NorthernLights HVDC Project

Transcription

1 WECC COMPREHENSIVE PROGRESS REPORT December 4, 2008 Prepared for TransCanada by Ben Williams

2 TABLE OF CONTENTS EXECUTIVE SUMMARY... III 1.0 BACKGROUND & INTRODUCTION BACKGROUND INTRODUCTION PROJECT INFORMATION PROJECT DESCRIPTION AND MODELING Alberta Terminal Oregon Terminal HVDC Line Model OTHER NORTHWEST PROJECTS PROJECT MILESTONE SCHEDULE STUDY METHODOLOGY STUDY CONDITIONS Project Study Cases Project DC Bi-Pole Outage Scenarios Generation Dispatch in Project Cases POWER FLOW ANALYSIS METHODOLOGY Power Flow Study Criteria Power Flow Contingencies and Monitoring TRANSIENT STABILITY ANALYSIS METHODOLOGY Transient Stability Study Criteria Transient Stability Study Contingencies POST-TRANSIENT ANALYSIS METHODOLOGY STUDY RESULTS POWER FLOW STUDY RESULTS CANADA Canada Power Flow Study Process Initial Canada Power Flow Study Results Final Canada Power Flow Study Results POWER FLOW STUDY RESULTS PACIFIC NORTHWEST Pacific Northwest Power Flow Study Setup Initial Pacific Northwest Power Flow Study Results Final Pacific Northwest Power Flow Study Results TRANSIENT STABILITY STUDY RESULTS POST-TRANSIENT VOLTAGE STABILITY STUDY RESULTS CONCLUSION APPENDIX 1: PROJECT DIAGRAMS APPENDIX 2: POWER FLOW BASE CASE CONDITIONS APPENDIX 3: POWER FLOW ANALYSIS CONTINGENCY LISTS APPENDIX 4: POWER FLOW CONTINGENCY ANALYSIS RESULTS APPENDIX 5: TRANSIENT STABILITY ANALYSIS RESULTS SUMMARY APPENDIX 6: TRANSIENT STABILITY ANALYSIS PLOTS ii

3 EXECUTIVE SUMMARY The NorthernLights project is an HVDC project that will extend from Milo, Alberta to the Buckley Substation area of Grass Valley, Oregon. The Project will result in creation of a new WECC Path linking Alberta, Canada to the Pacific Northwest. Power flow, transient stability, and post-transient studies have been performed for both north-to-south and south-to-north flow directions to validate the requested bi-directional 2000 MW rating. These studies, which are documented in this report, show that the Project meets applicable WECC criteria and the NERC/WECC Planning Standards. TransCanada has actively participated in the Transmission Coordination Working Group since January 2008, coordinating study assumptions and sharing data and results with other entities planning projects terminating in the Lower Columbia area of the Pacific Northwest and with all other interested parties. With the submission of this report showing that this project meets all applicable NERC and WECC standards and with the separate submission of full project representation to WECC for inclusion in WECC base cases, TransCanada requests formal completion status of Phase 1 and the establishment of a new transmission path with a Planned Rating of 2000 MW bi-directional for the NorthernLights Project. iii

4 1.0 BACKGROUND & INTRODUCTION 1.1 Background The NorthernLights HVDC Project ( the Project ) is a proposed High Voltage Direct Current ( HVDC ) merchant transmission line from Alberta to the Pacific Northwest with a planned inservice date of By interconnecting energy markets, the Project will enable development of clean forms of energy including wind, hydro, nuclear, dark fuel gasification with CO2 sequestration, and co-generation. This new WECC Path will link markets that are now effectively isolated from one another and will provide the opportunity for economic energy interchanges and mutual emergency (or low water year) support. The project will also provide incentives to develop large scale energy projects by providing access to adjacent markets for surplus energy. The Project plans to employ conventional current source converter HVDC technology in a +/- 500kV bi-polar configuration to achieve a bi-directional rating of 2000 MW. The total length of the Project is approximately 1550 kilometers (970 miles), composed of two separate sections. A map of the proposed project is shown in Figure 1. The Heartland area northeast of Edmonton has been selected as the northern terminus of the northern section of the full Project, which will extend to a terminal located at Milo in southern Alberta. Southern Alberta boasts significant wind resources for future development which will access the Project at this terminal. This northern section of the Project is not hereafter considered in this report and is not included in the studies referenced herein; it will be studied through Alberta s planning processes and is expected to have negligible impact on WECC members outside of Alberta. Figure 1-1: NorthernLights Overview 1.0 BACKGROUND & INTRODUCTION Page 1 of 60

5 The southern section of the project, considered the Project for the remainder of this report, will extend from Milo, Alberta to Grass Valley, Oregon in the United States, near BPA s existing Buckley Substation, a distance of 990 kilometers (615 miles). From this point, energy can enter the Pacific Northwest and can be transferred further south to California, across the Cascades to the western side of Washington and Oregon, or to the Mid-Columbia Trading Hub. Because the new path is bi-directional, surplus energy from the Pacific Northwest or the remainder of the WECC to the south can enter Alberta based on market conditions or the need for emergency energy in Alberta. In summary, the Project will accomplish the following objectives: Create a bi-directional path between Alberta and the Pacific Northwest Enhance regional resource reliability by providing bi-directional market access Provide opportunities for markets to access large-scale renewable energy resources Enhance regional wind capacity factors though geographic diversity Enable development of new environmentally attractive generation resources in Alberta Improve regional transmission reliability Provide market participants with beneficial opportunities to use Project facilities 1.2 Introduction The purpose of this report is to document study work completed to date and to demonstrate that the Project is in compliance with the NERC/WECC Planning Standards and WECC Reliability Criteria, meeting the requirements documented in WECC s Overview of Policies and Procedures for Regional Planning Project Review, Project Rating Review, and Project Reports, dated April The Project officially completed the Regional Planning process on February 14, 2008, and was granted Phase 1 status. Since entering Phase 1, TransCanada has participated in the Transmission Coordination Working Group 1 ( TCWG ), coordinating study assumptions 1 TCWG is a voluntary group of project proponents with projects terminating in the Lower Columbia area who have agreed to work together in the WECC Phase 1 rating process. This group is expected to continue through the end of the projects Phase 2 rating processes. 1.0 BACKGROUND & INTRODUCTION Page 2 of 60

