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 The Alberta Utilities Commission 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
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
Decision 3585-D03-2016 (June 6, 2016) • i
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 ii • Decision 3585-D03-2016 (June 6, 2016)
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
Decision 3585-D03-2016 (June 6, 2016) • iii
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
iv • Decision 3585-D03-2016 (June 6, 2016)
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 22. Project D.0238 key cost variance events ...... 193
Table 23. Hanna Regional Transmission Development (HRTD) Nilrem cost breakdown 198
Table 24. Project D.0353 key cost variance events ...... 200
Table 25. HRTD Hansman Lake cost breakdown ...... 203
Decision 3585-D03-2016 (June 6, 2016) • v
Table 26. Project D.0354 key cost variance events ...... 205
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 32. Project D.0377 key cost variance events ...... 215
Table 33. ENMAX No. 65 Interconnection cost breakdown ...... 218
Table 34. Project D.0409 key cost variance events ...... 221
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 39. Project D.0458 key cost variance events ...... 230
Table 40. Red Deer Area – Split 768L & 778L cost breakdown ...... 233
Table 41. Project D.0459 key cost variance events ...... 235
Table 42. Red Deer Area – Benalto 17S cost breakdown ...... 236
Table 43. Project D.0460 key cost variance events ...... 238
Table 44. Red Deer Area – Capbank at Joffre 535SS cost breakdown ...... 239
Table 45. Project D.0461 key cost variance events ...... 240
Table 46. Red Deer Area – Capbank at Prentiss 276S cost breakdown ...... 242
Table 47. Project D.0462 key cost variance events ...... 243
Table 48. Red Deer Area – Capbank at Ellis 332S cost breakdown ...... 244
Table 49. Project D.0463 key cost variance events ...... 245
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
vi • Decision 3585-D03-2016 (June 6, 2016)
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) • vii
The Alberta Utilities Commission 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.
Decision 3585-D03-2016 (June 6, 2016) • 1 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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.
2 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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.
Decision 3585-D03-2016 (June 6, 2016) • 3 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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.
4 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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.
Decision 3585-D03-2016 (June 6, 2016) • 5 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
(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
6 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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.
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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 Exhibit 3585-X0859, paragraph 22.
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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 Exhibit 3585-X0863, paragraph 41. 21 Exhibit 3585-X0865, paragraph 5. 22 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.
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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 71. 25 Exhibit 0002.00.AML-3585, paragraph 72. 26 Exhibit 0002.00.AML-3585, paragraph 74. 27 Exhibit 0002.00.AML-3585, paragraph 76.
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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 Exhibit 3585-X0666, paragraph 204. 29 Exhibit 3585-X0704, paragraph 81. 30 Exhibit 3585-X0704, paragraph 85. 31 Exhibit 3585-X0704, paragraph 86. 32 Decision 2014-283, paragraph 77, cited at Exhibit 3585-X0704, paragraph 88. 33 Exhibit 3585-X0704, paragraph 92. 34 Exhibit 3585-X0704, paragraph 93. 35 Exhibit 3585-X0704, paragraph 95. 36 Exhibit 3585-X0860, paragraph 28.
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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-X0860, paragraph 31. 38 Exhibit 3585-X0860, paragraph 32. 39 Exhibit 3585-X0857, paragraph 14, citing Transcript, Volume 9, pages 1518-1520. 40 Exhibit 3585-X0857, paragraph 15. 41 Exhibit 3585-X0860, paragraph 44. 42 Exhibit 3585-X0864, paragraph 4.
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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 Exhibit 3585-X0666, paragraph 28. 44 Exhibit 3585-X0666, paragraph 29. 45 Exhibit 3585-X0666, paragraph 30.
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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 Exhibit 3585-X0859, paragraph 32. 47 Decision 2013-407, paragraph 1191, cited at Exhibit 3585-X0859, paragraph 34. 48 Exhibit 3585-X0859, paragraph 35. 49 Exhibit 3585-X0860, paragraph 3. 50 Exhibit 3585-X0860, paragraph 43. 51 Exhibit 3585-X0859, paragraph 61.
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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 3585-X0666, paragraph 18. 53 Exhibit 3585-X0666, paragraph 20. 54 Exhibit 3585-X0666, paragraph 21. 55 Exhibit 3585-X0704, paragraph 5. 56 Exhibit 3585-X0704, paragraph 8. 57 Exhibit 3585-X0704, paragraph 7. 58 Exhibit 3524-X0429, AML-AUC-2015JAN20-027 (October 16, 2015 update), cited at paragraph 644 of Exhibit 3585-X0704. 59 Exhibit 3585-X0704, paragraph 644.
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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 50. 61 Exhibit 3585-X0860, paragraph 52. 62 Exhibit 3585-X0860, paragraph 53. 63 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 Exhibit 3585-X0860, paragraph 56. 66 Exhibit 3585-X0859, paragraph 13.
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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 Exhibit 3585-X0859, paragraph 14. 68 Exhibit 3585-X0859, paragraph 36. 69 Exhibit 3585-X0859, paragraph 38. 70 Exhibit 3585-X0859, paragraph 39. 71 Exhibit 3585-X0859, paragraph 40. 72 Exhibit 3585-X0859, paragraph 41. 73 Exhibit 3585-X0859, paragraph 43. 74 Exhibit 3585-X0859, paragraph 44. 75 Exhibit 3585-X0865, paragraph 20. 76 Exhibit 3585-X0865, paragraph 22. 77 Exhibit 3585-X0865, paragraph 29.
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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 30. 79 Exhibit 3585-X0865, paragraph 31. 80 Exhibit 3585-X0865, paragraph 32, citing Exhibit 3585-X0860,paragraph 70. 81 Exhibit 3585-X0863, paragraph 72. 82 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.
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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.
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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 Exhibit 3585-X0704, PDF page 9. 88 Exhibit 3585-X0704, PDF page 17. 89 Transcript, Volume 1, page 187, line 8-10. 90 Transcript, Volume 9, page 1658, lines 8-11. 91 Transcript, Volume 1, page 63, lines 11-13. 92 Transcript, Volume 9, page 1525, lines 2-3. 93 Transcript, Volume 1, page 62, lines 7-11. 94 Transcript, Volume 5, page 838, lines 12-19. 95 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.
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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 Exhibit 3585-X0860, PDF page 17. 99 Exhibit 3585-X0860, PDF page 9. 100 Exhibit 3585-X0859, PDF pages 16-17. 101 Exhibit 3585-X0859, PDF page 18. 102 Alberta Regulation 86/2007, Transmission Regulation, Section 46(1). 103 Exhibit 3585-X0859, PDF pages 19-21. 104 Decision 2013-358: ATCO Electric Ltd., 2013-2014 Transmission General Tariff Application, Proceeding 1989, Application 1608610-1, September 24, 2013, paragraph 393.
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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 13-14. 106 Exhibit 3585-X0865, PDF page 22. 107 Exhibit 3585-X0865, PDF page 25. 108 Exhibit 3585-X0865, PDF pages 15 and 18. 109 Exhibit 3585-X0863, PDF pages 24-25. 110 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
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(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.
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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-X0666, paragraph 23. 117 Exhibit 3585-X0704, paragraph 110. 118 Exhibit 3585-X0045, cited at paragraph 110 of Exhibit 3585-X0704.
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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 Exhibit 3585-X0704, paragraph 113. 121 Exhibit 3585-X0704, paragraph 116. 122 Exhibit 3585-X0704, paragraph 117. 123 Exhibit 3585-X0860, paragraph 121. 124 Exhibit 3585-X0860, paragraph 122. 125 Exhibit 3585-X0860, paragraph 131. 126 Exhibit 3585-X0860, paragraph 132.
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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 Exhibit 3585-X0859, paragraph 75. 128 Exhibit 3585-X0859, paragraph 81. 129 Exhibit 3585-X0859, paragraph 77. 130 Exhibit 3585-X0859, paragraph 78. 131 Exhibit 3585-X0859, paragraph 79. 132 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-X0859, paragraph 89. 136 Exhibit 3585-X0857, paragraph 5. 137 Exhibit 3585-X0857, paragraph 5, citing Decision 2014-283, paragraphs 323 to 332.
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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 Exhibit 3585-X0865, paragraph 103. 139 Exhibit 3585-X0865, paragraph 105. 140 Exhibit 3585-X0865, paragraph 115. 141 Exhibit 3585-X0865, paragraph 116. 142 Exhibit 3585-X0865, paragraph 117. 143 Exhibit 3585-X0865, paragraph 118. 144 Exhibit 3585-X0865, paragraph 120.
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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-X0865, paragraph 122. 146 Exhibit 3585-X0865, paragraph 125. 147 Exhibit 3585-X0863, paragraph 111, referencing Decision 2044-D01-2016 at paragraph 17. 148 Exhibit 3585-X0863, paragraph 111. 149 Exhibit 3585-X0863, paragraph 113. 150 Exhibit 3585-X0864, paragraph 2. 151 Exhibit 3585-X0864, paragraph 3. 152 Exhibit 3585-X0864, paragraph 11.
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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
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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.
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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. 155 Exhibit 3585-X0666, paragraph 37. 156 Exhibit 3585-X0666, paragraph 35 157 Exhibit 3585-X0704, paragraph 111. 158 Exhibit 3585-X0704, paragraph 114. 159 Exhibit 3585-X0704, paragraph 115. 160 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.
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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 Exhibit 3585-X0860, paragraph 139. 165 Exhibit 3585-X0859, paragraph 93. 166 Exhibit 3585-X0859, paragraph 94. 167 Exhibit 3585-X0859, paragraph 96. 168 Exhibit 3585-X0865, paragraph 113 169 Exhibit 3585-X0865, paragraph 113.
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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-X0865, paragraph 113. 171 Exhibit 3585-X0865, paragraph 129. 172 Exhibit 3585-X0865, paragraph 130. 173 Exhibit 3585-X0865, paragraph 131. 174 Exhibit 3585-X0863, paragraph 118, citing several Proceeding 3585 exhibits.
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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.
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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.
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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-X0847, PDF page 1. 179 Exhibit 3585-X0860, paragraph 180. 180 Exhibit 3585-X0860, paragraph 181, citing Exhibit 3585-X0847, PDF page 1. 181 Exhibit 3585-X0860, paragraph 182. 182 Exhibit 3585-X0860, paragraph 187, citing Transcript, Volume 10, page 1815. 183 Exhibit 3585-X0860, paragraph 185, citing Exhibit 3585-X0847, PDF page 2. 184 Exhibit 3585-X0859, paragraph 111. 185 Exhibit 3585-X0859, paragraph 115.
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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 3585-X0859, paragraph 117. 188 Exhibit 3585-X0860, paragraph 179. 189 Exhibit 3585-X0860, paragraph 183. 190 Exhibit 3585-X0863, paragraph 138. 191 Exhibit 3585-X0863, paragraph 139. 192 Exhibit 21206-X0145. 193 Exhibit 3585-X0863, paragraph 140.
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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.
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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.
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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 Exhibit 3585-X0667, PDF page 4.
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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, paragraph 28. 203 Exhibit 3585-X0704, Table 1, pages 8-13. 204 Exhibit 3585-X0704, paragraph 30. 205 Exhibit 3585-X0704, paragraph 33. 206 Exhibit 3585-X0704, paragraph 53. 207 Exhibit 3585-X0704, paragraph 54. 208 Exhibit 3585-X0860, paragraph 145. 209 Exhibit 3585-X0860, paragraph 146, citing Decision 2005-120, pages 3-4. 210 Exhibit 3585-X0860, paragraph 148.
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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-X0860, paragraph 149. 212 Exhibit 3585-X0860, paragraph 150. 213 Exhibit 3585-X0860, paragraph 23. 214 Exhibit 3585-X0859, paragraph 96. 215 Exhibit 3585-X0859, paragraph 100, citing Decision 2014-283, paragraph 107. 216 Exhibit 3585-X0859, paragraph 101. 217 Exhibit 3585-X0859, paragraph 114. 218 Exhibit 3585-X0667, PDF page 2.
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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-X0666, paragraph 15. 220 Exhibit 3585-X0859, paragraph 113. 221 Exhibit 3585-X0860, paragraph 149. 222 Exhibit 3585-X0860, paragraph 150. 223 Exhibit 3585-X0860, paragraph 152. 224 Exhibit 3585-X0860, paragraph 153, citing Decision 2014-283, paragraph 108. 225 Exhibit 3585-X0860, paragraph 154, citing Decision 2013-407, paragraph 1311. 226 Exhibit 3585-X0860, paragraph 155. 227 Exhibit 3585-X0860, paragraph 157, citing Decision 2007-071, page 32. 228 Exhibit 3585-X0860, paragraph 158.
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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 Exhibit 3585-X0859, paragraph 121. 233 Exhibit 3585-X0860, paragraphs 119-132. 234 Exhibit 3585-X0865, paragraph 106. 235 Exhibit 3585-X0704, paragraph 199.
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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-X0704, paragraph 200. 237 Exhibit 3585-X0704, paragraph 205 238 Exhibit 3585-X0860, paragraph 174. 239 Exhibit 3585-X0863, paragraph 133, citing Decision 2014-283, paragraph 77. 240 Exhibit 3585-X0666, Appendix 1, paragraph 24. 241 Exhibit 3585-X0859, paragraph 113.
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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 Exhibit 3585-X0859, paragraph 113. 243 Exhibit 3585-X0865, paragraph 138. 244 Exhibit 3585-X0860, paragraph 176. 245 Exhibit 3585-X0860, paragraph 175. 246 Exhibit 3585-X0863, paragraph 135. 247 Exhibit 3585-X0863, paragraph 135.
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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.
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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.
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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 2044-X0048, PDF page 32. 251 Exhibit 3585-X0666 at page 61.
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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.
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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.
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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, paragraph 36. 258 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 46. 262 Exhibit 3585-X0666, paragraph 127 and paragraph 154. 263 Exhibit 3585-X0666, paragraph 158 and paragraph 170. 264 Exhibit 3585-X0666, paragraph 185. 265 Exhibit 3585-X0666, paragraph 209. 266 Exhibit 3585-X0704, paragraph 35.
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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. 268 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 Exhibit 3585-X0704, paragraph 45. 271 Exhibit 3585-X0860, paragraph 12. 272 Exhibit 3585-X0859, paragraph 371. 273 Exhibit 3585-X0859, paragraph 379.
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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 Exhibit 3585-X0865, paragraph 227. 275 Exhibit 3585-X0865, paragraph 227. 276 Exhibit 3585-X0863, paragraph 26. 277 Exhibit 3585-X0863, paragraph 255. 278 Exhibit 3585-X0863, paragraph 256. 279 Exhibit 3585-X0863, paragraph 257, citing Transcript, Volume 10, pages 1783-1785. 280 Exhibit 3585-X0864, paragraph 7.
