Text

Point Beach, Units 1 and 2 - Transmittal of Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study
	ML092400526
Person / Time
Site:	Point Beach
Issue date:	08/24/2009
From:	Meyer L; Point Beach
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML092400540	List: ML092400526; NRC 2009-0082, Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study, Appendixes B - J; NRC 2009-0082, Point Beach, Units 1 and 2 - Transmittal of Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study;
References
	NRC 2009-0082 G833/G834-J022/J023, Rev 1
	Download: ML092400526 (51)
	v • d • e

NEXT August 24,2009 ENERGVk POINT BEACH / NRC 2009-0082 10 CFR 50.90 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Point Beach Nuclear Plant, Units 1 and 2 Dockets 50-266 and 50-301 Renewed License Nos. DPR-24 and DPR-27 Transmittal of Backaround Information to Support License Amendment Request 261 ATC lnterim Operation and Impacts Re-Study

Reference:

(1) FPL Energy Point Beach, LLC, Letter to NRC, dated April 7,2009, License Amendment Request 261, Extended Power Uprate (ML091250564) To support NRC review of the Point Beach Nuclear Plant (PBNP) License Amendment Request (LAR) 261 (Reference I) for an Extended Power Uprate (EPU), NextEra Energy Point Beach, LLC (NextEra) is providing the following document: G833lG834-J022lJ023 lnterim Operation and Impacts Re-Study Report, Revision 1, 11 8 MW Nuclear Generation Increase (59 MW each at Point Beach Generators 1 and 2), Manitowoc County, Wisconsin, dated July 14, 2009. The study was prepared by American Transmission Company (ATC), the transmission grid ownerloperator for PBNP. The report provides the interim operation and impacts re-study required by the Midwest Independent System Operator (MISO) for the PBNP EPU. In order to address the thermal and stability limits of the transmission grid that will be associated with the implementation of the PBNP EPU, a combination of interim or final requirements including breaker protection improvements, installation of a switching station, line segment upgrades, and operating restrictions will be implemented. These requirements are being addressed to allow PBNP to operate either unit at EPU conditions. Reference (I), Attachment 5, Licensing Report Section 2.3.2, contains a discussion of the Offsite Power System for the proposed EPU. NextEra Energy Point Beach, LLC, 6610 Nuclear Road, Two Rivers, WI 54241 Document Control Desk Page 2 This letter contains no new commitments and no revisions to existing commitments. The enclosure to this letter is being provided to the NRC in accordance with Commitment 2 of Reference (1). As stated in this commitment, revisions to this report will be provided to the NRC within 45 days of receipt from ATC. Questions concerning the enclosure should be directed to Mr. Steve Hale, EPU Licensing Manager, at 5611691-2592. Very truly yours, NextEra Energy Point Beach, LLC Larry Meyer L~ite Vice President Enclosure cc: Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW ENCLOSURE NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT UNITS 1 AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE G833lG834-JO221J023 INTERIM OPERATION AND IMPACTS RE-STUDY REPORT REVISION 1 118 MW NUCLEAR GENERATION INCREASE (59 MW EACH AT POINT BEACH GENERATORS I AND 2) MANITOWOC COUNTY, WISCONSIN DATED JULY 14,2009 AMERICAN TRANSMISSION COMPANY, LLC 102 Pages Follow G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 AMERICAN TRANSMISSION COMPANY @ G833lG834-502215023 Interim Operation and Impacts Re-Study Report Revision 1 118 MU7 Nuclear Generation Increase (59 MW each at Point Beach Generators 1 and 2) Manitowoc County, Wisconsin 6833 - MIS0 Queue #39297-01 5022 - MIS0 Queue Date (1/16/2009) G834 - MIS0 Queue #39297-02 5023 - MIS0 Queue Date (1/14/2009) July 14,2009 American Transmission Company, LLC Prepared By: Sun Wook Kang, Planning Approved By: David K. Cullum, P.E. Team Leader - G-T Interconnections & Special Studies American Transmission Company Page 1 of 102 G833/4-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table of Contents EXECUTIVE

SUMMARY

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SUMMARY

.............. .. ............................................................................................................................................ 7 ................................................................................ 2 . CRITERIA. METHODOLOGY AND ASSUMPTIONS 20 .......................................................................................... .................................. 2.1 S~Y CRITERIA .... 20 ........................... 2.2 STUDY M%THODOLOGY ... ......................................................................................... 20 ............................................................................................................ 2.2.1 Competing Generation Requests 20 ......................................................................................................... 2.2.2 A.C. Power Flow Analysis Methods 20 ...................................................................................................................................... 2.2.3 Stability Analysis 20 ...................................................................................................................... ................... 2.3 BASE CASES .. 2 1 .......................................................................................................... 2.3.1 Power Flow Analysis (Steady State) 21 ................................................................................................................. 2.3.2Stability Analysis (Dynamics) 21 ............................................................................................................................. 2.4 GENERATION FACILITY 22 ................................................................................................................... 2.4.1 Generating Facility Modeling 22 ................................................................................................................................ 2.4.2 Voltage Sag Criteria 23 ................... 3 . ANALYSIS RESULTS .. ..................................................................................................................... 24 ......................................................................................................... 3.1 POWER FLOW ANALYSIS RESULTS 24 ........................................................................... 3.1.1 Power Factor Capability and Voltage Requirements 24 ......................................................................... 3.1.2 Results of Intact System and Single Contingencies (N-1) 24 ............................................................................................................. 3.1.3 Results of Double Contingencies 25 ................................................................................................................ 3.2 STABILITY ANALYSIS RESULTS 26 .............................. 3.2.1 Results of Primary Clearing of Three-Phase Faults Under Intact System Conditions 27 ................ 3.2.2Results of Primary Clearing Three-Phase Faults on Two Circuits of a Multiple Circuit Lines 27 3.2.3Results of Primary Clearing Three-Phase Faults During a Prior Outage ................................ .. .............. 28 ....... 3.2.4Results of Three-Phase Fault Delayed (Breaker Failure) Clearing under Intact System Conditions 30 ................................................. 3.2.5Point Beach Bus. Generator Step Up andAuxiliary Transformer Faults 32 ............................................................................................................................................... 3.2.6 Unit Outage 32 ......................................................................................................................... 3.2.7Stability Results Summary 33 .................................................................. APPENDIX A: POWER FLOW ANALYSIS RESULTS ....................... .. 36 ................................................................................................ APPENDIX B: STABILITY ANALYSIS RESULTS 49 ................................................................................................. APPENDIX C: COMPETING WIND GENERATORS 74 APPENDIX D: OPERATING RESTRICTIONS ........................ .. ............................................................................. 75 APPENDIX E: SHORT CIRCUIT / BREAKER DUTY ANALYSIS RESULTS ...................................................... 77 APPENDIX G: ESTIMATED ALLOWABLE MW OUTPUT FROM G834 OR G833 UNDER SPRINGmALL OR WINTER EMERGENCY RATINGS ............................................................................................................................ 84 APPENDIX H:

SUMMARY

TABLE OF STABILITY STUDY RESULT ................................................................ 86 APPENDIX I: MINIMUM EXCITATION LIMITS AT POINT BEACH AND KEWAUNEE DURING INTERIM PERIODS ..................... .... ........................................................................................................................................... 90 American Transmission Company Page 2 of 102 07/14/2009 G83314-J0221J023 Interim Operation and Impacts Re-Study Report-RO1 APPENDIX J: UNIT RESTRICTION DUE TO STABILITY UNDER PRIOR OUTAGE CONDITIONS IN TABLE ES-3 DURING ONE OF POINT BEACH UNITS OFFLINE .... ... ...... .. ......... ................ ........ .........,,.,.,,, ...... 101 American Transmission Company Page 3 of 102 G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Executive Summary The Impact Study (ISIS) report for Midwest Independent System Operator (MISO) Generation Interconnection Requests identified as Projects G833, Queue #39297-01, and G834, Queue #39297-02, to the 345-kV transmission system in Manitowoc County, Wisconsin, was originally posted in July 2008 and the revision (#3) was posted on December 18,2008. On January 14 and 16, 2009, the interconnection customer increased the MW output of the original G83314 by 6 MW per unit (MISO Generator Interconnection Requests J022 and J023) and the original dynamic models of the generators were modified. As a result, the requests became 59 MW increase to each of the Point Beach Nuclear generators for a total increase in plant output of 11 8 MW. Each generator was studied with a net output, as measured at the low-side of the generator step-up transformer, of 619.56 MW net (642.96 MW gross per unit). The requested commercial operation date is May 3 1, 2010 for G834lJ023 (Point Beach Unit 1) and May 31, 201 1 for G833lJ022 (Point Beach Unit 2). Since the requested commercial operation date is earlier than the timeframe to complete the long term Network Upgrade, an interim operation study of the period between the expected commercial operation date and the expected completion date of a long term solution was undertaken to identify the possible unit restrictions and/or additional system upgrades needed during this interim period. This report identifies restrictions due to system thermal limitations (Tables ES-1 and ES-2) and due to angular instability of the Point Beach units and/or other nearby plants (Table ES-3). Information regarding the required system upgrades can be found in Table 1.2. As a result of the study with the latest data and prior to the long term Network Upgrades, it was also identified that generation instability may occur under fault conditions when Kewaunee and Point Beach units operate at reactive power outputs lower than the outputs shown in Appendix I (Minimum Excitation Limits). Reactive power output from a synchronous machine has an impact on the transient stability of the unit. Typically, a unit tends to be less stable under a fault when the unit produces relatively small reactive power output or absorbs reactive power from transmission system (under-excitation). The results of this interim operation study indicate that a certain level of reactive power output (over-excitation) needs to be maintained to ensure generation stability in anticipation of critical fault conditions. This is primarily due to too many generators