6 and sharing results with other entities planning projects terminating in the Pacific Northwest and with all other interested parties. TransCanada has completed studies conforming to the guidelines for Phase 1, which are documented in this report. With the submission of this report showing that this project meets all applicable NERC and WECC standards and with the separate submission of full project representation to WECC for inclusion in WECC base cases, TransCanada requests formal completion status of Phase 1 and the establishment of a new path with a Planned Rating of 2000 MW bi-directional for the Project. 1.0 BACKGROUND & INTRODUCTION Page 3 of 60

7 2.0 PROJECT INFORMATION 2.1 Project Description and Modeling Figure 2-1 below shows the proposed NorthernLights project routing superimposed on a WECC transmission map. Figure 2-1: NorthernLights Routing on WECC Map 2.0 PROJECT INFORMATION Page 4 of 60

8 2.1.1 Alberta Terminal The DC converter station in Alberta at the northern terminal of the Project will connect via 240kV ties to a new 240kV switching substation at Milo Junction 2. This switching station will terminate two existing 3-terminal 240kV lines in addition to the ties to the converter station. A +525/-100 MVAr SVC 3 was modeled at the new Milo Switching Station to provide required additional local area voltage support. Figure A1-1 in Appendix 1 shows this arrangement in the form of a power flow one-line diagram Oregon Terminal The DC converter station in Oregon at the southern terminal of the Project will connect via two 500kV tie lines to a new air-insulated 500kV substation near BPA s existing gas-insulated Buckley Substation. This new air-insulated station will connect to the existing Buckley Substation and will also loop in three 500kV lines in the vicinity of Buckley Substation: John Day Grizzly #1, John Day Grizzly #2, and Ashe Marion #2. Figure 2-2 is a geographic overview of this arrangement in the Buckley area 4 and Figure A1-2 in Appendix 1 is another annotated aerial view of the Buckley Substation vicinity; the new air-insulated substation would presumably be sited very close to this existing station, possibly to the southeast. Figure A1-3 in Appendix 1 shows the new arrangement in the form of a power flow one-line diagram. Figure A1-4 shows this arrangement superimposed on a WECC transmission map of the Buckley area. 2 Termination at Milo or an alternate location is subject to the results of public consultation and regulatory approval. 3 The new SVC modeled at Milo is primarily required for local area voltage support as a result of the new switching station sited at Milo and is not necessarily an upgrade caused by the addition of the Project. Issues of cost responsibility for system upgrades are not the focus of this report and will be resolved in separate processes. 4 Location of the new Buckley area facilities is subject to the results of public consultation and regulatory approval. 2.0 PROJECT INFORMATION Page 5 of 60

9 Figure 2-2: Buckley Substation Geographic Overview 2.0 PROJECT INFORMATION Page 6 of 60

10 2.1.3 HVDC Line Model An HVDC line model of the Project was created for the studies, with the 615 mile line modeled as an impedance of ohms per pole for two poles. The terminals for the two poles at each end are modeled as connected by a low-impedance AC tie. Approximately 500 MVAr of shunt capacitance is modeled at each terminal for each pole as part of the AC harmonic filter system. 2.2 Other Northwest Projects NorthernLights is one of many major transmission projects terminating in the Pacific Northwest between 2010 and The sponsors of these projects are participating in the TCWG to coordinate study assumptions and share results. Figure A1-5 in Appendix 4 displays a rough overview of all projects being planned by TCWG participants, including NorthernLights. 2.3 Project Milestone Schedule This project milestone schedule demonstrates the Project s planned in-service date of Initial Feasibility (complete 2006) Market Verification & Commercial Support 2012: Fully Permitted and Committed Line Open Season Detailed Siting and Permitting Detailed Technical Studies / Path Rating Finalize Land Acquisition and Construct Commence Operations 2.0 PROJECT INFORMATION Page 7 of 60

11 3.0 STUDY METHODOLOGY NorthernLights project studies included power flow, transient stability, and post-transient reactive margin verification analyses. 3.1 Study Conditions The first step in conducting studies was to establish base case study conditions Project Study Cases Consistent with agreements made by TCWG participants, the power flow base case for summer conditions was based on the 2007 WECC base case modeling heavy summer 2015 conditions, 15hs1sa. This case was modified by TCWG members to increase key path flows even further, add some missing projects (e.g. BPA s COI 4800 and West of McNary Generation Interconnection Project WOMGIP and the Montana-Alberta Tie Line MATL project), and replace the Alberta system model with an updated model provided by the Alberta Electric System Operator ( AESO ). The new AESO model is a 2016 case modeling the 84 th percentile on Alberta s load curve. (Because of Alberta s low seasonal diversity, this case can be used as starting point for both summer and winter base cases with minor modifications to load and generation dispatch.) Project base cases were created from this starting case, modeling the NorthernLights project with 2000 MW flow in both the north-to-south and south-to-north directions. Table A2-1 displays the path flows for the original WECC base case, the modified base case, and the two base cases showing maximum flow on the Project in each direction Project DC Bi-Pole Outage Scenarios In developing the base case conditions shown in Table A2-1, special consideration was given to NorthernLights HVDC bi-pole scenarios and the resulting flows between Alberta, British Columbia, and the Northwest on WECC Paths 1 and 3. The Project base case conditions were developed with the following objectives in mind: North-to-South ( N-S ) Case: Retain original base case flows on Path 1 and Path 3. Employ sufficient RAS generation tripping to keep Path 3 within its 3150 MW pre-contingency limit 3.0 STUDY METHODOLOGY Page 8 of 60

