Service Requested 150 MW, Firm. Table ES.1: Summary Details for TSR #

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2 Executive Summary Firm point to point transmission service has been requested by Transmission Service Request (TSR) # , under the SaskPower Open Access Transmission Tariff (OATT). The TSR consists of a request for 150 MW firm transmission service from the McNeill HVDC Converter Station, located at the Alberta terminal of the Swift Current to McNeill (S1M) 230 kv transmission line, to SaskPower (SPC) load. The details of TSR # are summarized in Table ES.1. SPC TSR # Point of Receipt Point of Delivery AB.SK.MC SPC Service Requested 150 MW, Firm Start Time Stop Time Queue Date :00:00 CS :00:00 CS :52:29 CS Table ES.1: Summary Details for TSR # A System Impact Study was conducted to assess the impacts of TSR # on the SaskPower transmission system, and to determine if facilities are required to provide the requested firm transmission service for TSR # The TSR point of delivery (POD) was identified as SaskPower (SPC) and a specific load sink was not designated, which effectively represents network service rather than point to point service. As such, the point of delivery for the TSR was not modeled at a specific POD in the SPC system. When assessing the TSR, 150 MW of Alberta to Saskatchewan transfer was modeled through the McNeill back-to-back converter station. To account for no designated load sink, generation within the SPC system was redispatched to account for the McNeill transfer. Therefore the actual point of delivery was dependent on the case and varied based on the SPC system re-dispatch. ES.1 SPC System Facilities Required Due to TSR # A summary of the SPC system facilities required due to TSR # is shown in Table ES.2. If the SPC facilities in Table ES.2 are not in-service, firm service for TSR # cannot be provided under the OATT. The SPC system facilities identified as mitigation in Table ES.2 are considered to be network upgrades and are not direct assignment facilities. System re-dispatch may be an alternative to the system facilities identified in Table ES.2. The feasibility and cost of system re-dispatch can be assessed if TSR # proceeds to a Facilities Study. i

3 TSR # Transfer Level SPC System Facilities Required Due to TSR # Potential Construction Time Estimated Cost of Identified SPC Facilities (x1,000) Full Service (150 MW Alberta to Saskatchewan through McNeill Station) Replace disconnect switches at Poplar River and Condie switching stations. Up to 1 year after customer commitment to TSR. $400 Table ES.2: Facilities Required in SPC System Due to TSR # The in-service dates and costs for the facilities identified in Table ES.2 will be confirmed if the TSR proceeds to a Facilities Study. Prior to providing firm service for TSR # under the OATT, system upgrades are also required to address some pre-tsr SPC system issues, as some facilities required for pre-tsr issues on the SPC system directly impact the transfer capability of TSR # These facilities are discussed in Section ES.2.1. Full or partial firm service for TSR # cannot be provided under the OATT until these upgrades for pre- TSR SPC system issues that directly impact the transfer capability of TSR # are in-service. These pre-tsr SPC system upgrades are not shown in Table ES.2. The cost for these pre-tsr SPC system upgrades are not currently allocated to TSR # ES.2 Other Considerations ES.2.1 Facilities Required for Pre-TSR Issues in SPC System that Directly Impact Transfer Capability of TSR # Shown in Table ES.3 are future SPC transmission facilities required for pre-tsr issues on the SPC system that directly impact the transfer capability of TSR # Firm service for TSR # cannot be provided under the OATT until the transmission facilities of Table ES.3 are in-service. The in-service dates in Table ES.3 will be confirmed if the TSR proceeds to a Facilities Study. ii

4 Facilities Current Targeted In-Service Date Project Status Replace disconnect switch at Regina South switching station. Q Planned Remove wavetraps at Poplar River, Condie, Coteau Creek, and Swift Current switching stations. Q Planned Construction of new Pasqua to Swift Current 230 kv line. Q Planned Rebuild of Pasqua to Chaplin (P1C) 138 kv line and Swift Current to Chaplin (S1C) 138 kv line. Q Planned Construction of new Regina to Pasqua 230 kv line. Approximately Q Conceptual Construction of new Rowatt 230 kv switching station Approximately Q Conceptual Table ES.3: Planned and Conceptual SPC Transmission Facilities Shown to Impact the Transfer Capability of TSR # The construction of a new Regina to Pasqua 230 kv line and the construction of a new Rowatt 230 kv switching station (both shown in Table ES.3) are conceptual projects and have not yet been fully committed to by SPC. The Regina to Pasqua 230 kv line and the Rowatt 230 kv station are required for firm service to be provided to TSR # If SPC does not commit to proceeding with the Regina to Pasqua 230 kv line or the Rowatt 230 kv switching station, their cost will be allocated to TSR # The estimated cost for a new Regina to Pasqua 230 kv line is approximately $100 million, and the estimated cost for a new Rowatt 230 kv switching station is approximately $30M. The in-service date and cost allocation for these projects will be assessed if TSR # proceeds to a Facilities Study. ES.2.2 Facilities Required for Pre-TSR Issues in SPC System that Do Not Significantly Impact the Transfer Capability of TSR # In addition to the facilities of Table ES.3, other facilities that do not significantly impact the transfer capability of TSR # are required for pre-tsr issues on the SPC system. These facilities are not scheduled to be in-service until Q at the earliest. Given that these facilities do not significantly impact the transfer capability of TSR # , it is not expected that firm service for TSR # will be impacted if these facilities are not in-service when service for TSR # is granted. However, prior to these additional facilities being inservice, there could still be infrequent conditions in which curtailment of TSR # in the form of transmission loading relief (TLR) is required to address system conditions unrelated to the TSR. iii

