1

MISO-SPP Coordinated System Plan Study Report

June 18, 2015

2

1 Table of Contents 2 Executive Summary .......................................................................................................................... 1

3 Introduction ..................................................................................................................................... 1

4 Stakeholder Involvement ................................................................................................................. 2

4.1 Third Party Coordination ................................................................................................................. 2

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

5.1 Sensitivities ...................................................................................................................................... 5

6 Model Development ........................................................................................................................ 6

6.1 Economic Model .............................................................................................................................. 6

6.2 Reliability Models ............................................................................................................................. 8

6.2.1 Dynamics ........................................................................................................................... 8

6.3 Constraint Assessment..................................................................................................................... 8

7 Cost Estimates .................................................................................................................................. 9

8 Economic Evaluation ........................................................................................................................ 9

8.1 Issues Identification ......................................................................................................................... 9

8.1.1 Historical Congestion Analysis .......................................................................................... 9

8.1.2 Historical Congestion Analysis Results .............................................................................. 9

8.1.3 Projected Congestion Analysis ........................................................................................ 10

8.2 Economic Transmission Solution Development ............................................................................ 11

8.2.1 APC Methodology ........................................................................................................... 11

8.2.2 Screening Process ........................................................................................................... 11

8.2.3 20-Year Benefit to Cost Calculation ................................................................................ 12

8.2.4 Top Performing Projects ................................................................................................. 13

8.2.5 Sensitivity Analysis .......................................................................................................... 19

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

9.1 Steady State Contingency Analysis ................................................................................................ 20

9.1.1 Issues Assessment ........................................................................................................... 20

9.1.2 Reliability Assessment Solutions Development .............................................................. 22

9.1.3 Solution Evaluation ......................................................................................................... 23

3

9.2 Dynamic Assessment ..................................................................................................................... 25

9.3 Review of Regional Projects ........................................................................................................... 26

9.4 No-harm Test on Economic Projects.............................................................................................. 26

10 Conclusions .................................................................................................................................... 27

10.1 Economic ..................................................................................................................................... 27

10.2 Reliability ..................................................................................................................................... 28

10.3 Interregional Cost Allocation ...................................................................................................... 28

11 Joint Planning Committee and IPSAC Recommendation ............................................................... 29

12 Regional Review Process ................................................................................................................ 29

12.1 Southwest Power Pool ................................................................................................................ 29

12.1.1 Project Review Process ................................................................................................... 29

12.1.2 SPP Regional Cost Allocation........................................................................................... 29

12.2 Midcontinent Independent System Operator ............................................................................ 29

12.2.1 Project Review Process ................................................................................................... 29

12.2.2 MISO Regional Cost Allocation ........................................................................................ 29

1

2 Executive Summary [TO BE COMPLETED IN THE FINAL VERSION AFTER JPC RECOMMENDATION]

3 Introduction The FERC-filed MISO-SPP Joint Operating Agreement (JOA) establishes a Joint Planning Committee (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 Coordinated System Plan (CSP). The JPC will verify that the results of the study are accurate and meet the expectations of the JPC based on the study scope. The Interregional Planning Stakeholder Advisory Committee (IPSAC) was formed to provide 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 Coordinated System Plan (CSP) study. When MISO and SPP determine a CSP study is warranted, the Order 1000 interregional coordination procedures outlined in the MISO-SPP JOA will be used to guide the CSP study process. The purpose of the MISO-SPP CSP study is to jointly evaluate seams transmission issues and identify transmission solutions that efficiently address the identified issues to the benefit of both MISO and SPP. 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 shall produce 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. Taking into consideration the recommendation of the IPSAC, the JPC shall meet and vote 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 processes for review and approval by the respective Board of Directors. The Annual Issues Review IPSAC meeting was held on January 21, 2014, in Dallas, TX. Multiple stakeholders, along with MISO and SPP staff, presented proposed transmission issues that were considered for evaluation in a CSP. The issues ranged from reliability issues, economic issues, and issues identified due to the sub-regional power balance constraint between MISO North\Central and MISO

2

South. The feedback from stakeholders at this meeting indicated that there was a strong consensus for moving forward with a CSP starting in 2014. Following the IPSAC the JPC held a meeting where it was formally decided to perform a CSP starting in 2014. The schedule for the 2014 SPP-MISO CSP study would be no longer than 18 months and would be scheduled to conclude in June 2015.

4 Stakeholder Involvement The MISO-SPP IPSAC is the joint stakeholder group which is utilized to provide stakeholders an opportunity to comment on the CSP Study. The IPSAC’s role is to provide input and review on the following items in the CSP Study:

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

iii. identified seams transmission issues or opportunities; iv. proposed transmission solutions and alternatives; v. recommendation on transmission solutions; and

vi. CSP report. 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. November 6, 2013; ii. January 21, 2014; iii. April 8, 2014; iv. May 12, 2014; v. October 7, 2014; vi. February 24, 2015; vii. May 6, 2015; and viii. June 18, 2015.

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.

4.1 Third Party Coordination In addition to coordination between the RTOs and the stakeholders within each RTO, there were opportunities to work with third party stakeholders. As an example, there were some projects which could potentially provide value to Associated Electric Cooperatives, Inc., which is a cooperative located in Missouri. Due to AECI’s location it is possible that they would be interested in certain projects identified in the CSP.

3

If it was determined that a project could provide value to a third party, that party was contacted to determine if there was any interest in that party participating in that project along with MISO and SPP. While there were a few projects where this took place, as you will see below, none of those projects were identified as being more cost effective or efficient than other interregional projects or regional solutions.

