SUMMARY OF MOTIONS AND ACTION ITEMS

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SOUTHWEST POWER POOL ECONOMIC STUDIES WORKING GROUP MEETING

December 3-4, 2020 Net Conference

SUMMARY OF MOTIONS AND ACTION ITEMS General:

• Approved RR 417: Clarify no NTC issued from 20-year assessment • Approved the TX1 white paper with TWG modifications

2021 ITP:

• Approved Bakken as a target area • Approved SPS-New Mexico as a target area

2022 ITP:

• Approved the electric demand growth assumptions • Approved not to accept the High Banks Wind resource addition request • Approved to accept the Rockhaven Wind resource addition request • Approved staff’s recommendation for a waiver of the ITP manual for the 2022 ITP

requiring the use of resource expansion software

20-Year Assessment: • Approved to adopt 4th future based on SPP F3 with hurdle rate of 0 between MISO and

SPP Action Items:

• Added action item to review pulling the RPS table out of the ITP Manual

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SOUTHWEST POWER POOL ECONOMIC STUDIES WORKING GROUP MEETING

December 3-4, 2020 Net conference

MINUTES

AGENDA ITEM 1 – ADMINISTRATIVE ITEMS

Economic Studies Working Group (ESWG) Chair Alan Myers called the meeting to order at 8:00 a.m. The following members were in attendance or represented by proxy:

Al Tamimi, SUNC Alan Myers, ITC Anita Sharma, AEP Bennie Weeks, SPS Calvin Daniels, WFEC Derek Brown, Evergy Gayle Nansel, WAPA Jeremy Severson, BEPC Jody Holland, GridLiance Kurt Stradley, LES Kyle McKinney, GSEC Michael Watt, OMPA Randy Collier, CUS Steve Gaw, APA Steve Hohman, OPPD Tim Owens, NPPD Zac Hager, OGE Proxies: Joe Dan Wilson for Kyle McKinney on 12/4 (Attachment 1 – Attendance) (Attachment 2 – Proxy) Joshua Norton confirmed there was a quorum and provided the antitrust statement. Alan Myers reviewed the agenda for any changes. (Attachment 3 – Agenda)

Tim Owens made a motion, seconded by Kurt Stradley to approve the agenda. The motion was approved unanimously.

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AGENDA ITEM 2 – CONSENT AGENDA

The consent agenda included the following items:

RR 417: Clarify no NTC issued from 20-year assessment (Attachment 4 – RR 417

Recommendation Report) (Attachment 5 – RR417 – 20 Year Assessment No NTC

presentation)

The consent agenda was approved.

AGENDA ITEM 3A – ESR TASK TEAM REPORTS: TX1 WHITE PAPER

Scott Benson and Josh Pilgrim presented the TX1 white paper with TWG-requested revisions to include local TO load profile data. (Attachment 6 – TX1 White Paper Redline) (Attachment 7 – TX1 White Paper presentation)

Kurt Stradley made the motion, seconded by Zac Hager, to approve the TX1 white paper with TWG modifications. The motion was approved unanimously.

AGENDA ITEM 3B – ESR TASK TEAM REPORTS: E1 UPDATE

Al Tamimi gave an update for the E1 task team. (Attachment 8 – E1 White Paper Summary)

AGENDA ITEM 4A – 2021 ITP SCHEDULE UPDATE

Dara Solomon reviewed the 2021 ITP schedule. (Attachment 9 – 2021 ITP Schedule)

AGENDA ITEM 4B – 2021 ITP TARGET AREA DISCUSSION

Josh Pilgrim and Liz Gephardt presented target areas for the 2021 ITP assessment. They reviewed the Bakken and SPS-New Mexico as recommendations for target areas. There was discussion about the two additional SVCs required in models. (Attachment 10 – 2021 Target Area)

Jeremy Severson made the motion, seconded by Gayle Nansel, to approve Bakken as a target area in the 2021 ITP assessment. The motion was approved unanimously.

Jeremy Severson made the motion, seconded by Bennie Weeks, to approve SPS-New Mexico as a target area in the 2021 ITP assessment. The motion was approved with one vote against (Jody Holland) and three abstentions: Zac Hager, Al Tamimi, and Kyle McKinney.

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AGENDA ITEM 5A – 2022 ITP SCHEDULE UPDATE

Dara Solomon reviewed the 2022 ITP schedule. (Attachment 11 – 2022 ITP Schedule)

AGENDA ITEM 5B – 2022 ITP ELECTRIC VEHICLE DEMAND GROWTH

Jake Pannell reviewed the electric vehicle energy demand growth calculation process. (Attachment 12 – 2022 ITP EV Demand Growth)

Zac Hager made the motion, seconded by Jeremy Severson, to approve the electric demand growth assumptions for use in the 2022 ITP assessment. The motion was approved unanimously.

AGENDA ITEM 5C – 2022 ITP DRAFT SCOPE REVIEW

Adam Bell reviewed the draft scope. (Attachment 13 – Draft Scope)

AGENDA ITEM 5D – 2022 ITP RENEWABLE POLICY REVIEW/RESOURCE PLAN – PHASE 1

Krishada Watson gave an overview of the Renewable Policy Review and Resource Plan Phase 1 milestones. (Attachment 14 – Renewable Policy Review) (Attachment 15 – Resource Plan Phase 1)

Tim Owens made the motion, seconded by Kurt Stradley, to add an action item to review pulling the RPS table out of the ITP Manual. The motion was approved unanimously.

Action Item: Review pulling the RPS table out of the ITP Manual

AGENDA ITEM 5E – 2022 ITP LOAD & GENERATION REVIEW

Brooke Keene gave an update on the Load and Generation Review. (Attachment 16 – Load & Generation Review)

AGENDA ITEM 5F – 2022 ITP RESOURCE ADDITION REQUESTS

Derek Johnson presented a resource addition request for High Banks Wind. (Attachment 17 – High Banks RAR)

Jeremy Severson made the motion, seconded by Tim Owens, not to accept the High Banks Wind resource addition request. The motion was approved with one abstention: Jody Holland.

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The Lonesome Creek resource addition request did not need to be covered because it was approved as a waiver at the December TWG meeting. (Attachment 18 – Lonesome Creek RAR)

Aaron Vander Vorst presented a resource addition request for Rockhaven Wind. (Attachment 19 – Rockhaven RAR)

Zac Hager made the motion, seconded by Calvin Daniels, to accept the Rockhaven Wind resource addition request. The motion was approved with four abstention: Jody Holland, Anita Sharma, Jeremy Severson, and Tim Owens.

During discussions it was voiced that the sooner in-service date was a factor in approving the Rockhaven RAR and not the High Banks Wind RAR. It was decided to revisit the discussion of the RAR process after the other agenda items. Once revisited it was decided to have an education session on RARs and siting exception decision making.

AGENDA ITEM 6A – 20-YEAR ASSESSMENT FUTURES DEVELOPMENT

Adam Bell gave a recap of recent activity in regards to the 20-year assessment scope development and presented options to finalize the futures. (Attachment 20 – 20YA Futures Development)

Steve Gaw made the motion, seconded by Anita Sharma, to adopt 4th future based on MISO MTEP F3 with hurdle rate of 0 between MISO and SPP.

Calvin Daniels proposed a friendly amendment to adopt 4th future based on SPP F3 with hurdle rate of 0 between MISO and SPP. The amendment was accepted and the motion was approved unanimously.

AGENDA ITEM 7 – RESOURCE PLANNING SOFTWARE

Antonio Barber (Attachment 21 – Resource Planning Software)

Kurt Stradley made the motion, seconded by Tim Owens, to approve SPP staff’s recommendation for a waiver of the ITP manual for the 2022 ITP requiring the use of resource expansion software. The motion was approved unanimously.

AGENDA ITEM 8 – BUTLER-TIOGA PROJECT DISCUSSION

Kelsey Allen presented history of the Butler-Tioga project in the 2019 and 2020 ITP assessments. He discussed ongoing work for refining the project after the Board of Directors deferred action and covered information on different routes for the project. (Attachment 22 – Butler-Tioga 138kV)

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AGENDA ITEM 9 – RR 431: LOCAL PLANNING CRITERIA IN THE ITP

This item was struck from the agenda

AGENDA ITEM 10 – PLANNING ROADMAP

Erin Cathey presented an overview of the strategic roadmap development process including a background and breakdown of the phases of the process. (Attachment 23 – Strategic Roadmap Development Process)

ECONOMIC STUDIES WORKING GROUP MINUTES December 3-4, 2020

AGENDA ITEM 11 – CLOSING ITEMS

An action item was taken to review pulling the RPS table out of the ITP Manual.

Respectfully Submitted,

Joshua Norton

Secretary

Name Company/Email AttendanceAaron Shipley [email protected] WebexAaron Vander Vorst [email protected] WebexAdam Bell [email protected] WebexAhmed Alazzawi [email protected] WebexAl Tamimi [email protected] WebexAlan Myers [email protected] WebexAmber Greb [email protected] WebexAmy Newton [email protected] WebexAndrew Berg [email protected] WebexAnita Sharma [email protected] WebexAntonio Barber [email protected] WebexBen Abing [email protected] WebexBennie Weeks [email protected] WebexBrian Johnson [email protected] WebexBrian Rounds [email protected] WebexBritt Runion [email protected] WebexBrooke Keene [email protected] WebexBrownyn Collier [email protected] WebexBruce Grey [email protected] WebexCalvin Daniels (WFEC) [email protected] WebexCasey Cathey [email protected] WebexCharlton Hill [email protected] WebexChris Jamieson [email protected] WebexChris Matthes [email protected] WebexChristopher Davis [email protected] WebexClifford Franklin [email protected] WebexDara Solomon [email protected] WebexDavid Busse [email protected] WebexDavid Marshall [email protected] WebexDerek Brown [email protected] WebexDerek Johnson [email protected] WebexDerek Sunderman [email protected] WebexEddie Watson [email protected] WebexEllen Cook [email protected] WebexEric Rodriguez [email protected] WebexErin Cathey [email protected] WebexGayle Nansel [email protected] WebexHarika Basaran (PUCT) [email protected] WebexIan Wren [email protected] WebexJACOB PANNELL [email protected] Webex

James Bailey [email protected] WebexJason Atwood (Hitachi ABB) [email protected] WebexJason Davis [email protected] WebexJason Mazigian [email protected] WebexJason Shook [email protected] WebexJeremy Severson [email protected] WebexJerry Bradshaw [email protected] WebexJim Jacoby (AEP) [email protected] WebexJodi Woods [email protected] WebexJody Holland [email protected] WebexJoe Dan Wilson [email protected] WebexJoe Fultz (GRDA) [email protected] WebexJoe Richardson [email protected] WebexJohn Boshears [email protected] WebexJohn Turner [email protected] WebexJohn Varnell [email protected] WebexJonathan Surls [email protected] WebexJordan Schmick [email protected] WebexJosh Jarriel [email protected] WebexJoshua Pilgrim [email protected] WebexJosie Daggett [email protected] WebexJP Meitner [email protected] WebexKeith Collins [email protected] WebexKelsey Allen [email protected] WebexKirk Hall [email protected] WebexKrishada Watson [email protected] WebexKurt Stradley [email protected] WebexKylah McNabb [email protected] WebexKyle McKinney [email protected] WebexLane Sisung [email protected] WebexLiz Gephardt [email protected] WebexMatthew Rudy [email protected] Webexmatthew stoltz [email protected] WebexMaurisa Hughes [email protected] WebexMichael Swan [email protected] WebexMichael Watt [email protected] WebexMichael Wegner (ITC) [email protected] WebexMike Swan [email protected] WebexMoses Rotich [email protected] WebexNeeya Toleman (SPP) [email protected] WebexPat Hayes [email protected] Webex

Paul Vovk [email protected] WebexPius Fischer [email protected] WebexRandy Collier [email protected] WebexRaul Perez Guerrero [email protected] WebexRobert Tallman [email protected] WebexRyan Benton [email protected] WebexRyan Yokley [email protected] WebexScott Benson [email protected] WebexSean Rogers [email protected] WebexSerhat Guney (SPP MMU) [email protected] WebexSteve Gaw [email protected] WebexSteve Hohman (OPPD) [email protected] WebexSunny Raheem [email protected] WebexTim Owens [email protected] WebexTim Sell [email protected] WebexTimothy Sell [email protected] WebexTony Gott [email protected] WebexTyler Baxter [email protected] WebexWilliam Leung [email protected] WebexZac Hager [email protected] Webex

Proxy Statements

Member Proxy Note Kyle McKinney Joe Dan Wilson Friday only

Hey guys, I will need Joe Dan Wilson to be my proxy for tomorrow’s meeting.

Sr. Modeling Analyst – Settlements, Markets & Resource Planning

O: (806) 349-5246

C: (806) 282-9451

E: [email protected]

Golden Spread Electric Coop.

905 S Fillmore St, Amarillo, TX 79101

mailto:[email protected]

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.

SOUTHWEST POWER POOL, INC. ECONOMIC STUDIES WORKING GROUP MEETING

December 3-4, 2020 Net Conference

AGENDA Thursday, 8:00a.m – 12:00p.m.

Friday, 8:00a.m – 12:00p.m.

Administrative Items ......................................................................................................... Alan Myers (15 min)

A. Call to Order, Introductions ..................................................................................................... Alan Myers

B. Receipt of Proxies ................................................................................................................. Joshua Norton

C. Review of Agenda1 ...................................................................................................................... Alan Myers

D. Antitrust Reminder ............................................................................................................... Joshua Norton

Consent Agenda1

A. RR 417: Clarify no NTC issued from 20-Year Assessment

ESR Task Team Reports

A. Tx1 White Paper (Approval Item)1 ................................................................... Scott Benson (45 min)

B. E1 Update1 ...................................................................................................................... Al Tamimi (30 min)

2021 ITP

A. Schedule Update1................................................................................................. Dara Solomon (10 min)

B. Target Area Discussion1 .............................................................. Josh Pilgrim/Liz Gephardt (30 min)

2022 ITP

A. Schedule Update1................................................................................................. Dara Solomon (10 min)

1 Background Material Included

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.

B. Electric Vehicle Demand Growth (Approval Item)1 ...................................... Jake Pannell (30 min)

C. Draft Scope Review1 .................................................................................................... Adam Bell (30 min)

D. Renewable Policy Review/Resource Plan – Phase 11 ......................... Krishada Watson (20 min)

E. Load & Generation Review1 .............................................................................. Brooke Keene (10 min)

F. Resource Addition Requests (Approval Item)1 ........................................... Brooke Keene (30 min)

20-Year Assessment

A. Futures Development (Approval Item)1 ............................................................... Adam Bell (60 min)

Resource Planning Software (Approval Item)1 ............................................... Antonio Barber (15 min)

Butler-Tioga Project Discussion (Approval Item)1 ................ Kelsey Allen / Casey Cathey (30 min)

RR 431: Local Planning Criteria in the ITP (Approval Item)1 .................... Maurisa Hughes (60 min)

Planning Roadmap1 .......................................................................................................... Erin Cathey (45 min)

Closing Items ........................................................................................................................................ All (10 min)

A. Summary of Action Items

B. January Meeting Agenda Items

C. Future Meetings

i) January: 4, 2021: Net Conference – Joint with TWG ii) January 7, 2021: Net Conference iii) February 3-4, 2021: Net Conference

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Revision Request Recommendation Report

RR #: 417 Date: 7/28/2020

RR Title: Clarify no Notification to Construct issued from 20-Year Assessments

SUBMITTER INFORMATION

Submitter Name: Aaron Shipley Company: Southwest Power Pool

Email: [email protected] Phone: 501-482-2197

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.)

OBJECTIVE OF REVISION (Ensure the objective has been updated to reflect the intent of the revisions presented for approval)

Describe the problem/issue this revision request will resolve.

As part of the updates to the Integrated Transmission Planning processes the ITP 20 study was removed. To replace this study and maintain a long-range planning look, it was determined a 20 Year Assessment shall be performed at a minimal once every five years. Historically, SPP does not issue Notifications to Construct (“NTC”) from these long range studies, however it is not precluded. Revision Request 334 was submitted seeking to add the 20 Year Assessment as an eligible study in Attachment Y that could result in a Competitive Upgrade (“CU”). The Markets and Operation Policy Committee (“MOPC”) rather than approving RR334 as submitted, tableded it and directed that language should be developed to specifically prohibit any projects being approved and receiving a NTC from the 20 Year Assessment.

Describe the benefits that will be realized from this revision.

This RR will provide further clarification that the 20 Year Assessment can not result in projects derived from this study receiving a NTC. The intention of this study was to continue to provide a long range look at the transmission system from a high level, but does not include the level of detail and review required of studies that may result in approved projects. This RR will continue to allow the benefits and guidance a long range study can provide to the planning process without requiring projects become approved and receive NTCs.

SPP STAFF COMMENTS

IMPACT ANALYSIS (See RR Impact Analysis Form for complete impact details)

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):

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Estimated Vendor Cost: 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: ROM based on information available at the time of the estimate

Estimated Implementation Time: 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): Attachment O Section IV, Attachment Y Section I Business Practice Business Practice Number: 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: RTWG

Date: 9/24/2020

Motion: To approve RR 417 MJMEUC-Evergy-Sunflower Comments 09172020 as modified during the September 24, 2020 RTWG meeting as implementing the MOPC direction

Action: Approved

Abstained: None

Opposed: None

Reason for Abstention/Opposition:

Secondary Working Group:

Date:

Motion:

Action:

Abstained:

Opposed:


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Date:

Motion:

Action:

Abstained:

Opposed:



Date:

Motion:

Action:

Abstained:

Opposed:


MOPC

Date:

Motion:

Action:

Abstained:

Opposed:


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: Tom Hestermann (Sunflower) – 8/20/2020

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Summary of Comments: These comments intend to remedy several conflicts in Attachment O Section V that were created by the revisions proposed in Attachment O Section IV.

Organizational Group Review Results (e.g. Reviewed and accepted, reviewed but not accepted, reviewed with partial acceptance – provide details to explain): Reviewed but not accepted

2. Comment Form Date and Submitter: Heather Starnes (MJMEUC)/Mo Awad (Evergy)/Tom Hestermann (Sunflower) – 9/17/2020

Summary of Comments: These comments propose language to Attachment O and Attachment Y to clarify that any upgrades identified in the 20-year Assessment are not eligible for construction and shall not be issued a Notice to Construct. The comment submitters have discussed the proposed changes with SPP regulatory and legal staff. Our proposed revisions would be a complete substitute for those proposed in RR417 as initially written rather than additive.

Organizational Group Review Date and Results (e.g. Reviewed and accepted, reviewed but not accepted, reviewed with partial acceptance – provide details to explain): Reviewed and accepted

PROPOSED REVISION(S) TO SPP DOCUMENTS

SPP Tariff (OATT)

Attachment O IV. Other Planning Studies

2) 20-Year Assessments

a) The Transmission Provider shall perform a 20-Year Assessment at least once every

five years, or more frequently if approved by the SPP Board of Directors. The

purpose of the 20-Year Assessment is to produce an informational report of

possible transmission upgrades that may be used in future planning studies by

looking at a longer planning horizon. No project may be authorized for

construction as the result of a 20-Year Assessment.

b) The 20-Year Assessment shall review the system for a twenty-year planning

horizon and address, at a minimum, facilities 300 kV and above needed in year 20.

This assessment is not intended to review each consecutive year in the planning

horizon.

c) The Transmission Provider, in consultation with the stakeholders, shall develop the

scope for each 20-Year Assessment and post the scope on the SPP website.

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d) For each 20-Year Assessment the Transmission Provider shall publish a report

summarizing the findings. The report and related studies and the criteria,

assumptions and data underlying the report shall be posted on the SPP website.

ATTACHMENT Y

I. OVERVIEW OF TRANSMISSION OWNER DESIGNATION PROCESS

1) As determined in accordance with Section I.2 of this Attachment Y, the Transmission Provider

shall designate a Transmission Owner in accordance with the process set forth in Section III of

this Attachment Y for transmission facilities approved for construction by the Transmission

Provider after January 1, 2015 that meet all of the following criteria:

a) Transmission facilities that are: ITP Upgrades, high priority upgrades, or Interregional

Projects;

b) Transmission facilities with a nominal operating voltage of greater than 100 kV; c) Transmission facilities that are not a Rebuild of an existing facility;

d) Transmission facilities that do not alter a Transmission Owner’s use and control of its existing

right of way under relevant laws or regulations;

e) Transmission facilities located where the selection of a Transmission Owner pursuant to

Section III of this Attachment Y does not violate relevant law where the transmission facility

is to be built;

f) Transmission projects that do not require both a Rebuild of existing facilities and new

transmission facilities; and

g) Transmission facilities that are not a Local Transmission Facility.