5 ES.2.3 Requested Start Date and Rollover Potential for TSR # The requested start date for TSR # is Jan 1, 2012, with a time period of five years. Prior to providing firm service for TSR # under the OATT, facilities required for pre-tsr issues on the SPC system that directly impact the transfer capability of TSR # must be in-service (see Table ES.3). These required facilities are not scheduled to be in-service until Q at the earliest. Based on this schedule, it is estimated that firm service for TSR # cannot be provided under the OATT until approximately Q The potential in-service date for these facilities will be determined if TSR # proceeds to a Facilities Study. As the facilities of Table ES.3 address pre-tsr system issues that occur prior to TSR # , no amount of partial firm service for TSR # can be provided under the OATT prior to implementing the system upgrades shown in Table ES.3. Based on the study analysis, rollover of the TSR will be possible. However, third party impacts or constraints not known at the time of this study may be reevaluated at the time of roll-over to determine if service can still be granted. ES.2.4 Service Conditions for TSR # Firm service for TSR # may not be available for load and dispatch patterns in Saskatchewan that were not assessed as part of this study. Firm service for TSR # is dependent upon system-intact operation of the SPC system. If SPC facilities that have a direct impact on the transfer capability of TSR # are not available due to maintenance or repair, curtailment of the TSR may be required. Capability for re-direct of the POR and POD was not assessed in this study, and a request for re-direct must be made as per the SPC OATT. The TSR point of delivery was identified as SaskPower (SPC) and a specific load sink was not designated. This may effectively represent network service rather than point to point service under the SPC OATT. The use of this requested transmission service in a partial path application where a POR of SPC is used as the source for the next stage in the overall transfer may be problematic. It is unclear how a POR of SPC consisting of multiple locations of native load in the SPC system can be considered as the source for the next stage of an overall transfer path. iv

6 The Study Agreement for TSR # identified that the source for TSR # was Alberta generating facilities, and the sink for TSR # was SPC load. The study results are dependent on this information. Firm service for TSR # should be conditioned on the source and sink remaining as previously identified (i.e. the POD of SPC must continue to represent a sink of SPC load), otherwise a request for re-direct or potential reassessment of the transmission service may be required. The transmission customer was unable to arrange for the exchange of detailed modeling data with the facility owner of the McNeill HVDC converter station, therefore a simplified model for the McNeill HVDC converter station was developed based on available data. If a detailed model becomes available, the transmission service may require re-evaluation, and curtailment may be required. Curtailment of the transfer due to operation of the McNeill run-back protection system could occur for unplanned operational conditions, or for N-2 events. System restoration will occur following the run-back event and the transfer may be restored depending on system conditions. v

7 TABLE OF CONTENTS 1.0 INTRODUCTION STUDY OBJECTIVES STUDY SCOPE STUDY CRITERIA STUDY METHODOLOGY BASE CASE DEVELOPMENT STEADY-STATE SYSTEM-INTACT ANALYSIS CONTINGENCY ANALYSIS NON-CONVERGENT CONTINGENCY ANALYSIS FOR PRE-TSR SPC SYSTEM NON-CONVERGENT CONTINGENCY ANALYSIS FOR TSR EQUIPMENT OVERLOAD ANALYSIS FOR PRE-TSR SPC SYSTEM EQUIPMENT OVERLOAD ANALYSIS FOR TSR REQUIREMENT FOR RE-PQ 230 KV LINE REQUIREMENT FOR PQ-SW 230 KV LINE AND REBUILD OF P1C AND S1C 138 KV LINES OVERVOLTAGE AND UNDERVOLTAGE ANALYSIS DYNAMICS ANALYSIS ASSESSMENT OF N-1 EVENTS ASSESSMENT OF N-2 EVENTS MCNEILL RUN-BACK PROTECTION SYSTEM MITIGATION COSTS COST OF REQUIRED SPC FACILITIES UPGRADES AND MODIFICATIONS EFFECT ON SPC SYSTEM LOSSES REQUIRED FACILITIES FOR PRE-TSR SPC SYSTEM OTHER TRANSMISSION SERVICE CONSIDERATIONS...15 vi