with few outlets out of Fox Valley area. Imposition of Minimum Excitation Limits can impact the local transmission system in regard to voltage control. As Appendix I demonstrates, transmission system voltage control will be retained with the proposed limits. Therefore, although ATC and the customer agreed on the unit reactive power output level that is generally consistent with historical levels and corresponds to the low end (352 kV, 1.0203 pu) of the preferred voltage range at the Point Beach power plant, the use of revised Minimum Excitation Limits ensures stable generator operation for system faults. American Transmission Company Page 4 of 102 G83314-J0221J023 Interim Operation and Impacts Re-Study Report-ROl Table ES-4: Restrictions Due to Thermal (Valid per condition noted) Maximum 642.96 MW Gross per Point Beach unit Assumes all competing wind farms at full output Table ES-2: Restrictions Due to Thermal (Valid per condition noted) Maximum 642.96 MW Gross per Point Beach unit Assumes all competing wind farms at 20% output American Transmission Company Page 5 of 102 Limiting Transmission Line System Load Level 100% Season Winter SpringIFall Summer Restrictions Due to Thermal (UllU2 gross MW) None None None Point Beach-Sheboygan 345-kV 50% Winter SpringIFall Summer None None 535 1537 MW G833/4-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table ES-3: Restrictions Due to Stability (Valid any hour of year) Maximum 642.96 MW Gross per Point Beach unit American Transmission Company Page 6 of 102 Notes The operating restrictions are valid only with the stability upgrade in-service which are required by May 2010 in Table 1.2. (R-304 Breaker Replacement at North Appleton) The operating restrictions are valid only with all the stability upgrades in-service required by May 2010 and 201 1 in Table 1.2. (Point Beach relay upgrades and Addition of a breaker in series with existing Q-303 breaker at Point Beach) Condition Prior outage of 345-kV line 6832 Prior outage of Point Beach Bus Tie 2-3 Year May 2010- April 201 1 (i.e. G834lJ023 only) May2011 - beyond With G83314 (J02213) With Kewaunee May 201 1 - beyond With G83314 (JO2213) With existinq Kewaunee Point Beach Unit Unit #I Restrictions Due to Stability (gross MW) 560 MW 580 MW Unit#2 . unit #I Prior outage of 345-kV line 121 Prior outage of 345-kV line 151 Prior outage of 345-kV line R304 Prior outage of 345-kV line 6832 Prior outage of SEC31 Prior outage of Point Beach Bus Tie 2-3 Prior outage of Point Beach Bus Tie 4-5 Unit #2 Unit #2 Unit #2 Both Unit #I and #2 Unit #2 Unit #I Unit #2 620 MW 620 MW 600 MW 540 MW per unit 580 MW 580 MW 620 MW The operating restrictions are valid only with all the stability upgrades in-service and with Kewaunee bus reconfiguration project in-service 600MW 580 MW Prior outage of 345-kV line 6832 Prior outage of Point Beach Bus Tie 2-3 G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 1. Summary Primarily due to the modification to the original generator models of G833 and G834 supplied by the Interconnection Customer, an extensive stability analysis was performed to identifl impact of the modification and to provide interim operating limitations andfor interim system upgrades needed to maximize the output of G833lJ022 and G834lJ023 until completion of the long term Network Upgrades. Key modifications include: In-service date of new generator step-up transformer of Unit 2 (October 2009) MW output increased by 6 MW per unit (total 642.96 MW gross per unit) Dynamic models of unit 1 and 2 G833lJ022 and G834lJ023, with an expected in-service date of May 31,2011 and May 31,2010, respectively, became 59 MW increases to each of the existing Point Beach nuclear units. For this interim operation period re-study, no new thermal analysis was performed since the plant impact will not change substantially. No significant impact is expected due to additional 12 MW output increase. Instead, the thermal impact due to the proposed 6 MW increase per unit (J022123) was assessed based on the formula in Section 1.1 and the results shown in the previous version of the Interim Operation Study report dated Dec. 30,2008. The following three different scenarios were studied for the interim period stability analysis: Interim 1 scenario representing the period between May 2010 (after G834lJ023) and April 201 1 (before G833lJ022) Interim 2 scenarios representing the period between May 201 1 (after G833lJ022) and the in-service date of a long term solution: o Interim 2A: with G83314-J02213 and with existing Kewaunee substation o Interim 2B: with G83314-J02213 and with new Kewaunee substation Different generation patterns and load levels were considered for each scenario. Consistent with the G83314 System Impact Study report dated Dec. 18, 2008, both high and low Fox Valley generation scenarios were studied to evaluate stability for the scenarios. More details can be found in Section 2.3. This re-study assumes the Point Beach generator and turbine improvements submitted for requests J022123 (MISO queue dates: January 16 and 14, 2009). The limitations and solutions described in this report may not be valid if the Point Beach data changes. 1.1 Injection ~imits' No new thermal analysis was performed since the plant impact will not change substantially. No significant impact is expected due to additional 12 MW output increase. Among the four injection limits identified in the previous interim operation report, only Point Beach-Sheboygan Energy Center and Cypress-Arcadian 345 kV lines are now required to be See Appendix F, Section F3.1 for a definition of what transmission overloads qualify as injection limits. American Transmission Company Page 7 of 102 07/14/2009 G833/4-502215023 Interim Operation and Impacts Re-Study Report-RO1 mitigated. The Elkhart Lake-Saukville and Elkhart Lake-G611 138 kV lines, which were originally identified in the previous interim operation study report, are no longer injection limits under the new MIS0 Generation Interconnection Business Practices. The new MIS0 generation interconnection procedure does not require transmission reinforcement for thermal issues resulting from an outage of generation outlet if distribution factor is below 5%. For the two remaining injection limits, new required ratings in this report were estimated using the formula given below: New Required Rating = Old Required Rating + (AP x DFl0.95) Where AP : MW output of new G833lJ022 and/or G834lJ023 - MW output of old G833lJ022 and/or G834lJO23 DF: Distribution Factor The injection limits are identified in Tables A. 1 through A.8 in Appendix A and are listed below. As mentioned in the previous study report, the thermal study identified no steady-state thermal violations for NERC Category A (intact system) events for all models studied. For NERC Category B (N-1) events, no injection limits were identified in the scenarios with 100% of system peak load while the two injection limits were identified in the scenarios with a 50% of system peak load condition. The two injection limits are: 1. Point Beach-Sheboygan Energy Center 345 kV line (Ll 1 1) 2. Cypress-Arcadian 345 kV Line (L-CYP3 1 north) As described in the previous interim study report, the thermal upgrades are needed for certain system scenarios but not all scenarios. The most critical upgrade is the improvement required to 345 kV line Llll from Point Beach to Sheboygan Energy Center. Independent of these Interconnection Requests, this line has been identified by ATC for improvement due to MIS0 energy market impacts. Interim mitigation measures for these injection limits are described in Section 1.4 and are required for the requested Interconnection Service of G833lJ022 and G834lJO23 to maximize their power output. 1.2 Generating Facility Operation Restrictions Various potential thermal constraints are shown in Table A.10 in Appendix A for Category C.3 events. In general, re-dispatching - generators in the Fox Valley area may relieve the loadings on the constraints. Since thermal constraints will be mitigated in the day-ahead and real-time market through the MIS0 binding constraint procedure, no operating restrictions are listed for the thermal constraints. However, there are restrictions based on the stability analysis. With all stability upgrades assumed in-service and the Minimum Excitation Limiter settings for Point Beach and Kewaunee units modified, generation restrictions identified for each interim period are: American Transmission Company Page 8 of 102 G833/4-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 During Interim 1 period (2010 after G834lJ023 - 201 1 before G833lJ022) i. GI at 560 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) ii. GI at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 During Interim 2A period (Without Kewaunee project, 201 1 after G833lJ022 - beyond ) i. G2 at 620 MW (gross) under prior outage of 121 (Point Beach-Forest Junction 345 kV line) ii. G2 at 620 MW (gross) under prior outage of 151 (Point Beach-Fox River 345 kV line) iii. G2 at 600 MW (gross) under prior outage of R304 (Kewaunee-North Appleton 345 kV line) iv. Both GI and G2 at 540 MW (gross) under prior outage of 6832 (North Appleton- Fox River 345 kV line) v. G2 at 580 MW (gross) under prior outage of SEC3 1 (Sheboygan Energy Center- Granville 345 kV line) vi. G1 at 580 MW (gross) under prior outage of Point Beach Bus Tie 2-3 vii. G2 at 620 MW (gross) under prior outage of Point Beach Bus Tie 4-5 During Interim 2B period (With Kewaunee project, 201 1 after G833lJ022 -beyond) i. G2 at 600 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) ii. GI at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 1.3 Generating Facility Requirements Point Beach Power System Stabilizers The existing Point Beach Power System Stabilizers (PSS) are required due to inadequate rotor angle damping under certain system conditions. The G833lJ022 and G834lJ023 projects will continue to require the use of PSS on the Point Beach units. This study incorporated the modified PSS information supplied by the Interconnection Customer and it assumed that the PSS for each unit was in-service for each simulation. The re-tuning of the PSS should be reviewed and commissioned by experienced professionals. The results of the on site PSS tuning, including the parameters expressed in terms of the appropriate power system stabilizer models in the Siemens PTI PSSIE program, must be provided to ATC prior to the commercial operation of G833lJ022 and G834lJ023. ATC will then test the performance of the Point Beach units with the tuned parameters in the computer simulations to ensure that rotor angle damping is within criteria. American Transmission Company Page 9 of 102 G83314-J022lJO23 Interim Operation and Impacts Re-Study Report-RO1 SEC FJT L KEW FOX ),::?;& MV& AUX AUX ~2x04 MVA Figure 1.1 -Existing Point Beach Substation ConJiguration Reduction of Auxiliary Transformers TlX03 and T2X03 Primarv Clearing Times (Table 1.4) Both the previous G83314 ISIS study and this interim operation study showed the need for faster primary clearing time for a fault at the high side of TlX03 or at the high side of T2X03 to address potential instability of the generators in the area (see Figure 1.1). As shown in the stability study results for Interim 2A (with existing Kewaunee) and 2B (with new Kewaunee bus configuration) periods, a total clearing time of 4.0 cycles is needed for the auxiliary transformer 345 kV fault primary clearing time under certain outage conditions to avoid instability of generators in the area. Plant Svecific Voltage Requirements The Point Beach Nuclear has specific 345 kV voltage range requirements. The preferred range is 352 kV (1.020 pu) to 354 kV (1.026 pu), the normal range is 351 kV (1.017 pu) to 358 kV (1.037 pu) and the maximum permissible is 348.5 kV (1.010 pu) to 362 kV (1.049 pu). Any voltage outside the maximum permissible range is a voltage limitation as described in the plant technical specifications. . . 