Attachment Y Study Presque Isle 5, 6, 7, 8, & 9: 344 MW ......Aug 15, 2014 · Presque Isle Generation Operating Guide R10 (2010-S-011-E) b. Flow South Standing Op Guide R08 (2010-S-012-E)

Attachment Y Study Presque Isle 5, 6, 7, 8, & 9: 344 MW Coal Retirement, Effective 10/15/2014

ATTACHMENT Y STUDY REPORT August 15, 2014

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EXECUTIVE SUMMARY

Pursuant to the Tariff, an Attachment Y Notification submitted by We Energies was received by MISO on April 15, 2014. The request was for the Retirement of Presque Isle Units 5, 6, 7, 8, & 9 effective October 15, 2014.

Previously, We Energies had provided an Attachment Y Notice to Suspend Presque Isle Units 5, 6, 7, 8, & 9 from February 1, 2014 until June 1, 2015. The Suspension request was denied by MISO and the units were designated System Support Resources (SSRs) due to the identification of transmission reliability issues that could not be mitigated prior to the requested change of status date, February 1, 2014. The units have continued to operate under an SSR agreement filed by MISO January 31, 2014.

MISO performed a transmission system reliability assessment that was reviewed and discussed with stakeholders at five Technical Studies Task Force (TSTF) meetings consistent with MISO’s FERC Order 890 planning practices as provided for in Attachment FF to the Tariff, and with section 38.2.7 of the Tariff (System Support Resources). Through this analysis, and stakeholder discussions, MISO determined that all five Presque Isle units are required to be System Support Resources for the requested Retirement date. These results are consistent with current operating practices that require the availability of all of the Presque Isle units for reliability commitments.

Reliability analysis was performed for both summer peak and shoulder peak load conditions (representative of spring and fall period loading levels). NERC Transmission Planning (TPL) standards were applied to determine whether system performance was within equipment design voltage and thermal limitations, and whether the system remained stable for applicable contingencies within these standards.

The results of the reliability analysis show system instabilities (voltage instability) for the following contingencies resulting from the change in status of Presque Isle generation for both summer peak and shoulder peak load levels:

NERC Category B Contingencies 1. [CEII REDACTED] 2. [CEII REDACTED] 3. [CEII REDACTED] 4. [CEII REDACTED] 5. [CEII REDACTED]

NERC Category C Contingencies 1. [CEII REDACTED] 2. [CEII REDACTED]

Additionally, for summer peak load conditions voltage instability would occur due to the change in status of Presque Isle for:

NERC Category B Contingencies 1. [CEII REDACTED]

NERC Category C Contingencies 1. [CEII REDACTED]

There are additional contingencies and conditions that are less severe which are further detailed in this report.

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MISO reviewed the reliability analysis and potential alternatives to the operation of Presque Isle with stakeholders. The alternatives considered include known new generation interconnection requests, commitments for demand response, system operational steps including reconfigurations, special protection schemes, and transmission system additions. No feasible alternatives have been identified to alleviate the reliability issues that would result in substantial and sustained loss of load without the continued availability of the Presque Isle plant considering the requested Retirement date.

After being reviewed for power system reliability impacts and feasible alternatives as provided for under Section 38.2.7 of the MISO’s Open Access Transmission, Energy & Operating Reserve Markets Tariff (“Tariff”), MISO has determined that Presque Isle Units 5, 6, 7, 8, & 9 should enter into an SSR agreement until sufficient mitigation measures are completely developed and implemented. MISO continues to work with stakeholders in regularly scheduled Technical Study Task Force meetings to evaluate alternatives to the SSR designation.

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ContentsI. Introduction ............................................................................................................................ 5

II. Study objectives ..................................................................................................................... 6

III. Models and Assumptions ....................................................................................................... 7

a. Study Models ..................................................................................................................... 7

b. Study Assumptions ............................................................................................................ 7

IV. Study Criteria and Methodology ............................................................................................ 8

a. Powerflow Analysis Tools .................................................................................................. 8

b. Transmission Owner Planning Criteria ............................................................................... 9

c. MISO Transmission Planning BPM – SSR Impacted Facility Criteria .............................. 10

d. Monitored Areas ............................................................................................................... 11

e. Contingencies .................................................................................................................. 11

f. Number of Units Required ................................................................................................ 11

V. Reliability Study Results ...................................................................................................... 12

a. Contingency Analysis Results .......................................................................................... 12

b. Voltage Stability Results .................................................................................................. 12

c. Number of SSR Units Required ....................................................................................... 13

VI. SSR Agreement Cost Allocation .......................................................................................... 14

VII. Alternatives Analysis ............................................................................................................ 15

a. System Reconfiguration and Operation Guidelines ......................................................... 15

b. Generation Redispatch .................................................................................................... 15

c. New Generation ............................................................................................................... 15

d. Demand Response .......................................................................................................... 17

Generic Demand Response ................................................................................................ 17

Empire Mine Demand Response ........................................................................................ 17

e. New Generation + Demand Response ............................................................................ 18

f. Transmission Projects ...................................................................................................... 19

Transmission Projects to eliminate Presque Isle SSR need: .............................................. 19

VIII. Conclusion ........................................................................................................................... 20

IX. List of Tables and Figures ................................................................................................... 21

X. Appendices .......................................................................................................................... 22

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I. INTRODUCTION

We Energies submitted an Attachment Y Notice to MISO on August 1, 2013 to provide notification of the planned Retirement of Presque Isle Units 5, 6, 7, 8, & 9 per MISO’s Tariff. The generating units are connected to the 138 kV American Transmission Company (ATC) transmission system. The load shape for this area is much flatter than normal with a shoulder peak load that is approximately 85% of the summer peak. Area load is primarily served by 6 sources: the Generation at Presque Isle, the Mackinac VSC, a flow control device, and the Highway 22 – Morgan – Plains 345 kV, Pulliam – Stiles 138 kV, Pulliam – Little Suamico - Stiles 138 kV, and Cranberry – Lakota Road 115 kV transmission lines.

Table 1: Presque Isle Unit Capabilities

Unit Nameplate

(MW)

Module E Net Capacity

(MW)

5 90 556 90 557 90 788 90 789 90 78

Total 450 344

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Figure 1: ATC Transmission map including the Presque Isle Generators in Marquette, MI

II. STUDY OBJECTIVES

Under Section 38.2.7 of MISO’s Tariff, SSR procedures maintain system reliability by providing a mechanism for MISO to enter into agreements with Market Participants (MP) that own or operate Generation Resources or Synchronous Condenser Units (SCUs) that have requested to either Retire or Suspend, but are required to maintain system reliability.

The principal objective of an Attachment Y study is to determine if the unit(s) for which a change in status is requested is necessary for transmission system reliability based on the criteria set forth in the MISO Business Practices Manuals. The study work included monitoring and identifying the steady state branch/voltage violations on transmission facilities due to the unavailability of the Generation Resource or SCU. The relevant MISO Transmission Owner and/or regional reliability criteria are used for monitoring such violations.

If reliability issues are identified during the study MISO will also conduct an open stakeholder planning process to evaluate feasible alternatives to an SSR agreement. The evaluation of alternatives will also be included in this report, if conducted.

