,361,769 2,678,049

O: proposal to provide service 150,000 371,774 176,921

O: facility applications 547,000 1,257,544 333,897

O: land-rights - easements 0 0 518,895

O: land-rights – damage claims 0 0 249,565

978



Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0458.


228 • Decision 3585-D03-2016 (June 6, 2016)

PPS

Mar 11, 2011 +20/-10 in FA May 9, 2012

+/-10 update Oct 10 2013

O: land - acquisitions 100,000 125,754 16,917

O: ROW Costs 0 0 0

Total owner costs 797,000 1,755,042 1,296,195

D: procurement 395,513 349,467 1,190,811

D: project management 3,045,973 4,269,270 4,331,560

D: construction management 1,438,043 3,805,002 4,765,299

D: escalation(1) 2,154,241 0 2,126,288

D: contingency 3,151,654 0 5,000,000

Total distributed costs 10,185,424 8,423,739 17,413,959

OT: ES&G 2,227,442 3,117,460 4,532,555

OT: AFUDC 0 0 0

Total project costs(2) 39,049,872 54,246,299 90,894,100

Source: Exhibit 0192.00.AML-3585, PDF pages 48, 139 and 691 and Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 103. *Final cost report not available for entire project.

Note: 1) Escalation line item was included in other costs in the PPS estimate. 2) Total project costs do not include salvage.


1139. The East HVDC Converter Station Interface project was part of the scope of work

completed by AltaLink with respect to the East Alberta Transmission Line (EATL) project, the

majority of which was constructed by ATCO Electric. AltaLink’s scope of work in EATL

involved engineering, procurement, construction and commission of equipment to integrate

ATCO Electric’s EATL converter station with the AltaLink infrastructure.981

1140. At the direction of the AESO, AltaLink prepared a PPS for the East HVDC Converter

Station Interface project, which estimated costs of $39.4 million and a target in-service date of

“mid to late 2014.”982

1141. AltaLink submitted a facility application for its part of the EATL project, which included

the East HVDC Converter Station Interface, on April 30, 2011. In its facility application,

AltaLink noted that:

The project was designated as CTI as defined in the Electric Utilities Act.

Section 13.1(2) of the Hydro and Electric Energy Act states that: “The construction,

connection and operation of a transmission line or part of a transmission line that is

designated as critical transmission infrastructure is required to meet the needs of Alberta

and is in the public interest.”983

1142. Based on the above, AltaLink considered that facilities required to connect EATL, such

as the East HVDC Converter Station Interface, should be included in the CTI designation.984 As

the East HVDC Converter Station Interface project was designated as a CTI project, no

981


Exhibit 0192.00.AML-3585, PDF page 29 983


The Commission acknowledged this project as a CTI in paragraph 3 of Decision 2012-305.


Decision 3585-D03-2016 (June 6, 2016) • 229

Commission proceeding was convened to consider an AESO NID application in respect of the

project.985

1143. In the facility application, AltaLink proposed the following to meet the scope of the CTI:

Expansion of the approved Heartland 12S substation.

Rerouting and re-terminating approximately 350 metres of 500-kV transmission lines

1206L/1212L.

Addition of three 500-kV circuit breakers to the Heartland 12S substation.

Addition of new structures on 1035/1034L line between the Bowmanton 244S and

Cassils 324S substation.

Installation of a new telecommunications tower near Bowmanton 244S substation .

Installation of new towers on 923L/935L between the Milo 356S and Cassils 324S

substations.

Rerouting approximately 700m of 950L and 933L/934L lines.

Installation of single circuit structures on 1053L, 931L and 1075L lines for crossings.986

1144. On July 10, 2012, AltaLink requested that the facility application be withdrawn and that

it be given permission to file a new application in its place. The Commission granted AltaLink’s

request.987

1145. AltaLink re-submitted its facility application on May 11, 2012. Additional changes were

filed to the updated facility application on October 29, 2012 to update the proposed relocation of

line 950L. The updates were required from a system reliability perspective.988

1146. The Commission approved the facility application, with the exception of requested

alterations to 1206L/1212L, on November 15, 2012 in Decision 2012-305.989

1147. AltaLink filed a letter of enquiry on December 21, 2012 requesting approval to reroute a

portion of the approved 1206L/1212L line to allow for the termination of ATCO Electric’s

EATL line into the Heartland 12S substation.990 The Commission approved the application on

January 11, 2013 in Decision 2013-009.991

1148. AltaLink also filed a letter of enquiry on November 27, 2013 requesting permission to

relocate the approved Bowmanton 9244R radio tower to reduce the site footprint and minimize

environmental and land use impacts.992 The Commission approved the application on December

19, 2013 in Decision DA2013-285 (Errata).

985





Decision 2012-305: AltaLink Management Ltd., Eastern Alberta Transmission Line Interconnection and

Interface Project, Proceeding 1884, Application 1608447-1, November 15, 2012. 990

Exhibit 0192.00.AML-3585, PDF page 241-242. 991

Decision 2013-009: AltaLink Management Ltd., Relocation of Transmission Line 1206L/1212L,

Proceeding 2325, Application 1609166-1, January 11, 2013. 992

Exhibit 0192.00.AML-3585, PDF page 249-250.


230 • Decision 3585-D03-2016 (June 6, 2016)

1149. Only the work in the East HVDC Link project that was completed and energized in 2012

or 2013 is included in the scope of this proceeding. This work includes: alterations to 950L,

1053L, 1075L and 931L. AltaLink noted that much of the work on this project cannot be

completed until ATCO Electric energizes its EATL 500-kV HVDC project.993


approvals. A table listing the proceedings, decisions and associated approvals issued by the

Commission in respect of the East HVDC Link project, is in Appendix 4.

1151. The components of the project that are included in this application were energized as

follows:

950L re-energization on May 20, 2013

931L temporary bypass on May 26, 2013

933L temporary bypass on June 9, 2013

933L permanent line energization on July 7, 2013

935L temporary line energization on July 7, 2013




1152. All of the change notices for the East HVDC Converter Station Interface project were

provided in Exhibit 0192.00.AML-3585. In the project schedules submitted with the application,

AltaLink stated “Additions to date are 35% of total project. Variance explanations to be provided

when project is completed.”995

1153. The relevant trends and changes that drove project cost variances as set out in AltaLink’s




Cost Impact ($ million)

CP#1 Revised project scope and costs due to delay in receipt of P&L. 15,730,992

CP#3 950L re-route to ensure that the existing double circuit and 950L are not within the dead ends of ATCO HVDC line crossing.

(58,985)

CP#7 AML submitted the +/- 10% Estimate 33,010,145

Source: Exhibit 0192.00.AML-3585, PDF pages 304-386 and 688. Note: CP#3 is entirely applicable to the East HVDC Link project.

1154. Further information in support of the key cost variances, for the East HVDC Link project,

from the project related to change notices, are listed below:

993

Exhibit 3585-X0042, AML-AUC-2015MAR05-005, Table 1, PDF page 146. 994


Exhibit 0006.00.AML-3585, tab D.0458.


Decision 3585-D03-2016 (June 6, 2016) • 231

CP#1 included additional scope for temporary line bypasses for

931L/1075L/1053L/935L/923L lines in order to satisfy the AESO’s outage scheduling

constraints. This scope change had a cost impact of $3.6 million.996

The forecast contingency for the entire project was increased in CP#1 to reflect the

additional project risk due to a compressed construction schedule and limited outage

availability.

The forecast contingency for the entire project was also increased in CP#3 to reflect

additional project risk due to rerouting 950L in a wetland area.997

The cost increases in CP#7 were described as being due to increased complexity for the

transmission line modifications, spring construction conditions and the market conditions

on construction labour costs. The AESO filed the information in the change notice with

the Commission on April 30, 2014, in accordance with ISO Rule 9 – Market Participant –

Transmission, subsection 9.1.3.5(d). The AESO confirmed the need for the project in a

letter dated April 28, 2014.998

The forecast contingency fund was decreased by $4.3 million in CP#7 based on the

known risk profile at the time of the updated PPS estimate.999

1155. The East HVDC Link project was not addressed by interveners in evidence, nor in

argument and reply.

Commission findings

1156. AltaLink is applying to recover costs associated with the portions of the East HVDC

Converter Station Interface project that have been energized. Part of those costs were incurred

for temporary bypass lines that were required due to outage constraints to complete work on live

lines. The Commission understands that the temporary bypass lines were required in order to

complete alterations to existing lines.

1157. As stated by the Commission in Section 4.1.1, the Commission is satisfied that evidence

filed on the record of this proceeding related to this portion of the EATL EAST HVDC

Converter Station Interface project was sufficient to enable the Commission to test the costs

incurred and to reach a determination regarding the prudence of these costs.

1158. The Commission finds these capital expenditures to be reasonably incurred and a

necessary component of this project as these components were integral to the actual interface

work and facilitated the completion of the actual HVDC interface. However, although these parts

were energized, because the expenditures are only a small percentage of the total HVDC

interface project’s total costs, the Commission considers it more appropriate that these

expenditures should remain in CWIP and should be considered for addition to rate base when the

project is complete. AFUDC can be accumulated on the expenditures in the interim. AltaLink is

therefore directed to keep the expenditures in CWIP and file for their approval when the project

is complete.

996


Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF page 386 998

Exhibit 0192.00.AML-3585, PDF pages 348 and 350-351. 999



232 • Decision 3585-D03-2016 (June 6, 2016)

4.2.3.11 Red Deer Area Transmission project

1159. The AESO filed a NID application in respect of the Red Deer Region Transmission

Development project on July 19, 2011. In its application, the AESO indicated that, based on

studies it had conducted, it would be unable to serve the current load without reliability criteria

violations. The AESO noted that certain operational measures had been adopted due to the

reliability criteria violations, and indicated the forecast load increase in the Red Deer region was

anticipated to increase the number of occurrences and the magnitude of the reliability criteria

violations. The Red Deer Region Transmission Development project would include new

240/138-kV substation developments, additions to existing substations, new 138-kV

transmission line developments, 138-kV transmission line rebuilds and discontinued operation of

existing 138-kV lines, which would be completed in two stages. The AESO noted that the study

area referred to in its NID application as the Red Deer region centred on the City of Red Deer,

extending south to Didsbury, north to Wetaskiwin, east to the Joffre area (including the industrial

complexes of Nova Chemicals) and west to the Benalto and Harmattan areas.1000

1160. The AESO issued various directions to AltaLink, including directions to assist in the

preparation of its NID application.1001 According to the AltaLink witness, Ms. Picard-Thompson,

the AESO indicated some urgency in the Red Deer Area Transmission Development projects and

directed AltaLink to acquire specific equipment and material that has lengthy delivery times. For

this reason, AltaLink began some of its tendering processes prior to P&L.1002 AltaLink noted that

the construction contract work for all Red Deer capacitor bank addition projects (Joffre, Ellis and

Prentiss) were combined in the interest of securing a volume discount.1003

1161. The Commission approved the NID application on April 10, 2012 through the issuance of

Decision 2012-098.

1162. AltaLink filed a facility application on September 26, 2011 to meet the need for Stage 1

of the Red Deer Area Transmission Development. The scope of the project included the

alteration of 138-kV transmission lines 768L and 778L, the alteration of several substations and

adding capacitor banks at three other substations.1004 AltaLink filed an amendment to the

application on June 7, 2012 to correct errors in the original application and amend the type of

structure that was proposed for the alterations to the 768L and 778L lines.1005 The Commission

approved this facility application in Decision 2012-254 on September 24, 2012.

1163. On June 20, 2013, AltaLink filed an application for a time extension for the capacitor

bank addition projects (Joffre, Prentiss and Ellis). In DA2013-162, the Commission approved a

time extension for those projects from June 30, 2013 to December 31, 2013.1006


approvals.

1000



Transcript, Volume 7, pages 1333-1334 and 1336. 1003






Decision 3585-D03-2016 (June 6, 2016) • 233


Commission in respect of the Red Deer Area Transmission Development projects, is in

Appendix 4.

1166. In its current application, AltaLink filed requests for approval for capital additions in

2013 in respect of four Red Deer region projects assigned to AltaLink, as follows:

Project D.0459 – Red Deer Area Transmission – Split 768L and 778L

Project D.0460 – Red Deer Area Transmission – Benalto 17S

Project D.0461 – Red Deer Area Transmission – Capacitor Bank Addition at Joffre 535S

Project D.0462 – Red Deer Area Transmission – Capacitor Bank Addition at Prentiss

276S

Project D.0463 – Red Deer Area Transmission – Capacitor Bank Addition at Ellis 332S

1167. The AESO audited all the Red Deer Area Transmission Development Stage 1 projects

AltaLink for compliance to its material procurement requirements as required by ISO Rule 9.1.5.

No findings of non-compliance were made.1007

1168. The Red Deer Area Transmission Development projects were not addressed by


1169. Each of the Red Deer Area Transmission Development Stage 1 projects is described

separately in the subsections below.

4.2.3.11.1 D.0459 – Red Deer Area Transmission – Split 768L & 778L



in 2013, representing a variance of approximately $1.9 million in relation to the project cost

forecast by AltaLink at the PPS stage.1008 AltaLink filed its final cost report on December 19,

2014,1009 which reported a final cost, excluding salvage, of $7.7 million for the project.

1171. A detailed breakdown of the Red Deer Area Transmission Development – 768L and

778L line split (Red Deer line split) project costs at major stages, is provided in Table 40 below:

Table 40. Red Deer Area – Split 768L & 778L cost breakdown

PPS

July 2011 +/-10 update Mar 14, 2013




Transmission line labour 760,000 1,148,000 1,009,196 976,968



Telecommunication materials 8,000 0 36,189 36,189


O: proposal to provide service 99,000 75,000 0 0


1007

Exhibit 3585-X0042, AML-AUC-2015MAR05-007(b), PDF page 247. 1008




234 • Decision 3585-D03-2016 (June 6, 2016)

PPS

July 2011 +/-10 update Mar 14, 2013



O: land-rights - easements 0 14,000 0 0


O: land - acquisitions 0 0 0 0



D: procurement 112,000 157,000 200,000 200,000

D: project management 716,000 974,000 1,100,000 1,100,000


D: escalation(1) - 17,000 - -

D: contingency 512,000 252,000 - -


OT: ES&G 252,000 291,000 224,015 228,457

OT: AFUDC 59,000 2,000 1,735 1,735



Source: Exhibit 0144.00.AML-3585, PDF page 28; Exhibit 0151.00.AML-3585; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 104 and AML-AUC-2015MAR05-010 Attachment, PDF pages 333-334; and Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. Note: 1) Escalation line item was not included in the PPS estimate.

2) Salvage has been removed from total project costs. 3) Some numbers may not add up due to differences between exhibits in significant digits used.


1172. The Red Deer line split project included alteration of the lines 768L and 778L, addition

of one 138-kV circuit breaker in the North Red Deer 217S substation and addition of two 138-kV

circuit breakers in the Gaetz 87S substation. The 768L and 778L lines were split and re-

terminated into the North Red Deer 217S and Gaetz 87S substations.1010

1173. At the direction of the AESO, AltaLink prepared a PPS for the project that estimated

costs of $5.5 million and a forecast ISD of October 30, 2012.1011

1174. The project was energized on March 28, 2013.1012




1010





Decision 3585-D03-2016 (June 6, 2016) • 235



Cost Impact ($)

TCA#7 Grounding studies at 87S and 217S and structure change at 217S: existing studies are insufficient to determine step and touch potential at each site. New studies are required. Detailed engineering has identified space constraints that necessitate changing from two-pole structures to monopoles

128,000

TCA#8 Telecom tower replacement Detailed engineering has determined the existing telecom tower cannot support the new radio equipment. A new tower is required to support the load.

141,000

CP#12 The change is required to cover the variance between the estimated construction costs and the actual bids received for the scope of work.

1,095,000

CP-AFUDC#1 AFUDC Reconciliation (58,437)

CP#18 Increased costs due to delay in P&L; complexities of working at brownfield substations; soil conditions differ from PPS estimate

1,209,000

CP-AFUDC#2 AFUDC Reconciliation #2 1,172


1176. CP#12 was further broken down to show the cost increases attributable to specific labour

rate increases and other costs. Cost increases attributable to additional scope amounted to

$180,000 for an increased amount of control cable and $80,000 for a change to foundations

(from screw piles assumed in the PPS to concrete piles) due to local soil conditions, which

required additional geotechnical testing. Higher bid prices for construction labour amounted to a

cost increase of $675,000 and high bid prices on salvage amounted to $72,000. Factored costs,

such as project management, construction management, procurement and E&S, increased by

$88,000. AltaLink stated that no alternatives were considered to address these issues. A portion

of the project contingency fund ($142,000) was applied against the higher bids to mitigate the

financial effects. However, there was not enough money in the contingency fund to cover the

entire variance.1013

1177. CP#18 was broken down further to show the cost increases attributable to specific issues:

Increased project duration: $376,000.

Winter construction, which negatively affected the outage windows available: $109,000.

Increased complexities of working at Gaetz and North Red Deer substations; namely,

work required to identify and protect existing underground facilities, and

accommodations required by the City of Red Deer (which shares ownership of the

substations): $657,000.

Changes in conditions from the PPS; namely, a requirement for a battery charger,

removing soils that could not be stored on site, brushing and clearing of existing right-of-

way: $57,000.

No alternatives were considered for the delay in P&L or the changes in conditions. AltaLink

stated that there were only limited options to address the complexities of working at Gaetz and

1013



236 • Decision 3585-D03-2016 (June 6, 2016)

North Red Deer substations and the option with the smallest effect on cost and schedule was

selected.1014

Commission findings


expenditures on the Red Deer line split project, and is satisfied with the explanations provided

for the variances observed in respect of this project from initial forecast costs. The Commission

considers the requested capital amounts for 2013 of $7,361,566, to be prudent. AltaLink is

authorized to add this amount to its rate base.

4.2.3.11.2 D.0460 – Red Deer Area Transmission – TX add at Benalto 17S


1179. In the application, AltaLink requested additions to rate base for the D.0460 - Red Deer

Area Transmission project - TX add at Benalto 17S project (the Red Deer Benalto project) in the

amount of $8.3 million in 2013, representing a variance of approximately $1.8 million compared

to the project cost forecast by AltaLink at the PPS stage.1015 AltaLink filed its final cost report on

December 19, 2014,1016 which reported a final cost, excluding salvage, of $8.4 million for the

project.

1180. A detailed breakdown of the Red Deer Benalto project costs at major stages, is provided

in Table 42 below:

Table 42. Red Deer Area – Benalto 17S cost breakdown

PPS

June 2011 +/- 10% update March 14, 2013



Transmission line materials - - 0 -

Transmission line labour - - 0 -



Telecommunication materials - - 0 -

Telecommunication labour - - 0 -








1014

Exhibit 0149.00.AML-3585, PDF pages 21-22 and 26. 1015


Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF Page 335.


Decision 3585-D03-2016 (June 6, 2016) • 237

PPS

June 2011 +/- 10% update March 14, 2013



D: procurement 84,000 184,000 200,000 200,000

D: project management 628,000 710,000 900,000 900,000


D: escalation - 6,000 -0 -

D: contingency(1) 263,000 132,000 -0 -


OT: ES&G 300,000 231,000 206,405 203,319

OT: AFUDC 23,000 1,000 1,390 1,390


Source: Exhibit 0134.00.AML-3585, PDF 22; Exhibit 0141.00.AML-3585; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 105 and AML-AUC-2015MAR05-010 Attachment, PDF page 335; and Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. Note: 1) Contingency and escalation line items were combined in the PPS estimate.

2) Salvage has been removed from total project costs. 3) Some numbers may not add up due to differences between exhibits in significant digits used.


1181. The Red Deer Benalto project included alteration of the Benalto 17S substation to add

one 240/138-kV transformer, one 138-kV circuit breaker and one 240-kV circuit breaker.1017

1182. At the direction of the AESO, AltaLink prepared a PPS for the project, which estimated


1183. The project was energized on March 27, 2013.1019


1184. AltaLink indicated that the cost variances for substation labour were due to market

escalation in construction labour rates, complexities of working at brownfield substations, as

well as the City of Red Deer accommodation requirements. The increase in owner costs was

attributed to a delay in P&L.1020 AltaLink submitted six change notices to the AESO in respect of

the cost variances. The AESO approved all but one change notice.1021



1017




Exhibit 3585-X0043, AML-AUC-2015MAR05-042, tab D.0460. 1021

Exhibit 0139.00.AML-3585, PDF pages 1.


238 • Decision 3585-D03-2016 (June 6, 2016)



Cost Impact ($)

TCA#9 New battery bank, racks and charger and new digital data recorder and digital fault recorder – it was assumed in the PPS that the existing equipment would have the capacity to handle the load

174,000

CP#11 The change is required to cover the variance between the estimated construction costs and the actual bids received for the scope of work.

932,000


CP#14 Increased costs due to delay in P&L; complexities of working at Benalto site; soil conditions differ from PPS estimate

1,128,000

CP-AFUDC#2 AFUDC Reconciliation #2 939


1186. CP#11 was broken down further to show the specific labour rate increases and other

costs. Cost increases attributable to additional work related to $342,000 for a concrete firewall

with caisson foundations (instead of the brick wall assumed in the PPS), $326,000 for an

increased cable amount and $128,000 for foundations and site preparation that were not

anticipated and were required due to a larger than typical transformer. Higher bid prices for

construction labour amounted to a cost increase of $77,000. Factored costs, such as project

management, construction management, procurement and E&S increased in $59,000. AltaLink

stated that no alternatives were considered to address these issues. A portion of the project

contingency ($103,000) was applied against the higher bids to mitigate the financial effect.

However, there was not enough money in the contingency fund to cover the entire variance.1022

1187. CP#14 was also broken down further to list the specific issues that contributed to

increased costs:

Increased project duration due to delayed P&L (six months later than anticipated):

$282,000.

Winter construction premium: $187,000.

Increased complexities of working at Benalto substation; namely, work required to

identify and protect existing underground facilities and coordinating outages: $574,000.

Changes in soil conditions, which impacted the foundation requirements and required

additional excavation, material removal and insulating rock: $85,000.

No alternatives were considered for the delay in P&L. For the increases in scope, AltaLink stated

that the changed proposed represented the best available solution.1023

Commission findings

1188. The Commission has reviewed AltaLink’s submissions in support of the costs associated

with the Red Deer Benalto project, and is satisfied with the explanations provided for the cost

variances from its initial forecast costs. The Commission considers the requested capital amounts

for 2013 of $8,347,437 to be prudent. AltaLink is authorized to add this amount to its rate base.

1022


Exhibit 0139.00.AML-3585, PDF pages 20-21 and 26.


Decision 3585-D03-2016 (June 6, 2016) • 239

4.2.3.11.3 D.0461 – Red Deer Area Transmission – Capbank at Joffre 535S






1190. A detailed breakdown of the Red Deer Area Transmission Development – Joffre

Capacitor Bank Addition (Joffre) project costs at major stages, is provided in Table 44 below:

Table 44. Red Deer Area – Capbank at Joffre 535SS cost breakdown

PPS

June 2011 +/- 10% update Mar 14, 2013



Transmission line materials - - 0 -

Transmission line labour - - 0 -












D: procurement 77,000 70,000 100,000 100,000



D: escalation 86,000 67,000 - -

D: contingency(1) 174,000 391,000 - -

Total distributed costs 972,000 1,867,000 1,370,184 1,548,060

OT: ES&G 133,000 208,000 127,784 1543,254

OT: AFUDC 32,000 2,000 1735 1,735


Source: Exhibit 203.00.AML-3585, PDF pages 20 and 63; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 106 and AML-AUC-2015MAR05-010 Attachment, PDF page 336; and Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. Note: 1) Contingency and escalation line items were combined in the PPS estimate. Disaggregation of contingency and

escalation were provide in Exhibit 3585-X0042, AML-AUC-2015MAR05-015 at PDF page 385. 2) Salvage has been removed from total project costs. 3) Some numbers may not add up due to differences between exhibits in significant digits used.


1191. The Joffre project included alteration of the Joffre 535S substation to add a new capacitor

bank, including modifications to protection and control, SCADA and communications.1026

1024


Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 336. 1026



240 • Decision 3585-D03-2016 (June 6, 2016)

1192. At the direction of the AESO, AltaLink prepared a PPS for the project which estimated





initial application evidence are summarized in Table 45 below:




TCA#6

Funding to construct temporary 138-kV breaker assembly The temporary breaker is required to reduce outages on the radial feed to Joffre and Brookfield plants

270,000


CP#19 Increased costs due to delay in P&L; higher construction bids; and additional requirements after PPS submitted.

