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2014 STEP 2014 SPP Transmission Expansion Plan Report January 6, 2014 Engineering

2014 STEP - Home - Southwest Power Pool Power Pool, Inc. Revision History 2 2014 STEP Report Revision History Date Author Change Description 01/06/2014 SPP staff Initial Draft 01/15/2014

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Page 1: 2014 STEP - Home - Southwest Power Pool Power Pool, Inc. Revision History 2 2014 STEP Report Revision History Date Author Change Description 01/06/2014 SPP staff Initial Draft 01/15/2014

2014 STEP 2 0 1 4 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

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Southwest Power Pool, Inc. Revision History

2 2014 STEP Report

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

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Southwest Power Pool, Inc. Table of Contents

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Table of Contents

REVISION HISTORY ...................................................................................................................................................2 TABLE OF CONTENTS ................................................................................................................................................3 LIST OF FIGURES ......................................................................................................................................................4 SECTION 1: EXECUTIVE SUMMARY .............................................................................................................................6 SECTION 2: TRANSMISSION SERVICES .................................................................................................................... 10

2.1: Transmission Service 2013 Overview ..................................................................................................... 10 2.2: Tariff Attachments AQ and AR ................................................................................................................ 12

SECTION 3: GENERATION INTERCONNECTION .......................................................................................................... 14 3.1: Generation Interconnection 2013 Overview ............................................................................................ 14 3.2: Generator Interconnection Improvements ............................................................................................... 15

SECTION 4: INTEGRATED TRANSMISSION PLANNING ................................................................................................ 17 4.1: 2013 ITP20 .............................................................................................................................................. 17 4.2: 2015 ITP10 .............................................................................................................................................. 19 4.3: 2014 ITP Near-Term (ITPNT) .................................................................................................................. 19

SECTION 5: BALANCED PORTFOLIO ........................................................................................................................ 23 SECTION 6: HIGH PRIORITY STUDIES ...................................................................................................................... 25

6.1: SPP Priority Projects ................................................................................................................................ 25 SECTION 7: SPONSORED UPGRADES ...................................................................................................................... 27 SECTION 8: REGIONAL COST ALLOCATION REVIEW (RCAR) .................................................................................... 28 SECTION 9: INTERREGIONAL COORDINATION ........................................................................................................... 30

9.1: Integrated System Integration Study ....................................................................................................... 30 9.2: Interregional Requirements of Order 1000 .............................................................................................. 32 9.3: ITP Seams Coordination Enhancements ................................................................................................. 32 9.4: Eastern Interconnection Planning Collaborative ...................................................................................... 32

SECTION 10: SUB-REGIONAL PLANNING ................................................................................................................. 34 10.1: Stakeholder Process and Forums ......................................................................................................... 34

SECTION 11: PROJECT TRACKING .......................................................................................................................... 35 11.1: Business Practice 7060 ......................................................................................................................... 35 11.2: Project Cost Working Group .................................................................................................................. 35 11.3: NTC Letters Issued in 2013 ................................................................................................................... 36 11.4: Projects Completed in 2013 ................................................................................................................... 36

APPENDIX A: STEP LIST ........................................................................................................................................ 38 NTCS ISSUED IN 2013 ........................................................................................................................................... 46 APPENDIX C: 2013 ITP20 PROJECT LIST ................................................................................................................ 49 APPENDIX D: 2014 ITPNT PROJECT LIST .............................................................................................................. 50 APPENDIX E: PROJECTS COMPLETED IN 2013 ......................................................................................................... 53

ITP Projects Completed in 2013 ..................................................................................................................... 53 Transmission Service Projects Completed in 2013 ........................................................................................ 54 Generation Interconnection Projects Completed in 2013 ............................................................................... 55 Balanced Portfolio Projects Completed in 2013 ............................................................................................. 55 Priority Projects Completed in 2013 ............................................................................................................... 55 Sponsored Projects Completed in 2013 ......................................................................................................... 55

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List of Figures Southwest Power Pool, Inc.

4 2014 STEP Report

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 – 2009-2014 ............................. 12

Figure 3.1: STEP Cost Estimate Comparison for Generation Interconnection Projects – 2009-2014 .................... 14

Figure 3.2: Generator Improvement Process Flowchart ......................................................................................... 16

Figure 4.1: 2014 ITPNT Potential Violations and Draft Solutions ........................................................................... 21

Figure 4.2: 2014 ITPNT Project Plan Mileages ....................................................................................................... 22

Figure 5.1: STEP Cost Estimate Comparison for Balanced Portfolio Projects – 2010-14 ..................................... 23

Figure 5.2: Approved Balanced Portfolio ................................................................................................................. 24

Figure 6.1: STEP Cost Estimate Comparison for High Priority Projects – 2010-14 ................................................ 25

Figure 9.1: IS/SPP Integration Date “Brightline” Summary ..................................................................................... 31

Figure 10.1: SPP Sub-Regional Map ...................................................................................................................... 34

Figure 11.1: Projects Completed in 2013 ................................................................................................................ 37

Figure Appendix A.2: Percentage of Total Cost by Facility Type ............................................................................ 40

Figure Appendix A.3: Total Cost of Line Upgrades ................................................................................................. 41

Figure Appendix A.4: Total Miles of Line Upgrades by Project Type ...................................................................... 41

Figure Appendix A.5: Total Line Mileage by Voltage Class .................................................................................... 42

Figure Appendix A.6: Line Cost by Voltage Class ................................................................................................... 42

Figure Appendix A.7: History of Total STEP Miles 2012-2033 ............................................................................... 43

Figure Appendix A.8: History of STEP New Line Miles ........................................................................................... 43

Figure Appendix A.9: History of STEP Line Rebuilds and Conversions 2012-2033 ............................................... 44

Figure Appendix A.10: Costs of Transformer and Substation Upgrades ................................................................ 44

Figure Appendix A.11: Costs of Capacitive and Reactive Devices ......................................................................... 45

Figure Appendix C.0.1: 2013 ITP20 Project Map .................................................................................................... 49

Figure Appendix D.0.1: 2014 ITPNT Violations and Draft Solutions Map ............................................................... 52

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List of Tables

Table 1.1: 345 kV Projects completed in 2013 ...........................................................................................................8

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-AGP1 .......................................................... 11

Table 2.2: Initial and Final Request and Capacity Amounts for 2011-AGP2 .......................................................... 11

Table 2.3: Active 2013 Aggregate Studies .............................................................................................................. 11

Table 2.4: AQ Study Summary – 2011-2013 .......................................................................................................... 13

Table 5.1: Balanced Portfolio Projects completed in 2013 ...................................................................................... 23

Table 9.2: Scenario 5 Potential Thermal and Voltage Violations ............................................................................ 31

Table 11.1: BP 7060 Cost Estimate Stage Definitions ............................................................................................ 35

Table Appendix B.13.1: NTCs Issued in 2013 ....................................................................................................... 48

Table Appendix C.1: 2013 ITP20 Project List ......................................................................................................... 49

Table Appendix E.2: Transmission Service Projects Completed in 2013 ............................................................... 55

Table Appendix E.4: Balanced Portfolio Projects Completed in 2013 .................................................................... 55

Table Appendix E.6: Sponsored Projects Completed in 2013 ................................................................................ 55

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6 2014 STEP Report

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.

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

Balanced Portfolio (9%)

$533M

High Priority (22%) $1,380M

ATSS (1%) $86M

ITP (66%) $4,134M

GI (2%) $99M

2014 STEP Cost by Project Type $6.2B

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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 2018. 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

$604.64 million for ITP10 projects.

A list of the NTCs issued in 2013 can be found in Appendix B.

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, 2013. 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

$1,022

$1.1 $13.7

$604.7

$-

$200

$400

$600

$800

$1,000

$1,200

Regional Reliability Zonal Reliability High Priority ITP10

NTCs Issued in 2013 per Project Type ($Millions)

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8 2014 STEP Report

Figure 1.3: 2013 Completed Projects

The following tables list EHV projects completed in 2013 as well as active EHV projects carrying forward into 2014.

345 kV Projects completed in 2013

American Electric Power

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

Install new 345/161 kV transformer at new Eastowne substation (Sponsored)

Westar Energy

Install 3rd Rose Hill 345/138 kV transformer (Transmission Service)

Table 1.1: 345 kV Projects completed in 2013

274.9

65.7

6.8 21.9

0

50

100

150

200

250

300

Itp (59) TSS (14) GI (3) BP (3)

2013 Completed Projects ($Millions)

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345 kV projects with NTCs in the 2014 STEP

American Electric Power

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

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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 Process1 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.

The Transmission Provider will combine all long-term point-to-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 2013. 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: 2013-11-08 Ag Study Backlog Clearing Process Tariff Revisions

ER13-2164-001

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2011-AGP1-AFS1 2011-AGP1-AFS11

# of requests-beginning of study 112

# of MW-beginning of study 10291

# of requests-end of study 27

#of MW-end of study 1401

Table 2.1: Initial and Final Request and Capacity Amounts for 2011-AGP1

2011-AG2-AFS1 2011-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 2013.

Study Currently

Active Iteration

Due Date Requests Currently in Study

MW Currently in Study

Currently Posted Study

Date Posted

2012-AG1 AFS-6 1/4/2014 36 2,515 AFS-5 10/21/2013

2012-AG2 AFS-7 LOI 1/11/2014 15 1,841 AFS-6 12/27/2013

2012-AG3 AFS-7 2/17/2014 26 3,581 AFS-5 12/4/2013

2013-AG1 AFS-4 2/23/2014 24 1,483 AFS-2 6/17/2013

2013-AG2 AFS-3 1/20/2014 25 14,807 AFS-2 10/9/2013

2013-AG3 AFS-2 11/29/2013 23 2,309 AFS-1 11/26/2013

2014-AG1 Open

Season After 1/31/2014

Total 149 26,536

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.

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Figure 2.1: STEP Cost Estimate Comparison for Transmission Service Projects – 2009-2014

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.

$455

$550

$433

$152

$86

0

100

200

300

400

500

600

2009 2010 2012 2013 2014

Transmission Service ($ Millions)

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Study Year Delivery Point Requests Full Studies Required Load Increase

2011 84 9 550 MW

2012 156 51 1,200 MW

2013 87 22 882 MW

Table 2.4: AQ Study Summary – 2011-2013

Attachment AR

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.

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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 2012. 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.

Figure 3.1: STEP Cost Estimate Comparison for Generation Interconnection Projects – 2009-2014

$81

$103

$69 $56

$99

0

20

40

60

80

100

120

2009 2010 2012 2013 2014

Generation Interconnection ($ Millions)

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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 2013. Tariff language was approved in October 2013. 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 2009. 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).

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Figure 3.2: Generator Improvement Process Flowchart

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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, 2011. The next phases of the ITP process were developed concurrently (ITP10 and ITPNT) in 2011 with the Board of Directors’ acceptance on January 31, 2012.

4.1: 2013 ITP20

The final 2013 ITP20 Report was approved by the SPP Board of Directors on July 30, 2013. 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:

$1.5B Benefit

$560M Cost

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Future 1: Business-As-Usual - This future included state renewable mandates and targets as identified in the 2012 Policy Survey2 resulting in 9.2 GW of renewable resources modeled in SPP, load growth projected by load serving entities, and SPP member-identified 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

2 2012 Policy Survey

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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 2015.

4.3: 2014 ITP Near-Term (ITPNT)

The 2014 ITPNT analyzed the SPP region’s immediate transmission needs over the near-term 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

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Balancing Authorities provided generation dispatch and load information. The study scope3 – 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

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 near-term 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.

3 2014 ITPNT Scope

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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

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Figure 4.2: 2014 ITPNT Project Plan Mileages

0

20

40

60

80

100

120

140

345kV 230kV 161kV 138kV 115kV 69kV

41 40

17

28

128

3 0

27

0

37

18

92

New Line

Rebuild/Reconductor

Project Plan: Miles of New Lines and Rebuild/Reconductor

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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 2009.

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.

Figure 5.1: STEP Cost Estimate Comparison for Balanced Portfolio Projects – 2010-14

NTC ID

Project ID

Project Owner

Project Name Current

Cost Estimate

20040 698 GRDA Line - Cleveland – Sooner 345 kV $3,718,139

20041 699 OGE Line – Sooner – Cleveland 345 kV $46,000,000

20042 702 KCPL Tap – Swissvale – Stilwell $1,922,840

20084 704 SPS Multi - Tuco - Woodward 345 kV $16,234,558

Table 5.1: Balanced Portfolio Projects completed in 2013

$821 $870

$622

$533

$-

$150

$300

$450

$600

$750

$900

2010 2012 2013 2014

Balanced Portfolio ($ Millions)

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Figure 5.2: Approved Balanced Portfolio

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Section 6: High Priority Studies

6.1: SPP Priority Projects

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 2013.

Figure 6.1: STEP Cost Estimate Comparison for High Priority Projects – 2010-14

$1,418

$1,444

$1,392

$1,380

$1,340

$1,360

$1,380

$1,400

$1,420

$1,440

$1,460

2010 2012 2013 2014

Priority Projects ($ Millions)

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Figure 6.2: Priority Projects

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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 2013.

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Section 8: Regional Cost Allocation Review (RCAR)

The Regional Allocation Review Task Force4 (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 in-service 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 2013. 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

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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 2015. 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.

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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 C5 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 0 4 0 0 0 4

2015S 0 0 0 0 0 0

2015W 0 3 0 0 0 3

2019L 0 0 0 0 0 0

2019S 0 0 0 0 0 0

2019W 0 1 2 0 0 0

TOTAL 0 8 2 0 0 7

Table 9.1: Scenario 0 Potential Thermal and Voltage Violations

5 Category C contingencies were provided to SPP by the IS.

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Scenario 5 THERMAL VOLTAGE

BASE CAT B CAT C BASE CAT B CAT C

2014W 0 0 0 0 0 2

2015S 0 1 0 0 0 0

2015W 0 0 1 0 0 3

2019L 0 0 0 0 0 0

2019S 0 0 0 0 0 0

2019W 0 0 0 0 0 0

TOTAL 0 1 1 0 0 5

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 2015.

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

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9.2: Interregional Requirements of Order 1000

In July of 2013 SPP filed at FERC procedures to meet the interregional requirements of Order 1000. 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 www.eipconline.com.

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.

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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 2023. 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.

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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 email 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.

2013 Sub-Regional Meetings

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.

Figure 10.1: SPP Sub-Regional Map

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Section 11: Project Tracking

11.1: Business Practice 7060

Applicable to projects issued an NTC on or after January 1, 2012, the MOPC approved Business Practice 7060 on March 27, 2012. 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*

Stage End Usage Precision

Bandwidth

Projects > 100

kV & > $20 Million

All other BOD Approved Projects

Conceptual 1 1 Concept screening for ITP20/ITP10

-50% to + 100%

Study 2 2 Study of feasibility and plan development for ITP10/ITPNT

-30% to +30%

NTC-C Issued NTC Issued

NTC-C Project (CPE)

3 N/A Final baseline (NTC-C)** -20% to +20%

New NTC Issued

NTC Project (NPE)

N/A 3 Final baseline (NTC)** -20% to +20%

Design & Construction

4 4 Design after NTC issued and build the project

-20% to +20%***

* The Conceptual Estimate will be prepared by SPP. All subsequent estimates will be prepared by the DTO(s).

**BOD approval required to reset the baseline. ***Actual cost is expected to be within +/-20% of final baseline estimate.

Table 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

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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 2018. 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

$604.64 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, 2013. 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

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Figure 11.1: Projects Completed in 2013

274.9

65.7

6.8 21.9

$0

$50

$100

$150

$200

$250

$300

Itp (59) TSS (14) GI (3) BP (3)

2013 Completed Projects ($Millions)

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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 BOD-approved 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.

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NTC ID PID UID

Facility

Owner

2014 Project

Type Cost Estimate

Estimated

Cost Source Upgrade Description

TO Projected In-

Service Date

SPP Determined

Need Date

Upgrade

Lead Time

(Mo)

From Bus

Number From Bus Name

To Bus

Number To Bus Name Circuit

Voltages

(kV)

Miles of

Reconductor

Miles of

New Line

Miles of

Voltage

Conversion Ratings

136 10174 WFEC

Regional

Reliability $6,674,000 SPP

Build new 10 mile Meeker - Hammett 138 kV and

install terminal equipment. 6/1/2015 520994 MEEKER 4 520951 HAMMETT2 1 138 10 219/235

20003 137 10175 WFEC ITP $8,000,000 WFEC

Reconductor 18.9 mile Wakita - Hazelton Junction

69 kV from 1/0 ACSR to 336.4 ACSR for new rating

of 53/65 MVA. 1/1/2014 4/1/2009 10 521085 WAKITA 520938 HAZELTON JCT 1 69 18.9 53/65

20003 138 10176 WFEC ITP $1,050,000 SPP

Upgrade WFEC Woodward sub to 1200 A and

reconductor from 336.4 ACSR to 795 ACSR; new

rating 91/110 MVA. 6/1/2015 4/1/2009 12 514782 WOODWARD 69 521096 WOODWARD 1 69 3.5 91/114

200166 151 10195 SPS ITP $3,094,772 SPS Add third Tuco 115/69 kV autotransformer. 6/1/2014 6/1/2012 24 525826 TUCO Interchange 69 kV 525828 TUCO Interchange 115 1 115/69 75/84

20081 235 10300 OGE ITP $1,834,692 OGE

Reconductor 2.2 miles of Fort Smith - Colony 161

kV line to 1590 kcmil ACSR and change terminal

equipment at Ft. Smith and Colony substations to

2000A. 2/3/2014 6/1/2013 24 515300 FT SMITH 161 515345 COLONY 161 1 161 2.2 472/542

20003 241 10307 WFEC ITP $2,000,000 WFEC

Rebuild 2 mile Anadarko - Georgia 138 kV line

from 556 to 1113 ACSR. 12/1/2014 6/1/2009 12 520814 ANADARKO 520923 GEORGIA 1 138 2 212/264

20003 242 10308 WFEC ITP $3,240,000 SPP Elmore - Paoli Rebuild 3/0 to 336 ACSR - 10.8 12/2/2014 6/1/2009 12 520898 ELMORE 521022 PAOLI 1 69 10.8 47/61

20003 311 10401 WFEC ITP $2,065,000 SPP Convert 5 mile Acme - Franklin from 69 kV to 138 12/31/2014 6/1/2010 12 520917 FRANKLIN SW 520802.1 ACME 1 138 4.9 132/163

20003 311 10403 WFEC ITP $1,577,000 SPP Convert 8 mile OU - West Norman from 69 kV to 12/31/2014 6/1/2010 12 521095 WEST NORMAN 521104 OU SWITCH 4 1 138 8.3 183/228

200212 319 10413 WR ITP $4,151,903 WR Rebuild 2.1-mile 69 kV line from Cowskin to 12/1/2015 6/1/2015 533788 COWSKIN 69 KV 533854 WESTLINK 69 KV 1 69 2.11 131/143

