RSC Minutes & Attachments 20182901.pdf - Southwest Power ...

Southwest Power Pool REGIONAL STATE COMMITTEE

Skirvin Hotel, Oklahoma City, OK January 29, 2018

• MINUTES •

ADMINISTRATIVE ITEMS The following members participated:

Shari Feist Albrecht, Kansas Corporation Commission (KCC) Kristie Fiegen, South Dakota Public Utilities Commission (SDPUC) Randy Christmann, North Dakota Public Service Commission (NDPSC) Dennis Grennan, Nebraska Power Review Board (NPRB) Geri Huser, Iowa Utilities Board (IUB) Patrick Lyons, New Mexico Public Regulation Commission (NMPRC) Dana Murphy, Oklahoma Corporation Commission (OCC) Kim O’Guinn, Arkansas Public Service Commission (APSC) Scott Rupp, Missouri Public Service Commission (MoPSC)

DeAnn T. Walker, Public Utility Commission of Texas (PUCT) President Shari Feist Albrecht called the Regional State Committee (RSC) meeting to order at 1:06 p.m. with roll call, and a quorum was declared. President Albrecht welcomed Commissioner Scott Rupp from the Missouri Public Service Commission and Mr. Lane Sisung from the Louisiana Public Service Commission. Lane will be the Cost Allocation Working Group representative. Commissioner Foster Campbell will represent the commission on the RSC. President Albrecht requested introductions of those in attendance. There were 125 people in attendance, either in person or via the phone (Attendance & Proxies – Attachment 1). The first item of business was the approval of the 10/30/17 meeting minutes (RSC Minutes 10/30/17 – Attachment 2). Commissioner DeAnn Walker moved to approve the minutes with corrections; Commissioner Geri Huser seconded. The motion was approved unanimously. Ms. Kandi Hughes (SPP staff) reviewed the RSC action items (RSC Action Items – Attachment 3). UPDATES RSC Fourth Quarter Financial Report Mr. Paul Suskie (SPP staff) provided the financial report for the fourth quarter (RSC 2017 Q4 Financials – Attachment 4). He noted that the RSC was under budget for the fourth quarter with the exception of the audit. Federal Energy Regulatory Commission (FERC) Report Mr. Patrick Clarey (FERC staff) provided the FERC report. Mr. Clarey reported that FERC was now operating with five commissioners after the swearing in of Chairman Kevin McIntyre. The full commission held open meetings in December and January.

Regional State Committee January 29, 2018

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At the December meeting, Chair McIntyre announced FERC will examine the Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, adopted in 1999, as part of a pledge he made during his Senate confirmation to take a fresh look at all aspects of the agency’s work. The next steps will be announced in the near future. On January 8th, FERC terminated the proceeding it initiated in Docket No. RM18-1-000 to consider the Department of Energy’s September 29 proposal on grid reliability and resilience pricing. In addition, the Commission initiated a new proceeding, Docket No. AD18-7-000, to holistically examine the resilience of the bulk power system. In Docket No. AD18-7, the Commission directs operators of the regional wholesale power markets to provide information as to whether FERC and the markets need to take additional action on resilience of the bulk power system. The goals of the proceeding are to: (1) develop a common understanding among the Commission, industry and others of what resilience of the bulk power system means and requires; (2) understand how each regional transmission organization and independent system operator assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional Commission action regarding resilience is appropriate. Each regional market operator must submit the required information within 60 days of issuance of the order. FERC also invited other interested entities to respond to the market operators’ comments. SPP Report Mr. Nick Brown (SPP staff) provided the SPP update. He began his report by discussing the plan for putting together comments to FERC on the resilience docket. SPP has until March 9 to respond to 39 questions posed by FERC. SPP staff will work with the Strategic Planning Committee (SPC) to pull the information together in response to the questions. This is a very broad topic. Paul Suskie has the questions posed by FERC. If you are interested in reviewing the questions and the information please contact Paul. The goal is to distribute a draft of the SPP response to the SPC by February 20. SPP will then host an SPC webinar on February 23. Resiliency has been looked at in the past as a subcategory of reliability. It is now taking a lead in the consideration of reliability. Mr. Brown also provided an update on Mountain West Transmission Group efforts over the last nine months. There have been a number of forums and meetings involving members, the RSC and state staff. There have been a number of topics discussed and reduced. A smaller negotiating team was formed which consists of SPP Board Chair Jim Eckelberger, SPP Board Vice Chair Larry Altenbaumer, Mr. Mike Wise (Golden Spread Electric Cooperative), Mr. Kelly Harrison (Westar), and Nick Brown and Mr. Carl Monroe (SPP staff). Commissioner Geri Huser moved to have the RSC direct the Cost Allocation Working Group (CAWG) to start performing the duties listed on page 13, Section 8.2, of the New Member Process document dated October 24, 2016; Commissioner DeAnn Walker seconded the motion. The motion was approved unanimously. BUSINESS MEETING Auditor Costs for Audit and Taxes for 2017 and Auditor Engagement Letter (Voting Item) Mr. Suskie (SPP staff) discussed the engagement letter from Thomas and Thomas (Thomas and Thomas Letter – Attachment 5) to conduct the audit and prepare the taxes for 2017 for the RSC. Commissioner Patrick Lyons made a motion to engage Thomas and Thomas again to complete the audit and taxes for the RSC; Commissioner Geri Huser seconded the motion. The motion was approved unanimously. Mr. Suskie provided an update on the revised RSC travel policy (RSC Travel Policy – Attachment 6), which has not been updated since 2007. Commissioner Geri Huser made a motion to accept the revised RSC travel policy; Commissioner Dennis Grennan seconded the motion. The motion was approved unanimously.


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Cost Allocation Working Group Report and Voting Items CAWG Report Ms. Christine Aarnes (KCC staff and CAWG Chair) provided the CAWG report (CAWG Report – Attachment 7). Ms. Aarnes reported on the meetings that have taken place since October and future meeting dates. She provided an update of the various projects and voting items of the CAWG. There were no revision requests (RR) approved on the CAWG consent agenda. The expected future issues are cost allocation for projects in wind-rich areas, competitive project minimum threshold (FERC Docket No. ER17-2523-000), and continued developments with the Mountain West Transmission Group. Safe Harbor Criteria “Lessons Learned” Update (Voting Item) Mr. Adam McKinnie (MoPSC staff) provided a report on the safe harbor criteria (Lessons Learned: Aggregate Study Safe Harbor Waiver Criteria Review – Attachment 8). The purpose of this report was to provide a list of CAWG-approved lessons learned from the Aggregate Study Safe Harbor Waiver Criteria work and to request a vote from the RSC to adopt the lessons learned. The safe harbor is applied if the applicable aggregate study waiver criteria are met. A utility may apply for a waiver if the transmission service request (TSR) does not meet the applicable safe harbor criteria or for an increase in the safe harbor amount. The CAWG will continue to work with SPP staff to determine how many waiver requests have been submitted, and continue to ask for feedback from stakeholders. The CAWG asked the RSC to endorse the lessons learned on the safe harbor criteria. Commissioner Patrick Lyons made a motion for the RSC to endorse the safe harbor criteria lessons learned as drafted; Commissioner Randy Christmann seconded the motion. The motion was approved unanimously. RR251 – Supply Adequacy Update (Voting Item) Supply Adequacy Working Group Chair Mr. Brad Hans provided a report on RR 251 Supply Adequacy (RR251 Presentation and Recommendation Report – Attachment 9). Mr. Hans noted that FERC rejected SPP’s RR187 filing without prejudice and provided guidance on three issues: 1) SPP’s proposal failed to include a requirement that all power purchases agreements be backed by verifiable capacity to meet SPP’s resource adequacy requirement (RAR) and failed to include provisions to allow SPP to review the agreements to verify that they are backed by capacity, 2) SPP’s proposed treatment of firm power purchases and sales in the determination of net peak demand was unduly discriminatory, and 3) SPP did not support as just and reasonable its proposal to post publicly a list of all load responsible entities (LREs) that have not met their RAR. There were changes reflected in RR251 to address these issues, and SPP re-engaged the stakeholder process to address only the FERC-identified issues. Commissioner Dennis Grennan made a motion for the RSC to approve RR251 as addressing the FERC- identified issues outlined in their rejection without prejudice in FERC Docket No. ER17-1098, while maintaining the originally-approved Capacity Margin Task Force (CMTF); Commissioner Kim O’Guinn seconded the motion. The motion was approved unanimously. Cost Allocation in Wind-Rich Areas (Voting Item) Mr. Al Tamimi (Sunflower) provided a presentation on cost allocation in wind-rich areas (Cost Allocation in Wind-Rich Areas – Attachment 10). He provided an overview of the problem as he sees it and provided a case history and analysis. He also provided possible solutions to the problem. Commissioner Patrick Lyons made a motion to adopt the action item in which the RSC directed the CAWG to work with SPP staff and stakeholders on a proposed scope of work identifying interrelated issues as it relates to issues of cost allocation and report at the April 2018 meeting; Commissioner DeAnn Walker seconded the motion. The motion was approved unanimously. REPORTS/PRESENTATIONS Integrated Transmission Planning (ITP) Update Mr. Lanny Nickell (SPP staff) proved the ITP Update (Integrated Transmission Planning Update – Attachment 11). The three areas covered in the update is the 2018 Integrated Transmission Planning Near-Term


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assessment (ITPNT) update, the 2019 ITP update, and the 2018 SPP Transmission Expansion Plan (STEP). The 2019 ITP scope is an assessment to develop a regional transmission plan that provides reliable and economic delivery of energy and facilitates achievement of public policy objectives, while maximizing benefits to the end-use customer. The 2018 STEP includes ITP, high priority, balanced portfolio, interregional, transmission service, generation interconnection, and sponsored upgrades. Integrated Marketplace Update Mr. Bruce Rew (SPP staff) provided the Integrated Marketplace Operational update (Integrated Marketplace Operational Update – Attachment 12). A new winter peak was set on December 19. The low temperatures in the last week of December and early January did drive high system demand with higher gas prices and increased generation outages. There are currently 211 market participants with 141 financial only and 70 asset owning. The real-time balancing market has successfully solved 99.92% of all intervals. SPP set a new historical maximum wind output of 15,690 MW in December. Regional Allocation Review Task Force (RARTF) Update Commissioner Dennis Grennan provided an RARTF update (RARTF Presentation – Attachment 13). Commissioner Grennan was appointed chair of the RARTF on January 1. During its last meeting, the group focused on the SPP/AECI seams remedy project, the regional cost allocation review (RCAR) frequency filing at FERC, and RCAR III options. The SPP/AECI seams projects are the Brookline Reactor and Morgan Transformer projects. The Brookline Reactor project is being evaluated in the 2018 ITPNT, and if it is approved in the planning process then no further FERC filing will be necessary. SPP staff visited with FERC regarding the Morgan Transformer project and believes another filing at FERC is appropriate. Staff has provided four options to the RARTF for consideration with RCAR III. Staff was directed to provide more analysis at the January 15 meeting. Staff will provide results of a limited proof concept using the market engine to provide adjusted production cost savings and is comfortable that this process is feasible. At the next meeting there will be a strawman proposal to review the fourth option discussing hybrid operational/planning based to include cost and schedule, stakeholder group involvement, and RCAR II lessons learned. Seams Projects Update Mr. Suskie provided the seams projects update (SPP-AECI Joint Projects – Attachment 14). SPP and AECI agreed on two joint projects out of the 2016 SPP-AECI Joint and Coordinated System Plan (JCSP). SPP made filings at FERC for the two projects. FERC issued an order rejecting SPP’s proposal for region-wide/load-ratio share funding for SPP’s portion of the costs for the two joint projects. The order did not preclude SPP from making additional filings to the Commission to support region-wide funding or propose a new cost allocation methodology for the two joint projects. SPP staff is continuing to review the Commission’s order and is determining the best path forward for the two joint projects with AECI. Staff is also continuing to work on the best path forward for non-order 1000 joint projects. Ms. Kandi Hughes reviewed the action items from the RSC education session and the RSC meeting. Commissioner DeAnn Walker made a motion that if a special meeting is called at the April RSC meeting that there be an action item on the agenda for the RSC to go into a closed session, to the extent that the motion requires it, for deliberation on the topic of Mountain West; Commissioner Patrick Lyons seconded the motion. The motion was approved unanimously.


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SCHEDULING OF NEXT REGULAR MEETINGS, SPECIAL MEETINGS OR EVENTS

2018: April 23, 2018 - Kansas City, MO July 30, 2018 - Omaha, NE October 29, 2018 - Little Rock, AR

With no further business, the meeting adjourned at 5:16 p.m. Respectfully Submitted, Paul Suskie

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Monday, January 29, 2018

1:00 - 5:00 p.m.

Skirvin Hilton

Oklahoma City, OK

1. CALL TO ORDER 2. PRELIMINARY MATTERS

a. Commissioners’ Roll Call and Declaration of a Quorum b. Meeting Attendees Roll Call c. Adoption of Minutes from October 30, 2017 d. Review of Ongoing Action Items

3. UPDATES a. RSC Fourth Quarter 2017 Financial Report b. SPP c. FERC

4. BUSINESS MEETING a. Auditor Cost for Audit and Taxes for 2017 and Engagement Letter [Voting Item] b. RSC Travel Policy [Voting Item]

5. COST ALLOCATION WORKING GROUP REPORT a. CAWG Report……………………………………………………………………….………………..Christine Aarnes

This report will update the RSC on the activities of the Cost Allocation Working Group.

i. Safe Harbor Criteria “Lessons Learned” Update……………………………………..……Adam McKinnie [Voting Item]

This report will update the RSC on the Safe Harbor Criteria “Lessons Learned”.

ii. RR251 - Supply Adequacy Update …………………………………….……………………….….Brad Hans [Voting Item] This report will update the RSC on RR251 - Supply Adequacy Update

iii. Cost Allocation in Wind Rich Areas…………………………………………………………………Al Tamimi [Voting Item] This report will update the RSC on Cost Allocation in Wind Rich Areas.

6. REPORTS/PRESENTATIONS a. Integrated Transmission Planning (ITP) Update……………………………….…………………Lanny Nickell

This report will update the RSC on the 2018 and 2019 ITP study activities.

b. Integrated Marketplace Update…………………………………………………..………………………Bruce Rew

This report will update the RSC on the Integrated Marketplace.

c. RARTF Update.……………………………………………………………….………………………Dennis Grennan

This report update the RSC on the activities of the Regional Allocation Review Task Force.

d. Seams Projects Update………………………………………………………………………………...…Paul Suskie

This report update the RSC on Seams projects.

e. OTHER RSC MATTERS 7. NEW ACTION ITEMS

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8. SCHEDULING OF NEXT REGULAR MEETINGS, SPECIAL MEETINGS OR EVENTS a. RSC Meetings:

April 23, 2018 – Kansas City, MO July 30, 2018 – Omaha, NE October 29, 2018 – Little Rock, AR January 28, 2019 – Austin, TX April 29, 2019 – Tulsa, OK July 29, 2019 – Denver, CO October 29, 2019 – Little Rock, AR

9. ADJOURN

* NOTE: ADDITIONAL INFORMATIONAL MATERIAL ATTACHED

Attached to the RSC’s meeting agenda and background material is additional material that is either for informational or reporting purposes.

Southwest Power Pool REGIONAL STATE COMMITTEE

SPP Corporate Center, Little Rock, AR October 30, 2017

• MINUTES •

ADMINISTRATIVE ITEMS: The following members participated:

Steve Stoll, Missouri Public Service Commission (MoPSC) Shari Feist Albrecht, Kansas Corporation Commission (KCC) Kristie Fiegen, South Dakota Public Utilities Commission (SDPUC) Randy Christmann, North Dakota Public Service Commission (NDPSC) Dennis Grennan, Nebraska Power Review Board (NPRB) Geri Huser, Iowa Utilities Board (IUB) Heidi Pitts for Patrick Lyons, New Mexico Public Regulation Commission (NMPRC) Dana Murphy, Oklahoma Corporation Commission (OCC) Kim O’Guinn, Arkansas Public Service Commission (APSC)

DeAnn T. Walker, Public Utility Commission of Texas (PUCT) President Steve Stoll called the Regional State Committee (RSC) meeting to order at 1:06 p.m. with roll call, and a quorum was declared. President Stoll welcomed the new commissioner, DeAnn T. Walker, Public Utility Commission of Texas, to her first meeting and education session. He welcomed commissioners Cynthia Hall from New Mexico and Scott Rupp from Missouri. President Stoll requested introductions of those in attendance. There were 116 people in attendance, either in person or via the phone (Attendance & Proxies – Attachment 1). The first item of business was the approval of the 7/24/17 meeting minutes (RSC Minutes 7/24/17 – Attachment 2). Commissioner Kristie Fiegen moved to approve the minutes with corrections; Commissioner Shari Feist Albrecht seconded. The motion was approved unanimously. Ms. Kandi Hughes reviewed the RSC Action Items (RSC Action Items – Attachment 3). UPDATES RSC Third Quarter Financial Report Mr. Paul Suskie (SPP staff) provided the financial report for the third quarter (RSC 2017 Q2 Financials – Attachment 4). He noted that the RSC was under budget for the third quarter. SPP Report Mr. Nick Brown discussed the Sunday dinner with the RSC commissioners and the Board of Directors. This is a time for the Board and RSC commissioners to get to know each other better. Based on the dialogue and feedback, and due to the turnover that occurs regularly on the RSC, SPP staff is committed to preparing an orientation package for new RSC members. The staff will seek input from each of the commissioners on the

Regional State Committee October 30, 2017

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content in preparation for the commissioners’ successors. This will be an action item for SPP staff. During the dinner, the integration of the Mountain West Transmission Group (MWTG) into the SPP membership was discussed. SPP has been actively involved in the negotiations for quite some time. There is a State Commission forum and most of the commissioners are engaged. The participation of the states is very much appreciated. Various aspects of the negotiated items with the MWTG will be assigned to various stakeholder organizational groups. President Stoll agreed that a new member orientation packet would be a good idea. The industry is constantly changing and it is good to have a review. Federal Energy Regulatory Commission Report (FERC) Mr. Patrick Clarey provided the FERC report. Mr. Clarey provided an update about the FERC nominees. Last month the U.S. Senate Committee on Energy and Natural Resources held a hearing and voted in favor of the nominations of Kevin McIntyre and Richard Glick. They are awaiting a vote from the full senate. After the confirmations, Kevin McIntyre will become the FERC Chairman. Since establishing a quorum, the Commission has acted on over 250 filings. FERC held open meetings in September and October. At the open meeting in October, FERC staff and the Regional Transmission Organizations (RTOs) updated the Commission on winter readiness. Both staff and the RTOs indicated that the markets are prepared for the upcoming winter with adequate capacity and the forecast of warmer than average temperatures. Mr. Clarey thanked SPP and Mr. Bruce Rew for their help and participation. Last month the U.S. Department of Energy (DOE) sent a Notice of Proposed Rulemaking pursuant to section 403 of the Department of Energy Organization Act (DOE Act) to the Commission for final action. The proposed rule involves “Grid Resiliency rules” to ensure that certain eligible resources recover their full allocated costs. The proposed rule was noticed by the Commission on October 2, with comments due by October 23 and reply comments due by November 7. As of last week there have been over 550 comments filed in Docket No. RM18-1-000. BUSINESS MEETING RSC Budget for 2018 Mr. Paul Suskie presented the RSC proposed budget for 2018 (2018 Proposed RSC Budget– Attachment 5). Travel was increased in the 2017 budget, and that increase was carried over into the 2018 budget. Commissioner Albrecht recommends increasing the consultant budget line item from $50,000 to $150,000 in the event the course of the engagement as the RSC and MWTG integration would necessitate consultant expertise with targeted issues as yet unknown. Commissioner Shari Feist Albrecht made a motion to increase the Principal Consultant fee from $50,000 to $150,000; Commissioner Geri Huser seconded the motion. The motion was approved unanimously. Commissioner Shari Feist Albrecht made a motion to approve the Amended 2018 Proposed Budget; Commissioner Geri Huser seconded the motion. The motion was approved unanimously. Election of RSC Officers President Stoll provided the 2018 slate of officers: Shari Feist Albrecht, President; Kristie Fiegen, Vice President; and Dennis Grennan, Secretary/Treasurer. The titles for the RSC officers will be updated on the SPP website. Commissioner Dana Murphy made a motion to approve the slate of officers nominated for 2018; Commissioner Geri Huser seconded the motion. The motion was approved unanimously. Commissioner Murphy thanked President Stoll for his hard work and dedication during the 2017 term. President Stoll thanked the commissioners for their commitment to the RSC and SPP. He has enjoyed working with everyone.


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RSC Bylaws Revisions Commissioner Albrecht reported on the revisions to the RSC Bylaws (Bylaws Changes Matrix – Attachment 6, RSC Bylaws Redline – Attachment 7). President Stoll thanked Commissioner Albrecht for her hard work and diligence on updating the RSC Bylaws. Commissioner Shari Feist Albrecht made a motion to approve the amended language to Article I, Section 3 of the RSC Bylaws; Commissioner Kristie Fiegen seconded the motion. The motion was approved unanimously. Commissioner Shari Feist Albrecht made a motion to approve the amended language to Article IV, Section 10 of the RSC Bylaws; Commissioner Dennis Grennan seconded the motion. The motion was approved unanimously. Commissioner Shari Feist Albrecht made a motion to approve the amended language to Article VIII of the RSC Bylaws; Commissioner Geri Huser seconded the motion. The motion was approved unanimously. Commissioner Shari Feist Albrecht made a motion to approve the technical edits made in the RSC Bylaws; Commissioner Dana Murphy seconded the motion. The motion was approved unanimously. Commissioner Shari Feist Albrecht made a motion to approve the amended language to Article VII, Section 3 and Article XI regarding the Nominating Committee; Commissioner Randy Christmann seconded the motion. New Mexico Public Regulation Commission abstained. The motion was approved. During the discussion to Article VII, Section 4. Executive Committee, the following additional changes were suggested: changing the first “shall” to “may” in subsection (a) and striking “the immediate past-President of the RSC Board” from the listing of RSC officers who would participate on the Executive Committee. General consensus among the RSC commissioners was to drop the language from the amended bylaws and adding Section 4. The language for adding an executive committee will remain in the redline version of the bylaws and attached to the minutes for this meeting. Commissioner Shari Feist Albrecht made a motion to add the Executive Committee language to the existing RSC Bylaws with the additional deletion and substitution; Commissioner Geri Huser seconded the motion. No votes: Kristie Fiegen, South Dakota Public Utilities Commission, Steve Stoll, Missouri Public Service Commission, Kim O’Guinn, Arkansas Public Service Commission, Dennis Grennan, Nebraska Power Review Board, Heidi Pitts for Patrick Lyons, New Mexico Public Regulation Commission and DeAnn Walker, Public Utility Commission of Texas. The motion did not pass with the required two-thirds vote of a quorum. Cost Allocation Working Group (CAWG) Report and Voting Items CAWG Report Mr. Adam McKinnie (MoPSC) provided the CAWG report (CAWG Report – Attachment 8). Mr. McKinnie reviewed the meeting information from the CAWG meetings since the July RSC meeting. Ms. Meena Thomas (PUCT) provided an update on the 2019 Integrated Transmission Planning (ITP) futures development. The study will consider the near and long-term needs of transmission planning. The main driver of the study is the generation assumptions, particularly wind and solar. This study is of importance to the RSC because the projects that are approved will automatically be highway/byway projects. Prior studies have underestimated wind production. The Economic Studies Working Group (ESWG) approved two futures, reference case and emerging technologies. The CAWG approved its first consent agenda item in October. It was revision request (RR) 244 containing the Z2 Task Force recommendations. Future issues to be discussed in CAWG are projects related to wind generation, the MWTG, and non-Order 1000


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interregional projects. Mr. McKinnie asked the RSC to let the CAWG know if there are any topics and/or issues the RSC would like the CAWG to add to its agenda for future meetings. The CAWG completed its initial derated facilities review with respect to cost allocation, passing a motion at its October meeting recommending that the RSC take no action on the matter. Commissioner Kristie Fiegen made a motion to adopt the CAWG recommendation to take no action; Commissioner Shari Feist Albrecht seconded the motion. The motion was approved unanimously. Commissioner Stoll thanked Mr. McKinnie for serving as the CAWG chair for the past year. REPORTS/PRESENTATIONS Integrated Marketplace and Operations Update Mr. Bruce Rew (SPP staff) provided an update on the Integrated Marketplace (Integrated Marketplace Update – Attachment 9). There are currently 197 market participants, 130 of those are financial only and 67 are asset owning. One financial only entity has dropped since the last quarter. The SPP Balancing Authority (BA) has successfully maintained NERC control performance standards. The day-ahead market has been delayed once from posting in the last 12 months and the real-time balancing market has successfully solved 99.87% of all intervals. To date, there has been a total of 16,680 MW of installed and operation wind capacity. SPP averaged just over 12,000 MW of wind for an entire day this past quarter. Seams Update Mr. Carl Monroe (SPP staff) provided the seams update (Seams Update – Attachment 10). SPP and AECI agreed on two joint projects out of the 2016 SPP-Associated Electric Cooperative, Inc. (AECI) Joint and Coordinated System Plan (JCSP). SPP made filings at FERC for the two projects. Comments were received in support and in protest of the filing. FERC issued an order rejecting SPP’s filing. The order does not preclude SPP from making additional filings to the Commission to support region-wide funding or propose a new cost allocation for the two joint projects. SPP will continue to review and evaluate the Commission’s order and coordinate next steps with AECI and City Utilities of Springfield. A future goal is to try to develop another cost allocation proposal specific to these two projects and make a recommendation to SPP Markets and Operations Policy Committee (MOPC), Board of Directors, and RSC in January 2018, and make another filing at the Commission. The joint study between SPP and MISO resulted in one interregional project being recommended by SPP and MISO to continue to the regional review process. The project was to loop one Split Rock to Lawrence 115 kV circuit into Sioux Falls. MISO is not recommending the I-18 interregional project for further consideration. MISO recommends maintaining the status quo and operating the Lawrence-Sioux Falls kV line in the open state. Mountain West Update Mr. Carl Monroe (SPP staff) provided an update on the MWTG. SPP has entered the stakeholder review phase in its efforts with the MWTG, and will begin working with the stakeholders and the RSC to review the policies and proposals that the MWTG is requesting related to governance to provide the MWTG the ability to join SPP. A page on the SPP website has been dedicated to the MWTG effort. The current schedule is to come back in April 2018 to finalize the proposals and reach an agreement between the members and the MWTG parties. Generator Interconnection Improvement Task Force (GIITF) Update Mr. Al Tamimi (Sunflower) provided the update on the GIITF (GIITF Update Presentation – Attachment 11). The purpose of the GIITF is to evaluate the existing SPP generator interconnection procedures, including internal SPP transmission processes, and recommend changes. The GIITF requests that the MOPC take the following actions: publish study models and eliminate the standalone analysis, and appoint a stakeholder group with appropriate background and expertise to re-evaluate the purpose, scope and study requirements of Network Resource Interconnection Service (NRIS) with the goal of aligning it more closely with SPP’s current and future market structure. The task force would also like the MOPC to approve the concept of the three-stage study process and direct that a full and complete proposal be provided to the MOPC. The GIITF is also asking the MOPC to approve an amended charter extending the scope of the GIITF to address the remaining charter tasks and address the identified additional proposals. The benefits of the three-stage GI study process are that it is


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streamlined, simplified, and less confusing. It is also easier for SPP to administer, and for customers to understand and navigate. Mr. Tamimi reviewed all of the recommendations the GIITF placed before the MOPC, and the results of that review. Z2 Update Mr. Charles Locke (SPP staff) provided a Z2 Crediting Resettlement Update (Z2 Crediting Resettlement Update Presentation – Attachment 12). Attachment Z2 to the SPP Open Access Transmission Tariff (“Tariff”) provides a process to compensate those Upgrade Sponsors who pay for upgrades that are subsequently used by transmission customers. The credit amounts occurred as early as 2008. The complexity of system implementation delayed the invoicing until 2016. FERC approved a waiver of the Tariff to permit settlement of the 2008-2016 charges and credits under Attachment Z2. In the initial and revised settlement, a number of updates and corrections to the input data were identified. A resettlement has been prepared for both the historical period and the month subsequent to the historical period. For those affected by the payment plan, the historical period amounts owed and received will be adjusted for the remaining installments. Individual company results were posted on October 13, 2017. The payment plan will continue on the original schedule but with revised amounts. Net amounts, the differences between revised settlement and original settlement, and the next installment of the payment plan are to be invoiced on November 3, 2017. Regional Allocation Review Task Force (RARTF) Update President Steve Stoll (MoPSC) provided the update on the RARTF (RARTF Update Presentation – Attachment 13). The RARTF is preparing for the third Regional Cost Allocation Review (RCAR). On October 6, FERC issued an order rejecting the proposed Morgan Transformer and Brookline Reactor transmission projects identified pursuant to the joint planning process contained in the Commission-approved Joint Operating Agreement (JOA) between SPP and AECI. The first two RCARs were conducted once every three years. The timeline was changed to conducting an RCAR once every six years. The transmission provider and/or the RSC may initiate such a review at any time. President Stoll reviewed the RCAR III options being considered. SPP staff will provide additional information on creating the operational model process and initial metrics results for evaluation. Commissioner Dennis Grennan has agreed to serve as chair of the RARTF after Commissioner Stoll steps down. SCHEDULING OF NEXT REGULAR MEETINGS, SPECIAL MEETINGS OR EVENTS:

2018: January 29, 2018 - Oklahoma City, OK April 23, 2018 - Kansas City, MO July 30, 2018 - Omaha, NE October 29, 2018 - Little Rock, AR

With no further business, the meeting adjourned at 4:20 p.m. Respectfully Submitted, Paul Suskie

Page 1 of 9

Southwest Power Pool, Inc. REGIONAL STATE COMMITTEE

Action Items Status Report January 29, 2018

No. Action Item Date Originated Status Comments

19 Circulation of RSC Agendas 4/25/2016 Ongoing SPP to circulate draft agendas to RSC members and CAWG earlier for comment

27 Consolidate all previously

approved RSC policies into one document.

7/24/2017 Ongoing SPP Staff working to consolidate said policies and will include as a part of the orientation package referenced in Action Item No. 35.

33 RSC Website Page Revisions 10/30/2017 Ongoing

Contact Communications to update officers’ titles on website. Add secretary/treasurer to the website, as well. (Update: the SPP website is moving in-house and will be updated as soon as practically possible.)

35 RSC Orientation Package 10/30/2017 Ongoing SPP Staff to put together an orientation package for current and future RSC Commissioners.

Page 2 of 9


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EPA 111(d) : (1) Lanny Nickell to provide scope document on compliance analysis and an update on

when SPP reliability analysis will be completed

(2) Commissioner Reeves to provide update on possibility of studies to be performed by BPC and GPI, what services those entities are providing

8/25/2014

Completed

Addressed at 9/29/14 Meeting

2 RARTF: Update on RARTF and New Metrics 8/25/2014 Completed Addressed at 9/29/14 Meeting

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Seams Project Task Force: CAWG will consider the issue

at next meeting and bring back to RSC for discussion

8/25/2014 Completed Addressed at 9/29/14 Meeting; On 10/27/14 Meeting as a voting item

Page 3 of 9


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SPC Task Force on New Members: RSC should email Commissioner Murphy with

any concerns or topics. Update to be provided at next

RSC meeting

8/25/14 Completed Addressed at 9/29/14 Meeting

5 Consideration of RSC Bylaws

changes related to membership eligibility

Ongoing Completed

Discussed at December 1, 2014 meeting, January 2015 Educational Session and March 9, 2015 Meeting. The bylaws draft modifications were discussed at the RSC retreat and meeting on July 27, 2015. Bylaws changes were considered at the September 21, 2015 meetings but were not approved. January 25, 2016 – RSC Goal for 2016 to consider adopting the clean-up of the Bylaws discussed in 2015. Prior to the January 30, 2017 RSC meeting, the current draft of the bylaws was distributed to the RSC. Phone call late August/early September on a Friday (Kandi to work with SS to get it scheduled) to finalize bylaws changes nominating committee; technical clean-up language, Executive Committee inclusion. July 2017 RSC meeting. Plan to vote in October. Send call information/agenda.

6 EPA’s Clean Power Plan –RSC Comments 9/29/2014 Completed Discussed at October 27, 2014 RSC Meeting.

Comments filed on November 24, 2014.

Page 4 of 9


7 SPC Task Force on New

Members – Discuss 3 RSC Action Items

9/29/2014

Completed

Discussed at October 27, 2014 Meeting and December 1, 2014 Meeting. On January 2015 Educational Session for discussion and January 2015 Meeting Agenda as a voting item. Feedback was provided to SPC TF on NM on items 1 and 2 on January 26, 2015 and subsequent to the March 9, 2015 RSC teleconference. The RSC will continue to discuss item 3 on cost allocation and has delegated this item to the CAWG (Action Item 12). On July 27, 2015, the RSC approved a scoping document developed by CAWG. The SPC TF on New Members finalized its report, which was approved by the SPC in July 2015. The RSC approved the New Member Process document with the addition of catch-al language permitting the RSC to invoke the new member process for matters within the RSC’s responsibility.

8 Cost Allocation for Non-Order 1000 Seams Projects 10/27/2014 Completed RSC vote taken in December 2015 approving 60%

threshold. Approved on January 25, 2015.

9 Goals and Objectives for 2015 RSC Year 12/1/2014 Completed

Discussed at December 1, 2014 meeting and draft goals were reviewed on January 26, 2015, March 9, 2015, April 27, 2015 and September 21, 2015.

11 Educational Session on SPP “Building Blocks” 1/25/2015 Removed

Educational Session on the SPP “Building Blocks” – possible topic for July retreat. Unclear what this was intended to cover. Removed when list of retreat topics was updated.

Page 5 of 9


12 RSC Role in Cost Allocation for New Member Integrations 4/27/2015 Completed

In January 2015, the RSC tasked the CAWG with looking at what role the RSC should have in regards to Cost Allocation methodology for new members joining SPP. The RSC tasked the CAWG to develop a scoping document on how to apply cost allocation for new members joining SPP. The Scope Document developed by CAWG was approved by the RSC on July 27, 2015. At its October 2016 meeting, the RSC approved the process document developed by the CAWG.

13 Aggregate Study Waiver Criteria 4/27/2015 Completed

The RSC determined it should review the eligibility requirements set out in Section III.B.1 (specifically the 20% threshold), and whether the requirements are applicable today in light of the changes to the transmission system since the requirements were approved. The RSC tasked the CAWG to evaluate the eligibility requirements for a waiver request to see if the requirements are still applicable to the transmission system as it operates now. CAWG presented a draft scoping document to the RSC on July 27, 2015. A recommendation by the CAWG to retain the study waiver criteria was approved by the RSC on January 30, 2017.

14 Capacity Margin Task Force Update 4/27/2015

Completed

After a presentation at the April 2015 RSC meeting, and discussion of the Capacity Margin Task Force, the RSC tasked the CAWG to evaluate how load is forecasted for the purpose of determining the reserve margin. CAWG reported back to the RSC at their July 2015 meeting. Voted and approved at April 2016 meeting.

Page 6 of 9


15 RSC Goals for 2016 1/25/2016 Completed

RSC discussed goals for 2016 at the January 2016 Educational Session. Any additional goals should be submitted to Erin Cullum for distribution in advance of the April 2016 RSC meeting.

16 Engagement Term of RSC Auditor 1/25/2016 Completed

Determine the initial arrangement with the RSC auditor and the number of years for reengagement. Erin Cullum will review the agreement and inform the RSC

17 Educational Session Topic Request – Role of RSC in

SPP FERC Filings 1/25/2016 Completed Request for SPP Staff to provide educational update

on the FERC filings process and the role of the RSC.

18 Talking Points on CPP 1/25/2016 Completed Request for SPP’s talking points on the CPP. Erin Cullum will distribute the link to posted comments.

20 Z2 Crediting Overview 4/25/2016 Completed

SPP to provide higher level overview of Z2 key points, significance, and state specific information (if possible). This will be provided in advance of the next RSC Meeting.

Page 7 of 9


21 Form Commissioner Forum for Mountain West proposal. 01/30/2017 Completed Phone call scheduled for February 10, 2017 to

discuss further.

22 Establish a Nominating Committee per the RSC

Bylaws 01/30/2017 Completed

Established for providing a slate of officers for RSC. Commissioner Albrecht to draft sample bylaw language in establishing a Nominating Committee for review at July RSC Meeting

23 Aggregate Study Waiver Criteria Review 01/30/2017 Completed

Annual CAWG review for limited time period (i.e. not in perpetuity). CAWG to present recommendation(s) to the RSC in July 2017 on how the RSC should proceed in reviewing the Aggregate Study Criteria.

24 RSC Retreat Information 04/17/2017 Completed Paul Suskie to send RSC Retreat information to Commissioners.

25

Send new member integration

process documents to RSC members.

07/24/2017 Completed Emailed on July 24, 2017

Page 8 of 9


26

Paul Suskie to send SPP bylaws to Commissioner

Huser.

07/24/2017 Completed Provided July 24, 2017

28 RSC Bylaw Revisions 07/24/2017 Completed

Schedule phone call late August/early September to finalize bylaws changes nominating committee, technical clean-up language, and Executive Committee inclusion. Plan to vote in October. Send call information/agenda.

29 Annual Review of Safe Harbor Criteria 07/24/2017 Completed

CAWG will bring a proposal to the RSC for the limited annual review of the Safe Harbor Criteria CAWG and will synchronize the limited review with SPP’s annual filing with FERC.

30 October Education Session topic(s) 07/24/2017 Completed Kandi Hughes will send request to RSC soliciting

potential educational session topics for October.

31 FERC Contact Information 10/30/2017 Completed Sam Loudenslager to send Patrick Clarey’s contact information to RSC members.

Page 9 of 9


32 January 2018 Education Session Topic(s) 10/30/2017 Completed

Kandi Hughes will send request to RSC soliciting potential educational session topics for January 2018. One topic suggested is the Mountain West Transmission Group.

34 State Commissioner Forum for Mountain West proposal. 10/30/2017 Completed

RSC Member to review online documents pertaining to Mountain West. Commissioner Fiegen will send a Doodle Poll to schedule a State Commissioner Forum to be held during the last week of November.

Regional State CommitteeFor the Twelve Months Ending December 31, 2017

Budget vs. Actual

YTD Actuals YTD Budget Variance

Income Other Income 256,237 321,700 (65,463) Total Income 256,237 321,700 (65,463)

Expense Travel/Meeting 253,637 268,400 (14,763) Audit 2,600 2,300 300 Administrative Costs 1,000 (1,000) RSC Consultant - 50,000 (50,000) Technical Conference - - - Total Expense 256,237 321,700 (65,463)

Net Income - - -

RSC Travel Policy UpdateJanuary 2018 RSC Meeting

1

RSC Travel Policy

• The current posted RSC Travel Policy was last updated in 2007

• The RSC auditor mentioned that the policy seemed outdated and may need to be reviewed

• The current policy includes references to: RSC Associate Members (removed from RSC Bylaws in 2017) Price guidelines for travel (airfare, hotels, meals, car rental, etc.) based in 2007 Cost guidelines for meetings (meeting rooms, meals, snacks, etc.) based in 2007

2

RSC Travel Policy• Staff proposed an updated policy to the CAWG in December 2017 that

included: Removal of the RSC Associate Member references Removal of the Price Guidelines for Travel “Members are expected to use their best judgment while traveling.”

Removal of Cost Guideline for Meetings SPP Corporate Services handles meetings based on their guidelines RSC has not scheduled meetings on their own

• CAWG voted on this proposed policy in January 2018; it passed unanimously.

• CAWG Recommendation:

“The CAWG recommends the RSC approve the updated RSC Travel Policy.”

3

April

Page 1 of 4

Travel Policy

The Southwest Power Pool Regional State Committee (“RSC”) will reimburse RSC members (and/or their delegated representatives) and RSC associate members [BB1](hereinafter severally and jointly referred to as “Member(s)”) for all fair and reasonable expenditures incurred by Members when conducting RSC business. It is intended that Members should neither lose nor gain money as a result of reimbursement.

1. Travel expenses must be submitted on the RSC expense reimbursement form within 60

days after the conclusion of the travel. Receipts are required for all expenses.

2. The RSC expense reimbursement form must be signed by Member seeking reimbursement and in the case of an assigned delegate, by the individual state Commissioner assigned to the RSC.

3. While traveling and away from home, Members are expected to use good judgment when

incurring expenses for lodging, meals, transportation, etc. RSC will reimburse business related mileage at the rate approved by the IRS. Reimbursement will be for mileage claimed due to travel to business location and return.

4. Members are responsible for making their own arrangements for transportation, lodging

and car rentals. All accommodations should be purchased as far in advance as possible to obtain available discount fares/rates. All air travel is to be booked at the lowest accommodating fare.

5. Lodging reservations should be made at mid-priced establishments, when available. If a

Member is attending a meeting or function being held at a specific facility or where a room block has been negotiated, then reservations may be made at that facility.

6. The RSC will not accommodate advances for travel expenses; the RSC will only

reimburse expenses after the fact with supporting documentation and approval as specified in this policy.

7. If a spouse or family member accompanies a Member on a business trip for non-business

reasons, the family member’s travel expenses are not reimbursable.

April

Page 2 of 4

Travel Guidelines

These numbers are provided as guidelines and are based on historical averages. Members are expected to use their best judgment while traveling.