1,950,000


CP#39 Rev 2 Late mobilization of electrical sub-contractor resulted in the necessity to re-negotiate planned outages which moved the ISD back approximately 2.5 months. Increased costs due to construction trailer being unavailable locally so were sourced from the US which resulted in shipping and border crossing charges.

206,000


1195. CP#19 was further broken down to show the cost increases attributable to specific issues.

The six-month delay in receiving P&L required restarting construction plans. Conditions had

changed in that time and industrial customers did not support a construction that involved work

during freezing conditions as any unplanned outages required could result in their product

freezing and potentially causing significant damage. AltaLink took this into consideration, along

with the premium that would have resulted from winter construction, and further delayed

construction another six months. The decision to delay resulted in increased costs of

$1.95 million. Of this, $617,000 represented additional construction planning and re-tendering

efforts, $862,000 represented higher construction bids, and the remaining $471,000 was due to

additional or increased requirements, which were identified after additional project planning and

engineering. These requirements included increased levels of construction supervision, safety,

testing, commissioning, planning and communication requirements. Contingency and escalation

funds were not used to cover the cost increases because the project did not have sufficient

contingency funds.1029

1196. The forecast contingency for the Red Deer capacitor bank projects (Joffre, Prentiss and

Ellis) was increased at the time of the PPS update based on the revised risks related to

construction execution requirements specific to each industrial customer that were not known at

the time of the PPS. Specifically, AltaLink indicated that construction tenders had not been

1027





Decision 3585-D03-2016 (June 6, 2016) • 241

awarded at the time of the PPS update and additional contingency was added for potential

pricing increase and schedule risk that could be encountered during contract negotiations due to

the complexities of the job. $76,000 of the contingency estimate was drawn down prior to the

PPS update to provide additional funds to execute engineering and construction planning specific

to the industrial customer’s facility that was not known at the time of the PPS.1030

1197. AltaLink argued that it executed the project efficiently and responded reasonably to the

challenges it faced during the execution of the project so the project costs should be approved as

filed.1031

Commission findings


expenditures on the Joffre project. The Commission understands that the primary reason for cost

variances from the PPS estimate were delays to the construction schedule and planning and re-

work activities associated with the delays in obtaining P&L. The evidence on the record is that

the AESO considered this project to be of an “urgent” nature.” The Commission finds that it was

reasonable for AltaLink to incur additional costs to meet the expectations of the AESO and the

Commission is satisfied with the explanations provided for the variances from initial forecasts

observed in respect of this project. The Commission considers that the requested capital amounts

for 2013 of $4,271,409 were prudently incurred. AltaLink is authorized to add this amount to its

rate base.

4.2.3.11.4 D.0462 – Red Deer Area Transmission - Capbank at Prentiss 276S






1200. A detailed breakdown of the Red Deer Area Transmission Development – Prentiss

Capacitor Bank Addition (Prentiss) project costs at major stages, is provided in Table 46 below:

1030

Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF pages 386-387. 1031





242 • Decision 3585-D03-2016 (June 6, 2016)

Table 46. Red Deer Area – Capbank at Prentiss 276S cost breakdown

PPS

June 2011 +/- 10% update Mar 14, 2013



Transmission line materials - - 0 0

Transmission line labour - 1,000 0 1,445



Telecommunication materials - - 0 0

Telecommunication labour - - 0 0








D: procurement 78,000 81,000 100,000 200,000



D: escalation 91,000 23,000 0 -

D: contingency(1) 184,000 315,000 0 -


OT: ES&G 140,000 171,000 107,687 133,940

OT: AFUDC 32,000 2,000 1,735 3,469


Source: Exhibit 0204.00.AML-3585, PDF pages 16 and 53; Exhibit 3585–X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 107 and AML-AUC-2015MAR05-010 Attachment, PDF page 337; and Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. Note: 1) Contingency and escalation line items were combined in the PPS estimate. Disaggregation of contingency and



1201. The Prentiss project included alteration of the Joffre 276S substation to add a new

capacitor bank, including modifications to protection and control, SCADA and

communications.1034

1202. At the direction of the AESO, AltaLink prepared a PPS for the project, which estimated






1034





Decision 3585-D03-2016 (June 6, 2016) • 243


Change report identifier

Reason or Need



CP#20 Increased costs due to delay in P&L; higher construction bids; additional requirements after PPS submitted.

1,262,000


CP#38 Rev 1 Late mobilization of electrical sub-contractor resulted in the necessity to re-negotiate planned outages which moved the ISD back approximately 2.5 months. Increased costs due to construction trailer being unavailable locally so were sourced from the US which resulted in shipping and border crossing charges.

184,000


1205. CP#20 was largely similar to CP#19 from the Joffre project. The breakdown in CP#20

was as follows:

$546,000 in costs associated delay in P&L due to carrying the project for an additional 12

months, additional construction planning efforts and re-tendering construction contracts.

$556,000 due to higher construction bids, which was a reflection of increases in labour

rates.

$160,000 due to additional or increased requirements, which were identified after

additional project planning and engineering. These requirements included increased

levels of construction supervision, safety, testing, commissioning, planning and

communication requirements.

1206. Contingency and escalation funds were not used to cover the cost increases because the

project did not have sufficient money in the contingency fund.1037





awarded at the time of the PS update and additional contingency funding was added to account

for potential pricing increases and schedule risk that could be encountered during contract

negotiations due to the complexities of the job. $103,000 of the contingency estimate was drawn

down prior to the PPS update to provide additional funds to execute engineering and construction

planning specific to the industrial customer’s facility that was not known at the time of the

PPS.1038

1037


Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF pages 386-387.


244 • Decision 3585-D03-2016 (June 6, 2016)


challenges it faced during the execution of the project, so the project costs should be approved as

filed.1039

Commission findings


expenditures on the Prentiss project. The Commission understands that the primary reason for

cost variances from the PPS estimate were delays to the construction schedule and planning and

re-work activities associated with the delays. The evidence on the record is that the AESO

considered this project to be of an “urgent” nature. The Commission finds that it was reasonable

for AltaLink to incur additional costs to meet the expectations of the AESO and the Commission

is satisfied with the explanations provided for the variances from initial forecasts observed in

respect of this project. The Commission considers that the requested capital amounts for 2013 of

$3,836,700 were prudent. AltaLink is authorized to add this amount to its rate base.

4.2.3.11.5 D.0463 – Red Deer Area Transmission – Capbank at Ellis 332S






1211. A detailed breakdown of the Red Deer Area Transmission Development – Ellis Capacitor

Bank Addition (Ellis) project costs at major stages is provided in Table 48 below:

Table 48. Red Deer Area – Capbank at Ellis 332S cost breakdown

PPS

June 2011 +/- 10% update Mar 14, 2013


Final Cost Report(3)

Dec 19, 2014

Transmission line materials - - - -

Transmission line labour - - - -









O: land - acquisitions 0 35,000 0 0



D: procurement 77,000 90,000 100,000 200,000



D: escalation(1) 78,000 24,000 - -

1039





Decision 3585-D03-2016 (June 6, 2016) • 245

PPS

June 2011 +/- 10% update Mar 14, 2013



Dec 19, 2014

D: contingency 159,000 367,000 - -


OT: ES&G 122,000 199,000 103,939 114,717

OT: AFUDC 30,000 2,000 1,735 1,735


Source: Exhibit 0202.00.AML-3585, PDF pages 18 and 64; Exhibit 3585-X0042, AML-AUC-2015MAR05-003 Attachment, PDF page 108 and AML-AUC-2015MAR05-010 Attachment, PDF page 338; and Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. Note: 1) Contingency and escalation line items were combined in the PPS estimate. Disaggregation of contingency and



1212. The Ellis project included alteration of the Elis 332S substation to add a new capacitor

bank, including modifications to protection and control, SCADA and communications.1042

1213. At the direction of the AESO, AltaLink prepared a PPS for the project which estimated


1214. The project was energized on November 28, 2013.1044








CP#21 Increased costs due to delay in P&L; higher construction bids;

additional requirements after PPS submitted.

2,162,000


CP#40 Increased costs associated with lease negotiation with Dow Chemical Canada (Ellis 332S is in the Dow facilities), delays as a result of the negotiation and outage planning and relocation of a water line.

284,000


1216. CP#21 was largely similar to CP#19 from Joffre and CP#20 from Prentiss. The

breakdown in CP#21 was as follows:

$575,000 in costs associated delay in P&L due to carrying the project for an additional 12

months, additional construction planning efforts and re-tendering construction contracts.

1042





246 • Decision 3585-D03-2016 (June 6, 2016)

In response to an undertaking, AltaLink noted that it was unable to provide a further

breakdown of this amount.1045

$836,000 due to higher construction bids, which was a reflection of increases in labour

rates.

$751,000 due to additional or increased requirements, which were identified after

additional project planning and engineering. These requirements were to meet the

demands of working within the industrial customer’s facilities and included relocation of

a water line, increased levels of construction supervision, safety, testing, commissioning,

planning and communication requirements.

1217. Contingency and escalation funds were not used to cover the cost increases because the

project did not have sufficient money in its contingency fund.1046





awarded at the time of the PS update and additional contingency funding was added to account

for potential pricing increases and schedule risk that could be encountered during contract

negotiations due to the complexities of the job. $99,000 of the contingency estimate was drawn

down prior to the PPS update to provide additional funds to execute engineering and construction

planning specific to the industrial customer’s facility that was not known at the time of the

PPS.1047


challenges it faced during the execution of the project so the project costs should be approved as

filed.1048

Commission findings


expenditures on the Ellis project. The Commission understands that the primary reason for cost

variances from the PPS estimate were due to delays to the construction schedule and planning

and re-work activities associated with the delays. There were additional complexities on this

project because the substation is located within Dow Chemical Canada’s (Dow) facilities and

AltaLink was required to negotiate lease space and outages with Dow.

1221. The evidence on the record is that the AESO considered this project to be of an “urgent”

nature. The Commission finds that it was reasonable for AltaLink to incur additional costs to

meet the expectations of the AESO and to mitigate negative effects on the industrial customer

(Dow). The Commission is satisfied with the explanations provided for the variances from initial

forecasts observed in respect of this project. The Commission considers that the requested capital

1045

Exhibit 3585-X0804. 1046


Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF pages 386-387. 1048



Decision 3585-D03-2016 (June 6, 2016) • 247

amounts for 2013 of $3,577,763 were prudent. AltaLink is authorized to add this amount to its

rate base.

4.2.4 Minor projects

1222. This section includes system projects that were identified in the project schedules,1049 but

which had no supporting documentation filed in the application.

1223. In response to an IR, AltaLink provided a table, which showed the corresponding

application and decision numbers and provided a description of the project and applicable

supporting documents. These supporting documents were not included with the IR response.1050

1224. The projects are as follows:

Project D.0259 – Leismer 72s Capacitor Bank Addition

Project D.0166 – Judy Creek 236S Substation Salvage

Project D.0214 – ENMAX SS-10 69-kV Conversion

Project D.0365 – Surmont Phase II -9L990 Protection Mod

Project D.0478 – 9016R AESO BCC PBX Cross-Connection

1225. In the application, AltaLink requested total additions to rate base in the amount of $3.2

million in 2012 and $1.1 million in 2013 for these projects. The total requested capital additions

for the minor direct assign system projects totalled $4.4 million to the end of 2013, which was

$2.4 million less than the projects’ cost forecasts by AltaLink at the PPS stage. AltaLink

included final costs for the projects totalling $4.4 million.1051

1226. A table of the minor direct assigned system projects costs at major stages, is provided in

Table 50 below:

Table 50. Minor direct assigned system projects costs

PPS estimate +/- 10% update


Final Cost Report

D.0259 – Leismer 72s Capacitor Bank Addition 5,181,708 5,182,000 3,138,779 3,136,397

Project D.0166 - Judy Creek 236S Substation Salvage Project 622,560 Not provided 295,643 298,823

Project D.0214 - ENMAX SS-10 69-kV Conversion Project 844,100 Not provided 839,977 Not provided

Project D.0365 – Surmont Phase II -9L990 Protection Mod 74,000 Not provided 75,324 75,324

Project D.0478 - 9016R AESO BCC PBX Cross-Connection 0 Not provided 8,848 Not provided

Total project costs(1) 6,722,368

Unable to calculate

4,358,571 4,359,369

Source: Calculated from tabs D.0259, D.0166, D.0214, D.0365 and D.0478 in Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. Note: 1) Where final costs were not provided, it was assumed that they were equal to the additions to date.

1049

Exhibit 0006.00.AML-3585. 1050

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 137-143. 1051

Calculated from tabs D.0259, D.0166, D.0214, D.0365 and D.0478 in Exhibit 3585-X0043, AML-AUC-

2015MAR05-042 Attachment. Note: where final costs were not provided, it was assumed that they were equal

to the additions to date.


248 • Decision 3585-D03-2016 (June 6, 2016)

1227. The Leismer 72S capacitor bank addition project included upgrades to the existing

substation by adding two 138-kV capacitor banks and two 138-kV circuit breakers. No

expansion of the substation footprint was required.

1228. The Judy Creek 236S substation salvage project included work associated with

decommissioning and salvaging the Judy Creek 236S substation and connecting the existing

transmission line 536L and 515L together. Line 515L was renumbered as continuation of

526L.1052 In the hearing, AltaLink clarified that any costs related to salvage would not be

included in the requested addition amounts.1053

1229. The ENMAX SS-10 69-kV conversion project was part of a larger South Calgary

transmission system upgrades project and included alteration of the 138-kV transmission line

832L to an in/out configuration at the ENMAX SS-10 substation and re-designating a portion of

the 138-kV transmission line between Sarcee 42S substation and ENMAX SS-10 substation as

693L.

1230. The Surmont Phase II 9L990 protection modification project included a revision of the

existing relay scheme at Leismer 72S substation to be in line with ATCO Electric’s change to the

existing transmission line 9L990.1054

1231. The 9016R AESO BCC PBX Cross-Connection project was required to connect the

AESO and AltaLink’s Private Branch Exchange (PBX) [telecommunications] systems to provide

a direct dial access, independent of current Telus communications, from the AESO to the

AltaLink control centre and AltaLink substations and radio sites.1055 In the hearing,

Ms. Picard-Thompson clarified that telecommunications projects do not increase system capacity

and as such, do not require a NID application. Ms. Picard-Thompson indicated that, for

telecommunications projects such as this, which are at the direction of the AESO, AltaLink

includes the projects in DACDAs, as opposed to general tariff applications.1056

1232. All the projects were self-managed by AltaLink with the exception of the Leismer 72S

capacitor bank addition project, which was executed under the MSA with SNC-Lavalin ATP

Inc.1057

1233. AltaLink provided some variance explanations as follows:

Leismer 72S capacitor bank addition:

o Less structural steel and bus materials were required due to the change in scope.

o Actual E&S rates were less than the PPS estimate and AFUDC was removed.

1052

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 138. 1053


Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 137 and 141. 1055

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 142. 1056


Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379.


Decision 3585-D03-2016 (June 6, 2016) • 249

o Project management costs were greater than the PPS estimate because of project

delays due to the change in scope (i.e., removing the substation expansion) and

technical decisions that needed to be made regarding the reduced scope.1058

AltaLink, in response to an IR, indicated that contingency funds were drawn

down by $92,044 to offset project management cost increases.1059

ENMAX SS-10 69-kV Conversion:

o The time between the PPS estimate and the final ISD of approximately six years,

resulted in escalation in material and labour costs.

o More coordination with ENMAX was required than initially assumed.

o Pathway relocation was necessary due to tower locations, which was not known at

the time of the PPS.1060


Commission in respect of the minor direct assigned system projects, is in Appendix 4.

1235. In argument, the RPG stated that it had limited resources and it was unable to address the

minor system projects. However, the projects appear to be at, or under, budget compared to the

PPS estimates and from that, the RPG assumed that the original PPS estimates costs were

reasonable.1061

1236. AltaLink submitted argument for each of the projects, generally stating the projects

adhered to ISO Rule 9.1.5 and the costs should be approved as filed.1062 AltaLink did not address,

only noted, the RPG’s argument in reply argument.1063

Commission findings


with the minor direct assigned system projects and based on evidence provided, is prepared to

approve the project costs for Leismer, Judy Creek, ENMAX Conversion and PBX as filed, for

the purpose of determining 2012/2013 capital addition amounts.

1238. The Commission does not approve the requested capital additions for Surmont II at this

time. The Surmont II 9L990 project costs were defined as customer costs in the facility

application.1064 Conoco Phillips was the end-use customer for ATCO Electric’s Quigley line and

substation project, which drove the need for AltaLink’s Surmont II 9L990 protection

modification project.1065 AltaLink has provided no evidence on the record of this proceeding to

demonstrate when and why this project was designated a system project and why contributions

were not directed from Conoco Phillips. Without evidence on the record to demonstrate the

1058







Proceeding 1615, Exhibit 0002.00.AML-1615. 1065

Proceeding 1615, Exhibit 0022.00.AML-1615.


250 • Decision 3585-D03-2016 (June 6, 2016)

system benefits, the Commission will not approve the requested additions at this time. AltaLink

is directed to provide evidence in the compliance filing, to support this project as a system

project and to provide evidence, for example by way of a letter from the AESO, that explains

why this project does not merit a contribution from Conoco Phillips. The Commission will

consider the explanation of the system or customer project designation at the time of AltaLink’s

compliance filing.

4.3 Customer projects

4.3.1 Fortis projects

4.3.1.1 Prudence assessment

1239. For the following direct assign projects, Fortis was the market participant:1066

D.0093 – Leduc 325S

D.0172 – Wainwright 51S Transformer Addition

D.0179 – Kirby 651S New Substation

D.0202 – Westwood 422S New Substation

D.0267 – Round Hill New Substation – Lac La Biche Area

D.0281 – Willesden Green 68S Upgrade

D.0283 – Winefred 818S Substation Capacity Upgrade

D.0284 – Thompson New Substation – Lac La Biche Area

D.0388 – Tilley 498S Transformer Upgrade

D.0393 – Bruderheim 127S Upgrade

D.0395 – Whitecourt Industrial 364S Substation Upgrade1067

D.0413 – Amelia 108S Upgrade

D.0425 – Keystone 384S Upgrade

D.0426 – Rimbey 297S Substation Upgrade

D.0427 – Lodgepole 61S Substation Upgrade

D.0435 – Cherhill 338S Substation Transformer Addition

D.0447 – Jackfish 698S New Substation

D.0454 – Ponoka 331S Substation Upgrade

D.0340 – Cynthia 178S Substation Upgrade

D.0277 – Fortis Bruderheim 127S 25-kV Add

D.0336 – Sundre 575S 25-kV Breaker Addition

D.0345 – Moon Lake 131S 25-kV Breaker Addition

D.0357 – Willesden Green 68S Breaker Addition

D.0360 – Onoway 352S Substation Upgrade

D.0485 – BUCCSDC Fortis Airdrie Telecommunication

1240. No supporting documentation was filed in the initial application for D.0340 – Cynthia

178S Substation Upgrade, D.0277 – Fortis Bruderheim 127S 25-kV Add, D.0336 – Sundre 575S

1066

Additional information on the project descriptions, energization dates, and variance explanations can be found

in the relevant project appendices filed with the application. 1067

This was a partial addition project. AltaLink stated that none of the P&Ls issued for this project were

substantially complete at the end of 2013. The additions requested are for the energization of one transformer

(Exhibit 3585-X0442, AML-AUC-2015MAR05-005, PDF page 146).


Decision 3585-D03-2016 (June 6, 2016) • 251

25-kV Breaker Addition, D.0345 – Moon Lake 131S 25-kV Breaker Addition, D.0357 –

Willesden Green 68S Breaker Addition, D.0360 – Onoway 352S Substation Upgrade or D.0485

– BUCCSDC Fortis Airdrie Telecommunication. In response to an IR, AltaLink provided a table

that showed the corresponding application and decision numbers and provided a description of

the project and applicable supporting documents. These supporting documents were not included

with the IR response.1068

1241. In the application, AltaLink requested total additions to rate base in the amount of

$32.3 million in 2012 and $39.2 million in 2013 for these projects. The total requested capital

additions for the Fortis connection direct assigned system projects totalled $71.5 million to the

end of 2013. AltaLink indicated final costs for the projects totalling $294.8 million, which was

$47.1 million more than the projects’ cost forecasts by AltaLink at the PPS stage.

1242. A table of the Fortis connection direct assigned projects costs at major stages, is provided

in Table 51 below:

Table 51. Fortis connection projects costs

PPS

estimate(2) +/- 10%

update(2)

Additions to Dec 31, 2013(2) (4)

Net additions to Dec 31,2013


D.0093 – Leduc 325S 18,566,000 35,159,000 31,816,349 10,025,711 31,928,138

D.0172 – Wainwright 51S Transformer Addition 6,426,000 8,760,694 9,663,280 424,526 9,664,323

D.0179 – Kirby 651S New Substation 19,272,000 18,432,067 17,888,700 13,449,033 18,614,308

D.0202 – Westwood 422S New Substation 14,985,000 18,592,000 17,781,890 8,755,226 17,872,154

D.0267 – Round Hill New Substation – Lac La Biche Area 41,346,000 51,276,220 46,443,247 6,899,221 46,443,247

D.0281 – Willesden Green 68S Upgrade 4,686,000 5,027,000 6,326,616 1,042,628 6,291,377

D.0283 – Winefred 818S Substation Capacity Upgrade 6,840,000 7,102,675 6,594,546 2,921,488 7,136,022

D.0284 – Thompson New Substation – Lac La Biche Area 10,397,000 10,728,195 10,525,328 7,059,496 11,388,422

D.0388 – Tilley 498S Transformer Upgrade 7,885,845 7,713,961 7,196,853 2,139,116 7,289,234

D.0393 – Bruderheim 127S Upgrade 6,716,000 8,329,000 7,253,322 0 7,959,389

D.0395 – Whitecourt Industrial 364S Substation Upgrade 12,245,000 17,939,000 10,288,048 0 16,767,155

D.0413 – Amelia 108S Upgrade 19,126,000 19,381,459 16,507,755 1,464,931 17,333,627

D.0425 – Keystone 384S Upgrade 7,958,000 9,852,000 9,670,357 (131,443) 10,031,044

D.0426 – Rimbey 297S Substation Upgrade 10,340,000 11,465,000 10,942,923 0 11,738,178

D.0427 – Lodgepole 61S Substation Upgrade 5,919,000 7,455,000 6,554,137 1,282,637 7,291,672

D.0435 – Cherhill 338S Substation Transformer Addition 7,097,145 9,570,000 8,387,196 0 9,174,442

D.0447 – Jackfish 698S New Substation 32,304,000 41,301,697 36,909,808 9,747,983 40,028,702

D.0454 – Ponoka 331S Substation Upgrade 6,982,000 8,415,000 7,069,217 0 7,737,380

1068

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 137-143.


252 • Decision 3585-D03-2016 (June 6, 2016)

PPS

estimate(2) +/- 10%

update(2)




D.0340 – Cynthia 178S Substation Upgrade 778,000 Not available 1,415,254 1,415,254 1,415,254

D.0277 – Fortis Bruderheim 127S 25-kV Add 695,000 Not available 719,308 726,321 726,302

D.0336 – Sundre 575S 25-kV Breaker Addition 1,498,606 Not available 2,261,097 687,999 2,287,835

D.0345 – Moon Lake 131S 25-kV Breaker Addition 2,149,974 Not available 2,582,855 2,457,981 2,545,270

D.0357 – Willesden Green 68S Breaker Addition 371,000 Not available 365,379 342,527 365,379

D.0360 – Onoway 352S Substation Upgrade 2,186,000 Not available 2,109,486 0 1,993,491

D.0485 – BUCCSDC Fortis Airdrie Telecommunication(3) 976,256 Not available 774,666 774,666 774,666


Unable to calculate

278,024,765 71,485,301

294,797,011

Source: Exhibit 0112.00.AML-3585, PDF page 27; Exhibit 0120.00.AML-3585, PDF page 2; Exhibit 0121.00.AML-3585, PDF page 2; Exhibit 0209.00.AML-3585, PDF pages 25, 344 and 346; Exhibit 0197.00.AML-3585, PDF pages 27, 417 and 419; Exhibit 0164.00.AML-3585, PDF page 24; Exhibit 0172.00.AML-3585, PDF page 2; Exhibit 0173.00.AML-3585; Exhibit 0206.00.AML-3585, PDF pages 23, 383 and 385; Exhibit 0213.00.AML-3585, PDF pages 19, 353 and 355; Exhibit 0214.00.AML-3585, PDF pages 19, 315 and 317; Exhibit 0198.00.AML-3585, PDF pages 22, 395 and 397; Exhibit 0208.00.AML-3585, PDF pages 13, 316 and 317; Exhibit 0188.00.AML-3585, PDF pages 22, 372 and 377; Exhibit 0212.00.AML-3585, PDF pages 23, 462 and 468; Exhibit 0200.00.AML-3585, PDF pages 21, 350 and 351; Exhibit 0196.00.AML-3585, PDF pages 23, 321 and 326; Exhibit 0205.00.AML-3585, PDF pages 23, 354 and 359; Exhibit 0199.00.AML-3585, PDF pages 22, 284 and 289; Exhibit 0189.00.AML-3585, PDF pages 21, 365 and 370; Exhibit 0101.00.AML-3585, PDF page 28; Exhibit 0109.00.AML-3585, PDF page 2; Exhibit 0110.00.AML-3585, PDF page 2; Exhibit 0201.00.AML-3585, PDF pages 23, 345 and 347; and calculated from tabs Totals, D.0093, D.0172, D.0179, D.0202, D.0267, D.0281, D.0283, D.0284, D.0388, D.0393, D.0395, D.0413, D.0425, D.0426, D.0427, D.0435, D.0447, D.0454, D.0340, D.0277, D.0336, D.0345, D.0357, D.0360 and D.0485 in Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment.

