MISO-SPP Coordinated System Plan Study Report

May 25, 2017

Table of Contents

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1 Executive Summary........................................................................................................................1

1.1 Regional Reviews............................................................................................................................1

2 Introduction....................................................................................................................................2

3 Stakeholder Involvement................................................................................................................3

4 Scope..............................................................................................................................................3

5 Joint Future Development..............................................................................................................4

6 Joint Economic Model Development..............................................................................................5

7 Cost Estimates................................................................................................................................8

8 Economic Analysis..........................................................................................................................8

8.1 Needs Identification.......................................................................................................................8

8.2 Economic Transmission Solution Development..............................................................................9

8.3 Economic Transmission Solution Evaluation.................................................................................10

8.3.1 APC Methodology..........................................................................................................10

8.3.2 Screening Process..........................................................................................................11

8.3.3 Benefit-to-Cost Analysis.................................................................................................12

8.3.4 Potential Interregional Projects.....................................................................................13

8.3.5 Noteworthy Interregional Projects that Did Not Meet JOA Criteria...............................19

9 Reliability Assessment..................................................................................................................19

10 Conclusions...................................................................................................................................19

10.1 Economic...................................................................................................................................19

10.2 No-harm Test on Economic Projects..........................................................................................20

10.3 Interregional Cost Allocation.....................................................................................................20

11 IPSAC and Joint Planning Committee Recommendation..............................................................21

11.1 IPSAC Recommendation............................................................................................................21

11.2 Joint Planning Committee Recommendation.............................................................................21

12 Regional Review Process..............................................................................................................22

12.1 Southwest Power Pool...............................................................................................................22

12.1.1 Project Review Process..................................................................................................22

12.1.2 Review Results...............................................................................................................22

12.2 Midcontinent Independent System Operator............................................................................22

12.2.1 Project Review Process..................................................................................................22

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Appendix A – Project Screening Results....................................................................................................22

Table 1: 2016 MISO-SPP Coordinated System Plan Tasks............................................................................4Table 2: Regional Carbon Constrained Future Major Assumptions.............................................................5Table 3: 2016 MISO-SPP Coordinated System Plan Hurdle Rates................................................................7Table 4: 2016 MISO-SPP CSP Joint Needs List..............................................................................................9Figure 1: 2016 MISO-SPP CSP Needs Map...................................................................................................9Table 5: Stakeholder Project Submission Summary...................................................................................10Table 6: Projects that Passed Screening....................................................................................................11Table 7: Results of Benefit-to-Cost Analysis..............................................................................................12Figure 2: Loop One Split Rock - Lawrence 115kV Ckt into Sioux Falls........................................................14Figure 3: Crosstown - Blue Valley 161 kV line............................................................................................15Figure 4: Lacygne - Blackberry 345 kV line plus 345/161 kV transformer and Blackberry - Asbury 161 kV line.............................................................................................................................................................17Figure 5: James River - Brookline 345 kV line plus 345/161 kV transformer.............................................18Table 8: Interregional Cost Allocation for Potential MISO-SPP Interregional Project................................21

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1 Executive SummaryThe 2016 MISO-SPP Coordinated System Plan (CSP) study was performed to evaluate the combined MISO & SPP transmission systems in an effort to identify mutually beneficial transmission improvements. The study was a nearly yearlong effort that began on May 31, 2016. MISO and SPP staff focused efforts on an economic analysis of a targeted set of transmission needs identified by MISO and SPP’s respective regional planning processes along the MISO and SPP border.

MISO and SPP evaluated seven (7) unique transmission needs in the 2016 CSP that were identified in the 2017 SPP Integrated Transmission Planning study (2017 ITP10) or the 2016 MISO Transmission Expansion Planning (2016 MTEP) process. This approach of targeting transmission needs identified by the regional planning processes was chosen in response to stakeholder feedback and to make the joint study process more efficient by leveraging much of the regional study work. This approach was also thought to better facilitate a determination of whether interregional transmission solutions exist that are more efficient or cost effective than the regional solutions of the SPP 2017 ITP10 and MISO 2016 MTEP. Beginning with the list of seven (7) targeted needs, staff and stakeholders collaborated to propose potential Interregional Projects to solve the identified transmission issues. The proposed Interregional Projects were then tested for Adjusted Production Cost (APC) benefits. Based on those results, MISO and SPP identified one transmission project for consideration as an Interregional Project:

Loop One Split Rock to Lawrence 115 kV circuit into Sioux Falls

The 2016 CSP study demonstrated this project provides benefit to both MISO and SPP as well as APC benefits that exceed the cost of the project over the initial 20 years of the project’s life. As a result the Loop One Split Rock to Lawrence 115kV circuit into Sioux Falls project was recommended by MISO and SPP to the Interregional Planning Stakeholder Advisory Committee (IPSAC) for endorsement to move from the interregional portion of the study into the regional review process of each respective region. Both the MISO and SPP portion of the IPSAC1 endorsed this recommendation with no opposition. Based on that recommendation, the MISO-SPP Joint Planning Committee (JPC) voted in favor of approving this project for review in both the MISO and SPP regional review processes.

1.1 Regional ReviewsIn accordance with section 9.3.3.6 of the MISO-SPP Joint Operating Agreement (JOA), Interregional Projects recommended by the JPC are subject to a regional review by each region and require approval of each region’s Board of Directors (BOD) to qualify for interregional cost allocation.

1 The MISO portion of the IPSAC is made up of the voting sectors of the Planning Advisory Committee (PAC) and SPP’s portion of the IPSAC is made up of the Seams Steering Committee (SSC) and non SSC Transmission Owners interconnected with MISO.

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2 IntroductionThe JOA establishes a JPC comprised of representatives of both MISO and SPP. The JPC is the decision-making body for coordinated interregional transmission planning and is responsible for all aspects of coordinated interregional transmission planning, including the development of a CSP. The JPC is charged with verifying that the study is conducted in accordance with the requirements of the JOA and that the results of the study are accurate and meet the expectations of the JPC and IPSAC based on the study scope.

The IPSAC provides a forum and an opportunity for stakeholders to review the development of the CSP study and to provide guidance and recommendations to the JPC. IPSAC participation is open to all stakeholders.

