BVY 04-086, Attachment 2, Vermont Yankee - Proposed Technical Specification Change No. 263 - Supplement No. 12 Extended Power Uprate - Revised Grid Impact Study Revised System Impact Study

Attachment 2, Vermont Yankee - Proposed Technical Specification Change No. 263 - Supplement No. 12 Extended Power Uprate - Revised Grid Impact Study Revised System Impact Study

ML042430573
Person / Time
Site:	Vermont Yankee
Issue date:	11/11/2003
From:	Clark K, Wu M General Electric Co
To:	Office of Nuclear Reactor Regulation
References
BVY 04-086
Download: ML042430573 (105)

Text

BVY 04-086 Docket No. 50-271 Attachment 2 Vermont Yankee Nuclear Power Station Proposed Technical Specification Change No. 263 - Supplement No. 12 Extended Power Uprate - Revised Grid Impact Study Revised System Impact Study Total number of pages In Attachment 2 l (excluding this cover sheet) Is 102. l

GE PowerSystems Final Report to:

ISO-New England for Vermont Yankee Uprate System Impact Study Prepared by:

Kara Clark Ming Wu November 11, 2003

Foreword This document was prepared by General Electric International, Inc. through its Power Systems Energy Consulting (PSEC) in Schenectady, NY. It is submitted to ISO-New England. Technical and commercial questions and any correspondence concerning this document should be referred to:

Kara Clark Power Systems Energy Consulting General Electric International, Inc.

Building 2, Room 624 Schenectady, New York 12345 Phone: (518) 385-5395 Fax: (518) 385-9529 E-mail: kara.clark(ps.ge.com RepartllllO3.cfoc Systems GE-PowerSystems Energy Consulting GE-Power iiii Consulting Energy I Report11101odoc

Legal Notice This report was prepared by General Electric International, Inc.'s Power Systems Energy

'Consulting (PSEC) as an account of work sponsored by ISO-New England. Neither ISO-New England nor PSEC, nor any person acting on behalf of either:

I. Makes any warranty or representation, expressed or implied, with respect to the use of any information contained in this report, or that the use of any information, apparatus, method, or process disclosed in the report may not infringe privately owned rights.

2. Assumes any liabilities with respect to the use of or for damage resulting from the use of any information, apparatus, method, or process disclosed in this report.

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Table of Contents EXECUTIVE S UNINARY .................................... VI

1. INTRODUCTION.............................................................................................................................................

.1.1

2. STUDY APPROACH ................................... 2.1 2.1 POWER FLOW STUDY .................................... 2.1 2.1.1 Benchmark System ................................... 2.1 2.1.2 Vermont Yankee Full Uprate System ................................... 2.3 2.1.3 Performance Criteria................................... 2.9 2.1.4 ContingencyList................................... 2.10 2.2 TRANSIENT STABILITY STUDY ................................... . 2.12 2.2.1 Benchmark System .2.12 2.2.2 Vermont Yankee Full UprateSystem.2.18 2.2.3 Performance Criteria.2.19 2.2.4 FaultScenario List.2.19 2.2.5 OtherDynamic Modeling.2.24 2.2.6 Special ProtectionSystem Modeling.2.25

3. PONVER FLOWVANALYSIS RESULTS .3.1 3.1 GUIDE TO POWER FLOW ANALYSIS RESULTS WORKBOOK . .3.1 3.2 PRE-CONTINGENCY BUS VOLTAGE RESULTS .. 3.2 3.2.1 Vermont Yankee 115kV CapacitorSvitching Evaluation.3.3 3.2.2 Vermont Yankee FirstPhase Uprate Impact on 345kV Voltage .3.8 3.3 POST-CONTINGENCY BUS VOLTAGE RESULTS .. 3.9 3.3.1 Vermont Yankee 115kV CapacitorPost-ContingencyEvalutation.3.9 3.4 PRE-CONTINGENCY BRANCH LOADING RESULTS .. 3.9 3.5 POST-CONTINGENCY BRANCH LOADING RESULTS .. 3.9 3.5.1 Impact of.Additional Breakers at Chelsea andHartford 115V.3.9 3.6 N-2 CONTINGENCY ANALYSIS RESULTS .. 3.9

4. TRANSIENT STABILITY ANALYSIS .......................................................... 4.9 4.1 GUIDE TO STABILITY SIMULATION RESULTS ..................... ..................................... 4.9 4.2 2006 LIGHT LOAD CASE WITH HIGH MAINE GENERATION (SLTI) . .............................4.9 4.2.1 Normally ClearedFaults.......................................................... 4.9 4.2.2 7hree-PhaseStuck Breaker Faults.......................................................... 4.9 4.3 2006 LIGHT LOAD CASE WITH HIGH NEWINGTON GENERATION (SLT2) . .........................

4.9 4.3.1 Normally ClearedFaults.......................................................... 4.9 4.3.2 Three-PhaseStuck BreakerFaults.......................................................... 4.9 4.4 2006 SUMMER PEAK LOAD CASE (SPKI) .......................................................... 4.9 4.4.1 Normally ClearedFaults.......................................................... 4.9 4.4.2 Three-PhaseStuck Breaker Faults....................................................................................... 4.9 4.5 2006 SUMMER PEAK LOAD SENSITIVrrY ANALYSIS (SPK4, SPK5). 4.9 4.6 APANALYSISREsuLT. .4.9 4.7 VERMONT YANKEE EXCITER MODELING .4.9 4.8 OUT OF STEP PROTECTION .4.9 4.9 AMHERST PROJECT SENSITIVITY .4.9

5. SHORT CIRCUIT ANALYSIS .5.9

6. CONCLUSIONS AND RECOMMENDATIONS. .6.9 6.1 POWER FLOW ANALYSIS .6.9 6.2 TRANSIENT STABILITY .6.9 GE-Power Systems Energy GE-Power Systems Consulting Energy Consulting iv Repodl 11103.rioc Reportt11 103.doc iv

APPENDIX A. BENChMN1ARK POWER FLOW SUMINIARIES AND DIAGRAMS FOR POWER FLOW ANALYSIS ........ ........................................................................... A-9 APPENDIX B. FULL UPRATE POWER FLOWN SUMNIMARIES AND DIAGRAMS FOR POWER FLOW ANALYSIS .................................................................................... B-9 APPENDIX C. BENCIIIMARK POWER FLOW SUNMNMARIES AND DIAGRAMS FOR TRANSIENT STABILITY ANALYSIS ................................................................................... C-9 APPENDIX D. VERMNIONT YANKEE BENCIINIARK DYNAMIC MODELS. ......................................D-9 APPENDIX E. FULL UPRATE POWER FLOW SUMIMtARIES AND DIAGRAMS FOR TRANSIENT STABILITY ANALYSIS............................................................................................................................................

.E-9 APPENDIX F. VERMIONT YANKEE FULL UPRATE DYNAMIC M1ODELS.................................................F-9 APPENDIX G. MILLSTONE #3 EXCITER IODEL.........................................................................................G-9 APPENDIX }1. OUT-OF-SERVICE MODELS FOR IN-SERVICE GENERATORS ...................................... II-9 APPENDIX 1. PONWER FLOW SUMNMNARIES AND DIAGRAMS FOR N-2 ANALYSIS ................................ 1-9 APPENDIX J. VERMONT YANKEE EXCITER MODELS FOR SENSITIVITY ANALYSIS ...................... J-9 APPENDIX K. ENTERGY TRANSMITTAL OF EXCITER MODEL DATA ................................................. K-9 APPENDIX L. PRELIMINARY OUT OF STEP RELAY PROTECTION .................... ................................... L-9 V Repoifl 11103.cfoc GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy v Reportff1 l03doc

Executive Summary Entergy is requesting approval for an uprate of the Vermont Yankee nuclear plant. The Vermont Yankee Extended Power Uprate Project will increase the output of the unit in two steps. During the refueling outage scheduled for spring of 2004, numerous modifications will be implemented, including replacement of the high pressure turbine steam path and rewind of the main generator to increase the nameplate rating to 684MVA. Following receipt of Nuclear Regulatory Commission (NRC) approval of the Extended Power Uprate license amendment application during the third quarter of 2004, Vermont Yankee will increase its power output to as high as 630 MW gross and 220 MVAR. After the refueling outage scheduled for the fourth quarter of 2005, Vermont Yankee will further increase its power output to 667 MW gross and 150 MVAR. The bulk of the study focused on this full uprate to 667MW and 150MVAr. A limited sensitivity analysis evaluated the first phase uprate of 630MW and 220MVAr.

The purpose of this study was to analyze the impact of the full uprate on the interconnected New England system in accordance with the "NEPOOL Reliability Standards" and the NEPOOL "Minimum Interconnection Standard", and to identify any necessary facility upgrades to meet these standards under the NEPOOL Subordinate 18.4 Application Policy. Relevant queued resources for this project include the Berwick Energy Center, UAE Tewksbury, Neptune Phase 3 Boston Import, Neptune Phase 7 Wyman Export, Mystic 4,5, 6 conversion, and Millstone #3 uprate projects. Vermont Yankee is subordinate to all of these.

For this study, the existing Vermont Yankee unit was represented with a rating of 626MVA, a power output rating of 563MW, and a gross reactive power output rating of 150MVAr at rated power output.

The final Vermont Yankee uprate configuration, with a power output of 667 MW gross, was evaluated rather than the intermediate uprate, with a power output of 630 MW gross.

An analysis of system performance with the final uprate and its associated reinforcements ensures that system performance with the intermediate uprate and the same reinforcements would be acceptable. Therefore, the proposed full uprate project was represented with a rating of 684MVA, a final power output rating of 667MW, and a gross reactive power output rating of 150MVAr at rated power output. There is no expected change to the station service or cooling tower loads, which are 25.5MW, 13.5MVar and 8.5MW, 5.7MVAr, respectively. Therefore, the net rating of the full uprate, as evaluated in this study with all station service and cooling loads in service under peak load conditions, was 633MW.

For the stability analysis, the Vermont Yankee exciter was modeled, both pre- and post-full uprate, with an e-xac3a model representing an IEEE type AC3A excitation system.

This is the manufacturer recommended model and replaced the ieeetl model used in prior studies. Therefore, this study also supports the exciter model change.

This study used a relative performance approach to determine the impact of the proposed Vermont Yankee nuclear plant full uprate on the New England (NE) power system. First, GE-Power Systems Energy GE-Power Systems Consulting Energy Consulting vi ReportllllO3.doc Report111103.doc vi

system performance without the proposed uprate was determined in order to establish the benchmark. Then system performance with the proposed full uprate was determined and compared to the benchmark. This relative approach removed any ambiguities as to the actual impact of the proposed project since existing criteria violations, if any, were identified.

Power flow and stability analyses were performed, including a voltage and thermal N-1 contingency analysis, a thermal N-2 contingency analysis, a transient stability analysis, and a AP analysis.

No short circuit analysis was performed because there was no significant change to the generator impedances, as described in Section 5.

The power flow analysis indicated that the following upgrades will be required as part of the Vermont Yankee uprate project:

1. Increase the pre-contingency MVA rating on the Vermont Yankee-Northfield 345kV line (Section 381) from the current rating of 896MVA to a minimum rating of 1075MVA by replacing the limiting line relay equipment.

2. Increase the post-contingency MVA rating on the Ascutney-Coolidge 11 5kV line from the current LTE rating of 205MVA to 240MVA by replacing approximately 25 feet of the limiting riser conductor.

3. Ensure that the Vermont Yankee 345kV pre-contingency bus voltage is not degraded as a result of the full uprate project by the addition of 60MVAr of shunt capacitors at the Vermont Yankee 115kV bus (Section 3.2). One bank of 30MVAr and two banks of 15MVAr are proposed. The 30MVAr bank should be connected such that is trips with the autotransformer. The 15MVAr banks should be connected to the 115kV bus such that they are available with the autotransformer out of service.

The study identified the Vermont Yankee-Northfield 345kV line relay replacement as a reliability upgrade required to mitigate preexisting conditions. It was not prompted by the Vermont Yankee full uprate, however it is required for the full uprate. The Ascutney-Coolidge 115kV line upgrade and Vermont Yankee 115kV shunt capacitors are upgrades associated with the full uprate project itself. The Vermont Yankee area voltage performance was significantly better with the full uprate and its associated capacitor banks than with the existing system. In addition, Entergy has verified that there is sufficient room for the capacitor banks and any associated equipment.

Overloads were also observed, both with and without the full uprate, on the Wallingford Tap-Mt Holly-Ludlow 46kV line segment under peak load conditions in response to the Ascutney-Coolidge 115kV line outage. This is a pre-existing problem that is adversely impacted by the full uprate. Currently, there is no proposed mitigation for this problem.

The full uprate is not responsible for any additional mitigation.

The N-2 power flow analysis, as described in Section 3.6, showed the need for no additional system reinforcements due to the full uprate. The Vermont Yankee plant will be required to reduce power output at the rate of approximately 13MW/min in order to GE-Power Systems GE-Power Energy Consulting Systems Energy Consulting vii RepartllllO3.doc ReportI11103.doc vii

reduce output from 667MW to 275MW in 30 minutes. Entergy has confirmed that this ramp rate can be safely achieved.

While the bulk of the power flow analysis focused on system performance with the full uprate, Entergy requested a sensitivity analysis of the impact of the first phase uprate (630MW, 220MVAr) on the pre-contingency Vermont Yankee 345kV bus voltage. The evaluation focused on the most limiting Vermont generation dispatch scenario under 2006 extreme weather peak load conditions. The pre-uprate Vermont Yankee 345kV bus voltage was 1.024pu. For the first phase uprate, 1.024pu on the Vermont Yankee 345kV bus was achieved with an output of 194MVAr from the unit, which is within the 220MVAr capability. This analysis showed that the 345kV bus voltage could be maintained at pre-uprate levels after the first phase uprate without the 115kV capacitor banks required for the full uprate.

The results of the stability analysis are described in Section 4 and show that the following upgrades will be required as part of the Vermont Yankee full uprate project:

I. Modification to provide a second primary protection scheme on the Vermont Yankee north bus to achieve acceptable performance in response to the normal contingency fault NC 14.

2. Addition to provide a second primary protection scheme on the Vermont Yankee GSU to achieve acceptable performance in response to the normal contingency fault NC15.

3. Independent pole tripping on the Vermont Yankee 381 breaker is required to achieve acceptable performance in response to the extreme contingency fault EC8.

4. Addition of out of step protection on the Vermont Yankee generator to ensure acceptable performance in response to several extreme contingencies.

The study identified the second primary protection schemes as reliability upgrades required to mitigate preexisting conditions. It was not prompted by the Vermont Yankee full uprate, however it is required for the full uprate. The IPT breaker operation and the out of step protection are upgrades associated with the full uprate project itself. Whether breaker 381 upgrade or replacement is required to achieve IPT capability will be determined by the facilities study.

AP is the sudden change in generator power output resulting from line switching; it is measured in per unit of the machine MVA rating. AP levels that could be imposed on the Vermont Yankee generator were calculated under relatively stressed transmission system loading conditions that would result in relatively high AP values. The highest level observed for the uprate with all lines in service was 0.36pu in response to reclosing Section 381 (Vermont Yankee-Northfield 345kV). The highest AP observed for the full uprate with a line out of service was 0.39pu in response to reclosing Section 381 (Vermont Yankee-Northfield 345kV) with Section 394 (Seabrook-Tewksbury 345kV) out. The Vermont Yankee project has the option to mitigate the AP levels if it deems such action necessary.

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After the full uprate, the Vermont Yankee plant operators will continue to be required to reduce plant output to 275MW within 30 minutes of being instructed to do so by the System Operator immediately following the occurrence of certain single line outages.

This requirement enables the System Operator to return the system to a secure operating state within 30 minutes of a continuous outage of a single transmission line or facility in accordance with established operating criteria.

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1. Introduction Entergy is requesting approval for an uprate of the Vermont Yankee nuclear plant. The Vermont Yankee Extended Power Uprate Project will increase the output of the unit in two steps. During the refueling outage scheduled for spring of 2004, numerous modifications will be implemented, including replacement of the high pressure turbine steam path and rewind of the main generator to increase the nameplate rating to 684MVA. Following receipt of Nuclear Regulatory Commission (NRC) approval of the Extended Power Uprate license amendment application during the third quarter of 2004, Vermont Yankee will increase its power output to as high as 630 MW gross and 220 MVAR. After the refueling outage scheduled for the fourth quarter of 2005, Vermont Yankee will further increase its power output to 667 MW gross and 150 MVAR. The bulk of the study focused on this full uprate to 667MW and 150MVAr. A limited sensitivity analysis evaluated the first phase uprate of 630MW and 220MVAr.

The purpose of this study was to analyze the impact of the full uprate on the interconnected New England system in accordance with the "NEPOOL Reliability Standards" and the NEPOOL "Minimum Interconnection Standard", and to identify any necessary facility upgrades to meet these standards under the NEPOOL Subordinate 18.4 Application Policy. Relevant queued resources for this project include the Berwick Energy Center, UAE Tewksbury, Neptune Phase 3 Boston Import, Neptune Phase 7 Wyman Export, Mystic 4,5, 6 conversion, and Millstone #3 uprate projects. Vermont Yankee is subordinate to all of these.

The capabilities of the existing Vermont Yankee plant as well as the proposed full uprate are shown in Table 1-1. For this study, the existing Vermont Yankee unit was represented with a rating of 626MVA, a power output rating of 563MW, and a gross reactive power output rating of 150MVAr at rated power output. The final Vermont Yankee uprate configuration, with a power output of 667 MW gross, was evaluated rather than the intermediate uprate, with a power output of 630 MW gross. An analysis of system performance with the final uprate and its associated reinforcements ensures that system performance with the intermediate uprate and the same reinforcements would be acceptable. Therefore, the proposed uprate project was represented with a rating of 684MVA, a final power output rating of 667MW, and a gross reactive power output rating of 150MVAr at rated power output.

A one-line diagram of the Vermont Yankee plant and substation is shown in Figure 1-1.

The station service load is connected to the generator terminal bus, and the cooling tower load is connected to the 115kV bus. Station service load is in-service for all system conditions. The cooling tower load is in-service for all study conditions except for the light load cases, because it is not needed during lower ambient temperatures.

The study approach is described in Section 2. Power flow, transient stability and short circuit analyses were performed. The results of the power flow analysis are described in Section 3, the stability analysis results are described in Section 4 and the short circuit analysis results are described in Section 5. Conclusions and recommendations are presented in Section 6.

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Table 1-1. Capability of Existing and Full Uprate Vermont Yankee Plant.

Generator (gross) Present Full Uprate MVA rating 626 MVA 684 MVA Pmax 563 MW 667 MW Pmin 0 MW 0 MW Qmax 150 MVAr 150 MVAr Qmin -100 MVAr -100 MVAr Station Service Load P 25.5 MW 25.5 MW Q 13.5 MVAr 13.5 MVAr Cooling Tower Load P 18.5 MW 18.5 MW Q l5.7 MVAr l5.7 MVAr to Amherst 345kV L- }4o Chestnut Hill 5B K186 & Vernon Rd t)Cooling Tower Load CUT) , to Northfield 4160v Staton Service Load Figure 1-1. E-isting Vermont Yankee Plantand Substation One-Line Diagram.

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2. Study Approach This study used a relative performance approach to determine the impact of the proposed Vermont Yankee nuclear plant full uprate on the New England (NE) power system. First, system performance without the proposed uprate was determined in order to establish the benchmark. Then system performance with the proposed full uprate was determined and compared to the benchmark. This relative approach removed any ambiguities as to the actual impact of the proposed project since existing criteria violations, if any, were identified. The following Sections describe the benchmark system conditions, full uprate project study scenarios, as well as the performance criteria and contingency list.

The analysis was performed using PSEC's Positive Sequence Load Flow (PSLF) software package. PSLF is a large-scale database and network solution program for power flow analysis. It also includes the Symmetrical Component Short-Circuit (SCSC) program for fault current calculations and the Positive Sequence Dynamic Simulation (PSDS) program for transient stability analyses.

2.1 Power Flow Study 2.1.1 Benchmark System The study was based on the "2000 New England Library" summer peak and light load conditions for 2006. The study cases were developed from databases used in a previous study. Mutually agreed upon modifications were made to these databases before the study began. Such modifications included the addition of new generating units, transmission system reinforcements, and load increases to better reflect expected 2006 load levels.

The generation unit additions were as follows:

• AES Londonderry 721MW combined cycle plant connected to the 230kV lines between Tewksbury and Comerford

• UAE Lowell, two 46MW units connected near the Tewksbury 11 5kV bus

• UAE Tewksbury, three 200MW gas turbines connected to the Tewksbury 345kV bus

• Mystic 8 800MW combined cycle plant connected to the Mystic 345kV bus

• Mystic 9 800MW combined cycle plant connected to the Mystic 115kV bus

• Fore River 800MW combined cycle plant connected to the Edgar 115kV bus The transmission system modifications were as follows:

• Add Vermont 46kV system from Bennington to Vernon Rd

• Modify CVPS 46kV loads, increase Wallingford Tap-Mt. Holly-Ludlow 46kV line rating from 17MVA to 17.9MVA

• Add two 13.1 MVAr, one 26.2MVAr capacitor banks at Chestnut Hill 11 5kV bus

• Add 350MVA, +/-60 degree PAR at Sand Bar 11 5kV bus 2.1 Reparfl II 103.doc Systems Energy GE-Power Systems GE-Power Consulting Energy Consulting 2.1 RepW11 1103.doc

• Add 24.75MVAr 115kV capacitor bank at Georgia 115kV bus

• Add 26.4MVAr capacitor bank at each of the two 115kV Ocean Road buses

• Add two 25.4MVAr, one 12.6MVAr capacitor banks at Three Rivers 11 5kV bus

• Add two 25.4MVAr capacitor banks at Madbury 11 5kV bus

• Add 104.8MVAr capacitor bank at Frostbridge 11 5kV bus

• Add 157.2MVAr capacitor bank at Southington 115kV bus

• Add 63MVAr capacitor bank at Millbury 115kV bus

• Add 54MVAr capacitor bank at NBORO Road 115kV bus

• Add 20MVAr capacitor bank at Beebe 115kV bus

• Add 50MVAr capacitor bank at Crowleys 115kV bus

• Add 72MVAr capacitor bank at Merrimack 11 5kV bus

- Add a second Scobie 345/115kV autotransformer, identical to the existing autotransformer

• Upgrade Merrimack 230/115kV transformer rating from 230/245/305 MVA to 230/300/305 MVA

• Upgrade Deerfield-Garvins 115kV (Section G146) transmission line rating from 160/170/200 MVA to 300/380/430 MVA

• Upgrade Dover-Three River 11 5kV line rating from 165/180/210 MVA to 165/240/240 MVA

• Upgrade Maxcys-Bowman 1 15kV (Section 60) rating from 185.1/226.1/241.4 MVA to 190.1/232.5/251.5 MVA

• Maxcys-Augusta East Side 115kV (Section 88) line rating from 72.2/72.2/79.1 MVAto 126.8/126.8/135.1 MVA

• Upgrade Scobie-Lawrence 345kV line rating from 1220/1405/1430 MVA to 1220/1430/1430 MVA

• Upgrade Dunbarton-Merrimack 230kV line rating from 230/245/305 MVA to 230/300/305 MVA

• Add a third PAR at Waltham, identical to the two existing PARs

• Add 2.75ohm series reactor to Mystic-Woburn 115 kV line

• Add North Cambridge-Brighton A 115kV series reactor

• Add North Cambridge-Brighton B 11 5kV series reactor

• Add Great Bay 11 SkV substation, 115/34.5kV transformer, and 27.1 MW, 3.9MVAr load The proposed VELCO 115kV Northern Loop project, with an expected in service date of December 2004, and the proposed VELCO Northwest Vermont Reliability Project (NRP), with expected in service dates ranging from May 2004 to December 2007, were 2.2 Repotfl 111034cc GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy 2.2 Reportt 11 103.doc

not included. These projects were not represented for two reasons. First, because of uncertainties regarding in service dates and whether or not the VELCO projects would be completed before the full uprate. Second, because the full uprate would not adversely impact system performance with these projects due to its electrical distance from the projects and the intent of the VELCO projects is to maintain rather than increase the transfer capability of the transmission system external to Vermont.

A detailed model of the Vermont Yankee plant, down to the 4.16kV buses, was added to the system model. This load model includes transformers, individual motors and lumped equivalent induction motors. The 4160v plant buses are shown in all one-line diagrams of the Vermont system.

The Essex STATCOM was represented as a synchronous condenser in the power flows with a reactive power capability of +/-75MVAr. Two 5 MVAr capacitor banks were modeled on the STATCOM 3.2kV terminal bus. In addition, a total of 148.5MVAr of shunt capacitor banks were represented on the Essex 115kV bus. Two banks (24.75MVAr each) are always in service. The remaining four banks are in service as needed to support the Essex 11 5kV bus voltage.

The Highgate HVDC link is included in all cases, but with power transfer levels that vary with system load condition. The shunt capacitor banks at the Highgate 115kV bus are represented by a synchronous generator with a reactive power capability from 0 to 140MVAr.

For the power flow analysis, three peak load cases, representing the 2006 summer 90/10 peak load condition as published in the 2003 CELT report (New England total load and losses of approximately 28029 MW) were developed. One light load case, representing the 2006 light load condition (45% of 50/50 peak load, or approximately 11831 MW),

was developed. One shoulder load case, representing the 2006 75% of 50150 summer peak load condition (approximately 19715 MW), was developed. A second light load sensitivity case was also developed. The databases used in the power flow analysis represented each generation unit's maximum power output at its 50'F operating capability. Station service load is in-service for all system conditions. Cooling tower load is in-service for all conditions except for the light load cases, because it is not needed during lower ambient temperatures.

A brief summary of each benchmark case, including significant interface flows and major New England real and reactive power generation output, is shown in Tables 2-1 and 2-2.

Table 2-1 shows the real power output of major New England generating plants and selected NE interface flows. Table 2-2 shows the reactive power output of major New England generating plants and selected reactive device output. A detailed summary for each case of the generation dispatch across New England, as well as additional interface flows and other information, is included in Appendix A. One line diagrams of the Vermont and NE 345kV transmission system for each case are also included in this appendix.

2.1.2 Vermont Yankee Full Uprate System The proposed Vermont Yankee nuclear plant full uprate increases the unit rating from 626MVA to 684MVA and the maximum power generation from 563MW to 667MW.

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The maximum reactive power output remains at 150MVAr. There is also no expected change in the station service or cooling tower loads.

Six power flow cases with the proposed Vermont Yankee full uprate were developed from the six benchmark cases described above. The Vermont Yankee full uprate was redispatched against Merrimack G1 for all cases.

A brief summary of each full uprate case, including significant interface flows and major New England real and reactive power generation output, is also shown in Tables 2-1 and 2-2 with the corresponding benchmark cases. Table 2-1 shows the real power output of major New England generating plants and selected NE interface flows. Table 2-2 shows the reactive power output of major New England generating plants and selected reactive device output. A detailed summary for each case of the generation dispatch across New England, as well as additional interface flows and other information, is included in Appendix B. One line diagrams of the Vermont and NE 345kV transmission system for each case are also included in this appendix.

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Table 2-1. Real Powver Summary for Major New lEtgland GeneratingPlantsandSelected Interface Flovsv.