Price Guidelines:

1. Airfare - $500 roundtrip within the SPP footprint 2. Hotel - $130/night 3. Meals - $45/ day 4. Car Rental - $70/day 5. Parking - $10/day 6. Tips & Gratuities – 15% tip for meals, 10% tip for cab fare, $1 per bag for baggage

handling

April

Page 3 of 4

Expense Reimbursement Policy

This policy is intended to identify reasonable, necessary and customary business expenses, which are eligible for reimbursement. Southwest Power Pool Regional State Committee (“RSC”) participants eligible for reimbursement include RSC members (and their delegates assigned to specific task forces and working groups) and RSC associate members (hereinafter severally and jointly referred to as “Member(s)”)

Business Mileage – Members will be reimbursed for all mileage incurred while using a personal vehicle for business. The Member will be reimbursed at the standard IRS mileage rate.

Personal Auto Use on Company Business – If a Member requests use of a personal vehicle in lieu of air travel, reimbursement will be made at the approved reimbursement rate for the most direct mileage to and from the business destination unless round trip air travel is less expensive. When this occurs, the round trip air travel cost will be reimbursed instead.

Mileage will be reimbursed at the then current IRS mileage rate. This expense is to be turned in on an expense account (within 30 days) with the number of miles and the purpose of the trip.

Rental Cars, Taxis, Bus Fares, tolls, etc. – Reimbursement will be made for transportation while on RSC business, including transportation to and from airports and transportation to and from local businesses. Members are expected to use cost effective methods. The standard rental automobile will be a mid-size sedan.

RSC Meals –Members will be reimbursed for meals under the following circumstances:

• When out of town on business, the reasonable costs of the Member’s meals will be

reimbursed. • Business meals will be reimbursed when business is discussed and the Member

documents the business purpose and who attended.

Lodging – Members will be reimbursed for lodging expenses incurred while on RSC business.

Meetings - The following are guidelines for a meeting the RSC might incur.

1. Lunch – plan for $25/ person

2. Continental Breakfast – plan for $10/person

3. Afternoon Break – plan for $150/total

4. Beverages – plan for $12/person

5. Meeting Room (<20 people) - $250/day

6. Meeting Room (>20 people) - $650/day

April

Page 4 of 4

7. Supplies (<20 people) - $350/day

8. Supplies (>20 people) - $700/day

9. A/V Equipment

10. Conference Phones

11. Internet Access

April

Page 5 of 4

12. Teleconference : 25 ports/2 hr. meeting

Receipts are required on all expenses.

Reimbursement will be approved per this policy. Periodically, reimbursements will be reviewed by the RSC officers for compliance with this policy.

Christine AarnesKCC

Goal of Presentation:• Discuss CAWG activities since last RSC meetingNovember 14, 2017 – WebEx/TeleconferenceDecember 5, 2017 – AEP Offices, Dallas, TX January 12, 2018 – AEP Offices, Dallas, TX

• Discuss CAWG recommendations on RSC voting items• List any Revision Requests reviewed by CAWG under a CAWG consent

agenda• Discuss ongoing and expected future CAWG issues

November 14 WebEx/Teleconference:

Project Tracking

Morgan Transformer and Brookline Reactor Projects

Supply Adequacy

Mountain West Transmission Group

December 5, AEP Offices, Dallas, TX: RSC Travel Policy


Generation Interconnection Improvement Task Force

Cost Allocation in Wind Rich Areas

Safe Harbor Lessons Learned

Supply Adequacy Update (RR 251)

NITS Redispatch Compliance Filing Update (RR 257)

January 12, AEP Offices, Dallas, TX: Competitive Project Minimum Threshold (ER17-2523-000)

CAWG Effectiveness Survey

RSC Travel Policy (Voting Item – CAWG unanimously approved)


Cost Allocation in Wind Rich Areas

Safe Harbor Lessons Learned (Voting Item – CAWG approved via e-mail vote on January 16)

RR 251 Supply Adequacy (Voting Item – CAWG unanimously approved)

RR 255 Adding Triggers to Stop Annual Escalation of Baseline Estimates


RSC Travel Policy Current travel policy was developed in 2007.

Policy contained outdated expense estimates and needed to be updated.

New travel policy eliminates expense estimates and cleans up language.

CAWG Motion: The CAWG recommends the RSC approve the updated RSC Travel Policy.

Safe Harbor Criteria “Lessons Learned” Evaluation of the lessons learned from CAWG’s review of the Aggregate

Study Safe Harbor Waiver Criteria

Adam McKinnie will present to the RSC.

CAWG approved the revised lessons learned via an e-mail vote on January 16th.

CAWG Motion: The CAWG recommends the RSC endorse the Safe Harbor Criteria “Lessons Learned” as drafted.

RR 251 Supply Adequacy RR 187 (Planning Reserve Margin) was approved by the MOPC, the RSC, and the BOD at their respective January

2017 meetings and Tariff revisions were filed on March 3, 2017.

A FERC Order rejecting the filing without prejudice was issued on August 29, 2017.

In that Order, FERC guidance was given on three key issues: (1) SPP’s proposal fails to include a requirement that all power purchase agreements are backed by verifiable capacity to meet SPP’s Resource Adequacy Requirement (RAR) and fails to include provisions to allow SPP to review the agreements to verify that they are backed by capacity; (2) SPP’s proposed treatment of firm power purchases and sales in the determination of net peak demand is unduly discriminatory; and (3) SPP has not supported as just and reasonable its proposal to post publicly a list of all Load Responsible Entities (LREs) that have not met their RAR.

RR 251 addresses the key issues identified by FERC.

SAWG Chair, Brad Hans, will present RR 251 to the RSC.

CAWG Motion: The CAWG recommends that the RSC approve RR 251 as addressing the FERC identified issues outlined in their rejection without prejudice in FERC Docket No. ER17-1098, while maintaining the originally approved CMTF policies.

Cost Allocation in Wind Rich Areas Large percentage of wind projects are built in small SPP load zones with stagnant

load growth.

Two-thirds of the costs of projects are assigned to the local zone.

Is the current cost allocation method properly allocating costs to those who benefit from the transmission build out?

Al Tamimi will present to the RSC.

CAWG Motion: The CAWG recommends the RSC direct CAWG to work with SPP Staff to further investigate the cost allocation in wind rich areas issue.

Revision Requests Approved Through the CAWG Consent Agenda None

Expected Future Issues: Cost allocation for projects in wind rich areas

FERC, in Docket No. ER17-2256, issued an order rejecting the cost allocation for the Morgan and Brookline projects from the SPP-AECI interregional study. The RSC had previously approved the 100% highway funding for regional

recovery of the cost of non Order 1000 interregional projects.

Competitive Project Minimum Threshold (ER17-2523-000)


Upcoming CAWG Meetings: February 13, 2018 - WebEx/Teleconference

March 6, 2018 - AEP Offices, Dallas, TX

April 3, 2018 - AEP Offices, Dallas, TX

Lessons Learned: Aggregate Study Safe Harbor Waiver Criteria Review

Adam McKinnieRSC Meeting

January 29, 2018

Purpose

• Give a list of CAWG approved “Lessons Learned” from our Aggregate Study Safe Harbor Waiver Criteria work

• Request a vote from the RSC to adopt the “Lessons Learned”

2

Refresher – Aggregate Study Safe Harbor Criteria

• The “Safe Harbor” is applied if the applicable Aggregate Study waiver criteria are met:– If the TSR is granted, the utility will not have over 20% of their

designated resources from wind (only applies to a TSR related to designating wind as a Designated Resource*) [<20% wind]

– 5 year minimum term of commitment for the TSR– If the TSR is granted, the utility will not have Designated

Resources greater than 125% of their forecasted load [<125% of load]

• A utility may apply for a waiver if the TSR does not meet the applicable “Safe Harbor” criteria or for an increase in the “Safe Harbor” amount.

• *A Designated Resource is used to meet the capacity margin requirement of a Load Serving Entity

3

General Lessons Learned

• For all three criteria, continue work with SPP staff to determine how many waiver requests have been submitted

• Continue to ask for feedback from stakeholders.

4

125% of Load Criterion Lessons

• Request information from stakeholders and/ or work with SPP staff to verify whether the criteria adversely affects smaller transmission customers

• Consider a business practice or other report / statement that memorializes the reasons this criteria might be waived around the idea of some stakeholder comments that were received on possibly revising or revisiting this metric in light of stakeholder work on capacity, including changes to wind and solar capacity accreditation.

5

20% Wind Criterion Lessons• It is difficult to pick a number between 20% and 100% and provide a rationale for

that number. • To the extent the wind limit is increased to a number other than 100%, there may

be a need to ensure that entities that have already exceeded the 20% wind limit are not disadvantaged (e.g. if the limit is increased from 20% to 30%, an option to consider would be to apply the percentage increase (10%) to all entities regardless of whether they are at or exceed the 20% limit).

– For example, if a hypothetical utility was at 25% wind when the 20% wind criterion was raised to 30% (a 10% increase), that hypothetical utility could have a limit of 35%, a 10% increase over their current wind amount

• If parties raise concerns such as operational cost shifts that have to be addressed by other stakeholder groups (e.g. MWG), CAWG may need to work with those groups to ensure that the concerns are addressed within a reasonable period of time.

• Should the limit apply to solar, hydro, or other renewable resources? • Work with SPP staff and stakeholders to verify whether the original concerns that

justified the 20% wind limit still exist.• See if there are additional reasons utilities may be designating wind as a Network

Resource, which may cause more utilities to reach the 20% wind criterion.

6

$180k/MW Safe Harbor amount Lesson

• Work with SPP staff and stakeholders to come up with a reasonable methodology to update the $180,000 Safe Harbor amount.

7

Recommended RSC motion

• The CAWG recommends the RSC endorse the Safe Harbor Criteria “Lessons Learned” as drafted.

8

RR 251Implementation of Resource Adequacy Policies

Brad Hans

Chairman – Supply Adequacy Working Group

1

Background• Filing (RR 187) was made on March 3, 2017 requesting effective

dates of June 1, 2017 and July 1, 2017 to implement stakeholder approved resource adequacy package

• FERC rejected the filing without prejudice on August 29, 2017 and provided guidance on three key issues

• SPP reengaged the stakeholder process to address the FERC identified issues while maintaining the foundational policies RR 251 was approved by the SAWG on December 21, 2017 RR 251 was approved by the RTWG on January 3, 2018 with five

abstentions (AECC, City of Independence, KMEA, MJMEUC, Westar) CAWG reviewed on January 12, 2018 and recommended that the RSC

approve RR 251 RR 251 was approved by the MOPC on January 16, 2018 with one no

vote (KMEA) and ten abstentions (Flat Ridge 2, Westar KGE, Prairie Wind, Westar Energy, LES, South Central MCN, Empire Dist., MJMEUC, Enel Green, BPU)

2

Three Issues Identified by FERC1. SPP’s proposal fails to include a requirement that all power

purchase agreements are backed by verifiable capacity to meet SPP’s RAR and fails to include provisions to allow SPP to review the agreements to verify that they are backed by capacity

2. SPP’s proposed treatment of firm power purchases and sales in the determination of net peak demand is unduly discriminatory

3. SPP has not supported as just and reasonable its proposal to post publicly a list of all LREs that have not met their RAR

3

Changes to Address Issues 1 & 2• New Section 7.0 (Qualification of Deliverable Capacity, Firm

Capacity, and Firm Power)

• (7.1, 7.2, and 7.4) Internal resources must: Register the Resource in the Integrated Marketplace (Deliverable Capacity) Register the Resource in the Integrated Marketplace or declare the

Designated Resource on the Network Integration Transmission Service Agreement (Firm Capacity and Firm Power)

Submit the current Operational Test results Submit the current Capability Test results Demonstrate that there is firm transmission service from the internal

capacity to the LRE’s load

• (7.3 and 7.5) External resources must: Demonstrate ownership or contractual rights Submit the current operational test results per the requirements of the

Balancing Authority where the resource is located Demonstrate that there is firm transmission service from the external

capacity to the LRE’s load Demonstrate that the capacity includes planning reserves (Firm Power) Attest that any external capacity being identified is not otherwise being

used as capacity in any other Balancing Authority or in another resource adequacy construct 4

Changes to Address Issues 1 & 2• New Section 8.0 (Qualification and Verification of Power Purchase

Agreements)

• (8.1) Required to provide a copy of the PPA

• (8.2) When a PPA qualifies as Firm Power and the purchaser and seller are both LREs Purchaser deducts the contract amount from its Net Peak Demand Seller adds the amount to its Net Peak Demand and becomes

responsible for the Resource Adequacy Requirement

• (8.3) When a PPA qualifies as Firm Power and the seller is not an LRE Purchaser cannot deduct the contract amount from its Net Peak

Demand Purchaser reflects the contract amount plus the purchaser’s PRM

multiplied by the contract amount as Firm Capacity Firm transmission service is only required for the contract amount

5

Changes to Address Issues 1 & 2• (8.4) When a PPA qualifies as Firm Power and the purchaser is

not an LRE Seller cannot include the purchased contract amount in its Net Peak

Demand Seller reflects the contract amount plus the seller’s PRM multiplied by

the contract amount as Firm Capacity Firm transmission service is only required for the contract amount

• (8.5) Grandparent PPAs (prior to July 1, 2018) will be continued to be defined and qualified as Firm Power

6

Changes to Address Issue 3• (9.0) Removes the April report requirement

• “(7) No later than April 1st of each year, the Transmission Provider will review the information in the Workbook to determine whether each LRE meets the Resource Adequacy Requirement. The Transmission Provider will notify the Market Participant and the LRE if the LRE has not met the Resource Adequacy Requirement.”

7

Additional Tariff Changes• (2.0) Firm Capacity definition – removed Deliverable Capacity

Associated changes throughout

• (2.0) Net Peak Demand definition

• (4.0) Planning Reserve Margin moved to the SPP Planning Criteria Details of how the Planning Reserve Margin will be determined remain

in the Tariff

• (7.0) Language added to the SPP Planning Criteria for satisfying Operational and Capability test results for newly installed generation and generation that was out of service during the entire preceding peak season

• (7.6 and 8.7) Added confidentiality provisions

• (8.6) Clarifying language to short-term capacity provisions

8

Recommendation• The CAWG recommends that the RSC approve RR 251 as

addressing the FERC identified issues outlined in their rejection without prejudice in FERC Docket No. ER17-1098, while maintaining the originally approved CMTF policies.

9

SAWG Update

10

Action Items for 2018• Distributed Energy Resources

Demand Response/Behind the Meter Generation/Battery Storage/Variable Resources

Policy Development with consideration for accreditation, market registration, reliability and other factors

• Effective Load Carrying Capability Accreditation Methodology Consideration of methodology for accrediting variable resources Mountain West consideration Utilization of variable resources for capacity

• SERVM zonal representation Preparation for 2019 LOLE Study Study as zones or one balancing area

• Non-Coincident vs Coincident Peak Methodology for Resource Adequacy Continue discussion Address cost/benefit analysis

11

Action Items for 2018• Resource Adequacy Policy

Implementation into Tariff Workbook integration and verifications

• Criteria Updates Generator Testing and accreditation Fuel Supply

• Mountain West Integration

• Other Action Items Winter Reserve Margin Post Season Analysis for Resource Adequacy LOLE Studies Deliverability Studies Standardization of Load Forecasting Methodology

12

Page 1 of 42

Revision Request Recommendation Report

RR #: 251 Date: 10/12/2017

RR Title: Implementation of Resource Adequacy Policies

SUBMITTER INFORMATION

Name: Charles Hendrix Company: Southwest Power Pool

Email: [email protected] Phone: 501.614.3546

EXECUTIVE SUMMARY AND RECOMMENDATION FOR MOPC AND BOD ACTION

On August 29, 2017 FERC issued an order rejecting the SPP Resource Adequacy filing without prejudice. SPP reengaged the stakeholder process to address the FERC identified issues while maintaining the originally approved policies. This revision request implements the approved resource adequacy package.

SAWG recommends that the MOPC approve RR 251 as submitted.

OBJECTIVE OF REVISION

Objectives of Revision Request: The capacity margin has remained unchanged since 1998. Since that time, SPP has had significant transmission expansion, as well as expanding the footprint and operational responsibilities. SPP became the Balancing Authority in 2014, thus creating the need to revisit existing SPP criteria regarding capacity margin. The current mechanisms to ensure timely, reliable assurance of requirements in SPP are inadequate. SPP’s existing assurance mechanisms are either unlikely to be exercised or would be exercised in a way that would not encourage proper behavior and would not adequately compensate parties with excess capacity. Tasked by the MOPC to review resource adequacy in SPP, the Capacity Margin Task Force created 4 whitepapers:

• Load Responsible Entity • Planning Reserve Margin Requirement • Planning Reserve Assurance Policy • Deliverability Study

These policies identify who is responsible for resource adequacy, what the resource adequacy requirement is, and how and when the resource adequacy requirement can be and should be met. These four policy papers were approved by MOPC, RSC, and the Board in April 2016. RR 187 (Planning Reserve Margin) was approved by the MOPC and the BOD at their January 2017 meetings and Tariff revisions were filed on March 3, 2017. Numerous comments and protests were received and SPP answered on April 18, 2017. FERC issued a deficiency letter on May 31, 2017 and SPP answered on June 30, 2017. A FERC order rejecting the filing without prejudice was received on August 29, 2017. In that order, FERC guidance was given on three key issues: (1) SPP’s proposal fails to include a requirement that all power purchase agreements are backed by verifiable capacity to meet SPP’s RAR and fails to include provisions to allow SPP to review the agreements to verify that they are backed by capacity; (2) SPP’s proposed treatment of firm power purchases and sales in the determination of net peak demand is unduly discriminatory; and (3) SPP has not supported as just and reasonable its proposal to post publicly a list of all LREs that have not met their RAR. This revision request implements the approved resource adequacy package. It also addresses the three issues identified by FERC while continuing to maintain the foundational policy that has already been approved. Additionally, it moves the Planning Reserve Margin percentage to the SPP Planning Criteria and keeps the study process for determining the Planning Reserve Margin in the Tariff.

SPP STAFF ASSESSMENT

SPP supports RR 251.

mailto:[email protected]

Page 2 of 42

IMPACT

Will the revision result in system changes No Yes

Summarize changes:

Will the revision result in process changes? No Yes

Summarize changes:

Is an Impact Assessment required? No Yes

If no, explain:

Estimated Cost: $ Estimated Duration: months

Primary Working Group Score/Priority:

SPP DOCUMENTS IMPACTED Market Protocols Protocol Section(s): Protocol Version: Operating Criteria Criteria Section(s): Criteria Date: Planning Criteria Criteria Section(s): 4, 6, 7 Criteria Date: Tariff Tariff Section(s): Attachment AA – Resource Adequacy (new) Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s): Revision Request Process Section(s): Minimum Transmission Design

Standards for Competitive Upgrades (MTDS) Section(s):

Reliability Coordinator and Balancing Authority Data Specifications (RDS) Section(s):

SPP Communications Protocols Section(s): WORKING GROUP REVIEWS AND RECOMMENDATIONS

List Primary and any Secondary/Impacted WG Recommendations as appropriate

Primary Working Group: SAWG

Date: 11/17/2017

Action Taken: Approved

Abstained: Westar

Opposed: None

Date: 12/21/2017

Action Taken: To approve RTWG edits, SAWG edits, and the addition of Force Majeure definition fix

Abstained: None

Opposed: None

Reason for Opposition:

Page 3 of 42

Secondary Working Group: RTWG

Date: 1/3/2018

Action Taken: To approve RR 251 as modified in the meeting

Abstained: AECC, City of Independence, KMEA, MJMEUC, Westar

Opposed: None

Reasons for Opposition:

MOPC

Date: 1/16/2018

Action Taken: Approved

Abstained: BPU, Empire, Enel Green, Flat Ridge 2, LES, MJMEUC, Prairie Wind, SouthCentral MCN, Westar Energy, Westar KGE

Opposed: KMEA


KMEA: KMEA feels that B-T-M generation should have option to be included as Firm Capacity instead of being a Load Modifier, regardless of NITS or Registration Status. Load Modifiers allows LSE to cover less reserves, since Load Modifiers adjust Peak load. KMEA believes that all should carry reserves for entirety of Actual Load. New material in Attachment AA, Section 7 defines Firm Capacity in a different manner than KMEA has interpreted for the past 10 years.

RSC

Date:

Action Taken:

Abstained:

Opposed:


BOD/Members Committee

Date:

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author: Woody Lally, Jim Jacoby

Date Comments Submitted: 10/31/2017

Description of Comments: The existing Criteria includes "capacity" in the definition of Firm Power and there is no reason to lessen this requirement because of the FERC rejection. This term should not be removed since capacity is critical to the supply of Firm Power as compared to the supply of "financially firm" power. As we learned from our discussion with SWPA, just because the term "capacity" does not appear in older agreements does not mean that capacity is not being committed to support the

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transaction. In addition, the sellers of Firm Power will need to verify the specific resources that supply the capacity just as is required for any other purchase agreement. See the added requirements in the Article 8. An important concept for adjusting Net Peak Demand for Firm Power is that the contract amount is used to make the adjustment. This concept was lost with the revised definition. The requirement to provide a copy of the contract and verify the agreement should apply equally to a "Firm Power" agreement.

Status: Addressed.

Comment Author: Various

Date Comments Submitted: 10/26-31/2017

Description of Comments: SPP staff did receive comments from stakeholders outside of the revision request process. Through the stakeholder process all of the comments received were addressed and discussed, excluding the comments that were outside the scope of addressing the FERC identified issues. The comments that fell outside of the scope of this effort have been captured and will be addressed through the stakeholder process in the future.

Status: Addressed comments that met the scope of this effort.

PROPOSED REVISION(S) TO SPP DOCUMENTS

SPP Tariff (OATT)

10 Force Majeure and Indemnification

10.1 Force Majeure: An event of Force Majeure means any act of God, labor disturbance, act of the

public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any Curtailment, order, regulation or restriction imposed by governmental, military, or lawfully established civilian authorities, or any other cause beyond a Party's control. A Force Majeure event does not include an act of negligence or intentional wrongdoing. Neither the Transmission Provider, the Transmission Owner(s), nor the Transmission Customer will be considered in default as to any obligation under this Tariff if prevented from fulfilling the obligation due to an event of Force Majeure. However, a Party whose performance under this Tariff is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Tariff.

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ATTACHMENT AA Resource Adequacy

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1.0 Overview

Maintaining appropriate planning reserves ensures that the Transmission Provider will have

sufficient capacity to serve the SPP Balancing Authority Area’s peak demand. This Attachment AA

requires a Load Responsible Entity to maintain capacity required to meet its load and planning reserve

obligations. Additionally, this Attachment AA provides the obligations and responsibilities of the

Transmission Provider, Market Participants, Load Responsible Entities, and Generator Owners with

regard to load and planning reserves.

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2.0 Definitions

Terms defined herein shall only be applicable to this Attachment AA.

Asset Owner

As defined in Attachment AE of this Tariff.

Deficiency Payment

A payment by a Market Participant when one or more of its LREs has not met the Resource Adequacy

Requirement as calculated in accordance with Section 14.2 of this Attachment AA.

Deliverable Capacity

The accredited capacity of a Resource that is determined to be deliverable in an annual Deliverability

Study for a Summer Season.

Firm Capacity

The accredited capacity of commercially operable generating units, or portions of generating units,

adjusted to reflect purchases and sales of capacity with another party, and that is deliverable with firm

transmission service to the LRE’s load.

Firm Power

Power purchases and sales deliverable with firm transmission service to serve the LRE’s load with

capacity, energy, and planning reserves, that must be continuously available in a manner comparable to

power delivered to native load customers.

Generator Owner

The Asset Owner of a Resource.

Jointly Owned Unit


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Load Responsible Entity (“LRE”)

An Asset Owner with registered load in the Integrated Marketplace.

Market Participant


Net Peak Demand

The forecasted Peak Demand less the a) projected impacts of demand response programs and behind-the-

meter generation that are controllable and dispatchable and not registered as a Resource and b) adjusted

to reflect the contract amount of Firm Power with another entity as specified in Section 8.2 of this

Attachment AA.

Peak Demand

The highest demand including transmission losses for energy measured over a one clock hour period.

Resource


Summer Season

June 1st through September 30th of each year.

Winter Season

December 1st through March 31st of each year.

Workbook

An electronic spreadsheet provided by the Transmission Provider which is used by an LRE or Generator

Owner to submit information to the Transmission Provider for the purposes of administering this

Attachment AA.

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3.0 Roles and Responsibilities

3.1 Generator Owner and Load Responsible Entity

Except as provided in Section 3.1(1) of this Attachment AA, the roles and responsibilities

of the LRE and Generator Owner are separate and distinct from the other under this Attachment

AA. An entity may be an LRE, a Generator Owner, or both. For an entity that is both an LRE and

Generator Owner, the Transmission Provider shall recognize the rights, roles, and responsibilities

as separate and distinct functions.

(1) An LRE that is also a Generator Owner shall access its Workbook pursuant to the

provisions of Section 9.3(b) of this Attachment AA but shall be considered an LRE for

Workbook reporting purposes, and all excess capacity of the Generator Owner shall be

considered LRE Excess Capacity for purposes of Resource Adequacy Assurance as

described in Section 14.0 of this Attachment AA.

3.2 Market Participant and Load Responsible Entity

(1) An LRE may be a Market Participant or can engage a third party Market Participant to

represent it. If an LRE refuses to either (a) become a Market Participant or (b) engage a

third party Market Participant to represent it, the Transmission Provider shall file an

unexecuted Market Participant Agreement with the Commission pursuant to Section 2.2(6)

of Attachment AE of this Tariff.

(2) A Market Participant that represents an LRE under Attachment AH of this Tariff is the

entity responsible under this Attachment AA to ensure the LRE’s compliance with the

Resource Adequacy Requirement.

(3) The relationship between a Market Participant and its LRE, as established in the

submission of the Workbook on February 15th, will be considered fixed for the upcoming

Summer Season for enforcement of the Resource Adequacy Requirement.

(4) The Market Participant is responsible to ensure its LRE(s) provides the necessary data to

allow the Transmission Provider to verify its LRE(s)’ compliance with the Resource

Adequacy Requirement.

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(5) An LRE shall submit all necessary data to the Transmission Provider either directly or

through the LRE’s Market Participant.

(6) A Market Participant may aggregate the forecasted Peak Demand of multiple LREs whose

load assets are served by a common set of Designated Resources or a Firm Power

transaction between the LREs. In such case, the Market Participant shall be considered the

LRE for the aggregated demand and, for purposes of compliance with this Attachment AA,

the Market Participant’s forecasted Peak Demand shall be used to calculate a single

Resource Adequacy Requirement for the aggregated load assets.

(7) The Market Participant is responsible for any Deficiency Payment(s) incurred by the

LRE(s) it represents.

3.3 Procedures for Assignment of Market Participant Obligations

(1) A Market Participant may assign its duties, obligations and responsibilities for an LRE

under this Attachment AA, but only to another Market Participant. A non-Market

Participant must become a Market Participant prior to accepting an assignment.

(1)(2) Assignor Market Participant shall be responsible to negotiate and contract with another

Market Participant for the assignment of its duties, obligations, and responsibilities with

respect to the LRE. A valid assignment must be in writing, bilaterally executed by both

parties, and the assignee Market Participant shall affirmatively accept the duties,

obligations, and responsibilities of the assignor Market Participant under this Attachment

AA.

(3) Assignor Market Participant shall provide copies of the assignment to the Transmission

Provider prior to February 15th of each calendar year. In the event the demonstration of

such assignment does not occur prior to February 15th of each calendar year, the

Transmission Provider shall not be required to accept the assignment for the upcoming

Summer Season.

(4) A valid assignment by the assignor Market Participant under this Attachment AA does not

affect the assignor Market Participant’s status as a Market Participant or other rights and

obligations it may have under other provisions of this Tariff.

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(5) Except as otherwise provided in Sections 3.3(6), 3.3(7), and 3.3(8) of this Attachment AA,

upon demonstration of a valid assignment, Transmission Provider will accept the transfer

of the LRE to the assignee Market Participant, and enforce the provisions of Attachment

AA against the assignee Market Participant, without recourse against the assignor Market

Participant.

(6) Either party may serve the Transmission Provider with written notice of the assignment’s

termination. The Transmission Provider will recognize the assignment’s termination if the

notice contains a written acknowledgement by both parties that the assignment has been

terminated. Upon termination of the assignment, the duties, obligations, and

responsibilities of the Market Participant for the transferred LRE under Attachment AA of

the Tariff shall immediately revert back to assignor Market Participant, unless a

replacement assignment that meets the requirements of this section is provided to the

Transmission Provider.

(7) Nothing in the Transmission Provider’s acceptance of the assignment shall be construed

to create or give rise to any liability on the part of the Transmission Provider and the

parties to the assignment expressly waive any claims that may arise in their favor against

the Transmission Provider, except as specifically may be provided in the Tariff. The

Transmission Provider shall be held harmless by the by parties for any breach of the

assignment or dispute between the parties with regards to the assignment, and such

dispute shall not delay or cancel the financial responsibilities of the assignee Market

Participant under this Attachment AA. Any dispute between the Transmission Provider

and either party may be subject to the dispute resolution provisions of Section 12 of the

Tariff.

(8) The Transmission Provider shall not be responsible for the actions of any party, or have

any affirmative duties assigned to the Transmission Provider under the assignment. The

Transmission Provider’s recognition of the assignment shall not be construed as

Transmission Provider’s acceptance of the provisions of the assignment that may conflict

with the Tariff or the Transmission Provider’s administration of the Tariff, and

specifically, the application of this Attachment AA against the assignee Market

Participant, or upon termination of the assignment, the assignor Market Participant. In

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the event there exists a conflict between a term of the assignment and this Tariff, the

provisions of this Tariff shall control.

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4.0 Planning Reserve Margin

The Planning Reserve Margin (“PRM”) shall be set in the SPP Planning Criteria. Determination

of the PRM will be supported by a probabilistic Loss of Load Expectation (“LOLE”) Study, which will

analyze the ability of the Transmission Provider to reliably serve the SPP Balancing Authority Area’s

forecasted Peak Demand. The LOLE Study will be performed by the Transmission Provider on a biennial

basis, or more often as determined by the Transmission Provider. The Transmission Provider, with input

from the stakeholders, shall develop the inputs and assumptions to be used for the LOLE Study. The

Transmission Provider will study the PRM such that the LOLE for the applicable planning year does not

exceed one (1) day in ten (10) years, or 0.1 day per year. At a minimum, the PRM shall be determined

using probabilistic methods by altering capacity through the application of generator forced outages and

forecasted demand through the application of load uncertainty to ensure the LOLE does not exceed 0.1

day per year. The Transmission Provider shall post the final results of the LOLE Study.

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5.0 Summer Season Resource Adequacy Requirement

5.1 The Resource Adequacy Requirement is equal to the LRE’s Summer Season Net Peak Demand

plus its Summer Season Net Peak Demand multiplied by the PRM.

(1) The LRE is responsible to meet the Resource Adequacy Requirement for the Summer

Season and failure to comply shall result in a Deficiency Payment as calculated in

accordance with Section 14.2 of this Attachment AA.

5.2 The Deliverable Capacity or Firm Capacity utilized by an LRE to meet the Resource Adequacy

Requirement may not be included in the Deliverable Capacity or Firm Capacity utilized by another

LRE to meet the Resource Adequacy Requirement. Deliverable Capacity or Firm Capacity that is

contracted to other entities shall not be available to the LRE that is transferring the Deliverable

Capacity or Firm Capacity for compliance with the Resource Adequacy Requirement.

5.3 If an LRE serves load both internal and external to the SPP Balancing Authority Area, compliance

with the Resource Adequacy Requirement contained in this Attachment AA is not intended to

affect an LRE’s obligation to maintain distinct and separate amounts of Resources to cover its

applicable planning reserve obligation for its load located external to the SPP Balancing Authority

Area. Load and Resources that are pseudo-tied into the SPP Balancing Authority Area shall be

considered internal for purposes of determining the Resource Adequacy Requirement.

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6.0 Winter Season Obligation

6.1 For the Winter Season, each LRE shall maintain sufficient capacity equal to the LRE’s Winter

Season Net Peak Demand plus its Winter Season Net Peak Demand multiplied by the PRM.

6.2 The Firm Capacity utilized by an LRE may not be included in the Firm Capacity utilized by another

LRE. Firm Capacity that is contracted to other entities shall not be available to the LRE that is

transferring the Firm Capacity.

6.3 If an LRE serves load both internal and external to the SPP Balancing Authority Area, compliance

with the obligation in Section 6.0 of this Attachment AA is not intended to affect an LRE’s

obligation to maintain distinct and separate amounts of Resources to cover its applicable planning

reserve obligation for its load located external to the SPP Balancing Authority Area. Load and

Resources that are pseudo-tied into the SPP Balancing Authority Area shall be considered internal

for purposes of complying with Section 6.0 of this Attachment AA.

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7.0 Qualification of Deliverable Capacity, Firm Capacity, and Firm Power

7.1 As part of the annual Workbook submission, an LRE or Generator Owner with Deliverable

Capacity from resources internal to the SPP Balancing Authority Area shall qualify such capacity

by: (a) registering the Resource in the Integrated Marketplace; (b) submitting, or causing to be

submitted, to the Transmission Provider the current Operational Test results as performed in

accordance with the SPP Planning Criteria; and (c) submitting, or causing to be submitted, to the

Transmission Provider the current Capability Test results as performed in accordance with the SPP

Planning Criteria.

7.2 As part of the annual Workbook submission, an LRE or Generator Owner with Firm Capacity

from a resource(s) internal to the SPP Balancing Authority Area shall qualify such capacity by: (a)

demonstrating the resource(s) is (i) registered in the Integrated Marketplace or (ii) listed as a

Designated Resource in the Network Integration Transmission Service Agreement; (b) submitting,

or causing to be submitted, to the Transmission Provider the current Operational Test results as

performed in accordance with the SPP Planning Criteria; (c) submitting, or causing to be

submitted, to the Transmission Provider the current Capability Test results as performed in

accordance with the SPP Planning Criteria; and (d) demonstrating that there is firm transmission

service from the internal resource(s) to the LRE’s load.

7.3 As part of the annual Workbook submission, an LRE or Generator Owner with Firm Capacity

from a resource(s) external to the SPP Balancing Authority Area shall qualify such capacity by:

(a) demonstrating ownership or contractual rights; (b) submitting, or causing to be submitted, to

the Transmission Provider the current operational test results per the requirements of the Balancing

Authority where the resource(s) is located; (c) demonstrating that there is firm transmission service

from the external resource(s) to the LRE’s load; and (d) attesting that any external capacity being

identified is not otherwise being used as capacity in any other Balancing Authority Area or in

another resource adequacy construct.

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7.4 As part of the annual Workbook submission, an LRE with Firm Power from a resource(s) internal

to the SPP Balancing Authority Area shall qualify those purchases or sales by: (a) demonstrating

the resource(s) is (i) registered in the Integrated Marketplace or (ii) listed as a Designated Resource

in the Network Integration Transmission Service Agreement; (b) submitting, or causing to be

submitted, to the Transmission Provider the current Operational Test results as performed in

accordance with the SPP Planning Criteria; (c) submitting, or causing to be submitted, to the

Transmission Provider the current Capability Test results as performed in accordance with the SPP

Planning Criteria; and (d) demonstrating that there is firm transmission service from the internal

resource(s) to the LRE’s load.

7.5 As part of the annual Workbook submission, an LRE with Firm Power from a resource(s) external

to the SPP Balancing Authority Area shall qualify those purchases or sales by: (a) demonstrating

ownership or contractual rights; (b) submitting, or causing to be submitted, to the Transmission

Provider the current operational test results per the requirements of the Balancing Authority where

the resource(s) is located; (c) demonstrating that there is firm transmission service from the

external resource(s) to the LRE’s load; (d) demonstrating that the capacity includes planning

reserves; and (e) attesting that any external capacity being identified is not otherwise being used

as capacity in any other Balancing Authority Area or in another resource adequacy construct.

7.6 The Transmission Provider shall make all reasonable efforts to preserve the confidentiality of

information received pursuant to Section 7 of this Attachment AA when such information is so

designated as “confidential” and if such designation is reasonable, except to the extent required by

this Tariff, by regulatory or judicial order, by law or statute.

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8.0 Qualification and Verification of Power Purchase Agreements

8.1 An LRE or Generator Owner shall provide the Transmission Provider a copy of the power purchase

agreement(s) to enable the Transmission Provider to verify the Deliverable Capacity, Firm

Capacity, or Firm Power and to confirm compliance with this Attachment AA. On a prospective

basis, the LRE or Generator Owner shall only submit a copy of a new or modified agreement(s).

(1) Any redacted versions of a power purchase agreement submitted by an LRE or Generator

Owner shall contain sufficient information to allow the Transmission Provider to verify

compliance with the Resource Adequacy Requirement.

(2) An LRE or Generator Owner with a power purchase agreement that does not identify the

specific resource(s) shall identify each resource that is available or partially available

through an attestation supporting the power purchase agreement.

8.2 When the purchaser and seller are both LREs, a power purchase agreement that qualifies as Firm

Power shall result in a Net Peak Demand adjustment of the obligation for capacity and planning

reserves from the purchaser to the seller. The purchaser shall deduct the purchased contract

amount from its Net Peak Demand and the seller shall add the amount to its Net Peak Demand.

The responsibility to maintain the Resource Adequacy Requirement and the Winter Season

obligation shall transfer from the purchaser to the seller.

8.3 When the seller is not an LRE, a power purchase agreement that qualifies as Firm Power shall not

result in a Net Peak Demand adjustment and the purchaser will remain responsible for the Resource

Adequacy Requirement and Winter Season obligation for load served by the agreement. The

purchaser shall not deduct the purchased contract amount from its Net Peak Demand; however,

the purchaser may reflect as Firm Capacity the contract amount of the agreement plus the

purchaser’s PRM multiplied by the contract amount. Firm transmission service is only required

for the contract amount.

8.4 When the purchaser is not an LRE, a power purchase agreement qualifies as Firm Power shall

result in a Firm Capacity transaction for load served by the agreement. The seller, who is an LRE,

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shall not include the purchased contract amount in its Net Peak Demand; however, the seller shall

reflect as Firm Capacity the contract amount of the agreement plus the seller’s PRM multiplied by

the contract amount. Firm transmission service is only required for the contract amount.

8.5 A power purchase agreement executed prior to July 1, 2018 will continue to be defined and

qualified as Firm Power if it does not include provisions permitting the seller to interrupt deliveries

thereunder for reasons other than Force Majeure (as defined in Section 10.1 of this Tariff) or

uncured defaults. All other power purchase agreements must specifically meet the definition of

Firm Power.

8.6 An LRE may arrange for short-term capacity to provide a part of its Firm Capacity or short-term

Firm Power to reduce a portion of either its Summer Season Net Peak Demand or Winter Season

Net Peak Demand, but not both, subject to the following provisions:

(1) Such short-term capacity or short-term Firm Power shall be available for a minimum of

four consecutive months, starting either June 1st or December 1st;

(2) The amount of short-term Firm Capacity, Deliverable Capacity, or short-term Firm

Power purchased in aggregate shall not exceed 25% of an LRE’s applicable Net Peak

Demand; and

(3) If the seller under a short-term Firm Power agreement is not an LRE, then the purchaser

under the short-term Firm Power agreement will remain responsible for any Resource

Adequacy Requirement or Winter Season obligation for load served under the short-term

Firm Power agreement.

8.7 The Transmission Provider shall make all reasonable efforts to preserve the confidentiality of

information received pursuant to Section 8 of this Attachment AA when such information is so

designated as “confidential” and if such designation is reasonable, except to the extent required by

this Tariff, by regulatory or judicial order, by law or statute.

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9.0 Resource Adequacy Timeline

The Resource Adequacy Requirement process is performed annually beginning on July 1st

of each year. For any prescribed date that falls on a weekend or holiday, the date of performance

shall be the next business day.

(1) On July 1st of each year the Transmission Provider shall post the following on the SPP

website and distribute via email distribution list:

(a) Notification of the commencement of the process; and

(b) A timeline indicating when the Market Participant, LRE, and Generator Owner are

required to meet their respective obligations.

(2) By October 1st of each year the Transmission Provider will perform the Deliverability

Study.

(3) On October 1st of each year the Transmission Provider shall post and provide notice via

email distribution list:

(a) The following on the SPP website:

(i) The unpopulated Workbook;

(ii) Instructions for completing the Workbook; and

(iii) The deadline to submit the Workbook.

(b) The following on a secure website:

(i) A Workbook populated with the results of the Deliverability Study for each

individual Generator Owner.

(4) The Transmission Provider shall not modify the unpopulated Workbook after December

31st of each year. Any modification to the unpopulated Workbook by the Transmission

Provider after the initial October 1st posting shall be posted on the SPP website and

distributed via email distribution list.

(5) By February 15th of each year, each Market Participant and participating Generator Owner

will ensure the Transmission Provider is provided with a Workbook.

(6) No later than five (5) calendar days after February 15th, the Transmission Provider shall

provide notice to all Market Participants, LREs, and Generator Owners that have not

submitted a Workbook by the deadline. Such notice shall include the communication that

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the Market Participant may be subject to a Deficiency Payment if such deficiency is not

cured. A Market Participant, LRE, or Generator Owner that receives such notice shall have

ten (10) calendar days to submit its Workbook. Failure to provide a Workbook within the

ten (10) calendar days after notification shall result in the Transmission Provider disclosing

a listing of the entities that have not submitted a Workbook to the Supply Adequacy

Working Group, which will provide a report to the Markets and Operations Policy

Committee.

(7) No later than April 1st of each year, the Transmission Provider will review the information

in the Workbook to determine whether each LRE meets the Resource Adequacy

Requirement. The Transmission Provider will notify the Market Participant and the LRE

if the LRE has not met the Resource Adequacy Requirement.

(8) By May 15th of each year, an LRE or Generator Owner shall update its Workbook to reflect

purchases and sales that occurred after the initial submission.

(9) By May 15th of each year, an LRE must demonstrate it has cured any deficiency in

compliance with the Resource Adequacy Requirement.