On an annual basis, MISO and SPP have agreed to review potential transmission issues identified by each RTO or any stakeholder at an IPSAC meeting as part of an Annual Issues Review process. The Annual Issues Review is administered by the JPC in coordination with the IPSAC to determine whether there is a need for MISO and SPP to perform a CSP study. When MISO and SPP determine a CSP study is warranted, the Order 1000 interregional coordination procedures outlined in the JOA are used to guide the CSP study process.

The purpose of the MISO-SPP CSP study is to jointly evaluate seams transmission issues and to identify if there are transmission solutions that provide benefit to both MISO and SPP and are more efficient or cost effective than regional transmission solutions. This study incorporates an evaluation of economic seams transmission issues and an assessment of potential reliability violations.

At the completion of the CSP study, the JPC produces a draft report documenting the study, including transmission issues evaluated, studies performed, solutions considered, and if applicable, the recommended Interregional Projects with the associated interregional cost allocation. The draft report is made available for stakeholder review. Taking into consideration the recommendation of the IPSAC, the JPC shall meet and vote on whether to recommend any Interregional Project(s) and the associated interregional cost allocation identified in the CSP study report to both MISO’s and SPP’s respective regional review processes for review and approval by the respective Board of Directors.

The Annual Issues Review IPSAC meeting was held on March 9, 2016, at the SPP offices in Little Rock, AR. Multiple stakeholders, along with MISO and SPP staff, presented proposed transmission issues that were considered for evaluation in the CSP study. The feedback from stakeholders at this meeting indicated that there was a strong consensus for moving forward with a CSP study starting in 2016.

Following the IPSAC, the JPC held a meeting to decide if a CSP study would be performed in 2016. The 2016 CSP study was formally initiated on May 31st, 2016, when the JPC voted in favor of performing a 2016 CSP Study. The JPC’s decision was based upon the recommendation of the IPSAC which voted to recommend to the JPC to commence a joint study in 2016. While the JOA allows for up to 18 months to

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complete the study, SPP and MISO staff committed to a completion date for the 2016 CSP study of April 2017.

3 Stakeholder Involvement

The JPC worked with the IPSAC to review and gather input on the 2016 CSP study. The IPSAC met throughout the 2016 CSP study process to review and provide input on such items as:

i. study scope and analysis approach;ii. joint planning models and input assumptions;

iii. seams transmission needs determined from regional processes;iv. proposed transmission solutions and alternatives; andv. recommendation on transmission solutions;

The IPSAC met on multiple occasions throughout the CSP Study both in person and via conference calls. The IPSAC met on the following dates:

i. March 9, 2016;ii. August 2, 2016;

iii. September 7, 2016;iv. December 16, 2016;v. March 9, 2017; and

vi. April 24, 2017

The IPSAC meetings were facilitated jointly by MISO and SPP staff, and the meetings were hosted by one RTO or the other on an alternating basis. All meeting materials are maintained on each RTO’s respective IPSAC webpage. In addition to the IPSAC meetings, each RTO kept their respective stakeholders updated on the status of the 2016 CSP study through regularly scheduled regional stakeholder meetings.

4 ScopeThe JOA requires that each year in which a CSP study is not already in progress, the regions will meet to determine whether a CSP study should be performed. At the March 9th Annual Issues Review meeting, stakeholders provided feedback on issues they would like to see evaluated in a potential CSP study beginning in 2016. A broad range of issues were proposed including, the following:

EPA Clean Power Plan (CPP) Impacts, Settlement Transfer Limits & Contract Path, Market-to-Market (M2M) Flowgate Congestion, Interregional Criteria & Benefits, Congestion, and Integrated System (IS) Seam

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The JPC considered the feedback provided by the IPSAC as well as a targeted completion date and resource availability when developing the 2016 MISO-SPP CSP Scope.

A high-level overview of the scope of the CSP study is shown in Table 1 below:

Table 1: 2016 MISO-SPP Coordinated System Plan Tasks

2016 MISO-SPP CSP Tasks

1. Develop and finalize scope document for CSP study – August 20162. Develop detailed schedule for CSP study – August 20163. Economic Evaluation

Model Development – November 2016 Determine needs list from regional studies – August 2016 Solution Development – November 2016 Solution Evaluation and Robustness Testing – February 2017 Reliability No Harm Analysis – March 2017 Determine interregional cost allocation - March 2017

4. Coordinated Reliability Assessment – March 20175. Draft Coordinated System Plan study report – April 20176. Regional Evaluation and Cost Allocation (if needed)

5 Joint Future DevelopmentThe 2016 CSP study future was based on a regional implementation approach to a national carbon reduction policy. The 2016 CSP study regional carbon-constrained future was based on the MISO 2016 MTEP Regional Clean Power Plan (CPP) Compliance Model and the 2017 SPP ITP10 Regional CPP Compliance Future (Future 1).

The MISO 2016 MTEP Regional CPP future focused on several key items from a footprint-wide level that, in combination, resulted in significant carbon reductions over the course of the study period. Assumptions are consistent with MISO CPP Phase I & II analyses, and include:

Capturing expected effects of existing environmental regulations on the coal fleet, with 12.6 GW of coal unit retirements modeled, including existing or announced retirements

14 GW of additional coal unit retirements, coupled with a $25/ton carbon cost, state mandates for renewables, and half of the Energy Efficiency annual growth used by the EPA, to result in significant carbon emissions reduction by 2030

Additional, age-related retirements using 60 years as a cutoff for non-coal, non-nuclear thermal units and 100 years for conventional hydroelectric

An economic maturity curve with solar and wind to reflect declining costs over time

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Demand and energy growth rates modeled at levels as reported in Module E

The SPP 2017 ITP10 Future 1 utilized responses provided by SPP stakeholders to develop the modeling inputs based on the assumption of how a solution to the EPA CPP would be implemented. This future assumed that the EPA CPP would be implemented at a regional level by meeting emissions targets within the SPP footprint. Future 1 included assumptions from the SPP reference case along with an increase in large-scale solar development and minimal distributed solar development. Assumptions for Future 1 also included but are not limited to the following:

Stakeholder-submitted generation retirements totaled 4 GW of primarily coal generation through the 2017 ITP10 Generation Review process and additional 1.4 GW of CPP related retirements made up a total of 5.4 GW of retirements by 2025

