ENMAX Power Corporation - No. 1 Substation Replacement Project January 18, 2021 - Decision 25206-D01-2021 - Alberta Utilities Commission
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Decision 25206-D01-2021 ENMAX Power Corporation No. 1 Substation Replacement Project January 18, 2021
Alberta Utilities Commission
Decision 25206-D01-2021
ENMAX Power Corporation
No. 1 Substation Replacement Project
Proceeding 25206
Applications 25206-A001 to 25206-A008
January 18, 2021
Published by the:
Alberta Utilities Commission
Eau Claire Tower
1400, 600 Third Avenue S.W.
Calgary, Alberta T2P 0G5
Telephone: 310-4AUC (310-4282) in Alberta
1-833-511-4AUC (1-833-511-4282) outside Alberta
Email: info@auc.ab.ca
Website: www.auc.ab.ca
The Commission may, within 30 days of the date of this decision and without notice, correct
typographical, spelling and calculation errors and other similar types of errors and post the
corrected decision on its website.Contents
1 Introduction ........................................................................................................................... 1
2 Discussion............................................................................................................................... 2
2.1 Introduction .................................................................................................................... 2
2.2 Need and capital maintenance ........................................................................................ 4
2.3 Asset condition ............................................................................................................... 6
2.3.1 Introduction ....................................................................................................... 6
2.3.2 Substation buildings .......................................................................................... 6
2.3.3 Transformers ..................................................................................................... 9
2.3.4 Medium voltage switchgear ............................................................................ 13
2.3.5 High voltage switchgear ................................................................................. 15
2.3.6 Other asset condition issues ............................................................................ 18
2.4 Alternative options and substation upgrades ............................................................... 19
2.4.1 Introduction ..................................................................................................... 19
2.4.2 Transformers ................................................................................................... 19
2.4.3 Medium voltage bus configuration ................................................................. 24
2.4.4 High voltage bus configuration ....................................................................... 24
2.4.5 The CCA’s proposal ....................................................................................... 27
2.5 System reliability ......................................................................................................... 31
2.6 Load forecasts and uncertainty..................................................................................... 35
2.7 Other issues .................................................................................................................. 38
2.7.1 Environment .................................................................................................... 38
2.7.2 Noise ............................................................................................................... 41
2.7.3 Potential future sale of land ............................................................................ 42
3 Concluding findings ............................................................................................................ 43
4 Decision ................................................................................................................................ 44
Appendix A – Proceeding participants ..................................................................................... 46
Appendix B – Summary of Commission conditions of approval............................................ 47Alberta Utilities Commission
Calgary, Alberta
Decision 25206-D01-2021
ENMAX Power Corporation Proceeding 25206
No. 1 Substation Replacement Project Applications 25206-A001 to 25206-A008
1. In this decision, the Alberta Utilities Commission approves applications from
ENMAX Power Corporation to decommission the existing EN 1S Substation and construct and
operate a new substation to be designated as the No. 1 Substation in downtown Calgary.
1 Introduction
2. ENMAX Power Corporation (EPC) filed applications with the Alberta Utilities Commission,
pursuant to sections 14, 15, 18 and 21 of the Hydro and Electric Energy Act, seeking approval to:
• decommission the existing EPC EN 1S Substation located in downtown Calgary 1
• construct and operate a new substation designated as the EPC No. 1 Substation
• alter the six underground transmission lines that feed the substation (138-1.80L through
138-1.85L)
• connect the new substation and altered transmission lines to the Alberta Interconnected
Electric System
3. EPC also requested a Class A2 ambient monitoring adjustment to 66 A-weighted decibels
(dBA) for the nighttime permissible sound level (PSL) in accordance with Section 2 of
Rule 012: Noise Control. The applications were registered on December 18, 2019, as
Applications 25206-A001 to 25206-A008.
4. On January 14, 2020, the Commission issued a notice of applications for the project. The
Commission received statements of intent to participate from Brenda McManus on behalf of
QuadReal Property Group, the Consumers’ Coalition of Alberta (CCA), and the Office of the
Utilities Consumer Advocate (UCA). On March 11, 2020, the Commission granted standing to
all three parties. QuadReal did not submit any further evidence on the record of the proceeding.
5. On April 17, 2020, the Commission issued a ruling on scope following a written technical
meeting attended by EPC, the CCA and the UCA. At the request of the parties actively involved
in the proceeding, the Commission initiated an information request process in lieu of an oral
hearing.
1
The official name of the existing substation is the “EN 1S Substation.” For consistency, it is referred to in this
decision as the “existing No. 1 Substation”. The proposed project is referred to as the “new No. 1 Substation” or
“proposed No. 1 Substation”.
Decision 25206-D01-2021 (January 18, 2021) 1No. 1 Substation Replacement Project ENMAX Power Corporation
6. On October 13, 2020, EPC held a site visit at the existing No. 1 Substation to help parties
better understand the layout, equipment and buildings within the existing substation. The
Commission, the UCA and the CCA attended the site visit.
7. Oral argument and reply were heard virtually on October 23, 2020.
2 Discussion
2.1 Introduction
8. EPC’s application indicates that the existing No. 1 Substation was built in 1912 and
currently supplies power to approximately 45 per cent of the downtown area. Customers in the
area are primarily high density commercial with a mixture of high density and single family
residential. The existing No. 1 Substation is located at 738 9 Avenue S.W. in Calgary.
9. EPC’s evidence is that the replacement of the existing No. 1 Substation is driven by aging
major assets and civil infrastructure that are at or near end-of-life. EPC explained that if the
substation is not replaced, there is a high risk of equipment failure, which would require
expensive repairs or replacements. Such an event would also disrupt the power supply of EPC’s
customers and result in potential safety risks to the public and EPC personnel.