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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
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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.
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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, paragraph 92. 283 Exhibit 0002.00.AML-3585, Figure 7.5-1, PDF page 46. 284 Exhibit 0002.00.AML-3585, paragraph 93. 285 Exhibit 0002.00.AML-3585, paragraph 96. 286 Exhibit 0002.00.AML-3585, paragraph 97. 287 Exhibit 3585-X0666, paragraph 203. 288 Exhibit 3585-X0666, paragraph 208.
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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-X0666, paragraph 209. 290 Exhibit 3585-X0704, paragraph 99. 291 Exhibit 3585-X0704, paragraphs 100 and 101. 292 Exhibit 3585-X0704, paragraph 656. 293 Exhibit 3585-X0704, paragraph 658. 294 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.
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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 123. 297 Exhibit 3585-X0859, paragraph 124, referencing Decision 2013-407, paragraphs 555-556. 298 Exhibit 3585-X0859, paragraph 125. 299 Exhibit 3585-X0859, paragraph 128. 300 Exhibit 3585-X0859, paragraph 129. 301 Exhibit 3585-X0859, paragraph 132. 302 Exhibit 3585-X0865, paragraph 145. 303 Exhibit 3585-X0865, paragraph 147.
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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 Exhibit 3585-X0865, paragraphs 152-153. 305 Exhibit 3585-X0865, paragraph 155. 306 Exhibit 3585-X0865, paragraph 159. 307 Exhibit 3585-X0865, paragraph 160. 308 Exhibit 3585-X0865, paragraph 163.
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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.
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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.
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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 Exhibit 3585-X0042, PDF page 185. 314 Exhibit 3585-X0667, PDF page 91.
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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 $856,527.320 In each case, the contingency allowance appears to have been based on an allowance of 10 per cent of AltaLink’s forecast of incremental direct costs.
315 Exhibit 3585-X0042, response to AML-AUC-2015MAR05-014, cited at paragraph 106 of Exhibit 3585- X0704. 316 Exhibit 3585-X0704, paragraph 106. 317 Exhibit 3585-X0859, paragraph 119. 318 Exhibit 3585-X0859, paragraph 127. 319 Exhibit 3585-X0043, energizations Tab and Proceeding 1298, Permit and Licenses U2011-333, U2011-334, U2011-346 and U2011-347 dated October 10, 2011. 320 Exhibit 0206.00.AML-3585, PDF page 44.
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Table 2. Summary of Round Hill project contingency allowance updates Contingency Approved by TCA# Change Proposal Date Update Amount ($) 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 Exhibit 0206.00.AML-3585, PDF page 379.
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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.
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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 DAIC DAIC ($ million) ALP ALP ALP Labour labour as Total Labour as O&M Capital Total included a % of DA a % of DA Labour Labour Labour in DAIC capital CAPEX CAPEX labour 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.
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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.
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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.
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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-X0864, paragraph 202. 340 Exhibit 3585-X0017, paragraph 51, PDF page 52. 341 Exhibit 3585-X0017, paragraph 10, PDF page 42-43.
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(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 57, PDF page 54. 343 Exhibit 3585-X0017, paragraph 119, PDF page 68. 344 Exhibit 3585-X0017, paragraph 50, PDF page 52. 345 Exhibit 3585-X0017, paragraph 53, PDF page 53. 346 Exhibit 3585-X0017, paragraph 70, PDF page 57. 347 Exhibit 3585-X0017 paragraph 72, PDF page 57. 348 Exhibit 3585-X0045, PDF pages 315-316. 349 Exhibit 3585-X0017, PDF page 74.
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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 4. 351 Exhibit 3585-X0017, PDF page 4. 352 Exhibit 3585-X0017, PDF page 4. 353 Exhibit 3585-X0017, PDF page 8. 354 Exhibit 3585-X0017, PDF page 10. 355 Exhibit 3585-X0017, PDF page 3. 356 Exhibit 3585-X0017. PDF page 3. 357 Exhibit 3585-X0017. PDF page 6. 358 Exhibit 3585-X0017. PDF page 6. 359 Exhibit 3585-X0017. PDF page 7. 360 Exhibit 3585-X0017. PDF page 7.
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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-X0221, PDF page 15. 363 Exhibit 3585-X0264-CONF. 364 Transcript, Volume 6, page 1052, lines 9-24. 365 Transcript, Volume 6, page 1055, lines 20-22. 366 Transcript, Volume 6, page 1059, line 5. 367 Transcript, Volume 6, page 1084, line 13. 368 Transcript, Volume 6, page 1076. 369 Transcript, Volume, 6 page 1062. 370 Exhibit 3585-X0792, PDF page 8.
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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 372 optimal selection decision. 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 376 all costs including opportunity costs, risks and profit. 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 Decision 2013-407, paragraph 665. 374 Exhibit 3585-X0864, paragraphs 176-177. 375 Transcript, Volume 8, page 1400, lines 15-18. 376 Transcript, Volume 8, page 1368, line19 to page 1369, line 6. 377 Exhibit 3585-X0864, paragraph 248.
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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 Decision 2013-407, paragraph 681. 379 Ibid., paragraph 682. 380 Ibid., paragraphs 689, 693 and710. 381 Ibid., paragraph 704. 382 Ibid., paragraph 717. 383 Ibid., paragraph 716.
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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 Transcript, Volume 5, page 799, lines 3-10; page 809, line 19 to page 810, line 1; page 810, line 21 to page 811, line 1; page 816, lines 10-19; page 818, lines 9-19.
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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 Exhibit 3524-X0792, PDF page 2.
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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 Exhibit 3524-X0792, PDF page 8.
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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 Transcript, Volume 6, page 1086. 392 Decision 2013-407, paragraph 733. 393 Decision 2013-407, paragraph 759. 394 Exhibit 0002.00.AML-3585, paragraphs 134-137.
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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-X0666, paragraph 194. 397 Exhibit 3585-X0666, paragraph 195. 398 Exhibit 3585-X0666, paragraph 193. 399 Exhibit 3585-X0666, paragraph 196. 400 Exhibit 3585-X0704, pages 191-192. 401 Exhibit 3585-X0704, paragraph 669. 402 Exhibit 3585-X0704, paragraph 670. 403 The RPG addressed risk reward mechanism payments as part of its argument on trailing costs.
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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 Exhibit 3585-X0860, paragraph 391. 405 Exhibit 3585-X0860, paragraph 392. 406 Exhibit 3585-X0859, paragraph 253. 407 Exhibit 3585-X0865, paragraph 329. 408 Exhibit 3585-X0863, paragraphs 177 and 386. 409 Exhibit 3585-X0859, paragraph 252. 410 Exhibit 3585-X0666, paragraphs 193-194. 411 Decision 2013-407 paragraph 737.
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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 Decision 2013-407, paragraph 753. 413 Decision 2013-407, paragraph 758. 414 Exhibit 3585-X0667. 415 Exhibit 3585-X0667, PDF page 80. 416 Exhibit 3585-X0667, PDF page 82. 417 Exhibit 3585-X0667, PDF page 85.
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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 420 performance” that “virtually eliminates SNC-ATP’s obligation to control costs and greatly 421 reduces SNC-ATP’s responsibility” 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 Exhibit 3585-X0667, PDF page 91. 419 Proceeding 13898, Application 1336421-1, AltaLink argument refiling November 22, 2004, PDF page 138. 420 Exhibit 3585-X0667, PDF page 86. 421 Exhibit 3585-X0667, PDF page 87. 422 Exhibit 3585-X0667, PDF pages 79-82.
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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 425 competitive bid process is but one. 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 Exhibit 3585-X0667, PDF pages 80-81. 424 Exhibit 3585-X0160, PDF pages 6-7. 425 Exhibit 3585-X0160, PDF pages 63-64.
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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 Exhibit 3585-X0667, PDF page 82. 427 Omers Energy Inc. v. Alberta (Energy Resources Conservation Board) 2011 ABCA 251.
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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.
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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 Exhibit 3585-X0859, paragraph 256.
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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
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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.
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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.
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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 Transcript, Volume 3, pages 487-489. 446 Exhibit 3585-X0860, PDF page 58. 447 Exhibit 3585-X0863, PDF page 49.
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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.
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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 Exhibit 3585-X0665, PDF page 29. 452 Exhibit 3585-X0666, PDF page 3. 453 Exhibit 3585-X0665, PDF pages 8-9. 454 Exhibit 3585-X0665, PDF pages 9-10. 455 Exhibit 3585-X0665, PDF pages 11-13.
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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-X0665, PDF page 12. 457 Exhibit 3585-X0665, PDF page 16. 458 Exhibit 3585-X0696, CCA-AML-2015SEP24-010, PDF page 16. 459 Exhibit 3585-X0665, PDF pages 15-23. 460 Exhibit 3585-X0665, PDF pages 26 and 28. 461 Exhibit 3585-X0704, PDF page 171. 462 Exhibit 3585-X0704, PDF page 173.
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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 Exhibit 3585-X0704, PDF pages 172-173. 466 Exhibit 3585-X0704, PDF pages 43-44.
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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 Exhibit 3585-X0704, PDF pages 174-176. 470 Exhibit 3585-X0704, PDF pages 178-180.
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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-X0704, PDF page 173. 473 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.
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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 4, pages 605-606. 478 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 495, lines 22-24. 482 Transcript, Volume 3, page 530, lines 10-13.
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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 Transcript, Volume 10, pages 1757-1759. 485 Exhibit 3585-X0708, Manitoba Hydro report, PDF page 3. 486 Transcript, Volume 3, pages 545-546. 487 Transcript, Volume 3, page 548. 488 Transcript, Volume 4, pages 618-619. 489 Transcript, Volume 10, pages 1736-1740. 490 Exhibit 3585-X0859, PDF pages 77-79.
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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-X0860, PDF pages 56-59. 492 Exhibit 3585-X0863, PDF page 45. 493 Exhibit 3585-X0863, PDF page 47. 494 Exhibit 3585-X0865, PDF pages 45-46. 495 Exhibit 3585-X0666, PDF page 53. 496 Exhibit 3585-X0699, RPG-AML-2015SEP24-020(a), PDF page 30. 497 Exhibit 3585-X0666, PDF pages 54-55. 498 Exhibit 3585-X0689, CCA-AUC-2015SEP24-009(b), PDF page 24.
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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 Exhibit 3585-X0666, PDF pages 53-57. 501 Exhibit 3585-X0704, PDF page 52.
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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 Transcript, Volume 2, pages 228-229. 503 Exhibit 3585-X0734a-CONF, Exhibit 3585-X0734b-CONF and Exhibit 3585-X0734c-CONF. 504 Transcript, Volume 1, page 130, lines 1-9. 505 Exhibit 3585-X0735. 506 Exhibit 3585-X0742-CONF. 507 Decision 2014-283, paragraph 190.
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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.
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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.
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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.
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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.
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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.0353 Hanna Area D.0354 Hanna Area D.0355 Hanna Area D.0305 Cassils to D.0371 Transmission – Transmission – Transmission – Bowmanton Heartland Nilrem Hansman Lake Ware Junction $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 Exhibit 3585-X0666, PDF page 49.
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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.
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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-X0704, paragraph 558. 523 Exhibit 3585-X0860, page 62, refers to Exhibit 3585-X0704, paragraph 560. 524 Exhibit 3585-X0704, paragraph 560, PDF page 159. 525 Decision 2011-250, paragraph 117. 526 Transcript, Volume 10, page 1793, lines 4-8. 527 Transcript, Volume 10, page 1793, lines 4-8. 528 Transcript, Volume 10, page 1793, line 24 to page 1794, line 2. 529 Transcript, Volume 10, page 1794, lines 5-23.
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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 533 because it mitigates the concerns of landowners. However, the RPG noted with respect to the 534 CB project, the mitigating measure suggested before AltaLink changed its matting plan 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-X0859, paragraph 349. 531 Exhibit 3585-X0859, paragraph 348, PDF page 83. 532 Exhibit 3585-X0666, paragraphs 163-164, PDF page 52. 533 Exhibit 3585-X0859, paragraph 348, PDF page 83. 534 Exhibit 3585-X0704, paragraph 560, PDF page 159. 535 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-X0704, paragraph 558. 539 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.
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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 543 indicator of the imprudence of AltaLink’s matting practices. 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 544 Electric Transmission does not use matting to the same extent as AltaLink.”
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-X0860, paragraph 250. 542 Exhibit 3585-X0704, paragraph 557. 543 Exhibit 3585-X0860, paragraph 253. 544 Exhibit 3585-X0704, paragraph 253, PDF page 63.
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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 Exhibit 3585-X0704, paragraph 123. 546 Exhibit 3585-X0666, paragraph 127.
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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 549 inaccessible to cranes and other vehicles 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 550 the line. 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-X0666, paragraph 137. 548 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.
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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 553 practice for a range of transmission line activities, 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-X0704, paragraph 167. 553 Exhibit 3585-X0704, paragraph 165, PDF page 54. 554 Exhibit 3585-X0666, paragraph 129, PDF pages 37-38; Transcript, Volume 10, page 1800, lines 8-13, and page 1797, lines 15-22. 555 Exhibit 3585-X0704, paragraph 478, PDF page 135. 556 Exhibit 3585-X0689, PDF page 17.
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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 Exhibit 3585-X0860, paragraph 262. 558 Exhibit 3585-X0863, paragraph 247.
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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,
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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.
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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.
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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 Exhibit 3585-X0859, paragraph 136. 569 Exhibit 3585-X0859, paragraph 137. 570 Transcript, Volume 5, pages 1024-1025, cited at Exhibit 3585-X0859, paragraph 138. 571 Exhibit 3585-X0859, paragraph 138. 572 Exhibit 3585-X0859, paragraph 139. 573 Exhibit 3585-X0042, AML-AUC-2015MAR05-028, cited at Exhibit 3585-X0859, paragraph 140. 574 Transcript, Volume 5, page 1026. 575 Exhibit 3585-X0859, paragraph 141, referencing Transcript, Volume 1, pages 97-98. 576 Exhibit 3585-X0859, paragraph 142.
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(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.
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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 +/- 10% update Additions to Dec Estimated Final PPS Jun 29, 2012 31, 2013(6) 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 2009-126, paragraph 10.
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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 0020.00.AML-3585, paragraph 2. 581 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.