$21.28/ton carbon cost adder

Wind capacity additions were set to 25% and Utility-Scale solar used 3% for year 2020 and 5% for year 2025. Year 2030 model (built specifically for the CSP) utilized 30% wind capacity additions and 7% Utility-Scale solar capacity addition

Demand and energy growth rates as reported by SPP Stakeholders in the 2017 ITP10 Load Review process

Table 2: Regional Carbon Constrained Future Major Assumptions

Regional CPP Futures

Demand and Energy Growth

2025 Regional

CPP Retirements

(GW)

2025 Natural Gas

Price ($)

RPS (10-year

incremental GW)

2025 CO₂ ($) DSM (annual

reduction in year 10 for

EE/DR)MISO 0.75%/0.82% 30 $8.78 5.5 $25 Demand

Impact: EE 9,655 MWEnergy: EE

41,268 GWhSPP 1.01% 5.4 $7.25 8.6 $21.28 Value is

included in peak load

6 Joint Economic Model DevelopmentBoth MISO and SPP utilize ABB’s PROMOD Powerbase software in their respective regional planning processes for performing economic evaluations of proposed transmission solutions, so PROMOD was also used in the 2016 CSP study. The foundation of the joint model used the MISO MTEP 16 Regional CPP Powerbase model. This model was updated with the SPP 2017 ITP10 Future 1 modeling data for the SPP Region to serve as the 2016 CSP study joint model. The joint model also included material updates identified after the regional models were completed as well as changes to each entity’s regional study assumptions as needed. The study used models for years 2020, 2025, and 2030 in evaluating potential transmission solutions to the targeted transmission needs. Since the SPP 2017 ITP10 Regional CPP modeling did not include a 2030 model year, one was created for use in the joint study. The 2030

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Powerbase model utilized SPP’s Economic Studies Working Group (ESWG) approved load and generation data as well as approved resource siting and CPP retirement methodologies that extended out to year 2035. Wind and utility-scale solar capacity percentage additions were increased to reflect SPP’s Generation Interconnection Queue totals.

Modeling FootprintThe modeling footprint included: MISO, SPP, AECI, Manitoba Hydro, MRO, PJM, SERC, and TVA. Transmission TopologyThe transmission topology used in the 2020, 2025, and 2030 models was created using the MISO MTEP 16 and SPP 2017 ITP10 Regional CPP Powerbase powerflow models. The transmission topology for MTEP16 used the 2016 Market Congestion Planning Study (MCPS) models for the candidate Interregional Project coming from the CSP, then relevant approved MTEP16 Appendix A projects (or targeted MTEP16 Appendix A projects depending on the time of the study) were added to the models to evaluate their impacts on the Interregional Project candidate. In addition to the MTEP 16 Appendix A projects, several updates were also made to SPP’s topology that was used in the CSP powerflow model. These updates included 2016 Integrated Transmission Plan Near-Term (ITPNT) projects with a Notification To Construct (NTC), projects from SPP’s Generation Interconnection and Transmission Service Studies with NTCs, and model corrections submitted during the 2016 ITPNT and 2017 ITP10 studies. Note that PJM, SERC, TVA, and Manitoba areas used MISO’s MTEP modeling of external areas that is largely based on the Eastern Reliability Assessment Group (ERAG) Multi-regional Modeling Working Group (MMWG) series models; unless specific regions have provided MISO updated information. The AECI region was enhanced from the ERAG model to include AECI’s approved firm construction plan and any updates as included in the 2017 ITP10 model.

DC interconnections between the Eastern Interconnection and the Western Interconnection and ERCOT that are inservice used SPP’s energy profiles from the 2017 ITP10 models.

Load ForecastsThe load forecasts for the MISO and SPP regions were the forecasts used in the MISO MTEP 16 and the SPP 2017 ITP10, respectively. The load forecast was a 50/50 case. Demand response and energy efficiency was modeled consistent with how each planning region models it in their respective regional carbon-constrained futures.

GenerationThe existing resource mix came from the SPP 2017 ITP10 and MISO MTEP 16 Regional CPP Powerbase models for their respective regions as well as additional retirements required to meet each RTO’s Regional CPP assumptions. New generation, including siting, came from each planning region’s Regional CPP resource expansion plans. The AECI resource plan was derived from the SPP 2017 ITP10. All other regions were modeled using the MISO MTEP 16 expansion results.

The hourly profiles for renewable resources were developed using data from the National Renewable Energy Laboratory (NREL). MISO hourly wind-resource profiles were based on data for 2005, except for the MISO South region and portions of SERC which used data from 2006. SPP hourly wind-resource profiles were based on 2012 data. These yearly profiles were selected as being representative of “normal” or “typical” weather patterns and adjusted to match expected wind-resource annual output levels. These profiles have no effect on the amount of nameplate wind capacity in the models.

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Fuel PricesSPP’s 2017 ITP10 fuel price forecasts for natural gas, coal, oil and uranium were based upon ABB Simulation Ready Data. MISO’s MTEP 16 fuel price forecasts were similarly based on ABB Simulation Ready Data except natural gas prices which were based on the Bentek forecast. After comparing the natural gas prices from the respective SPP and MISO chosen regional study futures and noting that no significant difference existed between the two, the JPC agreed to use the natural gas prices from MISO’s MTEP 16 Regional CPP future.

Hurdle RatesThe 2016 CSP study used the hurdle rates from MISO’s MTEP 16 Regional CPP future for all areas. The hurdle rates used in the joint model differ from what was outlined in the CSP Scope document for certain areas2. The actual hurdle rates used for the joint model are shown below in Table 3.

Table 3: 2016 MISO-SPP Coordinated System Plan Hurdle Rates

2016 MISO-SPP CSP Hurdle Rates (2025 $/MWh)Hurdle Dispatch CommitMISO to SPP $7.55 $10.00SPP to MISO $9.28 $10.00MISO to AECI $7.55 $10.00AECI to MISO $8.29 $10.00SPP to AECI $5.09 $10.00AECI to SPP $8.29 $10.00

MISO North-South 1000 MW Contract PathThe 2016 CSP study utilized MISO’s N-S Nomogram to model the transfer limits defined in the MISO – SPP Settlement Agreement which include:

North/Central to South Regional Directional Transfer Limit: 3,000 MW

South to North/Central Regional Directional Transfer Limit: 2,500 MW

Stakeholder ReviewAfter MISO and SPP staff concluded the initial efforts on developing the model, the consolidated economic model was provided to stakeholders for their review and input. Input provided by stakeholders was reviewed by MISO and SPP staff and included in the final economic models as appropriate. Throughout the study the economic model was refined to address modeling errors as they were identified.