8 1.0 Introduction This study determines the system impacts associated with Transmission Service Request (TSR) # , as per the SaskPower Open Access Transmission Tariff (OATT). The TSR consists of a request for 150 MW firm point to point transmission service from the McNeill HVDC Converter Station, located at the Alberta terminal of the Swift Current to McNeill (S1M) 230 kv transmission line, to SaskPower (SPC) load. Summary details for TSR # are shown in Table 1.0.1: SPC TSR # Point of Receipt Point of Delivery AB.SK.MC SPC Service Requested 150 MW, Firm Start Time Stop Time Queue Date :00:00 CS :00:00 CS :52:29 CS Table 1.0.1: Summary Details for SPC TSR # Study Objectives The System Impact Study for TSR # has the following objectives: To assess the impact of TSR # on the SaskPower (SPC) transmission system, including SPC tie-lines. To determine if any identified impacts results in violation of SPC performance criteria. To determine if a level of partial service is available, given that identified impacts for the requested power transfer levels are unacceptable. To identify mitigation options, given that identified impacts for the requested power transfer levels are unacceptable. To determine if rollover of the TSR is possible. 1 The TSR point of delivery (POD) was identified as SaskPower (SPC) and a specific load sink was not designated. As such, the point of delivery for the TSR was not modeled at a specific POD in the SPC system, and effectively the TSR may be classified as a form of network service. 1

9 The System Impact Study Agreement for TSR # defines the following objectives: To determine the adequacy of the SPC transmission system to accommodate the TSR. To determine whether any additional costs may be incurred in order to provide transmission service. The System Impact Study will not address the cost of system additions or upgrades outside of SPC. To identify partial service, if applicable. To identify the system constraints. To identify the potential re-dispatch options, potential direct assignment facilities, or potential network upgrades required to provide the requested transmission service. 3.0 Study Scope The System Impact Study considers: Applicable SPC system topology and load levels using the latest available modeling information for the time frame studied. Most-likely stressed summer and winter load and generation scenarios for the SPC system. Applicable planned and conceptual system modifications/additions to primary facilities or operations for the time frame studied. Previously queued requests for interconnection studies and reserved transmission service that stress system conditions. Applicable planned SPC generation outages for the time frame studied. SPC system performance for steady-state system-intact normal operating conditions. SPC system performance for applicable events resulting in the loss of a single (N-1) SPC bulk electric system element, or the loss of two (N-2) or more SPC bulk electric system elements. Impacts on the SPC tie-lines to Manitoba, North Dakota, and Alberta. 2

10 Impacts on Manitoba Hydro (MH) and North Dakota (ND) facilities. The assessment of pre-tsr SPC system issues for pre-2015 system conditions based on previous studies. This System Impact Study does not consider: The use of SPC contingency reserve to mitigate post-contingency overloads in the MH system. Impacts on facilities outside of the SPC system, unless otherwise noted. System performance following extreme events resulting in the loss of two or more bulk electric system elements. Planned or prior forced outages of SPC transmission facilities with a contingency (N-1-1 transmission contingencies). Curtailment of contracted firm (nonrecallable reserved) power transfers are allowed for these contingencies to prepare the system for the next potential contingency. 4.0 Study Criteria SPC and NERC transmission planning standards were used to assess the system impacts of TSR # on system performance (system-intact and post-contingency). For assessing the dynamic performance impacts of TSR # , dynamic stability of existing and future generation and post-fault voltage performance was considered for applicable N-1 and N-2 events. 5.0 Study Methodology Simulations to assess the impacts to the SPC system due to TSR # were conducted using the PSS/E software package. 2 The following methodology process was used to assess the system impacts of TSR # : Conduct contingency analysis to identify impacts on the SPC system due to TSR # , for applicable N-1 and N-2 contingencies. 2 PSS/E is a software package by Siemens PTI (Power Technologies International). It is widely used by power utilities to perform steady-state, transient, and dynamic simulation of power system operation. 3

