APPENDIX A AESO System Planning Study Red Deer Technical Report
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APPENDIX A AESO System Planning Study Red Deer Technical Report
APPENDIX A AESO System Planning Study Red Deer Technical Report Report Index Section Number 1 2 3 4 5 6 7 8 9 Attachment A Attachment B Attachment C Attachment D Attachment E Attachment F Introduction Number of Pages Introduction 9 Planning Criteria and Study Assumptions 14 Existing System Assessment 5 Development of System Reinforcement Options 18 Transmission Alternatives- Near Term Assessment 5 Transmission Alternatives- Long Term Assessment 4 Alternatives Comparison 4 Sensitivity Analysis 2 Recommended Proposal 7 Existing System Analysis 120 Historical Substation Load Details 2 Alternative Details 8 Steady State and Voltage Stability Analysis 1752 Transient Stability Analysis 2732 Sensitivity Analysis 20 iii TABLE OF CONTENTS 1.0 1.1 1.2 2.0 Introduction .............................................................................................. 1 Study Region of Existing System ....................................................................................... 1 Study Objectives and Scope .............................................................................................. 8 Planning Criteria and Study Assumptions........................................... 10 2.1 Reliability Criteria .............................................................................................................. 10 2.2 Voltage Stability Methodology .......................................................................................... 12 2.3 Monitored Areas ............................................................................................................... 13 2.4 Load Scenarios ................................................................................................................. 14 2.5 Load Forecast ................................................................................................................... 15 2.6 Generation Assumptions .................................................................................................. 16 2.7 Facility Ratings ................................................................................................................. 17 2.8 Transmission Assumptions............................................................................................... 19 2.8.1 Bulk System Assumptions ....................................................................................... 19 2.8.2 Hanna Region System Assumptions ....................................................................... 20 2.8.3 Central East Region System Assumptions .............................................................. 21 2.8.4 Southern Alberta Transmission Reinforcements (SATR) ........................................ 22 2.9 System Inter Dependencies ............................................................................................. 23 3.0 Existing System Assessment ............................................................... 24 3.1 Power Flow Analysis ........................................................................................................ 24 3.1.1 Load Supply Adequacy ............................................................................................ 24 3.1.2 High SOK Cut Plane Flows ...................................................................................... 25 3.2 Voltage Stability Analysis ................................................................................................. 25 3.3 Transfer Capability Analysis ............................................................................................. 26 3.4 Short Circuit Analysis ....................................................................................................... 27 3.5 Existing System Need Assessment Summary ................................................................. 27 4.0 Development of System Reinforcement Options ................................ 29 4.1 Transmission Technology Options Screening .................................................................. 29 4.1.1 New Transmission Lines .......................................................................................... 29 4.1.2 Transmission Line Upgrades and Rebuild ............................................................... 30 4.1.3 Voltage Up-Rating.................................................................................................... 31 4.1.4 Build New Transmission Substations and Upgrade Existing Stations ..................... 31 4.1.5 Provide Reactive Power Support Equipment .......................................................... 31 4.1.6 Consideration of Operational Measures .................................................................. 32 4.2 Formulation and Screening of Red Deer Alternatives ...................................................... 32 4.2.1 Common Set of Transmission System Development .............................................. 33 4.2.2 Alternative 1 Development (80L Alternative) ........................................................... 37 4.2.3 Development of Alternative 2 (Hybrid Alternative) ................................................... 41 4.2.4 Development of Alternative 3 (Double Loop Alternative)......................................... 45 4.2.5 Summary of Screening of Alternatives .................................................................... 45 5.0 Transmission Alternatives- Near Term Assessment (2012) ............... 47 5.1 Power Flow Analysis (2012) ............................................................................................. 47 5.1.1 System Performance under Category C and D Contingency Events ...................... 48 5.2 Transient Stability Studies (2012) .................................................................................... 48 5.3 Voltage Stability (P-V and Q-V) Analysis ......................................................................... 49 5.4 Transfer Capability Analysis ............................................................................................. 49 5.5 Short Circuit Analysis ....................................................................................................... 51 iv 6.0 Transmission Alternatives- Long Term Assessment (2017) .............. 52 6.1 Power Flow Analysis (2017) ............................................................................................. 52 6.1.1 System Performance under Category C and D Contingency Events ...................... 52 6.2 2017 Transient Stability Studies (2017) ........................................................................... 53 6.3 Voltage Stability (P-V and Q-V) Analysis ......................................................................... 53 6.4 Transfer Capability Analysis ............................................................................................. 54 6.5 Short Circuit Analysis ....................................................................................................... 55 7.0 Comparison of Alternatives .................................................................. 56 8.0 Sensitivity Analysis (Load Forecast) .................................................... 60 8.1 8.2 8.3 9.0 9.1 Sensitivity Analysis for 2012 ............................................................................................. 60 Sensitivity Analysis for 2017 ............................................................................................. 61 Sensitivity Study Conclusions........................................................................................... 61 Recommended Development ................................................................ 62 Rationale for the Recommended Development ............................................................... 65 v LIST OF TABLES AND FIGURES LIST OF TABLES Table 2-1: General Acceptable Range of Voltage (kV) ................................................................ 11 Table 2-2: Acceptable Voltage Deviation and Equipment Loading .............................................. 11 Table 2-3: Buses Voltage (kV) Range in the Red Deer Area (OPP 702) ..................................... 11 Table 2-4: Voltage Stability Criteria .............................................................................................. 13 Table 2-5: Summary of Monitored Areas for Load flow Analysis ................................................. 14 Table 2-6: Assumptions for Import/Export to BC and SK (MW) ................................................... 15 Table 2-7: Assumptions for HVDC Dispatch in 2017 (MW) ......................................................... 15 Table 2-8: Load Forecast Modeled in Red Deer Region (MW) .................................................... 15 Table 2-9: Rated Capacity for Existing Generation in the Red Deer Region ............................... 16 Table 2-10:Generation Dispatch (MW) .......................................................................................... 17 Table 2-11:Transmission Line Ratings in the Red Deer Region ................................................... 17 Table 2-12:Transformer Ratings in Red Deer Region ................................................................... 19 Table 4-1: List of the Common Set of Transmission System Developments ............................... 36 Table 4-2: 2012 List of Alternative 1 Development Excluding Common Set of Transmission System Developments ................................................................................................. 38 Table 5-1: Power Flow Analysis Results – 2012 .......................................................................... 47 Table 5-2: 2012 First Contingency Incremental Transfer Capability (FCITC) for Alternative 1.... 50 Table 5-3: 2012 First Contingency Incremental Transfer Capability (FCITC) for Alternative 2.... 50 Table 6-1: Power Flow Analysis Results – 2017 .......................................................................... 52 Table 6-2: 2017 First Contingency Incremental Transfer Capability (FCITC) for 2017................ 54 Table 6-3: First Contingency Incremental Transfer Capability (FCITC) for Alternative2.............. 55 Table 7-1: Category C Performance Comparison of Alternatives1&2 for 2012 High SOK and 2012WP with Nova Joffre Cogeneration Plant Out of Service .................................... 57 Table 7-2: Category C Performance Comparison of Alternatives1&2 for 2017WP with Nova Joffre Cogeneration Plant Out of Service .............................................................................. 58 Table 7-3: Summary of the Technical Performance Evaluation of the Alternatives 1 and 2 ......... 59 Table 9-1: Details of the Recommended Plan............................................................................... 64 vi LIST OF FIGURES Figure 1-1: Red Deer Region Planning Areas ................................................................................. 3 Figure 1-2: Schematic of Transmission System of Red Deer Region ............................................. 4 Figure 1-3 : Schematic of South of Keephills, Ellerslie and Genesee (SOK-240) cut plane ........... 5 Figure 1-4: Joffre Area Inflow Cut Plane ......................................................................................... 6 Figure 1-5: Joffre Area Outflow Cut Plane ...................................................................................... 7 Figure 4-1: Schematic of the Common Set of Transmission System Developments ................... 35 Figure 4-2: Schematic of Red Deer Region Transmission System Upgrades- Alternative 1 ...... 39 Figure 4-3: Map of Red Deer Region Transmission System Upgrades- Alternative 1.................. 40 Figure 4-4: Schematic of Red Deer Region Transmission System Upgrade - Alternative 2......... 43 Figure 4-5: Schematic of Red Deer Region Transmission System Upgrade - Alternative 2......... 44 Figure 4-6: Schematic of Red Deer Region Transmission System Upgrade - Alternative 3......... 46 Figure 9-1: Recommended Transmission Plan (Alternative 2) .................................................... 63 ATTACHMENTS Attachment A: Existing System Analysis Attachment B: Historical Substation Load Details Attachment C: Alternative Details Attachment D: Steady State and Voltage Stability Analysis Attachment E: Transient Stability Analysis Attachment F: Sensitivity Analysis vii 1.0 Introduction The Alberta Interconnected Electric System (AIES) is a vital component of the electric industry and provides a platform for the competitive wholesale electricity market in Alberta. The AIES connects generators to load over a large and diverse geographic area and is planned, designed, and operated to deliver electric energy to Alberta customers reliably and efficiently under a wide variety of system operating conditions. The AESO Long Term Transmission System Plan 2009 identifies system constraints on the existing transmission system between and including the City of Red Deer and the Town of Didsbury. This planning study report expands on this by specifically studying the need for transmission system developments in the Red Deer region. This report identifies existing and future reliability constraints using the projected load growth for the Red Deer region. Further, transmission system development alternatives have been developed and evaluated for both the short term (2012) and long term (2017) horizons and a preferred alternative have been proposed. 