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Table 9. CB change notices
Impact # Analysis Summary of Requested Cost Months Date Change
Change Impact ISD Submitted Notice Status
$M Shifted
Scope Schedule Cost CP X AFUDC reconciliation (48.3) - Nov 2012 Approved AFUDC1 CP AFUDC2 X AFUDC reconciliation (0.2) - May 2013 Approved Project proceeding ahead of CP3 X schedule - -4 Oct 2013 Approved AFUDC correction to CP4 X coding 0.5 - Nov 2013 Approved Delay FCR to include CP5 X accurate AC mitigation - - May 2014 Acknowledged costs – YE 2014 CP6 X Pipeline AC mitigation 19.9 - Jul 2014 Approved Delay FCR to include CP7 X accurate AC mitigation - - Nov 2014 Acknowledged costs – June 2015
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.
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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.
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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 Exhibit 3585-X0704, paragraph 442.
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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 655. As more particularly detailed in Section 4.1.17 of this decision, the RPG was critical of 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.
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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.
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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 0018.00.AML-3585, PDF page 162. 594 Exhibit 3585-X0098, AML-CCA-2015MAR05-067 Attachment 1, PDF page 331. 595 Exhibit 0018.00.AML-3585, PDF page 20. 596 Exhibit 3585-X0704, PDF page 156. 597 Exhibit 0025.00.AML-3585, PDF page 416. 598 Exhibit 0025.00.AML-3585, PDF page 424.
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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 0024.00.AML-3585, PDF pages 33-38. 600 Exhibit 3585-X0704, PDF page 157. 601 Exhibit 3585-X0666, PDF page 32. 602 Exhibit 3585-X0042, AML-AUC-2015MAR05-038(a), PDF page 450. 603 Exhibit 3585-X0666, PDF pages 34-36. 604 Exhibit 3585-X0704, PDF pages 155-157.
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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 Exhibit 3585-X0863, PDF page 65. 606 Exhibit 0017.00.AML-3585, PDF page 5.
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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.
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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.
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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 Estimated +/- 10% Additions to Final PPS Oct 12, 2012 Dec 31, 2014 Cost Transmission line materials 89,671,806 73,106,196 71,747,423 73,066,582 Transmission line labour 183,213,434 257,940,503 369,870,072 381,282,634 Substation materials 28,551,035 19,952,891 23,351,265 23,380,047 Substation labour 25,344,287 33,536,822 41,162,801 44,281,778 Telecommunication materials 437,699 443,261 259,215 258,529 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 Total project costs(1) 579,613,427 600,162,476 697,115,788 712,463,796 (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.
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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.
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Table 11. Heartland change notices AESO Impact Change Analysis Summary of Cost Impact # Date Change Notice No. Requested Change Months Submitted Notice (TCA or ISD Status
CP) Shifted
Scope Schedule Cost Bannerman project TCA1 X X delay resulted in $61,000 - Dec. 2011 Rejected additional scope TCA2 X X X Reconcile to AUC $41,177,888 6 Dec 2011 Acknowledged Decision TCA3 X X Redesign 240-kV yard $279,939 - Mar 2012 Approved electrical scheme CP4 X Remove AFUDC ($33,514,531) - Nov 2012 Approved
Bannerman project CP5 X X delay resulted in $519,985 - Apr 2013 Approved additional scope CP6 X Subcontractor re- - 2 Apr 2013 Approved contracting True-up to PPS Update CP7 X Estimate (+/- 10%) $12,568,409 - Oct 2013 Approved
Bannerman project CP8 X X delay resulted in ($617,400) - Oct 2013 Approved reduction in scope Temporary CP9 X X X energization at $4,917,567 - Nov 2013 Approved 240 kV CP10 X Additional construction $56,737,229 - Feb 2014 Rejected costs CP11 X Increased cost of AC $50,652,640 - Feb 2014 Approved Mitigation X X Complete CP12 energization at $2,788,678 7.5 Jan 2014 Approved 500 kV
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.
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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 0002.00.AML-3585, paragraph 4. 622 Exhibit 3585-X0666, paragraph 46. 623 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.
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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-X0704, paragraph 410. 627 Exhibit 3585-X0860, paragraph 317. 628 Exhibit 3585-X0860, paragraph 318. 629 Exhibit 3585-X0860, paragraph 319. 630 Exhibit 3585-X0860, paragraph 320. 631 Exhibit 3585-X0860, paragraph 321. 632 Exhibit 3585-X0860, paragraph 322. 633 Exhibit 3585-X0859, paragraph 522. 634 Exhibit 3585-X0859, paragraph 525, citing Transcript, Volume 9, pages 1597-1598.
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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 Exhibit 3585-X0859, paragraph 527. 636 Exhibit 3585-X0859, paragraph 528, citing Transcript, Volume 10, pages 1811-1812. 637 Exhibit 3585-X0859, paragraph 529, citing Transcript, Volume 9, page 1627. 638 Exhibit 3585-X0863, paragraph 300. 639 Transcript, Volume 10, page 1811. 640 Exhibit 3585-X0863, paragraph 302.
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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 page 52. 644 Exhibit 0092.00.AML-3585, PDF pages 7 and 10. 645 Exhibit 0092.00.AML-3585, PDF page 13. 646 Exhibit 0092.00.AML-3585, PDF page 15.
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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 Exhibit 0092.00.AML-3585, PDF page 14. 648 Exhibit 0098.00.AML-3585, PDF page 19. 649 Exhibit 0087.00.AML-3585, PDF page 11. 650 Exhibit 0089.00.AML-3585, PDF pages 66-67. 651 Exhibit 0087.00.AML-3585, PDF page 15. 652 Exhibit 0089.00.AML-3585, PDF page 489. 653 Transcript, Volume 1, page 78, lines 10-21. 654 Exhibit 0087.00.AML-3585, PDF page 37.
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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 0087.00.AML-3585, PDF page 21. 656 Exhibit 3585-X0098, AML-CCA-2015MAR05-048 Attachment 1, PDF page 55. 657 Note: the appendices were not included in this proceeding. 658 Exhibit 0089.00.AML-3585, PDF page 65. 659 Exhibit 0089.00.AML-3585, PDF page 909. 660 Exhibit 0093.00.AML-3585, PDF pages 7-8.
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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 Exhibit 3585-X0704, PDF page 83. 664 Exhibit 3585-X0704, PDF pages 75-76. 665 Exhibit 3585-X0859, PDF page 123.
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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.
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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 746. As more particularly detailed in Section 4.1.17 of this decision, the RPG was critical of 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
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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.
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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 Exhibit 0089.00.AML-3585, PDF page 105. 672 Exhibit 0087.00.AML-3585, PDF page 40. 673 Exhibit 0087.00.AML-3585, PDF page 42. 674 This was not provided on the record of this proceeding. 675 Exhibit 0087.00.AML-3585, PDF page 30. 676 Exhibit 0087.00.AML-3585, PDF page 74. 677 Exhibit 3585-X0042, AML-AUC-2015MAR05-055(a), PDF page 488. 678 Exhibit 0006.00.AML-3585, Tab D.0371. 679 Exhibit 3585-X0042, AML-AUC-2015MAR05-045(a-b), PDF pages 465 and 468.
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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.
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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-X0666, PDF pages 28-29. 691 Exhibit 3585-X0689, CCA-AUC-2015SEP24-006, PDF pages 13-15. 692 Exhibit 3585-X0689, CCA-AUC-2015SEP-24-006, PDF page 16. 693 Transcript, Volume 9, pages 1550-1552. 694 Transcript, Volume 9, page 1551, lines 1-5. 695 Transcript, Volume 9, pages 1558-1559.
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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-X0666, PDF page 28. 698 Exhibit 3585-X0666, PDF page 29. 699 Exhibit 3585-X0042, AML-AUC-2015MAR05-055(b), PDF page 488.
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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-X0704, PDF pages 116-117. 701 Exhibit 3585-X0689, RPG-AML-2015SEP24-009(a) and 010(A), PDF pages 13 and 15. 702 Exhibit 3585-X0704, PDF page 118. 703 Exhibit 3585-X0860, PDF pages 80-81.
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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 Exhibit 3585-X0859, PDF pages 134-138. 705 Exhibit 3585-X0865, PDF page 57. 706 Exhibit 3585-X0865, PDF pages 59-60. 707 Exhibit 3585-X0863, PDF page 67.
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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 Decision 2011-436, paragraph 663.
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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.
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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-X0667, PDF page 95. 714 Exhibit 3585-X0667, PDF page 44. 715 Exhibit 3585-X0667, PDF page 47. 716 Exhibit 3585-X0704, paragraph 385. 717 Exhibit 0093.00.AML-3585, PDF page 7. 718 Exhibit 3585-X0704, paragraph 245. 719 Exhibit 3585-X0704, paragraphs 247-248.
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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-X0860, paragraph 341, citing Exhibit 3585-X0667, PDF page 46. 721 Exhibit 3585-X0859, paragraph74. 722 Exhibit 3585-X0859, paragraph 578.
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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 Exhibit 3585-X0863, paragraph 317. 724 Exhibit 3585-X0863, paragraph 318. 725 Exhibit 3583-X0704, paragraph 245. 726 Exhibit 3585-X0089, PDF pages 421-422.
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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 Exhibit 3585-X0667, PDF page 49.
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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 Exhibit 3585-X0667, PDF page 67. 729 Exhibit 3585-X0704, paragraph 305. 730 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-X0704, paragraph 306. 732 Exhibit 3585-X0860, paragraph 342, citing Exhibit 0093.00.AML-3585, PDF pages 140-157. 733 Exhibit 3585-X0860, paragraph 343.
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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 Exhibit 3585-X0860, paragraph 348. 735 Exhibit 3585-X0860, paragraph 349. 736 Exhibit 3585-X0860, paragraph 350. 737 Exhibit 3585-X0863, paragraph 323. 738 Exhibit 3585-X0863, paragraph 324.
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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 Exhibit 3585-X0704, paragraph 254.
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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.
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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 743 limited exceptions, Rule 9.1.5.5 requires selection of the lowest priced compliant bid.
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 746 any items to Graham. 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 Exhibit 3585-X0704, paragraphs 286 and 291. 745 Exhibit 3585-X0860, paragraph 359. 746 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.
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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 3585-X0860, paragraph 363. 749 Exhibit 0086.00.AML-3585.
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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 Exhibit 3585-X0704, paragraph 206, PDF page 65. 751 Exhibit 3585-X0704, PDF page 83.
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(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.
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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.
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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 Description No./Document No. Rokstad Subcontract amendment 1, Exhibit 382, Quality control on towers to document 371 in subfolder C44 determine deficiencies and repairs needed Rokstad Subcontract amendment 7, Exhibit 382, Completion of towers started by document 377 in subfolder C44 Graham Rokstad Subcontract amendment 8, Exhibit 382, Quality control of Graham towers document 378, page 25 of 40, EWR 28, Rev 5 Henkels & McCoy Subcontract amendment 7, Exhibit 382, Completion of Graham towers document 390 in subfolder C35
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 Exhibit 3585-X0440, PDF page 10. 766 This amount is shown in Exhibit 3585-X0819b, PDF page 8, item 3 of the 5 items list.
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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.
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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 Exhibit 3585-X0042, PDF page 99. 771 Transcript, Volume 7, page 1323. 772 Transcript, Volume 7, pages 1323-1324. 773 Exhibit 3585-X0859, paragraph 696. 774 Exhibit 3585-X0859, paragraph 697. 775 Exhibit 3585-X0859, paragraph 699. 776 Exhibit 3585-X0859, paragraph 700.
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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 Exhibit 3585-X0860, paragraph 370. 778 Exhibit 3585-X0860, paragraph 371. 779 Exhibit 0086.00.AML-3585, paragraph 27. 780 Exhibit 3585-X0042, PDF page 99. 781 Exhibit 0086.00.AML-3585.
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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.
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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
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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 +/- 10% update Addition to Final Cost Mar 23, 2010 Nov 7, 2011 Dec 31, 2013(3) Report(3) Transmission line materials 12,022,000 9,956,554 10,490,917 10,410,037 Transmission line labour 16,543,000 14,393,105 41,582,110 42,067,825 Substation materials 738,000 824,028 819,319 819,319 Substation labour 1,153,000 2,322,975 2,569,915 2,594,542 Telecommunication materials 25,000 6,932 11,496 11,496 Telecommunication labour 159,000 167,819 175,612 175,612 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 Total owner costs 2,246,000 1,884,789 2,613,817 2,554,257
782 Exhibit 0184.00.AML-3585. 783 Exhibit 0174.00.AML-3585, PDF page 7, paragraph 15.
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PPS +/- 10% update Addition to Final Cost Mar 23, 2010 Nov 7, 2011 Dec 31, 2013(3) Report(3) 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 - - Total distributed costs 10,973,000 9,495,405 8,324,528 10,035,163 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 $47.4 million and a forecast ISD of November 2011.786
911. AltaLink filed a facility application to meet the Hinton/Edson transmission planning area need considered in Decision 2010-208 in August 2010. The scope of the project included the construction of new 138-kV transmission lines connecting its Edson 58S substation and Cold Creek 602S substation to its Bickerdike 39S substation and included the replacement and alteration of approximately 84 km of the existing single‐circuit 138-kV transmission line 745L between Cold Creek 602S substation and Edson 58S substation.787 The Commission approved this facility application in Decision 2011-188 on April 29, 2011.
784 Decision 2010-208, paragraph 2. 785 Decision 2010-208: Alberta Electric System Operator, Needs Identification Document Application, Yellowhead Area Transmission System Development, Proceeding 270, Application 1605154-1, May 12, 2010. 786 Exhibit 0174.AMl-3585, page 3. 787 Exhibit 0174.AMl-3585, page 4 and Decision 2011-188, paragraph 4.
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912. In conjunction with Decision 2011-188,788 the Commission issued a number of P&Ls or approvals. In Decision DA2012-185,789 the Commission approved a time extension in respect of approved alterations to transmission line 745L from July 31, 2012 to December 31, 2012.790
913. A table listing the proceedings, decisions and associated approvals issued by the Commission in respect of AltaLink project D.0030.01 is in Appendix 4.
914. The project was energized on October 31, 2012.791
4.2.3.1.3 Key project variances 915. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 15 below:
Table 15. Project D.0030.01 key cost variance events Change report Cost Impact identifier Reason or Need ($) 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, 15,398,424 additional subcontractor hours, and additional project management, construction management and procurement management costs. CP-AFUDC AFUDC Reconciliation (558,493) Source: Exhibit 0182.00.AML-3585, PDF page 289.
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 0174.00.AML-3585, PDF pages 4 and 7. 792 Exhibit 3585-X0042, AML-AUC-2015MAR05-029(b), PDF pages 428-430.
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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-X0859, PDF page 166. 796 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 Exhibit 3585-X0859, PDF pages 166-167.
