S P P T r a n s m i s s i o n E x p a n s i o n P l a n R e p o r t

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1 2014 STEP S P P T r a n s m i s s i o n E x p a n s i o n P l a n R e p o r t January 6, 2014 Engineering

2 Revision History Revision History Date Author Change Description 01/06/2014 SPP staff Initial Draft 01/15/2014 SPP staff Endorsed by MOPC 1/28/2014 SPP staff Approved by SPP BOD STEP Report

3 Table of Contents Table of Contents REVISION HISTORY...2 TABLE OF CONTENTS...3 LIST OF FIGURES...4 SECTION 1: EXECUTIVE SUMMARY...6 SECTION 2: TRANSMISSION SERVICES : Transmission Service 2013 Overview : Tariff Attachments AQ and AR SECTION 3: GENERATION INTERCONNECTION : Generation Interconnection 2013 Overview : Generator Interconnection Improvements SECTION 4: INTEGRATED TRANSMISSION PLANNING : 2013 ITP : 2015 ITP : 2014 ITP Near-Term (ITPNT) SECTION 5: BALANCED PORTFOLIO SECTION 6: HIGH PRIORITY STUDIES : SPP Priority Projects SECTION 7: SPONSORED UPGRADES SECTION 8: REGIONAL COST ALLOCATION REVIEW (RCAR) SECTION 9: INTERREGIONAL COORDINATION : Integrated System Integration Study : Interregional Requirements of Order : ITP Seams Coordination Enhancements : Eastern Interconnection Planning Collaborative SECTION 10: SUB-REGIONAL PLANNING : Stakeholder Process and Forums SECTION 11: PROJECT TRACKING : Business Practice : Project Cost Working Group : NTC Letters Issued in : Projects Completed in APPENDIX A: STEP LIST NTCS ISSUED IN APPENDIX C: 2013 ITP20 PROJECT LIST APPENDIX D: 2014 ITPNT PROJECT LIST APPENDIX E: PROJECTS COMPLETED IN ITP Projects Completed in Transmission Service Projects Completed in Generation Interconnection Projects Completed in Balanced Portfolio Projects Completed in Priority Projects Completed in Sponsored Projects Completed in

4 List of Figures Southwest Power Pool, Inc. List of Figures Figure 1.1: Cost by Project Type 2014 STEP...6 Figure 1.2: NTCs Issued in 2013 per Project Type...7 Figure 1.3: 2013 Completed Projects...8 Figure 2.1: STEP Cost Estimate Comparison for Transmission Service Projects Figure 3.1: STEP Cost Estimate Comparison for Generation Interconnection Projects Figure 3.2: Generator Improvement Process Flowchart Figure 4.1: 2014 ITPNT Potential Violations and Draft Solutions Figure 4.2: 2014 ITPNT Project Plan Mileages Figure 5.1: STEP Cost Estimate Comparison for Balanced Portfolio Projects Figure 5.2: Approved Balanced Portfolio Figure 6.1: STEP Cost Estimate Comparison for High Priority Projects Figure 9.1: IS/SPP Integration Date Brightline Summary Figure 10.1: SPP Sub-Regional Map Figure 11.1: Projects Completed in Figure Appendix A.2: Percentage of Total Cost by Facility Type Figure Appendix A.3: Total Cost of Line Upgrades Figure Appendix A.4: Total Miles of Line Upgrades by Project Type Figure Appendix A.5: Total Line Mileage by Voltage Class Figure Appendix A.6: Line Cost by Voltage Class Figure Appendix A.7: History of Total STEP Miles Figure Appendix A.8: History of STEP New Line Miles Figure Appendix A.9: History of STEP Line Rebuilds and Conversions Figure Appendix A.10: Costs of Transformer and Substation Upgrades Figure Appendix A.11: Costs of Capacitive and Reactive Devices Figure Appendix C.0.1: 2013 ITP20 Project Map Figure Appendix D.0.1: 2014 ITPNT Violations and Draft Solutions Map STEP Report

5 List of Tables Table 1.1: 345 kv Projects completed in Table 1.2: 345 kv projects with NTCs in the 2014 STEP...9 Table 2.1: Initial and Final Request and Capacity Amounts for 2011-AGP Table 2.2: Initial and Final Request and Capacity Amounts for 2011-AGP Table 2.3: Active 2013 Aggregate Studies Table 2.4: AQ Study Summary Table 5.1: Balanced Portfolio Projects completed in Table 9.2: Scenario 5 Potential Thermal and Voltage Violations Table 11.1: BP 7060 Cost Estimate Stage Definitions Table Appendix B.13.1: NTCs Issued in Table Appendix C.1: 2013 ITP20 Project List Table Appendix E.2: Transmission Service Projects Completed in Table Appendix E.4: Balanced Portfolio Projects Completed in Table Appendix E.6: Sponsored Projects Completed in

6 Section 1: Executive Summary The 2014 SPP Transmission Expansion Plan (STEP) is a comprehensive listing of all transmission projects in SPP for the 20-year planning horizon. Projects in the 2014 STEP include: Upgrades required to satisfy requests for Transmission Service; Upgrades required to satisfy requests for Generation Interconnection; Approved projects from the ITP 20-Year, 10-Year, and Near Term Assessments; Approved Balanced Portfolio upgrades; Approved High Priority upgrades; and Endorsed Sponsored upgrades. The 2014 STEP consists of 386 upgrades with a total cost of $6.2 billion. The chart below illustrates the cost distribution of the 2014 STEP based on project type. More detail on the total portfolio is listed in Appendix A STEP Cost by Project Type $6.2B GI (2%) $99M Balanced Portfolio (9%) $533M ITP (66%) $4,134M High Priority (22%) $1,380M ATSS (1%) $86M Figure 1.1: Cost by Project Type 2014 STEP After the SPP Board of Directors approves transmission expansion projects or once service agreements are filed with FERC, SPP issues Notifications to Construct (NTC) letters to STEP Report

7 appropriate Transmission Owners. In 2013, SPP issued 25 NTC letters with estimated construction costs of $1.64 billion for 86 projects to be constructed over the next five years through Of this $1.64 billion, the project cost breakdown is as follows: $1.02 billion for Regional Reliability; $1.12 million for Zonal Reliability; $13.65 million for High Priority; and $ million for ITP10 projects. A list of the NTCs issued in 2013 can be found in Appendix B. $1,200 $1,000 NTCs Issued in 2013 per Project Type ($Millions) $1,022 $800 $600 $604.7 $400 $200 $- $1.1 $13.7 Regional Reliability Zonal Reliability High Priority ITP10 Figure 1.2: NTCs Issued in 2013 per Project Type SPP actively monitors the progress of approved projects by soliciting feedback from project owners. Seventy-nine (79) upgrades were completed as of December 31, The breakdown includes: 59 ITP $274.9 million 14 Transmission Service $65.7 million 3 Generation Interconnection $6.8 million 3 Balanced Portfolio $21.9 million 7

8 2013 Completed Projects ($Millions) Itp (59) TSS (14) GI (3) BP (3) Figure 1.3: 2013 Completed Projects The following tables list EHV projects completed in 2013 as well as active EHV projects carrying forward into American Electric Power 345 kv Projects completed in 2013 Replaced autotransformer at Diana substation with new 450 MVA autotransformer (Transmission Service) American Electric Power and Oklahoma Gas and Electric Company Tap of Pittsburg to Muskogee 345 kv transmission line and install 450 MVA autotransformer (Regional Reliability) Install Canadian River 345 kv terminal equipment at new Canadian River substation tapping the Pittsburg to Muskogee line transmission (Regional Reliability) Grand River Dam Authority Install terminal equipment at Cleveland substation for new Cleveland to Sooner 345 kv transmission line (Balanced Portfolio) Kansas City Power and Light Company West Gardner 345 kv bus cut-in to Swissvale to Stilwell 345 kv transmission line (Balanced Portfolio) KCP&L Greater Missouri Operations Company Westar Energy Install new 345/161 kv transformer at new Eastowne substation (Sponsored) Install 3rd Rose Hill 345/138 kv transformer (Transmission Service) Table 1.1: 345 kv Projects completed in STEP Report

9 American Electric Power 345 kv projects with NTCs in the 2014 STEP 76 miles of 345 kv transmission line from Northwest Texarkana to Valliant (High Priority) 18 miles of 345 kv transmission line from Flint Creek to Shipe Road (Regional Reliability) 41 miles of 345 kv transmission line from Shipe Road to East Rogers to Kings River (Regional Reliability) 55 miles of 345 kv transmission line from Welsh to Lake Hawkins (ITP) American Electric Power and Oklahoma Gas & Electric Company 93 miles of 345 kv transmission line from Elk City to Gracemont Kansas City Power & Light 30 miles of 345 kv transmission line from Iatan to Nashua (Balanced Portfolio) KCP&L Greater Missouri Operations Company and Omaha Public Power District 181 miles of 345 kv transmission line from Sibley to Maryville to Nebraska City (High Priority) ITC Great Plains 114 miles 345 kv double-circuit transmission line from Spearville to Clark Co to Thistle (High Priority) ITC Great Plains and Westar Energy 58 miles of 345 kv transmission line from Elm Creek to Summit (ITP) Nebraska Public Power District 222 miles of 345 kv transmission line from Gentleman to Cherry County to Holt County (ITP) 40 miles of 345 kv transmission line from Neligh to Hoskins (Regional Reliability) Prairie Wind Transmission 78 miles double-circuit 345 kv transmission line from Thistle to Wichita (High Priority) Oklahoma Gas and Electric Company and Prairie Wind Transmission 110 miles of double-circuit 345 kv transmission line from Thistle to Woodward District EHV (High Priority) Oklahoma Gas and Electric and Southwestern Public Service Company 250 miles of 345 kv transmission line from Woodward District EHV to Oklahoma/Texas Stateline to Tuco (Balanced Portfolio) 122 miles of double-circuit 345 kv transmission line from Hitchland to Woodward District EHV (High Priority) Table 1.2: 345 kv projects with NTCs in the 2014 STEP 9

10 Section 2: Transmission Services 2.1: Transmission Service 2013 Overview Studies are conducted as a result of customer-submitted long-term firm transmission service requests to determine if the SPP transmission system can accommodate transmission service above what is currently in use. In October of 2013, SPP implemented a new process for evaluating transmission service requests, designed to more expedite the evaluation of requests in the queue currently (The Backlog Clearing Process ). The Backlog Clearing Process 1 is intended to clear the queue of pending requests in anticipation of a new process that will permanently replace the existing process and that will be more efficient and streamlined. This successor process to the Backlog Clearing Process is still in development in the SPP stakeholder process. Southwest Power Pool, Inc. The Transmission Provider will combine all long-term pointto-point and long-term designated network resource requests received during a specified period of time into a single Aggregate Transmission Service Study. Using this Aggregate Transmission Service Study process, the Transmission Provider will combine all requests received during an open season to develop a more efficient expansion of the transmission system that provides the necessary ATC to accommodate all such requests at the minimum total cost. During 2013, SPP Staff posted 23 Aggregate Facilities Studies, as compared to 21 in 2012, to meet 60-day study completion deadlines and FERC Order 890 requirements. Order 890 requires Transmission Providers to file notice with FERC if more than 20% of the Facilities Studies in any two (2) consecutive calendar quarters are not completed in the 60-day study window. In 2013, SPP was not required to file with FERC, as there were no two (2) consecutive quarters in which more than 20% of the studies were late. This was due in large part to the timely submission of documentation by Transmission Owners. The tables below summarize the Aggregate Studies that were closed and produced Service Agreements during The tables show the number of requests and requested capacity (MW) for the initial study (AFS1) and the final number of requests and requested capacity (MW) for the last study iteration (AFS11, AFS10). 1 The SPP Tariff filing can be found at the following location: Ag Study Backlog Clearing Process Tariff Revisions ER STEP Report

11 2011-AGP1-AFS AGP1-AFS11 # of requests-beginning of study 112 # of MW-beginning of study # of requests-end of study 27 #of MW-end of study 1401 Table 2.1: Initial and Final Request and Capacity Amounts for 2011-AGP AG2-AFS AG2-AFS10 # of requests-beginning of study 66 # of MW-beginning of study 5941 # of requests-end of study 13 #of MW-end of study 452 Table 2.2: Initial and Final Request and Capacity Amounts for 2011-AGP2 The table below summarizes the Aggregate Studies for Study Currently Active Iteration Due Date Requests Currently in Study MW Currently in Study Currently Posted Study Date Posted 2012-AG1 AFS-6 1/4/ ,515 AFS-5 10/21/ AG2 AFS-7 LOI 1/11/ ,841 AFS-6 12/27/ AG3 AFS-7 2/17/ ,581 AFS-5 12/4/ AG1 AFS-4 2/23/ ,483 AFS-2 6/17/ AG2 AFS-3 1/20/ ,807 AFS-2 10/9/ AG3 AFS-2 11/29/ ,309 AFS-1 11/26/ AG1 Open Season After 1/31/2014 Total ,536 Table 2.3: Active 2013 Aggregate Studies The graph below shows the total estimated cost of Transmission Service projects included in the 2014 STEP as compared to previous STEP Reports. Fluctuations in the annual STEP estimates may be influenced by the number of new projects identified in completed Transmission Service Studies either having been issued NTCs or approved and awaiting the issuance of an NTC, the completion of Transmission Service related projects, and the increase and decrease of Transmission Owner submitted projects cost estimates within the applicable STEP timeframe. 11

12 $455 Transmission Service ($ Millions) $550 $ $ $ Figure 2.1: STEP Cost Estimate Comparison for Transmission Service Projects A list of Transmission Service projects completed in 2013 can be found in Appendix E. 2.2: Tariff Attachments AQ and AR Attachment AQ SPP Tariff Attachments AQ defines a process through which delivery point additions, modifications, or abandonments can be studied without having to go through the Aggregate Study process. Delivery points submitted through the process are examined in an initial assessment to determine if a project is likely to have a significant effect on the transmission system. If necessary, a full study is then performed on the requested delivery points to determine any necessary upgrades. There were six (6) NTC s issued in 2013 as a result of the AQ process. A flowchart of the AQ Study process in contained in Appendix F. The number of requests and required studies are summarized in Table 2.4 below STEP Report

13 Attachment AR Study Year Delivery Point Requests Full Studies Required Load Increase MW ,200 MW MW Table 2.4: AQ Study Summary Attachment AR defines a screening process used to evaluate potential Long-Term Service Request (LTSR) options or proposed Delivery Point Transfers (DPT). The LTSR option provides customers with a tool to assess possible availability of transmission service. The DPT screening study option enables customers to implement a DPT via issuance of a service agreement more expediently pending the results of the screening. Both of these screening tools allow for a more streamlined Aggregate Study process by reducing the number of requests in the studies. A flowchart of the AR Study process in contained in Appendix F. During 2013, four (4) DPT studies were posted, two (2) of which were granted service. Four (4) LTSR studies were requested and posted. Three (3) LTSR studies were requested and posted. 13

14 Section 3: Generation Interconnection 3.1: Generation Interconnection 2013 Overview A Generation Interconnection (GI) study is conducted pursuant to Attachment V of the SPP Tariff whenever a request is made to connect new generation to the SPP transmission system. GI studies are conducted by SPP in collaboration with affected Transmission Owners to determine the required modifications to the transmission system, including cost and scheduled completion date required to provide the service. As of October 30, 2013, SPP received 35 SPP and 7 affected system GI requests, similar to the 35 SPP and 7 affected system study requests received through the same period in As of that date, there were 29 active queue requests for 3,973.4 MW under study and 6 requests were removed from the queue either from being withdrawn by the requesting Transmission Owner or from the execution of a Generation Interconnection Agreement (GIA). The 7 affected system study requests were made by neighboring systems requesting SPP s evaluation of the impact of the requests on SPP s transmission system. The approval of Priority Projects has facilitated the increase of Generation Interconnection requests. About 6,500 MW of additional Generation Interconnection Agreements were approved based on the existence of Priority Projects and Balanced Portfolio. The graph below shows the total estimated cost of Generation Interconnection projects included in the 2014 STEP as compared to previous STEP Reports. Fluctuations in the annual STEP estimates may be influenced by the number of new projects identified in completed Generation Interconnection Studies that have either been issued NTCs or are approved and are awaiting the issuance of an NTC, the completion of Generation Interconnection related projects, and the increase and decrease of Transmission Owner submitted projects cost estimates within the applicable STEP timeframe $81 Generation Interconnection ($ Millions) $103 $ $56 $99 Figure 3.1: STEP Cost Estimate Comparison for Generation Interconnection Projects STEP Report