2 The differing hurdle rates outlined in the CSP Scope document are as follows: SPP to MISO Commit $9.28, SPP to AECI Dispatch $9.28, SPP to AECI Commit $9.28, AECI to SPP Dispatch $10.46 and AECI to SPP Commit $10.46.

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7 Cost EstimatesCost estimates for transmission projects being evaluated in the 2016 CSP study were developed utilizing the assumptions MISO and SPP use in their respective regional planning processes. If the prospective project was geographically located within MISO’s footprint, MISO’s project cost estimates were utilized. If the project was geographically located within SPP’s footprint, SPP’s project cost estimates were utilized. SPP applied the SPP region-wide average of 18.16% for the Net Plant Carrying Charge Rate (NPCC) and approximately 8% for the Discount Rate. MISO applied the latest MISO Gross-Plant Weighted Average annual charge rate and approximately 8% for the Discount Rate.

Two separate cost estimate methodologies were utilized. The first was for project screening, which are called the conceptual cost estimates in the CSP. The conceptual cost estimates are derived by using generic data which is used by each RTO in their respective region and is compiled based on stakeholder input and historical data for projects previously constructed in each region. While the actual values used in the cost estimates may vary between the RTOs, this is reasonable because costs associated with transmission development vary by region. MISO and SPP’s cost estimation processes are consistent in the process that is used to develop a cost estimate at this stage of the study. The assumptions used by MISO and SPP for these cost estimates were reviewed with the IPSAC.

The second cost estimate in the CSP is called the study-level estimate. The study-level estimate was developed for each project being considered by the JPC for recommendation as an Interregional Project. The study-level estimate is expected to be a +/- 30% level estimate. MISO utilizes their internal staff in the Competitive Transmission Administration (CTA) group to develop the study-level estimate. SPP contracts with a consultant to develop the study-level estimate. While MISO and SPP have their own processes for calculating study-level estimates, both RTOs target a cost estimate that is within +/-30%. If study-level estimates for projects were already available through each respective RTO’s regional processes those cost estimates were leveraged for the interregional evaluation.

8 Economic Analysis

8.1 Needs IdentificationMISO and SPP leveraged the transmission needs identified in the SPP 2017 ITP10 and the MISO MTEP 16 Regional CPP scenarios. The needs from each respective regional study were compared to determine the set of needs that could potentially be resolved in the 2016 CSP with interregional projects. The selected needs were determined by identifying common areas of congestion where an interregional project could potentially solve congestion on both the MISO and SPP transmission systems.

The set of transmission needs used for the 2016 CSP study was determined by MISO and SPP filtering each of their respective regional needs list to the top needs along the entire seam between MISO and SPP. As described above, this was done by identifying common areas of congestion on the MISO and SPP systems in an attempt to identify which needs could benefit the most from a potential interregional project. Once those lists were created, MISO and SPP staff collaborated with stakeholders to compare

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the regional needs in order to identify areas of common congestion that were most likely to benefit from a potential interregional project. MISO and SPP agreed on seven (7) total needs to be evaluated as part of the 2016 CSP study.

Table 4: 2016 MISO-SPP CSP Joint Needs List

2016 MISO-SPP CSP Joint Needs ListNee

dConstraint Location

1 Rugby WAUE-Rugby OTP Tie FLO Rugby – Balta 230 kV SPP-MISO Tie2 Hankinson - Wahpeton 230 kV FLO Jamestown - Buffalo 345 kV MISO3 Sub3 - Granite Falls 115 kV Ckt1 FLO Lyon Co. 345/115 kV transformer SPP-MISO Tie4 Sioux Falls - Lawrence 115 kV FLO Sioux Falls - Split Rock 230 kV SPP-MISO Tie5 Northeast - Charlotte 161 kV FLO Northeast - Grand Ave West 161 kV SPP6 Neosho - Riverton 161 kV FLO Neosho - Blackberry 345 kV SPP7 Brookline 345/161 kV Ckt 1 Transformer FLO Brookline 345/161 kV Ckt 2

TransformerSPP

Figure 1: 2016 MISO-SPP CSP Needs Map

8.2 Economic Transmission Solution DevelopmentThe seven (7) needs identified in the MISO and SPP regional planning processes and targeted in the 2016 CSP study guided the development of transmission solution ideas that were evaluated as potential MISO-SPP Interregional Projects. Solutions were solicited through the MISO-SPP IPSAC meetings, and each respective RTO staff and stakeholders proposed transmission solutions to address the identified

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transmission issues. SPP and MISO staff also leveraged proposed solutions that had been previously submitted into their respective regional processes.

On October 3, 2016, MISO and SPP staff requested that stakeholders submit potential projects addressing each of the seven (7) targeted transmission needs presented at the September 7, 2016 IPSAC meeting. Stakeholders submitted a total of 36 projects (34 unique) for evaluation in the 2016 CSP study. In addition to stakeholder submissions, staff submitted 10 additional projects for consideration. The table below summarizes the number of stakeholder submitted solutions for each need. No stakeholder developed solutions were submitted for Need 5, so MISO and SPP staff used staff-proposed solutions to evaluate that particular need.

Table 5: Stakeholder Project Submission Summary

2016 MISO-SPP CSP Stakeholder Submitted Project SummaryNeed Constraint Number of Solutions

1 Rugby WAUE-Rugby OTP Tie FLO Rugby – Balta 230 kV 22 Hankinson - Wahpeton 230 kV FLO Jamestown - Buffalo 345 kV 113 Sub3 - Granite Falls 115 kV Ckt1 FLO Lyon Co. 345/115 kV transformer 24 Sioux Falls - Lawrence 115 kV FLO Sioux Falls - Split Rock 230 kV 75 Northeast - Charlotte 161 kV FLO Northeast - Grand Ave West 161 kV 06 Neosho - Riverton 161 kV FLO Neosho - Blackberry 345 kV 87 Brookline 345/161 kV Ckt 1 Transformer FLO Brookline 345/161 kV Ckt 2

Transformer6

8.3 Economic Transmission Solution Evaluation

8.3.1 APC MethodologyAs stated in the JOA, MISO and SPP used an agreed-upon APC metric over a multi-year analysis to jointly evaluate the benefits to the combined MISO-SPP region and to each region individually. The APC is calculated for each simulated year (2020, 2025 and 2030) and benefits for intermediate years between simulated years were estimated using interpolation. Benefits for years beyond the last simulated year were based on extrapolation. The total project benefit was determined by calculating the present value of annual benefits for the first 20 years of project life after the projected in-service date.