Light Load,TLTI I ight Load, TLT2 Peak Load, TPKI l Peak Load, TPK2 1Peak Load, TPK3 Shoulder Load, TS111 Description Existing Full Existing Full Existing Full Existing Full Existing Full Existing Full Pmax3 Uprate Uprate Uprate Uprate Uprate Uprate NELoad(+Losses)' 11944 11941 11942 11939 28049 28049 28007 28008 28043 28042 19781 19782 NELoad(+Losses)Goal 11831 11831 11831 11831 28029 28029 28029 28029 28029 28029 19715 19715 Generation VT Yankee 563 667 563 667 536 667 536 667 536 667 536 667 563/667 Other Vermont 89 89 89 89 109 109 109 109 109 109 109 109 214 MIS 523 523 523 523 523 523 523 523 523 523 523 523 523 Bucksport 0 0 0 0 130 130 130 130 130 130 100 100 174 RPA 0 0 0 0 266 266 266 266 266 266 0 0 266 AEC 0 0 0 0 173 173 173 173 173 173 115 115 173 Other Western Maine' 67 67 67 67 233 233 185 185 233 233 198 198 247 WFWyman 1,2,3 0 0 0 0 57 57 0 0 57 57 57 57 239 WF Wynan 4 0 0 0 0 0 0 0 0 0 0 0 0 636 Westbrook 0 0 0 0 531 531 531 531 531 531 531 531 531 Schiller4,5,6 0 0 0 0 145 145 48 48 145 145 48 48 145 Merrimack 1,2 113 0 0 0 433 320 433 320 433 320 113 0 433 Newington I 0 0 0 0 411 411 411 411 411 411 0 0 411 Con Ed Newington 267 267 533 436 533 533 533 533 533 533 533 533 533 Canal 1,2 0 0 0 0 966 966 966 966 966 966 498 498 1142 Brayton Point 1,2,3,4 0 0 0 0 1501 1501 1260 1260 1501 1501 425 425 1501 AES Londonderry 721 721 721 721 721 721 721 721 721 721 721 721 810 UAETewksbury 0 0 0 0 0 0 0 0 0 0 0 0 591 Mystic 7 565 565 565 565 565 565 565 565 565 565 0 0 565 Mystic 8 0 0 0 0 824 824 824 824 824 824 700 700 824 Mystic 9 700 700 700 700 824 824 824 824 824 824 700 700 824 Edgar/Fore River 702 702 702 702 824 824 824 824 824 824 702 702 824 Seabrook 1209 1209 1209 1209 1209 1209 1209 1209 1209 1209 1209 1209 1209 NornhrieldfBearSwamp -1560 -1560 -1560 -1560 1640 1640 1640 1640 1640 1640 1640 1640 1640 Comerford/Moore 0 0 0 0 0 0 0 0 0 0 0 0 356 Salem Harbor 0 0 0 0 79 79 79 79 79 79 79 79 702 Millstone 2,3 2008 2008 2008 2008 1146 1146 1146 1146 1146 1146 1146 1146 2008 Total 3959 3950 4112 4119 13233 13251 12790 12808 13233 13251 9537 9555 GE-Power Systems Energy Consulting 2.5 Report111103doc

Table 2-1. Real PowerSumntaryfor Major New England GeneratingPlantsand Selected Interface Flows (continued,).

Light Load, TLTI Light Load, TLT2 j Peak Load, TPKI Peak Load, TPK2 Peak Load, TPK3 Shoulder Load, TSIII Description Existing Full Existing Full Existing Full Existing Full TExisting Full Existing Full Uprate Uprate Uprate Uprate j Uprate Uprate Interfaces NB/NE 696 696 696 696 l 696 696 696 696 696 696 696 696 Orrington-South 1095 1095 1095 1095 989 989 989 989 989 989 1083 1083 Surowiec-South 1082 1082 1048 1048 936 936 895 895 937 937 1043 1043 ME/Nil 971 971 937 937 1031 1030 932 932 1032 1032 1332 1332 SeabrookSouth 1195 1189 1333 1278 1625 1619 1606 1600 1617 1612 1416 1410 NNE-Scobie+394 2112 2083 2282 2192 2626 2595 2502 2471 2627 2596 2529 2498 (variable limit) (2385) (2385) (2545) (2545) (2800) (2800) (2800) (2800) (2800) (2800) (2725) (2725)

Nonth-South 2934 2929 3006 3012 2518 2536 2371 2388 2483 2502 2760 2777 East-West 712 605 726 633 1967 1858 1239 1130 2235 2126 1949 1839 CT Import -714 -714 -605 -606 2289 2289 2273 2273 2121 2121 1367 1366 PV 20 Import 143 145 141 141 144 144 144 145 143 144 141 142 NEMA/Boston Import 1171 1169 1157 1155 3814 3813 3790 3789 3774 3777 2799 2798 Boston Import 1053 1050 1043 1039 3242 3240 3214 3212 3254 3253 2361 2359 SEMA/RI Export -464 463 -495 -495 1829 1829 1260 1260 2061 2061 556 556 NY/NE .5 1 2 -8 18 -1 721 704 -692 -711 -1211 -1229 Northwest Vermont -11 -10 -11 -10 297 298 299 300 295 296 129 130 Central Vermont -93 -85 -71 -69 190 198 218 225 170 178 20 28 Highgate HVDC 220 220 220 220 215 215 215 215 215 215 215 215 Phase 11HVDC 0 0 0 0 2000 2000 2000 2000 2000 2000 2000 2000 Notes:

1. Does not include 95MW of motor load (modeled as generators)

2. Includes Wyman, Williams, Harris, SEA, Gorbell

3. Maximum power is the generator output in the power flow. For most machines it represents a net value. Station service load is modeled only at Vermont Yankee, Seabrook, Mystic 8, Mystic 9, and Fore River. At those plants, the maximum power therefore represents a gross value.

2.6 ReportllllO3.doc Energy Consulting GE-Power Systems Energy Consulting 2.6 Reot111101doc

Table 2-2. Reactive Pon'erSuonmmaryfor MajorNew Etgland Gen1eratingPlants atdSelected Interface Flovs.

l Light Load, TLTI Light Load, TLT2 Peak Load, TPKI Peak Load, TPK2 Peak Load, TPK3 Shoulder Load, TSII1I Description NE Load (+Losses)'

Existing 11944 Full Uprate 11941 Existing 11942 Full Uprate 11939 Existing 28049 Full Uprate 28049 Existing 28007 Full Uprate 28008

{l Existing 28043 Full Uprate 28042 Existing 19781 Full Uprate 19782 Qmax NE Load (+Losses) Goal 11831 11831 11831 11831 28029 28029 28029 28029 28029 28029 19715 19715 Reactive Generation VT Yankee 150 150 150 i150 5 150 150 150 150 150 150 ISO 150 Other Vermont -9 -8 -10 -10 I1 12 12 13 11 13 .6 -5 205 MIS 75 73 85 85 160 160 152 152 160 160 132 132 324 Bucksport 0 0 0 0 58 58 56 56 58 58 44 44 120 RPA 0 0 0 0 72 72 70 70 72 72 0 0 190 AEC 0 0 0 0 59 59 57 57 59 59 23 23 123 OtherWesternMaine' 3 3 3 3 45 45 35 35 45 45 12 12 103 WF Wymanl,2,3 0 0 0 0 14 14 0 0 14 14 14 14 83 WF Wyman 4 0 0 0 0 0 0 0 0 0 0 0 0 242 WVestbrook 0 0 0 0 103 104 107 108 104 105 114 115 330 Schiller 4,5,6 0 0 0 0 29 30 25 25 29 31 25 25 75 Merrimack 1,2 -10 0 0 0 54 56 49 51 57 58 -10 0 203 Newington I 0 0 0 0 38 39 35 36 39 39 0 0 180 ConEdNewington 0 0 38 27 113 116 105 108 116 118 108 110 330 Canal 1,2 0 0 0 0 359 359 359 359 359 359 120 120 359 Brayton Point 1,2,3,4 0 0 0 0 339 341 358 360 301 299 163 163 752 AESLondonderry 101 94 114 III 232 232 228 229 235 234 95 95 441 UAE Tewksbury 0 0 0 0 0 0 0 0 0 0 0 0 300 Mystic 7 .150 -150 -150 .150 204 207 221 234 184 191 0 0 335 Mystic 8 0 0 0 0 230 230 230 230 230 230 34 34 515 Mystic 9 50 42 45 43 328 328 331 336 325 325 134 133 515 Edgar/Fore River 0 -2 10 10 30 30 39 39 -7 -8 29 29 515 Seabrook 75 75 106 92 394 398 381 385 394 396 269 270 560 Northfield/Bear Swamp 341 346 351 366 514 515 536 538 516 517 502 501 610 Comerford/Moore 0 0 0 0 0 0 0 0 0 0 0 0 119 Salem Harbor 0 0 0 0 32 32 32 32 32 32 32 32 386 Millstone2,3 0 0 0 0 459 463 364 367 489 493 165 169 940 Total 626 623 742 727 3568 3587 3568 3603 3483 3497 1984 1997 Notes:

1. Does not include 95MW of motor load (modeled as generators)

2. Includes Wyman, Williams, Harris, SEA, Gorbell 2.7 Report1111O34c GE-Power Systems Energy Consulting Systems Energy ConsultIng 2.7 Repot111103.doc

Table 2-2. Reactive Power Sumimnaryfor iajorNew Eniglantd GeneratingPlantsand Selected Interface Flows (continuled).

Light Load, TLTI Light Load, TLT2 Peak Load, TPKI Peak Load, TPK2 Peak Load, TPK3 Shoulder Load, TSIII Description Existing Full Existing Full Existing Full Existing Full Existing Full Existing Full Qmax Uprate Uprate Uprate Uprate Uprate Uprate Reactive Devices Chester SVC 30 30 30 30 30 30 30 30 30 30 30 30 30 Orrington 345kV 201 201 201 201 201 201 201 201 21 201 201 201 201 Z of Maxcys, Mason, 300 300 250 250 350 350 350 350 350 350 300 300 300 Surowiec, South Gorham Crowleys ll5kV 50 50 50 50 50 50 50 50 50 50 50 50 50 Sanford 115kV 31 31 31 31 31 31 31 31 31 31 31 31 31 Beebe 115kV 20 20 20 20 20 20 20 20 20 20 20 20 20 3Riversll5kV 63 63 63 63 63 63 63 63 63 63 63 63 63 Ocean 115kV 53 53 53 53 53 53 53 53 53 53 53 53 53 Merrimack 230kV 72 72 72 72 72 72 72 72 72 72 72 72 72 Madbury 115kV 51 51 51 51 51 51 51 51 51 51 51 51 51 Chestnut Hill 115kV 52 52 52 52 52 52 52 52 52 52 52 52 52 HighgatellSkV 112 113 112 111 104 105 105 106 15 105 107 107 112 llighgate 46kV 0 0 0 0 0 0 0 0 0 0 0 0 0 Georgia 115kV 25 25 25 25 25 25 25 25 25 25 25 25 25 Sand Bar 115kV 0 0 0 0 25 25 25 25 25 25 25 25 0 Berlin 115kV 25 25 25 25 25 25 25 25 25 25 25 25 25 Barre34.5kV II I 1 II 16 16 16 16 16 16 16 16 II iEssex Caps II5kV 109 109 109 109 119 119 119 119 124 124 119 119 109 Essex STATCOM -6 -6 -8 -8 -1 -1 -1 0 -1 0 -8 -8 -6 Williston 115kV 0 0 0 0 25 25 25 25 25 25 0 0 0 Middleburyll5kV 0 0 0 0 23 23 23 23 23 23 0 0 0 Rutland 115kV 0 0 0 0 24 24 24 24 24 24 0 0 0 Coolidge 115kV 50 50 50 50 50 50 50 50 50 50 50 50 50 Ascutney46kV 16 16 16 16 16 16 16 16 16 16 16 16 16 GE-Power Systems Energy Consulting 2.8 RepWIt11103.dc

2.1.3 Performance Criteria For the power flow analysis, different thermal, or branch loading, performance criteria were used for normal operation and for contingency operation. Similarly, different criteria were used to determine acceptable pre- and post-contingency bus voltages.

The thermal criteria required branch loading to be less than 100% of normal rating (Rate

1) for pre-contingency conditions, and to be less than the long term emergency (LTE) rating (Rate 2) for post-contingency conditions. The voltage criteria are summarized in Table 2-3.

Table 2-3. Voltage PerformanaceCriteriafor Power Flow Atalysis.

Region kV Pre-contingency Voltage Criteria Post-contingency Voltage Criteria Vernont Yankee 345kV 0.985 pu < Vbus < 1.05 pu 0.985 pu < Vbus < 1.05 pu Venront Yankee 115kV 1.00 pu < Vbus < 1.05 pu 1.00 pu < Vbus < 1.05 pu (auto in) 0.95 pu < Vbus < 1.05 pu (auto out)

Vermont Yankee 4160v 0.90 pu < Vbus < 1.05 pu 0.90 pu < Vbus < 1.05 pu Ve34ont 115kV 0.95 pu < Vbus < 1.05 pu 0.92 pu < Vbus < 1.05 pu Chester 345kV 0.97 pu < Vbus < 1.042 pu 0.97 pu < Vbus < 1.042 pu Seabrook 345kV 1.00 pu < Vbus < 1.05 pu 1.00 pu < Vbus < 1.05 pu BHE 11 SkV 0.90 pu < Vbus < 1.05 pu 0.90 pu < Vbus < 1.05 pu CMP, NSTAR, PSNH 145kV 0.95 pu < Vbus < 1.05 pu 0.95 pu < Vbus < 1.05 pu OtherNE 11 SkV 0.95 pu < Vbus < 1.05 pu 0.90 pu < Vbus < 1.05 pu 345kV 0.95 pu < Vbus < 1.05 pu 0.95 pu < Vbus < 1.05 pu NY Pleasant Valley 74344 345kV 0.994 pu < Vbus < 1.05 pu 0.951 pu < Vbus < 1.10 pu NY Oakdale 75405 345kV 0.977 pu < Vbus < 1.05 pu 0.942 pu < Vbus < 1.10 pu NY Oakdale 75415 230kV 0.943 pu < Vbus < 1.05 pu 0.900 pu < Vbus < 1.05 pu NY Watercure 75418 230kV 0.935 pu < Vbus < 1.05 pu 0.900 pu < Vbus < 1.05 pu NY Edic 78450 345kV 1.010 pu < Vbus < 1.05 pu 0.951 pu < Vbus < 1.05 pu NY Lceds 78701 345kV 1.000 pu < Vbus < 1.05 pu 0.951 pu < Vbus < 1.08 pu NY New Scotland 77 345kV 1.010 pu < Vbus < 1.05 pu 0.951 pu < Vbus < 1.05 pu NY New Scotland 79 345kV 1.010 pu < Vbus < 1.05 pu 0.951 pu < Vbus < 1.05 pu NY Marcy 345kV 1.010 pu < Vbus < 1.05 pu 0.951 pu < Vbus < 1.1Opu Presently, Vermont Yankee requires that the voltage on both the 345kV and 11 5kV buses be maintained at I.Opu or above, under pre- and post-contingency conditions, whether the autotransformer is in service or not. The proposed changes, noted in the Table 2-3, will need to be reflected in the appropriate operations documents, such as MS#1, before they can go into effect.

The monitored region consisted of area 701 (NE), and selected buses in 702 (NY).

The power flow analysis was performed with pre-contingency solution parameters that allowed SVDs, PARs, and LTCs to move. The post-contingency solution parameters allowed SVDs and LTCs only to move for area 701 (NE), except for zones 41 (VELCO-2.9 RepmtllllO3 doe GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 2.9 Report111103.doc

VT) and 42 (VELCO-NC). In these Vermont zones, no control action was allowed post-contingency.

2.1.4 Contingency List The power flow contingency list consisted of single line contingencies, as well as multiple element outages reflecting the results of stuck breaker faults. These outages focused on the 345kV and 115kV transmission system near Vermont Yankee. The full contingency list is shown in Table 2-4.

Table 2-4. Powver Flow Contingency List.

1. I Description 1 Loss of Section 379 (Scobie-Amherst-Vermont Yankee 345kV) 2 Loss of Section 394 (Seabrook-Ward Hill-Tewksbury 345kV), Ward Hill 345/115kV autotransformer, and Pelham-G192 Tap 115kV line (SPS #31) 3 Loss of Section 326 (Scobie-Lawrence-Sandy Pd 345kV), Lawrence 345/34.5kV autotransformer 4 Loss of Section 312 (Northfield-Many-Alps-Berkshire 345kV), Berkshire 345/115kV autotransformer 5 Loss of Section 354 (Northfield-Ludlow 345kV) 6a Loss of Highgate HVDC, St. ALB-T-Highgate 115kV line 6b Loss of Highgate HVDC, St. ALB-T-Highgate 115kV line, insert Sandbar series reactor 7 Loss of PV-20, Plattsburgh-Grand-S. Hero-Sandbar 115kV line, run back Highgate to 150 MW 8 Loss of Section K-30 (West Rutland-Florence-Middlebury 115kV), Florence 115/46kV transformer 9 Loss of Section K-35 (Coolidge-Cold River 11 5kV) 10 Loss of Section K-31 (Coolidge-Ascutney 115 kV) 11 Loss of Section K-149/V-149S (Ascutney-Slayton Hill-Bellows Falls 115kV) 12 Loss of Section W-149N (Wilde-Slayton Hill-Mt. Support 11 5kV) 13 Loss of Section K-174 (Ascutney-North Road 115kV) 14 Loss of Section M-127 (North Road-Webster 115kV) 15 Loss of Section K-I 86 (Vermont Yankee-Vernon Road-Chestnut Hill 115kV), and loads 16 Loss of Section N-186 (Chestnut Hill-Westport-Swanzey-Keene 115kV), including Chestnut Hill 115kV capacitor banks 17 Loss of Section L-163 (Keene-Jackman 115kV) 18 Loss of Section F-162 (Jackman-Greggs 115kV) 19 Loss of Section T-198 (Keene-Monadnock 115kV) 20 Loss of Section I-135N (Bellows Falls-Monadnock Tap-Flagg Pond- East Winchendon-Ashbumham 115kV) 21 Loss of Section 1-135S (Flagg Pond-Pratts Junction 115kV) 22 Loss of Section 1-136N (Bellows Falls-East Winchendon-Ashbumham-Flagg Pond 115kV),

Ashbumham 115/13.8kV transformer 23 Loss of Section J136S (Flagg Pond-Litchfield Street-Pratts Junction 115kV)

GE-Power Systems Energy Consulting 2.10 Report 1111 03doc

Table 24. Pow'er Flow Contingency List (continuled).

I/ Description 24 Granite K52 breaker failure, Loss of Section K-26 (Barre-Wilder 115kV), Chelsea 115/46kV transformer, and Hartford II 5/46kV transformer 25 Loss of Section F-206 (Comerford-Granite 230kV), Granite transformer 26 Loss of Section 340 (Vermont Yankee-Coolidge 345kV) 27 Loss of Section 350 (Coolidge-West Rutland 345kV) 29 Loss of Section 381 (Vermont Yankee-Northfield 345kV) 30 Loss of Vermont Yankee 345/115kV autotransformer 31 Loss of Coolidge 345/115 autotransformer 32 Coolidge 40-50 breaker failure, Loss of Sections 350 (Coolidge-WVest Rutland 345kV) and 340 (Vermont Yankee-Coolidge 345kV) 33 Vermont Yankee 7940 breaker failure, Loss of Sections 379 (Scobie-Aniherst-Vermont Yankee 345kV) and 340 (Vermont Yankee-Coolidge 345kV) 34 Vermont Yankee 379 breaker failure, Loss of Section 379 (Scobie-Amherst-Vermont Yankee 345kV) and Vermont Yankee autotransformer 35 Vermont Yankee 381 breaker failure, Loss of Section 381 (Vermont Yankee-Northfield 345kV line) and Vermont Yankee autotransformer 36 Vermont Yankee IT breaker failure, Loss of Section 340 (Vermont Yankee-Coolidge 345kV) and Vermont Yankee GSU and generator 37 Loss of Granite-Wilder 115kV, Chelsea and Hartford l15/46kV transformers.

38 Loss of Granite-Chelsea 115kV 39 Granite K52 breaker failure, loss of K26-Barre-Chelsea 115kV 2.11 RepoflhlllO3.doc Energy Consulting Systems Energy GE-PowerSystems Consulting 2.11 Reportt1103Obc

2.2 Transient Stability Study 2.2.1 Benchmark System A light load power flow case, sltI, was developed to represent a New England 2005 light load condition with a high level of Maine generation, and with the modifications described in Section 2.1.1. As noted in that Section, the proposed VELCO 115kV Northern Loop project, with an expected in service date of December 2004, and the proposed VELCO Northwest Vermont Reliability Project (NRP), with expected in service dates ranging from May 2004 to December 2007, were not included. However, the Amherst project, represented as a 345kV four circuit breaker ring bus at the Amherst Substation, was included in the stability analysis.

Modifications were also made to each generating unit's output such that each in-service unit was generating at its 00 rated output. The overall generation dispatch was also modified to stress the transmission interfaces up to their stability limits, disregarding thermal limitations as needed. A second light load power flow case, slt2, was developed from the above sMtU case with the Newington units replacing some of the Maine generation. A peak load power flow case, spkl, representing a New England 2006 peak load condition was also developed. Finally, two peak power flow sensitivity cases with high levels of East-West interface flow were developed. One case includes all Northfield units, spk4, and one cases includes no Northfield units, spk5.

A brief summary of each benchmark case, including significant interface flows and major New England real and reactive power generation output, is shown in Tables 2-5 and 2-6.

Table 2-5 shows the real power output of major New England generating plants and selected NE interface flows. Table 2-6 shows the reactive power output of major New England generating plants and selected reactive device output. A detailed summary for each case of the generation dispatch across New England, as well as additional interface flows and other information, is included in Appendix C. One line diagrams of the Vermont and NE 345kV transmission system for each case are also included in this appendix.

The Vermont Yankee plant was represented using the following models:

• GENROU - Solid rotor generator represented by equal mutual inductance rotor modeling

• EXAC3A - IEEE type AC3A excitation system

• No governor model

• MOTOR1 - a one-cage induction machine for the station service motor loads

• OOSLEN - a three zone out of step relay model with a low voltage threshold For the stability analysis, the Vermont Yankee exciter was modeled, both pre- and post-uprate, with an exac3a model representing an IEEE type AC3A excitation system. This is the manufacturer recommended model and replaced the ieeetl model used in prior studies.

GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 2.12 Repo.1111103.doc 2.12 Report111103.doc

Appendix D contains block diagrams and corresponding data for the dynamic models used to represent the existing Vermont Yankee plant in this study.

The Vermont Yankee KLF relay is a loss-of-field relay currently used for out of step protection. The relay operates when all of the following criteria are met for 15 cycles:

• The apparent impedance as seen from the generator is within the impedance circle

. The apparent impedance as seen from the generator is below the reactance characteristic of the directional unit

• The generator terminal voltage is below 0.8pu (17.6kV)

The relay operation characteristic, as provided by Vermont Yankee, is shown in Appendix F, as well as the parameters of the ooslen model.

The Vermont Yankee 41 60v buses are equipped with undervoltage relays that both alarm and trip. If the relay indicates a low bus voltage (less than 0.90pu for more than 10 see),

an alarm is generated. The control room tries to determine the cause of the alarm and contacts the grid dispatcher. If corrective actions are in progress and the alarm will clear quickly, then the plant will stay on line. Otherwise, the operators will take the plant off line. These relays are represented in the motor load models using the voltage and time thresholds that initiate motor tripping.

In addition, there is undervoltage, overvoltage and underfrequency protection on the motor-generator (MG) sets on the reactor protection system (RPS) buses. The voltage protection is only in-service when the MG set voltage regulators are out of service.

Hence, that protection was not represented in the stability study. The underfrequency protection was represented. This relay monitors the output of the RPS MG sets and trips when that frequency falls below approximately 57.8Hz. This corresponds to a slightly higher system frequency, due to the slip of the MG drive motor, so actual system frequency corresponding to this trip threshold would be about 58.6Hz. A time delay of 0.15 seconds was assumed for the underfrequency trip. If the underfrequency trips are actuated for both MG sets, the reactor will trip.

2.13 Repoit111103.doc Systems Energy GE-Power Systems GE-Power Consulting Energy Consulting 2.13 Reponrt11103ADoc

Table 2-5. Real Power Sumnmary for Major New England GeneratingPlants aidSelected Interface Flowvs.

Light Load, SLTI Light Load, SLT2 Peak Load, SPKI Peak Load, SPK4 Peak Load, SPK5 Description Existing Full Existing Full Existing Full Existing Full Existing Full Pmax3 Uprate Uprate Uprate Uprate Uprate NE Load (+ Losses)' 11732 11719 11691 11678 28103 28115 28181 28193 28124 28135 NE Load (+ Losses) Goal 11831 11831 11831 11831 28029 28029 28029 28029 28029 28029 Generation VT Yankee 563 667 563 667 563 667 563 667 563 667 563/667 Other Vermont 190 87 190 87 109 9 109 8 109 8 232 MIS 358 358 0 0 550 550 550 550 550 550 550 Bucksport 191 191 191 191 191 191 191 191 191 191 191 RPA 0 0 0 0 273 273 273 273 273 273 273 AEC 0 0 161 161 108 108 108 108 108 108 161 Other Vestern Maine2 153 153 153 153 175 175 175 175 175 175 247 WF Wyman 1,2,3 0 0 0 0 239 239 239 239 239 239 239 WF Wyman 4 0 0 0 0 0 0 0 0 0 0 636 Westbrook 579 579 0 0 579 579 579 579 579 579 579 Schiller4,5,6 0 0 0 0 146 146 146 146 146 146 145 Merrimack 1,2 440 440 440 440 440 440 440 440 440 440 440 Newington I 0 0 422 422 422 422 422 422 422 422 422 Con Ed Newington 0 0 561 561 561 561 561 561 561 561 561 Canal 1,2 0 0 0 0 1142 1142 1142 1142 1142 1142 1142 Brayton Point 1,2,3,4 482 482 482 482 1320 1320 1320 1320 1320 1320 1561 AES Londondeny 0 0 0 0 811 811 811 811 811 811 810 UAETewksbury 0 0 0 0 0 0 0 0 0 0 591 Mystic 7 565 565 565 565 0 0 565 565 565 565 565 Mystic 8 866 866 866 866 866 866 866 866 866 866 866 Mystic 9 866 866 866 866 866 866 866 866 866 866 866 Edgar/Fore River 0 0 0 0 865 865 865 865 865 865 866 Seabrook 1209 1209 1209 1209 1209 1209 1209 1209 1209 1209 1209 Northfield/l3earSwamp -1310 -1310 -1310 -1310 1666 1666 1080 1080 293 293 1666 Comerford/Moore 356 356 356 356 96 96 96 96 96 96 356 Salem Harbor 400 400 231 231 230 230 745 745 745 745 662 Millstone2,3 1146 1146 1146 1146 2008 2008 2008 2008 2008 2008 2008 Total 5908 5909 5946 5947 13427 13431 15929 15932 15142 15145 2.14 RepotflhllO3.doc. 1111104 GE-Power Systems Energy Consulting Systems Energy Consufltng 2.14 Repot01 I MAX, 1/1 1/04

Table 2-5. Real Pon'erSuntmtaryfor Major Newv England GeneratingPlantsand Selected Interface Flows (contintled).