15 A list of Generation Interconnection projects completed in 2013 can be found in Appendix E. 3.2: Generator Interconnection Improvements SPP-proposed changes to the DISIS process were approved by the MOPC and BOD in April Tariff language was approved in October The improved process establishes a path that will allow Interconnection Customers who are ready to construct their projects the ability to do so without the current uncertainties related to having a later queue position. The new process makes changes to the first ready approach that was established in SPP will allow more time for customers to remedy deficiencies in their applications before studies begin. Interconnection Customers should be able to move through the process shown below as long as they meet the financial and construction milestones required and will be able to start construction of their projects within 11 months of the start of the study. The amount of time to a final study result will be reduced from the current average time of 24 months to approximately 11 months. Interconnection Customers that move forward in the process will have less exposure to restudies since less viable projects will not be moving forward into Interconnection Agreements. Customers will save money on restudy costs. The improved process will increase the burden on Interconnection Customers that do not have a viable project and will encourage those projects not to enter the queue until such time that their projects become viable. It is thought that the administrative and study work on SPP Staff will be neutral. While the DISIS studies will be more complex, there will only be one DISIS study in progress at any one time. Multiple restudies of multiple clusters will not be necessary. The improved process is expected to provide value by providing cost and time certainty to Interconnection Requests that are ready to build their generating facilities. The new process is shown in Figure 3.2. Information on the Generation Interconnection Improvements Process can be found on SPP s website posted under background materials for the April 16-17, 2013 MOPC meeting (SPP.org>Org Groups>MOPC>MOPC Documents). 15

16 Figure 3.2: Generator Improvement Process Flowchart STEP Report

17 Section 4: Integrated Transmission Planning The Integrated Transmission Planning (ITP) process is Southwest Power Pool s iterative three-year study process that includes 20- Year, 10-Year, and Near Term Assessments. The 20-Year Assessment (ITP20), performed once every three (3) years, identifies transmission projects, generally above 300 kv, needed to develop a grid flexible enough to provide benefits to the region across multiple scenarios. The 10-Year Assessment (ITP10), performed once every three (3) years, focuses on facilities 100 kv and above to meet system needs over a 10-year horizon. The Near Term Assessment (ITPNT), performed annually, assesses system upgrades, at all applicable voltage levels, required in the near-term planning horizon to address reliability needs. Along with the Highway/Byway cost allocation methodology, the ITP process promotes transmission investment that will meet reliability, economic, and public policy needs intended to create a cost-effective, flexible, and robust transmission network which will improve access to the region s diverse generating resources and facilitate efficient market processes. A list of ITP projects completed in 2013 can be found in Appendix E. The first phase of the ITP process was completed with the Board of Directors acceptance of the ITP20 Report on January 25, The next phases of the ITP process were developed concurrently (ITP10 and ITPNT) in 2011 with the Board of Directors acceptance on January 31, : 2013 ITP20 $560M Cost $1.5B Benefit The final 2013 ITP20 Report was approved by the SPP Board of Directors on July 30, For more information on the 2013 ITP 20-Year Assessment, see the full report available on SPP s website (SPP.org > Engineering > Transmission Planning). Five distinct futures were considered to account for possible variations in system conditions over the assessment s 20-year horizon. The futures were approved by the Strategic Planning Committee (SPC) with input from the Economic Studies Working Group (ESWG). The futures evaluated as part of the 2013 ITP20 were: 17

18 Future 1: Business-As-Usual - This future included state renewable mandates and targets as identified in the 2012 Policy Survey 2 resulting in 9.2 GW of renewable resources modeled in SPP, load growth projected by load serving entities, and SPP memberidentified generator retirement projections of approximately 4 GW. This future assumed no major changes to policies that are currently in place. Future 2: Additional Wind - This future s assumptions built upon the Business as Usual future assumptions. Instead of implementing current state renewable mandates and targets, a 20% Renewable Energy Standard (RES) was implemented for each region in the Eastern Interconnect with local renewable resources, resulting in 16.4 GW of renewable resources modeled in SPP. This provided an assessment of the transmission outlook if a similar federal renewable standard were implemented. Future 3: Additional Wind plus Exports - Future 3 assumed SPP will produce and export 10 GW of wind resources above the 20% RES of Future 2 to assist other regions in meeting their RES. This 10 GW was exported to Entergy, PJM, Southern Company, and TVA. Future 4: Combined Policy - This future examined various policy changes and impacts encouraging more green generation. A 20% RES for each region was implemented in this future, as well as a carbon constraint of $36/ton. A potential result of these policy changes was a more aggressive demand response/energy efficiency approach than the Business as Usual future. This was implemented through reductions in peak demand and energy usage, as well as a flatter load curve and higher load factor. An annual 1% reduction to the growth of load was applied from 2021 through 2033 for the SPP region such that the load growth during these years was 0.3% instead of 1.3%. This was done to account for efficiencies gained in demand response/energy efficiency technology that might be expected if the carbon constraint was implemented. The Policy Survey STEP Report

19 decrease in annual energy percentage was approximately half of the decrease in peak demand percentage resulting in a higher load factor than the Business as Usual future. Future 5: Joint SPP/MISO Future - The joint future parameters were developed by the SPP ESWG and the MISO Planning Advisory Committee (PAC). The ESWG and PAC determined the joint model should reflect business as usual conditions. This future was based on the same guidelines as Future 1 (normal load growth, state targets for renewable generation, etc.). While the joint future was similar to Future 1, it was not absolutely the same. Some of the assumption values varied from Future 1 due to collaboration with MISO for the joint future. These Future 5 differences included additional transmission constraints outside of SPP, natural gas prices approximately 4 cents less than Future 1 gas prices and more generation in the MISO region of the resource plan than Future 1. Data provided by MISO regarding the modeling of the MISO region was also leveraged in the other futures to improve the representation of the MISO region in the SPP model. The recommended 2013 ITP20 portfolio was estimated at $560 million in engineering and construction cost and included projects needed to meet potential reliability, economic, and policy requirements. Those projects, with a total estimated net present value revenue requirement of $845 million, are expected to provide net benefits of approximately $1.5 billion over the life of the projects under a Future 1 scenario containing 9.2 GW of wind capacity. The complete list of recommended 2013 ITP20 projects can be found in Appendix C of this report. 4.2: 2015 ITP10 The second phase of the ITP study process includes the ITP 10-Year Assessment performed under the requirements of Attachment O, Section III of the SPP OATT. The approved portfolio includes projects ranging from comprehensive regional solutions to local reliability upgrades to address the expected reliability, economic, and policy needs of the studied 10-year planning horizon. The 2015 ITP10 study process will continue through 2014 with the goal of approval by the BOD in January : 2014 ITP Near-Term (ITPNT) The 2014 ITPNT analyzed the SPP region s immediate transmission needs over the nearterm planning horizon. The ITPNT assessed: (a) regional upgrades required to maintain reliability in accordance with the NERC TPL 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. ITPNT projects are reviewed by SPP s Transmission Working Group (TWG), Markets and Operations Policy Committee (MOPC), and approved by the Board of Directors. Following Board of Directors approval, staff will issue Notification to Construct (NTC) letters for upgrades that require a financial commitment within the next four-year timeframe. SPP developed models for the 2014 ITPNT analysis based on the SPP Model Development Working Group (MDWG) models, for which Transmission Owners and 19

20 Balancing Authorities provided generation dispatch and load information. scope 3 approved by the TWG on December 19, 2012 contains: The years and seasons to be modeled, including 2014, 2015, and 2019; Treatment of upgrades in the models; Scenario cases to be evaluated; Description of the contingency analysis and monitored facilities; and The study Any new special conditions that are modeled or evaluated for the study including the development of the 2019 summer peak model for SPP s Consolidated Balancing Authority (CBA) dispatch. SPP performed analyses identifying potential bulk power system reliability needs. These findings were presented to Transmission Owners and the Transmission Working Group (TWG) to solicit transmission solutions to the potential issues identified. Also considered were transmission solutions from other SPP studies, such as the Aggregate Transmission Service Study and Generation Interconnection processes. From the resulting list of potential solutions, staff identified the optimal regional solutions for potential reliability needs. Staff presented these solutions for member and stakeholder review at SPP s November 2013 planning summit. Through this process, SPP developed a draft list of 69 kv and above solutions necessary to provide reliable service in the SPP region in the nearterm planning horizon. The map in Figure 4.1 shows the draft ITPNT solutions in correlation to the areas identified with reliability criteria violations. The complete list of 2014 ITPNT projects is located in Appendix D of this report ITPNT Scope STEP Report

21 Figure 4.1: 2014 ITPNT Potential Violations and Draft Solutions The 2014 ITPNT Project Plan consists of the following: 266 unique thermal and voltage issues resolved in the 2014 ITPNT. 75 proposed projects at a total estimated cost of $696 million for upgrades that will receive an NTC, NTC-C, or NTC Modify. o 64 will be issued a new Notice to Construct (NTC/NTC-C) at an estimated cost of $486 million. o 11 upgrades have been identified as needing a modified NTC (NTC Modify) at an estimated cost of $210 million. 12 upgrades with NTCs at an estimated cost of $74 million were requested for withdrawal. Project Plan mileage consists of: o 257 miles of new transmission line. o 174 miles of rebuild/reconductor. o Approximately 36 miles of voltage conversion. 69/138 kv: 23 miles 69/115 kv: 13 miles 21

22 Project Plan: Miles of New Lines and Rebuild/Reconductor kV 230kV 161kV 138kV 115kV 69kV New Line Rebuild/Reconductor Figure 4.2: 2014 ITPNT Project Plan Mileages STEP Report

23 Section 5: Balanced Portfolio The SPP Board of Directors approved the Balanced Portfolio projects in April 2009 and directed staff to finalize the Balanced Portfolio Report in accordance with the SPP Tariff and then issue Notifications to Construct (NTC). The NTCs were issued in June The Balanced Portfolio was an initiative to develop a group of economic transmission upgrades benefitting the entire SPP region and to allocate those project costs regionally. The benefits of this group of 345 kv transmission upgrades have been demonstrated by model analysis to outweigh the costs, and the regional cost sharing creates balance across the SPP region. For more information on the Balanced Portfolio, see the full report (SPP.org > Engineering > Transmission Planning). Figure 5.1 below is a graph of the total estimated costs attributed to Balanced Portfolio projects for the 2014 STEP and previous years. The estimated project costs are affected by the completion of projects, as seen in Table 5.1, and adjustments in project cost estimates by Project Owners. $900 $821 Balanced Portfolio ($ Millions) $870 $750 $600 $450 $300 $150 $622 $533 $ Figure 5.1: STEP Cost Estimate Comparison for Balanced Portfolio Projects Current NTC Project Project Project Name Cost ID ID Owner Estimate GRDA Line - Cleveland Sooner 345 kv $3,718, OGE Line Sooner Cleveland 345 kv $46,000, KCPL Tap Swissvale Stilwell $1,922, Multi - Tuco - Woodward 345 kv $16,234,558 Table 5.1: Balanced Portfolio Projects completed in

24 Figure 5.2: Approved Balanced Portfolio STEP Report

25 6.1: SPP Priority Projects Section 6: High Priority Studies In 2010, the SPP Board of Directors and Members Committee approved for construction a group of "priority" high voltage electric transmission projects estimated to bring benefits of at least $3.7 billion to the SPP region over 40 years. The projects will improve the regional electric grid by reducing congestion, better integrating SPP s east and west regions, improving SPP members ability to deliver power to customers, and facilitating the addition of new renewable and non-renewable generation to the electric grid. For information on Priority Projects, see the full report (SPP.org > Engineering > Transmission Planning). Figure 6.1 below is a graph of the total estimated costs attributed to Priority Projects for the 2014 STEP and previous years. The estimated project costs are affected by the completion of projects and adjustments in project cost estimates by Project Owners. No Priority Projects were completed in $1,460 $1,440 Priority Projects ($ Millions) $1,444 $1,420 $1,418 $1,400 $1,380 $1,392 $1,380 $1,360 $1, Figure 6.1: STEP Cost Estimate Comparison for High Priority Projects

26 Figure 6.2: Priority Projects STEP Report

27 Section 7: Sponsored Upgrades Sponsored upgrades are Network Upgrades requested by a Transmission Customer or other entity which do not meet the definition of any other category of Network Upgrades. Any entity may request a Sponsored Upgrade. SPP will evaluate the impact of any Sponsored upgrade on transmission system reliability and identify any necessary mitigation of these impacts. The proposed Sponsored upgrades will be submitted to the MOPC and BOD for endorsement. The Project Sponsor must be willing to assume the cost of the Sponsored upgrade, study costs, and any cost associated with necessary mitigation. No Sponsored upgrades were completed in

28 Section 8: Regional Cost Allocation Review (RCAR) The Regional Allocation Review Task Force 4 (RARTF) report recommended that if the Regional Cost Allocation Review (RCAR) of [a]ll SPP projects that have been issued an NTC since June 2010 and all projects that have not received an NTC that have an inservice date of ten years or less from the year of the report shows that a zone is below the 0.8 B/C ratio Section 4.1 of the RARTF Report then SPP staff should evaluate, and recommend possible mitigation remedies for the zone. The RCAR Report referenced 5 zones that are below the 0.8 benefit to cost ratio for projects with NTCs and all projects without NTCs that have an in-service date of ten years or less. Those zones are: City Utilities of Springfield The Empire District Electric Company Grand River Dam Authority Lincoln Electric System Sunflower Electric Power Corporation Figure 5 on page 22 of the RARTF Final Report, provided a list of mitigation remedies that SPP staff should consider for study and to be made part of the report. SPP Staff and the RARTF recommended the RCAR Report be finalized in October 2013 in order to incorporate and include the finding in SPP s current ITP10 assessment that commenced in July This recommendation was in-line with the direction of the RARTF Report approved in January 2012 as described below. As stated in the report, the first two remedies for SPP staff to consider for City Utilities of Springfield, Empire District Electric Company, Grand River Dam Authority, Lincoln Electric System, and Sunflower Electric Power Corporation as a part of the RCAR Report is the [a]cceleration of planned upgrades and [i]ssuance of NTCs for selected new upgrades. Furthermore, Section 4.2 of the RARTF Report states, [a]dditionally, the RARTF recommends that any Regional Cost Allocation Review, which shows that a zone is above the 0.8 threshold in Section 4.1, but below a 1.0 B/C ratio, should be used and considered as a part of SPP s transmission planning process in the future. Because SPP s 18-month ITP10 Assessment has commenced and remedies contemplated in the RARTF Report include the evaluation of transmission upgrade remedies, SPP Staff recommended the RCAR Report be finalized and considered in SPP s current ITP10 Assessment in collaboration with deficient zones and SPP Stakeholders. 4 Regional Allocation Review Task Force Charter STEP Report

