board of directors/members committee meeting - Southwest ...

1

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING April 27, 2021 8:00a.m. – 3:00p.m. | Webex

- Summary of Action Items -

1. Approved Consent Agenda Items

a. Approve January 26, 2021 and March 2, 2021 Minutes b. Corporate Governance Committee

i. Recommendation – L&O Membership Agreement Amendment ii. Recommendation – Change User Forum Chair-Jodi Hall

c. Finance Committee i. Recommendation – 2020 Financial Audit ii. Recommendation – 2021 Benefit Plan Funding

d. Markets and Operations Policy Committee Report i. Recommendations:

1. Sponsored Upgrade SUS-016 Onida 2. Sponsored Upgrade SUS-019 Hughes County 3. Line-Mustang–Seminole 115 kV Ckt 1 Cost Variance 4. Line–Chaves-Price-CV Pines-Capitan 115 kV Ckt 1 NTC Mod.

e. Holistic Integrated Tariff Team i. Change Assignment Threshold for ERIS in the GI Study Process BP 7250 (RR435)

f. Staff i. Recommendation – Minco – Pleasant Valley – Draper ii. Evergy Short Circuit Breakers Out-of-Cycle NTC Re-evaluation iii. WAPA Devils Lake Reactor Out-of-Cycle NTC Re-evaluation

2. Approved OC IEP for 2021

3. Approved FC 2021 Capex Funding

4. Approved SPC Mission, Vision & Values recommendation

5. Approved Staff 2023 ITP Mitigation

6. Approved Staff Butler-Tioga recommendation

1 of 306

SPP Board of Directors/Members Committee Minutes April 27, 2021

2

Minutes No. 195

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING April 27, 2021 8:00a.m. – 3:00p.m. | Webex

MINUTES

Agenda Item 1 – Administrative Items SPP Board of Directors Chair Mr. Larry Altenbaumer called the regular meeting to order at 8:00 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy: Mr. Larry Altenbaumer, Director Ms. Bronwen Bastone, Director Mr. Julian Brix, Director Ms. Susan Certoma, Director Mr. Mark Crisson, Director Mr. Graham Edwards, Director Mr. Josh Martin, Director Ms. Liz Moore, Director Ms. Darcy Ortiz, Director Ms. Barbara Sugg, Director Ms. Betsy Beck, Enel Green Power North America Mr. Bleau LaFave, NorthWestern Energy Mr. Chris Jones, City Utilities of Springfield, MO Mr. Dave Osburn, Oklahoma Municipal Power Authority Mr. David Hudson, Xcel Energy Mr. Lloyd Linke, Western Area Power Administration – Upper Great Plains Region Mr. Joe Lang, Omaha Public Power District Mr. Joel Bladow, Tri-State Generation and Transmission Mr. Kevin Noblett, Evergy Companies Mr. Kevin Smith, Tenaska Power Services Company Mr. Mike Wise, Golden Spread Electric Cooperative, Inc. Ms. Peggy Simmons, Public Service of Oklahoma Mr. Rob Janssen, Dogwood Energy LLC Mr. Steve Gaw, Advanced Power Alliance Mr. Stuart Lowry, Sunflower Electric Power Corporation Mr. Tom Christensen, Basin Electric Power Cooperative Mr. Thomas Kent, Nebraska Public Power District Ms. Usha Turner, Oklahoma Gas and Electric Company Mr. Zac Perkins, Tri-County Electric Coop. There were 215 participants in attendance via net conference. Ms. Barbara Sugg reported the proxies for today’s meeting. (Attachment - Attendance). Agenda Item 2 – Consent Agenda

Mr. Larry Altenbaumer asked if there were any items that needed to be removed from the consent agenda; there were none. (Attachment- Consent Agenda).

2 of 306


3

Ms. Barbara Sugg moved to approve the consent agenda. Mr. Graham Edwards seconded the motion. The Members Committee voted and unanimously approved. The Board voted by email; the motion passed. Agenda Item 3 – Reports to the Board

a. President’s Report Ms. Barbara Sugg (SPP President and CEO) provided the SPP Report. She began her report looking back over her first year as CEO and the unprecedented events that took place. Ms. Sugg announced the release of the 2020 Annual report and she discussed the Polar Vortex, Strategic Plan, Wind records, Joint-study with MISO, and the continued work in the West with the Western Energy Imbalance Service (WEIS). Ms. Sugg introduced SPP’s newest member of the Officer team, Ms. Kelly Carney,Vice President of Human Capital and Chief People Officer. b. Regional State Committee Report Regional State Committee (RSC) President Kristie Fiegen began her discussion by describing the phrase for the past year as the Silver Lining. Ms. Fiegen explained that the Silver Lining for Covid-19 is the RSC and Cost Allocation Working Group (CAWG) members are more engaged due to less travel which lead to increased attendance at events and leadership across the Commissioners. Ms. Fiegen announced that Iowa Utilities Board Member Geri Huser will be the new RSC secretary/treasurer. Ms. Fiegen acknowledged the SPP staff for their contributions to the RSC and CAWG over the last year. c. Oversight Committee Mr. Josh Martin presented the Oversight Committee (OC) report. He provided an update on the meetings that took place between the RTO and the Market Monitoring Unit in April 2021. Mr. Graham Edwards provided the Market Monitoring report. Mr. Julian Brix provided the Internal Audit report. Mr. Martin presented the 2021 Independent Expert Pool (IEP). The Oversight Committee recommended the Board approve the recommended candidates for the 2021 IEP. (Attachment – OC Presentation). Mr. Josh Martin made a motion to approve the recommended candidates for the 2021 IEP. Mr. Graham Edwards seconded. The Members Committee voted with one opposed-Golden Spread Electric Cooperative; and one abstention-SPS/Xcel Energy. The Board voted by email. The motion passed. d. Finance Committee Ms. Susan Certoma provided the Finance Committee (FC) report. Ms. Certoma discussed Committee membership, actions taken by the committee and discussion topics. (Attachment-FC Presentation). Ms. Bronwen Bastone made a motion to approve the 2021 Capex Funding recommendation. Mr. Julian Brix seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. e. Human Resources Committee Mr. Mark Crisson provided the Human Resources Committee (HRC) report. Mr. Crisson discussed the affirmative action plan, performance compensation, Human Resources metrics and the SPP benefits review. Ms. Liz Moore provided the Diversity, Equity, and Inclusion Task Force report. (Attachment-HRC Presentation).

3 of 306


4

f. Corporate Governance Committee Ms. Barbara Sugg provided the Corporate Governance Committee (CGC) report. Ms. Sugg discussed the March 8, 2021, meeting. The CGC discussed the 2021 Winter Weather event; delegated the review of Scope documents for groups reporting to the Markets and Operations Policy Committee (MOPC) to the MOPC; Strategic Planning Committee’s representation, and the Board of Directors Election process. g. Strategic Planning Committee Mr. Larry Altenbaumer provided the Strategic Planning Committee (SPC) quarterly report. Mr. Altenbaumer discussed the SPC members, meeting dates, Strategic Plan development, Strategic Planning Committee development, Transmission owner selection process review, Holistic Integrated Tariff Team update, 2023 ITP update and the West new member process. The Strategic Planning Committee recommends the Board approve the new SPP Mission, Vision, and Value Proposition. (Attachment-SPC Presentation). Ms. Susan Certoma made a motion to approve the new SPP Mission, Vision, and Value Proposition. Ms. Bronwen Bastone seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. h. Markets and Operations Policy Committee Ms. Denise Buffington presented the Markets and Operations Policy Committee (MOPC) Report. Ms. Buffington discussed the number of votes recorded at the April MOPC meeting, MOPC’s Initiatives, and the post-MOPC survey results. Mr. Antoine Lucas presented the quarterly ITP update. Mr. Lucas discussed 2021 ITP and 2023 ITP Mitigation. (Attachment – MOPC Presentation, ITP Presentation). Mr. Mark Crisson made a motion to accept Staff’s recommendation to delay the decision on the 2023 ITP until July 2021 with the understanding that the delay will cost an estimated $80,000. Ms. Bronwen Bastone seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. i. Staff Mr. Antoine Lucas presented the Butler to Tioga recommendation. SPP Staff recommends that the Board withdraw the Butler-Tioga 138 kV project, which includes the new 138 kV line between the existing Butler substation and the existing Tioga substation in Kansas that is subject to SPP-RFP-000004, as well as the associated substation upgrades included in NTC 210602. If the Board approves this recommendation, SPP will withdraw SPP-RFP-000004 in accordance with Section VIII of Attachment Y of the Tariff.

Mr. Mark Crisson made a motion to approve the Butler to Tioga recommendation. Ms. Susan Certoma seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. Agenda Item 4-Future Meetings

2021 RSC/BOD July 26-27 Little Rock, AR RSC/BOD October 25-26 Little Rock, AR BOD December 6 Virtual

4 of 306


5

2022 RSC/BOD January 24-25 Virtual RSC/BOD April 25-26 Location TBD RSC/BOD July 25-26 Virtual RSC/BOD October 24-25 Little Rock, AR BOD December TBD Conference Call

Adjournment With no further business, Mr. Altenbaumer adjourned the meeting at 11:50a.m. The Board and Members Committee went into executive session at 12:30p.m. Respectfully Submitted, Paul Suskie, Corporate Secretary

5 of 306

Aaron Shipley SPPAdam Bell SPPAdam McKinnie Missouri PSCAdam Schieffer OPPDAhmed Alazzawi Southwest Power PoolAl Tamimi SepcAl Taylor Holland & KnightAlan Myers ITC HoldingsAmber Greb SPPAndrew French Kansas Corporation CommissionAndrew Lachowsky Arkansas Electric CoopAnna Hyatt Iowa Utilities BoardAntoine Lucas SPPAntonio Barber SPPBarbara Sugg SPPBary Warren GridLiance GridLianceBen Bright SPPbernie cevera bernard cevera consultingBernie Liu Xcel EnergyBethany McCrrea TransourceBetsy Beck Enel Green Power North AmericaBill Dowling Midwest Energy, IncBill Grant SPSBleau LaFave NorthWestern EnergyBob Wittmeyer Longhorn PowerBrenda Prokop (ITC GP) ITC Holdings Corp.Brett Leopold ITC Great PlainsBrian Johnson (AEP OKTCo) AEPBrian Rounds AESL ConsultingBrian Smith Southwest Power PoolBritney Lloyd SPPBritt Runion Southwest Power PoolBronwen Bastone SPPBrooke Keene sppBruce Rew Southwest Power Pool, Inc.Calvin Daniels (WFEC) WFECCarl Huslig Grid Reliability Consulting LLCCarrie Dixon Xcel EnergyCasey Cathey Southwest Power PoolCharles Yeung SPPChris Cranford SPPChris Giles Tri County Electric CooperativeChris Jamieson Southwest Power PoolChris Jones City UtilitiesChristine Aarnes Sunflower Electric Power CorporationChristopher Davis SPPChristy Siharath OGE

6 of 306

Cindy Ireland AR PSCDana Murphy OCCDana Shelton LPSCDane Rogers OGE Energy Corp (OK Gas & Elec)Daniel Hall acpaDara Solomon SPPDarcy Ortiz SPP DirectorDaryl Huslig OGE Energy CorpDavid Hudson SPS / Xcel EnergyDavid Kelley SPPDavid Mindham EDP RenewablesDavid Osburn OMPADeborah Currie Southwest Power PoolDenise Buffington Evergy CompaniesDenise Martin SPPDennis Constien (SWPA) SWPADennis Grennan Nebr. Power Review BoardDennis Reed MWRCDerek Wingfield DeWayne Todd DDT LLCDon Frerking-SPP SPPEddie Watson SPPElizabeth Moore SPPEvan Johnson ACESFarrokh Rahimi OATIGayle Freier SPPGeri Huser Iowa Utilities BoardGraham Edwards SPPGreg Rislov SDPUCHarika Basaran (PUCT) PUCTHeather Starnes MJMEUCJ.P. Maddock BEPCJack Clark NextEra Energy ResourcesJack Madden GDS Associates, Inc.Jason Chaplin OCCJason Fortik Lincoln Electric SystemJason Mazigian Basin Electric Power CooperativeJay Caspary Grid Strategies LLCJeff Knottek City Utilities of Springfield, MOJeffery Riles Google LLCJeremy Severson Basin Electric Power CooperativeJillian Janik Southwest Power PoolJim Jacoby (AEP) AEP/PSOJim Krajecki Customized Energy Solutions, LTDJOE RICHARDSON XCEL ENERGYJoel Bladow Tri-State G&TJohn Boshears City Utilities of Springfield

7 of 306

John Krajewski NPRBJohn O'Dell SPPJohn Olsen Live Phase, LLCJohn Stephens City Utilities of SpringfieldJohn Tennyson SPRMJohn Varnell Tenaska power servicesJOHN WILLIAMS MPUAJon Sunneberg Nebraska Public Power DistrictJon Thurber South Dakota PUCJoseph Lang Omaha Public Power DistrictJosh Norton Southwest Power Pooljoshua martin SPPJoshua Phillips Southwest Power PoolJoshua Pilgrim SPPJulian Brix SPPJustin Hinton SPPKandi Hughes SPPKara Fornstrom Southwest Power PoolKassia Micek S&P Global PlattsKatie Southworth Sustainable FERC ProjectKaye McCarty SPPKayli Farris Southwest Power PoolKeith Collins (MMU) Southwest Power PoolKelly Carney SPPKevin Noblet EvergyKevin Smith Tenaska Power ServicesKirk Hall Southwest Power PoolKrishada Watson Southwest Power PoolKristie Fiegen SD PUCKristina Luke-Fry Kansas Corporation CommissionKylah McNabb Vesta Strategic Solutions, LLCLane Sisung LPSCLanny Nickell Southwest Power PoolLarry Altenbaumer SPP Directorlarry Holloway Kansas Power PoolLauren Krigbaum Southwest Power PoolLee Elliott Southwest Power PoolLen Tao Southwest Power PoolLiz Gephardt SPPLloyd Linke Western Area Power AdministrationLoren Ditsch OPPDLuke Haner OPPDMaggie Berry Golden Spread Electric Cooperative, Inc.Malcolm Ainspan NRGCSMarisa Choate SPPMark Crisson SPPMatt Caves (WFEC) Western Farmers Electric Cooperative

8 of 306

Matt Pawlowski NextEra Energy Resources, LLCMaurice Moss CUSMeghan Sever Southwest Power PoolMichael Desselle Southwest Power PoolMichael Spencer NPPDMICHAEL WISE Golden Spread Electric CooperativeMichelle Harris SPPMike Kraft Basin Electric Power CooperativeMike Mathis Continental ResourcesMike Riley SPPMike Ross SPPMike Wech SWPANatasha Henderson Golden Spread Electric Cooperative, Inc.Nate Morris Liberty Utilities / Empire DistrictNeeya Toleman NextEra EnergyNick Parker SPPNicole Wagner SPPNoman Williams GridLiance HPorijit ghoshal invenergyPat Hayes LS PowerPatrick Clarey FERCPatrick Woods ITC Great Plains, LLCPatti Kelly SPPPaul Suskie SPPPeggy Simmons AEP/PSOPhoenix Anshutz Kansas Corporation CommissionPIus Fischer BEPCRandel Christmann ND PSCRay Bergmeier Sunflower Electric Power CorporationRebecca Thiem Innovative Energy Alliance CooperativeRichard Ross(AEPSC) AEPSCRob Janssen Dogwood EnergyRobert Pick NPPDRobert Safuto Customized Energy SolutionsRobert Tallman OG&E OG&ERodney Massman MOPSCRussell Carey SPPRussell Quattlebaum Southwest Power Poolryan houk TransourceRyan Kirk (AEPSC) AEPSCSam Ellis SPPSam Loudenslager Southwest Power PoolSean Black Amerenseth cochrab dc energyShari Albrecht KCCShawn Geil KEPCoShawn Schukar Ameren

9 of 306

Sherri Maxey Southwest Power PoolSteve Drew NextEraSteve Gaw APASteve Hardebeck OG&ESteve Johnson SPPSteve Purdy SPPStuart Lowry Sunflower Electric Power CorporationSunny Raheem Southwest Power PoolSusan Certoma SPP DirectorTammy Bright SPPTara Smith Southwest Power PoolTed Thomas Arkansas PSCTerri Pyle Oklahoma Gas & ElectricTessie Kentner SPPTheo Brown SPPTom Christensen Basin ElectricTom Dunn SPPTom Hestermann Sunflower Electric Power CorporationTom Kent Nebraska Public Power DistrictTom Kleckner RTO InsiderTony Green Southwest Power PoolTraci Bender NPPDUsha-Maria Turner OGE EnergyVen Bujimalla IUBVincent Vandaveer City Utilities of Springfield, MOWalt Cecil Missouri Public Service CommissionZac Perkins TCEC

10 of 306

Antitrust: SPP strictly prohibits use of participation in SPP activities as a forum for engaging in practices or communications that violate the antitrust laws. Please avoid discussion of topics or behavior that would result in anti-competitive behavior, including but not limited to, agreements between or among competitors regarding prices, bid and offer practices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that might unreasonably restrain competition.

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

April 27, 2021 - Net Conference

Agenda

8:00 a.m. – 3:00 p.m.

Board of Directors/Members Committee Meeting

1. Call to Order and Administrative Items………………………………………………………….Mr. Larry Altenbaumer

2. Consent Agenda

a. Approve January 26, 2021 and March 2, 2021 Minutes b. Corporate Governance Committee

i. Recommendation – L and O Membership Agreement Amendment ii. Recommendation – Change User Forum Chair-Jodi Hall

c. Finance Committee i. Recommendation – 2020 Financial Audit ii. Recommendation – 2021 Benefit Plan Funding

d. Markets and Operations Policy Committee Report i. Recommendations:

i. Sponsored Upgrade SUS-016 Onida ii. Sponsored Upgrade SUS-019 Hughes County iii. Line-Mustang–Seminole 115 kV Ckt 1 Cost Variance iv. Line–Chaves-Price-CV Pines-Capitan 115 kV Ckt 1 NTC Mod.

e. Holistic Integrated Tariff Team i. Change Assignment Threshold for ERIS in the GI Study Process BP 7250 (RR435)

f. Staff i. Recommendation – Minco – Pleasant Valley – Draper ii. Evergy Short Circuit Breakers Out-of-Cycle NTC Re-evaluation iii. WAPA Devils Lake Reactor Out-of-Cycle NTC Re-evaluation

3. Reports to the Board

a. President’s Report .............................................................................................................. Ms. Barbara Sugg

b. Regional State Committee Report .........................................................RSC President Kristie Fiegen

c. Oversight Committee Report ........................................................................................... .Mr. Josh Martin

i. Draft State of the Market Report .................................................................. Mr. Keith Collins

ii. Recommendation – Independent Expert Pool for 2021 ........................ Mr. Josh Martin

d. Finance Committee Report ........................................................................................ Ms. Susan Certoma

i. Recommendation – 2021 Capex Funding

e. Human Resources Committee Report ........................................................................ Mr. Mark Crisson

f. Corporate Governance Committee.............................................................................Ms. Barbara Sugg

g. Strategic Planning Committee Report ............................................................. Mr. Larry Altenbaumer

i. Recommendation – Mission, Vision & Values

11 of 306

Antitrust: SPP strictly prohibits use of participation in SPP activities as a forum for engaging in practices or communications that violate the antitrust laws. Please avoid discussion of topics or behavior that would result in anti-competitive behavior, including but not limited to, agreements between or among competitors regarding prices, bid and offer practices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that might unreasonably restrain competition.

h. Markets and Operations Policy Committee Report ....................................Ms. Denise Buffington

i. 2021 ITP Mitigation Plan

i. Staff ......................................................................................................................................... Mr. Antoine Lucas

i. Recommendation - Butler - Tioga

4. Future Meetings

2021 RSC/BOD July 26-27 Little Rock, AR RSC/BOD October 25-26 Little Rock, AR BOD December 6 Virtual 2022 RSC/BOD January 24-25 Virtual RSC/BOD April 25-26 Location TBD RSC/BOD July 25-26 Virtual RSC/BOD October 24-25 Little Rock, AR BOD December TBD Conference Call

(NOTE: Attendance for the executive session is limited to the Board of Directors, Members Committee and Officers)

12 of 306

1

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING January 26, 2021 8:00a.m. – 3:00p.m. | Webex


1. Approved Consent Agenda Items

Approve December 7, 2020 Minutes CGC Committee Nominations

Finance Committee Nominations Al Tamimi, Sunflower Electric Power Co. – TO Matt Palowski, NextEra Energy Resources – TU

Human Resources Committee Scott Briggs, Oklahoma Gas & Electric –TO Maria Smedley, Arkansas Electric Cooperative Corporation – TU

Organizational Group Chair Credit Practices Working Group- Caleb Head

Corporate Governance Committee-Approval of Scopes from MOPC Re-Organization

MOPC Working Groups: i. Economic Studies Working Group ii. Market Working Group iii. Operating Reliability Working Group iv. Project Cost Working Group v. Regional Tariff Working Group vi. Supply Adequacy Working Group vii. Transmission Working Group

MOPC Advisory Groups: i. Model Development Advisory Group ii. Reliability Compliance Advisory Group iii. Seams Advisory Group iv. Security Advisory Group v. System Protection and Control Advisory Group

MOPC User Forums:

i. Change Users Forum ii. Generation Interconnection Users Forum iii. Operations Training Users Forum iv. Settlements Users Forum v. Transmission Service Users Forum

Credit Practices Working Group Scope

Finance Committee Amendment to Borrowing Resolution

Markets and Operations Policy Committee

RR424 Separation of RC Area SOL Methodology from Planning Criteria PCWG-Multi-Hobbs-Yokum 345/230 kV Ckt 1 PCWG-OOB XFR McDowell 230 115kV

13 of 306

SPP Board of Directors/Members Committee Minutes January 26, 2021

2

Holistic Integrated Tariff Team Report M2: Study Offer Requirements for Variable Resources White Paper M3: Study Automatic Mitigation of Unduly Low Offers White Paper M4a: Study Economic Evaluations of Reliability: Dynamic Line Rating Whitepaper

Staff Sooner-Wekiwa 345kV Assignment NTC 210542 EKC Modification NTC 200282 Withdrawal-Dollarhide-Tobosa Flats Santa Fe 138 kV Out-of-Cycle NTC Re-evaluation Request (Informational)

Market Monitoring Unit

WEIS Market FCA Study Recommendation

2. Approved MOPC 2021 SPP Transmission Expansion Plan Report

3. Approved Staff-2020 ITP-Butler to Tioga 138kV Scope Recommendation

4. Approved SPP Member Value Statement

14 of 306


3

Minutes No. 194

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING January 26, 2021 8:00a.m. – 3:00p.m. | Webex

MINUTES

Agenda Item 1 – Administrative Items SPP Board of Directors Chair Mr. Larry Altenbaumer called the regular meeting to order at 8:30 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy: Mr. Larry Altenbaumer, Director Ms. Bronwen Bastone, Director Mr. Julian Brix, Director Ms. Susan Certoma, Director Mr. Mark Crisson, Director Mr. Graham Edwards, Director Mr. Josh Martin, Director Ms. Liz Moore, Director Ms. Darcy Ortiz, Director Ms. Barbara Sugg, Director Ms. Betsy Beck, Enel Green Power North America Mr. Alan Myers-Proxy for Bleau LaFave, NorthWestern Energy Mr. Chris Jones, City Utilities of Springfield, MO Mr. Dave Osburn, Oklahoma Municipal Power Authority Mr. David Hudson, Xcel Energy Mr. Lloyd Linke, Western Area Power Administration – Upper Great Plains Region Mr. Joe Lang, Omaha Public Power District Mr. Joel Bladow, Tri-State Generation and Transmission Mr. Kevin Noblett, Evergy Companies Mr. Kevin Smith, Tenaska Power Services Company Mr. Mike Wise, Golden Spread Electric Cooperative, Inc. Ms. Peggy Simmons, Public Service of Oklahoma Mr. Rob Janssen, Dogwood Energy LLC Mr. Steve Gaw, Advanced Power Alliance Mr. Stuart Lowry, Sunflower Electric Power Corporation Mr. Nate Morris-Proxy for Tim Wilson, Liberty Utilities Mr. Tom Christensen, Basin Electric Power Cooperative Mr. Robert Pick-Proxy for Thomas Kent, Nebraska Public Power District Ms. Usha Turner, Oklahoma Gas and Electric Company Mr. Zac Perkins, Tri-County Electric Coop. There were 194 participants in attendance via net conference. Ms. Barbara Sugg reported the proxies for today’s meeting. (Attachment - Attendance). Agenda Item 2 – Consent Agenda

Mr. Larry Altenbaumer asked if there were any items that needed to be removed from the consent agenda; there were none. (Attachment- Consent Agenda).

15 of 306


4

Ms. Barbara Sugg moved to approve the consent agenda. Mr. Graham Edwards seconded the motion. The Members Committee voted and unanimously approved. The Board voted by email; the motion passed. Agenda Item 3 – Reports to the Board

a. President’s Report Ms. Barbara Sugg (SPP President and CEO) provided the SPP Report. She began her report by announcing Ms. Kara Fornstrom, former Chair of the Wyoming Public Service Commission, and Mr. Len Tao, former senior FERC staff member, have joined SPP. Ms. Sugg introduced the 2020 John Marschewski Leadership Award winners Erin Cathey and Glenn Bethea. She continued by announcing that SPP is the first Regional Transmission Organization (“RTO”) to have wind as its number one annual fuel source. She also announced that FERC approved the Western Energy Imbalance Service (WEIS) Tariff on December 23, 2020, and that she is looking forward to another historic moment when the WEIS market is launched on time and under budget on February 1, 2021. The majority of WEIS participants have submitted Letters of Interest to join SPP and the New Member Forum is underway with the first meeting being held on January 5, 2021. Ms. Sugg discussed the ongoing coordination efforts between the SPP and MISO and the joint study and the technical phase that kicked off in December 2020. Ms. Sugg concluded her report by providing an overview of the Strategic Planning Process and the goals for the upcoming year. b. Regional State Committee Report Regional State Committee (RSC) President Kristie Fiegen began her discussion by breaking down the meaning of each letter of the acronym “RSC”. “R” is for the many reports presented by the SCRIPT, FERC, and stakeholder meetings; “S” is for SEAMS that was discussed in a public setting, more discussion will continue on February 12, 2021; and “C” is for C1 Schedule 9 & 11 decoupling and C4 Storage devices as transmission assets that the RSC has been working together on for the greater good. c. Oversight Committee Mr. Josh Martin presented the Oversight Committee (OC) report. He provided an update on the meetings that took place between the RTO and the Market Monitoring Unit in December 2020 and January 2021. (Attachment – OC Presentation). d. Finance Committee Ms. Susan Certoma provided the Finance Committee (FC) report. Ms. Certoma discussed Committee membership, actions taken by the committee and discussion topics. (Attachment-FC Presentation). e. Strategic Planning Committee Mr. Larry Altenbaumer provided the Strategic Planning Committee (SPC) quarterly report. Mr. Altenbaumer discussed the SPC members, meeting dates, and current Strategic activities. (Attachment-SPC Presentation). Agenda Item 4. Markets and Operations Policy Committee Ms. Denise Buffington presented the Markets and Operations Policy Committee (MOPC) Report. Ms. Buffington discussed the Revision Request summary for January 2021, new groups, and the 2021 goals. Mr. Antoine Lucas presented the 2021 SPP Transmission Expansion Plan report. SPP Staff recommends the Board approve MOPC’s endorsement of the 2021 SPP Transmission Expansion Plan report as documentation of completion of the Attachment O STEP requirements.

16 of 306


5

Mr. Mark Crisson made a motion to approve the 2021 STEP Report; seconded by Mr. Graham Edwards. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. Agenda Item 5 – SPP Staff Recommendation Mr. Antoine Lucas presented the 2020 ITP – Butler to Tioga 138kV Scope recommendation as a carryover item from the October 2021 board meeting. SPP staff recommended that the SPP Board approve the construction of a new 138kV line between the existing Butler substation and the existing Tioga substation in Kansas. (Attachment - Butler to Tioga Presentation) Ms. Denise Buffington presented the Butler to Tioga 138kV line recommendation on behalf of Evergy, Companies. (Attachment – Evergy-SPP BOD Butler – Tioga 138kV Reevaluation) Mr. Larry Altenbaumer made a motion to approve the construction of a new 138kV line between the existing Butler substation and the existing Tioga substation in Kansas including construction for the Butler to Tioga substation upgrades necessary to accept the new line. Additionally, the Board will meet as soon as possible after a request for restudy is submitted. The Members Committee voted- six members approved, eleven members opposed, and two abstentions. The Board voted by email. The motion passed. Agenda Item 6 – SPP Member Value Statement Mr. Lanny Nickell presented the Southwest Power Pool Member Value Statement Improvement Effort. Staff recommends that the Board of Directors and Members Committee affirm the proposed methodology described in the attached Member Value 2020 – SPP’s Member Value Statement and Methodology that will be used to annually calculate the aggregate value of SPP. (Attachment-MOPC Presentation) Mr. Julian Brix made a motion to approve the SPP Member Value Statement as presented. Ms. Bronwen Bastone seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. Agenda Item 7-Future Meetings

2021 RSC/BOD April 26-27 Virtual RSC/BOD July 26-27 Little Rock, AR RSC/BOD October 25-26 Little Rock, AR BOD December 6 Virtual

Adjournment With no further business, Mr. Altenbaumer adjourned the meeting at 12:30p.m. The Board and Members Committee went into executive session at 1:00p.m. Respectfully Submitted, Paul Suskie, Corporate Secretary

17 of 306

1

SPECIAL BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING March 2, 2021 10:30a.m. – 12:00p.m. | Webex


1. Approved a Comprehensive Review of the 2021 winter storm by the Comprehensive Review Steering Committee

2. Approved Staff-2020 ITP-Butler-Tioga 138kV Scope Recommendation and approved the

suspension of the Transmission Owner Selection Process (TOSP) for SPP-RFP-000004 and

associated NTC 210602 for the required non-competitive portions of the Butler-Tioga 138kV

project.

18 of 306

Special Board of Directors/Members Committee Minutes March 2, 2021

2

Minutes No. 195

SPECIAL BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING March 2, 2021 10:30a.m. – 12:00p.m. | Webex

MINUTES

Agenda Item 1 – Administrative Items SPP Board of Directors Chair Mr. Larry Altenbaumer called the special meeting to order at 10:30 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy: Mr. Larry Altenbaumer, Director Mr. Julian Brix, Director Ms. Susan Certoma, Director Mr. Mark Crisson, Director Mr. Graham Edwards, Director Mr. Josh Martin, Director Ms. Liz Moore, Director Ms. Barbara Sugg, Director Ms. Betsy Beck, Enel Green Power North America Mr. Bleau LaFave, NorthWestern Energy Mr. John Stephens, Proxy for Mr. Chris Jones, City Utilities of Springfield, MO Mr. Dave Osburn, Oklahoma Municipal Power Authority Mr. David Hudson, Xcel Energy Mr. Lloyd Linke, Western Area Power Administration – Upper Great Plains Region Mr. Joe Lang, Omaha Public Power District Ms. Mary-Ann Zehr, Proxy for Mr. Joel Bladow, Tri-State Generation and Transmission Ms. Denise Buffington, Proxy for Mr. Kevin Noblett, Evergy Companies Mr. Brad Cox, Proxy for Mr. Kevin Smith, Tenaska Power Services Company Mr. Mike Wise, Golden Spread Electric Cooperative, Inc. Ms. Peggy Simmons, Public Service of Oklahoma Mr. Rob Janssen, Dogwood Energy LLC Mr. Steve Gaw, Advanced Power Alliance Mr. Stuart Lowry, Sunflower Electric Power Corporation Mr. Tim Wilson, Liberty Utilities Mr. Tom Christensen, Basin Electric Power Cooperative Mr. Thomas Kent, Nebraska Public Power District Ms. Usha Turner, Oklahoma Gas and Electric Company Mr. Zac Perkins, Tri-County Electric Coop. There were 270 participants in attendance via net conference. (Attachment - Attendance). Agenda Item 2 – February Polar Vortex Update a. Event Summary Mr. Lanny Nickell provided the February 2021 Winter Storm Event update. Mr. Nickell discussed the early preparations, public appeals for reduced demand, service interruptions, and how collaboration controlled temporary interruptions and prevented uncontrolled blackouts. Mr. Nickell explained the various alert levels and operations within the Balancing Authority. (Attachment-2021 Winter Event Presentation).

19 of 306

Special Board of Directors/Members Committee Minutes March 2, 2021

3

b. Expedited FERC Filings/Orders Mr. Paul Suskie provided an update on expedited Federal Energy Regulatory Commission (FERC) filings and orders for two waiver requests-Settlement Posting Waiver and the Collateral Call 2-Day Waiver. (Attachment- Expedited FERC Orders Presentation). c. Comprehensive Review Steering Committee Ms. Barbara Sugg provided a description of a 2021 Winter Storm Event Comprehensive Review process. Ms. Sugg discussed the need for internal and external reviews; the goals of the SPP reviews; five-parallel paths for an Operational review, Financial review, Regional State Committee review, Market Monitoring Unit review and a Communications review. (Attachment – Comprehensive Review Steering Committee Presentation). Mr. Graham Edwards made a motion to initiate a 5-path collaborative review of the 2021 winter storm event with coordination and oversight to be provided by the Comprehensive Review Steering Committee. Overall assessments and lessons learned to be reported to the board of directors in July 2021. Ms. Susan Certoma seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. Agenda Item 3. SPP Staff Recommendation a. Butler – Tioga 138kV Re-evaluation and TOSP Suspension Mr. Antoine Lucas presented the Butler to Tioga 138kV re-evaluation request. Mr. Lucas discussed the background, re-evaluation requirements and recommendations. SPP Staff recommends the approval of re-evaluation of the Butler-Tioga 138kV project and the approval for suspension of the Transmission Owner Selection Process (TOSP) for SPP-RFP-000004 and associated NTC 210602 for the required non-competitive portions of the Butler-Tioga 138kV project. Mr. Graham Edwards made a motion to approve re-evaluation of the Butler-Tioga 138kV project and approve the suspension of the TOSP for SPP-RFP-000004 and associated NTC 210602 for the required non-competitive portions of the Butler-Tioga 138kV project. Mr. Mark Crisson seconded. The Members Committee voted and unanimously approved. The Board voted by email. The motion passed. Agenda Item 7-Future Meetings

2021 RSC/BOD April 26-27 Virtual RSC/BOD July 26-27 Little Rock, AR RSC/BOD October 25-26 Little Rock, AR BOD December 6 Virtual

Adjournment With no further business, Mr. Altenbaumer adjourned the meeting at 12:00 p.m. Respectfully Submitted, Paul Suskie, Corporate Secretary

20 of 306

Southwest Power Pool, Inc.

Corporate Governance Committee

Recommendation to the SPP Board of Directors

April 27, 2021

Amendment to Membership Agreement

L and O Power Cooperative

Background

L and O Power Cooperative (“L&O”), a member of Basin Electric Power Cooperative (“Basin Electric”), has requested certain amendments be made to SPP’s Membership Agreement that are materially the same as amendments approved by the Corporate Governance Committee (“CGC”), the Board of Directors, and accepted by the Federal Energy Regulatory Commission for the following entities:

Heartland Consumers Power District (“Heartland”) (Docket No. ER14-2851)

Basin Electric (Docket No. ER14-2851)

Basin Electric members: Central Power Electric Cooperative, Inc. (“Central Power”) (Docket No. ER16-539) East River Electric Power Cooperative, Inc. (“East River”) (Docket No. ER15-1906) Northwest Iowa Power Cooperative (“NIPCO”) (Docket No. ER15-1906) Corn Belt Power Cooperative (“Corn Belt”) (Docket No. ER15-1906) Mountrail-Williams Electric Cooperative (“Mountrail-Williams”) (Docket No. ER16-539) Mor-Gran-Sou Electric Cooperative, Inc. (“Mor-Gran-Sou”) (Docket No. ER19-453) Roughrider Electric Cooperative, Inc. (“Roughrider”) (Docket No. ER20-1731)

The integration of the Integrated System parties (Western Area Power Administration – Upper Great Plains Region (“Western-UGP”), Basin Electric, and Heartland) occurred on October 1, 2015.

L&O plans to sign the SPP Membership Agreement as soon as the amendment is approved by the CGC and the Board of Directors.

Analysis

The amendments proposed are designed to address the interconnected nature between this Basin Electric member and the Integrated System. The cooperative is embedded within the Integrated System.

The Corporate Governance Committee considered and approved a Membership Agreement amendment for L&O as follows:

21 of 306

1) Dispute Resolution: Disputes under the Membership Agreement or SPP Bylaws will be subject to binding dispute resolution under Section 3.13 of the SPP Bylaws only with consent of the entity’s board and subject to terms and conditions the entity’s board may impose.

2) Withdrawal Rights: Allows the entity to terminate membership with less notice than prescribed in Section 4.2.2 of the Membership Agreement if: Basin Electric withdraws, Western-UGP withdraws, or FERC finds SPP has not complied with the Membership Agreement amendments of the entity, Basin Electric, or Western-UGP. If Basin Electric or Western-UGP withdraws, the entity’s withdrawal is effective the same date and the entity is subject to the financial withdrawal obligations of the Membership Agreement.

3) Obligation to Build: The entity’s obligation to construct transmission facilities is subject to the discretionary authority of its board of directors. The entity’s board will not supplant any state regulatory authority over siting or permitting under state law.

Recommendation: The CGC recommends that the BOD approve the SPP Membership Agreement

amendment of L&O as reflected in the attachments. Approved: Corporate Governance Committee March 8, 2021

Action Requested:

Approve Recommendation

Attachments: L&O Membership Agreement Amendment Comparison to Basin Electric Membership Agreement Amendment

22 of 306

AMENDMENTS TO SPP MEMBERSHIP AGREEMENT

FOR L and O POWER COOPERATIVE

A1. Dispute Resolution

Notwithstanding any provisions in the Agreement or the SPP Bylaws to the contrary, any

disputes arising under the Agreement or SPP Bylaws and relating to determinations,

decisions, conduct and actions made or taken by L and O Power Cooperative ("L&O")

pursuant to its participation in SPP shall be subject to binding resolution under Section

3.13 of the SPP Bylaws only to the extent agreed upon by L&O’s board of directors, and

subject to the terms and conditions set by L&O’s board of directors.

A2. Withdrawal Rights

L&O may terminate this Agreement and withdraw as a member of SPP with less than the

advance notice required by Section 4.2.2 of the Agreement in the event that (1) Western

Area Power Administration-Upper Great Plains Region (“Western-UGP”) or Basin

Electric Power Cooperative (“Basin Electric”) withdraws from SPP in accordance with

its withdrawal rights; (2) FERC finds that SPP has not adhered to all of the Federal Power

Marketing Agency Amendments or all of the Basin Electric Amendments; or (3) SPP

files and FERC approves one or more changes to the L&O Amendments without L&O’s

consent, and such changes have a material adverse effect on L&O. In such event, L&O

and SPP shall meet and confer to facilitate the withdrawal as soon as practicable or as

necessary to ensure compliance with state or Federal law. In the event of a withdrawal

by Western-UGP or Basin Electric, L&O’s withdrawal will become effective on the same

date as that of Western-UGP or Basin Electric. If L&O exercises its withdrawal rights

under this provision, the financial obligations will be calculated under § 4.3 of this

Agreement.

A3. Obligation to Build Conditions

L&O’s board of directors shall have discretionary authority to decide whether L&O will

construct new transmission facilities. L&O’s board of directors shall not replace any state

regulatory authority with responsibility for siting activities under state law.

IN WITNESS WHEREOF, L&O and SPP have caused their duly authorized

representatives to execute, on their respective behalves, these Amendments to L&O's

Membership Agreement with SPP, which Amendments are fully applicable and incorporated into

said Membership Agreement and together shall constitute one and the same instrument binding

upon L&O and SPP.

23 of 306

AMENDMENTS TO SPP MEMBERSHIP AGREEMENT

FOR L and O BASIN ELECTRIC POWER COOPERATIVE

A1. Dispute Resolution

Notwithstanding any provisions in the Agreement or the SPP Bylaws to the contrary, any

disputes arising under the Agreement or SPP Bylaws and relating to determinations,

decisions, conduct and actions made or taken by L and O Basin Electric Power

Cooperative ("L&OBasin Electric") pursuant to its participation in SPP shall be subject to

binding resolution under Section 3.13 of the SPP Bylaws only to the extent agreed upon

by L&O’s Basin Electric’s board of directors, and subject to the terms and conditions set

by L&OBasin Electric’s board of directors.

