Southwest Power Pool TRANSMISSION WORKING GROUP MEETING January 3, 2013 Net Conference. Summary of Action Items

Transcription

1 Southwest Power Pool TRANSMISSION WORKING GROUP MEETING January 3, 2013 Net Conference Summary of Action Items 1. Approved the 2013 ITPNT Report. 2. Approved the Voltage Security Study as indicative. Page 1 of 4 1 of 168

2 Southwest Power Pool TRANSMISSION WORKING GROUP MEETING January 3, 2013 Net Conference MINUTES Call to Order Administrative Items TWG Vice Chair Travis Hyde called the meeting to order at 11:19 a.m. following the conclusion of the joint ESWG-TWG meeting. The following members were in attendance: Scott Benson, Lincoln Electric System John Boshears, City Utilities of Springfield, MO Ronnie Frizzell, Arkansas Electric Cooperative Corp. John Fulton, Southwestern Public Service Co. Travis Hyde, Oklahoma Gas & Electric Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Jim McAvoy, Oklahoma Municipal Power Authority Matt McGee, American Electric Power Nathan McNeil, Midwest Energy, Inc. Alan Myers, ITC Great Plains John Payne, Kansas Electric Power Co. Jason Shook, GDS representing East Texas Electric Coop. Tim Smith, Western Farmers Electric Cooperative Mo Awad, Westar Energy, Inc., Noman Williams, Sunflower Electric Power Corporation Harold Wyble, Kansas City Power & Light The following stakeholders and staff were also in attendance: Jonathan Abebe, Clean Line Energy Roy Boyer, Southwestern Public Service Co. Bob Burner, Duke Energy Tom DeBaun, Kansas Corporation Commission Christin Domian, Mitsubishi Electric Steve Gaw, Wind Coalition Tony Gott, Associated Electric Cooperative, Inc. Kirk Hall, SPP Staff Jody Holland, SPP Staff Barry Huddleston, Clean Line Energy Rachel Hulett, SPP Staff Antoine Lucas, SPP Staff Bob Lux, SPP Staff Adam McKinnie, Missouri Public Service Commission Debbie Prater, Oklahoma Corporation Commission Katherine Prewitt, SPP Staff Jeff Rooker, SPP RE David Sargent, Southwestern Power Administration Wayman Smith, American Electric Power Al Tamimi, Sunflower Electric Power Corporation Page 2 of 4 2 of 168

3 Kyle Watson, Entergy Pat Wilkins, Tres Amigas, LLC Rachel Hulett, SPP staff, noted there was a quorum to begin the meeting. The TWG continued into the TWG only items on the meeting agenda (Attachment 1 Agenda). Agenda Item ITPNT Report Jody Holland summarized the changes made to the 2013 ITPNT report, including the re-evaluations, and also summarized additional pending changes not in the posted report. The members made several corrections to the report and appendices (Attachment ITPNT Report). Noman stated staff was seeking TWG approval on the report, a shift from endorsement in past years. TWG would then take this to MOPC for recommendation. TWG agreed to this concept. Alan Myers motioned to approve the 2013 ITPNT, which was seconded by Mo Awad. The motion was approved unanimously. TWG asked staff to send out the revised report after the meeting. Agenda Item 4 BPR Reviews BPR-033 NTC Re-evaluation Antoine Lucas, SPP staff, reviewed the NTC Re-evaluation Business Practice with the group. TWG discussed the need for two different criteria: 1) the second criterion which addresses if the project s inservice date is delayed beyond the need date; 2) the last criterion based on the project cost exceeding $20 million. TWG agree there does not need to be automatic re-evaluation for upgrades if they cannot meet the SPP need date. They also suggested changes to the $20 million cost based criterion in order to minimize risk on a re-evaluated project if the TO needs to move forward with the project during the automatic re-evaluation period. TWG asked the Project Cost Working Group to define project lead time, giving their suggestion that the definition is the time to get project energized from NTC issuance (Attachment 3a NTC Review Business Practice). BPR-021 ATP Antoine Lucas summarized the latest changes in the ATP Business Practice. The group discussed which, if any, models ATPs should be included in for internal SPP studies and for sharing with non-tariff entities. Currently staff plans to only include ATPs in SPP s GI and Aggregate Studies models based on the identified Need Date from ITP processes. They made revisions to the business practice (Attachment 3b ATP Business Practice). TWG tabled action on the business practice until the next meeting. TWG also asked staff to provide the original approved documentation of the ATP concept for the next discussion on this topic. Agenda Item 5 Voltage Security Study Jody Holland reviewed the Voltage Security Study assumptions and results. Staff is seeking TWG approval of this study as indicative (Attachments 4a,b Voltage Security Study Presentation and Report). Mo Awad motioned to approve the Voltage Security Study as indicative. Jason Shook seconded, and the motion passed unopposed. Page 3 of 4 3 of 168

4 Agenda Item 6 Teleconference schedule for 2013 Rachel Hulett shared the proposed schedule for conference calls in 2013 (Attachment Teleconferences). These calls would occur in months in which a face-to-face meeting is not held. Staff selected the calls be on the fourth Wednesday of the month from 9-11 a.m. unless noted. TWG asked staff to schedule proposed calls in The next call is January 23. Agenda Item 7 Closing The meeting was adjourned at 1:23 p.m. Respectfully Submitted, Rachel Hulett Secretary Page 4 of 4 4 of 168

5 Southwest Power Pool, Inc. ECONOMIC STUDIES WORKING GROUP MEETING TRANSMISION WORKING GROUP MEETING January 3, 2013 Net Conference AGENDA 9:00 a.m. - 11:00 a.m. 1. Probabilistic Planning Business Case (Action Item)... Antoine Lucas 2. SFOTF Report... Brett Hooton TWG Meeting only 11:00 a.m. - 1:00 p.m ITPNT Report (Action Item)... Staff 4. BPR Reviews... Antoine Lucas a. BPR-033 NTC Re-evaluation (Action Item) b. BPR-021 ATP (Action Item) 5. Voltage Security Study (Action Item)... Jody Holland 6. Teleconference schedule for Rachel Hulett Relationship-Based Member-Driven Independence Through Diversity Evolutionary vs. Revolutionary Reliability & Economics Inseparable 5 of 168

6 2013 Integrated Transmission Plan Near-Term Assessment Report January 15, 2013 Engineering 6 of 168

7 Southwest Power Pool, Inc. Revision History Revision History Date Author Change Description 9/11/2012 Staff Initial Draft 10/6/12 Staff Updated for October MOPC 12/12/12 Staff Updated for TWG Endorsement 12/18/12 Staff Updated for TWG Meeting on 12/19/12 12/20/12 Staff Added language for NTC Re-Evaluations 1/2/2013 Staff Added missing cost estimates to Appendix I and updated cost info in report 1/3/2012 TWG Unanimously endorsed by TWG and recommended MOPC endorsement ITPNT Assessment 7 of 168

8 Southwest Power Pool, Inc. Table of Contents Revision History...2 List of Figures...5 List of Tables...5 Executive Summary...6 Part I: Study Scope...8 Section 1: Introduction : ITPNT s Focus : Goals... 9 Section 2: Assumptions : Modeling Assumptions : Load Forecast : Criteria : Use of Transmission Operating Guides Part II: Analysis...12 Section 3: Study Process : Steady State Analysis : Rate Impacts : Stability Analysis : CBA Model Development : NTC Re-evaluation Process Part III: Study Results...21 Section 4: Study Results : Summary of Potential Steady State Upgrades : Project Plan Breakdown : Rate Impacts on Transmission Customers : Summary of Potential Stability Violations : CBA Results : NTC Re-Evaluation Results Section 5: Recommendation...53 Part IV: Appendices...55 Section 6: Appendices...56 Appendix I Upgrades for Board Approval ITPNT Assessment 8 of 168 3

9 Southwest Power Pool, Inc. Appendix II 2013 ITPNT Scope...59 Appendix III Generation Details...68 Appendix IV CBA Benchmarking...71 Appendix V 2013 ITPNT Stability Analysis ITPNT Assessment 9 of 168 4

10 Southwest Power Pool, Inc. List of Figures Figure ITPNT Project Plan Figure 2.1 History of Load Growth Figure 3.1 Load Areas for 2013 ITPNT Analysis Figure 4.1 Sub-Region 1 Figure 4.2 Sub-Region 2 Figure 4.3 Sub-Regions 3 Figure ITPNT Project Plan Breakdown Figure 4.5 Miles of New Line by Voltage Class Figure 4.6 Miles of Rebuild/Reconductor by Voltage Class Figure 4.7: Peak Year 2019 ATRR Impact by Pricing Zone Figure 4.8: 2013 ITPNT Monthly Bill Impact to a 1000 kwh/m Residential Customer Figure 4.9: Split between Regional and Zonal Cost Allocation of 2013 ITPNT Figure 4.10: Lynn County 69 kv Substation Figure 4.11: Halstead South 138/69 kv Transformer Figure 4.12: Afton 161/69 kv Transformer Figure 4.13: Auburn Road 230/115 kv Transformer Figure 4.14: Curry Bailey 115 kv line Figure 4.15: Kress Kiser Cox 115 kv line Figure 4.16: Ellsworth Bushton Rice 115 kv line Figure 4.17: Bowers Howard 115 kv line Figure 4.18: Haggard Ingalls 115 kv line Figure 4.19: Cedar Lake Interchange Sulphur Springs 115 kv line Figure 4.20: Lea County and Hobbs Substations Figure 4.21: Muleshoe East 69 kv Substation Figure 4.22: Stegall Scottsbluff Victory Hill 115 kv line Figure 4.23: Joplin, MO Area Figure 4.24: Pentagon 115 kv substation Figure 4.25: Wheatland 115 kv substation Figure ITPNT Project Plan List of Tables Table 3.1: 2012 Quarter 2 Re-evaluations Table 3.2: 2012 Quarter 3 Re-evaluations Table 3.3: 2012 Quarter 4 Re-evaluations Table 3.4: Cost Estimate Stage Definition Overview Table 3.5: 2012 CPE Bandwidth Violations Table 3.6: 2012 NPE Bandwidth Violations Table 4.1: Rate Impacts Table 4.2: Voltage Stability Results Table 4.3: CBA Comparison Results Table 4.4: NTC Re-Evaluation Recommendation 2013 ITPNT Assessment 10 of 168 5

11 Southwest Power Pool, Inc. Executive Summary Executive Summary This report documents analysis of the 2013 Integrated Transmission Planning Near-Term (ITPNT) Assessment. The ITPNT analyzes the SPP region s immediate transmission needs. The goals of the ITPNT are to not only preserve grid reliability, in compliance with NERC Reliability Standards and individual transmission owner planning requirements, but to also efficiently bridge SPP s 10-year and 20-year plans that meet public policy objectives and provide access to more economic energy sources. The ITPNT assesses: (a) regional upgrades required to maintain reliability in accordance with the NERC Reliability Standards and SPP Criteria in the near term horizon, (b) zonal upgrades required to maintain reliability in accordance with more stringent individual Transmission Owner planning criteria in the near term horizon, and (c) coordinated projects with neighboring Transmission Providers. SPP developed models for the 2013 ITPNT analysis based on the SPP Model Development Working Group (MDWG) models, for which transmission owners and balancing authorities provided generation dispatch and load information. The study scope approved by the TWG on May 9, 2012 contains: The years and seasons to be modeled, including 2013, 2014, and 2018 Treatment of upgrades in the models Scenario cases to be evaluated Description of the contingency analysis and monitored facilities Any new special conditions that are modeled or evaluated for the study including developing the 2018 summer peak model for CBA dispatch SPP performed reliability analyses identifying potential bulk power system problems. These findings were presented to Transmission Owners and stakeholders to solicit transmission solutions. Also considered were transmission options from other SPP studies, such as the Aggregate Study and Generation Interconnection processes. From the resulting list of potential solutions, staff identified the best regional solutions for potential reliability violations. Staff presented these solutions for member and stakeholder review at SPP s August 2012 planning summit. Through this process, SPP developed a draft list of 69 kv and above solutions necessary to ensure the reliability in the SPP region in the near-term. The 2013 ITPNT draft project plan includes 81 new upgrades (including 5 ATPs), 11 modified upgrades, and 22 withdrawn upgrades. The new upgrades include 146 miles of new line: 15 miles of 230 kv, 4 miles of 161 kv, and 50 miles of 138 kv, 69 miles of 115 kv, and 9 miles of 69 kv. The project plan also includes 188 miles of reconductor/re-build projects: 15 miles of 161 kv, 42 miles of 138 kv, 86 miles of 115 kv, and 45 miles 69 kv. Additionally, there are 16 new transformer upgrades. The total cost of the 2013 ITPNT Project Plan is estimated to be $773.6 million for upgrades that will receive an ATP, NTC, NTC-C, NTC Modify, or NTC-C Modify. Of that total, $655 million comes from new projects identified in the 2013 ITPNT Assessment. Upgrades recommended for an NTC Modify account for $118.6 million of the total project plan cost. $80.9 million of transmission upgrades are recommended for withdrawal. Figure 0.1 below shows a map of the SPP footprint with the 2013 ITPNT Project Plan marked on the map. Smaller maps with a better view of each individual project can be seen later in this report as well as the Appendices ITPNT Assessment 11 of 168 6

12 Southwest Power Pool, Inc. Executive Summary Figure 0.1: 2013 ITPNT Project Plan 2013 ITPNT Assessment 12 of 168 7

13 PART I: STUDY SCOPE 2013 ITPNT Assessment 13 of 168 8

14 Southwest Power Pool, Inc. Section 1: Introduction 1.1: ITPNT s Focus Section 1: Introduction The ITPNT evaluates the near-term reliability and robustness of the SPP transmission system, identifying needed upgrades through stakeholder collaboration. The ITPNT focuses primarily on solutions required to meet the reliability criteria defined in OATT Attachment O Section III.6. The ITPNT process coordinates the ITP20, ITP10, Aggregate Studies, and the Generation Interconnection transmission plans by communicating potential solutions between processes and using common solutions when appropriate. The 2013 ITPNT will create an effective near-term plan for the SPP footprint which identifies solutions to potential issues for system intact and (N-1) conditions using the following principles: Identifying potential reliability-based problems (NERC Reliability Standards TPL-001 and TPL- 002, SPP and local criteria) Utilizing Transmission Operating Guides Developing additional mitigation plans including transmission upgrades to meet the region s needs and maintain SPP and local reliability/planning standards Stability analysis is performed on the SPP system, including the proposed 2013 ITPNT upgrades. This analysis determines if there are voltage stability issues within high load areas inside the SPP footprint. The areas studied this year are Southwest Missouri, East Texas, and Southwestern Public Service Company. The ITPNT process is open and transparent, allowing for stakeholder input throughout. Study results are coordinated with other entities, such as Entergy, AECI, AECC, and the Midwest ISO and regions responsible for transmission assessment and planning. 1.2: Goals The 2013 ITPNT is intended to provide solutions to ensure the reliability of the transmission system during the study horizon which includes modeling of the transmission system for six years (i.e. 2018). This will provide enough lead time requirements such that NTC letters can be issued. The process is open and transparent, allowing for stakeholder input. Study results are coordinated with other entities and regions responsible for transmission assessment and planning ITPNT Assessment 14 of 168 9

15 Southwest Power Pool, Inc. Section 2: Assumptions 2.1: Modeling Assumptions Section 2: Assumptions The 2013 ITPNT load flow cases utilized for the study were developed from the SPP MDWG 2012 Build 1 series models. The study cases in this analysis were: 2013 light load and summer peak 2014 summer peak 2018 light load and summer peak The models topology reflected the current transmission system and the following transmission upgrades: SPP approved for construction upgrades (including all projects with NTCs, NTC-C, and projects approved for interconnection with an authorization to proceed), SPP Transmission Owners planned upgrades, upgrades from Entergy s Construction Plan, and AECI s 2011 transmission plan. To account for the confirmed long-term transmission service SPP develops two scenario models: the first scenario contains projected transmission transfers and generation dispatch on the system; the second scenario contains all confirmed long-term firm transmission service with its necessary generation dispatch. Existing generating resources are represented in the power flow models taking into account planned and current retirements. SPP developed separate models with generation based on EPA s 2011 Cross-State Air Pollution Rule (CSAPR) and 2012 Mercury and Air Toxics Standards (MATS). New generating resources included in the power flow models were limited to resources with a FERC filed Interconnection Agreement not on suspension or resources with an executed Service Agreement. Exceptions to these qualifications are addressed in the ITP Manual. 2.2: Load Forecast Load Serving Entities provided the load forecast used in the reliability analysis study models through the model building process ITPNT analysis models showed an annual growth of approximately 1% between summers 2013 through summer Overall forecasted growth rate for the 2013 ITPNT slowed compared to the 2009 and 2010 STEP and 2012 ITPNT forecasts. Figure 1 compares the load forecasts for the previous STEP and ITPNT assessments ITPNT Assessment 15 of

16 Southwest Power Pool, Inc. Section 2: Assumptions 2.3: Criteria Figure 2.1: History of Load Forecasts NERC Reliability TPL-001 and TPL-002 Standards, SPP Criteria, and local Transmission Owner planning criteria were utilized in this analysis, upholding the most stringent criteria. Projects needed for more stringent local Transmission Owner s planning criteria are identified as Zonal Reliability Upgrades. SPP Criteria is available on SPP.org > Engineering > Transmission Planning Transmission Owners planning criteria are available through SPP.org > Engineering > Transmission Planning > Local Area Planning and High Priority Studies 2.4: Use of Transmission Operating Guides Transmission Operating Guides (TOG) are tools used to mitigate violations in the daily management of the transmission grid. TOGs may be used as alternatives to planned projects and are tested annually to determine effectiveness in mitigating potential violations. The 2013 ITPNT identifies all solutions where the use of a TOG is not effective ITPNT Assessment 16 of

17 Southwest Power Pool, Inc. PART II: ANALYSIS 2013 ITPNT Assessment 17 of

18 Southwest Power Pool, Inc. Section 3: Study Process 3.1: Steady State Analysis Section 3: Study Process Facilities in the SPP footprint 69 kv and above were monitored for 95% thermal loading. All facilities in first-tier control areas were monitored at 100 kv and above. Non-contingency (base case) and N-1 contingency analysis on SPP facilities 69 kv and above and 100 kv and above for tier control areas were performed on the 2013 ITPNT models. After performing the reliability assessment identifying the bulk power problems, potential violations were presented and solutions requested to those transmission reliability problems from Transmission Owners and stakeholders. Utilizing stakeholders feedback and current Aggregate Studies and Generation Interconnection studies, proposed regional solutions were developed and validated. This process repeated for several iterations as solutions were refined. The solutions were then timed using linear interpolation based on line loading between available model years of 2013, 2014, and For example, to time a solution due to a 2018 potential overload, SPP interpolated line loadings between the 2014 and 2018 models to determine when the loading exceeded 100%. The need date was assigned based on this analysis. A similar process for timing potential voltage issues was used. Throughout the process, alternative solutions were proposed by stakeholders, which were analyzed in accordance with Section III.8 of Attachment O of the OATT. 3.2: Rate Impacts The SPP Open Access Transmission Tariff (OATT) requires that a Rate Impact Analysis be performed for each Integrated Transmission Plan (ITP) per Attachment O: Transmission Planning Process, Section III: Integrated Transmission Planning Process, Sub-Section 8): 8) Process to Analyze Transmission Alternatives for each Assessment: The following shall be performed, at the appropriate time in the respective planning cycle, for the 20-Year Assessment, 10-Year Assessment and Near Term Assessment studies: e) The analysis described above shall take into consideration the following: vi) The analysis shall assess the net impact of the transmission plan, developed in accordance with this Attachment O, on a typical residential customer within the SPP Region and on a $/kwh basis. The rate impact analysis process required to meet this 2013 ITPNT requirement was developed under the direction of the Regional State Committee in by the Rate Impact Task Force (RITF). The RITF developed a methodology that allocated costs to specific rate classes in each SPP Pricing Zone. The first step in this process is to estimate the Zonal cost allocation of the Annual Transmission Revenue Requirements (ATRR) for the ITPNT upgrades using the SPP Cost Allocation of ATRR Forecast (Forecast). The Forecast allocated 2013 ITPNT upgrade costs to the SPP Pricing Zones using the Highway/Byway ratemaking method. This method allocates costs to the individual Zones and to the Region based on the individual upgrade s voltage. Transformer costs were allocated based on the low 2013 ITPNT Assessment 18 of