1.1 Study Region of Existing System The Red Deer region mainly encompasses the AIES planning areas of: Red Deer (Area 35), Didsbury (Area 39) and a part of Wetaskiwin (Area 31). Figures 1-1 and 1-2 show the geographical areas and the schematic of existing transmission system of the study region respectively. The study region contains three 240kV source substations; Benalto 17S, Gaetz 87S, and Red Deer 63S. Transmission in the study region primarily consists of 138kV lines that supply industrial, commercial and residential loads. The 240kV lines that connect the generation in the Wabamun (Area 40) in the north to the loads in the Calgary (Area 6) in the south pass through the study region. These lines are known as South of Keephills, Ellerslie and Genesee (SOK-240) cut plane (see Figure 1-3). The SOK-240 Total Transfer Capability (TTC) is estimated at about 2150MW1 and 2050 under winter and summer normal system conditions respectively. The Joffre area, which lies to the east of the City of Red Deer, is an important part of the Red Deer study region because it is a home for several industrial loads and a large combined cycle generation plant which consists of two gas turbines and one steam turbine. This plant is located at Joffre 535S–Nova Complex. The Maximum Continuous Rating (MCR) of the Nova Joffre cogeneration plant is 510MW. Since 2005, the operation of Nova Joffre cogeneration plant has been subjected to Operating Policies 1 OPP 521 SOK-240 Operation, can be found on the AESO website 1 and Procedures OPP 5022 that provides policies and procedures for operation of the Joffre area 138kV transmission system, including transfer limits into and out of the Joffre area. Under some system conditions, generation may have to be curtailed at the Nova Joffre cogeneration plant to comply with the Joffre outflow limits. When all three Nova Joffre cogeneration plant units are off line, area load may need to be reduced by load shedding to comply with the Joffre inflow limits. Both curtailment of generation and reduction of loads are done in accordance with the AESO Transmission Reliability Criteria. The Joffre area inflow and outflow cut planes are presented in Figures 1-4 and 1-5 respectively. 2 OPP 502Joffre Area Operation, can be found on the AESO website 2 Figure 1‐1: Red Deer Region Planning Areas 3 Figure 1‐2: Schematic of Transmission System of Red Deer Region 4 Figure 1‐3 : Schematic of South of Keephills, Ellerslie and Genesee (SOK‐ 240) Cut Plane3 3 SOK-240 flow is defined as the sum of: outflows on 926L and 922L measured at the Sundance substation (T310P), outflows on 903L and 190L measured at the Keephills substation (T320P), outflows on 914L and 910L at the Ellerslie substation (T89S), and 35 % of outflows on 912L at the Red Deer substation (T63S) and inflows on 995L at the Benalto substation (T17S). 5 Figure 1‐4: Schematic of Joffre Area Inflow Cut Plane4 4 Sum of MW flow of: 756L: Gaetz 87S to Joffre 535S, measured at Gaetz, 759L: Gaetz 87S to Prentiss 276S, measured at Gaetz, 793L: Gaetz 87S to Joffre 535S, measured at Gaetz, 755L: Red Deer 63S to Piper Creek 247S, measured at Red Deer. This schematic is for illustrative purposes only. 6 Figure 1‐5: Schematic of Joffre Area Outflow Cut Plane5 5 Sum of MW flow of, 756L: Joffre 535S to Gaetz 87S, measured at Joffre, 775L: Joffre 535S to Prentiss 276S, measured at Joffre, 793L: Joffre 535S to Gaetz 87S, measured at Joffre, 755L: Joffre 535S to Piper Creek 247S, measured at Joffre. 7 1.2 Study Objectives and Scope The objectives of the system study are given below. A transmission reinforcement solution is needed to: Meet the projected load growth of approximately 3.5 per cent per year and 1.7 per cent per year in the Red Deer and Didsbury areas respectively over the 10-year period (2008- 2018). The load growth is spurred by expansion in industrial, residential and commercial sectors, and Alleviate existing transmission constraints, including Joffre outflow and inflow limits (i.e., OPP 502), in the study region. The AESO Long Term Transmission System Plan 2009 identifies the occurrence of system constraints on existing transmission system elements between, and including, the Cities of Red Deer and Didsbury in the year 2017.6 This Planning Study Report expands upon studies conducted for the LongTerm Plan by focusing on identifying the specific need for transmission system upgrades in the Red Deer Region. Accordingly, the AESO assessed the performance of the Red Deer region transmission system considering its projections for load growth in the region to identify existing and future reliability constraints. Study assumptions and reliability criteria are described in Section 2. The assessment of the existing system is presented in Section 3. The transmission system low voltage and thermal constraints identified in Section 3 were used to develop system reinforcement alternatives. The development of system reinforcement options and the identification of the preferred alternatives to address the transmission constraints are presented in Section 4. The performance of the preferred alternatives is evaluated for the shortterm (2012) and long-term (2017) horizons by performing load flow, short circuit, voltage stability, transfer capability, and transient stability analyses. These study results are presented in Sections 5 and 6. Technical performance, future expandability, and operational flexibility of study alternatives are compared in Section 7. A sensitivity analysis was carried out to verify that the latest load forecast (FC2009) does not have any impacts on the proposed preferred plan. The results of this analysis are reported in Section 8. 6 Central Region Transmission Plan contained in the 2009 AESO Long-Term Transmission System Plan, Appendix K, p.336. Figure 5.0-2 identifies forecasted transmission system constraints in year 2017. Table 5.0-3 contains preliminary plans for system upgrades in and around the Cities of Red Deer and Didsbury. 8 The recommended development for Red Deer region and its rationale are presented and discussed in Section 9. Note: The System studies utilized assumptions regarding the future configuration of the Alberta Interconnected Electric System (AIES) follows provisions of Section 8 of the Transmission Regulation (TReg)7. The Study assumptions regarding the bulk transmission system are generally consistent with those used in developing the 2009 AESO LongTerm Transmission System Plan. At the time the study was conducted, the AESO may have made assumptions about the timing, load growth, configurations and locations of future regional and bulk system developments. While the AESO believes that its assumptions are realistic and representative of the future system developments, the AESO acknowledges that assumptions are subject to change as specific studies are executed, plans refined, and facilities are approved and constructed. The analyses performed in this study do not include explicit consideration of all potential changes to assumptions. To the extent that future system developments are different from those assumed in the study, the expected system performance may also differ from the results predicted within. The AESO addresses this uncertainty by performing regular system planning studies and adjusting long-term plans as required. 7 TReg describes the AESO’s responsibilities in making assumptions about future load growth, the timing and location of future generation additions and other related assumptions to support the transmission system. 9 2.0 Planning Criteria and Study Assumptions To identify the need to reinforce the transmission system in the Red Deer region, the AESO tests the present and future adequacy of the existing transmission system by applying the AESO Transmission Reliability Criteria. The Red Deer region transmission system was tested under specific load forecast and future generation assumptions. This section describes the Reliability Criteria, study assumptions and methodology. 2.1 Reliability Criteria The AESO performs technical studies to assess transmission supply and reliability needs in Alberta. These studies examine the transmission system for adequacy, security, operability, and maintainability. The Reliability Criteria were applied to determine the load supply adequacy of the planned transmission system in the Red Deer region. That is, the existing transmission system along with the proposed alternatives were tested to see if the proposed alternatives were capable of supplying the forecasted peak demand under both Category A (i.e., all elements in service) and Category B (i.e., an element out of service, N-1 and N-G-1) contingencies. The study alternatives were put through an iterative planning process to optimize the planning alternatives and ensure that the planned transmission system conformed to the Reliability Criteria. Category B contingencies also cover single element outage contingency events while the most critical generator is out of service (N-G-1), and the remaining generators in the system are dispatched according to the forecasted merit order. All equipment must operate within its acceptable thermal and voltage limits. Category C and D contingencies are only studied for the recommended alternatives. The system performance is evaluated to ensure no system cascading occurs. Remedial Action Schemes (RAS), suggested in the AESO’s OPPs, are tested to ensure planned system security and additional RAS are proposed if deemed necessary. Table 2-1 presents the acceptable operational voltage range under steady state and emergency conditions. The voltage stability criteria that were used to test the system performance are provided in Tables 2-2 and 2-3. 10 Table 2‐1: General Acceptable Range of Voltage (kV) Nominal Extreme Minimum Normal Minimum Normal Maximum Extreme Maximum 240 220 240 264 264 138 124 135 145 150 69 62 65 72 74 Table 2‐2: Acceptable Voltage Deviation and Equipment Loading Parameter Post Transient (Up to 30 sec.) Post Auto Control (30 sec. to 5 min.) Post Manual Control (Steady State) ±10% ±7% ±5% Voltage Deviation from Steady State at Low Voltage Bus Transmission Equipment Loading 100% of Emergency Rating 100% of Emergency Rating 100% of continuous Rating Table 2‐3: Buses Voltage (kV) Range in the Red Deer Area (OPP 702) Nominal Voltage Minimum Operating Limit Desired Range Maximum Operating limit 240 242 246 – 256 260 138 138 138 – 144 145 240 240 245 – 256 257 138 138 138 -143 145 240 240 240 – 256 260 Gaetz 87S 138 138 138 – 144 145 Joffre 535S 138 138 138 – 142 142 Substation Name Benalto 17S Red Deer 63S 11 2.2 Voltage Stability Methodology Among the methods for assessing steady-state voltage stability, the most frequently used are P-V (Real Power-Voltage) and Q-V (Reactive PowerVoltage) analysis. In this study, transmission system steady-state voltage stability was tested using P-V and Q-V analysis. The objective of P-V and Q-V analysis is to determine the ability of a power system to maintain sufficient reactive power margins at all the buses in the system under normal and abnormal steady state operating conditions. P-V and Q-V analysis are utilized to: Ensure system voltage stability under steady state and abnormal conditions by checking the buses’ voltage collapse points. Ensure proper sizing of reactive power compensation devices that deal with slow voltage stability. Investigate the effects of Nova Joffre cogeneration plant, loads, and reactive power compensation devices on the transmission network. P-V analysis is obtained using a series of AC load flow solutions. The P-V curve represents the bus voltage change as a function of increased power transfer between two systems; the sending system is called ‘The source’ while the receiving system is called ‘The sink’. P-V analysis was performed according to the Western Electricity Coordinating Council (WECC) Voltage Stability Assessment Methodology, as described in more detail in the AESO Transmission Reliability Criteria that is outlined in Table 2-4. The reference load level is the maximum established load level. The Red Deer region was considered the sink system while the Wabamun (Area 40) was considered the source system. While conducting P-V analysis, the forecasted loads in the Red Deer region were increased with a corresponding generation increase in the Wabamun area. P-V curves were generated for Category A conditions and critical Category B contingencies in the study area. Table 2-4 was utilized to judge compliance with voltage reliability criteria. The MW margin is defined as the difference between maximum power transfer corresponding to voltage level of 0.95 p.u. and the reference load level. The MW margin is defined to ensure that steady state voltage does not go below 0.95 p.u, the voltage level deemed necessary for proper operation of motor loads in the area. The Q-V curve represents the change in reactive power demand by a bus or buses as the voltage level changes. Q-V curves are used to determine the reactive power injection required at a bus in order to vary the bus voltage to the required value. The curve is obtained through a series of AC load flow calculations. Starting with the existing reactive loading at a bus, the voltage at the bus can be computed for a series of power flows as the reactive load is increased in steps, until the power flow experiences 12 convergence difficulties as the system approaches the voltage collapse point. Q-V curves are commonly used to identify voltage stability issues and reactive power margins for specific locations in the power system under various loading and contingency conditions. The Q-V curves are also used as a method to size shunt reactive compensation at any particular bus to maintain the required scheduled voltage. Q-V analysis was performed according to the Western Electricity Coordination Council (WECC) methodology for the critical buses in Red Deer region. A reactive margin is defined as a reactive power corresponding to 0.95 p.u. voltage. A positive reactive margin indicates that additional reactive power is needed to maintain the bus voltage above 0.95 p.u. Table 2‐4: Voltage Stability Criteria Performance Level MW Margin (P-V method) MVAr Margin (Q-V method) A Any element such as: one generator, one circuit, one transformer, one reactive power source, and one DC monopole ≥ 5% Worst Case Scenario 8 B Bus section ≥ 2.5% 50% of margin requirement in Level A C D 2.3 Disturbance Initiated by: Fault or No fault HVDC Disturbance Any combination of two elements such as: A line and a generator, A line and a reactive power source, Two generators, ≥ 2.5% Two circuits , Two transformers, Two reactive power sources DC bipole Any combination of three or more elements, such as: three or more circuit >0 on ROW, entire substation, entire plant including switchyard 50% of margin requirement in Level A >0 Monitored Areas The study areas monitored for voltage and thermal violations during Category A and Category B contingency analysis are shown in Figure 1-1 and Table 2-5. The contingency list covers single element outage in the 8 The most reactive deficient bus must have adequate reactive power margin for the worst single contingency to satisfy either of the following conditions, whichever is worst: (i) a 5% increase beyond maximum forecasted loads or (ii) 5% increase beyond maximum allowable interface flows. The worst single contingency is the one that causes the largest decrease in the reactive power margin. 