At the first IPSAC meeting held in November 2013, stakeholders proposed 34 transmission issues in preparation for the start of the Annual Issues Review process. The submitted issues were reviewed by the JPC for consideration to be evaluated in the CSP. The selected issues to be evaluated in the CSP study were used to identify and evaluate potential interregional projects that may provide benefits to MISO and SPP. A broad range of issues were proposed including, the following:

• congestion; • integration of the MISO South region; • expanded market operation by SPP; • real-time operational issues; • reliability issues; and • public policy requirements1.

During the development of the CSP study scope the JPC took into consideration those proposed issues. A high-level overview of the scope of the CSP study is shown in the table below:

MISO-SPP CSP Tasks

Scope Development Develop and finalize scope document for CSP study

Develop detailed schedule for CSP study Economic Evaluation and Reliability Assessment

Economic Evaluation Reliability Assessment • Future and Model

Development • Perform steady-state

reliability assessment using jointly developed power flow models

• Historical and Projected Congestion Analysis

• Test system stability using scenario(s) appropriate for studying dynamics.

• Solution Development • Determine if there are 1 It should be noted that while there was not a specific assessment focused on public policy issues, all approved public policy mandates and targets were included in the models used for the economic and reliability assessment.

4

interregional alternatives to proposed regional solutions

• Solution Evaluation and Robustness Testing

• Evaluate potential transmission solutions, as needed, based on identified issues.

• Reliability Analysis Determine interregional cost allocation

Draft Coordinated System Plan study report Regional Evaluation and Cost Allocation (if needed)

5 Future Development The future for this study was a Business as Usual (BAU) Future based off the MISO 2015 MISO Transmission Expansion Plan (MTEP 15) BAU Future and the 2015 SPP Integrated Transmission Plan 10-Year Assessment (ITP10) BAU Future (F1). MISO’s MTEP 15 BAU Future captures all current policies and trends in place at the time of futures development and assumes they continue, unchanged, throughout the duration of the study period. All applicable Environmental Protection Agency (EPA) regulations governing electric power generation, transmission and distribution are modeled. Demand and energy growth rates are modeled at a level equivalent to the 50/50 forecasts submitted into the Module E Capacity Tracking (MECT) tool. All current state-level Renewable Portfolio Standard (RPS) and Energy Efficiency Resource Standard (EERS) mandates are modeled. To capture the expected effects of environmental regulations on the coal fleet, 12.6 GW of coal unit retirements are modeled. SPP’s 2015 ITP10 BAU Future-(F1) utilizes inputs provided by SPP stakeholders to develop the modeling inputs based on the assumption that policy requirements will remain constant. Stakeholders provide to SPP their anticipated level of renewable resources to meet all required mandates and targets. Renewable resources include 3.3 GW of new wind and 20.5 MW of new solar. Less than 1 GW of coal unit retirements are modeled in the 2015 ITP10. The load forecast used in the 2015 ITP10 BAU (F1) is a 50/50 load forecast.

Table 1: Regional Business as Usual Future Major Assumptions

Regional BAU

Futures

Demand and Energy

Growth

Retirements Natural Gas Price

(2014$)

RPS (10-year incremental GW)

CO₂ Price

DSM (annual demand reduction

in year 10 for EE/DR)

MISO 0.8% 12.6 GW $4.30 3.6 GW wind/ 1.1 None 6,000 GWh/ 12

5

Coal GW Solar MW SPP 1.3% < 1 GW Coal $5.41 3.3 GW Wind/

20.5 MW Solar None Embedded in Load

The sensitivities were used to further evaluate the potential project. This evaluation utilizing the sensitivities provides additional information that the JPC can use in determining whether or not to propose an interregional project to the respective RTOs.2

5.1 Sensitivities In additional to the BAU future described above, MISO and SPP agreed, based on stakeholder feedback, to also perform three sensitivities. These sensitivities were used to evaluate the impacts of a carbon price, higher natural gas price forecast, and the Sub-Regional Power Balance Constraint (SRPBC)between MISO /Central and South on congestion between the two planning regions. 3

For the carbon price sensitivity a carbon price of $64 dollars was used. This was derived from the MISO MTEP 15 Public Policy Future.

The natural gas price sensitivity is used to evaluate the impact of rising natural gas prices on the performance of the Interregional Projects. The natural gas prices used were derived from an SPP 2015 ITP10 sensitivity.

The Sub-Regional Power Balance Constraint sensitivity is an attempt to replicate the power transfer limits and constraints between the two MISO sub-regions (North/Central and South) consistent with the operation of the current MISO Market. The effect of the SRPBC on MISO’s market dispatch is currently the subject of a dispute and settlement discussions between MISO and SPP. Pending the outcome of those discussions, it is unknown how this constraint will be utilized in the future, and this sensitivity is only meant to reflect one possibility which is consistent with how the MISO Market is currently being operated.

The SRPBC models the difference between generation and load in the MISO South Region with an adjustment for interchange transactions with the balancing authority areas connected to the MISO South sub-region. Additionally, the SRPBC is modeled to reflect the following market criteria:

• Hurdle rate of 9.57 $/MWh for transfers above 1000 MW • Maximum transfer limit of 2000 MW4

2 It is not a requirement that a project perform well in the sensitivities in order to be recommended to the RTOs. 3 The Sub-Regional Power Balance Constraint as used in this report refers to the 1000 MW contract path between Ameren, AECI, and Entergy. 4 This sensitivity was designed prior to increasing the Operational Reliability Coordination Agreement (ORCA) transfer limit to 3,000 MW which is the current limit.

6

6 Model Development

6.1 Economic Model Two economic models were built: a 2019 model and a 2024 model. As the CSP Study is focused on the 10th year of the study horizon, the 2024 model was the primary model used for issues evaluation, screening, and project development. The 2019 model was utilized for the 20-year financial analysis to extrapolate data points beyond the 2024 model year.