19 Southwest Power Pool, Inc. Section 3: Study Process side voltage. Regional ATRRs are summed and allocated to the Zones based on their individual Load Ration Share percentages. The following inputs and assumptions were required to generate the Forecast: Initial investment of each upgrade o Total ITPNT investment modeled was $651 Million Transmission Owner s estimated individual annual carrying charge % o SPP Footprint averages ~16.5% per year Voltage level of each upgrade In-service year of each upgrade 2.5% annual straight line rate base depreciation Mid-year in-service convention 3.3: Stability Analysis Voltage stability was analyzed for eight significant load areas or pockets as part of the 2012 ITPNT Assessment. Stakeholder input was crucial in the load pockets suggested for analysis. These areas included: 1) Central Nebraska, 2) South Oklahoma, 3) West Arkansas, 4) SPS-Amarillo, 5) South Central Westar, 6) Northeast Westar, 7) Oklahoma City, and 8) Lincoln Omaha. During the 2013 ITPNT assessment stakeholders requested voltage stability analysis for some areas that were not studied in the 2012 ITPNT. The three load areas requested by stakeholders, shown below in Figure 3.1, for the 2013 ITPNT voltage stability analysis were: Area 1: Southwest Missouri Area 2: East Texas Area 3: Southwestern Public Service Company 2013 ITPNT Assessment 19 of

20 Southwest Power Pool, Inc. Section 3: Study Process Figure 3.1: Load Areas for 2013 ITPNT Analysis Contingencies used for the stability analysis were first created by determining the single worst generator unit outage within the load area. This identified generator outage was paired with all transmission line outages within the load area, except for the Southwest Missouri load pocket. Stakeholders specifically requested the entire Stateline plant to be paired with all transmission line outages. Pairing the largest generator outage with each transmission line outage causes the largest amount of voltage instability in the load pocket. Methodology to test the load pockets for voltage collapse began by increasing the amount of load within the load pocket. Simultaneously, a power transfer sending power from adjacent areas to the load pocket was simulated. The load and power transfer increased until voltage collapse occurs within the load pocket. This simulation was tested under system intact conditions as well as the previously identified contingency conditions on the 2013 ITPNT 2018 summer peak models. The simulation was run with 2013 ITPNT Assessment 20 of

21 Southwest Power Pool, Inc. Section 3: Study Process and without the 2013 ITPNT proposed upgrades included in the models to determine the difference in stability with and without the 2013 ITPNT portfolio. 3.4: CBA Model Development In order to account for the impacts of the Integrated Marketplace on the SPP footprint a Consolidated Balancing Authority (CBA) model was developed as part of the 2013 ITPNT Assessment. Once completed, the 2013 ITPNT contingency analysis was completed in order to find any new and/or solved thermal or voltage violations. Results can be found in Section 4.5 of this report. Development of the CBA model utilized the 2012 Flowgate Assessment, 2013 ITPNT transmission topology, and 2013 ITP20 economic dispatch data. The goal was to attain a security-constrained economic dispatch and unit commitment (SCED/SCUC) in the 2013 ITPNT 2018 summer peak scenario 0 EPA PSS/E model (AC model). Making use of the economic data from the 2013 ITP20, the CBA model dispatches the most economical power around the flowgates identified in the 2012 Flowgate Assessment. The security constrained economic dispatch in the CBA was only applied to the SPP footprint. The rest of the Eastern Interconnect remained unchanged. PROMOD Powerbase was updated to match the AC topology and load assumptions at the bus level. Load profiles and regional net interchange, including DC tie schedules, were held constant for the simulation to achieve the required generation output. Wind profiles were held constant at levels projected by the MDWG to avoid the uncertainty of hourly wind dispatch. The PROMOD Analysis Tool (PAT) was used to translate the dispatch profile obtained from a selected hour in PROMOD to the AC model. Utilizing the interchange provided in the AC model during PROMOD simulation allowed the translation of only generation output in the SPP footprint. No forced generator outages were utilized and area interchange was turned off allowing the system swing to adjust for minor changes in losses. 3.5: NTC Re-evaluation Process As part of the quarterly project tracking effort as specified in OATT Attachment O Section V.6 and Business Practices 7050 and 7060, SPP staff reviews the cost estimates provided by Transmission Owners (TOs) for all SPP Transmission Expansion Plan Network Upgrades approved by the SPP Board of Directors (BOD) and identifies each project with a cost estimate variance that exceeds the applicable thresholds set forth in Business Practices 7050 and SPP staff then requests from the designated TO additional information about the project to determine the cause(s) of the cost variance, along with other pertinent factors, such as percentage of construction complete. Using this information, SPP staff then makes a recommendation to the BOD as to whether the project should be re-evaluated to determine if the project is still warranted to fulfill a reliability need and/or to evaluate if the project could be adequately replaced with a more cost-effective alternative. Business Practice 7050 Applicable to projects issued a NTC prior to January 1, 2012, Business Practice 7050 directs SPP staff to review any project with a cost estimate greater than 20% than the previous quarter s cost estimate. Based on this criterion, SPP staff recommended to the BOD to re-evaluate three projects as a part of the 2013 ITPNT study process during The BOD approved all three recommendations and suspended the NTCs for all three projects until the re-evaluations were complete ITPNT Assessment 21 of

22 Southwest Power Pool, Inc Quarter 2 Section 3: Study Process During the 2nd quarter project tracking cycle of 2012, SPP staff made the recommendation to reevaluate the project with Project ID 1029 titled Lynn Co. Substation 115 kv Load Conversion. Project ID 1029 Project Owner Q Cost Estimate Q Cost Estimate Variance % Variance Lynn Co. Substation 115 kv SPS $100,000 $4,489,314 $4,389, % Load Conversion Table 3.1: 2012 Quarter 2 Re-evaluations SPP staff identified this project as a regional reliability solution in the 2010 ITP Near-Term Study, and was subsequently approved by the BOD in January SPP staff included the project in a NTC issued to Southwestern Public Service Company (SPS) on February 14, The original cost estimate for the project of $100,000 was listed on the NTC along with the following project scope description: Expand 115 kv bus at Lynn County Interchange to provide connection for new distribution transformer. Install 115/22.5 kv distribution transformer. SPS accepted the NTC on April 28, On March 9, 2012, SPS provided SPP staff with their project tracking updates for Quarter , including a new cost estimate for the Lynn Co. Substation project of $4,489,314. This was the first estimate for the project that was provided by SPS. SPS noted the reason for the cost variance is the substantial amount of work required to convert the substation to a breaker-and-a-half scheme. SPP staff was not aware the configuration change was required, and that work was not considered into the original estimate. SPS informed SPP that approximately $300,000 had been spent on the project to date. SPS estimated the date of completion for the project as December 31, 2013, and indicated a 12-month lead time was required for completion of the project Quarter 3 During the 3rd quarter project tracking cycle of 2012, SPP staff made the recommendation to re-evaluate the project with Project ID 534 titled Halstead South Transformer 138/69 kv. Project ID 534 Project Owner Q Cost Estimate Q Cost Estimate Variance % Variance Halstead South Transformer WR $1,875,000 $3,205,323 $1,330, % 138/69 kv Table 3.2: 2012 Quarter 3 Re-evaluations SPP staff identified this project as a regional reliability solution in the 2009 STEP and was subsequently approved by the BOD in January SPP staff included the project in a NTC issued to Westar Energy, Inc. (Westar) on February 9, The NTC indicated a need date of June 1, 2011, and listed the following project scope description and specification: 2013 ITPNT Assessment 22 of

23 Southwest Power Pool, Inc. Section 3: Study Process Replace Halstead South 138/69 kv transformer. Install the transformer for emergency rating 110 MVA. Westar accepted the NTC on April 16, On June 16, 2012, Westar provided SPP with their project tracking updates for Quarter , including a new cost estimate for the Halstead South project of $3,205,323. This indicated a 71% increase from the previously submitted cost estimate of $1,875,000. Westar noted the primary reason for the cost variance as additional work required at the Halstead South substation that was not known until a more detailed engineering review of the project was conducted. Westar estimated the date of completion for the project as June 1, 2014, and indicated a 24-month lead time was required for completion of the project. A mitigation plan for the project was previously provided by Westar and approved by SPP staff Quarter 4 As a result of the 4th quarter project tracking cycle of 2012, SPP staff made the recommendation to reevaluate the project with Project ID 393 titled Afton Transformer 161/69 kv. Project ID Project Owner Q Cost Estimate Q Cost Estimate Variance % Variance 393 Afton Transformer 161/69 kv GRDA $3,000,000 $8,020,000 $5,020, % Table 3.3: 2012 Quarter 4 Re-evaluations SPP staff identified this project as a regional reliability solution in the 2007 SPP Transmission Expansion Plan, which was subsequently approved by the BOD in January SPP staff included the project in NTC issued to Grand River Dam Authority (GRDA) on February 13, SPP staff issued GRDA a NTC with modifications to the project (NTC 20076) on February 8, 2010 moving the need date for the project from 6/1/2012 to 6/1/2010. The following project scope description and specification was listed on NTC 20076: Add second 161/69 kv transformer at Afton. Install the transformer for emergency rating 50 MVA. GRDA accepted NTC on March 10, On August 6, 2012, GRDA submitted to SPP staff an updated cost estimate of $8,020,000 for the Afton Transformer project. This indicated a % increase from the previously submitted cost estimate of $3,000,000. GRDA noted the reason for the cost variance is the substantial amount of work required to convert the substation to a breaker-and-a-half scheme that was not considered in previous estimates. GRDA informed SPP staff that approximately $720,000 had been spent on the project to date. GRDA estimated the date of completion for the project as August 1, 2013, and indicated a 24-month lead time 2013 ITPNT Assessment 23 of

24 Southwest Power Pool, Inc. Section 3: Study Process was required for completion of the project. A mitigation plan for the project was previously provided by GRDA and approved by SPP staff. Business Practice 7060 Applicable to projects issued a NTC on or after January 1, 2012, the Market and Operation Policy Committee approved Business Practice 7060 on March 27, The Business Practice commenced a cost estimation process defined by a tiered approach for project cost estimates based upon the level of project definition that is known. Table 3.4 below lists the cost estimate stage definitions. Estimate Name* Stage End Usage Precision Bandwidth Projects > 100 kv & > $20 Million All other BOD Approved Projects Conceptual 1 1 Study 2 2 NTC-C Project (CPE) NTC Project (NPE) NTC-C Issued NTC Issued 3 N/A New NTC Issued N/A 3 Concept screening for ITP20/ITP10 Study of feasibility and plan development for ITP10/ITPNT Final baseline (NTC-C)** Final baseline (NTC)** -50% to + 100% -30% to +30% -20% to +20% -20% to +20% Design & Construction 4 4 Design after NTC issued and build the project -20% to +20%*** * The Conceptual Estimate will be prepared by SPP. All subsequent estimates will be prepared by the DTO(s). **BOD approval required to reset the baseline. ***Actual cost is expected to be within +/-20% of final baseline estimate. Table 3.4: Cost Estimate Stage Definition Overview The precision bandwidths defined in Business Practice 7060 are used as guidelines for NTC review triggers. For a project that is issued a Notification to Construct with Conditions (NTC-C), an automatic review of the project is initiated if the ±20% precision bandwidth of the cost estimate that is received after NTC-C issuance, called the NTC-C Project Estimate (CPE), exceeds the ±30% bandwidth of the cost estimate previously submitted during the study phase of the project, titled the Study Estimate. CPE Bandwidth Violations In April 2012, SPP staff issued one NTC-C to Westar for the only project that met the NTC-C qualifications as a result of the 2012 ITPNT study. The CPE that was received for the project exceeded the variance bandwidth threshold, triggering an automatic re-evaluation to be done in the 2013 ITPNT study ITPNT Assessment 24 of

25 Southwest Power Pool, Inc. Section 3: Study Process Project ID Project Owner Study CPE Variance % Variance Auburn Road Transformer 230/115 kv WR $25,845,600 $29,507,894 $3,662, % NPE Bandwidth Violations Table 3.5: 2012 CPE Bandwidth Violations In addition to the one NTC-C, SPP staff issued NTCs for 39 projects as a result of the 2012 ITPNT study. In adherence to Business Practice 7060, TOs were asked to respond within 90 days with an updated cost estimate, called the NTC Project Estimate (NPE). Like the CPE, the level of accuracy of the NPE is expected to be such that final project cost will be within a ±20% bandwidth of the NPE. Although Business Practice 7060 does not explicitly define the same automatic NTC re-evaluation trigger for NPE bandwidth violations like the process for CPEs, SPP staff evaluated the 39 NPEs using the same business rules applicable to CPE bandwidth guidelines. Of the 39 projects issued NTCs, five were identified as having a lower NPE bandwidth, thus violating the lower Study Estimate bandwidth threshold. 13 projects were identified as having an upper NPE bandwidth exceed the upper Study Estimate bandwidth threshold. At its discretion, SPP staff selected eight of these projects to be re-evaluated as a part of the ITPNT study process based on factors such as the amount of cost increase and total cost estimate amount. Table 3.6 below lists the projects that were selected for re-evaluation. Project ID Project Owner Study NPE Variance % Variance 461 Curry - Bailey 115kV SPS $9,132,270 $35,099,588 $25,967, % 839 Kress Interchange - Kiser - Cox 115 kv SPS $20,188,805 $29,272,481 $9,083, % Ellsworth - Bushton - Rice 115 kv MKEC/MIDW $19,459,597 $27,485,183 $8,025, % 805 Bowers - Howard 115 kv SPS $17,407,520 $23,709,821 $6,302, % Haggard - Ingalls 115 kv Ckt 1 MKEC $12,530,103 $23,377,556 $10,847, % Cedar Lake Interchange 115 kv SPS $10,027,742 $13,224,520 $3,196, % Move lines from Lea Co. to Hobbs 230/115 kv SPS $8,270,297 $10,608,509 $2,338, % 836 Convert Muleshoe East 69 kv to 115 kv SPS $1,634,119 $4,673,759 $3,039, % Table 3.6: 2012 NPE Bandwidth Violations Section 4.5 of this report details the re-evaluation of each of the above projects as well as 4 additional projects which were re-evaluated at the request of the TO to whom the NTC was issued ITPNT Assessment 25 of

26 Southwest Power Pool, Inc. PART III: STUDY RESULTS 2013 ITPNT Assessment 26 of

27 Southwest Power Pool, Inc. Section 4: Study Results Section 4: Study Results 4.1: Summary of Potential Steady State Upgrades Based on the results of the contingency analysis, transmission upgrades were developed to mitigate potential reliability problems that were unable to be solved by mitigation plans or operating guides. A draft list of 100 kv+ solutions was presented at the 2012 August Planning Summit held at the new SPP Corporate Campus in Little Rock. The final 2013 ITPNT draft portfolio was presented at the 2012 December Planning Summit, also held in Little Rock. Each of the projects in the 2013 ITPNT Project Plan can be found in one of the 3 Sub-Region maps on the following pages. Following the Sub-Region maps is a description of each project ITPNT Assessment 27 of

28 Southwest Power Pool, Inc. Section 4: Study Results Sub-Region 1 Figure 4.1: Sub Region ITPNT Assessment 28 of

29 Southwest Power Pool, Inc. Section 4: Study Results A 2nd 345/115/13.8 kv transformer at Mingo is needed to address low voltages in the area. A new 10 mile 115 kv line from Pheasant Run Seguin and install necessary terminal equipment to address overloads in the area Rebuild 3.25 miles of 115 kv from Hays Plants South Hays to address overloads in the area Replace the 800 amp wave trap at Harper 138 kv Ckt 1 Rebuild the Gray County Haggard West Dodge 115 kv line to address overloads in the area Rebuild Ochiltree Tri-County Rec Cole 115 kv Ckt 1 to address the overloads in the area Convert 26 miles of Potter Co Channing from 115 kv to 230 kv and upgrade necessary terminal equipment at Potter to address voltage issues in the area Convert 35 miles of Channing Dallum County 115 kv to 230 kv tapping Channing Dallum into new XIT sub Install new 230/115/13.2 kv transformer at Dallam County to address voltage issues in the area Replace 230/115 kv transformer at Grapevine to address the overloads in the area Build new 38-mile 115 kv line from Bowers Interchange Howard and install necessary terminal equipment to address load growth in the area Install a 2 nd 115/69 kv transformer at Bowers to address load growth in the area Upgrade Deaf Smith 230/115 kv Ckt 2 transformer to address the overloads in the area Rebuild Crosby County Floyd County 115 kv Ckt 1 to address low voltage in the area Install MVAR capacitors at Floyd County Interchange 115 kv to address low voltage in the area Upgrade Crosby County 115/69 kv transformer Ckt 1 to address low voltage in the area Upgrade Crosby County 115/69 kv transformer Ckt 2 to address low voltage in the area Build new 15 mile 230 kv line from Carlisle Interchange Wolfforth Interchange to address overloads in the area Rebuild Allen Lubbock South Interchange 115 kv Ckt 1 to address overloads in the area Install a 2 nd 230/115/13.2 kv transformer at Lubbock South to address overloads in the area Upgrade wave trap at Jones and Lubbock South 230 kv bus to address overloads in the area 2013 ITPNT Assessment 29 of

