Public Version
MISO
2013 Summer
Coordinated Seasonal
Transmission Assessment
May 31, 2013
Final Report
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MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
CONTENTS
Contents .................................................................................................................................................. 2
1.0 Executive Summary .......................................................................................................................... 4
2.0 Introduction .................................................................................................................................... 10
3.0 Study Criteria .................................................................................................................................. 13
4.0 Study Participants ........................................................................................................................... 15
5.0 Models and Input Data .................................................................................................................... 17
6.0 Study Methodology ......................................................................................................................... 22
6.1 Steady State AC Contingency Analysis ...................................................................................................22
6.2 FCITC Transfer Analysis ..........................................................................................................................23
6.3 Critical Interface Voltage Stability Analysis ............................................................................................23
6.4 Large Load Area Analysis .......................................................................................................................23
7.0 Steady-State Analysis Results......................................................................................................... 25
7.1 Summary....................................................................................................................................................25
7.2 Prior Outages to Watch .............................................................................................................................25
8.0 Transfer Analysis Results ............................................................................................................... 26
8.1 Carmel Region to St. Paul Region ............................................................................................................27
8.2 Carmel Region + SPP to NW Dakotas ....................................................................................................28
8.3 St. Paul Region to Carmel Region ...........................................................................................................29
8.4 MISO Indiana/Illinois to TVA .................................................................................................................30
8.5 PJM N. Illinois to PJM Ohio....................................................................................................................31
8.6 MISO IL/MO to MISO South Region & TVA .......................................................................................32
8.7 Missouri to Indiana...................................................................................................................................33
8.8 Southern Carmel Region & PJM Ohio to Michigan ................................................................................34
8.9 MISO Southern Carmel Region to IESO..................................................................................................35
8.10 IESO to MISO Southern Carmel Region ...............................................................................................36
8.11 Entergy Texas + AEPW to Southern Company .....................................................................................37
8.12 S. MISO South Region to MISO IN/IL ..................................................................................................38
8.13 MISO South Region to TVA ..................................................................................................................39
8.14 TVA to MISO South Region ..................................................................................................................40
8.15 MISO South Region to PJM Mid-Atlantic .............................................................................................41
8.16 Southern Company to AEPW + Entergy Texas .....................................................................................42
8.17 PJM Ohio to PJM Northern Illinois ........................................................................................................43
9.0 Critical Interface Analysis Results ................................................................................................. 44
9.1
9.2
9.3
9.4
9.5
Minnesota-Wisconsin Export (MWEX) ..................................................................................................45
Southern Louisiana HV Interface ............................................................................................................49
Down Stream of Gypsy HV Interface......................................................................................................51
MISO South’s Western HV Interface ......................................................................................................53
St. Louis South Interface ..........................................................................................................................54
10.0 Large Load Area Analysis Results................................................................................................ 55
10.1 Vectren/BREC Combined Metro LLA ...................................................................................................56
10.2 West Of The Atchafalaya Basin (WOTAB) ...........................................................................................58
10.3 Little Rock Metro Area ...........................................................................................................................60
10.4 Indianapolis Metro Area .........................................................................................................................62
10.5 Detroit Metro Area ..................................................................................................................................64
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11.0 Wind Generation Sensitivity Analysis .......................................................................................... 66
12.0 IROL Limits ................................................................................................................................. 68
13.0 Nuclear Plant Interface requirements ............................................................................................ 69
14.0 Appendices .................................................................................................................................... 79
15.0 Abbreviations and acroynms ......................................................................................................... 80
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1.0 EXECUTIVE SUMMARY
The MISO Coordinated Seasonal Transmission Assessment (CSA) is a reliability assessment that tests the
performance of MISO’s transmission network under anticipated operating horizon loading conditions. This
study is coordinated with other studies performed by MISO members and other planning entities. This study
includes the new MISO South region which consists of Entergy transmission system that began receiving
Reliability Coordination services in December 2012. Fourteen new members resulting in seven new Local
Balancing Authorities (LBA) in the MISO South Region, will begin receiving Reliability Coordination services
on June 1, 2013 and have declared intent to join MISO as a Transmission Owning member in 2013, was
included in this CSA. None of these LBAs were MISO transmission owning members when this study was
performed.
This Summer transmission system assessment is produced in order to provide system operators with guidance
as to possible acute system conditions that would warrant close observation to ensure system reliability. The
sensitivity cases and outage contingencies contained herein often go beyond regional planning criteria and such
criteria used by the local transmission owners.
The 2013 Summer CSA performed the following transmission system assessments:
Steady State AC Contingency Analysis was performed of the MISO system.
Transfer Analysis was performed to identify thermal limitations using First Contingency Incremental Transfer
Capability (FCITC) analysis. The transfers considered in the study are shown below:

















MISO Carmel Region to MISO St. Paul Region
MISO S. Carmel & SPP to NW & Dakotas
MISO St. Paul Region to MISO Carmel Region
MISO IN/IL to TVA
PJM Northern Illinois to PJM Ohio
MISO MO/IL to MISO South & TVA
MISO Missouri to Indiana
Southern Carmel Region & PJM Ohio to Michigan
Southern Carmel Region to IESO
IESO to Southern Carmel Region
AEPW + EES_TX to SOCO
S. MISO South Region to MISO IN/IL
MISO South Region to TVA
TVA to MISO South Region
MISO South Region to PJM Mid-Atlantic
SOCO to AEPW + EES_TX
PJM Ohio to PJM N. Illinois
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MISO Coordinated Seasonal Assessment – 2013 Summer
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Critical Interface Voltage Stability Analysis was performed for those areas that are either known to experience
voltage stability limitations under certain operating conditions or are suspected of having potential voltage
stability limitations. The areas analyzed were:





MWEX Interface
S. Louisiana HV Interface
Down Stream of Gypsy (DSG) HV Interface
MISO South’s Western HV Interface
St. Louis South Interface
Large Load Area Screening Analysis was performed within the MISO footprint for potential voltage instability
arising from limited local reactive reserves under severe disturbances and load sensitivities. The large load
areas covered in this assessment are:





Vectren and Big Rivers Metro
WOTAB area
Little Rock Metro
Indianapolis Metro
Detroit Metro
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MISO Coordinated Seasonal Assessment – 2013 Summer
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Summary of Results
Steady State AC Contingency Analysis
In general, the MISO transmission system performed well. There are some contingencies that may require
operator action to avoid potential overloads or low voltages during the 2013 Summer peak conditions,
depending on system conditions. These contingencies have been identified and tabulated, with the actions
required to address these potential issues contained in Section 7 of this report.
FCITC Transfer Analysis
There were seventeen transfers studied in the 2013 Summer assessment; however, the following transfer is
being discussed in this section because it has been one of the most limiting transfers in prior Summer
assessments and it has been one of the top binding constraints seen in real-time operations in years past.

PJM Ohio to PJM Northern Illinois: This transfer was requested by NIPSCO as they expect to see
issues this summer for high transfers from PJM Ohio sinking into PJM N. Illinois. This transfer
simulates high east-to-west transfers over NIPSCOs system. PJM N. Illinois is now an importing
control area, they were an exporting control area in years past.
-
The inter-Regional transfer limit was observed at 1,500 MW. The limiting element for this
transfer was the [CE] Kincaid—[AMIL] Pana 345 kV line for a category B contingency.
This transfer was not performed last year.
A Shift in PJM N. Illinois summer peak
interchange of exporting 2,800 MW in 2012 to importing 50 MW in 2013 is one cause for
this limit. PJM N. Illinois is now importing.
See Section 8 for additional details on the remaining transfers studied.
Critical Interface Voltage Analysis
The purpose of this analysis was to determine voltage stability and voltage violation limitations.

Minnesota-Wisconsin Export Interface: This interface is voltage stability limited by the
transfer from Minnesota to the southeast direction through and into ATC under certain
operating scenarios. By evaluating 2013 Summer peak base case scenario flow on the
MWEX Interface may be limited from 800 MW to 1,800 MW to avoid voltage instability for
a category B contingency event. This 1,000 MW range is a slight decrease over the prior year
result as observed in the 2012 Summer CSA. This interface was studied with the Sherburne
County unit No. 3 online. It was later discovered that it will be offline again for the 2013
Summer season. It is expected that the MWEX results to be similar to the 2012 Summer
CSA in which this interface was analyzed with Sherburne County unit No. 3 offline.

Southern Louisiana HV Interface: Localized issues limited this analysis to the point that we
could not stress this fourteen EHV interface without observing a local thermal loading issue
far from the interface.
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MISO Coordinated Seasonal Assessment – 2013 Summer

Public Version
Down Stream of Gypsy Interface: This interface is voltage stability limited by transfers from
Central Louisiana into the Down Stream of Gypsy Region of Entergy under certain operating
scenarios. By evaluating 2013 Summer peak base case scenario flow, the DSG Interface may
be limited 1,800 MW to 2,200 MW to avoid voltage instability for a category C3 contingency
event plus a prior outage. This 400 MW range is considered adequeate for the upcoming
season. This transfer was not performed in the 2012 Summer CSA.

Western portion of the West Of The Atchafalaya Basin Interface: This interface is voltage
stability limited by transfers from an increase in Entergy’s Western subregion load and a
decrease in remaining Entergy area load outside of the Western subregion. By evaluating
2013 Summer peak base case scenario flow, the Western Interface may be limited from 2,200
MW to 2,600 MW; to avoid voltage instability for the loss of several category B events. This
400 MW range is considered adequeate for the upcoming season. This transfer was not
performed in the 2012 Summer CSA.

St. Louis South Interface: No voltage stability issues were observed.
See Section 9 for additional P/V analysis details.
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Large Load Area Analysis
The purpose of this analysis is to stress the transmission network supporting large load areas by subjecting it to
multiple contingency events leading to low reactive power supply. Further analysis was also undertaken to
investigate the sensitivity of the area to increases in forecast demand and to changes in load power factor.

Vectren/BREC Area: The combined Vectren and BREC load areas have low reactive reserves
for some extreme conditions for the 2013 summer season. The least reactive reserves were
seen for a category D contingency event. Also the load was increased by 5 percent and the
power factor was decreased by 4 percent. The second lowest reactive reserves were seen
under a category C3 contingent event. Again, the load was increased by 5 percent and the
power factor was decreased by 4 percent. These severe events are beyond what would
typically be expected. In the event one of these or a variation occurs, some operational actions
may be required to improve voltage stability margins: ensure all switched shunts are on, and
bring on peaking units as is appropriate.

West Of The Atchafalaya Basin (WOTAB): The WOTAB Region is a high profile industrial
area that accounts for 25 percent of the total Entergy load. The least reactive reserves were
seen for the category C3 contingency event. This reactive reserve decrease was observed
through a severe load condition that increased the load by 5 percent (90/10 load profile) along
with a power factor reduction of 4 percent. The severity of a category C3 contingency on top
of a category B prior outage is beyond what would typically be expected. In the event one of
these or a variation occurs, some operational actions may be required to improve voltage
stability margins: ensure all switched shunts are on, and bring on peaking units as is
appropriate.

Little Rock Metro Area: In general, the Little Rock metro load area is projected to have
sufficient reactive reserves and be voltage stable for the upcoming 2013 Summer season. The
least reactive reserves were seen for a category B contingency event. This reactive reserve
decrease was observed through a severe load condition that increases the load by 5 percent
(90/10 load profile) along with a power factor reduction of 5 percent. These severe events are
beyond what would typically be expected. In the event one of these or a variation occurs, some
operational actions may be required to improve voltage stability margins: ensure all switched
shunts are on, and bring on peaking units as is appropriate. The Little Rock Metro area was
determined to have sufficient reactive reserves and is voltage stable for the 2013 Summer
season.

Indianapolis Metro Area: In general, the Indianapolis metro load area is projected to have
sufficient reactive reserves and be voltage stable for the upcoming 2013 Summer season. The
least reactive reserves were seen for a category B contingency event. This reactive reserve
decrease was observed through a severe load condition that increases the load by 5 percent
(90/10 load profile) along with a power factor reduction of 9 percent. These severe events are
beyond what would typically be expected. In the event one of these or a variation occurs, some
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MISO Coordinated Seasonal Assessment – 2013 Summer
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operational actions may be required to improve voltage stability margins: ensure all switched
shunts are on, and bring on peaking units as is appropriate. The Indianapolis Metro area was
determined to have sufficient reactive reserves and is voltage stable for the 2013 Summer
season.