12 following a DC bi-pole outage of the Project namely, apply 1200 MW generation dropping in Alberta. South-to-North ( S-N ) Case: Modify original base case flows so that Alberta is exporting enough power to British Columbia to allow a 2000 MW reversal of flow and stay within the AESO s ~1400 MW emergency limit of Path 1, demonstrating that the project can achieve maximum south-to-north flow without load shedding in Alberta under these conditions. To demonstrate these concepts, the approximate conditions before and after a DC bi-pole outage of the Project are shown in Figure A2-2 in Appendix 2. The studied conditions represent one possible scenario to demonstrate maximum flow over the Project. The RAS settings chosen for this demonstration for north-to-south Project flow would likely vary with Path 1 and/or Path 3 interchange values, as well as actual Project flow. For the south-to-north Project flow case, the only proposed RAS action modeled is to trip the MATL project to avoid overloads and voltage violations in Montana. Tripping MATL may not be required under some system conditions. No generation dropping RAS actions are assumed, though dropping 1700 MW of generation in BPA is considered as a study sensitivity. Finally, although the DC bi-pole outage in the north-to-south case does not push Path 3 flow over its steady-state limit, Path 3 is able to support flows over the path limit during the post-transient period up to the point at which physical equipment emergency ratings or stability limits are reached. In summary, these scenarios were developed to demonstrate feasibility of maximum flow on the Project, not to establish firm precedents for RAS actions in these situations. These issues should be resolved in the next phase of the path rating process Generation Dispatch in Project Cases Generation dispatch for the N-S and S-N Project flow base cases was intended to attain the desired flow on the Project and to conform to the intended DC bi-pole outage scenarios. Generation dispatch for the N-S case is itemized in Table A2-3 of Appendix 2, and generation dispatch for the S-N case is similarly described in detail in Table A2-4. Generation dispatch in the Pacific Northwest for both the N-S Project case and the S-N Project case conforms to the recommendations of Bonneville Power Administration engineers, and generation dispatch in Alberta for each case conforms to the recommendations of Alberta Electric System Operator 3.0 STUDY METHODOLOGY Page 9 of 60

13 engineers. For the S-N Project case, generation decreases in Alberta are loosely based on merit order re-dispatch. Both Project case dispatch scenarios rely heavily on increased wind generation in Alberta (N-S case) and the Northwest (S-N case), both existing and future. 3.2 Power Flow Analysis Methodology Power flow analysis has been conducted to identify thermal overloads created by or exacerbated by the project in Canada or in the Pacific Northwest Power Flow Study Criteria Problems are attributed to the NorthernLights project if post-project results show that equipment flow exceeds 100% of the applicable rating and the severity of the problem increased by 2% or more from the pre-project case. Criteria applied during the power flow analysis are as follows: Normal (Category A) Conditions Bus voltages maintained between 0.95 p.u. and 1.05 p.u., unless specific minimum voltage operating requirements exist All line and transformer flows below normal continuous ratings Net VAR flow interchange with each interconnected utility within limits established by transmission owners Contingency (Category B & C) Conditions No transmission element loaded above the applicable emergency rating Equipment emergency voltage limits (high or low) not exceeded Bus voltage deviations from base case do not exceed established planning limits No loss of load for single contingencies (except radial systems) No new RAS actions for single contingencies, including single-pole outage of NorthernLights HVDC line New RAS actions considered acceptable for multiple element contingencies, including bipole outage of NorthernLights HVDC line 3.0 STUDY METHODOLOGY Page 10 of 60

14 3.2.2 Power Flow Contingencies and Monitoring The following contingencies were simulated during the power flow analysis: Canadian Study: All 240kV single-element outages in Alberta, including tie lines and generator step-up transformer banks; southern Alberta double-line Category C outages Pacific Northwest Study: BPA COI, PDCI, and West of McNary / West of Slatt 500kV Category B and C outages All contingencies include modeling of applicable RAS actions. The full contingency list for each study (except double-line Alberta outages) is included in Appendix 3. For Pacific Northwest contingencies, RAS actions modeled for each contingency are also indicated. The contingency list, RAS action details, and interface definitions for the Pacific Northwest were obtained from BPA engineers. Different areas in the power flow base case were monitored for the Canadian study and the Pacific Northwest study. For the Canadian contingency study, all equipment in the following areas was monitored for flow and voltage violations: Area 50: B.C. HYDRO Area 52: FORTISBC Area 54: ALBERTA For the Pacific Northwest contingency study, one area was monitored for violations: Area 40: NORTHWEST Every branch and bus in the monitored areas was checked for violations, regardless of voltage level. The NorthernLights HVDC line single-pole and bi-pole outage contingencies were applied to both the Canadian and the Pacific Northwest studies. Thus, violations caused by these outages were monitored in all of the areas listed above. For the double-line outages in Alberta, an emergency equipment rating of 120% was applied for branches in Alberta per AESO policy and direction. 3.0 STUDY METHODOLOGY Page 11 of 60