11 Conduct dynamic analysis to identify impacts on the dynamic performance of the SPC system due to TSR # , for applicable N-1 and N-2 contingencies. Identify facilities required to mitigate the system impacts of TSR # Estimate costs for facilities required to mitigate the system impacts of TSR # The TSR point of delivery (POD) was identified as SaskPower (SPC) and a specific load sink was not designated, which effectively represents network service rather than point to point service. As such, the point of delivery for the TSR was not modeled at a specific POD in the SPC system. When assessing the TSR, 150 MW of Alberta to Saskatchewan transfer was modeled through the McNeill back-to-back converter station. To account for no designated load sink, generation within the SPC system was redispatched to account for the McNeill transfer. Therefore the actual point of delivery was dependent on the case and varied based on the SPC system re-dispatch. Based on existing transmission reservations and previously queued requests, the MH SPC interfaces were modeled with the transfers shown in Table 5.0.1, to represent stressed conditions: The transfers include a 75 MW transmission reliability margin (TRM) to account for SPC load variations and area control impacts on the SPC MH interface. The TRM was held constant at 75 MW for this study. The SPC-MH interface was modeled at 75 MW transfer (0 MW firm transfer level + 75 MW TRM) for this study. Given the west to east directional flow of TSR # , modeling an east to west (MH to SPC) transfer in the case that is countervailing flow to the direction of TSR # would not typically identify further system limitations associated with the TSR. In conjunction with modeling the overall SPC to MH transfer at 75 MW, the Island Falls Return was modeled at 0.0 MW. SPC Interface Scheduled Transfer TRM Total Power Transfer Modeled MH SPC 0 MW (SPC-South to MH) 75 MW (SPC- 75 MW (SPC-South to MH) 0 MW (Island Falls Return) South to MH) 0 MW (Island Falls to MH) Table 5.0.1: Modeled Transfers on MH SPC Interfaces for Assessment of TSR #

12 Sensitivity analysis was performed for the following: SPC North Dakota interface transfers: 165 MW and -165 MW (i.e. 150 MW transfer plus 15 MW TRM). This sensitivity analysis captures the long-term firm transfer for TSRs # and # (see Table 5.0.2). Spring light-load, summer peak, summer off-peak, and winter peak load levels and topologies for applicable term of contract. Prior planned outage of a large baseload generating unit in SPC. OASIS Reference # Customer MW Granted Status Point of Receipt Point of Delivery NRPT 150 CONFIRMED North Dakota Saskatchewan NRPT 150 CONFIRMED Saskatchewan. Boundary Dam Power Station North Dakota Table 5.0.2: Existing Long-Term Firm TSRs within SPC that were Considered in the Sensitivity Analysis. Applicable N-1 and N-2 contingencies for the 230 kv and 138 kv SPC systems were used for the post-contingency assessment of TSR # These include: Tripping of SPC generators (N-1). Loss of a single-circuit SPC grid transmission line or tie-line (N-1). Loss of a SPC transformer (N-1). Loss of a double-circuit SPC grid transmission line (N-2). 230 kv and 138 kv breaker-fail events at SPC stations (N-2). 6.0 Base Case Development Base case development is intended to produce a range of operating cases to ensure that potential system impacts and associated mitigation requirements across a wide range of operating conditions are identified, and to provide for an acceptable level of firm transmission service by minimizing transmission loading relief (TLR). 5

13 For this study, the following regional planning case cases were used: 2017 Spring Light-Load, Summer Off-Peak, Summer Peak, and Winter Peak cases for analysis of requested reservations in the near-term Summer Off-Peak, Summer Peak, and Winter Peak cases for analysis of rollover potential. The following modifications were made to the cases used for this study: SPC system data was updated using the latest available modeling information to represent 2016 and 2021 SPC system conditions. Applicable future planned and conceptual SPC system modifications and additions were modeled in the cases. The following SPC load levels were modeled in the modified cases. Off peak cases model a standard off-peak load of 70% of peak, and spring light-load cases are modeled based on the SPC light-load forecast: o 2016 Spring Light-Load: 2051 MW o 2016 Summer Off-Peak: 2577 MW o 2016 Summer Peak: 3681 MW o 2016 Winter Peak: 4090 MW o 2021 Summer Off-Peak: 2772 MW o 2021 Summer Peak: 3960 MW o 2021 Winter Peak: 4400 MW The transmission customer was unable to arrange for the exchange of detailed modeling data with the facility owner of the McNeill HVDC converter station, therefore a simplified model for the McNeill HVDC converter station was developed based on available data. If a detailed model becomes available, the transmission service may require re-evaluation, and curtailment may be required. Island Falls generation was modeled at maximum output and Island Falls load was modified to deliver a 0 MW Island Falls return transfer. This was done in conjunction with modeling the SPC to MH transfer at 75 MW (0 MW firm transfer + 75 MW TRM). 7.0 Steady-State System-Intact Analysis PSS/E was used to assess the steady-state system-intact performance of the modified base cases of Section 6.0, with and without TSR # modeled in the case. Under steady-state system-intact conditions, with and without TSR # modeled in the case, there were no overloads of SPC bulk electric system equipment, and there were no voltage violations for any SPC bulk electric system buses. 6