A2. Withdrawal Rights

L&OBasin Electric may terminate this Agreement and withdraw as a member of SPP

with less than the advance notice required by Section 4.2.2 of the Agreement in the event

that (1) Western Area Power Administration-Upper Great Plains Region (“Western-

UGP”) or Basin Electric Power Cooperative (“Basin Electric”) withdraws from SPP in

accordance with its withdrawal rights; (2) FERC finds that SPP has not adhered to all of

the Federal Power Marketing Agency Amendments or all of the Basin Electric

Amendments; or (3) SPP files and FERC approves one or more changes to the L&O

Basin Electric Amendments without L&OBasin Electric’s consent, and such changes

have a material adverse effect on L&OBasin Electric. In such event, L&OBasin Electric

and SPP shall meet and confer to facilitate the withdrawal as soon as practicable or as

necessary to ensure compliance with state or Federal law. In the event of a withdrawal

by Western-UGP or Basin Electric, L&OBasin Electric’s withdrawal will become

effective on the same date as that of Western-UGP or Basin Electric. If L&O Basin

Electric exercises its withdrawal rights under this provision, the financial obligations will

be calculated under § 4.3 of this Agreement.

A3. Obligation to Build Conditions

L&O’s Basin Electric’s board of directors shall have discretionary authority to decide

whether L&O Basin Electric will construct new transmission facilities. L&O’s Basin

Electric’s board of directors shall not replace any state regulatory authority with

responsibility for siting activities under state law.

IN WITNESS WHEREOF, L&O Basin Electric and SPP have caused their duly

authorized representatives to execute, on their respective behalves, these Amendments to

L&OBasin Electric's Membership Agreement with SPP, which Amendments are fully applicable

and incorporated into said Membership Agreement and together shall constitute one and the

same instrument binding upon L&OBasin Electric and SPP.

24 of 306

Southwest Power Pool, Inc. CHANGE USERS FORUM

Recommendation to the Board of Directors April 27, 2021

CHAIR NOMINATION TO FILL EXPIRING TERM

Organizational Roster The following persons are members of the Change Working Group:

Arash Ghodsian Jonathan Hathhorn Brad Lafler Justin Friedman Bradley Parker Kevin Carter Brian McArdle Neil Lindgren Carrie Dixon (Chair) Nichole Braunberger Danny Ragsdale Paulo Araujo Doug (Byron) Singletary Ron Allen Greg Thurnher Ron Chartier Jacob (Jake) Burger Ryan Kirk Jeff Rives Ryan Tuter Jerin Purtee Shane Jenson Jodi Hall (Vice Chair) Shawn Geil Joe Dan Wilson Steve Gaw John Seck

Background A representative nominated from the Change Users Forum was approved by the Corporate Governance Committee to serve as Chair of the committee for a two-year term.

Analysis The Corporate Governance Committee is responsible for approving a chairman for the Change Users Forum for consideration and election at the SPP Board of Directors meeting in April. Jodi Hall, Evergy has been nominated for a two-year term to commence January 1, 2021.

Recommendation Recommend Jodi Hall to chair the Change Users Forum. Jodi Hall has served successfully as the vice chair of the Change Users Forum for the past two years and has agreed to serve as the chair for the upcoming term. Jodi has extensive experience in SPP’s Integrated Marketplace and actively participates in a number of SPP stakeholder meetings and stakeholder committees. Jodi’s in-depth industry knowledge allows her to understand varying perspectives and bridge communication within and across SPP stakeholder groups. Jodi’s leadership and facilitation skills provide an ability to ensure the group remains cohesive and productive. The committee endorses Jodi Halls’ nomination as the chair of the Change Users Forum.

25 of 306

No other nomination was received for this position.

Approved: Corporate Governance Committee 2/16/21

Change Working Group 12/17/20

The Change Working Group elected Jodi Hall, Evergy as the new chair of the Change Users Forum.

Action Requested:

Approve the recommendation of Jodi Hall, Evergy.

26 of 306


FINANCE COMMITTEE

Recommendation to the Board of Directors

April 27, 2021

2020 Financial Audit Acceptance

Organizational Roster

The following persons are members of the Finance Committee:

Susan Certoma Julian Brix Darcy Ortiz Sarah Stafford Matt Pawlowski Sandra Bennett Al Tamimi Mike Wise

SPP Director SPP Director SPP Director OG&E NextEra AEP Sunflower Golden Spread

Background

SPP annually engages a Certified Public Accounting firm to audit its financial statements and accounting controls. SPP has engaged BKD, LLC to perform audits of its financial reports since fiscal year 2004. SPP last performed a request for proposal for the financial audit engagement in July 2020.

Analysis

BKD, LLC has completed and published its audit of SPP’s 2020 financial statements. The Finance Committee, at its April 15, 2021 meeting met with representatives of BKD, LLC and discussed their findings, specifically focusing on: 1) adequacy of SPP’s accounting policies and procedures, 2) adequacy of internal control procedures and the extent tested, and 3) any areas of weakness or concern that SPP should address going forward.

BKD’s opinion will be unqualified. No issues or material/significant weaknesses were noted during the audit. BKD informed the Committee of upcoming changes in accounting standards.

Recommendation

The Finance Committee recommends the SPP Board of Directors accept in its entirety the 2020 audit report and findings of BKD, LLC.

Approved: SPP Finance Committee April 15, 2021

Action Requested: Approve Recommendation

27 of 306


Independent Auditor’s Report and Financial Statements

December 31, 2020 and 2019

28 of 306

Southwest Power Pool, Inc. December 31, 2020 and 2019

Contents

Independent Auditor’s Report ............................................................................................... 1

Financial Statements

Balance Sheets .................................................................................................................................... 3

Statements of Income ......................................................................................................................... 4

Statements of Members’ Deficit ......................................................................................................... 5

Statements of Cash Flows .................................................................................................................. 6

Notes to Financial Statements ............................................................................................................ 8

29 of 306

Independent Auditor’s Report

Board of Directors Southwest Power Pool, Inc. Little Rock, Arkansas We have audited the accompanying financial statements of Southwest Power Pool, Inc., which comprise the balance sheets as of December 31, 2020 and 2019, and the related statements of income, members’ deficit, and cash flows for the years then ended, and the related notes to the financial statements. Management’s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s Responsibility Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

30 of 306

Board of Directors Southwest Power Pool, Inc. Page 2

Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Power Pool, Inc. as of December 31, 2020 and 2019, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America. Little Rock, Arkansas April 15, 2021

31 of 306

Southwest Power Pool, Inc. Balance Sheets (in Thousands)


See Notes to Financial Statements

Assets

2020 2019Current Assets

Cash and cash equivalents 76,128$ 48,694$ Restricted cash deposits 445,550 401,478 Accounts receivable 85,251 74,285 Prepaid expenses and other 11,883 11,714

Total current assets 618,812 536,171

Property and Equipment, at CostLand 4,812 4,812 Building and improvements 68,373 68,373 Furniture and fixtures 10,538 10,328 Equipment and machinery 61,459 56,025 Software 169,976 185,622 Software in development 4,298 7,081

319,456 332,241 Less accumulated depreciation and amortization 250,329 258,151

69,127 74,090

Investments (Note 2 ) 29,160 35,276

Other Assets, Net 8,337 6,349

725,436$ 651,886$

32 of 306

3

Liabilities and Members’ Deficit

2020 2019Current Liabilities

Accounts payable 78,204$ 60,811$ Customer deposits 445,550 401,478 Current maturities of long-term debt (Note 4 ) 27,260 22,596 Accrued expenses 86,878 79,569 Deferred revenue 8,243 5,203

Total current liabilities 646,135 569,657

Line of Credit (Note 3) 12,090 12,760

Long-term Debt (Note 4 ) 154,871 169,603 Less unamortized debt issuance costs (518) (613)

154,353 168,990

Other Long-term Liabilities 45,980 44,241

Members’ Deficit (133,122) (143,762)

725,436$ 651,886$

33 of 306

Southwest Power Pool, Inc. Statements of Income (in Thousands)

Years Ended December 31, 2020 and 2019

See Notes to Financial Statements 4

2020 2019Operating Income

Tariff fees and member assessments $ 197,235 188,518$ Other member services 16,367 7,171

213,602 195,689 Operating Expenses

Salaries and benefits 110,578 101,221 Employee travel 375 1,907 Administrative 5,081 4,865 Regulatory assessment 22,324 20,591 Meetings 274 933 Communications system 4,754 4,449 Maintenance 15,686 16,308 Consulting services 15,861 14,909 Depreciation and other 18,480 16,930

193,413 182,113

Operating Income 20,189 13,576

Other Income (Expense)Investment income 576 665 Interest expense (8,210) (8,550) Change in fair market value of interest rate swaps (196) (322) Other income (expense) 2,583 (744)

(5,247) (8,951)

Income Before Unrealized Gain and Change in FundedStatus of Employee Benefit Plans 14,942 4,625

Unrealized Gain on Investments 144 2,552

Change in Funded Status of Employee Benefit Plans (4,446) (845)

Net Income 10,640$ 6,332$

34 of 306

Southwest Power Pool, Inc. Statements of Members’ Deficit (in Thousands)



2020 2019

Balance, Beginning of Year (143,762)$ (150,094)$

Net income 10,640 6,332

Balance, End of Year (133,122)$ (143,762)$

35 of 306

Southwest Power Pool, Inc. Statements of Cash Flows (in Thousands)



2020 2019Operating Activities

Net income 10,640$ 6,332$ Items not requiring cash

Depreciation, amortization and other 18,582 17,036 Change in funded status of employee benefit plans 4,446 845 Unrealized gain on investments (144) (2,552) Loss on disposal of fixed assets - 46 Change in fair market value of interest rate swaps (196) (322)

Changes in assets and liabilitiesAccounts receivable (10,966) (8,743) Prepaid expenses and other (169) 743 Other assets (1,996) 288 Accounts payable 17,326 (16,495) Accrued expenses and other liabilities 9,692 (12,519) Other current liabilities 44,072 56,573 Other long-term liabilities (2,511) 3,617

Net cash provided by operating activities 88,776 44,849

Investing ActivitiesAcquisition of property and equipment (12,792) (14,056) Purchase of investments (70,761) (55,859) Proceeds from investment maturities 66,372 47,042 Proceeds from sale of investments 10,648 1,526

Net cash used in investing activities (6,533) (21,347)

Financing ActivitiesRepayments of long-term debt (25,767) (22,281) Repayments of capital lease obligation - (1,966) Repayment of borrowings under lines of credit (44,087) (76,583) Borrowings under lines of credit 43,417 89,003

Issuance of long-term debt 15,700 -

Net cash used in financing activities (10,737) (11,827)

Increase in Cash, Cash Equivalents, and Restricted Cash 71,506 11,675

Cash, Cash Equivalents, and Restricted Cash, Beginning of Year 450,172 438,497

Cash, Cash Equivalents, and Restricted Cash, End of Year 521,678$ 450,172$

Supplemental Cash Flows Information

Interest paid on long-term debt (net of interest capitalizedof $0 and $209 in 2020 and 2019, respectively) 8,093$ 8,474$

Property and equipment purchases in accounts payable and accrued liabilities 3,156$ 2,431$

36 of 306

Southwest Power Pool, Inc. Statements of Cash Flows (in Thousands)



2020 2019

Cash and cash equivalents 76,128$ 48,694$ Restricted cash deposits 445,550 401,478

Total cash, cash equivalents and restricted cashshown on the balance sheet 521,678$ 450,172$

37 of 306

Southwest Power Pool, Inc. Notes to Financial Statements (in Thousands)


8

Note 1: Nature of Operations and Summary of Significant Accounting Policies

Nature of Operations

Southwest Power Pool, Inc. (the Company) is a not-for-profit entity formed in 1941 and incorporated in 1994. The Company is a Federal Energy Regulatory Commission (FERC)-approved regional transmission organization (RTO) serving more than 19 million ultimate customers across all or parts of 17 states. The Company’s membership consists of investor-owned utilities, municipal systems, generation and transmission cooperatives, state authorities, federal agencies, independent power producers, contract participants, power marketers, independent transmission companies, alternative power/public interest companies and large retail customers.

Major services provided by the Company to its members and customers include tariff administration, reliability coordination, regional scheduling, market operations and regional transmission expansion planning. Market operations encompass day-ahead and real-time markets, transmission congestion rights, reliability unit commitment, operating reserve market and consolidated balancing authority.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents and Deposits

The Company considers all highly liquid interest-earning investments with stated maturities and coupon rate reset dates of no more than three months to be cash equivalents. At December 31, 2020 and 2019, the Company’s cash and cash equivalents, including restricted deposits, are invested primarily in money market funds, mutual funds and commercial paper. These investments are typically revalued to the market each day. The Company’s cash and cash equivalents consist primarily of funds accumulated for general operating purposes. Restricted cash deposits consist primarily of customer security deposits, amounts deposited for engineering studies and funds set aside for disputed invoices.

Investments

The Company’s investments include equity and fixed income mutual funds and government securities. These investments are recorded at fair value, with unrealized gains and losses reported as nonoperating income. Dividends, interest income and realized gains and losses are reported as investment income. The Company’s investments are intended to be utilized in funding benefits associated with the Company’s postretirement health care plan and maintaining collections under Schedule 12 to be utilized for the annual FERC assessment.

Income Taxes

The Company is exempt from income taxes under Section 501c(6) of the Internal Revenue Code and a similar provision of state law. However, the Company is subject to federal income tax on any unrelated business taxable income.

38 of 306



9

Accounts Receivable

Accounts receivable are stated at the amount of consideration from members, customers, and others of which the Company has an unconditional right to receive plus any accrued and unpaid interest. The Company provides an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Accounts that are unpaid after the due date are subject to interest at a rate set by FERC. During the years ended December 31, 2020 and 2019, no allowance for doubtful accounts was recorded.

Property and Equipment

Property and equipment over $5 are recorded at cost and depreciated on a straight-line basis over the estimated useful life of each asset. The estimated useful lives are as follows:

Building 20 years Building improvements Shorter of useful life or remaining life of building Furniture and fixtures 5 years Vehicles 5 years Equipment and machinery 3 years Software 3 years

The Company capitalizes interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Interest cost capitalized was $0 and $209 in 2020 and 2019, respectively.

The Company capitalizes development costs, including interest, for internal use software costs. These costs are included in software in development. Management of the Company is of the opinion that all costs capitalized in association with the software in development are fully recoverable over the anticipated life of the asset.

Long-Lived Asset Impairment

The Company evaluates the recoverability of the carrying value of long-lived assets whenever events or circumstances indicate the carrying amount may not be recoverable. If a long-lived asset is tested for recoverability and the undiscounted estimated future cash flows expected to result from the use and eventual disposition of the asset is less than the carrying amount of the asset, the asset cost is adjusted to fair value and an impairment loss is recognized as the amount by which the carrying amount of a long-lived asset exceeds it fair value.

In 2020, the Company recorded an impairment loss of $379 for implementation cost associated with customized software held in work in progress. No asset impairment was recognized during the year ended December 31, 2019. The amount is recorded as an impairment loss in the accompanying statements of income and is included in the line item Depreciation and other.

39 of 306



10

Revenue Recognition

Revenues, consisting of member assessments, tariff administrative fees, contract services and miscellaneous revenues are recognized when performance obligations are satisfied, and expenses are recognized when incurred.

Customer Deposits

Customers may be required to make deposits with the Company prior to the performance of transmission services, market transactions and engineering studies. An offsetting liability equal to the deposit balance is recorded in current liabilities. Funds set aside for any disputed invoices are also recorded as customer deposits under current liabilities.

Tariff Fees and Member Assessments

An administrative charge is applied to all transmission service under the Company’s Open Access Transmission Tariff (tariff) to cover the expenses related to its administration. The charge is calculated in accordance with the terms of the Company’s tariff. The administrative rate used for the calculation is established by the board of directors.

Members are assessed monthly based on their prior year average 12-month peak demand multiplied by the total hours in a month and by the monthly assessment rate as established by the board of directors.

A member’s monthly assessment is offset dollar for dollar for qualifying tariff administrative fees collected from a member in any given assessment period.

The Company collects a membership fee from each member annually. The amount of the membership fee is established by the board of directors of the Company. For 2020 and 2019, all members paid a $6 membership fee.

The Company also bills transmission customers a charge under Schedule 12 on all energy delivered under point-to-point transmission service and network integration transmission service. This provides a mechanism for recovering the annual charges the Company pays to FERC.

Deferred Revenue

Revenues for services received in advance are recognized over the periods to which the revenues relate.

Other Member Services

The Company provides reliability, tariff administration and scheduling for non-members on a contract basis. The Company also provides engineering study services for long-term transmission service and generation interconnection requests.

40 of 306



11

Withdrawing Members

Prior to December 2019, members wishing to withdraw their membership from the Company must provide 24 months’ written notice and were responsible for their portion of the Company’s existing obligations as defined in the bylaws, which included unpaid membership fees, any assessments imposed prior to the effective withdrawal date, any costs or expenses imposed upon the Company as a direct consequence of the member’s withdrawal and the member’s share of long-term obligations and related interest. Additionally, withdrawing members were responsible for all financial obligations incurred and costs allocated to its load for transmission facilities approved prior to their withdrawal. As a result of a complaint, FERC ordered the Company in its ruling dated December 19, 2019 to revise its membership agreement and bylaws to eliminate for non-transmission owners the membership exit fee comprised of member’s share of long-term obligations and related interest. FERC also ordered the Company to revise its exit fee formula to ensure that the Company’s debt is fully covered by the continued application of the exit fee to transmission-owning members. As of December 31, 2020, the Company had not been notified by any member of their intent to withdraw their membership from the Company.

Concentration of Credit Risk

The Company is exposed to credit risk primarily through accounts receivable and uninsured cash balances. During 2020 and 2019, the Company maintained cash balances, including transaction accounts and short-term investment accounts that are not insured by the Federal Deposit Insurance Corporation. At December 31, 2020, the Company had one transaction account exceeding the federal insurance limit by $245. The Company did not have transaction accounts exceeding federal insurance limits at December 31, 2019. The Company’s investment accounts were primarily invested in highly liquid short-term investments such as money market funds, mutual funds, and commercial paper. The Company also requires the financial institutions holding its cash balances to be rated A or better by nationally recognized rating agencies.

The Company considers its accounts receivable to be highly probable of collection. No allowance for doubtful accounts was recorded for 2020 and 2019.

The Company requires its customers to meet certain minimum standards of financial condition and creditworthiness to receive unsecured credit from the Company. If these standards cannot be met by a customer, the Company requires the posting of defined financial security instruments to cover potential liabilities.

Economic Uncertainties

As a result of the spread of the SARS-CoV-2 virus and the incidence of COVID-19, economic uncertainties have arisen which may negatively affect the financial position, results of operations and cash flows of the Company. The duration of these uncertainties and the ultimate financial effects cannot be reasonably estimated at this time

41 of 306



12

Note 2: Investment and Investment Returns

Investments at December 31 consisted of the following:

2020 2019

Mutual Funds

Equity 2,523$ 10,354$

Fixed income 1,292 3,737 Total mutual funds 3,815 14,091

U.S. Government Securities

Treasury Notes 25,345 21,185 Total Government Securities 25,345 21,185

29,160$ 35,276$

Total investment return is comprised of the following:

2020 2019

Interest and dividends reported at fair value 576$ 665$ Unrealized gains on

investments reported at fair value 144 2,552

720$ 3,217$

Interest, dividends and realized gains and losses are reported as investment income, while unrealized gains and losses are reported separately in the Statements of Income.

Note 3: Lines of Credit

The Company has a $30,000 revolving line of credit with a commercial bank expiring in 2021. At December 31, 2020 and 2019, no amounts were borrowed against this line. The agreement has a variable interest rate equal to the 2020 and 2019 London Interbank Offered Rate (LIBOR) plus a 1.00% credit margin. The interest rate at December 31, 2020 and 2019, was 1.19% and 2.75%, respectively. The Company’s line of credit requires compliance with certain financial and non-financial covenants as well as periodic reporting requirements. The Company was in compliance with the covenant and reporting requirements throughout and at December 31, 2020.

42 of 306



13

The Company has a $80,000 revolving line of credit expiring in 2023. At December 31, 2020 and 2019, $12,090 and $12,760, respectively, was borrowed against this line. The agreement has a variable interest rate equal to London Interbank Offered Rate (LIBOR) plus a 1.5 % credit margin, with a floor of 2.75%. The interest rate at December 31, 2020 and 2019, was 2.75% and 3.19%, respectively. The Company’s line of credit requires compliance with certain financial and non-financial covenants as well as periodic reporting requirements. The Company was in compliance with the covenant and reporting requirements throughout and at December 31, 2020.

Note 4: Long-term Debt and Interest Rate Swaps

Long-term Debt

2020 2019

Variable Rate Term Note due 2027 (A) 2,313$ 2,519$

4.82% Series 2010-A and B Senior Notes due 2042 (B) 55,540 56,930

3.55% Series 2010-C Senior Notes due 2024 (C) 22,750 29,750

3.00% Series 2012-D-1 Senior Notes due 2024 (D) 16,250 21,250

3.25% Series 2012-D-2 Senior Notes due 2024 (E) 18,750 23,750

3.80% Series 2014-E Senior Notes due 2025 (F) 37,000 37,000

Floating Series Note - 2024 (G) 17,000 21,000

2.875% Fixed Rate Note due 2023 (H) 3,497 -

2.875% Fixed Rate Note due 2024 (I) 9,031 -

182,131 192,199

Less unamortized debt issuance costs 518 613

Less current maturities 27,260 22,596

154,353$ 168,990$

(A) Due February 1, 2027; principal and interest are payable quarterly based on a 25-year amortization. Payments commenced on May 1, 2007. The interest rate adjusts quarterly based on LIBOR plus 0.85%. At December 31, 2020 and 2019, the interest rate was 1.13% and 2.81%, respectively. The note is secured by a first mortgage on the Company’s operation facility.

(B) Due December 30, 2042; principal and interest are payable quarterly based on a 32-year amortization. Principal payments commenced on March 30, 2013. The interest rate is fixed at 4.82%. The notes are unsecured.

(C) Due March 30, 2024; principal and interest are payable quarterly based on a 13-year amortization. Principal payments commenced on June 30, 2014. The interest rate is fixed at 3.55%. The notes are unsecured.

43 of 306



14

(D) Due March 30, 2024; principal and interest are payable quarterly based on a 10-year amortization. Principal payments commenced on June 30, 2014. The interest rate is fixed at 3.00%. The notes are unsecured.

(E) Due September 30, 2024; principal and interest are payable quarterly based on a 10-year amortization. Principal payments commenced on December 30, 2014. The interest rate is fixed at 3.25%. The notes are unsecured.

(F) Due December 30, 2025; principal and interest are payable quarterly based on an 11 year and 9 months amortization. Principal payments commence on March 30, 2024. The interest rate is fixed at 3.80%. The notes are unsecured.

(G) Due March 30, 2024; principal and interest are payable monthly based on an eight-year amortization. Payments commenced on June 30, 2016. The interest rate adjusts monthly based on LIBOR plus 1.75%. At December 31, 2020 and 2019, the interest rate was 1.90% and 3.46%, respectively. The note is unsecured.

(H) Due December 31, 2023; principal and interest are payable quarterly based on a 4-year amortization. Payments commenced on June 30, 2020. The interest rate is fixed at 2.875%. The note is unsecured.

(I) Due March 30, 2024; principal and interest are payable quarterly based on a 4-year amortization. Payments commenced on June 30, 2020. The interest rate is fixed at 2.875%. The note is unsecured.

Aggregate annual maturities of long term debt at December 31, 2020, are:

2021 27,260$

2022 27,694

2023 28,558

2024 25,865

2025 23,972

Thereafter 48,782

182,131$

Certain of the Company’s term notes require compliance with financial and nonfinancial covenants, as well as periodic reporting requirements. The Company was in compliance with the covenant and reporting requirements throughout and at December 31, 2020.

In an April 2019 Order, FERC directed the Company to eliminate the membership exit fee from non-transmission owners and revise the exit fee formula to ensure that the continued application to transmission owners ensures that the Company’s debt is fully secured. In August 2019, the Company submitted a Section 206 compliance filing to FERC, which amends the Company’s Membership Agreement and Bylaws to clearly establish an exit fee that only applies to transmission owning members in compliance with the FERC order.

44 of 306



15

The Company notified its debt holders of a potential event of default under the agreements as a result of the April 2019 Order. During 2020, the Company executed amendments to all of its note agreements to bring the terms of the agreements in line with the requirements imposed on the Company by the FERC order, thereby eliminating the potential event of default.

Variable-to-Fixed Interest Rate Swap

As a strategy to maintain acceptable levels of exposure to the risk of changes in future cash flows due to interest rate fluctuations, the Company enters into interest rate swap agreements. On September 15, 2006, the Company entered into an interest rate swap agreement with U.S. Bank National Association. The agreement provides for the Company to receive interest from the counterparty at LIBOR and to pay interest to the counterparty at a fixed rate of 5.51% on notional amounts of $2,295 and $2,499 at December 31, 2020 and 2019, respectively. Under the agreement, the Company pays or receives the net interest amount quarterly, with the quarterly settlements included in interest expense. The swap was established to hedge interest rate risk on its floating rate debt obligation (Loan A).

The Company entered into another interest rate swap agreement on March 10, 2014, with Regions Bank. The agreement provides for the Company to receive interest from the counterparty at LIBOR and to pay interest to the counterparty at a fixed rate of 3.225% on notional amounts of $17,000 and $21,000 at December 31, 2020 and 2019, respectively. Under the agreement, the Company pays or receives the net interest amount monthly, with the monthly settlements included in interest expense. The swap was established to hedge interest rate risk on its floating rate debt obligation (Loan G).

The table below presents certain information regarding the Company’s interest rate swap agreements.

2020 2019

Fair value of interest rate swap agreements 1,510$ 1,314$

Balance sheet location of fair value amounts Other Long-term Liabilities

Other Long-term Liabilities

Loss recognized in statement of income (196)$ (322)$

Location of loss recognized in statement of incomeChange in Fair

Market Value of Interest Rate Swaps

Change in Fair Market Value of

Interest Rate Swaps

Note 5: Capital Lease Obligation

The Company entered into a capital lease obligation on February 1, 2015, in the amount of $6,901 to finance data storage equipment. The term of the financing was five years and expired on November 1, 2019.

45 of 306



16

Note 6: Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

The Company has a noncontributory defined benefit pension plan covering all employees meeting eligibility requirements. The Company’s funding policy is to make the minimum annual contribution that is required by applicable regulations, plus such amounts as the Company may determine to be appropriate from time to time. The Company expects to contribute approximately $5,100 to the plan in 2021.

The Company has a noncontributory defined benefit postretirement health care plan that was partially terminated in 2020, leaving only current retirees drawing benefits in the plan. The plan covered eligible retirees, including those retiring between the ages of 55–65 and hired prior to January 1, 1996. Employees hired after June 1, 2006 were not eligible to participate in the plan. As a result of the partial termination of the plan, the Company paid eligible non-vested employees and eligible vested employees lump sum payments in the amount of $3,516 in lieu of future benefits. The Company also recorded a settlement gain of $4,475 as a result of partial termination of the plan which is reported under Other Income (Expense) in the statements of income. Current retirees remaining in the plan are provided monies through a tax-free health reimbursement account to pay for individual Medicare supplemental health insurance plans or other eligible health care expenses.

The Company uses a December 31 measurement date for the plans. Information about the plans’ funded status is as follows:

2020 2019 2020 2019

Benefit obligation 138,422$ 115,547$ 3,890$ 11,476$

Fair value of plan assets 102,489 87,657 - -

Funded status (35,933)$ (27,890)$ (3,890)$ (11,476)$

Postretirement

Health Care BenefitsPension Benefits

Amounts recognized in the balance sheets:

2020 2019 2020 2019

Other long-term liabilities (35,933)$ (27,890)$ (3,890)$ (11,476)$

Pension Benefits Health Care Benefits

Postretirement

46 of 306



17

Amounts recognized in members’ deficit not yet recognized as components of net periodic benefit cost as of December 31, 2020 and 2019, consist of:

2020 2019 2020 2019

Net loss 26,119$ 21,291$ 1,018$ 4,553$

Prior service credit (26) (25) - (1,157)

Transition obligation - 16 - 4

26,093$ 21,282$ 1,018$ 3,400$

Pension Benefits Health Care Benefits

Postretirement

The accumulated benefit obligation for the defined benefit pension plan was $110,573 and $93,595 at December 31, 2020 and 2019, respectively.

Other significant balances and costs are:

2020 2019 2020 2019

Employer contributions 5,000$ 5,400$ -$ -$ Benefits paid 1,265 3,341 136 139

Benefit costs 8,232 7,633 770 1,050

Postretirement Pension Benefits Health Care Benefits

No amounts for the postretirement plan were funded by the Company into the investment account intended to be utilized in providing benefits for eligible retirees in 2020 and 2019.

The following amounts have been recognized in the Statements of Income for the years ended December 31, 2020 and 2019:

2020 2019 2020 2019Amounts arising during the period

Net gain (loss) 7,381$ 8,757$ 1,190$ 677$

Amounts recognized as benefit components of net periodic cost of the period

Net loss 695 775 171 187

Net prior service cost (credit) 1 1 (48) (83)

Net transition obligation 16 16 3 4

Pension Benefits

Postretirement Health Care Benefits

47 of 306



18

The components of net periodic benefit cost other than the service cost component are included in the line item Other Expense in the statements of income and shown below:

2020 2019 2020 2019

(30)$ 778$ 501$ 642$

Pension Benefits Health Care BenefitsPostretirement

The estimated net loss, prior service cost and transition obligation for the defined benefit pension plan that will be amortized from members’ equity into net period benefit credit over the next fiscal year are $877, $1 and $0, respectively. The estimated net loss, prior service credit and net obligation for the defined benefit postretirement health care plan that will be amortized from members’ equity into net periodic benefit cost over the next fiscal year are $105, $0 and $0, respectively.

Weighted-average assumptions used to determine benefit obligations and costs:

2020 2019 2020 2019

Discount rate benefit obligation 4.0% 4.5% 4.0% 4.5%

Expected return on plan assets 7.0% 7.0% N/A N/A

Rate of compensation increase 4.0% 4.0% N/A N/A

Health Care Benefits

Postretirement

Pension Benefits

The Company has estimated the long-term rate of return on plan assets based primarily on historical returns on plan assets, adjusted for changes in target portfolio allocations and recent changes in long-term interest rates based on publicly available information.

For measurement purposes, a 9% annual rate of increase in the per capita cost of covered health care benefits in the next year was assumed for 2020 and 2019. The rate was assumed to decrease gradually to 5% by the year 2025 and remain at that level thereafter.

48 of 306



19

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid as of December 31:

Postretirement

Pension Health Care

Benefits Benefits

2021 1,661$ 168$

2022 1,970 191

2023 2,207 213

2024 2,510 240

2025 2,921 250

2026-2030 22,833 1,241

The Company’s investment strategy is based on an expectation that equity securities will outperform fixed income securities over the long term. Accordingly, the composition of the Company’s plan assets is broadly characterized as a 70/30 allocation between equity and fixed income securities. The strategy utilizes indexed and actively managed mutual fund instruments as well as direct investment in individual equity and fixed income securities. Investments in the plan must adhere to the Investment Policy Statement developed by the Company. The Investment Policy Statement limits investments in foreign securities to 20% of the total fair value of plan assets. The Investment Policy Statement is reviewed annually.

At December 31, 2020 and 2019, plan assets by category are as follows:

2020 2019

Fixed income securities 29% 30%Equity securities 69 65

Cash and equivalents 2 5

100% 100%

Pension Plan Assets

Pension Plan Assets

Following is a description of the valuation methodologies used for the pension plan assets measured at fair value on a recurring basis and recognized in the accompanying balance sheets, as well as the general classification of the assets pursuant to the valuation hierarchy.

49 of 306



20

Where quoted market prices are available in an active market, plan assets are classified within Level 1 of the valuation hierarchy. Level 1 plan assets include cash, money market accounts, closed-end mutual funds and common and foreign company stock. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of plan assets with similar characteristics or discounted cash flows. Level 2 plan assets include open-end mutual funds, corporate debt obligations, foreign corporate debt obligations and foreign government securities.

In certain cases where Level 1 or Level 2 inputs are not available, plan assets are classified within Level 3 of the hierarchy. At December 31, 2020 and 2019, the Company does not hold any plan assets valued using Level 3 inputs.

The fair values of the Company’s pension plan assets at December 31, 2020 and 2019, by asset category are as follows:

Quoted Prices inActive Markets for Significant Other SignificantIdentical Assets Observable Inputs Unobservable

2020 (Level 1) (Level 2) (Level 3)

Money market mutual funds 1,907$ 1,907$ -$ -$ Mutual funds

Equity funds 59,954 41,061 18,893 - Fixed income funds 26,829 19,510 7,319 - Other Funds 1,018 - 1,018 -

87,801 60,571 27,230 - Domestic common stock

Financials 4,673 4,673 - - Industrials 2,490 2,490 - - Healthcare 1,988 1,988 - - Real Estate 748 748 - - Telecommunications 465 465 - - Other 211 211 - -

10,575 10,575 - -

Corporate debt obligations 2,206 - 2,206 -

Total 102,489$ 73,053$ 29,436$ -$

Fair Value Measurements Using

Fair Value

50 of 306



21

Quoted Prices in Active Markets for

Identical AssetsSignificant Other

Observable Inputs

Significant Unobservable

Inputs2019 (Level 1) (Level 2) (Level 3)

Money market mutual funds 3,987$ 3,987$ -$ -$ Mutual funds

Equity funds 45,828 30,342 15,486 - Fixed income funds 23,314 16,878 6,436 - Other funds 523 - 523 -

69,665 47,220 22,445 - Domestic common stock

Financials 4,170 4,170 - - Healthcare 2,146 2,146 - - Industrials 2,271 2,271 - - Telecommunications 632 632 - - Other 765 765 - - Energy 1,294 1,294 - -

11,278 11,278 - -

Corporate debt obligations 2,727 - 2,727 -

Total 87,657$ 62,485$ 25,172$ -$


Fair Value

Defined Contribution Plans

The Company has a 401(k) defined contribution plan covering substantially all employees. The Company matches contributions at 4.75% for those employees deferring 6% of compensation, with the match fluctuating from 1% to 4.75% for each percentage of compensation contributed under 6%. Contributions to the plan were $3,264 and $3,035 for 2020 and 2019, respectively.

The Company has a 457(b) non-qualified tax-deferred compensation plan. This plan is an unfunded plan maintained for the purpose of providing deferred compensation for a select group of management or highly compensated employees and, therefore, is intended to be exempt from the participation, vesting, funding and fiduciary requirements of Title I of the Employee Retirement Income Security Act of 1974 (ERISA). Accumulated contributions and earnings of $4,426 and $3,561 are recorded in other long-term liabilities at December 31, 2020 and 2019, respectively. The Company also offers a 457(f) non-qualified tax-deferred compensation plan to a select group of executive management. The 457(f) plan was intended to be exempt from the participation, vesting, funding and fiduciary requirements of Title I of ERISA and serves to further supplement benefits lost due to IRS limits on compensation and benefits. There were accrued benefits of $221 and $554 recorded in other long-term liabilities for the 457(f) plan participants December 31, 2020 and 2019, respectively.

51 of 306



22

Note 7: Revenue from Contracts with Customers

In 2020 and 2019, the Company’s revenues were derived from a number of sources including tariff administration fees, FERC fees, engineering studies, contract services, and other miscellaneous income sources. The table below presents a complete breakdown of the Company’s revenues:

2020 2019

Tariff administration fees (Schedule 1A) 172,377$ 157,997$ FERC fees (Schedule 12) 24,240 29,927 Engineering studies 7,896 4,902 Contract services 6,247 669 Virtual market participation fees 816 691 Membership dues 618 594 Other miscellaneous income 1,404 909

213,598$ 195,689$

The Company recovers its costs of operating through the Schedule 1-A tariff administration fee that is billed to transmission customers on a monthly basis. With this fee, the Company seeks to recover the costs associated with providing tariff administration, reliability coordination, regional scheduling, expansion planning, and integrated marketplace services. A per MWh fee is charged based on each customer’s prior year average 12 month peak demand multiplied by the total hours in a month. The fee is established by the board of directors annually. The Company also bills transmission customers a charge under Schedule 12 to recover the annual fees the Company pays to FERC. The rate is determined by the Company annually and applied monthly to all energy delivered under point-to-point transmission service and network integration transmission service. Revenues are recognized, customers are billed, and payments are collected on a monthly basis for both Schedule 1A and Schedule 12 revenues. The Company performs engineering studies for its customers, mainly for long-term transmission service and generator interconnection requests. Prior to commencement of studies, customers sign contracts with the Company and are responsible for actual costs of the study which are generally comprised of staff time of internal and external resources. The Company recognizes revenues on a monthly basis as costs are incurred for such resources. Deposits are required from customers when they register for the studies. Actual costs are applied against such deposits at the conclusion of studies and customers are refunded their excess deposits. Customers will be invoiced at the end of or during a study if their deposit is not sufficient to cover the actual costs. The Company provides reliability, tariff administration, scheduling and other administrative and billing services for non-members on a contract basis. Similar to engineering studies, revenues are determined based on actual costs of providing such services and recognized on a monthly basis evenly over the service period which is usually one year. Customers are generally billed and payments collected from customers prior to the service period. The Company collects a membership fee from each member annually. The amount of the membership fee is established by the board of directors. For 2020 and 2019, all members paid a $6 fee which is billed and recognized in January of each year.

52 of 306



23

The Company charges financial-only market participants a transaction fee of $0.05 per virtual energy bid and virtual energy offer in the day-ahead market. Invoicing, settlements, and revenue recognition occur on a weekly basis. Other miscellaneous income is comprised of various pass-thru costs, purchase and tax rebates, small administrative service fees, and sales of maps. The Company elected the following practical expedient: Measuring Progress for Revenue Recognized Over Time (606-10-55-18). The Company elected to use the right to invoice practical expedient. This practical expedient allows an entity to recognize revenue in the amount of consideration to which the entity has the right to invoice when the amount that the entity has the right to invoice corresponds directly to the value transferred to the customer.

Note 8: Related Party Transactions

General disbursements of the Company are apportioned to members based on the formula described in the bylaws of the Company (see Note 1). The Company’s receivables from members totaled $80,539 and $23,756 as of December 31, 2020 and 2019, respectively. The Company recognized revenues $167,269 and $146,574, including assessments and tariff administrative fees, from members for the years ended December 31, 2020 and 2019, respectively.

The Southwest Power Pool Regional State Committee (RSC) was incorporated on April 7, 2004, in the state of Arkansas. The RSC is comprised of commissioners from public service commissions or equivalent, having regulatory authority over Company members. FERC, in its February 20, 2004 order regarding the Company’s RTO application, stated, “the RSC should have primary responsibility for determining regional proposals and the transition process for funding of regional transmission enhancements, rate structure for a regional access charge and allocation of transmission rights.” The RSC prepares budgets annually for the expected costs of its operations. This budget is submitted to the Company’s board of directors for approval. The Company includes in its annual budget funds sufficient to cover 100% of the operating costs of the RSC. During 2020 and 2019, the Company incurred $81 and $301, respectively, in expenses attributable to the RSC operations. Management of the Company expects such expenditures for 2021 to be approximately $498.

Note 9: Open Access Transmission and Market Operations

The Company provides short- and long-term firm and non-firm point-to-point transmission services and network integration transmission service across 47 providers in 17 states. The Company is responsible for the billing of the transmission customers for the respective services and the remittance of the subsequent collections to the transmission owners on a monthly basis. Billings for these transmission services are not included in the statements of income. The Company receives a fee for facilitating the transmission process, which is recorded as tariff fees in the Company’s Statements of Income.

For the years ended December 31, 2020 and 2019, the Company billed transmission customers $2,354,384 and $2,325,085, respectively. For the years ended December 31, 2020 and 2019, the Company remitted to transmission owners and upgrade sponsors $2,148,230 and $2,086,986, respectively. At December 31, 2020 and 2019, the Company was due to collect from transmission customers and remit to transmission owners and upgrade sponsors transmission service charges of $182,075 and $172,920, respectively.