1.4 System Upgrades 1.4.1 Existing System Upgrades (See Table 1.1) Injection Upgrades Analysis prior to G833lJ022 and G834lJO23 found no required system upgrades due to injection limits. American Transmission Company Page 10 of 102 G83314-5022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Voltage Related Analysis prior to G833lJ022 and G834lJ023 found no unacceptable voltages. Breaker Duty Related No existing over-duty circuit breaker conditions were found prior to be significantly (i.e. 21%) impacted due to the addition of G833IJ022 and G834lJ023. Therefore, no over-dutied circuit breakers are identified in Table 1.1. 1.4.2 System Upgrades and Interim Mitigation Measures Required due to 683415023 and/or G833lJ022 Addition The stability related upgrades listed in this section are required for increased plant operation during all hours in the year. In addition, the identified stability upgrades do not eliminate all restrictions on the upgraded Point Beach units since operating restrictions will exist during each interim period for certain prior outage conditions. Revised operating restrictions, in addition to the required stability upgrades, can be found at Section 1.2. In addition to the system upgrades listed below, both Point Beach units and the Kewaunee unit will be required to modify the Minimum Excitation Limit settings on these units to ensure stable operation for a variety of fault conditions. The proposed limits are described in Appendix I. 1.4.2.1 System Upgrades due to Thermal Issues To accommodate G83314-J02213, the following lines need to be uprated by May 1,2010: Point Beach-Sheboygan Energy Center 345-kV line: The most critical upgrade is the improvement required to 345 kV line Ll 1 1 from Point Beach to Sheboygan Energy Center, which has also been independently identified by ATC for improvement due to MIS0 energy market impacts. - Required rating: A minimum summer emergency rating of 596 MVA (997.4 A) - As an independent economic benefit project, ATC has proposed uprating the line to a summer emergency rating of 1120 MVA which is higher than the required rating for G83314-502213. The proposed in-service date of the line uprate project is April 25,2010 (ATC Project PR03208). Cypress-Arcadian 345-kV line: As described in the previous interim operation study report, roughly 52% and 33% of total output from all competing wind generators were estimated as the upper bounds for not exceeding the existing summer emergency rating (488 MVA SE) with G834 in- service and with ~83413-h2213 in-service, respectively, under light system load conditions. - Required rating: A minimum summer emergency rating of 572 MVA (957.3 A) - In-service date: May 1,2010 American Transmission Company Page 11 of 102 G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 1.4.2.2 System Upgrades due to Stability Issues For the G834lJ023 interconnection in 2010, the following stability upgrades are required: a. Improve primary clearing time at R-304 North Appleton terminal for R-304 fault at Kewaunee: - Replace the existing 3 cycle R-304 circuit breaker at North Appleton with new 2 cycle IPO circuit breaker to reduce the existing 6.5 cycle clearing time to 4.5 cycles to permit additional MW output from Point Beach unit #1 under certain prior outage conditions. - Required clearing times for R-304 fault at Kewaunee: o From the existing 4.5 cycle local primary and 6.5 cycle remote primary, o To 4.5 cycle local primary and 4.5 cycle remote. For the G833lJ022 interconnection in 201 1, the following stability upgrades are required: a. Improve breaker failure clearing time at Ll 1 1 Point Beach terminal for Ll 1 1 fault at Point Beach: - Replace the existing Point Beach Llll SBF breaker failure relay with an SEL-352, and replace the existing Line 1 1 1 SEL-22 1 F backup relay with an SEL-42 1. - Required clearing times for L111 fault at Point Beach: o From the existing 3.5 cycle local primary, 9.0 cycle local delayed, and 4.5 cycle remote primary o To 3.5 cycle local primary, 8.0 cycle local delayed, and 4.5 cycle remote primary b. Improve breaker failure clearing time at L151 Point Beach terminal for L151 fault at Point Beach: - Replace the existing Point Beach L151 SBF breaker failure relay with an SEL-352, and replace the existing Line 15 1 SEL-22 1F backup relay with an SEL-42 1. - Required clearing times for L15 1 fault at Point Beach: o From the existing 3.5 cycle local primary, 9.0 cycle local delayed, and 4.5 cycle remote primary o To 3.5 cycle local primary, 8.5 cycle local delayed (8.0 cycle achieved with the upgrade), and 4.5 cycle remote primary c. Isolate Q-303 fault at Point Beach in primary time: - Add a new Point Beach 345 kV Circuit Breaker in series with the existing 4-303 Circuit Breaker. The upgrade will clear a Q-303 breaker failure at Point Beach in primary time. - Wit5 the series breaker addition, achieve& clearing times for Q-303 fault at Point Beach: o From the existing 3.5 cycle local primary, 9.0 cycle local delayed, and 6.5 cycle remote primary (4.5 cycle remote primary with Kewaunee bus reconfiguration project in-service) American Transmission Company Page 12 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 o To 3.5 cycle local primary, 3.5 cycle local delayed (cleared in primary time), and 6.5 cycle remote primary (4.5 cycle remote primary with Kewaunee bus reconfiguration project in-service) d. Improve breaker failure clearing time of Point Beach Bus Tie 2-3 for a single-line to ground fault on Point Beach Bus 2: - Change Relay setting (without Breaker Failure relay replacement) for Failure of Point Beach Bus Tie 2-3 to no more than 11 cycle total breaker failure clearing time for bus faults. - Required clearing times for single line to ground fault on Point Beach Bus 2 with failure on Bus Tie breaker 2-3: o From the existing 4.75 cycle local primary and 12.5 cycle local delayed o To 4.75 cycle local primary and 11.0 cycle local delayed e. Upgrade back-up relay for better maintenance and operating flexibility during a L121 relay outage at Point Beach. - Replace L121 SEL-221F backup relay with SEL-421 to provide better maintenance and operating flexibility during a L12 1 relay outage. 1.4.2.3 Upgrades Required due to Voltage None identified. 1.4.2.4 Upgrades Required due to Breaker Duty None identified. American Transmission Company Page 13 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 NORTH APPLETON SHEBOYGAN ENERGYCENTER Legend - Existing (solid line) 7 (Pnint nf Channe To Arcadian Figure 1.2 - One Line Diagram of the 2010 System with G834 (J023) Shown With existing Kewaunee Substation American Transmission Company Page 14 of 102 G83314-J022lJO23 Interim Operation and Impacts Re-Study Report-RO1 NORTH ~353a CYPRESS 6354 a To Fitzgerald 6427 a T22 T21 L-CYP31 To Columbia SHEBOYGAN ENERGYCENTER GI03 EDGEWATER Legend - Existing (solid line) L3-4 L4-1 LSEC31 2-3 GRANVILLE 9911 1-2 To ~rcidian Figure 1.3 - One Line Diagram of the 2011 System with G833 (J022) and G834 (J023) Shown With exutzng Kewaunee Su American Transmission Company Page 15 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 NORTH KEWAUNEE TI0 To Columbia - I 796L41 5 F; 4 TI 3431 7 To Arcadian Figure 1.4 - One Line Diagram of the 2011 System with G833 (J022) and G834 (J023) Shown With Kewaunee Bus ReconJiguration Project Legend - Existing (solid line) PC0 (Point of Cha and POI (Pnint nf I American Transmission Company Page 16 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table 1.1- Existing System Upgrades Required before Operation of G833/J022 and/or G834 /J023 American Transmission Company Page 17 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table 1.2 - Required Interim Network Upgrades for Thermal and Stability Issues due to the Point Beach- Sheboygan Energy Center 345-kV line Addition of G833/J022 and/or G834/J023 North Appleton 345 kV Bus Point Beach 345 kV Bus Reason Injection Limit In- service Date 5/1/2010 Location Cypress-Arcadian 345-kV line Item 4A: Achieve L111 clearing times of 3.5 cycles local primary, 8.0 cycles local delayed and 4.5 cycles remote primary by reducing local delayed clearing time 1.0 cycles. It requires Point Beach L111 SBF Breaker Failure Relay replacement with an SEL-352, and the existing Line 11 1 SEL-221F backup relay replacement with an SEL-42 1. Good Faith Cost Estimate (Y2009) $1.7 M Facilities Item #1 -Look at plan and profile and Patrol to observe any close wire crossings and adjust to obtain a minimum Summer Emergency rating of 572 MVA (957.3 A). Item #2 - L111 requires a minimum summer emergency rating of 596 MVA (997.4 A). PRF PRO3208 requires a minimum summer emergency rating of 1120 MVA with a proposed in-service date of Spring 2010. Completion of PRF PRO3208 accomplishes the requirements for G833 and G834. Item #3 - R-304 Fault at Kewaunee Protection Improvement - North Appleton R-304 Circuit Breaker Replacement with 2 cycle Circuit Breaker implemented for Independent Pole Operation (345 kV, 3000 A, SO kA, Gas CB, IPO) in order to achieve 4.5 cycles remote primary clearing time. With Kewaunee bus reconfiguration project and Item #3 assumed in-service, R-304 fault clearing times become 3.5' cycles local primary, 8.5' cycles local delayed and 4.52 cycles remote primary by reducing the remote clearing time by 2.0 cycles Item #4 -Point Beach Faults Protection Improvements. Item 4B: Achieve L151 clearing times of 3.5 cycles local primary, 8.5 cycles local delayed and 4.5 cycles remote primary by reducing local delayed clearing time 0.5 cycles. It requires Point Beach L15 1 SBF Breaker Failure Relay replacement with an SEL-352, and the existing Line 151 SEL-221F backup relay replacement with an SEL-421 (note 8.0 cycles delayed clearing time can be obtained with Item 4B implemented). Injection Limit Stability Upgrades Item 4C: Isolate 4-303 line fault in primary time at Point Beach. This requires Point Beach 345 kV Circuit Breaker Addition (345 kV, 3000 A, 50 kA, Gas CB, IPO) in series with the existing Q- 303 Circuit Breaker to isolate line fault in primary time. Stability Upgrades Item 4D: Achieve breaker B23 clearing times of 11 cycles local delayed by reducing local delayed clearing time 1 cycle. It requires relay setting change (without Breaker Failure relay replacement) for Failure of Point Beach Bus Tie 2-3 to achieve no more than 11 cycle total breaker failure clearing time for bus faults Item 4E: Replace L121 SEL-221F backup relay with SEL-421 to provide better maintenance and operating flexibility during a L121 relay outage TOTAL Note 1 - Clearing times at Kewaunee with Kewaunee Bus Reconfiguration in-service Note 2 - Clearing time achieved by implementing item #3 American Transmission Company Page 18 of 102 5/1/2010 Not required since existing ATC project will satisfy rating needs G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Transmission None. Owner Table 1.3 - Required Interconnection Facilities,for G833/J022 and G834/J023 G833 (J022) Minimum Excitation Limiter setting changes are documented in and G834 Appendix I. (5023) Entity Facilities Interconnection Note: These facilities are to be provided by the generator Customer interconnection customer. Hence, cost estimate is not applicable. Cost Estimate (Y2009) 3 Recommended improvements to the Point Beach substation design. I Add 345 kV, 3000A, 50 kA, 2 cycle gas Circuit Breakers on the G833 (5022) high side of Point Beach auxiliary transformers TlX03 and T2X03 and G834 with adequate primary and breaker failure relaying. (J023) Reduce Auxiliary Transformer TlX03 primary fault clearing time Interconnection from 5.1 cycles to 4.0 cycles and Auxiliary Transformer T2X03 Customer from 5.1 cycles to 4.0 cycles. Note: These facilities are to be provided by the generator interconnection customer. Hence, cost estimate is not applicable. Table 1.5 -Required Improvements due to Third Party Impacts I I Facilities Cost Estimate (Y2009) Minimum Excitation Limiter setting changes are documented in Kewaunee unit Appendix 1. I NA Note: No cost estimate is identified for Third Party impacts. American Transmission Company Page 19 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 2. Criteria, Methodology and Assumptions 2.1 Study Criteria All relevant MISO-adopted NERC Reliability Criteria and the American Transmission Company contingency criteria are to be met for thermal, voltage and angular stability analysis. Details of the analysis criteria used in this study can be found in Appendix F. 2.2 Study Methodology The results of this study are subject to change. The results of the study are based on data provided by the Interconnection Customer and other ATC system information that was available at the time the study was performed, and the injection study does not guarantee deliverability to the MIS0 energy market. If there are any significant changes in the generator and controls data, earlier queue Generator Interconnection Requests, related Transmission Service Requests, or ATC transmission system development plans, then the results of this study may also change significantly. Therefore, this request is subject to restudy. The Interconnection Customer is responsible for communicating any significant generating facility data changes in a timely fashion to MIS0 and ATC prior to commercial operation. 