Public Version
MISO
2014 Spring
Coordinated Seasonal
Transmission Assessment
February 3, 2014
Final Report
1
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
CONTENTS
Contents .................................................................................................................................................. 2
1.0 Executive Summary .......................................................................................................................... 3
2.0 Introduction ....................................................................................................................................... 4
3.0 Study Criteria .................................................................................................................................... 7
4.0 Study Participants ............................................................................................................................. 9
5.0 Models and Input Data .................................................................................................................... 11
6.0 Study Methodology ......................................................................................................................... 15
6.1 Steady State AC Contingency Analysis ................................................................................................. 15
7.0 Steady-State Analysis Results......................................................................................................... 16
7.1 Summary ................................................................................................................................................ 16
8.0 IROL Limits .................................................................................................................................... 17
9.0 Nuclear Plant Interface requirements .............................................................................................. 18
10.0 Appendices .................................................................................................................................... 33
11.0 Abbreviations and acroynms ......................................................................................................... 34
2
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 and sometimes stressed operating
horizon loading conditions. This study is coordinated with other studies performed by MISO members and
other adjacent planning entities. This study includes the new MISO South region. The following Balancing
Authorities came into the MISO footprint on December 19, 2013: Entergy transmission (EES, EAI), Cleco
(CLEC), South Mississippi Electric Power Association (SMEPA), Louisiana Generating, LLC (LAGN),
Lafayette Utilities System (LAFA), and Louisiana Energy and Power Authority (LEPA). There were fourteen
total new members, resulting in the seven aforementioned new Local Balancing Authorities (LBA) in the MISO
South Region. All of these LBAs were MISO transmission owning members when this study was performed.
This Spring transmission system assessment was performed as a high wind light load transfer from MISO North
and Central Regions to a shoulder peaking MISO South and Central Region, see Figure 5.0-1. The conditions
created in this Spring assessment go beyond the planning criteria of most MISO Stakeholders. Portions of the
MISO transmission footprint were stressed beyond normal base case assumptions. The constraints shown in
this report only apply to the stressed conditions outlined in section 5. This assessment was produced in order to
provide system operators with guidance as to possible acute system conditions that would warrant close
observation to ensure system reliability, in the event that these extreme conditions were to occur.
The 2014 Spring CSA performed the following transmission system assessments and listed the results below:
Steady State AC Contingency Analysis was performed of the MISO system.
•
Category A screening
•
Category B contingency screening
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 2014 Spring 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.
3
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 access 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.
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), Reliability First Corporation (RFC) and SERC Reliability Corporation (SERC) regions.
4
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
MISO Regions
MISO incorporated 15 new Balancing Authorities on June 1, 2013. These 15 new BAs consolidated into 7 new
Local Balancing Authorities as of December 19, 2013; therefore, the MISO transmission system consists of
three operating regions. The three operating regions are called MISO North Region, MISO Central Region, and
MISO South Region; see Figure 2.0-2 below.
North
Central
South
Figure 2.0-2: MISO RC Operating Regions
The North 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]. The North
subregions all belong to the NERC approved MRO Region.
The Central 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 Central subregions belong to
MRO, SERC or RFC regions of NERC.
5
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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
[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 Association [SMEPA], and Union Power Partners L.P. [PUPP]. The South subregions belong to
the SERC Region of NERC. Please note that Entergy-Arkansas [EAI] is governed under the Entergy Company
but is separate from Entergy transmission [EES] and contains Arkansas’s BA’s.
Study Purpose
The purpose of this Coordinated Seasonal Transmission Assessment (CSA) is to analyze and assess the MISO
transmission system under extreme high wind light load conditions that could be expected for the 2014 Spring
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 focused on the performance of large scale category B steady-state contingency analysis during a
high wind (90% of nameplate) scenario. Seasonal outages were also applied.
The contingency levels 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 2014 Spring 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 fulfil 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.
6
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 and B.
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 power flow model. Note some members are within other members’ control areas so the control
area that they belong to is shown as “in xxx”.
Table 3.0-1: MISO CSA Systems Studied
Region
Central
Central
Area
206
Abbrev
OVEC
System
Ohio Valley Electric Corporation
207
HE
Hoosier Energy Rural Electric Cooperative
Central
208
DEI
Duke Energy Indiana
Central
210
SIGE
Vectren (Southern Indiana Gas & Electric Co)
Central
216
IPL
Indianapolis Power & Light Company
Central
217
NIPS
Northern Indiana Public Service Company
Central
in 217
IMPA*
Indiana Municipal Power Agency
Central
in 217
WVPA*
Wabash Valley Power Association
Central
218
METC
Michigan Electric Transmission Co.