Both MISO and SPP utilize Ventyx’s PROMOD model in their respective regional planning processes for their economic evaluations. In a similar manner, PROMOD was used in the CSP Study. The PROMOD model was built starting with the base data provided by Ventyx. Ventyx creates and compiles this data from publicly available information and their proprietary sources and processes. In each RTO’s regional processes MISO and SPP then update the model with data specific to the MISO and SPP regions through their own respective stakeholder processes.

As a starting point for the CSP Study the applicable respective regional PROMOD models were merged. Data for the SPP region and for the Associated Electric Cooperatives, Inc. (AECI) region was pulled from the SPP regional PROMOD model. Data for the MISO region and all regions east of MISO was pulled from the MISO regional PROMOD model.

Modeling Footprint The joint CSP economic model footprint included: MISO, SPP, AECI, Manitoba Hydro, MRO, PJM, SERC, and TVA. The SPP footprint and balancing authority was modeled to include the Integrated System as a member of the SPP RTO5. Transmission Topology The transmission topology used in the 2019 and 2024 models was created using the latest MISO MTEP 15 and SPP 2015 ITP10 power flow models. Note that PJM, SERC, TVA, and Manitoba Hydro areas were based on 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 2015 ITP10 model. DC interconnections between the Eastern Interconnection and the Western Interconnection and ERCOT that are in-service used SPP’s profiles from the 2015 ITP10 models.

5 The Integrated System (IS) was included as a part of the SPP System. The IS is comprised of Western Area Power Administration Upper Great Plains Region (WAPA), Basin Electric Cooperatives (Basin), and Heartland Consumer Power District (Heartland). The IS members are joining SPP as transmission owning members in October 2015.

7

Load Forecasts The load forecasts for the MISO and SPP region were the forecasts used in the MISO MTEP 15 BAU Future and SPP 2015 ITP10 BAU Future. The load forecasts utilized reflect a 50/50 case. The load shape profiles are from the same year as the wind profiles to ensure synchronization. Demand response and energy efficiency was modeled consistent with how each planning region models it in their respective regional BAU Futures. Generation The existing resource mix came from the SPP 2015 ITP10 and MISO MTEP 15 models for their respective regions. Retirements were modeled based on each RTO’s BAU assumptions. New generation, including siting, came from each planning region’s current BAU resource expansion plan. The resource expansion plan was incorporated into the model using the same process as the rest of the modeling data. Data from the SPP 2015 ITP10 F1 was utilized for the SPP and AECI regions. All other data was sourced from the 2015 MISO MTEP.

The hourly profiles for renewables were developed using data from NREL and were time-synchronized with load shapes. The hourly profiles were based on data for 2005, except for the MISO South region and portions of SERC which used data from 2006. Fuel Prices Coal, oil, and uranium fuel prices were provided by Ventyx. After comparing the natural gas prices from the respective MISO and SPP BAU futures and noting that no significant difference exists between the two, the JPC agreed to use the natural gas prices from MISO’s MTEP 15 BAU future. Hurdle Rates The CSP study used the hurdle rates from MISO’s MTEP15 BAU future for the following areas: 1) where only MISO is interconnected (e.g., MISO-PJM, MISO-TVA, MISO-MHEB); and 2) AECI-TVA, TVA-PJM, PJM-SERC, SERC-TVA, SERC-AECI. MISO and SPP developed and agreed to the hurdle rates between MISO-SPP, MISO-AECI, and SPP-AECI. The specific values used for the hurdle rates in the study were provided to the IPSAC. Hurdle Dispatch Commit MISO to SPP $10.40 $13.12 SPP to MISO $7.02 $13.12 MISO to AECI $7.55 $10.00 AECI to MISO $30.00 $30.00 SPP to AECI $1.50 $10.00 AECI to SPP $30.00 $30.00 Stakeholder Review After staff concluded the initial efforts on developing the model, the consolidated economic model was provided to stakeholders for their review and suggested edits. These suggested edits were reviewed by

8

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.

6.2 Reliability Models A 2024 summer peak power flow model was built for the CSP reliability assessment. The model utilizes generation dispatch consistent with both MISO and SPP regional study processes. As a starting point the 2014 MISO MTEP power flow model was merged with the 2015 SPP ITP10 power flow model. The MTEP model provided the most current MISO topology and dispatch and the ITP10 model provided the same for the SPP footprint. The MISO footprint used a Local Balancing Authority (LBA) dispatch and includes all approved MTEP14 Appendix A projects. The SPP footprint used a Consolidated Balancing Authority – Security Constrained Economic Dispatch (CBA-SCED) and excluded all 2015 ITP10 projects approved in January 2015 by the SPP Board of Directors. The modeling footprint and transmission topology are consistent with what was described in Section 7.1 for the economic model. The following steps were taken to accomplish the merge of the MTEP and ITP power flow models:

• extracted SPP with ties from the MTEP model; • pulled SPP from the 2015 ITP10 model and applied it to the MTEP model; • applied SPP ties from the MTEP; and • verified MISO and SPP Interchange was unchanged.

Stakeholder Review After staff concluded the initial efforts on developing the model, the consolidated power flow model was provided to stakeholders for their review. Throughout the study the issues were refined to address modeling errors as they were identified.

6.2.1 Dynamics The dynamics assessment also included a jointly developed model consisting of the MISO MTEP14 model, the SPP 2015 MDWG model, and the 2013 MMWG series for the external footprint. The dynamics assessment was run using a 2019 light load case.

As a starting point, the 2014 MISO MTEP model was merged with the 2015 ITP10 reliability model in order to utilize the generation dispatch that is consistent with both MISO and SPP regional models. The MTEP model provided the most current MISO topology and dispatch and the ITP10 model provided the same for SPP.