30 Southwest Power Pool, Inc. Section 4: Study Results Rebuild Oxy Permian Sanger Switching Station 115 kv Ckt 1 to address overloads in the area Install 2 nd 345/230 kv transformer at Hitchland substation to address overloads in the area Upgrade the Grassland 230/115 kv transformer to address overloads in the area Upgrade the Graham 115/69 kv Ckt1 transformer to address overloads in the area Build new Kiser 115/69 kv substation with 115/69 kv transformer and install necessary 69 kv terminal equipment to address overloads and low voltage in the area Build new 22 mile 115 kv line from Kress Interchange to new Kiser 115/69 kv substation to address overloads and low voltage in the area Build new 8.7 mile 115 kv line from Cox Interchange to new Kiser 115/69 kv substation to address overloads and low voltage in the area. Build 2.2 miles of 115 kv from Zodiac 115 kv to South Portales 115 kv and install necessary terminal equipment to address overloads in the area Build 1.9 miles of 115 kv from S Portales to Market St 115 kv and install necessary terminal equipment to address overloads in the area Build 7 miles of 115 kv from Market St to Portales substation and install necessary terminal equipment to address overloads in the area Build a new 115 kv line from Atoka to Eagle Creek and install necessary terminal equipment to address low voltage in the area Upgrade the Eddy County Interchange 230/115 kv Ckt 1 transformer to address overloads in the area Upgrade the Chaves County Interchange 230/115 kv Ckt 2 transformer to address overloads in the area Upgrade Potash Junction 115/69 kv transformer Ckt 1 to address overloads in the area Upgrade Potash Junction 115/69 kv transformer Ckt 2 to address overloads in the area Install MVAR capacitors at Red Bluff 115 kv to address voltage issues in the area 2013 ITPNT Assessment 30 of

31 Southwest Power Pool, Inc. Section 4: Study Results Sub-Region 2 Figure 4.2: Sub Region ITPNT Assessment 31 of

32 Southwest Power Pool, Inc. Section 4: Study Results A new 115 kv capacitor bank at Cozad is needed to address low voltages in the area Increase line clearance on Sub 917- Sub kv Ckt 1 and replace terminal equipment to allow for a higher line rating Rebuild 915 tap in Ckt 623 Sub 915 T2 Primary 69 kv Add new kv substation and build 3.37 miles of 161 kv line tapping into line S1244-S kv line Replace Prairie Lee 161 kv wave trap Install a 5% series reactor at the St. Joseph bus for the Midway St. Joseph 161 kv line to address overloads in the area Build a new Geary County 345/115 kv substation with a 345 kv ring bus Install a 345/115 kv transformer and install necessary 115 kv terminal equipment at Geary County Build a new10 mile 115 kv line from Chapman Geary County along the Abilene Chapman 115 kv line to address voltage issues in the area Install 2 nd 138/115 kv transformer at Moundridge to address overloads in the area Install 3 rd 138/69 kv transformer at Gill Energy Center Build 28 miles of new 138 kv line from Gill Energy Center Viola Build 22 miles of new 138 kv line from Clearwater Viola Install 345/138 kv transformer at Viola station Install a 30 MVAR reactor at Hunter 345 k V for the Hunter Wichita 345 kv line to address high voltage in the area Rebuild the Cowskin Westlink 69 kv line to address overloads in the area Rebuild the Westlink Tyler 69 kv line to address overloads in the area Rebuild Tyler Hoover 69 kv and install necessary terminal equipment at Tyler to address overloads in the area Install 9.6 MVAR capacitor bank on the Potwin 69 kv bus to address voltage issues in the area Rebuild the Eastborough 64 th 69 kv line to address overloads in the area 2013 ITPNT Assessment 32 of

33 Southwest Power Pool, Inc. Section 4: Study Results Tear down and rebuild the El Paso Farber 138 kv line Install 345/115 kv transformer at Stegall Build new 22 mile 115 kv line from Stegall to Scottsbluff 2013 ITPNT Assessment 33 of

34 Southwest Power Pool, Inc. Section 4: Study Results Sub-Region 3 Figure 4.3: Sub Region ITPNT Assessment 34 of

35 Southwest Power Pool, Inc. Section 4: Study Results Install necessary terminal equipment at the Arcadia 345 kv substation to address overloads in the area Replace CTs and wave trap at Classen to address overloads in the area Install a 50 MVAR reactor at the Gracemont 345 kv substation to address high voltages in the area Install a 30 MVAR reactor at Tatonga 345 kv bus to address high voltages in the area Rebuild the Bluebell Prattville 138 kv line to address overloads in the area Rebuild 52 nd & Delaware Riverside Station 138 kv line and update relay settings at Riverside Station 138 kv bus to address overloads in the area Reconductor 5 Tribes Pecan Creek 161 kv line, increase CT ratios at Pecan Creek and 5 Tribes, and replace 2 wave traps, one breaker, and 3 switches at 5 Tribes 161 kv bus to address overloads in the area Rebuild Chamber Springs Farmington 161 kv and upgrade wavetraps, CT ratios, and relay settings at Chamber Springs to address overloads in the area Rebuild Midland-Midland REC 69 kv Ckt 1 and upgrade CT ratios, relay settings, switches, and station conductors at Midland to address overloads in the area Reconductor Northwest Henderson Poynter 69 kv line to address overloads in the area Rebuild Diana Perdue 138 kv line and install necessary terminal equipment to address overloads in the area Replace 138 kv breaker at Perdue substation to address overloads in the area Rebuild Forbing Tap Southwest Shreveport 69 kv line to address overloads in the area Rebuild Hardy Street Waterworks 69 kv line to address overloads in the area Rebuild Fern Street Broadmoor 69 kv line and install necessary terminal equipment at Fern Street to address overloads in the area Rebuild Midland REC-North Huntington 69 kv Ckt 1 and install necessary terminal equipment at North Huntington to address overloads in the area Rebuild Rock Hill-Springridge Pan-Harr REC 138 kv to address overloads in the area Rebuild DeKalb New Boston 69 kv line and install necessary terminal equipment upgrades at New Boston to address overloads in the area Rebuild Brownlee-North Market 69 kv line to address overloads in the area Rebuild State Line Midland 69 kv line and install necessary terminal equipment at Midland to address overloads in the area 2013 ITPNT Assessment 35 of

36 Southwest Power Pool, Inc. Section 4: Study Results Rebuild Evenside-Northwest Henderson 69kV line and install necessary terminal equipment at Evenside to address overloads in the area Rebuild Ellerbe Road Forbing Road 69 kv line to address overloads in the area Rebuild and convert 4 miles of 69 kv between OU Switchyard and Cole Substation to 138kV install terminal equipment in OU Switchyard to address voltage issues in the area Convert the 10.2 mile 69 kv Cole Criner line to 138 kv to address voltage issues in the area Convert Criner to the new Payne Switching Station from 69 kv to 138 kv and install necessary terminal equipment to address voltage issues in the area Tap the Paoli-Cornville Tap 138 kv and install switching station at Payne to address voltage issues in the area Increase line clearance Chelsea-Childers 69 kv to address overloads in the area Install new 500/230 kv transformer at Messick to address overloads in the area 2013 ITPNT Assessment 36 of

37 Southwest Power Pool, Inc. Section 4: Study Results 4.2: Project Plan Breakdown Figure 4.4 below shows a breakdown of the 2013 ITPNT Project Plan. There are 92 total proposed upgrades in the project plan, as well as 22 being withdrawn. Of the 90 proposed upgrades 76 will be issued new a Notice to Construct (NTC/NTC-C). 11 upgrades have been identified as needing a modified NTC (NTC Modify/NTC-C Modify). Based on the results of this assessment each of these upgrades is being accelerated. The 5 upgrades, which will receive an Authorization to Plan (ATP), are projects that have need dates which fall outside of the financial commitment window. Therefore, no NTC will be issued New Accelerated ATP Withdrawn Figure 4.4: 2013 ITPNT Project Plan Breakdown 2013 ITPNT Assessment 37 of

38 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.5 illustrates the amount of new line needed based on each voltage class in the 2013 ITPNT Project Plan. There are 147 miles of new transmission line in the project plan. As shown in the graph, most of the new transmission line will be built at the 138 kv and 115 kv voltage levels. 50 mi 69 mi 4 mi 15 mi 9 mi 230 kv 161 kv 138 kv 115 kv 69 kv Figure 4.5: Miles of New Line by Voltage Class 2013 ITPNT Assessment 38 of

39 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.6 illustrates the amount of transmission line that will require a rebuild or reconductor. There are 188 miles of rebuild/reconductor in the 2013 ITPNT Project Plan. The largest need of rebuild or reconductor lies at the 115 kv voltage level. However, only 15 miles of 161 kv line is needed. 45 mi 86 mi 15 mi 42 mi 161 kv 138 kv 115 kv 69 kv Figure 4.6: Miles Rebuild/Reconductor by Voltage Class 4.3: Rate Impacts on Transmission Customers The peak impact year, based on peak ATRR, was shown to be ITPNT Assessment 39 of

40 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.7: Peak Year 2019 ATRR Impact by Pricing Zone For additional information on estimating ATRR by zone please see: The peak year ATRR was then converted to an incremental impact to a typical 1000 kwh per month to each Zone s retail residential electric consumer s monthly electric bill. The rate impacts were solved by multiplying the peak year ATRR by each Zone s specific residential and retail allocation percentage(s). The allocated ATRR in 2019 was then divided by the forecast of annual sales in each specific Zone in 2019 to determine an incremental rate based on the ITPNT upgrades. The ATRR cost allocated first to the Zone then to the retail ratepayer in the zone was then multiplied by an assumed average consumption of 1000 kwh per month to determine the final rate impact shown here in $ per month: 2013 ITPNT Assessment 40 of

41 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.8: 2013 ITPNT Monthly Bill Impact to a 1000 kwh/m Residential Customer These results are shown in 2012 dollars; neither the effect of construction price inflation nor the discounting of future dollars was considered. The effect of depreciation may be seen in the years after As shown in the following chart, the voltage of the near term reliability upgrades tends to generate costs that will be allocated directly to the Zones where the upgrades will be built. These Zones also tended to have the highest rate impacts ITPNT Assessment 41 of

42 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.9: Split between Regional and Zonal Cost Allocation of 2013 ITPNT For additional information on how rate impacts are estimated please see: The Rate Impacts results shown in this section are incomplete at this time due to one missing cost estimate for which a conceptual estimate is used. Also a minor adjustment made to 3 other cost estimates, totaling less than $600K, has not been incorporated in these results. 4.4: Summary of Potential Stability Violations Based on the projected 2018 load levels, no voltage instability in the three load pockets was identified for the 2013 ITPNT upgrades. Results of the voltage stability analysis for the three load pockets can be found in Table ITPNT Assessment 42 of

43 Southwest Power Pool, Inc. Section 4: Study Results SW Missouri East Texas SPS Initial Load (MW): Voltage Collapse Load (MW): Security Limit (MW): Load Margin (MW/%): 1100/43% 90/28% 1020/16% 4.5: CBA Results Table 4.2: Load Pocket Analysis Results Following the 2013 ITPNT assessment assumptions, an issues list was developed from the CBA model. This was compared to the 2018 ITPNT Summer Peak EPA Scenario 0 model issues list to determine new and solved thermal overloads and voltage violations. The CBA model was analyzed through data comparison and performing contingency analysis. Negligible difference was found in the fuel type makeup of dispatched generation between the EPA and CBA scenario models, with most changes less than 1%. Following the 2013 ITPNT assessment assumptions, an issues list was developed from the CBA model. This was compared to the 2018 ITPNT summer peak EPA scenario 0 model issues list to determine new and solved thermal overloads and voltage violations. No upgrades were identified and placed in to the project plan for the 2013 ITPNT Assessment. Comparison results can be found in Table 4.3 on the following page ITPNT Assessment 43 of

44 Southwest Power Pool, Inc. Section 4: Study Results Total By Voltage Level (345/230/161/ 138/115/69 kv) % Increase or Decrease compared with 2018 summer peak Total % Change New Overloads 19 0/0/6/1/4/8 28.8% Increase 16.7% net increase in total overloads Solved Overloads 9 0/0/4/0/2/3 12.1% Decrease New Voltage Violations Solved Voltage Violations 40 0/1/5/2/9/ % Increase 58 10/1/0/0/23/24 Table 4.3: CBA Comparison Results 19.9% Decrease 5.4% net decrease in total voltage violations The TWG recommends that in addition to scenarios 0 and 5, an additional scenario for the CBA be included in the 2014 ITPNT Assessment for purposes of solution determination and project approval. 4.6: NTC Re-Evaluation Results Each of the projects listed in Section 3.5 were reevaluated to determine the most cost effective solution to mitigate the potential violations each upgrade or project initially intended to solve. Each reevaluation is found below with a recommendation and justification for the recommendation Lynn Co. Substation 115 kv Load Conversion NTC directed SPS to expand the 115 kv bus and install a 115/22.5 kv distribution transformer at Lynn County to address an overload at Lynn County as part of the 2010 STEP. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC ITPNT Assessment 44 of

45 Southwest Power Pool, Inc. Section 4: Study Results Halstead South 138/69 kv Transformer Figure 4.10: Lynn County 69 kv Substation NTC directed Westar to replace the Halstead South 138/69 kv transformer to address the overload of the existing transformer as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC. Figure 4.11: Halstead South 138/69 kv Transformer Afton 161/69 kv Transformer NTC directed Grand River Dam Authority (GRDA) to add a second 50 MVA 161/69 kv transformer at Afton to address additional loads in the area as part of the 2012 ITPNT. This reliability need was not identified as part of the 2013 ITPNT due to the additional loads not materializing. It was determined that this project was no longer needed in the 2013 ITPNT. Staff recommends the NTC be withdrawn as part of the 2013 ITPNT ITPNT Assessment 45 of

46 Southwest Power Pool, Inc. Section 4: Study Results Auburn Road 230/115 kv Transformer Figure 4.12: Afton 161/69 kv Transformer NTC directed Westar Energy, Inc. to install a 230/115 kv transformer at Auburn Road to address an overload of the Auburn Road transformer as part of the 2012 ITPNT. This NTC was issued with conditions (NTC-C) based upon the cost and voltage level. NTC also withdrew an NTC to install a 2 nd 230/115 kv transformer at Auburn Road because the 2 nd transformer would not fit in the existing Auburn Road substation. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends the conditions of the NTC be removed and baselining at the new cost estimate. Figure 4.13: Auburn Road 230/115 kv Transformer 2013 ITPNT Assessment 46 of

47 Southwest Power Pool, Inc. Section 4: Study Results Curry Bailey 115 kv NTC directed Southwestern Public Service Co. (SPS) to construct a 40 mile 115 kv line between Bailey County and Curry County to solve low voltages at the Bailey County 115 kv substation for system intact conditions as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT. An alternative of a 115 kv capacitor bank at Bailey County Interchange was evaluated as a possible solution. The capacitor bank did mitigate the low voltage issues, but did not provide any regional benefits. SPS provided additional justification in favor of the project discussing the loss of the existing single 115 kv source into Bailey County Interchange causing all 69 kv loads fed from Bailey County to become de-energized. Closing the normally open switches associated with the 69 kv circuits causes low voltage and overload conditions on the 69 kv bus and 115/69 autotransformer, thus the need for this project. Additionally, SPP staff has been informed of the possibility of tapping the new Bailey County Curry County 115 kv line and reconfiguring loads in the area by other members in the area though no request currently has been submitted as part of the Attachment AQ process. Staff recommends no change to the NTC and baselining at the new cost estimate. Figure 4.14: Curry Bailey 115 kv line Kress Interchange Kiser Cox 115 kv NTC directed Southwestern Public Service Co. (SPS) to build a new substation at Kiser and install a 115/69 kv transformer and 69 kv terminal equipment at the new substation instead of Plainview City as part of the Kress Interchange Kiser Cox 115 kv line as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC and baselining at the new cost estimate ITPNT Assessment 47 of

48 Southwest Power Pool, Inc. Section 4: Study Results Ellsworth Bushton Rice 115 kv Figure 4.15: Kress Kiser Cox 115 kv line NTC directed Midwest Energy and Mid-Kansas Electric Company to construct a 28 mile 115 kv line from Ellsworth Bushton Rice including the addition of a 3 breaker ring bus at Ellsworth Tap, to address multiple voltage violations in the area as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC and baselining at the new cost estimate ITPNT Assessment 48 of

49 Southwest Power Pool, Inc. Section 4: Study Results Bowers Howard 115 kv Figure 4.16: Ellsworth Bushton Rice 115 kv line NTC directed Southwestern Public Service Co. (SPS) to build a new 38 mile 115 kv line from Bowers Interchange Howard, install a second 115/69 kv transformer at Bowers, and convert the Bowers Interchange substation to a three breaker ring configuration to mitigate low voltage issues in the Bowers Interchange and Grapevine area as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution and requires acceleration to mitigate the potential reliability issues identified. This project also serves as a solution to added load delivery points submitted in an Attachment AQ request. Staff recommends issuing a modified NTC accelerating the need date and baselining at the new cost estimate ITPNT Assessment 49 of

50 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.17: Bowers Howard 115 kv line Haggard Ingalls 115 kv NTC directed Mid-Kansas Electric Company to build a 20.5 mile 115 kv line from Haggard to Ingalls to mitigate overloads in the area as part of the 2012 ITPNT. A reliability need in the area was determined to continue to exist in the Haggard area as part of the 2013 ITPNT. An alternative solution to rebuild the Haggard Gray County Tap West Dodge 115 kv line was analyzed. This solution was determined to mitigate the reliability need. The alternative solution is also determined to be a more cost effective solution. Staff recommends the NTC be withdrawn ITPNT Assessment 50 of

51 Southwest Power Pool, Inc. Section 4: Study Results Cedar Lake Interchange 115 kv Figure 4.18: Haggard Ingalls 115 kv line NTC directed SPS to build a new 12 mile 115 kv line from Sulphur Interchange to Cedar Lake Interchange and install a 115/69 kv transformer at Cedar Lake Interchange to address overloads in the Sulphar area as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC and baselining at the new cost estimate ITPNT Assessment 51 of

52 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.19: Cedar Lake Interchange Sulphur Springs 115 kv line Move lines from Lea Co. to Hobbs 230/115 kv NTC directed SPS to modify the Hobbs 230 kv bus to provide termination points from moving 230 kv lines from Lea County to Hobbs and install a new 230/115 kv transformer at Hobbs as part of the 2012 ITPNT. This project was driven by the migration of load from Cap Rock in to ERCOT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC and baselining at the new cost estimate ITPNT Assessment 52 of

53 Southwest Power Pool, Inc. Section 4: Study Results Convert Muleshoe East 69 kv to 115 kv Figure 4.20: Lea County and Hobbs Substations NTC directed SPS to tap the Bailey County Interchange Plant X 115 kv line and convert the Muleshoe East 69 kv substation to operate at 115 kv to address overloads in the Bailey County and Curry County area as part of the 2012 ITPNT. This need was determined to continue to exist in the 2013 ITPNT with the identified solution still considered the appropriate regional solution. Staff recommends no change to the NTC and baselining at the new cost estimate. Figure 4.21: Muleshoe East 69 kv Substation Stegall 345/230 kv Transformer NTC and NTC directed Nebraska Public Power District (NPPD) build 3.3 miles of 230 kv line from Stegall to Stegall Tap and install a 2nd parallel 345/230 transformer at Stegall as part of the 2012 ITPNT Assessment. This reliability need was determined to continue to exist in the 2013 ITPNT ITPNT Assessment 53 of