Detroit Metro Area: The Detroit Metro area accounts for 75 percent of the total ITCT load.
The least reactive reserves were seen for several category B contingency events as well as a
category C5 contingency event along with the independent prior outages of a category B
contingency event.
This reactive reserve decrease was observed through a severe load
condition that increased the load by 5 percent (90/10 load profile) along with a power factor
reduction of 4 percent. The severity of a category B contingency on top of a prior outage
category B event is beyond what would typically be expected. In the event one of these or a
variation occurs, some operational actions may be required to improve voltage stability
margins: ensure all switched shunts are on, and bring on peaking units as is appropriate.
See Section 10 for additional details on Large Load Area analysis.
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2.0 INTRODUCTION
MISO was approved by FERC as the nation’s first Regional Transmission Organization (RTO) in 2001. MISO
launched its wholesale electricity market in 2005 and the Ancillary Services Market (ASM) in year 2009,
providing both energy and operating reserves as well as regulation and response services that support reliable
transmission system operation and equal acess to high voltage transmission system in 14 U.S. states and the
Canadian province of Manitoba. The geographic location of the MISO CSA study footprint is shown below in
Figure 2.0-1. Note again that Entergy’s transmission system is included in this diagram as party receiving RC
services and as a party who has declared intent to become a MISO transmission owner. For the purposes of this
study report, any references to the MISO transmission system include non-transmission owning member,
Entergy, as their transmission system was assessed as part of this study.
Figure 2.0-1: MISO CSA Study footprint
The Bulk Power System (BPS) within the MISO CSA study footprint consists of an extensive 115 kV to 500
kV network. The 500 kV network in MISO is located in Arkansas, Louisiana, Minnesota, Mississippi, and
Texas. The 345 kV networks are located in Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan,
Missouri, Minnesota, North Dakota, South Dakota, Texas, and Wisconsin. The 230 kV networks are located in
Arkansas, Illinois, Indiana, Iowa, Louisiana, Michigan, Mississippi, Missouri, Minnesota, North Dakota, South
Dakota, Texas, and Wisconsin.
MISO’s BPS lies in the following NERC regions: Midwest Reliability
Organization (MRO), ReliabilityFirst Corporation (RFC) and Southeastern Reliability Corporation (SERC)
regions.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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MISO Regions
MISO is providing Reliability Coordination services to Entergy as of December 1, 2012; therefore, the MISO
transmission system consists of three operating regions. The three operating regions are called St. Paul Region,
Carmel Region, and South Region; see Figure 2.0-2 below.
St. Paul
Carmel
South
Figure 2.0-2: MISO RC Operating Regions
The St. Paul Region contains the MISO transmission systems in the states of Iowa, Minnesota, North Dakota,
South Dakota and Wisconsin, consisting of the following control areas: Alliant Energy West [ALTW],
Dairyland Power Cooperative [DPC], Great River Energy [GRE], MidAmerican Energy Company [MEC],
Minnesota Power [MP], Montana-Dakotas Utilities [MDU], Muscatine Power and Water [MPW], Otter Tail
Power [OTP], Southern Minnesota Municipal Power Agency [SMMPA] and Xcel Energy [XEL]. These St.
Paul subregions all belong to the NERC approved MRO Region.
The Carmel Region contains the MISO transmission systems in the states of Illinois, Indiana, Kentucky
Michigan, Missouri, and (Eastern) Wisconsin consisting of the following control areas: Alliant Energy East
[ALTE], Ameren Missouri [AMMO], Ameren Illinois [AMIL], Big Rivers Electric Cooperation [BREC],
Columbia Water & Light Division [CWLD], City of Springfield (IL), Water Light & Power [CWLP], Duke
Energy Indiana [DEI], Hoosier Energy [HE], Indianapolis Power and Light [IPL], International Transmission
Company [ITCT], Madison Gas and Electric [MGE], Michigan Electric Transmission Company [METC],
Northern Indiana Public Service Company [NIPSCO], Southern Illinois Power Cooperative [SIPC] and
Southern Indiana Gas & Electric [SIGE], We Energies Corporation [WEC], Wisconsin Public Service [WPS],
Wolverine Power [WPSC] and Upper Peninsula Power Company [UPPC]. The Carmel subregions belong to
MRO, SERC or RFC regions of NERC.
The South Region contains the MISO transmission systems in the states of Arkansas, Louisiana, Mississippi,
and Texas consisting of the following control areas: Batesville generation [BBA], Brazos Electric Cooperative
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MISO Coordinated Seasonal Assessment – 2013 Summer
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[BRAZ], Cleco [CLEC], City of Benton AR [BUBA], City of Conway AR [CWAY], City of North Little Rock
AR [NLR], City of Osceola AR [OMLP], City of Ruston, LA [DERS], City of West Memphis AR [WMU],
Entergy Transmission [EES], Lafayette Utilities System [LAFA], Louisiana Energy and Power Authority
[LEPA], Louisiana Generating, LLC [LAGN], Plum Point Energy Associates LLC [PLUM], South Mississippi
Electric Power Associations [SMEPA], and Union Power Partners L.P. [PUPP]. The South subregions belong
to the SERC Region of NERC.
Study Purpose
The purpose of this Coordinated Seasonal Transmission Assessment (CSA) is to analyze and assess the MISO
transmission system under projected peak load conditions for the 2013 Summer peak season. The coordination
of this study across MISO’s area provides the benefit of reviewing the network over a much larger area than
would normally be assessed by the individual participating transmission owners. This assessment has focused
on the performance of large scale steady-state contingency analysis, critical interface analysis P/V for selected
areas where voltage stability margins are known to be small, and screening for potential voltage instability (VQ) in large metropolitan areas under multiple contingent events and increased load sensitivities, as well as wide
area transfer analyses under NERC category B contingencies.
The contingency levels and sensitivity cases included in this assessment are, in many cases, beyond those
typically considered and are beyond regional planning criteria. These events have been evaluated in order to
provide system operators with guidance as to possible but unlikely system conditions that would warrant close
observation to ensure system security.
This CSA report does not attempt to determine Available Transfer Capability (ATC), Available Flowgate
Capacity (AFC), the availability of transmission service, or provide a forecast of anticipated dispatch patterns
for the 2013 Summer season. There were no Capacity Benefit Margins (CBM) or Transmission Reliability
Margins (TRMs) included in this assessment. Also, the assessments documented in this report are not intended
to fulfill all of the study requirements for Transmission Planners or Planning Coordinators listed in NERC
Standards TPL-001 through TPL-004.
The results from this year’s assessment do not override the currently posted operating guide limits and values.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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3.0 STUDY CRITERIA
The NERC Planning Standards TPL-001, TPL-002, TPL-003 and TPL-004 are the applicable study criteria for
this assessment. This assessment evaluates NERC contingency categories A, B, and C as well as combinations
of category B and C; for example, a generator outage plus a category C event.
The MISO members’ thermal and voltage thresholds are used to flag thermal and voltage violations and voltage
deviation exceptions on their respective systems. Monitored element files for system intact and contingency
conditions are included in Appendix A. MISO members’ system elements (> 69 kV) were monitored. Precontingency equipment loadings above 100 percent of normal rating (Rate A) were flagged. Post-contingency
equipment loadings above 100 percent of emergency rating (Rate B) were also flagged. Equipment loadings
above 125 percent of emergency rating were identified for cascade screening review.
All of the MISO members’ systems were studied, except one small radial system. Below is a list of MISO
members shown in Table 3-0-1. The table also includes the operating Region and their associated control areas
or zones in the powerflow model. Note some members are within other members’ control areas so area number
is blank.
Table 3.0-1: MISO CSA Systems Studied
Region
Carmel
Carmel
Area
206
207
Abbrev
OVEC
HE
System
Ohio Valley Electric Corporation
Hoosier Energy Rural Electric Cooperative
Carmel
208
DEI
Duke Energy Indiana
Carmel
in 208
IMPA
Indiana Municipal Power Agency
Carmel
in 208
WVPA
Wabash Valley Power Association
Carmel
210
SIGE
Vectren (Southern Indiana Gas & Electric Co)
Carmel
216
IPL
Indianapolis Power & Light Company
Carmel
217
NIPS
Northern Indiana Public Service Company
Carmel
218
METC
Michigan Electric Transmission Co.
Carmel
in 218
LBWL
Lansing Board of Water & Light (zone 1261)
Carmel
in 218
MSCPA
Michigan South Central Power Agency
Carmel
in 218
WPSC
Wolverine Power Supply Cooperative (zone 1262)
Carmel
219
ITC
International Transmission Company
Carmel
in 219
MPPA
Michigan Public Power Agency
Carmel
295
WEC
Wisconsin Electric Power Company (ATC)
Carmel
314
BREC
Big Rivers Electric Corporation
Carmel
333
CWLD
Columbia, MO Water and Light Department
Carmel
356
AMMO
Ameren Missouri
Carmel
357
AMIL
Ameren Illinois
Carmel
360
CWLP
City of Springfield (IL) Water Light & Power
Carmel
361
SIPC
Southern Illinois Power Cooperative
Carmel
694
ALTE
Alliant Energy East (ATC)
Carmel
696
WPS
Wisconsin Public Service Corporation (ATC)
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Region
Area
Abbrev
System
Carmel
697
MGE
Madison Gas & Electric Company (ATC)
Carmel
698
UPPC
Upper Peninsula Power Company (ATC)
South
325
BRAZ
Brazo Electric Cooperative
South
328
PLUM
Plum Point Energy Associates, LLC
South
329
OMLP
City of Osceola, LA
South
332
LAGN
Louisiana Generating, LLC
South
334
WMU
City of West Memphis, AR
South
335
CWAY
City of Conway, AR
South
336
BUBA
City of Benton, AR
South
337
PUPP
Union Power Partners, L.P.
South
338
DERS
City of Ruston, LA
South
339
NLR
City of North Little Rock, AR
South
349
SMEPA
South Mississippi Electric Association
South
351
EES
Entergy Transmission
South
502
CLEC
Cleco
South
503
LAFA
Lafayette Utilities System
South
504
LEPA
Louisiana Energy and Power Authority
St. Paul
600
XEL
Xcel Energy
St. Paul
608
MP
St. Paul
in 608
NWEC
St. Paul
613
SMMPA
Minnesota Power & Light
Northwestern Wisconsin Electric (radial, not
studied)
Southern Minnesota Municipal Power Agency
St. Paul
615
GRE
Great River Energy
St. Paul
620
OTP
Otter Tail Power Company
St. Paul
in 620
MPC
Minnkota Power Cooperative
St. Paul
627
ALTW
ITC Midwest
St. Paul
633
MPW
Muscatine Power & Water
St. Paul
635
MEC
MidAmerican Energy Company
St. Paul
in 635
CFU
Cedar Falls Utility
St. Paul
652
WAPA
Western Area Power Administration
St. Paul
661
MDU
Montana-Dakota Utilities Company
St. Paul
667
MH
Manitoba Hydro
St. Paul
680
DPC
Dairyland Power Cooperative
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4.0 STUDY PARTICIPANTS
Table 4.0-1 below shows the individuals who actively participated in this study.
Table 4.0-1: MISO's 2013 Summer CSA Participation List1
1
First Name
Last Name
Company
Name
First
Name
Last Name
Company
Name
Tony
Gott
AECI*
Jason
Brown
MISO
Evan
Shuvo
Ameren
David
Duebner
MISO
Eric
Fleming
ATC
Scott
Goodwin
MISO
Kerry
Marinan
ATC
Virat
Kapur
MISO
Nate
Wilke
ATC
Josh
Netherton
MISO
Kyle
Minnix
BRAZ
Joe
Reddoch
MISO
Chris
Bradley
BREC
Tony
Rowan
MISO
Mike
Doyle
BUBA
Kris
Ruud
MISO
Ken
Kagy
Cedar Falls
Kevin
Sherd
MISO
Michelle
Corley
CLECO
Raja
Thappetaobula
MISO
Donald
Idzior
CMS Energy
Jeff
Webb
MISO
Denis
Leitch
CMS Energy
Andy
Witmeier
MISO
George
Heintzen
CNWY
Ruth
Pallapati
MP
Adam
Schuttler
CWLD
Peter
Schommer
MP
Chris
Daniels
CWLP
Will
Lovelace
MPC
Steve
Rose
CWLP
Matt
Dykstra
MPPA
Phil
Briggs
DEI
Mark
Nelson
MPW
Bob
Evanich
DEI
Lewis
Ross
MPW
John
Jozefowski
DEI
John
Stolley
MPW
Darrell
Caraway
DERS
Bob
Vargus
MPW
Steve
Porter
DPC
David
Austin
NIPS
Samrat
Datta
EES
Mike
Melvin
NIPS
Sharma
Kolluri
EES
Syedkhair
Quadri
NIPS
Scott
McMahan
EES
Jessica
Stephens
NLR
Joe
Payne
EES
Cody
Moore
OMLP
Maryclaire
Peterson
EES
Luis
Leon
OTP
Jared
Shaw
EES
Jeff
McLaughlin
PJM*
Cameron
Warren
EES
Russell
Abel
PLUM
Richa
Singhal
GRE
John
Heisey
PUPP
Todd
Taft
HE
Ryan
Abshier
SIGE
Jonathan
Mendoza
IESO*
Jeff
Jones
SIPC
Ovidiu
Vasilachi
IESO*
Pat
Egan
SMMPA
Robert
Grubb
IPL
Sam
Copeland
SOCO*
* denotes non-MISO member participant
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MISO Coordinated Seasonal Assessment – 2013 Summer
Dave
Osterkamp
Company
Name
ITCM
Bahbaz
Company
Name
SPP*
Joshua
Hurst
ITCT
Jason
Smith
SPP*
Sherry
Tang
ITCT
Tim
Fritch
TVA*
Ron
Gary
LAFA
Roy
Mathai
TVA*
Jennifer
Vosburg
LAGN
Nate
Schweighart
TVA*
Lynn
McKintry
LBWL
Scott
Walker
TVA*
Cordell
Grand
LEPA
Chris
Bultsma
WAPA
Shawn
Heilman
MDU
Todd
Pederson
WMU
Dan
Rathe
MEC
Tom
King
WPSCI
Kris
Long
MH
Dan
Wilkinson
WPSCI
Gayan
Wijeweera
MH
Michelle
Wood
XEL
Tim
Aliff
MISO
Khalid
Yousif
XEL
First Name
Last Name
First
Name
Yassar
Public Version
Last Name
In addition to the aforementioned list of participants above, the final 2013 Summer CSA report will also be
distributed to the following entities in accordance with NERC FAC-013-1 and FAC-014-2 standards.
Table 4.0-2: Final Report Distribution List
Adjacent Planning Authorities
AECI
MH
ATC
Ontario IESO
LGE/KU
PJM
EEI
PS
EKPC
Sask Power
Entergy
SOCO
SPP
GTC
MAPP
TVA
Reliability Coordinators
MISO
Transmission Operators
Ameren
MDU
ATC
MEC
BREC
MH
CWLD
MPC
CWLP
MP
DPC
MPW
DEM
NIPS
EEI
OTP
EES
RPU
GRE
SIGE
HE
SIPC
IPL
SMEPA
ITCM
WAPA
ITCT
WPSCI
METC
XEL
Transmission Planners
Ameren
LBWL
ATC
MEC
Basin Electric
METC
BREC
MH
Cedar Falls
MPC
CIPC
MP
CWLD
MPW
CWLP
NIPS
DEM
OTP
DPC
RPU
EEI
SIGE
Entergy
SIPC
GRE
SMMPA
HE
WAPA
IPL
WPSCI
ITCM
XEL
ITCT
Transmission Service Provider
BREC
MPC
CIPC
MISO
DPC
RPU
Entergy
WPA
MH
XEL
Adjacent Reliability Coordinators
Ontario IESO
SOCO
PJM Interconnection
SPP
Sask Power
TVA
WECC
16
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
5.0 MODELS AND INPUT DATA
A power flow model used for the 2013 Summer peak CSA was built from the ERAG/MMWG 2012 series
Summer peak load base case in coordination with the MMWG, which modeled firm, capacity backed transfers,
as base case interchange. This case was further updated with the most recent transmission system status
information and projected capacity backed transfers across the entire eastern interconnect. The MISO data was
submitted by MISO stakeholders to MISO’s Model-on-Demand (MOD) tool. The case was then reviewed by
CSA study participants for accuracy of the topology, load, generation and interchange values. The dispatch
