Text

American Transmission Company - Interconnection System Impact Study Report, 106 MW Nuclear Generation Increase (53 MW Each at Point Beach Generators 1 and 2), Revision 3
	ML091030482
Person / Time
Site:	Point Beach
Issue date:	12/17/2008
From:	Mary Anderson, Baynard P, Foundos P, Grossenbach N, Marz M; American Transmission Co
To:	; Office of Nuclear Reactor Regulation
References
	NRC 2009-0044
	Download: ML091030482 (71)
	v • d • e

G833-4 Interconnection System Impact Study Report, Revision 3 AMERICAN TRANSMISSION COMPANY ?

THE ENERGY ACCESS COMPANY Interconnection System Impact Study Report 106 MW Nuclear Generation Increase (53 MW each at Point Beach Generators 1 and 2)

Manitowoc County, Wisconsin G833 - MISO Queue #39297-01 G834 - MISO Queue #39297-02 Revision 3 December 17, 2008 American Transmission Company, LLC PreparedBy:

Michael B. Marz, P.E., Planning Pete Foundos, System Protection Mike Anderson, Engineering & Construction Services Nick Grossenbach, Engineering & Construction Services Patsy Baynard, Project Management Approved By:

David Cullum, P.E.

Team Leader - G-T Interconnections & Special Studies American Transmission Company Page 1 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table of Contents EXECUTIVE

SUMMARY

.................................................................................................................................................. 3

1. SU M M A R Y ................................................................................................................................................................. 5 1.1 IN JEC T ION L IMIT S ........................................................................................................................................ 6 1.2 GENERATING FACILITY OPERATION RESTRICTIONS ................................................................................ 6 FIGURE 1.1 - CONCEPTUAL ONE LINE DIAGRAM OF THE 2011 SYSTEM WITH G833 AND G834 SHOWN ................... 8 1.3 G ENERATING FACILITY REQUIREM ENTS ................................................................................................... 9 FIGURE 1.2: EXISTING POINTBEACH SUBSTATION CONFIGURATION....................................................................... 10 1.4 N ETWO R K U PG RA DES ................................................................................................................................. 11 1.5 INTERCONNECTION FACILITIES ............................. ................................ 13 1.6 F U RTH ER STU D Y ..................................................................... . .............................................................. 13 Table 1.1- Existing System Upgrades Required before Operationof G833 and G834................................. 14 Table 1.2 - RequiredNetwork Upgrades due to the Addition of G833 and G834 ....................................... 14 Table 1.3 - RequiredInterconnection Facilitiesfor G833 and G834 .......................................................... 15 Table 1.4 - Recommended FacilitiesDue To Third Party Impact of G833 and G834 ................................. 15

2. CRITERIA, METHODOLOGY AND ASSUMPTIONS ................................................................................. 16 2 .1 S TU DY C R IT ER IA .: ............................................................................... ........................ .............................. 16 2.2 STU DY M ETHODOLO GY ............................................................................................................................. 16 2.2.1 Competing Generation R equests .............................................................................................................. 16 2.2.2 Linear Transfer Analysis andA. C. Power Flow Analysis Methods ...................................................... 16 2.2.3 Stability A nalysis ...................................................................................................................................... 17 2 .3 B ASE C ASE S ............................................................................................................................................... 17 2.3.1 Power Flow Analysis (Steady State).......................................................................................................... 17 2.3.2StabilityA nalysis (Dynam ics) ................................................................................................................... 18 2.3.3 DeliverabilityA nalysis ................................................................................................................................ 18 2 .4 G EN ERA TION F A C ILITY .............................................................................................................................. 18 2.4.1 GeneratingF acility Modeling.................................................................................................................. 18 2.4.2 Synchronizing and Energization of Substation/GeneratorStep-Up Transformers .............................. 19 2.4.3 Unit Black Start andATC Black Start Plan Participation................................................................. 20

3. A N A LY SIS R ESULTS .............................................................................................................................................. 21 3.1 POW ER FLOW ANALYSIS RESULTS ............................................................................................................. 21 3.1.1 PowerFactorCapability and Voltage Requirements........................................................................... 21 3.1.2 Results ofIntact System and Single Contingencies (N-1) ..................................................................... 21 3.1.3 Results ofD ouble Contingencies (7-I-i) ............................................................................................ 23 3.2 STABILITY ANALYSIS RESULTS .................................................................................. . .............. 25 3.2.1 Results of Primary Clearingof Three-phase Faults Under IntactSystem Conditions........................ 26 3.2.2Results of Primary ClearingSLG Faults on Two Circuitsof a Multiple CircuitLines........................... .27 3.2.3 Results of PrimaryFault ClearingDuringa PriorOutage................................. 28 3.2.4 Results of Three-PhaseFaultDelayed Clearing under Intact System Conditions............................... 29 3.2.5 GeneratorStep Up And Auxiliary TransformerBreakerFailureEvents ............................................. 30 3.2.6Stability Results Summary .................................................................. ....... 31 3.3 SHORT-CIRCUIT & BREAKER DUTY ANALYSIS RESULTS ....................... ............................................... 31 3.4 DELIVERABILITY ANALYSIS RESULTS .................................................... . .................................. 32 APPENDIX A: POWER FLOW ANALYSIS RESULTS ............................................. 33 APPENDIX B: OPERATION RESTRICTIONS ........................... e......................................................................... 43 APPENDIX C: STABILITY ANALYSIS RESULTS .............................. .................................................................. 45 APPENDIX D: SHORT CIRCUIT / BREAKER DUTY ANALYSIS RESULTS ........................................................ 57 APPENDIX E: DELIVERABILITY ANALYSIS RESULTS .............................................................................. 60 APPENDIX F: STUDY CRITERIA .......................................................... ............. .......................................................... 61 APPENDIX G: TYPICAL PLANNING LEVEL COST ESTIMATES ............................................................... 65 APPENDIX H: ALTERNATIVES CONSIDERED............................... .................................................................... 68 American Transmission Company Page 2 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Executive Summary This Interconnection System Impact Study report documents the system impacts and required upgrades needed to interconnect Midwest Independent System Operator (MISO) Generation Interconnection Requests identified as Projects G833, Queue #39297-01, and G834, Queue

39297-02, to the 345-kV transmission system in Manitowoc County, Wisconsin. These requests consist of a 53 MW increase to each of the Point Beach Nuclear generators for a total increase in plant output of 106 MW. Each generator was studied with a net output, as measured at the low-side of the generator step-up transformer, of 612.6 MW net (636 MW gross per unit). The requested commercial operation date is May 31, 2010 for G834 (Point Beach Unit 1) and May 31, 2011 for G833 (Point Beach Unit 2).

Revision 1 includes the MISO Deliverability Analysis results that indicate than no upgrades are needed for G833 and G834 Network Resource Interconnection Service (NRIS) operation.

Revision 2 changed the requirement to add 345 kV high side breakers to auxiliary transformers T 1X03 and T2X03 to a recommendation to add these breakers and further explained the benefits of these breakers. Revision 3 includes stability simulation results for Point Beach GSU and Auxiliary Transformer faults based on fault clearing times provided by staff at Point Beach in response to a request by ATC.

This study has identified the Interconnection Facilities and Network Upgrades to facilitate the requested interconnection for Energy Resource Interconnection Service (ERIS). Deliverability analysis has shown that no upgrades are needed for NRIS operation. For ERIS, the good faith estimate of cost for the Network Upgrades identified in this report is approximately $18.7 million. The preliminary, good faith estimate of schedule indicates that all of the Network Upgrades can be in-service within 5 years of an executed Interconnection Agreement.

Although there are no required Interconnection Facilities for this project, ATC recommends that the Interconnection Customer reduce the primary fault clearing time for Point Beach auxiliary transformer TlX03 from 5.1 cycles to 4.75 cycles and for auxiliary transformer T2X03 from 5.1 cycles to 4.25 cycles to prevent these faults from causing the Point -Beach and Kewaunee generators to lose synchronism. ATC also recommends installing 345 kV circuit breakers on the high side of each of these two 345/13.2 kV auxiliary transformers to prevent a breaker failure event during auxiliary transformer faults from tripping Point Beach generation. Section 1.3 describes the reliability benefits of these recommendations.

The Interconnection Customer must commission updated optimal settings for the existing Point Beach Power System Stabilizers (PSSs) as described in Section 1.4 of this report.

The next step in the Generator Interconnection Request process is for the customer to decide whether or not to proceed to an Interconnection Facilities Study. 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 the ISIS report.

American Transmission Company Page 3 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Kewaunee Point Beach G833 & G834 LAKE MICHIGAN O 345 kV Substation o 138 kV Substation o 69 kV Substation

0) Generation

- 345 kV Transmission

-115-161 kV Transmission 69 kV Transmission W *- stee Figure 1 - G833 and G834 ProposedInterconnectionat the Point Beach 345 kV Substation and SurroundingSystem (as expected in 2010) with Proposed West Switching Station.

American Transmission Company Page 4 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3

1. Summary This study report is a revision of Revision 2 of the posted G833/G834 System Impact Study Report dated August 13, 2008 for the Midwest Independent System Operator (MISO) Generation Interconnection Requests identified as Projects G833 and G834, Queue #39297-01 and #39297-

02. This study evaluates the impact of the proposed 106 MW increase in generation at the Point Beach nuclear plant which is connected to the 345 kV transmission system in Manitowoc County, Wisconsin. The customer has requested the following dates for the various stages of interconnection:

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

Initial Synchronization Date: Not supplied

Commercial Operation Date: May 31, 2010 for G834 and May 31, 2011 for G833.

Revision 1 included the following changes:

Updates to the Executive Summary, Sections 1, 1.4, 1.6, 2.3.3 and 3.4, Appendix E and Table 1.2 to reflect completion of the deliverability analysis.

Revision 2 included the following changes:

Updates to Sections 1.3 and 3.2.5, Figure 1.1 and Table 1.4 and adding Figure 1.2 to reflect that the addition of 345-kV high side circuit breakers to transformers TiX03 and T2X03 are recommendations and not requirements.

Revision 3 includes the following changes:

Updates to Sections 1.3, 2.4.1, 3.2.1 and 3.2.5, Figure 1.1, and Tables 1.4, C-9 and C-10, and adding Tables C-11 to C-13 to incorporate Point Beach supplied clearing times for faults on the Generator Step Up and Auxiliary Transformers.

The Large Generator Interconnection Procedures permit the Interconnection Customer to request specific Backfeed, Initial Synchronization and Commercial Operation Dates. G833 and G834 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 or system topography 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 2011 time frame, including the required 345 kV switching station east of Fond du Lac that eliminates stability issues found with the increased Point Beach generation.

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 American Transmission CompanyP Page 5 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Generating Facilities. The Interconnection Customer will need to supply Generating Facility diagrams for the Large Generator Interconnection Agreement.

Required construction outages to build the new 345 kV switching station 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 ISO for approval. The Midwest studies outages based on the submitted queue position within their outage scheduling database.

This study identifies steady state system thermal and voltage impacts, system angular stability impact and the circuit breaker fault duty impacts associated with the interconnection of G833 and G834. These interconnection system impacts are based on Linear Transfer and 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 are also provided for the identified Network Upgrades.

In order for G833 and G834 to interconnect as an Energy Resource (ER), the required Network Upgrades and Interconnection Facilities must be completed. In order for G833 and G834 to qualify as a Network Resource (NR), any additional Network Upgrades that are identified based on the MISO deliverability analysis must also be completed.

1.1 Injection Limits1 The injection limits are identified in Tables A. 1 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) events for all seasonal models studied.

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

1. Cypress-Conceptual West Switching Station 345-kV Line (L-CYP31 north)

2. Point Beach-Sheboygan Energy 345 kV Line (LI 11)

3. Elkhart Lake-G611 Tap 138 kV Line (4035 southern section),

The Network Upgrades for these injection limits are described in Section 1.4 and are required for either ERIS or NRIS for the full 106 MW of requested interconnection service of G833 and G834.

1.2 Generating Facility Operation Restrictions Two distinct NERC Category C.3 events (double contingencies) resulted in seven (7) distinct thermal constraints where the worst case overloading occurred for summer 2010 100% of system See Appendix F, Section F3.1 for a definition of what transmission overloads qualify as injection limits.

.American Transmission Company Page 6 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 peak load conditions (Table A.7, Appendix A). No violations were found for Category C.5 events, which is the outage of two circuits on a multi-circuit tower.

Thermal constraints will be mitigated in the day-ahead and real-time market through the MISO binding constraint procedures. Therefore, no operating restrictions are listed for these thermal constraints.

The existing limitations on Kewaunee generation for the outage of either Q-303 or R-304 followed by a fault on the remaining Kewaunee 345-kV outlet are unchanged with the addition of the proposed switching station. A new operating restriction will be created for Point Beach for the prior outage of the Point Beach 345 kV bus tie breaker 2-3. See Section 3.2.6 for more information.

American Transmission Company. Page 7 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 NORTH KEWAUNEE T10 APPLETON L I?Y 313-S To Columbia _ W-5

_ I -_IW-1 W-1E 796L41 Legend U EASU o* ~CEDARSU Existing (solid fine) C L3-4 L4-1 Required Fix (green - future dotted) ',

Recommended Facilities Due to 3431C'r- T Third Party Impacts 123 L-SEC_31 2-PCO (Point of Change of Ownership) GRANVILLE and POI (Point of Interconnection) L9911 9 1 To Arcadian Figure 1.1 - Conceptual One Line Diagramof the 2011 System with G833 and G834 Shown With Kewaunee Bus ReconfigurationProject American Transmission Company Page 8 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 1.3 Generating Facility Requirements Point Beach Power System Stabilizers The existing Point Beach Power System Stabilizers (PSS) are required due to inadequate rotor angle damping under certain system conditions. The G833 and G834 projects will continue to require the use of PSS on the Point Beach units. 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 PSS/E program, must be provided to ATC prior to the commercial operation of G833 and G834. ATC will then test the performance of G833 and G834 with the tuned parameters in the computer simulations to ensure that rotor angle damping is within criteria.

Auxiliary Transformers T1X03 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 TiX03 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 T1X03 and T2X03, the follow events would occur for a fault on the T1X03 or T2X03 equipment, including a fault at the 13.8 kV level:

1. For a fault on T1X03,

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 L11.

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 Li11 to Sheboygan Falls Energy Center substation, ii. 345 kV line L121 to Forest Junction substation and iii. Point Beach generating unit #1.

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 Li 51.

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:

1. 345 kV line L151 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 and, for faults involving TlX03, a second 345 kV transmission line. 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.

American Transmission Company Page 9 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Reduction of Auxiliary Transformers T1X03 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. Without the recommended circuit breakers, but with the proposed Kewaunee bus reconfiguration and the West switching station, fault clearing times will have to be reduced to 4.75 cycles for T1X03 and 4.25 cycles for T2X03. The existing primary clearing time is acceptable with the present system configuration and generation levels. With the addition of G833 and G834, failure to reduce these fault clearing times to the recommended times would result in loss of synchronism on the Point Beach and Kewaunee generators for high side faults on these auxiliary transformers cleared in primary time.

FJT KEW FOX 152 T2X03 H21 13.2 kV H31 Figure 1.2 - Existing Point Beach Substation Configuration Power Factor Capability The G833 and G834 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 1.00 leading (when a facility is consuming reactive power from the transmission system) to 0.95 lagging (when a facility Js supplying reactive power to the transmission system). For the scenarios examined, study results indicate that satisfactory system performance is achieved by supplying a range of 0 to 200 Mvars to the system, based on its maximum net generation, as measured at the low-side of the generator step-up transformer, of 612.6 MW.