15 3.3 Transient Stability Analysis Methodology Transient stability studies were performed to assess the impact of the NorthernLights Project on the transmission system in Alberta, British Columbia, Montana, and the Pacific Northwest Transient Stability Study Criteria Criteria applied during the transient stability analysis were as follows: All machines in the system remain synchronized as demonstrated by relative rotor angles System stability evaluated based on damping of relative rotor angles and damping of voltage magnitude swings Transient voltage dips meet WECC Reliability Criteria: Performance Level Disturbance Transient Voltage Dip Criteria B N-1 V Dip not to exceed 25% or 20% for 20 cycles at load buses C N-2 V Dip not to exceed 30% or 20% for 40 cycles at load buses D N-3 Not Specified Transient frequency dips meet WECC Reliability Criteria: Performance Level Disturbance Transient Frequency Dip Criteria B N-1 Frequency not below 59.6 Hz for >6 cycles at load buses C N-2 Frequency not below 59.0 Hz for >6 cycles at load buses D N-3 Not Specified Transient Stability Study Contingencies The contingencies chosen to be simulated for transient stability analysis were recommended by BPA engineers. They are as follows ( DLO is shorthand for Double Line Outage ): 0. No-Contingency Run: To verify all units initially stable 1. Palo Verde G-2: Trip two nuclear plant generating units at Palo Verde; 8 cycles after outage, trip 120 MW of APS/SRP load 2. Diablo Canyon G-2: Trip two nuclear plant generating units at Diablo Canyon 3.0 STUDY METHODOLOGY Page 12 of 60

16 3. PDCI DC Bi-Pole (N-S): Trip both poles of PDCI; 12.6 cycles after outage, begin Fast AC Reactive Insertion ( FACRI ) actions; 21.7 cycles after outage, begin tripping 2650 MW NW generation; 2 seconds after outage, switch out Celilo capacitors 4. NorthernLights DC Bi-Pole (N-S): Trip both poles of NorthernLights and switch out capacitors; 37.4 cycles after outage, trip 1200 MW Alberta wind generation 5. NorthernLights DC Bi-Pole (S-N): Trip both poles of NorthernLights and switch out capacitors; 14 cycles after outage, initiate BC Rx RAS; 21.7 cycles after outage, begin tripping 1700 MW NW generation; 26 cycles after outage, trip MATL (plus comparisons with no MATL tripping and with no NW generation tripping) 6. Malin Round Mt. DLO: Three-phase fault at Malin 500kV; 4 cycles after fault, trip Malin Round Mt. #1 & 2 500kV lines; 13 cycles after fault, begin tripping California Department of Water Resources ( CDWR ) pumps; 14.3 cycles after fault, insert Chief Joseph braking resistor; 21.7 cycles after fault, begin tripping 2650 MW NW generation (other actions omitted for brevity) L Tap Cranbrook (Langdon Cranbrook): Three-phase fault at Langdon 500kV; 4 cycles after fault, trip 1201L Tap Cranbrook 500kV line and line reactors; 12 cycles after fault, begin tripping 2-138kV ties between AB and BC; 26 cycles after fault, trip MATL 8. Custer Ingledow DLO: Three-phase fault at Custer 500kV; 4 cycles after fault, trip Custer Ingledow #1 & 2 500kV lines and insert GMS braking resistor; 10 cycles after fault, trip Nelway Boundary 230kV line; 12 cycles after fault, trip 1930 MW (for N-S case) BC generation; 14 cycles after fault, initiate BC Rx RAS; 26 cycles after fault, trip MATL 3.4 Post-Transient Analysis Methodology WECC criteria prescribe the following post-transient voltage stability analysis methodology: For transfer paths, post-transient voltage stability is required with the path modeled at a minimum of 105% of the path rating for system normal conditions (Category A) and for single contingencies (Category B). For multiple contingencies (Category C), post-transient voltage stability is required with the path modeled at a minimum of 102.5% of the path rating. To verify post-transient voltage stability in this study, Project flow is increased by 5% and all Category B and C contingencies are run to verify that all cases converge, demonstrating that voltage collapse does not occur. If any of the Category C contingencies result in a diverged case, the Project flow is reduced to 2.5% and those contingencies are re-run. The contingencies run for post-transient voltage stability analysis are the same as those run for the power flow analysis; namely, the contingencies listed in Appendix STUDY METHODOLOGY Page 13 of 60

17 4.0 Study Results Studies were conducted according to the methodology described in Section Power Flow Study Results Canada Power flow studies for the Alberta transmission system were conducted in consultation with and with the support of the AESO s transmission planning group Canada Power Flow Study Process After study cases had been developed as described in Section 3.1, a preliminary Category B contingency analysis was performed for both N-S and S-N cases, then truncated versions of these cases and the preliminary results were sent to AESO engineers for their own Category B analysis. The AESO then developed recommended solutions for the local problems identified based on projects included in their long-term plan which had not been included in the base cases. (The Alberta system model provided by the AESO for these cases did not include all long-term projects because they have not yet studied 2015 in detail due to resource uncertainty; thus, the analysis turned up many problems unrelated to the NorthernLights project.) After verifying that the proposed solutions resolved the local problems in the truncated cases, the AESO sent a list of the solutions to be incorporated and tested in the full-loop case. Any problems that remained were then identified and sent back to the AESO for new solutions. This iterative process continued until all local problems had been resolved and only problems related to the Project, if any, remained Initial Canada Power Flow Study Results Initial results for the Alberta contingency analysis with monitoring of Canada showed: N-S Case 37 transmission branches violated study criteria No voltage criteria violations S-N Case 46 transmission branches violated study criteria 10 buses with voltage criteria violations These initial results seemed to indicate that the south-to-north Project flow conditions studied were more severe than the north-to-south Project flow conditions studied. 4.0 Study Results Page 14 of 60

