NRC 2009-0114, Transmittal of Background Information to Support License Amendment Request 261 Final Interconnection System Impact Study

Transmittal of Background Information to Support License Amendment Request 261 Final Interconnection System Impact Study

ML093200067
Person / Time
Site:	Point Beach
Issue date:	11/13/2009
From:	Meyer L Point Beach
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NRC 2009-0114
Download: ML093200067 (135)

Text

EN?- POINT BEACH November 13,2009 NRC 2009-0114 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 Sup~ort License Amendment Request 261 Final lnterconnection System Impact Study

References:

( 1 FPL Energy Point Beach, LLC, Letter to NRC, dated April 7, 2009, License Amendment Request 261, Extended Power Uprate (ML091250564)

(2) FPL Energy Point Beach, LLC, Letter to NRC, dated April 8,2009, Transmittal of Background Information to Support License Amendment Request 261, lnterconnection System Impact Study (ML091000647)

To support NRC review of the Point Beach Nuclear Plant (PBNP) License Amendment Request 261 for an Extended Power Uprate (EPU), NextEra Energy Point Beach, LLC (NextEra) is providing the "Final G833lG834 with additional 6 MW per unit (J022lJ023) lnterconnection System Impact Study Report, 118 MW Nuclear Generation Increase (59 MW each at Point Beach Generators Iand 2), Manitowoc County, Wisconsin," dated October 2, 2009.

The study was prepared by American Transmission Company (ATC), the transmission grid ownerloperator for PBNP. The report provides the system impact 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. The 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 Summary of Regulatory Commitments The final Interconnection System Impact Study transmitted via this letter fulfills Regulatory Commitment 2 of Reference (1).

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

_- l i a r r y Meyer

' Site Vice President Enclosure cc: Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW

ENCLOSURE 1 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT UNITS IAND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE FINAL G833lG834 WITH ADDITIONAL 6 MW PER UNIT (J022lJ023)

INTERCONNECTION SYSTEM IMPACT STUDY REPORT 118 MW NUCLEAR GENERATION INCREASE (59 MW EACH AT POINT BEACH GENERATORS I AND 2)

MANITOWOC COUNTY, WISCONSIN DATED OCTOBER 2,2009 132 pages follow

G833/4-JO22/3ISIS Report AMERICAN RANSMISSION COMPANY @

FINAL G833 / a 3 4 with additional 6 MW per unit (J02WJ023)

Interconnection System Impact Study Report 118 M W Nuclear GeneratTon Increase (59 NW each at Point Beach Generators 1 and 2)

Manitawoc County, Wisconsin G833 MIS0 Queue #39297-01 JQ22- MISO Queue Date (1/16/2009)

G834 MISO Queue #3929742 3023 MISO Queue Date (lj14120W)

October 2,2009 American Transmission Company, LLC PrepuredBy:

Sun W w k brig, Planning Sue Micheb, Protection Mathew Westrich, Maintenance Michael Anderson, Engineering Approved By:

David K. CuZtum, P.E.

Team Lads$ G-T InteK;onnectiom & Special Studies

G83314-502213 ISIS Report Table of Contents EXECUTIVE

SUMMARY

.........................................................................................................................................4

1.

SUMMARY

....................................................................................................................................................... 7 2 . CRITERIA. METHODOLOGY AND ASSUMPTIONS ............................................................................. 23 2.1 STUDYCRITERIA ........................................................................................................................................ 23 2.2 STUDYMETHODOLOGY .............................................................................................................................. 23 2.2.1 Cotnpeting Generation Reqzrests............................................................................................................... 23 2.2.2 Power Flow Analysis Methods ............................................................................................................. 24 2.2.3 Stability Analysis ....................................................................................................................................... 24 2.3 BASECASES............................................................................................................................................... 24 2.3.1Power Flow Analysis (Steady State) .......................................................................................................... 24 2.3.2Stability Analysis (Dynatnics).................................................................................................................... 25 2.3.3 Deliverability Analysis ...............................................................................................................................25 2.4 GENERATION FACILITY .............................................................................................................................. 25 2.4.1 Generating Facility Modeling ................................................................................................................... 25 2.4.2 Voltage Sag Criteria.................................................................................................................................. 26 2.4.3 Synchronizing and Energization of Szrbstation/Generator Step- Up Transformers....................................26 2.4.4 Unit Black Start and ATC Black Start Plan Participation......................................................................... 27 3 . ANALYSIS RESULTS ................................................................................................................................. 28 3.1 POWERFLOWANALYSIS RESULTS............................................................................................................. 28 3.1.1 Power Factor Capability and Voltage Requirenzents ................................................................................ 28 3.1.2Results of Intact Systetn and Single Contingencies (N-I) ..................................................................... 28 3.1.3 Reszrlts of Dozrble Contingencies (N-1-1) .................................................................................................. 29 3.2 STABILITY ANALYSIS RESULTS................................................................................................................ 1 3.2.I Results of Primary Clearing of Three-Phase Faults zrnder Intact Systetn Conditions............................... 32 3.2.2Results ofprimary Clearing SLG Fazrlts on Two Circzrits of a Mzrltiple Circuit Lines ............................. 32 3.2.3Results of Pritnaty Fault Clearing During a Prior Outage ....................................................................... 33 3.2.4Results of Three-Phase Fault Delayed Clearing zrnder Intact Systetn Conditions .................................... 34 3.2.5Point Beach Bzrs, Generator Step Up and Azrxiliaty Transforiner Faults.................................................. 35 3.2.6Unit Outage ............................................................................................................................................... 36 3.2.7Stability Results Sztmlnary ......................................................................................................................... 36 3.3 SHORT-CIRCUIT & BREAKER DUTYANALYSIS RESULTS........................................................................... 36 3.4 DELIVERABILITY ANALYSIS RESULTS ........................................................................................................ 36 APPENDIX A: POWER FLOW ANALYSIS RESULTS .................................................................................... 38 APPENDIX B: OPERATION RESTRICTIONS ................................................................................................... 51 APPENDIX C: STABILITY ANALYSIS RESULTS ............................................................................................. 53 APPENDIX D: SHORT CIRCUIT I BREAKER DUTY ANALYSIS RESULTS ...............................................68 APPENDIX E: DELIVERABILITY ANALYSIS RESULTS ............................................................................... 71 APPENDIX P: STUDY CRITERIA ...................................................................................................................... 72 American Transmission Company Page 2 of 132 10/2/2009

G83314-502213 ISIS Report APPENDIX G: TYPICAL PLANNING LEVEL COST ESTIMATES ................................................................76 APPENDIX H: ALTERNATIVES CONSIDERED ............................................................................................... 79 APPENDIX I: MINIMUM EXCITATION LIMITS AT POINT BEACH AND KEWAUNEE WITH PROPOSED SOLUTION .......................................................................................................................................128 APPENDIX J: PROJECT ONE LINE DIAGRAM OF PROPOSE SOLUTION (FIX 11 AND UPRATING NEW EAST-CEDARSAUK 345 KV LINE) .......................................................................................................... 130 American Transmission Company Page 3 of 132

G83314-502213 ISIS Report Executive Summary The Interconnection System Impact Study (ISIS) report for Midwest Independent System Operator (MISO) Generation Interconnection Requests identified as Projects G833, Queue

1. 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 submitted additional requests of 6 MW per unit (MIS0 Generator Interconnection Requests J022 and 5023) and the original dynamic models of the generators were modified. As a result, the requested additional generation is 59 MW for each of the Point Beach Nuclear generators with a total increase in plant output of 118 MW over the existing Interconnection Agreement. 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 31, 2010 for G834lJ023 (Point Beach Unit 1) and May 31, 201 1 for G833JJ022 (Point Beach Unit 2).

This ISIS report identifies the Interconnection Facilities and Network Upgrades needed to facilitate the requested interconnection for either Energy Resource Interconnection Service (ERIS) or Network Resource Interconnection Service (NRIS). For interconnection, the good faith estimate of cost for the Network Upgrades identified in this report is approximately between $13 1 million and $246 million. The cost range of the proposed project has been updated from the draft report to a range of costs due to the uncertain condition of the existing 3451138 kV double circuit structures reported from ATC Asset Management in their recent review of the draft system impact study. The condition of the existing 3451138 kV structures will be evaluated as part of the detailed engineering study during the Facilities Study. The preliminary, good faith estimate of schedule indicates that all of the Network Upgrades can be in-sewice within 8-10 years of an executed Generator Interconnection Agreement.

Although there are no required Interconnection Facilities for this project, ATC recommends installing 345 kV circuit breakers on the high side of each of the two 34Y13.2 kV auxiliary transformers to prevent a breaker failure event during auxiliary transformer faults from tripping Point Beach generation. Although a fault on these transformers does not cause the local generators such as Point Beach and Kewaunee to lose synchronism with the required Network Upgrades assumed in-service, ATC still recommends that the Interconnection Customer reduce the primary fault clearing time for the Point Beach auxiliary transformer from 5.1 cycles to 4.0 cycles to prevent these faults from causing the instability of the local generators until the proposed solution is in service. Section 1.3 describes the reliability benefits of these recommendations.

This study was performed with the proposed Power System Stabilizers at Point Beach in-service.

The Interconnection Customer must commission a tuning study for the new Point Beach Power System Stabilizers (PSSs) as described in Section 1.3 of this report.

The Interconnection Customer will have to submit the Definitive Planning Continuation milestones (M3) prior to entering the Facilities Study for this project. An Interconnection American Transmission Company Page 4 of 132 101212009

G83314-502213 ISIS Report Facilities Study will specify in more detail the time and cost of the equipment, engineering, procurement and construction of the system upgrades identified in the ISIS report.

American Transmission Company Page 5 of 132

G83314-502213ISIS Report wrzd ~u.wounffin~

System with Propomd Solutian American Transmission Company Page 6 of 132

G833/4-502213 ISIS Report This study evaluates the impact of the proposed 118 MW increase in generation at the Point Beach nuclear plant which is connected to the 345 kV transmission system in Manitowoc County, Wisconsin. This is the re-study of the Interconnection System Impact Study (ISIS) for Generator Interconnection Requests G833 and G834 (53 MW per unit, Queue #39297-01 and

1. 39297-02) and the ISIS for requests 5022 and 5023 (6 MW per unit, Queue dates: January 14 and 16,2009). This study incorporates the updated dynamic models of the generator provided by the Interconnection Customer. The customer has requested the following dates for the various stages of interconnection:

e Interconnection Facilities In-Service (Backfeed) Date: Existing facility, not applicable.

e Initial Synchronization Date: Not supplied e Commercial Operation Date: May 31, 2010 for G83415023 and May 31, 201 1 for G83315022.

Due to the proposed commercial operation dates of the Interconnection Requests (i.e. May 2010 for Unit #I at Point Beach and May 201 1 for Unit #2 at Point Beach), a study report is posted describing the "interim" system improvements that can form the basis for a Temporary Interconnection Agreement until the Network Upgrades described in this ISIS report can be completed. The "Interim Operation" Re-study Report can be found at:

http://oasis.midwestiso.org/documents/ATC/Cluster8-Queue.htm1.

The Interim Operation Re-study Report examines the period between the expected commercial operation date and the expected completion date of a long term solution to identify the possible unit restrictions andlor interim system improvement needed during the interim periods. After implementation of the upgrades needed for "interim" operation, there are several issues that must be addressed to ensure that the Point Beach generation increase is reliable beyond temporary operation. The issues are:

(1) Generator instability due to the isolation of Point Beach Generator 1 on L l l l (Point Beach-Sheboygan) which occurs when Point Beach 345 kV breaker 2-3 is out of service and L121 (Point Beach-Forest Junction 345 kV) trips, (2) Generator instability due to the outage of 6832 (Fox River-North Appleton) followed by a fault on R-304 (Kewaunee-North Appleton),

(3) Most significantly, limitations on Point Beach and Kewaunee generating unit reactive power output at all hours. Generator instability was identified for fault conditions when Point Beach and Kewaunee units produce relatively small reactive power output (over-excitation) or absorbs reactive power fiom transmission system (under-excitation).

Reactive power output from a synchronous machine has an impact on the transient stability of the unit. Typically, the lower the excitation on a generating unit, the less stable the unit tends to be under a fault condition. The results of the 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. The units may not be allowed to reduce their MVAR outputs, reducing their effectiveness in controlling system voltage.

American Transmission Company Page 7 of 132

G83314-502213 ISIS Report The interim operation study identified that, for temporary operation, Issue (1) and (2) should be mitigated by reducing generation at Point Beach to 580 MW (GI gross) and 600 MW (G2 gross) respectively, and Issue (3) should be mitigated by maintaining MVAR output from Point Beach and Kewaunee to a certain level through the use of Minimum Excitation Limiter settings. Issue (1) may be addressed by a long term solution such as reconfiguring the existing Point Beach substation such that Point Beach Unit #1 cannot be isolated on 345-kV line L111. However, a more robust long term solution such as a new 345 kV line andor substation will be needed to address Issue (2) and Issue (3). Issues (2) and (3) can not be solved by reconfiguring Point Beach because the issues are primarily due to the limited number of 345-kV outlets out of Fox Valley area for the amount of generation located in this area.

This System Impact Study is performed to identify a long-term solution that addresses the following needs andor provides benefits:

Addresses the generation instability issues under prior outage conditions, Ensures a wider operating envelope for the local transmission system and the interconnected generators by permitting generating unit operation at unity or under-excited conditions, Provides better maintenance and operations flexibility during planned or unplanned transmission outage conditions by tying together critical transmission elements in strategic locations and, possibly, providing an additional transmission outlet, and Relieves loadings under intact and contingency conditions on the existing 138 kV and 345 kV lines running from Fox Valley area to the south by providing an additional transmission outlet.

This study also identifies steady state system thermal and voltage impacts, system angular stability impact and the circuit breaker fault duty impacts associated with the interconnection of G833lJ022 and G83415023. These interconnection system impacts are based on AC power flow analyses, transient stability analysis and short circuit analysis. This study also identifies the Network Upgrades and Interconnection Facilities required to eliminate any unacceptable system impacts and to allow the generator to interconnect to the system. Preliminary, good faith estimates of cost and schedule will be provided for the identified Network Upgrades.

The Generator Interconnection Procedures permit the Interconnection Customer to request specific Backfeed, Initial Synchronization and Commercial Operation Dates. G833lJ022 and G834lJ023 involve increasing output from existing generators and the required Interconnection Facilities already exist. The Interconnection Facilities Study process will include a high-level evaluation of any known scheduled outage requirements. The scheduled outage requirements and associated evaluations will continue to be refined as project implementation details progress.

The proposed increase in Point Beach generation will be obtained by increasing the thermal power of the reactor. This will require the rewinding of the stator and rotor of the existing Point Beach generators. No changes to the Point Beach substation layout are required to "interconnect" the increased generation since the units are already connected to the transmission grid. Figure 1.1 shows the expected 345 kV transmission system topology near the Point Beach substation for the 201 1 time frame, including the required Network Upgrades that eliminates the stability issues found with the increased Point Beach generation.

American Transmission Company Page 8 of 132 10/2/2009

G83314-502213 ISIS Report Note that Figure 1.1 shows the existing substation layout for the existing Generating Facilities.

Figure 1.1 provides a conceptual, equivalent depiction of the Interconnection Customer's Generating Facilities. The Interconnection Customer will need to supply Generating Facility diagrams for the Generator Interconnection Agreement.

Required construction outages to build the new 345 kV substations and the new 345 kV and 138 kV lines will be reviewed further in the Interconnection Facilities Study, along with outages required for the other identified Network Upgrades. Any requested outage must be cleared through an ATC screening process and be formally submitted (outage is logistically supported with a work order and associated construction resources) to the Midwest IS0 for approval. The Midwest I S 0 studies outages based on the submitted queue position within their outage scheduling database.

In order for G833lJ022 and G834lJ023 to interconnect, the required Network Upgrades and Interconnection Facilities must be completed.

1.1 Injection ~ i m i t s '

The injection limits are identified in Tables A.l and A.2 in Appendix A and are listed below.

The thermal study identified no steady-state thermal violations for NERC Category A (intact system).

The study identified two steady-state thermal violations for NERC Category B (N-1) events that meet the criteria for injection limits:

1. Point Beach-New North Switching Station 345 kV Line (Point Beach-Sheboygan Energy Center L l 11 east)

2. New East substation-Cedarsauk 345 kV line (Edgewater-Cedarsauk 796L41 southern section)

As documented in the G83314-J02213 Interim Operation Re-study Report, the Point Beach-Sheboygan Energy Center line will be uprated independently by ATC for improvement due to MIS0 energy market impacts.

The Network Upgrades for these injection limits are described in Section 1.4 and are required for either ERIS or NRIS for the full 118 MW of requested interconnection service of G83314-502213.

' See Appendix F, Section F3.1 for a definition of what transmission overloads qualify as injection limits.

American Transmission Company Page 9 of 132

G83314-502213 ISIS Report NORTH KEWAUNEE TtO Requred N6tviurk U r n * (345 kV)

- --rkU-(l=w

-Fubn FtommlwmBrt

+ +

andFW)(ofkfteqnnrc To Areadlrn Figure 1.1 - Conceptual One Line Diagram of the 201 1 System with G833/J022 and G834/J023 I

and Required Network Upgrade American Transmission Company Page 10 of 132

G83314-502213 ISIS Report 1.2 Generating Facility Operation Restrictions Various potential thermal constraints are shown in Table A.7 and A.8 in Appendix A for Category C.3 events. In general, re-dispatching generators in the local 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.

Three potential thermal constraints were found for Category C.5 event, which is the outage of two circuits on a multi-circuit tower. No operating restrictions are listed for these thermal constraints because the New East-Cedarsauk 345 kV line shown in Table A.9 will be uprated as one of the Network Upgrades required for G83314-502213 and the other two constraints, which can be mitigated by local generation redispatch, are not considered as thermal constraints due to G83314-J02213.

With all Network Upgrades assumed in-sewice and the revised Minimum Excitation Limiter settings for Point Beach and Kewaunee units maintained at the level described in Appendix I, there are no generation restrictions due to stability issue for the conditions studied.

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 G833IJ022 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 each upgraded unit. 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.

Auxiliary Transformers TlX03 and T2X03 High-Side Breakers ATC recommends that new 2 cycle 345 kV circuit breakers and adequate relaying be installed on the high-side of Point Beach auxiliary transformers TlX03 and T2X03 to avoid a trip of the Point Beach units for a breaker failure event (Table 1.4).

The current configuration of the Point Beach substation is shown in Figure 1.2. Due to the current design where the Bulk Electric System equipment is providing the primary fault protection for the TlX03 and T2X03, the following events would occur for a fault on the TlX03 or T2X03 equipment, including a fault at the 13.8 kV level:

American Transmission Company Page 11 of 132

G83314-J02213 ISIS Report

1. ForafaultonTlX03,

a. With normal clearing, 345 kV bus #1 will be removed from service and result in the loss of the network connection to Sheboygan Falls Energy Center substation via 345 kV line L111.

b. With delayed clearing on 345 kV bus tie 1-2,345 kV bus #1 and 345 kV bus #2 will be removed from service and result in the loss of the following elements:

i. 345 kV line Ll 11 to Sheboygan Falls Energy Center substation, ii. 345 kV line L121 to Forest Junction substation and iii. Point Beach generating unit #l .

2. For a fault on T2X03,

a. With normal clearing, 345 kV bus #5 will be removed from service and result in the loss of the network connection to Fox River substation via 345 kV line L15 1.

b. With delayed clearing on 345 kV bus tie 4-5,345 kV bus #4 and 345 kV bus #5 will be removed from service and result in the loss of the following elements:

i. 345 kV line L15 1 to Fox River substation and ii. Point Beach generating unit #2.

The addition of new 2 cycle 345 kV circuit breakers will eliminate the loss of 345 kV (i.e. Bulk Electric System) elements for the more probable normal fault clearing events and will substantially reduce the impact of certain delayed clearing events by eliminating a trip of a Point Beach generating unit. ATC recommends these circuit breaker additions to improve the reliability of the transmission network and power plant interconnection, bringing the substation configuration closer to current ATC design standards.

Reduction of Auxiliary Transformers TlX03 and T2X03 Primary Clearing Times ATC also recommends, regardless of whether or not the recommended TlX03 and T2X03 2 cycle 345 kV circuit breakers are installed, that the existing 5.1 cycle auxiliary transformer 345 kV fault primary clearing time should be reduced to 4.0 cycle to prevent loss of synchronism on the Point Beach and Kewaunee generators for high side faults on these auxiliary transformers cleared in primary time until the proposed solution in place (see G83314-502213 Interim Operation Study Report). With the proposed solution and the planned Kewaunee bus reconfiguration assumed in-service, no stability issues were identified without the recommended circuit breakers. The existing primary clearing time is acceptable with the present system configuration and generation levels. With the addition of G83314-502213, failure to reduce these fault clearing times to the recommended times would result in loss of synchronism on the generators for the faults until completion of the proposed solution.

American Transmission Company Page 12 of 132

G833/4-J02213 ISIS Report FJT KEW FOX SEC 1 Figure 1.2 - Existing Point Beach Substation Conjigzrration Power Factor Capabilitv The G83314-502213 customer has submitted a generating facility design capable of maintaining power delivery at continuous rated power output at the POI (Point of Interconnection) at all power factors over 0.95 leading (when a facility is consuming reactive power from the transmission system) to 0.94 lagging (when a facility is supplying reactive power to the transmission system). For the steady-state scenarios examined, study results indicate that satisfactory system performance is achieved by supplying a range of -21 1.3 to 233.4 Mvars (gross) to the system. In addition, study done with minimum excitation limits assumed in-service also showed adequate results.