14 Sensitivity analysis was also performed to assess the steady-state system-intact performance of the SPC system prior to the planned addition of a new Pasqua to Swift Current 230 kv line and planned rebuild of the Pasqua to Chaplin (P1C) and Swift Current to Chaplin (S1C) 138 kv lines, and prior to the addition of a conceptual Regina to Pasqua 230 kv line. Even without these line upgrades and additions modeled, there were no overloads of SPC bulk electric system equipment, and there were no voltage violations for any SPC bulk electric system buses, under steady-state system-intact conditions, with or without TSR # modeled. 8.0 Contingency Analysis Contingency analysis was performed using the ACCC activity in PSS/E. For this analysis, the SPC, MH, and ND bulk-electric systems, and the SPC tie-lines were assessed. The contingency analysis included the following applicable N-1 and N-2 contingencies: Generator tripping (N-1). Loss of a single-circuit grid transmission line (N-1). Loss of a transformer (N-1). Loss of a double-circuit line (N-2). 138 kv and 230 kv breaker-fail events (N-2). 8.1 Non-Convergent Contingency Analysis for Pre-TSR SPC System Non-convergent contingency analysis was performed on the SPC system to determine whether any resulted in non-convergent solutions prior to modeling TSR # SPC system issues that result in non-convergent contingencies prior to modeling TSR # were identified in this assessment, and in previous studies. These pre- TSR SPC system issues are mitigated by planned and conceptual system additions. All mitigation for pre-tsr SPC system issues is targeted to be in-service by Q

15 8.2 Non-Convergent Contingency Analysis for TSR # Based on the non-convergent contingency analysis, there are no non-convergent contingencies that are directly related to TSR # All non-convergent solutions that occurred with TSR # modeled in the cases, also occurred prior to modeling TSR # Equipment Overload Analysis for Pre-TSR SPC System Equipment overload analysis was performed on the pre-tsr system to determine whether any SPC contingencies resulted in equipment overloads prior to modeling TSR # SPC system contingencies that result in equipment overloads prior to modeling TSR # were identified in this assessment, and in previous studies. These overloads are mitigated by planned and conceptual system additions. All mitigation for pre-tsr SPC system issues is targeted to be in-service by Q Equipment Overload Analysis for TSR # A summary of overloads on SPC equipment that occurred due to modeling TSR # are shown in Table Overloaded Equipment Regina South to Pasqua (R1P) 138 kv Line Coteau Creek to Ermine (C1E) 138 kv Line Poplar River to Condie (P2C) 230 kv Line Coteau Creek to Swift Current (C1S) 230 kv Line Mitigation Replace disconnect switch at Regina South station. Remove wavetraps at Milden station. Remove wavetraps at Poplar River and Condie stations. Replace disconnect switches at Poplar River and Condie stations. Remove wavetraps at Coteau Creek and Swift Current stations. Table 8.4.1: Summary of Overload Issues that Occur Due to TSR # The mitigation for the SPC system identified in Table is a requirement to allow firm service for TSR # under the OATT. If the mitigation identified in Table is not in-service, firm service for TSR # cannot be provided under the OATT. No overloads were identified in the MH or ND systems that were directly related to the transfer of TSR # Facilities costs and potential in-service dates for the mitigation identified in Table are discussed in Section

16 8.5 Requirement for Regina to Pasqua 230 kv Line Prior to TSR # Sensitivity cases for 2016 were built to assess system performance prior to the addition of a new Regina to Pasqua 230 kv line. This line addition is considered a conceptual project and has not yet been fully committed to by SPC. Without the Regina to Pasqua 230 kv line modeled, the following overloads were identified, both before and after TSR# was modeled in the case: Overloads of the Regina South to Pasqua (R1P) 138 kv line beyond its conductor capability for N-1 and N-2 contingencies involving trips of the Pasqua to Condie (P2C) 230 kv line, the Belle Plaine to Pasqua (B6P) 138 kv line, or the Regina South to Belle Plaine (R5B) 138 kv line. Overloads of the Belle Plaine to Pasqua (B6P) 138 kv line beyond its conductor capability for N-1 and N-2 contingencies involving trips of the Poplar River to Condie (P2C) 230 kv line or the Regina South to Pasqua (R1P) 138 kv line. The overloads occur both before and after modeling TSR # in the case. The modeling of TSR # in the case increases the overloads due to the underlying west-to-east power transfer on the R1P and B6P lines that is occurring in the pre-tsr cases. The overloads are mitigated by the addition of a new Regina to Pasqua 230 kv line. Due to the identified overload condition for the R1P and B6P 138 kv lines, and the potential worsening of the overload condition due to TSR # , firm service for TSR # cannot be provided under the OATT until a new Regina to Pasqua 230 kv line is in-service. The addition of a new Rowatt 230 kv switching station is required to connect a new Regina to Pasqua 230 kv line into the Regina area. The Rowatt 230 kv station is also considered a conceptual project and has not yet been fully committed to by SPC. The approximate in-service date for a new Regina to Pasqua 230 kv line and a new Rowatt 230 kv switching station is Q The in-service date will be assessed if TSR # proceeds to a Facilities Study. 8.6 Requirement for Pasqua to Swift Current 230 kv Line and Rebuild of P1C and S1C 138 kv Lines Prior to TSR # Sensitivity cases for 2016 were built to assess system performance prior to the addition of a new Pasqua to Swift Current 230 kv line and the rebuild of the Pasqua to Chaplin (P1C) and Swift Current to Chaplin (S1C) 138 kv lines. These are planned projects that have been authorized and committed to by SPC. 9