13 monitored areas (see Table 2-5) and also the Edmonton (Area 60) and the Wabamun (Area 40). All elements in the voltage range (138-500kV) were considered. In addition to these contingencies, the HVDC contingencies in 2017 were considered. 2.4 Table 2‐5: Summary of Monitored Areas for Load flow Analysis Area Number Area Name 35 31 38 39 Red Deer Wetaskiwin Caroline Didsbury Voltage Range (kV) 138-500 138-500 138-500 138-500 Load Scenarios In this study, the following load scenarios were considered 2012 Winter Peak Load Condition (2012WP) 2012 Summer Peak Load Condition (2012SP) 2012 Summer Light Load Condition (2012SL) 2012 Summer High SOK Load Condition(2012S-SOK) 2017 Winter Peak Load Condition (2017WP) 2017 Summer Peak Load Condition (2017SP) 2017 Summer Light Load Condition (2017SL) In addition, the 2012WP and 2017WP cases were studied with Nova Joffre cogeneration plant out of service. For the purpose of assessing long-term system performance, it was necessary to make assumptions regarding future load, generation and transmission system developments outside of the Red Deer region, as described in some detail in sections 2.5 to 2.8. Table 2-6 presents the assumptions related to Alberta to BC and Alberta to Saskatchewan (SK) system interchanges. The HVDC line dispatch assumption for 2017 load scenarios is presented in Table 2-7. In Summer High SOK load condition, the SOK-240 flow is set to about 2050MW which is the allowable Total Transfer Capability (TTC) under summer loading condition as defined in OPP520. Based on these assumptions, the 2012WP, 2012SP, 2012SL, and 2012 High SOK scenarios were utilized to assess the performance of potential system reinforcement options and to identify the AESO’s preferred system alternative. The 2017WP, 2017SP, and 2017SL scenarios were utilized to assess long-term system performance. 14 Table 2‐6: Assumptions for Import/Export to BC and SK (MW) 2012 2017 SL SP WP High SOK SL SP WP Import/Export (BC) 600 0 -150 0 600 0 -150 Import/Export (SK) 0 0 0 0 0 0 0 Note: For BC and SK interchange positive amount represents export, while negative sign denotes import. Table 2‐7: Assumptions for HVDC Dispatch in 2017 (MW) 2.5 SL SP WP HVDC Genesee to Langdon 500 375 375 HVDC Heartland to W. Brooks 500 500 500 Load Forecast The 2012 and 2017 load forecasts used in this study are based on Future Demand and Energy Outlook, 2007-2027 and details are given in Appendix titled Red Deer Region Load and Generation Forecasts. Table 2-8 summarizes the load forecast modeled in the 2012 and 2017 technical studies. The load forecasts for areas 35 and 39 included station service load, system load, Behind-the-Fence (BTF) load, and motor load. Table 2‐8: Load Forecast Modeled in Red Deer Region (MW) 2012 SL 2017 SP WP SOK SL SP WP Red Deer 318.9 539 581 321.7 346.1 575.0 653.4 109.1 83 66.3 100.3 114.3 Load (MW) Didsbury 61.2 95.8 15 2.6 Generation Assumptions The existing generation within the Red Deer region is located at the JoffreNova complex and consists of a gas fired combined cycle power plant. The combined cycle plant consists of two gas units and one steam turbine. The rated capacities of these individual units are listed in Table 2-9. Currently there are no projects requesting connection in the Red Deer region (Planning areas 35 and 39). Table 2‐9: Rated Capacity for Existing Generation in the Red Deer Region Name Location Fuel Type Nova -Joffre GT1 Nova Chemicals near Joffre 535S Nova -Joffre GT2 Nova Chemicals near Joffre 535S Nova -Joffre ST2 Nova Chemicals near Joffre 535S Total - Existing Gross Capacity (MW) 185 Gas 185 140 510 Generation forecast assumptions are based on Generation Scenario B3 presented in the AESO Long-term Transmission System Plan9. A description of the generation scenario is included in the Appendix titled Red Deer Region Load and Generation Forecasts. None of the generation scenarios forecast additional generation developing in the Red Deer region in the next ten year. Scenario B3 was chosen for this study as it stresses the transmission system in the study region. The principal reasons for it are listed below. The Red Deer region’s 138kV transmission system is integrated into the 240kV system that runs between the Edmonton and Calgary regions. The SOK cut plane is a part of this 240kV North –South (N-S) system in Central Alberta that transfers power from the Wabamun area generation to loads in Calgary and southern Alberta. Scenario B3 contains a significant amount of base load generation in the Wabamun area and North East areas of the province. Increased generation located North of the Red Deer area (Wabamun and North East areas) will result in increased flows on the SOK N-S 240kV system. Higher SOK N-S flows will result in not only higher potential overloads but also 9 The 2009 AESO Long-Term Transmission System Plan can be found on the AESO website at: http://www.aeso.ca/downloads/AESO_LTTSP_Final_July_2009.pdf 16 under voltages on the 138kV system in the Red Deer region under a number of contingencies. These stress conditions must be addressed in developing transmission plans. Furthermore, the 240kV system is a major source of supply to the Joffre area when the local Nova power plant is out of service. The Red Deer’s regional system must be designed and developed to maintain the established maximum SOK transfer capability level. There is less wind in generation scenario B3 than scenario B5. The impact of wind generation in the Southern and Hanna regions on the Red Deer region’s transmission system is relatively modest because a major portion of it will be consumed in the Calgary, Hanna and the surrounding areas, and any remaining generation will be shipped to the other areas via the 240kV system. Table 2-10 presents summary of the generation dispatch in Red Deer, wind power generation dispatch in the southern and Hanna regions of Alberta. Table 2‐10: Generation Dispatch (MW) Generation Dispatch 2012 SL 2012SP Red Deer area 438 438 510 438 438 438 510 Southern Alberta Wind Power 600 600 600 0 1290 1290 1290 Central Area Wind Power ( Hanna region) 150 150 150 150 300 300 300 2.7 Nova 2017 2012 2017 2012 SOK 2017 SP WP SL WP Facility Ratings Thermal ratings of transmission facilities within the Red Deer region are presented in Table 2-11 and 2-12. Table 2‐11: Transmission Line Ratings in the Red Deer Region Line From Substation 910L 914L 914L 914L 926L/922L 903L/190L 995L 900L 901L 925L/929L Ellerslie 89S Ellerslie 89S Bigstone 86S Gaetz 87S Sundance 821S Keephills 868S Amoco W. G. 68S Benalto 17S Red Deer 63S Red Deer 63S To Substation Red Deer 63S Bigstone 86S Gaetz 87S Red Deer 63S Benalto 17S Benalto 17S Benalto 17S Red Deer 63S Crossfield 64S Janet 74S Voltage (kV) Summer (MVA) Winter (MVA) Emergency (MVA) 240kV 240kV 240kV 240kV 240kV 240kV 240kV 240kV 240kV 240kV 466 481 499 499 466 466 466 584 408 481 499 499 499 499 499 499 499 705 494 499 599 599 599 599 499 499 499 776 494 599 17 Line 912L 906L/928L 918L 716L 80L From Substation Red Deer 63S Benalto 17S Benalto 17S Wetaskiwin 40S Ponoka 331S 883L 80AL Ponoka 331S W. Lacombe 958S 80L 80L W. Lacombe 958S Blackfalds 198S 80L 778L/768L 80L 717L N. Red Deer 217S N. Red Deer 217S S. Red Deer 194S Red Deer 63S 717L 755L 755L 759L 793L/956L 774L 784AL 784L 775L 889L 757L Sylvan Lake. 580S Red Deer 63S Piper Creek 247S Gaetz 87S Gaetz 87S UC Prentiss 276S Ellis 332S Haynes TAP UC Prentiss 276S Joffre 535S Benalto 17S Via 758L JNC Eckville 534S Rocky M.H. 262S Benalto 17S 758L 717L 848L 80L 80L 80L 80L 189L 80L 166L 166L 166AL 719L Red Deer 63S Innisfail 214S Olds 55S Didsbury 152S Madden TAP Madden TAP Didsbury 152S 166L JNC 166L JNC Harmattan 256S To Substation Nevis 766S Sarcee 42S Beddington 162S Ponoka 331S W. Lacombe 958S Nelson L. 429S N.E. Lacombe 212S Blackfalds 198S N. Red Deer 217S S. Red Deer 194S Gaetz 87S Red Deer 63S Sylvan Lake. 580S Benalto 17S Piper Creek 247S Joffre 535S UC Prentiss 276S Joffre 535S Ellis 332S Haynes TAP Joffre 535S Joffre 535S Brookfield 536S Rimbey 297S 758L JNC Benalto 17S Schrader Cr. 531S Innisfail 214S Olds 55S Didsbury 152S Madden TAP Madden 373S Ghost Plant 20S 166L JNC Harmattan 256S Shell H. 238S Eagle TAP Voltage (kV) Summer (MVA) Winter (MVA) Emergency (MVA) 240kV 240kV 240kV 138kV 138kV 499 449 417 122 122 549 499 499 147 147 549 499 499 162 162 138kV 138kV 96 75 96 79 150 87 138kV 138kV 112 122 135 147 135 162 138kV 138kV 138kV 138kV 121 180 174 128 143 220 215 165 157 264 237 182 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 128 120 120 154 154 154 154 154 154 125 85 165 147 147 190 190 190 190 190 190 152 90 182 162 162 209 209 209 209 209 209 167 99 138kV 138kV 138kV 85 112 174 90 135 215 99 149 237 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 138kV 172 122 122 122 75 122 81 78 85 120 172 147 143 143 79 143 122 120 90 143 189 162 157 157 87 157 134 132 99 157 18 Table 2‐12: Transformer Ratings in Red Deer Region Transformer Location HV / LV (kV) Summer (MVA) Winter (MVA) T1/T2 T1/T2 Gaetz 87S Red Deer 63S 240/138 240/138 200 200 200 200 T2 Benalto 17S 240/138 200 200 HV: High voltage; LV Low Voltage 2.8 Transmission Assumptions The system model used for this study included the following bulk system additions for the years indicated. These assumptions are consistent with AESO long term plans, recently approved NIDs for South Area Transmission Reinforcement (SATR), Hanna Region Transmission Development (HRTD), and Central East Transmission Development (CETD). 2.8.1 Bulk System Assumptions Bulk System by 2012 240kV line from Brintnell to Wesley Creek; New 240kV line to the Thickwood substation; New Cache Creek substation located between Ruth Lake and Kinosis substations; 240kV line from the Thickwood substation to Cache Creek; 240kV 600MVA phase shifting transformer at Keephills; Reconfiguration of 946L/947L resulting in one 240kV line from Ellerslie to Clover Bar and one 240kV line from Ellerslie to East Edmonton; 240kV double circuit line from Ellerslie to the new Eastwood substation; and De-bottlenecking project: o New 2x477 Kcmil 240kV lines from Keephills to new 904L – 908L – 909L confluence points; o 908L (Ellerslie – Sundance) re-termination from its existing location at Sundance to the new 904L – 908L – 909L confluence point; o Swap the connections of 904L (Jasper – Wabamun) and 908L at the confluence point so that the 904L termination at Wabamun can be moved to Sundance; and 19 o New 240kV 600MVA phase shifting transformer located at the new Livock substation and on 9L57 (Livock – Dover) and the new 240kV line to the Fort Murray 240kV substation. Bulk System by 2017 New HVDC Lines Developments: ± 500kV, 1000MW, HVDC Monopole line from Genesee to Langdon with associated static VAr compensators (SVC); and ± 500kV, 1000MW, HVDC Monopole line from the new Heartland 500kV substation to the existing 240kV West Brooks with associated SVCs. New Substations: 500kV Heartland substation; and 500kV Thickwood substation. New Transmission Lines: 2.8.2 500kV AC line from Ellerslie to Thickwood via Heartland; and 500kV AC line from Ellerslie to Heartland. Hanna Region System Assumptions The following assumptions include upgrades and/or additions that are proposed to be in place by 2012 and 2017 in the Hanna region: System Reinforcements by 2012: Single circuit 240kV line from Hansman Lake 650S to a new substation Pemukan 932S; Single circuit 240kV line from Pemukan 932S to a new substation Lanfine 959S; First 240kV line from Oakland 946S to Lanfine 959S; Double circuit 240kV line from Anderson 801S to Oakland switching station 946S; Split 240kV line 953L mid-way between Cordel 755S and Hansman Lake 650S and build a 240kV line using in and out configuration at a new 240/138kV substation Nilrem 574S (Nilrem 138kV bus will be tied to the newly added Tucuman 478S); (-100/200MVAr) SVC at Hansman Lake 650S, and (100/200MVAr) SVC at Lanfine 959S. New 240kV line between Ware Junction 132S and West Brooks 28S; 20 New 240/144kV collector substation Coyote Lake 963S in the Hand Hills area; and New 240kV line (9L29) between Coyote Lake 963S and Oakland 946S on double circuit structures with single side strung. System Reinforcements by 2017: 2.8.3 Second 240kV line from Oakland 946S to Lanfine 959S; Second 240/138kV tie transformer at Hansman Lake 650S; 2x27MVAr 138kV capacitor banks at new Nilrem 574S; 2x36MVAr 240kV capacitor banks at Hansman Lake 650S; 27MVAr 138kV capacitor bank at Hansman Lake 650S; 27MVAr 138kV capacitor bank at Metiskow 648S; and ( -100/200 MVAr)SVC at Pemukan 932S. Second side strung on planned D/C towers (9L31 240kV line) between Coyote Lake 963S and Oakland 946S; and New 240kV line between Halkirk switching station 401S and Cordel 755S. Central East Region System Assumptions System Reinforcement by 2012 Conversion of existing 72kV St. Paul and Willingdon to 144 kV Substations Cold Lake Area Reinforcements o A new 240kV switching station designated Bourque 970S o A new double circuit 144kV line (< 2 km) from Bourque 970S to Mahihkan 837S o A new double circuit 240kV line (approximately 50 km in length) from Bourque 970S to Bonnyville 700S, o Re-build the single circuit 144kV line 7L87 o Re-build the single circuit 144kV line 7L74 o Re-build the single circuit 144kV line 7L83 Provost & Lloydminster Areas Line Rebuilds o Rebuild the single circuit 144kV line 7L749 from Edgerton 899S to Lloydminster 716S o Build a new single circuit 138kV line (approximately 30 km in length) from Provost 545S to Hayter 277S o Rebuild the single circuit 138kV line 748L from Hayter 277S to Killarney Lake 267S o Rebuild the single circuit 138kV line 715L from Hansman Lake 650S to Provost 545S o Rebuild the single circuit 138kV line 715L from Metiskow 648S to Edgerton 899S 21 Wainwright Area Upgrades o Build a new single circuit 138kV line (approximately 40 km in length) on the existing 69kV line right-of-way from Wainwright 51S to Edgerton 899S o Rebuild the single circuit 138kV lines 704L and 704AL between Wainwright 51S, Tucuman 478S and Jarrow 252S Line Clearance Mitigations 7L14, 7L701, and 7L53 Battler River & Lloydminster Areas Reinforcements 25MVAr capacitor bank at Vermilion 710S. System Reinforcement by 2017 2.8.4 Rebuild 7L50 using 1x477 Kcmil ACSR and single circuit construction from Battle River 757S to Buffalo Creek 526S Build a new double circuit 240kV line (with one circuit strung initially) from Bourque 970S to Marguerite Lake 826S using 2x795 Kcmil ACSR conductors per phase. This line will be initially operated at 144kV. Southern Alberta Transmission Reinforcements (SATR) The following assumptions include upgrades and/or additions that are expected to be in place by 2012 and 2017 in southern Alberta: System Reinforcements by 2012: Replace the existing 240kV 911L (Langdon 102S to Peigan 59S) by Calgary South–Peigan 240kV double circuit transmission line with 50% series compensation; New 150 (2x-75MVAr) shunt reactor at Peigan 59S; Milo Junction upgrade to Switching Station to tie in 924L, 927L, 923L and 933L; New 120MVA Phase Shifting Transformer on 170L Coleman to Natal; New 240kV substation Whitla 251S (Sub D) close to the Burdette substation; New 240/138kV Medicine Hat 2 substation; Whitla 251S (Sub D) – Medicine Hat2 240kV double circuit transmission line; New 240kV double circuit line from West Brooks to the new Whitla 251S (Sub D) substation; and Medicine Hat 138kV changes/upgrades. 