18 In response to the problems identified, the AESO recommended including numerous long-term projects in the study cases, including: 38 transmission line upgrades to increase capacity 25 transformer bank upgrades to increase capacity 1 new transmission line 4 new transformers 1 new phase shifting transformer 4 new 500kV line shunts 14 new shunt capacitors or SVC s (3 removed) Various bus voltage schedule changes A detailed list of projects added to the base case per AESO recommendations is presented in Table A2-5 of Appendix Final Canada Power Flow Study Results The figure below displays a comparison of equipment overloads obtained using the original base cases and the results obtained using cases with the AESO s recommended upgrades included. As shown, the equipment overloads are almost eliminated by the upgrades Initial Run Final Run N-S 240kV OL S-N N-S 138kV OL S-N N-S 69kV OL S-N N-S Xfmr OL S-N N-S Total OL S-N 4.0 Study Results Page 15 of 60

19 North-To-South Canada Results Detailed results for all equipment with loading exceeding 90% of rating for any contingency are displayed in Table A4-1 of Appendix 4. Only one qualifying branch overload appears in the results: Circuit Contingency Pre-Project % Rating Project % Rating % Change from Original Contingency NTL LCCTAP #1 Various (7) < 90% 108.6% 90.1% This overloaded circuit is a facility owned by BCTC that is effectively on the boundary between Alberta and British Columbia s transmission systems. This circuit has been identified as a problem in other forums and is the subject of on-going discussions between the owners in Alberta and British Columbia, but a final solution has not yet been agreed upon. This overload is likely to be resolved independent of the Project, and is therefore not considered to be a violation caused by the Project. However, TransCanada will continue to monitor developments related to this circuit. One other overload appearing in these study results exceeds 100% of rating in the post-project case, but the overload is pre-existing and loading decreases as a result of adding the NorthernLights DC project. Voltage results for the N-S contingency study are displayed in Table A4-2 of Appendix 4. The important finding from these results is that there are several buses in British Columbia that experience low voltages following a DC bi-pole outage of the Project. These low voltages are a result of Path 3 flow being pushed to the limit by this outage. Although the voltages are greater than 5% below nominal (assume 525kV nominal for 500kV), the voltage dips are less than a 5% deviation from the initial voltage because these bus voltages are below nominal in the base case. Therefore, the voltage results meet criteria. Table A4-3a shows the high interface flows that increase more than 1% compared to the preproject contingency case. These results show a moderate shift in interface flows around the WECC for the DC bi-pole outage and the associated RAS actions assumed in this study. Table A4-3b shows key interface flows before and after NorthernLights single- and bi-pole DC outages for N-S Project flow, showing the re-distribution of flows across WECC for these outages. 4.0 Study Results Page 16 of 60

20 South-To-North Canada Results Detailed results for all equipment with loading exceeding 90% of rating for any contingency are displayed in Table A4-4 of Appendix 4. Nine qualifying branch overloads appear in these final S-N contingency study results: Circuit Contingency Pre-Project % Rating Project % Rating % Change from Original Contingency CBK L #01 NorthernLights DC Bi-Pole Outage <90% 121.5% 208.6% NTL LCCTAP #1 NorthernLights DC Bi-Pole Outage <90% 107.7% 95.5% NTL VR NTL #1 NorthernLights DC Bi-Pole Outage <90% 101.1% 130.3% JASPER MEADOWLK 69.0 #18 Various (8) 124.6% 128.9% 4.2% JASPER WOODCRF #19 Various (8) 112.7% 116.5% 4.1% WABAMUN ONOWAY #04 Various (2) 102.6% 112.1% 16.1% N BARRH N BARRH #T1 SUNDANC4-N BARRH4 240 Line #R3 <90% 102.3% 23.2% MILLENN HORSE #51 MILLENN4-MILLENN8 240/ 69 #1T 100.0% 101.9% 2.7% MILLENN HORSE #32 MILLENN4-MILLENN8 240/ 69 #T4 99.9% 101.8% 2.8% The first three transmission lines on this list comprise part of the intertie between British Columbia and Alberta (Path 1). Although the flow on Path 1 of nearly 1300 MW exceeds the normal transfer capability of 800 MW from BC to Alberta, system adjustments would reduce the flow under the studied conditions to within the 800 MW limit within 30 minutes as follows: Alberta system load in the study case is 13,880 MW. This load level requires Alberta contingency reserves of at least 694 MW. Thus, contingency reserves alone will be more than adequate to reduce the Path 1 flow from 1300 MW to 800 MW. When contingency reserves are deployed, the MATL line can be restored with a phase shift setting that keeps MATL within its limit, adding another 300 MW of import capability. The tie between Alberta and Saskatchewan can also be adjusted to provide support. The remaining five lines and one transformer on this list are part of the Alberta 69kV transmission system. These six branches are all either pre-existing overloads or are less than 103% of rating in the post-project case. These overloads appear because studies conducted by the AESO considered only facilities at 138kV and above. AESO studies did not consider these facilities because the AESO plans to retire Alberta s 69kV system over time and they will not 4.0 Study Results Page 17 of 60

21 upgrade these facilities. As 69kV problems arise over time, they will be resolved through internal AESO planning processes. For these reasons, 69kV problems will not be considered the responsibility of the Project per the AESO s direction. Voltage results for the N-S contingency study are displayed in Table A4-5 of Appendix 4. The following buses in Alberta experience low voltages and more than a 5% drop from the original case for B contingencies: E CROSS4 240: 213kV NORLIGHT 240kV: 201kV 791S702T 138kV: 121kV 737S602T 69kV: 59kV Most of these voltage problems are pre-existing and local issues that the Project exacerbates slightly. Two of them exceed the 5% criteria by the slimmest of margins. TransCanada, while recognizing that the Project is not the primary cause of these problems, will continue to work with the AESO to ensure that these local problems are resolved to eliminate these violations. Table A4-6a shows the high interface flows that increase more than 1% compared to the preproject contingency case. These results show minor shifts in interface flows in WECC for the DC bi-pole outage and the associated RAS actions assumed in this study. Table A4-6b shows key interface flows before and after NorthernLights single- and bi-pole DC outages for S-N Project flow, showing the re-distribution of flows across WECC for these outages Southern Alberta Double-Line Outage Results Category C double-line outages in Southern Alberta were run for both the north-to-south and south-to-north project flow cases as described in Section This study revealed no violations more severe than those already identified in the Category B outage studies. 4.0 Study Results Page 18 of 60

