MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Appendix D1: American Transmission Company LLC
Baseline Reliability Projects
Project 3110/3111: Dane County Corrective Plan Phase 1
Project Description:
These projects are to install switched capacitor banks at Femrite and Kegonsa 138 kV
stations in the Madison, WI area. Each station will gain a single-stage 32.66 MVAR bank
with switching speeds of 1 and 1.5 seconds, respectively. A new position will also be
created on the existing 138 kV bus at Kegonsa. This is Phase 1 of a 3-phase load-andcapacitor project scheduled to be complete by 2016. The total estimated cost of this project
is $3.2 million ($1.2 and $2.0 million, respectively). The expected in service date for this
project is June 1, 2011.
The project is shown in the figure below.
Figure P3110.1: Geographic Transmission Map of Project Area
1
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project Justification:
The Dane County transmission system is at risk of low voltages or voltage collapse for several
category C2 and C5 events starting in 2011. This risk is pronounced during load peak hours of
expected generation availability and shoulder peak hours of low online generation in Dane
County. As C2 and C5 events are simultaneous multiple-outage events, manual system
adjustment (anticipatory load shedding, redispatch, etc) following the “first event” is not
available. Large local VAR sources are necessary to avoid calling upon generation and
demand response resources out of economic order or shedding load in anticipation of the next
event.
This voltage risk will be further mitigated by the commissioning of the Rockdale-Cardinal 345 kV
line, currently under construction, in 2013.
PV Analysis
Figure 3110.2 demonstrates an optimistic 2012 scenario in which all potentially-available Dane
County generation is fully committed and a severe event occurs. Curves represent the voltage
at the Fitchburg 138 kV bus, typically the lowest-voltage location in Dane County, for a range of
Dane County demand levels. The 50/50 MGE load forecast is indicated at 768 MW, the 90/10
at 797 MW. In a 90/10 year, in the most optimistic generation scenario, Plot 3110.2.1 indicates
that voltages in Dane county could dip to 0.9 per unit for a single-initiating event. The PV
curves also indicate that operators could not maintain a 10% load margin from the nose of the
PV curve in a 90/10 year.
Plot 3110.2.2 indicates that installing capacitors at Kegonsa and Femrite ensures system
stability for these disturbances well through 2012.
Cost Allocation:
This is a Baseline Reliability Project. It is not eligible for regional cost sharing.
2
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Figure P3110.2 P/V Curves at Fitchburg 138 kV bus for 3 severe events, before and after Projects
3110 and 3111
3
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project 3120: Straits Reactor Banks
Project Description:
This project is to install a 10 MVAR reactor on the tertiary of the Straits 138/69 kV
transformer T1 and a 15 MVAR reactor on the tertiary of T2. These bays are currently
unoccupied. The total estimated cost for this project is $2.1 million, and the estimated inservice date is September 15, 2010.
The project is shown in the figure below. Michigan’s Lower Peninsula is not pictured, but is
linked via underwater 138 kV cable at Straits.
Straits
138/69 kV
T1 & T2
Figure 3120.1: Geographic Transmission Map of Project Area
Project Justification:
This project is driven by operations concerns. ATC and Midwest ISO Operations regularly
observe high voltages, sometimes in excess of Operations criteria, in the eastern U.P. Michigan
at system normal condition.
Cost Allocation:
This is Baseline Reliability Project. It is not eligible for regional cost sharing.
4
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project 1626: Summit Capacitor Banks
Project Description:
This project is to install two 24.5 MVAR 138 kV capacitor banks at Summit substation in
western Waukesha County, WI. The total cost of this project is $2.1 million. The project
was placed into service on May 21, 2010.
The project is shown in the figure below.
Figure P1626.1: Geographic Transmission Map of Project Area
Project Justification:
Busses along the Summit-Merrill Hills, Summit-Sussex, and Summit-Concord 138 kV paths
have marginal voltages at system normal conditions: approximately 0.975 in June 2010.
Capacitor banks at Summit 138 boost area voltages to at least 0.985.
Alternatives Considered:
Regularly dispatch peaking generation at Concord (case contains four 119 MVA gas CTs).
Cost Allocation:
This is a Baseline Reliability Project. It is not eligible for regional cost sharing.
5
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project 1940: M38 Capacitor Bank
Project Description:
This project consists of expanding and reconfiguring the M38 substation to accommodate a
new 8.16 MVAR, 138 kV capacitor bank. The project cost totaled $3.3 million. It was
placed into service in October, 2009.
Project Justification:
An N-1 outage at peak of one of the two 138 kV lines from Marquette, MI that serves the M38
substation and Ontonagon, Houghton, and Baraga counties causes low voltages on the 138 kV
system at M38 and beyond. The project mitigates low voltages. Dispatching diesel generators
in the area is expensive and resources may not be available.
Cost Allocation:
This is a Baseline Reliability Project. It is not eligible for regional cost sharing.
Project 2821: Replace North Fond du Lac 138/69 kV transformers T31 and T32
with a single 100 MVA unit
Project Description:
This project consists of replacement of the two existing T3 units with new 100 MVA unit. The
existing banks are hobbled in parallel under the same protection. The project cost is projected
to be $3.3 million, and the expected in service date is December 31, 2010.
Project Justification:
This project is needed because the existing NFL T3 banks are end-of-life.
Cost Allocation:
This is a Baseline Reliability Project. It is not eligible for regional cost sharing.
6
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Generator Interconnection Projects
Project 2837: Uprate Cypress-Arcadian 345 kV line
Project Description:
This is a ground-clearance uprate project. The CYP-ADN 345 kV line will be uprated to a
summer normal rating of 125 F/50 C. The total cost of this project is $200,000. The project
was completed in December, 2009.
Project Justification:
See Generator Interconnection Project G833/4-J022/3.
Cost Allocation:
This is a Generator Interconnection Project, eligible for regional cost sharing.
Project 2793: Uprate Point Beach-Sheboygan Energy Center 345-kV
Project Description:
This is a ground-clearance uprate project. The POB-SEC 345 kV line will be uprated to a
summer normal rating of 167 F/75 C. The total cost of this project is $2.9 million. The
project was completed on March 1, 2010.
Project Justification:
See Generator Interconnection Project G833/4-J022/3.
Cost Allocation:
This is a Generator Interconnection Project, eligible for regional cost sharing; however the
LODF for this project is zero.
7
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Other Projects
Project 2819: Replace Bluemound 230/138 kV Transformer T3
Project Description:
This project consists of replacement of the existing 230/138/13.8 kV transformer T3 with a new
500 MVA bank and the associated relaying. The total estimated cost is $8.0 million. The
project is expected to be in service by November 30, 2011. The project is associated with
project 2820: replacement of the second Bluemound bank, due in May 2012.
Project Justification:
The Bluemound transformers are at end-of-life.
Cost Allocation:
This is an Other Project. It is not eligible for regional cost sharing.
Project 2032: 2nd Shorewood-Humboldt 138 kV UG cable
Project Description:
This project consists of adding a second parallel underground 138 kV cable from Shorewood
substation to the Humboldt riser.
Project Justification:
The Shorewood load is served by two underground 138 kV cables, one to Glendale substation
and one to the Humboldt riser. The Humboldt line continues overhead to Cornell substation. If
one of the two circuits is out of service for maintenance, then the next outage would force load
shedding at Shorewood. The parallel cable from Shorewood to Humboldt would reduce the risk
of load shedding.
Cost Allocation:
This is an Other project, driven by reliabilty needs. It is not eligible for cost sharing.
Project 2451: Rebuild Brodhead-South Monroe 69 kV
Project Description:
This project consists of a line rebuild of Brodhead to South Monroe 69 kV with T2 477 kcmil
ACSR. The line can be found in ATC Zone 3, southern Green County, WI. The estimated cost
is $11.8 million, and the estimated ISD is March 1, 2012.
Project Justification:
During a peak condition, this line is overloaded and Monroe is voltage-depressed for the loss of
North Monroe – Idle Hour 69 kV, the North Monroe 138/69 kV transformer, or the TownlineBass Creek 138 kV line. The rebuild will reduce the impedance by 42% and double the SE
rating, eliminating the violations.
Cost Allocation:
This is an Other project, driven by reliabilty needs. It is not eligible for cost sharing.
8
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project 3094: Construct a new Milton Tap-Milton 69 kV line
Project Description:
This project consists of a tap on the Y-61 line in Rock County and a new 69 kV line to a new
Milton station. The project cost is projected to be $3.0 million, and the expected in service date
is December 15, 2010.
Project Justification:
This project is needed to serve load in Milton, WI.
Cost Allocation:
This is a Distribution Project. It is not eligible for regional cost sharing.
Project 2033: Uprate Bain-Kenosha 138 kV
Project Description:
This project consists of upgrading substation equipment at Bain and Kenosha to raise the
overall line rating to the conductor rating. The estimated cost is $7.0 million, and the expected
in service date is November 10, 2010.
Project Justification:
This project is driven by economics. It is the least-cost near-term project identified by the study
team in the Cross Border Top Congested Flowgate Study, Lake Michigan section.
Cost Allocation:
This is an Other project, economics type. It is not eligible for regional cost sharing.
Project 1731: Replace Blount-Ruskin 69 kV
Project Description:
This project consists of replacing an existing 2x69 kV overhead BLT-RKN circuit through urban
Madison, WI with a single underground 69 kV cable. The estimated cost is $6.5 million, and the
expected in service date is March 2011.
Project Justification:
MGE has an agreement with the City of Madison to move BLT-RKN underground.
Cost Allocation:
This is an environmental project. It is not eligible for regional cost sharing.
Project 1690: Rebuild Verona-Oregon 69 kV
Project Description:
This project consists of rebuilding the Verona-Oregon 69 kV line south of Madison, WI. The
cost is $6.5 million, and the project was placed into service in June, 2010.
9
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project Justification:
Loads are growing in the Oregon area. If Stoughton-Stoughton South 69 kV is out of service at
peak (hanging Oregon off of Verona) voltages in the Oregon area can sag below 0.95 pu.
Reducing the VER-ORE impedance keeps voltages in southern Dane County near 1.0 pu.
Cost Allocation:
This is a reliability (Other) project. It is not eligible for regional cost sharing.
Project 2840: Rebuild Blanchardville-Forward 69 kV line
Project Description:
This line was rebuilt in March, 2010 to address performance (lightning protection, voltage
support) and condition issues. The cost was $5.2 million.
Project 2835: Rebuild Chaffee Creek-Plainfield 69 kV line
Project Description:
This line was rebuilt in March, 2010 to address performance (lightning protection, voltage
support) and condition issues. The cost was $5.0 million.
Project 2841: Replace existing Council Creek 138/69 kV transformer
Project Description:
The Council Creek transformer is end-of-life and is scheduled to be replaced in November,
2010. The estimated cost is $3.3 million.
Project 3090: Wick Drive T-D interconnection
Project Description:
This project installed 0.4 miles of new double circuit 69 kV line to interconnect a new, breakered
substation on the Spring Green-Stagecoach line. The project was placed in service on March 1,
2010 for approximately $4.8 million.
Project 2836: Rebuild Whitcomb-Deer Trail 69 kV line
Project Description:
This project consists of rebuilding 4.8 miles of line Y-86 with T2-4/0 and replacing 19 poles. The
estimated cost is $3.7 million, and the estimated in service date is March 15, 2011.
Project Justification:
This project is needed due to condition and performance issues of the existing line.
10
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project 2028: Uprate the Y-61 69 kV line and add capacitors at Lamar
Project Description:
This project consists of uprating the McCue-Lamar 69 kV line in Rock County, WI to a conductor
maximum and adding a 2x12.45 MVAR capacitor bank at Lamar. The total estimated cost for
the project is $2.9 million, and the estimated in service date is November 10, 2010.
Project Justification:
This project is needed to mitigate numerous thermal violations for N-1 contingencies.
Project 3122: Reconductor a section of Dam Heights-Okee Tap 69 kV
This project consists of reconductoring 2.0 miles of Dam Heights-Okee Tap 69 kV and replacing
26 lattice towers and 4 poles. The estimated cost is $2.2 million, and the projected in service
date is June 2012.
Project Justification:
This project is driven by the poor condition and performance of the line. Lattice structures are
rusting and date from 1919, arrestors are in poor condition, lightning shield angle is poor, and
there are issues with ground clearance.
11
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Table: Other Small Projects
PrjID
Project Name
884 Spri ng Green 32 (2-16.33) MVAR
ca pa ci tor ba nk
1282 Ins ta l l 1-4.08 MVAR 69 kV ca p ba nk a t
the Os ceol a s ubs ta ti on i n Houghton
County, MI.
1554 Indi a n La ke 138kV Ca pa ci tor Ba nk
Project Description
Estimated Cost Expected ISD
$1,200,000
6/1/2011
$800,000
12/4/2009
$584,007
12/17/2010
$122,666
6/1/2010
$2,800,000
12/16/2009
1691 Upra te McCue-Mi l ton La wns 69 kV l i ne Upra te termi na l l i mi ta ti ons a t McCue
for the McCue-Mi l ton La wns 69 kV l i ne
$800,000
11/25/2010
1704 Upra te Sheeps ki n-Da na 69 kv l i ne
$726,000
4/12/2010
$120,642
6/9/2010
1627 Upra te Ba i n-Al bers 138-kV l i ne
1686 Bra ndon-Fa i rwa ter 69 kV l i ne
2-16.33 MVAR 69 kV ca pa ci tor ba nks a t
Spri ng Green
Ins ta l l 1-4.08 MVAR 69 kV ca p ba nk a t
the Os ceol a s ubs ta ti on i n Houghton
County, MI.