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4.2.3.2 D.0030.03 – Yellowhead Area Transmission Development Cherhill Area Development 4.2.3.2.1 Recovery requested 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 +/-10% update Additions to Final report PPS Nov 7, 2011 Dec 31, 2013(2) Feb 18, 2014(2) Transmission line materials 568,000 321,106 330,997 330,057 Transmission line labour 1,449,000 1,361,161 1,304,645 1,253,507 Substation materials 5,055,000 5,874,715 5,543,488 5,542,253 Substation labour 5,265,000 6,406,035 6,493,799 6,483,231 Telecommunication materials 485,000 232,002 219,519 219,567 Telecommunication labour 839,000 542,625 562,141 579,388 O: proposal to provide service 227,000 Not provided 0 0 O: facility applications 250,000 Not provided 600,000 600,000 O: land-rights - easements 200,000 Not provided 100,000 100,000 O: land-rights – damage claims 0 Not provided 200,000 200,000 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: procurement 377,000 Not provided 500,000 500,000 D: project management 1,806,000 Not provided 3,100,000 3,300,000 D: construction management 1,248,000 Not provided 1,500,000 1,500,000 D: escalation Not provided 0 - D: escalation contingency (cont) 4,737,000 Not provided 0 - Total distributed costs 8,168,000 7,745,797 5,067,359 5,346,667 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.
4.2.3.2.2 Project overview 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 Exhibit 0215.00.AML-3585, PDF page 482.
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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 $24.6 million and a target ISD of March 28, 2011.803
927. AltaLink filed a facility application on July 26, 2010. The scope of the project included construction of a new 240/25-kV substation, designated as Cherhill 338S, the construction of approximately 100 m of two single‐circuit 240-kV transmission lines and the decommissioning and salvaging of existing 69-kV transmission lines.804 The Commission approved the facility application in Decision 2011-161 on April 21, 2011.
928. In conjunction with Decision 2011-161, the Commission issued a number of P&Ls or approvals. In Decision DA2013-53,805 the Commission approved a request to extend three P&Ls from June 30, 2012 to December 31, 2013, regarding the decommissioning and salvaging of some transmission lines.806
929. A table listing the proceedings, decisions and associated approvals issued by the Commission in respect of the Yellowhead Cherhill project is in Appendix 4.
930. The project was energized on April 2, 2012.807
4.2.3.2.3 Key project variances 931. AltaLink identified the following key trends and changes as affecting project cost variances as set out in AltaLink’s initial application evidence:
Table 17. Project D.0030.03 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA #3 Change in scope 10,000 7L230 - improve the line rating to 114/143 MVA CP-AFUDC AFUDC reconciliation ($779,910) Source: Exhibit 0215.00.AML-3585, AESO change notices, PDF pages 146 and 155-157.
801 Decision 2010-208, paragraph 2. 802 Exhibit 3585-X0859, PDF page 168. 803 Exhibit 0215.00.AML-3585, PDF page 4. 804 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 Exhibit 215.00.AML-3585, PDF page 118. 807 AESO transmission System Projects – Quarterly Report – Q3 2012 (retrieved from http://www.aeso.ca/downloads/2012_Q3_Tx_System_Quarterly_Report_R1.pdf).
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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 4.2.3.3.1 Recovery requested 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 +/- 10 update Additions to Final report June 5, 2008 September 2011 Dec 31, 2013(2) Oct 1, 2012(2) Transmission line materials 1,439,000 1,412,845 1,420,469 1,420,469 Transmission line labour 2,023,000 2,939,187 4,432,375 4,432,375 Substation materials 349,000 510,020 465,727 465,727 Substation labour 657,000 1,091,379 1,049,015 1,049,014 Telecommunication materials 3,000 4,739 1,856 1,856 Telecommunication labour 59,000 51,249 36,395 36,394 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-rights – damage claims 0 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 Exhibit 0002.00.AML-3585, PDF page 45. 809 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 810 Exhibit 0162.00.AML-3585, PDF page 482.
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PPS +/- 10 update Additions to Final report June 5, 2008 September 2011 Dec 31, 2013(2) Oct 1, 2012(2) D: procurement 135,000 Not provided 300,000 300,000 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 - - D: contingency 1,115,000 Not provided - - Total distributed costs 2,410,000 1,814,613 2,193,695 2,193,695 OT: ES&G 515,000 556,957 432,118 432,972 OT: AFUDC 38,000 454,467 311,734 311,745 Total project costs(1) 7,954,000 9,104,117 10,620,429 10,621,290 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.
4.2.3.3.2 Project overview 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.
940. A table listing the proceedings, decisions and associated approvals issued by the 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 Exhibit 0154.00.AML-3585, PDF page 8. 813 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.
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941. The project was energized in January 2012, two years after forecast, at a total project cost of $10.7 million (as outlined in the 150-day final cost report).815
4.2.3.3.3 Key project variances 942. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 19 below:
Table 19. Project D.0108 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA #2 666L Incremental Scope of Work $ 549,000 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. TCA #3 Project costs estimated in 2008, but project executed in 2011 $1,310,000 Longer regulatory process extended the Project life cycle by one year, escalation in construction, materials, and project management. 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 evidence, nor in argument and reply.
Commission findings 947. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 0153.00.AML-3585, PDF page 7. 816 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.
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4.2.3.4 D.0213 – Edmonton Region 240-kV Lines Upgrades 4.2.3.4.1 Recovery requested 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.
4.2.3.4.2 Project overview 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 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 819 Need Assessment Approval U2009-62: Alberta Electric System Operator, Edmonton Region 240-kV Transmission System Updates, Application 1584342-1, February 24, 2009. 820 Exhibit 0193.00.AML-3585, PDF pages 90-91.
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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.
953. A table listing the proceedings, decisions and associated approvals issued by the 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
4.2.3.4.3 Key project variances 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 Exhibit 0193.00.AML-3585, PDF page 99. 822 Exhibit 3585-X0859, PDF page 170. 823 Exhibit 0193.00.AML-3585, PDF page 6. 824 Decision 2012-293, paragraph 15. 825 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.
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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 4.2.3.5.1 Recovery requested 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 Exhibit 3585-X0042, AML-AUC-2015MAR05-042 Attachment. 829 Exhibit 0186.00.AML-3585, PDF page 463.
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Table 21. Athabasca Area Telecom Development cost breakdown PPS +/- 10 update Additions to Final report Mar 3, 2010 Aug 31, 2012 Dec 31, 2013(2) 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: facility applications 430,000 Not provided 600,000 800,000 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: procurement 212,000 Not provided 400,000 400,000 D: project management 1,193,000 Not provided 1,800,000 2,000,000 D: construction management 1,166,000 Not provided 1,700,000 1,700,000 D: escalation 500,000 Not provided - - D: contingency 1,833,000 Not provided - - Total distributed costs 4,904,000 4,562,117 3,845,252 4,100,806 OT: ES&G 1,054,000 870,000 694,973 707,187 OT: AFUDC 843,000 63,882 63,882 63,882 Total project costs(1) 19,936,000 17,362,175 16,056,463 17,201,734 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.
4.2.3.5.2 Project overview 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 $20 million and a forecast ISD of December 31, 2011.831
966. AltaLink filed a facility application in September 2010. The scope of the project included the construction of new radio sites adjacent to existing substations, construction of new radio sites, alterations to the associated existing substations and radio sites and the decommissioning and salvage of the existing telecommunications towers at the certain substations in the Athabasca area.832 The Commission approved the facility application in Decision 2012-064 on March 8, 2012.
830 Decision 2012-023, paragraph 1. 831 Exhibit 0186.00.AML-3585, PDF page 7. 832 Decision 2012-064, paragraphs 5-7.
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967. In conjunction with Decision 2012-064, the Commission issued a number of P&Ls or approvals. In Decision DA2012-240,833 the Commission approved a time extension from September 30, 2012 to December 31, 2012. In Decision DA2013-44,834 the Commission approved a further time extension from December 31, 2012 to April 30, 2013.
968. A table listing the proceedings, decisions and associated approvals issued by the Commission in respect of this project is in Appendix 4.
969. The project was completed in 2013.
4.2.3.5.3 Key project variances 970. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence are summarized in Table 22 below:
Table 22. Project D.0238 key cost variance events Change Description of Trends and Changes Cost Impact report identifier Reason or Need ($) 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 evidence, nor in argument and reply.
Commission findings 974. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 Exhibit 3585-X0859, PDF page 171. 836 Transcript, Volume 7, pages 1283-1284.
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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 Exhibit 0042.00.AML-3585, paragraph 2. 839 Exhibit 0042.00.AML-3585, paragraph 10. 840 Exhibit 0042.00.AML-3585, paragraph 11. 841 Exhibit 0042.00.AML-3585, PDF page 7. 842 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.
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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 Exhibit 3585-X0859, PDF page 172.
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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.
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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 995. In the application, AltaLink requested additions to rate base in the amount of $3.5 million 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-X0043, AML-AUC-2015MAR05-042 Attachment. 847 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 324.
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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 +/- 10 update Additions to Final report Jan 5, 2010 Jan 11, 2013 Dec 31, 2013(2) Dec 1, 2014(2) Transmission line materials 9,780,000 8,858,000 10,640,749 9,011,936 Transmission line labour 20,664,000 35,416,000 41,437,505 42,202,798 Substation materials 12,970,000 10,798,000 10,837,405 10,894,378 Substation labour 8,605,000 12,974,000 13,356,092 13,146,183 Telecommunication materials 113,000 193,000 198,013 194,352 Telecommunication labour 270,000 272,000 322,480 341,014 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 Total owner costs 3,221,000 4,877,000 4,782,954 5,008,548 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 Total distributed costs 14,075,000 12,159,000 8,361,011 12,369,558 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 Total project costs(1) 76,488,000 89,333,000 93,091,818 96,267,167 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.
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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
1004. A table listing the proceedings, decisions and associated approvals issued by the 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 Exhibit 0054.00.AML-3585, PDF page 134. 850 Decision 2011-445, paragraph 177. 851 Decision 2011-191, paragraph 6. 852 Decision 2012-358, paragraphs 4-5. 853 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 Exhibit 0052.00.AML-3585, PDF page 2. 858 Exhibit 0051.00.AML-3585, PDF page 3.
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4.2.3.6.1.3 Key project variances 1006. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 24 below:
Table 24. Project D.0353 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA #1 More lengthy consultation process than expected due to recent 4,787,000 involvement of landowner association in the area such as CAEPLA and the need to add a second round of landowner consultation. TCA#2 Early land compensation package for landowner located on the 368,000 preferred 240-kV line route. TCA#6 Swap location for one new 138-kV tie-bus switch at the request of 51,000 Fortis/AESO. TCA#7/8 This change has occurred as a consequence of the recent AUC 4,532,854 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. CP-AFUDC AFUDC Reconciliation (5,448,263) CP#10 Updated Service Proposal +/-10% Estimate on 15-Jan-13 and 13,086,000 meeting with the AESO on 22-Jan-13. CN submitted on February 8, 2013. Approved on May 7, 2013. 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 2011-445, paragraph 178.
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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 Exhibit 0058.00.AML-3585, change notice #7/8, PDF page 35. 863 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 #7/8, PDF page 36. 865 Exhibit 0058.00.AML-3585, change notice #7/8, PDF page 35. 866 Exhibit 0058.00.AML-3585, change notice #16, PDF pages 66-67. 867 Exhibit 3585-X0045, AML-CCA-2015MAR05-015(e), PDF page 221. 868 Exhibit 3585-X0045, AML-CCA-2015MAR05-015(d)(iv), PDF page 220. 869 Exhibit 0002.00.AML-3585, PDF page 45.
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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 1019. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.6.2.1 Recovery requested 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 Exhibit 3585-X0859, PDF pages 173-174. 871 See Section 25.2 of the Transmission Regulation. 872 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment.
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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 +/- 10 update Additions to Final report Feb 9, 2010 Jan 11, 2013 Dec 31, 2013(2) Dec 1, 2014(2) Transmission line materials 7,230,000 7,230,000 6,907,144 7,142,095 Transmission line labour 13,887,000 35,297,000 34,451,187 33,887,133 Substation materials 24,596,000 25,583,000 24,555,109 25,663,699 Substation labour 8,798,000 9,214,000 4,091,059 7,778,712 Telecommunication materials 35,000 36,000 3,675 1,625 Telecommunication labour 82,000 88,000 61,243 64,358 O: proposal to provide service 75,000 686,000 500,000 1,200,000 O: facility applications 370,000 1,892,000 3,200,000 1,100,000 O: land-rights - easements 1,375,000 1,423,000 1,400,000 1,500,000 O: land-rights – damage claims 0 147,000 200,000 300,000 O: land - acquisitions 0 1,082,000 200,000 200,000 O: ROW Costs 0 0 0 0 Total owner costs 1,820,000 5,230,000 5,456,544 4,288,485 D: procurement 256,000 895,000 1,200,000 1,100,000 D: project management 2,577,000 2,725,000 6,200,000 5,000,000 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 Total distributed costs 12,900,000 12,162,000 9,411,828 10,007,040 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 Total other costs 13,008,000 4,021,000 2,812,682 2,753,956 Total project costs(1) 82,349,400 98,859,000 87,753,471 91,587,103 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.
4.2.3.6.2.2 Project overview 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 Exhibit 0043.00.AML-3585, PDF pages 277-278.
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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.
1030. A table listing the proceedings, decisions and associated approvals issued by the 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
4.2.3.6.2.3 Key project variances 1032. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 26 below:
875 Decision 2012-120, paragraph 48. 876 Decision 2011-175: AltaLink Management Ltd., Hansman Lake 650S Substation, Metiskow Area, Proceeding 974, Application 1606802-1, April 27, 2011.paragraph 4. 877 Exhibit 0044.00.AML-3585, PDF page 10. 878 Exhibit 0041.00.AML-3585, PDF page 1. 879 Exhibit 0040.00.AML-3585, PDF page 8. 880 Exhibit 3585-X0042, AML-AUC-2015MAR05-040(b), PDF page 456.
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Table 26. Project D.0354 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA #3 Early land compensation package for landowner located on the 474,000 preferred 240-kV line route TCA#5 Due to late start by AUC to review the Facilities Application (FA) filed 0 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) TCA#9 SVC ISD change ($100,000 of contingency used) 0 CP-AFUDC AFUDC Reconciliation (8,691,879) CP#11 Updated Service Proposal +/-10% Estimate on 15-Jan-13 and 24,750,000 meeting with the AESO on 22-Jan-13. CN submitted on February 8, 2013. Approved on May 7, 2013. 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
1036. 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.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 3585-X0045, AML-CCA-2015MAR05-015(e), PDF page 221. 884 Exhibit 0002.00.AML-3585, PDF page 45. 885 Exhibit 0040.00.AML-3585, PDF pages 3, 4 and 7.