22 4.2 Power Flow Study Results Pacific Northwest Power flow studies for the Pacific Northwest transmission system were conducted in consultation with BPA s transmission planning group Pacific Northwest Power Flow Study Setup The planned interconnection of the Project s DC converter to the BPA transmission system, as described in Section 2.1.2, includes looping the John Day Grizzly #1 & 2 and Ashe Marion 500kV lines into a Buckley New substation to create the following connections (see Figure 2-2 in Section 2.0 and Figure A1-3 and Figure A1-4 in Appendix 1 for graphical presentations of this information): John Day Buckley New #1 500kV John Day Buckley New #2 500kV Buckley New Grizzly #1 500kV Buckley New Grizzly #2 500kV Ashe Buckley New 500kV Buckley New Marion 500kV Buckley New NorthernLights Converter Sub #1 500kV Buckley New NorthernLights Converter Sub #2 500kV Buckley Buckley New 500kV For the last connection on this list, uncertainty whether the connection to the existing Buckley Substation would be necessary or beneficial resulted in running all studies with both options Initial Pacific Northwest Power Flow Study Results Initial results showed a major imbalance in flows among the three 500kV lines between the Buckley area and Grizzly Substation and resulted in substantial overloads. As a result, series compensation levels for the three lines were studied. The Buckley New Grizzly 500kV lines are both compensated with 25 ohms of series capacitance at Bakeoven, roughly 5 miles south of Buckley Substation, but the Buckley Grizzly 500kV line currently has no series compensation. Based on studies considering a number of series compensation options, series compensation of 20 ohms was added to the Buckley Grizzly line at Bakeoven in the model to better balance parallel flows among the three lines. 4.0 Study Results Page 19 of 60

23 4.2.3 Final Pacific Northwest Power Flow Study Results The most significant problems observed in the Pacific Northwest contingency studies the only 500kV overloads occur between the Buckley area substations and Grizzly; each of the three lines is overloaded under some condition. Table 4-1 summarizes these 500kV overloads, the situation under which each occurs, and the proposed solution to mitigate each problem. Based on these studies, the best approach is to connect Buckley and Buckley New with a 500kV line, but install a Remedial Action Scheme which will open the tie when the critical double-line outage occurs. Another RAS proposal which is effective in studies is to bypass the series capacitors on the Buckley New Grizzly #1 500kV line for the loss of the two parallel 500kV lines. The proposed actions will be further analyzed in an upcoming BPA Interconnection Study. Table 4-1: Buckley Area Grizzly 500kV Overloads and Proposed Solutions Contingency Overloaded Circuit % Rating Buckley New Grizzly #1 500kV Buckley New Grizzly #2 500kV 118.3% Buckley New Grizzly #2 500kV Buckley New Grizzly #1 500kV 108.6% Buckley Subs Tied? No NorthernLights Flow Direction N-to-S Proposed Solution Tie Buckley and Buckley New substations together. Buckley New Grizzly #2 500kV + Buckley Grizzly 500kV Buckley New Grizzly #1 500kV + Buckley New Grizzly #2 500kV 117.3% Yes N-to-S 115.0% No N-to-S Buckley New Grizzly #1 500kV 113.6% Yes S-to-N 107.5% No S-to-N Buckley Grizzly 500kV 107.6% N-to-S Yes Buckley Grizzly 500kV 104.3% S-to-N Add RAS to bypass series capacitors on Buckley New Grizzly #1 500kV line for this contingency. Add RAS to open tie between Buckley substations for this contingency Other North-To-South Pacific Northwest Branch Overloads Detailed results for all equipment with loading exceeding 90% of rating for any contingency are displayed in Table A4-7 of Appendix 4. Other than the 500kV overloads discussed above, three qualifying branch overloads appear in the N-S results with Buckley area substations connected: Circuit Contingency Pre-Project % Rating Project % Rating % Change from Original Contingency LONEPINE 69 LONEPINE 115 #3 KlamFalls-Meridian #1 500 SLO 141.4% 146% 3.4% LONEPINE 69 LONEPINE 115 #1 KlamFalls-Meridian #1 500 SLO 112% 115.6% 3.1% REDMOND 230 ROUND BU 230 #1 Various (2) 107.6% 114.4% 6.3% 4.0 Study Results Page 20 of 60