200212 319 10414 WR ITP $5,834,124 WR

Rebuild 2.65-mile 69 kV line from Westlink to

Tyler. Install terminal equipment at Tyler. 6/1/2015 6/1/2015 533854 WESTLINK 69 KV 533847 TYLER 69 KV 1 69 2.65 131/143

200212 319 10415 WR ITP $4,614,819 WR Rebuild 1.96-mile 69 kV line from Tyler to Hoover. 6/1/2014 6/1/2015 533847 TYLER 69 KV 533806 HOOVER SOUTH 69 KV 1 69 1.96 131/143

20003 361 10471 WFEC ITP $2,000,000 WFEC

Upgrade 7 miles to 795 ACSR from Fletcher SW to

Marlow Junction 69 kV. 6/1/2014 6/1/2011 16 520911 FLETCHER 520990 MARLOW JCT 1 69 7 72/72

20003 399 10519 WFEC ITP $1,347,000 SPP Upgrade line from 1/0 to 336.4, 4.85 miles 6/1/2015 6/1/2012 12 520979 LINDSAY SW 521087 WALLVILLE 1 69 4.85 53/65

20003 402 10522 WFEC ITP $1,125,000 SPP

Convert 3 miles of 69 kV to 138 kV from

Indiahoma to Grandfield. 3/31/2014 6/1/2012 12 521106 Grandfield 520954 INDIAHOMA 1 138 3 183/228

20003 402 10523 WFEC ITP $7,306,000 SPP

Tap Cache to Paradise 138 kV and install 13.7

miles of 138 kV from Cache to Indiahoma. 3/31/2014 6/1/2012 24 520954 INDIAHOMA 521105 CACHE 4 1 138 13.7 183/228

20003 402 10524 WFEC ITP $5,000,000 SPP Install new 138/69 kV transformer at Grandfield 3/31/2014 6/1/2012 24 521106 Grandfield 520926 GRANDFIELD 1 138/69 70/70

200212 412 10538 WR ITP $4,104,097 WR Rebuild 2.65-mile 69 kV line from Eastborough to 6/1/2015 6/1/2013 18 533792 EASTBOROUGH 69 KV 533842 SIXTY-FOURTH (64TH) 1 69 2 131/143

20000 450 10582 AEP ITP $11,962,000 AEP

Install 9 miles of 161 kV from new Shipe Road

Substation to East Centerton Substation. 6/1/2014 6/1/2014 60 506980 Shipe Road 161 506929

EAST CENTERTON

161KV 1 161 9 520/729

20000 450 10584 AEP ITP $13,104,000 AEP Install 345/161 kV transformer at Shipe Road. 6/1/2014 6/1/2014 48 506979 Shipe Road 345 506980 Shipe Road 161 1 345/161 675/743

20000 450 10585 AEP ITP $34,085,000 AEP Install 18 miles of new 345 kV, 2-954 ACSR line. 6/1/2014 6/1/2014 60 506935 FLINT CREEK 345KV 506979 Shipe Road 345 1 345 18 1011/1176

200216 451 10583 AEP ITP $12,705,537 AEP

Rebuild and reconductor 11.1-mile 161 kV line

from Chamber Springs to Farmington REC with 2-

959.6 ACSR/TW. Upgrade wavetraps, CT ratios,

and relay settings at Chamber Springs. 6/1/2015 6/1/2013 36 506944 CHAMBER SPRINGS 161KV 504020 FARMINGTON AECC 1 161 11.1 294/360

200166 461 10597 SPS ITP $36,112,744 SPS

Build 40 miles of 115 kV transmission line

between Bailey County and Curry County. 6/1/2015 6/1/2012 30 524822

Curry County Interchange

115 kV 525028

Bailey County

Interchange 115 kV 1 115 41.5 273/300

200216 478 10615 AEP ITP $1,221,505 AEP

Rebuild 2.3-mile 69 kV line from Forbing to South

Shreveport with 1233.6 ACSR/TW. 6/1/2015 6/1/2013 18 507728 FORBING TAP 507754

SOUTH SHREVEPORT

69KV 1 69 2.3 90/121

20122 479 10616 AEP ITP $14,500,000 AEP

Rebuild 12.63 miles of the Georgia Pacific -

Keatchie 138 kV line from 795 ACSR to 1272 ACSR 6/1/2016 6/1/2016 24 509064 GEORGIA-PACIFIC 509050 KEATCHIE REC 1 138 12.63 287/287

200214 486 10629 SPS ITP $3,206,653 SPS

Upgrade Chaves 230/115 kV transformer Ckt 2 to

250 MVA. 6/30/2014 6/1/2013 24 527483

Chaves County

Interchange 230 kV 527482

Chaves County

Interchange 115 kV 2 230/115 250/250

200216 501 10646 AEP ITP $11,980,465 AEP

Rebuild 6.4-mile 69 kV line from Evenside to

Northwest Henderson with 1233.6 ACSR/TW.

Replace breaker at Evenside. 6/1/2018 6/1/2018 24 509061 EVENSIDE 509075

NORTHWEST

HENDERSON 69KV 1 69 6.4 71/96

200216 502 10647 AEP ITP $7,815,833 AEP

Reconductor 3.25-mile 69 kV line from Northwest

Henderson to Poynter with 1272 ACSR. 6/1/2014 6/1/2013 24 509075

NORTHWEST HENDERSON

69KV 509081 POYNTER 1 69 3.25 140/143

200167 503 10648 AEP ITP $1,004,187 AEP

Replace two breakers, jumpers, and wave traps at

Perdue substation. Replace wave traps at Diana

substation. 6/1/2014 6/1/2013 15 508351 PERDUE 138KV 508831 DIANA 138KV 1 138 261/303

200216 504 10649 AEP ITP $12,424,849 AEP

Rebuild 4.7-mile 69 kV line from Brownlee to

North Market with 1233.6 ACSR/TW. 6/1/2015 6/1/2013 24 507718 BROWNLEE 507745 NORTH MARKET 1 69 4.7 136/143

20000 511 10656 AEP ITP $11,000,000 AEP

Install new 345/161 kV transformer at Kings River

(Previous name Osage Creek) 6/1/2016 6/1/2016 60 506987 Kings River 161 kV 506988 Kings River 161 kV 1 345/161 400/440

20000 511 10659 AEP ITP $24,500,000 AEP Install 9 miles of 345 kV line from Shipe Road to 6/1/2016 6/1/2016 60 506979 Shipe Road 345 506982 East Rogers 345 1 345 9 1366/1915

20000 511 10660 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 6/1/2016 60 506982 East Rogers 345 506987 Kings River 161 kV 1 345 32 1366/1915

200175 30390 10600 WR Regional Reliability $53,832,758 WR

Rebuild 27-mile 230 kV line from East Manhattan

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. 6/1/2017 532861 EAST MANHATTAN 230 KV 532852

JEFFREY ENERGY

CENTER 230 KV 1 230 27 797/797

200168 550 10699 GRDA ITP $1,419,469 GRDA

Reconductor 1.4-mile Maid-Redden 69 kV line

and replace 600A switches with 1200A switches. 5/1/2014 6/1/2012 12 512626 MAID69 512698 REDDEN 69 1 69 1.4 130/143

Appendix A: 2014 STEP List

Page 40: 2014 STEP - Home - Southwest Power Pool Power Pool, Inc. Revision History 2 2014 STEP Report Revision History Date Author Change Description 01/06/2014 SPP staff Initial Draft 01/15/2014

20029 615 10792 OGE ITP $9,552,704 OGE

Convert 13.64 miles of 69 kV to 138 kV from

Crescent to Cottonwood Creek and install

terminal equipment at Cottonwood Creek,

completing loop from Crescent to Twin Lakes

(WFEC). 6/30/2014 6/1/2010 18 515377 Crescent 138kv 514827

COTTONWOOD CREEK

138 1 138 13.64 84/104

20034 646 10847 GMO ITP $2,000,000 GMO

Replace Clinton 161/69 kV transformer #1 with

new 100/125 MVA to match transformer #2. 1/31/2014 6/1/2013 12 541303 Clinton 69 KV 541242 Clinton 161 KV 1 161/69 100/125

20027 649 10853 AEP ITP $2,150,000 AEP Reconductor 2.15 mile section of 115 kV line with 6/1/2014 6/1/2014 24 510399 LONE STAR 510423 LOCUST GROVE 1 115 2.15 120/120

20079 653 10858 MKEC ITP $15,079,303 MKEC

Rebuild 21.9 mile St. John - Pratt 115 kV line with

795 ACSR conductor. 6/15/2014 6/1/2013 24 539696 St John 115 KV 539687 Pratt 115 KV 1 115 21.9 165/198

200204 669 10875 OGE ITP $2,591,900 OGE

Reconductor 4.07-mile Five Tribes - Pecan Creek

161 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

Five Tribes. 10/1/2014 6/1/2013 18 515234 PECAN CREEK 161 515228 5 TRIBES 161 1 161 4.07 441/542

200216 681 10898 AEP ITP $4,923,124 AEP

Rebuild 1-mile portion of the 69 kV line from

Broadmoor to Fern Street with 1233.6 ACSR/TW.

Replace switches at Fern Street. 6/1/2015 6/1/2013 24 507716 BROADMOOR 507724 FERN STREET 1 69 1 68/94

20041 700 10930 OGE Balanced $170,000,000 OGE Build new 345 kV line from Seminole to 12/31/2015 6/1/2015 515045 SEMINOL7 515224 MUSKOGE7 1 345 100 1200/1200

20041 701 10932 OGE Balanced $120,000,000 OGE Build new 345 kV line from Woodward EHV to 5/19/2014 40 515458 Border 515375 Woodward EHV 345kv 1 345 125 1475/1623

20041 701 10933 OGE Balanced Install 2nd 345/138 kV transformer at Woodward 5/19/2014 24 515376 Woodward EHV 138kv 515375 Woodward EHV 345kv 2 345/138 448/493

20043 701 10937 OGE

Balanced

Portfolio

Build midpoint reactor station at interception

point of Woodward to Tuco line. 5/19/2014 515458 Border 345 560/560

200188 703 10935 KCPL

Balanced

Portfolio $10,811,309 KCPL

Add 345 kV line terminal at Iatan. Add ring bus at

Iatan to accommodate line terminals. 6/1/2015 542982 IATAN 345 KV 542980 PAOLA 345KV 1 345 30 2546/2546

20042 703 10945 KCPL Balanced $2,905,550 KCPL Install new 345/161 kV transformer at Nashua 6/1/2015 542980 PAOLA 345KV 543028 NASHUA 161 KV 1 345/161 400/440

200189 703 50499 GMO Balanced $51,647,155 GMO Build 31 miles of new 345 kV line from Iatan to 6/1/2015 542982 IATAN 345 KV 542980 PAOLA 345KV 1 345 31 2546/2546

20043 704 10936 SPS

Balanced

Portfolio $177,336,345 SPS

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. 5/19/2014 525832 TUCO Interchange 345 kV 515458 Border 1 345 202 1792/1972

20087 715 10952 GMO ITP $1,950,000 KCPL

Reconductor GMO portion of Glenare - Liberty 69

kV for 70/79 MVA rating. 3/31/2014 6/1/2013 24 543081 GLENARE 69 KV 541262 Liberty 69 KV 1 69 0.19 70/79

756 10998 WR ITP $18,343,600 WR

Tap Lawrence Hill-Swissvale 230 kV line near

Baldwin Creek substation and install Baldwin

Creek 230/115 kV transformer 3/1/2022 6/1/2021 24 532858 BALDWIN CREEK 533232

BALDWIN CREEK 115

KV 1 230/115 280/308

757 11000 OGE ITP $6,509,948 OGE

Reconductor 12.08 mile FPL Switch - Woodward

District 138 kV line to 1590 ASCR. 3/1/2022 24 514785 WOODWARD 138 515785 FPL SWITCH 138 1 138 12.08 404/485

20130 764 11007 SPS ITP $2,809,520 SPS Upgrade Happy County 115/69 kV Transformer #1 6/1/2014 6/1/2012 28 525154 Happy Interchange 115 kV 525153 Happy Interchange 69 1 115/69 84/96

20130 764 11009 SPS ITP $2,812,436 SPS Upgrade Happy County 115/69 kV Transformer #2 6/1/2014 6/1/2012 28 525154 Happy Interchange 115 kV 525153 Happy Interchange 69 2 115/69 84/96

200216 512 10657 AEP Regional Reliability $8,174,689 AEP

Rebuild 2.0-mile 69 kV line from Ellerbe Road to

Forbing T with 1233.6 ACSR/TW. 6/1/2018 6/1/2014 24 months 507723 ELLERBE ROAD 69 kV 507728 FORBING TAP 1 69 2 90/121

200229 772 11017 SPS ITP $32,429,240 SPS

Build new 16.8-mile 230 kV line from Carlisle to

Wolfforth South and install necessary terminal

equipment. 6/1/2017 6/1/2017 36 526525

Wolfforth Interchange 230

kV 526161

Carlisle Interchange

230 kV 1 230 16.8 478/478

20084 774 11019 SPS ITP $3,144,699 SPS

Tap Potter - Harrington West 230 kV line at

Cherry and bring 230 kV into Cherry substation. 6/30/2015 6/1/2010 20 524010 Cherry Sub 230 kV 523959

Potter County

Interchange 230 kV 1 230 0.1 478/502

20084 774 11020 SPS ITP $9,069,568 SPS New 230/115 kV Autotransformer at Cherry 6/30/2015 6/1/2010 20 524010 Cherry Sub 230 kV 524009 Cherry Sub 115 kV 1 230/115 218/239

20084 774 11021 SPS ITP $1,048,295 SPS Convert Hastings Sub from 69 kV to 115 kV 6/30/2015 6/1/2010 30 524136 Hastings Sub 115 kV 115

20084 774 11023 SPS ITP $3,402,558 SPS Build new 3.7 mile Hastings - East Plant 115kV 6/30/2015 6/1/2010 4 524136 Hastings Sub 115 kV 524162 East Plant Interchange 1 115 3.7 157/173

20130 774 11378 SPS ITP $5,540,583 SPS

Construct approximately 3.5 miles of 115 kV line

from Cherry Street substation to Hastings

substation 6/30/2015 6/1/2013 12 524009 Cherry Sub 115 kV 524136 Hastings Sub 115 kV 1 115 3.5 174/192

20084 791 11040 SPS ITP $13,796,842 SPS

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 6/1/2010 24 525461

Newhart Interchange 230

kV 525460

Newhart Interchange

115 kV 1 230/115 250/250

20084 791 11041 SPS ITP $18,468,396 SPS

New 19 mile Swisher County Interchange -

Newhart 230 kV line. 4/30/2015 6/1/2010 36 525461

Newhart Interchange 230

kV 525213

Swisher County

Interchange 230 kV 1 230 19 492/541

20084 791 11042 SPS ITP $16,108,465 SPS New 18 mile Kress - Newhart 115 kV line. 4/30/2015 6/1/2010 36 525192 Kress Interchange 115 kV 525460 Newhart Interchange 1 115 18 157/173

20084 791 11043 SPS ITP $18,501,085 SPS

New 24 mile Castro County Interchange -

Newhart 115 kV line. 4/30/2015 6/1/2010 36 524746

Castro County Interchange

115 kV 525460

Newhart Interchange

115 kV 1 115 24 157/173

20084 791 11044 SPS ITP $2,568,905 SPS

Build new 4 mile Hart Industrial Substation -

Newhart Substation 115 kV line. 4/30/2015 6/1/2010 15 525124 Hart Industrial 115 kV 525460

Newhart Interchange

115 kV 1 115 4 157/173

20084 791 11045 SPS ITP $15,963,547 SPS

New 15 mile Lampton Interchange - Hart

Industrial Substation 115 kV line. 4/30/2015 6/1/2010 36 525414

Lamton Interchange 115

kV 525124 Hart Industrial 115 kV 1 115 15 157/173

20084 795 11052 SPS ITP $16,422,903 SPS Add 230/115 kV transformer 250/250 MVA CKT 1 12/30/2014 6/1/2011 24 524770 Pleasant Hill 230 kV 524768 Pleasant Hill 115 kV 1 230/115 250/250

20084 795 11053 SPS ITP $18,647,234 SPS Build new 16 mile Pleasant Hill - Oasis 230 kV line. 12/30/2014 6/1/2011 24 524770 Pleasant Hill 230 kV 524875 Oasis Interchange 230 1 230 16 492/541

20084 795 11054 SPS ITP $18,805,425 SPS

Build new 26 mile Pleasant Hill - Roosevelt County

230 kV line. 12/30/2014 6/1/2011 30 524770 Pleasant Hill 230 kV 524909

Roosevelt County

Interchange NORTH

230 kV 1 230 26 492/541

200214 802 11064 SPS ITP $4,255,145 SPS

Upgrade Eddy County 230/115 kV transformer

Ckt 1 to 250 MVA. 6/1/2015 6/1/2016 24 527800

Eddy County Interchange

230 kV 527798

Eddy County

Interchange 115 kV 1 230/115 250/250

200190 805 11067 SPS ITP $3,100,001 SPS Install second 115/69 kV transformer at Bowers. 11/28/2014 6/1/2013 24 523748 Bowers Interchange 115 523747 Bowers Interchange 69 2 115/69 84/96

200190 805 50453 SPS ITP $30,851,077 SPS

Build new 38-mile 115 kV line from Bowers

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 6/1/2013 36 523748

Bowers Interchange 115

kV 523797 Howard 115 kV 1 115 33 180/199

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200170 816 11078 NPPD ITP $1,049,361 NPPD

Uprate conductor and substation equipment to

100 degrees Celsius. 6/1/2014 6/1/2014 24 640054 Albion 640181 Genoa 1 115 137/137

20086 819 11082 WR ITP $6,284,667 WR

Rebuild 5.56 mile Gill Energy Center East -

MacArthur 60 kV line. Replace substation bus and

jumpers at MacArthur 69 kV. 6/1/2015 6/1/2013 18 533795

GILL ENERGY CENTER

EAST 69 KV 533813 MACARTHUR 69 KV 1 69 5.56 134/147

20130 833 11100 SPS ITP $3,000,000 SPS

Construct 115 kV bus at NE-Hereford Interchange

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 6/1/2011 30 524567

Northeast Hereford

Interchange 115 kV 524573

Northeast Hereford

Interchange 69 kV 2 115/69 84/96

20084 834 11101 SPS ITP $6,500,000 SPS

Convert existing 3 mile Portales Interchange -

Zodiac 69 kV line to operate at 115 kV. 6/1/2014 6/1/2013 18 524924

Portales Interchange 115

kV 524935 Zodiac Sub 115 kV 1 115 3 157/173

200166 836 11104 SPS ITP $3,000,000 SPS

Tap Bailey County Interchange - Plant X 115 kV

line and convert Muleshoe East substation to 115

kV operation. 11/28/2015 6/1/2012 20 524030 Muleshoe E 115 kV 115 0.3 1.5 139/160