Note: 1) Where final costs were not provided, the estimate at complete amounts from Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment were used.

2) Salvage has been removed from project costs. 3) Final costs were assumed to be equal to additions to date.

4) Additions are gross amounts, contributions have not been netted out.

1243. All the projects were executed under the MSA with SNC-Lavalin ATP Inc. with the

exception of the following: D.0388 – Tilley 498S Transformer Upgrade, which was executed

under the relationship agreement with Burns and McDonnell; D.0393 – Bruderheim 127S

Upgrade, D.0395 – Whitecourt Industrial 364S Substation Upgrade and D.0435 – Cherhill 338S

Substation Transformer Addition, which were executed under the relationship agreement with

SNC-Lavalin ATP Inc.; and D.0340 – Cynthia 178S Substation Upgrade, D.0277 – Fortis

Bruderheim 127S 25-kV Add, D.0336 – Sundre 575S 25-kV Breaker Addition, D.0345 – Moon

Lake 131S 25-kV Breaker Addition, D.0357 – Willesden Green 68S Breaker Addition, D.0360 –

Onoway 352S Substation Upgrade and D.0485 – BUCCSDC Fortis Airdrie Telecommunication.

These were self-executed by AltaLink.1069

1244. The following projects also applied the risk reward mechanism to completion: D.0388 –

Tilley 498S Transformer Upgrade, D.0393 – Bruderheim 127S Upgrade, D.0395 – Whitecourt

1069



Decision 3585-D03-2016 (June 6, 2016) • 253

Industrial 364S Substation Upgrade and D.0435 – Cherhill 338S Substation Transformer

Addition.1070 As set out in Section 4.1.14.3, the Commission has directed the removal of any risk

reward mechanism costs from applicable capital projects.

1245. In argument, the RPG stated that it had limited resources and was unable to address the

customer projects. It conducted a high level analysis that showed several projects had costs

above the PPS and several projects had cost variances of greater than 20 per cent, though some

of those projects costs may be offset by customer contributions. The RPG recommended that the

Commission direct additional analysis by AltaLink to provide additional explanations for the

cost variances, possibly using a price-quantity analysis so that further examination of the cost

increases may be completed.1071

1246. AltaLink rejected the RPG’s recommendation arguing that the RPG had the opportunity

to adduce contrary evidence to show imprudence but had not done so and, therefore, AltaLink’s

costs can be presumed to be prudent.1072

Commission findings

1247. The Commission has reviewed these projects and found AltaLink’s requested rate base

addition to December 31, 2013, to represent prudent costs for most of the Fortis direct assign

projects. However, for some projects, the Commission was unable to reconcile the amount that

AltaLink indicated as the gross addition to rate base to December 31, 2013, with other evidence

filed on the record.

1248. Six projects, as listed in Table 52 below, were identified as irreconcilable. In some cases,

the final cost amount shown in the overall summary provided in the “totals” tab or in individual

project tabs of Exhibit 3585-X0043, is different from the final cost amount reported by the

AESO in final cost reports filed with the application or provided in summaries of AESO

customer contribution decisions in exhibits 3585-X0778, 3585-X0779, and 3585-X0780.

1249. The amount that the Commission is prepared to approve as a capital addition in this

decision and the source of that amount, is set out below.

Table 52. Summary of Fortis direct assigned project capital addition adjustments

Project ID

Project Name

Approved Addition Amount

($) Source of Capital Addition Used

D.0360 Onoway 1,993,491 Exhibit X0043, project tab, final cost amount

D.0426 Rimbey 10,942,923 Exhibit X0043, project tab, LTD actual additions to December 31, 2013

D.0427 Lodgepole 6,554,137 Exhibit X0043, project tab, LTD actual additions to December 31, 2013

D.0435 Cherhill 8,387,196 Exhibit X0043, project tab, LTD actual additions to December 31, 2013

D.0447 Jackfish 36,909,808 Exhibit X0043, project tab, LTD actual additions to December 31, 2013

D.0454 Ponoka 7,069,217 Exhibit X0043, project tab, LTD actual additions to December 31, 2013

1250. For these projects, AltaLink is directed to confirm in the compliance filing, the actual

final cost of the project, the portion of that final cost to be accounted for as trailing costs in a

1070





254 • Decision 3585-D03-2016 (June 6, 2016)

future DACDA, the amount of the project to be paid for by a customer contribution and the

amount deemed to be a system cost and the source of those amounts.

BUCCSDC Fortis Airdrie Telecommunication

1251. While the BUCCSDC Fortis Airdrie Telecommunication project (D.0485) is represented

as a customer project in the cost breakdown on the totals tab of Exhibit 3585-X0043,1073 AltaLink

explained in the hearing that if the project was undertaken at the request of the AESO and that,

as a result, no contribution was paid for the project. Effectively, the Commission understands

project D.0485 to be a system classified project that it undertook at the request of the AESO,

without a NID application. Accordingly, project D.0485 is different from the Athabasca Area

Telecom Development project (D.0238), which was completed following the approval of an

AESO NID application, but which was classified as a system-related project for the purposes of

the AESO’s contribution policy.

1252. Although the Commission accepts the gross addition to rate base to December 31, 2013

in the amount of $774,666 for the BUCCSDC Fortis Airdrie Telecommunication project, the

Commission finds the circumstances to be similar to the telecom-related projects that were the

subject of AltaLink’s 2009-2010 GTA. In that application, AltaLink applied for approval of

Power System Risk Mitigation (PRSM) projects as a distinct program, on the basis that it was

similar to AltaLink’s application for approval of capital replacement and upgrade program

forecasts and actuals within GTA proceedings.

1253. In Decision 2009-151, the Commission took note of the fact that the application evidence

for the PSRM project expenditures included correspondence from the AESO that supported the

expenditure. On the basis of this letter of support, the Commission indicated that the projects

should have been submitted as direct assign projects that would be subject to the NID application

process.1074 AltaLink requested a review and variance of this finding, which was granted in

Decision 2010-147.

1254. In Decision 2011-453, the Commission determined that a Stage 2 variance proceeding

was not required and stated “… that it would be of assistance if AltaLink would highlight PSRM

projects in future AltaLink GTAs. The Commission leaves it up to AltaLink to decide whether it

wants to do this as part of its CRU forecast or as a separate section within its application.”1075 Accordingly, the Commission directs AltaLink to clarify its position as to the venue for the

consideration of telecom-related projects in its compliance filing application, pursuant to this

decision.

4.3.1.2 Contributions and capital trackers

1255. The detailed examination of projects in this proceeding has raised certain issues that may

need to be considered in the context of other tariff decisions. The Commission’s examination of

the direct assigned connection projects where Fortis Alberta is the market participant has raised

concerns of this nature.

1073

Transcript, Volume 6, pages 1204-1206 and Transcript, Volume 7, pages 1275-1276. 1074




Decision 3585-D03-2016 (June 6, 2016) • 255

1256. In Decision 2014-283, in respect of the 2012 transmission deferral accounts application

of ATCO Electric Ltd, the Commission made the following finding:

113. Certain end-use customer connection projects that ATCO included for

consideration within the application experienced significant variances attributed to cost

line items such as construction management or project management. While the increases

attributed to such line items were significant in some instances, the Commission is not

concerned by such increases in circumstances where the costs were incurred primarily to

meet an end-use customer’s need for timely service, and the end-use customer that

ultimately benefited pays for the associated incremental costs through an increased

contribution.

114. Accordingly, the Commission has, as and when appropriate, taken into account

the existence and amount of a customer contribution in its assessment of the prudence of

amounts sought by ATCO in relation to certain projects.1076

1257. The Commission’s findings above reflected the extent to which the Commission

scrutinized the costs of ATCO’s direct assigned connection projects. In particular, a customer

may be causing forecast costs to be higher to meet that customer’s needs, because the customer

would also be responsible for paying these costs in the form of an increased customer

contribution, other ratepayers are protected. Payment for any additional costs falling above the

investment allowance permitted under the AESO tariff’s contribution policy sends a proper price

signal to the end-use customer.

1258. In Exhibit 3585-X0772, AltaLink provided a reconciliation between the contribution

addition amounts set out by AltaLink in Exhibit 3585-X0043 and the AESO customer

contribution amounts for which Fortis had requested capital tracker treatment in recent Fortis

tariff proceedings. AltaLink’s table added explanatory notations.1077

1259. For example, AltaLink explained that the Kirby 651S (D.0179) and Thompson New

Substation (D.0284) projects do not show a Fortis contribution amount because they are both

Fortis direct connect transmission projects. In addition, during the oral hearing, these two

projects were referred to as “flow-through” direct connect projects.

1260. With regard to these projects, because the end-use customer is driving the requirements

for each project and must pay any incremental cost above the investment allowance determined

in accordance with the AESO’s tariff, other rate payers are not harmed by any excessive costs.

Although the end-use customers could be concerned with the cost of the connection facilities

constructed by AltaLink, no evidence was filed by these end-use customers in this proceeding to

express any such concerns.1078

1261. For all other Fortis direct assigned connection projects in the current proceeding,

AltaLink’s reconciliation indicates that for any contribution addition that AltaLink has recorded

in the current proceeding,1079 Fortis has requested a corresponding amount as a flow-through item

1076




Note: In Exhibit 3585-X0772 no contribution for either AltaLink or Fortis is shown for projects D.0277,

D.0357 and D.0485.


256 • Decision 3585-D03-2016 (June 6, 2016)

under its tariff.1080 For these projects, the same considerations as found in Decision 2014-283,

cannot apply.

1262. Although the AESO is involved in the preparation of NID applications for Fortis direct

assigned connection projects that may be triggered by requests for increases in Fortis’ DTS

contract capacity, the AltaLink panel confirmed during cross examination that language that is

commonly included in AESO NID applications for Fortis projects results in the driver of the

project being Fortis, not the AESO:1081

Q. Okay. Would you conclude, from reading this clause, that the DFO, not the AESO, is

the driver of the project, although the AESO does some cross-checking, but primarily to

reconcile it's long-term plan load forecast with load forecast information provided by the

DFO?

A. MS. PICARD-THOMPSON: So I think I would agree to that.

A. MS. PICARD-THOMPSON: And I believe, more specifically to the point relative to

the interaction that we have with Fortis, they are the ones who make the determination

between a distribution or a transmission solution, and the AESO supports them in their

choice.

[…]

A. MS. PICARD-THOMPSON: In this particular case, they are the ones that bring -- if

you could say bring the project to us in the sense that as they're looking for making a

decision between whether they would use a distribution solution or a transmission

solution, when they decide that it's a transmission solution, that

conversation occurs with the AESO and they are the ones who, if I can use the term

promote the transmission solution.

1263. The AltaLink witness panel also confirmed its understanding that Fortis independently

determines the level of the DTS contract capacity that it enters into with the AESO, and that this

decision drives the level of the investment that is granted to Fortis in accordance with the

AESO’s tariff.1082 Accordingly, because the investment coverage determined by Fortis’ decisions

on DTS contract levels determines the residual contribution that must be paid (project cost less

investment allowance equals contribution), it follows that Fortis’ decisions are setting

contribution levels.

1264. A summary of DTS contract levels and contributions for the Fortis direct assign projects

(other than Kirby 651S and Thompson New Substation) included in the current application, is set

out below:

1080

In some cases, AltaLink explanatory notes indicate that the AltaLink contribution addition amount and Fortis

addition amount do not align due to timing differences between cash received and the date of addition. In each

case where there is a small difference, the amount that Fortis has accounted for as a flow through item under

its tariff is greater than the contribution addition amount shown by AltaLink. 1081


Transcript, Volume 6, page 1129.


Decision 3585-D03-2016 (June 6, 2016) • 257

Table 53. Contributions and DTS contract levels on Fortis direct assign connection projects

Project Number Project Name

DTS Increase

(MW) Contribution

($)

D.0093 Leduc 325S 28.0 21,790,638

D.0172 Wainwright 51S Transformer 4.4 9,238,754

D.0202 Westwood 422S Substation 19.6 9,026,664

D.0267 Round Hill New Substation 12.3 39,544,026

D.0283 Winefred 818S Substation Upgrade 24.4 3,673,058

D.0388 Tilley 498S Transformer Upgrade 15.4 5,057,737

D.0393 Bruderheim 127S Upgrade 4.9 7,253,322

D.0395 Whitecourt Industrial 364S Upgrade 4.0 10,288,048

D.0413 Amelia 108S Upgrade 48.2 15,042,824

D.0425 Keystone 384S Upgrade 1.6 9,801,800

D.0426 Rimbey 297S Substation Upgrade 4.1 10,942,923

D.0427 Lodgepole 61S Upgrade 10.6 5,271,500

D.0435 Cherhill 338S Substation Transformer 0 8,387,196

D.0447 Jackfish 698S New Substation 50.8 27,161,602

D.0454 Ponoka 331S Substation Upgrade 0.2 7,069,217

D.0340 Cynthia 178S Upgrade 9.6 0

D.0277 Bruderheim 127S 25kV Transformer 7.2 0

D.0336 Sundre 575S 25 kV Breaker 2.5 1,573,098

D.0345 131S Moon Lake 25 kV Breaker 11.5 124,874

D.0281 Willesden Green 68S Upgrade 5.9 5,283,988

D.0360 Onoway 352S Substation Upgrade 0 2,109,486

Source: Prepared by the Commission from Exhibit 3585-X0043; Exhibit 3585-X0778; Exhibit 3585-X0779; Exhibit 3585-X0780; Exhibit 3585-X0806.

1265. For a number of Fortis direct assigned projects within AltaLink’s current application,

either a very low (e.g., D.0425 – Keystone; D.054 Ponoka) or even zero (e.g. D.0340 – Cynthia;

D.0277 Bruderheim transformer; D.0435 – Cherhill 338S; D.0360 - Onoway) DTS contract level

increase request is setting the amount of the contribution determined by the AESO. Fortis’

decision to request a low or zero DTS contract level means that the AESO’s investment

allowance provides little or no coverage of the cost of Fortis connection projects.

1266. Unlike the connection projects of AESO direct-connect or Fortis flow-through end-use

customers, where the end-use customer must pay all costs above the maximum investment

allowance under the AESO tariff’s contribution policy, allowing capital tracker treatment for the

AESO contribution amount on Fortis projects other than those under flow-through Fortis rates

may not provide an adequate signal to end-use customers when it is the primary end-use

customer’s requirements or timing that is causing higher costs to meet specific demands.

1267. The Round Hill 852S substation project (D.0267), which was a very expensive customer

connection project that was constructed in an impressively short period of time, represents an

example of this problem. AltaLink witnesses confirmed during cross examination, that the

Round Hill project was the most expensive connection project considered by the AESO in the

assessment of the POD (point of demand) cost function for various purposes within the AESO’s

tariff, including the determination of maximum investment levels.1083 The AESO’s June 20, 2011

NID application for the Round Hill project, indicated that this project was initially targeted to be

1083

Exhibit 3585-X0760, referenced at Transcript, Volume 6, page 1172.


258 • Decision 3585-D03-2016 (June 6, 2016)

in service by July 2012.1084 AltaLink’s records for the current proceeding indicate that initial

energization occurred on March 24, 2012, four months ahead of schedule.1085

1268. The effect of the accelerated pace of the construction of this project on the cost of this

project, may not have been fully considered in the assessment of the weighting to give to the cost

of this project in establishing investment levels for the AESO tariff contribution policy. Based on

evidence within the current proceeding, the Commission considers that the aggressiveness of the

in-service date for this project manifested in areas such as the high camp costs, accrued to the

project. In addition, the evidence on the record suggests that while Fortis was the market-

participant of record, the primary proponent of the accelerated completion of the project was

Enbridge.1086

1269. Further, because the AESO’s POD cost function attempts to assess the relationship

between the capacity of POD facilities and cost, the contribution policy is affected by the initial

DTS contract level requested by Fortis for this project. In an exhibit provided in error by

AltaLink on the record of the current proceeding, a second project at the Round Hill 852S

substation was undertaken on behalf of Fortis, with a much lower cost than the first project, but

which aligned with a higher DTS capacity request. Accordingly, to the extent that the POD cost

function analysis represents an attempt to capture a systematic relationship between capacity and

cost, a more accurate representation of this relationship for the Round Hill project within the

POD cost function assessment, would have been the combined cost of the two projects, with the

relationship assessed on the basis of the combined DTS capacity requests for the two projects.

1270. In addition to the Commission’s concern that the Round Hill project may have distorted

the POD cost function analysis, the Commission’s major concern with this project relates to the

capital tracker treatment applied to the AESO contribution for this project within Fortis’ tariff. In

this regard, the Commission notes that Fortis requested capital tracker treatment totalling

$40,861,441 for the Round Hill project.1087 This amount corresponds exactly to the customer

contribution amount initially determined for the project in the AESO’s customer contribution

decision.1088 This suggests that no amount of the contribution that Fortis paid was passed on to

Enbridge. Accordingly, while the Commission accepts AltaLink’s submission that load

requirements beyond those of Enbridge may have driven Fortis’ assessment of the ultimate need

for the project, the Commission nevertheless considers that the requirements of Enbridge

affected the accelerated pace of the project and likely significant corresponding costs.

1271. The Commission considers that because the application of the contribution policy makes

customers indifferent to the ISD, all customers may be paying for the costs of building to an

aggressive ISD target that is being driven by one customer. This issue should be further

investigated in future Fortis tariff proceedings.

1084


Exhibit 3585-X0043, “energizations” tab. A subsequent energization date of August 15, 2012 is also noted. 1086

At PDF page 165 of Exhibit 0206.00.AML-3585, TCA#2 indicates that a cost increase of $1,472,986 for

camp costs primarily arose from discussions between AltaLink, Enbridge, and the camp provider (Horizon).

The scope change documentation attached to TCA 02 (Exhibit 0206.00.AML-3585, PDF page 167) refers to

the project as “Enbridge RoundHill.” 1087

Exhibit 3585-X0772. 1088



Decision 3585-D03-2016 (June 6, 2016) • 259

4.3.1.2.1 Contribution on D.0179 – Kirby 651S New Substation (D.0179)

1272. The Commission has reviewed AltaLink’s evidence in support of expenditures on the

Kirby 651S new substation project and, taking into account findings discussed in Section 4.3.1.2

that the ultimate end-use customer Canadian Natural Resources Ltd. (CNRL) is required to pay

participant-related costs above the investment allowance provided for by the AESO’s tariff, the

Commission is satisfied that the gross addition amount for this project to December 31, 2013 in

the amount of $17,888,700 should be approved as filed.

1273. However, apart from its findings related to the prudence of AltaLink’s expenditures on

this project, the Commission is concerned about the reasonableness of the customer contribution

addition that was established for this project by the AESO. The Commission’s concerns relate to

the AESO’s determination that costs totalling $4,033,971 relating to the temporary use of mobile

capacitor banks, should be treated as system-related costs, rather than participant-related costs

for the purposes of the application of the AESO’s customer contribution policy.

1274. The decision to designate costs related to the temporary capacitor banks as system-related

costs was raised with the AltaLink witness panel during the oral hearing.1089 Part of the rationale

offered by AltaLink witnesses was that, since the AESO has a duty to build in advance of the

need to connect load, and since the need to connect CNRL was urgent and could not have been

accommodated by waiting for the completion of the Christina Lake project, the costs of

temporary capacitor banks were necessary, system-related costs to accommodate the

requirements of CNRL. This view seems to be in evidence in comments provided by

Mr. Watson, provided below:

A. MR. WATSON: Yeah. Because -- I mean, in an ideal world, you would have all your

transmission built ahead of its need.

Christina Lake was a particular area where load growth did kind of get ahead of us, and

this was a temporary measure to support that customer until the 240 could get backfilled

into that.1090

1275. The Commission considers this rationale to have been rejected in Decision 2014-242.1091

In its 2014 tariff application, the AESO proposed to eliminate subsection 3(2) of Section 8 of its

tariff terms and conditions pertaining to the advancement of planned transmission facilities.1092

The Commission stated:

470. The Commission considers that the exercise of the AESO’s discretion in the

context of its duty to manage the timing for the construction of an uncongested system

safely and economically is relevant to the Commission’s assessment of whether, and to

what extent, costs related to the advancement of system projects, driven at the request of

a market participant, should be designated as a participant-related cost and paid for by the

requesting market participant.

1089






260 • Decision 3585-D03-2016 (June 6, 2016)

1276. The record of the current proceeding indicates that temporary capacitor banks were

provided in order accommodate an in-service date requested by CNRL, and that these facilities

were to be removed when the Christina Lake project was completed.1093 Given this, the

Commission considers that the costs of these temporary facilities was driven by the in-service

date requested by CNRL, and, as such, should have been classified as a participant-related cost

under the customer contribution policy in effect for the Kirby 651S project.

1277. The Commission considers the following testimony of the witness for IPCAA, Ms.

Bellissimo, who provides insight in the assessment of how costs arising from the timing of

service requested by end-use customers of the transmission system, should be classified:

A. MS. BELLISSIMO: Yes. Actually, when you describe the difficulty in reconciling

customers wanting their projects connected yesterday and other customers wanting their

rates to be low, I think you just described my job. It's a -- it's a difficult balancing act. I

think how we've tried to address it within IPCAA is to try to engage the AESO as much

as we can on project delays, so we've actually had them come to board meetings and have

gone around the room and said: Can everyone talk through, you know, what their

company's approach to commodity price drop has been? What kind of projects you're

delaying? What your timelines look like? And make sure that that's on the AESO's radar,

especially when they're engaged in their long-term planning process. I think that's

something that we could probably engage the TFOs on further and that might be one of

our initiatives going forward. It is certainly a difficult balancing act.

And when we've talked about it with the AESO, what they do is they get essentially a

slew of in-service requests that they probably couldn't meet if they wanted to meet them,

and a lot of those projects will either be cancelled or pushed out.

And so they're essentially building a model that takes into account haircuts on all of these

projects, and that's a difficult task for them to do. However, some of the things that Mr.

Levson has mentioned today, including going out to visit sites, would really help them.

Building a better relationship with customers so that customers didn't feel the need to

emphatically state we need this on this timeline, and they weren't worried that the

customer connection was going to be the aspect of their big capital project that would be

the last -- last thing that got into service. There's a lot of moving parts here obviously, but

these are some of the things that we're working on.

1278. The AESO registered as an interested party for Proceeding 3585 but did not actively

participate. As the administration of the AESO’s customer contribution policy is done by the

AESO itself, the Commission directs AltaLink to contact the AESO for the purposes of obtaining

the AESO’s assessment of customer contribution decisions for the Kirby 651S project in light of

the findings set out in this decision. AltaLink is directed to provide a summary of the AESO’s

recommendations in respect of the contribution on the Kirby 651S project at the time of its

compliance filing. The Commission will assess the amount of the contribution addition to

December 31, 2013 for the Kirby 651S project at that time.