2.2.1 Competing Generation Requests Competing generation requests can be found in Appendix C. Public information related to the MIS0 Interconnection Request queue can be found at: http://www.midwestmarket.ordpagelGenerator%2O~tercomection and the Interconnection Requests specific to the ATC footprint can be found at: http:Noasis,midwestiso.orddocumentslATC/Cluster 8 Oueue.htm1. 2.2.2 A.C. Power Flow Analysis Methods No thermal analyses were performed based on the reasons described in Section 1.1. 2.2.3 Stability Analysis ATC recently conducted extensive stability analysis of the area near the Point Beach generators and determined that there were no generation limitations for intact and single outage conditions, with the existing Power System Stabilizers (PSS) in service, and prior to requests G83315022 and G834lJO23. Simulations were performed with G8331J022 and/or G834lJ023 in service to determine the stability impacts that attributed to the additional generation with the latest dynamic data submitted to MIS0 for J022lJ023. Any violations of the stability study criteria (in Appendix F) identified with the increased generation in service can be attributed to the G833lJ022 and G834lJ023 interconnection request and are documented in this report. American Transmission Company Page 20 of 102 G83314-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 For the analysis, the Power System Stabilizers are assumed in-service. Simulated/tested clearing times shown in each table in Appendix B contains the required planning margin described in Section 3.2. The stability and grid disturbance performance analysis was performed using the Dynamics Simulation and Power Flow modules of the Power System SimulationIEngineering-29 (PSSE, Version 29.5.1) program from Siemens Power Technologies, Inc (PTI). This program is accepted industry-wide for dynamic stability analysis. 2.3 Base Cases 2.3.1 Power Flow Analysis (Steady State) No thermal analyses were performed based on the reasons shown in Section 1.1. 2.3.2 Stability Analysis (Dynamics) The 2010 50% of system peak load base case used in the stability analysis was developed based upon the ATC 2009 Ten Year Assessment 50% peak load dynamics-ready model from the 2007 Series NERC MMWG cases. The ATC area was replaced with the 2010 planned and proposed projects and load and generation was set to expected levels. All local and competing generators were dispatched at full output in accordance with ATC's generator interconnection study methodology. The resulting additional generation was delivered to ComEd (75%) and Northern States Power (25%) control areas. Two stability scenarios per each interim period were studied for G83314-J02213 interim operations. Specifically, high local generation and low local generation models were created. Only the wind generator (G427) located at Cypress 345-kV substation was considered as the competing generator for stability analysis based on the assumption that other wind generators connected at 138 kV would not significantly impact the stability results. For the high generation scenario, in addition to Point Beach and all local generation (Kewaunee, Fox River, Sheboygan Energy, South Fond du Lac and Cypress) were modeled with maximum generation. Weston Units 3 and 4 were also in service. For the low generation scenario, the same dispatch was used except that the Fox Energy, Sheboygan Energy, Cypress and South Fond du Lac were modeled as off-line. Table 2.3.1 - Key generation status for Interim Period 1 (May 201 04pril2011, with G834 and American Transmission Company Page 21 of 102 07/14/2009 G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Table 2.3.2 - Key generation status for Interim Period 2 (May 201 l-until completion of long term project, with G834 and with G833, with Kewaunee bus reconfiguration) I 1 I I Units 1 Low Generation Scenario I High Generation Scenario Point Beach Unit 1 (G834) Point Beach Unit 2 (G833) Kewaunee 642.96 MW (Gross) 642.96 MW (Gross) South Fond du Lac generators 2.4 Generation Facility 642.96 MW (Gross) 642.96 MW (Gross) 603 MW (Gross) Sheboygan Energy Center 2.4.1 Generating Facility Modeling The G833lJ022 and G834lJ023 projects are increases to the existing capacity of Point Beach generating units and are modeled by changing the existing representation in the planning cases so that the total gross real power is 642.96 MW and a new machine base of 684 MVA for each unit. 603 MW (Gross) OMW Prior to performing the stability analysis, ATC investigated and reviewed historical reactive power outputs from both the Point Beach and Kewaunee plants. Reactive power output fiom a synchronous machine has an impact on the transient stability of the unit. Therefore, for the interim study, ATC wanted to review the assumptions for building the study models. ATC selected a unit reactive power output level that is generally consistent with historical levels and corresponds to the low end of the preferred voltage range at the Point Beach power plant. 258 MW Cypress 352 MW OMW As a result, 352 kV (1.0203 pu) is assumed as the voltage schedule of both the Point Beach and Kewaunee generating units. The voltage schedule is consistent with the lowest value of the preferred voltage range of Point Beach (see Attachment H of OP 2A Revision 64). Table 2.4.1 shows the WAR output (gross) fiom the Point Beach and Kewaunee units in each scenario. OMW 632 MW Fox Energy Center 346.8 MW This re-study used the latest dynamic model data of J022IJ023 submitted by the Interconnection Customer to MIS0 on February 9 2009. OMW After the units are physically modified and prior to initial unit synchronization, final generator dynamic models should be provided so that operational studies confirming fne resub of??& study can be completed. American Transmission Company Page 22 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Interim 1 (with G8341J023 and without G833lJ022, without Kewaunee project) Interim 2a (with G833'J022 and G83415023, without Kewaunee project) 2.4.2 Voltage Sag Criteria Based on the voltage sag criteria information provided by the Interconnection Customer on March 13 2009, 19 kV and 345 kV bus voltage relay settings at Point Beach were also modeled and monitored during for the dynamic stability study. 47.4 MVAR at Point Beach G1 47.4 MVAR at Point Beach G2 30.4 MVAR at Kewaunee Interim 2b (with G833'J022 and G834lJ023, with Kewaunee nroi ecth 75.6 MVAR at Point Beach G1 75.6 MVAR at Point Beach G2 62.2 MVAR at Kewaunee 60.1 MVAR at Point Beach G1 60.1 MVAR at Point Beach G2 35.8 MVAR at Kewaunee American Transmission Company 85.7 MVAR at Point Beach G1 85.7 MVAR at Point Beach G2 68.2 WAR at Kewaunee 58.6 MVAR at Point Beach G1 58.6 MVAR at Point Beach G2 27.3 MVAR at Kewaunee Page 23 of 102 83.8 MVAR at Point Beach G1 83.8 MVAR at Point Beach G2 59.9 MVAR at Kewaunee 19 kV 84.6% 74.3% 94.1% 345 kV 1" criteria 2nd criteria 86.2% 75.7% 95.7% 1.5 seconds 1.0 second 1.5 seconds G833/4-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 3. Analysis Results 3.1 Power Plow Analysis Results No new thermal analysis was performed since the plant impact will not change substantially. No significant impact is expected due to additional 12 MW output increase. Appendix A, which is based on the previous version of the report, was revised using the formula given below: New Required Rating = Old Required Rating + (N x DFf0.95) Where AP : MW output of new G833fJ022 and/or G834fJ023 - MW output of old G833fJ022 and/or G834lJ023 DF: Distribution Factor 3.1.1 Power Factor Capability and Voltage Requirements No power factor analysis was completed for this interim operation study. 3.1.2 Results of Intact System and Single Contingencies (N-1) 3.1.2.1 Base Case Analyses No new thermal analysis was performed since the plant impact will not change substantially. No significant impact is expected due to additional 12 MW output increase. Among the four injection limits identified in the previous interim operation report, only the Point Beach-Sheboygan Energy Center and Cypress-Arcadian 345 kV lines are now required. Since L111 (Point Beach-Sheboygan Energy Center 345 kV line) will be uprated as an independent economic benefit project (1120 MVA SE with ATC Project PRO3208 assumed in-service), required ratings are given but these are lower than those required for ATC Project PR03208. Therefore, for all practical purposes, the only thermal upgrade required for G833f4 interconnection is the Cypress-Arcadian 345 kV line. Although an upgrade to the Cypress- Arcadian 345 kV line is noted, the overload of this 345 kV line only occurs for specific conditions whereas the interim upgrades needed for stability are required for all hours in the year. The Elkhart Lake-Saukville and Elkhart Lake-G6 1 1 1 3 8 kV lines that were originally identified in the previous interim operation study report are no longer injection limits under the new MIS0 Generation Interconnection Business Practice Manual (BPM). The new MIS0 generation interconnection procedure does not require transmission reinforcement for thermal issue resulting fiom an outage of a generation outlet if distribution factor is below 5%. American Transmission Company Page 24 of 102 G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 The two injection upgrades found with 50% system peak load modeled were Line L-CYP31, Cypress to Arcadian 345 kV. Approximately 20% of the increased generation will flow on this line, with Line Llll Point Beach to Sheboygan Energy Center 345-kV out of service. Line L111, Point Beach to Sheboygan Energy 345 kV. Approximately 24% of the increased generation flowing on this line with L-CYP3 1 out of service The revised maximum allowable real power output without system upgrades is presented in Table A. 1 1 in Appendix A. No study was performed for voltage analysis since no significant impact is expected due to 12 MW increase fiom the original request (G83314). Thus, it is expected that no transmission system voltage limits will be violated as a result of the interconnection of J022 and J023. See also Table A. 13. 3.1.3 Results of Double Contingencies 3.1.3.1 NERC Category C.3 Contingencies (N-1-1) Table A. 10 in Appendix A was revised due to additional 12 MW output increase. The results of this analysis are supplied for information only since no operating restrictions will be created for thermal N-1-1 limits. In the day-ahead and real-time market, MIS0 will utilize a binding constraint procedure to mitigate transmission system overloads. This process may result in curtailment of generation and could affect G833lJO22 and G834lJ023 for the contingencies noted in this N 1 analysis. 3.1.3.2 NERC Category C.5 Contingencies (IV-2) Table A.9 in Appendix A was revised due to additional 12 MW output increase. NERC Category C.5 events (i.e. two circuits on shared tower) evaluated are shown in Table 3.1. 