Peak Load, SPKI Peak Load, SPK4 Peak Load, SPK5 Light SLT1 Load, SLTI Light Load, Light Load, Light SLT2 Lead, SUM2 Peak Load, SPKI Peak Lead, SPK41 Peak Load, SPK5 Description Existing Full Existing Full Existing Full Existing Full Existing Full InterfacesX NB/NE 699 Uprate 699 699 Uprate 699 I 696 Uprate 696 696 Uprate 696 696 Uprate 696 Orrington-South 1078 1078 723 723 1059 1059 1059 1059 1059 1059 Surowiec-South 885 885 708 708 909 909 909 909 909 909 ME/NH 1220 1220 484 484 j 1197 1197 1196 1196 1196 1196 Seabrook South 1017 1018 1478 1479 1704 1705 1636 1637 1625 1626 NNE-Scobie+394 2121 2114 2408 2402 2833 2824 2826 2817 2828 2819 (variable limit) (2445) (2445) (2520) (2520) (2800) (2800) (2800) (2800) (2800) (2800)

North-South 2961 2985 3214 3238 2990 2991 2895 2892 2957 2957 East-West 2123 2108 2199 2184 2130 2109 3129 3107 3163 3141 Crlimport 937 937 728 727 2359 2358 1826 1826 1818 1818 PV20Import 103 110 101 109 108 109 102 100 102 102 NEMA(Boston Import -276 -276 -105 -105 4228 4227 3184 3185 3161 3161 Boston Import -259 -260 -89 -89 3604 3605 2673 2674 2641 2641 SEMA/RI Export -246 -246 -246 .246 1957 1957 1947 1947 1952 1952 NY/NE -271 -285 -262 -275 8 17 -714 -704 16 24 Northwest Vermont -90 -17 -91 -17 281 364 278 361 278 361 Central Vermont -171 -142 -168 -139 150 191 92 135 115 158 Highgate HVDC 221 221 221 221 215 215 215 215 215 215 Phase 11HVDC 0 0 0 0 2000 2000 2000 2000 2000 2000 Notes:

1. Does not include 95MW of motor load (modeled as generators)

• 2. Includes Wyman, Williams, Harris, SEA, Gorbell

3. Maximum power is the generator output in the power flow. For most machines it represents a net value.

Station service load is modeled only at Vermont Yankee, Seabrook, Mystic 8, Mystic 9, and Fore River.

At those plants, the maximum power therefore represents a gross value.

GE-Power Systems Energy Consulting 2.15 ReportI11103ADoc, 1/11/04

Table 2-6. Reactive Power Siinmaryfor MajorNewv England GeneratingPlantsandSelected Interface Flowvs.

Light Load, SLTI I Light Load, SLT2 Peak Load, SPKI Peak Load, SPK4 Peak Load, SPKS Description Existing Full Existing Full Existing Full Existing Full Existing Full Qmax Uprate Uprate Uprate Uprate Uprate NELoad(+Losses)' 11732 11719 11691 11678 28103 28115 28181 28193 28124 28135 NE Load (+ Losses) Goal 11831 11831 11831 11831 28029 28029 28029 28029 28029 28029 Reactive Generation VT Yankee 150 ISO 150 150 150 150 150 150 ISO 150 150 OtherVermont -30 -48 -31 -47 15 53 -15 19 -16 18 205 MIS 105 105 0 0 169 169 173 173 173 173 324 Bucksport 58 57 57 57 66 67 68 68 68 68 120 RPA 0 0 0 0 68 68 69 69 69 69 190 AEC 0 0 44 44 50 50 52 52 52 52 123 Other WesternMaine 2 12 12 7 7 34 34 36 36 36 36 103 WF Wyman 1,2,3 0 0 0 0 44 44 47 48 47 48 83 NVF Wyman 4 0 0 0 0 0 0 0 0 0 0 242 Westbrook 66 65 0 0 91 92 99 99 99 99 330 Schiller4,5,6 0 0 0 0 21 23 31 32 31 32 75 Merrimack 1,2 13 5 1 -7 33 46 59 67 57 66 203 Newington I 0 0 -45 -45 42 43 51 52 52 52 180 ConEdNewington 0 0 121 119 125 128 154 157 155 157 330 Canal 1,2 0 0 0 0 359 359 359 359 359 359 359 Brayton Point 1,2,3,4 20 19 19 18 400 404 534 539 462 466 752 AES Londonderry 0 0 0 0 231 246 256 276 247 265 441 UAE Tewksbury 0 0 0 0 0 0 0 0 0 0 300 Mystic 7 -150 -150 -150 -150 0 0 251 260 185 193 335 Mystic8 149 147 142 140 311 314 235 235 235 235 515 Mystic 9 -16 -19 -33 -37 413 416 355 356 343 344 515 Edgar/ForeRiver 0 0 0 0 30 31 57 58 42 43 515 Seabrook 125 120 133 128 489 501 469 478 455 462 560 Northfield/Bear Swamp 247 256 252 261 537 541 320 320 145 145 610 omerford/Moore -25 -38 -27 -42 5 15 14 25 14 25 119 Salem Harbor -104 -106 -60 -60 79 79 161 161 157 158 386 Millstone 2,3 183 184 154 155 579 584 773 785 598 605 940 Total 620 575 580 536 3762 3873 4758 4874 4215 4320 2.16 RepoetllllO3.doc. 1I11O4 GE-Power Systems Energy Consulting Systems Energy Consulting ReportI11110J.cb, 1/11/0 2.16

Table 2-6. Reactive PonierSummary for iajorNew Englaed GeneratingPlantsand Selected Interface Flows f(continuted).

Light Load, SLTI I Light Load, SLT2 Peak Load, SPKI Peak Load, SPK4 Peak Load, SPK5 Description Existing Full Existing Full Existing Full Existing Full Existing Full Qmax Uprate Uprate Uprate Uprate Uprate Reactive Devices Chester SVC 30 30 30 30 30 30 30 30 30 30 450 Orrington 201 201 201 201 201 201 201 201 201 201 201 Z of Maxcys, Mason, 200 200 50 50 450 450 450 450 450 450 450 Surowiec, South Gorham Crowleys 50 50 50 50 50 50 50 50 50 50 50 Sanford 31 31 31 31 31 31 31 31 31 31 31 Beebe 20 20 20 20 20 20 20 20 20 20 20 3Rivers 63 63 63 63 63 63 63 63 63 63 63 Ocean 53 53 53 53 53 53 53 53 53 53 53 Merrimack 72 72 72 72 72 72 72 72 72 72 72 Madbury 51 51 51 51 51 51 51 51 51 51 51 Chestnut Hill 52 52 52 52 52 52 52 52 52 52 52 Highgate 114 112 114 112 107 108 96 97 96 97 140 Highgate46kV 0 0 0 0 0 0 6 6 6 6 6 Georgia 25 25 25 25 25 25 25 25 25 25 25 and Bar 0 0 0 0 0 0 25 25 25 25 25 Berlin 25 25 25 25 25 25 25 25 25 25 25 Barre34.5kV 0 0 0 0 16 16 16 16 16 16 16 Essex Caps 124 124 124 124 149 149 149 149 149 149 150 Essex STATCOM -32 -53 -34 -52 3 53 -28 18 -28 17 75 Williston 0 0 0 0 0 0 25 25 25 25 25 Middlebury 23 23 23 23 23 23 23 23 23 23 23 Rutland 0 0 0 0 24 24 24 24 24 24 24 Coolidge 50 50 50 50 50 50 50 50 50 50 50 Ascutney46kV 16 16 16 16 16 16 16 16 16 16 16 Notes:

1. Does not include 95MW of motor load (modeled as generators)

2. Includes Wyman,Williams, Harris, SEA, Gorbell GE-Power Systems Energy Consulting 2.17 Report111103.doc.1/11/04

2.2.2 Vermont Yankee Full Uprate System The proposed Vermont Yankee nuclear plant full uprate increases the unit rating from 626MVA to 684MVA and the maximum power generation from 563MW to 667MW.

The maximum reactive power output remains at 150MVAr. There is also no expected change in the station service or cooling tower loads.

Power flow cases with the proposed Vermont Yankee full uprate were developed from the benchmark cases described above. The Vermont Yankee full uprate was redispatched against Vermont units.

A brief summary of each full uprate case, including significant interface flows and major New England real and reactive power generation output, is also shown in Tables 2-5 and 2-6 with the corresponding benchmark cases. Table 2-5 shows the real power output of major New England generating plants and selected NE interface flows. Table 2-6 shows the reactive power output of major New England generating plants and selected reactive device output. A detailed summary for each case of the generation dispatch across New England, as well as additional interface flows and other information, is included in Appendix E. One line diagrams of the Vermont and NE 345kV transmission system for each case are also included in this appendix.

The Vermont Yankee plant was represented using the following models:

• GENROU - Solid rotor generator represented by equal mutual inductance rotor modeling

• EXAC3A - IEEE type AC3A excitation system

• No governor model

• MOTOR1 - a one-cage induction machine for the station service motor loads

• OOSLEN - a three zone out of step relay model with a low voltage threshold The parameters associated with the generator model are the only differences between the representation of the existing unit and the full uprate. The excitation system was unchanged as well as the station service motor load. The same protection functions as described in Section 2.2.1 were also used in the full uprate analysis. Appendix F contains block diagrams and corresponding data for the dynamic models used to represent the full uprate of the Vermont Yankee plant in this study.

The Vermont Yankee KLF relay settings will be modified as part of the full uprate. The relay operates when all of the following criteria are met for 15 cycles:

• The apparent impedance as seen from the generator is within the impedance circle

• The apparent impedance as seen from the generator is below the reactance characteristic of the directional unit

• The generator terminal voltage is below O.8pu (17.6kV)

The new relay operation characteristic, as recalculated by Stone & Webster and provided by Vermont Yankee, is shown in Appendix F, as well as the parameters of the ooslen model.

2.18 Reportl 11103.doc GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 2.18 ReportI11103 doc

2.2.3 Performance Criteria The criteria defining stable transmission system performance for normal contingencies (3-phase faults cleared by the slower of the two fastest protection groups or 1-phase faults with backup clearing) are as follows:

• All units must be transiently stable except for units tripped for fault clearing

• A 50% reduction in the magnitude of system oscillations must be observed over four periods of the oscillation

• A loss of source greater than 1200MW is not acceptable

• Keswick GCX entry is not acceptable The criteria defining stable transmission system performance for extreme contingencies (3-phase faults with breaker failure and backup clearing) are as follows:

• Transiently stable with positive damping

• A loss of source greater than 1400MW is not immediately acceptable

• A loss of source between 1400MW and 2200MW may be acceptable depending upon a limited likelihood of occurrence and other factors

• A loss of source above 2200MW is not acceptable

• A 50% reduction in the magnitude of system oscillations must be observed over four periods of the oscillation Selected 345kV and 1I5kV bus voltages in Vermont and throughout NE were monitored.

The generator angle, field voltage, terminal voltage, machine speed, real and reactive power output were also monitored for all units in Vermont, as well as units with a power output of at least 40MW in the rest of New England. In addition, the angular swings for selected generators in New York were monitored.

2.2.4 Fault Scenario List A variety of 3-phase and 1-phase faults with both primary and backup clearing were evaluated for this study. Tables 2-7 and 2-8 summarizes all the fault scenarios that were analyzed. The planned upgrade of the Amherst station to a full ring bus configuration was assumed for faults on Section 379.

GE-Power Systems Energy Consulting 2.19 ReportI11103.6oc

Table 2-7. Normal ContintgenicyLi.stfor Stability Analysis.

Fault Stuck Near End Far End ID Location Type Impedance Breaker Clearing Location Clearing ncl Chestnut Hill 115kV 34 0.0+j;.0 none 6.0 cy VY, Vernon Rd 115kV 35.0 cy Vernon Rd 115/69kV TX 35.0 cy Vernon Rd 115/46kV TX 35.0 cy nc2 Vermont Yankee 345kV 30 0.0+jO.0 none 4.0 cy Amherst 345kV 4.0 cy nc3 Vermont Yankee 345kV 30 °-°+jO.0 none 4.0 cy Northfield 345kV 4.0 cy nc4 Vermont Yankee 345kV 14 0.0025+jO.0203 (04cy) 81-1T 9.3 cy Nonthfield 345kV 4.0 cy 0.0033+jO.037 (4-9.3cy) VY Generator 9.3 cy nc5 Vermont Yankee 345kV I4 0.0025+jO.0203 (0-4cy) 381 I 9.3 cy Nonthfield 345kV 4.0 cy 0.0033+jO.037 (4-10.3cy) VY 345/115kV Autotransfommer 10.3 cy nc6 Vermont Yankee 345kV I4, 0.0025+jO.0203 IT 9.3 cy Coolidge 345kV 4.0cy VY Generator 9.3 cy nc7 Vermont Yankee 345kV 14 0.0025+jO.0203 7940 9.3 cy Coolidge 345kV 4.0 cy i Amherst 345kV 10.3 cy ncS Vermont Yankee 345kV 14 0.0025+jO.0203 79.40 9.3 cy Amherst 345kV 4.0 cy Coolidge 345kV 12.6 cy nc9 Vermont Yankee 345kV 14 0.0025+jO.0203 379 9.3 cy Amherst 345kV 4.0 cy

_ _VY 345/115kV Autotzansformer 10.3 cy nclO Vermont Yankee 345kV 14, 0.0025+jO.0203 381 I 10.3 cy VY 345/115kV Autotransformer 5.5 cy Nonthfield 345kV 12.6 cy ncl I Vermont Yankee 345kV 14 0.0025+jO.0203 379 10.3 cy VY 345/115kV Autotransformer 5.5 cy

_ Amherst 345kV 11.3 cy ncl2 Vermont Yankee 345kV 14, 0.0025+jO.0203 81-IT 9.3 cy Northfield 345kV 11.55 cy VY Generator 11.55 cy ncl 3 Vermont Yankee 345kV 14, 0.0025+jO.0203 IT 10.3 cy Coolidge 345kV 12.6 cy VY Generator 12.6 cy ncl4 Vermont Yankee 345kV 34 0.0+jO.0 none 27.5 cy Coolidge, Northfield, Amherst 27.5 cy North Bus VY Generator 27.5 cy VY 345/l 15kV Autotransformer 27.5 cy Chestnut Hill, Vernon Rd 11 5kV 5.0 sec Vernon Rd 11 5/69kV TX 5.0 sec Vemon Rd I l5/46kV TX 5.0 sec ncl4x Vermont Yankee 345kV 34 0.0+jO.0 none 4.0 cy VY 379, 381 4.0 cy North Bus VY 345/115kV Autotransformer 4.0 cy Chestnut Hill, Vemnon Rd 11SkV 5.0 sec Vernon Rd 1IlS/69kV TX 5.0 sec

_ Vemon Rd IlS/46kV TX 5.0 sec 2.20 RepoetllllO3.doc GE-Power GE-PowerSystems Consulting Energy Consulting Systems Energy 2.20 ReportilllOldac

Table 2-7. Nornmal Conitingency Listfor StabilityAntalysis (continured).

Fault Stuck Near End Far End ID Location Type Impedance _ Breaker Clearing Location Clearing ncl5 Vermont Yankee 345/22kV 3 0.04jO.O none 27.5 cy Coolidge, Northfield, Amherst 27.5 cy GSU High Side VY Generator 27.5 cy VY 345/115kV Autotransformer 27.5 cy nclSx Vermont Yankee 345/22kV 30 O.0+jO.O none 4.0 cy VY 81-lT, IT 4.0 cy GSU High Side VY Generator 4.0 cy ncl6 Northfield 345kV 30 °.0+jO.0 none 4.0 cy Alps 345kV 4.0 cy

_ Berkshire 345/115kV Autotransformer 5.0 cy ncl7 Northfield 345kV 30 0.0+jO.0 none 4.0 cy Ludlow 345kV 4.0 cy nc18 Scobie 345kV 30 O.°+i°.0 none 4.0 cy Sandy Pond 345kV 4.0 cy I__I _Lawrence 345/34.5kV Autotransforner 6.0 cy ncI9 Scobie345kV I0 0.0053+jO.028O 7973 8.0 cy Deerfield 345kV 4.0 cy Amherst 345kV 8.0 cy nc396 Orrington 345kV 30 0.0+i0.0 none 4.0 cy Keswick 345kV 4.0 cy Chester SVC 4.0 cy nc312 Northfield 345kV 1 0.0022+jO.0201 3T 8.05 cy Alps 345kV 4.0 cy Berkshire 345/115kV Autotransforner 5.0 cy

_ VY 345kV 10.3 cy ph2 Trip Phase If HVDC NA NA none NA NA NA nyOI Edic 345kV 30 0.0+jO.0 none 3.5 cy N.SCOT77 345kV 5.0 cy N.SCOT77 re-close 41.0 cy N.SCOT77 re-open 45.0 cy nyO2 Fraser-345kV Two l0 0.0007838+jO.007716 none 3.5 cy Marcy 345kV 4.5 cy Coopers Comers 345kV 4.5 cy I _ Edic 345kV 5.5 cy nyO3 Marcy 345kV 30 0.0+jO.0 none 3.5cy Massena345kV 5.5cy Chateauguay 345kV 9.5 cy

. Massena 345kV 11.5 cy ReportllllO3. doe GE-Power Systems Energy Consulting 2.21 2.21 RepM11~1103.dcc

Table 2-8. Eytrenme ContingencyListfor Stability Analysis.

Fault l Stuck lNeardEnd Far End ID Location Type Impedance Breaker Clearing Location Clearing I ecl Vermont Yankee I15kV 30 0.0+j0.0 N186 19.3 cy Chestnut Hill 115kV 35.0cy Vernon Rd 115kV 35.0 cy VernonRd 115/69kVTX 35.0cy

___ _ VenonRd 115/46kVTX 35.0cy ec2 Vermont Yankee 345kV 30 0.0+j0.0 81-IT 9.3 cy Northfield 345kV 4.0 cy VY Generator 9.3 cy ec3 Vermont Yankee 345kV 30 0.0+ji.0 381 9.3 cy Nonhfield 345kV 4.0 cy

_I _ WVY345/115kV Autotransformer 10.3 cy ec4 Vermont Yankee 345kV 34 0.0+jO.0 IT 9.3 cy Coolidge 345kV 4.0 cy I I V Generator 9.3 cy ec5 Vermont Yankee 345kV 30 0.0+jo.0 7940 9.3 cy Coolidge 345kV 4.0 cy Amherst 345kV 10.3 cy ec6 Vermont Yankee 345kV 3§ 0.0+j0.0 7940 9.3 cy Amherst 345kV 4.0 cy Coolidge 345kV 12.6 cy ec7 Vermont Yankee 345kV 30 0.0+j0.0 379 9.3 cy Amherst 345kV 4.0 cy VY 345/1 15kV Autotransformer 10.3 cy ec8 Vermont Yankee 345kV 30 0.0+j0.0 381 10.3 cy VY 345/115kV Autotransformer 5.5 cy Open BKR 81-IT 10.3 cy Northfield 345kV 12.6 cy ec8x Vermont Yankee 345kV 30 0.0+j0.0 381 9.5 cy VY 345/115kV Autotransformer 5.5 cy OpenBKR81-IT 9.5 cy ec8ipt Vermont Yankee 345kV 3VilO 0.0025+jO.0203 F_

381 10.3 cy Northfield 345kV VY 345/115kV Autotransformer OpenBKR81-lT 10.5 cy 5.5 cy 10.3 cy Northfield 345kV 12.6 cy ec9 Vermont Yankee 345kV 30 0.0+ji.0 379 10.3 cy VY 345/115kV Autotransformer 5.5 cy Amherst 345kV 11.3 cy eclO Vermont Yankee 345kV 30 0.0+j0.0 81-IT 11.55 cy Northfield 345kV 11.55 cy VY Generator 11.55 cy ecl I Vermont Yankee 345kV 30 0.0+j0.0 IT 10.3 cy Coolidge 345kV 12.6 cy VY Generator 12.6 cy ecI9 Scobie345kV 30 0.0+j0.0 7973 8.0 cy Deerfield 345kV 4.0 cy Amherst 345kV 8.0 cy ec312 Northfield 345kV 3V/lO 0.0022+jO.0201 3T 8.05 cy Alps 345kV 4.0 cy Berkshire 345/115kV Autotransformer 5.0 cy VY 345kV 10.3 cy ec326 Scobie345kV 3V/l4 0.0053+jO.0280 9126 8.0 cy SandyPond 345kV 4.0 cy Lawrence 345/34.5kV Autotransformer 6.0 cy Buxton 345kV 8.0 cy ec328 Sherman Rd 345kV 3V/IO 0.0020+jO.0162 142 9.5 cy West Famum 345kV 4.0 cy

- ANP 336 345kV 10.5 cy_

GE-Power Systems Energy Consulting 2.22 Report111013.doc

Table 2-8. Extreme Contingency Listfor Stability Analysis (contilnlted).

Fault Stuck Near End Far End

11) Location Type Impedance Breaker Clearing Location Clearing ec368 Card345kV 30/1l 0.0044+jO.0211 2T 10.5cy Manchester345kV 4.Ocy l Millstone 345kV 12.75 cy ec394a Seabrook 345kV 30/10 .00081+jO.01351 294 l 8.0Cy Tewksbury345kV 4.0cy

.IIa _ rd Hill 345/115kV Autotransforrner 4.0 cy 2.23 Rerotflh11O3.ctoc GE-Power Energy Consulting Systems Energy GE-PowerSystems Consulting 2.23 Reportll1103.dac

2.2.5 Other Dynamic Modeling Several protective functions and other special dynamic modeling are described below.

Vernon Road UndervoltageProtection If an undervoltage condition is detected on the Vernon Rd 115kV bus, then circuit breakers on the low voltage sides of the transformers are opened. Specifically, for the 46kV and 69kV breakers to open, the 115kV voltage must be below 0.92pu for 0.5seconds.

Bear Swtamp/Northlfield Underfrequency Protection There is underfrequency protection on the Bear Swamp and Northfield units when they are pumping. If the frequency falls below 59.65Hz, the units are tripped.

SandBar OverloadManagement System (OMS)

This function is designed to mitigate overloads on the PV20 tie. If the flow on the PV20 tie exceeds 254MW for 5 seconds, the Sand Bar series reactor is inserted to mitigate overloads on that tie.

Generic Out of Step Relay Function A generic out of step relay function was used to trip units that appear to lose synchronism with the rest of the system. Throughout a simulation, unit machine angles are compared to their initial angles. If the difference exceeds 180 degrees, the unit is tripped.

CapacitorSwitching Model The shunt capacitors at five Maine 345kV substations (Orrington, Maxcys, Mason, South Gorham, and Surowiec) are allowed to switch during transient stability simulations.

In the power flow, these capacitor installations are modeled as static var devices (SVD) with the appropriate number of banks. Specifically, three 67MVAr banks are represented at Orrington, three 50MVAr banks at Surowiec, and two 50MVAr banks at each of the other three substations.

The control logic for dynamic simulations was provided by Central Maine Power Co. in a dynamic capacitor switching model, msc6.p, for the Maxcys, Mason, South Gorham, and Surowiec banks. A separate dynamic model, orrington.p, was also provided by CMP to represent the Orrington capacitor banks.

Chester SVC Low Voltage Blocking FunctionModel The dynamic modeling of the Chester SVC consists of a voltage regulating SVC (vwscc),

which regulates to the scheduled voltage from the power flow, a power oscillation damping control (pss2a) and a supervisory low voltage blocking function. This blocking function reduces the SVC output to OMVAr when the Chester 345kV bus voltage is below 0.60pu. Voltage control is restored to the SVC when the 345kV bus voltage returns to 0.68pu or greater.

Load Model Load was modeled as constant impedance P and constant impedance Q.

GE-PwerSystms .24fleoft1110.do nery Cosuling GE-Power Systems Energy Consulting 2.24 RepWIt11103.dbc

Millstone #3 Exciter Model The Millstone 3 exciter model exac3a parameters were changed from the original data to more representative data. The block diagram and data for the Millstone 3 exac3a model are shown in Appendix G. This modeling change is subject to analysis and review as part of the Millstone #3 power uprate study, and its subsequent approval under Section 18.4 of the NEPOOL Agreement.

Appendix H documents the models that were out-of-service for in-service generators.

These models include generator exciter, governor and power system stabilizer models.

These models were removed in the initial database development to improve simulation initialization and prevent unstable model behavior.

2.2.6 Special Protection System Modeling The Maine Special Protection Systems (SPS) were modeled for the stability analysis, as described below.

Maxcys Ovier-CurrentSPS (NPCCSPS #28)

The purpose of this SPS is to protect the underlying 115kV system for loss of Section 392 (Maxcys-Maine Yankee 345kV). The Maxcys over-current SPS trips the Maxcys 345/115kV autotransformer when current flow on the Maxcys-Mason 115kV line (Section 68) exceeds 960A (equivalent to 191MVA at 1.0pu voltage) for 0.2 seconds.

Bucksport Ovier-CurrentSPS (NPCCSPS #21)

The purpose is to protect the underlying 11 5kV system for loss of Sections 392 (Maxcys-Maine Yankee 345kV) and 388 (Orrington-Maxcys 345kV). The Bucksport over-current SPS trips the Bucksport-Detroit (Section 203) and Bucksport-Belfast (Section 86) 115kV lines as well as the Bucksport and Maine Independence Station generators when total flow on the Orrington-Bucksport (Section 65) and Betts Rd-Bucksport (Section 205) 115kV lines exceeds a threshold for a specified amount of time.

Specifically, this SPS begins timing if the current flow on Section 65 exceeds 678A (135MVA) and the current flow on Section 205 exceeds 693A (138MVA) simultaneously, or if the Section 65 current exceeds 960A (19lMVA), or if the Section 205 current exceeds 960A (19lMVA). When the timer reaches 0.2 seconds, Sections 203 and 86 and the Bucksport generator are tripped. In addition, a transfer trip is started and the Maine Independence Station is tripped after 15 cycles.

Bucksport Reverse Power SPS (NPCCSPS #22)

The purpose is to protect BHE from low voltages for loss of Section 388 (Orrington-Maxcys 345kV) or 392 (Maxcys-Maine Yankee 345kV) as well as Section 396 (Keswick-Orrington 345kV) with low internal generation. The Bucksport reverse power SPS trips the Bucksport-Orrington (Section 65) and Bucksport-Betts Road (Section 205) 115kV lines when the total south-to-north power flow on those lines exceeds 50MW for 0.3 seconds.

In addition, there is an under-voltage supervisory function which prevents operation of this SPS if the Bucksport 115kV bus voltage remains above 0.92pu and allows operation when the voltage has been below 0.92pu voltage for 0.2 seconds.

2.25 Rep oflhlllO3.doc GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy 2.25 Reports t1103.dbc

Saco Valley Under Voltage Load Shed Although not an SPS, its purpose is to relieve local undervoltage problems in the vicinity of Saco Valley. This protection system trips the loads at the Saco Valley and Intervale 34.5kV buses when the Saco Valley 115kV bus voltage has been below 0.94pu for 4 seconds.