used was MISO’s Security Constrained Economic Dispatch (SCED) which was achieved by re-dispatch of
MISO generation while maintaining MISO’s interchange.
The projected non-coincident 2013 Summer peak demand of MISO’s footprint in the power flow model used
for this transmission assessment is 140, 611 MW. This does include the projected Summer peak demand of the
fourteen new LBAs in the MISO South region; since they are receiving RC services from MISO starting on
June 1, 2013. Power flow model control areas of MISO member utilities include loads of other utilities that are
not MISO members. Therefore, the demand in the power flow model is not directly comparable to the resource
assessment demand forecast for MISO member utilities. The total amount of generation available to serve
MISO load from internally and externally designated capacity resources during the 2013 Summer peak period is
148,516 MW. The net scheduled interchange for MISO in the power flow model is 4,161 MW, which indicates
a net export of power by the MISO member utilities in the 2013 Summer peak.
The following seasonal outages were included because the outages were scheduled for all of July and August;
the Summer peak months.
Table 5.0-1: Seasonal Outages
Operating
Region
Control
Area
Type
Planned
Start
Planned
End
From Station
Equip
Type
kV
Capacity
Carmel
Ameren
E
2011-2212
2015-0101
Hutsonville unit No. 3
UN
13
75.8
Carmel
Ameren
E
2011-1220
2014-1231
Meredosia unit No. 3
UN
19
208.7
Carmel
Ameren
F
2011-1222
2015-0101
Hutsonville unit No. 4
UN
13
76.8
Carmel
Ameren
F
2010-0104
2015-1108
Meredosia unit No. 1
UN
14
67
Carmel
Ameren
F
2010-0104
2015-1108
Meredosia unit No. 2
UN
14
67
Carmel
Ameren
P
2012-0925
2015-1001
Meredosia unit No. 4
UN
19
73.5
Carmel
ATC
P
2013-0426
2013-1017
Blue Mound—96th St 138 kV
LN
138
Carmel
ATC
P
2013-0503
2013-1108
Blue Mound—S 43rd St 138 kV
line
LN
138
Carmel
ATC
P
2012-1221
2013-1231
Hiawha—Engadine Tap 69 kV
LN
69
Carmel
ATC
P
2012-1221
2013-1231
Hiawha—Indian Lake 69 kV
LN
69
Carmel
ATC
P
2012-1203
2013-1205
Racine 345/138 kV Transformer
XF
345
17
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
Operating
Region
Control
Area
Type
Planned
Start
Planned
End
From Station
Equip
Type
kV
Capacity
Carmel
ATC
P
2013-0412
2014-0321
Lakefront unit No. 6
UN
69
27.9
Carmel
ITCT
F
2012-0705
2013-1001
Hancock unit No. 11
UN
42
13
Carmel
ITCT
F
2010-0805
2014-0101
Northeast unit No. 11
UN
24
11.6
Carmel
ITCT
F
2010-0304
2013-1231
Superior unit No. 11
UN
42
20
Carmel
ITCT
P
2011-0328
2014-0328
Montcalm
UN
13
29
Carmel
ITCT
P
2013-0301
2020-0301
Dayton unit No. 11
UN
42
10
Carmel
ITCT
P
2013-0301
2020-0301
Essex unit No. 11
UN
24
4.6
Carmel
ITCT
P
2012-1121
2016-0101
Harbor Beach unit No. 11
UN
120
3.4
Carmel
ITCT
P
2012-1209
2015-0101
Oliver unit No. 11
UN
42
9.2
Carmel
METC
F
2012-0923
2013-1101
Straits unit No. 1
UN
14
20
Carmel
METC
P
2012-0501
2015-0301
Campbell unit No. A
UN
14
11.2
Carmel
METC
P
2008-0408
2036-1231
Gaylord unit No. 5
UN
14
21
Carmel
METC
P
2010-0412
2013-1101
Gaylord unit No. 4
UN
14
17
Carmel
METC
P
2012-0212
2015-0211
Morrow unit No. A
UN
14
12.8
Carmel
METC
P
2012-0212
2015-0211
Morrow unit No. B
UN
14
10.6
Carmel
METC
P
2009-1118
2013-1014
Thetford unit No. 7
UN
14
19
Carmel
METC
P
2010-1028
2013-1014
Thetford unit No. 1
UN
14
30
Carmel
METC
P
2010-1028
2013-1014
Thetford unit No. 2
UN
14
30
Carmel
METC
P
2010-1028
2013-1014
Thetford unit No. 5
UN
14
15
Carmel
METC
P
2010-1028
2013-1014
Thetford unit No. 6
UN
14
15
Carmel
METC
P
2012-0601
2015-0515
Thetford unit No. 3
UN
14
22.5
Carmel
METC
P
2012-0601
2015-0515
Thetford unit No. 4
UN
14
24.6
Carmel
METC
P
2012-0601
2015-0515
Thetford unit No. 8
UN
14
11.1
Carmel
METC
P
2012-0601
2015-0515
Thetford unit No. 9
UN
14
10.6
Carmel
METC
P
2010-1028
2013-1014
Weadcock unit No. A
UN
14
13
Carmel
METC
P
2010-1028
2013-1014
Whiting unit No. A
UN
14
21
Carmel
METC
P
2012-0316
2014-1230
Fermi unit No. 11
UN
120
12.2
St. Paul
ALTW
F
2012-0702
2014-0131
Lansing unit No. 3
UN
22
42
St. Paul
ALTW
F
2010-0414
2013-1230
Fairmount unit No. 5
UN
69
20
18
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
Operating
Region
Control
Area
Type
Planned
Start
Planned
End
From Station
Equip
Type
kV
St. Paul
ALTW
P
2012-1201
2013-1226
Collins—Collins Tap 69 kV
LN
69
St. Paul
ALTW
P
2012-1201
2013-1226
Collins—Mario 69 kV
LN
69
St. Paul
ALTW
P
2012-1201
2013-1226
Collins—Hiawha 69 kV
LN
69
St. Paul
MH
F
2011-1101
2013-1231
Jenepeg unit No. 4
UN
4.2
30.5
St. Paul
MH
P
2013-0402
2013-1130
Great Falls unit No. 4
UN
11
22
St. Paul
MH
P
2010-0720
2015-0930
PTD unit No. 5
UN
6.9
4.7
St. Paul
MH
P
2011-1225
2013-1231
Jenpeg 230/4 kV Transformer
XF
230
St. Paul
MP
F
2012-0620
2014-0101
Thompson unit No. 6
UN
115
34.1
St. Paul
NSP
F
2011-0221
2015-1231
French unit No. 3
UN
14
100
St. Paul
NSP
F
2012-0828
2013-1101
Byron 161/345 kV Transformer
XF
345
St. Paul
SMMPA
F
2009-1027
2015-1231
Owatanawa unit No. 5
UN
69
Capacity
21
The following major 100 kV and above facility additions were included in the power flow model because the
new facility was scheduled to be in service after the 2012 Summer season but before 2013 Summer season.
Table 5.0-2: New Major Facility Additions >100 kV
MISO
Operating
Region
Control Area
ISD
Carmel
218 METC
10/15/2012
Carmel
218 METC
6/1/2013
Carmel
218 METC
12/31/2012
Carmel
218 METC
12/31/2012
Carmel
218 METC
12/31/2012
Carmel
218 METC
9/30/2012
Carmel
218 METC
9/30/2012
Carmel
219 ITC
6/1/2013
Carmel
219 ITC
6/1/2013
Carmel
219 ITC
6/1/2013
Project Name - Description
Nelson Road - Loop the existing Nelson Road-Goss
345 kV line into Slate, New Slate substation, Nelson
Road sub work, Goss sub work
Eagles Landing - Eagles Landing Taps the Cottage
Grove - East Tawas 138 kV circuit - Eagles Landing
Taps the Cottage Grove - East Tawas 138 kV circuit
Tompkins - Loop Tompkins-Kipp Rd into new URV
Jct. Station
Alma - New line created by looping the existing
Alma-Summerton 138 kV line into Begole
Summerton - New line created by looping the existing
Alma-Summerton 138 kV line into Begole
Karn - New line created by looping the existing KarnClaremont 138 kV line into Manning
Claremont - New line created by looping the existing
Karn-Claremont 138 kV line into Manning
Wayne 345 kV - replace overloaded station
equipment - replace overloaded station equipment
ClydeTP - Clyde taps the Placid-Durant 120 kV
circuit - Clyde taps the Placid-Durant 120 kV circuit
ScioTP - Scio Taps the Lark-Spruce 120 kV circuit Scio Taps the Lark-Spruce 120 kV circuit
Voltage
(kV)
345
138
138
138
138
138
138
345
120
120
19
MISO Coordinated Seasonal Assessment – 2013 Summer
MISO
Operating
Region
Control Area
ISD
Carmel
219 ITC
5/31/2013
Carmel
219 ITC
6/1/2013
Carmel
219 ITC
6/1/2013
Carmel
219 ITC
11/2/2012
Carmel
219 ITC
11/2/2012
Carmel
295 WEC
8/14/2013
Carmel
314 BREC
12/1/2012
Carmel
314 BREC
12/1/2012
Carmel
357 AMIL
6/1/2013
Carmel
357 AMIL
6/1/2013
Carmel
361 SIPC
9/1/2012
St Paul
600 XEL
12/1/2012
St Paul
600 XEL
6/20/2013
St Paul
600 XEL
6/1/2013
St Paul
600 XEL
6/1/2013
St Paul
600 XEL
6/1/2013
St Paul
608 MP
12/31/2012
St Paul
608 MP
4/1/2013
St Paul
St Paul
608 MP
608 MP
12/31/2012
4/1/2013
St Paul
615 GRE
5/7/2013
St Paul
615 GRE
8/15/2013
Public Version
Project Name - Description
Tahoe - Creates at new Tahoe-Wixom 120
kV;constructs 2.6 miles of 120 kV line circuit
Dexter Twp - Loop Madrid to Majestic 120 kV line
and new breaker station
Dexter Twp - Loop Madrid to Majestic 120 kV line
and new breaker station
Harbor Beach - New line created by looping the
Harbor Beach-Rapson 120 kV line into Minden
Rapson - New line created by looping the Harbor
Beach-Rapson 120 kV line into Minden
Pleasant Prairie - Construct a new Pleasant-Zion
Energy Center 345 kV line
Wilson - 10.5 Mile 161 kV of line from Wilson
Substation to new 161 kV station - only 600 feet of
new construction required.
BR Tap (3 terminal midpoint) - 10.5 Mile 161 kV of
line from Wilson Substation to new 161 kV station only 600 feet of new construction required.
LaFarge - Provide 161 kV supply to customer
substation
Line 1364 (new tap) - Tap 138 kV Line 1364 for 'inout' arrangement, replace Line 1326 w/ 'in-out'
Power Plant - 25-mile 161 kV transmission line from
Southern Illinois Power Cooperative's power plant to
a new 161/69 kV substation - 25-mile 161 kV
transmission line from Southern Illinois Power
Cooperative's power plant to a new 161/69 kV
substation
Stone Lake - New 161 kV line from Stone Lake to
Edgewater
Hiawatha - Double Circuit 1.25 mile line
Park Falls - Install ~1.5 miles of 336 ACSR 115 kV
line
Norrie - The existing 115 kV heading south out of the
Ironwood substation will be re-directed into the
Norrie substation. This will involve removing about a
mile of lattice structures and builting a new mile of
line into the sub. All 100 kV plus line is planned at
795 ACSR.
Norrie - New 336 ACSR line from Norrie to Orvana
mine site.
Boswell - Essar Line 94L Line reroute
Essar Steel Sub (McCarthy Lake) - Essar 94L Line
reroute
Essar Mine Sub (Calumet) - Essar new Line
Boswell - reroute existing MP Line #28
Alexandria SS - Add a new 345 kV line from
Alexandria Switching Station to Waite Park and
terminal works - Add a new 345 kV line from
Alexandria Switching Station to Waite Park and
terminal works
Cedar Mountain - 69 miles of new 345 kV line - new
line
Voltage
(kV)
120
120
120
120
120
345
161
161
161
138
161
161
115
115
115
115
230
230
230
115
345
345
20
MISO Coordinated Seasonal Assessment – 2013 Summer
MISO
Operating
Region
St Paul
Public Version
Control Area
ISD
Project Name - Description
615 GRE
12/31/2012
St Paul
615 GRE
5/1/2013
St Paul
620 OTP
7/1/2013
Northport - New Distribution
Parkers Prairie - Parkers Prairie Conversion from 41.6
to 115 kV
Buffalo 115 kV - Construct new 16-mile 115 kV line
from Buffalo - Casselton
St Paul
627 ITCM
5/1/2013
St Paul
St Paul
635 MEC
635 MEC
4/1/2013
4/1/2013
St Paul
661 MDU
7/31/2013
St Paul
661 MDU
10/31/2012
Salem - 81 miles of new 345 kV line - Construct a
new 345-161 kV dbl ckt line(54 miles) and all new
ROW for 27 miles of new single ckt 345 kV.
Pony Creek - 345 kV line tap
Sugar Creek - 161 kV line tap (tap miles only)
Keystone tap - Radial 115 kV line tapping the BakerCabin Creek 115 kV line
Matheson tap - Radial 115 kV line tapping the
Dickinson Basin-Green River Jct 115 kV line to the
Matheson distribution substation
Voltage
(kV)
115
115
115
345
345
161
115
115
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MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
6.0 STUDY METHODOLOGY
The following power system analysis software tools were utilized: Siemens PTI’s PSS/e (ver32.05), MUST
(ver11.1) and Powertech’s Voltage Security Assessment Tool (VSAT), ver12.0.
6.1 Steady State AC Contingency Analysis
Siemens PTI’s MUST ver11.1 program was used to analyze the steady-state voltage levels and thermal
loadings of the MISO footprint under base case transfers for system intact and contingency conditions. MISO’s
three operating regions, greater than 60 kV, were analyzed for category B and C contingencies. Also, the entire
MISO tier-1 footprint was analyzed for both category B and C contingencies. Single generator outages and
double generator outages by control area were examined. Automated category C3 analysis was performed
across the MISO’s three operating regions, for 200 kV and above facilities, using double branch and double-tie
contingency specifications by MISO operating Region. Some neighboring system contingencies were also
analyzed, if included by members or non-member participants.
The MUST solutions options used in the thermal and voltage analysis is shown below in Table 6.1-1. The
analyses were conducted enabling transformer taps and switched shunts. These settings were chosen as they
represent the post-contingency steady state condition, which is assumed to be at a time when all operator
actions have been deployed in order to maintain/re-establish system security levels. The MUST’s default
dispatch option (governor control dispatch) was used to specify that all MISO and adjacent control area
generators would respond to a generator outage, not just the system swing bus.
Table 6.1-1: MUST Options used for ACCC Analysis
MUST AC Load Flow Solution Options
Tap Adjustments
Area Interchange Control
Mvar Limits
AC LF Method
Non Divergent LF
Stepping
Disabled
Apply immediately
Full Newton
Only If Normal Diverged
Solution Options
Phase Shift Adjustment
General Solution Options
Maximum Load Flow Iterations
20
MW/Mvar tolerance
1
Reactive Adj. De-acceleration Factor
0.9
Low Voltage Break Point
Max Iteration to freeze adjustment
0.7
99
22
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
6.2 FCITC Transfer Analysis
The bulk transmission systems of the MRO, RFC and SERC regions were evaluated using linear analysis to
identify congested transmission facilities for large scale transfers of energy in the Regional Reliability
Organizations’ (RRO’s) respective seasonal assessments. In order to avoid duplication of effort, the CSA study
team selected several system transfers based on historical transfers seen on the system. The analysis was
intended to identify those facilities that may become heavily loaded for both base case and first contingent
cases with the transfer applied. This transfer may simulate the system’s ability to replace needed generation for
a possible outage of a large base load plant. The MISO Transfer Capability Methodology was followed in this
analysis.
This study report identifies any assets that may be required to operate beyond the limits specified below, which
applies to both transmission and generation contingencies.
Table 6.2-2: Transfer Distribution Factor Cutoff
Transfer Case
Equipment Rating Applied
Transfer Distribution Factor
Base
Normal
> 3%
First Contingency Outage
Emergency
> 3%
Transfer scenarios were modeled as either area generation shifts (i.e. reducing generation in study area) or as
area load shifts (i.e. increasing load in study area). The generation shifts were modelled with the assumption
that the subsystem would only use available generation including off-line units. Machine maximum generation
limits (Pmax) was honored.
6.3 Critical Interface Voltage Stability Analysis
Voltage stability P/V analysis was performed on several critical interfaces either suspected to have potential for
voltage instability under transfer or known to have the potential for voltage instability. The analysis was
performed using Powertech’s VSAT ver12.0. The study was performed by incrementally increasing the energy
transfer and solving a power flow under base and contingent cases until a steady-state voltage violation was
detected, or voltage instability was detected. Interfaces critical to the transfer were monitored and plotted
against critical bus voltages. The VSAT input files may be seen in Appendix F.
6.4 Large Load Area Analysis
Load flow analysis, contingency analysis and VQ curve plotting were performed to study the system voltage
performance of the large load areas. The study methodology was classified into two phases:

Phase 1: Identification of critical prior generation outage scenarios, contingencies, and buses to be
monitored through feedback from TOs and MISO RT-Operations, previous reports and/or contingency
analysis with selected single and multiple contingencies for the area of interest.

Phase 2: VQ plotting for the base case, the generator outage cases, the load escalation cases, the load
power factor reduction cases, and the transfer and/or import cases.
23
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
Phase 1
AC contingency analysis was used to identify the critical buses with the lowest voltages and largest voltage
drops. Contingencies included (n-1) and (n-2) events. Contingency analysis was performed on the base case as
well as cases with single and multiple prior outages. No more than three simultaneous outages, either prior or
contingent, were studied.
Once the critical contingencies and buses were identified, VQ plotting was performed to calculate the reactive
margin from the operating point to the instability point. Using the PSS/e program, a fictitious synchronous
condenser was modeled at the critical bus, the scheduled bus voltage was adjusted step-by-step, and the
corresponding reactive power of the fictitious synchronous condenser was recorded. A VQ curve was then
plotted for this bus, which served as a reference curve for the sensitivity cases created in the Phase 2.
Phase 2
VQ curves were also plotted for the following system conditions:

Base case conditions

Selected generator/transmission prior outage scenarios

Load escalation scenarios - a 5% increase in the total summer peak load for the area of interest