Ins ta l l 2x8.16 MVAR Ca pi ca tor ba nk a t
Indi a n La ke s ubs ta ti on
Increa s e cl ea ra nce of the Ba i n-Al bers
138-kV l i ne
Cons truct Bra ndon-Fa i rwa ter 69 kV l i ne
2163 Repl a ce El l i nwood Tr #2
Upra te Sheeps ki n-Da na 69 kv l i ne to
95 MVA
Increa s e l i ne cl ea ra nce to 187 deg F
SN/SE
Increa s e l i ne cl ea ra nce to 187 deg F
SN/SE
Upra te X23 Col l ey Rd Termi na l (Col l ey
Rd-Ma ri ne)
Repl a ce El l i nwood 138-69 kv Tr #2
2165 Upra te Femri te-Roys ter 69 kV
Upra te Femri te-Roys ter 69 kV
2019 Upra te Cha ndl er Del ta 69 kV #1
2020 Upra te Cha ndl er Del ta 69 kV #2
2035 Upra te X23 Col l ey Rd Termi na l
2451 Brodhea d-S Monroe 69kV Rebui l d
2815
2816
2817
2818
2839
2843
3088
3109
3114
Rebui l d Brodhea d- S Monroe 69kV l i ne
wi th T2 477 kcmi l ACSR
Upra te La ke Pa rk-Ci ty Li mi ts -Ka uka una Increa s e l i ne cl ea ra nce to a chi eve a
Combi ned Locks Ta p 138-kV
200 deg F opera ti ng tempera ture
Upra te Fors yth-Muni s i ng 138kV
Increa s e l i ne cl ea ra nce to a chi eve a
200 deg F opera ti ng tempera ture
Upra te Wi nona -M38 138kV
Increa s e l i ne cl ea ra nce to a chi eve a
125 deg F opera ti ng tempera ture
Upra te Ka uka una Centra l Ta pIncrea s e l i ne cl ea ra nce to a chi eve a
Mea dows Ta p-Mel i s s a 138kV
200 deg F opera ti ng tempera ture
Poi nt Bea ch #2 upra te
G833-J022 Poi nt Bea ch #2 upra te
i ncrea s e Pma x from 514 MW to 617.06
MW & repl a ce GSU
Upra te the Autra i n 69-kV l i ne
Increa s e ground cl ea ra nce for the
Autra i n 69 kV l i ne to 293 Amps for a l l
s ea s ons
Ins ta l l Di s tri buti on Ca ps a t Di cki ns on Ins ta l l 2x 9.6 Ma r Di s tri buti on Ca ps on
the l ow vol ta ge s i de of the Di cki ns on
138/24.9 kV Tr a t Di cki ns on for
tra ns mi s s i on vol ta ge s upport
Increa s e ground cl ea ra nce for the Ea s t Increa s e Ea s t Krok-Kewa unee 138kV
Krok-Kewa unee 138kV l i ne to 200 deg f l i ne ground cl ea ra nce
cl ea ra nce
Upra te CRBU11 l i ne Cra nberry-St
Increa s e ground cl ea ra nce for the
Germa i n 115kV
CRBU11 l i ne Cra nberry-St Germa i n
115kV by movi ng a di rt mound
12
10/31/2012
$2,592,000
6/1/2010
$2,012,243
10/22/2010
$441,446
5/12/2010
$11,800,000
3/1/2012
$18,740
3/4/2010
$133,334
10/31/2010
$380,619
3/1/2010
$852,153
6/30/2010
5/31/2011
$260,000
3/31/2011
$362,000
6/1/2010
$1,254,433
12/31/2010
$1,000
5/1/2010
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
PrjID
Project Name
Project Description
3115 Upra te Fi tchburg-Syene-Ni ne Spri ngs
69kV l i ne
Increa s e ground cl ea ra nce for
Fi tchburg-Syene-Ni ne Spri ngs 69kV l i ne
3116 Rebui l d/upra te Y-207 Si gel Auburnda l e-Rozel l vi l l e 69kV l i ne
3123 Upra te Perch La ke-M38 138kV
Rebui l d/upra te Y-207 Si gel Auburnda l e-Rozel l vi l l e 69kV l i ne
Increa s e ground cl ea ra nce for the 605
ACSR Perch La ke-M38 138kV l i ne to 130
deg F cl ea ra nce
13
Estimated Cost Expected ISD
$155,125
3/31/2010
$2,081,005
2/25/2010
$224,500
7/1/2010
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Appendix D1: Great River Energy
Basline Reliability Projects
Project 2670: North Perham 115/41.6 kV Source
Transmission Owners: Great River Energy
Project Description:
This project involves establishing a 115/41.6 kV substation at North Perham Jct. This substation will tap
the Rush Lake – Frazee 115 kV line. The total estimated cost of this project is $4.24 million. The
expected in service date is June, 2013.
The project is shown in the figure below.
North
Perham
Figure P2670-1: Geographic Transmission Map of Project Area
14
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
This project is required to address low voltage concerns in the area. Contingency analysis in the area
show that the loss of the Frazee 115/41.6 kV transformer is the critical contingency that cause near
term low voltage issues. Frazee, Dora, Evergreen and Burlington areas experience low voltage
concerns in the short time during the Frazee 115/41.6 kV transformer outage.
The following forecast is the load served in the area which includes both GRE and OTP loads.
Table P2670-1 Study Area Substation Loads Modeled
Season
Summer
Winter
2011
42.1
42.6
15
2021
52.0
52.4
2031
67.3
66.9
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
Three options have been considered to address the short-term and long-term needs of the area. The first
option includes installing a second 115/41.6 kV transformer at Frazee and rebuilding the nearly 10 mile
line from Dent to Dent Tap with 477 ACSR conductor. The second alternative recommends upgrading the
Frazee and Perham Distribution substations to 115 kV in the short term and establishing a 115/41.6 kV
sub at North Perham junction in the long term (2021 timeframe). These two alternatives didn’t pan out in
the best value analysis.
Cost Allocation:
This is a Baseline Reliability Project which is not eligible for regional cost sharing.
16
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Other Reliability Projects
Projects that are not defined as Baseline Reliability, Generation Interconnection or Transmission
Delivery Service Planning per Attachment FF transmission project definitions but are still
needed for system reliability for various reasons are categorized as “Other” Projects.
Project 2621: Effie 230/69 kV Source
Transmission Owners: Great River Energy
Project Description:
This project consists of a new Effie 230/69 kV substation that would tap the Little Fork-Shannon 230 kV
line. A new 20 mile, 69 kV line would be established from the Effie substation to the North Itasca Electric
Cooperative (NIEC) Big Fork substation.
A new source at Effie would provide looped service to the NIEC substations and provide support to the
Deer River area, especially on loss of the MP 115 kV system out of Boswell Generating Station. The total
estimated cost of this project is $10.6 million. The expected in service date for this project is June, 2013.
The project is shown in the figure below.
Proposed Location
Figure P2671-1: Geographic Transmission Map of Project Area
17
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
This area consists of the load served between Deer River and Blackberry 115/69 kV substations. The 62
mile, 69 kV line that serves the NIEC service territory is also included in this area. The radial Deer RiverBoswell 115 kV line which includes some 115 kV loads (including the GRE Cohasset load) was examined
for the capability of the 69 kV system in supporting the 115 kV load. The 2011 winter load is projected to
surpass the 2003 Long Range Plan’s 2026 winter load projection.
Long-term Deficiencies
Overloads
Rating Estimated
MVA
Year
46.7
2012
56
2014
13.3
2015
9.7
2021
Facility
Blackberry 115/69 kV transformer
Deer River 115/69 kV transformer
Deer River-Jessie Lake 69 kV
Jessie Lake-Wirt Tap 69 kV
Voltage Deficiencies
Estimated
Substation
Year
Big Fork 69 kV
2010
Wirt 69 kV
2010
Evenson 69 kV
2010
Jessie Lake 69 kV
2014
2011
%
91.0
91.7
91.2
94.4
2011
MVA
57.8
64.0
11.3
10.5
2021
MVA
78.7
83.9
16.3
7.1
2021
%
79.8
80.5
80.1
84.6
Table P2671-1, 2 Long-term Deficiencies
The following is the load projections that are served from this system which contain both GRE and MP
load:
Season
Summer
Winter
2011
45.9
68.6
18
2021
57.4
86.5
2031
67.2
104.2
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2671.2-1a: 2015 Winter Pre Blackbery xfmr
19
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2671.2-1b: 2015 Winter Post Blackbery xfmr
Alternatives Considered
Alternatives look at reducing the radial nature of the NIEC area. Option 1 provides a new source at Big
Fork via a new Effie 230/69 kV substation tapping the Running-Shannon 230 kV line. Option 2 looks at
adding generation to the NIEC system and providing looped 115 kV service to the Deer River substation.
NIEC generation and Deer River area transmission system improvements.
This option adds in generation at Big Fork and Evensen to avoid transmission development to loop the
NIEC loads. Generation is added based on projected load growth to serve the NIEC system if
disconnected from the Deer River source. 115/69 kV transformers at Blackberry (replacement) and Deer
River (second unit) would alleviate transformer loading issues seen at those locations. A 115-69 kV
double circuit from Arbo Tap to Deer River (tapping the MP 28 Line) would loop in the Deer River
substation and provide support to Deer River upon loss of the 115 kV tie out of Boswell.
A present worth analysis was performed with Option 1 being used as a benchmark for loss savings. Loss
savings for Option 2 are as follows:
20
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Option
2
2011
Summer
-0.6
2021
Summer
-1.1
2031
Summer
-1.4
With the loss allocations, the present worth is summarized as follows (in 1000’s):
Option
1
2
Cumulative
Investment
$24,091
$51,665
Present
Worth
$37,185
$61,225
Present Worth w/
Loss Savings
$55,916
Option 1 is the least cost plan and requires the least amount of investment.
Option 1 provides the NIEC radial system with looped service and better transmission reliability while
offering support to the Deer River area. The Effie source can be sized to accommodate long-term load
growth whereas generation investment would require continual investment as load growth occurs.
Depending on system growth, a second, future 115 kV source into the Deer River substation would
reduce the effects of losing the Boswell tie.
Cost Allocation:
Shared status is Other (Reliability), not shared
21
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2672: Rush City – Bear Creek – Effie Transformer Swap
Transmission Owners: Great River Energy
Project Description:
This project involves the purchase of one 140 MVA 230/69 kV transformer to place at the
Rush City substation. The existing 84 MVA Rush City 230/69 kV unit would be moved to the
Bear Creek substation while the existing 60 MVA Bear Creek 230/69 kV unit would be
moved to the new Effie substation location. The total estimated cost of this project is $3.2 million.
The expected in service date for this project is December, 2011.
The project is shown in the figure below.
22
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
23
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2672-1, 2, 3: Geographic Transmission Map of Project Area
Project Justification:
Load growth along the I-35 Corridor causing the Bear Creek and Rush City 230/69 kV
transformers to approach their loading limits. Additionally, the new Effie substation requires
a 230/69 kV transformer. This project allows for a single transformer purchase while
allowing for adequate transformer capacity at the three substations in question.
24
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2672-2-1a: 2015 Summer Pre Rush City xfmr
25
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2672-2-1b: 2015 Summer Post Rush City xfmr
Alternatives Considered
The alternative to this project would to purchase three separate transformers for each
substation in question.
Cost Allocation:
Cost sharing status is Other ( Reliability), Not shared.
26
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2636: Spicer 230/69 kV Source
Transmission Owners: Great River Energy
Project Description:
This project involves establishing a new Spicer 230/69 kV substation and constructing up to a 2.0
mile double circuit line from Spicer to Green Lake area. The Spicer substation will tap the Willmar –
Paynesville 230 kV line. The total estimated cost of this project is $9.2 Million. The expected inservice date for this project is 2015.
The approximate location of the project is shown in the figure below
Spicer
Figure P2636-1: Geographic Transmission Map of Project Area
Project Justification:
The 69 kV system in the Willmar area is served with a 230/69 kV and 230/115 kV sources which are both
at Willmar. This area was found to experience low voltage and transmission loading problems in the short
term during contingencies. The loss of the Willmar to Kandiyohi 69 kV line causes low voltage problems
on the 69 kV system between Sunburg and Kandiyohi. The same contingency was found to cause
loading issues on the Sunburg to Hawwick 69 kV system.
27
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2636-2-1a: 2015 Pre plan Kandiyohi – Wilmar out
28
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2636-2-1b: 2015 Post plan Kandiyohi-Wilmar out
Alternatives Considered
One alternative was considered to address the long term deficiencies of the area. This alternative
includes constructing a 9.6 mile 69 kV line from Paynesville to Hawick and establishing a breaker station
at Hawick. This alternative however was found to be insufficient to address the long term needs of the
area. The Willmar area experiences severe low voltage problems with this alternative for the loss of the
Willmar 230/69 kV and 115/69 kV transformers at the same time.
29
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Cost Allocation:
This is an Other (Reliability) project which is not eligible for regional cost sharing.
Table D1_West_GRE: Other (Low Cost) Projects
Project Description
Potato Lake (IM) 7 mile, 115 kV line
Need Summary
New Distribution Tap on 34.5 kV
Other
Project
Type
Distribution
2573
H-Frame 230 kV Storm Structures
Line Protection to Dominoe effect
2574
St. Lawrence Substation and Tap - MVEC
2577
Elmcrest (CE) 69 kV Substation
2579
Estimated
Cost
$3,226,245
Expected
ISD
7/11/2011
Reliability
$526,397
5/24/2010
New Distribution Tap
Distribution
$370,231
5/1/2014
New Distribution Tap
Distribution
$140,000
5/3/2011
Foster Lake (WH) 69 kV Substation
New Distribution Tap
Distribution
$140,000
4/29/2011
2581
Niniger (DEA) 115 kV Substation
New Distribution Tap
Distribution
$219,051
5/2/2011
2585
Woodland (WH) 1 mile, 115 kV line
New Distribution Tap
Distribution
$621,187
6/1/2011
2589
Barnes Grove (DEA) 2.0 mile, 69 kV line
New Distribution Tap
Distribution
$950,000
5/1/2012
2605
Bunker Lake #2 (CE at GRE) 69 kV Substation
New Distribution Tap
Distribution
$107,972
3/1/2011
2620
Sandstone-Sandstone MP Temperature Upgrade
Overloaded based on line temperature
Reliability
$74,400
12/1/2010
2624
115 kV conversion
Overloaded transformer
Distribution
$380,000
11/1/2011
2648
Milaca Breaker
Overloaded line on Contingency
Reliability
$169,561
12/15/2009
2667
Rush City-Adrian Robinson Rush City Dist Retemp
Overloaded line on Contingency
Reliability
$284,800
6/1/2012
2671
Soderville-Ham Lake-Johnsville (6.18 mi.) Retemp
Overloaded line on Contingency
Reliability
$257,000
6/1/2010
2833
Lake Caroline (WH) 69 kV Distribution Substation
New Distribution tap 1 mile in length tappiing
near Xcel's South Haven substation
Distribution
$570,000
7/22/2012
Project ID
2566
30
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Generation Interconnection Projects
Table D1_West_GRE: Generation Interconnection Projects
Project ID
3104
Project Description
Required equipment: 1485.4 MV A rating at Wilmarth
sub, it is necessary to replace two existing 345kV
2000A gas circuit breakers (8S23 & 8S25) with 3000A
gas
Need Summary
GIP 514
Allocation
Type per
FF
GIP
GIP252
115 kV Rebuild from Tamarac to Cormorant
Junction
Estimated
Cost
$796,000
Expected
ISD
10/1/2009
GIP
$150,000
11/30/2009
GIP
$2,630,000
10/12/2011
circuit brealcers.
Replace two existing 345kV 2000A gas circuit
breakers (8S23 & 8S25) with 3000A gas
3105
circuit brealcers.
3-way group operated disconnect
3106
Tamarac-Cormorant Junction
31
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Transmission Delivery Service Planning Projects
Project 1018: Little Falls (CWP) Conversion to 115 kV
Transmission Owners: Great River Energy
Project Description:
MP Little Falls – Crow Wing Power Little Falls, 3.0 mile, 795 ACSS, 115 kV line and 115 kV
substation conversion. The total estimated cost of this project is $1.7 million. The expected in
service date for this project is November, 2011.