Central
in 218
MPPA*
Michigan Public Power Agency
Central
in 218
MSCPA*
Michigan South Central Power Agency
Central
in 218
WPSC*
Wolverine Power Supply Cooperative
Central
219
ITC
International Transmission Company
Central
295
WEC
Wisconsin Electric Power Company (ATC)
Central
314
BREC
Big Rivers Electric Corporation
Central
333
CWLD
Columbia, MO Water and Light Department
Central
356
AMMO
Ameren Missouri
Central
357
AMIL
Ameren Illinois
Central
360
CWLP
City of Springfield (IL) Water Light & Power
Central
361
SIPC
Southern Illinois Power Cooperative
Central
694
ALTE
Alliant Energy East (ATC)
Central
696
WPS
Wisconsin Public Service Corporation (ATC)
Central
697
MGE
Madison Gas & Electric Company (ATC)
Central
698
UPPC
Upper Peninsula Power Company (ATC)
7
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Region
Area
Abbrev
South
327
EAI
System
Entergy Arkansas
South
in 327
BUBA*
City of Benton, Arkansas
South
in 327
CWAY*
City of Conway, Arkansas
South
in 327
NLR*
City of North Little Rock, Arkansas
South
in 327
OMLP*
City of Osceola, Arkansas
South
in 327
PLUM*
Plum Point Energy Associates, LLC
South
in 327
PUPP*
Union Power Partners
South
in 327
WMU*
City of West Memphis, Arkansas
South
332
LAGN
Louisiana Generating LLC
South
349
SMEPA
South Mississippi Electric Power Association
South
in 349
BBA*
Batesville Generation
South
351
EES
Entergy Louisiana
South
in 351
BRAZ*
Brazos Electric Cooperative
South
in 351
DERS*
City of Ruston, Louisiana
South
502
CLEC
Cleco
South
503
LAFA
Lafayette Utilities System
South
504
LEPA
Louisiana Energy and Power Authority
North
600
XEL
Xcel Energy
North
in 600
NWEC*
Northwestern Wisconsin Electric
North
608
MP
Minnesota Power & Light
North
613
SMMPA
Southern Minnesota Municipal Power Agency
North
615
GRE
Great River Energy
North
620
OTP
Otter Tail Power Company
North
in 620
MPC*
Minnkota Power Cooperative
North
627
ALTW
ITC Midwest
North
633
MPW
Muscatine Power & Water
North
635
MEC
MidAmerican Energy Company
North
in 635
CFU*
Cedar Falls Utility
North
652
WAPA
Western Area Power Administration
North
661
MDU
Montana-Dakota Utilities Company
North
667
MH
Manitoba Hydro
North
680
DPC
Dairyland Power Cooperative
8
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
4.0 STUDY PARTICIPANTS
Table 4.0-1 below shows the individuals who actively participated in this study.
Table 4.0-1: MISO's 2014 Spring CSA Participation List1
1
First Name
Last Name
Company
Name
First
Name
Last Name
Company
Name
Tony
Gott
AECI*
Tim
Aliff
MISO
Evan
Shuvo
Ameren
David
Duebner
MISO
Eric
Fleming
ATC
Scott
Goodwin
MISO
Brad
Larson
ATC
BeiBei
Li
MISO
Kerry
Marinan
ATC
Josh
Netherton
MISO
Chris
Bradley
BREC
Tony
Rowan
MISO
James
Simms
CLEC
Kris
Ruud
MISO
Chris
Thibodeaux
CLEC
Raja
Thappetaobula
MISO
Adam
Schuttler
CWLD
Andy
Witmeier
MISO
Chris
Daniels
CWLP
Ruth
Pallapati
MP
Steve
Rose
CWLP
Peter
Schommer
MP
Phil
Briggs
DEI
Will
Lovelace
MPC
Veronda
Johns
DEI
Pete
Schimpke
MPPA
John
Jozefowski
DEI
Lewis
Ross
MPW
Steve
Porter
DPC
John
Stolley
MPW
Maryclaire
Peterson
EES
Bob
Vargus
MPW
Jared
Shaw
EES
Amir
Quadri
NIPS
Richa
Singhal
GRE
Jake
Heck
OTP
Todd
Taft
HE
Luis
Leon
OTP
Robert
Grubb
IPL
Ryan
Abshier
SIGE
Dave
Osterkamp
ITCM
Jeff
Jones
SIPC
John
Andree
ITCT
Damion
Cuevas
SMEPA
Joshua
Hurst
ITCT
Yu-Loong
Liew
SMEPA
Jeffrey
Stewart
LAFA
Pat
Egan
SMMPA
Wayne
Messina
LAGN
Yassar
Bahbaz
SPP*
Jamal
Ahmed
LBWL
Jason
Smith
SPP*
Kevin
Bihm
LEPA
Nate
Schweighart
TVA*
Shawn
Heilman
MDU
Chris
Bultsma
WAPA
Dan
Custer
MEC
Tom
King
WPSCI
Dan
Rathe
MEC
Dan
Wilkinson
WPSCI
Kris
Long
MH
Michelle
Wood
XEL
Gayan
Wijeweera
MH
Khalid
Yousif
XEL
* denotes non-MISO member participants
9
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
In addition to the aforementioned list of participants above, the final 2014 Spring CSA report will also be
distributed to the following entities in accordance with FAC-014-2 and standards.
Table 4.0-2: Final Report Distribution List
Adjacent Planning Authorities
Transmission Planners
AECI
MH
Ameren
LBWL
ATC
Ontario IESO
ATC
MEC
E.ON U.S.
