NRC 2009-0082, Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study, Appendixes B - J

Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study, Appendixes B - J

ML092400528
Person / Time
Site:	Point Beach
Issue date:	07/14/2009
From:	Point Beach
To:	Office of Nuclear Reactor Regulation
Shared Package
ML092400540	List: ML092400526 NRC 2009-0082, Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study, Appendixes B - J NRC 2009-0082, Point Beach, Units 1 and 2 - Transmittal of Background Information to Support License Amendment Request 261, ATC Lnterim Operation and Impacts Re-Study
References
NRC 2009-0082 G833/G834-J022/J023, Rev 1
Download: ML092400528 (54)

Text

G83314-J022/J023 Interim Operation and Impacts Re-Study Report-ROl Appendix B: Stability Analysis Results American Transmission Company Page 49 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Nomenclature K or KEW:

P or POB:

S or SEC:

F or FOX:

NAP:

GVL:

CYP:

ADN:

FJT TH:

L111:

L121:

Q303:

L151:

R304:

NAPL71:

CYP31:

6832:

TIO:

SEC3I:

H:

KWH:

KWL:

POBxy:

Y311 CCT:

Kewaunee Point Beach (PI and P2)

Sheboygan Energy Center Fox Energy North Appleton Granville Cypress Arcadian Forest Junction Thilmany Point Beach-Sheboygan Energy Center 345 kV line Point Beach-Forest Junction 345 kV line Point Beach-Kewaunee 345 kV line Point Beach-Fox Energy 345 kV line Kewaunee-North Appleton 345 kV line North Appleton-Werner West 345 kV line CypressArcadian 345 kV line North Appleton-Fox Energy Center 345 kV line Kewaunee TI0 3451138 kV transformer Sheboygan Energy Center-Granville 345 kV line High side KewauneeT10 High side Kewaunee TI0 Low side Point Beach bus tie xy Nora Appleton-Fitzgerald 345 kV line Critical Clearing Time Note: The simulated clearing times and critical clearing times (CCT) noted in Appendix B contains planning margin described in Section 3.2 American Transmission Company Page 50 of 102

G83314-Jo22tJo23 Interim Ope I ation and Impacts Re-study Report-Ro1 Tab1 B.1-Stability Results for Faults Clearing in Primary Time under Intact System Conditions I

Tntorim 7 /with G8?4/11073 with ~ r i. r t i n ~

Kcrwnlinc!~?

.ruh.rtntinn)

Intact System Fault Cleared in Primary Time - Interim Period 1 (May 2010-April 2011)

I Faulted End Breakers 111 121,123 151 Q-303 Q-303,1099,2450 R-304,3451 2-3,34 1-2,6-1 4-5,5-6 1-2,16 1-2,3-6 1-2,5-6 Q-303,1099,3450 Remote Location SEC FJT FOX KEW PO0 NAP POB NAP FJT POB GVL ADN KWL Remote End Event I Simulated I

I I

I Breakers Notes Clearing* I High 1-2.16 NO SPS 4.514.5 1-2,23 4.514.5 2-3.3-1 NO SPS 4.514.5 Q-303,1099,2450 KEW SPS In 4.516.5 Q-303 KEW SPS In 6.514.5 R-304 6.516.5 Generation I Low Generation I 151 4.514.5 1

243,344,45467-6 4.514.5 5-6,7-1 4.514.5 Ill 4.514.5 L-SEC31 4.516.5 L-CYP31 4.514.5 American Transmission compbY Page 51 of 102

G83314-J022lJO23 Interim ~Aeration and Impacts Re-Study Report-RO1 Intact System Fault Cleared in Primary Time - Interim Period 2A ( ~ i r i l 2 0 1 1 and beyond, with existing Kewaunee)

I 1

Interim 2A (with G834/J023 and G833/J022. with existing Kewau tee substation)

Simulated I iigh Generation 1

Interim 2B (with G834/J023 and G833/J022, with new Kewmrnee substation)

Element Fault Faulted End Remote Remote End Event Simulated File Faulted Location FltPOBSEC L111 POB 111 SEC 1-2,16 NO SPS 4.514.5 FltPOBFJT L121 POB 121,123 FJT 1-2,2-3 FltPOBFOX L151 POB 151 FOX 2-3,3-4 NO SPS 4.514.5 No FltPOBKEW Q-303 POB 4303 KEW Q-303 New 1 and 2 SPSs 4.514.5 No American Transmission ~ o m $ a n ~

Page 52 of 102 07/14/2009

G833/4-J022/JO23 Interim 0~4ration and Impacts Re-Study Report-RO1 Table B.2-Stabilify Results for Double Circuit Single Line-to-Ground Faults Cleared in Primary Time under Intact System Conditions Interim 1 (with G834/J023, with existing Kewaunee substation) 1 I

I I

I I

I I

File Event I

Fiyk Fault # I Acceptable Fault

1. 2 Fault R Location American Transmission comP/any Simulated Clearing time DC3-111-971K51-I DC3-Ill-971K51-2 DC3-111-HOLG21-1 DC3-111-HOLG21-2 DC3-121-971K51-1 DC3-121-971K51-2 DC3-SEC31-3431-1 DC3-SEC31-3431-2 DC3SEC31-8231-1 DC3-SEC31-8231-2 DC3-9932-2642-1 DC~-9932-2642-2 DC3-9932-2661-1 DC3-9932-2661-2 DC3-9932-9911-1 DC3-9932-9911-2 Page 53 of 102 Interim Pel (May 2010-Apr 201 1) mm L1 l1 L1ll L l 1 I L l l l L121.R.

L121.R L-SE(31-L-

L-L-

L-BeachSheboygan 345 kV

-Point 345 kV

- Point BeachSheboygan 345 kV

-Point Beach-Sheboygan 345 kV Beach-Forest Junction 345 kV Beach-Forest Junction 345kV Sheboygan-Granville 345 kV L-SEC31-Sheb0ygan-Granvi11e 345 kV LSEC31Sheb0ygan-Granvi'le 345 kV L-SE231Sheb0~!3an-Granville 345 kV CYP3l-Cypress-Arcadian 345 kV CYP31 -

345 kV CyP31 -

345 kV CyP31 - Cypress-Arcadian 345 kV CyP31 - Cypress-Arcadian 345 kV CyP31-Cypress-Arcadian 345 kV 38.5% frorn POB 16.3% from SEC SEC