22 System Reinforcements by 2017: 2.9 500kV Chapel Rock 491S substation located on the existing 500kV 1201L with two 500/240kV 1200MVA transformers and one 240kV 400MVAr SVC; 240kV double circuit transmission line from Chapel Rock 491S to Goose Lake; 240kV single circuit transmission line from Goose Lake to Journault 260S (Sub C); 240kV single circuit transmission line from Journault 260S (Sub C) to MATL substation; and 240kV double circuit transmission line from Journault 260S (Sub C) to Whitla 251S (Sub D). System Inter Dependencies The Red Deer Region development is mainly intended to address local system constraints and hence it is classified as a local development. Its development is not dependent upon other projects. However, customers like the City of Red Deer and Joffre area depend upon the implementation of this project. 23 3.0 Existing System Assessment The AESO carried out power flow analysis for the existing system (i.e., without any system reinforcements in the region) to assess whether the system can supply forecasted demand in the year 2012 in accordance with Reliability Criteria requirements. Three load conditions, namely, 2009 Winter Peak (2009WP), 2012 Winter Peak (2012WP) and 2012 Summer High SOK flow cases were studied to assess load supply adequacy, and impact of High SOK flows on the existing system. Category B contingencies, including N-G-1, were investigated. For this analysis, Nova Joffre cogeneration plant was taken out of service during 2012WP condition. A list of key contingencies is presented in Attachment A. The following sections provide a description of the study region and discussion of need assessment results. A set of representative power flow plots that show reliability criteria violations is included in Attachment A. 3.1 Power Flow Analysis 3.1.1 Load Supply Adequacy Load supply adequacy scenario investigates the ability of the transmission system to meet expected load growth in the Red Deer region. Load supply adequacy was investigated using both 2009WP and 2012WP load scenarios. The analysis showed that the system sustained low voltage profile around Blackfalds, Innisfail and Didsbury areas under certain Category B contingencies. When Nova Joffre cogeneration power plant is out of service, Joffre loads are supplied by the generation outside the Red Deer region and the Joffre area loses a local source for reactive power support. The voltage support in the Joffre area becomes the main concern in such conditions and hence affects the Joffre inflow limits. The analysis showed that the voltage level in the Joffre area is lower than the minimum operating voltage stipulated in OPP 70210. Furthermore, the voltages during 2012WP conditions deteriorated compared to already low voltage levels observed in the 2009WP case due to load growth in the area. In addition to voltage criteria violations, the following transmission elements are overloaded under a number of contingencies: 240/138kV autotransformer at Benalto 17S; 138kV 80L line (N. Red Deer 217S through S. Red Deer 194S to Red Deer 63S); 10 OPP 702 Voltage Control Procedure can be found on the AESO website. 24 138kV 755L line (Red Deer 63S to Piper Creek 247S); 138kV 756L/793L line (Gaetz 87S to N. Red Deer 217S); and 240/138kV autotransformer at Gaetz 87S and Red Deer 63S. 3.1.2 High SOK Cut Plane Flows In Alberta, a large part of the provincial load is located in southern Alberta, including the City of Calgary, yet the mass of coal generation is situated in northern Alberta, Edmonton area. As a result, a significant amount of power has to be transferred via the north-south 240kV transmission path (SOK cut plane) between Edmonton and Calgary. Transmission system thermal overloads during high SOK flow conditions were investigated using 2012 Summer High SOK flow scenario. The following transmission lines are overloaded under a number of critical Category B Contingencies: 138kV 80L (N. Red Deer 217S through S. Red Deer 194S to Red Deer 63S); 138kV 80L (Innisfail 214S to Olds 55S); 138kV 755L (Joffre 535S to Piper Creek 247S) ; and 138kV 717L (Sylvan Lake 580S to Red Deer 63S). 3.2 Voltage Stability Analysis Voltage stability analysis (both P-V and Q-V) was performed using the 2012WP scenario with Nova Joffre cogeneration plant out of service, to determine the system reactive margin and maximum operation load limits before the voltage drops below 0.95 p.u. following contingency conditions. The summary of P-V analysis for the existing system is presented in Attachment A. The P-V analysis reveals that the system does not have sufficient capability to transfer additional power to the Red Deer and Joffre areas. Any incremental change in real power transfer will cause the voltage to drastically drop below 0.95p.u. Such low voltage will affect motor load operation in this area. Similar conclusion can be drawn from Q-V analysis which is presented in Attachment A. The positive reactive power margin observed at Joffre 535S, Ellis 332S, Blackfalds 198S, and Innisfail 214S substations suggest deficiency in reactive power. Hence suitable measures must be taken to 25 provide reactive power support to improve the voltage profile in the Joffre area, in and around Blackfalds and Innisfail areas along the 138kV 80L. 3.3 Transfer Capability Analysis Transfer capability is a measure of the ability of the transmission system to reliably transfer electric power from one area (the source) to another area (the sink) by the way of all transmission lines between those areas under specific system condition. First Contingency Incremental Transfer Capability (FCITC) is used to evaluate the transfer capability. FCITC is defined as the amount of electric power, incremental above normal base power transfers that can be transferred over the interconnected transmission systems in a reliable manner. A negative FCITC indicates that the system has no room for additional transfer following first contingency. The transfer out analysis for 2012WP, 2012SP, 2012SL, and 2012S-SOK load conditions were conducted based on the following assumptions: The generation source is Wabamun ( Area 40); Calgary is the sink; All the AIES facilities within the Red Deer region were monitored; and Category B contingencies for all the AIES facilities within the Red Deer region and tie lines in the region were examined. Table 3-1 presents a summary for the FCITC for the existing system. As depicted in Table 3-1, the following transmission elements located in the Red Deer region will limit the transfer capability between North and South Systems. 240/138kV Transformer T2 at Benalto 17S 138kV 80L(Innisfail 214S to Olds 55S) 138kV 80L(N. Red Deer 217S to S. Red Deer 194S) 138kV 755L (Joffre 535S to Piper Creek 247S) The negative values shown in Table 3-1 indicate that the system has no capability to transfer any incremental power since there are already limiting transmission elements that are overloaded under normal conditions. 26 Table 3‐1: First Contingency Incremental Transfer Capability (FCITC) for the Existing System Case FCITC (MW) -391 2012WP 830 1193 -10 2012SP 36 207 -295 2012SL -23 285 -5881 2012SSOK -4565 -1002 3.4 Limiting Element (Red Deer Region) 240/138kV Transformer T2 at Benalto 17S 240kV 900L(Red Deer 63S to Benalto 17S) 138kV 80L(Red Deer 63S to Innisfail 214S) 138kV 80L(Innisfail 214S to Olds 55S) 240/138kV Transformer T2 at Benalto 17S 138kV 778L(Gaetz 87S to 787LSKP1) 138kV 80L(N. Red Deer 217S to S. Red Deer 194S) 138kV 778L(Gaetz 87S to 787LSKP1) 138kV 80L(Red Deer 63S to Innisfail 214S) 138kV 778L(Gaetz 87S to 787LSKP1) 138kV 755L(Piper Creek 247S to Joffre 535S) 138kV 80L(N. Red Deer 217S to S. Red Deer 194S) Contingency 240kV 900L(Red Deer 63S to Benalto 17S) 240kV 918L(Benalto 17S to Beddington 162S) 138kV 719L (Sundre 575S to Shell Caroline 378S) 138kV 719L (Sundre 575S to Shell Caroline 378S) 240kV 900L(Red Deer 63S to Benalto 17S) 240kV 914L(Gaetz 87S to Red Deer 63S) 240kV 914L(Gaetz 87S to Red Deer 63S) 240kV 914L(Gaetz 87S to Red Deer 63S) 138kV 719L (Sundre 575S to Shell Caroline 378S) 138kV 755L(Piper Creek 247S to Joffre 535S) 138kV 778L(Gaetz 87S to 787LSKP1) 138kV 755L(Piper Creek 247S to Joffre 535S) Short Circuit Analysis Short circuit analysis was performed on the 2012WP load scenario to determine the fault levels in the existing system. Both three phase and single phase to ground fault currents were calculated for substations in the Red Deer region. The results of the short circuit analysis are presented in Attachment A.11 3.5 Existing System Need Assessment Summary The detailed analysis of the existing system as described in the above subsections (see 3.1 to 3.4) led to the following conclusions: 11 Short circuit current calculation is based on modeling information provided to the AESO by third parties. Short circuit estimation is subject to change. The information provided in this study is not intended to be used as the sole source of information for electrical equipment specification and the design of public or worker safety-grounding systems. 27 The existing 138kV transmission system in the Red Deer region is near its capacity and will not be able to reliably supply forecasted load to customers without reinforcements; The Joffre area would continue to be subjected to operational measures (OPP 502) under certain contingencies if the transmission system is not reinforced; The portion of the existing 138kV 80L that traverses the Red Deer region is subject to severe thermal overloads under a number of credible contingency conditions; The Blackfalds, Innisfail and Didsbury areas require reactive power support to maintain normal voltages under Category B conditions; and Reactive power support is also required under both Category A and Category B events in the Joffre area when Nova Joffre cogeneration plant is out of service. To address the above identified transmission system needs within the Red Deer region, the AESO identified potential alternatives to relieve the transmission constraints and screened them down to two technically viable alternatives that were studied in detail. Attachment C contains description of these alternatives for the Red Deer region. 28 4.0 Development of System Reinforcement Options The need for reinforcements in the Red Deer region has been established in Section 3. The next steps are to examine available transmission technologies and determine their suitability of implementation in the Red Deer region, formulate a set of study alternatives using suitable transmission technologies, screen the preliminary alternatives and determine an appropriate and manageable set of alternatives which can be studied further. 4.1 Transmission Technology Options Screening The potential options for the Red Deer region transmission development include: Developing new transmission lines Upgrading and/or rebuilding existing transmission lines Conversion of existing 138kV transmission to 240kV system Building new transmission substations and associated facilities Providing reactive power support Consideration of operational measures The following subsections discuss potential transmission options for the Red Deer region. 