MISO-SPP Coordinated System Plan Study Report

Transcription

1 MISO-SPP Coordinated System Plan Study Report June 30, 2015

2 Table of Contents 1 Executive Summary Introduction Stakeholder Involvement Third Party Coordination Scope Future Development Sensitivities Model Development Economic Model Reliability Models Dynamics Constraint Assessment Cost Estimates Economic Evaluation Issues Identification Historical Congestion Analysis Projected Congestion Analysis Economic Transmission Solution Development APC Methodology Screening Process Benefit-to-Cost Analysis Potential Interregional Projects for Recommendation Sensitivity Analysis Reliability Assessment Steady State Contingency Analysis Issues Assessment Reliability Assessment Solutions Development Solution Evaluation Dynamic Assessment Review of Regional Projects... 29

3 9.4 No-harm Test on Economic Projects Conclusions Economic Reliability Dynamics Interregional Cost Allocation IPSAC and Joint Planning Committee Recommendation IPSAC Recommendation Joint Planning Committee Recommendation Regional Review Process Southwest Power Pool Project Review Process SPP Regional Cost Allocation Midcontinent Independent System Operator Project Review Process MISO Regional Cost Allocation Appendix A Appendix B Table 1: MISO-SPP Coordinated System Plan Tasks... 4 Table 2: Regional Business as Usual Future Major Assumptions... 5 Table 3: MISO-SPP Coordinated System Plan Hurdle Rates... 8 Table 4: MISO-SPP Coordinated System Plan Economic Issues List Table 5: Results of Benefit-to-Cost Analysis Table 6: Sensitivity Analysis Results Table 7: Steady - State Thermal and Voltage Issues Table 8: Areas modeled in Dynamics Assessment Table 9: Results of Fast Fault Screen Table 10: Selected Disturbances Table 11: Combined Project Results Table 12: Interregional Cost Allocation for Potential MISO-SPP Interregional Projects Table 13: Congested Flowgate Analysis Table 14: MISO Congested Flowgate Analysis... 41

4 Figure 1: Elm Creek to Mark Moore 345 kv Project Figure 2: Elm Creek NSUB (Tap of Mark Moore - Pauline 345 kv) 345 kv Figure 3: New Series Reactor on Alto Swartz 115 kv Figure 4: S. Shreveport Wallace Lake 138 kv Rebuild Figure 5: Map of Steady - State Thermal and Voltage Issues Figure 6: Map of Fisher - Rodemacher 230 kv Project Figure 7: Map of Gobbler Knob - Datto 161 kv Project Figure 8: Rotor Angle Response Laramie River Figure 9: Voltage Response - Laramie River Figure 10: Rotor Angle Response Arkansas Nuclear One Figure 11: Voltage Response Arkansas Nuclear One Figure 12: Rotor Angle Response Turk Figure 13: Voltage Response Turk Figure 14: Rotor Angle Response Center Figure 15: Voltage Response Center... 40

5 1 Executive Summary The 2014 MISO-SPP Coordinated System Plan (CSP) was performed to evaluate the combined MISO & SPP transmission systems in an effort to identify mutually beneficial transmission improvements. The study was an 18-month effort that began in January MISO and SPP staff focused efforts on two primary sets of analyses - an economic evaluation and a reliability assessment. For the economic assessment, a 2024 joint model was built specifically for this study. SPP and MISO staff evaluated the congestion resulting from the 2024 model to identify a list of economic needs. Based on those needs, both staff and stakeholders collaborated to propose potential projects to solve the identified issues, which were then tested for Adjusted Production Cost (APC) and other benefits. Based on those results, SPP and MISO identified three projects for consideration as an Interregional Project: 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 SPP and MISO as well as APC benefit that exceeds the cost of the project over the initial 20 years of the project life. These projects were then recommended by MISO and SPP to the Interregional Planning Stakeholder Advisory Committee (IPSAC) for endorsement to move from the interregional portion of the study onto the regional review process. Both the MISO and SPP portion of the IPSAC endorsed the projects with no opposition. Based on that recommendation the Joint Planning Committee (JPC) voted in favor for approving all three projects for review in both the MISO and SPP regional processes. To accomplish the reliability assessment, a 2024 joint power flow model reflecting generation dispatch utilized in MISO and SPP s respective regional planning processes was built specifically for the reliability assessment. MISO and SPP staff also performed an ACCC assessment on the joint power flow model to determine a list of reliability needs. Similar to the economic assessment, those needs were reviewed by staff and stakeholders to develop potential projects addressing the issues. The projects that were tested were compared to MISO and SPP regional projects that also fixed the corresponding needs to determine if the potential Interregional Projects were more cost effective than the regional solutions. Based on the results of the study, SPP and MISO did not identify any Interregional Projects for the sole purpose of resolving reliability issues more cost effectively than MISO and SPP regional solutions. 2 Introduction The FERC-filed MISO-SPP Joint Operating Agreement (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

6 results of the study are accurate and meet the expectations of the JPC and IPSAC based on the study scope. The 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, in response to the RTO s request, 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 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. The draft report will be made available for stakeholder review. 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 the 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 South. The feedback from stakeholders at this meeting indicated that there was a strong consensus for moving forward with a CSP starting in Following the IPSAC, the JPC held a meeting where it was formally decided to perform a CSP starting in The schedule for the 2014 SPP-MISO CSP study would be no longer than 18 months and would be scheduled to conclude in June Stakeholder Involvement

7 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, 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. 3.1 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. (AECI), 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. 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.