1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit tower. American Transmission Company Page 25 of 102 G833/4-J022/5023 Interim Operation and Impacts Re-Study Report-RO1 3.2 Stability Analysis Results The stability analysis in this study was done for the following grid disturbance scenarios: 1. Three-phase fault cleared in primary time with an otherwise intact system (NERC Cat. B); 2. Single line-to-ground fault on both circuits of a double circuit structure with an otherwise intact system (NERC Cat. C); 3. Single line-to-ground fault on a bus with an otherwise intact system (NERC Cat. C); 4. Three-phase fault cleared in primary clearing time with a prior outage of any other transmission element (NERC Cat C); and 5. Three-phase fault cleared in delayed clearing time (e.g., breaker failure condition or zone 2 trip due to communication-based protection system failure) with an otherwise intact system (NERC Cat D). In general, for any grid disturbance, the proposed generation's dynamic response must not degrade the system stability performance. Recent stability analysis of the area near Point Beach, prior to requests G833lJ022 and G834lJ023, found no stability problems for (a) three-phase fault cleared in primary time with an otherwise intact system, (b) single line-to-ground fault on both circuits of a double circuit structure with an otherwise intact system, and (c) three-phase fault cleared in delayed clearing time with an otherwise intact system. For the G833lJ022 and G834lJ023 analysis, it is assumed that the Power System Stabilizers are in-service for all simulations. For existing system components, actual existing breaker clearing times were simulated. Wherever clearing times faster than existing settings are required, a notation is made. For new system components, the clearing times used in this study are as follows: Primary Clearing (Local): Delayed Clearing (Local Breaker Failure): Primary Clearing (Remote End): 3.5 cycles, 9.0 cycles, 4.5 cycles A planning margin of 1.0 cycle is required between any studied (simulated/tested) clearing time and the maximum expected clearing time of the system protection equipment (i.e. relay and circuit breaker operation). This 1.0 cycle is added to the local primary clearing time for primary clearing simulations and the local breaker failure time for breaker failure simulations. If a fault is cleared using Independent Pole Operation (IPO) breakers, it is assumed that only one phase of the breaker will fail, so that after the primary clearing time, a three phase to ground fault will become a single line-to-ground fault until it is cleared by the breaker failure relaying. No margin is added to the primary clearing times during breaker failure simulations. As shown in Appendix B, the disturbances were evaluated using the high and low generation cases described in Table 2.3.1 and 2.3.2. The following three different scenarios were studied for the interim period stability analysis: Interim 1 scenario representing the period between May 2010 (after G834lJ023) and April 20 1 1 (before G833lJ022) American Transmission Company Page 26 of 102 G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Interim 2 scenarios representing the period between May 201 1 (after G833lJ022) and the in-service date of the long term Network Upgrade: o Interim 2A: with G83314-J02213 and with existing Kewaunee substation o Interim 2B: with G83314-J02213 and with new Kewaunee substation In addition to examining angular stability of the generation, voltage recovery at Point Beach was also monitored to ensure acceptable performance under Point Beach's requirements. These requirements for 345 kV and 19 kV voltage are listed in Table 2.4.2. Results of the stability analysis are summarized in Appendix B. 3.2.1 Results of Primary Clearing of Three-Phase Faults Under Intact System Conditions The 13 faults listed in Table 3.2.1 were simulated as 3-phase faults cleared in primary time under intact system conditions. No stability problem under intact system conditions was identified under Interim 1,2A or 2B. These results are summarized in Table B. 1 in Appendix B. Table 3.2.1 - Simulated Single Circuit 3-Phase Faults Cleared in Primary Time 3.2.2 Results of Primary Clearing Three-Phase Faults on Two Circuits of a Multiple Circuit Lines The transmission system near Point Beach contains eight double circuit lines of concern (Table 3.2.2). Three phase faults were simulated on both ends of the double circuit, for a total of sixteen simulated events. No stability problem under intact system conditions was identified under Interim 1,2A or 2B. These results are summarized in Table B.2 in Appendix B. American Transmission Company Table 3.2.2 - Simulated Intact System Double Circuit 3-Phase Faults Page 27 of 102 Fault 1 Element Ill-Pt. Beach -Sheboygan Energy 345 kV I I I-Pt. Beach -Sheboygan Energy 345 kV Ill-Pt. Beach -Sheboygan Energy 345 kV Ill-Pt. Beach -Sheboygan Energy 345 kV Fault 2 Location 38.5% from POB 16.3% from SEC SEC 15.7% from SEC Element 971K51-Forest Jct.-Howard's Grove 138 kV 971K51-Forest Jct.-Howard's Grove 138 kV HOGL21-Howard's Grove-Holland 138 kV HOGL21-Howard's Grove-Holland 138 kV Location 33.9% from FJT 6.3% from HOG 46.8% from HOL 12.3% from HOG G83314-502215023 Interim Operation and Impacts Re-Study Report-RO1 3.2.3 Results of Primary Clearing Three-Phase Faults During a Prior Outage Primary fault clearing under prior outage conditions simulated all of the events listed in Table 3.2.1 under the outages listed in Table 3.2.3. Table 3.2.3 - Simulated Prior Outage Elements Interim 1 (with G834/J023, with existing Kewaunee): For interim 1, three events with generation instability were found for prior outage scenarios (Table B.3 in Appendix B). These events could be eliminated by one or more of the mitigation American Transmission Company Page 28 of 102 07/14/2009 G83314-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 options listed below. Specific mitigation options for each event can be found in Table B.3 in Appendix B. North Appleton R-304 breaker replacement with 2 cycle circuit breaker Point Beach G1 reduction under prior outage conditions To minimize generation restriction under Point Beach 345-kV bus 2-3 prior outage condition in anticipation of L121 fault, it is recommended to take the bus tie out of service during a Point Beach G1 refueling outage window. Otherwise, an operating restriction will be needed to limit Point Beach G1 to 580 MW (gross) during the POB 2-3 prior outage in anticipation of a L121 fault at Point Beach. With the North Appleton R-304 breaker replaced, Point Beach G1 will need to be restricted to 560 MW (gross) under the prior outage of 6832 (North Appleton-Fox River 345 kV line) in anticipation of R-304 fault at Kewaunee Interim 2A (with G834/J023 and G833/J022, with existing Kewaunee): For interim 2A, eleven events with generation instability were found for prior outage scenarios (Table B.3 in Appendix B). These events could be eliminated by one or more of the mitigation options listed below. Specific mitigation options for each event can be found in Table B.3 in Appendix B. North Appleton R-304 breaker replacement with 2 cycle circuit breaker, which is already required for Interim 1. Point Beach G1 and/or G2 reduction under prior outage conditions With the stability upgrades and thermal upgrades assumed in-service, Point Beach G1 and/or G2 will still need to be restricted during the following prior outage conditions in anticipation of a next critical contingency: G2 at 620 MW (gross) under the prior outage of 121 (Point Beach-Forest Junction 345 kV line) I G2 at 620 MW (gross) under the prior outage of 151 (Point Beach-Fox River 345 kV line) G2 at 600 MW (gross) under the prior outage of R-304 (Kewaunee-North Appleton 345 kV line) Both G1 and G2 at 540 MW (gross) under the prior outage of 6832 (North Appleton-Fox River 345 kV line) G2 at 580 MW (gross) under the prior outage of L-SEC31 (Sheboygan Energy Center- Granville 345 kV line) G1 at 580 MW (grossj under the prior outage of Point Beach Bus Tie 2-3 = G2 at 620 MW (gross) under the prior outage of Point Beach Bus Tie 4-5 Interim 2B (with G834/J023 and G833/J022, with new Kewaunee Substation): The Kewaunee Bus Reconfiguration project is assumed in-service for Interim 2B. The planned Kewaunee Bus Reconfiguration project will replace the existing 3 cycle non-IPO breakers at Kewaunee 345 kV with new 2 cycle IPO breakers. According to ATC System Protection, 3.5 cycles, 8.5 cycles, and 4.5 cycles will be achieved with the Kewaunee project as local primary, American Transmission Company Page 29 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 local delayed(breaker failure), and remote primary time respectively. The new clearing times at Kewaunee were considered for the simulations discussed in this section. The original 2011 in- service date of the project may need to be deferred roughly by 18 months due to project schedule constraints. For interim 2B, two events with generation instability were found for prior outage scenarios (Table B.3 in Appendix B). These events could be eliminated by one or more of the mitigation options listed below. Specific mitigation options for each event can be found in Table B.3 in Appendix B . North Appleton R-304 breaker replacement with 2 cycle circuit breaker, which is already required for Interim 1 and 2A. I Point Beach G1 and G2 reduction under prior outage conditions With the stability upgrades and thermal upgrades assumed in-service, Point Beach GI andlor G2 will still need to be restricted during the following prior outage conditions in anticipation of a next critical contingency: G2 at 600 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) G1 at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 3.2.4 Results of Three-Phase Fault Delayed (Breaker Failure) Clearing under Intact System Conditions Delayed (breaker failure) 3-phase fault clearing under otherwise intact system was simulated for the events listed in Table 3-2-4. Table 3-2 Simulated 3-Phase Faults Cleared in Delayed Time American Transmission Company Page 30 of 102 G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Interim 1 (with G834/J023, with existing Kewaunee): No stability problems were found due to breaker failure scenarios evaluated. Interim 2A (with G834/J023 and G833/J022, with existing Kewaunee): For interim 2A, three events with generation instability were found for breaker failure scenarios (Table B.4 in Appendix B). These events could be eliminated by the mitigation options listed below. More details can be found in Table B.4 in Appendix B. For fault on L111 at Point Beach with breaker failure, o Point Beach L111 SBF Breaker Failure Relay replacement with an SEL-352 and the existing Line 1 1 1 SEL-221F backup relay replacement with an SEL-421. I For fault on L 15 1 at Point Beach with breaker failure, o Point Beach L15 1 SBF Breaker Failure Relay replacement with an SEL-352 and the existing Line 15 1 SEL-22 1F backup relay replacement with an SEL-42 1 I For fault on Q-303 at Point Beach with breaker failure, o Point Beach 345 kV Circuit Breaker Addition in series with the existing 4-303 Circuit Breaker to isolate line fault in primary time2 With the stability upgrades and thermal upgrades assumed in-service, generation restriction at Point Beach G1 and G2 will not be needed under intact conditions. Interim 2B (with G834/J023 and G833/J022, with new Kewaunee Substation): For interim 2B, four events with generation instability were found for breaker failure scenarios (Table B.4 in Appendix B). These events could be eliminated by the mitigation options listed below. More details can be found in Table B.4 in Appendix B. For fault on L111 at Point Beach with breaker failure, o Point Beach Llll SBF Breaker Failure Relay replacement with an SEL-352 and the existing Line 111 SEL-221F backup relay replacement with an SEL-421, which is already required for Interim 2A For fault on L15 1 at Point Beach with breaker failure, o Point Beach L151 SBF Breaker Failure Relay replacement with an SEL-352 and the existing Line 15 1 SEL-221F backup relay replacement with an SEL-421, which is already required for Interim 2A For fault on 4-303 at Point Beach with breaker failure, o Point Beach 345 kV Circuit Breaker Addition in series with the existing 4-303 Circuit Breaker to isolate line fault in primary time, which is already required for Interim 2A For fault on R-304 at Kewaunee with breaker failure, o North Appleton R-304 Circuit Breaker Replacement with 2 cycle Circuit Breaker implemented for Independent Pole Operation, which is already required for Interim 1 and Interim 2A.