Maine Yankee Double Circuit Tower Outage SPS (NPCCSPS #141)

The purpose of the DCT SPS is to relieve overloads on the underlying 115kV system for loss of the two 345kV lines crossing the Kennebec River south of Maine Yankee (Sections 375 and 377) or the Maxcys-Maine Yankee and Maine Yankee-Buxton (Sections 392 and 375) 345kV lines. The Maine Yankee DCT SPS trips the Maine Independence Station for these two events.

Keswick Loss of 3001 SPS (NPCC SPS #5)

The purpose of the Loss of Line 3001 SPS is to detect islanding of the Maritimes due to trips of any one of the existing Maine 345kV connections to southern New England, i.e.,

Line 3001/Section 396 (Keswick-Orrington 345kV) or Sections 388 (Orrington - Maxcys 345kV) or 392 (Maxcys - Maine Yankee 345kV). This SPS rejects generation in New Brunswick and/or reduces import in response to a sudden drop in power flow on the Keswick-Orrington 345kV line simultaneous with an increase in frequency at the Keswvick 345kV bus. This SPS is only armed when the initial power flow on Line 3001 is greater than 180MW.

The SPS begins when the power flow on Line 3001/Section 396 falls below 330MW and the first timer is started. If the power flow falls below 260MW before this first timer reaches 3 seconds, then a second timer is started. If the Keswick 345kV bus frequency exceeds 60.3Hz and the second timer has not reached 1.25seconds, then generation is tripped in New Brunswick. The amount of generation tripped approximates the initial flow on Section 3001 less 200MW.

The system operator selects sufficient generation and/or HVDC imports from the list shown in Table 2-9 to trip about 200 MW less than the initial flow on Line 3001/Section 396.

Table 2-9. NB Pow'er Generation Rejection Option List.

Facility Operational Choices Madawaska 350MW HVDC link Runback to 175MW or block to zero Eel River 350MW HVDC link Runback to 270,200, 160, 120, 80 or 40MW Mactaquac Hydro plant Up to four of six 110 MW units can be tripped Beechwood Hydro plant All three 35MW units can be tripped Coleson Cove Steam plant One of three 350MW units can be tripped Belledune One 480MW unit can be tripped Dalhousie Unit 2 (200MW) can be tripped Lingan Steam plant (NS) One or two of four 160MW units can be tripped GE-PwerSysems nery Cnsuling2.2 RepeflllO.do GE-PowerSystems Energy Consulting 2.26 Report111ll3.doc

Keswick GCXSPS (NPCCSPS #11)

The purpose of the Keswick GCX SPS is to provide overload protection for Line 3001/Section 396 (Keswick-Orrington 345kV) such that it does not trip for a large load loss in the Maritimes when it is near its maximum export (from NB) capability. The GCX SPS has frequency supervision so that it will not operate for a large source loss in New England. The characteristics of the Keswick GCX relay are shown in Table 2-10, where the distance and angle determine the center point and the reach defines the diameter of the impedance circle.

Table 2-10. Keswick Zone 1, Zone 2, and GCXRelay Characteristics.

Zone Reach Center Distance Angle Operating Time (see)

(pu) (pu) (deg) 1 0.0440 0.0220 75 0.0 2 0.0723 0.0672 75 0.3 3 0.1060 0.0530 60 If over-frequency conditions are satisfied.

Zone I and 2 and the line protection are always armed. When the apparent impedance of Line 3001/Section 396 (Keswick-Orrington 345kV) enters zone I or 2, it trips the line (instantaneously in zone I and after 0.3 seconds in zone 2). Loss of Line 3001/Section 396 (Keswick-Orrington 345kV) causes the Section 396 Type I SPS (NPCC SPS #140) to operate to trip the Maine Independence Station.

The zone 3 portion represents the GCX circle of the SPS, and is armed or blocked based upon the Keswick 345kV bus frequency. If the Keswick bus frequency exceeds 60.06Hz for more then 0.1 seconds with a rate of change in excess of 0.1Hz/sec, then the GCX relay is armed on the basis of over-frequency for 8 seconds. If the bus frequency falls below 59.94Hz for more then 0.1 seconds with a rate of change in excess of 0.lHz/sec, then the GCX relay is blocked on the basis of under-frequency for 10 seconds.

If the apparent impedance enters the GCX circle (zone 3 of the model) and the overfrequency conditions are satisfied, the GCX sends a signal to reject some amount of pre-selected generation in New Brunswick according to the rules of the Loss of 3001 SPS as described above. A 6-cycle delay is allowed between generation rejection and the instant where both the overfrequency conditions are satisfied and GCX entry occurs.

Keswick PowerRelay (NPCCSPS #12)

Another SPS called the Keswick Power Relay (KPR), is normally out-of-service and armed only when the Chester SVC is out of service and flows are high (i.e. > 550MW).

This SPS causes runback of import from Eel River HVDC link, if the real power flow from Keswick to Orrington exceeds 650 MW and the reactive power flow exceeds 200MVAR. For the purposes of this study it was assumed that this SPS was out-of-service.

GE-Power Systems GE-Power Energy Consulting Systems Energy Consulting 2.27 2.27 RepartllllO3.t+/-c ReportI t1tO3doc

3. Power Flow Analysis Results The power flow analysis was performed using GE's PSLF program. For pre-contingency solutions, transformer tap and phase shifting transformer angle movement as well as static var device switching were allowed. For post-contingency solutions, phase shifter angles remained fixed, while transformer tap and static var device switching were allowed for area 701 (NE), except for zones 41 (VELCO-VT) and 42 (VELCO-NC). In these Vermont zones, no control action was allowed post-contingency.

The bus voltage and branch loading performance was compared against appropriate criteria, as described in Section 2.1.3. The results of this analysis are described in the following subsections.

The results of both the base case and contingency analysis for the 10 study conditions (5 benchmark cases and 5 cases with the full uprate) are shown in the linked Excel workbook. The voltage and thermal violations are presented in several tabbed worksheets and are discussed below.

Entries in the tables that are in violation of criteria are indicated in red type. Black type and zero entries indicate that the result is within criteria.

3.1 Guide to Power Flow Analysis Results Workbook The first tab (Outages) of the workbook contains the contingency list. The second tab (VT Qg) documents the reactive power output from Vermont Yankee unit for all contingencies. The third tab (Essex Statcom) documents the reactive power output from the static compensator at Essex for all contingencies.

The fourth tab (Pre-cont Ws) documents all voltage violations for pre-contingency cases, grouped by bus. The fifth tab (VV by Bus) documents all voltage violations for post-contingency cases, also grouped by bus. The sixth tab (VV by Outage) documents the same post-contingency voltage violations, but grouped by contingency.

The seventh tab (Uprate Impact on Low Ws) is a subset of the fifth tab, reporting only significant bus voltage violations in New England and New York for post-contingency cases due to the Vermont Yankee full uprate. A significant uprate impact was defined as a post-contingency bus voltage that was at least 1% lower with the full uprate. Vermont Yankee bus voltage results are included even if the pre- and post-full uprate results are not significantly different. The results were further screened such that only low voltage violations are shown. The results are grouped by bus.

The eighth tab of the workbook (Pre-cont OLs) documents all thermal violations in New England for pre-contingency cases, grouped by branch. The ninth tab of the workbook (LTE OLs by Branch) documents all long-term emergency (post-contingency) thermal violations in New England, also grouped by branch. The tenth tab of the workbook (LTE OLs by Outage) documents the same thermal violations, but grouped by contingency.

The eleventh tab of the workbook (Uprate Impact on OLs) is a subset of the ninth tab, reporting only significant branch overloads due to the Vermont Yankee full uprate. A GE-PwerSysems nery Cnsuling3.1Rep flhllOdoc GE-PowerSystems Energy Consulting 3.1 Report11ll03.doc,

significant overload was defined as branch loading that was at least 3% higher with the full uprate. The results are grouped by branch.

3.2 Pre-contingency Bus Voltage Results There are several buses throughout New England that have minor pre-contingency high and low voltage violations, as shown in the fourth tab in the results workbook (Prc-cont Ws). The high voltages are observed primarily in Maine and in the neighborhood of the Comerford/Moore hydro plants for the light load cases both pre- and post- full uprate.

The Comerford/Moore units are out of service for these cases. The low voltages are primarily observed on the Vermont 34.5kV and 46kV system. These voltage violations are largely unaffected by the full uprate. Minor differences between the benchmark and corresponding full uprate cases are due mostly to differences in unit commitment between the cases.

The pre-contingency voltages in the Vermont Yankee area for the ten primary power flow study cases are shown in Table 3-1. This table shows the Vermont Yankee generator reactive power output, 345kV scheduled voltage, 345kV actual voltage, 115kV actual voltage, 4160v station service bus voltage, the nominal reactive power from the Chestnut Hill capacitors, and the Chestnut Hill 115kV actual voltage.

An additional pk3 scenario, with approximately 700MW flowing from NE to NY, was developed with low levels of Vermont generation. This Vermont dispatch scenario maintained regional interfaces, such as NY-NE, East-West and North-South, constant.

The pre-contingency Vermont Yankee voltages for these two cases are also shown in Table 3-1.

The Vermont Yankee 115kV and 345kV buses meet the minimum bus voltage criteria, l.Opu and 0.985pu respectively, for all cases. The Vermont Yankee plant 4160v buses, for both the station service and cooling tower loads, also meet the minimum bus voltage criteria, 0.90pu, for all cases.

However, the voltage schedule at the Vermont Yankee 345kV bus is not met in any of the pre- or post- full uprate cases. Since the existing system does not meet the voltage schedule under the study conditions, the full uprate project will not be required to meet the voltage schedule. However, a comparison of the pre-uprate 345kV voltage with the post- full uprate voltage shows a slight reduction due to the full uprate. Therefore, the full uprate project is required to maintain the 345kV voltage at pre-uprate levels. The worst case voltage reduction was observed for the pk3 sensitivity case with the Vermont dispatch. With the full uprate, the Vermont Yankee 345kV bus voltage was reduced from 1.024pu to 1.016pu, a 0.008pu reduction. All other system conditions showed approximately 0.005pu voltage reduction due to the full uprate. Therefore, Vermont dispatch scenario was the most limiting study condition in terms of voltage impact. Any mitigation that works under those conditions, will also work under the other study conditions.

Since the voltage requirements are on the Vermont Yankee 345kV bus, the local Vermont Yankee substation is the preferred location for the proposed capacitor banks. In addition, these shunt capacitor banks are better placed on the 11 5kV bus because it would be more cost effective than on the 345kV bus. Therefore, it is proposed that the additional voltage GE-Power Systems Energy Consulting 3.2 ReportI11101doc.

support be provided by 60MVAr of capacitor banks on the Vermont Yankee 15kV bus.

Entergy has confirmed that there is sufficient room in their 115kV switchyard for these capacitor banks and associated equipment.

The impact of the proposed 60MVAr shunt capacitors on pre-contingency voltages in the Vermont Yankee area is shown in Table 3-2. This table shows the same information as Table 3-1 for the pk3 sensitivity case with and without the full uprate. In addition, it shows the local Vermont Yankee conditions with the full uprate and the proposed 60MVAr capacitor banks. Table 3-2 shows that the proposed capacitors provide sufficient additional voltage support and ensure equivalent Vermont Yankee 345kV bus voltage performnance under both pre- and post- full uprate system conditions. This table also shows that it is feasible to operate, under pk3 peak load all-lines-in conditions, with the proposed capacitor banks on the Vermont Yankee II5kV bus and the existing capacitor banks on the Chestnut Hill I1 5kV bus. The 11 5kV bus voltages resulting with both the Vermont Yankee and Chestnut Hill banks in-service are below the specified maximum pre-contingency voltage criteria of 1.05pu.

3.2.1 Vermont Yankee 115kV Capacitor Switching Evaluation Additional power flow analysis was performed to determine the number and size of each switchable bank of the proposed 60MVAr shunt capacitor at Vermont Yankee 115kV.

This analysis focused on the expected change in voltage (AV) on the Vermont Yankee area buses with the insertion of the proposed Vermont Yankee 115kV capacitor banks under the Vermont dispatch scenario. Taking the Chestnut Hill capacitor banks as an example, the 60MVAr addition was split into one 30MVAr bank and two 15MVAr banks. Both 15MVAr and 30MVAr capacitor bank removals at the Vermont Yankee 115kV bus were performed with either all lines in service or with the Vermont Yankee autotransformer out of service. In addition, similar capacitor switching events were performed with the Chestnut Hill 13.1MVAr and 26.2MVAr capacitor banks as a comparison. No other SVD, LTC or PAR action was allowed in this analysis. The AV capacitor switching criteria was as follows:

• AV < 2.5% with all line in service

• AV < 5% with the Vermont Yankee autotransformer out of service Complete results of this capacitor switching analysis as well as the contingency analysis described in Section 3.3.1 are shown in the linked spreadsheet, capanal.xls. The AV results with all lines in service are shown in Table 3-3. The AV analysis results with the autotransformer out of service are shown in Table 3-4.

The largest AV with all lines in service was -1.2% at the Vermont Yankee 115kV for a 30MVAr capacitor removal. This meets the criteria and indicates the feasibility of switching a 30MVAr bank under normal operating conditions.

The largest AV with the autotransformer out of service was -9.6% at the Vermont Yankee 115kV for a 30MVAr capacitor removal. Switching out a 15MVAr bank resulted in a -4.8% AV at the 115kV bus. The 30MVAr capacitor switching event does not meet criteria, however, the 15MVAr capacitor switching does result in acceptable AVs. Therefore, it is proposed that the 60MVAr shunt capacitor be split into three banks GE-PwerSysems nery Cnsuling3.3Repo111lO3doc GE-PowerSystems Energy Consulting 3.3 Report111103.doc,

- one 30MVAr bank and two 15MVAr banks. This will allow for capacitor switching both with and without the autotransformer in service.

The final step in sizing the capacitor banks considered the impact of these banks on local voltage performance in response to outages. This is discussed in Section 3.3.

Energy Consulting Systems Energy GE-Power Systems Consulting 3.4 Repot1111O3.dac.

3.4 RepWIt11103.dbc,

Table 3-1. Pre-ContingencyBits Voltages and Reactive Power Output in the Vermont Yankee Area.

I ,

Light Load Peak Load Peak Load Peak Load Low Vt Generation Shoulder Load (vy-tltl) (vy-tpkl) (vy-tpk2) (vy-tpk3) (vy-tpk3novt) (vy-tshl)

NY-NE = 01MV NY-NE = 0NTV NY-NE = 700MW NY-NE = -7001I1V NY-NE = -700 M1V NY-NE = -1200MW Description Existing Full Existing Full Existing Full Existing Full Existing Full Existing Full Uprate Uprate Uprate Uprate Uprate Uprate VYG ReactivePoNverOutput(MVAr) 150 150 150 150 150 150 150 150 150 150 150 150 VY 345kV Scheduled Voltage (pu) 1.026 1.026 1.043 1.043 1.043 1.043 1.043 1.043 1.043 1.043 1.043 1.043 VY 345kV Bus Voltage (pu) 1.024 1.024 1.030 1.025 1.034 1.030 1.025 1.021 1.024 1.016 1.025 1.020 VY 115kV Bus Voltage (pu) 1.022 1.021 1.028 1.023 1.030 1.027 1.023 1.019 1.023 1.015 1.018 1.014 VY 4160v Bus Voltage (pu) 0.949 0.946 0.955 0.947 0.959 0.951 0.951 0.943 0.950 0.938 0.951 0.942 Chestnut Hill Capacitors (MVAr) 0 0 511 5 51 51 51 51 51 51 0 0 ChestnutHill 115kVBusVoltage(pu) 1.020 1.021 1.028 1.024 1.029 1.027 1.023 1.019 1.023 1.015 1.015 1.011 3.5 fleportllllO3doc GE-Power GE-Power Systems Energy Consulting Systems Energy Consulting 3.5 Repor111103.doc

Table 3-2. V~erin out YanikeeArea Conditio,,s uitit Additional 6OMVAr Capacitor Bank.

Lowl Vt Generation (vy-tpk3r-nov)

NY-NE = -700M1V Description Existing Full Full Uprate+

Uprate 60NWAr VY GI Reactive Power Output (MVAr) 150 150 150 VY 345kV Scheduled Voltage (pu) 1.043 1.043 1.043 VY 345kV Bus Voltage (pu) 1.024 1.016 1.024 VY 115kV Capacitors (MVAr) 0 0 60 VY 115kV Bus Voltage (pu) 1.023 1.015 1.035 VY 4160v Bus Voltage (pu) 0.950 0.938 0.946 Chestnut Hill Capacitors (MVAr) 51 51 51 Chestnut Hill 115kV Bus Voltage (pu) 1.023 1.015 1.034 Table 3-3. AVi iRespotse to CapacitorBantkIntsertiontsnith AllLintesIzt-Sertice.

Low V't Generation

(*y-tpk3r-nov)

NY-NE = -700'MWN' Bus Existing Full AVmax Capacitor Switching Event Uprate+ (pu) 60D VAr 70490 VERNONRD 115 0.000 -0.011 0.025 Switch Out 30MVAr Vermont Yankee 115kV Caps 70490 VERNONRD 115 -0.010 -0.011 0.025 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 70506 V.RD.TAP 115 0.000 -0.011 0.025 Switch Out 30MVAr Vermont Yankee 1 15kV Caps 70506 V.RD.TAP 115 -0.010 -0.011 0.025 Switch Out 26.2MVAr Chestnut Hill 115 kV Caps 70523 VTYANKEE 115 0.000 -0.012 0.025 Switch Out 30MVAr Vermont Yankee 115kV Caps 72717 CHSNT HL 115 0.000 -0.011 0.025 Switch Out 30MVAr Vermont Yankee 115kV Caps 72717 CHSNT HL 115 -0.012 -0.013 0.025 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 72750 WESTPORT 115 -0.011 -0.012 0.025 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 73906 VYBUS SB 4 0.000 -0.012 0.025 Switch Out 30MVAr Vermont Yankee 115kV Caps 3.6 Report 111103.dac GE-Power GE-Power Systems Energy Consulting Systems Energy Consulting 3.6 Report111101.doc

Table 3-4. AJVin Response to CapacitorBank Insertions xwith Jerlnont Yankee A utotransforinerOut ofSenice.

Low Vt Generation (vy-tpk3nov*t)

NY-NE = -7001MWNN' Bus Existing Full AVmax Capacitor Switching Event Uprate+ (pu) 60NDVAr 70506 V.RD.TAP 115 NA -0.047 0.05 Switch Out I SMVAr Vermont Yankee 115kV Caps 70506 V.RD.TAP 115 NA -0.093 0.05 Switch Out 30MVAr Vermont Yankee 115kV Caps 70506 V.RD.TAP 115 -0.064 -0.079 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 70506 V.RD.TAP 115 -0.029 -0.039 0.05 Switch Out 13.IMVAr Chestnut Hill 115kV Caps 70490 VERNONRD 115 NA -0.047 0.05 Switch Out 15MVAr Vermont Yankee 115kV Caps 70490 VERNONRD 115 NA -0.093 0.05 Switch Out 30MVAr Vermont Yankee 115kV Caps 70490 VERNONRD 115 -0.063 -0.078 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 70490 VERNONRD 115 -0.028 -0.039 0.05 Switch Out 13.1MVAr Chestnut Hill 115kV Caps 70523 VTYANKEE 115 NA -0.048 0.05 Switch Out I5MVAr Vermont Yankee I15kV Caps 70523 VTYANKEE 115 NA -0.096 0.05 Switch Out 30MVAr Vernont Yankee 115kV Caps 70523 VTYANKEE 115 -0.064 -0.079 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 70523 VTYANKEE 115 -0.029 -0.040 0.05 Switch Out 13.1MVAr Chestnut Hill 115kV Caps 72717 CHSNT HL 115 NA -0.045 0.05 Switch Out 13MVAr Vermont Yankee 115kV Caps 72717 CHSNT HL 115 NA -0.090 0.05 Switch Out 31MVAr Vermont Yankee 115kV Caps 72717 CHSNT HL 115 -0.064 -0.078 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 72717 CHSNT HL 115 -0.029 -0.039 0.05 Switch Out 13.1MVAr Chestnut Hill 115kV Caps 72726 KEENE 115 NA -0.026 0.05 Switch Out 13.MVAr Vermont Yankee 115kV Caps 72726 KEENE 115 NA -0.02 0.05 Switch Out 31MVAr Vermont Yankee 115kV Caps 72726KEENE 115 jNA -0.052 0.5Sic ut0Vreronake15Vap 72726 KEENE 115 -0.037 -0.045 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 72726 KEENE 115 -0.017 -0.022 0.05 Switch Out 13.IMVAr Chestnut Hill 115kV Caps 72747 SWANZEY 115 NA -0.032 0.05 Switch Out 15MVAr Vermont Yankee 115kV Caps 72747 SWANZEY 115 NA -0.063 0.05 Switch Out 30MVAr Vermont Yankee 115kV Caps 72747 SWANZEY 115 -0.045 -0.055 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 72747 SWANZEY 115 -0.020 -0.027 0.05 Switch Out 13.1MVAr Chestnut Hill 115kV Caps 72750 WESTPORT 115 NA -0.040 0.05 Switch Out 15MVAr Vermont Yankee 115kV Caps 72750 WESTPORT 115 NA -0.079 0.05 Switch Out 30MVAr Vermont Yankee 115kV Caps 72750 WESTPORT 115 -0.056 -0.069 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 72750 WESTPORT 115 -0.025 -0.034 0.05 Switch Out 13.IMVAr Chestnut Hill 115kV Caps 73906 VYBUS 5B 4 NA -0.048 0.05 Switch Out 15MVAr Vermont Yankee 115kV Caps 73906 VYBUS 5B 4 NA -0.096 0.05 Switch Out 30MVAr Vermont Yankee 115kV Caps 73906 VYBUS 5B 4 -0.064 -0.079 0.05 Switch Out 26.2MVAr Chestnut Hill 115kV Caps 73906 VYBUS 5B 4 -0.029 -0.040 0.05 Switch Out 13.1MVAr Chestnut Hill 115kV Caps 3.7 RepadllllOadac GE-Power Systems Consulting Energy Consulting Systems Energy 3.7 Report111103.doc

3.2.2 Vermont Yankee First Phase Uprate Impact on 345kV Voltage As described in the Introduction, the Vermont Yankee uprate will be performed in two steps. The first phase will occur during the refueling outage scheduled for spring 2004, and will include replacement of the high pressure turbine steam path and rewind of the main generator to increase the nameplate rating to 684MVA. As a result, the maximum power output will increase to 630 MW gross and 220 MVAR after this first phase of the uprate. While the bulk of this study focused on system performance with the full uprate, Entergy requested a sensitivity analysis of the impact of the first uprate phase on the Vermont Yankee 345kV bus voltage. The goal of this analysis was to determine whether the 345kV bus voltage could be maintained at pre-uprate levels without the 115kV capacitor banks required for the full uprate.

The evaluation focused on the most limiting Vermont generation dispatch scenario under 2006 extreme weather peak load conditions for five system conditions. Table 3-5 summarizes the pre-contingency Vermont Yankee reactive output, both scheduled and actual Vernont Yankee bus voltages, Chestnut Hill 1 15kV bus voltage, Vermont Yankee and Chestnut Hill capacitor reactive output, and selected interface flows.

Note that the pre-uprate Vermont Yankee 345kV bus voltage was 1.024pu, even though the scheduled voltage was 1.043pu. Therefore, 1.024pu was the goal for all uprate cases.

For phase 1, 1.024pu on the Vermont Yankee 345kV bus was achieved with an output of 194MVAr from the unit, which is within the 220MVAr capability. For reference, the results for the first phase uprate with an output of only 150MVAr and two full uprate cases (with and without the 60MVAR of Vermont Yankee 115kV capacitor banks) are also shown. With the full uprate and without the 11SkV capacitors, the 345kV bus voltage was 1.016pu. With the full uprate and with the 115kV capacitors, the 345kV bus voltage was 1.024pu.

GE-Power Systems Energy Consulting 3.8 Reportlt1103.doc

Table 3-5. Verniont Yankee Area Conditionsutndler FirstPlhase and Full Uprate Conditionls.

First Phase First Phase Full Uprate Full Uprate Description Existing Uprate Uprate Qmax=150MVAr Qmax=150NIVAr ystem Qmax=150MVAr Qmax=220IVAr No Caps 60MVAr Caps VY Reactive Power Output (MVAr) 150 150 194 150 150 345kV Scheduled Voltage (pu) 1.043 1.043 1.043 1.043 1.043 V 345kV Bus Voltage (pu) 1.024 1.018 1.024 1.016 1.024 115kV Capacitors (MVAr)

V 0 0 0 0 60 V 115kV Bus Voltage (pu) 1.023 1.017 1.022 1.015 1.035 VY 4160v Bus Voltage (pu) 0.95 0.942 0.957 0.938 0.946 Chestnut Hill Capacitors (MVAr) 52 52 52 52 52 Chestnut Hill 115kV Bus Voltage (pu) 1.023 1.018 1.022 1.015 1.034 North-South Interface (MW) 2485 2472 2471 2507 2506 East-West Interface (MW) 2254 2227 2227 2225 2226 NY-NE Interface (MW) -719 -739 -740 -720 -721 rthwest Vermont Interface (MW) 373 378 378 378 378 Central Vermont Interface (MW) 193 211 211 211 211 39 Repo,1111103.cAc GE-Power Systems GE-Power Energy Consulting Systems Energy Consulting 3.9 Report111103.dDc

3.3 Post-Contingency Bus Voltage Results There are several Vermont buses that have post-contingency low voltage violations, as shown in the seventh tab in the results workbook (Uprate Impact on LowvVNs). This worksheet shows only the Vermont Yankee area voltages and low voltage violations that are significantly impacted by the full uprate. Differences between pre- and post- full uprate performance that are less than 1% are not included in this tab, but can be found in the fifth and sixth tabs (VV by Bus and VY by Outage). Bus violations impacted by the full uprate, without the proposed capacitor banks, were observed for the following eight contingencies:

1. 2. Loss of Section 394 (Seabrook-Tewksbury 345kV)

1. 4. Loss of Section 312 (Northfield-Alps 345kV)

1. 24. Granite K52 Breaker Failure

1. 30. Loss of Vermont Yankee Autotransformer

1. 34. Vermont Yankee 379 Breaker Failure, Loss of Section 379 (Vermont Yankee-Scobie 345kV) and Autotransformer

1. 35. Vermont Yankee 381 Breaker Failure, Loss of Section 381 (Vermont Yankee-Northfield 345kV) and Autotransformer

1. 36. Vermont Yankee IT Breaker Failure, Loss of Section 340 (Vermont Yankee-Coolidge 345kV) and Generator

1. 37. Loss of Granite-Wilder 1 15kV line, Chelsea & Hartford 11 5/46kV Transformers The Granite K52 breaker failure outage (contingency 24) and the Granite-Wilder 11 5kV line outage (contingency 37) result in significant low voltages on the Vermont 46kV system, some as low as 0.60pu, both with and without the full uprate. Some bus voltages are improved by the addition of the full uprate and some are reduced. These violations are a pre-existing problem, and there is a plan to add breakers at Chelsea and/or Hartford station to reduce the number of elements lost for these two contingencies. The primary concern is branch loading, rather than bus voltages, so a sensitivity analysis was performed under pk2 peak load conditions with 700MW flowing from NY to NE to evaluate the impact of the planned additions on local branch loading. That analysis is described in Section 3.5.1.