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III. MODELS AND ASSUMPTIONS

a. Study Models

Corresponding to the anticipated Retirement of Presque Isle Units 5, 6, 7, 8, & 9 the following power system analysis models were used for the study:

2015 Summer Peak 2015 Shoulder Peak 2015 Shoulder Peak with future Mackinac VSC (flow control device)

The Attachment Y study models were created from the MTEP13 SCED reliability analysis models. The “before” model was created by fully dispatching the Presque Isle units and incorporating the modelling assumptions below. There are no other dispatchable generating units in the area to replace Presque Isle generation, therefore the “after” model was manually dispatched with Presque Isle units 5-9 offline. Replacement generation was sourced from remote generators in the MISO footprint. A comparison of the generation dispatch between the models with Presque Isle generation online and offline is included in Appendix C of this report.

b. Study Assumptions

1. Load a. Upper Peninsula shoulder peak load is modelled at 85% of summer peak

i. ATC supplied load forecast b. Upper Peninsula Mine Load

i. Empire Substation: 116.3 MW, 21.2 Mvar ii. Tilden Substation: 164.3 MW, 5.7 Mvar iii. Total Load: 280.6 MW, 26.9 Mvar iv. From ATC supplied load forecast

c. City of Marquette, Michigan net load: 15 MW i. Was enforced by adjusting the City of Marquette generation (non-market)

2. Generation a. Approved Attachment Y Units were excluded from the model b. Escanaba Generation (SSR Agreement)

i. Summer Peak: 2 of 2 units fully dispatched (25 MW) ii. Shoulder Peak: 2 of 2 units fully dispatched (25 MW)

c. Escanaba CT i. Summer Peak: fully dispatched (13 MW) ii. Shoulder Peak: fully dispatched (13 MW)

d. White Pine Generation i. Summer Peak: 2 of 2 units fully dispatched (36 MW) ii. Shoulder Peak: 2 of 2 units fully dispatched (36 MW)

e. West Marinette Generation i. Summer Peak: 4 of 4 units fully dispatched (213 MW) ii. Shoulder Peak: 1* of 4 units fully dispatched (71 MW)

1. *Due to air permit limitations confirmed by WPS f. Adjacent Wind Units offline:

i. Garden g. The numerous and small run of river units in the local area are not capable of re-

dispatch and were not adjusted in the model 3. System Configuration

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a. In models without the Mackinac VSC project (P2846), the transmission system is normally split between the upper and lower peninsulas of Michigan. The system split is currently at [CEII REDACTED] which has the following lines out of service for construction:

i. [CEII REDACTED] ii. [CEII REDACTED] iii. [CEII REDACTED]

4. Transmission Projects a. Included based on expected In-Service Date (ISD):

i. Indian Lake – Hiawatha 138 kV line, P333, ISD 10/1/2013 ii. Mackinac Flow Control Project, P2846, ISD 7/19/2014

1. The Mackinac VSC project will be included in a variation of the 2014 shoulder model with a 40 MW N -> S flow

2. The UP will be closed-in for this case 3. The adjacent Straits – Pine River 69 kV line rebuild, P3108, ISD

6/1/2014 will be included in this variation b. Excluded based on expected In-Service Date (ISD):

i. Arnold 345/138 kV transformer # 1, P3125, ISD 5/1/2015 ii. Bay Lake Project, P3679, ISD 12/31/2016 iii. North Appleton – Morgan 138 kV line, P3952, ISD 12/31/2016 iv. Berryville T-D, P4358, ISD 6/1/2017 v. Pulliam – Glory Rd Conversion, P3841, ISD 12/1/2016

5. Operating Guides referenced: a. Presque Isle Generation Operating Guide R10 (2010-S-011-E) b. Flow South Standing Op Guide R08 (2010-S-012-E)

Table 2: Table of Models

System Topology

Dispatch Source Model Att Y Gen VSC U.P. Split

2014 SP MTEP13 2015SP

Off N/A Yes

2014 SP MTEP13 2015SP

On N/A Yes

2014 SH MTEP13 2018SH

Off N/A Yes

2014 SH MTEP13 2018SH

On N/A Yes

2014 SH MTEP13 2018SH

Off 40 MW N -> S

No

2014 SH MTEP13 2018SH

On 40 MW N -> S

No

IV. STUDY CRITERIA AND METHODOLOGY

a. Powerflow Analysis Tools

Siemens Power System Simulator (PSS/E) was used to perform AC contingency analysis. Models were solved with automatic control of LTCs, phase shifters, DC taps, and switched shunts enabled. Contingency analysis was performed on before and after models. The results were compared to find if there were any criteria violations due to the unit(s) change of status.

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Powertech’s Voltage Security Assessment Tool (VSAT) was used to perform voltage stability analysis. Models were solved with automatic control of LTCs, phase shifters, switched shunts enabled pre-contingency. Using the before model, a transfer was created by decreasing Presque Isle generation, one unit at a time, starting with the smaller units (5, 6, then 7…). Generation was replaced by increasing Concord and Paris generation. Using MISO-wide generation to replace Presque Isle generation yielded the same result. The maximum transfer step size was 10 MW and the minimum was 1 MW. Contingencies that produced criteria violations during the contingency analysis were selected for simulation in the voltage stability analysis. Thermal and voltage criteria limits were both respected and ignored to determine the steady state operating limits (the first and most limiting thermal or voltage criteria violation that causes system insecurity) as well as the voltage stability limit. The system security limits for this analysis included in this report indicate thermal loadings at 100% of the emergency rating or voltages at emergency limits (0.9 and 1.1 p.u.).

V&R Energy’s Physical and Operational Margins (POM) and Optimal Mitigation Measures (OPM) powerflow analysis software was used to calculate the optimal load shed. Optimal load shed was calculated using the “after” model and the contingencies that produced criteria violations during the contingency analysis.

b. Transmission Owner Planning Criteria

ATC Transmission Planning Criteria applied for thermal analysis: For System Intact (Category A), all thermal loadings exceeding 100% of the normal

rating For Category B and C contingencies, all thermal loadings exceeding 100% of the

emergency rating ATC Transmission Planning Criteria applied for voltage analysis:

For System Intact (Category A), all substation voltages less than 95% or above 105% For Category B and C contingencies, all substation voltages less than 90% or above

110% DPC Transmission Planning Criteria applied for thermal analysis:

For System Intact (Category A), all thermal loadings exceeding 100% of the normal rating

For Category B and C contingencies, all thermal loadings exceeding 100% of the emergency rating

DPC Transmission Planning Criteria applied for voltage analysis: For System Intact (Category A), >100 kV substation voltages less than 90% or above

105% For System Intact (Category A), <100 kV substation voltages less than 95% or above

105% For Category B and C contingencies, all substation voltages less than 90% or above

110% XEL Transmission Planning Criteria applied for thermal analysis:



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XEL Transmission Planning Criteria applied for voltage analysis:

For System Intact (Category A), all substation voltages less than 95% or above 105% For Category B and C contingencies, all non-generator substation voltages less than

92% or above 105% For Category B and C contingencies, all generator substation voltages less than 95% or

above 105% For Category C3 contingencies, all generation substation voltages less than 92% or

above 105%

ITC Transmission Planning Criteria applied for thermal analysis: For System Intact (Category A), all thermal loadings exceeding 100% of the normal

rating For Category B and C contingencies, all thermal loadings exceeding 100% of the

emergency rating

ITC Transmission Planning Criteria applied for voltage analysis: For System Intact (Category A), all substation voltages less than 97% or above 107% For Category B and C contingencies all substation voltages less than 92% or above

107% ITC Transmission Planning Criteria applied for Load Shed analysis:

C1 Contingencies: Facilities > 300 kV, 0 MW; Facilities < 300 kV, 100 MW C2 Contingencies: Facilities > 300 kV, 0 MW; Facilities < 300 kV, 300 MW C3 Contingencies: 500 MW, after the second contingency C5 Contingencies: 300 MW

WPSC Transmission Planning Criteria applied for thermal analysis:



No cascading outages WPSC Transmission Planning Criteria applied for voltage analysis:

For System Intact (Category A), all substation voltages less than 95% or above 105% For Category B contingencies, all substation voltages less than 92% or above 106% For Category C contingencies, all substation voltages less than 90% or above 106%

Under category C contingencies, for the valid thermal and voltage violations as specified above, generation re-dispatch, system reconfiguration, and/or load shedding was considered, if applicable.

c. MISO Transmission Planning BPM – SSR Impacted Facility Criteria

As specified in the MISO BPM-020-r6, the System Support Resource criteria for determining if an identified facility is impacted by the generator change of status will be:

Under system intact and category B contingencies, branch thermal violations are only valid if the flow increase on the element in the “after” retirement scenario is equal to or greater than:

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a) 5% of the “to-be-retired” unit(s) MW amount (i.e. 5% PTDF) for a “base” violation compared with the “before” retirement scenario, or b) 3% of the “to-be-retired” unit(s) amount (i.e. 3% OTDF) for a “contingency” violation compared with the “before” retirement scenario.