17 Without the Pasqua to Swift Current 230 kv line and the rebuild of the P1C/S1C 138kV lines modeled, the following overloads were identified, both before and after TSR# was modeled in the case: Overloads of the Pasqua to Chaplin (P1C) 138 kv line beyond its conductor capability for numerous N-1 and N-2 contingencies involving lines and transformers in the southwest area of SPC. Overloads of the Swift Current to Chaplin (S1C) 138 kv line beyond its conductor capability for N-1 and N-2 contingencies involving trips of the Pasqua to Chaplin (P1C) 138 kv line, or an N-2 trip of the Coteau Creek to Swift Current (C1S) 230 kv line and Rushlake Creek to Swift Current (R1S) 230 kv line. The overloads occur both before and after modeling TSR # in the case. The modeling of TSR # in the case increases the overloads due to the underlying west-to-east power transfer on the P1C and S1C lines that is occurring in the pre-tsr cases. The overloads are mitigated by the planned addition of a new Pasqua to Swift Current 230 kv line and rebuild of the P1C and S1C 138 kv lines. The target in-service date for the Pasqua to Swift Current 230 kv line and rebuild of the P1C and S1C 138 kv lines is Q Due to the identified overload condition for the P1C and S1C 138 kv lines, and the potential worsening of the overload condition due to TSR # , firm service for TSR # cannot be provided under the OATT until the new Pasqua to Swift Current 230 kv line is in-service. 8.7 Overvoltage and Undervoltage Analysis The post-contingency voltage assessment did not identify any overvoltage or undervoltage issues in the SPC, MH, or ND systems that are attributable directly to TSR # Some overvoltage and undervoltage issues were identified for the SPC system prior to modeling TSR # All identified overvoltage and undervoltage conditions within the pre-tsr SPC system are correctable by planned and conceptual system additions, or are correctable through operator or automatic action. All mitigation for pre-tsr SPC system issues is targeted to be in-service by Q

18 9.0 Dynamics Analysis For assessing the dynamic performance impacts of TSR # , dynamic stability of existing and future generation and post-fault voltage performance was assessed. For the N-1 dynamics analysis, all sensitivities discussed in Section 5.0 were assessed to identify critical or limiting system conditions for dynamic performance. Based on the results of the N-1 analysis, the following four scenarios displayed the most onerous conditions for dynamic system performance, and N-2 dynamic analysis was limited to these scenarios: 2016 summer off-peak SPC load conditions, SPC to North Dakota transfer: 165 MW; Alberta to SPC transfer: 150 MW; Full output from SPC wind generation summer off-peak SPC load conditions, North Dakota to SPC transfer: 165 MW; Alberta to SPC transfer: 150 MW; Full output from SPC wind generation summer off-peak SPC load conditions, SPC to North Dakota transfer: 165 MW; Alberta to SPC transfer: 150 MW; Full output from SPC wind generation summer off-peak SPC load conditions, North Dakota to SPC transfer: 165 MW; Alberta to SPC transfer: 150 MW; Full output from SPC wind generation. 9.1 Assessment of N-1 Events The N-1 events evaluated consist of 230 kv and 138 kv three-phase faults, and were selected for evaluation due to their vicinity to existing, planned, or conceptual SPC generation and for their potential impacts on SPC generation stability or post-fault voltage performance. Additional events were also selected due to their vicinity to the McNeill converter station (the only existing tie-line between Alberta and Saskatchewan). Some N-1 dynamic issues were identified for the SPC system prior to the modeling of TSR # The planned and conceptual system additions required to mitigate these pre-tsr system issues is targeted to be in-service by Q The effect of TSR # on the N-1 dynamics results was marginal. No new issues were identified for the N-1 dynamics results that are attributable to TSR #

