XXXX. Skookum Creek Power Project. Interconnection System Impact Study

Transcription

1 XXXX Skookum Creek Power Project Report No. August 2010 British Columbia Hydro and Power Authority British Columbia Hydro and Power Authority All rights reserved..

2 DISCLAIMER OF WARRANTY, LIMITATION OF LIABILITY This report was prepared by the British Columbia Hydro And Power Authority ( BCH ) or, as the case may be, on behalf of BCH by persons or entities including, without limitation, persons or entities who are or were employees, agents, consultants, contractors, subcontractors, professional advisers or representatives of, or to, BCH (individually and collectively, BCH Personnel ). This report is to be read in the context of the methodology, procedures and techniques used, BCH s or BCH s Personnel s assumptions, and the circumstances and constraints under which BCH s mandate to prepare this report was performed. This report is written solely for the purpose expressly stated in this report, and for the sole and exclusive benefit of the person or entity who directly engaged BCH to prepare this report. Accordingly, this report is suitable only for such purpose, and is subject to any changes arising after the date of this report. This report is meant to be read as a whole, and accordingly no section or part of it should be read or relied upon out of context. Unless otherwise expressly agreed by BCH: 1. any assumption, data or information (whether embodied in tangible or electronic form) supplied by, or gathered from, any source (including, without limitation, any consultant, contractor or subcontractor, testing laboratory and equipment suppliers, etc.) upon which BCH s opinion or conclusion as set out in this report is based (individually and collectively, Information ) has not been verified by BCH or BCH s Personnel; BCH makes no representation as to its accuracy or completeness and disclaims all liability with respect to the Information; 2. except as expressly set out in this report, all terms, conditions, warranties, representations and statements (whether express, implied, written, oral, collateral, statutory or otherwise) are excluded to the maximum extent permitted by law and, to the extent they cannot be excluded, BCH disclaims all liability in relation to them to the maximum extent permitted by law; 3. BCH does not represent or warrant the accuracy, completeness, merchantability, fitness for purpose or usefulness of this report, or any information contained in this report, for use or consideration by any person or entity. In addition BCH does not accept any liability arising out of reliance by a person or entity on this report, or any information contained in this report, or for any errors or omissions in this report. Any use, reliance or publication by any person or entity of this report or any part of it is at their own risk; and 4. In no event will BCH or BCH s Personnel be liable to any recipient of this report for any damage, loss, cost, expense, injury or other liability that arises out of or in connection with this report including, without limitation, any indirect, special, incidental, punitive or consequential loss, liability or damage of any kind. British Columbia Hydro and Power Authority, All rights reserved ii

3 COPYRIGHT NOTICE Copyright and all other intellectual property rights in, and to, this report are the property of, and are expressly reserved to, BCH. Without the prior written approval of BCH, no part of this report may be reproduced, used or distributed in any manner or form whatsoever. British Columbia Hydro and Power Authority, All rights reserved. iii

4 Executive Summary The XXXX, the Interconnection Customer (IC), proposes to develop the Skookum Creek Power Project to deliver electric energy to BC Hydro (BCH) through the BCH 2008 Clean Power Call (CPC). This report identifies the required system modifications for interconnecting the proposed Skookum Power Project. The maximum power injection to the system is 27.5 MW at the Point of Interconnection (POI) located at the 132 kv bus of Cheekye (CKY) Substation. The proposed Commercial Operation Date (COD) is August 1, To interconnect the Skookum project and its facilities to the BCH Transmission System at the POI at CKY Substation, this System Impact Study (SIS) has identified the following issues and requirements: The customer-owned 132 kv transmission interconnection line will be terminated at CKY 132 kv bus by creating a three-breaker ring bus configuration. A HV circuit breaker with independent pole operation and point-on-wave controller may be required at the IC site for step-up transformer energization from the system. A generation run-back or tripping scheme is required to resolve the post-contingency overloads on 2L9 and 2L13. If overload is detected on 2L9 or 2L13 at Cheekye substation (CKY), then a signal is sent to Skookum Power plant to run back or trip the Skookum generation. A direct transfer tripping scheme to trip the Skookum Power plant or the IC line is required to resolve transient instability issues and overload on 1L35 caused by the loss of CKY T4. A direct transfer tripping scheme to trip the Skookum Power plant or the IC line is required to resolve transient instability issues caused by the loss of 1L31. Out of step protection function is required at the Skookum Power plant. Minor revision of the existing system protection, control and/or telecom is required to accommodate the interconnection of the project. The non-binding good faith cost estimate for interconnection Network Upgrades required to interconnect the proposed project to the BCH Transmission System is $4.7 million. The estimated time to construct the Network Upgrades required to interconnect the project to the BCH Transmission System is estimated at 18 months. The Interconnection Facilities Study report will provide greater details of the interconnection Network Upgrade requirements and associated cost estimates and estimated construction timeline for this project. Upgrades that are common to the other IPP projects in this area are not included in this report. British Columbia Hydro and Power Authority, All rights reserved. iv