Plant Specific Voltage Requirements The Point Beach Nuclear Plant 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). A new high voltage limit of 360 kV has been proposed by the plant and incorporated into this study.

Any voltage outside the maximum permissible range is a voltage limitation as described in the plant technical specifications.

1.4 Network Upgrades In addition to the Network Upgrades listed below, both Point Beach units and the Kewaunee unit will be required to maintain the revised Minimum Excitation Limit settings on these units to ensure stable operation for a variety of fault conditions. The proposed limits are lower than the settings required in the Interim Operations Restudy Report and can be found in Appendix I.

American Transmission Company Page 13 of 132 10/2/2009

G83314-J022/3 ISIS Report Existing Network Upgrades Required Before G83314-502213 Operation (See Table 1.1)

Injection Upgrades Analysis prior to G833lJ022 and G834lJ023 found no required system upgrades due to injection limits.

Voltage Related Analysis prior to G833lJ022 and G83415023 found no unacceptable voltages.

Breaker Duty Related No existing over-duty circuit breaker conditions were found to be significantly (i.e. 21%)

impacted prior to the addition of G833lJ022 and G834lJ023. Therefore, no over-dutied circuit breakers are identified in Table 1.1.

Network Upgrades Required Due to G833lJ022 and G834lJ023 Addition (See Table 1.2.a)

The preliminary, good faith estimate of schedule indicates that all of the Network Upgrades can be in-service within 8-10 years of an executed Generator Interconnection Agreement.

Stability Upgrades (see Table 1.2.a)

To achieve adequate system stability with G833lJ022 and GI33415023 in service, the following Network Upgrades are required. See Table 1.2.a for more details:

1) An eight position (expandable to twelve) 345 kV and six position (expandable to ten) 138 kV breaker-and-a-half scheme substation located at the intersection of the existing 345 kV lines W- 1 (Edgewater-South Fond Du Lac) and L-SEC3 1 (Sheboygan Energy Center-Granville). A new 3451138 kV transformer capable of at least 5001625 MVA for SN and SE needs to be installed at the new substation. The existing 345 kV lines W-1, L-SEC31 and 796L41 (Edgewater-Cedarsauk) are looped into the new substation. The existing 138 kV line X-57 (South Sheboygan Falls-Mullet River) and the line from Holland are looped into the substation. New 138 kV line from Plymouth is terminated at the substation (see also item 6).

2) A six position (expandable to ten) breaker-and-a-half scheme substation located near the intersection of the existing 345 kV line L l l l (Point Beach-Sheboygan Energy Center) and the existing 138 kV line L90 (Shoto - Glenview). The existing 345 kV lines L l l l and L121 (Point Beach-Forest Junction) are looped into the new switching station.

3) Conversion of the existing lines 971K5 1 (Forest Junction-Howard Grove 138 kV line) and portion of HOLG21 (Howards Grove-Plymouth #4-Holland 138 kV line) to 345 kV

(-48 miles). It is terminated at Forest Junction and New East 3451138 kV substation and then looped into the new North 345 kV switching station.

4) Construction of new double circuit 345 kV lines to loop the line 796L41 into the new East substation (-1.1 miles)

5) Construction of new double circuit 345 kV lines to loop the line L121 into the new North switching station (-3.2 miles)

6) Construction of new 138 kV lines to form new East-Plymouth-Howards Grove-Erdman 138 kV lines (-1 6 miles).

American Transmission Company Page 14 of 132

G83314-J02213 ISIS Report Injection Upgrades (see Table 1.2.a)

In summary, the study identified the following line segment which will need to be upgraded to achieve the necessary rating.

0 Cedarsauk-New East 345-kV line 796L41 south (24.1 miles) must be uprated to obtain a minimum summer emergency rating of 960 MVA or higher. The required rating (960 MVA) is from Table A.7 (NERC C.3). This value was selected as the target rating to address potential overloads of the line under various multiple contingency events evaluated.

Point Beach-New North 345 kV line L l l l (51.1 miles) must be uprated to obtain a minimum summer emergency rating of 754 MVA or higher. ATC has a planned project, as an independent economic benefit project, for the Point Beach-Sheboygan Energy Center line uprate to a summer emergency rating of 1095 MVA (1834 A), which is higher than the required rating for G83314-502213. The proposed in-sewice date of the line uprate project is April 25,2010 (ATC Project PR03208).

Voltage Related None Breaker Duty Related None Network Resource Interconnection Service (NRIS) Related MIS0 performed the generator deliverability analysis needed for G833lJ022 and G83415023 to qualify for NRIS. No additional upgrades were identified to qualify for NRIS for the entire requested amount.

Typical planning level cost estimates for new and rebuilt facilities in the American Transmission Company (ATC) footprint are listed in Appendix G for the Interconnection Customer's reference.

1.5 Interconnection Facilities Interconnection Facilities include all facilities and equipment that are located between the interconnecting generator's Generating Facility and the POI. Note that the POI is the terminal in the Point Beach 345-kV Substation where each unit will inject its power output, while the Point of Change of Ownership (PCO) may be a different element within the same 345-kV substation.

The G83315022 and G83415023 Interconnection Facilities already exist. Table 1.3 describes the new facilities owned by the Interconnection Customer and the Transmission Owner respectively.

American Transmission Company Page 15 of 132

G83314-J02213 ISIS Report 1.6 Further Study In order for G8331J022 and G834lJ023 to interconnect, the required Network Upgrades and Interconnection Facilities must be completed. The Interconnection Customer will have to submit the Definitive Planning Continuation milestones (M3) prior to entering the Facilities Study for this project. An Interconnection Facilities Study will specify in more detail the time and cost of the equipment, engineering, procurement and construction of the system upgrades identified in this ISIS report.

American Transmission Company Page 16 of 132

G83314-502213 ISIS Report Table I. I- Existing System Upgrades Required before Operation of G833/J022 and/or G834 /J023 Location Facilities Reason None Table 1.2.0 -Required 'Zona-Term" Network U~arades(Fix 11) due to the Addition of G833/J022 and/or G834 /J023 (For more detail, see Appendix J )

Good Faith Cost Estimate Location Facilities Reason (Assumed In-service Date:

2018)

Item #1- Increase the line clearance and upgrade terminal Cedarsauk-East equipment (CTs) on Cedarsauk 345 kV ring buses to obtain a Switching Station minimum Summer Emergency rating of 960 MVA (1607 Amps). Injection 345 kV line Look at plan and profile and Patrol to observe any close wire Limit (796L41 south) crossi~igsand adjust to obtain a minimum Summer Emergency rating of 960 MVA (1 607 Amps).

Item #2 - Increase 345 kV line clearance to obtain a minimum Summer Emergency rating of 754 MVA (1262 Amps). ATC has Existing ATC Point Beach-New a planned project, as an independent economic benefit project, Injection project will North 345-kV line for the L111 uprate to a summer emergency rating of 1095 MVA Limit satisfy rating (L111 east) (1834 A) higher than the required rating for G83314-502213. The needs proposed in-service date of the line uprate project is April 25, 2010 (ATC Project PR03208).

Item #3.1

- An eight position (expandable to twelve) 345 kV and a six position (expandable to ten) 138 kV breaker-and-a-half scheme substation located at the intersection of the existing 345 kV lines W-1 (Edgewater-South Fond Du Lac) and L-SEC3 1 (Sheboygan Energy Center-Granville). Provisions to Cost of Item be made to expand the 345 kV bus for four additional future -

1. 3.1 #3.6.a 345 kV transmission facilities (e.g. a 3451138 kV $129,554,079 transformer, 2nd 345 kV line to South Fond du Lac, 2nd 345 kV line in the direction of Saukville, 345 kV shunt inductor). (T-line:

- Design and constn~ctnew 345 kV substation facilities per $70,356,942, ATC substation design standards. Minimum SN bus rating of Substation:

5000 Amps. Use ATC 345 kV Standard for ratings of CT's, $59,197,137) switches, jumpers, etc connected to bus.

A New 3451138 kV - Install a new 3451138 kV transformer capable of at least Stability Cost of Item Substation at the Upgrades 5001625 MVA for SN and SE. Select transformer based on #3.1 -#3.6.b Intersection of lines ATC transformer standard $243,714,953 W-1 and L-SEC31. - Install 12 new 345 kV circuit breakers capable of 3000 A, 50 (East Substation) kA, 2-cycle, Complete IPO Gas Circuit Breakers (GCB). (T-line:

- Install 32 new 345 kV disconnect switches capable of 3000 A $184,517,816 at a minimum. Substation:

- The existing lines W-1, L-SEC3 1 and 796L41 (Edgewater- $59,197,137)

Cedarsauk) are looped into the new substation. Northern portion of HOLG21, converted to 345 kV, is terminated at the new substation.

- Design and construct new 138 kV substation facilities per American Transmission Company Page 17 of 132 10/2/2009

G83314-J02213 ISIS Report switches, jumpers, etc connected to bus.

- Install 8 new 138 kV circuit breakers capable of at least 3000 A, 40 kA,3-cycle, Non-IPO Installation Gas Circuit Breakers

- Install 21 new 138 kV disconnect switches capable of 3000 A at a minimum.

- Provisions to be made to expand the 138 kV bus for four additional future 138 kV transmission facilities (e.g. a future 3451138 kV transformer, other h t m e 138 kV transmission facility such as capacitor bank, potential split of X57 into two circuits (existing: 2-795 ACSR)). Purchasing sufficient land to accommodate future expansion is required.

- Terminate the not-converted southern portion of the HOLG21 138 kV line at the new East 138 kV substation and loop the existlng line X57 into the substation.

- Terminate new 138 kV line from the Plymouth #4 138 kV substation (reference: Item 3.6)

- A six position (expandable to ten) breaker-and-a-half scheme substation in the area of the intersection of the existing 345 kV line L l 11 (Point Beach-Sheboygan Energy Center) and the existing 138 kV line L90 (Shoto -

Glenview). Provisions to be made to expand the 345 kV bus for four additional future 345 kV transmission facilities (e.g.

new 345 kV line to East, new 345 kV line to North or 345 kV shunt inductor, two 3451138 kV transformers).

- Design and construct new 345 kV substation facilities per A New Switching ATC substation design standards. Minimum SN bus rating Station in the area of 5000 Amps. Use ATC 345 kV Standard for ratings of of tlie Intersection CT's, switches, jumpers, etc connected to bus.

of lines L l l l and - Install 9 new 345 kV circuit breakers capable of 3000 A, 50 kA, 2-cycle, Complete IPO Gas Circu~tBreakers (GCB).

Switching Station) - Install 24 new 345 kV disconnect switches capable of 3000 A at a minlmum.

- Lines L111 and L121 are looped into the new switching station in addition to converted 971KSl(Forest Junction-Howards Grove 138 kV line)

- Provisions for a future 138 kV substation with eight position breaker and a half configuration to terminate existing lines L90, 971K5 1, two future 3451138 kV transformers, other fi~tt~re 138 kV transmission facility such as capacitor bank and f i ~ h ~138 r e kV line to the northeast or south. Purchasing sufficient land to accommodate future expansion is required.

- Install a new 345 kV circuit breaker capable of 3000 A, 50 Forest Junction 345 kA,2-cycle, Complete IPO Gas Circuit Breakers (GCB).

kV Substation - Install 3 new disconnect switches capable of 3000 A at a

- Use ATC 345 kV Standard for ratings of CT's, switches, jumpers, etc connected to bus.

- Terminate new 138 kV line from Erdman

- Install a new disconnect switch capable of 3000 A at a minimum.

Holvards Grove 138 - Provision for a future line breaker kV substation - Design and construct new 138 kV substation facilities per ATC substation design standards. Use ATC 138 kV Standard for ratings of CT's, switches, jumpers, etc American Transmission Company Page 18 of 132 10/2/2009

G83314-502213 ISIS Report

- Terminate new 138 kV line from Howards Grove

- Install 6 new disconnect switches capable of 3000 A at a minimum.

- Install 3 new 138 kV circuit breakers capable of at least 3000 A, 40 kA, 3-cycle, Non-IPO Installation Gas Circuit Erdman 138 kV Breakers (GCB)

- Extend the existing 138 kV bus to accommodate a new 138 kV line from Howards Grove. Minimum SN bus rating of 3000 Amps. Use ATC 138 kV Standard for ratings of CT's, switches, jumpers, etc connected to bus.

- Relocate the termination point of the existing Erdman 138169 kV transformer to the new 138 kV bus Item 3.6.a (Assumes reconductorind

- Constn~ctnew double-circuit 345 kV lines (roughly 1 mile) to loop the existing 796L41 into the East switching station.

Use bundled T2-556 ACSR or equivalent. Required ratings are 191012639 MVA (3 19614416 amps) for SNISE. CPCN application to PSCW may be required.

- Construct a new double-circuit 345 kV line on new right of way using Bundled T2-556 ACSR or equivalent in order to loop L121 into the new North switching station. Length: 3 -

miles, Required Ratings: 191012639 MVA (3 196 1 44 16 Amps for SNISE). CPCN application to PSCW may be

- Convert the existing 971K51 138 kV line to 345 kV (Forest Jct-Howards Grove: -38.72 mile). Convert portion (-9.13 mile) of HOLG21 (Howards Grove-Plymouth-Holland) to 345 kV line. Review the conditions of the existing double circuit structures. Reconductor the converted line using 2156 ACSR (225712973 Amps for SNISE) or equivalent. It is assumed that the existing structures are designed for new heavy conductors. The converted 971K51 will be looped into the new North 345 kV switching station. The converted HOLG21 line side will be terminated at the new East 345 Conversion of kV substation. Retain the existing double circuit 138 kV existing 138 kV line segments going into Howards Grove and Plymouth #4 138 kV substations Construction of - To form New East-Plymouth #4-Howards Grove-Erdman 345 and 138 kV 138 kV lines, o Construct a new 138 kV line from new East 138 kV substation to the point where the existing double circuit 138 kV lines go into Plymouth #4. Use T2-477 ACSR or equivalent. Length: -6 miles, Ratings: 145512014 Amps for SNISE o Constn~cta new 138 kV line from the Plymouth #4 double circuit loop ends to the point where the existing double circuit 138 kV lines go into Howards Grove.

Use T2-477 ACSR or equivalent. Length: -3.2 miles, Ratings: I45512014 Amps for SNISE. One of the existing double circuits going into Howards Grove 138 kV substation will be de-energized.

o Construct a new 138 kV line from Howards Grove to Erdman using T2-477 ACSR or equivalent. Length:

-6.6 miles, Ratings: 145512014Amps for SNISE Item 3.6.b (Assumes rebuild in^ structures)

Same as Item 3.6a except the following sub-item.

- Convert the existing 971K51 138 kV line to 345 kV (Forest Jct-Howards Grove: -38.72 mile). Convert portion (-9.13 mile) of HOLG21 (Howards Grove-Plymouth-Holland) to 345 kV line. Review the conditions of the existing double American Transmission Company Page 19 of 132 10/2/2009

G83314-J022/3 ISIS Report structures. Expand the existing right of way to accommodat the new stmctures.

TOTAL *

• Note: The cost range of the proposed project has been updated from the draft report to a range of costs due to the uncertain condition of the existing 3451138 kV double circuit structures reported from ATC Asset Management in their recent review of the drafi system impact study. The condition of the existing 3451138 kV structures will be evaluated as part of the detailed engineering study during the Facilities Study.

American Transmission Company Page 20 of 132

G83314-502213 ISIS Report Table 1.2.6 -Required "interim"' Network Upgradesfor Thermal and Stability Issues due to the Addition o f G833/J022 and/or G834/J023 Good Faith In-Cost Location Facilities Reason service Estimate Date (Y2009)

Item #1 -Look at plan and profile and Patrol to observe any close Cypress-Arcadian Injection wire crossings and adjust to obtain a minimum Summer 5/1/2010 $1.7 M 345-kV line Limit Emergency rating of 572 MVA (957.3 A).

Item #2 - L111 requires a minimum summer emergency rating of Point Beach- 596 MVA (997.4 A). PRF PRO3208 requires a minimum summer Sheboygan Energy emergency rating of 1120 MVA with a proposed in-service date Center 345-kV line 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, 50 kA, Gas CB, IPO) in order to achieve 4.5 North Appleton 345 cycles remote primary clearing time. With Kewaunee bus kV 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 4.5' cycles remote primary by reducing the remote clearing time by 2.0 cycles Item #4 -Point Beach Faults Protection Improvements.

Item 4A: Achieve L l l l 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 111 SEL-221F backup relay replacement with an SEL-421.

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-22 IF backup relay replacement with an SEL-421 (note 8.0 cycles delayed clearing Point Beach 345 kV time can be obtained with Item 4B implemented).

Bus Item 4C: Isolate Q-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.

Item 41): 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 Note 3 -Based on Interim Operations Restudy Report.

American Transmission Company Page 21 of 132

G833/4-502213 ISIS Report Table 1.3 - Required Interconnection Facilities.for G833/J022 and G834/J023 I I 1 Entity Facilities Cost Estimate (Y2018)

Transmission None. NA Owner Minimum Excitation Limiter setting maintained at the level G833/J022 and described in Appendix I. Required Minimum Excitation Limits: 12 G834/J023 MVAR (gross) or higher Interconnection Customer Note: These facilities are to be provided by the generator interconnection customer. Hence, cost estimate is not applicable.

Table 1.4 - Recommended Facilities at Point Beach Dzre To G833/J022 and G834/J023 Entity Facilities Cost Estimate (Y2018)

I Recommended improvements to the Point Beach substation design.

Add 345 kV, 3000A, 50 kA, 2 cycle gas Circuit Breakers on the NA high side of Point Beach auxiliary transformers TlX03 and T2X03 G833lJ022 and with adequate primary and breaker failure relaying.

G8341J023 For the potential stability issue that may occur until the proposed Interconnection solution in place, reduce Auxiliary Transformer TlX03 primary Customer fault clearing time from 5.1 cycles to 4.0 cycles and Auxiliary Transformer T2X03 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 Facilities Dzre To Third Party Impact of G833/J022 and G834/J023 I I I Entity Facilities Cost Estimate (Y2018)

Required Minimum Excitation Limit at Kewaunee GI: -20 MVAR (gross) or higher Kewaunee Note: These facilities are to be provided by Kewaunee owned by Dominion. Hence, cost estimate is not applicable.

American Transmission Company Page 22 of 132

G833/4-J022/3 ISIS Report

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 Generator 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 Generator is responsible for communicating any significant generating k i l i t y data changes in a timely fashion to MIS0 and ATC prior to commercial operation.

2.2.1 Competing Generation Requests ATC determined in its judgment that four Interconnection Requests with an earlier Queue Position may impact the G833lJ022 and G834lJO23 study results. G427, G590, G611 and G773 are included in all of the thermal analysis cases. Because of their location on the 138 kV system, G590, G611 and G773 were not included in the stability models.

Public information related to the MIS0 Interconnection Request queue can be found at:

btt~.:llww.midwes~8?rket.0~dva~elGene1;at0rOA2OInterc0me0ti~n and the Interconnection Requests specific to the ATC footprint can be found at:

http:/l~asis.ruidwestiso. org;/d0~wmentslATC/C1~~ ter 8 Oueuehtd, TBD (suspended) I Cypress 345 kV Substah I

G590 98 TBD (suspended) Tecumseh Rd 138 kV Substation G611 100.5 12-31-207 1 Elkhart Lake-Forest Junction 138 kV line 1 0773 1 150 1 12-01-2012 I Forest Junction-Lost Dauphin 138 kV line (

American Transmission Company Page 23 of 132

G83314-502213 ISIS Report 2.2.2 Power Flow Analysis Methods Thermal overloads were identified using AC power flow solutions. All AC power flow solutions utilized actual equipment ratings in MVA (i.e. 0% TRM) along with real and reactive power flows. A 5% TRM was factored in the computation of required MVA rating for the limiting elements.

All AC power flow solutions were performed using the Power Flow module of the Power System SimulationIEngineering-30.3.2(PSSIE, Version 30.3.2) program from Siemens Power Technologies, Inc (PTI). This program is accepted industry-wide for power flow analysis.

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 G833lJ022 and G834lJ023. Simulations were performed with G833lJ022 andor 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.

For the analysis, the proposed Point Beach Power System Stabilizers are assumed in-service.

Simulatedtested clearing times shown in each table in Appendix C 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 (PSSIE, Version 29.5.1) program from 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)

Base cases used in the thermal and voltage analysis for this study were developed based upon the 2013 Summer Peak and Summer Off-Peak MIS0 Definitive Planning Phase (DPP) Cycle 2 Models developed from 2013 MIS0 Transmission Expansion Plan (MTEP) models built in 2008. According to MISO, the existing generators in the DPP Cycle 2 models were dispatched to serve the control area load, and the remaining generators were dispatched based on contracts.

Based on the new MIS0 Generation Interconnection Business Practice Manual (BPM), all wind generation including competing wind generation was dispatched at 20% of nameplate capacity for summer peak load conditions and 100% for summer off-peak load conditions.

For the AC power flow analysis, half of the output of G833lJ022 and G834lJ023 was delivered to the WAPA control area and the remaining half was delivered to the TVA control area. This dispatch pattern in the AC analysis was used to mimic delivery to the MIS0 footprint.