54 Southwest Power Pool, Inc. Section 4: Study Results NPPD is proposing an alternative project to replace these currently approved NTC Projects. The alternate project is a new Stegall 345/115 kv Transformer (400 MVA) and new 115 kv transmission lines from Stegall 115 kv (New sub) to Scottsbluff 115 kv (Existing NPPD Sub). The Stegall Scottsbluff 115 kv line would be approximately 22 miles with a minimum rating of 500 MVA. NPPD suggests that this new proposed project is a more cost effective alternative to the current 2nd Stegall 345/230 kv transformer & 230 kv line project. This project also mitigates the need for the upgrade of Victory Hill 230/115 kv transformer which has been identified in a recent Aggregate Study. This alternative project has been analyzed and was determined to be the better regional solution because it addresses additional critical contingencies in the area. SPP staff recommends issuance of a modified NTC to include Stegall 345/115 kv transformer and a 115 kv line from Stegall to Scottsbluff at an incremental cost increase of $6.9M over the existing NTC and the additional upgrade of the Victory Hill 230/115 transformer identified in the Aggregate Study. Figure 4.22: Stegall Scottsbluff Victory Hill 115 kv line Joplin Area Re-Evaluation Multiple NTCs have been issued to Empire District Electric around the Joplin area as part of SPP s regional reliability process. Load reductions in the Joplin area resulting from a tornado occurring in 2011 have reduced loads in the Joplin area in the 2013 ITPNT model set. The effects of reduced load in this area caused Empire District Electric to request a reevaluation of NTCs associated with the Joplin area. It was determined that these upgrades were no longer needed in the 2013 ITPNT. Staff recommends previous NTCs issued to Empire District Electric be withdrawn as part of the 2013 ITPNT. Each NTC is listed individually in Appendix I ITPNT Assessment 54 of

55 Southwest Power Pool, Inc. Section 4: Study Results Figure 4.23: Joplin Area Mund Pentagon 115 kv Line Terminal Upgrades NTC directed Westar Energy, Inc., to replace terminal equipment at the Pentagon 115 kv substation to address overloads in the area as part of the 2012 ITPNT Assessment. After Westar accepted the NTC, it was determined that the equipment at the Pentagon 115 kv substation was already rated at the minimum rating needed in the NTC. Based upon this finding, it was determined that this project was not needed as part of the 2012 ITPNT and Westar requested the NTC be withdrawn. Staff recommends the NTC be withdrawn as part of the 2013 ITPNT. Figure 4.24: Pentagon 115 kv substation 2013 ITPNT Assessment 55 of

56 Southwest Power Pool, Inc. Section 4: Study Results Wheatland 115 kv Capacitor Bank NTC directed Westar Energy, Inc., to install a 10.8 Mvar capacitor bank at the Wheatland 115 kv substation to address low voltages in the area as part of the 2012 ITPNT. Westar requested the NTC be re-evaluated as part of the 2013 ITPNT Assessment. It was determined that this project was no longer needed in the 2013 ITPNT. Staff recommends the NTC be withdrawn as part of the 2013 ITPNT. Figure 4.25: Wheatland 115 kv substation On the following page Table 4.4 summarizes the SPP staff recommendations for each re-evaluation completed as part of the 2013 ITPNT ITPNT Assessment 56 of

57 Southwest Power Pool, Inc. Section 4: Study Results Project Staff Recommendation Lynn County 115 kv Load Conversion No Change to NTC Halstead South 138/69 kv Transformer No Change to NTC Auburn 230/115 kv Transformer No Change to NTC Afton 161/69 kv Transformer Withdraw NTC Curry - Bailey 115kV No Change to NTC Kress Interchange - Kiser - Cox 115 kv No Change to NTC Ellsworth - Bushton - Rice 115 kv No Change to NTC Bowers - Howard 115 kv Accelerate Need Date Haggard - Ingalls 115 kv Ckt 1 Use Alternate Solution Cedar Lake Interchange 115 kv No Change to NTC Move lines from Lea Co. to Hobbs 230/115 kv No Change to NTC Convert Muleshoe East 69 kv to 115 kv No Change to NTC Stegall 345/230 kv Transformer Use Alternate Solution Joplin Area Re-Evaluations Withdraw NTC Mund Pentagon 115 kv Line Terminal Upgrades Withdraw NTC Wheatland 115 kv Capacitor Bank Withdraw NTC Table 4.4: NTC Re-Evaluation Recommendations 2013 ITPNT Assessment 57 of

58 Southwest Power Pool, Inc. Section 5: Recommendation Section 5:Recommendation Staff recommends the BOD approve Appendix I which is reflected in the map below ITPNT Assessment 58 of

59 Southwest Power Pool, Inc. Section 5: Recommendation Figure 5.1: 2013 ITPNT Project Plan 2013 ITPNT Assessment 59 of

60 Southwest Power Pool, Inc. Section 5: Recommendation PART IV: APPENDICES 2013 ITPNT Assessment 60 of

61 Southwest Power Pool, Inc. Section 6: Appendices Section 6: Appendices 2013 ITPNT Assessment 61 of

62 2013 Requested Board Action PID UID Facility Owner Project Description/Comments In-Service Date 2013 STEP Date Project Lead Time Cost Estimate Estimated Cost Source 2013 Project Type New and Modification NTC-C AEP Build Messick 500/230 kv substation. Connect to Mt Olive-Hartburg 500 kv and Carrol, Clarence, & Western Kraft 230 kv lines and install 500/230 kv 675 MVA transformer 12/31/2015 6/1/ months $50,000,000* AEP Regional Reliability Messick 500 kv / /675 NTC AEP Rebuild 0.3 miles of 666 ACSR with ACSR/TW. 6/1/2015 6/1/ months $1,221,505 AEP Regional Reliability FORBING TAP SOUTH SHREVEPORT 69KV /121 Rebuild Hardy Street-Waterworks 69 kv Ckt miles of 666 ACSR with NTC AEP ACSR/TW. Rebuild Midland-Midland REC 69 kv Ckt miles of 4/0 ACSR with /1/2015 6/1/ months $7,519,658 AEP Regional Reliability HARDY STREET WATERWORKS /121 NTC AEP ACSR/TW. Upgrade CT ratios, relay settings, switches, and station conductors at Midland. 6/1/2015 6/1/ months $5,653,353 AEP Regional Reliability MIDLAND MIDLAND REC /217 NTC - Modify AEP Reconductor 3.25-mile Northwest Henderson - Poynter 69 kv line with 1272 ACSR. 6/1/2014 6/1/ months $7,815,833 AEP Regional Reliability NORTHWEST HENDERSON 69KV POYNTER /143 NTC AEP Rebuild Brownlee-North Market 0.6 miles of ACSR and 4.1 miles of 666 ACSR with ACSR/TW. 6/1/2015 6/1/ months $12,424,849 AEP Regional Reliability BROWNLEE NORTH MARKET /143 NTC AEP Rebuild 2 miles of 266 ACSR with ACSR/TW and replace Fern Street Switches 6/1/2015 6/1/ months $4,923,124 AEP Regional Reliability BROADMOOR FERN STREET /94 NTC AEP Rebuild Dekalb-New Boston 69 kv Ckt miles of 4/0 ACSR with ACSR/TW. Upgrade CT ratios & relay settings at New Boston. 6/1/2015 6/1/ months $16,548,317 AEP Regional Reliability NEW BOSTON DEKALB /69 From Bus Number From Bus Name To Bus Number To Bus Name Circuit Voltages (kv) Miles of Reconduct or/rebuild Miles of New Miles of Voltage Conversion Rating NTC AEP Rebuild Midland REC-North Huntington 69 kv Ckt miles with ACSR/TW. Upgrade CT ratios, relay settings, and jumpers at North Huntington 6/1/2015 6/1/ months $1,829,026 AEP Regional Reliability MIDLAND REC NORTH HUNTINGTON 69KV /143 NTC AEP Rebuild 7.0 miles of 4/0 ACSR from state line to Midland with ACSR/TW. Upgrade CT ratios, relay settings, switches, and station conductors at Midland. Rebuild mile Diana to Perdue 138 kv line. Replace switches, jumpers, 6/1/2015 6/1/ months $9,145,130 AEP Regional Reliability HOWE INT MIDLAND /217 NTC - Modify AEP and upgrade CT ratios at Diana and Perdue substations. Upgrade relay settings at Diana substation. 6/1/2014 6/1/ months $18,805,489 AEP Regional Reliability PERDUE 138KV DIANA 138KV /478 NTC AEP Rebuild and reconductor 11.1 mile Chamber Springs-Farmington REC 161 kv line with ACSR/TW. Upgrade wave trap at Chamber Springs. 6/1/2015 6/1/ months $12,705,537 AEP Regional Reliability CHAMBER SPRINGS 161KV FARMINGTON AECC /360 NTC-C AEP Rebuild 5.4 miles of 556 ACSR with ACSR. Upgrade relay settings at Riverside Station Rebuild 9.0 mile Prattville-Bluebell 138 kv line from 795 ACSR to /1/2015 6/1/ months $24,992,196 AEP Regional Reliability ND & DELAWARE WEST TAP RIVERSIDE STATION 138KV /331 NTC AEP ACSR/TW. New summer ratings 287/287 limited by breaker, switches, CTs, wave trap. 6/1/2015 6/1/ months $10,241,314 AEP Regional Reliability BLUEBELL PRATTVILLE /287 NTC-C AEP Rebuild and upgrade conductor 27.6 miles Rock Hill-Springridge Pan-Harr REC 138 kv with ACSR/TW. 6/1/2016 6/1/ months $25,060,655 AEP Regional Reliability ROCK HILL SPRINGRIDGE PAN-HARR REC /376 NTC AEP Replace 138 kv breaker at Perdue 6/1/2016 6/1/ months $1,000,000 AEP Regional Reliability NEW GLADEWATER PERDUE 138KV /272 Rebuild Evenside-Northwest Henderson 69kV Ckt. 6.4 miles of 397 ACSR with NTC AEP ACSR/TW. Replace breaker at Evenside. 6/1/2018 6/1/ months $11,980,465 AEP Regional Reliability EVENSIDE NORTHWEST HENDERSON 69KV /96 Rebuild 2.0 miles Ellerbe Road 69 kv Ckt 1 to Forbing Road with NTC AEP ACSR/TW. 6/1/2018 6/1/ months $8,174,689 AEP Regional Reliability ELLERBE ROAD FORBING TAP /121 NTC GMO Install 6% series reactor on the Midway - St. Joseph 161 kv line. Reactor will be installed at the St. Joseph bus. 6/1/2014 6/1/2013 $440,733 GMO Regional Reliability ST Joe 161 KV MIDWAY 161 KV NTC GMO upgrade Prairie Lee wave trap to at least 1200 amps 6/1/ months $20,537 GMO Regional Reliability Blue Spring South 161 KV Prairie Lee 161 KV /259 NTC GRDA Increase line clearance Chelsea-Childers 69 kv Ckt 1 6/1/ months $334,400 GRDA Zonal Reliability CHELSEA CHILDERS /56 ATP GRDA Replace 161kV,1200A switch with a 2000A Switch at Kerr Substation bus. 6/1/ months $161,100 GRDA Regional Reliability SUB KERR /432 ATP GRDA Replace 161kV, 1200A switch with a 2000A switch at Kansas Tap Substation. 6/1/ months $161,100 GRDA Regional Reliability SUB KANSAS TAP /432 ATP GRDA Increase line clearance Okay-Unarco 69 kv Ckt 1 6/1/ months $150,700 GRDA Zonal Reliability OKAY UNARCO /108 NTC MIDW Rebuild 3.25 miles of 115 kv from Hays Plant to South Hays 6/1/ months $4,734,006 Regional Reliability HAYS PLANT 115 KV SOUTH HAYS 115 KV /199 Build new 10 mile 115 kv line from Pheasant Run - Seguin and install new NTC MIDW terminal equipment at Pheasant Run and Seguin 6/1/2014 6/1/ months $10,794,325 MIDW Regional Reliability PHEASANT RUN 115 KV /199 NTC MKEC Replace wave trap at Harper substation. 12/31/2013 4/1/ months $385,244 MKEC Regional Reliability Harper 138 KV Milan Tap 138 KV /110 NTC NPPD 18 Mvar 115 KV CAP BANK AT COZAD 6/1/2014 6/1/ months $677,370 NPPD Regional Reliability Cozad Mvar Build new substation with new Stegall substion with a 345/115 kv 400 MVA $11,500,000 NTC-C NPPD Stegal transformer 6/1/ months NPPD Regional Reliability STEGALL Stegall 115 kv 1 345/ /440 Install a new 22 miles of 115 kv from Stegal-Scottsbluff and install necessary $18,800,000 NTC-C NPPD terminal equipment 6/1/ months NPPD Regional Reliability Stegall 115 kv Scottsbluff /440 Install a 30 Mvar reactor at the Tatonga 345 kv bus on the Tatonga - NTC OGE Woodward District 345 kv line 4/1/2013 4/1/ months $3,500,452 OGE Regional Reliability Tatonga 345kv Woodward EHV 345kv NTC OGE Replace 800 amp CT and wave trap at Classen substation. 6/1/2013 6/1/ months $161,204 OGE Regional Reliability CLASSEN SW 5TAP /287 NTC OGE Upgrade 345 kv 2000 amp breakers and associated switches to 3000 amp at Arcadia Sub. This will give Arcadia - Redbud 345 kv Ckt1 and Ckt2 a summer emergency rating of 1426 and a Summer Normal rating of Reconductor 4.07 miles of 161 kv. Increase CT ratios at Pecan Creek to 2000A. 6/1/2013 6/1/ months $1,010,523 OGE Regional Reliability ARCADIA REDBUD /1426 NTC OGE Replace 2 wave traps, 1-161kV breaker, 3 switches at Five Tribes plus increase CTR. 12/1/2013 6/1/ months $2,591,900 OGE Regional Reliability PECAN CREEK TRIBES /542 NTC OGE Install a 50 MVAR reactor at Gracemont 345 kv bus 4/1/2015 4/1/ months $3,500,452 OGE Regional Reliability Gracemont 345kv 345 NTC OGE Install a 30 Mvar reactor at Hunter 345 kv for the Hunter - Wichita 345 kv line Add a new 161 kv substation and shift the load from two of our 69 kv subs 4/1/2016 4/1/ months $3,500,452 OGE Regional Reliability (Subs 904 & 915) to the new 161 kv sub. Install 3.37 miles of 161 kv taping into NTC OPPD line S1244-S kv line 6/1/2013 6/1/ months $11,067,000 OPPD Regional Reliability SUB kV NTC OPPD Rebuild 915 tap in Ckt 623-Sub 915 T2 Primary 69 kv Ckt 6/1/2015 6/1/ months $260,590 OPPD Regional Reliability Tap in Ckt Sub 915 T2 Primary /65 NTC OPPD Increase line clearances to allow the use of a higher conductor rating and replacing some terminal equipment 6/1/2018 6/1/ months $475,340 OPPD Regional Reliability Sub Sub /89 NTC MKEC Rebuild the Haggard - Gray County Tap - West Dodge 115 kv line 4/1/2013 $10,485,402 SEPC Regional Reliability /248.8 NTC SEPC Install a 2nd 3 winding 345/115/13.8 kv at Mingo 6/1/2015 6/1/ months $12,116,815 SEPC Regional Reliability MINGO MINGO 2 345/ /280 NTC SPS Upgrade Graham 115/69 kv transformer Ckt 1 (84 MVA) 12/31/2014 6/1/2013 $2,356,320 SPS Regional Reliability Graham Interchange 69 kv Graham Interchange 115 kv 1 115/69 84/84 NTC SPS Install two 14.4 MVAR 115 kv capacitors at Red Bluff substation. 6/1/2013 6/1/ months $2,791,331 SPS Regional Reliability Red Bluff 115 kv 115 two 14.4 MVAR capacitor bank NTC SPS Install two 14.4 MVA capacitors 6/1/ months $2,356,579 SPS Regional Reliability Floyd County Interchange 115 kv 115 Two 14.4 Mvar total 28 MVAR NTC SPS Upgrade Chaves 230/115 kv to 225/258 MVA. 6/1/2020 6/1/ months $3,644,914 SPS Regional Reliability Chaves County Interchange 230 kv Chaves County Interchange 115 kv 2 230/ /250 NTC - Modify SPS Install second 115/69 kv transformer at Bowers. 6/1/2016 6/1/ months $2,980,329 SPS Regional Reliability Bowers Interchange 115 kv Bowers Interchange 69 kv 2 115/69 84/96 NTC - Modify SPS Upgrade Grassland 230/115 kv transformer Ckt 1 to a 250 MVA. 6/1/2015 6/1/ months $3,914,401 SPS Regional Reliability Grassland Interchange 230 kv Grassland Interchange 115 kv 1 230/ /250 NTC SPS Upgrades Crosby County 116/69 kv transformer No. 1 to 84 MVA 6/1/2015 6/1/ months $2,357,062 SPS Regional Reliability Crosby County Interchange 115 kv Crosby County Interchange 69 kv 1 115/69 84/84 NTC SPS Upgrades Crosby County 116/69 kv transformer No. 2 to 84/96 MVA 6/1/2015 6/1/ months $2,381,597 SPS Regional Reliability Crosby County Interchange 115 kv Crosby County Interchange 69 kv 2 115/69 84/84 NTC SPS Install a second 230/115/13.2 kv transformer at Lubbock South. 12/31/2014 6/1/ months $5,179,953 SPS Regional Reliability Lubbock South Interchange 230 kv Lubbock South Interchange 115 kv 2 230/ /250 NTC SPS Upgrade Deaf Smith Interchange 230/115 kv transformer ckt 2 to 250 MVA 3/1/2015 6/1/ months $4,273,633 SPS Regional Reliability Deaf Smith County Interchange 230 kv Deaf Smith County Interchange 115 kv /259 NTC SPS Rebuild 16.9 miles Ochiltree-TRI-County Rec Cole 115 kv ckt 1 12/31/2014 6/1/ months $12,840,220 SPS Regional Reliability Ochilltree Interchange 115 kv Cole Interchange 115 kv /273 NTC SPS Rebuild 28 miles 115 kv Crosby-Floyd ckt 1 6/1/ months $19,997,019 SPS Regional Reliability Crosby County Interchange 115 kv Floyd County Interchange 115 kv /273 NTC SPS Upgrade Potash Junction 115/69 kv Ckt transformer to 84 MVA 6/1/ months $2,144,733 SPS Regional Reliability Potash Junction Interchange 115 kv Potash Junction Interchange 69 kv 1 115/69 84/84 NTC SPS Upgrade Potash Junction 115/69 kv transformer Ckt 2 to 84 MVA 6/1/ months $2,148,879 SPS Regional Reliability Potash Junction Interchange 115 kv Potash Junction Interchange 69 kv 115/69 84/84 62 of 168