10. The new substation would be located at 808 and 830 9 Avenue S.W. EPC analyzed five
potential sites for the new substation and selected a site across the street from the existing site as
the best option. Below is a map showing the locations of the existing and proposed
No. 1 Substation:
5 AVE. S.W.
4 ST. S.W.
AUC
Alberta Utilities Commission
9 ST. S.W.
6 AVE. S.W. Legend
Proposed substation location
7 ST. S.W.
Existing substation and
decommissioning location
7 AVE. S.W.
6 ST. S.W.
8 AVE. S.W. N
5 ST. S.W.
NOTES:
1. Data Sources: Alberta Environment and Parks
2. Background Source: AutoCAD Map 3D
9 AVE S.W.
Proposed ENMAX No. 1
Substation
1
10 AVE. S.W.
CALGARY
8 ST. S.W.
36
Calgary Area
11 AVE. S.W. Proceeding 25206
Enmax Power Corporation
N.T.S.
Figure 1: Project map
Decision 25206-D01-2021 (January 18, 2021) 2No. 1 Substation Replacement Project ENMAX Power Corporation
11. EPC evaluated two options in determining its proposed project: rebuilding the substation
on the existing site or building a new substation on a new site. Ultimately, EPC concluded that
building a new substation on a new site would result in lower costs and impacts including shorter
construction time, fewer construction risks, reduced likelihood of an electrical system event and
a safer work environment. EPC’s evidence is that rebuilding the substation on the existing site
would take approximately 10 years, and result in added challenges because of the requirement to
work around energized equipment. EPC estimated that constructing the substation on a new site
would take five years.
12. EPC proposed a number of changes and upgrades for the new substation:
Table 1: Specifications for existing and new No. 1 Substation
Existing substation Proposed substation
Transformers Four 138-kV/13-kV, 37.5/50.0/62.5- Five 138/13.8-kV, 30/40/50-MVA
megavolt ampere (MVA) transformers transformers (in parallel configuration)
High voltage bus One 138-kV gas-insulated switchgear One 138-kV GIS in breaker-and-a-third
(GIS) in ring bus configuration configuration
Medium voltage bus Two sets of 13.8-kV switchgear One 15-kV class arc resistant, air-insulated
switchgear
Buildings Four buildings (main substation building New building for HV and MV switchgear,
housing auxiliary equipment, high voltage protection and control, SCADA,
(HV) switchgear building, medium voltage telecommunications equipment
(MV) switchgear building, and former HV
cable oil storage building, now used as
equipment storage)
13. EPC proposed to re-terminate the six underground transmission lines that are currently
connected to the existing No. 1 Substation. EPC designed the new transmission line segments to
match the cables used in the existing transmission lines. The new cables would be installed in the
road allowance, in alignments granted by the City of Calgary.
14. EPC planned to decommission the existing No. 1 Substation once the new
No. 1 Substation is fully energized. All transmission and distribution equipment would be
removed but the buildings and fence would remain intact on the site. EPC explained that it
intends to sell the existing site once decommissioning is complete and added that
decommissioning will be conducted in accordance with the Environmental Protection Guidelines
for Transmission Lines. 2
15. EPC conducted a participant involvement program in accordance with the requirements
of Appendix A1 in Rule 007: Applications for Power Plants, Substations, Transmission Lines,
Industrial System Designations and Hydro Developments. In October 2019, EPC sent project
2
The Commission notes that the referenced guideline was rescinded on March 31, 2020, and a new guideline
(Reclamation Practices and Criteria for Powerlines) issued on May 29, 2020. While the new guideline does not
reference substations explicitly, the Commission takes EPC’s statement to mean, and expects that EPC will,
conduct the decommissioning in accordance with applicable laws, regulations and guidelines in place at the
time of decommissioning.
Decision 25206-D01-2021 (January 18, 2021) 3No. 1 Substation Replacement Project ENMAX Power Corporation
information packages to landowners and utilities at or directly adjacent to the project, local and
provincial government representatives, and neighbourhood community associations. In October
and November 2019, EPC personally engaged with 64 occupants, residents and landowners
located at or directly adjacent to the project. EPC held two public open houses for the project.
16. EPC submitted a noise impact assessment (NIA) in support of its applications and
concluded that the proposed project would comply with PSLs established in accordance with
Rule 012.
17. EPC estimated the project cost to be $207 million with an accuracy level of
+20 per cent/-10 per cent. 3 EPC noted that the estimated cost to rebuild the substation on the
existing site is $256 million. 4 EPC estimated the project would be in-service by early 2025.
2.2 Need and capital maintenance
18. EPC stated that the need for the project is driven by the age and condition of assets and
infrastructure at the No. 1 Substation. EPC confirmed that the Alberta Electric System Operator
(AESO) was aware of the project and the proposed changes to the substation, and had no
concerns. EPC submitted that, pursuant to Section 1.4.1 of Rule 007, the project is exempt from
the AESO’s requirement for a needs identification document (NID): 5
A needs identification document application is not required for:
(a) Maintenance upgrades, enhancements or other modifications to a transmission
facility proposed by a TFO or market participant if the maintenance upgrade,
enhancement, or other modification improves the efficiency or operation of the
transmission facility but does not materially affect transmission facility
capacity. 6 [emphasis added]
19. While the Commission determined the question of whether the project requires a NID
and the AESO’s involvement to be out of scope in this proceeding, the CCA argued that EPC
was increasing substation load supply capability from 125 MVA to 150 MVA, an increase of
20 per cent, which is an enhancement and expansion of the capability of the transmission system.
The CCA therefore submitted that the new substation is not a capital maintenance project and
requires an approved NID.
20. In its evidence, the CCA maintained that EPC had incorrectly quoted Section 34 of the
Electric Utilities Act, which requires a NID for “an expansion or enhancement of the capability
of the transmission system.” 7 (emphasis added) The CCA argued that the concept of capacity and
capability are distinct and that capability of a transmission system as described in the
Transmission Regulation should be determined by assessing reliability standards and planning
criteria. The CCA submitted that EPC’s substation proposal is an expansion of capability and
should not be approved by the Commission without an approved NID.