',5.70m from SEC FJT 42.3% from FJT GVL 26.7% from GVL 43.5% from GVL 48.3% frorn GVL 32.00/0 from ADN 16.6% from ADN 10.8% from ADN 16.6% from ADN 10.8% from ADN ADN 5.515.5 5.515.5 5.515,5 5.515.5 5.515.5 5.515.5 7.517.5 7.517.5 7.517.5 7.517.5 5.515.5 5.515.5 5.55.5 5.515.5 5.515.5 5.515.5 971 K51 - Forest Junction-Howard's Grove 138 kV 971K51 -Forest Junction-Howard's Grove 138 kV HOGL21 -Howard's Grove-Holland 138 kV HOGL21-Howard's GroveHolland 138 kV Grove 138 kV 971 K51-Forest Junction-Howard's 971K51-Forest Junction-Howard's Grove 138 kV 3431 - Granville-Saukville 345 kV 3431 - Granville-Saukville 345 kV 8231 - Saukville-Barton 138 kV 8231 - Saukville-Barton 138 kV 2642 - Saukville-Gemantown 138 kV 2642 - Saukville-Gemantown 138 kV 2661 - Germantown-Bark River 138 kV 2661 - Germantown-Bark River 138 kV 991 1 - Granville-Arcadian 345 kV 991 1 - Granville-Arcadian 345 kV 33.g9/0 from NT 6.3% from HOG 76.9% from HOL 314X from HOG FJT 33.9% from FJT GVL 25.3% from SAU 36.4% from BRT 36.4% from SAU 34.2% from SAU GER 31.5% from GER GER 45.4% from GVL ADN 6.516.5 6.516.5 6.516.5 6.516.5 6.516.5 6.516.5 7.517.5 7.517.5 7.517.5 7.517.5 7.517.5 7.517.5 8.518.5 8.518.5 7.517.5 7.517.5

G83314-J022lJ023 Interim opetiation and Impacts Re-Study Report-RO1 Event File American Transmission comPby Dm-111-971 K51-I DC3-111-971K51-2 DC3-111-HOLG21-1 DC3-111-HOLG21-2 DC3-121-971 K51-1 DC3-121-971K51-2 DCSEC31-3431-1 DC3SEC31-3431-2 DC3-SEC31-8231-1 DC3SEC31-8231-2 DC3-9932-2642-1 DC3-9932-2642-2 DC3-9932-2661-1 DC3-9932-2661-2 DC3-9932-9911-1 DC3-9932-9911-2 Page 54 of 102 Interim 2A (with G834/J023 and G833/J022, with existing Kewaunee substation)

Fault

1. 1 L111 -

L l l I L l l l -

L l l l -

L121-fk L121-%.

L-SECSl L-L-

L-L-

L-L-

Point BeachSheboygan 345 kV Point BeachSheboygan 345 kV Point Beach-Sheboygan 345 kV Point BeachSheboygan 345 kV Beach-Forest Junction 345 kV Beach-Forest Jundon 345 kV

- Sheboygan-Granville 345 kV LSEI.>31Sheboygan-Granville 345 kV LSEC>31Sheboygan-Granville 345 kV L-SEC>31-Sheboygan-Granville 345 kV C\\rbP31 - Cypress-Arcadian 345 kV CYf"fJ1-Cypress-Arcadian 345 kV CtkP31 - Cypress-Arcadian 345 kV C"P31-Cypress4wdian 345 kV C"P31 - Cypress-Arcadian 345 kV Cbp31 - Cypress-Arcadian 345 kV Fauit#2 Location Fault #1 Location 38.5% from POB 16.3% from SEC SEC 15.7% from SEC FJT 42.3% from FJT GVL 26.7% from GVL 43.5% from GVL 48.3% from GVL 32.0% from ADN 16.6% from ADN 10.8% from ADN 16.6% from ADN 10.8% from ADN ADN Acceptable CCT" Fault

1. 2 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 7.5R.5 7.517.5 7.517.5 7.5R.5 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 971K51-Forest Junction-Howard's Grove 138 kV 971K51-Forest Junction-Howard's Gmve 138 kV HOGL21-Howard's GroveHolland 138 kV HOGL21 - Howard's Grove-Holland 138 kV 971K51-Forest Junction-Howard's Grove 138 kV 97101 - Forest Junction-Howard's Grove 138 kV 3431 - Granvile-Saukville 345 kV 3431 - GranvilleSaukville 345 kV 8231 - Saukville-Barton 138 kV 8231 - Saukville-Barton 138 kV 2642 - Saukville-Germantown 138 kV 2642 - Saukville-Germantown 138 kV 2661 - Germantown-Bark River 138 kV 2661 - Germantown-Bark River 138 kV 9911 - Granville-Arcadian 345 kV 991 1 - Granville-Arcadian 345 kV 33.9% from FJT 6.3% from HOG 76.9% from HOL 31.4% from HOG FJT 33.9% from FJT GVL 25.3X from SAU 36.4% from BRT 36.4% from SAU 34,2% from SAU GER 31.5% from GER GER 45.40/0 from GVL ADN 6.516.5 6.516.5 OK OK 6.516.5 6.516.5 6.516.5 6.516.5 7.517.5 7.517.5 7.517.5 7.517.5 7.5175 7.517.5 8.518.5 8.518.5 7.517.5 I

I 7.5R.5

G83314-J022lJO23 ~nterim operation and Impacts Re-Study Report-RO1 Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation)

I I

I I

I I

I I

I Event 1

Fault Fault #I Fault Fault #2 File

1. I I

Location

1. 2 I

Location Interim Period 2B (May 2011 -), WI new Ke American Transmission c~mPany Page 55 of 102 DC3-111-971 K51-1 DC3-111-971 K51-2 DC3-111-HOLG21-1 DC3-111MOLG21-2 DC3-121-971 K51-1 DC3-121-971 K51-2 DC3SEC31-3431-1 DC3SEC31-3431-2 DC3SEC31-8231-1 DC3SEC31-8231-2 DC3-9932-2642-1 DC3-9932-2642-2 DC3-9932-2661-1 DC3-9932-2661-2 DC3-9932-99111 DC3-9932-9911-2 L111-L111..

L l I I

-1 L l I 1.

L121-~3.

L121-3.

LSEC31-L-

L-L-

L-L-

L-Point BeachSheboygan 345 kV Point BeachSheboygan 345 kV Point BeachSheboygan 345 kV Point BeachSheboygan 345 kV Beach-Forest Junction 345 kV Beach-Forest Junction 345 kV Sheboygan-Granville 345 kV L-SEC31-Sheboygan-Granville 345 kV L-SEC31Sheboygan-Granville 345 kV LSEC31Sheboygan-Granville 345 kV C"P31-Cypress-Arcadian 345kV C'P31-Cypress-Arcadian 345 kV C\\?31-Cypress-Arcadian 345 kv C\\?31 - Cypress-Arcadian 345 kV C\\'P31 - Cypress-Arcadian 345 kV C'931-Cypress-Arcadian 345 kV 38.5% from POB 16.3% from SEC SEC 15.7% from SEC FJT 42.3% from FJT GVL 26.7% from GVL 43.5% from GVL 48.3% from GVL 32.0% from ADN 16.6% from ADN 10.8% from ADN 16.6% from ADN 10.8% from ADN ADN 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 7.5R.5 7.5R.5 7.5R.5 7.517.5 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 5.515.5 971K51 -Forest Junction-Howard's Grove 138 kV 971K51-Forest Junction-Howard's Grove 138 kV HOGL21 -Howard's GroveHolland 138 kV HOGL21-Howard's Gmve-Holland 138 kV 971K51-Forest Junction-Howard's Grove 138 kV 971K51-Forest Junction-Howard's Grove 138 kV 3431 - GranvilleSaukville 345 kV 3431 - GranvilleSaukville 345 kV 8231 - Saukhile-Barton 138 kV 8231 - Saukville-Barton 138 kV 2642 - Saukville-Germantown 138 kV 2642 - Saukville-Germantown 138 kV 2661 - Germantown-Bark River 138 kV 2661 - Germantown-Bark River 138 kV 991 1 - Granville-Arcadian 345 kV 991 1 - Granville-Arcadian 345 kV High Gen I Low Gen I 33.9% from FJT 6.516.5 6.3% from HOG 6.516.5 1