29 In addition to this recommendation, SPP staff and the RARTF recommended that a second RCAR process [RCAR II] be commenced and worked in parallel with the current ITP10 Assessment which is expected to be completed in January This will allow SPP staff to follow the directions contained in Sections 4.2 and Section 5.1 of the RARTF Report through ITP10 while utilizing RCAR II as a means to understand whether proposed remedies approved in the ITP10 provide equity for certain zones. If RCAR II does not show that adequate remedies exist, SPP staff, deficient zones, and SPP Stakeholders can begin the process of analyzing additional potential remedies for any zone below the threshold. The RCAR II report will be completed either (i) shortly after the ITP10 is completed, if cost estimates are to be used in the RCAR II analysis; or (ii) shortly after the completion of the competitive solicitation process, if the RFP results are to be used in the RCAR II analysis. 29

30 Section 9: Interregional Coordination 9.1: Integrated System Integration Study The Integrated System (IS) is comprised of three utilities: Western Area Power Administration Upper Great Plains (WAPA), Basin Electric Power Cooperative, and Heartland Consumers Power District. These three utilities operate under a tariff administered by WAPA. In the third quarter of 2013 SPP performed a study to evaluate the reliability and transmission needs of the (IS) in the event the IS were to join the SPP RTO. The study was performed to provide SPP staff, stakeholders, and the IS with data and information regarding the potential integration of the IS as transmission-owning members of SPP. A potential integration date of October 2015 was assumed for this study. The study had two primary objectives: 1. Evaluate the reliability of the IS s transmission system at the time of the assumed integration date; and 2. Identify the need-by date of the IS planned transmission projects using SPP s planning models and project timing criteria. Reliability Assessment SPP evaluated the reliability of the IS s transmission system for NERC Category A, Category B, and select Category C 5 conditions using the SPP Criteria. This analysis was performed using SPP s Scenario 0 and Scenario 5 planning models which were updated by the IS to ensure accurate modeling of the IS transmission system. After SPP identified potential reliability needs, these potential needs were provided to the IS so mitigations could be provided and tested. The IS provided an acceptable mitigation for each potential reliability need identified by SPP. The results of this analysis are summarized in the tables below. Scenario 0 THERMAL VOLTAGE BASE CAT B CAT C BASE CAT B CAT C 2014W S W L S W TOTAL Table 9.1: Scenario 0 Potential Thermal and Voltage Violations 5 Category C contingencies were provided to SPP by the IS STEP Report

31 Scenario 5 THERMAL VOLTAGE BASE CAT B CAT C BASE CAT B CAT C 2014W S W L S W TOTAL Table 9.2: Scenario 5 Potential Thermal and Voltage Violations SPP Determined Need-by Date for IS Transmission Projects The IS provided SPP with a list of planned transmission projects. SPP evaluated the projects and the rationale for the projects to determine when SPP identified each project would be needed relative to the assumed integration date of October The chart below includes the IS s planned transmission projects along with the SPP determined need-by date based on SPP s Criteria and identifies which side of the assumed integration date ( brightline ) each project falls. Figure 9.1: IS/SPP Integration Date Brightline Summary 31

32 9.2: Interregional Requirements of Order 1000 In July of 2013 SPP filed at FERC procedures to meet the interregional requirements of Order This filing included enhancements to the SPP-MISO Joint Operating Agreement (JOA), a new section in Attachment O of the SPP Tariff to incorporate coordination and cost allocation procedures with the Southeastern Regional Transmission Planning (SERTP) region, and enhancements to Attachment O to outline a regional approval process and regional cost allocation for interregional projects. 9.3: ITP Seams Coordination Enhancements In 2013, SPP enhanced the ITP process by including additional opportunities for coordination with SPP s neighbors. The enhancements provide an opportunity for additional coordination with SPP s neighbors throughout multiple stages of the ITP including model development, issues identification, and solution development. In each of these stages of an ITP study SPP will coordinate with each neighbor on a similar basis as that of SPP stakeholders. The value provided to the ITP process from this additional coordination is better modeling of neighboring regions and more accurate issues identification for potential seams projects as solutions to those issues. 9.4: Eastern Interconnection Planning Collaborative SPP is a participating Planning Authority ( PA ) in the Eastern Interconnection Planning Collaborative (EIPC). The activities of the EIPC can be found on the EIPC website at The EIPC produced a report in December 2013 that details the efforts of the EIPC Steady State Modeling and Load Flow Working Group (SSMLFWG) to produce a 2018 and a 2023 Roll-Up Integration Case of the Eastern Interconnection and provide a summary of the assessments performed. The SSMLFWG includes representatives from each NERC registered PA that is a party to the EIPC Analysis Team Agreement. The Roll-Up Integration Case represents the base case for the Eastern Interconnection and a starting point for additional analysis. This base case will then be evaluated against various scenarios that will be developed with stakeholder input. The Roll-Up Integration Case is an integrated model of the expansion plans for the Eastern Interconnection as they existed in 2013, not a single blueprint for expanding the system. These cases provide solved power flow modeling suitable as a starting point for transmission analysis on an interconnection-wide basis and they are available to all stakeholders to perform their own analyses provided they have CEII clearance STEP Report

33 As with all power flow models, the 2018 and 2023 roll-up integration cases are a representation of the power system for a particular snapshot in time (2018 and 2023 Summer Peak hours) based upon actual facilities and planning forecasts as they existed to meet NERC Reliability Standards at the time the model was developed. The SSMLFWG utilized transmission plans that were provided by each PA as the source of data for model development. These existing transmission plans are a product of each participating PA and the FERC approved regional transmission planning processes for each of the participating EIPC members (as applicable) and extend out through the year It should be noted that loads as well as generation and demand-side resources are inputs into the transmission expansion plans developed by each Planning Authority, and that these inputs are provided by the respective Load Serving Entities (LSEs), market participants, or other applicable entities within each Planning Authority s jurisdiction. Because these inputs are continuously changing, the local and regional transmission plans will necessarily also continuously change resulting in them being more current than can be achieved in wide-area modeling. Nonetheless, wide-area modeling, such as the 2018 and 2023 roll-up integration cases, provides a sound basis for assessing inter-dependencies between and among regions which may not be achievable through local assessments individually. Potential constraints and efficiencies identified through inter-regional analysis are valuable inputs into local and regional processes, where they can be assessed for inclusion into regional transmission expansion plans. 33

34 Section 10: Sub-Regional Planning Based on FERC Order 890 and Section III.2.b of Attachment O of the OATT, sub-regional areas were defined and local area planning meetings were held during 2013 in conjunction with the SPP planning summits. The purpose of local area planning meetings is to identify unresolved local issues and transmission solutions at a more granular level than are accomplished at general regional planning meetings. Local area planning meetings provide stakeholders with local needs the opportunity to give advice and recommendations to the Transmission Provider and Transmission Owners. Local area planning meetings are open, coordinated, and transparent, providing a forum to review local area planning criteria as specified in Section II of the OATT, Attachment O. Feedback offered at each sub-regional meeting is taken into consideration by SPP staff when developing the regional reliability plan. 10.1: Stakeholder Process and Forums Notices for the sub-regional planning meetings are posted on SPP.org and distributed to the appropriate distribution lists. Sub-regional planning meetings are open to all entities. Any regulatory agency is invited and encouraged to participate. The map above represents the three SPP local areas Sub-Regional Meetings Figure 10.1: SPP Sub-Regional Map SPP held sub-regional planning meetings in Little Rock, AR as part of the May and November planning summits. Meetings for all sub-regions were held concurrently in breakout sessions during the spring and fall gatherings. Subject matter experts from SPP staff were present at all of the meetings to receive suggestions, answer questions, and discuss any concerns that stakeholders had about the transmission needs in their respective region STEP Report

35 11.1: Business Practice 7060 Section 11: Project Tracking Applicable to projects issued an NTC on or after January 1, 2012, the MOPC 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. It also introduced the Notification to Construct with Conditions (NTC-C) issued to applicable projects, projects with an estimated cost of $20 Million or greater and a nominal operating voltage greater than 100 kv. The table below lists the cost estimate stage definitions. Estimate Name* Projects > 100 kv & > $20 Million Stage All other BOD Approved Projects Conceptual 1 1 Study 2 2 NTC-C Project (CPE) NTC Project (NPE) NTC-C Issued NTC Issued End Usage Concept screening for ITP20/ITP10 Study of feasibility and plan development for ITP10/ITPNT Precision Bandwidth -50% to + 100% -30% to +30% 3 N/A Final baseline (NTC-C)** -20% to +20% New NTC Issued N/A 3 Final baseline (NTC)** -20% to +20% Design & Design after NTC issued and -20% to 4 4 Construction build the project +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 11.1: BP 7060 Cost Estimate Stage Definitions The precision bandwidths defined in Business Practice 7060 are used as guidelines for NTC review triggers. For a project that is issued a 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. 11.2: Project Cost Working Group Business Practice 7060 also defined the role of the Project Cost Working Group (PCWG) for reviewing projects that have experienced a cost variance that exceeds ±20% of the established baseline estimate. The PCWG will initially be responsible for only applicable projects. If the PCWG recommends a restudy and/or changes or revocation of a NTC, the recommendation to the MOPC would follow SPP s existing processes for approval to the 35

36 BOD. The BOD will make the final determination on whether to restudy and/or change or revoke the NTC. The PCWG is also responsible for maintaining the Standardized Cost Estimate Reporting Template (SCERT) developed to provide consistency of cost estimates and facilitate the Project Tracking process. The SCERT is to be utilized by Transmission Owners for all project cost estimates and applicable monthly/quarterly updates. 11.3: NTC Letters Issued in 2013 The NTC informs transmission project owners of their responsibility for constructing BOD approved network upgrades. NTCs are needed by project owners to assist them in the regulatory and cost recovery process. In 2013, 25 NTCs were issued with current estimated engineering and construction costs of $1.64 billion for 86 projects to be constructed over the next 5 years through Of this $1.64 billion, the project cost breakdown is as follows: $1.02 billion for Regional Reliability; $1.12 million for Zonal Reliability; $13.65 million for High Priority; and $ million for ITP10 projects. A list of the NTCs issued in 2013 can be found in Appendix B. 11.4: Projects Completed in 2013 After the SPP Board of Directors approves transmission expansion projects or once Interconnection or Network Integrated Transmission Services Agreements are filed with FERC, SPP issues Notifications to Construct (NTC) letters to appropriate Transmission Owners. SPP actively monitors the progress of approved projects by soliciting feedback from project owners. Seventy-nine (79) upgrades were completed as of December 3, The breakdown includes: 59 ITP $274.9 million 14 Transmission Service $65.7 million 3 Generation Interconnection $6.8 million 3 Balanced Portfolio $21.9 million STEP Report

37 $300 $ Completed Projects ($Millions) $200 $150 $ $50 $ Itp (59) TSS (14) GI (3) BP (3) Figure 11.1: Projects Completed in

38 Appendix A: STEP List The 2014 STEP List includes a comprehensive listing of transmission projects identified by the SPP RTO. Not all projects in the List have been approved by the BOD, but all BODapproved projects are included in the list. The List also includes Tariff study projects, economic projects, and zonal projects. Projects in the STEP List are categorized in the column labeled Project Type by the following designations: Balanced Portfolio Projects identified through the Balanced Portfolio process Generation Interconnection Projects associated with a FERC-filed Generation Interconnection Agreement High priority Projects identified in the high priority process ITP Projects needed to meet regional reliability, economic, or policy needs in the ITP study processes Transmission Service Projects associated with a FERC-filed Service Agreement Zonal Reliability Projects identified to meet more stringent local Transmission Owner criteria The complete Network Upgrade list includes two dates. 1. In-service: Date Transmission Owner has identified as the date the upgrade is planned to be in-service. 2. SPP Need Date: Date upgrade was identified as needed by the RTO STEP Report

39 NTC ID PID UID Facility Owner WFEC 2014 Project Type Cost Estimate Regional Reliability $6,674,000 SPP Estimated Cost Source Upgrade Lead Time (Mo) Upgrade Description TO Projected In- Service Date SPP Determined Need Date From Bus Number From Bus Name To Bus Number To Bus Name Circuit Voltages (kv) Miles of Reconductor Miles of New Line Ratings Build new 10 mile Meeker - Hammett 138 kv and install terminal equipment. 6/1/ MEEKER HAMMETT / kv from 1/0 ACSR to ACSR for new rating of 53/65 MVA. 1/1/2014 4/1/ WAKITA HAZELTON JCT / WFEC ITP $8,000,000 WFEC reconductor from ACSR to 795 ACSR; new WFEC ITP $1,050,000 SPP rating 91/110 MVA. 6/1/2015 4/1/ WOODWARD WOODWARD / ITP $3,094,772 Add third Tuco 115/69 kv autotransformer. 6/1/2014 6/1/ TUCO Interchange 69 kv TUCO Interchange /69 75/84 kv line to 1590 kcmil ACSR and change terminal equipment at Ft. Smith and Colony substations to OGE ITP $1,834,692 OGE 2000A. 2/3/2014 6/1/ FT SMITH COLONY / WFEC ITP $2,000,000 WFEC Rebuild 2 mile Anadarko - Georgia 138 kv line from 556 to 1113 ACSR. 12/1/2014 6/1/ ANADARKO GEORGIA / WFEC ITP $3,240,000 SPP Elmore - Paoli Rebuild 3/0 to 336 ACSR /2/2014 6/1/ ELMORE PAOLI / WFEC ITP $2,065,000 SPP Convert 5 mile Acme - Franklin from 69 kv to /31/2014 6/1/ FRANKLIN SW ACME / WFEC ITP $1,577,000 SPP Convert 8 mile OU - West Norman from 69 kv to 12/31/2014 6/1/ WEST NORMAN OU SWITCH / WR ITP $4,151,903 WR Rebuild 2.1-mile 69 kv line from Cowskin to 12/1/2015 6/1/ COWSKIN 69 KV WESTLINK 69 KV /143 Rebuild 2.65-mile 69 kv line from Westlink to WR ITP $5,834,124 WR Tyler. Install terminal equipment at Tyler. 6/1/2015 6/1/ WESTLINK 69 KV TYLER 69 KV / WR ITP $4,614,819 WR Rebuild 1.96-mile 69 kv line from Tyler to Hoover. 6/1/2014 6/1/ TYLER 69 KV HOOVER SOUTH 69 KV /143 Upgrade 7 miles to 795 ACSR from Fletcher SW to WFEC ITP $2,000,000 WFEC Marlow Junction 69 kv. 6/1/2014 6/1/ FLETCHER MARLOW JCT / WFEC ITP $1,347,000 SPP Upgrade line from 1/0 to 336.4, 4.85 miles 6/1/2015 6/1/ LINDSAY SW WALLVILLE /65 Convert 3 miles of 69 kv to 138 kv from WFEC ITP $1,125,000 SPP Indiahoma to Grandfield. 3/31/2014 6/1/ Grandfield INDIAHOMA /228 Tap Cache to Paradise 138 kv and install WFEC ITP $7,306,000 SPP miles of 138 kv from Cache to Indiahoma. 3/31/2014 6/1/ INDIAHOMA CACHE / WFEC ITP $5,000,000 SPP Install new 138/69 kv transformer at Grandfield 3/31/2014 6/1/ Grandfield GRANDFIELD 1 138/69 70/ WR ITP $4,104,097 WR Rebuild 2.65-mile 69 kv line from Eastborough to 6/1/2015 6/1/ EASTBOROUGH 69 KV SIXTY-FOURTH (64TH) /143 Install 9 miles of 161 kv from new Shipe Road EAST CENTERTON AEP ITP $11,962,000 AEP Substation to East Centerton Substation. 6/1/2014 6/1/ Shipe Road KV / AEP ITP $13,104,000 AEP Install 345/161 kv transformer at Shipe Road. 6/1/2014 6/1/ Shipe Road Shipe Road / / AEP ITP $34,085,000 AEP Install 18 miles of new 345 kv, ACSR line. 6/1/2014 6/1/ FLINT CREEK 345KV Shipe Road /1176 from Chamber Springs to Farmington REC with ACSR/TW. Upgrade wavetraps, CT ratios, AEP ITP $12,705,537 AEP and relay settings at Chamber Springs. 6/1/2015 6/1/ CHAMBER SPRINGS 161KV FARMINGTON AECC /360 Build 40 miles of 115 kv transmission line Curry County Interchange Bailey County ITP $36,112,744 between Bailey County and Curry County. 6/1/2015 6/1/ kv Interchange 115 kv /300 Rebuild 2.3-mile 69 kv line from Forbing to South SOUTH SHREVEPORT AEP ITP $1,221,505 AEP Shreveport with ACSR/TW. 6/1/2015 6/1/ FORBING TAP KV / AEP ITP $14,500,000 AEP Rebuild miles of the Georgia Pacific - Keatchie 138 kv line from 795 ACSR to 1272 ACSR 6/1/2016 6/1/ GEORGIA-PACIFIC KEATCHIE REC / ITP $3,206,653 Upgrade Chaves 230/115 kv transformer Ckt 2 to 250 MVA. 6/30/2014 6/1/ Chaves County Interchange 230 kv Chaves County Interchange 115 kv 2 230/ /250 Northwest Henderson with ACSR/TW. NORTHWEST AEP ITP $11,980,465 AEP Replace breaker at Evenside. 6/1/2018 6/1/ EVENSIDE HENDERSON 69KV /96 Reconductor 3.25-mile 69 kv line from Northwest NORTHWEST HENDERSON AEP ITP $7,815,833 AEP Henderson to Poynter with 1272 ACSR. 6/1/2014 6/1/ KV POYNTER / AEP ITP $1,004,187 AEP Perdue substation. Replace wave traps at Diana substation. 6/1/2014 6/1/ PERDUE 138KV DIANA 138KV /303 Rebuild 4.7-mile 69 kv line from Brownlee to AEP ITP $12,424,849 AEP North Market with ACSR/TW. 6/1/2015 6/1/ BROWNLEE NORTH MARKET / AEP ITP $11,000,000 AEP Install new 345/161 kv transformer at Kings River (Previous name Osage Creek) 6/1/2016 6/1/ Kings River 161 kv Kings River 161 kv 1 345/ / AEP ITP $24,500,000 AEP Install 9 miles of 345 kv line from Shipe Road to 6/1/2016 6/1/ Shipe Road East Rogers / AEP ITP $65,500,000 AEP Install 32 miles of 345 kv line from East Rogers to Kings River (previous Osage Creek) 6/1/2016 6/1/ East Rogers Kings River 161 kv / WR Regional Reliability $53,832,758 WR GRDA ITP $1,419,469 GRDA Appendix A: 2014 STEP List to Jeffrey Energy Center to 345 kv construction but operate as 230 kv using bundled 1590 ACSR conductor. Upgrade terminal equipment at East Manhattan and Jeffrey Energy Center to a minimum emergency rating of 2000 Amps. 6/1/ EAST MANHATTAN 230 KV Miles of Voltage Conversion JEFFREY ENERGY CENTER 230 KV /797 Reconductor 1.4-mile Maid-Redden 69 kv line and replace 600A switches with 1200A switches. 5/1/2014 6/1/ MAID REDDEN /143