2) For transmission projects involving both a Rebuild of existing facilities and the construction of

new transmission facilities, the Transmission Provider shall designate the Transmission Owner(s)

as follows:

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a) If 80% or more of the total cost of a project consists of the Rebuild of existing facilities, then

the Transmission Provider shall designate the Transmission Owner(s) for the project in

accordance with Section IV of this Attachment Y; or

b) Otherwise, the Transmission Provider shall divide the project into two or more segments based

upon whether that portion of the project is a Rebuild of existing facilities or new facilities. For

those segments that are Rebuilds of existing facilities, the Transmission Provider shall

designate the Transmission Owner(s) in accordance with Section IV of this Attachment Y. For

those segments that are new facilities, the Transmission Provider shall designate the

Transmission Owner(s) in accordance with Section III of this Attachment Y.

3) For any upgrade meeting the specifications listed in Section I.1 of this Attachment Y, the

Transmission Provider may designate the Transmission Owner(s) in accordance with Section IV

of this Attachment Y if such upgrade is required to be in service within 3 years or less to address

an identified reliability violation (“Short-Term Reliability Project”). To have a transmission

project approved as a Short-Term Reliability Project, the Transmission Provider shall:

a) Separately identify and post an explanation of the reliability violations and system conditions

for which there is a time-sensitive need, in sufficient detail to allow stakeholders to understand

the need and why it is time sensitive.

b) Provide to stakeholders and post on its website a full and supported written description

explaining:

i. The decision to designate the Transmission Owner pursuant to Section IV of this

Attachment Y, including an explanation of other transmission or non-transmission

options that the Transmission Provider considered but concluded would not sufficiently

address the immediate reliability need; and

ii. The circumstances that generated the immediate reliability need and an explanation of

why that immediate reliability need was not identified earlier.

c) Permit stakeholders thirty (30) days to provide comments in response to the description

required under Section I.3.b of this Attachment Y and make such comments publicly available.

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d) Maintain and post a list of prior year designations of Short-Term Reliability Projects. The list

must include the Short-Term Reliability Project’s need date and the date that the DTO actually

energized the project. Such list must be filed with the Commission as an informational filing

in January of each calendar year covering the designations of the prior calendar year.

e) Obtain approval by the SPP Board of Directors.

4) No project may receive an NTC as the result of a 20-Year Assessment.

4)5) For any upgrade not defined in Section I.1 or Section I.4, or does not meeting the

requirements of Sections I.2 or I.3 of this Attachment Y, the Transmission Provider shall designate

the Transmission Owner(s) in accordance with the process set forth in Section IV of this

Attachment Y.

5)6) The designation from the Transmission Provider shall be provided pursuant to Section V

of this Attachment Y.

6)7) The Transmission Provider shall track all projects that are approved for construction in

accordance with Section VI of this Attachment Y.

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

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REVISION REQUEST PROCESS UPDATESRR417 – 20 YEAR ASSESSMENT NO NTCESWG – DECEMBER 03, 2020AARON SHIPLEY

2

AGENDA

• Review for approval RR417

• Proposed modifications

• Recommendation

• Questions & Answers

• Next Steps fro RR417

3

ASK OF ESWG TODAY

• Todays presentation is intended to seek approval for RR417.• ESWG is a Secondary WG per RR Routing

Criteria• This was presented for education purposes to

the RTWG on May 28, 2020 and for approval on September 24, 2020.• RTWG had a small group work “offline” to

create language all parties could support and met the MOPC directive

4

GOAL OF RR417

• Purpose of RR417:1. To clarify that the 20 Year Assessment can

not result in the issuance of a Notification to Construct.

• The additional language does not impact the purpose or ability to use the 20 Year Assessment in any manner.

5

BACKGROUND ON RR417

• RR334 Criteria Update Used in Transmission Owner Designation Process, posted October 8, 2018• Intended to simply add that the 20 Year Assessment

could result in a Competitive Upgrade initiating the Transmission Owner Selection Process

• Approved through working groups however at January 2019 MOPC was not approved.• MOPC directed to go back and clarify that no NTC

should be the result of the 20 Year Assessment as that was not the intent of the study.

• RR417 seeks to implement the MOPC request and will result in RR334 being withdrawn.

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PROPOSED MODIFICATIONS

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WHAT IS BEING PROPOSED?Attachment O Section IV.2:

IV. Other Planning Studies

2) 20-Year Assessments

a) The Transmission Provider shall perform a 20-Year Assessment at least once every five years, or more frequently if approved by the SPP Board of Directors. The purpose of the 20-Year Assessment is to produce an informational report of possible transmission upgrades that may be used in future planning studies by looking at a longer planning horizon. No project may be authorized for construction as the result of a 20-Year Assessment.

b) The 20-Year Assessment shall review the system for a twenty-year planning horizon and address, at a minimum, facilities 300 kV and above needed in year 20. This assessment is not intended to review each consecutive year in the planning horizon.

c) The Transmission Provider, in consultation with the stakeholders, shall develop the scope for each 20-Year Assessment and post the scope on the SPP website.

d) For each 20-Year Assessment the Transmission Provider shall publish a report summarizing the findings. The report and related studies and the criteria, assumptions and data underlying the report shall be posted on the SPP website.

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WHAT IS BEING PROPOSED?Attachment Y Section I.4:

4) No project may receive an NTC as the result of a 20-Year Assessment

5) For any upgrade not defined in Section I.1 or Section I.4, or does not meet the requirements of Sections I.2 or I.3 of this Attachment Y, the Transmission Provider shall designate the Transmission Owner(s) in accordance with the process set forth in Section IV of this Attachment Y.

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RECOMMENDATION

• SPP Staff recommends the ESWG approve RR417 as submitted.

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Q&A

11

NEXT STEPS

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NEXT STEPS FOR RR417

Below is the Working Group schedule for RR417:RTWG 5/28 (education)

RTWG 9/24 (Approved)

PCWG 12/2 (seek approval)

ESWG 12/3 (seek approval)

RCWG 12/17 (seek approval)

TWG 12/2 (seek approval)

MOPC 1/11 (seek approval)

Following MOPC approval RR will be filed with FERC for implementation

Internal Use Only

E S W G / T W G / O R W G R e c o m m e n d a t i o n s t o t h e M O P C : H I T T S 3 R e c o m m e n d a t i o n T X 1 -

R E C O N C I L E E S R D U R A T I O N W I T H T R A N S M I S S I O N P L A N N I N G S C E N A R I O

Southwest Power Pool, Inc. Revision History

ESWG/TWG/ORWG Action Items for MOPC

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Internal Use Only

Revision History

Date or Version Number

Author Change Description Comments

8/25/2020 ESR Tx1 Task Team N/A Initial draft.

11/09/2020 ESR Tx1 Task Team Updated to reflect discussions at 9/09/2020 and 10/21/2020 task team meetings, parallel review with ORWG representatives and enhancements to capacity/duration analysis.

Second draft.

11/19/2020 ESR Tx1 Task Team Updated to reflect discussions at 11/09/2020 and 11/19/2020 task team meetings.

Final Draft Approved by ESR Tx1 Task Team

12/02/2020 ESR Tx1 Task Team Updated to consider load profile coordination with local TO, per contingent approval motion at 12/02/2020 TWG meeting.

Updated final draft for ESWG & ORWG approval consideration on 12/03/2020.

Southwest Power Pool, Inc.


2 Internal Use Only

Table of Contents

Revision History .......................................................................................................................................... 1

Introduction ........................................................................................................................... 3

ESWG/ORWG/TWG Position .............................................................................................. 4

2.1. Problem Statement...................................................................................................................... 4

2.2. ESR Ratings ............................................................................................................................... 4

2.3. ESR Ratings Reliability Margin ................................................................................................. 5

2.4. ESR Ratings Identification Timeline .......................................................................................... 5

2.5. ESR Charging Capability and Requirements ............................................................................. 6

2.6. ESR Testing ................................................................................................................................ 7

2.7. Mitigating ESR Deficiencies in the Operating Realm ................................................................ 7

Conclusion and Recommendations ....................................................................................... 8

Appendix ............................................................................................................................... 9



3 Internal Use Only

Introduction This white paper summarizes the Transmission Working Group (TWG), Economic Studies Working Group

(ESWG) and Operating Reliability Working Group’s (ORWG) recommendations to the Market and Operations

Policy Committee (MOPC) for a high priority Electric Storage Resource (ESR) action item, specifically a process

that reconciles the duration of an ESR (when used to address a transmission issue) with transmission planning

scenarios. This is the result of a coordinated effort between the three working groups, based on the

recommendation from the Electric Storage Resources white paper and the assignment originating from the

Electric Storage Resources Steering Committee (ESRSC). The ESRSC is coordinating and directing various

working groups in development of policy and procedure recommendations to the MOPC regarding grid

integration of ESRs. Policies developed to integrate ESRs should seek to maximize the flexibility of ESRs while

maintaining reliable and economic operations.

ESR White Paper Transmission Issue Description

TX1. Reconcile ESR Duration with Transmission Planning Scenario

The planning scenarios used in SPP’s transmission planning process are worst-case historical scenarios.

Consequently, a scenario may exceed an ESR’s duration. Although an ESR’s duration may vary significantly,

the cost-benefit analysis is impacted by both the MW rating and the duration. For example, the revenue stream

for a 200 MW ESR with a four-hour duration likely would be different than revenue from an 800 MW ESR

with a one-hour duration, although they are both an 800 MWh ESR. FERC Order 841 allows an ESR to be

derated in the energy market to qualify to provide a service/product. FERC has not addressed ESRs as

transmission facilities.

ESR White Paper Recommendation

The TWG and ORWG are to develop a procedure for handling an ESR transmission facility when the ESR’s

duration is insufficient to meet the transmission issue. The ORWG needs to accept this procedure as practical

in real-time operations before using it in transmission planning cases. Examples of procedures may be to either

derate transmission facilities’ output to increase ESRs’ duration or combine multiple ESRs to increase their

duration.



4 Internal Use Only

ESWG/ORWG/TWG Position A task force comprised of ESWG, ORWG and TWG members was assembled to analyze and propose a

methodology to address item TX1. This task force, working in conjunction with related SPP staff, drafted a series

of recommendations for review by the three respective working groups.

The following recommendations represent the coordinated proposal of the ESWG, ORWG and TWG:

2.1. Problem Statement

As previously stated, the ESR Whitepaper called for TX1 to “develop a procedure for handling an ESR

transmission facility when the ESR’s duration is insufficient to meet the transmission issue.” The working groups

contend that this problem statement may be too narrow in scope, as the issue would be better addressed by simply

eliminating it to the extent possible. For this reason, the working groups instead focused on developing processes,

procedures and requirements to ensure an ESR used as a transmission asset can sufficiently address the related

transmission issue throughout the intended life of the asset, but then also developing general procedures to deal

with inevitable shortcomings in the operating realm.

2.2. ESR Ratings

One of the keys to ensuring ESR transmission solutions successfully address the related needs is accurately

identifying the required discharge capacity and duration ratings during the planning process. For thermal and

perhaps voltage violations, PSS/E power flow models can be used to determine the minimum usable ESR

discharge capacity required to mitigate a contingency scenario, but the single-hour snapshot they provide doesn’t

help identify how often, or for what duration, system conditions will support the issue. Leveraging the 8,760-hour

load profile information within the PROMOD economic models, however, could allow staff to isolate the hours

where system conditions exceed these levels, and thus identify the minimum required ESR duration. In practice,

more accurate load profile information may even be available via coordination with the local transmission owner.

To test this approach, SPP staff analyzed two reliability needs from the 2019 ITP, seeking to identify the capacity

and duration ratings required to alleviate the issues. These test cases varied in complexity, but the process

appeared to successfully identify the required ratings in both instances. A summary of these cases and the related

analysis are included in the Appendix.



5 Internal Use Only

Establishing the required capacity and duration ratings to address transmission needs isn’t a “paint-by-numbers”

process, with each scenario needing to be evaluated in its own accord. However, under most scenarios, the

working groups propose using load curves to help determine the required discharge capacity and duration of an

ESR facility.

2.3. ESR Ratings Reliability Margin

As proposed here, the minimum usable ESR discharge capacity rating could often be determined from the power

flow models. SPP staff regularly conducts power flow analysis that avoids implementing a marginal transmission

solution, else the same issue could crop up again in the near term. For example, they typically identify

transmission solutions that reduce overloads to 90% of the applicable facility ratings, allowing some margin for

future system changes and load growth. In this fashion, determining a suitable ESR discharge capacity rating that

allows reasonable room for future system accommodations should not be out of the ordinary.

However, the suggested load curve analysis to identify the minimum ESR duration rating appears to represent a

new application of the economic modelthis data. Until a proven history has been developed with this new load

curve methodology, the working groups propose to apply a prescribed reliability margin to the ESR duration

requirements identified through the analysis. The working groups recommend a reliability margin of 1 to 4 hours,

mimicking the duration of conductor emergency ratings suggested under the SPP Planning Criteria. To coordinate

with the required duration of the specific ESR, this reliability margin would be calculated as 25% of the minimum

required capacity rating, rounded up to the next whole hour, and then capped at the maximum of 4 hours. For

illustration purposes, this reliability margin was applied to each of the 2019 ITP needs analyzed in the Appendix.

The need for this additional reliability margin will need to be continually evaluated as more experience with the

load curve methodology is accumulated. Once implemented, the working groups recommend the application and

size of the ESR duration reliability margin be revaluated on an annual basis.

2.4. ESR Ratings Identification Timeline

Another important consideration is the most efficient point within the planning process for SPP to identify the

ESR capacity and duration requirements to remedy the related transmission issues. On one extreme, SPP could

conduct this analysis prior to the DPP window for every single need in the ITP. This approach would theoretically

establish the expectations for any potential ESR respondents upfront, possibly eliminating inadequate ESR



6 Internal Use Only

submittals all together, or at the very least making it easy to eliminate them during the evaluation process. An

ESR would likely not be submitted for every single need though, leading to some amount of wasted effort on the

part of SPP staff. This is supported by recent history, with only one ESR-related proposal in the 2018 ITPNT, 12

in the 2019 ITP and one in the 2020 ITP.

On the other extreme, SPP could conduct this analysis only after an ESR proposal is made via the DPP process,

ensuring there is no wasted effort on the front end. However, this could bring more complexity on the back end,

requiring SPP to put more work in to identifying ways to successfully leverage deficient ESR submittals, like

perhaps in aggregate with other proposals. Plus, not all potential DPP respondents would have access to the

proprietary load profile data within the economic model, impacting the ability of some entities to perform this

analysis prior to proposing an ESR solution to a transmission issue.

In consideration of the relatively small number of ESR proposals associated with past ITPs, the working groups

recommend performing the ESR rating requirements analysis only after an ESR has been proposed. However, at

some point when ESR proposals become more common, this approach could be revisited to reconsider

performing the analysis for all needs prior to opening the DPP window.

2.5. ESR Charging Capability and Requirements

Assuming an ESR with adequate discharge capacity and duration ratings is installed, its inherent dual role as both

a generator and a load means continual oversight of the charging process will be required to ensure success as a

transmission asset. For example, the ESR will need to be fully charged whenever local system conditions

approach those of the projected contingency threshold. The ESR also cannot be allowed to charge from the SPP

system when the additional load may contribute to the issue. These criteria will need to be established on a case-

by-case basis and documented within an SPP operating guide, as every ESR application will bring its own unique

charging considerations. They will also need to be continually revisited, as changes to the system will necessitate

ongoing review.

As discussed previously, the 8,760-hour load profile information within from either the economic models or the

local transmission owner could be leveraged to isolate the approximate hours where system conditions will

support a specific contingency scenario. This in turn could help identify, at least initially, when an ESR likely



7 Internal Use Only

needs to be fully charged and available to mitigate a potential issue. As an example, this analysis was conducted

for each of the 2019 ITP needs analyzed in the Appendix.

Additionally, should an ESR utilized as a transmission asset be allowed to perform other functions under a multi-

use application, it is essential that its role as a transmission asset take priority over the ESR’s other services and

charging cycle. Service as a transmission asset should always be considered the first use of the ESR by default,

and the ESR should only be allowed to perform other multi-use services if (i) the ESR is expressly released from

transmission service considerations for a finite period, and (ii) the ESR has the ability to be fully charged and

completely ready for operation as a transmission asset upon its required return.

2.6. ESR Testing

The working groups believe ESR facilities must be tested to ensure they initially meet the minimum capacity and

duration requirements established through the transmission planning process. Although the details of this testing

may likely fall outside the purview of these working groups, they believe it is imperative to confirm the validity

of the ESR from the very beginning. They also recommend that follow-up testing and/or operating confirmations

be required on an annual basis to sufficiently ensure the assets continue to perform to minimum expectations

throughout their intended lifespan.

2.7. Mitigating ESR Deficiencies in the Operating Realm

Even with the aforementioned planning and governance safeguards in place, the very nature of the grid and the

related equipment dictates that an ESR will potentially encounter a scenario where it is unable to fully mitigate a

real-world transmission issue. In these situations, the working groups believe the following sequence should

generally be adhered to:

Operations should address real-time operational constraints caused by insufficient ESR capacity or

duration using operating guides and or real-time actions.

Use the ESR as required in real time even if the reliability issue is expected to outlast the duration of the

ESR at the required capacity.

Upon depletion of an ESR the congestion management process will be utilized, up to and including the

use of other ESRs to resolve transmission issues, as applicable. Manual load shedding would be utilized if

all other measures fail to relieve the constraint.



8 Internal Use Only

Conclusion and Recommendations This white paper summarizes the TWG, ESWG and ORWG recommendations to the MOPC for high priority

action items (as indicated by the ESRSC) related to developing a procedure for handling an ESR transmission

facility when the ESR’s duration is insufficient to fully mitigate the transmission issue. In order to eliminate this

issue to the fullest extent possible, the working groups chose to focus on developing processes, procedures and

requirements to ensure an ESR used as a transmission asset can sufficiently address the related transmission issue

throughout the intended life of the asset, but then also developing general procedures to deal with inevitable

shortcomings in the operating realm.

Following their review and analysis, the respective working groups propose the following:

PSS/E power flow models can generally be used to determine the minimum usable ESR discharge

capacity, while either the PROMOD economic models or more accurate load profile data from the local

transmission owner could be leveraged to allow staff to isolate the hours where system conditions exceed

these levels, and thus identify the minimum required ESR duration.

A prescribed reliability margin should be applied to the calculated ESR duration requirements, ranging

from 1 to 4 hours. Specifically, this should equate to 25% of the identified duration requirements, rounded

up to the next whole hour and capped at a maximum of 4 hours.

In consideration of the relatively small number of ESR proposals associated with past ITPs, ESR rating

requirements should only be analyzed after an ESR has been proposed, at least initially.

Charging criteria will need to be established on a case-by-case basis and documented within an SPP

operating guide, but load profile data from either the economic models or the local transmission owner

could be leveraged to help identify, at least initially, when an ESR needs to be fully charged and available.

Should an ESR utilized as a transmission asset be allowed to perform other functions under a multi-use

application, its role as a transmission asset should take priority over the ESR’s other services and charging

cycle.

ESR facilities must be tested to ensure they initially meet the minimum capacity and duration

requirements established through the transmission planning process. To ensure continued success, follow-

up testing and/or operating confirmations shall be required on an annual basis.

When attempting to mitigate a transmission issue, Operations should address insufficient ESR capacity or

duration using operating guides and or real-time actions. Under this scenario, an ESR should still be



9 Internal Use Only

utilized to its fullest extent, even if the reliability issue is expected to outlast the duration of the ESR.

Upon depletion of an ESR, the standard congestion management process will be utilized.

Appendix

Identifying ESR rating requirements for sample reliability needs from the 2019 ITP.



10 Internal Use Only

Example 1

System Topology

Need Description

Thermal violation directly driven by system load during summer peak conditions.

