ATTACHMENT - DFO STATEMENT OF NEED

ATTACHMENT - DFO STATEMENT OF NEED

Table of Contents Executive Summary... 3 1. Description of the Area... 5 1.1 Geographic Study Area... 5 1.2 Current System Configuration... 7 1.3 Distributed Generation... 9 2. Equipment Ratings... 10 3. Area Loading... 11 3.1 Load Growth Development... 11 3.2 Load Forecast... 12 3.3 Customer Sites... 12 4. Distribution System Performance Standard... 14 4.1 Distribution Point of Delivery (POD) Substations... 14 5. Risk Assessment... 15 5.1 Distribution Load at Risk... 15 5.2 Customer Count Impact... 18 5.3 Load at Risk Frequency... 19 6 Alternatives... 20 6.1 Alternative 1: Do Nothing... 20 6.2 Alternative 2: Add Distribution System Capacity... 20 6.3 Alternative 3: Install Second Autotransformer (Spare) at No.21 Sub... 21 6.4 Alternative 4: Upgrade 36.5TR (Spare)... 22 6.5 Alternative 5: Install New 36.5TR Autotransformer... 23 7 Capital Cost Estimates... 24 7.1 Alternative 1: Do Nothing... 24 7.2 Alternative 2: Add Distribution System Capacity... 24 7.3 Alternative 3: Install Second Autotransformer (Spare) at No.21 Sub... 24 7.4 Alternative 4: Upgrade 36.5TR (Spare)... 24 7.5 Alternative 5: Install New 36.5TR Auto... 25 8 Proposed System Development Preferred Alternative 4... 26 9 Load-at-Risk Preferred Alternative 4 Implemented... 28 10 In-Service Date... 28 2

Executive Summary ENMAX Power Corporation (EPC) Distribution Facility Owner (DFO), in its capacity as the legal owner of the electric distribution system, is submitting a request for system access service to the Alberta Electric System Operator (AESO). The request for system access service includes a request for upgrades at EPC No. 36 substation in order to satisfy ENMAX DFO Distribution System Performance Standard. At the present time, there is no request for change to the current Demand Transmission Service (DTS) contract at No. 36 Substation as part of the request for system access. The North 69 kv Subsystem supplies distribution commercial, institutional and residential communities in northwest Calgary, including major distribution customers such as Alberta Children s Hospital, the University of Calgary, LRT stations, Market Mall and the Foothills Medical Centre (refer to Figure 1 for North 69 kv Subsystem distribution customer geographic area). For purposes of obtaining transmission maintenance outages in the North 69 kv Subsystem, radial transmission reconfigurations (resulting in four radially supplied substations) and distribution load transfers are required due to subsystem overloads under the next contingency. ENMAX DFO has identified that these transmission reconfigurations and distribution load transfers result in more than two radially fed substations and an increased risk of prolonged distribution outages (distribution customer load at risk) in the event of the next transmission or distribution contingency. Based on 2016 customer site counts, planned and unplanned outages on in-feed autotransformers and transmission lines supplying the North 69 kv Subsystem distribution POD substations will place roughly 28,313 metered distribution customer sites at risk of a prolonged outage. The worst case North 69 kv Subsystem radial transmission reconfigurations, shown in Figure 3, result in a customer load at risk that cannot be restored in the event of the next autotransformer or transmission line outage. In 2016, the worst case load at risk was found to be 23 MVA 1, with the 10 year forecasted load at risk increasing to 25 MVA. Presently, the Distribution Point of Delivery substations in the North 69 kv Subsystem do not meet the EPC Distribution System Performance standard pertaining to the planning and operation of a reliable distribution system when performing maintenance activities on the transmission system: Distribution Point of Delivery (POD) substations shall be planned, designed and operated to ensure no more than two POD substations are supplied radially as a result of a planned transmission circuit or autotransformer outage 2. Pre-system reconfigurations that require distribution load transfers to alleviate transmission system overloads are not acceptable due to the increased customer outage risk under the next distribution contingency. Remedial Action Schemes (RAS) that involve customer load shedding to alleviate transmission system overloads are not acceptable. 1 Combined No. 15 Sub and No. 34 Sub load at risk. 2 Three or more POD Substations supplied by separate radial configurations are considered a violation of condition. 3