It is proposed if installing a series breaker is feasible. If it is not feasible, replace existing Position 131 SBF breaker failure relay with an SEL-352, and replace the existing Line 4-303 SEL-221F backup relay with an SEL-421 in order to improve existing breaker failure clearing time. With the relays upgraded, Point Beach G2 will need to be restricted to 600 MW at all times (with 8.0 cycle BF clearing time, previously 580 MW with 8.25 BF clearing time) fromMay 201 1 until completion of the Kewaunee reconfiguration project (roughly 18 months) American Transmission Company Page 31 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 With the stability upgrades and thermal upgrades assumed in-service, generation restriction at Point Beach G1 and G2 will not be needed under intact conditions. 3.2.5 Point Beach Bus, Generator Step Up and Auxiliary Transformer Faults 3.2.5.1 Point Beach 345 kVBus Fault Clearing Interim 1 (with G834/J023, with existing Kewaunee): No stability problems were found due to breaker failure scenarios evaluated. Interim 2A (with G834IJ023 and G833/J022, with existing Kewaunee): For interim 2A, one event with generation instability was found (Table B.5 in Appendix B). The event could be eliminated by the mitigation option listed below. More details can be found in Table B.5 in Appendix B. For single-line-to-ground fault at Point Beach 345 kV bus 2 with breaker failure at the bus tie 2-3, o Relay setting change (without Breaker Failure relay replacement) for failure of Point Beach Bus Tie 2-3 to no more than 11 cycle total breaker failure clearing time for bus faults Interim 2B (with G834/J023 and G833/J022, with new Kewaunee Substation): No stability problems were found due to breaker failure scenarios evaluated. 3.2.5.2 Generator Step-Up (GSU) Trans former Fault Clearing (TlXOl and T2XO1) No stability problems were found in the three interim scenarios due to single-line-to-ground (intact system with delayed clearing) and three phase (primary clearing under both intact and prior outage conditions) GSU faults (see Tables B.6 and B.8 in Appendix B). 3.2.5.3 Auxiliary Transformer Fault Clearing (TlX03 and T2X03) No stability problems were found in the three interim scenarios due to single-line-to-ground (intact system with delayed clearing) auxiliary transformer faults (see Table B.7 in Appendix B). For three phase (primary clearing under both intact and prior outage conditions) TlX03 and T2X03 faults, Interim 1: no stability problems were found Interim 2A: 11 events with generation instability were found (Table B.9 in Appendix B). Generator stability can be maintained for all N-1 conditions if TlX03 clearing time is reduced to 4.0 cycles and T2X03 clearing time is reduced to 4.0 cycles. Interim 2B: 10 events with generation instability were found (Table B.9 in Appendix B). Generator stability can be maintained for all N-1 conditions if TlX03 clearing time is reduced to 4.0 cycles and T2X03 clearing time is reduced to 4.0 cycles. 3.2.6 Unit Outage Kewaunee and Point Beach unit outages were also simulated (Table B.10 in Appendix B) and no stability problems were found for the three interim scenarios. American Transmission Company Page 32 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 3.2.7 Stability Results Summary The improvements in system stability required for G8331J022 and G8341J023 are provided by reductions in fault clearing times described in this report. For the G83415023 interconnection in 2010, the following stability upgrades are required: a. Improve primary clearing time at R-304 North Appleton terminal for R-304 fault at Kewaunee: - Replace the existing 3 cycle R-304 circuit breaker at North Appleton with new 2 cycle IPO circuit breaker to reduce the existing 6.5 cycle clearing time to 4.5 cycles to permit additional MW output from Point Beach unit #I under certain prior outage conditions. - Required clearing times for R-304 fault at Kewaunee: o From the existing 4.5 cycle local primary and 6.5 cycle remote primary, o To 4.5 cycle local primary and 4.5 cycle remote. For the G833lJ022 interconnection in 201 1, the following stability upgrades are required: b. Improve breaker failure clearing time at Ll 1 1 Point Beach terminal for Ll 1 1 fault at Point Beach: - Replace the existing Point Beach Llll SBF breaker failure relay with an SEL-352, and replace the existing Line 11 1 SEL-221F backup relay with an SEL-421. - Required clearing times for L111 fault at Point Beach: o From the existing 3.5 cycle local primary, 9.0 cycle local delayed, and 4.5 cycle remote primary o To 3.5 cycle local primary, 8.0 cycle local delayed, and 4.5 cycle remote primary c. Improve breaker failure clearing time at L151 Point Beach terminal for L15 1 fault at Point Beach: - Replace the existing Point Beach L151 SBF breaker failure relay with an SEL-352, and replace the existing Line 15 1 SEL-22 1F backup relay with an SEL-42 1. - Required clearing times for L 15 1 fault at Point Beach: o From the existing 3.5 cycle local primary, 9.0 cycle local delayed, and 4.5 cycle remote primary o To 3.5 cycle local primary, 8.5 cycle local delayed (8.0 cycle achieved with the upgrade), and 4.5 cycle remote primary d. Isolate Q-303 fault at Point Beach in primary time: Circuit Breaker. The upgrade will clear a Q-303 breaker failure at Point Beach in primary time. - With the series breaker addition, achieved clearing times for Q-303 fault at Point Beach: American Transmission Company Page 33 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 o From the existing 3.5 cycle local primary, 9.0 cycle local delayed, and 6.5 cycle remote primary (4.5 cycle remote primary with Kewaunee bus reconfiguration project in-service) o To 3.5 cycle local primary, 3.5 cycle local delayed (cleared in primary time), and 6.5 cycle remote primary (4.5 cycle remote primary with Kewaunee bus reconfiguration project in-service) e. Improve breaker failure clearing time of Bus Tie 2-3 for a single-line to ground fault on Point Beach Bus 2: - Change Relay setting (without Breaker Failure relay replacement) for Failure of Point Beach Bus Tie 2-3 to no more than 11 cycle total breaker failure clearing time for bus faults. - Required clearing times for single line to ground fault on Point Beach bus 2 with failure of bus tie breaker 23: o From the existing 4.75 cycle local primary and 12.5 cycle local delayed o To 4.75 cycle local primary and 11.0 cycle local delayed f. Upgrade back-up relay for better maintenance and operating flexibility during a L121 relay outage at Point Beach. - Replace L121 SEL-221F backup relay with SEL-421 to provide better maintenance and operating flexibility during a L121 relay outage. With the stability upgrades assumed in-service and the Minimum Excitation Limiter settings for Point Beach and Kewaunee units modified, generation restrictions identified for each interim period are During Interim 1 period (May 2010 after G834lJ023 - April 201 1 before G833lJ022) i. G1 at 560 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) ii. GI at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 During Interim 2A period (May 201 1 after G833lJ022 - beyond without Kewaunee project) i. G2 at 620 MW (gross) under prior outage of 121 (Point Beach-Forest Junction 345 kV line) ii. G2 at 620 MW (gross) under prior outage of 151 (Point Beach-Fox River 345 kV line) iii. G2 at 600 MW (gross) under prior outage of R304 (Kewaunee-North Appleton 345 kV line) iv. Both GI and G2 at 540 MW (gross) under prior outage of 6832 (North Appleton- Fox River 345 kV line) v. G2 at 580 MW (gross) under prior outage of SEC3 1 (Sheboygan Granville 345 kV line) vi. GI at 580 MW (gross) under prior outage of Point Beach Bus Tie 2-3 vii. G2 at 620 MW (gross) under prior outage of Point Beach Bus Tie 4-5 During Interim 2B period (May 201 1 after G833lJ022 - beyond with Kewaunee project) American Transmission Company Page 34 of 102 0711 412009 G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 i. G2 at 600 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) ii. G1 at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 American Transmission Company Page 35 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-ROl Appendix A: Power Flow Analysis Results *Note that no thermal analysis was performed as described in this report. However, the tables in Appendix A were updated based on the formula shown in Section 3.1 and the new MIS0 Generation Interconnection Procedures. American Transmission Company Page 36 of 102 G833/4-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 S2010 at 50% of peak load conditions S2010 at 100% of peak load conditions Note: For each scenario, cases with "before" and "affef G-T were studied to assess the impact of the new generators. 