3
Exhibit 25206-X0001, 2019-12-18-EPC-No. 1 Substation Replacement Application, PDF pages 11 to 12.
4
Exhibit 25206-X0064, 2020-04-09-EPC - Supplemental Evidence 25206, PDF page 28.
5
Exhibit 25206-X0001, 2019-12-18-EPC-No. 1 Substation Replacement Application, PDF pages 8 to 9.
6
Rule 007, Section 1.4.1, PDF pages 5 to 6.
7
Electric Utilities Act, Section 34, Chapter E-5.1.
Decision 25206-D01-2021 (January 18, 2021) 4No. 1 Substation Replacement Project ENMAX Power Corporation
21. In response to the CCA’s submissions, EPC reiterated that it is not relying on Section 34
of the Electric Utilities Act, but rather the exemption set out in Section 1.4.1(a) of Rule 007,
which makes no mention of expanding or enhancing the capability of the transmission system.
22. EPC also suggested that the CCA incorrectly interpreted the statutory framework around
NID requirements. While EPC acknowledged that Section 34 of the Electric Utilities Act
stipulates the requirement of a NID for the expansion or enhancement of the capability of the
transmission system, it also referred to Section 142(1)(l)(v.6) of the Electric Utilities Act,
which gives cabinet the authority to make regulations respecting the making of rules by the
Commission setting out when a NID is not required. EPC went on to explain that in
Section 11.1(a) of the Transmission Regulation, cabinet did just that and granted the
Commission the authority to make exemptions from the NID requirement set out in Section 34 of
the Electric Utilities Act. 8
23. The CCA disagreed with EPC’s characterization of the project as capital maintenance,
submitting that it involves a significant expansion in load supply capacity, functionality, and the
amount of equipment installed, which has resulted in a need for more space, new buildings, and
the construction of an entirely new facility. The CCA argued that EPC should have created a
business case where the baseline case was a true like-for-like replacement of substation assets
with any incremental upgrades supported by a cost-benefit analysis.
24. While EPC agreed that its proposal is different from the original substation, it explained
that its design for the new substation has taken into account the development of modern
technology and current industry standards in an effort to modernize the substation while
maintaining the existing capacity.
25. EPC submitted that transmission facility capacity is measured by installed transformer
capacity, not load supply capacity during contingency situations and that despite the number of
transformers increasing from four 62.5-MVA transformers to five 50-MVA transformers,
installed transformer capacity would remain unchanged at 250 MVA.
26. Similar to the CCA, the UCA suggested that the project is not a like-for-like replacement
as it is being built to a higher reliability standard than required to provide safe and reliable
service. The UCA stated that need for the project has declined substantially because of the
COVID-19 pandemic and a worldwide reduction in demand for oil, all of which has led to
decreasing economic activity in downtown Calgary.
27. In response, EPC argued that because the project is asset condition driven and not load
driven, changes in load do not affect the need for the project. Therefore, whether the project is a
like-for-like replacement does not affect the fact that the project is exempt from a NID.
Commission findings
28. The Commission previously ruled that the question of whether the project requires a NID
and the AESO’s involvement in this proceeding was out of scope. The Commission finds that it
is unnecessary for it to repeat or to reconsider that ruling. In the interest of clarity, the
Commission is satisfied that EPC’s application falls into the NID exemption set out in
Section 1.4.1(a) of Rule 007, which explicitly includes maintenance upgrades, enhancements and
8
Transmission Regulation, AR 86/2007, Section 11.1(a).
Decision 25206-D01-2021 (January 18, 2021) 5No. 1 Substation Replacement Project ENMAX Power Corporation
other modifications that do not materially affect transmission facility capacity. While EPC has
proposed to expand and upgrade the No. 1 Substation, the substation’s total capacity will remain
unchanged at 250 MVA.
29. The Commission agrees with EPC that equipment condition is the main driver for the
project, not future load requirements. However, the fact that a NID is not required does not rule
out consideration of whether there is a need for the project, based on current economic
conditions and projected future load. Although the No. 1 Substation Replacement Project is an
asset condition driven project, future load requirements are appropriately a factor which the
Commission is permitted to and has considered as part of its overarching public interest review
of EPC’s applications. Issues around load and reliability are further discussed in Section 2.6.
2.3 Asset condition
2.3.1 Introduction
30. EPC submitted that the major assets and civil infrastructure at the No. 1 Substation are
aging and nearing, or at, their end of life, and therefore at risk of failure based on their current
condition. EPC stated that the condition of the assets at the substation have led to maintenance
difficulties, safety and operational risks. Assets that require repair or replacement include the
substation buildings, transformers, MV switchgear, HV switchgear, and other equipment
including substation protection relays, battery banks, battery chargers and grounding equipment.
31. The CCA provided technical evidence on the current condition of the major assets within
the substation. The authors of this technical evidence were Trevor Cline, Naval Tauh and
Tom Greenwood-Madsen. The CCA’s evidence concluded that, with the exception of the MV air
blast switchgear, most of the equipment and buildings within the No. 1 Substation appear to be in
reasonably good condition and do not require immediate replacement. The CCA provided a
staged capital maintenance replacement program over the next five to 20 years for the existing
equipment as an alternative to rebuilding the substation.
32. As part of its facility application, EPC engaged Read Jones Christoffersen Ltd. (RJC),
who in collaboration with Remedy Engineering, SMP Engineering and William B. Evans
Architect Ltd., conducted a condition assessment for each building. EPC noted that “RJC is a
leading Canadian engineering firm that specializes in structural engineering and building
science” and that it has considerable experience with old buildings. 9 RJC was again engaged to
respond to the CCA’s evidence on the condition of the buildings in the substation.
33. EPC also engaged PowerNex Associates Inc., who it submitted is “an industry leading
expert in the areas of asset condition, asset management, power equipment design and
application, and maintenance engineering”, 10 to provide a report responding to the CCA’s
evidence.
2.3.2 Substation buildings
34. The existing No. 1 Substation contains four buildings:
• The main building, constructed in 1912, contains a fiber optic switching room.