(10) No later than June 15th of each year, the Transmission Provider shall post its final report

on the status of each LRE’s compliance with the Resource Adequacy Requirement for the

upcoming Summer Season and whether the respective Market Participant is subject to the

Deficiency Payment.

(11) On or before June 30th of each year, and after the posting of the final report, the

Transmission Provider shall calculate and assess the Deficiency Payment in accordance

with the provisions contained in Sections 14.2 and 14.3, respectively, of this Attachment

AA.

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10.0 Deliverability Study

10.1 The Transmission Provider shall perform an annual Deliverability Study. The Deliverability Study

will evaluate the deliverability to the SPP Balancing Authority Area of each Resource registered

in the Integrated Marketplace and not whether such Resources are deliverable to specific delivery

points or SPP Zones. The Deliverability Study will result in a determination of each Resource’s

capacity that is deliverable to the SPP Balancing Authority Area. The results of the Deliverability

Study shall be valid for the upcoming Summer Season and the subsequent Summer Season.

10.2 The Transmission Provider will utilize its current transmission planning models to perform the

Deliverability Study. The Transmission Provider will begin the Deliverability Study with the

initial assumption that any Resource generating in the planning model is automatically deliverable

to the SPP Balancing Authority Area for the dispatched output. A Resource’s total capacity equals

the generating unit’s maximum output of MWs. For multiple generating units at one site, the total

capacity for the site is the sum of maximum MWs of all generating units. A transfer level equal

to the difference between the Resource’s maximum MW capacity and the amount dispatched in

the planning model is determined for each Resource. A First Contingency Incremental Transfer

Capability (“FCITC”) analysis of each transfer will be performed to determine the deliverability

of the Resource. Transmission Facilities 100 kV and above will be included in the FCITC analysis.

A three percent (3%) transfer distribution factor threshold will be used to analyze constraints

impacted by the transfer.

10.3 The Deliverability Study results for each Generator Owner’s Resource shall consist of the total

Resource’s deliverability of MW amounts. Each Generator Owner of a Jointly Owned Unit will

coordinate to determine the MW deliverability amounts for its share of a Jointly Owned Unit.

10.4 The amount of Deliverable Capacity of any Resource available for purchase to meet the PRM

portion of the Resource Adequacy Requirement shall equal the lesser of: a) the Resource’s

accredited capacity less the MW amount of capacity that has been committed to meet i) Firm

Capacity and ii) a sale to another entity; or b) the amount of a Resource’s total deliverable MWs

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less the MW amount of capacity that has been committed to meet i) Firm Capacity and ii) a sale

to another entity, as determined from the Generator Owner’s Workbook.

10.5 A Generator Owner that does not submit a Workbook that contains the amount of generation

capacity available through the Deliverability Study shall be deemed to have no Deliverable

Capacity and shall not be entitled to receive any revenue distributions collected from Deficiency

Payments.

10.6 A power purchase agreement to satisfy the PRM portion of the Resource Adequacy Requirement

based on the most recent Deliverability Study may only rely on the results of such study for no

longer than the upcoming Summer Season and the subsequent Summer Season.

(1) Deliverable Capacity purchases by an LRE to satisfy the PRM portion of the Resource

Adequacy Requirement will not require firm transmission service to support the capacity.

Deliverable Capacity purchases shall not entitle a Market Participant to receive Auction

Revenue Rights under Attachment AE of the Tariff.

(2) Deliverable Capacity purchases shall not be utilized to serve any portion of the LRE’s

Summer Season Net Peak Demand. If the LRE’s power purchase agreement to satisfy the

PRM portion of the Resource Adequacy Requirement also includes capacity needed to

serve any portion of its Summer Season Net Peak Demand, the LRE must secure firm

transmission service for such capacity to serve any portion of its Summer Season Net Peak

Demand.

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11.0 Workbook

11.1 The Generator Owner’s Workbook will contain, but is not limited to, the following information:

(1) Capacity sales to another entity; and

(2) Uncommitted Deliverable Capacity available to meet the PRM.

11.2 The LRE’s Workbook will contain, but is not limited to, the following information:

(1) The LRE’s Summer Season Net Peak Demand;

(2) Firm Capacity owned by the LRE;

(3) Purchases and sales for Deliverable Capacity;

(4) Purchases and sales for Firm Capacity;

(5) Purchases and sales for Firm Power; and

(6) Uncommitted Deliverable Capacity available to meet the PRM.

11.3 The LRE’s Workbook shall be subject to the following provisions:

(1) A Workbook will be used to qualify the LRE’s compliance with the Resource Adequacy

Requirement for the upcoming Summer Season. Absent a calculation error or otherwise

incorrect information, an LRE that demonstrates compliance with the requirements of

Section 5.0 of this Attachment AA is considered to have met its Resource Adequacy

Requirement, subject to any subsequently reported sales. An LRE shall update its

Workbook by May 15th to correct calculation errors or incorrect information.

(2) A Workbook may include any Resources, provided the Resource’s capacity is expected to

be available during June 15th through September 15th. After February 15th, if the expected

availability of a Resource changes to unavailable during June 15th through September 15th,

the Resource will be considered as available for purposes of meeting the Resource

Adequacy Requirement.

(3) Resources contained in the Workbook that are identified by February 15th to be unavailable

during part or all of the period from June 15th through September 15th will not count as

capacity for purposes of meeting the LRE’s compliance with the Resource Adequacy

Requirement. Should a Resource that is initially identified to be unavailable during part or

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all of the period from June 15th through September 15th but subsequently becomes

available and the LRE updates its Workbook by May 15th, such Resource will count as

capacity for purposes of meeting the Resource Adequacy Requirement.

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12.0 Post-Season Analysis

The Transmission Provider shall conduct a post-Summer Season analysis to compare the LRE’s

actual Summer Season Net Peak Demand versus the LRE’s planning forecast. The analysis would be

used to evaluate, at a minimum, LRE’s planning forecast consistency and develop further improvements

for the resource adequacy process. The Transmission Provider will take the results to the Supply

Adequacy Working Group for review who may refer cases of potential discrepancies to the Markets and

Operations Policy Committee for further investigation and action, if necessary.

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13.0 Cost of New Entry

The Cost of New Entry (“CONE”) value shall be 85.61 $/kw-yr. The CONE value shall

be reviewed on or before November 1st of each year by the Transmission Provider and any changes

shall be filed with the Commission. The Transmission Provider shall post the Commission-

approved CONE for the next Summer Season on the SPP website within ten (10) calendar days of

Commission approval.

The Transmission Provider’s calculation of the CONE for the SPP Balancing Authority

Area shall be based on publicly available information (e.g., information provided by the Energy

Information Administration) relevant to the estimated annual capital and fixed operating costs of

a hypothetical natural gas-fired peaking facility. The Transmission Provider shall consider factors,

including, but not limited to: (1) physical factors (such as, the type of generating resource that

could reasonably be constructed to provide Firm Capacity in the SPP Balancing Authority Area,

costs associated with locating the Resource within the SPP Balancing Authority Area); (2)

financial factors (such as, the hypothetical debt/equity ratio for the Resource, the cost of capital, a

reasonable return on equity, applicable taxes, interest, insurance); and (3) other costs (such as,

costs related to permitting, environmental compliance, operating and maintenance expenses). In

calculating the CONE value, the Transmission Provider shall not consider the anticipated net

revenue from the sale of capacity, energy or Ancillary Services.

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14.0 Resource Adequacy Assurance

14.1 Variables

The variables used in the calculations are as follows:

(1) Generator Owner Excess Capacity

The available Deliverable Capacity above the committed capacity of Generator Owner

Resource(s) as reflected in its completed Workbook.

(2) LRE Deficient Capacity

Resource Adequacy Requirement less the sum of Deliverable Capacity and Firm Capacity,

or zero if the sum of Deliverable Capacity and Firm Capacity is greater than or equal to the

Resource Adequacy Requirement.

(3) LRE Excess Capacity

Deliverable Capacity and Firm Capacity less Resource Adequacy Requirement, or zero if

the Deliverable Capacity and Firm Capacity is less than or equal to the Resource Adequacy

Requirement.

(4) SPP Balancing Authority Area Planning Reserve

[(The sum of all LREs’ Deliverable Capacity and Firm Capacity less the sum of all LREs’

Summer Season Net Peak Demand) plus the sum of all Generator Owner Excess Capacity]

divided by the sum of all LREs’ Summer Season Net Peak Demand.

14.2 Deficiency Payment

(1) Deficiency Payment =

LRE Deficient Capacity * CONE * CONE FACTOR

Where the CONE FACTOR shall be:

(a) 125% when the SPP Balancing Authority Area Planning Reserve is greater than or

equal to the PRM plus 8%; or

(b) 150% when the SPP Balancing Authority Area Planning Reserve is greater than or

equal to the PRM plus 3%, but less than the PRM plus 8%; or

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(c) 200% when the SPP Balancing Authority Area Planning Reserve is less than the

PRM plus 3%.

(2) An LRE that resolves its capacity deficiency for the purpose of meeting the Resource

Adequacy Requirement by May 15th of the applicable year will be considered compliant.

(3) An LRE that fails to obtain sufficient capacity to meet the Resource Adequacy

Requirement by May 15th of the applicable year, or fails to correct its Workbook by May

15th of the applicable year, will be considered deficient for the upcoming Summer Season.

The responsible Market Participant shall be subject to the Deficiency Payment and such

payment shall not relieve the LRE’s obligation to comply with the Resource Adequacy

Requirement.

(4) A Market Participant, or its LRE, that does not submit the Workbook to the Transmission

Provider by May 15th of the applicable year will be considered one hundred percent

(100%) deficient and in violation of the Resource Adequacy Requirement for the upcoming

Summer Season and shall subject the responsible Market Participant to the Deficiency

Payment for the entire Resource Adequacy Requirement. To calculate the LRE Deficient

Capacity, the Transmission Provider shall set the Deliverable Capacity and Firm Capacity

to zero and utilize the previous year’s Summer Season Peak Demand.

14.3 Billing Procedure

On an annual basis, the Transmission Provider shall calculate the Deficiency Payment

amounts to be assessed against a Market Participant pursuant to Section 14.2 of this Attachment

AA. On or before June 30th of the applicable calendar year, the Transmission Provider shall

submit an invoice to the Market Participant as a charge for the Deficiency Payment amount. The

invoice shall be paid by the Market Participant within seven (7) calendar days of receipt. All

payments shall be made in immediately available funds payable to the Transmission Provider, or

by wire transfer to a bank named by the Transmission Provider. In the event of a dispute between

the Transmission Provider and the Market Participant related to the calculation and assessment of

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a Deficiency Payment, the Market Participant shall pay the amount in dispute, and the

Transmission Provider shall deposit into an escrow account the portion of the invoice in dispute,

pending resolution of such dispute.

14.4 Revenue Distribution

Revenues from Deficiency Payments collected by the Transmission Provider shall be

distributed to Market Participant(s) for its LRE(s) with LRE Excess Capacity or Generator

Owner(s) with Generator Owner Excess Capacity on a pro rata basis according to the following:

(1) In the event that the sum of all LRE Excess Capacity is greater than or equal to the sum of

LRE Deficient Capacity then:

LRE revenue =

(individual LRE Excess Capacity / sum of all LRE Excess Capacity) * sum of the

Deficiency Payment(s)

(2) In the event that the sum of all LRE Excess Capacity is less than the sum of LRE Deficient

Capacity, then the allocation of revenues shall be distributed according to the following

steps:

(a) LRE revenue =

[(individual LRE Excess Capacity / sum of LRE Deficient Capacity) * sum of the

Deficiency Payment(s)]; and

(b) Any remaining revenues not allocated pursuant to Section 14.4(2)(a) of this

Attachment AA will be allocated to Generator Owner(s) in accordance with each

Generator Owner’s submitted completed Workbook in the following manner:

(i) In the event that the sum of all LRE Excess Capacity and all Generation

Owner Excess Capacity is greater than or equal to the sum of Deficient

Planning Reserve(s) then:

Generator Owner revenue =

[[(sum of LRE Deficient Capacity – sum of all LRE Excess Capacity) / sum

of LRE Deficient Capacity] * (individual Generator Owner Excess Capacity

/ sum of all Generator Owner Excess Capacity) * sum of Deficiency

Payment(s)]; or

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(ii) In the event that the sum of all LRE Excess Capacity and all Generator

Owner Excess Capacity is less than the sum of Deficient Planning Reserve(s)

then:

(a) Generator Owner revenue =

[(individual Generator Owner Excess Capacity / sum of LRE

Deficient Capacity) * sum of Deficiency Payment(s)]; and

(b) All remaining revenue not allocated in Section 14.4(2)(b)(ii)(a) of

this Attachment AA will be allocated to each LRE that has met its

Resource Adequacy Requirement on a load ratio share based on

Summer Season Net Peak Demand:

LRE revenue =

[(sum of LRE Deficient Capacity – sum of all LRE Excess Capacity

– sum of all Generator Owner Excess Capacity) / sum of LRE

Deficient Capacity] * (individual LRE Summer Season Net Peak

Demand / sum of LRE Summer Season Net Peak Demand(s) that

have met the Resource Adequacy Requirement) * sum of Deficiency

Payment(s)

(3) The Transmission Provider shall not be liable to an LRE for any revenues collected and

distributed pursuant to this Attachment AA, or for damages arising out of or relating to any

act or omission, performance, or failure to perform of a Market Participant with respect to

such revenues or distribution thereof. It is the responsibility of each Market Participant to

distribute such revenues that it receives pursuant to Section 14.4 of this Attachment AA to

its eligible LREs.

14.5 Dispute Resolution

All disputes under this Attachment AA shall be subject to the dispute resolution procedures

contained in Section 12 of this Tariff.

SPP Operating Criteria

N/A

Page 32 of 42

SPP Planning Criteria

4. Planning Reserve Margin

The Planning Reserve Margin (“PRM”) shall be twelve percent (12%). If a Load Responsible

Entity’s Firm Capacity is comprised of at least seventy-five percent (75%) hydro-based generation, then

such PRM shall be nine point eight nine percent (9.89%).

Determination of the PRM will be supported by a probabilistic Loss of Load Expectation

(“LOLE”) Study, which will analyze the ability of the Transmission Provider to reliably serve the SPP

Balancing Authority Area’s forecasted Peak Demand. The LOLE study will be performed in accordance

with Attachment AA of the SPP OATT.

4.1 Definitions

4.1.1 Load Responsible Entity

As defined in Attachment AA of the SPP OATT.

4.1.2 Firm Capacity

As defined in Attachment AA of the SPP OATT.

4.1.3 P e a k D e m a n d

As defined in Attachment AA of the SPP OATT. A Load Serving Member’s System Capacity shall be equal to the capability of its generating facilities, including its ownership share of jointly owned units, demonstrated under procedures set forth in SPP Rating of Generating Equipment Criteria, adjusted to reflect the purchase from and/or sale to any other party of generating capacity or SPP defined Operating Reserve, under any appropriate agreement. For purchases and sales, the contract amount governs regardless of the amount actually delivered at the time of such Load Serving Member's greatest Net Load.

Page 33 of 42

Capacity purchases shall only be considered if Firm Transmission Service is in place to the Load Serving Member for delivery of power from such capacity.

Unless reported separately, generating facilities owned by others within the Load Serving Member’s system that are obligated to furnish firm power to customers within the Load Serving Member’s system shall also be reported. Absent any bilateral contractual arrangements with the host Control Area, the host Control Area will not be required to be responsible for capacity and/or reserve requirements. The reporting of generating facilities owned by others does not constitute an obligation on the Load Serving Member's part to furnish reserves or back up power for that generation.

4.1.4 Net Load

The term Net Load for any Load Serving Member shall mean, for any clock hour:

a) Net generation by the Load Serving Member's facilities; plus b)

Net receipts into the Load Serving Member's system; minus c) Net

deliveries out of such Load Serving Member's system

Unless reported separately, the Net Load of other non-Load Serving Members located within the Load Serving Member’s system shall also be reported. Absent any bilateral contractual arrangements, the reporting of these loads does not constitute an obligation on the Load Serving Member's part to furnish reserves, back up power, or incur financial obligations from SPP for that load.

4.1.5 Capacity Year

Capacity Year shall mean a period of twelve consecutive months beginning on October 1 of each calendar year. Any period less than a Capacity Year shall be designated as Short Term.

4.1.6 System Peak Responsibility

System Peak Responsibility of a Load Serving Member for any Capacity Year shall mean the Load Serving Member's greatest Net Load during that Capacity Year plus:

a) The contract amount of Firm Power sold to others under agreements in effect as of the time

of such Load Serving Member's greatest Net Load which provide for the sale of a specified amount of Firm Power; and minus

b) The contract amount of Firm Power purchased from others under agreements in effect as of the time of such Load Serving Member's greatest Net Load which provide for the purchase of a specified amount of Firm Power.

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In each case, the contract amount governs regardless of the amount actually delivered at the time of a Load Serving Member's greatest Net Load.

4.1.7 Capacity Margin

Capacity Margin shall mean the amount by which a Load Serving Member's System Capacity exceeds its System Peak Responsibility.

4.1.8 Percent Capacity Margin

Percent Capacity Margin shall be defined by the formula:

Percent Capacity Margin = (Capacity Margin/System Capacity) x 100

4.1.9 Minimum Required Capacity Margin

Each Load Serving Member’s Minimum Required Capacity Margin shall be twelve percent. If a Load Serving Member’s System Capacity for a Capacity Year is comprised of at least seventy- five percent hydro-based generation, then such Load Serving Member’s Minimum Required Capacity Margin for that Capacity Year shall be nine percent.

4.1.10 System Capacity Margin Responsibility

A Load Serving Member’s System Capacity Responsibility for any Capacity Year shall mean the sum of that Load Serving Member's System Peak Responsibility and its Minimum Required Capacity Margin.

4.1.11 Capacity Balance

Capacity Balance shall mean the amount by which a Load Serving Member's System Capacity exceeds its System Capacity Responsibility.

4.1.12 Firm Transmission Service

Firm Transmission Service is that service defined in any applicable transmission service provider tariff.

4.2 Capacity Responsibility

a) Each Capacity Year, each Load Serving Member shall possess System Capacity at least equal to

its System Capacity Responsibility.

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b) Prior to the establishment of its System Peak Responsibility for each Capacity Year, each Load

Serving Member shall provide System Capacity by one or more of the following means:

i) Establishing a unit rating consistent with SPP generating equipment rating Criteria, prior to establishing its System Peak Responsibility;

ii) Reducing its System Peak Responsibility by purchase of Firm Power from any

Member or non-Member by separate agreement;

iii) Separate written agreement with another Member or a non-Member for purchase of a specified amount of capacity; and/or

iv) Reducing its Net Load.

c) A Load Serving Member may purchase Short Term capacity to provide a part of its System

Capacity or Short Term Firm Power to reduce its System Peak Responsibility subject to each of the following restrictions:

i) Such Short Term period shall not be less than four consecutive months, and shall

include the day the Load Serving Member establishes its System Peak Responsibility. Such period shall begin during May 1 to June 1 or November 1 to December 1;

ii) The amount of Short Term capacity or Short Term Firm Power purchased shall not exceed

25% of the Load Serving Member's System Peak Responsibility; and

iii) The Load Serving Member shall purchase such Short Term Capacity or Short Term Firm Power prior to the start of the Short Term period.

d) A Load Serving Member may sell Short Term Capacity or Short Term Firm Power from resources

comprising its Capacity Balance, provided that it’s System Capacity Responsibility is met.

4.3 Records

Each Load Serving Member, upon request, shall provide accurate and detailed records of information related to this Criteria to the SPP Staff. Except for System Peak Responsibility, all other information shall be provided prior to establishing System Peak Responsibility for a Capacity Year and shall include; validation of System Capacity per SPP Rating of Generating Equipment Criteria, Capacity purchase and sale contracts, Firm Power purchase and sale contracts, and firm transmission service agreements. The SPP Staff shall verify information supplied by each Load Serving Member. Calculations shall be based on the highest peak load of each of the Load Serving Members during the

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Capacity Year. All capacity and demand values will be rounded to the nearest whole MW for purposes of this Criteria. All data submitted to SPP related to this Criteria shall be considered confidential by the SPP Staff and shall not be released in any form except by force of law

4.4 Generation Planning

4.4.1 Design Futures

a) In order to maintain a balanced design of the electric system, excessive concentration of generating

capacity in one unit, at one location, or in one area shall be avoided.

b) Auxiliary power sources shall be provided in each major generating station to provide for the safe shutdown of all the units in the event of loss of external power.

c) In each major load area of SPP, a unit capable of black start shall be provided having the capability of restarting the other units in the area.

d) Boiler controls and other essential automation of major generating units shall be designed to withstand voltage dips caused by system short circuits.

4.4.2 Fuel Supply

Assurance of having desired generating capacity depends, in part, on the availability of an adequate and reliable fuel supply. Where contractual or physical arrangements permit curtailment or interruption of the normal fuel supply, sufficient quantities of standby fuel shall be provided. Due to the dependence of hydroelectric plants on seasonal water flows, this factor shall be taken into consideration when calculating capacity for capacity margin requirements. 6.3.5 Capacity Benefit Margin (CBM)

CBM on a Flowgate basis is the amount of Flowgate capacity reserved by load serving entities to ensure access to generation from interconnected systems to meet generation reliability requirements. SPP will use a probabilistic approach for Regional and sub-regional Generation Reliability assessments. These assessments will be performed by the SPP on a biennial basis. Generation Reliability assessments examine the regional ability to maintain a Loss of Load Expectation (LOLE) standard of 1 day in ten years. The SPP capacity margin Criteria requires each control area to maintain a minimum of 12% capacity margin for steam-based utilities and 9% for hydro- based utilities. Historical studies indicate that the LOLE of one day in ten years can be maintained with a 10% - 11% capacity margin. SPP does not utilize CBM for calculations of ATC for some or all of the following reasons:

Page 37 of 42

(1) the existing level of internal capacity reserve margin of each member is adequate

(2) historical reliability indicators of transmission strength of the SPP area

(3) Open Access transmission usage environment allows greater purchasing options

Since SPP does not utilize CBM for any flowgate within the SPP footprint, the CBM value used in any calculations will be zero.

7.1 Accredited Net Generating Capacity

This Section shall be used to determine the annual and seasonal accredited net generating capacity of generators in calculating the capacity/reserve margin. Procedures are herein for establishing a system of records so that changes in capacity during the life of the equipment can be recognized. These Aprocedures define the framework under which the net generating capacity are to be established while recognizing the necessity of exercising judgment in their determination. The terms defined and the net generating capacity established pursuant to these procedures shall be used for SPP purposes, including determining capacity reserve margins for capacity planning and preparation of reports of other information for industry organizations, news media, and governmental agencies. These net generating capacity are not intended to restrict daily operating practices associated with SPP operating reserve sharing, for which more dynamic ratings may be necessary. Each member shall test its generating equipment in accordance with the procedures contained herein. On the basis of these tests summer and winter net capability ratings for each generating unit and station on the member's electric system shall be established. This net capability is the maximum capacity a unit can sustain over a specified period modified for seasonal limitations and reduced by the capacity required for station service or auxiliaries. The summer net capability of each unit may be used as the winter net capability without further testing, at the option of the member. As a minimum, each member shall conduct tests on all its generators that are designated as a part of the resource for supplying a member’s peak load and minimum capacity/reserve margin requirement of this Criteria. The seasonal net capabilities shall be furnished to SPP for all existing generating units and upon installation of new generating units and shall be revised at other times when necessary. For newly installed generating units, design output may be used for the first peak operating season to allow sufficient time for Operational and Capability test. For generating units out of service during the entire preceding peak season, the Operational test and the effective Capability test results may be used to satisfy the Operational and Capability test requirement for the upcoming peak operating season. Members shall annually report the seasonal net generating unit capability in conjunction with the Department of Energy 411 Report data gathering effort.

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7.1.5.2 Seasonality

(1) The summer season is defined by the months June, July, August and September. The winter season is defined by the months December, January, February, and March. The adjustments required to develop seasonal net capabilities are intended to include seasonal variations in ambient temperature, condenser cooling water temperature and availability, fuel changes, quality and availability, steam heating loads, reservoir levels, scheduled reservoir discharge, and wind speed.

(2) The total seasonal net capability rating shall be that available regularly to satisfy the daily load patterns of the member and shall be available for a minimum of four continuous hours taking into account possible fuel curtailments and thermal limits.

(3) The seasonal net capability of each generating unit shall be based upon a set of conditions, referred to as the "Net generating capacity Conditions" for that unit. This set of conditions is determined by the geographical location of the unit, and is composed of three or four factors, depending upon the type of unit. The three factors which can affect most generating units are: Ambient dry-bulb temperature, Ambient wet-bulb temperature and Barometric pressure. Condensing steam turbines which obtain condenser cooling water from a lake, river, or comparable source have a fourth factor: Condenser cooling water source temperature.

(4) The Rating dry-bulb and wet-bulb temperatures shall be obtained from weather data provided in the most recently published American Society of Heating, Refrigeration, and Air Conditioning Engineers (ASHRAE) Fundamentals Handbook, Chapter 27 Climatic Design Information. The handbook is published every four years; 1997, 2001, etc., and is based on 15 years of historical weather data where available. If the generating station is within 30 miles of the nearest weather station reported in the Handbook, then these temperatures will be those for the nearest station. For all other stations, rating temperatures shall be determined by interpolating between weather stations using plant latitude and longitude. The steps to be used for interpolating weather data and correcting for elevation are presented in SPP Criteria Appendix PL-1.

(5) If experience for a given unit suggests otherwise, members may optionally use their own site specific temperature data if accurate hourly data is available to allow calculation of the temperature levels as defined in the Criteria. Site specific data shall contain both dry- bulb and wet-bulb temperatures.

(6) Temperatures for summer rating of equipment should be taken from Handbook Table 1B: Cooling and Dehumidification Design Conditions - Cooling DB/MWB for 0.4% DB (dry-

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bulb) and MWB (mean wet-bulb) (Column 2a and 2b, respectively). According to the 2001 Handbook Page 27.2, "The 0.4% annual value is about the same as the 1.0% summer design temperature in the 1993 ASHRAE Handbook." In older Handbooks, the dry-bulb temperature for summer rating of equipment shall be taken as that which is equaled or exceeded 1% of the total hours during the months of June through September for the plant's geographical location. The wet-bulb temperature for the summer rating shall be the "mean coincident wet-bulb" temperature corresponding to the above dry-bulb temperature.

(7) The temperature for winter rating of equipment should be taken from Handbook Table 1A: Heating and Wind Design Conditions-United States - Heating Dry Bulb 99% (Column 2b). According to the 2001 Handbook Page 27.3, "Annual 99.6% and 99.0% design conditions represent a slightly colder condition than the previous cold season design temperatures, although there is considerable variability in this relationship from location to location." In older Handbooks, the minimum dry-bulb temperature for winter testing and net generating capacity shall be taken as that which is equaled or exceeded 99% of the total hours during the months of December through February (per Handbook definition) for the plant's geographical location. The wet-bulb temperature is not significant for the winter rating and can be disregarded.

(8) Standard barometric pressure for a plant site shall be determined for each plant elevation from the equation provided in Appendix PL-1.

(9) For those units using a lake or river as a source of condenser cooling water, the summer standard inlet temperature is the highest water inlet temperature during the month concurrent with the Load Serving Mmember’s peak load of the year, averaged over the past ten years.

(10) Ambient wet-bulb temperature and condenser cooling water temperature are generally not significant factors in adjusting cold weather capability of generating units. Shall special situations arise in which these temperatures are required, reasonable estimates for temperatures occurring coincidentally with the winter rating dry-bulb temperature as defined in the Criteria shall be used.

7.1.5.3 Net Generating Capacity Adjustments

(1) The rated net capability of a unit may be above or below the actual tested net generation as a

result of adjustments for Net generating capacity Conditions, with the exception of units with winter season net generating capacity greater than their summer net generating capacity. For these units, the winter season rated net capability shall be no greater than the actual tested net generation. No net generating capacity adjustment for ambient conditions shall be made.

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(2) Seasonal net capability shall not be reduced to provide regulating margin or spinning reserve. It shall reflect operation at the power factor level at which the generating equipment is normally expected to be operated over the daily peak load period.

(3) Extended capability of a unit or plant obtained through bypassing of feed-water heaters, by utilizing other than normal steam conditions, by abnormal operation of auxiliaries in steam plants, or by abnormal operation of combustion turbines or diesel units may be included in the seasonal net capability if the following conditions are met; a) the extended capability based on such conditions shall be available for a period of not less than four continuous hours when needed and meets the other restrictions, and b) appropriate procedures have been established so that this capability shall be available promptly when requested by the system operator.

(4) The seasonal net capability established for nuclear units shall be determined taking into consideration the fuel management program and any restrictions imposed by governmental agencies.

(5) The seasonal net capability established for hydro electric plants, including pumped storage projects, shall be determined taking into consideration the reservoir storage program and any restrictions imposed by governmental agencies and shall be based on median hydro conditions.

(6) The seasonal net capability established for run-of-the-river hydroelectric plants shall be determined using historical hydrological data on a monthly basis.

(7) The recommended methodology to evaluate the net planning capability established for wind or solar facilities shall be determined on a monthly basis, as stated below. If a member’s desire to use a more restrictive methodology to evaluate the net capability of wind or solar they may do so, however net capability determined by the alternative methodology employed cannot credit the wind or solar with a capability greater than determined with the methodology stated below:

(a) Assemble all available hourly net power output (MWH) data measured at the system interconnection point.

(b) Select the hourly net power output values occurring during the top 3% of load hours for the SPP Load Serving Entity for each month of each year for the evaluation period.

(c) Select the hourly net power output value that can be expected from the facility

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60% of the time or greater. For example, for a 5 year period with the 110 hourly net power output values ranked from highest to lowest, the capacity of the facility will be the MW value in the 65th data point.

(d) A seasonal or annual net capability may be determined by selecting the appropriate monthly MW values corresponding to the Load Serving Entity’s peak load month of the season of interest (e.g., 22 hours for a typical 30 day month and 110 hours for a 5 year period).

(e) Facilities in commercial operation 3 years or less:

(i) The data must include the most recent 3 years.

(ii) Values may be calculated from wind or solar data, if measured MW values are

not yet available. Wind data correlated with a reference tower beyond fifty miles is subject to Generation Supply Adequacy Working Group approval. Solar data correlated with a reference measuring device beyond two hundred miles is subject to Generation Supply Adequacy Working Group approval. For calculated values, at least one year must be based on site specific data.

(iii) If the Load Serving Entity chooses not to perform the net capability calculations as described above during the first 3 years of commercial operation, the Load Serving Entity may submit 5% for wind facilities and 10% for solar facilities of the site facility’s nameplate rating.

(f) Facilities in commercial operation 4 years and greater:

(i) The data must include all available data up to the most recent 10 years of

commercial operation.

(ii) Only metered hourly net power output (MWH) data may be used.

(iii) After three years of commercial operations, if the Load Serving Entity does not perform or provide the net capability calculations to SPP as described above, then the net capability for the resource will be 0 MW.

(g) The net capability calculation shall be updated at least once every three years.

7.1.6 4.4.2 Fuel Supply

Assurance of having desired generating capacity depends, in part, on the availability of an adequate and reliable fuel supply. Where contractual or physical arrangements permit curtailment or interruption of the normal fuel supply, sufficient quantities of standby fuel shall be

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provided. Due to the dependence of hydroelectric plants on seasonal water flows, this factor shall be taken into consideration when calculating capacity for reserve margin requirements.

Market Protocols

N/A

SPP Business Practices

N/A

Integrated Planning Model (ITP Manual)

N/A

Revision Request Process

N/A

Minimum Transmission Design Standards for Competitive Upgrades (MTDS)

N/A

Reliability Coordinator and Balancing Authority Data Specifications (RDS)

N/A

SPP Communications Protocols

N/A

Cost Allocation - Wind Rich Areas(2011 – Now)

January 29, 2018

Al Tamimi, Ph.D., P.E.

VP, Transmission Planning & Policy

Sunflower Electric Power Corporation

Overview• There has been a Paradigm Shift on why SPP builds Transmission

o When HWBW was created, Transmission projects were primarily based on changes in load or changes in Designated Resources

o What is driving transmission build today,? load is mostly stagnant and DR’s are taken care of by the Aggregate Study process Renewable generation is built Geographically far from load centers, i.e. Wind where the wind blows, Solar

where the sun shines• Large percentage of wind projects in SPP are built in small load zones

o Causes wind power to be exported out of the local zones for many hours of the year as connected wind has exceeded the local load in the Zone

o Additional Wind benefits the whole SPP Market, but not necessarily the local zones More transmission upgrades may need to be built, most of which are Byway Projects

o 2/3 of the costs of Byway projects will probably be assigned to the local Zone which is not receiving the benefits of reduced energy costs

o Continued development of Wind/Solar may drive additional upgrades in the ITP processo The GI and/or Aggregate study does not protect the local Zone the situation All direct assigned upgrade costs are eligible for Z2 credits, over 90% of Z2 credits

are uplifted through HWBW2

Overview (cont.)• Highway/byway cost allocation is not working well under the new Paradigm

o HWBW based on voltage level and geographyo Load growth: works well since transmission would be built close to loado No load growth in host zones: does not work as well, local upgrades may be built

for other reasonso Costs are not being assigned to those getting the benefits Lower energy costs to the Market as a whole, but not necessarily to the local Zone Building new transmission that releases trapped generation will probably not lower

energy costs to the local Zone, • Generally there is an increase in energy cost plus the increase in Zonal Transmission

rates Congestion and congestion relief impact on host entities

• RCAR is not finding the problemo The current analysis is only focused on “Historic Benefit/Costs”o Need to look at how new facilities are being used and why it is being built. The use of the transmission facilities changes under different markets

• BA• Energy Imbalance Service Market (EIS) • Integrated Market (IM) 3

Questions Needing Answered• Why are we building transmission today with minimal load growth?

• Is the current cost allocation method properly allocating cost to those who benefit from the transmission build out?

4

Paradigm Shift: Is the Current Byway Voltage Cost Allocation in SPP Reflective of the System Use Today?

2009• Historically Transmission Built to connect generators to Load & Changes in Load• SPP Examined Cost Allocation• Ran Tests for FERC Filing• Developed Highway/Byway Cost Allocation

Mar-14

• Integrated Marketplace started• Economic Upgrades became more important• IPPs can send power into the Market w/o Firm Transmission (ERIS)

Future

• Has the “Highway” been built out enough that most of the future upgrades are “Byway” projects?

• Are “Byway” projects the new Economic Upgrade?• If So, Should the Cost Allocation Method be modified?

11-17

• <2000 MW load growth, >13,000 MW of wind additions*, 3600 MW of generation retirements**• More Projects Constructed on the “Byway” Than the “Highway” ***

• 5x as many Byway projects than Highway projects through based on RCAR II project list• About 2,000 miles of 345 kV• With minimal load growth, 1,600 miles of Byway projects

* EIA, SPP Fast Facts, Wind Coalition presentations** Question answered through SPP RMS portal*** SPP Quarterly Project Status Update

5

The Current Situation

• SPP Peak Load in 2016 = 51,200 MW

• 5 yr. demand growth of 1,100 MW in SPP (approx. 2% total or 0.4%/yr.)

• 6GW of solar in the queue

• Analysts predict 8.2 GW of wind build (43 GW in queue)

6

7OKLAHOMA

Colorado

Sunflower Transmission System

99 MW‐WR

GC 102 MW‐KCPL

Ensign98.9 MW‐KCPL

CIMARONI165 MW‐KCPLCIMARII200 MW ‐ ?

MRWYI 101 MW‐EmpireMRWYII 99 MW ‐ WR

SST‐105 MM ‐ SECI

GPW100.5 MW‐SprintSPRVILL 154.5 MW – KCPL & Sprint

IRONWD 250 MW‐ WR‐?WESTPLN 294.6 MW – ?

WTGLVB 178.2 MW‐ AlianzP1,2B1,2 400 MW – Google, KC Board of PU

Flat Ridge‐101 MM ‐ WR

100 MW

200 MW

300 MW

500 MW

Case History & Analysis: Sunflower Electric• Sunflower is in a “Wind Rich Area”• Sunflower zone exported wind power to other SPP members 61.89% of

the time in 2016• Transmission facility costs are high

o Sunflower zone has small load compared to facilities needed for new generation installed.

• Impacts to Customers is largeo For the same cost, projects in Zones with small loads cost more per customer than

larger load zones

Note: The use of “Sunflower in this presentation refers to the combined Sunflower (SECI) and Mid-Kansas (MKEC) Zones unless otherwise noted

8

9

$82

$725

$447

$913

$225

$958

$2,215

$286

$128

$348

$1,214

$149

$772

$521

$165

$0

$500

$1,000

$1,500

$2,000

$2,500

AEP EDE GMO GRDA KCPL LES MIDW NPPD OGE OPPD SPRM SPS SECI WFEC WR

COMPARISON OF COST / MW OF LOAD FOR $1.0 M OF BYWAY PROJECT FOR EA. ZONE

Impact on SECI VS Selected Zones

AEP 1 9.5KCPL 1 3.4OGE 1 6.0WR 1 4.7SPS 1 5.2

2011 – 2018 Transmission Byway Cost / MW Load

10

Zone 2016 12CPLRS

(w/o IS)

67% of Byway Costs Allocated to The Zone

for Projects built between 2011‐2018

% of B/W Project Per

Entity

Byway Projects

$/MW LoadAEP 8,174 22.75% 199,892,054 15.82% $24,456 EDE 919 2.56% ‐ 0.00% $0 GMO 1,493 4.15% 3,041,780 0.24% $2,038 GRDA 730 2.03% 215,874 0.02% $296 KCPL 2,966 8.25% 127,874 0.01% $43 LES 696 1.94% 3,482,366 0.28% $5,007

MIDW 301 0.84% 19,941,809 1.58% $66,328 NPPD 2,331 6.49% 73,020,873 5.78% $31,332 OGE 5,202 14.48% 97,415,320 7.71% $18,726 OPPD 1,916 5.33% 36,757,631 2.91% $19,186 SPRM 549 1.53% ‐ 0.00% $0 SPS 4,469 12.44% 441,474,236 34.94% $98,788 SECI 864 2.41% 124,378,127 9.84% $143,874 WFEC 1,280 3.56% 58,216,813 4.61% $45,479 WR 4,043 11.25% 205,438,245 16.26% $50,809

4th Largest Total Cost Largest Cost/MWRanked 10th

Transmission Build Vs. Generation Build

11

Cost Allocation Number of Projects Cost

BW 25 $ 185,638,996

HW 10 $ 328,463,780

Upgrades in the Sunflower Zone – RCARII Project ListWith 2,471 MW of Wind

12

Deman

d in M

W

ATRR

in Dollars

556 617716

1,732 1,732 1,732 1,732

2,471

2,791

3,491

1,0291,118 1,143 1,156 1,147 1,114 1,101 1,142 1,123 1,155

$0

$2

$5 $5

$13

$19

$22

$27

$29

$40

$19

$22

$25$27

$39

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Millions

Schedule 11 ATRR vs MW Wind Installed vs Combined Sunflower/MKEC Load

MW of Wind SEPC/MKEC Combined Load Sched. 11 ATRR + Z2 Sched. 11 ATRR

What Has Been Happening in the Sunflower Zone?

Wind Generation in The Sunflower Zone

13

0

200

400

600

800

1,000

1,200

1,400

Janu

ary

Februa

ry

March

April

May

June July

Augu

st

Septem

ber

Octob

er

Nov

embe

r

Decembe

r

SystemLoad

WindGeneration

Wind Generation for 2016

Average for 20162016 Wind in MW Load in MW Penetration

January ‐ March 667 605 110.25%April ‐ May 613 586 104.61%

June ‐ August 499 804 62.06%September ‐ December 621 627 99.04%

Average 600 655.5 93.99%Max Penetration on Hourly Basis 253%

Projected Wind Generation for 2019 in the Sunflower Zone

14

0

200

400

600

800

1,000

1,200

1,400

Janu

ary

Februa

ry

March

April

May

June July

Augu

st

Septem

ber

Octob

er

Nov

embe

r

Decembe

r

SystemLoad

2018 Wind

Projected Wind Generation for 2019Approximately 50% more Wind connected in 2019 vs 2016 (1,233 MW IA Pending & Facility Study)

Expected Average for 20192019 Wind in MW Load in MW Penetration

January ‐ March 1019 605 168.46%April ‐ May 936 586 159.84%June ‐ August 762 804 94.83%

September ‐ December 948 627 151.34%Average 916.8 655.5 139.86%

2016 Wind Integration Study January 5, 2016

$114M of new Byway investment to enable SPP wind penetration of 45%, 60%

Transfer Impacts on Highway vs. BywaySummer Peak

• 756 Unique Transfers Modeled (each transfer is 1,000 MW between two zones across all SPP footprint)• Each transfer will flow on the Highway and Byway transmission facilities in each zone.• Example: AEP Zone: 22.8% of all the flows impacted Highway Facilities, 14.2 % of the Flows impacted the Byway

22.8%

11.0%

29.5%

6.6%7.8%

26.7%

30.9%

14.2%

2.8%

10.8%

19.2%

8.9%

29.0%

4.6%

14.2%

5.5%

17.9%

2.6%

16.1%

21.4%

11.7%

7.0%6.1%

15.3%

17.2%

20.5%

26.3%

8.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

AEP GRDA KCPL LES MIDW NPPD OGE OPPD SPRM SPS SECI WAPA WR WFEC

Highway Avg. Flows Byway Avg. Flows

Average Flow on the Byway vs Total Flows in ZoneSummer Peak

38.40%

33.30%

37.80%

28.30%

67.40%

44.50%

27.50%

33.00%

51.30%

58.60%

47.30%

69.70%

47.50%

63.40%

0%

10%

20%

30%

40%

50%

60%

70%

80%

AEP GRDA KCPL LES MIDW NPPD OKGE OPPD SPRM SPS SECI WAPA WR WFEC

Average 46.29%

17

Wind Exp. Entities: MIDW, WFEC, SECI

Case History & Analysis: Sunflower Electric• Benefit/Cost Ratio is dependent on energy prices

o Currently lower energy prices due to trapped generationo Recent SPP studies show that long term, those benefits are projected to be

relatively smallo Energy Benefits are only one ITP study away from being half as big. i.e. The Potter-Tolk 345 kV line

18

19

2014 Report RCAR IMKEC 1.27

SEPC 0.3

RCAR Analysis is not capturing the issues• Largest Benefits are the APC and Assumed Reliability Benefits• APC Savings from Congestion keeping the energy costs low in the MKEC and SEPC Zones• Elimination of Congestion: Good for the Region, but will reduce the APC saving for Zones like Sunflower• Transmission Projects are mostly caused to solve issues from the many Windfarms in the Sunflower Zone• All reliability projects are assumed to have B/C ratio of 1, can give a false indication of “Benefits” from Reliability

Projects

$60

$83

$1.28

$3.73

What is in the Tariff?• Tariff has a limited “Wind protection” rule in the HWBW cost allocation

o Only applies to upgrades from the Aggregate Study Process (i.e. Designated Resources)

o Upgrades in Zones where the Load is NOT located 2/3 of upgrade costs Regionally allocated 1/3 of upgrade cost is direct assigned to Customer

o Does not cover any other renewable resources (i.e. Solar)• Generation Interconnections

o All costs are direct assigned to the GI customero Does not cover all the upgrades required to deliver power to the Market

• All Customers with Direct Assigned Costs are eligible for Z2 creditso Over 90% of Z2 credits are uplifted to general rates Any Z2 credits for Byway Projects do NOT receive the Wind Protection

• ITP Upgradeso All costs are HWBW allocatedo No protection if transmission upgrades are indicated due to additional Generation

20

What is The Solution?• Four Possible solutions:• Option 1: Do Nothing

o Pros: Easy to doo Cons: Inflicts cost on Zones in SPP that are not seeing the Benefits from the Construction Having Zones that will fail the RCAR review in the future as the RCAR looks backward not forward on

transmission investments

• Option 2: Modify the Current HWBW – Expand the Wind Protections

• Option 3: Modify the Percent Allocations of the Byway Projects

• Option 4: Combination of Options 2 and 3

21

Option 2: Add More Generation Protections • All costs related to a transmission upgrade which was paid, all or in part, by an entity

(Sponsored Upgrade) is eligible for Z2 creditso Over 90% of the Z2 Credits that are collected for payment are uplifted to Transmission Rates using

HWBW which means that all costs related to a Byway voltage project can be reasonably assumed to eventually be cost allocated to the host Zone.