Three of the Vermont Yankee contingencies listed above (contingencies 30, 34, and 35) show significant low voltages on the Vermont 46kV, 69kV and 115kV system, some as low as 0.83pu, both with and without the full uprate. The Vermont Yankee 4160v bus with the cooling tower load is among those with low voltages. In general, the full uprate improves these voltages. There are no known plans to address these low voltages. This is a pre-existing problem due to the loss of the Vermont Yankee autotransformer in each of these contingencies, and the full uprate project will not be required to mitigate it.

The 345kV line outages (contingencies 2 and 4) result in slight voltage violations at the Vermont Yankee 115kV bus for both pre- and post- full uprate system conditions. The lowest voltage observed pre-uprate was 0.995pu for the loss of Section 312 (Northfield-Alps 345kV) under peak load conditions with near zero flow on the NY/NE interface.

The lowest voltage observed post- full uprate was 0.988pu, also for the loss of Section 312 under peak load conditions with near zero flow on the NY/NE interface.

3.10 ReprxtllIlO3.doc GE-Power Energy Consulting Systems Energy GE-PowerSystems Consulting 3.10 Report111103.doc

Contingency 36 (Vermont Yankee IT stuck breaker) results in slight low voltages on both the Vermont Yankee 11 5kV bus both with and without the full uprate. The 11 5kV bus voltage was low, both pre- and post- full uprate, under system conditions with a high NE to NY transfer (peak load with 700MW NE/NY, and shoulder load with 1200MW NE/NY). The minimum voltage observed was 0.992pu, both pre- and post- full uprate.

3.3.1 Vermont Yankee 115kV Capacitor Post-Contingency Evaluation The low voltages observed on the Vermont Yankee buses with the full uprate will be improved by the addition of the 60MVAr of shunt capacitors proposed in the previous section. An analysis of the impact of the banks on post-contingency performance was performed and is described in the following paragraphs. The peak load condition with the Vermont dispatch and approximately 700MW flowing from NE to NY was evaluated for all study contingencies as described in Section 2.1.4. Contingencies that include the loss of the Vermont Yankee autotransformer have the greatest impact on the local bus voltages. Therefore, coordination between the loss of that transformer and the proposed capacitor banks is important. To evaluate the impact of the proposed capacitor banks, several variations on existing contingencies 30, 34 and 35 were developed, as follows:

1. 30x. Loss of Vermnont Yankee Autotransformner and 15MVAr of 11 5kV Capacitors

1. 30y. Loss of Vermont Yankee Autotransformer and 30MVAr of 11 5kV Capacitors

1. 34y. Vermont Yankee 379 Breaker Failure, Loss of Section 379 (Vermont Yankee-Scobie 345kV), Autotransformner, and 30MVAr of 11 5kV Capacitors

1. 35. Vermnont Yankee 381 Breaker Failure, Loss of Section 381 (Vermont Yankee-Northfield 345kV), Autotransformer, and 30MVAr of 115kV Capacitors Complete results of this contingency analysis as well as the capacitor switching analysis described in Section 3.2.1 are shown in the linked spreadsheet, capanal.xls.

While the analysis shows a number of voltage violations, the Vermnont dispatch conditions were considered severe and only the Vermont Yankee area was deemed significant. The proposed VELCO projects are expected to address any other concerns.

Therefore, a subset of significant results is shown in Table 3-5. The first column identifies the bus, while the second and third columns show the specified post-contingency bus voltages for the existing system and for the full uprate system with the 60MVAr of shunt capacitors. The next to last column shows the minimum acceptable voltage at that bus, and the final column identifies the contingency. Bus voltages that violate the specified criteria are shown in red, a zero indicates that the bus voltage was within criteria.

Under these peak load conditions, there were no voltage violations, either with or without the full uprate, on the Vermont Yankee 345kV bus. Hence, it does not appear in Table 3-

5. There were low voltage violations on the Chestnut Hill 115kV bus without the full uprate, but acceptable voltages with the full uprate regardless of the coordination of capacitor tripping with the loss of the autotransformer.

GE-Power Systems Energy Consulting 3.11 Reportl11l03.dbc

Without the full uprate and its associated capacitors, the Vermont Yankee 115kV and 4160v bus voltages were unacceptable for contingencies including the loss of the autotransformer. Bus voltages under these conditions were approximately 0.89pu, while the minimum voltage criteria for this bus is 1.00pu.

With the full uprate and the capacitors, but without any capacitor tripping in conjunction with the loss of the autotransformer, the Vermont Yankee 15kV and 41 60v bus voltages are 1.039pu to 1.055pu for the three contingencies. This indicates the potential for unacceptably high voltages (maximum acceptable voltage criteria is 1.05pu) after the loss of the autotransformer if all of the 60MVAr of capacitor banks are left in service.

Tripping 30MVAr of capacitors with the autotransformer reduces the post-contingency voltages at both the 115kV and 4160v buses. The 4160v bus voltages are acceptable and therefore are not shown in the table. The 115kV buses are approximately 0.94pu to 0.95pu post-contingency. This violates the minimum voltage criteria for the Vermont Yankee 115kV bus. These voltages are still, however, much higher than observed in the existing system. Currently, the NRC allows the Vermont Yankee plant to operate for one week with the autotransformer out of service and with the corresponding reduced voltage on the 115kV bus. That is not expected to change with the full uprate. The VELCO 115kV post-contingency voltage limit is 0.92pu. Therefore, no upgrades are needed to meet VELCO voltage criteria. However, Entergy may wish to improve the 115kV bus voltage to meet their own needs.

One final evaluation of the coordination of capacitor bank tripping with the loss of the Vermont Yankee autotransformer was performed. This evaluation focused on the AV resulting from an outage that includes loss of the autotransformer as well as 30MVAr of capacitors. The AV criteria in response to contingencies was as follows:

• AV < 5% on the 345kV system

• AV < 10% on the 115kV system and below The significant results are shown in Table 3-6. There are no violations of the contingency AV criteria at the Vermont Yankee 345k-V bus either with or without the full uprate. Without the uprate, there are AVs in excess of 10% at both the Vermont Yankee and Chestnut Hill 1kV buses. With the full uprate and its associated capacitors, there are no AV violations for any of the contingencies including the loss of the autotransformer, regardless of any associated capacitor tripping.

As a result of the analysis described above, as well as in Section 3.2.1, it is proposed that the 60MVAr of capacitors be divided into one 30MVAr bank and two 15MVAr banks.

In addition, the 30MVAr capacitor bank should be connected such that it will trip with the Vermont Yankee autotransformer and the two 15MVAr capacitor banks should be connected to the 115kV bus such that they will be available for post-contingency switching. A one-line diagram of such an arrangement is shown in Figutre3-1. The final design of the proposed capacitor banks and their associated equipment (e.g., circuit breakers) will require review and approval by VELCO.

GE-Power Energy Consulting Systems Energy GE-PowerSystems Consulting 3.12 Rep'x?111103.doc 3.12 Repon11tfO3.doc

Table 3-6. Post-ConftingencyBits Voltages in the Jernmont Yankee Area with Additional 60MVAr of Shtnt CapacitorBanks.

Low Vt Generation (vy-tpk3novt)

NY-NE = -700MIW Bus Existing Full Vmin Outage Description Uprate+ (pu) 60NINVAr 70523 VTYANKEE 115 0.897 1.055 1.000 Loss of VY Autotransformer 70523 VTYANKEE 115 0.897 0.958 1.000 Loss of VY Autotransformer, 30MVAr VY Caps 70523 VTYANKEE 115 0.885 1.044 1.000 VY 379 BK Failure, trip 379 & VY Auto 70523 VTYANKEE 115 0.885 0.947 1.000 VY 379 BK Failure, trip 379 & VY Auto, 30MVAr cap 70523 VTYANKEE 115 0.887 1.039 1.000 VY 381 BK Failure, trip 381 & VY Auto 70523 VTYANKEE 115 0.887 0.942 1.000 VY 381 BK Failure, trip 381 & VY Auto, 30MVAr cap 72717 CHSNT HL 115 0.900 1.048 0.950 Loss of VY Autotransformer 72717 CHSNT HL 115 0.889 1.037 0.950 VY 379 BK Failure, trip 379 & VY Auto 72717 CHSNTIHL 115 0.890 1.032 0.950 VY381 BK Failure, trip 381 &VY Auto 73906 VYBUS SB 4 0.897 1.055 0.900 Loss of VY Autotransformer 73906 VYBUS SB 4 0.885 1.044 0.900 VY 379 BK Failure, trip 379 & VY Auto 73906 VYBUS SB 4 0.887 1.039 0.900 VY 381 BK Failure, trip 381 & VY Auto GE-Power Systems Energy Consulting 3.13 RepontI11t3.doc

Table 3-Z. Post-Contintgenzcy 4Vi, thle Vtermonit Yanlkee Area withI Alditionlal 60MAVAr of Shunt CapacitorBanks.

Low Vt Generation (vy-tpk3iiovt)

NY-NE = -700NIMWI Bus Existing Full AVrmax Outage Description UprateI (pu) 60ININ'Ar 70486 VTYNK345 345 0.015 0.000 0.05 VY 379 BK Failure, trip 379 & VY Auto 70486 VTYNK345 345 0.000 -0.019 0.05 VY 381 BK Failure, trip 381 & VY Auto 70486 VTYNK345 345 0.000 -0.022 0.05 VY 381 BK Failure, trip 381 & VY Auto, 30MVAr cap 70523 VTYANKEE 115 -0.125 -0.029 0.10 Loss of VY Autotransformer, 15MVAr VY Caps 70523 VTYANKEE 115 -0.125 -0.076 0.10 Loss of VY Autotransformer, 30MVAr VY Caps 70523 VTYANKEE 115 -0.125 0.021 0.10 Loss of VY Autotransformer 70523 VTYANKEE 115 -0.137 0.009 0.10 VY 379 BK Failure, trip 379 & VY Auto 70523 VTYANKEE 115 -0.137 -0.088 0.10 VY 379 BK Failure, trip 379 & VY Auto, 30MVAr cap 70523 VTYANKEE 115 -0.136 0.005 0.10 VY381 BKFailure, trip 381 &VY Auto 70523 VTYANKEE 115 -0.136 -0.093 0.10 VY 381 BK Failure, trip 381 & VY Auto, 30MVAr cap 70523 VTYANKEE 115 -0.011 -0.005 0.10 VY IT BK Failure, trip 340 & VY GI 72717 CHSNT HL 115 -0.123 -0.032 0.10 Loss of VY Autotransforner, I5MVAr VY Caps 72717 CHSNTHL 115 -0.123 -0.077 0.10 Loss of VY Autotransformer, 30MVAr VY Caps 72717 CHSNT HL 115 -0.123 0.015 0.10 Loss of VY Autotransformer 72717 CHSNT HL 115 -0.134 0.003 0.10 VY 379 BK Failure, trip 379 & VY Auto 72717 CHSNT HL 115 -0.134 -0.088 0.10 VY 379 BK Failure, trip 379 & VY Auto, 30MVAr cap 72717 CHSNT HL 115 -0.133 -0.001 0.10 VY 381 BK Failure, trip 381 & VY Auto 72717 CHSNT HL 115 -0.133 -0.093 0.10 VY 381 BK Failure, trip 381 & VY Auto, 30MVAr cap 72717 CHSNT HL 115 -0.013 -0.008 0.10 VY IT BK Failure, trip 340 & VY GI Note: 0 indicates acceptable performance GE-Power Systems Energy Consulting 3.14 Repon111 103 dbc

to Coolidge to Amherst 345kV 30 MVAr t t L ot Chestnut Hill K I86I & Vernon Rd 5B} 15MVAr 15MVAr CoolingTower Load l >M Northfield

-to 4160v Station Service Load Figure3-1. Full Uprateof Vermont Yankee PlanitandSubstationt Onze-Line Diagrami withl 60M'arof Situntt Capacitors.

3.15 Reportl 11103.doc GE-Power GE-Power Systems Energy Consulting Systems Energy Consulting 3.15 Reports 1103.doc

3.4 Pre-Contingency Branch Loading Results There are several branches throughout the region that have minor thermal violations, as shown in the eighth tab in the results workbook (Pre-cont OLs). The violations outside of the Vermont Yankee region are largely unaffected by the addition of the Vermont Yankee full uprate project. The minor differences between the benchmark cases and corresponding full uprate cases are mostly due to differences in unit commitment between the cases.

The 345kV line from Vermont Yankee to Northfield is currently rated at 896MVA.

Under light load conditions the flow on this line is 0.96pu pre-uprate and 1.0pu post- full uprate. The redispatch of the full uprate was taken against the smaller of the two Merrimack units in this case. The Merrimack unit is connected to the 115kV system, while other possible redispatch choices, such as the ConEd Newington plant, are connected to the 345kV system. Therefore, a second series of light load cases (tlt2r and tlt2u) was developed to test the sensitivity of the Vermont Yankee-Northfield 345kV line flow to the full uprate redispatch scenario under pre-contingency conditions only. For the sensitivity case without the uprate, the Vermont Yankee-Northfield 345kV line flow was approximately 0.98pu. With the full uprate, the sensitivity case showed a Vermont Yankee-Northfield 345kV line flow of approximately 1.02pu. This indicates a relative lack of sensitivity to redispatch choices on the east side of the NE East-West interface.

The relatively low 345kV line rating, 896MVA, is due to the limited rating of line relay equipment at the Vermont Yankee substation. The rating on this line should be increased by replacing the limiting equipment.

A detailed summary of the generation dispatch across New England, as well as additional interface flows and other information, for the light load sensitivity cases is included in Appendices A and B. One line diagrams of the Vermont and NE 345kV transmission system for each sensitivity case are also included in these appendices. Pre-uprate information is shown in Appendix A and post- full uprate information is shown in Appendix B.

GE-Power Systems Energy Consulting 3.16 Report1 t1103ADoc

3.5 Post-Contingency Branch Loading Results There are several Vermont branches that have post-contingency overloads, as shown in the eleventh tab in the results workbook (Uprate Impact on OLs). This worksheet shows only the branch overloads that are significantly impacted by the full uprate.

Differences between pre- and post- full uprate performance that are less than 3% are not included in this tab, but can be found in the ninth and tenth tabs (LTE OLs by Branch and LTE OLs by Outage). In addition, the post-contingency overloads for the Vermont Yankee-Northfield 345kV line are shown in the Uprate Impact on OLs tab.

The maximum overload observed on Vermont Yankee-Northfield 345kV line was 1.20pu, which indicates that the rating of the Vermont Yankee-Northfield 345kV line must be increased to a minimum of 1075MVA.

Additional branch overloads were observed for the following contingencies:

1. 10. Loss of Coolidge-Ascutney 115kV (Section K31)

1. 24. Granite K52 Breaker Failure

1. 35. Vermont Yankee 381 Breaker Failure, Loss of Section 381 (Vermont Yankee-Northfield 345kV) and Autotransformer

1. 37. Loss of Granite-Wilder 115kV line, Chelsea & Hartford 115/46kV Transformers Overloads were observed, both with and without the full uprate, on the W Rutland-Blissville-Whitehall 115kV line under light load conditions (near zero NE/NY flow) and shoulder load conditions (1200MW NE/NY flow) for contingency 35. The largest pre-uprate overload was 1.04pu of LTE rating on the W Rutland-Blissville section under shoulder load conditions. The largest post- full uprate overload was 1.09pu on the same section under the same load conditions. This is a pre-existing problem and it is expected that the proposed PAR on the Whitehall-Blissville line will mitigate these overloads. No additional mitigation will by required of the full uprate project.

Overloads were also observed, both with and without the full uprate, on the Wallingford Tap-Mt Holly-Ludlow 46kV line segment under peak load conditions in response to the Ascutney-Coolidge 115kV line outage. The maximum pre-uprate loading was 1.23pu with a NY/NE interface flow of 700MW on the Wallingford Tap-Mt Holly segment. The maximum post- full uprate loading was 1.30pu under the same conditions. A sensitivity was performed with the Ascutney Jet unit in service. For the pre-uprate sensitivity, an overload of 1.1 lpu was observed. For the post- full uprate sensitivity, an overload of 1.18pu was observed. This indicates that the Ascutney Jet is effective in reducing flow on the 46kV system. This is a pre-existing problem that is adversely impacted by the full uprate. Currently, there is no proposed mitigation for this problem. The full uprate is not responsible for any additional mitigation.

Overloads on the Ascutney-Coolidge 11 5kV line were observed for the full uprate cases, under all peak load conditions in response to the Vermont Yankee 381 breaker failure outage (contingency 35). This overload can be attributed to the full uprate project, and mitigation will be required. The limiting item is approximately 25 feet of riser conductor.

Replacing that will increase the Ascutney-Coolidge 11 5kV line rating to 240MVA which GE-Power Systems Energy Consulting 3.17 RepWI1t1103.doc

would result in acceptable performance. The Vermont Yankee uprate project is responsible for replacing the limiting riser conductor.

Overloads were observed, both with and without the full uprate, on a few 46kV line segments in response to the Granite K52 breaker failure outage (contingency 24) and the Granite-Wilder 115kV line outage (contingency 37) under all peak load conditions.

There are current plans for additional circuit breakers at Chelsea and/or Hartford 115kV stations, which would mitigate these overloads. A sensitivity analysis, focused on Granite area outages, was performed and is discussed in the following section.

3.5.1 Impact of Additional Breakers at Chelsea and Hartford 115kV The Granite area sensitivity analysis evaluated performance of the peak load case, pk2, with a NY/NE flow of 700MW. This system condition was selected because it showed the largest impact due to the full uprate. The original Granite area contingencies were as follows:

1. 24. Granite K52 Breaker Failure, Loss of Barre-Granite and Granite-Wilder 115kV lines, Chelsea & Hartford 115/46kV Transformers

1. 37. Loss of Granite-Wilder 115kV line, Chelsea & Hartford 115/46kV Transformers Five more contingencies were evaluated,

1. 38. Loss of Granite-Chelsea 15kV line

1. 39. Granite K52 Breaker Failure, Loss of Barre-Granite and Granite-Chelsea 115kV lines

1. 40. Loss of Granite-Hartford 115kV line, Chelsea 115/46kV Transformer

1. 41. Loss of Hartford-Wilder 115kV

1. 42. Loss of Chelsea-Wilder 115kV line, Hartford 115/46kV Transformer Contingencies 38, 39 and 42 assumed new breakers at the Chelsea 115kV substation.

Contingencies 40 and 41 assumed new breakers at the Hartford 115kV substation. The primary analysis discussed in the previous section included all contingencies through 39.

Contingencies 40 through 42 were only evaluated for this sensitivity analysis. Complete branch loading results for this Granite area analysis are shown in the linked spreadsheet, granite.xls.

In response to contingency 24 (Granite K52 stuck breaker without new breakers), an increase in flow due to the full uprate was observed on the ASCUT-HIBR and WNDSR V4-TAFTS 46-QUECHE T-NORWICH 46kV lines, and the Windsor 115/46kV transformer. The maximum increase due to the full uprate was about 11%. Several of these line segments were overloaded without the full uprate.

Contingency 39 is the equivalent Granite K52 stuck breaker contingency with the proposed new breakers at Chelsea 115kV substation. The number of overloads was reduced to only those branches that had pre-contingency overloads. The post-contingency overloads were somewhat larger than the pre-contingency overloads, and there was no significant impact due to the full uprate.

Contingency 37 (Granite-Chelsea-Hartford-Wilder 115kV line outage without new breakers) shows about a 3% increase in flow on the Windsor transformer and about a 5%

GE-Power Energy Consulting Systems Energy GE-PowerSystems Consulting 3.18 Repoit111103.doc 3.18 Report1t1103.doc

increase in flow on the TAFTS-QUECHE 46kV line due to the full uprate. Both branches were overloaded without the uprate for this outage.

Contingency 38 is the above Granite-Wilder outage modified with additional breakers at Chelsea. There were overloads on the Blissville and N Rutland transformers that are a bit higher than already observed under pre-contingency conditions. There was no significant impact due to the full uprate.

Contingency 40 is the above Granite-Wilder outage modified with additional breakers at Hartford instead of Chelsea. - There were overloads on the Blissville and N Rutland transformers again that are a bit higher than under pre-contingency conditions. There was no significant impact due to the full uprate.

Contingency 41 (Loss of Hartford-Wilder 115kV) shows no post-contingency overloads.

Contingency 42 (Loss of Chelsea-Wilder 115kV line and Hartford 115/46kV transformer) shows no increase in the pre-contingency overloads.

This indicates that the proposed breakers at Chelsea and/or Hartford will eliminate the overloads observed on the local 46kV system for the existing Granite-Wilder 11 5kV line and Granite stuck breaker outages. In addition, there was no adverse impact due to the full uprate once those breakers were added.

3.6 N-2 Contingency Analysis Results The first step in the N-2 contingency analysis was to develop power flow cases representing the appropriate N-I system conditions. The peak load condition with 700MW of flow from NE to NY (pk3 series) was selected. Power flow cases representing two N-I conditions were then created. One case represented a system with Section 379 (Vermont Yankee-Amherst 345kV line) out of service, and the other represented a system with Section 381 (Vermont Yankee-Northfield 345kV line) out of service. All controlled devices (SVDs, LTCs, PARs) were allowed to act. This approximates the actions required to accommodate a contingency. These power flow cases represented both the existing system and the system with the Vermont Yankee uprate.

Several pre-contingency overloads observed in the primary pk3 cases, were also observed in the N-I power flow cases. No modifications were made to address these overloads.

Next, approximately a 1200MW redispatch was performed on each case. This represents the maximum redispatch allowed after one contingency in order to ensure acceptable system performance in response to a second contingency. This redispatch is illustrated in Table 3-7. Note that system conditions with and without the full uprate are identical after the redispatch because the Vermont Yankee output was limited to 275MW. Therefore, one case represents both the pre- and post- full uprate system conditions, for each of the N-1 outages.

GE-Power Systems Energy Consulting 3.19 Repont11t101doc

Table 3-8. RedispatclhAfter N-1 Outage and Before N-2 Outage.

- Existing System Full Uprate System Unit l Pre- Post- AP Pre- Post- AP Redispatch Redispatch Redispatch Redispatch Vermont Yankee 563MW 275MW 288MW 667MW 275MWV 392MWV Merimack #1 120MW OMW 120MW 0W OMW OMW ConEd Newington 533MW 125MWW 408MW 533MW 125MW 408MW Newington #I 411MW OMW 411MW 411MW OMW 411MW Total Redispatch 1227MNIW 1211NMWV A detailed summary for each case of the generation dispatch across New England, as well as additional interface flows and other information, are included in Appendix L One line diagrams of the Vermont and NE 345kV transmission system for each case are also included in this appendix.

All contingencies, as shown in Section 2.1.4, were then applied to the N-I power flow cases. In addition, three variations on existing contingencies were created to include insertion of the Greggs series reactor. The new contingencies are 30G (Loss of Vermont Yankee autotransformer and Greggs series reactor insertion), 34G (Vermont Yankee 379 breaker failure and Greggs series reactor insertion), and 35G (Vermont Yankee 381 breaker failure and Greggs series reactor insertion). The resulting N-2 contingency performance was evaluated against LTE ratings. Results are shown in the linked spreadsheet, n-2.xls.

A combination of N-1 and N-2 outages that leaves the Vermont Yankee generator connected only to the autotransformer and the Vermont Yankee-Vernon Road 115kV line is of particular interest. Such a combination is the Section 381 N-I outage with the stuck breaker 79-40 loss of both Sections 379 and 340 (Contingency 33). No overloads were observed on Vermont Yankee-Vernon Road 115kV line.

The majority of overloads shown in the N-2 spreadsheet were observed in the primary power flow analysis. In that analysis, no significant difference was observed between the pre- and post- full uprate cases for these overloads. Therefore, these overloads were ascribed to the system conditions represented in the study cases (generation dispatch, load level, etc), rather than the Vermont Yankee full uprate. These overloads include the following:

• WDFRD 115/46kV transformers #1 and #2

• SANDB 115-SB RCTOR 115kV line segment

• GRAND IS-S HERO 115kV line segment

• GRAND IS-PLAT T#3 115kV line segment

• SB PAR-S HERO 115kV line segment

• COLD RV 115/46kV transformer

• ASCUT 115/46kV transformer

• BLISS 115/46kV transformer 3.20 Reportl 11103.dac GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 3.20 Reportllll103doc

• BURL34-MCNEIL T 34.5kV line segment

• WILL#2-ESSEX 34.5kV line segment

• PRATTS J-LITCHTP 11 5kV line segment

• PELHAM51-G192 TAP 115kV line segment

• GH TP 45-WKFLDJ45 115kV line segment

• GH TP 46-WKFLDJ46 115kV line segment

• GLDNRKTP-W METHUN 115kV line segment

• DRACUT J-E DRCT51 115kV line segment

• DRACUT J-W METHUN 11 5kV line segment

• E DRCT5 I -TWKSJ5 115kV line segment Several other overloads identified in the primary contingency analysis were also observed in the N-2 analysis, as follows:

• WALL TAP-MT HOLLY-LUDLOW 46kV line segment

• TAFTS 46-QUECHE T 46kV line segment

• WNDSR V4 115/46kV transformer These overloads are discussed in Sections 3.5 and 3.5.1.

The SBRAT TP-NBRAT TP 69kV line segment became slightly overloaded with the Section 379 N-I outage, but before the 1200MW redispatch. After the 1200MW redispatch and the N-2 loss of Section 312 (Northfield-Alps 345kV), a slight overload was observed.

Minor overloads were observed on the GREGGS-GREGG RX 115kV line segment in response to Contingencies I and 29. The overloads observed for Contingencies 30, 34 and 35 disappear for Contingencies 30G, 34G, and 35G which include the series reactor insertion.

The FLAGG PD-PRATTSJ and FLAGG PD-LITCHTP 115kV lines show minor overloads for outages that include the Greggs reactor insertion. Overloads were also observed for local outages (Contingencies 21 and 23). These overloads are due primarily to the N-I outage. For example, the FLAGG PD- PRATTS J 115kV line flow increased by about 10% between the benchmark peak load case, tpk3, and the N-I peak load cases with Section 379 out of service. These line segments pick up significant flow because they connect to Vermont, effectively underlying the 345kV lines that constitute the N-I outages for this analysis.

A final overload was observed on the HUDSON-SCOBIE1 115kV line segment in response to the loss of Section 326. This 115kV line is part of underlying system parallel to the Scobie-Sandy Pond 345kV line (Section 326). This overload would be alleviated by operation of the Y-151 SPS. This SPS measures line current at Hudson, and opens Section Y-151 (Hudson-Dracut Junction-W Methuen-Tewksbury 115kV) if the line rating is exceeded for more than 5 seconds. This SPS was designed to operate for the loss of either Section 326 or 394 with high levels of North-South interface flow.

None of the overloads discussed above are attributable to the full uprate. Therefore, no additional system reinforcements are required by the N-2 analysis. The Vermont Yankee 3.21 RepartllllO3.doc GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 3.21 Report111103.doc

plant will be required to reduce power output at the rate of approximately 13MW/min in order to reduce output from 667MW to 275MW in 30 minutes.