40 Crescent to Cottonwood Creek and install terminal equipment at Cottonwood Creek, completing loop from Crescent to Twin Lakes (WFEC). 6/30/2014 6/1/ Crescent 138kv COTTONWOOD CREEK / OGE ITP $9,552,704 OGE Replace Clinton 161/69 kv transformer #1 with GMO ITP $2,000,000 GMO new 100/125 MVA to match transformer #2. 1/31/2014 6/1/ Clinton 69 KV Clinton 161 KV 1 161/69 100/ AEP ITP $2,150,000 AEP Reconductor 2.15 mile section of 115 kv line with 6/1/2014 6/1/ LONE STAR LOCUST GROVE /120 Rebuild 21.9 mile St. John - Pratt 115 kv line with MKEC ITP $15,079,303 MKEC 795 ACSR conductor. 6/15/2014 6/1/ St John 115 KV Pratt 115 KV / kv line. Increase CT ratios at Pecan Creek to 2000 A. Replace two wavetraps, one 161 kv breaker, three switches and increase CT ratio at OGE ITP $2,591,900 OGE Five Tribes. 10/1/2014 6/1/ PECAN CREEK TRIBES / AEP ITP $4,923,124 AEP Broadmoor to Fern Street with ACSR/TW. Replace switches at Fern Street. 6/1/2015 6/1/ BROADMOOR FERN STREET / OGE Balanced $170,000,000 OGE Build new 345 kv line from Seminole to 12/31/2015 6/1/ SEMINOL MUSKOGE / OGE Balanced $120,000,000 OGE Build new 345 kv line from Woodward EHV to 5/19/ Border Woodward EHV 345kv / OGE Balanced Install 2nd 345/138 kv transformer at Woodward 5/19/ Woodward EHV 138kv Woodward EHV 345kv 2 345/ / OGE Balanced Portfolio Build midpoint reactor station at interception point of Woodward to Tuco line. 5/19/ Border / KCPL Balanced Portfolio $10,811,309 KCPL Add 345 kv line terminal at Iatan. Add ring bus at Iatan to accommodate line terminals. 6/1/ IATAN 345 KV PAOLA 345KV / KCPL Balanced $2,905,550 KCPL Install new 345/161 kv transformer at Nashua 6/1/ PAOLA 345KV NASHUA 161 KV 1 345/ / GMO Balanced $51,647,155 GMO Build 31 miles of new 345 kv line from Iatan to 6/1/ IATAN 345 KV PAOLA 345KV / Balanced Portfolio $177,336, GMO ITP $1,950,000 KCPL WR ITP $18,343,600 WR Build new 345 kv line from Tuco to OGE's Border station near TX/OK Stateline. Install line reactor outside Border station and line reactors at Tuco. 5/19/ TUCO Interchange 345 kv Border /1972 Reconductor GMO portion of Glenare - Liberty 69 kv for 70/79 MVA rating. 3/31/2014 6/1/ GLENARE 69 KV Liberty 69 KV /79 Baldwin Creek substation and install Baldwin BALDWIN CREEK 115 Creek 230/115 kv transformer 3/1/2022 6/1/ BALDWIN CREEK KV 1 230/ /308 Reconductor mile FPL Switch - Woodward District 138 kv line to 1590 ASCR. 3/1/ WOODWARD FPL SWITCH / OGE ITP $6,509,948 OGE ITP $2,809,520 Upgrade Happy County 115/69 kv Transformer #1 6/1/2014 6/1/ Happy Interchange 115 kv Happy Interchange /69 84/ ITP $2,812,436 Upgrade Happy County 115/69 kv Transformer #2 6/1/2014 6/1/ Happy Interchange 115 kv Happy Interchange /69 84/96 Rebuild 2.0-mile 69 kv line from Ellerbe Road to AEP Regional Reliability $8,174,689 AEP Forbing T with ACSR/TW. 6/1/2018 6/1/ months ELLERBE ROAD 69 kv FORBING TAP /121 Wolfforth South and install necessary terminal Wolfforth Interchange 230 Carlisle Interchange ITP $32,429,240 equipment. 6/1/2017 6/1/ kv kv /478 Tap Potter - Harrington West 230 kv line at Potter County ITP $3,144,699 Cherry and bring 230 kv into Cherry substation. 6/30/2015 6/1/ Cherry Sub 230 kv Interchange 230 kv / ITP $9,069,568 New 230/115 kv Autotransformer at Cherry 6/30/2015 6/1/ Cherry Sub 230 kv Cherry Sub 115 kv 1 230/ / ITP $1,048,295 Convert Hastings Sub from 69 kv to 115 kv 6/30/2015 6/1/ Hastings Sub 115 kv ITP $3,402,558 Build new 3.7 mile Hastings - East Plant 115kV 6/30/2015 6/1/ Hastings Sub 115 kv East Plant Interchange / ITP $5,540,583 from Cherry Street substation to Hastings substation 6/30/2015 6/1/ Cherry Sub 115 kv Hastings Sub 115 kv / ITP $13,796,842 Tap the Potter Interchange - Plant X Station 230 kv line for new Newhart Substation and install 230/115 kv, 150/173 MVA transformer. 4/30/2015 6/1/ Newhart Interchange 230 kv Newhart Interchange 115 kv 1 230/ / ITP $18,468,396 New 19 mile Swisher County Interchange - Newhart 230 kv line. 4/30/2015 6/1/ Newhart Interchange 230 kv Swisher County Interchange 230 kv / ITP $16,108,465 New 18 mile Kress - Newhart 115 kv line. 4/30/2015 6/1/ Kress Interchange 115 kv Newhart Interchange / ITP $18,501,085 New 24 mile Castro County Interchange - Newhart 115 kv line. 4/30/2015 6/1/ Castro County Interchange 115 kv Newhart Interchange 115 kv / ITP $2,568,905 Build new 4 mile Hart Industrial Substation - Newhart Substation 115 kv line. 4/30/2015 6/1/ Hart Industrial 115 kv Newhart Interchange 115 kv / ITP $15,963,547 New 15 mile Lampton Interchange - Hart Industrial Substation 115 kv line. 4/30/2015 6/1/ Lamton Interchange 115 kv Hart Industrial 115 kv / ITP $16,422,903 Add 230/115 kv transformer 250/250 MVA CKT 1 12/30/2014 6/1/ Pleasant Hill 230 kv Pleasant Hill 115 kv 1 230/ / ITP $18,647,234 Build new 16 mile Pleasant Hill - Oasis 230 kv line. 12/30/2014 6/1/ Pleasant Hill 230 kv Oasis Interchange / ITP $18,805,425 Build new 26 mile Pleasant Hill - Roosevelt County 230 kv line. 12/30/2014 6/1/ Pleasant Hill 230 kv Interchange NORTH 230 kv / ITP $4,255,145 Upgrade Eddy County 230/115 kv transformer Ckt 1 to 250 MVA. 6/1/2015 6/1/ Eddy County Interchange 230 kv Eddy County Interchange 115 kv 1 230/ / ITP $3,100,001 Install second 115/69 kv transformer at Bowers. 11/28/2014 6/1/ Bowers Interchange Bowers Interchange /69 84/ ITP $30,851,077 Interchange - Howard. At Bowers, install 115 kv breaker positions to serve the new transmission line, converting to a three-breaker ring configuration. 6/1/2015 6/1/ Bowers Interchange 115 kv Howard 115 kv /199

41 NPPD ITP $1,049,361 NPPD Uprate conductor and substation equipment to 100 degrees Celsius. 6/1/2014 6/1/ Albion Genoa / WR ITP $6,284,667 WR MacArthur 60 kv line. Replace substation bus and jumpers at MacArthur 69 kv. 6/1/2015 6/1/ GILL ENERGY CENTER EAST 69 KV MACARTHUR 69 KV / ITP $3,000,000 to accept two transformer terminals, two 115 kv line terminals, and one future 115 kv line terminal. Add 2nd 115/69 kv 84/96 MVA transformer. 6/1/2014 6/1/ Northeast Hereford Interchange 115 kv Northeast Hereford Interchange 69 kv 2 115/69 84/96 Convert existing 3 mile Portales Interchange - Portales Interchange ITP $6,500,000 Zodiac 69 kv line to operate at 115 kv. 6/1/2014 6/1/ kv Zodiac Sub 115 kv /173 line and convert Muleshoe East substation to ITP $3,000,000 kv operation. 11/28/2015 6/1/ Muleshoe E 115 kv /160 Build new 22-mile 115 kv line from Kress ITP $15,196,472 Interchange to new Kiser substation. 11/30/2014 6/1/ Kress Interchange 115 kv Kiser Sub 115 kv / ITP $8,300,000 Build new 8.7-mile 115 kv line from Cox to new Kiser substation. 2/28/2014 6/1/ Cox Interchange 115 kv Kiser Sub 115 kv / ITP $6,400,000 Build new substation at Kiser and install a 115/69 kv transformer and 69 kv terminal equipment to connect to the local 69 kv system. 2/28/2014 6/1/ Kiser Sub 115 kv Kiser Sub 69 kv / ITP $2,101,391 Upgrade Graham 115/69 kv transformer Ckt 1 to 12/31/2014 6/1/ Graham Interchange 69 kv Graham Interchange 1 115/69 84/ Regional Reliability $6,386,196 Add second 230/115 kv 250 MVA transformer at Newhart substation. 6/1/2015 6/1/ Newhart Interchange 230 kv Newhart Interchange 115 kv 2 230/ / WFEC ITP $14,737,500 SPP Rebuild 25.2-mile Anadarko - Blanchard 69 kv line 12/1/2014 6/1/ ANADARKO BLANCHARD / WFEC ITP $1,125,000 SPP Rebuild 2-mile Blanchard - OU Switchyard 69 kv 12/1/2015 6/1/ BLANCHARD OU SWITCH /264 Upgrade 9.9 miles of 69 kv line from Mustang to WFEC Regional Reliability $4,725,000 WFEC Sunshine Canyon from 4/0 to /27/2015 6/1/ months MUSTANG SUNSHINE CANYON /89 Hereford to Centre Street. Convert Centre Steet distribution transformer high side from 69 kv to 115 kv. Install necessary terminal equipment at Northeast Hereford Hereford Centre Street Regional Reliability $9,754,258 Northeast Hereford. 12/15/2015 6/1/ Interchange 115 kv Sub / OGE ITP $15,000,000 OGE Convert 14-mile Mehan - Cushing 69 kv line to 6/1/2014 6/1/ Mehan 138 kv CUSHING OGE ITP Convert 6-mile Stillwater - Spring Valley 69 kv line 6/1/2014 6/1/ STILLWATER Spring Valley 138kV OGE ITP Convert 3-mile Spring Valley - Mehan 69 kv line to 6/1/2014 6/1/ Spring Valley 138kV Mehan 138 kv OGE ITP Convert 8.7-mile Spring Valley - Knipe 69 kv line 6/1/2014 6/1/ Spring Valley 138kV Knipe 138 kv /286 Increase line clearances and upgrade terminal equipment on Sub Sub kv line to OPPD ITP $475,340 OPPD allow the use of a higher conductor rating. 6/1/2018 6/1/ Sub Sub / AEP ITP $10,241,314 AEP Rebuild 9.0-mile 138 kv line from Prattville to Bluebell with ACSR/TW. 6/1/2015 6/1/ BLUEBELL PRATTVILLE / AEP ITP $11,830,128 AEP Carthage line from 336 ACSR to 1272 ACSR and remove switches in middle of line. Upgrade breaker, switches, CT ratios, and relay settings at Carthage substation. Upgrade jumpers, switches, CT ratios, and relay settings at Rock Hill 6/1/2014 6/1/ ROCK HILL CARTHAGE / ITP $4,863,725 Install second 230/115 kv transformer at Eddy Co. 6/1/2014 6/1/ Eddy County Interchange 230 kv Eddy County Interchange 115 kv 2 230/ / MKEC Transmission Service $4,782,312 MKEC Rebuild 8.05 mile line 2/1/2014 1/1/ Flat Ridge Tap Medicine Lodge 138 KV / MKEC Transmission Service $13,645,827 MKEC Rebuild 26 mile line 6/15/2014 1/1/ Medicine Lodge 115 KV Pratt 115 KV /198 Rebuild and convert 4-mile Oklahoma University Switchyard - Cole Substation line to 138 kv and WFEC ITP $1,705,000 WFEC install necessary terminal equipment. 6/1/2014 6/1/ OU SWITCH COLE / WFEC ITP $1,400,000 WFEC Convert 10.2-mile Cole - Criner line to 138 kv and convert the Cole substation to 138 kv. 6/1/2014 6/1/ COLE CRINER / WFEC ITP $3,000,000 WFEC Convert 6.3 miles of 69 kv line to 138 kv from Criner to new Payne Switching Station. 11/27/2014 6/1/ CRINER Payne Switching Station 138 kv / WFEC ITP $250,000 WFEC install switching station at Payne with any necessary terminal equipment. The new switching station will terminate the Payne - Criner - Cole - Oklahoma University 138 kv line. 11/27/2014 6/1/ Payne Switching Station 138 kv / OGE Transmission Service $225,000 OGE Replace wavetrap 6/1/2019 6/1/ BRYANT MEMORIAL / AEP High Priority $127,995,000 AEP NW Texarkana with at least 3000 A capacity. Upgrade the Valliant and NW Texarkana substations with the necessary breakers and terminal equipment. 5/1/ VALLIANT 345KV NORTHWEST TEXARKANA 345KV /1940