PJM
Basin Electric
METC
EEI
Sask Power
BREC
MH
EKPC
SOCO
SPP
Cedar Falls
MP
CIPC
MPC
TVA
CLEC
MPW
Corn Belt
NIPS
CWLD
OTP
Reliability Coordinators
CWLP
OVEC
MISO
DEI
RPU
DPC
SIGE
EEI
SIPC
Entergy
SMEPA
GTC
MAPP
Transmission Operators
Ameren
MEC
GRE
SMMPA
ATC
METC
HE
WAPA
BREC
MH
IPL
WPSCI
CLEC
Corn Belt
MP
ITCM
XEL
MPC
CWLD
MPW
CWLP
NIPS
DEI
OTP
CIPC
DPC
OVEC
Corn Belt
MPC
EEI
RPU
DPC
OVEC
EES
SIGE
MH
RPU
GRE
SIPC
XEL
WAPA
HE
SMEPA
ITCT
Transmission Service Provider
MISO
IPL
SOCO
ITCM
WAPA
Ontario IESO
SOCO
ITCT
WPSCI
PJM
SPP
LBWL
XEL
Sask Power
TVA
MDU
Adjacent Reliability Coordinators
WECC
10
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
5.0 MODELS AND INPUT DATA
The power flow model used for the 2014 Spring assessment was based on the ERAG/MMWG 2012 series
model. The MISO control area was built from MOD with the MISO external areas from MMWG 2013
series. The MISO footprint blended two load levels across their operating regions, see Figure 5.0-1 below.
o
o
Spring Light Load: MISO North Region + Michigan, AMIL, CWLP, ATC, NIPS.
Spring Peak Load: MISO South Region + AMMO, SIPC, CWLD, SIGE, IPL, DEI, HE, BREC.
Light Load
Figure 5.0-1: 2014 Spring CSA * Light Load vs. Spring Peak
All MISO wind generators were dispatched at 90% of the nameplate full output; a reflection of the 90%
MISO wide average capacity credit wind units receive. PJM N. Illinois wind was also dispatched to 90%
and that generation was transferred to PJM Ohio. 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 model
was developed in accordance with the Operations Reliability Coordination Agreement (ORCA) that was
reached between MISO And all Joint Parties (JPs).
The projected non-coincident 2014 Spring demand for MISO’s footprint in the power flow model used for
this transmission assessment is 92,822 MW. This does include the projected Spring demand of the fifteen
new LBAs in the MISO South region; since they have joined MISO starting on December 19, 2013. Power
flow model control areas of MISO member utilities include loads of other utilities that are not MISO
11
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 2014 Spring period is
148,516 MW. The net scheduled interchange for MISO in the power flow model is 4,213.9 MW, which
indicates a net export of power by the MISO member utilities in the 2014 Spring season.
The following seasonal outages were included based on an April 15, 2014 target date in addition to a 30 day
duration period.
Table 5.0-1: Seasonal Outages
Operating
Region
CA
Type
Planned Start
Planned End
Station Name
Equip
Type
kV
Pmax
Central
ALTE
P
1/6/2014
06/06/14
Berlin--Omro Industrial Park 69 kV line
LN
69
n/a
Central
ALTE
P
3/31/2014
05/30/14
Paddock--Shirland Ave 69 kV line
LN
69
n/a
Central
ALTE
P
4/14/2014
05/30/14
Hilltop--Buckhorn Tam 69 kV line
LN
69
n/a
Central
ALTE
P
03/19/14
5/9/2014
Boscobel Cap Bank C-5_4
SS
Central
ALTE
P
2014-04-11
2014-06-04
UN
22
260
Central
AMIL
P
2014-03-03
2014-05-09
MARSEILLE; T138.00 4MARSEILLES 138.00 1
LN
138
n/a
Central
AMIL
E
2011-12-20
2014-12-31
1MERDSA 3 20.000 3
UN
19.2
229
COL G1
22.000 1
n/a
Central
AMIL
P
2012-09-25
2015-10-01
1MERDSA 4 20.000 4
UN
19.2
200
Central
AMMO
P
2014-03-17
2014-05-17
7WILDWD TP 345.00 7LABADIE3 345.00 1
LN
345
n/a
Central
AMMO
P
2014-03-17
2014-05-17
7MASON 2 345.00 7LABADIE1 345.00 1
LN
345
n/a
Central
AMMO
P
2014-03-17
2014-05-17
7WILDWD TP 345.00 7MASON 3 345.00 1
LN
345
n/a
Central
AMMO
P
01/13/14
05/31/14
7PALM TAP 345.00 SUB T 3 345.00
LN
345
n/a
Central
AMMO
P
2014-04-05
2014-06-02
1LAB G2 20.000 2
UN
20
630
Central
AMMO
P
2014-01-25
2014-04-28
1SIOUX 2 18.000 H & L
UN
18
535
Central
AMMO
P