1093



Decision 3585-D03-2016 (June 6, 2016) • 261

4.3.1.3 Fortis non direct assign projects

1279. In AML-AUC-2015-MAR05-004, the Commission sought additional clarification about

projects included in the application,1094 for which AltaLink provided limited background

documentation. In its response to this IR, AltaLink explained that a number of the limited

documentation projects included in the application were not direct assigned projects. In addition,

within description information provided by AltaLink in its AML-AUC2015MAR05-004

response, a number of these non-direct assigned projects were identified as projects that were

undertaken at the request of Fortis. The projects were customer projects that were 100 per cent

funded by the customer; thus, no amounts are requested to be added to rate base in this

application. In the project description information provided in the IR response, AltaLink

indicated that no NID or other applications were filed (with the exception of the Transfer Trip

Harmattan 256S – 228L project for which AltaLink filed a letter of enquiry with the

Commission, which was considered in Proceeding 1634 and approved in Decision

DA2011-1701095), nor are there any applicable AESO supporting documents. No other supporting

documentation was filed for these projects.1096

1280. In the hearing, Ms. Picard-Thompson stated that non-direct assigned projects were not

intended to be submitted in a DACDA, as opposed to a general tariff application, but AltaLink

does not intend to remove the projects from this application.1097

1281. The following projects were identified as non-direct assigned projects where Fortis was

the customer:

D.0372 – ECB Enviro – Transfer Trip at North Lethbridge

D.0342 – Re-Conductoring at Rundle

D.0421 – Fortis Brazeau River BTF

D.0484 – Strathmore 151 Transfer Trip

D.0505 – Benbow 397S BTF

D.0361 – Transfer trip Harmattan 256S-228L

1282. A table of the Fortis non-direct assigned project costs at major stages, is provided in

Table 54 below:

1094

These projects were identified in the project schedules submitted in Exhibit 0006.00.AML-3585. 1095

Decision DA2011-170, AltaLink Management Ltd., Harmattan 256S substation development,

Proceeding 1634, Application 1607992-1, December 29, 2011. 1096

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 136, 140, 141, 142 and 143. 1097



262 • Decision 3585-D03-2016 (June 6, 2016)

Table 54. Fortis non-direct assigned projects costs

PPS

estimate(1)


(2) Net additions to

Dec 31,2013 Final Cost Report(1)

D.0372 - ECB Enviro - Transfer Trip at North Lethbridge 139,000 266,283 0 266,283

D.0342 - Re-Conductoring at Rundle 16,536 1,067 0 27,790

D.0421 - Fortis Brazeau River BTF Project 56,000 12,487 0 12,487

D.0484 - Strathmore 151 Transfer Trip 112,000 130,113 0 96,323

D.0505 - Benbow 397S BTF(3) 80,000 19,155 0 19,155

D.0361 - Transfer trip Harmattan 256S-228L 119,867 141,532 0 141,534

Total project costs 523,403 570,637 0 563,572

Source: Calculated from tabs Totals, D.0372, D.0342, D.0421, D.0484, D.0505 and D.0361 in Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment and Totals tab in Exhibit 3585-X0794. Note: 1) Salvage has been removed from project costs. 2) Additions are gross amounts, contributions have not been netted out. 3) Final costs were assumed to be equal to additions to date. *These amounts to be removed in an application amendment so total additions will be $0.

1283. The ECB Enviro – Transfer Trip at North Lethbridge project included work at North

Lethbridge 370S substation to facilitate the interconnection of a customer generator at the

request of Fortis. AltaLink initially inadvertently included $266,283 in capital additions in

Schedule 7-4, which, in response to an IR, AltaLink indicated would be corrected to remove the

amounts.1098 1099 This project was energized on September 27, 2012.

1284. The Re-Conductoring at Rundle project included re-conductoring 64L and 2286L

distribution feeder lines for Fortis.

1285. The Fortis Brazeau River BTF project included metering and telecommunications

changes to accommodate a customer’s needs at the Brazeau River 498S substation. This project

was energized on November 7, 2012.

1286. The Strathmore 151 Transfer Trip project included modifications to the existing transfer

trip scheme for Fortis. This project was energized on April 24, 2013.

1287. The Benbow 397S BTF project included re-energization of a transformer at the Benbow

397S substation to accommodate new load.

1288. The Transfer trip Harmattan 256S-228L project included replacing existing conductor of

the first three-phase span of the 25–kV feeder line 228L within the substation and associated

substation upgrades. This project was energized on March 2, 2012.1100 1101

1289. All the projects were self-executed by AltaLink.1102

1098

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 136 and 142. 1099

According to AltaLink witnesses at Transcript, Volume 5, page 983, this correction was made within the IR

response. Exhibit 3585-X0794, which is the updated project schedules, shows net additions for this project

have been removed in the Totals tab. 1100

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 136, 140-143. 1101

Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, Energizations tab.


Decision 3585-D03-2016 (June 6, 2016) • 263

1290. None of these projects were addressed by interveners in evidence, or in argument and

reply.

Commission findings

1291. The Commission has accepted AltaLink’s explanations for the inclusion of these projects

in the current application and notes that AltaLink has indicated that it will improve its filtering

process so that non-direct assigned projects will not be included in future DACDAs.1103 There are

no requested additions to rate base; therefore, the Commission is not required to make any

findings on the prudence of these projects.

4.3.2 Non-Fortis connection projects

4.3.2.1 Non-Fortis direct assign projects

1292. The following projects were direct assigned customer projects for which Fortis was not

the market participant:1104

D.0073 – Castle Rock Ridge (CRR) Wind Farm Interconnection

D.0275 – Abee New Substation – Lac La Biche Area

D.0279 – Weasel Creek New Transmission Line – Lac La Biche Area1105

D.0383 – Cope Creek Interconnection

D.0407 – Sunday Creek 539S Connection

D.0434 – Greengate – Blackspring Ridge Wind Farm Interconnection

D.0041 – Picture Butte 120S (MATL)

D.0410 – East Calgary Transmission/Shepard Energy Centre Interconnection

D.0191 – NRGreen Chickadee Creek 259S Substation Interconnection

D.0263 – EPCOR Poundmaker Substation

D.0376 – Enbridge Vermillion (Bauer)

D.0381 – Enbridge Chard Project

D.0398 – WISP Synchrophasor PMU Upgrade

D.0482 – Halkirk RAS

1293. In the application, AltaLink requested total additions to rate base in the amount of

$31.9 million in 2012 and $26.4 million in 2013 for these projects. The total requested capital

additions for the customer connection direct assigned projects totalled $58.2 million to the end of

2013. AltaLink included final costs for the projects totalling $214.2 million, which was

$45.0 million than the projects’ cost forecasts by AltaLink at the PPS stage.1106

1102



Additional information on the project descriptions, energization dates, and variance explanations can be found

in the relevant project appendices filed with the application. 1105

Abee and Weasel Creek projects were considered together in the NID, PPS, PPS update and facility

application. Separate monthly reporting, change notices and final cost reports for filed for each project. 1106

See sources for Table 55.


264 • Decision 3585-D03-2016 (June 6, 2016)

1294. Of the projects listed above, D.0434 –- Greengate – Blackspring Ridge Wind Farm

Interconnection and D.0410 - East Calgary Transmission Project/Shepard Energy Centre

Interconnection were partial additions.

1295. No supporting documentation was filed in the initial application for the D.0191 –-

NRGreen Chickadee Creek 259S Substation Interconnection, D.0263 –- EPCOR Poundmaker

Substation, D.0376 –- Enbridge Vermillion (Bauer), D.0381 –- Enbridge Chard, D.0398 –- WISP

Synchrophasor PMU Upgrade and D.0482 –- Halkirk RAS projects. In response to an IR,

AltaLink provided a table that showed the corresponding application and decision numbers along

with a description of the project, which identified the documents it relied on to support the

response. The supporting documents identified were not included with the IR response.1107

1296. A table of the direct assigned customer projects costs at major stages, is provided in

Table 55 below:

Table 55. Non-Fortis direct assigned connection project costs

PPS

estimate(2) +/- 10%

update(2)




D.0073 - Castle Rock Ridge (CRR) Wind Farm Interconnection Project 25,244,000 47,907,000 47,780,802 20,599,802 47,780,844(5)

D.0275 - Abee New Substation – Lac La Biche Area(6) 7,361,000 9,875,294 8,872,386 (380,078) 9,696,481

D.0279 - Weasel Creek New Transmission Line – Lac La Biche Area(6) 6,965,000 7,033,528 6,380,502 4,900,050 7,819,089

D.0383 - Cope Creek Interconnection Project 11,302,000 13,116,000 11,709,171 7,320,171 12,653,595

D.0407 - Sunday Creek 539S Connection Project 6,339,000 8,116,000 7,301,034 1,984,584 7,838,318

D.0434 - Greengate – Blackspring Ridge Wind Farm Interconnection 28,023,000 34,600,000 637,516 0 31,929,474

D.0041 - Picture Butte 120S (MATL) 9,140,000 13,505,000 14,891,748 10,979,957 14,958,405

D.0410 - East Calgary Transmission Project/Shepard Energy Centre Interconnection 70,059,000 77,324,000 29,334,655 11,835,655 77,324,000

D.0191 - NRGreen Chickadee Creek 259S Substation Interconnection Project 1,519,000 Not available 2,009,178 77,178 2,004,849

D.0263 - EPCOR Poundmaker Substation 154,500 Not available 186,037 189,107 200,231

D.0376 - Enbridge Vermillion (Bauer) Project 616,000 Not available 479,997 396,390 476,997

D.0381 - Enbridge Chard Project 103,000 Not available 83,565 40,983 90,742

D.0398 - WISP Synchrophasor PMU Upgrade Project(3) 568,000 Not available 282,170 282,170 282,170

D.0482 - Halkirk RAS Project 936,000 Not available 910,044 0 930,218


Unable to calculate 131,258,209 58,225,969 214,181,102

Source: Exhibit 0030.00.AML-3585, PDF page 26; Exhibit 0038.00.AML-3585; Exhibit 0039.00.AML-3585, PDF page 2; Exhibit 0194.00.AML-3585, PDF pages 28, 29, 520, 521 and 522; Exhibit 0210.00.AML-3585, PDF page 287;

1107

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 137-143.


Decision 3585-D03-2016 (June 6, 2016) • 265

Exhibit 0190.00.AML-3585, PDF pages 19 and 401; Exhibit 0207.00.AML-3585, PDF pages 27, 484 and 490; Exhibit 0187.00.AML-3585, PDF pages 26 and 597; Exhibit 0123.00.AML-3585, PDF page 32; Exhibit 0131.00.AML-3585; Exhibit 132.00.AML-3585, PDF page 2; Exhibit 0191.00.AML-3585, PDF pages 51, 997 and 998; Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment, PDF pages 346 and 352; and calculated from tabs Totals, D.0073, D.0275, D.0279, D.0383, D.0407, D.0434, D.0041, D.0410, D.0288, D.0191, D.0263, D.0376, D.0381, D.0398 and D.0482 in Exhibit 3585-X0794, AML-AUC-2015MAR05-042 Attachment. Notes: 1) Where final costs were not provided, the estimate at complete amounts from Exhibit 3585-X0794, AML-AUC-

2015MAR05-042 Attachment were used. 2) Salvage has been removed from project costs. 3) Final costs were assumed to be equal to net additions to date. 4) Additions are gross amounts, contributions have not been netted out.

5) Final cost report was filed January 13, 2013 with the AEO but actual amounts column is titled “estimate at completion” 6) Abee and Weasel Creek projects were considered together in the NID, PPS, PPS update and facility application.

Separate monthly reporting, change notices and final cost reports for filed for each project.

1297. All the projects were executed under the MSA with SNC-ATP with the exception of the

following: D.0191 – NRGreen Chickadee Creek 259S Substation Interconnection Project,

D.0263 – EPCOR Poundmaker Substation, D.0376 – Enbridge Vermillion (Bauer) Project,

D.0381 – Enbridge Chard Project, D.0398 – WISP Synchrophasor PMU Upgrade Project and

D.0482 – Halkirk RAS Project. These projects were self-executed by AltaLink.1108

1298. Some of the key trends and changes that drove project cost variances as set out in


Table 56. Non-Fortis direct assigned connection projects cost variance events

Project Name

Variance between additions to 2013 and PPS estimate High level variance explanation

D.0073 - Castle Rock Ridge (CRR) Wind Farm Interconnection Project

$22.5 million

Scope modifications to includes a additional 4km of new transmission line and the Goose Lake portion of the Fidler project, market escalation, scope changes due to an unanticipated change in foundation type and procedural delays.

D.0275 - Abee New Substation – Lac La Biche Area

$1.5 million Requirement for additional screw piles, market escalation and winter construction.

D.0383 - Cope Creek Interconnection Project

$0.4 million Changes in line foundation design to minimize outage at customer’s site, ISD delays requested by the customer and market escalation.

D.0407 - Sunday Creek 539S Connection Project

$1.0 million Re-design and additional materials required to accommodate a line route change requested by the customer and market escalation.

D.0041 - Picture Butte 120S (MATL)

$5.8 million

Delays associated with MATL challenges (this project began construction five years later than anticipated and land transfers from MATL resulted in further delays), market escalation and additional scope (increase substation capacity).

D.0191 - NRGreen Chickadee Creek 259S Substation Interconnection Project

$0.5 million Increased labour and material costs associated with an ISD change requested by customer.

Source: Exhibit 3585-X0859, AltaLink argument, relevant project sections.

1299. Concerns regarding the transmission line design of the Castle Rock Ridge Wind Farm

Interconnection project were raised by the CCA in evidence, argument and reply. These

concerns were addressed in the common matters – line optimization and design issues section of

this decision (Section 4.1.16).

1108



266 • Decision 3585-D03-2016 (June 6, 2016)

1300. Aside from the transmission line design issues, no other issues were raised by

interveners in evidence, argument or reply regarding these projects.

1301. The RPG did indicate in its argument that it had limited resources and it was unable to

address the connection projects. It conducted a high level analysis, which showed that several

projects had costs above the PPS and several projects had cost variances of greater than

20 per cent, though some of those projects costs may be offset by customer contributions. The

RPG recommended that the Commission direct additional analysis by AltaLink to provide

additional explanations for the cost variances, possibly using a price-quantity analysis so that

further examination of the cost increases may be completed.1109

1302. AltaLink opposed the RPG’s recommendation on the basis that cost variances are not an

indication of imprudence and that the RPG had the opportunity to adduce contrary evidence to

show imprudence, but had not done so.1110

Commission findings

1303. The Commission’s review of these projects revealed that some of these projects reported

significant variances from the PPS estimate that were attributable to delays or requests from the

customers. Although the increases attributed to such line items were significant in some

instances, the Commission has taken into account the existence and amount of a customer

contribution in its assessment of the prudence of amounts sought by AltaLink in relation to

certain projects. In circumstances where the costs were incurred primarily to meet an end-use

customer’s request, and the end-use customer that benefited from the requested change paid for

the associated incremental costs through an increased contribution, the Commission will not

consider AltaLink to have imprudently incurred costs to meet those requests.


with the direct assigned customer connection projects and is satisfied with the explanations

provided for the variances from initial forecasts observed in respect of these projects. The

Commission approves the requested 2012-2013 capital additions for these projects.

4.3.2.2 Non-Fortis customer projects

1305. In AML-AUC-2015-MAR05-004, the Commission sought additional clarification for the

projects1111 for which AltaLink provided limited background documentation. In its response to

this IR, AltaLink explained that a number of these projects that had been included in the

application were not direct assigned projects. Rather, they were customer projects that were

100 per cent funded by the customer thus no amounts were requested to be added to rate base in

this application.

1306. In the hearing, AltaLink’s witness, Ms. Picard-Thompson, stated AltaLink did not intend

to include non-direct assigned projects in a DACDA, as opposed to in a general tariff

application, but that it did not intend to remove the projects from this application.1112

1109



These projects were identified in the project schedules submitted in Exhibit 0006.00.AML-3585. 1112



Decision 3585-D03-2016 (June 6, 2016) • 267

1307. The projects were:

D.0288 – Blue Trail Telecom Wind Farm

D.0405 – Enbridge Kingman 299S 5-kV5kV Upgrades

D.0491 – Shell Scotford BTF

D.0296 – MEG Energy G2 Coms

D.0402 – Cable Termination at North Calder 37S

1308. No supporting documentation was filed in the initial application for any of these projects.

In response to an IR, AltaLink provided a table that showed the applicable application and

decision numbers as well as provided a description of the project and applicable supporting

documents. These supporting documents were not included with the IR response.1113

1309. A table of the non-Fortis customer projects costs at major stages, is provided in Table 57

below:

Table 57. Non-Fortis customer project costs

PPS

estimate(1)


(3) Net additions to Dec

31,2013 Final Cost Report(1)

D.0288 - Blue Trail Telecom Wind Farm 456,850 461,939 0 477,859

D.0405 - Enbridge Kingman 299S 5kV Upgrades 46,000 42,132 (1) 42,132

D.0491 - Shell Scotford BTF 37,000 8,988 0 20,107

D.0296 - MEG Energy G2 Coms Project(2) 80,000 31,560 0 31,560

D.0402 - Cable Termination at North Calder 37S 65,700 93,256 72 93,183

Total project costs 685,550 637,875 71 664,841

Source: Calculated from tabs Totals, D.0288, D.0405, D.0491, D.0296 and D.402 in Exhibit 3585-X0794, AML-AUC-2015MAR05-042 Attachment. Note: 1) Final project costs do not include salvage. 2) Final costs were assumed to be equal to net additions to date. 3) Additions are gross amounts, contributions have not been netted out.

1310. The Blue Trail Telecom Wind Farm project included installation of radio hops

telecommunications poles at several substations for teleprotection, as requested by TransAlta.1114

AltaLink initially inadvertently included $461,939 in capital additions for D.0288 –- Blue Trail

Telecom Wind Farm in Schedule 7-4, which, in response to an IR, AltaLink indicated would be

corrected to remove the amounts.1115

1113

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 137-143. 1114

Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 136, 139 and 142. 1115

According to AltaLink witnesses at Transcript, Volume 5, page 983, this correction was made within the IR

response. Exhibit 3585-X794, which is the updated project schedules, shows net additions for this project

have been removed in the Totals tab.


268 • Decision 3585-D03-2016 (June 6, 2016)

1311. The Enbridge Kingman 299S 5-kV Upgrades project included an upgrade at the Kingman

299S substation at the request of Enbridge. In AltaLink’s argument, it advised that this project

was cancelled.1116

1312. The Shell Scotford BTF project included modifications to existing control modules to

provide their status to Shell.

1313. The MEG Energy G2 Coms project included modifications to protection at Conklin 762S

substation at the request of MEG Energy. This project was energized on September 16, 2012.

1314. The Cable Termination at North Calder 37S project included termination of the 2029L

25-kV feeder circuit in the North Calder 37S substation. This project was energized on March 8,

2012.1117 1118

1315. All the projects were self-executed by AltaLink.1119

1316. None of these projects were addressed by interveners in evidence, nor in argument and

reply.

Commission findings

1317. The Commission has accepted AltaLink’s explanations for the inclusion of these projects

in the current application and notes that AltaLink has indicated that it will improve its filtering

process so that non-direct assigned projects will not be included in future DACDAs.1120

1318. AltaLink has stated that there are no requested additions to rate base however the net

actual additions submitted in the project schedules show $71 of requested additions requested.

Given the amount of the discrepancy, the Commission is prepared to accept AltaLink’s assertion

that it is requesting no additions for these projects to its rate base and approves the $0 amount for

additions for these projects.

4.4 Cancelled projects

1319. Projects that were cancelled following the submission of AltaLink’s 2011-2012 or 2013-

2014 GTA were set out in Schedule 7-4 of Appendix 2 to its application.1121 AltaLink also

provided a version of its cancelled projects table, rounded to the nearest dollar, in a response to

an IR, reproduced below as Table 58:

1116



Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, Energizations tab. 1119



Exhibit 0006.00.AML-3585, tab “Totals.”


Decision 3585-D03-2016 (June 6, 2016) • 269

Table 58. Summary of cancelled projects

Ref. Project Name

2012 Gross

addition

2013 Gross

addition Total

addition Customer Contrib.

Net addition

($)

D.0271 West Cascade 177S 3,672 3,672 3,672

D.0286 Wiau Lake Project 75 75 75

D.0254 Waiparous 639S substation

D.0257 McLauglin Wind Power Facility Connection

D.0282 Altagas ‐ Glenridge Wind Farm Interconnection

D.0293 Vindt ‐ Willowridge Wind Farm Interconnection

D.0347 Devon - Distribution Transfer Trip 23,398 7,347 30,745 (30,745) 0

D.0364 Plasco DG Project

D.0370 Brazeau River Natural Gas Storage Project

D.0385 BioRefinex Transfer Trip-Blackfalds 198S

Total 27,145 7,347 34,492 (30,745) 3,747

Source: Exhibit 3585-X0042, AML-AUC-2015MAR05-025(a), Table 1.

1320. In argument, AltaLink stated that, with the exception of one project, all costs incurred for

the cancelled projects included in its application were recovered from the customer proponent.

With regard to the one exception, AltaLink referred to its IR response to the Commission1122 in

which it explained that for project D.0254 (Waiparous 639S Substation), with the agreement of

both the customer proponent and the AESO, all incurred costs for the Waiparous 639S

Substation project (totalling $1.77 million) were transferred to the Cochrane 291S project

(AESO Project #1450), because the Waiparous 639S Substation was the original option to serve

the same load as the Cochrane 291S project.1123

1321. In reply argument, the RPG submitted that AltaLink’s requested capital addition amount

for cancelled projects represented another area of the application that, due to limited resources, it

was unable to examine in depth. However, the RPG noted that while AltaLink explained in its IR

response to the Commission that $1.77 million in incurred costs for the D.0254 Waiparous 639S

substation project was transferred to the Cochrane 291S project, AltaLink had provided no

details about these costs in the application, beyond mentioning that there was an agreement

between the customer and the AESO to do this.1124 In the table that provided explanations of the

type of costs incurred for the trailing cost projects included in the application,1125 the explanation

provided was: “Scope changes resulting in additional engineering and construction cost.” There

was no mention of the transfer of Waiparous project costs.1126 As there was no adequate evidence

on the record that the $1.77 million in Waiparous costs transferred to the Cochrane projects were

prudently incurred, the RPG submitted that these costs should be disallowed.1127

1322. Further, the RPG submitted that in any further DACDA application where costs

associated with cancelled projects are proposed to be charged to rate base, the Commission

should require AltaLink to provide full disclosure of such costs, including a description of what

1122

Exhibit 3585-X0042 AML-AUC-2015MAR05-025(b). 1123



Exhibit 3585-X0042, AML-AUC-2015MAR05-024, Table7.6-1, PDF page 407. 1126




270 • Decision 3585-D03-2016 (June 6, 2016)

the component of the costs were, an explanation of why the costs were incurred, and any

authorization documents from the AESO.1128

1323. In reply, AltaLink noted that, by its own admission, the RPG did not provide any

evidence regarding the transfer of the D.0254 Waiparous 693S project to AESO Project #1450.

As any finding of imprudence must be based on evidence, and as there was no evidence to

suggest the transfer was imprudent, the Commission must approve this cost as filed.1129

1324. In its reply, the RPG submitted that stating that Cochrane was the original option to serve

the load does not mean that a customer who triggered cost at another location (i.e., the

Waiparous substation) should not be required to reimburse the AESO for costs incurred in

developing that service. As such, the RPG submitted that AltaLink had not provided a

satisfactory explanation to support the prudence of $1.77 million in incurred cost.1130

Commission findings

1325. In Exhibit 3585-X0043, AltaLink provided an excel spreadsheet which set out AltaLink’s

cancelled projects. The document, on its face, indicated that the total cost for these projects was

$0. This reflected AltaLink’s practice of rounding down any cost less than $500,000. In order to

provide better visibility of the actual costs spent on these cancelled projects, AltaLink provided

an undertaking to file a schedule setting out a breakdown of the costs for the cancelled

projects.1131

1326. AltaLink’s practice of netting out expenditures and recoveries is inconsistent with its

treatment of customer connection direct assign projects and other non-direct assign projects

included in the application, where the gross amount of the addition and the offsetting

contributions are fully visible. For future DACDA’s, AltaLink is directed to account fully for all

gross additions, contributions, and net additions for any cancelled projects that AltaLink

includes. Due to the small amounts that may be involved, amounts to the dollar should be shown.

1327. AltaLink provided its undertaking response in Exhibit 3585-X0773. On review, it is

apparent that project D.0347 (Devon Distribution Transfer Trip) is the only cancelled project in

the application where both the gross additional amount and the fully offsetting contribution are

shown. For all other projects, save for projects D.0271 (West Cascade 177S) and D.0286 (Wiau

Lake), no amounts are shown for either gross additions, customer contributions, or net additions.