Plant Specific Voltage Requirements The Point Beach Nuclear has specific 345 kV voltage range requirements. The preferred range is 352 kV (1.020 pu) to 354 kV (1.026 pu), the normal range is 351 kV (1.017 pu) to 358 kV (1.037 American Transmission Company Page 10 of 71 12/17/2008

G833-4 Interconnection System impact Study Report, Revision 3 pu) and the maximum permissible is 348.5 kV (1.010 pu) to 362 kV (1.049 pu). Any voltage outside the maximum permissible range is a voltage limitation as described in the plant technical specifications.

1.4 Network Upgrades Existing Network Upgrades Required Before G833 and G834 Operation (See Table 1.11)

Injection Upgrades Analysis prior to G833 and G834 found no required network upgrades due to injection limits.

Voltage Related Analysis prior to G833 and G834 found no unacceptable voltages.

Breaker Duty Related No breaker duty related required upgrades were found prior to the addition of G833 and G834.

Network Upgrades Required Due to G833 and G834 Addition (See Table 1.2)

The preliminary, good faith estimate of schedule indicates that all of the Network Upgrades can be in-service within 5 years of an executed Interconnection Agreement.

Stability Upgrades (see Table 1.2)

To achieve adequate system stability with G833 and G834 in service, one 345 kV switching station with complete Independent Pole Operation (IPO) for each 2 cycle 345-kV breaker is required as follows:

1) A four position ring bus at the intersection of lines L-CYP31 (Cypress-Arcadian) and W-1 (Edgewater-South Fond du Lac) with future expansion to a six position ring bus.

For Existing Kewaunee Bus Configuration The following protection improvements included in Table 1.2 are required to achieve adequate system stability if the Planned Kewaunee bus reconfiguration is not constructed:

1) L 111 (Point Beach-Sheboygan Energy Center 345 kV) at Point Beach fault clearing time should be reduced:

a. From the existing 3.5 cycle local primary, 9.0 cycles local delayed, and 4.5 cycles remote primary,

b. To either 3.5 cycle local primary, 8.25 cycles local delayed and 4.5 cycles remote primary.

2) L151 (Point Beach-Fox 345 kV) at Point Beach fault clearing time should be reduced:

a* From the existing 3.5 cycle local primary, 9.0 cycles local delayed, and 5.5 cycles remote primary,

b. To 3.5 cycle local primary, 8.5 cycles local delayed and 4.5 cycles remote primary.

3) Q-303 (Point Beach-Kewaunee 345 kV) at Point Beach fault clearing time should be reduced:

a. From the existing 3.5 cycle local primary, 9.0 cycles local delayed, and 5.5 cycles remote primary, American.Transmission Company Page I11 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3

b. To 3.5 cycle local primary, 8.5 cycles local delayed, and 4.5 cycles remote primary.

4) R-304 (Kewaunee-North Appleton 345 kV) at Kewaunee fault clearing time should be reduced:

a. From the existing 5.5 cycle local primary and 6.5 cycles remote primary,

b. To 3.5 cycle local primary and 6.5 cycles remote.

5) Kewaunee T-10 (Kewaunee 345/138 kV) at Kewaunee fault clearing time should be reduced:

a. From the existing 6.5 cycle 345 kV primary and 8.5 cycles 138 kV primary,

b. To 4.5 cycle 345 kV primary and 5.5 cycles 138 kV primary.

For Planned Kewaunee Bus Reconfiguration If the Planned Kewaunee bus reconfiguration is constructed, the following protection improvements are required:

1) L11I (Point Beach-Sheboygan Energy Center 345 kV) at Point'Beach fault clearing time should be reduced:

a. From the existing 3.5 cycle local primary, 9.0 cycles local delayed, and 4.5 cycles remote primary,

b. To either 3.5 cycle local primary, 8.5 cycles local delayed and 4.5 cycles remote primary.

2) L151 (Point Beach-Fox River 345 kV) at Point Beach fault clearing time should be reduced:

a. From the existing 3.5 cycle local primary, 9.0 cycles local delayed, and 4.5 cycles remote primary,

b. To either 3.5 cycle local primary, 8.5 cycles local delayed and 4.5 cycles remote primary.

3) R-304 (Kewaunee-North Appleton 345 kV) at North Appleton fault clearing time should be reduced:

a. From the existing 3.5 cycle local primary, 8.5 cycles local delayed, and 5.5 cycles remote primary,

b. To 3.5 cycle local primary, 8.5 cycles local delayed and 4.5 cycles remote primary.

Injection Upgrades (see Table 1.2)

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

Cypress-West Switching Station 345-kV line CYP31 (north) (11.7 miles) must be uprated to obtain a minimum summer emergency rating of 675 MVA (1130 A) or higher.

Point Beach-Sheboygan Energy 345 kV line L 11 (51.1 miles) must be uprated to obtain a minimum summer emergency rating of 555 MVA (929 A) or higher.

Elkhart Lake-G611 Tap 138-kV line 4035 (18.7 miles) must be uprated to obtain a minimum summer emergency rating of 131 MVA (549 A) or higher.

Voltage Related None American Transmission Company Page 12 of 71. 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 BreakerDuty Related None Network Resource InterconnectionService (NRIS) Related MISO performed the generator deliverability analysis needed for G833 and G834 to qualify for NRIS. For nuclear generators full plant capacity (100%) is evaluated. No upgrades were identified to qualify for NRIS.

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 PO. 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 G833 and G834 Interconnection Facilities already exist. Table 1.3 describes the new facilities owned by the Interconnection Customer and the Transmission Owner respectively.

1.6 Further Study In order for G833 and G834 to interconnect under Energy Resource Interconnection Service (ERIS), the required Network Upgrades and Interconnection Facilities must be completed. In order for G833 and G834 to qualify as a Network Resource (NR), any additional network upgrades that are identified based on the MISO deliverability analysis (none were found for G833 and G834) must also be completed.

The next step in the Generator Interconnection Request process is for the customer to decide whether or not to proceed to an Interconnection Facilities Study. An Interconnection Facilities Study will specify in more detail the time and cost of the equipment, engineering, procurement and construction of the systemupgrades identified in this ISIS report.

American Transmission Company Page 13.of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table 1.1- Existing System Upgrades Requiredbefore Operation of G833 and G834 Location Facilities Reason None-Table 1.2 - RequiredNetwork Upgrades due to the Addition of G833 and G834 Good Faith Location Cost Facilities Reason Estimate

. ' (Y2008)

Cypress-West Item #1 - Increase conductor temperature rating 4' F. look at Switching Station plan and profile and Patrol to observe any close wire crossings Injection $150000 345-kV line and adjust to obtain a minimum Summer Emergency rating of Limit

_(L-CYP31 north) 675 MVA (1130 A).

Point Beach- Item #2 - Increase 345 kV line clearance to obtain a minimum Sheboygan Energy Summer Emergency rating of 555 Ce n Ene work is expected to be required to MVA (929 increase A). Little rating only 40toF.noCost Injection inet $150,000 C t4-li is to review plan and profile and patrol to observe any close wire (Lili) crossings and adjust accordingly.

Elkhart Lake-G611 Item #3 - Increase the, clearance on the 138 kV line to obtain a Injection Tap 138-kV line minimum Summer Emergency rating of 131 MVA (549 A) by Limit$5,876,000

___(4035 south) replacing the existing conductor with 336 kcmil or T2-4/0 AWG.

Item #4 - A 4 (expandable to 6) position 345 kV ring bus connecting lines L-CYP31 (Cypress-Arcadian) and W-1 A New 345 kV (Edgewater-South Fond du Lac). Include: Control house, relay protection (ATC standard 345 kV line protection panels plus a bus Switching Station at differential panel with redundant relays), communication and Stability $11,919,014 linterseLCtioand o accessories, four 3000A, 50kA, 2 Cycle, GCB (complete IPO Ugades lines L-CYP31

.W-1. (West and installation), four line and twelve maintenance disconnect Upgrades Switching Station) switches, four dead ends, twelve bus CCVTs, eight line CCVTs, line traps, and tuners; twelve MCOV arresters, jumpers, cables, trench, conduits, and grounds. Assumes transmission line additions <1 mile and falling within PSCW CA guidelines.

Item #51 -Point Beach Faults Protection Improvements.

Item 5A: Achieve L 111 clearing times of 3.5 cycles local Point Beach 345 kV primary, 8.5 cycles local delayed and 4.5 cycles remote primary Stability Bus by reducing local delayed clearing time 0.5 cycles. 2 $106,592 Bus Item 5B: Achieve L 151 clearing times of 3.5 cycles local primary, Upgrades 8.5 cycles local delayed and 4.5 cycles remote primary 2 by reducing local delayed clearing time 0.5 cycles.

Item #61 - R-304 Fault at Kewaunee Protection Improvement North Appleton 345 Achieve R-304 fault clearing times of 3.5 cycles local primary, 8.5 Stability $515,437 kV Bus cycles local delayed and 4.5 cycles remote primary by reducing Upgrades 3

remote primary by 1.0 cycle. ,

TOTAL $18,717,043.

Note1 -Assumes Kewaunee Bus Reconfiguration ($17,509,123 in 2011 dollars) goes forward. Additional upgrades will be needed to reduce fault clearing times at Kewaunee if the Kewaunee Bus Reconfiguration project does not go forward (See Section 1.4).

Note 2 - Replace existing breaker failure relay with SEL-352 with high speed contacts and wire relay to direct trip

-breaker failure breakers.

Note 3 - Replace existing North Appleton 345 kV R-304 circuit breaker with a 345 kV, 3000 A; 50 kA, Gas CB.

American Transmission Company Page 14 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table 1.3 - RequiredInterconnectionFacilitiesfor G833 and G834 Entity Facilities Cost Estimate (Y2008)

Transmission None. NA Owner G833 and G834 None. NA Interconnection Note: These facilities are to be provided by the generator Customer interconnection customer. Hence, cost estimate is not applicable.

Table 1.4 - Recommended FacilitiesDue To Third PartyImpact of G833 and G834 Entity Facilities Cost Estimate (Y2008)

Recommended improvements to the Point Beach substation design. NA Add 345 kV, 3000A, 50 kA, 2 cycle gas Circuit Breakers on the high side of Point Beach auxiliary transformers T1X03 and T2X03 G833 and'G834 with adequate primary and breaker failure relaying.

Interconnection Reduce Auxiliary Transformer T1X03 primary fault clearing time Customer from 5.1 cycles to 4.75 cycles and Auxiliary Transformer T2X03 from 5.1 cycles to 4.25 cycles.

Note: These facilities are to be provided by the generator interconnection customer. Hence, cost estimate is not applicable.

American Transmission Company . Page 15 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3

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 MISO 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 facility data changes in a timely fashion to MISO and ATC prior to commercial operation.

2.2.1 Competing Generation Requests ATC determined in its judgment that five Interconnection Requests with an earlier Queue Position may impact the G833 and G834 study results. G384, G427, G590, G61 1, and G773 are included in all of the thermal analysis cases. Because of its location on the 138 kV system, G773 was not included in the stability models.

Table 2.1 - Competing Generation Requests Queue umberControl Queue Number Crea MW Requested In-Service Year G384 WPS 99 2009 G427 WEC 98 2006 (In Suspension)

G590 WEC 98 2007 G611 WEC 99 2008 G773 WPS 150 2009 Public information related to the MISO Interconnection Request queue can be found at:

http://www.midwestmarket.org/page/Generator%201nterconnection and the Interconnection Requests specific to the ATC footprint can be found at:

http://oasis.midwestiso.org/documents/ATC/Cluster 8 Queue.html.

2.2.2 Linear Transfer Analysis and A.C. Power Flow Analysis Methods Thermal overloads were identified using linear transfer analysis and then verified with AC power flow solutions. The linear transfer analysis was used to evaluate the intact system, N-1 contingency and certain ATC multiple contingency conditions. The linear transfer analysis utilized adjusted MW ratings to account for reactive power flows and a 5% transmission reserve margin ("TRM"). All AC power flow solutions utilized actual equipment ratings in MVA (i.e.

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G833-4 Interconnection System Impact Study Report, Revision 3 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.

The linear transfer analysis was performed using the Linear Transfer Analysis modules of the Managing and Utilizing System Transmission-8.3.2 (MUST, Version 8.3.2) program from Siemens Power Technologies, Inc (PTI). All AC power flow solutions were performed using the Power Flow module of the Power System Simulation/Engineering-29.5.1 (PSS/E, Version 29.5.1) program from Siemens Power Technologies, Inc (PTI). These programs are 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. Simulations were performed with G833 and G834 in service to determine the stability impacts that attributed to the additional generation. Any violations of the stability study criteria (in Appendix F) identified with the increased generation in service can be attributed to the G833 and G834 interconnection request and are documented in this report.

The stability and grid disturbance performance analysis was performed using the Dynamics Simulation and Power Flow modules of the Power System Simulation/Engineering-29 (PSS/E, 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 expected topology for the local area for summer 2010 at 100% and 50% of system peak loading conditions. The cases were developed using the 2006 series of NERC/MMWG base cases with planned and proposed projects added for the time frame studied. The topology representing the ATC service territory was taken from ATC internal planning models and inserted into the NERC/MMWG cases to update the local area model.

The output of competing generators G384, G427, G590, G611 and G773 was delivered to the WAPA and TVA control areas in an equal distribution.

The output of G833 and G834 was delivered to all MISO generation for the linear analysis portion of the study. For the AC analysis portion of the study,, half of the output of G833 and G834 .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 MISO footprint.

The study models correspond to two. load levels for the first summer season topology after the expected in-service date of G834 (G833 will bein-service one year after to G834).

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G833-4 Interconnection System Impact Study Report, Revision 3 2.3.2 Stability Analysis (Dynamics)

The 2010 50% of system peak load base case used in the stability analysis for this study was.

developed based upon the ATC 2009 Ten Year Assessment 50% peak load dynamics-ready model from the 2007 Series MMWG cases. The ATC area was replaced with the 2010 planned and proposed projects and load and generation was set to expected levels. All local and competing generators were dispatched at full output in accordance with ATC generator interconnection study methodology. The resulting additional generation was delivered to ComEd (75%) and Northern States Power (25%) control areas.

.Two stability scenarios were studied for G833 and G834. Specifically, high local generation and low local generation models were created. For the high generation scenario, in addition to Point Beach and competing generation (except G773), all local generation (Kewaunee, Fox River, Sheboygan Energy, 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 locally except that the gas plants at Fox Energy and Sheboygan Energy were modeled as off-line.

When the proposed switching station was modeled, the Edgewater unit outputs were increased slightly to their maximum capabilities and the South Fond du Lac units were put into service at their maximum capabilities.

2.3.3 Deliverability Analysis Deliverability analysis, required for G833 and G834 to attain Network Resource Interconnection Service (NRIS), has been performed by MISO. No upgrades were identified to qualify for NRIS.

Details on the MISO deliverability study methodology can be found in the whitepaper posted at the following link: MISO Deliverability Whitenaper (see Appendix E for complete URL).

2.4 Generation Facility 2.4.1 Generating Facility Modeling The G833 and G834 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 636 MW for each unit. The voltage regulation set point of each machine was 102.02% (352 kV) of nominal at the POI to reflect preferred plant operation.

The generator has informed ATC that some of the dynamic models associated with the Point Beach units will change after the units are rewound as part of the G833 and G834 project.

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 G833 and G834 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 assumed high-side clearing times for faults on the Point Beach generator step up (GSU) and.