The APC benefit metric is based upon the impact of the project on adjusted production cost, which is adjusted to account for purchases and sales. Both MISO and SPP’s APC represents the summation of the APC for the defined areas in each region. Each area’s production cost was adjusted for purchases and sales as follows:

For each simulation hour in which an area is selling interchange, the APC was calculated by multiplying the interchange sales MW times the area’s generation-weighted Locational Marginal Price (LMP) and then subtracting this value from the area’s production cost; and

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For each simulation hour in which an area is purchasing interchange, the APC was calculated by multiplying the interchange purchase MW times the area’s load-weighted LMP and then adding this value to the area’s production cost.

While the JOA outlines how APC should be calculated for evaluating benefits for purposes of determining interregional cost allocation of potential Interregional Projects, MISO calculates APC differently in their regional planning processes than the method used by SPP and stated in the JOA. Instead of using load-weighted LMP to price purchases and generation-weighted LMP to price sales, generation-weighted LMP is adopted for pricing both purchases and sales in current MISO regional APC metrics. The difference in pricing mechanisms can lead to varying results between the benefits calculated in the CSP and the benefits determined by MISO’s regional review process.

8.3.2 Screening ProcessA preliminary screening analysis was performed on all proposed transmission solution ideas to determine the solution ideas that have the most potential and warrant further evaluation. All transmission solution ideas which have potential value were evaluated for APC benefits to MISO and SPP. If there were projects which appeared to be electrically equivalent, only one of the projects was evaluated.

For the preliminary screening analysis, the Benefit to Cost ratio (B/C) for each proposed project was calculated by using APC benefit results of the 2025 model year compared to the 2025 model year estimated costs. If the one-year B/C was at least 0.5, the project was considered to have passed the preliminary screening analysis. A complete list of screening results can be found in Appendix A. Proposed projects passing the preliminary screening process are included in Table 6 below.

Table 6: Projects that Passed Screening

Solution ID Solution Description

Addressed Need ID

#

SPP &

MISO B/CI-1 Rugby 115 kV Breaker/Line Addition 1 5.23

I-1_2 Closes NO switch at North Harvey 115 1 64.62I-2 Rolette 230 kV station 1 0.86I-4 Jamestown 345 kV (OTP) to Jamestown 230 kV

(WAPA) 230 kV Tie2 0.92

I-5 Replace Hankinson & Wahpeton wavetraps 2 20.08I-6 Spiritwood 115 kV to Jamestown 115 kV line 2 1.00I-9 Construct new Rose substation at the juncture of

the Jamestown-Buffalo 345 kV and Jamestown (WAPA)-Pickert 230 kV line

2 0.63

I-11 Hankinson - Wahpeton 230 kV Rebuild 2 1.66I-12 Hankinson - Maple River 230 kV 2 1.26I-14 2nd Lyon County 345/115 kV Transformer 3 1.57I-17 Lawrence - Sioux Falls 115 kV Terminal Equipment

Upgrades4 6.68

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I-18 Loop One Split Rock - Lawrence 115 kV Ckt into Sioux Falls

4 1.89

I-18c Loop Sioux Falls - W. Brandon 115 kV into Split Rock

4 0.82

I-18d Loop Sioux Falls - Beresford 115 kV into Lawrence 4 1.01I-18e De-energize lawrence - Sioux Falls 115 kV 4 45.78

Staff Sol 1 Northeast - Charlotte 2 ohm series reactor 5 27.97Staff Sol 2 Crosstown - Blue Valley 161 kV line 5 2.59

I-19 Tap Neosho - Delaware 345 kV line plus Riverton - tap 345 kV line add new 345/161 kV transformer

at Riverton

6 0.86

I-20 Lacygne - Morgan 345 kV line 6 0.63I-24 Lacygne - Blackberry 345 kV line plus 345/161 kV

transformer and Blackberry - Asbury 161 kV line6 0.85

I-28 James River - Brookline 345 kV line plus 345/161 kV transformer

7 0.69

Staff Sol 3 Morgan 345/161 kV Transformer plus Morgan - Brookline 161 kV uprate

7 2.41

8.3.3 Benefit-to-Cost AnalysisTo calculate an indicative B/C ratio for the proposed transmission solutions passing the preliminary screening analysis, a 20-year net present value calculation of benefits and costs was used3. Benefits were calculated by the change in APC with and without the proposed Interregional Project that passed the screening process. The APC was adjusted to account for purchases and sales. The APC benefit metric was calculated for the simulated years 2020, 2025 and 2030. Benefits for intermediary years were calculated using interpolation and years beyond 2030 used extrapolation. The period covered by the benefit and cost calculation was 20 years starting with the project’s in-service year4. The annual costs were estimated using each RTO’s own respective ATRR/ARRs5 based on whether the project was located in MISO or SPP. The present value calculation assumed an 8% discount rate. Table 7 below shows the B/C analysis of each project that passed the preliminary screening phase of the study. Some projects in the table do not have an associated cost due to the project not having adequate total benefit or adequate benefit to both SPP and MISO to warrant additional analysis.

Table 7: Results of Benefit-to-Cost Analysis

Solution ID

Addressed Need ID #

Solution Description

Project Cost

(2016-M$)

NPV Project Cost (2016-

M$)

20-Yr PV Project Benefit

(2016-M$)

B/C6

SPP Benefit

%

MISO Benefi

t %I-1 1 Rugby 115 kV Breaker/Line Addition 2.5 5.49 1.84 112% -12%

I-1_2 1 Closes NO switch at North Harvey 115 0.2 (5.64) (23.58) 103% -3%I-2 1 Rolette 230 kV station 20.0 2.17 0.09 267% -167%

3 There is not a B/C ratio requirement in the CSP study.4 Initially MISO and SPP have made the assumption that the in-service date for all projects is 2021.5 ATRR/ARR: Annual Transmission Revenue Requirement/Annual Revenue Requirement6 B/C ratio is a NPV number utilizing the 20 year NPV benefit and cost.