Under system intact and category B contingencies, high and low voltage violations are only valid if the change in voltage is greater than 1% as compared to the “before” retirement voltage calculation.

d. Monitored Areas

In the analysis, voltage and thermal loadings were monitored in the Wisconsin Electric (WEC), Alliant East (ALTE), Wisconsin Public Service (WPS), Dairyland Power Cooperative (DPC), and Michigan Electric Transmission Company* (METC) Control Areas from 69 – 345 kV. The Xcel Wisconsin Zone was also monitored from 69 – 345 kV.

*The METC Control area, including the Wolverine Zone, was only monitored in models where the VSC was in-service, due to the system configuration (split at Straits).

e. Contingencies

A subset of the MISO Transmission Expansion Plan (MTEP) contingencies in the ATC, DPC, and Xcel areas were used for AC contingency analysis.

The following NERC Categories of contingencies were evaluated for all models:

1. Category A when the system is under normal conditions. 2. Category B contingencies resulting in the loss of a single element. 3. Category C contingencies resulting in the loss of two or more (multiple) elements.

Maintenance outages with a forced outage were also evaluated in shoulder peak models.

f. Number of Units Required

Throughout this report there are references to both the number of units operating at Presque Isle and the number of units that would be needed in an SSR contract. Due to the system topology and the fact that Presque Isle is the largest plant in the region, there are no other generators that can be used to supplement power to support planned and/or forced outages of one of the Presque Isle units. The number of units operating at Presque Isle represent the number of units running pre-contingent, in order to meet post-contingent NERC reliability criteria. For shoulder load conditions, where unit maintenance is typically performed, it would be necessary to have one additional unit on an SSR contract, in order to meet NERC reliability criteria while one unit is out of service for planned maintenance (TPL-002-0b R1.3.12).

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V. RELIABILITY STUDY RESULTS

Significant voltage stability, thermal, and voltage criteria violations associated with the Retirement of Presque Isle 5, 6, 7, 8, and 9 were identified when compared to the continued availability of the units.

a. Contingency Analysis Results

Thermal Results

Table 13a in Appendix A shows numerous NERC Category B and C contingencies causing thermal criteria violations without Presque Isle 5, 6, 7, 8, and 9 operating and the improvements resulting from the operation of Presque Isle 5, 6, 7, 8, and 9. A majority of the constraints identified are along the high voltage transmission path that serves Eastern Wisconsin and the Upper Peninsula of Michigan.

Voltage Results

Table 13b in Appendix A shows a few NERC Category C contingencies causing voltage criteria violations without Presque Isle 5, 6, 7, 8, 9 and the improvements resulting from the operation of Presque isle 5, 6, 7, 8, and 9. There were several contingencies which did not solve and appeared to result in voltage instability that were further studied. The results of the voltage stability analysis are included below in Sections V.b and V.c.

b. Voltage Stability Results

Voltage stability analysis indicates that several NERC Category B and C contingencies would result in voltage instability for both Summer Peak and Shoulder Peak load conditions if Presque Isle generation is offline:

NERC Category B Contingencies 1. [CEII REDACTED] 2. [CEII REDACTED] 3. [CEII REDACTED] 4. [CEII REDACTED] 5. [CEII REDACTED]

NERC Category C Contingencies 1. [CEII REDACTED] 2. [CEII REDACTED]

Additionally, there are several contingencies that would result in voltage instability only for Summer Peak load conditions if Presque Isle generation is offline:

NERC Category B Contingencies 1. [CEII REDACTED]

NERC Category C Contingencies 1. [CEII REDACTED]

The voltage stability limits were determined using the methodology in Section IV.a. The minimum generation limits and the most severe contingencies are included below in Section V.c.

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c. Number of SSR Units Required

MISO performed voltage stability analysis to determine the most limiting constraints and the number of Presque Isle units required in order to meet transmission system reliability criteria. The detailed methodology of this analysis is included in Section IV.a. The voltage stability analysis indicates that all five Presque Isle units will be needed as System Support Resource (SSR) units. Four units operating are necessary due to both the steady state and voltage stability operating limits. One additional unit would be needed at Presque Isle to ensure unit maintenance and necessary environmental retrofits.

The highlighted row in the following tables indicates the number of Presque Isle units that would need to be operating to prevent the most limiting contingency – constraint pair. The minimum step size (Section IV.a) of 1 MW indicates that if Presque Isle Generation were decreased by 1 MW from what is shown in the table, the first security violation would occur due to the indicated contingency. The most limiting contingencies identified in this analysis were also shown to cause voltage instability if all generation at Presque Isle were offline. If the generation at Presque Isle continued to decrease from the value indicated in the table, additional thermal and voltage violations are expected occur until the voltage stability limit is reached.

Table 3: Most Limiting Contingency-Constraint Pairs - 2014 Shoulder Peak

Most Limiting Contingency

Con Type

Most Limiting Element Mead Loada

Min. PSQI Generation

PSQI Units Operating

[CEII REDACTED] C5 [CEII REDACTED] 40 MW 295 MW 5

[CEII REDACTED] C5 [CEII REDACTED] 0 MW 253 MW *4*

[CEII REDACTED] B [CEII REDACTED] 40 MW 181 MW 3


aMead Load is non-firm load that can be curtailed to reduce flows

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Table 4: Most Limiting Contingency-Constraint Pairs - 2014 Summer Peak


Con Type

Most Limiting Element Mead Loada



[CEII REDACTED] C5 [CEII REDACTED] 40 MW 343 MW 5

[CEII REDACTED] C5 [CEII REDACTED] 0 MW 277 MW *4*




The voltage stability limits require 4 Presque Isle units to be operating in order to maintain system stability for the C5 loss of the [CEII REDACTED] and [CEII REDACTED] transmission lines. Load shed cannot be taken in advance of this event, so the load at Mead is not considered in this case.

Table 5: Voltage Stability Limits - 2014 Summer Peak


Con Type



[CEII REDACTED] C5 276 MW *4*

[CEII REDACTED] B 163 MW 3

VI. SSR AGREEMENT COST ALLOCATION

MISO utilizes a load shed methodology to determine the reliability benefits to each MISO Local Balancing Area (LBA) of operation, without the retired or suspended unit(s). The LBA shares that are calculated in this analysis are used for cost allocation if an SSR agreement is necessary. Although load shed is not permitted for NERC Category A or B events, this methodology determines the load shed amount needed to resolve the reliability issues identified due to the unit change of status, as a proxy for the reliability benefit of SSR unit operation. The load shed values for each contingency are organized by LBA and accumulated to determine the total load shed for each LBA along with the corresponding share ratio. The hypothetical SSR agreement shares that were calculated for this Attachment Y study are included below in Table 6.

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Table 6: SSR Agreement LBA Shares

LBA Load Shed (MW) Share WEC 6536.0 93.79%WPS 38.1 0.55% UPPC 394.6 5.66%

We Energies announced its intention to create a new MIUP LBA that will be comprised of a subset of loads presently contained within the existing WEC LBA. The effective date for this change is currently targeted for December 1, 2014. The load shed calculation itself is not changed due to the creation of or assignment of buses to the MIUP LBA. However, new share ratios would result from the creation of the new MIUP LBA.

VII. ALTERNATIVES ANALYSIS

MISO’s System Support Resource Tariff (Section 38.2.7.c) provides for an open stakeholder planning process to assess feasible alternatives to an SSR agreement. The reliability assessment of this Attachment Y request resulted in SSR eligibility. As provided for in the Tariff, MISO disclosed the Attachment Y Notice on the MISO OASIS and scheduled a stakeholder meeting to review the reliability issues identified in the Attachment Y reliability analysis. MISO solicited alternatives from stakeholders that were reviewed at subsequent meetings. The following is a summary of the alternatives that were reviewed for this study and the impact each may have towards reducing or eliminating the need for SSR status for the subject Attachment Y units.

a. System Reconfiguration and Operation Guidelines

No other tie-ins to the rest of the transmission system exist in this area for loss of critical elements. Any system switching would island or disconnect load.

b. Generation Redispatch

Available units at Escanaba, White Pine, and West Marinette were included in the models. The availability of West Marinette is limited, due to air permit restrictions. The other dispatchable units, Gladstone and Portage, are “Emergency Run Only” units due to air permit restrictions and require a Local Transmission Emergency declaration to run. They cannot be used to support planned maintenance or construction outages. Emergency cannot be called on pre-contingency to prevent voltage instability.

c. New Generation

Presently there are three generator interconnection requests in the MISO queue. At the time of this report, none of the generators have met their milestones to move forward to the Definitive Planning Phase (DPP), a required step prior to an Interconnection Agreement (IA) can be executed. Under the Attachment Y process, only future generators with signed interconnection agreements can be considered as alternatives to an SSR contract. Although it is not required, MISO may evaluate proposed generation in the queue that has not yet entered into an Interconnection Agreement to provide an indication of the potential benefits to the reliability issues caused by the unavailability of the units in an Attachment Y request.