345/13.2 kV auxiliary transformers used in the initial stability analysis were as follows:

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G833-4 Interconnection System Impact Study Report, Revision 3

1. For faults on T1XO and T2XO1 GSUs, total breaker failure clearing time was assumed to be 14 cycles.

2. For faults on T1X03 and T2X03 transformers, total breaker failure clearing time was assumed to be 12 cycles with the recommended 2 cycle high-side circuit breakers.

The actual clearing times determined using information from the Interconnection Customer and used for the analysis contained in Revision 3 of this report are:

1. For GSU transformers TIXO 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 T1X03 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 both the assumed and 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 Synchronizing and Energization of Substation/Generator Step-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.

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.

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G833-4 Interconnection System Impact Study Report, Revision 3 2.4.3 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.

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G833-4 Interconnection System Impact Study Report, Revision 3

3. Analysis Results 3.1 Power Flow Analysis Results The Intact and N-1 thermal analysis in this report used AC analysis under 100% and 50% load conditions with the conceptual West Switching Station in service. The N-2 Analysis power flow analysis used DC analysis techniques under 100% load conditions only.

3.1.1 Power Factor Capability and Voltage Requirements Power Factor Capability The G833 and G834 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 1.00 leading (when a facility is consuming reactive power from the transmission system) to 0.95 lagging (when a facility is supplying reactive power to the transmission system). For the scenarios examined, study results indicate that satisfactory system performance is achieved by supplying a range of 0 to 200 Mvars to the system, based on its maximum net generation, as measured at the low-side of the generator step-up transformer, of 612.6 MW. Tables A.3 through A.6 in Appendix A tabulate the results of the system voltage analysis under single contingencies and the analysis of the plant specific voltage requirements noted below.

Plant Specific Voltage Requirements The Point Beach Nuclear has specific 345 kV voltage range requirements. The preferred range is 352 kV (1.020 pu) to 354 kV (1.026 pu), the normal range is 351 kV (1.017 pu) to 358 kV (1.037 pu) and the maximum permissible is 348.5 kV (1.010 pu) to 362 kV (1.049 pu). Any voltage outside the maximum permissible range is a voltage limitation as described in the plant technical specifications.

3.1.2 Results of Intact System and Single Contingencies (N-I) 3.1.2.1 Base Case Analyses This analysis was conducted with all Fox Valley generation on line under 100% and 50% of system peak loading conditions with the proposed switching station modeled. The 50% of system peak loading model included expected generation levels in the Fox Valley. For this model, the Sheboygan Energy Center and Fox Energy Units were out of service and the wind farms were studied at both full output and at two-thirds of their maximum output (compare Table A.2 and Table A. 11 in Appendix A).

This study identified one transmission element steady-state thermal violation due to G833 and G834 for NERC Category B (N-1) events for the summer 2010 100% of system peak load model. Three additional transmission element steady-state thermal violations due to G833 and G834 were identified for NERC Category B (N-I) events for the summer 2010 50% of system.

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G833-4 Interconnection System Impact Study Report, Revision 3 peak load model. The transmission elements overloaded meet the criteria of an injection limit. A summary of the thermal violations due to G833 and G834 is presented in Tables A. 1, A.2 and A. 11 in Appendix A.

The one Injection Upgrade found with 100% system peak load modeled was Line LCYP31 (north end), Cypress to the new West Switching Station 345 kV. Approximately 25% of the increased generation will flow on this line, with Line 6832 North Appleton-Fox River 345 kV out of service. In addition to a slightly increased loading found on LCYP31 (north end), two additional lines were found with 50% of system peak loading conditions and maximum generation modeled. These were L111 (Point Beach to Sheboygan Energy 345 kV), with approximately 23% of the increased generation flowing on this line with LCYP31 (north end) out, of service, and Line 4035 (Elkhart Lake-G611 Tap), with approximately 3% of the new generation flowing on the line with L 11I out of service. Although Line 4035 carries only 3% of the increased generation with L 111 out of service, because L 111 is a generator outlet, this is an injection limit.

The maximum allowable real power output without system upgrades was determined by calculating the distribution factor for the element using AC analysis and then using linear interpolation to find the output of the plant based on the maximum capacity of the line and the distribution factor. The maximum allowable output without Network Upgrades for injection limits is presented in Table A.10 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 G833 and G834 (see Tables A3 and A.4 in Appendix A).

3.1.2.2 Sensitivity Analyses Sensitivity analyses are performed on the G833 and G834 interconnections to determine what effect the planned Kewaunee substation reconfiguration project will have on the study results.

The project, which is in the "planned" stage, will reconfigure the Kewaunee substation from the existing configuration; shown in Figure 3.1, to the ultimate design shown in Figure 3.2. Included in the reconfiguration is the addition of a new 345/138-kV transformer parallel to the existing 345/138-kV transformer.

Inclusion of the second 345/138-kV transformer was not found to cause any significant changes in study thermal results. In most cases, the thermal results presented include worst case loading with and without the Kewaunee bus reconfiguration modeled. The loading differences are usually less than 1 MW. Past studies have shown that the Kewaunee 138 kV outlets overload as a result of adding the second 345/138 kV transformer for certain contingencies if G384 is constructed. This result was not seen in these studies, but if it does occur in the future, it will not be associated with G833-4 and overloads will be addressed by reducing Kewaunee generation or improving the transmission network.

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G833-4 Interconnection System Impact Study Report, Revision 3 Point Beach N. Appleton Tertiary Aux Mishicot East Krok Transformer 138 kV West 22 Bus n n n (-\r 64 MVAR Cap Bank 138 kV East Bus RAT Figure 3.1 - Existing Kewaunee 345 kV and 138 kV Bus Configurations New Transformer iRAT) 1500 1717 MVA)

......... Future Syste. (2009)

New 138 kV RAT (2009)

Figure 3.2 - Proposed Two Transformer Kewaunee Bus Configuration 3.1.3 Results of Double Contingencies (N-1-1) 3.1.3.1 NERC Category C.3 Contingencies (N-1-i)

Thermal and voltage constraints were evaluated for NERC Category C events (N-1-1 contingencies) in the electrical proximity of G833 and G834 for the summer 2010 100% of system peak load model with the West Switching Station in service, as well as the second Kewaunee 345/138 kV transformer. The double contingency constraints are not required to be resolved for the generator to attain either Energy Resource or Network Resource Interconnection American Transmission Company Page 23 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Service status. The purpose of the N-i-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 linear transfer analysis. The distinct thermal violations identified from the summer 2010 100% of system peak load condition model used in the study are listed in Table A.7 in Appendix A.

The results of this analysis are supplied for information only since no operating restrictions will be created for thermal N-i-1 limits. In the day-ahead and real-time market, MISO will utilize a binding constraint procedure to mitigate transmission system overloads. This process may result in curtailment of generation and could affect G833 and G834 for the contingencies noted in this N-i-1 analysis.

This study identified seven transmission element steady-state thermal constraints for the summer 2010 100% load condition.

3.1.3.2 NERC Category C.5 Contingencies 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. No violations were found for Category C.5 events, which is the outage of two circuits on a multi-circuit tower. The Category C.5 violations are shown in Tables A.8 (100% loading) and A.9 (50% loading),

Appendix A.

Table 3.1 - NERC Category C.5 Events Reviewed Contingency Pairs Point Beach - Forest Junction 345-kV Forest Junction - Meeme - Howards Grove 138-kV Line 121 Line 971K51 Point Beach - Sheboygan Energy 345-kV Forest Junction - Meeme - Howards Grove 138-kV Line 111 Line 971K51 Point Beach - Sheboygan Energy 345-kV Howards Grove - PM4 - Holland 138-kV Line 111 Line HOLG21 Sheboygan Energy - Granville 345-kV Howards Grove - PM4 - Holland 138-kV Line L-SEC31 Line HOLG21 Sheboygan Energy - Granville 345-kV Holland - Charter Industrial - Saukville 138-kV Line L-SEC31 Line 8222 Saukville - Maple - Germantown 138-kV Cypress - Arcadian 345-kV Line 2642 Line L-CYP31. Germantown - Bark River 138-kV Line 26612

1. NERC Category C.5 events studied are limited to the simultaneous outage of any two circuits of a multi-circuit tower.

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G833-4 Interconnection System Impact Study Report, Revision 3 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.

That analysis did find stability problems for three scenarios involving a three-phase fault cleared in primary clearing time with a prior outage of another transmission element. Two of these problems were eliminated if the Point Beach Unit 1 power system stabilizer (PSS) was in-service. For the G833 and G834 analysis, it is assumed that this PSS is in-service whenever any other system element is out of service. An operating guideline exists to reduce local generation when this PSS and certain system elements outages are out of service.

The third prior outage problem concerned thermal limits at Kewaunee when Q-303 (Kewaunee-Point Beach 345 kV) was out of service and R-304 (Kewaunee-North Appleton 345 kV) tripped.

Although, under the existing system configuration, a fault on Q-303 will trip Kewaunee Transformer.T-10 so that an overload will not occur with R-304 out of service, with the proposed Kewaunee bus configuration, any fault on Q-303 or R-304 with the other line out of service will require limiting Kewaunee generator output. This is an existing limitation that will not be made better or worse by the addition of G833 and G834 and their associated Network Upgrades.

Simulations were run adding a second Kewaunee-Point Beach 345 kV line to see if this addition would eliminate this restriction. While this problem was eliminated, the second line resulted in worse performance for at least one other prior outage condition. Because this is an existing problem that is not significantly affected by G833 and G834, it will not be discussed further in this report, other than to note that the existing operating guide will not be significantly changed when G833 and G834 go into service.

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G833-4 Interconnection System Impact Study Report, Revision 3 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 A planning margin of 1.0 cycle is required between any studied 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 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.

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. The only stability problem under intact system conditions was for a fault on the high side of Kewaunee transformer T10 if the proposed Kewaunee bus reconfiguration is not completed. This problem can be eliminated by reducing fault clearing times at Kewaunee. If the Kewaunee Bus Reconfiguration is not constructed, the Kewaunee Ti0 transformer fault clearing time must be reduced to 5.5 cycles after the West switching station is in service (5.0 cycles prior to the West switching station). Even though neither Point Beach Power System Stabilizer (PSS) was modeled, no damping problems were found under any of the faults simulated. These results are summarized in Table C. 1 in Appendix C.

Table 3-2 Simulated Single Circuit 3-Phase Faults Cleared in Primary Time Faulted Element Fault Location Description L111 Point Beach 345*kV Point Beach-Sheboygan Energy 345 kV Line L121 Point Beach 345 kV Point Beach-Forest Junction 345 kV Line Li51 Point Beach 345 kV Point Beach-Fox River 345 kV Line Q-303 Point Beach 345 kV Point Beach-Kewaunee 345 kV Line Q-303 Kewaunee 345 kV Point Beach-Kewaunee 345 kV Line R-304 Kewaunee 345 kV Kewaunee-North Appleton 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 971 L71 Fox River 345 kV Fox River-Forest Junction 345 kV Line SL111 Sheboygan Energy 345 kV Point Beach-Sheboygan Energy 345 kV Line LSEC31 Sheboygan Energy 345 kV Sheboygan Energy-Granville 345 kV Line LCYP31 Cypress 345 kV Cypress-Arcadian 345 kV Line KEW T10 H* Kewaunee 345 KV Kewaunee 345/138 kV Transformer American Transmission Company Page 26 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 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). Single line-to-ground faults were simulated on both ends of the double circuit, for a total of sixteen simulated events. Although a conservative single line-to-ground fault level of 63 kA was used for both the 345 kV and 138 kV faults and the Point Beach PSSs were not modeled, no synchronous machines were observed to be unstable and there were no damping problems.

These results are summarized in Table C.2 in Appendix C.

Table 3-2 Simulated Intact System Double Circuit Single Line-to-Ground Faults Fault 1 Fault 2 Element Location Element Location 111-Pt. Beach -Sheboygan Energy 345 kV 38.5% from POB 971K5 1 Forest Jct.-Howard's Grove 138 kV 33.9% from FJT 111-Pt. Beach -Sheboygan Energy 345 kV 16.3% from SEC 971 K51-Forest Jct.-Howard's Grove 138 kV 6.3% from HOG 111-Pt. Beach -Sheboygan Energy 345 kV SEC HOGL21-Howard's Grove-Holland 138 kV 46.8% from HOL 111-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 SEC31-Sheboygan Energy-Granville 345 kV GVL 3431-Granville-Saukville 345 kV GVL SEC31-Sheboygan Energy-Granville 345 kV 26.7% from GVL 3431-Granville-Saukville 345 kV 25.3% from SAU SEC31-Sheboygan Energy-Granville 345 kV 43.5% from GVL 8231-Sukville-Barton 138 kV 36.4% from BRT SEC31-Sheboygan Energy-Granville 345 kV 48.3% from GVL 8231-Sukville-Barton 138 kV 36.4% from SAU CYP31-Cypress-Arcadian 345 kV 32.0% from ADN 2642-Saukville-Germantown 138 kV 34.2% from SAU CYP31-Cypress-Arcadian 345 kV 16.6% from ADN 2642-Saukville-Germantown 138 kV GER CYP31-Cypress-Arcadian 345 kV 10.8% from ADN 2661-Germantown-Bark River 138 kV 31.5% from GER CYP31-Cypress-Arcadian 345 kV 16.6% from ADN 2661-Germantown-Bark River 138 kV GER CYP31-Cypress-Arcadian 345 kV 10.8% from ADN 9911-Granville-Arcadian 345 kV 45.4% from GVL CYP31-Cypress-Arcadian 345 kV ADN 9911-Granville-Arcadian 345 kV ADN American Transmission Company Page 27 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 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 with the Point Beach PSSs initially out of service. If a problem was found, the PSSs were put into service. Previous studies simulating hundreds of cases resulted in unacceptable damping in only a few cases, all when the Point Beach PSSs were out of service. These damping problems were eliminated when the Point Beach PSSs were modeled as being in service. If G833 and G834 are constructed, future studies will determine system operating restrictions with the Point Beach PSSs out of service.

Table 3-2 Simulated Prior Outage Elements Element Description L111 Point Beach-Sheboygan Energy 345 kV Line L121 Point Beach-Forest Junction 345 kV Line Li51 Point Beach-Fox River 345 kV Line Q-303 Point Beach-Kewaunee 345 kV Line R-304 Kewaunee-North Appleton 345 kV Line L6832 Fox River-North Appleton 345 kV Line 971 L71 Fox River-Forest Junction 345 kV Line SEC31 Sheboygan.Energy -Granvitte 345 kV Line LCYP31 Cypress-Arcadian 345 kV Line NAPL71 North Appleton-Werner West 345 kV Line 971L51 Forest Junction-Cypress 345 kV Line Y311 North Appleton-Fitzgerald 345 kV Line T10 Kewaunee 345/138 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 With the existing Kewaunee substation modeled, 30 cases with generator instability were found for prior outage scenarios (Table C.3 in Appendix C). This number was decreased to 5 when the planned Kewaunee Substation reconfiguration was modeled (Table C.4 in Appendix C).

ForExisting Kewaunee Bus Configuration With the existing Kewaunee substation modeled, all but 3 of the prior outage problems can be eliminated by reducing fault clearing times. In most cases this will require breaker replacement at the Kewaunee bus and, possibly, replacing relays and/or upgrading communication equipment.