The project is shown in the figure below.
Potential Corridor
Figure P1018-1: Geographic Transmission Map of Project Area
Project Justification:
Conversion of the area GRE loads to 115 kV will greatly extend the life of the 34.5 kV system and provide
34.5 kV loading relief to the regulating stations. This project would also be a start to establishing a 115 kV
path to Little Falls from Lastrup will also provide a future tie to a Pierz 230/115 kV source to help with bulk
system voltage support around the Little Falls area.
The transmission system in this area is already deficient for both line overloads and voltage violations.
They are as follows:
32
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Overloads
Rating
MVA Outage
10
Little Falls Bulk-GRE Little Falls 34.5 kV
18
Little Falls Bulk-GRE Little Falls 34.5 kV
18
Little Falls Bulk-GRE Little Falls 34.5 kV
18
Little Falls Bulk-GRE Little Falls 34.5 kV
Facility
Royalton 34.5 kV regulator
Royalton Regulator-Rice Tap 34.5 kV
Rice Tap-Little Rock 34.5 kV
Little Rock-526-511 Tie Sw. 34.5 kV
Substation
Pierz Regulator 34.5 kV
Rich Prairie 34.5 kV
Buckman 34.5 kV
Lastrup 34.5 kV
Lastrup 34.5 kV
Pierz Regulator 34.5 kV
Pierz 34.5 kV
GRE Little Falls 34.5 kV
Lastrup 34.5 kV
Little Rock 34.5 kV
Pierz 34.5 kV
GRE Little Falls 34.5 kV
Little Falls 34.5 kV
2011
%
92.1
92.6
93.7
97.6
101.2
99.0
99.0
102.8
97.2
97.2
102.4
100.4
101.1
Voltage Deficiencies
2021
%
Outage
75.8 Little Falls Bulk-GRE Little Falls 34.5 kV
77.3 Little Falls Bulk-GRE Little Falls 34.5 kV
79.5 Little Falls Bulk-GRE Little Falls 34.5 kV
88.7 System Intact
101.5 Little Falls Bulk-GRE Little Falls 34.5 kV
91.2 System Intact
91.1 System Intact
83.5 Little Falls Bulk-GRE Little Falls 34.5 kV
88.2 Rice Tap-61k Distribution 34.5 kV
86.0 Little Falls Bulk-GRE Little Falls 34.5 kV
83.7 Little Falls Bulk-GRE Little Falls 34.5 kV
93.1 System Intact
94.6 System Intact
2011
MVA
19.2
19.2
18.8
17
Estimated
Year
2013
2013
2014
2014
2016
2016
2016
2017
2017
2018
2018
2019
2021
The GRE criteria are to have a 95% System Intact voltage and a 92% contingent voltage at GRE buses,
whereas MP buses have a criterion of 90% during contingency conditions.
The following forecast is the load served in the Blanchard – Platte River – Little Falls area. This load
includes GRE and MP substations.
Season
Summer
Winter
2011
28.7
24.6
33
2021
35.3
31.1
2031
35.7
32.5
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
The immediate issue in this area is relieving the flow on the 34.5 kV system upon loss of the Little Falls
source. Also, it already takes two regulators to maintain voltage when the tie out of the Little Falls is lost.
Taking these items into consideration, only one alternative was tested.
Present worth analysis was not performed as there are no counter options provided for proposed plan.
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
34
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2564: Sartell (SEA) 2 mile, 115 kV line
Transmission Owners: Great River Energy
Project Description:
SEA has proposed a Sartell distribution substation which will be located about 2.5 miles east of the
existing Fisher Hill distribution substation. This substation is expected to tap the 115 kV line from Le
Sauk Tap to LeSauk after the LeSauk 69 kV sub is upgraded to 115 kV. The total estimated cost of
this project is $1.2 million. The expected in-service date for this project is February, 2011.
The project is shown in the figure below.
Sartell
Figure P2564-1: Geographic Transmission Map of Project Area
Project Justification:
The Sartell distribution substation is required by Stearns Electric to accommodate present and
future residential/commercial load growth in the City of Sartell. The sub will also relieve loading
from the Le Sauk, Fischer Hill & Westwood distribution substations as well as provide backfeed
capability in the surrounding area.
35
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
Upgrading existing distribution transformers and building new feeders to pick up growing
loads were found to be an insufficient option for the area. Load in the area is expected to
grow significantly and therefore a new distribution substation is required to provide reliable
service in the area.
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
36
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2565: Frazer Bay Development
Transmission Owners: Great River Energy
Project Description:
Lake Country Power has proposed a Frazer Bay substation roughly 10 miles east of Cook in the Lake
Vermillion area. This substation will be served will initially be served from a new Tower 115/69 kV
substation since the Shannon-Virginia 69 kV loop can not handle this new load. This line is estimated
to be about 15 miles in length and will terminate at the new Tower 115/69 kV substation. The
conductor is proposed to be 477 ACSR operated at 69 kV.
The second phase of the project is completing the loop between Frazer Bay and Cook and
establishing a 69 kV breaker station at Cook to address voltage concerns on the Shannon-Virginia 69
kV loop.
The total estimated cost of this project is $16.5 million from Tower to Cook. The expected in service
date for this project is November, 2012.
The project is shown in the figure below.
Proposed Route
Figure P2565-1: Geographic Transmission Map of Project Area
37
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
The voltages need to be improved immediately due to a 50% growth in load over the last 5 years. This
can be done by placing capacitors at the distribution substations or by installing a large parallel capacitor
bank at Potlatch breaker station. However due to the load growth, nearly 10% on a winter annual basis,
capacitors would only be for the short-term and would not be a good investment. Also, the load will
approach the emergency capability of the transformers at Shannon and Virginia around 2020. A third
source is needed for the area. The critical outages are loss either of the three sources of Shannon,
Virginia, or Tower.
38
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Voltage Deficiencies
Estimated
Substation
Year
Existing
Side Lake
Meadowbrook
Existing
Cook
Existing
Potlatch
Existing
Sand Lake
Existing
Pike River
Existing
Tower
Existing
Frazer Bay
Existing
Orr
2012*
*Deficient when built
2011
%
77.9
79.0
79.6
77.9
75.8
78.2
85.6
85.0
78.8
GRE realized this significant growth was occurring and immediately began the process for developing the
Tower 115 kV source jointly with MP to facilitate a 69 kV line to the proposed new Frazer Bay substation.
Following this construction, the Frazer Bay line would be extended into to Cook to establish a third source
into the Shannon-Virginia 69 kV loop.
The following is the load forecasted for this system.
Study Area Substation Loads Modeled
Season
Summer
Winter
2011
24.3
53.4
39
2021
30.9
71.6
2031
40.1
97.9
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
Option 1: Frazer Bay-Cook 69 kV line
The plan would be to connect the Tower source through Frazer Bay into Cook. The alternative would be a
69 kV source from the MinnTac 230/115 kV substation into Potlatch. A 10.8 MVAr capacitor will be
needed in 2023 to support the Pike River load on loss of the Virginia source.
Estimated
Year
2011
2011
2023
Facility
Cook Breaker Station
Frazer Bay-Cook 12 miles, 477 ACSR, 69 kV line
Cook 10.8 MVAr capacitor
Cost
$1,891,000
$5,402,000
$258,200
Option 2: MinnTac 115/69 kV source
This option would establish a 115/69 kV source at the MinnTac 230/115 kV substation, extend a 9.0 mile,
69 kV line to the Sand Lake 69 kV substation from Minn Tac, and build an 18 mile line along railroad
corridor from the Pike River-Sand Lake 69 kV line to Cook substation.
Estimated
Year
2011
2011
2011
2011
2011
Facility
MinnTac, 70 MVA, 115/69 kV source
MinnTac-Sand Lake 9.0 miles, 477 ACSR, 69 kV line
Railroad Tap-Cook 18 miles, 477 ACSR, 69 kV line
Railroad Tap 3-way, 69 kV Switch
Cook 69 kV Breaker Station
Cost
$2,278,375
$2,925,000
$5,850,000
$100,000
$1,891,00
Since the time line is the same it is easy to determine that Option 1 will be the least cost plan and
involves the least amount of investment. Since Tower is already establishing a 69 kV line into the area,
the extra 12 miles from Frazer Bay to Cook is not that much more when compared to the MinnTac
infrastructure that would be developed. Option 1 also allows Frazer Bay to be looped unlike Option 2 thus
an improved reliability is being created. The other concern is that Option 2 is going through a mining area
which may pose some corridor issues.
Future Considerations
The voltage in the area will continue to be a concern, if the load continues to grow as projected. More
capacitance may need to be added to the system to account for the voltage drop on the long 69 kV lines.
The other alternative is looking at rebuilding the aging infrastructure. The Side Lake–Meadowbrook line
will be 70 years old by 2020. This line and other lines could be rebuilt to 115 kV standards while being
operated at 69 kV. Eventually, the option would then involve moving the Shannon or Virginia transformer
closer to Cook, if not at Cook. The benefit is that the LTC transformer will be in the load center alleviating
any voltage concerns. The other alternatives would be adding a fourth source such as the MinnTac option
or another 69 kV line from Tower to Pike River. GRE will need to revisit the area and determine if the load
is continuing to grow and if line rebuilding to 115 kV provides an economical solution compared to
providing a fourth source. At this time, due to age, portions of the SM and PK lines will be considered to
be rebuilt to 115 kV standards and operated at 69 kV until enough of the infrastructure has been replaced
40
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
to move the Virginia or Shannon transformer to a more northerly point such as Cook. The following is the
estimated schedule for replacing the line segments:
Estimated
Year
Facility
2020
Side Lake-Meadowbrook 15.1 mile, 477 ACSR, 115 kV Line
2032
Virginia to Cook (PK) 34.17 mile, 477 ACSR, 115 kV line
Cost
$4,152,500
$9,396,750
Generation Options
The Potlatch plant site would be a great site for a generation plant as it will remove the major load from
this 69 kV system and provide a voltage source when Virginia or Shannon is out of service. A generation
plant in this area could lead to a long-term solution.
Present Worth
No present worth was performed based on Option 1 being clearly the least cost plan.
Viability with Growth
Option 1 is establishing the needed third source. The voltage may continue to be a problem requiring
additional voltage support. One issue is the Side Lake-Meadowbrook line which will be 70 years old by
2020. Replacing this line with a larger conductor and capability of future 115 kV operation will decrease
the voltage drop.
Cost Allocation:
Transmission Service Delivery Project which is not eligible for regional cost sharing.
41
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2567: Northport (BENCO) 1.0 mile double circuit 115 kV line
Transmission Owners: Great River Energy
Project Description:
This project constructs a 115 kV transmission line approximately ¾-mile long line from a tap point on the Xcel
Energy 115 kV line between the South Bend and Wilmarth substations. It also includes the GRE share of the
property costs associated with the space required for future 115 kV circuit breakers at the Northport
substation.
Transmission structures for the new line should be built for the addition of a future 115 kV circuit to afford an
in-and-out configuration at the Northport substation.
Right-of-Way for the line should be obtained as soon as possible. BENCO and GRE have been discussing
the need for the new line and substation with the City of North Mankato. The City would like to have the route
and easements obtained as part of the layout of the industrial/commercial part development.
Xcel Energy is constructing the 3-way, 115 kV tap switch in the Xcel Energy-owned 115 kV circuit between
South Bend and Wilmarth. The new switch is expected to be installed during the reconnection of the
transmission line when the South Bend bulk substation is constructed during 2009.
Other issues that will need research are:
• Need for transfer trip for Northport circuit switcher failure
• Is a wave trap required at Norhport
• Layout of the Northport for future ring-bus
The total estimated cost of this project is $1.57 million. The expected in service date for this project is
May, 2012.
The project is shown in the figure below.
42
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2567-1: Geographic Transmission Map of Project Area
Project Justification:
1
In 2003, BENCO completed a long range plan amendment which recommended the construction of the
Northport distribution substation in order to provided adequate distribution service to the loads in the
developing industrial park area of North Mankato. The original in-service date for the substation was 2008,
however, slower than predicted development has delayed the need until the fall of 2011.
The new substation will provide for contingency support of the loads that are presently served by the Johnson
and Penelope substation as well as normal load service to new loads in the industrial/commercial
development. Northport will be designed for future expansion into a two-bank distribution substation. The
date for the addition of the second bank is not yet known, however it is expected to be at least five years
away. The first transformer is expected to have a 12/22 MVA rating. The initial substation loading is
projected to be about 10 MW.
43
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
The transmission alternatives evaluated to serve this new substation were a tap on the Minn-Valley—
Wilmarth 115 kV line or the Johnson—Penelope 69 kV line, both of which are extremely weak sources
during contingencies.
BENCO evaluated distribution alternatives to the construction of the new Northport substation. The
recommendation was to build the new substation as opposed to upgrading existing feeders from
Penelope and Johnson. New feeders would have a limited capability to serve the anticipated load growth
in the commercial-industrial park. The new substation also provides a more robust source at the new
load point as well as backup capacity for the existing Johnson substation, which is approaching is
distribution bus loading limits during distribution contingencies.
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
44
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2568: Savanna 115/69 kV source
Transmission Owners: Great River Energy
Project Description:
The new Savanna 115/69 kV substation will be established to provide a third source into the Gowan
area 69 kV system. The total estimated cost of this project is $4.5 million. The expected in service
date for this project is February, 2012.
The project is shown in the figure below.
Proposed Substation Location
Figure P2568-1: Geographic Transmission Map of Project Area
45
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
This area suffers from both low voltage problems and thermal overloading issues as the transmission
lines are rather old and constructed of small conductor. The critical contingencies are loss of the Four
Corners or Cromwell sources.
Overloads
Rating Estimated 2011
2021
Facility
MVA
Year
MVA
MVA
Four Corners 115/69 kV transformer
28
2010
35.6
63.0
Cromwell-Cromwell Distribution 69 kV
36.9
2010
38.6
59.4
Four Corners-Solway 69 kV
35.9
2010
38.5
65.2
Cromwell-Wright 69 kV
9.7
2011
9.7
14.5
Cromwell Distribution-Gowan 69 kV
26.8
2014
20.0
42.7
Wright-Round Lake 69 kV
9.7
2018
6.4
10.8
Cromwell 115/69 kV transformer
56
2020
23.3
79.1
Voltage Deficiencies
Estimated 2011
Substation
Year
%
Round Lake 69 kV
2009
85.7
Wright 69 kV
2010
88.1
Palisade 69 kV
2010
85.3
Cromwell Distribution 69 kV
2011
90.2
Grand Lake 69 kV
2011
91.5
Solway 69 kV
2011
91.3
Cromwell 69 kV
2011
89.4
Branden Road 69 kV
2012
92.3
Cedar Valley 69 kV
2013
94.8
Gowan 69 kV
2014
95.6
Lakehead Gowan 69 kV
2014
95.8
2021
%
54.0
60.2
52.8
65.5
77.9
77.5
41.4
80.5
78.7
80.3
81
The following is the load that is expected to be served from this system
Season
Summer
Winter
2011
36.3
54.9
46
2021
50.8
79.3
2031
67.5
102.1
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2568-2-1a: 2015 Summer Peak pre Cromwell
Figure P2568-2-1b: 2015 Summer Peak post Cromwell
47
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
48
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
The alternative to the proposed project would be a Kimberly 115/69 kV source and Kimberly-Palisade
69 kV line. This alternative eliminates 30 miles of radial line exposure and covers for the loss of the
Cromwell 115/69 kV source but cannot support the system enough for loss of the Four Corners 115/69 kV
source. The Savanna 115/69 kV alternative places a source in the middle of the system and can offer
support for a wider range of transmission contingencies. The Savanna substation can serve as a
termination point for a Savanna-Cromwell 115 kV line that is also needed in the area.