9
Exhibit 25206-X0334, Vol_01_2020-10-23, PDF page 84.
10
Exhibit 25206-X0287, 2020-09-25-EPC - Reply Evidence AUC Proceeding 25206, PDF page 43.
Decision 25206-D01-2021 (January 18, 2021) 6No. 1 Substation Replacement Project ENMAX Power Corporation
• The 13-kilovolt (kV) building, constructed in 1956, contains the 13.8-kV MV switchgear.
• The Sulphur hexafluoride (SF6) building, constructed in 1974, contains the 138-kV HV
switchgear.
• The oil storage building, estimated to be constructed in the 1960s, previously stored the
HV transmission cable oil, but now stores substation maintenance tools and equipment.
35. RJC identified a number of issues associated with the buildings and concluded that all
four buildings have structural, building envelope, mechanical, and electrical issues that need to
be addressed to continue the safe and reliable operation of equipment within the buildings. RJC
estimated a total cost of $6 million to repair or upgrade the buildings, with the bulk of the repairs
recommended immediately. 11 RJC noted that the 13-kV and SF6 buildings are in significantly
better structural condition than the main building and suggested that the switchgear could be
replaced within those buildings. Based on these recommendations, EPC determined that
redeveloping the substation with new buildings would eliminate the need for costly and risky
condition assessments, upgrades, and repairs.
36. The CCA proposed a long term capital maintenance plan which would eliminate the need
for EPC to tear down and replace the buildings at the No. 1 Substation. In its plan, the CCA
discussed the possibility of reusing the existing substation buildings to house new substation
equipment over the next five to 15 years.
37. EPC noted that “[t]he CCA’s proposal to replace the assets within the existing buildings
implicitly assumes that the existing buildings can be safely and reliably used for an additional
50 years (based on an approximate service life of new electrical equipment) with only minor
repairs or modifications.” 12 RJC submitted that the CCA’s assessment was incomplete and
inadequate as it neglected to consider the need and associated costs for repairs or modifications
that would be required to maintain the existing structures for the next 50 years. RJC strongly
recommended against reusing the existing buildings to house new substation equipment as it
does not expect the main building to remain for an additional 40 to 50 years without major
structural repairs or modifications. Additionally, it said that continued use of the existing
buildings would have implications on EPC’s ability to perform maintenance or repairs around
the existing equipment, as well as on the flexibility to accommodate new equipment.
38. EPC maintained that there is currently insufficient space within the existing 13-kV
building to install new MV switchgear while allowing the current switchgear to remain in
service. EPC added that because the MV switchgear is required to remain in service to supply
electricity to customers, the removal and subsequent installation of new MV switchgear would
require an extended outage.
39. The CCA suggested that, because the existing MV and HV switchgear at the
No. 1 Substation occupy significantly more space than is required for their modern equivalents,
the replacement of equipment should create additional space within the 13-kV and SF6 buildings,
thereby eliminating the need to construct new buildings to house the new switchgear. The CCA
also argued that, for the SF6 and 13-kV buildings, the total RJC estimate for both lateral
11
Exhibit 25206-X0066, Appendix 2 - RJC-Condition Assessment Report - FA Redacted Version, PDF page 8.
12
Exhibit 25206-X0287, 2020-09-25-EPC - Reply Evidence AUC Proceeding 25206, PDF page 50.
Decision 25206-D01-2021 (January 18, 2021) 7No. 1 Substation Replacement Project ENMAX Power Corporation
stabilization, as well as a new structure to support new switchgear, is $1.3 million which is small
in comparison to constructing two new buildings. 13
40. RJC recommended against reusing the existing No. 1 Substation buildings to house new
substation equipment. In response to the CCA’s submission in this regard, RJC stated that such
claims appear to be based on a cursory comparison of the size of the existing buildings versus the
equipment. RJC explained that the CCA did not consider the effect of changes in the size,
weight, footprint, and anchorage requirements of the new equipment, and thus how the new
equipment might result in different loading conditions on the base building structure.
41. In regard to the 13-kV building which hosts the MV switchgear, RJC explained that the
smaller footprint associated with the new MV switchgear may concentrate the load and increase
structural support requirements. RJC cautioned against the idea of working above energized
equipment as it is “extraordinarily difficult and risky.” 14 In relation to the SF6 building which
hosts the HV GIS, RJC considered it unlikely that EPC could replace the existing HV switchgear
within the SF6 building without structural modifications. These structural modifications would
likely cost more than the CCA’s cited $1.3 million which RJC said only includes immediate
costs and does not factor in conditional costs which would be required in the event of significant
renovations. 15
42. EPC asserted that unlike the authors of the RJC reports, the CCA’s consultants are not
structural engineers. RJC opined that the CCA’s technical consultants are not qualified to make
the conclusions they did about building condition and their potential for future usage.
43. RJC noted that, in general, buildings meant to house specialized equipment are
specifically designed to house that equipment, and that specialized equipment is not generally
modified to suit existing buildings. RJC submitted that if the existing buildings were to be
reused, they would need to be brought up to modern standards including the current standards for
post-disaster buildings. RJC stated that the CCA’s building-related estimates significantly
understate the risks and hazards involved in long-term construction around energized equipment.
Commission findings
44. The Commission is faced with conflicting evidence regarding the structural integrity of
the existing substation and the potential to upgrade the current buildings for continued on-site
use. The evidence provided by RJC was prepared by structural and design engineers with
considerable experience in structural matters, building design and maintenance. The evidence of
the CCA was provided by electrical engineers with limited experience in structural matters. The
Commission prefers the evidence of RJC which was based on the application of considerable
knowledge and expertise to a comprehensive assessment of the existing structures. The
Commission therefore finds RJC’s evidence to be more reliable. The CCA’s evidence on this
issue, on the other hand, was anecdotal in nature and premised upon a cursory examination of the
proposed structures. In the Commission’s view, the CCA witnesses lacked the necessary
specialized expertise to provide reliable opinion evidence on these matters.