The proposed West. switching station, in association with reducing breaker clearing times, eliminated the problem of a 345 kV R-304 fault at Kewaunee with 345 kV line 6832 out of service. The. remaining two problems, an R-304 fault with Q-303 out of service and a fault on L121. with Point Beach breaker 2-3 out of service can be eliminated by reducing Kewaunee and Point Beach Unit 1 generation, respectively. The R-304/Q-303 problem is addressed by an existing operating guide and G833 and G834 will not make the situation worse. The L121/POB American Transmission Company Page 28 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 2-3 problem can be eliminated by an operating guide that will require Point Beach unit #1 restrictions for the unlikely condition of POB 2-3 being out of service when POB Unit 1 is in service.

With PlannedKewaunee Bus Reconfiguration None of the 5 prior outage problems found with the planned Kewaunee substation reconfiguration modeled can be eliminated by reducing fault clearing times. The proposed Kewaunee bus reconfiguration will replace all Kewaunee 345 kV breakers, eliminating the need to replace breakers to obtain the fault clearing times required under the existing Kewaunee bus configuration. The proposed West switching station once again eliminated the problem of a 345 kV R-304 fault at Kewaunee with 345 kV line 6832 out of service. The remaining problems, an R-304 fault with Q-303 out of service, Q-303 fault with R-304 out (either end faulted) and a fault on L121 with Point Beach breaker 2-3 out of service can be eliminated by reducing Kewaunee generation for the Q-303 and R-304 faults and Point Beach Unit 1 generation for the L121 fault.

The R-304/Q-303 problem is addressed by an existing operating guide and G833 and G834 will not make the situation worse. The L121/POB 2-3 problem can be eliminated by an operating guide that will require Point Beach unit #1 restrictions for the unlikely condition of POB 2-3 being out of service when POB Unit 1 is in service.

3.2.4 Results of Three-Phase Fault Delayed Clearing under Intact System Conditions Delayed 3-phase fault clearing under otherwise intact system was simulated for the events listed in Table 3-2-4 both with and without the proposed Kewaunee substation reconfiguration. This reconfiguration will remove double breakers from Kewaunee, making three additional scenarios where breaker failure could occur, two of which (Q-303 and R-304 faults at Kewaunee) were

found to cause generator instability. Three of the simulated breaker failure events resulted in generator instability for the existing Kewaunee configuration (Table C.5 in Appendix C) and four with the proposed Kewaunee bus configuration (Table C.6 in Appendix C) with existing clearing times and the proposed West Switching Station modeled. All of these unstable events can be eliminated if the faster breaker clearing times specified in Tables C.5 and C.6 are modeled.

With the existing Kewaunee substation configuration and the West Switching Station modeled, faults. on Llii, L151 and Q-303 at Point Beach resulted in generator instability if existing breaker clearing times (3.5 cycle primary local, 9.0 cycles delayed local and 4.5 cycles primary remote) were modeled. For the L151 and Q-303 faults, reducing the local delayed clearing time to 8.5 cycles eliminated the. generator instability. For the L111 fault the local delayed clearing time had to be reduced to 8.25 cycles, the fasted primary breaker failure time achievable. For faults occurring 10% or more down the line from Point Beach, the acceptable clearing time is 8.5 cycles. These results indicate that the SPSs for L11i, Li51 and Q-303 at Point Beach can be removed.

With the proposed Kewaunee substation configuration and the West Switching Station modeled, faults on L11i. and L151 at Point Beach and Q-303 and R-304 at Kewaunee resulted in generator instability if existing breaker clearing times were modeled. For all of these faults, reducing the.

primary local clearing time to 3.5 cycles, delayed local clearing time to 8.5 cycles and primary American Transmission Company Page 29 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 remote clearing time to 4.5 cycles eliminated the generator instability. These results indicate that the SPSs for L11i, L151 and Q-303 at Point Beach can be removed.

Table C.8 presents results for three phase faults with breaker failure at the proposed West switching station for an otherwise intact system. These simulations provide the required clearing times for the new switching station and did not identify any stability problems.

Table 3-2 Simulated 3-Phase Faults Cleared in Delayed Time Faulted Element Fault Location Description L111 Point Beach 345 kV Point Beach-Sheboygan Energy 345 kV Line Li 51 Point Beach 345 kV Point Beach-Fox River 345 kV Line Q-303 Point Beach 345 kV Point Beach-Kewaunee 345 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 971 L51 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 971 L71 Fox River 345 kV Fox River-Forest Junction 345 kV Line L111 Sheboygan Energy 345 kV Point Beach-Sheboygan Energy. 345 kV Line LSEC31 Sheboygan Energy 345 kV Sheboygan Energy-Granville 345 kV Line LCYP31 Cypress 345 kV Cypress-Arcadian 345 kV Line 971 L51 Cypress 345 kV Cypress-Forest Junction 345 kV Line Q-303* Kewaunee 345 kV Point Beach-Kewaunee 345 kV Line R-304* Kewaunee 345 kV Kewaunee-North Appleton 345 kV Line KEW T10 H* Kewaunee 345 KV Kewaunee 345/138 kV Transformer

Breaker Failure Scenario Only Possible with New Kewaunee Bus Configuration 3.2.5 Point Beach Bus, Generator Step Up and Auxiliary Transformer Faults.

Point Beach 345 kVBus FaultClearing Table C.7 presents results for single-line-to-ground bus 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 G833 and G834 for these faults.

GeneratorStep-Up (GSU) TransformerFault Clearing (TJX01 and T2X01)

Tables C.9 and C. 11 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 or in unacceptable system damping. Therefore, there are no upgrades necessary due to these faults.

Auxiliary TransformerFaultClearing (TJX03 and T2X03)

Table C.10 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 or in unacceptable system damping. Therefore, there are no upgrades necessary due to these faults.

American Transmission Company Page 30 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.12 presents results for three phase (primary clearing under N-I conditions) TIX03 and T2X03 faults. Simulating these faults with existing clearing times (i.e. 5.1 cycles) resulted in generators going unstable for 7 different outages for TiX03 faults and 6 different outages for T2X03 faults. As shown in Table C.13, generator stability can be maintained for all N-I conditions if TiX03 clearing time is reduced to 4.75 cycles and T2X03 clearing time is reduced to 4.25 cycles.

Most, but not all, of the TlX03 and T2X03 auxiliary transformer fault issues could be eliminated with the existing fault clearing times by the addition of high side breakers to the auxiliary transformers. While not required, it is recommended that 345-kV 2 cycle circuit breakers be installed on the T1X03 and T2X03 auxiliary transformers to avoid tripping Point Beach units for a breaker failure event (see Section 1.3).

3.2.6 Stability Results Summary The improvements in system stability required for G833 and G834 are provided by reductions in fault clearing times and the conceptual West switching station described in this report. Although these upgrades eliminate all of the stability problems created by G833 and G834, they do not fix the existing stability problems at Kewaunee when one of the Kewaunee 345 kV lines is out of service and the other is faulted. This problem is presently addressed by an operating guide that requires a Kewaunee generation reduction for a Q-303 line outage or trips the Kewaunee generator for a R-304 line outage followed by a fault on Q-303. This problem is not made worse by G833 and G834, so its solution is beyond the scope of this report. Although the stability problem found when L121 is faulted when Point Beach breaker 2-3 out of service does not presently exist due to Point Beach unit #1 net output never exceeding 550 MW, it can be dealt with by reducing Point Beach Unit I generation to 550 MW (net) in the unlikely event that POB Breaker 2-3 is out of service when Point Beach Unit #1 is in service. Alternatives to the Network Upgrades specified are discussed in Appendix H of this report.

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

Fault currents with and without contribution from G383 and G384 for three-phase and single line-to-ground faults are given in Table D. 1 in Appendix D. The corresponding Thevenin equivalent impedances are given in Table D.2.

The minimum short circuit current at the G833 and G834 POI bus occurs when Q-303 (Point Beach-Kewanee) is 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 conceptual West Switching Station showed that no over-dutied breakers had their fault levels increase by more than 1% due to. the addition ofG833-4 and associated upgrades. In addition, for American Transmission Company Page 31 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 circuit breakers impacted by more than 1% (Table D.3), none of these breakers were over-dutied.

Therefore, no circuit breaker replacements due to increased fault currents are needed for G833 and G834 generator interconnection requests.

3.4 Deliverability Analysis Results Nuclear generation interconnections are tested for deliverability to a maximum of 100% of the net MW capacity of the Generating Facility. The deliverability analysis for G833 and G834 did not identify any constraints at 100% output, as noted in Table E. 1 in Appendix E.

All deliverability constraints must be resolved to achieve Network Resource Interconnection Service (NRIS). However, G833 and G834 may choose Energy Resource Interconnection Service (ERIS) without resolving the deliverability constraints, as long as all other identified Network Upgrades are constructed. 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 32 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix A: Power Flow Analysis Results American Transmission Company Page 33 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table A. 1 - Identified Thermal Violations Due to G833 and G834 Summer 2010 (100% Load) Delivery to MISOfor NERC CategoryA and B events (TDF>3%)

West Switching Station in Service Existing Required Worst TDF Injection Potential Limiting Element Rating Rating Solution (MVA) (MVA) 1.2 Contingency 3

(%) Limit Identified Cypress - West Switching Station 488 SE 659 SE N.Appleton - Fox River345-kV 25.6 Yes No4 345-kV Line L-CYP31 (North) Line 6832 Elkhart Lake-G611 Tap 138-kV 96 SE 98 SE Granville-Sheboygan Energy 345-kV 3.2 No No5 Line 4035 (South) Line L-SEC31

1. Includes provision for 5% TRM. The required ratings are calculated using AC transfer analysis in ACCC dispatching 100% of power from G833 and G834 to MISO. Because of the minimal difference in results with and without a second 345/138 kV Kewaunee Transformer, only worst case results are reported.

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, including:

a. SPS to trip Kewaunee - N. Appleton 345-kV Line R-304 for a fault on the N. Appleton 345/138-kV Transformer T I

4. Required Rating Should be able to be met by increasing line clearance

5. Line Rating is being increased to 112 MVA due to requirements of G611 and G927 generation interconnection studies Table A.2 - Identified Thermal Violations Due to G833 and G834 Summer 2010 (50% Load)Delivery to MISO for NERC Category A and B events (TDF>3%o)

West Switching Station in Service, Wind Farms at Full Outout Existing Required Potential Limiting Element Rating Rating Worst TDF Injection Solution (MVA) (MVA) 1,2 Contingency (%) Limit Identified Cypress- West Switching Station 488 SE 675 SE Point Beach-Sheboygan Energy 27.2 Yes No3 345-kV Line L-CYP31 (North) Center 345-kV Line 111 Point Beach-Sheboygan Energy 488 SE 555 SE Cypress - West Switching Station 22.7 Yes No Center 3457kV Line 111 345-kV Line L-CYP31 (North)

Arcadian - West Switching Station 488 SE 554 SE Edgewater-Saukville 345 kV 14.0 No No 345-kV Line L-CYP31 (South) Line 796L41 Elkhart Lake-G611 Tap 138-kV 96 SE 131 SE Point Beach-Sheboygan Energy 3.2 Yes 5 No4 Line 4035 (South) Center 345-kV Line 111

1. Includes provision for 5% TRM. The required. ratings are calculated using AC transfer analysis in ACCC dispatching 100% of power from G833 and G834 to MISO. Because of the minimal difference in results with and without a second 345/138 kV Kewaunee Transformer, only worst case results are reported. WN= Winter Normal, WE = Winter Emergency

2. SN = Summer Normal, SE = Summer Emergency

3. Required Rating Should be able to be met by increasing line clearance

4. Line Rating is being increased to 112 MVA due to requirements of G611 and G927 generation interconnection studies

5. This line is an Injection Limit because the contingency causing the overload is an outlet of the proposed generation.

American Transmission Company Page 34 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table A.3 - Identified Voltage Violations Due to G833 and G834 Summer 2010 Deliver (100% Load) to MISOjorNERC CategoryA & B events (AV> O.1 .l.)

Worst Voltage (p.u.) Potential Limiting Element Contingency Pre Post AV (p.u.) Solution G833-4 G833-4 Identified None Identified -

Table A.4 - Identified Voltage Violations Due to G833 and G834 Summer 2010 Deliver (50% Load) to MISO for NERC Category A & B events (A V> 0.1 p.u Limiting Worst Voltage (p.u.) Potential Element Contingency Pre Post AV (p.u.), Solution

_ G833-4 G833-4 identified None Identified American Transmission Company Page 35 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table A. 5 - Voltage Measurements at the Point Beach 345-kV Substationwith West Switching Station Summer 2010 100% Load with Selected Contingencies' Voltage 2 (p.u.)

Contingency Point Beach Point Beach Point Beach Point Beach Point Beach Bus #1 Bus#2 Bus#3 Bus #4 Bus #5 Intact System 1.02026 1.02020 1.02020 1.02020 1.02024 Point Beach BS 2-3 1.02026 1.02020 1.02020 1.02020 1.02023 Point Beach BS 2 - Forest Junction 345-kV 1.02026 1.02020 1.02020 1.02020 1.02014 Line 121 Point Beach BS 1-2 1.02505 1.02020 1.02020 1.02020 1.02021 Point Beach BS 4-53 1.020263 1.02020 1.02020 1.02020 1.02237 Point Beach BS 3-4 1.02026 1.02020 1.02020 1.02020 1.02019 Point Beach BS 5- Fox River 345-ky 1.02026 1.02020 1.02020 1.02020 1.02019 Line 151 Forest Junction - Fox River 345-kV Line 971L71 1.02026 1.02020 1.02020 1.02020 1.02025 Point Beach BS 1 - Sheboygan Energy 345-kV 1.02019 1.02020 1.02020 1.02020 1.02021 Line 111 Point Beach BS Line3 - 3Kewaunee BahS 345-ky 1.02026 1.02020 1.02020 1.02020 1.02023 Line Q-303 Forest Junction - Cypress 345-kV 1.02026 1.02020 1.02020 1.02020 1.02024 Line 971L51 Forest Junction 345/138-kV 1.02026 1.02020 1.02020 1.02020 1.02025 Transformer TI Forest Junction 345/138-kV Transformer T2 1.02026 1.02020 1.02020 1.02020 1.02025 Fox River - N.Appleton 345-kV 1.02026 1.02020 1.02020 1.02020 1.02024 Line 6832 Fox Energy Center Unit CT 1 1.02026 1.02020 1.02020 1.02020 1.02018 Fox Energy Center UnitCT 2 1.02026 1.02020 1.02020 1:02020 1.02018 Fox Energy Center Unit ST 1.02026 1.02020 1.02020 1.02020 1.02018 S Line L-SEC31 1.02015 1.02020 1.02020 1.02020 1.02016 Sheboygan Energy Center Unit #1 1.02021 1.02020 1.02020 1.02020 1.02025 Sheboygan Energy Center Unit #2 1.020213 1.02020 1.02020 1.02020

1.02025 Point Beach Unit #14 1.02025 1.02020 1.02020 1.02020 1.02025 Point Beach Unit #25 1.02025 1.02020 1.02020 1.02020 1.02025 Point Beach Units #1 &#26 1.01917 1.01912 1.01912 1.019W2 1.01918 American Transmission Company Page 36 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3

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 1.0202 p.u.

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345/13.2-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 #1. 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. As explained in Section 2.4.2 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 and WAPA.

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 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. As explained in Section 2.4.2 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 and WAPA.

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. As explained in Section 2.4.2 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 and WAPA.

American Transmission Company Page 37 of 71 12/17/2008

G833-4 Interconnection System Impact StudyReport, Revision 3 Table A. 6 - Voltage Measurements at the PointBeach 345-kV SubstationAfter West Switching Station Winter 2010 (50% Load) with Selected Contingencies' Voltage 2 (p.u.)