Cost Allocation:
Transmission Service Delivery Project which is not eligible for regional cost sharing.
49
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2570: Ravenna (DEA) 161 kV Substation
Transmission Owners: Great River Energy
Project Description:
Construct a tap of the GRE-owned Prairie Island—Spring Creek 161 kV line (DA-SP) to provide an
interconnection for a new DEA distribution substation (Ravenna). To maintain the reliability of the 161 kV
transmission (see operational concerns below), the project would include terminating the 161 kV tap into
bus-mounted 161 kV group operated switches and the construction of 161 kV buswork in the substation.
The total estimated cost of this project is $1.0 million. The expected in service date for this project is
November, 2012.
The project is shown in the figure below.
Figure P2570-1: Geographic Transmission Map of Project Area
50
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
This substation is required by DEA to serve the load in and around the Treasure Island casino on the
Prairie Island Indian reservation. This area includes the growing Tresure Island and Casino which is
served by two feeders from Marshan and Miesville. The loss of one of these feeders or substation causes
load serving problems in the Tresure Island and Casino area. As the load continue growing, the existing
system will not be adequate to serve the area at normal system conditions. The Ravenna distribution
substation will reliably serve the Tresure Island and Casino area and provide back feed service to the
distribution substations in the area during contingencies.
51
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
No significant need to define alternatives for future load serving capability.
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
52
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2576: Pokegama (LCP) 8.0 mile, 115 kV line
Transmission Owners: Great River Energy
Project Description:
Lake Country Power (LCP) has proposed a Pokegama substation that will be served from the 115 kV
system on the MP #11 Line between Grand Rapids and Hill City. Great River Energy is proposing an 8.0
mile, radial 115 kV line to serve this substation, although actual length will be determined by land
acquisition. The total estimated cost of this project is $3.78 million. The expected in service date for this
project is December, 2011.
The project is shown in the figure below.
Potential Corridor
Figure P2576-1: Geographic Transmission Map of Project Area
Project Justification:
GRE is constructing this project to fulfill a member-distribution cooperative interconnection request.
53
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Study Area Substation Loads Modeled
Season
Summer
Winter
2011
45.9
68.6
54
2021
57.4
86.5
2031
67.2
104.2
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
No significant need to define alternatives for future load serving capability.
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
55
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2630: Resag Big Fork – Wirt Tap – Jessie Lake Retemp
Transmission Owners: Great River Energy
Project Description:
Temperature upgrade of the 16.13 mile Big Fork-Wirt Tap-Jessie Lake 69 kV line to 170° F (212° F
desired). The total estimated cost of this project is $1.29 million. The expected in service date for this
project is May, 2012.
The project is shown in the figure below.
Figure P2630-1: Geographic Transmission Map of Project Area
56
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
Summer load in the North Itasca Electric Cooperative (NIEC) service territory has grown to the point
that the line loading on the Jessie Lake-Wirt Tap-Big Fork 69 kV line is approaching the limit.
Furthermore, the addition of the Effie 230/69 kV substation adds additional loading to the line in
question exacerbating the problem. A higher line rating is required to address these deficiencies.
The following are the load projections that are to be served from this system over the LRP timeframe
(including MP load between Boswell and Deer River).
Study Area Substation Loads Modeled
Season
Summer
Winter
2011
45.9
68.6
57
2021
57.4
86.5
2031
67.2
104.2
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
The alternative to seeking a temperature upgrade is to rebuild the line. This option is not as
cost effective as a temperature upgrade and would only be performed if a line survey reveals
that a significant number of poles need to be replaced to achieve the desired line ratings.
Cost Allocation:
Transmission Service Delivery Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2631: Resag Deer River – Jessie Lake Retemp
Transmission Owners: Great River Energy
Project Description:
Temperature upgrade of the 13.94 mile Deer River to Jessie Lake 69 kV to 170° F (212° F desired).
The total estimated cost of this project is $1.32 million. The expected in service date for this project is
December, 2012.
The project is shown in the figure below.
59
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2631-1: Geographic Transmission Map of Project Area
Project Justification:
Summer load in the North Itasca Electric Cooperative (NIEC) service territory has grown to the point
that the line loading on the Deer River-Jessie Lake 69 kV line is approaching the limit. Furthermore,
the addition of the Effie 230/69 kV substation adds additional loading to the line in question
exacerbating the problem. A higher line rating is required to address these deficiencies.
The following are the load projections that are to be served from this system over the LRP timeframe
(including MP load between Boswell and Deer River).
Study Area Substation Loads Modeled
Season
Summer
Winter
2011
45.9
68.6
60
2021
57.4
86.5
2031
67.2
104.2
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
The alternative to seeking a temperature upgrade is to rebuild the line. This option is not as cost
effective as a temperature upgrade and would only be performed if a line survey reveals that a
significant number of poles need to be replaced to achieve the desired line ratings.
Cost Allocation:
Transmission Service Delivery Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2731: Lake Lillian (KEPCA) 3.0 mile, 69 kV line
Transmission Owners: Great River Energy
Project Description:
Kandiyohi Power Cooperative plans to energize the Lake Lillian distribution substation
tapping the Melville Tap to Cosmos Tap 69 kV line. The total estimated cost of this project
is $1.1 million. The expected in service date for this project is June, 2012.
The project is shown in the figure below.
Lake
Lillian
Figure P2731-1: Geographic Transmission Map of Project Area
Project Justification:
The Lake Lillian distribution substation is required to serve new and growing loads south
east of the Svea distribution substation. It will provide back feed capability to Svea
distribution substation..
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2834: Rice Lake (MKR) 69 kV Distribution Substation
Transmission Owners: Great River Energy
Project Description:
This project involves constructing a 5 mile 69 kV line from Paynesville to the Rice Lake
distribution substation location. Loads which are being served from the existing Meeker
Cooperative Light and Power Association (MCLPA) Paynesville distribution substation will
be moved to the new Rice Lake distribution substation. The total estimated cost of this project is
$1.72 million. The expected in service date for this project is November, 2012.
The project is shown in the figure below.
Rice Lake
Figure P2834-1: Geographic Transmission Map of Project Area
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project Justification:
The MCLPA Paynesville substation used to be served from the Paynesville 115/34.5 kV
substation at normal system condition and from Watkins 69/34.5 kV substation during the
loss of Paynesville 115/34.5 kV transformer or Paynesville to Paynesville Tap 34.5 kV line.
The Watkins 69/34.5 kV transformer failed late 2008, and GRE decided not to replace this
transformer for number of reasons. This left the Paynesville distribution sub on radial 34.5
kV line, which is old and has reliability concerns. In addition GRE plans to build a 69 kV line
from Paynesville to Watkins in the long term. Thus, it was found the new 69 kV line from
Paynesville sub to Rice Lake will provide a more reliable service to the loads which are now
served from the Paynesville distribution substation. In addition, this project was found to be
in line with GRE’s long range plan of this area.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Alternatives Considered
The alternative to this project is replacing the Watkins 69/34.5 kV transformer and rebuilding
the Watkins – Paynesville 34.5 kV line. The Watkins 69/34.5 kV sub was constructed on a
leased land which is set to expire in the 2011 timeframe. As the lease is not renewable, it
will be a total rebuild of the Watkins 69/34.5 kV sub. This option is by far more expensive
than the preferred option.
Cost Allocation:
This is a Transmission Service Delivery Project for distribution load. There is no anticipated
cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Great River Energy Generator Interconnection Projects
Project 3104: G514 Heartland Wind
Project Description:
Add 345 kV circuit breakers at Wilmarth to allow isolation of new wind generators. The total
cost of this project is $796,000. The project was completed in October, 2009.
Project Justification:
See Generator Interconnection Project G514.
Cost Allocation:
This is a Generator Interconnection Project, eligible for regional cost sharing.
Project 3105: G252
Project Description:
Add 69 kV 3-way group operated disconnect switch and switch structure. The total cost of
this project is $150,000. The project was completed in December, 2009.
Project Justification:
See Generator Interconnection Project G252.
Cost Allocation:
This is a Generator Interconnection Project, eligible for regional cost sharing.
Project 3106: G619
Project Description:
Rebuild 8.87 miles of 115 kV line from Cormorant Tap to Tamarac and Cormorant Junction
to allow interconnection of new wind generators. The total cost of this project is $2,630,000.
The project ISD is October, 2011.
Project Justification:
See Generator Interconnection Project G619.
Cost Allocation:
This is a Generator Interconnection Project, eligible for regional cost sharing.
Project 1542: G532
Project Description:
Net: tap Odin Tap - Odin 69kV line structure 88, install switches, metering equipment to
allow interconnection of new wind generators. The total cost of this project is $174,498.
The project ISD is November, 2007.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Project Justification:
See Generator Interconnection Project G532.
Cost Allocation:
This is a Generator Interconnection Project, eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Appendix D1: ITC Midwest
Other Projects
Project 3055: Cedar Rapids 34kV Conversion Plan
Transmission Owners: ITC Midwest
Project Description:
ITCM, working with IP & L, has formed a plan to better serve Cedar Rapids load with new
larger, 2-transformer substations that will allow retirement of the 4kV system along with
several other small distribution substations. Most of these new substations will be served
from a new 69 kV and 161 kV Cedar Rapids transmission system that will use the existing
34.5 kV system right-of-way. This will allow retirement of several existing 34.5kV lines while
shifting distribution load to a higher voltage to allow better normal and contingency
performance. The facilities include a new 161kV Downtown Industrial substation ($2.16 M),
161 kV Downtown Network substation ($2.16 M), 69kV Oak Hill substation ($2.16M), 69kV
Emerald Isle substation ($2.16M), 69kV Collins substation ($2.16M), 69kV Cargill West
substation, adding Marion 161/69 kV 100 MVA transformer ($3.24M). The following line
segments are being rebuilt from 34kV to 161kV: Downtown Industrial – Downtown Network
($2.1M), Downtown Network – PCI ($2.1M), 6th Street – Downtown Industrial ($2.1M). The
following line segments are going to be rebuilt from 34kV to 69kV, but continued to be
operated at 34kV until the 69kV distribution subs are completed: Oak Hill – Marion
($1.01M), PCI – Oak Hill ($1.01M), Collins – Hiawatha ($0.7M), Marion – Collins ($0.7M),
Cargill West – PCI ($0.81M), Marion – Emerald Isle ($0.74), Emerald Isle – Cargill West
($0.81), Emerald Isle – Louisa ($0.74). The total estimated cost of this project is $29 million.
The expected in service date for this project is December, 2011-December 2014.
Project Justification:
The City of Cedar Rapids has numerous small older IP & L distribution substations,
including many 4kV substations, which can no longer adequately serve the load. IP
& L is in the process of upgrading their substations and the ITCM Cedar Rapids area
projects are needed to serve the new IP & L substations. This will allow retirement
of several existing 34.5kV lines while shifting distribution load to a higher voltage to
allow better normal and contingency performance.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3058: Vinton - Hazleton 34kV Conversion Plan
Transmission Owners: ITC Midwest
Project Description:
The plan includes rebuilding a line between Dundee and Vinton substations and converting
this line to 69 kV operation. In order to operate this line at 69 kV a 161/69 kV transformer
will need to be installed at Vinton. Also, an approximatley 6 mile line will be built to connect
the Hazleton source to the Dundee - Vinton line. This plan also includes rebuilding a line
between Coggon and Hiawatha substations and converting this line to 69 kV operation. A
161/69 kV transformer will need to be installed at Coggon. The total estimated cost of this
project is $21.988 million. The expected in service date for this project is December 2011December 2012.
Project Justification:
The 34.5 kV system is unable to adequately serve new loads that may want to connect in
the area. Also, ITCM is working to upgrade the 34.5 kV system to 69 kV operation, which
will decrease system losses. The 34.5 kV system is unable to adequately serve new loads
that may want to connect in the area. Also, ITCM is working to upgrade the 34.5 kV system
to 69 kV operation, which will decrease system losses.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3056: Grundy Center – Reinbeck – Hicks tap 69kV Line
Transmission Owners: ITC Midwest
Project Description:
Construct a 16 mile 69kV line between Grundy Center and the Hicks tap 69kV line.
Constructing this line will allow consolidation of the Dike and Morrison substations into a
single new distribution substation and will allow retirement of more than 30 miles of 50 year
old 34.5kV line. The total estimated cost of this project is $5.76 million. The expected in
service date for this project is December, 2011.
Project Justification:
This project is being done to allow consolidation of two distribution substations as well as
retirement of several miles of 50 year old 34.5kV line which is in poor condition and is not
the result of a planning criteria violation.
Alternatives Considered
Rebuilding over 30 miles of 34.5kV line to 69kV standards is an alternative. This option was
not considered practical as construction of the 16 mile new 69kV line can serve the same
load that would otherwise require rebuilding over 30 miles of 34.5kV line. Rebuilding the
34.5kV line would also cost roughly $5 million more.
Cost Allocation:
This is an Other project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3053: Keokuk Hydro – Carbide 69 kV Dbl Ckt
Transmission Owners: ITC Midwest
Project Description:
This project is to build a new 69kV circuit from Keokuk Hydro-Carbide and also involves
rebuilding Keokuk Hydro – Messenger – Commercial – Carbide. The total estimated cost of
this project is $3.24 million. The expected in service date for this project is December, 2011.
The project is shown in the bottom right of the figure below.