76.9% from HOL 6.516.5 31.4% from HOG 6.516.5 I

FJT 6.516.5 I

33.9% from FJT 6.516.5 GVL 7.5R.5 25,3% from SAU 7.5R.5 36.4% from BRT 7.517.5 36.4% from SAU 7.5R.5 34.2K from SAU 7.5R.5 GER 7.5R.5 31.5% from GER 8.518.5 GER 8.518.5 45.4% from GVL 7.5R.5 ADN 7.517.5

G83314-J022/JO23 Interim Table B.3-Stl Note: Among various Event Elemen Faulted I

FltKEWNAP I R-304

• • • Stable at 5.514.5 with G1 res Event Element Faulted

• • Stable at 5.514.5 -replace R-!

Event Element

• For stability, G1 needs to be re

• • For stability, Gl needs to be I American Transmission C Operation and Impacts Re-Study Report-RO1 lbility Results for 3-Phase Faults Cleared in Primary Time under Prior Outage Condition Units Trpping contingencies evaluated, only faults with stability issues are listed in Table B.3.

Interim 1 (with G834/J023, with existing Kewaunee substation)

Primary Clearing Time, Prior Outage: 6832 (FOX-NAP, 38894-39556), (POB PSSs In Service) Existing KEW Sub Fault Faulted End Remote Remote End Event Simulated High Generation I Low Generation Location Breakers Location Breakers Notes Clearing*

I Primary Clearing Time, Prior Outage: SEC31 (SEC-GVL, 3986538870), (POB PSSs In Service) Existing KEW Sub Fault Faulted End Remote Remote End Event Simulated High Generation Low Generation Location Breakers Location Breakers Notes KEW R-304.3451 NAP R-304 6.516.5 04 breaker at NAP. 4.5 is MECT for R304 fault at KEW. Existing clearing time at faulted end is 4.5 cycles without margill Primary Clearing Time, Prior Outage: PO0 2-3 (POB-B23,3889&39211), (PO0 PSSs In Service) Existing KEW Sub Fault Faulted End Remote Remote End Event Simulated High Generation Low Generation acation Breakers Location Breakers rtricted to 580 MW gross estricted to 620 MW gross Page 56 of 102

G83314-J022lJO23 Inte ' Operation and Impacts Re-Study Report-RO1 Interim 2A (with G834/J023 and G833/J022, with existing Kewaunee substation)

Primary Clearing Time, Prior Outage: L l l l (POB-SEC, 39433-39865), 'POB PSSs In Sewice) Existing KEW Sub Event Element Fault Faulted End Remote Remote End Event Simulated High Generation Low Generation Fle Faulted Location Breakers Location Breakers Notes Clearing' Base Base FIWWNAP R-304 KEW R-304,3451 NAP R-304 6.516.5

"* Stable at 5.514.5, Replace R-304 breaker at North Appleton. Note: MECT of R304 at Kew is 4.5 Primary Clearing Time, Prior Outage: L121 (POB-FJT, 38898-39304), (POB PSSs In Service) Existing KEW Sub Event Element Fault Faulted End Remote Remote End Event Simulated High Generation Low Generation File Faulted Location Breakers Location Breakers Notes Clearing*

Base Base I FltKEWNAP I R-304 I KEW I

R-304,3451 I

NAP I R-304 I

1 6.516.5 A Stable at 5.014.5 or Stable at 5.514 5 with G2 reduced to 620 MW-replace R304 breaker at NAP. Existing clearing time at faulted end is 4.5 cycle^ cy out margin Primary Clearing Time, Prior Outage: L151 (POB-FJT, 38898-39304), (POB PSSs In Sewice) Existing KEW Sub Event Element Fault Faulted End Remote Remote End Event Simulated High Generation I Low Generation I

File Faulted Location Breakers Location Breakers Note: Without G2 reduction, Vsag uAl trip P with 5.514.5 (PI 1.513sfor 19KV, P2 1.521sfor I9KV, BIB5 1st 1.083s, BIB5 2nd 1.575s). Thus, if time delay can be readjusted to avoid violation, only thing to be done is replacing R-304 breaker at NAP Primary Clearing Time, Prior Outage: R-304 (KEW-NAP, 39630-39359), (POB PSSs In Sewice) Existing KEW Sub Event 1 Element 1 Fault 1

Faulted End Remote Remote End Event I Simulated I High Generation I Low Generation I

I File I Faulted I lrocation I Breakers

( ~ocation I Breakers Notes I Clearing* I FltFOXNAP 1

L6832 1 FOX I 1-2,6-1 1

NAP 1

34-3,344,454.67-6 1

1 4.5145

• Stable at 4.014.5 OR Stable at 4.5'4.5 with G2 reduced to 600 MW gmss. At 4.514.5 with G2 at 620 MW, 345 kV 2nd criteria is violated: 81: 1.583s and 82: 1.583s.

Primary Clearing Time, Prior Outage: 6832 (FOX-NAP, 38894-39556), (POB PSSs In Sewice) Existing KEW Sub Event Element Fault Faulted End Remote Remote End Event Simulated High Generation Low Generation File Faulted Location Breakers Location Breakers Notes Clearing*

Base Base American Transmission Gmpany FIKEWNAP I R-304 1 KEW 1

R-304,3451 I NAP I

R-304

(

6.516.5 FLTKEWXFH2ROl I TI0 I KWH 1 Q-303,1099,3450 1

KWL I 1066E, 1066W I Open Q-303 at KEW 1

6.518.5 Page 57 of 102

"*Stable at 6.018.5 with G2 reduced Stable at 5.514.5 with G2 at 580 to 580 MW gmss. 5.0 cyde is the existing dearing time at the high side of TI0 transformer.

MW (replace R-304 breaker at NAP and reduce G2 to 580 MW gross). Existing clearing time at faulted end is 4.5 cycles without margin AM Stable at 5.514.5 with both GI a11d 62 at 540 MW (replace R-304 breaker at NAP and reduce both GI and G2 to 540 MW). Existing clearing time at faulted end is 4.5 cycles without margin

G83314-J022/J023 ~nterim erati ti on and Impacts Re-Study Report-RO1 Event File FltKEWNAP FLTKEWXFHPROI I TI0 A Stable at 6.018.5 with G2 at 620 (02 Stable at 5.518.5 or Stable at 6.018.5

• Stable at 5.514.5 with G2 580 MW Primary Clearing Time, Prior Outage: SEC31 (SEGGVL, 398638870), (POB PSSs In Service) Existing KEW Sub Element Faulted R-304 KWH 1 Q-303,1099,3450 1

KWL I 1066E, 1066W I

Open Q-303 at KEW 1

6.518.5 reduction to 620 gross). 5.0 cycle without margin is the existing clearing time at the high side of TI0 transformer.

with G2 at 580 MW (62 reduction to 580 gross). 5.0 cycle without margin is the existing clearing time at the high side of TI0 transformer.