2014-04-01
2014-04-30
7PALMYRA 345.00 5PALMYRA 161.00 1
XF
345
n/a
Central
AMMO
P
2014-03-17
2014-05-17
7WILDWD
XF
345
n/a
Central
BREC
P
2014-04-05
2014-05-26
COLEMAN3 18.000 3
UN
161
155
Central
CWLP
P
2014-03-22
2014-05-17
1DALMAN 33 19.000 3
UN
138
199
Central
DEI
P
2014-01-02
2014-05-31
Central
DEI
P
2014-03-07
2014-05-19
Central
DEI
P
2014-04-11
2014-05-12
Central
DEI
P
2014-04-11
Central
DEI
P
2014-04-11
Central
HE
P
2014-03-01
345.00 4WILDWD 1 138.00 1
08KOK HP 230.00 08TIPTN
LN
230
n/a
UN
24
635
08EDWST1 18.000 ST
UN
18
331
2014-05-12
ED_WARDS_CT1_18_not_in_idc
UN
18
232
2014-05-12
ED_WARDS_CT2_18_not_in_idc
UN
18
232
2014-04-27
07MEROM5 345.00 2
UN
345
600
07MEROM5 345.00 1
UN
345
600
UN
22
438
LN
220
n/a
08GIB4
230.00 1
24.000 42
Central
HE
P
2014-04-12
2014-05-11
Central
IPL
P
2014-03-08
2014-04-06
Central
ITCT
P
2014-01-20
2014-04-17
Central
ITCT
P
2014-02-14
2014-05-06
19MON2
26.000 2
UN
26
800
Central
ITCT
P
2014-02-28
2014-05-23
19SC7
18.000 7
UN
18
460
Central
METC
F
2013-10-07
2014-12-31
18KARN4
26.000 4
UN
26
638
Central
METC
P
2013-11-09
2014-07-19
18LUDN12 20.000 2
UN
20
340
Central
METC
P
2014-04-07
2014-05-05
18LUDN12 20.000 1
UN
20
340
STOUT 7
22.000 7
SCOTT_TS 220.00 19B3N PS 220.00 1
2 The outage date was pushed out to September 2014. This unit was still offline in the model.
12
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Operating
Region
CA
Type
Planned Start
Planned End
Station Name
Equip
Type
kV
Central
METC
P
2014-03-15
2014-05-14
18KARN1A 16.000 A
UN
16
260
Central
METC
P
2014-04-12
2014-05-10
18ZELND1 18.000 1
UN
18
181.7
Central
MGE
P
2014-04-12
2014-06-03
UN
22
125
Central
MGE
P
2013-04-22
2014-04-22
CARDINAL 345.00 CARDINAL 138.00 1
XF
345
n/a
Central
NIP
F
06/01/14
08/31/14
Babcock--Tower Road
LN
138
n/a
Central
NIP
F
06/01/14
08/31/14
Babcock--Tower Road
LN
345
n/a
Central
NIP
F
06/01/14
08/31/14
St. John--Schaffer
LN
345
n/a
Central
NIP
P
2014-03-22
2014-05-12
17SCHAFER-1824.000 18
UN
345
361
Central
NIP
P
2014-04-05
2014-05-26
17BAILLY-8 22.000 8
UN
138
320
Central
NIP
P
2014-03-15
2014-05-05
17BAILLY-7 22.000 7
UN
138
160
Central
SIPC
P
2014-03-27
2014-05-25
1MRNG4
UN
20
173
Central
UPPC
P
9/20/2014
6/30/2014
Evergreen Tap--Pine River 69 kV line
LN
69
n/a
Central
UPPC
P
9/20/2014
6/30/2014
Straits--Pine River 69 kV line
LN
69
n/a
Central
WEC
P
2013-09-20
2014-06-30
BREVRT
138.00 MACKINAC N 138.00 1
LN
138
n/a
Central
WEC
P
4/7/2014
4/25/2014
Bluemound--West Junction Tap 138 kV line
LN
138
n/a
Central
WEC
P
4/7/2014
4/25/2014
Everett--28th St 138 kV line
LN
138
n/a
Central
WEC
P
2014-03-08
2014-05-19
Central
WEC
P
2014-03-29
2014-04-28
Central
WEC
P
2014-04-10
2014-05-05
POWSTG20 18.000 1
Central
WEC
P
2014-04-10
2014-05-05
Central
WEC
P
2014-04-10
2014-05-05
Central
WEC
F
2012-11-06
2014-12-01
PRS GT1
Central
WEC
F
2012-11-06
2014-12-01
Central
WEC
P
2014-04-05
2014-05-05
Central
WEC
P
2014-04-05
2014-05-05
COL G1
22.000 1
20.000 4
Pmax
OK C G8
18.000 8
UN
17.2
291
OK C G7
18.000 H
UN
17.2
286.4
UN
18
273.7
POWCTG21 18.000 1
UN
18
184
POWCTG22 18.000 1
UN
18
181
13.800 1
UN
13.8
100
PRS GT4
13.800 4
UN
13.8
100
PRS GT4
13.800 4
UN
13.8
100
PRS GT7
13.800 7
UN
13.8
100
Central
WEC
P
4/7/2014
4/25/2014
Elm Road unit No. 1
UN
25
1272
Central
WPS
P
2/28/2014
4/28/2018
Pulliam WPS-East Bus time 138 kV line
LN
69
n/a
Central
WPS
P
2014-04-11
2014-06-03
22
180
COL G1
22.000 1
UN
PUL G8
16.000 8
Central
WPS
P
2014-02-28
2014-04-28
UN
16
133
North
ALTW
P
2014-02-17
2014-05-01
COGGON 7 115.00 DUNDEE 7 115.00 1
LN
115
n/a
North
DPC
F
2013-07-19
2014-06-01
ALMA5 5G 14.400 5
UN
161
80
North
DPC
F
2013-07-19
2014-06-01
ALMA5 4G 13.800 4
UN
161