Figure P3053-1: Geographic Transmission Map of Project Area
Project Justification:
This project will address loading problems on the Messenger – Keokuk Hydro 69kV line
when the Roquette – Keokuk Hydro line is out due to a contingency. During this
contingency, loading on this line is approximately 98% in a summer peak 2010 model,
however, depending on the system bias, real time flows have been seen to exceed this
value violating the 100% loading criteria. In the MTEP10 2015 spk model the Messenger –
Keokuk line (116.6%), Commercial – Messenger 69kV line (101.8%) and Hamilton (Ameren
IL) – Keokuk Hydro (112%) is overloaded. Also, taking either of the existing 69kV lines out
from the Keokuk Hydro plant to the ITCM system results in loadings such that the next
contingency would significantly overload the remaining in-service line. This has resulted in
difficulty getting the lines out of service for maintenance and minor upgrades.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Table P3053-1 Project Contingency Drivers
Limiting Element or
Need Driver
Contingency
Cont
Type
Keokuk Hydro Roquette - Keokuk
Messenger 69 kV Line Hydro 69 kV Line
B
Commercial Roquette - Keokuk
Messenger 69 kV Line Hydro 69 kV Line
B
Rating
(MVA or
pu)
Study Area
Load Level
87 before
project,
112 after
project
2015 spk
74 before
project,
112 after
project
2015 spk
project
Loading /
Voltage
project
Loading /
Voltage
103.9
61.4
(112.1%) (53.6%)
76.4
34.6
(101.8%) (30.3%)
The table below lists the substation loads that define the study area for this project and are
the Study Area Loads shown in the results table above in MTEP10 2015 Summer Peak
model.
Table P3053-2 Study Area Substation Loads Modeled
Substation
Level 1 (MW)
Messenger
26.7
69kV
Commercial
3.0
69kV
Devil’s Creek
12.5
69kV
Dial 69kV
2.3
Griffin Wheel
21
69kV
Wayland 69kV
15.3
bus
Climax 69kV
6.7
Bluff 69kV
16.7
Area Total
104.2
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3053-1: 2015 Summer Peak without Project System Intact
74
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3053-2: 2015 Summer with Project System Intact
75
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3053-3: 2015 Summer Pre-Project “contingency description”
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3053-4: 2015 Summer with Project “contingency description”
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Alternatives Considered
Construction of a new 69kV circuit on an entirely new route was also looked at. This alternative was rejected due to the difficulty
(potentially not possible) in routing a new line through town between the Keokuk Hydro plant and the Carbide substation. The
cost would be expected to be greater than the double circuit line due to difficult terrain as well as the potential for extra miles to
find a route where easements could be obtained. The Goose Pond 161kV 3-breaker switching station was identified as being
constructed by IP&L in the “Interchange Agreement Between Union Electric Company (dba AmerenUE) and Interstate Power And
Light Company”. This agreement was assigned to ITCM during the sale of IP&L transmission assets to ITCM and ITCM is now
responsible for meeting the commitment in the agreement. During the initial design stages, it was determined that a usable site
could not be obtained to construct the breaker station.
Cost Allocation:
This is an Other(Reliability) Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3059: West Branch & West Liberty Switch Stations
Transmission Owners: ITC Midwest
Project Description:
This project is to construct two new 3 terminal 69kV breaker stations at West Branch and at
West Liberty. The total estimated cost of this project is $3.12 million. The expected in
service date for this project is December, 2011.
Project Justification:
Following completion of the West Branch to West Liberty 34.5kV line rebuild, the long term plan
is to convert the line to 69kV operation and network it with the existing West Liberty to CIPCO
69kV line. Creating the 69kV network will result in 3-terminal lines at West Branch and at the
connection with the CIPCO line which are difficult to adequately protect. This can result in not
seeing a fault on some segments of the line or tripping the line due to loading when a fault does
not exist. This project is being done to improve the protection coordination of the system in the
West Liberty area and is not the result of a planning criteria violation.
Alternatives Considered
Operate system in a network configuration with 3-terminal lines. This is not considered an
acceptable configuration from a system protection coordination perspective.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3048: Jefferson Co – Perlee 69kV Rebuild
Transmission Owners: ITC Midwest
Project Description:
This project is to rebuild the Jefferson Co-Perlee 69kV line section. The total estimated cost
of this project is $2.70 million. The expected in service date for this project is December,
2011.
Project Justification:
The recommended project is to completely rebuild the Jefferson Co-Perlee 69 kV line. This
is an old 69 kV line and which has been patrolled identifying numerous structures in very
poor condition and a copper static wire that is badly deteriorated. Approximately 25% of the
structures warrant individual pole replacements, but the entire line needs to be re-sagged.
This line section also needs all new guying, anchors, and new shield wire installed.
Furthermore, AR twisters would need to be installed to reduce the likelihood of galloping. In
summation, the amount of work required to adequately address all of the infrastructure
issues with this line section and the recent outage/reliability concerns, the overall condition
of this line warrants a complete rebuild.
Alternatives Considered:
The second proposal considered was to perform wood pole replacements only on the worst
of the structures and replace the static wire. Approximately 20-30% of the structures would
need to be replaced and all new guying and anchors would need to be installed. This line
section would need to be completely re-sagged due to the tension variations caused by the
leaning poles. In addition, AR twisters would need to be installed o this line section to
address galloping issues. However, this option was rejected as a long term solution after
line patrols identified this line section as needing a complete rebuild.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3057: West Branch 34kV Load Shift Projects
Transmission Owners: ITC Midwest
Project Description:
This project is to construct 69kV taps for the Moscow & New Liberty distribution substations.
The total estimated cost of this project is $2.47 million. The expected in service date for this
project is December, 2011.
Project Justification:
Moscow and New Liberty are located in the West Branch area which ITCM is in the process
of converting to 69kV operation. The existing 7 mile and 9.4 mile taps to these substations
are not constructed for operation at 69kV. This project will construct the proposed shorter
taps that connect each substation to a nearby 69kV CIPCO line.
Alternatives Considered
Rebuild existing taps to 69kV. This alternative was rejected as the cost was significantly
higher without additional benefits.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3052: Washington 69kV Upgrades
Transmission Owners: ITC Midwest
Project Description:
This project is to replace 40-60 year old equipment, 2 breakers, relays, and improve breaker
configuration, add bus tie breaker, and install a new control building. The total estimated
cost of this project is $2.4 million. The expected in service date for this project is December,
2011.
Project Justification:
Reconfiguration of the substation and replacement of 40-60 year old equipment will allow an
improved protection scheme that will prevent recurrence of the over-trip condition that
resulted in the four Washington 69kV lines tripping simultaneously both locally and at the
remote ends.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3047: IA Falls Industrial 115/69kV Transformer
Transmission Owners: ITC Midwest
Project Description:
This project is to upgrade the Iowa Falls Industrial 115/69 kV transformer with a dual high
side (161-115)/69 kV transformer. The total estimated cost of this project is $1.98 million.
The expected in service date for this project is December, 2010.
The project is shown in the figure below.
Figure P3047-1: Geographic Transmission Map of Project Area
Project Justification:
The existing Iowa Falls Industrial transformer loads to nearly 100% during the contingency
loss of the Hampton 161/69 kV transformer with the existing 69kV load. The 115/69 kV
transformer loading will increase during normal and contingency operation as additional load
is added to the 69 kV system during conversion of 34.5 kV load to 69 kV. This will result in
planning criteria violations.
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Appendix D : New Appendix A Project Justifications
Table P3047-1 Project Contingency Drivers
Limiting Element or
Need Driver
Iowa Falls Industrial
161/69 kV xfmr
Iowa Falls Industrial
161/69 kV xfmr
Cont
Type
Contingency
Hampton 161/69 kV
xfmr
B
base case
Rating
(MVA or
pu)
Study Area
Load Level
31.3
(before
project),
100 after 2015 spk
31.3
(before
project),
100 after 2015 spk
project
Loading /
Voltage
53.7
(166.5%) 66 (66%)
48.3
59.5
(149.6%) (59.5%)
The table below lists the substation loads that define the study area for this project and are
the Study Area Loads shown in the results table above (in MTEP10 2015 spk model).
Table P3047-2 Study Area Substation Loads Modeled
Substation
Level 1 (MW)
Iowa Falls
23.6
Industrial 69 kV
IFE 69 kV
7.4
Alden 69 kV
2.0
ALDNBUCKEYE8
8.8
69 kV
Hampton 69 kV
6.5
Farmland 69 kV
0.6
ACKLYTAP 69
1.2
kV
Pine Lake 69 kV
4.4
Area Total
54.5
84
project
Loading /
Voltage
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3047-1: 2015 Summer Peak without Project System Intact
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3047-2: 2015 Summer with Project System Intact
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3047-3: 2015 Summer Pre-Project “Hampton 161/69 kV transformer outage”
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3047-4: 2015 Summer with Project “Hampton 161/69 kV transformer outage”
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Appendix D : New Appendix A Project Justifications
Alternatives Considered
Add a second Iowa Falls Industrial 161/69 kV transformer in a 2nd bay. This was rejected due to the higher expected cost and
the fact that the existing 115/69 kV 31 MVA exiting unit would need to be changed out when the 115kV line is converted to 161
kV.
Cost Allocation:
This is an Other(Reliability) Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3046: SW Cedar Rapids 69kV System Upgrade (Phase 1)
Transmission Owners: ITC Midwest
Project Description:
This project is to re-route 69kV lines near the load to connect to the 161/69kV transformer at
the Beverly substation. Install two breaker terminals and a main breaker to connect the rerouted lines. This adds significant capacity to the 69kV system with minimal line
construction and no new transformer purchases. The total estimated cost of this project is
$1.8 million. The expected in service date for this project is December, 2011.
Project Justification:
NERC Catergory B outage of the Prairie Creek Industrial 161/69kV TRF in the 2015 summer
peak model overloads the Fairfax 161/69 TRF when new firm load greater than 11MVA is
added.
Alternatives Considered
All alternatives to add capacity would require purchase of a new transformer. As this option
utilizes an existing transformer, alternative options were not considered.
Cost Allocation:
This is an Other(Reliability) Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3054: Swisher Breaker Station
Transmission Owners: ITC Midwest
Project Description:
This project is to construct a 69kV breaker station at the 3-terminal point to improve system
reliability and allow adequate system protection. The total estimated cost of this project is $1.8
million. The expected in service date for this project is December, 2011.
Project Justification:
Single outages on the Tiffin to North Liberty 69 kV line cause load to be interrupted until a
normal open switch can be closed. Closing a single normal open switch violates voltage
criteria. Closing multiple normally open switches creates a three terminal line which is
difficult to adequately protect.
Alternatives Considered:
Install capacitor banks to improve voltages under contingency conditions. This would be
difficult to implement and utilize due to the radial nature of the Tiffin to North Liberty 69 kV
line. This option is less beneficial because loads would still be interrupted until a normally
open switch can be closed.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3050: Alden-Buckeye Distribution Substation Tap
Transmission Owners: ITC Midwest
Project Description:
This project is to constuct a new 3 mile 69kV tap to the new Alden-Buckeye distribution
substation from the CBPC Alden sub site. The total estimated cost of this project is $1.08
million. The expected in service date for this project is December, 2011.
Project Justification:
This project is to connect a new customer substation and is not the result of a planning
criteria violation. The Iowa Falls Industrial 115/69kV transformer is currently scheduled to be
replaced with a larger unit to support 69kV load additions in this area so transfer of load to
the 69kV system from the 34.5kV system will not result in planning criteria violations
Alternatives Considered:
Connect the new substation to the 34.5kV system. This option was not considered practical
as the current plan is to upgrade the 34.5kV system to 69kV and in this case tying the load
to an existing 69kV line is more cost effective than rebuilding several miles of 69 year old
34.5kV line.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Appendix D1: Montana-Dakota Utilities Co.
Basline Reliability Projects
There are no Baseline Reliability projects moving to Appendix A for Montana-Dakota Utilities
Co. this MTEP cycle.
Other Reliability Projects
There are no ‘Other’ Reliability projects moving to Appendix A for Montana-Dakota Utilities Co.
this MTEP cycle.
Generation Interconnection Projects
There are no projects that have network upgrades eligible for cost allocation per energy Markets
Tariff (EMT). Details of other study work are posted at:
http://www.midwestiso.org/publish/Folder/3e2d0_106c60936d4_-76840a48324a?rev=4.
Transmission Delivery Service Planning Projects
There are no projects that have network upgrades for transmission service, directly assigned to
customer per Energy Markets Tariff (EMT). Detailed study reports are posted at:
https://oasis.midwestiso.org/documents/miso/Transmission%20Service%20Planning%20%20SIS%20Reports.htm
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Appendix D1: Midamerican Energy Company
Other Projects
Project 2936: Colona Rd 161/13 kV Project
Transmission Owners: Midamerican Energy Company
Project Description:
This project is to build the Colona Road substation to serve customers and a new half mile
double circuit 161kV line off the existing Sub 39 to Sub 18 161kV line. The Colona Road
substation will be a 161-13.2 kV distribution substation with a 20/26.7/33.3
MVA transformer, two 161 kV line breakers and 13.2 kV switchgear. The double circuit line
build will lead to line sections of Sub 39 to Colona Rd Sub and Colona Rd Sub to
Sub 18 with Sub 43 tapped off this line. The cost of the substation is $2.7 million and the
161 kV double circuit line is $800,000. The total estimated cost of this project is $3.5 million.
The expected in service date for this project is June 1, 2012.
The project is shown in the figure below.
Figure P2936-1: Geographic Transmission Map of Project Area
Project Justification:
The urban and rural fringe area in the southeastern Quad Cities near Colona, Illinois is served
by Sub 27, a 69-13.2 kV substation. The projected load level will require additional distribution
94
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
transformer capacity to serve customers. The existing facilities are not adequate to serve the
expected load. These projects provide facilities to serve customers, improve reliability and
benefit distribution criteria.
Cost Allocation:
This is an Other Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Appendix D1: Minnesota Power
Basline Reliability Projects
There are no Baseline Reliability projects moving to Appendix A for Minnesota Power this MTEP
cycle.
Other Reliability Projects
Projects that are not defined as Baseline Reliability, Generation Interconnection or Transmission
Delivery Service Planning per Attachment FF transmission project definitions but are still
needed for system reliability for various reasons are categorized as “Other” Projects.
Project 2547: Essar Steel Phase I, Phase II and Phase III
Transmission Owners: Minnesota Power
Project Description:
Transmission is required to supply electric power to the new Essar Steel Minnesota mine and steel mill.
The Essar Steel Minnesota (ESM) Project will be developed in three phases with Phase I consisting of a
conventional taconite plant and mining load of 95 MW. Phase II of the project adds a Direct Reduced Iron
(DRI) facility which is scheduled to be operational in the fall of 2012 and increases total demand to 145
MW (a 50 MW increase). Phase III of the project will add an Arc furnace and steel slab plant scheduled to
be in service by the fall of 2013. This will increase the total peak demand to nearly 300 MW.
Analysis was conducted to evualte the fesability of serving Phase I of the (ESM) Project at 115 kV via a
reroute of MP’s 115 kV Line #28 (see P 2756). The results of this analysis indicated that there would be
reliability issues associated with serving Phase 1 at 115 kV as well as issuses associated with
construction of the 230 kV transmission required to serve ESM Phase II and Phase III. Because of these
issues, at this time, preferred method of serving Phase I of the ESM Project will be via 230 kV
transmission.