42 GMO High Priority $241,448,558 GMO GMO High Priority $90,750,965 GMO OPPD High Priority $75,564,841 OPPD High Priority $51,370, High Priority High Priority $13,649, OGE High Priority $165,000,000 OGE OGE High Priority OGE High Priority $145,040,000 OGE OGE High Priority PW High Priority $23,800,000 PW PW High Priority $23,800,000 PW ITCGP High Priority $50,152,303 ITCGP ITCGP High Priority $50,152,303 ITCGP 3000 A capacity from Sibley to a new Mullin Creek (formerly Maryville) substation. Upgrade the Sibley substation with the necessary breakers and terminal equipment. 6/1/ Sibley 345 KV Maryville 345 kv /2496 (formerly Maryville) with a ring bus and necessary terminal equipment. Build a new 65 mile 345 kv line with at least 3000 A capacity from the new Mullin Creek substation to the Missouri/Nebraska state border towards OPPD's Nebraska City substation. 6/1/ Sub 3458 (Neb Cty) Maryville 345 kv / A capacity from the Nebraska City substation to the Missouri/Nebraska state border towards KCPL's Mullin Creek (formerly Maryville) substation. Upgrade the Nebraska City substation with the necessary breakers and terminal 6/1/ Sub 3458 (Neb Cty) Maryville 345 kv /2496 least 3000 A capacity from the Hitchland substation to the OGE interception point from the Woodward District EHV substation. Upgrade the Hitchland substation with the necessary breakers and terminal equipment. 6/30/ least 3000 A capacity from the Hitchland substation to the OGE interception point from the Woodward District EHV substation. Upgrade the Hitchland substation with the necessary breakers and terminal equipment. 6/30/ Install a second 345/230 kv transformer at Hitchland substation. 6/30/2014 6/1/ with at least 3000 A capacity from the Woodward District EHV substation to the interception from the Hitchland substation. Upgrade the Woodward District EHV substation with the necessary breakers and terminal equipment. 6/30/ with at least 3000 A capacity from the Woodward District EHV substation to the interception from the Hitchland substation. Upgrade the Woodward District EHV substation with the necessary breakers and terminal equipment. 6/30/ Hitchland Interchange 345 kv Woodward EHV 345kv /1792 Hitchland Interchange 345 kv Woodward EHV 345kv /1792 Hitchland Interchange 345 Hitchland Interchange kv kv 2 345/ /560 Hitchland Interchange 345 kv Woodward EHV 345kv /1792 Hitchland Interchange 345 kv Woodward EHV 345kv /1792 with at least 3000 A capacity from the Woodward District EHV substation to the Kansas/Oklahoma state border towards the Medicine Lodge substation. Upgrade the Woodward District EHV substation with the necessary breakers and terminal equipment. 12/31/ Thistle 345 kv Woodward EHV 345kv /1792 with at least 3000 A capacity from the Woodward District EHV substation to the Kansas/Oklahoma state border towards the Medicine Lodge substation. Upgrade the Woodward District EHV substation with the necessary breakers and terminal equipment. 12/31/ Thistle 345 kv Woodward EHV 345kv /1792 Build a new 30.4 mile double circuit 345 kv line with at least 3000 A capacity from the Thistle substation to the Kansas/Oklahoma state border towards the Woodward District EHV substation. 12/31/ Thistle 345 kv Woodward EHV 345kv /1792 Build a new 30.4 mile double circuit 345 kv line with at least 3000 A capacity from the Thistle substation to the Kansas/Oklahoma state border towards the Woodward District EHV substation. 12/31/ Thistle 345 kv Woodward EHV 345kv /1792 with at least 3000 A capacity from the new Ironwood substation to the new Clark Co. substation. Build the Clark Co. 345 kv substation with a ring bus and necessary terminal 12/31/ /31/ SPEARVILLE Clark Co 345 kv /1792 with at least 3000 A capacity from the new Ironwood substation to the new Clark Co. substation. Build the Clark Co. 345 kv substation with a ring bus and necessary terminal 12/31/ /31/ SPEARVILLE Clark Co 345 kv /1792

43 ITCGP High Priority $86,286,538 ITCGP with at least 3000 A capacity from the Thistle 345 kv substation to the new Clark County substation. Build a new 345 kv substation at Thistle near Flat Ridge with the necessary breakers and terminal equipment for connecting the Spearville-Thistle- Wichita double circuit transmission lines and for connecting to the Woodward District EHV 345 kv double circuit transmission lines. 12/31/ Clark Co 345 kv Thistle 345 kv / ITCGP High Priority $86,286,538 ITCGP with at least 3000 A capacity from the Thistle 345 kv substation to the new Clark County substation. Build a new 345 kv substation at Thistle near Flat Ridge with the necessary breakers and terminal equipment for connecting the Spearville-Thistle- Wichita double circuit transmission lines and for connecting to the Woodward District EHV 345 kv double circuit transmission lines. 12/31/ Clark Co 345 kv Thistle 345 kv / ITCGP High Priority $6,370,595 ITCGP Install a 400 MVA 345/138 kv transformer at the new 345 kv Thistle substation. 12/31/ Thistle 345 kv Thistle 138 kv 1 345/ / ITCGP High Priority $5,776,280 ITCGP Build 1 mile 138 kv line from new Thistle substation to Flat Ridge substation. 12/31/ Thistle 138 kv Flat Ridge Tap Build new Ironwood 345 kv switching station with the necessary terminal equipment. The new switching station will interconnect the new Clark ITCGP High Priority Co. substation with the Spearville 345 kv bus. 12/31/ /31/ ITCGP High Priority new Ironwood substation to the Spearville 345 kv bus. 12/31/ /31/ with at least 3000 A capacity from the Wichita substation to ITC Great Plains' Thistle 345 kv PW High Priority $61,200,000 PW substation. 12/31/ Thistle 345 kv WICHITA 345 KV / PW High Priority $61,200,000 PW with at least 3000 A capacity from the Wichita substation to ITC Great Plains' Thistle 345 kv substation. 12/31/ Thistle 345 kv WICHITA 345 KV / WR High Priority $14,155,302 WR necessary breakers and terminal equipment to accommodate two new 345 kv circuits form the new Thistle 345 kv substation 12/31/ WICHITA 345 KV /1792 Transmission BROKEN ARROW AEP Service $6,072,000 AEPW Rebuild 4.33 of 795 ACSR with 1590 ACSR. 6/1/2015 6/1/ ONETA 138KV NORTH - SOUTH TAP / Transmission Service $345,942 Upgrade line trap at both Jones Bus #2 and Lubbock South Interchange. 12/30/2014 6/1/ Jones Station Bus#2 230 kv Lubbock South Interchange 230 kv / ITP $2,775,000 line from Randall Co. with 795 ACSR. Tie new line into V70 around (not to) Osage Substation. Add new 115 kv terminal at Randall Co. Interchange. (Re-build Randall 115 kv bus to breaker and onehalf design.) Re-Conductor V70 with 795 ACSR. Remove line termination at Osage Substation. Upgrade terminal equipment and reset relays at South Georgia Interchange. Remove V04 termination from Osage and remove circuit back to Manhattan Tap (remove 3-terminal condition). Remove circuits V67 & V05 terminations from Osage and tie together around Osage Substation. 6/1/2015 6/1/ Randall County Interchange 115 kv South Georgia Interchange 115 kv / ITP $4,179,553 Upgrade Grassland 230/115 kv transformer Ckt 1 6/1/2015 6/1/ Grassland Interchange Grassland Interchange 1 230/ / Regional Reliability $3,496,698 Upgrade existing 230/115 kv transformer at Swisher to 250 MVA. 6/30/2017 6/1/ months Swisher County Interchange 230 kv Swisher County Interchange 115 kv 1 230/ /250 Perdue. Replace switches, jumpers, and upgrade CT ratios at Diana and Perdue. Upgrade relay AEP ITP $18,805,489 AEP settings at Diana. 6/1/2014 6/1/ PERDUE 138KV DIANA 138KV / OGE ITP $161,204 OGE Replace 800 A CT and wavetrap at Classen 138 kv 2/15/2014 6/1/ CLASSEN SW 5TAP /287 Transmission OGE Service $18,000,000 OGE Add 3rd 345kV line from Arcadia to Redbud 6/1/2019 6/1/ ARCADIA REDBUD / WFEC Transmission Service $150,000 WFEC Replace CTs 6/1/2015 6/1/ BLUE CANYON WIND PARADISE / ITP $5,342,685 Convert Lynn County Substation to 115 kv service 12/31/2014 6/1/ Lynn County Interchange 115 kv ITP $2,378,798 Upgrade Crosby County 115/69 kv transformer Ckt 1 to 84 MVA. 6/1/2015 6/1/ Crosby County Interchange 115 kv Crosby County Interchange 69 kv 1 115/69 84/ ITP $2,301,000 Upgrade Crosby County 115/69 kv transformer Ckt 2 to 84 MVA. 6/1/2015 6/1/ Crosby County Interchange 115 kv Crosby County Interchange 69 kv 2 115/69 84/84

44 ITP $4,000,000 Reconductor 4.1 miles of 6.1-mile 115 kv line from Randall County to South Georgia. 7/31/2015 6/1/ tapping the 115 kv line from Sunset Substation to Coulter Interchange at I-40 & Soncy Street. At Soncy Sub split the converted Z33 line off the 69 kv bus and terminate to a new 115/13.2 kv transformer to serve the Soncy distribution load. Install new 115/13.2 kv distribution transformer. Randall County Interchange 115 kv South Georgia Interchange 115 kv / ITP $929,500 Leave 69 kv underground cable to Lawrence Park 6/1/2015 6/1/ Soncy Tap 115 kv New Soncy 115 kv /173 North Plainview substation. Convert North North Plainview Sub ITP $300,000 Plainview substation to 115 kv. 12/31/2014 6/1/ kv 115 Kress Rural. Convert Kress Rural substation to ITP $280,000 kv. 11/30/2014 6/1/ Kress Rural Sub 115 kv /173 Build 6 miles of double circuit 69 kv line from new Franklin substation to Mulberry - Sheffield 69 kv WR ITP $7,392,705 WR line, tapping line and connecting to Mulberry. 6/1/2014 6/1/ FRANKLIN MULBERRY 69 KV /72 Build 6 miles of double circuit 69 kv line from new Franklin substation to Mulberry - Sheffield 69 kv WR ITP $1,695,722 WR line, tapping line and connecting to Sheffield. 6/1/2014 6/1/ FRANKLIN SHEFFIELD 69 KV /72 Tap Litchfield - Marmaton 161 kv line at new WR ITP $12,204,315 WR Franklin substation 6/1/2014 6/1/ FRANKLIN / WR ITP $8,805,014 WR New 161/69 kv transformer at Franklin 6/1/2014 6/1/ FRANKLIN FRANKLIN 1 161/69 100/110 Welsh Reserve with ACSR/TW. Upgrade switches at both ends and wave traps, jumpers, AEP Regional Reliability $24,880,495 AEP CT ratios, and relay settings at Wilkes. 6/1/2019 6/1/ Welsh Reserve 138 kv WILKES 138KV /592 Replace CTs and relays at Pratt substation and St MKEC ITP $100,000 MKEC John substation 6/15/2014 6/1/ Pratt 115 KV St John 115 KV /198 Transmission Install third 345/138 kv transformer in Northwest OGE Service $15,000,000 OGE Sub 6/1/2017 6/1/ NORTHWEST NORTHWEST / /493 Transmission Accelerate installation of third 345/138 kv bus tie OGE Service $2,260,299 OGE in Northwest Sub (UID 11496). 6/1/2015 6/1/ NORTHWEST NORTHWEST / /493 Install 345/115 kv transformer between Tuco and ITP $6,158,183 new 115 kv substation (New Deal). 6/1/2018 6/1/ New-Sub-EH1 345kV New-Sub-EH1 115kV 1 345/ /474 high side of new transformer between Tuco and ITP $27,602,755 Stanton. 6/1/2018 6/1/ TUCO Interchange 345 kv New-Sub-EH1 345kV /1792 and low side of new transformer between Tuco ITP $23,362,589 and Stanton. 6/1/2018 6/1/ New-Sub-EH1 115kV Stanton Sub 115 kv /192 Install a second 230/115/13.2 kv transformer at Lubbock South Lubbock South ITP $4,679,150 Lubbock South. 12/31/2014 6/1/ Interchange 230 kv Interchange 115 kv 2 230/ / ITP $4,220,694 Build a second 230/115/13.2 kv transformer at 6/1/ Hitchland Interchange Hitchland Interchange 2 230/ / ITP $4,714,312 Reconductor 3.98 miles of Carlisle - Murphy 115 6/1/ Carlisle Interchange Murphy Sub 115 kv / ITP $3,644,914 Upgrade the Carlisle 230/115/13.2 transformer - 6/1/ Carlisle Interchange Carlisle Interchange 1 230/ /250 Potter to 230 kv and upgrade necessary terminal Potter County ITP $2,045,196 equipment at Potter. 6/1/2015 6/1/ Channing 230 kv Interchange 230 kv /541 Convert 35 miles of 115 kv line from Channing to ITP $4,796,000 new XIT substation (near Dallam) to 230 kv. 6/1/2015 6/1/ Channing 230 kv Dallam 230 kv /541 Dallam County ITP $8,849,320 Install 230/115 kv transformer at XIT substation. 6/1/2015 6/1/ Dallam 230 kv Interchange 115 kv 1 230/ / WFEC ITP $243,000 SPP Install 6 Mvar capacitor at Esquandale 69 kv. 6/1/2014 6/1/ ESQUANDALE 69 6 Mvar GRDA ITP $374,000 GRDA Add 7.2 Mvar capacitor at Sallisaw 69 kv. 6/1/ SALLISAW Mvar Install 10.9-Mvar capacitor bank at 115 kv bus at WR Zonal Reliability $1,198,694 WR Vaughn substation. 6/1/ months VAUGHN 115 KV Mvar Transmission Convert Ft. Smith 161KV to 1-1/2 breaker design OGE Service $14,000,000 OGE and install 3rd KV transformer bank. 6/1/2017 6/1/ FT SMITH FT SMITH / /493 Transmission OGE Service $100,000 OGE Upgrade CT 6/1/2017 6/1/ VBI VBI NORTH / NPPD ITP $700,000 NPPD Add a 18 Mvar capacitor bank at Clarks substation 11/1/ Clarks Mvar capacitor bank at Ainsworth substation 115 kv NPPD ITP $50,000 NPPD bus.. 11/1/ Ainsworth Mvar 115 kv substation for a total of 36 Mvar at this NPPD ITP $700,000 NPPD location. 11/1/ O'Neill Mvar NPPD ITP $677,370 NPPD Install 18 Mvar 115 kv capacitor bank at Cozad. 6/1/2014 6/1/ Cozad Mvar Milan Tap 115 kv with bundled kcmil ACSR MKEC ITP $2,501,569 MKEC conductor (Bunting) 3/1/ CLEARWATER 138KV Milan Tap 138 KV /314 tap 115 kv with bundled kcmil ACSR WR ITP $11,839,190 WR conductor (Bunting) 3/1/ CLEARWATER 138KV Milan Tap 138 KV /314 Transmission kcmil ACSR to achieve a minimum 1200 amp BURLINGTON JUNCTION COFFEY COUNTY NO WR Service $2,951,558 WR emergency rating. 6/1/2014 7/1/ KV WESTPHALIA 69 KV /147