- Replace R-304 breaker at NAP and 62 at 580 MW gross. Existing clearing time at faulted end is 4.5 cycles without margin 1

Stable at 5.514.5 with G2 at 620 f#W gross. Existing clearing time at faulted end is 4.5 cycles without margin American Transmission chmPany Event Simulated High Generation Low Generation Notes Clearine Base Base 6.516.5 Event File FIWWNAP I

Page 58 of 102 Remote End Breakers R-304 Primary Clearing Time, Prior Outage: POB 1-2 (POB-Bl2,39433-38898), (POB PSSs In Service) Existing KEW Sub Element Faulted R-304 Primary Clearing Time, Prior Outage: POB 2-3 (POB-B23,38898-39211), (POB PSSs In Service) Existing KEW Sub Event File Remote Location NAP Fault Location KEW Fault Lpcation KEW

"'Stable at 5.514.5. Replace R-304 Element Faulted Event A e FltKEWNAP Faulted End Breakers R-304,3451 Event Simulated High Generation I Low Generation Notes Clearing' Rscn Rscn 4.514.5 Primary Clearing Time, Prior Outage: POB 4-5 (POB-B45,38900-38901), (POB PSSs In Senrice) Existing KEW Sub Element Faulted R-304

~reaker at NAP. Existing clearing time at faulted end is 4.5 cycles without margin

• For stabili, GI needs to be resbi ed to 580 MW gmss Remote End Breakers 1-2,2-3 Pault Loption Fault Lpcation KEW

"'Stable at 5.514.5 with G2 at 620 k Event Simulated High Generation I Low Generation Notes Clearing* -

I Base Faulted End Breakers R-304,3451 FltPOBFJT YOB Faulted End Breakers L121 JV (replace R-304 breaker at NAP and reduce G2 to 620 MW). Existing clearing time at faulted end is 4.5 cycles without margin Remote Location NAP Remote Location Event Simulated High Generation Low Generation Notes Clearing*

Base Base 6.516.5 Remote End Breakers R-304 121,123 Remote End Breakers R-304 Faulted End Breakers R304,3451 FJT Remote Location NAP

G83314-502215023 Interim Event Element I FltKEWNAP I R-304 1

' Stable at 4.514.5 with G2 restricted Event Element File Faulted To be stable at 4.514.5, GI needs 1 "To be stable at 4.514.5, GI needs American Transmission C Operation and Impacts Re-Study Report-RO1 Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation)

Primary Clearing Time, Prior Outage: 6832 (FOX-NAP, 38894-39556), (POB PSSs In Service) New KEW Sub Page 59 of 102 Low Generation Base Primary Clearing Time, Prior Outage: POB 2-3 (POBB23,38898-39211!,

High Generation Base J be restricted to 580 MW gmss to be restricted to 620 MW gross (POB PSSs In Sewice) New KEW Sub Simulated Clearing*

Event Notes Remote End Breakers 1-2,23 4.516.5 Event Notes Simulated High Generation Low Generation Clearing*

Base Base 4.514.5 Remote Location FJT Fault acation POB to 600 MW gmss (G2 restriction 600 MW gross with R-304 breaker at NAP replaced)

R-304 Remote End Breakers Faulted End Breakers 121,123 NAP Remote Location KEW Fault

)cation R-304,3451 Faulted End Breakers

G83314-J022tJ023 Interim Operation d d Impacts Re-Study Report-RO1 Table B. - Stability Results for 3-Phase Faults Cleared in Delayed (Breaker Failure) Time under Intact Conditions, Units Tripping 1

Interim I (with G834/J023, with existing Kewaunee substation) re Events - lnter~m Per~od 1 (May 2010-Aprll 2011)

I American Transmission Company 1

Page 60 of 102

Page 61 of 102

G833/4-JO22/JO23 Interim Operation Impacts Re-Study Report-RO1 Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation)

I Event I

Element I

I File 1

Faulted I I BFIFOXPOBZ I

L151 I FOX BFIFOXNAR 1

L6832 1

FOX 1

BFIFOWJT;!

1 971171 1

FOX BFlSECPOBl I

L l l l I SEC BFISECGVLl I

LSEC31 I SEC BFICYPADN I

LGYP~I I cn BFICYPFJT 1

971L51 1

CYI I

I

'Relay upgrades or lnstalllng a series breaker desa

" Relav uoarades described in Section 1.1 wlll addn ad el; ibrades described in Section 1.I will add, American Transmission Company Event I

Simulated I

High Gen I

LOW tien I

I 1

!din Section 1.1 will address the issue.

the issue she issue Page 62 of 102

G833/4-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 Table B.5-Stability Results for Point Beach Bus Single Line-to-Ground Faults Cleared in Delayed Time under Intact Conditions Kewaunee substation)

Fault Location Element Clearing 1

I I

i-Interim 1 tripped POB Bus 1 POBSEC 4.75124.5 POB BUS 1 POB Bus 1-2 4,75112.5 2A wl E x ~ s t ~ n a KEW Fault Failure Simulated Location Element Clearing

(

tripped 1

POB Bus I I

POBSEC 1 4.75124.5 POB Bus 1 I POB Bus 1-2 1 4.75112.5 POB Bus 2 I POB Bus 2-1 1 4,75112.5 POB Bus 2 I POB Bus 2-3 1 4.75112.5 POB Bus 3 I POB Bus 3-2 ( 4.75112.5 POB Bus 3

(

POB-KEW 1 4,75124.5 POB Bus 3 POB Bus 4 POB Bus 5 I POB BUs5-4 ( 4.751128 POB Bus 5 I

POB-FOX 1 4. 7 ~ ~ 5

• • Stable at 4,75112.0. As described in Section 1.1, Change Relay senlug (w~mnout areaKer ral~ure relay lcpraccucur, LUL rarrruo ur I oint Beach Bus Tie 2-3 to no more than 11 cycle total breaker failure clearing time for bus faults American Transmission Company Page 63 of 102

G83314-502215023 Interim Operation and Impacts Re-Study Report-RO1 Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation) 1

~ o G i o n I Elementhipped I Clearing 1

Ul-h pal I -.., can IOB Bus 1 I

PoB-sEc 1

4.75124.5 1

POB Bus 1 POB Bus 2 I

POB Bus2-1 I

~ 7 5 1 1 3 5

POB Bus 2 POB Bus 2-3 4.75112.5 POB Bus 3 POB Bus 3-2 4.75112.5 POB Bus 3 POB-KEW 4.75112.5 POB Bus 3 I