4.1.1 New Transmission Lines Building new transmission lines is one of the viable transmission options to solve thermal overload and voltage range violation problems provided that right-of-ways are available to accommodate these new transmission lines. Power systems around the globe use a variety of transmission technology options to meet their needs. These include Extra High Voltage 765kV, 500kV Alternating Current (AC) & High Voltage Direct Current (HVDC) technologies in addition to 240kV and 138/144kV voltage levels. In Alberta, both 500kV AC and HVDC technologies are being considered as potential options for development of the bulk system. The 765kV, 500kV AC and HVDC technologies are well suited to situations where large quantities of power need to be transported over long distances. Since the amount of power transfers and the transmission distances in the Red Deer region are far below the typical levels used for such options, these technologies are not suitable for the 29 Red Deer region transmission plan. Therefore, these options will not be pursued any further, leaving only lower voltage level options (i.e., 240kV and 138kV lines). The transmission system in the Red Deer region primarily consists of 138kV AC transmission lines with three 240/138kV substations at Benalto 17S, Red Deer 63S and Gaetz 87S. Therefore, these two voltages form a prudent choice for new transmission lines in this area. When considering new transmission lines, single-circuit as well as double circuit designs will be explored as potential options for the area. Candidate new transmission lines include: New 240kV line between Joffre 535S and Red Deer 63S to replace existing 138kV line; and New 138kV line between Ellis 332S to N.E. Lacombe 212S. Transmission Line Upgrades and Rebuild12 4.1.2 Transmission line upgrade and/or rebuild options helps mitigate thermal overloads on certain lines in the Red Deer region that were identified in the Need Assessment. This option is valid for the existing transmission lines and potentially avoids the need for acquiring new rights-of-way. However, a temporary right of way maybe necessary during the construction phase. The following 138kV lines are candidates for the transmission line upgrades The following sections of 80L o 80L ( S. Red Deer 194S to N. Red Deer 217S); o 80L ( S. Red Deer 194S to Red Deer 63S); o 80L ( Blackfalds 198S to W. Lacombe 958S); o 80L ( Blackfalds 198S to N. Red Deer 217S); o 80AL ( N.E. Lacombe 212S to W. Lacombe 958S); 12 The AESO uses the term “rebuild” in this Application as part of the identification of transmission system developments required to address an identified need. The term “rebuild” means that an existing connection between two points will be modified in some manner. The needs identification documents do not identify locations of proposed facilities. The legal owner of transmission facilities will identify in its facility application(s) proposed locations for facilities to be rebuilt, which may be in existing locations or in new locations. 30 716L (Wetaskiwin 40S to Ponoka 331S); 717L (Red Deer 63S through Sylvan Lake 580S to Benalto 17S); 755L (Red Deer 63S through Piper Creek 247S to Joffre 535S);and 166L (Didsbury 152S to Harmattan 256S) 4.1.3 Voltage Up-Rating Voltage up-rating from 138kV to 240kV can increase the capacity of the transmission line under consideration by the ratio of the two voltage level. Up-rating of existing 138kV transmission circuit requires adding transformation capacity at both ends of the line and detailed assessment of the existing transmission line under consideration. The voltage up-rating from 138kV to 240kV may require completely rebuilding the line. The following lines are candidates for voltage upratings 755L(Red Deer 63S through Piper Creek 247S to Joffre 535S) 717L (Red Deer 63S through Sylvan Lake 580S to Benalto 17S) 4.1.4 Build New Transmission Substations and Upgrade Existing Stations The Red Deer region is supplied from three 240/138kV substations, namely, Benalto 17S, Red Deer 63S, and Gaetz 87S. Due to load growth, addition of transformation capacity is required to alleviate thermal overloads and provide voltage support in the region as outlined in the Need Assessment stage. Voltage profile and thermal overloads along 80L that traverses the Red Deer region can be improved by building a number of new 240/138kV transmission substations along with associated facilities. These proposed transmission substations will add additional ties between the 240kV and the local 138kV system. Application of this transmission option can minimize the required upgrades on 80L lines. The following locations are potential candidates for upgrading existing 138kV substations and building new 240/138kV substations: Ponoka 331S, Blackfalds 198S, Innisfail 214S, Benalto 17S, N.E. Lacombe 212S, Olds 55S, and Didsbury 152S. 4.1.5 Provide Reactive Power Support Equipment The Need Assessment has identified that reactive power support is required for the Joffre area as well as other locations along 80L line around Innisfail 214S, Blackfalds 198S and Didsbury 152S under a number of contingencies. The required reactive power support can be 31 supplied by a variety of VAr supply device(s) such as shunt capacitors and Static VAr compensators (SVCs). Potential locations for VAr support devices include the following locations: Gaetz 87S; Joffre 535S; UC Prentiss 276S; Ellis 332S; Innisfail 214S and Didsbury 152S. 4.1.6 Consideration of Operational Measures Operational measures are considered when AESO Transmission Reliability Criteria are violated under Category C contingencies and also under certain special circumstances. Under these contingencies, Remedial Action Schemes will be developed to manage these contingencies. These schemes may include operational measures such as shedding of non firm loads; generation re dispatch and/or curtailment, network reconfiguration and a suitable combination of these are employed. 4.2 Formulation and Screening of Red Deer Alternatives This section presents the analysis conducted during phase 2 of the planning process which involves development and screening of alternatives for further evaluation based on detailed technical, economic and social impacts considerations. Throughout the course of formulating these alternatives, AltaLink played an active role and provided their comments and suggestions. In addition, the Hanna region, SATR, and Central East developments have been fully integrated into this region to maximize their combined effect on the overall system. The following subsections identify possible alternative solutions that could address each of the constraints identified in Section 3. The formulation of study alternatives consisted of combining a variety of technology options outlined in Section 4.1. The proposed alternatives will help resolve system performance issues that have been already identified and aim to achieve the following: Identify reinforcements that will meet load supply adequacy requirements up to 2017; Provide adequate reactive power support to the area and identify type of VAr support devices and their locations for mitigating existing voltage issues (e.g. voltage violations in the Joffre area when Nova Joffre cogeneration plant is out of service); Eliminate the OPP 502 and provide sufficient Total Transfer Capability in and out of the Joffre area; Ensure proper operation of the system under high SOK power flow conditions; and Ensure adequacy of operational measures to handle critical system contingencies. 32 Three alternatives were developed and then were reduced to two based on high level technical analysis, engineering judgment and consideration of rights-of-way. The three alternatives have common developments that meet load supply adequacy requirements but represent three different approaches to address the need to reinforce multiple sections of 80L that experience thermal overloads under high SOK conditions. Alternative 1 proposes upgrading the 80L sections to alleviate the overload on those sections. Alternative 2 proposes adding two new 240/138kV substations at Ponoka and Innisfail areas and salvaging 80L line sections (Ponoka 331S to W. Lacombe 958S) and (Red Deer 63S to Innisfail 214S) and Salvaging 716L (Wetaskiwin 40S to Ponoka 331S). Alternative 3 proposes a new double circuit line between Gaetz 87S and Piper Creek 247S and circuit reconfiguration of the existing lines to form two separate 138kV loops one is for feeding the Joffre area and the other one is for feeding the City of Red Deer. 4.2.1 Common Set of Transmission System Development This section highlights the common set of transmission system development for all three study alternatives. The ensuing three sections present details on the three proposed alternatives, which differ mainly in handling upgrades required for 80L line and how to manage Joffre inflow and outflow limitations. The common transmission elements required for the Red Deer region is shown in Table 4-1 and Figure 4-1. The following transmission reinforcements are required to meet supply load adequacy: 1. The 138kV 768/778L is a double circuit (D/C) line but the ends of these lines are tied together to make it as a single line. Consequently, the end section of line gets overloaded under several contingencies and thus limits the capacity of the double circuit line. The line could be restored to its original D/C status by splitting the end sections and terminating each line on an individual breaker. This will enable the Nova Joffre cogeneration plant to operate at full output. This development is required as soon as possible, since this is a current operating problem being managed under OPP 502. 2. A new substation (240/138kV) at Didsbury is required to provide local voltage support to Didsbury and surrounding area loads. The station will tie into the 240kV network via in/out arrangement with 918L. The existing 138kV Didsbury substation 33 152S and associated infrastructure will be salvaged. The new substation’s 138kV bus will be connected to the existing 80L sections going to Olds 55S and Ghost 20S13, and the 166L to Harmattan 256S. 3. A new transmission line from Ellis 332S to N.E. Lacombe 212S will provide voltage support to the Blackfalds area loads under the loss of 80L segment Blackfalds 198S to N. Red Deer 217S. 4. Rebuild 80L (S. Red Deer 194S to N. Red Deer 217S). The capacity of 80L line segment is thermally limited (121/143MVA) and needs to be upgraded to meet the future load growth. 5. Rebuild 166L (new Didsbury substation to Harmattan 256S): This line has limited capacity and needs to be upgraded to eliminate thermal overloads associated with load growth in this area. The following transmission reinforcements are required to meet load supply adequacy when Nova Joffre cogeneration plant is out of service: 1. A second Transformer at Benalto 17S will help mitigate thermal overload on the existing transformer at Benalto 17S under certain Category B contingencies including the loss of 900L. 2. Shunt capacitor banks at Joffre 535S, UC Prentiss 276S and Ellis 332S will provide reactive power support when Nova Joffre plant is out of service and also to compensate for additional MVAr losses caused by higher MW import from the system to the Joffre area. 3. Rebuild the existing 138kV 717L line (Red Deer 63S through Sylvan Lake 580S to Benalto 17S) will address the 717L thermal overload encountered under the loss of 240kV 900L. 13 The 80L sections: New Didsbury to Olds 55S and New Didsbury to Ghost 20S to be renumbered as 417L and 418L respectively. 34 Figure 4‐1: Schematic of the Common Set of Transmission System Developments 35 Table 4‐1: List of the Common Set of Transmission System Developments Name Voltage kV Capacity (MVA) Transmission Option Required Year Load Supply Adequacy Requirements 1 768L/778L split and add circuit breakers to North Red Deer 217S and Gaetz 87S 2 Didsbury 240kV transformer 3 138 180/220 Rebuild ASAP 138/240 200MVA New 2012 New 138kV transmission line (N.E. Lacombe 212 to Ellis 332) 138 252/314 New 2012 4 Rebuild 80L line ( S. Red Deer 194S to N. Red Deer 217S) 138 350/450 Rebuild 2012 5 Rebuild 166L Line from new Didsbury substation to Harmattan 256S 138 252/314 Rebuild 2017 Load Supply Adequacy- When Nova Joffre cogeneration plant is out of service 1 2nd autotransformer at Benalto 17S 138/240 2.a Joffre 535S – add 50 MVAr capacitor bank 138 2.b UC Prentiss 276S – add 50MVAr capacitor bank 2.c 3 200MVA New 2012 N/A New 2012 138 N/A New 2012 Ellis 332S – add 25 MVAr capacitor bank 138 N/A New 2012 Rebuild 717L line(Red Deer 63S through Sylvan Lake 580S to Benalto 17S) 138 252/314 Rebuild 2012 36 4.2.2 Alternative 1 Development (80L Alternative) As discussed in Section 3, the 80L line which traverses the Red Deer region from north to south needs major upgrades to ensure reliable performance under load supply adequacy and high SOK conditions. Alternative 1 proposes the following developments: Rebuild most sections of the existing 138kV 80L as well as 716L to avoid thermal overloads during High SOK flow conditions, and Rebuild 755L (Red Deer 63S through Piper Creek 247S to Joffre 535S) to higher capacity. The benefits of this line upgrade are: provide extra transfer capability between the Joffre and Red Deer areas which will help alleviate flow limitation of the Joffre area. Table 4.2 lists the detailed upgrades required for Alternative 1 excluding common set of transmission development presented in Table 4-1. Figures 4-2 and 4-3 depict the transmission network structure following the implementation of Alternative 1. 37 Table 4‐2: 2012 List of Alternative 1 Development Excluding Common Set of Transmission System Developments Name 14 Voltage kV Capacity (MVA)14 Transmission Option Operating Year 1 Rebuild 80L( Blackfalds 198S to W. Lacombe 958S) 138 252/314 Rebuild 2012 2 Rebuild 80L(Blackfalds 198S to N. Red Deer 217S) 138 252/314 Rebuild 2012 3 Rebuild 80L(Ponoka 331S to W. Lacombe 958S) 138 252/314 Rebuild 2012 4 Rebuild 80L( Red Deer 63S through Innisfail 214S to Olds 55S) 138 252/314 Rebuild 2012 6 Rebuild 80L( S. Red Deer 194S to Red Deer 63S) 138 350/450 Rebuild 2012 7 Rebuild 716L (Wetaskiwin 40S to Ponoka 331S) 138 252/314 Rebuild 2012 8 Rebuild 80AL( N.E. Lacombe 212S to W. Lacombe 958S) 138 252/314 Rebuild 2012 9 Rebuild 755L( Red Deer 63S through Piper Creek 247S to Joffre 535S) 138 252/314 Rebuild 2012 Expressed in the following format (Summer/Winter) rating 38 Figure 4‐2: Schematic of Red Deer Region Transmission System Upgrades‐ Alternative1 39 Figure 4‐3: Map of Red Deer Region Transmission System Upgrades‐ Alternative 115 15 This map shows the general areas where the AESO has identified the need for potential transmission system developments. This map does not identify actual line routes and substation locations. Line routes and substation locations will be determined when specific facility proposals are prepared. 