Upgrades – Major Assets
In this decision, the AUC approved the applications from ENMAX Power Corporation (“EPC”) to decommission the EN 1S Substation and construct and operate a new substation to be designated as the No. 1 Substation in downtown Calgary.
EPC planned to decommission the existing No.1 Substation once the new No. 1 Substation became fully energized. EPC estimated the proposed project would be in-service by early 2025, and estimated the project cost to be $ 207 million with an accuracy of +20 per cent/-10 per cent.
Need and Capital Maintenance
EPC stated that the need for the project was driven by the age and condition of assets and infrastructure at the No. 1 Substation. The AUC was satisfied that the needs identification document exception set out in Section 1.4.1(a) of Rule 007 covered this application and agreed with EPC that the equipment condition, not future load requirements, was the main motivator for the project.
The AUC found that the evidence provided by EPC regarding the structural integrity of the existing substation and the potential to upgrade the current building for continued on-site use was more reliable than evidence provided by other parties.
The AUC was not persuaded by alternatives proposed by the Consumers’ Coalition of Alberta (“CCA”) and determined that the existing buildings within the No. 1 Substation required replacement.
The AUC found that the existing transformers at the No. 1 Substation are near end-of-life and should be replaced. The CCA submitted that transformers manufactured in the 1960s and 1970s can be expected to last well beyond 50 years. The AUC acknowledged that, while it may be true that transformers manufactured in a given era tend to be more robust than their modern equivalents, EPC provided compelling evidence describing why the specific transformers at the No. 1 Substation may not follow this trend and should be replaced. The AUC was particularly persuaded by the safety, environmental, operational, and financial consequences that would result from a potential simultaneous or cascading failure of multiple transformers. The CCA’s recommendation to replace the transformers over the next three to 20 years appeared to be essentially a “run to failure” approach, which the AUC found imprudent for a major substation that supplies a significant portion of downtown Calgary’s load.
Medium Voltage Switchgear
The AUC accepted that both sets of MV switchgear at the No. 1 Substation are obsolete, have reached their end-of-life, and should be replaced. It noted that all parties agreed that the MV switchgear at the substation is at end-of-life condition. However, the CCA suggested that the minimum oil switchgear is at low risk of failure and can be replaced in the next 10 to 15 years. The AUC does not consider it acceptable from a safety or reliability standpoint to delay the replacement of an asset for up to 15 years when it has already reached end-of-life. It agreed that the MV switchgear in the No. 1 Substation should be replaced in the next five years.
High Voltage Bus Configuration
The AUC found that the high voltage (“HV”) gas-insulated switchgear (“GIS”) at the No. 1 Substation was in poor condition and required replacement within five years. In making this finding, the AUC noted that lead times between four and greater than 12 months, associated with spare parts, combined with the obsolete nature and poor performance of the model of GIS.
Other Asset Condition Issues
The AUC found that it was an unusual situation for EPC to apply for simultaneous replacement of all major assets at the No. 1 Substation. Regarding the issue of not many staged repairs or replacements of major assets having taken the place in the previous ten years, the AUC accepted EPC’s explanation that the repairs had been prevented by operational and space constraints.
Alternative Options and Substation Upgrades
EPC approached the project as a “like-for-like” replacement, incorporating modern technologies and design practices, where appropriate, in the new No. 1 Substation.
The AUC found that changing the substation layout from four 62.5-MVA transformers to five 50-MVA transformers, as proposed by EPC, was an appropriate design change. The AUC was satisfied that the total installed capacity of the substation under normal operating conditions would remain the same. It further found that the existing transformers were near end-of-life and that their replacement was justified. The AUC found that the proposed transformer change would not result in an increase in transmission capacity and restated the Alberta Electric System Operator’s (“AESO”) conclusion that a NID application to the AUC was not required.
The AUC approved EPC’s design change to parallel transformer operation and noted that the Calgary downtown secondary distribution network was designed for parallel operation. The AUC found that, with the changes to parallel operations, the reliability would be increased because all transformers would be used simultaneously to supply load.