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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.
1041. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.6.3.1 Recovery requested 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-X0859, PDF pages 175-176. 887 Transcript, Volume 6, pages 1236-1240. 888 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.
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Table 27. SATR Ware cost breakdown PPS +/- 10 update Additions to Final report Sept 29, 2010 Jan 11, 2013 Dec 31, 2013(2) Dec 11, 2014(2) Transmission line materials 118,000 120,000 84,645 84,645 Transmission line labour 172,000 187,000 186,204 229,126 Substation materials 1,761,000 1,836,000 1,531,252 1,488,971 Substation labour 1,262,000 1,860,000 2,738,539 2,512,342 Telecommunication materials 42,000 42,000 7,107 50,281 Telecommunication labour 80,000 80,000 108,652 124,907 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 O: ROW Costs 0 0 0 0 Total owner costs 140,000 136,000 139,489 136,509 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 Total distributed costs 1,703,000 2,223,000 1,066,929 1,775,447 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 Total project costs(1) 6,098,000 6,774,000 6,027,657 6,564,655 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 +/- 10 update Additions to Final report Mar 2, 2010 Jan 11, 2013 Dec 31, 2013(2) Dec 1, 2014(2) Transmission line materials 12,326,000 8,858,000 15,989,750 15,543,939 Transmission line labour 29,674,000 35,416,000 63,780,638 63,203,914 Substation materials 4,874,000 10,798,000 5,280,462 5,284,115 Substation labour 3,668,000 12,974,000 9,590,749 9,493,740 Telecommunication materials 12,000 193,000 33,716 33,716 Telecommunication labour 90,000 272,000 71,125 252,865 O: proposal to provide service 95,000 180,000 100,000 100,000 O: facility applications 630,000 2,068,000 1,600,000 1,900,000 O: land-rights - easements 2,679,000 1,761,000 4,200,000 4,300,000 O: land-rights – damage claims 0 33,000 100,000 100,000 O: land - acquisitions 0 836,000 100,000 100,000 O: ROW Costs 0 0 0 0 Total owner costs 3,404,000 4,877,000 6,109,929 6,509,205 D: procurement 314,000 1,112,000 700,000 600,000 D: project management 2,532,000 4,307,000 3,800,000 5,500,000 D: construction management 1,182,000 2,429,000 1,000,000 3,000,000 D: escalation 0 560,000 0 0
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PPS +/- 10 update Additions to Final report Mar 2, 2010 Jan 11, 2013 Dec 31, 2013(2) Dec 1, 2014(2) D: contingency 12,304,000 3,752,000 0 0 Total distributed costs 16,332,000 12,159,000 5,560,611 9,128,223 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 Total other costs 8,277,000 3,786,000 3,431,175 3,396,864 Total project costs(1) 78,227,000 89,333,000 109,848,153 112,846,580 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 Exhibit 0019.00.AML-3585, PDF pages 9 and 13. 891 Exhibit 0042.00.AML-3585, PDF pages 7 and 9. 892 Decision 2011-102, PDF page 7.
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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.
1055. A table listing the proceedings, decisions and associated approvals issued by the 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
4.2.3.6.3.3 Key project variances 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 Exhibit 0075.00.AML-3585, PDF page 3. 898 Exhibit 0064.00.AML-3585, PDF page 1. 899 Exhibit 0063.00.AML-3585, PDF page 3.
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Table 29. Key cost variance events Project Change Cost Impact report identifier Reason or Need ($) 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 (1,419,000) complete breaker unit. 2.) Early land compensation package for landowner located on the preferred 240 kV CP-AFUDC AFUDC Reconciliation (3,973,754) CP#12 Updated Service Proposal +/-10% Estimate on 15-Jan-13 and 35,879,000 meeting with the AESO on 22-Jan-13. CN submitted on February 8, 2013. Approved on May 7, 2013. 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 Transcript, Volume 6, pages 1240-1244. 904 Exhibit 0070.00.AML-3585, change notice CP#12, PDF page 15.
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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
1066. The AESO audited AltaLink for compliance to its material procurement requirements as 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-X0045, AML-CCA-2015MAR05-015(e), PDF page 221. 908 Exhibit 3585-X0042, AML-AUC-2015MAR05-010Attachment 1, PDF pages 329 and 331. 909 Exhibit 0002.00.AML-3585, PDF page 45. 910 Exhibit 3585-X0859, PDF pages 176-179. 911 Exhibit 0063.00.AML-3585, PDF pages 7-8.
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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.
1072. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.7.1 Recovery requested 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 +/- 10% update Additions to Final Cost report June 11, 2012 June 21, 2013 Dec 31, 2013(2) Dec 18, 2013(2) Transmission line materials 267,000 459,000 306,419 296,370 Transmission line labour 686,000 2,364,000 1,829,679 1,902,106 Substation materials 2,913,000 4,702,000 5,033,213 5,219,924 Substation labour 8,843,000 16,693,000 15,772,992 16,854,567 Telecommunication materials 147,000 106,000 66,253 80,397 Telecommunication labour 156,000 360,000 328,406 335,270
912 Transcript, Volume 6, page 1241. 913 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 914 Exhibit 0016.00.AML-3585.
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PPS +/- 10% update Additions to Final Cost report June 11, 2012 June 21, 2013 Dec 31, 2013(2) Dec 18, 2013(2) 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 Total owner costs 954,000 782,000 675,353 718,378 D: procurement 279,000 339,000 500,000 500,000 D: project management 1,069,000 1,147,000 1,300,000 1,800,000 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 Total distributed costs 4,873,000 2,928,000 2,553,906 4,677,330 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.
4.2.3.7.2 Project overview 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 Exhibit 0009.00.AML-3585, PDF pages 3-6.
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Table 31. Christina Lake Development Phases and NID stage cost estimates Forecast NID Phase / ISD Target Forecast Project Name at NID Project Elements ($ million) Phase 1 Q2 2013 a new 240 kV switching substation (Black Spruce 154S 25 Black Spruce 154S substation) located between the existing Christina Lake 723S and Conklin 762S substation and near to the existing 971L transmission line Phase 2 Q2 2014 a new 240/138-kV substation (Pike 170S substation) to 105 Pike 170S and connect the future loads in the central Christina Lake area associated a new 30 km double circuit, single side strung 240-kV transmission lines transmission line (1115L) between the Black Spruce 154S substation and the new Pike 170S substation Phase 3 Q2 2015 a new 240/138-kV Ipiatik Lake 167S substation 266 Ipiatik Lake 167S a new double-circuit, single side strung, 240-kV transmission and associated line (1116L) of approximately 30 km in length between the new transmission lines 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 Phase 3 Q2 2015 a project (assigned to ATCO Electric Ltd) to connect 12 Heart lake 898S transmission line 1117L inside of ATCO Electric’s Heart Lake 898S substation 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 $20 million and a forecast ISD of June 28, 2013.919
1080. AltaLink filed a facility application on July 23, 2012. The scope of the project included:
Construction of a new 240-kV switching station, Black Spruce 154S. Construction of approximately 150 metres each of two new single-circuit 240-kV transmission line to the proposed Black Spruce 154S substation (971L/1099L). Alteration of the existing 971L transmission line to facilitate interconnection of the proposed in/out 971L/1099L.
917 Exhibit 0007.00.AML-3585, PDF page 3. 918 Decision 2012-112: Alberta Electric System Operator, Christina Lake Area 240-kV Transmission System Development Needs Identification Document, Proceeding 1518, Application 1607795-1, April 24, 2012. 919 Exhibit 0008.00.AML-3585, PDF page 13.
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Renumber a portion of the line from the Jackfish 698S substation to the proposed Black Spruce 154S substation as 1099L.920
1081. The Commission approved the facility application on December 24, 2012, in Decision 2012-356.921 A table listing the proceedings, decisions and associated approvals for project D.0377 (Black Spruce 154S) is in Appendix 4.
1082. The Sunday Creek 539S connection project NID (AltaLink project D.0407, discussed in Section 4.3.2.1 below) was also approved in Decision 2012-356. Completion of the Black Spruce 154S project was required to allow the Sunday Creek 539S substation to connect to the Alberta electric system.
1083. The project was energized on July 23, 2013.922
4.2.3.7.2.1 Key project variances 1084. The key trends and changes that drove the projects’ cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 32 below:
Table 32. Project D.0377 key cost variance events Change Cost Impact report identifier Reason or Need ($) CP#2 Geotechnical Survey and Report 41,000 Variance in PPS Budget to Actual Costs CP#3 Brushing and Clearing Contract 128,000 Variance in PPS Budget to Actual Costs CP#4 Civil Contract 3,783,000 Variance in PPS Budget to Actual Costs CP#5 Screw Piles Contract 901,000 Variance in PPS Budget to Actual Costs CP#6 Electrical, P&C, SCADA(1) and Telecom Contract 2,339,000 Variance in PPS Budget to Actual Costs CP#7 Lines Installation Contract 676,000 Variance in PPS Budget to Actual Costs CP#8 Telecom Installation Contract 186,000 Variance in PPS Budget to Actual Costs CP#9 Access Mats for In/Out within ROW 1,128,000 Scope Change required for work to be completed within ROW above a pipeline CP#10 Substation Materials cost Variance 1,852,000 Variance in PPS Budget to Actual Costs CP#11 Station Service Transformer 737,000 Required to add back up redundancy to station, distribution solution was cost prohibitive. 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 Exhibit 0010.00.AML-3585, PDF page 20. 921 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 Exhibit 0007.00.AML-3585, PDF page 7.
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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 page 10. 924 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 pages 10 and 15. 927 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.
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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-X0045, AML-CCA-2015MAR05-015(e), PDF page 221. 932 Exhibit 0002.00.AML-3585, PDF page 45. 933 Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379. 934 Exhibit 3585-X0042, AML-AUC-2015MAR05-023(a), PDF page 404. 935 Exhibit 3585-X0859, PDF pages 179 and 181.
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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.
1096. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.8.1 Recovery requested 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 +/- 10% update Additions to Jan 19, 2011 Sep 25/12 Dec 31, 2013(2) Final Cost Report(2) Transmission line materials 907,000 1,180,000 1,100,323 1,100,323 Transmission line labour 1,449,000 2,059,000 2,286,156 2,104,387 Substation materials 0 14,000 47,230 47,230 Substation labour 0 79,000 279,965 290,354 Telecommunication materials 17,000 16,000 15,497 12,419 Telecommunication labour 33,000 32,000 96,530 81,027
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-X0043, AML-AUC-2015MAR05-042 Attachment. 938 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF Page 349.
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PPS +/- 10% update Additions to Jan 19, 2011 Sep 25/12 Dec 31, 2013(2) Final Cost Report(2) 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 O: ROW Costs 0 0 0 0 Total owner costs 2,244,000 2,244,000 2,255,356 2,255,691 D: procurement 38,000 38,000 100,000 100,000 D: project management 304,000 648,000 1,000,000 700,000 D: construction management 99,000 142,000 200,000 400,000 D: escalation 232,000 233,000 - - D: contingency 610,000 610,000 - - Total distributed costs 1,283,000 1,516,000 1,366,572 1,609,707 OT: ES&G 342,000 342,000 259,805 257,981 OT: AFUDC 621,000 621,000 0 9,240 Total other costs 963,000 963,000 259,805 267,224 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.
4.2.3.8.2 Project overview 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 Exhibit 0195.00.AML-3585, PDF page 52. 941 Exhibit 0195.00.AML-3585, PDF page 2.
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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
1107. A table listing the proceedings, decisions and associated approvals issued by the 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 Exhibit 0195.00.AML-3585, PDF page 88. 944 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 Exhibit 0195.00.AML-3585, PDF page 208.
220 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
4.2.3.8.3 Key project variances 1109. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 34 below:
Table 34. Project D.0409 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA#1 Revised Cost Estimate 1,265,000 Update Cost Estimate – Steel Quantity, Protection CP#2 AFUDC Reconciliation (611,760) AUC decision for approval of CWIP in rate base. CP#5 Change of foundations 240,000 Adverse soil conditions were encountered resulting in additional foundation costs. Submitted September 26, 2013. Source: Exhibit 0195.00.AML-3585, PDF page 521.
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 interveners in evidence, nor in argument and reply.
Commission findings 1113. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 0195.00.AML-3585, PDF pages 141 and 144. 948 Exhibit 3585-0859, PDF page 182.
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4.2.3.9 D.0414 – Western Alberta Transmission Line 4.2.3.9.1 Recovery requested 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 Additions to Jan 20, 2011 Dec 31, 2013 Transmission line materials 954,293 1,720,361 Transmission line labour 1,295,400 14,246,368 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 +/- 10 update Jan 20, 2011 May 28, 2013 Transmission line materials 203,798,715 128,638,513 Transmission line labour 308,618,528 579,378,647 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. 950 Exhibit 3585-X0042, AML-AUC-2015MAR05-010, PDF page 323. 951 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0414.
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PPS +/- 10 update Jan 20, 2011 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.
4.2.3.9.2 Project overview 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 Exhibit 0211.00.AML-3585, PDF page 80. 954 Exhibit 211.00.AML-3585, PDF page 101. 955 Exhibit 0211.00.AML-3585, PDF page 2.
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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 Exhibit 0211.00.AML-3585, PDF page 108. 957 Exhibit 0211.00.AML-3585, PDF pages 365-366, 373-376 and 379-380. 958 Exhibit 0211.00.AML-3585, PDF pages 380-381. 959 Exhibit 0211.00.AML-3585, PDF pages 367-372, 377-378 and 385-387. 960 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 pages 714 and 730. 962 Exhibit 0211.00.AML-3585, PDF page 734-735, 738-739, 741-742, 767-769 and 785-786.
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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 DA2013-173: AltaLink Management Ltd., Transmission Line 1325L, Letter of Enquiry Approval, Proceeding 2727, Application 1609769-1, July 24, 2013. 965 Decision DA2013-174: AltaLink Management Ltd., Transmission Line 1325L, Letter of Enquiry Approval, Proceeding 2728, Application 1609771-1, July 24, 2013. 966 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 0211.00.AML-3585, PDF pages 760-762. 972 Exhibit 3585-X0042, AML-AUC-2015MAR05-005, Table 1, PDF page 146. 973 Exhibit 3585-X0042, AML-AUC-2015MAR05-005(a), PDF page 144.
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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
4.2.3.9.3 Key project variances 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 3585-X796, PDF page 1. 975 Exhibit 0006.00.AML-3585, tab D.0414. 976 Exhibit 0002.00.AML-3585, PDF page 45. 977 Exhibit 3585-X0859, PDF page 182.