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I-4 2 Jamestown 345 kV (OTP) to Jamestown 230 kV (WAPA) 230 kV Tie

18.0 (0.23) (0.01) -2303% 2403%

I-5 2 Replace Hankinson & Wahpeton wavetraps

2.0 155.74 65.13 98% 2%

I-6 2 Spiritwood 115 kV to Jamestown 115 kV line

10.0 2.12 0.18 63% 37%

I-9 2 Construct new Rose substation at the juncture of the Jamestown-Buffalo 345 kV and Jamestown (WAPA)-Pickert 230 kV line

12.0 (6.09) (0.42) 92% 8%

I-11 2 Hankinson - Wahpeton 230 kV Rebuild

26.0 31.09 160.32 5.16 3% 97%

I-12 2 Hankinson - Maple River 230 kV 61.0 219.16 3.00 98% 2%

I-14 3 2nd Lyon County 345/115 kV Transformer

11.0 13.15 (21.09) (1.60) -2% 102%

I-17 4 Lawrence - Sioux Falls 115 kV Terminal Equipment Upgrades

0.5 0.6 11.44 19.14 68% 32%

I-18 4 Loop One Split Rock - Lawrence 115 kV Ckt into Sioux Falls

6.1 7.51 27.83 3.71 19% 81%

I-18c 4 Loop Sioux Falls - W. Brandon 115 kV into Split Rock (Prior to model updates)

4.7 (558.34) (99.36) 46% 54%

I-18d 4 Loop Sioux Falls - Beresford 115 kV into Lawrence (Prior to model updates)

5.8 1.63 0.24 -8% 108%

I-18e 4 De-energize Lawrence - Sioux Falls 115 kV

0.5 0.6 19.05 31.86 26% 74%

Staff Sol 1 5 Northeast - Charlotte 2 ohm series reactor

0.5 0.61 25.89 42.38 83% 17%

Staff Sol 2 5 Crosstown - Blue Valley 161 kV line 8.06 9.84 35.21 3.58 66% 34%

I-19 6 Tap Neosho - Delaware 345 kV line plus Riverton - tap 345 kV line add new 345/161 kV transformer at Riverton

52.73 64.43 55.94 0.87 101.28% -1.28%

I-20 6 Lacygne - Morgan 345 kV line 123.0 150.29 -22.79 -0.15 273.72% -273.72%

I-24 6 Lacygne - Blackberry 345 kV line plus 345/161 kV transformer and Blackberry - Asbury 161 kV line

153.65 187.75 193.83 1.03 95% 5%

I-28 7 James River - Brookline 345 kV line plus 345/161 kV transformer

25.0 30.54 62.49 2.05 80% 20%

Staff Sol 3 7 Morgan 345/161 kV Transformer plus Morgan - Brookline 161 kV uprate

9.25 11.3 51.09 4.52 96% 4%

8.3.4 Potential Interregional Projects Transmission projects that pass the JOA criteria in the CSP have potential to be Interregional Projects. The JOA requirements for Interregional Projects defined in Section 9.6.3.1 of the JOA are as follows:

i. Estimated project cost is $5 million or greater

ii. Project is evaluated as part of a CSP and recommended by the JPC

iii. Benefits to MISO and SPP must each represent 5% or greater of the total benefits identified in the combined MISO and SPP region

iv. Estimated in service date is within 10 years from the date the project is approved

v. Project must be approved under the terms of the MISO OATT and SPP OATT

vi. The project may interconnect to facilities in both the MISO and SPP regions or be wholly within the MISO or SPP region

For the 2016 CSP study, 4 projects passed the Interregional Project criteria defined in the JOA.

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Loop One Split Rock - Lawrence 115kV Ckt into Sioux Falls Crosstown - Blue Valley 161 kV line Lacygne - Blackberry 345 kV line plus 345/161 kV transformer and Blackberry - Asbury 161 kV

line James River - Brookline 345 kV line plus 345/161 kV transformer

8.3.4.1 Loop One Split Rock - Lawrence 115 kV Ckt into Sioux FallsThe proposed Interregional Project, Loop One Split Rock to Lawrence 115 kV Ckt into Sioux Falls, is a proposed new transmission project located near Sioux Falls, South Dakota. This project has an estimated in-service date of 2021.

Figure 2: Loop One Split Rock - Lawrence 115kV Ckt into Sioux Falls

This project was proposed to relieve congestion on the Lawrence to Sioux Falls 115 kV flowgate. MISO and SPP’s analyses show the project completely relieves the congestion on this flowgate and provides benefit to both parties.

MISO estimated a scoping level cost estimate of approximately $6.15 million for this project which has been reviewed by SPP7. Assuming the in-service date of 2021, the $6.15 million cost results in a 20-year present value cost of $7.51 million8. MISO and SPP’s 20-year present value benefit analysis shows that

7 2016 dollars

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MISO and SPP are estimated to collectively receive $27.83 million9 in APC benefit over the first 20 years of the project’s life, resulting in a B/C ratio of 3.71. Of the $27.83 million of APC benefit, SPP is estimated to receive $5.15 million with MISO receiving $22.68 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of benefits, both MISO and SPP’s B/C ratio is 3.71. Based on these numbers, both MISO and SPP supported the recommendation of this project into the regional review process.

8.3.4.2 Crosstown - Blue Valley 161 kV lineThe proposed Interregional Project, Crosstown – Blue Valley 161 kV, is a proposed new transmission project near Kansas City, Missouri. This project has an estimated in service date of 2021.

Figure 3: Crosstown - Blue Valley 161 kV line

This project was proposed to relieve congestion on the Northeast to Charlotte 161 kV flowgate. MISO and SPP’s analyses show that relieving the congestion on this flowgate provides benefit to both Parties. This proposed project is expected to relieve all of the congestion on the Northeast to Charlotte 161 kV flowgate.