13
Exhibit 25206-X0334, Vol_01_2020-10-23, PDF page 137.
14
Exhibit 25206-X0293, 2020-09-25-RJC Rebuttal Evidence on Behalf of EPC, PDF page 17.
15
Exhibit 25206-X0293, 2020-09-25-RJC Rebuttal Evidence on Behalf of EPC, PDF pages 16 to 17.
Decision 25206-D01-2021 (January 18, 2021) 8No. 1 Substation Replacement Project ENMAX Power Corporation 45. The Commission is persuaded by the evidence submitted by RJC that reusing the existing buildings at the No. 1 Substation to house new equipment would result in increased costs and would carry with it construction feasibility challenges, maintenance issues and increased safety and operational risks compared to the new build option. While the CCA provided a major equipment replacement timeline, which it said would allow the use of the existing buildings to house replacement MV and HV switchgear, the Commission observes that the CCA did not anticipate the costs needed to repair or modify those existing buildings after the 15-year time horizon assessed for the replacement of the switchgear. It is reasonable to assume that the buildings housing the existing switchgear will deteriorate further during and after this 15-year period. The Commission considers this to be an oversight in the CCA’s plan given EPC’s assertion that the new equipment will likely last 40 to 50 years, and that the existing buildings housing the equipment will continue to deteriorate. 46. The Commission accepts EPC’s evidence that the structural, mechanical, electrical and architectural issues present in the existing buildings currently create safety hazards for all EPC personnel present at the substation. The Commission finds that these risks would only increase over the next 40 to 50 years if the existing buildings remained in place. 47. The Commission acknowledges RJC’s assertions that the replacement of old equipment with new equipment (all of which likely have different technical requirements and specifications than the existing equipment) within an existing space calls for a more holistic approach than the predominantly physical rearrangements proposed by the CCA. 48. For the reasons enumerated above, the Commission considers the existing buildings within the No. 1 Substation would need to be replaced to accommodate the proposed equipment replacement. 2.3.3 Transformers 49. The No. 1 Substation contains four 138-kV/13-kV, 37.5/50.0/62.5-MVA, three-phase transformers, manufactured by Westinghouse Electric Corporation. The transformers were installed between 1968 and 1977 and are between 43 and 52 years old. EPC submitted that the typical life span of a transformer is generally 30 to 40 years. EPC maintained that all four transformers have asset condition and maintenance issues, as well as operational and safety risks, and as such, should be replaced. EPC added that, because it has no spare transformers with the same specifications, should a major component in one of the transformers fail, a new transformer would need to be ordered and manufactured. This process typically takes 12 to 14 months. 50. The CCA submitted that the transformers at the No. 1 Substation appear to be in fair condition and can be refurbished. Based on the test data provided and historic and ongoing low loading on the transformers, the CCA concluded that the units can be expected to last another 10 years or more with effective maintenance, active monitoring and prompt repair of deficiencies. 51. The CCA disagreed that the typical transformer lifespan of 30 to 40 years quoted by EPC applies to the transformers at the No. 1 Substation, mainly because of the light loading (average loading of 33 per cent or less), low operating temperatures, and common knowledge that units built before the 1980s are designed to be more robust than modern transformers. The CCA stated that transformer units of this age, if properly maintained, can be expected to last well beyond 50 years. Decision 25206-D01-2021 (January 18, 2021) 9
No. 1 Substation Replacement Project ENMAX Power Corporation 52. EPC stated that there is no technical support for the CCA’s claim that the transformers can last another 10 years or more if refurbished and monitored in real time. In its report, PowerNex stated that all four transformers at the No. 1 Substation are at, or near, end of life, and should be replaced as soon as possible. PowerNex also suggested that the loading history of a transformer provides little to no information about the health of the asset, and disagreed with the CCA’s conclusions on the basis that it did not adequately take into account the specific operating and environmental stresses on the transformers (i.e., higher loading due to the substation’s location in a high density urban area). 53. EPC assessed the condition of each transformer by carrying out a dissolved gas analysis (DGA) and an insulation power factor analysis. EPC maintained that these techniques are industry accepted means of assessing transformer condition. A DGA identifies the types of gas produced by an internal fault, measures the quantity of gas, and allows the operator to identify a trend. One of the gases produced by internal high energy arcing is acetylene. The DGA carried out by EPC focused on the acetylene levels inside the main tank of each transformer. EPC’s DGA results indicated a trend of internal high intensity arcing or continuous discharge in all four transformers. EPC also explained that power factor measures the efficiency of a piece of electrical equipment, and that increasing power factor values signal insulation deterioration. EPC noted that industry recommended insulation power factor levels are 0.5. EPC submitted that the insulation power factor values of the four transformers at the No. 1 Substation have been substantially higher than industry recommended levels for several years, and have continued to trend upward. EPC concluded that these results indicate insulation deterioration in the transformers. 54. The CCA argued that EPC had incorrectly interpreted the DGA test results as gas concentrations alone are not a sufficient indicator of transformer condition. The CCA asserted that EPC had not carried out any diagnostic test such as a partial discharge to verify its claim that there is worsening internal high-energy arcing within the transformers. The CCA stated that the four transformers have had a relatively flat but high level of acetylene in their oil for the last 20 years, and that results indicate there has been no material change in the internal condition of the transformers over this time. The CCA also submitted that EPC’s DGA analysis is suspect due to strong evidence that there is some gas transfer between the main transformer compartment and diverter switch chamber, which may not have been taken into consideration when evaluating the presence of acetylene in the main tank. 55. In response, PowerNex submitted that acetylene levels for the four transformers have not been relatively flat over the past 20 years, but agreed that the DGA results are not a reliable indicator of transformer condition. 56. The CCA also maintained that EPC’s measurements show minimal changes in power factor values over the last 15 years. The CCA noted that the 0.5 per cent industry recommended levels relate to new transformers, and that EPC’s tests overstated the power factor and were completed under inaccurate conditions: power factor tests were performed at a wide range of varying ambient temperatures well below the recommended 20°C, apparatus temperatures were not recorded, and temperature correction was set to “false”. 57. PowerNex maintained that the power factor limit provided by EPC is intended to be used as a guideline for service-aged transformers and that it is normal for utilities to perform these tests at varying temperatures. PowerNex opined that EPC’s insulation power factor testing was Decision 25206-D01-2021 (January 18, 2021) 10