American Transmission Company Page 24 of 132 10/2/2009

G83314-502213 ISIS Report 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 fiom 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. The Kewaunee bus reconfiguration project planned for 2011 was also modeled in the study cases. 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 CornEd (75%) and Northern States Power (25%) control areas.

Two stability scenarios were studied for G833lJ022 and G834lJ023. 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, 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 with G833/4-J022/3 I I I Units Low Generation Scenario High Generation Scenario Point Beach Unit 1 (G834/J023) 642.96 MW (Gross) 642.96 MW (Gross)

Point Beach Unit 2 (68330023) 642.96MW (Gross) 642.96 MW (Gross)

Kewaunee 603 MW (Gross) 603 MW (Gross)

Cypress OMW 258 MW South Fond du Lac generators OMW 352 MW Fox Energy Center OMW 632 MW Sheboygan Energy Center OMW 346.8 MW 2.3.3 Deliverability Analysis The deliverability analysis case was developed by MIS0 following the MIS0 deliverability study methodology. Details on the MIS0 deliverability study methodology can be found in the whitepaper posted at the following link MIS0 Deliverabilitv Whitepa~er(see Appendix E for complete URL).

2.4 Generation Facility 2.4.1 Generating Facility Modeling The G8331J022 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 for each unit. The voltage regulation set point of each machine was 102.03% (352 kV) of nominal at the POI to reflect preferred plant operation.

American Transmission Company Page 25 of 132

G83314-502213 ISIS Report Later, as shown in Appendix H, various voltage regulation set points of the generators were studied to evaluate the dynamic stability performance of each option in terms of minimum MVAR limitation of Point Beach and Kewaunee.

Dynamic model changes that have been reported to ATC have been incorporated into the Point Beach generator stability models. In addition, the generator step up transformers will be replaced as part of the G833lJ022 and G834lJ023 projects and these modifications were incorporated into the model.

After the units are physically modified and prior to initial unit synchronization, final generator dynamic models should be provided so that operational studies confirming the results of this study can be completed.

The actual clearing times determined using information from the Interconnection Customer and used for the analysis contained in this report are:

1. For GSU transformers TlXOl and T2XO1, the primary clearing time is 4.5 cycles and the breaker failure clearing time is 12.5 cycles for bus breakers and 13.0 cycles for line breakers.

2. For auxiliary transformers T 1X03 and T2X03, the primary clearing time is 5.1 cycles and the breaker failure clearing time is 12.3 cycles for bus breakers and 23.5 cycles for line breakers.

It should be noted that the actual clearing times listed above do not contain any ATC planning margins. Also, the actual clearing times assume the recommended high side auxiliary transformers breakers are not installed.

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.

Table 2.4.2 - 19 kV and 345 kV bus voltage relay settings at Point Beach Bus KV Drop Out Voltage Reset Voltage Minimum Time Delay I 19 kV I 84.6% I 86.2% 1 1.5 seconds I 1 345kV 1st criteria 2nd criteria 74.3%

94.1%

75.7%

95.7%

1.0 second 1.5 seconds 2.4.3 Synchronizing and Energization of SubstationIGeneratorStep-Up Transformers ATC's standard design is for synchronization of the generator to occur at the interconnection customer's high-side (i.e. transmission voltage) circuit breaker. Exceptions to this standard must be requested for examination during the interconnection study.

American Transmission Company Page 26 of 132

G83314-J02213 ISIS Report The Point Beach nuclear units are presently undergoing design development to support the inclusion of generator breakers in their Iso-phase Bus connections. The generator breaker(s) will be positioned so as to enable a generating unit trip at the generator output voltage level/position without the need to de-energize the main transformers. Since the high voltage side breakers will remained closed, the power plant auxiliary buses are intended to be powered via the backfeed Main Transformers and the Iso-phase bus direct-connected Unit Auxiliary Transformers. This arrangement eliminates the presently needed high speed transfer of auxiliary busses to the grid-connected Startup Transformer upon a generating unit trip, and will also serve to resolve present marginal bus voltage issues. For purposes of the grid studies, the generator breakers are considered to be in place and operable at the time of startup of the generating units at their increased levels of output.

A generator step-up transformer will require the initial energization to occur from the transmission grid. Prior to initial energization, the Interconnection Customer must permanently install mitigation equipment (e.g., pre-insertion resistors on the high-side transformer circuit breaker) or commission a technical study of the initial energization event to ensure that the initial energization of the transformer will not result in any unacceptable impact to ATC or interconnected customers.

2.4.4 Unit Black Start and ATC Black Start Plan Participation Generating units interconnecting with the ATCLLC transmission system must report black start requirements to ATCLLC. Additionally, the customer and ATCLLC must discuss the unit's participation in the ATCLLC system black start plan.

American Transmission Company Page 27 of 132

G83314-J02213 ISIS Report

3. Analysis Results 3.1 Power Flow Analysis Results The intact system, single contingency and multiple contingency thermal analyses in this report used AC analysis under 2013 Summer Peak and Off-Peak load conditions with the proposed solution in service.

3.1.1 Power Factor Capability and Voltage Requirements Power Factor Capability The G83314-J02213 customer has submitted a generating facility design capable of maintaining power delivery at continuous rated power output at the POI (Point of Interconnection) at all power factors over 0.95 leading (when a facility is consuming reactive power from the transmission system) to 0.94 lagging (when a facility is supplying reactive power to the transmission system). For the steady-state scenarios examined, study results indicate that satisfactory system performance is achieved by supplying a range of -21 1.3 to 233.4 Mvars (gross) to the system.

Plant Specific Voltage Requirements The Point Beach Nuclear Plant 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). A new high voltage limit of 360 kV has been proposed by the plant and incorporated into this study.

Any voltage outside the maximum permissible range is a voltage limitation as described in the plant technical specifications.

3.1.2 Results of Intact System and Single Contingencies (N-1) 3.1.2.1 Base Case Analyses With the proposed solution modeled, the analysis was conducted using the cases developed based upon the 2013 Summer Peak (100% load conditions) and Off-Peak (roughly 70% load conditions) MIS0 DPP Cycle 2 models. All wind generation including competing wind generation was dispatched at 20% of nameplate capacity for summer peak load conditions and 100% for summer off-peak conditions. For the summer off-peak model, the Fox Energy generating units and one of the two Sheboygan Energy units were out of service. The remaining Sheboygan Energy unit was on-line at 90 MW in the 2013 Summer Off-Peak model.

This study identified two transmission element steady-state thermal violations as injection limits due to G83314-J02213 for NERC Category B (N-1) events for the 2013 Summer Off-Peak model and one injection limit was identified for NERC Category B (N-1) events for the 2013 Summer Peak model. The injection limits are Point Beach Bus 1-New North 345 kV line ( L l l l east). The line is overloaded with the outage of Point Beach Bus 2-New North 345 kV line (L121 east). Distribution factor is American Transmission Company Page 28 of 132 10/2/2009

G83314-502213 ISIS Report not available because the contingency pair is created by the proposed new North switching station and it does not exist in the base model prior to G83314-J02213.

= New East-Cedarsauk 345 kV line (796L41 south). The line is overloaded with the outage of new East-Granville 345 kV line. Distribution factor is not available because the contingency pair is created by the proposed new East substation and it does not exist in the base model prior to G83314-J02213.

A summary of the thermal violations due to G83314-J02213 is presented in Tables A. 1 and A.2 in Appendix A.

L l 11, Point Beach Bus 1-(New North)-Sheboygan Energy Center 345 kV line, will be uprated as an independent economic benefit project (1095 MVA SE with ATC Project PRO3208 assumed in-service), required ratings are given but these are lower than those required for ATC Project PR03208.

The maximum allowable output without Network Upgrades for injection limits is presented in Table A.13 in Appendix A. As shown in this table, the maximum real power output for injection limits without any system upgrades is 0 MW for all conditions studied.

Voltage analysis shows that no Transmission System voltage limits will be violated as a result of the interconnection of G83314-J02213 (see Tables A.3 and A.4 in Appendix A).

3.1.3 Results of Double Contingencies (N-1-1) 3.1.3.1 NERC Category C.3 Contingencies (N-1-1)

Thermal and voltage constraints were evaluated for NERC Category C events (N-1-1 contingencies) in the electrical proximity of G83314-502213 for the 2013 Summer Peak and Off-Peak models with the proposed solution in service. The double contingency constraints are not required to be resolved for the generator to attain either Energy Resource or Network Resource Interconnection Service status. The purpose of the N-1-1 analysis is to reveal potential violations under prior outage conditions.

Thermal violations under a selected number of N-1-1 contingencies were evaluated using AC analysis. The distinct thermal violations identified from the 2013 Summer Peak and Off-Peak load condition models used in the study are listed in Table A.7 and A.8 in Appendix A.

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 G83314-J02213 for the contingencies noted in this N 1 analysis.

3.1.3.2 NERC Category C.5 Contingencies American Transmission Company Page 29 of 132

G83314-502213 ISIS Report The Transmission System local to the selected Point of Interconnection was reviewed for facilities that could be defined as double contingencies that correspond to NERC Category C.5 events (i.e. two circuits on shared tower). Table 3.1 shows all NERC Category C.5 events that were considered local and potentially limiting the proposed interconnection. Three overloads were found for the Category C.5 events studied. Two of them are not considered as a problem due to G83314-J02213:

Lau Rd-Elkhart Lake 138 kV line. Approximately 2.9% of the increased generation flowing on this line with New East-Cedarsauk and Holland-Charter Industrial-Saukville 138 kV line which is relatively minor impact and below the 5% distribution factor cutoff in the MIS0 BPM. Therefore, it is not considered as a problem due to G83314-J02213. In addition, the thermal overload can be mitigated by generation redispatch in the local area.

Elkhart Lake-Saukville 138 kV line. Approximately 0.5% of the increased generation flowing on this line with New East-Cedarsauk and Holland-Charter Industrial-Saukville 138 kV line which is relatively minor impact and below the 5% distribution factor cutoff.

Therefore, it is not considered as a problem due to G83314-J02213. In addition, the thermal overload can be mitigated by generation redispatch in the local area.

New East-Cedarsauk 345 kV line (796L41 south). The line is overloaded with the outage of Cypress-Arcadian 345 kV line and Germantown-Maple-Saukville 138 kV line.

Distribution factor is not available because it is a new line created by the new East s~~bstation.

As discussed in Section 3.1.2.1, the new East-Cedarsauk 345 kV line will be uprated to 960 MVA SE, which is higher than the required rating shown in Table A.9 as one of the required Network Upgrades (see Table 1.2.a).

The Category C.5 results are shown in Tables A.9 and A.10 in Appendix A.

Line 796L41 south I Line 8222 East-Cedarsauk 345-kV I East-Edaewater 345-kV Line 796L41 south ( Line 796~41east Edgewater-Cedarsauk 345-kV I Edgewater-South Fond du Lac 345-kV American Transmission Company Page 30 of 132 10/2/2009

G83314-502213 ISIS Report Line 796L41 I Line W-I Edgewater-East 345-kV #2 I Edgewater-East345-kV # I Line W-I east Line 796L41 east Lau Rd (G611)-Elkhart Lake 138-kV Tecumseh Rd-Meyer Rd 138-kV Line 4035 Line 40561 Point Beach Bus I-North 345 kV line Point Beach Bus 2-North 345 kV line North-Sheboygan Energy Center 345 kV line North-East 345 kV line Sheboygan Energy Center-East 345 kV line North-East 345 kV line North-ForestJunction 345 kV line # I North-Forest Junction 345 kV line #2

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two

- ~

circuits of a multi-circuit tower.

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 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. In addition, that analysis found no stability problems for three-phase faults cleared in primary clearing time under prior outage conditions with proposed Power System Stabilizers (PSS) in-service. The only existing issue is a potential stability problem with a fault on 345-kV line Q-303 (Point Beach to Kewaunee) under the prior outage condition of 345-kV line R-304 (Kewaunee to North Appleton). However, this issue is addressed by the existing operating guide, which requires Kewaunee generation to be reduced to 382 MW (net) for thermal reasons.

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): 3.5 cycles; Delayed Clearing (Local Breaker Failure): 9.0 cycles; Primary Clearing (Remote End): 4.5 cycles American Transmission Company Page 3 1 of 132

G83314-J02213 ISIS Report A planning margin of 1.O cycle is required between any studied (simulatedltested) 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.

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 voltages are listed in Table 2.4.2. If no stability issue was identified with G83314-J02213 and without the proposed solution, no additional stability analysis with the proposed solution was performed since the proposed solution improves stability response by tying together critical transmission elements and providing an additional 345 kV line in parallel with the existing 345 kV lines (portion of L1 11, L121 and L-SEC3 I).

Results of the stability analysis are summarized in Appendix C.

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 problems were identified. These results are summarized in Table C. 1 in Appendix C.

Table 3.2.1 - Simulated Single Circuit 3-Phase Faults Cleared in Primary Time Faulted Element Fault Location Description Llll Point Beach 345 kV Point Beach-SheboyganEnergy 345 kV Line L121 Point Beach 345 kV Point Beach-Forest Junction 345 kV Line L151 Point Beach 345 kV Point Beach-Fox River 345 kV Line Q-303 Point Beach 345 kV Point Beach-Kewaunee345 kV Line Q-303 Kewaunee 345 kV Point Beach-Kewaunee345 kV Line R-304 Kewaunee 345 kV Kewaunee-NorthAppleton 345 kV Line L151 Fox River 345 kV Point Beach-Fox River 345 kV Line L6832 Fox River 345 kV Fox River-North Appleton 345 kV Line 971L71 Fox River 345 kV Fox River-Forest Junction 345 kV Line Llll Sheboygan Energy 345 kV Point Beach-SheboyganEnergy 345 kV Line L-SEC31 Sheboygan Energy 345 kV Sheboygan Energy-Granville345 kV Line L-CYP31 Cypress 345 kV Cypress-Arcadian 345 kV Line KEW TI0 H Kewaunee 345 KV Kewaunee 3451138 kV Transformer 3.2.2 Results of Primary Clearing SLG 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, to simplify the simulations. If a generator is not stabe for the three phase fault, a single line to ground fault would then be studied. No stability problems were identified. These results are summarized in Table C.2 in Appendix C.

American Transmission Company Page 32 o f 132

G83314-J02213 ISIS Report Table 3.2.2 - Simulated Intact System Double Circuit Single Line-to-Ground Faults Fault I Fault 2 Element Location Element Location I 1I-Pt. Beach -Sheboygan Energy 345 kV 38.5% from POB 971K51-Forest Jct.-Howard's Grove 138 kV 33.9% from FJT III-Pt. Beach -Sheboygan Energy 345 kV 16.3% from SEC 971K51-Forest Jct.-Howard's Grove 138 kV 6.3% from HOG Ill-Pt. Beach -Sheboygan Energy 345 kV SEC HOGL21-Howard's Grove-Holland 138 kV 46.8% from HOL Ill-Pt. Beach -Sheboygan Energy 345 kV 15.7% from SEC HOGL21-Howard's Grove-Holland 138 kV 12.3% from HOG 121-Pt. Beach -Forest Junction 345 kV FJT 971K51-Forest Jct.-Howard's Grove 138 kV FJT 121-Pt. Beach -Forest Junction 345 kV 42.3% from FJT 971K51-Forest Jct.-Howard's Grove 138 kV 33.9% from FJT L-SEC31-Sheboygan Energy-Granville 345 kV GVL 3431-Granville-Saukville345 kV GVL L-SEC31-Sheboygan Energy-Granville 345 kV 26.7% from GVL 3431-Granville-Saukville 345 kV 25.3% from SAU L-SEC31-Sheboygan Energy-Granville 345 kV 43.5% from GVL 8231-Sukville-Barton 138 kV 36.4% from BRT L-SEC3l-SheboyganEnergy-Granville 345 kV 48.3% from GVL 8231-Sukville-Barton 138 kV 36.4% from SAU L-CYP31-Cypress-Arcadian 345 kV 32.0% from ADN 2642-Saukville-Germantown 138 kV 34.2% from SAU L-CYP31-Cypress-Arcadian 345 kV 16.6% from ADN 2642-Saukville-Germantown138 kV GER L-CYP31-Cypress-Arcadian 345 kV 10.8% from ADN 2661-Germantown-BarkRiver 138 kV 31.5% from GER L-CYP31-Cypress-Arcadian345 kV 16.6% from ADN 2661-Germantown-BarkRiver 138 kV GER L-CYP31-Cypress-Arcadian345 kV 10.8% from ADN 9911-GranvilleArcadian345 kV 45.4% from GVL L-CYP31-Cypress-Arcadian 345 kV ADN 9911-Granville-Arcadian345 kV ADN 3.2.3 Results of Primary Fault Clearing 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 Element Description L l II Point Beach-SheboyganEnergy 345 kV Line L121 Point Beach-Forest Junction 345 kV Line L151 Point Beach-Fox River 345 kV Line (2-303 Point Beach-Kewaunee345 kV Line R-304 Kewaunee-NorthAppleton 345 kV Line L6832 Fox River-North Appleton 345 kV Line 971L71 Fox River-Forest Junction 345 kV Line L-SEC31 Sheboygan Energy -Granville 345 kV Line L-CYP31 Cypress-Arcadian 345 kV Line NAPL71 North Appleton-Werner West 345 kV Line 971L51 Forest Junction-Cypress 345 kV Line Y-311 Norlh Appleton-Fitzgerald 345 kV Line T I0 Kewaunee 3451138 kV Transformer POB 1-2,2-3, 3-4,4-5 Point Beach 345 kV Breakers 1-2,2-3, 3-4,4-5 FOX 1-2,2-3,3-4,4-5,5-6,6-1 Fox River 345 kV Breakers 1-2,2-3, 3-4,4-5,5-6,6-1 SEC BT12, BT23, BT36, BT16 Sheboygan Energy 345 kV Breakers BT12, BT23, BT36, BT16 CYP BT16, BT12, BT56 Cypress 345 kV Breakers BT16, BT12, BT56 FJT 1-2,2-3,4-5,5-6,7-1 Forest Junction 345 kV Breakers 1-2,2-3,4-5,5-6, 7-1 American Transmission Company Page 33 o f 132 10/2/2009

G83314-502213 ISIS Report Two events with generation instability were found for prior outage scenarios (Table C.3 in Appendix C), which are Fault on L121 (Point Beach-Forest Junction) under the outage of Point Beach 345 kV breaker 2-3 Fault on R-304 (North Appleton-Kewaunee) under the outage of 6832 (Fox River-North Appleton) followed by a fault on R-304 (Kewaunee-North Appleton)

Both prior outage stability problems were not found with the addition of the proposed solution.

Until completion of the proposed solution, the following operating restrictions already documented in the G83314-J02213 Interim Operation Re-study Report are required under the prior outage conditions to eliminate the stability problems:

G2 at 600 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line)

Gl at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 The existing stability problems, an R-304 fault with 4-303 out of service or a 4-303 fault with R-304 out of service, can be eliminated by reducing Kewaunee generation. Based on the future Kewaunee operating restrictions associated with the planned Kewaunee Bus Reconfiguration Project (see Figure l.l), angular stability will be maintained. This is an existing limitation that will not be made better or worse by the addition of G83314-J02213 and their associated Network Upgrades.

Table C.12 presents result for a three phase fault under the worst critical prior outage condition at the new East Switching Station (Fix 2 in Appendix H, part of the proposed solution), which is assumed to be a fault on the East-Cedarsauk 345 kV line under the outage of East-Granville 345 kV line. This is assumed to be the worst prior outage event because the outage of the East-Granville 345 kV line results in the highest flow on the 345 kV lines out of the new East substation, particularly on the East-Cedarsauk 345 kV line. The simulation provides the required clearing times for the new switching station and did not identify any stability problems that cannot be mitigated by the installation of 2 cycle 345 kV circuit breakers and high-speed relaying. Additional simulation is not performed with the proposed solution since stability response will only improve.

3.2.4 Results of Three-Phase Fault Delayed 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.

No stability problems were identified with the interim upgrades described in the G83314-J02213 Interim Operation Re-study Report which include relay upgrades at Point Beach, breaker replacement at North Appleton and a breaker addition at Point Beach.

Table 3.2.4 - Simulated 3-Phase Faults Cleared in Delayed Time Faulted Element I Fault Location Description Llll I Point Beach 345 kV Point Beach-Sheboygan Energy 345 kV Line American Transmission Company Page 34 of 132 10/2/2009

G83314-502213 ISIS Report L151 Point Beach 345 kV Point Beach-Fox River 345 kV Line (2-303 Point Beach 345 kV Point Beach-Kewaunee345 kV Line R-304 North Appleton 345 kV North Appleton-Kewaunee 345 kV Line L121 Forest Junction 345 kV Forest Junction-Point Beach 345 kV Line 971L51 Forest Junction 345 kV Forest Junction-Cypress 345 kV Line 971L71 Forest Junction 345 kV Forest Junction-Fox River 345 kV Line L151 Fox River 345 kV Point Beach-Fox River 345 kV Line L6832 Fox River 345 kV Fox River-North Appleton 345 kV Line 971L71 Fox River 345 kV Fox River-Forest Junction 345 kV Line Llll Sheboygan Energy 345 kV Point Beach-SheboyganEnergy 345 kV Line L-SEC31 Sheboygan Energy 345 kV Sheboygan Energy-Granville 345 kV Line L-CYP31 Cypress 345 kV CypressArcadian 345 kV Line 971L51 Cypress 345 kV Cypress-Forest Junction 345 kV Line Q-303 Kewaunee 345 kV Point Beach-Kewaunee345 kV Line R-304 Kewaunee 345 kV Kewaunee-NorthAppleton 345 kV Line KEWTIO H Kewaunee 345 KV Kewaunee 3451138 kV Transformer Table C.ll presents results for three phase faults with breaker failure at the new East Switching Station (with Fix 2 in Appendix H, part of the proposed solution) for an otherwise intact system.