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4.2.3.10 D.0458 – East HVDC Converter Station Interface 4.2.3.10.1 Recovery requested 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* Additions to Mar 11, 2011 Dec 31, 2013 Transmission line materials 1,374,789 3,074,393 Transmission line labour 3,833,335 10,153,108 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 +20/-10 in FA +/-10 update Mar 11, 2011 May 9, 2012 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. 979 Exhibit 3585-X0042, AML-AUC-2015MAR05-010, PDF page 323. 980 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0458.
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PPS +20/-10 in FA +/-10 update Mar 11, 2011 May 9, 2012 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.
4.2.3.10.2 Project overview 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 1. 982 Exhibit 0192.00.AML-3585, PDF page 29 983 Exhibit 0192.00.AML-3585, PDF page 75. 984 The Commission acknowledged this project as a CTI in paragraph 3 of Decision 2012-305.
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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 Exhibit 0192.00.AML-3585, PDF page 62. 986 Exhibit 0192.00.AML-3585, PDF pages 78-79. 987 Exhibit 0192.00.AML-3585, PDF page 239. 988 Exhibit 0192.00.AML-3585, PDF page 141. 989 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.
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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
1150. In conjunction with Decision 2012-305, the Commission issued a number of P&Ls or 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 923L temporary line energization on July 14, 2013 931L temporary line energization on July 17, 2013994
4.2.3.10.3 Key project variances 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 initial application evidence, are summarized in Table 39 below:
Table 39. Project D.0458 key cost variance events Change Cost Impact report identifier Reason or Need ($ 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 (58,985) not within the dead ends of ATCO HVDC line crossing. 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 3585-X0796, PDF page 2. 995 Exhibit 0006.00.AML-3585, tab D.0458.
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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 0192.00.AML-3585, PDF page 304. 997 Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF page 386 998 Exhibit 0192.00.AML-3585, PDF pages 348 and 350-351. 999 Exhibit 3585-X0042, AML-AUC-2015MAR05-016(b), PDF page 387.
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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
1164. In conjunction with Decision 2012-254, the Commission issued a number of P&Ls or approvals.
1000 Exhibit 0135.00.AML-3585, PDF pages 3 and 7. 1001 Exhibit 0135.00.AML-3585, PDF page 4. 1002 Transcript, Volume 7, pages 1333-1334 and 1336. 1003 Exhibit 0203.00.AML-3585, PDF page 46. 1004 Exhibit 0136.00.AML-3585, PDF page 9. 1005 Exhibit 0136.00.AML-3585, PDF pages 58-60. 1006 Exhibit 202.00.AML-3585, PDF pages 27-30.
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1165. A table listing the proceedings, decisions and associated approvals issued by the 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 interveners in evidence, nor in argument and reply.
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 4.2.3.11.1.1 Recovery requested 1170. In the application, AltaLink requested additions to rate base in the amount of $7.4 million 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 +/-10 update Additions to Final Cost report July 2011 Mar 14, 2013 Dec 31, 2013(3) Dec 19, 2014(3) Transmission line materials 225,000 279,000 272,301 272,523 Transmission line labour 760,000 1,148,000 1,009,196 976,968 Substation materials 827,000 900,000 866,349 867,747 Substation labour 1,258,000 2,882,000 2,586,288 2,878,967 Telecommunication materials 8,000 0 36,189 36,189 Telecommunication labour 233,000 302,000 159,444 154,944 O: proposal to provide service 99,000 75,000 0 0 O: facility applications 112,000 196,000 200,000 200,000
1007 Exhibit 3585-X0042, AML-AUC-2015MAR05-007(b), PDF page 247. 1008 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 1009 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 333.
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PPS +/-10 update Additions to Final Cost report July 2011 Mar 14, 2013 Dec 31, 2013(3) Dec 19, 2014(3) O: land-rights - easements 0 14,000 0 0 O: land-rights – damage claims 0 0 0 0 O: land - acquisitions 0 0 0 0 O: ROW Costs 0 0 0 0 Total owner costs 211,000 285,000 292,845 293,217 D: procurement 112,000 157,000 200,000 200,000 D: project management 716,000 974,000 1,100,000 1,100,000 D: construction management 310,000 671,000 600,000 700,000 D: escalation(1) - 17,000 - - D: contingency 512,000 252,000 - - Total distributed costs 1,650,000 2,071,000 1,913,205 1,972,512 OT: ES&G 252,000 291,000 224,015 228,457 OT: AFUDC 59,000 2,000 1,735 1,735 Total other costs 311,000 293,000 225,750 230,191 Total project costs(2) 5,483,000 8,160,000 7,361,566 7,683,260 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.
4.2.3.11.1.2 Project overview 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 $5.5 million and a forecast ISD of October 30, 2012.1011
1174. The project was energized on March 28, 2013.1012
4.2.3.11.1.3 Key project variances 1175. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 41 below:
1010 Exhibit 3585-X0859, PDF page 184. 1011 Exhibit 0008.00.AML-3585, PDF page 13. 1012 Exhibit 0133.00.AML-3585, PDF page 7.
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Table 41. Project D.0459 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA#7 Grounding studies at 87S and 217S and structure change at 217S: 128,000 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 TCA#8 Telecom tower replacement 141,000 Detailed engineering has determined the existing telecom tower cannot support the new radio equipment. A new tower is required to support the load. CP#12 The change is required to cover the variance between the estimated 1,095,000 construction costs and the actual bids received for the scope of work. CP-AFUDC#1 AFUDC Reconciliation (58,437) CP#18 Increased costs due to delay in P&L; complexities of working at 1,209,000 brownfield substations; soil conditions differ from PPS estimate CP-AFUDC#2 AFUDC Reconciliation #2 1,172 Source: Exhibit 0149.00.AML-3585, AESO change notices.
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 Exhibit 0149.00.AML-3585, PDF page 12.
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North Red Deer substations and the option with the smallest effect on cost and schedule was selected.1014
Commission findings 1178. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.11.2.1 Recovery requested 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 +/- 10% update Additions to Final Cost report June 2011 March 14, 2013 Dec 31, 2013(3) Dec 19, 2014(3) Transmission line materials - - 0 - Transmission line labour - - 0 - Substation materials 3,060,000 3,107,000 3,100,813 3,100,812 Substation labour 1,379,000 3,329,000 3,252,814 3,252,778 Telecommunication materials - - 0 - Telecommunication labour - - 0 - O: proposal to provide service 64,000 60,000 0 0 O: facility applications 92,000 135,000 200,000 200,000 O: land-rights - easements 0 1,000 0 0 O: land-rights – damage claims 0 0 0 0 O: land - acquisitions 0 0 0 0 O: ROW Costs 0 0 0 0 Total owner costs 156,000 196,000 226,816 223,853
1014 Exhibit 0149.00.AML-3585, PDF pages 21-22 and 26. 1015 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 1016 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF Page 335.
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PPS +/- 10% update Additions to Final Cost report June 2011 March 14, 2013 Dec 31, 2013(3) Dec 19, 2014(3) D: procurement 84,000 184,000 200,000 200,000 D: project management 628,000 710,000 900,000 900,000 D: construction management 685,000 542,000 500,000 500,000 D: escalation - 6,000 -0 - D: contingency(1) 263,000 132,000 -0 - Total distributed costs 1,660,000 1,573,000 1,559,199 1,572,391 OT: ES&G 300,000 231,000 206,405 203,319 OT: AFUDC 23,000 1,000 1,390 1,390 Total project costs(2) 6,578,000 8,437,000 8,347,437 8,354,544 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.
4.2.3.11.2.2 Project overview 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 costs of $6.6 million and a forecast ISD of October 30, 2012.1018
1183. The project was energized on March 27, 2013.1019
4.2.3.11.2.3 Key project variances 1184. AltaLink indicated that the cost variances for substation labour were due to market escalation in construction labour rates, complexities of working at brownfield substations, as well as the City of Red Deer accommodation requirements. The increase in owner costs was attributed to a delay in P&L.1020 AltaLink submitted six change notices to the AESO in respect of the cost variances. The AESO approved all but one change notice.1021
1185. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 43 below:
1017 Exhibit 3585-X0859, PDF page 186. 1018 Exhibit 0134.00.AML-3585, PDF page 3. 1019 Exhibit 0133.00.AML-3585, PDF page 7. 1020 Exhibit 3585-X0043, AML-AUC-2015MAR05-042, tab D.0460. 1021 Exhibit 0139.00.AML-3585, PDF pages 1.
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Table 43. Project D.0460 key cost variance events Change Cost Impact report identifier Reason or Need ($) TCA#9 New battery bank, racks and charger and new digital data recorder 174,000 and digital fault recorder – it was assumed in the PPS that the existing equipment would have the capacity to handle the load CP#11 The change is required to cover the variance between the estimated 932,000 construction costs and the actual bids received for the scope of work. CP-AFUDC#1 AFUDC Reconciliation (22,549) CP#14 Increased costs due to delay in P&L; complexities of working at 1,128,000 Benalto site; soil conditions differ from PPS estimate CP-AFUDC#2 AFUDC Reconciliation #2 939 Source: Exhibit 0139.00.AML-3585, AESO change notices.
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 page 11. 1023 Exhibit 0139.00.AML-3585, PDF pages 20-21 and 26.
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4.2.3.11.3 D.0461 – Red Deer Area Transmission – Capbank at Joffre 535S 4.2.3.11.3.1 Recovery requested 1189. In the application, AltaLink requested additions to rate base in the amount of $4.3 million in 2013, representing a variance of approximately $2.4 million in relation to the project cost forecast by AltaLink at the PPS stage.1024 AltaLink filed its final cost report on December 19, 2014,1025 which reported a final cost, excluding salvage, of $4.8 million for the project.
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 +/- 10% update Additions to Final Cost report June 2011 Mar 14, 2013 Dec 31, 2013(3) Dec 19, 2014(3) Transmission line materials - - 0 - Transmission line labour - - 0 - Substation materials 712,000 847,000 722,116 753,511 Substation labour 873,000 1,966,000 1,821,995 2,127,346 Telecommunication materials - - 0 - Telecommunication labour - - 0 - O: proposal to provide service 76,000 43,000 0 0 O: facility applications 87,000 147,000 200,000 200,000 O: land-rights - easements 0 7,000 0 0 O: land-rights – damage claims 0 0 0 0 O: land - acquisitions 0 0 0 0 O: ROW Costs 0 0 0 0 Total owner costs 163,000 197,000 227,596 229,429 D: procurement 77,000 70,000 100,000 100,000 D: project management 436,000 864,000 700,000 800,000 D: construction management 199,000 476,000 500,000 600,000 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 Total project costs(2) 2,885,000 5,087,000 4,271,409 4,803,334 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.
4.2.3.11.3.2 Project overview 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-X0043, AML-AUC-2015MAR05-042 Attachment. 1025 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 336. 1026 Exhibit 3585-X0859, PDF page 187.
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1192. At the direction of the AESO, AltaLink prepared a PPS for the project which estimated costs of $2.9 million and a forecast ISD of October 30, 2012.1027
1193. The project was energized on October 11, 2013.1028
4.2.3.11.3.3 Key project variances 1194. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence are summarized in Table 45 below:
Table 45. Project D.0461 key cost variance events Change Cost Impact ($ report identifier Reason or Need million) TCA#6 Funding to construct temporary 138-kV breaker assembly 270,000 The temporary breaker is required to reduce outages on the radial feed to Joffre and Brookfield plants CP-AFUDC#1 AFUDC Reconciliation (31,437) CP#19 Increased costs due to delay in P&L; higher construction bids; and 1,950,000 additional requirements after PPS submitted. CP-AFUDC#2 AFUDC Reconciliation #2 1,172 CP#39 Rev 2 Late mobilization of electrical sub-contractor resulted in the necessity 206,000 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. Source: Exhibit 0203.00.AML-3585, AESO change notices.
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 Exhibit 0203.00.AML-3585, PDF page 4. 1028 Exhibit 3585-X0859, PDF page 188. 1029 Exhibit 0203.00.AML-3585, PDF pages 46-47.
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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 1198. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.11.4.1 Recovery requested 1199. In the application, AltaLink requested additions to rate base in the amount of $3.8 million in 2013, representing a variance of approximately $0.8 million in relation to the project cost forecast by AltaLink at the PPS stage.1032 AltaLink filed its final cost report on December 19, 2014,1033 which reported a final cost, excluding salvage, of $4.0 million for the project.
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 Exhibit 3585-X0859, PDF page 188. 1032 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 1033 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 337.
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Table 46. Red Deer Area – Capbank at Prentiss 276S cost breakdown PPS +/- 10% update Additions to Final Cost report June 2011 Mar 14, 2013 Dec 31, 2013(3) Dec 19, 2014(3) Transmission line materials - - 0 0 Transmission line labour - 1,000 0 1,445 Substation materials 808,000 725,000 917,261 664,931 Substation labour 896,000 1,625,000 1,496,040 1,703,503 Telecommunication materials - - 0 0 Telecommunication labour - - 0 0 O: proposal to provide service 74,000 64,000 0 0 O: facility applications 87,000 103,000 100,000 100,000 O: land-rights - easements 0 1,000 0 0 O: land-rights – damage claims 0 0 0 0 O: land - acquisitions 0 0 0 0 O: ROW Costs 0 0 0 0 Total owner costs 161,000 169,000 175,801 178,144 D: procurement 78,000 81,000 100,000 200,000 D: project management 419,000 769,000 700,000 800,000 D: construction management 201,000 370,000 300,000 400,000 D: escalation 91,000 23,000 0 - D: contingency(1) 184,000 315,000 0 - Total distributed costs 973,000 1,557,000 1,138,176 1,353,923 OT: ES&G 140,000 171,000 107,687 133,940 OT: AFUDC 32,000 2,000 1,735 3,469 Total project costs(2) 3,010,000 4,250,000 3,836,700 3,999,355 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 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.
4.2.3.11.4.2 Project overview 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 costs of $3.1 million and a forecast ISD of October 30, 2012.1035
1203. The project was energized on October 31, 2013.1036
4.2.3.11.4.3 Key project variances 1204. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 47 below:
1034 Exhibit 3585-X0859, PDF page 188. 1035 Exhibit 0204.00.AML-3585, PDF page 3. 1036 Exhibit 3585-X0859, PDF page 188.
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Table 47. Project D.0462 key cost variance events Change Cost Impact report identifier Reason or Need ($ million) CP-AFUDC#1 AFUDC Reconciliation (31,437) CP#20 Increased costs due to delay in P&L; higher construction bids; 1,262,000 additional requirements after PPS submitted. CP-AFUDC#2 AFUDC Reconciliation #2 1,172 CP#38 Rev 1 Late mobilization of electrical sub-contractor resulted in the necessity 184,000 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. Source: Exhibit 0204.00.AML-3585, AESO change notices.