Basis of Violation

Simply summing loads along the loop, as identified in the power flow model, indicates a minimum aggregate

loading threshold of approximately 59 MW for the violation to occur.

Required ESR Capacity

The following table details how an ESR located within the loop and discharging at various levels impacts loading

on the overloaded line, based on analysis of the power flow model. In order to avoid implementing a marginal

solution, a capacity of at least 10 MW would be required.




Capacity (MW) Loading (%)

2 100

10 90

20 78

Required ESR Duration

Based on a review of the economic model, an aggregate loop load of at least 59 MW is recorded for as much as 3

consecutive hours, per the chart below. The ESR duration reliability margin would then be applied, calling for an

additional 25%, rounded to the next whole hour and capped at a maximum of 4 hours.

Reliability Margin:

3 hours x 25% = 0.75 hours

0.75 hours rounds up to 1 whole hour

1 hour < 4 hour maximum

Minimum Duration Rating = 3 hours + 1 hour = 4 hours

Therefore, the minimum required duration for an ESR solution would be 4 hours, equating to a minimum energy

rating of 40 MWh for a 10 MW capacity rating.




Preliminary ESR Charging Capability and Requirements

Per the chart above, an aggregate loop load of 59 MW only occurs in the month of July. Based on further review

of the economic model, this aggregate loop load only occurs on these July days between hour-ending 15:00 and

hour-ending 17:00, as shown in the chart below. Conservatively, an ESR solution could hypothetically then be

required to be fully charged and 100% available to serve as a transmission asset from 12:00 to 19:00 each day

during the summer months.

0

0.5

1

1.5

2

2.5

3

3.5

7/10/2030 7/11/2030 7/12/2030 7/15/2030 7/16/2030 7/17/2030

Hours Over 59 MW




Example 2

System Topology

Need Description

Thermal violation directly driven by system load during summer peak conditions.

Basis of Violation

Due to the complexity of this case, SPP staff scaled down the entire AEPW load along its load curve in the power

flow model until the violation disappeared in order to find the critical, area-wide loading. This value was

determined to be 8,124 MW.

Required ESR Capacity

Due to the surrounding topology, the counterflow provided by an ESR (assumed to be at bus 509811) would not

all go towards the violation on the monitored element. Therefore, based on analysis of the power flow model, the

ESR must have a capacity of at least 100 MW before the violation is addressed.

Required ESR Duration

Based on a review of the economic model, the aggregate area load exceeds the target amount of 8,124 MW for up

to 15 hours, per the chart below. The ESR duration reliability margin would then be applied, calling for an

additional 25%, rounded to the next whole hour and capped at a maximum of 4 hours:




Reliability Margin:

15 hours x 25% = 3.75 hours

3.75 hours rounds up to 4 whole hours

4 hours = 4 hour maximum

Minimum Duration Rating = 15 hours + 4 hours = 19 hours

Therefore, the minimum required duration for an ESR solution would be 19 hours, equating to a minimum energy

rating of 1,900 MWh for a 100 MW capacity rating.

Preliminary ESR Charging Capability and Requirements

Per the chart above, an aggregate area load of 8,124 MW only occurs between the months of May and September.

Based on further review of the economic model, this aggregate area load only occurs on these days between hour-

ending 9:00 and hour-ending 24:00, as shown in the chart below.




Due to the fact that the load is often over the target amount for at least 12 hours on consecutive days, an ESR

would need to be able to recharge at a very high rate to adequately address the transmission issue. Under this fast-

charging scenario, an ESR solution could conservatively be required to be fully charged and 100% available to

serve as a transmission asset from 7:00 to 2:00 each day from May to September. If a sufficiently fast charging

rate weren’t possible, then significantly more storage duration would be required to provide coverage across

consecutive days.


ESR TASK TX1TASK TEAM RECOMMENDATIONS

SCOTT BENSONJOSH PILGRIM

DECEMBER 3, 2020

2

ASSIGNED WORKING GROUPS

• ESWG

• ORWG

• TWG

3

PROBLEM STATEMENT

• Original ESR White Paper• Develop a procedure for handling an ESR

transmission facility when the ESR’s duration is insufficient to meet the transmission issue.

• Task Team Update• Develop processes, procedures and requirements

to ensure an ESR transmission facility can sufficiently address the related transmission issue throughout the intended life of the asset, but then also develop general operating procedures to deal with inevitable shortcomings.

4

ESR RATINGS

• Leverage existing models to determine required ratings.

• Recommendation:• Utilize PSS/E power flow models to identify

minimum usable discharge capacity.• Utilize PROMOD economic model or local TO

load profiles to identify minimum duration.

* Reflects minor revisions following 12/02/2020 TWG meeting.

5

ESR RATINGS RELIABILITY MARGIN

• Until proven history with load curve methodology has been established, add prescribed reliability margin to calculated duration.

• Recommendation:• 25% of calculated rating, rounded up to whole hour.• Capped at maximum of 4 hours, mimicking

conductor emergency rating durations suggested under SPP Planning Criteria.

• Review application and calculation annually.

6

ESR RATINGS IDENTIFICATION TIMELINE

• Where in ITP process to identify required ESR ratings:• For all needs prior to opening the DPP window?• Only after DPP submittals are made?

• ESR-related proposals not common to date:• 2018 ITPNT - 1• 2019 ITP - 12• 2020 ITP - 1

• Recommendation:• Analyze rating requirements only after ESR has been

proposed. Revisit when they become more common.

7

ESR CHARGING CAPABILITY & REQUIREMENTS

• Oversight of charging process required to ensure success as a transmission asset:• ESR must be fully charged whenever local system

conditions approach contingency threshold.• ESR cannot charge from SPP system when additional

load may contribute to issues.

• Recommendation:• Use SPP op guide to establish charging criteria.• Utilize PROMOD economic model load profiles to

identify preliminary charging/availability requirements.

8

ESR TESTING

• Details likely outside the scope of these working groups, but testing critical to success.

• Recommendation:• Initial testing to ensure ESR meets minimum

requirements upon installation.• Annual follow-up testing and/or operating

confirmations to ensure continued performance.

9

MITIGATING OPERATING DEFICIENCIES

• ESR still likely to encounter scenarios where it’s unable to fully mitigate transmission issues.

• Recommendation:• Address real-time operational constraints caused

by insufficient ESR capacity/duration using op guides and real-time actions.

• Use ESR as required in real time even if reliability issue expected to outlast ESR duration.

• Upon depletion of ESR, utilize standard congestion management process.

10

SAMPLE CALCULATIONS

• Tested proposed methodology on two reliability needs from the 2019 ITP, identifying:• Minimum usable capacity.• Minimum duration.• Preliminary charging capability and requirements.

11

• Thermal violation driven by system conditions during summer peak period.

• Per power flow model, minimum aggregate loop loading of 59 MW before violation occurs.

EXAMPLE 1NEED DETAILS

12

• Per power flow model, minimum capacity of 10 MW required to avoid marginal solution.

Capacity (MW) Loading (%)

2 100

10 90

20 78

EXAMPLE 1CAPACITY REQUIREMENT

13

• Per economic model, aggregate loop load of 59 MW only occurs in July for 3 hours/day.

0

0.5

1

1.5

2

2.5

3

3.5

7/10/2030 7/11/2030 7/12/2030 7/15/2030 7/16/2030 7/17/2030

Hours Over 59 MW

EXAMPLE 1INITIAL DURATION REQUIREMENT

14

• Duration Reliability Margin:• 3 hours x 25% = 0.75 hours• 0.75 hours rounds up to 1 whole hour• 1 hour < 4 hour maximum

• Minimum Duration Rating:• 3 hours + 1 hour = 4 hours

• Minimum ESR Ratings:• 10 MW/40 MWh

EXAMPLE 1FINAL DURATION REQUIREMENT

15

EXAMPLE 1CHARGING CAPABILITY & REQUIREMENT

• Per economic model, aggregate loop load of 59 MW only occurs between HE 15:00 and HE 17:00.

• ESR potentially required to be fully charged from 12:00 – 19:00 each day during summer months.

16

• Thermal violation driven by system conditions during summer peak period.

• Per power flow model, minimum AEPW area-wide load of 8,124 MW before violation occurs.

EXAMPLE 2NEED DETAILS

17

• Per power flow model, minimum capacity of 100 MW required to provide required counterflow to alleviate violation.

EXAMPLE 2CAPACITY REQUIREMENT

18

• Per economic model, aggregate area load of 8,124 MW occurs up to 15 hours/day from May - Sep.

EXAMPLE 2INITIAL DURATION REQUIREMENT

19

• Duration Reliability Margin:• 15 hours x 25% = 3.75 hours• 3.75 hours rounds up to 4 whole hours• 4 hours = 4 hour maximum

• Minimum Duration Rating:• 15 hours + 4 hours = 19 hours

• Minimum ESR Ratings:• 100 MW/1,900 MWh

EXAMPLE 2FINAL DURATION REQUIREMENT

20

EXAMPLE 2CHARGING CAPABILITY & REQUIREMENT

• Aggregate area load of 8,124 MW only occurs between HE 9:00 and HE 24:00.

• ESR potentially required to be fully charged from 7:00 – 2:00 each day from May – Sep.

• Without fast charging capability, significantly more duration would be required to cover consecutive days.

21

APPROVAL RECOMMENDATION

• Approval Schedule:• TWG consideration

12/02/2020

• ESWG consideration12/03/2020

• ORWG consideration12/03/2020

• Tx1 Task Force recommends ESWG approval of the related white paper, as revised to reflect the TWG’s contingent approval, dated 11/19/202012/02/2020.

- Approved with addition of local TO load profile data.

ESR “Planning Process” Task Force Update

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

V.P., Transmission Planning & Policy

Sunflower Electric Power Corporation

ESR Planning Process Review Task Force

• Scope – This task is in the energy and related services issues section of the white paper. Based on the recommendation, the deliverable for E1 is to, “develop a process for analyzing an ESR as both a load and generation.”

• The whitepaper addresses ESRs dispatch in the following SPP study processes1. ITP2. Generation Interconnection Process (GIP)3. Transmission Service (ATSS) – In progress

ITP Process

1 ESR as Transmission (reliability & economic)

2 ESR as an energy resource

3 ESR as a firm capacity resource

ESR As Transmission

1. ReliabilityESR as resource, it will be dispatched based on how it was originally identified as a solution

1. ESR will remain off during the solution process in the ITP until the original need for the ESR applied, then ESR is turned on at specific dispatch.

2. Same works if the ESR was a “load” solution

3. When issuing an NTC for ESR as transmission, the NTC should capture the duration and ratings and any other controls/specifications needed to be an effective solution

2. Economic1. The ESR could be identified to resolve economic issues for any ITP economic needs

2. ESR will be dispatched based on how it was originally identified as a solution.

ESR As Energy Resource

1. Reliability Analysisa. Market Power flow Models: dispatched according to the ITP Manual; it is expected that the dispatch for ESR energy resources will be

charging during light load conditions and discharging during peak load conditions2. Economic Analysis

a. Currently, resource builds have an assigned MW amount from the ITP Resource Plan of storage to meet planning reserve marginsb. Storage will be dispatched based on the dispatch methodology in the appropriate economic models (PROMOD and Market Power

flow)3. Hybrid (definition: combination of ESR and generation at a common/near-common POI, i.e. solar and battery): not being operated as true hybrids; operating separately but at the same POI

a. Currently, resource builds have an assigned MW amount from the ITP Resource Plan of hybrid to meet planning reserve marginsb. Hybrid units will be dispatched based on the dispatch methodology in the appropriate economic models (PROMOD and Market Power

flow)a. Following are examples of known technologies and dispatch for reliability criteria, which follows the current ITP Manual Base

Reliability assumptions on wind and solar• For wind-storage hybrids, the net output at the POI will be based on light load (maximum output of the wind-storage

hybrid); for peak load (average 5-year output of the wind plus storage hybrid)• For solar-storage hybrids, the net output at the POI will be based on light load (zero output of solar + storage-load hybrid is

consuming from grid); for peak load (average 5-year output of solar and/plus ? storage hybrid)

ESR As Firm Capacity

1. Reliability Analysis 1. The ITP Base Reliability Models are dispatched according to the ITP Manual; it is expected that the dispatch for ESR energy

resources will be charging during light load conditions and discharging during peak load conditions

2. Economic Analysis not needed for long term ESR firm capacity

3. Hybrid (definition: combination of ESR and generation at a common/near-common POI, i.e. solar and battery): not being operated as

true hybrids; operating separately but at the same POI

Hybrid units will be dispatched based on the dispatch methodology in the appropriate reliability models (Base Reliability)

Generation Interconnection Process – ESR as Transmission

1. Existing ESRs as transmission or ESRs as transmission that have been “approved” for construction in the Planning or

GI Processesa. If the transmission solution already exists, they only implement ESR to resolve reliability issues that they were identified to resolve

• ESR as resource, it will be dispatched based on how it was originally identified as a solution. If it fixes N-1 contingency, then

it will be on at full name plate during that N-1 contingency (adding it to the CON file). Other than that, it will remain off

during the solution process in the GIP.

• ESR as a load, it will be modeled as a load based on how it was originally identified as a solution.

2. GI solution may contain ESR as transmission 1. GI solution set may contain storage ESR as a solution to reliability problems (either generating or considered as load)

• Will be dispatched based on how it was approved as a solution. If it fixes N-1 contingency, then it will be on at full name

plate during that N-1 contingency (adding it to the CON file). Other than that, it will remain off during the solution process

in the GI.

• ESR will be excluded from the generator dispatch algorithm (MISO case at FERC)

Generation Interconnection Process

1. Currently, energy storage resources are dispatched as variable energy resources in the high variable case and not dispatched in the low variable case

2. Task Team recommends that current methodology be reviewed for consistency across SPP processes that use energy models

3. Charging does not typically occur on-peak and therefore there would be no reason to study it except in the off-peak case. Charging would require that there be a transmission service reservation, in which case the impact would be evaluated in the transmission study, except to the extent that the market directs an ESR to charge.

Generation Interconnection Process – ESR as Energy Resource

Transmission Service

1. ESR as transmission 1. Existing ESRs as transmission or ESRs as transmission that have been “approved” for construction in the Planning or GI

Processes. The ESR could be identified to resolve reliability issues for any ATSS reliability needs

1. ESR as resource, it will be dispatched based on how it was identified as a solution. If it fixes N-1 contingency, then it will

be on at full name plate during that N-1 contingency (adding it to the CON file). Other than that, it will remain off during

the solution process in the ATSS.

2. ESR as a load, it will be modeled as a load based on how it was identified as a solution.

3. Any changes to the original functionality of the storage device should go through re-evaluation and can be discussed in

the material modification process. SPP Criteria should be changed to accommodate changes to characteristics of a

storage device (material modification)

Transmission Service

1. Existing ESRs as capacity resources in the models1. Task Team recommends that storage dispatch methodology used in the ITP Base Reliability Models be used for

existing ESR capacity resources in the ATSS

1. New ESRs as capacity resources in the models

2. Reliability Analysis1. Customers can request transmission service to the transmission zone wanting to claim the resource as capacity

2. Customers can also request transmission service for charging activities through long-term or short-term transmission

service requests

3. absence of ‘b’ above, ESR will charge through market dispatch

4. Discharging during peak load models at the requested amount

5. Market Power flow Models: Resource is dispatched as determined in the ITP economic model

SPP Staff to draft language

Josh Ross


1

2021 ITP

2021 ITP SCHEDULEDARA SOLOMON

DECEMBER 2020

2

2021 ITP Timeline

2019 2021

Today

Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep

100% Jul 8 - Jan 14

Jul 19 - Mar 13

100% Jan 7 - Jun 12

Jul 9 - Nov 16

Jul 19 - Nov 16

95% Mar 15 - Oct 6

75% Dec 1 - Dec 18

0% Sep 21 - Dec 18

Nov 4 - Mar 8

Mar 9 - Apr 7

Mar 9 - Aug 20

Aug 23 - Sep 21

Aug 23 - Sep 21

Aug 23 - Sep 21

Aug 23 - Sep 21

Aug 1 - Oct 1

Scope Development

Load Forecast and Generation Review

Renewable/Conventional Resource Plans

Powerflow Model Development and Benchmarking

Short Circuit Model Development

Siting Plan and GOFs (Generator Outlet Facilities)

Economic Model Development and Benchmarking

Constraint Assessment

Needs Assessment

DPP Response Window

Solutions Evaluation and Portfolio Development

Project Staging & Rate Impacts

Benefit Metrics Calculations

Stability Analysis

Sensitivity Analysis

Final report with recommended solutions

Jun 18 - Oct 262021 ITP Assessment

Aug 23 - Sep 21Final Reliability Assessment (includes model updates)

Jul 8

Oct 26

Planning Summit

SPP Board

MOPC Oct 13

42021 ITP

BASE RELIABILITY (BR) POWERFLOW & SHORT CIRCUIT (SC) MODELS• Start: 7/09/2019• Initial Approval: 3/20/2020 for BR Powerflow models; Re-approved 6/18/20• Initial Approval: Requested: 7/27/2020 • BR Powerflow & SC - Final Approval: TBD pending additional Section 10.3 updates• Member Review Time:

• Pass 0 – Trial 1: 7/22/2019 – 7/26/2019 (5 days) (complete) – BR Powerflow only• Pass 0 – Trial 2: 8/12/2019 – 8/30/2019 (15 days) (complete) – BR Powerflow only• Pass 1 – Trial 1: 9/30/2019 – 10/18/2019 (15 days) (complete) – BR Powerflow only• Pass 1 – Trial 1: 10/4/2019 – 10/18/2019 (10 days) (complete) – SC only• Pass 1 – Trial 2: 11/18/2019 – 12/13/2019 (20 days) (complete) – BR Powerflow & SC• Last Chance Data Submission Deadline: 12/13/2019* (complete) • Pass 2: 1/20/2020 – 2/07/2020 (15 days) (complete) – BR Powerflow & SC • Final Chance Data Submission Deadline: 2/07/2020** (complete) • Initial Final SC posted: 4/06/2020 – 4/10/2020 (5 days) (complete) – SC only• Initial Final BR Powerflow: 3/09/2020 – 3/20/2020 (10 days) (complete) – Approved via email• Updated Initial Final BR Powerflow posted: 5/15/2020• Initial Final BR Powerflow Re-approved: 6/18/2020• Initial Final SC Postings and Approval: Requested: 7/27/2020; approval delayed pending Section 10.3

updates being applied & models reposted• Final BR Powerflow & SC Approval with Oct. 2020 Board approved projects from 2020 ITP in Nov. 2020

• Staff Leader: David Duhart ([email protected])• Working Group Approval: TWG

* Last Chance - Data Submitters provide final Transmission Service Inputs (AG1) Data, review Pass 2 models/data submission through MOD, update load and generation reports/reconcile transaction discrepancies.** Final Chance - Data Submitters submit final generation dispatch, DocuCheck corrections and topology data updates through MOD and EDST.