These simulations provide the required clearing times for the new switching station and did not identify any stability problems that cannot be mitigated by the installation of 2 cycle 345 kV circuit breakers and high-speed relaying. Additional simulation is not performed with the proposed solution since stability response will only improve.

3.2.5 Point Beach Bus, Generator Step Up and Auxiliary Transformer Faults 3.2.5.1 Point Beach 345 kV Bzrs Fault Clearing Table C.5 presents results for single-line-to-groundbus faults with breaker failure at Point Beach using existing system clearing times. These simulations did not identify any Network Upgrades or other required changes for G83314-J02213 for these faults.

3.2.5.2 Generator Step-Up (GSU) Transformer Fault Clearing (TIXOI and T2XOl)

Tables C.6 and C.8 present results for single-line-to-ground (intact system with delayed clearing) and three phase (primary clearing under N-1 conditions) GSU faults. Simulating these faults with existing clearing times did not result in any generators going unstable. Therefore, there are no upgrades necessary due to these faults.

3.2.5.3 Auxiliary Transformer Fault Clearing (TlX03 and T2X03)

Table C.7 presents results for single-line-to-ground (intact system with delayed clearing) auxiliary transformer faults. Simulating these faults with existing clearing times did not result in any generators going unstable. Therefore, there are no upgrades necessary due to these faults.

Table C.9 presents results for three phase (primary clearing under both intact and prior outage conditions) T1X03 and T2X03 faults. Without the proposed solution, simulating these faults with existing clearing times (i.e. 5.1 cycles) resulted in generators going unstable for various different outages for TlX03 faults and for T2X03 faults. However, the stability problems were not found with the addition of the proposed solution. Until the proposed solution in place, generator stability can be maintained for all N-1 conditions if T1X03 clearing time is reduced to 4.0 cycles and T2X03 clearing time is reduced to 4.0 cycles.

American Transmission Company Page 35 o f 132 10/2/2009

G83314-J02213 ISIS Report 3.2.6 Unit Outage Unit outages were simulated for the events listed in Table 3.2.5. As shown in Table C.10 in Appendix C, no stability problems were found for the three interim scenarios, and no cascading failure was identified for the loss of these units.

Table 3.2.5 - Unit Otrtage 3.2.7 Stability Results Summary The improvements in system stability required for G83314-502213 are provided by the proposed solution described in this report. It eliminates all of the stability problems created by G83314-502213. In addition, the proposed solution allows the wider MVAR operating range at Point Beach and Kewaunee as described in Appendix H. More details can be found in Appendix H which discusses alternatives to the proposed solution.

3.3 Short-Circuit & Breaker Duty Analysis Results Although this project is to increase generation at an existing generator, the effect of the proposed solution, changes in Point Beach generator impedance and GSU impedance will affect system short circuit currents.

Fault currents with and without contribution from G83314-502213 for three-phase and single line-to-ground faults are given in Table D.l in Appendix D. The corresponding Thevenin equivalent impedances are given in Table D.2.

The minimum short circuit current at the G83314-502213 POI bus occurs when Q-303 (Point Beach-Kewanee), Point Beach GI and G2 are not in service. The three-phase and single line-to-ground fault currents for this weak source condition are also given in Table D. 1.

Short circuit current analysis with the revised generator and GSU impedances as well as the proposed solution showed that, for circuit breakers impacted by more than 1% (Table D.3), none of these breakers were over-dutied due to the addition of G83314-502213 and associated upgrades. Therefore, no circuit breaker replacements due to increased fault currents are needed for G83314-502213 generator interconnection requests.

Although an over-dutied breaker is found at the low side of Edgewater T22, it is an existing problem since it is already over-dutied prior to G83314-J02213. The over-dutied breaker will be evaluated and replaced by ATC Asset Maintenance.

3.4 Deliverability Analysis Results American Transmission Company Page 36 of 132

G83314-502213 ISIS Report Deliverability analysis was performed by MIS0 for these requests. No additional upgrades beyond those discussed in the previous sections were identified to achieve Network Resource Interconnection Service (NRIS).

NRIS certification does not guarantee a resource to serve a specific load or to operate during any particular set of operating circumstances. Additionally, certification of deliverability makes no guarantee as to price of available resources. Congestion charges may, in fact, be extremely high.

American Transmission Company Page 37 of 132

G83314-J02213 ISIS Report Appendix A: Power Flow Analysis Results American Transmission Company Page 38 of 132

G83314-J022/3 ISIS Report Table A. 1 - IdentiJied Therinal ViolationsDue to G833/4-J022/3 Szimmer Off-Peak 2013 (70% Load) Delivery to lWSO for NERC Category A and B events (TDF>S%)

Pro~osedSolution in Service. C o m ~ e t"i nWind ~ Farms at 100% ozrt~ut Existing Required Potential Limiting Element Rating Rating Worst TDF Injection Contingency3 Solution (MVA) (MVA)lsZ (%I Limit identified Elkhart Lake-Saukville 138 kVline 1 88 SE 1 93 SE I New East-Cedarsauk345kV line 1 -1.2 1 No I No4 I Elkhart line Lake-LauRd (G611) 13' kV I 96 SE I I12 SE I New East - Cedarsauk 345 kV line 1 1 -1.25 No I Yes5 I New North-Point Beach Bus 1 345 kV New North-Point Beach 345 kV bus line 488 SE 754 SE 2 line NIA Yes Yes6 New East-Cedarsauk345 kV line 1 653 SE 1 797 SE I New East-Granville 345 line kV I NIA 1 Yes I No7 I I I I I

1. Includes provision for 5% TRM. The required ratings are calculated using AC analysis in PSSIE dispatching 100% of power &om G83314-J022/3 to MISO.

2. SN = Summer Normal, SE = Summer Emergency

3. Local Special Protection Systems are included if designed to operate for NERC Category A or B events

4. Distribution factor was calculated assuming that Edgewater-Cedarsauk 345 kV line as the contingency corresponding to New East-Cedarsauk 345 kV line. The line is limited by the existing line conductor (1-477 and 1-410 ACSR, 33.73 mile)

5. Distribution factor was calculated assuming that Edgewater-Cedarsauk 345 kV line as the contingency corresponding to New East-Cedarsauk 345 kV line. The line will be uprated to 112 MVA per G6111G927 G-T interconnection. It is limited by the existing line conductor (410 ACSR, 28.9 mile: Forest Junction-Elkhart Lake)

6. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/20 10

7. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE (required for new East Switching Station option-Fix 2). The existing line rating is limited by the line clearance (2156 ACSR @ 129F).

Table A.2 -Identified Thermal Violations Due to G833/4-J022/3 Summer Peak 2013 (100% Load) Delivery to MlSO for NERC Category A and B events (TDF>S%)

Pt.oposec1 Solzition in Service, Competing Wind l;irtainsN / 20% Ozrtpzrt Existing Required Potential Limiting Element Rating Rating Worst TDF Injection Contingency3 Solution

(%) Limit I

New North-Point Beach Bus 1 345 kV line

/

I (MVA) 488 SE I (MVA)'J 678 SE I I

New North-Point Beach 345 kV bus 2 line I I I

NIA I

Yes /

1 Identified Yes4 /I

1. Includes provision for 5% TRM. The required ratings are calculated using AC analysis in PSS/E dispatching 100% of power from G83314-J022/3 to MISO.

2. SN = Summer Normal, SE = Summer Emergency

3. Local Special Protection Systems are included if designed to operate for NERC Category A or B events

4. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/20 10 American Transmission Company Page 39 of 132

G833/4-J022/3 ISIS Report Table A.3 - Identzjied Voltage Violations Dzre to G833/J022 and G834/J023 Summer Of-Peak 2013 (70% Load) Delivery to MlSO for NERC Category A & B events (A V > 0.1 None Identified Table A.4 - Identzjied Voltage Violations Due to G833/J022 and G834/J023 Summer Peak 201 3 (100% Load) Delivery to M S O for NERC Category A & B events (A V > 0.1 p.u.),

None Identified American Transmission Company Page 40 of 132

G83314-502213 ISIS Report Table A.5 - Voltage Measurements at the Point Beach 345-kV Substation with Proposed Solution, Szlmmer 2013 Peak Load with Selected contingencies1 Intact System 1 I

1.0203 1 I

1.0203 1 I

1.0203 1 I

1.0203 1 I

1.0203 1 I

64.62 1 I

64.62 Point Beach BS 2-3 1.0203 1.0203 1.0203 1.0203 1.0203 81.95 35.02 Point Beach BS 2 -New North 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 65.48 65.48 Line 121 Point Beach BS 1-2 1.0168 1.0203 1.0203 1.0203 1.0203 62.04 62.04 Point Beach BS 4-53 1.0203 1.0203 1.0203 1.0203 1.0224 72.05 72.05 Point Beach BS 3-4 1.0203 1.0203 1.0203 1.0203 1.0203 77.15 74.01 I I Point Beach BS 5 - Fox River 345-kV . nnnm II *.0203 1.0203 1.0203 1.0203 73.11 73.11 Line 151 I '

Forest Junction - Fox River 345-kV Line 971L71 I

. "A""

'.ULuL II '.0203 I

1.0203 1.0203 1.0203 83.48 83.48 Point Beach BS 1 -New North 345-kV II '.0203

-*,,A 1.0203 1.0203 1.0203 64.85 64.85 A

Line 111 I 1.uLU5 Point Beach BS 3 - Kewaunee 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 75.68 75.68 Line 0-303 Forest Junction -Cypress 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 69.67 69.67 Line 971L51 Forest Junction 3451138-kV 1.0203 1.0203 1.0203 1.0203 1.0203 58.27 58.27 Transformer TI Forest Junction 3451138-kV 1.0203 1.0203 1.0203 1.0203 1.0203 58.27 58.27 Transformer T2 Fox River - N. Appleton 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 64.53 64.53 Line 6832 Sheboygan Energy - New East 345-kV 1.0202 1.0203 1.0203 1.0203 1.0203 74.75 74.75 Line L-SEC31 North Fox Energy Center Unit CT 1 1.0203 1.0203 1.0203 1.0203 1.0203 63.16 63.16 Fox Energy Center Unit CT 2 1.0203 1.0203 1.0203 1.0203 1.0203 63.17 63.17 Fox Energy Center Unit ST 1.0203 1.0203 1.0203 1.0203 1.0203 62.63 62.63 Sheboygan Energy Center Unit #2 1.0203 1.0203 1.0203 1.0203 1.0203 72.96 72.96 Point Beach Unit #I4 1.0203 1.0203 1.0203 1.0203 1.0203 0 72.16 Point Beach Unit #z5 1.0203 1.0203 1.0203 1.0203 1.0203 72.16 0 Kewaunee G I 1.0203 1.0203 1.0203 1.0203 1.0203 66 29 66.29 Point Beach Units # I & #2" 1.0194 1.0194 1.0194 1.0194 1.0195 0 0 American Transmission Company Page 4 1 o f 132 10/2/2009

G83314-502213 ISIS Report I. Included for Interconnection Customer's defined voltage levels:

a. Preferred: 352-kV to 354-kV

b. Normal: 351-kV to 358-kV

c. Maximum Permissible: 348.5-kV to 362-kV, any voltage outside of the Maximum Permissible range would be identified in Table A.3 as a Voltage Violation

2. The planning case used models both Point Beach units as regulating the respective POI bus voltage at the Point Beach substation to 1.0203 p.u. (352 kV).

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345113.2-kV transformer isolated at this bus with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus.

4. This contingency is intended to model the emergency trip of Point Beach Unit #I. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer T1X03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

5. This contingency is intended to model the emergency trip of Point Beach Unit #2. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of Ioad at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

6. This contingency is intended to model an emergency dual unit trip modeled by the outage of each Point Beach generating unit, but maintaining the auxiliary load connection to the transmission system. Transformer T1X03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. Both generator Auxiliary loads are fed from their generator GSUs (23.4 MW and 13.9 MVAR each) and do not trip and are not moved. The Control Area replacement power was imported from TVA.

American Transmission Company Page 42 of 132

G83314-502213 ISIS Report Table A.6 - Voltage Measurements at the Point Beach 345-kV Szrbstation with Proposed Solzrtion, Szrmmer 2013 Off-PeeakLoad with Selected contingencies1 Intact System 1.0202 1.0203 1.0203 1.0203 1.0203 114.61 114.61 Point Beach BS 2-3 1.0202 1.0203 1.0203 1.0203 1.0202 138.22 80.31 Point Beach BS 2 -New North 345-kV 1.0201 1.0203 1.0203 1.0203 1.0202 113.99 113.99 Line 121 Point Beach BS 1-2 1.0113 1.0203 1.0203 1.0203 1.0202 109.49 109.49 Point Beach BS 4 - f ~ ~ 1.0202 1.0203 1.0203 1.0203 1.0136 110.13 110.13 Point Beach BS 3-4 1.0202 1.0203 1.0203 1.0203 1.0202 148.05 112.96 Point Beach BS 5 - Fox River 345-kV 1.0202 1.0203 1.0203 1.0203 1.0203 114.68 114.68 Line 151 Forest Junction - Fox River 345-kV 1.0202 1,0203 1.0203 1.0203 1.0203 117.67 117.67 Line 971L71 Point Beach BS 1 -New North 345-kV 1.0203 1.0203 1.0203 1.0203 1.0202 113.09 113.09 Line 111 Point Beach BS 3 - Kewaunee 345-kV 1.0202 1.0203 1.0203 1.0203 1.0203 117.99 117.99 Line Q-303 Forest Junction - Cypress 345-kV 1.0202 1.0203 1.0203 1.0203 1.0202 120.07 120.07 Line 971L51 Forest Junction 3451138-kV 1.0202 1.0203 1.0203 1.0203 1.0203 107.62 107.62 Transformer T I Forest Junction 3451138-kV 1.0202 1.0203 1.0203 1.0203 1.0203 107.62 107.62 Transformer T2 Fox River - N. Appleton 345-kV 1.0202 1.0203 1.0203 1.0203 1.0203 107.89 107.89 Line 6832 Sheboygan Energy - New East 345-kV 1.0202 1.0203 1.0203 1.0203 1.0202 114.03 114.03 Line L-SEC31 North Fox Energy Center Unit CT 1 NIA NIA NIA NIA NIA NIA NIA pppp - - -

FOXEnergy Center Unit CT 2 NIA NIA NIA NIA NIA NIA NIA FOXEnergy Center Unit ST NIA NIA NIA NIA NIA NIA NIA Sheboygan Energy Center Unit # I 1.0202 1.0203 1.0203 1.0203 1.0202 127.41 127.41 Sheboygan Energy Center Unit #2 NIA NIA NIA NIA NIA NIA NIA Point Beach Unit # I 4 1.0202 1.0203 1.0203 1.0203 1.0203 0 149.52 Point Beach Unit #25 1.0202 1.0203 1.0203 1.0203 1.0203 149.52 0 Kewaunee G I 1.0202 1.0203 1.0203 1.0203 1.0203 93.72 93.72 Point Beach Units # I & #26 1.0178 1.0178 1.0178 1.0178 1.0178 0 0 American Transmission Company Page 4 3 o f 132 10/2/2009

G83314-502213 ISIS Report

1. Included for Interconnection Customer's defined voltage levels:

a. Preferred: 352-kV to 354-kV

b. Normal: 351-kV to 358-kV

c. Maximum Permissible: 348.5-kV to 362-kV, any voltage outside of the Maximum Permissible range would be identified in Table A.3 as a Voltage Violation

2. The planning case used models both Point Beach units as regulating the respective POI bus voltage at the Point Beach substation to 1.0203 p.u (352 kV).

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345113.2-kV transformer isolated at this bus with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus.

4. This contingency is intended to model the emergency trip of Point Beach Unit # l . Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #I with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

5. This contingency is intended to model the emergency trip of Point Beach Unit #2. Assumes the 13.2-kV bus is split, separating the auxiliaiy loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

6. This contingency is intended to model an emergency dual unit trip modeled by the outage of each Point Beach generating unit, but maintaining the auxiliary load connection to the transmission system. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. Both generator Auxiliary loads are fed from their generator GSUs (23.4 MW and 13.9 MVAR each) and do not trip and are not moved. The Control Area replacement power was imported from TVA.

7. Fox Energy Center Units and Sheboygan Energy Center Unit #2 are off-line in the study case.

American Transmission Company Page 44 of 132

G83314-502213 ISIS Report Table A. 7 - Identified Thermal Violations zrnder select NERC Category C.3 events1 (TDF>J%), Summer Off-Peak 2013 70% Load Delivery to MIS0 with Proposed Solzrtion, Conlpeting Wind Far~n.sat 100% otctptrt Existing Required Potential Limiting Rating Ratingzn3 Worst TDF Solution Element Double Contingency (%)

(MVA) (MVA) Identified Cypress-Arcadian345 kV line 488SE 559SE NIA NO^

Lau Rd (Gel I)-ElkhartLake 138 kV line I 96 SE I 144 SE I I NIA I No5 Elkhart Lake-Saukville 138 kV line

/ SE I 122 SE 1 New East-Granville345 kV line New EastCedarsauk 345 kV line / NIA I No" New East-Holland 138 kV line I 283SE / 330SE I I NIA 1 No7 Holland-CharterSteel 138 kV line 1 283 SE 1 296 SE 1 / NIA I NoE Granville 3451138 kV transformer T3 I I

478SE 1 541 SE I I

Cypress-Arcadian 345 kV line Granville 345 kV bus tie 1-2

/

I I

I NoP I New North-Point Beach bus 1 345 kV I New North-Point Beach bus 2 345 kV line I 883 SE I 965 SE II line pointBeach 345 kV tie445Or Point Beach-Fox River 345 kV line I I NIA / No1O I New North-Point Beach bus 2 345 kV I New North-Point Beach bus 1 345 kV line 488 SE 985 SE line NIA No1' New NorthSheboygan Energy Center 345 kV line 1 488 SE I 608 SE 1 Point Beach-Fox River 345 kV line New North-New East 345 kV line Cypress-Arcadian 345 kV line I I NIA NoI2 New East-Granville345 kV line New East-Cedarsauk 345 kV line 653 SE 960 SE NIA ~0'3 Cypress-Arcadian 345 kV line

1. NERC Category C.3 events studied are limited to the concurrent outage of two elements without manual syst&nBdjustments between outages. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

2. Includes provision for 5% TRM. The required ratings are calculations using AC analysis in PSSIE dispatching G8331J022 and G8341J023 to all MIS0 generation.

3. SE = Summer Emergency

4. The line will be uprated to at least 572 MVA as part of G83314-J02213 interim upgrades. Whether additional 12 MVA is achievable without any significant constraints needs to be confirmed with Project Team. Generation redispatch using local generators would address the issue.

5. Generation redispatch using local generators would address the issue. The line will be uprated to 112 MVA per G6111G927 G-T interconnection. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (410 ACSR, 28.9 mile: Forest Junction-Elkhart Lake).

6. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (1-477 and 1-410 ACSR, 33.73 mile)

7. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (1033.5 at 167F, approximate length from new East substation to Holland: 8.2 miles)

8. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (1033.5 at 167F, length: 15 miles)

9. Generation redispatch using the local generators would address the issue. It is limited by the transformer (504 MVA SE) and equipment associated with the transformer. The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

American Transmission Company Page 45 of 132 10/2/2009

G833/4-502213 ISIS Report

10. Generation redispatch using local generators or taking the bus tie out of service during Point Beach generation refueling outage window would address the issue. It is limited by the portion of the existing line conductor (1-2156 ACSR, approximate length: 21 mile). The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

11. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/2010. The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

12. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/2010. The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

13. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE (required for new East Switching Station option). The existing line rating is limited by the line clearance (2156 ACSR @ 129F)

American Transmission Company Page 46 of 132

G83314-502213 ISIS Report Table A.8 - IdentiJied Thermal Violations under select NERC Category C.3 events1 (TDF>S%), Summer Peak 2013 100% Load Delivery to M S O with Proposed Solution, New North-Point Beach bus 1 345 kV line h Appleton-Kewaunee345 kV

1. NERC Category C.3 events studied are limited to the concurrent outage of two elements without manual system adjustments between outages. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

2. Includes provision for 5% TRM. The required ratings are calculations using AC analysis in PSS/E dispatching G833lJ022 and G834lJ023 to all MIS0 generation.

3. SE = Summer Emergency

4. Generation redispatch using local generators or taking the bus tie out of service during Point Beach generation refueling outage window would address the issue. It is limited by the portion of the existing line conductor (1-2156 ACSR, 11.32 mile). The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

5. Generation redispatch using local generators would address the issue. It is limited by the terminal equipment.

6. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/20 10.

7. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE (required for new East Switching Station option). The existing line rating is limited by the line clearance (2156 ACSR @ 129F)

American Transmission Company Page 47 of 132

G83314-J02213 ISIS Report Table A.9 - IdentiJied Thermal Violations under select NERC Category C.5 events1 Elkhart Lake-Saukville 138 kV line Cypress-Arcadian 345 kV line New East-Cedarsauk 345 kV line 653 SE 688 SE Germantown-Maple-Saukville138 kV NIA No6 line

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 3 4 5 - k ~and 138-kV facilities determined relevant based on engineering judgment.