5 Table of Contents DISCLAIMER OF WARRANTY, LIMITATION OF LIABILITY...ii COPYRIGHT NOTICE... iii Executive Summary...iv 1.0 Introduction Purpose of Study Terms of Reference Assumptions System Studies Steady State Pre-outage Power Flows Power Flow Based First Contingency Study Transient Stability Study Islanding Fault Analysis Analytical Studies Protection and Control & Telecommunications BCH System Black Start Capability Transmission Line Upgrade Requirements Additional BCH Station Upgrades/Additions Other Issues Cost Estimate and Schedule Conclusion & Discussion...14 Appendix A Skookum Creek Model and Data...15 British Columbia Hydro and Power Authority, All rights reserved. v

6 1.0 Introduction The project reviewed in this System Impact Study (SIS) report is as described in Table 1 below. Table 1: Summary Project Information Project Name Skookum Power Project Interconnection Customer (IC) XXXX Point of Interconnection (POI) 132 kv bus at CKY Substation IC Proposed COD August 1, 2013 Type of Interconnection Service NRIS ERIS Maximum Power Injection (MW) 27.5 (Summer) 27.5 (Winter) Number of Generator Units 2 Plant Fuel Hydro The XXXX, the Interconnection Customer (IC), proposes to develop the Skookum Power Project which involves construction of a powerhouse with two hydro power generators each rated at 14.8 MVA on Skookum Creek to deliver electric energy to BC Hydro (BCH) through the BCH 2008 Clean Power Call (CPC). The generating station will be connected to the 132 kv bus of Cheekye (CKY) Substation through a step-up transformer and a 20.4 km customer-owned 132 kv transmission line. The proposed maximum power to be injected to the BCH system from the generating station is 27.5 MW. The Point of Interconnection (POI) is the 132 kv bus of CKY Substation. The proposed Commercial Operation Date (COD) is August 1, Figure 1 shows the transmission system in the Cheekye Area. British Columbia Hydro and Power Authority, All rights reserved. Page 1 of 17

7 Skookum Power km 22 km Figure 1 Transmission System with the interconnection of Skookum Power in the CKY Area The following diagram in Figure 2 shows the more detailed connection of the Skookum Power (SKO) to the Transmission System. Skookum Power Figure 2 - The Skookum Power Project Interconnection One Line Diagram British Columbia Hydro and Power Authority, All rights reserved. Page 2 of 17