ENMAX DFO has considered implementing changes and additions to the existing distribution infrastructure and found the distribution alternatives to be in violation of the EPC Distribution System Performance Standard, cost prohibitive and unable to address the identified deficiency. As a result, ENMAX DFO, in consultation with the ENMAX Transmission Facility Owner (TFO), explored alternatives that will address the DFO reliability requirements. The preferred Alternative 4 involves the upgrade of the autotransformer at No.36 Substation (36.5TR) and is the most viable and cost effective engineering solution to address the Distribution System Performance violation. Upon implementation of Alternative 4, performing in-feed autotransformer and transmission line maintenance outages that supply the North 69 kv Subsystem POD substations will no longer need transmission reconfigurations that create a load at risk to distribution customers and increase their exposure to prolonged outages. The estimated capital cost for the preferred Alternative 4 is $1.9M (+/- 30%), including Interest During Construction (IDC) and Administrative Overhead (AOH), with a requested in-service date of Q4 2018. 4

1. Description of the Area 1.1 Geographic Study Area The North 69 kv Subsystem comprises the 138-69 kv autotransformers 36.5TR at No. 36 Sub, 13.4TR at No. 13 Sub and 21.4TR at No. 21 Sub, which are the three supply sources to the North 69 kv transmission facilities supplying the 69-13.8 kv Point of Delivery (POD) No. 15, 16, 27, and 34 Substations. The POD substations serve the distribution 13.8 kv facilities supplying load in the following commercial and residential communities: Banff Trail Bowness Brentwood Cambrian Heights Capitol Hill Charleswood Collingwood Dalhousie Highland Park Highwood Huntington Hills Montgomery Major distribution customers include: Mount Pleasant North Haven North Haven Upper Nose Hill Park Parkdale Point McKay Rosemont Silversprings Thorncliffe University District Varsity Alberta Children s Hospital Foothills Medical Centre Four Calgary Light Rail Transit (LRT) traction power substations: Dalhousie, Northland, Brentwood, University University of Calgary Market Mall The North 69 kv Subsystem Distribution Customer Load Area is shown in Figure 1. 5

DALHOUSIE LRT SUB 16.63L 16.61L NORTHLAND LRT SUB BRENTWOOD LRT SUB 13.60L MARKET MALL 15.62L 16.60L 16.60L ALBERTA CHILDREN S HOSPITAL 21.61L UNIVERSITY LRT SUB FOOTHILLS MEDICAL CENTRE 15.60L 21.61L Figure 1: North 69 kv Subsystem Distribution Customer Load Area 6

1.2 Current System Configuration The North 69 kv Subsystem is supplied from three in-feed sources at No. 13, No. 21 and No. 36 Substations through the following 138-69 kv step-down autotransformers: 13.4TR 112 MVA (located at No.13 Substation) 21.4TR 112 MVA (located at No.21 Substation) 36.5TR 50 MVA (located at No.36 Substation) These sources supply a network of seven 69 kv transmission lines: 13.60L 15.60L 15.62L 16.60L 16.61L 16.63L 21.61L These sources and transmission lines further supply four 69-13.8 kv Point of Delivery substations to support the local area distribution load (refer to Figure 1 for geographic representation of distribution load area). The four 69-13.8 kv POD Substations are: No.15 Substation No.16 Substation No.27 Substation No.34 Substation Figure 2 depicts the in-feed sources and the transmission lines supplying the North 69 kv POD substations as well as the POD substations in the North 69 kv Subsystem that supply the 13.8 kv distribution customer load. 7

Figure 2: North 69 kv Subsystem 16.63L 16.61L 13.60L 36 16 27 13 36.5TR 50 MVA 15.62L 16.60L 13.4TR 112 MVA 15 34 15.60L 21.61L LEGEND 138 kv 21.4TR 112 MVA 69 kv Substation 21 138/69 kv Autotransformer 8