The AUC found that there was uncertainty regarding the time at which the load served by the substation would exceed 100 MVA, and the fifth transformer would be needed. As a result, the AUC approved the construction and operation of the fifth transformer but did not allow EPC to include the fifth transformer in its rate base until it is required to be used to provide utility service.
Medium and HV Bus Configuration
EPC proposed a multi-ring configuration for the substation. It stated this was a standard MV bus layout, would facilitate the de-energization of a bus diameter during a system contingency, and would facilitate parallel transformer operation, improving reliability and crew safety. The AUC approved the MV bus design.
EPC stated that the ring bus configuration of the HV bus was outdated and did not meet EPC’s design standards or the proposed AESO Rule 502.11. The AUC agreed with this statement and approved EPC’s proposed upgrade to the breaker-and-a-third configuration.
The AUC found that the incremental cost to upgrade the ring bus configuration was justified to meet modern design standards. The AUC further found EPC’s selection of 170-kV rated equipment reasonable, as 170-kV was the lowest standard voltage rating that would meet the anticipated voltage requirements.
The CCA’s Proposal
The CCA submitted that the different types of major equipment at the No. 1 Substation were not interdependent and that they could all be replaced separately and in any sequence. The CCA submitted that not all equipment required immediate replacement and, therefore, the sequence and timing of replacement should be determined by individual equipment condition. In its proposal, the CCA suggested a staged replacement of the major equipment to be completed by 2030.
The AUC was not persuaded by the alternative proposal provided by the CCA as it was insufficient and lacked detail. The AUC found that the CCA’s proposal understated safety and reliability concerns, which raised further doubt regarding the CCA evidence.
The AUC was satisfied that EPC had adequately assessed the costs, reliability, and risks of the No. 1 Substation Replacement Project. The AUC found that downtown Calgary, served by the No. 1 Substation, required a high level of reliability. The AUC was satisfied with EPC’s assessment of the costs and benefits associated with the project, despite the value of lost load not having been calculated. The AUC accepted EPC’s proposal to maintain its existing N-2 reliability standards and was not persuaded that this level was not needed.
Load Forecast and Uncertainty
The AUC found EPC’s forecast of load to have been better supported and more representative of future load than that suggested by the CCA and Utilities’ Consumer Advocate (“UCA”). Regarding issues of vacancy rate in downtown Calgary and long-term impacts, the AUC was persuaded by the evidence presented by EPC. The AUC found that long-term impacts on load due to the COVID-19 pandemic were uncertain. The AUC repeated that its decision regarding the No. 1 Substation project was primarily driven by asset condition, not load.
The AUC accepted that the installation of the fifth transformer and its associated components during the initial construction was warranted from a cost and safety perspective. The AUC found that by placing conditions on when the fifth transformer and associated components are placed into EPC’s rate base, it addressed the load uncertainty while balancing EPC’s cost and safety concerns.
The AUC acknowledged concerns raised by interveners regarding limited information on the record associated with land remediation or reclamation at the existing site. Given statements and confirmations regarding environmental remediation and liability made by EPC, the AUC expected that EPC had reasonably accounted for the risk of potential environmental liability being imposed upon EPC at the existing site, as well as costs related to land remediation at the proposed site.
Regarding concerns raised by the CCA related to cost estimates of asbestos abatement of the existing buildings, the AUC accepted EPC’s anticipated asbestos abatement requirements for the buildings at the existing substation.
The AUC further found that residual environmental effects of the project would not be significant if EPC observed suggested mitigation measures. The AUC required that EPC file a copy of the environmental management plan for the project, including mitigation measures, 60 days prior to the commencement of construction. This requirement was imposed to ensure an up-to-date environmental management plan was in place at the time of construction.
Concluding Findings and Decision
Based on its findings, the AUC determined that the applications were in the public interest in accordance with Section 17 of the Alberta Utilities Commission Act. The AUC approved EPC’s application.