2. Includes provision for 5% TRM. The required ratings are calculations using AC analysis in PSSIE dispatching G833lJ022 and G834lJ023 to all MIS0 generation

3. SE = Summer Emergency

4. Distribution factor was calculated assuming that Edgewater-Cedarsauk 345 kV line as the contingency corresponding to New East-Cedarsauk 345 kV line. Generation redispatch using local generators would address the issue. The line will be uprated to 112 MVA per G6111G927 G-T interconnection. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (410 ACSR, 28.9 mile: Forest Junction-Elkhart Lake).

5. Distribution factor was calculated assuming that Edgewater-Cedarsauk 345 kV line as the contingency corresponding to New East-Cedarsauk 345 kV line. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (1-477 and 1-410 ACSR, 33.73 mile).

6. Generation redispatch using local generators would address the issue. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE (required for new East Switching Station option). The existing line rating is limited by the line clearance (2156 ACSR @ 129F).

Table A.10 - IdentiJied Thermal Violations under select NERC Category C.5 events1 (TDF>5%), Summer Peak 2013 100% Load Delivery to M S O with Proposed Solution, Com~etina " Wind Farms at 20% o u t ~ z ~ t Existing Required Potential Rating RatingZsJ Worst TDF Limiting Double Contingency Solution Element (%) Identified (MVA) (MVA)

None identified

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit-toherline. The transmission elements studied are local 3 4 5 - k ~and 138-kV facilities determined relevant based on engineering judgment.

American Transmission Company Page 48 of 132

G83314-502213 ISIS Report Table A.11- Identitied Voltage Violations under select NERC Category C.5 events1 Szrmmer OfJlPeak 2013 70% Load Delivery to MISO, with Proposed Solution, Competing Wind

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

Table A. 12 - Identijied Voltage Violations under select NERC Category C.5 events1 Szrmmer Peak 2013 100% Load Delivery to MISO, with Proposed Solution, Competing Wind Farms at 20% ozrt~ut None Identified

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

American Transmission Company Page 49 of 132

G83314-J022/3 ISIS Report Table A.13 - Maximum Allowable Generationfor G833/J022 and G834/J023, With Stability Uppades, Without Thermal Upgradesfor Injection Limits G83314J02213 Max Output Worst Model Limiting Element with ATC Planned and Contingency Description1 Proposed Projectsz(MW)

New North-Point Beach MIS0 Summer Peak and Off-New North-Point Beach Bus 1 Peak 2013, and 118 MW3 345 kV line 345 kV bus 2 line Loads New East-Cedarsauk 345 kV New East-Granville 345 MIS0 Summer OfiPeak kV line 2013,70%Load 0 MW line

1. Study models are built based on the MIS0 DPP Cycle 2 models (April 2009 Versions)

2. Planned and Proposed projects from the latest ATC Ten Year Assessment report

( h t t r , : l / ~ ~ ~lOyearplan.conl/).

.atc

3. Max output allowed with the planned ATC Project PRO3208 in-service line. It uprates Line L111 to 1095 MVA (1 834 A). Estimated in-service date is 4/25/2010.

American Transmission Company Page 50 of 132

G83314-502213 ISIS Report Appendix B: Operation Restrictions American Transmission Company Page 51 of 132

G833/4-502213 ISIS Report Table B. 1 - Summary of IdentiJied Generation Restrictions due to Stability Constraints (With New Kewaunee substation, With Proposed Solution in service, With Minimum Excitation Limits at Point Beach and Kewaunee)

None American Transmission Company Page 52 of 132

G833/4-J022/3 ISIS Report Appendix C: Stability Analysis Results American Transmission Company Page 53 of 132

G83314-502213 ISIS Report Nomenclature K or KEW: Kewaunee P or POB: Point Beach (PI and P2)

S or SEC: Sheboygan Energy Center For FOX: Fox Energy NAP: North Appleton GVL: Granville CYP: Cypress ADN: Arcadian FJT Forest Junction TH: Thilmany Point Beach-Sheboygan Energy Center 345 kV L111:

line L121: Point Beach-Forest Junction 345 kV line Q-303: Point Beach-Kewaunee345 kV line L151: Point Beach-Fox Energy 345 kV line R-304: Kewaunee-NorthAppleton 345 kV line NAPL7I: North Appleton-Werner West 345 kV line CYP31: CypressArcadian 345 kV line 6832: North Appleton-Fox Energy Center 345 kV line TIO: Kewaunee TI0 3451138 kV transformer SEC31: Sheboygan Energy Center-Granville345 kV line H: High side KWH: KewauneeTI0 High side KWL: KewauneeTI0 Low side POBxy: Point Beach bus tie xy Y311 North Appleton-Fitzgerald 345 kV line CCT: Critical Clearing Time Note: The simulated clearing times and critical clearing times (CCT) noted in Appendix C contains planning margin described in Section 3.2 American Transmission Company Page 54 of 132

G83314-502213 ISIS Report Table C.1- Stability Results for Faults Clearing in Primary Time under Intact System Conditions (With G833/4-J022/3, With New Kewaunee substation, Without Proposed Solution)

Event Element Fault Faulted End Remote Remote End Event Simulated High Generation Low Generation File Faulted Location Breakers Location Breakers Notes Clearing FltPOBSEC Llll POB 111 SEC I-2,16 NOSPS 4.514.5 FltPOBFJT L121 POB 121,123 FJT 1-2,23 4.514.5 FltPOBFOX L151 POB 151 FOX 2-3,34 NOSPS 4.514.5 FltPOBKEW Q-303 POB Q-303 KEW Q-303 New 1 and 2 No SPS 4.514.5 FltKEWPOB Q-303 K M Q303 New 1 and 2 POB Q-303 4.514.5 FltKEWNAP R-304 K M R-304 New 1 and 2 NAP R-304 4.516.5 FltFOXPOB L151 FOX 2-3,34 POB 151 4.514.5 FltFOXNAP L6832 FOX 1-2.6-1 NAP 34-3,344,454,676 4.514.5 FltFOXFJT 971L71 FOX 4-5,M FJT 5-6,7-1 4.514.5 FltSECPOB L l l1 SEC 1-2,16 POB 111 4.514.5 FltSECGVL L-SEC3I SEC 1-2.3-6 GVL LSEC31 4.516.5 FltCYPADN LCYP3l CYP 1-2,M ADN L-CYP31 4.514.5 American Transmission Company Page 55 of 132

G833/4-502213 ISIS Report Table C.2 - Stability Resultsfor Double Circuit Single Line-to-Ground Faults Cleared in Primary Time under Intact System Conditions (With G833/4-J022/3, With New Kewaunee substation, Without Proposed Solution)

Event Fault Fault# I Fault #2 Simulated Fault File Clearing High Gen Low Gen

1. I Location #2 Location lime DC~-111-971~51.1 L l l l -Point BeachSheboygan345 kV 38.5% from POB 971K51 -Forest Junction-Howard's Grove 138 kV 33.9% from FJT 6.516.5

~~3-111-g71~51-2 L l l l -Point BeachSheboygan345 kV 16.3% from SEC 971K51 - Forest Junction-Howard's Grove 138 kV 6.3% from HOG 6.516.5 DC~-I1~-HOLG~I-I L l II- Point Beach-Sheboygan345 kV SEC HOGL21 -Howard's Grove-Holland 138 kV 76.9% from HOL 6.516.5 D C ~ -11I-HOLG~I-~ L l l l - Point BeachSheboygan345 kV 15.7% from SEC -

HOGL21 Howard's Grove-Holland 138 kV 31.4% from HOG 6.516.5

~~3-121-g71~51-1 L121-R. Beach-ForestJunction 345 kV FJT 971K51- Forest Junction-Howard'sGrove 138 kV FJT 6.516.5

~c3-121-971~51-2 L121-Pt. Beach-ForestJunction 345 kV 42.3% from FJT 971K51 - Forest Junction-Howard's Grove 138 kV 33.9% from FJT 6.516.5

~ ~ 3 ~ ~ ~ 3 1 3 4 3LSEC31 1 SheboyganGranville345 kV GVL 3431 - Granville-Saukville 345 kV GVL 7.517.5

~ ~ 3 6 ~ ~ 3 1 - 3 4 3 1 -LSEC3lSheboygan-Granville 2 345 kV 26.7% from GVL 3431 - Granville-Saukville 345 kV 25.3% from SAU 7.517.5

~ ~ ~ ~ ~ 3 1 a 2 3LSEC31-Sheboygan-Granville 1 - 1 345 kV 43.5% from GVL -

8231 Saukville-Barton 138 kV 36.4% from BRT 7.5R.5 DC~SEC~I~~~I-2 LSEC31Sheboygan-Granville345 kV 48.3% from GVL 8231 - Saukville-Barton 138 kV 36.4% from SAU 7.517.5

~c3-9932-2642-1 L- CYP3l - Cypress-Arcadian345 kV 32.0% frorn ADN 2642 - Saukville-Germantown 138 kV 34.2% from SAU 7.517.5 DC~-9932-2642-2 L- CYP3l - Cypress-Arcadian345 kV 16.6% from ADN -

2642 Saukville-Germantown138 kV GER 7.5R.5 DC~-9932-2661.1 -

L- CYP3l Cypress-Arcadian345 kV 10.8% from ADN -

2661 Germantown-Bark River 138 kV 31.5% from GER 8.518.5 DC~-9932-2661-2 L- CYP3l- Cypress-Arcadian345 kV 16.6% from ADN 2661 - Germantown-Bark River 138 kV GER 8.518.5 DC~-9932-9911-1 L- CYP3l - CypressArcadian 345 kV 10.8% from ADN -

9911 Granville-Arcadian345 kV 45.4% from GVL 7.5R.5 DC~-9932-991 1-2 L- CYP3l - Cypress-Arcadian345 kV ADN 9911 - Granville-Arcadian345 kV ADN 7.5R.5 American Transmission Company Page 56 of 132

G83314-J02213ISIS Report Table C.3 - Stability Results for 3-Phase Faults Cleared in Primary Time under Prior Outage Condition Units Tripping (With G833/4-J022/3, With New Kewaunee substation, With and Without Proposed Solution)

Note: Among various contingencies evaluated, only faults with stability issues are listed in Table C.3.

Primary Clearing Time, Prior Outage: 6832 (Fox Energy-NorthAppleton 345 kV line)

High Generation Low Generation With New With With New East With Proposed Without New Event Element Fault Faulted End Remote Remote End Event Simulated Without New Switching solution (fix East Proposed File Faulted Location Breakers Location Breakers Notes Clearing East Station East Switching solution (Fix Switching 11) Switching Station 11)

(4.514,5" (4.514.V"

, cvcle tested) . cycle tested) . Station

. (4.514.5" (4.514.5"

-..& ted-A\ ' -.-I-R-304 New NAP R-304 4.516.5 FltKEWNAP R-304 1 and 2

• Stable at 4.514.5 with G2 restricted to 600 MW gross (G2 restriction600 MW gross w'm R-304 breaker at NAP replaced)

'"4.5 cycles at remote end achieved by R-304 breaker replacement at North Appleton as documented in the G83314-J02213 Interim Operation Re-study Report Primary Clearing Time, Prior Outage: POB 2-3 Point Beach 345 kV bus tie 2-3)

High Generation Low Generation Event Element Fault Faulted End Remote Remote End Event Simulated h'ih0~t New East With Without New With New With File Faulted Location Breakers Location Breakers Notes Clearing New East Pmposed East East Proposed Switching Switching solution (Fix Switching Switching solution (Fix Station (Fix21 11) Station Station 11)

POB 121,123 FJT 1-2,2-3 4.514.5 FltPOBFJT LIZ1

• To be stable at 4.514.5, GI needs to be restricted to 580 MW gross

• TO be stable at 4.514.5, GI needs to be restricted to 620 MW gross American Transmission Company Page 57 of 132

G83314-J02213 ISIS Report Table C.4 - Stability Results for 3-Phase Faults Cleared in Delayed (Breaker Failure) Time under Intact Conditions, Units Tripping (With G833/4-J022/3, With New Kewaunee substation, Without Proposed Solution)

Intact System Breaker Failure Events April 2011 and beyond, WI new KewauneeSubstation Event Element Fault Remote Event Simulated High Gen Low Gen File Faulted Location Location Notes clearing time Existing 1 3.519.514.5 Existing 3.519.514.5 3.519.2514.5 . =#A ,,,. p BFIPOBSEC 1111 POB SEC TlX03 Tripped, Aux Moved 3.5110.014.5 rn BFIPOBFOX L151 POB FOX T2X03 Tripped, Aux Moved 3.5110.014.5 BFIPOBKEW Q-303 POB KEW Future: Delay POB Split, No TI0 Trip BFIKEWPOB Q-303 KEW POB Delay KEW TlO Trip BFIKEWNAP2 R-304 KEW NAP Delay KEW TI0 Trip BFlKEWXFH2 KEW T I 0 KWH KWL Future (Existng No BF possible)

'8.0 cycle clearing time will be achieved by relay upgrades scheduled for 2011 (see the G83314J022MInterim Operation Re-Study Report).

"The fault will be cleared in primary time due to a breaker addition in series with (2-303 scheduled for 2011 (see the G83314-J022/3 Interim Operation Re-Study Report). Breaker failure is not possible with the upgrade.

• • • According to protection, breaker failure clearing time will become 8.5 cycles with the planned Kewaunee bus reconfiguration project in-service. In addition, R-304 breaker at North Appleton will be replaced by 2010 (see the G83314J022/3 Interim Operation Re-Study Report)

American Transmission Company Page 58 of 132

G83314402213 ISIS Report Table C.5 - Stability Results for Point Beach Bus Single Line-to-Ground Faults Cleared in Delayed Time under Intact Conditions (With G833/4-J022/3, WithNew Kewaunee substation, Without Proposed Solution)

American Transmission Company Page 59 of 132

G83314-502213 ISIS Report Table C.6 - Stability Results for GSU Single Line-to-Ground Faults Cleared in Delayed Time under Intact Conditions, Units Tripping (With G833/4-J022/3, With New Kewaunee substation, WithoutProposed Solution)

POB GSU BF Faults Breaker Fault Location POB Unit 1 GSU Failure Element tripped POB Bus 2 Simulated Clearing 4.5113.5/14.0*

w High Gen OK OK Low Gen OK OK POB Unit 2 GSU POB Bus 4 4.5113.5

'-Primary Clearing TimelBus Breaker Failure TimelLine Breaker Failure Time (GSU # I Only)

American Transmission Company Page 60 of 132

G83314-J02213 ISIS Report Table C.7 - Stability Results for Auxiliary Transformer High Side Single Line-to-Ground Faults Cleared in Delayed Time under Intact Conditions, Units Tripping (With G833/4-J0221'3, With Nav Kewaunee substation, Without Proposed Solution)

Faulted Breaker Failure Element ElementTripped 1 5.1124.5 15.1124.5 1 POBAUXl HS 1 POB-SEC @ SEC POBAUX2 HS I POB-FOX @ FOX I Faulted Element I I

Breaker Failure Element Tripped 51/199* 6 1119.1.

POBAUXl HS I POB Bus 2n POBAUX2HS I POB Bus 4-

" -The Stability ModelTime Step is 025 cycles, so a 13.3 cycle tault actually clears In 13.5 cycles.

• • - POB-Forest Junction 345 kV line Trips, POB Generator 1 is Isolated.

• " - POB Generator 2 is isolated American Transmission Company Page 61 of 132

G83314-J02213 ISIS Report Table C.8 - Stability Resultsfor GSU Three Phase 345 kVFaults Cleared in Primary (5.5 cycles, including 1 cycle margin) Time under Intact and Prior Outage Conditions, Units Tripping (With G833/4-J022/3, WithNew Kewaunee substation, WithoutProposed Solution)

Fault Prior Outage I High Gen I -Low Gen Fault Prior Outage High Gen

- Low Gen HtPBGSUl None I FItPBGSU2 None OK OK FltPBGSUl 111 FItPBGSU2 111 OK OK FltPBGSUl 121 FltPBGSUl 151 FltPBGSUI Q-303 FltPBGSUl R-304 FltPBGSUl 6832 FltPBGSUl 971L71 FltPBGSUl L-SEC31 FltPBGSUl L-CYP31 FltPBGSUl T I0 FltPBGSUl NAPL7l FltPBGSUl 971L51 FltPBGSUl Y-311 FltPBGSUl 812 FltPBGSUl 823 FltPBGSUl B34 FltPBGSUl American Transmission Company Page 62 of 132

(383314-502213 ISIS Report Table C.9 - Stability Results for Auxiliary Transformer High Side 3-Phase Faults Cleared in Primary Time (6.1 cycles, including 1 cycle margin) under Intact and Prior Outage Conditions (With G833/4-J022/3, WithNew Kewaunee substation, With and Without Proposed Solution)

Without East Switching Station With East Switching Station With Proposed Solution (Fix 11)

Prior (Aux I )

Fault Outage High Generation Low Generation High Generation Low Generation High Generation Low Generation (5.7516.1) (5.7516.1) (5.7516.1) (57516.1) (5.7516.1) (5.7516.1)

FltPOBAXl None FltPOBAXl Ill FltPOBAXl 121 FltPOBAXl 151 FltPOBAXl Q-303 FltPOBAXl FltPOBAXl k t -

FltPOBAXl 971L51 tE3q-L FltPOBAXl FltPOBAXl

• SEC Gens Isolated

[

American Transmission Company Page 63 of 132

G833/4-502213 ISIS Report Without East Switching Station With East Switching Station With Proposed Solution (Fix 11)

Prior Fault (Aux 2) outage High Generation Low Generation High Generation Low Generation High Generation Low Generation (5.7516.1) (5.7516.1) (5.7516.1) (5.7516.1) (5.7516.1) (5.7516.1) 1 FltPOBAX2 1 1 Ill I

FltPOBAX2 L-SEC31 FltPOBAX2 L-CYP31 FltPOBAX2 T I0 FltPOBAX2 NAPL71 FltPOBAX2 971L51 FltPOBAX2 Y-311 FltPOBAX2 B12 FltPOBAX2 B23 FltPOBAX2 834 FltPOBAX2 845

'POB Unit 2 Isolated American Transmission Company Page 64 o f 132

G83314-J02213 ISIS Report Table C.10 - Stability Results for Kewaunee and Point Beach Generation Outage under Intact Conditions (With G833/4-J022/3, With New Kewaunee substation, Without Proposed Solution)

I UNITTRIP (

I Trip time (sec) ( Hih Gen I Low Gen I

POB G I 0.15 POB G2 POB GIG2 KEW 0.15 American Transmission Company Page 65 of 132

G83314-502213 ISIS Report Table C.11 * - Stability Results.for 3-Phase Faults at East Switching Station (Fix 2) Cleared in Delayed Time under Intact Conditions, (With ~833/4-~022/3, w i h New Kewaunee substation, With only East switching Station (Fix 2, part ofproposed solution))

Event File I Element Faulted I I

Fault

~ocation II Remote Location I Event Notes I I

Simulated clearing time I

I High Gen I I

Low Gen I BFIESSEDGWI I W-1 East I New East I Edgewater I e rips W-1 west I 3.5110.015.0 1 BFIESSSFL

- -... - I W-I West II New East II S. Fond du Lac I 1

T r i ~ W-1 s East 1I 3.5110.015.0 1 BFIESSSEC I L-SEC31 North I New East I Sheboygan Energy Center I L-SECSI south 1 3.5110.015.0 BFIESSGVL LSEC3l South New East Granville Trips L-SEC31 North 3.5110.0/5.0 BFIESSEDG796 796L41 East New East Edgewater Trips 796L41 South 3.511 0.015.0 BFIESSSAU 796L41 South New East Cedarsauk Trips 796L41 East 3.5/10.015.0

• Not re-run with the proposed solution (Fix 11) since stabilitywill only improve American Transmission Company Page 66 of 132

G833/4-J022/3 ISIS Report Table C.12** - Stability Resultsfor 3-Phase Faults at East Switching Station (Fix 2) Cleared in Primary Time under Critical Prior Outage Condition, (With G833/4-J022/3, With New Kewaunee substation, With only East switching Station (Fix 2, part ofproposed solution))

Primamy Clearing Time, Prior Outage: New East-Granville345 kV line*, New KEW Sub, New East sub Event Element I Fault I Faulted End 1 Remote I Remote End I Simulated I High Gen I Low Gen

• Fault on East-Cedarsauk 345 kV line under prior outage of East-Granville 345 kV line is evaluated as the worst prior outage event because, among the prior outage conditions at the new East switching station (Fix2), the outage of E&-~ranviile 345 kV line results in the highest power flow on the 345 kV linesout of new East switching station, particularly on the East-Cedarsauk 345 kV line.

• • Not re-run with the proposed solution (Fix 11) since stability will only improve American Transmission Company Page 67 of 132

G83314-J02213 ISIS Report Appendix D: Short Circuit 1 Breaker Duty Analysis Results Table D.l -Maximum and Minimum Fault Duties at the G833/4-J022/3 Point ofInterconnection

• POB G I and G2 offline and Q-303 out of service Table 0 . 2 - Thevenin Equivalent Impedances in Ohms covvesponding to Maximum Fault Duty American Transmission Company Page 68 of 132

G83314-J02213 ISIS Report Table 0 . 3 -Breaker Fault Duty Analysis for Breakers I Bn&rFadlD#~kn~k@~dCdI@rDlK 11weueIn FsmII C m d , Fink C 9 f i r QK In B m k r ~ I a d n J I American Transmission Company Page 69 of 132

0833/4-10ZW3 ISIS Report Page 70 of 132

G83314-J02213 ISIS Report Appendix E :Deliverability Analysis Results Table E . l - Deliverability Analysis Restrictions G83314502213 Limiting Element Contingency Potential Solution MW Deliverable I

None identified.