• Any Z2 credits for Sponsored Project related to a Generation Interconnection be Regionally Allocatedo Only for Generation that is not a DR for the local load. o Cost allocated for Byway Upgrades related to local DR – Normal HWBW

• Economic Upgrades related to releasing “trapped generation” into the SPP Market be 100% Regionally Allocated

• Pros: o Very targeted changeo Protects the Zonal Customers from costs of upgrades that do not benefit themo Allocates Costs to the Customers that get the benefits, i.e. the entire SPP Market Assumes these upgrades are required to deliver the cheaper energy from the IPPs to Load outside the host Zone

• Cons:o Does increase the regional costs paid by all loado Need to be able to define which upgrades qualify for the Regional cost allocation

22

Option 3: Changing the Percentage Byway Cost AllocationConclusions

• Use of the Byway System is greater than ever• Model flows indicate that the Byway is supporting more regional flows• A change in the regional vs Zonal costs is needed• Recommend a change from 33% Regional, 67% Zonal to a new

allocation based upon an updated flow analysis (example: 50% Regional, 50% Zonal as indicated by the Sunflower Analysis)

• Pros:o Allocates costs to those customers getting benefitso Reflects today’s reality related to what is driving the building of byway facilitieso Minimal Tariff changes to Implement

• Cons:o Additional model runs by SPP Staff to confirm the analysiso Does shift some costs from a Zone to the Region

23

Option 4: Combine Option 2 and 3 (Preferred)• Makes sense to provide the additional protections to those Zones that

are receiving a disproportionate number of generation interconnections under Option 2o The current Tariff has several significant “holes” that can inappropriately over

allocate costs to a Zoneo Properly allocated the cost of any Z2 credit payments to those customers benefiting

from the upgrade• Make the change in percentage allocation as supported in Option 3 to

reflect the current reality of how the byway facilities are being used

24

Conclusions

• Sunflower believes that Option 4 is the correct strategyo Change the Tariff to stop the inadvertent allocation of costs of

upgrades to the host Zonal customerso Sunflower is proposing to change the cost allocation to match or be

close to the usage of the HWBW transmission system. o Future projects should be changed to reflect a new zonal allocation

• Sunflower supports wind and solar development projects and only wants to be sure all SPP Customers are paying the proper costs for transmission upgrades being built.

25

ITP UpdateLanny Nickell

January 29, 2018

1

Included Topics• 2018 Integrated Transmission Planning –

Near-Term Assessment (ITPNT) Update

• 2019 Integrated Transmission Planning (ITP) Update

• 2018 SPP Transmission Expansion Plan (STEP)

2

2018 ITPNT Update

3

2018 ITPNT Timeline

4

Model Summary

5

55,017

54,225

53,683

52,832

55,837

54,744

54,052

53,401

58,561

56,795

55,169

54,646

49,000

50,000

51,000

52,000

53,000

54,000

55,000

56,000

57,000

58,000

59,000

2015 ITPNT 2016 ITPNT 2017 ITPNT 2018 ITPNT

SPP ITPNT Load Trends

Year-1 Year-2 Year-5

6

7

6799

137

591

0

100

200

300

400

500

600

700

Thermal Voltage

NU

MB

ER

OF

NE

ED

S2017 ITPNT Posted Needs vs 2018 ITPNT

Preliminary Needs

2018 ITPNT 2017 ITPNT

2019 ITP Update

8

2019 ITP Scope• The objective of the 2019 ITP Assessment is to

develop a regional transmission plan that provides reliable and economic delivery of energy and facilitates achievement of public policy objectives, while maximizing benefits to the end-use customer The 2019 ITP Scope contains assumptions to be

utilized in the 2019 ITP Assessment that are not standardized in the ITP Manual

• The 2019 Scope was approved by ESWG and TWG on January 4

• MOPC approved January 16

• Board approval requested January 30

9

2019 ITP Futures• Future 1: Reference Case

• Future 2: Emerging Technologies

10

Key Assumptions Reference Emerging Case Technologies

Year 2 Year 5 Year 10 Year 5 Year 10Energy Demand Growth

RatesAs submitted in load

forecastAs submitted in load

forecastIncrease due to electric

vehicle growth

Fossil Fuel RetirementsAge-based 60+,

subject to stakeholder input

Age-based 60+, subject to stakeholder input Age-based, 60+

Distributed Generation (Solar)

As submitted in load forecast

As submitted in load forecast +300MW +500MW

Solar (GW) ~0.25+ 3 5 4 7

Wind (GW) ~18+ 25 26 29 32

Drivers

Total Renewable Capacity

11

2018 STEP

12

STEP Components

13

Projects Completed in 2017

14

• 36 upgrades ‐ $246 M

– 19 Integrated Transmission Planning ‐ $163.9 M

– 3 Transmission Service ‐ $26.6 M

– 13 Generator Interconnection ‐ $43.4 M

– 1 High Priority ‐ $11.7 M

New or Modified NTCs Issued in 2017

• 71 projects ‐ $263.2 M

– $0.11 M for Generator Interconnection

– $28.7 M for High Priority

– $140.9 M for Transmission Service

– $93.5 M for Integrated Transmission Planning

15

16

2018 STEP NTC Cost by Project Type – $2.6 B

17

Integrated Marketplace Operational UpdateBruce Rew, PE

Vice President, Operations

1

2

SPP Integrated Marketplace Update • Marketplace Highlights Over Last 12 Months

• Marketplace Statistical Information

• Marketplace Wind Highlights and Records

• Enhancements implemented and under development

• New Winter Peak set on December 19 with a peak of 40,322 MW

• No significant winter ice/snow storms, but very low temperatures in the last week of December (and first two weeks of January) did drive high system demand, higher gas prices, and increased generation outages. New winter peaks set in January

• Total of 17,530 MW of installed and operational wind capacity to date As of January 9th, there is approximately 75 MW of wind

registered, but not yet operational

• New wind generation peak (15,690 MW) and wind penetration (56.25%) peaks in the first half of December.

• 21 of 92 days in October – December (23% of days) had average wind power output over 10 GW.

3

Q4 Marketplace Operational Highlights

Marketplace Over Last 12 Months

• 211 Market Participants 141 financial only and 70 asset owning

• SPP BA has successfully maintained NERC control performance standards (BAAL & CPS)

• High System availability Day-Ahead Market results have posted late four times in the last

12 months 3 due to oracle upgrade; one due to difficult solution

Real-Time Balancing Market has successfully solved 99.92% of all intervals

4

5

Dispatch by Fuel Type

6

Fuel on the Margin in RT

7

Real-Time versus DA pricing

• SPP set a new historical maximum wind output of 15,690 MW on 12/15/2017 at 20:51 Previous wind max output was 14,150 MW on 12/4/2017 @ 21:55

• SPP Load at time of 12/15 peak was 30,956 MW

• Generation Mix at Peak:

8

Wind Peaks in December

Fuel Type Generation Penetration PerFuel Type

Wind 15,690 MW 50.69%

Coal 9,847 MW 31.81%

Gas 3,689 MW 11.92%

Nuclear 2,045 MW 6.61%

Hydro 970 MW 3.13%

Other 49 MW 0.16%

Wind Output: October - December 2017

@ Max Wind Output

@ Min Wind Output

MW Wind 15,690 MW 638 MW

Time 12/15 @ 22:00 12/2 @11:15

SPP Load 30,956 MW 26,470 MW

Appx Gen Mix

Coal 26% 63%

Wind 49% 2%

Nat. Gas 11% 22%

Nuclear 6% 8%

Hydro 3% 5%

9

Wind Penetration: October - December 2017

Max Penetration

Min Penetration

Wind Penetration

56.25% of load 2.4% of load

Time 12/4 @05:20 12/2 @11:15

SPP Load 23,591 MW 26,470 MW

Wind Output 13,270 MW 638 MW

Appx Gen Mix

Coal 27% 63%

Wind 51% 2%

Nat. Gas 11% 22%

Nuclear 8% 8%

Hydro 2% 5%

10

October - December 2017

11

Min and Max Percent of Generation Mix Per Fuel Type – Q4 2017

12

66.9

52.9

37.1

9.86.3

24.5

2.4

7.35.2

1.1

43.7

27.6

17.5

7.3

3.50.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

Coal Wind Natural Gas Nuclear Hydro

Perc

ent

Fuel Type

-…

Min and Max Percent of Generation Mix Per Fuel Type - 2017

13

70.3

52.9

44.8

10.08.2

20.1

0.5

6.03.6

0.7

46.1

23.4

18.9

7.04.1

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

Coal Wind Natural Gas Nuclear Hydro

Perc

ent

Fuel Type

-…

Recently Implemented:

• RR242 – Regulation Deployment Priority Change

On The Way:

• RR243 – Mitigated Energy Offer for Regulation Deployment Adjustment Settlements Estimated Implementation Q2 2018

• Other MP and SPP requested enhancements

Future:

• RR229 - Order No. 831 Compliance (Offer Caps)

• Quick Start Real-Time Commitment design enhancements

Integrated Marketplace Enhancements

14

RARTF UpdateJanuary 2018 RSC Meeting

Dennis Grennan, RARTF Chair

1

RARTF Update

2

RARTF Update - Membership

• Dennis Grennan (NPRB) appointed Chair of RARTF on January 1, 2018 Steve Stoll term on the Missouri PSC ended December 13, 2017

• Phil Crissup (OG&E) resigned his RARTF seat effective December 31, 2017

• RARTF Charter states:“The RSC and SPP Members representatives shall be appointed by the RSC President and MOPC Chairman and shall represent diverse members.”

• Next Steps: RSC President Shari Albrecht and MOPC Chair Paul Malone will

appoint one RSC member and one MOPC member to the RARTF.3

RARTF UPdate

• The RARTF has met twice since the October RSC Meeting: December 8, 2017 Conference Call Webex January 15, 2018 - Dallas Texas

• Major Topics of Discussion: SPP/AECI Seams Remedy Project RCAR Frequency Filing at FERC RCAR III Options

4

RARTF Update – SPP/AECI Seams Projects

• Brookline Reactor Project Addition of a 50 MVAR Reactor at City Utilities Brookline 345 kV substation Wholly on SPP’s Transmission System $5M Cost Estimate SPP Responsible for $4.85M (97%)

• This project is being evaluated in the 2018 ITP Near Term; July 2018 If approved in the planning process; no further FERC filing is necessary.

5

RARTF Update – SPP/AECI Seams Projects• Morgan Transformer Project Addition of a new 400 MVA 345/161 kV Transformer at AECI’s Morgan substation and

an uprate of the 161 kV line between Morgan and Brookline Wholly on AECI’s Transmission System $13.75M Cost Estimate

SPP Responsible for $12.25M (89%)

• Staff visited with FERC January 10, 2018 regarding this project Staff believes another filing at FERC to establish cost allocation for this project is

warranted. Staff will provide additional justification Staff determining timing on the next filing

• RARTF Motion: The RARTF supports SPP refiling the Morgan Transformer seams project with FERC seeking approval. The RARTF notes the benefits the Morgan Transformer would have for improving RCAR benefits for the region. 6

RARTF Update – RCAR Frequency

Attachment J Section III. Base Plan Upgrades

D. Review of Base Plan Allocation Methodology

1. The Transmission Provider shall review the reasonableness of theregional allocation methodology and factors (X% and Y%) and thezonal allocation methodology at least once every six three years inaccordance with this Section III.D. The Transmission Provider and/orthe Regional State Committee may initiate such review at any time. Anychange in the regional allocation methodology and factors or the zonalallocation methodology shall be filed with the Commission.

7

RARTF Update – RCAR Frequency• 2/17/17 – RARTF voted unanimously to recommend the RCAR analysis move to a six

year cycle.

• 3/23/17 – RTWG tabled vote on RR-223 pending RSC and MOPC policy decision

• 4/4/17 – CAWG reviewed and took no action on RR-223

• 4/11/17 – MOPC approved policy and language for RR-223

• 4/17/17 – RSC approved policy for RR-223

• 4/18/17 – RTWG approved tariff language for RR-223

• 4/25/17 – BOD approved RR-223

• 8/02/17 – Tariff Language filed at FERC (ER17-2229) Comment period ended 8/23/2017 One protest: Sunflower/Mid-Kansas

• 9/29/17 – FERC Order Accepting Tariff Revisions

• 10/30/17 – Request for Rehearing – Sunflower/MKEC

• 11/29/17 – FERC issued “Tolling Order” on Request for Rehearing8

RARTF Update – RCAR III Options• Staff has provided 4 options to the RARTF for consideration:

1. Planning Based (Status Quo)2. Operations Based3. Operations Based (Historical Only)4. Hybrid (Operations/Planning Based)

• Staff was directed to provide more analysis in the January 15 meeting Staff provided results of a “limited proof of concept” using the market engine to

provide Adjusted Production Cost savings Staff comfortable that this process is feasible

• Next Steps – April 4, 2018 Conference Call Strawman Proposal: Option 4 Hybrid (Operations/Planning Based) to include: Cost and Schedule Stakeholder Group involvement Inclusion of RCAR II Lessons Learned

9

SPP-AECI Joint Projects

1

Morgan Transformer Project

• Addition of a new 400 MVA 345/161 kV Transformer at AECI’s Morgan substation and an uprate of the 161 kV line between Morgan and Brookline• Located in southwest

Missouri• Wholly on AECI’s

transmission system• $13.75M Cost Estimate

2

Brookline Reactor Project

3

• Addition of a 50 MVAR Reactor at City Utilities Brookline 345 kV substation • Located in southwest

Missouri• Wholly on SPP’s

transmission system• $5.0M Study-level Cost

Estimate

Approvals • SPP Board of Directors Approved the Morgan Transformer Project as a part of the 2017 SPP

ITP10 Portfolio Approved Regional Cost Allocation of the Morgan Transformer

Project Approved the Brookline Reactor Project out of the Regional Review

of the SPP-AECI JCSP

• Regional State Committee Approved Regional Cost Allocation of the Morgan Transformer

Project

• AECI Board of Directors Met on May 24th, 2017 to approve AECI’s participation in both the


4

2016 SPP-AECI Joint Projects• SPP and AECI agreed to two joint projects out of the 2016

SPP-AECI Joint and Coordinated System Plan (JCSP)

• Morgan Transformer Project Addition of a new 400 MVA 345/161 kV Transformer at AECI’s

Morgan substation and an uprate of the 161 kV line between Morgan and Brookline

Wholly on AECI’s Transmission System $13.75M Cost Estimate SPP Responsible for $12.25M (89%)

• Brookline Reactor Project Addition of a 50 MVAR Reactor at City Utilities Brookline 345 kV

substation Wholly on SPP’s Transmission System $5M Cost Estimate SPP Responsible for $4.85M (97%)

5

FERC Filings for Joint Projects with AECI • SPP made filings at FERC for the two projects on August 7,

2017 Approval of SPP-AECI Joint Projects Cost Sharing between SPP and AECI SPP Regional Cost Allocation of both projects Other Issues Related to the Treatment of the Projects Docket Numbers ER17-2256 & ER17-2257

• Comments received in support of the filing City Utilities, AECI, Missouri PSC, Southwestern Power

Administration & South Central MCN

• Comments received in protest of the filing Xcel & Westar

6

Summary of FERC’s Order• FERC issued an order rejecting SPP’s filing on October 6, 2017

• The Commission rejected SPP’s proposal for region-wide / load-ratio share funding for SPP’s portion of the costs for the two joint projects “SPP has not shown that the proposed cost allocation for these specific non-Order No.

1000 projects, and the allocation of SPP’s share of the costs of these projects on a region-wide, load-ratio share basis, is roughly commensurate with the projects’ benefits…”

• The order did not preclude SPP from making additional filings to the Commission to support region-wide funding or propose a new cost allocation for the two joint projects “Our rejection of SPP’s proposal in these dockets does not preclude SPP from making

a filing with the Commission demonstrating that the Morgan Transformer Project and Brookline Reactor Project provide regional benefits or proposing an alternative allocation of its share of the costs of these transmission projects that is roughly commensurate with the benefits”

7

Next Steps

• SPP staff is continuing to review the Commission’s order and determining the best path forward for the two joint projects with AECI

• SPP staff is continuing to work on the best path forward for Non Order 1000 Joint Projects

8

Next Steps – Brookline Reactor• Being Studied in current

ITP

• Estimated Decision July 2018

• If approved: Highway Funding

• Per SPP’s Tariff no FERC Filing

9

Next Steps – Morgan Transformer Project • SPP’s tariff has no

method to cost allocate this project

• Requires a FERC filings

• SPP Stakeholder’s (RSC supports Highway Funding

• Seeking FERC Advice

10

FIRST QUARTERLY

PROJECT TRACKING

REPORT 2018 January 2018

Southwest Power Pool, Inc.

CONTENTS

Executive Summary ................................................................................................................................................................ 3

NTC Project Summary ........................................................................................................................................................... 5

NTC Issuance................................................................................................................................................................................................ 7

NTC Withdraw ............................................................................................................................................................................................. 7

Completed Projects ................................................................................................................................................................................... 8

Project status summary ........................................................................................................................................................................ 10

Out-of-Bandwidth Projects ................................................................................................................................................ 11

Responsiveness Report ....................................................................................................................................................... 12

Appendix 1 ............................................................................................................................................................................... 14


Q1 2018 Project Tracking Report 3

EXECUTIVE SUMMARY

SPP actively monitors and supports the progress of transmission expansion projects, emphasizing

the importance of maintaining accountability for areas such as regional grid reliability standards,

firm transmission commitments, and Tariff cost recovery.

SPP staff solicits quarterly feedback from the project owners to determine the progress of each

approved transmission project. This quarterly report charts the progress of all SPP Transmission

Expansion Plan (STEP) projects approved by the SPP Board of Directors (Board) or through a FERC

filed service agreement under the SPP Open Access Transmission Tariff (OATT).

The reporting period is August 1, 2017 through October 31, 2017. Table 1 provides a summary of

all projects in the current Project Tracking Portfolio (PTP), which includes all Network Upgrades in

which construction activities are ongoing, or construction has completed but not all the close-out

requirements have been fulfilled in accordance with Section 13 of Business Practice 7060. The PTP

includes all active Network Upgrades including transmission lines, transformers, substations, and

devices.

Table 1 below summarizes the PTP for this quarter. Figures 1 reflects the percentage cost of each

upgrade type in the PTP. Figure 2 shows the percentage cost of each project status in the PTP.

Upgrade Type No. of

Upgrades Estimated Cost

Miles of New

Miles of Rebuild

Miles of Voltage

Conversion

Economic 23 $74,829,382 1.9 0.0 28.8

High Priority 61 $1,114,960,503 757.7 5.1 0.0

Regional Reliability 351 $3,214,044,137 1598.4 423.6 457.1

Transmission Service 18 $100,495,428 12.9 15.3 0.0

Zonal Reliability 8 $138,128,100 28.0 26.9 0.0

NTC Projects Subtotal 461 $4,642,457,550 2399.0 470.9 485.9

Generation Interconnection 84 $256,476,756 0.0 0.0 0.0

Regional Reliability - Non OATT 1 $7,107,090 0.0 0.0 0.0

TO - Sponsored 3 $16,719,000 10.7 0.0 0.0

Non-NTC Projects Subtotal 88 $280,302,846 10.7 0.0 0.0

Total 549 $4,922,760,396 2409.7 470.9 485.9

Table 1: Q1 2018 Portfolio Summary



Figure 1: Percentage of Project Type on Cost Basis

Figure 2: Percentage of Project Status on Cost Basis

1.5%

5%

23%

66%

2%

3%

Economic

Generation Interconnection

High Priority

Regional Reliability

Transmission Service

Zonal Reliability

3%

40%

24%

0%

31%

0% 1% 1%

Closed Out

Complete

On Schedule < 4

On Schedule > 4

Delay - Mitigation

Suspended

NTC - Commitment Window

Re-evaluation



NTC PROJECT SUMMARY

In adherence to the OATT and Business Practice 7060, SPP issues Notifications to Construct (NTCs)

to Designated Transmission Owners (DTOs) to begin work on Network Upgrades that have been

approved or endorsed by the SPP Board to meet the construction needs of the STEP, OATT, or

Regional Transmission Organization (RTO).

Figure 3 reflects project status within each source study, and Table 2 provides the supporting data.

Figure 4 shows the amount of estimated cost by in-service year for all Network Upgrades that have

been issued an NTC or Notifications to Construct with Conditions (NTC-C). Note: Figures 3 and 4,

and Table 2 provide data for all projects for which SPP has issued an NTC or NTC-C,

regardless of completion date, and therefore include data from Network Upgrades no longer

included in PTP.

Figure 3: Project Status by NTC Source Study

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400On Schedule

Suspended

Delayed

Complete

$ M

illi

on



Source Study Complete Delayed Suspended On Schedule Total

2006 STEP $202,493,500 $0 $0 $0 $202,493,500 2007 STEP $498,368,218 $393,563 $0 $0 $498,761,781 2008 STEP $415,126,157 $0 $0 $0 $415,126,157 Balanced Portfolio $834,720,484 $0 $0 $0 $834,720,484 2009 STEP $533,469,214 $1,441,050 $0 $0 $534,910,264 Priority Projects $1,348,761,003 $0 $0 $0 $1,348,761,003 2010 STEP $109,968,782 $4,041,273 $0 $0 $114,010,055 2012 ITPNT $182,110,561 $4,294,271 $0 $0 $186,404,832 2012 ITP10 $105,901,240 $342,148,981 $0 $295,933,246 $743,983,467 2013 ITPNT $333,999,035 $130,387,317 $0 $33,289,587 $497,675,939 2014 ITPNT $257,913,185 $271,353,382 $0 $53,073,689 $582,340,256 HPILS $214,658,160 $157,726,337 $0 $285,465,421 $657,849,918 2015 ITPNT $88,084,589 $119,077,120 $0 $7,342,119 $214,503,828 2015 ITP10 $0 $0 $0 $50,553,697 $50,553,697 IS Integration Study $223,284,902 $38,000,000 $0 $111,000,000 $372,284,902 2016 ITPNT $79,924,328 $428,831,040 $0 $14,675,075 $523,430,443 2017 ITP10 $0 $13,975,764 $0 $0 $13,975,764 2017 ITPNT $0 $0 $0 $17,077,427 $17,077,427 Ag Studies $715,580,900 $100,245,986 $0 $85,871,775 $901,698,661 DPA Studies $180,276,593 $15,339,894 $0 $7,282,123 $202,898,610 GI Studies $629,412,971 $10,273,744 $0 $177,706,865 $817,393,580

Total $6,954,053,822 $1,637,529,722 $0 $1,139,271,022 $9,730,854,566

Table 2: Project Status by NTC Source Study

Figure 4: Estimated Cost for NTC Project per In-Service Year

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

New Q1 2018 NTC

Modified Q1 2018 NTC

Previous NTC

$ M

illi

on



NTC ISSUANCE Three new NTCs were issued in the reporting period totaling an estimated $31.2 million.

One new NTCs were issued as a result of the Board’s approval of the 2017 Integrated Transmission

Planning Near-Term Assessment (ITPNT). Total estimated cost of upgrades described in that NTCs

are $21.8 million.

One new NTC was issued as a result of Aggregate Study 2016-AG2-AFS-2. Total estimated costs for

upgrades resulting from this NTC are $9.2 million.

One NTC was issued resulting from Generation Interconnection study GEN-2015-016. Total

estimated cost of the Network Upgrades are $110 thousand.

NTC ID Owner NTC Issue

Date Upgrade Type

Source Study

No. of Upgrades

Estimated Cost of

New Upgrades

Estimated Cost of

Previously Approved Upgrades

200462 CPEC 8/2/2017 Regional

Reliability 2017 ITPNT 2 $21,780,000

200463 WR 8/16/2017 Generation

Interconnection GEN-2015-

016 1 $110,000

200466 WR 9/21/2017 Regional

Reliability 2016-AG2-

AFS-2 4 $9,260,540

Total 7 $9,370,540 $21,780,000

Table 3: NTC Issuance Summary

NTC WITHDRAW One NTC was withdrawn for one Network Upgrade during the reporting period, totaling an

estimated $145.8 thousand. The NTC for this upgrade was issued out of Aggregate Study 2015-

AG1-AFS-6 and is no longer needed.

Table 4 lists the NTC Withdraw activity during the reporting period. NTC ID values in bold font

indicate NTC-Cs.

NTC ID Owner NTC

Withdraw Date

Upgrade Type Source Study No. of

Upgrades

Estimated Cost of Withdrawn

Upgrades

200464 WR 9/21/2017 Transmission

Service SPP-2015-AG1-

AFS-6 1 $145,773

Total 1 $145,773

Table 4: NTC Withdraw Summary



COMPLETED PROJECTS Six Network Upgrades with NTCs were verified as completed during the reporting period, totaling an estimated $39.4 million.

Table 5 lists the Network Upgrades reported and confirmed as completed during the reporting

period. Table 6 summarizes the completed projects over the previous year, including Network

Upgrades not yet confirmed as completed. Figure 5 reflects the completed projects by upgrade type

on a cost basis for the current year and the following year based on current projected in-service

dates. Tables 7 and 8 summarize all Network Upgrades that include construction of transmission

lines, both for the current year and the following year. Note: Previous quarter’s updated results

are listed as the Transmission Owners may make adjustments to final costs and status of

projects completed during the year.

UID Network Upgrade Name Owner NTC Source

Study Cost Estimate

50608 Bobcat Canyon 345/115 kV Transformer Ckt 1 NPPD 2014 ITPNT $5,928,480

50609 Bobcat Canyon - Scottsbluff 115 kV Ckt 1 NPPD 2014 ITPNT $23,700,242

50616 Bobcat Canyon 345 kV Terminal Upgrades NPPD 2014 ITPNT $4,072,936

51474 Minco 345kV Substation GEN-2014-056 Addition

(TOIF) OGE GI Studies $5,000

51509 Berthold - Southwest Minot 115 kV Ckt 1

Reconductor BEPC 2016 ITPNT $2,876,720

71925 Tap Coyote-Medford Tap 138kV - GEN-2015-015

Addition (NU) OGE GI Studies $2,840,000

Total $39,423,378

Table 5: Completed Network Upgrades as of Q4 2017

Upgrade Type Q1 2017 Q2 2017 Q3 2017 Q4 2017 Total

Regional Reliability 9 16 13 11 49

Regional Reliability $98,767,760 $112,710,788 $42,899,461 $157,568,378 $411,946,387

Transmission Service 0 1 0 0 1

Transmission Service $0 $228,364 $0 $0 $228,364

Balanced Portfolio 0 0 0 0 0

Balanced Portfolio $0 $0 $0 $0 $0

High Priority 8 0 5 0 13

High Priority $523,778,049 $0 $36,074,471 $0 $559,852,520

Economic 0 0 0 0 0

Economic $0 $0 $0 $0 $0

Zonal Reliability 0 0 0 0 0

Zonal Reliability $0 $0 $0 $0 $0

Generation Interconnection 11 8 11 14 44

Generation Interconnection $28,039,697 $14,242,460 $38,872,518 $39,126,045 $120,280,720

Table 6: Completed Project Summary as of Q4 2017



Figure 5: Completed Upgrades by Type per Quarter

Voltage Class

Number of Upgrades New

Rebuild/ Reconductor

Voltage Conversion Estimated Cost

69 6 7.9 30.4 69.0 $47,667,540 115 12 67.8 42.6 0.0 $91,410,897 138 3 27.5 16.5 138.0 $33,750,509 161 1 0.0 11.1 0.0 $12,705,537 230 2 32.0 0.0 0.0 $44,100,000 345 6 377.7 0.0 0.0 $633,456,253

Total 30 512.9 100.7 207.0 $863,090,736

Table 7: Line Upgrade Summary for Previous 12 Months

Voltage Class

Number of Upgrades New

Rebuild/ Reconductor

Voltage Conversion Estimated Cost

69 9 3.9 40.0 69.0 $64,345,742 115 20 149.7 29.9 13.0 $151,493,161 138 11 110.0 2.4 0.0 $102,067,394 161 1 17.0 0.0 0.0 $29,069,150 230 2 18.8 0.0 0.0 $31,270,623 345 12 329.5 0.0 28.8 $408,278,114

Total 55 628.9 72.3 110.8 $786,524,183

Table 8: Line Upgrade Projections for Next 12 Months

$0.0

$100.0

$200.0

$300.0

$400.0

$500.0

$600.0

$700.0

$800.0

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018Projected

Q2 2018Projected

Q3 2018Projected

Q4 2018Projected

Generation Interconnection

Zonal Reliability

Economic

High Priority

Transmission Service

Regional Reliability

$ M

illi

on



PROJECT STATUS SUMMARY SPP assigns a project status to all Network Upgrades based on the projected in-service dates

provided by the DTOs relative to the Need Date determined for the project. Project status

definitions are provided below:

Complete: Construction complete and in-service Closed Out: Construction complete and in-service; all close-out requirements fulfilled On Schedule < 4: On Schedule within 4-year horizon On Schedule > 4: On Schedule beyond 4-year horizon Delayed: Projected In-Service Date beyond Need Date; interim mitigation provided or

project may change but time permits the implementation of project Within NTC Commitment Window: NTC/NTC-C issued, still within the 90-day written

commitment to construct window and no commitment received Within NTC-C Project Estimate Window: Within the NTC-C Project Estimate (CPE)

window Within RFP Response Window: RFP issued for the project Re-evaluation: Project active; pending re-evaluation

Suspended: Project suspended; pending re-evaluation

Figure 6 reflects a summary of project status by upgrade type on a cost basis.

Figure 6: Project Status Summary on a Cost Basis

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

RegionalReliability

TransmissionService

High Priority Economic GenerationInterconnection

Suspended

Re-evaluation

Within RFP Response Window

Within NTC-C Project Estimate Window

Within NTC Commitment Window

Delayed

On Schedule > 4

On Schedule < 4

Complete

Closed Out

$ M

illi

on



OUT-OF-BANDWIDTH PROJECTS

In adherence to the Business Practice 7060, SPP reports projects that have updated cost values that exceed their established baseline values based upon a ±20% bandwidth. Variances are determined

by total project cost.

Seven projects with a cost estimate greater than $5 million were identified as having exceeded the ±20% bandwidth requirement during the reporting period.

Table 9 provides summary information and Table 10 lists cost detail for out-of-bandwidth projects

for Q4 2017.

PID Project Name Owner NTC Source

Study Upgrade Type

In-Service Date

30596 Multi - Broken Bow Wind - Ord 115 kV Ckt 1

NPPD 2014 ITPNT Regional

Reliability 6/1/2018

30637 Multi - Hobbs - Kiowa 345 kV Ckt 1

SPS HPILS High Priority 4/30/2018

30817 Line - Canyon West - Dawn - Panda - Deaf Smith 115 kV Ckt 1 Rebuild

SPS 2016 ITPNT Regional


1001 Line - Randall - South Georgia and Osage Station 115 kV Line Re-termination

SPS Ag Studies Regional


30694 Multi - Ponderosa - Ponderosa Tap 115 kV

SPS HPILS High Priority 6/1/2017

30988 Sub - Eddy Co. 230 kV Bus Tie SPS Ag Studies Transmission

Service 11/30/2019

31127 Line - Knoll - Post Rock 230 kV New Line Ckt 2

MIDW 2017 ITP10 Economic 6/1/2019

Table 9: Out-of-Bandwidth Project Summary

PID Baseline

Cost Estimate

Baseline Cost

Estimate Year

Baseline Cost Estimate with

Escalation

Latest Estimate or Final Cost

Variance Variance

%

30596 $34,593,371 2014 $37,253,277 $28,534,673 ($8,718,604) -23.40%

30637 $71,058,482 2014 $76,522,213 $58,767,041 ($17,755,172) -23.20%

30817 $19,159,617 2016 $19,638,607 $12,787,234 ($6,851,373) -34.89%

1001 $10,316,217 2016 $10,574,122 $13,179,208 $2,605,086 24.64%

30694 $13,201,633 2014 $14,216,715 $10,222,364 ($3,994,351) -28.10%

30988 $10,425,309 2016 $10,685,942 $15,929,021 $5,243,079 49.07%

31127 $3,872,285 2017 $3,872,285 $5,400,044 $1,527,759 39.45%

Table 10: Out-of-Bandwidth Project Cost Detail



RESPONSIVENESS REPORT

Table 11 and Figures 7 and 8 provide insight into the responsiveness of DTOs constructing Network

Upgrades within SPP in the Quarterly Project Tracking Report for Q3 2017. Note: Network

Upgrades with statuses of “Suspended”, “Re-evaluation”, “Within NTC Commitment Window”,

“Within NTC-C Project Estimate Window”, and “Within RFP Response Window” were

excluded from this analysis.

Project Owner

Number of

Upgrades

Number of

Upgrades Reviewed

Reviewed %

In-Service

Date Changes

ISD Change

%

Cost Changes

Cost Change

%

AEP 61 61 100% 2 3% 1 2%

BEPC 24 8 33% 0 0% 0 0%

GMO 2 2 100% 1 50% 0 0%

GRDA 10 1 10% 1 10% 0 0%

ITCGP 7 2 29% 2 29% 2 29%

KCPL 8 8 100% 1 13% 0 0%

LES 0 0 0% 0 0% 0 0%

MIDW 11 11 100% 0 0% 3 27%

MKEC 7 7 100% 1 14% 7 100%

NPPD 38 20 53% 3 8% 3 8%

OGE 47 5 11% 4 9% 0 0%

OPPD 14 14 100% 0 0% 0 0%

SPS 185 183 99% 35 19% 49 26%

TSMO 7 7 100% 0 0% 1 14%

WFEC 29 1 3% 0 0% 8 28%

WR 38 37 97% 4 11% 6 16%

Total 501 379 76% 55 11% 87 17%

Table 11: Responsiveness Summary by Project Owner



Figure 7: In-Service Date Changes by Project Owner

Figure 8: Cost Changes by Project Owner

0

20

40

60

80

100

120

140

160

180

200

In-Service Date Changes

0

20

40

60

80

100

120

140

160

180

200

Cost Changes



APPENDIX 1

{See accompanying list of active Applicable Projects}

COMPLETECLOSED OUT

ON SCHEDULE < 4ON SCHEDULE > 4

NTC‐C PROJECT ESTIMATE WINDOW

DELAY ‐ MITIGATION

SUSPENDEDRE‐EVALUATION

NTC ‐ COMMITMENT WINDOWRFP RESPONSE WINDOW

NTC

_ID

PID

UID

Project Owne

r

State(s)

Project Nam

e

Upg

rade

Nam

e

Project Type

Project Owne

r Indicated In‐

Service Date

RTO Determined

Nee

d Date

Letter of N

otification

to

Construc

t Issue Date

NTC

Sou

rce Stud

y

Baselin

e Co

st Estim

ate

Baselin

e Co

st Estim

ate Ye

ar

Baselin

e Co

st Estim

ate with

Escalation

Curren

t Co

st Estim

ate

Fina

l Cost

Project Status

Voltag

es (k

V)

Num

ber of New

Num

ber of

Rebu

ild/Recon

ductor

Num

ber of Voltage

Co

nversion

20003 138 10176 WFEC OK Line - OGE Woodward - WFEC Woodward 69 kV WOODWARD - WOODWARD 69KV CKT 1 Regional Reliability 5/1/2017 4/1/2009 2/13/2008 2007 STEP $1,050,000 2014 $1,130,735 $1,050,000 $393,563 DELAY ‐ MITIGATION 69 3.519985 140 10179 WFEC OK Line - ACME - W Norman 69 kV ACME - WEST NORMAN 69KV CKT 1 Regional Reliability 8/1/2015 6/1/2008 2/2/2007 2006 STEP $912,000 2014 $982,124 $912,000 $1,033,064 COMPLETE 69 3.8200397 242 10308 WFEC OK Line - Elmore - Paoli 69 kV Rebuild Elmore - Paoli 69 kV Ckt 1 Rebuild Regional Reliability 8/1/2017 6/1/2009 5/17/2016 2016 ITPNT $3,240,000 NTC ‐ COMMITMENT WINDOW 69 10.8200291 319 10413 WR KS Multi - Cowskin - Westlink - Tyler - Hoover 69 kV Cowskin - Westlink 69 kV Ckt 1 Rebuild Regional Reliability 5/22/2015 6/1/2014 8/4/2014 SPP-2012-AG1-AFS-7 $4,151,903 2014 $4,471,145 $4,030,427 $4,030,427 CLOSED OUT 69 2.11200291 319 10414 WR KS Multi - Cowskin - Westlink - Tyler - Hoover 69 kV Tyler - Westlink 69 kV Ckt 1 Rebuild Regional Reliability 12/1/2015 6/1/2014 8/4/2014 SPP-2012-AG1-AFS-7 $5,834,124 2014 $6,282,713 $5,742,378 $5,742,378 CLOSED OUT 69 2.6520003 361 10471 WFEC OK Line - Fletcher - Marlow Jct 69 kV FLETCHER - MARLOW JCT 69KV CKT 1 Regional Reliability 9/25/2015 6/1/2011 2/13/2008 2007 STEP $2,000,000 2014 $2,153,781 $2,000,000 $2,257,877 COMPLETE 69 720003 399 10519 WFEC OK Line - Lindsay - Wallville 69 kV LINDSAY SW - WALLVILLE 69KV CKT 1 Regional Reliability 3/13/2015 6/1/2012 2/13/2008 2007 STEP $1,347,000 2014 $1,450,572 $1,347,000 $1,609,327 COMPLETE 69 4.8520003 402 10522 WFEC OK Multi - Granfield - Cache SW 138 kV GRANDFIELD - INDIAHOMA 138KV CKT 1 Regional Reliability 10/15/2015 6/1/2012 2/13/2008 2007 STEP $1,125,000 2014 $1,211,502 $1,125,000 $5,335,005 COMPLETE 138 320003 402 10523 WFEC OK Multi - Granfield - Cache SW 138 kV CACHE - INDIAHOMA 138KV CKT 1 Regional Reliability 3/31/2015 6/1/2012 2/13/2008 2007 STEP $7,306,000 2014 $7,867,763 $7,306,000 $1,431,400 COMPLETE 138 13.720003 402 10524 WFEC OK Multi - Granfield - Cache SW 138 kV GRANDFIELD 138/69KV TRANSFORMER CKT 1 Regional Reliability 4/1/2016 6/1/2012 2/13/2008 2007 STEP $5,000,000 2014 $5,384,453 $5,000,000 $4,867,365 COMPLETE 138/69200212 412 10538 WR KS Line - 64th - Eastborough 69 kV Rebuild Eastborough - Sixty-Fourth (64th) 69 kV Ckt 1 Regional Reliability 5/29/2015 6/1/2013 2/20/2013 2013 ITPNT $4,104,097 2013 $4,530,155 $5,356,933 $5,356,933 CLOSED OUT 69 2