24 The LONEPINE transformer overloads are a result of heavy MVAr flows from the 69kV bus to the 115kV bus. These are local voltage issues unrelated to the Project. The Redmond-Round Butte #1 230kV line is overloaded in the pre-project case. This 230kV path is in parallel with the Grizzly-Ponderosa 500kV line section and picks up significant flow after an outage of the Ponderosa 500/230kV transformer bank. TransCanada will monitor developments related to this line due to the pre-existing overload condition and will further analyze this issue in an upcoming BPA Interconnection Study, including possible mitigation alternatives Other South-To-North Pacific Northwest Branch Overloads Detailed results for branches with loading >90% of rating for any contingency are shown in Table A4-8 of Appendix 4. Other than the 500kV overloads and LONEPINE transformers, nine qualifying branch overloads appear in the S-N results with Buckley area substations connected: Circuit Contingency Pre-Project % Rating Project % Rating % Change from Original Contingency CRAGVIEW 115 WEED JPS 115 #1 Malin-Round Mt. #1&2 500kV DLO 113.5% 116.4% 2.5% DELTA 115 CASCADE 115 #1 Malin-Round Mt. #1&2 500kV DLO 107.3% 110.1% 2.6% HART SS 115 WEED JCT 115 #1 Malin-Round Mt. #1&2 500kV DLO 98.0% 100.4% 2.4% COPCO 115 HART SS 115 #1 Malin-Round Mt. #1&2 500kV DLO 98.0% 100.4% 2.5% PILOTBT 230 REDMOND 230 #1 Grzly-Malin2+Gzly-Pnd-SmLk DLO 105.7% 110.2% 4.2% CLEVELND 69 PILOTBT1 69 #1 Grzly-Malin2+Gzly-Pnd-SmLk DLO 103.3% 105.9% 2.5% VIEW TAP 115 MERWIN 115 #1 Various (3) 98.3% 102.9% 4.7% BONANTAP 69 CASEBEER 69 #1 Various (9) 104.6% 106.8% 2.1% BONANZA 69 CASEBEER 69 #1 Various (16) 100.8% 103.1% 2.3% Most of these branches show overloads in the pre-project case and the Project contributes less than 5% to each overload. The two BONANZA 69kV circuits are overloaded by shunt capacitance at the end of a radial system, so these overloads are unrelated to the Project. Increases in the other overloads may be caused by generation re-dispatch rather than the Project itself. These branches will be further analyzed in the upcoming BPA Interconnection Study to verify whether any of these seven branch overloads is legitimately caused by the Project, and if so, to explore mitigation alternatives. 4.0 Study Results Page 21 of 60

25 Voltage Results and Interface Flows Voltage results for all Pacific Northwest contingency studies are displayed in Table A4-9 of Appendix 4. Only one interesting result appears for S-N Project flow, the BEND PLT 69kV bus voltage dips just over 10% in the pre-project case and more than 12% after adding the project for a double-line 500kV outage. This bus is located in the PILOTBT area, which experiences some overloads for the same outage. This problem appears linked to the overload issue and the same solution is likely to resolve both. This too will be analyzed during the BPA Interconnection Study. Table A4-10 shows the high interface flows that increase more than 1% compared to the preproject contingency case. These results show that the COI flow exceeds the normal limit during a 2PV or PDCI outage, and North of John Day exceeds the normal limit during a 2PV outage. These results are not surprising and do not violate criteria Study Sensitivity with 1700 MW Northwest Generation Drop A sensitivity study which investigated tripping 1700 MW of Northwest generation for a NorthernLights HVDC bi-pole outage yielded results that varied little from the original study without Northwest generation dropping. Therefore, if such an action proves necessary in the future, it is not expected to create additional violations. 4.0 Study Results Page 22 of 60

26 4.3 Transient Stability Study Results Transient stability analysis is the study of dynamic behavior of the transmission system following a fault on the transmission system or the loss of major generation resources. The results from these dynamic tests determine if the transmission system remains stable during a disturbance. The purpose of this analysis was to determine the impact of the Project on the existing system. Transient stability analysis was performed on the Pre-Project, N-S Project, and S-N Project cases discussed in Section 3.1.1, applying the contingencies listed in Section to these cases. Stability data were provided with the original WECC base case and additional stability data provided by the AESO were merged with this data to maintain consistency with the new AESO case that replaced the original Alberta model in the case. Because the detailed dynamic performance of the Project is not yet available, the Intermountain DC dynamics model was used as a template for the purposes of this study. Table A5-1 in Appendix 5 summarizes the results of transient stability studies, indicating actions that occur for each contingency and problems identified. Plots of the transient stability analysis output are found in Appendix 6. The most significant findings are described below. In all three cases, for the Custer Ingledow #1 & 2 500kV double-line outage, which results in separation between the Northwest and the Canadian Provinces, BCTC s Rx RAS is critical for controlling high voltages in Canada. Initial results showed severe problems because this RAS was not modeled, but these problems were resolved by modeling this RAS. With the BCTC Rx RAS modeled, both the Pre-Project case and N-S Project case meet all WECC criteria without new RAS actions. With the exception of one contingency, the S-N Project case also meets WECC criteria without new RAS actions. For the S-N Project case, the NorthernLights DC bi-pole outage raises some issues: - The bi-pole Project outage causes transient voltage dips in Montana that do not meet WECC criteria. For example, the BOLE 69kV load bus in Montana experiences a 21.6% voltage deviation for 49 cycles, slightly exceeding the maximum transient voltage dip of 20% for 40 cycles at a load bus. There are 7 such load bus transient voltage dip violations, all in Montana. These voltage dips are a result of the MATL tie picking up excessive S-N flow following a bi-pole Project outage. One potential resolution of this violation is to trip the MATL project for this outage; modeling this action did resolve all problems in Montana. The possibility of tripping the MATL project for this outage, or some other mitigation, will need to be resolved between TransCanada and the owners of 4.0 Study Results Page 23 of 60

27 MATL during the next phase of the rating process. (Note that contingency studies assumed that MATL would be tripped for this outage for consistency.) - No Northwest generation dropping is assumed to be necessary for this outage because there are no criteria violations in the Pacific Northwest. However, as a sensitivity study, BPA s Low Gen Drop RAS was applied for the S-N bi-pole Project outage to see if there would be any adverse impacts. The study uncovered no criteria violations related to this generation tripping. With the modifications noted above modeled, transient stability analysis results show that the Project meets all WECC criteria. 4.4 Post-Transient Voltage Stability Study Results To verify adequate reactive margin for voltage stability under the studied conditions, studies were run as described in Section 3.4. The Project flow in both the N-S and S-N cases was increased to 2100 MW by increasing and decreasing load by 100 MW in the Alberta and Northwest areas, as appropriate, to hold all other interchange flows constant. Then, all contingencies were run with these modified cases to verify that the cases converge for all contingencies under these conditions. Results showed that all contingencies solved, indicating acceptable reactive margin for the studied B and C contingencies under the modeled system conditions. 4.0 Study Results Page 24 of 60