1.3 Distributed Generation POD No. 34 Substation supplies the load of University of Calgary. In addition to consuming load, the University of Calgary (U of C) has a 15 MW cogeneration plant 1 connected to the ENMAX distribution system. Depending on time of day load demand at University of Calgary, the U of C cogeneration plant may backfeed onto the ENMAX distribution system. Historical performance of U of C cogeneration plant indicates that the plant may be shut down for maintenance for prolonged periods at various times throughout the year. For the purposes of the distribution load at risk assessment in section 5.1, the cogeneration plant is assumed to be off in the study. As well, the coincident load forecast for the North 69 kv Subsystem (refer to Section 3.2) does not incorporate the generation from U of C as it is not considered a reliable generation supply. 1 https://ucalgary.ca/facilities/buildings/central-heating-cooling-plant 9

2. Equipment Ratings The summer and winter ratings of the major transmission equipment identified in Section 1.2 are outlined in Table 1. These ratings, provided by ENMAX TFO, define the operating limits of major equipment in the North 69 kv Subsystem. In addition, each transmission line has an approved 10-minute emergency rating at which the equipment can be operated, also shown in Table 1. If equipment is overloaded during an emergency event, ENMAX Operators will take immediate action to reduce the loading below normal equipment ratings. Autotransformers do not have an approved emergency rating and can only be operated to the manufacturer nameplate rating. Equipment Table 1: North 69 kv Subsystem Major Transmission Equipment Ratings Nominal Voltage (kv) Summer Normal Rating (MVA) Winter Normal Rating (MVA) Summer Emergency Rating (MVA) 1 Winter Emergency Rating (MVA) 2 13.4TR 138-69 112 112 NA NA 21.4TR 138-69 112 112 NA NA 36.5TR 138-69 50 50 NA NA 13.60L 69 72 72 73 79 15.60L 69 72 72 79 79 15.62L 69 72 72 79 79 16.60L 69 72 72 79 79 16.61L 69 72 72 79 79 16.63L 69 72 72 79 79 21.61L 69 72 72 79 79 1 Emergency ratings are available for up to 30 minutes. 2 Emergency ratings are available for up to 30 minutes. 10

3. Area Loading The 2011 to 2017 actual coincident loading in the North 69 kv Subsystem is shown in the table below. Sub 15 16 27 34 Total 1 Peak Season S W S W S W S W S W Table 2: North 69 kv System POD Coincident Peak Load Actuals (MVA) Power Actual Load (MVA) Factor 0.959 21 21 22 19 19 20 20 2011 2012 2013 2014 2015 2016 2017 0.976 21 21 21 21 20 19 19 0.966 19 19 18 18 18 18 18 0.978 23 23 23 23 22 21 20 0.932 14 14 14 13 12 13 14 0.944 22 22 22 22 20 19 20 0.934 37 36 37 31 34 33 35 0.934 35 35 34 34 30 28 30 N/A 91 91 91 82 84 85 87 N/A 90 90 89 90 86 87 89 3.1 Load Growth Development The major subdivision developments and the associated distribution load growth for the next 20 years are listed in Table 3. The load growth shown below has been integrated into the overall area load forecast, shown in Table 5, but at a coincident level. Table 3: North 69 kv Subsystem Major Area Anticipated Load Additions (2017-2035) Description of New Load Addition Substation Forecasted Load (MVA) Northland Village Redevelopment 16 4 University District (West Campus) 34 20 Brentwood Redevelopment 34 8 Montgomery/Bowness Redevelopment 15 5 Major Institutions Upgrade 15/34 15 Total Area Load Growth (Non-Coincident) 52 1 Totals influenced by rounding. 11

3.2 Load Forecast The load forecast for the 69-13.8 kv POD substations No.15, 16, 27 and 34 in the North 69 kv Subsystem is shown in Table 5. 3.3 Customer Sites The North 69 kv Subsystem supplies roughly 28,313 metered distribution customer sites. A detailed customer site breakdown by substation is shown in Table 4. Table 4: North 69 kv Subsystem Total Distribution Customer Count Breakdown Substation Number of Metered Customer Sites 1 15 4,078 16 8,995 27 10,350 34 4,890 Total 28,313 The University of Calgary (supplied from 34 Sub) which supports roughly 33,400 students and staff, consists of only a few metered sites in the total distribution customer count. Distribution customer counts are based on the total number of metered sites even though some large institutions or commercial operations might service multiple floors or buildings. 1 Total North 69 kv Subsystem metered customer sites as of 2016. 12