56
North
GRE
P
2013-10-31
2014-10-31
GRE-PL VLLY5161.00 AUSTIN 5 161.00 1
LN
161
n/a
North
GRE
P
2014-04-05
2014-05-02
GRE-COAL 41G22.000 1
UN
230
582
North
MDU
P
2013-06-24
2014-06-27
HESKETT7 115.00 MANDANW7 115.00 1
LN
115
n/a
North
MEC
P
2014-03-21
2014-05-05
NEAL 3G 22.000 3
UN
22
144
North
MEC
P
2014-04-12
2014-06-02
CBLUF4G
North
MP
P
2014-03-24
2014-04-25
North
MP
P
2014-04-05
North
WAPA
P
2014-04-01
North
WAPA
P
North
WAPA
North
North
UN
345
77.47
FLDWDTP7 115.00 BLCKBRY7 115.00 1
26.000 4
LN
115
n/a
2014-05-05
BOSWE43G 20.900 3
UN
20.9
362
2014-05-15
GARRISN4 230.00 LELANDO4 230.00 1
LN
230
n/a
04/14/14
05/21/14
FB-WT 230KV LINE,
LN
230
n/a
P
04/14/14
05/21/14
HU-WT NO.2 230KV LINE,
LN
230
n/a
WAPA
P
2014-03-29
2014-05-25
ANTEL31G 24.000 1
UN
24
477
WAPA
P
2013-10-09
2014-12-31
CRESTON5 161.00 CRESTON8 69.000 1
XF
161
n/a
13
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Operating
Region
CA
Type
Planned Start
Planned End
Station Name
Equip
Type
kV
Pmax
North
WAPA
P
04/14/14
05/21/14
WATERTN3 345.00 STARBUS245 1.0000 1,
XF
345/230
n/a
North
WAPA
P
04/14/14
05/21/14
STARBUS249 230.00 WATERTN4 1.0000 1,
XF
345/230
n/a
North
XEL
P
2013-11-01
2014-11-01
FARIBALT P 7115.00 GRE-LKMARN 7115.00 1
LN
115
n/a
North
XEL
P
2014-01-15
2014-10-15
MINVALY7 115.00 LYON CO7 115.00 1
LN
115
n/a
North
XEL
P
2014-03-10
2014-04-04
PR ISLD3 345.00 BLUE LK3 345.00 1
LN
345
n/a
North
XEL
P
2014-03-22
2014-04-27
KING 31G 20.000 1
UN
20
555
North
XEL
P
2014-02-22
2014-04-22
SHERC33G 26.000 3
UN
26
537
North
XEL
P
2014-03-29
2014-04-28
RIVRSIDEG9 718.000 9
UN
18
255
North
XEL
P
2014-03-29
2014-04-28
RIVRSIDG10 718.000 10
UN
18
255
North
XEL
F
2011-02-21
2015-12-31
FEN 83G 13.800 3
UN
13.8
100
South
CLEC
P
2014-02-22
2014-04-28
G2RODEMR 22.000 1
UN
22
434
South
EAI
P
2014-03-03
2014-07-11
LN
161
n/a
South
EAI
P
2014-03-09
2014-04-07
1ANO U2 22.000 1
UN
22
1031
South
EAI
P
2014-03-15
2014-04-19
1BLUF U2 26.000 1
UN
26
844
South
EAI
P
2014-04-12
2014-05-17
1CATH U4 22.000 1
UN
22
547
South
EAI
P
2012-12-01
2017-01-01
1RITC U2 18.000 1
UN
18
544
South
EAI
P
2012-12-01
2017-01-01
1RITC U2 18.000 1
UN
22
356
South
EEI
F
2010-09-01
2014-05-01
JOPPA G3 13.800 3
UN
161
62
South
EEI
F
2013-02-20
2014-04-30
JOPPA G2 13.800 2
UN
161
62
South
EEI
F
2013-02-21
2014-04-30
South
EES
P
2014-03-14
2014-04-18
4GONZL
138.00 4SORXFM
South
EES
P
2014-03-03
2014-05-09
4LEWIS
138.00 4EGYPT
South
EES
U
2013-04-01
2015-09-30
South
EES
P
2014-03-15
2014-05-03
1ANDRUS U1 24.000 1
South
EES
P
2013-08-31
2014-08-31
1G5WGLEN 20.000 1
South
EES
P
2014-02-22
2014-04-19
South
EES
P
2013-08-31
2014-08-31
South
EES
P
2014-02-15
2014-05-10
South
EES
P
2012-12-01
South
EES
P
2014-03-15
South
EES
P
South
EES
South
EES
5CALCR
161.00 5MELBRN
161.00 1
JOPPA G1 13.800 1
UN
161
62
LN
138
n/a
LN
138
n/a
LN
115
n/a
UN
24
761
UN
20
550
1GYP U3 24.000 1
UN
24
545
1G3WGLEN 20.000 1
UN
20
537
1G4NELSON 24.000 1
UN
24
500
2017-01-01
1G10LAST 13.800 1
UN
13
260
2014-05-17
1MICH U2 18.000 1
UN
18
240
2013-08-31
2014-08-31
1G3WGLEN 20.000 1
UN
18
160
F
2013-05-13
2020-08-05
1G3NELSON 18.000 1
UN
18
153
P
2014-04-05
2014-05-17
1G3NELSON 18.000 1
UN
18
153
138.00 1
138.00 1
3STERLING% 115.00 3OKRIDG
4SORXFM
138.00 3SORNTO
115.00 1
South
EES
P
2014-03-14
2014-04-18
XF
138
n/a
South
LAGN
P
2014-03-01
2014-04-15
1G1INTHB 18.000 1
115.00 1
UN
500
330
South
LAGN
F
2013-04-04
2015-06-01
1BC1 U4
13.800 1
UN
230
115
Tier-1
CE
P
2014-04-19
2014-05-18
KINCAID ;2U20.000 2
UN
20
579
14
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
6.0 STUDY METHODOLOGY
The following power system analysis software tools were utilized: Siemens PTI’s PSS/e (ver33).