3.22 RepotllllO3.doc GE-Power GE-PowerSystems Energy Consulting Systems Energy Consulting 3.22 Repor1tlffl.dbc

4. Transient Stability Analysis A transient stability analysis was performed under the assumptions described in Section

2. The results for the light load case with high levels of Maine generation, sltl, are summarized in the Excel file sltl stabresults5.xls. The results for the light load case with high levels of Newington generation, slt2, are summarized in the Excel file slt2stabresults4.xls. And, results for the peak case, spkl, are summarized in the Excel file spklstabresults4.xls. A description of the format of the results shown in the Excel files is provided in Section 4.1. Sections 4.2, 4.3, and 4.4 describe the primary stability simulation results under each of the studied system conditions. The order of the discussion corresponds to fault type groups in the spreadsheet summaries.

As shown in Section 5, there are no significant differences between the pre- and post- full uprate generator impedances. In addition, the difference between the existing turbine generator inertia (3.89 MW-sec/MVA) and the full uprate inertia (3.875 MW-sec/MVA) is small. As a result, there was no need to reevaluate the line out stability limits.

4.1 Guide to Stability Simulation Results At the top of each Excel file, and above the major column groupings, is a summary of the initial conditions. The Pre-fault Caps shows the total on-line MVArs for all Maine 345kV shunt capacitor bank, Essex shunt capacitor bank and Essex Statcom. WF Wyman #4 shows the initial power output of this unit. Interface Flows shows eleven key interface flows in the following order: NBNE (New Brunswick-New England), OrSo (Orrington South), SuSo (Surowiec South), MENH (Maine-New Hampshire), NNE (Northern New England-Scobie + 394), NS (North-South), EW (East-West), NYNE (New York-New England), SEMARI Export (Southeast Massachusetts and Rhode Island),'NWVT (Northwest Vermont), and CVT (Central Vermont).

NB Gen max is the total New Brunswick generation that might be rejected by the GCX Zone 3 or Loss of 3001 SPSs. When NB load rejection occurs, this value is used in calculation of loss of service (LOS), even when the actual amount tripped, as shown in NB Gen Rei, is less. Phase II is the initial power transfer on the Phase II HVDC tie. The output of key generators (MIS. Bucksport. Seabrook. Westbrook. Pt. Lepreau) is also shown.

The summary tables list the faults in the first set of columns, the results of the benchmark system analysis in the second set, and the results of the full uprate system in the third and final set. The individual columns in each set of results represent the details of the simulation.

For the existing system set of columns, column I indicates system response in terms of transient stability. Simulations are either stable (S) or unstable (U). Cases which result in a system separation note the location of the split. Column 2 shows the damping of the least damped mode of oscillation in this system (0.25 Hz). It is calculated as the real part of the 0.25Hz component of a measured signal. The 0.25Hz component is derived from an FFT frequency decomposition of the Seabrook machine angle signal. The third column indicates the total MW of generation tripped by a generic out-of-step tripping 4.1 ReportllllO3.doc GE-Power Systems Consulting Energy Consulting Systems Energy 4.1 Reporn111103 doc

function during the simulation. The individual machines tripped are identified in the comment box. Columns 4 through 10 show the time of a specific SPS operation. The final column shows the total loss of source (LOS) in the simulation. It is the sum of the unstable units tripped (column 3), the units tripped by SPS operation (e.g., Maine Independence Station in response to Bucksport OC SPS operation), any NB generation rejection, and any generation tripped as part of the fault.

The set of results for the Vermont full uprate presents the same information in the first 10 columns, and the final column again shows the total loss of source.

A hyperlink is provided in the Fault ID column to plots of each simulation. In all plots, the solid line represents the existing system and the dotted line represents the full uprate system. The plots show selected interface real and reactive power flows on the first two pages, and SPS variables on pages 3 and 4. Vermont Yankee generator variables are shown on page 5. The machine angles for selected NE machines are shown on pages 6 and 7, the real power output for the same units are shown on pages 8 and 9, and the reactive power output are shown on pages 10 and 11. Selected 345kV voltages across NE are shown on pages 12 and 13, selected 115kV voltages in Vermont are shown on page 14, and selected 345kV bus frequencies are shown on page 15. Variables associated with significant Vermont devices, such as the Highgate HVDC link and the Essex STATCOM, are shown on page 16. PV20 flow is also shown on this page. The apparent impedance seen by the Keswick GCX relay is shown on page 17, as well as the zone 1, 2 and 3 impedance circles. The apparent impedance seen by the Vermont Yankee KLF relay is shown on page 18, as well as the impedance circles and directional line for both the existing relay (upper circle) and the modified relay associated with the full uprate (lower circle).

Entry of the apparent impedance into the zones shown on either page 17 or 18 may indicate relay operation. However, there are additional timers associated with both relays and a voltage threshold associated with the Vermont Yankee KLF relay. The Keswick GCX relay is represented by a detailed dynamic model that incorporates all of the relevant functions and its operation is noted in the Excel summary sheets. The KLF relay was represented by a detailed dynamic model for selected simulations only. In general, its operation was inferred from entry of the apparent impedance into the zone 1 circle and operation of the generic out of step relay function.

4.2 2006 Light Load Case with High Maine Generation (sltl)

This section discusses the simulation results for the faults under 2006 light load conditions with a high level of Maine generation (sltl). Section 4.2.1 discusses the simulation results for normally cleared 1-phase or 3-phase faults and Section 4.2.2 discusses the simulation results for 3-phase stuck breaker faults.

4.2.1 Normally Cleared Faults The normally cleared 1-phase and 3-phase fault simulation results are described in this Section. A brief summary of each fault is shown in Table 4-1, which also provides hyperlinks to the plotted results.

All normal contingencies, both with and without the full uprate, were stable and met LOS and damping criteria except for the NC14 and NC15 fault scenarios. NC14 and NC15 GE-Power Systems Energy Consulting 4.2 Reportlll103doc

consist of bolted 3-phase faults at the Vermont Yankee 345kV bus with one primary protection system out of service, resulting in a fault duration of 27.5 cycles. System performance in response to these faults is unstable either with or without the full uprate.

This indicates the need for a second primary protection system, such that the loss of one system would not significantly increase fault clearing times.

Additional fault scenarios, NC14X and NC15X with 4 cycle fault clearing, were created to illustrate the performance improvement due to the addition of a second primary protection scheme. Simulation results were stable and met LOS and damping criteria for the NC 14X and NC I 5X fault scenarios, both with and without the full uprate.

In addition, no operation of the Vernon Rd 115kV undervoltage protection, Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the stable simulations.

Table 4-1. Normiially ClearedFaultResuiltsfor Ligtt Load Condition SLT1.

ID Fault Location Type Stuck Breaker Cleared Elements ncl Chestnut Hill I I5kV 30 none VY-Chestnut Hill-Vemon Rd 115kV

. Vernon Rd 115/69kV Transformer Vernon Rd 115/46kV Transformer

_ Vermont Yankee 345kV 34 none VY-Amherst 345kV nc3 Vermont Yankee 345kV 34 none VY-Northfield 345kV nc4 Vermont Yankee 345kV I 81-IT VY-Northfield 345kV VY Generator, GSU nc5 Vermont Yankee 345kV 1¢ 381 VY-Northfield 345kV VY345/115kV Autotransformer nc6 Vermont Yankee 345kV It IT VY-Coolidge 345kV WVYGenerator, GSU n_ Vermont Yankee 345kV 7940 VY-Coolidge 345kV

_I _ VY-Amherst 345kV nc8 Vermont Yankee 345kV 14 7940 VY-Amherst 345kV VY-Coolidge 345kV nc9 Vermont Yankee 345kV 1. 379 VY-Amherst 345kV VY 345/115kV Autotransformer nc 10 Vermont Yankee 345kV 10 381 VY 345/115kV Autotransformer VY-Northfield 345kV nci I Vermont Yankee 345kV 10 379 VY 345/115kV Autotransformer VY-Amherst 345kV nc12 Vermont Yankee 345kV l 81-IT VY-Northfield 345kV VY Generator, GSU ncl3 Vermont Yankee 345kV 1t IT VY-Coolidge 345kV VY Generator, GSU nc 14 Vermont Yankee 345kV 30 none VY-Coolidge 345kV North Bus VY-Northfield 345kV VY-Amherst 345kV VY Generator, GSU VY 345/1 15kV Autotransformer VY-Chestnut Hill-Vemon Rd 115kV Vernon Rd 115/69kV Transformer Vernon Rd 115/46kV Transformer nc14x Vermont Yankee 345kV 30 none VY 345/115kV Autotransformer North Bus VY-Chestnut Hill-Vemon Rd 115kV Vernon Rd 115/69kV Transformer

. Vernon Rd 115/46kV Transformer GE-Power Systems Energy Consulting 4.3 Report1111103 doc

Table 4-1. Nlormtally ClearedFaultResuiltsforLigltLoad Condeition SLTI (con tinuned).

ID Fault Location Type Stuck Breaker Cleared Elements IclS5 Vermont Yankee 34V22kV 3¢ none VY-Coolidge345kV GSU High Side VY-Northfield 345kV VY-Amherst 345kV VY Generator, GSU VY 345115kV Autotransformer nc l5x Vermont Yankee 345/22kV 3¢ none VY Generator, GSU GSU High side ____ __ __

nc 16 Northfield 345kV 30 none Northfield-Alps 345kV Berkshire 345/I 15kV Autotransformer nc 17 Northfield 345kV 30 none Northfield-Ludlow 345kV ncI Scobie 345kV 34 none Scobie-Sandy Pond 345kV Lawrence 345/34.5kV Autotransformer ncl9 Scobie 345kV l 7973 Scobie-Deerifeld 34skV Scobie-Amherst 345kV nc396 Orington 345kV 3 none Orington-Keswick 345kV Chester SVC nc312 Northfield 345kV It 3T Nortlhfield-AIps 345kV Berkshire 345/I 15kV Autotransformer VY-Northfield 345kV ny2 Edic 345kV 3¢ none Edic-New Scotland 345kV New Scotland re-close New Scotland re-open nvO2 Fraser 345kV Two 1t none Fraser-Edic 345kV

_ _____ I __Coopers Comers-Marcy 345kV nyO3 Marcy 345kV 3 1none Marcy-Massena 345kV

_I Chateauguay-Massena 345kV 4.2.2 Three-Plhase Stuck Breaker Faults The three phase stuck breaker fault simulation results are described in this Section. A brief summary of each fault is shown in Table 4-2, which also provides hyperlinks to the plotted results.

All extreme contingencies, both with and without the full uprate, were stable and met LOS and damping criteria except for the EC8 (3-phase fault on autotransformer, 381 stuck breaker at Vermont Yankee) fault with the full uprate. System response, both with and without the full uprate, to the equivalent single phase, stuck breaker faults (NC10) was stable with an acceptable LOS.

An additional fault scenario, EC8X, with faster backup fault clearing, was created to illustrate the performance improvement possible with faster relay operation. The simulation results were stable and met LOS criteria for the EC8X fault with the full uprate.

Another variation on the EC8 fault scenario, EC8IPT, with independent pole tripping (IPT) on the Vermont Yankee 381 breaker was evaluated with the original fault clearing times. The simulation results were stable and met LOS criteria with the full uprate.

The Vermont Yankee full uprate loses synchronism in response to faults EC5 (3-phase fault on Coolidge line, 79-40 stuck breaker at Vermont Yankee), EC6 (3-phase fault on Amherst line, 79-40 stuck breaker at Vermont Yankee), EC7 (3-phase fault on Amherst 4.4 RepotflhllO3.doc GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy 4.4 Report111103.doc

line, 379 stuck breaker at Vermont Yankee), and EC9 (3-phase fault on autotransformer, 379 stuck breaker at Vermont Yankee). A comparison of the apparent impedance seen by the generator with the modified KLF relay circle (lower circle) indicates that the unit wvill not be tripped by the KLF relay. Therefore, out of step protection will be required with the full uprate.

In addition, no operation of the Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the stable simulations.

The Vernon Rd 115kV undervoltage protection would operate for fault scenarios EC3, EC4, EC5, EC6, EC8, EC8X, EC9, ECll, EC19, EC326, and EC394A both with and without the full uprate.

Table 4-2. 3-PhaseStuck Breaker FaultResults for Light Load Condition SLT1.

ID Fault Location Type Stuck Breaker Cleared Elements ecl Vermont Yankee 115kV 30 N186 VY-Chestnut Ifill-Vernon Rd 115kV Vernon Rd 11 5/69kV Transformer Vernon Rd 115/46kV Transformer ec2 Vermont Yankee 345kV 30 81-IT VY-Northfield 345kV VY Generator, GSU ec3 Vermont Yankee 345kV 30 381 VY-Northfield 345kV

_ __ VY 345/115kV Autotransformer ec4 Vermont Yankee 345kV 30 IT VY-Coolidge 345kV VY Generator, GSU ec5 Vermont Yankee 345kV 3¢ 7940 VY-Coolidge 345kV VY-Amherst 345kV ec6 Vermont Yankee 345kV 3¢ 7940 VY-Amherst 345kV VY-Coolidge 345kV ec7 Vermont Yankee 345kV 3¢ 379 VY-Amherst 345kV VY 345/115kV Autotransformer ec8 Vermont Yankee 345kV 3d 381 VY 345/115kV Autotransformer

___________VY-Northrield 345kV ec8x Vermont Yankee 345k-V 3~ 381 VY 345/1 1 kV Autotransformer VY-Northfield 345kV ec8x Vermont Yankee 345kV 30110 381 VY 345111 5kV Autotransformer VY-Northfield 345kV cc9 Vermont Yankee 345kV 3'1 379 VY 345/11 5kV Autotransformer VY-Northfield 345kV eclO Vermont Yankee345kV 30 81-IT VY-Northfield345kV VY Generator, GSU cI I Vermont Yankee 345kV 30 IT VY-Coolidge 345kV VY Generator, GSU c19 Scobie 345kV 30 7973 Scobie-Deerfield 345kV Scobie-Amherst 345kV cc312 Northfield 345kV 3V/IO 3T Northfield-Berkshire 345kV Berkshire 345/111 kV Autotransformer VY-Northfield 345kV ec326 Scobie 345kV 3V/I4 9126 Scobie-Sandy Pond 345kV Lawrence 345/34.5kV Autotransformer

. Scobie-Buxton 345kV ec328 Sherman Rd 345kV 3¢/10 142 Sherman Rd-NVest Famum 345kV Sherman Rd-ANP 336 345kV ec368 Card 345kV 3¢/10 2T Card-Manchester 345kV Card-Millstone 345kV ec394a Seabrook 345kV 34/1k 294 Seabrook-Tewksbury 345kV

_Ward Hill 3451115kV Autotransformer 4.5 Report111103.doc GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 4.5 Report111103doc

4.3 2006 Light Load Case with High Newington Generation (slt2)

This section discusses the simulation results for the faults under 2006 light load conditions with a high level of Newington generation (slt2). Section 4.3.1 discusses the simulation results for normally cleared 1-phase or 3-phase faults and Section 4.3.2 discusses the simulation results for 3-phase stuck breaker faults.

4.3.1 Normally Cleared Faults The normally cleared 1-phase and 3-phase fault simulation results are described in this Section. A brief summary of each fault is shown in Table 4-3, which also provides hyperlinks to the plotted results.

All normal contingencies, both with and without the full uprate, were stable and met LOS and damping criteria except for the NC14 and NCI5 fault scenarios. NC14 and NC15 consist of bolted 3-phase faults at the Vermont Yankee 345kV bus with one primary protection system out of service, resulting in a fault duration of 27.5 cycles. System performance in response to these faults is unstable either with or without the full uprate.

As noted in Section 4.2, this indicates the need for a second primary protection system, such that the loss of one system would not significantly increase fault clearing times.

Additional fault scenarios, NC I4X and NC 15X with 4 cycle fault clearing, were created to illustrate the performance improvement due to the addition of a second primary protection scheme. Simulation results were stable and met LOS and damping criteria for the NC14X and NCI 5X fault scenarios, both with and without the full uprate.

In addition, no operation of the Vernon Rd II5kV undervoltage protection, Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the stable simulations.

Table 4-3. Norntallj ClearedFaulttResutltsforLighltLoadCondition SLT2.

ID Fault Location Type Stuck Breaker Cleared Elements nc I Chestnut Hill 11 5kV 34 none Chestnut Hill-W-Venon Rd Il SkV Vernon Rd 115/69kV Transformer Vernon Rd 115/46kV Transformer nc2 Venront Yankee 345kV 3 _ none VY-Amherst 345kV nc3 Vermont Yankee 345kV 3¢ none VY-Northfield 345kV nc4 Vermont Yankee 345kV 81-IT VY-Northfield 345kV VY Generator, GSU nc5 Vermont Yankee 345kV 14 381 VY-Northfield 345kV VY 3451115kV Autotransformer nc6 Vermont Yankee 345kV IT VY-Coolidge 345kV VY Generator, GSU nc7 Vermont Yankee 345kV 7940 VY-Coolidge 345kV VY-Amherst 345kV nc8 Vermont Yankee 345kV 14, 79-40 VY-Amherst 345kV VY-Coolidge 345kV DC9 Vermont Yankee 345kV 1A 379 VY-Amherst 345kV VY 3451151 kV Autotransformer nc 10 Vermont Yankee 345kV 1 381 VY 345/11 SkV Autotransformer VY-Northfield 345kV nc11l Vermont Yankee 345kV 10 379 VY 345/1115kV Autotransformer VY-Amherst 345kV 4.6 Report 111103.doc GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 4.6 Reporflll103 doc

Table 4-3. Normally ClearedFailtResiultsforLiglhtLoadColdition SLT2 (continued).

ID Fault Location Type Stuck Breaker Clcared Elements ncl2 Vermont Yankee 345kV 1)0 81-IT VY-Northfield 345kV VY Generator, GSU ncl3 Vermont Yankee 345kV I IT VY-Coolidge 345kV WVYGenerator, GSU ncI4 Vermont Yankee 345kV 34 none VY-Coolidge 345kV North Bus VY-Northfield 345kV VY-Amherst 345kV VY Generator, GSU VY 345/115kV Autotransformer VY-Chestnut Hill-Vemon Rd 115kV Vernon Rd 115/69kV Transformer Vernon Rd 115/46kVTransfonner ncl4x Vermont Yankee 345kV 30 none VY 345/115kV Autotransformer North Bus VY-Chestnut Hill-Vernon Rd 115kV Vernon Rd 115/69kV Transfonner Vernon Rd 115/46kV Transformer ncl 5 Vermont Yankee 345/22kV 34 none VY-Coolidge 345kV GSU High Side VY-Northfield 345kV VY-Amherst 345kV VY Generator, GSU VY 345/115kV Autotransformer ncl 5x Vernont Yankee 345/22kV 34 none VY Generator, GSU GSU High Side ncl6 Northfield 345kV 34 none Northfield-Alps 345kV Berkshire 345/115kV Autotransformer ncl7 Northfield 345kV 34 none Northfield-Ludlow 345kV ncl8 Scobie345kV 34 none Scobie-Sandy Pond 345kV oeLawrence 345/34.5kV Autotransformer nle9 fiScobie 345kV I¢ l 7973 Scobie-Deerfield 345kV Scobie-Amherst 345kV n f Orrington 345kV 34 none Orrington-Keswick 345kV Chester SVC nc312 Northfield 345kV I 3T Northfield-Alps 345kV Berkshire 345/115kV Autotransformer VY-Northfield 345kV nv01 Edic 345kV 34 none Edic-New Scotland 345kV New Scotland re-close New Scotland re-opcn nvO2 Fraser 345kV Two 10 none Fraser-Edic 345kV Coopers Comers-Marcy 345kV nvO3 Marcy 345kV 34 none Marcy-Massena 345kV Chateauguay-Massena 345kV 4.3.2 Three-Phase Stuck Breaker Faults The three phase stuck breaker fault simulation results are described in this Section. A brief summary of each fault is shown in Table 4-4, which also provides hyperlinks to the plotted results.

All extreme contingencies, both with and without the full uprate, were stable and met LOS and damping criteria except for the EC8 (3-phase, 381 stuck breaker fault at Vermont Yankee) fault with the full uprate. System response, both with and without the full uprate, to the equivalent single phase, stuck breaker faults (NC 10) is stable with an acceptable LOS.

GE-PowerSystems Energy Consulting 4.7 ReportHt1103.dbc

An additional fault scenario, EC8X with faster backup fault clearing, was created to illustrate the performance improvement possible with faster relay operation. The simulation results were stable and met LOS and damping criteria for the EC8X fault with the full uprate.

The Vermont Yankee full uprate loses synchronism in response to faults EC5 (3-phase fault on Coolidge line, 79-40 stuck breaker at Vermont Yankee), EC6 (3-phase fault on Amherst line, 79-40 stuck breaker at Vermont Yankee), EC7 (3-phase fault on Amherst line, 379 stuck breaker at Vermont Yankee), and EC9 (3-phase fault on autotransformer, 379 stuck breaker at Vermont Yankee). A comparison of the apparent impedance seen by the generator with the modified KLF relay circle (lower circle) indicates that the unit will not be tripped by the KLF relay. Therefore, out of step protection will be required with the full uprate.

In addition, no operation of the Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the stable simulations. The Vernon Rd 115kV undervoltage protection would operate for fault scenarios EC3, EC4, EC5, EC6, EC8, EC8X, EC9, EC 1I, EC19, EC326, and EC394A both with and without the full uprate.

Table 4-4. 3-PhIase Stuck Breaker FaultResultsfor Liglt Load Coldition SLT2.

ID Fault Location Type Stuck Breaker Cleared Elements ccO Vermont Yankee 115kV 30 N186 VY-Chestnut Hill-Vernon Rd 11 SkV Vernon Rd 115/69kV Transformer Vernon Rd 115146kV Transformer ec2 Vermont Yankee 345kV 30 81-IT VY-Northfield 345kV VY Generator, GSU ec3 Vermont Yankee 345kV 30 381 VY-Northfield 345kV

._ VY 345/115kV Autotransformer cc4 Vermont Yankee 345kV 30 IT VY-Coolidge 345kV VY Generator, GSU ec5 Vermont Yankee 345kV 30 7940 VY-Coolidge 345kV VY-Amherst 345kV ec6 Vermont Yankee 345kV 30 7940 VY-Amherst 345kV VY-Coolidge 345kV ec7 Vermont Yankee 345kV 30 379 VY-Amherst 345kV VY 3451115kV Autotransformer ec8 Vermont Yankee 345kV 34 381 VY 345/115kV Autotransformer VY-Northfield 345kV ec8x Vermont Yankee 345kV 34 381 VY 345/115kV Autotransformer

_ VY-Northfield 345kV ec9 Vermont Yankee 345kV 34 379 VY 345/115kV Auto VY-Amherst 345kV cd10 Vermont Yankee 345kV 31 81-IT VY-Northfield 345kV VY Generator, GSU eel I Vermont Yankee 345kV 30 IT VY-Coolidge 345kV VY Generator, GSU ec19 Scobie 345kV 3' 7973 Scobie-Deerfield 345kV Scobie-Amherst 345kV ec312 Northfield 345kV 3011/ 3T Northrield-Alps 345kV Berkshire 345/115kV Autotransformer VY-Northrield 345kV ec326 Scobie 345kV 30110 9126 Scobie-Sandy Pond 345kV Lawrence Auto 34.5kV Scobie-Buxton 345kV GEPwrSsesEeg oslig48RprllO.o GE-PowerSystems Energy Consulting 4.8 Report11103 arc

Table 4-4. 3-PhiaseStutck Breaker FaultResultsfor Ligtt Load Conditiol SLT2 (confintued).

ID Fault Location Type Stuck Breaker Cleared Elements ec328 Sherman Rd 345kV 311¢ 142 Sherman Rd-West Famum 345kV

__ Sherman Rd-ANP 336 345kV ec368 Card 345kV 34!110 2T Card-Manchester 345kV

_ _ _Card-Millstone 345kV eM394a Seabrook 345kV 300 294 Seabrook-Tewksbury 345kV

. _Ward Hill 345/115kV Autotransfomner 4.4 2006 Summer Peak Load Case (spkl)

This section discusses the simulation results for the faults under 2006 summer peak load condition. Section 4.4.1 discusses the simulation results for normally cleared 1-phase or 3-phase faults and Section 4.4.2 discusses the simulation results for 3-phase stuck breaker faults.

4.4.1 Normally Cleared Faults The normally cleared 1-phase and 3-phase fault simulation results are described in this Section. A brief summary of each fault is shown in Table 4-5, which also provides hyperlinks to the plotted results.

All normal contingencies, both with and without the full uprate, were stable and met LOS and damping criteria except for the NC14 and NC15 fault scenarios. NC14 and NC15 consist of bolted 3-phase faults at the Vermont Yankee 345kV bus with one primary protection system out of service, resulting in a fault duration of 27.5 cycles. System performance in response to these faults is unstable either with or without the full uprate.

As before, this indicates the need for a second primary protection system, such that the loss of one system would not significantly increase fault clearing times.

Additional fault scenarios, NC14X and NC15X with 4 cycle fault clearing, were created to illustrate the performance improvement due to the addition of a second primary protection scheme. Simulation results were stable and met LOS and damping criteria for the NCI4X and NC15X fault scenarios, both with and without the full uprate.

In addition, no operation of the Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the stable simulations.

The Vernon Rd 115kV undervoltage protection would operate for fault scenarios NC5, NC9, NCI0, NCI 1, and NC14X both with and without the full uprate.

Table 4-5. Norm ally ClearedFaultRestultsfor Peak Load Colditiol SPKI.

ID Fault Location Type Stuck Breaker Cleared Elements ncl Chestnut Hill 115kV 34 none Chestnut Hill-Y-Vemon Rd 115kV Vernon Rd 115/69kV Transformer Vernon Rd 115/46kV Transformer c2 Vermont Yankee 345kV 34 none VY-Amherst 345kV nc3 Vermont Yankee 345kV 30 none VY-Northfield 345kV nc4 Vermont Yankee 345kV 10 81-IT VY-Northfield 345kV V Generator, GSU GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 4.9 RepcflhlllO3.doe 4.9 ReportI1 103 doc

Table 4-5. Normally ClearedFault Resultsfor Peak Load Condition SPKI (continued).