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The following analysis indicates how the addition of proposed generators may reduce or eliminate the need for the Attachment Y units to remain designated SSR units. This analysis does not determine what new issues may arise from the interconnection of new generation or any network upgrades that would be needed to support such an interconnection. The issues caused by an interconnection and any needed upgrades would be determined within a generator interconnection study.

Generator interconnection request J317 is for 112 MW of proposed natural gas fueled generation interconnecting to the Empire 138 kV substation. The requested in service date is June 1, 2016. The developer of this project indicated that it may be possible to accelerate the unit in-service date of the proposed unit so that it would be in-service prior to the MATS compliance deadline faced by Presque Isle (April 16, 2016).

For the purposes of this study, this hypothetical unit was assumed to have a 118 MVA base, with a 0.95 power factor giving it 112.1 MW and ± 36.8 Mvar capabilities. Given the expected in-service date of the unit, both the Arnold 345/138 kV transformer and Holmes – Old Mead Road 138 kV transmission line projects were assumed to be in service.

The addition of this proposed generator at Empire did not affect the number of units required in order to meet system reliability criteria. The limits were determined through a voltage stability analysis, reducing the generation at Presque Isle until the first constraint was identified. The limits determining the number of units required are highlighted in the tables below.

Table 7: Most Limiting Contingency-Constraint Pairs with J317

Load Most Limiting Contingency

Con Type

Most Limiting Element



SP [CEII REDACTED] C5 [CEII REDACTED] 246 MW *4*

SP [CEII REDACTED] B [CEII REDACTED] 153 MW 2

Table 8: Voltage Stability Analysis with J317


Con Type



SP [CEII REDACTED] C5 [CEII REDACTED]

*2*

SP [CEII REDACTED] B [CEII REDACTED]

2

MISO received two interconnection requests after the Attachment Y Notice for Retirement was submitted by WEC. These two projects are J352 and J353 for a 342 and 690 MW, respectively, generating facility connecting to the 345 kV substation at Arnold, the 345 kV substation at Plains, or the 138 kV substation at Plains. The requested in-service date of both of these

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generator proposals is August 1, 2017. MISO is still evaluating the effectiveness of these two proposed generator alternatives and will include the details of that analysis in future revisions of this report.

d. Demand Response

Generic Demand Response

Using optimal powerflow analysis software, MISO determined the optimal and minimum amount of load shed necessary to eliminate all voltage stability, thermal, and voltage criteria violations for 2014 summer peak and shoulder peak load conditions. This provides an indication of the minimum amount of demand response that would be necessary to alleviate all system constraints with all Presque Isle generating units offline. The amount of demand response indicated is for the most severe contingency for each NERC category.

Table 9: Generic Demand Response Values

NERC Category

2014SP Model

2014SH Model

B 237 MW 311 MW

C 287 MW 323 MW

Empire Mine Demand Response

In addition to the generic demand response, MISO also analyzed a theoretical load reduction at the Empire mine at the request of stakeholders. The Empire mine presently has firm transmission service. No demand side management options have been proposed by a Load Serving Entity (LSE) to date. For the purposes of this analysis, it was assumed that this load would be entirely offline or disconnected. If this load were to be disconnected, only 4 Presque Isle units may be needed for an SSR contract, to ensure that 3 may remain operating.

The steady state limits require only 2 Presque Isle units to be operating, as shown in the following table.

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Table 10: Empire Mine Demand Response - Most Limiting Contingency-Constraint Pairs


Con Type


Mead Loada




39 MW

225 MW 3


0 MW 150 MW *2*

SH [CEII REDACTED] C5 [CEII REDACTED]

0 MW 136 MW 2


39 MW

79 MW 2


0 MW 61 MW 1

SH [CEII REDACTED] B [CEII REDACTED]

0 MW 12 MW 1


The voltage stability limits require 3 Presque Isle units to be operating in order to maintain system stability for the C5 loss of the [CEII REDACTED] and [CEII REDACTED] transmission lines. Load shed cannot be taken in advance of this event, so the load at Mead is not considered in this case.

Table 11: Empire Mine Demand Response – Voltage Stability Limits


Con Type




SP [CEII REDACTED]

C5 Voltage Stability

157 MW *3*

SP [CEII REDACTED]

B Voltage Stability

78 MW 2

e. New Generation + Demand Response

A combination of 116 MW of theoretical demand response at Empire (complete removal of load) was also studied in conjunction with the proposed generator J317. With both of these alternatives in place, only the 3 largest units at Presque Isle (7, 8, & 9) may be required for SSR status.

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Table 12: Most Limiting Contingency-Constraint Pairs with J317 and Empire Demand Response


Con Type





129 MW 2

f. Transmission Projects

MISO asked ATC to identify a set of transmission projects that would eliminate the SSR need for any units at Presque Isle. ATC reviewed several transmission projects, including previously approved projects and proposed projects that support multiple system needs, in developing a high-level proposal. The projects considered are a stand-alone proposal that do not include other potential alternatives. ATC’s analysis indicates that the approved projects P3679 and P3952 may eliminate the need of 1 SSR unit (4 on SSR contract). The expected in-service dates for both of these approved projects are still several years away. The incremental set of transmission projects is expected to take 5-7 years to implement. ATC and MISO are continuing to evaluate and determine the transmission upgrades necessary to eliminate the SSR need of Presque Isle.

Transmission Projects to eliminate Presque Isle SSR need:

1. Previously Approved Projects a. P3679, estimated in-service date 12/31/2016

i. North Appleton – Morgan 345 kV line ii. North Appleton 345 kV substation iii. De-bifurcate Morgan – Stiles 138 kV lines iv. Benson Lake (near Amberg) 150 Mvar 138 kV SVC v. Holmes – Old Mead Road 138 kV line

b. P3952, estimated in-service date 12/31/2016 i. North Appleton – Morgan 138 kV line ii. North Appleton 345/138 kV transformer

2. Projects with multiple potential need drivers a. [PRIVILEGED REDACTED] b. [PRIVILEGED REDACTED]

3. Additional Projects to eliminate SSR a. [PRIVILEGED REDACTED] b. [PRIVILEGED REDACTED] c. [PRIVILEGED REDACTED] d. [PRIVILEGED REDACTED] e. [PRIVILEGED REDACTED] f. [PRIVILEGED REDACTED]

PUBLIC VERSION

20

VIII. CONCLUSION

The reliability study for the Retirement of all 5 units at Presque Isle identified reliability issues that cannot be mitigated prior to the unit change of status and thus qualifies Presque Isle for SSR designation. MISO has reviewed these reliability issues and potential alternatives with stakeholders at several Technical Study Task Force (TSTF) meetings from November 2013 until August 2014. The analysis of the proposed alternatives identified no near term solutions that would eliminate or reduce the number of units needed to address the reliability issues that are caused by the Retirement of Presque Isle 5, 6, 7, 8, and 9. Until such time any sufficient alternative can be contracted and implemented, all 5 units at Presque isle should be included in the SSR agreement to ensure that 4 units may be in operating condition at any time, with one unit able to be inoperable for maintenance, retrofit, or other planned outages.