8 2.0 Purpose of Study The purpose of this SIS is to assess the impact of the IC interconnection on the BCH Transmission System. This study will identify constraints and Network Upgrades required for the reliable operation of the Transmission System. 3.0 Terms of Reference The study investigates and addresses the voltage and overloading issues of the transmission networks in the vicinity of the Skookum Power generating station as a result of the proposed interconnection. Topics studied include equipment thermal loading and rating requirements, system transient stability and voltage stability, transient over-voltages, protection coordination, operation flexibility, telecom requirements and high level remedial action scheme requirements. BCH planning methodology and criteria are used in the studies. The SIS does not investigate the operating restrictions and other factors for the possible second contingency outages. Subsequent internal network studies will determine the requirements for reinforcements or operating restrictions/instructions for those kinds of events. Impact to the bulk transmission system is not included in the SIS and will be covered in a separate study. The work necessary to implement the network improvements identified in this SIS report will be described in greater detail in the Interconnection Facilities Study report for this project. 4.0 Assumptions The power flow conditions studied are base cases that include generation, transmission facilities, and load forecast representing the queue position applicable to this project. Applicable seasonal conditions and the appropriate study years for the study horizon are also incorporated. The 2013 heavy winter, 2013 heavy summer and light summer load flow base cases were selected for this study. The study is based on the model and data information provided by the proponent in the Generator Interconnection Data Form for this project. Reasonable assumptions are made to complete the study and the report, whenever such information is unavailable. Prior to addition of the proposed Box Canyon Project, the 230/60 kv transformers at Cheekye Substation (CKY) would already be overloaded for the loss of CKY (T6&7) or CKY T5. A generation run-back scheme is required to reduce Mamquam (MAM) generation output within minutes. 5.0 System Studies Power flow, short circuit and transient stability studies were carried out to evaluate the impact of the proposed interconnection. Studies were also performed to determine the protection, control and communication requirements and to evaluate possible over-voltage issues. British Columbia Hydro and Power Authority, All rights reserved. Page 3 of 17

9 5.1 Steady State Pre-Outage Power Flows Pre-outage power flows are prepared to assess the impact of the proposed interconnection using three basic system load conditions: 2013 winter peak load, 2013 summer light load and 2013 summer peak load, and defined generation conditions. The steady-state power flow studies have indicated: No voltage violations are observed. No circuits overload before and after the proposed interconnection Table 2 provides the power flow study results for the proposed interconnection Table 2: Steady-state Pre-outage Power Flow Study Results System Condition IPP Injection Bus Voltage (PU) Circuit Flow (MW) (MW) SKO 13G CKY 132 CKY T4 230/ HW LS HS Note: LS: light summer load; HW: heavy winter load; HS: heavy summer load CKY T4 summer rating: 90 MVA 5.2 Power Flow Based First Contingency Study Power flow based single contingency (N-1) studies have been conducted to check if the post-disturbance performance including bus voltage deviation and facility loading meets the planning criteria under different system load conditions including heavy winter, heavy summer and light summer. The single contingency studies have indicated that there are severe overload problems on 2L9 or 2L13 due to high Bridge River generation and the addition of the Skookum Creek Project. Therefore, a generation run-back scheme is required to reduce the generation output at Skookum Creek. This scheme should be expandable to include generation runback or tripping at Box Canyon and Culliton Creek as they are connected to the BC Hydro system. 2L9 (CKY-LYN), 2L13 (CKY-CYP) and 2L17 (LYN-WLT) will be overloaded in both 2013 LS and HS cases for the following contingencies: 2L13(CKY-CYP) + CYP T2 2L78 (ROS-ALZ) + ROS T1 2L77 ALZ-CBN + ALZ T2 British Columbia Hydro and Power Authority, All rights reserved. Page 4 of 17

10 2L9 (CKY-LYN) + LYN T1 2L17(LYN-WLT) + LYN T2 2L14 CYP-WLT 3L2 BRT-UHT 3L5 UHT-ROS Existing Bridge River gen-shedding RAS is relied on to address this issue first. If the overloads still exist, generation runback or generation tripping will be applied at the three CPC IPPs: Box Canyon, Culliton Creek and Skookum Creek. The single contingency studies also indicated that there is a minor overloading problem on 1L35 for loss of CKY T4. A direct transfer tripping scheme is required to trip the Skookum Creek IPP or the IPP line. The contingency study results based on 2013 summer light load and 2013 summer heavy load are listed in Tables 3 to 6. British Columbia Hydro and Power Authority, All rights reserved. Page 5 of 17