ID Fault Location Type Shick Breaker Cleared Elements nc5 Vermont Yankee 345kV 1i 381 VY-Northfield 345kV VY 345/11 5kV Autotransformer nc6 Vermont Yankee 345kV I IT VY-Coolidge 345kV VY Generator, GSU nc7 Vermont Yankee 345kV 10 79-40 VY-Coolidge 345kV VY-Amherst 345kV nc8 Vermont Yankee 345kV I1 79-40 VY-Amherst 345kV VY-Coolidge 345kV nc9 Vermont Yankee 345kV 10 379 VY-Amherst 345kV VY 345/11 5kV Autotransfomner nclO Vermont Yankee 345kV 1I 381 VY 345/115kV Autotransformer VY-Northfield 345kV ncl I Vermont Yankee 345kV I 379 VY 345/115kV Autotransformer VY-Amherst 345kV ncl2 Vermont Yankee 345kV I0 81-IT VY-Northfield 345kV VY Generator, GSU nc13 Vernont Yankee 345kV I IT VY-Coolidge 345kV VY Generator, GSU ncl4 Vermont Yankee 345kV 30 none VY-Coolidge 345kV North Bus VY-Northfield 345kV VY-Amherst 345kV VY Generator, GSU VY 345/115kV Autotransformer VY-Chestnut Hlill-Vemon Rd I15kV Vernon Rd 115/69kV Transfonmer

. Vernon Rd 115/46kV Tmnsformer ncl4x Vermont Yankee345kV 30 none VY 345/115kV Autotransforner North Bus VY-Chestnut llill-Vemon Rd 115kV Vernon Rd 115/69kV Tmnsformer Vernon Rd 115146kVTransformer ncl1 Vermont Yankee 3p none VY-Coolidge 345kV 345/22kV GSU High Side VY-Northfield 345kV VY-Arnherst 345kV VY Generator VY 345/115kV Autotransformer nc 15x Vermont Yankee 30 none VY Generator, GSU 345/22kV GSU High Side nc!6 Northfield 345kV 30 none Northfield-Alps 345kV Berkshire 345/115kV Autotransformer ncl 7 Northfield 345kV 3+ none Northfield-Ludlow 345kV ncl 8 Scobie 345kV 3¢ none Scobie-Sandy Pond 345kV Lawrence 345/34.5kV Autotransformer nc 19 Scobie 345kV I0 7973 Scobie-Deerfield 345kV Scobie-Amherst 345kV nc396 Orrington 345kV 3+ none Orrington-Keswick345kV Chester SVC nc312 Northfield 345kV 1i 3T Northfield-Alps 345kV Berkshire 345/1 15kV Autotransformer VY-Northfield 345kV

__ _ Trip Phase 11HVDC NA none NA nvo0 , Edic 345kV 30 none Edic-New Scotland 345kV New Scotland re-close New Scotland re-open M02 Fraser 345kV Two I ¢ none Fraser-Edic 345kV Coopers Corners-Marcy 345kV nvO3 Marcy 345kV 30 none Marcy-Massena 345kV

. Chateauguay-Massena 345kV GE-Power Systems Energy Consulting 4.10 ReportI11103.69c

4.4.2 Three-Phase Stuck Breaker Faults The three phase stuck breaker fault simulation results are described in this Section. A brief summary of each fault is shown in Table 4-6, which also provides hyperlinks to the plotted results.

All extreme contingencies, both with and without the full uprate, were stable and met LOS and damping criteria. In addition, no operation of the Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the simulations.

The Vermont Yankee full uprate loses synchronism in response to faults EC8 (3-phase fault on autotransformer, 381 stuck breaker at Vermont Yankee) and EC9 (3-phase fault on autotransformer, 379 stuck breaker at Vermont Yankee). A comparison of the apparent impedance seen by the generator with the modified KLF relay circle (lower circle) indicates that the unit will not be tripped by the KLF relay. Therefore, out of step protection will be required with the full uprate.

The Vernon Rd 115kV undervoltage protection would operate for fault scenarios EC3, EC5, EC6, EC7, EC8, and EC9 both with and without the full uprate.

Table 4-6. 3-Phase Stuck Breaker FaultResults for Peak Load Conzdition,SPKI.

ID Fault Location Type Stuck Breaker Clcared Elements ec] Vermont Yankee 115kV 30 N186 VY-Chestnut Hill-Vernon Rd I15kV Vernon Rd 115/69kV Transformer Vernon Rd 115/46kV Transfonner ec2 Vermont Yankee 345kV 34 81-IT VY-Northfield 345kV VY Generator, GSU ec3 Vermont Yankee 345kV 34 381 VY-Northfield 345kV VY 345/1115kV Autotransformer ec4 Vermont Yankee 345kV 34 IT VY-Coolidge 345kV VY Generator, GSU e5 Vermont Yankee 345kV 34 79-40 VY-Coolidge 345kV

_ _ _ _ _ _ __ VY-Amherst 345kV ec6 Vermont Yankee 345kV 34 7940 VY-Amherst 345kV VY-Coolidge 345kV ec7 Vermont Yankee 345kV 30 379 VY-Arnherst 345kV VY 345/1115kV Autotransformer ec8 Vermont Yankee 345kV 34) 381 VY 3451115kV Autotransformer

_ VY-Northfield 345kV ec9 Vermont Yankee 345kV 34 379 VY 345/11 SkV Autotransformer VY-Northfield 345kV ecO Vermont Yankee 345kV 30 81-IT VY-Northfield 345kV VY Generator, GSU el IVermont Yankee 345kV 30 IT VY-Coolidge 345kV VY Generator, GSU ee 19 Scobie 345kV 34 7973 Scobie-Deerfield 345kV Scobie-Amherst 345kV ec312 Northfield 345kV 34)1 3T Northfield-Berkshire 345kV Berkshire 345/11 SkV Autotransformer VY-Alps 345kV ec326 Scobie345kV 3 l4 9126 Scobie-Sandy Pond 345kV Lawrence 345/34.5kV Autotransformer

. _ _. Scobie-Buxton 345kV ec328 Sherman Rd 345kV 30!1¢4 142 Sherman Rd-WVest Farnum 345kV Sherman Rd-ANP 336 345kV 4.11 RepoftllllO3.c*2c Systems Energy GE-Power Systems GE-Power Consulting Energy Consulting 4.11 Reportt11103.doc

Table 4-6. 3-PhaseStuck BreakerFault Resultsfor Peak Load Condition SPKI (continuled).

ID Fault Location Type Stuck Breaker Cleared Elements ec368 Card 345kV 3¢/11¢ 2T Card-Manchester 345kV

. __ _ _Card-Millstone 345kV ec394a Seabrook 345kV 30/1¢ 294 Seabrook-Tewksbury 345kV

___,__ _ __ _ Ward Hill 345/115kV Autotmnsforner 4.5 2006 Summer Peak Load Sensitivity Analysis (spk4, spk5)

A sensitivity analysis was performed to test system performance, both with and without the full uprate, at high levels of New England East-West interface flow. The impact of Northfield generation levels was also tested. Results for the peak case with all Northfield units in service and a high East-West interface flow, spk4, are summarized in the Excel file spk4stabresults4.xls. Results for the peak case with all Northfield units out of service and a high East-West flow, spk5, are summarized in the Excel file spk5stabresults4.xls.

A brief summary of each fault for the all Northfield in case, spk4, is shown in Table 4-7, which also provides hyperlinks to the plotted results. Similarly, a brief summary of each fault for the all Northfield out case, spk5, is shown in Table 4-8, which also provides hyperlinks to the plotted results.

All contingencies, both with and without the full uprate, were stable and met LOS and damping criteria. The Vermont Yankee unit loses synchronism, under both peak sensitivity full uprate conditions, in response to the two extreme contingencies evaluated.

In particular, the Vermnont Yankee full uprate loses synchronism in response to faults EC8 (3-phase fault on autotransformer, 381 stuck breaker at Vermont Yankee) and EC9 (3-phase fault on autotransformer, 379 stuck breaker at Vermont Yankee). A comparison of the apparent impedance seen by the generator with the modified KLF relay circle (lower circle) indicates that the unit will not be tripped by the KLF relay. Therefore, out of step protection will be required with the full uprate.

In addition, no operation of the Vermont Yankee RPS MG set underfrequency protection, Bear Swamp and Northfield underfrequency protection, or the Sand Bar OMS was observed for any of the simulations.

The Vernon Rd ISkV undervoltage protection would operate for fault scenarios NCIO, EC8 and EC9, both with and without the full uprate.

Table4-7. Senisith'ityiResuiltsforPeakLoadContditionSPK4.

ID Fault Location Type Stuck Breaker Cleared Elements nc10 Vermont Yankee 345kV 1¢ 381 VY 345/115kV Autotransformer VY-Northfield 345kV ec8 Vermont Yankee 345kV 3, 381 VY 345/115kV Autotransformer VY-Northfield 345kV ec9 Vermont Yankee 345kV 3t 379 VY 345/115kV Autotransformer

_ _ I_ VY-Northfield 345kV GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 4.12 ReportllllO3.doc 4.12 Reportt11103 doc

Table 4-8. Sensitivit, Resultsfor Peak Load Condition SPK5.

ID Fault Location Type fStuck Breaker Cleared Eleiments nc 10 Vennont Yankee 345kV I0 F381 VY 3451115kV Autotransformer

_ VY-Northfield 345kV cv8 Vermont Yankee 345kV 30 381 VY 345/115kV Autotransformer VY-Northfield 345kV cC9 Vermont Yankee 345kV 3l 379 VY 3451115kV Autotransformer

____ _ _ _VY-Northfield 345kV 4.6 AP Analysis Results AP is the sudden change in generator power output resulting from line switching; it is measured in per unit of the machine MVA rating. A AP analysis was performed on the light load case with high levels of Newington generation, because the highest levels of line flow near the Vermont Yankee plant were observed under this condition. The intent was to calculate the highest AP under relatively stressed conditions, but within the existing transfer capability of the system. Stability simulations of line trip and reclose events were performed for each of the 345kV lines connected to Vermont Yankee. None of the lines are equipped with automatic high speed reclosing, so the reclose event occurred 10 seconds after the trip. No faults were associated with any of the line trip and reclose events.

The APs observed on the Vermont Yankee unit with all lines in service, both with and without the full uprate, are shown in Table 4-9. Values are shown in both MW and pu of machine MVA base.

Table 4-9. APforLightLoad Condlitions (slt2) with AllLiizesI f-Selrtice.

[ Existing I Uprate l AP Cause AW Pu MW Pu (on 626N1VA) (on 684NMVA)

Trip Section 340 (Vermont Yank-ee-Coolidge 345kV) 9 0.014 5 0.007 Reclose Section 340 (Vermont Yankee-Coolidge 345kV) -11 -0.018 -6 -0.009 Trip Section 379 (Vermont Yankee-Amherst 345kV) 83 0.13 79 0.12 Reclose Section 379 (Vermont Yankee-Amherst 345kV) -113 -0.18 -109 -0.16 Trip Section 381 (Vermont Yank-ee-Northfield 345kV) -220 -0.35 -220 -0.32 Reclose Section 381 (Vermont Yankee-Northfield 345kV) 259 0.41 249 0.36 An additional AP analysis under line out conditions was also performed. Power flows were developed with either Section 394 (Seabrook-Tewksbury 345kV) or Section 302 (Millbury-Ludlow 345kV) out of service for the light load study conditions. The line-out power flows were solved with all SVDs, LTCs, and PARs active. No system redispatch was implemented, because all line flows were less than the LTE rating. The sole exception was the Vermont Yankee-Northfield 345kV line, which is almost always overloaded because of the relay limited 896MVA rating.

With Section 302 out of service and no system redispatch, the trip of Section 381 caused Vermont Yankee to lose synchronism with the system, both with and without the full uprate. Therefore, a redispatch of the system was performed for only this combination of werSysems nery nsuling4.1 GE-P C Repit1110.do GE-PowerSystems Energy Consulting 4.13 Report111103.dc

events. Two Northfield pumping units were removed, as well as a corresponding amount of generation at Brayton Point. This left one Northfield unit on.

The changes in power observed on the Vermont Yankee unit with either Section 394 or 302 out of service, both with and without the full uprate, are shown in Table 4-10.

Values are shown in both MW and pu of machine MVA base.

Table 4-10. APfor Light Load Conditions (slt2) s'ithl One Line Out of Service.

Existing Uprate AP Cause I AM puu AM pu

_ (on 626N1VA) (on 684N1VA)

Section 394 Out:

Trip Section 379 (Vermont Yankee-Amherst 345kV) 98 0.16 93 0.14 Reclose Section 379 (Vermont Yankee-Amherst 345kV) -135 -0.22 -131 -0.19 Trip Section 381 (Vermont Yankee-Northfield 345kV) -239 -0.38 -239 -0.35 Reclose Section 381 (Vermont Yankee-Northfield 345kV) 284 0.45 267 0.39 Section 302 Out:

Trip Section 379 (Vermont Yankee-Amherst 345kV) 112 0.18 107 0.16 Reclose Section 379 (Vermont Yankee-Amherst 345kV) -173 -0.28 -168 -0.25 Trip Section 381 (Vermont Yankee-Northfield 345kV)* -228 -0.36 -227 -0.33 Reclose Section 381 (Vermont Yankee-Northfield 345kV)* 275 0.44 261 0.38

• Redispatched after 302 outage The highest AP observed for the full uprate with all lines in service was 0.36pu in response to reclosing Section 381 (Vermont Yankee-Northfield 345kV). The highest AP observed for the full uprate with a line out of service was 0.39pu in response to reclosing Section 381 (Vermont Yankee-Northfield 345kV) with Section 394 (Seabrook-Tewksbury 345kV) out.

4.7 Vermont Yankee Exciter Modeling Historically, the Vermont Yankee exciter was represented by an ieeetl model in ISO-NE databases. As part of this study, the model was changed to the more representative exac3a model (shown in Appendices D and F). At the end of this study, the exac3a model parameters were changed to reflect the latest available information on the exciter design. Both the ieeeti model parameters and the latest exac3a model parameters are shown in Appendix J. The changes in exac3a model parameters between those studied and the latest information are highlighted in the appendix. Note that there will be no exciter change due to the full uprate. The transmittal documentation from Entergy to ISO-NE is contained in Appendix K.

A sensitivity analysis of the impact of the three exciter models on system behavior was performed. Five fault scenarios, which exhibited the most oscillatory performance, were selected for analysis under the most severe light load conditions (sltl) for the full uprate.

A brief summary of each fault is shown in Table 4-11, which also provides hyperlinks to the plotted results. In all plots, the solid line represents the exac3a model with the latest parameters, the dotted line represents the exac3a model with the parameters used in this study, and the dashed line represents the ieeetl model as traditionally used.

4.14 RepcflhlllO3.dac GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 4.14 Report111103.doc

No significant difference was observed in system performance for any of the studied faults.

Table 4-11. Ieriuiont Ytarkee ExciterAodel Sensitivity Resullts ni: der SLTI Con ditio,,s.

ID Fault Location Type StucklBreaker Cleared Elements nc3 Vermont Yankee 345kV 3t none VY-Northfield 345kV nc5 Vermont Yankee 345kV I 1 381 VY-Northfield 345kV VY 345/115kV Autotransformer ncM1 Vermont Yankee 345kV I1 381 VY 345/115kV Autotransformer VY-Northfield 345kV ec3 Vermont Yankee 345kV 34 381 VY-Northfield 345kV W 345/11 SkV Autotransformer cc8x Vermont Yankee 345kV 34 381 VY 345/115kV Autotransformer

. . VY-Northfield 345kV 4.8 Out of Step Protection The results discussed in Sections 4.2 through 4.5 indicate the need for out of step protection on the full uprate Vermont Yankee generator. This additional protection was required because several faults resulted in operation of the generic out of step relay function, which tripped the Vermont Yankee unit. Therefore, system performance with the out of step protection explicitly modeled was evaluated for these full uprate cases.

Preliminary out of step relay parameters were provided by Entergy and an out of step relay model, ooslen, was developed with the parameters shown in Appendix L.

A brief summary of each case is shown in Table 4-12, which also provides hyperlinks to the plotted results. In all plots, the solid line represents system performance with the individual out of step protection and the latest exciter parameters (Appendix J). The dotted line represents system performance with the generic out of step tripping function and the exciter model used in the bulk of the analysis (Appendices D and F).

All extreme contingencies from Table 4-12 resulting in operation of the out of step protection were stable and met LOS and damping criteria. In all cases, the explicit out of step protection operated faster than the generic function.

Two extreme contingencies, EC6 (3-phase fault on Amherst line, 79-40 stuck breaker at Vermont Yankee) and EC7 (3-phase fault on Amherst line, 379 stuck breaker at Vermont Yankee), showed a reduced LOS with the explicit protection model under sltl light load conditions. The difference was the NB generation rejection due to GCX relay operation in the cases with the generic protection function. All other extreme contingencies summarized in Table 4-12 showed no difference in LOS.

Cnsutin GE-PwerSysemsEnery 4.1 Reot1110.do GE-PowerSystems Energy Consulting 4.15 Report111103.doc

Table 4-12. Jermolot Yilaikee Out of Step ProtectionResults for Cases with Operation of Generic Function in Primaryi Analysis.

ID Fault Location Type IStuck ]Cleared Elements l Generic OOS Relay

_ l Breaker l l Trip Time Trip Time sitI: light load conditions with high levels of Maine generation ec5 Vermont Yankee 345kV 34 79-40 VY-Coolidge 345kV 0.8 sec 0.48 sec VY-Amherst 345kV ec6 Vermont Yankee 345kV 34 7940 VY-Amherst 345kV 0.8 see 0.48 sec VY-Coolidge 345kV cc7 Vermont Yankee 345kV 3¢, 379 VY-Amherst 345kV 0.8 sec 0.48 sec VY 345/115kV Autotransformer ec9 Vermont Yankee 345kV 34 379 VY 345/115kV Auto 0.7 see 0.48 sec VY-Amherst 345kV slt2: light load conditions with high levels of New Hampshire generation eC5 Vermont Yankee 345kV 30 7940 VY-Coolidge 345kV 0.7 see 0.48 see VY-Amherst 345kV ec6 Vermont Yankee 345kV 34 7940 VY-Amherst 345kV 0.7 sec 0.48 see VY-Coolidge 345kV ec7 Vermont Yankee 345kV 34 379 VY-Amherst 345kV 0.8 sec 0.48 see VY 345/115kV Autotransfonmer ec9 Vermont Yankee 345kV 34 379 VY 345/115kV Auto 0.7 sec 0.48 sec VY-Amherst 345kV spkl: peak load conditions ec8 Vermont Yankee 345kV 34 381 VY 345/115kV Autotransformer I.Isec 0.48 see VY-Northfield 345kV c9 Vermont Yankee 345kV 34 379 VY 345/115kV Auto 1.0 sec 0.48 see VY-Amherst 345kV spk4: peak load conditions with high E-W flows and all Northfield units in service ec8 Vennont Yankee345kV 34) 381 VY 345/115kV Autotransfonner 0.9 sec A.48sec VY-Northfield 345kV ec9 Vermont Yankee 345kV 30 379 VY 345/115kV Auto 0.8 sc .48 see l _VY-Amherst 345kV spk5: peak load conditions with high E-W flows and no Northfield units in service ec8 Vermont Yankee 345kV 34 381 VY 345/115kV Autotransformer 0.9 sec 0.48 sec VY-Northfield 345kV ec9 Vermont Yankee 345kV 30 379 VY 345/115kV Auto 0.8 see 0.48 see VY-Amherst 345kV l The apparent impedance as seen from the Vermont Yankee generator was plotted for all cases described in Section 4. A comparison of these apparent impedances with the out of step relay protection characteristic indicated that the out of step protection could possibly operate for other cases, beyond those evaluated and summarized in Table 4-12.

Additional analysis confirmed operation of the out of step protection for several additional extreme contingencies. These results are summarized in Table 4-13. Again, hyperlinks are provided to the plotted results.

Most extreme contingencies summarized in Table 4-13 showed an increased LOS with the explicit out of step protection scheme because the Vermont Yankee unit was not tripped by the generic function in the primary analysis. All still met LOS criteria, except for the EC8X contingency (3-phase fault on autotransformer, 381 stuck breaker at Vermont Yankee with faster clearing times) under sltl light load conditions. Additional tests showed that a maximum backup clearing time of 8.0 cycles at both Vermont Yankee and Northfield was required to meet LOS criteria (EC8Y). However, LOS criteria was met for the EC8 contingency assuming IPT operation of the Vermont Yankee 381 breaker under sltl light load conditions.

GE-Power Energy Consulting Systems Energy GE-PowerSystems Consulting 4.16 ReportllllO3.doc 4.16 Report111103.doc

One contingency, EC3 (3-phase fault on Northfield line, 381 stuck breaker at Vermont Yankee), showed an increased LOS with the explicit protection model under slt2 light load conditions due to operation of the zone 2 protection on Section 396 (Keswick-Orrington 345kV).

One contingency, EC8 (3-phase fault on autotransformer, 381 stuck breaker at Vermont Yankee), showed a reduced LOS with the explicit out of step relay model under slt2 light load conditions. This indicates that fast tripping of the Vermont Yankee unit may be beneficial to system performance under some conditions.

No normal contingencies resulted in operation of the out of step protection.

The results shown in Tables 4-12 and 4-13 indicate that the preliminary out of step protection scheme will trip the Vermont Yankee unit when desired and result in acceptable system performance. These results also indicate that the required clearing times for EC8 may be too fast to implement, and that IPT breaker operation would be a preferred solution.

Table 4-13. Vermn01 out Yanikee Oit of Step ProtectionResultsfor Additionial Cases w'ithout Operation of GeniericFunction in PrimaryAnalysis.

ID Fault Location Type Stuck 1Clearcd Elements l Generic l OOS Relay Breaker Trip Time Trip Time sit l: light load conditions with high lcvels of Maine generation cc3 Vermont Yankee 345kV 34 381 VY-Northfield 345kV NA 0.74 see VY 345/115kV Autotransformer cc8x Vermont Yankee 345kV 34 381 VY 34511 15kV Autotransformer NA 0.75 sec VY-Northfield 345kV cc~v Vermont Yankee 345kV 30 381 VY 3451115kV Autotransformer Not Run 0.79 sec VY-Northrield 345kV ee8int Vermont Yankee 345kV 34)114) 381 VY 3451115kV Autotransformer NA NA VY-Northfield 345kV slt2: light load conditions with high levels of New Hampshire generation cc3 Vermont Yankee 345kV 3¢ 381 VY-No4h/ield 345kV A oNA 0.74 se VY 345t115kV Autotransfor0er s ecS Vermont Yankee 345kV spkl: peak load conditions 34 381 VY345/115kVAutotransfonmer VY-Northfield 345kV j 1.0 see 0.73 sec ec3 Vermont Yankee 345kV 30 381 VY-Northfield 345kV NA 0.48 sec VY 345/115kV Autotransformer ec5 Vermont Yankee 345kV 30 79-40 VY-Coolidge 345kV NA 0.48 see VY-Amherst 345kV ec6 Vermont Yankee 345kV 34 7940 VY-Amherst 345kV NA 0.48 see VY-Coolidge 345kV ec7 Vermont Yankee 345kV 30 379 VY-Amherst 345kV NA 0.48 sec VY 345/115kV Autotransformer GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 4.17 Repo4llllO3.doc 4.17 Reports11103.doc

4.9 Amherst Project Sensitivity Due to recent changes in the Amherst project, a sensitivity analysis was performed to determine whether those changes would have any impact on the Vermont Yankee full uprate project. The Amherst substation is currently tapped off of the 379 Line (Scobie Pond-Vermont Yankee 345kV ). The Amherst project will include the addition of a second 140 MVA, 345/34.5kV two-winding distribution transformer and a 345kV four circuit breaker ring bus to the Amherst Substation. The new Amherst 345 kV circuit breakers will be installed with independent pole trip (IPT) capability. The estimated in-service date is December 2003. The system impact study for the Amherst 345kV substation reconfiguration determined that the clearing times for faults on the Scobie-Amherst 345kV line should be increased by 0.5 cycles. Therefore, an evaluation of the impact of this change on the performance of the study system with the Vermont Yankee full uprate was performed. Both fault scenarios involving the Scobie-Amherst 345kV line were re-evaluated under the most severe sitI light load conditions with the full uprate.

A brief summary of each case is shown in Table 4-14, which also provides hyperlinks to the plotted results. In all plots, the solid line represents system performance with the longer clearing times, individual out of step protection and the latest exciter parameters (Appendix J). The dotted line represents system performance with the original clearing times, generic out of step tripping function, and the exciter model used in the bulk of the analysis (Appendices D and F).

The difference between system performance with and without the longer clearing time at Amherst was not significant. All results were stable and met both LOS and damping criteria.

Table 4-14. Impact of IncreasedClearing Thnes (+0.5 cycles) atAmnherst.

ID I Fault Location Type Stuck Breaker Cleared Elements ncl9x Scobie 345kV 7973 Scobie-Defiedd 345kV Scobie-Amherst 345kV ccl 9x Scobie 345kV 3 I 7973 Scobie-Deerfield 345kV Scobie-Amherst 345kV GE-Power Systems Energy Consulting 4.18 Report 1 103.doc

5. Short Circuit Analysis A comparison of selected machine parameters pre and post- full uprate is shown in Table 5-1. All reactances are shown on the 626MVA base of the existing unit. The difference between the reactances are insignificant. The key data for a short circuit study is the direct axis subtransient reactance, which is 0.225pu pre and post- full uprate. Therefore, no short circuit analysis was deemed necessary. Complete dynamic model data for the existing unit is shown in Appendix D; complete dynamic model data for the full uprate unit is shown in Appendix F.

Table 5-1. A Comparisonof Vermont Yankee GeneratorReactances with and with out the Uprate.

Parameter Description Existing Full Uprate (on 626MIVA) (on 626M VA)

Ld d-axis synchronous reactance (pu) 1.810 1.814 L'd d-axis transient reactance (pu) 0.345 0.350 L"d d-axis subtransient reactance (pu) 0.225 0.225 Lq q-axis synchronous reactance (pu) 1.750 1.747 L'q q-axis transient reactance (pu) 0.570 0.558 L"q q-axis subtransient reactance (pu) 0.225 0.225 LI Stator leakage reactance (pu) 0.190 0.191 GE-Power Systems Energy Consulting 5.1 ReporH11103.doc

6. Conclusions and Recommendations Entergy is requesting approval for an uprate of the Vermont Yankee nuclear plant. The purpose of this study was to analyze the impact of this uprate on the interconnected New England system in accordance with the "NEPOOL Reliability Standards" and the NEPOOL "Minimum Interconnection Standard", and to identify any necessary facility upgrades to meet these standards under the NEPOOL Subordinate 18.4 Application Policy. Relevant queued resources for this project include the Berwick Energy Center, UAE Tewksbury, Neptune Phase 3 Boston Import, Neptune Phase 7 Wyman Export, Mystic 4,5, 6 conversion, and Millstone #3 uprate projects. Vermont Yankee is subordinate to all of these.

For this study, the existing Vermont Yankee unit was represented with a rating of 626MVA, a power output rating of 563MW, and a gross reactive power output rating of 150MVAr at rated power output. The proposed full uprate project will result in a Vermont Yankee unit with a rating of 684MVA, a power output rating of 667MW, and a gross reactive power output rating of 150MVAr at rated power output. There is no expected change to the station service or cooling tower loads, which are 25.5MW, 13.5MVar and 8.5MW, 5.7MVAr, respectively. Therefore, the net rating of the full uprate, as evaluated in this study with all station service and cooling loads in service under peak load conditions, was 633MW.

For the stability analysis, the Vermont Yankee exciter was modeled, both pre- and post-full uprate, with an exac3a model representing an IEEE type AC3A excitation system.

This is the manufacturer recommended model and replaced the ieeetl model used in prior studies. Therefore, this study also supports the exciter model change.

Power flow and stability analyses were performed, including a voltage and thermal N-1 contingency analysis, a thermal N-2 contingency analysis, a transient stability analysis, and a AP analysis.

No short circuit analysis was performed because there was no significant change to the generator impedances, as described in Section 5.

6.1 Power Flow Analysis The power flow analysis indicated that the following upgrades will be required as part of the Vermont Yankee full uprate project:

1. Increase the pre-contingency MVA rating on the Vermont Yankee-Northfield 345kV line (Section 381) from the current rating of 896MVA to a minimum rating of 1075MVA by replacing the limiting line relay equipment.

2. Increase the post-contingency MVA rating on the Ascutney-Coolidge 11 5kV line from the current LTE rating of 205MVA to 240MVA by replacing approximately 25 feet of the limiting riser conductor.