102021 ITP

SITING PLAN• Start: 4/20/2020• End: 11/2/2020 (Members’ Final Approval)• Member Review Time:

• Site Repository: 5/21/2020 – 6/03/2020 (10 days)• Preliminary Siting Plan (Renewable): Post & Request Exceptions: 7/31/2020 – 8/13/2020• Site Assignment (Renewable) ESWG Review: 8/13/2020 – 8/19/2020 (5 days)• Site Assignment (Distributed Solar) Review: 8/17/2020 – 8/21/2020 (5 days)• Site Assignment (Renewable) & Exceptions: ESWG Review to Approve: 9/10/2020 – 9/16/2020 (5 days) • Site Assignment (Renewable/Distributed Solar): Updated/Reposted: 10/8/2020• Site Assignment (Renewable/Distributed Solar): ESWG Approval requested 10/21/2020 via email vote• Site Assignment (Conventional/Storage): Post & Request Exceptions: 10/23/2020 – 10/29/2020 (5 days)• Site Assignment (Conventional/Storage): Post for ESWG Approval: 10/29/2020 – 10/31/2020 (3 days)• Site Assignment (Conventional/Storage) ESWG Approval: 11/2/2020 request via email vote

• Staff Leaders: Joshua Norton ([email protected])

• Working Group Approval: ESWG


112021 ITP

GENERATOR OUTLET FACILITIES (GOFS) - (COMPLETE)

• Start: 4/9/2020• End: 11/03/2020 (Members’ Final Approval)

• Member Review Time: • Preliminary Renewable GOFs: Post for stakeholder Review: 10/07/2020 – 10/13/2020 (5 days)• TWG Meeting Review: 10/06/2020• GOFs: Post for Final TWG Review to Approve: 10/27/2020 – 11/3/2020 (5 days)• GOFs: TWG Post to Review for Approval: 11/03/2020 • GOFs: Stake holder Review to Approve: 11/4/2020 – 11/10/2020 (5 days)• GOFs TWG Request for Final Approval: 11/10/2020

• Staff Leaders: Brooke Keene ([email protected])

• Working Group Approval: TWG


122021 ITP

MARKET ECONOMIC MODEL BUILD• Start: 12/01/2019

• End: 3/1/2021 (Members Final Approval)

• Member Review Time: • Pass 1 (Year 2): 8/06/2020 – 8/14/2020 (6 days)• Pass 1 (Year 2) Updated: 8/24/2020 – 8/28/2020 (5 days)• Pass 1 (Year 2) Updated for Final Approval: 8/31/2020 – 9/04/2020 (5 days)• Pass 1 (Year 2) ESWG Final Approval: 9/04/2020• Pass 2 (Years 2/5/10): 1/13/2021 – 1/19/2021 (5 days)

* Schedule being reviewed for rebaseline

• Staff Leader: Charlton Hill ([email protected])



132021 ITP

MARKET ECONOMIC BENCHMARKING (COMPLETE)

• Start: 7/01/2020

• End: 11/23/2020 (Members’ Final Approval)

• Member Review Time:

• Pass 1: 10/07/2020 – 10/13/2020 (5 days)• Pass 2: Post for ESWG Final Review: 11/16/2020 – 11/23/2020 (5 days)• Pass 2: ESWG Request for Approval : 11/23/2020



13


142021 ITP

CONSTRAINT ASSESSMENT

• Start: 12/04/2020

• End: 2/24/2021 (Member’s Final Approval)

• Staff Leader: Ahmed M Al Azzawi ([email protected])



152021 ITP

MARKET POWERFLOW MODELS (MPM)

• Start: 11/12/2020


• Staff Leader: Michael Odom ([email protected])


15


162021 ITP

NEEDS ASSESSMENT

• Start: 11/18/2020

• End: 4/20/2021

• Staff Leaders:• BR and MP Needs: Joshua Pilgrim ([email protected])• Econ/Policy Needs: Neeya Toleman ([email protected])• Short-Circuit Needs: Nathan Bean ([email protected])• Operational Needs: Will Tootle ([email protected])

16





172021 ITP

DPP WINDOW

• Start: 3/19/2021 12:00 a.m.

• End: 4/17/2021 11:59 p.m.

• Member Review Time: • Transmission-planning response window (30 calendar days)

• Staff Leader: Tammy Bright ([email protected])

17


182021 ITP

SOLUTIONS DEVELOPMENT & TECHNICAL VALIDATION

• Start: 3/19/2021

• End: 5/15/2021

• Staff Leader: Maurisa Hughes ([email protected])

18


192021 ITP

SOLUTIONS EVALUATION

• Start: 3/23/2021• End: 6/11/2021

• Staff Leaders: • Reliability: Jacob Pannell ([email protected])• Economic/Policy: Neeya Toleman ([email protected])• Operational: Will Tootle ([email protected])• Short Circuit: Nathan Bean ([email protected])

19





202021 ITP

RELIABILITY PORTFOLIO DEVELOPMENT

• Start: 6/04/2021

• End: 7/23/2021


20


212021 ITP

ECONOMIC PORTFOLIO DEVELOPMENT (PROJECT GROUPING)

• Start: 6/04/2021

• End: 7/23/2021

• Staff Leader: Ahmed M. Al Azzawi ([email protected])

21


222021 ITP

STUDY COST ESTIMATES – ROUND 1

• TBD

• Staff Leader: John O’Dell ([email protected])

22


232021 ITP

PLANNING SUMMIT

• July 2021 – Date TBD


23


242021 ITP


• TBD


24


252021 ITP

OPTIMIZATION & PORTFOLIO CONSOLIDATION

• Start: 7/26/2021

• End: 8/13/2021

• Staff Leaders:• Ahmed M. Al Azzawi ([email protected])• Jacob Pannell ([email protected])

25



262021 ITP

PROJECT STAGING

• Start: 8/16/2021

• End: 8/27/2021

• Staff Leader: Jacob Pannell ([email protected])

26


272021 ITP

BENEFIT METRICS CALCULATION

• Start: 8/16/2021

• End: 9/15/2021

• Staff Leader: Krishada Watson ([email protected])

27


282021 ITP

STABILITY ANALYSIS

• Start: 8/16/2021

• End: 9/15/2021


28


292021 ITP

SENSITIVITY ANALYSIS

• Start: 8/16/2021

• End: 9/15/2021

• Staff Leader: James Lampley ([email protected])

29


302021 ITP

FINAL RELIABILITY ASSESSMENT

• Start: 8/16/2021

• End: 9/15/2021

• Staff Leader: Ahmed M. Al Azzawi ([email protected])

30


312021 ITP

RATE IMPACTS/ATRR

• Start: 8/30/2021

• End: 9/15/2021


31


322021 ITP

FINAL REPORT

• Start: 8/1/2021

• End: 10/01/2021

• Final ESWG/TWG Approval in Sept. 2021


32


332021 ITP

TWG/ESWG FINAL APPROVALS

• Start: 9/21/2021

• End: 10/01/2021

• Staff Leaders: • TWG – Adam Bell ([email protected])• ESWG – Joshua Norton ([email protected])

33



342021 ITP

MOPC AND SPP BOARD

• MOPC: 10/12-13/2021

• SPP Board: 10/26/2021

34


2021 ITP TARGET AREA DISCUSSIONJOSHUA PILGRIM

2

OVERVIEW

3

OVERVIEW

• Target Areas

• Comparisons

• Potential Additional Analysis

• How This Affects the 2021 ITP

4

TARGET AREAS

5

TARGET AREAS

• Bakken area (UMZ)• Experienced high load growth between the 2020 and 2021

model sets• Currently requires 2 SVCs included in the Year 10 Winter 2021

BR models to solve• SPS New Mexico

• 2020 ITP showed potential voltage collapse in Year 10 Summer models

• Currently requires 1 SVC included in the Year 10 Summer 2021 BR models to solve

6

SPS-NEW MEXICO

7

BAKKEN

8

TARGET AREA JUSTIFICATIONS

9

TARGET AREAS JUSTIFICATION

• Both areas have undergone localized load growth

• Both areas are showing indications of voltage collapse issues in later years

• Both require later-year voltage support being added to the model in order to solve, revealing the marginal voltage stability limits of the areas

• Bakken area is subject of a MOPC action item to incorporate winter peaking and generation issues

• During the 2020 ITP, the recommendation was to use the 2021 ITP to address uncertainties in eastern New Mexico

10

ADDITIONAL ANALYSES

11

ADDITIONAL ANALYSES

• New Mexico Interface• Base reliability:

• Implement interface definition that accounts for generation uncertainty by outaging Mustang combined cycle plant as a prior outage condition and running N-1

• Economic:• Interface Guidelines and Study Scope for solution evaluation

• AC Power transfer thermal and voltage analysis with 0.02 p.u. voltage safety margin applied to low voltage monitoring criteria

12

ADDITIONAL ANALYSES (CONT)

• Bakken Area• Base reliability

• Create similar prior outage conditions for consistency with SPS

• Economic• Create similar study scope to identify voltage stability limits

• AC Power transfer thermal and voltage analysis with 0.02 p.u. voltage safety margin applied to low voltage monitoring criteria

13

ADDITIONAL ANALYSES (CONT)

• Base Reliability and Market Powerflow reliability Needs Assessment (informational)• MOPC AI 302 (Cold weather-driven scenarios and contingencies)• Inclusion of higher order events for risk-based planning initiative

• Solution Development• Model-specific solution determination • Utilize informational needs

• Sensitivity analyses (as needed)

14

2021 ITP EFFECTS

15

NEEDS ASSESSMENT AND SOLUTIONS DEVELOPMENT CONSIDERATION

• Additional models will lead to reliability needs outside of the normal BR/MPM model sets

• Low voltages in these areas will be reported as potential collapse points due to the inclusion of fake voltage support

• Solutions in these areas will need to be able to take into account the full scope of the issues and assumptions in the area

16

RECOMMENDATION

17

RECOMMENDATION

• SPP recommends that these two areas be designated as the target areas for this study

18

NEXT STEPS

19

NEXT STEPS

• Provide more details around proposed additional analyses

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

2022 ITP

2022 ITP & 20-YEAR ASSESSMENT SCHEDULESDARA SOLOMON

DECEMBER 2020

22022 ITP

2022 ITP Schedule

2020 2022

Today

Jul Nov Mar Jul Nov Mar Jul

45% BR Powerflow & Short Circuit Model Builds (and Benchmarking)

75% Scope Development

45% Load and Generation Review

Resource PlanningSiting & Generator Outlet Facilities (GOFs)Market Economic Model Build (MEM) / BenchmarkingConstraint Assessment

Market Powerflow Models (MPM)Needs Assessment

Solutions Development and EvaluationPortfolio Development

Benefit Metrics

Sensitivity AnalysisStability Assessment

Staging & Rate Impacts

Final Report

2022 ITP Assessment

DPP Window

Final Reliability Assessments

Model Updates from 2021 ITP

Study Cost Estimates -

Round 1

Planning Summit

Study Cost Estimates -

Round 2

TWG/ESWG Final Approval

SPP Board ApprovalOct 25

MOPC ApprovalOct 12

32022 ITP

20-Year Assessment

2020 2022

Today

Jul Nov Mar Jul Nov Mar Jul

65% Scope Development

40% Load and Generation Review

Resource PlanningSiting & Generator Outlet Facilities (GOFs)Market Economic Model Build (MEM) / BenchmarkingConstraint AssessmentNeeds Assessment

Solutions Development and EvaluationEconomic Portfolio DevelopmentAPC Benefit MetricSensitivities AnalysisFinal Report

20-Year Assessment

Solution Submittals

TWG/ESWG Final Approval

SPP Board ApprovalOct 25

MOPC ApprovalOct 12

42022 ITP

SCOPE DEVELOPMENT• Start: 7/06/2020

• End: 1/13/2021 (Member’s Final Approval)• December 2020: TWG/ESWG approval• MOPC Approval: 1/13/2021

• Member Review Time:

• Staff Leader: Adam Bell ([email protected])

• Working Group Approvals: ESWG, TWG and MOPC


52022 ITP

BASE RELIABILITY POWERFLOW & SHORT CIRCUIT MODELS• Start: 7/06/2019• Initial Final Approval: 3/12/2021 (BR Powerflow) & 3/19/2021 (Short-Circuit)• Final Approval: 11/12/2021 (BR Powerflow) & 11/19/2021 (Short-Circuit)

• Member Review Time: • Pass 0 – Trial 1 (Posting: 7/17/2020): 7/20/2020 – 7/24/2020 (5 days)• Pass 0 – Trial 2 (Posting: 8/07/2020): 8/10/2020 – 8/28/2020 (15 days)• Pass 1 – Trial 1 (Posting: 9/25/2020): 9/28/2020 – 10/16/2020 (15 days)• Pass 1- Trail 1 (Short Circuit) (Posting: 9/29/2020): 9/30/2020 – 10/16/2020 (13 days)• Pass 1 – Trial 2 (Posting: 11/13/2020): 11/16/2020 – 12/11/2020 (20 days)• Final Submission Deadline: 12/11/2020*

• Pass 2 (Posting: 1/15/2021): 1/18/2021 – 2/05/2021 (15 days)• Final Submission Deadline: 2/05/2021**

• Final Initial ITP (Posting: 2/05/2021): 2/08/2021 – 2/19/2021 (10 days)• Final Initial BR Powerflow & Short-Circuit TWG Approval (Posting: 3/05/2021): 3/08/2021 – 3/12/2021 (5 days)• Final Initial Final Short-Circuit TWG Approval: 3/19/2021 • Final Approval after Oct. 2021 Board approved projects in Nov. 2021

• Staff Leader: David Duhart ([email protected])• Working Group Approval: TWG

* Data Submitters – Final Submission of Generator Additions, Retirements, Pmin & Pmax, Loads, and Interchange Corrections through MOD & EDST** Data Submitters – Final Submission of Generation Dispatch, Docucheck Corrections, MOD-033 Feedback & Topology data updates through MOD & EDST


62022 ITP

LOAD REVIEW• Start: 8/1/2020

• End: 3/22/2021 (Member’s Final Approval)• Member Review Time:

• Load Pass 1 – Trial 1: (Posting: 10/02/2020) 10/05/2020 – 10/16/2020 (10 days)• Load Pass 1 – Trial 2: (Posting: 11/20/2020) 11/23/2020 – 12/11/2020 (13 days)• Final Submission Deadline: 12/11/2020*• Load Pass 2: (Posting: 1/22/2021) 1/25/2021 – 2/5/2021 (10 days)• Final Posting for Approval: 3/12/2021• Final Load Pass – Stakeholder Review: 3/15/2021 – 3/19/2021 (5 days)• Final ESWG Approval: 3/22/2021

• Staff Leader: Brooke Keene ([email protected])



72022 ITP

GENERATION REVIEW• Start: 8/1/2020• End: 3/22/2021 (Member’s Final Approval)• Member Review Time:

• Generation Pass 1 – Trial 1: (Posting: 10/02/2020) 10/05/2020 – 10/16/2020 (10 days)• RAR & Waiver Request to Stakeholders: (Posting: 10/02/2020) 10/05/2020 – 10/16/2020 (10 days)• Generation Pass 1 – Trial 2: (Posting: 11/20/2020) 11/23/2020 – 12/11/2020 (13 days)• Final Submission Deadline: 12/11/2020*• Generation Pass 2: (Posting: 1/22/2021) 1/25/2021 – 2/5/2021 (10 days)• Final Posting for Approval: 3/12/2021• Final Generation Pass – Stakeholder Review: 3/15/2021 – 3/19/2021 (5 days)• Final ESWG Approval: 3/22/2021

• Staff Leader: Brooke Keene ([email protected])



82022 ITP

RENEWABLE POLICY REVIEW

• Start: 2/01/2021




8


92022 ITP

RENEWABLE RESOURCE PLAN – PHASE 1

• Start: 2/06/2021




7


102022 ITP

RENEWABLE RESOURCE PLAN – PHASE 2

• Start: 2/06/2021


• Staff Leader: Antonio Barber ([email protected])


7


112022 ITP

SITING PLAN & GENERATOR OUTLET FACILITIES (GOFS)

• Start: 3/01/2021• End: 7/08/2021 (Members’ Final Approval)




122022 ITP

MARKET ECONOMIC MODEL BUILD

• Start: 10/01/2020

• End: 12/10/2021 (Members’ Initial Final Approval)




132022 ITP

MARKET ECONOMIC BENCHMARKING

• Start: 5/13/2021




13


142022 ITP

CONSTRAINT ASSESSMENT

• Start: 08/02/2021


• Staff Leader: Neeya Toleman ([email protected])



152022 ITP

MARKET POWERFLOW MODELS (MPM)

• Start: 11/15/2021


• Staff Leader: Michael Odom ([email protected])


15


162022 ITP

NEEDS ASSESSMENT

• Start: 11/18/2021

• End: 3/08/2022

• Staff Leaders:• BR and MP Needs: Maurisa Hughes ([email protected])• Econ/Policy Needs: Greg Lampley ([email protected])• Short-Circuit Needs: Nathan Bean ([email protected])• Operational Needs: Will Tootle ([email protected])

16




172022 ITP

DETAILED PROJECT PROPOSAL (DPP) WINDOW

• Start: 3/09/2022 12:00 a.m.

• End: 4/07/2022 11:59 p.m.• Member Review Time:

• Transmission-planning response window (30 calendar days)


17


182022 ITP

SOLUTIONS DEVELOPMENT & TECHNICAL VALIDATION

• Start: 3/09/2022• End: 5/10/2022


18


192022 ITP

SOLUTIONS EVALUATION

• Start: 3/23/2022• End: 6/03/2022

• Staff Leaders: • Reliability: Jake Morris ([email protected])• Economic/Policy: Greg Lampley ([email protected])• Operational: Will Tootle ([email protected])• Short Circuit: Nathan Bean ([email protected])

19





202022 ITP

RELIABILITY PORTFOLIO DEVELOPMENT

• Start: 5/27/2022

• End: 8/01/2022


20


212022 ITP

ECONOMIC PORTFOLIO DEVELOPMENT (PROJECT GROUPING)

• Start: 5/27/2022

• End: 8/01/2022

• Staff Leader: Joshua Pilgrim ([email protected])

21


222022 ITP


• TBD


22


232022 ITP

PLANNING SUMMIT

• TBD


23


242022 ITP


• TBD


24


252022 ITP

OPTIMIZATION

• Start: 8/02/2022

• End: 8/08/2022

• Staff Leaders: Krishada Watson ([email protected])

25


262022 ITP

PORTFOLIO CONSOLIDATION

• Start: 8/09/2022

• End: 8/22/2022

• Staff Leaders: Jake Morris ([email protected])

26


272022 ITP

PROJECT STAGING

• Start: 8/23/2022

• End: 9/02/2022

• Staff Leader: Greg Lampley ([email protected])

27


282022 ITP

BENEFIT METRICS CALCULATION

• Start: 8/23/2022

• End: 9/21/2022

• Staff Leader: Jake Morris ([email protected])

28


292022 ITP

STABILITY ANALYSIS

• Start: 8/23/2022

• End: 9/21/2022


29


302022 ITP

SENSITIVITY ANALYSIS

• Start: 8/23/2022

• End: 9/21/2022

• Staff Leader: Jacob Pannell ([email protected])

30


312022 ITP

FINAL RELIABILITY ASSESSMENT• Start: 8/23/2022

• End: 9/21/2022

• Staff Leader: Joshua Pilgrim ([email protected])

31


322022 ITP

RATE IMPACTS/ATRR

• Start: 9/02/2022

• End: 9/16/2022

• Staff Leader: Jake Morris ([email protected])

32


332022 ITP

FINAL REPORT

• Start: 5/01/2022

• End: 10/01/2022

• Member Review:• Final ESWG/TWG Approval in Sept. 2022


33


342022 ITP

TWG/ESWG FINAL APPROVALS• Start: 9/21/2022

• End: 10/01/2022

• Staff Leaders: • TWG – Adam Bell ([email protected])• ESWG – Joshua Norton ([email protected])

34



352022 ITP

MOPC AND SPP BOARD

• MOPC: 10/12-13/2022

• SPP Board: 10/25/2022

35

362022 ITP

CONTACT INFODara Solomon, SPP [email protected]



2022 ITP2022 ITP & 20-YEAR ASSESSMENT: ELECTRIC VEHICLES AND ENERGY DEMANDOCTOBER 2020

JAKE PANNELL

22022 ITP

OBJECTIVES

• Projections

• Drivers

• State of the Footprint

• Methodology and Recommendation

3

2022 ITP

PROJECTIONS

42022 ITP

2022 ITP EV & ENERGY DEMAND: PROJECTIONS

52022 ITP


62022 ITP


58%

37%

13%

0%

10%

20%

30%

40%

50%

60%

70%

2025 2030 2040

Selected Global EV Market Share Projections

BNEF IEA (averaged) ORNL OPEC

72022 ITP


6028

2111155

11097

646

6212

0

2000

4000

6000

8000

10000

12000

2019 ITP 2020 ITP 2021 ITP

Historic SPP ITP F2 Energy Projections

Y5 Y10

8

2022 ITP

DRIVERS

92022 ITP

2022 ITP EV & DEMAND: DRIVERS

102022 ITP


Technology, Industry, Consumer

• $100/kWh ~2023• 90% cost

decrease over past 10 years

112022 ITP


Policy and Regulatory• March 31, 2020 U.S NHTSA and EPA issued the Safer

Affordable Fuel-Efficient (SAFE) Vehicles Rule for Model Years 2021–2026 Passenger Cars and Light Trucks. The final rule reduces the annual fuel economy improvement required for new passenger cars and light trucks from 5% to 1.5%, and projects essentially no increase in electric vehicle sales share by 2026 beyond the current level of 2%.