Load power factor reduction scenarios - a 2% total load power factor reduction and a 4% total load
power factor reduction to address the load forecasting uncertainty and reactive power uncertainty.
Excessively hot weather may produce a larger than predicted load within the uncertainty factor.
It should be noted that contingency screenings were run on the sensitivity cases defined above as well as the
base case in order to determine if the scenarios created any additional thermal loadings or voltage levels outside
of the criteria.
24
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
7.0 STEADY-STATE ANALYSIS RESULTS
7.1 Summary
In general, the MISO transmission system is projected to perform well. There are a number of contingencies
that may require operator action to avoid potential overloads or low voltages during the 2013 Summer peak
season. There were zero category A violations and 100 category B contingency violations found in MISO’s
BPS (>100 kV).
Operational procedures were identified for all category A and B thermal and voltage
violations. These contingencies have been tabulated with the actions required to address these potential issues.
The steady-state AC contingency analysis results may be seen in Appendix B.
7.2 Prior Outages to Watch
There are a number of frequently reoccurring contingencies among the category C3 AC contingency analysis
results. If the contingency occurred just one time in a category C3 pair, these were flagged as prior outages to
watch. With an outage of one of the facilities2 there is a possibility for a thermal overload to occur with the
next contingency. Note the area number may be associated with the contingent limiter (limiting element), not
the prior outage elements. The complete list of category C results is provided in Appendix B.
2 Prior Outage Critical Facilities list is shown in the non-public version of this report.
25
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.0 TRANSFER ANALYSIS RESULTS
There were seventeen transfers analyzed for the 2013 Summer peak period. The First Contingency Incremental
Transfer Capability (FCITC) for each transfer was calculated, along with the Transfer Distribution Factor
(TDF) on some crucial flowgates. Typical tested transfer level is 5,000 MW which is a high transfer. A
graphic of the transfer and associated constraint location are shown on a geographic map. The flowgates
analyzed in this section3 were monitored for potential bottlenecks across the transmission system.
New
flowgates in the MISO South Region and neighboring entities to MISO South were monitored. The transfer
capability values obtained from this evaluation are not used for OASIS posting purposes.
3 Flowgate definitions are only available in the non-public version of this report.
26
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.1 Carmel Region to St. Paul Region
A high transfer from MISO Carmel Region to MISO St.
Paul Region was analyzed. The observed intra-Regional transfer capability of 1,900 MW is determined to be
adequate for this upcoming summer season. The limiting element for this transfer was the [ALTW] Grand
Mound—[ALTW] Maquoketa 161 kV line under a category B contingency event. The transfer capability of
1,900 MW is an increase from the 2012 Summer CSA in which transfer capability was observed at 1,550 MW
for the same transfer. This limit has shifted to Iowa due to outages related to the construction of the [ALTW]
Salem—[ALTW] Hazleton 345 kV line. The new limit is due to a NERC Alert that derated this line. Also, the
increase in Transfer Capability is due to Sherburne County unit No. 3 being back on line.
Table 8.1-1: Carmel Region to St. Paul Region
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
Carmel Region to St. Paul Region
1,900
[ALTW] Grand Mound—[ALTW] Maquoketa 161 kV line
3.00%
57 MW
109 MW
166 MW
168 MVA
NERC Category B
As shown below on Table 8.1-2 this transfer had a significant impact on the following flowgates.
Table 8.1-2: Transfer Impact on Flowgates
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
FG 3810: Werner West—Werner 138 kV line (flo)
NERC Category B Contingency
-83
-190
7.8
FG 6183: Quad Cities—Sub 91 345 kV line (flo)
NERC Category B Contingency
641
847
10.7
FG 6001: NDEX
FG 6193: MWEX
96
739
-128
12
17
Flowgate
409
27
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.2 Carmel Region + SPP to NW Dakotas
A high transfer from the southwest portion of MISO’s
Carmel region and SPP to the northwest Dakotas portion of the MISO St. Paul region was analyzed.
The
observed inter-Regional transfer capability is 1,600 MW for this upcoming Summer season. The limiting
element for this transfer was the [ALTW] Lime Creek—[ALTW] Emery 161 kV line No. 1 for a category B
contingency event. The transfer capability of 1,600 MW is a decrease from the 2012 Summer CSA in which
transfer capability was observed at 1,900 MW for the same transfer. This limit has shifted to Iowa due to
outages related to the construction of the [ALTW] Salem—[ALTW] Hazleton 345 kV line. The limit is new
this Summer due to a NERC Alert that derated this line. Also, the increase in Transfer Capability is due to
Sherburne County unit No. 3 being back on line.
Table 8.2-1: Carmel Region + SPP to NW Dakotas
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
Carmel Region + SPP to NW Dakotas
1,600
[ALTW] Lime Creek—[ALTW] Emery 161 kV line No. 1
3.00%
48 MW
133.5 MW
181.5 MW
185 MVA
NERC Category B Contingency
As shown below on Table 8.2-2 this transfer had a significant impact on the following flowgates.
Table 8.2-2: Transfer Impact on Flowgates
Flowgate
FG 3810: Werner—Werner 138 kV line (flo)
NERC Category B Contingency
FG 3706: Arnold—Hazleton 345 kV line_PTDF
FG 3529: North Appleton—Werner West 345 kV line
PTDF
FG 6193: MWEX
FG 6001: NDEX
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-83
-332
6.4
227
385
9
406
620
13
739
96
468
-209
16
18
28
MISO Coordinated Seasonal Assessment – 2013 Summer
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8.3 St. Paul Region to Carmel Region
A high transfer from the MISO St. Paul region to the MISO
Carmel region was analyzed. The observed intra-Regional transfer capability is 1,800 MW for this upcoming
Summer season. The limiting element for this transfer was the [CE] Byron Red—[CE] Cherry Valley Red 345
kV line for a category B contingency event. The transfer capability of 1,800 MW is a decrease from the 2012
Summer CSA in which transfer capability was greater than 5,000 MW for the same transfer. The decrease in
transfer capability from the 2013 Summer limit is due to several system condition changes from last Summer.
First, the Sherburne County unit No. 3 is back online. Second, the Salem—Hazleton 345 kV line is in service.
Finally, there was a shift in the CE summer peak interchange from exporting 2,800 MW (last Summer) to
importing 50 MW.
Table 8.3-1: St. Paul Region to Carmel Region
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
St. Paul Region to Carmel Region
1,800 MW
[CE] Byron Red—[CE] Cherry Valley Red 345 kV line
4.50%
81 MW
1,394
1,475 MW
1,479 MVA
NERC Category B Contingency
As shown below on Table 8.3-3 this transfer had a significant impact on the following flowgates.
Table 8.3-2: Transfer Impact on Flowgates
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
FG 3810: Werner—Werner 138 kV line (flo)
NERC Category B Contingency
-83
33
6
FG 6183: Quad Cities—Sub 91 345 kV line (flo)
NERC Category B Contingency
641
474
8.9
FG 6001: NDEX
FG 6193: MWEX
96
739
270
1,013
9
14.5
Flowgate
29
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.4 MISO Indiana/Illinois to TVA
A high transfer from the MISO Indiana and Illinois states to
TVA was analyzed.
The observed inter-Regional transfer capability is greater than 5,000 MW for this
upcoming Summer season.
Table 8.4-1: MISO Indiana/Illinois to TVA
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
MISO Indiana/Illinois to TVA
>5,000
n/a
n/a
n/a
n/a
n/a
n/a
n/a
As shown below on Table 8.4-2 this transfer had a significant impact on the following flowgates.
Table 8.4-2: Transfer Impact on Flowgates
Flowgate
FG 1624: Summershade—Summershade Tap 161 kV (flo)
NERC Category B Contingency
FG 1625: Summershade—Summershade 161 kV (flo)
NERC Category B Contingency
FG 1617: SNP—Consauga 500 kV (flo)
NERC Category B Contingency
FG 1638: Sans Souci—Dell 500 kV PTDG
FG 1634: Bull Run—Volunteer 500 kV (flo)
NERC Category B Contingency
FG 1613: Volunteer—Phipps Bend 500 kV PTDF
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
150
-14
3.7
150
-14
3.7
447
245
4.5
-576
-983
9
-1,275
-749
11.8
781
188
13
30
MISO Coordinated Seasonal Assessment – 2013 Summer
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8.5 PJM N. Illinois to PJM Ohio
A high transfer from PJM Northern Illinois to PJM Ohio
was analyzed. The observed inter-Regional transfer capability is 1,900 MW for this upcoming Summer season.
The limiting element for this transfer was the [FE] Lakeview—[FE] Ottawa 138 kV line for a category B
contingency event. The transfer capability of 1,900 MW is a slight decrease from the 2012 Summer CSA in
which transfer capability was observed at 2,140 MW for the same transfer. Ameren’s Prairie State generation is
the main contributor in moving this limit out of the MISO system.
Table 8.5-1: PJM N. Illinois to PJM Ohio
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
PJM N. Illinois to PJM Mid-Atlantic (1%)
1,900 MW
[FE] Lakeview—[FE] Ottawa 138 kV line
2.70%
51.3 MW
322 MW
373 MW
375 MVA
NERC Category B Contingency
As shown below on Table 8.5-2 this transfer had a significant impact on the following flowgates.
Table 8.5-2: Transfer Impact on Flowgates
Flowgate
FG 2974: Dune Acres-Michigan City 138 kV PTDF
FG 2520: Dune Acres—Michigan City 138 kV No. 1 (flo)
NERC Category B Contingency
FG 2521: Dune Acres—Michigan City 138 kV No. 2 (flo)
NERC Category B Contingency
FG 3270: State Line—Wolf Lake 138 kV (flo)
NERC Category B Contingency
FG 3271: State Line—Wolf Lake 138 kV (flo)
NERC Category B Contingency
FG 2980: Dune Acres-Michigan City 138 kV (1 &2)
FG 2337: Cook—Palisades 345 kV (flo)
NERC Category B Contingency
FG 106: Cleveland Bowl
FG 2286: Burnham Munster 345 kV line (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-7.5
98
1.9
-24
96
2.1
-24
96
2.1
59
226
3
38
221
3.2
-48
192
4.3
-526
-188
6
1,077
1,428
6.3
-410
237
11.6
31
MISO Coordinated Seasonal Assessment – 2013 Summer
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8.6 MISO IL/MO to MISO South Region & TVA
A high North to South transfer from MISO Illinois and
Missouri states to MISO South Region plus TVA was analyzed.
The observed inter-Regional transfer
capability is 3,700 MW for this upcoming Summer season. The limiting element for this transfer was the
[AMIL] W. Frankfort East—[AMIL] West Frankfort 138 kV for a category B contingency event. The transfer
capability of 3,700 MW is an increase from the 2013 Summer CSA in which a transfer capability was observed
at the maximum generation limit (from source) of 2,800 MW for the same transfer. The increase in transfer
capability from the 2012 Summer is due to an improvement in the source subsystem definition. This time, the
source was a combination of load decrease and generation increase, thus allowing the transfer to go beyond the
2,800 MW of generation capacity that was observed last Summer.
Table 8.6-1: MISO Illinois/Missouri to MISO South Region & TVA
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
MISO Illinois/Missouri to MISO South & TVA
3,700 MW
[AMIL] W. Frankfort East—[AMIL] West Frankfort 138 kV
4.40%
162 MW
141 MW
303 MW
308 MVA
NERC Category B Contingency
As shown below on Table 8.6-2 this transfer had a significant impact on the following flowgates.
Table 8.6-2: Transfer Impact on Flowgates
Flowgate
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
267
400
3.5
392
117
7
-769
-390
10
32
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.7 Missouri to Indiana
A high West to East transfer from Missouri (including
AECI) to Indiana was analyzed.
The observed inter-Regional transfer capability is 3,100 MW for this
upcoming Summer season. The limiting element for this transfer was the [AMIL] Casey—[AMIL] Newton 345
kV line for a category B contingency event. This transfer is slightly different than the one performed last
Summer. Last year, the source subsystem was Illinois sinking into Indiana which observed an intra-Regiona
transfer capability of 4,400 MW. This year, the source subsystem was moved farther west and now includes
Associated Electric (AECI).
Table 8.7-1: Missouri to Indiana
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
Missouri to Indiana
3,100 MW
[AMIL] Casey—[AMIL] Newton 345 kV line
14.00%
434 MW
880 MW
1,314 MW
1,319 MVA
NERC Category B Contingency
As shown below on Table 8.7-2 this transfer had a significant impact on the following flowgates.
Table 8.7-2: Transfer Impact on Flowgates
Flowgate
FG 104: Thomas Hill Trans (flo)
NERC Category B Contingency
FG 3430: St. Louis East Interface
FG 3405: Bunsonville—Eugene 345 kV line PTDF
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
525
445
2.8
58
123
-415
700
16
20
33
MISO Coordinated Seasonal Assessment – 2013 Summer
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8.8 Southern Carmel Region & PJM Ohio to Michigan
A high transfer from the southern portion of MISO
Southern Carmel Region & PJM Ohio sinking into the state of Michigan was analyzed. The observed interRegional transfer capability is greater than 5,000 MW for this upcoming Summer season. This transfer was not
performed last year.
Table 8.8-1: Southern Carmel Region to Michigan
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
Southern Carmel Region & PJM Ohio to Michigan
> 5,000 MW
n/a
n/a
n/a
n/a
n/a
n/a
n/a
As shown below on Table 8.8-2 this transfer had a significant impact on the following flowgates.
Table 8.8-2: Transfer Impact on Flowgates
Flowgate
FG 2337: Cook—Palisades 345 kV_PTDF
Pre-Cont
Pre-Transfer
(MW)
-526
Post-Cont
Post-Transfer
(MW)
TDF
(%)
323
28
34
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.9 MISO Southern Carmel Region to IESO
A high transfer from MISO Southern Carmel region to
IESO was analyzed. The observed inter-Regional incremental transfer capability of 350 MW is determined to
be adequate for this upcoming summer season. The limiting element for this transfer was the [IESO] Lambton
TS—[IESO] Lambton GS 220 kV line for the category C contingency event. This contingency is category C in
accordance with the NPCC transmission operating criteria which requires IESO to consider Category C
contingencies in addition to Category B contingencies in the operation of the Bulk Power System (BPS, as
defined by NPCC).
All Michigan/IESO PARs are inservice. The model used for this transfer already had a 1,200 MW MISO to
IESO bias across the controlled interface with the PARs set to control these flows at this level.
The
combination of the 1,200 MW plus the 350 MW transfer capability (shown below) means the total transfer
capability from MISO to IESO is 1,550 MW.
Table 8.9-1: MISO Southern Carmel Region to IESO
Transfer
FCTTC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
S. Carmel Region to IESO
350 + 1,200 = 1,550 MW
[IESO] Lambton TS—[IESO] Lambton GS 220 kV line
26.00%
91 MW
743 MW
834 MW
845 MVA
NERC Category C Contingency
As shown below on Table 8.9-2 this transfer had a significant impact on the following flowgates.
Table 8.9-2: Transfer Impact on Flowgates
Flowgate
Interface 9: Ontario-Michigan
Interface 10: Ontario-New York
Pre-Cont
Pre-Transfer
(MW)
-1,200
-19
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-1,370
-199
49
46
35
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.10 IESO to MISO Southern Carmel Region
A high transfer from IESO to the MISO Southern Carmel
Region was analyzed. The observed inter-Regional incremental transfer capability of -50 MW is determined to
be adequate for this upcoming summer season. The limiting element for this transfer was the [IESO] Lambton
TS—[IESO] Lambton GS 220 kV line for the category C contingency event. This contingency is category C in
accordance with the NPCC transmission operating criteria which requires IESO to consider Category C
contingencies in addition to Category B contingencies in the operation of the Bulk Power System (BPS, as
defined by NPCC).
All 4 Michigan/IESO PARs are in service. The model used for this transfer already had a 1,500 MW IESO-toMISO bias across the controlled interface with the PARs set to control these flows at this level.
The
combination of the 1,500 MW plus the (-50) MW transfer capability (shown below) means the total transfer
capability from IESO to MISO is 1,450 MW. For the contingency loss shown below, SPS action with
generation rejection of only one unit was considered. With generation rejection of additional units, through SPS
action, the total transfer capability from IESO to MISO would increase.
Table 8.10-1: IESO to MISO Southern Carmel Region
Transfer
FCTTC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
IESO to S. Carmel Region
-50 + 1,500 = 1,450 MW
[IESO] Lambton TS—[IESO] Lambton GS 220 kV line
33.00%
-16.5 MW
861 MW
844 MW
845 MVA
NERC Category C Contingency
As shown below on Table 8.10-2 this transfer had a significant impact on the following flowgates.
Table 8.10-2: Transfer Impact on Flowgates
Flowgate
Interface 9: Ontario-Michigan
Interface 10: Ontario-New York
Pre-Cont
Pre-Transfer
(MW)
1,500
-6
Post-Cont
Post-Transfer
(MW)
TDF
(%)
1,472
-27
55
41
36
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.11 Entergy Texas + AEPW to Southern Company
A West to East transfer from Entergy Texas plus AEPW to
Southern Company through MISO’s Southern Region was analyzed. The observed inter-Regional transfer
capability is 2,950 MW for this upcoming Summer season. The limiting element for this transfer was the [EES]
Grimes—[EES] Mount Zion 138 kV line for a category B contingency event. This transfer was not performed
in the 2012 Summer assessment. This transfer limit is close to the 3,000 MW test level of what Entergy would
evaluate at. Entergy has a project in its 2013-2017 Construction Plan, the Grimes—Ponderosa 230 kV line
Project, which will alleviate this constraint. This project, which includes the construction of approximately 39
miles of new 230 kV transmission in the Western Region of Entergy Texas is currently planned to be placed in
service by the summer of 2016.
Table 8.11-1: Entergy Texas + AEPW to Southern Company
Transfer
Entergy Texas + AEPW to Southern Company
FCITC
2,950
Limiting Element
[EES] Grimes—[EES] Mount Zion 138 kV line
TDF(%) on the Limiting Element
3.10%
FCITC Flow on the Limiting Element
91.5 MW
Base Flow on the Limiting Element
112 MW
Limiting flow on the Limiting Element
204 MW
Summer Emergency Rating
206 MVA
Contingency Description
NERC Category B Contingency
As shown below on Table 8.11-2 this transfer had a significant impact on the following flowgates.
Table 8.11-2: Transfer Impact on Flowgates
Flowgate
FG 16272: Nelson 500/230 KV Transformer (flo)
NERC Category B Contingency
FG 18135: Big Cajun—Fancy Point 500 kV (flo)
NERC Category B Contingency
FG 17965: Champaigne—Bobcat 138 KV Line (flo)
NERC Category B Contingency
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
FG 17408: Cypress 500/138 kV Transformer (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-75
-328
8
1,416
1,942
18
69
225
5
267
100
6
-769
-374
13
392
936
18
381
217
6
37
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.12 S. MISO South Region to MISO IN/IL
A high South to North transfer from the Southern portion of
MISO South region sinking into MISO Indiana and Illinois region was analyzed. The observed inter-Regional
transfer capability was found to be greater than the 1,400 MW transfer test level. The limiting element for this
transfer was the [EES] Winnfield 230/115 kV Transformer No. 1 for a category B contingency event. This
transfer was not performed in the 2012 Summer assessment.
Table 8.12-1: Southern Portion of MISO South Region to MISO IN/IL
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
S. MISO Southern Region to MISO IN/IL
1,400 MW
[EES] Winnfield 230/115 kV Transformer No. 1
4.50%
63 MW
237 MW
300 MW
300 MVA
NERC Category B Contingency
As shown below on Table 8.12-2 this transfer had a significant impact on the following flowgates.
Table 8.12-2: Transfer Impact on Flowgates
Flowgate
FG 16272: Nelson 500/230 KV Transformer (flo)
NERC Category B Contingency
FG 18135: Big Cajun—Fancy Point 500 kV (flo)
NERC Category B Contingency
FG 17965: Champaigne—Bobcat 138 KV Line (flo)
NERC Category B Contingency
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
FG 17408: Cypress 500/138 kV Transformer (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-75
-328
8
1,416
1,942
18
69
225
5
267
100
6
-769
-374
13
392
936
18
381
217
6
38
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.13 MISO South Region to TVA
A high transfer from MISO South Region to TVA was
analyzed. The observed inter-Regional transfer capability is 3,100 MW for this upcoming Summer season. The
limiting element for this transfer was the [EES] West Memphis 500/161 kV Transformer for a category B
contingency event. This transfer was not performed in the 2012 Summer assessment.
Table 8.13-1: MISO Southern Region to TVA
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
MISO South Region to TVA
3,100 MW
[EES] West Memphis 500/161 kV Transformer
3.30%
102 MW
345 MW
447 MW
450 MVA
NERC Category B Contingency
As shown below on Table 8.13-2 this transfer had a significant impact on the following flowgates.
Table 8.13-2: Transfer Impact on Flowgates
Flowgate
FG 16272: Nelson 500/230 KV Transformer (flo)
NERC Category B Contingency
FG 18135: Big Cajun—Fancy Point 500 kV (flo)
NERC Category B Contingency
FG 17965: Champaigne—Bobcat 138 KV Line (flo)
NERC Category B Contingency
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
FG 17408: Cypress 500/138 kV Transformer (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-75
-328
8
1,416
1,942
18
69
225
5
267
100
6
-769
-374
13
392
936
18
381
217
6
39
MISO Coordinated Seasonal Assessment – 2013 Summer
Public Version
8.14 TVA to MISO South Region
A high North to South transfer from Tennessee Valley
Authority (TVA) to MISO South region was analyzed. The observed inter-Regional transfer capability is 1,400
MW for this upcoming Summer season. The limiting element for this transfer was the [EES] Freeport—[EES]
Twinkletown 230 kV line for a category B contingency event. This transfer was not performed in the 2012
Summer assessment.
Table 8.14-1: TVA to MISO South Region
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
TVA to MISO South Region
1,400 MW
[EES] Freeport—[EES] Twinkletown 230 kV line
3.30%
46.2 MW
414 MW
460 MW
462 MVA
NERC Category B Contingency
As shown below on Table 8.14-2 this transfer had a significant impact on the following flowgates.
Table 8.14-2: Transfer Impact on Flowgates
Flowgate
FG 16272: Nelson 500/230 KV Transformer (flo)
NERC Category B Contingency
FG 18135: Big Cajun—Fancy Point 500 kV (flo)
NERC Category B Contingency
FG 17696: Fancy 500/230 kV Transformer (flo)
NERC Category B Contingency
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-75.0
-19.0
3.8
1416.0
1276.0
9.6
-586.0
-687.0
6.9
267.0
402.0
9.3
-769.0
-601.0
11.5
392
111
19.3
40
MISO Coordinated Seasonal Assessment – 2013 Summer
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8.15 MISO South Region to PJM Mid-Atlantic
A high South to North transfer from MISO South Region to
PJM Mid-Atlantic was analyzed.
The observed inter-Regional transfer capability is 2,900 MW for this
upcoming Summer season. The limiting element for this transfer was the [EES] West Memphis 500/161 kV
Transformer for a category B contingency event. This transfer was not performed in the 2012 Summer
assessment.
Table 8.15-1: MISO’s South Region to PJM Mid-Atlantic
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
MISO South Region to PJM Mid-Atlantic
3,200 MW
[EES] West Memphis 500/161 kV Transformer
3.20%
102 MW
345 MW
447 MW
450 MVA
NERC Category B Contingency
As shown below on Table 8.15-2 this transfer had a significant impact on the following flowgates.
Table 8.15-2: Transfer Impact on Flowgates
Flowgate
FG 16272: Nelson 500/230 KV Transformer (flo)
NERC Category B Contingency
FG 18135: Big Cajun—Fancy Point 500 kV (flo)
NERC Category B Contingency
FG 17696: Fancy 500/230 kV Transformer (flo)
NERC Category B Contingency
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-75.0
-19.0
3.8
1416.0
1276.0
9.6
-586.0
-687.0
6.9
267.0
402.0
9.3
-769.0
-601.0
11.5
392
111
19.3
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8.16 Southern Company to AEPW + Entergy Texas
A high East to West transfer from Southern Company to
AEPW and Entergy Texas was analyzed. The observed inter-Regional transfer capability is 2,100 MW for this
upcoming Summer season. The limiting element for this transfer was the [CLECO] Montgomery—[CLECO]
Clarence 230 kV line for a category B contingency event. This transfer was not performed in the 2012 Summer
assessment.
Table 8.16-1: Southern Company to AEPW + Entergy Texas
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
Southern Company to AEPW & Entergy Texas
2,100 MW
[CLECO] Montgomery—[CLECO] Clarence 230 kV line
3%
63 MW
344 MW
407 MW
414 MVA
NERC Category B Contingency
As shown below on Table 8.16-2 this transfer had a significant impact on the following flowgates.
Table 8.16-2: Transfer Impact on Flowgates
Flowgate
FG 16272: Nelson 500/230 KV Transformer (flo)
NERC Category B Contingency
FG 18135: Big Cajun—Fancy Point 500 kV (flo)
NERC Category B Contingency
FG 17965: Champaigne—Bobcat 138 KV LINE (flo)
NERC Category B Contingency
FG 18207: Lakeover 500/115 kV Transformer (flo)
NERC Category B Contingency
FG 17272: El Dorado EHV—Sterlington 500 kV PTDF
FG 16451: Mabelvale—Kn Wrightsville 500 kV line (flo)
NERC Category B Contingency
FG 17408: Cypress 500/138 kV Transformer (flo)
NERC Category B Contingency
Pre-Cont
Pre-Transfer
(MW)
Post-Cont
Post-Transfer
(MW)
TDF
(%)
-75
171
11
1,416
982
20
69
-58
6
267
393
6
-769
-1,023
12
392
5
18
381
546
8
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8.17 PJM Ohio to PJM Northern Illinois
A high East to West transfer from PJM Ohio to PJM
Northern Illinois was analyzed. The observed inter-Regional transfer capability is 1,500 MW for this upcoming
Summer season. The limiting element for this transfer was the [CE] Kincaid—[AMIL] Pana 345 kV line for a
category B contingency event. This transfer was not performed in the 2012 Summer assessment.
Table 8.17-1: PJM Ohio to PJM Northern Illinois
Transfer
FCITC
Limiting Element
TDF(%) on the Limiting Element
FCITC Flow on the Limiting Element
Base Flow on the Limiting Element
Limiting flow on the Limiting Element
Summer Emergency Rating
Contingency Description
PJM Ohio to PJM Northern Illinois
[CE] Kincaid—[AMIL] Pana 345 kV line
1,500 MW
6.00%
90 MW
1,101 MW
1,191 MW
1,195 MVA
NERC Category B Contingency
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9.0 CRITICAL INTERFACE ANALYSIS RESULTS
Critical interface voltage stability analysis (P/V analysis) was performed on areas that are either known to
experience voltage stability limits under some operating conditions or are suspected to experience potential
voltage stability limits. All results displayed in Sections 9.1 through 9.5 are reflected to interface flows. The
areas analyzed were as follows:





MWEX Interface
S. Louisiana HV Interface
Down Stream of Gypsy (DSG) HV Interface
MISO South’s Western HV Interface
St. Louis South Interface
Voltage instability may occur fast or slow. If voltage instability occurs fast, there may not be time for
transformer tap adjustment, capacitor bank switching, and phase shifter MW flow control. For the voltage
stability study, transformer taps, switched shunts, and phase shifters are all locked after the contingency. So the
calculated voltage stability limit may be conservative.
For the voltage violation study, transformer taps, switched shunts, and phase shifters may all be adjusted after
the contingency. This provides a reasonable transfer level for identifying voltage violations. Please refer to
Appendix C for complete results of the five critical interfaces studied.
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9.1 Minnesota-Wisconsin Export (MWEX)
Twin
Cities
Metro
The Wisconsin Upper Michigan System (WUMS)
has experienced low steady state voltages and has been susceptible to potential voltage instability during heavy
transfers from Minnesota into and through Wisconsin. This interface was studied with the Sherburne County
unit No. 3 online. It was later discovered that it will be offline again for the 2013 Summer season. It is
expected that the MWEX results to be similar to the 2012 Summer CSA in which this interface was analyzed
with Sherburne County unit No. 3 offline.
Study Results
The studies include thirty one scenarios, base case and thirty prior outage cases:

Scenario 0 * NERC Category A: The category A voltage stability limit for the MWEX Interface
is determined to be 1,790 MW for loss of a category B contingency event. The MWEX flows are
measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This 1,790 MW limit is a
slight decrease from the prior year result of 1,816 MW as reported in the 2012 Summer CSA.

Scenario 1 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,406 MW for loss of a category B contingency event.
The MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
prior outage was not performed in the 2012 Summer CSA.

Scenario 2 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 783 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This 783
MW limit is a slight decrease from the prior year result of 870 MW as reported in the 2012
Summer CSA.

Scenario 3 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,465 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
1,465 MW limit is a slight decrease from the prior year result of 1,596 MW as reported in the
2012 Summer CSA.
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MISO Coordinated Seasonal Assessment – 2013 Summer

Public Version
Scenario 4 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,158 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
1,158 MW limit is a slight decrease from the prior year result of 1,247 MW as reported in the
2012 Summer CSA.

Scenario 5 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,789 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
prior outage was not performed in the 2012 Summer CSA.

Scenario 6 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,745 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
prior outage was not performed in the 2012 Summer CSA.

Scenario 7 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,697 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 8 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,790 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 9 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,067 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA. See Figure 9.1-8 below for PV plot.

Scenario 10 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,684 MW for loss of a category B contingency event.
The MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
1,684 MW limit is a slight increase from the prior year result of 1,967 MW as reported in the
2012 Summer CSA.

Scenario 11 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,743 MW for loss of a category B contingency event.
The MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
was not performed in the 2012 Summer CSA.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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Public Version
Scenario 12 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,648 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 13 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,272 MW for loss of the a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
1,272 MW limit is a slight increase from the prior year result of 1,624 MW as reported in the
2012 Summer CSA.

Scenario 14 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,696 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 15 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,659 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
1,659 MW limit is a slight increase from the prior year result of 1,889 MW as reported in the
2012 Summer CSA.

Scenario 16 * NERC Category C Prior Outage: The category C voltage stability limit for the
MWEX Interface is determined to be 1,677 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 17 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,640 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 18 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,662 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 19 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,479 MW for loss of a category B contingency event.
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MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 20 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,452 MW for loss of a category B contingency event.
The MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
was not performed in the 2012 Summer CSA.

Scenario 21 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,519 MW for loss of a category B contingency event.
The MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
was not performed in the 2012 Summer CSA.

Scenario 22 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,311 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA. See Figure 9.1-12 below for PV plot.

Scenario 23 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,760 MW for loss of the a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 24 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,763 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 25 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,525 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 26 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,547 MW for loss of a category B contingency event.
MWEX flows are measured at the Apple River 161 kV bus. This was not performed in the 2012
Summer CSA.

Scenario 27 NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,711 MW for loss of a category B contingency event.
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MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 28 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,704 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This
1,704 MW limit is a slight increase from the prior year result of 1,700 MW as reported in the
2012 Summer CSA.

Scenario 29 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,764 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.

Scenario 30 * NERC Category B Prior Outage: The category B voltage stability limit for the
MWEX Interface is determined to be 1,756 MW for loss of a category B contingency event.
MWEX flows are measured at the Arrowhead 230 kV bus and A.S. King 345 kV bus. This was
not performed in the 2012 Summer CSA.
9.2 Southern Louisiana HV Interface
A
P/V
analysis was performed to examine the impact of excess generation from Northern Louisiana and
Arkansas moving south into the southern portion of Louisiana. The S. Louisiana HV interface supports
70% of MISO South’s total load. The S. Louisiana HV interface is comprised of fourteen HV lines
which support the southern portion of MISO South’s load.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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Study Results
The studies include six scenarios, base case and five prior outage cases:

Scenario 0 * Base Case: There was no voltage stability limit observed on the S. Louisiana HV
interface for loss of a category B contingency event. The maximum generation level of 3,600 MW
was reached in the source subsystem prior to any thermal overloads.

Scenario 1 * NERC Category B Prior Outage: There was no voltage stability limit observed on the S.
Louisiana HV interface for loss of a category B contingency event. The maximum generation level of
3,600 MW was reached in the source subsystem prior to any thermal overloads.

Scenario 2 * NERC Category B line Prior Outage: There was no voltage stability limit observed on the
S. Louisiana HV interface for loss of a category B contingency event. The maximum generation level
of 3,600 MW was reached in the source subsystem prior to any thermal overloads.

Scenario 3 * NERC Category B Prior Outage: There was no voltage stability limit observed on the S.
Louisiana HV interface for loss of a category B contingency event. The maximum generation level of
3,600 MW was reached in the source subsystem prior to any thermal overloads.

Scenario 4 * NERC Category B Prior Outage: There was no voltage stability limit observed on the S.
Louisiana HV interface for loss of a category B contingency event. The maximum generation level of
3,600 MW was reached in the source subsystem prior to any thermal overloads.

Scenario 5 * NERC Category B Prior Outage: There was no voltage stability limit observed on the S.
Louisiana HV interface for loss of a category B contingency event. The maximum generation level of
3,600 MW was reached in the source subsystem prior to any thermal overloads.
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9.3 Down Stream of Gypsy HV Interface
Lake
Pontchartrain
Gulf
Of
Mexico
DSG
The DSG (Down Stream of
Gypsy) Region of Entergy is a subset of the Amite South load pocket and includes the area in and around metro
New Orleans. The DSG Region is supported by five 230 kV lines plus two 138 kV lines from the north and
west; however, only two of the four 138 kV lines were used in the interface definition. Under extreme
conditions the DSG Region can become a voltage constrained area. DSG generation consist of resources at
Ninemile and Michoud. The Slidell—Front Street 230 kV line is a long line supporting DSG from the North
and may be susceptible to voltage issues under one of the prior outages being considered below.
Study Results
The studies include five scenarios, base case and four prior outage cases:

Scenario 0 * Base Case: The category C3 voltage stability limit for the DSG HV interface is
determined to be 2,638 MW for the loss of a category C3 contingency event. The DSG voltage is
measured at the Fourchon 115 kV bus. This interface was not analyzed in the 2012 CSA.

Scenario 1 * NERC Category B Prior Outage: The category C3 voltage stability limit for the DSG HV
interface is determined to be 2,523 MW for the loss of a category C3 contingency event. The DSG
voltage is measured at the Fourchon 115 kV bus. This interface was not analyzed in the 2012 CSA.

Scenario 2 * NERC Category B Prior Outage: The category C3 voltage stability limit for the DSG HV
interface is determined to be 1,874 MW for the loss of a category C3 contingency event. The DSG
voltage is measured at the Fourchon 115 kV bus. This interface was not analyzed in the 2012 CSA.

Scenario 3 * NERC Category B Prior Outage: The category C3 voltage stability limit for the DSG HV
interface is determined to be 2,129 MW for the loss of a category C3 contingency event. The DSG
voltage is measured at the Fourchon 115 kV bus. This interface was not analyzed in the 2012 CSA.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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Public Version
Scenario 4 * NERC Category B Prior Outage: The category C3 voltage stability limit for the DSG HV
interface is determined to be 2,005 MW for the loss a category C3 contingency event. The DSG
voltage is measured at the Fourchon 115 kV bus. This interface was not analyzed in the 2012 CSA.
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9.4 MISO South’s Western HV Interface
Houston Metro
The Western Region of Entergy is a subset
of the WOTAB (West Of The Atchafalaya Basin) Region supported by one 345 kV line from the North, two
230 kV lines and five 138 kV lines from the East. The Western Region is a voltage dependent area. Generation
in the area consists of Entergy resources at Lewis Creek and external resources at Frontier and San Jacinto
(Pelican Road).
These resources make up for approximately 1,020 MW.
Peak load of Western is
approximately 1,800 MW. An N-2 planning criteria is enforced through the use of Required Must Run (RMR)
units.
Study Results
The studies include two scenarios, base case and one prior outage case:

Scenario 0 * Base Case: The category B voltage stability limit for the Western Interface is
determined to be 2,600 MW for the loss of a category B contingency event. The Western
Interface voltages are measured at various 69 kV and 138 kV buses. A 15% safety margin for the
Western interface brings the tolerable transfer limit down to 2,200 MW and is shown below in
each PV plot with the red line.

Scenario 1 NERC Category B Prior Outage: The category B voltage stability limit for the Western
Interface is determined to be 2,200 MW for the loss of a category B contingency event. The
Western Interface flows are measured at various 69 kV and 138 kV buses. A 15% safety margin
for the Western interface brings the tolerable transfer limit down to 1,870 MW and is shown
below in each PV plot with the red line.
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9.5 St. Louis South Interface
St. Louis Metro
A P/V analysis was performed to examine the impact
of light St. Louis Metro load scenario in which excess generation moved south to north higher than forecasted
load levels to the south of St. Louis Metro area. The St. Louis Missouri area voltage levels of selected buses
within the St. Louis metro area were monitored. The St. Louis South Interface is calculated and monitored,
which consists of the following lines:
Study Results
The studies include four scenarios, base case and three prior outage cases:

Scenario 0 * Base Case: There was no voltage stability limit observed on the St. Louis South interface.
The maximum generation level of 5,000 MW was reached in the source subsystem prior to any
thermal overloads.

Scenario 1 * NERC Category B Prior Outage: There was no voltage stability limit observed on the St.
Louis South interface. The maximum generation level of 5,000 MW was reached in the source
subsystem prior to any thermal overloads.

Scenario 2 * NERC Category B Prior Outage: There was no voltage stability limit observed on the St.
Louis South interface. The maximum generation level of 5,000 MW was reached in the source
subsystem prior to any thermal overloads.

Scenario 3 * NERC Category B Prior Outage: There was no voltage stability limit observed on the St.
Louis South interface. The maximum generation level of 5,000 MW was reached in the source
subsystem prior to any thermal overloads.
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10.0 LARGE LOAD AREA ANALYSIS RESULTS
Objectives

Determine for a defined load/generation area:

Minimum voltages at critical buses relative to voltage stability margin criteria

Critical bus and voltage at point of voltage instability

Reactive power margin between post contingency operating point and point of voltage
instability on a V-Q curve

Adequacy of operating and reactive power resources for the defined areas for 2013 Summer

Examine contingent events to find the limits of the system

Indication of what action (s) may be beneficial to prevent voltage instability for multiple contingency
conditions involving generators, transmission lines/ transformers
Five Large Load Areas were selected for analysis in this assessment:

Vectren and Big Rivers Metro

WOTAB area

Little Rock Metro

Indianapolis Metro

Detroit Metro
Areas are subject to voltage instability when there is inadequate reactive Mvar supply. This may be due to key
generator(s) being unavailable due to tripping or being out on maintenance, or transmission contingencies of
lines that serve as the main path of Mvar supply to the load area. The V-Q Curves provide an illustration of the
reactive power margin at the bus that is tested. The Mvar margin is determined by the difference between the
point of instability (knee of the curve) and the zero reactive power point (y-axis). The larger the Q-Margin, the
more stable the bus. The V-Q plots are in Appendix E.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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10.1 Vectren/BREC Combined Metro LLA
Overview
The combination of the Vectren and Big Rivers Electric Corporation (BREC) transmission systems was selected
by MISO Planning & Operations staff for Large Load Analysis. Vectren’s service territory is located in
southwest Indiana, while Big Rivers Electric Corp. (BREC) is in northwest Kentucky and borders Vectren’s
southern territory (See Figure 10.1-1 below). Vectren provides power to the city of Evansville and several
major industrial customers. Big Rivers Electric Corp provides power to its three member cooperatives and the
major industrial customers of Century Aluminum and Rio Tinto Alcan aluminum smelters.
The intent of this analysis is to identify crucial contingencies and the substations (buses) operating personnel
should monitor in the event of an acute transmission system scenario.
Figure 10.1-1: Vectren & BREC Transmission Systems
Vectren/BREC
Metro
Analysis Results
Four scenarios were run to analyse the Mvar injection capability of the Vectren/BREC combined metro area for
the 2013 Summer season. The results of the analysis are shown below in both narrative and tabular format. See
a brief synopsis of the analysis results for each scenario below.
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MISO Coordinated Seasonal Assessment – 2013 Summer

Public Version
Scenario 0 * Base Case * 50/50 Load * PF @ 0.94: The Mvar injection capability for the
Vectren/BREC region is limited to slightly under 100 Mvar of injection at a 138 kV bus for a category
C contingency event.