8 4 Scope 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 requirements 1. 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: Table 1: MISO-SPP Coordinated System Plan Tasks 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 Historical and Projected Congestion Analysis Perform steady-state reliability assessment using jointly developed power flow models Test system stability using scenario(s) appropriate for studying dynamics. Solution Development Determine if there are interregional alternatives to proposed regional solutions Solution Evaluation and Evaluate potential 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.

9 Robustness Testing 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 CSP study future was a Business as Usual (BAU) Future, developed from the 2015 MISO Transmission Expansion Plan (MTEP15) and the 2015 SPP Integrated Transmission Plan 10-Year Assessment (ITP10) BAU Futures. 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 2: Regional Business as Usual Future Major Assumptions Regional BAU Futures Demand and Energy Growth Retirements Natural Gas Price (2014$) RPS (10-year incremental GW) MISO 0.8% 12.6 GW Coal $ GW wind/ 1.1 GW Solar SPP 1.3% < 1 GW Coal $ GW Wind/ 20.5 MW Solar CO₂ Price DSM (annual demand reduction in year 10 for EE/DR) None 6,000 GWh/ 12 MW None Embedded in Load

10 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 impacts on congestion between the two planning regions. 2 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 carbon price is applied to the model year 2024 in an effort to capture changes in generation dispatch and market economics assuming a carbon tax. 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 3. 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 sensitivity 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; and maximum transfer limit of 2000 MW 4. Sensitivities were used to further evaluate the potential Interregional Projects. 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. 5 2 The Sub-Regional Power Balance Constraint as used in this report refers to the 1000 MW contract path between Ameren, AECI, and Entergy. 3 FERC dockets Docket Nos. EL14-21, EL14-31, ER , EL This sensitivity was designed prior to increasing the Operational Reliability Coordination Agreement (ORCA) transfer limit to 3,000 MW which is the current limit. 5 It is not a requirement that a project perform well in the sensitivities in order to be recommended to the RTOs.

11 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 10 th 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 RTO 6. 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. Existing DC interconnections between the Eastern Interconnection and the Western Interconnection and ERCOT were modeled using profiles from SPP s 2015 ITP10 study. 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 6 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.

12 profiles are from the same year as the wind profiles to ensure synchronization. Demand response and energy efficiency were 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 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. Table 3: MISO-SPP Coordinated System Plan Hurdle Rates Hurdle Dispatch Commit MISO to SPP $7.55 $10.00 SPP to MISO $5.09 $10.00 MISO to AECI $7.55 $10.00 AECI to MISO $8.29 $10.00 SPP to AECI $1.50 $10.00 AECI to SPP $10.00 $10.00 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 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.

13 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 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.

14 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. While the actual values used in the cost estimates may vary between the RTOs, this is a reasonable assumption as 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 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 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. While MISO and SPP have their own processes for calculating this estimate, both RTOs target a cost estimate that is within +/-30%. 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 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 reviewed to determine the reason.

15 MISO and SPP reviewed the MISO and SPP market reports and identified flowgates along the MISO SPP seam. After identifying the applicable flowgates, MISO and SPP staff reviewed the CSP model to determine if the model reflected similar congestion as to what is described in the respective market reports. If the flowgate is not congested in the CSP model, staff reviewed to confirm that the issue was resolved through a MISO or SPP previously approved regional project. The results are shown in Appendix B. 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 Projected Congestion Analysis The projected congestion analysis involved 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 Table 4: MISO-SPP Coordinated System Plan Economic Issues List Issue Constraint Name Contingency Id 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 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 were focused on the set of identified congested flowgates that captured a majority of congestion costs (e.g., greater than 70%).

16 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 October 7, 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 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 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 were evaluated for APC benefits to MISO and SPP. If there were projects which appeared to be duplicates, only one of the projects was evaluated. 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;

17 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 Benefit-to-Cost Analysis To calculate an indicative benefit to cost ratio for proposed transmission solutions, a 20-year net present value calculation of benefits and costs was used 7. 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 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 year 8. 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 5: Results of Benefit-to-Cost Analysis Project Description NPV Project Cost (2015-M$) B/C Ratio Benefit: MISO% Benefit: SPP% Walker Tap - Rivtrin 138kV $ % -17% St Francois - Fletcher 345kV $ % 12% Elm Creek Mark Moore 345kV $156.3* % 93% Elm Creek NSUB 345kV $133.8* % 80% Series Reactor on Alto Swartz 115kV $5.4* % 14% S Shreveport - Wallace Lake 138kV $17.7* % 20% *Denotes study level cost estimates (+/- 30%) Potential Interregional Projects for Recommendation 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 There is not a B/C ratio requirement in the CSP study. 8 Initially MISO and SPP have made the assumption that the in-service date for all projects is 2024.