63 NTC - Modify SPS Build new 22-mile Kress Interchange - Kiser 115 kv. 11/30/2014 6/1/ months $13,856,881 SPS Regional Reliability Kress Interchange 115 kv Kiser Sub 115 kv /173 NTC - Modify SPS Build new 8.7-mile Cox - Kiser 115 kv line. 2/28/2014 6/1/ months $5,848,405 SPS Regional Reliability Cox Interchange 115 kv Kiser Sub 115 kv /173 NTC - Modify SPS Build new Kiser substation. Install a 115/69 kv transformer and 69 kv terminal equipment to connect to the local 69 kv system. Build new 38-mile 115 kv line from Bowers Interchange - Howard. At Bowers, 2/28/2014 6/1/ months $6,500,705 SPS Regional Reliability Kiser Sub 115 kv Kiser Sub 69 kv 1 115/ /97 NTC - Modify SPS install 115 kv breaker positions to serve the new transmission line, converting to a three-breaker ring configuration. 5/31/2014 6/1/ months $22,577,591 SPS Regional Reliability Bowers Interchange 115 kv Howard 115 kv /199 Convert 26 miles Channing - Potter 115 kv to 230 kv, upgrade terminal NTC SPS equipment at Potter. 12/31/2015 6/1/ months $2,115,794 SPS Regional Reliability Channing 230 kv Potter County Interchange 230 kv /541 NTC SPS Convert 35 miles Channing - Dallam 115 kv to 230 kv. Tapping Channing - Dallam 230/115 kv into new XIT sub. 12/31/2015 6/1/ months $12,509,767 SPS Regional Reliability Channing 230 kv Dallam 230 kv /541 NTC SPS Install 230/115/13.2 kv Transformer at Dallam County Jr. (XIT) Sub. 12/31/2015 6/1/ months $4,293,268 SPS Regional Reliability Dallam 230 kv Dallam County Interchange 115 kv 1 230/ /168 NTC - Modify SPS Install a second 345/230 kv transformer at Hitchland substation. 6/30/2014 6/1/2013 $12,715,142 SPS High Priority Hitchland Interchange 345 kv Hitchland Interchange 230 kv 2 345/ /560 NTC SPS Rebuild 6 miles of 115 kv line from Lubbock South Interchange to Allen 6/1/2017 6/1/ months $10,946,449 SPS Regional Reliability Lubbock South Interchange 115 kv Allen Sub 115 kv /300 NTC SPS Replace 230/115 kv transformer at Grapevine substation with 250 MVA transformer. 12/1/2015 6/1/ months $4,249,540 SPS Regional Reliability Grapevine Interchange 230 kv Grapevine Interchange 115 kv 1 230/ /250 NTC SPS Build a new 115 kv line from Atoka-Eagle Creek and install terminal equipment 6/1/ months $19,639,618 SPS Regional Reliability Atoka Interchange 115 kv Eagle Creek 115 kv /249 NTC SPS UPGRADE EDDY CO transformer KV 250 MVA CKT 1 7/1/2015 6/1/ months $4,265,720 SPS Regional Reliability Eddy County Interchange 230 kv Eddy County Interchange 115 kv 1 230/ /250 Rebuild.5 miles of 115 kv line Oxy Permian Substation-Sanger Switching NTC SPS Station 115 kv 6/1/ months $1,567,971 SPS Regional Reliability OXY Permian Sub Sanger Switching Station 115 kv /303 Build new 230kV line from Carlisle to Wolfforth So. and install terminal NTC-C SPS equipment 6/1/2017 6/1/ months $32,790,576 SPS Regional Reliability Wolfforth Interchange 230 kv Carlisle Interchange 230 kv /478 ATP SPS Install a 2 stage kv capacitor bank each stage 14.4 Mvar 6/1/ months $1,401,907 SPS Regional Reliability Cochran Interchange 115 kv MVAR NTC-C SPS Build 1.9 miles of 115 kv from S Portales to Market St 115 kv and install necessary terminal equipment 6/1/ months $4,589,547 SPS Regional Reliability S Portales 115 kv Market ST 115 kv /175 NTC-C SPS Build 7 miles of 115 kv from Market St to Portales substation and install necessary terminal equipment 6/1/ months $14,576,999 SPS Regional Reliability Market ST 115 kv Portales Interchange 115 kv NTC-C SPS Build 2.2 miles of 115 kv from Zodiac 115 kv to South Portales 115 kv and install necessary terminal equipment 6/1/2018 $5,784,674 SPS Regional Reliability Zodiac Sub 115 kv S Portales 115 kv /175 NTC WFEC Rebuild and convert the 4 miles of 69 kv between OU Switchyard and Cole Substation to 138kV (R )and install terminal equipment in OU Switchyard. 10/31/2013 6/1/ months $1,705,000 WFEC Regional Reliability OU SWITCH COLE /179 NTC WFEC Convert 10.2 mile Cole-Criner 69 kv to 138 kv. Cole substation conversion. 11/27/2013 6/1/ months $1,400,000 WFEC Regional Reliability COLE CRINER /179 NTC WFEC Convert Criner to the new Payne Switching Station from 69 kv to 138 kv. Install necessary terminal equipment. Tap the Paoli-Cornville Tap 138 kv and install switching station at Payne. The 11/27/2013 6/1/ months $3,000,000 WFEC Regional Reliability CRINER Payne Switching Station 138 kv /178 NTC WFEC new switching station will terminate the Payne-Criner-Cole-Oklahoma University 138 kv line. 11/27/2013 6/1/ months $250,000 WFEC Regional Reliability Payne Switching Station 138 kv /286 NTC WR Install 9.6 Mvar capacitor bank on Potwin 69 kv bus 6/1/2013 $724,896 WR Zonal Reliability POTWIN 69 KV Mvar NTC WR Rebuild 2.65 miles Eastborogh - 64th 69 kv line. 6/1/ months $4,104,097 WR Regional Reliability EASTBOROUGH 69 KV SIXTY-FOURTH (64TH) 69 KV /163 NTC - Modify WR Tear down and rebuild 3.1-mile El Paso-Farber 138 kv line. 6/1/ months $5,561,163 WR Regional Reliability EL PASO 138 KV FARBER 138 KV /314 NTC - Modify WR Install second 138/115 kv transformer at Moundridge. 12/1/2014 6/1/ months $18,063,183 WR Regional Reliability MOUNDRIDGE 138 KV MOUNDRIDGE 115 KV 2 138/ /240 NTC WR Rebuild Cowskin - Westlink 69 kv. 6/1/2015 $2,720,000 WR Regional Reliability COWSKIN 69 KV WESTLINK 69 KV /157 NTC WR Rebuild Westlink-Tyler 69 kv. 6/1/2015 $5,834,124 WR Regional Reliability WESTLINK 69 KV TYLER 69 KV /157 NTC WR Rebuild Tyler-Hoover 69 kv. Install terminal equipment at Tyler substation. 6/1/2015 $3,599,711 WR Regional Reliability TYLER 69 KV HOOVER SOUTH 69 KV /157 NTC WR Install a third 138/69 kv transformer at Gill 6/1/ months $7,122,480 WR Regional Reliability GILL ENERGY CENTER SOUTH 138 KV GILL ENERGY CENTER EAST 69 KV 2 138/69 150/165 NTC-C WR Instal new Geary County 345/115 kv substation south of Junction City where JEC-Summit and McDowell Creek-Junction City #2 ckt separate. Insatall 345/115 kv 440 MVA transformer and 115 kv terminal equipment 6/1/ months $20,387,444 WR Regional Reliability Geary County Geary County 1 345/ /440 NTC-C WR Install 345 kv ring bus at the new Geary County substation 6/1/ months $15,376,365 WR Regional Reliability Geary County /1793 NTC-C WR Build new Geary County - Chapman 115 kv line. 6/1/ months $27,938,225 WR Regional Reliability Geary County CHAPMAN 115 KV /262 ATP WR Install two 25 Mvar reactors on the tertiaries of each of the kv Transformers at Reno County Substation. 4 x 25Mvar total. 4/1/ months $1,966,717 WR Regional Reliability 14.4 Total rating of 100Mvar NTC-C WR Install new 345/138 kv transformer at Viola substation 6/1/ months $15,402,744 WR Regional Reliability Viola Viola 138kV 1 345/ /492 NTC-C WR Build new 138kV line between new Viola substation 345/138 kv transformer and existing Clearwater 138 kv substation. 6/1/ months $40,525,225 WR Regional Reliability Viola 138kV CLEARWATER 138KV /628 NTC-C WR Build new 138kV line between new Viola substation 345/138 kv transformer and existing Gill 138 kv substation. 6/1/ months $22,234,744 WR Regional Reliability Viola 138kV GILL ENERGY CENTER WEST 138 KV /628 Withdrawal NTC - Withdraw EDE Reconductor 2.85 miles of 1/0 CU with 556 ACSR 12 months $1,550,000 EDE Regional Reliability SUB EXPLORER SPRING CITY TAP SUB JOPLIN SOUTHWEST /65 NTC - Withdraw EDE Reconductor 9.85 miles of 69 kv 1/0 Cu between Sub #170 and Sub #345 with 556 ACSR 24 months $2,973,000 EDE Regional Reliability SUB NICHOLS ST SUB REPUBLIC NORTHEAST /72 NTC - Withdraw EDE Reconductor 3.58 miles of 69 kv 1/0 Cu between Sub #345 and Sub #451 with 556 ACSR 24 months $1,100,500 EDE Regional Reliability SUB REPUBLIC NORTHEAST SUB REPUBLIC HINES STREET /72 NTC - Withdraw EDE Reconductor 1.55 miles of 69 kv 1/0 Cu between Sub #451 and Sub #359 with 556 ACSR 24 months $476,500 EDE Regional Reliability SUB REPUBLIC HINES STREET SUB REPUBLIC EAST /72 NTC - Withdraw EDE Build new 6-mile Sub Monett kv line as part of multi line upgrade 48 months $7,369,319 EDE Regional Reliability SUB MONETT SUB South Monett 161 kv /268 NTC - Withdraw EDE Build new 1.04-mile 69 kv line from new Monett S. substation to existing 69 kv trunk line 48 months $468,000 SPP Regional Reliability SUB South Monett 69kV Monett SW PT2 2 69kV /92 NTC - Withdraw EDE Install 3-winding transformer connecting Monett kv bus to Monett kv bus as part of multi line upgrade 48 months $2,250,000 SPP Regional Reliability SUB South Monett 161 kv SUB South Monett 69kV 1 161/69 100/100 NTC - Withdraw EDE Build new 0.72-mile 69 kv line (one of double circuit) from new Monett S. substation to existing 69 kv on SW corner of city of Monett Build new 1.06-mile 69 kv line (second of double circuit for approx 0.72 mi, 48 months $324,000 SPP Regional Reliability SUB MONETT CITY EAST SUB South Monett 69kV /92 NTC - Withdraw EDE then single circuit for 0.34 mi) from new Monett S. substation to existing 69 kv on south side of city of Monett which will tie/feed radially to substation PUR months $4,149,000 SPP Regional Reliability SUB PURDY SOUTH SUB South Monett 69kV /32 Tear down the Riverton - Joplin kv line, rebuild as 161 kv from Stateline NTC - Withdraw EDE to outside Joplin 59 substation 48 months $3,591,000 SPP Regional Reliability SUB STATELINE Joplin kv /268 NTC - Withdraw EDE Tear down and rebuild Pillsbury - Reinmiller 69 kv as 161 kv 48 months $2,011,500 SPP Regional Reliability SUB ND & STEPHENS SUB REINMILLER /268 NTC - Withdraw EDE Rebuild Joplin Joplin kv as 161 kv 48 months $1,647,000 SPP Regional Reliability SUB JOPLIN 24TH & CONNECTICUT Joplin kv /268 NTC - Withdraw EDE Rebuild Joplin Pillsbury 69 kv as 161 kv 48 months $1,201,500 SPP Regional Reliability SUB JOPLIN 24TH & CONNECTICUT SUB ND & STEPHENS /268 NTC - Withdraw EDE Rebuild Joplin Gateway 69kV as 161 kv 48 months $749,250 SPP Regional Reliability SUB JOPLIN SOUTHEAST SUB GATEWAY SOUTH /268 NTC - Withdraw EDE Rebuild Gateway - Joplin kv as 161 kv 48 months $4,968,000 SPP Regional Reliability SUB GATEWAY SOUTH SUB JOPLIN SOUTHWEST /268 NTC - Withdraw GRDA Add 50 MVA 161/69 kv transformer Ckt 2 at Afton. 24 months $8,020,000 GRDA Regional Reliability AFTON AFTON /69 50/50 Install 20.5 miles of 115 kv from Haggard to Ingalls. Install two breakers at NTC - Withdraw MKEC Haggard substation. 24 months $23,377,556 MKEC Regional Reliability Haggard 115 KV INGALLS /240 NTC - Withdraw NPPD Add second parallel 3-winding transformer at Stegall 48 months $8,000,000 NPPD Regional Reliability STEGALL TRANSFORMER STEGALL 2 345/ /400 NTC - Withdraw NPPD Build 3.3-mile tie line between Stegall 230 kv and 345 kv substations. 48 months $5,239,000 NPPD Regional Reliability STEGALL 230 kv Stegall Tie 230 kv NTC - Withdraw OGE Increase rating of HSL East kv to HSL West 69 kv line to 143 MVA. Planned by OGE in months $250,000 OGE Regional Reliability HSLEAST HORSESHOE LAKE / of 168

64 NTC - Withdraw WR Install 10.8 Mvar capacitor at Wheatland 115 kv substation. 12 months $957,660 WR Zonal Reliability WHEATLAND 115 KV Mvar Replace terminal equipment on Pentagon substation to increase Mund - NTC - Withdraw WR Pentagon 115 kv Ckt 1 to 1200A. 12 months $278,300 WR Regional Reliability MUND 115KV PENTAGON 115 KV /194 *SCERT for this upgrade has requested recently; Cost shown is total cost, actual cost to be borne by SPP will be determined pursuant to further discussion with Cleco. 64 of 168

65 2013 ITPNT Report Appendix II: 2013 ITPNT Scope of 168

66 2013 ITPNT Report 2013 ITPNT Scope February 14, 2012 TWG Approved with Revisions: 5/9/2012 Engineering of 168

67 2013 ITPNT Report Table of Contents Overview...62 Objective...62 Data inputs...63 A. Load...63 B. Generation Resources...63 C. Model Topology...63 D. Transmission Service...63 E. Demand Response...63 Analysis...64 A. Steady state assessment...64 B. Solution development...64 C. Stability assessment...64 D. Load pocket analysis...64 E. Final reliability assessment...64 Seams...64 Study Process...66 Timeline...66 Deliverables...67 Changes in Process and Assumptions of 168

68 2013 ITPNT Report Overview This document presents the scope and schedule of work for the 2013 Integrated Transmission Planning (ITP) Near-Term (NT) Assessment. This document was reviewed by the Transmission Working Group (TWG) in December Objective The third phase of the ITP process is the Near-Term Assessment (ITPNT). The main objectives of 2013 ITPNT are to evaluate the reliability and robustness of the SPP transmission system in the near-term planning horizon, collaborate on the development of improvements with stakeholders, and identify necessary upgrades for approval and construction. The 2013 ITPNT s primary focus is identifying solutions required to meet the reliability criteria defined in OATT Attachment O Section III.6 but also considers policy and economic components such as EPA policy and demand response. The process will also include coordination of transmission plans with the ITP20, ITP10, Aggregate Study, and Generation Interconnection processes. The 2013 ITPNT will create an effective near-term plan for the SPP footprint which identifies problems for normal conditions (no contingency) and (N-1) scenarios using applicable planning standards. The process will coordinate the development of appropriate mitigation plans to meet the needs of the SPP region. The study will assess the SPP transmission system to ensure SPP has mitigation plans for the following requirements: NERC Reliability Standards TPL-001 and TPL-002 SPP Criteria Local planning criteria as submitted by Transmission Owners (TO) Public policy objectives Consideration of identified economic projects The 2013 ITPNT study horizon will include modeling of the transmission system for six years (i.e. 2018). This will provide enough lead time requirements such that NTC letters can be issued and project owners can begin work in a timely fashion to enable the completion of more complex projects by the identified need date. The process is open and transparent, allowing for stakeholder input. Study results are coordinated with other entities and regions responsible for transmission assessment and planning. TWG will review and vet components of the 2013 ITPNT process, which includes but is not limited to the following items: model development, reliability analysis, stability analysis, transmission plan development, seams impacts, and 2013 ITPNT Report of 168

69 2013 ITPNT Report Data inputs SPP will consider power flow models with individual Balancing Authorities. SPP will use 2013, 2014, and 2018 models in the 2013 ITPNT for the following seasons: 2013 light load, 2013 summer peak, 2014 summer peak, 2018 light load, and 2018 summer peak. The modeling assumptions are detailed in sections below. A. Load The load density and distribution for the steady state analysis will be provided through the MDWG model building process 1. The load will represent each individual BA s coincident conditions per season (i.e. non-coincident conditions for the SPP region). Resource obligations will be determined for the footprint taking into consideration what load is industrial, non-scalable type loads and which load grows over time. B. Generation Resources Existing generating resources will be represented in the power flow models taking into account planned retirements and retirements. SPP will also develop separate models with generation based on EPA s 2011 Cross-State Air Pollution Rule (CSAPR) and 2012 Mercury and Air Toxics Standards (MATS). New generating resources included in the power flow models will be limited to resources with a FERC filed Interconnection Agreement not on suspension or resources with an executed Service Agreement. Exceptions to these qualifications are addressed in the ITP Manual. C. Model Topology The topology used to account for the transmission system excluding generation will be the current transmission system and the following transmission upgrades: SPP approved for construction upgrades, SPP Transmission Owners planned (zonal sponsored) upgrades, and first tier entities planned upgrades (AECI, Entergy, MEC, and WAPA). The model development processes for SPP MDWG and SERC account for long-term transmission line outages as forecasted by each process s member transmission owners. D. Transmission Service To account for the confirmed long-term transmission service SPP creates two scenario models: the first scenario contains projected transmission transfers and generation dispatch on the system; the second scenario contains all confirmed long-term firm transmission service with its necessary generation dispatch. E. Demand Response Demand response will be incorporated into the models through lower load and capacity forecasts, which is developed in Subsection A above. 1 SPP MDWG Powerflow Procedure Manual of 168

70 2013 ITPNT Report Analysis A. Steady state assessment The steady state assessment will use the following models: 2013 light load and summer peak, 2014 summer peak, 2018 summer peak and light load using individual BA dispatch. Staff will also use EPA models of these same seasons. An N-1 contingency analysis will be conducted for the peak and off-peak cases for facilities 60 kv and above in SPP and facilities 100 kv above in first-tier. All facilities 60 kv and above in SPP and 100 kv and above in first-tier will be monitored for this analysis in consideration of 60 kv and above solutions to the problems identified. B. Solution development SPP will use a pool of possible solutions to evaluate upgrades used to create the 2013 ITPNT plan. This pool of solutions will come from SPP transmission service studies, generation interconnection studies, ITP studies, local reliability planning studies by TOs, Attachment AQ studies, stakeholder input and staff evaluation. C. Stability assessment If any 300 kv and above upgrades are identified as solutions, staff will perform a voltage stability assessment to identify preliminary shunt reactive needs for the new transmission lines greater than 300 kv system. D. Load pocket analysis SPP will perform voltage stability analysis for three load pockets: Southwest Missouri area, Texas/Louisiana area, and an SPS pocket. As an input into the analysis, staff will determine contingencies by combining the single worst generator outage within the applicable load area and all transmission line outages within the applicable load area. Using the 2018 summer peak model, staff will perform analysis to identify voltage collapse when increasing load within the load pocket while increasing transfer to the load area from adjacent areas under system intact and contingency conditions. E. Final reliability assessment After all upgrades have been identified and incorporated into the power flow models, a steady state N-1 contingency analysis will be conducted to identify any new issues. Seams In the development of 2013 ITPNT, Staff will review expansion plans of neighboring utilities and Regional Transmission Organizations (RTOs) and include first-tier party s planned projects in the 2013 ITPNT models. Based upon that review, Staff may take into account other external of 168