1328. For all of the cancelled projects other than projects D.0271, D.0286, and D.0254

(Waiparous 693S), the Commission accepts AltaLink’s representation in its response to AML-

AUC-2015MAR05-0251132that all incurred costs were recovered from the relevant proponent

customer that triggered the creation of a project number and presumably, the accrual of some

expenditures.

1329. With respect to projects D.0271, and D.0286, although the amounts are effectively de

minimus, AltaLink failed to provide any basis to justify the reasonableness of these costs or why

1128





Exhibit 3585-X0042.


Decision 3585-D03-2016 (June 6, 2016) • 271

any net addition to rate base should be allowed. Accordingly, AltaLink’s proposed net additions

for these projects are denied.

1330. With respect to project D.0254, the Commission shares much of the concern expressed

by the RPG regarding the explanation that AltaLink provided regarding the transfer of

approximately $1.77 million to another project. AltaLink’s response to an IR1133 identifies that

the project to which this $1.77 million amount was transferred to as the “ Cochrane 291S

project” and “AESO Project #1450.” This tracking of the project showed a departure from using

the “D” numbering scheme that AltaLink used extensively throughout the rest of the application.

1331. The RPG suggested that the transfer was to project D.0248, which is included in the

current DACDA only as a trailing cost; however, this should be confirmed. Accordingly, the

Commission directs AltaLink to confirm in its compliance filing, that project D.0248, identified

as the Cochrane 291S transformer addition project is, in fact, the project to which the transfer of

the $1.77 million in costs was made. If this cannot be confirmed, AltaLink is directed to identify,

fully and clearly, the project in question.

1332. Assuming that AltaLink does confirm that project D.0248 was the project to which initial

expenditures of $1.77 million on project D.0254 (Waiparous) were transferred, AltaLink’s

description of trailing cost expenditures on project D.0248 is not inaccurate or is incomplete, by

virtue of failing to mention the transfer. Given the nature of trailing costs, it is reasonable to

conclude that any costs transferred from project D.0254 to project D.0248 would have been

included as part of the prior capital addition request that AltaLink made for project D.0248 in a

prior DACDA.

1333. Notwithstanding, absent any specific notification from AltaLink, it would not occur to

either the Commission or interveners to assume that a portion of the costs for which AltaLink

requested an addition to rate base in a prior period DACDA started out as costs incurred for

another project. Further, on the basis of the limited information that AltaLink disclosed regarding

the transfer of the Waiparous project costs to the Cochrane 291S project in the current

proceeding, it is not clear that the transfer would have been correct. In particular, while AltaLink

appears to be relying on the fact that the transfer was consented to by the AESO, such consent

does not necessarily persuade the Commission that Waiparous costs were properly transferred to

another project. In particular, the Commission’s general presumption is that cancelled costs

should be recovered from the project proponent, as AltaLink has done for the other projects

identified as cancelled projects within the current application.

1334. In light of the Commission’s concerns, additional information regarding the particulars of

the transfer of project D.0254 costs to project D.0248 must be provided before ruling on project

D.0248. Accordingly, AltaLink is directed to identify the customer that initiated expenditures on

project D.0254 and to provide a full accounting of expenditures on project D.0254 prior to the

point of transfer. In addition, AltaLink is directed to provide all applicable correspondence

between AltaLink, the identified customer, and the AESO that pertained to the decision to make

the transfer.

1133

Exhibit 3585-X0042. AML-AUC-MAR05-025(b).


272 • Decision 3585-D03-2016 (June 6, 2016)

4.5 Trailing costs

1335. AltaLink discussed its requests for approval of capital additions in respect of trailing

costs on direct assign projects in Section 7.6.1 of the application. AltaLink requested approval of

total trailing cost capital additions of $11.5 million for 20121134 and $8.5 million for 2013.1135

AltaLink noted that the combined amount of its trailing cost capital additions for the years 2012

and 2013 represented approximately 2.2 per cent of the aggregate amounts of the PPS stage

estimates for the projects for which trailing costs were incurred.

1336. AltaLink explained that the types of trailing costs that are incurred on direct assign

projects typically include activities such as site remediation, pipeline mitigation, validating and

archiving of project documents (return data), and the resolution of the “punch list” of project

defects or deficiencies.1136

1337. In argument, AltaLink noted that, in response to an IR,1137 AltaLink had provided

additional explanations of the nature of the trailing costs incurred for each project with trailing

costs. In addition, during the oral hearing, AltaLink explained that final cost reports may include

an estimate for future trailing costs.1138

1338. AltaLink submitted that as interveners did not provide any evidence with respect to

trailing costs, the requested trailing cost addition amounts for the trailing cost projects identified

in the application should be approved as filed.1139

1339. In its argument, the RPG submitted that because it does not include Heartland project

trailing costs, the $20.0 million figure AltaLink set out as the total for 2012 and 2013 trailing

costs is deceptive. In this regard, the RPG noted that AltaLink indicated that it anticipates

expenditures of approximately $16.7 million on Heartland project AC migration measures and

that AltaLink expects to recover costs from resales of purchased lands.1140 The RPG noted that

AltaLink has indicated that it intends to recover remaining Heartland project costs as trailing

costs to be considered in a future DACDA application.1141

1340. In reply,1142 the RPG submitted that, contrary to its submission in argument, AltaLink did

not provide a complete response to a Commission IR that asked for explanations of trailing cost

variances.1143 For example, the RPG submitted that variance explanations for three trailing cost

projects, representing aggregate trailing costs of $8.8 million have completely inadequate

justification of why the Commission should consider these costs were prudently incurred. In this

regard, the RPG submitted that for each of the three projects, AltaLink’s variance explanation

provides two or more reasons and, therefore, provides no basis to assess the costs attributable to

1134




Exhibit 3585-X0042 AML-AUC-2015MAR05-024. 1138





Note that argument and reply submissions of both AltaLink and the RPG that were originally submitted in

relation to trailing costs in accordance with the outline for argument prepared by the Commission have been

dealt with as part of Section 4.1.14.3 of this decision. 1143



Decision 3585-D03-2016 (June 6, 2016) • 273

the specific reasons mentioned. In addition, the RPG submitted that AltaLink has provided no

price-quantity information, no description of whether or not AltaLink attempted to identify lower

costs options or made efforts to minimize costs.1144

1341. In summation, the RPG submitted that AltaLink has provided insufficient information to

demonstrate that trailing costs of $20 million were prudently incurred. Accordingly, the RPG

recommended that the Commission direct AltaLink to provide improved variance explanations

that address these concerns for future DACDA applications.1145

Commission findings

1342. The Commission has reviewed Table 7.6-1 of the application, the trailing costs related to

2012, and has reconciled the amounts from this table to the amounts included in Exhibit 3585-

X0043. The total amount is consistent with the $11.5 million amount requested for approval in

the application.

1343. The Commission has also reviewed Table 7.6-2 of the application, the trailing costs

related to 2013. While the Commission is able to reconcile the amounts for the projects shown in

Table 7.6-2 to amounts shown in Exhibit 3585-X0043, some of the projects included in Table

7.6-2 were not part of a previous deferral application. Based on the Commission’s review of

Exhibit 3585-X0043, the Commission is only prepared to approved 2013 trailing costs totalling

$2.3 million in respect of the Yellowhead Cherhill (D.0030.03 – $1.4 million), Yellowhead

Hinton Edson (D.0030.01 – $0.8 million) and Yellowhead Drayton Valley (D.0030.04 –

$0.1 million) projects.

1344. For all other projects identified in Table 7.6-2, the Commission has determined that the

2013 trailing costs amounts claimed have also been proposed for the first time in this proceeding

as a new project for approval. Consequently, reviewing trailing costs for these projects separately

would be akin to double-counting of these costs. Therefore, the balance of the $8.5 million 2013

trailing cost addition amount shown in Table 7.6-2 (approximately $6.2 million) has been

reviewed as part of the addition amounts requested for the years 2012 and 2013 for these

projects.

1345. AltaLink is claiming only $0.8 million as trailing costs for the Cochrane project

(D.0248). However, in IR response AML-AUC-0251146 AltaLink indicated that the amount of

$1.8 million was transferred from the cancelled Waiparous project (D.0254), to the Cochrane

project. In Section 4.4, the Commission directed AltaLink to provide an analysis of the

$1.8 million transferred from the Waiparous project to Cochrane. Accordingly, with the

exception of the $0.8 million claimed for the Cochrane project, the balance of the $11.5 million

claimed as trailing costs for 2012 is approved.

1144



Exhibit 3585-X0042.


274 • Decision 3585-D03-2016 (June 6, 2016)

5 Other deferral accounts

5.1 2012 and 2013 long-term debt deferral accounts

1346. In Section 3 of its application, AltaLink provided calculations to show the difference

between its forecast and actual incremental long-term debt costs for 2012 and 2013. The

calculations resulted in a $3.6 million and $2.9 million refund payable to the AESO for 2012 and

2013 respectively. AltaLink subsequently identified an amount reported in error that resulted in a

change to the refund amount for 2013 to $2.8 million.

1347. AltaLink amended its 2013 amount further following the release of the 2013 generic cost

of capital decision, which increased its capital structure debt ratio from 63 per cent to 64 per

cent. The amended 2013 debt deferral calculation resulted in a refund of $3.6 million payable to

the AESO.

1348. The ADC filed evidence in which it asserted that AltaLink had over-recovered debt

interest costs by $14.3 million and that when this over-recovery was combined with the ADC’s

calculation of AltaLink’s under-recovered plant addition costs of $15.4 million, a charge to the

AESO of no more than $1.1 million, not the $30 million requested by AltaLink, should be

approved.1147

Commission findings

1349. Similar to the Commission findings in Section 4.1.19 regarding the ADC proposal, the

Commission has previously rejected the proposition that AltaLink should not be allowed deferral

account recovery if there was a positive difference between the forecast and actual return in any

year. The Commission again finds that accepting the ADC’s proposed change in a deferral

account proceeding would be procedurally unfair to the applicant.

1350. The proposal put forward by the ADC is denied.

1351. AltaLink has calculated the debt deferral balance amount consistent with the approach

approved in Decision 2011-453 and Decision 2013-407, therefore the Commission approves

AltaLink’s 2012 refund calculations of $3.6 million in 2012 and $3.6 million in 2013.

1352. The Commission, through IRs and questioning in the hearing about the mechanics of the

debt deferral calculation, has identified issues with the calculation that it would like to

investigate further, and will be performing a review of the calculation in AltaLink’s 2017-2018

GTA.

5.2 Other costs associated with short-term debt

1353. The Commission approved discontinuation of the other costs associated with the short-

term debt deferral account in Decision 2013-407.

1354. AltaLink calculated a refund balance of $0.3 million in its application related to the 2012

other costs associated with short-term debt.

1147



Decision 3585-D03-2016 (June 6, 2016) • 275

Commission findings

1355. The Commission approves AltaLink’s calculated refund amount of $0.3 million payable

to the AESO for 2012 other costs associated with short-term debt account variance.

5.3 Taxes other than income taxes

1356. In Decisions 2011-453 and 2013-407, the Commission approved the continuation of

deferral account treatment for taxes other than income taxes.

1357. AltaLink applied to collect $0.2 million relating to its 2013 variance-to-approved

forecast.

1358. In response to an IR, AltaLink identified that the variance to forecast in 2013 was due to

higher property taxes. This $0.2 million variance was due to higher forecast substation capital

additions and higher than forecast land assessment values. The increases were partially offset by

a lower than forecast assessment year modifier and lower than forecast average mill rate.1148

Commission findings

1359. The Commission approves AltaLink’s applied-for amount as filed.

5.4 Annual structure payments

1360. In Decision 2011-453 and 2013-407, the Commission approved the continuation of the

annual structure payment deferral treatment.

1361. AltaLink applied to refund $0.5 million in 2012 and $0.1 million in 2013.

1362. In argument, AltaLink stated the variance in 2012 was primarily to payments for the

CBW and Heartland projects.

Commission findings

1363. The Commission approves the refund of $0.5 million in 2012 and of $0.1 million to the

2013 account variance.

6 Responses to Commission directives

1364. AltaLink provided its responses to Commission directives at Section 2 of the application.

For those directions in which AltaLink was directed to provide information on an ongoing basis,

AltaLink is directed to continue to provide this information in future DACDA filings.

1365. The Commission’s determinations with respect to other directives, are detailed in the

following table.

1148

Exhibit 3585-X0042, AML-AUC-2015MAR05-059.


276 • Decision 3585-D03-2016 (June 6, 2016)

Table 59. Directive responses

Decision Decision reference Subject Commission decision and follow up direction (if applicable)

2010-284

Directive 1 page 7 paragraph 39

Trailing Costs

Commission acknowledges compliance. AltaLink is directed to continue to file the requested information in future DACDAs.

2010-284


Trailing Costs


2013-407


Competitive Procurement Process

Commission acknowledges compliance. No further action is necessary due to findings elsewhere in this decision.

2013-407




2013-407


Risk Reward Model


2013-407


OCASTD

Commission acknowledges compliance. No further action is necessary.

2013-407


Direct Assigned Capital Deferral Application – Minimum Filing Requirements


2013-407


Direct Assigned Capital Deferral Application –Filing Requirements


2014-258

Directive 3 pages 16 and 17 paragraph 76



7 Reconciliation

7.1 Refund of CWIP in rate base amounts

1366. In Decision 3524-D01-2016 in respect of AltaLink’s 2015-2016 GTA, the Commission

made findings in respect of AltaLink’s proposal in that proceeding to provide rate relief through

various measures outlined in AltaLink’s GTA, which included a proposal to refund amounts

previously collected through the collection of CWIP-in-rate base. As part of its findings on

AltaLink’s proposals, the Commission made the following finding at paragraph 953, reproduced

in part below:1149

953. … AltaLink is to adjust all DACDA projects not approved on a final basis in

Decision 2013-407 or in Decision 2044-D01-2016 to include AFUDC in accordance with

normal historic regulatory accounting practices in its compliance filing and file an update

that includes the relevant AFUDC-related amounts in Proceeding 3585.

1367. On June 2, 2016, AltaLink provided a filing on the record of the current proceeding in

compliance with the findings at paragraph 953 of Decision 3524-D01-2016. AltaLink’s

1149

Construction work in progress.


Decision 3585-D03-2016 (June 6, 2016) • 277

compliance filing include updates to various schedules previously filed as exhibits in Proceeding

3585,1150 as well as a project summary schedule1151 that set out AFUDC amounts and revised

addition amounts for each of the projects listed in Exhibit 3585-X0043.

1368. AltaLink also took note of the following finding from Decision 3524-D01-2016 at

paragraph 953:

Customers and AltaLink are to be kept revenue neutral from any adjustment made to the

above DACDA projects in AltaLink’s applications, by refunding the accumulated return

on CWIP balances that were paid to AltaLink, in addition to any return earned on those

amounts, calculated based on the WACC for the period from the date on which the

amounts were received, and accounting for any other impacts.

1369. In consideration of this finding, AltaLink noted that the updated schedules provided in its

June 2, 2016 compliance filing no longer showed CWIP-in-rate base allowances and that a true-

up in accordance with the above noted finding from paragraph 953 of Decision 3524-D01-2016

would be provided as part of AltaLink’s compliance filing application pursuant to Decision

3524-D01-2016.

Commission findings

1370. The Commission acknowledges AltaLink’s June 2, 2016 filings pursuant to Decision

3524-D01-2016 directives.

1371. As the Commission has not approved all of the rate base additions amounts requested by

AltaLink for all projects, AltaLink’s proposed AFUDC reconciliation as set out in Exhibit 3585-

X0870 will have to be updated at the time of AltaLink’s compliance filing application to this

decision.

7.2 Compliance filing

1372. As the Commission did not approve the full amount of the rate base addition amount

requested by AltaLink for all projects in the application, AltaLink is directed to file a compliance

application to reflect the capital addition amounts approved by the Commission and to reflect the

Commission findings arising from Decision 3524-D01-2016 regarding the inclusion of AFUDC

in accordance with normal historic regulatory practice for projects other than those approved on

a final basis in Decision 2013-407 or Decision 2044-D01-2016.

1373. AltaLink is directed to refile its 2012 and 2013 deferral accounts reconciliation

application to reflect the findings conclusions and directions arising from this decision on or

before August 15, 2016.

1150

AltaLink filed updates to Exhibits 3585-X0653, 3585-X0654 and 3585-X0655 as Exhibits 3585-X0867, 3585-

X0868 and 3585-X0869, respectively. 1151

Exhibit 3585-X0870.


278 • Decision 3585-D03-2016 (June 6, 2016)

8 Order

1374. It is hereby ordered that:

(1) AltaLink shall, on or before August 15, 2016, refile its 2012 and 2013 deferral

accounts reconciliation application to reflect the findings, conclusions and

directions of this decision.

Dated on June 6, 2016.


(original signed by)

Mark Kolesar

Vice-Chair


Henry van Egteren

Commission Member


Kate Coolidge

Acting Commission Member


Decision 3585-D03-2016 (June 6, 2016) • 279

Appendix 1 – Proceeding participants

Name of organization (abbreviation) Company name of counsel or representative

AltaLink Management Ltd. (AltaLink or AML) Borden, Ladner Gervais LLP

ATCO Electric Ltd. (ATCO) Bennett Jones LLP Alberta Electric System Operator (AESO) Alberta Direct Connect Consumers Association (ADC) Ackroyd LLP

Consumers’ Coalition of Alberta (CCA)

EPCOR Distribution & Transmission Inc. (EDTI)

Industrial Power Consumers Association of Alberta (IPCAA) Bull, Housser and Tupper LLP

Office of the Utilities Consumer Advocate (UCA) Brownlee LLP

The Alberta Utilities Commission Commission Panel M. Kolesar, Vice-Chair H. van Egteren, Commission Member K. Coolidge, Acting Commission Member Commission Staff

C. Wall (Commission counsel) K. Kellgren (Commission counsel) L. Desaulniers (Commission counsel) J. Halls J. Cameron C. Strasser M. Kopp-van Egteren


280 • Decision 3585-D03-2016 (June 6, 2016)

Appendix 2 – Oral hearing – registered appearances

Name of organization (abbreviation) Name of counsel or representative

Witnesses

AltaLink Management Ltd. (AltaLink or AML)

R. Block K. Salmon

B. Townsend D. Watson J. Picard-Thompson D. Fedorchuk J. Piotto C. Lomore R. Venerus J. Kell T. Dorsey

Consumers’ Coalition of Alberta (CCA) and Ratepayer Group (RPG)

J. A. Wachowich

C. Chekerda V. Bellissimo D. Levson T. Cline W. Tusa

Alberta Direct Connect Consumers Association (ADC)

R. Secord

M. Gorman

ATCO Electric Transmission (ATCO) L. Keough N. Bryanskiy

Alberta Utilities Commission Commission panel M. Kolesar, Vice-Chair H. van Egteren, Commission Member K. Coolidge, Acting Commission Member Commission staff

C. Wall (Commission counsel) L. Desaulniers (Commission counsel) J. Halls J. Cameron C. Strasser M. Kopp-van Egteren


Decision 3585-D03-2016 (June 6, 2016) • 281

Appendix 3 – Motions and procedural rulings

1. On December 18, 2014, AltaLink filed a motion1 pursuant to Section 13.4 of Rule 001:

Rules of Practice, which sought to have certain reports referenced in the application treated on a

confidential basis. The Commission acknowledged AltaLink’s December 18, 2014 motion in a

letter dated December 19, 2014,2 but indicated that it would not establish a process to consider

the motion until after the deadline for the filing of SIPs had passed.

2. The Commission established a process to consider AltaLink’s December 18, 2014 motion

on January 6, 2015.3 The Commission issued its ruling in respect of this motion on February 10,

2015.4 In accordance with findings and directions set out in that ruling, AltaLink filed

supplemental evidence on both the public and confidential records of Proceeding 3585 on or

before February 13, 2015. Following the issuance of this ruling, the Commission established a

process schedule5 that provided for the submission of information requests (IRs) to AltaLink and

responses thereto, to be filed by March 19, 2015. In the same correspondence, the Commission

requested that parties provide submissions on the need for intervener evidence and related

process steps on or before March 25, 2015.

3. On March 13, 2015, AltaLink filed a request for an extension to the deadline for filing

information requests to April 2, 2015.6 The Commission granted this request in correspondence

dated March 17, 2015.7

4. On March 17, 2015, the CCA filed a letter requesting that an audit report prepared in

respect of an AltaLink capital project, pursuant to findings in Decision 2013-407, be made

available for consideration in Proceeding 3585.8 In correspondence dated April 17, 2015,9 the

Commission dismissed the CCA’s request on the basis that the subject report had been filed on

the record of Proceeding 2044.

5. On April 2, 2015, AltaLink filed responses to information requests posed to it by the

Commission, the CCA, and IPCAA. In a cover letter filed in conjunction with its responses to

IRs of the Commission, AltaLink indicated that it had determined in the course of preparing its

responses that certain adjustments would be made to certain exhibits filed with its original

application on December 17, 2014.10 Specifically, AltaLink filed updates to Exhibit 0003.AML-

3585, 0004.AML-3585, 0005.AML-3585 and 0006.AML-3585. AltaLink indicated that the

updated exhibits comprised the primary excel schedules pertaining to revenue requirement and

the reconciliation of requested rate base additions. In the same correspondence, AltaLink

1 Exhibit 0220.01.AUC-3585.

2 Exhibit 0222.01.AUC-3585.

3 Exhibit 3585-X0001.

4 Exhibit 3585-X0013.

5 Exhibit 3585-X0018.

6 Exhibit 3585-X0035.

7 Exhibit 3585-X0036.

8 Exhibit 3585-X0037.

9 Exhibit 3585-X0162.

10 Exhibit 3585-X0042.


282 • Decision 3585-D03-2016 (June 6, 2016)

indicated that, due to the volume of information requested, it required additional time to file

information sought in an IR prepared by the CCA.11

6. Concurrent with its filing of IR responses on April 2, 2015, AltaLink filed a notice of

motion pursuant to AUC Rule 001 for confidential treatment of certain information it was

requested to provide in IRs (confidentiality motion).12

7. The Commission established a process to consider AltaLink’s confidentiality motion in a

letter dated April 7, 2015.13 In the same correspondence, the Commission directed AltaLink to

provide copies of the documents AltaLink expected to be subjected to confidential treatment so

that they could be reviewed by the Commission panel chair, Commission counsel, and select

Commission staff, in preparation for the Commission’s ruling on the confidentiality motion. Also

in the April 7, 2015 correspondence, the Commission advised parties that it had scheduled an

oral hearing to be held in Calgary between June 22, 2015 and July 3, 2015.

8. On April 10, 2015, AltaLink filed an update to its April 2, 2015 confidentiality motion,

reflecting certain minor adjustments.14 On the same date, AltaLink filed the remaining IR

responses that it had not been able to file by April 2, 2015.15

9. On April 23, 2015, the CCA filed correspondence that advised the Commission that it did

not expect to meet the hearing dates set out in the Commission’s April 7, 2015 correspondence.16

On April 28, 2015, AltaLink filed a letter that requested the Commission to maintain a schedule

that would allow for the commencement of the oral hearing on June 22, 2015.17

10. On April 25, 2015, the CCA filed a motion (CCA motion) pursuant to sections 9, 30, and

31 of AUC Rule 001 and pursuant to Section 8 of the Alberta Utilities Commission Act, for an

order or orders directing AltaLink to provide full and complete responses to IRs set out in an

appendix thereto.18 The Commission set out a process to consider the CCA motion on April 30,

2015.19 In its April 30, 2015 letter, the Commission advised parties that the process schedule for

Proceeding 3585 would be held in abeyance, but advised parties that the oral hearing would be

rescheduled to commence on July 20, 2015 rather than on the previously specified date of June

22, 2015.

11. On May 11, 2015, the Commission issued a ruling on AltaLink’s confidentiality motion

of April 2, 2015.20 In its ruling, the Commission granted some of the confidentiality requests of

AltaLink and denied others. As a result of its ruling, AltaLink was directed to file certain

documents on a fully public basis, and to file certain other documents on a redacted basis. With

regard to the documents that were to be filed on the confidential record, AltaLink was also

11

AltaLink indicated that it would require two to four weeks to prepare information sought by the CCA in IR

AML-CCA-2015MAR05-038. 12

Exhibit 3585-X0119. 13

Exhibit 3585-X0120. 14

Exhibit 3585-X0123. 15

Exhibit 3585-X0125. 16

Exhibit 3585-X0164. 17

Exhibit 3585-X0168. 18

Exhibit 3585-X0842. 19

Exhibit 3585-X0169. 20

Exhibit 3585-X0184.