For a full description of the Midwest IS0 Generator deliverability process, follow the "Deliverability Study Whitepaper" link that can be found at:

h ~ ~ / / w w . ~ d ~ e ~ ~ k ~ t . ~ r ~ p1Q6~60936d4 ~ b ~ i ~ -767fOa48324a?rev==

~ 0 ~ ~ m ~ n ~ 3 ~ 2 d O (Navigate to: www.midwestmarket.org > Planning > Generator Interconnection > Generator Deliverability Tests)

American Transmission Company Page 71 of 132

G83314-502213 ISIS Report Appendix F: Study Criteria American Transmission Company Page 72 of 132

G83314-502213 ISIS Report Study Criteria F. 1 Contingencies For stability analysis, a set of branches in the vicinity of the generatorlpower plant of concern is selected as contingencies, based on engineering judgment. Fault analysis is performed for the following six categories of contingency conditions:

1. Three-phase fault cleared in primary time with an otherwise intact system.

2. Three-phase fault cleared in delayed clearing time (i.e. breaker failure conditions) with an otherwise intact system.

3. Three-phase fault cleared in primary clearing time with a pre-existing outage of any other transmission element.

4. Single Line Ground (SLG) bus section fault cleared in primary clearing time with an otherwise intact system.

5. SLG internal breaker fault cleared in primary clearing time with an otherwise intact system.

6. SLG fault of double circuits on common tower cleared in primary time with an otherwise intact system.

For power flow analysis, contingencies include:

1. N-1 contingencies - all lines and transformers operated at 69kV and above in the following control areaslzones: ATC Planning Zones 1-5 and ties to those zones and all branches of voltage level 69kV and above in the Dairyland Power Cooperative, Northern States Power Control Area, Commonwealth Edison, and Alliant Energy West control areas.

2. Selected N-2 and multiple contingencies that ATCLLC has determined to be significant.

F.2 Monitored Elements F.2.1Intact System, N-1,N-2 and Special Multiple Contingency Evaluation Using Linear Transfer Analysis Methods All load carrying elements operated at 69kV and above in the following control areaslzones were studied: ATCLLC Planning Zones 1-5 and ties to those zones, and all branches of voltage level 69kV and above in the Dairyland Power Cooperative, Northern States Power Control Area, Commonwealth Edison, and Alliant Energy West control areas.

A Transmission Reliability Margin (TRM) of 5% must be applied to the MVA ratings of each monitored ATCLLC element. Violations reported will be based upon the adjusted MVA rating.

American Transmission Company Page 73 of 132

G83314-502213 ISIS Report F.3 Thermal Loading Criteria F. 3.1 Injection Violations Generation injection violations include: 1) thermal violations of the transmission elements that connect the Generator to the rest of the transmission network (outlet congestion); 2) thermal violations of the transmission elements that have a transfer distribution factor (TDF) 2 5% for NERC Category A (system intact) conditions and TDF 2 20% for NERC Category B contingencies anywhere in the studied system in relation to real power injected at the Point of Interconnection (POI) when delivered to all of MISO; or 3) thermal violations created by the loss of a transmission element connected to the generator interconnection substation.

F.3.2 Operating Restriction Calculation Equipment Rating - [Line Flow - (Generation Output

• TDF)]

Allowable Output =

TDF F.4 Steady State Under Voltage Criteria F.4.1 Intact System, N-1 and Special Mzrltiple Contingency Evaluation Using ACCC Under intact system conditions, the voltage magnitude of all transmission system buses with a decrease of 0.01 per unit due to the Generator must not be lower than 0.95 per unit. Under contingency conditions, the voltage magnitude of all transmission system buses with a decrease of 0.01 per unit, due to the Generator, must not be lower than 0.90 per unit.

F. 4.2 N-2 Contingency Evaluation Power flow solutions must converge for a selected number of N-2 contingencies in the electrical proximity of the studied Generator. Divergence of a power flow solution indicates potential voltage collapse. A "fix" must be identified for any non-converging power flow simulation and may include generator operating restrictions. [Note: Non-convergence may be due to solution settings such as switched shunt operation andlor LTC action.]

F.5 Angular Stabiliw Criteria Critical Clearing Time (CCT) is a period relative to the start of a fault, within which all generators in the system remain stable (synchronized). CCT is obtained from simulation.

Maximum Expected Clearing Time (MECT) determines a period of time that is needed to clear a fault using the existing system facilities. MECT is dictated by the existing system facilities. In any contingency, if the computed CCT is less than the MECT plus a margin determined by ATC (1.0 cycle for studies using estimated generator data and 0.5 cycles for studies using confirmed generator data), it is considered an unstable situation and is unacceptable. Otherwise, it is considered acceptable transient stability performance.

American Transmission Company Page 74 of 132

G83314-502213 ISIS Report Longer time-domain simulations must be performed on faults cleared at the CCT to examine dynamic stability. Simulations will typically cover 20 seconds of system dynamics and machine angle oscillations must meet the damping criteria in the ATC Planning Criteria.

Note that ATC stability criteria and NERC stability criteria differ on the study assumptions used for breaker failure analysis. ATC study criterion models breaker failure by modeling a three-phase fault during the primary time, reduced to SLG fault if the failed breaker is an Independent Pole Operated (IPO) breaker during delayed clearing and cleared at the end of the delayed clearing time. On the other hand, NERC study criterion assumes a single line-to-ground fault for the entire breaker failure analysis. Hence, the CCT computed from ATC stability criteria is always less than or equal to the value computed using the NERC study criteria. This report assumes ATC stability criteria unless otherwise stated.

The time-domain simulations must also be reviewed for compliance with the transient and dynamic voltage standards in the ATC Planning Criteria. Voltages of all transmission system buses must recover to be at least 70% of the nominal system voltages immediately after fault removal and 80% of the nominal system voltages in 2.0 second after fault removal.

American Transmission Company Page 75 of 132

G83314-502213 ISIS Report Appendix 6:Typical Planning Level Cost Estimates American Transmission Company Page 76 of 132

G83314-502213 ISIS Report Typical Transmission Line and Substation Capital Costs -March 16,2006 It should be noted that the costs listed are merely representative for projects within each category. Actual project costs can vary, in some cases dramatically, based on the scope, location and particular design of the project. Capital costs include material, labor, licensing, design, land acquisition, environmental mitigation fees if applicable and project close-out. While some projects require additional costs of generator redispatch during construction outages, such costs are very project specific and have not been included in the estimates below.

Cost estimates for 345kV, 138kV, 115kV, 69kV T-Lines and Substations:

e New transmission line cost estimates include new structures, foundations, insulators, hardware, conductor, and easements shown in dollars per mile. No distribution underbuild costs are included.

0 Rebuilt transmission line cost estimates include 100% new structures, foundations, insulators, hardware, and conductor on existing ROWIeasements shown in dollars per mile. No distribution underbuild costs are included.

0 -

Reconductor transmission line cost estimates include 10 30% new structures & foundations, 100% new conductor, insulators, and hardware on existing ROWIeasements shown in dollars per mile. No distribution underbuild costs are included.

Uprate 69kV to 69kV or 138kV to 138kV transmission line cost estimates include 25% new structures, foundations to increase clearances, reuse existing conductor, insulators, and hardware on existing ROWleasements shown in dollars per mile. No distribution underbuild costs are included.

0 Uprate 69kV to 138kV transmission line cost estimates include 25% new structures, foundations to increase clearances, 100% new insulators, and hardware, and reuse existing conductor on existing ROWIeasements shown in dollars per mile. No distribution underbuild costs are included.

a Routing an existing transmission line into a new substation typically requires two terminals, particularly at 100 kV and above.

0 New substation cost estimate includes purchase and prepare site, control house, switches, bus, structures, breakers, and protection shown in dollars per terminals, transformers, and breakers at each voltage.

0 Installing a new transformer in a substation requires two terminals, one at the higher voltage and one at the lower voltage. Thus, a new 345-138 kV substation that incorporates an existing 345 kV line and two 138 kV transmission lines, all of which exist near the new substation site, would require three 345 kV terminals and five 138 kV terminals. Two spare terminals that include disconnect switches and bus, but no breaker, for each voltage, should be provided for future growth.

Transformer costs are shown for typical transformer sizes in each class, 500 MVA, 3451138 kV, and 3451115 kV; 100 MVA, 138169 kV and 115169 kV.

American Transmission Company Page 77 of 132 10/2/2009

G83314-J022/3 ISIS Report Typical Transmission Line and Szrbstation Project Capital Costs TRANSMISSION FACILITY TYPICAL CAPITAL COST UNIT IN 2006 $

New 345 kV single circuit line rural urban - -

$1,600,000 $2,2007000/Mile New 345 kV double circuit line rural urban - -

$3,000,000 $3,600,000/Mile New 345 kV HPFF single circuit UG line (w/o terminals) $1O,OOO,OOO/Mile New 345 kV HPFF UG line 2 terminals with shunt reactors $8,900,000 New 345 kV HPFF UG line 2 terminals without shunt reactors $4,300,000 New 138 kV single circuit line rural urban - -

$630,000 $800,00O/Mile New 138 kV double circuit line rural urban - -

$900,000 $1,100,000/Mile New 138 kV XLPE 1,200A single circuit UG line (wl terminals) $3,500,000/Mile New 138 kV HPFF 1,200A single circuit UG line (wl terminals) $3,500,000/Mile New 69 kV single circuit line rural urban - -

$450,000 $585,00O/Mile New 69 kV double circuit line rural urban - -

$650,000 $770,00O/Mile New 69 kV XLPE 550A single circuit UG line (wl terminals) $2,500,000/Mile New 69 kV HPFF single circuit underground line (wl terminals) $2,8007000/Mile Rebuild 138 kV to 138 kV single circuit -

$530,000 $700,00O/Mile Rebuild 138 kV to 138 kV double circuit -

$800,000 $1,000,000 /Mile Rebuild 69 kV to 138 kV, single circuit -

$530,000 $670,00O/Mile Rebuild 69 kV to 69 kV, single circuit -

$280,000 $330,00O/Mile Reconductor 138 kV or 115 kV line, single circuit $2 10,00O/Mile Reconductor 69 kV line, single circuit $1 17,0001Mile WV to 138 kV s i n s circuit -

$125,000 $200,00O/Mile Uprate 69 kV to 138 kV single circuit -

$350,000 $375,00O/Mile Uprate 69 kV to 69 kV single circuit -

$125,000 $150,00O/Mile 345 kV substation terminal1 $550,000 each 345kV gas circuit breaker2 $754,000 each 138 kV or 115 kV substation terminal1 $450,000 each 138kV gas circuit breaker2 $390,000 each 69 kV substation terminal1 $375,000 each 69kV gas circuit breaker2 $3 10,000 each 3451138 kV transformer4 (transformer only $2,700,000~) $5,000,000 each 138169 kV transformer6 (transformer only $1,405,000~) $2,500,000 each Notes:

All substation costs are in year 2006 dollars.

1 .

includes dead end structure, line switch and line terminal relays

' includes breaker, two maintenance switches, breaker failure relay, controls 300/400/500 MVA unit includes high and low side switches and transf. relays includes transformer3,2-345kV GCBS' and 2-138kV GCBS'

'100 MVA unit, includes high side and low side switches and transf, relays includes transformer5, 2-138kV GCBS', and 1-69kV GCB' American Transmission Company Page 78 of 132

G83314-J02213 ISIS Report Appendix H: Alternatives Considered American Transmission Company Page 79 of 132

G83314-502213 ISIS Report The transmission system near Point Beach has five large generating stations (Point Beach, Kewaunee, Fox River, Sheboygan Energy Center, and Cypress) with a total generating capability of approximately 3000 MW and only four 345 kV lines connecting this generation to the rest of the system. Three additional wind generation projects with a total rated generation of approximately 350 MW and queue positions below G83314-502213 (G590, G611, and G773) are located on the Fox Valley 138 kV system near Forest Junction. These three projects were not modeled in the G833-4 study stability analysis because of their location on the 138 kV system, but they were modeled in the study's thermal analysis. This combination of high generation and relatively few transmission outlets produces stability issues with the existing system strength and fault clearing times, in particular at Kewaunee and North Appleton which have slower breakers and longer clearing times than other area busses.

As documented in the G83314-502213 Interim Operation Re-study Report, the possible unit restrictions andor interim system upgrades are identified and planned to accommodate the G83314-J02213 during the interim periods. After implementation of the upgrades needed for "interim" operation, there are several issues that must be addressed to ensure that the Point Beach generation increase is reliable beyond temporary operation. The issues are:

(1) Generator instability due to the isolation of Point Beach Generator 1 on L111 (Point Beach-Sheboygan) which occurs when Point Beach 345 kV breaker 2-3 is out of service and L121 (Point Beach-Forest Junction 345 kV) trips, (2) Generator instability due to the outage of 6832 (Fox River-North Appleton) followed by a fault on R-304 (Kewaunee-North Appleton),

(3) Most significantly, limitations on Point Beach and Kewaunee generating unit reactive power output at all hours. Generator instability was identified for fault conditions when Point Beach and Kewaunee units produce relatively small reactive power output (over-excitation) or absorbs reactive power from transmission system (under-excitation).

Reactive power output from a synchronous machine has an impact on the transient stability of the unit. Typically, the lower the excitation on a generating unit, the unit tends to be less stable under a fault condition. The results of the 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. The units may not be allowed to reduce their MVAR outputs, reducing their effectiveness in controlling system voltage As described in the Interim Operation Re-study Report, for temporary operation, Issue (1) and (2) should be mitigated by reducing generation at Point Beach to 580 MW (G1 gross) and 600 MW (G2 gross) respectively, and Issue (3) should be mitigated by maintaining MVAR output from Point Beach and Kewaunee to a certain level through the use of Minimum Excitation Limiter settings. Issue (I) may be addressed by a long term solution such as reconfiguring the existing Point Beach substation such that Point Beach Unit #I cannot be isolated on 345-kV line Ll 11. However, a more robust long term solution such as a new 345 kV line andor substation will be needed to address Issue (2) and Issue (3). Issues (2) and (3) can not be solved by reconfiguring Point Beach such as ring bus configuration because the issues are primarily due to the limited number of 345-kV outlets out of Fox Valley area for the amount of generation located in this area.

American Transmission Company Page 80 of 132

G833/4-502213 ISIS Report As shown in Appendix H.l, various options are being studied to identifl a Network Upgrade that:

Addresses the generation instability issues under prior outage conditions, Provides a wider operating envelope for the local transmission system and the interconnected generators by permitting generating unit operation at unity or under-excited conditions Provides better maintenance and operations flexibility during planned or unplanned transmission outage conditions by tying together critical transmission elements in strategic locations and, possibly, providing an additional transmission outlet, and Relieves loadings under intact and contingency conditions on the existing 138 kV and 345 kV lines running from Fox Valley area to the south by providing an additional transmission outlet.

Appendix H.l presents a description of the various options considered as well as geographic representations of the various options.

To screen and select options for hrther consideration, the dynamic stability study was performed. The Power System Stabilizer (PSS) models supplied by the customer for both units

1. 1 and #2 were assumed in-service. Scenarios with each solution option were built from the high and low generation cases used for the dynamic stability study for the Interim Operation Re-study. The high generation scenario consists of all generation on-line in the Point Beach area, which primarily stresses the system for prior transmission outage conditions due to the limited number of 345-kV outlets from this area. The low generation scenario is similar to the high generation scenario except the Fox Energy and Sheboygan Energy gas-fired power plants are off-line, which primarily stresses the system for breaker failure conditions due to the lower system inertia.

As shown in Appendix H.1 and Appendix H.2, thirteen different options were evaluated for transient stability performance by applying the critical faults identified in the Interim Operation Re-study listed under the period with completion of the G833/4 and .7022/3 requests and completion of the Kewaunee bus reconfiguration project. The critical faults are:

Fault on L l l l (Point Beach-Sheboygan Energy Center) at Point Beach with breaker failure Fault on L151 (Point Beach-Fox River) at Point Beach with breaker failure Fault on Q-303 (Point Beach-Kewaunee) at Point Beach with breaker failure. The 4-303 breaker failure may be able to be disregarded if a breaker is added in series with the existing Q-303 breaker at Point Beach as described in the interim operation study report.

Fault on R-304 (Kewaunee-North Appleton) at Kewaunee with breaker failure Fault on R-304 (Kewaunee-North Appleton) at Kewaunee with prior outage of 6832 (North Appleton-Fox River)

Fault on L121 (Point Beach-Forest Junction) at Point Beach with prior outage of Point Beach 345 kV bus tie 2-3 Two types of stability analyses were performed to screen and measure the robustness of each option. As shown in Section H.2.1 of Appendix H.2, the maximum critical clearing time was identified under the critical faults for each option. For this specific study, Point Beach and Kewaunee 345 kV voltage schedule was set to 352 kV to maintain Point Beach 345-kV bus American Transmission Company Page 81 of 132 10/2/2009

G83314-J02213 ISIS Report voltage at the low end of the preferred voltage range and set MVAR output from Kewaunee and Point Beach to typical historical levels. The maximum critical clearing time is the slowest fault clearing time for which no units will lose synchronism. Thus, the longer clearing time for an option represents a more robust system solution.

The second type of analysis is shown in Section H.2.2 of Appendix H.2. This analysis examined the minimum allowable MVAR output from the Point Beach and Kewaunee units while maintaining synchronism for the critical faults by varying the voltage schedule of these generators. This analysis should not be interpreted as permitting or requiring a change in voltage schedule to the values noted in the table. Rather, varying the voltage schedule is simply a method for varying the excitation on the unit. This analysis identifies the options that allow generating unit operation at unity or leading (i.e. under-excited) power factor, or at least provide a foundation to achieve the wider operating envelop through additional transmission reinforcement in the area that may be needed in the future.

Among the thirteen options studied, four options were identified as alternatives due to their dynamic stability performance. These options are described more fully in Section H.3.1 of Appendix H.3 and are summarized as:

1. Fix 2 (new "East" 345 kV switching station),

2. Fix 5 (new "East" and new "North" 345 kV switching stations with a new 345 kV line, -32 miles),

3. Fix 11 (new "East" 3451138 kV substation and new "North" 345 kV switching substation with conversion of existing 138 kV line to 345 kV, -48 miles) and

4. Fix 13 (new "East" 345 kV switching station and approximately 41 miles of new double circuit 3451138 kV lines from Forest Junction to the "East" substation).

These options were selected because they address stability issues adequately, provide a wider operating range (except Fix 2) of MVAR output from Point Beach and Kewaunee, unload parallel facilities and provide an alternate route since the Certificate of Public Convenience and Necessity (CPCN) process at the Public Service Commission of Wisconsin (PSCW) requires both route and system alternatives. Based on the further analysis, Fix 11 is selected as the proposed solution because it:

= Achieves the widest operating envelop for the local transmission system and the interconnected generators by permitting generating unit operation to unity or under-excited conditions.

Addresses the transient stability issues with certain level of MVAR output maintained from Point Beach and Kewaunee.

Achieves better maintenance and operations flexibility during planned or unplanned transmission outage conditions by tying together critical transmission elements in strategic locations and providing an additional transmission outlet.

Unloads the existing 138 kV and 345 kV lines running from Fox Valley area to the south under intact and contingency conditions by providing an additional transmission outlet. As a benefit, the proposed solution (Fix 11) would also help Wisconsin to accommodate potential future wind development in the area.

Fix 2 is a common facility required for Fix 5, Fix 11 and Fix 13. However, Fix 2 does not immediately allow wider MVAR operating range unless additional transmission reinforcement shown in Fix 5, 11 and 13 are combined and implemented with Fix 2.

American Transmission Company Page 82 of 132 10/2/2009

G83314-502213 ISIS Report Although Fix 5 and Fix 13 immediately allow wider MVAR operating range, they are not better than Fix 11 (see Appendix H.3).

Fix I1 (roughly $129 million) would require relatively less construction cost than Fix 5 (roughly $182.3 million) and Fix 13 (roughly $219.3 million). As noted in Table 1.2, the cost of Fix 11 may increase depending on the condition of the existing double circuit 3451138 kV structures (L111, portion of L-SEC3 1, 971K5 1 and portion of HOLG2 1). More detailed analysis will be performed during the Facilities Study to determine the condition of the existing structures.

Compared to Fix 11, significant challenge is expected for Fix 5 and Fix 13 primarily due to relatively extensive new right-of-way for new 345 kV and (or) 138 kV lines.

Options rejected from further consideration are Fix 1 (new West 345 kV switching station): it does not address the stability issue under prior outage of Point Beach bus tie 2-3. Generally, it does not provide better stability performance than Fix 2 (new East 345 kV switching station).

Fix 1 plus Fix 2 (new West and East 345 kV switching stations): constructing East and West 345 kV switching stations together does not significantly improve stability response.