53 of 306



24

The Company’s Integrated Marketplace includes a day-ahead market with transmission congestion rights, a reliability unit commitment process, a real-time balancing market, an operating reserve market and a consolidated balancing authority. Weekly settlements of market participants’ energy transactions are not reflected in the Company’s Statements of Income since they do not represent revenues or expenses of the Company, as the Company merely acts as an intermediary in the settlement process. In this role, the Company receives and disburses funds to/from market participants on a weekly basis. At December 31, 2020 and 2019, the Company held $34,758 and $35,494, respectively, in cash collections from the settlement of auction revenue rights in accordance with terms of the Company’s tariff. These funds are disbursed annually in June for collections from the previous twelve months. A corresponding liability is reflected in accrued expenses on the Balance Sheets.

Note 10: Commitments and Contingencies

Litigation and Regulatory Matters

The Company is engaged in various legal and regulatory proceedings at both the federal and state levels. The Company is also subject to claims and lawsuits that arise primarily in the ordinary course of business.

It is the opinion of management that the disposition or ultimate resolution of such proceedings, claims and lawsuits will not have a material adverse effect on the financial position, results of operations and cash flows of the Company.

Note 11: Disclosures About Fair Value of Financial Instruments

ASC Topic 820, Fair Value Measurements, defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Topic 820 also specifies a fair value hierarchy, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:

Level 1 Quoted prices in active markets for identical assets or liabilities

Level 2 Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities

Level 3 Unobservable inputs that are supported by little or no market activity and are significant to the fair value of the assets or liabilities

54 of 306



25

Quoted Prices in Active

Markets for Identical Assets

Significant Other

Observable Inputs


Inputs(Level 1) (Level 2) (Level 3)

December 31, 2020

Mutual funds

Equity $ 2,523 $ - $ 2,523 $ - Fixed income 1,292 - 1,292 -


Treasury Notes 25,345 25,345 - - Interest rate swap agreements (1,510) - (1,510) -


Fair Value

Quoted Prices in Active

Markets for Identical Assets

Significant Other

Observable Inputs


Inputs(Level 1) (Level 2) (Level 3)

December 31, 2019

Mutual funds

Equity 10,354$ -$ 10,354$ -$

Fixed income 3,737 - 3,737 -


Treasury Notes 21,185 21,185 - -

Interest rate swap agreements (1,314) - (1,314) -


Fair Value

Following is a description of the valuation methodologies used for assets and liabilities measured at fair value on a recurring basis and recognized in the accompanying Balance Sheets, as well as the general classification of such assets and liabilities pursuant to the valuation hierarchy. There have been no significant changes in the valuation techniques during the year ended December 31, 2020.

Investments

Where quoted market prices are available in an active market, securities are classified within Level 1 of the valuation hierarchy. If quoted market prices are not available, then fair values are estimated by using quoted prices of securities with similar characteristics or independent asset pricing services and pricing models, the inputs of which are market-based or independently sourced market parameters, including, but not limited to, yield curves, interest rates, volatilities, prepayments, defaults, cumulative loss projections and cash flows. Such securities are classified in Level 2 of the valuation hierarchy. In certain cases where Level 1 or Level 2 inputs are not available, securities are classified within Level 3 of the hierarchy. At December 31, 2020 and 2019, the Company does not hold any assets valued using Level 3 inputs.

55 of 306



26

Interest Rate Swap Agreements

The fair value is estimated using forward-looking interest rate curves and discounted cash flows that are observable or that can be corroborated by observable market data and, therefore, are classified within Level 2 of the valuation hierarchy.

Cash Equivalents

The fair value of money market mutual funds included in cash equivalents is estimated using quoted prices in active markets for identical assets and, therefore, is classified within Level 1 of the valuation hierarchy.

The Company has no assets or liabilities measured and recognized in the accompanying Balance Sheets on a nonrecurring basis.

The following methods were used to estimate the fair value of all other financial instruments recognized in the accompanying Balance Sheets at amounts other than fair value.

Restricted Cash Deposits

For these short-term instruments, the carrying amount is a reasonable estimate of fair value.

Customer Deposits

The carrying amount is a reasonable estimate of fair value.

Line of Credit

The carrying amount is a reasonable estimate of fair value.

Long-term Debt and Capital Lease Obligations

Fair value is estimated based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities.

56 of 306



27

The following table presents estimated fair values of the Company’s financial instruments at December 31, 2020 and 2019:

Fair Fair Value Value

Financial assets

Cash and cash equivalents 76,128$ 76,128$ 48,694$ 48,694$

Restricted cash deposits 445,550$ 445,550$ 401,478$ 401,478$

Investments 29,160$ 29,160$ 35,276$ 35,276$

Financial liabilities

Customer deposits 445,550$ 445,550$ 401,478$ 401,478$

Line of credit 12,090$ 12,090$ 12,760$ 12,760$

Long-term debt 182,131$ 197,763$ 192,199$ 199,412$

Swap agreements 1,510$ 1,510$ 1,314$ 1,314$

2020 2019

Carrying Amount

Carrying Amount

Note 12: Subsequent Events

Subsequent events have been evaluated through April 15, 2021, which is the date the financial statements were available to be issued.

57 of 306

Finance Committee and Board of Directors Southwest Power Pool, Inc. Little Rock, Arkansas As part of our audit of the financial statements of Southwest Power Pool, Inc. (the Company) as of and for the year ended December 31, 2020, we wish to communicate the following to you. AUDIT SCOPE AND RESULTS Auditor’s Responsibility Under Auditing Standards Generally Accepted in the United States of America

An audit performed in accordance with auditing standards generally accepted in the United States of America is designed to obtain reasonable, rather than absolute, assurance about the financial statements. In performing auditing procedures, we establish scopes of audit tests in relation to the financial statements taken as a whole. Our engagement does not include a detailed audit of every transaction. Our engagement letter more specifically describes our responsibilities. These standards require communication of significant matters related to the financial statement

audit that are relevant to the responsibilities of those charged with governance in overseeing the financial reporting process. Such matters are communicated in the remainder of this letter or have previously been communicated during other phases of the audit. The standards do not require the auditor to design procedures for the purpose of identifying other matters to be communicated with those charged with governance. An audit of the financial statements does not relieve management or those charged with governance of their responsibilities. Our engagement letter more specifically describes your responsibilities. Qualitative Aspects of Significant Accounting Policies and Practices Significant Accounting Policies The Company’s significant accounting policies are described in Note 1 of the audited financial statements.

58 of 306

Finance Committee and Board of Directors Southwest Power Pool, Inc. Page 2

Alternative Accounting Treatments No matters are reportable. Management Judgments and Accounting Estimates Accounting estimates are an integral part of financial statement preparation by management, based on its judgments. The following areas involve significant estimates for which we are prepared to discuss management’s estimation process and our procedures for testing the reasonableness of those estimates:

Pension and postretirement health benefits liabilities

Interest rate swaps Financial Statement Disclosures The following areas involve particularly sensitive financial statement disclosures for which we are prepared to discuss the issues involved and related judgments made in formulating those disclosures:

Pension and other postretirement benefit plans

Fair value measurements

Revenue recognition

Commitments and contingencies

Audit Adjustments No matters are reportable. Auditor’s Judgments About the Quality of the Entity’s Accounting Principles No matters are reportable. Significant Issues Discussed with Management Prior to Retention No matters are reportable.

59 of 306


During the Audit Process No matters are reportable. Other Material Communications Listed below are other material communications between management and us related to the audit:

Management representation letter (attached) We orally communicated to management a deficiency in internal control identified

during our audit that is not considered a material weakness or significant deficiency. FUTURE ACCOUNTING PRONOUNCEMENTS New Lease Accounting Standard On February 25, 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02, Leases (Topic 842), the new standard on lease accounting. Under the new ASU, lessees will recognize lease assets and liabilities on their balance sheet for all leases with terms of more than 12 months. The new lessee accounting model retains two types of leases and is consistent with the lessee accounting model under existing GAAP. One type of lease (finance leases) will be accounted for in substantially the same manner as capital leases are accounted for today. The other type of lease (operating leases) will be accounted for (both in the income statement and statement of cash flows) in a manner consistent with today’s operating leases. Lessor accounting under the new standard is fundamentally consistent with existing GAAP. Lessees and lessors would be required to provide additional qualitative and quantitative disclosures to help financial statement users assess the amount, timing, and uncertainty of cash flows arising from leases. These disclosures are intended to supplement the amounts recorded in the financial statements so that users can understand more about the nature of an organization’s leasing activities. For nonpublic entities, the final leases standard will be effective for fiscal years beginning after December 15, 2021, and interim periods beginning after December 15, 2022. Early application is permitted.

60 of 306


This communication is intended solely for the information and use of management, the finance committee and the board of directors and is not intended to be and should not be used by anyone other than these specified parties. April 15, 2021 Enclosures

61 of 306


FINANCE COMMITTEE


April 27, 2021

2021 Funding for Pension and Post-retirement Healthcare Plans



Susan Certoma Julian Brix Darcy Ortiz Sarah Stafford Sandra Bennett Al Tamini Matt Pawlowski Mike Wise

SPP Director SPP Director SPP Director OG&E American Electric Power Sunflower Electric NextEra Golden Spread

Background

The SPP Finance Committee is charged with reviewing reports from the plan’s actuary, establishing funding policies, and recommending annual funding levels for the plans to the SPP Board of Directors. SPP engaged Osborn, Carreiro & Associates (“the Actuary”) to prepare actuarial valuation reports of the SPP Defined Benefit Retirement Plan and SPP Post-retirement Benefits Plan as of January 1, 2021.

Analysis

SPP Defined Benefit Retirement Plan

The report identifies 2021 accounting expense for this plan as well as minimum and maximum contributions for the plan. The Actuary determined 2021’s minimum contribution level to be $0.00 and suggested level to be $5.50. SPP’s 2021 budget anticipated contributions to the defined benefit pension plan of $5.00.

The schedule below illustrates the historical funding of the SPP Defined Benefit Retirement Plan:

2017 2018 2019 2020 2021

Maximum Contribution (tax deductible) $61.01 $69.18 $86.13 $89.66 $126.65 Minimum Contribution $0.00 $0.00 $0.00 $0.00 $0.00 Actuary Suggested Contribution 5.20 4.59 5.44 5.00 5.50 Actual Contribution 5.20 4.50 5.44 5.00 Projected Benefit Obligation (PBO) $85.89 $96.52 $115.55 $138.42 Accumulated Benefit Obligation (ABO) 68.96 78.42 93.60 110.73 Fair Value of Plan Assets 70.18 71.59 87.66 102.49 Discount Rate 5.00% 5.00% 4.50% 4.00%

Plan Assets vs. PBO -$15.71 -$24.93 -$27.89 -$35.93 Plan Assets vs. ABO -1.22 -6.83 -5.94 -8.24 Total Participants 796 819 824 858 Benefits Paid $0.79 $0.94 $3.34 $1.26

62 of 306

SPP Defined Benefit Retirement Plan Fund Status as of December 31, 2020

The fund had total assets of $102.49 versus an Accumulated Benefit Obligation of $110.57, Projected Benefit Obligation of $138.42 and termination value of approximately $103.00. The Actuary estimates participants active on January 1, 2021 will accrue $5.10 in benefits during fiscal year 2021. Finally, the value of the early retirement feature of the Defined Benefit Retirement Plan is estimated to be $2.00.

SPP Post-retirement Benefits Plan

In 1995, the Board of Directors approved retiree medical coverage for all SPP employees who retire at their Normal Retirement Date as defined in the SPP Defined Benefit Retirement Plan. The Board also awarded benefits under this plan to those employees of record on January 1, 1996 who retire between the ages of 55 - 65. The SPP Board acted in 2006 to limit benefits from this plan to only those employees hired prior to June 1, 2006. The SPP Board acted in 2020 to terminate the plan for unvested eligible participants. As of January 1, 2021 SPP had 28 retirees covered by this plan.

The Actuary estimated 2021 net periodic post-retirement benefit cost to be $0.77. This computation is based on a 4.00% discount rate and retirement at age 65. The health care cost trend was assumed to increase 9% next year, 8% the year after and so on down to 5% and remain there thereafter.

If the plan were a funded plan and the assets SPP has set aside to cover benefits were considered in the actuarial calculations; the actuary would suggest SPP fund an additional $0.00 during 2021. SPP’s 2021 budget allocates $0.00 in funding for post-retirement benefits. Assets SPP has set aside to cover benefits are below the accumulated benefit obligation as of year-end 2020 by approximately $0.09.

2017 2018 2019 2020 2020

Actual Contribution $0.00 $0.00 $0.00 $0.00 Pension Cost $1.11 $1.02 $1.05 $1.10 $0.77 Accumulated Benefit Obligation (ABO) $9.47 $10.34 $11.48 $3.89 Fair Value of Plan Assets1 11.96 11.58 14.09 3.80 Funded Status vs. ABO 2.49 1.24 2.61 -0.09 Plan Participants – Active 105 100 96 0 Plan Participants – Retired 22 23 24 28

Recommendation

Approve 2021 funding of the SPP Retirement Plan of $5.10

Approve 2021 funding of the SPP Post-retirement Healthcare Plan of $0.00



1 The Post-retirement Healthcare plan is an unfunded plan and therefore has no plan assets. The plan sponsor has set aside specific assets with the intent to use those assets to pay benefits under the plan.

63 of 306

SOUTHWEST POWER POOL

RETIREMENT PLAN

ACTUARIAL VALUATION

AS OF JANUARY 1, 2021

64 of 306

65 of 306

66 of 306

67 of 306

68 of 306

TABLE OF CONTENTS

EXHIBITS:

Exhibit 1

Executive Summary

Exhibit 2

Summary of Financial Information

Exhibit 3

Accounting Information

Exhibit 4

Participant Data

Exhibit 5

Principal Provisions of the Plan

APPENDICES:

Appendix A

Calculation of Contributions

Appendix B

Costs and Liabilities

Appendix C

Development of the Unfunded Actuarial Accrued Liability

Appendix D IRC 430 Calculations

Appendix E

Amortization of Short Falls

Appendix F

Contributions and Funding Balances

Appendix G

Top-Heavy Test

Appendix H

Actuarial Cost Methods and Assumptions

69 of 306

1

EXHIBIT 1

Executive Summary

1/1/2019 1/1/2020 1/1/2021

1. Individuals included in report

a. Active 590 620 635

b. Inactive 229 204 223

c. Covered Payroll $ 58,782,615 $ 62,954,125 $ 66,097,584

2. Normal Cost Amount $ 4,637,961 $ 4,955,718 $ 5,134,207

Normal Cost Rate 7.89% 7.87% 7.77%

3. Assets $ 71,577,630 $ 87,657,117 $ 102,489,547

Investment Return for year

- 3.0% 19.2% 12.4%

4. Funding Levels

Maximum under Pension

Protection Act

$ 86,129,564 $ 89,656,988 $ 126,650,592

Suggested $ 5,438,549 $ 4,955,718 $ 5,134,207

Minimum

$ 0 $ 0 $ 0

5. Accounting Information

(for use in auditor’s report)

a. Present Value of

Vested Benefits

$ 70,011,271 $ 83,668,659 $ 103,238,325

b. Present Value of

Non-Vested Benefits

8,406,219 9,926,496 7,334,733

c. Present Value of

Accumulated Benefits

$ 78,417,490 $ 93,595,155 $ 110,573,058

d. Pension Cost per SFAS No. 87 $ 7,632,876 $ 8,231,838 $ 9,187,403

6. Top-Heavy Ratio 23.0% 23.0% 22.3%

70 of 306

2

EXHIBIT 2

Summary of Financial Information

Plan Year Ending December 31,

2018 2019 2020

A. INCOME

1. Contributions

Employee $ 0 $ 0 $ 0

Employer 4,500,004 5,439,998 5,000,000

Other 814 0 0

2. Investment Income

a. Interest and Dividends 1,843,636 2,124,510 1,920,221

b. Realized Gains 683,601 923,658 - 1,165,249

c. Unrealized Appreciation - 4,513,837 11,075,052 10,606,840

d. Investment Expenses - 179,013 - 142,643 - 264,540

e. Subtotal - 2,165,613 13,980,577 11,097,272

TOTAL $ 2,335,205 $ 19,420,575 $ 16,097,272

B. EXPENSES

1. Administrative $ 0 $ 0 $ 0

2. Monthly Benefits 940,633 1,085,663 1,264,842

3. Lump Sum Benefits 0 2,255,425 0

TOTAL $ 940,633 $ 3,341,088 $ 1,264,842

71 of 306

3

Exhibit 2 - Continued

12/31/2018 12/31/2019 12/31/2020

C. ASSETS (Market Basis)

1. Short Term

Cash $ 0 $ 0 $ 0

Money Market Funds 8,443,238 3,979,463 1,906,688

2. U.S. Treasury Bills 0 0 0

3. Fixed Income Assets

Government 0 0 0

Corporate 5,256,636 2,685,795 2,170,728

4. Common Stock 5,825,738 11,264,080 10,548,472

5. Mutual Funds

Fixed Income 17,630,232 23,836,512 27,843,490

Equity 34,310,203 45,792,404 59,920,133

6. Other

Contribution Receivable 0 0 0

Benefits payable 0 0 0

Accrued Interest 111,583 98,863 100,036

Other 0 0 0

TOTAL $ 71,577,630 $ 87,657,117 $ 102,489,547

D. Net Investment Return: - 3.0% 19.2% 12.4%

72 of 306

4


1/1/2019 1/1/2020 1/1/2021

E. INFORMATION FOR PBGC

FORM 1 SCHEDULE A:

1. Participant count 819 824 858

2. Per person rate 80 83 86

3. (1) x (2) $ 65,520 $ 68,392 $ 73,788

4. Interest Assumption 3.38% 2.02% 0.51%

4.32% 3.06% 2.26%

4.69% 3.59% 3.01%

5. Present Value of Vested Benefits $ 74,428,836 $ 100,813,322 $ 132,782,897

6. Adjusted Market Value of Assets 71,577,630 87,657,117 102,489,547

7. Unfunded Vested Benefits $ 2,851,206 $ 13,156,205 $ 30,293,350

8. Rounded to next higher $1,000 2,852,000 13,157,000 30,294,000

9. Variable Rate Premium Percentage 4.3% 4.5% 4.6%

10. Variable Rate Premium = (8) x (9) $ 122,636 $ 592,065 $ 1,393,524

11. Per person cap 541 561 582

12. Variable rate premium cap =

(1) x (11)

443,079 462,264 499,356

13. Minimum of (10) and (12) 122,636 462,264 499,356

14. Total PBGC premium = (3) + (13) $ 188,156 $ 530,656 $ 573,144

73 of 306

5

EXHIBIT 3

Accounting Information

This Exhibit is included to provide information according to FASB ASC 715-30 disclosure

requirements.

Statement of Accumulated Plan Benefits

1/01/2020 1/01/2021

Investment Return Assumption 4.50% 4.00%

Actuarial present value of accumulated plan

benefits

Vested Benefits

Participants currently receiving benefits $ 13,863,009 $ 19,072,902

Other Participants 69,805,650 84,165,423

$ 83,668,659 $ 103,238,325

Non-Vested Benefits 9,926,496 7,334,733

Total actuarial present value of

accumulated plan benefits

$

93,595,155

$

110,573,058

Statement of Changes in Accumulated Plan Benefits

Actuarial present value of accumulated

plan benefits at beginning of year $ 78,417,490 $ 93,595,155

Increase (Decrease) attributable to:

Plan Amendment 0 0

Benefits Accumulated* 11,036,185 9,024,745

Benefits Paid - 3,341,088 - 1,264,842

Change in Assumptions 7,482,568 9,218,000

Actuarial present value of accumulated

plan benefits at end of year $ 93,595,155 $ 110,573,058

* Includes effect of interest and actuarial gains and losses.

74 of 306

6


FASB ASC 715-30 Pension Cost for 2021 A. Reconciliation of Funded Status

1/01/2021

Projected

12/31/2021

1. Actuarial present value of accumulated

benefit obligations

a. Vested portion $ (103,238,325) $ -

b. Non-Vested portion (7,334,733) -

2. Accumulated Benefit Obligation $ (110,573,058) $ -

3. Effect of estimated future pay growth ( 27,849,088) -

4. Projected Benefit Obligation $ (138,422,146) $ (152,576,007)

5. Plan assets at fair value 102,489,547 113,833,681

6. Funded status: (4)+(5) $ ( 35,932,599) $ ( 38,742,326)

7. Unrecognized net (gain) or loss 26,119,263 25,242,331

8. Unrecognized prior service cost (26,114) ( 26,858)

9. Unrecognized net obligation 0 0

10. Accum. Comp. Other Income 26,093,149 25,215,473

11. Total: (6) + (10) $ ( 9,839,450) $ ( 13,526,853)

B. Determination of Pension Cost 2021

1. Service Cost $ 9,728,406

2. Interest Cost (on A(4) and B(1)) 5,896,599

3. Expected return on assets (7,315,278)

4. Amortization of

a. Unrecognized net (gain) or loss 876,932

b. Unrecognized prior service cost 744

c. Unrecognized net obligation 0

5. Net Periodic Pension Cost $ 9,187,403

C. The assumptions are the same as those shown in Appendix E.

D. Prior Service of $708,682 added 1/1/98 is amortized over 25 years. Prior service of $(469,257) added 1/1/07 is amortized over 17 years. 10% corridor used for unrecognized net (gain) or loss.

75 of 306

76 of 306

8


Participant Data as of January 1, 2021

Active

Retired

Terminated

Vested

Total

Number of Participants at 1/1/2020 620 68 136 824

New during year + 44 0 0 + 44

Rehired 0 0 0 0

Terminated Vested - 11 0 + 11 0

Terminated nonvested - 11 0 0 - 11

Cashed out 0 0 0 0

Retired - 7 + 8 - 1 0

Died 0 0 0 0

Other 0 + 1 0 + 1

Number of Participants at 12/31/2020 635 77 146 858

New Entrants on 1/1/2021 0 0 0 0

Number of Participants 1/1/2021* 635 77 146 858

*Does not include 0 employees who failed to meet the age or service requirements for

participation.

77 of 306

9

EXHIBIT 5

Principle Provisions of the Plan

EFFECTIVE DATE: January 1, 1996, adopted May 15, 1996. Restatement

effective January 1, 1997, adopted December 19, 2001.

Restatement effective January 1, 2008. Restatement

effective January 1, 2013, adopted December 11, 2013.

PARTICIPATION: Employees at January 1, 1996, who were in the Entergy

Corporation Retirement Plan for Non-Bargaining

Employees are eligible on January 1, 1996. Any other

employee is eligible to participate on the first day of the

month after date of hire, or attainment of age 21,

whichever is later.

PLAN YEAR: January 1 to December 31.

COMPENSATION: Base pay during the calendar year.

FINAL AVERAGE

MONTHLY EARNINGS:

Average of the Participant’s Compensation over the sixty

consecutive completed calendar months, out of the last

120, that produces the highest average.

SERVICE: A period of employment with Southwest Power Pool,

Inc. For those Participants who were previously

employed by a member company of Southwest Power

Pool immediately prior to their being hired by Southwest

Power Pool, such previous employment is also Service. (a) Benefit Service is all Service after age 21. (b) Vesting Service is all Service after age 18.

ACCRUED BENEFIT: Benefit based on Final Average Monthly Earnings and

Benefit Service to date.

78 of 306

10


NORMAL RETIREMENT:

Eligibility: The first of the month on or after age 65.

Benefit: 1.5% of Final Average Monthly Earnings, times Benefit

Service not in excess of 40 years. This benefit is offset

by the amount due at age 65 from any Southwest Power

Pool member company defined benefit plan for which

Service is granted under this plan. However, the net

benefit cannot be less than the benefit based on

Southwest Power Pool service only.

Form: Life Annuity.

EARLY RETIREMENT: Eligibility: Age 55 with 10 years of Service. Benefit: Accrued Benefit (unreduced for any prior plan benefits),

reduced by a percentage for each year that the Early

Retirement Date precedes the Normal Retirement Date,

and then reduced for any member company defined

benefit plan benefits payable at the Early Retirement

Date. The percentage reduction is: a) 2% for those who were age 45 with 5 years of

service by December 31, 2006; b) 6% for all others, except that the percentage is

2% for that part of the benefit accrued to

December 31, 2006. DEATH: Eligibility: Death prior to the commencement of benefits. Benefit: The Pre-Retirement Joint and 50% Survivors Annuity VESTING: Eligibility: A Participant is 100% vested after 5 years of Service (3

years for those hired before 2014) and 0% before.

Benefit: Accrued Benefit times the Vested Percentage, payable at

Normal Retirement Age. Reduced amounts are payable

if eligible for Early Retirement.

79 of 306

11

APPENDIX A

Calculation of Contributions

2020 2021

A. Maximum tax-deductible contribution

(IRC 404(o)(2))

1. Funding Target $ 90,380,485 $ 116,021,212

2. Target Normal Cost 8,427,384 7,311,627

3. Cushion Amount

a) 50% of Funding Target 45,190,243 58,010,606

b) Amount Funding Target increases

due to pay growth

33,315,993 47,796,694

4. Actuarial value of plan assets 87,657,117 102,489,547

5. Funding Target IF plan were “At Risk” 90,380,485 116,021,212

6. Maximum = (1)+(2)+(3)-(4), but not less

than (5)+(2)-(4) $ 89,656,988 $ 126,650,592

B. Intermediate contribution

1. Normal Cost for current group $ 4,955,718 $ 5,134,207

2. Partial years cost for expected

new people

0 0

3. Amortization of Unfunded Actuarial

Accrued Liability

0 0

4. Interest 0 0

5. Suggested contribution $ 4,955,718 $ 5,134,207

C. Minimum required contribution (IRC 430)

1. Target Normal Cost $ 6,060,350 $ 4,945,890

2. Shortfall amortization charges (App E) 1,311,028 1,600,443

3. Waiver amortization charges (App E) 0 0

4. Subtotal (1)+(2)+(3) $ 7,371,378 $ 6,546,333

5. Excess of actuarial value of asset (less 0 0

credit balances ) over Funding Target

6. Minimum (beginning of year) = (4), or if

(5) is greater than 0, then (1)-(5), but not

less than $0.

$ 7,371,378 $ 6,546,333

7. Minimum reflecting pre-funding balance $ 0 $ 0

80 of 306

12

APPENDIX B

Costs and Liabilities

1/1/2020 1/1/2021

1. Present Value of Future Benefits

A. Active Lives $ 117,262,694 $ 121,317,954

B. Inactive Lives 16,017,559 20,975,542

C. Total Present Value $ 133,280,253 $ 142,293,496

2. Actuarial Accrued Liability

$

84,755,278 $

92,023,035

3. Assets 87,657,117 102,489,547

4. Unfunded Actuarial Accrued Liability (2 - 3) $ -2,901,839 $ - 10,466,512

5. Entry Age Normal Cost $ 4,955,718 $ 5,134,207

6. Total Covered Salary 62,954,125 66,097,584

7. Normal Cost Rate (5 / 6) .078720 .077676

Note: The “liabilities” shown on this page are not liabilities in the usual sense. These

numbers are simply mathematical values derived in determining the maximum and

minimum funding levels for the plan.

81 of 306

13

APPENDIX C

Development of Unfunded Actuarial Accrued Liability

2020 2021

(1) Unfunded Actuarial Accrued Liability

beginning of year

$ 5,813,145 $ - 2,901,839

(2) Normal Cost for year 4,637,961 4,955,718

(3) Contributions for year 5,439,998 5,000,000

(4) Interest on (1), (2), and (3) 378,849 - 204,679

(5) Other adjustments 0 0

(6) Expected Unfunded Actuarial Accrued Liability

at end of year: (1)+(2)-(3)+(4)+(5)

$ 5,389,957 $ - 3,150,800

(7) Gain/loss during year -8,192,118 - 7,267,241

(8) Effect of changes in assumptions - 99,678 - 48,471

(9) Unfunded Actuarial Accrued Liability

at end of year

$ -2,901,839 $ - 10,466,512

(10) Amortization period 10 10

(11) Amortization of Unfunded Actuarial

Accrued Liability

$

0

$

0

Note: The “liabilities” shown on this page are not liabilities in the usual sense. These

numbers are simply mathematical values derived in determining the maximum and

minimum funding levels for the plan.

82 of 306

14

APPENDIX D

IRC 430 Calculations

2020 2021

A. Segment Rates 3.64/5.21/5.94 3.32/4.79/5.47

Equivalent rate 5.62% 5.18%

B. Asset Information

1. Market Value of assets on $ 87,657,117 $ 102,489,547

valuation date

2. Actuarial Value of assets on 87,657,117 102,489,547

valuation date

3. Carryover balance on valuation date 0 0

4. Pre-funding balance on valuation date 24,428,576 24,611,188

5. Security pledges & annuity purchases 0 0

on non HCE’s within last two years

C. Funding Target (IRC 430(d)(1)) $ 69,040,093 $ 84,374,966

D. Target Normal Cost $ 6,060,350 $ 4,945,890

E. “At Risk” calculations (IRC 430 (i))

1. Present value of accrued benefits under $ 71,563,294 $ 84,502,999

alternate assumptions

2. Loads

a) $700 times number of participants 576,800 600,600

b) 4% of (1) 2,862,532 3,380,120

3. Was plan “at risk” in 2 of last 4 years? NO NO

4. Funding target (1, +2 if 3=yes, and not

less than C)

71,563,294 84,502,999

5. Target normal cost under alternate

assumptions

6,060,350

4,945,890

6. 4% load 242,414 197,836

7. Target normal cost (5, +6 if 3=yes, and not

less than D)

6,060,350 4,945,890

83 of 306

15

Appendix D - Continued

2020 2021

F. Various percentages

1. Funding Target Attainment Percentage for Year

a. B(2) divided by C 126.96% 121.46%

b. B(2)-B(3)-B(4), divided by C 91.58% 92.30%

c. If a is greater than 100% then a, else b. 126.96% 121.46%

2. Adjusted Funding Target Attainment Percentage for

Year B(2)-B(3)-B(4)+B(5), divided by C+B(5) [if

1(a) is greater than 100%, then 1(a)]

126.96% 121.46%

3. At Risk Funding Target Attainment Percentage for

Year B(2)-B(3)-B(4), divided by E(1)

88.35% 92.16%

G. “At Risk” test for next year

1. Minimum required Funding Target Attainment

Percentage

80% 80%

2. Minimum required At Risk Funding Target

Attainment Percentage

70% 70%

3. Does Plan have more than 500 participants? YES YES

4. Is plan “At Risk” for the next year? (If F1(c) > 80%,

then “NO”)

NO NO

84 of 306

16

APPENDIX E

Amortization of Shortfalls

Date 1/1/2021

Initial Added Outstanding Amortization Amortization

Item Amount To Costs Balance Period Amount 1) 2018 Shortfall $ 5,818,695 1/1/2018 $ 3,620,356 4 $ 949,901

2) 2019 Shortfall 7,056,667 1/1/2019 5,376,314 5 1,146,622

3) 2020 Shortfall - 4,849,619 1/1/2020 - 4,304,699 6 - 785,495

4) 2021 Shortfall 1,804,636 1/1/2021 1,804,636 7 289,415

$ 6,496,607 $ 1,600,443

Shortfall amortization base for this year

1. Funding Shortfall

a) Funding Target from Appendix D $ 84,374,966

b) Actuarial value of assets less carryover and 77,878,359

prefunding balances

c) Funding shortfall = (a)-(b), not less than $0 $ 6,496,607

2. Present value of remaining shortfall amortization

installments

4,691,971

3. Shortfall amortization base = (1)-(2), or $0 if

(1)(b) is greater than Funding Target from

Appendix B

$ 1,804,636

85 of 306

17

APPENDIX F

Contributions and Funding Balances

Contributions for 2020:

CARRYOVER

BALANCE

PRE-

FUNDING

BALANCE

TOTAL

1) Minimum required

contribution for 2020

$ 7,371,378

2) Balances used to offset

minimum

$ 0 $ 2,487,360 2,487,360

3) Additional cash requirement

(1) – (2)

4,884,018

4) Contributions discounted to

1/1/2020

4,884,018

5) Excess contributions (4) – (3) $ 0

Carryover and Pre-funding Balances:

CARRYOVER

BALANCE

PRE-

FUNDING

BALANCE

TOTAL

1) Balance at 1/1/2020 $ 0 $ 24,428,576 $ 24,428,576

2) Portion used to offset 2020

funding requirement*

0 2,532,501 2,532,501

3) Amount Remaining 0 21,896,075 21,896,075

4) Interest at 12.40% 0 2,715,113 2,715,113

5) Subtotal 0 24,611,188 24,611,188

6) Prior year’s excess contributions 0 0

7) Interest on (6) at 5.62% 0 0

8) Subtotal (6) + (7) 0 0

9) Portion of (8) to be added to

prefunding balance

0 0

10) Voluntary reduction 0 0 0

11) Balance at 1/1/2021

(5) + (9) + (10)

$ 0 $ 24,611,188 $ 24,611,188

*includes interest penalty for late quarterly contributions

86 of 306

18

APPENDIX G

Top-Heavy Test for 2021 Plan Year

Determination Date: 12/31/2020

Valuation Date: 1/01/2021

Present Value of Accrued Benefits at 7% interest – Actives

1) Key Employees (22) $ 7,771,487

2) Non-key Employees (613) 35,106,648

3) Total $ 42,878,135

Present Value of Accrued Benefits at 7% interest for new Inactives during year

1) Key Employees (3) $ 2,826,643

2) Non-key Employees (15) 2,053,929

3) Total $ 4,880,572

Benefit Payments Since 1/1/2020 for new Retirees during year

1) Key Employees (1) $ 72,117

2) Non-key Employees (5) 48,934

3) Total $ 121,051

Totals

1) Key Employees $ 10,670,247

2) Non-key Employees 37,209,511

3) Total $ 47,879,758

Top-Heavy Ratio = Key / Total 22.3%

Note: These results should be combined with top-heavy test for 401(k) plan to determine

whether the combined plans are top-heavy. If neither plan is top-heavy, the

combined plans will not be top-heavy.

87 of 306

19

APPENDIX H

Actuarial Cost Methods and Assumptions

COST METHOD: The "entry age normal” cost method has been used

in your plan. PRE-RETIREMENT MORTALITY:

Deaths have been projected on the basis of the IRS

annuitant and non-annuitant tables for 2021.

Mortality rates at a few sample ages are:

AGE MORTALITY RATE PER 1,000

Male Female

25 .356 .129

30 .397 .175

35 .515 .258

40 .611 .354

45 .830 .505

50 1.307 .789

55 2.133 1.314

60 3.850 2.140

POST-RETIREMENT MORTALITY: The IRS annuitant and non-annuitant tables for

2021 were used. The life expectancy according to

the annuitant table is as follows:

Age Males Females

55 29.43 years 31.70 years

65 20.36 years 22.25 years

88 of 306

20

Appendix H (continued)

ASSUMED INVESTMENT RETURN: 7.00% annually before retirement, and 7.00% after

retirement. For purposes of the accounting

calculation in Exhibit 3, a discount rate of 4.00%

and a long-range return on assets of 7.00% were

used.

For purposes of calculating the Minimum and

Maximum Contributions, the following segment

rates were used: Min Max

1st segment (1-5 years) 3.32% 1.75%

2nd segment (5-20 years) 4.79% 3.04%

3rd segment (20+ years) 5.47% 3.65%

The equivalent rate is 5.18%.

SALARY GROWTH: Salaries were assumed to increase 4.00% per year,

(4.50% for the suggested contribution).

DISABILITIES: None assumed.

VOLUNTARY TERMINATIONS: For the suggested contribution, rates under the T-1

table in the Actuary’s Handbook, minus mortality

rates per the GA-51 table, but not less than 1%.

Assumed termination rates at a few sample ages

are:

Age Termination Rate per 1,000

25 49.1

30 36.6

35 22.9

40 10.4

45 10.0

50 10.0

55 10.0

60 10.0

89 of 306

21

Appendix H (continued)

EXPECTED RETIREMENT PATTERN: For the suggested contribution, we have assumed

the following rates of retirement:

Age Retirement Rate

55 - 61 .10

62 .25

63 .15

64 .15

65 1.00

ADMINISTRATIVE EXPENSES: These were assumed to be paid by the Sponsor.

ASSET VALUATION: Market Value

CONSIDERATION OF FUTURE

MORTALITY IMPROVEMENTS:

The minimum and maximum contribution

requirements are determined using mortality

assumptions specified by the Internal Revenue

Service. These assumptions do include anticipated

mortality improvements up to the valuation date but

not beyond.

Future mortality improvements were not considered

in developing the suggested contribution or the

financial statement items in Exhibit 3. A change in

the life expectancy table would normally have the

greatest impact on current retirees. This plan has

few retirees and a relatively low average age. Thus,

the liabilities are significantly more volatile with

regards to the other assumptions (i.e., investment

return, salary growth, retirement age and turnover)

than mortality.

90 of 306

91 of 306

92 of 306

93 of 306

94 of 306

95 of 306

96 of 306

97 of 306

98 of 306

SOUTHWEST POWER POOL, INC. TRANSMISSION WORKING GROUP

RECOMMENDATION TO THE BOARD OF DIRECTORS AND MEMBERS COMMITTEE

APRIL 27, 2021 SPONSORED UPGRADE SUS-016 ONIDA

ORGANIZATIONAL ROSTER

Members of the Markets and Operations Policy Committee (MOPC):

Denise Buffington, Evergy Companies – Chair

Alan Myers, ITC Holdings, Inc– Vice Chair

Mo Awad, Evergy Companies Mark Barbee, Kansas Electric Power

Cooperative, Inc. Betsy Beck, Enel Green Power North

America Bill Bojorquez, Hunt Transmission Kevin Bornhoft, Corn Belt Power

Cooperative Cheryl Bredenbeck, Xcel Energy

Southwest Transmission Co. Tim Brown, GRDA Robert Burner, Duke Energy Matt Caves, Western Farmers Electric

Cooperative Jack Clark, NextEra Energy Resources Seth Cochran, DC Energy Gregory Coco, Cleco Power Burton Crawford, Evergy Companies Jason Doerr, Basin Electric Power

Cooperative Bill Dowling, Midwest Energy Inc Steven Drew, NextEra Energy

Transmission, LLC Bobby Ferris, Lea County Electric

Cooperative, Inc. Dennis Florom, Lincoln Electric System

Jim Flucke, Evergy Companies Steve Gaw, Advanced Power Alliance Arash Ghodsian, Edf Renewable Chris Giles, Tri County Electric

Cooperative Tracy Golden, Northeast Nebraska

Public Power District Adam Graff, Heartland Consumers

Power District Bill Grant, Southwestern Public

Service-Xcel Energy John Grotzinger, Missouri Joint

Municipal EUC Luke Haner, Omaha Public Power

District Bradley Hans, Municipal Energy

Agency of Nebraska Dale Haugen, Mountrail-Williams

Electric Cooperative Carrie Hawkins, East Texas Electric

Cooperative Pat Hayes, LS Power Chad Heitmeyer, AEP Robert Helton, Engie North America Natasha Henderson, Golden Spread

Electric Cooperative Eric Hixson, Central Nebraska Public

Power & Irrigation District Mark Hoffman, East River Electric

Power Cooperative, Inc.