11 Table 3: The Power Flow Study Results after Single Element Contingency in 2013 LS case (Bus voltage) Cont. Name Bus Voltages (pu) CKY 132 MSA 132 SEC 132 WFR 132 SCG 132 PHR 132 COM 132 GIB 132 CKY 230 CKY 60 SQH 60 WFR 31P Pre Contingency (system normal) CKY T MSA T1&T5 trip 1L CKY T5 + T CKYT5+T9 shed CTN CKY T6 + T CKY T6+T7 shed CTN L13(CKY-CYP) + CYP T L3 ROS-WAH + WAH T L78 (ROS-ALZ) + ROS T L77 ALZ-CBN + ALZ T L1(BRT-FCN) + FCN T L5 (CKY-FCN) + FCN T L2 BRT-CKY + RBW T L9 (CKY-LYN) + LYN T L17 (LYN-WLT) + LYN T L14 CYP-WLT L12 (CKY to CMS) + CMS L31 (GIB-CKY) L32(SEC-GIB) L35(MSA-SEC) + PHR T L70 CKY-SQH L68 CKY-SQH L69 SQH-PTO L72 MAM-MAM 72P L2 BRT-UHT L5 UHT-ROS British Columbia Hydro and Power Authority, All rights reserved. Page 6 of 17

12 Table 4: The Power Flow Study Results after Single Element Contingency in 2013 HS case (Bus voltage) Cont. Name Bus Voltages (pu) CKY 132 MSA 132 SEC 132 WFR 132 SCG 132 PHR 132 COM 132 GIB 132 CKY 230 CKY 60 SQH 60 WFR 31P Pre Contingency(System normal) CKY T CKY T5 + T CKY T6 + T L13(CKY-CYP) + CYP T L3 ROS-WAH + WAH T L78 (ROS-ALZ) + ROS T L77 ALZ-CBN + ALZ T L1(BRT-FCN) + FCN T L5 (CKY-FCN) + FCN T L2 BRT-CKY + RBW T L2 BRT-CKY+ RBW T L9 (CKY-LYN) + LYN T L17 (LYN-WLT) + LYN T L14 CYP-WLT L12 (CKY to CMS) + CMS L31 (GIB to CKY) L32(SEC-GIB) L35(MSA-SEC) + PHR T L70 CKY-SQH L68 CKY-SQH L69 SQH-PTO L72 MAM-MAM 72P L2 BRT-UHT L5 UHT-ROS British Columbia Hydro and Power Authority, All rights reserved. Page 7 of 17

13 Table 5: The Power Flow Study Results after Single Element Contingency in 2013LS case (Branch flow) Cont. Name From Bus To Bus No. Name No. Name ID O/L facility Area Zone Current (A) Rating (A) Load (%) CKY T4 102 MSA PHR L SEC PHR L SEC GIB L MSA T1&T5 trip1l GIB BOX 31P 1 1L WFR 31P 9723 BOX 31P 1 1L CKY and CKY T CKY T5 + T9 601 CKY and CKY T CKY and CKY T CKY and CKY T CKY and CKY T CKYT5+T9 shed CTN 601 CKY and CKY T CKY and CKY T CKY and CKY T CKY T6 + T7 201 CKY and CKY T CKY and CKY T CKY T6+T7 shed CTN 201 CKY and CKY T CKY and CKY T L13(CKY-CYP) + CYP T2 201 CKY LYN 2T1 1 2L WLT LYN 2T2 1 2L CKY LYN 2T1 1 2L L78 (ROS-ALZ) + ROS T1 201 CKY CYP 2T2 1 2L WLT LYN 2T2 1 2L L77 ALZ-CBN + ALZ T2 201 CKY LYN 2T1 1 2L L9 (CKY-LYN) + LYN T1 201 CKY CYP 2T2 1 2L L17 (LYN-WLT) + LYN T2 201 CKY CYP 2T2 1 2L L14 CYP-WLT 201 CKY LYN 2T1 1 2L WLT LYN 2T2 1 2L SEC GIB L L35(MSA-SEC) + PHR T3 173 GIB BOX 31P 1 1L WFR 31P 9723 BOX 31P 1 1L L5 UHT-ROS 201 CKY LYN 2T1 1 2L British Columbia Hydro and Power Authority, All rights reserved. Page 8 of 17