40 4.2.3 Development of Alternative 2 (Hybrid Alternative) Discussion with AltaLink revealed that rebuilding of major portion of 80L is beset with a number of challenges which include acquiring new right-of- ways since this line was built on cross country and difficulty of scheduling line outages during construction period in a timely manner. To minimize the required upgrades for 80L, a number of 240/138kV transformer stations along 80L line path were considered. The AESO carried out an optimization study to identify the suitable number and locations of 240/138kV substations to minimize the upgrades to 80L. These optimization studies showed that the addition of two (2) 240/138kV substations, at Ponoka and Innisfail, would be adequate to serve the long–term needs of these areas. Furthermore, the 80L sections from Ponoka 331S to W. Lacombe 958S and Red Deer 63S to Innisfail 214S could be salvaged as they are no longer needed for transmission purposes. Additional Substations Two new (240/138kV) substations are required at Ponoka 331S and Innisfail 214S. The new substations will not only provide support to boost voltage profile in and around the Ponoka and Innisfail areas but more importantly enable them to serve the load growth over the long – term because they are directly tied to the bulk supply system. Salvage of Transmission Lines16 The addition of the above two 240/138kV substations will allow salvage of the following 80L/716L line sections which total to approximately 100 km of line as follows: 716L (Wetaskiwin 40S to Ponoka 331S), 80L (Ponoka 331S to W. Lacombe 958S), and 80L (Red Deer 63S to Innisfail 214S). 80L Upgrades The following 80L upgrades are required to avoid thermal overloads under high SOK flow conditions Rebuild 80L( S. Red Deer 194S to Red Deer 63S) 16 The AESO uses the term “salvage” in this document to mean that an existing transmission facility is no longer required for the transmission system and that its operation will be discontinued. The subsequent use of "salvaged" facilities and existing rights-of-way will be determined by the legal owner of transmission facilities when preparing their facility proposal(s), which will be filed with the Commission for approval. 41 It should be noted that only a short segment of 80L is to be upgraded compared to almost entire 80L in Alternative 1. 755L Upgrade Rebuild 755L (Red Deer 63S through Piper Creek 247S to Joffre 535S) to higher capacity. The benefit of this line upgrade is to provide extra power transfer capability between Joffre and Red Deer areas which will help alleviate the existing flow limitation of the Joffre area. Table 4-3 summarizes the proposed development of Alternative 2 excluding common set of transmission development presented in Table 4-1 and Figures 4-4 and 4-5 depict the transmission network structure following the implementation of Alternative 2. Table 4‐3: List of Reinforcements Excluding Common Set of Transmission System Developments‐ Alternative 2 (Hybird Alternative) 1 2 3 4 Name Voltage Level Capacity (MVA) Transmission Option Operating Year Connect new Ponoka sub to 240kV 910 L via in /out configuration 240/138 2x100MVA new 2012 Connect new Innisfail sub to 240kV 918 L via in /out configuration 240/138 200MVA new 2012 Salvage 138kV 716L (Wetaskiwin 40S to Ponoka 331S) 138 NA Salvage TBD Salvage 138kV 80L (Ponoka 331S to W. Lacombe 958S) 138 NA Salvage TBD 138 NA Salvage TBD 5 Salvage 80L ( Red Deer 63S to Innisfail 214S) 6 Rebuild 138kV 80L( S. Red Deer 194S to Red Deer 63S) 138 350/450 Rebuild 2012 Rebuild 755L( Red Deer 63S through Piper Creek 247S to Joffre 535S) 138 252/314 Rebuild 2012 7 42 Figure 4‐4: Schematic of Red Deer Region Transmission System Upgrade ‐ Alternative 2 43 Figure 4‐5:Schematic of Red Deer Region Transmission System Upgrade ‐ Alternative 217 17 This map shows the general areas where the AESO has identified the need for potential transmission system developments. This map does not identify actual line routes and substation locations. Line routes and substation locations will be determined when specific facility proposals are prepared. 44 4.2.4 Development of Alternative 3 (Double Loop Alternative) Alternative 3 proposes a new 138kV double circuit line between Gaetz 87S and Piper Creek 247S substations. This helps to create two new 138kV loops as shown in Figure 4-6. To facilitate the double loop, the 80L from Blackfalds will be connected to 768L instead of terminating it at North Red Deer 217S. The first loop consists of connecting N. Red Deer 217S to Piper Creek 247S with one of the new circuit of the double circuit lines between Gaetz 87S via 778L. The second loop is formed by connecting Gaetz 87S via second circuit of the new Double circuit line to Joffre 535S (note this line no longer passes through Piper Creek 247S). The first loop is formed to feed the City of Red Deer and the second loop is formed to feed the Joffre area. This Alternative was eliminated for the following reasons and hence will not be pursued further: New rights-of-way are required between Gaetz 87S and Piper Creek 247S substations for the proposed 138kV double circuit transmission line; The Red Deer and Joffre areas will be separated by the creation of independent loops that will be fed from the 240 kV Gaetz substation (see Figure 4-6). This configuration of lines will degrade the reliability of supply to both areas; This alternative did not alleviate overload on 80L line and hence upgrading of 80L is still needed thereby increasing the cost; and A third transformer at Gaetz 87S is required because of thermal overload caused by the proposed configuration. 4.2.5 Summary of Screening of Alternatives Three potential alternatives were formulated and evaluated based on technical considerations and feasibility. Alternative 3, though feasible, was eliminated because of need for new right-of ways, the need for additional equipment which could drive up costs, and the degradation of reliability in both the Red Deer and Joffre areas. Hence only Alternatives 1 and 2 will be studied in detail to determine their relative technical performance for use in selecting a final one. 45 Figure 4‐6: Schematic of Red Deer Region Transmission System Upgrade ‐ Alternative 3 46 5.0 Transmission Alternatives- Near Term Assessment (2012) This section summarizes the results of the detailed technical studies carried out to evaluate the relative performance of Alternatives 1 and 2 for meeting the projected load growth over the planning period 2008-2017. 5.1 Power Flow Analysis (2012) Power flow analysis for Alternatives 1 and 2 was carried out for 2012 under winter peak, summer peak, summer light, high summer SOK flow conditions. Generation Scenario B3 along with the existing generation was modeled in these power flow analyses. A total of 37 Category B contingencies for Alternative 1 and 39 Category B contingencies for Alternative 2 were simulated to evaluate the system performance. Nova Joffre cogeneration plant was identified as the critical generating station in the area for the purposes of the load supply adequacy study as it is the only generation station within the Red Deer region. With the Red Deer region reinforcements in-service by 2012, the loads in the Joffre area will be supplied from power plants in the Wabamun and Drayton areas via 928/922L, 903/190L, 910L, 914L, 900L and 995L respectively when the Nova Joffre cogeneration plant is out of service. Attachment D presents power flow plots for the load flow studies carried out for Category A and B, in 2012 for Alternatives 1 and 2. These power flow plots have been identified by the study year and contingency. A summary table outlining the power flow plots is also included. Simulation results reveal that the two alternatives satisfy voltage range and deviation requirements without any thermal overloads for both Category A and B contingencies. Thus the proposed alternatives meet the Reliability Criteria for 2012 forecast load as shown in Table 5-1. Table 5‐1: Power Flow Analysis Results – 2012 Alternative Thermal Loading Violations Voltage Range Violations Alternative 1 None None Alternative 2 None None 47 5.1.1 System Performance under Category C and D Contingency Events The system performance for the recommended plan (Alternative 2) was tested using power flow analysis for a selected number of Category C and D contingencies. The power flow plots for Category C and D contingencies for year 2012 are presented in Attachment D. Summary of system performance under Category C and D contingencies are also tabulated in Attachment D. Tables D-2012-7 to D-2012-20 of Attachment D list figure numbers of power flow plots for Category C and D contingency events. Overall, performance of Alternative 2 for the Red Deer region is satisfactory and met the Reliability Criteria for 2012 load conditions. However, it should be noted that for Category C, the worst case N-1-1 contingency involves losing both 928/906L (Benalto 17S to Sarcee 575S), which would cause overloads on 918L (Benalto 17S to new Didsbury substation) by 16% of its summer rating; for Category D, the worst case involves loss of 240kV bus and related 240kV lines at Benalto 17S. In some extreme contingency conditions, shedding of the load or tripping some generation are necessary to alleviate overloads observed under these circumstances. This is accomplished in compliance with the AESO Transmission Reliability Criteria. 5.2 Transient Stability Studies (2012) Transient stability studies for both Alternatives 1 and 2 were conducted using 2012SL and 2012WP load conditions as these load conditions stress the system. Over eighty (80) Category B contingencies, eighteen (18) C3 contingencies, seventeen (17) C5 contingencies, thirty (30) C7 contingencies and over twenty-five (25) D8 contingencies were simulated. The following categories of system parameters in the Red Deer and neighboring areas are included in the output channels for monitoring system performances during the transient simulations: Active and reactive powers, terminal voltages and “speeds” of generator’s bus voltages at 240kV and 138kV levels Bus frequencies Power flows on major 240kV and 138kV transmission lines Motor loads and motor load bus voltages 48 All simulation results are presented in Attachment E. The results of the transient stability analyses are summarized below: The AIES system is stable for all simulated Category B, C3, C5 and C7 contingency events For Category D contingency events, there is only one contingency, namely, loss of Benalto 240kV substation under winter peak load condition that caused system to be unstable. The substation is one of the major 240kV substations in AIES system with eight 240kV transmission lines connected. Remedial Action Scheme is required to manage this contingency. No loss of load is anticipated except for those tripped due to the radial network configuration such as Rimbey 297S and Nelson Lake 429S connected loads. 5.3 Voltage Stability (P-V and Q-V) Analysis Voltage stability (P-V and Q-V) analysis were also performed to determine the ability of the proposed system based on Alternatives 1 and 2 to be voltage stable under normal and abnormal system conditions. Moreover, these studies were used to calculate the reactive power margins available under Category B contingency events. This information was used to ensure that the reactive power compensation recommended is adequate under normal and contingency conditions. The results of these P-V and QV analyses are presented in Attachment D. The results reveal that the system is voltage stable and meets the AESO Voltage Stability Criteria. 5.4 Transfer Capability Analysis The transfer analysis was repeated for the proposed Alternatives 1 and 2 using the same methodology and assumptions as outlined in section 3.3. Tables 5-2 and 5-3 present a summary of the results for both alternatives. Alternatives 1 and 2 provide sufficient FCITC for the Red Deer region. In the case of High SOK flow conditions for Alternative 1, the 138kV 80L (new Didsbury substation to Madden 373S) will be the limiting element for the loss of parallel 240kV 918L (new Didsbury substation to Beddington 162S) line. This overload can be managed by developing a suitable RAS which will be required until the west HVDC line comes into service. On the other hand, Alternative 2 does not have this limitation. Thus Alternative 2 offers additional operational flexibility. 49 Table 5‐2: 2012 First Contingency Incremental Transfer Capability (FCITC) for Alternative 1 Case FCITC (MW) 2012WP 370 960 977 2012SP 285 740 907 2012SL 625 871 937 2012SPSOK -106 194 226 Limiting Element ( Red Deer Region) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 922/926L(Sundance 821S to Benalto 17S) 240kV 918L(Benalto 17S to new Didsbury substation) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to New Didsbury substation) 138kV 166L(Harmattan 256S to 166L_JNC) 138kV 80L(New Didsbury substation to Madden 373S) 138kV 80L(Olds 55S to new Didsbury substation) 240kV 918L(Benalto 17S to new Didsbury substation) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) Contingency 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 926/922L(Sundance 821S to Benalto 17S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 240kV 926/922L(Sundance 821S to Benalto 17S) Table 5‐3: 2012 First Contingency Incremental Transfer Capability (FCITC) for Alternative 2 Case FCITC (MW) 445 2012WP 899 924 340 2012SP 679 714 752 2012SL 842 999 31 2012SPSOK 112 184 Limit Element 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 138kV 166L(Harmattan 256S to 166L JNC) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 918L(New Didsbury substation to Beddington 162S) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) Contingency 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 929L(Red Deer 63S to Innisfail 214S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) 50 5.5 Short Circuit Analysis A short circuit analysis was carried out by applying three phase and single phase to ground faults at the existing and proposed 240kV and 138/144 kV substations to determine the impact of Alternative 2 reinforcements on the short circuit levels in the Red Deer region. Short circuit levels are calculated and presented in Attachment D18. The results indicate that all fault levels remain within their respective maximum equipment ratings. 