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
1207. 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 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 0203.00.AML-3585, PDF pages 37-38. 1038 Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF pages 386-387.
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1208. 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.1039
Commission findings 1209. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 4.2.3.11.5.1 Recovery requested 1210. In the application, AltaLink requested additions to rate base in the amount of $3.6 million in 2013, representing a variance of approximately $0.9 million in relation to the project cost forecast by AltaLink at the PPS stage.1040 AltaLink filed its final cost report on December 19, 2014,1041 which reported a final cost, excluding salvage, of $4.0 million for the project.
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 Final Cost PPS +/- 10% update Additions to Report(3) June 2011 Mar 14, 2013 Dec 31, 2013(3) Dec 19, 2014 Transmission line materials - - - - Transmission line labour - - - - Substation materials 554,000 631,000 562,454 559,834 Substation labour 886,000 1,941,000 1,603,293 1,765,281 Telecommunication materials - - 0 - Telecommunication labour - - 0 - O: proposal to provide service 78,000 67,000 0 0 O: facility applications 87,000 100,000 100,000 100,000 O: land-rights - easements 0 5,000 0 0 O: land-rights – damage claims 0 0 0 0 O: land - acquisitions 0 35,000 0 0 O: ROW Costs 0 0 0 0 Total owner costs 165,000 207,000 171,293 173,908 D: procurement 77,000 90,000 100,000 200,000 D: project management 404,000 735,000 700,000 800,000 D: construction management 180,000 602,000 300,000 400,000 D: escalation(1) 78,000 24,000 - -
1039 Exhibit 3585-X0859, PDF page 188. 1040 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment. 1041 Exhibit 3585-X0042, AML-AUC-2015MAR05-010 Attachment 1, PDF page 338.
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Final Cost PPS +/- 10% update Additions to Report(3) June 2011 Mar 14, 2013 Dec 31, 2013(3) Dec 19, 2014 D: contingency 159,000 367,000 - - Total distributed costs 898,000 1,818,000 1,135,050 1,380,840 OT: ES&G 122,000 199,000 103,939 114,717 OT: AFUDC 30,000 2,000 1,735 1,735 Total project costs(2) 2,655,000 4,797,000 3,577,763 3,996,314 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 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.
4.2.3.11.5.2 Project overview 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 costs of $2.7 million and a forecast ISD of October 30, 2012.1043
1214. The project was energized on November 28, 2013.1044
4.2.3.11.5.3 Key project variances 1215. The key trends and changes that drove project cost variances as set out in AltaLink’s initial application evidence, are summarized in Table 49 below:
Table 49. Project D.0463 key cost variance events Change Cost Impact report identifier Reason or Need ($ million) CP-AFUDC#1 AFUDC Reconciliation (29,437) CP#21 Increased costs due to 2,162,000 delay in P&L; higher construction bids; additional requirements after PPS submitted. CP-AFUDC#2 AFUDC Reconciliation #2 1,172 CP#40 Increased costs associated with lease negotiation with Dow Chemical 284,000 Canada (Ellis 332S is in the Dow facilities), delays as a result of the negotiation and outage planning and relocation of a water line. Source: Exhibit 0202.00.AML-3585, AESO change notices.
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 Exhibit 3585-X0859, PDF page 188. 1043 Exhibit 0202.00.AML-3585, PDF page 3. 1044 Exhibit 3585-X0859, PDF page 189.
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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
1218. 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 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
1219. 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.1048
Commission findings 1220. The Commission has reviewed AltaLink’s evidence and submissions in support of its 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 0202.00.AML-3585, PDF pages 42-43. 1047 Exhibit 3585-X0042, AML-AUC-2015MAR05-016(a), PDF pages 386-387. 1048 Exhibit 3585-X0859, PDF page 189.
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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 Additions to Final Cost estimate +/- 10% update Dec 31, 2013 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) Unable to 6,722,368 4,358,571 4,359,369 calculate 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.
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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 Transcript, Volume 5, page 1019. 1054 Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 137 and 141. 1055 Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF pages 142. 1056 Transcript, Volume 7, pages 1283-1284. 1057 Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379.
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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
1234. A table listing the proceedings, decisions and associated approvals issued by the 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 1237. The Commission has reviewed AltaLink’s submissions in support of the costs associated 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 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, tab D.0259. 1059 Exhibit 3585-X0045, AML-CCA-2015MAR05-015(e), PDF page 221. 1060 Exhibit 3585-X0043, AML-AUC-2015MAR05-0042 Attachment, tab D.0214. 1061 Exhibit 3585-X0860, PDF page 90. 1062 Exhibit 3585-X0859, PDF pages 189-191. 1063 Exhibit 3585-X0863, PDF page 79. 1064 Proceeding 1615, Exhibit 0002.00.AML-1615. 1065 Proceeding 1615, Exhibit 0022.00.AML-1615.
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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).
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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 Additions to PPS +/- 10% Dec 31, Net additions Final Cost estimate(2) update(2) 2013(2) (4) to Dec 31,2013 Report(2) 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.
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Additions to PPS +/- 10% Dec 31, Net additions Final Cost estimate(2) update(2) 2013(2) (4) to Dec 31,2013 Report(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 Total project costs(1) Unable to 247,745,826 278,024,765 294,797,011 calculate 71,485,301 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 Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379.
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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 Approved Addition Project Project Amount ID Name ($) 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 Exhibit 3585-X0042, AML-AUC-2015MAR05-023(a), PDF page 404. 1071 Exhibit 3585-X0860, PDF pages 90-91. 1072 Exhibit 3585-X0863, PDF page 79.
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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 2009-151, paragraph 358. 1075 Decision 2011-451, paragraph 529.
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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 Decision 2014-283, paragraphs 113-114. 1077 Transcript, Volume 6, page 1123. 1078 Transcript, Volume 6, page 1124. 1079 Note: In Exhibit 3585-X0772 no contribution for either AltaLink or Fortis is shown for projects D.0277, D.0357 and D.0485.
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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 1128. 1082 Transcript, Volume 6, page 1129.
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Table 53. Contributions and DTS contract levels on Fortis direct assign connection projects DTS Project Increase Contribution Number Project Name (MW) ($) 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.
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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 0206.00.AML-3585, PDF page 30. 1085 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 Exhibit 3585-X0806, PDF page 9.
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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 Transcript, Volume 6, pages 1145-1152. 1090 Transcript, Volume 6, page 1150. 1091 Decision 2014-242, paragraphs 461-479. 1092 Decision 2014-242, paragraph 452.
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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 Transcript, Volume 6, pages 1149-1150.
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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 Transcript, Volume 5, pages 984-986.
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Table 54. Fortis non-direct assigned projects costs Additions to PPS Dec 31, 2013(2) Net additions to Final Cost estimate(1) (2) Dec 31,2013 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.
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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 Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379. 1103 Transcript, Volume 5, page 984. 1104 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.
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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 Additions to PPS +/- 10% Dec 31, Net additions Final Cost estimate(2) update(2) 2013(2) (4) to Dec 31,2013 Report(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 Total project costs(1) Unable to 168,631,850 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.
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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 AltaLink’s initial application evidence, are summarized in Table 56 below:
Table 56. Non-Fortis direct assigned connection projects cost variance events Variance between additions to 2013 Project Name and PPS estimate High level variance explanation Scope modifications to includes a additional 4km of new transmission D.0073 - Castle Rock Ridge line and the Goose Lake portion of the Fidler project, market (CRR) Wind Farm $22.5 million escalation, scope changes due to an unanticipated change in Interconnection Project foundation type and procedural delays. D.0275 - Abee New Substation Requirement for additional screw piles, market escalation and winter $1.5 million – Lac La Biche Area construction. D.0383 - Cope Creek Changes in line foundation design to minimize outage at customer’s $0.4 million Interconnection Project site, ISD delays requested by the customer and market escalation. D.0407 - Sunday Creek 539S Re-design and additional materials required to accommodate a line $1.0 million Connection Project route change requested by the customer and market escalation. Delays associated with MATL challenges (this project began D.0041 - Picture Butte 120S construction five years later than anticipated and land transfers from $5.8 million (MATL) MATL resulted in further delays), market escalation and additional scope (increase substation capacity). D.0191 - NRGreen Chickadee Increased labour and material costs associated with an ISD change Creek 259S Substation $0.5 million requested by customer. Interconnection Project 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 Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379.
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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.
1304. The Commission has reviewed AltaLink’s submissions in support of the costs associated 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 Exhibit 3585-X0860, PDF pages 90-91. 1110 Exhibit 3585-X0863, PDF page 79. 1111 These projects were identified in the project schedules submitted in Exhibit 0006.00.AML-3585. 1112 Transcript, Volume 5, pages 984-986.
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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 Additions to PPS Dec 31, 2013(1) Net additions to Dec Final Cost estimate(1) (3) 31,2013 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.
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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 $0 amount for additions for these projects.
4.4 Cancelled projects 1319. Projects that were cancelled following the submission of AltaLink’s 2011-2012 or 2013- 2014 GTA were set out in Schedule 7-4 of Appendix 2 to its application.1121 AltaLink also provided a version of its cancelled projects table, rounded to the nearest dollar, in a response to an IR, reproduced below as Table 58:
1116 Exhibit 3585-X0859, PDF page 216. 1117 Exhibit 3585-X0042, AML-AUC-2015MAR05-004, PDF page 142. 1118 Exhibit 3585-X0043, AML-AUC-2015MAR05-042 Attachment, Energizations tab. 1119 Exhibit 3585-X0042, AML-AUC-2015MAR05-012 Attachment, PDF page 379. 1120 Transcript, Volume 5, page 984. 1121 Exhibit 0006.00.AML-3585, tab “Totals.”
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Table 58. Summary of cancelled projects 2012 2013 Gross Gross Total Customer Net addition addition addition Contrib. addition Ref. Project Name ($) 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-X0859, paragraph 1050. 1124 Exhibit 3585-X0860, paragraph 384. 1125 Exhibit 3585-X0042, AML-AUC-2015MAR05-024, Table7.6-1, PDF page 407. 1126 Exhibit 3585-X0860, paragraph 385. 1127 Exhibit 3585-X0860, paragraph 386.
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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-X0860, paragraph 387. 1129 Exhibit 3585-X0863, paragraph 384. 1130 Exhibit 3585-X0865, paragraph 326. 1131 Transcript, Volume 6, pages 1140-1141. 1132 Exhibit 3585-X0042.
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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).
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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 0002.00.AML-3585, Table 7.6-1, PDF page 51. 1135 Exhibit 0002.00.AML-3585, Table 7.6-1, PDF page 52. 1136 Exhibit 0002.00.AML-3585, paragraph 113. 1137 Exhibit 3585-X0042 AML-AUC-2015MAR05-024. 1138 Transcript, Volume 6, page 1213. 1139 Exhibit 3585-X0859, paragraph 1056. 1140 Exhibit 3585-X0860, paragraph 388. 1141 Exhibit 3585-X0860, paragraph 389. 1142 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 Exhibit 3585-X0865, paragraph 328.
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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-X0865, paragraph 331. 1145 Exhibit 3585-X0865, paragraph 332. 1146 Exhibit 3585-X0042.
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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 Exhibit 3585-X0661, PDF page 13.
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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.
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Table 59. Directive responses Commission decision and follow up Decision Decision reference Subject direction (if applicable) 2010-284 Directive 1 Trailing Costs Commission acknowledges compliance. page 7 AltaLink is directed to continue to file the paragraph 39 requested information in future DACDAs. 2010-284 Directive 2 Trailing Costs Commission acknowledges compliance. page 7 AltaLink is directed to continue to file the paragraph 41 requested information in future DACDAs. 2013-407 Directive 26 Competitive Procurement Commission acknowledges compliance. No page 145 Process further action is necessary due to findings paragraph 731 elsewhere in this decision. 2013-407 Directive 27 Competitive Procurement Commission acknowledges compliance. No page 145 Process further action is necessary due to findings paragraph 732 elsewhere in this decision. 2013-407 Directive 28 Risk Reward Model Commission acknowledges compliance. No page 150 further action is necessary due to findings paragraph 759 elsewhere in this decision. 2013-407 Directive 39 OCASTD Commission acknowledges compliance. No page 209 further action is necessary. paragraph 1079 2013-407 Directive 45 Direct Assigned Capital Commission acknowledges compliance. page 263 Deferral Application – AltaLink is directed to continue to file the paragraph 1361 Minimum Filing requested information in future DACDAs. Requirements 2013-407 Directive 45 Direct Assigned Capital Commission acknowledges compliance. No page 263 Deferral Application –Filing further action is necessary due to findings paragraph 1361 Requirements elsewhere in this decision. 2014-258 Directive 3 Competitive Procurement Commission acknowledges compliance. No pages 16 and 17 Process further action is necessary due to findings paragraph 76 elsewhere in this decision.
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.
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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.
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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.
The Alberta Utilities Commission
(original signed by)
Mark Kolesar Vice-Chair
(original signed by)
Henry van Egteren Commission Member
(original signed by)
Kate Coolidge Acting Commission Member
278 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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
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Appendix 2 – Oral hearing – registered appearances
Name of organization (abbreviation) Witnesses Name of counsel or representative
AltaLink Management Ltd. (AltaLink or AML) B. Townsend R. Block D. Watson K. Salmon J. Picard-Thompson D. Fedorchuk J. Piotto C. Lomore R. Venerus J. Kell T. Dorsey
Consumers’ Coalition of Alberta (CCA) and C. Chekerda Ratepayer Group (RPG) V. Bellissimo J. A. Wachowich D. Levson T. Cline W. Tusa
Alberta Direct Connect Consumers Association (ADC) M. Gorman R. Secord
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
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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.
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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.
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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.
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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.
284 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Appendix 4 – Project proceedings and approvals
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID approval D.0030.01 Yellowhead Area Transmission 2010-208 270 2011-188 766 U2011-146 Alter Transmission Line 745L Development Hinton-Edson U2011-147 Alter and Re-designate Transmission Line from 745L to 671L Development U2011-148 Decommission and Salvage Part of Transmission Line 745L U2011-149 Alter Transmission Line 740L U2011-150 Alter Bickerdike 39S Substation DA2012-185 1980 U2012-339 Alter Transmission Line 745L D.0030.03 Yellowhead Area Transmission 2010-208 270 2011-161 762 U2011-88 Construct and operate new Cherhill 338S substation Development Cherhill Area U2011-89 Discontinue operation and salvage Lac La Nonne 994S substation Development – 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.