Table 5: North 69 kv System POD Coincident Peak Load Forecast (MVA) Sub 15 16 27 34 Total 1 Peak Season Power Factor Forecast Load (MVA) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 S 0.959 20 20 21 21 21 21 21 21 21 21 21 W 0.977 18 19 19 19 19 19 19 19 19 19 20 S 0.949 19 19 19 19 19 19 19 19 19 19 20 W 0.972 22 22 22 22 22 22 22 22 22 22 22 S 0.956 14 14 14 14 14 14 14 14 14 14 14 W 0.960 21 21 21 21 21 21 21 21 21 21 21 S 0.940 33 34 34 35 35 36 37 38 39 40 40 W 0.940 31 31 32 33 33 34 35 35 36 37 38 S 86 88 88 89 89 90 91 92 93 94 95 W 92 92 94 95 95 96 97 97 98 99 101 M 2 65 66 66 67 67 68 68 69 70 71 71 1 Totals influenced by rounding. 2 Maintenance season considered to be 75% of summer peak. 13

4. Distribution System Performance Standard The purpose of the EPC Distribution System Performance Standard EPC-ARBP-DSP-ST-0001 is to ensure that a reliable distribution system is planned and can be operated to meet specific performance and customer reliability requirements. The applicable section of the EPC Distribution System Performance Standard is shown below and it pertains to the planning and operation of a reliable distribution system when performing maintenance activities on the transmission system. 4.1 Distribution Point of Delivery (POD) Substations Distribution Point of Delivery (POD) substations shall be planned, designed and operated to ensure no more than two POD substations are supplied radially as a result of a planned transmission circuit or autotransformer outage 1. Pre-system reconfigurations that require distribution load transfers to alleviate transmission system overloads are not acceptable due to the increased customer outage risk under the next distribution contingency. Remedial Action Schemes (RAS) that involve customer load shedding to alleviate transmission system overloads are not acceptable. 1 Three or more POD Substations supplied by separate radial configurations are considered a violation of condition. 14

5. Risk Assessment The risk assessment explores a typical North 69 kv reconfiguration when ENMAX TFO is performing maintenance activities on 13.60L or 13.4TR. The impacts of the next contingency occurring when performing transmission maintenance activities and its resulting distribution capacity deficiency, the number of customers impacted and the frequency of these reconfigurations occurring were studied. The results of these studies are summarized in this section. Based on Table 5, under the planned outage on 13.4TR followed by the next Category B Outage on 21.4TR (N-1-1), 36.5 TR will be the only supply for the North 69 kv Subsystem. It is anticipated that the power flow on 36.5TR would exceed the transformer rating under this N- 1-1 event. In this N-1-1 event, ENMAX forecasts that there will be 15 MVA of load at risk in 2018 increasing to 21 MVA of load at risk in 2028. 5.1 Distribution Load at Risk ENMAX TFO typically schedules transmission maintenance activities in two week periods where the system loading averages 75% of the summer coincident peak loading level. A typical reconfiguration of the North 69 kv Subsystem is shown in figure 3 and occurs when ENMAX TFO performs maintenance activities on 13.60L transmission line or 13.4TR autotransformer resulting in four radially fed substations, with two substations No. 16 and No. 27 Sub supplied radially via 16.63L transmission line and fed via single element 36.5TR autotransformer at No. 36 Substation, and the other two substations No. 15 and No. 34 Sub are supplied radially via a single element 21.4TR autotransformer from No. 21 Substation. The four radially supplied substations resulting from the transmission radial reconfigurations of the North 69 kv Subsystem during an N-1 maintenance outage are in violation of the EPC Distribution System Performance Standard (refer to Section 4.1), which requires no more than two radially fed POD substations as a result of a transmission maintenance outage. The ENMAX distribution system is planned and built with POD transformer and feeder capacity to sustain a single N-1 POD transformer or feeder loss. An N-1-1 transmission loss on the North 69 kv subsystem results in the loss of multiple substations, which the distribution system cannot back up. The following distribution capacity study is provided to the AESO to highlight the capacity deficiency the distribution system will have under an N-1-1 transmission contingency and is for information only. A distribution capacity study was performed on this typical reconfiguration to assess the impacts of the next transmission contingency resulting in multiple POD substations losing supply. 15