PUBLIC VERSION

21

IX. LIST OF TABLES AND FIGURES

Tables

Table 1: Presque Isle Unit Capabilities ......................................................................................... 5 Table 2: Table of Models .............................................................................................................. 8 Table 3: Most Limiting Contingency-Constraint Pairs - 2014 Shoulder Peak ............................. 13 Table 4: Most Limiting Contingency-Constraint Pairs - 2014 Summer Peak .............................. 14 Table 5: Voltage Stability Limits - 2014 Summer Peak ............................................................... 14 Table 6: SSR Agreement LBA Shares ........................................................................................ 15 Table 7: Most Limiting Contingency-Constraint Pairs with J317 ................................................. 16 Table 8: Voltage Stability Analysis with J317 .............................................................................. 16 Table 9: Generic Demand Response Values .............................................................................. 17 Table 10: Empire Mine Demand Response - Most Limiting Contingency-Constraint Pairs ........ 18 Table 11: Empire Mine Demand Response – Voltage Stability Limits ........................................ 18 Table 12: Most Limiting Contingency-Constraint Pairs with J317 and Empire Demand Response .................................................................................................................................................... 19

Figures

Figure 1: ATC Transmission map including the Presque Isle Generators in Marquette, MI ......... 6

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22

X. APPENDICES

Appendix A: Steady State Contingency Analysis Results

Table 13a: Thermal Results

Table 13b: Voltage Results

Appendix B: Model Generation Dispatch Comparison

Appendix C: Area Transmission System Maps

PUBLIC VERSION

AppendixA: SteadyStateContingencyAnalysisResults

PUBLIC VERSION

MISO Attachment Y Study Results - Presque Isle 5,6,7,8,9 - CONFIDENTIALTable 13a: Compare Thermal ResultsModel VSC Contingency From Bus From Bus Name From kFrom ATo Bus To Bus Name To kV To AreCkt Rating Off MVA Off Pct. On MVA On Pct. OTDF MISO Comments2014SH N [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 846.6 102.37 728 88.03 34.48 Violation caused by suspension2014SH N [CEII REDACTED] 694000 ARPIN B1 345.00 345 694 699245 ARP 138 138.00 138 694 1 381 403.7 105.96 367.9 96.56 10.41 Violation caused by suspension2014SH N [CEII REDACTED] 694064 ROCKY RN B4 345.00 345 696 694065 ROCKY RN BV 345.00 345 696 Z 703 717.3 102.03 658.4 93.66 17.12 Violation caused by suspension2014SH N [CEII REDACTED] 694061 ROCKY RN B1 345.00 345 696 694068 ROCKY RN B8 345.00 345 696 Z 703 710.4 101.05 651.5 92.67 17.12 Violation caused by suspension2014SH N [CEII REDACTED] 694061 ROCKY RN B1 345.00 345 696 694068 ROCKY RN B8 345.00 345 696 Z 703 710.4 101.05 651.5 92.67 17.12 Violation caused by suspension2014SH N [CEII REDACTED] 603141 IRONRIV7 115.00 115 600 608632 DAHLBRG7 115.00 115 608 1 92.2 112.6 122.13 100.2 108.68 3.60 Violation made worse by suspension2014SH N [CEII REDACTED] 698800 MAINE115 115.00 115 696 699703 HILLTP 115.00 115 696 1 205 231.8 113.07 208.4 101.66 6.80 Violation made worse by suspension2014SH N [CEII REDACTED] 698800 MAINE115 115.00 115 696 699733 PINE 115.00 115 696 1 205 216.3 105.51 192.4 93.85 6.95 Violation caused by suspension2014SH N [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 872 105.44 750.9 90.80 35.20 Violation caused by suspension2014SH N [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 885.6 107.09 759.6 91.85 36.63 Violation caused by suspension2014SH N [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 848 102.54 729.4 88.20 34.48 Violation caused by suspension2014SH N [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 895.7 108.31 772 93.35 35.96 Violation caused by suspension2014SH N [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 878.1 106.18 754.6 91.25 35.90 Violation caused by suspension2014SH N [CEII REDACTED] 698561 SUMMITLK 115.00 115 696 699780 VENUS 115.00 115 696 1 150 159.3 106.20 133 88.67 7.65 Violation caused by suspension2014SH N [CEII REDACTED] 699667 ANTIGO 115.00 115 696 699784 BLACK BK 115.00 115 696 1 189 192.7 101.96 168.1 88.94 7.15 Violation caused by suspension2014SH N [CEII REDACTED] 699732 BUNKERHL 115.00 115 696 699784 BLACK BK 115.00 115 696 1 89 93.7 105.28 79.7 89.55 4.07 Violation caused by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 204.1 114.73 191 107.36 3.81 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 241.2 111.67 228.4 105.74 3.72 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 243.1 112.55 230.3 106.62 3.72 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 266.2 123.24 253.3 117.27 3.75 Violation made worse by suspension2014SH N [CEII REDACTED] 602023 LACROSS5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216.1 229.5 106.20 217.5 100.65 3.49 Violation made worse by suspension2014SH N [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 239.1 122.62 227.1 116.46 3.49 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 209.1 117.54 195.8 110.06 3.87 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 242.9 112.45 230.1 106.53 3.72 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 243.1 112.55 230.3 106.62 3.72 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 193.9 108.99 180.1 101.24 4.01 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 204.7 115.06 191.6 107.70 3.81 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 205.6 115.57 192.5 108.21 3.81 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 237.7 110.05 224.9 104.12 3.72 Violation made worse by suspension2014SH N [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 253.4 129.95 240.5 123.33 3.75 Violation made worse by suspension2014SH N [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 229.8 117.85 217.9 111.74 3.46 Violation made worse by suspension2014SH N [CEII REDACTED] 603141 IRONRIV7 115.00 115 600 608632 DAHLBRG7 115.00 115 608 1 92.2 112.3 121.80 100.2 108.68 3.52 Violation made worse by suspension2014SH N [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 253.4 129.95 240.5 123.33 3.75 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 195.1 109.67 182.1 102.36 3.78 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 192 107.93 174.6 98.15 5.06 Violation caused by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 204.1 114.73 191 107.36 3.81 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 224.6 126.25 211.6 118.94 3.78 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 234.6 131.87 220.8 124.11 4.01 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 217.6 122.32 204.5 114.95 3.81 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 230.8 106.85 217.9 100.88 3.75 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 194 109.05 178.2 100.17 4.59 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 229.1 106.06 218.4 101.11 3.11 Violation made worse by suspension2014SH N [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 234.4 120.21 222.4 114.05 3.49 Violation made worse by suspension2014SH N [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 203.6 104.41 192.9 98.92 3.11 Violation caused by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 230.8 106.85 217.9 100.88 3.75 Violation made worse by suspension2014SH N [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 229.1 106.06 218.4 101.11 3.11 Violation made worse by suspension2014SH Y [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 852.5 103.08 737.1 89.13 33.55 Violation caused by suspension2014SH Y [CEII REDACTED] 694000 ARPIN B1 345.00 345 694 699245 ARP 138 138.00 138 694 1 381 407.1 106.85 370.8 97.32 10.55 Violation caused by suspension2014SH Y [CEII REDACTED] 694064 ROCKY RN B4 345.00 345 696 694065 ROCKY RN BV 345.00 345 696 Z 703 718.9 102.26 660 93.88 17.12 Violation caused by suspension2014SH Y [CEII REDACTED] 694061 ROCKY RN B1 345.00 345 696 694068 ROCKY RN B8 345.00 345 696 Z 703 712 101.28 653.1 92.90 17.12 Violation caused by suspension2014SH Y [CEII REDACTED] 694061 ROCKY RN B1 345.00 345 696 694068 ROCKY RN B8 345.00 345 696 Z 703 712 101.28 653.1 92.90 17.12 Violation caused by suspension2014SH Y [CEII REDACTED] 603141 IRONRIV7 115.00 115 600 608632 DAHLBRG7 115.00 115 608 1 92.2 113.4 122.99 100.2 108.68 3.84 Violation made worse by suspension2014SH Y [CEII REDACTED] 698800 MAINE115 115.00 115 696 699733 PINE 115.00 115 696 1 205 221.5 108.05 196.3 95.76 7.33 Violation caused by suspension2014SH Y [CEII REDACTED] 698800 MAINE115 115.00 115 696 699703 HILLTP 115.00 115 696 1 205 236.7 115.46 212.2 103.51 7.12 Violation made worse by suspension