Contingency Point Beach Point Beach Point Beach Point Beach Point Beach Bus #1 Bus #2 Bus #3 Bus #4 Bus #5 Intact System 1.02009 1.02020 1.02020 1.02020 1.02017 Point Beach BS 2-3 1.02013 1.02020 1.02020 1.02020 1.02014 Point Beach BS 2 - Forest Junction 345-kV 1.02004 1.02020 1.02020 1.02020 1.02008 Line 121 Point Beach BS 1-2 1.02136 1.02020 1.02020 1.02020 1.02010 Point Beach BS 4-53 1.02005 1.02020 1.02020 1.02020 1.01491 Point Beach BS 3-4 1.02011 1.02020 1.02020 1.02020 1.02012 Point Beach BS 5 - Fox River 345-ky 1.02005 1.02020 1.02020 1.02020 1.02019 Line 151 Forest Junction - Fox River 345-kV 1.02009 1.02020 1.02020 1.02020 1.02022 Line 971 L71 Point Beach BS 1 - Sheboygan Energy 345-kV 1.02019 1.02020 1.02020 1.02020 1.02009 Line 111 Point Beach BS 3- Kewaunee 345-ky 1.02009 1.02020 1.02020 1.02020 1.02017 Line Q-303 Forest Junction -Cypress 345-ky 1.02005 1.02020 1.02020 1.02020 1.02016 Line 971L51 Forest Junction 345/138-kV 1.02009 1.02020 1.02020 1.02020 1.02018 Transformer T1 Forest Junction 345/138-kV 1.02009 1.02020 1.02020 1.02020 1.02018 Transformer T2 Fox River - N.Appleton 345-kV 1:02007 1.02020 1.02020 1.02020 1.02015 Line 6832 Fox Energy Center Unit CT 1 N/A N/A N/A N/A N/A Fox Energy Center Unit CT 2 N/A N/A N/A N/A N/A Fox Energy Center Unit ST N/A N/A N/A N/A N/A Sheboygan Energy - Granville 345-ky 1.02030 1.02020 1.02020 1.02020 1.02009 Line L-SEC31 Sheboygan Energy Center Unit #1 N/A N/A N/A N/A N/A Sheboygan Energy Center Unit #2 N/A N/A N/A N/A N/A Point Beach Unit #14 1.02020 1.02020 1.02020 1.02020 1.02022 Point Beach Unit #25 1.02020 1.02020 1.02020. 1.02020 1.02022 Point Beach Units #1 &#26 1.01894 1.01888 1.01888 1.01888 1.01891 American Transmission Company Page 38 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3

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 1.0202 p.u.

3. Point Beach Bus Section #5 is isolated from both Point Beach generating units for this contingency. The planning case used models the T2X03 345/13.2-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 #1. 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. As explained in Section 2.4.2 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 and WAPA.

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 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. As explained in Section 2.4.2 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 and WAPA.

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 TIX03 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. As explained in Section 2.4.2 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 and WAPA.

American Transmission Company Page 39 ofT71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table A. 7 - Identified Thermal Violations under select NERC Category C.3 events1 Summer 2010 100% Load Delivery to MISO West Switching Station and Proposed2 nd KEW 345/138 kV Transformerin Service Limiting Existing Required Worst TDF Potential Rating Rating2 ,3 Solution Element (MVA) (MVA) Double Contingency (%) Identified 4

Point Beach - Forest Junction 345-kV 883 SE 1099 SE 57.6 No Line 121 Cypress-Forest Junction 345 kV 488 SE 612 SE 29.9 No5 Line 971L51 Cypress-West Switching Station 345 kV 488 SE 878 SE N.Appleton - Fox River 345-kV 29.6 No6 Line CYP31 (North) Line 6832 Kewaunee - East Krok 138-kV N.Appleton - Kewaunee 345-kV Line F-84 287 SE 347 SE Line R-304 8.4 No7 Forest Junction - Kaukauna Central Tap 293 SE 325 SE 5.2 No8 138-kV Line 971K11 Forest Junction - Darboy 138-kV 293 SE 504 SE 4.8 No9 Darboy - Lake Park 138-kV 293 SE 476 SE 4.8 No9 Line 728K21 Cypress-West Switching Station Neevin-Woodenshoel38-kV 345-kV Line CYP31 (North)

Line 80952 N.Appleton - Fitzgerald 345-kV Line Y-311

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 DC analysis in PSS/E dispatching G833 and G834 to all MISO generation.

3. SE = Summer Emergency

4. Rating limited by 12.6 miles of 2156.0 kcmil ACSR 84/19 Bluebird line conductor at an emergency temperature rating of 146' F.

5. Rating limited by 30.43 miles of 2156.0 kcmil ACSR 84/19 Bluebird line conductor at an emergency temperature rating of 120' F.

6. Rating limited by 11.7 miles of 2156.0 kcmil ACSR 84/19 Bluebird line conductor at an emergency temperature rating of 1200 F.

7. Rating limited by line conductor, station conductors, meters, traps, switches, CTs and the East Krok breaker.

8. Rating limited by 9.3 miles of 795.0 kcmil ACSR .26/7 Drake line conductor at an emergency temperature rating of 2000 F.

9. Rating limited by 11.7 miles of 795.0 kcmil ACSR 26/7 Drake line conductor at an emergency temperature rating of 2000 F.

10. Rating limited by 4.04 miles of 795.0 kcmil ACSR 26/7 Drake line conductor at an emergency temperature rating of 2300 F.

American Transmission Company .Page 40 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 1

Table A. 8- Identified Voltage Violations under select NERC Category C.5 events Summer 2010 100% Loading Mode, Delivery to MISO, West Switching Station In Limiting Worst Voltage (p.u.) Potential Element Contingency1 Pre Post ,V(p.u.) Solution G833,4

_ G833-4 Identified 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. See Table 3.1 for a list of all NERC Category C.5 events studied.

1 Table A.9 - Identified Voltage Violations under select NERC Category C.5 events Summer 2010 50% LoadingMode, Delivery to MISO, West Switching Station In Limiting Worst Voltage (p.u.) Potential Element Contingency1 Pre Post AV (p.u.) Solution

_ G833-4 G833-4 Identified 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. See Table 3.1 for a list of all NERC Category C.5 events studied.

American Transmission Company Page 41 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table A. 10 - Maximum Allowable Generationfor G833 and G834 without Network Upgr des for Injection Limits G833-4 Max Output with Limiting Element Wort Model Planned and Proposed LtContingency Description Projects' (MW)

Cypress-West Switching Point Beach-Sheboygan 2010, 50% Load, Existing 0 MW Station (L-CYP31 north) 345 kV Energy (Ll 11)345 kV Kewaunee Sub 2 Arcadian-West Switching Edgewater-Saukville 2010, 50% Load, Existing 0 MW Station (L-CYP31 south) 345 kV (796L41) 345 kV Kewaunee Sub 3 Elkhart Lake-G611 Tap Granville-Sheboygan 2010, 50% Load, Proposed 4

0 MW (4035 South) 138 kV Energy (L-SEC31) 345 kV Kewaunee Sub Point Beach-Sheboygan Edgewater-Saukville 2010, 50% Load, Existing 3

0 MW Energy (L111) 345 kV (796L41) 345 kV Kewaunee Sub

1. Planned and Proposed projects from the ATC 2006 Ten Year Assessment report (http://www.atcl0yearplan.com/). The 345 kV West Switching Station described in this report is also modeled.

2. The Maximum Output is the same with 100% of system peak load and/or the new Kewaunee Substation configuration modeled. Maximum generator out put is 89 MW for Intact System conditions with 50% of system peak load modeled. There is no intact system generation limit under 100% of system peak load conditions.

3. The Maximum Output is the same with the new Kewaunee Substation configuration modeled.

The overload does not exist for 100% of system peak load models.

4. The maximum output for the 50% of system peak load case (0 MW) is the same after the Line 4035 upgrade to 112 MVA for G611 and G927 is completed. For the 100% of system peak load case, there is no restriction after the 4035 line upgrade due to G61 1 and G927, but there would be a 125 MW (proposed Kewaunee substation configuration) or 141 MW (existing Kewaunee substation configuration) restriction at the existing line rating (96 MVA).

Table A. 1] - Identified Thermal Violations Due to G833 and G834 Summer 2010 (50% Load) Delivery to MlSO for NERC CategoryA and B events (TDF>3%)

West Switching Station in Service, Wind Farms at Two-Thirds Output

-Existing Required Worst Limiting Element Rating Rating (MVA) (MVA) 1,2 Contingency Cypress - West Switching Station 488 SE 579 SE Point Beach-Sheboygan Energy 345-kV Line L-CYP31 (North) Center 345-kV Line 111 Point Beach-Sheboygan Energy 488 SE 516 SE Cypress - West Switching Station Center 345-kV Line. 111 345-kV Line L-CYP31 (North)

Arcadian - West Switching Station 488 SE 513 SE Edgewater-Saukville 345 kV 345-kV Line L-CYP31 (South) Line 796L41 Elkhart Lake-G611 Tap 138-kV Point Beach-Sheboygan Energy Line 4035 (South) 96 SE3 117 SE Center 345-kV Line 111 I Includes provision for 5% TRM. The required ratings are calculated using AC transfer analysis in ACCC dispatching 100% of power from G833 and G834 to MISO. Because of the minimal difference in results with and without a second 345/138 kV Kewaunee Transformer, only worst case results are reported.

WN =.Winter Normal, WE = Winter Emergency

2. SN = Summer Normal, SE = Summer Emergency

3. Line Rating is being increased to 112 MVA due to requirements of other generation interconnection studies.

American Transmission Company Page 42 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix B: Operation Restrictions American Transmission Company Page 43 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table B..] - Summary of Identified GenerationRestrictions due to Stability Constraints (West Switching Station in service and Kewaunee Substation Reconfigured)

PriorOutage , Worst Next Contingency Generation Restriction' Q-303 Point Beach-Kewaunee 345 kV R-304 Kewaunee-North Appleton 345 kV Kewaunee Net Generation -5500 MW 1 R-304 Kewaunee-North Appleton 345 kV Q-303 Point Beach-Kewaunee 345 kV Kewaunee Net Generation -5475 MW2 Point Beach 345 kV Breaker 2-3 L121 Point Beach-Forest Junction 345 kV Point Beach Unit #1 Net Generation < 550 MW3

1. The same restrictionexists with or without the West Switching Station and with both existing and minimum North Appleton breaker clearing times. Prior to Kewaunee substation reconfiguration Kewaunee Generation must be < 382 MW (T1 0 thermal limit).

2. The same restriction exists with or without the West Switching Station. Prior to Kewaunee substation reconfiguration there is no restriction on Kewaunee Generation because T1 0 is tripped with R-304.

3. The same restriction exists with or without the West Switching Station and before and after the Kewaunee Substation Reconfiguration.

Armerican Transmission Company Page 44of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix C: Stability Analysis Results American Transmission Company Page 45 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.1 - G833 and G834 Stability Resultsfor Faults Clearingin Primary Time under Intact System Conditions (Kewaunee SPS Implementedfor ExistingKewaunee Substation Configuration,PointBeach PSS out-of-service)

Item Element Fault Remote Kewaunee Clearing Cycles High Gen Model Low Gen Model Number Faulted Location Location Substation Local/Remote Units Tripped Units Tripped I Lli 1 -Point Beach-Sheboygan 345 kV POB SEC Existing 4.5/4.5 none none 2 Ll 1i-Point Beach-Sheboygan 345 kV POB SEC Proposed 4.5/4.5 none none 3 L121 - Point Beach-Forest Junction 345 kV POB FJT Existing 4.5/4.5 none none 4 L121 - Point Beach-Forest Junction 345 kV POB FJT Proposed 4.5/4.5 none none 5 Li51 -Point Beach-Fox Energy 345 kV POB FOX Existing 4.5/4.5 none none 6 L151 -Point Beach-Fox Energy 345 kV POB FOX Proposed 4.5/4.5 none none 7 Q-303 - Point Beach-Kewaunee 345 kV POB KEW Existing 4.5/6.5 none none 8 Q-303 - Point Beach-Kewaunee 345 kV POB KEW Proposed 4.5/4,5 none none 9 Q-303 - Point Beach-Kewaunee 345 kV KEW POB Existing 6.5/4.5 none none 10 Q-303 -Point Beach-Kewaunee 345 kV KEW POB Proposed 4.5/4.5 none none 11 R-304 - Kewaunee-North Appleton 345 kV KEW NAP Existing 6.5/6.5 none none 12 R-304 - Kewaunee-North Appleton 345 kV KEW NAP Proposed 4.5/6.5 none none 13 L151 - Point Beach-Fox Energy 345 kV FOX POB Existing 4.5/4.5 none none 14 L151 - Point Beach-Fox Energy 345 kV FOX POB Proposed 4.5/4.5 none none 15 L6832 Fox Energy-North Appleton 345 kV FOX NAP Existing 4.5/4.5 none none 16 L6832 Fox Energy-North Appleton 345 kV FOX NAP Proposed 4.5/4.5 none none 17 971L71 - Fox Energy-Forest Junction 345 kV FOX FJT Existing 4.5/4.5 none none 18 971L71 - Fox Energy-Forest Junction 345 kV FOX FJT Proposed 4.5/4.5 none none 19 L11i -Point Beach-Sheboygan 345 kV SEC POB Existing 4.5/4.5 none none 20 Llii - Point Beach-Sheboygan 345 kV SEC POB Proposed 4.5/4.5 none none 21 LSEC31 -Sheboygan-Granville 345 kV SEC GVL Existing 4.5/6.5 none none 22 LSEC31 -Sheboygan-Granville 345 kV SEC GVL Proposed 4.5/6.5 none none 23 L9932 -Cypress-Arcadian 345 kV CYP ADN Existing 4.5/4.5 none none 24 L9932 - Cypress-Arcadian 345 kV CYP ADN Proposed 4.5/4.5 none none 25 T10 - Kewaunee 345/138 kV Transformer KWH KWL Existing 7.5/8.5 26 TIO -Kewaunee 345/138 kV Transformer KWH KWL Proposed 5.5/5.5 none none Notes: (1) Tripped Units - K-KEW, P1-POB 1, P2-POB 2, P-POB 1 &2, Fl-Fox CT1, F2-Fox CT2, FS-Fox ST, F-Fox CT1, CT2 &ST, Si-SEC 1, S2-SEC 2, S-SEC 1&2.

(2)Clearing Times Include 1.0 Cycle Margin on Faulted End Clearing Time

Stable at 6.5/6.5 (KEW Trips at 7.0/7.0), Also Stable at 6.5/6.5 (KEW Trips at 7.0/7.0) with West Switching Station Modeled.

-Stable at 6.0/6.0 (KEW Trips at 6.5/6.5). Stable at 6.5/6.5 (KEW Trips at 7.0/7.0) with West Switching Station Modeled.