Figure 3: Radial Configuration for a 13.60L or 13.4TR Outage 16.63L 16.61L 13.60L 36 16 27 13 36.5TR 15.62L 16.60L 13.4TR 15 34 15.60L 21.61L LEGEND Out of Service Element 138 kv 21.4TR 21 69 kv Substation 138/69 kv Autotransformer In the event of the next N-1-1 transmission contingency occurring during a planned N-1 North 69 kv maintenance outage, there exists distribution customer load that cannot be restored without customers experiencing a prolonged outage. This is defined as Load at Risk (LAR) and it is the distribution customer load (MVA) that cannot be returned to service until the North 69 kv transmission system is returned to an N-1 state. Total tie-away capacity is defined as the maximum distribution capacity available to effectively transfer load should an entire Point of Delivery Substation incur a loss of supply. 15 + 34 Sub Combined Loading 15+34 Sub Total Tie Away Capacity (Adjacent Feeders outside of North 69 kv Subsystem) 15+34 Sub Load at Risk Table 7: Distribution Load at Risk (MVA) Impacts During a 13.60L or 13.4TR Outage Season* 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 M 45 45 45 45 46 47 48 48 49 50 50 M 22 22 22 22 23 23 23 24 24 25 25 M 23 23 23 23 24 24 24 25 25 25 25 Season* 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 16 + 27 POD Combined Loading M 29 29 29 29 29 29 29 29 30 30 30 16+27 Sub Total Tie Away Capacity (Adjacent Feeders outside of North M 22 22 22 22 22 22 22 23 23 23 23 69 kv Subsystem) 16+27 Sub Load at Risk M 6 6 6 7 7 7 7 7 7 7 7 * Maintenance (M) season is considered 75% of loading of North 69kV Subsystem summer coincident peak 16

Although Table 7 shows a large amount of available Total Tie-Away Capacity, from operational point of view, it is not practical to transfer that magnitude of load through switching due to the following reasons: - Large number of feeders impacted and switching required for the load transfer, causing increased safety risk to ENMAX field staff performing live line work; - Large number of feeders, therefore customers experiencing abnormal state of supply resulting in inability to restore customer services should a distribution outage occur; - Uncertainty of the availability of the feeder tie-away capacity due to construction work, maintenance work or unplanned outages on the feeders, resulting in more customer load at risk With expected load growth in the study area of 52MVA over the next twenty years, the impact of the next N-1-1 transmission contingency to customers supplied from North 69 kv Subsystem will only worsen. Typical reconfigurations required to obtain North 69 kv Subsystem maintenance outages place four substations on radial transmission supply placing customers at risk of experiencing outages under the next transmission system contingency. These reconfigurations are in violation of the EPC Distribution System Performance Standard (refer to Section 4.1). The following section correlates the distribution load at risk to the number of customers that will experience prolonged outages as a result of the next contingency. 17

5.2 Customer Count Impact Further to the risk assessment study in 5.1, an assessment was done to quantify the number of customers impacted as a result of the next transmission contingency (N-1-1) occurring on the radially reconfigured North 69 kv Subsystem during an N-1 13.4TR or 13.60L maintenance outage (refer to Fig 4 for radial reconfiguration). The resulting customer outage impacts, represented by the number of metered sites, are shown in Table 8. Table 8: (N-1-1) Contingency impacts during a planned (N-1) 13.60L or 13.4TR maintenance outage Contingency N-1-1 Sub(s) Impacted Load Loss (MVA) 1 Number of Metered Sites 2 16.61L 27 10 10,350 21.4TR 15, 34 41 8,968 15.60L 15 15 4,078 16.63L or 36.5TR 16, 27 24 19,345 - LRT 21.61L 34 26 4,890 Major Customers - Primarily residential - LRT - University of Calgary - Market Mall - LRT - Alberta Children s Hospital (main feeder) - Foothills Hospital (alternate feeder) - University of Calgary - Market Mall - Alberta Children s Hospital (main feeder) - University of Calgary - Market Mall - LRT Notes - Risk exists regardless of radial configuration - Restoration of 15.62L to 15 Sub possible - Restoration of 16.60L to 34 Sub not possible due to 36.5TR capacity constraints - University of Calgary accommodates approx. 33,400 students and staff daily - University of Calgary accommodates approx. 33,400 students and staff daily - Restoration of 15.62L and 16.60L to 16 Sub and 27 Sub possible - University of Calgary accommodates approx. 33,400 students and staff daily 1 Based on 2017 substation maintenance loading levels (75% of 2017 actual substation summer peak load). 2 Total North 69 kv Subsystem metered customer sites as of 2016. 18