PUBLIC VERSION

MISO Attachment Y Study Results - Presque Isle 5,6,7,8,9 - CONFIDENTIALTable 13a: Compare Thermal ResultsModel VSC Contingency From Bus From Bus Name From kFrom ATo Bus To Bus Name To kV To AreCkt Rating Off MVA Off Pct. On MVA On Pct. OTDF MISO Comments2014SH Y [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 879.3 106.32 759.9 91.89 34.71 Violation caused by suspension2014SH Y [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 887.2 107.28 769.3 93.02 34.27 Violation caused by suspension2014SH Y [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 853.9 103.25 738.5 89.30 33.55 Violation caused by suspension2014SH Y [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 897.5 108.52 781.4 94.49 33.75 Violation caused by suspension2014SH Y [CEII REDACTED] 694082 WERNER W B4 345.00 345 295 694066 ROCKY RN B6 345.00 345 696 1 827 879.4 106.34 764.1 92.39 33.52 Violation caused by suspension2014SH Y [CEII REDACTED] 698561 SUMMITLK 115.00 115 696 699780 VENUS 115.00 115 696 1 150 163.4 108.93 139.3 92.87 7.01 Violation caused by suspension2014SH Y [CEII REDACTED] 699667 ANTIGO 115.00 115 696 699784 BLACK BK 115.00 115 696 1 189 197.1 104.29 173.3 91.69 6.92 Violation caused by suspension2014SH Y [CEII REDACTED] 699732 BUNKERHL 115.00 115 696 699784 BLACK BK 115.00 115 696 1 89 96.5 108.43 82.4 92.58 4.10 Violation caused by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 203.4 114.33 190.4 107.03 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 240.9 111.53 228.1 105.60 3.72 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 242.9 112.45 230 106.48 3.75 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 266.6 123.43 253.1 117.18 3.92 Violation made worse by suspension2014SH Y [CEII REDACTED] 602023 LACROSS5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216.1 230.3 106.57 217.2 100.51 3.81 Violation made worse by suspension2014SH Y [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 240.8 123.49 228.7 117.28 3.52 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 208.4 117.14 195.2 109.72 3.84 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 242.7 112.36 229.8 106.39 3.75 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 242.9 112.45 230 106.48 3.75 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 193.3 108.66 180.3 101.35 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 204.1 114.73 191.1 107.42 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 205 115.23 191.9 107.87 3.81 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 237.4 109.91 224.7 104.03 3.69 Violation made worse by suspension2014SH Y [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 254.7 130.62 242.5 124.36 3.55 Violation made worse by suspension2014SH Y [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 231.3 118.62 219.2 112.41 3.52 Violation made worse by suspension2014SH Y [CEII REDACTED] 603141 IRONRIV7 115.00 115 600 608632 DAHLBRG7 115.00 115 608 1 92.2 113.3 122.89 100.2 108.68 3.81 Violation made worse by suspension2014SH Y [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 254.7 130.62 242.5 124.36 3.55 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 194.6 109.39 181.6 102.08 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 191.3 107.53 178.2 100.17 3.81 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 203.4 114.33 190.4 107.03 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 224.1 125.97 211.1 118.66 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 234.3 131.70 220.5 123.95 4.01 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 216.9 121.92 203.9 114.61 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 230.2 106.57 217 100.46 3.84 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 681531 LAC TAP5 161.00 161 680 1 177.9 193.3 108.66 180.3 101.35 3.78 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 229.2 106.11 218.5 101.16 3.11 Violation made worse by suspension2014SH Y [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 236 121.03 223.9 114.82 3.52 Violation made worse by suspension2014SH Y [CEII REDACTED] 681519 STONEMAN 161.00 161 680 631060 TRK RIV5 161.00 161 627 1 195 205.3 105.28 194.5 99.74 3.14 Violation caused by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 230.2 106.57 217 100.46 3.84 Violation made worse by suspension2014SH Y [CEII REDACTED] 601043 BRIGGS RD 5 161.00 161 600 602026 MAYFAIR5 161.00 161 600 1 216 229.2 106.11 218.5 101.16 3.11 Violation made worse by suspension2014SP N [CEII REDACTED] 698606 LENA WPS 69.000 69 696 699199 PNR TAP 69.000 69 696 1 30 32.6 108.67 21.26 70.87 3.31 Violation caused by suspension2014SP N [CEII REDACTED] 698800 MAINE115 115.00 115 696 699703 HILLTP 115.00 115 696 1 205 254.7 124.24 232.3 113.32 6.51 Violation made worse by suspension2014SP N [CEII REDACTED] 698800 MAINE115 115.00 115 696 699733 PINE 115.00 115 696 1 205 235.5 114.88 212.6 103.71 6.66 Violation made worse by suspension2014SP N [CEII REDACTED] 698561 SUMMITLK 115.00 115 696 699780 VENUS 115.00 115 696 1 150 169.1 112.73 148.3 98.87 6.05 Violation caused by suspension2014SP N [CEII REDACTED] 699667 ANTIGO 115.00 115 696 699784 BLACK BK 115.00 115 696 1 189 210.4 111.32 188.9 99.95 6.25 Violation caused by suspension2014SP N [CEII REDACTED] 699732 BUNKERHL 115.00 115 696 699784 BLACK BK 115.00 115 696 1 89 101.7 114.27 88.6 99.55 3.81 Violation caused by suspension

PUBLIC VERSION

MISO Attachment Y Study Results - Presque Isle 5,6,7,8,9 - CONFIDENTIALTable 13b: Compare Voltage Results

Presque Isle Off Presque Isle OnModel VSC Contingency Bus Bus Name kV Area Vmin Vmax Contingent Voltage Contingent Voltage Voff-Von MISO Comments2014SH Y [CEII REDACTED] 698917 TILDEN2 138.00 138 295 0.9 1.1 0.8217 Violation caused by suspension2014SH Y [CEII REDACTED] 698918 TILDEN3 138.00 138 295 0.9 1.1 0.8219 Violation caused by suspension2014SH Y [CEII REDACTED] 698919 TILDEN4 138.00 138 295 0.9 1.1 0.8221 Violation caused by suspension2014SH Y [CEII REDACTED] 699915 TILDEN1 138.00 138 295 0.9 1.1 0.8217 Violation caused by suspension2014SP N [CEII REDACTED] 698917 TILDEN2 138.00 138 295 0.9 1.1 0.8041 Violation caused by suspension2014SP N [CEII REDACTED] 698918 TILDEN3 138.00 138 295 0.9 1.1 0.8042 Violation caused by suspension2014SP N [CEII REDACTED] 698919 TILDEN4 138.00 138 295 0.9 1.1 0.8044 Violation caused by suspension2014SP N [CEII REDACTED] 699915 TILDEN1 138.00 138 295 0.9 1.1 0.8040 Violation caused by suspension2014SP N [CEII REDACTED] 605537 GRT LKS8 88.000 88 600 0.92 1.05 0.8806 0.8908 -0.0102 Violation made worse by suspension2014SP N [CEII REDACTED] 605538 MINE RD8 88.000 88 600 0.92 1.05 0.8743 0.8845 -0.0102 Violation made worse by suspension2014SP N [CEII REDACTED] 605539 GOGEBIC8 88.000 88 600 0.92 1.05 0.8698 0.8800 -0.0102 Violation made worse by suspension