No. 1 Substation Replacement Project ENMAX Power Corporation sufficiently accurate, and based on the results, the transformer insultation is likely contaminated with high moisture content and therefore at or near end of life. 58. In addition to DGA and power factor tests, EPC also analyzed the condition of the transformers’ on-load tap changers (OLTCs), which are designed to alter the voltage output of the transformer. EPC stated that, if the transformers are not replaced, the OLTCs would have to be overhauled as the operation counts for two of the four OLTCs exceed the 100,000 operation overhaul threshold recommended by the manufacturer. A complete overhaul would be time consuming and involve safety and environmental risks. In 2017, an OLTC failure in one of the four transformers resulted in an increased reliability risk for the six months it took to repair the transformer. EPC maintained that the other three transformers are at risk of a similar failure if not overhauled or replaced. 59. The CCA disagreed that OLTC condition was an immediate concern for any of the transformers. The CCA noted that EPC did not provide test results indicating the degraded condition of the OLTCs. The CCA also noted that one of the transformers had more than three times the number of operations than the other units, and that the same transformer was the only unit for which an excitation current test was completed. Test results indicated that this most used transformer does not have any issues relating to the condition of the OLTCs and windings. Finally, the CCA concluded that it is almost always more economical to overhaul a transformer and extend its life, rather than replacing it. 60. PowerNex disagreed with the CCA’s conclusions and stated that the OLTCs are aged and are a probable future cause of transformer failure. 61. EPC submitted that all four transformers currently suffer from exterior oil leaks containing polychlorinated biphenyl concentrations ranging from 3.4 to 10 parts per million, that the leaks reflect the age of the transformers and that repairs are required to address these leaks. EPC explained that modern transformers include spill containment to prevent oil spills from contaminating the soil, but due to their age, the existing transformers do not have spill containment. EPC estimated that addressing the oil leaks would cost between $0.5 million and $0.7 million per transformer, and would introduce risks to workers and to the equipment. EPC currently manages the leaks through increased inspections and maintenance. 62. EPC stated that it has no spare transformers with the same specifications as the ones that need to be replaced. A replacement transformer would need to be ordered and require 12 to 14 months to replace. This replacement would have to be conducted while the existing transformers are energized and serving load, which poses operational and safety challenges. EPC noted other existing safety risks for personnel working on the transformers such as a lack of fixed ladders on the transformers, deluge system piping surrounding the transformers creating challenges for safe access, and pothead structures located directly in front of the transformers which creates access challenges for maintenance. 63. EPC stated that the refurbishment cost of each transformer is approximately half the cost of a new transformer, and that refurbishment would not address issues such as deteriorated insulation, which would require a complete rebuild of the transformer. 64. The CCA suggested that the risk for older transformer units can be managed by installing real time DGA monitoring equipment so that units can be taken out of service and assessed prior Decision 25206-D01-2021 (January 18, 2021) 11
No. 1 Substation Replacement Project ENMAX Power Corporation
to the occurrence of an actual internal fault. The CCA referred to both ATCO and
AltaLink Management Ltd. as examples where this approach is used. Finally, the CCA
recommended two transformer experts as candidates to assist EPC with the design and
implementation of a comprehensive condition assessment for the transformers, one of which
was the engineer from PowerNex hired by EPC.
65. PowerNex disagreed with the CCA’s suggestion to use real time DGA monitoring
equipment on the existing transformers, as that would not be a practical or cost effective solution
given the age and condition of the transformers at the substation. PowerNex estimated costs of
over $200,000 per transformer for the installation of DGA monitoring equipment, and noted that,
even then, monitoring systems do not resolve existing condition issues and do not eliminate the
risk of failure associated with internal faults. 16 PowerNex also disagreed with the CCA’s
suggestion to refurbish the transformers since as they are “too old to economically refurbish.” 17
PowerNex suggested that, although refurbishment for mid-life transformers are a practical
option, the benefits of life extension for transformers well beyond mid-life are difficult to
quantify and the costs difficult to justify.
66. PowerNex warned that the failure of one transformer creates a high risk of collateral
damage to neighbouring transformers. PowerNex calculated there to be an 83 per cent chance
that one of the four transformers at the No. 1 Substation will fail in the next 10 years and
emphasized that the transformers should be replaced as soon as possible.
Commission findings
67. The Commission finds 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 Commission acknowledges
that, while it may be true that transformers manufactured in a given era tend to be more robust
than their modern equivalents, EPC and PowerNex have provided compelling evidence
describing why the specific transformers at the No. 1 Substation may not follow this trend and
should be replaced. The Commission is 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 appears to be essentially a “run to failure” approach,
which the Commission finds imprudent for a major substation that supplies a significant portion
of downtown Calgary’s load.
68. The CCA took issue with EPC’s use of DGA and insulation power factor testing to assess
transformer condition. The Commission acknowledges that EPC’s DGA results may not be a
reliable method of testing transformer condition. However, the Commission considers that the
rising acetylene levels measured in the transformers are an additional factor in the consideration
of whether to replace the transformers. With respect to the CCA’s concern with EPC’s
methodology for conducting power factor tests, the Commission finds EPC’s testing methods to
16
Exhibit 25206-X0291.01, 2020-09-25-PNXA Rebuttal Evidence ENMAX Power Corporation Substation No. 1,
PDF pages 17 to 18.
17
Exhibit 25206-X0291.01, 2020-09-25-PNXA Rebuttal Evidence ENMAX Power Corporation Substation No. 1,
PDF page 18.