99 of 306

Larry Holloway, Kansas Power Pool Carla Holly, BP Wind Energy North

America Inc. (reps-Flat Ridge 2 Wind Energy)

Jayme Huber, Northwest Iowa Power Cooperative

Jim Jacoby, American Electric Power-Public Service Co of OK (TO)

Robert Janssen, Dogwood Energy, LLC Brian Johnson, American Electric

Power-OK Transmission Co. (TU) Lucy Johnston, Luminant Energy

Company LLC Robert Kelly, Innovative Energy

Alliance Cooperative Jeff Knottek, City Utilities of

Springfield, MO Mick Kossan, Central Power Electric

Cooperative, Inc. Brett Kruse, Calpine Corporation Bleau LaFave, NorthWestern Energy Paul Lampe, City of Independence, MO David Lazos, El Paso Energy Marketing

co Lloyd Linke, Western Area Power

Administration Michael Madia, Argo Infrastructure

Partners, LLC Mark McCulla, Entergy Services Courtney Mehan, Tenaska Power

Services Corp Ken Meringolo, CPV Renewable Energy

Company, LLC David Mindham, EDP Renewables Nate Morris, Liberty Utilities Jerry Ohmes, Kansas City Board of

Public Utilities Gregory Pakela, DTE Energy Trading

Inc Harshikesh Panchal, XO Energy Philip Pauls, Cargill Robert Pick, NPPD Randall Porter, Geronimo Energy

Robert Priest, Clarksdale Public Utilities Eddy Reece, Rayburn Country Electric

Coop Jeff Riles, Google Energy LLC Andrew Rosenlieb, Entergy Asset

Management C. Richard Ross, American Electric

Power-Southwestern Electric Power Co (TO)

Thomas Saitta, Kansas Muncipal Energy Agency

Trisha Samuelson, Innovative Energy Alliance Cooperative representing Roughrider Electric Cooperative

Mike Shook, City of Coffeyville Chase Smith, Southern Power

Company Holly Smith, Walmart Derek Sunderman, Savion LLC Resmi Surendran, Shell Energy North

America R J Tallman, Oklahoma Gas & Electric-

Electric Services Al Tamimi, Sunflower Electric Power

Corp Rebecca Turner, Clean Line Energy

Partners LLC Usha-Maria Turner, OGE Energy Richard Tyler, Northeast Texas Electric

Cooperative, Inc. Melie Vincent, Oklahoma Municipal

Power Authority Jennifer Vosburg, NRG Louisiana

Generating LLC Bruce Walkup, Arkansas Electric

Cooperative Corporation Kenneth Weber, Harlan Municipal

Utilities Jimmy Wever, Public Service Comm. of

Yazoo City, MS Noman Williams, GridLiance High

Plains LLC

100 of 306

Terry Wolf, Missouri River Energy Services

Mary Ann Zehr, Tri-State Generation and Transmission Association, Inc.

BACKGROUND, GOALS & DRIVERS

In accordance with Attachment O, Section IV.1 of the SPP Open Access Transmission Tariff (SPP OATT), SPP has performed Sponsored Upgrade Study SUS-016 Onida. The purpose of the study is to evaluate the impact of the Onida capacitor bank addition on Transmission System reliability and identify any necessary mitigation of these impacts.

SUPPORTING ANALYSIS

East River Electric Power Cooperative proposes the addition of a 3.6 MVAR capacitor bank at Onida 69 kV. The proposed Sponsored Upgrade has an in-service date of June 1, 2020. SPP evaluated the reliability impacts of change in topology. The results indicated no system impacts associated with the Sponsored Upgrade.

The Sponsored Upgrade was presented to the TWG for their review as part of the transmission planning process. In accordance with Attachment O, Section IV.1 of the SPP OATT, the Sponsor shall assume the costs of the Sponsored Upgrade. In order to proceed with the Sponsored Upgrade, the Project Sponsor must execute the agreement found in Schedule 1 to Attachment J of the SPP OATT that financially commits the Sponsor to pay for the Sponsored Upgrade. This agreement requires that the Sponsored Upgrade must first be endorsed by Markets and Operations Policy Committee (MOPC) and the SPP Board of Directors.

Matt McGee (American Electric Power)

AEP abstained from the 3/2/2021 TWG motion to endorse the Sponsored Upgrade Study work and study report for SUS-016 Onida because AEP believes that if TWG is going to be asked to endorse study work and a study report, some basic information about the project should be provided in the report including: The problem being addressed by the project, a description of how the project solves the problem, a map and a one-line diagram of the project

The Sponsored Upgrade was sent to MOPC for their review. MOPC voted to approve the Sponsored Upgrade Study-Hughes County on the consent agenda.

101 of 306

RECOMMENDATION

MOPC recommends the Board endorse the Sponsored Upgrade Study work for SUS-019 Hughes County.

Approved: MOPC 04/14/2021

58 For, 0 Apposed, 0 Abstention (Consent Agenda)

TWG recommends the MOPC endorse the Sponsored Upgrade Study work for SUS-016 Onida.

Approved: TWG 03/02/2021

27 For, 0 Apposed, 1 Abstention (AEP)

102 of 306

SPONSORED UPGRADE STUDY SUS-016 Onida Capacitor Bank

Published on 06/17/2020

By SPP Engineering, Transmission Services

103 of 306


REVISION HISTORY

DATE OR

VERSION NUMBER AUTHOR

CHANGE

DESCRIPTION COMMENTS

06/17/2020 SPP Original

104 of 306


CONTENTS

Revision History ......................................................................................................................................................................... i

Introduction ............................................................................................................................................................................... 1

Study Methodology ................................................................................................................................................................. 2

Objective ................................................................................................................................................... 2

Study Process ............................................................................................................................................ 2

Results of Analysis .................................................................................................................................................................. 5

Potential Thermal Overloads and Voltage Violations ............................................................................... 5

Short Circuit .............................................................................................................................................. 5

Mitigation Upgrades Required ........................................................................................................................................... 6

Conclusion .................................................................................................................................................................................. 7

105 of 306


SUS-016 Onida Sponsored Upgrade Study 1

INTRODUCTION

This report outlines the results of an evaluation of regional transmission impacts within the SPP

footprint of the proposed Sponsored Upgrade of the Onida capacitor bank. East River Electric

Power Cooperative (EREPC) would like to sponsor the addition of a 3.6 MVAR capacitor bank at the

Onida 69 kV substation.

The load flow models used for the evaluation were 2020 ITPNT models. SPP performed an AC

contingency analysis on these models using PSS®E.

106 of 306



STUDY METHODOLOGY

OBJECTIVE The purpose of this study was to determine the regional transmission system impacts within the

SPP footprint due to the addition of a 3.6 MVA capacitor bank at Onida 69 kV substation.

SPP performed a Sponsored Upgrade Study to evaluate the reliability impacts of the capacitor bank

and to assess any required mitigation needed for reliability in accordance with Attachment O,

Section IV.1 of the SPP Open Access Transmission Tariff (“Tariff”). The proposed in-service date for

the Sponsored Upgrade is 6/1/2020.

STUDY PROCESS

Model Assumptions

o 2020 ITPNT models

Model years 2020, 2021, 2022, 2025, and 2030

Summer Peak (2020S, 2021S, 2022S, 2025S, and 2030S), Winter Peak

(2020W, 2021W, 2022W, 2025W, and 2030W), and Light Load (2021L,

2022L, 2025L, and 2030L)

Base Reliability Scenario

Total of 14 models

o SPP compared results from study models both with and without the capacitor bank

addition to determine the impact of the new sponsored upgrade to the transmission

system.

Case Name Study Year Season Scenario Load (MW/MVAR)

2020ITPP5b-20S.sav 2020 Summer Peak Base Reliability Base Case

2020ITPP5b-20W.sav 2020 Winter Peak Base Reliability Base Case



2020ITPP5b-21L.sav 2021 Light Load Base Reliability Base Case










2020ITPP5b-20S_016.sav 2020 Summer Peak Base Reliability Base Case

2020ITPP5b-20W_016.sav 2020 Winter Peak Base Reliability Base Case

107 of 306




2020ITPP5b-21S_016.sav 2021 Summer Peak Base Reliability Base Case

2020ITPP5b-21W_016.sav 2021 Winter Peak Base Reliability Base Case

2020ITPP5b-21L_016.sav 2021 Light Load Base Reliability Base Case

2020ITPP5b-22S_016.sav 2022 Summer Peak Base Reliability 3.6 MVA Capacitor Bank

2020ITPP5b-22W_016.sav 2022 Winter Peak Base Reliability 3.6 MVA Capacitor Bank

2020ITPP5b-22L_016.sav 2022 Light Load Base Reliability 3.6 MVA Capacitor Bank







Table 2-1: Study Cases

Steady State Analysis o Assumptions (consistent with the 2020 ITPNT analysis)

AC contingency analysis on all load flow models using PSS®E Monitored Elements

SPP facilities 69 kV and above First-tier companies 100 kV and above

Contingencies P1, P2, P4, P5 events for all models P3 events for 22S, 22L, 25S, and 30S Includes all events in these categories as provided for the 2020 ITPNT

by SPP members and first-tier companies Apply SPP Criteria and NERC reliability standards

o Compared thermal overloads and voltage violations that occur with and without the new capacitor bank included in the models to determine thermal overloads and voltage violations resulting from the new sponsored upgrade on the transmission system.

Dynamics Analysis o Assumptions

2019 MDWG Dynamics Model Set

2022 and 2030 MDWG Summer Peak Base and Change Case

o Analyses

Fast Fault Screening using POM Studio

Short Circuit Analysis o Assumptions

Used 2020 Final ITP Short Circuit models (Max Fault) Placed all available facilities in service

o Generation o Transmission lines o Transformers o Buses

108 of 306



Short Circuit Output o Physical

Short Circuit Coordinates o Polar

Short Circuit Parameters o 3 Phase

FLAT – classical fault analysis conditions o Analyses

Three-phase fault

109 of 306



RESULTS OF ANALYSIS

POTENTIAL THERMAL OVERLOADS AND VOLTAGE VIOLATIONS The analysis identified no potential thermal overloads or voltage violations resulting from the

addition of the Sponsored Upgrade.

SHORT CIRCUIT Short circuit analysis was performed for the 2022 Summer Peak model with the addition of the new

capacitor bank. The short circuit analysis identified the currents as listed in Table 3-1.

Season Model Fault Bus Current(Amps)

22SP MAX FAULT Three Phase PIERRE 8 69.000 2,739

22SP MAX FAULT Three Phase FTTHOMP4 230.00 19,166

22SP MAX FAULT Three Phase OAHE 4 230.00 13,554


22SP MAX FAULT Three Phase OAHE2-3G 13.800 88,562





22SP MAX FAULT Three Phase MOS-PCKT-ER869.000 2,113

22SP MAX FAULT Three Phase MOS-SLY1-ER869.000 3,244

22SP MAX FAULT Three Phase SW-BUCKY-ER869.000 2,456

22SP MAX FAULT Three Phase POCKET-ER8 69.000 1,192

22SP MAX FAULT Three Phase LOGAN-ER8 69.000 2,086

22SP MAX FAULT Three Phase ONIDA-ER8 69.000 2,256

22SP MAX FAULT Three Phase OKOBOJO-ER8 69.000 3,244

22SP MAX FAULT Three Phase BCKYSUB-ER8 69.000 2,450

22SP MAX FAULT Three Phase LOGANSUB-ER869.000 2,084

22SP MAX FAULT Three Phase MOS-SLY2-ER869.000 3,249

22SP MAX FAULT Three Phase GREYGOOS-ER869.000 2,467

22SP MAX FAULT Three Phase MOS-PIER-ER869.000 2,711

22SP MAX FAULT Three Phase SULLYBT-ER4 230.00 6,231

22SP MAX FAULT Three Phase SULLYBT-ER8 69.000 3,253

22SP MAX FAULT Three Phase SB.LS-WK-ER4230.00 6,231

22SP MAX FAULT Three Phase WHITLOCK_-RM230.00 4,361

22SP MAX FAULT Three Phase PHILIP_T-BE4230.00 3,600

Table 3-1: Short Circuit Results

110 of 306



MITIGATION UPGRADES REQUIRED

Attachment O, Section IV.1 of the SPP Tariff requires SPP to evaluate the impact of the proposed

Sponsored Upgrade on Transmission System reliability and identify any necessary mitigation of

these impacts. Since there were no potential thermal or voltage violations resulting from the

proposed Sponsored Upgrade, no mitigation upgrades are required.

111 of 306



CONCLUSION

The AC analysis revealed no potential thermal or voltage violations associated with the Sponsored

Upgrade of the new capacitor bank. No mitigation upgrades are needed.

Upon endorsement of the Sponsored Upgrade from the appropriate working groups, the Project

Sponsor and SPP may execute the “Agreement for Sponsored Upgrade” found in Schedule 1 to

Attachment J of the SPP OATT, financially committing the Project Sponsor to pay for the Sponsored

Upgrade. The Project Sponsor must execute the Agreement on or before June 6, 2020, in order for

SPP to issue an NTC for the Sponsored Upgrade.

The Sponsored Upgrade will be a Creditable Upgrade eligible for cost recovery through Attachment

Z2 revenue crediting (if SPP determines that the Sponsored Upgrade is needed as part of the

Transmission System) or ILTCRs, in accordance with Attachment Z2 of the SPP OATT.

112 of 306

SouthwestPowerPool SPPorg southwest-power-poolHelping our members work together to keep the lights on... today and in the future. 1

SPONSORED UPGRADE STUDYSUS-016 ONIDA 69KV

MOPC – APRIL 27, 2021

113 of 306

2

SUS-016 ONIDA 69 KV

• SPP performed a Sponsored Upgrade Study for East River Electric Power Cooperative (Sponsor and Host Transmission Owner)

• Attachment O, Section IV.1:• Evaluate reliability impacts of proposed upgrade• The Sponsored Upgrade shall be submitted to the proper

stakeholder working group for their review as part of the transmission planning process

• MOPC endorsed on 04/14/2021

• TWG endorsed on 3/2/2021

• Seeking Board of Directors endorsement today

2

114 of 306

3

PROPOSED SPONSORED UPGRADE

• East River proposes the addition of a 3.6 MVAR capacitor bank at Onida 69 kV in Onida, SD• Proposed ISD: June 2020• No system impacts resulting from the

new capacitor bank

3

115 of 306

4

RESULTS OF ANALYSIS

• No System Impacts

• No mitigation needed

4

116 of 306

5

NEXT STEPS

• After Board of Directors endorsement, Sponsor executes Schedule 1 to Attachment J, financially committing to pay for the upgrade

• Obtain SCERT estimate from TO

• Per BP 7060 Section 3.2, NTCs would be issued at this point• Proposed Sponsored Upgrade• Costs assigned to Sponsor

5

117 of 306

6

ENDORSEMENT

• SPP recommends the Board of Directors endorse the Sponsored Upgrade study work and study report for SUS-016 Onida 69 kV

6

118 of 306

SOUTHWEST POWER POOL, INC. TRANSMISSION WORKING GROUP

RECOMMENDATION TO THE BOARD OF DIRECTORS AND MEMBERS COMMITTEE

APRIL 27, 2021 SPONSORED UPGRADE SUS-019 HUGHES COUNTY


Members of the Markets and Operations Policy Committee (MOPC):

Denise Buffington, Evergy Companies – Chair

Alan Myers, ITC Holdings, Inc– Vice Chair

Mo Awad, Evergy Companies Mark Barbee, Kansas Electric Power

Cooperative, Inc. Betsy Beck, Enel Green Power North

America Bill Bojorquez, Hunt Transmission Kevin Bornhoft, Corn Belt Power

Cooperative Cheryl Bredenbeck, Xcel Energy

Southwest Transmission Co. Tim Brown, GRDA Robert Burner, Duke Energy Matt Caves, Western Farmers Electric

Cooperative Jack Clark, NextEra Energy Resources Seth Cochran, DC Energy Gregory Coco, Cleco Power Burton Crawford, Evergy Companies Jason Doerr, Basin Electric Power

Cooperative Bill Dowling, Midwest Energy Inc Steven Drew, NextEra Energy

Transmission, LLC Bobby Ferris, Lea County Electric

Cooperative, Inc. Dennis Florom, Lincoln Electric System

Jim Flucke, Evergy Companies Steve Gaw, Advanced Power Alliance Arash Ghodsian, Edf Renewable Chris Giles, Tri County Electric

Cooperative Tracy Golden, Northeast Nebraska

Public Power District Adam Graff, Heartland Consumers

Power District Bill Grant, Southwestern Public

Service-Xcel Energy John Grotzinger, Missouri Joint

Municipal EUC Luke Haner, Omaha Public Power

District Bradley Hans, Municipal Energy

Agency of Nebraska Dale Haugen, Mountrail-Williams

Electric Cooperative Carrie Hawkins, East Texas Electric

Cooperative Pat Hayes, LS Power Chad Heitmeyer, AEP Robert Helton, Engie North America Natasha Henderson, Golden Spread

Electric Cooperative Eric Hixson, Central Nebraska Public

Power & Irrigation District Mark Hoffman, East River Electric

Power Cooperative, Inc.

119 of 306

Larry Holloway, Kansas Power Pool Carla Holly, BP Wind Energy North

America Inc. (reps-Flat Ridge 2 Wind Energy)

Jayme Huber, Northwest Iowa Power Cooperative

Jim Jacoby, American Electric Power-Public Service Co of OK (TO)

Robert Janssen, Dogwood Energy, LLC Brian Johnson, American Electric

Power-OK Transmission Co. (TU) Lucy Johnston, Luminant Energy

Company LLC Robert Kelly, Innovative Energy

Alliance Cooperative Jeff Knottek, City Utilities of

Springfield, MO Mick Kossan, Central Power Electric

Cooperative, Inc. Brett Kruse, Calpine Corporation Bleau LaFave, NorthWestern Energy Paul Lampe, City of Independence, MO David Lazos, El Paso Energy Marketing

co Lloyd Linke, Western Area Power

Administration Michael Madia, Argo Infrastructure

Partners, LLC Mark McCulla, Entergy Services Courtney Mehan, Tenaska Power

Services Corp Ken Meringolo, CPV Renewable Energy

Company, LLC David Mindham, EDP Renewables Nate Morris, Liberty Utilities Jerry Ohmes, Kansas City Board of

Public Utilities Gregory Pakela, DTE Energy Trading

Inc Harshikesh Panchal, XO Energy Philip Pauls, Cargill Robert Pick, NPPD Randall Porter, Geronimo Energy

Robert Priest, Clarksdale Public Utilities Eddy Reece, Rayburn Country Electric

Coop Jeff Riles, Google Energy LLC Andrew Rosenlieb, Entergy Asset

Management C. Richard Ross, American Electric

Power-Southwestern Electric Power Co (TO)

Thomas Saitta, Kansas Muncipal Energy Agency

Trisha Samuelson, Innovative Energy Alliance Cooperative representing Roughrider Electric Cooperative

Mike Shook, City of Coffeyville Chase Smith, Southern Power

Company Holly Smith, Walmart Derek Sunderman, Savion LLC Resmi Surendran, Shell Energy North

America R J Tallman, Oklahoma Gas & Electric-

Electric Services Al Tamimi, Sunflower Electric Power

Corp Rebecca Turner, Clean Line Energy

Partners LLC Usha-Maria Turner, OGE Energy Richard Tyler, Northeast Texas Electric

Cooperative, Inc. Melie Vincent, Oklahoma Municipal

Power Authority Jennifer Vosburg, NRG Louisiana

Generating LLC Bruce Walkup, Arkansas Electric

Cooperative Corporation Kenneth Weber, Harlan Municipal

Utilities Jimmy Wever, Public Service Comm. of

Yazoo City, MS Noman Williams, GridLiance High

Plains LLC

120 of 306

Terry Wolf, Missouri River Energy Services

Mary Ann Zehr, Tri-State Generation and Transmission Association, Inc.


In accordance with Attachment O, Section IV.1 of the SPP Open Access Transmission Tariff (SPP OATT), SPP has performed Sponsored Upgrade Study SUS-019 Hughes County. The purpose of the study is to evaluate the impact of replacing Ash Tap with Hughes County 115 kV substation and move Buckeye and Grey Goose 69 kV lines from Pierre to Hughes County on Transmission System reliability and identify any necessary mitigation of these impacts.

SUPPORTING ANALYSIS

East River Electric Power Cooperative proposes replacing Ash Tap with Hughes County 115 kV substation and move Buckeye and Grey Goose 69 kV lines from Pierre to Hughes County. The proposed Sponsored Upgrade would have an in-service date of June 1, 2021. SPP evaluated the reliability impacts of change in topology. The results indicated no system impacts associated with the Sponsored Upgrade.

The Sponsored Upgrade was presented to the TWG for their review as part of the transmission planning process. In accordance with Attachment O, Section IV.1 of the SPP OATT, the Sponsor shall assume the costs of the Sponsored Upgrade. In order to proceed with the Sponsored Upgrade, the Project Sponsor must execute the agreement found in Schedule 1 to Attachment J of the SPP OATT that financially commits the Sponsor to pay for the Sponsored Upgrade. This agreement requires that the Sponsored Upgrade must first be endorsed by Markets and Operations Policy Committee (MOPC) and the SPP Board of Directors.

Matt McGee (American Electric Power) AEP abstained from the 3/2/2021 TWG motion to endorse the Sponsored Upgrade Study work and study report for SUS- 019 Hughes County because AEP believes that if TWG is going to be asked to endorse study work and a study report, some basic information about the project should be provided in the report including: The problem being addressed by the project, a description of how the project solves the problem, a map and a one-line diagram of the project.

The Sponsored Upgrade was sent to MOPC for their review. MOPC voted to approve the Sponsored Upgrade Study-Hughes County on the consent agenda.

121 of 306

RECOMMENDATION

MOPC recommends the Board endorse the Sponsored Upgrade Study work for SUS-019 Hughes County.

Approved: MOPC 04/14/2021

58 For, 0 Apposed, 0 Abstention (Consent Agenda)

TWG recommends the MOPC endorse the Sponsored Upgrade Study work for SUS-019 Hughes County.

Approved: TWG 03/02/2021

27 For, 0 Apposed, 1 Abstention (AEP)

122 of 306

SPONSORED UPGRADE STUDY SUS-019 Hughes County 115/69 kV

Substation

Published on 11/13/2020

By SPP Engineering, Transmission Services

123 of 306


REVISION HISTORY

DATE OR VERSION

NUMBER AUTHOR

CHANGE DESCRIPTION

COMMENTS

11/13/2020 SPP Original

124 of 306


CONTENTS

Revision History ......................................................................................................................................................................... i

Introduction ............................................................................................................................................................................... 1

Study Methodology ................................................................................................................................................................. 2

Objective ................................................................................................................................................... 2

Study Process ............................................................................................................................................ 2

Results of Analysis .................................................................................................................................................................. 5

Potential Thermal Overloads and Voltage Violations ............................................................................... 5

Short Circuit .............................................................................................................................................. 5

Stability ..................................................................................................................................................... 6

Mitigation Upgrades Required ........................................................................................................................................... 7

Conclusion .................................................................................................................................................................................. 8

125 of 306


SUS-019 Hughes County 115/69 kV Substation 1

INTRODUCTION

This report outlines the results of an evaluation of regional transmission impacts within the SPP

footprint of the proposed Sponsored Upgrade of a new Hughes County 115/69 kV substation to

replace Ash Tap and move East River’s Grey Goose and Buckeye 69 kV interconnection from Pierre

to the new Hughes County substation. East River Electric Power Cooperative, Inc. (EREC) has

requested evaluation of the new upgrades as a Sponsored Upgrade in order to evaluate the

reliability impacts on the Transmission System.

The load flow models used for the evaluation were 2020 ITPNT models. SPP performed an AC

contingency analysis on these models using PSS®E.

126 of 306



STUDY METHODOLOGY

OBJECTIVE The purpose of this study was to determine the regional transmission system impacts within the

SPP footprint due to the addition of a new Hughes County 115/69 kV substation to replace Ash Tap

and move East River’s Grey Goose and Buckeye 69 kV interconnection from Pierre to the new

Hughes County substation. This is a group of planned upgrades, of which EREC plans to sponsor a

portion. Since the planned projects are codependent have significant impact on the sponsored

upgrades, all projects were assessed simultaneously to identify the full impact. The full list of

facilities and which are sponsored are as follows:

Planned Project Facilities 115-kV switchyard (six breakers) 69-kV switchyard (three breakers) One 115/69-kV transformer 0.75 miles of 115-kV transmission line Line/terminal modifications (Pierre, Oahe, Garfield)

Sponsored Upgrade Facilities 115-kV switchyard (5 breakers) 69-kV switchyard (1 breaker)

SPP performed a Sponsored Upgrade Study to evaluate the reliability impacts of the sponsored

projects and to assess any required mitigation needed for reliability in accordance with Attachment

O, Section IV.1 of the SPP Open Access Transmission Tariff (“Tariff”). The proposed in-service date

for the Sponsored Upgrade is June 1, 2021.

STUDY PROCESS Model Assumptions

o 2020 ITP models

Model years 2021, 2022, 2025, and 2030

Summer Peak (2021S, 2022S, 2025S, and 2030S), Winter Peak (2021W,

2022W, 2025W, and 2030W), and Light Load (2022L, 2025L, and 2030L)

Base Reliability Scenario

Total of 11 models

o The change case models include replacing Ash Tap with Hughes County substation

and moving Buckeye and Grey Goose 69 kV lines from Pierre to Hughes County.






127 of 306











2020ITPP5b-21S_019.sav 2021 Summer Peak Base Reliability

Replace Ash Tap 115 kV with Hughes Co. 115/69 kV Lengthen Pierre to Hughes Co. by 0.75 miles

Move Buckeye and Grey Goose 69 kV lines from Pierre to Hughes Co.

2020ITPP5b-21W_019.sav 2021 Winter Peak Base Reliability









2020ITPP5b-22L_019.sav 2022 Light Load Base Reliability





















Table 2-1: Study Models

Steady State Analysis o Assumptions (consistent with the 2020 ITPNT analysis)

AC contingency analysis on all load flow models using PSS®E

128 of 306



Monitored Elements SPP facilities 69 kV and above First-tier companies 100 kV and above

Contingencies P1, P2, P4, P5 events for all models P3 events for 22S, 22L, 25S, and 30S Includes all events in these categories as provided for the 2019 ITPNT

by SPP members and first-tier companies Apply SPP Criteria and NERC reliability standards

o Compared thermal overloads and voltage violations that occur with and without the Sponsored Upgrade included in the models to determine thermal overloads and voltage violations resulting from the Sponsored Upgrade

Dynamics Analysis o Assumptions

2019 MDWG Series Dynamics Model Set

2022 and 2030 MDWG Summer Peak Base and Change Case

o Analyses

Fast Fault Screening using POM Studio

Short Circuit Analysis o Assumptions

Used 2020 Final MDWG Short Circuit models (Max Fault) Placed all available facilities in service

o Generation o Transmission lines o Transformers o Buses

Short Circuit Output o Physical

Short Circuit Coordinates o Polar

Short Circuit Parameters o 3 Phase

FLAT – classical fault analysis conditions o Analyses

Three-phase fault

129 of 306



RESULTS OF ANALYSIS

POTENTIAL THERMAL OVERLOADS AND VOLTAGE VIOLATIONS The analysis identified no potential thermal overloads or voltage violations resulting from the

addition of the Sponsored Upgrade.

SHORT CIRCUIT Short circuit analysis was performed for the 2022 Summer Peak model with replacing Ash Tap with

Hughes County substation and moving Buckeye and Grey Goose 69 kV lines from Pierre to Hughes

County. The short circuit analysis identified the currents as listed in Table 3-1.


22SP Max Fault Three Phase FAITH 7 115.00 2,208

22SP Max Fault Three Phase EAGLEBE8 69.000 1,618

22SP Max Fault Three Phase EAGLEBW8 69.000 2,109

22SP Max Fault Three Phase MIDLAND8 69.000 2,072

22SP Max Fault Three Phase PHILIP 8 69.000 2,373

22SP Max Fault Three Phase FTTHMP19 13.800 25,897

22SP Max Fault Three Phase FTTHMP29 13.800 25,898

22SP Max Fault Three Phase FTTHOMP8 69.000 6,685


22SP Max Fault Three Phase EAGLEBT7 115.00 1,902

22SP Max Fault Three Phase MARTIN 7 115.00 2,302

22SP Max Fault Three Phase MAURINE7 115.00 3,506

22SP Max Fault Three Phase MIDLAND7 115.00 3,246

22SP Max Fault Three Phase NUNDRWD4 230.00 3,216

22SP Max Fault Three Phase PHILIP 7 115.00 4,994

22SP Max Fault Three Phase PIERRE 7 115.00 7,817

22SP Max Fault Three Phase IRVSIMM7 115.00 7,887

22SP Max Fault Three Phase WALL 7 115.00 3,278

22SP Max Fault Three Phase WICKSVL7 115.00 3,843



22SP Max Fault Three Phase FTRANDL4 230.00 11,098

22SP Max Fault Three Phase HURON 4 230.00 11,026

22SP Max Fault Three Phase OAHE 4 230.00 13,554


22SP Max Fault Three Phase BIGBND14 230.00 11,623

22SP Max Fault Three Phase BIGBND24 230.00 11,459

22SP Max Fault Three Phase OAHE2-3G 13.800 88,562


130 of 306





22SP Max Fault Three Phase OAHE 1G 13.800 46,975

22SP Max Fault Three Phase WANBLEE 7 115.00 2,360



22SP Max Fault Three Phase ASH ST 7 115.00 7,032

22SP Max Fault Three Phase EVANS ST 115.00 7,351

22SP Max Fault Three Phase LETCHER4 230.00 4,752

22SP Max Fault Three Phase WESSINGTON 4230.00 6,958

22SP Max Fault Three Phase MOS-PCKT-ER869.000 2,177

22SP Max Fault Three Phase MOS-SLY1-ER869.000 3,310

22SP Max Fault Three Phase SW-BUCKY-ER869.000 2,563

22SP Max Fault Three Phase POCKET-ER8 69.000 1,213

22SP Max Fault Three Phase LOGAN-ER8 69.000 2,144

22SP Max Fault Three Phase OKOBOJO-ER8 69.000 3,310

22SP Max Fault Three Phase BCKYSUB-ER8 69.000 2,556

22SP Max Fault Three Phase MOS-SLY2-ER869.000 3,315

22SP Max Fault Three Phase GREYGOOS-ER869.000 2,533

22SP Max Fault Three Phase MOS-PIER-ER869.000 2,848

22SP Max Fault Three Phase LAKPLAT-ER4 230.00 5,818

22SP Max Fault Three Phase SULLYBT-ER4 230.00 6,236

22SP Max Fault Three Phase SULLYBT-ER8 69.000 3,319

22SP Max Fault Three Phase SB.LS-WK-ER4230.00 6,236

22SP Max Fault Three Phase HUGHCNTY-ER7115.00 8,242

22SP Max Fault Three Phase GARFLD 7 115.00 7,003

22SP Max Fault Three Phase PHILIP_T-BE4230.00 3,600

22SP Max Fault Three Phase PHILIP__-BE4230.00 3,040

22SP Max Fault Three Phase PHILIP__-BE913.200 12,068

Table 3-1: Short Circuit Results

STABILITY SPP performed a Fast Fault Screening (FFS) study for the base case and change case models. The

FFS was performed for 2022 Summer Peak and 2030 Summer Peak. The change case models

include replacing Ash Tap with Hughes County substation and moving Buckeye and Grey Goose 69

kV lines from Pierre to Hughes County. There were no significant differences in the critical clearing

times between the base and change cases. Therefore, a transient stability analysis is not required.

131 of 306



MITIGATION UPGRADES REQUIRED

Attachment O, Section IV.1 of the SPP Tariff requires SPP to evaluate the impact of the proposed

Sponsored Upgrade on the Transmission System reliability and identify any necessary mitigation of

these impacts. Since there were no potential thermal or voltage violations resulting from the

proposed Sponsored Upgrade, no mitigation upgrades are required.

132 of 306



CONCLUSION

The AC analysis revealed no potential thermal or voltage violations associated with the Sponsored

Upgrade to replace Ash Tap with Hughes County substation and move Buckeye and Grey Goose 69

kV lines from Pierre to Hughes County. No mitigation upgrades are needed.

Upon endorsement of the Sponsored Upgrade from the appropriate working groups, the Project

Sponsor and SPP may execute the “Agreement For Sponsored Upgrade” found in Schedule 1 to

Attachment J of the SPP OATT, financially committing the Project Sponsor to pay for the Sponsored

Upgrade. The Project Sponsor must execute the Agreement on or before November 13, 2021, in

order for SPP to issue an NTC for the Sponsored Upgrade.

The Sponsored Upgrades are eligible for cost recovery through ILTCRs, in accordance with

Attachment Z2 of the SPP OATT. EREC has elected to forgo the ILTCR option for the Hughes County

115/69 substation Sponsored Upgrade.

133 of 306


SPONSORED UPGRADE STUDYSUS-019 HUGHES COUNTY 115/69KV

BOARD OF DIRECTORS – APRIL 27, 2021

134 of 306

2

SUS-019 HUGHES COUNTY

• SPP performed a Sponsored Upgrade Study for East River Electric Power Cooperative (Sponsor and Host Transmission Owner)

• Attachment O, Section IV.1:• Evaluate reliability impacts of proposed upgrade• The Sponsored Upgrade shall be submitted to the proper

stakeholder working group for their review as part of the transmission planning process

• MOPC endorsed on 04/14/2021

• TWG endorsed on 3/2/2021

• Seeking Board of Directors endorsement today

2

135 of 306

3

PROPOSED SPONSORED UPGRADE

• East River proposes the replacing Ash Tap with Hughes County 115 kV substation and move Buckeye and Grey Goose 69 kV lines from Pierre to Hughes County. • Proposed ISD: June 2021• No system impacts resulting from the new capacitor bank

3

136 of 306

4

RESULTS OF ANALYSIS

• No System Impacts

• No mitigation needed

4

137 of 306

5

NEXT STEPS

• After Board of Directors endorsement, Sponsor executes Schedule 1 to Attachment J, financially committing to pay for the upgrade

• Obtain SCERT estimate from TO

• Per BP 7060 Section 3.2, NTCs would be issued at this point• Proposed Sponsored Upgrade• Costs assigned to Sponsor

5

138 of 306

6

ENDORSEMENT

• SPP recommends the Board of Directors endorse the Sponsored Upgrade study work and study report for SUS-019 Hughes County

6

139 of 306

SOUTHWEST POWER POOL, INC. Project Cost Working Group

RECOMMENDATION TO THE SPP BOARD OF DIRECTORS

04/27/2021 PCWG Recommendation for Line - Mustang – Seminole 115 kV Ckt 1


Members of the Project Cost Working Group:

• Brian Johnson, AEP, TO, Chair • Kenny Munsell, SPS, TO, Vice

Chair • Jerry Bradshaw, CUS, TU • Scott Brunnert, OG&E, TO • James Ging, KPP, TU • Jamie Hajek NWE, TU • Tom Hestermann, Sunflower, TO • Travis Hill, NPPD, TO • Teddy Hutchinson, OPPD, TO

• Brenda Jessop, Evergy Companies, TO

• Jonah Martin, Tri-State G&T, TU • Todd Meyers, WAPA, TO • Curtis Miller, WFEC, TO • Matthew Mohr, EREC, TU • Boyd Trester, Basin Electric, TO • Harika Basaran, CAWG Liaison,

Public Utility Commission of Texas

BACKGROUND

On July 26, 2016, the Board approved the 2016 ITP Near-Term study (2016 ITPNT). On August 17, 2016, SPP issued Southwestern Public Service Company (SPS) Notification to Construct (NTC) No. 200407, which included Line - Mustang - Seminole 115 kV Ckt 1. On November 15, 2016, SPS accepted NTC 200407. SPS submitted an updated project cost estimate in February 4, 2021, of $16,064,921. Compared to the escalated baseline estimate of $21,784,880, the resulting project cost variance is -$5,719,959 or -26.3%. This project went into service on December 15, 2020.

140 of 306

Upgrade ID Owner Upgrade Name Upgrade Scope

51478 SPS Mustang - Seminole 115 kV Ckt 1 New Line

Construct new 115 kV line from Mustang to Seminole.

51479 SPS Mustang 115 kV Terminal Upgrades

Install terminal upgrades at Mustang 115 kV substation.

51480 SPS Seminole 115 kV Terminal Upgrades

Install terminal upgrades at Seminole 115 kV substation.

Upgrade ID Owner Baseline Cost

Estimate (Adj. for Inflation)

Latest Variance Var. %

51478 SPS $16,565,463 $11,037,124 ($5,528,339) -33.4%

51479 SPS $2,993,755 $2,629,398 ($364,357) -12.2%

51480 SPS $2,225,662 $2,398,399 $172,737 7.8%

Total $21,784,880 $16,064,921 ($5,719,959) -26.3%

SUPPORTING ANALYSIS

PCWG reviewed information provided by SPS for this project. The following were significant items included among justification for cost decreases.

• Construction labor cost for line was $3,298,762 less than estimated. Construction resource practices have changed since this project was originally estimated and we've seen significant reductions in construction costs in recent years. Scope change allowed for reduction in construction labor due to reuse of some structures.

• Material cost for line was less $981,234 less than estimated. Major risks did not materialize which enabled the release of contingency reserves from the project budget.

• Contingency cost for Mustang substation was $324,562 less than estimated. Lower material and engineering labor costs offset high construction labor costs. Otherwise, major risks did not materialize which enabled the release of contingency reserves from the project budget.

141 of 306

• Material for Seminole substation was $289,170 less than estimated. Foundation, fence, and grading material was included in construction contracts and not captured as material costs.

RECOMMENDATION

PCWG requests that the Board approve MOPC’s recommendation to accept the cost estimate deviation as reasonable and acceptable and reestablish the baseline used to evaluate future cost estimate deviations.

Approved: Project Cost Working Group 03/03/2021

Approved, unanimous

Markets & Operations Policy Committee 04/12/2021

Approved, consent agenda

142 of 306

SOUTHWEST POWER POOL, INC. SPP Staff


April 27, 2021 Recommendation to modify NTC for Line – Chaves – Price Tap – CV Pines – Capitan 115 kV


The following persons represent the Southwest Power Pool: • Lanny Nickell, Executive Vice President and Chief Operating Officer • Antoine Lucas, Vice President, Engineering • David Kelley, Director, Research, Development & Tariff Services • Casey Cathey, Director, System Planning


LINE – CHAVES – PRICE TAP – CV PINES – CAPITAN 115 KV On February 19, 2014 SPP issued Notification to Construct (NTC) 200256 to Southwestern Public Service Company (SPS) based on approval of the 2014 ITP Near-Term assessment (2014 ITPNT). On December 15, 2020, SPS requested that SPP modify NTC-200256 to combine UIDs 50723 and 50724 into a single UID with the Network Upgrade Name and Description calling for a 115 kV line from the Price Tap to the Capitan Sub, eliminating references to the Central Valley Electric Cooperative (CVEC) Pine Lodge Sub (527514). CVEC made the decision to defer the conversion of their CVEC-Pine Lodge Substation from 69kV to 115kV. This project was placed in service on January 30, 2018. Project ID Project Name

30577 Line - Chaves - Price - CV Pines - Capitan 115 kV Ckt 1

Upgrade ID

Upgrade Name Upgrade Descriptions Owner Cost

Estimate

50722 Chaves - Price 115 kV Ckt 1 Rebuild

Rebuild 5-mile 69 kV line from Chaves to Price converting to 115 kV. Install any necessary terminal equipment at Chaves.

SPS $4,701,279

50723 CV Pines - Price 115 kV Ckt 1 Rebuild

Rebuild 3-mile 69 kV line from CV Pines to Price converting to 115 kV. SPS $4,158,668

143 of 306

Upgrade ID

Upgrade Name Upgrade Descriptions Owner Cost

Estimate

50724 Capitan - CV Pines 115 kV Ckt 1 Rebuild

Rebuild 5-mile 69 kV line from Capitan to CV Pines converting to 115 kV. SPS $5,415,053

Total $14,275,000 Business Practice 7060, Section 6.4:

If SPP determines that an NTC/NTC-C Project modification is reasonable, it will inform the TWG, MOPC, and BOD of this fact at their next regularly scheduled quarterly meeting and request the BOD approval or endorsement, as necessary, to issue an NTC/NTC-C modification.

After the BOD approves or endorses the NTC/NTC-C modification, SPP will issue a modified NTC/NTC-C, as needed.

ANALYSIS

SPP Staff has determined that the modification below is reasonable and will not adversely impact contracted service.

Upgrade ID Upgrade Name Upgrade Descriptions Owner Latest

Estimate

50722 Chaves - Price 115 kV Ckt 1 Rebuild

Rebuild 5-mile 69 kV line from Chaves to Price converting to 115 kV. Install any necessary terminal equipment at Chaves.

SPS $5,961,279

50724 Capitan - Price 115 kV Ckt 1

Rebuild 8-mile 69 kV line from Capitan to Price converting to 115 kV.

SPS $1,741,345

Total $7,702,624

RECOMMENDATION

Staff recommends that the Board approve modification of Upgrade ID 50724 as shown above and withdrawal of NTC for Upgrade ID 50723.


144 of 306

of 7

Revision Request Recommendation Report

RR #: 435 Date: 1/6/2021

RR Title: Change Assignment Threshold for ERIS in the GI Study Process APP Business Practice 7250

SUBMITTER INFORMATION

Submitter Name: Steve Purdy on behalf of TWG Company: SPP

Email: [email protected] Phone: 501-614-3371

EXECUTIVE SUMMARY AND MOTION FOR RECOMMENDED MOPC/BOD ACTION (Executive summary is high-level explanation of what the revision request will accomplish and should include a summary of voting

records and opposition. The motion for recommended MOPC/BOD action should be written such that the organization group “recommends” the action needed.)