6.3 Constraint Assessment The NERC book of flowgates was used as the initial source in the selection of the flowgates for use in the event file. MISO and SPP evaluated the additional flowgates used in the current MTEP and ITP10 studies and identified a mutually agreed upon list of constraints to use for the MISO-SPP CSP study.

9

7 Cost Estimates Cost estimates were developed utilizing the assumptions MISO and SPP respectively use in their regional planning processes. If the 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 17% for the Net Plant Carrying Charge Rate (NPCC) and approximately 8% for the Discount Rate. MISO applied the MISO region-wide average of 17.4% for the NPCC Rate and approximately 8% for the Discount Rate.

Two separate cost estimate methodologies were utilized. The first was for project screening. In the CSP these estimates are called the conceptual cost estimates. These estimates are derived by using generic data which is used by each RTO in their respective region. That data is compiled based on historical data for projects previously constructed in each region and stakeholder feedback. The second cost estimate is called the study estimate in the CSP. The study estimate was developed for those projects which are being considered by the JPC for recommendation as an Interregional Project. This estimate is expected to be a +/- 30% level estimate. MISO and SPP have their own processes for calculating this estimate. MISO utilizes their internal staff in the Transmission Developer Qualification Selection group to develop the study level estimate. SPP contracts with a consultant to develop the study level estimate.

8 Economic Evaluation

8.1 Issues Identification As previously stated, the JPC reviewed 34 transmission issues submitted by stakeholders for consideration to be included in this study scope. In addition to the submitted transmission issues, the JPC included in the study scope an evaluation to review economic congestion utilizing historical top congested flowgates from market reports and projected congestion resulting from the joint economic model developed for this study effort.

8.1.1 Historical Congestion Analysis The purpose of the historical congestion analysis is to identify congested flowgates based on current and past market activity. The historically congested flowgates were evaluated to determine whether similar congestion is occurring in the 2024 CSP Study economic model. If there is congestion on that flowgate in the model to a sufficient degree then it will be evaluated to determine if there is an efficient and cost effective interregional solution. If that historically congested flowgate does not show up in the 2024 CSP Study model, MISO and SPP staff will review to determine the reason.

8.1.2 Historical Congestion Analysis Results MISO and SPP reviewed the MISO and SPP market reports and identified flowgates along the MISO – SPP seam. The second column in the table below lists these flowgates. After identifying the applicable flowgates, MISO and SPP staff reviewed the CSP model to determine if the model reflected similar

10

congestion as to what is described in the respective market reports. The results are shown below. The column labeled “In CSP” demonstrates whether the flowgate from the market report is shown as being congested in the CSP model. If the flowgate is not congested in the CSP model staff, reviewed to determine the reason. That reason was included in the comment column.

RTO Seams Flowgate In CSP Comment SPP Pentagon to Mund (115 kV) No Congestion mitigated by SPP Approved Projects SPP Circleville - King Hill (115 kV) Yes N/A SPP Lake Road - Alabama (161 kV) No Congestion mitigated by SPP Approved Projects SPP S1226 - Tekamah (161 kV) Yes N/A SPP Eastowne Transformer No Congestion mitigated by SPP Approved Projects SPP Hayes - Vine (115 kV) Yes N/A SPP Iatan - Stranger (345 kV) Yes N/A

These results demonstrate that the seams flowgates that are described in the respective market reports as being congested are either shown as being congested in the CSP model or they are not congested in the CSP model because the congestion is expected to be mitigated by a previously approved planned project.

8.1.3 Projected Congestion Analysis The projected congestion analysis involves identifying the top congested flowgates based on the 2024 CSP Study model. The flowgates were ranked using the following indicators:

1. Binding Hours – number of hours in a year the flowgate is binding 2. Shadow Price – Reduced production cost for 1 MW increase of thermal rating on the flowgate 3. Congestion Costs – flowgate shadow price times MW flow on the flowgate

Issue Id

Constraint Name Contingency

M-1 Frederick Town AECI - Frederick Town AMMO 161 kV Lutesville - St Francois 345kV S-2 North East - Charlotte 161 kV Iatan – Stranger 345 kV M-5 Blue Earth - Winnebago 161kV Lakefield Junction - Lakefield 345kV M-6 Wapello 161/69 kV Transformer T1 Wapello 161/69 kV Transformer T2 M-9 Prairie 345/230kV Transformer T2 Prairie 345/230kV Transformer T1 M-10 Swartz - Alto 115kV Baxter Wilson - Perryville 500 kV M-11 Reed - Dumas 115kV Sterlington - El Dorado 500kV S-12 Essex - Idalia 161 kV Essex - New Madrid 345 kV M-13 Grimes – Mt Zion 138 kV Grimes – Ponderosa 230 kV S-14 South Shreveport – Wallace Lake 138 kV Dolet Hills 345/230 kV Transformer

11

8.2 Economic Transmission Solution Development The historical and projected congestion analysis, combined with the issues submitted by stakeholders, guided the development of transmission solution ideas that were evaluated as potential MISO-SPP Interregional Projects. The solution development and evaluation was focued on the set of identified congested flowgates that captures a majority of congestion costs (e.g., greater than 70%). Each respective RTO staff and stakeholders were able to propose transmission solutions to address the identified transmission issues. Solutions were solicited through the MISO-SPP IPSAC meetings. MISO and SPP staff solicited a request for stakeholders to submit potential projects addressing congestion identified in the issues list presented at the October7, 2014 IPSAC meeting. Stakeholders submitted a total of 39 projects addressing approximately 75% of the issues posted. In addition to stakeholder submissions, staff submitted 15 additional projects for consideration.

8.2.1 APC Methodology As stated in the MISO-SPP JOA, MISO and SPP agreed to jointly evaluate the benefits to the combined MISO-SPP region and to each region individually, using an agreed upon APC metric over a multi-year analysis. The APC is calculated for each simulated year and benefits for intermediate years between simulated years will be based on interpolation. Benefits for years beyond the last simulated year will be 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 LMP and then subtracting this value from the area’s production cost; and

• 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.