14 Table 6: The Power Flow Study Results after Single Element Contingency in 2013 HS case (Branch flow) Cont. Name From Bus To Bus Num Name Num Name ID O/L facility Area Zone Current (A) Rating (A) Load (%) 106 SEC GIB L MSA T1&T5 trip1l GIB BOX 31P 1 1L WFR 31P 9723 BOX 31P 1 1L CKY and CKY T CKY T5 + T9 601 CKY and CKY T CKY and CKY T CKY and CKY T CKY and CKY T CKYT5+T9 shed CTN 601 CKY and CKY T CKY and CKY T CKY and CKY T CKY T6 + T7 201 CKY and CKY T CKY and CKY T CKY T6+T7 shed CTN 201 CKY and CKY T CKY and CKY T L13(CKY-CYP) + CYP T2 201 CKY LYN 2T1 1 2L WLT LYN 2T2 1 2L CKY LYN 2T1 1 2L L78 (ROS-ALZ) + ROS T1 201 CKY CYP 2T2 1 2L WLT LYN 2T2 1 2L L77 ALZ-CBN + ALZ T2 201 CKY LYN 2T1 1 2L L9 (CKY-LYN) + LYN T1 201 CKY CYP 2T2 1 2L L17 (LYN-WLT) + LYN T2 201 CKY CYP 2T2 1 2L L14 CYP-WLT 201 CKY LYN 2T1 1 2L WLT LYN 2T2 1 2L SEC GIB L L35(MSA-SEC) + PHR T3 173 GIB BOX 31P 1 1L WFR 31P 9723 BOX 31P 1 1L L2 BRT-UHT 201 CKY LYN 2T1 1 2L CKY LYN 2T1 1 2L L5 UHT-ROS 201 CKY CYP 2T2 1 2L WLT LYN 2T2 1 2L British Columbia Hydro and Power Authority, All rights reserved. Page 9 of 17

15 5.3 Transient Stability Study A series of transient stability studies under various system conditions including the heavy winter case and the most severe light summer case have been performed. The model of the generating project was based on the IC s data submission plus additional assumptions where the IC s data was incomplete/inappropriate. The models and data values of the key components are shown in Appendix A. Skookum Creek generators will be unstable after the loss of CKY T4 or 1L31 in 2013 LS, HS and HW cases. A direct transfer tripping (DTT) scheme is required to trip Skookum Creek IPP or the IPP interconnection line in 9 cycles for loss of CKY T4 or 1L31. An alternative method is for the IPP to replace the AC excitation system with a fast-responding static excitation system. If the second option is adopted by the IPP, further study is required to assess the performance of this option. The IPP must be able to detect and be tripped for out-of-step conditions caused by severe disturbances in the transmission system. Out of step protection is required at Skookum Creek and shall be provided by the IC. The swing center is expected to be inside the power plant. BCH can provide apparent impedance versus time plots of stable and unstable swings if requested. The transient stability study results for 2013 summer light load are summarized in Tab. 7. British Columbia Hydro and Power Authority, All rights reserved. Page 10 of 17