POB Bus 3-4 1

4.75112.5 POB Bus 4 I

POB Bus 4-3 1

4.75112.5 POB Bus 4 I

POB BUS 4-5 1

4.75112.5 POB Bus 5 POB Bus 5 American Transmission Company Page 64 of 102

G83314-J022/5023 Interim Operation and Impacts Re-Study Report-RO1 Table B.6-Stability Results for GSU Single Line-to-Ground Faults Cleared in Delayed Time under Intact Conditions, Units Tripping Interim 1 (with G834/J023, with existing Kewaunee substation)

Breaker Fault 1

Failure I Simulated 1

Location Element Clearing POB GSU BF Faults Interim 2A (with G834/J023 and G833/J022, POB GSU BF Faults w'

Breaker Fault I

Failure I Simulated Location Element Clearing Interim 2B (with G834/J023 and G833/JO POB GSU BF Faults Breaker Fault 1

Failure 1

Simulated 1 Location Element Clearing American Transmission Company Page 65 of 102

G833/4-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table B. 7-Stability Results for Auxiliary Transformer High Side Single Line-to-Ground Faults Cleared in Delayed Time under Intact Conditions, Units Tripping Interim I 1 (with G834/J023, I

with existing I

Kewaunee substation)

I POB AUXl HS POB-SEC @

SFC Interim 1 I

Faulted Element Element Tripped Faulted Element Failure POB AUXl HS I

POB Bus2" POB AUX2 HS I POB Bus4"'

I

-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 Tri~s. POB Generator 1 is Isolated.

"* - POB ene era to; 2 'is isolated taulreo Element Interim 2A (with G834/J023 and G833/J02 I

Failure Breaker POB AUXl HS POB AUX2 HS Faulted Breaker Element Failure POB-SEC @

Faulted Element I

POB AUX2 HS POB-FOX @

FOX Breaker Failure Element Tripped

- A 'a- -&

Faulted Breaker Element Failure Element Tripped 5.1113.3' 5.1113.3' m

m s

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

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

"** - POB Generator 2 is isolated American Transmission Company Page 66 of 102 POB AUXl HS I

POBBus2" I

OK I

POB AUX2 HS I POB Bus4"'

1 OK I

OK

• -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 Interim 2B (with G834/J023 and G833/J02L" "'

ee substation)

G83314-J022lJ023 ~nterimlo~eration and Impacts Re-Study Report-RO1 Table B.8-Stability R for GSU Three Phase 345 kVFaults Cleared in Primary (5.5 cycles, including I cycle margia) Time under Intact and Prior Outage Conditions, Units Tripping Interim 1 (with G834/J023, with existing Kewaunee substation)

Interim 1 Interim 1 American Transmission c/omPany Page 67 of 102

G833/4-J022/J023 1nte4 Operation and Impacts Re-Study Report-RO1 Interim 2A (with G834/J023 and G833/J022, with existing Kewaunee substation)

American Transmission dompany Page 68 of 102

G833/4-J022IJ023 Operation and Impacts Re-Study Report-RO1 Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation) 5.5 cyles di-cycle margin).

American Transmission C/ompany Page 69 of 102

G83314-502215023 Interim Operation and Impacts Re-Study Report-RO1 Table B.9-Stability Results for Auxiliary Transformer High Side 3-Phase Faults Cleared in Primary Time (6.1 cycles, including 1 cycle margin) under Intact and Prior Outage Conditions Interim 1 (with G834/J023, with existing Kewaunee substation)

I I

I H~igh Generatian Low Generation Interim 1 I&< '

5.75B.1 5.75 I

"SEC Gens Isolated 7

Prior Outage I Low Generation I Interim 1 American Transmission Company "POB GEN 2 Isolated Page 70 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Interim 2A (with G834/J023 and G833/J022, with existing Kewaunee substation)

I I

Uinh Canardinn I

I nw Generation I

Prior Fault FltPOBAXl Inlerlm 2A wl exlstlng lnlerlm 2A wl ex~sllng KEW 5 7516 1 5 7516 1 FltPOBAXl L-CYP31 t i E i ? T m FltPOBAXl NAPL7l FltPOBAXl 971L51 FltPOBAXl Y-311 I FItPOBAX1 1 :ii FltPOBAXl I FltPOBAXl 1 845

'SEC Gens Isolated I

Prior Fault "POB GEN 2 Isolated American Transmission Company nlerini 2A 1. ~ 1 exisl~ng lnlerini 2A wl existing KE!I\\!

KE\\N 5 7516 1 5 7516.1

' I

G83314-502215023 Interim Operation and Impacts Re-Study Report-RO1 Prior Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation FltPOBAXl FltPOBAXl FltPOBAXl Hinh Ganaratinn FltPOBAXl 6832 FltPOBAXl 971L71 FltPOBAXl LSEC31 FltPOBAXl L-CYP31 FltPOBAXl TI 0 FltPOBAXl NAPL71 FltPOBAXl 971L51 FltPOBAXl Y-311 FltPOBAXl 812 FltPOBAXl 823 FltPOBAXl 834 FltPOBAXl 845 Low Generation

'SEC Gens Isolated High Generalon I

Low Generation Prior Fault Outage FltPOBAX2 None "POB GEN 2 isolated I

OK" OK merican Transmission Company Page 72 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table B.10- Stability Results for Kewaunee and Point Beach Generation Outage under Intact Conditions Interim 1 (with G834/J023, with existing Kewaunee substation)

I Interim I UNlT TRlP Trip time UNITTRIP POBGltn' POBG2tri POBGlGStri KEWGl tri I Low Gen i Interim 2A (with G834/J023 and G833/m77 with ~ri.vtinc Kewaunee substation)

I I Interim 2A (wl existing UNlT TRlP POBGltri POBG2tri POBGlG2tri Interim 2B (with G834/J023 and G833/J022, with new Kewaunee substation)

American Transmission Company Page 73 of 102

G83314-J022lJO23 ~nteriml operation and Impacts Re-Study Report-RO1 1

A~nendix C: Cornnetin9 Wind Generators 1

99 1

TBD (suspended)

I Kewaunee-Mishimt 138 kV line I

12-31-2011 Elkhart Lake-Forest Junction 138 kV line C

12-01-2012 Forest Junction-Lost Dauphin 138 kV line American Transmission qmpany 427 G590 Page 74 of 102 WEC WEC 98 98 TBD (suspended)

TBD (suspended)

Cypress 345 kV Substation Tecumseh Rd 138 kV Substation

G833/4-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 Appendix D: Operating Restrictions American Transmission Company Page 75 of 102

G833/4-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 With all stability upgrades assumed in-service and the Minimum Excitation Limiter settings for Point Beach and Kewaunee units modified, generation restrictions identified for each interim period are:

During Interim 1 period (2010 after G834lJ023 - 201 1 before G8331J022) iii. G1 at 560 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) iv. GI at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 During Interim 2A period (Without Kewaunee project, 201 1 after G833lJ022 - beyond )

viii. G2 at 620 MW (gross) under prior outage of 121 (Point Beach-Forest Junction 345 kV line) ix. G2 at 620 MW (gross) under prior outage of 15 1 (Point Beach-Fox River 345 kV line)

x. G2 at 600 MW (gross) under prior outage of R304 (Kewaunee-North Appleton 345 kV line) xi. Both GI and G2 at 540 MW (gross) under prior outage of 6832 (North Appleton-Fox River 345 kV line) xii. G2 at 580 MW (gross) under prior outage of SEC3 1 (Sheboygan Energy Center-Granville 345 kV line) xiii. GI at 580 MW (gross) under prior outage of Point Beach Bus Tie 2-3 xiv. G2 at 620 MW (gross) under prior outage of Point Beach Bus Tie 4-5 During Interim 2B period (With Kewaunee project, 201 1 after G83315022 - beyond)

i. G2 at 600 MW (gross) under prior outage condition of 6832 (North Appleton-Fox River 345 kV line) ii. G1 at 580 MW (gross) under prior outage condition of Point Beach Bus Tie 2-3 American Transmission Company Page 76 of 102

683314-J022lJO23 Interim Operation and Impacts Re-Study Report-RO1 Appendix E: Short Circuit / Breaker Duty Analysis Results

\\

I sub with line conversion 26615.1 23988.7 10915.9 13402.2

• POB GI and G2 ofline and Q-303 out of service

• • Scenario 6 and 7 were also studied to provide maximum and minimum fault duties that may appear due to potential future bansmission reinforcement.

Scenario 1 = Existing system Scenario 2 = Existing with new GSU of POB G2 (Fall 2009-May 2010)

Scenario 3 =With G834 (J023) and new GSU of POB GI (May 2010-May 2011)

I Scenario 4 = With G83314 (J02.213) with existing Kewaunee (May 201 1-beyond)

Scenario 5 =With G83314 (J02213) with new Kewaunee (May 201 1-beyond)

• • Scenario 6 =With G83314 (J02213) with new Kewaunee and potential East sub

• • Scenario 7 =With G83314 (~02d3) with new Kewaunee and ~otential EasffNorth Table E.2 - Thevenin Equivalent Impedances in Ohms corresponding to Maximum Fault Duty 23293.9 23878.5 24516 24660.4 24801.6 25448.4 Pos Seq.

American Transmission Company 21 160.4 21419.7 21758.5 21927.2 22017 22749.3 Scenario 1 = Existing system Scenario 2 = Existing with new GSU of POB G2 (Fall 2009-May 2010)

I Scenario 3 = With G834 (J023) and new GSU of POB GI (May 2010-May 201 1)

Scenario 4 =With G83314 (J02213) with existing Kewaunee (May 201 $-beyond)

I Scenario 5 =With G83314 (J02213) with new Kewaunee (May 2011-beyond)

• • Scenario 6 = With G83314 (J02213) with new Kewaunee and potential East sub

• • Scenario 7 =With G83314 (J02213) with new Kewaunee and potential EastlNorth sub with line conversion Page 77 of 102 Neg. Seq.

9288 9288 9288 9288 9288.2 9786.8 Zero Seq.

• • These scenarios were also studied to provide maximum and minimum fault duties that may appear due to potential future transmission reinforcement.

0.492146+ j 9.400272 0.47915+ j 9.28685 0.476195+ j 9.141977 0.480694+ j 9.071247 0.500629+ j 9.033035 0.483549 + j 8.742337 0.455713 + j 8.290790 11100.6 11 100.6 11100.6 11100.6 11 100.7 11 954.8 0.563439t j 9.4053 0.547887+ j 9.291845 0.648689+ j 9.140315 0.754597+ j 9.060422 0.774579+ j 9.021229 0.734901 + j 8.732362 0.685388 + j 8.282391 0.589203+ j 6.794582 0.530596+ j 6.397666 0.480063+ j 6.038944 0.480063t j 6.038944 0.483616+ j 5.974935 0.491449 + j 5.944132 0.496780 + j 5.818807

G83314-J022/1023 Interim Operation and Impacts Re-Study Report-RO1 American Transmission Company Page 78 of 102

G83314-J022N023 Interim Operation and Impacts Re-Study Report-RO1 Page 79 Of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Appendix P: Study Criteria American Transmission Company Page 80 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Study Criteria F. 1 Contingencies For stability analysis, a set of branches in the vicinity of the generatorlpower plant of concern is selected as contingencies, based on engineering judgment. Fault analysis is performed for the following six categories of contingency conditions:

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

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

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

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

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

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

For power flow analysis, contingencies include:

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

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

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

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

American Transmission Company Page 81 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 F.3 Thermal Loading Criteria F.

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

F.3.2 Operating Restriction Calculation Allowable Output =

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

F.

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

F.5 Anwlar 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.

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 82 of 102

G833/4-J022/J023 Interim Operation and Impacts Re-Study Report-RO1 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 83 of 102

G83314-J022/JO23 ~ntermj Operation and Impacts Re-Study Report-RO1 I

cypress-Arcadian 345-k" line I 968 I P0intBeach-shebo~ginEnerg~Center345~

kV line 98.7 1

519.3 119.80% 1 546.61 Appendix 6 :

Point Beach-Sheboygan ~ n e r g ~

1311 CypressArcadian 345-kV line 516.2 540.5 23.37%

568.94 Center 345-kV line 1076 Point Beach-Sheboygan Energy Center 345-498.7 CypressArcadian 345kV line 519.3 19.80%

546.61 kV line Estimated Allowable MW Output from 6834 or 6833 under SpringIFall or Winter Emergency Ratings

1. The Pre and Post MV flow were re-estimated fiom the previous interim operations study report in order to calculate new required ratings and new allowable MW output. The old valu s in the previous study report was obtained fiom Table A.5 9

New Pre MVA - old Pre MVA

-L New Post MVA,- old Post MVA + 6 MW x DF American Transmission Qompany Page 84 of 102

G83314-J022/JO23 1nte4 Operation and Impacts Re-Study Report-RO1

2. The Pre MVA flow w re-estimated fiom the previous interim operations study report in order to calculate new required ratings and new allowable MW output. The old values in e previous study report was obtained fiom Table A.5 S

New Pre MVA old Pre MVA + 6 MW x DF 1

3. The Post MVA flow re-estimated fiom the previous interim operations study report in order to calculate new required ratings and new allowable MW output. The old value previous study report was fiom the case (Scenario 5 with G8331834 and all wind loo%, with 201 1 Kewaunee modeled) old Post MVA + 12 MW x DF Note: The results shown 4 the above tables are based on 50% peak load cases.