Decision 25206-D01-2021 (January 18, 2021) 12No. 1 Substation Replacement Project ENMAX Power Corporation be satisfactory and recognizes the likelihood of contaminated insulation, which indicates transformer deterioration. 69. The CCA suggested the installation of monitoring equipment as a preventative measure against transformer faults. While this is technically possible, the Commission considers the costs associated with such monitoring equipment to be impractical for transformers of this age. The CCA also stated that it is almost always more economical to overhaul a transformer and extend its life, than to replace it completely. While this may be true from an economic standpoint depending on a transformer’s age and condition and other factors, cost is not the only factor in determining whether to replace an asset. In the case of the transformers at the No. 1 Substation, there are other maintenance, safety, and operational concerns which will not completely be addressed by a refurbishment. 70. John Lackey, the transformer specialist who contributed to PowerNex’s report, worked for Westinghouse during the period that the transformers at the No. 1 Substation were manufactured. The Commission considers John Lackey’s expertise to be instrumental when it comes to the assessment of the transformers at the No. 1 Substation. 71. The Commission finds that the transformers at the No. 1 Substation are near end-of-life, likely to fail in the next five years, and therefore should be replaced. 2.3.4 Medium voltage switchgear 72. EPC explained that switchgear is composed of electrical disconnect switches, fuses or circuit breakers whose purpose is to control, protect, and isolate electrical equipment. The No. 1 Substation contains two sets of MV switchgear. A Sprecher & Schuh minimum oil-filled switchgear (minimum oil switchgear), which supplies the J and K buses, was installed in 1978 and is more than 40 years old. A Brown Boveri high speed air blast switchgear (air blast switchgear), which supplies the L bus, was installed between 1954 to 1957 and is more than 60 years old. EPC submitted that both sets of switchgear have shown asset condition and maintenance issues, resulting in operational and safety risks. 73. EPC stated that both sets of MV switchgear at the substation are obsolete and need to be replaced as they are no longer manufactured. Because of this, costly custom parts may need to be used if a replacement spare part cannot be found. EPC cautioned that an MV breaker failure would cause a prolonged outage while a replacement is made. Due to the configuration of the secondary network distribution system, an MV bus failure would result in an outage that would last until the switchgear is repaired or replaced. 74. The CCA agreed that the MV switchgear at the substation is at end-of-life condition, and that the technology in both sets of switchgear is obsolete and are less safe to operate compared to modern metal clad switchgear using vacuum breakers. The CCA acknowledged that replacement breakers and spare parts for the air blast switchgear are difficult to find, but noted that EPC had not indicated the number of spares they currently have on hand or when they forecast running out of spares. 75. EPC stated that, because breakers deteriorate slightly every time they operate, the age and high operation counts of the MV switchgear indicate that they are at a high risk of failure. Also of concern is the time it takes to open several of the breakers on the minimum oil switchgear (up to 133 per cent longer than the manufacturer specification). EPC maintained that the increased Decision 25206-D01-2021 (January 18, 2021) 13
No. 1 Substation Replacement Project ENMAX Power Corporation
time it takes to open a breaker increases the risk of longer-lasting arcs, which cause damage to
the breaker contacts, and increase the risk to personnel and the equipment that the breaker is
designed to protect. EPC also stated that the existing MV switchgear requires a much higher
level of maintenance than its modern equivalent.
76. EPC listed a number of safety risks associated with the MV switchgear including the
installation of temporary plywood barriers between each minimum oil switchgear cell to avoid
contact of personnel to exposed energized buses, inadequate working clearances and safety
barriers for personnel working on or around the air blast switchgear, and asbestos abatement
measures that must be put in place if a switchgear cell were to be modified.
77. The CCA acknowledged that, if or when EPC runs out of spare parts to maintain the air
blast switchgear lineup, a complete replacement of at least part of the switchgear would be the
most practical solution. However, the CCA maintained that EPC had not presented condition
assessments demonstrating unacceptable wear or any instance of breaker failure for the air blast
switchgear. Similarly, the CCA acknowledged that it would be reasonable for EPC to only
partially replace the minimum oil switchgear to create a pool of spares if there are no spares and
parts cannot be purchased.
78. PowerNex emphasized that, because the original equipment manufacturers for both sets
of MV switchgear have either ceased manufacturing switchgear or left the business decades ago,
replacement parts have been unavailable for decades. PowerNex did not recommend the use of
reverse engineered parts or salvaged parts due to reliability concerns and uncertainty around their
remaining life.
79. PowerNex concluded that “the CCA Technical Evidence presents an unrealistic
assessment of the condition of the [minimum oil switchgear] and fails to meaningfully consider
the relevant risks and hazards.” 18
80. PowerNex submitted that, although the minimum oil switchgear is newer than the air
blast switchgear, the probability of failure is significantly higher, and the corresponding failure
would be more catastrophic. EPC currently has two spare breaker cells for the minimum oil
switchgear. EPC noted that, once these spares are used, retrofitting the switchgear with modern
breakers is not practical.
81. PowerNex claimed that the CCA did not address the serious safety risks associated with
the current MV switchgear layout:
The obsolete … air blast switchgear layout is particularly hazardous. It is essentially an
outdoor switchyard located in a building. There are extensive bare bus systems and
disconnect switches connected to the air blast circuit breakers in semi-open cubicles with
walls of asbestos sheeting. The L bus arrangement leaves extremely limited space and
inadequate working clearances… EPC has prudently instituted ad hoc administrative
controls and modified working practices to deal with the unusually hazardous L bus
environment. These do not fully eliminate the hazards, however.
The J and K bus [minimum oil] switchgear is newer than the L bus switchgear but is still
more than four decades old. It does not fully meet the definition of metal-clad switchgear
and the layout is almost as hazardous as the L bus layout. This switchgear uses an open
18
Exhibit 25206-X0287, 2020-09-25-EPC - Reply Evidence AUC Proceeding 25206, PDF page 46.