The pupose of this revision request is to implement improvements to the GI study process that were recommended by the Generation Interconnet Improvement Task Force (GIITF), NRIS / ERIS Deliverability Task Force (NEDTF) and the Markets and Operations Policy Committee (MOPC). The TWG recommends the MOPC approve RR 435: Change Assignment Threshold for ERIS in the GI Study Process, Business Practice 7250. The TWG approved the motion unanimously with one abstention.

OBJECTIVE OF REVISION (Ensure the objective has been updated to reflect the intent of the revisions presented for approval)

Objectives: The current criteria for allocating network upgrade costs to interconnection customers is defined in SPP Business Practice 7250. Under this criterion, there will be a number of constraints that are not required to be mitigated. Some stakeholders have concluded that the number of unmitigated constraints is too great and is resulting in undesirable effects in the SPP market. Benefits: Modification of the requirements will capture more constraints and assign them to the interconnection requests that cause them in order to reduce these undesirable effects.

SPP STAFF COMMENTS

Staff supports the proposed language. This will clarify that when both the existing and new criteria are satisfied, all requests that meet either criteria will be eligible for cost allocation.

IMPACT ANALYSIS (See RR Impact Analysis Form for complete impact details)

145 of 306

mailto:[email protected]

of 7

System Changes No Yes Process Changes? No Yes

Impact Analysis Required? No Yes | If no, but system or process changes are expected please explain why an Impact Analysis will not be performed (e.g. FERC Order, work included in another Impact Analysis for a related RR):

Estimated Vendor Cost: NA ROM based on information available at the time of the estimate Cost Categories: A>0-20k, B>20-60k, C>60-100k, D>100-300k, E>300k – 600k, F>600k – 1mm, *G>1mm *If greater than 1mm an upper limit will also be provided.

Estimated Implementation Staff Hours: NA ROM based on information available at the time of the estimate

Estimated Implementation Time: NA ROM based on information available at the time of the estimate

Primary Working Group Priority:

SPP DOCUMENTS IMPACTED Market Protocols Protocol Section(s): Protocol Version: Operating Criteria Criteria Section(s): Criteria Date: Planning Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): Business Practice Business Practice Number: 7250 Integrated Transmission Planning (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): ORGANIZATIONAL GROUP ACTION

(Action = Approved, Approved Unanimously, or Rejected)

Primary Working Group: TWG

Date: 1/6/2021

Motion: Approve with the modification suggested by ENEL and by SPP Staff.

Action: Passed

Abstained: 1-Sunflower

Opposed: None

Reason for Abstention/Opposition:

146 of 306

of 7

Secondary Working Group: RTWG

Date: 2/25/2021

Motion:Approve RR 435 as modified at the RTWG.

Action:Passed

Abstained: None

Opposed:None


Secondary Working Group:

Date:

Motion:

Action:

Abstained:

Opposed:


Secondary Working Group:

Date:

Motion:

Action:

Abstained:

Opposed:


MOPC

Date: 4/11/2021

Motion:

Action: Approved on MOPC Consent Agenda 4/15/21

Abstained:

Opposed:


147 of 306

of 7

BOD/Member Committee

Date:

Motion:

Action:

Abstained:

Opposed:


SUMMARY OF COMMENTS (See comment forms in the RR folder on SPP.org for full comment details)

1. Comment Form Date and Submitter: 11/20/2020, Ann Coultas, Enel Green Power N.A.

Summary of Comments: Enel Green Power North America wishes to clarify the proposed business practice manual language to be more precise and consistent with the language approved by the GIITF and MOPC and sent to the BPWG. These proposed tweaks more clearly differentiate between the use of MW Impact and TDF in the new criteria.

Organizational Group Review Results (e.g. Reviewed and accepted, reviewed but not accepted, reviewed with partial acceptance – provide details to explain): Reviewed and accepted by TWG on 1/6/2021

2. Comment Form Date and Submitter:

Summary of Comments:

Organizational Group Review Date and Results (e.g. Reviewed and accepted, reviewed but not accepted, reviewed with partial acceptance – provide details to explain):

3. Comment Form Date and Submitter:

Summary of Comments:

Organizational Group Review Date and Results (e.g. Reviewed and accepted, reviewed but not accepted, reviewed with partial acceptance – provide details to explain):

PROPOSED REVISION(S) TO SPP DOCUMENTS

SPP Business Practices (As approved by TWG)

7250 Generator Interconnection Service

Generator Interconnection Service is provided by SPP pursuant to the Generator Interconnection Procedures (Attachment V). Process and procedure guidelines have been established in order to attain a common understanding regarding the study process and the integration of Network Resource Interconnection Service (NRIS) facilities and Energy Resource Interconnection Service (ERIS) facilities into the SPP Transmission System.

Business Practice Current Day Rules and Procedures:

148 of 306

of 7

1) Energy Resource Interconnection Service (ERIS) will be studied based on Attachment V of the SPP OATT, using various percentages of Generation Interconnection request values spread to the entire SPP footprint based on the load ratio share of the Transmission Owner zones. Upgrades required to interconnect the ERIS generating facility will be cost allocated based on a 20% TDF threshold for outage based constraints and 3% TDF threshold for system intact constraints. In addition, upgrades required to mitigate every outage-based constraint where at least one request has at least 5% TDF and the sum of all MW impacts from project with at least 5% TDF equals at least 20% of the facility’s emergency rating will be cost allocated to every request having a TDF on the constraint of at least 5%.

Network Resource Interconnection Service (NRIS) facilities will be studied based on an analysis through Attachment V of the SPP Open Access Transmission Tariff (OATT), using the nameplate amount of the resource to the interconnection host zone. Upgrades required to interconnect will be identified and cost assigned based on a 3% TDF threshold. NRIS studies also include an ERIS component which uses various percentages of nameplate values spread to the entire footprint based on the load ratio share of the Transmission Owner zones.

2) Once interconnection is complete, there is no difference between SPP Operations’ treatment of generating facilities regardless of generation interconnection type (NRIS or ERIS).

3) Neither NRIS nor ERIS guarantees transmission service or deliverability pursuant to Part II or Part III of the SPP OATT. Transmission service must be requested and studied through the same process as any other Designated Resource wanting to deliver energy to a specified point (PointTo-Point Transmission Service) or to a specified Network Load (Network Integrated Transmission Service).

4) Base Plan funding determinations for Base Plan Upgrades are subject to limits stated in Attachments Z2 and J of the SPP OATT. Upgrades required to attain either NRIS or ERIS are not eligible for Base Plan funding.

Future Procedure consideration:

1) Current business rules will change once the new SPP Integrated Marketplace is implemented.

Definitions

Designated Resource: Any designated generation resource owned, purchased or leased by a Transmission Customer to serve load in the SPP Region. Designated Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Transmission Customer's load on a non-interruptible basis.

Energy Resource Interconnection Service: An Interconnection Service that allows the Interconnection Customer to connect its Generating facility to the Transmission System to be eligible to deliver the Generation Facility’s electric output using the existing firm or nonfirm capacity of the Transmission System on an as available basis. Energy resource Interconnection Service in and of itself does not convey transmission service.

Firm Transmission Service: The highest quality (priority) service offered to customers under a filed rate schedule that anticipates no planned interruption.

Grandfathered Agreements or Transactions: Grandfathered Agreements or Transactions include (1) agreements providing long term firm transmission service executed prior to April 1, 1999 and Network Integration Transmission Service executed prior to February 1, 2000; (2) bundled wholesale contracts (that reserve transmission as part of the contract); (3) short-term firm and non-firm point-to-point transmission transactions which were accepted and confirmed prior to the Effective Date; (4) existing or new contracts entered into by the Southwestern Power Administration on behalf of the United States for the use of transmission facilities of the

149 of 306

of 7

Southwestern Power Administration that are constructed or acquired by purchase or other agreement, as authorized under Section 5 of the Flood Control Act of 1944, for the transmission of Federal Power; and (5) contracts executed before the Effective Date, regardless of term, entered into by the Southwestern Power Administration on behalf of the United States for the transmission of power or energy across transmission facilities owned and operated by the Southwestern Power Administration; (6)contracts entered into by a Nebraska public-power entity prior to the transfer of functional control of its transmission facilities to the Transmission Provider; (7) existing contracts entered into by a Member which is a Nebraska public-power entity with any retail or wholesale electric utility customer that has a right under state law to obtain electric transmission service or energy service from such Member; and (8) new contracts entered into by a Member which is a Nebraska publicpower entity with any retail or wholesale electric utility customer that has a right under state law to obtain electric transmission service or energy service from such Member to the extent that provision of service under the Tariff would not satisfy such Member’s obligation under state law. These agreements are set forth on the list which is Attachment W to this Tariff. Umbrella service agreements are specifically not Grandfathered.

Long-Term Service: Long-Term Firm Point-To-Point Transmission Service or Network Integration Transmission Service of one year or longer in duration.

Network Integration Transmission Service: Service that allows an electric transmission customer to integrate, plan, economically dispatch and regulate its network reserves in a manner comparable to that in which the Transmission Owner serves Native Load customers. This transmission service is provided under Part III of the SPP Tariff.

Network Resource Interconnection Service: An Interconnection Service that allows the Interconnection Customer to integrate its Generating Facility with the Transmission System in a manner comparable to that in which the Transmission Owner integrates its generating facilities to serve Native Load Customers as a Network Resource. Network Resource Interconnection Service in and of itself does not convey transmission service.

Non-Firm Transmission Service: Transmission service that is reserved on an as-available basis and is subject to curtailment or interruption.

OATT: Open Access Transmission Tariff

Part II: Tariff Sections 13 through 27 pertaining to Point-To-Point Transmission Service in conjunction with the applicable Common Service Provisions of Part I and appropriate Schedules and Attachments.

Part III: Tariff Sections 28 through 36 pertaining to Network Integration Transmission Service in conjunction with the applicable Common Service Provisions of Part I and appropriate Schedules and Attachments.

Point-To-Point Transmission Service: The reservation and transmission of capacity and energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under Part II of the SPP Tariff.

Short-Term Service: Short-Term Firm Point-To-Point Transmission Service or Network Integration Transmission Service of less than one year in duration.

SPP: The Southwest Power Pool, Inc.

Transfer Distribution Factor (TDF): A general term, which may refer to either PTDF or OTDF – The TDF represents the relationship between the participation adjustment of two areas and the Flowgates within the system.

150 of 306

of 7

Transmission System: The facilities used by the Transmission Provider to provide transmission service under Part II, Part III and Part IV of the SPP Tariff.

SPP OATT References:

Part II

Part III

Attachment C

Attachment J

Attachment V

Attachment AC

Attachment Z1 & Z2

151 of 306



April 27, 2021 Multi - Minco - Pleasant Valley - Draper 345 kV Cost Estimate Increase


The following persons represent the Southwest Power Pool: • Lanny Nickell, Executive Vice President and Chief Operating Officer • Antoine Lucas, Vice President, Engineering • David Kelley, Director, Research, Development & Tariff Services • Casey Cathey, Director, System Planning


On October 27, 2020, the SPP Board of directors approved the Multi - Minco - Pleasant Valley - Draper 345 kV as part of the 2020 Integrated Transmission Planning Assessment (2020 ITP). On November 17, 2020, SPP issued NTC-C 210587 to Oklahoma Gas & Electric Company (OGE).

SPP received OGE’s acceptance of NTC 210587 and NTC-C Project Estimate (CPE) on February 15, 2021.

Project ID Project Name Project Description Study Estimate

81741 Multi - Minco -

Pleasant Valley - Draper 345 kV

Build new 345 kV line from Minco to Pleasant Valley 345 kV substation and install

new 345/138 kV transformers at Pleasant Valley. Tie Pleasant Valley sub into existing Cimarron - Draper line. Upgrade Terminal

equipment on Franklin – Midwest.

$121,793,243

SUPPORTING ANALYSIS

Section 5 of Business Practice 7060 states:

If the CPE variance bandwidth exceeds the variance bandwidth of -30% to +30% of the Study Estimate, SPP staff will re-evaluate this Applicable Project using the new cost estimate data provided by the DTO, and will make a recommendation to the BOD at its next regularly scheduled meeting. In other words, if the CPE is greater than 1.0833 times the Study Estimate or is less than 0.875 times the Study Estimate SPP staff will re-evaluate the project.

152 of 306

The table below shows a comparison of Study Estimates and CPEs for the upgrades and the total project.

Upgrade ID

Upgrade Name Upgrade Descriptions Owner Study

Estimate

NTC-C Cost Estimate

(CPE)

122848 Minco 345

kV Terminal Equipment

Install terminal equipment at Minco substation 345 kV to

support new 345 kV line from Minco with sum emergency

rating of 1792 MVA

OGE $2,288,668 $1,843,729

122849

Pleasant Valley 345

kV Substation

Expand the existing Pleasant Valley 138 kV substation to 345 kV, new terminals for Minco to Pleasant Valley to Draper and terminals for cut-in of existing

Cimarron to Draper 345 kV line. Tie into Cimarron to Draper 345

kV line

OGE $25,500,000 $30,707,951

122850

Pleasant Valley

345/138 kV Transformer

Ckt 1

Install new 345/138 kV transformer to achieve a summer

emergency rating of 478 MVA OGE $4,225,000 $5,003,830

122851

Pleasant Valley

345/138 kV Transformer

Ckt 2

Install a new 345/138 kV transformer to achieve a summer

emergency rating of 478 MVA OGE $4,225,000 $4,885,649

122858

Cimarron - Draper 345 kV Terminal Upgrades #2

Upgrade any necessary terminal equipment on the Cimarron to Draper 345 kV line to achieve a summer emergency rating of

1540 MVA

OGE $2,288,668 $2,541,200

122863

Midwest 138 kV Ckt 1 Terminal Upgrades

Upgrade necessary terminal equipment at Midwest 138 kV on the Midwest to Franklin 138 kV

line to achieve a summer emergency rating of 308 MVA

OGE $65,000 $65,000

153 of 306

Upgrade ID

Upgrade Name Upgrade Descriptions Owner Study

Estimate

NTC-C Cost Estimate

(CPE)

143176 Draper 345 kV Terminal Equipment

Install a new line terminal at Draper 345 kV to accommodate new 345 kV line from Pleasant

Valley

OGE $2,288,668 $6,484,533

133085

Minco - Pleasant

Valley 345 kV Ckt 1

Construct new 345 kV line from Minco – Pleasant Valley with summer emergency rating of

1792 MVA

TBD $57,512,100 $57,512,1001

133106

Draper - Pleasant

Valley 345 kV Ckt 2

Construct new 345 kV line from Draper – Pleasant Valley with summer emergency rating of

1792 MVA

TBD $23,400,139 $23,400,1392

Total $121,793,243 $132,444,131

Multi - Minco - Pleasant Valley - Draper 345 kV was identified as an Economic project in the 2020 ITP. Cost for construction of this project are base plan funded.

OGE supplied the following causes for cost increase: • Pleasant Valley Substation

• Estimated cost increase is $5.2 million • Existing Pleasant Valley substation needs expansion in order to accommodate

345 kV facilities • Approximately $10 million to reconfigure 138 kV facilities • Remainder of estimate will be spent on 345 kV facilities

• Draper Substation • Estimated cost increase is $4.2 million • Existing 345 kV lines entering Draper sub will need to be reconfigured to allow

entry of the new line

1 Study Estimate used for this upgrade in order to calculate variance since RFP Response Estimate (RRE) has not been received. 2 Study Estimate used for this upgrade in order to calculate variance since RFP Response Estimate (RRE) has not been received.

154 of 306

Pursuant to SPP OATT Attachment Y Section V.3, SPP staff has re-evaluated this project using CPEs. After a review of benefit/cost ratios (B/C), the cost increase reported does not impact the B/C ratios to an extent that would change staff’s recommendation to issue NTC for this project.

RECOMMENDATION

Staff recommends that the Board accept the refined cost estimate associated with the Multi - Minco - Pleasant Valley - Draper 345 kV project.

Action requested: Approve recommendation

B/C Comparison Future 1 40 Yr Future 2 40 Yr Previous B/C 2.44 5.18 Updated Cost B/C 2.25 4.77

155 of 306

SouthwestPowerPool SPPorg southwest-power-poolHelping our members work together to keep the lights on... today and in the future.

1

MULTI - MINCO - PLEASANT VALLEY - DRAPER 345 KV COST INCREASE

ANTOINE LUCAS

4/27/2021

156 of 306

2

GOVERNING LANGUAGE

Business Practice 7060

• Section 5.1- If the CPE variance bandwidth exceeds the variance bandwidth of -30% to +30% of the Study Estimate, SPP staff will re-evaluate this Applicable Project using the new cost estimate data provided by the DTO, and will make a recommendation to the BOD at its next regularly scheduled meeting.

• In other words, if the CPE is greater than 1.0833 times the Study Estimate or is less than 0.875 times the Study Estimate SPP staff will re-evaluate the project

• Re-evaluation required if

• Estimated project cost exceeds $131,938,620

• Estimated project cost is less than $106,569,088157 of 306

3

NTC BACKGROUND

• NTC 210587 : Issued 11/20/2020 per 2020 ITP Assessment

• Project Type: Base Plan

• Need Date: 1/1/2025

• Multi - Minco - Pleasant Valley - Draper 345 kV includes 2 competitive upgrades

• Minco - Pleasant Valley 345 kV Ckt 1

• Draper - Pleasant Valley 345 kV Ckt 2

• OGE provided NTC-C Project Estimates (CPEs) for upgrades in NTC-C 210587 on 2/15/2021

• Costs in response to NTC-C increased $10.7 million or 8.74%158 of 306

4

PROJECT INFORMATION – PID 81741Upgrade

IDUpgrade Name Upgrade Descriptions Owner

Study Estimate

NTC-C Cost Estimate

122848Minco 345 kV Terminal Equipment

Install terminal equipment at Minco substation 345 kV to support new 345 kV line from Minco with sum emergency rating of 1792 MVA

OGE $2,288,668 $1,843,729

122849Pleasant Valley 345 kV Substation

Expand the existing Pleasant Valley 138 kV substation to 345 kV, new terminals for Minco to Pleasant Valley to Draper and terminals for cut-in of existing Cimarron to Draper 345 kV line. Tie into Cimarron to Draper 345 kV line

OGE $25,500,000 $30,707,951

122850Pleasant Valley 345/138 kV Transformer Ckt 1

Install new 345/138 kV transformer to achieve a summer emergency rating of 478 MVA OGE $4,225,000 $5,003,830

122851Pleasant Valley 345/138 kV Transformer Ckt 2

Install a new 345/138 kV transformer to achieve a summer emergency rating of 478 MVA OGE $4,225,000 $4,885,649

122858Cimarron - Draper 345 kV Terminal Upgrades #2

Upgrade any necessary terminal equipment on the Cimarron to Draper 345 kV line to achieve a summer emergency rating of 1540 MVA

OGE $2,288,668 $2,541,200

122863Midwest 138 kV Ckt 1 Terminal Upgrades

Upgrade necessary terminal equipment at Midwest 138 kV on the Midwest to Franklin 138 kV line to achieve a summer emergency rating of 308 MVA

OGE $65,000 $65,000

143176Draper 345 kV Terminal Equipment

Install a new line terminal at Draper 345 kV to accommodate new 345 kV line from Pleasant Valley

OGE $2,288,668 $6,484,533

133085Minco - Pleasant Valley 345 kV Ckt 1*

Construct new 345 kV line from Minco – Pleasant Valley with summer emergency rating of 1792 MVA

TBD $57,512,100 $57,512,100

133106Draper - Pleasant Valley 345 kV Ckt 2*

Construct new 345 kV line from Draper – Pleasant Valley with summer emergency rating of 1792 MVA

TBD $23,400,139 $23,400,139

Total $121,793,243 $132,444,131*Competitive upgrades

159 of 306

5

FACTORS DRIVING COST INCREASE

• Pleasant Valley Substation

• Estimated cost increase is $5.2 million

• Existing Pleasant Valley substation needs expansion in order to

accommodate 345 kV facilities

• Approximately $10 million to reconfigure 138 kV facilities

• Remainder of estimate will be spent on 345 kV facilities

• Draper Substation

• Estimated cost increase is $4.2 million

• Existing 345 kV lines entering Draper sub will need to be reconfigured

to allow entry of the new line

160 of 306

6

ANALYSIS

After a review of benefit/cost (B/C) ratios, the cost increase reported does

not impact the B/C ratios to an extent that would change staff’s

recommendation to issue NTC for this project.

B/C Comparison Future 1 40 Yr Future 2 40 Yr

Previous B/C 2.44 5.18

Updated Cost B/C 2.25 4.77

161 of 306

7

STAFF RECOMMENDATION

Project Name Staff Recommendation

Multi - Minco - Pleasant

Valley - Draper 345 kV

Staff requests that the Board accept the refined cost

estimate associated with this project.


162 of 306


MULTI - MINCO - PLEASANT VALLEY - DRAPER 345 KV COST INCREASE

4/27/2021

163 of 306

2

GOVERNING LANGUAGE

Business Practice 7060• Section 5.1- If the CPE variance bandwidth exceeds the variance

bandwidth of -30% to +30% of the Study Estimate, SPP staff will re-evaluate this Applicable Project using the new cost estimate data provided by the DTO, and will make a recommendation to the BOD at its next regularly scheduled meeting.

• In other words, if the CPE is greater than 1.0833 times the Study Estimate or is less than 0.875 times the Study Estimate SPP staff will re-evaluate the project

• Re-evaluation required if • Estimated project cost exceeds $131,938,620• Estimated project cost is less than $106,569,088

164 of 306

3

NTC BACKGROUND

• NTC 210587 : Issued 11/20/2020 per 2020 ITP Assessment

• Project Type: Base Plan

• Need Date: 1/1/2025

• Multi - Minco - Pleasant Valley - Draper 345 kV includes 2 competitive upgrades • Minco - Pleasant Valley 345 kV Ckt 1• Draper - Pleasant Valley 345 kV Ckt 2

• OGE provided NTC-C Project Estimates (CPEs) for upgrades in NTC-C 210587 on 2/15/2021• Costs in response to NTC-C increased $10.7 million or 8.74%

165 of 306

4

PROJECT INFORMATION – PID 81741Upgrade

ID Upgrade Name Upgrade Descriptions Owner Study Estimate

NTC-C Cost Estimate

122848 Minco 345 kV Terminal Equipment

Install terminal equipment at Minco substation 345 kV to support new 345 kV line from Minco with sum emergency rating of 1792 MVA OGE $2,288,668 $1,843,729

122849 Pleasant Valley 345 kV Substation

Expand the existing Pleasant Valley 138 kV substation to 345 kV, new terminals for Minco to Pleasant Valley to Draper and terminals for cut-in of existing Cimarron to Draper 345 kV line. Tie into Cimarron to Draper 345 kV line

OGE $25,500,000 $30,707,951

122850 Pleasant Valley 345/138 kV Transformer Ckt 1 Install new 345/138 kV transformer to achieve a summer emergency rating of 478 MVA OGE $4,225,000 $5,003,830

122851 Pleasant Valley 345/138 kV Transformer Ckt 2 Install a new 345/138 kV transformer to achieve a summer emergency rating of 478 MVA OGE $4,225,000 $4,885,649

122858Cimarron - Draper 345 kV Terminal Upgrades #2

Upgrade any necessary terminal equipment on the Cimarron to Draper 345 kV line to achieve a summer emergency rating of 1540 MVA OGE $2,288,668 $2,541,200

122863 Midwest 138 kV Ckt 1 Terminal Upgrades

Upgrade necessary terminal equipment at Midwest 138 kV on the Midwest to Franklin 138 kV line to achieve a summer emergency rating of 308 MVA OGE $65,000 $65,000

143176 Draper 345 kV Terminal Equipment

Install a new line terminal at Draper 345 kV to accommodate new 345 kV line from Pleasant Valley OGE $2,288,668 $6,484,533

133085 Minco - Pleasant Valley 345 kV Ckt 1*

Construct new 345 kV line from Minco – Pleasant Valley with summer emergency rating of 1792 MVA TBD $57,512,100 $57,512,100

133106 Draper - Pleasant Valley 345 kV Ckt 2*

Construct new 345 kV line from Draper – Pleasant Valley with summer emergency rating of 1792 MVA TBD $23,400,139 $23,400,139

Total $121,793,243 $132,444,131*Competitive upgrades

166 of 306

5

FACTORS DRIVING COST INCREASE• Pleasant Valley Substation

• Estimated cost increase is $5.2 million• Existing Pleasant Valley substation needs expansion in order to

accommodate 345 kV facilities• Approximately $10 million to reconfigure 138 kV facilities• Remainder of estimate will be spent on 345 kV facilities

• Draper Substation • Estimated cost increase is $4.2 million• Existing 345 kV lines entering Draper sub will need to be reconfigured

to allow entry of the new line

167 of 306

6

ANALYSIS

After a review of benefit/cost (B/C) ratios, the cost increase reported does not impact the B/C ratios to an extent that would change staff’s recommendation to issue NTC for this project.

B/C Comparison Future 1 40 Yr Future 2 40 YrPrevious B/C 2.44 5.18Updated Cost B/C 2.25 4.77

168 of 306

7

STAFF RECOMMENDATION

Project Name Staff Recommendation

Multi - Minco - Pleasant Valley - Draper 345 kV

Staff requests that the Board accept the refined cost estimate associated with this project.


169 of 306


SPP STAFF


April 27, 2021

Evergy Short Circuit Breakers Out-of-Cycle NTC Re-evaluation Request


SPP staff

Background

On February 24, 2021, a re-evaluation request was submitted by Evergy, Inc (“Evergy”) on behalf of Evergy Metro, Inc. ("EM") and Evergy Missouri West, Inc. ("EMW"), requesting an out-of-cycle re-evaluation of PID 81721, project name “Sub - Stilwell 161 kV”, PID 81726, project name “Sub - Craig 161 kV #2” and PID 81725, project name “Sub - Lake Road 161 kV”. These three projects were identified by SPP as needed for Regional Reliability in the 2020 ITP Assessment. Following the conclusion of the short-circuit portion of the 2020 ITP evaluation, Evergy performed a field verification of the interrupting capability of the breakers and found that all were sufficient compared to the calculated short-circuit current, thus eliminating the need for the upgrades. For that reason, Evergy requests a re-evaluation of the listed upgrades identified in SPP-NTC-210583 and SPP-NTC-210608. Recommendations

SPP staff recommends the SPP Board approve the out-of-cycle re-evaluation of PID 81721, 81726, and 81725 for the Evergy short circuit breakers.


170 of 306


SPP STAFF


April 27, 2021

Device - Devil's Lake 115 kV Out-of-Cycle NTC Re-evaluation Request


SPP staff

Background

On February 2, 2021, Western Area Power Administration ("WAPA") submitted a request to SPP for re-evaluation of NTC 210579, PID 91880, project name “Device - Devil's Lake 115 kV” which was identified by SPP as needed for Regional Reliability in the 2020 ITP Assessment. Upon receiving the NTC for the Devils Lake reactor, WAPA reviewed historical operational data in the vicinity to determine the effectiveness of the reactor sizing, as well as the influence of the 115kV tie with Midcontinent Independent System operator (“MISO”) at Devils Lake. WAPA found that the operational data appeared to potentially conflict with the voltages indicated by the 2020 ITP MPM light load which showed base case voltage as high as 1.086 per unit (MPM_F2-25L). While investigating the potential cause, there were several modeling discrepancies found in the neighboring MISO area. WAPA’s conclusion is that the Devils Lake reactor project does not add value to the SPP transmission system. The 2020 ITP needs that indicated that a Devils Lake high voltage mitigation was necessary were a result of modeling discrepancies immediately neighboring the SPP system in MISO. Recommendations

1. SPP staff recommends the SPP Board approve the out-of-cycle request from WAPA to re-evaluate NTC 210579, PID 91880, project name “Device - Devil's Lake 115 kV.”


171 of 306

C a p i t a l S p e n d i n g R e v i e w M a r c h 3 1 , 2 0 2 1

P r e p a r e d b y : A c c o u n t i n g D e p a r t m e n t

172 of 306

SOUTHWEST POWER POOL, CAPITAL SPENDING REVIEW, MARCH 31, 2021 PAGE 1

Project and Foundation Investments as of March 31, 2021

Note: Dollar amounts presented in the tables throughout the report are in $000s

Projects Budget (a) Forecast Variance

EMS, CMT & Markets Upgrade 3,150$ 3,150$ -$

Markets & Reliability Training Simulator (formerly DTS) 2,187 2,187

Ramping Capability 790 790 -

Identity Access Management Deployment (IAM) 500 1,938 (1,438)

FERC Order 841: Electric Storage 423 1,109 (686) Transmission & Generation Implementation Tracking (TAGIT), Standardized Cost Estimation Reporting Template (SCERT) Rewrite 250 88 162

Freeze Date Replacement 226 226 -

Fast-Start Resource Compliance 200 200 -

Interface Pricing & Pseudo Tie Modeling 155 155 -

Total Projects 7,881$ 9,843$ (1,962)$

Foundation - 2021 (b) Budget (a) Forecast Variance

Information Technology 7,610$ 8,060$ (450)$

Operations 2,852 2,300 552

Engineering 1,000 298 702

Facilities 50 66 (16)

Total Foundation - 2021 11,512$ 10,724$ 787$

Contract Services - 2021 (b) Budget (a) Forecast Variance

RC West - EMS Upgrade (c) 350$ 350$ -$

RC West - PMU 88 80 8

WEIS Ongoing Market Enhancements 200 200 -

Total Contract Services - 2021 638$ 630$ 8$ (a) Budget amounts are per the 2021 capital projects budget approved by the board unless otherwise noted. (b) Foundation and contract services projects are reforecast annually. Unused funds do not carry over to the following year.(c) Represents allocation of the 2021-2022 EMS Upgrade capital project.

173 of 306


Capital Projects

Energy Management System (EMS), Centralized Modeling Tool (CMT), and Markets

Software Upgrade

This project addresses the hardware refresh and software upgrade required to continue operations of the

EMS, CMT, and Markets applications. Both the system software and the hardware (included in IT Foundation

Capital) used for the systems are due for refresh by December 2022. In addition, a time frequency device must

be replaced in conjunction with this project no later than September 2022, which is the timeline for this

project. The EMS and Markets systems are essential critical infrastructure protection (CIP) applications that

require continual patch source and vendor support to operate SPP’s reliability and market functions.

During 4Q’20, the vendor began gathering requirements for the

development of a statement of work for design and implementation.

The project requirements were completed in Q1’21. SPP staff and the

vendor are currently finalizing scope of work and cost estimates. The

statement of work is expected to be finalized in late April and development work to begin in May, with an

expected implementation date in 3Q’22.

Markets & Reliability Training Simulator (formerly DTS Upgrade)

This final phase of the multi-year training simulator project includes the build and integration of simulation

software for market functionality to create a Markets and Reliability Training Simulator (MRTS). It consists of

the following three phases of work:

o Phase 2B-1: Requirements, system design, and implementation of some of the core

infrastructure that is required for Phase 2B. This phase of design included work on the Delta

Design Notes (DDNs) for eight different areas of functionality and was finalized in Q4’20.

174 of 306


o Phase 2B-2: Design, installation, testing, and implementation of a basic MRTS. During 2Q’20, a

statement of work for Phase 2B-2 was signed and the vendor began working on detailed design

work however there were delays due to limited vendor resources available for markets-related

work in this phase. Internal resources took advantage of the resultant delay to incorporate

additional design details that would have otherwise waited

until Phase 2B-3. These details are being developed to

achieve additional needed functionality to simulate

subsystems such as automation features that make the

creation of scenarios easier. As a result, Phase 2B-3 is no

longer necessary. In 2Q’21, delivery of the system

components is expected with testing to follow in late

Q2’21. The project is expected to wrap up in Q3’21.

o Phase 2B-3: As noted, this work has been incorporated into the previous phase.

Ramp Product

This project will address the impact that resource ramp shortages in the market cause with respect to short-

term spikes in market prices by designing methods to better anticipate the need for responsive resources in

the market.

The goal of a ramping product is to provide a market-based approach for ramp management that leverages

existing operational experiences to systematically pre-position resources with ramp capability to manage net

load variations and uncertainties and to provide transparent price signals to incent resource flexibility and

economic investment.

The project was originally approved in the 2020-2022 budget for $0.2M. During the 2021-2023 budget cycle,

the project was revised and approved for a total of $0.8M. The project

requirements were finalized during Q1’21. Development is expected

to begin in late Q2’21, with projected implementation in 4Q’21.

Key Completion Dates Phase 2B-1 Completed

Phase 2B-2

3Q/2021

Phase 2B-3 Cancelled

175 of 306


Identity Access Management (IAM) Deployment

The project was initially launched in 2017 and an industry-leading IAM tool was acquired. In 2018, it became

apparent that the initial scope of the in-progress implementation was not sufficient and the project was

paused. A consultant was engaged in 2020 to perform an analysis of the current state of the program through

the review of business procedures and performance of various assessments. Through SPP’s initial efforts in the

project, lessons learned, expanded internal knowledge and understanding, and consultation with IAM and

regulatory experts, a dedicated and expanded effort is ready to be initiated to develop a successful IAM

program that will focus on overall security and compliance related to identity and access management with

the appropriate overarching framework, processes, procedures, tools and personnel.

The new direction that the project will be taking is expected to result in additional capital spend of

approximately $1.9M. In 4Q’20, the SPP Oversight Committee approved the scope for a multi-phased

approach to establish and support an IAM program. During 1Q’21, the Finance Committee approved $0.4M

out of budget spend for 2021. The additional costs to complete all phases will be submitted for consideration

in the 2022-2024 budget cycle.

The approved spend for 2021 includes the installation of the IAM solution into production to run user access

certification campaigns and support provisioning and de-provisioning of access for a defined set of targets in a

phased approach and to identify and integrate additional applications into the solution. During 1Q’21, staff

was engaged with the vendor to start laying the groundwork for the project kickoff.

FERC Order 841: Electric Storage

The project originally began back in 2018, but was put on hold due to its dependence on the completion of the

settlement’s system replacement project, which occurred in early 2020.

As a result of FERC mandating an implementation date of August 5,

2021 in response to SPP’s 4Q’19 filing, the project resumed in order to

meet that date.

176 of 306


The vendor provided a statement of work during 4Q’20 for the completion of development which exceeded

the approved budget by $0.7M. Executive approval was received in early 1Q’21.

Development efforts continued throughout 1Q’21. Member testing will begin in May and is planned to

conclude in July. The program is in yellow health status due to development delays at the vendor’s location.

Although this was a known risk, the program and sub-projects remain on schedule and mitigation steps are

being taken to ensure the project deadline is met.

Transmission and Generation Implementation Tracking (TAGIT), Standardized Cost

Estimation Reporting Template (SCERT) Rewrite

The goal of this project was to enhance the TAGIT/SCERT platform in a way that would allow operators to

focus on data analysis, remove potential barriers for additional operators to cross-train, and improve data

integrity.

The new tool, which was implemented 1Q’21, was renamed

Transmission Reporting and Communication (TRAC). No additional costs were

incurred in 2021 to complete the project. Utilizing more internal resources than

originally contemplated resulted in a favorable variance to budget.

Freeze Date Replacement

SPP’s congestion management process details the method used to allocate rights for transmission service on

flowgates with shared impacts between one or more parties of the Congestion Management Process (CMP)

members. The process is based on a methodology that employs a baseline of transmission reservations set in

2004, known as the freeze date. The project was broken into two phases. Phase I of the project allowed new

designated network resources to participate in the allocation process and was implemented in June 2018 with

no vendor software changes required.

177 of 306


SPP is currently working with other CMP members to develop and implement Phase II. The Phase II design is

intended to better align the allocation process with CMP members’ respective planning processes. This phase

will require vendor system changes and will tentatively start later in 2021 and extend into 2022.

Fast-Start Resource Compliance

This project will address FERC Order 206 which requests SPP to specifically address certain issues around the

requirement to allow commitment cost of fast-start resources to be reflected in day-ahead and real-time

prices.

In 3Q’21, the vendor is expected to begin gathering requirements for the

development of a statement of work for the design and implementation,

with an expected implementation date in 2Q’22.

Interface Pricing & Pseudo Tie Modeling

SPP will collaborate with MISO to design a common methodology for modeling pricing interfaces and treating

pseudo-tie-congesting charges. Once SPP and MISO agree on a methodology, they will begin designing, testing

and implementing the changes. Multiple vendor changes may be required to properly model the new

interfaces. Settlement changes will be required to remove pseudo-tie overlapping congestion charges.

The project was budgeted to begin in 2021, but has been deferred to 2022 as part of an effort to reduce 2021

capital spend.

178 of 306


Foundation Capital Expenditures

The following sections discuss foundational capital expenditures for information technology, operations,

engineering, and facilities for the current year. Although foundational spend is presented for the upcoming three

years during each annual budget cycle, foundational budgets are re-forecast every budget cycle for the

upcoming year. The following table shows the 3-year projection for foundation capital spend that was presented

in the 2021 budget.

2021 2022 2023 Total

Information Technology 7,610$ 7,900$ 8,100$ 23,610$

Operations 2,852$ 2,290$ 2,260$ 7,402$

Engineering Department 1,000$ 410$ 410$ 1,820$

Facilities 50$ 50$ 50$ 150$

Total 11,512$ 10,650$ 10,820$ 32,982$

179 of 306


Foundation Expenditures: Information Technology

The IT Foundation budget captures corporate-wide hardware and software requirements to support SPP’s

business applications and systems and is managed in two broad categories:

• Infrastructure Refresh: This category includes upgrades and/or replacements of existing infrastructure

to support the ongoing requirements of existing systems and services.

• New Initiatives: This category is for incremental hardware, software, and/or development services to

support new IT and/or corporate projects and services.

2021 forecast of $8.1M includes $0.7M of spend requisitioned in late-2020 that was received/recorded as capex in early 2021.

The total spend during 1Q’21 was $0.8M and included the following items:

• Additional storage to meet data retention and long-term archival policies – Infrastructure Refresh

• Additional firewall/security appliances - Infrastructure Refresh

• Software licenses associated with additional storage and blade technology servers/platforms –

Infrastructure Refresh

• Storage monitoring tool – New Initiatives

IT Foundation (IT Dept. only)2021

Budget2021

Forecast Variance2021 YTD

Spend

Infrastructure Refresh 7,030$ 7,480$ (450)$ 745$

New Initiatives 580$ 580$ -$ 55$

Total 7,610$ 8,060$ (450)$ 800$

180 of 306


Foundation Expenditures: Operations, Engineering, & Facilities

The following foundation budgets reflect capital spend for enhancements to operations, engineering, and for

various upgrades/improvements to SPP’s physical facilities.

Operations MOS Enhancements

Total spend during 1Q’21 was $0.4M and included the following:

• Delivery and internal testing of MOS Release 2.2. This release is member-impacting and includes

the following:

o Multi-day Pricing and Forecast Commitment functionality

o Allow Markets UI/API to display data older than 7 days

o MUI Resource Offer Reports download

o New Commitment History

o Market Clearing Engine: keeps reliability resources online to meet run time requirement

A primary focus for 2Q’21 includes the following:

• Completion of member testing and implementation of MOS 2.2 Release

• Code delivery of MOS 2.3 Release. This release is member-impacting and includes multiple defects

and enhancements

• Start of member testing for MOS 2.3 Release

Other Foundation2021

Budget2021


Spend

Operations - MOS Enhancements 2,000$ 1,650$ 350$ 402$

Operations - Legacy Systems 852$ 650$ 202$ 13$

Engineering 1,000$ 298$ 702$ -$

Facilities 50$ 66$ (16)$ 6$

181 of 306


Operations Legacy System Enhancements include energy management system (EMS), control-room operations

window (CROW), open access same-time information system (OASIS), dispatch training simulator (DTS),

centralized modeling tool (CMT) and various other applications supporting the operations division. The total

spend in 1Q’21 was $0.01M and included enhancements to the DTS & EMS systems.

Engineering Enhancements - The 2021 budget included consulting work that ultimately was not capital in nature,

and was appropriately expensed creating the variance to budget. The consulting engagement includes analyzing

SPP’s congestion hedging process and providing an independent recommendation to the Strategic Planning

Committee (SPC).

Facilities Enhancements – 1Q’21 spend was minimal and included the purchase of a disinfectant cleaning

machine that delivers superior cleaning coverage in an efficient and cost-effective way.