American Transmission Company Page 46 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.2 - G833 and G834 Stability Resultsfor Double CircuitSingle Line-to-GroundFaults Clearedin Primary Time under Intact System Conditions, Point Beach PSS in-service Item Faulted Element Fault #1 #1 Faulted Element Fault #2 #2 Existing KEW Sub Future KEW Sub

#1 Location Cycles #2 Location Cycles High Gen Low Gen High Gen Low Gen 1 L111 - Point Beach-Sheboygan 345 kV 38.5% from POB 5.5 971 K51 - Forest Junction-Howard's Grove 138 kV 33.9% from FJT 6.5 none none none none 2 L111 - Point Beach-Sheboygan 345 kV 16.3% from SEC 5.5 971 K51 - Forest Junction-Howard's Grove 138 kV 6.3% from HOG 6.5 none none none on 3 L11i - Point Beach-Sheboygan 345 kV SEC 5.5 HOGL21 - Howard's Grove-Holland 138 kV 76.9% from HOL 6.5 none none none none 4 L111 - Point Beach-Sheboygan 345 kV 15.7% from SEC 5.5 HOGL21 - Howard's Grove-Holland 138 kV 31.4% from HOG 6.5 none none one none 5 Li21 - Pt. Beach-Forest Junction 345 kV FJT 5.5 971K51 - Forest Junction-Howard's Grove 138 kV FJT 6.5 none none none non 6 L121 - Pt. Beach-Forest Junction 345 kV 42.3% from FJT 5.5 971K51 - Forest Junction-Howard's Grove 138 kV 33.9% from FJT 6.5 none none none none 7 SEC31 -Sheboygan-Granville 345 kV GVL 7.5 3431 -Granville-Saukville 345 kV GVL 7.5 none none none none 8 SEC31 - Sheboygan-Granville 345 kV 26.7% from GVL 7.5 3431 - Granville-Saukville 345 kV 25.3% from SAU 7.5 none none none none 9 SEC31 - Sheboygan-Granville 345 kV 43.5% from GVL 7.5 8231 - Saukville-Barton 138 kV 36.4% from BRT 7.5 none none none none 10 SEC31 -Sheboygan-Granville 345 kV 48.3% from GVL 7.5 8231 - Saukville-Barton 138 kV 36.4% from SAU 7.5 none none none none 11 CYP31 - Cypress-Arcadian 345 kV 32.0% from ADN 5.5 2642 - Saukville-Germantown 138 kV 34.2% from SAU 7.5 none none none none 12 CYP31 - Cypress-Arcadian 345 kV 16.6% from ADN 5.5 2642 - Saukville-Germantown 138 kV GER 7.5 none none none none 13 CYP31 - Cypress-Arcadian 345 kV 10.8% from ADN 5.5 2661 - Germantown-Bark River 138 kV 31.5% from GER 8.5 none none none none 14 CYP31 - Cypress-Arcadian 345 kV 16.6% from ADN 5.5 2661 - Germantown-Bark River 138 kV GER 8.5 none none none none 15 CYP31 - Cypress-Arcadian 345 kV 10.8% from ADN 5.5 9911 - Granville-Arcadian 345 kV 45.4% from GVL 7.5 none none none none 16 CYP31 - Cypress-Arcadian 345 kV ADN 5.5 9911 - Granville-Arcadian 345 kV ADN 7.5 none none none none Notes: (1) Tripped Units - K-KEW, P1-POB 1, P2-POB 2, P- POB 1 & 2, Fl-Fox CT1, F2-Fox CT2, FS-Fox ST, F-Fox CT1, CT2 &ST, S1-SEC 1, S2-SEC 2, S-SEC 1 &2.

(2)Clearing Times (Cycles) Include 1.0 Cycle Margin on Faulted End Clearing Time American Transmission Company Page 47 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.3 - G833 and G834 Stability Resultsfor 3-Phase Faults Cleared in Primary Time under PriorOutage Condition Units Tripping, Existing Kewaunee Substation Configuration,Point Beach PSS in-service Existing Existing Clearing Existing Clearing Tested Tested Clearing Tested Clearing Event Faulted Fault Prior Clearing High Gen Low Gen Clearinq Hiah Gen Low Gen Element Location Outage Time Existing I West SS Existing I West SS Time Existing West SS Existing West SS 1 T-10 KEW None 7.5/8.5 5.5/5.5 none none none none 2 R-304 KEW L-111 6.5/6.5 4.5/6.5 none none none none 3 T-10 KEW L-111 7.5/8.5 5.5/5.5 none none none none 4 R-304 KEW L-121 6.5/6.5 4.5/6.5 none none none none 5 T-10 KEW L-121 7.5/8.5 5.5/5.5 none none none none 6 R-304 KEW L-151 6.5/6.5 4.5/6.5 none none non none 7 T-10 KEW L-151 7.5/8.5 5.5/5.5 none none none none 8 + R-304 - +

I KEW 1 0-303 1 6.5/6.5 1 4.5/6.5 K' K* K* K*

9 T-10 I KEW I Q-303 1 7.5/8.5 I 5.5/5.5 none none none none 10 R-304 KEW 6832 6.5/6.5 4.5/6.5 none none none 11 T-10 KEW 6832 7.5/8.5 5.5/5.5 none none none none 12 T-10 KEW 971L71 7.5/8.5 5.5/5.5 none none none none 13 R-304 KEW SEC31 6.5/6.5 4.5/6.5 none none none none 14 T-10 KEW SEC31 7.5/8.5 5.5/5.5 none none none none 15 R-304 KEW CYP31 6.5/6.5 1 4.5/6.5 none none 16 T-10 KEW CYP31 7.5/8.5 5.5/5.5 none none none none 17 R-304 KEW T10 6.5/6.5 4.5/6.5 none none 18 R-304 KEW NAPL71 6.5/6.5 4.5/6.5 none none 19 T-10 KEW NAPL71 7.5/8.5 5.5/5.5 none none none none 20 R-304 KEW 971 L51 6.5/6.5 4.5/6.5 none none none 21 T-10 KEW 971 L51 7.5/8.5 5.5/5.5 none none none none 22 R-304 KEW L311 6.5/6.5 4.5/6.5 none none 23 T-10 KEW L311 7.5/8.5 5.5/5.5 none none norM none 24 R-304 KEW POB12 6.5/6.5 4.5/6.5 none none none none 25 T-10 KEW P0612 7.5/8.5 5.5/5.5 none none none none 26 L121 POB POB23 4.5/4.5 n/a 27 R-304 KEW POB23 6.5/6.5 4.5/6.5 none none none none 28 T-10 KEW POB23 7.5/8.5 5.5/5.5 none none none none 29 T-10 KEW POB34 7.5/8.5 5.5/5.5 none none none none 30 R-304 KEW POB45 6.5/6.5 4.5/6.5 none none none none 31 T-10 KEW POB45 7.5/8.5 5.5/5.5 none none none none Notes: (1) Tripped Units - K-KEW, P1-POB 1, P2-POB 2, P- POB 1 &2, Fl-Fox CT1, F2-Fox CT2, Fs-Fox ST, F-Fox CT1, CT2 &ST, Si-SEC 1, S2-SEC 2, S-SEC 1 &2.

(2) Clearing Times (Cycles) Include 1.0 Cycle Margin on Faulted End Clearing Time K*- Stable with Existing Kewaunee Generation 382 MW Limit for Kewaunee Transformer T1 0 Thermal Concerns P1 - Stable with West Switching Station and Kewaunee Net Generation 5 550 MW. Stable at Full Generation with East Switching Station, w/or w/o West Switching Station.

P, K,F, S*- Unstable with even with 4.5/4.5 Cycle Clearing, None* - Stable at 6.5/6.5 Clearing Time, none** - Stable at 6.0/6.0 Clearing Time.

American Transmission Company Page 48 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.4 - G833 and G834 Stability Results for 3-PhaseFaults Clearedin Primary Time under PriorOutage Condition Units Tripping, ProposedKewaunee Substation Configuration,Point Beach PSS in-service I I I I -,

Existing Existing Clearing Existing Clearing Tested Tested Clearing Tested Clearing Event Faulted Fault Prior Clearing . High Gen Low Gen Clearing High Gen Low Gen Element Location Outage Time Time Existing West SS Existina West SS 1 R-304 KEW Q-303 4.5/6.5 2 Q-303 POB R-304 4.5/4.5 n/a 3 Q-303 KEW R-304 4.5/4.5 4.5/4.5 n/a 4 R-304 KEW 6832 4.5/6.5 4.5/4.5 - . none none none 5 L-121 POB P0B23 4.5/4.5 n/a I Notes: (1) Tripped Units - K-KEW, P1-POB 1, P2-POB 2, P- POB 1 &2, Fl-Fox CT1, F2-Fox CT2, Fs-Fox ST, F-Fox CT1, CT2 &ST, Si-SEC 1,S2-SEC 2, S-SEC 1 &2.

(2) Clearing Times (Cycles) Include 1.0 Cycle Margin on Faulted End Clearing Time K*- Stable with Kewaunee Net Generation < 500 MW.

K** - Stable with Kewaunee Net Generation < 475 MW.

P1* - Stable with West Switching Station and Kewaunee Net Generation 5 550 MW. Stable at Full Generation with East Switching Station, w/or w/o West Switching Station.

American Transmission Company Page 49 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.5 - G833 and G834 StabilityResults for 3-PhaseFaults Clearedin Delayed Time under Intact Conditions, Units Tripping, Existing Kewaunee Substation Configuration,Point Beach PSS in-service Event Element Fault Remote Event Existing High Generation Base High Generation - West SS Low Generation Base Low Generation - West SS Number Faulted Location Location Notes CCT* 3.5/9.5/4.5 Existing 3.5/9.5/4.5 Ex g 3.5/95/4.5 Existing 3.5/9.5/4.5 Existing 1 -111 POB SEC T1X03 Tripped, Aux Moved 3.5/10.0/4.5 no 2 L151 POB FOX T2X03 Tripped, Aux Moved 3.5/10.0/4.5 none none 3 Q303 POB KEW Trip T10 Primary, Delay POB Split 3.5/10.0/6.5 none none 4 R-304 NAP KEW Split NAP Primary, T10 Trips inBF 5.5/14.25/5.5 nonenone none none 5 L121 FJT POB Tnps Transformer 3.5/10.5/4.5 none none none none 6 971L51 FJT CYP Trips Line 971 L71 3.5/10.5/4.5 none none none none 7 971171 FJT FOX Trips Line 971 L51 3.5/10.5/4.5 none none none none 8 L151 FOX POB BF Trips Fox Unit 1 3.5/10.5/4.5 none none none none 9 L6832 FOX NAP BF Trips Fox Unit 2 3.5/10.0/4.5 none none none none 10 971L71 FOX FJT BF Trips Fox Unit 2 3.5/10.0/4.5 none none none none 11 L111 SEC POB Do Not Trip Gen (worst case) 3.5/10.5/4.5 none none none none 12 LSEC31 SEC GVL Do Not Trip Gen (worst case) 3.5/10.5/6.5 none none none none 13 LCYP31 CYP ADN Trips CYP Units 3.5/10.5/4.5 none none none none 14 971L51 CYP FJT Trips CYP Units 3.5/10.5/4.5none none none none Notes. 0 (: Trinnad I Init. - K.KW PI.DPB 1 P9.PfR 92 P- POP 1 R 9 PIS, r.TI (T9 (77 PF.Pny (T .Pnv (7TI 779 k QT RI.-Pr I Q9sgr- 9 qc.rPr 1 k 9 (2)Clearing Times (Cycles) Include 1.0 Cycle Margin on Faulted End Clearing Time

- Stable at 9.25 cycles at bus and 9.5 cycles for a fault at 10% of the line length.

- Stable at 9.0cycles at bus.

American Transmission Company Page 50 of 71t 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.6 - G833 and G834 Stability Resultsfor 3-Phase FaultsClearedin Delayed Time under Intact Conditions, Units Tripping, ProposedKewaunee Substation Configuration,PointBeach PSS in-service Event Element Fault Remote Event Existing High Generation Base High Generation - West SS Low Generation Base Low Generation - West SS Number Faulted Location Location Notes CCT* 3.5/9.5/4.5 Existing 3.519.5/4.5 Existing 3.5/9.5/4.5 Exist 3.5/9.5/4.5 Existing 1 L111 POB SEC TIX03Tripped, Aux Moved 3.5/101 5 o nn 2 L151 POB FOX T2X03 Tripped, Aux Moved 3.5/10.0/4.5 none rnone none 3 Q303 POB KEW Delay POB Split 3.5/10.0/6.5 none n none none none 4 Q303 KEW POB Trip T10 Primary, Delay POB Split 3.5/10.0/4.5 none none none none 5 R-304 KEW NAP Split NAP Primary, T10 Trips in BF 5.5/14.25/5.5 none none none none 6 KEW T10 KEWH KEWL Split NAP Primary, TI 0 Trips in BF 5.5/14.25/5.5 none none none none 7 R-304 NAP KEW Split NAP Primary, T10 Trips in BF 5.5/14.25/5.5 none none none none 8 L121 FJT POB Trips Transformer 3.5/10.5/4.5 none none none none 9 971 L51 FJT CYP Trips Line 971 L71 3.5/10.5/4.5 none none none none 10 971171 FJT FOX Trips Line 971L51 3.5/10.5/4.5 none none none none 11 L151 FOX POB BF Trips Fox Unit 1 3.5/10.5/4.5 none none none none 12 L6832 FOX NAP BF Trips Fox Unit 2 3.5110.0/4.5 none none none none 13 971 L71 FOX FJT BF Trips Fox Unit 2 3.5/10.0/4.5 none none none none 14 L111 SEC POB Do Not Trip Gen (worst case) 3.5/10.5/4.5 none none none none 15 LSEC31 SEC GVL Do Not Trip Gen (worst case) 3.5/10.5/6.5 none none none none 16 LCYP31 CYP ADN Trips CYP Units 3.5/10.5/4.5 none none none none 17 971 L51 CYP FJT Trips CYP Units 3.5/10.5/4.5 none none none none V + l- *1Trinnarl I Inite Vl*(D:I Le_ DODtR4 DOD12) D DnI I 2- ) C1 C tT4 C1_ C IL VA (T')

d I C:I:_l C QT C C

.- VA VI -

r'T4 r(T')

VA III 'dLI IJI ~LI

- OTT01 42_t1' I Q) Crrlt)

I, IdILI ,

C QrI' ILA I 1 2. )

4.

(2)Clearing Times (Cycles) Include 1.0 Cycle Margin on Faulted End Clearing Ti

- Stable at 9.25 cycles at bus and 9.5 cycles 10% down the line.

- - Stable at 9.Ocycles at bus.

American Transmission Company Page 51 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C. 7 - G833 and G834 StabilityResults for Point Beach Bus Single Line-to-GroundFaults Clearedin Delayed Time under Intact ConditionsAll Cases with West Switching Station Modeled, Point Beach PSS in-service Event Fault Breaker Failure Existing Existing Kewaunee Substation Proposed Kewaunee Substation

Location Element Tripped Clearing* High Gen Model Low Gen Model High Gen Model Low Gen Model 1 POB Bus 1 POB-SEC 4.75/24.5 none none none none 2 POB Bus 1 POB Bus 1-2 4.75/12.5 none none none none 3 POB Bus 2 POB Bus 2-1 4.75/12.5 none none none none 4 POB Bus 2 POB Bus 2-3 4.75/12.5 none none none none 5 POB Bus 3 POB Bus 3-2 4.75/12.5 none none none none 6 POB Bus 3 POB-KEW 5.0/8.0 none none none none 7 POB Bus 3 POB Bus 3-4 4.75/12.5 none none none none 8 POB Bus 4 POB Bus 4-3 4.75/12.5 none none none none 9 POB Bus 4 POB Bus 4-5 4.75/12.5 none none none none 10 POB Bus 5 POB Bus 5-4 4.75/12.5 none none none none 11 POB Bus 5 POB-FOX 4.75/24.5 none none none none Table C.8 - G833 and G834 Stability Results for 3-Phase Faultsat ProposedWest Switching Station Clearedin Delayed Time under Intact Conditions, Units TrippingListed, PlannedKewaunee Substation Configurationwith Network Upgrades,PSS in-service Event Faulted Breaker Failure Simulated Existing Kewaunee Sub Proposed Kewaunee Sub

Line Element Tripped Clearing* High Gen Model Low Gen Model High Gen Model Low Gen Model 1 Arcadian S. Fond du Lac 3.5/10.5/4.5 none none none none 2 Arcadian Edgewater 3.5/10.5/4.5 none none none none 3 Cypress S. Fond du Lac 3.5/10.5/4.5 none none none none 4 Cypress Edgewater 3.5/10.5/4.5 none none none none 5 Edgewater Arcadian 3.5/10.5/4.5 none none none none 6 Edgewater Cypress 3.5/10.5/4.5 none none none none 7 S. Fond du Lac Arcadian 3.5/10.5/4.5 none none none none 8 S. Fond du Lac Cypress 3.5/10.5/4.5 none none none none American Transmission Company Page 52 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.9 - G833 and G834 GSU Single Line-to-GroundFaults Clearedin Delayed Time under Intact Conditions, Units Tripping, Existing and PlannedKewaunee Substation Configuration with West Switching Station Modeled, Point Beach PSS in-service Event Faulted Breaker Failure Simulated Existing Kewaunee Sub Proposed Kewaunee Sub

Element Element Tripped Clearing* High Gen Model Low Gen Model High Gen Model Low Gen Model 1 POB Unit 1 GSU POB Bus 2 4.5/13.5/14.0 none none none none 2 POB Unit 2 GSU POB Bus 4 4.5/13.5 none none none none

- Primary Clearing Time/Bus Breaker Failure Time/Line Breaker Failure Time (GSU #1 Only)

Simulation Results (i.e. no stability problems) were the same without the West Switching Station Modeled.