6.1 Steady State AC Contingency Analysis
Siemens PTI’s PSS/e ver33 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 contingencies. Also, the entire MISO tier1 footprint was analyzed for category B contingencies. Single generator outages by control area were examined.
Some neighboring system contingencies were also analyzed, if included by members or non-member
participants.
The PSS/e 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: PSS/e Options used for ACCC Analysis
PSS/e AC Load Flow Solution Options
Tap Adjustments
Area Interchange Control
Stepping
Disabled
Mvar Limits
AC LF Method
Apply immediately
Full Newton
Non Divergent LF
Solution Options
Only If Normal Diverged
Phase Shift Adjustment
General Solution Options
Maximum Load Flow Iterations
20
MW/Mvar tolerance
Reactive Adj. De-acceleration Factor
1
0.9
Low Voltage Break Point
Max Iteration to freeze adjustment
0.7
99
15
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 2014 Spring season.
There were 17 category A high voltage violations and 30 category B (thermal/low voltage) 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.
HE's Ratts Generating Station in
Pike County Indiana
16
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
8.0 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 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 6 facilities that were evaluated for IROL candidacy in this analysis accompanied with an operating
procedure as mitigation. There were no new IROLs identified in this assessment.
Xcel's Chippewa Falls
Hydro in Wisconsin
17
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
9.0 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 Generator 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 9.0-1 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 9.0-1: MISO Nuclear Plants
Operating
Region
Plant Name
Capacity
( MW)
Central
Callaway
1,369
Central
Clinton
1,264
Central
Point Beach
1,162
Central
Enrico Fermi
1,138
Central
Palisades
955
Central
Kewaunee
0
North
Prairie Island
1,318
North
Monticello
718
North
Duane Arnold
630
South
Arkansas
Nuclear One
2,010
South
Grand Gulf
1,544
South
Waterford
1,214
South
Riverbend
1,080
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 2014 Spring CSA. The
MISO nuclear units that are currently in the MISO market can be geographically seen below in Figure 9.0-1.
18
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Figure 9.0-1: Geographic Location of MISO Nuclear Plants
19
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 456.3 MVA, 25 kV/345 kV units for a
total capability of 1369.5 MVA. The Callaway Nuclear Plant Substation is connected to the Eastern
Interconnection at its associated switchyard by four 345 kV circuits. The 345 kV bus is configured with a break
and a half scheme. Ameren owns and operates in this plant.
2013-14 Winter Analysis for Nuc-001-2 R9.2.3:
Ameren Operations Planning tested the effects of various system configurations on the Callaway 345 kV bus
voltage. The 2014 Spring SERC NTSG 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 2014 Spring.
The LOCA load modeled in these cases was 75 + j35 MVA. Power was imported to the Ameren control area
from the Midwest ISO cloud 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 9.0-2: Callaway Bus Summary
Configuration
0.
Base Case
1a. Callaway Offline
Callaway 345 kV Bus
Limit
Simulation
358.8
358.8
332.9
353.7
1b. Callaway Offline & NERC Category B Event
329.8
342
1c. Callaway Offline & only NERC Category B Event
329.8
351.7
1d. Callaway Offline & only NERC Category B Event
329.8
352
1e. Callaway Offline & only NERC Category B Event
329.8
352
2a. Callaway Offline & NERC Category B Event
329.8
354.3
2b. Config. #2a & NERC Category B Event
329.8
354.6
20
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Clinton
Description:
Clinton Power Station is comprised of one 1264.777 MVA unit with an auxiliary station service load of 43 MW
and 16 Mvar. The step-up transformer is a 1,425 MVA, 22 kV/345 kV unit. The Clinton substation is connected
to the Eastern Interconnection by three 345 kV circuits and one 138 kV circuit. 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.