12

2022 ITP

STATE OF THE FOOTPRINT

132022 ITP

2022 ITP EV & DEMAND: STATE OF THE FOOTPRINT

0

1

2

3

4

5

6

7

8

9

0

100

200

300

400

2011 2012 2013 2014 2015 2016 2017 2018

SPP

Sale

s x 1

000

Nat

iona

l Sal

es x

100

0

EV Sales (BEV, PHEV) SPP and US

National SPP Weighted

142022 ITP


Average US EV Market Share

0.00%

0.20%

0.40%

0.60%

0.80%

1.00%

1.20%

1.40%

1.60%

SPP State EV Market Share:Weighted, Raw and US Average

SPP Population Weighted EV Share SPP Raw EV Share

152022 ITP


SPP,

0.2

9%

Inno

vato

rs, 3

%

Early

Ado

pter

s, 1

4%

Early

Maj

ority

, 34%

Late

Maj

ority

, 34%

Lagg

ards

, 16%

19,442

171,189

924,418

2,328,164 2,328,164

1,095,606

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

35.00%

40.00%

0

500000

1000000

1500000

2000000

2500000

SPP EV Sales Relative to Diffusion of Innovation Model SPP %

Population2018 Vehicle Registration SPP Weighted

Arkansas 62% 921,161 571,980

Iowa 32% 1,242,219 401,197

Kansas 100% 975,171 975,171

Louisiana 10% 1,389,249 136,205

Minnesota 3% 1,976,525 50,471

Missouri 48% 2,102,216 1,014,521

Montana 46% 452,845 207,672

Nebraska 100% 683,020 683,020

New Mexico 15% 655,766 98,875

North Dakota 97% 240,048 233,404

Oklahoma 100% 1,296,219 1,296,219

South Dakota 97% 358,859 348,253

Texas 10% 8,248,322 788,924

Wyoming 20% 203,546 41,628

Total 20,745,166 6,847,540

SPP Light Vehicle Registrations

16

2022 ITP

SPP METHODOLOGY

172022 ITP

2022 ITP EV & DEMAND: METHODOLOGY

The Bass Product Diffusion Model• A model for forecasting the adoption (first purchase) of an

innovation• Key parameters:

• Market size -> adopters -> m• Rate of spontaneous adoption -> innovators -> p• Rate of imitation of adoption -> imitators -> q

182022 ITP


153.02

201.09

m=207,911p=0.0025q=.3939

0%

1%

1%

2%

2%

3%

3%

4%

0

50

100

150

200

250

% o

f SPP

Mar

ket

Adop

tions

x 1

000

Bass EV Adoptions:Parameters Estimated (Sales~CSales+Csales2)

Actual Sales Actual Cumlative Sales Projected Sales Projected Cumulative Sales

192022 ITP


0.577 1.392 1.798 1.667 1.458 2.122 3.068

7.701 6.910

16

24

31

39

58.1

0

10

20

30

40

50

60

70

Sale

s x

1000

SPP EV Sales

SPP % Population 2018 Vehicle Registration SPP Weighted

Arkansas 62% 921,161 571,980

Iowa 32% 1,242,219 401,197

Kansas 100% 975,171 975,171

Louisiana 10% 1,389,249 136,205

Minnesota 3% 1,976,525 50,471

Missouri 48% 2,102,216 1,014,521

Montana 46% 452,845 207,672

Nebraska 100% 683,020 683,020

New Mexico 15% 655,766 98,875

North Dakota 97% 240,048 233,404

Oklahoma 100% 1,296,219 1,296,219

South Dakota 97% 358,859 348,253

Texas 10% 8,248,322 788,924

Wyoming 20% 203,546 41,628

Total 20,745,166 6,847,540

SPP Light Vehicle Registrations

202022 ITP


0.32

1.32

m=3,457,037p=0.0013

q=.40

0%

10%

20%

30%

40%

50%

60%

0

1

2

3

4

% o

f SPP

Mar

ket

Mill

ions

Bass EV Adoptions:Adjusted Data to 50% SPP Market

Sales Cumlative Sales Projected Sales Projected Cumulative Sales

212022 ITP


Assumptions:

SPP EV Cumulative Adoptions

• 2027 = 319,527 • 2032 = 1,321,403 • 2042 = 3,400,115

Avg. miles/person/yr = 13,476

Avg. energy/100 miles = 28.5 kWh

SPP Annual Energy (preliminary data)

• 2027 = ~330 TWh• 2032 = ~343 TWh• 2042 = ~369 TWh

EV Energy = SPP EV Total x Avg. miles/person/year x Avg. energy/mile

1,227.19

5,075.06

13,058.69

0.37%

1.48%

3.54%

0.00%

0.50%

1.00%

1.50%

2.00%

2.50%

3.00%

3.50%

4.00%

0

2000

4000

6000

8000

10000

12000

14000

2027 2032 2042

% o

f SPP

Ann

ual E

nerg

y

Ener

gy G

Wh

ITP 2022 EV Energy

222022 ITP

2022 ITP EV & DEMAND: RECOMMENDATION

SPP staff recommends using the projections from the Bass Model of Diffusion assuming a 50% EV market share, and applying the derived energy amounts to the F2 demand group structure via valley fill load shape adjustment.

• 2027 (Y5) – 0.37%

• 2032 (Y10) – 1.48%

• 2042 (Y20) – 3.54%

23

2022 ITP

APPENDIX

242022 ITP

2022 ITP EV & DEMAND: RECOMMENDATION

0

2000

4000

6000

8000

10000

12000

14000

2019 ITP 2020 ITP 2021 ITP 2022

SPP ITP Energy Projections

Y5 Y10 Y20

252022 ITP


262022 ITP


• Bass Product Diffusion Model• S(t) = [p + (q/m) N(t-1)] [m – N(t-1)]

• Estimating m, p, q via linear regression• S(t) = a + b * N(t-1) +c (N(t-1))2

• m = (-b +- (b2 – 4ac).5)/2c• p = a/m• q = -mc or b+p

272022 ITP


282022 ITP


292022 ITP


2022 INTEGRATED TRANSMISSION

PLANNING ASSESSMENT SCOPE

By SPP Engineering

Published on [DATE]

Version 0.1


REVISION HISTORY

Date or version number Author Change Description Comments

11/25/2020 v0.1 SPP Staff Initial Draft Scope Posted for stakeholder review


CONTENTS

Revision History ................................................................................................................................................................ i Section 1: Overview ........................................................................................................................................................ 3

Objective ............................................................................................................................................. 3 Section 2: Modeling Details and Assumptions .................................................................................................... 4

Market Economic Model Overview ...................................................................................................... 4 Futures ......................................................................................................................................... 4 External Load Forecasts ................................................................................................................ 6 Must-Run Units ............................................................................................................................ 6 Hurdle rates and interchange ....................................................................................................... 6

Resource Plan ...................................................................................................................................... 7 Conventional Generator Prototypes ............................................................................................. 7 Renewable Accreditation .............................................................................................................. 7 New Resource Allocation and Assignment .................................................................................... 8 Resource Plan Modeling ............................................................................................................... 9

Section 3: Solution Evaluation & Portfolio Development ............................................................................. 10 Persistent Economic Operational Solution Evaluations ....................................................................... 10

Flowgates ................................................................................................................................... 10 Manual Commitment of Generators ........................................................................................... 10

Consolidation .................................................................................................................................... 10 Section 4: Final Assessments ................................................................................................................................... 13

Sensitivities ....................................................................................................................................... 13 Voltage Stability Assessment ............................................................................................................. 13

Section 5: Schedule ..................................................................................................................................................... 14 Section 6: Changes in Process and Assumptions ............................................................................................. 16


2022 ITP Scope 3

SECTION 1: OVERVIEW

This document presents the scope and schedule of work for the 2022 Integrated Transmission Planning (ITP) Assessment. The Economic Studies Working Group (ESWG) and Transmission Working Group (TWG) are responsible for the creation and review of this document with approvals from the Market Operations and Policy Committee (MOPC) and the board of directors (Board).

OBJECTIVE The objective of the 2022 ITP Assessment is to develop a regional transmission plan that provides reliable and economic delivery of energy and facilitates achievement of public policy objectives, while maximizing benefits to the end-use customer. This 2022 ITP Assessment Scope contains assumptions to be utilized in the 2022 ITP Assessment that are not standardized in the ITP Manual. These documents should be reviewed together for a comprehensive view of the 2022 ITP process and assumptions.

https://www.spp.org/spp-documents-filings/?id=19027


2022 ITP Scope 4

SECTION 2: MODELING DETAILS AND ASSUMPTIONS

MARKET ECONOMIC MODEL OVERVIEW

FUTURES

The ESWG developed two futures with input from the Strategic Planning Committee (SPC) and TWG. The MOPC reviewed both futures in October 2020.

Reference Case Future (Future 1) The reference case future will reflect the continuation of current industry trends and environmental regulations. For years 5 and 10, subject to review from generator owners, coal generators over the age of 56 will be retired, while gas fired and oil generators over the age of 50 years will be retired. Exceptions will be allowed based on stakeholder-submitted, utility-specific integrated resource plans (IRP). Long-term industry forecasts will be used to determine coal prices. Natural gas prices will be determined per the ITP Manual. Solar and wind additions will exceed current renewable portfolio standards (RPS) due to economics, public appeal, and current trends as reflected in historical renewable installations and Generator Interconnection (GI) requests. Battery energy storage resources will also be included relative to the approved solar amounts.

Emerging Technologies Future (Future 2) The emerging technologies future will be driven primarily by the assumption that electrical vehicles and distributed generation will impact energy growth rates. Coal generators over the age of 52 will be retired, while gas-fired and oil generators over the age of 48 will be retired. Exceptions will be allowed as requested by generator owners and approved by the ESWG. As in the reference case future, current environmental regulations will be assumed and coal prices will use long-term industry forecasts. Natural gas prices will be determined per the ITP Manual. This future also assumes higher solar, wind, and energy storage resource additions than the reference case due to advances in technology that decrease capital costs and increase energy conversion efficiency. This future also accounts for the potential that state and/or federal policies will promote the utilization of these technologies in an effort to modernize the grid. This future will align the renewable resource potential with company IRP goals to the extent possible.

DRIVERS

KEY ASSUMPTIONS

Year 2 Future 1 – Reference

Case Future 2 – Emerging

Technologies 2 5 10 5 10

Peak Demand Growth Rates

As submitted in load forecast




2022 ITP Scope 5

DRIVERS

KEY ASSUMPTIONS

Year 2 Future 1 – Reference

Case Future 2 – Emerging

Technologies 2 5 10 5 10

Energy Demand Growth Rates



Increase due to electric vehicle growth

Natural Gas Prices Current industry forecast

Current industry forecast


Coal Prices Current industry forecast



Emissions Prices Current industry forecast



Fossil Fuel Retirements Current forecast

Coal age-based 56+, Gas/Oil age-based 50+,

subject to generator owner (GO) review

Coal age-based 52+, Gas/Oil age-based 48+, subject to GO review and ESWG

approval Environmental

Regulations Current regulations Current regulations Current regulations

Demand Response1 As submitted in load forecast



Distributed Generation (Solar)


As submitted in load forecast +300 MW +500 MW

Energy Efficiency As submitted in load forecast



Storage Existing + RARs 20% of projected solar (1.4 GW / 2.2 GW)

35% of projected solar (3.7 GW / 5.2 GW)

Total Renewable Capacity

Solar (GW) Existing + RARs 7 11 9 15

Wind (GW) Existing + RARs 33 36 38 42 Table 1: Future Drivers

1 As defined in the MDWG Model Development Procedure Manual: MDWG Manual

https://www.spp.org/spp-documents-filings/?id=18607


2022 ITP Scope 6

EXTERNAL LOAD FORECASTS

Table 2 details the data sources of load forecasts external to SPP for the Market Economic Models (MEM) and Market Powerflow Models (MPM) for the simulated regions.

External Entity Load Data Source

AECI 2021 Base Reliability Model2

MISO MTEP21

Manitoba Hydro MTEP21

TVA MTEP21 Table 2: External Load Data Sources

MUST-RUN UNITS

Must-run designations for SPP areas will be assigned to co-generation, nuclear, landfill gas, and hydroelectric units, unless an exception is requested during the generation review and approved by the ESWG. Co-generation units will be identified based on EIA 860 data, as well as ABB simulation-ready data. If a unit was originally identified as a must-run in a previous study, but was removed as an exception, it will not be identified as a must-run in the 2022 ITP. External areas will have the same criteria, with the deviation that external co-generation units will be assigned a must-run status subject to SPP review.

HURDLE RATES AND INTERCHANGE

Hurdle rates for all futures will be based upon the latest vendor data set. However, prior to and during the MEM benchmarking and initial year 5 and year 10 MEM builds, SPP and ESWG will be reviewing the reasonableness of the latest vendor data set hurdle rates and respective interchange. SPP and ESWG may utilize, as appropriate, previous ITP MEMs in this review. This review may result in adjustments to the MEM hurdle rates and/or other economic model parameters that impact MEM interregional “economy-energy” transactions. Any ESWG-approved adjustments and MEM interchange results will be documented in the ITP assessment report.

2 AECI actively participates in the SPP model development process that produces the base reliability model set.


2022 ITP Scope 7

RESOURCE PLAN

CONVENTIONAL GENERATOR PROTOTYPES

Generator prototype parameters will be set using the Cost and Performance Characteristics of New Generating Technologies, Annual Energy Outlook 2020 – EIA (EIA-AEO).3 Multi-shaft combined cycle (CC) and industrial combustion turbine (CT) prototypes will be used as the available alternatives. While both the multi-shaft CC and industrial CT prototypes were approved, the resource plan will initially consist of the industrial CT prototypes based upon a waiver of the ITP Manual requirement to use resource planning software. The waived requirement to utilize resource planning software was based upon historical performance of the resource planning software and the cost curves associated with the conventional prototypes considered for the 2022 ITP. If any exceptions for the resource plan are requested, the multi-shaft CC prototype data will be used. Table 3 details the characteristics of the approved prototypes, in 2019 dollars for currency values.

Generation Type Data

Source Technology

Type Size

(MW)

Total Capital

Cost ($/kW)

Variable O&M

($/MWh)

Fixed O&M

($/kW-yr)

Heat Rate (Btu/kWh)

Combined Cycle (CC)

EIA-AEO 2020 Multi-Shaft 1,083 $954 $1.86 $12.15 6,370

Combustion Turbine (CT)

EIA-AEO 2020 Industrial 237 $710 $4.48 $6.97 9,905

Table 3: Generator Prototype Parameters

RENEWABLE ACCREDITATION

Accreditation of existing renewable units will be determined by member data based on SPP Planning Criteria 7.1.6 (7)(8)4 submitted through the Generation Review. If no accreditation data is submitted for a resource then it will default first to previous ITP study data and secondly to the average of the submitted data for the existing resources in the 2022 ITP, capped at the accreditation values for projected resources. A projected resource that is assigned ownership to a load serving entity within the modeled SPP footprint is eligible for capacity credit. Projected wind, utility scale solar, and battery storage resources will have a stand-alone capacity accredited at 20, 70, and 100 percent, respectively. Total projected utility scale solar, wind, and storage will be accredited based on the approximate average effective load-carrying capability (ELCC) value for the respective resource. Projected wind and

3 https://www.eia.gov/outlooks/aeo/assumptions/pdf/table_8.2.pdf 4 SPP Planning Criteria

Commented [LG1]: TBD based on if a waiver is warranted

https://www.eia.gov/outlooks/aeo/assumptions/pdf/table_8.2.pdf

https://www.spp.org/Documents/58638/SPP%20Planning%20Criteria_V2.2_0316020.docx


2022 ITP Scope 8

battery storage accredited capacity used to meet load and reserve requirements will be capped at 12 percent of a load serving entity’s total load to reflect the assumption that the resources will not have transmission service and thus can only be used to meet the 12 percent reserve margin.

NEW RESOURCE ALLOCATION AND ASSIGNMENT

SOLAR WIND BATTERY STORAGE

ASSIGNED Yes No No

ALLOCATED Load-Ratio Share Based on Zonal Reserve Margin Load-Ratio Share

Table 4: Resource assignment and allocation

Projected utility scale solar will be assigned and allocated by load-ratio share. Projected wind will be unassigned and allocated to maximize accreditation to deficient zones. Projected battery storage will be unassigned and allocated by load ratio share. Policy additions will be met with 70 percent wind and 30 percent solar, based on the active, non-suspended GI queue requests. The accreditation process is as shown:

Figure 1: Accreditation process flowchart


2022 ITP Scope 9

RESOURCE PLAN MODELING

As noted in the ITP Manual, the MPM will contain system topology consistent with their respective MEM. This topology consistency does not include the reactive power settings of the resource plans because they are not considered in the MEM. The following parameters will guide how the resource plans, both internal and external, are modeled with regards to reactive settings, such as maximum and minimum VAR support and voltage schedule. Stakeholders are given the opportunity to review certain reactive device settings during the MPM review period described in Section 2.3.2 of the ITP Manual.

All resources included in the internal or external resource plans (excluding distributed generation, such as rooftop solar) will be modeled as directly injecting power at the point of interconnection (i.e., ESWG-approved site). Maximum and minimum reactive capability of generators will be determined by utilizing a .95 power factor and the maximum real power capability of the resource. Resources sited where existing generation is already interconnected will follow the voltage schedule and remote bus determination of the existing resource. The following information is resource fuel type specific and references settings observed in the powerflow modeling software utilized in the ITP process. The following settings apply to both the internal and external resource plans.

Conventional Generation The control mode for conventional generation will be set to “Not a wind machine.” The voltage schedule (i.e., vsched) will be set at 1.015 per unit for system peak models and 1.00 per unit for off- peak models, unless a voltage set point warning is observed. For sites with no existing generation, the remote bus will be the point of interconnection of the new resource.

Solar, Wind, or Energy Storage Resources The control mode for renewable and energy storage resources will be “+ or – Q limits based on WPF5”. WPF will be set at .95. The voltage schedule will be set at 1.015 per unit for system peak models and 1.00 per unit for off peak models, unless a voltage set point warning is observed. For sites with no existing generation, the remote bus will be the point of interconnection of the new resource.

5 Wind power factor


2022 ITP Scope 10

SECTION 3: SOLUTION EVALUATION & PORTFOLIO DEVELOPMENT

PERSISTENT ECONOMIC OPERATIONAL SOLUTION EVALUATIONS

FLOWGATES

Leading up to the 2022 ITP needs assessment, SPP will leverage the 2021 ITP economic operational needs assessment and solution evaluation outcome and continue to track on a quarterly basis operations and planning congestion throughout the 2021 ITP. SPP will make a recommendation to working groups on whether or not to address on as needed basis new and unresolved persistent operation economic congestion remaining after 2021 ITP persistent operation needs assessment and solution evaluation.

MANUAL COMMITMENT OF GENERATORS

Some transmission system issues require the manual commitment of generation by SPP in the Integrated Marketplace to provide relief on the system. The make-whole payments avoided when a proposed solution is included in the model will be considered in the solution’s benefit. Each solution’s one-year benefit-to-cost (B/C) ratio and its ability to reduce or eliminate the need for manual commitments will be considered during project selection.

CONSOLIDATION SPP must consolidate the future-specific portfolios into a single set of projects to determine a recommended plan. The methodology by which this consolidation will occur is based on individual project performance. A systematic approach to evaluate each project’s merits and an SPP-developed narrative of each project’s drivers will guide the decision for inclusion in the recommended plan. Three different scenarios could occur during the consolidation of the future-specific portfolios into a recommended plan:

1. The same project is addressing the same or similar needs in both futures 2. Different projects are addressing the same or similar needs in both futures 3. A project addresses certain needs only in one future

Projects applicable to scenario one will be considered for the recommended plan. Projects applicable to scenarios two and three will be given a score based on the point system detailed in Table 5. Each project will be awarded points based on its performance or ability to meet six different considerations, up to 100 total possible.