Table C.10 - G833 and G834 Auxiliary TransformerHigh Side Single Line-to-GroundFaults Clearedin Delayed Time under Intact Conditions, Units Tripping, Existing and PlannedKewaunee Substation Configurationwith West Switching Station Modeled, Point Beach PSS in-service Event Faulted Breaker Failure New AUX Simulated Existing Kewaunee Sub Proposed Kewaunee Sub

Element Element Tripped HS Breaker? Clearing* High Gen Model Low Gen Model High Gen Model Low Gen Model 1 POB AUX1 HS POB-SEC @ SEC No 5.1/24.5 none none none none 2 POB AUX2 HS POB-FOX @ FOX No 5.1/24.5 none none none none 3 POB AUX1 HS POB Bus 2** No 5.1/13.03 none none none none 4 POB AUX2 HS POB Bus 4*** No 5.1/13.3 none none none none

- The Stability Model Time Step is 0.25 cycles, so a 13.3 cycle fault actually clears in 13.5 cycles.

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

- POB Generator 2 is isolated Simulation Results (i.e. no stability problems) were the same without the West Switching Station Modeled.

American Transmission Company Page 53 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.II - G833 and G834 GSU Three Phase 345 kV Faults Clearedin Primary(5.5 cycles, including 1 cycle margin) Time under N-I Conditions, Units Tripping,Existing and PlannedKewaunee Substation Configurationwith and without West Switching Station Modeled, Point Beach PSS in-service High Gen Low Gen No Fix West SS No Fix West SS Fault PO As Is KEW New KEW As Is KEW New KEW As Is KEW New KEW As Is KEW New KEW FItPBGSU1 None OK OK OK OK OK OK OK OK FItPBGSU1 111 OK OK OK OK OK OK OK OK FItPBGSU1 121 OK OK OK OK OK OK OK OK FItPBGSU1 151 OK OK OK OK OK OK OK OK FItPBGSU1 303 OK OK OK OK OK OK OK OK FItPBGSU1 304 OK OK OK OK OK OK OK OK FItPBGSU1 6832 OK OK OK OK OK OK OK OK FItPBGSU1 971 L71 OK OK OK OK OK OK OK OK FItPBGSU1 SEC31 OK OK OK OK OK OK OK OK FItPBGSU1 CYP31 OK OK OK OK OK OK OK OK FItPBGSU1 T10 OK OK OK OK OK OK OK OK FItPBGSU1 NAPL71 OK OK OK OK OK OK OK OK FItPBGSU1 971L51 OK OK OK OK OK OK OK OK FItPBGSU1 311 OK OK OK OK OK OK OK OK FItPBGSU1 B12 OK OK OK OK OK OK OK OK FItPBGSU1 B23 OK OK OK OK OK OK OK OK FItPBGSU1 B34 OK OK OK OK OK OK OK OK FItPBGSU1 B45 OK OK OK OK OK OK OK OK FItPBGSU2 None OK OK OK OK OK OK OK OK FItPBGSU2 111 OK OK OK OK OK OK OK OK FItPBGSU2 121 OK OK OK OK OK OK OK OK FItPBGSU2 151 OK OK OK OK OK OK OK OK FItPBGSU2 303 OK OK OK OK OK OK OK OK FItPBGSU2 304 OK OK OK OK OK OK OK OK FItPBGSU2 6832 OK OK OK OK OK OK OK OK FItPBGSU2 971 L71 OK OK OK OK OK OK OK OK FItPBGSU2 SEC31 OK OK OK OK OK OK OK OK FItPBGSU2 CYP31 OK OK OK OK OK OK OK OK FItPBGSU2 T10 OK OK OK OK OK OK OK OK FItPBGSU2 NAPL71 OK OK OK OK OK OK OK OK FItPBGSU2 971 L51 OK OK OK OK OK OK OK OK FItPBGSU2 311 OK OK OK OK OK OK OK OK FItPBGSU2 B12 OK OK OK OK OK OK OK OK FItPBGSU2 B23 OK OK OK OK OK OK OK OK FItPBGSU2 B34 OK OK OK OK OK OK OK OK FItPBGSU2 B45 OK OK OK OK OK OK OK OK American Transmission Company Page 54 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C. 12 - G833 and G834 Auxiliary TransformerHigh Side 3-PhaseFaults Clearedin Primary Time (6.1 cycles, including 1 cycle margin) under N-1 Conditions,Existing and PlannedKewaunee Substation Configurationswith and without West Switching Station Modeled, Point Beach PSS in-service (No Aux High Side Breaker (existing condition).

6.1 cycle Clearin High Generation Modeled Low Generation Modeled Fault P0 Existin Kew 2 Fix 1 K2T, Fxl Exisfin Kew 2T Fix 1 K2T, Fxl FItPOBAX1 None OK OK OK OK OK OK OK OK FItPOBAX1 111 OK OK OK OK OK OK OK OK FItPOBAX1 121 FItPOBAX1 151OK FItPOBAX1 303 OK OK OK OK OK OK OK OK FItPOBAXl 304 FItPOBAX1 6832OK FItPOBAX1 971 L7 OK OK OK OK OK OK OK OK FItPOBAX1 SEC31 OK OK OK OK OK OK OK OK FItPOBAX 1 OK OK FItPOBAX1 TOK FItPOBAX1 NAPL71 FItPOBAX1 971 L51 FItPOBAX1 311 OK FItPOBAX1 B12 OK K OK OK OK OK OK OK FItPOBAX1 B23 OK OK OK OK OK OK OK OK FItPOBAX1 B34 OK IOOK I OK OK IOK OK OK FItPOBAX1 B45 FItPOBAX2 None OK OK OK OK OK OK OK OK FItPOBAX2 121 FItPOBAX2 151 FItPOBAX2 303 OK OK OK OK OK OK OK OK FItPOBAX2 304 FItPOBAX2 6832 OK OK OK OK OK OK OK OK FItPOBAX2 971L71 OK OK OK OK OK OK OK OK FItPOBAX2 SEC31 FItPOBAX2 CYP31 OK OK OK OK OK OK OK OK FItPOBAX2 T10 OK OK OK OK OK OK OK OK FItPOBAX2 NAPL71 OK OK OK OK OK OK OK OK FItPOBAX2 971 L51 OK OK OK OK OK OK OK OK FItPOBAX2 311 OK OK OK OK OK OK OK OK FItPOBAX2 B12 FItPOBAX2 B23 OK OK FItPOBAX2 B34 K* OK OK OK OK- OK- OK 0K**

FItPOBAX2 B45 OK OK OK OK OK OK OK OK

SEC Gens Isolated **POB GEN 2 Isolated American Transmission Company Page 55 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table C.13 - G833 and G834 Auxiliary TransformerHigh Side 3-PhaseFaults Clearedin Primary Time (6.1 cycles, including I cycle margin) under N-I Conditions, PlannedKewaunee Substation Configurationswith West Switching Station Modeled, PointBeach PSS not in service (No Aux High Side Breaker, existing condition). CriticalClearingTime Simulations.

Hioh Generation Modeled Low Generation Modeled I

I I5.75 cycles I 5.0 cycles I

Fault PO 1 6.1/6.25 1 6.0 cycles 1 5.5 cvcles S5.75 cycles 5.5 cydes 15.25 cdes FItPOBAXI 121 OK OK OK OK FItPOBAX 151 OK OK OK OK OK FItPOBAX1 30lO OK OK FItPOBAX1 683K OK OK OK FItPOBAX1 NAPL71 OK OK OK FItPOBAX1 971L51 OK OK OK OK FItPOBAX1 B45 OK___ OK OK FItPOBAX2 il K OK OK O FItPOBAX2 121 OK O-* OOK FItPOBAX2 304OK OK. OK OK OK FItPOBAX2 SEC31 OK FItPOBAX2 E12OK OK _OK FItPOBAX2 823 OK OK OK OK OK American Transmission Company Page 56 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix D: Short Circuit / Breaker Duty Analysis Results American Transmission Company Page 57 ofT71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Table D.1 - Maximum and Minimum FaultDuties at the G833-4 Point of Interconnection Maximum Fault Duty Minimum Fault Duty Single-phase Three-Phase Single-phase Three-Phase Without G8433-4 23,023 A 20,820 A 17,795 A 16,075 A With G833*4 and West 24,575 A 21,813 A 19,374 A 17,109 A Switching Station Note: Minimum fault duty was calculatedwith the Q-303 (PointBeach-Kewaunee 345 kV) line out ofservice.

Table D.2 - Thevenin EquivalentImpedances in Ohms correspondingto Maximum FaultDuty Pos Seq. Neg. Seq. Zero Seq.

Without G8433-4 0.4989+j9.5541 Q 0.5744+j9.5596 K 0.5885+j6.7883 f2 Fly/.*,,L/(22 If 11 T1 0.52j.08 .87+607 S Stati o

-wcng'-Stationj Switching 0.4785+j9.1192 Q 0.7572+j9.1083 92 0.4817+j6.0275 92 Table D.3 - Breaker FaultDuty Analysisfor Breakers with >1% Increase in Fault Current Three Phase Fault Analysis SinQle Phase Fault Analysis Derated Symmetrical Change Breaker Derated Symmetrical Change Breaker Breaker . Fault Current in Fault Margin Breaker Fault Current in Fault Margin Rating (amps) Current I (%) Rating (amps) Current I (%)

BUS NAME KV BREAKER (kA) Before I After I (%) I Before I After .(kA) Before I After I (%) I Before I After ARCADIAN_5 138 LINE_9952 53.3 33492 33888 1.2% 31.9 31.0 55 37732 38229 1.3% 37.6 36.8 ARCADIAN_6 138 LINE_9962 53.3 36094, 36494 1.1% 27.2 26.2 55 40226 40730 1.3% 33.5 32.7 ARCADIAN_4 138 LINE 9942 63 36043 36444 1:1% 38.4 37.6 63 40180 40684 1.3% 36.2 35.4 ARCADIAN 4 138 BUS4-5 63 32096 32397 0.9% 47.1 . 46.6 63 35678 36060. 1.1% 25.9 24.9 ARCADIAN_5 138 BUS 5-6 . 63 32171 32473 0.9% 48.5 48.0. 63 35375 35750 .1.1% 43.8 43.3 ARCADIAN2 345 LINELERG71 40 19534 20150 3.2% 51.2 49.6 40 17926 18531 3.4% 55.2 53.7 ARCADIAN3 345 LINE-971L51 40 21634 24023 11ý0% 45.9 39.9 40 19640 21515 9.5% 50.9 46.2 ARCADIAN1 345 LINE_612 40 20300 20907 3.0% 49.2 47.7 40 18229 18833 3.3% 54.4 52.9 ARCADIAN1 345 LINE 9911 40 18056 18915 4.8% 54.9 52.7 40 16330 16978 4.0% 59.2 57.6.