418 10544 KCPL Sub - Waldron Sub Waldron 161 kV TO - Sponsored 6/1/2021 $2,200,000 ON SCHEDULE > 4 161200216 451 10583 AEP AR Multi - Chamber Springs - Farmington 161 kV Chamber Springs - Farmington REC 161 kV Ckt 1 Regional Reliability 3/28/2017 6/1/2013 2/20/2013 2013 ITPNT $12,705,537 2013 $14,024,536 $12,705,537 COMPLETE 161 11.1200166 461 10597 SPS TX/NM Line - Curry - Bailey 115kV Bailey County Interchange - Curry County Interchange 115 kV Ckt 1 Regional Reliability 9/29/2016 6/1/2012 4/9/2012 2012 ITPNT $35,099,588 2012 $39,711,962 $38,607,163 $38,607,163 COMPLETE 115 41.5200379 468 10604 WR KS Sub - Arkansas City - Paris 69 kV Terminal Upgrades Arkansas City - Paris 69 kV Terminal Upgrades Transmission Service 2/24/2017 6/1/2017 4/5/2016 SPP-2015-AG1-AFS-6 $229,690 2016 $235,432 $228,364 $228,364 COMPLETE 69200216 478 10615 AEP LA Line - Forbing Tap - South Shreveport 69 kV Forbing Tap - South Shreveport 69 kV Ckt 1 Regional Reliability 4/13/2016 6/1/2013 2/20/2013 2013 ITPNT $1,221,505 2013 $1,348,313 $1,221,505 COMPLETE 69 2.3200216 501 10646 AEP TX Line - Evenside - Northwest Henderson 69 kV Evenside - Northwest Henderson 69 kV Ckt 1 Regional Reliability 6/1/2018 6/1/2018 2/20/2013 2013 ITPNT $11,980,465 2013 $13,224,191 $11,980,465 ON SCHEDULE < 4 69 6.4200167 503 10648 AEP TX Line - Diana - Perdue 138 kV Diana - Perdue 138 kV Ckt 1 Regional Reliability 12/31/2014 6/1/2013 4/9/2012 2012 ITPNT $1,004,187 2012 $1,136,145 $1,004,187 COMPLETE 138200216 504 10649 AEP LA Line - Brownlee - North Market 69 kV Brownlee - North Market 69 kV Ckt 1 Regional Reliability 3/22/2017 6/1/2013 2/20/2013 2013 ITPNT $12,424,849 2013 $13,714,708 $16,401,035 COMPLETE 69 4.7200246 512 10657 AEP LA Line - Ellerbe Road - Forbing Tap 69 kV Ckt 1 Ellerbe Road - Forbing T 69 kV Ckt 1 Regional Reliability 4/13/2016 6/1/2014 2/19/2014 2014 ITPNT $8,174,689 2014 $8,803,246 $8,174,689 COMPLETE 69 2

636 10834 TEXLA Line - Chireno-Martinsville 138 kV Chireno 138 kV - Martinsville 138 kV TO - Sponsored 9/1/2019 $8,894,000 ON SCHEDULE < 4 138 10.69717 10954 NPPD Line - Clarks - Central City North 115 kV CEN C N7 - CLARKS 115KV CKT 1 TO - Sponsored 6/1/2020 $5,625,000 ON SCHEDULE < 4 115

20130 764 11007 SPS TX XFR - Happy County 115/69 kV Transformers HAPPY INTERCHANGE 115/69KV TRANSFORMER CKT 1 Regional Reliability 1/8/2016 6/1/2012 2/14/2011 2010 STEP $2,809,520 2014 $3,025,546 $1,518,414 COMPLETE 115/6920130 764 11009 SPS TX XFR - Happy County 115/69 kV Transformers HAPPY INTERCHANGE 115/69KV TRANSFORMER CKT 2 Regional Reliability 3/20/2016 6/1/2012 2/14/2011 2010 STEP $2,812,436 2014 $3,028,686 $1,565,056 COMPLETE 115/69200256 766 11010 SPS TX XFR - Newhart 230/115 kV Ckt 2 Newhart 230/115 kV Ckt 2 Transformer Regional Reliability 12/2/2016 6/1/2015 2/19/2014 2014 ITPNT $6,886,931 2014 $7,416,471 $8,500,000 COMPLETE 230/115200229 772 11017 SPS TX Line - Carlisle - Wolfforth 230 kV Carlisle Interchange - Wolfforth Interchange 230 kV Ckt 1 Regional Reliability 3/27/2018 6/1/2017 9/10/2013 2013 ITPNT $32,429,240 2013 $35,795,813 $30,000,000 DELAY ‐ MITIGATION 230 16.8200381 777 11027 SPS TX Sub - East Plant 115 kV Terminal Upgrade East Plant 115 kV Terminal Upgrade Regional Reliability 6/1/2017 6/1/2017 4/12/2016 SPP-2014-AG1-AFS-6 $5,000 2016 $5,125 $0 DELAY ‐ MITIGATION 115200214 802 11064 SPS NM XFR - Eddy Co. 230/115 kV Transformer Ckt 1 Eddy County Interchange 230/115 kV Transformer Ckt 1 Regional Reliability 3/31/2017 6/1/2016 2/20/2013 2013 ITPNT $4,255,145 2013 $4,696,884 $4,525,790 DELAY ‐ MITIGATION 230/115200190 805 50453 SPS TX Multi - Bowers - Howard 115 kV Ckt 1 Bowers - Howard 115 kV Regional Reliability 2/28/2016 6/1/2013 1/18/2013 DPA-2011-SEPTEMBER-095 $30,851,077 2013 $34,053,816 $30,851,077 $21,906,370 COMPLETE 115 3320084 834 11101 SPS NM Line - Portales - Zodiac 69 kV to 115 kV Conversion PORTALES INTERCHANGE - ZODIAC 115KV CKT 1 Regional Reliability 11/30/2015 6/1/2013 2/8/2010 2009 STEP $6,500,000 2014 $6,999,789 $8,231,332 $8,084,263 COMPLETE 115 3200166 836 11104 SPS TX Sub - Convert Muleshoe East 69 kV to 115 kV Convert Muleshoe 69 kV to 115 kV Regional Reliability 12/18/2015 6/1/2012 4/9/2012 2012 ITPNT $4,673,759 2012 $5,287,929 $1,547,828 $1,631,376 COMPLETE 115 0.3 1.5200214 841 11110 SPS TX XFR - Graham 115/69 kV Ckt 1 Graham Interchange 115/69 kV Transformer Ckt 1 Regional Reliability 12/9/2015 6/1/2014 2/20/2013 2013 ITPNT $2,101,391 2013 $2,319,542 $1,400,000 COMPLETE 115/69200397 844 11113 WFEC OK Line - Sara Road - Sunshine Canyon 69 kV Ckt 1 Rebuild Sara Road - Sunshine Canyon 69 kV Ckt 1 Rebuild Regional Reliability 4/1/2018 6/1/2020 5/17/2016 2016 ITPNT $4,725,000 ON SCHEDULE < 4 69 10

200256 856 11127 SPS TX Multi - Centre St. - Hereford NE 115 kV Ckt 1 and Centre St. and Hereford 115 kV Load Conversion Centre St. - Hereford NE 115 kV Ckt 1 Regional Reliability 3/30/2018 6/1/2014 2/19/2014 2014 ITPNT $9,247,136 2014 $9,958,154 $10,699,546 DELAY ‐ MITIGATION 115 7.8

200256 856 50754 SPS TX Multi - Centre St. - Hereford NE 115 kV Ckt 1 and Centre St. and Hereford 115 kV Load Conversion Hereford 115 kV Load Conversion Regional Reliability 12/15/2016 6/1/2014 2/19/2014 2014 ITPNT $435,146 2014 $468,605 $727,279 DELAY ‐ MITIGATION 115

200207 865 11142 OPPD NE Line - Sub 917 - Sub 918 69 kV Ckt 1 Sub 917 - Sub 918 69 kV Ckt 1 Regional Reliability 6/1/2018 6/1/2018 2/20/2013 2013 ITPNT $475,340 2013 $524,686 $475,340 ON SCHEDULE < 4 69200216 879 11158 AEP OK Line - Bluebell - Prattville 138 kV Bluebell - Prattville 138 kV Ckt 1 Regional Reliability 6/2/2015 6/1/2014 2/20/2013 2013 ITPNT $10,241,314 2013 $11,304,495 $10,241,314 COMPLETE 138 9200340 879 51298 OGE OK Line - Bluebell - Prattville 138 kV Bluebell 138 kV Terminal Upgrades Regional Reliability 3/9/2016 5/7/2015 2013 ITPNT $0 COMPLETE 138200208 909 11205 WFEC OK Multi - Payne Switching Station - OU 138 kV conversion Cole - OU Switchyard 138 kV Ckt 1 Regional Reliability 7/1/2016 6/1/2013 2/20/2013 2013 ITPNT $1,705,000 2013 $1,882,001 $1,705,000 $1,677,465 COMPLETE 138200208 909 11425 WFEC OK Multi - Payne Switching Station - OU 138 kV conversion Cole - Criner 138 kV Ckt 1 Regional Reliability 4/1/2016 6/1/2013 2/20/2013 2013 ITPNT $1,400,000 2013 $1,545,338 $1,400,000 $2,402,109 COMPLETE 138200208 909 50579 WFEC OK Multi - Payne Switching Station - OU 138 kV conversion Criner - Payne Switching Station 138 kV Regional Reliability 9/25/2015 6/1/2013 2/20/2013 2013 ITPNT $3,000,000 2013 $3,311,439 $3,000,000 $3,672,718 COMPLETE 138200208 909 50580 WFEC OK Multi - Payne Switching Station - OU 138 kV conversion Payne Switching Station 138 kV Regional Reliability 9/25/2015 6/1/2013 2/20/2013 2013 ITPNT $250,000 2013 $275,953 $250,000 $308,707 COMPLETE 13820110 910 11207 OGE OK Line - Bryant - Memorial 138 kV BRYANT - MEMORIAL 138KV CKT 1 Transmission Service 6/1/2019 6/1/2019 8/25/2010 SPP-2008-AGP1-AFS-9 $225,000 2014 $242,300 $225,000 ON SCHEDULE < 4 13820096 936 11236 AEP TX/OK Line - Valliant - NW Texarkana 345 kV NORTHWEST TEXARKANA - VALLIANT 345KV CKT 1 High Priority 12/16/2016 10/1/2014 6/30/2010 Priority Projects $185,751,250 2016 $190,395,031 $185,751,250 COMPLETE 345 76.2520097 938 11238 TSMO MO Multi - Nebraska City - Mullin Creek - Sibley 345 kV (GMO) Sibley - Mullin Creek 345 kV High Priority 12/14/2016 6/1/2017 7/23/2010 Priority Projects $184,665,083 2015 $194,013,753 $173,500,000 COMPLETE 345 10520097 938 11239 TSMO MO Multi - Nebraska City - Mullin Creek - Sibley 345 kV (GMO) Nebraska City - Mullin Creek 345 kV (GMO) High Priority 12/15/2016 6/1/2017 7/23/2010 Priority Projects $81,407,015 2015 $85,528,245 $76,500,000 COMPLETE 345 6520098 939 11240 OPPD NE Line - Nebraska City - Mullin Creek 345 kV (OPPD) Nebraska City - Mullin Creek 345 kV (OPPD) High Priority 12/15/2016 6/1/2017 6/30/2010 Priority Projects $70,361,776 2015 $73,923,841 $58,708,013 COMPLETE 345 4520104 947 11261 AEP OK Line - Broken Arrow North South Tap - Oneta 138 kV Ckt 1 BROKEN ARROW NORTH - SOUTH TAP - ONETA 138KV CKT 1 #2 Transmission Service 5/25/2016 6/1/2015 8/25/2010 SPP-2008-AGP1-AFS-9 $6,072,000 2014 $6,538,880 $6,072,000 COMPLETE 138 4.33

970 11285 AECI Line - Bristow - Gypsy 138 kV Gypsy - Stroud City 138 kV Regional Reliability - Non OATT 3/1/2017 $7,107,090 COMPLETE 13820126 997 11311 MIDW KS XFR - Colby 69/34.5 kV TrXFR - Colby 115/34.5 kV Transformer Ckt 4 COLBY 115/34.5 kV transformer Ckt 4 Regional Reliability 5/1/2013 6/1/2011 2/14/2011 2010 STEP $1,097,586 COMPLETE 115/34.5200404 1001 11315 SPS TX Line - Randall - South Georgia and Osage Station 115 kV Line Re-termination Randall County Interchange - South Georgia Interchange 115 kV Ckt 1 Regional Reliability 4/19/2017 6/1/2016 7/25/2016 SPP-2015-AG1-AFS-6 $10,316,217 2016 $10,574,122 $13,179,208 DELAY ‐ MITIGATION 115 2200214 1003 11317 SPS TX XFR - Grassland 230/115 kV Transformer Ckt 1 Grassland Interchange 230/115 kV Transformer Ckt 1 Regional Reliability 2/19/2016 6/1/2013 2/20/2013 2013 ITPNT $3,961,322 2013 $4,372,558 $3,861,094 COMPLETE 230/115200256 1004 11318 SPS TX XFR - Swisher 230/115 kV Ckt 1 Swisher County Interchange 230/115 kV Ckt 1 Transformer Regional Reliability 12/3/2015 6/1/2014 2/19/2014 2014 ITPNT $3,183,028 2014 $3,427,773 $2,896,214 $2,869,670 COMPLETE 230/11520110 1021 11343 OGE OK Line - Arcadia - Redbud 345 kV Ckt 3 ARCADIA - REDBUD 345KV CKT 3 Transmission Service 6/1/2019 6/1/2019 8/25/2010 SPP-2008-AGP1-AFS-9 $18,000,000 2014 $19,384,031 $18,000,000 ON SCHEDULE < 4 345 5200214 1031 11355 SPS TX XFR - Crosby Co. 115/69 kV Transformers Ckt 1 and Ckt 2 Crosby County Interchange 115/69 kV Transformer Ckt 1 Regional Reliability 5/1/2015 6/1/2013 2/20/2013 2013 ITPNT $2,378,798 2013 $2,625,748 $2,353,396 $4,197,329 COMPLETE 115/69200214 1031 11356 SPS TX XFR - Crosby Co. 115/69 kV Transformers Ckt 1 and Ckt 2 Crosby County Interchange 115/69 kV Transformer Ckt 2 Regional Reliability 9/10/2015 6/1/2013 2/20/2013 2013 ITPNT $2,301,000 2013 $2,539,873 $1,874,922 $1,861,774 COMPLETE 115/69

200166 1033 11358 SPS TX Line - Randall - South Georgia 115 kV reconductor Randall County Interchange - South Georgia Interchange 115 kV Ckt 1 # 2 Regional Reliability 4/12/2017 6/1/2017 4/9/2012 2012 ITPNT $6,300,000 2014 $6,784,411 $4,294,271 DELAY ‐ MITIGATION 115 4.1

20130 1036 11372 SPS TX Line - Soncy convert load to 115 kV Soncy Tap 115 kV - New Soncy 115 kV Regional Reliability 4/15/2019 6/1/2015 2/14/2011 2010 STEP $929,500 2014 $1,000,970 $4,041,273 DELAY ‐ MITIGATION 115 1.04200305 1083 11423 AEP TX Line - Welsh Reserve - Wilkes 138 kV Ckt 1 Welsh Reserve - Wilkes 138 kV Ckt 1 Rebuild Regional Reliability 6/1/2019 6/1/2019 9/30/2014 2014 ITPNT $24,880,495 2014 $26,793,572 $24,880,495 ON SCHEDULE < 4 138 23.7420132 1084 11424 WFEC OK Line - Alva - Freedom 69 kV Ckt 1 ALVA - FREEDOM 69KV CKT 1 Regional Reliability 3/28/2014 6/1/2011 2/14/2011 2010 STEP $6,243,750 2014 $6,723,836 $6,243,750 $6,066,031 COMPLETE 69 18.5200297 1139 11501 SPS TX Line - Allen Sub - Lubbock South Interchange 115 kV Ckt 1 Allen Substation - Lubbock South Interchange 115 kV Ckt 1 Regional Reliability 6/1/2019 6/1/2019 5/5/2015 SPP-2012-AG3-AFS-9 $1,164,782 2015 $1,223,749 $630,000 ON SCHEDULE < 4 115200369 1142 11506 SPS TX Line - Canyon East - Randall 115 kV Ckt 1 Rebuild Canyon East Sub - Randall County Interchange 115 kV Ckt 1 Rebuild Regional Reliability 12/31/2020 2/1/2014 2/12/2016 SPP-2011-AG3-AFS-11 $12,806,065 2016 $13,126,217 $12,806,065 DELAY ‐ MITIGATION 115 18.5200262 1144 11508 SPS TX XFR - Hitchland 230/115 kV Ckt 2 Hitchland 230/115 kV Ckt 2 Transformer Regional Reliability 3/29/2017 6/1/2019 4/9/2014 SPP-2011-AG3-AFS-11 $4,087,144 2014 $4,401,407 $4,525,487 ON SCHEDULE < 4 230/115200359 1146 11509 SPS TX XFR - Carlisle 230/115 kV Ckt 1 Carlisle 230/115 kV Ckt 1 Transformer Regional Reliability 3/27/2018 10/1/2015 12/2/2015 SPP-2014-AG1-AFS-6 $3,853,326 2016 $3,949,659 $3,384,000 DELAY ‐ MITIGATION 230/115200214 1147 11512 SPS TX Multi - Potter - Channing - Dallam 230 kV Conversion Channing - Potter County 230 kV Ckt 1 Regional Reliability 12/31/2015 6/1/2013 2/20/2013 2013 ITPNT $1,819,440 2013 $2,008,321 $1,775,315 $2,512,528 COMPLETE 230 52200214 1147 11514 SPS TX Multi - Potter - Channing - Dallam 230 kV Conversion Channing - XIT 230 kV Ckt 1 Regional Reliability 12/31/2015 6/1/2013 2/20/2013 2013 ITPNT $9,166,904 2013 $10,118,547 $9,171,505 $871,088 COMPLETE 230 70200214 1147 11515 SPS TX Multi - Potter - Channing - Dallam 230 kV Conversion XIT 230/115/13.2 kV Transformer Ckt 1 Regional Reliability 12/31/2015 6/1/2013 2/20/2013 2013 ITPNT $3,863,195 2013 $4,264,244 $1,954,807 $9,865,350 COMPLETE 230/11520003 30079 50085 WFEC OK Device - Carter Cap 69 kV CARTER JCT 69KV Regional Reliability 10/15/2015 6/1/2010 2/13/2008 2007 STEP $324,000 2014 $348,913 $324,000 $568,369 COMPLETE 69200242 30097 50103 WR KS Device - Vaughn Cap 115 kV Vaughn 115 kV Cap Bank Zonal Reliability 11/25/2015 6/1/2014 2/19/2014 2014 ITPNT $1,184,617 2014 $1,275,703 $805,624 $805,624 CLOSED OUT 11520017 30160 50168 OGE AR XFR - Ft Smith 500/161 kV Ckt 3 FT SMITH 500/161KV TRANSFORMER CKT 5 Transmission Service 11/10/2017 6/1/2017 1/16/2009 SPP-2006-AG3-AFS-11 $25,635,637 2017 $25,635,637 $25,635,637 COMPLETE 500/16120017 30164 50172 OGE AR Line - VBI - VBI North 69 kV VBI - VBI NORTH 69KV CKT 1 Transmission Service 6/1/2014 6/1/2017 1/16/2009 SPP-2006-AG3-AFS-11 $100,000 2014 $107,689 $0 COMPLETE 16120078 30190 50197 MIDW KS Device-Pawnee 115 kV PAWNEE 115KV Regional Reliability 1/31/2013 6/1/2011 2/8/2010 2009 STEP $712,979 COMPLETE 11520080 30201 50208 NPPD NE Device - Clarks 115 kV CLARKS 115KV Regional Reliability 6/1/2018 11/1/2012 2/8/2010 2009 STEP $700,000 2014 $753,823 $700,000 DELAY ‐ MITIGATION 11520080 30203 50210 NPPD NE Device - Oneill 115 kV ONEILL 115KV Regional Reliability 6/1/2018 11/1/2012 2/8/2010 2009 STEP $700,000 2014 $753,823 $741,050 DELAY ‐ MITIGATION 115

20108 30290 50328 WR KS Line - Halstead South - Sedgwick 138 kV HALSTEAD SOUTH BUS - SEDGWICK COUNTY NO. 12 COLWICH 138KV CKT 1 Transmission Service 4/20/2016 6/1/2019 8/25/2010 SPP-2008-AGP1-AFS-9 $700,000 2014 $753,823 $146,944 $146,944 CLOSED OUT 138

20122 30296 50334 AEP TX Device - Winnsboro 138 kV WINNSBORO 138KV Regional Reliability 4/21/2016 6/1/2016 2/14/2011 2010 STEP $1,166,400 2014 $1,256,085 $1,166,400 COMPLETE 13820122 30298 50336 AEP LA Device - Logansport 138 kV LOGANSPORT 138KV Regional Reliability 9/10/2016 6/1/2016 2/14/2011 2010 STEP $1,166,400 2014 $1,256,085 $1,731,419 COMPLETE 13820136 30320 50366 WFEC OK Line - Canton - Taloga 69 kV ckt 1 CANTON - TALOGA 69KV CKT 1 Transmission Service 10/15/2015 6/1/2011 5/27/2011 SPP-2009-AGP2-AFS-6 $4,800,000 2014 $5,169,075 $4,800,000 $3,059,477 COMPLETE 69 9.7200282 30331 50378 SPS NM Device - Eagle Creek 115 kV Eagle Creek 115 kV Cap Bank High Priority 3/14/2016 6/1/2015 5/19/2014 HPILS $1,470,325 2014 $1,583,379 $1,353,402 $1,414,349 COMPLETE 115200166 30351 50401 SPS TX Device - Crosby 115 kV Capacitor Crosby 115 kV #2 Regional Reliability 11/4/2015 6/1/2012 4/9/2012 2012 ITPNT $985,519 2012 $1,115,024 $1,480,193 $1,334,087 COMPLETE 115200166 30356 50406 SPS TX Multi - Cedar Lake Interchange 115 kV Diamondback Interchange 115/69 kV Transformer Ckt 1 Regional Reliability 8/14/2015 6/1/2012 4/9/2012 2012 ITPNT $5,524,876 2012 $6,250,890 $6,628,573 $6,981,891 COMPLETE 115/69 17.79200166 30356 50407 SPS TX Multi - Cedar Lake Interchange 115 kV Sulphur Interchange - Diamondback Interchange 115 kV Ckt 1 Regional Reliability 8/14/2015 6/1/2012 4/9/2012 2012 ITPNT $7,699,644 2012 $8,711,440 $9,472,173 $9,933,961 COMPLETE 115 12.5200255 30361 50413 AEP OK Multi - Chisholm - Gracemont 345 kV Chisholm - Gracemont 345kV Ckt 1 (AEP) Regional Reliability 3/1/2018 3/1/2018 2/6/2014 2012 ITP10 $65,082,311 2017 $65,082,311 $65,082,311 ON SCHEDULE < 4 345 72200255 30361 50414 AEP OK Multi - Chisholm - Gracemont 345 kV Chisholm 345/230 kV Substation Regional Reliability 3/1/2018 3/1/2018 2/6/2014 2012 ITP10 $17,471,695 2017 $17,471,695 $17,471,695 ON SCHEDULE < 4 345/230200240 30361 50419 OGE OK Multi - Chisholm - Gracemont 345 kV Chisholm - Gracemont 345 kV Ckt 1 (OGE) Regional Reliability 3/1/2018 3/1/2018 12/20/2013 2012 ITP10 $43,853,500 2017 $43,853,500 $43,853,500 ON SCHEDULE < 4 345 29.8200255 30361 50768 AEP OK Multi - Chisholm - Gracemont 345 kV Chisholm 230 kV Regional Reliability 3/1/2018 3/1/2018 2/6/2014 2012 ITP10 $1,270,623 2017 $1,270,623 $1,270,623 ON SCHEDULE < 4 230 2200223 30364 50420 OGE OK Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Tatonga - Woodward District EHV 345 kV Ckt 2 Regional Reliability 2/1/2018 3/1/2021 5/23/2013 2012 ITP10 $59,522,400 2013 $65,701,592 $50,594,040 ON SCHEDULE < 4 345 49200223 30364 50421 OGE OK Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Matthewson - Tatonga 345 kV Ckt 2 Regional Reliability 2/1/2018 3/1/2021 5/23/2013 2012 ITP10 $65,785,650 2013 $72,615,048 $56,387,700 ON SCHEDULE < 4 345 61200223 30364 50456 OGE OK Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Cimarron - Matthewson 345 kV Ckt 2 Regional Reliability 7/1/2016 3/1/2021 5/23/2013 2012 ITP10 $32,936,400 2013 $36,355,623 $32,936,400 COMPLETE 345 16200223 30364 50458 OGE OK Multi - Woodward District EHV - Tatonga - Matthewson - Cimarron 345 kV Matthewson 345 kV Regional Reliability 6/24/2016 3/1/2021 5/23/2013 2012 ITP10 $19,967,850 2013 $22,040,770 $19,967,850 COMPLETE 345200222 30367 50425 ITCGP KS Multi - Elm Creek - Summit 345 kV Elm Creek - Summit 345 kV Ckt 1 (ITCGP) Regional Reliability 3/1/2018 3/1/2018 3/21/2013 2012 ITP10 $31,312,169 2013 $34,562,776 $42,024,978 ON SCHEDULE < 4 345 29.77200222 30367 50426 ITCGP KS Multi - Elm Creek - Summit 345 kV Elm Creek 345/230 kV Transformer Regional Reliability 12/31/2016 3/1/2018 3/21/2013 2012 ITP10 $5,405,101 2013 $5,966,220 $4,928,468 ON SCHEDULE < 4 345/230200222 30367 50427 ITCGP KS Multi - Elm Creek - Summit 345 kV Elm Creek 345 kV Terminal Upgrades Regional Reliability 12/31/2016 3/1/2018 3/21/2013 2012 ITP10 $8,243,291 2013 $9,099,051 $12,154,733 ON SCHEDULE < 4 345

Quarter 1 2018 Project Tracking Portfolio

RFP Issued

Complete and in‐serviceIn‐service and all required project close‐out documentation supplied by TOOn Schedule within 4‐year horizonOn Schedule beyond 4‐year horizonWithin the NTC‐C Project Estimate (CPE) windowBehind schedule, interim mitigation provided or project may change but time permits the implementation of project; asterisk (*) indicates interim mitigation plan provided by SPPNTC/GIA suspendedNTC/NTC‐C active; pending re‐evaluationNTC/NTC‐C issued, still within the 90 day written commitment to construct window and no commitment received

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200222 30367 50428 ITCGP KS Multi - Elm Creek - Summit 345 kV Elm Creek 230 kV Terminal Upgrades Regional Reliability 12/31/2016 3/1/2018 3/21/2013 2012 ITP10 $1,886,035 2013 $2,081,830 $2,165,198 ON SCHEDULE < 4 230200221 30367 50429 WR KS Multi - Elm Creek - Summit 345 kV Elm Creek - Summit 345 kV Ckt 1 (WR) Regional Reliability 12/31/2016 3/1/2018 3/21/2013 2012 ITP10 $66,202,442 2013 $73,075,109 $52,996,990 $52,996,990 CLOSED OUT 345 28.46200212 30369 10425 WR KS XFR - Moundridge 138/115 kV Moundridge 138/115 kV Transformer Ckt 2 Regional Reliability 4/7/2015 6/1/2013 2/20/2013 2013 ITPNT $19,770,066 2013 $21,822,454 $12,846,183 $12,846,183 CLOSED OUT 138/115200253 30374 50440 NPPD NE Multi - Hoskins - Neligh 345 kV Hoskins - Neligh 345 kV Ckt 1 Regional Reliability 6/17/2016 6/1/2016 2/19/2014 2014 ITPNT $51,692,702 2017 $51,692,702 $51,692,703 COMPLETE 345 41200253 30374 50441 NPPD NE Multi - Hoskins - Neligh 345 kV Neligh 345/115 kV Substation Regional Reliability 4/1/2018 6/1/2016 2/19/2014 2014 ITPNT $10,082,325 2017 $10,082,325 $10,082,325 DELAY ‐ MITIGATION 345/115200253 30374 50621 NPPD NE Multi - Hoskins - Neligh 345 kV Neligh 115 kV Terminal Upgrades Regional Reliability 6/17/2016 6/1/2016 2/19/2014 2014 ITPNT $19,769,490 2017 $19,769,490 $19,769,491 COMPLETE 115 11.4 7200220 30375 50442 NPPD NE Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Cherry Co. - Gentleman 345 kV Ckt 1 Regional Reliability 10/1/2019 1/1/2018 3/11/2013 2012 ITP10 $139,090,440 2013 $153,529,821 $139,090,440 DELAY ‐ MITIGATION 345 110200220 30375 50444 NPPD NE Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Cherry Co. Substation 345 kV Regional Reliability 10/1/2019 1/1/2018 3/11/2013 2012 ITP10 $11,896,383 2013 $13,131,381 $9,936,752 DELAY ‐ MITIGATION 345200220 30375 50445 NPPD NE Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Cherry Co. - Holt Co. 345 kV Ckt 1 Regional Reliability 10/1/2019 1/1/2018 3/11/2013 2012 ITP10 $146,065,000 2013 $161,228,430 $180,002,660 DELAY ‐ MITIGATION 345 117200220 30375 50446 NPPD NE Multi - Gentleman - Cherry Co. - Holt Co. 345 kV Holt Co. Substation 345 kV Regional Reliability 10/1/2019 1/1/2018 3/11/2013 2012 ITP10 $16,324,800 2013 $18,019,525 $13,119,129 DELAY ‐ MITIGATION 345200309 30376 50452 SPS NM Multi - Hobbs - Yoakum 345/230 kV Ckt 1 Hobbs 345/230 kV Ckt 1 Transformer High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $16,204,449 2014 $17,450,419 $14,027,120 ON SCHEDULE < 4 345/230200309 30376 50457 SPS NM/TX Multi - Hobbs - Yoakum 345/230 kV Ckt 1 Hobbs - Yoakum 345 kV Ckt 1 High Priority 6/15/2020 6/1/2020 12/3/2014 HPILS $90,628,750 2014 $97,597,251 $90,628,750 DELAY ‐ MITIGATION 345 52200296 30390 10600 WR KS Line - East Manhattan - Jeffrey Energy Center 230 kV Ckt 1 East Manhattan - Jeffrey Energy Center 230 kV Ckt 1 Rebuild Regional Reliability 4/7/2017 6/1/2017 9/2/2014 2014 ITPNT $41,100,000 2016 $42,127,500 $41,100,000 COMPLETE 230 30200190 30410 50503 SPS TX Line - Bowers - Canadian 69 kV Rebuild Bowers - Canadian 69 kV Rebuild Regional Reliability 1/15/2016 6/1/2012 1/18/2013 DPA-2011-SEPTEMBER-095 $34,999,584 2013 $38,632,992 $31,779,309 $31,779,309 COMPLETE 69 39 10

200262 30420 50513 SPS TX Line - Bushland Interchange - Deaf Smith County Interchange 230 kV Ckt 1 Bushland Interchange - Deaf Smith Co Interchange 230 kV Ckt 1 Terminal Upgrade Regional Reliability 12/15/2017 2/1/2014 4/9/2014 SPP-2011-AG3-AFS-11 $285,176 2014 $307,103 $261,084 DELAY ‐ MITIGATION 230