Scenario 1 * Base Case * 90/10 Load * PF @ 0.90: The Mvar injection capability for the
Vectren/BREC region is is 0.00 Mvar of injection at a 161 kV bus for the category C contingency
event.
There is a standing op-guide to close the Newtonville transformers under this extreme
condition.

Scenario 2 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.90: The Mvar injection
capability for the Vectren/BREC region is is 0.00 Mvar of injection at a 161 kV and 138 kV bus and
the Henderson County 138 kV bus for a category C contingency event. There is a standing op-guide
to close the Newtonville transformers under this extreme condition.

Scenario 3 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.90: The Mvar injection
capability for the Vectren/BREC region is is 0.00 Mvar of injection at a 161 kV and 138 kV bus for a
category C contingency event. There is a standing op-guide to close the Newtonville transformers
under this extreme condition.
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10.2 West Of The Atchafalaya Basin (WOTAB)
Overview
The Entergy WOTAB transmission system was selected by MISO Planning and Operations staff for Large Load
Analysis. WOTAB stands for “West Of The Atchafalaya Basin” and is located in Southeast Texas and
Southwest Louisiana, see Figure 10.2-1 below. The WOTAB Region is a high profile industrial area that
accounts for 25 percent of the total Entergy load.
The intent of this analysis is to identify crucial contingencies and the substations (buses) operating personnel
should monitor in the event of an acute transmission system scenario.
Figure 10.2-1: WOTAB Transmission Systems
Western
Houston
Metro
WOTAB
Louisiana
Texas
Gulf
of
Mexico
Analysis Results
Five scenarios were run to analyse the Mvar injection capability of WOTAB for the 2013 Summer season. The
results of the analysis are shown below in both narrative and tabular format. See a brief synopsis of the analysis
results for each scenario below.

Scenario 0 * Base Case * 50/50 Load * PF @ 0.94: The Mvar injection capability for the WOTAB
Region of Entergy is limited to 287 Mvar of injection at a 138 kV bus for a category C3 contingency
event.
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MISO Coordinated Seasonal Assessment – 2013 Summer
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Public Version
Scenario 1 * Base Case * 90/10 Load * PF @ 0.90: The Mvar injection capability for the WOTAB
Region of Entergy is 0.00 Mvar of injection at the Neches 138 kV bus for a category C3 contingency
event. Also, the Mvar injection capability is reduced to 0.00 Mvar of injection at eight buses
monitored for a category C3 contingency event.

Scenario 2 * Prior Outage of Category B * 90/10 Load * PF @ 0.90: The Mvar injection capability for
the WOTAB Region of Entergy is 0.00 Mvar of injection at eight buses monitored for a category C3
contingency event.

Scenario 3 * Prior Outage of Category B * 90/10 Load * PF @ 0.90: The Mvar injection capability for
the WOTAB Region of Entergy is 0.00 Mvar of injection at a Neches 138 kV bus for a category C3
contingency event. Also, the Mvar injection capability is reduced to 0.00 Mvar of injection at eight
buses monitored for a category C3 contingency event.

Scenario 4 * Prior Outage of Category B * 90/10 Load * PF @ 0.90: The Mvar injection capability for
the WOTAB Region of Entergy is 0.00 Mvar of injection at a 138 kV bus for a category C3
contingency event. Also, the Mvar injection capability is reduced to 0.00 Mvar of injection at eight
buses monitored for a category C3 contingency event.
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10.3 Little Rock Metro Area
Overview
The Little Rock metropolitan area is served by Entergy Arkansas and is geographically located in the middle of
the state of Arkansas, see Figure 10.3-1 below. For the purposes of this study the Little Rock metro area is
defined as all urban areas both north and south of the Arkansas river which runs straight through the city.
Figure 10.3-1: Little Rock Metropolitan Area
Little Rock
Metro
Analysis Results Four scenarios were run to analyse the Mvar injection capability of the Little Rock metro area for the 2013
Summer season. See a brief synopsis of the analysis results for each scenario below.

Scenario 0 * Basecase * 50/50 Load * PF @ 0.98: The Mvar injection capability for the Little
Rock metro is limited to 530 Mvar of injection at a 115 kV bus for a category B contingency
event.

Scenario 1 * Basecase * 90/10 Load * PF @ 0.93: The Mvar injection capability for the Little
Rock metro is limited to 429 Mvar of injection at a 115 kV bus for a category B contingency
event.
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
Public Version
Scenario 2 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.93: The Mvar injection
capability for the Little Rock metro is limited to 430 Mvar of injection at a 115 kV bus for a
category B contingency event.

Scenario 3 * Prior Outage of NERC Categpry B * 90/10 Load * PF @ 0.93: The Mvar injection
capability for the Little Rock metro is limited to 429 Mvar of injection at a 115 kV bus for a
category B contingency event.
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10.4 Indianapolis Metro Area
Overview
The Indianapolis metropolitan area is served by Indianapolis Power and Light (IPL) and is geographically
located in the middle of the state of Indiana, see Figure 10.4-1 below. For the purposes of this study the
Indianapolis metro area is defined as all urban areas within highway 465 which circles Indianapolis completely.
Figure 10.4-1: Indianapolis Metropolitan Area
Indianapolis
Metro
Analysis Results Four scenarios were run to analyse the Mvar injection capability of the Indianapolis Metro area for the 2013
Summer season. The results of the analysis are shown below in both narrative and tabular format. See a brief
synopsis of the analysis results for each scenario below.

Scenario 0 * Base Case * 50/50 Load * PF @ 0.99: The Mvar injection capability for the
Indianapolis Metro is limited to 734 Mvar of injection at a 138 kV bus for a category B
contingency event. The Mvar injection capability for the Indianapolis Metro is limited to 845
Mvar of injection at a 138 kV bus for a category C3 contingency event.

Scenario 1 * Basecase * 90/10 Load * PF @ 0.95: The Mvar injection capability for the
Indianapolis Metro is limited to 552 Mvar of injection at a 138 kV bus for a category B
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contingency event. The Mvar injection capability for the Indianapolis Metro is limited to 633
Mvar of injection at a 138 kV bus for a category C3 contingency event.

Scenario 2 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.95: The Mvar injection
capability for the Indianapolis Metro is limited to 484 Mvar of injection at a 138 kV bus for a
category B contingency event. The Mvar injection capability for the Indianapolis Metro is limited
to 529 Mvar of injection at a 138 kV bus for a category C3 contingency event.

Scenario 3 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.90: The Mvar injection
capability for the Indianapolis Metro is limited to 318 Mvar of injection at a 138 kV bus for a
category B contingency event. The Mvar injection capability for the Indianapolis Metro is limited
to 289 Mvar of injection at a 138 kV bus for a category C3 contingency event.
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10.5 Detroit Metro Area
The Detroit metropolitan area is served by International Transmission Company is geographically located in the
southeast edge of the state of Michigan, see Figure 10.5-1 below. For the purposes of this study the Detroit
metro area is defined as all urban areas inside the Monroe—Wayne—Wixom—Pontiac—Belle River 345 kV
transmission system.
Figure 10.5-1: Detroit Metropolitan Area
Detroit
Metro
Analysis Results Four scenarios were run to analyse the Mvar injection capability of the Detroit Metro area for the 2013 Summer
season. The results of the analysis are shown below in both narrative and tabular format. See a brief synopsis
of the analysis results for each scenario below.

Scenario 0 * Base Case * 50/50 Load * PF @ 0.93: The Mvar injection capability for the Deroit
Metro is limited to approximately 700 Mvar of injection at two 120 kV buses for two category B
contingency events.

Scenario 1 * Basecase * 90/10 Load * PF @ 0.90: The Mvar injection capability for the Deroit
Metro drops below 300 Mvar of injection at several 120 kV buses for three category B
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contingency events. The Mvar injection capability drops below 50 Mvar for one of the category
C5 contingency events.

Scenario 2 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.90: The Mvar injection
capability for the Deroit Metro drops below 150 Mvar of injection at several 120 kV buses for
multiple category B contingency events. The Mvar injection capability drops to 0.00 Mvar for
two category C5 contingency events.