182 of 306


Contract Services

The following contract services budgets reflect capital spend for RC West and WEIS:

*The budget/forecast includes a two-year total for the 2021-2022 EMS upgrade project.

Contract Services2021

Budget2021


Spend

RC West - EMS Upgrade * 350$ 350$ -$ -$

RC West - PMU 88$ 80$ 8$ -$

WEIS Ongoing Market Enhancements 200$ 200$ -$ -$

183 of 306


Capital Cash Forecast

*Spend to date is for current year forecast only.

Actual Prior

Year(s)2021

Forecast2022

Forecast2023

ForecastTotal

Forecast Spend to

Date

Projects 2,213$ 4,182$ 3,448$ -$ 9,843$ 2,700$

Foundation* - 10,724 10,650 10,820 32,194 1,221

Contract Services - 500 330 200 1,030 -

Total Cash Forecast 2,213$ 15,406$ 14,428$ 11,020$ 43,067$ 3,921$

184 of 306

M o n t h l y F i n a n c i a l R e p o r t i n g P a c k a g e

M a r c h 2 0 2 1

185 of 306

SPP Executive Summary – March

2021 Over / (Under) Recovery

Compensation and Outside Services Expenses

Page 1 186 of 306

2021 FY 2021 FY Fav/(Unfav)

Forecast Budget Variance

Revenues $190,901 $196,510 ($5,609) (2.9%)

Expenses 202,167 200,867 (1,300) (0.6%)

Net Income/(Loss) ($11,265) ($4,356) ($6,909) 158.6%

2021 FY 2021 FY Fav/(Unfav)

Forecast Budget Variance

Tariff Administration Service $148,171 $151,337 ($3,166) (2.1%)

FERC Fees 19,893 22,467 (2,575) (11.5%)

Engineering Studies 10,239 9,504 735 7.7%

Contract Services 10,581 10,585 (4) (0.0%)

Miscellaneous 1,363 1,951 (588) (30.2%)

Annual Non-Load Dues 654 666 (12) (1.8%)

Total Revenue $190,901 $196,510 ($5,609) (2.9%)

9

10

Summary

Revenue

Southwest Power Pool2021 Financial Commentary

March 31, 2021(in thousands)

The annual billing determinants assumed in the 2021 budget for Tariff Administration Service revenues for the market rate schedules were based on actual data from August 2019 - July 2020. The current projections are based on the most recent 2020 actual data that is slightly lower and results in a projected unfavorable variance to budget.

FERC Fees & Assessments revenue reflects the actual rate to be charged under Schedule 12 for 2021, which is $0.072 as compared to $0.083 assumed in the budget.

SPP billable staff time for engineering studies is expected to increase throughout the year and result in a projected favorable variance to budget in Engineering Studies revenues.

Miscellaneous Income primarily includes revenues associated with various sources such as pass-thru consulting costs for the Order 1000 transmission owner selection process, joint operating agreement fees, miscellaneous rebates, reserve sharing, and circuit reimbursements. The variance is driven primarily by the Order 1000 revenues that are offset by lower consulting expenses.

Page 2 187 of 306

Fav/(Unfav)

SPP RTO Contract Services Total SPP SPP RTO Contract Services Total SPP Variance

Salary & Benefits $106,145 $4,310 $110,455 $103,457 $4,346 $107,803 ($2,652) (2.5%)

Assessments & Fees 22,474 - 22,474 22,474 - 22,474 0 0.0%

Communications 4,431 508 4,939 4,440 485 4,925 (14) (0.3%)

Maintenance 16,085 328 16,413 17,471 385 17,856 1,443 8.1%

Outside Services & RSC 18,217 333 18,550 18,667 307 18,974 424 2.2%

Administrative 5,726 1 5,728 5,422 1 5,423 (304) (5.6%)

Travel & Meetings 482 59 541 1,345 59 1,404 862 61.4%

Depreciation 16,475 1,276 17,751 16,776 1,336 18,112 361 2.0%

Interest Expense 7,318 315 7,633 7,588 308 7,896 263 3.3%

Other (Income)/Expenses (2,317) - (2,317) (4,000) - (4,000) (1,683)Total Expense $195,036 $7,130 $202,167 $193,641 $7,226 $200,867 ($1,300) (0.6%)

Expense

2021 FY Forecast 2021 FY Budget

Southwest Power Pool2021 Financial Commentary


Salary & Benefits are expected to be unfavorable to budget partially related to increases in pension and retiree health care plan costs of approximately $1.1 million. This variance is partially offset in Other (Income)/Expenses where the non-service portion of the annual pensioncosts is recorded ($0.5 million). These costs are excluded from the net revenue requirement (NRR) recovery. Various out-of-budget expenses also contributing to the unfavorable variance.

The budget contains a $4 million reduction in overall costs as recommended by SPP management and approved by the Finance Committee and Board of Directors. The recommendation was proposed to reduce total controllable expenditures in an attempt to maintain a 2021 GRR more equally aligned with the 2020 GRR. As no specific reductions were proposed to attain the $4 million reduction, an offset to expenses was budgeted under (Other Income)/ Expenses. Currently $1.6 million of the $4 million reductions remain unidentified.

SPP staff has proposed cost reductions in Maintenance, Outside Services and Travel & Meetings that are reflected in the 2021 forecast at the account level. The unidentified amount remains in the forecast under (Other Income)/ Expenses. Actual amounts also recorded in Other (Income)/Expenses include swap valuation, investment income, unrealized gain/loss on investments, and other miscellaneous income and expense amounts. These expense and income items are highly unpredictable and therefore are not included in the budget.

A portion of the decrease in Outside Services is attributed to lower pass-thru consulting costs associated with the Order 1000 industry expert panel (IEP). The decrease is driven by a slower start up in the process and due to the budget assuming additional projects driven by the 2021 ITP which has subsequently been delayed. This projected decrease in expense is directly offset by pass-thru revenues with no impact to the NRR. The favorable variances are partially offset by out-of-budget items related to staff augmentation for incremental engineering initiatives and congestion hedging studies within operations. Certain services that were originally covered in the 2020 budget were carried forward into 2021, which also offsets the targeted cost reductions in 2021.

Debt payments are forecasted to be favorable to budget due to the early conversion of term notes, which did not include capital expenditures for December 2020 and ultimately contributes to a $1.8 million offset to the GRR.

Page 3 188 of 306

Actual Actual Actual Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast FY 2021 FY 2021 Variance FY 2020 VarianceJan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Forecast Budget Fav/(Unfav) Actual Fav/(Unfav)

IncomeTariff Administrative Service $10,282 $11,599 $11,898 $11,218 $11,564 $12,948 $14,146 $13,956 $11,998 $12,051 $11,676 $14,835 $148,171 $151,337 ($3,166) $172,377 ($24,206)FERC Fees 2,498 1,526 2,068 1,626 1,485 1,288 1,585 1,965 1,799 1,525 1,530 1,651 20,547 23,133 (2,587) 24,858 (4,311)Contract Services 476 869 1,024 1,010 885 885 1,007 885 885 885 885 885 10,581 10,585 (4) 6,247 4,334Engineering Studies Income 769 947 1,076 828 828 828 828 828 828 828 828 828 10,239 9,504 735 7,843 2,396Miscellaneous 137 65 80 87 172 147 127 158 77 77 82 152 1,363 1,951 (588) 2,277 (914)

Total Income 14,161 15,007 16,146 14,769 14,934 16,096 17,692 17,793 15,586 15,366 15,002 18,351 190,901 196,510 (5,609) 213,602 (22,701)

ExpenseSalary & Benefits 8,826 10,083 9,608 8,983 9,171 9,134 9,199 9,109 9,085 9,072 9,030 9,156 110,455 107,803 (2,652) 110,578 123Employee Travel (1) 0 0 - - - 24 58 58 65 66 60 330 969 639 375 45Administrative 234 328 906 285 690 315 473 932 352 499 339 373 5,728 5,423 (304) 5,081 (647)Assessments & Fees 1,873 1,873 1,873 1,873 1,873 1,873 1,873 1,873 1,873 1,873 1,873 1,873 22,474 22,474 0 22,324 (150)Meetings 7 3 0 0 0 0 106 0 29 36 3 27 211 435 224 275 64Communications 417 414 425 409 409 409 409 409 409 409 409 409 4,939 4,925 (14) 4,754 (185)Maintenance 1,200 1,152 1,182 1,303 1,304 1,382 1,379 1,495 1,351 1,312 1,403 1,947 16,413 17,856 1,443 15,686 (727)Services 947 1,237 1,328 1,700 1,480 1,520 1,969 1,494 1,628 1,714 1,481 1,802 18,301 18,475 175 15,795 (2,505)Regional State Committee - - - - - - - - 125 - - 125 249 498 249 65 (184)Depreciation and Other 1,363 1,346 1,448 1,484 1,478 1,491 1,508 1,528 1,550 1,504 1,524 1,527 17,751 18,112 361 18,480 729

Total Expense 14,866 16,436 16,772 16,037 16,406 16,125 16,940 16,899 16,460 16,483 16,128 17,297 196,851 196,971 120 193,413 (3,437)

Other Income/(Expense)Investment Income 25 27 37 - - - - - - - - - 89 - 89 576 (488)Interest Expense (652) (651) (665) (646) (644) (648) (628) (630) (632) (612) (613) (611) (7,633) (7,896) 263 (8,210) 578Capitalized Interest - - - - - - - - - - - - - - - - - Change in Valuation of Swap - - 251 - - - - - - - - - 251 - 251 (196) 447Other Income/(Expense) (3) 111 148 24 24 24 24 24 24 503 503 503 1,908 4,000 (2,092) 2,583 (675)Unrealized Gain on Investment (49) 50 69 - - - - - - - - - 69 - 69 144 (75)Chg in Emp Benefit Plan Funded Sta - - - - - - - - - - - - - - - (4,446) 4,446

Net Other Income (Expense) (679) (464) (160) (622) (620) (624) (605) (607) (608) (109) (110) (108) (5,316) (3,896) (1,420) (9,548) 4,232

Net Income (Loss) ($1,384) ($1,894) ($787) ($1,890) ($2,092) ($653) $148 $287 ($1,483) ($1,227) ($1,236) $945 ($11,265) ($4,356) ($6,909) $10,641 ($21,906), ,2021 Headcount

Approved Budgeted Positions 652 654 654 654 654 654 653 653 653 653 653 653 653 653 656 Actual Headcount (Incl. Vacancy) 639 636 638 637 637 640 640 639 639 639 639 639 639 636 Actual Positions (Excl. Vacancy) 652 654 654 654 654 654 653 653 653 653 653 653 653 656

Headcount Vacancy Run rate 2.0% 2.8% 2.4% 2.6% 2.6% 2.1% 2.0% 2.1% 2.1% 2.1% 2.1% 2.1% 2.3% 3.5%

NRR Over / (Under) Recovery $1,841 $889 ($4,992) $1,135 $1,022 ($4,112) $3,251 $2,961 ($5,411) $1,917 $1,866 ($2,859) ($2,492)

Southwest Power PoolMonthly Financial Overview


Page 4 189 of 306

2021 FY 2021 FY Variance 2021 FY 2021 FY Variance 2021 FY 2021 FY Variance

Forecast Budget Fav/(Unfav) Forecast Budget Fav/(Unfav) Forecast Budget Fav/(Unfav)

IncomeTariff Administrative Service $148,171 $151,337 ($3,166) - - - $148,171 $151,337 ($3,166)Fees & Assessments 20,547 23,133 (2,587) - - - 20,547 23,133 (2,587)Contract Services Revenue 308 312 (4) 10,273 10,272 0 10,581 10,585 (4)Miscellaneous Income 11,602 11,455 147 - - - 11,602 11,455 147

Total Income $180,629 $186,238 ($5,610) $10,273 $10,272 $0 $190,901 $196,510 ($5,609)

ExpenseSalary 68,011 67,057 (954) 3,193 3,232 39 71,203 70,289 (915)Benefits & Taxes 37,628 35,760 (1,869) 1,096 1,087 (10) 38,725 36,846 (1,878)Continuing Education 506 641 135 21 28 6 527 668 141

Salary & Benefits 106,145 103,457 (2,688) 4,310 4,346 36 110,455 107,803 (2,652)Employee Travel 283 922 639 47 47 - 330 969 639Administrative 5,726 5,422 (304) 1 1 () 5,728 5,423 (304)Assessments & Fees 22,474 22,474 0 - - - 22,474 22,474 0Meetings 199 423 224 12 12 - 211 435 224Communications 4,431 4,440 9 508 485 (23) 4,939 4,925 (14)Maintenance 16,085 17,471 1,386 328 385 57 16,413 17,856 1,443Services 17,968 18,169 201 333 307 (26) 18,301 18,475 175Regional State Committee 249 498 249 - - - 249 498 249Depreciation 16,475 16,776 301 1,276 1,336 60 17,751 18,112 361

Total Expense 190,035 190,053 18 6,816 6,918 103 196,851 196,971 120

Net Other Income (Expense) (5,001) (3,588) (1,413) (315) (308) (7) (5,316) (3,896) (1,420)

Net Income (Loss) ($14,408) ($7,403) ($7,005) $3,143 $3,047 $96 ($11,265) ($4,356) ($6,909)

2021 Headcount 620 620 - 33 33 - 653 653 -

SPP RTO Contract Services Total SPP

Southwest Power PoolContract Services Breakout


Page 5 190 of 306

Mar-2021 Mar-2021 Variance Mar-2021 Mar-2021 Variance FY 2021 FY 2021 VarianceActual Forecast Fav/(Unfav) Actual Budget Fav/(Unfav) Forecast Budget Fav/(Unfav)

IncomeTariff Administrative Service $11,898 $11,914 ($16) $33,779 $37,371 ($3,592) $148,171 $151,337 ($3,166) (2%)

FERC Fees 2,068 1,877 191 6,092 6,363 (270) 20,547 23,133 (2,587) (11%)

Contract Services 1,024 1,010 14 2,369 2,372 (4) 10,581 10,585 (4) (0%)

Engineering Studies 1,076 825 251 2,792 2,376 416 10,239 9,504 735 8%

Miscellaneous 80 152 (72) 282 456 (174) 1,363 1,951 (588) (30%)

Total Income 16,146 15,778 367 45,314 48,938 (3,625) 190,901 196,510 (5,609) (3%)

ExpenseSalary & Benefits 9,608 9,035 (573) 28,516 27,358 (1,159) 110,455 107,803 (2,652) (2%)

Employee Travel - () () - 330 969 639 66%

Administrative 906 301 (606) 1,469 1,045 (424) 5,728 5,423 (304) (6%)

Assessments & Fees 1,873 1,770 (103) 5,620 5,733 113 22,474 22,474 0%

Meetings () 10 20 10 211 435 224 51%

Communications 425 409 (16) 1,256 1,231 (25) 4,939 4,925 (14) (0%)

Maintenance 1,182 1,345 163 3,535 4,464 929 16,413 17,856 1,443 8%

Services 1,328 1,452 124 3,512 4,666 1,153 18,301 18,475 175 1%

Regional State Committee - - - - 125 125 249 498 249 50%

Depreciation 1,448 1,502 54 4,157 4,518 361 17,751 18,112 361 2%

Total Expense 16,772 15,815 (957) 48,075 49,158 1,083 196,851 196,971 120 0%

Other Income/(Expense)Investment Income 37 - 37 89 - 89 89 - 89Interest Expense (665) (663) (2) (1,969) (1,975) 6 (7,633) (7,896) 263 (3%)

Capitalized Interest - - - - - - - - - Change in Valuation of Swap 251 - 251 251 - 251 251 - 251Other Income/Expense 148 - 148 256 1,000 (744) 1,908 4,000 (2,092) (52%)

Unrealized Gain on Investment 69 - 69 69 - 69 69 - 69Net Other Income (Expense) (160) (663) 503 (1,304) (975) (329) (5,316) (3,896) (1,420)

Net Income (Loss) ($787) ($700) ($87) ($4,065) ($1,194) ($2,870) ($11,265) ($4,356) ($6,909)

Headcount 638 638 - 638 654 16 653 653 -

Southwest Power PoolCurrent Month Financial Overview


Current Month Compared to Forecast YTD Actual Compared to YTD Budget FY Forecast Compared to FY Budget

Page 6 191 of 306

3/31/2021 12/31/2020 Net Change

ASSETSCurrent Assets

Cash & Equivalents $148,682 $76,128 $72,553Restricted Cash Deposits 531,719 445,550 86,169Accounts Receivable (net) 13,802 85,251 (71,449)Other Current Assets 20,207 11,883 8,324

Total Current Assets $714,409 $618,812 $95,598

Total Fixed Assets 66,828 69,127 (2,299)Total Other Assets 4,698 8,337 (3,639)Investments 3,719 29,160 (25,441)

Total Assets $789,655 $725,436 $64,219

LIABILITIES & EQUITYLiabilities

Current LiabilitiesAccounts Payable $22,419 $78,204 (55,785)Customer Deposits 537,282 445,550 91,732Current Maturities of LT Debt 31,313 27,260 4,053Other Current Liabilities 122,193 86,877 35,315Deferred Revenue 6,672 8,243 (1,572)

Total Current Liabilities 719,879 646,134 73,745

Line of Credit 2,740 12,090 (9,350)

Long Term LiabilitiesLong-Term Debt 156,990 154,353 2,636Other Long Term Liabilities 47,232 45,980 1,253

Total Long Term Liabilities 204,222 200,333 3,889

Net Income (4,065) 10,641 (14,706)Members' Equity (133,122) (143,763) 10,641

Total Members' Equity (137,186) (133,122) (4,065)

TOTAL LIABILITIES & EQUITY $789,655 $725,436 $64,219

Southwest Power PoolBalance SheetMarch 31, 2021

(in thousands)

Page 7 192 of 306

Current Month Actual vs. Budget Year End Forecast vs. BudgetActual Budget Over/(Under) 2021 2021 Over/(Under)Mar-21 Mar-21 Budget Forecast Budget Budget

Information Technology 165 168 (3) 168 168 0

Operations 165 171 (6) 167 171 (4)

Engineering 93 100 (7) 98 100 (2)

Process Integrity 55 56 (1) 56 56 0

Administration 55 56 (1) 57 56 1

HR & Administrative Services 21 24 (3) 23 24 (1)

Regulatory Policy & General Counsel 27 28 (1) 27 27 0

Market Monitoring 16 16 0 16 16 0

Communications & Gov't Affairs 8 8 0 8 8 0

Contract Services 33 33 0 33 33 0

Budgeted Attrition (6) 6 (6) 6

Total Positions 638 654 (16) 653 653 0

Headcount summary2021

Forecast2021

Budget - 2020 Total positions at year-end 656 6592020 attrition / eliminations 0 (3)2021 attrition / eliminations (3) (3)

2021 Headcount 653 653

Southwest Power PoolHeadcount Analysis

March 31, 2021

Note: The 2021 budget included the elimination of three unidentified positions from 2020 (that had not occurred at the time the budget was proposed) and an additional three unidentified eliminations for 2021. Three positions were eliminated in late 2020 and three in January 2021.

Page 8 193 of 306


OVERSIGHT COMMITTEE REPORT TO THE BOARD

194 of 306


OVERSIGHT COMMITTEE REPORT TO THE BOARDJOSH MARTIN, GRAHAM EDWARDS, JULIAN BRIX

APRIL

2021

195 of 306

3

MEETING

• April 14, 2021 Conference Call (MMU, RTO & RCAG sessions)

196 of 306

4

MMU SESSION - APRIL 14, 2021

• February Winter Event• Review of MMU activities during and after the event

• MMU organizational status• Staffing update and discussions

• MMU budget update

• MMU communications with FERC

• MMU quarterly update

197 of 306

5

RTO SESSION – APRIL 14, 2021

• Emergency Management & Business Continuity Update• Vision – Continual State of Readiness• Discussed 20/21 highlights

• 37 BCPs updated, facilitated COVID response• Agreement between AR DOH in Nov 2020• Sought FEMA reimbursement ($167k)• Coordinated 2021 winter storm• Target return to Chenal 5/10

• Next Steps• GridEx VI – Nov 16-17• Focus on BC/COOP on physical recovery of ODC• Focus EM on other all-hazards

198 of 306

6


• Commercial Insurance Renewal Update

• Corporate Risk Management Update• Corporate risks

• Pandemic/economic recession• Western interconnection activities• 2021 winter storm event

• Risk matrix reviewed• Next steps

• Continued evolution & training• Budget/FTE updates• GRC tool usage• Integrated risk management model

199 of 306

7


• Quarterly Activity Reports• Internal Audit• Compliance• Cyber and Physical Security

200 of 306

8


• 2021 Independent Expert Panel (IEP) Pool Recommendation• Approved slate of 19 candidates for recommendation to the Board

• Renewed 11 existing IEP members, and,• Approved 8 new IEP members (subject to new OC policy)

• Established new policy If an expert has been selected to serve in the IEP pool and their respective retirement from their previous employer is less than two years and appears to present a conflict of interest, they may not be chosen to serve on a panel until the two year period has expired.

201 of 306

9

OC MOTION

• Oversight Committee recommends the BOD approve the recommended candidates for the 2021 IEP:• Renew 11 of the 2020 IEP pool members; and,• 8 new applicants, Mike Schiavone, Heather Bailey, Jay Caspary,

Mark Workman, Bill Eakin, Joseph Hassink, John Olsen, and Paul Johnson, (subject to the OC’s established policy regarding “panel selection” for recent retirees and the appearance of a conflict of interest within the two-year cooling off period).

202 of 306

10

RCAG – APRIL 14, 2021

• Regional Compliance Advisory Group Report• Shared the NERC’s identified risk and state of reliability

• Grid transformation, extreme natural events, critical infrastructure interdependencies and security risks

• Discussed transition of RCWG to RCAG scope• Discussed value of information exchange

203 of 306


SPP OVERSIGHT COMMITTEE


April 27, 2021

Industry Expert Pool for 2021


The following persons are members of the SPP Oversight Committee:

Joshua Martin Julian Brix Graham Edwards Darcy Ortiz Elizabeth Moore

Chair, SPP Director SPP Director SPP Director SPP Director SPP Director

Background

Pursuant to Attachment Y of the SPP OATT the SPP Order 1000 process requires the use of an Industry Expert Pool/Panel to review, rank and score proposals for Competitive Upgrade projects. The Oversight Committee has the delegated responsibility to make formal recommendations to the SPP Board for the approval of experts that would serve on the Industry Expert Pool/Panel. From this pool, a panel(s) of 3-5 experts will be chosen to fulfill the responsibilities of making a recommendation of the winning proposal and an alternate proposal to the SPP Board. Ultimately, the SPP Board will select the winning proposal and name the Designated Transmissions Owner for each Competitive Upgrade project.

Analysis

SPP Staff publicized the need for these expert positions and received applications from interested applicants. Experts from the 2020 pool have also requested to be renewed onto the expert pool for 2021. Staff reviewed these applications and made some recommendations to the Oversight Committee during its April 14, 2021 meeting. Following discussions on the recommendation of candidates; where the members of the Oversight Committee and relevant SPP Staff attended, staff brought forward summaries of all eleven renewals from 2020 and eight new applications received for the Oversight Committee to review. Each new applicant was reviewed and voted on by the Committee. The vote was unanimous for those committee members present to recommend all eleven renewals and the eight new applicants to the SPP Board for inclusion in the 2021 pool. The selection of the eight new candidates would be subject to the following panel selection policy for the Oversight Committee:

If an expert has been selected to serve in the IEP pool and their respective retirement from their previous employer is less than two years and appears to present a conflict of interest, they may not be chosen to serve on a panel until the two year period has expired.

204 of 306

Recommendation

The Oversight Committee recommends that the SPP Board approve the recommended Industry Expert Pool for 2021. The applicants recommended are:

2020 IEP Renewals

1. William Steele 2. Michael Jacobs 3. Raj Rana 4. Steve Strickland 5. Dave Nevius 6. Michael McDowell 7. Ali Al-Fayez 8. Tom Bozeman 9. Brian Van Gheem 10. Herb Schrayshuen 11. Bernie Cevera

2021 New IEP Applicants

1. Jay Caspary 2. Mark Workman 3. Bill Eakin 4. Mike Schiavone 5. Joseph Hassink 6. John Olsen 7. Heather Bailey 8. Paul Johnson Summaries of the recommended applicants are attached.

Approved: SPP Oversight Committee April 14, 2021

Unanimous


205 of 306

IEP Candidate Name: William Arthur Steele (Bill Steele) Education: (School, Years, Degree) University of Northern Colorado (Jan 75-June 76) – BS in Bus Admin University of Phoenix (Sept 85-May 87) MBA Institute of Public Utilities Grid School coursework in 2014 Employment History: (Company, Years, Position) Bill Steele & Associates LLC (May 2012-present) Owner Colorado Public Utilities Commission (Mar 1978-May 2012) Principal Financial Analyst, Commission Advisor Center for Public Utilities at NMSU (1998-present) Instructor in “Basics of Regulation” among other courses Affiliations: (Personal affiliations vs. Company affiliations) None Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – N/A Electric Transmission Project Management and Construction – N/A Electric Transmission Operations - Includes testifying in rate cases; reviewing securities filings by electric utilities Electric Transmission Rate Design and Analysis - Being a rate case witness for the Colorado PUC trial staff; became supervisor of Auditing Unit in ’87, which included auditing the cost allocation methodologies of how utilities assigned costs within the company and how the company allocated costs between multi- state jurisdictions. Revenue requirement and rate design were also issues addressed by his work experience. When moved to Commission staff advisor, work included educating Commissioners and ALJs on technical operations of the electric system including transmission, cost allocation and assignment by function, and cost recovery in rates. Electric Transmission Finance – Being a rate case witness for the Colorado PUC trial staff; became supervisor of Auditing Unit in ’87, which included auditing the cost allocation methodologies of how utilities assigned costs within the company and how the company allocated costs between multi - state jurisdictions. Revenue requirement and rate design were also issues addressed by his work experience. When moved to Commission staff advisor, work included educating Commissioners and ALJs on technical operations of the electric system including transmission, cost allocation and assignment by function, and cost recovery in rates. Published: As a member of NARUC’s Staff Subcommittee on Management Analysis, co-authored “A Guide to Management Audit Plans” published in 1992 and “A Guide to Auditing Implementation Activities” published in 1996. Has presented and testified numerous times Other: (summary of other important items in application/resume) Presenter to various organizations on numerous regulatory/utility related topics Speaker at NARUC Staff Subcommittee on Accounting and Finance on various topics

206 of 306

IEP Candidate Name: Michael B. Jacobs Education: (School, Years, Degree) Wesleyan University, ’81-’85, BA in Social Studies University of Wisconsin-Madison, ’86-’87, Urban and Regional Planning University of Massachusetts-Amherst, ’89-’90, MS-Regional Planning Employment History: (Company, Years, Position) Union of Concerned Scientists, Jan ’13-present - Sr Analyst, Markets and Transmission Xtreme Power, Sept ’10-Jul ’12 - Director of Regulatory Affairs and Market Policy National Renewable Energy Lab (Alliance for Sustainable Energy), Jul’09-Jul’10 Engineer - Transmission and Grid Integration First Wind, ’07-’09 - Vice-President Transmission American Wind Energy Association, ’04-’07 - Deputy Policy Director TransEnergiUs, ’01-’03 - Open Season Manager Affiliations: (Personal affiliations vs. Company affiliations) None Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design - lead in development of interconnection requests for over 10 wind farms from application through completion of Interconnection Agreements Electric Transmission Project Management and Construction - As manager for ISO Affairs and Open Seasons for the first “merchant” transmission projects, implemented strategy and communications for including independent transmission in ISO tariffs and in the plans for prospective bidders for transmission capacity. This required clear description of roles and responsibilities for projects in relation to ISO-NE, NYISO, and PJM, tariff and rule changes, extensive stakeholder and staff interactions as the model for participation in the ISO took shape Electric Transmission Operations - As VP-Transmission for wind developer, organized operations for radial lines with multiple generator assets. Pre-construction, established protocols for reservations made by multiple parties; negotiated with ISO-NE and Bangor Hydro to use dynamic line rating based on ambient temperature on radial portion of Bangor Hydro system; led analyses of unused transmission capacity for use of non-firm reservationElectric Transmission Rate Design and Analysis - for TransEnergiUS, established the OASIS site for Cross- Sound Cable connecting NYISO and ISO-NE; set up business manual, physical website, participated as member of ISO-NE OASIS users group; for First Wind, prepared for third-party use through OATT of 345 kV radial line in Utah Electric Transmission Finance - as decision-making member of Northern Maine Independent System Administrator board, reviewed setting manual tariff rates; as manager of Open Season marketing, made value projections for economic transfers, monthly reservation rates Published: “Qualifying Storage as Transmission” with PJM staff, 2013 “Transmission Recommendations for High Wind Penetration” IEEE Power Engineering Society General Meeting 2007 “Making Wind Fit” EEI Electric Perspectives 2005 Other: (summary of other important items in application/resume) Utility Variable Integration Group Past BOD Positions: Northern Maine Independent System Administrator, ended 2009 The Wind Coalition, ended 2007 Wind on the Wires, ended 2007 Present BOD Positions: Solar Grid Storage, began 2014 Vineyard Power Cooperative, began 2012 207 of 306

IEP Candidate Name: Raj Rana Education: (School, Years, Degree) M.S. University, India, ’66-’71, BSEE-Electric power West Virginia University, ’74-’77, MSEE-Electric power University of Dayton, ’81-’82, MBA-Finance and International Business Employment History: (Company, Years, Position) Rana Energy Consulting LLC, ’11 – present Owner, Consulting Engineer (see below for detail) American Electric Power Service Corp, ’00-’10 - Director-RTO Policy and NERC Compliance American Electric Power Service Corp, ’77- ’99 - Engineer, Sr. Engineer, Principle Engineer Since January 2011, I am providing consulting services pertinent to NERC reliability compliance, wholesale energy markets, transmission ratemaking, market power analysis, energy efficiency, demand response, ISO/RTO participation, transmission system planning and operat ion. I also develop and teach courses in the areas of technical and business aspects of electric utility. The following provides a list of major projects covered or working on as part of the consulting work: - EEI – Restore power and mutual assistance program manager for two years - Conduct mock NERC Reliability and CIPs audits, and review compliance documents for a major electric

power company - Expand power system restoration plan to prepare for rapid restoration following blackouts due to GMD

as well as malicious electromagnetic pulse (EMP) attack - Evaluate the neutral earthing resistor data collected by TransPower New Zealand for the effectiveness

of such neutral blocking devices to protect transformers against potential impact of EMP attacks. Affiliations: (Personal affiliations vs. Company affiliations) None listed on Application Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design - Planning of AEP’s bulk transmission network at 230 to 765 kV voltage level. Active member of the engineering and design team for the EHV lines and stations approved for construction. Regional and inter-regional reliability studies to assess the interconnected network reliability. Participate in testing and commissioning of new EHV lines and large generators while integrating them into the existing EHV network. Also, conduct tests on 800 and 1,300 MW generators to address dynamic stability and protection issues such as transient stability, loss of excitation, and sub- synchronous resonance. Electric Transmission Project Management and Construction - As a planning engineer, was an active member of AEP’s transmission construction team to manage construction of 345 and 765 kV lines and stations for timely integration into the system. Supported the construction group in right-of-way acquisition process, such as educating affected communities and property owners on perceived EMF, radio/TV interference, corona effect, and other concerns. Electric Transmission Operations - As part of short-term transmission planning responsibilities, conducted next-day, weekly, and seasonal studies to assess reliability performance of the existing bulk transmission network, and developed appropriate mitigation measures to maintain security of the AEP transmission system in the interconnected system environment. Participated in regional and inter- regional studies for short-term and long-term interconnected system assessments. Address loop flows issue. Evaluate total and available transmission capability (TTC and ATC) for AEP OASIS.

208 of 306

Electric Transmission Rate Design and Analysis - As Director of Transmission Policy, coordinated the efforts of OATT filings at FERC including preparing testimonies for senior executives as well as ROI studies and testimonies. Review transmission rate calculations for FERC filings. Electric Transmission Finance - Developed multi-year capital budget for transmission lines and stations for inclusion in Company’s overall Capital budget planning. As part of this activity, input received from line and station engineering as well as from the construction and project management groups. Also conducted sensitivity studies to evaluate the impact of variations in assumed parameters, such as inflation rates, in-service date delays to regulatory issues, equipment delivery issues, contingencies and variances. Worked with the Finance department for issuance of bonds to finance major EHV transmission projects Published: Seven technical papers in the area of transmission planning, power plant integration, momentary fast turbine valving, sub-synchronous resonance, loss of excitation, and torsional measurements of 800 and 1,300 MW steam generators Other: (summary of other important items in application/resume) Registered Professional Engineer (P.E.) Ohio Certified Energy Manager (CEM) Project Management Professional (PMP_PMI) IEEE – Life Member Association of Energy Engineers (AEE) – Member

209 of 306

IEP Candidate Name: Steve Strickland Education: (School, Years, Degree) University of Arkansas, ’77-’79, BS-Chemical Engineering UALR, ’80-’85, MBA UALR Law School, ’90-’95, J.D. Employment History: (Company, Years, Position) Entergy Arkansas, Inc., 5/79-5/14 VP-Regulatory Affairs (also: Engineer, Manager Business Development, Executive Assistant to the Chairman, Manager Regulatory Planning and Special Studies, Manager Regulatory Affairs, and Director Regulatory Affairs) Affiliations: (Personal affiliations vs. Company affiliations) No current affiliations. As part of work in regulatory affairs for EAI, had repeated interactions with SPP members OG&E, AECC, and AEP/SWEPCO related to regulatory issues that affected all of these electric utilities that provide retail service to customers in Arkansas. Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design - none specific to transmission; was staff and project engineer on design of two generation plants, coal/coke gasification projects; responsibilities included engineering review; coordinating review of all engineering functions with contract engineering design firm; development of detailed critical path scheduled for final engineering and construction; selection of flue gas desulfurization equipment for lignite-based generating plant Electric Transmission Project Management and Construction - none specific to transmission; have experience in project management (see above answer about engineering design) Electric Transmission Operations - as head of Regulatory Affairs for EAI, responsibilities included securing regulatory approval for sites for transmission projects; close interaction with transmission planning to find right balance of site/route design, cost, and public impact to meet need for new transmission facilities in order to secure regulatory approval for construction Electric Transmission Rate Design and Analysis - have more than 25 years’ experience dealing with state and federal regulatory policy issues, including those related to transmission, and in the design of tariffs to recover the revenue requirement for utility facilities that include transmission Electric Transmission Finance - none specific to transmission, but as part of duties as VP, Regulatory Affairs for EAI, was responsible for securing APSC approval for financing authorization for all the utility’s securities used to provide financing for operations, which included transmission facilities; responsibilities also included addressing regulatory issues related to issuance of securities raised in underwriter due diligence calls Published: Nothing public Other: (summary of other important items in application/resume) Member of Arkansas Bar Association Registered Professional Engineer in Arkansas, inactive status Served from ’11-’13 on University of Missouri Financial Research Institute, a regional utility policy forum Also served on BODs of several community organizations during career, including Centers for Youth and

210 of 306

Families and LRSD Public Education Foundation. Currently serve on Advisory Board of Baptist Health Systems and BOD of the Arkansas Repertory Theater

211 of 306

IEP Candidate Name: David R. Nevius Education: (School, Years, Degree) Drexel Institute of Technology, ’64-’69, BSEE-Power System Engineering Drexel University, ’73-’75, MS-Engineering Management Employment History: (Company, Years, Position) NERC, ’79-‘13 Senior VP PSE&G, ’69-‘79 Senior Engineer Affiliations: (Personal affiliations vs. Company affiliations) No past, present or planned affiliations with any QRP or SPP stakeholder. As an employee or officer of NERC, have interfaced with SPP, SPP RE, and SPP members in conducting bulk power system event investigations and seasonal and long-term bulk power system reliability assessments. Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design - Staff lead on development of joint PSE&G/Con Ed plan for second Hudson-Farragut 345kV interconnection with Con Ed and associated transmission adds to PSEG system to effect a 600MW wheeling arrangement; transmission planning sponsor for Northern Zone of PSE&G Transmission System; PSE&G rep on PJM Planning Study for 1980 as well as several special PJM transmission studies and voltage and reactive power studies; Electric Transmission Project Management and Construction - Secured engineering plans and relay recommendations from PSE&G engineering department for the Hudson-Farragut 345kV addition; Electric Transmission Operations - prepared seasonal voltage studies and voltage recommendations for PSE&G system as well as PJM overall system; at NERC, prepared seasonal assessment studies of operating conditions for the upcoming Summer and Winter seasons; lead NERC representative on the evaluation of system operating conditions associated with major blackouts, including Aug 2003 and Sept 2011; Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance – N/A Published: History of deregulation in the U.S. electricity industry with emphasis on the evolution of NERC and its role as the Electric Reliability Organization. Published a European journal at the request of the President of the European Transmission System Operator (ETSO) organization. Other: (summary of other important items in application/resume) IEEE Member since 1969 IEEE USA Energy Policy Committee member U.S. Department of Energy Electricity Advisory Committee (past member) Testified before the U.S. Congress on the need for reliability legislation to make reliability rules mandatory

212 of 306

IEP Candidate Name: Michael L. McDowell Education: (School, Years, Degree) University of Kansas, ’61-’69, BS, MPA, Management, Public Policy Employment History: (Company, Years, Position) Heartland Consumers Power District, ’04-‘13 CEO Western States Power Corporation, ’95-‘00 President, CEO Affiliations: (Personal affiliations vs. Company affiliations) Basin Electric Power Cooperative, East River Electric Power Cooperative, Heartland Consumers Power District, Kansas Municipal Energy Agency, Missouri River Energy Services, Municipal Energy Agency of Nebraska, Nebraska Public Power District, NextEra Energy, NorthWestern Energy, Tenaska Power Services, WAPA (details of affiliations attached to application) Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – N/A Electric Transmission Project Management and Construction - As CEO and later Board Member and President of WSPC, approved for customer funding support selected transmission projects submitted by WAPA, US Bureau of Reclamation, and US Army Corps of Engineers; as CEO of Heartland, helped review and approve interconnection, maintenance, construction plans of transmission projects of Joint Transmission System, Missouri River Basin Power Project, and Whelan Energy Center 2 Electric Transmission Operations – N/A Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance - at WSPC, arranged funding plans for federal power customers’ investments in approved transmission projects submitted by the WAPA, US Bureau of Reclamation, and US Army Corps of Engineers; at Heartland, reviewed and approved funding plans of interconnection, maintenance, and construction projects of Joint Transmission System, Missouri River Basin Power Project, and Whelan Energy Center 2 Published: “Qualifying Storage as Transmission” with PJM staff, 2013 “Transmission Recommendations for High Wind Penetration” IEEE Power Engineering Society General Meeting 2007 “Making Wind Fit” EEI Electric Perspectives 2005 Other: (summary of other important items in application/resume) South Dakota Transportation Commission Board of Directors-American Public Power Association Chair-National Rural Electric Association-National Preference Customer Committee Board of Directors, CEO, and President-Western States Power Corporation (WSPC) Board of Directors and President-Lake Area Improvement Corporation (South Dakota) Midwest Electric Consumers Association Rocky Mountain Electric League Number of transmission projects developed , reviewed, and approved while at WSPC and Heartland covers 16 years and 8 states; will bring to the reviews of proposed projects the outlook and experience as one ultimately responsible to governing boards and customers for success of each project

213 of 306

IEP Candidate Name: Ali Al-Fayez Education: (School, Years, Degree) Ohio State University, ‘80 – MSEE – Power Systems University of Wisconsin-Madison, ’77 – BSEE-Power Systems Employment History: (Company, Years, Position) Al-Fayez Ecommerce LLC (’10-present) COO Independent System Operators (ISO’s) (Feb’18-present) Consultant TRC Solutions (Apr’13-‘15) Consultant AEP (’80-’10) Manager Affiliations: (Personal affiliations vs. Company affiliations) None listed Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – direct contact with AEP’s Engineering and Design group in the development of projects Electric Transmission Project Management and Construction – direct contact with Project Management group to ensure projects are completed on time Electric Transmission Operations – conducted seasonal operational studies for several regions of AEP system. Recently, lead consultant in the evaluation of competitive transmission projects for several ISO in the area of Operation and Maintenance. Conducted seasonal operational studies for AEP system. Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance - managed AEP’s Transmission capital budget; my group entered financial info for projects Published: “Priority Guide for Capital Improvement Projects,” 1990 Inter-RAM Conference “Probabilistic Approach to Transmission System Planning,” 1986 American Power Conference Other: (summary of other important items in application/resume) Registered PE in Ohio Senior Member of Institute of Electrical and Electronic Engineers (IEEE) Over 35 yrs of elec utility experience; 20 yrs in Transmission Planning, 10 yrs in Asset Mgmt; 5 yrs as Elec Utility Consultant; worked closely with planning, operation, substation engineering, transmission line engineering, project mgmt., finance, operation and maintenance, rate tariff, etc; currently working as expert on several confidential major projects In last 5 years with AEP, was responsible for entire AEP Transmission capital construction budget; had the responsibility of analyzing the $1B+ budget; prepared Board of Directors document approvals.