200214 839 11107 SPS ITP $15,196,472 SPS

Build new 22-mile 115 kV line from Kress

Interchange to new Kiser substation. 11/30/2014 6/1/2013 36 525192 Kress Interchange 115 kV 525271 Kiser Sub 115 kV 1 115 22.2 157/173

200214 839 11109 SPS ITP $8,300,000 SPS

Build new 8.7-mile 115 kV line from Cox to new

Kiser substation. 2/28/2014 6/1/2013 36 525326 Cox Interchange 115 kv 525271 Kiser Sub 115 kV 1 115 8.7 157/173

200214 839 50450 SPS ITP $6,400,000 SPS

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 6/1/2013 36 525271 Kiser Sub 115 kV 525272 Kiser Sub 69 kV 1 69 20.83 84/97

200214 841 11110 SPS ITP $2,101,391 SPS Upgrade Graham 115/69 kV transformer Ckt 1 to 12/31/2014 6/1/2014 526693 Graham Interchange 69 kV 526694 Graham Interchange 1 115/69 84/84

766 11010 SPS Regional Reliability $6,386,196 SPS

Add second 230/115 kV 250 MVA transformer at

Newhart substation. 6/1/2015 6/1/2015 525461

Newhart Interchange 230

kV 525460

Newhart Interchange

115 kV 2 230/115 250/250

20132 846 11115 WFEC ITP $14,737,500 SPP Rebuild 25.2-mile Anadarko - Blanchard 69 kV line 12/1/2014 6/1/2012 36 520814 ANADARKO 520828 BLANCHARD 1 138 25.2 212/264

20132 846 11116 WFEC ITP $1,125,000 SPP Rebuild 2-mile Blanchard - OU Switchyard 69 kV 12/1/2015 6/1/2012 12 520828 BLANCHARD 521104 OU SWITCH 4 1 138 2 212/264

844 11113 WFEC Regional Reliability $4,725,000 WFEC

Upgrade 9.9 miles of 69 kV line from Mustang to

Sunshine Canyon from 4/0 to 556. 2/27/2015 6/1/2014 18 months 521005 MUSTANG 521058 SUNSHINE CANYON 1 69 9.9 72/89

856 11127 SPS Regional Reliability $9,754,258 SPS

Build new 5.1-mile 115 kV line from Northeast

Hereford to Centre Street. Convert Centre Steet

distribution transformer high side from 69 kV to

115 kV. Install necessary terminal equipment at

Northeast Hereford. 12/15/2015 6/1/2014 524567

Northeast Hereford

Interchange 115 kV 524555

Hereford Centre Street

Sub 1 115 7.8 245/275

200198 858 11129 OGE ITP $15,000,000 OGE Convert 14-mile Mehan - Cushing 69 kV line to 6/1/2014 6/1/2014 36 515513 Mehan 138 kV 515033 CUSHING 138 1 138 14

200198 858 11129 OGE ITP Convert 6-mile Stillwater - Spring Valley 69 kV line 6/1/2014 6/1/2014 515011 STILLWATER 138 515512 Spring Valley 138kV 1 138 5.98

200198 858 11129 OGE ITP Convert 3-mile Spring Valley - Mehan 69 kV line to 6/1/2014 6/1/2014 515512 Spring Valley 138kV 515513 Mehan 138 kV 1 138 3

200198 858 11129 OGE ITP Convert 8.7-mile Spring Valley - Knipe 69 kV line 6/1/2014 6/1/2014 515512 Spring Valley 138kV 515514 Knipe 138 kV 1 138 8.69 268/286

200207 865 11142 OPPD ITP $475,340 OPPD

Increase line clearances and upgrade terminal

equipment on Sub 917 - Sub 918 69 kV line to

allow the use of a higher conductor rating. 6/1/2018 6/1/2018 18 647917 Sub 917 647918 Sub 918 1 69 89/89

200216 879 11158 AEP ITP $10,241,314 AEP

Rebuild 9.0-mile 138 kV line from Prattville to

Bluebell with 1926.9 ACSR/TW. 6/1/2015 6/1/2014 24 515242 BLUEBELL 138 509758 PRATTVILLE 1 138 9 272/287

200167 882 11171 AEP ITP $11,830,128 AEP

Rebuild or reconductor 11.4-mile Rock Hill -

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 6/1/2014 24 509082 ROCK HILL 69 509056 CARTHAGE 1 69 11.4 123/143

200166 884 11173 SPS ITP $4,863,725 SPS Install second 230/115 kV transformer at Eddy Co. 6/1/2014 6/1/2014 30 527800

Eddy County Interchange

230 kV 527798

Eddy County

Interchange 115 kV 2 230/115 168/168

20067 904 11201 MKEC

Transmission

Service $4,782,312 MKEC Rebuild 8.05 mile line 2/1/2014 1/1/2010 36 539638 Flat Ridge Tap 539674 Medicine Lodge 138 KV 1 138 8.05 261/314

20067 906 11203 MKEC

Transmission

Service $13,645,827 MKEC Rebuild 26 mile line 6/15/2014 1/1/2010 539673 Medicine Lodge 115 KV 539687 Pratt 115 KV 1 115 26 165/198

200208 909 11205 WFEC ITP $1,705,000 WFEC

Rebuild and convert 4-mile Oklahoma University

Switchyard - Cole Substation line to 138 kV and

install necessary terminal equipment. 6/1/2014 6/1/2013 12 521104 OU SWITCH 4 520861 COLE 1 138 4 144/179

200208 909 11425 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 6/1/2013 12 520861 COLE 520868 CRINER 1 138 10.2 144/179

200208 909 50579 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 6/1/2013 24 520868 CRINER 520888

Payne Switching

Station 138 kV 1 138 6.3 144/178

200208 909 50580 WFEC ITP $250,000 WFEC

Tap the Paoli - Cornville Tap 138 kV line and

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 6/1/2013 24 520888

Payne Switching Station

138 kV 138 286/286

20110 910 11207 OGE

Transmission

Service $225,000 OGE Replace wavetrap 6/1/2019 6/1/2019 12 514839 BRYANT 138 514835 MEMORIAL 138 1 138 478/478

20096 936 11236 AEP High Priority $127,995,000 AEP

Build a new 76 mile 345 kV line from Valliant to

NW Texarkana with at least 3000 A capacity.

Upgrade the Valliant and NW Texarkana

substations with the necessary breakers and

terminal equipment. 5/1/2015 51 510911 VALLIANT 345KV 508072

NORTHWEST

TEXARKANA 345KV 1 345 76.25 1330/1940

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20097 938 11238 GMO High Priority $241,448,558 GMO

Build a new 105 mile 345 kV line with at least

3000 A capacity from Sibley to a new Mullin Creek

(formerly Maryville) substation. Upgrade the

Sibley substation with the necessary breakers and

terminal equipment. 6/1/2017 72 541201 Sibley 345 KV 541197 Maryville 345 kV 1 345 105 2496/2496

20097 938 11239 GMO High Priority $90,750,965 GMO

Build a new 345 kV substation at Mullin Creek

(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. 6/1/2017 72 645458 Sub 3458 (Neb Cty) 541197 Maryville 345 kV 1 345 65 2496/2496

20098 939 11240 OPPD High Priority $75,564,841 OPPD

Build a new 11.2 mile 345 kV line with at least

3000 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 6/1/2017 645458 Sub 3458 (Neb Cty) 541197 Maryville 345 kV 1 345 45 2496/2496

20099 940 11241 SPS High Priority $51,370,321 SPS

Build 30 mile double circuit 345 kV line with at

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. 6/30/2014 523097

Hitchland Interchange 345

kV 515375 Woodward EHV 345kv 1 345 30 1792/1792

20099 940 11242 SPS High Priority

Build 30 mile double circuit 345 kV line with at

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. 6/30/2014 523097

Hitchland Interchange 345

kV 515375 Woodward EHV 345kv 2 345 30 1792/1792

200214 940 11243 SPS High Priority $13,649,558 SPS

Install a second 345/230 kV transformer at

Hitchland substation. 6/30/2014 6/1/2013 523097

Hitchland Interchange 345

kV 523095

Hitchland Interchange

230 kV 2 345/230 560/560

20100 941 11244 OGE High Priority $165,000,000 OGE

Build a new 92 mile double circuit 345 kV line

with at least 3000 A capacity from the Woodward

District EHV substation to the SPS interception

from the Hitchland substation. Upgrade the

Woodward District EHV substation with the

necessary breakers and terminal equipment. 6/30/2014 40 523097

Hitchland Interchange 345

kV 515375 Woodward EHV 345kv 1 345 92 1792/1792

20100 941 11245 OGE High Priority

Build a new 92 mile double circuit 345 kV line

with at least 3000 A capacity from the Woodward

District EHV substation to the SPS interception

from the Hitchland substation. Upgrade the

Woodward District EHV substation with the

necessary breakers and terminal equipment. 6/30/2014 40 523097

Hitchland Interchange 345

kV 515375 Woodward EHV 345kv 2 345 92 1792/1792

20121 942 11246 OGE High Priority $145,040,000 OGE

Build a new 79 mile double circuit 345 kV line

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. 12/31/2014 40 539801 Thistle 345 kV 515375 Woodward EHV 345kv 1 345 79 1792/1792

20121 942 11247 OGE High Priority

Build a new 79 mile double circuit 345 kV line

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. 12/31/2014 40 539801 Thistle 345 kV 515375 Woodward EHV 345kv 2 345 79 1792/1792

200163 943 11248 PW High Priority $23,800,000 PW

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. 12/31/2014 539801 Thistle 345 kV 515375 Woodward EHV 345kv 1 345 30.4 1792/1792

200163 943 11249 PW High Priority $23,800,000 PW

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. 12/31/2014 539801 Thistle 345 kV 515375 Woodward EHV 345kv 2 345 30.4 1792/1792

200162 945 11252 ITCGP High Priority $50,152,303 ITCGP

Build a new 36-mile double circuit 345 kV line

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 12/31/2014 12/31/2014 531469 SPEARVILLE 539800 Clark Co 345 kV 1 345 27.5 1792/1792

200162 945 11253 ITCGP High Priority $50,152,303 ITCGP

Build a new 36-mile double circuit 345 kV line

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 12/31/2014 12/31/2014 531469 SPEARVILLE 539800 Clark Co 345 kV 2 345 27.5 1792/1792

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200162 945 11254 ITCGP High Priority $86,286,538 ITCGP

Build a new 86 mile double circuit 345 kV line

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. 12/31/2014 539800 Clark Co 345 kV 539801 Thistle 345 kV 1 345 86 1792/1792

200162 945 11255 ITCGP High Priority $86,286,538 ITCGP

Build a new 86 mile double circuit 345 kV line

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. 12/31/2014 539800 Clark Co 345 kV 539801 Thistle 345 kV 2 345 86 1792/1792

200162 945 11260 ITCGP High Priority $6,370,595 ITCGP

Install a 400 MVA 345/138 kV transformer at the

new 345 kV Thistle substation. 12/31/2014 539801 Thistle 345 kV 539803 Thistle 138 kV 1 345/138 400/400

200162 945 50384 ITCGP High Priority $5,776,280 ITCGP

Build 1 mile 138 kV line from new Thistle

substation to Flat Ridge substation. 12/31/2014 539803 Thistle 138 kV 539638 Flat Ridge Tap 1 138 1

945 50792 ITCGP High Priority

Build new Ironwood 345 kV switching station with

the necessary terminal equipment. The new

switching station will interconnect the new Clark

Co. substation with the Spearville 345 kV bus. 12/31/2014 12/31/2014

945 50793 ITCGP High Priority

Construct second circuit of 345 kV line from the

new Ironwood substation to the Spearville 345 kV

bus. 12/31/2014 12/31/2014 345

200163 946 11258 PW High Priority $61,200,000 PW

Build a new 78 mile double circuit 345 kV line

with at least 3000 A capacity from the Wichita

substation to ITC Great Plains' Thistle 345 kV

substation. 12/31/2014 539801 Thistle 345 kV 532796 WICHITA 345 KV 1 345 77.5 1792/1792

200163 946 11259 PW High Priority $61,200,000 PW

Build a new 78 mile double circuit 345 kV line

with at least 3000 A capacity from the Wichita

substation to ITC Great Plains' Thistle 345 kV

substation. 12/31/2014 539801 Thistle 345 kV 532796 WICHITA 345 KV 2 345 77.5 1792/1792

20103 946 11497 WR High Priority $14,155,302 WR

Upgrade the Wichita substation with the

necessary breakers and terminal equipment to

accommodate two new 345 kV circuits form the

new Thistle 345 kV substation 12/31/2014 532796 WICHITA 345 KV 345 1792/1792

20104 947 11261 AEP

Transmission

Service $6,072,000 AEPW Rebuild 4.33 of 795 ACSR with 1590 ACSR. 6/1/2015 6/1/2015 20 509806 ONETA 138KV 509786

BROKEN ARROW

NORTH - SOUTH TAP 1 138 4.33 284/316

200193 1000 11314 SPS

Transmission

Service $345,942 SPS

Upgrade line trap at both Jones Bus #2 and

Lubbock South Interchange. 12/30/2014 6/1/2013 24 526338

Jones Station Bus#2 230

kV 526269

Lubbock South

Interchange 230 kV 2 230 478/478

20130 1001 11315 SPS ITP $2,775,000 SPS

Construct approximately 2 miles of new 115 kV

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 one-

half 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 6/1/2016 24 524364

Randall County

Interchange 115 kV 524322

South Georgia

Interchange 115 kV 1 115 2 160/160

200214 1003 11317 SPS ITP $4,179,553 SPS Upgrade Grassland 230/115 kV transformer Ckt 1 6/1/2015 6/1/2013 24 526677 Grassland Interchange 230 526676 Grassland Interchange 1 230/115 250/250

20130 1004 11318 SPS Regional Reliability $3,496,698 SPS

Upgrade existing 230/115 kV transformer at

Swisher to 250 MVA. 6/30/2017 6/1/2014 24 months 525213

Swisher County

Interchange 230 kV 525212

Swisher County

Interchange 115 kV 1 230/115 250/250

200216 1012 11331 AEP ITP $18,805,489 AEP

Rebuild 21.85-mile 138 kV line from Diana to

Perdue. Replace switches, jumpers, and upgrade

CT ratios at Diana and Perdue. Upgrade relay

settings at Diana. 6/1/2014 6/1/2013 30 508351 PERDUE 138KV 508831 DIANA 138KV 1 138 22 455/478

200204 1017 11339 OGE ITP $161,204 OGE Replace 800 A CT and wavetrap at Classen 138 kV 2/15/2014 6/1/2013 12 514922 CLASSEN 138 514921 SW 5TAP 138 1 138 268/287

20110 1021 11343 OGE

Transmission

Service $18,000,000 OGE Add 3rd 345kV line from Arcadia to Redbud 6/1/2019 6/1/2019 36 514908 ARCADIA 345 514909 REDBUD 345 3 345 5 1248/1426

20114 1027 11351 WFEC

Transmission

Service $150,000 WFEC Replace CTs 6/1/2015 6/1/2015 521129 BLUE CANYON WIND 5 521024 PARADISE 1 138 163/163

20130 1029 11353 SPS ITP $5,342,685 SPS Convert Lynn County Substation to 115 kV service 12/31/2014 6/1/2012 12 526656

Lynn County Interchange

115 kV 115

200214 1031 11355 SPS ITP $2,378,798 SPS

Upgrade Crosby County 115/69 kV transformer

Ckt 1 to 84 MVA. 6/1/2015 6/1/2013 24 525926

Crosby County

Interchange 115 kV 525925

Crosby County

Interchange 69 kV 1 115/69 84/84

200214 1031 11356 SPS ITP $2,301,000 SPS

Upgrade Crosby County 115/69 kV transformer

Ckt 2 to 84 MVA. 6/1/2015 6/1/2013 24 525926

Crosby County

Interchange 115 kV 525925

Crosby County

Interchange 69 kV 2 115/69 84/84

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200166 1033 11358 SPS ITP $4,000,000 SPS

Reconductor 4.1 miles of 6.1-mile 115 kV line

from Randall County to South Georgia. 7/31/2015 6/1/2017 18 524364

Randall County

Interchange 115 kV 524322

South Georgia

Interchange 115 kV 1 115 4.1 246/270

20130 1036 11372 SPS ITP $929,500 SPS

Convert 1.04 miles of Z33 to 115 kV service by

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.