Scenario 3 * Prior Outage of NERC Category B * 90/10 Load * PF @ 0.90: The Mvar injection
capability for the Detroit Metro is drops to 0.00 Mvar of injection at several buses for two
category B contingency events. The Mvar injection capability drops to 0.00 Mvar for two
category C5 contingency events.
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11.0 WIND GENERATION SENSITIVITY ANALYSIS
The total nameplate capacity of wind power generation in the MISO footprint in 2013 Summer is roughly
12,655 MW, as shown below in Table 11.0-1. The table also shows the metered wind generation output at the
time of the peak load for each year. A geographical map of the wind generation units in MISO’s footprint may
be seen in Figure 11.0-1 below. Approximately 90 percent of the wind capacity is concentrated in the high
wind regions in the states of Iowa, Minnesota, and the Dakotas.
Table 11.0-1: MISO Wind Capacity and Output at Peak Load
Summer
Peak Year
Installed
Wind
Capacity
(MW)
2005
Metered Output at
Peak Load hour
MW
% of
Installed
Capacity
907
109
12%
2006
1,251
700
56%
2007
2,064
43
2%
2008
3,085
401
13%
2009
5,636
79
1%
2010
8,179
1,718
21%
2011
9,107
4,200
46%
2012
12,594
1,169
9%
2013
12,655
In the 2013 Summer CSA power flow case, wind generators in the MISO areas were dispatched at 15 percent of
their nameplate capacity. In order to identify potential voltage stability issues due to high wind generation
output from Iowa, Minnesota, and the Dakotas, an abbreviated voltage stability P/V analysis was performed.
To identify potential thermal limits an FCITC was performed.
The methodology used in the P/V analysis was to gradually increase wind generation output, while at the same
time, the same amount of the highest cost peaking generation in MISO was decreased according to merit order.
Specific contingencies in Iowa and other contingencies used for the critical interface voltage stability P/V
analysis of MWEX, and St. Louis South interfaces were included in the analysis. All facilities 100 kV and
greater were monitored across all three MISO operating regions; Carmel Region, South Region and the St. Paul
Region.
In addition, an FCITC analysis was performed using all MISO category B contingencies. The analysis results
may be seen in Table 11.0-2 below, for which the most limiting thermal constraint was found at the transfer
level of 2,500 MW.
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Table 11.0-2: FCITC Constraints found in Illinois
FCITC
(MW)
2,500
Monitored Line
Contingency
[CE] Byron Red—[CE] Cherry Valley 345 kV line
NERC Category B
3,300
[CE] Byron Blue—[CE] Cherry Valley 345 kV line
NERC Category B
Study results and input files may be seen in Appendix G. Below is a geographical map of the wind generation
units in MISO’s footprint.
Figure 11.0-1: MISO Registered Wind Capacity
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12.0 IROL LIMITS
Interconnection Reliability Operating Limits (IROL) are system operating limits which, if violated, could lead
to instability, uncontrolled separation, or cascading outages that adversely impact the reliability of the Bulk
Power System.
All NERC category B and C1, C2, and C5 contingencies from the MUST AC analysis that caused facility
loading of more than 125 percent of the emergency rating were flagged to determine its potential to become an
IROL. The assumption is that cascading or collapse would occur when the monitored element loads to 125
percent or more and trips. All of the aforementioned overloaded elements were screened along with its
associated contingency and independently re-analyzed to find any subsequent overloaded branches (line loading
> 100 percent of emergency rating). Any branches over 100 percent were manually opened and the process was
continued until there were either no overloaded branches or the system collapsed. When the system settles with
no overloads, you add up the load that was shed. If the load shed is less than 1,000 MW then there is no IROL
event.
There were approximately 60 facilities that were evaluated for IROL candidacy in this analysis. Some were not
reported because the facility was below the NERC defined BES criteria of 100 kV. Others were not reported
due to them being associated with HVDC reduction schemes; thus making them invalid category B or C
contingencies. No IROLs were found in this analysis.
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13.0 NUCLEAR PLANT INTERFACE REQUIREMENTS
There are nine nuclear plants in the MISO market currently. Each nuclear plant has a set of Nuclear Plant
Interface Requirements (NPIR) that need to be met. These NPIRs are all outlined in the Nuclear Plant
Operating Agreements (NPOA) that each nuclear plant has reached between the Transmission Planner (TP), the
Planning Authority (PA) and the Geneator Operator (GOP). It is outlined in each of the NPOAs that the TP will
perform the assessment to assure the NPIRs are met. MISO will then provide those results in the CSA report.
See Table 13.0-1 for the list of nuclear plants within the MISO market. There are five additional nuclear units
in the MISO South region but because those units are not part of the MISO market they are not part of this
section.
Table 13.0-1: MISO Nuclear Plants
Operating
Region
Plant Name
Capacity
( MW)
Carmel
Callaway
1,369
Carmel
Clinton
1,264
Carmel
Enrico Fermi
1,138
Carmel
Kewaunee
576
Carmel
Palisades
955
Carmel
Point Beach
1,162
St. Paul
Duane Arnold
630
St. Paul
Monticello
718
St. Paul
Prairie Island
1,318
The results below are from our Transmission Owning Stakeholders who have a nuclear unit within their control
area. The timeline of their assessments do not always match that of which MISO requests this information;
therefore, in some instances their most recent assessment results were provided. On top of the Transmission
Planner’s assessment MISO also screened each nuclear bus for NPIR violations in the 2013 Summer CSA.
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Callaway
Description:
The Callaway Nuclear Plant is comprised of one 1,373 MVA unit with a maximum auxiliary station service load
of 75 MW and 35 Mvar. The step-up transformer is comprised of three 456 MVA, 25/345 kV units for a total
capability of 1,369 MVA. The Callaway Nuclear Plant Substation is connected to the eastern interconnection.
The 345 kV bus is configured with a breaker and a half scheme. Ameren Services owns and operates this plant.
Analysis:
In accordance with NUC-001-2 R9.2.3, Ameren Services tested the effects of various system configurations on
the Callaway 345 kV bus voltage. The 2012 Summer ERAG model was used as the basis for this study work,
with the detailed Ameren representation inserted into the model. The load level modeled in the Ameren system
was set to the projected 1-in-10 level for 2012 summer.
The Loss Of Coolant Accident (LOCA) load (auxilary load) modeled in these cases was 75 + j35 (MW +
jMvar). Power was imported to the Ameren control area from the MISO footprint to make up for the power loss
from the outage of the Callaway and Labadie units. The following table summarizes the results at the Callaway
bus, under none of the configurations tested did the Callaway bus voltage fall below the allowed limit.
Table 13.0-2: Ameren's Callaway assessment results
Configuration
1. Callaway Offline
2a. Condition #1 & NERC Category B
2b. Condition #2 & NERC Category B
3a. Condition #1 & NERC Category B
3b. Condition #1 & NERC Category B
3c. Condition #1 & NERC Category B
3d. Condition #1 & NERC Category B
Callaway 345 kV Bus
Limit
Simulation
333
357.4
330
356.8
330
357
330
346.3
330
356.3
330
355.7
330
355.7
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Clinton
Description:
Clinton Power Station is comprised of one 1,264 MVA unit with an auxiliary station service load of 43 MW and
16 Mvar. The step-up transformer is a 1,425 MVA, 22/345 kV unit. The Clinton substation is connected to the
eastern interconnection. The 345 kV bus is a ring bus configuration and the 138 kV bus is a straight bus
configuration. The 345 kV bus and 138 kV bus are not connected by transformation at the Clinton switchyard.
Exelon owns and operates this plant.
Analysis:
In accordance with NUC-001-2 R9.2.3, Ameren Services tested the effects of various system configurations on
the Clinton 345 kV and 138 kV bus voltages. The 2012 Summer ERAG model was used as the basis for this
study work, with the detailed Ameren control areas representation inserted into the model. The load level
modeled in the Ameren system was set to the projected 1-in-10 level for 2012 summer.
The LOCA load modeled in these cases was 44 + j27 (MW + jMvar). Power was imported to the Ameren
control area from the MISO cloud to make up for the power loss from the outage of the Clinton and Kincaid
units. The following table Summarizes the results at the Clinton bus, under none of the configurations tested did
the Clinton bus voltages fall below the allowed limit.
Table 13.0-3: Ameren's Clinton assessment results
Clinton Bus Voltages
Configuration
345 kV
138 kV
Limit
Simulation
Limit
Simulation
Base Case
327.8
362.2
129.7
140.5
1. Clinton Offline & NERC Category B
327.8
357.6
129.7
139.6
2. Clinton Offline & NERC Category B
327.8
355.9
129.7
138.8
3. Clinton Offline & NERC Category B
327.8
355.5
129.7
138.7
4. Clinton Offline & NERC Category B
327.8
357.2
129.7
135.6
5. Clinton Offline & NERC Category B
327.8
357.5
129.7
142.7
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Enrico Fermi
Description:
Enrico Fermi II Nuclear Plant (Fermi) is comprised of one 1,350 MVA unit connected to eastern interconnect.
The Fermi nuclear plant has two independent switchyards the 345 kV yard in which the unit is connected has
two 345 kV lines. The 120 kV switchyard which contains the interconnections for 4 Combustion Turbine
Generators normally used for peaking power has three 120 kV lines. Station service load is split between the
two switchyards. The 345 kV yard has a normal loading of 47 MW and 28 Mvar with an additional accident
loading adder of 2.69 MW and 11.682 Mvar. The 120 kV yard has a normal loading of 26 MW and 17 Mvar
with an additional accident loader of 2.59 MW and 12.095 Mvar. The plant is owned and operated by DTE
Electric Company (DECO).
Analysis:
As required by the Nuclear Plant Operating Agreement between ITC, DECO, Fermi II and MISO ITC performs
an annual grid analysis to insure that the system can meet the above requirements. In addition to the detailed
annual grid analysis all planning studies, including but not limited to load interconnections, generator
interconnections, seasonal system studies, and system reliability projects are required to use the above limits and
values to insure that the transmission system can be operated to meet them.
Results:
Past studies have indicated potential issues meeting the voltage drop limits and steady state voltage limits in
certain shutdown plus contingency scenarios. Long term solutions to these potential issues are currently being
developed in coordination with DECO, MISO and the Fermi II Nuclear Power Plant staff and to be proposed in
the MISO MTEP process.
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Palisades
Description:
Palisades Nuclear Generating Plant is comprised of one 955 MVA unit connected to eastern interconnect. The
Palisades Nuclear Generating Plant has one switch yard with six networked 345 kV transmission lines arranged
in a breaker and a half configuration. In addition there is one 345 kV line that runs to the Covert Generating
Plant. The plants auxiliary load of 43 MW and 31 Mvar is fed by two independent transformers. Safe-Guard
transformer is connected to the “F” bus of the switchyard while Start-up transformer is connected to the “R” bus
of the switchyard. Entergy Nuclear Palisades (ENP) is the owner and operator of the plant.
Analysis:
As required by the NPOA between METC, ENP, and MISO, METC performs an annual grid analysis to insure
that the system can meet the above requirements. In addition to the detailed annual grid analysis all planning
studies, including but not limited to load interconnections, generator interconnections, seasonal system studies,
and system reliability projects are required to use the above limits and values to insure that the transmission
system can be operated to meet them.
Results:
METC’s annual grid study, as well as the other studies in the area, has not indicated any issues with meeting the
above NPIRs. However; METC, MISO and ENP are currently engaged in negotiations surrounding proposed
changes to the High and Low voltage limits. It is unlikely this will affect the summer season.
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Kewaunee
Description:
The Kewaunee Nuclear plant retired on May 7, 2013.
Analysis:
MISO’s incorporated the Kewaunee NPIRs into its bi-annual assessments. The analysis was performed as part
of the MISO Coordinated Seasonal Transmission Assessment (CSA).
Results:
The Nuclear Plant Interface Requirements (NPIRs) for Kewaunee were incorporated into the MISO CSA study.
The results showed that the NPIRs met the required Kewaunee performance criteria.
: Entergy's Palisades Nuclear Power Plant located on the
Eastern shore of Lake Michigan
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Prairie Island
Description:
Prairie Island is located in Southeast Minnesota, along the Mississippi river. It is owned and operated by Xcel
Energy. The Prairie Island Plant is comprised of two 659 MVA Generator Step-Up Transformers with a
maximum combined auxiliary station service load of 63.2 MW and 35.3 Mvar. There are two 600 MVA, 20 kV
step-up transformers. It has four off site sources, two from the 345 kV bus, one from the 161 kV bus and one
from the 345/161 kV transformer tertiary bus. NSPM is the sole provider of off site power.
Analysis:
The analysis indicated that the 99.5% voltage criteria at 161 kV bus is not met during certain contingencies,
however this is not a concern as additional plant sources are available from the 345 kV bus. The Category D
contingency of a two unit trip was also analyzed with all voltages remaining acceptable for the plant.
Results:
Prairie Island NPIRs are satisfactorily met during this transmission assessment.
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Point Beach
Description:
The Point Beach Nuclear Plant is located in the eastern interconnect. This plant has a real gross output of 1,189
MW and is connected to the 345 kV transmission system. The Point Beach Nuclear Plant is owned and
operated by Nextera Energy Resources.
Analysis:
MISO’s incorporated the Point Beach NPIRs into its bi-annual assessments. The analysis was performed as part
of the MISO Coordinated Seasonal Transmission Assessment (CSA).
Results:
The Nuclear Plant Interface Requirements (NPIRs) for Point Beach were incorporated into the MISO CSA
study. The results showed that the NPIRs met the required Point Beach performance criteria.
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Monticello Plant
Description:
The Monticello plant is located in the eastern interconnect. It is owned and operated by Xcel Energy. The
Monticello Plant is comprised of one 718 MVA Generator Step Up Transformer with no unit connected
auxiliary station service transformer. There is one 800 MVA, 22/345 kV generator step-up transformer. It has
four off site sources, two from 345 kV bus, one from the 115 kV bus and one from 345/115 kV transformer
tertiary bus. NSPM is the sole provider of off-site power.
Analysis:
The analysis indicated that the 99.1% voltage on the 115 kV bus is not met during certain contingencies (mainly
C3), this is not a concern as there are two sources available from the 345 kV bus. The 345 kV low voltage can
be addressed by adjusting the generation set point to hold a higher voltage at the 345 kV bus.
Results:
Monticello NPIRs are satisfactorily met during this transmission assessment.
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Duane Arnold Energy Center
Description:
The Duane Arnold Energy Center (DAEC) is the eastern interconnect. This plant has a real gross output of 630
MW and is connected to the 161 kV. This nuclear plant is owned and operated by NextEra Energy.
Analysis:
ITCM Planning incorporated the Duane Arnold Energy Center (DAEC) into its annual transmission assessment.
The analysis was performed as part of the MAPP Transmission Reliability Assessment Subcommittee (TRAS)
study performed annually.
Results:
The Nuclear Plant Interface Requirements (NPIRs) for DAEC were incorporated into the TRAS study. The
DAEC load was modeled per the NPIRs. The results showed that the Iowa area meets the required DAEC
NPIRs performance criteria.
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14.0 APPENDICES
Appendices contain the actual study input files and detailed results of the analysis and are located in separate
folders on the extranet.
Appendix A – Subsystem, Monitored Element, and Contingency Files
Appendix B – Steady-State AC Contingency Results
Appendix C – FCITC Results
Appendix D – Critical Interface Results
Appendix E – Large Load Area Results
Appendix F – VSAT input files
Appendix G – Wind Generation Sensitivity Analysis
Appendix H – FCITC Stability Analysis Results
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15.0 ABBREVIATIONS AND ACROYNMS
MISO Carmel Region:
AMIL
AMMO
ATC
ALTE
MGE
UPPC
WEC
WPS
BREC
CWLD
CWLP
DEI
HE
IPL
ITC
ITCT
METC
LBWL
MPPA
NIPSCO
OVEC
SIGE
SIPC
WPSCI
Ameren Illinois
Ameren Missouri
American Transmission Company
Alliant Energy East
Madison Gas and Electric Company
Upper Peninsula Power Company
Wisconsin Electric Power Company (WE)
Wisconsin Public Service Corporation
Big Rivers Electric Company
Columbia Water & Light Department
City of Springfield (IL), Water Light & Power
Duke Energy Indiana
Hoosier Energy
Indianapolis Power & Light
ITC Holdings Corporation
International Transmission Company
Michigan Electric Transmission Company
City of Lansing Board of Water & Light
Michigan Public Power Agency
Northern Indiana Public Service Company
Ohio Valley Electric Corporation
Southern Indiana Gas & Electric (Vectren)
Southern Illinois Power Cooperative
Wolverine Power Supply Cooperative, Inc.
MISO South Region:
BRAZ
CLEC
EAI
PUPP
PLUM
OMLP
CWAY
NLR
BUBA
WMU
EES
DER
LAFA
LAGN
LEPA
SMEPA
BBA
Brazos Electric Cooperative
Cleco Power LLC
Entergy Arkansas
Union Power Partners, L.P.
Plum Point Energy Associates, LLC
City of Osceola, AR
City of Conway, AR
City of North Little Rock, AR
City of Benton, AR
City of West Memphis, AR
Entergy (Louisiana, Texas, Mississippi, New Orleans)
City of Ruston, LA
Lafayette Utilities System
Louisiana Generation, LLC
Louisiana Energy and Power Authority
Southerm Mississippi Electric Power Association
Batesville Generation
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MISO St. Paul Region:
ALTW
BEPC
DPC
GRE
ITC
ITCM
MHEB
MDU
MEC
MP
MPC
MPW
NWPS
OTP
RPU
SMMPA
WAPA
XEL
Alliant Energy West
Basin Electric Power Cooperative
Dairyland Power Cooperative
Great River Energy
ITC Holdings Corporation
International Transmission Company Midwest
Manitoba Hydro-Electric Board
Montana-Dakota Utilities Company
MidAmerican Energy Company
Minnesota Power
Minnkota Power Cooperative, Incorporated
Muscatine Power and Water Company
Northwestern Public Service Company
Otter Tail Power Company
Rochester Public Utilities
Southern Minnesota Municipal Power Agency
Western Area Power Administration
Xcel Energy
MISO Tier-1:
AEC
AECI
AEP
AEPW
ATSI
CE
DAY
DEO&K
EEI
EKPC
LGE/KU
EMDE
GMO
IESO
KACP
LES
NPPD
OKGE
OPPD
PS
SOCO
SPC
SPP
SWPA
TVA
Alabama Electric Corporation
Associated Electric Cooperative, Inc.
American Electric Power
AEP – Southwest Power Company
FirstEnergy Corp.
Commonwealth Edison (Exelon)
Dayton Power
Duke Energy Ohio & Kentucky
Electric Energy, Inc.
East Kentucky Power Cooperative
Louisville Gas & Electric and Kentucky Utility
Empire Electric Disctict
KCP&L Greater Missouri Operations
Independent Electricity System Operator
Kansas City Power & Light
Lincoln Electric Services
Nebraska Public Power District
Oklahoma Gas & Electric
Omaha Public Power District
Power South
Southern Company
Saskatchewan Power Company
Southwest Power Pool
Southwestern Power Administration
Tennessee Valley Authority
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Non-MISO:
DOE
FERC
MAPP
MRO
NERC
PJM
RCDC
RFC
SERC
WECC
Department Of Energy
Federal Energy Reliability Council
Mid-Continent Area Power Pool
Midwest Reliability Organization
North America Electric Reliability Corporation
PJM Interconnection, LLC
Rapid City DC Interconnect
ReliabilityFirst Corporation
Southeast Electric Reliability Corporation
Western Electric Coordinating Council
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