PUBLIC VERSION

AppendixB: ModelGenerationDispatchComparison

PUBLIC VERSION

Presque Isle Attachment Y Study

Model Dispatch Comparison

2014 SP Unit Dispatch Comparison

Bus Name MW On MW Off Delta MW %

6033 G531 57 75 18 31.6

256348 18ZELND3 0 80 80 999.9

345756 1SIOUX 1 484 519 35 7.2

345998 1GOSCK 1 18.2 72.2 54 295.9

346002 1GOSCK 5 51.5 71.5 20 38.8

364003 1BR FERRY N3 1179.1 1185.1 6 0.5

608763 SBAYP 1G 16.4 46.4 30 182.5

608775 BOSWE44G 500 620 120 24

608902 TAC HBRG3 37.3 85.3 48 128.8

638091 GENESEO8 8.1 26.1 18 222.2

698770 PSQI G5 56 0 ‐56 100

698771 PSQI G6 56 0 ‐56 100

698772 PSQI G7 77 0 ‐77 100

698773 PSQI G8 77 0 ‐77 100

698774 PSQI G9 77 0 ‐77 100

2014SH Unit Dispatch Comparison


364003 1BR FERRY N3 1219.2 1267.4 48.2 4

608774 BOSWE43G 290.7 385.7 95 32.7

620315 BIGSTN1G 304.1 414.5 110.4 36.3

635213 NEAL 3G 530.3 535.3 5 0.9

661015 COYOTE1G 201 444 243 120.9

698770 PSQI G5 56 0 ‐56 100

698771 PSQI G6 56 0 ‐56 100

698772 PSQI G7 77 0 ‐77 100

698773 PSQI G8 77 0 ‐77 100

698774 PSQI G9 77 0 ‐77 100

2014SH_VSC Unit Dispatch Comparison


364003 1BR FERRY N3 1227.2 1281.4 54.2 4.4

599956 PNM‐DC7 451.2 451.3 0.1 0

608774 BOSWE43G 290.7 385.7 95 32.7

620315 BIGSTN1G 304.1 414.5 110.4 36.3

635213 NEAL 3G 530.3 535.3 5 0.9

661015 COYOTE1G 201 444 243 120.9

698770 PSQI G5 56 0 ‐56 100

698771 PSQI G6 56 0 ‐56 100

698772 PSQI G7 77 0 ‐77 100

698773 PSQI G8 77 0 ‐77 100

698774 PSQI G9 77 0 ‐77 100

PUBLIC VERSION

AppendixC: AreaTransmissionSystemMaps

PUBLIC VERSION

L a k e S u p e r i o r

L a k e H u r o n

L a k e M i c h i g a n

C A N A D A

M I C H I G A N

KINGSFORD

O c o n t oO c o n t o

D o o rD o o r

O n e i d aO n e i d a

L a n g l a d eL a n g l a d e

F l o r e n c eF l o r e n c e

M a r i n e t t eM a r i n e t t e

L i n c o l nL i n c o l n

V i l a sV i l a s

F o r e s tF o r e s t

G o g e b i cG o g e b i c

S c h o o l c r a f tS c h o o l c r a f t

O n t o n a g o nO n t o n a g o n

H o u g h t o nH o u g h t o n

M a r q u e t t eM a r q u e t t e

C h i p p e w aC h i p p e w a

M e n o m i n e eM e n o m i n e e

D e l t aD e l t a

M a c k i n a cM a c k i n a c

L u c eL u c e

C h i p p e w aC h i p p e w a

K e w e e n a wK e w e e n a w

A l g e rA l g e r

B a r a g aB a r a g a

I r o nI r o n

Eagle River

Crandon

Tomahawk

Wausaukee

Merrill

Rhinelander

Crivitz

Hubbell

Negaunee

EscanabaGarden

Ontonagon

Baraga

Munising

Stambaugh

Powers

Stephenson

Marquette

Iron River

LakeLinden

Gwinn

Gaastra

Laurium

Daggett

IshpemingHarvey

De TourVillage

MackinacIsland

Kingsford

CrystalFalls

Alpha

Hancock

SouthRange

Carney

CopperCity

Sault Ste.Marie

BlaneyPark SW

STA

Detour

ForestLake

Sawyer Lumber

Brimley

MTU

Watson

DavesFalls

Hiawatha (ESE)

Nathan

Tilden

Eastom

Us Hydro9 & 10

PerchLake

Presque Isle SW YD

M-38

LakeheadRapidRiver

Delta(UPPCO)

NorthBluff

Seney(AD-REA)

Shingleton

Cranberry

BaragaVlg

Hiawatha(AD-REA)

Gladstone

Pines(UPPCO)

Manistique

Dafter

St Germain

AlgerTimberProducts

Conover

Talentino SW STA

GrandRapids Hy

Lincoln Ave (UPPCO)

Henry St.(UPPCO)

Chandler

Valley(ESE)

MichigammeFalls Hy

CrystalFalls

Perkins

Straits

Hulbert

Lakehead Naubinway

Bass Lake

Land OLakes

TwinLakes(UPP)

Newberry

Kincheloe Housing

Cornell-UP

RobertsSW STA

Osceola

St Ignace

McGulpin

Watersmeet

L'anse

FelchMountain

Metonga

Atlantic

Mead Paper

Barnum 3 Mile

Engadine

Goetzville

GouldCitySW STA

KincheloeMain

Tone

Seney(UPPCO)

Greenstone

CaldronFalls Hy

WhitePineMine

TroutLake

(CEC)

LoadingDock Sub

NiagraPaper Of

Wisconsin

ClearLake(WPS)

Elevation St

BruleSW STA

EscanabaSteamPlant

JH Warden

National

Big Bay

Rudyard

Winona

Harris

TwinLake

Curtis

Gwinn

Victoria Hy

Forsyth

Randville

LakeMine

FoxHills

SW STA

SaultEmpireMine

EagleRiver Mackinac

Holmes

Eckerman

Ingalls

MichTransmitterFacility

BruceCrossing

Pickford

StarSiding

ChalkHills Hy

Rexton

NewberryVlg

Stone Container

Humboldt Mine

Mead Pump

Raco

Thunder

Munising

Aspen

Venus

LakeheadIron River

Hodag

Pine Hy

Nordic

Mansfield

Norway

Arnold

Amberg

WhitePine Vlg

SummitLake(WPS)

MichWestern

Limestone

SilverCliff

Rockview

Brevort

Tomahawk -ATC 115kV

PineRiver

Sagola

IndianLake

Rockland(UPP)

SandstoneRapids Hy

TroutLake(ESE)

9 Mile SW STA

GredeFoundries

Mansfield

Plains

Keweenaw

UPSCO

Garden Corners

NorthLake

Lou Pac

Portage (UPPCO)

Toivola

Old Winona

Freeman

Aragon

PortageSt Hy

Goodman

RhinelanderPaper

Ontonagon

PeavyFalls Hy

Lakota RdIron Grove

Three Lakes

Marquette Diesel

Florence

Mass

Limeston

Powers

Woodmin

Pine Grove

K ISawyer

Masonville (UPPCO)

Chatham

M I C H I G A N

W I S C O N S I N

ZONE2

ZONE1

ZONE3

ZONE4

ZONE5

G:\GISDATA\WORKSPACE\ArcMap Templates\Zone Maps\Zone2 11x17.mxd Modified: March 7, 2012

Transmission Related FacilitiesP L A N N I N G Z O N E 2

E l e c t r i c T r a n s m i s s i o n N e t w o r k & S u b s t a t i o n s

Tap or Switching Structure

Substation or Switchyard

Generation

ATC Office Location

Transmission Line Voltage

0 20 4010Miles

Currently, ATC owns or operates transmission facilities in Wisconsin, Illinois, Minnesota, and the Upper Peninsula of Michigan. Facilities include: * Approximately 9440 miles of transmission lines * 109 wholly owned substations * 410 jointly owned substations * ATC offices in Madison, Cottage Grove, Pewaukee, De Pere, and Kingsford, MI

The information presented in this map document represent the most current and accurategeoreferenced compilation of ATC owned and operated transmission facilities available - some facility locations may be approximate. This map is advisory and intended for reference purposes only. Please direct any revisions or corrections to ATC Asset Applications and GIS Group. Base Map Information: ATC, PSCW, MiDNR, WDNR

69 kV Double Circuit

345 kV

115 kV Double Circuit138 kV Double Circuit230 kV Double Circuit345 kV Double Circuit