Leave 69 kV underground cable to Lawrence Park 6/1/2015 6/1/2015 18 524252 Soncy Tap 115 kV 524254 New Soncy 115 kV 1 115 1.04 157/173

20130 1042 11383 SPS ITP $300,000 SPS

Tap the Kress - Plainview City 115 kV line with

North Plainview substation. Convert North

Plainview substation to 115 kV. 12/31/2014 6/1/2015 525257

North Plainview Sub 115

kV 115

20130 1043 11384 SPS ITP $280,000 SPS

Tap the Kress - Plainview City 115 kV line with

Kress Rural. Convert Kress Rural substation to 115

kV. 11/30/2014 6/1/2015 525225 Kress Rural Sub 115 kV 115 157/173

20131 1073 11411 WR ITP $7,392,705 WR

Build 6 miles of double circuit 69 kV line from new

Franklin substation to Mulberry - Sheffield 69 kV

line, tapping line and connecting to Mulberry. 6/1/2014 6/1/2013 532938 FRANKLIN 533767 MULBERRY 69 KV 1 69 6 72/72

20131 1073 11412 WR ITP $1,695,722 WR

Build 6 miles of double circuit 69 kV line from new

Franklin substation to Mulberry - Sheffield 69 kV

line, tapping line and connecting to Sheffield. 6/1/2014 6/1/2013 532938 FRANKLIN 533774 SHEFFIELD 69 KV 1 69 6 72/72

20131 1073 11413 WR ITP $12,204,315 WR

Tap Litchfield - Marmaton 161 kV line at new

Franklin substation 6/1/2014 6/1/2013 533876 FRANKLIN 161 211/211

20131 1073 11444 WR ITP $8,805,014 WR New 161/69 kV transformer at Franklin 6/1/2014 6/1/2013 533876 FRANKLIN 532938 FRANKLIN 1 161/69 100/110

1083 11423 AEP Regional Reliability $24,880,495 AEP

Rebuild 23.7 miles of 138 kV line from Wilkes to

Welsh Reserve with 1926.9 ACSR/TW. Upgrade

switches at both ends and wave traps, jumpers,

CT ratios, and relay settings at Wilkes. 6/1/2019 6/1/2019 508355 Welsh Reserve 138 kV 508840 WILKES 138KV 1 138 23.74 395/592

20119 1096 11440 MKEC ITP $100,000 MKEC

Replace CTs and relays at Pratt substation and St

John substation 6/15/2014 6/1/2011 36 539687 Pratt 115 KV 539696 St John 115 KV 1 115 165/198

20137 1134 11496 OGE

Transmission

Service $15,000,000 OGE

Install third 345/138 kV transformer in Northwest

Sub 6/1/2017 6/1/2017 40 514880 NORTHWEST 345 514879 NORTHWEST 138 3 345/138 493/493

200194 1134 50585 OGE

Transmission

Service $2,260,299 OGE

Accelerate installation of third 345/138 kV bus tie

in Northwest Sub (UID 11496). 6/1/2015 6/1/2012 36 514880 NORTHWEST 345 514879 NORTHWEST 138 3 345/138 493/493

200184 1140 11502 SPS ITP $6,158,183 SPS

Install 345/115 kV transformer between Tuco and

new 115 kV substation (New Deal). 6/1/2018 6/1/2018 36 525836 New-Sub-EH1 345kV 525837 New-Sub-EH1 115kV 1 345/115 458/474

200184 1140 11503 SPS ITP $27,602,755 SPS

Build new 15-mile 345 kV line between Tuco and

high side of new transformer between Tuco and

Stanton. 6/1/2018 6/1/2018 36 525832 TUCO Interchange 345 kV 525836 New-Sub-EH1 345kV 1 345 13.63 1792/1792

200184 1140 11504 SPS ITP $23,362,589 SPS

Build new 17-mile 115 kV line between Stanton

and low side of new transformer between Tuco

and Stanton. 6/1/2018 6/1/2018 36 525837 New-Sub-EH1 115kV 526076 Stanton Sub 115 kV 1 115 17.6 174/192

200214 1143 11507 SPS ITP $4,679,150 SPS

Install a second 230/115/13.2 kV transformer at

Lubbock South. 12/31/2014 6/1/2013 24 526269

Lubbock South

Interchange 230 kV 526268

Lubbock South

Interchange 115 kV 2 230/115 250/250

1144 11508 SPS ITP $4,220,694 SPS Build a second 230/115/13.2 kV transformer at 6/1/2018 24 523095 Hitchland Interchange 230 523093 Hitchland Interchange 2 230/115 250/250

1145 11524 SPS ITP $4,714,312 SPS Reconductor 3.98 miles of Carlisle - Murphy 115 6/1/2021 24 526160 Carlisle Interchange 115 526192 Murphy Sub 115 kV 1 115 3.98 273/300

1146 11509 SPS ITP $3,644,914 SPS Upgrade the Carlisle 230/115/13.2 transformer - 6/1/2018 24 526161 Carlisle Interchange 230 526160 Carlisle Interchange 1 230/115 250/250

200214 1147 11512 SPS ITP $2,045,196 SPS

Convert 26 miles of 115 kV line from Channing to

Potter to 230 kV and upgrade necessary terminal

equipment at Potter. 6/1/2015 6/1/2013 48 523869 Channing 230 kV 523959

Potter County

Interchange 230 kV 1 230 52 492/541

200214 1147 11514 SPS ITP $4,796,000 SPS

Convert 35 miles of 115 kV line from Channing to

new XIT substation (near Dallam) to 230 kV. 6/1/2015 6/1/2013 48 523869 Channing 230 kV 523229 Dallam 230 kV 1 230 70 492/541

200214 1147 11515 SPS ITP $8,849,320 SPS Install 230/115 kV transformer at XIT substation. 6/1/2015 6/1/2013 48 523229 Dallam 230 kV 523228

Dallam County

Interchange 115 kV 1 230/115 168/168

20030 30039 50045 WFEC ITP $243,000 SPP Install 6 Mvar capacitor at Esquandale 69 kV. 6/1/2014 6/1/2014 12 520904 ESQUANDALE 69 6 Mvar

20028 30071 50077 GRDA ITP $374,000 GRDA Add 7.2 Mvar capacitor at Sallisaw 69 kV. 6/1/2011 12 512652 SALLISAW 69 69 7.2 Mvar

20033 30097 50103 WR Zonal Reliability $1,198,694 WR

Install 10.9-Mvar capacitor bank at 115 kV bus at

Vaughn substation. 6/1/2014 18 months 533308 VAUGHN 115 KV 115 10.9 Mvar

20017 30160 50168 OGE

Transmission

Service $14,000,000 OGE

Convert Ft. Smith 161KV to 1-1/2 breaker design

and install 3rd 500-161KV transformer bank. 6/1/2017 6/1/2017 36 515305 FT SMITH 500 515300 FT SMITH 161 5 500/161 493/493

20017 30164 50172 OGE

Transmission

Service $100,000 OGE Upgrade CT 6/1/2017 6/1/2017 9 515336 VBI 69 504032 VBI NORTH 1 161 72/72

20080 30201 50208 NPPD ITP $700,000 NPPD Add a 18 Mvar capacitor bank at Clarks substation 11/1/2012 24 640436 Clarks 115 18 Mvar

20080 30202 50209 NPPD ITP $50,000 NPPD

Expand existing 9 MVAR bank to 15 Mvar

capacitor bank at Ainsworth substation 115 kV

bus.. 11/1/2012 24 640051 Ainsworth 115 15 Mvar

20080 30203 50210 NPPD ITP $700,000 NPPD

Add a second 18 Mvar capacitor bank at Oneill

115 kV substation for a total of 36 Mvar at this

location. 11/1/2012 24 640305 O'Neill 115 18 Mvar

200218 30207 50214 NPPD ITP $677,370 NPPD Install 18 Mvar 115 kV capacitor bank at Cozad. 6/1/2014 6/1/2014 24 640144 Cozad 115 18 Mvar

30208 10991 MKEC ITP $2,501,569 MKEC

Rebuild MKEC portion of the 5.6 mile Clearwater-

Milan Tap 115 kV with bundled 1192.5 kcmil ACSR

conductor (Bunting) 3/1/2022 24 533036 CLEARWATER 138KV 539675 Milan Tap 138 KV 1 138 5.6 261/314

30209 10992 WR ITP $11,839,190 WR

Rebuild Westar portion of the Clearwater-Milan

tap 115 kV with bundled 1192.5 kcmil ACSR

conductor (Bunting) 3/1/2022 24 533036 CLEARWATER 138KV 539675 Milan Tap 138 KV 1 138 6.1 261/314

20091 30224 50233 WR

Transmission

Service $2,951,558 WR

Rebuild approximately 7 miles of line with 954

kcmil ACSR to achieve a minimum 1200 amp

emergency rating. 6/1/2014 7/1/2013 24 533626

BURLINGTON JUNCTION

69 KV 533630

COFFEY COUNTY NO. 3

WESTPHALIA 69 KV 1 69 7.2 134/147

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20059 30226 50230 WR

Transmission

Service $1,400,000 WR Add 6 Mvar Cap bank at Altoona East 6/1/2015 6/1/2014 18 533673 ALTOONA EAST 69 KV 69 6 Mvar

20117 30285 50319 NPPD ITP $5,645,881 NPPD

Replace 187MVA Ogallala transformer with

336MVA Ogallala transformer 6/1/2014 6/1/2010 36 659132 OGALLALLA 640302 Ogallala 1 230/115 336/336

20108 30290 50328 WR

Transmission

Service $700,000 WR Replace disconnect switches, wavetrap and CT 6/1/2016 6/1/2019 533012

HALSTEAD SOUTH BUS

138 KV 533065

SEDGWICK COUNTY

NO. 12 COLWICH 138

KV 1 138 160/160

20122 30296 50334 AEP ITP $1,166,400 AEP

Install a new 28.8 MVAR capacitor bank at

Winnsboro 138 kV substation. 6/1/2016 6/1/2016 18 508317 Winnsboro 138 kV 138 28.8 Mvar

20122 30298 50336 AEP ITP $1,166,400 AEP

Install 28.8 MVAR capacitor bank at Logansport

138 kV substation. 6/1/2016 6/1/2016 18 509071 LOGANSPORT 138KV 138 28.8 Mvar

20107 30299 50337 MKEC

Transmission

Service $150,000 MKEC

Replace CTs and relays at Jewell substation and

Smith Center substation 6/1/2018 6/1/2018 539669 Jewell 3 115 539693 Smith Center 115 KV 1 115 80/88

20136 30320 50366 WFEC

Transmission

Service $4,800,000 WFEC UPGRADE CANTON TO TALOGA TO 336.4 6/1/2015 6/1/2011 521064 TALOGA 520843 CANTON 1 69 9.7 106/132

20136 30321 50367 WFEC

Transmission

Service $1,000,000 WFEC

Replace Taloga 138/69 kV auto transformer with

112 MVA. 6/1/2015 6/1/2011 521065 TALOGA 521064 TALOGA 1 138/69 112/112

20140 30326 50372 WR Zonal Reliability $9,308,090 WR

Build 6.7-mile Clay Center Switching Station to TC

Riley 115 kV line with Single 1192.5 kcmil ACSR

(Bunting). 6/1/2015 10/1/2012 533320

Clay Center Switching

Station 115 kV 533319 Riley 1 115 6.7 233/245

20140 30328 50374 WR Zonal Reliability $963,441 WR

Install a 2000 Amp bus system, GOAB switches,

metering and communication systems. 6/1/2015 10/1/2012 533319 Riley 115

30329 50376 SPS ITP $944,754 SPS Install 28.8 Mvar capacitor at Lamb County 69 kV. 6/1/2022 12 526036

Lamb County REC-Opdyke

Sub 115 kV 69 28.8 Mvar

30331 50378 SPS ITP $697,688 SPS Install 14.4 MVAR capacitor at Eagle Creek 115 6/1/2015 12 527711 Eagle Creek 115 kV 115 14.4 Mvar

200166 30332 50379 SPS ITP $1,683,176 SPS Install 14.4 Mvar capacitor at Drinkard 115 kV. 6/1/2015 6/1/2015 12 528589 Drinkard Sub 115 kV 115 0.4 14.4 Mvar

200165 30340 50387 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. 511485

CLINTON JUNCTION

138KV 138

200167 30346 50438 AEP ITP $21,664,838 AEP

Upgrade the Cornville 138 kV bus to breaker-and-

a-half configuration in preparation for the 138 kV

line conversion to Lindsay Water substation. 12/31/2014 6/1/2012 12 511449 CORNVILLE 138KV 138

200211 30349 50398 WR ITP $29,507,894 WR Upgrade Auburn Road 230/115 kV transformer to 6/1/2014 6/1/2014 24 533151 AUBURN ROAD 115 KV 532851 AUBURN ROAD 230 KV 1 115 0.4 400/440

200166 30351 50401 SPS ITP $985,519 SPS Install 14.4 Mvar capacitor at Crosby 115 kV. 3/30/2014 6/1/2012 12 525926

Crosby County

Interchange 115 kV 115 14.4 Mvar

200167 30354 50405 AEP ITP $1,428,440 AEP Install 6 Mvar capacitor at Coweta 69 kV. 6/1/2014 6/1/2014 12 509719 COWETA 69 6 Mvar

200184 30355 50404 SPS ITP $56,981,082 SPS

Build new 230 kV line from Wolfforth to

Grassland, and install terminal equipment at

Grassland and Wolfforth substations. 3/1/2018 3/1/2018 54 526525

Wolfforth Interchange 230

kV 526677

Grassland Interchange

230 kV 1 230 47.04 478/478

200166 30356 50406 SPS ITP $5,400,001 SPS

Install new 115/69 kV transformer at new

Diamondback Interchange near Cedar Lake. 6/30/2015 6/1/2012 24 527212 Cedar Lake 115 kV 527211 Adair Tap 69 kV 1 69 17.79 84/84

200166 30356 50407 SPS ITP $8,000,000 SPS

Build 12 miles of new 115 kV line from Sulphur

Interchange to Diamondback Interchange near

Cedar Lake. 6/30/2015 6/1/2012 24 527262

Sulphur Interchange 115

kV 527212 Cedar Lake 115 kV 1 115 12.5 157/173

200173 30358 50409 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 6/1/2012 24 530623 RICE COUNTY 115 KV 539662 Ellsworth 115 KV 1 115 21 165/199

200173 30358 50410 MKEC ITP $5,914,221 MKEC Install 3-breaker ring bus at Ellsworth Tap 115 kV. 6/1/2015 6/1/2012 12 539642 Ellsworth Tap 115 239/239

200173 30358 50449 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 6/1/2012 24 539662 Ellsworth 115 KV 115

200173 30358 50549 MIDW ITP $1,459,629 MIDW

Install terminal equipment at new Bushton 115 kV

substation to accommodate the new 115 kV line

from Ellsworth. 6/1/2015 6/1/2012 29 530681 Bushton 115 kV 115 156/199

200183 30361 50413 AEP ITP $157,599,160 AEP

Build new 345 kV line from new Chisholm

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 3/1/2018 60 700345 Chisholm 345 kV 515800 Gracemont 345kv 1 345 93 1792/1792

200183 30361 50414 AEP ITP $25,168,480 AEP

Construct new 345/230 kV Chisholm substation

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 345/230 675 MVA

transformer at new Chisholm substation. 3/1/2018 60 700345 Chisholm 345 kV 700231 Chisholm 230 kV 1 230 1 675/675

200185 30361 50419 OGE ITP $43,853,500 OGE

Build OGE's portion of new 345 kV line from Elk

City to Gracemont. 3/1/2018 3/1/2018 60 700345 Chisholm 345 kV 515800 Gracemont 345kv 1 345 29.8 1792/1792

30361 50768 AEP ITP $5,326,722 AEP

Install approximately 2 miles of 230 kV

transmission line for a cut-in to the existing

Sweetwater - Elk City 230 kV line, creating

termination points at the new Chisholm 3/1/2018 700345 CHISHOLM7 1 345 0 2 0 1792/1792

30362 50416 AEP ITP $100,504,688 AEP

Build 55 mile new 345 kV line from Welsh to Lake

Hawkins (or Perdue). 3/1/2022 60 700346 Lake Hawkins 345 kV 508359 WELSH 1 345 55 1792/1792

30362 50417 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). 3/1/2022 60 700346 Lake Hawkins 345 kV 508358 LAKE HAWKINS 1 345/138 675/675

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30363 50418 OGE ITP $15,990,000 SPP

Reconductor 26 mile Glass Mountain - Mooreland

line to 795 AS33 3/1/2022 36 520999 MOORELAND 514788 GLASS MOUNTAIN 138 1 138 26 268/287

200223 30364 50420 OGE ITP $59,522,400 OGE

Build second circuit of new 49-mile 345 kV line

from Woodward District EHV to Tatonga. 3/1/2021 3/1/2021 72 515375 Woodward EHV 345kv 515407 Tatonga 345kv 2 345 49 1792/1792

200223 30364 50421 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 3/1/2021 72 515407 Tatonga 345kv 515497 MATHEWSON 345 1 345 61 1792/1792

200223 30364 50456 OGE ITP $32,936,400 OGE

Build second circuit of new 16-mile 345 kV line

from the new Matthewson substation to

Cimarron. 3/1/2021 3/1/2021 72 515497 MATHEWSON 345 514901 CIMARRON 345 1 345 16 1792/1792

200223 30364 50458 OGE ITP $19,967,850 OGE

Build new Matthewson 345 kV substation at the

intersection of the Woodring - Cimarron and

Northwest - Tatonga 345 kV lines. 3/1/2021 3/1/2021 72 515497 MATHEWSON 345 345 1792/1792

30365 50422 GMO ITP $3,039,096 KCPL

Reconductor 3.21 miles from Blue Springs to

Prairie Lee 161 kV to 795 ACSS. Upgrade

substation equipment to 2000 Amps. 6/1/2018 6/1/2018 24 541211 Blue Spring South 161 KV 541206 Prairie Lee 161 KV 1 161 3.21 558/558

30365 50423 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 6/1/2018 24 541205 Blue Springs East 161 KV 541211

Blue Spring South 161

KV 1 161 2.5 558/558

200222 30367 50425 ITCGP ITP $31,312,169 ITCGP

Build new 345 kV line from the Elm Creek

substation to the Westar Energy, Inc. interception

point from the Summit substation. 3/1/2018 3/1/2018 48 750011 Elm Creek 345 kV 532773 SUMMIT 345 KV 1 345 29.77 1792/1792

200222 30367 50426 ITCGP ITP $5,405,101 ITCGP Install new 345/230 kV transformer at Elm Creek. 12/31/2016 3/1/2018 48 750011 Elm Creek 345 kV 539639 Elm Creek Substation 1 345/230 448/448

200222 30367 50427 ITCGP ITP $8,243,291 ITCGP

Install terminal equipment on the 345 kV side of

the Elm Creek substation. 12/31/2016 3/1/2018 48 750011 Elm Creek 345 kV 1 345

200222 30367 50428 ITCGP ITP $1,886,035 ITCGP

Install terminal equipment on the 230 kV side of

the Elm Creek substation. 12/31/2016 3/1/2018 48 539639 Elm Creek Substation 230

200221 30367 50429 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 3/1/2018 60 750011 Elm Creek 345 kV 532773 SUMMIT 345 KV 1 345 28.46 1792/1792

30368 50430 WR ITP $11,501,055 WR

Tear down/rebuild 12.3 mile Abilene East -

Chapman 115 kV line as single circuit with

bundled 1192 ACSR conductor. 6/1/2022 36 533365 EAST ABILENE 115 KV 533362 CHAPMAN 115 KV 1 115 12.3 240/240

30368 50431 WR ITP $3,806,178 WR

Tear down/rebuild Abilene East - Abilene Energy

Center 115 kV as single circuit with bundled 1192

ACSR conductor. 6/1/2022 24 533365 EAST ABILENE 115 KV 533361

ABILENE ENERGY

CENTER 115 KV 1 115 3.33 240/240

30368 50432 WR ITP $19,949,242 WR

Tear down/rebuild Abilene Energy Center -

Northview 115 kV as single circuit with bundled

1192 ACSR conductor. 6/1/2022 36 533361

ABILENE ENERGY CENTER

115 KV 533371 NORTHVIEW 115 KV 1 115 21.75 240/240

30368 50433 WR ITP $5,131,249 WR

Tear down/rebuild North Street - Northview 115

kV as single circuit with bundled 1192 ACSR

conductor. 6/1/2022 24 533370 NORTH STREET 115 KV 533371 NORTHVIEW 115 KV 1 115 3.2 240/240

200212 30369 10425 WR ITP $19,770,066 WR Install second 138/115 kV transformer at 12/1/2014 6/1/2013 24 533013 MOUNDRIDGE 138 KV 533429 MOUNDRIDGE 115 KV 2 138/115 110/125

30372 50437 WFEC ITP $16,666,500 SPP

Reconductor Okeene - Dover Switching Station

138 kV to 795 ACSS. 3/1/2022 36 520882 DOVER SW 521016 OKEENE 1 138 27.1 286/286

200220 30374 50440 NPPD Regional Reliability $68,774,278 NPPD Build a new 41-mile 345 kV line from Hoskins to 6/1/2016 6/1/2016 39 months 640226 Hoskins 345 kV 750013 Neligh 345 kV 1 345 41 1792/1792

200220 30374 50441 NPPD Regional Reliability $12,118,564 NPPD

Build new substation at Neligh. Install a new

345/115 kV transformer and all necessary 345 kV

equipment at Neligh. 6/1/2016 6/1/2016 39 months 750013 Neligh 345 kV 640293 Neligh 115 kV 1 345/115 458/474

200228 30437 50532 WR Regional Reliability $20,530,196 WR

Build new Geary County 345/115 kV substation

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 6/1/2014 24 months 532767 Geary County 345 kV 533336 Geary County 115 kV 1 345/115 400/440

200220 30375 50442 NPPD ITP $139,090,440 NPPD

Build new 110-mile 345 kV line from Gerald

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 1/1/2018 72 640500 Cherry County 345 kV 640183

Gerald Gentleman

Station 1 345 110 1792/1792

200220 30375 50444 NPPD ITP $11,896,383 NPPD

Build new Cherry County 345 kV substation and

install necessary terminal equipment. This

upgrade is contingent upon approval from WAPA

to tap the Grand Island - Fort Thompson 345 kV

line. 1/1/2018 1/1/2018 72 640500 Cherry County 345 kV 345

200220 30375 50445 NPPD ITP $146,065,000 NPPD

Build new 117-mile 345 kV line from new Cherry

County substation to new Holt County substation.