71 2013 ITPNT Report plans. The models used in the 2013 ITPNT incorporate the latest data from the neighboring utilities and RTOs through the MMWG model development process. Potential impacts of the 2013 ITPNT on neighboring systems will be considered. Coordination is done in accordance with existing Seams agreements. For those without an explicit agreement, those neighbors will be contacted in order to discuss the potential impacts of the ITP on their systems of 168

72 2013 ITPNT Report Study Process 1. The resource additions and retirements, load profiles, and transmission service inclusion processes will be developed through stakeholder reviews. 2. The TWG/MDWG will oversee the development of the models that incorporate the assumptions developed in step #1 above, including review of data and results. A model review will be conducted by MDWG to verify the models before analysis proceeds. 3. Staff will perform an initial steady state analysis using applicable planning standards on power flow models that represent the applicable load profiles and generation dispatch per year and season. The assessment will be for the horizon years 1-6. Within SPP all facilities 60 kv and above in the models will be monitored and within the first-tier for all facilities 100 kv and above will be monitored in this analysis as a means to determine 60 kv and above solutions in the SPP footprint. 4. Staff will identify with input from stakeholders 60 kv and above solutions to potential criteria violations. Staff will coordinate solutions with the Aggregate (AG) and Generation Interconnection (GI) Study processes for the SPP transmission system footprint. a. Since Transmission Operating Guides (TOG) are tools used to mitigate violations in the daily management of the transmission grid, TOGs may be used as alternatives to planned projects and are tested annually to determine effectiveness in mitigating violations. For the purpose of this study, 2013 ITPNT will identify all solutions where the use of TOG is deemed not effective. b. A check will be performed to determine if projects identified in the ITP20 or ITP10 assessments will eliminate or defer any projects identified in the 2013 ITPNT. 5. A follow-up analysis will be performed by Staff repeating the steps above on the identified solutions to validate the solutions and check for potential violations that may have been created. 6. Staff will perform load pocket analysis on the final portfolio of upgrades. 7. Staff will perform stability analysis on the final portfolio of upgrades. Timeline of 168

73 2013 ITPNT Report The study will begin in January 2012 with final results complete by January The estimated study timeline is as follows: Group to review/endorse Start Date Completion Date Scoping TWG November 2011 February 2012 Model Development TWG February 2012 April 2012 Reliability Assessment TWG May 2012 Solution Development TWG June 2012 August 2012 Load Pocket Assessment TWG July 2012 October 2012 Stability Assessment TWG September 2012 October 2012 Final Reliability Assessment TWG October 2012 Review report TWG November 2012 November 2012 Final report with recommended plan TWG November 2012 December 2012 MOPC January 2013 Staff plans to hold stakeholder workshops at least twice during 2012 but may hold more as appropriate. Deliverables The results from the 2013 ITPNT, which define a set of transmission upgrades needed to meet the near-term needs of the system, will be compiled into a report detailing the findings and recommendations of SPP Staff. Changes in Process and Assumptions In order to protect against changes in process and assumptions that could present a significant risk to the completion of the ITPNT, any such changes must be vetted. If TWG votes on any process steps or assumptions to be used in the study, those assumptions will be used for the 2013 ITPNT. Changes to process or assumptions recommended by stakeholders must be approved by the TWG. This process will allow for changes if they are deemed necessary and critical to the ITP, while also ensuring that changes, and the risks and benefits of those changes, will be fully vetted and discussed of 168

74 2013 ITPNT Report Appendix III: Generation Details Appendix III exhibits the details of new generation that was captured in the ITPNT models along with the existing generation used to help serve a Balancing Authorities load if lacking sufficient generation. Table 1 shows new generation in SPP that was included in the ITPNT models. This generation has both executed Generation Interconnection and transmission service agreements. Model Area Generation Capacity with an Executed Transmission Service Agreement Plant Name Net Capacity (MW) In-Service Date American Electric Power Turk /15/2012 Nebraska Public Power District Broken Bow Wind Farm 80 12/31/2012 Nebraska Public Power District Crofton Bluffs Wind Farm 42 12/31/2012 Oklahoma Gas and Electric Company Chisholm View Wind /22/2012 Oklahoma Gas and Electric Company Crossroads Wind /1/2011 Oklahoma Gas and Electric Company Crossroads Wind Expansion 30 6/1/2012 Omaha Public Power District TPW Petersburg 41 In-Service Southwestern Public Service Company Buffalo Dunes /1/2012 Southwestern Public Service Company Spinning Spur Wind /1/2012 Southwestern Public Service Company Sun Edison /2/2012 Southwestern Public Service Company Sun Edison /2/2012 Southwestern Public Service Company Sun Edison /2/2012 Southwestern Public Service Company Sun Edison /2/2012 Southwestern Public Service Company Sun Edison /2/2012 Sunflower Electric Power Corporation CPV Cimarron 425 6/1/2012 Sunflower Electric Power Corporation Ironwood Wind 200 6/1/2012 Westar Energy Caney River Wind 201 1/1/2012 For wind farms, nameplate capacity is shown; for other generation, net summer capacity is shown. Table of 168

75 2013 ITPNT Report In the IPTNT models additional generation was included and dispatched that has an executed FERC-filed Generation Interconnection Agreement not on suspension even though it does not have an executed transmission service agreement. This is shown in Table 2. Generation Capacity without an Executed Transmission Service Agreement Model Area Plant Name Net Summer Capacity (MW) In-Service Date Southwestern Public Service Company Jones # /1/2012 Southwestern Public Service Company LCEC Lovington 42 3/1/2012 Southwestern Public Service Company GSEC Mustang Unit # /1/2013 Southwestern Public Service Company Jones # /1/2013 Southwestern Public Service Company Quay County 23 6/1/2013 Table 2 To address the generation deficiencies in 2018, existing IPP generation was also modeled and dispatched to serve load as represented in Table 3. IPP Generation Capacity Used to Meet Shortfall of Generation and Interchange Model Area Units used for shortfall MW available for Shortfall* American Electric Power Oneta Energy Center 310 American Electric Power Eastman Cogeneration Facility 485 American Electric Power Harrison County Power Project 262 KCP&L Greater Missouri Operations Company Dogwood 430 * Based on available capacity less confirmed long-term firm transmission service. Table 3 In development of the ITPNT EPA scenario, generation capacity was adjusted based on planned actions submitted by MOPC representatives. Adjustments were based on retirements, derates, fuel switching, among other actions, not already included in the ITPNT business as usual of 168

76 2013 ITPNT Report scenarios. Only those that affected plant capacity were necessarily accounted for in the ITPNT EPA model set. The adjustment totals were as follows 2 : Reduced capacity from retirements: 89 MW Reduced capacity from derates: 74 MW 3 Reduced capacity from reduced annual usage 4 : MW Increased capacity from fuel switching: 105 MW The total decrease in capacity was accounted for by either other machines in the customer resource list or through the SPP generation shortfall process. 2 All adjustments made were accounted for by dispatch and are not reflected in machine capability modeled. Also, total adjusted capacity may not equate to adjusted output per machine. 3 Derates span the planning horizon and are not necessarily all concurrent. 4 Light load (April minimum) only of 168

77 2013 ITPNT Report Appendix IV: CBA Benchmarking The following tables are comparisons between the CBA model developed for the 2013 ITPNT Assessment and the 2013 ITPNT 2018 summer peak scenario 0 case used for the contingency analysis in the 2013 ITPNT Assessment. The tables below new overloads, solved overloads, new voltage violations, and solved voltage violations found in an ACCC analysis of the CBA model. CBA Model ACCC Violation Calculations Total By Voltage Level (69kV/115/138/161/230/345) % Increase or Decrease compared with 2018 summer peak Total % Change New Overloads Solved Overloads /4/1/6/0/0 4/2/0/4/0/0 28.8% Increase 12.1% Decrease 16.7% net increase in total overloads New Voltage 43 26/9/2/5/1/0 14.5% Increase 5.4% net decrease Violations in total voltage Solved Voltage 58 24/23/0/0/1/ % Decrease violations Violations of 168

78 2013 ITPNT Report New Worse Case Overloads (none in 1 st Tier) AREA FACILITY NAME CONTINGENCY NAME FLOW % SWPA JONESBORO 161/13.8KV TRANSFORMER CKT 1 BASE CASE COLBY (COLBY T2) 115/34.5/12.47KV COLBY (COLBY T4) 115/34.5/12.47KV MIDW TRANSFORMER CKT 2 TRANSFORMER CKT COLBY (COLBY T4) 115/34.5/12.47KV COLBY (COLBY T2) 115/34.5/12.47KV MIDW TRANSFORMER CKT 4 TRANSFORMER CKT KACY COL PAL2 - MUNCIE 2 69KV CKT 1 BARBER 2 - KAW 2 69KV CKT KACY BARBER 2 - KAW 2 69KV CKT 1 COL PAL2 - KAW 2 69KV CKT KACY KAW 2 - SPEAKER 2 69KV CKT 1 BARBER 5 161/69KV TRANSFORMER CKT HARRISONVILLE 161/69KV TRANSFORMER CKT GMO 1 SPP-MIPU KACY MILL STREET 2 - MUNCIE 2 69KV CKT 1 BARBER 2 - KAW 2 69KV CKT SWPA JONESBO (JBO GSU3) 69/13.8/13.8KV TRANSFORMER CKT 1 BASE CASE 111 KACY COL PAL2 - KAW 2 69KV CKT 1 BARBER 2 - KAW 2 69KV CKT GMO BLUE SPRING SOUTH - PRAIRIE LEE 161KV CKT 1 DUNCAN ROAD - SIBLEYPL KV CKT OPPD SUB 1206 (S1206 T2) 161/69/13.8KV TRANSFORMER CKT 1 S1206T1 BSCL SWPA DONIPHAN 161/69KV TRANSFORMER CKT 1 DONIPHAN 161/69KV TRANSFORMER CKT OKGE MISSION HILL - SHAWNEE 69KV CKT 1 OGE3TERM CLEC CHAMPAGNE - PLAISANCE 138KV CKT 1 EAST OPELOUS OPPD SUB 1206 (S1206 T1) 161/69/13.8KV TRANSFORMER CKT 1 S1206T2 BSCL JONESBO /13.8KV TRANSFORMER JONESBO /13.8KV SWPA CKT 1 TRANSFORMER CKT NPPD BEATRICE - HARBINE 115KV CKT 1 KELLY - SOUTH SENECA 115KV CKT SPS DENVER CITY INTERCHANGE N. - MUSTANG STATION N. 115KV CKT 1 DENVER CITY INTERCHANGE S. - MUSTANG STATION N. 115KV CKT of 168

79 2013 ITPNT Report Solved Worst Case Overloads SPP AREA FACILITY NAME CONTINGENCY NAME FLOW % LAFA ELKS 2 - HARGIS 69KV CKT 1 BASE CASE SWPA HERGETT - JONESBORO 161KV CKT 1 HARISBURG TAP - MARKED TREE 161KV CKT WERE HUTCHINSON ENERGY CENTER - HUTCHINSON GAS TURBINE STATION 69KV CKT 1 CIRCLE - HUTCHINSON GAS TURBINE STATION 115KV CKT GRDA KERR - SALINA 161KV CKT 1 KERR - SALINA KV CKT GRDA KERR - SALINA KV CKT 2 KERR - SALINA 161KV CKT SPS MADDOX STATION - SANGER SWITCHING STATION 115KV CKT 1 MADDOX STATION - MONUMENT SUB 115KV CKT SPS OXY PERMIAN SUB - SANGER SWITCHING STATION 115KV CKT 1 MADDOX STATION - MONUMENT SUB 115KV CKT OPPD SUB SUB KV CKT 1 SUB 1209 (S1209 T1) 161/69/13.8KV TRANSFORMER CKT st Tier AECI AID JCT - BLOOMFIELD 69KV CKT 1 ASHERVILLE - IDALIA 161KV CKT EES-EAI TRUMANN - TRUMANN WEST AECC 161KV CKT 1 NEWPORT - NEWPORT INDUSTRIAL 161KV CKT of 168

80 2013 ITPNT Report New Worse Case Voltage SPP AREA FACILITY NAME CONTINGENCY NAME PU Voltage AEPW HUGO 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW SAWYER 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW FORT TOWSON 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW KIAMICHI PUMP NORTH 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW GEORGIA PACIFIC 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW KIAMICHI PUMP TAP 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW VALLIANT 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW WRIGHT CITY TAP 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW KIAMICHI PUMP 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT AEPW WRIGHT CITY 69KV VALLIANT (VALIANT1) 138/69/13.8KV TRANSFORMER CKT CLEC MAURICE KV CLARENCE - MONTGOMERY 230KV CKT NPPD JEFFREY 115KV LN NPPD PETERSBURG 115KV PETERSBRG.N PETERSBURG 115KV CKT NPPD FULLERTON 115KV ALBION - PETERSBURG 115KV CKT OKGE FRISCO 69KV AHLOSO TAP - HARDNTP KV CKT OKGE S OKLA CITY PUMP 69KV LULA - SOCPMPT KV CKT OKGE SOCPMPT KV LULA - SOCPMPT KV CKT OKGE FRSCOTP KV AHLOSO TAP - HARDNTP KV CKT SPS LUBBOCK POWER & LIGHT- HOLLY PLANT 230KV JONES STATION BUS#2 - LUBBOCK POWER & LIGHT- HOLLY PLANT 230KV CKT SPS KEYES SUB 69KV GUYMON NORTH SUB - TRI COUNTY REC-TEXAS COUNTY INTERCHANGE 69KV CKT SPS MALJAMAR SUB 115KV BASE CASE 0.95 SPS LEA COUNTY REC-ANCELL TAP 69KV LEA COUNTY REC-ANCELL TAP - LEA COUNTY REC-NEW SUB 69KV CKT SUNC RUSSELL 115KV SPP-MKEC SUNC WALDO 115KV SPP-MKEC SUNC COVERT KV SPP-MKEC SWPA KENNETT 161KV KENNETT - NEW MADRID 161KV CKT SWPA KENNETT CAP BANK 1 161KV KENNETT - NEW MADRID 161KV CKT of 168

81 2013 ITPNT Report SWPA INDEPCO KV GREERS FERRY - INDEPCO KV CKT SWPA JONESBORO 161KV JONESBORO - WATER VALLEY 161KV CKT SWPA HERGETT KV HERGETT JONESBO KV CKT WERE PEABODY 69KV BENTON - MIDIAN 138KV CKT WERE BUTLER COUNTY NO. 6 DEGRAFF 69KV BENTON - MIDIAN 138KV CKT WERE SPRING CREEK JUNCTION 115KV MOUNDRIDGE - SPRING CREEK JUNCTION 115KV CKT WERE MONTGOMERY 138KV COFFEYVILLE FARMLAND - DELAWARE 138KV CKT WERE BURRTON 69KV EVANS ENERGY CENTER NORTH - SEDGWICK COUNTY NO. 12 COLWICH 138KV CKT WERE CANEY VALLEY NO. 4 CANEY 69KV DEARING (DEARIN1X) 138/69/13.2KV TRANSFORMER CKT WERE RADIANT NO. 7 CANEY 69KV DEARING (DEARIN1X) 138/69/13.2KV TRANSFORMER CKT WERE CANEY 69KV DEARING (DEARIN1X) 138/69/13.2KV TRANSFORMER CKT WERE CANEY VALLEY NO. 7 MCCALL 69KV DEARING (DEARIN1X) 138/69/13.2KV TRANSFORMER CKT WERE TAYLOR 138KV COFFEYVILLE FARMLAND - DELAWARE 138KV CKT st Tier AECI HICKORY CREEK 161KV FAIRPORT - HICKORY CREEK 161KV CKT AECI CAMDENTON2 69KV CAMDENTON1 - TUNNEL DAM 69KV CKT EES-EAI PARAGOULD KV LIGHT - SEDGWICK 115KV CKT of 168

82 2013 ITPNT Report Solved Worst Case Voltage Violations (none in 1 st Tier) Area FACILITY NAME CONTINGENCY NAME PU Voltage AEPW LIEBERMAN 69KV OIL CITY - SUPERIOR 69KV CKT AEPW FORT HUMBUG 69KV BROADMOOR - FORT HUMBUG 69KV CKT AEPW ARSENAL HILL 69KV BASE CASE 1.05 AEPW MENA REC 69KV MENA - US MOTORS TAP 69KV CKT AEPW PITTSBURG 69KV MCALESTER SOUTH (MCALESTR) 138/69/13.8KV TRANSFORMER CKT MIDW ATWOOD 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT NPPD ORD 115KV ORD 115/34.5KV TRANSFORMER CKT NPPD WESTMINSTER 115KV JOHNSON NO 2 - WESTMINSTER 115KV CKT OKGE CRSRDSW KV NORTHWEST - TATONGA KV CKT OKGE TATONGA KV NORTHWEST - TATONGA KV CKT OKGE SCMMRCT KV ARDMORE - SCMMRCT KV CKT OKGE ROCKY POINT 69KV ROCKY POINT - SCMMRCT KV CKT OPPD SUB KV SUB SUB KV CKT OPPD SUB KV NEB CITY U SUB SUB KV CKT OPPD SUB 906 SOUTH 69KV SUB SUB KV CKT OPPD SUB KV SUB SUB KV CKT OPPD SUB KV SUB SUB 906 SOUTH 69KV CKT OPPD SUB KV SUB SUB KV CKT OPPD SUB KV FIRTH - SHELDON 115KV CKT OPPD KINDER MORGAN TAP 69KV FIRTH - SHELDON 115KV CKT OPPD KINDER MORGAN 69KV FIRTH - SHELDON 115KV CKT OPPD NEHAWKA 69KV PLATTESMOUTH - SUB KV CKT OPPD NEB CITY U SUB KV SUB SUB KV CKT SPS PERRYTON INTERCHANGE 69KV SPEARMAN INTERCHANGE - SPEARMAN SUB 115KV CKT SPS FINNEY SWITCHING STATION 345KV FINNEY SWITCHING STATION - HOLCOMB 345KV CKT SPS G KV FINNEY SWITCHING STATION - HOLCOMB 345KV CKT SPS CARLISLE INTERCHANGE 230KV CARLISLE INTERCHANGE - TUCO INTERCHANGE 230KV CKT SUNC HOLCOMB 345KV HOLCOMB (HOLCOMB) 345/115/13.8KV TRANSFORMER CKT SUNC SETAB 345KV HOLCOMB (HOLCOMB) 345/115/13.8KV TRANSFORMER CKT SUNC MINGO 345KV GEN GERALD GENTLEMAN STATION UNIT HOLCOMB (HOLCOMB) 345/115/13.8KV TRANSFORMER SUNC G KV CKT SUNC BUCKNER KV HOLCOMB (HOLCOMB) 345/115/13.8KV TRANSFORMER of 168