19 9.2 Assessment of N-2 Events The N-2 events evaluated are 230 kv and 138 kv single-line-to-ground breaker-fail events, and were selected due to their vicinity to existing, planned, or conceptual SPC generation and for their potential impacts on SPC generation stability or post-fault voltage performance. Additional events were also selected due to their vicinity to the McNeill converter station (the only existing tie-line between Alberta and Saskatchewan). Some N-2 dynamic issues were identified for the SPC system prior to the modeling of TSR # The planned and conceptual system additions required to mitigate these pre-tsr system issues is targeted to be in-service by Q The effect of TSR # on the N-2 dynamics results was marginal. No new issues were identified for the N-2 dynamics results that are attributable to TSR # McNeill Run-Back Protection System The McNeill run-back protection system monitors the voltage at the McNeill 230 kv bus and the Swift Current 230 kv bus. Based on the existing settings, power transfer from Alberta to Saskatchewan (through the McNeill DC converter station) will be run-back to 75 MW if the voltages at McNeill station or Swift Current station do not meet system requirements. No N-1 events were identified in the dynamics analysis that would initiate the McNeill run-back protection system. This assumes that the planned static-var system (SVS) at Swift Current station is in-service and operational. The targeted inservice date for the Swift Current SVS is Q Run-back may still occur for unplanned operational conditions, with system restoration occurring after the runback event and potential restoration of the transfer depending on the system conditions. N-2 events were identified in the dynamics analysis that would initiate the McNeill run-back protection system. As per SPC standards, controlled load shedding and/or curtailment of firm transfers are allowable to maintain the overall reliability of the system. System restoration will occur following the run-back event and the transfer may be restored depending on system conditions. 12

20 10.0 Mitigation Costs 10.1 Cost of Required SPC Facilities Upgrades and Modifications Shown in Table are SPC system facilities required to mitigate issues due to TSR # If the SPC facilities in Table are not in-service, firm service for TSR # cannot be provided under the OATT. The SPC system facilities identified as mitigation in Table are considered to be network upgrades and are not direct assignment facilities. System re-dispatch is an alternative to the system facilities identified in Table By reducing Poplar River generation by 35 MW and re-dispatching the 35 MW from other SPC generation, the overload on the disconnect switches can be mitigated. The operational cost of this system re-dispatch option will be assessed if TSR # proceeds to a Facilities Study. TSR # Transfer Level SPC System Facilities Required Due to TSR # Potential Construction Time Estimated Cost of Identified SPC Facilities (x1,000) Full Service (150 MW Alberta to Saskatchewan through McNeill Station) Replace disconnect switches at Poplar River and Condie switching stations. Up to 1 year after customer commitment to TSR. $400 Table : Facilities Required in SPC System Due to TSR # The in-service dates and costs for the facilities identified in Table will be confirmed if the TSR proceeds to a Facilities Study. Prior to providing firm service for TSR # under the OATT, system upgrades are also required to address some pre-tsr SPC system issues, as some facilities required for pre-tsr issues on the SPC system directly impact the transfer capability of TSR # These facilities are discussed in Section Full or partial firm service for TSR # cannot be provided under the OATT until these upgrades for pre-tsr SPC system issues that directly impact the transfer capability of TSR # are in-service. These pre-tsr SPC system upgrades are not shown in Table The cost for these pre-tsr SPC system upgrades are not currently allocated to TSR #

21 10.2 Effect on SPC System Losses The overall effect on SPC system losses due to TSR # was not assessed for this study. The calculation of real power loss factors for application to the power transfers of TSR # is covered in Schedule 9 (Real Power Loss Factors) of the SaskPower OATT Required Facilities for Pre-TSR SPC System Shown in Table are future SPC transmission facilities required for pre-tsr issues on the SPC system that directly impact the transfer capability of TSR # Firm service for TSR # cannot be provided under the OATT until the transmission facilities of Table are in-service. The in-service dates shown in Table will be confirmed if the TSR proceeds to a Facilities Study. Facilities Current Targeted In-Service Date Project Status Replace disconnect switch at Regina South switching station. Q Planned Remove wavetraps at Poplar River, Condie, Coteau Creek, and Swift Current switching stations. Q Planned Construction of new Pasqua to Swift Current 230 kv line. Q Planned Rebuild of Pasqua to Chaplin (P1C) 138 kv line and Swift Current to Chaplin (S1C) 138 kv line. Q Planned Construction of new Regina to Pasqua 230 kv line. Approximately Q Conceptual Construction of new Rowatt 230 kv switching station Approximately Q Conceptual Table : Planned and Conceptual SPC Transmission Facilities Shown to Impact the Transfer Capability of TSR # The construction of a new Regina to Pasqua 230 kv line and the construction of a new Rowatt 230 kv switching station (both shown in Table ) are conceptual projects and have not yet been fully committed to by SPC. The Regina to Pasqua 230 kv line and the Rowatt 230 kv station are required for firm service to be provided to TSR # If SPC does not commit to proceeding with the Regina to Pasqua 230 kv line or the Rowatt 230 kv switching station, their cost will be allocated to TSR # The estimated cost for a new Regina to Pasqua 230 kv line is approximately $100 million, and the estimated cost for a new Rowatt 230 kv switching station is approximately $30M. The in-service date and cost allocation for these projects will be assessed if TSR # proceeds to a Facilities Study. In addition to the facilities of Table , other facilities that do not significantly impact the transfer capability of TSR # are required for pre-tsr issues on the SPC 14