2 3 4 5 6 7 8 (N-I only) Load and Generation Level in Each Scenario 100% 100% 100% 20% Yes I I I I G8341J023 at loo%, G8331J022 offline, All competing generators at 20% Without 201 1 Kewaunee project (representing 2010-201 1) G8341J023 at loo%, G833IJ022 at 100% All competing generators at 20% With 201 1 Kewaunee project (representing 201 1 and beyond) G8341J023 at loo%, G8331J022 at 100% All competing generators at 100% With 201 1 Kewaunee project (representing 201 1 and beyond) G8341J023 at loo%, G8331J022 offline All competing generators at 100% Without 2011 Kewaunee project (representing 201 0-201 1) G8341J023 at loo%, G8331J022 offline All competing generators at 20% Without 201 1 Kewaunee project (representing 2010-201 1) G8341J023 at loo%, G833IJ022 at 100% All competing generators at 67% With 201 1 Kewaunee project (representing 201 1 and beyond) G8341J023 at loo%, G8331J022 at 100% All competing generators at 20% With 201 1 Kewaunee project (re~resentina 201 1 and beyond) 100% 100% 100% 100% Yes Summer 2010 Scenario 5 50% 100% offline 100% No American Transmission Company Scenario 6 Scenario 7 Scenario 8 Page 37 of 102 50% 50% 50% 100% 100% 100% offline 100% 100% 20% 67% 20% No Yes Yes G83314-J02215023 Interim Operation and Impacts Re-Study Report-RO1 Table A. 1 - IdentiJied Thermal Violations in Scenario 1 Due to G834/J023 Summer 201 0 (100% Load) Delivery to MSO for NERC Category A and B events (TDF>S%) Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE -Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. An operating guide is available to mitigate the Bain 3451138 kV transformer for Pleasant Prairie 345-kV bus tie outage. Table A.2 - IdentiJied Thermal Violations in Scenario 2 Due to G834/J023 Summer 201 0 (1 00% Load) Delivery to MSO for NERC Category A and B events (TDF>S%) Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. An operating guide is available to mitigate the Bain 3451138 kV transformer for Pleasant Prairie 345-kV bus tie outage. Table A.3 - Identzped Thermal Violations in Scenario 3 Due to G833/J022 (Assume G834/'023 online) Summer 201 0 (1 00% Load) Delivery to MSO for NERC Category A and B events Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. An operating guide is available to mitigate the Bain 3451138 kV transformer for Pleasant Prairie 345-kV bus tie outage. American Transmission Company Page 38 of 102 G83314-J02215023 Interim Operation and Impacts Re-Study Report-RO1 Table A.4 - Identzyed Thermal Violations in Scenario 4 Due to G833JJ022 (Assume G834/J023 online) Summer 201 0 (1 00% Load) Delivery to -,for NERC Category A and B events Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. An operating guide is available to mitigate the Bain 3451138 kV transformer for Pleasant Prairie 345-kV bus tie outage. Table A.5 - IdentiJed Thermal Violations in Scenario 5 Due to G834/J023 Summer 201 0 (50% Load) Delivery to MlSO for NERC Category A and B events (T.DF>S%) Center 345-kV line Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. Line rating is limited by the clearance of the existing line (51.07 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. 4. Line rating is limited by the clearance of the existing line (79.2 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. Cypress-Arcadian 345-kV line Table A.6 - IdentiJed Thermal Violations in Scenario 6 Due to G834/J023 Summer 2010 (50% Load) Delivery to MlSO for NERC Category A and B events (TDF>5%) 488 SE 499,52 sE by~uss-nluulau *a-KV Center 345-kV line line 24.0 2010s Yes No3 488 SE Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section Q 1 J.1. 3. Line rating is limited by the clearance of the existing line (51.07 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. American Transmission Company 547.3 SE Page 39 of 102 Point Beach-Sheboygan Erie 19.8 2010s Yes No" G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Table A. 7 - Identijled Thermal Violations in Scenario 7 Due to G833/J022 (Assume G834/J023 online) Summer 201 0 (50% Loaa7) Delivery to MISO for NERC Categov A and B events Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. Line rating is limited by the clearance of the existing line (51.07 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. 4. Line rating is limited by the clearance of the existing line (79.2 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. Table A.8 - Identijled Thermal Violations in Scenario 8 Due to G833/J022 (Assume G834/J023 online) Summer 201 0 (50% Load) Delivev to lWSO for NERC Category A and B events Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. Line rating is limited by the clearance of the existing line (51.07 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. 4. Line rating is limited by the clearance of the existing line (79.2 mile, 120 F for SNISE, 2156 ACSR). Required rating should be able to be met by increasing line clearance. American Transmission Company Page 40 of 102 G83314-J022lJ023 Interim Operation and hpacts Re-Study Report-RO1 Table A.9 - Identij'ied Thermal Violations Under Select NERC Category C.5 events In Each Scenario With Delivery to MISO for NERC Category C.5 events (TDF>S%) American Transmission Company Potential Solution Identified Cypress-Arcadian 345-kV line Point Beach-Sheboygan Energy Center 345-kV line Page 41 of 102 Scenario TDF (%) 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. Line rating is limited by the clearance of the existing line (79.2 mile, 120 F for SNISE, 2156 ACSR). Re- dispatching generation in the Fox Valley area may relieve the loading on the line. 4. Line rating is limited by the clearance of the existing line (51.07 mile, 120 F for SNISE, 2156 ACSR). Re- dispatching generation in the Fox Valley area may relieve the loading on the line. 488 SE 488 SE Limiting Element Required Rating,,2 Existing Rating, SE 551.6 SE 571.5 SE 501.5 SE 564.9 SE Worst Double Contingency Point Beach-Sheboygan Energy Center 345-kV line Howards Grove-Plymouth #4-Holland 138- kv line Cypress-Arcadian 345-kV line Saukville-Maple-Germantown-Bark River 138-kV line 20.61 20.73 23.67 24.08 23.23 Scenario Scenario 7 Scenario 5 Scenario 6 Scenario 7 No3 NO^

G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Table A.10 - IdentiJied Thermal Violations under Select NERC Category C.3 events In Each Scenario American Transmission Company Point Beach 345-kV bus 4-5 Point Beach-Forest North Appleton-Fox River 345-kV line Junction 345-kV line Forest Junction 3451138-kV transformer #2 North Appleton-Fox River 345-kV line Forest Junction 34511 38-kV transformer #I North Appleton-Fox River 345-kV line Point Beach 345-kV bus 2-3 Point Beach-Forest Junction 345-kV line Energy Center 345-kV line Page 42 of 102 Cypress-Arcadian 345-kV line 488 SE 674 SE 546 SE 568 SE 651 SE 556 SE 635 SE Edgewater-Cedarsauk 345-kV line Granville-Sheboygan Energy Center 345-kV line North Appleton-Fox River 345-kV line Point Beach 345-kV bus 1-2 Edgewater-Cedarsauk 345-kV line 23.85 23.37 23.44 21 .I2 22.04 - 21 .I 5 scenario 7 scenario scenario 4 scenario 5 scenario 6 scenario 7 NO^

G833/4-J022tJ023 Interim Operation and Impacts Re-Study Report-RO1 American Transniission Company Granville 3451138-kV Page 43 of 102 Granville 138-kV bus tie 5-6 Neevin-Woodenshoe 138- kV line Kewaunee 34511 38-kV transformer TI 0 Forest Junction-Kaukauna Central Tap 138-kV line Kaukauna Central- Kaukauna Central Tap 138- kV line Kaukauna Central Tap- Meadows 138-kV line 539 SE 332 SE 390 SE 293 SE 191 SE 169SE 567 SE 594 SE 580 SE 400 SE 342 SE 357 SE 415 SE 342 SE 335 SE 410 SE - 449 SE 407 SE 359 SE 364 SE 413 SE 194 SE 220 SE 190SE Cypress-Arcadian 345-kV line Granville 345-kV bus tie 1-2 Granville-Sheboygan Energy Center 345-kV lineNorth Appleton-Fitzgerald 345-kV line Point Beach-Sheboygan Energy Center 345- kV line North Appleton-Fitzgerald 345-kV line North Appleton-Fox River 345-kV line North Appleton-Kewaunee 345-kV line No9 Nolo No" No12 ~0'3 ~014 16.67 23.47 22.1 9 13.98 13.88 13.65 14.06 14.90 14.48 13.57 13.37 10.51 10.41 10.1 0 10.52 5.73 5.94 4.48 scenario 7 scenario 5 scenario 7 scenario 1 scenario 2 scenario 3 scenario 4 ' scenario 5 scenario 7 scenario 1 scenario 2 scenario 1 scenario 2 scenario 3 scenario 4 scenario 3 scenario 4 scenario 4 G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Granville-Sheboygan Energy Center 345-kV line North Appleton-Fitzgerald 345-kV line Potential Solution Identified Mears Corners- Woodenshoe 138-kV line TDF (%) Worst Double Contingency Limiting Element Sunset Point-Mears Corners 138-kV line Lake Park-Darboy 138-kV line Scenario 287 SE Darboy-Forest Junction 138-kV line 407 SE North Appleton-Fox River 345-kV line North Appleton-Kewaunee 345-kV line Existing Rating, 287 SE 293 SE 293 SE 366 SE 372 SE H 16.22 16.46 Required Rating,,2 7 302 SE 294 SE scenario 2 scenario 3 302 SE 388 SE 345 SE 350 SE 393 SE 401 SE Lake Park-City Limits 138- kV line 9.59 scenario 2 No18 9.48 scenario 3 Point Beach 345-kV bus 1-2 North Appleton-Fitzgerald 345-kV line Point Beach-Sheboygan Energy Center 345- kV line Kewaunee-East Krok 138- kV line 8.78 scenario 2 I No" North Appleton-Fitzgerald 345-kV line Granville-Sheboygan Energy Center 345-kV line North Appleton-Fitzgerald 345-kV line 293 SE 287 SE 318 SE 394 SE 1 10.83 I scenario 3 I 14.29 14.27 299 SE 304 SE 347 SE 338 SE 9.38 scenario 4 11 9.39 scenario 1 No47 13.75 9.39 9.39 9.27 American Transmission Company scenario 5 scenario 7 407 SE Page 44 of 102 ~015 scenario 4 scenario 1 scenario 2 scenario 3 No16 10.83 scenario 4 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-ROl American Transmission Company Melissa-Tayco 138-kV line Melissa-Meadows 138-kV line Forest Junction-Fox River 345-kV line Elkhart Lake-G61 1 Tap 138-kV line Elkhart Lake-Saukville 138- kV line North Appleton-Kewaunee 345-kV line Granville 3451138-kV transformer #I G59O-Tecumseh Rd 138-kV line Page 45 of 102 143 SE 169 SE 1096 SE 96 SE 88 SE 1071 SE 478 SE SE 158 SE 162 SE 182 SE 182 SE 1236 SE 1236 SE 102 SE 142SE 174 SE 134 SE 164 SE 108 SE 150 SE l4 SE 141 SE 171 SE 536 SE 181 SE 203 SE 187 SE North Appleton-Fox River 345-kV line North Appleton-Kewaunee 345-kV line North Appleton-Fox River 345-kV line Point Beach 345-kV bus tie 3-4 Cypress-Arcadian 345-kV line Granville-Sheboygan Energy Center 345-kV line Cypress-Arcadian 345-kV line Point Beach 345-kV bus 1-2 Granville-Sheboygan Energy Center 345-kV line Cypress-Arcadian 345-kV line Point Beach 345-kV bus 1-2 Cypress-Arcadian 345-kV line Granville-Sheboygan Energy Center 345-kV line North Appleton-Fox River 345-kV line Granville 345-kV bus tie 1-2 Cypress-Arcadian 345-kV line Granville-Sheboygan Energy Center 345-kV line Cypress-Arcadian 345-kV line 4.39 4.27 4.37 4.37 97.08 96.1 5 5.00 - 5,10 5.10 5.00 5.00 4.58 4.49 4.69 4.38 41.35 16.77 5.10 5.31 4.90 scenario 2 scenario 3 scenario 4 scenario 4 scenario 3 scenario 4 scenario 3 scenario scenario 5 scenario 6 scenario 7 scenario 4 scenario 5 scenario 6 scenario 7 scenario 4 scenario 4 scenario 4 scenario 5 scenario 7 Yesz1 Noz2 ~023 N024 ~025 No26 No27 Nozs G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. The required ratings are estimated values using the formula described in Section 3.1. 