83 2013 ITPNT Report Area FACILITY NAME CONTINGENCY NAME CKT 1 PU Voltage SUNC LAWN RIDGE 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC HERNDON 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC GOODLAND TAP 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC ST.FRANCIS TAP 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC GOODLAND 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC CITY OF ST.FRANCIS 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC ST.FRANCIS 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC BIRD CITY 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC ATWOOD SWITCH 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC NORTH ATWOOD 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC GRINNELL 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC MCDONLD KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC CITY OF GOODLAND 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC BVERVLLY KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC ONEOK KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC BREWSTER 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT SUNC MINGO 115KV MINGO (MINGO) 345/115/13.8KV TRANSFORMER CKT WFEC SUGDEN 69KV BASE CASE 0.95 WFEC RYAN 69KV BASE CASE 0.95 WFEC LITTLE AXE 69KV CANADIAN SW - LITTLE AXE 69KV CKT WFEC LAKE CREEK 69KV ELK CITY (ELKCTY-4) 138/69/13.8KV TRANSFORMER CKT WFEC CARTER JCT 69KV ELK CITY (ELKCTY-4) 138/69/13.8KV TRANSFORMER CKT WFEC DILL JCT 69KV ELK CITY (ELKCTY-4) 138/69/13.8KV TRANSFORMER CKT of 168

84 2013 ITPNT Report Appendix V: ITP Near-Term Stability Analysis 1.1: Introduction The 2013 ITPNT solutions were assessed for reliability by examining thermal and voltage performance. Thermal and voltage performance are normally assessed through the tools of steady state contingency analysis; however, this analysis does not determine the distance to, and location of voltage collapse or voltage instability. This must be determined by examining voltage performance during power transfer into a load area or across an interface. This document provides the methods of study as well as the results of these assessments for the 2013 ITPNT. 1.2: Background Voltage stability is defined as a power system s ability to control voltages following a large disturbance such as a fault or contingency. Voltage stability requires that system voltage characteristics be maintained during periods of high load, large power transfers, or sudden disturbances such as a loss of a generator or transmission line. For this study, voltage stability analysis was performed using Voltage Security Assessment Tool (VSAT), which is part of Powertech Labs, Inc. s Dynamic Security Assessment (DSA) Tools. 1.3: Objective The objective of the 2013 ITP Near-Term Stability Analysis was to determine voltage stability limitations and reactive reserve within high load areas in the SPP footprint. This was assessed using the 2013 ITPNT Base and Upgrade 2018 Summer Peak Cases. 1.4: Load Area Analysis A total of three load areas were selected and prioritized for the 2013 ITPNT voltage stability analysis. These load areas are shown in table 1 and graphically in figure 1. Analysis was performed by increasing load within the load area while increasing transfer to the load area from adjacent areas. The transfer was increased while under contingency until voltage collapse occurred on the transmission system inside the load area. This provided a load area increase limit as well as the amount of reactive reserve available at the collapse point. Southwest Missouri East Texas Southwestern Public Service Company Table 1: Load Areas Studied of 168

85 2013 ITPNT Report Study Methodology Equivalence load below 100 kv Increase load in load area Increase generation in adjacent areas Pair largest gen outage with transmission outages Modal analysis at max stable transfer Determine load margin Determine reactive reserve margin of 168

86 2013 ITPNT Report Figure 1: Load Areas for 2013 ITPNT Analysis The contingencies consisted of a selected single generation outage (G-1) with all branch outages (T-1), or one generator and one transmission branch within the load area removed from service. Specifically, the selected G-1 outage is the generator within the load area that, when compared to others within the load area, causes the highest degree of voltage instability stress during the transfer. This generator was paired with all T-1 contingencies, which consisted of all branches greater than 100 kv within the load area. Southwest Missouri The Southwest Missouri load area is defined by the following areas/zones/buses shown in Table 2. This load area is geographically located in Southwest Missouri, encompassing the cities of Branson, Springfield, Joplin and surrounding areas. The 2013 ITPNT load area analysis was performed by importing generation into the Southwest Missouri area while increasing both real and reactive load in the load area in proportion to the initial MW output of each source generator of 168

87 2013 ITPNT Report for both the Base Case and the Upgrade Case. Table 2 provides the simulation results. These results indicate that voltage instability occurs on the 161kV transmission system subsequent to a load increase of: Base Case: 1080 MW Upgrade Case: 1100 MW Base Used 2013 ITPNT 2018 SP Base Case 2013 ITPNT 2018 SP Upgrade Case Generation Source 330(exclude zones 304 & 306), 351, 356, 520, 523, 524, 525, 540, 541, 536 Initial Source (MW) 63,391 63,391 Load Area 544(only zones 1561, 1562, 1563, 1564, 1565, 1566, 1567) 546: All Zones 515: All Zones 330(only buses , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ) Initial Load Area (MW) 2,538 2,538 Voltage Collapse (MW) 3,638 3,658 Security Limit (MW) 3,618 3, (exclude zones 304 & 306), 351, 356, 520, 523, 524, 525, 540, 541, (only zones 1561, 1562, 1563, 1564, 1565, 1566, 1567) 546: All Zones 515: All Zones 330(only buses , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ) Load Margin (MW)* 1,080(42% above initial load) 1,100(43% above initial load) Limiting Contingency A 59: MVar Reserve at Security Limit G-1**: Stateline units S2,S3,S4 T-1: 5Morgan Dad kV Line Area 544 EMDE: 0.4 Area 546 SPRM: 11.6 A 59: G-1: Stateline units S2,S3,S4 T-1: 5Morgan Dad kV Line Area 544 EMDE: 0.0 Area 546 SPRM: 0.0 *Load Margin = Security Limit Initial Load **The Stateline Plant was used as the limiting G-1 contingency per the member s request Table 2: Southwest Missouri Load Area Results of 168

88 2013 ITPNT Report Table 3 shows the 161kV buses that have the highest participation in the collapse for both the base and upgrade case. These are also shown graphically in Figure ITPNT 2018 SP Base Case 2013 ITPNT 2018 SP Upgrade Case Bus No. Bus Name kv Bus No. Bus Name kv Area BOL BOL NOL NOL DAD DAD CPK CPK AUR AUR Table 3: Southwest Missouri Load Area Buses Experiencing Voltage Collapse Figure 2: Southwest Missouri Load Area Buses Experiencing Voltage Collapse of 168

89 2013 ITPNT Report The P-V curves shown below in Figure 3 and 4 are provided for the 161kV buses in table 3 above for the limiting contingency shown in table 2. These curves indicate that when the load is proportionally increased in the SWMO area by approximately 1,100 MW voltage collapses occur. The last point shown is the security limit. SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwest Missouri (SWMO) Bus Voltage (pu): Contingency: A BOL [547464] NOL [547496] DAD [547478] CPK [547499] AUR [547468] MON [547480] RDS [547473] pu SWMO Load VSAT AUG-12 08:24 Figure 3: 2013 ITPNT 2018 Summer Peak Base PV of 168

90 2013 ITPNT Report SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwest Missouri (SWMO) Bus Voltage (pu) Contingency: A BOL [547464] NOL [547496] DAD [547478] CPK [547499] AUR [547468] pu SWMO Load VSAT NOV-12 16:12 Figure 4: 2013 ITPNT 2018 Summer Peak Upgrade PV of 168

91 2013 ITPNT Report Figures 5 and 6 show the MVar reserve remaining in load areas 544 & 546 at the security limit for the limiting contingency for the Base and Upgrade Cases respectively. Figure 5: Southwest Missouri Load Area Base Q Reserve of 168

92 2013 ITPNT Report Figure 6: Southwest Missouri Load Area Upgrade Q Reserve of 168

93 2013 ITPNT Report Southwest Missouri EPA Cases The Southwest Missouri load area is defined by the following areas/zones/buses shown in Table 4. The 2013 ITPNT load area analysis was performed by importing generation into the Southwest Missouri area while increasing both real and reactive load in the load area in proportion to the initial MW output of each source generator for both the EPA Base Case and the EPA Upgrade Case. Table 4 provides the simulation results. These results indicate that voltage instability occurs on the 161kV transmission system subsequent to a load increase of: EPA Base Case: 1080 MW EPA Upgrade Case: 1140 MW Base Used 2013 ITPNT 2018 SP EPA Base Case 2013 ITPNT 2018 SP EPA Upgrade Case Generation Source 330 (exclude zones 304 & 306), 351, 356, 520, 524, 525, 540, 541, 536, 523 Initial Source (MW) 63,391 63,391 Load Area 544 (only zones 1561, 1562, 1563, 1564, 1565, 1566, 1567) 546: All Zones 515: All Zones 330 (only buses , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ) Initial Load Area (MW) 2,538 2,538 Voltage Collapse (MW) 3,638 3,698 Security Limit (MW) 3,618 3, (exclude zones 304 & 306), 351, 356, 520, 524, 525, 540, 541, 536, (only zones 1561, 1562, 1563, 1564, 1565, 1566, 1567) 546: All Zones 515: All Zones 330 (only buses , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ) Load Margin (MW)* 1,080 (42% above initial load) 1,140 (43% above initial load) Limiting Contingency MVAr Reserve at Security Limit A 59: G-1: Stateline units S2,S3,S4 T-1: 5Morgan Dad kV Line Area 544 EMDE: 0.0 Area 546 SPRM: 15.1 *Load Margin = Security Limit Initial Load A 59: G-1: Stateline units S2,S3,S4 T-1: 5Morgan Dad kV Line Area 544 EMDE: 0 Area 546 SPRM: 2.6 Table 4: Southwest Missouri EPA Load Area Results of 168

94 2013 ITPNT Report Table 5 shows the 161kV buses that have the highest participation in the collapse for both the base and upgrade case. These are also shown graphically in figure ITPNT 2018 SP EPA Base Case 2013 ITPNT 2018 SP EPA Upgrade Case Bus No. Bus Name kv Bus No. Bus Name kv Area BOL BOL NOL NOL DAD DAD CPK CPK AUR AUR Table 5: Southwest Missouri EPA Load Area Buses Experiencing Voltage Collapse Figure 7: Southwest Missouri EPA Load Area Buses Experiencing Voltage Collapse of 168

95 2013 ITPNT Report The P-V curves shown below in Figure 8 are provided for the 161kV buses in Table 5 above for the limiting contingency shown in Table 4. These curves indicate that when the load is proportionally increased in the SWMO area by approximately 1,100 MW voltage collapses occur. The last point shown is the security limit. SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwest Missouri (SWMO) Bus Voltage (pu): Contingency: A BOL [547464]:A 59:S NOL [547496]:A 59: DAD [547478]:A 59 CPK [547499]:A 59 AUR [547468]:A 59 MON [547480]:A 59 RDS [547473]:A pu SWMO Load Figure 8: 2013 ITPNT 2018 Summer Peak EPA Base PV VSAT AUG-12 08: of 168

96 2013 ITPNT Report SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwest Missouri (SWMO) Bus Voltage (pu): Contingency: A BOL [547464] NOL [547496] DAD [547478] CPK [547499] AUR [547468] MON [547480] RDS [547473] pu SWMO Load VSAT AUG-12 08:48 Figure 9: 2013 ITPNT Summer Peak EPA Upgrade PV of 168

97 2013 ITPNT Report Figures 10 and 11 show the MVar reserve remaining in load areas 544 and 546 at the security limit for the limiting contingency for the Base and Upgrade Cases respectively. Figure 10: Southwest Missouri EPA Load Area Base Q Reserve of 168

98 2013 ITPNT Report Figure 11: Southwest Missouri EPA Load Area Upgrade Q Reserve of 168

99 2013 ITPNT Report East Texas The East Texas load area under this study is defined by the following areas/zones/buses shown in Table 6. The 2013 ITPNT load area analysis was performed by importing generation into the East Texas area while increasing both real and reactive load in the load area in proportion to the initial MW output of each source generator for both the Base Case and the Upgrade Case. The 69 kv loads were equivalenced to the 138 kv system buses in the load zones. Table 6 provides the simulation results. These results indicate that voltage instability occurs on the 138kV transmission system subsequent to a load increase of: Base Case: 90 MW Upgrade: 90 MW Base Used 2013 ITPNT 2018 SP Base Case 2013 ITPNT 2018 SP Upgrade Case Generation Source Areas 351, 502, 520, 524 Include Bus Exclude Zones 529, 534, 539, 541 Initial Source (MW) 37,143 37,143 Load Area Buses: , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , Initial Load Area (MW) Voltage Collapse (MW) Security Limit (MW) Areas 351, 502, 520, 524 Include Bus: Exclude Zones: 529, 534, 539, 541 Buses: , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , Load Margin (MW)* 90(28% above initial load) 90(28% above initial load) Limiting Contingency A41: MVAr Reserve at Security Limit G-1: Welsh unit 1 *Load Margin = Security Limit Initial Load T-1: JACKSNV4 COFFEE4 138kV Line A41: G-1: Welsh unit 1 T-1: JACKSNV4 COFFEE4 138kV Line East Texas Load Area: 359 East Texas Load Area: 359 Table 6: East Texas Load Area Results Table 7 shows the 138kV buses that have the highest participation in the collapse for both the base and upgrade cases. These are also shown graphically in Figure of 168

100 2013 ITPNT Report 2013 ITPNT 2018 SP Base Case 2013 ITPNT 2018 SP Upgrade Case Bus No. Bus Name kv Bus No. Bus Name kv Area COFFEE COFFEE AEPW NEWYORK NEWYORK AEPW ANTIOCH ANTIOCH AEPW DVARANT DVARANT AEPW BARTONC BARTONC AEPW Table 7: East Texas Load Area Buses Experiencing Voltage Collapse Figure 12: East Texas Load Area Buses Experiencing Voltage Collapse of 168

101 2013 ITPNT Report The P-V curves shown below in Figure 13 and 14 are provided for the 138kV buses in Table 7 above for the limiting contingency shown in Table 6. These curves indicate that when the load is proportionally increased in the East Texas area by approximately 90 MW voltage collapses occur. The last point shown is the security limit. Figure 13: East Texas Load Area PV Curve for Base Case of 168

102 2013 ITPNT Report E T Figure 14: East Texas Load Area PV Curves for Upgrade Case of 168

103 2013 ITPNT Report Figures 15 and 16 show the MVar reserve remaining in load area 520 at the collapse point for the limiting contingency for the Base and Upgrade Cases respectively. Figure 15: East Texas Load Area Q Reserve of 168

104 2013 ITPNT Report Figure 16: East Texas Load Area Q Reserve of 168

105 2013 ITPNT Report East Texas EPA Cases The East Texas load area under this study is defined by the following areas/zones/buses shown in Table 8. The 2013 ITPNT load area analysis was performed by importing generation into the East Texas area while increasing both real and reactive load in the load area in proportion to the initial MW output of each source generator for both the EPA Base Case and the EPA Upgrade Case. The 69 kv loads were equivalenced to the 138 kv system buses in the load zones. Table 8 provides the simulation results. These results indicate that voltage instability occurs on the 138kV transmission system subsequent to a load increase of: Base Case: 90 MW Upgrade: 90 MW Base Used 2013 ITPNT 2018 SP EPA Base Case 2013 ITPNT 2018 SP EPA Upgrade Case Generation Source Areas 351, 502, 520, 524 Include Bus Exclude Zones 529, 534, 539, 541 Initial Source (MW) 37,143 37,143 Load Area Buses: , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , Initial Load Area (MW) Voltage Collapse (MW) Security Limit (MW) Areas 351, 502, 520, 524 Include Bus: Exclude Zones: 529, 534, 539, 541 Buses: , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , Load Margin (MW)* 90(28% above initial load) 90(28% above initial load) Limiting Contingency A41: MVAr Reserve at Security Limit G-1: Welsh unit 1 *Load Margin = Security Limit Initial Load T-1: JACKSNV4 COFFEE4 138kV Line A41: G-1: Welsh unit 1 T-1: JACKSNV4 COFFEE4 138kV Line East Texas Load Area: 359 East Texas Load Area: 359 Table 8: East Texas EPA Load Area Results of 168

106 2013 ITPNT Report Table 9 shows the 138 kv buses that have the highest participation in the collapse for both the base and upgrade cases. These are also shown graphically in figure ITPNT 2018 SP EPA Base Case 2013 ITPNT 2018 SP EPA Upgrade Case Bus No. Bus Name kv Bus No. Bus Name kv Area COFFEE COFFEE AEPW NEWYORK NEWYORK AEPW ANTIOCH ANTIOCH AEPW DVARANT DVARANT AEPW BARTONC BARTONC AEPW Table 9: East Texas EPA Load Area Buses Experiencing Voltage Collapse Figure 17: East Texas EPA Load Area Buses Experiencing Voltage Collapse of 168

107 2013 ITPNT Report The P-V curves shown below in Figures 18 and 19 are provided for the 138kV buses in Table 9 above for the limiting contingency shown in Table 8. These curves indicate that when the load is proportionally increased in the East Texas area by approximately 90 MW voltage collapses occur. The last point shown is the security limit. Figure 18: East Texas Load Area EPA PV Curve for Base Case of 168

108 2013 ITPNT Report Figure 19: East Texas Load Area EPA PV Curve for Upgrade Case of 168

109 2013 ITPNT Report Figures 20 and 21 show the MVar reserve remaining in load area 520 at the collapse point for the limiting contingency for the Base and Upgrade Case respectively. Figure 20: East Texas Area EPA Load Area Base Q Reserve of 168

110 2013 ITPNT Report Figure 21: East Texas Area EPA Load Area Upgrade Q Reserve of 168

111 2013 ITPNT Report Southwestern Public Service Company (SPS) Load Area Base Case The SPS load area under this study is defined by the following areas/zones/buses shown in Table 10. This load area is geographically located in Southwestern Public Service Company, encompassing all the zones of this area. The SPS load area analysis was performed by importing generation into the Southwestern Public Service area while increasing both real and reactive load in the load area. Load was increased in proportion to the initial MW output of each source generator for both the Base Case and the Upgrade Case. Table 10 provides the simulation results. These results indicate that voltage instability occurs subsequent to a load increase of: Base Case: 860 MW Upgrade: 1,020 MW Base Used 2013 ITPNT 2018 SP Base Case 2013 ITPNT 2018 SP Upgrade Case Generation Source Areas 520, 523, 524, 525, 527, 531, Areas 520, 523, 524, 525, 527, 531, 534, 536, 541, 640, 645, , 536, 541, 640, 645, 650 Initial Source (MW) 39,246 39,282 Load Area Area 526 Area 526 Initial Load Area (MW) Voltage Collapse (MW) Security Limit (MW) Load Margin (MW)* 860 (14% above initial load) 1020 (16% above initial load) Limiting Contingency Contingency Group A 149: MVAr Reserve at Security Limit G-1: Tolk_2 unit 1 *Load Margin = Security Limit Initial Load T-1: Bushland 6 Deafsmith 6 230kV Line Contingency Group A 149: G-1: Tolk_2 unit 1 T-1: Bushland 6 Deafsmith 6 230kV Line Area 526 SPS: Area 526 SPS: Table 10: Southwestern Public Service Load Area Results for Base and Upgrade Cases of 168

112 2013 ITPNT Report Table 11 shows the 115kV buses that have the highest participation in the collapse for both the base and upgrade case. These are also shown graphically in Figure ITPNT 2018 SP Base Case 2013 ITPNT 2018 SP Upgrade Case Bus No. Bus Name kv Bus No. Bus Name kv Area DS-# DS-# SPS DS-# DAWN SPS CASTRO_CNTY DS-# SPS DAWN CASTRO_CNTY SPS NE_HEREFORD DS-# SPS Table 11: Southwestern Public Service Load Buses Experiencing Voltage Collapse Figure 22: Southwestern Public Service Load Area Buses Experiencing Voltage Collapse of 168