Decision 3585-D03-2016 (June 6, 2016) • 283

required to file on the public record redacted versions of these documents in accordance with the

filing procedures set out in the Commission’s ruling. AltaLink was directed to provide these

unredacted documents to the Commission on or before May 29, 2015, and to any party who had

executed a confidentiality undertaking designed to protect the confidentiality of the information

received.

12. On May 13, 2015, the Commission received correspondence from the CCA advising the

Commission that the CCA had requested amendments to the schedule for AltaLink’s 2015-2016

general tariff application (GTA), which was being considered by the Commission in Proceeding

3524.21 The CCA indicated that it had filed its request for Proceeding 3524 schedule adjustments

within the current proceeding on the basis that accommodating such a request could have an

effect on the schedule for Proceeding 3585. On May 15, 2015, AltaLink filed a response to the

CCA’s May 13, 2015 letter, requesting that the scheduled start of the oral hearing on July 20,

2015, should be maintained.22

13. On May 24, 2015, AltaLink filed a list of documents pursuant to the Commission’s

May 11, 2015 ruling that had been granted confidentiality.23 AltaLink filed an amendment to its

May 24, 2015 documents list on May 29, 2015.24

14. On May 27, 2015, the Commission provided its ruling on the CCA’s April 25, 2015

motion to provide full and complete responses to IRs.25 The Commission’s ruling directed

AltaLink to provide improved responses to some, but not all, of the IRs identified by the CCA in

its motion.

15. On June 3, 2015, the CCA filed correspondence26 that requested the Commission

reconsider the scheduled oral hearing dates for Proceeding 3585 in light of conflicts with other

Commission proceedings, the unavailability of expert resources, the large dollar value

consequences of Commission rulings on the application, and the large size of the public and

confidential records for Proceeding 3585. AltaLink filed a letter on June 4, 201527 in response to

the CCA’s June 3, 2015 letter in which it reiterated its opposition to any further delays in the

schedule that might lead to a change in the proposed date of the oral hearing. The CCA filed a

response to AltaLink’s June 4, 2015 letter on June 5, 2015.28

16. On June 5, 2015, the Commission granted the CCA’s request for changes to the schedule

of Proceeding 3585.29 The Commission found that, in light of the volume of information

AltaLink had been directed to file and the effort required to process such information,

maintaining the schedule could significantly impair the ability of the CCA and other parties to

participate meaningfully in the proceeding. In light of these rulings, the Commission advised

parties that the oral hearing would be rescheduled to occur in Calgary between November 9,

2015 and November 20, 2015.

21

Exhibit 3585-X0189. 22

Exhibit 3585-X0190. 23

Exhibit 3585-X0445 and Exhibit 3585-X0444. 24

Exhibit 3585-X0492. 25

Exhibit 3585-X0475. 26

Exhibit 3585-X0494. 27

Exhibit 3585-X0594. 28

Exhibit 3585-X0595. 29

Exhibit 3585-X0596.


284 • Decision 3585-D03-2016 (June 6, 2016)

17. On June 10, 2015, for the purposes of simplifying the management of confidential

documents, the Commission directed AltaLink to file a consolidated list of confidential

documents filed pursuant to the May 11, 2015 and May 27, 2015 Commission rulings on

confidentiality motions.30 In accordance with this correspondence, AltaLink filed its consolidated

documents list on June 12, 2015.31

18. On June 24, 2015,32 the Commission set out a revised process schedule for Proceeding

3585 that provided for the filing of intervener evidence on August 28, 2015, the filing of IRs on

intervener evidence by September17, 2015, the filing of responses to IRs on October 5, 2015,

and the filing of rebuttal evidence by October 27, 2015.

30

Exhibit 3585-X0615. 31

Exhibit 3585-X0627. 32

Exhibit 3585-X0638.


Decision 3585-D03-2016 (June 6, 2016) • 285

Appendix 4 – Project proceedings and approvals

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval

Description of facilities or approval

D.0030.01

Yellowhead Area Transmission Development Hinton-Edson Development

2010-208

270

2011-188

766

U2011-146 Alter Transmission Line 745L

U2011-147 Alter and Re-designate Transmission Line from 745L to 671L

U2011-148 Decommission and Salvage Part of Transmission Line 745L


U2011-150 Alter Bickerdike 39S Substation

DA2012-185 1980 U2012-339 Alter Transmission Line 745L

D.0030.03

Yellowhead Area Transmission Development Cherhill Area Development

2010-208

270

2011-161

762

U2011-88 Construct and operate new Cherhill 338S substation

U2011-89 Discontinue operation and salvage Lac La Nonne 994S substation – rescinds U2003-102 on completion of salvage

U2011-90 Discontinue operation and salvage Glenevis 442S substation – rescinds U2002-486

U2011-91 Salvage of all 69 kV equipment save for one disconnect switch associated with transmission line 104L at North Barrhead 69S substation – rescinds U2002-332

U2011-92 Salvage of 69 kV equipment associated with transmission line 104L at Onoway 352S substation – rescinds U2002-449

U2011-93 Construct 100 m of 240 kV single circuit transmission line to connect transmission line 913L by way of an in-and-out configuration to the Cherhill 338S substation and to operate the transmission line 9L913 to Cherhill 338 substation as transmission line 913L – rescinds U2002-822

U2011-96 Discontinue operation and salvage transmission lines 104L, 104BL and 104EL – rescinds U2002-577

U2011-97 Construct 100 m of 240 kV single-circuit transmission line to connect transmission line 913L by way of an in-and-out configuration to Cherhill 338S substation and to operate the portion of the transmission line 913L from Sundance 310P substation to Cherhill 338S substation as transmission line 1046L – P&L U2002-822 rescinded in P&L U2011-93

DA2013-53

2433 U2013-96 Time extension for Lac La Nonne 994S substation decommission and salvage – rescinds U2011-89 – P&L U2003-102 to be rescinded on completion of decommission and salvage.

U2013-101 Time extension for Glenevis 442S substation decommission and salvage – rescinds U2011-90 – P&L U2002-486 to be rescinded on completion of decommission and salvage.


286 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2013-102 Time extension for transmission lines 104L, 104BL and 104EL decommission and salvage – rescinds U2011-96 – P&L U2002-577 to be rescinded on completion of decommission and salvage.

Disposition Letter

2761 Disposition Letter

Confirmation that portions of transmission lines 104L and 104EL decommissioned pursuant to Decision 2011-161 and approval U2011-96 can be sold to FortisAlberta Inc. and to local REAs without further process.

D.0108 SE Development Project – Brooks Area

U2008-232

16613

2011-001

220

U2011-106 Alter transmission line 100L

U2011-2 Construct and operate new transmission line 666L, re-designate a portion of transmission line 100L and 666L and discontinue operation and salvage remaining portion of line 100l – P&L U2005-224 rescinded on completion of salvage

U2011-3 Salvage a portion of transmission line 100L

U2011-4 Alter and operate West Brooks 28S substation – rescinds U2009-17

U2011-5 Alter and operate Brooks 121S substation – rescinds U2004-407

D.0213 Edmonton Region 240 kV Lines Upgrades

2011-340

754

2012-293 1394 U2012-529 Approval to alter transmission line 902L in the Wabamun Lake area – rescinds U2002-812

U2012-530 [TransAlta P&L; AltaLink facility application] alteration of transmission line 902L within the boundaries of I.R. 133A, I.R. 133B and I.R. 133C – rescinds U2002-930

U2012-531 Approval to connect transmission line 902L at the boundaries of Wabamun I.R. 133 – rescinds connection order U2003-335

D.0238

Athabasca Area Telecom Development

2012-023

861 2012-064

861

U2012-82 Construct Clyde 9150R Radio Site Westlock County

U2012-83 Construct Colinton 9159R Radio Site Athabasca County

U2012-84 Construct Ellscott 9900R Radio Site Athabasca County

U2012-85 Construct Weasel Creek 9901R Radio Site County of Thorhild

U2012-86 Alter Deerland 13S Substation Lamont County

U2012-87 Alter Larkspur 9374R Radio Site Westlock County

U2012-88 Alter Boyle 56S Substation Athabasca County

U2012-89 Alter Lac La Biche 157S Substation Lac La Biche County

U2012-90 Alter Plamondon 353S Substation Lac La Biche County

U2012-91 Alter Waupisoo 405S Substation Athabasca County

U2012-92 Alter Clyde 150S Substation Westlock County

U2012-93 Alter Colinton 159S Substation Athabasca County

U2012-94 Decommission and Salvage Telecommunications Tower at Boyle 56S Substation


Decision 3585-D03-2016 (June 6, 2016) • 287

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2012-95 Decommission and Salvage Telecommunications Tower at Lac La Biche 157S Substation

U2012-96 Decommission and Salvage Telecommunications Tower at Plamondon 353S Substation

U2012-97 Decommission and Salvage Telecommunications Tower at Clyde 150S Substation

U2012-98 Decommission and Salvage Telecommunications Tower at Colinton 159S Substation

DA2012-240

2076

U2012-389 Time extension to construct Clyde 9150R Radio Site – rescinds U2012-82

U2012-390 Time extension to construct Colinton 9159R Radio Site – rescinds U2012-83

U2012-391 Time extension to construct Ellscott 9900R Radio Site – rescinds U2012-84

U2012-392 Time extension to construct Weasel Creek 9901R Radio Site – rescinds U2012-85

U2012-393 Time extension for alterations at Deerland 13S substation – rescinds U2012-86

U2012-394 Time extension for alterations at Larkspur 9374R radio site – rescinds U2012-87

U2012-395 Time extension for alterations at Boyle 56S substation – rescinds U2012-88

U2012-396 Time extension for alterations at Lac La Biche 157S substation – rescinds U2012-89

U2012-397 Time extension for alterations at Plamondon 353S substation – rescinds U2012-90

U2012-398 Time extension for alterations at Waupisoo 405S substation – rescinds U2012-91

U2012-399 Time extension for alterations at Clyde 150S substation – rescinds U2012-92

U2012-400 Time extension for alterations at Colinton 159S substation – rescinds U2012-93

U2012-401 Time extension for decommissioning and salvage of telecommunications tower at Boyle 56S substation – rescinds U2012-94


288 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2012-402 Time extension for decommissioning and salvage of telecommunications tower at Lac La Biche 157S substation – rescinds U2012-95

U2012-403 Time extension for decommissioning and salvage of telecommunications tower at Plamondon 353S substation – rescinds U2012-96

U2012-404 Time extension for decommissioning and salvage of telecommunications tower at Clyde 150S substation – rescinds U2012-97

U2012-405 Time extension for decommissioning and salvage of telecommunications tower at Colinton 159S substation – rescinds U2012-98

DA2013-44 2372 U2013-73 Time extension to construct Clyde 9150R Radio Site – rescinds U2012-389

U2013-74 Time extension to construct Ellscott 9900R Radio Site – rescinds U2012-391

U2013-75 Time extension to construct Weasel Creek 9901R Radio Site – rescinds U2012-392

U2013-76 Time extension for alterations at Deerland 13S substation – rescinds U2012-393

U2013-77 Time extension for alterations at Clyde 150S substation – rescinds U2012-399

U2013-78 Time extension for decommissioning and salvage of telecommunications tower at Boyle 56S substation – rescinds U2012-401

U2013-79 Time extension for decommissioning and salvage of telecommunications tower at Lac La Biche 157S substation – rescinds U2012-402

U2013-80 Time extension for decommissioning and salvage of telecommunications tower at Plamondon 353S substation – rescinds U2012-403

U2013-81 Time extension for decommissioning and salvage of telecommunications tower at Clyde 150S substation – rescinds U2012-404

U2013-82 Time extension for decommissioning and salvage of telecommunications tower at Colinton 159S substation – rescinds U2012-405

D.0305 Cassils to Bowmanton 2009-126 171 2012-336 2004 U2012-677 Alter transmission line 1034L


Decision 3585-D03-2016 (June 6, 2016) • 289

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2012-678 Alter transmission line 1035L

U2012-679 Alter transmission line 964L-983L


2011-250 748 U2011-198 New Cassils 324S Substation

U2011-199 Decommission and salvage transmission line 923L-935L

U2011-200 New transmission line 1051L-1052L



U2011-203 New Bowmanton 244S substation

U2011-204 New Whitla 251S substation


D.0316 D.0355

Southern Alberta Transmission Reinforcement 933L In/Out at Ware Junction 132S Hanna Area Transmission – Ware Junction

2009-126 2010-188 2010-592 2011-102

171 278 768 748

2012-043

1150

U2012-12 Construct new 240 kV transmission line from Cassils 324S substation to Ware Junction 132S substation

U2012-13 Redesignate southern portion of transmission line from Ware Junction 132S substation to West Brooks 28S substation as transmission line 1075L

U2012-14 Alter and operate transmission line 933L so that it terminates at Ware Junction 132S substation and redesignate southern portion of existing transmission line from Ware Junction 132S substation to West Brooks 28S substation as transmission line 1075L – rescinds U2002-840

U2012-16 Alter and operate Cassils 324S substation – Rescinds U2011-198

U2012-17 Alter and operate Ware Junction 132S substation – Rescinds U2002-353

2012-230

1992 U2012-408 Alter Transmission Line 1053L – rescinds U2012-12

U2012-409 Alter Ware Junction 132S Substation – rescinds U2012-17

U2012-410 Alter Transmission Line 933L – rescinds U2012-14

U2012-411 Alter Transmission Line 1075L – rescinds U2012-13




DA2013-97

2515 U2013-169 Time extension for altering Cassils 324S substation – rescinds U2012-16

U2013-170 Time extension for altering Ware Junction 132S substation – rescinds U2012-409

U2013-171 Time extension for altering transmission line 933L – rescinds U2012-410


290 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval




D.0353 Hanna Area Transmission – Nilrem 2010-188 2011-102

278 748

2011-191 957 U2011-86 Alter and operate Hardisty 377S substation - rescinds U2010-46

2011-445 938 U2011-394 Construct new Nilrem 574S substation

U2011-395 Errata Alter transmission line 953L

U2011-396 Errata new transmission line 1047L

U2011-397 Alter Tucuman 478S Substation

U2011-398 Errata New Transmission Line 679L-680L

2012-358 2247 U2012-681 Alter and operate Nilrem 574S Substation – rescinds U2011-394

U2012-682 Alter and operate transmission line 953L – rescinds U2011-395

U2012-683 Errata: Alter and operate transmission line 1047L – rescinds U2012-136

DA2012-12 1671 U2012-26 Time extension for alteration of Hardisty 377S substation – rescinds U2011-86

DA2013-161 2688 U2013-318 Time extension for alterations of Tucuman 478S substation – rescinds U2011-397

U2013-319 Time extension for alterations of transmission line 679L – rescinds U2011-398

U2013-320 Time extension for construction of transmission line 680L – rescinds U2011-398

U2013-321 Time extension for alterations of Nilrem 574S substation – rescinds U2012-681



D.0354 Hanna Area Transmission – Hansman Lake

2010-188 2010-592

278 768

2011-175 974 U2011-174 Hansman Lake 650S Substation

2012-120 979 U2012-135 New 240-kV Transmission Line 966L

U2012-136 Alter 240-kV Transmission Line 1047L

U2012-137 A Portion of Transmission Line 1047L

U2012-138 Errata Alter Hansman Lake 650S Substation – rescinds U2011-174

D.0371 Heartland Transmission Project CTI N/A 2011-436 457 U2011-435 Construct and operate Heartland 12S substation in the Gibbons-Redwater area

U2011-436 Alter and operate Ellerslie 89S substation – rescinds U2009-389


Decision 3585-D03-2016 (June 6, 2016) • 291

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2011-437 Construct and operate double-circuit 500-kV transmission line 1206L/1212L from Ellerslie 89S substation in south Edmonton to Heartland 12S substation in the Gibbons-Redwater area.

U2011-438 Approval to: - build new double-circuit 240-kV line from Heartland 12S substation to cut into existing 240-kV transmission line 942L - split the existing transmission line 942L into the north and south segments at the cut-in point - operate the new line from Heartland 12S substation to Deerland 13S substation as transmission line 1054L Rescinds U2002-846

U2011-439 Approval to: - build new double-circuit 240-kV line from Heartland 12S substation to cut into existing 240-kV transmission line 942L - split the existing transmission line 942L into the north and south segments at the cut-in point - operate the new line from Heartland 12S substation to Lamoureaux 71S substation as transmission line 1061L Rescinds P&L U2002-846 in P&L 2011-438

U2011-440 Approval to connect transmission line 1206L/1212L to Ellerslie 89S substation

U2011-442 Approval to connect transmission line 1206L/1212L to Heartland 12S substation in Gibbons-Redwater area.

DA2013-256 2871 U2013-564 Time extension for alterations to Ellerslie 89S substation – rescinds U2011-436

U2013-566 Time extension for approval to construct and operate double-circuit 500kV transmission line 1206L/1212L – rescinds U2011-437

U2013-567 Errata time extension for construction of transmission line 1054L – rescinds U2011-438

DA2013-259 2905 U2013-585 Time extension for approval to contract transmission line 1206L/1212L - rescinds U2013-566

U2013-586 Time Extension for construction of transmission Line 1054L - rescinds U2013-567

U2013-587 Errata time extension for construction of transmission Line 1061L – rescinds U2013-359

U2013-588 Time extension for alteration of Ellerslie 89S substation - rescinds U2013-564


292 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2013-590 Approval to construct temporary line to terminate the new 500-kV transmission line 1206lL/1212l onto existing 240-kV system in Heartland 12S substation – rescinds U2012-575

D.0377 Christina Lake Area Development - Black Spruce 154S

2012-356 2010 2012-356 2010 U2012-704 Construct and operate Black Spruce 154S substation in Christina Lake area.


U2012-706 Alter and operate the portion of transmission line 971L from Jackfish 698S substation to Black Spruce 154S substation as transmission line 1099L – P&L U2012-243 rescinded in P&L U2012-705

D.0409 ENMAX No. 65 Interconnection Project

CTI N/A 2011-435 1007 U2011-277 Alter transmission line 911L by: - swapping locations of transmission line 911L and transmission line 850L on the common double-circuit lattice towers from structure 1 to structure 40 - building approximately 400 m of double-circuit 240-kV transmission line to connect ENMAX No. 65 substation in an in-out configuration Rescinds U2002-821

U2011-278 Transmission line 1080L Alter transmission line 911L by: - swapping locations of transmission line 911L and transmission line 850L on the common double-circuit lattice towers from structure 1 to structure 40 - building approximately 400 m of double-circuit 240-kV transmission line to connect ENMAX No. 65 substation in an in-out configuration with new 240-kV transmission line from Janet 74S substation to ENMAX No. 65 substation designated as transmission line 1080L - P&L U2002-821 rescinded in P&L U2011-277

U2011-279 Alter and operate transmission line 850L by swapping transmission line 850L and transmission line 911L on the common double-circuit lattice towers from structure 1 to 40 – rescinds U2007-014

U2011-280 Approval to redesignate transmission line 850AL as 911AL and energize the line to 240-kV – rescinds U2005-203

U2011-349 Approval to connect AltaLink transmission line 911L to TransAlta corporation transmission line 911L –rescinds connection order U2003-338


Decision 3585-D03-2016 (June 6, 2016) • 293

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2011-350 [TransAlta P&L; AltaLink facility application] Approval to operate transmission line 911L within the boundaries of Peigan Indian Reserve I.R. 147 – rescinds U2002-936

2013-121 2483

U2013-161 Approval to connect transmission line 911L to ENMAX No. 65 substation

U2013-162 Approval to connect transmission line 1080L to ENMAX No. 65 substation

DA2013-99 2516 U2013-164 Time extension for alterations to transmission line 911L – rescinds U2011-277

U2013-166 Time extension for alterations to transmission line 850L – rescinds U2011-279

U2013-167 Time extension for alterations to transmission line 911AL –rescinds U2011-280

DA2013-313

2692 U2013-370 Approval of minor alteration to transmission line 911L – rescinds U2013-164

U2013-371 Approval of minor alteration to transmission line 1080L – rescinds U2012-525

D.0414 Western Alberta Transmission Line CTI N/A

2012-327 1045 U2012-656 Alter transmission line 925L from Red Deer 63S substation to Janet 74S substation in the Red Deer to Calgary area restringing certain segments of the transmission line at specified locations on single-circuit structures to accommodate a crossing by AltaLink’s 500-kV DC transmission line 1325L – rescinds U2002-833

U2012-658 Alter transmission line 929L from Red Deer 63S substation to Janet 74S substation in the Red Deer to Calgary area by restringing certain segments of the transmission line at specified locations on single-circuit structures to accommodate a crossing by AltaLink’s 500-kV DC transmission line 1325L – rescinds U2002-837

DA2013-197 2788 U2013-377 Alter and operate transmission line 928L to reflect findings in DA2013-197 (alterations to 906L/928L and 918L at S½-6-37-2-W5M and N½-31-36-2-W5M) – rescinds U2011-403

U2013-379 Alter and operate transmission line 918L to reflect findings in DA2013-197 (alterations to 906L/928L and 918L at S½-6-37-2-W5M and N½-31-36-2-W5M) – rescinds U2002-175 and U2002-826

D.0458 East HVDC Converter Station Interface Project

CTI N/A 2012-305 1884 U2012-576 Alter transmission line 950L by relocating a segment of the line to accommodate the crossing of the line by ATCO Electric 500-kV DC line 13L50 – rescinds U2002-853


294 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2012-577 Alter transmission line 1053L by restringing a segment of the transmission line on single-circuit structures to accommodate a crossing by ATCO Electric 500-kV DC line 13L50 – rescinds U2012-408

U2012-578 Alter transmission line 1075L by relocating a segment of the line to accommodate the crossing of the line by ATCO Electric 500-kV DC line 13L50 – rescinds U2012-411

U2012-579 Alter transmission line 931L by restringing a segment of the transmission line on single-circuit structures to accommodate a crossing by ATCO Electric 500-kV DC line 13L50 – rescinds U2012-412

D.0459 Red Deer Area Transmission Project - Split 768L & 778L

2012-098 1368

2012-254

1468 U2012-221 Alter and operate transmission line 768L –rescinds license U2002-729

U2012-222 Alter and operate transmission line 778L – rescinds license U2002-735

U2012-223 Alter and operate North Red Deer 217S substation – rescinds license U2002-386 and P&L U2006-267

U2012-224 Alter and operate Gaetz 87S substation – rescinds U2002-339


U2012-452 Salvage structure 768L3 on transmission line 768L – license U2002-729 is rescinded by P&L U2012-221

U2012-453 Salvage structures 778L3 and 778L2 on transmission line 778L – license U2002-735 is rescinded by P&L U2012-222

U2012-454 Salvage structure 80L659 on transmission line 80L - U2002-574 is rescinded by P&L U2012-225

D.0460 Red Deer Area Transmission Project - TX add at Benalto 17S

2012-098 1368 2012-254 1468 U2012-225 Alter and operate Benalto 17S substation – rescinds U2007-34

D.0461 Red Deer Area Transmission Project - Capbank at Joffre 535S

2012-098 1368 2012-254 1468 U2012-226 Alter and operate Joffre 535S substation – rescinds U2006-194

DA2013-162 2685 U2013-324 Alter and operate Joffre 535S substation - rescinds U2012-226

D.0462 Red Deer Area Transmission Project - Capbank at Prentiss 276S

2012-098 1368 2012-254 1468 U2012-227 Alter and operate Prentiss 276S substation – rescinds U2002-419

DA2013-162 2685 U2013-329 Alter and operate Prentiss 276S substation – rescinds U2012-227

D.0463 Red Deer Area Transmission Project - Capbank at Ellis 332S

2012-098 1368 2012-254 1468 U2012-228 Alter and operate Ellis 332S substation – rescinds U2002-439

DA2013-162 2685 U2013-330 Alter and operate Ellis 332S substation – rescinds U2012-228

D.0041 Picture Butte 120S (MATL) 2008-006

15421 2010-302 535 U2010-138 Alter Transmission Line 923L

U2010-139 New MATL 120S Substation

2011-086 929 U2011-63 Picture Butte 120S substation

U2011-64 Transmission Line 1005L


Decision 3585-D03-2016 (June 6, 2016) • 295

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval



U2011-75 Connect Picture Butte 120S Substation to MATL 120S substation

2012-141 1301 U2012-238 Order. MATL 120S, Transmission Line 941L, AML Picture Butte 120S, Transmission Line 1005L and 940L