Decision 25206-D01-2021 (January 18, 2021) 14No. 1 Substation Replacement Project ENMAX Power Corporation
bus inside the building and has exposed cable terminations. It is difficult to safely de-
energize conductors without multiple modified working practices, which cannot fully
eliminate the hazards presented by the layout of this obsolete switchgear.19
82. PowerNex concluded that, because the assessment of these risks is an important
consideration in the decision to replace obsolete and outdated equipment, both sets of MV
switchgear should be replaced within the five year timeframe proposed by EPC.
Commission findings
83. The Commission accepts that both sets of MV switchgear at the No. 1 Substation are
obsolete, have reached their end-of-life, and should be replaced.
84. 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 Commission 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. The MV switchgear is clearly in poor condition as shown by circuit
breaker operation times that are substantially longer than manufacturer specifications.
85. The Commission understands that failure in both sets of switchgear would result in high
safety risks, and that a lack of available parts would result in substantial downtime of the
switchgear while EPC acquires spare parts. The manufacturers of both sets of switchgear have
not manufactured this equipment for decades, which gives rise to extreme difficulty sourcing
readily available original manufacturer replacement parts, and a lack of original manufacturer
technical support. The Commission understands the CCA’s proposal to involve replacing the
minimum oil switchgear on one of the two buses to create a pool of spares for the other bus.
However, the Commission is not satisfied that this solution will adequately reduce existing safety
hazards for workers, particularly given PowerNex’s description that a failure of the minimum oil
switchgear would result in catastrophic effects. The CCA acknowledged the higher safety risks
associated with continued operation of the existing switchgear.
86. The Commission finds that the hazardous conditions around the MV switchgear,
particularly the bare buses, asbestos sheeting, and exposed cables must be addressed. The safety
measures EPC has implemented around the operation of the existing MV switchgear serve to
mitigate risks but are not as effective as a full replacement.
87. For these reasons, the Commission agrees that the MV switchgear in the No. 1 Substation
should be replaced in the next five years.
2.3.5 High voltage switchgear
88. EPC stated that the HV gas-insulated switchgear (GIS) at the No. 1 Substation was
installed in 1976, and that there are asset condition issues, maintenance issues, and safety risks
associated with it. EPC stated that, because the HV GIS design is obsolete, replacement parts are
expensive, difficult to obtain, or require long lead times, some greater than four to six months.
19
Exhibit 25206-X0291.01, 2020-09-25-PNXA Rebuttal Evidence ENMAX Power Corporation Substation No. 1,
PDF pages 24 to 25.
Decision 25206-D01-2021 (January 18, 2021) 15No. 1 Substation Replacement Project ENMAX Power Corporation
89. After reviewing the maintenance records and outage history, the CCA concluded that the
HV GIS is in acceptable working condition, has only experienced minor maintenance issues over
the last 10 years, and does not need to be replaced.
90. PowerNex disagreed with the CCA’s assessment of the HV GIS condition as well as its
claim that it can remain in service as long as parts remain available.
91. SF6 is used as an insulator in the HV GIS. EPC has observed SF6 leaks at the substation.
In 2018 and 2019, the HV GIS at the substation accounted for 13.4 per cent of all the SF6
released from EPC’s SF6 substation equipment (at 17.8 kilograms). EPC estimates that there are
multiple points of leakage, and that a catastrophic event could cause a major SF6 release.
92. The CCA suggested that the SF6 leaks were actually top ups that were not correctly
accounted for. The CCA maintained that, over the last 10 years, Siemens has performed leakage
tests and reported no leaks. The CCA indicated that Siemens’ last major maintenance did not
highlight any imminent risks and showed that the breakers are in good operating condition.
93. PowerNex explained that SF6 is 22,800 times more harmful to the climate than CO2 and
that it is a major contributor to climate change. PowerNex submitted that “[m]odern switchgear
standards mandate that the leakage rate from any single compartment of HV GIS to atmosphere
shall not exceed 0.5 % per year, and a state-of-the art GIS can achieve a < 0.1 % leakage rate
over its service life.” 20 PowerNex noted that the leakage rates when the existing HV GIS was
manufactured were between one per cent and two per cent, which is several times greater than
current standardized values. PowerNex calculated that the 17.8 kilograms of SF6 leaked in 2018
and 2019 is equivalent to 403.6 tonnes of CO2. PowerNex also disagreed with the CCA’s
characterization that the Siemens test results indicated a lack of imminent risks. PowerNex noted
that a Siemens maintenance report identified cracked operating rods, which PowerNex
characterized as a serious issue that can lead to catastrophic failure.
94. EPC stated that worn out contacts on some of the breakers within the HV GIS interfere
with the breakers closing, which prevents the system from operating properly. Additionally,
binding issues on the switches result in the need for one transformer and one transmission line to
be taken out of service for at least a week to replace. EPC explained that the control system for
the switches and breakers have become unreliable due to age and require field crews to bypass
the interlock system to operate. EPC further stated that the exterior compartments of the HV GIS
induce stray voltage, which creates hazards to personnel during equipment switching. EPC
currently manages this issue through signage and work practices, but suggests that an ideal
solution would be an engineered solution or replacement of the HV GIS.
95. The CCA stated that gas-insulated substations have a long track record of high reliability
and that the failure rate on a GIS breaker bay is only around one in 440 years. The CCA also
stated that event logs for the past 10 years show that the HV GIS breakers have seen very light
duty use in terms of fault interruptions and open/close requirements, with an average of only
4.2 planned open/close operations per breaker per year. In contrast, an average six line substation
with overhead lines typically experiences about 151 unplanned breaker operations in a 10 year
period. The CCA submitted that, based on operational performance, very low duty requirement,
and the fact that an HV breaker failure at No. 1 Substation would have no material risk for the
20
Exhibit 25206-X0291.01, 2020-09-25-PNXA Rebuttal Evidence ENMAX Power Corporation Substation No. 1,
PDF pages 32 to 33.
Decision 25206-D01-2021 (January 18, 2021) 16You can also read