18 Short circuit current calculation is based on modeling information provided to the AESO by third parties. Short circuit estimation is subject to change. The information provided in this study is not intended to be used as the sole source of information for electrical equipment specification and the design of public or worker safety-grounding systems. 51 6.0 Transmission Alternatives- Long Term Assessment (2017) 6.1 Power Flow Analysis (2017) Power flow analysis was conducted for each alternative for the 2017 winter peak, summer light and summer peak load conditions using Generation Scenario B3. As with 2012, for purposes of the load supply adequacy study, Nova Joffre cogeneration plant is assumed to be the critical generation plant and was assumed to be out of service. Attachment D presents power flow plots for the above load flow studies. A summary table outlining the power flow plots is also included in the Attachment D. These power flow plots have been identified by the study year and contingencies in Attachment D. The proposed system in 2017 was found to be free of both voltage violations and thermal overloads for both Category A and B contingency events. The results indicate that these proposed alternatives meet the Reliability Criteria for supplying the forecast load in 2017 as shown in Table 6-1 below. Table 6‐1: Power Flow Analysis Results – 2017 6.1.1 Alternative Thermal Loading Violations Voltage Range Violations Alternative 1 None None Alternative 2 None None System Performance under Category C and D Contingency Events The system performance for the preferred plan (Alternative 2) was tested using power flow analysis for a number of Category C and D contingencies. The power flow plots for Category C and D contingency events for years 2017 are presented in Attachment D. A summary of system performance under Category C and D contingencies is also tabulated in Attachment D. Tables D-2017-5 to D-2017-13 of Attachment D list figure numbers of power flow plots for all load supply adequacy under Category C and D contingency events. 52 Overall, performance of Alternative 2 for the Red Deer region is satisfactory and met the Reliability Criteria for 2017 load adequacy conditions. However, it should be noted that for Category C contingency events, the worst case N-1-1 contingency involves loss of both 914L (Bigstone 86S to Gaetz 87S and Gaetz 87S to Red Deer 63S), which would cause the transformer at Red Deer 63S to be overloaded by 23% of its winter rating while Nova Joffre cogeneration plant is out of service; for Category D contingency events the worst case involves losing 240kV bus and related 240kV lines at Benalto 17S. Similar to 2012, under some extreme contingency conditions, shedding of the load or curtailing some generation are necessary to alleviate overloads observed under these circumstances. This is accomplished in compliance with the AESO Transmission Reliability Criteria. 6.2 2017 Transient Stability Studies (2017) Similar to 2012 analysis, transient stability studies for both Alternatives 1 and 2 were carried out using 2017SL and 2017WP load conditions. Simulated contingencies and monitored variables are similar to the ones studies in 2012 transient stability studies. All simulation results are presented in Attachment E. The results are summarized below: 6.3 The AIES system is stable for all simulated B, C3, C5, C7 and D contingency events. It is noted that the loss of the 240kV 995L transmission line from Benalto 17S to Brazeau 62S has caused sustained power oscillations in a number of lines. Further investigation shows that loss of 995L results in heavy overload on 240/138kV transformer at the Brazeau plant and one of its 138kV outgoing transmission lines. Additional study suggests that a cross-trip of one generator at Brazeau Hydro power station would eliminate the oscillation. No loss of load is anticipated except for those tripped due to the radial network configuration such as Rimbey 297S and Nelson Lake 429S connected loads. Voltage Stability (P-V and Q-V) Analysis Voltage stability (P-V and Q-V) analyses were carried out to determine the ability of the proposed system based on Alternatives 1 and 2 to be voltage stable under normal and abnormal system conditions. Also, these studies were used to calculate the reactive power margins available under Category B contingency events. This information was used to ensure that 53 the recommended reactive power compensation is adequate under normal and contingency conditions. The results of this P-V and Q-V study are presented in Attachment D. The results reveal that the system meets the AESO Voltage Stability Criteria. 6.4 Transfer Capability Analysis Transfer analysis for Alternatives 1 and 2 are repeated for 2017 using the same methodology and assumptions outlined in Section 3.3. Tables 6-2 and 6-3 present a summary for the transfer analysis. Both Alternatives offer large FCITC since the HVDC lines will be in service by 2017. The HVDC lines will significantly increase the available FCITC. Table 6‐2: 2017 First Contingency Incremental Transfer Capability (FCITC) for 2017 Case FCITC (MW) 2004 2017WP 2686 2717 1491 2017SP 2049 2296 1809 2017SL 2591 2684 Limit Element Contingency 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation)240kV 922/926L(Sundance 821S to Benalto 17S) 138kV 80L(New Didsbury substation to Madden 373S) 138kV 80L(Olds 55S to new Didsbury substation) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 906/928L(Benalto 17S to Sarcee 42S) 54 Table 6‐3: First Contingency Incremental Transfer Capability (FCITC) for Alternative2 Case FCITC (MW) 2086 2017WP 2578 2672 1556 2017SP 1965 2257 1930 2017SL 2559 2673 6.5 Limit Element Contingency 138kV 80L(New Didsbury substation to 240kV 918L(New Didsbury substation to Madden 373S) Beddington 162S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) 138kV 80L(New Didsbury substation to Madden 373S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) 240kV 918L(New Didsbury substation to Beddington 162S) 240kV 918L(Benalto 17S to new Didsbury substation) 240kV 922/926L(Sundance 821S to Benalto 17S) 240kV 906/928L(Benalto 17S to Sarcee 42S) 240kV 926/922L(Sundance 821S to Benalto 17S) Short Circuit Analysis A short circuit analysis was carried out by applying three phase and single phase to ground faults at the existing and proposed 240kV and 138/144 kV substations to determine the impact of Alternatives 1 and 2 reinforcements on the short circuit levels in the Red Deer region. Short circuit levels are calculated for the planned system in 2017 and presented in Attachment D. The results indicate that all fault levels remain within their respective maximum equipment ratings. 55 7.0 Comparison of Alternatives This section compares the technical performance of the Red Deer region transmission Alternatives 1 and 2. Factors used for comparing Alternatives consist of the following: ability to meet the reliability criteria, future expandability, and operational flexibility. Reliability Criteria Sections 5 and 6 of this report present the near and long term assessment results of the detailed technical analysis carried out for Alternatives 1 and 2. These results demonstrate that both alternatives meet the Reliability Criteria and that their performance is similar. Future Expandability Both Alternatives 1 and 2 provide adequate capacity to meet future needs. However, Alternative 2 is better than Alternative 1 since it provides access to the 240kV network via two additional 240/138kV substations at Innisfail 214S and Ponoka 331S. Consequently, Alternative 2 has more transmission capacity to serve the long term needs for this region than Alternative 1. This means Alternative 2 may not require additional rights-of-way in the long run. Operational Flexibility Performance of Alternatives 1 and 2 was evaluated under critical Category C contingencies for all loading conditions presented in Section 2. Both alternatives showed satisfactory and comparable performance under Category C contingencies. Table 7-1 compares the performance of Alternatives 1 and 2 under various Category C contingencies for the 2012 Summer High SOK and 2012 Winter Peak load with Nova Joffre cogeneration plant out of service conditions. In 2017, the number of observed overloads has reduced significantly compared to 2012 because of the availability of the HVDC lines. Table 7-2 compares the performance of Alternatives 1 and 2 for 2017 WP with Nova Joffre cogeneration plant out of service loading condition. In all simulated Category C contingencies in 2012 and 2017, the transmission line overloads did not exceed 120% for both Alternatives 1 and 2. Applicable operational measures according to the AESO Transmission Reliability Criteria and procedures will be used to mitigate these overloads. From transient stability point of view, Alternative 2 divides the existing integrated 138kV network into three independent 138kV sub networks interconnected by 56 240kV network. This will effectively isolate the faults at 138kV level thereby considerably reducing the exposure of these affected areas and thus improving the overall 138kV bus voltage profile under fault conditions. This is demonstrated in the transient stability analysis. Based on these technical performance measures, Alternative 2 meets the reliability criteria equally well as Alternative 1, provides a better opportunity to serve long term growth, and afford better operational flexibility. Table 7-3 presents a summary of the technical comparison of Alternatives 1 and 2. Table 7‐1: Category C Performance Comparison of Alternatives1&2 for 2012 High SOK and 2012WP with Nova Joffre Cogeneration Plant Out of Service Case Contingency 9L12(Nevis 766S to Red Deer 63S) 918L(New Didsbury substation to Beddington 162S) 900L (Red Deer 63S to Benalto 17S) 918L(New Didsbury substation to Beddington 162S) High SOK Flow 928/906L(Benalto 17S to Sarcee 575S) 925L(Red Deer 63S to Janet 74S) 929L (Red Deer 63S to Innisfail 214S) Alternative 1 Alternative 2 Percent Overload Percent Overload 108% 101% 113% 104% 80L(New Didsbury substation to Madden Tap) 106% None 900L (Red Deer 63S to Benalto 17S) 102% 102% 918L (Benalto 17 S to new Didsbury substation) 110% 116% Overloaded Element 80L (New Didsbury substation to Madden Tap) 80L (New Didsbury substation to Madden Tap ) 918L (Benalto 17S to new Didsbury N/A 104% (929L (Red Deer to 57 Case Contingency 914L (Bigstone 86S to Gaetz 87S) 910L (Red Deer 63S to Ponoka 331S) 2012WP Nova – Joffre Out of Service 914L(Gaetz 87S to Red Deer 63S) 914L(Gaetz 87S to Bigstone 86S) Overloaded Element Alternative 1 Alternative 2 Percent Overload Percent Overload substation) Innisfail does not exist) 900L( Red Deer 63S to Benalto 17S) N/A 138/240kV Transformer at Red Deer 63S 105% (910L Red Deer to Ponoka does not exist) None 107% Table 7‐2: Category C Performance Comparison of Alternatives1&2 for 2017WP with Nova Joffre Cogeneration Plant Out of Service Case Contingency 2017WP NovaJoffre Out of Service 910L(Ellerslie 86S to Red Deer 63S) 914L(Gaetz 87S to Red Deer 63S) Overloaded Element 240/138kV transformer at Red Deer 63S Alternative 1 Alternative 2 Percent Overload Percent Overload 117% N/A (910L Ellerslie to Red Deer 63S does not existing) N/A 914L (Red Deer 63S to Gaetz 87S) 910L (Red Deer 63S to Ponoka 331S) 914L(Gaetz 87S to Red Deer 63S) 914L(Gaetz 87S to Bigstone 86S) 240/ 138kV transformer at Red Deer 63S 138/240kV transformer at Red Deer 63S (910L Red Deer 63S to Ponoka 331S does not existing) 123% 112% 122% 58 Table 7‐3: Summary of the Technical Performance Evaluation of the Alternatives 1 and 2 Technical Performance Alternative 1 Alternative 2 Reliability Criteria Satisfactory Satisfactory Future Expandability Offers good opportunity Has higher capability than Alternative 1 because of additional 240/138kV substations Operational Flexibility Good Performance. Transmission line overloads do not exceed 120% Good Performance. Transmission line overloads do not exceed 120% Applicable operational measures will be deployed to mitigate overloads. Applicable operational measures will be deployed to mitigate overloads. Steady state: Performance under Category C contingency events Operational Flexibility Dynamic Conditions Dynamic analysis showed stable voltage and angle recovery following all simulated Category B and C contingencies Dynamic analysis showed stable voltage and angle recovery following all simulated Category B and C contingencies. Alternative 2 offers better voltage performance recovery under contingency conditions 59 8.0 Sensitivity Analysis (Load Forecast) The purpose of this section is to assess the impact of the most recent load forecast, FC2009, on the proposed transmission developments. A comparison of FC2007 and FC2009 load forecasts can be found in Appendix titled Red Deer Region Load and generation forecasts. Specifically, the objectives of the sensitivity analysis are: Investigate whether all elements of the proposed plan is still needed and the possibility to defer some elements of the proposed transmission plan to a later date when forecast peak load is lower than originally anticipated in 2012; and Investigate whether the preferred plan is adequate or requires additional reinforcements when the forecast peak load is higher than originally projected in 2017. The sensitivity analysis was carried out on the preferred alternative only. 8.1 Sensitivity Analysis for 2012 The sensitivity analysis was carried out by scaling the loads at all Red Deer and Didsbury substations in original power flow cases (2012WP, 2012SP, High SOK) to match the FC2009 load forecast condition. All other modeling assumptions, presented in Section 2, were kept the same as before. To assess the possibility of delaying some elements of the transmission system plan post 2012, the need assessment for the existing system, prior to the addition of any system reinforcement, was re-examined using the updated 2012S-SOK and 2012WP base-cases. For 2012WP load condition, the load flow analysis was performed for two scenarios, namely, (i) Nova Joffre cogeneration plant in service and (ii) Nova Joffre cogeneration plant out of service. The results of load flow analyses are presented in Attachment F. An examination of results reveals the following: Even though the peak loads were projected to be lower in 2012, the existing system (i.e., prior to any reinforcement), still does not meet reliability criteria because it experiences a number of thermal overloads and low voltages under certain contingencies ( see Attachment F); and All the reinforcements proposed in the preferred plan are still required to mitigate the reliability criteria violations. 