200193 30422 50515 SPS TX XFR - Deaf Smith County Interchange 230/115 kV transformer CKT 1 Deaf Smith County Interchange 230/115 kV Transformer Ckt 1 #2 Regional Reliability 2/25/2016 6/1/2012 11/20/2012 SPP-2010-AGP1-AFS-8 $4,273,633 2012 $4,835,223 $4,236,816 COMPLETE 230/115200214 30423 50516 SPS TX XFR - Deaf Smith County Interchange 230/115 kV Ckt 2 Deaf Smith County Interchange 230/115 kV Transformer Ckt 2 Regional Reliability 5/12/2016 6/1/2013 2/20/2013 2013 ITPNT $4,225,233 2013 $4,663,867 $4,225,233 COMPLETE 230/115200214 30424 50517 SPS TX/OK Line - Ochiltree - Tri-County Cole 115 kV Ckt 1 Ochiltree - Tri-County REC Cole 115 kV Ckt 1 Rebuild Regional Reliability 11/20/2015 6/1/2013 2/20/2013 2013 ITPNT $11,332,148 2013 $12,508,571 $13,000,000 $11,735,967 COMPLETE 115 17200210 30426 50519 MIDW KS Line - Pheasant Run - Seguin 115 kV Ckt 1 Pheasant Run - Seguin 115 kV Ckt 1 Regional Reliability 7/15/2014 6/1/2014 2/20/2013 2013 ITPNT $11,128,231 2013 $12,283,485 $7,811,905 COMPLETE 115 19.3200325 30427 50520 SEPC KS XFR - Mingo 345/115 kV Ckt 2 Transformer Mingo 345/115 kV Ckt 2 Transformer Regional Reliability 1/11/2017 6/1/2015 2/18/2015 2015 ITPNT $6,921,684 2015 $7,272,094 $8,597,207 $8,597,207 CLOSED OUT 345/115200325 30427 51180 SEPC KS XFR - Mingo 345/115 kV Ckt 2 Transformer Mingo 345 kV Terminal Upgrades Regional Reliability 1/11/2017 6/1/2015 2/18/2015 2015 ITPNT $2,920,633 2015 $3,068,490 $4,332,021 $4,332,021 CLOSED OUT 345200216 30436 50531 AEP TX Line - New Gladewater - Perdue 138 kV New Gladewater - Perdue 138 kV Ckt 1 Regional Reliability 12/31/2014 6/1/2016 2/20/2013 2013 ITPNT $1,000,000 2013 $1,103,813 $1,000,000 COMPLETE 138200242 30437 50532 WR KS Multi - Geary County 345/115 kV and Geary - Chapman 115 kV Geary County 345/115 kV Substation Regional Reliability 6/1/2018 6/1/2014 2/19/2014 2014 ITPNT $20,530,196 2014 $22,108,776 $22,470,822 DELAY ‐ MITIGATION 345/115200242 30437 50534 WR KS Multi - Geary County 345/115 kV and Geary - Chapman 115 kV Chapman Junction - Geary County 115 kV Ckt 1 Regional Reliability 6/1/2019 6/1/2014 2/19/2014 2014 ITPNT $27,938,225 2014 $30,086,413 $28,732,415 DELAY ‐ MITIGATION 115 4.67 10.42200242 30437 50605 WR KS Multi - Geary County 345/115 kV and Geary - Chapman 115 kV Geary County 345 kV Regional Reliability 6/1/2018 6/1/2014 2/19/2014 2014 ITPNT $16,190,561 2014 $17,435,463 $16,290,638 DELAY ‐ MITIGATION 345200241 30438 50533 GRDA OK Line - Kerr - 412 Sub 161 kV Ckt 1 Kerr - 412 Sub 161 kV Ckt 1 Terminal Upgrades Regional Reliability 6/1/2017 6/1/2017 2/19/2014 2014 ITPNT $161,100 2014 $173,487 $161,100 COMPLETE 161200241 30440 50535 GRDA OK Line - 412 Sub - Kansas Tap 161 kV Ckt 1 412 Sub - Kansas Tap 161 kV Ckt 1 Terminal Upgrades Regional Reliability 6/1/2018 6/1/2018 2/19/2014 2014 ITPNT $54,500 2014 $58,691 $294,840 ON SCHEDULE < 4 161200384 30444 50539 SPS TX Device - Cochran 115 kV Cap Bank Cochran 115 kV Cap Bank Regional Reliability 11/15/2018 6/1/2016 4/20/2016 DPA-2013-JUN-342 $1,808,805 2016 $1,854,025 $2,841,299 DELAY ‐ MITIGATION 115200231 30449 50545 AEP LA Line - Rock Hill - Springridge Pan-Harr REC 138 kV Ckt 1 Rock Hill - Springridge Pan-Harr REC 138 kV Ckt 1 Regional Reliability 9/19/2016 6/1/2014 9/23/2013 2013 ITPNT $25,060,655 2013 $27,662,274 $25,060,655 COMPLETE 138 27.6200214 30451 50546 SPS NM Line - Atoka - Eagle Creek 115 kV Ckt 1 Atoka - Eagle Creek 115 kV Ckt 1 Regional Reliability 12/31/2018 6/1/2015 2/20/2013 2013 ITPNT $20,808,304 2013 $22,968,474 $22,200,000 DELAY ‐ MITIGATION 115 22.1200214 30466 50560 SPS NM XFR - Potash Junction 115/69 kV Ckt 1 Potash Junction 115/69 kV Transformer Ckt 1 Regional Reliability 8/7/2015 6/1/2013 2/20/2013 2013 ITPNT $2,127,697 2013 $2,348,579 $2,496,879 $2,422,732 COMPLETE 115/69200229 30469 50563 SPS NM Multi - Kilgore Switch - South Portales - Market St. - Portales 115 kV Kilgore Switch - South Portales 115 kV Ckt 1 Regional Reliability 2/7/2018 6/1/2018 9/10/2013 2013 ITPNT $5,136,476 2013 $5,669,708 $5,212,250 ON SCHEDULE < 4 115 5.3200229 30469 50564 SPS NM Multi - Kilgore Switch - South Portales - Market St. - Portales 115 kV Market St. - South Portales 115 kV Ckt 1 Regional Reliability 7/13/2018 6/1/2018 9/10/2013 2013 ITPNT $6,498,682 2013 $7,173,329 $6,594,553 DELAY ‐ MITIGATION 115 6200229 30469 50565 SPS NM Multi - Kilgore Switch - South Portales - Market St. - Portales 115 kV Market St. - Portales 115 kV Ckt 1 Regional Reliability 2/7/2018 6/1/2018 9/10/2013 2013 ITPNT $15,394,429 2013 $16,992,569 $15,621,532 ON SCHEDULE < 4 115 10.4200216 30471 50567 AEP TX Line - Dekalb - New Boston 69 kV Dekalb - New Boston 69 kV Ckt 1 Regional Reliability 6/5/2015 6/1/2013 2/20/2013 2013 ITPNT $16,548,317 2013 $18,266,245 $16,548,317 $15,777,911 COMPLETE 69 13.2200216 30472 50568 AEP LA Line - Hardy Street - Waterworks 69 kV Hardy Street - Waterworks 69 kV Ckt 1 Regional Reliability 6/25/2015 6/1/2013 2/20/2013 2013 ITPNT $7,519,658 2013 $8,300,296 $7,519,658 $5,366,606 COMPLETE 69 1.65200216 30473 50569 AEP AR Line - Midland REC - North Huntington 69 kV Midland REC - North Huntington 69 kV Ckt 1 Regional Reliability 5/15/2015 6/1/2013 2/20/2013 2013 ITPNT $1,829,026 2013 $2,018,903 $1,829,026 $11,990,487 COMPLETE 69 1.3200216 30474 50570 AEP AR Line - Midland - Midland REC 69 kV Midland - Midland REC 69 kV Ckt 1 Regional Reliability 5/15/2015 6/1/2013 2/20/2013 2013 ITPNT $5,653,353 2013 $6,240,244 $5,653,353 COMPLETE 69 4.3200216 30475 50571 AEP AR Line - Howe Interchange - Midland 69 kV Howe Interchange - Midland 69 kV Ckt 1 Regional Reliability 5/15/2015 6/1/2013 2/20/2013 2013 ITPNT $9,145,130 2013 $10,094,513 $9,145,130 COMPLETE 69 7200202 30476 50572 GRDA OK Line - Chelsea - Childers 69 kV Chelsea - Childers 69 kV Ckt 1 Zonal Reliability 7/29/2015 6/1/2015 2/20/2013 2013 ITPNT $355,000 2013 $391,854 $355,000 COMPLETE 69200207 30478 50574 OPPD NE Line - 6815 Tap South in Ckt 623 - Sub 6815 T3 69 kV Ckt 1 6815 Tap South - Sub 6815 T3 69 kV Ckt 1 Regional Reliability 3/13/2015 6/1/2015 2/20/2013 2013 ITPNT $260,590 2013 $287,643 $260,590 COMPLETE 69 0.71200194 30481 50577 OGE OK Line - El Reno - Service PL El Reno 69 kV CKT 1 El Reno - Service PL El Reno 69 kV CKT 1 Transmission Service 6/1/2014 6/1/2017 11/20/2012 SPP-2010-AGP1-AFS-8 $10,000 2013 $11,038 $0 COMPLETE 69200212 30483 50581 WR KS XFR - Gill 138/69 kV Ckt 3 Gill 138/69 kV Transformer Ckt 3 Regional Reliability 9/17/2015 6/1/2015 2/20/2013 2013 ITPNT $7,122,480 2013 $7,861,885 $5,330,786 $5,330,786 CLOSED OUT 138/69200228 30484 50582 WR KS Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill Viola 345/138 kV Transformer Ckt 1 Regional Reliability 12/31/2018 6/1/2018 9/10/2013 2013 ITPNT $13,331,670 2017 $13,331,670 $13,331,670 DELAY ‐ MITIGATION 345/138200228 30484 50583 WR KS Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill Clearwater - Viola 138 kV Ckt 1 Regional Reliability 12/31/2018 6/1/2018 9/10/2013 2013 ITPNT $31,492,903 2017 $31,492,903 $31,492,903 DELAY ‐ MITIGATION 138 21.8200228 30484 50584 WR KS Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill Gill - Viola 138 kV Ckt 1 Regional Reliability 12/31/2018 6/1/2018 9/10/2013 2013 ITPNT $17,234,744 2017 $17,234,744 $17,234,744 DELAY ‐ MITIGATION 138 27.9200228 30484 50612 WR KS Multi - Viola 345/138kV Transformer and 138 kV Lines to Clearwater and Gill Viola 345 kV Terminal Equipment Regional Reliability 6/1/2018 6/1/2018 9/10/2013 2013 ITPNT $5,007,657 2017 $5,007,657 $5,007,657 DELAY ‐ MITIGATION 345200200 30488 50595 WFEC OK Multi - Renfrow - Wakita - Noel Switch 138 kV Noel Switch - Wakita 138 kV Ckt 1 Regional Reliability 1/28/2013 1/1/2013 3/1/2013 DPA-2012-MAR-143-147 $17,928,848 2013 $19,790,094 $17,928,848 $19,103,991 COMPLETE 138200200 30488 50596 WFEC OK Multi - Renfrow - Wakita - Noel Switch 138 kV Sandridge Tap - Wakita 138 kV Ckt 1 Regional Reliability 6/30/2013 1/1/2013 3/1/2013 DPA-2012-MAR-143-147 $7,220,000 2013 $7,969,529 $7,220,000 $7,250,930 COMPLETE 138200200 30488 50597 WFEC OK Multi - Renfrow - Wakita - Noel Switch 138 kV Wakita 138/69 kV Transformer Ckt 1 Regional Reliability 6/24/2013 1/1/2013 3/1/2013 DPA-2012-MAR-143-147 $3,573,553 2013 $3,944,534 $3,573,553 $3,247,997 COMPLETE 138/69200200 30488 50619 WFEC OK Multi - Renfrow - Wakita - Noel Switch 138 kV Sandridge Tap - Renfrow 138 kV Ckt 1 (WFEC) Regional Reliability 4/30/2014 1/1/2013 3/1/2013 DPA-2012-MAR-143-147 $2,000,000 2013 $2,207,626 $2,000,000 $1,700,835 COMPLETE 138200200 30490 50599 WFEC OK Device - Fairview 69 kV Fairview 69 kV Capacitor Regional Reliability 4/24/2015 1/1/2013 3/1/2013 DPA-2012-MAR-143-147 $237,000 2013 $261,604 $237,000 $524,345 COMPLETE 69200200 30491 50600 WFEC OK Device - Hazelton 69 kV Hazelton 69 kV Capacitor Regional Reliability 3/1/2017 1/1/2013 3/1/2013 DPA-2012-MAR-143-147 $237,000 2013 $261,604 $735,000 $728,843 COMPLETE 69200210 30494 50606 MIDW KS Line - Hays Plant - South Hays 115 kV Ckt 1 Rebuild Hays Plant - South Hays 115 kV Ckt 1 #2 Regional Reliability 10/13/2016 6/1/2013 2/20/2013 2013 ITPNT $8,832,219 2013 $9,749,117 $9,392,940 COMPLETE 115 3.87200231 30495 50607 AEP LA Sub - Messick 500/230 kV Layfield 500/230 kV Transformer Ckt 1 Regional Reliability 4/29/2016 6/1/2013 9/23/2013 2013 ITPNT $30,369,537 2013 $33,522,286 $22,851,755 COMPLETE 500/230200231 30495 50615 AEP LA Sub - Messick 500/230 kV Layfield 500 kV Terminal Upgrades Regional Reliability 4/29/2016 6/1/2013 9/23/2013 2013 ITPNT $21,508,234 2013 $23,741,066 $32,212,715 COMPLETE 500200400 30496 50608 NPPD NE Multi - Bobcat Canyon 345/115 kV and Bobcat Canyon - Scottsbluff 115 kV Bobcat Canyon 345/115 kV Transformer Ckt 1 Regional Reliability 10/26/2017 6/1/2014 8/17/2016 2014 ITPNT $5,928,480 COMPLETE 345/115200400 30496 50609 NPPD NE Multi - Bobcat Canyon 345/115 kV and Bobcat Canyon - Scottsbluff 115 kV Bobcat Canyon - Scottsbluff 115 kV Ckt 1 Regional Reliability 10/26/2017 6/1/2014 8/17/2016 2014 ITPNT $23,700,242 COMPLETE 115 23200400 30496 50616 NPPD NE Multi - Bobcat Canyon 345/115 kV and Bobcat Canyon - Scottsbluff 115 kV Bobcat Canyon 345 kV Terminal Upgrades Regional Reliability 10/26/2017 6/1/2014 8/17/2016 2014 ITPNT $4,072,936 COMPLETE 345200399 30496 51570 BEPC NE Multi - Bobcat Canyon 345/115 kV and Bobcat Canyon - Scottsbluff 115 kV Stegall 345 kV Terminal Upgrades Regional Reliability 6/1/2017 6/1/2014 8/17/2016 2014 ITPNT $2,499,727 COMPLETE 345200200 30497 50610 WFEC OK Line - Buffalo - Buffalo Bear - Ft. Supply 69 kV Buffalo Bear - Buffalo 69 kV Ckt 1 Regional Reliability 12/19/2014 12/1/2013 3/1/2013 DPA-2012-MAR-143-147 $6,000,000 2013 $6,622,877 $1,500,000 $4,094,378 COMPLETE 69200200 30497 50611 WFEC OK Line - Buffalo - Buffalo Bear - Ft. Supply 69 kV Buffalo Bear - Ft. Supply 69 kV Ckt 1 #2 Regional Reliability 12/19/2014 12/1/2013 3/1/2013 DPA-2012-MAR-143-147 $1,500,000 2013 $1,655,719 $6,000,000 $960,410 COMPLETE 69200234 30501 50624 WFEC OK Multi - Renfrow - Medford Tap - Chikaskia 138 kV Medford Tap - Pond Creek 138 kV (WFEC) Regional Reliability 4/1/2016 5/1/2013 10/28/2013 DPA-2012-MAR-151-154-161-JUL-218-SEP-243 $3,540,000 2015 $3,719,213 $3,540,000 $7,546,691 COMPLETE 138 13200234 30502 50626 WFEC OK Device - Renfrow-Sandridge 138 kV Renfrow-Sandridge Capacitor 138 kV Regional Reliability 6/1/2017 6/1/2017 10/28/2013 DPA-2012-MAR-151-154-161-JUL-218-SEP-243 $185,004 2013 $204,210 $185,004 DELAY ‐ MITIGATION 138200234 30503 50628 WFEC OK Device - Hazelton 69 kV #2 Hazelton Capacitor 69 kV #2 Regional Reliability 3/1/2017 6/1/2017 10/28/2013 DPA-2012-MAR-151-154-161-JUL-218-SEP-243 $185,004 2013 $204,210 $0 COMPLETE 69200263 30507 50634 MIDW KS Line - Hays Plant - Vine Street 115 kV Ckt 1 Hays Plant - Vine Street 115kV Ckt 1 Terminal Upgrade Regional Reliability 10/1/2014 2/1/2014 3/31/2014 SPP-2011-AG3-AFS-11 $15,720 2014 $16,929 $15,720 COMPLETE 115200264 30508 50635 OGE OK Line - Division Ave - Lakeside 138 kV Ckt 1 Division Ave - Lakeside 138 kV Ckt 1 Rebuild Regional Reliability 6/1/2019 6/1/2019 3/31/2014 SPP-2011-AG3-AFS-11 $1,720,000 2014 $1,852,252 $1,720,000 ON SCHEDULE < 4 138 3.6200369 30509 50636 SPS TX Line - Canyon East Sub - Canyon West Sub 115 kV Ckt 1 Canyon East Sub - Canyon West Sub 115 kV Ckt 1 Rebuild Regional Reliability 5/18/2016 2/1/2014 2/12/2016 SPP-2011-AG3-AFS-11 $2,694,811 2016 $2,762,181 $4,958,791 DELAY ‐ MITIGATION 115 3.7200262 30510 50637 SPS TX Line - Mustang - Shell CO2 115 kV Ckt 1 Mustang - Shell CO2 115 kV Ckt 1 Transmission Service 12/15/2019 6/1/2015 4/9/2014 SPP-2011-AG3-AFS-11 $15,473,119 2014 $16,662,857 $19,100,000 DELAY ‐ MITIGATION 115 7.71200420 30513 50640 SPS NM XFR - Potash Junction 230/115 kV Transformer Upgrade Potash Junction 230/115 kV Transformer Upgrade Regional Reliability 3/15/2022 6/1/2021 1/12/2017 SPP-2015-AG1-AFS-6 $6,655,500 DELAY ‐ MITIGATION 230/115200410 30552 50690 SPS NM Line - Oxy Permian Sub - West Bender Sub 115 kV Ckt 1 Oxy Permian Sub - West Bender Sub 115 kV Ckt 1 Rebuild Regional Reliability 10/28/2016 6/1/2018 8/17/2016 2014 ITPNT $742,000 ON SCHEDULE < 4 115 0.5200242 30553 50691 WR KS Line - Butler - Weaver 138 kV Ckt 1 Butler - Weaver 138 kV Terminal Upgrades Ckt 1 Regional Reliability 1/28/2016 6/1/2015 2/19/2014 2014 ITPNT $221,294 2014 $238,309 $0 COMPLETE 138200256 30555 50693 SPS NM Quahada Switching Station 115 kV Quahada Switching Station 115 kV Regional Reliability 7/9/2015 6/1/2015 2/19/2014 2014 ITPNT $6,943,260 2014 $7,477,132 $8,250,000 $7,668,328 COMPLETE 115 0.68200242 30558 50696 WR KS XFR - Neosho 138/69 kV Ckt 1 Neosho 138/69 kV Ckt 1 Transformer Regional Reliability 4/25/2016 6/1/2014 2/19/2014 2014 ITPNT $7,790,221 2014 $8,389,216 $7,925,681 COMPLETE 138/69 0.5200246 30559 50697 AEP TX Line - Chapel Hill REC - Welsh Reserve 138 kV Ckt 1 Chapel Hill REC - Welsh Reserve 138 kV Ckt 1 Rebuild Regional Reliability 6/1/2019 6/1/2019 2/19/2014 2014 ITPNT $6,651,694 2014 $7,163,147 $6,651,694 ON SCHEDULE < 4 138 4.39200296 30560 50698 WR KS Line - Sumner County - Viola 138 kV Ckt 1 Sumner County - Viola 138 kV Ckt 1 Zonal Reliability 6/1/2020 6/1/2019 9/2/2014 2014 ITPNT $51,513,963 2014 $55,474,904 $51,513,963 DELAY ‐ MITIGATION 138 28200258 30561 50699 OPPD NE XFR - S1366 161/69 kV Ckt 1 S1366 161/69 kV Ckt 1 Transformer Regional Reliability 5/31/2016 6/1/2016 2/19/2014 2014 ITPNT $4,426,730 2014 $4,767,104 $4,426,730 COMPLETE 161/69200258 30561 50761 OPPD NE XFR - S1366 161/69 kV Ckt 1 S1366 161 kV Ckt 1 Terminal Upgrades Regional Reliability 5/31/2016 6/1/2016 2/19/2014 2014 ITPNT $422,270 2014 $454,739 $422,270 $422,270 COMPLETE 161200245 30563 50702 WFEC OK Device - Sandy Corner 138 kV Sandy Corner 138 kV Cap Bank Regional Reliability 6/1/2017 6/1/2017 2/19/2014 2014 ITPNT $504,000 2014 $542,753 $504,000 ON SCHEDULE < 4 138200309 30569 50708 SPS NM Multi - Potash Junction - Road Runner 230/115 kV Ckt 1 Potash Junction - Road Runner 230 kV Ckt 1 High Priority 10/27/2015 6/1/2015 12/3/2014 HPILS $43,096,827 2014 $46,410,569 $51,035,181 $2,284,553 COMPLETE 230 40.4200309 30569 50709 SPS NM Multi - Potash Junction - Road Runner 230/115 kV Ckt 1 Road Runner 230/115 kV Substation High Priority 10/27/2015 6/1/2015 12/3/2014 HPILS $10,576,672 2014 $11,389,919 $10,893,806 $59,759,398 COMPLETE 230/115 1200246 30573 50718 AEP LA Line - Broadmoor - Fort Humbug 69 kV Ckt 1 Broadmoor - Fort Humbug 69 kV Ckt 1 Rebuild Regional Reliability 6/21/2017 6/1/2019 2/19/2014 2014 ITPNT $6,695,986 2014 $7,210,844 $6,695,986 COMPLETE 69 1.7200246 30574 50719 AEP TX Line - Daingerfield - Jenkins Rec 69 kV Ckt 1 Rebuild Daingerfield - Jenkins REC T 69 kV Ckt 1 Rebuild Regional Reliability 11/9/2017 6/1/2019 2/19/2014 2014 ITPNT $2,819,806 2014 $3,036,623 $2,819,806 COMPLETE 69 1.3200246 30575 50720 AEP TX Line - Hallsville - Longview Heights 69 kV Ckt 1 Hallsville - Longview Heights 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2014 2/19/2014 2014 ITPNT $8,851,677 2014 $9,532,288 $10,340,533 DELAY ‐ MITIGATION 69 6.6200246 30576 50721 AEP TX Line - Hallsville - Marshall 69 kV Ckt 1 Hallsville - Marshall 69 kV Ckt 1 Rebuild Regional Reliability 6/2/2017 6/1/2014 2/19/2014 2014 ITPNT $15,248,925 2014 $16,421,425 $16,571,092 COMPLETE 69 11.2200256 30577 50722 SPS NM Line - Chavis - Price - CV Pines - Capitan 115 kV Ckt 1 Chaves - Price 115 kV Ckt 1 Rebuild Regional Reliability 1/31/2018 6/1/2017 2/19/2014 2014 ITPNT $4,701,279 2014 $5,062,763 $5,961,279 DELAY ‐ MITIGATION 115 5 5200256 30577 50723 SPS NM Line - Chavis - Price - CV Pines - Capitan 115 kV Ckt 1 CV Pines - Price 115 kV Ckt 1 Rebuild Regional Reliability 1/31/2018 6/1/2017 2/19/2014 2014 ITPNT $4,158,668 2014 $4,478,431 $3,793,668 DELAY ‐ MITIGATION 115 3200256 30577 50724 SPS NM Line - Chavis - Price - CV Pines - Capitan 115 kV Ckt 1 Capitan - CV Pines 115 kV Ckt 1 Rebuild Regional Reliability 1/31/2018 6/1/2017 2/19/2014 2014 ITPNT $5,415,053 2014 $5,831,420 $3,793,053 DELAY ‐ MITIGATION 115 5 5200333 30578 50725 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV Bailey Co. - Bailey Co. Pump 115 kV Ckt 1 Regional Reliability 6/15/2021 6/1/2016 2/18/2015 2014 ITPNT $8,208,578 2014 $8,839,741 $9,715,422 DELAY ‐ MITIGATION 115200333 30578 50729 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV Bailey Co. Pump - Sundan Rural 115 kV Ckt 1 Regional Reliability 6/15/2021 6/1/2016 2/18/2015 2014 ITPNT $8,038,605 2014 $8,656,698 $8,753,365 DELAY ‐ MITIGATION 115 11.7200333 30578 50731 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV New Amherst 116/69 kV Ckt 1 Transformer Regional Reliability 4/15/2021 6/1/2016 2/18/2015 2014 ITPNT $5,367,770 2014 $5,780,501 $5,695,912 DELAY ‐ MITIGATION 115/69 0.2200333 30578 50732 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV New Amherst - Sudan Rural 115 kV Ckt 1 Regional Reliability 11/15/2021 6/1/2016 2/18/2015 2014 ITPNT $5,074,202 2014 $5,464,361 $5,713,799 DELAY ‐ MITIGATION 115 8.6200333 30578 50734 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV New Amherst 115 kV Terminal Upgrades Ckt 1 Regional Reliability 11/15/2021 6/1/2016 2/18/2015 2014 ITPNT $3,028,707 2014 $3,261,586 $3,064,697 DELAY ‐ MITIGATION 115200333 30578 50735 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV Lamb Co. - New Amherst 115 kV Ckt 1 Regional Reliability 3/15/2022 6/1/2016 2/18/2015 2014 ITPNT $16,737,611 2014 $18,024,576 $18,918,945 DELAY ‐ MITIGATION 115 13.71200401 30578 50736 SPS TX Multi - Bailey Co. - Lamb Co. 115 kV West Littlefield - West Littlefield Tap 115 kV Ckt 1 Regional Reliability 5/15/2021 6/1/2016 5/25/2016 2014 ITPNT $3,187,532 2016 $3,267,220 $795,547 DELAY ‐ MITIGATION 115 8.6200242 30579 50726 WR KS Line - Wellington - Creswell 69 kV City of Wellington - Sumner County No.4 Rome 69 kV Ckt 1 Rebuild Regional Reliability 3/16/2016 6/1/2014 2/19/2014 2014 ITPNT $7,405,817 2014 $7,975,255 $4,467,698 $4,467,698 CLOSED OUT 69 9200242 30579 50727 WR KS Line - Wellington - Creswell 69 kV Creswell - Sumner County No.4 Rome 69 kV Ckt 1 Rebuild Regional Reliability 11/20/2015 6/1/2014 2/19/2014 2014 ITPNT $8,131,536 2014 $8,756,775 $4,124,520 $4,124,520 CLOSED OUT 69 9.5200242 30580 50730 WR KS Line - Crestview - Kenmar 69 kV Crestview - Northeast 69 kV Ckt 1 Rebuild Regional Reliability 11/13/2015 6/1/2014 2/19/2014 2014 ITPNT $8,968,153 2014 $9,657,720 $8,833,123 $8,833,123 CLOSED OUT 69 5.59200242 30580 50733 WR KS Line - Crestview - Kenmar 69 kV Kenmar - Northeast 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2014 2/19/2014 2014 ITPNT $5,590,592 2014 $6,020,456 $6,740,273 DELAY ‐ MITIGATION 69 1.74200299 30581 50763 OGE OK Line - Park Lane - Ahloso - Harden City - Frisco - Lula 69/138 kV Ckt 1 Ahloso - Park Lane 138 kV Ckt 1 Voltage Conversion Regional Reliability 1/19/2016 6/1/2015 9/18/2014 2014 ITPNT $5,693,264 2014 $6,131,023 $5,693,264 COMPLETE 138 4.39200299 30581 50764 OGE OK Line - Park Lane - Ahloso - Harden City - Frisco - Lula 69/138 kV Ckt 1 Ahloso - Harden City 138 kV Ckt 1 Voltage Conversion Regional Reliability 4/1/2016 6/1/2015 9/18/2014 2014 ITPNT $6,929,179 2014 $7,461,968 $6,929,179 COMPLETE 138 10.12 10.12200299 30581 50765 OGE OK Line - Park Lane - Ahloso - Harden City - Frisco - Lula 69/138 kV Ckt 1 Frisco - Harden City 138 kV Ckt 1 Voltage Conversion Regional Reliability 6/1/2016 6/1/2015 9/18/2014 2014 ITPNT $2,121,320 2014 $2,284,430 $2,121,320 COMPLETE 138 3.42 3.42200299 30581 50766 OGE OK Line - Park Lane - Ahloso - Harden City - Frisco - Lula 69/138 kV Ckt 1 Frisco - Lula 138 kV Ckt 1 Voltage Conversion Regional Reliability 9/1/2016 6/1/2015 9/18/2014 2014 ITPNT $6,749,202 2014 $7,268,152 $6,749,202 COMPLETE 138 8.3 8.3200247 30582 50738 OGE OK Device - Wildhorse 69 kV Wildhorse 69 kV Cap Bank Regional Reliability 5/19/2017 6/1/2017 2/19/2014 2014 ITPNT $740,254 2014 $797,173 $740,254 COMPLETE 69200242 30584 50739 WR KS Line - Montgomery - Sedan 69 kV Ckt 1 Elk Junction - Montgomery 69 kV Ckt 1 Rebuild Zonal Reliability 6/1/2018 6/1/2018 2/19/2014 2014 ITPNT $16,110,343 2016 $16,513,102 $16,110,343 ON SCHEDULE < 4 69 7.9200242 30584 50740 WR KS Line - Montgomery - Sedan 69 kV Ckt 1 Elk Junction - Sedan 69 kV Ckt 1 Rebuild Zonal Reliability 12/31/2019 6/1/2018 2/19/2014 2014 ITPNT $19,015,228 2016 $19,490,609 $19,015,228 DELAY ‐ MITIGATION 69 19200320 30588 50745 OPPD NE Multi - Fremont - S991 E 161/69 kV Ckt 1 Fremont 161/69 kV Transformer Ckt 1 Regional Reliability 10/1/2018 6/1/2016 2/18/2015 2015 ITPNT $2,416,277 2015 $2,538,601 $2,416,277 DELAY ‐ MITIGATION 161/69200320 30588 50746 OPPD NE Multi - Fremont - S991 E 161/69 kV Ckt 1 Fremont - S991 E 69 kV Ckt 1 Regional Reliability 10/1/2018 6/1/2016 2/18/2015 2015 ITPNT $3,606,519 2015 $3,789,099 $3,606,519 DELAY ‐ MITIGATION 161/69 3200320 30588 50747 OPPD NE Multi - Fremont - S991 E 161/69 kV Ckt 1 S1226 161kV Ckt 1 Regional Reliability 10/1/2018 6/1/2016 2/18/2015 2015 ITPNT $29,069,150 2015 $30,540,776 $29,069,150 DELAY ‐ MITIGATION 161 17

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200258 30590 50748 OPPD NE Multi - S906 - S912 69 kV S906 - S924 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2019 2/19/2014 2014 ITPNT $1,360,327 2014 $1,464,923 $1,360,327 ON SCHEDULE < 4 69 1.34200258 30590 50749 OPPD NE Multi - S906 - S912 69 kV S924 - S912 69 kV Ckt 1 Terminal Upgrades Regional Reliability 6/1/2018 6/1/2019 2/19/2014 2014 ITPNT $69,679 2014 $75,037 $69,679 ON SCHEDULE < 4 69200294 30596 50757 NPPD NE Multi - Broken Bow Wind - Ord 115 kV Ckt 1 Broken Bow Wind - Ord 115 kV Ckt 1 Regional Reliability 3/1/2018 6/1/2014 8/26/2014 2014 ITPNT $34,182,113 2014 $36,810,397 $28,018,664 DELAY ‐ MITIGATION 115 42200294 30596 50760 NPPD NE Multi - Broken Bow Wind - Ord 115 kV Ckt 1 North Loup - Ord 115 kV Ckt 1 Regional Reliability 6/1/2018 6/1/2014 8/26/2014 2014 ITPNT $411,258 2014 $442,880 $516,009 DELAY ‐ MITIGATION 115200392 30597 50758 OGE OK Multi - Knob Hill - Lane - Noel 138 kV Ckt 1 Knob Hill - Lane - Noel 138 kV Ckt 1 Regional Reliability 3/31/2018 6/1/2017 5/17/2016 2016 ITPNT $4,009,000 2016 $4,109,225 $4,009,000 DELAY ‐ MITIGATION 138 0.09200397 30597 51030 WFEC OK Multi - Knob Hill - Lane - Noel 138 kV Ckt 1 Knob Hill - Noel 138 kV Ckt 1 Terminal Upgrades Regional Reliability 6/1/2017 6/1/2017 5/17/2016 2016 ITPNT $450,000 DELAY ‐ MITIGATION 138200361 30598 50759 AEP TX Device - Letourneau 69 kV Cap Bank Letourneau 69 kV Cap Bank Regional Reliability 6/26/2017 6/1/2017 12/11/2015 2016 ITPNT $1,409,347 2016 $1,444,581 $1,409,347 COMPLETE 69200269 30612 50786 OGE OK HEFNER - TULSA 138KV CKT 1 Hefner - Tulsa 138 kV Ckt 1 Transmission Service 6/1/2019 6/1/2019 7/1/2014 SPP-2012-AG1-AFS-7 $1,131,409 2014 $1,218,404 $1,131,409 ON SCHEDULE < 4 138 1.25200256 30616 50794 SPS NM Sub - Curry County 115 kV Curry County Interchange 115 kV Regional Reliability 4/30/2018 6/1/2018 2/19/2014 2014 ITPNT $813,381 2014 $875,922 $2,460,311 ON SCHEDULE < 4 115200310 30619 50802 AEP OK Line - Darlington - Roman Nose 138 kV Ckt 1 Darlington - Roman Nose 138 kV Ckt 1 (AEP) High Priority 6/29/2017 6/1/2015 12/2/2014 HPILS $11,652,107 2014 $12,548,045 $11,652,107 COMPLETE 138 14.25200311 30619 51117 OGE OK Line - Darlington - Roman Nose 138 kV Ckt 1 Darlington - Roman Nose 138 kV Ckt 1 (OGE) High Priority 12/15/2016 6/1/2015 12/2/2014 HPILS $12,701,091 2014 $13,677,686 $12,701,091 COMPLETE 138 13.2200311 30622 50805 OGE OK Multi - Knipe - SW Station - Linwood & Warwick Tap 138 kV Ckt 1 SW Station - Warwick Tap 138 kV Ckt 1 High Priority 6/1/2018 6/1/2018 12/2/2014 HPILS $12,767,120 2014 $13,748,792 $12,767,120 ON SCHEDULE < 4 138 13200311 30622 50806 OGE OK Multi - Knipe - SW Station - Linwood & Warwick Tap 138 kV Ckt 1 Linwood - SW Station 138 kV Ckt 1 High Priority 6/1/2018 6/1/2018 12/2/2014 HPILS $9,899,440 2014 $10,660,614 $9,899,440 ON SCHEDULE < 4 138 18200311 30622 50807 OGE OK Multi - Knipe - SW Station - Linwood & Warwick Tap 138 kV Ckt 1 Knipe - SW Station 138 kV Ckt 1 High Priority 6/1/2018 6/1/2018 12/2/2014 HPILS $8,218,020 2014 $8,849,909 $8,218,020 ON SCHEDULE < 4 138 5200397 30628 50813 WFEC OK Device - Freedom 69 kV Cap Bank Freedom 69 kV Cap Bank Regional Reliability 9/29/2015 6/1/2015 5/17/2016 2016 ITPNT $237,000 $330,386 COMPLETE 69200284 30635 50817 WFEC OK Device - Eagle Chief 69 kV Eagle Chief 69 kV Cap Bank High Priority 6/1/2015 6/1/2015 5/19/2014 HPILS $190,000 2014 $204,609 $237,000 COMPLETE 69200309 30637 50851 SPS NM Multi - Hobbs - Kiowa 345 kV Ckt 1 Kiowa 345 kV Substation High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $11,249,526 2014 $12,114,509 $10,383,515 ON SCHEDULE < 4 345200309 30637 50875 SPS NM Multi - Hobbs - Kiowa 345 kV Ckt 1 Hobbs - Kiowa 345 kV Ckt 1 High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $59,808,956 2014 $64,407,704 $48,383,526 ON SCHEDULE < 4 345 47.24200309 30638 50819 SPS NM Multi - Kiowa - North Loving - China Draw 345/115 kV Ckt 1 China Draw - North Loving 345 kV Ckt 1 High Priority 6/1/2018 6/1/2018 12/3/2014 HPILS $19,255,234 2014 $20,735,781 $22,256,315 ON SCHEDULE < 4 345 18.2200309 30638 50820 SPS NM Multi - Kiowa - North Loving - China Draw 345/115 kV Ckt 1 Kiowa - North Loving 345 kV Ckt 1 High Priority 6/1/2018 6/1/2018 12/3/2014 HPILS $25,716,516 2014 $27,693,875 $30,570,481 ON SCHEDULE < 4 345 20.4200309 30638 50849 SPS NM Multi - Kiowa - North Loving - China Draw 345/115 kV Ckt 1 China Draw 345/115 kV Ckt 1 Transformer High Priority 6/1/2018 6/1/2018 12/3/2014 HPILS $4,649,045 2014 $5,006,513 $4,723,246 ON SCHEDULE < 4 345/115200309 30638 50850 SPS NM Multi - Kiowa - North Loving - China Draw 345/115 kV Ckt 1 China Draw 345 kV Ckt 1 Terminal Upgrades High Priority 6/1/2018 6/1/2018 12/3/2014 HPILS $4,172,734 2014 $4,493,578 $4,666,983 ON SCHEDULE < 4 345200309 30638 50852 SPS NM Multi - Kiowa - North Loving - China Draw 345/115 kV Ckt 1 North Loving 345/115 kV Ckt 1 Transformer High Priority 6/1/2018 6/1/2018 12/3/2014 HPILS $5,950,217 2014 $6,407,733 $5,551,820 ON SCHEDULE < 4 345/115200309 30638 50854 SPS NM Multi - Kiowa - North Loving - China Draw 345/115 kV Ckt 1 North Loving 345 kV Terminal Upgrades High Priority 6/1/2018 6/1/2018 12/3/2014 HPILS $7,873,653 2014 $8,479,063 $4,688,295 ON SCHEDULE < 4 345

200309 30639 50862 SPS NM Multi - Potash Junction - Road Runner 345 kV Conv. and Transformers at Kiowa and Road Runner Road Runner 345/115 kV Ckt 1 Transformer High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $3,989,689 2014 $4,296,459 $6,471,987 ON SCHEDULE < 4 345/115

200309 30639 50863 SPS NM Multi - Potash Junction - Road Runner 345 kV Conv. and Transformers at Kiowa and Road Runner Road Runner 345 kV Substation Conversion High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $11,569,711 2014 $12,459,313 $8,118,914 ON SCHEDULE < 4 345

200309 30639 50868 SPS NM Multi - Potash Junction - Road Runner 345 kV Conv. and Transformers at Kiowa and Road Runner Kiowa 345/115 kV Ckt 1 Transformer High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $5,443,140 2014 $5,861,666 $6,824,687 ON SCHEDULE < 4 345/115

200309 30639 50871 SPS NM Multi - Potash Junction - Road Runner 345 kV Conv. and Transformers at Kiowa and Road Runner Kiowa - Potash Junction 345/115 kV Ckt 1 High Priority 4/30/2018 6/1/2018 12/3/2014 HPILS $2,176,451 2014 $2,343,800 $2,575,436 ON SCHEDULE < 4 345 2

200335 30644 50827 MKEC KS Line - Anthony - Harper 138 kV Ckt 1 Anthony - Harper 138 kV Ckt 1 High Priority 2/18/2018 6/1/2018 2/18/2015 HPILS $13,253,238 2014 $14,272,288 $11,949,636 ON SCHEDULE < 4 138 14.8200276 30645 50828 MKEC KS Line - Harper - Rago 138 kV Ckt 1 Harper - Rago 138 kV Ckt 1 High Priority 2/18/2018 6/1/2015 5/19/2014 HPILS $11,475,555 2016 $11,762,444 $12,625,134 DELAY ‐ MITIGATION 138 12.5200370 30649 50881 SPS NM Multi - Andrews 230/115 kV Transformer and Andrews - NEF 115 kV Ckt 1 Andrews 230/115 kV Ckt 1 Transformer High Priority 4/4/2016 6/1/2015 2/12/2016 HPILS $10,671,660 2016 $10,938,452 $11,500,000 COMPLETE 230/115 0.1200282 30649 50882 SPS NM Multi - Andrews 230/115 kV Transformer and Andrews - NEF 115 kV Ckt 1 Andrews - NEF 115 kV Ckt 1 High Priority 4/4/2016 6/1/2015 5/19/2014 HPILS $3,523,472 2014 $3,794,394 $3,523,472 $3,031,564 COMPLETE 115 2.1200371 30666 50864 SPS NM Device - China Draw and Road Runner 115 kV SVC China Draw 115 kV SVC Regional Reliability 6/8/2016 4/1/2015 2/12/2016 2015 ITPNT $25,925,187 2015 $27,237,650 $25,925,187 COMPLETE 115200371 30666 51132 SPS NM Device - China Draw and Road Runner 115 kV SVC Road Runner 115 kV SVC Regional Reliability 4/1/2016 4/1/2015 2/12/2016 2015 ITPNT $28,918,070 2015 $30,382,047 $28,918,070 COMPLETE 115200282 30672 50874 SPS NM Multi - Dollarhide - Toboso Flats 115 kV Dollarhide - Toboso Flats 115 kV Ckt 1 High Priority 6/1/2018 6/1/2018 5/19/2014 HPILS $5,062,341 2014 $5,451,588 $5,062,341 ON SCHEDULE < 4 115 7.4200282 30675 50869 SPS NM Multi - China Draw - Yeso Hills 115 kV China Draw - Yeso Hills 115 kV Ckt 1 High Priority 6/1/2021 6/1/2018 5/19/2014 HPILS $14,583,586 2014 $15,704,927 $14,729,995 ON SCHEDULE < 4 115 18.4200282 30675 50988 SPS NM Multi - China Draw - Yeso Hills 115 kV Yeso Hills 115 kV Substation High Priority 6/1/2021 6/1/2018 5/19/2014 HPILS $1,046,485 2014 $1,126,950 $1,046,485 ON SCHEDULE < 4 115200277 30678 50889 NPPD NE XFR - Thedford 345/115 kV Thedford 345/115 kV Transformer High Priority 10/1/2019 6/1/2016 5/19/2014 HPILS $9,306,000 2014 $10,021,544 $9,306,001 DELAY ‐ MITIGATION 345/115200277 30678 51002 NPPD NE XFR - Thedford 345/115 kV Thedford 345 kV Terminal Upgrades High Priority 10/1/2019 6/1/2016 5/19/2014 HPILS $930,800 2014 $1,002,370 $930,800 DELAY ‐ MITIGATION 345200313 30688 50915 OGE OK Line - Park Lane - Seminole 138 kV Terminal Upgrades Park Lane 138 kV Terminal Upgrades Transmission Service 1/29/2016 6/1/2015 1/30/2015 SPP-2012-AG2-AFS-8 $89,100 2015 $93,611 $89,100 $40,999 COMPLETE 138200457 30690 50918 SPS TX XFR - Plant X 230/115 kV Ckt 2 Plant X 230/115 kV Ckt 2 Transformer Regional Reliability 6/1/2022 5/15/2017 SPP-2016-AG1-AFS-3 $14,278,278 ON SCHEDULE < 4 230/115200395 30692 50920 SPS TX XFR - Seminole 230/115 kV #1 and #2 Seminole 230/115 kV #1 Transformer Economic 11/14/2019 6/1/2017 5/17/2016 2016 ITPNT $3,621,405 2016 $3,711,940 $3,621,405 DELAY ‐ MITIGATION 230/115200395 30692 50921 SPS TX XFR - Seminole 230/115 kV #1 and #2 Seminole 230/115 kV #2 Transformer Economic 5/14/2019 6/1/2017 5/17/2016 2016 ITPNT $3,621,405 2016 $3,711,940 $3,621,405 DELAY ‐ MITIGATION 230/115200421 30693 50922 SPS TX XFR - Wolfforth 230/115 kV Ckt 1 Transformer Wolfforth 230/115 kV Ckt 1 Transformer Regional Reliability 1/12/2017 SPP-2015-AG2-AFS-3 $3,510,969 ON SCHEDULE < 4 230/115200282 30694 50877 SPS NM Multi - Ponderosa - Ponderosa Tap 115 kV Ponderosa 115 kV Substation High Priority 6/1/2017 6/1/2018 5/19/2014 HPILS $996,485 2014 $1,073,105 $972,364 ON SCHEDULE < 4 115200282 30694 50879 SPS NM Multi - Ponderosa - Ponderosa Tap 115 kV Ponderosa Tap 115 kV Substation High Priority 6/1/2017 6/1/2018 5/19/2014 HPILS $4,174,446 2014 $4,495,422 $4,250,000 ON SCHEDULE < 4 115 0.2200411 30694 50923 SPS NM Multi - Ponderosa - Ponderosa Tap 115 kV Ponderosa - Ponderosa Tap 115 kV Ckt 1 High Priority 6/1/2017 6/1/2018 8/17/2016 HPILS $8,030,702 2014 $8,648,188 $5,000,000 ON SCHEDULE < 4 115 9.3200309 30695 50925 SPS NM Multi - Livingston Ridge - Sage Brush - Cardinal 115 kV Sage Brush 115 kV Substation High Priority 12/16/2016 6/1/2018 12/3/2014 HPILS $3,822,672 2014 $4,116,600 $2,472,695 ON SCHEDULE < 4 115200436 30695 50926 SPS NM Multi - Livingston Ridge - Sage Brush - Cardinal 115 kV Livingston Ridge - Sage Brush 115 kV Ckt 1 High Priority 11/30/2017 6/1/2018 2/22/2017 HPILS $13,187,417 2016 $13,517,102 $11,510,000 ON SCHEDULE < 4 115 13.9200309 30695 50951 SPS NM Multi - Livingston Ridge - Sage Brush - Cardinal 115 kV Cardinal 115 kV Substation High Priority 12/15/2016 6/1/2018 12/3/2014 HPILS $6,115,613 2014 $6,585,846 $6,025,000 ON SCHEDULE < 4 115 0.2200436 30695 50967 SPS NM Multi - Livingston Ridge - Sage Brush - Cardinal 115 kV Cardinal - Sage Brush 115 kV Ckt 1 High Priority 12/15/2016 6/1/2018 2/22/2017 HPILS $9,244,612 2014 $9,955,436 $8,120,000 ON SCHEDULE < 4 115 17.5200420 30699 50943 SPS TX Line - Northwest - Rolling Hills 115 kV Ckt 1 Northwest - Rolling Hills 115 kV Rebuild Ckt 1 Regional Reliability 6/1/2021 6/1/2021 1/12/2017 SPP-2015-AG1-AFS-6 $4,514,434 ON SCHEDULE < 4 115 7.2200365 30708 50954 SPS NM Line - Ochoa - Ponderosa Tap 115 kV Ckt 1 Rebuild Ochoa - Ponderosa Tap 115 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2018 1/12/2016 SPP-2014-AG1-AFS-6 $7,032,376 2016 $7,208,185 $8,200,000 ON SCHEDULE < 4 115200309 30717 50870 SPS NM Line - Hopi Sub - North Loving - China Draw 115 kV Ckt 1 Hopi Sub - North Loving 115 kV Ckt 1 High Priority 5/25/2015 6/1/2015 12/3/2014 HPILS $9,980,879 2014 $10,748,315 $11,345,995 $3,566,068 COMPLETE 115 9.5200309 30717 50883 SPS NM Line - Hopi Sub - North Loving - China Draw 115 kV Ckt 1 China Draw - North Loving 115 kV Ckt 1 High Priority 5/25/2015 6/1/2015 12/3/2014 HPILS $13,283,227 2014 $14,304,583 $10,291,637 $17,588,398 COMPLETE 115 19.7200306 30731 50990 AEP TX Line - Mt. Pleasant - West Mt. Pleasant 69 kV Ckt 1 Mt Pleasant - West Mt Pleasant 69 kV Ckt 1 Rebuild Regional Reliability 4/20/2015 6/1/2015 11/24/2014 DPA-2013-SEP-351 $4,715,419 2015 $4,954,137 $7,381,799 COMPLETE 69 2.72200362 30732 50991 MKEC KS Multi - Anthony - Bluff City - Caldwell - Mayfield - Milan - Viola 138 kV Ckt 1 Anthony - Bluff City 138 kV Ckt 1 High Priority 6/1/2018 6/1/2015 12/21/2015 HPILS $17,226,557 2016 $17,657,221 $13,533,878 DELAY ‐ MITIGATION 138 14.8200362 30732 50993 MKEC KS Multi - Anthony - Bluff City - Caldwell - Mayfield - Milan - Viola 138 kV Ckt 1 Bluff City - Caldwell 138 kV Ckt 1 High Priority 6/1/2018 6/1/2015 12/21/2015 HPILS $9,378,604 2016 $9,613,069 $9,053,898 DELAY ‐ MITIGATION 138 15.2200362 30732 50994 MKEC KS Multi - Anthony - Bluff City - Caldwell - Mayfield - Milan - Viola 138 kV Ckt 1 Caldwell - Mayfield 138 kV Ckt 1 High Priority 6/1/2018 6/1/2015 12/21/2015 HPILS $7,527,006 2016 $7,715,181 $7,400,863 DELAY ‐ MITIGATION 138 10200362 30732 50995 MKEC KS Multi - Anthony - Bluff City - Caldwell - Mayfield - Milan - Viola 138 kV Ckt 1 Mayfield - Milan 138 kV Ckt 1 High Priority 6/1/2018 6/1/2015 12/21/2015 HPILS $6,608,453 2016 $6,773,664 $6,691,298 DELAY ‐ MITIGATION 138 6.6200362 30732 51394 MKEC KS Multi - Anthony - Bluff City - Caldwell - Mayfield - Milan - Viola 138 kV Ckt 1 Viola 138 kV Line Tap (MKEC) High Priority 6/1/2018 6/1/2015 12/21/2015 HPILS $4,414,629 2016 $4,524,995 $3,640,327 DELAY ‐ MITIGATION 0.3 5.1200363 30732 51395 WR KS Multi - Anthony - Bluff City - Caldwell - Mayfield - Milan - Viola 138 kV Ckt 1 Viola 138 kV Line Tap (WR) High Priority 6/1/2018 6/1/2015 12/21/2015 HPILS $3,915,388 2016 $4,013,273 $3,915,388 DELAY ‐ MITIGATION200272 30747 51014 AEP OK Line - Grady - Round Creek 138 kV Ckt 1 Grady - Round Creek 138 kV Ckt 1 High Priority 11/5/2015 6/1/2015 5/19/2014 HPILS $12,132,497 2014 $13,065,372 $12,132,497 COMPLETE 138200272 30748 51015 AEP OK Line - Grady - Phillips Gas 138 kV Ckt 1 and 2 Grady - Phillips 138 kV Ckt 1 and 2 High Priority 12/31/2014 6/1/2015 5/19/2014 HPILS $8,318,584 2014 $8,958,205 $8,318,584 COMPLETE 138 4200272 30750 51017 AEP OK Line - Stonewall - Wapanucka 138 kV Ckt 1 Stonewall - Wapanucka 138 kV Ckt 1 High Priority 12/31/2013 6/1/2015 5/19/2014 HPILS $8,934,149 2014 $9,621,101 $8,934,149 $7,200,874 COMPLETE 138 6.4200455 30755 50992 SPS TX XFR - Tuco 230/115 kV Ckt 1 Tuco 230/115 kV Ckt 1 Transformer Transmission Service 6/1/2018 6/1/2018 5/12/2017 2017 ITPNT $3,800,415 2015 $3,992,811 $200,000 ON SCHEDULE < 4 230/115200282 30756 50873 SPS NM Multi - Battle Axe - Road Runner 115 kV Battle Axe - Road Runner 115 kV Ckt 1 High Priority 11/12/2015 6/1/2018 5/19/2014 HPILS $13,816,310 2014 $14,878,655 $8,143,031 COMPLETE 115 18.9200282 30756 50968 SPS NM Multi - Battle Axe - Road Runner 115 kV Battle Axe 115 kV Substation High Priority 12/4/2015 6/1/2018 5/19/2014 HPILS $2,964,499 2014 $3,192,441 $3,006,810 COMPLETE 115200298 30761 51033 AEP LA Line - Cedar Grove - South Shreveport 138 kV Cedar Grove - South Shreveport 138 kV Transmission Service 6/1/2020 6/1/2020 9/30/2014 SPP-2010-AGP1-AFS-8 $6,566,218 2014 $7,071,099 $6,566,218 ON SCHEDULE < 4 138200339 30762 51034 AEP LA Multi - Ellerbe Road - Lucas 69 kV Ellerbe Road - Lucas 69 kV Ckt 1 Rebuild Regional Reliability 3/1/2019 3/1/2019 3/17/2015 DPA-2013-MAR-296 $6,629,465 2015 $6,965,081 $6,629,465 ON SCHEDULE < 4 69 3.2200339 30762 51035 AEP LA Multi - Ellerbe Road - Lucas 69 kV Ellerbe Road - Lucas 69 kV Terminal Upgrades Regional Reliability 3/1/2019 3/1/2019 3/17/2015 DPA-2013-MAR-296 $652,658 2015 $685,699 $652,658 ON SCHEDULE < 4 69200262 30766 51039 SPS TX XFR - Yoakum County Interchange 230/115 kV Ckts 1 and 2 Yoakum County Interchange 230/115 kV Ckt 1 Transformer Transmission Service 3/15/2019 6/1/2019 4/9/2014 SPP-2011-AG3-AFS-11 $3,632,101 2014 $3,911,376 $3,632,101 ON SCHEDULE < 4 230/115200262 30766 51050 SPS TX XFR - Yoakum County Interchange 230/115 kV Ckts 1 and 2 Yoakum County Interchange 230/115 kV Ckt 2 Transformer Regional Reliability 5/31/2019 6/1/2019 4/9/2014 SPP-2011-AG3-AFS-11 $3,432,506 2014 $3,696,434 $3,432,506 ON SCHEDULE < 4 230/115200272 30770 51047 AEP OK Sub - Ellis 138 kV Ellis 138 kV Substation High Priority 6/1/2013 6/1/2015 5/19/2014 HPILS $4,100,000 2014 $4,415,252 $4,100,000 $4,086,696 COMPLETE 138200286 30771 51048 MIDW KS Multi - Midwest Pump - Midwest Pump Tap 115 kV Ckt 1 Midwest Pump Tap 115 kV Substation High Priority 7/2/2016 6/1/2015 5/19/2014 HPILS $4,477,251 2014 $4,821,509 $4,477,251 COMPLETE 115200286 30771 51049 MIDW KS Multi - Midwest Pump - Midwest Pump Tap 115 kV Ckt 1 Midwest Pump - Midwest Pump Tap 115 kV Ckt 1 High Priority 7/2/2016 6/1/2015 5/19/2014 HPILS $2,443,469 2014 $2,631,349 $2,443,469 COMPLETE 115 6