45 WR Transmission Service $1,400,000 WR Add 6 Mvar Cap bank at Altoona East 6/1/2015 6/1/ ALTOONA EAST 69 KV 69 6 Mvar NPPD ITP $5,645,881 NPPD Replace 187MVA Ogallala transformer with 336MVA Ogallala transformer 6/1/2014 6/1/ OGALLALLA Ogallala 1 230/ / WR Transmission Service $700,000 WR Replace disconnect switches, wavetrap and CT 6/1/2016 6/1/ HALSTEAD SOUTH BUS 138 KV NO. 12 COLWICH 138 KV / AEP ITP $1,166,400 AEP Install a new 28.8 MVAR capacitor bank at Winnsboro 138 kv substation. 6/1/2016 6/1/ Winnsboro 138 kv Mvar AEP ITP $1,166,400 AEP Install 28.8 MVAR capacitor bank at Logansport 138 kv substation. 6/1/2016 6/1/ LOGANSPORT 138KV Mvar MKEC Transmission Service $150,000 MKEC Replace CTs and relays at Jewell substation and Smith Center substation 6/1/2018 6/1/ Jewell Smith Center 115 KV /88 Transmission WFEC Service $4,800,000 WFEC UPGRADE CANTON TO TALOGA TO /1/2015 6/1/ TALOGA CANTON / WFEC Transmission Service $1,000,000 WFEC Replace Taloga 138/69 kv auto transformer with 112 MVA. 6/1/2015 6/1/ TALOGA TALOGA 1 138/69 112/112 Riley 115 kv line with Single kcmil ACSR Clay Center Switching WR Zonal Reliability $9,308,090 WR (Bunting). 6/1/ /1/ Station 115 kv Riley / WR Zonal Reliability $963,441 WR Install a 2000 Amp bus system, GOAB switches, metering and communication systems. 6/1/ /1/ Riley 115 Lamb County REC-Opdyke ITP $944,754 Install 28.8 Mvar capacitor at Lamb County 69 kv. 6/1/ Sub 115 kv Mvar ITP $697,688 Install 14.4 MVAR capacitor at Eagle Creek 115 6/1/ Eagle Creek 115 kv Mvar ITP $1,683,176 Install 14.4 Mvar capacitor at Drinkard 115 kv. 6/1/2015 6/1/ Drinkard Sub 115 kv Mvar AEP Generation Interconnection $150,000 AEP Replace transmission line relays protecting the terminal to a new WFEC 138 kv switching station being built for Windfarm66 LLC CLINTON JUNCTION 138KV AEP ITP $21,664,838 AEP Upgrade the Cornville 138 kv bus to breaker-anda-half configuration in preparation for the 138 kv line conversion to Lindsay Water substation. 12/31/2014 6/1/ CORNVILLE 138KV WR ITP $29,507,894 WR Upgrade Auburn Road 230/115 kv transformer to 6/1/2014 6/1/ AUBURN ROAD 115 KV AUBURN ROAD 230 KV / ITP $985,519 Install 14.4 Mvar capacitor at Crosby 115 kv. 3/30/2014 6/1/ Crosby County Interchange 115 kv Mvar AEP ITP $1,428,440 AEP Install 6 Mvar capacitor at Coweta 69 kv. 6/1/2014 6/1/ COWETA 69 6 Mvar ITP $56,981,082 Grassland, and install terminal equipment at Grassland and Wolfforth substations. 3/1/2018 3/1/ Wolfforth Interchange 230 kv Grassland Interchange 230 kv / ITP $5,400,001 Install new 115/69 kv transformer at new Diamondback Interchange near Cedar Lake. 6/30/2015 6/1/ Cedar Lake 115 kv Adair Tap 69 kv / ITP $8,000,000 Interchange to Diamondback Interchange near Cedar Lake. 6/30/2015 6/1/ Sulphur Interchange 115 kv Cedar Lake 115 kv / MKEC ITP $13,151,512 MKEC Build 21-mile new 115 kv line from Ellsworth to the Midwest Energy's Bushton substation. 6/1/2015 6/1/ RICE COUNTY 115 KV Ellsworth 115 KV / MKEC ITP $5,914,221 MKEC Install 3-breaker ring bus at Ellsworth Tap 115 kv. 6/1/2015 6/1/ Ellsworth Tap / MKEC ITP $2,669,385 MKEC Expand Ellsworth Substation to include two new 115 kv breakers for the new 115 kv line to Rice. 6/1/2015 6/1/ Ellsworth 115 KV MIDW ITP $1,459,629 MIDW substation to accommodate the new 115 kv line from Ellsworth. 6/1/2015 6/1/ Bushton 115 kv / AEP ITP $157,599,160 AEP substation to point of interconnection with OGE towards Gracemont. The approximate line length for the Chisholm - Gracemont 345 kv line is 100 miles, of which AEP will construct approximately 70 miles from Chisholm to the OGE 3/1/ Chisholm 345 kv Gracemont 345kv / AEP ITP $25,168,480 AEP between existing 230 kv substations, Sweetwater and Elk City. Cut-in existing Sweetwater - Elk City 230 kv Ckt 1 line into new Chisholm substation and install any necessary 230 kv terminal equipment. Install new 345/ MVA transformer at new Chisholm substation. 3/1/ Chisholm 345 kv Chisholm 230 kv / OGE ITP $43,853,500 OGE Build OGE's portion of new 345 kv line from Elk City to Gracemont. 3/1/2018 3/1/ Chisholm 345 kv Gracemont 345kv /1792 transmission line for a cut-in to the existing Sweetwater - Elk City 230 kv line, creating AEP ITP $5,326,722 AEP termination points at the new Chisholm 3/1/ CHISHOLM /1792 Build 55 mile new 345 kv line from Welsh to Lake AEP ITP $100,504,688 AEP Hawkins (or Perdue). 3/1/ Lake Hawkins 345 kv WELSH / AEP ITP $16,666,456 AEP Expand Lake Hawkins (or Perdue) substation (or build new station). Install a 345/138 kv transformer at Lake Hawkins (or Perdue). 3/1/ Lake Hawkins 345 kv LAKE HAWKINS 1 345/ /675

46 OGE ITP $15,990,000 SPP Reconductor 26 mile Glass Mountain - Mooreland line to 795 AS33 3/1/ MOORELAND GLASS MOUNTAIN /287 Build second circuit of new 49-mile 345 kv line OGE ITP $59,522,400 OGE from Woodward District EHV to Tatonga. 3/1/2021 3/1/ Woodward EHV 345kv Tatonga 345kv / OGE ITP $65,785,650 OGE Build second circuit of new 61-mile 345 kv line from Tatonga to new Matthewson substation. 3/1/2021 3/1/ Tatonga 345kv MATHEWSON / OGE ITP $32,936,400 OGE from the new Matthewson substation to Cimarron. 3/1/2021 3/1/ MATHEWSON CIMARRON / OGE ITP $19,967,850 OGE intersection of the Woodring - Cimarron and Northwest - Tatonga 345 kv lines. 3/1/2021 3/1/ MATHEWSON /1792 Prairie Lee 161 kv to 795 ACSS. Upgrade GMO ITP $3,039,096 KCPL substation equipment to 2000 Amps. 6/1/2018 6/1/ Blue Spring South 161 KV Prairie Lee 161 KV / GMO ITP $2,399,248 KCPL Reconductor 2.5 mile from Blue Springs South - Blue Springs East 161 kv to 795 ACSS. Upgrade substation equipment to 2000 Amps. 6/1/2018 6/1/ Blue Springs East 161 KV Blue Spring South 161 KV /558 Build new 345 kv line from the Elm Creek substation to the Westar Energy, Inc. interception ITCGP ITP $31,312,169 ITCGP point from the Summit substation. 3/1/2018 3/1/ Elm Creek 345 kv SUMMIT 345 KV / ITCGP ITP $5,405,101 ITCGP Install new 345/230 kv transformer at Elm Creek. 12/31/2016 3/1/ Elm Creek 345 kv Elm Creek Substation 1 345/ / ITCGP ITP $8,243,291 ITCGP Install terminal equipment on the 345 kv side of the Elm Creek substation. 12/31/2016 3/1/ Elm Creek 345 kv ITCGP ITP $1,886,035 ITCGP Install terminal equipment on the 230 kv side of the Elm Creek substation. 12/31/2016 3/1/ Elm Creek Substation WR ITP $66,202,442 WR Build new 345 kv line from the Summit substation to the ITC Great Plains, LLC interception point from the Elm Creek substation. 12/31/2016 3/1/ Elm Creek 345 kv SUMMIT 345 KV /1792 Chapman 115 kv line as single circuit with WR ITP $11,501,055 WR bundled 1192 ACSR conductor. 6/1/ EAST ABILENE 115 KV CHAPMAN 115 KV / WR ITP $3,806,178 WR Center 115 kv as single circuit with bundled 1192 ACSR conductor. 6/1/ EAST ABILENE 115 KV ABILENE ENERGY CENTER 115 KV / WR ITP $19,949,242 WR Northview 115 kv as single circuit with bundled 1192 ACSR conductor. 6/1/ ABILENE ENERGY CENTER 115 KV NORTHVIEW 115 KV / WR ITP $5,131,249 WR kv as single circuit with bundled 1192 ACSR conductor. 6/1/ NORTH STREET 115 KV NORTHVIEW 115 KV / WR ITP $19,770,066 WR Install second 138/115 kv transformer at 12/1/2014 6/1/ MOUNDRIDGE 138 KV MOUNDRIDGE 115 KV 2 138/ /125 Reconductor Okeene - Dover Switching Station WFEC ITP $16,666,500 SPP 138 kv to 795 ACSS. 3/1/ DOVER SW OKEENE / NPPD Regional Reliability $68,774,278 NPPD Build a new 41-mile 345 kv line from Hoskins to 6/1/2016 6/1/ months Hoskins 345 kv Neligh 345 kv / NPPD Regional Reliability $12,118,564 NPPD 345/115 kv transformer and all necessary 345 kv equipment at Neligh. 6/1/2016 6/1/ months Neligh 345 kv Neligh 115 kv 1 345/ / WR Regional Reliability $20,530,196 WR south of Junction City where JEC - Summit 345 kv and McDowell Creek - Junction City #2 115 kv circuits separate. Install 345/115 kv 440 MVA transformer and 115 kv terminal equipment. 6/1/2017 6/1/ months Geary County 345 kv Geary County 115 kv 1 345/ / NPPD ITP $139,090,440 NPPD Gentleman Station substation to new Cherry County substation. This upgrade is contingent upon approval from Western Area Power Administration ("WAPA") to tap the Grand Island - Fort Thompson 345 kv line. 1/1/2018 1/1/ Cherry County 345 kv install necessary terminal equipment. This upgrade is contingent upon approval from WAPA to tap the Grand Island - Fort Thompson 345 kv Gerald Gentleman Station / NPPD ITP $11,896,383 NPPD line. 1/1/2018 1/1/ Cherry County 345 kv 345 County substation to new Holt County substation. This upgrade is contingent upon approval from WAPA to tap the Grand Island - Fort Thompson NPPD ITP $146,065,000 NPPD 345 kv line. 1/1/2018 1/1/ Cherry County 345 kv Holt County 345 kv /1792 the Grand Island - Fort Thompson 345 kv line owned by WAPA. Install necessary terminal equipment at new substation. This upgrade is contingent upon approval from WAPA to tap the NPPD ITP $16,324,800 NPPD Grand Island - Fort Thompson 345 kv line. 1/1/2018 1/1/ Holt County 345 kv ITP $88,198,879 Build new 67-mile 345 kv line from Tuco to 1/1/2020 1/1/ TUCO Interchange 345 kv Amoco 345 kv /1792 Station 230 kv (Amoco ITP $21,629,389 Install new 345/230 kv transformer at Amoco. 1/1/2020 1/1/ Amoco 345 kv Slaughter) / ITP $10,262,813 Install new 345/230 kv transformer at Hobbs. 1/1/2020 1/1/ Hobbs 345 kv Hobbs Interchange / /448 Build new 100 mile Amoco - Hobbs 345 kv line ITP $137,452,487 Expand the Hobbs substation. 1/1/2020 1/1/ Amoco 345 kv Hobbs 345 kv / ITP $1,581,080 Reconductor 1.5 miles line from Indiana to 6/1/ Indiana Sub 115 kv Stanton Sub 115 kv /240

47 ITP $1,604,810 Reconductor 4 miles from Indiana to SP-Erskine. 6/1/ Indiana Sub 115 kv South Plains REC /240 Generation New 138 kv three breaker ring bus substation containing kv circuit breakers, associated disconnect switches, structures, relaying, grounding, fencing, and all associated and miscellaneous equipment. Required in mitigation of SPP Affected Facilies from new AECI GI project GRDA Interconnection $2,500,000 GRDA located near Burbank, OK. SPP STUDY ID - ASGI- 6/1/ GRDA Generation Interconnection $11,900,000 GRDA rebuild existing 69 kv line from Fairfax - Pawnee, approximately 19.5 miles with double circuit towers for double circuit 138 kv line. One side will be operated at 69 kv. Required in mitigation of SPP Affected Facilities from new New GI project near Burbank, OK. SPP study ID - ASGI /31/ Fairfax Shidler substation with 4 breaker ring. Provide Terminal for KAMO's 138kV line from Remington Station. Replace ground switch and circuit switcher, Move terminal for OG&E Osage 138kV line. Replace relay panels for OGE Osage and AEP Mound Road line terminals. Install 138kV meter transformers and meter at Shidler station. Install relay panel, line trap and RTU at Mound Road station for line to Shidler station.required in mitigation of SPP Affected Facilities from new 2/8/ SHIDLER AEP Generation Interconnection $5,728,000 ties Construction terminal primary and redundant relaying with SEL uprocessor based relays, install 3-138kV PTs, Generation Install 1-138kV CB, Install metering, Install 2000A OGE Interconnection $399,300 es Construction line Trap 1/15/ OSAGE 138 Replace 161kV, 1200A switch with a 2000A Switch GRDA Regional Reliability $161,100 GRDA at Kerr substation bus. 6/1/2017 6/1/ months SUB KERR /432 Build new 28 miles 345 kv Cass Co. - S.W. Omaha OPPD ITP $33,126,800 SPP (aka S3454) and associated terminal equipment 1/1/ Sub Sub / OPPD ITP $12,600,000 SPP Install 2nd 345/161 kv 560 MVA S3459 1/1/ Sub Sub / /560 Rebuild 49-mile 69 kv line between Bowers and ITP $36,000,000 Canadian with 795 ACSR conductor. 6/1/2015 6/1/ Bowers Interchange 69 kv Canadian Sub 69 kv /69 Replace existing Howard 115/69 kv transformer ITP $1,554,313 with new 84 MVA transformer. 6/1/ /1/ Howard 115 kv Grave Sub 69 kv 1 115/69 84/84 Add two banks of 7.2 Mvar capacitors at the Kingsmill Interchange ITP $815,598 Kingsmill Interchange 115 kv substation. 12/31/2014 6/1/ kv Mvar Replace 230/115 kv transformer at Grapevine Grapevine Interchange Grapevine Interchange ITP $3,216,093 substation with 250 MVA transformer. 6/1/2014 6/1/ kv kv 1 230/ /250 Add two banks of 14.4 Mvar capacitors at the ITP $1,127,389 Howard 115 kv substation. 6/1/2014 6/1/ Howard 115 kv Mvar second circuit between North Ft Dodge and Spearville. Reroute Ft. Dodge - Greensburg 115 kv to North Ft. Dodge Substation. Build second Generation circuit between Ft. Dodge and North Ft Dodge North Judson Large MKEC Interconnection $28,200,834 MKEC (these stations are very close to each other). 11/8/ Judson Large 115 KV kv Sub Needed as Network Upgrade for GEN MKEC Generation Interconnection $31,460,024 MKEC but cost shared with GEN & previously with GEN prior to project withdrawal. 11/8/ SPEARVILLE Spearville 115 KV 1 345/ ITP $4,236,816 Upgrade Deaf Smith County Interchange 230/115 kv Ckt 1 transformer to 250 MVA. 3/1/2015 6/1/ Deaf Smith County Interchange 230 kv Deaf Smith County Interchange 115 kv 1 230/ / ITP $4,225,233 Upgrade Deaf Smith Interchange 230/115 kv transformer Ckt 2 to 250 MVA. 3/1/2015 6/1/ Deaf Smith County Interchange 230 kv Deaf Smith County Interchange 115 kv 2 230/ / ITP $11,600,000 Rebuild 16.9-mile 115 kv line from Ochiltree to Tri- County REC Cole Ckt 1. 12/31/2015 6/1/ Ochilltree Interchange 115 kv Cole Interchange 115 kv / MIDW ITP $11,128,231 MIDW Run to Seguin and install necessary terminal equipment at Pheasant Run and Seguin substations. 6/1/2014 6/1/ PHEASANT RUN 115 KV / ITP $22,191,845 Rebuild 25.8-mile 115 kv line from Crosby to Floyd Ckt 1. 3/1/2015 6/1/ Crosby County Interchange 115 kv Floyd County Interchange 115 kv / ITP $1,731,323 Install two 14.4 Mvar capacitors at Floyd 115 kv substation. 12/31/2014 6/1/ Floyd County Interchange 115 kv Mvar WR ITP $5,561,163 WR Rebuild 3.1-mile 138 kv line from El Paso to 6/1/2014 6/1/ EL PASO 138 KV FARBER 138 KV / AEP ITP $1,000,000 AEP Replace 138 kv breaker at Perdue. 6/1/2016 6/1/ NEW GLADEWATER PERDUE 138KV /272