16 Table 7: Transient Stability Study Results (Pre-outage condition: 2013 LS, Skookum Power injection: 27.5 MW) Fault Clearing Time IPP Max Rotor Swing (Deg.) 3 Fault (Cycles) (Delta =max - initial) Stability Case Outage Location BOX SKO COM Performance Close End Far End MCH IPP IPP IPP IPP 1L35 SEC132 MSA132 Unstable SEC acceptable (MSA-SEC) 8 9 (Note 3) 1L31 CKY132 GIB132 2 CKY132 islanding Unstable acceptable (CKY-GIB) 8 8 (Note 2) 1L31 CKY132 GIB132 Unstable 3 GIB132 islanding acceptable (CKY-GIB) 8 8 (Note 1) CKY132 CKY230 Unstable 4 CKY T4 CKY acceptable 8 6 (Note 2) CKY230 CKY132 5 CKY T4 CKY acceptable L32 (SEC-GIB) 1L32 (SEC-GIB) SEC132 GIB132 SEC132 8 GIB132 8 GIB132 9 SEC Unstable (Note 1) Unstable (Note 1) acceptable acceptable Notes: 1. To be tripped by out-of-step relay. 2. Direct transfer tripping SKO IPP or the IPP line is required. 3. The circuit breakers of 1L35 (8 cycles fault clearing time) will be upgraded to new faster ones (fault clearing time no more than 6 cycles). This issue has been identified and resolved in a previous study (Bear Creek Hydro Project SIS study). 4. Stability performance is acceptable after applying the above solutions. 5.4 Islanding Islanded operation is normally not an acceptable practice in BCH. Power quality protection will be required at the generating units to detect abnormal system conditions such as under/over voltage and under/over frequency and subsequently trip the units. The settings of these protective relays must conform to the existing BCH practice for generating plants so that the generator will not trip during normal ranges of voltages and frequencies. 5.5 Fault Analysis The short circuit analysis for the CPC System Impact Studies is based upon the latest BCH system short circuit model, which includes project equipment and impedances provided by the successful CPC Interconnection Customers. The model includes higher queued projects and planned system reinforcements but excludes the Northwest Transmission Line (NTL) and other lower queued projects. At this stage, the report does not provide Thevenin impedances at the Point of Interconnection (POI) due to uncertainties associated with the system reinforcement options identified for the CPC British Columbia Hydro and Power Authority, All rights reserved. Page 11 of 17

17 projects and the statuses of higher queued projects. However, these Thevenin impedances, including the ultimate fault levels at POI, will be made available to Interconnection Customers upon request. BC Hydro will work with the IC to provide accurate data, as required, during the project design phase. 5.6 Analytical Studies Preliminary calculation results indicate that i) when energizing the customer owned stepup transformer under system normal conditions, the voltage sag at the POI will be about 9.7%, which exceeds the limits stated in the Interconnection Requirements; and ii) the voltage sags will be much higher if the CKY transformer T4 is out of service (the worst single contingency). Therefore, the IPP may require a HV breaker with independent pole operation and a Point-on-Wave controller to energize its step-up transformer from CKY. The IC will be responsible for undertaking the appropriate studies required to determine the necessity of an inrush mitigation scheme. A scheme to delay controlled opening of GIB terminal of 1L31 and send a direct transfer tripping (DTT) signal to the IPP is required to avoid over-voltages when CKY T4 is out of service. 5.7 Protection and Control & Telecommunications Protection, control and telecom requirements for the new Skookum Power generator addition have also been reviewed. The main items are summarized below: The IC is responsible to provide protection equipment at its site for the 132 kv interconnection line from the IPP to CKY. The IC is responsible to provide required telemetry and status information to BCH s Fraser Valley Office and Southern Interior Office via broadband satellite communication. Revision of 2L9 and 2L13 protections at CKY substation is required to add a new special protection scheme to signal generation run-back at Skookum Power to mitigate overload on 2L9 or 2L13. Revision of 1L31 protections at CKY and GIB is required to accommodate control scheme to delay GIB controlled opening of 1L31. GIB will send transfer tripping signal to CKY to trip the IPP line. The scheme is armed by the condition of CKY T4 out of service. At CKY substation, protection will be provided to the customer-owned transmission line. Revision of CKY T4 protection is required to add a connection to the new breaker 1CB1. Revision of 1L31 protections is required to add a connection to the new breaker 1CB1. Broadband satellite communication from the IPP to BCH is required Other minor revisions of existing system protection, control and telecom are required British Columbia Hydro and Power Authority, All rights reserved. Page 12 of 17