This upgrade is contingent upon approval from

WAPA to tap the Grand Island - Fort Thompson

345 kV line. 1/1/2018 1/1/2018 72 640500 Cherry County 345 kV 640503 Holt County 345 kV 1 345 117 1792/1792

200220 30375 50446 NPPD ITP $16,324,800 NPPD

Build new Holt County 345 kV substation tap on

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

Grand Island - Fort Thompson 345 kV line. 1/1/2018 1/1/2018 72 640503 Holt County 345 kV 345

200184 30376 50447 SPS ITP $88,198,879 SPS Build new 67-mile 345 kV line from Tuco to 1/1/2020 1/1/2020 72 525832 TUCO Interchange 345 kV 750014 Amoco 345 kV 1 345 65.91 1792/1792

200184 30376 50451 SPS ITP $21,629,389 SPS Install new 345/230 kV transformer at Amoco. 1/1/2020 1/1/2020 72 750014 Amoco 345 kV 526460

Amoco Switching

Station 230 kV (Amoco

Slaughter) 1 230 3.53 448/448

200184 30376 50452 SPS ITP $10,262,813 SPS Install new 345/230 kV transformer at Hobbs. 1/1/2020 1/1/2020 72 750015 Hobbs 345 kV 527894 Hobbs Interchange 230 1 345/230 448/448

200184 30376 50457 SPS ITP $137,452,487 SPS

Build new 100 mile Amoco - Hobbs 345 kV line.

Expand the Hobbs substation. 1/1/2020 1/1/2020 72 750014 Amoco 345 kV 750015 Hobbs 345 kV 1 345 113 1792/1792

30377 50454 SPS ITP $1,581,080 SPS Reconductor 1.5 miles line from Indiana to 6/1/2018 24 526146 Indiana Sub 115 kV 526076 Stanton Sub 115 kV 1 115 1.5 240/240

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30377 50455 SPS ITP $1,604,810 SPS Reconductor 4 miles from Indiana to SP-Erskine. 6/1/2018 24 526146 Indiana Sub 115 kV 526109 South Plains REC- 1 115 4 240/240

30379 50459 GRDA

Generation

Interconnection $2,500,000 GRDA

New GRDA 138 kV switching station at Pawnee.

New 138 kV three breaker ring bus substation

containing 3 138 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

located near Burbank, OK. SPP STUDY ID - ASGI- 6/1/2014 700001 138

30380 50460 GRDA

Generation

Interconnection $11,900,000 GRDA

Build new Fairfax (AECI) - Pawnee 138 kV line and

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-2010-006 12/31/2014 300139 Fairfax 700001 1 138 19.5

30381 50461 AEP

Generation

Interconnection $5,728,000Affected SYstems Facilities Construction Agreement SA 2234R1

At Shidler 138kV: Replace existing 138kV CB at

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 2/8/2014 510403 SHIDLER 138

30381 50646 OGE

Generation

Interconnection $399,300Osage Wind Facilities Construction Agreement SA 2502

Osage Substation:Replace Shidler 138kV line

terminal primary and redundant relaying with SEL

uProcessor based relays, install 3-138kV PTs,

Install 1-138kV CB, Install metering, Install 2000A

line Trap 1/15/2014 514743 OSAGE 138

30438 50533 GRDA Regional Reliability $161,100 GRDA

Replace 161kV, 1200A switch with a 2000A Switch

at Kerr substation bus. 6/1/2017 6/1/2017 12 months 512637 412SUB 161 512635 KERR 161 1 161 356/432

30401 50492 OPPD ITP $33,126,800 SPP

Build new 28 miles 345 kV Cass Co. - S.W. Omaha

(aka S3454) and associated terminal equipment 1/1/2033 645740 Sub 3740 645454 Sub 3454 1 345 28 1792/1792

30402 50493 OPPD ITP $12,600,000 SPP Install 2nd 345/161 kV 560 MVA S3459 1/1/2033 645459 Sub 3459 646209 Sub 1209 1 345/161 558/560

200190 30410 50503 SPS ITP $36,000,000 SPS

Rebuild 49-mile 69 kV line between Bowers and

Canadian with 795 ACSR conductor. 6/1/2015 6/1/2012 36 523747 Bowers Interchange 69 kV 523579 Canadian Sub 69 kV 1 69 10 39 52/69

200190 30411 50504 SPS ITP $1,554,313 SPS

Replace existing Howard 115/69 kV transformer

with new 84 MVA transformer. 6/1/2014 12/1/2012 36 523797 Howard 115 kV 523796 Grave Sub 69 kV 1 115/69 84/84

200190 30412 50505 SPS ITP $815,598 SPS

Add two banks of 7.2 Mvar capacitors at the

Kingsmill Interchange 115 kV substation. 12/31/2014 6/1/2013 36 523712

Kingsmill Interchange 115

kV 2 115 7.2 Mvar

200190 30413 50506 SPS ITP $3,216,093 SPS

Replace 230/115 kV transformer at Grapevine

substation with 250 MVA transformer. 6/1/2014 6/1/2014 36 523771

Grapevine Interchange

230 kV 523770

Grapevine Interchange

115 kV 1 230/115 250/250

200190 30414 50507 SPS ITP $1,127,389 SPS

Add two banks of 14.4 Mvar capacitors at the

Howard 115 kV substation. 6/1/2014 6/1/2014 36 523797 Howard 115 kV 2 115 28.8 Mvar

30416 50509 MKEC

Generation

Interconnection $28,200,834 MKEC

Build approximately 20 miles of 115 kV to serve as

second circuit between North Ft Dodge and

Spearville. Reroute Ft. Dodge - Greensburg 115 kV

to North Ft. Dodge Substation. Build second

circuit between Ft. Dodge and North Ft Dodge

(these stations are very close to each other). 11/8/2014 36 539671 Judson Large 115 KV 539771

North Judson Large 115

kV Sub 115 20

30417 50510 MKEC

Generation

Interconnection $31,460,024 MKEC

Add 345/115 kV transformer at Spearville.

Needed as Network Upgrade for GEN-2008-079

but cost shared with GEN-2006-006 & previously

with GEN-2009-062 prior to project withdrawal. 11/8/2014 36 531469 SPEARVILLE 539694 Spearville 115 KV 1 345/115

200193 30422 50515 SPS ITP $4,236,816 SPS

Upgrade Deaf Smith County Interchange 230/115

kV Ckt 1 transformer to 250 MVA. 3/1/2015 6/1/2012 24 524623

Deaf Smith County

Interchange 230 kV 524622

Deaf Smith County

Interchange 115 kV 1 230/115 250/250

200214 30423 50516 SPS ITP $4,225,233 SPS

Upgrade Deaf Smith Interchange 230/115 kV

transformer Ckt 2 to 250 MVA. 3/1/2015 6/1/2013 24 524623

Deaf Smith County

Interchange 230 kV 524622

Deaf Smith County

Interchange 115 kV 2 230/115 250/259

200214 30424 50517 SPS ITP $11,600,000 SPS

Rebuild 16.9-mile 115 kV line from Ochiltree to Tri-

County REC Cole Ckt 1. 12/31/2015 6/1/2013 24 523154

Ochilltree Interchange 115

kV 523120

Cole Interchange 115

kV 1 115 17 249/273

200210 30426 50519 MIDW ITP $11,128,231 MIDW

Build new 19.3-mile 115 kV line from Pheasant

Run to Seguin and install necessary terminal

equipment at Pheasant Run and Seguin

substations. 6/1/2014 6/1/2014 36 530559 PHEASANT RUN 115 KV 530683 1 115 19.3 164/199

200214 30429 50522 SPS ITP $22,191,845 SPS

Rebuild 25.8-mile 115 kV line from Crosby to

Floyd Ckt 1. 3/1/2015 6/1/2013 24 525926

Crosby County

Interchange 115 kV 525780

Floyd County

Interchange 115 kV 1 115 25.8 249/273

200214 30430 50523 SPS ITP $1,731,323 SPS

Install two 14.4 Mvar capacitors at Floyd 115 kV

substation. 12/31/2014 6/1/2013 12 525780

Floyd County Interchange

115 kV 115 28.8 Mvar

200212 30431 50526 WR ITP $5,561,163 WR Rebuild 3.1-mile 138 kV line from El Paso to 6/1/2014 6/1/2013 18 533039 EL PASO 138 KV 533042 FARBER 138 KV 1 138 3.1 245/245

200216 30436 50531 AEP ITP $1,000,000 AEP Replace 138 kV breaker at Perdue. 6/1/2016 6/1/2015 12 508560 NEW GLADEWATER 508351 PERDUE 138KV 138 272/272

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200228 30437 50534 WR Regional Reliability $27,938,225 WR

Build new 15.1-mile 115kV line between the new

Geary County substation and Chapman Tap. 10.4

miles of the line will be built as a 2nd circuit to the

existing Summit - McDowell Creek 345 kV line. 6/1/2017 6/1/2014 36 months 533336 Geary County 115 kV 533362 CHAPMAN 115 KV 1 115 10.42 4.67 218/262

30440 50535 GRDA Regional Reliability $161,100 GRDA

Replace 161kV, 1200A switch with a 2000A switch

at Kansas Tap substation. 6/1/2018 6/1/2018 12 months 512637 412SUB 161 512714 KANSAS TAP 161 1 161 356/432

200228 30437 50605 WR Regional Reliability $16,190,561 WR Install 345 kV ring bus at the new Geary County 6/1/2014 24 months 532767 Geary County 345 kV 345 1793/1793

200230 30496 50608 NPPD Regional Reliability $5,800,000 NPPD

Install new 345/115 kV 400 MVA transformer at

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. 6/1/2014 48 months 659135 STEGALL 345 kV 640530 Stegall 115 kV 1 345/115 400/440

200230 30496 50609 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 50608. 6/1/2014 48 months 640530 Stegall 115 kV 640338 Scottsbluff 1 115 23 400/440

200231 30496 50616 NPPD Regional Reliability $5,417,100 NPPD

Install any necessary terminal equipment at the

345 kV bus in Stegall substation. This upgrade is

contingent upon Basin Electric's approval noted in

Upgrade ID 50608. 6/1/2014 48 months 659135 STEGALL 345 kV 1 345

200214 30451 50546 SPS ITP $20,808,304 SPS

Build new 12-mile 115 kV line from Atoka to Eagle

Creek and install necessary terminal equipment. 12/31/2016 6/1/2015 36 527786 Atoka Interchange 115 kV 527711 Eagle Creek 115 kV 1 115 22.1 249/249

200214 30466 50560 SPS ITP $2,160,976 SPS

Upgrade Potash Junction 115/69 kV transformer

Ckt 1 to 84 MVA. 12/31/2014 6/1/2013 24 527962

Potash Junction

Interchange 115 kV 527961

Potash Junction

Interchange 69 kV 1 115/69 84/84

200214 30467 50561 SPS ITP $2,147,773 SPS

Upgrade Potash Junction 115/69 kV transformer

Ckt 2 to 84 MVA. 12/31/2014 6/1/2013 24 527962

Potash Junction

Interchange 115 kV 527961

Potash Junction

Interchange 69 kV 2 115/69 84/84

200229 30469 50563 SPS ITP $5,136,476 SPS

Build new 5.3-mile 115 kV line from the switching

station east of Kilgore substation to South

Portales and install necessary terminal

equipment. 6/1/2018 6/1/2018 524935 Zodiac Sub 115 kV 524949 S Portales 115 kV 1 115 5.3 159/175

200229 30469 50564 SPS ITP $6,498,682 SPS

Build new 6-mile 115 kV line from South Portales

to Market St. and install necessary terminal

equipment. 6/1/2018 6/1/2018 24 524949 S Portales 115 kV 524950 Market ST 115 kV 1 115 6 159/175

200229 30469 50565 SPS ITP $15,394,429 SPS

Build new 10.4-mile 115 kV line from Market St.

to Portales and install necessary terminal

equipment. 6/1/2018 6/1/2018 24 524950 Market ST 115 kV 524924

Portales Interchange

115 kV 1 115 10.4 159/175

200216 30471 50567 AEP ITP $16,548,317 AEP

Rebuild 13.2-mile 69 kV line from Dekalb to New

Boston with 1233.6 ACSR/TW. Upgrade CT ratios

and relay settings at New Boston. 6/1/2015 6/1/2013 24 508067 NEW BOSTON 508289 DEKALB 1 69 13.2 52/69

200216 30472 50568 AEP ITP $7,519,658 AEP

Rebuild 1.6-mile 69 kV line from Hardy Street to

Waterworks with 1233.6 ACSR/TW. 6/1/2015 6/1/2013 18 507734 HARDY STREET 507766 WATERWORKS 1 69 1.65 90/121

200216 30473 50569 AEP ITP $1,829,026 AEP

Rebuild 4.0-mile 69 kV line from Midland REC to

North Huntington with 1233.6 ACSR/TW. Upgrade

CT ratios, relay settings, and jumpers at North

Huntington. 6/1/2015 6/1/2013 24 507196 MIDLAND REC 507188

NORTH HUNTINGTON

69KV 1 69 4 143/143

200216 30474 50570 AEP ITP $5,653,353 AEP

Rebuild 1.3-mile 69 kV line from Midland to

Midland REC with 1233.6 ACSR/TW. Upgrade CT

ratios, relay settings, switches, and station

conductors at Midland. 6/1/2015 6/1/2013 18 507187 MIDLAND 507196 MIDLAND REC 1 69 4.3 150/217

200216 30475 50571 AEP ITP $9,145,130 AEP

Rebuild 7.0-mile portion of the 69 kV line from

Howe Interchange to Midland with 1233.6

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 6/1/2013 24 515259 HOWE INT 69 507187 MIDLAND 1 69 7 150/217

200202 30476 50572 GRDA Zonal Reliability $355,000 GRDA Increase line clearance for Chelsea - Childers 69 6/1/2015 6/1/2015 24 512725 CHELSEA 69 512723 CHILDERS 69 1 69 50/56

200207 30478 50574 OPPD ITP $260,590 OPPD Rebuild 1.6-mile 69 kV line from 915 Tap South to 6/1/2015 6/1/2015 12 647016 915 Tap in Ckt 623 647915 Sub 915 T2 Primary 1 69 1.6 65/65

200194 30481 50577 OGE

Transmission

Service $10,000 OGE Replace 400 amp CT in El Reno sub with 800 amp. 6/1/2017 6/1/2017 14 514818 EL RENO 69 514817 SERVICE PL EL RENO 69 69 72/72

200212 30483 50581 WR ITP $7,122,480 WR

Install a third 138/69 kV transformer at Gill

Energy Center. 12/1/2015 6/1/2015 18 533046

GILL ENERGY CENTER

SOUTH 138 KV 533795

GILL ENERGY CENTER

EAST 69 KV 1 138/69 150/165

200228 30484 50582 WR ITP $14,331,670 WR Install new 345/138 kV transformer at Viola 6/1/2016 6/1/2018 36 532798 Viola 7 533075 Viola 138kV 1 345/138 448/492

200228 30484 50583 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 6/1/2018 36 533075 Viola 138kV 533036 CLEARWATER 138KV 1 138 21.8 534/586

200228 30484 50584 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 6/1/2018 36 533075 Viola 138kV 533045

GILL ENERGY CENTER

WEST 138 KV 1 138 27.9 534/586

200228 30484 50612 WR ITP $5,007,657 WR Install 345 kV breakers at Viola substation. 6/1/2016 6/1/2018 36 532798 Viola 7 1 345 448/492

200199 30486 50586 OGE ITP $3,079,700 OGE Build 400 MVA 345/138 kV bus tie transformer at 3/15/2014 3/1/2013 1 345/138 400/400

200199 30486 50587 OGE ITP $11,659,600 OGE

Build substation at Renfrow and tap Woodring-

Wichita 345 kV line. 3/15/2014 3/1/2013 345 0.06

200199 30486 50588 OGE ITP $4,998,388 OGE

Build Grant County substation on the 69 kV line

between the Koch and Medford substations. 3/15/2014 3/1/2013 138

200199 30486 50589 OGE ITP $1,173,170 OGE Install a 138/69 kV transformer at Grant County 5/1/2014 3/1/2013 1 138/69 100/100

200199 30486 50590 OGE ITP $4,540,425 OGE Build 138 kV line from Renfrow to Grant County 10/1/2014 3/1/2013 138 11

200199 30486 50592 OGE ITP $587,690 OGE Convert Koch 69 kV substation to 138 kV. 9/1/2014 3/1/2013 138

200212 30487 50593 WR Zonal Reliability $767,165 WR Install 9.6 Mvar capacitor bank at Potwin 69 kV 6/1/2014 6/1/2013 533601 POTWIN 69 KV 69 9.6 Mvar

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200200 30488 50619 WFEC ITP $2,000,000 WFEC

Build new 138 kV line from Sandridge Tap to

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 1/1/2013 138 4

200200 30490 50599 WFEC ITP $237,000 WFEC

Install two 4.8 Mvar capacitors at Fairview 69 kV

for total of 9.6 Mvar. 2/1/2014 1/1/2013 69

200200 30491 50600 WFEC ITP $237,000 WFEC

Install two 4.8 Mvar capacitors at Hazelton 69 kV

for total of 9.6 Mvar. 2/1/2014 1/1/2013 520937 HAZELTON 69

200210 30494 50606 MIDW ITP $8,832,219 MIDW Rebuild 3.25-mile 115 kV line from Hays Plant to 6/1/2015 6/1/2013 30 530562 HAYS PLANT 115 KV 530553 SOUTH HAYS 115 KV 1 115 3.25 164/199

200231 30495 50607 AEP ITP $30,369,537 AEP

Build Messick 500/230 kV substation. Connect to

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 6/1/2013 30 999113 Messick 500 kV 999114 500/230 675/675