28 5.0 CONCLUSION The NorthernLights project is an HVDC project that will extend from Milo, Alberta to the Buckley Substation area of Grass Valley, Oregon. Power flow, transient stability, and posttransient studies have been performed for both north-to-south and south-to-north flow directions to validate the requested bi-directional 2000 MW rating. The results of these studies are summarized as follows: Canada power flow analysis results indicate a handful of problems that are being resolved, are not Project-related, or are problems to be resolved by local planning processes. Pacific Northwest power flow analysis results indicate that the best Project arrangement is for the Buckley New Substation to be tied to the existing Buckley Substation, with RAS actions recommended to resolve 500kV issues between the Buckley substations and Grizzly. Also, a handful of other lower voltage line overloads either appear to be unrelated to the Project or will be further investigated in an upcoming BPA Interconnection Study. Transient stability study results show that, with the assumption for the S-N Project bi-pole outage that MATL will be tripped, all WECC criteria are met for the transient conditions studied without the need for any new RAS actions. Post-transient reactive margin verification studies show that all contingencies converge with 105% Project flow, indicating adequate reactive margin for the conditions studied. In the process of conducting these studies, the following potential simultaneous path interactions were identified: Interactions with MATL following a bi-pole outage of the Project will need to be considered to avoid transient voltage deviation violations in Montana Interactions with Path 3 between British Columbia and the Northwest and Path 1 between British Columbia and Alberta will need to be considered for bi-pole outages of the Project, and Alberta and Pacific Northwest RAS actions will need to be determined for a variety of potential operating conditions 5.0 CONCLUSION Page 25 of 60

29 TransCanada has completed studies conforming to the guidelines for Phase 1, as documented in this report. In the spirit of cooperation and openness, TransCanada has actively participated in the TCWG since January 2008, coordinating study assumptions and sharing data and results with other entities planning projects terminating in the Pacific Northwest and with all other interested parties. With the submission of this report showing that this project meets all applicable NERC and WECC standards and with the separate submission of full project representation to WECC for inclusion in WECC base cases, TransCanada requests formal completion status of Phase 1 and the establishment of a new transmission path with a Planned Rating of 2000 MW bidirectional for the NorthernLights Project. 5.0 CONCLUSION Page 26 of 60

30 APPENDIX 1: Project Diagrams Figure A1-1: Milo Substation Power Flow One-Line Diagram APPENDIX 1: Project Diagrams Page 27 of 60

31 Figure A1-2: Buckley Substation Aerial View APPENDIX 1: Project Diagrams Page 28 of 60

32 Figure A1-3: Air-Insulated Station Near Buckley - Power Flow One-Line Diagram APPENDIX 1: Project Diagrams Page 29 of 60

33 Figure A1-4: Air-Insulated Station Near APPENDIX 1: Project Diagrams Buckley WECC Map Page 30 of 60

34 Figure A1-5: New Transmission Projects in the Northwest Planned Operation: APPENDIX 1: Project Diagrams Page 31 of 60

35 APPENDIX 2: Power Flow Base Case Conditions Path Path Rating Original WECC 15HS1SA1 Case Flow Revised WECC 15HS1SA1 Case Flow N-S NorthernLights Case S-N NorthernLights Case Path 1 Alberta BC Path 101 (MATL) Alberta Montana Path 102 (NorthernLights) Alberta Northwest 1200 MW (w-e) 1000 MW (e-w) 300 MW (n-s) 300 MW (s-n) 2000 MW (n-s) 2000 MW (s-n) 400 MW (w-e) 340 MW (w-e) 342 MW (w-e) 597 MW (e-w) Not Modeled 60 MW (s-n) 59 MW (s-n) 58 MW (s-n) Not Modeled Not Modeled 1945 MW net* (n-s) 1945 MW net* (s-n) Alberta Net Interchange 400 MW import 400 MW import 1600 MW export 1460 MW import Path 3 Northwest - Canada 3150 MW (n-s) 2000 MW (s-n) 2300 MW (n-s) 73% 2360 MW (n-s) 75% 2359 MW (n-s) 75% 2357 MW (n-s) 75% Path 5 West of Cascades South 7000 MW (e-w) 4796 MW (e-w) 5489 MW (e-w) 4636 MW (e-w) 4174 MW (e-w) Path 26 Midway - Vincent 4000 MW (n-s) 3000 MW (s-n) 509 MW (n-s) 468 MW (n-s) 495 MW (n-s) 630 MW (n-s) Path 65 PDCI 3100 MW (n-s) 3100 MW (s-n) 2000 MW (n-s) 64% 2800 MW (n-s) 90% 2800 MW (n-s) 90% 2800 MW (n-s) 90% Path 66 Oregon - Northern California 4800 MW (n-s) 3675 MW (s-n) 3758 MW (n-s) 78% 4461 MW (n-s) 93% 4489 MW (n-s) 94% 4616 MW (n-s) 96% Path 73 North of John Day 7900 MW (n-s) 6601 MW (n-s) 79% 7183 MW (n-s) 86% 5969 MW (n-s) 71% 8105 MW (n-s) 102% Path 75 Midpoint Summer Lake 1500 MW (e-w) 400 MW (w-e) 294 MW (e-w) 221 MW (e-w) 139 MW (e-w) 236 MW (e-w) * Initial DC line loss allocation assumed 50%, so ~61 MW losses were assigned to each terminal s area; = 1945 MW net. APPENDIX 2: Power Flow Base Case Conditions Page 32 of 60 Table A2-1: Summer Base Case Path Flows