8.2.2 Screening Process A 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 consolidated transmission solution ideas and all transmission solution ideas which have potential value will be evaluated for APC benefits to MISO and SPP. If there were projects which appeared to be duplicates, only one of the projects was evaluated.

12

The screening index was calculated by using results of one model year 2024 of APC benefits compared to one model year 2024 costs. If the screening index was at least .5 and the project provided significant benefits to both MISO and SPP, the project was considered to have passed screening.

Projects passing the screening process include:

• St Francois – Fletcher 345 kV; • St Francois – Taum Sauk – Fletcher 345 kV; • Walker Tap – Rivtrin 138 kV; • Series Reactor on Alto – Swartz 115 kV; • S Shreveport – Wallace Lake 138 kV; • Elm Creek – Mark Moore 345 kV; and • Elm Creek NSUB 345 kV.

8.2.3 20-Year Benefit to Cost Calculation To calculate an indicative benefit to cost ratio for proposed transmission solutions, a 20-year net present value calculation of benefits and costs was used6. Benefits were calculated by the change in adjusted production cost with and without the proposed interregional project. The adjusted production cost was adjusted to account for purchases and sales. The APC benefit metric was calculated for the simulated years, 2019 and 2024. Benefits for intermediary years were calculated using interpolation and years beyond 2024 using extrapolation. The period covered by the benefit and cost calculation was 20 years starting with the project’s in-service year7. The annual costs were calculated using an average carrying cost of existing Transmission Owners in MISO and SPP. The present value calculation assumed an 8% discount rate. Table 1: Results of Benefit-to-Cost Analysis

Project Description NPV Project Cost (2015-M$)

B/C Ratio Benefit: MISO%

Benefit: SPP%

Walker Tap - Rivtrin 138kV $48.7 1.05 117% -17% St Francois - Fletcher 345kV $113 .51 88% 12% Elm Creek – Mark Moore 345kV $156.3* 1.03 7% 93% Elm Creek – NSUB 345kV $133.8* 1.22 20% 80% Series Reactor on Alto – Swartz 115kV $5.4* 4.32 86% 14% S Shreveport - Wallace Lake 138kV $17.7* 2.61 80% 20%

*Denotes study level cost estimates (+/- 30%)

6 There is not a B/C ratio requirement in the CSP study. 7 Initially MISO and SPP have made the assumption that the in-service date for all projects is 2024.

13

8.2.4 Top Performing Projects

8.2.4.1 Elm Creek – Mark Moore 345 kV The proposed Interregional Project Elm Creek – Mark Moore 345 kV is a new transmission project heading north from an Elm Creek 345 kV substation in North Central Kansas (Cloud County) to the current Mark Moore 345 kV in Southeastern Nebraska (Lancaster County) with a length of approximately 100 miles. The Elm Creek 345 kV substation is being built as a part of the SPP Elm Creek – Summit 345 kV project that was approved in the 2012 SPP ITP10. That project has an expected in-service date of 2018.

14

This project was proposed to relieve congestion on the Northeast to Charlotte 161 kV flowgate. MISO and SPP’s analysis shows that relieving the congestion on this flowgate provides benefit to both Parties. This project relieves 23%8 of the congestion on the Northeast to Charlotte 161 kV flowgate. The number of binding hours is reduced from 1,802 hours with the project to 1,307 with the project. However, in addition to the relief to the Northeast to Charlotte 161 kV flowgate, this project also addresses congestion on the Fairport – Osborn 230 kV which is a north-south flowgate east of the Kansas City area. Congestion on this flowgate is reduced by 29%. While the Gentleman – Red Willow 345 kV flowgate is a north-south flowgate geographically located in western Nebraska it is a flowgate that can constrain both the MISO and SPP markets. This flowgate is relieved by 10%. Additional congestion was relieved or mitigated throughout the combined system, primarily along the north-south corridor.

SPP estimated an engineering and construction (E&C) study-level cost estimate of approximately $164.4 million9 with an assumed in-service date of 2024. The $164.4 million E&C cost results in a 20-year present value of $156.3 million10. 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 $161.8 million11 in APC benefit resulting in a B/C ratio of 1.03. Of the $161.8 million of APC benefit, SPP is estimated to receive $150.4 million with MISO receiving $11.3 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.

8.2.4.2 Elm Creek – NSUB (Tap of Mark Moore - Pauline 345 kV) 345 kV The proposed Interregional Project Elm Creek – NSUB 345 kV is a new transmission project heading north from an Elm Creek 345 kV substation in North Central Kansas (Cloud County) to a new 345 kV substation that taps the existing Mark Moore – Pauline 345 kV line. This project has an estimated length of 78 miles. The Elm Creek 345 kV substation is being built as a part of the SPP Elm Creek – Summit 345 kV project that was approved in the 2012 SPP ITP10. That project has an expected in-service date of 2018.

8 This value is calculated by comparing the congestion scores with and without the project. The congestion score is calculated by multiplying the binding hours times the average shadow price. 9 2015 dollars 10 The 20-year present value cost number is calculated using SPP’s 17% NPCC, factoring in depreciation, and discounting at 8%. 11 The 20-year present value benefit number is calculate using a discount rate of 8%.