The plan is to loop MP’s 230 kV Line #94 (Boswell to Shannon Line) into the Essar Mine Plant and Essar
Steel Substaions that will also be constructed as part of this project, construct a 230 kV line between the
two ESM substaions and construct a new 230 kV line from the MP Blackberry 230 kV Substation to the
Essar Steel Plant Substaion.. The transmission to serve ESM will be constructed in stages to concide with
the load expantions associated with Phase 1, Phase II and Phase III of the ESM Project. The 230 kV lines
between the Blackberry and the Essar Steel Plant Substaion and between the Essar Steel Plant and
Essar Mine Substations will be the first lines to be constructed. These two lines are expected to be placed
in service by Febuary 2011 to meet Essar’s schedule. The Boswell to Essar Mine Substaion and the
Shannon to Essar Steel Plant Substaions lines will be constructed as required to meet the load increases
associated with Phase II and Phase III of ESM Project. Based on ESM’s current schedule, it is
anticipated these 230 kV lines will be completed and become opterational in fall 2012 and fall 2013. The
project is shown in the figure below.
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Appendix D: New Appendix A Project Justifications
Figure P2547-1: Geographic Transmission Map of Project Area
Project Justification:
This project is required to supply new load associated with the ESM Project. The ESM Project will be
constructed in three phases with Phase I having a Peak demand of 95 MW, Phase II will increase
demand by 50 MW to a peak demand of 145 MW. Phase III will increase demand by approximately 155
MW to a peak demand of nearly 300 MW.
Table P2547-1 Project Contingency Drivers
Need Driver
Contingency
Rating
Cont (MW/p
u)
Type
New 95 MW Load Phase I
50 MW Load addition Phase II
155 MW Load addition Phase III
Year
(Load Level)
2011 (95 MW)
2012 (145 MW)
2013 (300 MW)
97
Pre-project
Loading /
Voltage
Post-project
Loading /
Voltage
230 kV
230 kV
230 kV
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Alternatives Considered
Several alternatives to connect Essar Steel Minnesota to the area’s transmission network were studied
including bringing 500 kV to the site from the Forbes Substation as well as connecting Essar Steel to the
areas 230 kV or 115kV systems. Studies have shown that 230 kV transmission will be required in order
to supply the additional load expected when Phase II and Phase III are completed and may be needed to
reliability serve Phase I of the Essar Project. The preferred alternative to serve Phase II and Phase III
consists of looping MP’s 230 kV Line #94 (Boswell to Shannon Line) into Essar and constructing a new
230 kV line from the MP Blackberry 230 kV Substation to the Essar site. Nashwauk Public Utilities
Commission (Applicant) and Minnesota Power (co-applicant) are applying for a Route Permit to construct
the 230 kV transmission lines and two 230 kV substations to supply electric power to Essar Steel
Minnesota. It is expected that this route permit will be submitted in June 2009. Depending on the final
approved route and permit conditions, the 230 kV transmission to supply Essar Steel Minnesota is
estimated to cost between $30 and $45 million.
Cost Allocation:
This is an Other (Distribution) project which is not eligible for regional cost sharing.
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Appendix D: New Appendix A Project Justifications
Project 2761 Polymet
Transmission Owners: Minnesota Power
Project Description:
This project consists of development of a new Range Area 138/13.8 kV substation to serve Polymet
Mining that will be supplied by connecting the existing MP 138 kV Line #1, (Taconite Harbor to Hoyt
Lakes) into the new Dunka Road Substation. Dunka Road Substation will be in a ring bus
configuration with four positions. One position will serve two 138/13.8 kV distribution transformers;
two positions are for Line#1 entry and exit, and the fourth position is for future use. In addition to the
two transformers, the substation will have three 138kV circuit breakers, low voltage 13.8 kV
switchgear, associated accessory apparatus, and an electrical equipment enclosure with associated
relay/control panels.
The total estimated cost of this project is $3.2M (~$1.4M for Transmission Assets and ~$1.8M for
Distribution Assets). The expected in-service date is December 2011.
The project is shown in the figure below.
Figure P2761-1: Geographic Transmission Map of Project Area
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Project Justification:
Polymet, a Canadian precious metals mining firm, requires electric service at their new Northmet Pit.
This pit is located just north of MP 138 kV Line #1 which runs between the Taconite Harbor and Hoyt
Lakes substations. There is currently no existing transmission service into the mine site. To provide
service to this site and its approximately 10 MW of load, MP must construct a new substation, the
Dunka Road Substation, and connect it to the nearby high voltage 138 kV transmission system.
Table P2761-1 Project Contingency Drivers
Need
Driver
Study
Area Load
Cont
Level
Contingency Type Rating
Polymet
New Load NA
NA NA
Preproject
Loading
10 MW
Postproject
Loading
0
10 MW
The table below shows the new substation that will be constructed as part of the Polymet project and
expected loads that define the study area driving the need for this project. The primary driver for this
project is transmission supply to this new mine load. At this time, the Polymet precious metals mine
is still in the permitting phase. Provided Polymet receives its permits, MP will move forward with
construction of the Dunka Road Substation. As of now, electric service to Northmet Pit is expected to
be needed by December 2011.
Table P2761-2 Study Area Substation Loads Modeled
Substation
Level 1 (MW)
Level 2 (MW)
Dunka Road
10
NA
Area Total
10
NA
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Alternatives Considered
This is a new load to a mine site located adjacent to an existing 138 kV transmission line. Therefore
there are no other reasonable alternative methods to provide a transmission connection to this new
load.
Cost Allocation:
This is an Other (Distribution) project which is not eligible for regional cost sharing.
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Appendix D: New Appendix A Project Justifications
Project 2762 – Air Park
Transmission Owners: Minnesota Power
Project Description:
This Project consists of development of a new Duluth, MN, area 115/34.5/13.8 kV substation that will be
supplied by looping the existing MP 115 kV Line # 52 into and out of the new substation. The new Airpark
Substation will have one 115/14 kV transformer with 39.2 MVA capacity, one 115/34.5 kV transformer
with 33.6 MVA capacity, two 115 kV SF6 circuit breakers, two 115 kV circuit switchers, seven 115 kV
group operated switches, 14 kV switchgear, 34.5 kV switchgear, an electrical equipment enclosure, and
associated relay/control panels.
The total estimated cost of this project is $4M (~$1.2M for Transmission Assets and ~$2.8M for
distribution assets). The expected in-service date is June 2012.
The project is shown in the figure below.
Figure P2762-1: Geographic Transmission Map of Project Area
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Appendix D: New Appendix A Project Justifications
Project Justification:
Duluth has experienced about a 15% load growth over the past decade. Many new loads have been
added to the system due to hospital expansions, new hotel/motel additions and general residential
and commercial load growth. Two of the firm capacity substations serving Duluth – Haines Road and
Ridgeview – have exceeded their firm capacity during winter peak load conditions. That is, an outage
of one of the transformers at either site requires immediate switching of feeders to shift load to other
facilities to prevent the other transformer from overloading. This is a concern during winter peak load
levels with system conditions as listed in the table below.
The Airpark Substation, which may be renamed Swan Lake Road Substation, will serve load currently
served from the Haines Road and Ridgeview substations. This project will reduce loads to less than
the firm capacity at both the Haines Road and Ridgeview Substations. The need for the project is
demonstrated in the table below.
Table P2762-1 Project Contingency Drivers
Limiting Element or
Need Driver
Haines Road 115/13.8
kV Transformer
Ridgeview 115/13.8
kV Transformer
Rating
Study
Cont (MVA Area Load Pre-project
)
Level
Loading
Contingency Type
Haines
Road
B
Ridgeview
Transformer B
Postproject
Loading
33.6 74.2 MW 38.3 MW 28.6 MW
33.6 74.2 MW 35.9 MW 26.2 MW
The table below lists the substation loads that define the study area for this project. These loads are
driving the system needs in this area. The primary driver for this project is 115/13.8 kV transformer
overloading during loss of one of the two transformers located in the Haines Road or Ridgeview
substations. This occurs at a study area load greater that the firm capacity of 33.6 MVA at either of
the existing substations. It is expected that the study area will reach load levels above which load
cannot be transferred to other distribution substations in 2013; therefore, this project needs to be in
service before that time. The Airpark Substation is expected to provide adequate capacity to the study
area for the foreseeable future.
Table P2762-2Study Area Substation Loads Modeled
Substation
Pre Project
Post Project
Haines Road
38.3
28.6
Ridgeview
35.9
26.2
Airpark
0
19.4
Area Total
74.2
74.2
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Alternatives Considered
MP considered adding transformer capacity at the existing substations. However, this was
determined not to be a long-term solution. Several sites for the new Airpark Substation were also
considered with the proposed site being the best solution.
Cost Allocation:
This is an Other (Distribution) project which is not eligible for regional cost sharing.
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Appendix D: New Appendix A Project Justifications
Project 3091: 28L Reroute
Transmission Owners: Minnesota Power
Project Description:
Essar Steel Minnesota LLC (ESM) is proposing the construction of an iron ore mining and steel
production facility to be located near Nashwauk, MN. MP’s existing 115 kV Line #28 crosses the area
that ESM will be mining, so the line must be moved prior to commencement of mining activities. The
project will require construction of approximately 6.5 miles of new 115 kV transmission line to route
the line around the area to be mined. The total estimated cost of this project is $2.9 million. The
expected in service date for this project is December 2011, but will be adjusted as required based on
ESM mining operations.
The project is shown in the figure below.
Figure P3091-1: Geographic Transmission Map of Project Area
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Project Justification:
The commencement of mining operations by Essar Steel will require removal of a section of the
existing MP Line #28.
Table P3091-1 Project Contingency Drivers
Limiting Element or
Need Driver
Mining operations
Study
project
Area Load Loading /
Cont
Contingency Type Rating
Voltage
Level
NA
NA
NA
NA
NA
project
Loading /
Voltage
NA
In addition to serving the load at the Nashwauk Substation, MP Line #28 serves as a generator outlet
for Boswell Units 1 & 2. The line is necessary in order to maintain adequate generator outlet capacity
for Boswell and reliable load service to Nashwauk. Therefore, it cannot simply be abandoned due to
Essar Steel’s mining operations, but must be rerouted.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Alternatives Considered
MP Line #28 must be rerouted as Essar Steel plans to start mining operations that requires removal
of a section of the existing line. This line serves as a generator outlet for Boswell Units 1 & 2, so the
alternative of decommissioning and removal of the line rather than relocating it is not a viable option.
Several alternative routes were considered; however rerouting the line within the preferred corridor for
the 230 kV transmission that will serve ESM (Project # P2547 Essar Phase 1-2-3) is the preferred
alternative. A route permit was approved in January 2010.
Cost Allocation:
This is an Other (Relocation) project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Generation Interconnection Projects
There are no projects that have network upgrades eligible for cost allocation per energy Markets
Tariff (EMT). Details of other study work are posted at:
http://www.midwestiso.org/publish/Folder/3e2d0_106c60936d4_-76840a48324a?rev=4.
Transmission Delivery Service Planning Projects
There are no projects that have network upgrades for transmission service, directly assigned to
customer per Energy Markets Tariff (EMT). Detailed study reports are posted at:
https://oasis.midwestiso.org/documents/miso/Transmission%20Service%20Planning%20%20SIS%20Reports.htm
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Appendix D1: Muscatine Power and Water
Other Projects
Project 2934: Replace South Subtation 161/69 kV Transformer
Transmission Owners: Muscatine Power and Water
Project Description:
This project is to replace the existing 161/69 kV 75MVA transformer at the South substation
with at least a 134 MVA transformer. Also, the 161 kV bus at the South substation will
become a ring bus, splitting the three terminal 161 kV line into two sections between MPW
Unit 9 – MPW South substation – MEC Sub 18. The total estimated cost of this project is
$5. 4 million. The expected in service date for this project is June, 2014.
The project is shown in the figure below.
Figure P2934-1: Geographic Transmission Map of Project Area
Project Justification:
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
This project will address the overload of the South substation 161/69 kV transformer under
the C3 contingency of the 134 MVA 161/69 kV transformers at Unit 9 and West substations.
Table P2934-1 Project Contingency Drivers
Limiting Element or
Need Driver
3 winding xfmr South Sub
161/69/13.8 kV bus #
633301-633501-633601
Rating
Cont (MVA or
pu)
Type
Contingency
West 161/69/13.8 3
winding xfmr
(633321-633521633621) + Unit 9
161/69/13.8 (633209633409-633609) 3
winding xfmr
C3
Study Area
Load Level
134
after
project,
75
MVA
before
project 2015 spk
project
Loading /
Voltage
96.61
(126%)
The table below lists the substation loads that define the study area for this project and are
the Study Area Loads for the results in the table above. These loads are driving the system
needs in this area.
Table P2934-2 Study Area Substation Loads Modeled
Substation
Level 1 (MW)
Cedar 69
13.5
Grandview Tap
21
69
Isett Sub 69
34.6
Muscatine
3.7
Switching
Station 69
Fruitland REC
2.1
69
Wiggins 69
16.5
Letts 69
1.5
Pine Street
18
Muscatine
46.6
Generation
(not SSL)
KINDERMO 69
9.4
Area Total
166.9
110
project
Loading /
Voltage
111.69
(81.8%)
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P2934-3: 2015 Summer Pre-Project “West substation 161/69/13.8 kV + Unit 9 substation 161/69/13.8 kV 3 winding transformer
outages”
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P2934-4: 2015 Summer with Project “West substation 161/69/13.8 kV + Unit 9 substation 161/69/13.8 kV 3 winding transformer
outages”
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Cost Allocation:
This is an Other Reliability Project which is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Appendix D1: Northwestern Wisconsin Electric
Basline Reliability Projects
There are no Baseline Reliability projects moving to Appendix A for Northwestern Wisconcin
Electric this MTEP cycle.
Other Reliability Projects
Projects that are not defined as Baseline Reliability, Generation Interconnection or Transmission
Delivery Service Planning per Attachment FF transmission project definitions but are still
needed for system reliability for various reasons are categorized as “Other” Projects.
Project 3092: Webb Lake 69 kV Line
Transmission Owners: Northwestern Wisconsin Electric
Project Description:
This project will rebuild a 34.5 kV line to Webb Lake as a 69 kV line with horizontal post
construction and #4/0 ACSR. The expected inservice date is June 2011. The estimated cost for
this project is $425,000.
Project Justification:
This project will serve load in the Webb Lake area. This project also will replace an aging pole
line.
Alternatives Considered
No Alternatives
Cost Allocation:
Other – Not Shared
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Appendix D: New Appendix A Project Justifications
Generation Interconnection Projects
There are no projects that have network upgrades eligible for cost allocation per energy Markets
Tariff (EMT). Details of other study work are posted at:
http://www.midwestiso.org/publish/Folder/3e2d0_106c60936d4_-76840a48324a?rev=4.
Transmission Delivery Service Planning Projects
There are no projects that have network upgrades for transmission service, directly assigned to
customer per Energy Markets Tariff (EMT). Detailed study reports are posted at:
https://oasis.midwestiso.org/documents/miso/Transmission%20Service%20Planning%20%20SIS%20Reports.htm
115
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Appendix D1: Otter Tail Power
Basline Reliability Projects
Project 2823: Gwinner Capacitor Bank
Transmission Owners: Otter Tail Power
Project Description:
This project will install a Capacitor Bank made up of two 8 MVAR capacitors on the 115 kV bus
at Gwinner, North Dakota. The expected inservice date is December 2010. The estimated cost
for this project is $883,000.