5.3 Load at Risk Frequency In order to adequately maintain equipment in the North 69 kv Subsystem, outages on elements 13.4TR, 21.4TR, 36.5TR, 13.60L, 15.60L, 15.62L, 16.60L, 16.61L, 16.63L and 21.61L are routinely required. Maintenance outages can range in duration from one day to several weeks and include: Line and substation washing Breaker inspections Switch maintenance Motorized Disconnect (MD) maintenance Transformer and surge arrestor testing Based on existing loading levels in the North 69 kv Subsystem, planned outages are not possible for the majority of regular maintenance activities without implementing radial reconfigurations. Furthermore, the North 69 kv Subsystem has experienced an increased number of unplanned outages mainly due to equipment failures. These unplanned outages include cable, pothead, transformer and pole failures which require extended emergency outages to replace the failed equipment. As EPC proactively plans to replace the aging assets, longer duration outages will be required. EPC is currently evaluating pole and framing replacements on 16.63L, and a full rebuild of 16.61L. Construction schedules for these capital replacement activities can take several months and will require implementation of radial configurations to accommodate these longer duration outages, consequently increasing the reliability risk to EPC customers in the North 69 kv Subsystem. 19

6 Alternatives The existing transmission system configuration in the study area is presently unable to meet the EPC Distribution System Performance Standard (refer to section 4.1). In consultation with the ENMAX TFO, ENMAX DFO has explored alternatives and their abilities to resolve the identified system deficiency of having more than two POD substations supplied radially during a planned transmission circuit or autotransformer outage. 6.1 Alternative 1: Do Nothing This alternative involves leaving the North 69 kv Subsystem as currently configured without performing any capacity upgrades to mitigate the reliability risk. This alternative was dismissed for the following reasons: Existing North 69 kv Subsystem infrastructure cannot support maintenance outage requirements due to the distribution load at risk in the event of the next transmission contingency. Radial configurations during maintenance activities, as outlined in Section 4.1, will still be required, thus increasing the reliability risk to EPC customers and would be in violation of EPC Distribution System Performance Standard. 6.2 Alternative 2: Add Distribution System Capacity This alternative is provided for information only as it does not meet the EPC Distribution System Performance Standard. The alternative involves installing additional substation transformer and distribution breaker capacity at No. 14 and 20 Substations and adding new 13kV distribution feeders to be utilized for backup during substation contingencies in the North 69 kv Subsystem. This alternative was dismissed as it does not meet the EPC Distribution System Performance Standard. 20

6.3 Alternative 3: Install Second Autotransformer (Spare) at No.21 Sub This alternative involves installing a second 75/100/112 MVA, 69/138 kv autotransformer at No.21 Substation using a spare unit, installation of bus tie breakers on the 138 kv and 69 kv buses. This alternative will eliminate the need to reconfigure the North 69 kv Subsystem into a radial configuration, therefore mitigating the violation of the EPC Distribution System Performance Standard. Bus-tie breakers will also be required on the 69 kv and 138 kv busses in order to isolate the transformers during a transformer or bus fault event. Advantages: Radial configurations during maintenance activities, as outlined in Section 4.1, will no longer be required, thus reducing the reliability risk to EPC customers. Distribution load transfers to alleviate potential transmission system overloads (which are in violation of the EPC Distribution System Performance Standard) will no longer be required. Provides operational maintenance flexibility during peak loading periods. Utilization of an existing spare 75/100/112 MVA, 69/138 kv autotransformer reduces the cost of the upgrade. Alleviates immediate North 69 kv Subsystem capacity constraints during N-1-1 events and ensures compliance with EPC Distribution System Performance Standard. Disadvantages: Spare autotransformer at risk of requiring replacement due to age (42 years old). High cost alternative. This alternative is technically acceptable, but it was dismissed due to it being the highest cost alternative with marginal advantages it provides over Alternative 4. 21