18 5.8 BCH System Black Start Capability BCH does not require the proposed project to have black start (self-start) capability. However, if the IC desires their facilities to be energized from the BCH system, the IC is required to apply for an Electricity Supply Agreement. Upon receipt of this application, a plant pick-up study would be required to assess the impact of energizing the IC s facilities. A high level plant pick-up screening was performed as part of the SIS and any issues are identified in Section Transmission Line Upgrade Requirements To accommodate the Skookum Power project s interconnection into the Transmission System, the IC will build a 132 kv transmission line from Skookum Power generation station to the POI at its own cost. No transmission line upgrade is required on the BCH Transmission System side Additional BCH Station Upgrades/Additions The customer-owned 132 kv transmission interconnection line will be terminated at the CKY 132 kv bus by creating a three-breaker ring bus configuration, in which two new 132 kv circuit breakers will be installed with associated electric power devices such as disconnects, CVT, surge arrestors, etc Other Issues There are no other issues identified at this stage Cost Estimate and Schedule The non-binding good faith cost estimate for interconnection Network Upgrades required to interconnect the proposed project to the BCH Transmission System is $4.7 million. The Facilities Study Report will provide more accurate information of the cost estimates. The estimated time to construct the Network Upgrades required to interconnect the project to the BCH Transmission System is estimated at 18 months after the Standard Generation Interconnection Agreement is signed and a BCH capital project is approved. A more detailed construction timeline will be provided in the Facilities Study Report. BCH system upgrades triggered by CPC projects are being determined and the IC may be required to post security to cover one or more upgrade. Further information will be provided over the next few months. British Columbia Hydro and Power Authority, All rights reserved. Page 13 of 17

19 6.0 Conclusion & Discussion To interconnect the Skookum Creek Power Project and its facilities to the BCH Transmission System at the 132 kv CKY bus, this System Impact Study has identified the following issues and requirements: The customer-owned 132 kv transmission interconnection line will be terminated at CKY 132 kv bus by creating a three-breaker ring bus configuration. A HV circuit breaker with independent pole operation and point-on-wave controller may be required at the IC side for step-up transformer energization. No unacceptable voltage condition in the Transmission System was observed in the power flow and transient stability analysis due to the Skookum plant interconnection under normal and N-1 contingencies. No voltage instability has been observed in the Transmission System due to Skookum power plant interconnection. A generation run-back or tripping scheme is required to resolve the post-contingency overloads on 2L9 and 2L13. If overload is detected on 2L9 or 2L13 at Cheekye substation (CKY), then a signal is sent to Skookum Power to run back or trip the generation within minutes. This scheme should be expandable to run back or trip the generation at Box Canyon and Culliton generating plants as they connect to the BCH system. A direct transfer tripping scheme to trip the Skookum Power plant or the IC line is required to resolve transient instability issues and overload on 1L35 caused by the loss of CKY T4. A direct transfer tripping scheme to trip the Skookum Power plant or the IC line is required to resolve transient instability issues caused by the loss of 1L31. Out of step protection is required at the Skookum Power plant. Islanded operation of the plant is not allowed. Power quality protection is required to prevent/mitigate possible islanded operation. Revision to system protection, control and telecom in the BCH Transmission System and control center is needed to accommodate the interconnection of the generating project. Upgrades that are common to the other IPP projects in this area are not included in this report. British Columbia Hydro and Power Authority, All rights reserved. Page 14 of 17

20 Appendix A IPP Model and Data Skookum Power Generator Model The contents of this section have been removed due to the proprietary nature of the information. British Columbia Hydro and Power Authority, All rights reserved. Page 15 of 17

21 Skookum Power Excitation Control System Model The contents of this section have been removed due to the proprietary nature of the information. British Columbia Hydro and Power Authority, All rights reserved. Page 16 of 17

22 Skookum Power Governor Control System Model The contents of this section have been removed due to the proprietary nature of the information. British Columbia Hydro and Power Authority, All rights reserved. Page 17 of 17