200231 30495 50615 AEP ITP $21,508,234 AEP

Install terminal equipment on 500 kV side of new

Messick substation. Connect to Mt. Olive -

Hartburg 500 kV line. This upgrade is contingent

upon approval from Cleco Power LLC for Upgrade

ID 50607. 12/31/2015 6/1/2013 30 999113 Messick 500 kV 1 500

200230 30496 50616 NPPD Regional Reliability $5,417,100 NPPD

Install any necessary terminal equipment at the

345 kV bus in Stegall substation. This upgrade is

contingent upon Basin Electric's approval noted in

Upgrade ID 50608. 6/1/2014 48 months 659135 STEGALL 345 kV 1 345

200220 30374 50621 NPPD Regional Reliability $17,804,878 NPPD

Install necessary terminal equipment at the 115

kV bus in the new Neligh substation. Construct

approximately 18 miles of new 115 kV

transmission to tie Neligh East 345/115 kV into

the existing 115 kV transmission system 6/1/2016 6/1/2016 39 months 640293 Neligh 115 kV 1 115 7 11.4

30552 50690 SPS Regional Reliability $973,674 SPS

Rebuild 0.5 miles of 115 kV line from OXY

Permian Sub to West Bender Sub. 6/1/2018 6/1/2018 528575 OXY Permian Sub 115 kV 528449

West Bender Sub 115

kV 1 115 0.5 276/303

200200 30497 50610 WFEC ITP $1,500,000 WFEC Reconductor Buffalo Bear - Buffalo 69 kV line with 7/1/2014 12/1/2013 520835 BUFFALO 521120 BUFFALO BEAR 2 69 14.5 72/89

200200 30497 50611 WFEC ITP $6,000,000 WFEC Reconductor Ft. Supply - Buffalo Bear 69 kV line 7/1/2014 12/1/2013 520919 FT SUPPLY 521120 BUFFALO BEAR 2 1 69 3.5 72/89

30500 50439 MKEC ITP $9,613,332 MKEC Reconductor 22.1 mile Harper to Milan Tap 138 3/1/2020 12 539668 Harper 138 KV 539675 Milan Tap 138 KV 1 138 22.11 261/314

200226 30501 50622 OGE ITP $3,195,056 OGE Build new 4-mile 138 kV line from Renfrow to 5/1/2014 5/1/2013 22 1 138 4 183/228

200234 30501 50624 WFEC ITP $3,540,000 WFEC

Build new 12-mile 138 kV line from new Pond

Creek substation to Oklahoma Gas and Electric

Co. interception point going towards Medford

Tap. 2/28/2014 5/1/2013 138 13 183/228

200226 30501 50625 OGE ITP $13,765,950 OGE

Build new 22-mile 138 kV line from Medford Tap

to new Doolin substation. 12/1/2015 6/1/2015 22 138 22 183/228

200226 30501 50627 OGE ITP $8,164,117 OGE

Build new 5-mile 138 kV line from Chikaskia to

new Doolin substation. 12/1/2015 5/1/2013 22 138 5 183/228

200226 30501 50629 OGE ITP $3,041,661 OGE Build new 138 kV Doolin switching station. 12/1/2015 5/1/2013 22 138 183/228

200226 30501 50630 OGE ITP $185,400 OGE

Install new 138 kV three-way transmission line

switch at Medford Tap. 5/1/2014 5/1/2013 22 138 183/228

200234 30502 50626 WFEC ITP $185,004 WFEC

Install new 138 kV 4.8-Mvar capacitor at Renfrow-

Sandridge substation. 6/1/2017 138 4.8 Mvar

200234 30503 50628 WFEC ITP $185,004 WFEC Install new 69 kV 4.8-Mvar capacitor at Hazelton 6/1/2017 69 4.8 Mvar

30553 50691 WR Regional Reliability $200,046 WR

Change CT setting from 600/5 to 1200/5 and

upgrade relays at both Butler and Weaver to get

to 160 MVA conductor limit. 6/1/2015 532991 WEAVER 138 KV 532989 Butler 138kV 1 138 143/160

30555 50693 SPS Regional Reliability $2,593,936 SPS

Install 4-breaker ring bus to connect the

Cunningham - PCA Interchange 115 kV line and

the Lea National - Maljamar 115 kV line. 6/1/2015 6/1/2015 528394 Quahada 115 kV 115 0.42

30556 50694 WR Regional Reliability $258,795 WR

Upgrade terminal equipment including the wave

trap at McDowell Creek Substation to a minimum

of 1200 Amps. 6/1/2014 6/1/2014 533335

MCDOWELL CREEK

SWITCHING STATION 115

KV 115 201/239

30558 50696 WR Regional Reliability $8,878,557 WR

Replace the existing Neosho #2 A, B, and C

transformers with a single transformer with a

minimum emergency rating of 165 MVA. Then, re-

terminate the Neosho 345/138 kV #1 transformer

from 533020-532793-532824 to 533021-532793-

532824. This will move the 138 kV connection of

this transformer from the Neosho South 138 kV

bus (533020) to the Neosho 138 kV center bus 6/1/2016 6/1/2014 533021 NEOSHO 138 KV 533768 NEOSHO 69 KV 1 345/138 0.5 150/165

30559 50697 AEP Regional Reliability $6,651,694 AEP

Rebuild 4.4 miles of 138 kV line from Chapel Hill

REC to Welsh Reserve 138 kV. 6/1/2019 6/1/2019 508337 ChapelL Hill REC 138 kV 508355 Welsh Reserve 138 kV 138 4.39 395/592

30560 50698 WR Zonal Reliability $51,513,963 WR Build new 28-mile 138 kV line from Viola to 6/1/2019 6/1/2019 532984 SUMNER COUNTY 138 kV 533075 Viola 138kV 1 138 28 262/314

30561 50699 OPPD Zonal Reliability $4,426,730 OPPD

Install new 161/69 kV auto transformer and 69kV

terminal equipment. 6/1/2016 646366 SUB 1366 161kV 647866 161/69 200/200

30562 50700 WFEC Regional Reliability $3,675,000 WFEC

Reconductor 9-mile 138 kV line from Red Hills to

Elk City. 6/1/2015 521116

RED HILLS WIND FARM

BUS 138 kV 511458 ELK CITY 138 1 138 9 183/228

30563 50702 WFEC Regional Reliability $504,000 WFEC Add 20 Mvar of capacitors at Sandy Corner 138 5/1/2017 6/1/2017 18 months 520204 Sandy Corner 138 kV 138 20 Mvar

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30565 50703 SEPC Regional Reliability $4,812,363 SEPC Install 24-Mvar capacitor at Mingo substation. 6/1/2014 24 months 531429 MINGO 1 115 24 Mvar

30566 50704 NPPD Regional Reliability $30,000 NPPD

Upgrade substation equipment at Maxwell and

North Platt substations to 1200 Amp to increase

line rating to 215 MVA. 6/1/2014 6/1/2014 12 months 640287 North Platte 115 kV 640267 Maxwell 115 kV 115 215/215

30568 50706 WR Zonal Reliability $1,390,166 WR

Install 10.8-Mvar capacitor bank at Clay Center

Switching Station (bus# 533320). 6/1/2016 6/1/2016 533320

Clay Center Switching

Station 115 kV 115 10.8 Mvar

30569 50708 SPS Regional Reliability $35,007,385 SPS

Build new 40-mile 230 kV line from Potash

Junction Interchange to new Road Runner

substation. Install any necessary 230 kV terminal

equipment at Potash Junction Interchange and

Road Runner. 12/1/2015 6/1/2016 527963

Potash Junction

Interchange 230 kV 528027 Road Runner 230 kV 1 230 40.4 497/547

30569 50709 SPS Regional Reliability $8,989,747 SPS

Install new Road Runner substation with a

230/115 kV 250 MVA transformer and 115 kV

terminal equipment. 12/1/2015 6/1/2016 528027 Road Runner 230 kV 528025 Road Runner 115 kV 1 230/115 250/250

30573 50718 AEP Regional Reliability $6,695,986 AEP

Rebuild 1.7-mile 69 kV line from Fort Humbug to

Broadmoor with 1233.6 ACSR/TW. Upgrade

jumpers at Fort Humbug and jumpers and bus at

Broadmoor. 6/1/2019 6/1/2019 507716 BROADMOOR 507730 FORT HUMBUG 69KV 1 69 1.7 136/143

30574 50719 AEP Regional Reliability $2,819,806 AEP

Rebuild 1.3-mile 69 kV line from Daingerfield to

Jenkins REC T with 959.6 ACSR/TW. 6/1/2019 6/1/2019 508288 DAINGERFIELD 508293 JENKINS REC T 69 1.3 132/178

30575 50720 AEP Regional Reliability $8,851,677 AEP

Rebuild 6.6-mile 69 kV line from Longview Heights

to Hallsville with 1233.6 ACSR/TW. Upgrade

jumpers, CT ratios, and relay settings at Longview

Heights. 6/1/2017 6/1/2014 508543 HALLSVILLE 508553

LONGVIEW HEIGHTS

69KV 1 69 6.6 68/89

30576 50721 AEP Regional Reliability $15,248,925 AEP

Rebuild 11.2-mile 69 kV line from Hallsville to

Marshall with 1233.6 ACSR/TW. Upgrade

jumpers, CT ratios, and relay settings at Marshall. 6/1/2017 6/1/2014 508556 MARSHALL 69KV 508543 HALLSVILLE 1 69 11.2 68/89

30577 50722 SPS Regional Reliability $4,701,279 SPS

Rebuild 5-mile 69 kV line from Chaves to Price

converting to 115 kV. Install necessary terminal

equipment at Chaves. 12/30/2017 6/1/2017 527482

Chaves County

Interchange 115 kV 527543 PRICE 3 115 kV 1 115 5 250/250

30577 50723 SPS Regional Reliability $4,158,668 SPS

Rebuild 3-mile 69 kV line from Price to CV Pines

converting to 115 kV. 6/1/2017 6/1/2017 527543 PRICE 3 115 kV 527542 CV-PINES 3 115 kV 1 115 3 245/245

30577 50724 SPS Regional Reliability $5,415,053 SPS

Rebuild 5-mile 69 kV line from CV Pines to Capitan

converting to 115 kV. 1/30/2016 6/1/2017 527542 CV-PINES 3 115 kV 527541 Capitan 115 kV 1 115 5 245/265

30578 50725 SPS Regional Reliability $6,941,335 SPP

Build 10-mile 115 kV line from Bailey County to

Bailey Pump. Install necessary terminal

equipment at Bailey County. 6/1/2016 525028

Bailey County Interchange

115 kV 525040 Bailey Pump 115 KV 1 115 10 276/304

30575 50720 AEP Regional Reliability $8,851,677 AEP

Rebuild 6.6-mile 69 kV line from Longview Heights

to Hallsville with 1233.6 ACSR/TW. Upgrade

jumpers, CT ratios, and relay settings at Longview

Heights. 6/1/2017 6/1/2014 508543 HALLSVILLE 508553

LONGVIEW HEIGHTS

69KV 1 69 6.6 68/89

30576 50721 AEP Regional Reliability $15,248,925 AEP

Rebuild 11.2-mile 69 kV line from Hallsville to

Marshall with 1233.6 ACSR/TW. Upgrade

jumpers, CT ratios, and relay settings at Marshall. 6/1/2017 6/1/2014 508556 MARSHALL 69KV 508543 HALLSVILLE 1 69 11.2 68/89

30577 50722 SPS Regional Reliability $4,701,279 SPS

Rebuild 5-mile 69 kV line from Chaves to Price

converting to 115 kV. Install necessary terminal

equipment at Chaves. 12/30/2017 6/1/2017 527482

Chaves County

Interchange 115 kV 527543 PRICE 3 115 kV 1 115 5 250/250

30577 50723 SPS Regional Reliability $4,158,668 SPS

Rebuild 3-mile 69 kV line from Price to CV Pines

converting to 115 kV. 6/1/2017 6/1/2017 527543 PRICE 3 115 kV 527542 CV-PINES 3 115 kV 1 115 3 245/245

30577 50724 SPS Regional Reliability $5,415,053 SPS

Rebuild 5-mile 69 kV line from CV Pines to Capitan

converting to 115 kV. 1/30/2016 6/1/2017 527542 CV-PINES 3 115 kV 527541 Capitan 115 kV 1 115 5 245/265

30578 50725 SPS Regional Reliability $6,941,335 SPP

Build 10-mile 115 kV line from Bailey County to

Bailey Pump. Install necessary terminal

equipment at Bailey County. 6/1/2016 525028

Bailey County Interchange

115 kV 525040 Bailey Pump 115 KV 1 115 10 276/304

30579 50726 WR Regional Reliability $7,405,817 WR

Rebuild 9.06-mile 69 kV line from Wellington to

Sumner County No. 4 Rome with single 1192

ACSR conductor to achieve 1200 Amp minimum

ampacity. 6/1/2016 6/1/2014 533553

SUMNER COUNTY NO. 4

ROME 69 KV 533560

CITY OF WELLINGTON

69 KV 69 9 96/96

30579 50727 WR Regional Reliability $7,988,648 WR

Rebuild 9.43-mile 69 kV line from Creswell to

Sumner County No. 4 Rome with single 1192

ACSR conductor to achieve 1200 Amp. 12/1/2015 6/1/2014 533543 CRESWELL 69 KV 533553

SUMNER COUNTY NO.

4 ROME 69 KV 69 9.5 96/96

30578 50729 SPS Regional Reliability $6,941,335 SPP

Build 10-mile 115 kV line from Bailey County

Pump to Sundan Rural and covert Bailey Pumb

and Sundan Rural distribution transformer high

side from 69 to 115 kV. 6/1/2016 525040 Bailey Pump 115 KV 525594 Sundan Rural 115 kV 1 115 10 276/304

30580 50730 WR Regional Reliability $7,752,352 WR Rebuild 5.64-mile 69 kV line from Crestview to 6/1/2015 6/1/2014 533822 NORTHEAST 69 KV 533789 CRESTVIEW 69 KV 69 5.59 131/143

30578 50731 SPS Regional Reliability $3,000,000 SPP

Install new 115/69 kV transformer 84 MVA.

Install necessary 69 kV terminal equipment. 6/1/2016 525600

Lamb County Sandhill 115

kV 525599

Lamb County REC-

Sandhill 115 kV 1 115/69 84/84

30578 50732 SPS Regional Reliability $2,845,947 SPP

Build 4.1-mile 115 kV line from Sudan Rural to

Lamb County REC Sandhill. Install 115 kV terminal

equipment for new 115/69 kV transformer. 6/1/2016 525594 Sundan Rural 115 kV 525600

Lamb County Sandhill

115 kV 1 115 4.1 276/304

30580 50733 WR Regional Reliability $2,829,128 WR

Rebuild 69 kV line from Kenmar to Northeast with

single 1192 ACSR to achieve 1200 Amp minimum

ampacity. 6/1/2016 6/1/2014 533822 NORTHEAST 69 KV 533811 KEN MAR 69 KV 69 1.74 131/143

30578 50734 SPS Regional Reliability $1,804,747 SPP

Build 2.6-mile 115 kV line from Lamb County REC

Sandhill to Amherst. Convert Amherst distribution

transformer high side from 69 kV to 115 kV. 6/1/2016 525600

Lamb County Sandhill 115

kV 525608 Amherst 115 kV 115 2.6 276/304

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30578 50735 SPS Regional Reliability $3,401,254 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. 6/1/2016 525608 Amherst 115 kV 525615 West Littlefield 115 kV 1 115 4.9 276/304

30578 50736 SPS Regional Reliability $4,858,935 SPP

Build 7-mile 115 kV line from West Littlefield to

Lamb County converting. Install necessary

terminal equipment at Lamb County. 6/1/2016 525615 West Littlefield 115 kV 525636

Lamb County

Interchange 115 kV 1 115 7 276/304

30582 50738 OGE Regional Reliability $740,254 OGE

Install a 9-Mvar capacitor bank at either County

Line or Wildhorse substation. 6/1/2017 6/1/2017 18 months 515126 County Line 69 kV 69 9 Mvar

30584 50739 WR Zonal Reliability $10,537,806 WR

Rebuild 9.7-mile 69kV line from Elk Junction to

Montgomery to 72 MVA. 6/1/2018 6/1/2018 533698 MONTGOMERY 69 KV 533690 ELK JUNCTION 69 KV 1 69 9.5 72/72

30584 50740 WR Zonal Reliability $32,548,502 WR

Rebuild 18.8-mile 69kV line from Elk Junction to

Sedan to 72 MVA. 6/1/2018 6/1/2018 533690 ELK JUNCTION 69 KV 533544

CANEY VALLEY NO. 5

SEDAN 69 KV 1 69 19 72/72

30583 50741 GMO Regional Reliability $2,773,480 GMO

Install a second 50 MVA 161/69 kV transformer at

Harrisonville including any 69 kV terminal

equipment. 1/30/2014 6/1/2014 541239 Harrisonville 161 KV 541295 Harrisonville 69 KV 2 161/69 50/55

30588 50745 OPPD Regional ReliabilityOPPD

New 161/69 kV transformer at Fremont to

accommodate a new 161 kV interconnection. 6/1/2019 646301 S1301 161kV 647801 S6801 8 69kV 161/69 134.4/134.4

30588 50746 OPPD Regional ReliabilityOPPD

Build new 3-mile 69 kV line from Fremont to new

substation S6801. 6/1/2019 647422 Fremont Sub B 647801 S6801 8 69kV 161/69 3 144/144

30588 50747 OPPD Regional Reliability $29,069,150 OPPD

Build new 17-mile 161 kV line from S1226 to new

substation S1301. 6/1/2019 646226 Sub 1226 646301 S1301 161kV 161 17 377/377

30590 50748 OPPD Regional Reliability $1,360,327 OPPD

Rebuild 1.34-mile 69 kV line from S906 to S924

with a new rating of 143 MVA. 6/1/2019 647906 Sub 906 South Bus 647924 Sub 924 69 1.34 143/143

30590 50749 OPPD Regional Reliability $69,679 OPPD

Substation improvements to increase S924 - S912

69 kV rating to 99 MVA. 6/1/2019 647912 Sub 912 647924 Sub 924 69 99/99

30589 50750 SEPC Regional Reliability $2,791,167 SEPC

Add an additional 12 Mvar of capacitance at

Ruleton substation. 6/1/2016 18 months 531357 RULETON 1 115 24 Mvar

856 50754 SPS Regional Reliability $93,130 SPS

Convert Hereford distribution transformer high

side from 69 kV to 115 kV. 12/15/2015 6/1/2014 524606

Hereford Interchange 115

kV 115

30596 50757 NPPD Regional Reliability $32,244,000 NPPD

Build a new 35-mile 115 kV line from Ord to

Broken Bow Wind and install necessary termal

equipment. 6/1/2014 36 months 640445 Broken Bow Wind 640308 Ord 1 115 42 160/176

30597 50758 OGE Regional Reliability $4,644,880 OGE

Install the new LANE 138-12.5 kV substation

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

OG&E to construct the new 1 ½ mile 138 kV Noel 6/1/2019 6/1/2019 30 months 514795 KNOBHILL 138 514794 KNOBHILL 69 138/69 1.6