22 system. These facilities are not scheduled to be in-service until Q at the earliest. Given that these facilities do not significantly impact the transfer capability of TSR # , it is not expected that firm service for TSR # will be impacted if these facilities are not in-service when service for TSR # is granted. However, prior to these additional facilities being in-service, there could still be infrequent conditions in which curtailment of TSR # in the form of transmission loading relief (TLR) is required to address system conditions unrelated to the TSR. The requested start date for TSR # is Jan 1, 2012, with a time period of five years. Prior to providing firm service for TSR # under the OATT, facilities required for pre-tsr issues on the SPC system that directly impact the transfer capability of TSR # must be in-service (see Table ). These required facilities are not scheduled to be in-service until Q at the earliest. Based on this schedule, it is estimated that firm service for TSR # cannot be provided under the OATT until approximately Q The potential in-service date for these facilities will be determined if TSR # proceeds to a Facilities Study. For the study of TSR # , year 2016 cases were used for assessment of the TSR in the near-term time-period, despite the requested TSR start date of Jan 1, This was done to better align with the approximate time-frame that facilities to address pre- TSR SPC system issues could be in-service. Year 2021 cases were used to assess the system at the end of the requested 5 year time period of the TSR. As the facilities of Table address pre-tsr system issues that occur prior to TSR # , no amount of partial firm service for TSR # can be provided under the OATT prior to implementing the system upgrades shown in Table Based on the study analysis, rollover of the TSR will be possible. However, third party impacts or constraints not known at the time of this study may be re-evaluated at the time of roll-over to determine if service can still be granted Other Transmission Service Considerations The System Impact Study for TSR # includes time-sensitive results. The results of the System Impact Study will be deemed invalid 3 months after completion of the System Impact Study. Completion of the System Impact Study is deemed to occur upon signing and issuing of the System Impact Study. If the proponent elects to proceed with TSR # , a Facilities Study will be required to determine the schedule and cost for required mitigation to correct pre- TSR issues on the SPC system. SPC will provide the Customer with an executable Facilities Study Agreement for TSR # within 30 days of the completion of the System Impact Study. The Customer must execute the Facilities Study Agreement within 15 days of its 15

23 receipt. If the Customer does not execute the Facilities Study Agreement within 15 days, the results of the System Impact Study will be deemed invalid, and TSR # shall be deemed terminated and withdrawn. SPC, at its discretion, may elect to augment the proposed options or develop other options that would meet the technical requirements. However, any additional associated costs would not be allocated to TSR # Any roll-over granted will need to be conditioned by third party impacts or constraints. That is, third party impacts or constraints not known at the time of this study may be re-evaluated at the time of roll-over to determine if service can still be granted. Service may not be available for load and dispatch patterns in Saskatchewan that were not assessed as part of this study. Service is dependent upon system-intact operation of the SPC system. If SPC facilities that have an impact on the transfer capability of TSR # are not available due to maintenance or repair, curtailment of the TSR may be required. Capability for re-direct of the POR and POD was not assessed in this study, and a request for re-direct must be made as per the SPC OATT. The TSR point of delivery was identified as SaskPower (SPC) and a specific load sink was not designated. This may effectively represent network service rather than point to point service under the SPC OATT. The use of this requested transmission service in a partial path application where a POR of SPC is used as the source for the next stage in the overall transfer may be problematic. It is unclear how a POR of SPC consisting of multiple locations of native load in the SPC system can be considered as the source for the next stage of an overall transfer path. The Study Agreement for TSR # identified that the source for TSR # was Alberta generating facilities, and the sink for TSR # was SPC load. The study results are dependent on this information. Firm service for TSR # should be conditioned on the source and sink remaining as previously identified (i.e. the POD of SPC must continue to represent a sink of SPC load), otherwise a request for re-direct or potential reassessment of the transmission service may be required. The transmission customer was unable to arrange for the exchange of detailed modeling data with the facility owner of the McNeill HVDC converter station, therefore a simplified model for the McNeill HVDC converter station was developed based on available data. If a detailed model becomes available, the transmission service may require re-evaluation, and curtailment may be required. 16

24 The calculation of real power loss factors for application to the power transfers of TSR # is covered in Schedule 9 (Real Power Loss Factors) of the SaskPower OATT. Curtailment of the transfer due to operation of the McNeill run-back protection system could occur for unplanned operational conditions, or for N-2 events. System restoration will occur following the run-back event and the transfer may be restored depending on system conditions. 17