60 8.2 Sensitivity Analysis for 2017 To examine the ability of the planned system to cope with higher load forecast in 2017, the loads at all Red Deer and Didsbury buses power flow cases for, 2017WP and 2017SP with planned system in place were scaled to represent the FC2009 load forecast condition. All other modeling assumptions, presented in Section 2, are kept without any change. Load flow analysis was then repeated for Category A and B contingencies. Simulation results reveal that the preferred Alternative with FC2009 load forecast satisfies AESO Transmission Reliability Criteria i.e., no voltage range and deviation violations nor any thermal overloads for both Category A and B contingencies. 8.3 Sensitivity Study Conclusions A reassessment of system needs for 2012 (i.e., prior to the addition of planned transmission development) using FC2009 load forecast indicated that the change in load forecast between FC2007 and FC2009 values was not large enough either to eliminate the need for system reinforcements or to defer any components of proposed transmission plan to a later date. Assessment of planned transmission system for 2017 using FC2009 load forecast showed that there is no need to add any new additional transmission facilities or introduce any change for the preferred transmission plan (Alternative 2). In summary, the preferred transmission development as identified in Section 9 is not affected by the variation in load forecasts and is still required. 61 9.0 Recommended Development This section describes the recommended development which was selected based on an in-depth technical analysis outlined in Sections 5, 6 and 7. Alternative 2 is recommended as the AESO’s preferred alternative to reliably supply forecasted loads, eliminate both the Joffre area transmission constraints and overloads on the Red Deer region 138kV network under various system operating conditions including SOK cut plane flows. The recommended proposal is shown in Figure 91. The AESO recommends a staged approach for implementation of the recommended plan. Stage I is recommended to meet load supply adequacy, eliminate Joffre inflow and outflow limitation, and facilitate high SOK flows. The requested in-service date for completion of Stage I is on or before Q4, 2012. Stage II, as per studies presented here is required by 2017 to meet forecast load in the region. This development consists of rebuilding approximately 20km of 138kV line from new Didsbury substation to Harmattan 256S. The need for it is driven by the region’s peak load of 826MW. Accordingly, the timing of its development will be determined by the future load projections. The AESO will monitor Red Deer region’s annual load forecast and will take steps to proceed with this development. Table 9-1 summarizes the recommended development for two stages. 62 Figure 9‐1: Recommended Transmission Plan (Alternative 2) 19 19 This map shows the general areas where the AESO has identified potential transmission system developments. This map does not identify actual line routes and substation locations. Line routes and substation locations will be determined when specific facility proposals are prepared. 63 Table 9‐1: Details of the Recommended Development Item # Description of Details Development Stage I I-1 Split existing 768L & 778L Split existing 768L and 778L into two separate lines. Add two circuit breakers one each at Gaetz 87S and another at North Red Deer 217S substations. I-2 New 240kV Didsbury substation Build a new 240kV substation with a single 240/138kV, 200MVA autotransformer near the existing 138kV Didsbury 152S within close proximity to the existing 240kV transmission line. Connect the existing 240kV 918L line to the new 240kV substation in an in/out arrangement with a conductor that matches capacity of 918L line. Connect the new substation’s 138kV bus to the existing 80L sections going to Olds 55S and Ghost 20S, and the 166L to Harmattan 256S. Install associated protection, control and SCADA equipment. Discontinue operation of the existing Didsbury 152S substation and associated infrastructure. I-3 New 138kV line from N.E. Lacombe 212S to Ellis 332S Build approximately 17km of a new S/C 138kV line from N.E. Lacombe 212S to Ellis 332S, utilizing appropriate conductor with summer/winter capacity of at least 252/314MVA. Install 138kV circuit breaker and associated protection and control equipment at N.E. Lacombe and Ellis 332S. I-4 New Autotransformer at Benalto 17S Add a second 200MVA, 240/138kV autotransformer at Benalto 17S and associated equipment. I-5 New 50MVAr 138kV Capacitor bank at Joffre 535S Add one (1) 50MVAr 138kV capacitor bank at Joffre 535S and associated equipment. I-6 New 50MVAr 138kV Capacitor bank at UC Prentiss 276S Add one (1) 50MVAr 138kV capacitor bank at UC Prentiss 276S and associated equipment. I-7 New 25MVAr 138kV Capacitor bank at Ellis 332S Add one (1) 25MVAr 138kV capacitor bank at Ellis 332S and associated equipment. I-8 Rebuild 80L(S. Red Deer 194S to N. Red Deer 217S) Rebuild 138kV transmission S/C line from South Red Deer 194S to North Red Deer 217S utilizing appropriate conductor with summer/winter capacity of at least 350/450MVA. I-9 Rebuild 80L ( S. Red Deer 194S to Red Deer 63S) Rebuild 138kV transmission S/C line from South Red Deer 194S to Red Deer 63S utilizing appropriate conductor with summer/winter capacity of at least 350/450MVA. 64 Item # Description of Details Development I-10 Rebuild 755L( Red Deer 63S to Joffre 535S) New S/C 138kV transmission line from Red Deer 63S to Piper Creek 247S to Joffre 535S, Utilizing appropriate conductor with summer/winter capacity of at least 252/314MVA. For approximately 36km and 4km tapping into Piper Creek substation (total of 40km). I-11 Rebuild 717L( Red Deer 63S to Benalto 17S via Sylvan Lake 580S) Rebuild 717L from Red Deer 63S to Sylvan Lake to Benalto 17S for approximately 34km utilizing appropriate conductor with summer/winter capacity of at least 252/314MVA. I-12 New 240kV Ponoka substation Build a new 240kV substation with two 240/138kV 100MVA autotransformers at a close proximity of the existing 240kV 910L line. Connect the existing 240kV 910L line to the new substation in an in/out arrangement with a conductor that matches capacity of 910L line. Build new D/C 138kV line from the new 240kV substation to Ponoka 331S with a rated summer and winter capacity of 175/215 MVA. Install required protection, control and SCADA equipment. I-13 New 240kV Innisfail substation Build a new 240kV substation with a single 240/138kV 200MVA autotransformer within a close proximity of the existing 240kV 929L line. Connect the existing 240kV 929L line to the new substation in an in/out arrangement with a conductor that matches capacity of 929L line. Build a new D/C 14km 138kV line from the new 240kV substation to Innisfail 214S with a rated summer and winter capacity of 175/215 MVA. Install required protection, control and SCADA equipment. I-14 Salvage 716L(Wetaskiwin 40S to Ponoka 331S) Lines Salvage Salvage 80L(Ponoka 331S to W. Lacombe 958S) Salvage 80L( Red Deer 63S to Innisfail 214S) Stage II II-1 Rebuild 166L (new Didsbury substation to Harmattan 256S) Rebuild 166L from the new Didsbury substation to Harmattan 256S for approximately 21km. utilizing appropriate conductor with maximum summer/winter capacity of at least 252/314MVA. Note: The specific developments shown in Table 9-1 represent configurations that could address the transmission system needs identified in this study. The final configuration of the recommended development, as well as the routing, location, and sizing of the various components of this plan, will be proposed by the legal owner of transmission facilities later in the process as they prepare the facility proposals. 9.1 Rationale for the Recommended Development Split the existing 138kV 768L & 778L lines (Item I-1) Split the ends of the existing 138kV 768L/778L double circuit line (Gaetz 87S to N. Red Deer 217S) into two separate circuits to improve the transfer out capability of the Joffre area. Splitting of these lines requires one new circuit breaker at both ends of this line. These additional breakers will allow 65 these 768L and 778L lines operate continuously as independent lines thereby increasing the transfer out capability. New 240kV Didsbury Substation (Item I-2) Under steady state conditions, Didsbury 152S, Olds 55S, and Innisfail 214S substations are mainly fed from power coming from Red Deer 63S via 80L. Under certain Category B contingencies such as the loss of 80L (Red Deer 63S to Innisfail 214S), these three substations will be radially fed from Benalto 17S via four lines (848L, 719L, 166L, and 80L) that are far from this area. Consequently, these three substations will experience low voltages because of the large voltage drop along this long transmission path which get worse in the long run due to load growth in the area. The proposed new 240kV Didsbury substation will provide additional strong power source to the area and support the voltage profile under Category B contingencies related to the loss of 80L sections (Red Deer 63S to Innisfail 214S), (Innisfail 214S to Olds 55S), and (Olds 55S to Didsbury 152S). New Line from N.E. Lacombe 212S to Ellis 332S (Item I-3) The new 138kV line (N.E. Lacombe 212S to Ellis 332S) will strengthen supply to N.E. Lacombe area. This line will facilitate salvaging of 80L (Ponoka 331S-W to Lacombe 958S) and also providing voltage support to this area. New Autotransformer at Benalto 17S (Item I-4) Currently, Benalto substation has one 200MVA transformer which is feeding local loads in the Red Deer and Caroline areas. Under Certain Category B contingencies such as: loss of 240kV 900L (Benalto 17S to Red Deer 63S) or loss of one autotransformer at Red Deer 63S or loss of 80L (Red Deer 63S to Innisfail 214S), more power will be pushed onto the 138kV network via existing Benalto 17S autotransformer, thereby resulting in high overload on the existing autotransformer at Benalto 17S. A new 240/138kV autotransformer at Benalto 17S is required to alleviate this overload. Capacitor Bank Additions at Joffre 535S, UC Prentiss 276S, and Ellis 332S (Items I-5, I-6, I-7) When Nova Joffre cogeneration plant is out of service, the Joffre area experiences low voltages which limit the amount of power that can be transmitted to the Joffre area. That is the system in the Joffre area will not meet voltage criteria. Hence capacitor banks need to be installed at Joffre 535S, UC Prentiss 276S, and Ellis 332S for alleviating Joffre inflow limitations and support voltage profile in the Joffre area when Nova Joffre cogeneration plant is scheduled to be out of service or experiences forced outage conditions. 66 Rebuild Sections of Existing 80L: (S. Red Deer 194S to N. Red Deer 217S) and (S. Red Deer 194S to Red Deer 63S) (Items I-8, I-9) The existing 138kV 80L sections (North Red Deer 217S to South Red Deer 194S) & (South Red Deer 194S to Red Deer 63S) have limited thermal capacity to meet the growing demand in this region including the City of Red Deer. These line sections are overloaded under various Category B contingencies including the loss of 914L (Red Deer 63S to Gaetz 87S) and 755L (Red Deer 63S to Joffre 535S). It is vital to upgrade these 80L line sections to higher capacity for serving Red Deer area load reliably over the long term. Rebuild Existing 138kV 755L: Red Deer 63S to Joffre 535S (Item I-10) When Nova Joffre cogeneration plant is out of service, the Joffre area load is supplied from generation sources in the Wabamun and Brazeau which lie out of the Joffre area. Loss of 80L (Red Deer 63S to S. Red Deer 194S) will cause overload on 755L (Red Deer 63S to Joffre 535S). Hence 755L needs to be upgraded to ensure reliability of supply to Joffre and City of Red Deer loads. Rebuild 717L: Red Deer 63S to Benalto 17S (Item I-11) Upgrading 717L Red Deer 63S to Benalto 17S via Sylva Lake 580S is necessary to avoid line overload under the loss of parallel 240kV 900L and to serve growing load demand in the Sylvan Lake area. New 240kV Ponoka, Innisfail Substations and Line Salvage (Item I-12, I-13, I-14) Under high SOK flow conditions, the existing 138kV 716L and 80L lines sustain large thermal overloads for the loss of 240kV parallel lines (914L, 910L, and 918L). Salvage of 716L (Wetaskiwin 40S to Ponoka 331S) and 80L line sections (Ponoka 331S to West Lacombe 958S) & (Red Deer 63S to Innisfail 214S) will eliminate over loads on 716L and 80L. Development of new 240/138kV substations at Ponoka and Innisfail will provide alternate supply source for Ponoka and Innisfail area loads. In addition, the two new 240/138kV substations in the region will offer ample capability to meet long – term needs of the area with virtually no new right of way requirements as they become part of the bulk system. Rebuild 166L from the new Didsbury substation to Harmattan 256S (Item II-1) This development consists of rebuilding approximately 20km of 138kV line from the new Didsbury substation to Harmattan 256S. Stage II, as per studies presented here, is required by 2017 to meet forecasted peak load of 826MW. Hence the timing of its development will depend upon the future load growth in this region of Alberta. As part of long – term planning process, the AESO will continue to monitor the Red Deer region’s annual 67 load forecast and will take necessary steps either to advance this development if the peak load is projected to occur before 2017 or delay it if the load growth slows down. 68 ATTACHMENTS Attachment A: Existing System Analysis Attachment B: Historical Substation Load Details Attachment C: Alternative Details Attachment D: Steady State and Voltage Stability Analysis Attachment E: Transient Stability Analysis Attachment F: Sensitivity Analysis