SPP estimated an engineering and construction (E&C) cost estimate of approximately $8.06 million10 with an assumed in-service date of 2021. The $8.06 million E&C cost results in a 20-year present value of

8 The 20-year present value cost and benefit numbers here are calculated using SPP’s 18.16% NPCC, factoring in depreciation, and discounting at 8%. The numbers calculated used MISO’s Gross-Plant Weighted annual charge rate and 8% discount rate are similar with SPP’s.9

10 2016 dollars

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$9.84 million11. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the project’s life, MISO and SPP are estimated to receive $35.21 million12 in APC benefit resulting in a 20-year B/C ratio of 3.58. Of the $35.21 million of APC benefit, SPP is estimated to receive approximately $23 million with MISO receiving approximately $12 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of benefits both MISO and SPP’s B/C ratio is 3.58.

SPP prefers the regional solution, Northeast – Charlotte 2 Ohm series reactor, approved in the 2017 ITP10 to address this need and MISO’s preliminary regional evaluation indicates that the Crosstown to Blue Valley 161kV line would likely not pass MISO’s regional review.

8.3.4.3 Lacygne - Blackberry 345 kV line plus 345/161 kV transformer and Blackberry - Asbury 161 kV line

The proposed Interregional Project, Lacygne – Blackberry 345 kV line plus 345/161 kV transformer and Blackberry – Asbury 161 kV, is a new transmission project in Missouri. This project has an expected in service date of 2021.

Figure 4: Lacygne - Blackberry 345 kV line plus 345/161 kV transformer and Blackberry - Asbury 161 kV line

This project was proposed to relieve congestion on the Neosho - Riverton 161 kV flowgate. MISO and SPP’s analyses show that relieving the congestion on this flowgate provides benefit to both MISO and SPP. This project was calculated to relieve 69% of the congestion on the Neosho - Riverton 161 kV flowgate.

11 The 20-year present value cost and benefit numbers are calculated using SPP’s 18.16% NPCC, factoring in depreciation, and discounting at 8%.12

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SPP estimated an engineering and construction (E&C) cost of approximately $153.65 million13 with an assumed in-service date of 2021. The $153.65 million E&C cost results in a 20-year present value of $187.75 million14. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the project’s life, MISO and SPP are estimated to receive $193.83 million15 in APC benefit resulting in a 20-year B/C ratio of 1.03. Of the $193.83 million of APC benefit SPP is estimated to receive approximately $184 million with MISO receiving approximately $10 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of benefits both MISO and SPP’s B/C ratio is 1.03.

SPP and MISO agreed this project was marginally passing several of the JOA criteria for Interregional Projects. The B/C ratio of 1.03 would have likely fallen below the desired 1.0 B/C ratio with any cost increase to the project. The project also only attributes 5.0% of the estimated APC benefit to the MISO region. SPP and MISO agreed to not recommend this project to the regional review. Additionally, SPP prefers the regional solution, Upgrade Butler – Altoona and Neosho – Riverton Terminals, approved in the 2017 ITP10 to address this need. Additionally, Lacygne – Blackberry 345 kV line plus 345/161 kV transformer was evaluated in the 2017 ITP10 and did not pass the screening process.

8.3.4.4 James River - Brookline 345 kV line plus 345/161 kV transformerThe proposed Interregional Project, James River - Brookline 345 kV line plus 345/161 kV transformer, is a new 11 mile long transmission project in Missouri. This project has an expected in service date of 2021.

Figure 5: James River - Brookline 345 kV line plus 345/161 kV transformer

13 2016 dollars14 The 20-year present value cost number is calculated using SPP’s 18.16% NPCC, factoring in depreciation, and discounting at 8%.15 The 20-year present value benefit number is calculated using a discount rate of 8%.

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This project was proposed to relieve congestion on the Brookline 345/161 kV transformer. MISO and SPP’s analyses show that relieving the congestion on this transformer provides benefit to both MISO and SPP. This project was calculated to completely mitigate the congestion on the Brookline 345/161 kV transformer.

SPP estimated an engineering and construction (E&C) cost of approximately $25 million16 with an assumed in-service date of 2021. The $25 million E&C cost results in a 20-year present value of $30.54 million17. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the project’s life, MISO and SPP are estimated to receive $62.49 million18 in APC benefit resulting in a 20-year B/C ratio of 2.05. Of the $62.49 million of APC benefit SPP is estimated to receive approximately $50 million with MISO receiving $12.5 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of benefits both MISO and SPP’s B/C ratio is 2.05.

SPP prefers the regional solution, Morgan Transformer Project, approved in the 2017 ITP10 and SPP-AECI JCSP to address this need, and MISO’s preliminary regional evaluation indicates that the James River - Brookline 345 kV line plus 345/161 kV transformer would likely not pass MISO’s regional review.

8.3.5 Noteworthy Interregional Projects that Did Not Meet JOA Criteria

8.3.5.1 Hankinson - Wahpeton 230 kV RebuildThe proposed Interregional Project, Hankinson – Wahpeton 230 kV Rebuild failed the JOA criteria for Interregional Projects. Based on MISO and SPP’s analysis, this project provides benefits to MISO and SPP although the benefit split is 97% for MISO and 3% for SPP. This project fails to meet the JOA defined benefit threshold of 5% to both RTO’s. MISO will continue to evaluate this project as a potential regional solution.

8.3.5.2 Northeast - Charlotte 2 Ohm series reactorThe proposed Interregional Project, Northeast – Charlotte 2 Ohm series reactor, failed the JOA criteria for Interregional Projects. Based on MISO and SPP’s analysis, this project provides benefits to MISO and SPP with a benefit split of 83% for SPP and 17% for MISO. This project fails to meet the JOA defined cost threshold of $5 million. SPP will pursue this project as a regional solution. This project also more efficiently mitigates the congestion on the Northeast to Charlotte 161 kV flowgate than the proposed Crosstown – Blue Valley 161 kV line. SPP and MISO agree to review the JOA defined criteria to be an eligible Interregional Project, specifically, the review of the cost threshold of $5 million.

8.3.5.3 Morgan 345/161 kV Transformer plus Morgan - Brookline 161 kV uprateThe proposed Interregional Project, Morgan 345/161 kV Transformer plus Morgan – Brookline 161 kV uprate, failed the JOA criteria for Interregional Projects. Based on MISO and SPP’s analysis, this project provides benefits to MISO and SPP with a benefit split of 96% for SPP and 4% for MISO. This project fails to meet the JOA defined benefit threshold of 5% to both RTO’s. SPP will pursue this project through its

16 2016 dollars17 The 20-year present value cost number is calculated using SPP’s 18.16% NPCC, factoring in depreciation, and discounting at 8%.18 The 20-year present value benefit number is calculated using a discount rate of 8%.