2022 ITP Scope 11

No. Considerations Points Possible Threshold

1

40-year (1-year) APC B/C in Selected Future

50

1.0 (0.9) 40-year (1-year) APC B/C in Opposite Future 0.8 (0.7) 40-year (1-year) APC Net Benefit in Selected Future ($M) N/A 40-year (1-year) APC Net Benefit in Opposite Future ($M) N/A

2 Congestion Relieved in Selected Future (by need(s), all years) 10 N/A Congestion Relieved in Opposite Future (by need(s), all years) 10 N/A

3 Operational Congestion Costs or Reconfiguration ($M/year or hours/year) 10 >0

4 New EHV 7.5 Y/N 5 Mitigate Non-Thermal Issues 7.5 Y/N

6 Long Term Viability (e.g. 2013 ITP20) or Improved Auction Revenue Right (ARR) Feasibility 5 Y/N

Total Points Possible 100 Table 5: Consolidation Considerations Scoring Table

For two projects (P1 and P2) applicable to scenario two, points for consideration one will be calculated as follows:

1. Test B/C thresholds in opposite future • If project has less than 0.8 40-year B/C in opposite future, zero points will be awarded • If project meets 0.8 40-year B/C threshold in opposite future, continue calculations

2. Calculate 40-year net adjusted production cost (APC) benefits • Net APC benefitP1,AVE • Net APC benefitP2,AVE • Net APC benefitMax = Maximum(Net APC benefitP1,AVE,Net APC benefitP2,AVE)

3. Calculate points awarded • 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑃𝑃1,% = 50 × 𝑁𝑁𝑁𝑁𝑁𝑁 𝐴𝐴𝑃𝑃𝐴𝐴 𝑏𝑏𝑁𝑁𝑏𝑏𝑁𝑁𝑏𝑏𝑏𝑏𝑁𝑁𝑃𝑃1,𝐴𝐴𝐴𝐴𝐴𝐴

𝑁𝑁𝑁𝑁𝑁𝑁 𝐴𝐴𝑃𝑃𝐴𝐴 𝑏𝑏𝑁𝑁𝑏𝑏𝑁𝑁𝑏𝑏𝑏𝑏𝑁𝑁𝑀𝑀𝑀𝑀𝑀𝑀

• 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑃𝑃2,% = 50 × 𝑁𝑁𝑁𝑁𝑁𝑁 𝐴𝐴𝑃𝑃𝐴𝐴 𝑏𝑏𝑁𝑁𝑏𝑏𝑁𝑁𝑏𝑏𝑏𝑏𝑁𝑁𝑃𝑃2,𝐴𝐴𝐴𝐴𝐴𝐴𝑁𝑁𝑁𝑁𝑁𝑁 𝐴𝐴𝑃𝑃𝐴𝐴 𝑏𝑏𝑁𝑁𝑏𝑏𝑁𝑁𝑏𝑏𝑏𝑏𝑁𝑁𝑀𝑀𝑀𝑀𝑀𝑀

For individual projects (P1) applicable to scenario three, points for consideration one will be calculated as follows:

1. Test B/C threshold in opposite future • If project has less than 0.8 40-year B/C in opposite future, zero points will be awarded • If project has at least 1.0 40-year B/C in opposite future, 50 points will be awarded • If project meets 0.8 40-year B/C threshold in opposite future, but is less than 1.0,

continue calculations


2022 ITP Scope 12

2. Calculate net APC benefits • Net APC benefitP1,AVE • Net APC benefitP1’,AVE = Net APC benefitP1,AVE with 1.0 40-year B/C in opposite future

3. Calculate points awarded • 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑃𝑃1,% = 50 × 𝑁𝑁𝑁𝑁𝑁𝑁 𝐴𝐴𝑃𝑃𝐴𝐴 𝑏𝑏𝑁𝑁𝑏𝑏𝑁𝑁𝑏𝑏𝑏𝑏𝑁𝑁𝑃𝑃1,𝐴𝐴𝐴𝐴𝐴𝐴

𝑁𝑁𝑁𝑁𝑁𝑁 𝐴𝐴𝑃𝑃𝐴𝐴 𝑏𝑏𝑁𝑁𝑏𝑏𝑁𝑁𝑏𝑏𝑏𝑏𝑁𝑁𝑃𝑃1′,𝐴𝐴𝐴𝐴𝐴𝐴

Points for consideration two will be calculated as the percentage of total congestion relieved on the needs addressed by the project, multiplied by the points possible.

𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎= 10 × % 𝐶𝐶𝑃𝑃𝑃𝑃𝐶𝐶𝑎𝑎𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑟𝑟𝑃𝑃𝑎𝑎𝑟𝑟𝑎𝑎𝑎𝑎𝐹𝐹1,𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑁𝑁𝑎𝑎𝑎𝑎𝑁𝑁𝑎𝑎 𝑏𝑏𝑁𝑁𝑁𝑁𝑎𝑎𝑎𝑎+ 10 × % 𝐶𝐶𝑃𝑃𝑃𝑃𝐶𝐶𝑎𝑎𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑟𝑟𝑃𝑃𝑎𝑎𝑟𝑟𝑎𝑎𝑎𝑎𝐹𝐹2,𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑁𝑁𝑎𝑎𝑎𝑎𝑁𝑁𝑎𝑎 𝑏𝑏𝑁𝑁𝑁𝑁𝑎𝑎𝑎𝑎

Points for consideration three will be calculated based on the severity of an operational issue that the project is expected to address, as a percentage of the operational needs criteria6 multiplied by the points possible, up to 10.

𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎 = �$ 𝑃𝑃𝑜𝑜 𝑐𝑐𝑃𝑃𝑃𝑃𝐶𝐶𝑎𝑎𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑐𝑐𝑃𝑃𝑃𝑃𝑃𝑃24 𝑚𝑚𝑚𝑚𝑏𝑏𝑁𝑁ℎ𝑎𝑎

$10𝑀𝑀 �× 10

OR

𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎 = �𝐻𝐻𝑃𝑃𝐻𝐻𝑎𝑎𝑃𝑃 𝑃𝑃𝑜𝑜 𝑃𝑃𝑠𝑠𝑃𝑃𝑃𝑃𝑎𝑎𝑠𝑠 𝑎𝑎𝑎𝑎𝑐𝑐𝑃𝑃𝑃𝑃𝑜𝑜𝑃𝑃𝐶𝐶𝐻𝐻𝑎𝑎𝑎𝑎𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃12 𝑚𝑚𝑚𝑚𝑏𝑏𝑁𝑁ℎ𝑎𝑎

𝑋𝑋%7 × 8,760� × 10

All points possible for considerations four, five, and six will be awarded if the project meets the description of the consideration.

For projects applicable to scenario two, the project with the highest score will be considered the favorable project based on the systematic approach. Projects applicable to scenario three with a total score of 70 or greater will be considered for the final recommended plan.

SPP may use engineering judgement or other analysis to support or oppose results of the systematic approach described above. SPP will bring consolidation results and a recommendation for all projects selected for a future-specific portfolio to the ESWG and TWG for review and feedback.

6 Flowgate congestion cost totaling more than $10M over the last 24 months or system reconfiguration through an agreed-upon operating guide implemented 25 percent of year.

7 X equals 25 percent for operational thermal issues. X equals 10 percent for operational voltage issues.


2022 ITP Scope 13

SECTION 4: FINAL ASSESSMENTS

SENSITIVITIES Sensitivities will be conducted on the final consolidated portfolio in both futures to measure the flexibility of the portfolio with respect to the uncertainties of certain assumptions. Economic analysis will be performed for the sensitivities below:

• High and low natural gas prices • High and low demand levels

These sensitivities will be applied to years 5 and 10 and will not be used to develop the transmission projects nor filter out projects. Additional futures relevant sensitivity analyses will be determined via stakeholder survey leading up to this analysis, and will be documented in the ITP assessment report.

VOLTAGE STABILITY ASSESSMENT A voltage stability assessment will be conducted in both futures using the final consolidated portfolio to assess the megawatt transfer limit under two scenarios:

• Increasing renewable generation in SPP and decreasing conventional thermal generation in SPP.

• Increasing renewable generation in SPP and decreasing conventional thermal generation in external areas.

The transfer limit will be determined by examining voltage performance during power transfers across SPP. The stability assessment consists of a dispatch analysis to determine if the dispatched generation in the year 10 summer and light-load models can be dispatched without the occurrence of voltage collapse or thermal violations.


2022 ITP Scope 14

SECTION 5: SCHEDULE

The 2022 ITP assessment began in July 2020 and will be completed by October 2022. Figure 2 and Table 6 detail the study timeline.

Figure 2: 2022 ITP Timeline


2022 ITP Scope 15

Milestone Name Group(s) to

Review/Endorse Start Date Completion

Date

Scope Development ESWG, TWG, MOPC, SPC Jul 2020 Jan 2021 Load and Generation Review ESWG, TWG, MDWG Jul 2020 Mar 2021 Renewable Resource Plan ESWG Jan 2021 Mar 2021 Conventional Resource Plan ESWG Jan 2021 Jun 2021 Siting Plan & Generator Outlet Facilities (GOFs) ESWG Mar 2021 Jul 2020 Powerflow Model Development TWG Jul 2020 Mar 2021 Short Circuit Model Development TWG Jul 2020 Mar 2021 Economic Model Development ESWG Jan 2021 Dec 2021 Model Benchmarking ESWG, TWG Dec 2020 May 2021 Model Updates after October 2021 MOPC/Board (NTC/Re-evaluations) TWG Oct 2021 Nov 2021

Constraint Assessment TWG Aug 2021 Dec 2021 Needs Assessments ESWG, TWG Nov 2020 Mar 2022 Detailed Project Proposal (DPP) Window ESWG, TWG Mar 2022 Apr 2022 Solutions Development ESWG, TWG Apr 2022 May 2022 Project Grouping ESWG, TWG Jun 2022 Jul 2022 Study Cost Estimates (Round 1) Jun 2022 Jun 2022 Summit Jul 2022 Jul 2022 Study Cost Estimates (Round 2) Jul 2022 Jul 2022 Final Reliability Portfolios TWG Jul 2022 Jul 2022 Portfolio Optimization / Consolidation ESWG, TWG Jul 2022 Aug 2022 Project Staging ESWG, TWG Aug 2022 Sep 2022 Benefit Metrics Calculations ESWG Aug 2022 Sep 2022 Stability Analysis TWG Aug 2022 Sep 2022 Sensitivity Analysis ESWG Aug 2022 Sep 2022 Final Reliability Assessment TWG Aug 2022 Sep 2022 Review Draft Report with Recommended Solutions ESWG, TWG Aug 2022 Sep 2022

Final Report with Recommended Solutions

ESWG, TWG Sep 2022 Sep 2022 RSC, SPC, SSC

October 2022 MOPC, SPP Board MOPC, SPP Board

Table 6: 2022 ITP Schedule


2022 ITP Scope 16

SECTION 6: CHANGES IN PROCESS AND ASSUMPTIONS

To protect against changes in process and assumptions that could present a significant risk to the completion of the 2022 ITP Assessment, any changes to this scope or assessment schedule must be appropriately vetted and follow the process outlined in the stakeholder accountability section of the ITP Manual.


2022 ITP

2022 ITPRENEWABLE POLICY REVIEWKRISHADA WATSON

DECEMBER 3-4, 2020

22022 ITP

OBJECTIVE

• Review Renewable Policy Review methodology

• Review milestone schedule

• Approve Renewable Policy Standards deviating from ITP Manual

32022 ITP

RENEWABLE POLICY STANDARDS FOR 2022 ITP

State RPS Type Generation Type

Capacity- or Energy- Based

Year 5 %

Year 10 %

Kansas Goal Both Capacity 20 20

Minnesota Mandate Both Energy 25 25

Missouri Mandate Both Energy 15 15

Montana Mandate Both Energy 15 15

North Dakota Goal Both Energy 10 10

New Mexico Mandate Both Energy 40 50

South Dakota Goal Both Energy 10 10

Texas Mandate Both Capacity 5 5

• States within SPP not included in this table are presumed to have no RPS requirement

• A generation type of “Both” indicates that it can be met by wind and/or solar

42022 ITP

RECOMMENDATION

• SPP Staff recommends deviating from the ITP Manual Renewable Policy Standards as presented on slide 3 for the 2022 ITP

52022 ITP

METHODOLOGY

• Based on the finalized load forecast

Load Review

Renewable Policy

Standards

Renewable Requirements (Capacity &

Energy)

62022 ITP

SCHEDULE

• Start: 2/01/2021


• Member Review Time: • Stakeholder Review: 3/15/2021-3/19/2021




7

2022 ITP

APPENDIX

82022 ITP

FULL ITP MANUAL LANGUAGE ON RENEWABLE POLICY REVIEW

2.2.1.3 Renewable Policy Review

After the forecasted load is finalized, renewable policy standards (RPS) will be assessed for utilities within the SPP footprint. The percentages in Table 3 will be used to calculate the mandate or goal for each utility residing in the listed states with respect to the load submitted as part of the SPP annual data request. For those utilities that span multiple states, the approved powerflow models and geographical information system (GIS) data will be used to calculate each utility’s load obligation in the corresponding state for purposes of calculating mandates and goals.

The values in Table 3 consider forward-looking legislation set by the states that either should be or must be met, depending on the state, in each of the study years. A generation type of “both” indicates the mandate or goal can be met by either wind or solar generation in the study. Both capacity- and energy-based mandates and goals will be assessed for fulfillment during development of the resource plan. Those that are energy-based also will be assessed during the policy needs assessment. States within the SPP footprint that are not included in Table 3 do not have RPS requirement for the purposes of this renewable policy review.

Renewable energy credits will be accommodated appropriately as provided to SPP.

If any significant changes to renewable mandates or goals occur during an ITP assessment, SPP stakeholders can bring them to the ESWG for review and potential approval for use in the ITP assessment. If exemptions to the mandates or goals are allowed (e.g. the applicable technology is cost prohibitive or municipals are exempt), those exemptions will be considered as SPP is notified during the renewable policy review.

Any resulting deviations from the standard values in Table 3 will be noted in the study report.

92022 ITP

HIGH-LEVEL OVERVIEW OF THE PROCESS


2022 ITP

2022 ITPRESOURCE PLAN – PHASE IKRISHADA WATSON

DECEMBER 3-4, 2020

22022 ITP

OBJECTIVE

• Review Resource Plan – Phase I (RP1) methodology• Review milestone schedule

32022 ITP

HIGH-LEVEL OVERVIEW OF THE PROCESS

• Resource additions will be included to meet renewable policy standards

• Shortfalls are met with 70% wind and 30% solar.• RP1 does not impact the total forced amount of renewables

42022 ITP

DIRECTLY IMPACTED MILESTONES

• Resource Plan Phase II• Siting Plan

RP1

RP2

Siting

52022 ITP

SCHEDULE

• Start: 2/06/2021• End: 3/22/2021 (Member’s Final Approval)• Member Review Time:

• Stakeholder Review: 3/15/2021-3/19/2021

• Staff Leader: Krishada Watson ([email protected])• Working Group Approval: ESWG



2022 ITP2022 ITP AND 20-YEAR ASSESSMENT LOAD AND GENERATION REVIEW UPDATEBROOKE KEENE

12/3/2020

22022 ITP

OBJECTIVE

• Milestone Update

• Schedule Review

32022 ITP

MINIMUM CAPACITIES

• Changing to a yellow (editable) field for potential incorporation in the 2022 ITP study• Reviewing currently in 2021 ITP MEM Benchmarking• Surveying in 2022 ITP Load and Gen Reviews to get a more

comprehensive response from stakeholders• Coordinating with MISO to address external minimum capacity

changes for External Generation Review

42022 ITP

FLEET PPA TAB

• This tab is used for Resource Planning purposes only • We will not include intra-zonal PPAs in this list• Unit specific contracts should be reflected in the Ownership &

Accreditation tab

52022 ITP

GEN REVIEW APPROVALS

• RAR and Waiver Applications will be reviewed will be reviewed and voted on at December ESWG meeting.

• Review the 2022 ITP age based retirement dates. Provide rationale for F2 updates and those will be reviewed and voted on at March ESWG meeting.

• Review Must Run designation. Exceptions will be reviewed and voted on at March ESWG meeting.

62022 ITP

SCHEDULE

• Generation Pass 1 – Trial 1• Posting 10/02/2020• Review 10/05/2020 – 10/16/2020

• Waiver Requests & RAR• Posting 10/02/2020• Applications Due via RMS 11/20/2020

• Generation Pass 1 – Trial 2• Posting 11/20/2020• Review 11/23/2020 – 12/11/2020

• Generation Pass 2• Posting 1/22/2021• Review 1/25/2021 – 2/5/2021

• Final Pass• Posting for Approval 3/12/2021• Review 3/15/2021 – 3/19/2021• Final ESWG Approval: 3/22/2021

Derek Johnson (NEER Transmission Services)

SPP Resource Addition Request

2022 ITP ESWG

December 2020

2

• Need/Request:– SPP request for stakeholder additions to the ITP Market Models

• Stakeholder materials on requested exceptions must include:– Generation interconnection status – PPA, firm service, or utility ownership information– Status of necessary regulatory filings and/or approvals– Procurement of financing– PTC safe harbor eligibility– Additional supporting information (public announcements, etc.)

NEER Resource Addition Request – 2022 ITP

3

Recommend adding the below projects:

• GEN-2016-149: Washington Republic 1 (aka High Banks Wind)• GEN-2016-150: Washington Republic 4 (aka High Banks Wind)

Resource Addition Request (RAR)

4

Recommendation: Add entire 604 MW site in all futures as posted

1. Nameplate capacity: 604 MW

2. POI: WERE Stranger Creek 345 kV

3. Generation interconnection: Executed GIA in April 2020

4. Target COD: December 2022

5. PPA: N/A

6. Regulatory filings and/or approval: All necessary filings are on target

7. Procurement of financing: Will be financed in December 2022

8. PTC safe harbor eligibility: Eligible –project received safe harbor turbines

High Banks Wind [GEN-2016-149 & GEN-2016-150]: Information

5

motion not to approve high banks RAR

Waiver & Resource Addition Request2022 ITP

ESWG & TWGJeremy Severson

2

BEPC Waiver/Resource Addition Request - 2022 ITP

• SPP request for resource additions– Looking for any PPA’s or self build projects

not currently in models• Project : 45 MW Combustion Turbine

– Located near Watford City, ND– In Service August 1, 2021– BEPC will own and operate

3

Lonesome Creek 6 Info• Gen Interconnection with SPP

– GEN-2020-014 - 45 MW’s• Currently in the DISIS-2020 cluster• Request is going through the Interim GI process

• Connects to Lonesome Creek 115 kV bus• Land

– Owned by BEPC– Site was planned for 6th unit during construction of first 5

units.• LCS 1 - 2013• LCS 2&3 - 2015• LCS 4&5 - 2017

• PSC application and air permits have been approved for LCS 6

4

Project in relation to transmission

5

LCS 6

6

November 2020 Progress

7

Gen Interconnect Issues

• The expectation is that the interconnection will NOT result in any GOFs.

8

Request

BEPC requests that the TWG and ESWG accept the resource addition request for the GEN-2020-014 (45MW CT) to be included in the 2022 ITP study.

11/20/2020

1

ITP22 Resource Addition Request

Enel Green Power North AmericaDecember 03, 2020

Rockhaven Wind

GEN-2017-027, 140 MW, POI Carter County 138 kV

• Generation interconnection status:

• Interim study in progress expected to be completed 1/31/2021 with Interim GIA to follow

• No upgrades required beyond POI

• Agreement in place with TO for construction of POI by 9/1/21. TO has procured major equipment for POI facility. Final payment in process.

• Off-take: Construction is approved independent of offtake status

• Procurement of financing: Balance sheet financing through Enel, full approval to build obtained, procurement contracts awarded, funding received to achieve 12/1/21 COD.

• Equipment: Executed a capacity reservation agreement with turbine supplier

20/11/2020 2

1

2

11/20/2020

2

Rockhaven Wind

GEN-2017-027, 140 MW, POI Carter County 138 kV

• Sponsored Upgrade request submitted related to project

• All pre-construction permits in place

• All land rights secured for construction of generator and facilities

Requesting: Include GEN-2017-027 in near-term economic models at 140 MW.