ARCADIAN1 345 BUS 12 40 15977 16794 5.1% 60.1 58.0 40 14315 14965 4.5% 64.2 62.6 ARCADIAN1 345 XFORMER_1 50 23213 23819 2.6% 53.6 52.4 50 20429 21036 3.0% 59.1 57.9 BUTTERNUTB4 138 BUS45 40 6754 6832 1.2% 83.1. 82.9 40 4358 4386 0.6% 89.1 89.0 BUTTERNUT_B5 138 G-BTB52 40 6754 6832 1.2% 83.1 82.9 40 4358 4386 0.6% 89.1 89.0 CEDARSAUK_4 345 BUS L41 50 12304 12459 1.3% 73.8 73.6 50 9406 9429 0.2% 80.2 80.1 CEDARSAUK 345 BUS Li2 50 12304 12459 1.3% 73.8 73.6 50 9439 8915 -5.6% 81.1 80.9 CypressBl 345 BT12 50 8549 14105 65.0% 82.9 71.8 50 6160 10379 68.5% 87.7 79.2 CypressB2 345 BUS 2-3 50 8549 14105 65.0% 82.9 71.8 50 6160 10379 68.5% 87.7 79.2 CypressB1 345 BT16 50 8549 14105 65.0% 82.9 71.8 50 6160 10379 68.5% 87.7 79.2 ForestJctl 138 BSK-12 50. 33501 34446 2.8% 28.3 .26.0 50 37217 38155 2.5% 21.9 20.2 ForestJct_2 '138 BSK-23 50 33501 34446 2.8% 28.3 26.0 50 37217 38155 2.5% 21.9 20.2 ForestJct3 138 BSK-34 50 32813 33761 2.9% 29.7 27.3 50* 36597 37541 2.6% 23.0 21.3 American Transmission Company ,Page 58 0f 71 .12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Three Phase Fault Analysis Single Phase Fault Analysis Derated Symmetrical Change Breaker Table D-3 Continued Derated Symmetrical Change Breaker Breaker Fault Current in Fault Margin Breaker Fault Current inFault Margin Rating (aips) Current NA Ratng (amps) Current Ni BUS NAME KV BREAKER (kA) Before After (%) Before After (kA) Before After (%) Before After ForestJct_10 138 BSK-1011 50 34085 35053 2.8% 27.0 24.6 50 37707 38661 2.5% 20.8 19.2 ForestJct_1 1 138 BSK-1112 50 32683 33656 3.0% . 29.8 27.4 50 36442 37402 2.6% 23.2 21.5 ForestJct_4 138 BSK-45 50 34092 35058 2.8%. 27.2 24.8 50 37722 38677 2.5% 21.0 19.3 ForestJct_5 138 BSK-56 50 34092 35058 2.8% 27.2 24.8 50 37722 38677 2.5% 21.0 19.3 ForestJct_6 138 BSK-67 50 33856 34790 2.8% 27.5 25.1 50 37254 38177 2.5% 21.8 20.1 ForestJct_8 138 BSK-89 50 34128 35092 2.8% 26.9 24.5 50 *37707 38658 2.5% 20.9 19.2 ForestJct_9 138 BSK-910 50 34128 35092 2.8% 26.9 .24.5 50 37707 38661 2.5% 20.8 19.2 ForestJctl 345 BS-L12 50 17188 18859 9.7% 63.0 59.6 50 16287 17662 8.4% 67.4 64.7 ForesUct2 345 BS-L23 (L121) 50 17185 18855 9.7% 63.0 59.6 50 16297 17673 8.4% 67.4 64.7 ForestJct3 345 BS-L45 50 17185 18855 9.7% 63.0 59.6 50 16297 17673 8.4% 67.4 64.7 ForestJct5 345 BS-L56 50 16168 16373 1.3% 65.5 65.3 50 16151 16311 1.0% 67.7 67.4 ForestJct7 345 BS-L71 50 17188 18859 9.7% 65.6 62.3 50 16287 17662 8.4% 67.4 64.7 FOXBus_3 345 BSL-34 . 50 19489 20163 3:5% 61.0 59.7 50 19488 20023 2.7% 61.0 60.0 FOXBus_5 345 BSL-56 50 19335 20009 3.5% 61.3 60.0 50 19141 19675 2.8% 61.7 60.7 FOXBus_1 345 BSL-12 50 19256 19917 3.4% 61.5 60.2 50 18938 19456 2.7% 62.1 61.1 FOXGSUl 311 345 BSL-45 .50 17265 17790 *3.0% 65.5 64.4 50 17230 17642 2.4% 65.5 64.7 FOX GSU2 311 345 BSL-61 50 19315 19988 3.5% 61.3 60.0 50 19121 19654 2.8% 61.8 60.7 FOXBus_2 345 BSL-23 50 19444 20117 3.5% 61.1 59.8 50 19234 19768 2.8% 61.5 60.5 Granville 3 345 LINE 3431 39.5 16549 16788 1.4% 48.5 47.8 39.5 14239 14315 0.5% 49.7 49.4 Granville_2 345 BUS 2-3 40 15013 15209 1.3% 59.3 58.8 40 12911 12959 0.4% 61.1 61.0 Granville_1 345 BUS 1-2 42 12567 12737 1.4% 61.7 61.2 42 11058 11100 0.4% 62.3 62.1 NAP_345B_L1 345 BUS 12-1 40 21493 21722 1.1% 46.3 45.7 40 20088 20235 0.7% 49.8 49.4 NAP_345B_L34 345 BS34-4 40 21493 21722 1.1% 46.3 45.7 40 20088 20235 0.7% 49.8 49.4 NAP_345B_L81 345 BS 81-8 39.8 21493 21722 1.1% 35.2 34.8 39.8 20088 20235 0.7% 38.8 39.0 NAP_3456_L12 345 BUS 12-2 40 21493 21722 1.1% 46.3 45.7 40 20088 20235 0.7% 49.8 49.4 NAP_3456_L1 345 BS 81-1 50 21493 21722 1.1% 57.0 56.6 50 20088 20235 0.7% 59.8 59.5 NAP_345B_L4 345 BS 45-4 50 21493 21722 1.1% 57.0 56.6 . 50 20088 .20235 0.7% 59.8 59.5 NAP_345BL6 345 BS 67-6 50 21493 21722 1.1% 57.0 56.6 50 20088 20235 0.7% 59.8 59.5 NAP_345BL67 345 BS 67-7 50 21493 21722 1.1% 57.0 56.6 50 20088 20235 0.7% 59.8 59.5 NAP_345BL3 345 BS 34-3 38 21493 21722 1.1% 41.9 41.5 40 20088 20235 0.7% 47.8 47.9 NAP_345B8L7 345 BS 78-7 50 21493 21722 1.1% 57.0 56.6 50 20088 20235 0.7% 59.8 59.5 NAP 345BL78 345 BS 78-8 50 21493 21722 1.1% 57.0 56.6 50 20088 20235 0.7% 59.8 59.5 NAP_345BL2 345 BUS 23-2 42 21493 21722 1.1% 38.6 38.2 42 20088 20235 0.7% 42.0 42.1 NAP_345BL23 345 BUS 23-3 42 21493 21722 1.1% 38.6 38.2 42 20088 .20235 0.7% 42.0 42.1 POINTBCHB1 345 BS 1-2 40 18278 19262 5.4% 49.6 49.4 40 20560 22098 7.5% 45.3 44.8 POINTBCH_62 345 BS 2-3 40 13943 14344 2.9% 62.7 63.1 40 14946 15681 4.9% 61.3 60.8 POINTBCHB3 345 BS 3-4 40 16483 17064 3.5% 56.6 56.6 40 17219 .18145 5.4% 56.2 54.6 POINTBCH_64 345 BS 4-5 .40 18746 19652 4.8% 48.5 48.6 40 20815 22279 7.0% 44.2 44.3 POINT_BCH_B1 345 LINE 111 40 18278 19262 5.4% 49.6 49.4 40 20713 22243 7.4% 44.9 44.4 POINTBCHB2 345 LINE 121 40 18729 19499 4.1% 48.5 48.8 40 20886 22218 6.4% 43.9 44.5 POINTBCH_62 345 LINE 123 40 18729 19499 . 4.1% 48.5 48.8 40 20886 22218 6.4% 43.9 44.5 POINTBCH_63 345 LINE Q303 40 16127 17109 6.1% 55.5 55.3 40 17838 19374 8.6% 51.4 51.6 POINTBCH_85 345 LINE 151 40 18843 19750 4.8% 48.2 48.3 40 21008 22464 6.9% 43.7 43.8 American Transmission Company Page 59 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix E: Deliverability Analysis Results Table E.1 - DeliverabilityAnalysis Restrictions G833 and G834 7 Limiting Element Contingency MW Deliverable. Potential Solution None identified. 106 MW (100%) Not applicable.

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

http://www.midwestmarket.org/publish/Document/3e2dO 106c60936d4 -767fta48324a?rev=4 (Navigate to: www.midwestmarket.org > Planning > Generator Interconnection > Generator Deliverability Tests)

AmericanTransmission Company Page 60 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix F: Study Criteria American Transmission Company Page 61 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Study Criteria F. 1 Contingencies For stability analysis, a set of branches in the vicinity of the generator/power 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-I contingencies - all lines and transformers operated at 69kV and above in the following control areas/zones: ATC Planning Zones 1-5 andties 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.2.1 Intact System, N-l, N-2 and Special Multiple Contingency Evaluation Using Linear TransferAnalysis -Methods All load carrying elements operated at 69kV and above in the following control areas/zones 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 62 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 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) > 20%

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 OperatingRestriction Calculation Allowable Output = Equipment Rating - [Line Flow - (Generation Output

TDF)]

TDF F.4 Steady State Under Voltage Criteria F. 4. 1 Intact System, N-] and Special Multiple Contingency Evaluation Using A CCC 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 and/or LTC action.].

F.5 Angular Stability 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 63 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 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 64 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix G: Typical Planning Level Cost Estimates American Transmission Company Page 65 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 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:

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.

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

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

" 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 ROW/easements shown in dollars per mile. No distribution underbuild costs are included.

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

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.

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.

e Transformer costs are shown for typical transformer sizes inreach class, 500 MVA, 345/138 kV, and 345/115 kV; 100 MVA, 138/69 kV and 115/69 kV.-

American Transmission Company Page 66 of 71 12/17/2008

G833A4 Interconnection System Impact Study Report, Revision 3 Typical Transmission Line and Substation Project CapitalCosts TRANSMISSION FACILITY TYPICAL CAPITAL COST UNIT IN 2006 $

New 345 kV single circuit line rural - urban $1,600,000 - $2,200,000/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) $10,000,000/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 - $800,000/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 (w/ terminals) $3,500,000/Mile New 138 kV HPFF 1,200A single circuit UG line (w/ terminals) $3,500,000/Mile New 69 kV single circuit line rural - urban $450,000 - $585,000/Mile New 69 kV double circuit line rural - urban $650,000 - $770,000/Mile New 69 kV XLPE 550A single circuit UG line (w/ terminals) $2,500,000/Mile New 69 kV HPFF single circuit underground line (w/ terminals)- $2,800,000/Mile Rebuild 138 kV to 138 kV single circuit $530,000 $700,000/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 - $670,000/Mile Rebuild 69 kV to 69 kV, single circuit $280,000 - $330,000/Mile Reconductor 138 kV or 115 kV line, single circuit, $210,000/Mile Reconductor 69 kV line, single circuit $117,000/Mile Uprate 138 kV to 138 kV single circuit $125,000 - $200,000/Mile Uprate 69 kV to 138 kV single circuit $350,000 - $375,000/Mile Uprate 69 kV to 69 kV single circuit $125,000 - $150,000/Mile 345 kV substation terminal1 $550,000 each 345kV gas circuit breaker 2 $754,000 each 138kV or 115 kV substation terminal' $450,000 each 138kV gas circuit breaker 2 $390,000 each 69 kV substation terminal' $375,000 each 69kV gas circuit breaker 2 $310,000 each 345/138 kV transformer 4 (transformer only $2,700,0003) $5,000,000 each 138/69 kV transformer6 (transformer only $1,405,0005) $2,500,000 each Notes:

All substation costs are in year 2006 dollars.

includes dead end structure, line switch and line terminal relays 2includes breaker, two maintenance switches, breaker failure relay, controls 3 300/400/500 MVA unit includes high and low side switches and transf. relays 4 includes transformer 3, 2-345kV GCBs 2 and 2-138kV GCBs 2 I100 MVA unit, includes high side and low side switches and transf. relays 6includes transformer5 , 2-138kV GCBs 2, and 1-69kVGCB 2 American Transmission Company Page 67 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 Appendix H: Alternatives Considered American Transmission Company Page 68 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 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 G833 and G834 (G590, G61 1, 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. In addition to these general issues which can be addressed by breaker replacement, protection improvements, and a number of system configurations to strengthen the system, there are three specific issues that need to be addressed to make the Point Beach generation increase acceptable. These issues are (1) the isolation of Point Beach Generator 1 on LIII (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) the outage of 6832 (Fox River-North Appleton) followed by a fault on R-304 (Kewaunee-North Appleton), and (3) the outage of R-304 followed by a fault on Q-303 (Kewaunee-Point Beach) and vice versa.

Issue (1) is addressed in this study by reducing Point Beach Unit #1 net generation to 550 MW.

It could also have been addressed by strengthening L111. It could also be addressed changing the connectivity at the Point Beach bus so that Unit 1 could not be isolated on LI II or by strengthening Li II by creating a 345 kV switching station at the intersection of lines LSEC31 (Sheboygan Energy - Granville), W-1 (Edgewater - South Fond Du Lac) and 796L41 (Edgewater

- Cedarsauk). Issue (2) is a problem because the two strongest connections to the rest of the system are taken out of service at the same time. This problem can not be solved by changing system connectivity near Point Beach, it must be addressed by either strengthening the remaining connections to the rest of the system, as is done by the proposed 345 kV switching station at the intersection of L-CYP31 (Cypress - Arcadian) and W-1, or adding a new connection. Issue (3) is a local issue at Kewaunee that is-not made worse by the addition of G833 and G834, which can be addressed by reducing Kewaunee net generation. If a second transformer is not added at Kewaunee, Kewaunee generation is reduced below the stability limit to protect the Kewaunee 345/138 kV transformer. If a second transformer is added at Kewaunee, Kewaunee generation must be reduced to 500 MW with Q-303 out or 475 MW with R-304 out, although Many of the alternatives considered to address these issues are shown in Figure H. 1. Because these alternatives were not fully investigated, the substation configurations have not been optimized. A short description of several of the various alternatives considered and the advantages and disadvantages of each are discussed below in no particular order.

Create an East Switching Station by Connecting 345 kV Lines LSEC31, W-1, and 796L41.

This switching station, could address the Point Beach connectivity issues related to Point Beach Generator I being isolated on L III when POB breaker 2-3 is out of service and there is a fault on L 121: There is approximately 1 mile between. these lines. An alternative to this switching station is to reduce Point Beach #1 gross generation to 550 MW when POB breaker 2-3 is out of American Transmission Company Page 69 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 service. Coordinating breaker and generator outages would minimize the need to implement this generation restriction, making the time and expense necessary to build the proposed switching station unnecessary.

Forest Junction to West Switching Station 345 kV Line (Approximately 42 miles). One of the first alternatives evaluated was an approximately 42 mile 345 kV line from Forest Junction to the West Switching Station. This alternative, with some reductions in fault clearing time, addressed system strength issues, but did not address the Point Beach connectivity issues related to Point Beach Generator 1 being isolated on L III under certain system conditions. Essentially, this is the same improvement achieved with the West Switching Station alone.

A Second Point Beach to Kewaunee 345 kV Line (Approximately 6 miles). Although eliminating the local Kewaunee stability issue (the loss of both Kewaunee 345 kV lines) is not required for G833 and G834 because they do not make the existing issues (which are addressed by an operating guide) worse, the addition of a second Point Beach-Kewaunee 345 kV line was investigated to see if it addressed any other issues. When connected to Point Beach Bus 4, as shown in Figure H. 1, the line does not improve the Unit 1/L III issue. If the line was added in connection with a Point Beach 345 kV bus reconfiguration it could possibly do so, but that was not investigated. Although the line did address the local Kewaunee generation issue, because it does not strengthen area outlets, it did not improvethe outlet issues and in fact made at least one event (SEC31 out fault R-304) worse, it was not considered an acceptable alternative.

Forest Junction to North Switching Station 345 kV Line (Approximately 13 miles). A North Switching Station Connecting LIII and L121 when they are about a mile apart approximately 18 miles west of Point Beach solves all of the issues concerning Point Beach Unit I isolated on L11i, except for when the western part of L121 is out of service and there is a fault on Q-303 with an SPS operation splitting the Point Beach bus. To handle this situation, an approximately 13 mile line from Forest Junction to the North Switching Station could be built on existing 345.

kV towers that are presently being used by a 138 kV line. A 345/138 kV transformer would probably be necessary. at the North Switching station to support the existing 138 kV line.

Because these projects do not strengthen area outlets, however, they do not eliminate the 6832/R-304 prior outage/fault issue. This alternative, coupled with the West Switching Station may solve these problems, but because the economics of this alternative, it was not fully evaluated.

Forest Junction to East Switching Station 345 kV Line (Approximately 55 miles). Although not shown in Figure H.1, a 345 kV line from Forest Junction to the East Switching Station was considered. This line would address the system strength and Point Beach Unit 1/L III isolation issue, but these issues could be addressed by the East Switching Station without the line. If the North Switching Station were also built and this line tied into it, all of the issues addressed by the East and West Switching Station solution might be addressed, but the additional cost of 55 miles of 345 kV line, is not justified.

In summary, several alternatives to the Conceptual East and West Switching Station project were evaluated. The projects that addressed all of the issues presented included at least 13 miles of 345 kV line, which would most make the alternatives more expensive and more difficult to implement.

American Transmission Company Page 70 of 71 12/17/2008

G833-4 Interconnection System Impact Study Report, Revision 3 NORTH KEWAUNEE T10 APPLETON 313-S To Columbia Potential Fixes Existing (solid line)

Potential Fix (green)

- Future (dotted line)

To Arcadian Figure H. 1 - Alternative System Enhancements Considered (Kewaunee Reconfigured)

American Transmission Company Page 71 of 71 12/17/2008

NRC 2009-0044, American Transmission Company - Interconnection System Impact Study Report, 106 MW Nuclear Generation Increase (53 MW Each at Point Beach Generators 1 and 2), Revision 3

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NRC 2009-0044, American Transmission Company - Interconnection System Impact Study Report, 106 MW Nuclear Generation Increase (53 MW Each at Point Beach Generators 1 and 2), Revision 3

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