3. Line rating is limited by the trap (1071 MVA SE) and breakers (1132 MVA SE) at Kewaunee. A project is proposed for reconfiguring the existing Kewaunee switchyard by June 2011 which includes rebuilding the existing 345 kV substation. 4. Line rating is limited by the clearance of the existing line (30.75 mile, 146F, 167F, 275F for SE, 2156 ACSR). 5. Transformer rating is limited by the transformer (5001676 MVA for SNISE). 6. Line rating is limited by the clearance of the existing line (51.07 mile, 120 F for SNISE, 2156 ACSR). Re- dispatching generation in the Fox Valley area may relieve the loading on the line. 7. Line rating is limited by the clearance of the existing line (79.2 mile, 120 F for SNISE, 2156 ACSR). Re- dispatching generation in the Fox Valley area may relieve the loading on the line. 8. Transformer rating is limited by the transformer (504 MVA SE) and the equipment such as CT (478 MVA) and breaker associated with the transformer. 9. Rating is limited by the conductors (539 MVA SE) and breaker (566 MVA SE). ine rating is limited by the clearance of the existing line (4.04 mile, 2001230F for SNISE, 795 ACSR). Re- spatching generation in the Fox Valley area may relieve the loading on the line. 11. Transformer rating is limited by the transformer (504 MVA SE). Re-dispatching generation in the area will relieve the loading on the transformer. A project is proposed for reconfiguring the existing Kewaunee switchyard by June 2011 which includes adding a second 3451138 kV transformer in parallel with the existing TI0 transformer. 12. Line rating is limited by the clearance of the existing line (9.25 mile, 2001200F for SNISE, 795 ACSR). Re- dispatching generation in the Fox Valley area may relieve the loading on the line. 13. Line rating is limited by the switch (199 MVA SE) at Kaukauna Central Tap and the 336 ACSR jumper (191 MVA SE) at Kaukauna Central. Meyer Rd-Mullet River Tap- Lyndon 138-kV line Fredonia-Lyndon 138-kV line Edgewater-Saukville 345- kV line G611 Tap-Forest Junction 138-kV line American Transmission Company Page 46 of 102 0711 412009 169 SE 169 SE 653 SE 96 SE 190 SE 17' SE 179 SE 167 SE 698 SE 693 SE 117 SE Io3 SE Point Beach 345-kV bus 1-2 Cypress-Arcadian 345-kV line Cypress-Arcadian 345-kV line Point Beach-Sheboygan Energy Center 345- kV line Point Beach 345-kV bus 1-2 Cypress-Arcadian 345-kV line 5.92 5.42 5.41 5.21 13.98 13.75 5.20 4.69 scenario 5 scenario 7 scenario 5 scenario 7 scenario 5 scenario 7 scenario 6 scenario 7 ~030 ~031 ~032 No33 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 14. Line rating is limited by the clearance of the existing line (7.83 mile, 2001200F for SNISE, 336 ACSR). Re- dispatching generation in the Fox Valley area may relieve the loading on the line. 15. A line clearance study may be needed to validate line ratings. It is assumed that the rating is limited by the clearance of the line. 16. A line clearance study may be needed to validate line ratings. It is assumed that the rating is limited by the clearance of the line. 17. The rating of Lake Park-Darboy-Forest Junction 138 kV line is limited by the line clearance (1 1.73 mile, 200F SNISE, 795 ACSR) and jumpers (332 MVA SE) at Lake Park. Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 18. The rating of Lake Park-City Limits 138 kV line is limited by the line clearance (2.25 mile, 200F SNISE, 795 ACSR) and jumper (332 MVA SE) at Lake Park and jumper (300 MVA SE) at City Limits. Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 19. The rating of the line is limited by the line conductor and terminal equipment such as CTs, meters, traps, switches and East Krok breaker. 20. The line rating is being validated. There is potential for a higher line rating than the required ratings. 21. A project is being proposed to uprate the line to 198 MVA SE for near term. A provisional project is scheduled for 2016 to uprate the line to 229 MVA SE. 22. A line clearance study may be needed. It is assumed that the rating is limited by the clearance of the existing line (1.07 mile, 336ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 23. The rating is limited by the clearance of the existing line (1 1.32 mile, lO8F SNISE, 21 56 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 24. The rating is limited by the clearance of the existing line (28.4 mile, 167F for SNISE, 410 ACSR Penguin). It is being increased to 112 MVA due to requirements of G611 and G92 generation interconnection studies. 25. Line rating is limited by the clearance of the existing line (26.6 mile - 120 F for SNISE - 477 ACSR, 7.13 mile - 167 F for SNISE - 410 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 26. Line rating is limited by the trap (1071 MVA SE) and breakers (1132 MVA SE) at Kewaunee. A project is proposed for reconfiguring the existing Kewaunee switchyard by June 201 1 which includes rebuilding the existing 345 kV substation. 27. Transformer rating is limited by the transformer (504 MVA SE) and the equipment such as CT (478 MVA) and breaker associated with the transformer. 28. The rating is limited by the clearance of the existing line (200F SNISE, 336 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 29. The rating is limited by the clearance of the existing line (5 mile, 200F SNISE, 336 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 30. The rating is limited by the clearance of the existing line (18.93 mile, 200F SNISE, 336 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 31. The rating is limited by the clearance of the existing line (12.94 mile, 200F SNISE, 336 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 32. Line rating is limited by the clearance of the existing line (26.6 mile - 120 F for SNISE - 477 ACSR, 7.13 mile - 167 F for SNISE - 410 ACSR). Re-dispatching generation in the Fox Valley area may relieve the loading on the line. 33. Line rating is limited by the clearance of the existing line (28.4 mile, 167F for SNISE, 410 ACSR). American Transmission Company Page 47 of 102 G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table A. I I-Maximum Allowable Generation for G834/J023 and G833/J022 in Each Scenario without Network Upgrades, for Injection Limits I Point Beach-Sheboygan Energy Center 345-kV line I CypressArcadian 345-kV line I I 0 None Limiting Element Scenario Worst Contingency I I I None Cypress-Arcadian 345-kV line G833lJ022 and G834N023 Maximum Output (MW) 1 Point Beach-Sheboygan Energy Center 345-kV line Point Beach-Sheboygan Energy Center 345-kV line I Point Beach-Sheboygan Energy Center 345-kV line I Cypress-Arcadian 345-kV line I Scenario 8 1 0 Scenario 1 through 4 Point Beach-Sheboygan Energy Center 345-kV line Cypress-Arcadian 345-kV line Notes: 1. G833-4 ISIS report dated Dec. 18,2008 shows 0 MW allowed. 106 Cypress-Arcadian 345-kV line Cypress-Arcadian 345-kV line Table A. 12-Identified Thermal Violation Due to G834/J023 and G833/J022 in Scenario 5 Point Beach-Sheboygan Energy Center 345-kV line 0 Scenario 6 Scenario 7 14.6 (G834 1J023 only) 0 Each Scenario without Network Upgrades,for Injection Limits Notes: 1. SN - Summer Normal, SE - Summer Emergency, WN - Winter Normal and WE - Winter Emergency. 2. Includes provision for 5% TRM. Limiting Element Point Beach-Sheboygan Energy Center 345-kV line Cypressdrcadian 345-kV line Table A.13-IdentiJied Voltage Violation Due to G834/J023 and G833/J022 in No steady-state analysis was performed because of the reasons described in Section 1.1 488 SE 488 SE American Transmission Company Worst Contingency Existing Rating (MVA) I Page 48 of 102 Required Rating . (MVA)I.2 From previous From Revised G833,834 ISIS Table A.5 to A.8 report 569.5 SE (A.5) 547.3 SE (A.5) 516 SE 579 SE (north) 513 SF (nn11th1 Cypress-Arcadian 345-kV line Point Beach-Sheboygan Fnemv Center 345-kV line

NRC 2009-0082, Point Beach, Units 1 and 2 - Transmittal of Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study

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