6.1 Repot1111O3.doc GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting 6.1 Report11 tl103doc

3. Ensure that the Vermont Yankee 345kV pre-contingency bus voltage is not degraded as a result of the full uprate project by the addition of 60MVAr of shunt capacitors at the Vermont Yankee 115kV bus (Section 3.2). One bank of 30MVAr and two banks of 15MVAr are proposed. The 30MVAr bank should be connected such that is trips with the autotransformer. The 15MVAr banks should be connected to the 115kV bus such that they are available with the autotransformer out of service.

The study identified the Vermont Yankee-Northfield 345kV line relay replacement as a reliability upgrade required to mitigate preexisting conditions. It was not prompted by the Vermont Yankee full uprate, however it is required for the full uprate. The Ascutney-Coolidge 11 5kV line upgrade and Vermont Yankee 11 kV shunt capacitors are upgrades associated with the full uprate project itself. The Vermont Yankee area voltage performance was significantly better with the full uprate and its associated capacitor banks than with the existing system. In addition, Entergy has verified that there is sufficient room for the capacitor banks and any associated equipment.

Overloads were also observed, both with and without the full uprate, on the Wallingford Tap-Mt Holly-Ludlow 46kV line segment under peak load conditions in response to the Ascutney-Coolidge 115kV line outage. This is a pre-existing problem that is adversely impacted by the full uprate. Currently, there is no proposed mitigation for this problem.

The full uprate is not responsible for any additional mitigation.

The N-2 power flow analysis, as described in Section 3.6, showed the need for no additional system reinforcements due to the full uprate. The Vermont Yankee plant will be required to reduce power output at the rate of approximately 13MW/min in order to reduce output from 667MW to 275MW in 30 minutes. Entergy has confirmed that this ramp rate can be safely achieved.

While the bulk of the power flow analysis focused on system performance with the full uprate, Entergy requested a sensitivity analysis of the impact of the first phase uprate (630MW, 220MVAr) on the pre-contingency Vermont Yankee 345kV bus voltage. The evaluation focused on the most limiting Vermont generation dispatch scenario under 2006 extreme weather peak load conditions. The pre-uprate Vermont Yankee 345kV bus voltage was 1.024pu. For the first phase uprate, 1.024pu on the Vermont Yankee 345kV bus was achieved with an output of 194MVAr from the unit, which is within the 220MVAr capability. This analysis showed that the 345kV bus voltage could be maintained at pre-uprate levels after the first phase uprate without the 115kV capacitor banks required for the full uprate.

6.2 Transient Stability The results of the stability analysis are described in Section 4 and show that the following upgrades will be required as part of the Vermont Yankee full uprate project:

1. Modification to provide a second primary protection scheme on the Vermont Yankee north bus to achieve acceptable performance in response to the normal contingency fault NC 14.

6.2 RepaflhlllO3.dac GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy 6.2 Reporn111103.doc

2. Addition to provide a second primary protection scheme on the Vermont Yankee GSU to achieve acceptable performance in response to the normal contingency fault NC15.

3. Independent pole tripping on the Vermont Yankee 381 breaker is required to achieve acceptable performance in response to the extreme contingency fault EC8.

4. Addition of out of step protection on the Vermont Yankee generator to ensure acceptable performance in response to several extreme contingencies.

The study identified the second primary protection schemes as reliability upgrades required to mitigate preexisting conditions. It was not prompted by the Vermont Yankee full uprate, however it is required for the full uprate. The IPT breaker operation and the out of step protection are upgrades associated with the full uprate project itself. Whether breaker 381 upgrade or replacement is required to achieve IPT capability will be determined by the facilities study.

AP is the sudden change in generator power output resulting from line switching; it is measured in per unit of the machine MVA rating. AP levels that could be imposed on the Vermont Yankee generator were calculated under relatively stressed transmission system loading conditions that would result in relatively high AP values. The highest level observed for the full uprate with all lines in service was 0.36pu in response to reclosing Section 381 (Vermont Yankee-Northfield 345kV). The highest AP observed for the full uprate with a line out of service was 0.39pu in response to reclosing Section 381 (Vermont Yankee-Northfield 345kV) with Section 394 (Seabrook-Tewksbury 345kV) out. The Vermont Yankee project has the option to mitigate the AP levels if it deems such action necessary.

After the full uprate, the Vermont Yankee plant operators will continue to be required to reduce plant output to 275MW within 30 minutes of being instructed to do so by the System Operator immediately following the occurrence of certain single line outages.

This requirement enables the System Operator to return the system to a secure operating state within 30 minutes of a continuous outage of a single transmission line or facility in accordance with established operating criteria.

GE-Power Systems Energy GE-Power Systems Consulting Energy Consulting 6.3 6.3 RepodllllO3.dac RepW1t11103.doc

Appendix A. Benchmark Power Flow Summaries and Diagrams for Power Flow Analysis Casc Brief Description Vermont New England Summary One-Line One-Line tltlr Light load, NY/NE = 0 tltlrvt titIme tltIrsum tlt2r Light load, NY/NE = 0, tlt2rvt tlt2rne tlt2rsum Con Ed Newington sensitivity tpklr Peak load, NY/NE = 0 tpklrvt tpklme tpklrsum tpk2r Peak load, NY/NE = 700MW tpk2rvt tpk2rne tpk2rsum tpk3r Peak load, NY/NE = -700MW tpk3rvt tpk3me tpk3rsum tshlr Shoulder load, NY/NE = -1200MW tshl rvt tsh Irne tsh Irsum Systems Energy GE-Power Systems Consulting Energy Consulting A-I ReportllllO3.doc A-1 ReportI111tO3.dbc

Appendix B. Full Uprate Power Flow Summaries and Diagrams for Power Flow Analysis Case Brief Dcscription Vermont New England Summary One-Line One-Line tltlu Light load, NY/NE = 0 -j tltluvt tItlune titlusum tlt2u Light load, NY/NE = 0, tlt2uvt - tlt2unc tlt2usum Con Ed Newington sensitivity tpklu Peak load, NY/NE = 0 tpkluvt tpklune tpklusum tpk2u Peak load, NY/NE = 700MW tpk2uvt tpk2une tpk2usum tpk3u Peak load, NY/NE = -700MW tpk3uvt tpk3une tpk3usum tshlu Shoulder load, NY/NE = -1200MW tshluvt tshlune tsh I usum B-I Repottl 11103.doc GE-Power Energy Consulting Systems Energy GE-Power Systems Consulting B-1 Report11110.obc

Appendix C. Benchmark Power Flow Summaries and Diagrams for Transient Stability Analysis Case Brief Description Vermont New England Summary One-Line One-Line sltlr Light load with Maine generation sltlrvt sItlme sltlrsum slt2r Light load with Newington generation slt2rvt slt2rne slt2rsum spklr Peak load spkl rvt spklme spkl rsum spk4r Peak load, High E-W, All Northfield spk4rvt spk4rne spk4rsum spk5r Peak load, High E-W, No Northfield spk5rvt spk5me spk5rsum GE-Power Systems Energy Consulting C-1 ReportI11103.doc

Appendix D. Vermont Yankee Benchmark Dynamic Models Generator Motor - GENROU Block Diagram

.~ Ie L d-Ll I l 4

-a 4 D~O~ -~ -

-L'd-U l dadS id Se glq-AXIS not shcanW" Generator Motor - GENROU Data Id 1.8100 s12 0.2720 Ipd 0.3450 h 3.8900 Ippd 0.2250 d 0.0000 Iq 1.7500 rcomp 0.0000 Ipq 0.5700 xcomp 0.0000 lppq 0.2250 accel 0.0000 11 0.1900 ra 0.0000 tpdo 6.7000 tppdo 0.0350 tpqo 0.4100 tppqo 0.0580 sI 0.0830 GE-Power Systems Energy Consulting D-1 Reports1 10ldoc

Excitation System Model - EXAC3A Block Diagram S(

Excitation System Model - EXAC3A Data tr 0.0000 kc 0.1500 tb 0.0000 kd 1.0400 tc 0.0000 ke 1.0000 ka 140.1900 vlv 0.5100 ta 0.0130 cl 3.7800 vamax 1.0000 sel 0.3570 vamin -0.9500 e2 5.0400 te 4.4200 se2 3.8650 klv 0.0800 kIl 0.5900 kr 4.6300 kfa 0.0500 kf 0.1430 tf 1.0000 kn 0.0500 efdn 1.7710 GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy D-2 ReponllllO3.doc D-2 Report111103.dbc

Plant Motor Load Model - IMOTORI Block Diagram Lm -Ls-LI l ~Lm"-1./(1./Lm+UrI)=LUU Lm' m1.1(1.tLm+1.tUrl)-L'-L1 Lm"-1.J(1 ./Lm +1. JLF1t./JUr2)- L"-LI To - Llrl Lm I( a Rrd Lm) - (Iln + Lm)I (b Rr1)

T'o - LIr2 IM'JtV Rr2 LmV) a (LF2 + Lm) I(Jb Rr2)

Plant Motor Load Model - MIOTORl Data Is 2.5000 'pp 0.2000 Ip 0.2000 11 0.1200 ra 0.0050 tppo 0.0000 tpo 0.5000 h 1.0000 d 2.0000 sel 0.0500 se2 0.3000 vt 0.9000 tv 10.0000 ft 0.0000 tf 0.0000 vr 0.9100 tvr 0.0000 acc 0.0000 D-3 Repoflh11O3.doc GE-Power GE-PowerSystems Energy Consulting Systems Energy Consulting D-3 Report111103.doc

KLF-1 Relay Model - OOSLEN Relay Operation Characteristic X

(-0.41322,0.09546) pu R

(0.41322, -0.09546) pu "KLF-1" Existing Settings:

Circle Diameter: 0.30103pu Circle Origin: (0, -0.11864) pu KLF-1 Relay Model - OOSLEN Data notrip 0 rr2 -99999.0 type 11 w12 -99999.0 tcb 0.0000 t2 0.0 alphal 90.0 alpha3 0.0 rfl 0.03188 rf3 0.0 rrl -0.269153 rr3 0.0 w1l 0.0000 w13 0.0 ti 0.0 t3 0.0 alpha2 77.0 vtrip 0.7998 rf2 0.0 ta 0.25 D-4 RepartllllO3.doc GE-Power Systems Consulting Energy Consulting Systems Energy D-4 Reportll 103 doc

Appendix E. Full Uprate Power Flow Summaries and Diagrams for Transient Stability Analysis Case Brief Description Vcrmont New England I Summary One-Line One-Line sltlu Light load with Maine generation sltluvt sltlune sltlusum slt2u Light load with Newington generation slt2uvt slt2une slt2usum spklu Peak load spk I uvt spklune spklusum spk4u Peak load, High E-W, All Northfield spk4uvt spk4une spk4usum spk5u Peak load, High E-W, No Northfield spk5uvt spk5une spk5usum GE-Power Systems Energy Consulting E-1 Report111103 doc

Appendix F. Vermont Yankee Full Uprate Dynamic Models Generator Motor - GENROU Block Diagram l2d-Ld l 4LU P-d I IN-- Fl d Id Se )_=

S'c q-XIS nolshewn '" I Generator Alotor - GENROU Data Id 1.9818 s12 0.4110 lpd 0.3827 h 3.8750 lppd 0.2456 d 0.0000 Iq 1.9092 rcomp 0.0000 Ipq 0.6095 xcomp 0.0000 Ippq 0.2456 accel 0.0000 11 0.2084 ra 0.0000 tpdo 6.7260 tppdo 0.0350 tpqo 0.4270 tppqo 0.0560 s1 0.0870 GE-Power Systems Energy Consulting F-1 Reportl tl103dbc

Excitation System Model - EXAC3A Block Diagram 6o Excitation System Model - EXAC3A Data tr 0.0000 kc 0.1500 tb 0.0000 kd 1.0400 tc 0.0000 ke 1.0000 ka 140.1900 vlv 0.5100 ta 0.0130 el 3.7800 vamax 1.0000 sel 0.3570 vamin -0.9500 e2 5.0400 te 4.4200 se2 3.8650 klv 0.0800 kil 0.5900 kr 4.6300 kfa 0.0500 kf 0.1430 tf 1.0000 kn 0.0500 efdn 1.7710 GE-Power Systems Energy Consulting F-2 Reporn111 103 doc

Plant Motor Load Model - MOTORi Block Diagram I Irt I p- v _sF Vo WVXK{]

E Lm -Ls.LI 3- l Lm -t.J(1.JLm .Url)=LUU o l Lmn-1. iCi /Ii

.J~ 1. JLF1i + 1./LFr2) - L* -Ll t-o - WI Lm J1(dO Rr1 Ln)' - (Uri + Lm) (0-b Rrd)

T o - Llr2I MJ1(WoRr2Lm") - (Lr2 + Lm'IJ(Wo Rr2)

Plant Motor Load Model - MOTORI Data Is 2.5000 'pp 0.2000 lp 0.2000 11 0.1200 ra 0.0050 tppo 0.0000 tpo 0.5000 h 1.0000 d 2.0000 sel 0.0500 se2 0.3000 vt 0.9000 tv 10.0000 ft 0.0000 tf 0.0000 vr 0.9100 tvr 0.0000 acc 0.0000 F-3 Repat111103.doc Systems Energy GE-Power Systems GE-Power Consulting Energy Consulting F-3 ReportIM10.Obc

KLF-1 Relay Model - OOSLEN Relay Operation Characteristic x

R "KLF-1" Modified Settings:

Circle Diameter. 0.28996pu Circle Origin: (0, -0.17391) pu KLF-1 Relay Model - OOSLEN Data notrip 0 rr2 -99999.0 type 11 w12 -99999.0 tcb 0.0000 t2 0.0 alphal 90.0 alpha3 0.0 rfl -0.0289 rf3 0.0 rrl -0.319 rr3 0.0 w1l 0.0000 w13 0.0 tI 0.0 t3 0.0 alpha2 77.0 vtrip 0.7998 rf2 0.0 ta 0.25 GE-Power Systems Energy Consulting F-4 ReportII11f03.dbc

Appendix G. Millstone #3 Exciter Model Excitation System Model - EXAC3A Block Diagram Excitation System Model - EXAC3A Data tr 0.0000 kc 0.1300 tb 0.0000 kd 1.1400 tc 0.0000 ke 1.0000 ka 67.030 vlv 0.5400 ta 0.0130 el 5.0000 vamax 1.0000 sel 0.1560 vamin -0.9500 e2 6.6700 te 4.4000 se2 1.9510 klv 0.100 kil 0.5900 kr 5.9700 kfa 0.0700 kf 0.0465 tf 1.0160 kn 0.0500 efdn 1.8790 G-1 Reparti It 103.dac GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy Reportf f ttO3.dbc G-I

Appendix H. Out-of-Service Models for In-Service Generators 2006 Summer Light Load Condition Bus# Bus Name k-V ID Model Type Bus # Bus Name k.8 ID Model Type 350 SENECA#2 13.8 1 hygov governor 79500 NIAG. 1 13.8 I hygov4 governor 2907 KITrGENI 13.8 1 hygov governor 79501 NIAG. 2 13.8 2 hygov4 governor 2908 KITTGEN2 13.8 1 hygov governor 79503 NIAG. 4 13.8 4 hygov4 governor 2909 KITTGEN3 13.8 1 hygov governor 79504 NIAG.5 13.8 5 hygov4 governor 4061 CONOWI-2 13.8 1 sexs exciter 79505 NIAG. 6 13.8 6 hygov4 governor 4061 CONOWI-2 13.8 2 sexs exciter 79507 NIAG. 8 13.8 8 hygov4 governor 4062 CONOW34 13.8 1 sexs exciter 79509 NIAG. 10 13.8 A hygov4 governor 4062 CONOW3-4 13.8 2 sexs exciter 79512 NIAG. 13 13.8 D hygov4 governor 4063 CONOW5-6 13.8 1 sexs exciter 79513 MOS17-18 13.8 1 hygov4 governor 4063 CONOW5-6 13.8 2 sexs exciter 79513 MOS17-18 13.8 2 hygov4 governor 4064 CONOW7 13.8 1 sexs exciter 79515 MOS19-20 13.8 I hygov4 governor 4191 MDYRN1-2 13.8 1 hygov governor 79515 MOS19-20 13.8 2 hygov4 governor 4191 MDYRN1-2 13.8 2 hygov governor 79516 MOS21-22 13.8 I hygov4 governor 4192 MDYRN34 13.8 1 hygov governor 79516 MOS21-22 13.8 2 hygov4 governor 4192 MDYRN3-4 13.8 2 hygov governor 79518 MOS25-26 13.8 I hygov4 governor 4193 MDYRN5-6 13.8 1 hygov governor 79518 MOS25-26 13.8 2 hygov4 governor 4193 MDYRN5-6 13.8 2 hygov governor 79520 MOS23-24 13.8 I hygov4 governor 4194 MDYRN7-8 13.8 1 hygov governor 79520 MOS23-24 13.8 2 hygov4 governor 4194 MDYRN7-8 13.8 2 hygov governor 79521 MOS27-28 13.8 I hygov4 governor 5170 NWKBAY 2 30 1 exacl exciter 79521 MOS27-28 13.8 2 hygov4 governor 5170 NNVKBAY 2 30 2 exacl exciter 79522 MOS29-30 13.8 I hygov4 governor 5170 NWKBAY 2 30 3 exacl exciter 79522 MOS29-30 13.8 2 hygov4 governor 16501 IG2LEWIS I 1 exdcl exciter 79524 MOS31-32 13.8 I hygov4 governor 28290 18PEREMR1 38 1 exac4 exciter 79524 MOS31-32 13.8 2 hygov4 governor 28290 18PEREMR 1 38 1 hygov governor 79527 GILBOA#I 17 I hygov governor 28351 18LUD12G 20 1 hygov governor 79528 GILBOA#2 17 2 hygov governor 28351 18LUD12G 20 2 hygov governor 79529 GILBOA#3 17 3 hygov governor 28352 18LUD34G 20 3 hygov governor 79530 GILBOAI#4 17 4 hygov governor 28353 18LUD56G 20 5 hygov governor 79531 LEW 1-3 13.8 I hygov4 governor 28353 18LUD56G 20 6 hygov governor 79531 LEW 1-3 13.8 2 hygov governor 31400 OSAGE 1 38 1 exstl exciter 79531 LEW 1-3 13.8 3 hygov governor 31400 OSAGE 1 38 2 exstl exciter 79532 LEW 4-6 13.8 4 hygov governor 31400 OSAGE 1 38 3 exstl exciter 79532 LEW 4-6 13.8 5 hygov governor 31400 OSAGE 1 38 4 exstl exciter 79532 LEW 4-6 13.8 A hygov governor 31400 OSAGE 1 38 5 exstl exciter 79533 LEW 7-9 13.8 7 hygov governor 31400 OSAGE 1 38 6 exstl exciter 79533 LEW 7-9 13.8 8 hygov governor 31400 OSAGE 1 38 7 exstl exciter 79533 LEW 7-9 13.8 9 hygov governor 31400 OSAGE 1 38 8 exstl exciter 79534 LEWIO-12 13.8 6 hygov governor 33351 MARION 1 61 4 exst2 exciter 79534 LEW1O-12 13.8 B hygov governor 63598 7SISI-6G 11 1 exdc4 exciter 79534 LEWIO-12 13.8 C hygov governor 63598 7SISI-6G 11 1 ieeegl governor 80907 PIC A G3 24 I exacla exciter 63598 7SISI-6G 11 2 exdc4 exciter 73083 NRTHFD12 13.8 1 pidgov governor 73083 NRTHFD12 13.8 2 pidgov governor 73084 NRTHFD34 13.8 3 pidgov governor H-I ReprxtllllO3.dvc Systems Energy GE-Power Systems GE-Power Consulting Energy Consulting H-1 ReportI11103.doc

2006 Summer Pcak Load Condition Bus # Bus Name k-' ID Model Type Bus # Bus Name k-V ID Model Type 5170 NWK BAY 230 1 exacl exciter 33351 MARION 161 4 exst2 exciter 5170 NWVK BAY 230 2 exacl exciter 50361 BCI Ul 13.8 1 exst2 exciter 5170 NWK BAY 230 3 exacl exciter 50362 BCI U2 13.8 1 exst2 exciter 8307 PCLP GT 13.8 1 exac2 exciter 55673 NICHL3 1 22 1 exst2 exciter 8307 PCLP GT 13.8 1 tgovl governor 74193 DANSK G4 16.1 4 exst2 exciter 8885 EM5 23 1 exdcl exciter 79500 NIAG. I 13.8 1 hygov4 governor 11010 MARSHLI 20 1 exdcl exciter 79501 NIAG. 2 13.8 2 hygov4 governor 11010 MARSHLI 20 1 ieeegl governor 79503 NIAG. 4 13.8 4 hygov4 governor 11010 MARSHLI 20 L exdcl exciter 79504 NIAG. 5 13.8 5 hygov4 governor 11011 MARSHL2 20 2 exdcl exciter 79505 NIAG. 6 13.8 6 hygov4 governor 11011 MARSHL2 20 2 ieeegl governor 79507 NIAG. 8 13.8 8 hygov4 governor 11011 MARSHL2 20 L exdcl exciter 79509 NIAG. 10 13.8 A hygov4 governor 11012 MARSHL3 24 3 exdcl exciter 79512 NIAG. 13 13.8 D hygov4 governor 14070 6OGDEN M 230 A ieeetl exciter 79513 MOS17-18 13.8 1 hygov4 governor 14070 6OGDEN M 230 A ieeegl governor 79513 MOS17-18 13.8 2 hygov4 governor 14070 6OGDEN M 230 B ieeetl exciter 79515 MOS19-20 13.8 1 hygov4 governor 14070 6OGDEN M 230 B ieeegl governor 79515 MOS19-20 13.8 2 hygov4 governor 15167 IROCKYMI 13.8 1 exstl exciter 79516 MOS21-22 13.8 1 hygov4 governor 15167 IROCKYMI 13.8 1 pidgov governor 79516 MOS21-22 13.8 2 hygov4 governor 15167 IROCKYMI 13.8 1 ieeest stabilizer 79518 MOS25-26 13.8 1 hygov4 governor 15168 IROCKYM2 13.8 2 exstl exciter 79518 MOS25-26 13.8 2 hygov4 governor 15168 IROCKYM2 13.8 2 pidgov governor 79520 MOS23-24 13.8 1 hygov4 governor 15168 IROCKYM2 13.8 2 ieeest stabilizer 79520 MOS23-24 13.8 2 hygov4 governor 15169 IROCKYM3 13.8 3 exstl exciter 79521 MOS27-28 13.8 1 hygov4 governor 15169 IROCKYM3 13.8 3 pidgov governor 79521 MOS27-28 13.8 2 hygov4 governor 15169 IROCKYM3 13.8 3 ieeest stabilizer 79522 MOS29-30 13.8 1 hygov4 governor 16500 IGILEWIS I I exdcl exciter 79522 MOS29-30 13.8 2 hygov4 governor 16501 IG2LEWIS 1 1 exdcl exciter 79524 MOS31-32 13.8 1 hygov4 governor 25932 08ZIMRHP 26 1 exbbc exciter 79524 MOS31-32 13.8 2 hygov4 governor 25932 08ZIMRHP 26 1 ieeest stabilizer 79531 LEW 1-3 13.8 1 hygov4 governor 25933 08ZIMRLP 22 1 exacl exciter 33351 MARION 161 4 exst2 exciter 28290 18PEREMR 138 1 exac4 exciter 84249 LG2ABT59 13.8 1 exstl exciter 28290 18PEREMR 138 1 hygov governor 84249 LG2ABT59 13.8 1 ieeest stabilizer ReportllllO3.doc Systems Energy GE-Power Systems Consulting Energy Consulting H-2 HRepon11103.dcb

Appendix I. Power Flow Summaries and Diagrams for N-2 Analysis Case Brief Description Vermont New England Summary One-Line One-Line tpk3-379o Peak Load, Section 379 Out tpk3-379ovt tpk3-379one tpk3-379osum tpk3-381o Peak Load, Section 381 Out tpk3-381ovt tpk3-38lone tpk3-38losum GE-Power Systems Energy Consulting 1-1 RepWr111103.doc

Appendix J. Vermont Yankee Exciter Models for Sensitivity Analysis IEEETI Block Diagram with Traditional Parameters Vref Vrmax TTS- 1+ sTa Vc e sTe so S2 ka+ Efd SS S3 Tr 0.0000 ka 50.000 Ta 0.0200 Vrmax 1.0000 Vrmin -1.000 Ke 0.0000 Te 0.5280 Kf 0.0960 Tf 1.2600 el 3.2600 sel 0.072000 e2 4.3500 se2 0.282000 GE-Power Systems Energy Consulting J-1 Reportt11103 doc

EXAC3A Block Diagram with Latest Parameters Excitation System Model - EXAC3A Data tr 0.0000 kc 0.1500 tb 0.0000 kd L6000 tc 0.0000 ke 1.0000 ka 112.150 vlv 0.5100 ta 0.0130 el 5.1000 vamax 1.0000 sel 0.3570 vamin -0.9500 e2 i.8OOO te 4.4200 se2 3.8650 klv .11i 00 kll 0.5900 kr S.i900 kfa 0.0400 kf 0.1430 tf 1.0000 kn 0.0500 efdn 1.7710 GE-Power Systems Energy Consulting J-2 Report111103.doc

Appendix K. Entergy Transmittal of Exciter Model Data Both the transmittal letter and the associated exciter model block diagram and data are included in this CD report.

K-I ReportllllO3.doc GE-Power Systems GE-Power Consulting Energy Consulting Systems Energy K-1 Report111103.6Dc

Appendix L. Preliminary Out of Step Relay Protection Vermont Yankee Out of Step Relay - OOSLEN Relay Model Characteristic X

Blinder Blinder:

(-0.0275, 0) pu (0.0275, 0)pu R

Out-Of-Step Relay Settings:

Circle Diameter: 0.1698pu Circle Origin: (0, -0.0321) pu type 11 Tcb 0.0833 alphal 90. ailpha2 0. alpha3 0.

Rfl 0.0528 1Zf2 9999. Rr3 0.0275 RrI -0.117 1 -0.0275 Rr3 -9999.

WI1 0.0 IW12 0. W13 0.

TI 0.30 r2 0. T3 0.

GE-Power Systems Energy Consulting L-1 RepWI11d103.doc

BVY 04-086 Docket No. 50-271 Attachment 3 Vermont Yankee Nuclear Power Station Proposed Technical Specification Change No. 263 - Supplement No. 12 Extended Power Uprate - Revised Grid Impact Study Regulatory Commitments I Total number of pages in Attachment 3 l (excludina this cover sheet) is 1. I

-Adft ENN NON-QUAuTY RELATED ENN-LI-16 Revision I ENL NUCLEAR ADMINISTRATIVE ntergy MANAGEMENT MANUAL INFORMATION USE Page 1 of I Licensee Identified Commitment Form This form identifies actions discussed In this letter for which Entergy Nuclear Operations, Inc. (Entergy) commits to perform. Any other actions discussed in this submittal are described for the NRC's information and are not commitments.

(BVY 04-086)

TYPE (Check one)

CN _ SCHEDULED COMMITMENT ECOMPLETION DATE

. a (If Required)

Prior to increasing Implement those modifications contained in ISO New X power above CLTP England letter of March 12, 2004. (Jan. 31, 2005)

Prior to exceeding Install additional capacitor banks. X 630 MWe (gross)

(Fall 2005)