113 2013 ITPNT Report The P-V curves shown below in Figures 23 and 24 are provided for the 115kV buses in Table 11 above for the limiting contingency shown in Table 10. These curves indicate that when the load is proportionally increased in the SPS area by approximately 860 MW and 1020 MW voltage collapses occur. The last point shown is the security limit. Figure 23: Southwestern Public Service Load Area PV Curve for Base Case of 168

114 2013 ITPNT Report Figure 24: Southwestern Public Service Load Area PV Curve for Upgrade Case of 168

115 2013 ITPNT Report Figures 25 and 26 show the MVar reserve remaining in load area 526 at the security limit for the limiting contingency for the Base and Upgrade Cases respectively. Figure 25: Southwestern Public Service Load Area Base Q Reserve of 168

116 2013 ITPNT Report Figure 26: Southwestern Public Service Load Area Upgrade Q Reserve Southwestern Public Service Company (SPS) Load Pocket EPA Case of 168

117 2013 ITPNT Report The SPS load area under this study is defined by the following areas/zones/buses shown in Table 12. This load area is geographically located in Southwestern Public Service, encompassing all the zones of this area. The SPS load area analysis was performed by importing generation into the Southwestern Public Service area while increasing both real and reactive load in the load area. Load was increased in proportion to the initial MW output of each source generator for both the EPA Base Case and the Upgrade Case. Table 12 provides the simulation results. These results indicate that voltage instability occurs subsequent to a load increase of: Base Case: 1,080 MW Upgrade: 1,140 MW Base Used 2013 ITPNT 2018 SP EPA Base Case 2013 ITPNT 2018 SP EPA Upgrade Case Generation Source Areas 520, 523, 524, 525, 527, 531, Areas 520, 523, 524, 525, 527, 531, 534, 536, 541, 640, 645, , 536, 541, 640, 645, 650 Initial Source (MW) Load Area Initial Load Area (MW) Voltage Collapse (MW) Security Limit (MW) Load Margin (MW)* 1120 (17% above initial load) 1190 (18% above initial load) Limiting Contingency Contingency Group A 149: G-1: Tolk_2 T-1: Bushland Deafsmith 230kV Line MVAr Reserve at Security Limit *Load Margin = Security Limit Initial Load Contingency Group A 149: G-1: Stateline units S2,S3,S4 T-1: Bushland Deafsmith 230kV Line Area 526 SPS: Area 526 SPS: Table 12: Southwestern Public Service Load Area Results for EPA Base and Upgrade Cases Table 13 shows the 161kV buses that have the highest participation in the collapse for both the base and upgrade case. These are also shown graphically in Figure of 168

118 2013 ITPNT Report 2013 ITPNT 2018 SP EPA Base Case 2013 ITPNT 2018 SP EPA Upgrade Case Bus No. Bus Name kv Bus No. Bus Name kv Area DAWN CANYON_WEST SPS CANYON_WEST DAWN SPS DS-# CANYON_EAST SPS NE_HEREFORD DS-# SPS PANDAHFD PANDAHFD SPS Table 13: Southwestern Public Service Load Area Results Figure 27: Southwestern Public Service EPA Load Area Buses Experiencing Voltage Collapse of 168

119 2013 ITPNT Report The P-V curves shown below in Figures 28 & 29 are provided for the 115kV buses in Table 13 above for the limiting contingency shown in Table 12. These curves indicate that when the load is proportionally increased in the SPS area by approximately 1120 MW and 1190 MW voltage collapses occur. The last point shown is the security limit. SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwestern Public Service Company (SPS) Bus Voltage (pu) Contingency: A DAWN [524590] CANYON_WEST3115. [524516] DS-# [524629] NE_HEREFORD3115. [524567] PANDAHFD [524597] pu The security limit of 7544 MW is reached at the DAWN 115kV bus due to voltage collapse of approximately pu SPS Load VSAT OCT-12 15:50 Figure 28: Southwestern Public Service Load Area Load Area PV Curve for EPA Base Case of 168

120 2013 ITPNT Report SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwestern Public Service Company (SPS) Bus Voltage (pu) Contingency: A CANYON_WEST3115. [524516] DAWN [524590] CANYON_EAST3115. [524523] DS-# [524694] PANDAHFD [524597] pu The security limit of 7617 MW is reached at the CANYON_WEST 115kV bus due to voltage collapse of approximately pu SPS Load VSAT OCT-12 15:50 Figure 29: Southwestern Public Service Load Area PV Curves for EPA Upgrade Case Figures 30 & 31 show the MVar reserve remaining in load area 526 at the security limit for the limiting contingency for the Base and Upgrade Cases respectively of 168

121 2013 ITPNT Report SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwestern Public Service Company (SPS) Group MVAr Reserve Contingency: A SPS: A 149 MVAr MVAr SPS Load VSAT OCT-12 15:50 Figure 30: Southwestern Public Service Load Area EPA Base Q Reserve of 168

122 2013 ITPNT Report SPP ITP 2018 SUMMER PEAK: 2012 SOUTHWEST POWER POOL, INC. Southwestern Public Service Company (SPS) Group MVAr Reserve Contingency: A SPS: A 149 MVAr MVAr SPS Load VSAT OCT-12 15:50 Figure 31: Southwestern Public Service Load Area EPA Upgrade Q Reserve of 168

123 2013 ITPNT Report Summary Voltage instability due to transfers into load areas within SPP has been studied and results are provided in this report. Reactive reserve for these load areas are shown at the transfer levels that cause instability. Impacts due to upgrades include Southwest Missouri o Load margin increase is approximately 1% o MVar reserve remaining at the security limit is Zero (0) and Zero (0) for EMDE and SPRM respectively East Texas o Load margin not increased o 359 MVar reactive reserve remaining at the security limit SPS o Load margin increase is approximately 2% o 656 MVar reactive reserve remaining at the security limit of 168

124 Business Practice Draft BPR Number BPR033 Business Practice Section(s) Requiring Revision (include Section No., Title, and Protocol Version) Impact Analysis Required (Yes or No) MMU Report Required (Yes or No) Requested Resolution (Normal or Urgent) BPR Title NTC Review New Business Practice No No Normal Description Reason Tariff Implications or Changes (Yes or No; If yes include a summary of impact and/or specific changes) Criteria Implications or Changes (Yes or No; If yes include a summary of impact and/or specific changes) Credit Implications (Yes or No, and summary of impact) To describe the criteria used to select ITP projects assigned an NTC for re-evaluation. To assess the continued need for previously issued NTCs as new information becomes available and is evaluated in current planning processes. No No No Sponsor Name Katherine Prewitt Address kprewitt@spp.org Company Southwest Power Pool Company Address 201 Worthen Drive, Little Rock, AR Phone Number (501) Fax Number NOTIFICATION TO CONSTRUCT The process for issuing Notifications to Construct (NTCs) is fully described in Business Practices 7050 and 7060 as well as in Attachment O, Section VI of the Tariff. Projects assigned an NTC will be reviewed to determine if the projects will be re-evaluated. The intent of NTC project re-evaluation is to assess the continued need for the project(s) and the project s required in-service date. This business practice is intended to clarify the criteria used to determine transmission projects assigned NTCs that will be re-evaluated. Page 1 of of 168

125 Business Practice Draft DEFINITIONS BOD: SPP Board of Directors. Designated Transmission Owner (DTO): The Transmission Owner(s) or other entity designated to build and own a Network Upgrade in accordance with the Tariff. Notification to Construct (NTC/NTC-C): A formal document specifying approval of and notification to build specific Network Upgrades in accordance with Business Practice 7050 and the Tariff. Notification to Construct with Conditions (NTC-C): A formal document directing a DTO to further refine its Study Estimate for its Applicable Project. An NTC-C does not authorize the DTO to start construction or to order materials for the project. Need Date: Date when a Network Upgrade needs to be in-service as identified in the applicable planning study process. Network Upgrade: All or a portion of the modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider s overall Transmission System for the general benefit of all Users of such Transmission System. PCWG: SPP Project Cost Working Group Project: One or more Network Upgrades that together form a uniform upgrade on the network. Business Practice ITP Study Process o 10-Year Assessment ITP10 o Near Term Assessment - ITPNT This Business Practice clarifies the conditions under which an NTC will be re-evaluated during the ITP study process. The need for a re-evaluation of an NTC may arise from the availability of new information such as material changes to modeling assumptions, public policy, and project costs. These changes may result in a need to modify or replace NTCs to construct a more cost effective project. This business practice is applicable to NTCs resulting from the ITP Study Process that are issued after 1/1/2012. Re-evaluation of an NTC will be initiated based on the following criteria: There has been a change in Public Policy directly related to a project designated in the ITP study process as a Policy Project. o OR; Page 2 of of 168

126 Business Practice Draft A Project s in-service date is delayed beyond the project s Need Date by more than 12 months and the NTC has a Need Date greater than 12 months from the NTC issuance date and not under construction. o OR; A Project has been determined for re-evaluation by the PCWG and approved by the BOD. o OR; An force majeure condition event has occurred (e.g. tornadoes, hurricanes, earthquake, etc.) causing significant damage change to an area. o OR; Upon DTO request to re-evaluate their assigned NTC. o OR; Total estimated project cost exceeds $20 Million AND; o The NTC has been issued for at least one year AND; o The NTC has a Need Date greater than months from the NTC issuance date AND; o The re-evaluation shall be completed prior to the beginning of project lead time window AND; o The project(s) is not under constructioncommitted expenditures as of the date of considerationend of re-evaluation should not exceed 10% of the baseline NTC cost estimate. Formatted Comment [r1]: Take to PCWG for definition with suggestion it s defined as time to get project energized from NTC issuance Formatted: Font: Not Bold Applicable ITP Study Process for NTC Re-evaluation: Reliability projects meeting the NTC re-evaluation criteria with Need Dates within the current ITPNT planning horizon will be re-evaluated during the current ITPNT. Reliability projects meeting the NTC re-evaluation criteria with Need Dates beyond the current ITPNT planning horizon will be re-evaluated during the subsequent ITPNT with a horizon including the project s need date. Economic and Public Policy projects meeting the NTC re-evaluation criteria will be reviewed during the next ITP10. A DTO request to re-evaluate their assigned NTC outside of the ITP Study Process will require BOD approval. Determinations for re-evaluations in addition to the initial re-evaluation will be based on project lead times necessary to allow the Need Dates of the projects to be met. A DTO who s NTC has been chosen for re-evaluation will be contacted by SPP and informed of the project s re-evaluation status. Page 3 of of 168

127 NTC Review Closing Dates 1 : Business Practice Draft ITPNT: The closing date will be July 1 st of the current cycle of the ITPNT for the performance of the NTC review and the receipt of DTO re-evaluation requests. ITP10: The closing date will be November four (4) months following the start1 st of the current ITP10 cycle for NTC review for the performance of the NTC review and the receipt DTO re-evaluation requests. The withdrawal or modification of an NTC Project must not: Cause adverse impact to existing Service Agreements or other contractually committed service under the Tariff. Result in the inability to meet reliability standards. Render sold firm transmission service undeliverable. Render interregional studies or agreements invalid. Upon the withdrawal of an NTC, the DTO which received the NTC will be notified of the change in status of the Project. The NTC Project will also be removed from all planning models including TS and GI models. 1 Consideration for re-evaluation will be given to an NTC based on the occurrence of unforeseen circumstances adversely affecting the project after the specified closing date. Page 4 of of 168

128 Business Practice Revision DRAFT BPR BPR021 Number Business Practice Section(s) Requiring Revision (include Section No., Title, and Protocol Version) Impact Analysis Required (Yes or No) MMU Report Required (Yes or No) Requested Resolution (Normal or Urgent) Description Reason BPR Title Authorization to Plan New Business Practice. No No Urgent To describe the process for including ATPs in the SPP planning processes MOPC directed SPP Engineering to develop the Authorization to Plan process and incorporate the process into a Business Practice. Tariff Implications or Changes (Yes or No; If yes include a summary Possibly; Include ATPs into the SPP OATT. of impact and/or specific changes) Criteria Implications or Changes (Yes or No; If yes include a summary No of impact and/or specific changes) Credit Implications (Yes or No, and No summary of impact) Sponsor Name Katherine Prewitt Address kprewitt@spp.org Company Southwest Power Pool Company Address 415 North McKinley, STE 140, Little Rock, AR Phone Number (501) Fax Number Proposed Business Practice Language Revision Page 1 of of 168

129 Business Practice Revision DRAFT AUTHORIZATION TO PLAN The process for issuing Notifications to Construct (NTCs) is fully described in Business Practice 7060 and in Attachment O, Section VI of the Tariff. This business practice is intended to clarify how future transmission projects assigned a Need Date in the Integrated Transmission Planning (ITP) process, which are not issued NTCs are handled. For such projects, the Transmission Provider and the applicable Designated Transmission Owners (DTOs) are authorized to plan for these projects. Once issued an Authorization to Plan (ATP), the Transmission Provider and the DTOs will be expected to follow this business practice. SPP will not issue an ATP without prior approval of the SPP The authority for SPP to issue an ATP is derived from approval by the SPP Board of Directors (BOD). DEFINITIONS Authorization to Plan (ATP): A notification to a Transmission Owner that a transmission project identified in the ITP may be needed beyond the financial commitment horizon. Designated Transmission Owner (DTO): The Transmission Owner(s) or other entity designated to build and own a Network Upgrade in accordance with the Tariff. Notification to Construct (NTC): A formal document specifying approval of and notification to build specific Network Upgrades in accordance with Business Practice 7050 and the Tariff. Need Date: Date when a Network Upgrade needs to be in-service as identified in the applicable planning study process. Network Upgrade: All or a portion of the modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider s overall Transmission System for the general benefit of all Users of such Transmission System. Project: One or more Network Upgrades that together form a uniform upgrade on the network. may be identified in an NTC or ATP. Page 2 of of 168

130 Business Practice Revision DRAFT Business Practice An ATP will be assigned for Network Upgrades originating from the ITP study processes that do not meet the requirements necessary to obtain an NTC. An ATP does not take the place of an NTC. An ATP does not authorize the DTO to make any material or other capital expenditures. Any such costs may not be collected through the Tariff. ITP Study Process o 20-Year Assessment ITP20 o 10-Year Assessment ITP10 o Near Term Assessment - ITPNT The Transmission Provider will post a list of transmission projects approved through the ITP process which have received an ATP on its OASIS website. The ATP posting will be made within 15 business days from the time the BOD approves a Project. The Transmission Provider will notify the Market and Operations Policy Committee (MOPC) and the Transmission Working Group (TWG) once the posting is completed. A sample ATP posting is included in Appendix B of this Business Practice. Once an ATP is assigned to an upgrade and the ATP is posted on OASIS, SPP will include the project in future SPP Aggregate Study and Generation Interconnection models; in the appropriate model year. relative to the project s identified Need Date from the ITP planning processes. A Project that receives an ATP allows the following to occur: Aggregate Transmission Service Study (ATSS): o All projects assigned an ATP may be considered for mitigation for a constraint identified in the study process. Generation Interconnection Process (GI): o All projects assigned an ATP may be considered for mitigation for issues identified in the Generation Interconnection study process. Page 3 of of 168

131 Business Practice Revision DRAFT COST ALLOCATTION Aggregate Transmission Service Studies o Costs related to a project allocated an ATP that is required to satisfy an identified need through the ATSS process before the project s ITP Need Date and the results of the ATSS requires that an ATP be constructed, then the costs of the ATP Accelerated Need Date is within the financial commitment window will be allocated to the Transmission Customers in the Aggregate Study in accordance with the Attachment Z1 of the Tariff and an NTC will be issued in accordance with Business Practice If the ATSS indicates that an ATP may need to be built sooner than originally expected, but is not required to have an NTC issued, thenthe Accelerated Need Date is not within the financial commitment window, no an NTC willshall not be issued and no cost will be assigned to the Transmission Customer(s) in the ATSS. Generation Interconnection Studies o If a project assigned an ATP is determined to be needed for the approval of a Generation Interconnection Request, the Interconnection Customer(s) will be assigned the cost of the ATP which permits the approval of the request in accordance with Attachment V of the Tariff. The project assigned an ATP will be built either in accordance with the Generation Interconnection Agreement or SPP will issue an NTC. Studies related to Non-Tariff entities (Seams) o SPP Any SPPMDWG models shared with neighboring entities will not include projects assigned an ATP. In the event SPP is requested to perform an Affected System study for external transmission service requests by a neighboring entity, and such study indicates one or more transmission issues on the SPP System, SPP may use one or more projects assigned an ATP to resolve the identified issue(s). If an ATP is needed to grant the service, the neighboring entity will be assigned the cost of the project which permits the transmission service request to be granted. WITHDRAWAL OF AN AUTHORIZATION TO PLAN Page 4 of of 168

132 Business Practice Revision DRAFT Projects assigned an ATP will be reviewed annually consistent with in the Need Date in the appropriate ITP processnt and every three years in the ITP10 and ITP20 Assessments. These Assessments will determine if current ATPs will remain as-is, be adjusted in timing and/or scope, or be withdrawn from the list of valid projects assigned an ATP. Changes that could render an ATP unnecessary include, but are not limited to, the following: Changes in load Changes in generation Changes in Futures Modeling error Displacement, Deferral, or Replacement by another project Upon the withdrawal of an ATP, the ATP list will be updated accordingly and posted. The project assigned an ATP will also be removed from all planning models. Service granted under the GI and ATSS processes based on an ATP will be honored. Page 5 of of 168

133 Business Practice Revision DRAFT APPENDIX A: ATP Sample Posting Document Study Origination Project ID Upgrade ID Designated Transmission Owner Cost Estimate Cost Estimate Source Project Description Voltage Level (kv) ITP Required Need Date Page 6 of of 168

134 TWG Voltage Security Study Kirk Hall December 19, of 168

135 Voltage Security Study Shunt Reactive Requirements Analysis for Lines >300kV System Wide Reactive Requirements Verification Use light load case Determines shunt reactance needed for high voltage on open ended lines Use summer peak case Reactors found in Part A included Test for low voltage and stability issues 135 of 168 2

136 Assumptions Focus only on > 300 kv system Models 2013 ITPNT 2018 light load and summer peak case (scenario 0 only) Includes project with ISD beyond 2018 Monitored elements (> 300 kv elements ) High voltage > 1.05 p.u. (Part A only) Low voltage (Part B only) < 0.95 p.u. system intact < 0.90 p.u. emergency 136 of 168 3

137 Contingencies Assumptions (cont d) Part A: Open ended lines on > 300 kv system Part B: N-1 and member submitted multiple contingencies > 300 kv Differences from Phase 1 Light load case for Part A No limit on line length No line loadability analysis 137 of 168 4

138 Staff Recommendation TWG approve this as an indicative study. Staff will move forward with ITP Manual enhancements for February meeting 138 of 168 5

139 SPP Voltage Security Study Draft Report for Southwest Power Pool Prepared by: Excel Engineering, Inc. December 20, 2012 Principal Contributor: William Quaintance, P.E. 139 of 168