6.4 Alternative 4: Upgrade 36.5TR (Spare) This alternative involves upgrading 36.5TR autotransformer to a capacity of 75/100/112 MVA using a spare unit. This alternative will eliminate the need to reconfigure the North 69 kv Subsystem into a radial configuration, therefore mitigating the violation of the EPC Distribution System Performance Standard. Advantages: Radial configurations during maintenance activities, as outlined in Section 4.1, will no longer be required, thus reducing the reliability risk to EPC customers. Distribution load transfers to alleviate potential transmission system overloads (which are in violation of the EPC Distribution System Performance Standard) will no longer be required. Alleviates immediate North 69 kv Subsystem capacity constraints during N-1-1 events and ensures compliance with the EPC Distribution System Performance Standard. Aligns with the EPC strategy for the North 69kV Subsystem. Lowest cost alternative. Disadvantages: Spare autotransformer at risk of requiring replacement due to age (42 years old). The spare autotransformer in Alternative 4 is a 42 year old unit, with 36 years in service. It was last rebuilt and rewound in 1993. As such, the unit is in serviceable condition, with minimal risk of failure. Alternative 4 is the preferred alternative as it provides a cost-effective solution to address the identified North 69 kv Subsystem deficiencies. 22

6.5 Alternative 5: Install New 36.5TR Autotransformer This alternative involves upgrading 36.5TR autotransformer to capacity of 75/100/112 MVA with a new transformer. This alternative will eliminate the need to reconfigure the North 69 kv Subsystem into a radial configuration, therefore mitigating the violation of the EPC Distribution System Performance Standard. Advantages: Radial configurations during maintenance activities, as outlined in Section 4.1, will no longer be required, thus reducing the reliability risk to EPC customers. Distribution load transfers to alleviate potential transmission system overloads (which are in violation of the EPC Distribution System Performance Standard) will no longer be required Alleviates immediate North 69 kv Subsystem capacity constraints during N-1-1 events and ensures compliance with the EPC Distribution System Performance Standard. Aligns with the EPC strategy for the North 69kV Subsystem. Disadvantages: Costlier than the preferred Alternative 4, as it requires a new autotransformer. Alternative 5 was dismissed due to higher cost than Alternative 4. This alternative would have the same impact on the North 69 kv Subsystem during an N-1-1 event, as alternative 4. 23

7 Capital Cost Estimates Alternative cost estimates were prepared in consultation with ENMAX TFO and discussed in further detail in the following sections. Alternative estimates are based on +/-30% accuracy and include IDC and AOH, except for Alternative 2 estimate which was limited to +/-50% accuracy due to not meeting the EPC Distribution System Performance Standard (refer to Section 4.1) and excessive costs relative to other alternatives. 7.1 Alternative 1: Do Nothing There were no capital cost estimates prepared for Alternative 1 as this option does not address the North 69 kv Subsystem deficiencies. 7.2 Alternative 2: Add Distribution System Capacity There is no estimate provided for this alternative as it does not meet the EPC Distribution System Performance Standard (refer to Section 4.1). 7.3 Alternative 3: Install Second Autotransformer (Spare) at No.21 Sub Project Details Capital Cost Estimate (+/- 30%) Transmission: Upgrade substation equipment at No.21 Substation with the addition of a second 75/100/112 MVA 138-69 kv autotransformer using a spare unit and new bus-tie breakers on the 69 kv and 138 kv busses. $8.4M Distribution: $0 Total: $8.4M 7.4 Alternative 4: Upgrade 36.5TR (Spare) Project Details Transmission: Upgrade substation equipment at No.36 Substation with the replacement of existing 36.5TR with a 75/100/112 MVA 138-69 kv autotransformer using a spare unit. Capital Cost Estimate (+/- 30%) $1.9M Distribution: $0 Total: $1.9M 24