20/11/2020 3

3


20-YEAR ASSESSMENT FUTURES DEVELOPMENTESWG

DECEMBER 3, 2020

2

TOPICS

• Recap • Ongoing Planning Prioritization effort • Approved 20-Year Assessment Futures

• Re-baseline naming convention• 20-Year Assessment Futures Development Discussion

• Additional Future• Sensitivities

• Next Steps

3

20-YEAR ASSESSMENT RECAP

4

PLANNING PRIORITIZATION

• SPP staff is working internally to develop a proposal / work plan in regards to the planning prioritization discussions that took place at the ESWG in July and November• Targeting January 2021 MOPC and Board

• Depending on the outcome, SPP’s planning processes or initiatives could be impacted • Reduced scope, delayed schedule, reprioritization, etc.

5

APPROVED 20-YEAR ASSESSMENT FUTURES

• Approval of Future 4 Included a 93% to 95% Emission Reductions Target in 2042 from 2017 Levels

6

APPROVED 20-YEAR ASSESSMENT FUTURES - CONT.

• ESWG approved the following futures unanimously on November 23, 2020 • Future 1 – 2022 ITP Reference Case • Future 2 – 2022 ITP Emerging Technologies • Future 4 – Accelerated Decarbonization

• Including a 93% to 95% Emission Reductions Target in 2042 from 2017 Levels

7

NAMING CONVENTIONS RE-BASELINE

• Future 1 – 2022 ITP Reference Case

• Future 2 – 2022 ITP Emerging Technologies

• Future 3 – Accelerated Decarbonization • Including a 93% to 95% Emission Reductions Target in 2042

from 2017 Levels• Where F4 is mentioned in the Futures Template for this future it

would be revised to F3

8

20-YEAR ASSESSMENT FUTURES DEVELOPMENT

9

SPP-MISO JOINT FUTURE UPDATE

• MISO has plans to perform a “Long Range Plan” in 2021, 2022, and potentially beyond• Similar to SPP’s 20-Year Assessment

• SPP has reached out to MISO regarding our interest in a potential “Joint” Future • MISO is interested in further discussions to continue to discuss the

opportunity • Multiple different approaches could be utilized

• Joint Model, Joint Assumptions, Coordination • If this future is decided on, it will likely take longer to scope out

than the rest of the 20-Year Assessment

10

APPROACHES: JOINT MODEL, JOINT ASSUMPTIONS, COORDINATION

• Joint Model • Build a single Joint Model with MISO to represent a Future 4 in

the 20-Year Assessment • Similar to the “old” CSP process

• Joint Future• Build separate SPP and MISO models with jointly agreed on

assumptions • Coordination

• SPP only approach to build a model with the assumptions and inputs aligned with a MISO “LRP” model

11

20 YEAR ASSESSMENT MANUAL SENSITIVITY LANGUAGE

• The sensitivities will be used to measure the viability of the proposed transmission plan that is produced through the 20-Year Assessment• These sensitivities will not be used to develop the transmission

projects or filter out projects• Sensitivities, if needed, will be conducted on the project lists

for each scenario using the Scenario 1 model to assess how versatile the plan is in handling a range of uncertainties

12

EXPORT / HURDLE RATE SENSITIVITIES

• Export sensitivities can provide additional analysis into a portfolios ability to realize additional export benefit• Adjust hurdle rate prices and/or interregional constraints

• Used to adjust the net interchange between areas • Reduce external areas resource plan and increase installed

generation on SPP’s system• Different way to adjust the net interchange between areas • Ability to enforce additional exports over what adjusting

hurdle rates can realize

13

ADDITIONAL EXPORT / NEIGHBORING AREA CONSIDERATIONS

• SPP transmission planning studies typically focus on identifying projects that maximize benefits to the SPP region

• Given the interest in this study to evaluate export potential and other ongoing SPP initiatives, should additional focus be placed on maximizing or evaluating benefits to neighboring areas?• Futures development would not be impacted by this change• Project evaluation, project selection, and portfolio development would be

impacted • Two portfolios per future

• If this approach is agreed on, language can be placed in the scope to document the additional focus on neighboring areas

• Does this replace the need for an additional SPP-MISO future?

14

MOTION

Adopt 4th future based on MISO MTEP F3 with hurdle rate of 0 between MISO and SPP

Friendly amendment:

Adopt 4th future based on SPP F3 with hurdle rate of 0 between MISO and SPP

15

LOAD SENSITIVITIES

• Both high and low load projection sensitivities are currently performed in the ITP and can be applied to all 20-Year Futures

• Some stakeholders have expressed interest in an “Economic Downturn” Future • Low load sensitivities can serve to provide some additional

analysis into how the portfolios for each future might perform under low load growth and poor economic conditions

16

GAS PRICE SENSITIVITIES

• Both high and low gas price sensitivities are currently performed in the ITP and could be applied to all 20-Year Futures

• Some stakeholders have expressed interest in a future that reflects continued low gas prices • Low gas price sensitivities can serve to provide some

additional analysis into how the portfolios for each future might perform under sustained low gas prices

17

HIGH AND LOW RENEWABLES SENSITIVITIES

• Both high and low wind, solar, and storage capacity sensitivities are currently performed in the ITP and could be applied to all 20-Year Futures

• Typically in the ITP wind, solar, and storage sensitivities are run separate of each other

• Combinations of different renewable sensitivities could be utilized to provide additional analysis on the “gap” between Future 2 and Future 3

18

RETIREMENT SENSITIVITIES

• Age-based retirement sensitivities could be performed• Potential capacity replacement options for increased

retirements• Gas unit replacement at retirement sites• Increased renewables across footprint

• For decreased retirements, option to de-activate some resource plan units

19

RECOMMENDATION• SPP Staff recommends limiting the 20-Year Assessment Scope to the

previously approved Future 1, Future 2, and Future 3 with additional sensitivities and external benefit evaluation • SPP Staff recommends the ESWG approve the inclusion of the following

sensitivities in the 20-Year Assessment, and that the details / implementation of those sensitivities will be scoped out closer to the sensitivities milestone• Load • Hurdle Rate / Export • Gas Prices • Renewables • Retirement

• SPP Staff recommends including revisions in the study scope to document additional focus being placed on evaluating the benefit to neighboring areas

20

NEXT STEPS

• ESWG – January 4, 2020 • 20-Year Assessment Scope approval• 2022 ITP Scope approval

• January MOPC and Board • Planning Prioritization


1

2022 ITP

2022 ITP RESOURCE PLANNING SOFTWAREANTONIO BARBERDECEMBER 2020ESWG

22022 ITP

OVERVIEW

• Objective:• Discuss and approve waiver for resource

planning software in 2022 ITP

32022 ITP

ITP MANUAL LANGUAGE

42022 ITP

2022 ITP RESOURCE PLANNING SOFTWARE• Staff has discussed removing use of resource planning

software• Continued development of wind/solar,

implementation of ESRs will provide enough energy to supply system needs

• Porotype comparisons show Combustion Turbine (CT) as the viable resource

• Time & Money savings

52022 ITP

CONVENTIONAL GENERATION PROTOTYPESGeneration

Type Data Source Tech Type Size (MW) Total Capital Cost ($/kW)

V O&M ($/MWh)

F O&M ($/kW-yr)

Heat Rate (Btu/kWh) ITP Study

Combined Cycle (CC) Lazard 11 High 550 $1,333 $2.05 $5.64 6,900 2019

Combustion Turbine (CT) Lazard 11 Low 216 $820 $4.82 $5.13 10,300 2019

Gas Reciprocating

EngineLazard 11 Low 50 $897 $12.82 $17.94 8,500 2019

Combined Cycle (CC) EIA AEO ’18 Conv. 702 $1,007 $3.63 $11.39 6,600 2020

Combustion Turbine (CT) EIA AEO ’18 Adv. 237 $697 $11.08 $7.04 9,800 2020

Combustion Turbine (CT) EIA AEO ’19 Adv. 237 $691 $11.02 $7.01 9,800 2021

Combined Cycle (CC) EIA AEO ’19 Conv. 702 $999 $3.61 $11.30 6,600 2021

Combustion Turbine (CT) EIA AEO ’20 Industrial 237 $710 $4.48 $6.97 9,905 2022

Combined Cycle (CC) EIA AEO ’20 Multi Shaft 1083 $954 $1.86 $12.15 6,370 2022

62022 ITP EIA 2020 Annual Energy Outlook posted January 2020

$0.00

$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

$140.00

$160.00

$180.00

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Leve

lized

Bus

bar C

ost (

$/M

Wh)

Annual Capacity Factor

Levelized Busbar Costs for Combustion Turbine & Combined Cycle Units 30 Years, 8.0% Discount Rate, 2020$

EIA-Combined-cycle—Multi Shaft EIA-Combustion turbine—Industrial Frame

72022 ITP

RECOMMENDATION

SPP staff recommends a waiver of the ITP manual for the 2022 ITP requiring the use of resource expansion software


2020 ITP

BUTLER – TIOGA 138 KV2020 ITP

2

2020 ITP

BUTLER – TIOGA 138 KV

32020 ITP

OBJECTIVE/OVERVIEW

• Discuss Butler – Tioga 138 kV project history• Inform stakeholders on progress• Gather working group comments

• Why are we discussing today?• SPP Board of Directors deferred action on the Butler-Tioga 138

kV project due to the need for further refinement

42020 ITP

PROJECT HISTORY – 2019 ITP• SPP analyzed multiple options to address Butler – Altoona constraint

• Wreck-out/rebuild of Butler – Altoona• Wreck-out/rebuild of Butler – Altoona with re-termination to Tioga• Butler – Altoona “out-of-service”

• SPP discusses scope of projects, including re-termination “break-away” point near East Eureka

• Capital construction projects above did not meet B/C criteria• PST at Butler on the Butler-Altoona line selected for 2019 ITP portfolio

• Not approved for construction due to concerns about investment that does not address age and condition of the facility driving the need

52020 ITP

• Original scope of project from 2019 ITP

• Used for 2020 ITP modeling

• Used for 2020 ITP conceptual costs

EAST EUREKA

62020 ITP

PROJECT HISTORY – 2020 ITP• SPP re-analyzed most 2019 options

• Projects met requisite conceptual B/C ratios

• Discussed project with stakeholders at summit

• Includes wreck-out of Butler – Altoona• SPP models “break-away” point near East Eureka per 2019 ITP scope of re-termination option• Map does not reflect this (see map presented on next slide)

• Full project was incorrectly deemed potentially non-competitive, study estimate sent to Evergy

• SPP did not specify “break-away” point

• 2020 ITP report postings

• First draft posted with reference to tear down/rebuild of Butler – Altoona with “break-away” point of the line towards Tioga near East Eureka

• Second draft posted for working groups incorporated comments changing project narrative to specify re-direction of line towards Tioga at Yellow Jacket consistent with study cost estimate

72020 ITP

• Version of map included in all 2020 ITP documentation

NO ROUTE PREFERENCE

82020 ITP

• Version of map included in all 2020 ITP documentation, updated consistent with project list description

NO ROUTE PREFERENCE

92020 ITP

• General scope of project used for study cost estimate (simplified for map)

YELLOW JACKET

102020 ITP

PROJECT HISTORY – 2020 ITP• SPP posted updated report for ESWG/TWG approval with Evergy comments included

• From a modeling and benefit perspective, the different “break-away” points produce negligible differences in results

• ESWG/TWG approved “Yellow Jacket” project scope

• SPP discussed the project more and attempted to be more generic in terms of preference for “break-away” point

• Posted updated report for MOPC with generic point of re-direction towards Tioga, specifying “with the objective of minimizing transmission costs”

• MOPC approved no preference to “break-away” point project scope

• SPP continues to discuss project scope history and potential benefits/complications with different options

• Board of Directors defer action/approval on Butler-Tioga 138 kV

112020 ITP

INTERIM WORK

• Update to study cost estimates based on potentially competitive/non-competitive portions of top options

• More detailed discussions with engineering team on pros/cons of top options

• Additional cost/benefit analysis

• Discussions with SPP management, legal and regulatory


STRATEGIC ROADMAP DEVELOPMENT PROCESSERIN CATHEY, SENIOR MARKET DESIGN ANALYST

2

ORGANIZATIONAL INITIATIVE MANAGEMENT -BACKGROUND

3

VALUE AND AFFORDABILITY“SPP must understand its stakeholders’ and members diverse’ interests and consider competing demands and pressures as necessary and appropriate while ensuring the organization is positioned to create the sustainable, long-term value in which all stakeholders have an interest as a unified body.”• Stakeholders requested:

• Increased transparency regarding work

• Increased collaboration through vetting, approval, opportunity for input

• Increased transparency & consideration of initiative impact on budget

• Efficiency and improvement in RR process

• Clarity and improvement in stakeholder prioritization

• Streamlined stakeholder processes

4

Enhanced ValueProgrammatic data management & reporting

Proactive responsivenessImproved business cases, success measures

Efficient, effective, aligned processShared strategic vision & priorities

Effective engagement

Implement strategic &

tactical organizational

initiative management

Reengineer & align processes & stakeholder

engagement to gain efficiency & realize full

value

Roadblocks to measuring

value/success Competing misaligned priorities

Reactive

Lack of shared

strategic vision

SMART Organizational

Initiative Management

Depleted ValueConstraining manual processes

Strained responsivenessRework

Redundant/overlapping efforts & prioritiesConfusion

Ineffective engagement

Silos

Improving Organizational Initiative ManagementA holistic approach

5

ORGANIZATIONAL INITIATIVE MANAGEMENT

• Roadmap process is an input to Initiative Design Development Process, Project Process/Pipeline, & Budget process

• When initiatives are approved as RRs, Enhancements, Projects through the Initiative Design Development Process they are an input to Project Process/Pipeline & Budget Process

• Initiative Design Development, Project Process/Pipeline, & Budgeting Process run concurrently & information flows between the them

• Data management solution improves collection & maintenance of all data related to initiatives such that real-time reporting is possible

Select potential initiatives, based on vision and strategyValue/Impact assessmentSystem & resources

Develop, approve initiative designValue/Impact assessment (cost, system, & resources)Stakeholder prioritizationApproval, implementation, validation

Manages scope & budget for larger initiativesRuns concurrent w/Initiative Design & Development Process for RRs & enhancementsApproves business casesRecommends project budgets

Accounts for and reports cost related to initiativesApproves project budgetsApproves capital and operating budget

Roadmap Development

Process

Initiative Design Development

Process

Project Process & Project Pipeline

Budgeting Process

Organizational Initiative Data Mgmt

Organizational Initiative Data M

gmt

6

ROADMAP DEVELOPMENT PROCESS & DESIGN DEVELOPMENT PROCESS OVERVIEW

7

A living work plan for enhancing SPP’s future

Unified path to achieving strategic goals and creating sustainable long-term value

Evaluates initiatives both on their own merit and on how they support SPP’s strategy

Facilitates shared vision and informed decision making

Enhances ability to measure value and affordability

Diversified - strategic and tactical

Increases transparency & collaboration

Balances diverse stakeholder interests

Aligns with SPP’s strategic plan, budgets & portfolio management

Ensures focus on greatest area of need

Enhances coordination within SPP and Stakeholders

Flexible

Annually select, rank & approve initiatives

Provide education on submitted initiatives

Balance ad-hoc initiatives against approved roadmap initiatives

Monthly review progress & recommend adjustments

Proactively plan at stakeholder organizations

What is a Roadmap? Roadmap Benefits Stakeholders’ Role

Markets, Operations, Planning, Supply Adequacy

8

4. Stakeholder prioritization

quarterly review meeting

StakeholdersSPP

5. Implement & Validate

SPPStakeholders

Vendors1. Design research &

analysisStakeholders

SPP

2. Revision Request or

EnhancementStakeholders

SPP

3. ApproveMOPC

Board of directorsFERC

4. PrioritizeMar-April

Net-conference & In-person

5. ApprovalJuly

SPC/MOPC

1. Process TrainingSep-Nov

Net-conference

2. Submit/ Comment

Nov-JanRMS

3. EducationFeb-Mar

Net-conference

Monthly Reporting

Stakeholders, SPP RTO, SPP MMU submit initiatives

Multiple initiatives in design development at any given time

SPP Strategic Roadmap Development Process Design Development Process

2020-2021 Roadmap developed October through April

Roadmap

9

4. PrioritizeMar-April

Net-conference & In-person

5. ApprovalJuly

SPC/MOPC

1. Process TrainingSep-Oct

Net-conference

2. Submit/ Comment

Nov-JanRMS

3. EducationJan-Feb

Net-conference

Stakeholders, SPP RTO, SPP MMU submit initiatives

SPP Strategic Roadmap Development Process


• Annual Process• Identify and Prioritize what SPP will

research/analyze (consider) for design development

• 2-5 year work plan (Roadmap)• Flexible – Ad hoc initiative

management handled in design development process

• Input to Project Pipeline, Budget Process

• Early Awareness – SPP Leadership, Stakeholders, SPC, MOPC, Finance Committee

Stakeholder Input

Stakeholder Approval

SPP Leadership Approval

10

Training• Open forum• Stakeholder input• Development

process training, timeline, lessons learned

Submit• Qualified Entities

submit initiatives –SPP, MMU, Stakeholders• Anyone submits

comments• Request

Management System (RMS)• Standard

form/content• Supporting material

encouraged• Submit

new/modified initiatives• Data gathered

Education• Open forum at

Functional Area working groups• Rostered

stakeholders determine which initiatives move forward to rank & prioritization• Education &

Evaluation of initiatives• Submitters provide

education• Standard form &

content• Controlled time to

present• SPP provides

value/impact assessment•MMU advisory• Data gathered

Prioritize• Open Forum -

Functional Area working groups• Rostered

stakeholders - final Priority• SPP RTO & SPP

MMU priority submitted as informational• Online tool/survey• Results analysis,

check adjust• Existing initiatives

included, unless w/in18 months of MOPC approval• Required initiatives

not included• Programmatic tool,

multi-step subjective & quantitative criteria• Data gathered

Approve• SPC endorsed•MOPC approved• Approved roadmap

input to SPP PMO and Budgeting process

SPP Strategic Roadmap Development Process

11


• Roadmap initiatives analyzed per roadmap development process ranking/prioritization

• Initiatives appropriately pathed• Quantitative cost assessment• Implementation prioritization &

coordination• Validation• Ad Hoc Initiative Management• Input to Project Pipeline, Budget Process• Fine-tuned Awareness – SPP Leadership,

Stakeholders, SPC, MOPC, Finance Committee

Stakeholder Input

Stakeholder Approval

SPP Leadership Approval

4. Stakeholder prioritization

quarterly review meeting

StakeholdersSPP

5. Implement & Validate

SPPStakeholders

Vendors1. Design research &

analysisStakeholders

SPP

2. Revision Request or

EnhancementStakeholders

SPP

3. ApproveMOPC

Board of directorsFERC

Monthly Reporting

Multiple initiatives in design development at any given time

Design Development Process

12

Research & Analysis• Functional area

working groups• Timing based on

priority• Conceptual design

analysis• Value/Cost/Impact

analysis• Results determine

design development approach & path• Approved

whitepaper•MMU advisory• Training, legal,

compliance awareness• Data gathered• Reporting

Revision Request or Enhancement• Functional area

working groups• Policy developed

according to approved design approach• Cost Impact

Analysis• Existing stakeholder

service process depending on path, e.g., RR process, Enhancement, Project• Training, legal,


Approve•MOPC• FERC• Training, legal,


Stakeholder Prioritization• Implementation

timing• Stakeholder

prioritization quarterly process• Data gathered• Reporting

Implement & Validate• Coordinated

implementation –SPP staff, stakeholders• System change

development• Process change

development• Training, legal,

compliance, impacted SPP business functions and impacted stakeholder coordination• Testing• Validate design

operating as intended - SPP and stakeholders

Design Development Process

13

ROADMAP DEVELOPMENT PROCESS PHASES – CLOSER LOOK

14

• Initiative Submission• New or modifying existing• Only Qualified Entities may submit• Standard forms required• RMS• Supporting material highly

encouraged• SPP Roadmap Exploder

• Comment Submission• Anyone may submit comments• Standard forms and content required• RMS• Supporting material highly

encouraged• SPP Roadmap Exploder

Process Training

Submit or Comment Education Prioritize Approval Reporting

Nov Dec-Jan March April-May June-July On-going

Net-Conference RMS In-Person Net-Conference & In-Person

SPC/MOPC SPP.org

15

STRATEGIC ROADMAP QUALIFYING CRITERIAIf one or more of these criteria are met, the initiative should be assessed through the Roadmap Development Process

• New governing document language that results in more than a correction or clarification

• Required to correct a market inefficiency or gaming opportunity• FERC action or involves a NERC standard• BOD directive• Requires additional FTEs to manage in production • Requires member-facing or impacting system or process changes• Impacts long-term reliability

16

MANAGING AD HOC INITIATIVES – PROCESS OVERVIEWCase-by-case assessment1. Ad hoc initiative submitted

2. Assign primary functional area and primary stakeholder group

3. Review initiative with appropriate primary functional area stakeholder groupA. Does initiative align with roadmap qualifying criteria?

i. No, go to step 3Dii. Yes, go to step 3B

B. Assess initiativei. Initiative requires minimal effort, low impact, minimal or no system changes. Go to step 3D. ii. Initiative requires increased effort, greater impact, more involved system changes. Go to step 3C

C. Determine appropriate Roadmap rank/priority by affirmative vote (vote is optional)i. Add to existing initiativeii. Reprioritize roadmap to accommodate new initiativeiii. Add to Parking Lotiv. Reject/Recommend regular roadmap cycle submission

D. Design Development Process (Draft RR or Enhancement, submit project pipeline/budget awareness if appropriate)

Start

Path

Assign Primary

Func. Area Grp

Submit initiative

Enhancement

D

Roadmap Revision Request Public Data

A B C

Stakeholder review

SPP Rec.