18 Figure 1: Elm Creek to Mark Moore 345 kv Project 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% 9 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. 9 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.

19 SPP estimated an engineering and construction (E&C) study-level cost estimate of approximately $164.4 million 10 with an assumed in-service date of The $164.4 million E&C cost results in a 20-year present value of $156.3 million 11. 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 million 12 in APC benefit resulting in a B/C ratio of 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 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 dollars 11 The 20-year present value cost number is calculated using SPP s 17% NPCC, factoring in depreciation, and discounting at 8%. 12 The 20-year present value benefit number is calculate using a discount rate of 8%.

20 Figure 2: Elm Creek NSUB (Tap of Mark Moore - Pauline 345 kv) 345 kv 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% 13 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. 13 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.

21 SPP estimated an engineering and construction (E&C) cost estimate of approximately $140.6 million 14 with an assumed in-service date of The $140.6 million E&C cost results in a 20-year present value of $133.8 million 15. 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 million 16 in APC benefit resulting in a 20-year B/C ratio of Of the $165 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 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. Figure 3: New Series Reactor on Alto Swartz 115 kv dollars 15 The 20-year present value cost number is calculated using SPP s 17% NPCC, factoring in depreciation, and discounting at 8%. 16 The 20-year present value benefit number is calculated using a discount rate of 8%.

22 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 million 17 with an assumed in-service date of The $5.3 million E&C cost results in a 20-year present value of $5.4 million 18. 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 million 19 in APC benefit resulting in a 20-year B/C ratio of 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 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 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 dollars 18 The 20-year present value cost number is calculated using MISO s 17.4% NPCC, factoring in depreciation, and discounting at 8%. 19 The 20-year present value benefit number is calculated using a discount rate of 8%.

23 Figure 4: S. Shreveport Wallace Lake 138 kv Rebuild This project was proposed to relieve congestion on the South Shreveport Wallace Lake 138 kv flowgate. MISO and SPP s analysis show 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 million 20 with an assumed in-service date of The $18.5 million E&C cost results in a 20-year present value of $17.6 million 21. MISO and SPP s 20-year benefit analysis shows that over the first 20 years of the dollars 21 The 20-year present value cost number is calculated using MISO s 17.4% NPCC, factoring in depreciation, and discounting at 8%.

24 project s life MISO and SPP are estimated to receive $46.1 million 22 in APC benefit resulting in a 20-year B/C ratio of 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 Sensitivity Analysis As previously described in Section 6, additional analyses were performed on projects being considered for recommendation by the JPC using the three sensitivities. The proposed Interregional Projects that are identified in the assessment utilizing the BAU Future were 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 The table below demonstrates the potential change in APC benefit for each project. These are the results of a one-year analysis utilizing the 2024 model. As an example, the High Natural Gas Price Sensitivity indicated 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. Table 6: Sensitivity Analysis Results % Change in APC Benefits (MISO and SPP combined) Project Description High Natural Gas Carbon Tax SRPBC Price 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: 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 22 The 20-year present value benefit number is calculated using a discount rate of 8%.

25 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: respective RTO staff; stakeholders through regional planning processes; and 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 substantial 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 Issues Assessment Criteria used to determine the potential violations were as follows: Monitored o Facilities 100kV and above in the MISO and SPP footprints o Thermal Overloads over 100% o Base Case Voltages below.95pu o Contingency Voltages below.90pu o Or more stringent local planning criteria Contingencies o Full N-1 o 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: MISO and SPP performed separate contingency analyses and compared and verified that each other s results were consistent;

26 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. Table 7: Steady - State Thermal and Voltage Issues Needs Overall Unique MISO System SPP System Overloads Low Voltages

27 Figure 5: Map of Steady - State Thermal and Voltage Issues 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 stakeholdersubmitted 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

28 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 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 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.

29 Figure 6: Map of Fisher - Rodemacher 230 kv Project 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 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 23. The project potentially replaces $44M of regional upgrades on the MISO system and $3M of upgrades on the SPA system. 23 This estimate is a conceptual level cost estimate which was proposed by a stakeholder. If this project was deemed to be a viable Interregional Project MISO and SPP would have developed a study level cost estimate which could change the cost estimate.

30 Figure 7: Map of Gobbler Knob - Datto 161 kv Project 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 as described in section of this report. 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 shown in Table 8: Areas modeled in Dynamics Assessment below.