30781 51051 NPPD Sub - Rosemont 115kV Substation GEN-2008-123N Addition Rosemont 115kV Substation Generation Interconnection 11/1/2017 $5,950,000 ON SCHEDULE < 4 11530781 71940 NPPD Sub - Rosemont 115kV Substation GEN-2008-123N Addition Rosemont 115kV Substation GEN-2008-123N Addition (TOIF) Generation Interconnection 11/1/2017 $1,880,000 ON SCHEDULE < 430786 51069 NPPD Sub - Dixon County 230kV Dixon County 230kV Substation Generation Interconnection 11/1/2018 $5,750,000 ON SCHEDULE < 4 23030786 51577 NPPD Sub - Dixon County 230kV Dixon County 230kV Substation (TOIF) Generation Interconnection 11/1/2018 $450,000 ON SCHEDULE < 4 23030787 51070 NPPD Line - Twin Church - Dixon County 230kV Ckt 1 Twin Church - Dixon County 230kV Line Upgrade Generation Interconnection 11/1/2018 $100,000 ON SCHEDULE < 4 230

200382 30809 51096 AEP OK Line - Keystone Dam - Wekiwa 138 kV Ckt 1 Rebuild Keystone Dam - Wekiwa 138 kV Ckt 1 Rebuild Regional Reliability 6/1/2021 6/1/2021 4/12/2016 SPP-2014-AG1-AFS-6 $4,319,501 2016 $4,427,489 $4,319,501 ON SCHEDULE > 4 138 2 2 2200395 30817 51109 SPS TX Line - Canyon West - Dawn - Panda - Deaf Smith 115 kV Ckt 1 Rebuild Canyon West - Dawn 115 kV Ckt 1 Rebuild Regional Reliability 3/9/2018 6/1/2017 5/17/2016 2016 ITPNT $9,756,809 2016 $10,000,729 $6,519,222 DELAY ‐ MITIGATION 115 13.7200395 30817 51110 SPS TX Line - Canyon West - Dawn - Panda - Deaf Smith 115 kV Ckt 1 Rebuild Dawn - Panda 115 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2017 5/17/2016 2016 ITPNT $5,901,274 2016 $6,048,806 $4,212,298 DELAY ‐ MITIGATION 115 8.4200395 30817 51111 SPS TX Line - Canyon West - Dawn - Panda - Deaf Smith 115 kV Ckt 1 Rebuild Deaf Smith - Panda 115 kV Ckt 1 Rebuild Regional Reliability 12/15/2018 6/1/2017 5/17/2016 2016 ITPNT $3,501,534 2016 $3,589,072 $2,055,714 DELAY ‐ MITIGATION 115 3.5

200297 30820 51112 SPS TX Carlisle Interchange - Tuco Interchange 230 kV Ckt 1 Carlisle Interchange - Tuco Interchange 230 kV Ckt 1 Terminal Upgrade Transmission Service 9/1/2016 10/1/2015 5/5/2015 SPP-2012-AG3-AFS-9 $362,250 2015 $380,589 $289,000 DELAY ‐ MITIGATION 230

200282 30824 50821 SPS NM XFR - Potash Junction 230/115 kV Ckt 1 Potash Junction 230/115 kV Ckt 1 High Priority 4/15/2016 6/1/2015 5/19/2014 HPILS $3,508,346 2014 $3,778,105 $3,765,743 $3,765,743 COMPLETE 230/115200411 30825 50931 SPS NM Line - China Draw - Wood Draw 115 kV Ckt 1 China Draw - Wood Draw 115 kV Ckt 1 High Priority 6/15/2017 6/1/2018 8/17/2016 HPILS $14,200,000 ON SCHEDULE < 4 115 14200330 30838 51133 OPPD NE XFR - Sub 3459 345/161 kV Ckt 1 Transformer Sub 3459 345/161 kV Transformer Regional Reliability 6/1/2018 6/1/2019 2/18/2015 2015 ITP10 $6,588,939 2015 $6,922,505 $6,588,939 ON SCHEDULE < 4 345/161200330 30838 51136 OPPD NE XFR - Sub 3459 345/161 kV Ckt 1 Transformer Sub 3459 345 kV Terminal Upgrades Regional Reliability 6/1/2018 6/1/2019 2/18/2015 2015 ITP10 $3,604,757 2015 $3,787,248 $3,604,757 ON SCHEDULE < 4 345200416 30843 51139 OGE OK Sub - Cimarron - Draper 345 kV Terminal Upgrades Cimarron - Draper 345 kV Terminal Upgrades Regional Reliability 12/1/2017 4/1/2019 11/14/2016 2015 ITP10 $1,500,000 2015 $1,575,938 $1,500,000 ON SCHEDULE < 4 345200395 30844 51140 SPS TX Sub - Amoco - Sundown 230 kV Terminal Upgrades Amoco - Sundown 230 kV Terminal Upgrades Economic 12/14/2018 1/1/2019 5/17/2016 2016 ITPNT $1,771,222 2016 $1,815,503 $600,808 ON SCHEDULE < 4 230200316 30848 51146 GRDA OK Sub - Claremore 161 kV Terminal Upgrades Claremore 161 kV Terminal Upgrades Regional Reliability 11/17/2017 6/1/2018 2/18/2015 2015 ITPNT $11,200 2015 $11,767 $11,200 COMPLETE 161200328 30850 51151 KCPL MO Line - Iatan - Stranger 345 kV Ckt 1 Voltage Conversion Iatan 345 kV Voltage Conversion Economic 6/1/2018 1/1/2019 2/25/2015 2015 ITP10 $3,263,000 2015 $3,428,189 $3,263,000 ON SCHEDULE < 4 345 18200337 30850 51283 GMO MO Line - Iatan - Stranger 345 kV Ckt 1 Voltage Conversion Iatan - Stranger Creek 345 kV Ckt 1 Voltage Conversion (GMO) Economic 6/1/2018 1/1/2019 2/25/2015 2015 ITP10 $6,237,000 2015 $6,552,748 $6,237,000 ON SCHEDULE < 4 345200338 30850 51284 WR KS Line - Iatan - Stranger 345 kV Ckt 1 Voltage Conversion Iatan - Stranger Creek 345 kV Ckt 1 Voltage Conversion (WR) Economic 6/1/2018 1/1/2019 2/25/2015 2015 ITP10 $28,010,000 2015 $29,428,006 $28,010,000 ON SCHEDULE < 4 345 10.83200336 30859 51163 SPS NM Device - Plains Interchange 115 kV Cap Bank Plains Interchange 115 kV Cap Bank Regional Reliability 3/31/2018 6/1/2019 2/26/2015 2015 ITP10 $1,217,275 2015 $1,278,900 $1,350,000 ON SCHEDULE < 4 115200326 30866 51170 SPS TX Sub - Amarillo South 230 kV Terminal Upgrades Amarillo South 230 kV Terminal Upgrades Regional Reliability 4/1/2020 4/1/2020 2/18/2015 2015 ITPNT $31,198 2015 $32,777 $31,198 ON SCHEDULE < 4 230200314 30873 51187 AEP OK Line - Southwestern Station - Carnegie 138kV Ckt 1 Rebuild Southwestern Station - Carnegie 138 kV Ckt 1 Rebuild Regional Reliability 7/6/2017 6/1/2016 2/18/2015 2015 ITPNT $15,821,763 2015 $16,622,740 $9,397,311 COMPLETE 138 16.52 138200326 30875 51189 SPS NM Line - PCA Interchange - Quahada 115 kV Ckt 1 Rebuild PCA Interchange - Quahada 115 kV Ckt 1 Rebuild Regional Reliability 2/25/2017 6/1/2016 2/18/2015 2015 ITPNT $7,264,308 2015 $7,632,064 $9,000,000 DELAY ‐ MITIGATION 115 12.1200319 30876 51190 OGE OK Line - Little River - Maud 69 kV Ckt 1 Rebuild Little River - Maud 69 kV Ckt 1 Rebuild Regional Reliability 10/21/2016 6/1/2015 2/18/2015 2015 ITPNT $387,822 2015 $407,455 $361,871 $381,274 COMPLETE 69 10.7200317 30881 51197 KCPL MO XFR - South Waverly - 161/69 kV Ckt 1 Transformer South Waverly 161/69 kV Ckt 1 Transformer Regional Reliability 5/31/2016 6/1/2015 2/18/2015 2015 ITPNT $2,000,000 2015 $2,101,250 $2,000,000 $1,399,924 CLOSED OUT 161/69200317 30881 51268 KCPL MO XFR - South Waverly - 161/69 kV Ckt 1 Transformer South Waverly 161 kV Terminal Upgrades Regional Reliability 5/31/2016 6/1/2015 2/18/2015 2015 ITPNT $280,000 2015 $294,175 $280,000 $227,040 CLOSED OUT 161200318 30883 51200 NPPD NE Multi - Bassett 115 kV Bassett 115 kV Substation Regional Reliability 6/1/2018 6/1/2016 2/18/2015 2015 ITPNT $5,163,000 2015 $5,424,377 $5,163,000 DELAY ‐ MITIGATION 115 0.1200318 30883 51277 NPPD NE Multi - Bassett 115 kV Bassett 115 kV Cap Bank Regional Reliability 6/1/2018 6/1/2016 2/18/2015 2015 ITPNT $902,000 2015 $947,664 $902,000 DELAY ‐ MITIGATION 115200319 30884 51202 OGE OK XFR - Stillwater 138/69 kV Ckt 1 Transformer Stillwater 138/69 kV Ckt 1 Transformer Regional Reliability 6/1/2019 6/1/2019 2/18/2015 2015 ITPNT $3,989,023 2015 $4,190,967 $2,786,625 RE‐EVALUATION 138/69

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200319 30884 51269 OGE OK XFR - Stillwater 138/69 kV Ckt 1 Transformer Stillwater 138 kV Terminal Upgrades Regional Reliability 6/1/2019 6/1/2019 2/18/2015 2015 ITPNT $611,398 RE‐EVALUATION 138200326 30888 51206 SPS TX XFR - Lynn County 115/69 kV Ckt 1 Transformer Lynn County 115/69 kV Ckt 1 Transformer Regional Reliability 6/1/2019 6/1/2019 2/18/2015 2015 ITPNT $1,699,629 2015 $1,785,673 $2,302,251 ON SCHEDULE < 4 115/69200326 30888 51270 SPS TX XFR - Lynn County 115/69 kV Ckt 1 Transformer Lynn County 115 kV Terminal Upgrades Regional Reliability 6/1/2019 6/1/2019 2/18/2015 2015 ITPNT $0 ON SCHEDULE < 4 115200406 30889 51207 AEP LA Line - Linwood - South Shreveport 138kV Ckt 1 Rebuild Linwood - South Shreveport 138 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2017 8/17/2016 2016 ITPNT $5,919,107 DELAY ‐ MITIGATION 138 2.42200323 30891 51211 WR KS Sub - Benton 138 kV Terminal Upgrades Benton 138 kV Terminal Upgrades Regional Reliability 5/17/2016 6/1/2015 2/18/2015 2015 ITPNT $734,229 2015 $771,399 $824,836 $824,836 CLOSED OUT 138200326 30894 51214 SPS TX Device - Cargill 115 kV Cap Bank Cargill 115 kV Cap Bank Regional Reliability 11/30/2018 6/1/2019 2/18/2015 2015 ITPNT $1,262,485 2015 $1,326,398 $1,401,147 ON SCHEDULE < 4 115200314 30895 51215 AEP LA Line - Brooks Street - Edwards Street 69kV Ckt 1 Rebuild Brooks Street - Edwards Street 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2016 2/18/2015 2015 ITPNT $4,294,228 2015 $4,511,624 $4,294,228 DELAY ‐ MITIGATION 69 0.85200319 30900 51220 OGE OK Sub - Warner Tap 69 kV Terminal Upgrades Warner Tap 69 kV Terminal Upgrades Regional Reliability 10/1/2016 6/1/2015 2/18/2015 2015 ITPNT $2,565,000 2015 $2,694,853 $4,178,442 COMPLETE 69200343 30912 51235 SPS KS Multi - Walkemeyer Tap - Walkemeyer 345/115 kV Stevens Co. 345 kV Substation Regional Reliability 6/1/2018 6/1/2015 8/13/2015 2015 ITPNT $13,831,957 2015 $14,532,200 $15,276,827 DELAY ‐ MITIGATION 345 0.1200344 30912 51240 SEPC KS Multi - Walkemeyer Tap - Walkemeyer 345/115 kV Walkemeyer - Stevens Co. 115 kV Ckt 1 Regional Reliability 6/1/2018 6/1/2015 8/13/2015 2015 ITPNT $767,645 2015 $806,507 $1,219,321 DELAY ‐ MITIGATION 115 1200344 30912 51241 SEPC KS Multi - Walkemeyer Tap - Walkemeyer 345/115 kV Walkemeyer 115 kV Terminal Upgrades Regional Reliability 6/1/2018 6/1/2015 8/13/2015 2015 ITPNT $5,668,987 2015 $5,955,979 $7,086,075 DELAY ‐ MITIGATION 115200344 30912 51326 SEPC KS Multi - Walkemeyer Tap - Walkemeyer 345/115 kV Walkemeyer Tap 345 kV Substation (SEPC) Regional Reliability 6/1/2018 8/13/2015 2015 ITPNT $3,126,209 2017 $3,126,209 $3,642,129 DELAY ‐ MITIGATION 0.5200344 30912 51327 SEPC KS Multi - Walkemeyer Tap - Walkemeyer 345/115 kV Stevens Co. 345/115 kV Transformer Regional Reliability 6/1/2018 6/1/2015 8/13/2015 2015 ITPNT $11,695,379 2015 $12,287,458 $8,326,803 DELAY ‐ MITIGATION200343 30913 51237 SPS NM Multi - RIAC 115 kV Voltage Conversion RIAC 115 kV Voltage Conversion Regional Reliability 11/30/2018 6/1/2015 8/13/2015 2015 ITPNT $4,811,635 2015 $5,055,224 $5,278,168 DELAY ‐ MITIGATION 115 0.1 1.5200360 30914 50952 SPS NM Multi - Road Runner 115 kV Loop Rebuild IMC #1 Tap - Livingston Ridge 115 kV Ckt 1 Rebuild Regional Reliability 4/15/2019 6/1/2015 12/7/2015 2015 ITPNT $5,846,342 2015 $6,142,313 $5,700,000 DELAY ‐ MITIGATION 115 9.5 9.3200360 30914 50955 SPS NM Multi - Road Runner 115 kV Loop Rebuild Ponderosa Tap - Whitten 115 kV Ckt 1 Rebuild Regional Reliability 1/26/2018 6/1/2015 12/7/2015 2015 ITPNT $3,943,853 2015 $4,143,511 $2,280,000 DELAY ‐ MITIGATION 115 3.92200360 30914 50957 SPS NM Multi - Road Runner 115 kV Loop Rebuild Intrepid West - Potash Junction 115 kV Ckt 1 Rebuild Regional Reliability 4/15/2019 6/1/2015 12/7/2015 2015 ITPNT $3,196,240 2015 $3,358,050 $2,455,000 DELAY ‐ MITIGATION 115 1.5200360 30914 50958 SPS NM Multi - Road Runner 115 kV Loop Rebuild IMC #1 Tap - Intrepid West 115 kV Ckt 1 Rebuild Regional Reliability 4/15/2018 6/1/2015 12/7/2015 2015 ITPNT $3,121,473 2015 $3,279,498 $3,121,473 DELAY ‐ MITIGATION 115 3.9200360 30914 51131 SPS NM Multi - Road Runner 115 kV Loop Rebuild Byrd Tap - Monument Tap 115 kV Ckt 1 Rebuild Regional Reliability 11/16/2018 6/1/2015 12/7/2015 2015 ITPNT $3,163,083 2015 $3,323,214 $3,100,000 DELAY ‐ MITIGATION 115 4.6200360 30914 51245 SPS NM Multi - Road Runner 115 kV Loop Rebuild Cardinal - Targa 115 kV Ckt 1 Rebuild Regional Reliability 1/31/2018 6/1/2015 12/7/2015 2015 ITPNT $2,667,006 2015 $2,802,023 $2,435,548 DELAY ‐ MITIGATION 115 3200360 30914 51250 SPS NM Multi - Road Runner 115 kV Loop Rebuild National Enrichment Plant - Targa 115 kV Ckt 1 Regional Reliability 12/15/2018 6/1/2015 12/7/2015 2015 ITPNT $4,430,052 2015 $4,654,323 $4,704,602 DELAY ‐ MITIGATION 115 3200325 30916 51209 SEPC KS Sub - Buckner - Spearville 345 kV Terminal Upgrades Buckner - Spearville 345 kV Ckt 1 Terminal Upgrades Regional Reliability 7/20/2017 6/1/2015 2/18/2015 2015 ITPNT $2,437,937 2015 $2,561,358 $3,892,077 COMPLETE 345200394 30917 51271 SEPC KS Device - Ellsworth 115 kV Cap Bank Ellsworth 115 kV Cap Bank Regional Reliability 6/1/2018 6/1/2017 5/17/2016 2016 ITPNT $2,983,396 2016 $3,057,981 $2,687,615 DELAY ‐ MITIGATION 115200365 30918 51272 SPS NM Line - Byrd Tap - Cooper Ranch - Oil Center - Lea Road 115 kV Ckt 1 Rebuild Cooper Ranch - Oil Center 115 kV Ckt 1 Rebuild Regional Reliability 6/15/2021 6/1/2021 1/12/2016 SPP-2014-AG1-AFS-6 $3,044,258 2016 $3,120,364 $3,044,258 DELAY ‐ MITIGATION 2.6200365 30918 51273 SPS NM Line - Byrd Tap - Cooper Ranch - Oil Center - Lea Road 115 kV Ckt 1 Rebuild Byrd Tap - Cooper Ranch 115 kV Ckt 1 Rebuild Regional Reliability 6/15/2021 6/1/2021 1/12/2016 SPP-2014-AG1-AFS-6 $3,261,324 2016 $3,342,857 $3,791,000 DELAY ‐ MITIGATION 5.7200365 30918 51407 SPS NM Line - Byrd Tap - Cooper Ranch - Oil Center - Lea Road 115 kV Ckt 1 Rebuild Lea Road - Oil Center 115 kV Ckt 1 Rebuild Regional Reliability 6/15/2021 6/1/2021 1/12/2016 SPP-2014-AG1-AFS-6 $3,630,770 2016 $3,721,539 $3,333,000 DELAY ‐ MITIGATION 115 4.25200318 30921 51276 NPPD NE Line - Ainsworth - Ainsworth Wind 115 kV Ckt 1 Rebuild Ainsworth - Ainsworth Wind 115 kV Ckt 1 Rebuild Regional Reliability 6/1/2020 6/1/2020 2/18/2015 2015 ITPNT $200,000 2015 $210,125 $209,500 ON SCHEDULE < 4 115

30933 51291 SPS Sub - Crosby County Interchange - Floyd County Interchange 115kV Ckt 1 Crosby County Interchange - Floyd County Interchange 115kV Ckt 1 Generation Interconnection 11/6/2017 $4,043,580 ON SCHEDULE < 4 115

30933 51599 SPS Sub - Crosby County Interchange - Floyd County Interchange 115kV Ckt 1 Crosby County Interchange - Floyd County Interchange 115kV Ckt 1 (TOIF) Generation Interconnection 3/31/2017 $236,346 ON SCHEDULE < 4

30934 51292 NPPD Line - Hoskins - Dixon County 230kV Ckt 1 Hoskins - Dixon County 230kV Line Upgrade Generation Interconnection 11/1/2018 $500,000 ON SCHEDULE < 4 23030937 51299 SPS SUB - TUCO 230kV Switching Station GEN-2012-020 Addition TUCO 230kV Switching Station GEN-2012-020 Addition Generation Interconnection 4/30/2017 $1,500,377 ON SCHEDULE < 4 23030938 51300 ITCGP Sub - Clark County 345kV Switching Station GEN-2012-024 Addition Clark County 345kV Switching Station GEN-2012-024 Addition Generation Interconnection 4/19/2017 $1,940,084 $1,940,084 COMPLETE 34530938 51603 ITCGP Sub - Clark County 345kV Switching Station GEN-2012-024 Addition Clark County 345kV Switching Station GEN-2012-024 Addition (TOIF) Generation Interconnection 4/19/2017 $859,686 $859,686 COMPLETE30943 51306 BEPC ND Multi - AVS - Charlie Creek 345 kV AVS - Charlie Creek 345 kV Ckt 2 Regional Reliability 1/1/2016 12/1/2017 IS Integration Study $96,000,000 2014 $103,381,500 $96,000,000 $88,665,020 COMPLETE 34530943 51307 BEPC ND Multi - AVS - Charlie Creek 345 kV AVS 345 kV Substation Regional Reliability 6/1/2016 12/1/2017 IS Integration Study $3,000,000 2014 $3,230,672 $5,800,000 $3,194,872 COMPLETE 34530943 51308 BEPC ND Multi - AVS - Charlie Creek 345 kV Charlie Creek 345 kV Substation Regional Reliability 12/22/2015 12/1/2017 IS Integration Study $9,000,000 2014 $9,692,016 $9,000,000 $13,153,362 COMPLETE 34530944 51310 BEPC ND Multi - Charlie Creek - Judson - Williston 345/230 kV Charlie Creek - Judson 345 kV Ckt 1 Regional Reliability 12/22/2015 12/1/2017 IS Integration Study $103,000,000 2014 $110,919,734 $82,000,000 $95,382,067 COMPLETE 345 7530944 51311 BEPC ND Multi - Charlie Creek - Judson - Williston 345/230 kV Judson 345/230 kV Substation Regional Reliability 12/22/2015 12/1/2017 IS Integration Study $19,000,000 2014 $20,460,922 $27,000,000 $17,638,071 COMPLETE 34530944 51312 BEPC ND Multi - Charlie Creek - Judson - Williston 345/230 kV Judson - Williston 230 kV Ckt 1 Regional Reliability 12/22/2015 12/1/2017 IS Integration Study $2,400,000 2014 $2,584,538 $3,500,000 $2,686,818 COMPLETE 23030944 51313 BEPC ND Multi - Charlie Creek - Judson - Williston 345/230 kV Williston 230 kV Terminal Upgrades Regional Reliability 12/22/2015 12/1/2017 IS Integration Study $2,000,000 2014 $2,153,781 $2,000,000 $2,564,691 CLOSED OUT 23030945 51314 BEPC ND Multi - Judson - Tande - Neset 345/230 kV Judson - Tande 345 kV Ckt 1 Regional Reliability 10/31/2017 12/1/2017 IS Integration Study $86,000,000 2014 $92,612,594 $86,000,000 ON SCHEDULE < 4 345 5830945 51315 BEPC ND Multi - Judson - Tande - Neset 345/230 kV Tande 345/230 kV Substation Regional Reliability 10/31/2017 12/1/2017 IS Integration Study $18,000,000 2014 $19,384,031 $18,000,000 ON SCHEDULE < 4 34530945 51316 BEPC ND Multi - Judson - Tande - Neset 345/230 kV Neset - Tande 230 kV Ckt 1 Regional Reliability 10/31/2017 12/1/2017 IS Integration Study $3,000,000 2014 $3,230,672 $3,000,000 ON SCHEDULE < 4 230 230945 51317 BEPC ND Multi - Judson - Tande - Neset 345/230 kV Neset 230 kV Terminal Upgrades Regional Reliability 10/31/2017 12/1/2017 IS Integration Study $4,000,000 2014 $4,307,563 $4,000,000 ON SCHEDULE < 4 23030946 51318 BEPC SD Multi - Lower Brule - Witten 230 kV Lower Brule - Witten 230 kV Ckt 1 Regional Reliability 1/1/2018 12/1/2016 IS Integration Study $31,500,000 2014 $33,922,055 $31,500,000 DELAY ‐ MITIGATION 23030946 51319 BEPC SD Multi - Lower Brule - Witten 230 kV Lower Brule 230 kV Substation Regional Reliability 1/1/2018 12/1/2016 IS Integration Study $4,500,000 2014 $4,846,008 $4,500,000 DELAY ‐ MITIGATION 23030946 51320 BEPC SD Multi - Lower Brule - Witten 230 kV Lower Brule - Witten 230 kV Terminal Upgrades Regional Reliability 1/1/2018 12/1/2016 IS Integration Study $2,000,000 2014 $2,153,781 $2,000,000 DELAY ‐ MITIGATION 23030951 51331 NPPD Battle Creek – County Line – Antelope 115kV: Rebuild Antelope - County Line - 115kV Rebuild Generation Interconnection 3/31/2017 $2,047,174 COMPLETE30951 51340 NPPD Battle Creek – County Line – Antelope 115kV: Rebuild Battle Creek - County Line 115kV Rebuild Generation Interconnection 3/31/2017 $1,952,826 COMPLETE

200376 30952 51332 SEPC KS Device - Ingalls 115 kV Cap Bank Ingalls 115 kV Cap Bank Regional Reliability 4/10/2018 6/1/2017 7/12/2016 DPA-2015-MARCH-494 $6,126,015 DELAY ‐ MITIGATION 115 0.1200376 30953 51333 SEPC KS Device - Lane Scott 115 kV Cap Bank Lane Scott 115 kV Cap Bank Regional Reliability 4/10/2019 6/1/2017 7/12/2016 DPA-2015-MARCH-494 $3,852,343 DELAY ‐ MITIGATION 115

30956 51339 NPPD Multi - GEN-2013-032 Interconnection Work Antelope 115kV - Add terminal for GEN-2013-032 Generation Interconnection 5/1/2017 $2,300,000 ON SCHEDULE < 430956 51610 NPPD Multi - GEN-2013-032 Interconnection Work Antelope 115kV - Add terminal for GEN-2013-032 (TOIF) Generation Interconnection 5/1/2017 $700,000 ON SCHEDULE < 430957 51336 SPS SUB - Castro County 115kV - add terminal for GEN-2014-040 Castro County 115kV - add terminal for GEN-2014-040 Generation Interconnection 11/14/2016 $1,250,017 ON SCHEDULE < 430957 51612 SPS SUB - Castro County 115kV - add terminal for GEN-2014-040 Castro County 115kV - add terminal for GEN-2014-040 (TOIF) Generation Interconnection 10/28/2016 $260,000 ON SCHEDULE < 430959 51338 WR Sub - Tap Emporia Energy Center - Wichita 345kV (GEN-2014-001 Substation) Tap Emporia Energy Center - Wichita 345kV (GEN-2014-001 NU) Generation Interconnection 9/27/2019 $18,743,307 ON SCHEDULE < 430959 51360 WR Sub - Tap Emporia Energy Center - Wichita 345kV (GEN-2014-001 Substation) Tap Emporia Energy Center - Wichita 345kV (GEN-2014-001 TOIF) Generation Interconnection 9/27/2019 $600,000 ON SCHEDULE < 430962 51345 GRDA Multi - Interconnection Work for GEN-2013-028 GRDA3 345kV - Tonnece Relays Generation Interconnection 11/2/2016 $0 COMPLETE30962 51607 GRDA Multi - Interconnection Work for GEN-2013-028 GRDA3 345kV - Interconnection Substation for GEN-2013-028 (TOIF) Generation Interconnection 4/1/2017 $5,583,511 ON SCHEDULE < 430965 51598 ITCGP Sub - Clark County 345kV Switching Station GEN-2011-008 Addition Clark County 345kV Switching Station GEN-2011-008 Addition (TOIF) Generation Interconnection 10/7/2016 $767,163 $769,934 ON SCHEDULE < 430969 51356 OGE SUB - Border 345kV Substation - GEN-2011-049 Addition Border 345kV Substation - GEN-2011-049 Addition Generation Interconnection 4/1/2018 $2,554,395 ON SCHEDULE < 430969 51601 OGE SUB - Border 345kV Substation - GEN-2011-049 Addition Border 345kV Substation - GEN-2011-049 Addition (TOIF) Generation Interconnection 4/1/2018 $1,099,958 ON SCHEDULE < 4

200384 30971 51358 SPS TX Line - Cochran - Whiteface Tap 69 kV Ckt 1 Rebuild Cochran - Whiteface Tap 69 kV Ckt 1 Rebuild Regional Reliability 11/15/2018 6/1/2016 4/20/2016 DPA-2013-JUN-342 $2,254,282 2016 $2,310,639 $2,335,233 DELAY ‐ MITIGATION30973 51363 AEP Sub - Terry Road 345kV (Tap Lawton Eastside - Sunnyside 345kV) Terry Road 345kV Station (TOIF) Generation Interconnection 11/16/2016 $1,869,249 $2,021,716 COMPLETE30973 51364 AEP Sub - Terry Road 345kV (Tap Lawton Eastside - Sunnyside 345kV) Terry Road 345kV Station (NU) Generation Interconnection 11/16/2016 $11,620,871 COMPLETE

200402 30973 51365 OGE OK Sub - Terry Road 345kV (Tap Lawton Eastside - Sunnyside 345kV) Sunnyside Relays for GEN-2014-057 Interconnection Generation Interconnection 11/23/2016 11/23/2016 6/7/2016 GEN-2014-057 $20,000 2016 $20,500 $20,000 $13,051 COMPLETE 34530974 51366 SPS Sub - Hitchland 345kV GEN-2010-014 Addition Hitchland 345kV Substation GEN-2010-014 Addition (TOIF) Generation Interconnection 11/17/2017 $307,375 ON SCHEDULE < 430974 51367 SPS Sub - Hitchland 345kV GEN-2010-014 Addition Hitchland 345kV Substation GEN-2010-014 Addition (NU) Generation Interconnection 11/17/2017 $2,443,882 ON SCHEDULE < 430975 51368 SEPC Sub - Buckner 345kV GEN-2010-045 Addition Buckner 345kV Substation GEN-2010-045 Addition (TOIF) Generation Interconnection 10/15/2017 $4,000,000 ON SCHEDULE < 430975 51369 SEPC Sub - Buckner 345kV GEN-2010-045 Addition Buckner 345kV Substation GEN-2010-045 Addition (NU) Generation Interconnection 10/15/2017 $8,200,000 ON SCHEDULE < 430979 51377 SPS Sub - Hitchland 345kV GEN-2011-022 Addition Hitchland 345kV GEN-2011-022 Addition (TOIF) Generation Interconnection 10/13/2017 $270,000 ON SCHEDULE < 430979 51378 SPS Sub - Hitchland 345kV GEN-2011-022 Addition Hitchland 345kV GEN-2011-022 Addition (NU) Generation Interconnection 10/13/2017 $2,895,365 ON SCHEDULE < 4

200380 30984 51392 GRDA OK Sub - Claremore 69 kV Terminal Upgrades Claremore 161 kV Ckt 1 Terminal Upgrades Regional Reliability 6/1/2021 6/1/2021 4/20/2016 SPP-2014-AG1-AFS-6 $550,000 2016 $563,750 $550,000 ON SCHEDULE > 4 161200380 30984 51393 GRDA OK Sub - Claremore 69 kV Terminal Upgrades Claremore 69 kV Terminal Upgrades Regional Reliability 6/1/2021 6/1/2021 4/20/2016 SPP-2014-AG1-AFS-6 $340,000 RE‐EVALUATION 69

30985 51396 AEP Sub - Leonard 138kV Switching Station (GEN-2014-020 POI) Leonard 138kV Switching Station (TOIF) Generation Interconnection 6/6/2017 $668,626 COMPLETE30985 51397 AEP Sub - Leonard 138kV Switching Station (GEN-2014-020 POI) Leonard 138kV Switching Station (NU) Generation Interconnection 6/6/2017 $6,996,176 COMPLETE

200412 30985 51398 OGE OK Sub - Leonard 138kV Switching Station (GEN-2014-020 POI) Leonard 138kV Switching Station (NU - OGE) Generation Interconnection 6/14/2017 8/1/2017 9/19/2016 GEN-2014-020 $20,000 COMPLETE

30986 51402 TSMO Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 (TOIF) Generation Interconnection 6/19/2017 $600,000 COMPLETE

30986 51403 TSMO Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 (TSMO NU) Generation Interconnection 6/19/2017 $1,840,000 COMPLETE

200367 30986 51404 OPPD NE Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 Tap Nebraska City - Mullin Creek 345 kV (Holt County) POI for GEN-2014-021 (OPPD NU) Generation Interconnection 4/1/2017 10/31/2016 1/12/2016 GEN-2014-021 $122,455 2016 $125,516 $122,455 ON SCHEDULE < 4

30986 51405 TSMO Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 Sub - Tap Nebraska City - Mullin Creek 345kV (Holt County) POI for GEN-2014-021 (SANU) Generation Interconnection 6/19/2017 $16,570,000 COMPLETE

200365 30987 51406 SPS NM Line - Cunningham - Monument Tap 115 kV Ckt 1 Rebuild Cunningham - Monument Tap 115 kV Ckt 1 Rebuild Regional Reliability 6/15/2021 6/1/2021 1/12/2016 SPP-2014-AG1-AFS-6 $5,129,356 2016 $5,257,590 $6,185,000 DELAY ‐ MITIGATION 115200366 30988 51408 SPS NM Sub - Eddy Co. 230 kV Bus Tie Eddy Co. 230 kV Bus Tie Transmission Service 11/30/2019 10/1/2017 1/12/2016 SPP-2013-AG3-AFS-6 $10,425,309 2016 $10,685,942 $15,929,021 DELAY ‐ MITIGATION 0.2200365 30989 51409 SPS NM Sub - Potash Junction 230 kV Terminal Upgrade Potash Junction 230 kV Terminal Upgrade Regional Reliability 6/1/2018 6/1/2018 1/12/2016 SPP-2014-AG1-AFS-6 $63,251 2016 $64,832 $63,251 ON SCHEDULE < 4 230200365 30990 51410 SPS NM Line - Jal - Teague 115 kV Ckt 1 Rebuild Jal - Teague 115 kV Ckt 1 Rebuild Regional Reliability 12/15/2018 6/1/2021 1/12/2016 SPP-2014-AG1-AFS-6 $6,640,592 2016 $6,806,607 $6,640,592 ON SCHEDULE > 4 115200365 30991 51411 SPS NM Line - National Enrichment Plant - Teague 115 kV Ckt 1 Rebuild National Enrichment Plant - Teague 115 kV Ckt 1 Rebuild Regional Reliability 12/15/2018 6/1/2018 1/12/2016 SPP-2014-AG1-AFS-6 $4,915,370 2016 $5,038,254 $4,915,370 DELAY ‐ MITIGATION 115200375 30992 51425 OGE OK XFR - Woodward EHV 138kV Phase Shifting Transformer Woodward EHV 138kV Phase Shifting Transformer circuit #1 Generation Interconnection 5/24/2017 6/1/2017 3/11/2016 GEN-2011-019 $7,103,971 2016 $7,281,570 $7,103,971 COMPLETE200397 30995 51430 WFEC OK Device - Harrisburg 69 kV Cap Bank Harrisburg 69 kV Cap Bank Regional Reliability 12/31/2017 6/1/2017 5/17/2016 2016 ITPNT $450,000 RE‐EVALUATION 69200395 30996 51431 SPS TX Sub - Hobbs - Yoakum Tap 230 kV Substation and Transformer Hobbs - Yoakum Tap 230 kV Substation Economic 12/15/2019 6/1/2017 5/17/2016 2016 ITPNT $9,710,319 2016 $9,953,077 $11,722,411 DELAY ‐ MITIGATION 230/115 0.6200395 30996 51432 SPS TX Sub - Hobbs - Yoakum Tap 230 kV Substation and Transformer Hobbs - Yoakum Tap 230/115 kV Transformer Economic 12/15/2019 6/1/2017 5/17/2016 2016 ITPNT $3,020,218 2016 $3,095,723 $3,777,589 DELAY ‐ MITIGATION 230/115 0.6200386 30997 51433 AEP OK Device - Sayre 138 kV Cap Bank Sayre 138 kV Cap Bank Regional Reliability 12/31/2018 6/1/2017 5/17/2016 2016 ITPNT $758,441 2016 $777,402 $1,483,426 DELAY ‐ MITIGATION 138200395 30999 51436 SPS TX Sub - Potter Co. - Harrington 230 kV Terminal Upgrades Potter Co. - Harrington 230 kV Terminal Upgrades Regional Reliability 6/1/2019 6/1/2019 5/17/2016 2016 ITPNT $914,347 2016 $937,206 $914,347 ON SCHEDULE < 4 230200395 31001 51438 SPS NM Line - Road Runner - Agave Red Hills/Ochoa/Custer Mountain 115 kV New Line Agave Red Hills - Road Runner 115 kV Ckt 1 New Line Regional Reliability 3/20/2017 4/1/2020 5/17/2016 2016 ITPNT $443,866 2016 $454,963 $443,866 ON SCHEDULE < 4 115 0.8200395 31001 51439 SPS NM Line - Road Runner - Agave Red Hills/Ochoa/Custer Mountain 115 kV New Line Ochoa - Road Runner 115 kV Ckt 1 New Line Regional Reliability 3/20/2017 4/1/2020 5/17/2016 2016 ITPNT $519,061 2016 $532,037 $321,590 ON SCHEDULE < 4 115 0.8200395 31001 51440 SPS NM Line - Road Runner - Agave Red Hills/Ochoa/Custer Mountain 115 kV New Line Custer Mountain - Road Runner 115 kV Ckt 1 New Line Regional Reliability 4/28/2017 4/1/2020 5/17/2016 2016 ITPNT $759,610 2016 $778,600 $759,610 ON SCHEDULE < 4 115200395 31001 51441 SPS NM Line - Road Runner - Agave Red Hills/Ochoa/Custer Mountain 115 kV New Line Road Runner 115 kV Terminal Upgrades Regional Reliability 3/28/2017 4/1/2020 5/17/2016 2016 ITPNT $4,580,864 2016 $4,695,386 $4,580,864 ON SCHEDULE < 4 115200395 31001 51442 SPS NM Line - Road Runner - Agave Red Hills/Ochoa/Custer Mountain 115 kV New Line Ochoa 115 kV Terminal Upgrades Regional Reliability 3/28/2017 4/1/2020 5/17/2016 2016 ITPNT $25,280 2016 $25,912 $119,406 ON SCHEDULE < 4 115200395 31001 51443 SPS NM Line - Road Runner - Agave Red Hills/Ochoa/Custer Mountain 115 kV New Line Agave Red Hills 115 kV Terminal Upgrades Regional Reliability 3/28/2017 4/1/2020 5/17/2016 2016 ITPNT $25,280 2016 $25,912 $25,280 ON SCHEDULE < 4 115200392 31002 51444 OGE OK Line - Lincoln - Meeker 138 kV Ckt 1 New Line Lincoln - Meeker 138 kV Ckt 1 New Line (OGE) Regional Reliability 10/15/2017 6/1/2017 5/17/2016 2016 ITPNT $750,000 2016 $768,750 $750,000 DELAY ‐ MITIGATION* 138200397 31002 51445 WFEC OK Line - Lincoln - Meeker 138 kV Ckt 1 New Line Lincoln - Meeker 138 kV Ckt 1 New Line (WFEC) Regional Reliability 8/1/2017 6/1/2017 5/17/2016 2016 ITPNT $6,000,000 DELAY ‐ MITIGATION 138200386 31003 51446 AEP OK Sub - Northeastern Station 138 kV Terminal Upgrades Northeastern Station 138 kV Terminal Upgrades Regional Reliability 10/5/2016 6/1/2017 5/17/2016 2016 ITPNT $518,011 2016 $530,961 $518,011 COMPLETE 138200386 31005 51448 AEP OK Sub - Elk City 138 kV Move Load Elk City 138 kV Move Load Regional Reliability 6/1/2018 6/1/2017 5/17/2016 2016 ITPNT $2,904,911 2016 $2,977,534 $2,904,911 DELAY ‐ MITIGATION 138200395 31008 51451 SPS NM Multi - Artesia County 115 kV Artesia Country Club 115 kV Voltage Conversion Regional Reliability 12/15/2019 6/1/2017 5/17/2016 2016 ITPNT $2,290,117 2016 $2,347,370 $2,290,117 DELAY ‐ MITIGATION 115200395 31008 51452 SPS NM Multi - Artesia County 115 kV Artesia Country Club Tap 115 kV Line Tap Regional Reliability 12/15/2019 6/1/2017 5/17/2016 2016 ITPNT $336,134 2016 $344,537 $507,619 DELAY ‐ MITIGATION 115