7.5 Alternative 5: Install New 36.5TR Auto Project Details Transmission: Upgrade substation equipment at No.36 Substation with the replacement of existing 36.5TR with a new 75/100/112 MVA autotransformer. Capital Cost Estimate (+/- 30%) $3.9M Distribution: $0 Total: $3.9M 25

8 Proposed System Development Preferred Alternative 4 The preferred solution, Alternative 4, involves upgrading the existing 50 MVA, 69/138 kv autotransformer at No. 36 Substation (36.5TR) using a spare 75/100/112 MVA, 69/138 kv autotransformer. The existing No. 36 Substation configuration is shown in Figure 9 with the proposed development additions shown in Figure 10. This alternative will eliminate the need to reconfigure the North 69 kv Subsystem into a radial configuration, therefore mitigating the identified violation of the EPC Distribution System Performance Standard. The requested in service date for the proposed system development of the North 69 kv Subsystem upgrade is Q4 2018. In the interim, EPC customers will be taking increased risk during planned and unplanned outages. The estimated capital cost of the proposed system development is $1.9M (+/- 30%), including IDC and AOH. 26

Figure 4: No.36 Substation Existing Configuration Legend Existing To 16 Sub 16.63L Bus Line Dist. Feeder Switch Motor. Disc. 69 kv 36.5TR 37.5/50 MVA Breaker Transformer To 7 Sub 7.84L To 14 Sub 14.83L 138 kv To Bearspaw 36.81L 36.2TR 18/24/30 MVA 22.5 MVA 36.1TR 20/27/33.6 MVA 36.3TR 30/40/50 MVA 25 kv To GIS 13.8 kv 13.8 kv 8-36.18 8-36.17 8-36.16 8-36.15 8-36.14 8-36.13 8-36.12 Figure 5: Proposed No. 36 Substation Preferred Configuration (Alternative 4) Legend Proposed Existing To 16 Sub 16.63L Bus Line Dist. Feeder Switch Motor. Disc. 69 kv 36.5TR 75/100/112 MVA Breaker Transformer To 7 Sub 7.84L To 14 Sub 14.83L 138 kv To Bearspaw 36.81L 36.2TR 18/24/30 MVA 22.5 MVA 36.1TR 20/27/33.6 MVA 36.3TR 30/40/50 MVA 25 kv To GIS 13.8 kv 13.8 kv 8-36.18 8-36.17 8-36.16 8-36.15 8-36.14 8-36.13 8-36.12 27

9 Load-at-Risk Preferred Alternative 4 Implemented The preferred alternative eliminates the need to place more than two POD substations in a radial configuration and is therefore in compliance with the EPC Distribution System Performance Standard. As a result, an N-1-1 transmission contingency does not result in multiple POD substations losing supply. If the North 69 kv Subsystem substations do not lose supply, then there is also no load at risk, as the POD substations themselves remain in normal operating condition and are able to supply load with no customer disruption. Table 9: Distribution Load at Risk (MVA) Impacts During a 13.60L or 13.4TR Outage 15 + 34 Sub Combined Loading 15+34 Sub Total Tie Away (Adjacent Feeders outside of North 69 kv Subsystem) 15+34 Sub Load at Risk Season* 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 M 45 45 45 45 46 47 48 48 49 50 50 M 22 22 22 Not applicable as the DFO standard is met and the Load at Risk is mitigated M 23 23 23 0 0 0 0 0 0 0 0 16 + 27 POD Combined Loading 16+27 Sub Total Tie Away (Adjacent Feeders outside of North 69 kv Subsystem) 16+27 Sub Load at Risk Season* 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 M 29 29 29 29 29 29 29 29 30 30 30 M 22 22 22 Not applicable as the DFO standard is met and the Load at Risk is mitigated M 6 6 6 0 0 0 0 0 0 0 0 * Maintenance (M) season is considered 75% of loading of North 69kV Subsystem summer coincident peak 10 In-Service Date The requested in service date for the upgrade of the existing autotransformer at No. 36 Substation is Q4 2018. At the present time, there is no request for change to the current Demand Transmission Service (DTS) contract at No. 36 Substation. 28