214 of 306

IEP Candidate Name: Tom Bozeman Education: (School, Years, Degree) Kansas University – ’10-’11; Engineering Management 16 credit hours Kansas State University – ’73-’76; BS Electrical Engineering Fort Hays State University – ’71-’73; Undergrad Engineering Employment History: (Company, Years, Position) Atwell LLC, ’16-Present, Director Power Delivery CH2MHILL, ’14-’16, Project Director, Power Group Black & Veatch, ’01-’14, Associate VP and Sn Project Manager

Affiliations: (Personal affiliations vs. Company affiliations) While long industry experience at this time, no current affiliations with SPP QRPs or member companies. Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design - I have designed or led design and construction of over 54 projects / 1,000 miles of transmission line projects from 34kV to 500kV. I have designed or led design and construction of over 170 substation projects from 34kv to 765kV. I have lead system studies work for a 700 mile DC line. Experience includes:

OH lines UG lines DC lines Conventional outdoor substations GIS substations

Electric Transmission Project Management and Construction - The majority of the projects referenced in the answer to question #1 included me acting as the project manager responsible for all aspects of the project, including overseeing engineering, procurement, construction, and testing & commissioning activities. For the last ten plus years I have been a project manager / senior project manager with P&L responsibility for the success of the project. This includes delivering the project ahead of schedule and under budget.

Construction experience was gained during my time at Westar as I was the construction inspector for the majority of the projects I designed. In the last ten years I have had the chance to lead several EPC projects where I had direct responsibility for construction. These EPC projects ranged in size from $5M to one project that was over $620M. Electric Transmission Operations – N/A Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance - Worked extensively with the OPPD Finance Division to determine the cost of capital for projects and the calculation of discount rates to calculate net present value, rate of return, etc.

215 of 306

Published: "Emerging Issues Panel – FERC 1000” EEI Transmission Fall Conference, Charleston, SC. October 2013 “Emerging Issues Panel” EEI Transmission Spring & Fall Conferences, 2002 to present. "Populus EPC Project "Power Delivery - New 150 mile 500kV transmission line one of the longest in North America." B&V Annual Review. 2006. "Transmission Outlook: Financial and Regulatory Update." RMEL Spring Conference, Presentation at the RMEL Conference, Santa Fe, NM. 2003. "Engineering Professionalism." Kansas State University Sn Engineering Class, Presentations at Kansas State University, Manhattan, Kansas. 2001. "Rebuild of 30 Miles of 345 kV in 76 Days." EEI Transmission Committee, Presentation at the EEI Transmission Committee, Rapid City, SD. 1997. "Public Involvement in Siting Transmission Lines." Various State & Local Agencies, Presentations to Various State and Local Governing Agencies. 2000 - 2002. "EMF." Various State & Local Agencies, Presentations to various local and state agencies, EPRI EMF Task Force, and expert testimony. 1993 - 1998. "IEEE Design Guide for Wood Transmission Structures." IEEE STANDARD 751, IEEE PES. February 1991. Other: (summary of other important items in application/resume) EEI RMEL

216 of 306

IEP Candidate Name: Brian Van Gheem Education: (School, Years, Degree) Indiana Institute of Technology – ’04-’07, Master of Business Administration Indiana Institute of Technology – ’04-’07, Master of Science-Management Michigan Technological University – ’91-’96, Bachelor of Science in Electrical engineering with Focus on Electrical Power Employment History: (Company, Years, Position) Proven Compliance Solutions (PCS) – ’18- Present, Senior NERC Consultant ACES – ’13-’18, Manager of Reliability Compliance MISO – ’07-’13, Principal Compliance Engineer Affiliations: (Personal affiliations vs. Company affiliations) Brian has served as a consultant for these entities listed below, while working for ACES or working now for PCS. PCS does not have any current, ongoing, or future scheduled activities with these clients at this time. • Arkansas Electric Cooperative Corporation • Golden Spread Electric Cooperative, Inc. • Rayburn Country Electric Cooperative • Sunflower Electric Power Corporation • Western Farmers Electric Cooperative • American Electric Power Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – Brian’s experience with electric transmission engineering design comes from his experience with constructing underbuilds on such facilities. Brian worked with the primary engineer on the project, providing insight and his expertise on pole attachments and county ordinances on right of ways.

Electric Transmission Project Management and Construction – Brian’s experience with electric transmission project construction comes from his experience of designing distribution underbuilds on transmission facilities. He designed critical distribution feeders within the Cooperative’s service territory based on RUS-approved assemblies. Projects were designated based on the Cooperative’s three-year work plan and normally cost over one hundred thousand dollars apiece. Brian worked with the Cooperative’s Operations Department from design through after-inspections following construction. While with MISO, Brian shadowed various subject matter experts from Transmission Asset Management to map the Interconnection Queue process using Business Process Management Notation. Electric Transmission Operations – Brian obtained his NERC System Operator Certification while working as a Principal Compliance Engineer with MISO. Brian worked alongside Real-time Control Center personnel for support of generating compliance documentation during system events, including DOE OE-417s, Reliability Directive reviews, and post-event analyses. He also served as administrative support as NERC field-tested the Balancing Authority ACE Limits currently in place for NERC Reliability Standard BAL-001-2. As administrative support, Brian would collect Southwest Power Pool, Inc. frequency-based data from various Balancing Authorities across the Eastern and Western Interconnections to present to stakeholders on a monthly basis to identify if a 30-minute threshold was sufficient. He also coordinated the renewal of Nuclear Plant Operating Agreements that were enhanced to support NUC-001 Reliability Compliance. Brian had an opportunity to shadow each Control Center position, both at day and at night, during a six-week period to understand the role of each System Operator. While shadowing, Brian was

217 of 306

expected to observe and then explain the various activities and responsibilities of each position using the same on-the-job qualifications checklists used for MISO’s Training Department. Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance – N/A Published:

While with ACES, Brian commented on various NERC Standards Development Projects and NERC Reliability Guidelines under draft. Other: (summary of other important items in application/resume) Brian is a member of the Institute of Electrical and Electronics Engineers, IEEE Power & Energy Society, and the National Society of Professional Engineers.

218 of 306

IEP Candidate

Name: Herbert (Herb) Schrayshuen Education: (School, Years, Degree) Stevens Institute of Technology – ’72-’76, Bachelor Electrical Engineering Rensselaer Polytechnic Institute – ’77 - ’78, Masters Electric Power Engineering Rensselaer Polytechnic Institute – ’80-’82, Masters Business Administration Employment History: (Company, Years, Position) National Grid – ’79-’07, VP and Director Reliability Compliance SERC Reliability Corporation – ’08-’10, Director Reliability Assessment North American Electric Reliability Corporation – ’10 – ’13, VP & Director Standards and Training, VP &

Director Reliability Assessment Affiliations: (Personal affiliations vs. Company affiliations) Currently through Power Advisors, LLC (100% Owned by Herb Schrayshuen) is a consultant for clients with an interest in the electric power utility industry in the areas of: Electric Power System Reliability Regulation Electric Power System Planning and Operations Providing Expert Testimony Project Management Reliability Compliance Auditing Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – N/A Electric Transmission Project Management and Construction – In the course of my utility career I was an executive responsible for project management of utility transmission systems for a major US utility. Responsible for development of and implementation of transmission system expansion and refurbishment plans. In the course of my utility career, I was an executive responsible for asset management, which dealt with many facets of substation and transmission line design. I also was responsible for electric system project management among other assignments. Electric Transmission Operations – In the course of my utility career I worked closely with transmission operations (field operations and multiple control centers in New York and New England). Also in my post utility career I have audited utilities for compliance with numerous Operations and Planning related NERC standards governing transmission operations. Electric Transmission Rate Design and Analysis – I was an executive responsible for the FERC jurisdictional transmission rate development for Niagara Mohawk Power Corporation and, New England Power Company (as subsidiaries of National Grid, post 2002). Electric Transmission Finance – Has extensive experience in identifying and quantifying the economic benefits for utility customers of transmission alternative projects, specifically revenue requirements based economics.

219 of 306

Published:

Deposition, Affidavit & Testimony Record

AGENCY STATE & REGULATORY PROCEEDINGS CASE# NY PSC 1992 Niagara Mohawk Curtailment Case Need and Benefit of

Curtailment 92-E-0814

NY PSC 1993 Niagara Mohawk Rate Case Cost of Unregulated Generation

93-E-0376 93-E-0378

NY PSC 1994 Niagara Mohawk Rate Case Cost of Unregulated Generation Cost of Buyouts & Settlements

93-E-0376 93-E-0378 93-G-0162

NY PSC 1995 Niagara Mohawk Rate Case Cost of Unregulated Generation

93-E-0098 93-E-0099 94-G-0100

AGENCY FEDERAL REGULATORY PROCEEDINGS CASE#

FERC Indeck Olean – QF Status QF-90-154-002 FERC CalBan – QF Status QF-83-333-000 FERC LG&E Rennselaer – QF Status QF-91-138-000

COURT CIVIL PROCEEDINGS CASE#

US District Court Western District of New York

O’Shanter vs Niagara Mohawk Site Certainty 94-CV-0348 (WMS) (EFM)

State of New York Supreme Court Jefferson County

Black River vs Niagara Mohawk Overgeneration 94-1125

State of New York Supreme Court Warren County

New York State Dam L.P. vs Niagara Mohawk Validity of Amendment

Index 31747

US bankruptcy Court Northern District

Megan Racine Bankruptcy QF Status 92-00860

State of New York Supreme Court Warren County

Philadelphia Et al (Hydro Coalition) overgeneration

State of New York Supreme Court County of Albany

Fourth Branch Associates vs Niagara Mohawk Index 6821-93

US Bankruptcy Court Northern District of New York

Fourth Branch Bankruptcy 94-10972

Other: (summary of other important items in application/resume) Member (Life) Institute of Electrical and Electronic Engineers Member Small User Sector of NERC

220 of 306

Served on the following NERC Committees: Member Representatives Committee, Planning Committee, and Reliability Issues Steering Committee. Licensed Professional Engineer – State of New York

221 of 306

IEP Candidate

Name: Bernie Cevera Education: (School, Years, Degree) The Ohio State University ’85-‘91 – Business Administration Kent State University ’74-‘78 – Technical Mathematics Employment History: (Company, Years, Position) Bernard Cevera Consulting, LLC (‘19 – present) Owner/Principal Guernsey Engineers and Consultants (’11 – ‘19) Managing Consultant Affiliations: (Personal affiliations vs. Company affiliations) Prepared the QRP Application for Western Farmers, Mountrail Williams, and Mor Gran Sou. No follow up work on this topic since then. Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – Load flow, Stability, and short circuit modeling. Distribution level to 756 kV construction cost estimating. Testified ancillary services, must run units, and frequently led teams regarding design decisions and budgeting.

Electric Transmission Project Management and Construction – •Maintained, managed, and constructed a distribution system serving 65,000 electric customers in a service area of over 127.5 miles. The system consisted of 29 substations and 2,992 miles of distribution lines •Obtained approval for a Projected 20-year work plan of expenditures to improve the T&D system, $52,248,500 Transmission and $74,300,000 for Distribution •Conducted a 20-year in-depth transmission and distribution (T&D) system study for the utility that included the review and evaluation of the current condition of the transmission and distribution system and the ability to continuously serve customers. This study indicated that in many parts of the service area, the T&D system facilities are aging beyond the typical useful life. Age of facilities also consider the construction standards of the facilities. Modern T&D system construction standards provide greater safety clearances and sturdier mechanical performance than the standard of 40 to 50 years ago. The study also indicated that many facilities would not be capable of serving the increasing power flow caused by growth in customer energy needs. The study also indicated that during the outage of a single element of the electric system, certain older/undersized segments of the transmission system could become over loaded. The study recommended that the T&D lines be reconductored with larger wire and converted to higher operating voltages during the next 20-year period. Substation equipment (transformers and switchgear) should also be upgraded to larger capabilities and operating voltages •Maintained and managed the rebuilding of a 16 feeder 69/12.47 kV power plant substation while energized including replacement of all transformers, and all 69 kV switches with group operated switches, installation of 15 kV shelter-aisle switchgear with HVAC for existing 15 kV circuits, additional breakers, and spare breaker positions for future use, replacement of existing OCB with SF6 breaker, replacement of equipment pads, installation of oil containment system, installation of firewall between transformers, replaced all 69 kV lightning arresters, replaced communication and control equipment. Also provided oversight of the construction Electric Transmission Operations – •Mr. Cevera assured the cost-effective provision of electricity to nearly 600 MW of retail and wholesale customers by directing as a NERC balancing authority the Production, Production Support Services, Electric Operations, Electric System Control, Marketing and Interconnected Operations, Planning and

222 of 306

Environmental Service departments. Developing first critical communications fiber optic network linking administration with infrastructure assets •Employing physical and financial hedging techniques to reduce coal, gas, fuel oil, energy and transmission costs •Assisting with rating agency presentations and managing all electric rate concerns •NERC registrations included were BA, DP, GO, GOP, LSE, PSE, RP, TO, TOP, and TP •Started the first power dispatch scheduling center and backup control center, and created an environmental services department •Secured a 150 MW allocation of federal hydropower from NYPA saving the members over $300 million annually •Led an expansion of membership from 25 to 76 members totaling over 1,500 MW Electric Transmission Rate Design and Analysis – Mr. Cevera has testified as an expert witness in proceedings before the Federal Energy Regulatory Commission (FERC), the Ohio Public Service Commission, the Kansas Corporation Commission, the Wyoming Public Service Commission, and the Oklahoma Corporation Commission. Electric Transmission Finance – He directed a staff of up to 434 employees with $210 million in annual revenues and $177 million in operating expenses. He managed a 10-unit, 795 MW production department that included six steam units, four combustion turbines, rail contracts and fuel supply arrangements, including mining operations.

•Obtained approval for a Projected 20-year work plan of expenditures to improve the T&D system, $52,248,500 Transmission and $74,300,000 for Distribution •Chaired a group of 25 individuals/11 departments and developing company -wide electric master plan identifying more than $800 million in improvements and funding strategies, including a new 75 MW turbine and a 235 MW coal plant

Published: •Published technical papers in the Library of Congress and the British Library •Speaker at American Public Power Annual Conference, APPA Engineering and Operations Technical Conferences, and at numerous state and national conferences Other: (summary of other important items in application/resume) Mr. Cevera’s areas of responsibility includes identification of Production, Transmission and Distribution improvements for one, five, and up to thirty-year periods in a manner consistent with prudent utility practice, the age and condition of the existing facilities, forecasted load growth, and service reliability. Mr. Cevera has managed Production, Transmission, and Distribution projects from conception, secured funding, and managed construction. Mr. Cevera has modeled electrical systems including must run units and system support resources using PSSE load flow simulation, stability analysis, short circuit programs and conducted loss audit and verification studies and other technical analysis. Mr. Cevera has testified as an expert witness in proceedings before the Federal Energy Regulatory Commission (FERC), the Ohio Public Service Commission, the Kansas Corporation Commission, the Wyoming Public Service Commission, and the Oklahoma Corporation Commission. In addition to operating a balancing authority in the Southwest Power Pool (SPP), Mr. Cevera has utility operating experience in the California Independent System Operator (CalISO), Western Electric Coordinating Council (WECC), Midwest Independent System Operator (MISO), and the Pennsylvania Jersey Maryland Interconnection (PJM). Mr. Cevera has worked with clients in the Electric Reliability Council of Texas (ERCOT) and has maintained his knowledge of the transmission organizations (RTO’s/ISO’S) nationwide. Mr. Cevera’s consulting practice includes expert testimony regarding

223 of 306

transmission, power supply contracts and generation resources, load forecasts, fuel supply, and related regulatory matters. Mr. Cevera was Chief Operating Officer for a utility operating in the California Independent System Operator (CalISO), overseeing engineering, operations, public benefits, planning and marketing, transmission and distribution, and compliance with local, State and federal regulations. He was responsible for planning, directing, and administering the operation and maintenance activities of the electric and hydroelectric departments including five hydro projects including the New Exchequer and McSwain dams, reservoirs, and hydroelectric facilities licensed by the FERC. New Exchequer Reservoir (Lake McClure) has a storage capacity of 1,024,600-acre feet, McSwain Reservoir (Lake McSwain) has a storage capacity of 9,730-acre feet. The combined output for these facilities is 107 megawatts. The utility generates about 330,000,000 kilowatt hours each year. In addition to surface water from the Merced River, the District owns, operates and maintains 239 deep irrigation wells of which 170 are active. These deep irrigation wells historically developed a maximum of 182,900-acre feet at 100% pumping capacity (1976). The District is authorized to act as an electric utility under the California Water Code and provides electric services to customers in Eastern Merced County including the cities of Livingston, Atwater and Merced as well as Castle Airport and Aviation Development Center. Manager of Electric Supply, Kansas City Board of Public Utilities (KCBPU), Kansas City, Kansas. Mr. Cevera assured the cost-effective provision of electricity to nearly 600 MW of retail and wholesale customers by directing as a NERC balancing authority the Production, Production Support Services, Electric Operations, Electric System Control, Marketing and Interconnected Operations, Planning and Environmental Service departments. He directed a staff of up to 434 employees with $210 million in annual revenues and $177 million in operating expenses. He managed a 10-unit, 795 MW production department that included six steam units, four combustion turbines, rail contracts and fuel supply arrangements, including mining operations.

224 of 306

IEP Candidate Name: Jay Caspary Education: (School, Years, Degree)

University of Illinois ’77-‘81 – BSEE – Electric Power Systems Iowa State University ’81 – ’84 – Course requirements for a Masters of Engineering Sangamon State University/University of Illinois-Springfield ’85-’88, MBA courses Employment History: (Company, Years, Position)

Grid Strategies LLC (’20 – ’present) – Vice President Southwest Power Pool (’01 – ’20) – Director, Research Development & Tariff Services Illinois Power/Dynegy (’81 - ’00) – Manager Transmission Operations Affiliations: (Personal affiliations vs. Company affiliations)

Extensive professional relationships with many industry participants engaged in SPP as a result of his 40 year experience in the bulk power industry. Consistent with SPP’s policy for employees, he does not own any stock of member companies and has no positions which would be affected by their financial performance. Has existing consulting services agreement with one of SPP members, EDF Renewables North America LLC, but that activity to date has been limited to advisory services related to their projects and interests in ERCOT and NY.

Area(s) of Expertise: (summarize expertise for each area)

Electric Transmission Engineering Design – Extensive experience in electric transmission engineering design and planning, starting with Transmission Planning and Research engineer positions, prior to becoming Supervisor of Resource Planning and Director System Planning at Illinois Power. I joined SPP as Manager of Engineering to stand up the regional planning processes, led and completed the EHV Overlay Study to provide a vision for SPP’s network as well as facilitated member task force to establish minimum design standards, etc. I represented SPP at the EIPC, co-chair of Technical Review Committee for NREL Interconnections Seam Study. See CV for more details.

Electric Transmission Project Management and Construction – Served as Managing Director of Project Support activity in sponsoring testimony at the Illinois Commerce Commission regarding Sidney – Kansas 345kV line, led technical analysis which resulting in substation reconfiguration at the Clinton Nuclear Power Plant and modified the Final Safety Analysis Report to secure station license prior to commercial operations. I have been a witness at the Kansas Corporation Commission for Westar’s Wichita – Reno Co – Summit 345kV economic upgrade, and other state forums to support other proposed and approved SPP projects such as alternative to CREZ in ERCOT.

Electric Transmission Operations - Was a manager at Illinois Power in the Dispatch Center with responsibilities to support transmission operations and strategic assessments before joining SPP in 2001.

Electric Transmission Rate Design and Analysis - In addition to support at SPP for the RSC and executive management regarding the highway/biway cost allocation methodology adopted by SPP and approved by FERC, I was Director – Pricing at Illinois Power with responsibilities over retail electric and gas rate designs/tariff filings as well as customer contract negotiations. I led

225 of 306

Illinois Power’s efforts to support one of the nation’s first retail wheeling pilots with industrial customers subsequent to FERC ordering open access. I negotiated with large industrial customers to eliminate an interruptible rate provision which was effectively a heavily discounted load retention rate and transitioned those customers over to real-time pricing tariffs to better align risks and rewards. Electric Transmission Finance – N/A Published:

1. Wang, W., Ramasubramanian, D., Farantatos, E., Bowman, D., Scribner, H., Tanner, J., Cates, C., Caspary, J., and Gaikwad, A; Evaluation of Inverter Based

Resources Transient Stability Performance in Weak Areas in Southwest Power Pool’s

System Footprint, CIGRE Session 48, 2020 2. Figueroa-Acevedo, A., Jahanbani-Ardakani, A., Nosair, H., Venkatraman, A., McCalley, J., Bloom, A., Osborn, D., Caspary, J., Okullo, J., Bakke, J., and Scribner, H., Design and

Valuation of High-Capacity HVDC Macrogrid Transmission for the Continental US, IEEE Transactions on Power Systems, 2019 3. Bowman, D., McCann, R., Subramanian, D., Farantatos, E., Gaikwad, A., and Caspary, J., SPP Grid Strength Study with High Inverter-Based Resource Penetration, North American Power Symposium, 2019 4. Caspary, J., Bowman, D., Dial, K., Schoppe, R., Sharp, Z., Cates, C., Tanner, J., Ruiz, P. A, Li, X., and Tsuchida, T.B., Application of Topology Optimization in Real-Time Operations, CIGRE US National Committee 2019 Grid of the Future Symposium, 2019 5. McCalley, J., Caspary, J., Clack, C., Galli, W., Marquis, M., Osborn, D., Orths, A., Sharp, J., Silva, V., and Zeng, P., Wide-Area Planning of Electric Infrastructure: Assessing

Investment Options for Low-Carbon Futures, IEEE Power and Energy Society Magazine, November/December 2017. 6. Caspary, J., McCalley, J., Stoltz, M., Bloom, A., Scribner, H., Novacheck, J., and Figueroa, A., Eastern and Western Interconnections Seams Study Update, CIGRE US National Committee 2017 Grid of the Future Symposium, 2017 7. Caspary, J., and Waldele, B., Leveraging Technology: Maximizing Value in the

Bulk Power Industry [In My View], IEEE Power and Energy Society Magazine, November/December 2016 8. Mattei, A.K.; Grady, W. Mack; Caspary, P. Jay; and McBride, Scott A.; Detection of

time spoofing attacks on GPS synchronized phasor measurement units, 2016 69th Annual Conference for Protective Relay Engineers (CPRE) 9. Caspary, J., McCalley, J., Sanders, S., and Stoltz, M., Proposed Eastern

Interconnection and Western Electricity Coordinating Council Seams Study, CIGRE US National Committee 2015 Grid of the Future Symposium, 2015 10. Lauby, M., Ahlstrom, M., Brooks, D., Beuning, S., Caspary, J., Grant, W., Kirby, B., Milligan, M., O’Malley, M., Patel, M., Piwko, D., Pourbeik, P., Shirmohammidi, D., and

Smith, C., Balancing Act, IEEE Power and Energy Society Magazine, November/December 2011. 11. Osborn, D., Henderson, M., Nickell, B., Lasher, W., Liebold, C., Adams, J., and Caspary, J., Driving Forces Behind Wind, IEEE Power and Energy Society Magazine, November/December 2011. 12. Caspary, J., Power Engineer Profile, IEEE-USA Today’s Engineer, June 2011

226 of 306

13. Lawhorn, J., Osborn, D., Caspary, J., Nickell, B., Larson, D., Lasher, W., and Rahman, M., The View from the Top, IEEE Power and Energy Society Magazine, November/December 2009. 14. Caspary, J., Distribution Circuit Reliability Improvements, Proceedings to the American Power Conference, Chicago, IL, 1994 15. Caspary, J., Hollibaugh, B., Licklider, P., and Patel, K., Optimal Fuel Inventory

Strategies, Proceedings of the American Power Conference, Chicago, IL, 1990

Recent Whitepapers

1. Bloom, A., Azar, L., Caspary, J., Lew, D., Miller, N., Silverstein, A., Simonelli, J., and Zavadil, B., ESIG System Planning Working Group Transmission Planning for 100% Clean Electricity, February 2021 2. Gramlich, R., Caspary, J., Americans for a Clean Energy Grid (ACEG) Planning for

the Future: FERC’s Opportunity to Spur More Cost-Effective Transmission Infrastructure, January 2021 3. Caspary, J., Goggin, M., Gramlich, R., and Schneider, J., Americans for a Clean Energy Grid (ACEG) DISCONNECTED: The Need for New Generator Interconnection

Policy, January 2021

Other: (summary of other important items in application/resume)

2009 – Present Institute of Electrical and Electronics Engineers 2009 - Present Power and Energy Society 2016 – Present CIGRE

227 of 306

IEP Candidate

Name: Mark Workman, PE

Education: (School, Years, Degree) The Ohio State University ’74-‘78 – BS Electrical Engineering – Electric Power Systems Xavier University ’81 – ’84 – MBA Finance Employment History: (Company, Years, Position) American Electric Power Co. (AEP) (’79 – ’20) ’19 – ’20 Managing Director, Siting, Outreach, and Right of Way ’08 – ’19 Managing Director, Transmission Construction ’79 – ’08 Numerous positions with increasing levels of Responsibility Affiliations: (Personal affiliations vs. Company affiliations) Retired from AEP July 2020 Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – From 1979-1983 performed all functions of a protection and control engineer. Experience in power system control circuitry. Through 41.5 years of service at AEP, worked with all levels of Substation and T-Line engineering. Electric Transmission Project Management and Construction – Served as Managing Director of Project Management and Construction as well as siting, outreach, and right -of-way or last 15 years of career at AEP. Managed a $3 Billion project portfolio and supervision over project managers and project coordinators. Responsible for contractor safety. Electric Transmission Operations – Responsible for T&D dispatching and related engineering support from 1983-1990, managed the Ohio system of AEP. Director of substation operations for the AEP transmission organization for the central region of AEP East. 2004 named Director for all AEP transmission line facilities through the 11 state footprint. 2007 named managing director of project management and construction, directly responsible for all transmission field maintenance, operation, and restoration including the PP AEP transmission footprint. Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance – N/A Published: None

228 of 306

Other: (summary of other important items in

application/resume)

Registered PE OH, OSHA 30 Safety Certified

229 of 306

IEP Candidate

Name: Bill Eakin Education: (School, Years, Degree) Louisiana Tech University ’76 -‘79 – Electrical Engineering, BSEE degree Louisiana Tech University ’74 - ‘76 – Basic Studies and pre-engineering Employment History: (Company, Years, Position) AEP (American Electric Power) (’96 – ‘20) Director Project Management Texas - ERCOT Central and Southwest (’86 - ’96) Substation Design Engineer, Power Marketing Analyst/Engineer Affiliations: (Personal affiliations vs. Company affiliations) Employee of American Electric Power, retired September 2020. Career was focused in Texas and ERCOT region did not have interaction with SPP region or AEP SPP work. Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – 1982 to 1994 (12 Years): Position as a Substation design electrical engineer in the Substation Design department for SWEPCO, located in Shreveport, Louisiana. Job duties included all phases of station design and oversight of drawing creation and construction oversight for stations with operating voltages of 12KV through 345KV. Duties also included becoming the grounding expert for the department with extensive training in IEEE 80 guidelines. 1994 to 1995 (1 ½ Years): Position as a Substation design electrical engineer in the Substation Design department for Central and Southwest, located in Tulsa, Oklahoma. Job duties included all phases of station design and oversight of drawing creation and construction oversight for stations with operating voltages of 12KV through 345KV, including physical and protection and controls designs. Duties also included becoming the transformer expert for the department with extensive training in IEEE and ANSI guidelines. Electric Transmission Project Management and Construction – 1996 to 2020 (24 Years) Positions of project management for over 20 years. Duties included project scoping collaboration with the planning and operations departments and then responsibility for driving the projects from cradle to grave, up to and through, construction and commissioning. Responsibilities included putting together teams of design engineers and planning and operations employees and creating schedules and work breakdown structures to use in the oversight of the projects. Most projects were bid for outside contract construction and were usually lump sum firm price contracts. Bids were solicited on most construction and bid meetings were held and ultimately bids were evaluated for lowest qualified and competent bidders. Contracts were created and these contracts were used to drive and oversight the

230 of 306

construction progress and costs. After project completion, a “lessons learned” lookback meeting was held to gather a list of things learned from the project. Electric Transmission Operations – Interfaced with and collaborated with various operations functions to design and construct and commission many transmission line and substation projects in my positions with the electric utility, since 1982. In my engineering design positions we worked closely with operations and dispatching for project scopes. In my project management positions, we worked closely with operations through-out the entire process, especially for planning clearances and for final relay test and commissioning of projects. Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance – In project management positions, cost and finances were one of the primary oversight responsibilities for the projects. A budget was created for each project with monthly reviews and monthly forward-looking forecasts. In my roles as Director of Project Management for the Texas transmission regions, I was responsible for monthly reporting in person at corporate headquarters in Ohio for the transmission capital budgets for the Texas regions. In 2020 our Texas region capital transmission budget was approximately $730 million. When budgets were running under or over we would adjust our project portfolios to keep on budget. Usually we were able to bring in our yearly capital budgets within 1 or 2 % of target. Published: N/A Other: (summary of other important items in

application/resume)

PMI, member since 2016

231 of 306

IEP Candidate

Name: Mike Schiavone Education: (School, Years, Degree) Rochester institute of Technology – ’78-’83, Electrical Engineering

Employment History: (Company, Years, Position) Power Grid Consultants, LLC – ’18 – Present President – ’18 - Present Niagara Mohawk Power Corporation (dba National Grid) – ’83 - ’18

Director of the Transmission Control Center - ’03 - ’18 Affiliations: (Personal affiliations vs. Company affiliations) Mike has no affiliations with SPP members or QRPs.


Electric Transmission Engineering Design – Mike’s experience with electric transmission engineering design comes from his experience from reviewing transmission projects in the conceptual design phase. This review included the “operability” of the design to confirm the project met its system objectives and when appropriate would suggest other solutions. Mike has also provided input to review O1000 proposals related to the New York Energy Highway Initiative. Electric Transmission Project Management and Construction – Mike’s experience with electric transmission project construction comes from his experience in developing outage plans for every transmission project as the Director of the Transmission Control Center. This role covered all aspects including mitigation factors to breaking down insta llation of complex projects into phases. Electric Transmission Operations – Mike’s experience with electric transmission operations comes from his role as the Director of Transmission Control Center where his main role was to ensure the transmission system was operated in a safe, reliable, and efficient manner. This included meeting NERC TOP requirements and preparing for NERC TOP audits. Outage coordination and scheduling of mitigation plans to maintain the system was under his purview. As stated above he was a member on multiple NERC Standard drafting teams and NYISO/NPCC committees. Electric Transmission Rate Design and Analysis – N/A Electric Transmission Finance – N/A

Published: Mike was member of several NERC Standard Drafting teams (FAC-008 thru -012) (EOP-008) (NUC-001)

232 of 306


Mike is a registered Professional Engineer in the State of New York, and a NERC Reliability Coordinator. Held several committee positions with NPCC and NYISO during his career.

233 of 306

IEP Candidate

Name: Joseph Hassink Education: (School, Years, Degree) Georgia Institute of Technology ’74-‘79 – Bachelor in Electrical Engineering, Power Systems Purdue University ’79 – ’80 – Masters of Science in Electrical Engineering, Power Systems Employment History: (Company, Years, Position) American Electric Power (’81 – ’20) – Engineer – Director, Planning & Engineering Affiliations: (Personal affiliations vs. Company affiliations) Retired from American Electric Power Service Corporation, which is affiliated with the following QRP/Members: AEP Oklahoma Transmission Company, Inc Public Service Company of Oklahoma Southwestern Electric Power Company Transource Energy, LLC Transource Missouri, LLC Transource Oklahoma, LLC Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – Participated and lead specific development, design, implementation, construction, operation and maintenance of power system facilities over 40 year career. Many technologies in application of design experience. Electric Transmission Project Management and Construction – Through planning and engineer work has engaged in project management functions and interfaced directly with construction management. Director of Transmission Planning for ERCOT and SPP. . Electric Transmission Operations – As a Transmission Planning director, it was my responsibility to specify the control algorithms that managed real and reactive power flow. Working closely with operations, control schemes were developed to perform routine operations, thereby releasing dispatchers from the duties that could be automated and allowing them to focus on reliability. Such schemes were implemented for phase-shift transformers, a 4MW battery system, and several static Var compensation systems Electric Transmission Rate Design and Analysis – My experience covers the development of rates, the allocation of transmission cost and the rate case support of rate base. While FERC rate making differs in application, the principles apply and the nature of rate base investment is similar. While managing Transmission Planning of ERCOT facilities, there were several instances where I engaged in rate making proceedings. Starting in 1994, I participated in the original proceedings to separate transmission from the vert ical utility, the associated rate development and cost allocation to ERCOT distribution utilities. Building a separate rate base

234 of 306

and deriving rates that would allocate cost appropriately were some of the issues I addressed. I personally proposed a rate methodology1 dubbed “Efficient Access Pricing” that I designed to allocate cost based on facility impact on transmission capacity. Electric Transmission Finance – None

Published: 1. P. Hassink and S. Jones, “Efficient access transmission pricing,” The Electricity Journal, vol. 9, pp. 56-60, November 1996. 2. S. Arabi, P. Kundur, P. Hassink, and D. Matthews, "Small signal stability of a large power system as affected by new generation additions," in Power Engineering Society Summer Meeting, 2000, pp.812-816. 3. P. Hassink et al., "Dynamic reactive compensation system for wind generation hub," in IEEE PES Power Systems Conference and Exposition, 2006, pp. 470-475. 4. P. Hassink, V. Beauregard, R. O'Keefe, E. Larsen and R. Bodo, "Second & future applications of stability enhancement in ERCOT with asynchronous interconnections," in IEEE Power Engineering Society General Meeting, 2007, pp. 1-7. 5. P. Hassink, P. E. Marken, R. O'Keefe and G. R. Trevino, "Improving power system dynamic performance in Laredo, TX," in IEEE/PES Transmission and Distribution Conference and Exposition, 2008, pp. 1-5. 6. P. E. Marken, J. J. Marczewski, R. D'Aquila, P. Hassink, J. H. Roedel and R. L. Bodo, "VFT - a smart transmission technology that is compatible with the existing and future grid," in IEEE/PES Power Systems Conference and Exposition, 2009, pp. 1-7. 7. A. Bostrom, P. Hassink, M. Thesing, M. Halonen and R. Grunbaum, "Voltage stabilization for wind generation integration in western Texas grid," in CIGRE/IEEE PES Joint Symposium Integration of Wide-Scale Renewable Resources Into the Power Delivery System, 2009, pp. 1-1. 8. D. Kidd and P. Hassink, "Transmission operator perspective of Sub-Synchronous Interaction," in PEST&D, 2012, pp. 1-3.


Registered Professional Engineer in the state of Texas (1987-present) Member, Institute of Electrical and Electronic Engineers (IEEE) Member, International Council on Large Electric Systems (CIGRE)

235 of 306

IEP Candidate

Name: John Olsen Education: (School, Years, Degree) University of Nebraska ’82-‘87 – BS in Electrical Engineering University of Phoenix ’08 – ’12 – Masters of Business Administration Employment History: (Company, Years, Position) Live Phase, LLC (’20 – ’present) – President Utilicast, Inc. (’21 – Present) – Consultant Evergy (’98 - ’20) – Sr. director, Large T&S Construction Affiliations: (Personal affiliations vs. Company affiliations) Past affiliations were with Evergy, which also included TranSource through the Evergy ownership arrangement, and the dissolved Westar Energy joint ventures with Berkshire. Does not have current affiliation with any SPP stakeholder, member, or QRP participant Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – None Electric Transmission Project Management and Construction – My team was responsible for putting together the project plans, budgeting for projects, securing contractors to do the field work, procurement of materials, secure real estate and easements for lines and substations, work with landowners, coordinate with internal and external engineering resources, help prepare filings for the state utility commission as required for higher voltage transmission projects, completing transmission line routing studies, and managing the overall construction budget. . Electric Transmission Operations – I provided the executive direction for our transmission operations. I am very familiar with the utility perspective regarding the importance of sound transmission operations, what it takes to repair a system after major events, and coordination efforts with interconnected utilities. I have a good overall knowledge of operations, but not have a working knowledge of the exact steps necessary to complete clearances, perform studies, or all NERC related processes. Electric Transmission Rate Design and Analysis – Most of my rate design experience is working with internal staff and outside consultants during the development of rates. While overseeing the marketing and generation team, we created a generation formula rate that was modeled after the transmission formula rate. I also worked closely with an outside consultant to help create a template for use in the SPP competitive transmission process. I was part of the team that reviewed our annual transmission formula rate template updates.

236 of 306

Electric Transmission Finance – Most of the financing for the utility was blended with the remainder of the utility’s financial needs. The transmission joint ventures evaluated various capital structures and risk adjustment strategies to determine how best to balance the desired returns for our owners while providing a favorable rate for customers. We worked with our corporate finance team to determine the appropriate corporate structures, financing plans, and debt issuance options. Published: None Other: (summary of other important items in application/resume)

Past chair of SPP MOPC, Schedule 1A TF, Member of SPP SPC Professional engineer emeritus in the State of Nebraska

237 of 306

IEP Candidate

Name: Heather Bailey Education: (School, Years, Degree) University of Texas – ’89-’91, MBA University of Houston – ’78 - ’79, Accounting Sam Houston State University – ’74-’77, BA, Marketing

Employment History: (Company, Years, Position) HBailey Group – ’19-‘Present President Wind Energy Transmission Texas LLC (WETT Holdings)

Board member – ’20 -‘ Present City of Austin – May 18 – December 18

Chief of Staff City of Boulder Colorado – ’12 – ‘18 Executive Director of Energy Strategy and Electric Utility Development – ’12 – ‘18 Navigant Consulting – ’06 – ‘12 Director – ’06 – ‘12 Lower Colorado River Authority (LCRA) – ’87 – ‘06

Executive Director Transmission Services Business management and Asset Development/Co-Chief Operating Officer – ’01 – ‘06

Affiliations: (Personal affiliations vs. Company affiliations) NextEra Energy is a former client pre-2012 City of Independence Mo is a current client not transmission related AEP was a former partner in Transmission Development while at LCRA during 2000-2006

Area(s) of Expertise: (summarize expertise for each area) Electric Transmission Engineering Design – While I am not an engineer, I oversaw engineering operations from a general policy and strategy perspective during my tenure at LCRA. I also advised clients on various engineering related transmission stra tegies. Electric Transmission Project Management and Construction – While executive director and COO of LCRA Transmission company, I oversaw the project management section of our operation. During my time we grew the organization from about $20,000 in projects a year to $100,000 plus in annual transmission projects. As a result, we adopted a formal project management protocol requiring every project manager to become PMP certified over time. We developed a formalized software tracking and reporting tool as well a regular structured reporting. I was responsible for reporting to our board of directors the status of our projects on a regular basis, as well as budget responsibility.

238 of 306

Electric Transmission Operations – While forming the transmission company for LCRA and ultimately becoming the Co-COO of the company I had high level oversight and understanding of transmission operations. I am not experienced in the detailed operations of a transmission system. My knowledge is more from a strategic and regulatory perspective.