15

This project was proposed to relieve congestion on the Northeast to Charlotte 161 kV flowgate and is mutually exclusive of the Elm Creek - Mark Moore 345 kV project discussed above. MISO and SPP’s analysis shows that relieving the congestion on this flowgate provides benefit to both Parties. This project relieves 19%12 of the congestion on the Northeast to Charlotte 161 kV flowgate. The number of binding hours is reduced from 1,802 hours with the project to 1,413 with the project. However, in addition to the congestion relief to the Northeast to Charlotte 161 kV flowgate, this project also addresses congestion on the Fairport – Osborn 230 kV which is a north-south flowgate east of the Kansas City area. Congestion on this flowgate is reduced by 23%. While the Gentleman – Red Willow 345 kV flowgate is a north-south flowgate geographically located in western Nebraska it is a flowgate that can constrain both the MISO and SPP markets. This flowgate is relieved by 13%. Additional congestion was relieved or mitigated throughout the combined system, primarily along the north-south corridor. 12 This value is calculated by comparing the congestion scores with and without the project. The congestion score is calculated by multiplying the binding hours times the average shadow price.

16

SPP estimated an engineering and construction (E&C) cost estimate of approximately $140.6 million13 with an assumed in-service date of 2024. The $140.6 million E&C cost results in a 20-year present value of $133.8 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 $165 million15 in APC benefit resulting in a 20-year B/C ratio of 1.22. Of the $163.6 million of APC benefit SPP is estimated to receive $132 million with MISO receiving $33 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 1.22.

8.2.4.3 New Series Reactor on Alto – Swartz 115 kV The proposed Interregional Project New Series Reactor on Alto – Swartz 115 kV proposes to add a 10% reactor on 100 MVA base in series with the Alto-Swartz 115 kV line. The reactor is to be normally bypassed, and un-bypassed post-contingency for critical contingencies such as a loss of Baxter Wilson – Perryville 500 kV. The Alto-Swartz 115 kV line with which the reactor would be placed in series is located in North Central - Northwest Louisiana.

13 2015 dollars 14 The 20-year present value cost number is calculated using SPP’s 17% NPCC, factoring in depreciation, and discounting at 8%. 15 The 20-year present value benefit number is calculate using a discount rate of 8%.

17

This project was proposed to relieve congestion on the Swartz – Alto 115 kV flowgate. MISO and SPP’s analysis shows that relieving the congestion on this flowgate provides benefit to both MISO and SPP. This project completely mitigates the congestion on the Swartz – Alto 115 kV flowgate. Without the reactor this flowgate is projected to be binding 292 hours with an average shadow price of approximately $382. While the primary value from this project is addressing the congestion on Swartz – Alto 115 kV, additional congestion is mitigated on other flowgates though in a smaller magnitude.

MISO estimated an engineering and construction (E&C) cost estimate of approximately $5.3 million16 with an assumed in-service date of 2024. The $5.3 million E&C cost results in a 20-year present value of $5.4 million17. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the project life’s MISO and SPP are estimated to receive $23.4 million18 in APC benefit resulting in a 20-year B/C ratio of 4.32. Of the $23.4 million of APC benefit MISO is estimated to receive $20.1 million with SPP receiving $3.3 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 4.32.

8.2.4.4 S. Shreveport – Wallace Lake 138 kV Rebuild The proposed Interregional Project South Shreveport – Wallace Lake 138 kV rebuild proposes rebuilding the existing 11 mile South Shreveport to Wallace Lake 138 kV line with 1533.3 CSRT/TW conductor along with upgrades at the South Shreveport and Wallace Lake substations. The South Shreveport – Wallace Lake 138 kV line is located in Northwestern Louisiana.

16 2015 dollars 17 The 20-year present value cost number is calculated using MISO’s 17.4% NPCC, factoring in depreciation, and discounting at 8%. 18 The 20-year present value benefit number is calculate using a discount rate of 8%.

18

This project was proposed to relieve congestion on the South Shreveport – Wallace Lake 138 kV flowgate. MISO and SPP’s analysis shows that relieving the congestion on this flowgate provides benefit to both MISO and SPP. This project completely mitigates the congestion on the South Shreveport – Wallace Lake 138 kV flowgate. Without the rebuild this flowgate is projected to be binding 941 hours with an average shadow price of approximately $120. While the primary value from this project is addressing the congestion on the South Shreveport – Wallace Lake 138 kV, additional congestion is mitigated on other flowgates though in a smaller magnitude.

SPP estimated an engineering and construction (E&C) cost estimate of approximately $18.5 million19 with an assumed in-service date of 2024. The $18.5 million E&C cost results in a 20-year present value of

19 2015 dollars

19

$17.6 million20. 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 $46.1 million21 in APC benefit resulting in a 20-year B/C ratio of 2.61. Of the $46.1 million of APC benefit MISO is estimated to receive $36.8 million with SPP receiving $9.2 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 2.61.

8.2.5 Sensitivity Analysis Additional analyses were performed on projects being considered for recommendation by the JPC using the three sensitivities. The proposed interregional projects which are identified in the assessment utilizing the BAU Future will be evaluated using the three sensitivities to determine how the projects perform under these scenarios. After receiving input from stakeholders, the study scope included a high natural gas price, carbon price, and modeling of the Sub-Regional Power Balance Constraint as sensitivities. With input from the IPSAC, the JPC set the high natural gas price to $8.66/MMBtu for 2024 and the carbon price to $64/ton in 2024. The table below demonstrates the potential change in APC benefit for each project. These are the result of a one year analysis utilizing the 2024 model. As an example, the High Natural Gas Price Sensitivity indicates that the benefits attributed to the project Series Reactor on Alto – Swartz would increase by 43% if the gas price was set to $8.66/MMBtu.