Fix 3 (new West 345 kV switching station and a new 345 kV line from Forest Junction to West): This option also requires new 345 kV line (-42 miles) from Forest Junction to new West switching station. It does not address the stability issue under prior outage of Point Beach bus tie 2-3. In addition, this does not provide any significant improvement than new East 345 kV switching station.

Fix 6 (a new second 345 kV line from North Appleton to Fox River): This option requires constructing a new second 345 kV line (-9.8 miles) from North Appleton to Fox River. It does not address the stability issue under prior outage of Point Beach bus tie 2-3. It provides better stability response only under prior outage of 6832.

Fix 7 (new East 345 kV substation and new North 345 kV switching station and conversion of 971K5 1 and portion of existing 138 kV line HOLG21 to 345 kV): This option requires converting approximately 48 miles of existing 138 kV line to 345 kV in addition to building a new East and North 345 kV stations. It also requires constructing new 138 kV lines (- 16 miles) to continue serving the existing 138 kV substations and installing a new 3451138 kV transformer at new East Switching Station. This option provides significant improvement in stability response. However, it is not selected for hrther analysis since this option does not provide better stability performance than Fix 11 (Fix 7 plus 345 kV line L121, which is a Point Beach outlet, looped into North switching station) for a fault on L1 11 with breaker failure at Point Beach.

Fix 8 (Fix 5 plus 3451138 kV transformer at North Substation, loop 971K51 into the North 138 kV substation): In general, this option does not provide significantly better stability response than Fix 5 (new North and East 345 kV line, -32 miles) which is selected for further analysis. It appears that installing a new 3451138 kV transformer at North substation and looping the existing line 971K51 does not provide significant benefit from a stability perspective.

Fix 9 (Fix 8 plus converting Forest Junction-North 138 kV line to 345 kV): In addition to implementing Fix 8, this option also requires converting Forest Junction-North 138 kV American Transmission Company Page 83 of 132 10/2/2009

G83314-502213 ISIS Report line (-16 miles) to 345 kV. For similar reason described for Fix 8, it is not selected for fbrther analysis.

Fix 10 (new North switching station): This option requires constructing only the North 345 kV switching station. It does not address the stability issue under prior outage of 6832. In general, it does not perform better than Fix 2 from a stability perspective.

Fix 14 (Fix 7 without looping 796L41 (Edgewater-Cedarsauk 345kV) into new East Switching Station): This option was tested to understand the impact of looping 796L41 into the new East Switching Station. No significant stability impact was identified due to 796L41 looped into the new East Switching Station. However, looping 796L41 into new East Switching Station is preferred primarily because it will reduce the exposure to the outage of the existing Edgewater-Cedarsauk 345 kV line (-33.29 miles).

American Transmission Company Page 84 of 132

G83314-J02213 ISIS Report Appendix H.1.

Options Studied (Option Description and Geographical Maps)

American Transmission Company Page 85 of 132

G83314-J02213 ISIS Report Fix I + Fix 2 New West (Fix 1) and East (Fix 2) 345 kV Switching Stations with 345 kV lines looped into the switching stations New West 345 kV Switching Station and Loop existing W-I and CPY31 into the switching station (Fix I),

Fix 3 Build a new Forest Jct-West 345 kV line New East 345 kV Switching Station and Loop existing W-1, L-SEC31 and 796L41 into the switching station (Fix 2),

New North 345 kV Switching Station, Fix 5 Loop L111 and L121 into the North switching station, Build a new North-East 345 kV line Fix 6 Build a new second Fox River-N Appleton 345 kV line New East 3451138 kV substation and Loop existing W-1, L-SEC31 and 796L41 into the substation (Fix 2),

Convert existing 971K51 and portion of HOLG21 to 345kV, Modified North 345 kV Switching Station (Loop LA11 and converted 971K51 into the station),

Fix 7 New 3451138 kV transformer at East substation, New East-Plymouth #4-Howards Grove-Erdman 138 kV line, Loop Mullet River-South Sheboygan Falls 138 kV line into the East 138 kV substation, Terminate the remaining 138 kV line to Holland at the new East substation New East 345 kV Switching Station and Loop existing W-1, L-SEC31 and 796L41 into the switching station (Fix 2),

New North 3451138 kV substation (Loop L l l l and L121 into the station),

Fix 8 New 3451138 kV transformer at North, Build a new North-East 345 kV line, Loop existing 971K51 (Forest Jct-Howards Gr) and L-90 (Glenview-Shoto) into the new North 138 kV substation Fix 9 Fix 8 plus convert existing Forest Junction-North 138 kV line to 345 kV New North 345 kV Switching Station only Fix 10 Loop L121 and LA11 into the station Fix 11 Fix 7 plus loop L121 into North substation Center Line Conversion Option:

New East 345 kV Switching Station and Loop existing W-1, L-SEC31 and 796L41 into the switching station (Fix 2),

Rebuildlconvertexisting 138 kV lines 4035,971K91, portion of 40561, portion of 8241 to double-circuit 3451138 kV, Construct a new Mullet River 138 substation near the existing Mullet River 138169 kV substation Fix 13 Relocate all 138 kV facilities at the existing Mullet River 138169 kV substation to the new Mullet River 138 kV substation, Terminate the southern portions of 8241 (Elkhart Lake-Saukville)and 40561 (Meyer Rd-Lyndon) into the new Mullet River substation to form Mullet River-Saukvilleand Mullet River-Lyndon Construct a new 138 kV line from Erdman to Howards Grove Fix 14 Modified Fix 7: 796L41 (Edgewater-Cedarsauk 345kV) is not looped in the new East substation American Transmission Company Page 86 of 132 10/2/2009

G83314-502213 ISIS Report American Transmission Company Page 87 of 132

G83314-J02213 ISIS Report American Transmission Company Page 88 of 132

G83314-502213 ISIS Report American Transmission Company Page 89 of 132

G83314-J02213 ISIS Report American Transmission Company Page 90 of 132

G83314-502213 ISIS Report American Transmission Company Page 91 of 132

G83314-502213 ISIS Report American Transmission Company Page 92 of 132

G83314-502213 ISIS Report American Transmission Company Page 93 of 132

G833/4-J022/3 ISIS Report Appendix H.2.

Stability Study Results for Each Option Section H.2.1: Performance of Each Option Based on Maximum Critical Clearing Time (Critical Events Studied by Increasing Clearing Times)

Section H.2.2: Performance of Each Option Based on Allowable Minimum MVAR Outputs from Point Beach and Kewaunee (Critical Events Studied at Certain Tested Clearing Times)

American Transmission Company Page 94 of 132

G83314-.TO2213ISIS Report Nomenclature K or KEW: Kewaunee P or POB: Point Beach FLT: Fault cleared in primary time BF: Fault cleared in breaker failure time PO: Prior Outage High Gen High generation scenario Low Gen Low generation scenario American Transmission Company Page 95 of 132

G83314-502213ISIS Report H.2.1: Performance of Each Option Based on Maximum Critical Clearing Time (Critical Events Studied by Increasing Clearing Times)

Estimated critical clearing time (With Kewaunee, With 683314, at 352 kV Voltage Schedule at POB and KEW)

(For breaker failure, breaker clearing time at faulted end was increased. For primary fault, clearing time at faulted end was increased.)

F il Fw 2 Fat li+2 Fix3 Fot5 Fix 6 Fut 7 Low Gen a Critical Events High Gen Low Gen - Low Gen -High Gen

- Low Gen -Migh Gen - Low Gen - High Gen

- Low Gen -

High Gen B F L l l l @POB 10 9.5 9.25 10 95 10.5 9.5 12.5 11 9.5 9.25 11 9.5 BF L151@ POB I 11 9.5 12 1 10.5 1 11.5 I 10 1 12.5 1 11 1 10.5 1 9.5 ( 12.5 1 11.0 BFQ-303 @POB 1 10.5 1 9.5 1 10.5 1 9.5 1 10.5 1 9.5 1 10.5 1 9.5 11 10 1 10.5 1 9.5 I 11.0 1 10.0 BF R-304 @ KEW 12 10 12.5 11 13 11.5 12.5 10.5 14 12.5 11.5 10 13.5 12.0 FLT R-304 @ 5.514.5 NIA 5.514.5 NIA 6.514.5 NIA 6.514.5 NIA 7.014.5 NIA 7.014.5 NIA 6514.5 NIA KEW- PO 6832 I FLT I21 @ POB-POB23 American Transmission Company Page 96 of 132

G83314-502213 ISIS Report Maximum Critical Clearing Time (352 kV voltage schedule, With new Kewaunee, With G833/4 (JOW3))

0 1 2 3 4 9 6 7 8 9 10 11 12 13 14 Cycles American Transmission Company Page 98 of 132

G83314-J02213 ISIS Report H.2.2: Performance of Each Option Based on Allowable Minimum MVAR Outputs from Point Beach and Kewaunee (Critical Events Studied at Certain Tested Clearing Times)

Estimated Voltage Settings at Point Beach and Kewaunee for stable system under critical events tested (Tested Voltage settings are 353kV, 352 kV, 351 kV, 350 kV, 349 kV, 348 kV, 547 kV, 346 kV, 345 kV, 344 kV and 343 kV)

I Fx i2 I Fix3 I I American Transmission Company Page 99 of 132

G83314-502213 ISIS Report MVAR outputs from Point Beach and Kewaunee at the EstimatedVoltage Schedules American Transmission Company Page 100 of 132

142.0 -1288 1 47.2 61A I 257 a1234 1 -H2

.slcls' g-g Ql WB MA -76.6 NIA 86.6 NIA -734 MIA a.

0 NIP, -729 MIA NIA -76.6 NIA 66.8 MA -73.4 MIA 1m M Amaican Traasmisslon Company

G83314-J02213 ISIS Report American Transmission Company Page 102 of 132

G83314-J02213 ISIS Report High Gen MVARoutputs from Point Beach and Kewaunee at the Voltage Schedules shown in "By Voltage Level" worksheet I Fot 14 I FK 13 I Fot 11 I Fot 10 IFot 9 B Fot 8 I Fot 7 I Fot 6 IFot5 0 Fot 3 0 Fot l+2 I Fot 2 I Fot 1 MVAR (POBKRN)

American Transmission Company Page 103 of 132

G83314-502213 I S I S Report Low Gen MVARoutputs from Point Beach and Kewaunee at the Btimated Voltage Schedules r Foc 14 r Fot 13

~ F o 11 c

r Fot 10 r Fot 9 0 Fot 8 I Fot 7 r Fii 6 r Foc 5 Fot 3 FK l+2 I Fat 2 r Fot I

-150 -100 -50 0 50 I00 150 200 MVAR (POB+lWY)

American Trammission Company Page 104 o f 132

G83314-502213 ISIS Report Appendix H.3.

Options Selected For Further Analysis Section H.3.1. Options Selected Section H.3.2 Performance Comparison Section H.3.3. Thermal Analysis for Fix 2 Nomenclature K or KEW: Kewaunee P or POB: Point Beach FLT: Fault cleared in primary time BF: Fault cleared in breaker failure time PO: Prior Outage High Gen High generation scenario Low Gen Low generation scenario American Transmission Company Page 105 of 132

G83314-502213 ISIS Report H.3.1. Options Selected for Further Analysis New East 345 kV Switching Station and Loop existing W-1, L-SEC31 and 796L41 into the switching station (Fix 2),

New North 345 kV Switching Station, American Transmission Company Page 106 of 132

G83314-J02213 ISIS Report H.3.2 Performance Comparison

- Maximum Critical Clearing Time (Critical Events Studied by Increasing Clearing Times)

American Transmission Company Page 107 of 132

G83314-J02213 ISIS Report I Maximum Critical Cbaring Time BRX13 PRX 11

.Fix2 Interim 2b

- Rday W l i t y American Transmission Company Page 108 of 132

G83314-J02213 ISIS Report

-Allowable Minimum MVAR Outputsfrom Point Beach and Kewaunee (Critical Events Studied at Certain Tested Clearing Times)

American Transmission Company Page 109 of 132

G83314-502213 ISIS Report BF L l II@ POB (3.519.014.5)

BF L151@ POB (3.519.514.5)

BF (2-303 @ POB (3.519.2514.5)

BF R-304 @ KEW (3.519.514.5)

POB GI 153.3 -31.4 -76 -76.6 -66.6

- (WAR)

POB 62 153.3 -31.4 -76 -76.6 66.6 FI~R-304@ KEW PO 6832 - (WAR)

(4.514.5) KEW GI 154.1 20.9 -21.I -29.3 -17.3

, (WAR)

TOTAL (MVAR) 460.7 -41.9 -173.1 182.5 -150.5 POB GI 142.3 -50.5 -98.7 -104.1 -57.6 (MVAR)

POB 6 2 85.3 -40.7 -72.5 -69.8 -40.6 Flt 121 @ POB - PO 823 , (MVAR)

(4.514.5) KEW G1 87.5 -60 -60 -60 -60 (WAR)

TOTAL (WAR) 315.1 -151.2 -231.2 -233.9 -158.2 BF Total (WAR) 478.7 330.4 -185.3 -198.7 28.5 PO Total (MVAR) 775.8 -193.1 -404.3 -416.4 308.7 All Total (WAR, BF Total + PO Total) 1254.5 137.3 -589.6 -615.1 -280.2 American TransmissionCompany Page 110 of 132

G83314-502213 ISIS Report BF L l 11 @ PO0 (3.519.014.5)

BF L151 @ PO0 (3.519.514.5)

BF Q-303 @ POB (3.519.2514.5)

BF R-304 @ KEW (3.519.514.5)

POB G l 115.4 -29.3 -54.2 -59.3 -38.5 (WAR)

POB 62 82.3 13.1 9.6 4.4 6.9 Flt 121 @ POB - (WAR)

PO 823 (4.514.5) KEW G1 83.0 -60 -60 -60 -60 (WAR)

TOTAL (WAR) 280.7 -76.2 104.6 114.9 -91.6 BF Total (MVAR) 563.2 405.1 78.2 16.7 265.5 PO Total (WAR) 280.7 -76.2 -104.6 -114.9 -91.6 All Total (WAR) 843.9 328.9 -26.4 -982 173.9 American Transmission Company Page 11 1 of 132

I I 2500.0 Sum of WAR Outprrtshwn bwaunae and Polnt Bsach (HlpR + Lwv Smnadoa)

-4 m . 0 - --

1500.0 -

1mb-- -

I 486.2 m- - -

0.0 - - I ,

-W.O

-1m.o ngrbnl For2 Fa 5

-1" Altarnnhm Vm Inlorlm ab

-71x3 Fa 11 Wr 13 American Transmission Company Page 1 12 of 132

G83314-502213 ISIS Report Section H.3.3. Thermal Analysis for Fix 2 (East Switching Station)

American Transmission Company Page 113 of 132

G83314-502213 ISIS Report Table H.3.3.1 -Identified Thermal Violations Due to G833/4-J022/3 Summer Off-Peak 2013 (70% Load) Delivery to =.for NERC Category A and B events (TDF>5%)

~ i t Fix h 2 (East ,- switch in^

0 Station) , in Sewice. CornDetin~ " wind Farms at 100% out~zrt Existing Required Limiting Element Rating Rating (MVA)'sZ Worst Contingency3 TDF

(%)

injection Limit z:y2 Identified (MVA)

Point Beach-Sheboygan Energy Center 345 kV line I 488 SE I 529 SE I Cypress-Arcadian 345 kV line 1 1 52.9 Yes I Yes4 New East-Cedarsauk 345 kV line 653 SE 847SE New East-Granville345 kV \ine NIA Yes No5

1. Includes provision for 5% TRM. The required ratings are calculated using AC analysis in PSS/E dispatching 100% of power from G83314-J02213 to MISO.

2. SN = Summer Normal, SE = Summer Emergency

3. Local Special Protection Systems are included if designed to operate for NERC Category A or B events

4. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/20 10

5. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE. The existing line rating is limited by the line clearance (21 56 ACSR @ 129F).

Table H.3.3.2 - Identified Thermal Violations Due to G833/4-J022/3 Summer Peak 2013 (100% Load) Delivery to MSO.for NERC Category A and B events (TDF>5%)

With Fix2 ( E Aswitch

- ~ in^ ~tationjin sewice. Com~etinawind Farms at 20% Outout Existing Required Potential Worst TDF Injection Limiting Element Rating Rating Solution Contingency (%) Limit (MVA) (MVA)'J identified None Identified American Transmission Company Page 114 of 132

G83314-502213 ISIS Report Table H.3.3.3 - IdentiJied Voltage Violations Due to G833/J022 and G834/J023 Summer OfS-Peak 2013 (70% Load) Delivery to M1;SOfor NERC Category A & B events (A V > 0.1

y. I!.), bVith Fix2 (East Switching Station) in Service, Competing Wind Far-ins crt 100% output Voltage (p.u.)

Potential Limiting Worst Pre Post AV (P.u.) Solution Element Contingency G83314- G83314- Identified JO2213 J02213 None identified Table H. 3.3.4 - Identz$ed Voltage Violations Due to G833/4-J022/3 Summer Peak 2013 (100% Load) Delivery to MISO for NERC Category A & B events (A V > 0.I p.u.),

With Fix2 (East Switchina Station) in Sewice. Comvetin~Wind Farms at 20% outwzit L,

Voltage (p.u.)

Potential Worst Limiting Element Pre Post AV (P.u.) Solution Contingency G83314- G83314- Identified JO2213 JO2213 None ldentified American Transmission Company Page 115 of 132

G83314-502213 ISIS Report Table H.3.3.5.1 - Voltage Measzrrements at the Point Beach 345-kV Substation with Fix2 (East Switching Station), Summer 2013 Peak Load with Selected contingencies1 fwithotrt Minimtrm Excitation Limits)

Intact System 1.0203 1.0203 1.0203 1.0203 1.0203 59.48 59.48 Point Beach BS 2-3 1.0203 1.0203 1.0203 1.0203 1.0203 76.74 34.61 Point Beach BS 2 -Forest Junction 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 49.98 49.98 Line 121 Point Beach BS 1-2 1.025 1.0203 1.0203 1.0203 1.0203 64.13 64.13 Point Beach BS 4-53 1.0203 1.0203 1.0203 1.0203 1.0224 66.8 66.8 Point Beach BS 3-4 1.0203 1.0203 1.0203 1.0203 1.0203 65.2 74.01 Point Beach BS 5 - Fox River 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 67.86 67.86 Line 151 Forest Junction - Fox River 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 83.37 83.37 Line 971L71 Point Beach BS 1 - Sheboygan Energy 345-kV 1.0203 1.0203 1.0203 1.0203 65.28 65.28 Line 111 Point Beach BS 3 - Kewaunee 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 74.81 74.81 Line Q-303 Forest Junction -Cypress 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 63.95 63.95 Line 971L51 Forest Junction 3451138-kV 1.0203 1.0203 1.0203 1.0203 1.0203 54.03 54.03 Transformer T I Forest Junction 3451138-kV 1.0203 1.0203 1.0203 1.0203 1.0203 54.03 54.03 Transformer T2 Fox River - N. Appleton 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 64.57 64.57 Line 6832 Sheboygan Energy - New East 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 77.24 77.24 Line L-SEC31 North Fox Energy Center Unit CT 1 1.0203 1.0203 1.0203 1.0203 1.0203 61.43 61.43 Fox Energy Center Unit CT 2 1.0203 1.0203 1.0203 1.0203 1.0203 61.43 61.43 Fox Energy Center Unit ST 1.0203 1.0203 1.0203 1.0203 1.0203 59.56 59.56 Sheboygan Energy Center Unit # I 1.0203 1.0203 1.0203 1.0203 1.0203 68.03 68.03 Sheboygan Energy Center Unit #2 1.0203 1.0203 1.0203 1.0203 1.0203 68.03 68.03 Point Beach Unit #I4 1.0204 1.0203 1.0203 1.0203 1.0203 0 61.94 Point Beach Unit #25 1.0204 1.0203 1.0203 1.0203 1.0203 61.94 0 Kewaunee G I 1.0204 1.0203 1.0203 1.0203 1.0203 63.83 63.83 Point Beach Units # I & #2'j 1.0196 1.0196 1.0196 1.0196 1.0196 0 0 American Transmission Company Page 116 o f 132 10/2/2009

G83314-502213 ISIS Report

1. Included for Interconnection Customer's defined voltage levels:

a. Preferred: 352-kV to 354-kV

b. Normal: 351-kV to 358-kV

c. Maximum Permissible: 348.5-kV to 362-kV, any voltage outside of the Maximum Permissible range would be identified in Table H.3.3.3 as a Voltage Violation

2. The planning case used models both Point Beach units as regulating the respective POI bus voltage at the Point Beach substation to 1.0203 p.u. (352 kV).

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345113.2-kV transformer isolated at this bus with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus.

4. This contingency is intended to model the emergency trip of Point Beach Unit #I. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

5. This contingency is intended to model the emergency trip of Point Beach Unit #2. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

6. This contingency is intended to model an emergency dual unit trip modeled by the outage of each Point Beach generating unit, but maintaining the auxiliary load connection to the transmission system.

Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. Both generator Auxiliary loads are fed from their generator GSUs (23.4 MW and 13.9 MVAR each) and do not trip and are not moved. The Control Area replacement power was imported from TVA.