48 WR Regional Reliability $27,938,225 WR Build new 15.1-mile 115kV line between the new Geary County substation and Chapman Tap miles of the line will be built as a 2nd circuit to the existing Summit - McDowell Creek 345 kv line. 6/1/2017 6/1/ months Geary County 115 kv CHAPMAN 115 KV / GRDA Regional Reliability $161,100 GRDA Replace 161kV, 1200A switch with a 2000A switch at Kansas Tap substation. 6/1/2018 6/1/ months SUB KANSAS TAP / WR Regional Reliability $16,190,561 WR Install 345 kv ring bus at the new Geary County 6/1/ months Geary County 345 kv / NPPD Regional Reliability $5,800,000 NPPD Stegall substation and necessary terminal equipment at the 115 kv bus. This upgrade is contingent upon approval from Basin Electric to connect to the Stegall 345 kv substation that they operate. 6/1/ months STEGALL 345 kv Stegall 115 kv 1 345/ / NPPD Regional Reliability $23,782,900 NPPD Install new 22-mile 115 kv line from Stegall to Scottsbluff and install any necessary terminal equipment. This upgrade is contingent upon Basin Electric's approval noted in Upgrade ID /1/ months Stegall 115 kv Scottsbluff / NPPD Regional Reliability $5,417,100 NPPD 345 kv bus in Stegall substation. This upgrade is contingent upon Basin Electric's approval noted in Upgrade ID /1/ months STEGALL 345 kv ITP $20,808,304 Build new 12-mile 115 kv line from Atoka to Eagle Creek and install necessary terminal equipment. 12/31/2016 6/1/ Atoka Interchange 115 kv Eagle Creek 115 kv / ITP $2,160,976 Upgrade Potash Junction 115/69 kv transformer Ckt 1 to 84 MVA. 12/31/2014 6/1/ Potash Junction Interchange 115 kv Potash Junction Interchange 69 kv 1 115/69 84/ ITP $2,147,773 Upgrade Potash Junction 115/69 kv transformer Ckt 2 to 84 MVA. 12/31/2014 6/1/ Potash Junction Interchange 115 kv Potash Junction Interchange 69 kv 2 115/69 84/ ITP $5,136,476 station east of Kilgore substation to South Portales and install necessary terminal equipment. 6/1/2018 6/1/ Zodiac Sub 115 kv S Portales 115 kv / ITP $6,498,682 to Market St. and install necessary terminal equipment. 6/1/2018 6/1/ S Portales 115 kv Market ST 115 kv / ITP $15,394,429 to Portales and install necessary terminal equipment. 6/1/2018 6/1/ Market ST 115 kv Portales Interchange 115 kv / AEP ITP $16,548,317 AEP Rebuild 13.2-mile 69 kv line from Dekalb to New Boston with ACSR/TW. Upgrade CT ratios and relay settings at New Boston. 6/1/2015 6/1/ NEW BOSTON DEKALB / AEP ITP $7,519,658 AEP Rebuild 1.6-mile 69 kv line from Hardy Street to Waterworks with ACSR/TW. 6/1/2015 6/1/ HARDY STREET WATERWORKS / AEP ITP $1,829,026 AEP North Huntington with ACSR/TW. Upgrade CT ratios, relay settings, and jumpers at North Huntington. 6/1/2015 6/1/ MIDLAND REC NORTH HUNTINGTON 69KV / AEP ITP $5,653,353 AEP Midland REC with ACSR/TW. Upgrade CT ratios, relay settings, switches, and station conductors at Midland. 6/1/2015 6/1/ MIDLAND MIDLAND REC / AEP ITP $9,145,130 AEP Howe Interchange to Midland with ACSR/TW. The portion of line to be rebuilt is from the state line to Midland. Upgrade CT ratios, relay settings, switches, and station conductors at Midland. 6/1/2015 6/1/ HOWE INT MIDLAND / GRDA Zonal Reliability $355,000 GRDA Increase line clearance for Chelsea - Childers 69 6/1/2015 6/1/ CHELSEA CHILDERS / OPPD ITP $260,590 OPPD Rebuild 1.6-mile 69 kv line from 915 Tap South to 6/1/2015 6/1/ Tap in Ckt Sub 915 T2 Primary / OGE Transmission Service $10,000 OGE Replace 400 amp CT in El Reno sub with 800 amp. 6/1/2017 6/1/ EL RENO SERVICE PL EL RENO / WR ITP $7,122,480 WR Install a third 138/69 kv transformer at Gill Energy Center. 12/1/2015 6/1/ GILL ENERGY CENTER SOUTH 138 KV GILL ENERGY CENTER EAST 69 KV 1 138/69 150/ WR ITP $14,331,670 WR Install new 345/138 kv transformer at Viola 6/1/2016 6/1/ Viola Viola 138kV 1 345/ / WR ITP $35,992,903 WR Build new 21.8-mile 138 kv line from new Viola substation to Clearwater 138 kv substation. 6/1/2016 6/1/ Viola 138kV CLEARWATER 138KV / WR ITP $22,234,744 WR Build new 27.9-mile 138 kv line from new Viola substation to Gill 138 kv substation. 6/1/2016 6/1/ Viola 138kV GILL ENERGY CENTER WEST 138 KV / WR ITP $5,007,657 WR Install 345 kv breakers at Viola substation. 6/1/2016 6/1/ Viola / OGE ITP $3,079,700 OGE Build 400 MVA 345/138 kv bus tie transformer at 3/15/2014 3/1/ / / OGE ITP $11,659,600 OGE Build substation at Renfrow and tap Woodring- Wichita 345 kv line. 3/15/2014 3/1/ OGE ITP $4,998,388 OGE Build Grant County substation on the 69 kv line between the Koch and Medford substations. 3/15/2014 3/1/ OGE ITP $1,173,170 OGE Install a 138/69 kv transformer at Grant County 5/1/2014 3/1/ /69 100/ OGE ITP $4,540,425 OGE Build 138 kv line from Renfrow to Grant County 10/1/2014 3/1/ OGE ITP $587,690 OGE Convert Koch 69 kv substation to 138 kv. 9/1/2014 3/1/ WR Zonal Reliability $767,165 WR Install 9.6 Mvar capacitor bank at Potwin 69 kv 6/1/2014 6/1/ POTWIN 69 KV Mvar

49 WFEC ITP $2,000,000 WFEC Renfrow. The total mileage of this Renfrow to Sandridge Tap 138 kv line is 4 miles. Western Farmers Electric Cooperative and Oklahoma Gas and Electric Co. shall decide who shall build how much of these Network Upgrades and shall provide such information, along with specific cost estimates for each Designated Transmission Owner's portion of the Network Upgrades, to SPP 3/31/2014 1/1/ WFEC ITP $237,000 WFEC Install two 4.8 Mvar capacitors at Fairview 69 kv for total of 9.6 Mvar. 2/1/2014 1/1/ Install two 4.8 Mvar capacitors at Hazelton 69 kv WFEC ITP $237,000 WFEC for total of 9.6 Mvar. 2/1/2014 1/1/ HAZELTON MIDW ITP $8,832,219 MIDW Rebuild 3.25-mile 115 kv line from Hays Plant to 6/1/2015 6/1/ HAYS PLANT 115 KV SOUTH HAYS 115 KV / AEP ITP $30,369,537 AEP Carrol, Clarence, and Western Kraft 230 kv lines. Install 500/230 kv 675 MVA transformer. This upgrade is contingent upon approval from Cleco Power LLC. 12/31/2015 6/1/ Messick 500 kv / / AEP ITP $21,508,234 AEP Messick substation. Connect to Mt. Olive - Hartburg 500 kv line. This upgrade is contingent upon approval from Cleco Power LLC for Upgrade ID /31/2015 6/1/ Messick 500 kv NPPD Regional Reliability $5,417,100 NPPD 345 kv bus in Stegall substation. This upgrade is contingent upon Basin Electric's approval noted in Upgrade ID /1/ months STEGALL 345 kv kv bus in the new Neligh substation. Construct approximately 18 miles of new 115 kv transmission to tie Neligh East 345/115 kv into NPPD Regional Reliability $17,804,878 NPPD the existing 115 kv transmission system 6/1/2016 6/1/ months Neligh 115 kv Regional Reliability $973,674 Rebuild 0.5 miles of 115 kv line from OXY Permian Sub to West Bender Sub. 6/1/2018 6/1/ OXY Permian Sub 115 kv West Bender Sub 115 kv / WFEC ITP $1,500,000 WFEC Reconductor Buffalo Bear - Buffalo 69 kv line with 7/1/ /1/ BUFFALO BUFFALO BEAR / WFEC ITP $6,000,000 WFEC Reconductor Ft. Supply - Buffalo Bear 69 kv line 7/1/ /1/ FT SUPPLY BUFFALO BEAR / MKEC ITP $9,613,332 MKEC Reconductor 22.1 mile Harper to Milan Tap 138 3/1/ Harper 138 KV Milan Tap 138 KV / OGE ITP $3,195,056 OGE Build new 4-mile 138 kv line from Renfrow to 5/1/2014 5/1/ / WFEC ITP $3,540,000 WFEC Creek substation to Oklahoma Gas and Electric Co. interception point going towards Medford Tap. 2/28/2014 5/1/ / OGE ITP $13,765,950 OGE Build new 22-mile 138 kv line from Medford Tap to new Doolin substation. 12/1/2015 6/1/ / OGE ITP $8,164,117 OGE Build new 5-mile 138 kv line from Chikaskia to new Doolin substation. 12/1/2015 5/1/ / OGE ITP $3,041,661 OGE Build new 138 kv Doolin switching station. 12/1/2015 5/1/ / OGE ITP $185,400 OGE Install new 138 kv three-way transmission line switch at Medford Tap. 5/1/2014 5/1/ / WFEC ITP $185,004 WFEC Install new 138 kv 4.8-Mvar capacitor at Renfrow- Sandridge substation. 6/1/ Mvar WFEC ITP $185,004 WFEC Install new 69 kv 4.8-Mvar capacitor at Hazelton 6/1/ Mvar upgrade relays at both Butler and Weaver to get WR Regional Reliability $200,046 WR to 160 MVA conductor limit. 6/1/ WEAVER 138 KV Butler 138kV /160 Install 4-breaker ring bus to connect the Cunningham - PCA Interchange 115 kv line and Regional Reliability $2,593,936 the Lea National - Maljamar 115 kv line. 6/1/2015 6/1/ Quahada 115 kv WR Regional Reliability $258,795 WR trap at McDowell Creek Substation to a minimum of 1200 Amps. 6/1/2014 6/1/ transformers with a single transformer with a minimum emergency rating of 165 MVA. Then, reterminate the Neosho 345/138 kv #1 transformer from to This will move the 138 kv connection of this transformer from the Neosho South 138 kv SWITCHING STATION 115 KV / WR Regional Reliability $8,878,557 WR bus (533020) to the Neosho 138 kv center bus 6/1/2016 6/1/ NEOSHO 138 KV NEOSHO 69 KV 1 345/ /165 Rebuild 4.4 miles of 138 kv line from Chapel Hill AEP Regional Reliability $6,651,694 AEP REC to Welsh Reserve 138 kv. 6/1/2019 6/1/ ChapelL Hill REC 138 kv Welsh Reserve 138 kv / WR Zonal Reliability $51,513,963 WR Build new 28-mile 138 kv line from Viola to 6/1/2019 6/1/ SUMNER COUNTY 138 kv Viola 138kV /314 Install new 161/69 kv auto transformer and 69kV OPPD Zonal Reliability $4,426,730 OPPD terminal equipment. 6/1/ SUB kV /69 200/200 Reconductor 9-mile 138 kv line from Red Hills to RED HILLS WIND FARM WFEC Regional Reliability $3,675,000 WFEC Elk City. 6/1/ BUS 138 kv ELK CITY / WFEC Regional Reliability $504,000 WFEC Add 20 Mvar of capacitors at Sandy Corner 138 5/1/2017 6/1/ months Sandy Corner 138 kv Mvar