2013-14 Winter Analysis for Nuc-001-2 R9.2.3:
Ameren tested the effects of various system configurations on the Clinton 345 kV and 138 kV bus voltages. The
2014 Spring SERC NTSG 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 the 2014 Spring season.
The LOCA load modeled in these cases was 44 + j27 MVA. 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 9.0-3: Clinton Bus Summary
Configuration
0. Base Case
1a. Clinton Offline
1b. Clinton Offline & NERC Category B Event
1c. Clinton Offline & NERC Category B Event
1d. Clinton Offline & NERC Category B Event
1e. Clinton Offline & NERC Category B Event
1f. Clinton Offline & NERC Category B Event
2a. Clinton Offline & NERC Category B Event
Limit
327.75
327.75
327.75
327.75
327.75
327.75
327.75
327.75
Clinton Bus Voltages
345 kV
138 kV
Simulation
Limit
Simulation
358.8
129.72
139.7
351.6
129.72
138.2
348.7
129.72
137
351.4
129.72
138.3
343.8
129.72
135.5
351.4
129.72
134.9
351.7
129.72
139.5
352.4
129.72
138.4
21
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Point Beach
Description:
The Point Beach Nuclear Plant is located near Two Rivers, WI on the shore of Lake Michigan. 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.
22
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Enrico Fermi
Description:
Enrico Fermi II Nuclear Plant (Fermi) is comprised of one 1,350 MVA unit connected to the 345 kV
transmission grid in South East Michigan. 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 contains the interconnections
for 3 Combustion Turbine Generators which two are normally used for peaking power and one is reserved for
plant emergency use. 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.
23
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Palisades
Description:
Palisades Nuclear Generating Plant is comprised of one 955 MVA unit connected to the 345 kV transmission
grid in southwest Michigan. 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 42 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 upcoming 2013-14 Winter season.
24
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Kewaunee
Description:
The Kewaunee Nuclear plant retired on May 7, 2013.
NPIRs:
Real-time and post-contingent voltage range required by the plant is 128.0 kV to 148.0 kV (Note: ATC controls
the real-time voltage on the Kewaunee 138 kV buses to the range of 131.1 kV to 144.9 kV, corresponding to
0.95 – 1.05 pu, since this is more restrictive than the plant’s criteria.)
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.
25
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Arkansas Nuclear One
Description:
The Arkansas Nuclear One (ANO) Plant is comprised of two units, unit No. 1 is rated for 1,002.6 MVA and unit
No. 2 is rated for 1,133.33 MVA. The ANO combined maximum auxiliary station service load is as stated
below for each applicable bus voltage level. The step-up transformer bank for each generating unit is comprised
of three single phase transformers. The unit No. 1 three phase transformer bank is rated for 945 MVA and the
unit No. 2 three phase transformer bank is rated for 1,448 MVA (FOA).
In addition to ANO units No. 1 and No. 2 the ANO 500/161/22 kV auto transformer and the ANO 500 kV bus is
connected to Entergy’s Mabelvale, Pleasant Hill & Oklahoma Gas & Electric’s (OG&Es) Fort Smith 500 kV
switchyard. The ANO 161 kV bus is connected to Pleasant Hill, Russellville East 161 kV switchyards and the
ANO ST No. 3 is an offsite source.
Analysis:
MISO incorporated the Entergy’s South Nuclear Plants 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 Entergy’s South Nuclear Plants were incorporated into
the MISO CSA study. The results showed that the NPIRs met the required Entergy’s South Nuclear Plants
performance criteria.
26
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Grand Gulf
Description:
The Grand Gulf plant substation is connected to the Transmission System by 2 500 kV transmission circuits.
The 500 kV buses where the transmission lines connecting remote substations to the Grand Gulf 500 kV
Switchyard are two-bus-two-breaker schemes. The 115 kV bus configuration where the transmission line
connecting the remote substation to the Grand Gulf 115 kV Substation is a remote breaker radial line with no
circuit breakers located in the Grand Gulf 115 kV Substation. The Grand Gulf generator step-up transformer
and service transformer ST11 are each connected to the Grand Gulf 500 kV Switchyard by a breaker-and-onehalf scheme, located in the same bay of the Grand Gulf 500 kV Switchyard. Service transformer 21 is connected
to the Grand Gulf 500 kV Switchyard via a two-bus-two-breaker scheme.
Grand Gulf is comprised of one 1,600 MVA unit, with maximum auxiliary station service load as shown below
for each applicable bus voltage level:
•
•
•
Grand Gulf Normal Operations Loads 500 kV System = 76 MW and 37 Mvar
Grand Gulf Accident Loads 500 kV System = 69 MW and 34 Mvar
Grand Gulf Accident Loads 115 kV System = 13.05 MW and 6.32 Mvar
The step-up transformer bank for the generating unit is comprised of three single phase transformers with a total
unit rating of 1,650 MVA. Grand Gulf uses two 500/34.5 kV service transformers and a single 115/4.16 kV
ESF Transformer 12 to provide the unit with offsite power. Grand Gulf electrical loads are supplied from the
Grand Gulf 500 kV Switchyard located at Grand Gulf via two service transformers. The preferred source of
electrical power for Grand Gulf electric loads is the 500 kV offsite power supply. The Grand Gulf connection to
the 115 kV Transmission System is a separate (back-up) source of offsite power to Grand Gulf.
Analysis:
MISO incorporated the Entergy’s South Nuclear Plants 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 Entergy’s South Nuclear Plants were incorporated into
the MISO CSA study. The results showed that the NPIRs met the required Entergy’s South Nuclear Plants
performance criteria.