Project Justification:
This project will improve the 115 kV buses at Gwinner, Forman & Buffalo. The Capacitor is
especially needed for outage of the Gwinner-Forman 115 kV line.
Alternatives Considered
No Alternatives
Cost Allocation:
Baseline Reliability – Not Shared
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 3156: Cass Lake – Nary – Helga – Bemidji 115 kV Line
Transmission Owners: Otter Tail Power Company
Project Description:
Project 3156 consists of a 230/115 kV tap at Cass Lake along the path of the Boswell – Wilton 230 kV line (Project 279), and
upgrades to the 115 kV circuit from Cass Lake to Bemidji. This is the result of on-going transmission studies by Minnkota Power
Cooperative, Minnesota Power, Otter Tail Power Company, Great River Energy, and Xcel Energy. Project P3156 provides
increased load serving capabilities for the Bemidji area. The addition of a new 230 kV tap along the line at Cass Lake, will
connect the new 230 kV line into an expanded Cass Lake 115/69 kV substation. Along with this substation expansion at Cass
Lake, the capacity of the underlying 115 kV system between Cass Lake – Nary – Helga – Bemidji will also be increased.
Thermal upgrades along the Cass Lake – Nary 115 kV line will require replacing the existing conductor with a larger one capable
of handling the increased thermal flows along this line during contingencies (i.e. reconductor). Furthermore, the existing thermal
limit of the Nary – Helga – Bemidji 115 kV line is not the result of the limitations of the existing conductor, but of the conductor-toground clearances required by the National Electric Safety Code (NESC). To increase the limit of this line to a capacity sufficient
for the Bemidji – Grand Rapids 230 kV project, conductor-to-ground clearances must be increased by either replacing existing
structures in appropriate areas, or by using a technique called “phase raising.” None of the existing 115 kV upgrades will alter
the operating voltage of the lines, nor their existing rights-of-way, therefore, it is not anticipated that state permits will be required
to perform these upgrades.
In addition, a new 115 kV breaker station (switching station) at Nary will be added to improve reliability to the Bemidji area as well
as increase operational flexibility of the transmission system with the new 230 kV source at Cass Lake.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure 3156-1: Geographic Transmission Map of Project Area
118
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
119
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
A summary of the associated facilities for Project 3156 are as follows:
Facility
ID
Facility
Name
Summer
Rating
Facility
Description
3584
Cass Lake
230/115 kV
Transformer
Cass Lake –
Nary
Nary –
Helga
Helga –
Bemidji
Nary Switch
Station
187 MVA
Add new
230/115 kV
Transformer
Reconductor
115 kV Line
Structure
improvements
Structure
improvements
Develop 115
kV Switch
Station
5537
5539
5540
5538
~200 MVA
144 MVA
144 MVA
Miles
Estimated
Cost
$5.2 Million
Estimated
In-Service
Date
12/31/11
11.05
$3.9 Million
12/31/13
4.96
$33,000
12/31/13
7.67
$66,000
12/31/13
$2.7 Million
12/31/12
Project Justification:
Transmission studies completed by the project participants of the Bemidji – Grand Rapids
230 kV line have identified that the original proposal of the 230 kV line connecting the
Boswell Substation and the Wilton Substation still result in system performance concerns in
the Bemidji area for certain contingencies (namely the Bemidji – Wilton 115 kV line, Bemidji
– Helga 115 kV line, and the Helga – Nary 115 kV line). As a result of these concerns, the
project participants have optimized the original 230 kV proposal to include a tap at Cass
Lake to establish another 230/115 kV connection into the Bemidji area.
The new configuration of the project (Boswell – Cass Lake – Wilton 230 kV Line) has been
found to cause some underlying 115 kV loading concerns for outage of the new 230 kV line
section beteween Cass Lake and Wilton. The loading concerns are especially evident
during winter peak conditions with high Manitoba import conditions (700 MW north). As a
result of this contingency with the planned configuration of the Boswell – Wilton line, the
project participants are planning to upgrade the Cass Lake – Nary 115 kV line, the Nary –
Helga 115 kV line, and the Helga – Bemidji 115 kV line.
The results of the analysis performed by the project participants are shown in the table
below. These results are based on a 2012/2013 winter peak case with the Boswell – Wilton
230 kV line in the models with the Cass Lake 230/115 kV connection.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
Overloaded Circuit
From Bus
Ckt #
Rate
A
Overload
MVA
%
MVA
based
on
Current
120
112.35
134.82
126
108.07
136.17
120
117.25
140.70
To Bus
63246 BEMIDJI7 115 66730 HELGA_7 115
1
63247 CASS LK7 115 66710 NARY 7 115
1
66710 NARY 7 115 66730 HELGA_7 115
1
The overloads on the underlying 115 kV system indicate that excessive power flows from
east to west are expected during winter peak conditions. For outage of the Cass Lake –
Wilton 230 kV line, results of this analysis show that these excessive flows will be diverted
off the 230 kV line at Cass Lake and onto the 115 kV system back to Bemidji where there is
a substantial amount of load along with another 230 kV connection back to Winger.
The project participants are also planning to install a new 115 kV breaker station at Nary to
improve reliability and operational flexibility of the underlying 115 kV system. The existing
115 kV system between Bemidji and Akeley serves several communities and large
customers. This 115 kV system stretches nearly 60 miles from the Bemidji Substation south
to the Akeley Substation and east to Cass Lake, with the only fault interrupting devices for
the entire area located at the Bemidji and Akeley substations. The drawback of this
configuration is that a fault occurring anywhere between Bemidji and Akeley can affect
customers throughout the entire area. While this configuration does provide the area with
adequate and reliable service, it is not an optimal design. To improve the reliability and
effectiveness of this system, the existing 115 kV switches at Nary Junction are planning to
be replaced with three 115 kV circuit breakers.
The Nary Breaker Station will improve reliability in the area because it sectionalizes the
system and provides fault interrupting capability at a critical location in the existing 115 kV
system. This will result in fewer customers being affected by faults on the transmission
system between Bemidji, Cass Lake, and Akeley. The Nary Junction Breaker Station will
also improve system reliability since the addition of the Nary Junction Breaker Station
connects three 230 kV sources (Wilton, Cass Lake, Badoura) to the underlying 115 kV
system and separates these sources with circuit breakers. This makes the entire
transmission system more robust. This configuration will allow at least two 230 kV sources
to remain available if there is a fault on the underlying 115 kV system. Without the Nary
Junction Breaker Station, a fault on the underlying 115 kV system will result in the
disconnection of all three 230 kV sources.
The Nary breaker station will also improve operational flexibility. The transmission system
operators will be able to restore customers more quickly since the equipment at the Nary
Junction Breaker Station will be remotely controlled from dispatch centers rather than
manually switched by field personnel. This will allow faulted transmission elements to be
more quickly isolated. The Nary Breaker Station will also provide operational flexibility with
respect to planned outages on the transmission system. The addition of the Nary Breaker
Station would allow shorter line lengths to be de-energized for facility construction and
maintenance, thereby minimizing the operational impact of such activities on the existing
115 kV system.
The Nary breaker station would be located adjacent to the existing Nary Junction on an
approximately 5-acre site within a fenced and graded area of approximately 200 feet by 200
121
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
feet. The breaker station would consist of three 115 kV circuit breakers and nine new 115
kV switches; communications, relay and control equipment; three 115 kV line termination
structures; and a control house. An improved access road and small parking lot would also
be required to move equipment to the site. The estimated cost of the Nary Breaker Station
is $2.7 million.
122
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
Project Contingency Drivers
Limiting Element or
Need Driver
63246 BEMIDJI7
HELGA_7 115 1
115
Contingency
Cont
Type
Rating
(MVA
or pu)
B
120
B
126
B
120
66730
Cass Lake – Wilton 230 kV
63247 CASS LK7 115 66710
NARY 7 115 1
Cass Lake – Wilton 230 kV
66710 NARY
7 115 66730
HELGA_7 115 1
Cass Lake – Wilton 230 kV
123
Study Area
Load Level
project
Loading /
Voltage
project
Loading /
Voltage
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
Figure 3156-2: P3156 Winter Pre-Project: 700 MW north; Boswell – Wilton line 230 kV out
124
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
Figure 3156-3: P3156 Winter with Project: 700 MW north; Boswell – Wilton line 230 kV out
125
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Section : New Appendix D Project Justifications
Alternatives Considered
Alternatives to the Boswell – Wilton line Rapids 230 kV line are documented for Project 279.
Alternatives to address the Bemidji area load serving concerns after the Boswell – Wilton
line 230 kV line is in-service without the planned Cass Lake substation expansion, would
include the construction of a new 115 kV line from the Wilton Substation to the Cass Lake
115 kV substation. This new 115 kV line is estimated to be approximately 18.5 miles long
and cost approximately $17 Million considering the required line construction and
substation modifications required at both end-points. This alternative project offers similar
electrical performance as an expanded 230/115 kV substation at Cass Lake, but does cost
more to achieve this same level of system performance. The Wilton – Cass Lake 115 kV
line alternative would still likely be accommodated by the Nary breaker station discussed
above given that this alternative would now form a 115 kV loop between Wilton and Cass
Lake and offer many of the same benefits as that discussed above for the 230 kV
connection at Cass Lake.
Cost Allocation:
This is a Baseline Reliability Project which is eligible for regional cost sharing.
126
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Other Reliability Projects
Projects that are not defined as Baseline Reliability, Generation Interconnection or Transmission
Delivery Service Planning per Attachment FF transmission project definitions but are still
needed for system reliability for various reasons are categorized as “Other” Projects.
Project 2826: Enbridge Transmission Expansion
Transmission Owners: Otter Tail Power Company
Project Description:
Load forecasts received from Enbridge Energy indicate substantial load increases in the
2010 through 2012 timeframe. Additional transmission expansion is needed to reliably
serve the projected load increases. The study results concluded that the addition of the 30
MVar’s of reactive support at Clearbrook and 12 MVar’s of reactive support at Karlstad for
the Near-Term and 15 MVar’s of reactive support at Thief River Fall’s in the Out-Year term
would mitigate any voltage problems in the area..
The project is shown in the figure below.
Area of Low
Voltages
Clearbrook
Outage
127
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Area of low
Voltages
Outage
Area of Low
Voltages
Outage
Figure P2826-1: Geographic Transmission Map of Project Area
128
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Project Justification:
Other than providing reliable service to Enbridge pump stations, any new transmission
improvements for the purposes of Enbridge should improve service to existing OTP
customers in Northwest MN as well as reduce system losses within the OTP Balancing
Area.
Clearbrook - Completion date is December 31, 2010.
Karlstad - Completion date is December 31, 2011.
Thief River Falls – Completion date is December 31, 2013.
Alternatives Considered
The transmission alternatives that were considered for the study are:
1. New Oslo 230/115 kV Substation
a. Tap Drayton-Prairie 230 kV line at 50% of its length
b. 115 kV line from new Oslo Substation to existing Oslo 115 kV substation
(about 8 miles)
2. New Thief River Falls 230 kV Source
a. Add new Winger-Thief River Falls 230 kV line
b. Add new 230/115 kV Transformer at Thief River Falls
3. New Thief River Falls 230 kV Source
a. Add new Winger-Clearbrook-Thief River Falls 230 kV line
4. Other transmission reinforcements such as reactive sources
Cost Allocation:
This is an Other (Reliability) project not eligible for cost sharing. Otter Tail Power Company
estimated costs $3,000,000.00.
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Appendix D: New Appendix A Project Justifications
Project 2855: Grafton 41.6 kV Line Upgrade
Transmission Owners: Otter Tail Power
Project Description:
This project will rebuild three miles of a 41.6 kV line. The expected inservice date is October
2010. The estimated cost for this project is $78,000.
Project Justification:
This project is required due to loading concerns between Drayton 41.6 kV and Minto 41.6
kV.
Alternatives Considered
No Alternatives
Cost Allocation:
Other – Not Shared
130
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Generation Interconnection Projects
There are no projects that have network upgrades eligible for cost allocation per energy Markets
Tariff (EMT). Details of other study work are posted at:
http://www.midwestiso.org/publish/Folder/3e2d0_106c60936d4_-76840a48324a?rev=4.
Transmission Delivery Service Planning Projects
Project 2742: Bemidji – Wilton 115 kV Line Upgrade
Transmission Owners: Otter Tail Power
Project Description:
This project will replace Terminal Equipment on the existing line in order to increase capacity for
Midwest Independent System Operator’s project A411 (F075). The expected inservice date is
October 2010. The estimated cost for this project is $240,000.
Project Justification:
Alternatives Considered
No Alternatives
Cost Allocation:
Other – Not Shared
131
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D1: New Appendix A Project Justifications
Otter Tail Power Generator Interconnection Projects
Project 2825: G474 Grant County Wind
Project Description:
No network upgrades necessary, interconnection only.
Project Justification:
See Generator Interconnection Project G474.
Cost Allocation:
This is a Generator Interconnection Project, which is ineligible for regional cost sharing.
132
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Appendix D1: Southern Minnesota Municipal Power Agency
Basline Reliability Projects
There are no Baseline Reliability projects moving to Appendix A for Southern MN Municipal
Power Agency this MTEP cycle.
Other Reliability Projects
Projects that are not defined as Baseline Reliability, Generation Interconnection or Transmission
Delivery Service Planning per Attachment FF transmission project definitions but are still
needed for system reliability for various reasons are categorized as “Other” Projects.
Project 2166: Saint Peter Area
Transmission Owners: Southern Minnesota Municipal Power Agency.
Project Description:
Saint Peter Area:
Utility:
Southern MN Municipal Power Agency.
Project Justification:
Inadequacy:
Load has continued to grow in the City of Saint Peter area in Nicollet County, and additional load serving
resources are necessary. The existing distribution system is inadequate to serve these new load centers
within the City of Saint Peter. A map of the St. Peter area is shown on the following page.
Alternatives:
The only alternative is to build a new 69 kV load serving distribution substation in the City.
Analysis:
The City has determined that the best solution is to build a new 69 kV substation in the northeast part of
the City called the Sunrise Substation. A new 69 kV line will be constructed between the City’s existing
Broadway Substation and the new Sunrise Substation. The rating of this new 69 kV line section would be
71.7 MVA. This new 69 kV line section will be part of the existing 69 kV line between Traverse and Lake
Emily Substations. In addition, once the new line and substation are constructed, 3.3 miles of an existing
Xcel Energy 69 kV transmission line between the existing Main (Front) Substation and 36th Avenue can
be retired. This section of line being retried has a rating limitation and was planned to be rebuilt in 2010.