30598 50759 AEP Regional Reliability $2,358,802 AEP

Build new 0.3-mile 69 kV line from Letourneau to

a tap point along the existing Air Liquide Tap line

with 664.8 ACSR/TW. Make the existing

Letourneau plant - Letourneau line section

normally open. 6/1/2017 6/1/2017 508536 LETOURNEAU STEEL 508594 Letouteau W tap 69 kV 69 0.3 150/150

30596 50760 NPPD Regional Reliability $329,600 NPPD

Increase line clearance on 115 kV line from North

Loup to Ord to 100 degree C. Upgrade disconnect

switches, CTs, and jumpers at North Loup. 6/1/2014 24 months 640284 North Loup 640308 Ord 2 115 137/151

30561 50761 OPPD Zonal Reliability $422,270 OPPD

Install 161 kV terminal equipment at S1366 for

new 161/69 kV transformer. 6/1/2016 646366 SUB 1366 161kV 161

30583 50762 GMO Regional Reliability $1,005,220 GMO

Install 161 kV terminal equipment for new second

161/69 kV transformer at Harrisonville. 1/30/2014 6/1/2014 541239 Harrisonville 161 KV 161

30591 50751 SPS

Generation

Interconnection $2,252,249GIA for GEN-2008-018 (SA 2258)

New 345kV Breaker Line Terminal, Disturbance

Monitoring Device, and 345kV Disconnect Switch. 10/1/2014

30592 50752 SPS

Generation

Interconnection $12,525,622GIA for GEN-2008-022 (SA 2305)

345kV ring bus substation including: three (3)

345kV circuit breakers, control house,

transmission line work, right-of-way, relay

upgrades, disturbance monitoring device,

reactors, and associated equipment. 5/1/2015

30593 50753 SEPC

Generation

Interconnection $4,264,906GIA for GEN-2010-015 (SA 2266)

345kV line terminal including two (2) 345kV

circuit breakers, disconnect switches, and all

associated and miscellaneous equipment. 9/10/2014

30581 50763 OGE Regional Reliability $4,634,000 OGE

Convert existing 4.32-mile 69 kV line from Ahloso

to Park Lane to 138 kV. 6/1/2017 6/1/2015 30 months 515178 PARK LANE 138 515318 Ahloso 138KV 1 138 4.39 268/286

30581 50764 OGE Regional Reliability $5,566,000 OGE

Convert existing 10.12-mile 69 kV line from

Ahloso to Harden City to 138 kV. 6/1/2015 6/1/2015 30 months 515318 Ahloso 138KV 515362 Harden City 138KV 1 138 10.12 268/286

30581 50765 OGE Regional Reliability $3,715,500 OGE

Convert existing 3.39-mile 69 kV line from Harden

City to Frisco to 138 kV. 6/1/2017 6/1/2015 30 months 515500 Frisco 138 kV 515362 Harden City 138KV 1 138 3.39 268/286

30581 50766 OGE Regional Reliability $7,083,000 OGE

Convert existing 3.39-mile 69 kV line from Frisco

to Lula to 138 kV. 6/1/2015 6/1/2015 30 months 515192 LULA 138 515500 Frisco 138 kV 1 138 8.3 268/286

30599 50769 AEP ITP $12,600,000 SPP Install new 345/161 kV Transformer at South 1/1/2033 1 345/161 400/440

$5,601,611

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30599 50770 TBD ITP $21,295,800 SPP

Build new 345 kV line from Chamber Springs to

South Fayetteville and associated terminal

equipment. 1/1/2033 1 345 18 1792/1792

30600 50771 GMO ITP $12,600,000 SPP Install new 345/161 transformer at Maryville. 1/1/2033 541197 Maryville 345 kV 300097 Maryville 1 345/161 400/440

30601 50772 KCPL ITP $12,600,000 SPP Increase rating of Nashua transformer to 650/715 1/1/2033 1 345/161 650/715

30602 50773 TBD ITP $130,141,000 SPP

Build new 110 mile 345 kV line from Keystone to

Red Willow and associated terminal equipment. 1/1/2033 640252 Keystone 640325 Red Willow 1 345 110 956/956

30603 50774 TBD ITP $75,718,400 SPP

Build new 64 mile 345 kV line from Tolk to Tuco

and associated terminal equipment. 1/1/2033 525549 Tolk Station 345 kV 525832

TUCO Interchange 345

kV 1 345 64 1792/1792

30604 50775 SEPC ITP $12,600,000 SPP Install 2nd 345/115 kV transformer at Holcomb. 1/1/2033 1/1/2033 531449 HOLCOMB 531448 HOLCOMB 2 345/115 435/435

30605 50776 TBD ITP $117,126,900 SPP

Build new 99 mile 345 kV line from Neosho to

Wolf Creek and associated terminal equipment. 1/1/2033 532797 WOLF CREEK 345 KV 532793 NEOSHO 345 KV 1 345 99 1792/1792

30606 50777 TBD ITP $15,701,325 SPP Rebuild 29 mile 161 kV line from Clinton to 1/1/2033 300071 Clinton 505502 Truman 1 161 29 554/554

30606 50778 TBD ITP $1,082,850 SPP Rebuild 2 miles of 161 kV line from North Warsaw 1/1/2033 505502 Truman 541314 North Warsaw 161 1 161 2 554/554

30607 50782 OGE ITP $34,605,675 SPP

Upgrade terminal equipment at Muskogee and

Pecan Creek substations to increase Muskogee -

Pecan Creek 345 kV Ckts 1 & 2 ratings to

1195/1195 MVA. 1/1/2033 515224 MUSKOGEE 345 515235 PECAN CREEK 345 1195/1195

30608 50779 WR ITP $12,600,000 SPP Install new 345/115 kV transformer at Auburn. 1/1/2033 2 345/115 435/435

30608 50780 TBD ITP $20,112,700 SPP

Convert 17 mile Auburn - Swissvale 230 kV line to

a 345 kV line. 1/1/2033 1 345 17 1792/1792

30608 50781 TBD ITP $35,493,000 SPP Convert the 30 mile Auburn - Jeffrey EC 230 kV to 1/1/2033 1 345 30 1792/1792

30609 50783 OPPD ITP Near Term $3,141,600 OPPD

Rebuild 3.3-mile 69 kV line from S907 to S919

with a new rating of 143 MVA. 6/1/2019 647907 Sub 907 647919 Sub 919 69 3.3

30616 50794 SPS Regional Reliability $813,381 SPS

Install two 115 kV brakers at Curry Couty

Interchange to covert the high side of the Curry

Couty distibion transformer to 115 kV 6/1/2018 6/1/2018 524822

Curry County Interchange

115 kV 115

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Southwest Power Pool, Inc.

39

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

SPS Southwestern Public Service Company

SWPA Southwestern Power Administration

WFEC Western Farmers Electric Cooperative

WR Westar Energy

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Southwest Power Pool, Inc.

40 2014 STEP Report

Figure Appendix A.1: Cost by Facility Type

Figure Appendix A.2: Percentage of Total Cost by Facility Type

$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

Raise Line/Line Work

Capactive/Reactive Devices

Voltage Conversion

Substation

Transformer

Rebuild/Re-Conductor

New Line

Cost By Facility Type (Billions)

Raise Line/ Line Work

0.02%

Capacitive/ Reactive Devices

.5%

Voltage Conversion

3%

Substation 6%

Transformer 9%

Rebuild/ Re-Conductor

12%

New Line 70%

% of Total Project Cost by Facility Type

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Figure Appendix A.3: Total Cost of Line Upgrades

Figure Appendix A.4: Total Miles of Line Upgrades by Project Type

$M

$200M

$400M

$600M

$800M

$1000M

$1200M

$1400M

$1600M

2014 2015 2016 2017 2018 2019 2020 2021 2022 2033

Cost of Line Upgrades

non-NTC

NTC

0

200

400

600

800

1000

1200

1400

1600

1800

2014 2015 2016 2017 2018 2019 2020 2021 2022 2033

Miles of Line Upgrades

New Lines Reconductor Voltage Conversion

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Figure Appendix A.5: Total Line Mileage by Voltage Class

Figure Appendix A.6: Line Cost by Voltage Class

0

500

1000

1500

2000

2500

3000

69 kV 115 kV 138 kV 161 kV 230 kV 345 kV

Mile

s Line Mileage by Voltage Class

$M

$500M

$1000M

$1500M

$2000M

$2500M

$3000M

$3500M

$4000M

69 kV 115 kV 138 kV 161 kV 230 kV 345 kV

Line Cost by Voltage Class

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Figure Appendix A.7: History of Total STEP Miles 2012-2033

Figure Appendix A.8: History of STEP New Line Miles

0

250

500

750

1000

1250

1500

1750

2000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2033

Mile

s

Year

History of Total Miles

2012STEP 2013STEP 2014 STEP

0

150

300

450

600

750

900

1050

1200

1350

1500

1650

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2033

Mile

s

Year

History of New Miles

2012STEP 2013STEP 2014 STEP

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Figure Appendix A.9: History of STEP Line Rebuilds and Conversions 2012-2033

Figure Appendix A.10: Costs of Transformer and Substation Upgrades

0

50

100

150

200

250

300

350

400

450

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2033

Mile

s

Year

History of Rebuilds and Conversions

2012STEP 2013STEP 2014 STEP

$M

$50M

$100M

$150M

$200M

$250M

$300M

$350M

2014 2015 2016 2017 2018 2019 2020 2021 2022 2033

Costs of Transformer and Substation Upgrades

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Figure Appendix A.11: Costs of Capacitive and Reactive Devices

$M

$2M

$4M

$6M

$8M

$10M

$12M

$14M

$16M

2014 2015 2016 2017 2018 2019 2020 2021 2022

Costs of Capacitive and Reactive Devices

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NTCs issued in 2013

NTC ID Project

ID Facility Owner

Project Name Current Cost

Estimate

200190a

805

30410 30411

30412 30413 30414

SPS SPS SPS SPS SPS SPS

Multi - Bowers - Howard 115 kV Ckt 1 Multi - Bowers - Howard 115 kV Ckt 1 Line - Bowers - Canadian 69 kV Rebuild XFR - Howard 115/69 kV Transformers XFR - Howard 115/69 kV Transformers Device - Kingsmill 115 kV Capacitors XFR - Grapevine 230/115 kV Transformer Ckt 1 Device - Howard 115 kV Capacitors

$3,100,001 $30,851,077 $36,000,000

$1,554,313 $2,709,236

$815,598 $3,216,093 $1,127,389

200200b

30488

30489 30490 30491 30497

WFEC WFEC WFEC WFEC WFEC

Multi - Renfrow - Wakita - Noel Switch 138 kV Multi - Renfrow - Wakita - Noel Switch 138 kV Multi - Renfrow - Wakita - Noel Switch 138 kV Multi - Renfrow - Wakita - Noel Switch 138 kV Device - White Horse 69 kV Device - Fairview 69 kV Device - Hazelton 69 kV Line - Buffalo - Buffalo Bear - Ft. Supply 69 kV Line - Buffalo - Buffalo Bear - Ft. Supply 69 kV

$17,928,848 $7,220,000 $3,573,553 $2,000,000

$237,000 $237,000 $237,000

$1,500,000 $6,000,000

200202c 30476 GRDA Line - Chelsea - Childers 69 kV $355,000

200204c

669 1017

30433 30441 30442 30445

669 1017 30433 30441 30442 30445

Line - Pecan Creek - Five Tribes 161 kV Ckt 1 Line - Classen - Southwest 5 Tap 138 kV Line - Arcadia - Redbud 345 kV Device - Gracemont 345 kV Device - Hunter 345 kV Device - Tatonga 345 kV

$2,591,900 $161,204

$1,010,523 $3,500,452 $3,500,452 $3,500,452

200205c

716 30419

GMO GMO

Line - Blue Spring South - Prairie Lee 161 kV Ckt 1 Device - St. Joe 161 kV

$20,537 $440,733

200206c

30210 30447

MKEC MKEC

Line - Harper - Milan Tap 138 kV Line - Haggard - Gray County - West Dodge 115 kV Ckt 1

$45,451 $15,523,790

200207c

865 30478 30479

OPPD OPPD OPPD

Line - Sub 917 - Sub 918 69 kV Ckt 1 Line - 915 Tap South in Ckt 623 - Sub 915 T2 69 kV Ckt 1 Sub - Sub 1366 161 kV

$475,340 $260,590

$11,067,000

200208c

909 WFEC Multi - Payne Switching Station - OU 138 kV conversion Multi - Payne Switching Station - OU 138 kV conversion Multi - Payne Switching Station - OU 138 kV conversion Multi - Payne Switching Station - OU 138 kV conversion

$1,705,000 $1,400,000 $3,000,000

$250,000

200209c 30427 SEPC XFR - Mingo 345/115 kV Ckt 2 $15,165,940

200210c

30426 30494

MIDW MIDW

Line - Pheasant Run - Seguin 115 kV Ckt 1 Line - Hays Plant - South Hays 115 kV Ckt 1 Rebuild

$11,128,231 $8,832,219

200211d 30349 WR XFR - Auburn Road 230/115 kV Transformer Ckt 1 $29,507,894

200212c

319

412 30369 30431 30483 30487

WR WR WR WR WR WR

Multi - Cowskin - Westlink - Tyler - Hoover 69 kV Rebuild Multi - Cowskin - Westlink - Tyler - Hoover 69 kV Rebuild Multi - Cowskin - Westlink - Tyler - Hoover 69 kV Rebuild Line - 64th - Eastborough 69 kV Rebuild XFR - Moundridge 138/115 kV Line - El Paso - Farber 138 kV Ckt 1 XFR - Gill 138/69 kV Ckt 3 Device - Potwin 69 kV Capacitor

$4,151,903 $5,834,124 $4,614,819 $4,104,097

$19,770,066 $5,561,163 $7,122,480

$767,165

200214c

486 802 839

841 940

1003 1031

SPS SPS SPS SPS SPS SPS SPS SPS SPS

XFR - Chaves 230/115 kV Transformer Ckt 2 XFR - Eddy Co. 230/115 kV Transformer Ckt 1 Multi - Kress Interchange - Kiser - Cox 115 kV Multi - Kress Interchange - Kiser - Cox 115 kV Multi - Kress Interchange - Kiser - Cox 115 kV XFR - Graham 115/69 kV Ckt 1 Multi - Hitchland - Woodward 345 kV (SPS) XFR - Grassland 230/115 kV Transformer Ckt 1 XFR - Crosby Co. 115/69 kV Transformers Ckt 1 and Ckt 2

$3,597,195 $4,255,145

$15,196,472 $8,300,000 $6,400,000 $2,101,391

$13,159,749 $3,961,322 $2,378,798

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NTC ID Project

ID Facility Owner

Project Name Current Cost

Estimate

1139 1143 1147

30423 30424 30428 30429 30430 30451 30452 30466 30467

SPS SPS SPS SPS SPS SPS SPS SPS SPS SPS SPS SPS SPS SPS SPS

XFR - Crosby Co. 115/69 kV Transformers Ckt 1 and Ckt 2 Line - Allen Sub - Lubbock South Interchange 115 kV Ckt 1 XFR - Lubbock South 230/115/13.2 kV Ckt 2 Multi - Potter - Channing - Dallam 230 kV Conversion Multi - Potter - Channing - Dallam 230 kV Conversion Multi - Potter - Channing - Dallam 230 kV Conversion XFR - Deaf Smith County Interchange 230/115 kV Ckt 2 Line - Ochiltree - Tri-County Cole 115 kV Ckt 1 Device - Red Bluff 115 kV Capacitor Line - Crosby - Floyd 115 kV Ckt 1 Device - Floyd 115 kV Capacitor Line - Atoka - Eagle Creek 115 kV Ckt 1 Line - Oxy Permian - Sanger Switching Station 115 kV Ckt 1 XFR - Potash Junction 115/69 kV Ckt 1 XFR - Potash Junction 115/69 kV Ckt 2

$2,301,000 $10,946,449

$4,679,150 $1,819,440 $9,166,904 $3,863,195 $4,225,233

$11,332,148 $1,999,300

$22,191,845 $1,731,323

$20,808,304 $299,150

$2,127,697 $2,114,753

200216c

451 478 501 502 504 512 681 879

1012 30436 30471 30472 30473 30474 30475

AEP AEP AEP AEP AEP AEP AEP AEP AEP AEP AEP AEP AEP AEP AEP

Line - Chamber Springs - Farmington 161 kV Line - Forbing Tap - South Shreveport 69 kV Line - Evenside - Northwest Henderson 69 kV Line - Northwest Henderson - Poynter 69 kV Line - Brownlee - North Market 69 kV Line - Ellerbe Road - Forbing Tap 69 kV Line - Broadmoor - Fern Street 69 kV Line - Bluebell - Prattville 138 kV Line - Diana - Perdue 138 kV Reconductor Line - New Gladewater - Perdue 138 kV Line - Dekalb - New Boston 69 kV Line - Hardy Street - Waterworks 69 kV Line - Midland REC - North Huntington 69 kV Line - Midland - Midland REC 69 kV Line - Howe Interchange - Midland 69 kV

$12,705,537 $1,221,505

$11,980,465 $7,815,833

$12,424,849 $8,174,689 $4,923,124

$10,241,314 $18,805,489

$1,000,000 $16,548,317

$7,519,658 $1,829,026 $5,653,353 $9,145,130

200218c 30207 NPPD Device - Cozad 115 kV $677,370

200220e

30374

30375

NPPD NPPD NPPD NPPD NPPD NPPD NPPD

Multi - Hoskins - Neligh 345 kV Multi - Hoskins - Neligh 345 kV Multi - Hoskins - Neligh 345 kV Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Multi - Gentleman - Cherry Co. - Holt Co. 345 kV

$68,774,278 $12,118,564 $17,804,878

$139,090,440 $11,896,383

$146,065,000 $16,324,800

200221e 30367 WR Multi - Elm Creek - Summit 345 kV $66,202,442

200222e

30367

ITCGP ITCGP ITCGP ITCGP

Multi - Elm Creek - Summit 345 kV Multi - Elm Creek - Summit 345 kV Multi - Elm Creek - Summit 345 kV Multi - Elm Creek - Summit 345 kV

$31,312,169 $5,405,101 $8,243,291 $1,886,035

200223e

30364

OGE OGE OGE OGE

Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV

$59,522,400

$65,785,650

$32,936,400

$19,967,850

200226f

30501

OGE OGE OGE OGE OGE

Multi - Renfrow - Medford Tap - Chikaskia 138 kV Multi - Renfrow - Medford Tap - Chikaskia 138 kV Multi - Renfrow - Medford Tap - Chikaskia 138 kV Multi - Renfrow - Medford Tap - Chikaskia 138 kV Multi - Renfrow - Medford Tap - Chikaskia 138 kV