27
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Waterford
Description:
Waterford 3 is connected to the utility grid by two transmission lines to the Waterford 230 kV Switchyard via
the Switching Station. The Waterford 230 kV Switchyard also has several other 230 kV transmission lines
connected to it. Three of these transmission lines connect Waterford Units 1 and 2 to the Switchyard. Three of
the transmission lines cross the river on two separate river crossing towers to tie into the Little Gypsy 230 kV
Switchyard. There is a 230 kV tie to the adjacent 500 kV Switchyard. There are other transmission lines which
tie to other areas of the Entergy grid. The system is designed such that no transmission lines cross the 230 kV
lines connecting the Waterford No. 3 switching station to the Waterford No. 3 230 kV Switchyard. In addition
to the 230 kV lines connected to the switchyard, there is also a line constructed to 230 kV standards but
operating at 115 kV, which passes through the 230 kV switchyard.
Power is supplied from the main generator to the Waterford 3 switching station through two main transformers
which are in parallel. From the switching station, two overhead lines transmit power to the Waterford
switchyard, which is the point of connection to the grid. The Plant Electric Power Distribution System receives
power under normal operating conditions from the main generator through two unit auxiliary transformers. For
start-up and shutdown, when the main generator is unavailable, power is obtained through two startup
transformers from the grid through the switchyard transmission lines and the switching station. When Waterford
3 is not operating, an additional path of supply from the switching station to the Plant Electric Power
Distribution System may be made available by opening links in the generator main lead box and by using the
main transformers and unit auxiliary transformers instead of the start-up transformers. The Waterford 3 (WF-3)
Plant is comprised of one unit rated at 1,333.2 MVA. The Waterford 3 (WF-3) maximum auxiliary station
service load is 71.33 MW and 34.21 Mvar. The step-up transformer bank for the generating unit is comprised of
two (2) three-phase transformers units, one of the transformer (GSU-3A) is rated at 684 MVA (FOA) the other
transformer (GSU-3B) is rated at 672 MVA.
Analysis:
MISO incorporated the Entergy’s South Nuclear Plants 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 Entergy’s South Nuclear Plants were incorporated into
the MISO CSA study. The results showed that the NPIRs met the required Entergy’s South Nuclear Plants
performance criteria.
28
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Riverbend
Description:
River Bend is connected to the utility grid by two transmission lines to the Fancy Point 230 kV Switchyard. One
transmission line is a double circuit line with one circuit feeding the plant and the other connecting the generator
to the grid. The Fancy Point 230 kV Switchyard also has four other 230 kV transmission lines connected to it as
well as a connection to the Fancy Point 500 kV Switchyard. The Fancy Point 500 kV switchyard is connected to
two 500 kV transmission lines.
The Riverbend (RBS) Plant is comprised of one unit rated at 1,151.1 MVA. The RBS maximum auxiliary
station service load is 84.7 MW and 59.7 Mvar. The step-up transformer bank for the generating unit is
comprised of two (2) three-phase transformers units rated at 518/788.5 MVA (65o C FOA/FOA). River Bend
Station uses two 230/13.8 kV Preferred Station Service Transformers and two 230/4.16 kV Preferred Station
Service Transformers to provide the unit with offsite power.
Analysis:
MISO incorporated the Entergy’s South Nuclear Plants 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 Entergy’s South Nuclear Plants were incorporated into
the MISO CSA study. The results showed that the NPIRs met the required Entergy’s South Nuclear Plants
performance criteria.
29
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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 offsite 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.
30
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Monticello Plant
Description:
The Monticello plant is located in central Minnesota, along the Mississippi river. 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.
31
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
Duane Arnold Energy Center
Description:
The Duane Arnold Energy Center (DAEC) is a nuclear plant located in Palo, IA just outside of Cedar Rapids,
IA. 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.
32
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
10.0 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
33
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
11.0 ABBREVIATIONS AND ACROYNMS
MISO North 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 Central 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.
34
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
MISO South Region:
CLEC
EAI
PUPP
PLUM
OMLP
CWAY
NLR
BUBA
WMU
EES
DER
BRAZ
LAFA
LAGN
LEPA
SMEPA
BBA
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
Brazos Electric Cooperative
Lafayette Utilities System
Louisiana Generation LLC
Louisiana Energy and Power Authority
Southern Mississippi Electric Power Association
Batesville Generation
MISO Tier-1:
AEC
AECI
AEP
AEPW
ATSI
CE
DAY
DEO&K
EEI
EKPC
LGE/KU
EMDE
GMO
IESO
KACP
LES
NPPD
OKGE
OPPD
SOCO
SPC
SPP
SWPA
TVA
Alabama Electric Corporation (Power South)
Associated Electric Cooperative, Inc.
American Electric Power
AEP – Southwest Power Company
American Transmission System Inc. (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 District
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
Southern Company
Saskatchewan Power Company
Southwest Power Pool
Southwestern Power Administration
Tennessee Valley Authority
35
MISO Coordinated Seasonal Assessment – 2014 Spring
Contains CEII – Do Not Release
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
SERC Reliability Corporation
Western Electric Coordinating Council
36