American Transmission Company Page 117 of 132

G83314-502213 ISIS Report Table H.3.3.5.2 - Voltage Measurements at the Point Beach 345-kVSubstation with Fix2 (East Switching Station), Summer 2013 Peak Load with Selected contingencies1 Point Beach BS 2-3 1.0203 1.0203 1.0211 1.021 1 1.0212 76.74 68 Point Beach BS 2 - Forest Junction 345-kV 1.0212 1.0211 1.0211 1.021 1 1.0212 68 68 Line 121 Point Beach BS 1-2 1.025 1.0205 1.0205 1.0205 1.0205 68 68 Point Beach BS 4-53 1.0204 1.0204 1.0204 1.0204 1.0224 68 68 Point Beach BS 3-4 1.0204 1.0204 1.0204 1.0203 1.0203 68 74.01 Point Beach BS 5 - Fox River 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 68 68 Line 151 Forest Junction - Fox River 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 83.37 83.37 Line 971L71 Point Beach BS 1 - Sheboygan Energy 345-kV 1.0204 1.0204 1.0204 1.0205 68 68 Line 111 Point Beach BS 3 - Kewaunee 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 74.82 74.82 Line Q-303 Forest Junction - Cypress 345-kV 1.0205 1.0205 1.0205 1.0205 1.0205 68 68 Line 971L51 Forest Junction 3451138-kV 1.0209 1.0209 1.0209 1.0209 1.0209 68 68 Transformer T I Forest Junction 3451138-kV 1.0209 1.0209 1.0209 1.0209 1.0209 68 68 Transformer T2 Fox River - N. Appleton 345-kV 1.0208 1.0208 1.0208 1.0208 1.0208 68 68 Line 6832 Sheboygan Energy - New East 345-kV 1.0203 1.0203 1.0203 1.0203 1.0203 77.24 77.24 Line L-SEC31 North Fox Energy Center Unit CT 1 1.0206 1.0206 1.0206 1.0206 1.0206 68 68 Fox Energy Center Unit CT 2 1.0206 1.0206 1.0206 1.0206 1.0206 68 68 Fox Energy Center Unit ST 1.0207 1.0207 1.0207 1.0207 1.0207 68 68 Sheboygan Energy Center Unit # I 1.0203 1.0203 1.0203 1.0203 1.0203 68.03 68.03 Sheboygan Energy Center Unit #2 1.0203 1.0203 1.0203 1.0203 1.0203 68.03 68.03 Point Beach Unit # I 4 1.0205 1.0204 1.0204 1.0204 1.0205 o 68 Point Beach Unit #25 1.0205 1.0204 1.0204 1.0204 1.0205 68 0 Kewaunee G I 1.0209 1.0209 1.0209 1.0209 1.0209 68 68 Point Beach Units #I & #26 1.0196 1.0196 1.0196 1.0196 1.0196 0 0 American Transmission Company Page 118 o f 132 10/2/2009

G83314-J02213 ISIS Report

1. Included for Interconnection Customer's defined voltage levels:

d. Preferred: 352-kV to 354-kV

e. Normal: 351-kV to 358-kV

f. Maximum Permissible: 348.5-kV to 362-kV, any voltage outside of the Maximum Permissible range would be identified in Table H.3.3.3 as a Voltage Violation

2. The planning case used models both Point Beach units as regulating the respective POI bus voltage at the Point Beach substation to 1.0203 p.u (352 kV).

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345113.2-kV transformer isolated at this bus with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus.

4. This contingency is intended to model the emergency trip of Point Beach Unit # l . Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

5. This contingency is intended to model the emergency trip of Point Beach Unit #2. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

6. This contingency is intended to model an emergency dual unit trip modeled by the outage of each Point Beach generating unit, but maintaining the auxiliary load connection to the transmission system. Transformer TlX03 is connected to Bus Section #I with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. Both generator Auxiliary loads are fed from their generator GSUs (23.4 MW and 13.9 MVAR each) and do not trip and are not moved. The Control Area replacement power was imported from TVA.

American Transmission Company Page 119 of 132

G83314-502213 ISIS Report Table H. 3.3.6.1 - Voltage Measzrrements at the Point Beach 345-kV Substation with Fix2 (East Switching Station), Summer 2013 08-Peak Load with Selected ~ontin~encies' (Without Minimum Excitation Limits)

Intact System 1.0202 1.0203 1.0203 1.0203 1.0202 114.64 114.64 Point Beach BS 2-3 1.0203 1.0203 1.0203 1.0203 1.0202 132.69 86.09 Point Beach BS 2 - Forest Junction 345-kV 1.0202 1.0203 1.0203 1.0203 1.0202 104.49 104.49 Line 121 Point Beach BS 1-2 1.0141 1.0203 1.0203 1.0203 1.0202 113.65 113.65 Point Beach BS 4-53 1.0202 1.0203 1.0203 1.0203 1.011 106.77 106.77 Point Beach BS 3-4 1.0203 1.0203 1.0203 1.0203 1.0202 137.6 120.76 Point Beach BS 5 - Fox River 345-kV 1.0202 1.0203 1.0203 1.0203 1.0203 110.83 110.83 Line 151 Forest Junction - Fox River 345-kV 1.0202 1.0203 1.0203 1.0203 1.0203 117.65 117.65 Line 971L71 Point Beach BS 1 - Sheboygan Energy 345-kV 1.0203 1.0203 1.0203 1.0202 115.52 115.52 Line 111 Point Beach BS 3 - Kewaunee 345-kV 1.0202 1.0203 1.0203 1.0203 1.0202 122.02 122.02 Line Q-303 Forest Junction - Cypress 345-kV 1.0202 1.0203 1.0203 1.0203 1.0202 120.41 120.41 Line 971L51 Forest Junction 3451138-kV 1.0202 1.0203 1.0203 1.0203 1.0202 108.13 108.13 Transformer T I Forest Junction 3451138-kV 1.0202 1.0203 1.0203 1.0203 1.0202 108.13 108.13 Transformer T2 Fox River - N. Appleton 345-kV 1.0202 1.0203 1.0203 1.0203 1.0202 109.03 109.03 Line 6832 Sheboygan Energy - New East 345-kV 1.0203 1.0203 1.0203 1.0203 1.0202 115.37 115.37 Line L-SEC31 North Fox Energy Center Unit CT l7 NIA NIA NIA NIA NIA NIA NIA Fox Energy Center Unit CT 27 NIA NIA NIA NIA NIA NIA NIA Fox Energy Center Unit ST7 NIA NIA NIA NIA NIA NIA NIA Sheboygan Energy Center Unit # I 1.0202 1.0203 1.0203 1.0203 1.0202 126.03 126.03 Sheboygan Energy Center Unit #27 NIA NIA NIA NIA NIA NIA NIA Point Beach Unit #I4 1.0203 1.0203 1.0203 1.0203 1.0203 0 148.1 Point Beach Unit #25 1.0203 1.0203 1.0203 1.0203 1.0203 148.1 0 Kewaunee G I 1.0203 1.0203 1.0203 1.0203 1.0202 97.36 97.36 Point Beach Units #I & #26 1.0178 1.0178 1.0178 1.0178 1.0177 0 0 American Transmission Company Page 120 o f 132 10/2/2009

G83314-J02213 ISIS Report

1. Included for Interconnection Customer's defined voltage levels:

a. Preferred: 352-kV to 354-kV

b. Normal: 351-kV to 358-kV

c. Maximum Permissible: 348.5-kV to 362-kV, any voltage outside of the Maximum Permissible range would be identified in Table H.3.3.3 as a Voltage Violation

2. The planning case used models both Point Beach units as regulating the respective POI bus voltage at the Point Beach substation to 1.0203 p.u (352 kV).

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345113.2-kV transformer isolated at this bus with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus.

4. This contingency is intended to model the emergency trip of Point Beach Unit #l. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

5. This contingency is intended to model the emergency trip of Point Beach Unit #2. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported fiom TVA.

6. This contingency is intended to model an emergency dual unit trip modeled by the outage of each Point Beach generating unit, but maintaining the auxiliary load connection to the transmission system. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. Both generator Auxiliary loads are fed from their generator GSUs (23.4 MW and 13.9 MVAR each) and do not trip and are not moved. The Control Area replacement power was imported from TVA.

7. Fox Energy Center Units and Sheboygan Energy Center Unit #2 are off-line in the study case.

American Transmission Company Page 121 of 132

G83314-J022/3 ISIS Report Table H.3.3.6.2 - Voltage Measurements at the Point Beach 345-kV Substation with Fix2 (East Switching Station), Summer 2013 Off-Peak Load with Selected ~ontin~encies*

(With Minimum Excitation Limits)

Intact System 1.0202 1.0203 1.0203 1.0203 1.0202 114.64 114.64 Point Beach BS 2-3 1.0203 1.0203 1.0203 1.0203 1.0202 132.69 86.09 Point Beach BS 2 - Forest Junction 345-kV 1.0202 1.0203 1.0203 104.49 1.0203 1.0202 104.49 Line 121 Point Beach BS 1-2 1.0141 1.0203 1.0203 1.0203 1.0202 113.65 113.65 Point Beach BS 4-53 1.0202 1.0203 1.0203 1.0203 1.011 106.77 106.77 Point Beach BS 3-4 1.0203 1.0203 1.0203 1.0203 1.0202 137.6 120.76 Point Beach BS 5 -Fox River 345-kV 1.0202 1.0203 110.83 1.0203 1.0203 1.0203 110.83 Line 151 Forest Junction - Fox River 345-kV 1.0202 1.0203 1.0203 1.0203 117.65 1.0203 117.65 Line 971L71 Point Beach BS 1 - Sheboygan Energy 345-kV 1,0203 1.0203 1.0203 115.52 1.0203 1.0202 115.52 Line 111 Point Beach BS 3 - Kewaunee 345-kV 1.0202 1.0203 1.0203 122.02 1.0203 1.0202 122.02 Line Q-303 Forest Junction - Cypress 345-kV 1.0202 1.0203 120.41 120.41 1.0203 1.0203 1.0202 Line 9711151 Forest Junction 3451138-kV 1.0203 1.0203 108.13 1.0202 1.0203 1.0202 108.13 Transformer T I Point Beach Unit #I4 1.0203 1.0203 1.0203 1.0203 1.0203 0 145.2 Point Beach Unit #25 1.0203 1.0203 1.0203 1.0203 1.0203 145.2 0 Kewaunee G I 1.0203 1.0203 1.0203 1.0203 1.0202 97.36 97.36 Point Beach Units # I & #26 1.0178 1.0178 1.0178 1.0178 1.0177 0 0 American Transmission Company Page 122 of 132 10/2/2009

G833/4-J022/3 ISIS Report

1. Included for Interconnection Customer's defined voltage levels:

a. Preferred: 352-kV to 354-kV

b. Normal: 351-kV to 358-kV

c. Maximum Permissible: 348.5-kV to 362-kV, any voltage outside of the Maximum Permissible range would be identified in Table H.3.3.3 as a Voltage Violation

2. The planning case used models both Point Beach units as regulating the respective POI bus voltage at the Point Beach substation to 1.0203 p.u (352 kV).

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345113.2-kV transformer isolated at this bus with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus.

4. This contingency is intended to model the emergency trip of Point Beach Unit # l . Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

5. This contingency is intended to model the emergency trip of Point Beach Unit #2. Assumes the 13.2-kV bus is split, separating the auxiliary loads. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. The Auxiliary load fed from the generator GSU (23.4 MW and 13.9 MVAR) does not trip and is not moved. The Control Area replacement power was imported from TVA.

6 . This contingency is intended to model an emergency dual unit trip modeled by the outage of each Point Beach generating unit, but maintaining the auxiliary load connection to the transmission system. Transformer TlX03 is connected to Bus Section #1 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus and Transformer T2X03 is connected to Bus Section #5 with 2.5 MW and 2.1 MVAR of load at the 13.2-kV bus. Both generator Auxiliary loads are fed from their generator GSUs (23.4 MW and 13.9 MVAR each) and do not trip and are not moved. The Control Area replacement power was imported from TVA.

7. Fox Energy Center Units and Sheboygan Energy Center Unit #2 are off-line in the study case.

American Transmission Company Page 123 of 132

G833/4-502213 ISIS Report Table H.3.3.7 - IdentiJied Thermal Violations under select NERC Category C.3 events' (TDF>S%), Summer 08-Peak 2013 70% Load Delivery to MISO with Fix2 (East Switching North Appleton-Fitzgerald345 kV line New East-Cedarsauk 345 kV line New East-Granville 345 kV line and New East-Cedarsauk 345 kV line

1. NERC Category C.3 events studied are limited to the concurrent outage of two elements without manual system adjustments between outages. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

2. Includes provision for 5% TRM. The required ratings are calculations using AC analysis in PSS/E dispatching G83315022 and G834lJ023 to all MIS0 generation.

3. SE = Summer Emergency

4. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/2010.

5. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE. The existing line rating is limited by the line clearance (2156 ACSR @ 129F) 6 . Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (1 -477 and 1-410 ACSR, 33.73 mile)

7. The line will be uprated to at least 572 MVA as part of G83314-J02213 interim upgrades. Whether additional 14 MVA is achievable without any significant constraints needs to be confirmed with Project Team. Generation redispatch using local generators would address the issue.

8. The line will be uprated to 112 MVA per G6111G927 G-T interconnection. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (410 ACSR, 28.9 mile: Forest Junction-Elkhart Lake)

9. Generation redispatch using the local generators would address the issue. It is limited by the transformer. The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

10. Generation redispatch using the local generators would address the issue. It is limited by the transformer (504 MVA SE) and equipment associated with the transformer. The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

American Transmission Company Page 124 of 132

G83314-502213 ISIS Report Table H.3.3.8 - Identijied Thermal Violations under select NERC Category C.3 events*

(TDF>S%), Summer Peak 2013 100% Load Delivery to lWSO with Fix2 (East Switching Point Beach-ForestJunction 345 kV line Point Beach 345 kV bus tie 2-3 and Point Beach-SheboyganEnergy Center345 488 SE 649 SE Point Beach-Forest Junction 345 kV 52.9 % Yes8 kV line line New East-Sheboygan Energy Center Neevin-Woodenshoe 138 kV line 332 SE 355 SE 345 kV line and North Appleton- NIA NO' Fitzgerald 345 kV line New East-Sheboygan Energy Center Kewaunee-East Krok 138 kV line 287 SE 322 SE 345 kV line and North Appleton- NIA No6 Kewaunee 345 kV line New East-Granville 345 kV line and New East-Cedarsauk 345 kV line 653 SE 756 SE New East-South Fond du Lac 345 kV NIA NO^

line

1. NERC Category C.3 events studied are limited to the concurrent outage of two elements without manual system adjustments between outages. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

2. Incl~~des provision for 5% TRM. The required ratings are calculations using AC analysis in PSSIE dispatching G83315022 and G8341J023 to all MIS0 generation.

3. SE = Summer Emergency

4. Generation redispatch using local generators or taking the bus tie out of service during Point Beach generation refueling outage window would address the issue. It is limited by the portion of the existing line conductor (1-2156 ACSR, 30.75 mile). The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

5. Generation redispatch using local generators or taking the bus tie out of service during Point Beach generation refueling outage window would address the issue. It is limited by the portion of the existing line conductor (1-2156 ACSR, 11.32 mile). The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

6. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/2010. The bus tie outage is not considered as NERC Category B contingency, but it is listed in the table for informational purpose.

7. Generation redispatch using local generators would address the issue. It is limited by the existing line conductor (1-795 ACSR, 4.4 mile)

8. Generation redispatch using local generators would address the issue. It is limited by the terminal equipment.

9. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE. The existing line rating is limited by the line clearance (2156 ACSR @ 129F)

American Transmission Company Page 125 of 132

G83314-J02213 ISIS Report Table H.3.3.9 - Identified Thermal Violations under select NERC Category C.5 events1 (TDF>5%), Szrmmer Off-Peak 2013 70% Load Delivery to MlSO with Fix2 (East Switching New East-Granville 345 kV line and New East-Cedarsauk345 kV line

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

2. Includes provision for 5% TRM. The required ratings are calculations using AC analysis in PSS/E dispatching G833lJ022 and G8341J023 to all MIS0 generation

3. SE = Summer Emergency

4. The line will be uprated to 1095 MVA (1834 A) per ATC Project PR03208. Estimated in-service date is 4/25/2010

5. Portion (-24 miles) of the existing line 796L41 (-33.3 miles) going southerly to Cedarsauk 345 kV line needs to be uprated to achieve at least 997 MVA SE. The existing line rating is limited by the line clearance (2156 ACSR @ 129F).

Table H.3.3.10 -Identified Thermal Violations under select NERC Category C.5 events1 (TDF>5%), Szrmmer Peak 2013 100% Load Delivery to MlSO with Fix2 (East Switching None identified

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

American Transmission Company Page 126 of 132

G83314-502213 ISIS Report Table H. 3.3.11 - Identij?ed Voltage Violations under select NERC Category C.5 events1 Summer Off-Peak2013 70% Load Delivery to MSO, with Fix2 (East Switching Station),

Competing Win~/Far.m.sat 100% ozrtpzrt Voltage (p.u.)

Potential Limiting Worst Post Pre AV (p.u.) Solution Element Contingencyt G83314- G83314- Identified JO2213 JO2213 None ldentified

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

Table 11.3.3.12 - Identij?ed Voltage Violations under select NERC Category C.5 events1 Summer Peak 2013 100% Load Delivery to MISO, with Fix2 (East Switching Station),

None ldentified

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit towerline. The transmission elements studied are local 345-kV and 138-kV facilities determined relevant based on engineering judgment.

American Transmission Company Page 127 of 132

G83314-J02213 ISIS Report Appendix I: Minimum Excitation Limits at Point Beach and Kewaunee with Proposed Solution American Transmission Company Page 128 of 132

G83314-J02213 ISIS Report Minimum Excitation Limits (MELs) at Point Beach and Kewaunee with Proposed Solution Based on the study results in Section H.3.2 of Appendix H.3, the minimum excitation limit study results with the proposed solution (Fix 11) is tabulated in Table I. 1. With all Network Upgrades of G83314-J02213 in-service and based on the study results shown in Table I. 1 in this ISIS report, the Point Beach and Kewaunee units would need to maintain the following minimum excitation levels to ensure synchronism of these and nearby generators :

Post completion of the Proposed Solution and the Kewaunee bus reconfiguration proiect (With both Point Beach Units #I and #2 upgraded) o Point Beach GI and G2: 12 MVAR or higher per unit (gross) o Kewaunee GI: -19 MVAR or higher (gross)

Table 1.1 proves that installing a new 4-303 breaker in series with the existing breaker which is one of the G83314-502213 "Interim" Network Upgrades is also beneficial for long-term system operation because Q-303 breaker failure appears to the most restrictive contingency causing less improvement in MELs. This is same for alternatives Fix 5 and Fix 13.

Table 1.1. Minimum Excitation Limit Study Results (With 683314-502213, With Proposed Solution and Kewaunee Reconfiguration Complete)

With Proposed Solution (KV and gross MVAR level at POB and KEW for stable system under critical faults) under Low Gen Scenario High Gen Scenario Intact (tested clearing Comment (Gross MVAR) (Gross MVAR) times) 346 kV or higher 346 kV or higher (POB G1: -20.7 (POB GI: 4.8 POB G2: -20.7 POB G2: 4.8 Thus, minimum excitation KEW G l : -31.4) KEW G 1: -24.5) limits with Proposed Solution in-service and Point Beach 346 kV or higher 347 kV or higher unit 1 & 2 upgraded) are:

(POB G1: -20.7 (POB G1: 11.9 POB G2: -20.7 POB G2: 11.9 POB GI: 11.9 MVAR gross KEW G l : -31.4) KEW GI: -19.6) POB G2: 1 1.9 MVAR gross KEW G 1 : -1 9.6 MVAR gross 349 kV or higher

• 350 kV or higher * (Assuming 4-303 series breaker 4303 BF @ POB * (POB GI: 33.9 at Point Beach installed)

(POB GI: 31.5 (3.519.2514.5) POB G2: 3 1.5 POB G2: 33.9 (see comment) KEW GI: 13.5) KEW GI: 6.8)

• Result of Q303 BF is valid only if 4303 relays are 345 kV or higher 345 kV or higher upgraded instead of a new R304 BF @ KEW (POB GI: -37.9 (POB G1: -2.9 4303 series breaker (3.519.514.5) POB G2: -37.9 POB G2: -2.9 KEW G l : -53.8) KEW G l : -41.4)

American Transmission Company Page 129 of 132

G833i4-502213 ISIS Report Appendix J: Project One Line Diagram of Propose Solution (Fix 11 and Uprating New East-Cedarsauk 345 kV line)

Note:

The project diagram does not show the required long-term network upgrade at the Point Beach substation (e.g. adding a new breaker in series with the existing Q303 line breaker) because the Q-303 breaker addition is already required for interim period operation.

American Transmission Company Page 130 of 132

G83314-502213 ISIS Report

< Uprate Southern Portion of the existing line 796M1 to Cedarsauk 345 kV substation >

New East 345 kV Substation

- 1 mile from New East 345 kV Substation 796L41 East (To Edgewater)

Existing line 796LA1 South (To Cedarsauk)

To Granville Cedwsauk346 kV substation PROJECT NOTES Perform line clearance study and uprate the southern portion of the existing line 796L41 to Cedarsauk 345 kV substation to at least 960 MVA (SE). If some of the existing structures need to be replaced with new

@ structures, the nav structures should be designed for ATC standard operating temperatures (200,301X for SNISE).

@ Upgrade 1200:5 (300015 full ) CTs on the Cedarsauk 345 kV ring bus to achieve at least 960 MVA (SE)

American Transmission Company Page 132 of 132