69 kV115 kV138 kV230 kV

138 kV Underground

69 kV Underground

Non-ATC Line

115 kV Underground

Last Revision: January 2014

L ak e

Mi c

h ig a

n

G r ee n

B a y

Stephenson

Menominee

M e n o m i n e eM e n o m i n e e

W i n n e b a g oW i n n e b a g o

O c o n t oO c o n t o

D o o rD o o r

W a u s h a r aW a u s h a r a

S h e b o y g a nS h e b o y g a n

C o l u m b i aC o l u m b i a

D o d g eD o d g e

G r e e nG r e e nL a k eL a k e

O u t a g a m i eO u t a g a m i e

C a l u m e tC a l u m e t

L a n g l a d eL a n g l a d e

F o n d d uF o n d d uL a cL a c

W a s h i n g t o nW a s h i n g t o n

S h a w a n oS h a w a n o

B r o w nB r o w n

M a r i n e t t eM a r i n e t t e

K e w a u n e eK e w a u n e e

W a u p a c aW a u p a c a

F o r e s tF o r e s t

O z a u k e eO z a u k e e

M a n i t o w o cM a n i t o w o c

Tigerton

GreenLake

Clintonville

WhiteLake

Rosendale

Winneconne

Mayville

Kekoskee

Oshkosh

Cecil

Howard

Fredonia

RandomLake

St.Nazianz

Maribel

SturgeonBay

Marion

Neenah

Stockbridge

Sherwood

Pulaski

PortWashington

CedarGrove

Oconto

Sheboygan

Casco

Forestville

EggHarbor

Berlin

BigFalls

Weyauwega

Appleton

Nichols

Kiel

Wausaukee

Adell

Valders

Whitelaw

FrancisCreek

Fairwater

Fremont

Gresham

Menasha

BlackCreek

Seymour

Gillett

De Pere

Cascade

Oostburg

Mishicot

Luxemburg

Kewaunee

Ephraim

Bowler

Fox Lake

NewLondon

Manawa

Horicon

Bonduel

Eden

Newburg

Kellnersville

Omro

Hortonville

MountCalvary

Wrightstown

WestBend

Glenbeulah

Brillion

OcontoFalls

Crivitz

Waldo

HowardsGrove

Denmark

Manitowoc

Two Rivers

Waupaca

Ogdensburg

Embarrass

Theresa

Lomira

Oakfield

Campbellsport

St.Cloud

ElkhartLake

Chilton

Belgium

Plymouth

Cleveland

Peshtigo

Algoma

SisterBay

MarkesanBrandon

BearCreek

Shiocton

Suring

Kewaskum

Kaukauna

HilbertPotter

Pound

Coleman

Reedsville

Y-95

U-99

T-98

CRIY621

P-68

Y-59

Y-27

R-44

Y-92

Y-80

H-60

Y-68

D-30

Y-50

Y-77

Y-103

B-2

Y-25

J-140

Y-12

3

R-18

K-89

E-5

Y-26

I-87

C-55

Y-157

F-6

Z-130

FIRY11

B-28

WPS_X24

Z-26

Y-24

E-83

A-101

Y-13

3

J-10

Y-56

Y-93

J-88

Y-44

O-15

DYKY21

151

WERW

L61

L-CYP31

NAPL71

W-1

971L51

WERWL41

Y-311

HW22L31

W-5

F-31

8

R-304

971L71

121

111

L-SE

C31

Q-30

3

6832

796L41

HW22L21

111

796L41

L-CY

P31

121

HW22L21

3532

1

U-13J-36

X-1X-57

G-WEM23

MENG21

8222

971K

21

33542

6444

1

X-77X-4

64442

8650

2

X-97

W-75

75541

X-5

35351

X-96

6843

6851

971K11

N-118

X-47

80331

L-142

26523

6853

X-76

H-112

971K31

26522

W-101

WERW

G51

F-58

M-117

G-111

64451

M-39

80332

728K21

6862 6842

LSOG

21

G-85

X-3

WERWG3

1

E-57

X-64

G-INS11

H-86

M-143

I-113F-84

L-90

Y-51

8231

X-48

K-37

MCRG21

3815

1

HOLG

21

8032

971K

51

8232

40561

9752

82414035

G-BTB52

X-30

6084

1

971K

91

6445

264443

Ripon

CypressSW YD

ElkhartLake

Kellnersville

Fredonia

Tecumseh Rd

Lyndon

Canal

Brandon

Beardsley St

HighFalls Hy

Highway 22

Ellington

Neevin

Danz Ave SWSTA

Woodenshoe

Fairwater

Dartford

WestMarinette

SW YD

Auburn

New Holstein SW STA

Bay De NocPolar

Markesan

KettleMorraine(ALTE)

Mayville

Clintonville

Badger

Randolph

Barnett

EastScott St

Beaver Dam3rd St

Lost Dauphin

Willow Lawn

Glory Rd

Maes

Forest

Howard

LakePark

University(WPS)

Caroline

Revere Dr

Ohmstead

Booster

Butte DesMorts

Meyer Rd

OmroIndustrialPark

Ingalls

Shoto

Fitzgerald

BeaverDam East

Rockland (WPS)

Suamico

Casaloma

SouthSheboyganFalls

Butternut

Lawn Rd

Mountain

Bemis

ForwardEnergyCenter

Metomen

Lena

VelpAve

MearsCorners

Barton

PlymouthSub 4

Ashland Ave

SilverCliff

Ryan St

WhiteLake(WE)

SandstoneRapids Hy

Cloverleaf

Peshtigo

St Nazianz

EggHarbor

WernerWest

BayshorePound

Riverside(ALTE)

Mirro

EdgewaterSW YD

Hintz

StilesSW STA

Rosiere

NorthBeaverDam

Manawa

AppleHills

AlgomaCity

Luxemburg24.9

Random Lake

Northeast

Ellinwood

Melissa

Manrap

Menominee

MackfordPrairie

Dyckesville

Holland

PearlAve

Falls

Huebner

Oconto

Mystery Hills

Winneconne

Alto

Bayport SW STA

RiponInd Park

Center St

North Fond Du Lac

Berlin

Oshkosh

GrandRapids Hy

Koch Oil

Greenleaf

KewauneeSW YD

Waupun

Maplewood

ScottPaper Co

LittleSuamico

Michigan St

Red Maple

RiverRun

Dunn Rd

WhiteClay

Ogden St

Columbus St

North Gate

Industrial

Marion

SisterBay

PointBeachSW YD

Erdman

GravesvilleOmro

HowardsGrove

Progress

Rosendale

Sherwood

CaldronFalls Hy

Ontario

Aviation

Northside(sfm)

(ALTE)

EastShawano

Preble

NorthRandolph

Fox Lake(ALTE)

Mason St

FoxRiver

FordDrive

Glenview

Martin Rd

GreenLakeSW STA

Fox HillsSW STA

South Fond Du LacSW YD

Dewey

BrillionIron Works

Hickory St

WaupunMain

Plymouth Sub 3

Glacier

Thunder

Combined Locks

Brusbay

MulletRiver

Bluestone

BellePlaine

Custer

Kaukauna Central

Plymouth Muncipal

ForestJunction

Nicolet Paper Co

Algoma

NorthwestRipon

DeerTrail

Tayco

Horicon

KaukaunaNorth

Ledgeview

FountainValley

Morgan

2nd St (WPS)

Mishicot

NorthAppleton

Fox RiverSW YRD

30th Ave

Sobieski

HoriconInd Park

West Shawano

Mpu Plant

Hubbard

CedarRidge WindGeneration

Crivitz

EastKrok

Bowen St

Spring Brook

Wesmark

Oakfield

Pioneer(WPS)

Potts Avenue

G:\GISDATA\WORKSPACE\ArcMap Templates\Zone Maps\Zone4 11x17.mxd Modified: March 7, 2012

M I C H I G A N

W I S C O N S I N

ZONE2

ZONE1

ZONE3

ZONE4

ZONE5

P L A N N I N G Z O N E 4E l e c t r i c T r a n s m i s s i o n N e t w o r k & S u b s t a t i o n s

Currently, ATC owns or operates transmission facilities in Wisconsin, Illinois, Minnesota,and the Upper Peninsula of Michigan. Facilities include: * Approximately 9440 miles of transmission lines * 109 wholly owned substations * 410 jointly owned substations * ATC offices in Madison, Cottage Grove, Pewaukee, De Pere, and Kingsford, MI

The information presented in this map document represent the most current and accurategeoreferenced compilation of ATC owned and operated transmission facilities available - some facility locations may be approximate. This map is advisory and intended for reference purposes only. Please direct any revisions or corrections to ATC Asset Applications and GIS Group. Base Map Information: ATC, PSCW, MiDNR, WDNR

Transmission Related FacilitiesTransmission Line Voltage

Tap or Switching Structure

Substation or Switchyard

Generation

ATC Office Location

0 10 205Miles


345 kV





69 kV115 kV138 kV

230 kV

138 kV Underground69 kV Underground

Non-ATC Line

Revised: January 2014

Documents

Attachment Y Study Presque Isle 5, 6, 7, 8, & 9: 344 MW ......Aug 15, 2014 · Presque Isle Generation Operating Guide R10 (2010-S-011-E) b. Flow South Standing Op Guide R08 (2010-S-012-E)