American Transmission ompany Ci Page 85 of 102

G833/4-J02ZNOW Interim Operation and Impacts Restudy Report-RO1 I

I Il Open bustie during I

I I I I

I I

I I

I I

I I

I I -

now I KP 1

62620 1 zFE:z 1

5.W4.5 1

11 I

I I

I I

No~.5l)cvdek I I

I I

I I

American Transmission Company KP CCT - 5.W.O KP CCT - 5.546.0

&P,F CCT - 51V6.0 KP.F CCT - 51116.0 KP.F CCT - 5Y6.0 KP,F CCT -5516.0 KP CCT-5.016.0 KP CCT - 5.016.0 KPS CCT -5.016.0 Page 88 bf 102 KP.F CCT-5.D16.0 KP,F CCT - 5Y6.0 KP,F M-5.56.0 A15.75B.1 tasted deariw 6rne -

UV bip P (IS!+/ l.52ls, 345kV 1st 1.C&,

315kV md 1.5625)

CCT-5.5B.O CCT - 5.016.0 KP CCT - 5.W.O KP,S CCT-5.016.0 KP CCT - 5516.0

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Appendix I: Minimum Excitation Limits at Point Beach and Kewaunee during Interim Periods American Transmission Company Page 90 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Minimum Excitation Limits at Point Beach and Kewaunee during Interim Periods As noted in this G833lJ022-G834lJ023 Interim Operations Re-Study Report, Point Beach and Kewaunee units need to maintain certain reactive power output in anticipation of critical contingency conditions. Reactive power output from a synchronous machine has an impact on the transient stability of the unit. Typically, when a unit produces relatively small reactive power output or absorbs reactive power from transmission system (under-excitation), the unit tends to be less stable under a fault condition. The results of the interim operation study indicate that a certain level of reactive power output (over-excitation) needs to be maintained to ensure generation stability in anticipation of critical fault conditions. This is primarily due to too many generators with few outlets out of Fox Valley area.

The minimum excitation limiter, which may also be referred to as the under-excited reactive ampere limit or under-excitation limiter, settings are an effective mechanism to ensure a minimum level of unit excitation. However, limiting the amount of under-excited operation can negatively affect the ability to control system and plant voltages under lighter system load conditions where transmission line charging may result in higher system voltages. Therefore, any minimum excitation limits need to be coordinated with voltage control requirements.

The "interim" solutions described in the Interim Operations Re-Study Report would be followed by the completion of the necessary Network Upgrades identified in the G833lJ022-G834lJ023 System Impact Re-Study Report, which has yet to be posted. The Network Upgrades would be the long-term solutions which ensure a wider operating envelope for the local transmission system and the interconnected generators by permitting generating unit operation at near unity or leading power factor, or at least provide a foundation to achieve the wider operating envelop through additional transmission reinforcement in the area that may be needed in the future.

Transient Stability Studies To estimate minimum excitation limits (MVAR output levels), it is assumed that the stability upgrades identified for each interim period are in-service (see G833lJ022-G834lJ023 Interim Operation Re-Study Report). Various MVAR output levels at Point Beach and Kewaunee 345 kV buses were evaluated using two different generation dispatch scenarios during the three interim periods. Critical faults under system intact condition identified in the interim operation study were applied, which are:

Fault on Q-303 with breaker failure at Point Beach (post-May 2010 until May 201 1 only since a series breaker is proposed to be installed by May 201 1)

Fault on R-304 with breaker failure at Kewaunee (post Kewaunee bus reconfiguration project period only)

American Transmission Company Page 91 of 102

G83314-J022IJO23 Interim Operation and Impacts Re-Study Report-RO1 With stabilitv upmades for each interim period in-service and based on the studv results shown in Table 1.1 through 1.4, the Point Beach and Kewaunee units would need to maintain the following minimum excitation levels to ensure synchronism of these and nearby generators:

For May 2010 - May 201 1 (With Point Beach Unit #1 up~aded and with the existing Kewaunee bus confirnation) o Point Beach G1 and G2: 48 MVAR or higher per unit o Kewaunee GI: 41 MVAR or higher For May 2011 until completion of the Kewaunee bus reconfiguration proiect with both Point Beach Units #1 and #2 upgraded),

o Point Beach Gl and G2: 70 MVAR or higher per unit o Kewaunee GI: 58 MVAR or higher Post completion of the Kewaunee bus reconfiguration proiect (With both Point Beach Units #1 and #2 upgraded]

o Point Beach Gl and G2: 68 MVAR or higher per unit o Kewaunee GI: 49 MVAR or higher These minimum excitation limits were estimated by testing the critical system faults.

Additional study for all other relevant system faults was not performed because of the following reasons:

For Interim 1 period (see Table I.1), the critical faults under system intact conditions are more severe at the low generation scenario, and the estimated minimum excitation limits of Kewaunee and Point Beach units are either same or higher than their W A R outputs at the 352 kV voltage schedule where all other faults under system intact conditions were proven to be stable in the interim operation study. Therefore, additional study for all other relevant system faults under system intact conditions was not performed. For prior outage conditions, it is recommended to maintain at least 354 kV at the Point Beach and Kewaunee 345 kV buses (note: 354 kV is high-end of the preferred voltage range at Point Beach) in anticipation of critical faults. This is to ensure stable system even with faults under prior outage conditions which appear to be more severe at high generation scenario and were proven to be stable at the 352 kV voltage level with interim upgrades and operating restrictions implemented.

As mentioned above, the critical faults under system intact conditions appear to be more severe at the low generation scenario according to the results of the interim operation study, and the estimated minimum excitation limits of Kewaunee and Point Beach units are higher than their MVAR outputs at the 352 kV voltage schedule of low generation scenario (see Table 2.4.1) where all other faults under system intact conditions were proven to be stable in the interim operation report. 'l'herefore, additional study for an other relevant system taults under system intact conditions was not performed. For prior outage conditions, it is also recommended to maintain at least 354 kV (high-end of the preferred voltage range at Point Beach) in anticipation of critical faults. This is to ensure stable system even with faults under prior outage condition which appear to be more severe at high generation scenario and were proven to be stable at 352 kV.

American Transmission Company Page 92 of 102

G83314-J0221J023 Interim Operation and Impacts Re-Study Report-RO1 Steady State Voltage Control Studies at Minimum System Load Conditions Using a minimum load case with 40% of 2010 summer peak load condition, three scenarios were built and studied to confii if any high voltages occur at Point Beach 345 kV and Kewaunee 3451138 kV buses under various conditions. The scenarios are:

Scenario 1 : Minimum load case with G834-J023 added

=

Scenario 2: Minimum load case with G834/J023-G833/J022 added Scenario 3: Minimum load case with Scenario 2 and with Point Beach G2 and Kewaunee G1 offline.

The minimum reactive power outputs of Point Beach and Kewaunee units in each case were adjusted to match with the estimated minimum excitation limits as follows:

For Scenario 1 :

o Point Beach G1 and G2: 48 MVAR o Kewaunee GI: 41 MVAR For Scenario 2:

o Point Beach Gl and G2: 70 MVAR o Kewaunee GI: 58 MVAR No study was performed using the minimum excitation limits of Interim 2B period since no significant impact is expected due to the Kewaunee bus reconfiguration project.

For the study, the following critical contingencies were tested.

System Intact Open Line-end

i. Open North Appleton end of R-304 ii. Open Granville end of L-SEC3 1 iii. Open Arcadian end of L-CYP3 1 iv. Open Forest Junction end of L121

v. Open Fox River end of L15 1 N-1 or multiple contingency analyses are not performed since these conditions will lower voltages due to increased system impedances.