$3,195,056 $13,765,950

$8,164,117 $3,041,661

$185,400

200228c

30437

30484

WR WR WR WR WR

Multi - Geary County 345/115 kV and Geary - Chapman 115 kV Multi - Geary County 345/115 kV and Geary - Chapman 115 kV Multi - Geary County 345/115 kV and Geary - Chapman 115 kV Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill Multi - Viola 345/138kV Transformer and 138 kV Lines to

$20,530,196 $27,938,225 $16,190,561 $14,331,670

$35,992,903

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NTC ID Project

ID Facility Owner

Project Name Current Cost

Estimate

WR WR

Clearwater and Gill Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill

$22,234,744

$5,007,657

200229c

772 30469

SPS SPS SPS SPS

Line - Carlisle - Wolfforth 230 kV Multi - Kilgore Switch - South Portales - Market St. - Portales 115 kV Multi - Kilgore Switch - South Portales - Market St. - Portales 115 kV Multi - Kilgore Switch - South Portales - Market St. - Portales 115 kV

$32,429,240 $5,136,476 $6,498,682

$15,394,429

200230c

30496

NPPD NPPD NPPD

Multi - Stegall 345/115 kV and Stegall - Scottsbluff 115 kV Multi - Stegall 345/115 kV and Stegall - Scottsbluff 115 kV Multi - Stegall 345/115 kV and Stegall - Scottsbluff 115 kV

$5,800,000 $23,782,900

$5,417,100

200231c

30432 30449 30495

AEP AEP AEP AEP

Line - 52nd & Delaware West Tap - Riverside Station 138 kV Line - Rock Hill - Springridge Pan-Harr REC 138 kV Ckt 1 Sub - Messick 500/230 kV Sub - Messick 500/230 kV

$24,992,196 $25,060,655 $30,369,537 $21,508,234

200234f

30501 30502 30503

WFEC WFEC WFEC

Multi - Renfrow - Medford Tap - Chikaskia 138 kV Device - Renfrow-Sandridge 138 kV Device - Hazelton 69 kV #2

$3,540,000 $185,004 $185,004

aDPA-2011-SEPTEMBER-095

bDPA-2012-March-143-147

c2013 ITPNT

d2012 ITP Near -Term Assessment removing the conditions previously placed on the Auburn transformer

e2012 ITP10

fDPA-2012-151,154,161,218,243

Table Appendix B.0.1: NTCs Issued in 2013

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Appendix C: 2013 ITP20 Project List

Name Type Size Focus

Keystone – Red Willow New Branch 345 kV Reliability

Tolk – Tuco New Branch 345 kV Reliability

S3459 2nd Transformer 345/161 kV Economic

Holcomb 2nd Transformer 345/115 kV Reliability

Maryville New Transformer 345/161 kV Reliability

Pecan Creek – Muskogee Upgrade 2 circuits 345 kV Reliability

Nashua Upgrade Transformer 345/161 kV Reliability

JEC – Auburn Hills – Swissvale Rebuild (New Auburn Hills transformer)

345 kV, 345/115 kV Reliability

Clinton – Truman – N Warsaw Upgrade Branch 161 kV Reliability

S3740 - S3454 New Branch 345 kV Reliability

Chamber Springs – S Fayetteville

New Branch & Transformer

345 KV, 345/161 kV Economic

Wolf Creek - Neosho New Branch 345 kV Economic

Table Appendix C.1: 2013 ITP20 Project List

Figure Appendix C.0.1: 2013 ITP20 Project Map

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Appendix D: 2014 ITPNT Project List

Reliability Project Project Area(s)

Potential Violation Miles Added/ Modified

XFR - Swisher 230/115 kV Transformer Ckt 1 Upgrade

SPS Swisher 230/115 kV Transformer

0

Device - Vaughn Cap 115 kV WR Low voltage at East Eureka 115kV

0

Multi - Hoskins - Neligh 345 kV NPPD Overload of the Battle Creek - County Line 115 kV line

59.4

Multi - Geary County 345/115 kV and Geary - Chapman 115 kV

WR Low voltages along the Abilene - Chapman 115 kV line

15.09

Multi - Stegall 345/115 kV and Stegall - Scottsbluff 115 kV

NPPD Stegall 345/230 kV Transformer Ckt 2 and Stegall Tap 230 kV Ckt 2

23

XFR - Newhart 230/115 kV Ckt 2 SPS Kress Interchange-Swisher County Interchange 115 kV Ckt 1 overload

0

Line - Welsh Reserve - Wilkes 138 kV reconductor

AEP Line overload 23.74

Line - East Manhattan - JEC 230 kV WR East Manhattan - Jeffrey Energy Center 230kV line overload

27

SUB- Kerr - 412Sub 161kV Ckt 1 GRDA Kerr to 412 Sub overload 0

Line - 412 Sub - Kansas Tap 161kV Ckt 1 Switch

GRDA 412 Sub to Kansas Tap Sub 161kV line overload

0

Multi-Bailey Co-Lamb County Conversion 115 KV

SPS Lamb County 115/69 kV transformer overloads

38.6

Multi - Park Lane - Lula 69/138 kV voltage conversion

OGE

Park Lane - Ahloso Tap - Harden Tap,Valley View - Ada Industrial - Park Lane, and FRSCOTP – SOCPMT overloads and low voltages

22.8

Line - Wellington - Creswell 69 kV WR Creswell - Sumner County No.4 Rome 69 kV Ckt 1 facility overloads

18.5

Device - County Line 69 kV Cap OGE Mobil Oil 69 kV and Wildhorse 69 kV facilities voltage violations

0

XFR - Harrisonvile 161/69 kV GMO Harrisonville 161/69 kV Transformer Ckt 1 facility overloads

0

Line - Montgomery - Sedan 69kV WR Elk River 69 kV low voltages 28.5

Multi - Fremont 161/69 kV OPPD Fremont 115/69 kV transformer overloads; OPPD and NPPD area overloads;

20

Sub - Ruleton 115 kV SEPC Low voltages on multiple buses in Sunflower and Midwest

0

Multi-Broken Bow Wind-Ord 115 kV Ckt 1

NPPD North loup 115 kV,Ord 115 kV and Spalding 115 kV low voltages

42

XFR - Knobhill 138/12.5 kV OGE ALVA,CZYCRVT2,HELENA TAP,KNOBHILL,SALINE low voltages

1.6

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Line - Sub 907 - Sub 919 OPPD Sub 907 - Sub 919 69 kV line overloads

3.3

Line - OXY Permian Sub - West Bender Sub 115 kV Ckt rebuild

SPS OXY Permian Sub-West Bender Sub 115 kV Ckt 1 overload

.5

Sub - Butler - Weaver 138kV Terminal Equipment

WR Butler - Weaver 138kV Ckt 1 overload

0

Quahada Switching Station 115 kV

SPS Maljamr 115 kV system low voltage

.42

Sub - McDowell Creek Switching Station 115kV Terminal Upgrades

WR

Fort Junction Switching Station - McDowell Creek Switching Station 115kV Ckts 1 and 2 overload

0

XFR - Neosho 345/138kV WR Neosho 161/138/13.2kV Transformer Ckt 1 overload

.5

Line-Chapel Hill REC-Welsh Reserve 138 kV Ckt 1 rebuild

AEP Chapel Hill Reserve - Welsh Reserve 138 kV Ckt1 overload

4.4

Line - Sumner County - Viola 138kV WR

Creswell, Farber, Oxford, Sumner, Belle Plain, TC-Rock and Timber Junction low voltages

28

XFR - S1366 161/69kV OPPD Sub 1244 and S1366 voltage violations

0

Line - Elk City - Red Hills 138kV WFEC Elk City - Red Hills 138kV Ckt 1 base case overload

9

Sub - Sandy Corner 138kV WFEC Sand Ridge to Knob Hill138 kV low voltage

0

Sub - Keystone - Ogalala 115 kV Terminal Upgrades

NPPD Keystone - Ogalala 115 kV line overloads

0

Sub - Maxwell - North Platt 115 kV Terminal Upgrades

NPPD Maxwell - North Platte 115 kV overloads

0

Sub - Clay Center Switching Station 115kV

WR Clay Center area low voltages 0

Multi-Potash Junction Interchange - Road Runner 230 kV line and 230/115 kV XF

SPS Potash Junction Interchange 230/115 kV transformer overloads

40

Line - Battle Creek - North Norfolk 115 kV Ckt 1 Reconductor

NPPD Accommodate new line rating of 193 MVA

3.5

Curry County 115 kV SPS Curry County Interchange 116/69 kV transformer Ckt 2 overloads

0

Multi - convert Centre St load and Hereford load from 69 to 115 kV

SPS

Hereford 115/69 kV transformers Ckt 1 and Ckt 2 for the outage of the parallel transformer

7.8

Sub - Mingo 115 kV SEPC Mingo xfrm low voltages 0

Multi-Chavis-Price-CV Pines-Capitan 69 kV to 115 kV

SPS Chaves County Interchange 115/69 kV transformer base case overloads

13

Ellerbe Road - Forbing T 69 kV Ckt 1 AEP Ellerbe Road - Forbing Road 69 kV Ckt 1 overloads

2

Mustang - Sunshine Canyon 69 kV Ckt 1

WFEC Mustang - Sunshine Canyon 69kV Ckt 1 overloads

9.9

Broadmoor - Fort Humbug 69 kV Rebuild Ckt 1

AEP Broadmoor-Fort Humbug 69 kV overloads

1.7

Dangerfield - Jenkins REC T 69 kV Rebuild Ckt 1

AEP Daingerfield-Jenkins T 69 kV overload

1.3

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Hallsville - Longview Heights 69 kV Rebuild Ckt 1

AEP Hallsville-Longview Heights Ckt 1 69 kV overload

6.6

Hallsville-Marshall 69 kV Rebuild Ckt 1 AEP Hallsville-Marshall 69 kV Ckt 1 overload

11.2

City of Wellington - Sumner County No.4 Rome 69 kV Rebuild Ckt 1

WR City Of Wellington - Sumner County No.4 Rome 69 kV Ckt 1 overload

9.06

Kenmar - Northeast 69 kV Rebuild Ckt 1 WR Ken mar - Northeast 69 kV Ckt 1 overload

1.7

Crestview - Northeast 69 kV Ckt 1 WR Crestview - Northeast 69 kV Ckt 1 overload

5.6

Elk Junction - Montgomery 69kV Ckt 1 WR Elk River 69 kV low voltage 9.7

S906 - S924 69kV Rebuild Ckt 1 OPPD SUB 906 SOUTH - SUB 924 69KV CKT 1 overload

1.34

S924 - S912 69 kV Terminal Upgrades OPPD SUB 912 - SUB 924 69KV CKT 1 overloads

0

Letorneau - Air Liquide Tap 69 kV Ckt 1 AEP Letorneau - Letourneau Tap 69 kV overloads

.3

Table Appendix D.1:2014 ITPNT Project List

Figure Appendix D.0.1: 2014 ITPNT Violations and Draft Solutions Map

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Appendix E: Projects Completed in 2013

ITP Projects Completed in 2013

NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

20111 156 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV $19,178,968*

20111 156 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV $8,121,300*

20130 156 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV $1,491,086*

20006 172 WR Line - Tecumseh Energy Center - Midland 115 kV $5,471,093

20059 182 WR Line - Chase - White Junction 69 kV $6,066,000

20003 238 WFEC Line - Atoka - WFEC Tupelo - Lane 138 kV $8,265,000

20003 243 WFEC Multi - OU SW - Goldsby - Canadian SW 138 kV $2,753,800

20003 243 WFEC Multi - OU SW - Goldsby - Canadian SW 138 kV $2,250,000

20003 243 WFEC Multi - OU SW - Goldsby - Canadian SW 138 kV $5,000,000

20021 299 GRDA Multi - Kansas Tap - Siloam City 161KV $4,372,000

20021 299 GRDA Multi - Kansas Tap - Siloam City 161KV $1,831,000

20027 443 AEP Line - Osborne - Osborne Tap $2,000,000

20081 551 OGE Multi - Johnson - Massard 161 kV $6,200,000

20063 563 WR Multi - Litchfield - Aquarius - Hudson Jct. 69 kV Uprate $181,444

563 WR Multi - Litchfield - Aquarius - Hudson Jct. 69 kV Uprate $150,000

20030 616 WFEC Multi: WFEC-Dover-Twin Lake_Cresent-Cottonwood conversion 138 kV

$3,164,000

200175 624 WR Line - Fort Junction - West Junction City 115 kV $6,969,136

20034 634 GMO Multi - Loma Vista - Montrose 161 kV - Tap into K.C. South $3,527,710

20029 642 OGE Line - Kilgore - VBI 69 kV $19,783

20034 650 GMO Multi - South Harper 161 kV cut-in to Stilwell-Archie Junction 161 kV line

$3,281,565

20132 659 WFEC Line - Reeding - Twin Lakes Switchyard conversion to 138 kV $1,971,000

200205 716 GMO Line - Blue Spring South - Prairie Lee 161 kV Ckt 1 $20,537

20073 767 AEP Multi - Canadian River - McAlester City - Dustin 138 kV $24,965,000

20073 767 AEP Multi - Canadian River - McAlester City - Dustin 138 kV $9,513,000

20073 767 AEP Multi - Canadian River - McAlester City - Dustin 138 kV $4,096,000

20064 770 AEP Line - Ashdown - Craig Junction 138 kV Rebuild $2,500,000

20084 783 SPS XFR - Install 2nd Randall 230/115 kV transformer $7,997,141*

20130 792 SPS Line - Cunningham - Buckey Tap 115 kV reconductor $3,516,246*

20080 817 NPPD Line - Albion - Spalding 115 kV $1,200,869

20084 829 SPS XFR - Kingsmill 115/69 kV Ckt 2 $4,400,000

20088 835 SPS Multi - Move Load from East Clovis 69 kV to East Clovis 115 kV $2,125,000

20084 851 SPS Line - Harrington - Randall County 230 kV $159,060*

200198 858 OGE Multi - Cushing Area 138 kV $15,000,000

20084 888 SPS Line - Randall - Amarillo S 230 kV Ckt 1 $20,078,082*

20081 892 OGE Sub - Canadian River Substation $9,453,000

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54 2014 STEP Report

NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

20138 899 SEPC Line - Holcomb - Fletcher 115 kV Ckt 1 $4,100,000

20126 997 MIDW XFR - Colby 69/34.5 kV TrXFR - Colby 115/34.5 kV Transformer Ckt 4

$1,097,586

20130 1005 SPS Line - Wolford-Yuma 115 kV Ckt 1 Wave Trap $116,520*

20122 1081 AEP Line - Hooks - Lone Star Ordinance 69 kV Ckt 1 $2,100,000

20117 1094 NPPD Line - Canaday - Lexington 115Kv Ckt 1 $513,981

200169 1135 KCPL Line - Loma Vista East - Winchester Junction North 161kV Ckt 1 $176,118*

200166 1141 SPS XFR - Spearman 115/69/13.2 Ckt 1 Upgrade $2,100,000*

20007 30098 MKEC Device - Plainville Cap 115 kV $1,500,000

20122 30148 AEP Line - Bann - Lone Star Ordinance 69 kV Ckt 1 $6,600,000

20078 30190 MIDW Device-Pawnee 115 kV $712,979

200206 30210 MKEC Line - Harper - Milan Tap 138 kV $45,451

200170 30237 NPPD Device - Holdrege 115 kV $547,656*

200174 30302 OGE XFR - Paoli 138/69 kV $1,537,212*

20135 30319 AEP Line - Pirkey - Whitney 115 kV ckt 1 $900,000

200175 30348 WR Line - Cowskin - Centennial 138 kV rebuild $3,676,071

200171 30352 LES Line - Folsom & Pleasant Hill - Sheldon 115 kV Ckt 2 $6,382,777

200174 30357 OGE Device - Lula 69 kV $561,667

200190 30411 SPS XFR - Howard 115/69 kV Transformers $2,709,236

200205 30419 GMO Device - St. Joe 161 kV $440,733

200214 30428 SPS Device - Red Bluff 115 kV Capacitor $1,999,300

200207 30479 OPPD Sub - Sub 1366 161 kV $11,067,000

200200 30488 WFEC Multi - Renfrow - Wakita - Noel Switch 138 kV $17,928,848

200200 30488 WFEC Multi - Renfrow - Wakita - Noel Switch 138 kV $7,220,000

200200 30488 WFEC Multi - Renfrow - Wakita - Noel Switch 138 kV $3,573,553

*Final Cost

Table Appendix E.1: ITP Projects Completed in 2013

Transmission Service Projects Completed in 2013

NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

19964 375 WR XFR - Rose Hill 345/138 kV Ckt 3 $10,387,399

20067 903 MKEC Line - Clifton - Greenleaf 115 kV $6,063,189

20067 905 MKEC Line - Flatridge - Harper 138 kV $11,305,800

20107 1020 MKEC Line - Greenleaf - Knob Hill 115kV Ckt 1 $5,354,646

20112 1023 AEP Line - Southwest Shreveport - Springridge REC 138 kV $7,200,000

20112 1024 AEP Line - Eastex - Whitney 138 kV Accelerated $2,800,000

20114 1025 WFEC ALTUS SW - NAVAJO 69KV CKT 1 $150,000

20067 30211 MKEC XFR - Medicine Lodge 138/115 kV $10,555,536

20091 30224 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek 69 kV

$3,535,570

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NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

20059 30227 WR Device - Athens 69 kV Capacitor $700,000

20068 30271 WR Device - Dearing 138 kV Capacitor $1,215,000

20116 30291 KCPL Line - Stilwell - West Gardner 345 kV Ckt 1 $457,827*

20135 30316 AEP XFR - Diana 345/138 kV ckt 3 $5,500,000

200197 30406 WR Line - Greenleaf - Knob Hill 115 kV CKT 1 WR $456,403

*Final Cost

Table Appendix E.2: Transmission Service Projects Completed in 2013

Generation Interconnection Projects Completed in 2013

NTC ID Project

ID Project Owner

Upgrade Name Current Cost

Estimate

NA 30384 MIDW Rice - Lyons 115 kV Ckt 1 $3,245,758

NA 30499 SPS Sub - Lopez Switching Station $151,581*

NA 30499 SPS Lopez 115kV Substation $3,371,204*

*Final Cost

Table Appendix E.3: Generation Interconnection Projects Completed in 2103

Balanced Portfolio Projects Completed in 2013

NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

20040 698 GRDA Line - Cleveland – Sooner 345 kV $3,718,139*

20042 702 KCPL Tap – Swissvale – Stilwell $1,922,840

20084 704 SPS Multi - Tuco - Woodward 345 kV $16,234,558

*Final Cost

Table Appendix E.4: Balanced Portfolio Projects Completed in 2013

Priority Projects Completed in 2013

NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

NA

Table Appendix E.5: Priority Projects Completed in 2013

Sponsored Projects Completed in 2013

NTC ID Project

ID Project Owner

Project Name Current Cost

Estimate

NA

Table Appendix E.6: Sponsored Projects Completed in 2013