2012-345 1301 U2012-491 Picture Butte 120S Substation - rescinds U2011-63

U2012-493 Alter Transmission Line 940L - rescinds U2011-65

U2012-492 Transmission Line 1005L

2013-033 2160 U2013-042 Picture Butte 120S Substation - rescinds U2012-491

D.0073

Castle Rock Ridge (CRR) Wind Farm Interconnection Project

2011-439 2012-005

778

2011-439 778 U2011-386 New Castle Rock Ridge 205S substation

U2011-387 New Transmission Line 1071L


U2011-389 Alter Goose Lake 103S substation

DA 2012-190

1863 U2012-337 Alter Transmission Line 1071L - rescinds U2011-387


D.0093 Leduc 325S Project 2011-280 737 2011-416 737 U2011-357 New Leduc 325S Substation



DA2012-214 2056 U2012-374 New Leduc 325S Substation - rescinds U2011-357


D.0172 Wainwright 51S Transformer Addition 2009-206 217 2009-206 217 U2009-382 Need to alter and operate Wainwright 51S substation

U2009-383 Alter and operate Wainwright 51S substation

2010-614 1002 U2010-447 Alter and operate Wainwright 51S substation – rescinds U2009-383

2011-371 1340 U2011-271 Alter and operate Wainwright 51S substation – rescinds U2010-447

U2011-272 Salvage of substation equipment

D.0179 Kirby 651S New Substation Project 2012-087 1560 2012-087 1560 U2012-174 Construct and operate Kirby 651S substation

U2012-175 Construct and operate line 428L

U2012-176 Alter and operate Winefred 818S substation

U2012-177 Need for new Kirby 651S substation and new 428L transmission line

U2012-178 Salvage of capacitor banks and circuit switchers

DA2012-273 2113 U2012-474 Construct and operate line 428L – rescinds U2012-175

DA2013-47 2387 U2013-68 Alter and operate Winefred 818S substation – rescinds U2012-176

U2013-70 Construct and operate Kirby 651S substation – rescinds U2012-174

D.0202 Westwood 422S New Substation 2011-360 1070 2011-423 1070 U2011-338 New Westwood 422S Substation


296 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


Project U2011-338 Errata New Westwood 422S Substation

U2011-339 Salvage a portion Transmission Line 700L


U2011-341 Alter and Re-designate Transmission Line as 694L

DA2012-346 2208 U2012-603 New Westwood 422S - rescinds U2011-338 Errata

U2012-604 Salvage a Portion of Transmission Line 700L - rescinds U2011-339


U2012-606 Alter and Re-designate Transmission Line as 694L - rescinds U2011-341

D.0267 Round Hill New Substation – Lac La Biche Area

2011-408 1298 2011-408 1298 U2011-330 Need for Round Hill 852S Substation Connection

U2011-331 Construct and operate Round Hill 852S substation

U2011-332 Construct and operate 1085L/1086L transmission line

U2011-346 Order to connect transmission line 1085L to ATCO Electric transmission line 9L55

U2011-347 Order to connect transmission line 1086L to ATCO Electric transmission line 9L47

2012-185 1782 U2012-277 Construct and operate Round Hill 852S substation – rescinds U2011-331

D.0275 D.0279

Abee New Substation – Lac La Biche Area Weasel Creek New Transmission Line – Lac La Biche Area

2012-220 1363 2012-220 1363 U2012-282 Construct and operate Abee 993S substation

U2012-283 Construct and operate new transmission line 437L

U2012-284 Construct and operate new Transmission Line 808AL

U2012-288 Alter and operate transmission line 808L

2012-287 2104 U2012-532 Alter and operate new Transmission Line 808AL route – rescinds U2012-284

D.0281 Willesden Green 68S Upgrade 2011-418 1413 2011-418 1413 U2011-360 Alter and operate substation 68S

DA2012-172 1965 U2011-360 Alter and operate substation 68S (unchanged)

2012-052 1621 DA2012-178 1983 U2012-305 Alter and operate substation 68S – rescinds U2012-61

D.0283 Winefred 818S Substation Capacity Upgrade Project

2011-457 1461 2011-457 1461 U2011-406 Alter and operate Winefred 818S substation – rescinds U2002-537

D.0284 Thompson New Substation – Lac La Biche Area

2011-518 1428 2011-518 1428 U2011-456 Construct and operate Thompson 140S substation

U2011-457 Construct and operate 788AL transmission line

DA2012-120 1871 NONE NO CHANGE TO P&L REQUIRED

DA2012-204 2032 NONE NO CHANGE TO P&L REQUIRED

D.0383 Cope Creek Interconnection Project 2012-340 2016 2012-340 2016 U2012-692 Construct and operate Cope Creek 180S substation

U2012-693 Construct and operate 150A1L transmission line.

U2012-694 Alter and operate 150AL transmission line


Decision 3585-D03-2016 (June 6, 2016) • 297

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


U2012-695 Salvage segment of 150AL transmission line – rescinds license U2002-585 in P&L U2012-694.

DA2014-25 3029 U2014-39 Construct and operate Cope Creek 180S substation – rescinds U2012-692

U2014-40 Construct and operate 150A1L transmission line – rescinds U2012-693

U2014-41 Alter and operate 150AL transmission line – rescinds U2012-694

U2014-42 Salvage segment of 150AL transmission line – rescinds U2012-695

D.0388 Tilley 489S Transformer Upgrade Project

2013-130 2389 2013-130 2389 U2013-194 Alter and operate Tilley 498S substation

D.0393 Bruderheim 127S Upgrade 2012-366 2072 2012-366 2072 U2012-622 Alter and operate Bruderheim 127S substation – rescinds U2011-427

U2012-690 Salvage equipment in Bruderheim 127S substation – rescinds permit and license U2011-427 within U2012-622

D.0395 Whitecourt Industrial 364S Substation Upgrade

2013-186 2169 2013-186 2169 NONE No P&Ls for this project were substantially complete at the end of 2013. DA2013-195 2753

D.0407 Sunday Creek 539S Connection Project

2012-356 2010 2012-356 2010 U2012-707 Construct and operate 1118L transmission line

D.0410 East Calgary Transmission Project/Shepard Energy Centre Interconnection

2012-283 1229 2012-283 1229 U2012-524 Construct new transmission line 1003L

2013-022 2338 U2013-35 Construct underground transmission line 1109L

D.0413 Amelia 108S Upgrade 2013-053 1808 2013-053 1808 U2013-106 Alter and operate Amelia 108S substation – rescinds U2007-043

U2013-107 Alter and operate transmission lines 943L and 943AL and re-designate as transmission line 1120L – rescinds U2007-044 and U2007-045

U2013-108 Alter and operate transmission line 943L – rescinds permit and license 2007-045 within permit and license U2013-107

D.0425 Keystone 384S Upgrade 2012-338 1629 2012-338 1629 U2012-686 Alter Keystone 384S substation

U2012-687 Buswork salvage at Keystone 384S substation

D.0426 Rimbey 297S Substation Upgrade 2012-239 1638 2012-239 1638 U2012-432 Alter and operate Rimbey 297S substation

U2012-447 Salvage of circuit breakers at Rimbey 297S substation

DA2013-20 2352 U2013-37 Alter and operate Rimbey 297S substation

U2013-38 Salvage of circuit breakers at Rimbey 297S substation

D.0427 Lodgepole 61S Upgrade 2012-338 1629 2012-338 1629 U2012-688 Alter Lodgepole 61S substation


298 • Decision 3585-D03-2016 (June 6, 2016)

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


D.0434 Greengate – Blackspring Ridge Wind Farm Interconnection

2013-070 1625 2013-070 1625 NONE No P&Ls for this project were substantially complete at the end of 2013.

D.0435 Cherhill 338S Substation Transformer Addition

2013-219 2134 2013-219 2134 U2013-281 Alter and operate Cherhill 338S substation – rescinds U2011-88

D.0447 Jackfish 698S New Substation Project 2012-143 1639 2012-143 1639 U2012-241 New Jackfish 698S Substation

U2012-242 New transmission Line 1090L

U2012-243 Alter transmission Line 971L

DA2013-112 2544 U2013-199 New Jackfish 698S Substation – rescinds U2012-241

U2013-200 New transmission line 1090L – rescinds U2012-242

U2013-201 Alter transmission line 971L – rescinds U2012-243

D.0454 Ponoka Substation (331S) Upgrade 2012-308 1941 2012-308 1941

U2012-570 Alter and operate Ponoka 331S substation – rescinds license U2002-438

U2012-571 Salvage of 25-KV breaker at Ponoka 331S substation

D.0191 NRGreen Chickadee Creek 259S Substation Interconnection Project

2012-276 1888 2012-276 1888 Not provided Connect Chickadee Creek 259S Substation by constructing a new 138 kV transmission line, called 199AL, and to modify the existing 138 kV transmission line, 199L.

D.0336 575S Sundre 25 kV Breaker Addition Project

2013-155 1745 2013-155 1745 Not provided Alter the Sundre 575S Substation and re-terminate the existing 138 kV transmission line 719L

D.0214 ENMAX SS-10 69 kV Conversion Project

2012-194 234 2012-194 234 Not provided Alter the 138 kV transmission line 832L to an in/out configuration and redesignate a portion of the 138 kV transmission line between the Sarcee 42S Substation and ENMAX SS-10 Substation as 693L,

DA2014-114 3211

D.0345 131S Moon Lake 25 kV Breaker Addition Project

2012-314 2144 2012-314 2144 Not provided Upgrade the existing Moon Lake 131S Substation

D.0360 Onoway 352S Substation Upgrade Project

2013-083 2252 2013-083 2252 Not provided Alter the Onoway 352S Substation

D.0340 Cynthia 178S Upgrade 2012-240 1436 2012-240 1436 Not provided Alter the Cynthia 178S Substation

DA2013-8 2309

D.0259 Leismer 72S Capacitor Bank Addition 2011-325 1015 2011-325 1015 Not provided Upgrade the existing Leismer 72S Substation

DA2011-139 1591

D.0166 Judy Creek 236S Substation Salvage Project

2010-183 271 2013-011 2143 Not provided Decommission and Salvage the Judy Creek 236S Substation and connect the existing transmission lines 526L and 515L in and out of the substation, and renumber 515L as a continuation of 526L.

D.0482 Halkirk RAS Project 2012-053 1092 2013-020 2350 Not provided Installation of a telecommunications tower and the salvage of a telecommunications tower at Jarrow 252S substation Not required 2498

D.0277 Fortis Bruderheim 127s 25 kV Add 2011-482 1515 2011-482 1515 Not provided Alter the Bruderheim 127S Substation

D.0357 Willesden Green Breaker Addition 2012-052 1621 2012-052 1621 Not provided Alter the Willesden Green 68S Substation


Decision 3585-D03-2016 (June 6, 2016) • 299

Project ref

Project name NID

decision NID ID

Facility decision

Facility ID

P&L/ approval


DA2012-178 1983

D.0361 Transfer trip Harmattan 256s- 228L None None 2011-170 1634 Not provided Conductor replacement and associated substation upgrades.

D.0381 Enbridge Chard Project 2012-090 1514 DA2012-84 1514 Not provided Protection and control upgrades at the Leismer 72S Substation

D.0405 Enbridge Kingman 299S 5 kV Upgrades

None None None None None A 5 kV upgrade at Kingman 299S Substation at the request of Enbridge.

D.0376 Enbridge Vermillion (Bauer) Project 2012-274 1839 2012-274 1839 Not provided Alter the Buffalo Creek 526S Substation

D.0365 Surmont Ph II - 9L990 Protection Mod 2011-421 1131 2011-510 1615 Not provided Revise the existing relay scheme at the Leismer 72S Substation to adjust to ATCO’s change to the existing 9L990.

D.0398 WISP Synchrophasor PMU Upgrade Project

AESO letter of direction

None 2012-227 2092 Not provided Replacement of the existing phasor measurement unit devices at Langdon 102S and Sundance 310P substations

D.0485 BUCCSDC Fortis Airdrie Telecommunication

U2009-48 17550 2013-248 2596 Not provided Upgrade of telecommunications sites in Calgary.

D.0296 MEG Energy G2 Coms Project None None None None None Modify protections at Conklin 762S Substation

D.0342 Re-Conductoring at Rundle None None None None None Re-Conductor the 64L and 2286L distribution feeder lines for a Fortis Alberta project.

D.0491 Shell Scotford BTF None None None None None Modify existing control modules to provide their status to Shell.

D.0421 Fortis Brazeau River BTF Project None None None None None Metering and CT ratio changes to accommodate the Blaze Energy needs at the Brazeau River 489S Substation.

D.0478 9016R AESO BCC PBX Cross- Connection

None None None None None Cross connection to support the connection of the 9016R AESO BCC PBX with the AltaLink PBX.

D.0372 ECB Enviro - Transfer Trip at N Leth None None None None None Transfer trip scheme at North Lethbridge 370S Substation

D.0484 Strathmore 151 Transfer Trip None None None None None Modify existing transfer trip scheme for Fortis.

D.0402 Cable Termination at North Calder 37s

None None None None None Terminate the 2029L, 25 kV feeder circuit to the North Calder 37S Substation.

D.0263 EDTI Poundmaker Substation None None None None None Reviewed and modified protections, controls and SCADA equipment at the North Calder 37S Substation to accommodate the new EDTI substation.

D.0288 Blue Trail Telecom Wind Farm None None None None None Installation of telecommunications equipment for teleprotection requested by TransAlta.

D.0505 Benbow BTF None None None None None Re‐energization of a transformer at Benbow 397S for Fortis


Decision 3585-D03-2016 (June 6, 2016) • 300

Appendix 5 – Use of jurisdiction adjustment in assessing competitiveness of rates

1. In this Appendix, the reason for and usefulness of using a jurisdiction adjustment, as

included in the PowerAdvocate analysis of EPCM rates, is analyzed in the context of

determining whether AltaLink’s EPCM contractor rates are competitive within the North

American market.

2. The analysis in the PowerAdvocate report assesses competitiveness separately for a

number of different job classifications, and then a weighted average of these job-classification-

specific competitiveness measures is taken across all job classifications to arrive at an overall

competitiveness measure. Since the key component of the PowerAdvocate analysis is therefore

the competitiveness assessment for a single job classification, the analysis in this appendix

focuses on a single job classification.

3. To clarify the issues involved, in the following analysis the PowerAdvocate methodology

is initially applied to a hypothetical situation where, for the specific job classification being

considered, there is only one other contractor in North America that could provide the same

services as those for which AltaLink contracted, and this firm is located in Texas. This situation

is then generalized to the case where there are multiple contractors in a variety of jurisdictions

that could provide the same services for this same job classification, thereby matching the

PowerAdvocate approach.

4. The analysis bellow first considers the case where the jurisdiction adjustment is included

in the competitiveness analysis, as in the PowerAdvocate report. Subsequently, the analysis is

repeated with this jurisdiction adjustment excluded.

Definitions:

5. For convenience, all the following variables are considered to be evaluated in the same

time period (year and quarter), with all US denominated amounts pre-converted to Canadian

currency:

�̅�𝐴𝐵 = average (engineering) wage rate for civil, electrical, and mechanical engineers in Alberta

(AB)

�̅�𝑇𝑋 = average (engineering) wage rate for civil, electrical, and mechanical engineers in Texas

(TX)

J𝐴 = �̅�𝐴𝐵/�̅�𝑇𝑋 = Jurisdiction Adjustment (same regardless of job classification)

𝑤𝐴𝐵𝐶 = �̅�𝐴𝐵 × (1 + 𝑚𝐴𝐵

𝐶 ) = wage paid in Alberta by contractor there for job classification “C”,

where:

𝑚𝐴𝐵𝐶 = markup (or markdown) in Alberta for wages in job classification “C” relative to the

average engineering wage rate in Alberta, �̅�𝐴𝐵.

𝑤𝑇𝑋𝐶 = �̅�𝑇𝑋 × (1 + 𝑚𝑇𝑋

𝐶 ) = wage paid in Texas by contractor there for job classification “C”,

where:


Decision 3585-D03-2016 (June 6, 2016) • 301

𝑚𝐴𝐵𝐶 = markup (or markdown) in Texas for wages in job classification “C” relative to the

average wage engineering rate in Texas, �̅�𝑇𝑋.

𝐿𝐴𝐵𝐶 = loading charged by contractor in Alberta for job classification “C”, which converts wage

rates into (loaded) billing rates (including all burdens), so that:

𝐵𝑅𝐴𝐵𝐶 = 𝑤𝐴𝐵

𝐶 × (1 + 𝐿𝐴𝐵𝐶 ) = loaded billing rate for job classification “C” in Alberta

𝐿𝑇𝑋𝐶 = loading charged by contractor in Texas for job classification “C”, which converts wage

rates into (loaded) billing rates (including all burdens), so that:

𝐵𝑅𝑇𝑋𝐶 = 𝑤𝑇𝑋

𝐶 × (1 + 𝐿𝑇𝑋𝐶 ) = loaded billing rate for job classification “C” in Texas.

Analysis Including Jurisdiction Adjustments:

6. Ultimately, the comparison in the PowerAdvocate Report is between 𝐵𝑅𝐴𝐵𝐶 and (𝐵𝑅𝑇𝑋

𝐶 ×J𝐴), that is, between the billing rates in Alberta and Texas, where the billing rate in Texas is

multiplied by the Jurisdiction Adjustment (e.g., a number like 1.06). Taking the ratios of these

two terms and substituting using the above definitions yields:

(A) 𝐵𝑅𝐴𝐵

𝐶

𝐵𝑅𝑇𝑋𝐶 =

𝑤𝐴𝐵𝐶 ×(1+𝐿𝐴𝐵

𝐶 )

𝑤𝑇𝑋𝐶 ×(1+𝐿𝑇𝑋

𝐶 )×𝐽𝐴=

�̅�𝐴𝐵×(1+𝑚𝐴𝐵𝐶 )×(1+𝐿𝐴𝐵

𝐶 )

�̅�𝑇𝑋×(1+𝑚𝑇𝑋𝐶 )×(1+𝐿𝑇𝑋

𝐶 )×𝐽𝐴=


𝐶 )


𝐶 )×(�̅�𝐴𝐵�̅�𝑇𝑋

) ,

which by cancelling like terms can be simplified to:

(B) 𝐵𝑅𝐴𝐵

𝐶


(1+𝑚𝐴𝐵𝐶 )×(1+𝐿𝐴𝐵

𝐶 )

(1+𝑚𝑇𝑋𝐶 )×(1+𝐿𝑇𝑋

𝐶 )

7. The simplification of this jurisdiction-adjusted billing rate ratio shown in (B) reveals that

if the percentage markup over the average (engineering) wage for job classification “C” is the

same in each jurisdiction (so that 𝑚𝐴𝐵𝐶 = 𝑚𝑇𝑋

𝐶 ), and if the percentage loading charged by the

contractor is the same in each jurisdiction (so that 𝐿𝐴𝐵𝐶 = 𝐿𝑇𝑋

𝐶 ), then the ratio of the billing rates

will be 1. Although this is only for a single job classification, based on the analysis adopted in

the PowerAdvocate report that involves calculating a weighted average of percentage differences

between 𝐵𝑅𝐴𝐵𝐶 and 𝐵𝑅𝑇𝑋

𝐶 across different job classifications, a result in which the ratio of (𝐵𝑅𝐴𝐵

𝐶

𝐵𝑅𝑇𝑋𝐶 )

is less than or equal to 1.0 (or possibly even slightly above 1.0) would be interpreted as showing

that the Alberta rates are competitive.

8. There are several problems with using the ratio of (𝐵𝑅𝐴𝐵

𝐶

𝐵𝑅𝑇𝑋𝐶 ) as defined in (B) to determine

competitiveness. First, there is no reason why 𝑚𝐴𝐵𝐶 should equal 𝑚𝑇𝑋

𝐶 even if the Alberta rates

are competitive. The markup or markdown over the average engineering wage for, say, an

estimator, need not be the same in Alberta, or in Canada for that matter, as it is in Texas. A

similar observation applies to buyers, designers, project managers, and indeed all the other job

classifications that PowerAdvocate considers. In other words, the fact that these markups differ

in the two locations could be country or region specific, and therefore reflect nothing about

competitiveness. Of course different values for 𝑚𝐴𝐵𝐶 and 𝑚𝑇𝑋

𝐶 , could be in part due to a lack of

competitiveness. However, to assess the extent of any lack of competitiveness it would be

necessary to compare markups in the two jurisdictions to the average wage for job classification


302 • Decision 3585-D03-2016 (June 6, 2016)

“C” rather than to the average engineering wage rate. This issue therefore cannot be resolved by

having the same jurisdiction adjustments for each job classification.

9. Second, there is no reason why 𝐿𝐴𝐵𝐶 should equal 𝐿𝑇𝑋

𝐶 even if the Alberta rates are

competitive. The burden, or loading for each jurisdiction includes region-specific factors,

possibly including various mandatory components such as, in Canada, Employment Insurance,

Canada Pension Plan contributions, etc. Therefore, an observation that the two loading factors

differ in the two locations may reflect nothing about competitiveness. Of course different values

for 𝐿𝐴𝐵𝐶 and 𝐿𝑇𝑋

𝐶 , could in part be due to a lack of competitiveness. However, to assess the extent

of any lack of competitiveness it would be necessary to first account for any differences in these

loading factors that is due to specific jurisdictional considerations, which would likely be similar

regardless of job classifications. Such accounting would involve a jurisdictional adjustment, but

such an adjustment could not be based on a simple comparison of wages or average wages in the

different jurisdictions. Indeed, since (B) already includes the jurisdiction adjustment made by

PowerAdvocate, it is clear that the PowerAdvocate jurisdiction adjustment does not deal with

this consideration.

10. In view of these two reasons, therefore, determination that the jurisdiction-adjusted

billing rate ratio in (B) is less than or greater than 1.0, reveals no conclusive evidence about

competitiveness.

11. Of course the PowerAdvocate report does not consider only one other contractor, but

rather compares the Alberta billing rate to the average of billing rates across a variety of

jurisdictions, each with its own jurisdiction adjustment. This just means that the ratio in (B) is

replaced by one in which the denominator is the average over all the billing contractors in

PowerAdvocate’s database, that is, (B) is replaced by (C) where:

(C) 𝐵𝑅𝐴𝐵

𝐶

𝐵𝑅𝑎𝑣𝑔𝐶 =

(1+𝑚𝐴𝐵𝐶 )×(1+𝐿𝐴𝐵

𝐶 )

𝑎𝑣𝑒𝑟𝑎𝑔𝑒[(1+𝑚𝑗𝐶)×(1+𝐿𝑗

𝐶)] ,

where the subscript “j” refers to a particular observation (contractor and jurisdiction) in

PowerAdvocate’s database. Therefore the same comments that applied to (B) continue to apply

to (C). Specifically, the value of this ratio does not and cannot reveal the competitiveness of the

Alberta billing rates.

Analysis excluding jurisdiction adjustments:

12. With the jurisdiction adjustment excluded, the analysis is identical, except that the ratio

of the billing rates in the two jurisdictions excludes the term “JA”. In other words, for the case of

a comparison between the billing rate in Alberta and for a single contractor based in Texas, (A)

is replaced by (D):

(D) 𝐵𝑅𝐴𝐵

𝐶



𝐶 )


𝐶 )=


𝐶 )


𝐶 )

13. In this case, no clarification or simplification results from substituting the wage for a

particular job classification by the product of the average (engineering) wage and the markup for

that job classification relative to the average engineering wage. Therefore, the billing rate

comparison can be limited to the first term on the right-hand side of (D), that is:


Decision 3585-D03-2016 (June 6, 2016) • 303

(E) 𝐵𝑅𝐴𝐵

𝐶



𝐶 )


𝐶 )

14. This comparison in (E) removes one of the two major problems with using the ratio in

(B) to assess competitiveness, namely the potentially different markups that could apply relative

to the average engineering wage rate to obtain the wage rate for job classification “C” in the two

jurisdictions. As can be seen in (E), the first term in the numerator and denominator is the wage

rate for the same job classification in the two jurisdictions, and differences in this wage rate can

be viewed, at least in part, as reflecting competitiveness or a lack thereof. However, the

comparison in (E) does not remove the other problem identified with (B), namely the potentially

different loadings in different jurisdictions that could arise for reasons that do not necessarily

reflect competitiveness. This could only be remedied by including a jurisdiction-based

adjustment to the loading factors, but one that could not be based simply on a ratio of the loading

factor in Alberta to the loading factor in the other jurisdiction, as this would just have the effect

of removing the loading factors from the ratio in (E).