Decision 3585-D03-2016 (June 6, 2016) • 285 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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 2761 Disposition Confirmation that portions of transmission lines 104L and 104EL Letter Letter 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 U2008- 16613 2011-001 220 U2011-106 Alter transmission line 100L Area 232 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 2011-340 754 2012-293 1394 U2012-529 Approval to alter transmission line 902L in the Wabamun Lake Upgrades 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 2012-023 861 2012-064 861 U2012-82 Construct Clyde 9150R Radio Site Westlock County Development 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
286 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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
Decision 3585-D03-2016 (June 6, 2016) • 287 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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
288 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID approval U2012-678 Alter transmission line 1035L U2012-679 Alter transmission line 964L-983L U2012-680 Alter transmission line 1073L-1074L 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 U2011-201 New transmission line 1034L-1035L U2011-202 Alter transmission line 923L-935L U2011-203 New Bowmanton 244S substation U2011-204 New Whitla 251S substation U2011-205 New transmission line 964L-983L D.0316 Southern Alberta Transmission 2009-126 171 2012-043 1150 U2012-12 Construct new 240 kV transmission line from Cassils 324S Reinforcement 933L In/Out at Ware 2010-188 278 substation to Ware Junction 132S substation Junction 132S 2010-592 768 U2012-13 Redesignate southern portion of transmission line from Ware 2011-102 748 Junction 132S substation to West Brooks 28S substation as D.0355 Hanna Area Transmission – Ware transmission line 1075L Junction 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 U2012-412 Alter Transmission Line 931L U2012-413 Alter Transmission Line 944L U2012-414 Alter Transmission Line 951L 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
Decision 3585-D03-2016 (June 6, 2016) • 289 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID approval U2013-172 Time extension for altering transmission line 944L – rescinds U2012-413 U2013-173 Time extension for altering transmission line 951L – rescinds U2012-414 D.0353 Hanna Area Transmission – Nilrem 2010-188 278 2011-191 957 U2011-86 Alter and operate Hardisty 377S substation - rescinds U2010-46 2011-102 748 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 U2013-322 Time extension for alterations of transmission line 953L – rescinds U2012-682 U2013-323 Time extension for alterations of transmission line 1047L – rescinds U2012-683 D.0354 Hanna Area Transmission – Hansman 2010-188 278 2011-175 974 U2011-174 Hansman Lake 650S Substation Lake 2010-592 768 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
290 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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
Decision 3585-D03-2016 (June 6, 2016) • 291 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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 - 2012-356 2010 2012-356 2010 U2012-704 Construct and operate Black Spruce 154S substation in Christina Black Spruce 154S Lake area. U2012-705 Alter and operate transmission line 971L – rescinds U2012-243 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 CTI N/A 2011-435 1007 U2011-277 Alter transmission line 911L by: Project - 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
292 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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 CTI N/A 2012-305 1884 U2012-576 Alter transmission line 950L by relocating a segment of the line to Interface Project accommodate the crossing of the line by ATCO Electric 500-kV DC line 13L50 – rescinds U2002-853
Decision 3585-D03-2016 (June 6, 2016) • 293 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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 - 2012-098 1368 2012-254 1468 U2012-221 Alter and operate transmission line 768L –rescinds license U2002- Split 768L & 778L 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 U2012-235 Alter and operate transmission line 80L – rescinds U2002-574 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 - 2012-098 1368 2012-254 1468 U2012-225 Alter and operate Benalto 17S substation – rescinds U2007-34 TX add at Benalto 17S D.0461 Red Deer Area Transmission Project - 2012-098 1368 2012-254 1468 U2012-226 Alter and operate Joffre 535S substation – rescinds U2006-194 Capbank at Joffre 535S DA2013-162 2685 U2013-324 Alter and operate Joffre 535S substation - rescinds U2012-226 D.0462 Red Deer Area Transmission Project - 2012-098 1368 2012-254 1468 U2012-227 Alter and operate Prentiss 276S substation – rescinds U2002-419 Capbank at Prentiss 276S DA2013-162 2685 U2013-329 Alter and operate Prentiss 276S substation – rescinds U2012-227 D.0463 Red Deer Area Transmission Project - 2012-098 1368 2012-254 1468 U2012-228 Alter and operate Ellis 332S substation – rescinds U2002-439 Capbank at Ellis 332S 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
294 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID approval U2011-65 Alter Transmission Line 940L 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 2011-439 778 2011-439 778 U2011-386 New Castle Rock Ridge 205S substation Interconnection Project 2012-005 U2011-387 New Transmission Line 1071L U2011-388 New Transmission Line 1072L U2011-389 Alter Goose Lake 103S substation DA 2012- 1863 U2012-337 Alter Transmission Line 1071L - rescinds U2011-387 190 U2012-338 Alter Transmission Line 1072L - rescinds U2011-388 D.0093 Leduc 325S Project 2011-280 737 2011-416 737 U2011-357 New Leduc 325S Substation U2011-358 New Transmission Line 632L U2011-359 Alter Transmission Line 838L DA2012-214 2056 U2012-374 New Leduc 325S Substation - rescinds U2011-357 U2012-375 Alter Transmission Line 632L - rescinds U2011-358 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
Decision 3585-D03-2016 (June 6, 2016) • 295 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID approval Project U2011-338 Errata New Westwood 422S Substation U2011-339 Salvage a portion Transmission Line 700L U2011-340 Alter 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 U2012-605 Alter Transmission Line 700L - rescinds U2011-340 U2012-606 Alter and Re-designate Transmission Line as 694L - rescinds U2011-341 D.0267 Round Hill New Substation – Lac La 2011-408 1298 2011-408 1298 U2011-330 Need for Round Hill 852S Substation Connection Biche Area 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 Abee New Substation – Lac La Biche 2012-220 1363 2012-220 1363 U2012-282 Construct and operate Abee 993S substation Area U2012-283 Construct and operate new transmission line 437L D.0279 Weasel Creek New Transmission Line U2012-284 Construct and operate new Transmission Line 808AL – Lac La Biche Area 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 2011-457 1461 2011-457 1461 U2011-406 Alter and operate Winefred 818S substation – rescinds U2002-537 Upgrade Project D.0284 Thompson New Substation – Lac La 2011-518 1428 2011-518 1428 U2011-456 Construct and operate Thompson 140S substation Biche Area 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
296 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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 2013-130 2389 2013-130 2389 U2013-194 Alter and operate Tilley 498S substation Project 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 2013-186 2169 2013-186 2169 NONE No P&Ls for this project were substantially complete at the end of Upgrade DA2013-195 2753 2013. D.0407 Sunday Creek 539S Connection 2012-356 2010 2012-356 2010 U2012-707 Construct and operate 1118L transmission line Project D.0410 East Calgary Transmission 2012-283 1229 2012-283 1229 U2012-524 Construct new transmission line 1003L Project/Shepard Energy Centre 2013-022 2338 U2013-35 Construct underground transmission line 1109L Interconnection 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
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Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID approval D.0434 Greengate – Blackspring Ridge Wind 2013-070 1625 2013-070 1625 NONE No P&Ls for this project were substantially complete at the end of Farm Interconnection 2013. D.0435 Cherhill 338S Substation Transformer 2013-219 2134 2013-219 2134 U2013-281 Alter and operate Cherhill 338S substation – rescinds U2011-88 Addition 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 2012-276 1888 2012-276 1888 Not provided Connect Chickadee Creek 259S Substation by constructing a new Substation Interconnection Project 138 kV transmission line, called 199AL, and to modify the existing 138 kV transmission line, 199L. D.0336 575S Sundre 25 kV Breaker Addition 2013-155 1745 2013-155 1745 Not provided Alter the Sundre 575S Substation and re-terminate the existing Project 138 kV transmission line 719L D.0214 ENMAX SS-10 69 kV Conversion 2012-194 234 2012-194 234 Not provided Alter the 138 kV transmission line 832L to an in/out configuration Project DA2014-114 3211 and redesignate a portion of the 138 kV transmission line between the Sarcee 42S Substation and ENMAX SS-10 Substation as 693L, D.0345 131S Moon Lake 25 kV Breaker 2012-314 2144 2012-314 2144 Not provided Upgrade the existing Moon Lake 131S Substation Addition Project D.0360 Onoway 352S Substation Upgrade 2013-083 2252 2013-083 2252 Not provided Alter the Onoway 352S Substation Project 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 2010-183 271 2013-011 2143 Not provided Decommission and Salvage the Judy Creek 236S Substation and Project 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 Not required 2498 telecommunications tower at Jarrow 252S substation 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
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Project NID NID Facility Facility P&L/ Project name Description of facilities or approval ref decision ID decision ID 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 None None None None None A 5 kV upgrade at Kingman 299S Substation at the request of Upgrades 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 AESO None 2012-227 2092 Not provided Replacement of the existing phasor measurement unit devices at Project letter of Langdon 102S and Sundance 310P substations direction D.0485 BUCCSDC Fortis Airdrie U2009-48 17550 2013-248 2596 Not provided Upgrade of telecommunications sites in Calgary. Telecommunication 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- None None None None None Cross connection to support the connection of the 9016R AESO Connection 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 None None None None None Terminate the 2029L, 25 kV feeder circuit to the North Calder 37S 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) • 299 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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:
푤̅퐴퐵 = average (engineering) wage rate for civil, electrical, and mechanical engineers in Alberta (AB)
푤̅푇푋 = average (engineering) wage rate for civil, electrical, and mechanical engineers in Texas (TX)
J퐴 = 푤̅퐴퐵/푤̅푇푋 = Jurisdiction Adjustment (same regardless of job classification)
퐶 퐶 푤퐴퐵 = 푤̅퐴퐵 × (1 + 푚퐴퐵) = wage paid in Alberta by contractor there for job classification “C”, where:
퐶 푚퐴퐵 = markup (or markdown) in Alberta for wages in job classification “C” relative to the average engineering wage rate in Alberta, 푤̅퐴퐵.
퐶 퐶 푤푇푋 = 푤̅푇푋 × (1 + 푚푇푋) = wage paid in Texas by contractor there for job classification “C”, where:
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퐶 푚퐴퐵 = markup (or markdown) in Texas for wages in job classification “C” relative to the average wage engineering rate in Texas, 푤̅푇푋.
퐶 퐿퐴퐵 = loading charged by contractor in Alberta for job classification “C”, which converts wage rates into (loaded) billing rates (including all burdens), so that:
퐶 퐶 퐶 퐵푅퐴퐵 = 푤퐴퐵 × (1 + 퐿퐴퐵) = loaded billing rate for job classification “C” in Alberta
퐶 퐿푇푋 = loading charged by contractor in Texas for job classification “C”, which converts wage rates into (loaded) billing rates (including all burdens), so that:
퐶 퐶 퐶 퐵푅푇푋 = 푤푇푋 × (1 + 퐿푇푋) = loaded billing rate for job classification “C” in Texas. Analysis Including Jurisdiction Adjustments:
퐶 퐶 6. Ultimately, the comparison in the PowerAdvocate Report is between 퐵푅퐴퐵 and (퐵푅푇푋 × J퐴), 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:
퐵푅퐶 푤퐶 ×(1+퐿퐶 ) 푤̅ ×(1+푚퐶 )×(1+퐿퐶 ) 푤̅ ×(1+푚퐶 )×(1+퐿퐶 ) (A) 퐴퐵 = 퐴퐵 퐴퐵 = 퐴퐵 퐴퐵 퐴퐵 = 퐴퐵 퐴퐵 퐴퐵 , 퐵푅퐶 푤퐶 ×(1+퐿퐶 )×퐽퐴 푤̅ ×(1+푚퐶 )×(1+퐿퐶 )×퐽퐴 퐶 퐶 푤̅ 퐴퐵 푇푋 푇푋 푇푋 푇푋 푇푋 푇푋 푤̅푇푋×(1+푚푇푋)×(1+퐿푇푋)×( ) 푤̅ 푇푋 which by cancelling like terms can be simplified to:
퐶 퐶 퐶 퐵푅퐴퐵 (1+푚퐴퐵)×(1+퐿퐴퐵) (B) 퐶 = 퐶 퐶 퐵푅푇푋 (1+푚푇푋)×(1+퐿푇푋) 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 퐶 퐶 same in each jurisdiction (so that 푚퐴퐵 = 푚푇푋), and if the percentage loading charged by the 퐶 퐶 contractor is the same in each jurisdiction (so that 퐿퐴퐵 = 퐿푇푋), 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 퐶 퐶 퐶 퐵푅퐴퐵 between 퐵푅퐴퐵 and 퐵푅푇푋 across different job classifications, a result in which the ratio of ( 퐶 ) 퐵푅푇푋 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.
퐶 퐵푅퐴퐵 8. There are several problems with using the ratio of ( 퐶 ) as defined in (B) to determine 퐵푅푇푋 퐶 퐶 competitiveness. First, there is no reason why 푚퐴퐵 should equal 푚푇푋 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 퐶 퐶 competitiveness. Of course different values for 푚퐴퐵 and 푚푇푋, 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
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“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.
퐶 퐶 9. Second, there is no reason why 퐿퐴퐵 should equal 퐿푇푋 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 퐶 퐶 for 퐿퐴퐵 and 퐿푇푋, 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:
퐵푅퐶 (1+푚퐶 )×(1+퐿퐶 ) (C) 퐴퐵 = 퐴퐵 퐴퐵 , 퐵푅퐶 퐶 퐶 푎푣푔 푎푣푒푟푎푔푒[(1+푚푗 )×(1+퐿푗 )] 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):
퐶 퐶 퐶 퐶 퐶 퐵푅퐴퐵 푤퐴퐵×(1+퐿퐴퐵) 푤̅퐴퐵×(1+푚퐴퐵)×(1+퐿퐴퐵) (D) 퐶 = 퐶 퐶 = 퐶 퐶 퐵푅푇푋 푤푇푋×(1+퐿푇푋) 푤̅푇푋×(1+푚푇푋)×(1+퐿푇푋) 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:
302 • Decision 3585-D03-2016 (June 6, 2016) 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
퐶 퐶 퐶 퐵푅퐴퐵 푤퐴퐵×(1+퐿퐴퐵) (E) 퐶 = 퐶 퐶 퐵푅푇푋 푤푇푋×(1+퐿푇푋) 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:
퐶 퐶 퐶 퐵푅퐴퐵 푤퐴퐵×(1+퐿퐴퐵) (F) 퐶 = 퐶 퐶 퐵푅푎푣푔 푎푣푒푟푎푔푒[푤푗 ×(1+퐿푗 )] 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) • 303 2012 and 2013 Deferral Accounts Reconciliation Application AltaLink Management Ltd.
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,
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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
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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
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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
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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
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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
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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
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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 ATCO Electric Ltd. AET 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
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Abbreviation Name in full 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
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Abbreviation Name in full 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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