Project Description % Change in APC Benefits (MISO and SPP combined)

High Natural Gas Price

Carbon Tax SRPBC

Series Reactor on Alto – Swartz 115kV +43% +37% +73% S Shreveport - Wallace Lake 138kV -79% -58% -39% New Elm Creek – Mark Moore 345kV +52% -62% -7% New Elm Creek – NSUB 345kV +54% -67% -7%

9 Reliability Assessment The reliability assessment in this scope included multiple studies. This multi-faceted approach has allowed MISO and SPP to evaluate various transmission issues near the MISO-SPP seam. The phases of the reliability assessment included in the CSP study are:

20 The 20-year present value cost number is calculated using MISO’s 17.4% NPCC, factoring in depreciation, and discounting at 8%. 21 The 20-year present value benefit number is calculate using a discount rate of 8%.

20

1. Review of reliability projects that were identified in the respective regional planning processes of MISO and SPP that are located near the seam to determine if there were interregional alternatives to the currently proposed transmission solutions that should be evaluated through the respective regional planning processes;

2. A steady state assessment was conducted using jointly developed power flow models consistent with reliability processes used by each region; and

3. A dynamics assessment to test system stability using a light load power flow case.

Solutions to address the identified reliability issues were developed and reviewed in coordination with the respective regional planning processes. These solutions, which may include alternative projects that more effectively mitigate identified issues, were submitted by:

1. respective RTO staff; 2. stakeholders through regional planning processes; and 3. stakeholders through MISO-SPP IPSAC meetings

Transmission solutions to address identified reliability issues were evaluated to determine the most efficient and cost-effective method to address the identified constraints. Projects addressing reliability issues were also evaluated for potential economic benefits to MISO and SPP. The projects identified as addressing the identified reliability issues were not found to provide substancial economic benefit to MISO or SPP in the context of this study scope.

9.1 Steady State Contingency Analysis An N-1 contingency analysis was conducted using the Study models described in Section 6.2. Topology details can be found in Section 6.1.

9.1.1 Issues Assessment Criteria used to determine the potential violations were as follows:

• Monitored • Facilities 100kV and above in the MISO and SPP footprints • Thermal Overloads over 100% • Base Case Voltages below .95pu • Contingency Voltages below .90pu • Or more stringent local planning criteria

• Contingencies • Full N-1 • MISO and SPP Category B contingencies submitted by stakeholders

The process that was followed to jointly develop the final issues list which was posted and made available for stakeholders was as follows:

21

• MISO and SPP performed separate contingency analyses and compared and verified that each other’s results were consistent;

• issues were reviewed on each respective transmission system; and • MISO and SPP used engineering judgement to filter out issues not electrically close to the seam.

MISO and SPP jointly performed separate base case (N-0) and contingency (N-1) analysis that provided a list of potential thermal and voltage violations. The results were compared and verified. Engineering judgment was used to filter out issues not electrically close to the seam. This initial issues list was provided to stakeholders along with a request for potential solutions to address the potential violations. After stakeholder feedback and additional validation was completed a final issues list was created. The table below summarizes the number of potential reliability issues. The map below is an overview of all the issues identified.

Needs Overall Unique MISO System

SPP System

Overloads 50 18 14 4 Low Voltages 84 34 31 3

Final Issues Map:

22

9.1.2 Reliability Assessment Solutions Development The issues list and reliability power flow model were made available to stakeholders. MISO and SPP requested stakeholders submit any potential solutions that could address any of the listed issues. Staff received 12 project submissions from four different study participants. In addition to stakeholder-submitted projects, MISO and SPP Staff leveraged previously identified regional projects from the MTEP and ITP processes, respectively. MISO and SPP analyzed these regional projects to determine if they addressed the issues identified in the CSP:

• SPP ITP Projects o Evaluated 1401 projects from 2015 ITP10 o Evaluated 531 projects from 2015 ITPNT

• MISO MTEP Projects o Reviewed 578 projects from Appendix B and Target Appendix A o Evaluated 8 projects from MTEP 15

In addition to all the projects listed above, staff also worked to create numerous potential solutions addressing the issues specific to this study. Additionally, staff evaluated all potential projects identified

23

in the economic portion of the CSP. The CSP economic projects were evaluated to see if they provided any reliability benefit in addition to the economic benefit.

9.1.3 Solution Evaluation MISO and SPP evaluated projects to determine:

• if benefit was provided to both MISO and SPP; • if thermal overloads were solved to under 100%; • if base case voltages were solved to within applicable planning criteria; • if contingency voltages were solved to within applicable planning criteria; and • if interregional solutions were more cost effective than MISO and SPP regional projects.

Two projects were highlighted throughout the process as being mutually beneficial to both MISO and SPP.

9.1.3.1 Fisher to Rodemacher 230 kV Fisher to Rodemacher is a proposed new 50 mile 230 kV line addressing issues identified in the study located in west Louisiana. The project addresses thermal overloads in both MISO and SPP. The conceptual cost of the project was estimated to be approximately $46M.

24

MISO and SPP determined this project was not cost effective as both RTO’s could address the overloads with regional projects for approximately $10M each.

9.1.3.2 Gobbler Knob – Datto 161 kV Gobbler Knob to Datto is a proposed new 20 mile 161 kV line addressing issues identified in the study located in northeast Arkansas. The project addresses both thermal overloads and low voltages on the MISO system. The project also addresses low voltages on the SPP transmission system, specifically on portions of Southwestern Power Administration (SPA). The conceptual cost of the project was estimated to be approximately $25M. The project potentially replaces $44M of regional upgrades on the MISO system and $3M of upgrades on the SPA system.

25

MISO and SPP determined the project will not be recommended as a part of the MISO-SPP CSP due to the limited participation of SPA in SPP’s planning region. However the project will continue to be evaluated in the MISO regional process as an alternative to the MISO Targeted Appendix A project Jim Hill to Datto rebuild. SPP will continue to work with SPA and will be available to provide any coordination needed between SPP and others regarding SPA’s interest in this project.