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regional study processes and through coordination with AECI. This project also more efficiently mitigates the congestion on the Brookline 345/161 kV transformer.

9 Reliability AssessmentAs stated in the 2016 CSP scope, MISO and SPP staff reviewed proposed and approved reliability projects from their respective regional planning processes. No regional projects of one RTO were identified as replacing the need for a project in the other’s respective regional planning process. Additionally, the review did not indicate any regional projects that could potentially be replaced by a more efficient or cost effective Interregional Project. MISO and SPP have committed to continue to review regional reliability plans as they are approved out of each respective regional planning process.

10 Conclusions

10.1 Economic Based on the results of the economic assessment as well as preliminary regional evaluation results, MISO and SPP identified one proposed project for consideration as an Interregional Project:

I-18: Loop One Split Rock to Lawrence 115kV circuit into Sioux Falls

This project demonstrates benefit to both MISO and SPP as well as APC benefits that exceed the costs of the project over the initial 20 years of the project life.

10.2 No-harm Test on Economic ProjectsInterregional Projects identified to address congestion were evaluated to ensure they do not create reliability issues. The evaluation could have resulted in the modification of the Interregional Project or identification of additional interregional facilities that are needed to mitigate the projected reliability issue.

SPP utilized the their most recent and updated powerflow models to test the Loop One Split Rock to Lawrence 115kV Ckt into Sioux Falls for adverse reliability impacts. SPP 2017 ITP Near-term supplemental models as well as the 2017 ITP Near-term final reliability assessment models, which included the 2017 ITPNT approved projects, were used for the analysis. All 15 combinations of seasons and model years were tested, and no reliability violations were caused by the addition of the project.

MISO reviewed 2016 MISO Transmission Expansion Planning (MTEP) for any harmful impact of project I-18. Steady-state reliability analysis was performed to check for overloads and voltages within bandwidths. MISO performed steady state analysis on the Loop One Split Rock to Lawrence 115kV circuit into Sioux Falls. Five models were used to analyze pre- and post-project system conditions to compare impacts. Contingencies from the area provided by Transmission Planners and new contingencies representing the project were simulated. Results were analyzed for new inabilities for the transmission system to reliably meet violations and large impacts to existing issues. Reliability No-Harm-

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Testing of project I-18 found one adverse impact of the project to the MISO or SPP19 system for the studied conditions. This was an overload of the line between Lawrence to Sioux Falls due to a P6 event involving the loss of Sioux Falls – Lawrence and Split Rock – Lawrence line #2. Though this overload was shown in analysis, it is expected that a generator interconnection project will resolve loading issues by the end of 2017.

10.3 Interregional Cost AllocationAs outlined in the JOA, MISO and SPP have agreed to use the APC benefit metric to allocate the costs to each planning region of proposed Interregional Projects addressing primarily economic congestion.

If the recommended Interregional Project is approved by both the MISO Board of Directors and SPP Board of Directors as an Interregional Project, the cost allocation between MISO and SPP will be allocated in accordance with the chart below.

Table 8: Interregional Cost Allocation for Potential MISO-SPP Interregional Project

Project E&C Project CostM$

MISO Cost %

SPP Cost %

Loop One Split Rock - Lawrence 115 kV Ckt into Sioux Falls

$6.15 81.48% 18.52%

11 IPSAC and Joint Planning Committee RecommendationAs described in Section 9.3.3.5.1 of the JOA, a draft report detailing the work efforts completed as part of the CSP, including any proposed Interregional Projects, was provided to the IPSAC on May 25, 2017. The IPSAC had the opportunity to provide a recommendation to the JPC on the proposed Interregional Project. Taking into consideration the recommendation from the IPSAC and the combination of MISO and SPP stakeholders’ votes, the JPC met and voted to recommend the Interregional Project and associated interregional cost allocation, provided in this report, to both the MISO and SPP regional review processes for review and approval.

The CSP study report proposes one Interregional Project to be recommended for regional review:

Loop One Split Rock to Lawrence 115 kV circuit into Sioux Falls

11.1 IPSAC RecommendationThe IPSAC net conference on April 24, 2017 resulted in feedback in support of the proposed Interregional Project. Multiple stakeholders expressed support for the project while there was no voiced opposition.

19 Due to the construction of MTEP models and timing of ERAG model construction, facilities in the SPP footprint have a one year delay of representation in these models. For a more accurate test of no-harm, SPP analysis and results should be considered.

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In addition to the IPSAC input provided during the April 24 IPSAC net conference, the MISO stakeholders’ share of the IPSAC vote was conducted on April 27, 2017 at the MISO Planning Advisory Committee special meeting. The MISO portion of the IPSAC is represented by the sector representatives of the MISO Planning Advisory Committee. MISO stakeholders voted in favor of recommending the proposed Interregional Project to both the MISO and SPP regional review processes with no opposition.

The SPP stakeholders from the IPSAC conducted their vote on whether or not to move the Interregional Project to the respective regional review processes at the May 3, 2017 Seams Steering Committee (SSC) meeting. The SPP stakeholders on the IPSAC include the members of the SPP Seams Steering Committee (SSC) and a representative from each non-SSC member SPP Transmission Owner which is interconnected with MISO’s transmission system. The SPP stakeholders voted unanimously to direct the SPP portion of the JPC to vote in favor of recommending the proposed Interregional Project to both the MISO and SPP regional review processes.

11.2 Joint Planning Committee RecommendationThe MISO and SPP representatives of the Joint Planning Committee met on May 15, 2017 to formally vote on the proposed Interregional Projects to be recommended for review in both the MISO and SPP regional processes. Taking into consideration the recommendation of the IPSAC, the JPC voted in favor of recommending the proposed Interregional Project for review in both the MISO and SPP regional processes.

12 Regional Review Process

12.1 Southwest Power Pool

12.1.1 Project Review Process

12.1.2 Review Results

12.2 Midcontinent Independent System Operator

12.2.1 Project Review Process

Appendix A – Project Screening ResultsAppendix A will be added and posted with the final version of the 2016 MISO-SPP CSP Study Report.

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