200395 31008 51453 SPS NM Multi - Artesia County 115 kV Artesia Country Club - Artesia Country Club Tap 115 kV Ckt 1 New Line Regional Reliability 12/15/2019 6/1/2017 5/17/2016 2016 ITPNT $3,092,796 2016 $3,170,116 $3,092,796 DELAY ‐ MITIGATION 115 3

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200406 31009 51454 AEP OK Line - Duncan - Tosco 69 kV Ckt 1 Rebuild Duncan - Tosco 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2018 6/1/2018 8/17/2016 2016 ITPNT $5,974,766 DELAY ‐ MITIGATION 69 3.86 3.86 69200397 31010 51455 WFEC OK Device - Blanchard 69 kV Cap Bank Blanchard 69 kV Cap Bank Regional Reliability 6/1/2017 5/17/2016 2016 ITPNT $0 RE‐EVALUATION 69

31014 51467 NPPD Sub - Friend 115kV Substation - GEN-2014-039 Addition Friend 115kV Substation - GEN-2014-039 Addition (TOIF) Generation Interconnection 10/15/2017 $875,000 ON SCHEDULE < 431014 51468 NPPD Sub - Friend 115kV Substation - GEN-2014-039 Addition Friend 115kV Substation - GEN-2014-039 Addition Generation Interconnection 10/15/2017 $4,300,000 ON SCHEDULE < 431016 51471 SPS Line - Plant X - Tolk 230kV rebuild circuit #1 and #2 Plant X - Tolk 230kV rebuild circuit #1 Generation Interconnection 5/31/2018 $4,960,847 ON SCHEDULE < 431016 51472 SPS Line - Plant X - Tolk 230kV rebuild circuit #1 and #2 Plant X - Tolk 230kV rebuild circuit #2 Generation Interconnection 5/31/2018 $4,960,847 ON SCHEDULE < 431017 51473 SPS XFR - TUCO Interchange 345/230kV CKT 1 Replacement TUCO Interchange 345/230kV CKT 1 Replacement Generation Interconnection 6/1/2018 $3,347,036 ON SCHEDULE < 431018 51474 OGE Sub - Minco 345kV GEN-2014-056 Addition Minco 345kV Substation GEN-2014-056 Addition (TOIF) Generation Interconnection 10/1/2017 $5,000 COMPLETE

200407 31021 51478 SPS TX Line - Mustang - Seminole 115 kV Ckt 1 New Line Mustang - Seminole 115 kV Ckt 1 New Line Regional Reliability 6/1/2020 6/1/2017 8/17/2016 2016 ITPNT $15,007,492 DELAY ‐ MITIGATION 115 19.7200407 31021 51479 SPS TX Line - Mustang - Seminole 115 kV Ckt 1 New Line Mustang 115 kV Terminal Upgrades Regional Reliability 6/1/2020 6/1/2017 8/17/2016 2016 ITPNT $2,500,387 DELAY ‐ MITIGATION 115 19.7200407 31021 51480 SPS TX Line - Mustang - Seminole 115 kV Ckt 1 New Line Seminole 115 kV Terminal Upgrades Regional Reliability 12/31/2019 6/1/2017 8/17/2016 2016 ITPNT $2,628,163 DELAY ‐ MITIGATION 115 19.7200395 31022 51481 SPS TX Line - Canyon East Tap - Randall 115 kV Ckt 1 Rebuild Canyon East Tap - Randall 115 kV Ckt 1 Rebuild Regional Reliability 12/15/2019 6/1/2017 5/17/2016 2016 ITPNT $4,804,292 2016 $4,924,399 $5,783,021 DELAY ‐ MITIGATION 115200390 31024 51486 GRDA OK Device - Skiatook 69 kV Cap Bank Skiatook 69 kV Cap Bank Regional Reliability 6/1/2017 5/17/2016 2016 ITPNT $1,134,600 2016 $1,162,965 $1,134,600 DELAY ‐ MITIGATION 69200390 31025 51487 GRDA OK Sub - Sallisaw 161 kV Terminal Upgrades Sallisaw 161 kV Terminal Upgrades Regional Reliability 12/31/2017 6/1/2017 5/17/2016 2016 ITPNT $2,266,000 2016 $2,322,650 $2,266,000 DELAY ‐ MITIGATION 161

200417 31031 51501 BEPC ND Multi - Kummer Ridge - Roundup 345 kV New Line and Patent Gate and Roundup 345/115 kV Substations Kummer Ridge - Roundup 345 kV Ckt 1 New Line Regional Reliability 12/31/2019 6/1/2017 12/28/2016 2016 ITPNT $49,589,600 2016 $50,829,340 $52,312,877 DELAY ‐ MITIGATION 115 32.4

200417 31031 51503 BEPC ND Multi - Kummer Ridge - Roundup 345 kV New Line and Patent Gate and Roundup 345/115 kV Substations Roundup 345/115 kV Transformer Regional Reliability 9/1/2016 6/1/2017 12/28/2016 2016 ITPNT $6,662,000 2016 $6,828,550 $6,662,000 COMPLETE 345/115

200417 31031 51504 BEPC ND Multi - Kummer Ridge - Roundup 345 kV New Line and Patent Gate and Roundup 345/115 kV Substations Patent Gate 345/115 kV Transformer Regional Reliability 9/1/2016 6/1/2017 12/28/2016 2016 ITPNT $6,122,000 2016 $6,275,050 $6,662,000 COMPLETE 345/115

200417 31031 51543 BEPC ND Multi - Kummer Ridge - Roundup 345 kV New Line and Patent Gate and Roundup 345/115 kV Substations Patent Gate 345 kV Substation Regional Reliability 9/1/2016 6/1/2017 12/28/2016 2016 ITPNT $30,000,000 2016 $30,750,000 $30,000,000 COMPLETE 345

200417 31031 51544 BEPC ND Multi - Kummer Ridge - Roundup 345 kV New Line and Patent Gate and Roundup 345/115 kV Substations Roundup 345 kV Substation Regional Reliability 9/1/2016 6/1/2017 12/28/2016 2016 ITPNT $27,100,000 2016 $27,777,500 $27,100,000 COMPLETE 345

200388 31032 51506 BEPC ND Multi - Plaza 115 kV Substation and Blaisdell - Plaza 115 kV New Line Plaza 115 kV Substation Regional Reliability 12/31/2017 6/1/2017 5/17/2016 2016 ITPNT $4,110,395 2016 $4,213,155 $3,918,000 DELAY ‐ MITIGATION 115200388 31032 51507 BEPC ND Multi - Plaza 115 kV Substation and Blaisdell - Plaza 115 kV New Line Blaisdell - Plaza 115 kV New Line Regional Reliability 12/31/2017 6/1/2017 5/17/2016 2016 ITPNT $15,272,151 2016 $15,653,955 $14,841,308 DELAY ‐ MITIGATION 115 36200388 31032 51508 BEPC ND Multi - Plaza 115 kV Substation and Blaisdell - Plaza 115 kV New Line Plaza 115 kV Cap Bank Regional Reliability 12/31/2017 6/1/2017 5/17/2016 2016 ITPNT $820,000 2016 $840,500 $283,000 DELAY ‐ MITIGATION 115200388 31033 51509 BEPC ND Line - Berthold - Southwest Minot 115 kV Ckt 1 Reconductor Berthold - Southwest Minot 115 kV Ckt 1 Reconductor Regional Reliability 10/1/2017 6/1/2017 5/17/2016 2016 ITPNT $3,731,074 2016 $3,824,351 $2,876,720 COMPLETE 115 26.44

31034 51514 SPS Sub - Chaves County Interchange 115kV Substation GEN-2014-034 Addition Chaves County Interchange 115kV Substation GEN-2014-034 Addition (TOIF) Generation Interconnection 8/16/2016 $260,000 ON SCHEDULE < 4

31034 51515 SPS Sub - Chaves County Interchange 115kV Substation GEN-2014-034 Addition Chaves County Interchange 115kV Substation GEN-2014-034 Addition Generation Interconnection 8/24/2016 $755,000 ON SCHEDULE < 4200393 31038 51521 OPPD NE Device - S964 69 kV Cap Bank S964 69 kV Cap Bank Regional Reliability 6/1/2020 6/1/2020 5/17/2016 2016 ITPNT $722,660 2016 $740,727 $722,660 ON SCHEDULE < 4 69200406 31039 51524 AEP OK Line - Comanche Tap - Tosco 69 kV Ckt 1 Rebuild Comanche Tap - Tosco 69 kV Ckt 1 Rebuild Regional Reliability 12/19/2016 6/1/2020 8/17/2016 2016 ITPNT $4,365,864 COMPLETE 69 3.2 3.2 69200397 31040 51525 WFEC OK Device - Ringwood 138 kV Cap Bank Ringwood 138 kV Cap Bank Regional Reliability 6/1/2018 5/17/2016 2016 ITPNT $450,000 RE‐EVALUATION 138200397 31041 51526 WFEC OK Multi - Driftwood 138/69 kV Substation and Transformer Driftwood 138 kV Substation Regional Reliability 12/31/2018 6/1/2017 5/17/2016 2016 ITPNT $550,000 DELAY ‐ MITIGATION 138200397 31041 51527 WFEC OK Multi - Driftwood 138/69 kV Substation and Transformer Driftwood 138/69 kV Transformer Regional Reliability 12/31/2018 6/1/2017 5/17/2016 2016 ITPNT $3,600,000 DELAY ‐ MITIGATION 138/69

200418 31042 51528 OGE OK Multi - DeGrasse - Knob Hill 138 kV New Line and DeGrasse 345/138 kV Transformer DeGrasse 345 kV Substation Regional Reliability 6/1/2019 6/1/2017 12/27/2016 2016 ITPNT $7,700,661 2017 $7,700,661 $7,700,661 DELAY ‐ MITIGATION 345

200418 31042 51529 OGE OK Multi - DeGrasse - Knob Hill 138 kV New Line and DeGrasse 345/138 kV Transformer DeGrasse 345/138 kV Transformer Regional Reliability 6/1/2019 6/1/2017 12/27/2016 2016 ITPNT $3,600,000 2017 $3,600,000 $3,600,000 DELAY ‐ MITIGATION 345/138

200418 31042 51530 OGE OK Multi - DeGrasse - Knob Hill 138 kV New Line and DeGrasse 345/138 kV Transformer DeGrasse - Knob Hill 138 kV New Line Regional Reliability 6/1/2019 6/1/2017 12/27/2016 2016 ITPNT $8,383,000 2017 $8,383,000 $8,383,000 DELAY ‐ MITIGATION 138

200419 31042 51531 WFEC OK Multi - DeGrasse - Knob Hill 138 kV New Line and DeGrasse 345/138 kV Transformer DeGrasse 138 kV Substation (WFEC) Regional Reliability 12/31/2019 6/1/2017 12/27/2016 2016 ITPNT $1,400,000 2017 $1,400,000 $5,700,000 DELAY ‐ MITIGATION 138 2

200418 31042 51569 OGE OK Multi - DeGrasse - Knob Hill 138 kV New Line and DeGrasse 345/138 kV Transformer DeGrasse 138 kV Substation (OGE) Regional Reliability 6/1/2019 6/1/2017 12/27/2016 2016 ITPNT $7,723,383 2017 $7,723,383 $7,723,383 DELAY ‐ MITIGATION 138

200377 31050 51548 WR KS Sub - Summit 115 kV Terminal Upgrades Summit 115 kV Terminal Upgrades Transmission Service 10/5/2016 6/1/2021 3/17/2016 SPP-2015-AG1-AFS-6 $261,758 2016 $268,302 $239,258 $239,258 CLOSED OUT 115200395 31051 51549 SPS TX Sub - Terry Co. - Wolfforth 115 kV Terminal Upgrades Terry Co. - Wolfforth 115 kV Terminal Upgrades Regional Reliability 6/1/2018 4/1/2020 5/17/2016 2016 ITPNT $1,461,643 2016 $1,498,184 $1,461,643 ON SCHEDULE < 4 115200407 31052 51550 SPS TX Multi - Tolk Yoakum Tap 230/115 kV Substation and Transformer Tolk - Yoakum Tap 230/115 kV Substation and Transformer Regional Reliability 12/15/2020 6/1/2018 8/17/2016 2016 ITPNT $12,730,092 RE‐EVALUATION 230/115 2

200386 31057 51558 AEP OK Line - Atoka - Atoka Pump - Pittsburg - Savanna - Army Ammo - McAlester City 69 kV Ckt 1 Rebuild Army Ammo - McAlester 69 kV Ckt 1 Rebuild Zonal Reliability 12/31/2019 6/1/2017 5/17/2016 2016 ITPNT $13,512,897 2016 $13,850,719 $13,512,897 DELAY ‐ MITIGATION 69

200386 31057 51559 AEP OK Line - Atoka - Atoka Pump - Pittsburg - Savanna - Army Ammo - McAlester City 69 kV Ckt 1 Rebuild Army Ammo - Savanna - Pittsburg 69 kV Ckt 1 Rebuild Zonal Reliability 12/31/2019 6/1/2017 5/17/2016 2016 ITPNT $15,146,464 2016 $15,525,125 $13,767,520 DELAY ‐ MITIGATION 69

200386 31057 51560 AEP OK Line - Atoka - Atoka Pump - Pittsburg - Savanna - Army Ammo - McAlester City 69 kV Ckt 1 Rebuild Atoka - Atoka Pump - Pittsburg 69 kV Ckt 1 Rebuild Zonal Reliability 12/31/2019 6/1/2017 5/17/2016 2016 ITPNT $21,668,582 2016 $22,210,296 $23,047,526 DELAY ‐ MITIGATION 69

200386 31058 51561 AEP OK Line - Fort Towson - Kiamichi Pump Tap - Valliant 69 kV Ckt 1 Rebuild Fort Towson - Kiamichi Pump Tap 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2019 6/1/2018 5/17/2016 2016 ITPNT $11,778,983 2016 $12,073,458 $11,778,983 DELAY ‐ MITIGATION 69200386 31058 51562 AEP OK Line - Fort Towson - Kiamichi Pump Tap - Valliant 69 kV Ckt 1 Rebuild Kiamichi Pump Tap - Valliant 69 kV Ckt 1 Rebuild Regional Reliability 6/1/2019 6/1/2018 5/17/2016 2016 ITPNT $7,699,929 2016 $7,892,428 $7,699,929 DELAY ‐ MITIGATION 69200420 31061 51565 SPS NM Line - Livingston Ridge - Wipp 115 kV Ckt 1 Rebuild Livingston Ridge - Wipp 115 kV Ckt 1 Rebuild Regional Reliability 6/15/2021 6/1/2021 1/12/2017 SPP-2015-AG1-AFS-6 $301,000 DELAY ‐ MITIGATION 115200420 31063 51567 SPS NM Sub - Carlsbad - Pecos 115 kV Terminal Upgrades Carlsbad - Pecos 115 kV Terminal Upgrades Regional Reliability 6/1/2021 6/1/2021 1/12/2017 SPP-2015-AG1-AFS-6 $700,000 ON SCHEDULE < 4 115 0.03200397 31065 51484 WFEC OK Sub - Cleo Junction 138 kV Terminal Upgrades Cleo Junction 138 kV Terminal Upgrades Regional Reliability 12/31/2019 6/1/2017 5/17/2016 2016 ITPNT $4,000,000 DELAY ‐ MITIGATION 138200397 31066 51485 WFEC OK Sub - Ringwood 138 kV Terminal Upgrades Ringwood 138 kV Terminal Upgrades Regional Reliability 6/1/2017 5/17/2016 2016 ITPNT $4,000,000 RE‐EVALUATION 138200395 31067 50924 SPS NM Sub - Livingston Ridge 115 kV Substation Conversion Livingston Ridge 115 kV Substation Conversion Regional Reliability 11/30/2017 6/1/2017 5/17/2016 2016 ITPNT $5,283,323 2016 $5,415,406 $5,365,000 DELAY ‐ MITIGATION 115200395 31068 50447 SPS TX Multi - Tuco - Yoakum 345/230 kV Ckt 1 Tuco - Yoakum 345 kV Ckt 1 Regional Reliability 6/1/2020 6/1/2017 5/17/2016 2016 ITPNT $128,473,352 2016 $131,685,186 $128,473,352 DELAY ‐ MITIGATION 345 107200395 31068 50451 SPS TX Multi - Tuco - Yoakum 345/230 kV Ckt 1 Yoakum 345/230 kV Ckt 1 Transformer Regional Reliability 6/15/2019 6/1/2017 5/17/2016 2016 ITPNT $5,047,344 2016 $5,173,528 $5,047,344 DELAY ‐ MITIGATION 345/230

31071 51573 SPS Sub - Crossroads 345kV Substation - GEN-2014-047 Addition Crossroads 345kV Substation - GEN-2014-047 Addition (TOIF) Generation Interconnection 7/31/2017 $337,375 RE‐EVALUATION31071 51574 SPS Sub - Crossroads 345kV Substation - GEN-2014-047 Addition Crossroads 345kV Substation - GEN-2014-047 Addition (NU) Generation Interconnection 7/31/2017 $1,736,369 RE‐EVALUATION

31072 51575 WR Sub - Tap Wichita - Thistle 345 kV Ckt 1 & 2 - GEN-2015-024 Addition Tap Wichita - Thistle 345 kV Ckt 1 & 2 - GEN-2015-024 Addition (TOIF) Generation Interconnection 12/1/2016 $1,261,334 $1,223,589 COMPLETE

200437 31073 51578 MIDW KS XFR - Heizer 115/69 kV Ckt 4 Transformer Heizer 115/69 kV Ckt 4 Transformer Regional Reliability 6/1/2021 2/8/2017 SPP-2015-AG2-AFS-3 $2,663,963 ON SCHEDULE > 4 115/6931075 51613 KCPL Sub - Tap Centerville-Marmaton 161kV GEN-2015-016 Addition Tap Centerville-Marmaton 161kV GEN-2015-016 Addition (TOIF) Generation Interconnection 7/21/2018 $600,000 ON SCHEDULE < 431075 51614 KCPL Sub - Tap Centerville-Marmaton 161kV GEN-2015-016 Addition Tap Centerville-Marmaton 161kV GEN-2015-016 Addition (NU) Generation Interconnection 7/21/2018 $7,978,000 ON SCHEDULE < 4

200463 31075 51615 WR KS Sub - Tap Centerville-Marmaton 161kV GEN-2015-016 Addition Tap Centerville-Marmaton 161kV GEN-2015-016 Addition (WERE) Generation Interconnection 7/21/2018 8/16/2017 GEN-2015-016 $110,000 ON SCHEDULE < 431076 51616 SPS Sub - Norton 115kV GEN-2013-022 Addition Norton 115kV GEN-2013-022 Addition (TOIF) Generation Interconnection 11/28/2016 $260,000 ON SCHEDULE < 431076 51617 SPS Sub - Norton 115kV GEN-2013-022 Addition Norton 115kV GEN-2013-022 Addition (NU) Generation Interconnection 11/28/2016 $1,477,078 ON SCHEDULE < 4

200444 31079 51623 SPS TX Sub - Tuco - Stanton 115 kV Terminal Upgrades Tuco - Stanton 115 kV Terminal Upgrades Economic 12/31/2018 1/1/2017 2/22/2017 2017 ITP10 $283,963 2017 $283,963 $283,963 DELAY ‐ MITIGATION 115200444 31080 51624 SPS TX Sub - Stanton - Indiana 115 kV Terminal Upgrades Stanton - Indiana 115 kV Terminal Upgrades Economic 1/1/2017 2/22/2017 2017 ITP10 $0 DELAY ‐ MITIGATION 115200444 31081 51625 SPS TX Sub - Indiana - SP-Erskine 115 kV Terminal Upgrades Indiana - SP-Erskine 115 kV Terminal Upgrades Economic 2/28/2020 1/1/2017 2/22/2017 2017 ITP10 $1,133,153 DELAY ‐ MITIGATION 115200467 31082 51626 WR KS Sub - Butler - Altoona 138 kV Terminal Upgrades Butler - Altoona 138 kV Terminal Upgrades Economic 6/1/2019 1/1/2017 11/14/2017 2017 ITP10 $247,332 2017 $247,332 $247,332 DELAY ‐ MITIGATION 138200430 31083 51628 WR KS Sub - Neosho - Riverton 161 kV Terminal Upgrades Neosho 161 kV Terminal Upgrades Economic 6/1/2019 2/21/2017 2017 ITP10 $137,488 2017 $137,488 $137,488 DELAY ‐ MITIGATION 161200428 31085 51630 KCPL MO Device - Northeast - Charlotte - Crosstown 161 kV Reactor Northeast - Charlotte - Crosstown 161 kV Reactor Economic 3/1/2018 1/1/2018 2/22/2017 2017 ITP10 $500,000 2017 $500,000 $500,000 DELAY ‐ MITIGATION 161

31087 51633 TSMO Sub - Ketchem 345kV Interconnection Switching Station GEN-2015-005 Addition Ketchem 345kV Interconnection Switching Station GEN-2015-005 Addition (TOIF) Generation Interconnection 12/14/2016 $1,000,000 $695,619 CLOSED OUT

31087 51634 TSMO Sub - Ketchem 345kV Interconnection Switching Station GEN-2015-005 Addition Ketchem 345kV Interconnection Switching Station GEN-2015-005 Addition (NU) Generation Interconnection 12/14/2016 $9,447,755 COMPLETE

200413 31087 51635 GMO MO Sub - Ketchem 345kV Interconnection Switching Station GEN-2015-005 Addition Sibley 345kV Substation Relays for Ketchem 345kV Station GEN-2015-005 Addition Generation Interconnection 12/14/2016 12/31/2016 9/15/2016 GEN-2015-005 $30,000 COMPLETE

31089 51637 OGE Sub - Redington 345kV - GEN-2015-063 Addition Tap Woodring - Mathewson 345kV - GEN-2015-063 Addition (NU) Generation Interconnection 10/2/2017 $8,987,814 ON SCHEDULE < 431089 71972 OGE Sub - Redington 345kV - GEN-2015-063 Addition Tap Woodring - Mathewson 345kV - GEN-2015-063 Addition (TOIF) Generation Interconnection 10/2/2017 $1,109,186 ON SCHEDULE < 431090 51638 OGE Line - GEN-2015-063 Tap - Mathewson 345kV CKT 1 GEN-2015-063 Tap - Mathewson 345kV CKT 1 Generation Interconnection 3/1/2018 $4,490,795 ON SCHEDULE < 4

200429 31127 51730 MIDW KS Line - Knoll - Post Rock 230 kV New Line Ckt 2 Knoll - Post Rock 230 kV New Line Ckt 2 Economic 6/1/2019 1/1/2017 2/22/2017 2017 ITP10 $475,463 2017 $475,463 $2,157,736 DELAY ‐ MITIGATION 0.68200429 31127 51815 MIDW KS Line - Knoll - Post Rock 230 kV New Line Ckt 2 Knoll Sub 230 kV Terminal Economic 6/1/2019 1/1/2017 2/22/2017 2017 ITP10 $1,903,595 2017 $1,903,595 $1,558,445 DELAY ‐ MITIGATION200429 31127 51816 MIDW KS Line - Knoll - Post Rock 230 kV New Line Ckt 2 Post Rock Sub 230 kV Terminal Economic 6/1/2019 1/1/2017 2/22/2017 2017 ITP10 $1,493,227 2017 $1,493,227 $1,683,863 DELAY ‐ MITIGATION200431 31131 51738 AEP AR/OK Line - Siloam Springs - Siloam Springs City 161 kV Ckt 1 Rebuild Siloam Springs - Siloam Springs City 161 kV Ckt 1 Rebuild (AEP) Economic 1/1/2020 1/1/2017 2/21/2017 2017 ITP10 $4,780,000 2017 $4,780,000 $4,780,000 DELAY ‐ MITIGATION200432 31131 51739 GRDA OK Line - Siloam Springs - Siloam Springs City 161 kV Ckt 1 Rebuild Siloam Springs - Siloam Springs City 161 kV Ckt 1 Rebuild (GRDA) Economic 1/1/2017 2/21/2017 2017 ITP10 $312,400 2017 $312,400 $440,000 DELAY ‐ MITIGATION200433 31144 51764 WFEC OK Sub - Tupelo - Tupelo Tap 138 kV Terminal Upgrades Tupelo 138 kV Terminal Upgrades Economic 7/1/2021 1/1/2020 2/21/2017 2017 ITP10 $100,000 2017 $100,000 $100,000 DELAY ‐ MITIGATION

31147 51766 SPS Sub - Tap Tolk - Yoakum 230kV (Needmore) - GEN-2013-027 Addition Tap Tolk - Yoakum 230kV (Needmore) - GEN-2013-027 Addition (TOIF) Generation Interconnection 3/17/2018 $300,000 ON SCHEDULE < 431147 51767 SPS Sub - Tap Tolk - Yoakum 230kV (Needmore) - GEN-2013-027 Addition Tap Tolk - Yoakum 230kV (Needmore) - GEN-2013-027 Addition (NU) Generation Interconnection 3/17/2018 $6,398,806 ON SCHEDULE < 4

200434 31150 51774 OGE OK Sub - Lula - Tupelo Tap 138 kV Terminal Upgrades Lula- Tupelo Tap 138 kV Terminal Upgrades Economic 7/1/2021 1/1/2020 2/21/2017 2017 ITP10 $305,000 2017 $305,000 $305,000 DELAY ‐ MITIGATION200457 31176 51819 SPS TX Sub - Hockley County Interchange 115 kV Terminal Upgrades Hockley County Interchange 115 kV Terminal Upgrades Regional Reliability 5/15/2017 SPP-2016-AG1-AFS-3 $228,066 NTC ‐ COMMITMENT WINDOW200422 31184 51828 WR KS Line - Jeffrey Energy Center - Hoyt 345 kV Ckt 1 Jeffrey Energy Center - Hoyt 345 kV Ckt 1 Regional Reliability 1/11/2017 SPP-2016-AG1-AFS-2 $34,865,672 2017 $34,865,672 $23,683,317 RE‐EVALUATION 24.3200446 31186 51831 AEP TX/AR Device - IPC 138 kV Cap Bank IPC 138 kV Cap Bank Regional Reliability 6/1/2021 12/1/2018 5/12/2017 2017 ITPNT $1,298,049 DELAY ‐ MITIGATION 138200455 41188 61834 SPS TX Sub - Hale County 115 kV Hale County 115 kV Terminal Upgrades Regional Reliability 5/12/2017 2017 ITPNT $766,323 ON SCHEDULE < 4 115200444 41189 61836 SPS TX Sub - Martin - Pantex N 115 kV Terminal Upgrades Martin - Pantex North 115 kV Terminal Upgrades Economic 3/15/2018 1/1/2017 2/22/2017 2017 ITP10 $324,392 2017 $324,392 $324,392 DELAY ‐ MITIGATION200444 41189 61837 SPS TX Sub - Martin - Pantex N 115 kV Terminal Upgrades Pantex South - Highland Tap 115 kV Terminal Upgrades Economic 3/15/2018 1/1/2017 2/22/2017 2017 ITP10 $324,392 2017 $324,392 $324,392 DELAY ‐ MITIGATION200455 41192 61840 SPS TX Sub - Coulter 115 kV Coulter 115 kV Terminal Upgrades Regional Reliability 5/12/2017 2017 ITPNT $286,869 ON SCHEDULE < 4 115200455 41194 61844 SPS TX Sub - Plant X - Sundown 230 kV Plant X 230 kV Terminal Upgrades Regional Reliability 12/31/2018 5/12/2017 2017 ITPNT $0 DELAY ‐ MITIGATION 230200455 41194 61845 SPS TX Sub - Plant X - Sundown 230 kV Sundown 230 kV Terminal Upgrades Regional Reliability 12/31/2018 6/1/2018 5/12/2017 2017 ITPNT $360,540 DELAY ‐ MITIGATION 230200455 41198 61852 SPS OK Sub - Texas County - Hitchland 115 kV bus Texas County 115 kV Terminal Upgrades #1 Regional Reliability 12/31/2018 5/12/2017 2017 ITPNT $98,639 DELAY ‐ MITIGATION 115200455 41198 61853 SPS OK Sub - Texas County - Hitchland 115 kV bus Texas County 115 kV Terminal Upgrades #2 Regional Reliability 12/31/2018 5/12/2017 2017 ITPNT $108,430 DELAY ‐ MITIGATION 115200455 41199 71960 SPS TX Line - Etter - Moore - 115 kV Etter - Moore 115 kV Rebuild Regional Reliability 5/12/2017 2017 ITPNT $9,114,440 ON SCHEDULE < 4 115 10.25200452 41200 61856 WAPA ND Sub - Williston 115 kV Williston 115 kV Terminal Upgrades Regional Reliability 12/30/2017 6/1/2018 5/12/2017 2017 ITPNT $5,000 ON SCHEDULE < 4 115200446 41202 61858 AEP OK Line - Tulsa Southeast - E.61st 138 kV Rebuild Tulsa Southeast - E.61st 138 kV Rebuild Regional Reliability 6/1/2021 5/12/2017 2017 ITPNT $6,014,381 DELAY ‐ MITIGATION 138 1.8

200448 41209 61869 EDE MO Line - Line -– Republic East – Republic Hines Street – Republic North – Nichols 69 kV Reconductor Nichols – Republic North 69 kV Reconductor Regional Reliability 6/1/2018 6/1/2018 5/12/2017 2017 ITPNT $4,050,000 2017 $4,050,000 $4,050,000 ON SCHEDULE < 4 69 10

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200448 41209 61870 EDE MO Line - Line -– Republic East – Republic Hines Street – Republic North – Nichols 69 kV Reconductor Republic Hines Street - Republic North 69 kV Reconductor Regional Reliability 6/1/2018 6/1/2018 5/12/2017 2017 ITPNT $1,450,000 2017 $1,450,000 $1,450,000 ON SCHEDULE < 4 69 3.5

200448 41209 61871 EDE MO Line - Line -– Republic East – Republic Hines Street – Republic North – Nichols 69 kV Reconductor Republic East - Republic Hines Street 69 kV Reconductor Regional Reliability 6/1/2018 6/1/2018 5/12/2017 2017 ITPNT $800,000 2017 $800,000 $800,000 ON SCHEDULE < 4 69 1.6

200462 41223 61894 CPEC ND Line - New East Ruthville - SW Minot 115 kV New Line East Ruthville - SW Minot 115 kV New Line Regional Reliability 12/31/2019 8/2/2017 2017 ITPNT $20,746,000 DELAY ‐ MITIGATION* 115 23.8200462 41223 61895 CPEC ND Line - New East Ruthville - SW Minot 115 kV New Line East Ruthville - SW Minot 115 kV line Terminal Upgrades Regional Reliability 12/31/2019 8/2/2017 2017 ITPNT $1,035,000 DELAY ‐ MITIGATION* 115200446 41233 71945 AEP OK Line - Broken Arrow North - Lynn Lane East 138 kV Ckt 1 Broken Arrow North - Lynn Lane East 138 kV Ckt 1 Reconductor Regional Reliability 1/1/2020 6/1/2018 5/12/2017 2017 ITPNT $5,714,095 DELAY ‐ MITIGATION 138 7.13

51234 71923 OGE Line - Renfrow-Renfrow Tap 138kV Ckt 1 Renfrow-Renfrow Tap 138kV Ckt 1 Generation Interconnection 9/25/2017 $90,000 ON SCHEDULE < 4 13851235 71924 OGE Sub - Tap Coyote-Medford Tap 138kV - GEN-2015-015 Addition Tap Coyote-Medford Tap 138kV - GEN-2015-015 Addition (TOIF) Generation Interconnection 9/25/2017 $410,000 ON SCHEDULE < 451235 71925 OGE Sub - Tap Coyote-Medford Tap 138kV - GEN-2015-015 Addition Tap Coyote-Medford Tap 138kV - GEN-2015-015 Addition (NU) Generation Interconnection 10/3/2017 $2,840,000 COMPLETE

200452 51236 71926 WAPA SD Multi - Roberts County - Sisseton 115kV Roberts County 115 kV Substation Regional Reliability 9/1/2019 5/12/2017 2017 ITPNT $4,300,000 NTC ‐ COMMITMENT WINDOW 115200452 51236 71927 WAPA SD Multi - Roberts County - Sisseton 115kV XFR - Roberts County 115/69 kV Transformer Regional Reliability 9/30/2019 5/12/2017 2017 ITPNT $1,200,000 DELAY ‐ MITIGATION 115200450 51236 71938 EREC SD Multi - Roberts County - Sisseton 115kV Roberts County - Sisseton 69 kV New Line Regional Reliability 9/1/2019 5/12/2017 2017 ITPNT $603,000 NTC ‐ COMMITMENT WINDOW 69 2200451 51237 71928 KCPL KS Device - Stilwell Relaying Redundancy Relaying at Stilwell Regional Reliability 6/1/2018 5/12/2017 2017 ITPNT $147,500 ON SCHEDULE < 4 345

51239 71933 NPPD Sub - Holt County 345kV (Tap Grand Prairie - Grand Island 345kV) - GEN-2015-023 Addition

Holt County 345kV (Tap Grand Prairie - Grand Island 345kV) - GEN-2015-023 Addition (TOIF) Generation Interconnection 10/1/2020 $4,700,000 ON SCHEDULE < 4

51239 71934 NPPD Sub - Holt County 345kV (Tap Grand Prairie - Grand Island 345kV) - GEN-2015-023 Addition

Holt County 345kV (Tap Grand Prairie - Grand Island 345kV) - GEN-2015-023 Addition (NU) Generation Interconnection 11/1/2020 $5,900,000 ON SCHEDULE < 4 345

51240 71935 NPPD Sub - Hoskins 345kV - GEN-2015-007 Addition Hoskins 345kV - GEN-2015-007 Addition (TOIF) Generation Interconnection 11/1/2019 $16,700,000 ON SCHEDULE < 451240 71936 NPPD Sub - Hoskins 345kV - GEN-2015-007 Addition Hoskins 345kV - GEN-2015-007 Addition (NU) Generation Interconnection 11/1/2019 $4,600,000 ON SCHEDULE < 4 34551240 71937 TBD Sub - Hoskins 345kV - GEN-2015-007 Addition Hoskins 345kV - GEN-2015-007 Addition (MISO) Generation Interconnection 10/1/2019 $50,000 ON SCHEDULE < 4 34551241 71939 SEPC Sub - Johnson Corner 115kV - GEN-2015-021 Addition Johnson Corner 115kV - GEN-2015-021 Addition (TOIF) Generation Interconnection 4/15/2019 $1,276,522 ON SCHEDULE < 4

200455 51246 71949 SPS TX Sub - Nichols - 230 kV Nichols 230 kV Terminal Upgrades Regional Reliability 5/12/2017 2017 ITPNT $257,295 ON SCHEDULE < 4 230200466 51249 71954 WR KS Line - City of Winfield - Oak 69 kV Reconductor City of Winfield - Rainbow 69 kV Ckt 1 Regional Reliability 9/21/2017 $1,467,084 NTC ‐ COMMITMENT WINDOW200466 51249 71955 WR KS Line - City of Winfield - Oak 69 kV Reconductor Oak - Rainbow 69 kV Ckt 1 Regional Reliability 9/21/2017 $1,870,532 NTC ‐ COMMITMENT WINDOW200466 51252 71958 WR KS XFR - Creswell 138/69/13.2 kV Transformers Creswell (CRSW TX-1) 138/69/13.2 kV Transformer Ckt 1 Regional Reliability 9/21/2017 $2,961,462 NTC ‐ COMMITMENT WINDOW200466 51252 71959 WR KS XFR - Creswell 138/69/13.2 kV Transformers Creswell (CRSW TX-2) 138/69/13.2 kV Transformer Ckt 2 Regional Reliability 9/21/2017 $2,961,462 NTC ‐ COMMITMENT WINDOW200454 51253 71961 NIPCO IA Sub - L-10 Southern 69 kV Terminal Upgrades L-10 Southern 69 kV Terminal Upgrades Regional Reliability 7/1/2019 5/12/2017 2017 ITPNT $710,000 NTC ‐ COMMITMENT WINDOW 69200454 51253 71962 NIPCO IA Sub - L-10 Southern 69 kV Terminal Upgrades J16 69 kV Substation Regional Reliability 7/1/2019 5/12/2017 2017 ITPNT $1,220,000 NTC ‐ COMMITMENT WINDOW200460 51254 71963 NPPD NE Multi - Sheldon - Monolith 115 kV Monolith 345 kV Substation Regional Reliability 4/1/2020 7/20/2017 DPA-2016-December-703 $12,692,888 NTC ‐ COMMITMENT WINDOW 0.2200460 51254 71964 NPPD NE Multi - Sheldon - Monolith 115 kV Monolith 345/115 kV Transformer #1 Regional Reliability 4/1/2020 7/20/2017 DPA-2016-December-703 $5,179,657 NTC ‐ COMMITMENT WINDOW200460 51254 71965 NPPD NE Multi - Sheldon - Monolith 115 kV Monolith 345/115 kV Transformer #2 Regional Reliability 4/1/2020 7/20/2017 DPA-2016-December-703 $5,179,657 NTC ‐ COMMITMENT WINDOW200460 51254 71966 NPPD NE Multi - Sheldon - Monolith 115 kV Monolith 115 kV Substation Upgrades Regional Reliability 4/1/2020 7/20/2017 DPA-2016-December-703 $11,271,233 NTC ‐ COMMITMENT WINDOW 2.6200460 51254 71967 NPPD NE Multi - Sheldon - Monolith 115 kV Sheldon - Monolith 115 kV Ckt 1 New Line Regional Reliability 4/1/2020 7/20/2017 DPA-2016-December-703 $1,273,506 NTC ‐ COMMITMENT WINDOW 1200460 51254 71968 NPPD NE Multi - Sheldon - Monolith 115 kV Sheldon 115 kV Terminal Upgrades Regional Reliability 4/1/2020 7/20/2017 DPA-2016-December-703 $3,703,266 NTC ‐ COMMITMENT WINDOW

51259 71974 OGE Sub - Sooner 345kV GEN-2015-047 Addition Sooner 345kV GEN-2015-047 Addition (TOIF) Generation Interconnection 10/2/2017 $3,371,014 ON SCHEDULE < 451259 71975 OGE Sub - Sooner 345kV GEN-2015-047 Addition Sooner 345kV GEN-2015-047 Addition (NU) Generation Interconnection 10/2/2017 $1,772,666 ON SCHEDULE < 451261 71980 NPPD Multi - Belvidere 115kV Substation GEN-2015-087 Addition Belvidere 115kV Substation GEN-2015-087 Addition (TOIF) Generation Interconnection 11/1/2019 $300,000 RE‐EVALUATION 11551261 71981 NPPD Multi - Belvidere 115kV Substation GEN-2015-087 Addition Belvidere 115kV Substation GEN-2015-087 Addition (NU) Generation Interconnection 11/1/2019 $5,300,000 RE‐EVALUATION 11551261 71982 NPPD Multi - Belvidere 115kV Substation GEN-2015-087 Addition Belvidere – Fairbury 115kV circuit #1 Generation Interconnection 11/1/2019 $1,700,000 RE‐EVALUATION 115/11551261 71983 NPPD Multi - Belvidere 115kV Substation GEN-2015-087 Addition Beatrice – Harbine 115kV circuit #1 Generation Interconnection 11/1/2019 $900,000 RE‐EVALUATION 115/11551262 71984 NPPD Sub - Tobias 345kV Substation GEN-2015-088 Addition Tobias 345kV Substation GEN-2015-088 Addition (TOIF) Generation Interconnection 1/1/2019 $700,000 ON SCHEDULE < 4 345/34551262 71985 NPPD Sub - Tobias 345kV Substation GEN-2015-088 Addition Tobias 345kV Substation GEN-2015-088 Addition (NU) Generation Interconnection 1/1/2019 $11,700,000 ON SCHEDULE < 4 345/34551276 72002 WR Sub - Union Ridge 230kV GEN-2015-069 Addition Union Ridge 230kV GEN-2015-069 Addition (TOIF) Generation Interconnection 9/1/2018 $600,000 ON SCHEDULE < 451276 72003 WR Sub - Union Ridge 230kV GEN-2015-069 Addition Union Ridge 230kV GEN-2015-069 Addition (NU) Generation Interconnection 9/1/2018 $2,155,752 ON SCHEDULE < 4

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