Electric Transmission Rate Design and Analysis – While at LCRA, I oversaw the rate setting process and am intimately familiar with cost of service and ERCOT rate design processes. I also represented clients at the Texas PUC in regulatory and rate proceedings. Electric Transmission Finance – I have significant experience in transmission finance while working to establish LCRA’s transmission company. From restructuring debt to meeting with rating agencies to budget oversight. I was the deputy CFO for LCRA prior to being a COO. I am well versed and familiar with debt covenants, offering statements, and FERC accounting. As part of my responsibility of being an unaffiliated board member for WETT Holdings, I have become familiar with independent transmission company finance structures and regula tory requirements. Published: Prepared various presentations to rating agencies, trade organizations, boards of directors, city councils, elected officials and the public over the years and would be glad to provide samples if needed. Has guest lectured at the University of Colorado on public power, sustainability and policy. Other: (summary of other important items in application/resume) Member of Gulf Coast Power Association in Texas Texas PUC Manager of Regulatory Compliance developed the PUC’s first regulatory compliance audit program and testified in utility rate proceedings Certified Public Accountant, TX

239 of 306

IEP Candidate

Name: Paul Johnson Education: (School, Years, Degree) Purdue University ’71 - ‘75 – Bachelor of Science - Engineering Purdue University ’75 - ’79 – Masters of Science - Management

Employment History: (Company, Years, Position) American Electric Power (‘81 – ‘17) Managing Director Transmission Operations EASi Engineering (’18 – ‘present) Principle Engineer (part-time)

Affiliations: (Personal affiliations vs. Company affiliations) Employed with AEP for nearly 36 years, retired from AEP September 2017.


Electric Transmission Engineering Design – For more than 20 years of my 42 year professional career I held various positions (engineering and management) in Transmission Planning. During this time, I gained expertise in various elements of transmission engineering. These elements included project ‘scoping’, equipment selection, equipment maintenance requirements, and the performance requirements of protection and control systems. These are in addition to the more traditional planning functions of addressing load growth and contingency analysis. Electric Transmission Project Management and Construction – None

Electric Transmission Operations – For nearly 11 years, concluding with my retirement, I was Managing Director – Transmission Operations at American Electric Power. I was responsible for leading the transmission operations organization which included the AEP system control center, five transmission dispatch centers, transmission settlements, operations engineering, dispatcher/operator training and EMS/SCADA support for AEP’s 39,000 mile transmission system covering portions of 11 states. I was also responsible for the operations interface with the 3 RTOs.

Electric Transmission Rate Design and Analysis – None Electric Transmission Finance – None

240 of 306

Published: • Maximizing the Reactive Power Capability of AEP Generating Stations – American Power Conference – Chicago Illinois • Voltage Stability Enhancement Techniques used at AEP – Proceedings of EPRI/NERC Forum on Voltage Stability • Maximizing the Reactive Capability of Generating Stations at AEP – EEI – 179th Meeting - Electric System & Equipment Committee Other: (summary of other important items in application/resume)

Professional Engineer, OH Member of IEEE and NSPE My 42 year professional career has been in the power industry – nearly this entire time was in the electric transmission field. In the early years of my career, I was a Field Relay (P&C) Engineer. For over two decades I was in transmission planning at various levels, becoming Manager of System Performance Appraisal and Manager of Bulk Transmission Planning. For the concluding 11 years of my career I was Managing Director – Transmission Operations at American Electric Power. I was responsible for leading the transmission operations organization which included the AEP System Control Center, five Transmission Dispatch Centers, transmission settlements, operations engineering, and the EMS/SCADA suppor t for AEP’s 39,000 mile transmission system covering portions of 11 states. I was also responsible for the operations interface with the three RTOs.

241 of 306


SPP FINANCE COMMITTEESUSAN CERTOMA

242 of 306

2

REPORT AGENDA

Committee Membership

Actions Taken By Committee

Discussion Topics

243 of 306

3

COMMITTEE ROSTER

Susan Certoma Director Mike Wise GSEC

Julian Brix Director Sandra Bennett AEP

Darcy Ortiz Director Al Tamimi Sunflower

Sarah Stafford OGE Vacant TU Seat

Matt Pawlowski NextEra Tom Dunn SPP

244 of 306

4

ACTION ITEMS (RECOMMEND TO BOD)

• 2021 Financing• Issuance of $28MM in term notes to fund capital expenditures in 2021

and 2022.• Retirement of notes: $14MM in 2026, $8MM in 2027, $6MM in 2028• Utilize U.S. Bank as placement agent and place notes in the private

placement market.• Intention is to maintain scheduled principal and interest payments at

$35MM/year through 2025, then gradual reduction through 2030.

245 of 306

5


Forecast Using Existing Financing Facility Forecast Using Private Placement

246 of 306

6


Motion – Issuance of Term Notes

• Authorize the issuance of $28 million in senior unsecured term notes with scheduled principal retirements not occurring until 2026 and final maturities of 2028 or prior.

• The notes will be issued as a private placement, utilizing the services of USB as the sole placement agent.

• Authorize appropriate regulatory filings for the issuance of up to $28 million in senior unsecured term notes to be issued within 12 months of receiving regulatory approval.

• Authorize the SPP Finance Committee to oversee negotiation, final approval of terms and conditions, and authorizations to execute up to $28 million in senior unsecured term notes with final maturities of 2028 or prior.

• Authorize the SPP President and Chief Financial Officer to jointly execute notes and agreements for the issuance of up to $28 million of senior unsecured term notes with final maturities of 2028 or prior.

247 of 306

7


Motion – Extend Maturity of Revolving Line of Credit

• Authorize the extension of maturity date of $30 million revolving credit facility to October 2023 with all other terms and conditions remaining unchanged.

• Authorize appropriate regulatory filings for the extension of the maturity of the existing $30 million revolving credit facility to October 2023.

• Authorize the SPP President execute notes and agreements to effectuate the extension of the maturity date of the existing $30 million revolving credit facility to October 2023.

248 of 306

8

ACTION ITEMS (BOD CONSENT AGENDA)

• 2020 Financial Audit• Unmodified opinion• No material weaknesses, significant issues, or audit adjustments

• 2021 Benefit Plan Funding• Pension plan ABO and PBO exceed plan assets due to reduction in

discount rates• Plan remains actuarially funded, is not at risk• Contribute $5.1MM to pension, $0 to post-retirement healthcare

249 of 306

9

ACTION ITEMS (FORWARD TO RTWG)

• Credit Practices Working Group Recommendation• Clarify language in credit policy (attachment X to tariff) to include

congestion rights activities into definition of market exposure

250 of 306

10

DISCUSSION TOPICS

• Corporate Liability Insurance RenewalPremiums increased 23% over expiring (significant increase in cyber)Limits and coverages remained similar to expiringWinter weather in February had adverse impact on renewal

• Winter Weather Event

Staff briefing on the event and financial impacts

Committee reviewing draft outline of comprehensive review report

• Contract Services Financial Review

Looked at shared overhead which reduces schedule 1A251 of 306

THE END

11252 of 306


FINANCE COMMITTEE


April 27, 2021

2021 Private Placement



Susan Certoma Julian Brix Darcy Ortiz Sarah Stafford Matt Pawlowski Sandra Bennett Al Tamimi Mike Wise

SPP Director SPP Director SPP Director OG&E NextEra AEP Sunflower Golden Spread

Background

SPP’s term debt structure at the end of February 2021 was as follows:

All notes are unsecured except for the 2027 Sr. Notes, which are secured by a mortgage on SPP’s Maumelle, AR operations facility. SPP has a $30 million unsecured revolving line of credit maturing in October 2021. The revolving line currently has $0 advanced. Pricing of draws against the line of credit are variable based on LIBOR + 1.00%. SPP has an $80 million committed guidance line of credit to fund capital expenditures from a group of three commercial banks, this facility matures in October 2023. Draws under the guidance line are priced at LIBOR + 1.50% and are convertible into term notes at a rate fixed at the then existing 5 year U.S. Treasury rate plus 1.85% with a floor rate of 2.875%. As of March 1, 2021, SPP had $52 million available under the guidance facility.

SPP’s 2021-22 capital expenditure program identifies expenditures of $27.8 million which require funding. In an effort to minimize the expected increase in 2022 and 2023 schedule 1A administrative fee expense, SPP’s Finance Committee recommended extending the retirement of future term debt issuances to 2025 and beyond.

FundingIssuance Rate Original Current Year Lender Primary Purpose

2024 Sr. Notes ( C ) 3.55% $70 $23 2011 Insurance Integrated Marketplace2024 Sr. Notes ( D1 ) 3.00% $50 $16 2012 Insurance Integrated Marketplace2024 Sr. Notes ( D2 ) 3.25% $50 $19 2012 Insurance Capital expenditures2024 Sr. Notes (Region) 4.98% $33 $17 2014 Bank Capital expenditures/refinance2024 Sr. Notes (Arvest) 2.88% $11 $9 2020 Bank Capital expenditures2025 Sr. Notes (E1) 3.80% $37 $37 2014 Insurance Capital expenditures2025 Sr. Notes (Arvest) 2.88% $5 $5 2021 Bank Capital expenditures2025 Sr. Notes (Arvest) 2.88% $5 $3 2020 Bank RC West project2027 Sr. Notes 6.36% $5 $2 2007 Bank Maumelle Ops Center2042 Sr. Notes (A & B) 4.82% $65 $56 2010 Insurance Corporate Campus

Totals $331 $187

Balances ($MM)

253 of 306

Analysis

Term Debt Issuance

SPP staff unsuccessfully negotiated with the lenders providing the existing $80 million guidance line facility to commit to allowing capital expenditure draws during 2021 and 2022 to delay principal retirements to 2025 and beyond. The lenders were unable to provide that commitment but did offer a 1 year delay in principal retirements accompanied by an increase in interest rate and unused commitment fees.

SPP staff visited with private placement agents at both Bank of America Merrill Lynch (“BofAML”) and U.S. Bank (“USB”) about leading a placement of the delayed principal retirement notes preferred by SPP. Both indicated the offering in the private placement market should be fully subscribed and receive attractive fixed rate pricing off of the implied yield on a 6 year average life treasury note plus a credit spread of 90-100 basis points. Presently, the 6 year implied yield is just under 1.20%, so pricing today would be no worse than a 2.20% coupon.

SPP has used BofAML as its placement agent for all private placements dating back to 2010. SPP has no other business relationship with BofAML. The selection of BofAML at the time was based on their dominant position in the private placement market. USB is currently the #3 placement agent in domestic private placements in 2020 in terms of transaction size and number of transactions.

USB has been involved in over 375 transaction raising over $75 billion in financing for private placement customers since starting its private placement services in 2009. The senior members of the USB team have been lead managers in over 500 transactions and has over 50 years of aggregate experience in the private placement markets. USB has served as sole or joint lead in over 18 transactions for utility issuers since 2019 indicating strong experience representing utility issuers to the institutional market.

Execution of the private placement, following approval for the note issuance by the SPP board of directors and the Federal Energy Regulatory Commission, would be fairly quick. SPP can obtain a funding deferral of several months after the rate is set to help manage its cash flow and interest costs.

SPP is currently forecasting annual scheduled payments of principal and interest to peak at just over $40 million in 2023 and 2024 and then fall to just over $15 million in 2026 and remain relatively flat through 2030. Utilizing the flexibility inherent in the private placement market, SPP can manage its scheduled payments of principal and interest to remain at $35 million through 2025, then gradually decline through 2030. Proposed funding and repayment is as follows:

Funding September 2021 $28,000,000 Principal Retirement December 2026 -$14,000,000 Principal Retirement December 2027 -$8,000,000 Principal Retirement September 2028 -$6,000,000 The resulting schedule of all scheduled principal and interest payments is reflected in the graph below:

2020 Domestic League Table

Agent # of Deals Volume ($B)

BofAML 60 12.7$

JP Morgan 47 9.5$

USB 38 4.3$

Mitsubishi 23 3.5$

254 of 306

Revolving Line of Credit Renewal

SPP maintains a $30 million revolving credit facility with a commercial bank which is used to support liquidity needs and general corporate purposes. During 2020, average daily outstanding balances under the facility were $0.8 million with a high balance of $12 million and a low balance of $0. SPP uses an automatic sweep service with the bank to draw and repay as funds are needed or available, respectively.

SPP has negotiated with the commercial bank to extend the maturity to October 2023 while retaining all other terms and conditions.

Recommendation

1) Authorize the issuance of $28 million in senior unsecured term notes with scheduled principal retirements not occurring until 2026 and final maturities of 2028 or prior. The notes will be issued as a private placement, utilizing the services of USB as the sole placement agent. Authorize appropriate regulatory filings for the issuance of up to $28 million in senior unsecured term notes to be issued within 12 months of receiving regulatory approval. Authorize the SPP Finance Committee to oversee negotiation, final approval of terms and conditions, and authorizations to execute up to $28 million in senior unsecured term notes with final maturities of 2028 or prior. Authorize the SPP President and Chief Financial Officer to jointly execute notes and agreements for the issuance of up to $28 million of senior unsecured term notes with final maturities of 2028 or prior.

2) Authorize the extension of maturity date of $30 million revolving credit facility to October 2023 with all other terms and conditions remaining unchanged. Authorize appropriate regulatory filings for the extension of the maturity of the existing $30 million revolving credit facility to October 2023. Authorize the SPP President execute notes and agreements to effectuate the extension of the maturity date of the existing $30 million revolving credit facility to October 2023.



255 of 306

256 of 306


HRC REPORTMARK CRISSON

APRIL 27, 2021

257 of 306

2

HR COMMITTEE MEMBERS

• Bronwen Bastone, SPP Board of Directors

• Scott Briggs, OGE Energy

• Mark Crisson (Chair), SPP Board of Directors

• Suzanne Lane, KEPCo

• Joe Lang, OPPD

• Stuart Lowry, Sunflower Electric

• Liz Moore, SPP Board of Directors

• Maria Smedley, Arkansas Electric Cooperative

• Noman Williams, GridLiance High Plains

258 of 306


AFFIRMATIVE ACTION PLAN

259 of 306

4


•Required of All Government Contractors•Required Goals/Targets for Two Categories

• Females• Minorities

•Required Metrics for Two Categories• Protected Veterans• Disabilities

260 of 306

5

KEY AFFIRMATIVE ACTION EFFORTS

• Recruiting at Minority Colleges and Universities• Tennessee State• University of Arkansas at Pine Bluff• Philander Smith

• Women in Power

• Engineering Career Awareness Program

• Hiring Our Heroes Initiative

• Job Posting Outreach• utilityjobs.com – outreach to female/minority job boards• workplacediversity.com – outreach to minority, veteran, and disabled worker

websites• Arkansas Department of Workforce Services website

• Management Training/Awareness

• SPP DEI Initiative 261 of 306

6


• Two Distinct Plans: Corporate Office and Operations and Data Center

• Targets Reestablished Annually: Female and Minorities• Availability Analysis for Geographic Region

• Total of 50 Potential Targets• 15 Job Groups at Corporate Campus (30 potential targets)• 10 Job Groups at ODC (20 potential targets)

• Annual Analysis• Jackson-Lewis Law Firm• HR Management System Database

• Applicant Pool• Promotions• Compensation• Workforce Demographics

262 of 306

7

2020-20212 Goals

9.52%

5.26%

263 of 306

8

2020-20210 Goals

264 of 306

9

RESULTS: 2013 - 2021

9 98

6

3

1 1

56

54

1 1 1

1415

13

10

4

2 2

0123456789

10111213141516

2015 2016 2017 2018 2019 2020 2021

Targets by Category

Female Minority Combined Total

265 of 306


PERFORMANCE COMPENSATIONPROCESS AND DISTRIBUTION REVIEW

266 of 306

11

PROCESS OVERVIEW

1) SPP staff prepares results for HRC2) HRC makes recommends funding to BOD3) Board approves funding ($12,963,830 awarded for 2020)4) SPP management assesses individual performance and

provides rating for each employee (Scale = 0 -10)5) Ratings are calibrated at Organizational Unit level6) Org Unit individual ratings are reviewed with CEO/COO7) Officer team calibrates ratings at corporate level8) Officer team informs management of final calibrated ratings9) Management informs staff of individual payout

267 of 306


HR METRICSAPRIL 1, 2021

268 of 306

13

HR METRICS SNAPSHOT 4.1.2021

A

ActualHeadcount

637627

F

ForecastHeadcount

653656

AverageAge4444

AverageYears of Service

9.28.7

Mgmt to Staff Ratio1:6.21:6.1

VacancyRate

2.45%4.86%

TurnoverRate3.47%4.24%

SeparationsYTD59

PromotionsYTD1524

Internal TransfersYTD

420

Open RequisitionsYTD 1632

Requisitions FilledYTD 1136

New EmployeesYTD

716

Current Year-top numberLast Year-lower number

269 of 306


DEI TASK FORCE UPDATELIZ MOORE

270 of 306


SPP BENEFITS REVIEW

271 of 306

16

KEY EMPLOYEE ELECTIVE BENEFITS

•401(k) Plan•96% Participation•Average Deferral = 8%

•Medical Plans•2020 claims cost per employee/month down 5%

• Increase in participation in HSA plan•Dental Plans

•Average savings 50k

272 of 306

17

EXECUTIVE SESSION DISCUSSION

• Updated the annual performance evaluation timeline for CEO

• Finalized HRC recommendation for CEO base salary for 2021

273 of 306


QUESTIONS ?

274 of 306

SOUTHWEST POWER POOL, INC. Strategic Planning Committee


04/27/2021 Recommendation for approval of SPP Mission, Vision, and Value Proposition


Members of the Strategic Planning Committee are:

• Larry Altenbaumer, Board, Chair • Mark Crisson, Board, Vice Chair • Bruce Rew, SPP, Secretary • Barbara Sugg, SPP • Susan Certoma, Board • Andrew Lachowsky, AECC, TU • Bill Grant, SPS, TO • Tom Christensen, Basin, TO

• David Mindham, EDP, TU • Kevin Noblett, Evergy, TO • Richard Ross, AEP, TO • Melie Vincent, OMPA, TU • Ray Wahle, Missouri River, TU • Mike Wise, Golden Spread, TU • Traci Bender, NPPD, TO

BACKGROUND

Last year the Strategic Planning Committee (SPC) initiated the development of a new Strategic Plan for SPP. The SPC engaged Strategic Offsites Group to facilitate the development process. The initial schedule targeted a new Strategic Plan completion during the April 2021 Board meeting. To allow for greater focus on the winter event, the SPC has delayed completion of the Strategic Plan until the summer of 2021. During the past year, great progress has been made on the development of the new SPP Strategic Plan. This development process included several SPC special sessions focused on Strategic Plan initiatives for the organization. Additional sessions were held with the SPP Board of Directors, Members Committee, and Regional State Committee. A key part of this effort was updating the SPP Mission, developing an SPP Vision, and reviewing the SPP Value Proposition. The process has led to the development of a new Mission, Vision, and Value Proposition. These three key aspects to the Strategic Plan have been vetted with the supporting organizational groups. While the entire Strategic Plan is not completed at this time, the Mission, Vision and Value Proposition have been approved by the SPC. The SPC requests Board approval at this time to begin setting the organizational direction in anticipation of the completed Strategic Plan later this year. The following graphic displays the approved versions.

275 of 306

RECOMMENDATION

The Strategic Planning Committee requests the Board of Directors approve the recommendation to accept the new SPP Mission, Vision, and Value Proposition.

Approved: Strategic Planning Committee 04/14/2021

Approved, unanimously

276 of 306


SPP: STRATEGIC PLANNING COMMITTEEQUARTERLY REPORT

APRIL 27, 2021

277 of 306

2

Larry Altenbaumer, Chair – SPP Board Mark Crisson, Vice Chair Traci Bender – Nebraska Public Power District Susan Certoma – SPP Board Tom Christensen – Basin Electric Power Cooperative Bill Grant – Southwestern Public Service / Xcel Energy Andrew Lachowsky – Arkansas Electric Power Cooperative

Corporation David Mindham – EDP Renewables Kevin Noblet – Evergy Companies C. Richard Ross – American Electric Power / Southwestern

Electric Power Barbara Sugg – SPP President Melie Vincent – Oklahoma Municipal Power Authority Ray Wahle – Missouri River Energy Services Mike Wise – Golden Spread Electric Cooperative Bruce Rew – Staff Secretary

Announced retirement of Ray Wahle

Strategic Planning Committee – Committee Members

278 of 306

3

Strategic Planning Committee – Agenda

High-Level Agenda Review

Strategic Plan Development Update

Strategic Planning Committee Development

Transmission Owner Selection Process Review

HITT

2023 ITP Update

SPP West New Member Process

Note:

Other items on the agenda have been addressed during the Joint Quarterly Stakeholder Meeting

279 of 306

4

Strategic Planning Committee – Strategic Plan Development

Strategic Questions to Address

1. How does SPP approach strategy?• Common vocabulary, framework, and

process for strategy conversations

2. What is going on externally and internally?

• Major trends and potential implications• Strategic questions and considerations• Core capabilities and assets

3. Where does SPP want to be in five years?

• Mission, vision, and value proposition• Five-year definition of success, including

how success should be measured

5. What progress is SPP making?• Tracking and reporting mechanism• Management cadence

6. How do we communicate the strategy?

• High-level communication plan (i.e., audiences, key messages, channels, mechanisms, etc.)

4. What is SPP’s strategic game plan?• Strategic opportunities and enablers to

pursue• Detailed recommendations• Evaluation, prioritization, and sequencing• High-level resource (re)allocation

280 of 306

5©2021 The Strategic Offsites Group, Inc. All rights reserved. Proprietary and Confidential.

Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021

RSC, Board, MC Meetings SPC Meeting

High-Level Project Timeline (Through Winter Event)

I. External & Internal Analysis II. Strategy Identification & Prioritization

III. Strategy Definition & Assessment

IV. Final Strategy & Path Forward

Boar

d,M

C, R

SCSP

CO

ppor

tuni

ty/

Enab

ler T

eam

s

4/27-28 10/26-27 1/26 4/26-27

Refine strategy

Develop opportunity/enablerrecommendations

September 24-25 Retreat

January 13 April 14October 14-15

Profile opportunities and enablers

Data gathering

July 14

Kickoff (4/15)

4/27-5/22

August 27

Completed

7/27-28

December 8

POLAR VORTEX

281 of 306

©2021 The Strategic Offsites Group, Inc. All rights reserved. Proprietary and Confidential. 6

2025 Aspirations

Achieve seamless boundaries

SPP’s In-Process Strategy-on-a-Page

Attain high-quality decisions through an efficient,

collaborative stakeholder process

Deliver greater and more equitable value to members

Attract, develop, and retain an exceptional, diverse, and

inclusive workforce

MissionWorking together to responsibly and economically keep

the lights on today and in the future

Achieve excellence and unmatched execution in all we do

VisionLeading our industry to a brighter future while

delivering the best energy value

Value Proposition

Achieve collaboratively and engage passionately Embrace and promote diversityBuild and maintain trusted relationships

Drive value beyond reliabilityDeliver superior services

Enabling CapabilitiesSustaining, Enhancing, and Communicating Member Value

Strengthen the Core Change the Game

Implementing HITT Recommendations

Eastern Seams Strategy

Western Expansion Strategy

Transmission Planning Strategy

Strategic Opportunities

Grid of the FutureSupport Regional

Economic Development

Adaptive SPP Governance Model

Diversity, Equity, and InclusionOrganizational ReadinessTechnology

PRELIMINARY

282 of 306

7

Solicit an additional round of feedback on opportunities and enablers, incorporating the winter event where appropriate (targeting a June 22)

Finalize 2024 measures of success

Package the strategy for communication to various audiences through appropriate channels

Begin to develop more detailed action plans (e.g., milestones, dependencies, etc.) and further prioritize and sequence opportunities and enablers

Define the role of the SPC and other key groups in advancing, monitoring, and executing the strategy

Establish tracking and reporting cadence, including regular strategy reviews to ensure the plan is dynamic

Provide and walk-through a near-final package of materials for the July series of meetings

Seek approval of the plan from the Strategic Planning Committee and the Board and Members Committee by August 24

Conduct a Strategic Advance and Roll-out on September 16 – 17 (in Dallas)

Strategic Planning Committee – Strategic Plan Development

283 of 306

8©2021 The Strategic Offsites Group, Inc. All rights reserved. Proprietary and Confidential.

Execution, tracking, and reporting

Implementation and communication planning

Refine strategy

Q1 2021 Q2 2021 Q3 2021 Q4 2021

RSC, Board, MC Meetings

SPC Meeting

High-Level Project Timeline (Updated Post-Winter Event)

III. Strategy Definition & Assessment

IV. Final Strategy & Path Forward

Boar

d,M

C, R

SCSP

CO

ppor

tuni

ty/

Enab

ler T

eam

s

Completed

1/26 4/26-27

Develop opportunity/enablerrecommendations

January 13 April 14

June 22 (TBD)Strategy Workshop

August TBD

8/24

September 15-17Retreat

October 13July 14

7/26-27

To be scheduled

PRELIMINARY

Targeted for recommendation and approval

284 of 306

©2021 The Strategic Offsites Group, Inc. All rights reserved. Proprietary and Confidential. 9

Mission, Vision, and Value Proposition

MissionWorking together to responsibly and economically

keep the lights on today and in the future

VisionLeading our industry to a brighter future

while delivering the best energy value

Value Proposition

Achieve collaboratively and engage passionately Embrace and promote diversityBuild and maintain

trusted relationships

Drive value beyond reliabilityDeliver superior services

The Strategic Planning Committee requests Board of Directors approve the recommendation to accept the new SPP Mission, Vision and Value Proposition.

Approved unanimously by the Strategic Planning Committee

285 of 306

10

Strategic Planning Committee Discussion Topics• Assessment of the current strategic planning process• Discussion of the future roles • Addressing the differences in the roles of the Strategic

Planning Committee and the Members Committee• Usefulness of Education Sessions • Understanding prior stakeholder survey results related to

strategic planning• Structure and size of the SPC

Strategic Planning Committee – Committee Development

286 of 306

11

STRATEGIC PLANNING COMMITTEEHands-on driver of the overall plan implementation

Members CommitteeExecutive-level engagement

Informed Provide policy

guidance, advice, direction

Diversity of views Prioritization

perspectives

Staff

Subject matter expertise

Objective thought leaders

Independent perspective

Effective facilitation Well-developed initial

strategy constructs

Board

Independence Well-informed and

engaged Organizational

accountability Ultimate decision-

maker

Prioritization Guidance Education Monitoring

Implementation plans Initiative development Interdependencies coordination

PRIMARY ROLES and RESPONSIBILITIES

287 of 306

12

Strategic Planning Committee – Agenda

High-Level Agenda Review

Transmission Owner Selection Process Review

HITT

2023 ITP Update

SPP West New Member Process

Note:

Other items on the agenda have been addressed during the Joint Quarterly Stakeholder Meeting

288 of 306

13

Strategic Planning Committee

289 of 306


MOPC REPORT TO BOARDAPRIL 27, 2021DENISE BUFFINGTON, MOPC CHAIR

290 of 306

2

VOTES @ APRIL MOPC

Motion Consensus Approval

Approve consent agenda with the removal of RR 430 100% PASS

Waive the requirements in the ITP Manual to build and assess the market powerflow models during the 2021 ITP Reliability Needs Assessment, and approve 2021 ITP Scope modification to allow schedule adjustments within the 2021 ITP.

100% PASS

Waive the economic and policy requirements from the 2023 ITP, and approve moving 2023 ITP scope development start from July 2021 to January 2022. 65% FAIL

87% average consensus

291 of 306

3

REVISION REQUEST APPROVED IN APRIL

TariffBusiness Practices

ITP Manual

Market Protocols

Vendor Cost

Staff Hours

ESWG RR448 - Removing renewable portfolio standards table from ITP and replacing in scope

X None None

MWG RR441 - Ramp capability products settlements protocol corrections X None NoneMWG RR442 - Desired dispatch settlement definitions alignment X None NoneMWG RR444 - Order 841 electric storage resources additional settlements protocol

correction and clarificationX

None None

MWG RR445 - SPP holidays definition update and clean-up X X None NoneORWG RR443 - Resource retirement business practice clarification X None NoneTWG RR435 - Change assignment threshold for ERIS in the generation

interconnection study process (SPP BP7250)X None None

RTWG RR437 - Surplus interconnection service timing clarification X None NoneRTWG RR447 - Point-to-point megawatt-mile enhancement X None None

Primary Working Group Title

Impacted Document Estimated Cost

292 of 306

4

MOPC INITIATIVES

• Seeking board feedback on:• 2021 ITP mitigation plan

• Operations path discussing winter storm recommendations for July board report• SAWG, MWG, ORWG, TWG

• Held diversity panels with seven member representatives from different sectors

293 of 306

5

POST-MOPC SURVEYCONTINUOUS IMPROVEMENT

• Respondents found it helpful that agenda and materials were posted early

• Of 40 respondents, 80% found meeting effective or very effective

1

7

23

9

Not effective Somewhat effective Effective Very effective294 of 306

6

DENISE BUFFINGTONDirector of Federal Regulatory Affairs Evergy Companies

295 of 306

From: Lang, Joe <[email protected]> Sent: Friday, April 23, 2021 4:25 PM To: Paul Suskie <[email protected]> Cc: Casey Cathey <[email protected]>; Antoine Lucas <[email protected]>; Haner, Luke <[email protected]> Subject: **External Email** MOPC Vote Appeal Hi, Paul. Hope all is well sir! I am writing you to invoke Section 3.10 of the SPP Bylaws to appeal the MOPC vote of roughly 65/35 in April that denied SPP’s recommendation of the 2021 ITP mitigation plan and removal of the economic needs assessment from the 2023 ITP (MOPC Agenda Item No. 6). The outcome of the vote was too close for the SPP Board to be denied the opportunity to consider SPP’s recommendation on this important matter. I look forward to SPP’s presentation and Board discussion to ensure an appropriate outcome. Thank you, Joe Joseph E. Lang | Director - Energy Regulatory Affairs Omaha Public Power District 444 S. 16th St Mall, Omaha, NE 68102-2247 Office: 531-226-1042 Cell: 402-981-8811

296 of 306


ITP

2020 ITP BUTLER-TIOGA 138 KV RE-EVALUATIONANTOINE LUCAS

APRIL 2021

297 of 306

2

BACKGROUND

Jan. 26 2021

• The SPP Board of Directors approved the construction of the Butler-Tioga 138 kV project in southeast Kansas as part of the 2020 Integrated Transmission Planning (ITP) Assessment

Feb. 2 2021

• SPP issued a Request For Proposal (“RFP”) (SPP-RFP-000004 Butler-Tioga) for the Competitive Upgrade

Feb. 26 2021

• SPP issued Notification to Construct (NTC) 210602 for the Butler and Tioga substation upgrades necessary to accommodate the new line

Feb. 5 2021

• Evergy submitted a request for SPP to perform a re-evaluation of the Butler –Tioga 138 kV project• ascertain whether the project still meets the appropriate cost benefit thresholds• adequately resolves the needs of the region

Mar. 2 2021

• The SPP Board of Directors approved SPP’s recommendation for re-evaluation of the Butler-Tioga 138 kV project

298 of 306

3

RE-EVALUATION ANALYSIS

• Modified version of the 2020 ITP Economic Models were used

• Study procedures were consistent with those used in the 2020 ITP Assessment along with two types of new information:1. Material change to modeling assumptionsEvergy identified local planning projects in their submitted in MOD for the 2021 model sets

with expected completion date of December 2022: • MOD Project ID 95913- a rebuild of approximately 35 miles of the existing Butler-Altoona 138 kV line

out of the Butler substation to a new Otter Creek substation.• MOD Project ID 95925- an approximately 13 mile greenfield 115 kV line from Otter Creek to the existing

East Eureka substation.Other new modeling information was considered and deemed to be not impactful to the re-

evaluation of the Butler-Tioga 138 kV project.

2. New Project cost received was considered

299 of 306

4

ANALYSIS RESULTS2020 ITP Butler-Altoona 138 kV Path Congestion Scores

Model ConstraintMinimum Congestion Score

($K)Maximum Congestion

Score ($K)2020 ITP Base Butler-Altoona 138 kV $472 $1,105

2020 ITP Modified Otter Creek-Altoona 138 kV $1,353 $2,802

ProjectNO*

AssumptionE&C Cost

($M)

F1 40Y Benefit

($M)

F2 40Y Benefit

($M)

40Y NPV Cost ($M)

F1 40Y B/C

F2 40Y B/C

Butler-Tioga 138 kV O-A $121.3 $912.5 $1,323 $213.2 4.3 6.2Butler-Tioga 138 kV O-E, O-A $121.3 $887.1 $1,297 $213.2 4.2 6.1Butler-Tioga 138 kV None $121.3 $427.8 $575.2 $213.2 2.0 2.7Butler-Tioga 138 kV O-E $121.3 $564.2 $783.8 $213.2 2.7 3.7

*Normally Open line assumptions:•O-A: Otter Creek-Altoona 138 kV•O-E: Otter Creek-East Eureka 138 kV•None: No normally open line assumptions

Butler-Tioga 138 kV Costs and Economic Performance

300 of 306

5

CONCLUSION

Butler-Tioga 138 kV project still meets the required benefit-to-cost ratios specified in the ITP manual• rebuilding 35 miles of the original Butler-Altoona 138 kV 70.1-mile line to a new substation named Otter

Creek• does not address the remaining 35.1-mile transmission path to the Altoona 138 kV substation• increases system congestion in the same corridor that supports SPP bulk system transfers

Congestion Remains through Altoona138 KV Substation• Butler-Tioga 138 kV project may not be the most cost-effective project

• 35 miles of the existing corridor is being rebuilt by the local transmission owner• duplicating 35 miles with a new line along the same electrical path is redundant and may be costly to

the region as a whole• less costly, transmission upgrade options that consider the Locally Planned Transmission Change

should be evaluated within the ITP process

301 of 306

6

RECOMMENDATION

SPP Staff recommends that the Board withdraw the Butler-Tioga 138 kV project, which includes the new 138 kV line between the existing Butler substation and the existing Tioga substation in Kansas as well as the associated substation upgrades included in NTC 210602.

302 of 306


RECOMMENDATION TO THE BOARD OF DIRECTORS

April 27, 2021 2020 ITP Butler-Tioga 138 kV Re-evaluation Report


SPP Staff


On January 26, 2021, SPP Board of Directors approved the construction of the Butler-Tioga 138kV project in southeast Kansas as part of the 2020 Integrated Transmission Planning (ITP) Assessment. The Butler-Tioga 138 kV project consists of a new 138 kV line between the existing Butler substation and the existing Tioga substation and the upgrades at the Butler and Tioga substations necessary to accommodate the new line. The new 138 kV line between the Butler and Tioga substations met the requirements to be a Competitive Upgrade in Section I of Attachment Y of the Tariff. On February 2, 2021 SPP issued a Request For Proposal (“RFP”) (SPP-RFP-000004 Butler-Tioga) for the Competitive Upgrade in accordance with Section III of Attachment Y of the SPP Tariff. On February 26, 2021, SPP issued Notification to Construct (NTC) 210602 for the Butler and Tioga substation upgrades necessary to accommodate the new line.

On February 5, 2021, Evergy submitted a request for SPP to perform a re-evaluation of the Butler –Tioga 138kV project pursuant to Section VIII of Attachment Y of the SPP Tariff. Evergy stated in their request that the scope of the Butler-Tioga 138 kV project represented a significant and substantive scope change and the project no longer aligned with the 2020 ITP Assessment. Evergy also identified in the request two Evergy local planning projects that are currently under construction that may overlap with the Butler-Tioga 138 kV project. Evergy requested the re-evaluation to ascertain whether the project still meets the appropriate cost benefit thresholds and adequately resolves the needs of the region, based on relevant cost estimates and the operational considerations related to a 100% greenfield project and the Evergy local planning projects already underway in that area.

On March 2, 2021, SPP presented to the SPP Board of Directors its determination that the Evergy request includes revised parameters and values that constitute a material change to the parameters and criteria used in a portion of the analysis for the 2020 ITP Assessment. The SPP Board of Directors approved SPP’s recommendation for re-evaluation of the Butler-Tioga 138kV project. The SPP Board of Directors also approved SPP’s recommendation for suspension of the

303 of 306

TOSP for SPP-RFP-000004 and associated NTC 210602 for the required non-competitive portions of the Butler-Tioga 138kV project.

RE-EVALUATION ANALYSIS

SPP used a modified version of the 2020 ITP Economic Models in the re-evaluation. The re-evaluation used the study procedures consistent with those used in the 2020 ITP Assessment and the current ITP Manual. SPP considered two types of new information to perform this re-evaluation: 1) the material changes to modeling assumptions and 2) project costs. First, in the request for re-evaluation, Evergy identified two local planning projects in their submission into the SPP Model On Demand (MOD) tool for inclusion in the 2021 model sets. These local planning projects were also submitted as Planned Transmission System Change information on September 1, 2020. The two projects are identified as:

1. MOD Project ID 95913- a rebuild of approximately 35 miles of the existing Butler-Altoona 138kV line out of the Butler substation to a new Otter Creek substation.

2. MOD Project ID 95925- an approximately 13 mile greenfield 115kV line from Otter Creek to the existing East Eureka substation.

In the request for re-evaluation, Evergy also provided notice of an expected completion date of December 2022 for these projects. SPP deemed these projects to be a material change to the system. The projects were included in the 2020 ITP Economic Models as changes in the system for the purpose of evaluating the Butler-Tioga project. Other new modeling information was considered and deemed to be not impactful to the re-evaluation of the Butler-Tioga 138 kV project. Second, SPP considered new or updated project costs received since the SPP Board of Directors approval of the 2020 ITP Assessment for projects impacting this re-evaluation.

ANALYSIS RESULTS

The analysis tested the system performance of the Butler-Tioga 138 kV project incremental to the final 2020 ITP portfolio, including the Evergy Planned Transmission System Changes mentioned above. These model adjustments shifted, and significantly increased, the system congestion to the remaining portion of the original Butler-Altoona 138 kV line that was not upgraded. System congestion scores are shown in Table 1.

304 of 306

Model Constraint

Minimum Congestion Score

($K)

Maximum Congestion Score

($K) 2020 ITP Base Butler-Altoona 138 kV $472 $1,105 2020 ITP Modified Otter Creek-Altoona 138 kV $1,353 $2,802

Table 1: 2020 ITP Butler-Altoona 138 kV Path Congestion Scores

Consistent with the project scope recommendation from the 2020 ITP, which included normally open (NO) operation of the existing Butler-Altoona 138 kV facility, the analysis included various NO line assumptions modified for the impact of the Planned Transmission System Changes. The results of this analysis are shown in Table 2.

Project NO1

Assumption E&C Cost

($M)

F1 40Y Benefit

($M)

F2 40Y Benefit

($M)

40Y NPV Cost ($M)

F1 40Y B/C

F2 40Y B/C

Butler-Tioga 138 kV O-A $121.3 $912.5 $1,323 $213.2 4.3 6.2 Butler-Tioga 138 kV O-E, O-A $121.3 $887.1 $1,297 $213.2 4.2 6.1

Butler-Tioga 138 kV None $121.3 $427.8 $575.2 $213.2 2.0 2.7

Butler-Tioga 138 kV O-E $121.3 $564.2 $783.8 $213.2 2.7 3.7

Table 2: Butler-Tioga 138 kV Costs and Economic Performance

These re-evaluation results show that the Butler-Tioga 138 kV project still meets the required benefit-to-cost ratios specified in the ITP manual. This is expected, due to the fact that the Evergy Planned Transmission System Change constitutes rebuilding 35 miles of the original Butler-Altoona 138 kV 70.1-mile line to a new substation named Otter Creek, but does not address the remaining 35.1-mile transmission path to the Altoona 138 kV substation, which increases system congestion in the same corridor that supports SPP bulk system transfers.

While the need to address the system congestion through the Altoona 138 kV substation remains, the Butler-Tioga 138 kV project may not be the most cost-effective project to do so. Given that 35 miles of the existing corridor is being rebuilt by the local transmission owner, duplicating that 35 miles with a new line along the same electrical path is redundant and costly to the region as a whole. Other, less costly, transmission upgrade options that consider the Local Planned Transmission Change should be evaluated for the most optimal solution to address congestion in the transmission corridor.

1 Normally Open line assumptions: • O-A: Otter Creek-Altoona 138 kV • O-E: Otter Creek-East Eureka 138 kV • None: No normally open line assumptions

305 of 306

RECOMMENDATION

SPP Staff recommends that the Board withdraw the Butler-Tioga 138 kV project, which includes the new 138 kV line between the existing Butler substation and the existing Tioga substation in Kansas that is subject to SPP-RFP-000004, as well as the associated substation upgrades included in NTC 210602. If the Board approves this recommendation, SPP will withdraw SPP-RFP-000004 in accordance with Section VIII of Attachment Y of the Tariff.


Approvals: N/A

306 of 306

board of directors/members committee meeting - Southwest ...

Documents

Transcript of board of directors/members committee meeting - Southwest ...