9.2 Dynamic Assessment The dynamics assessment utilized a joint model developed from MISO and SPP’s regional models. A 2019 light load case was developed in an effort to highlight seasonal transient instability issues most likely to occur. MISO and SPP selected areas to be monitored that were adjacent to the MISO-SPP seam. Monitored variables were generator rotor angles, transient voltage deviations, oscillation damping, out-of-step conditions, and any additional local planning criteria.

Disturbances for study were determined using POM-TS’s Fast Fault Screening (FFS) Tool. The POM-TS FFS takes a single set of contingencies (N-1) and determines a severity ranking index (RI) and a critical clearing time (CCT). The ranking index takes into account kinetic energy, torque, and voltage deviations to determine a score. A shorter clearing time and higher severity index score indicates a more severe

26

disturbance. Contingencies resulting in a CCT of less than 9 cycles to clear were chosen for further evaluation. There were 16 disturbances resulting in a CCT of less 9 cycles for clearing. MISO and SPP staff reviewed the 16 disturbances for validity and selected 4 for transient stability analysis in PSS/E.

Within PSS/E, a three-phase fault was modeled to analyze the system response due to the disturbances. Results of the three-phase fault were evaluated against criteria used in MISO and SPP’s regional processes.

9.3 Review of Regional Projects MISO and SPP staff reviewed projects from their respective regional processes. No projects were identified as replacing the need for a project in the other respective regional process. Additionally there were not any projects that it appeared could be replaced by a joint Interregional Project which would address the issues from both regions.

9.4 No-harm Test on Economic Projects Interregional projects identified to address congestion were evaluated to ensure they do not create reliability issues. The evaluation may result in the modification of the Interregional Project or identification of additional interregional facilities that are needed to mitigate the projected reliability issue. Staff utilized the 2024 joint power flow model used in the initial steady state assessment of this study to perform the no-harm analysis. Individual ACCC runs were completed for each economic project that had the potential to be recommended by the JPC. Below are the four projects that were tested:

• Elm Creek to Mark Moore; • Elm Creek to NSUB5; • Alto Series Reactor; and • South Shreveport to Wallace Lake.

Staff compared the issues list from the original steady state assessment against the issues list resulting from the ACCC assessments including each economic project. This was done to determine if any new reliability issues were created by each project. After the conclusion of the no-harm evaluation for the four economic projects considered it was determined that no new reliability issues were identified due to the inclusion of the economic projects and that no mitigations are needed.

• Elm Creek to Mark Moore 345 kV o No new issues identified

• Elm Creek to NSUB5 345 kV o No new issues identified

27

• Alto Series Reactor o No new issues identified

• South Shreveport to Wallace Lake 138 kV Rebuild o No new issues identified

In addition to running each of the tested projects individually, they were analyzed as a group and again no new reliability issues were identified due to the inclusion of the projects as a group.

10 Conclusions

10.1 Economic Based on the results of the economic assessment MISO and SPP identified three projects for consideration as Interregional Projects:

• Elm Creek to NSUB 345 kV; • Alto Series Reactor; and • South Shreveport – Wallace Lake 138 kV Rebuild.

Each of these projects individually demonstrate benefit to both MISO and SPP as well as APC benefits that exceed the costs of the projects over the initial 20 years of the project life.

Project 20-Year Cost (2015 -M$)

20-Year Benefit (2015 -M$)

B/C Ratio

Elm Creek - NSUB 345 kV $133.8 $165.0 1.22 Alto Series Reactor $5.4 $23.4 4.32 S. Shreveport - Wallace Lake Rebuild $17.60 46.1 2.62

These three projects recommended for consideration as an Interregional Project were evaluated to ensure the reliability of the transmission system was not negatively impacted. As discussed in Section 10.4 the evaluation of these projects did not identify any new reliability issues as a result of these projects. Additionally, staff evaluated the reliability of the transmission system if all three projects were constructed. The results were consistent with the analysis from reviewing each project individually. No additional potential reliability were identified.

MISO and SPP also analyzed these three projects as a group to ensure that the benefits do not significantly change as a result of all three being in-service. If all projects are assumed to be in service the total NPV Benefit of the projects is $214.6 million resulting in a B/C ratio of 1.44.

28

Project NPV Cost (2015 - M$)

NPV Benefit (2015 - M$)

B/C Ratio

Benefit: MISO%

Benefit: SPP%

Series Reactor on Alto - Swartz 5.4 23.4 4.32 86% 14% S. Shreveport – Wallace Lake Rebuild 10.1 46.1 4.56 80% 20%

Elm Creek - NSUB 345kV 133.8 162.4 1.21 20% 80% Combination 149 214.6 1.44 36% 64%

10.2 Reliability Based on the results of the study, MISO and SPP did not identify any joint transmission solutions for the sole purpose of reliability that are more cost effective or more efficient solutions than MISO and SPP regional solutions addressing regional reliability issues.

10.3 Interregional Cost Allocation MISO and SPP have agreed to use the APC benefit metric to allocate the costs of proposed Interregional Projects to each planning region for projects addressing economic congestion.

If the recommended Interregional Projects are approved by both the MISO and SPP Board of Directors as an Interregional Project, the cost allocation between MISO and SPP will be allocated per the chart below.

Table 2: Interregional Cost Allocation for Potential MISO-SPP Interregional Projects

Project E&C Cost M$

MISO Cost %

SPP Cost %

Elm Creek - NSUB 345 kV $133.8 20% 80% Alto Series Reactor $5.3 86% 14% S. Shreveport - Wallace Lake Rebuild $18.5 80% 20%

29

11 Joint Planning Committee and IPSAC Recommendation

12 Regional Review Process

12.1 Southwest Power Pool

12.1.1 Project Review Process

12.1.2 SPP Regional Cost Allocation

12.2 Midcontinent Independent System Operator

12.2.1 Project Review Process

12.2.2 MISO Regional Cost Allocation