Schedule:
This project is expected to be completed by the fall of 2010. Since the project involves only 69 kV
facilities, no state review by the Public Utilities Commission will be required.
133
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2166-1: Geographic Transmission Map of Project Area
Cost Allocation:
Other Not shared.
134
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2167: Redwood Falls Load Serving Substation
Transmission Owners: Southern Minnesota Municipal Power Agency.
Project Description:
Redwood Falls Load Serving Substation
Project Justification:
Utility:
Southern Minnesota Municipal Power Agency
Inadequacy:
Load has continued to grow in the area around Redwood Falls, and additional resources are necessary
to serve residential and commercial customers. The City of Redwood Falls has already determined that a
new load serving substation, called the East Substation, should be installed on the east side of town. The
remaining matter to be determined is how best to provide transmission to this new East Substation. A
map of the area is shown on the following page.
Alternatives:
Two alternative transmission plans were studied to serve the proposed East Substation.
Alternative 1: Serve the new City load serving substation from the existing 69 kV
transmission system in the area.
Alternative 2: Serve the new City load serving substation from the existing 115 kV transmission system
in the area. This approach would involve approximately five miles of new 115 kV transmission line from
the existing West Substation to the new East Substation within the City of Redwood Falls.
Analysis:
Both Alternative 1 (the 69 kV alternatives) and Alternative 2 (the 115 kV alternative)
involve various choices for bringing either a 69 kV or a 115 kV source to the East Substation.
The results of the analysis of the 69 kV alternatives that were considered indicated that the 69 kV
transmission system in the area was only capable of providing adequate service until about 2015.
Therefore, it was determined that the 115 kV option was preferable. The new 115 kV transmission line
from the existing West Substation to the proposed East Substation will be approximately five miles in
length.
Schedule:
The proposed new City load serving East Substation and new 115 kV line serving this
new load serving substation are planned to be in service by 2011. A Certificate of Need for the line will
not be required because it is less than ten miles in length and does not cross the state border. A route
permit from the Public Utilities Commission or local government will be required for the route.
135
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2167-1: Geographic Transmission Map of Project Area
Cost Allocation:
Other project not eligible for cost sharing.
136
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Project 2813: Byron – Westside Rochester Area
Transmission Owners: Southern Minnesota Municipal Power Agency
Byron-Westside Rochester Area
Utility:
Southern Minnesota Municipal Power Agency
Project Justification:
Inadequacy:
The Byron-Westside Rochester area needs additional load serving support to protect against loss of load
in contingency situations. In addition, there are current congestion constraints on the Byron to Maple Leaf
161 kV MISO flow gate, resulting in an increase in the Locational Marginal Price for Rochester and
People’s Cooperative customers in the Rochester area under most system conditions. A map of the
Byron-Westside-Rochester Area is shown on the following page.
Alternatives:
The only alternative is a second 161 kV line between Byron and Maple Leaf.
Analysis:
The existing Byron-Maple Leaf-Cascade Creek 161 kV line was constructed in 1985. This line was
designed for a second 161 kV circuit (double circuit structure capable). This project will utilize this existing
designed double circuit 161 kV line. This new line is approximately seven miles long and is proposed to
be strung on the existing poles along an existing route that parallels Highway 14 for the majority of its
length. This project consists of the following components:
• Approximately 7 miles of 161 kV line, same as the existing conductor 954 ACSR
• 161 kV breaker addition at the existing Byron Substation
• 161 kV breaker addition at Rochester’s new Westside Substation
The total estimated cost for this project is approximately $3,500,000. Additional analysis for this line was
performed under the RIGO Study.
Schedule:
This project is needed by the fall of 2010. This project does not require a Certificate of Need from the
Commission because it is less than 200 kV and less than 10 miles in length, buta route permit from the
PUC or local government will be required.
137
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
Figure P2813-1: Geographic Transmission Map of Project Area
Cost Allocation:
Other project not eligible for cost sharing.
138
139
Figure P2813-2-1a: 2015 Summer Pre Plan; Byron-Cascade out
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
140
Figure P2813-2-1b: 2015 Summer Post Plan; Byron-Cascade out
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix D Project Justifications
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D: New Appendix A Project Justifications
Generation Interconnection Projects
There are no projects that have network upgrades eligible for cost allocation per energy Markets
Tariff (EMT). Details of other study work are posted at:
http://www.midwestiso.org/publish/Folder/3e2d0_106c60936d4_-76840a48324a?rev=4.
Transmission Delivery Service Planning Projects
Project 2171: Mora Land Fill Gas Generator
Transmission Owners: Southern Minnesota Municipal Power Association
Project Description:
This project will add 3 MW of landfill gas generation and construct approximately 7.0 miles of a
12.47 kV distrbution line. The expected inservice date is December 2010. The estimated cost
for this project is $3,700,000.
Project Justification:
This project was a TSR Request for local capacity resource, no interconncection request
was submitted.
Alternatives Considered
No Alternatives
Cost Allocation:
Transmission Delivery Service Planning – Direct Assign
141
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Appendix D1: Xcel Energy
Other Projects
Project 3100: Westgate 115/69 kV TR upgrade
Transmission Owners: Xcel Energy
Project Description:
Project 3100 upgrades the Westgate 115/69 kV transformer #2 to 70 MVA. The project is
required to serve the load at Gleason Lake radially from Westgate. The total estimated cost
of this project is $2,070,000. The expected in service date for this project is June, 2011.
The project is shown in the figure below.
Figure P3100-1: Geographic Transmission Map of Project Area
Project Justification:
142
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
The loss of the Gleason Lake 115/69 kV transformer makes the St. Boni source serve Mound
and Glen Lake loads through a long 69 kV line. This results in severe low voltages at the Glen
Lake load bus. The one-line drawing below indicates the low voltages at Glen Lake are 0.91 p.u.
using coincident peak loads at Mound and Glen Lake.
To avoid low voltages in this condition, all the load has to be served from Westgate substation
and the normally open has to be moved to the north side of the Glen Lake substation. The total
load at Glen Lake substation is expected to exceed the continuous rating of the Westgate
115/69 kV transformer (47 MVA).
Although the one-line diagram shows the load at Glen Lake to be less than 47 MVA, the noncoincident peak load at the substation is expected to exceed 47 MVA by 2010. Since this load
will be radially served from Westgate, non-coincident peak load should be used to determine the
transformer size required at Westgate.
To mitigate this issue, the normally open must be switched to the north side of Glen Lake
substation. All Glen Lake load must be served from the Westgate substation and the Westgate
transformer must be upgraded to 70 MVA.
143
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
One-Line P3100-1: Loss of Glen Lake 115/69 kV Transformer
144
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Cost Allocation:
This project is identified as Other (Reliability) and is not eligible for regional cost sharing
145
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Projects 3102: Louise 115 kV Interconnection
Transmission Owners: Xcel Energy
Project Description:
This project taps the existing 115 kV line between Cherry Creek and Lincoln County in Sioux
Falls, SD. This is a distribution interconnection request for a new 115 kV source to the City
of Sioux Falls. The ultimate build out is for 3 50 MVA distribution transformers. The
expected in service date for this project is December, 2011.
Cost Allocation:
This is an Other (Distribution) project which is not eligible for regional cost sharing.
146
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Projects 2176: Cannon Falls transmission improvements
Transmission Owner: Xcel Energy
Project Description:
This project will add a breaker row at Colvill Substation, install new 115/69 kV transformer at
Colvill substation, and construct a new 2 mile 69 kV line from Colvill to Byllesby. The total
estimated cost of this project is $5.94 million. The expected in service date for this project is
June, 2011.
The project area is shown in the figure below.
Figure 2176-1: Geographic Transmission Map of Project Area
Project Justification:
This project is being built for numerous overloads in the Cannon Falls area under contingencies.
147
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Table 2176-1 Project Contingency Drivers
Need Driver
602000 CANNFLS5
161 615478 GRESPRNGCK5 161 1
602000 CANNFLS5
161 603196 COLVILL
7 115 5
603000 CANNFLS7
115 605160
CNFLSTR8 69.0 1
603000 CANNFLS7
115 605160
CNFLSTR8 69.0 2
605175 BURNSID8
69.0 615479 GRESPRNGCK869.0 1
603000 CANNFLS7
115 603196 COLVILL
7 115 1
603000 CANNFLS7
115 603196 COLVILL
7 115 2
603000 CANNFLS7
115 605160
CNFLSTR8 69.0 1
605175 BURNSID8
69.0 617516 GREBNSD TP869.0 1
Rating
(MW/p
Cont Type
u)
Contingency
Area Load
Level
Pre-project
Loading
(%)/
Voltage
Postproject
Loading
(%) /
Voltage
Breaker 5S81 Failure
C2
168.9
121.3
215.4 n/a
Breaker 5S81 Failure
C2
215.0
121.3
165.6 n/a
Breaker 5S70 Failure
C2
129.0
121.3
157.2 n/a
5S73 Failure
C2
129.0
121.3
156.9 n/a
Breaker 5S81 Failure
C2
45.4
121.3
137.7 n/a
5S73 Failure
C2
154.0
121.3
130.3 n/a
Breaker 5S70 Failure
C2
167.5
121.3
119.9 n/a
Breaker 5S71 Failure
C2
129.0
121.3
111.2
Breaker 5S81 Failure
C2
45.4
121.3
105.4 n/a
The table below lists the substation loads that define the study area for this project and are the
Study Area Loads shown in the results table above.
Table P2176-2 Study Area Substation Loads Modeled
Level
Substation
(MW)
Cannon Falls 69
13.9
South Cannon 69
5.3
Hader 69
3.5
Kenyon 69
2.1
Cherry Grove 69
1.7
Zumbrota 69
10.6
148
77
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Substation
Wellsck J
Farmington 69
Northfield 69
Dundas 69
Castle Rock 69
Colville 138
Area Total
Level
(MW)
1.8
20.6
35.2
17.6
5.8
3.2
121.3
Figure 2176-1: 2014 Summer Pre-Project under Breaker 5S71 failure
149
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Figure 2176-2: 2014 Summer with Project under Breaker 5S71 failure
Cost Allocation:
This is an Other project which is not eligible for regional cost sharing.
150
MTEP10 Midwest ISO Transmission Expansion Plan 2009
Appendix D : New Appendix A Project Justifications
Projects 2767: Fenton 115/69 kV Interconnection
Transmission Owners: Xcel Energy
Project Description:
This project adds a new 69 kV source into the existing 69 kV line. In summer 2012, outage
of the Pipestone-Rock River 69 kV line will result in low voltage along the 69 kV line from the
Rock River substation to the Lake Sarah substation (approximately 88-90%). This existing
line is approximately 90 miles long and when you lose the source at the Pipestone side it is
served radially from the Lyon County source. Adding a new 69 kV source into the existing
69 kV line and adding a new breaker station will allow for better reliability and eliminate any
low voltages in the area. The expected in service date for this project is January, 2012.
Cost Allocation:
This is an Other(Reliability) project which is not eligible for regional cost sharing.
151
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Projects 3097: Monroe County 2nd Transformer
Transmission Owner: Xcel Energy
Project Description:
This project will add one 70 MVA 161/69 kV transformer at Monroe County Substation and add
a breaker to the existing configuration. The total estimated cost of this project is $3.35 million.
The expected in service date for this project is June, 2012.
The project area is shown in the figure below.
Figure 3097-1: Geographic Transmission Map of Project Area
152
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project Justification:
This project is being built for numerous overloads on the Monroe County 161/69 kV transformer
under base case and contingencies.
Table 3097-1 Project Contingency Drivers
**
From bus
** **
To bus
** CKT
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
602025
605292
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
MONROCO5
MONROCO8
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
161
69.0
1
1
1
1
1
1
1
1
1
1
1
1
1
Cont
MVA
Load
%
73.8
105.4
84.9
105.4
83.9
104.2
91.8
109.7
81.1
100.7
83.3
103.4
84.0
104.3
76.9
95.5
B2.LAX-TRM AS
72.5
90.1
B2.LAX-COU
78.1
97.0
C2.6L5 LAX AS
76.3
94.8
C2.6L4 LAX AS
81.0
100.7
C2.6L3 LAX AS
73.0
90.7
C2.6L34 COU AS
Contingency
**
605288
680107
605288
680110
605296
605316
681521
681523
680105
680107
681521
681526
Base Case
NSPGENO8
T RM
NSPGENO8
GENOA
WSTSALE8
LAX
8
SENECA 5
GENOA 5
PURDY
T RM
SENECA 5
BELLCTR5
Comments
**
69.0
69.0
69.0
69.0
69.0
69.0
161
161
69.0
69.0
161
161
1
1
1
1
1
1
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
Install Monroe
Co TR #2
The table below lists the substation loads that define the study area for this project and are the
Study Area Loads shown in the results table above.
Table P3097-2 Study Area Substation Loads Modeled
Substation
Load Level
(MW)
Sparta
Rockland
Bangor
West Salem
Camp McCoy
Swift Creek
Coon Valley
Onalaska
LaCrosse
Leon (DPC)
Sparta (DPC)
Mt. LaCrosse (DPC)
28.617
3.403
3.992
23.65
13.733
25.695
4.882
12.295
47.086
2.042
1.168
2.323
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Figure 2176-1: 2014 2011 Summer Pre-Project under LaCrosse-West Salem 69kV Line Outage
Figure 3097-2: 2011 Summer with Project under LaCrosse-West Salem 69kV Line Outage
Cost Allocation:
This is an Other project which is not eligible for regional cost sharing.
154
MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project 3098: Lake City to Wabasha Line Upgrade
Transmission Owners: Xcel Energy
Project Description:
This project will rebuild the 1FCW portion of Lake City to Wabasha 69 kV line to 477A. The
total estimated cost of this project is $3,300,000. The expected in service date for this
project is June, 2011.
The project is shown in the figure below.
Figure P3098-1: Geographic Transmission Map of Project Area
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Project Justification:
This project is needed to decrease the impedance between Lake City and Alma substations.
The project will prolong a future larger project for a few years and is needed for line
reliability as well, as the line section is in aging condition.
Cost Allocation:
This project has type Other and is not eligible for regional cost sharing.
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MTEP10 Midwest ISO Transmission Expansion Plan 2010
Appendix D : New Appendix A Project Justifications
Projects 3101: Chanarambie Line Move
Transmission Owner: Xcel Energy
Project Description:
This project will add a new 115 kV breaker, move the existing 115 kV line that goes to Lake
Yankton to the new breaker position, and open up the existing 5X95 breaker. The total
estimated cost of this project is $0.73 million. The expected in service date for this project is
June, 2010.
The project area is shown in the figure below.
Figure 3101-1: Geographic Transmission Map of Project Area
Project Justification:
This project is being built to mitigate problems associated with breaker failure at Chanarambie
substation. For a breaker failure of 5X94, Chanarmabie is radial out of Pipestone. This results
in low voltages at Chanarambie and forces curtailment of the wind generation at Chanarambie.
Cost Allocation:
This is an Other project which is not eligible for regional cost sharing.
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