15. Of course the PowerAdvocate report does not consider only one other contractor, but

rather compares the Alberta billing rate to the average of billing rates across a variety of

jurisdictions. This would mean that the ratio in (E) is replaced by one in which the denominator

is the average over all the billing contractors in PowerAdvocate’s database, that is, (E) is

replaced by (F) where:

(F) 𝐵𝑅𝐴𝐵

𝐶

𝐵𝑅𝑎𝑣𝑔𝐶 =


𝐶 )

𝑎𝑣𝑒𝑟𝑎𝑔𝑒[𝑤𝑗𝐶×(1+𝐿𝑗

𝐶)]

where the subscript “j” refers to a particular observation (contractor and jurisdiction) in

PowerAdvocate’s database. Therefore the same comments that applied to (E) continue to apply

to (F).

Summary:

16. Based on this analysis, neither the billing rate comparison that includes nor the billing

rate comparison that excludes the PowerAdvocate jurisdiction adjustment is ideal as a basis for

assessing the competitiveness of billing rates in Alberta. However, the billing rate comparison

that excludes this jurisdiction adjustment removes one of the main drawbacks, in terms of

assessing competitiveness, that was identified with the billing rate comparison that includes this

jurisdiction adjustment.


Decision 3585-D03-2016 (June 6, 2016) • 304

Appendix 6 – 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. Further to the above, the Commission directs AltaLink to ensure that there is no less than

six months separation between the filing of its GTA and its DACDA applications.

........................................................................................................................ Paragraph 187

2. In this proceeding, AltaLink stated its intention to file a combined DACDA application

for the years 2014 and 2015 as early as June 2016. Apart from the above direction

regarding the timing for filing its next DACDA vis-a-vis the filing of its next GTA, the

Commission was also concerned about the scope of this next DACDA. During the oral

hearing, AltaLink’s witnesses were asked to comment on a Commission cross

examination aid prepared from an exhibit filed by AltaLink within its 2015-2016 GTA

proceeding that outlined the specific projects that AltaLink forecast for completion and

addition to rate base in each of the years 2014 and 2015. Based on this examination, the

Commission finds that due to the number of large projects and the very high overall

dollar value of the projects that AltaLink is requesting to add to rate base in 2015, the

examination of both 2014 and 2015 projects in a single proceeding would be unduly

burdensome and administratively unfair. Therefore, the Commission directs AltaLink to

file its 2014 and 2015 DACDA applications separately and in full accordance with

additional time restrictions set out above. ..................................................... Paragraph 189

3. Accordingly, AltaLink is directed to provide a comparable cross reference table

containing all of the same information that it provided in AML-AUC-2015MAR05-002,

in its future DACDA applications. ................................................................ Paragraph 234

4. In the Exhibit 0006.00.AML-3585 spreadsheet filed with the application, AltaLink

included a tab with the title “Energizations,” which provided a cross reference between

AltaLink’s project identification number and name and each project’s energization date

or dates. This information is of assistance when a project has a single listed energization

date; however, the presentation of this information is less helpful when a project has

multiple energization dates since there is no indication regarding what facilities were

brought into service on each date. This information is particularly critical for projects for

which AltaLink is only proposing to add a portion of the expected final cost of a project

in a specific DACDA year. Accordingly, for future applications, for those projects where

more than one energization date is shown, the Commission directs AltaLink to provide an

additional description of the specific project facilities brought into service on each date

shown. .......................................................................................................... Paragraph 236

5. The individual project cost breakdowns that AltaLink provided in separate tabs of the

Exhibit 0006.00.AML-3585 excel spreadsheet contained most of the project cost line

items included in the report format used for reporting to the AESO pursuant to ISO Rule

9.1.2. However, AltaLink’s initial cost breakdowns in Exhibit 0006.00.AML-3585 tabs

did not breakdown owner costs and distributed costs by their respective component parts.

AltaLink provided this information in response to IRs from the Commission. As the

component line-item details of owner costs (PPS, facility applications, land rights –

easements, land – damage claims, land – acquisitions) and distributed costs (procurement,


Decision 3585-D03-2016 (June 6, 2016) • 305

project management, construction management, escalation, contingency) are of interest to

the Commission, AltaLink is directed to include breakdowns at this level of detail in

future DACDA applications. ........................................................................ Paragraph 237

6. The Commission is also concerned that it only became apparent at the time AltaLink

provided its responses to the initial set of IRs that a number of projects that AltaLink

included in the application were not direct assign projects. AltaLink is directed to

distinguish clearly between direct assign projects and non-direct assign projects in future

applications. .................................................................................................. Paragraph 238

7. The Commission found the project summary reports AltaLink prepared for a subset of the

projects in the application to be beneficial and directs AltaLink to continue to provide

these reports. However, the content of these reports could be improved. Presently, the

project summaries provide an overview of information such as summaries of key change

proposals, facility applications, functional specifications, proposals to provide service and

other documents that AltaLink filed as separate exhibits. However, for the most part, the

project summaries did not provide the information necessary to identify the analysis

made at key decision points in the project development life cycle on the basis of the

information that AltaLink had available, or ought to have had available at that time.

Accordingly, the Commission has commented on this deficiency in its findings regarding

decision registers and price/quantity reports discussed below. .................... Paragraph 239

8. The auditor’s report on AltaLink’s Southwest 240-kVproject which was assessed in

Decision 2044-D01-2016 relied extensively on an analysis of a risk register that AltaLink

had established for that project. In Section 4.1.8, the Commission has directed AltaLink

to file its 2014 and 2015 DACDA applications as separate proceedings. To the extent that

AltaLink has prepared similar risk registers for the direct assign projects it includes in its

2014 DACDA application, AltaLink is directed to provide the similar risk registers with

that application. Because AltaLink has historically used a risk register on at least one

direct assign project, for any project included in AltaLink’s 2014 DACDA application for

which no risk register was set up or maintained, AltaLink is directed to provide an

explanation as to why a choice not to set up or to maintain a risk register was made for

that project. ................................................................................................... Paragraph 240

9. On a go forward basis, the Commission considers that including a key decision matrix

and risk register in future applications may assist the applicants, the interveners and the

Commission in managing and focussing on the documentation necessary for testing

future transmission project deferral account reconciliation applications. The Commission

directs AltaLink to develop a proposal for a key decision matrix, and to review its risk

register practices and to fully describe such proposal and review in either its next GTA or

in its next transmission deferral account application, whichever comes first.

........................................................................................................................ Paragraph 241

10. Accordingly, for its 2014 DACDA, AltaLink is directed to provide a report similar to that

provided by the RPG at page 61 of its evidence for all projects where AltaLink’s

requested addition to rate base for 2014 is at least $25 million. ................... Paragraph 244

11. Accordingly, AltaLink is directed to establish a consultative process with representatives

from intervener groups active in AltaLink DACDA application proceedings to try to

arrive at a workable and mutually acceptable set of filing requirements and pre-filing

discovery processes to be followed for AltaLink’s 2015 DACDA application. AltaLink

may conduct the consultation process in whatever manner it considers will be the most


306 • Decision 3585-D03-2016 (June 6, 2016)

effective however, as a starting point for this process, AltaLink is directed to identify

specific proposals or recommendations for possible solutions such as the use of virtual or

physical data rooms or the creation of an agreed upon list of application documents.

........................................................................................................................ Paragraph 252

12. AltaLink is directed to file a report with the Commission regarding the outcome of this

consultation process on or before October 3, 2016, regardless of whether any consensus

on any proposals has been achieved. The report should include a full description of the

nature of the proposals considered and should identify any matters on which a consensus

of the parties has been achieved. The Commission will provide further direction

respecting the filing requirements for AltaLink’s 2015 DACDA application following its

review of this report. ..................................................................................... Paragraph 253

13. As AltaLink had to prepare these reports for the AESO pursuant to ISO Rule 9.1.3.6,

AltaLink is directed to file each of the final cost reports it has prepared for each direct

assign project it includes in its 2014 DACDA application. In the event that AltaLink is

unable to provide a final cost report for any direct assign projects included in its 2014

DACDA application, AltaLink is directed to provide a full explanation as to why a final

cost report cannot be filed. ............................................................................ Paragraph 254

14. AltaLink, in response to an information request, stated that DAIC studies are performed

every two years in conjunction with AltaLink’s GTA. The Commission directs AltaLink

to file the DAIC study and underlying data in its 2017-2018 GTA filing. ... Paragraph 331

15. The Commission directs AltaLink to confirm in its compliance filing:

(a) Whether the audit included the entire 2013 year.

(b) Whether all billings related to the Heartland project in 2014 were audited.

........................................................................................................ Paragraph 343

16. The Commission further directs AltaLink to provide any audit follow-up reviews

performed to confirm whether these audit recommendations have been implemented,

when they were implemented, and what recommendations are still outstanding. AltaLink

should also identify any billing error amounts, whether any over or under billing amounts

had been collected from or paid to SNC and been applied to any of the projects in this

application. .................................................................................................... Paragraph 344

17. For reassurance to the RPG and the Commission that the accruals in question do relate to

actual expenses for the fiscal year in which they have been recorded the Commission

directs AltaLink to provide a certification, signed by its chief financial officer, stating

that the accruals recorded for the years ending December 31, 2012, December 31, 2013,

and December 31, 2014, related to expenses actually incurred in the respective year they

were recorded and did not represent estimates. As it would be a serious breach of the

chief financial officer’s professional ethics to sign a document he did not believe to be

true the Commission considers such a certification would provide satisfactory evidence

as to the accuracy of the accrual amounts. The Commission also notes that the accruals

would have been subject to review by AltaLink’s external auditors during the conduct of

the year-end audit. ......................................................................................... Paragraph 462

18. The Commission’s review of the use of helicopters on these projects was assisted by the

business cases provided by AltaLink. AltaLink is directed to continue its present practice

of preparing a business case for those projects where the use of helicopters is proposed.

........................................................................................................................ Paragraph 598


Decision 3585-D03-2016 (June 6, 2016) • 307

19. As further discussed in Section 4.3.1, because Fortis contribution amounts are assessed in

Fortis capital tracker and capital tracker true-up proceedings, the Commission must

understand the basis for the customer contribution amounts for Fortis projects. In this

regard, the Commission found AltaLink’s undertaking response in Exhibit 3585-X0772

to have been helpful. AltaLink is directed to provide a similar reconciliation as between

AltaLink and Fortis contributions amounts in its future DACDA applications. As well,

for future DACDA applications, in order to ensure that the customer contribution

amounts on AltaLink’s records correspond to the accounting for customer contribution

amounts on the records of Fortis, AltaLink is directed to identify the AESO contribution

decision that it has used in its schedule of customer contribution additions and to file a

copy of the customer contribution decision that it has relied on for each direct assign

connection project. ........................................................................................ Paragraph 611

20. The Commission has reviewed AltaLink’s proposed compliance with directives 20 and

21 from Decision 2013-407, as set out in Attachment 2-E of Section 2 of the application

and finds that AltaLink has complied with these directives. AltaLink is directed to

provide comparable information in future DACDA applications. ................ Paragraph 620

21. AltaLink is therefore directed to include in its compliance filing, for purposes of rate base

and return calculations, the actual amount of pipeline mitigation costs. ...... Paragraph 677

22. AltaLink is also directed to include the pipeline mitigation amount in trailing costs in

AltaLink’s next DACDA where it will be reviewed for final approval. AltaLink can

supply full supporting documentation for the claimed amount at that time. Paragraph 678

23. The Commission has reviewed Tab 10 of AltaLink’s rebuttal evidence and can find no

indication that this amount was ever charged back. The Commission also reviewed the

PO/contract log and could find no evidence that a credit was processed against KEC.

AltaLink is directed, therefore, to deduct the total amount of this change order from its

compliance filing. AltaLink is also directed to deduct from its costs any management

surcharge amount it may have paid to SNC-ATP to manage this change order.

........................................................................................................................ Paragraph 685

24. The Commission notes that in AltaLink’s confidential rebuttal evidence, AltaLink filed

details of a settlement reached between it and SNC-ATP with respect to non-compliant

materials procured by SNC-ATP. AltaLink indicated litigation was ongoing between the

supplier and SNC-ATP but that AltaLink did not pay for the replacement of these

materials. As AltaLink has indicated that there may be additional funds paid to AltaLink

pending the outcome of this dispute between SNC-ATP and the supplier, AltaLink is

directed to file an update as to the status of this issue in its compliance filing.

........................................................................................................................ Paragraph 687

25. As a result of findings in Section 4.2.2.9 in this decision, the Commission expects that the

amounts added to rate base for the Heartland project will change. To address this issue

and the RPG’s expressed concerns, AltaLink is directed to provide, as part of its

compliance filing, a reconciliation showing all approved expenditures in the Heartland

project and how those expenditures are allocated between the AltaLink and EDTI rate

bases, along with appropriate supporting documentation. ............................ Paragraph 745

26. AltaLink is directed, therefore, to include in its compliance filing, for purposes of rate

base and return calculations, the actual amount of pipeline mitigation costs.

........................................................................................................................ Paragraph 799


308 • Decision 3585-D03-2016 (June 6, 2016)

27. AltaLink is also directed to include the pipeline mitigation amount in AltaLink’s next

DACDA where it will be reviewed for final approval. AltaLink can supply full

supporting documentation for the claimed amount at that time, including an explanation

of the discrepancy between the $43 million and $50.1 million estimates for final costs.

Further, the Commission directs AltaLink to provide evidence to demonstrate the net

present value of deferred pipeline mitigation costs due to the reduction in 10-year loading

parameters. .................................................................................................... Paragraph 800

28. The Commission reviewed the PO/contract log and could find no evidence that a credit

was processed against Graham. AltaLink is, therefore, directed to deduct the total amount

of these subcontract amendments from its compliance filing. AltaLink is also directed to

deduct from its costs any management surcharge amount it may have paid to SNC-ATP

related to these subcontract amendments. ..................................................... Paragraph 879

29. The Commission notes that Subcontract Amendment 5 to Graham’s subcontract

agreement includes a charge for “additional management resources.” The Commission

does not consider that the entirety of the costs for additional management resources are

justified. Although access and weather issues might have required more resources, when

Graham signed the subcontract agreement on March 16, 2012, it should have known that

the ISD was being extended to September, 2013, and that, consequently, it would require

additional management resources to accommodate that schedule extension. In the

Commission’s view, Graham did not adequately plan for the resources to complete the

project, even though it already knew the scope of the project, and ratepayers should not

be responsible for this cost. The Commission considers a disallowance of one third of this

amount to be reasonable. AltaLink is, therefore, directed to deduct one third of the

amount for additional management resources in Subcontract Amendment 5 from its

compliance filing. AltaLink is also directed to deduct from its costs one-third of any

management surcharge amount it may have paid to SNC-ATP related to the costs for

additional management resources. ................................................................ Paragraph 880

30. The Commission directs AltaLink, in the trailing cost application, to make submissions in

support of the prudence of its policy to “resell all of the properties required as a result of

its buyout policy no later than the first day of the sixth full month after energizing the

project and include the cost differential (positive or negative) as part of the project capital

costs,” and to justify deviation from its policy to resell all of the purchased properties

within six months following energization. .................................................... Paragraph 898

31. There is conflicting cost information between the updated IR response AML-AUC-

2015MAR05-043 Attachment which shows 2012 and 2013 requested capital additions of

$9.4 million and the cost breakdown provided in another IR response, which shows

actual final costs for 902L of $8.1 million excluding salvage. AltaLink is directed to

provide an explanation for this variance at the time of its compliance filing.

........................................................................................................................ Paragraph 959

32. Consistent with the Commission’s findings in Section 4.1.14.3 above, the risk reward

mechanism costs for projects where an arrangement had already been made prior to

Decision 2013-407, are not approved for inclusion in the project costs for these DACDA

projects. Accordingly, AltaLink is directed to remove the risk reward mechanism costs

from the applied-for additions for the Black Spruce 154S project in the compliance filing.

...................................................................................................................... Paragraph 1094


Decision 3585-D03-2016 (June 6, 2016) • 309

33. The Commission finds these capital expenditures to be reasonably incurred and a

necessary component of this project as these components were integral to the actual

interface work and facilitated the completion of the actual HVDC interface. However,

although these parts were energized, because the expenditures are only a small

percentage of the total HVDC interface project’s total costs, the Commission considers it

more appropriate that these expenditures should remain in CWIP and should be

considered for addition to rate base when the project is complete. AFUDC can be

accumulated on the expenditures in the interim. AltaLink is therefore directed to keep the

expenditures in CWIP and file for their approval when the project is complete.

...................................................................................................................... Paragraph 1158

34. The Commission does not approve the requested capital additions for Surmont II at this

time. The Surmont II 9L990 project costs were defined as customer costs in the facility

application. Conoco Phillips was the end-use customer for ATCO Electric’s Quigley line

and substation project, which drove the need for AltaLink’s Surmont II 9L990 protection

modification project. AltaLink has provided no evidence on the record of this proceeding

to demonstrate when and why this project was designated a system project and why

contributions were not directed from Conoco Phillips. Without evidence on the record to

demonstrate the system benefits, the Commission will not approve the requested

additions at this time. AltaLink is directed to provide evidence in the compliance filing,

to support this project as a system project and to provide evidence, for example by way of

a letter from the AESO, that explains why this project does not merit a contribution from

Conoco Phillips. The Commission will consider the explanation of the system or

customer project designation at the time of AltaLink’s compliance filing. . Paragraph1238

35. For these projects, AltaLink is directed to confirm in the compliance filing, the actual

final cost of the project, the portion of that final cost to be accounted for as trailing costs

in a future DACDA, the amount of the project to be paid for by a customer contribution

and the amount deemed to be a system cost and the source of those amounts.

...................................................................................................................... Paragraph 1250

36. In Decision 2011-453, the Commission determined that a Stage 2 variance proceeding

was not required and stated “… that it would be of assistance if AltaLink would highlight

PSRM projects in future AltaLink GTAs. The Commission leaves it up to AltaLink to

decide whether it wants to do this as part of its CRU forecast or as a separate section

within its application.” Accordingly, the Commission directs AltaLink to clarify its

position as to the venue for the consideration of telecom-related projects in its

compliance filing application, pursuant to this decision. ............................ Paragraph 1254

37. The AESO registered as an interested party for Proceeding 3585 but did not actively

participate. As the administration of the AESO’s customer contribution policy is done by

the AESO itself, the Commission directs AltaLink to contact the AESO for the purposes

of obtaining the AESO’s assessment of customer contribution decisions for the Kirby

651S project in light of the findings set out in this decision. AltaLink is directed to

provide a summary of the AESO’s recommendations in respect of the contribution on the

Kirby 651S project at the time of its compliance filing. The Commission will assess the

amount of the contribution addition to December 31, 2013 for the Kirby 651S project at

that time. ..................................................................................................... Paragraph 1278

38. AltaLink’s practice of netting out expenditures and recoveries is inconsistent with its

treatment of customer connection direct assign projects and other non-direct assign


310 • Decision 3585-D03-2016 (June 6, 2016)

projects included in the application, where the gross amount of the addition and the

offsetting contributions are fully visible. For future DACDA’s, AltaLink is directed to

account fully for all gross additions, contributions, and net additions for any cancelled

projects that AltaLink includes. Due to the small amounts that may be involved, amounts

to the dollar should be shown. .................................................................... Paragraph 1326

39. The RPG suggested that the transfer was to project D.0248, which is included in the

current DACDA only as a trailing cost; however, this should be confirmed. Accordingly,

the Commission directs AltaLink to confirm in its compliance filing, that project D.0248,

identified as the Cochrane 291S transformer addition project is, in fact, the project to

which the transfer of the $1.77 million in costs was made. If this cannot be confirmed,

AltaLink is directed to identify, fully and clearly, the project in question. Paragraph 1331

40. In light of the Commission’s concerns, additional information regarding the particulars of

the transfer of project D.0254 costs to project D.0248 must be provided before ruling on

project D.0248. Accordingly, AltaLink is directed to identify the customer that initiated

expenditures on project D.0254 and to provide a full accounting of expenditures on

project D.0254 prior to the point of transfer. In addition, AltaLink is directed to provide

all applicable correspondence between AltaLink, the identified customer, and the AESO

that pertained to the decision to make the transfer. .................................... Paragraph 1334

41. AltaLink provided its responses to Commission directives at Section 2 of the application.

For those directions in which AltaLink was directed to provide information on an

ongoing basis, AltaLink is directed to continue to provide this information in future

DACDA filings. .......................................................................................... Paragraph 1364

42. As the Commission did not approve the full amount of the rate base addition amount

requested by AltaLink for all projects in the application, AltaLink is directed to file a

compliance application to reflect the capital addition amounts approved by the

Commission and to reflect the Commission findings arising from Decision 3524-D01-

2016 regarding the inclusion of AFUDC in accordance with normal historic regulatory

practice for projects other than those approved on a final basis in Decision 2013-407 or

Decision 2044-D01-2016. ........................................................................... Paragraph 1372

43. AltaLink is directed to refile its 2012 and 2013 deferral accounts reconciliation

application to reflect the findings conclusions and directions arising from this decision on

or before August 15, 2016. ......................................................................... Paragraph 1373


Decision 3585-D03-2016 (June 6, 2016) • 311

Appendix 7 – Abbreviations

Abbreviation Name in full

AC alternating current

ACSR aluminum conductor steel reinforced

ACSS aluminum conductor steel supported

ADC Alberta Direct Connect Consumers Association

AESO Alberta Electric System Operator

AESRD Alberta Environment and Sustainable Resource Development

AFUDC allowance for funds used during construction

AIES Alberta Interconnected Electric System

AltaLink or AML AltaLink Management Ltd.

APEGA The Association of Professional Engineers and Geoscientists

of Alberta

APEGM The Association of Professional Engineers and Geoscientists

of the Province of Manitoba

ATCO/ATCO Electric

AET

ATCO Electric Ltd.

ATCO Electric Transmission

B&M Burns and McDonnell Canada Ltd.

BAR bid analysis and recommendation

BOF bid opening form

BW Bowmanton to Whitla

CAF commitment approval form

CB Cassils to Bowmanton

CCA Consumers’ Coalition of Alberta

CMDC costs for mobilization and demobilization of construction

crews

CN change notice

CNRL Canadian Natural Resources Ltd.

CP change proposal

CPP competitive procurement process

CRR Castle Rock Ridge

CTI Critical transmission infrastructure

CWIP construction work in progress

D distributed costs

DACDA direct assign capital deferral account

DAIC directly attributable indirectly charged

DFO distribution facility owner

DTS demand transmission service


312 • Decision 3585-D03-2016 (June 6, 2016)


EATL Eastern Alberta Transmission Line

EDTI EPCOR Distribution & Transmission Inc.

EPCM engineering procurement and construction management

ES&G engineering, supervision and general

EUB or board Alberta Energy and Utilities Board

FTE full-time equivalent

FTI FTI Consulting, Inc.

GTA general tariff application

H&M Henkels & McCoy

HRTD Hanna Region Transmission Development

HSS hollow structural section

HVDC high-voltage, direct current

IFRS International Financial Reporting Standards

IPCAA Industrial Power Consumers Association of Alberta

IR information request

ISD in-service date

ISO Independent System Operator

ksi kilopounds per square inch

kcmil kilo circular mils

Km kilometre

kV kilovolt

LOE letter of enquiry

MFR minimum filing requirement

MSA master services agreements and amending agreements

MW megawatt

NID need identification document

O owner costs

OCR optical character recognition

OEB Ontario Energy Board

OT other costs

P&L permit and licence

P3 private public partnership

PMCM project management and construction management

POD point of demand

PPS proposal to provide service

PRSM Power System Risk Mitigation


Decision 3585-D03-2016 (June 6, 2016) • 313


REF requisition enhancement form

RFP request for proposal

RFQ request for quotations

RFS request form for service

ROW right-of-way

RPG Ratepayer Group, comprising the ADC, the CCA and IPCAA

SATR Southern Alberta Transmission System Reinforcement

SC subcontract agreements

SCADA supervisory control and data acquisition

SCC Supreme Court of Canada

SLI SNC-Lavalin Inc.

SNC-ATP SNC-Lavalin ATP Inc.

SoleSource Form SoleSource Justification and Approval Forms

SPTR single pole trip and reclose

SRB Surface Rights Board

SVC static var compensator

TCA trend/change authorization form

TFCMC Transmission Facilities Cost Monitoring Committee

TFO transmission facility owner

TUC transportation utility corridor

UCA Office of the Utilities Consumer Advocate

USA uniform system of accounts

WAA Water Act approval

WATL Western Alberta Transmission Line

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