Monitored elements are Point Beach 19 kV and 345 kV, and Kewaunee 345 kV and 138 kV bus voltages. The following criteria are assumed for the monitored elements.

Point Beach 19 kV bus voltage: 95 percent to 105 percent of nominal voltage Point Beach 345 kV bus voltage: Not exceed 358 kV (high end of normal voltage range) under system intact condition. Not exceed 360 kV (slightly lower than high end of absolute voltage range) under a line end open Kewaunee 345 kV bus voltage: 95 percent to 105 percent of nominal voltage a

• * -. T I Kewaunee 138 KV bus voltage: 14U KV 1

ana 143 KV unaer system mmct ana contingency conditions In conclusion, no high voltage conditions were found as shown in Table 1.4. Sensitivity analysis was performed by turning on some of the capacitor banks in the area such as New Holstein, Glenview, Howard and Shoto. As a result, high voltage at Kewaunee 138 kV bus is identified with the Granville end of L-SEC3 1 open. However, the voltage issue American Transmission Company Page 93 of 102

G83314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 can be addressed by remedial actions such as turning off some of the capacitor banks in the area as described in Table 1.5.

American Transmission Company Page 94 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table 1.1. Minimum Excitation Limit Study Results for Interim 1 (May 2010 - May 2011)

/

Interim 1 (KV and MVAR level at POB and KEW for stable system under critical faults) I Critical Fault under Intact (tested clearing times)

L l l l BF @

POB (3.5/10.0/4.5)

Ll5l BF @

POB (3.5/10.0/4.5)

Thus, minimum excitation limits are:

POB Gl: 47.4 POB G2: 47.4 KEW GI: 40.9 High Gen scenario' Q303 BF @

POB (3.5/10.0/6.5)

Table 1.2. Minimum Excitation Limit Study Results for Interim 2A (May 2011 until Kewaunee Reconfiguration Complete)

I 350 kV or higher (POB Gl : 43.4 POB G2: 43.4 KEW GI: 40.9) 348 kV or higher (POB Gl: 12.0 POB G2: 12.0 KEW GI : 20.1)

I Interim 2A (KV level at POB and KEW for stable system under critical faults)

I Low Gen scenario' 35 1 kV or higher (POB GI: 42.7 POB G2: 42.7 KEW Gl: 26.1) 349 kV or higher (POB Gl: 33.3 POB G2: 33.3 KEW Gl: 17.5) 350 kV or higher (POB G1: 43.4 POB G2: 43.4 KEW GI: 40.9)

Critical Fault under Intact High Gen scenario' (tested clearing times)

L l l l BF @

35 1 kV or higher POB (POB Gl: 69.6 POB G2: 69.6 (3'519'014'5)

KEW GI: 57.5)

Ll5l BF @

350 kV or higher POB (POB Gl: 53.7 POB G2: 53.7 (3'5'Y'5'4'5)

KEW GI: 46.9)

Comment 352 kV or higher (POB G1: 47.4 POB G2: 47.4 KEW Gl : 30.4)

Low Gen scenario' 352 kV or higher (POB Gl: 60.1 POB G2: 60.1 KEW Gl: 35.8) 352 kV or higher (POB Gl: 60.1 POB G2: 60.1 KEW Gl: 35.8)

Comment Thus, minimum excitation limits are:

POB Gl: 69.6 POB G2: 69.6 KEW GI: 57.5 American Transmission Company Page 95 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table 1.3. Minimum Excitation Limit Study Results for Interim 2B (Post Kewaunee Reconfiguration)

I Interim 2B (KV level at POB and KEW for stable system under critical faults)

I I Critical Fault I I

I under Intact 1 (tested clearing I High Gen scenario1 I Low Gen scenario1 /

I times)

- I I

I Comment L111 BF @

POB (3+5".014.5)

Q303 BF @

POB Ll5l BF @

POB (3.519.514.51 POB G2: 67.2 KEW GI: 48.9 35 1 kV or higher (POB Gl: 67.2 POB G2: 67.2 KEW ~ 1 :

48.9) 352 kV or higher (POB GI: 58.6 POB G2: 58.6 KEW Gl: 27.3) 349 kV or higher (POB Gl: 35.6 POB G2: 35.6 KEW G1 27.1)

1. Approximate MVAR change at Point Beach and Kewaunee:

High generation scenario:

o 1kV change at Point Beach for every 16 MVAR change o 1 kV change at Kewaunee for every 1 1 MVAR change Low generation scenario:

o 1kV change at Point Beach for every 5 MVAR change o 1kV change at Kewaunee for every 4.5 MVAR change R304 BF @

KEW (3'519'5/4'5)

American Transmission Company POB GI: 67.2 3 52 kV or higher (POB GI: 58.6 POB G2: 58.6 KEW

27.3)

Page 96 of 102 Thus, minimum excitation limits are:

348 kV or higher (POB G1: 20.1 POB G2: 20.1 KEW GI: 16.4) 3 5 1 kV or higher (POB GI: 53.4 POB G2: 53.4 KEW Gl: 22.9)

683314-J022IJ023 Interim Operation and Impacts Re-Study Report-RO1 American Transmission Company Page 98 of 102

683314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Table 1.5. Voltages at Point Beach and Kewaunee Under System Intact and Contingencies Bus I Open North Appleton end Open Granville end of Open Forest Junction Open Fox River end of of Kewaunee-North I Granville-Shebovgan end of Point Beach-I Point Beach-Fox River American Transmission Company Page 99 of 102

@33&302%J0;53 En-Page 100 of 102

G83314-J022lJ023 Interim Operation and Impacts Re-Study Report-RO1 Appendix J: Unit Restriction Due to Stability under Prior Outage Conditions in Table ES-3 during One of Point Beach Units offline American Transmission Company Page 101 of 102

G833/4-.JO22N023 Infer& Operation and Impacts Re-Study Report-RO1 existing Kewa~ nee)

L121 at POB POB Bus tie 2-3 4.514.5 OK R304 at KEW L121 5.514.5 OK OK OK OK R304 at KEW L151 5.514.5 OK OK OK OK 6832 at FOX R-304 4.514.5 OK OK OK OK Interim 2A (With G83314J022r3, With R-304 at KEW 6832 5.514.5 OK OK OK OK existing Kewau lee)

R-304 at KEW LSEC31 5.514.5 OK OK OK OK LIZ1 at POB POB Bus tie 2-3 4.514.5 OK OK R-304 at KEW POB Bus tie 4-5 5.514.5 OK OK OK OK Interim 28 R-304 at KEW 6832 4.514.5 OK OK OK OK

( W i G833/4J022/3, With new Kewaune?)

L121 at POB POB Bus tie 2-3 45/45 OK OK 1

of Point Beach Bus tie 2-3 followed by L121 fault isolates Point Beach GI to the remaining line L111. Therefore, taking the Point Beach Bus tie 2-3 out of senrice g outage window does not eliminate the POB GI stability issue for L121 fault under Point Beach Bus tie 2 3 out of se~ce. Thus, follow the operating restriction for the G833/4J022/3 Interim Operation Re-study Report American Transmission C mpany 4

Page 102 of 102