50 SEPC Regional Reliability $4,812,363 SEPC Install 24-Mvar capacitor at Mingo substation. 6/1/ months MINGO Mvar North Platt substations to 1200 Amp to increase NPPD Regional Reliability $30,000 NPPD line rating to 215 MVA. 6/1/2014 6/1/ months North Platte 115 kv Maxwell 115 kv / WR Zonal Reliability $1,390,166 WR Regional Reliability $35,007, Regional Reliability $8,989,747 Install 10.8-Mvar capacitor bank at Clay Center Switching Station (bus# ). 6/1/2016 6/1/ Clay Center Switching Station 115 kv Mvar Junction Interchange to new Road Runner substation. Install any necessary 230 kv terminal equipment at Potash Junction Interchange and Potash Junction Road Runner. 12/1/2015 6/1/ Interchange 230 kv Road Runner 230 kv / /115 kv 250 MVA transformer and 115 kv terminal equipment. 12/1/2015 6/1/ Road Runner 230 kv Road Runner 115 kv 1 230/ / AEP Regional Reliability $6,695,986 AEP AEP Regional Reliability $2,819,806 AEP AEP Regional Reliability $8,851,677 AEP AEP Regional Reliability $15,248,925 AEP Regional Reliability $4,701, Regional Reliability $4,158, Regional Reliability $5,415, Regional Reliability $6,941,335 SPP AEP Regional Reliability $8,851,677 AEP AEP Regional Reliability $15,248,925 AEP Regional Reliability $4,701, Regional Reliability $4,158, Regional Reliability $5,415, Regional Reliability $6,941,335 SPP WR Regional Reliability $7,405,817 WR Rebuild 1.7-mile 69 kv line from Fort Humbug to Broadmoor with ACSR/TW. Upgrade jumpers at Fort Humbug and jumpers and bus at Broadmoor. 6/1/2019 6/1/ BROADMOOR FORT HUMBUG 69KV /143 Rebuild 1.3-mile 69 kv line from Daingerfield to Jenkins REC T with ACSR/TW. 6/1/2019 6/1/ DAINGERFIELD JENKINS REC T /178 to Hallsville with ACSR/TW. Upgrade jumpers, CT ratios, and relay settings at Longview Heights. 6/1/2017 6/1/ HALLSVILLE Rebuild 11.2-mile 69 kv line from Hallsville to Marshall with ACSR/TW. Upgrade LONGVIEW HEIGHTS 69KV /89 jumpers, CT ratios, and relay settings at Marshall. 6/1/2017 6/1/ MARSHALL 69KV HALLSVILLE /89 converting to 115 kv. Install necessary terminal Chaves County equipment at Chaves. 12/30/2017 6/1/ Interchange 115 kv PRICE kv /250 Rebuild 3-mile 69 kv line from Price to CV Pines converting to 115 kv. 6/1/2017 6/1/ PRICE kv CV-PINES kv /245 Rebuild 5-mile 69 kv line from CV Pines to Capitan converting to 115 kv. 1/30/2016 6/1/ CV-PINES kv Capitan 115 kv /265 Bailey Pump. Install necessary terminal Bailey County Interchange equipment at Bailey County. 6/1/ kv Bailey Pump 115 KV /304 to Hallsville with ACSR/TW. Upgrade jumpers, CT ratios, and relay settings at Longview LONGVIEW HEIGHTS Heights. 6/1/2017 6/1/ HALLSVILLE KV /89 Rebuild 11.2-mile 69 kv line from Hallsville to Marshall with ACSR/TW. Upgrade jumpers, CT ratios, and relay settings at Marshall. 6/1/2017 6/1/ MARSHALL 69KV HALLSVILLE /89 converting to 115 kv. Install necessary terminal Chaves County equipment at Chaves. 12/30/2017 6/1/ Interchange 115 kv PRICE kv /250 Rebuild 3-mile 69 kv line from Price to CV Pines converting to 115 kv. 6/1/2017 6/1/ PRICE kv CV-PINES kv /245 Rebuild 5-mile 69 kv line from CV Pines to Capitan converting to 115 kv. 1/30/2016 6/1/ CV-PINES kv Capitan 115 kv /265 Bailey Pump. Install necessary terminal Bailey County Interchange equipment at Bailey County. 6/1/ kv Bailey Pump 115 KV /304 Sumner County No. 4 Rome with single 1192 ACSR conductor to achieve 1200 Amp minimum ampacity. 6/1/2016 6/1/ Rebuild 9.43-mile 69 kv line from Creswell to Sumner County No. 4 Rome with single 1192 SUMNER COUNTY NO. 4 ROME 69 KV CITY OF WELLINGTON 69 KV /96 SUMNER COUNTY NO. 4 ROME 69 KV / WR Regional Reliability $7,988,648 WR ACSR conductor to achieve 1200 Amp. 12/1/2015 6/1/ CRESWELL 69 KV Pump to Sundan Rural and covert Bailey Pumb and Sundan Rural distribution transformer high Regional Reliability $6,941,335 SPP side from 69 to 115 kv. 6/1/ Bailey Pump 115 KV Sundan Rural 115 kv / WR Regional Reliability $7,752,352 WR Rebuild 5.64-mile 69 kv line from Crestview to 6/1/2015 6/1/ NORTHEAST 69 KV CRESTVIEW 69 KV /143 Install new 115/69 kv transformer 84 MVA. Lamb County Sandhill 115 Lamb County REC Regional Reliability $3,000,000 SPP Install necessary 69 kv terminal equipment. 6/1/ kv Sandhill 115 kv 1 115/69 84/84 Build 4.1-mile 115 kv line from Sudan Rural to Lamb County REC Sandhill. Install 115 kv terminal Lamb County Sandhill Regional Reliability $2,845,947 SPP equipment for new 115/69 kv transformer. 6/1/ Sundan Rural 115 kv kv / WR Regional Reliability $2,829,128 WR Regional Reliability $1,804,747 SPP single 1192 ACSR to achieve 1200 Amp minimum ampacity. 6/1/2016 6/1/ NORTHEAST 69 KV KEN MAR 69 KV /143 Build 2.6-mile 115 kv line from Lamb County REC Sandhill to Amherst. Convert Amherst distribution Lamb County Sandhill 115 transformer high side from 69 kv to 115 kv. 6/1/ kv Amherst 115 kv /304

51 Regional Reliability $3,401,254 SPP Regional Reliability $4,858,935 SPP Build 4.9-mile 115 kv line from Amherst to West Littlefield. Convert West Littefield distribuition transformer high side from 69 kv to 115 kv. 6/1/ Amherst 115 kv West Littlefield 115 kv /304 Build 7-mile 115 kv line from West Littlefield to Lamb County converting. Install necessary terminal equipment at Lamb County. 6/1/ West Littlefield 115 kv Install a 9-Mvar capacitor bank at either County Lamb County Interchange 115 kv / OGE Regional Reliability $740,254 OGE Line or Wildhorse substation. 6/1/2017 6/1/ months County Line 69 kv 69 9 Mvar Rebuild 9.7-mile 69kV line from Elk Junction to WR Zonal Reliability $10,537,806 WR Montgomery to 72 MVA. 6/1/2018 6/1/ MONTGOMERY 69 KV ELK JUNCTION 69 KV /72 Rebuild 18.8-mile 69kV line from Elk Junction to CANEY VALLEY NO WR Zonal Reliability $32,548,502 WR Sedan to 72 MVA. 6/1/2018 6/1/ ELK JUNCTION 69 KV SEDAN 69 KV /72 Harrisonville including any 69 kv terminal GMO Regional Reliability $2,773,480 GMO equipment. 1/30/2014 6/1/ Harrisonville 161 KV Harrisonville 69 KV 2 161/69 50/55 New 161/69 kv transformer at Fremont to OPPD OPPD Regional Reliability accommodate a new 161 kv interconnection. 6/1/ S kV S kV 161/ /134.4 $5,601,611 Build new 3-mile 69 kv line from Fremont to new OPPD OPPD Regional Reliability substation S /1/ Fremont Sub B S kV 161/ /144 Build new 17-mile 161 kv line from S1226 to new OPPD Regional Reliability $29,069,150 OPPD substation S /1/ Sub S kV /377 Rebuild 1.34-mile 69 kv line from S906 to S OPPD Regional Reliability $1,360,327 OPPD with a new rating of 143 MVA. 6/1/ Sub 906 South Bus Sub /143 Substation improvements to increase S924 - S OPPD Regional Reliability $69,679 OPPD 69 kv rating to 99 MVA. 6/1/ Sub Sub /99 Add an additional 12 Mvar of capacitance at SEPC Regional Reliability $2,791,167 SEPC Ruleton substation. 6/1/ months RULETON Mvar Convert Hereford distribution transformer high Hereford Interchange Regional Reliability $93,130 side from 69 kv to 115 kv. 12/15/2015 6/1/ kv 115 Broken Bow Wind and install necessary termal NPPD Regional Reliability $32,244,000 NPPD equipment. 6/1/ months Broken Bow Wind Ord /176 across the street from Knobhill sub. Install a new 138 kv terminal in Knobhill substation. Tie the new LANE substation and the existing Knobhill substations together with one span of 138 kv line. WFEC to eliminate the double circuit portion of the 138 kv Mooreland Noel and the 138 kv Noel Knobhill and return the 138 kv Mooreland Knobhill to its original configuration. WFEC or OGE Regional Reliability $4,644,880 OGE OG&E to construct the new 1 ½ mile 138 kv Noel 6/1/2019 6/1/ months KNOBHILL KNOBHILL / a tap point along the existing Air Liquide Tap line with ACSR/TW. Make the existing Letourneau plant - Letourneau line section AEP Regional Reliability $2,358,802 AEP normally open. 6/1/2017 6/1/ LETOURNEAU STEEL Letouteau W tap 69 kv /150 Increase line clearance on 115 kv line from North Loup to Ord to 100 degree C. Upgrade disconnect NPPD Regional Reliability $329,600 NPPD switches, CTs, and jumpers at North Loup. 6/1/ months North Loup Ord /151 Install 161 kv terminal equipment at S1366 for OPPD Zonal Reliability $422,270 OPPD new 161/69 kv transformer. 6/1/ SUB kV 161 Install 161 kv terminal equipment for new second GMO Regional Reliability $1,005,220 GMO 161/69 kv transformer at Harrisonville. 1/30/2014 6/1/ Harrisonville 161 KV 161 Generation New 345kV Breaker Line Terminal, Disturbance Interconnection $2,252,249 GEN (SMonitoring Device, and 345kV Disconnect Switch. 10/1/ kV circuit breakers, control house, transmission line work, right-of-way, relay Generation upgrades, disturbance monitoring device, Interconnection $12,525,622 GEN (Sreactors, and associated equipment. 5/1/ kV line terminal including two (2) 345kV Generation circuit breakers, disconnect switches, and all SEPC Interconnection $4,264,906 GEN (Sassociated and miscellaneous equipment. 9/10/2014 Convert existing 4.32-mile 69 kv line from Ahloso OGE Regional Reliability $4,634,000 OGE to Park Lane to 138 kv. 6/1/2017 6/1/ months PARK LANE Ahloso 138KV /286 Convert existing mile 69 kv line from OGE Regional Reliability $5,566,000 OGE Ahloso to Harden City to 138 kv. 6/1/2015 6/1/ months Ahloso 138KV Harden City 138KV /286 Convert existing 3.39-mile 69 kv line from Harden OGE Regional Reliability $3,715,500 OGE City to Frisco to 138 kv. 6/1/2017 6/1/ months Frisco 138 kv Harden City 138KV /286 Convert existing 3.39-mile 69 kv line from Frisco OGE Regional Reliability $7,083,000 OGE to Lula to 138 kv. 6/1/2015 6/1/ months LULA Frisco 138 kv / AEP ITP $12,600,000 SPP Install new 345/161 kv Transformer at South 1/1/ / /440

52 TBD ITP $21,295,800 SPP South Fayetteville and associated terminal equipment. 1/1/ / GMO ITP $12,600,000 SPP Install new 345/161 transformer at Maryville. 1/1/ Maryville 345 kv Maryville 1 345/ / KCPL ITP $12,600,000 SPP Increase rating of Nashua transformer to 650/715 1/1/ / / TBD ITP $130,141,000 SPP Build new 110 mile 345 kv line from Keystone to Red Willow and associated terminal equipment. 1/1/ Keystone Red Willow / TBD ITP $75,718,400 SPP Build new 64 mile 345 kv line from Tolk to Tuco and associated terminal equipment. 1/1/ Tolk Station 345 kv TUCO Interchange 345 kv / SEPC ITP $12,600,000 SPP Install 2nd 345/115 kv transformer at Holcomb. 1/1/2033 1/1/ HOLCOMB HOLCOMB 2 345/ /435 Build new 99 mile 345 kv line from Neosho to TBD ITP $117,126,900 SPP Wolf Creek and associated terminal equipment. 1/1/ WOLF CREEK 345 KV NEOSHO 345 KV / TBD ITP $15,701,325 SPP Rebuild 29 mile 161 kv line from Clinton to 1/1/ Clinton Truman / TBD ITP $1,082,850 SPP Rebuild 2 miles of 161 kv line from North Warsaw 1/1/ Truman North Warsaw / OGE ITP $34,605,675 SPP Pecan Creek substations to increase Muskogee - Pecan Creek 345 kv Ckts 1 & 2 ratings to 1195/1195 MVA. 1/1/ MUSKOGEE PECAN CREEK / WR ITP $12,600,000 SPP Install Convert new /115 mile Auburn kv transformer - Swissvale 230 at Auburn. kv line to 1/1/ / / TBD ITP $20,112,700 SPP a 345 kv line. 1/1/ / TBD ITP $35,493,000 SPP Convert the 30 mile Auburn - Jeffrey EC 230 kv to 1/1/ /1792 Rebuild 3.3-mile 69 kv line from S907 to S OPPD ITP Near Term $3,141,600 OPPD with a new rating of 143 MVA. 6/1/ Sub Sub Interchange to covert the high side of the Curry Curry County Interchange Regional Reliability $813,381 Couty distibion transformer to 115 kv 6/1/2018 6/1/ kv 115

53 Facility owner abbreviations used in the STEP List: Abbreviation and Identification AECC Arkansas Electric Cooperatives AECI Associated Electric Cooperative, Incorporated AEP American Electric Power CUS City Utilities, Springfield Missouri DETEC Deep East Texas Electric Cooperative EDE Empire District Electric Company GMO KCP&L Greater Missouri Operations Company GRDA Grand River Dam Authority GRIS Grand Island Electric Department (GRIS) INDN City Power & Light, Independence, Missouri ITCGP ITC Great Plains KCPL Kansas City Power and Light Company LEA Lea County Cooperative LES Lincoln Electric System MIDW Midwest Energy, Incorporated MKEC Mid-Kansas Electric Company NPPD Nebraska Public Power District OGE Oklahoma Gas and Electric Company OMPA Oklahoma Municipal Power Authority OPPD Omaha Public Power District PW Prairie Wind Transmission RCEC Rayburn Electric Cooperative SEPC Sunflower Electric Power Corporation Southwestern Public Service Company SWPA Southwestern Power Administration WFEC Western Farmers Electric Cooperative WR Westar Energy 39

54 Cost By Facility Type (Billions) $0.0 B $0.5 B $1.0 B $1.5 B $2.0 B $2.5 B $3.0 B $3.5 B $4.0 B $4.5 B New Line Rebuild/Re-Conductor Transformer Substation Voltage Conversion Capactive/Reactive Devices Raise Line/Line Work Figure Appendix A.1: Cost by Facility Type % of Total Project Cost by Facility Type New Line 70% Raise Line/ Line Work 0.02% Capacitive/ Reactive Devices.5% Voltage Conversion 3% Substation 6% Transformer 9% Rebuild/ Re-Conductor 12% Figure Appendix A.2: Percentage of Total Cost by Facility Type STEP Report

55 Cost of Line Upgrades $1600M $1400M $1200M $1000M $800M $600M non-ntc NTC $400M $200M $M Figure Appendix A.3: Total Cost of Line Upgrades Miles of Line Upgrades New Lines Reconductor Voltage Conversion Figure Appendix A.4: Total Miles of Line Upgrades by Project Type 41

56 Miles Southwest Power Pool, Inc Line Mileage by Voltage Class kv 115 kv 138 kv 161 kv 230 kv 345 kv Figure Appendix A.5: Total Line Mileage by Voltage Class $4000M Line Cost by Voltage Class $3500M $3000M $2500M $2000M $1500M $1000M $500M $M 69 kv 115 kv 138 kv 161 kv 230 kv 345 kv Figure Appendix A.6: Line Cost by Voltage Class STEP Report

57 Miles Miles Southwest Power Pool, Inc History of Total Miles Year 2012STEP 2013STEP 2014 STEP Figure Appendix A.7: History of Total STEP Miles History of New Miles Year 2012STEP 2013STEP 2014 STEP Figure Appendix A.8: History of STEP New Line Miles 43

58 Miles Southwest Power Pool, Inc. 450 History of Rebuilds and Conversions Year 2012STEP 2013STEP 2014 STEP Figure Appendix A.9: History of STEP Line Rebuilds and Conversions $350M Costs of Transformer and Substation Upgrades $300M $250M $200M $150M $100M $50M $M Figure Appendix A.10: Costs of Transformer and Substation Upgrades STEP Report