17

INITIATIVE SUBMISSION FORMSubmit/ Comments

18

INITIATIVE COMMENT FORMSubmit/ Comments

19

ROADMAP QUICK PICK RMSSubmit/ Comments

20

• Initiative submitters required to provide education• In-person, open forum• Standard template and content• Stakeholders & SPP evaluate & finalize initiative list for ranking• SPP feedback provided on each submission during session• MMU advisory

Process Training




SPC/MOPC SPP.org

21

INITIATIVE EDUCATION SESSION TEMPLATEEducation

• Purpose

• Benefits

• Related Initiatives

• Value and Impact Assessment Summary

• SPP Comments

• MMU Comments

• Stakeholder Comments

22

ROADMAP VALUE & IMPACT ASSESSMENT

Roadmap rank &

prioritization

Impact

ValuePotential Impact• Design & Implementation

Complexity• System Impact• Resource Impact• Budget Impact• Functional Area Specific

Impacts• Example: Markets

• MCE Performance

Potential Value• Alignment Strategic Plan• Alignment MMU ASOM• Other Value – Resource/Budget• Functional Area Strategic Goal

Alignment• Example: Markets

• Enhancement Market Philosophy

• Market efficiency• Market reliability• Market transparency• Price formation• Price convergence

23

• Prioritization of “what”

• Stakeholders, SPP, and SPP MMU will participate in ranking

• Online survey or prioritization tool

• Subjective and programmatic ranking – 4 tier methodology

Process Training




SPC/MOPC SPP.org

• Certain items may necessitate a “fixed” priority

• FERC Order• NERC Standard• BOD directive

• Initiatives near completion are not re-ranked, rank rolls forward

• Considering within 18 months from MOPC approval

24

Prioritize initiatives by applying a pool of pointsPlace initiatives in

numerical order of importance

Rate initiatives for relevance

INITIATIVE PRIORITIZATION

1) Subjective

2) Numerical Order

3) Point Pool Weighted

4) Step 2 & 3 Combined Weighted

Prioritize

RoadmapInitiatives prioritized by combined results of step 2 and 3

Survey Results

25

ROADMAP PRIORITIZATION - SUBJECTIVE• Includes one question - strongly agree, agree, disagree, or strongly

disagree

• Provides qualitative opportunity to indicate where initiatives should or should not be included• This initiative aligns with SPP’s Strategic Plan and meets the qualification

criteria, as defined in the Strategic Market Roadmap Development Process, to be included in the Strategic Market Roadmap

• Assign 1 point for Strongly Agree, 2 points for Agree, 3 points for Disagree, and 4 points for Strongly Disagree

26

ROADMAP PRIORITIZATION - NUMERIC• Involves placing initiatives in numerical order of importance

• One (1) through X – where X is the total number of initiatives

27

ROADMAP PRIORITIZATION – POINT POOL• Using a point pool to indicate importance

• Higher amount of points applied results in a higher ranking

• Point pool determined by applying a factor equal to 5 times the total number of initiatives. • Point cap per initiative enforced to ensure sufficient

number of initiatives ranked • Point cap equal to 30% of total point pool • Must use all points • May not use same amount of points on any two

initiatives, unless zero • Initiatives receiving zero points from all respondents

will be removed from the list

Example

Point Pool Calculation:

• 33 initiatives * 5 = 165 point factor

• 33 initiatives * 165 point factor = 5,445 total point pool

Point Cap Calculation:

• 5,445 total point pool * 30% cap = 1,634 point cap

28

ROADMAP PRIORITIZATION - COMBINED• Numerical and point pool combined weighted prioritization

• SPP inputs stakeholders’ results to prioritization tool

• Initiative prioritization combined from both the numeric order and point pool prioritization steps

• Tool programmatically determines final proposed initiative prioritization for stakeholder review, check and adjust

29

ROADMAP PRIORITIZATION• The roadmap is a relative priority of what initiatives will be considered

and when

• Initiatives may be grouped and aligned • Some may run simultaneously• Others may need to occur before or after another

• Dynamic environment with diverse and changing needs requires flexibility• Ad hoc initiative assessment• Resource constraints

30

• SPC ensures alignment with Strategic Plan

• SPC makes recommendation to MOPC

• MOPC review/approval

• Approved roadmap is input to SPP PMO, budgeting processes, stakeholder processes

Process Training




SPC/MOPC SPP.org

31

• Monthly Roadmap Initiative Status Report• Posted to SPP Roadmap page

• Changes highlighted and discussed at relevant stakeholder groups and MOPC

• SPP Roadmap Initiative Master List updated continuously• Serves as initiative dashboard

Process Training




SPC/MOPC SPP.org

32

YOUR ROLE AS FUNCTIONAL AREA REPRESENTATIVES

1) Submit Initiatives• Now – Jan. 15, 2021

2) Review submitted initiatives and provide comments• Now – Jan. 31, 2021

3) Participate in education session• February 23, 2021

4) MDAG rep individual informational prioritization of modeling initiatives• March 5 –March 17, 2021

5) Prioritize initiatives individually – TWG and ESWG• March 22 – April 9, 2021

6) Prioritize as a team – TWG, ESWG, and MDAG• May 17, 2021

7) Manage ad-hoc initiatives• Ongoing

TWG ESWGMDAG

33

RESOURCES & REFERENCE

34

ROADMAP WEBPAGE HTTPS://WWW.SPP.ORG/STAKEHOLDER-CENTER/SPP-ROADMAP/

• Process & Training• Initiative

Documentation• Forms and Templates• Timeline• Meeting Registration

https://www.spp.org/stakeholder-center/spp-roadmap/

35

ROADMAP COMMUNICATIONHTTPS://WWW.SPP.ORG/STAKEHOLDER-CENTER/EXPLODER-LISTS/

• Notification via “SPP Exploder

• Roadmap Training• Initiative Submission• Initiative Comment• Timeline• Meeting Registration• Roadmap approval• Ad hoc

additions/changes to prioritization

https://www.spp.org/stakeholder-center/exploder-lists/

36

STRATEGIC MARKET ROADMAP RESOURCES/REFERENCE• SPP Roadmap Webpage

• Forms• Process• Training• FAQ• Initiative Candidate List• Initiative Master List

• SPP Roadmap Exploder• Request Management System• Erin Cathey – [email protected]

https://www.spp.org/stakeholder-center/spp-roadmap/

https://www.spp.org/stakeholder-center/exploder-lists/

37

APPENDIX

38

ROADMAP DEVELOPMENT ANALYSIS (MARKET ROADMAP)

39

Requesting SPC endorsement of the “2020 Strategic Market Roadmap”

40

ROADMAP RANKING & PRIORITIZATION• MWG, SPP RTO Staff, SPP MMU Staff, interested stakeholders

• 53 Initiatives submitted, evaluated in education (1) and ranking & prioritization sessions (2)

• Removed 9 initiatives• Combined 13 initiatives

• 44 Initiatives ranked and prioritized

• 3 priority buckets

• 2019-2024

High Priority19 Initiatives (9

HITT)2019-2020

Medium Priority

22 Initiatives2020-2024

Parking Lot3 Initiatives

No Schedule

41

ROADMAP RANKING & PRIORITIZATION• Initiatives evaluated for value and impact

• Alignment with Strategic Plan• Alignment with MMU issues and ASOM recommendations• Enhancement of Key Market Philosophies

• Market Reliability• Market Efficiency• Market Transparency• Price Formation• Price Convergence

• Potential Impact• Design and Implementation Complexity• MCE Performance• System Changes

• Other Functional Area Impacts (Planning and Operations)

Transparent and Collaborative

MWG Members and StakeholdersSPP RTO Staff

SPP MMU Staff

42

ROADMAP RANKING & PRIORITIZATION RESULTS

Market Efficiency

36%

Market Reliability…

Price Formation24%

Market Transparency

12%

Price Convergence6%

Market Philosophy Enhancements

Market Efficiency Market Reliability Price Formation Market Transparency Price Convergence

• 36% potentially enhance market efficiency (38/44)

• 24% potentially enhance price formation (25/44)

• 22% potentially enhance market reliability (23/44)

• 12% potentially enhance market transparency (13/44)

• 6% potentially enhance price convergence (6/44)

• Not included - 2/44 decrease Market Transparency and 4/44 increase risk of opportunity for Market Manipulation

43


0%

10%

20%

30%

40%

50%

60%

70%

80%

0

5

10

15

20

25

30

35

Reliabilityassurance

Maintaining aneconomical,optimized

transmissionsystem

Enhance andoptimizing

interdependentsystems

Enhancingmember value and

affordability

Alignment with Foundational Strategies

Foundational Strategy Initiative Alignment

• 50% - Align with “Reliability Assurance”• Integration of VERS, Security Resilience, Reliability

Excellence, and/or Regional Resource Needs

• 73% - Align with “Maintaining an economical, optimized transmission system”

• ARR/TCR Feasibility, Optimized Strategies for the Future, and/or Value Pricing

• 20% - Align with “Enhance and Optimizing Interdependent Systems”

• Transmission (Seams), Optimize Markets Efficiencies Along the Seams, and/or Grid Resilience

• 5% - Align with “Enhancing Member Value and Affordability”

• Communication Strategy, PMO Best Practices, and Strategic Membership Expansion

44


0%

5%

10%

15%

20%

25%

30%

35%

40%

0

2

4

6

8

10

12

14

16

18

Incentives forresourceadequacycapacity

Distortion ofprices by self-

committedgeneration

Under-schedulingwind resources

DA

Analyzing &address seams

issues

Improve priceformation inemergency

conditions &scarcity events

Incentivizecapacity

performance

Address &improve outage

coordinationmethodology

MMU Issues & ASOM Recommendation Alignment

MMU Issues & ASOM Recommendations Initiative Alignment

• 36% address “Incentives for resource adequacy capacity” (16/44)

• 27% address “Incentivize capacity performance” (12/44)

• 20% address “Analyzing and addressing seams issues” (9/44)

• 16% address “Improve Price formation during emergency conditions and scarcity events” (7/44)

• 16% address “Update and improve outage coordination methodology” (7/44)

• 14% address “Distortion of prices by self-committed generation” (6/44)

• 7% address “Under-scheduling of wind resources in DA” (3/44)

45


High32%

Medium41%

Low25%

None2%

Design Complexity

High Medium Low None

High30%

Medium36%

Low32%

None2%

Implementation Effort


• High - 32% potentially involve a highly complex process to research and analyze design options (14/44)

• Medium - 41% potentially involve a moderately complex process to research and analyze design options (18/44)

• Low – 25% potentially involve a minimally complex process to research and analyze design options (11/44)

• None – 2% will not involve any level of complexity to research and analyze design options (1/44)

• High - 30% potentially involve a highly complex process to implement the chosen design (13/44)

• Medium – 36% potentially involve a moderately complex process to implement the chosen design (16/44)

• Low – 25% potentially involve a minimally complex process to implement the chosen design(14/44)

• None – 2% no level of complexity to implement (1/44)

46


High32%

Medium18%

Low43%

None7%

Overall Market SW Impact


High7%

Medium25%

Low66%

None2%

Number of Systems Impacted


• High – 32% potentially highly impact MCE performance (14/44)

• Medium – 23% potentially moderately impact MCE performance (10/44)

• Low – 23% potentially minimally impact MCE performance (10/44)

• None – 23% will not have an impact on MCE performance (10/44)

• High – 32% potentially require highly involved system changes (14/44)

• Medium – 18% potentially require moderately involved system changes (8/44)

• Low – 43% potentially require minimally involved system changes (19/44)

• None – 7% will not impact systems in a substantial way (3/44)

• High – 7% impacted a high number systems (3/44)

• Medium – 25% impacted a moderate number of systems (11/44)

• Low – 66% impacted a low number of systems (29/44)

• None – 2% did not have system impacts (1/44)

1-6 systems = L 7-14 systems = M 15-22 systems = H

High32%

Medium23%

Low23%

None23%

MCE Performance Impact


47

Rank Initiative Est. Start Est. MOPC Approval SPP MWG MMU All

1 SIR 19 - HITT R4: Implement Uncertainty Market Product 2019 2020 1 3 1 1.72 SIR 17 - HITT R3b: Implement Marketplace Enhancements: Fast Start Resources (Enhancement) 2019 2020 2 2 3 2.33 SIR 12 - HITT M1: Implement Congestion Hedging Improvements 2019 2020 3 8 6 5.74 SIR 18 - HITT R3c: Implement Marketplace Enhancements: Multi-Day Market (Phase 1 and 2) 2019 2022 4 1 2 2.35 SIR 16 - HITT R1-2: Study & Implement ERS/ORS Compensation Models Based on Study Results (Phase 1 & 2) 2019 2022 5 6 8 6.3

6 SIR 15, SIR 28, SIR 41-HITT M4: Study Eco Evaluations of Reliability, Outage Mitigation, TOP Incentives (Phase 1) 2019 2020 7 5 7 6.3

7 SIR 13, SIR 50-HITT M2: Study Offer Reqs for VERs, incentive for Renewables in Day Ahead Market (Phase 1) 2019 2021 6 4 4 4.7

8 SIR 14 - HITT M3: Study Mitigation of Unduly Low Offers that Create Uneconomic Dispatch 2019 2021 8 7 5 6.79 SIR 30 - HITT S3: Energy Storage Resources and ESR Phase 2 (phase 1) 2020 2021 9 10 12 10.310 SIR 7, SIR 9 - Decommitment and Enhanced Commitment 2020 2021 13 11 11 11.711 SIR 35 - Reduce Self-Commitments and Consider Extending DA Market 2020 2021 14 9 18 13.712 SIR 38 - RTBM Submit Timing and SIR22 - Limit Market Power Through Physical Parameters 2020 2021 16 13 19 16.013 SIR 24, SIR 45 - MCR Design Expansion and Enhancements & MCR Logic 2021 2022 21 16 16 17.714 SIR 32 - Price formation During Conservative Operations and Emergency Conditions 2020 2022 18 12 20 16.715 SIR 29 - Overlapping Congestion Across Seams 2021 2022 15 15 24 18.016 SIR 8 - Distributed Energy Resources for Markets 2021 2023 11 23 22 18.717 SIR 36 - Reg-up for VERS 2021 2022 10 34 15 19.718 SIR 42 - Transactional Incentives and Scheduling Inefficiencies (Phase 1) 2019 2020 24 19 9 17.319 SIR 20 - Improved Economic Incentive of Regulation Mileage 2021 2022 20 20 21 20.320 SIR 53 - Cost Allocation 2024 2026 38 27 23 29.321 SIR 44 - Ancillary Service Buyback Risk 2021 2022 27 18 17 20.722 SIR 25 - DC TIE Optimization 2021 2022 17 16 37 23.323 SIR 5 - Coordinated Transaction Scheduling 2022 2024 32 23 13 22.724 SIR 10 - FFE Exchange Process 2021 2022 12 30 26 22.6725 SIR 31 - Pre Synchronization Unit Commitment 2022 2023 27 27 27 27.026 SIR 6 - DA Must Offer and Physically Withholding 2022 2023 19 18 17 18.027 SIR 51 - Dynamic Scheduling Interchange 2023 2024 23 32 28 27.728 SIR 52 - DVER Ramp Rate Limits 2022 2023 27 23 14 21.329 SIR 21, SIR 49 - Interface Pricing & Interfacing Pricing Granularity 2022 2024 22 21 24 22.330 SIR 11 - Generalized DC 2024 2025 28 31 32 30.331 SIR 23 - Market-to-Market Allocations 2022 2023 28 28 28 28.032 SIR 37 - Resource Ramp Rate Interaction 2023 2024 31 26 27 28.033 SIR 1 - Actual meter data for Initials and State Estimator Load Value Tolerance 2024 2025 41 21 31 31.034 SIR 34 - Real-Time Hedging Product 2022 2024 25 13 39 25.7PL SIR 33 - Protect Day-Ahead Margin TBD TBD 29 37 29 31.7PL SIR 3 - Cold Start Logic TBD TBD 33 27 37 32.3PL SIR 47 - Enhanced Visual Tools SPP Website TBD TBD 37 29 34 33.3

48

2019 – 2020• 14 Initiatives ongoing/new, includes 9 HITT initiatives

Rank Initiatives Est. Research and Analysis Start

Est. MOPC Approval

1 SIR 19 - HITT R4: Implement Uncertainty Market Product 2019 2020

2 SIR 17 - HITT R3b: Implement Marketplace Enhancements: Fast Start Resources (Enhancement) 2019 2020

3 SIR 12 - HITT M1: Implement Congestion Hedging Improvements 2019 2020

4 SIR 18 - HITT R3c: Implement Marketplace Enhancements: Multi-Day Market (Phase 1 and 2) 2019 2022

5 SIR 16 - HITT R1-2: Study and Implement ERS and ORS Compensation Models Based on Study Results (Phase 1 & 2) 2019 2022

6 SIR 15, SIR 28, SIR 41 - HITT M4: Study Eco Evaluations of Reliability, Outage Mitigation, TOP Incentives (Phase 1) 2019 2020

7 SIR 13, SIR 50 - HITT M2: Study Offer Reqs for VERs, Incentive for Renewables in DA Market (Phase 1) 2019 2021

8 SIR 14 - HITT M3: Study Mitigation of Unduly Low Offers that Create Uneconomic Dispatch 2019 2021

9 SIR 30 - HITT S3: Energy Storage Resources and ESR Phase 2 (phase 1) 2020 2021

10 SIR 7, SIR 9 - Decommitment and Enhanced Commitment 2020 2021

11 SIR 35 - Reduce Self-Commitments and Consider Extending DA Market 2020 2021

12 SIR 38 - RTBM Submit Timing and SIR22 - Limit Market Power Through Physical Parameters 2020 2021

14 SIR 32 - Price formation During Conservative Operations and Emergency Conditions 2020 2022

18 SIR 42 - Transactional Incentives and Scheduling Inefficiencies (Phase 1) 2019 2020

A living work plan for enhancing SPP’s Future

49

2019 – 2020SIR 19 - HITT R4: Implement Uncertainty Market Product H H H H H M H LSIR 17 - HITT R3b: Implement Marketplace Enhancements: Fast Start Resources (Enhancement) M H L M H H L L

SIR 12 - HITT M1: Implement Congestion Hedging Improvements M M NA H M L H LSIR 18 - HITT R3c: Implement Marketplace Enhancements: Multi-Day Market M H M H M H H LSIR 16 - HITT R1-2: Study and Implement ERS and ORS Compensation Models Based on Study Results H H M M M M H M

SIR 15 - HITT M4: Study Economic Evaluations of Reliability H H L H H H M HSIR 28 - Outage Mitigation M M L H H H L MSIR 41 - TOP Incentives M M L H H H H M

SIR 13 - HITT M2: Study Offer Requirements for VERs M H L L L L M L

SIR 50 - Incentive for Renewables in Day Ahead Market M M L M M M H LSIR 14 - HITT M3: Study Mitigation of Unduly L Offers that Create Uneconomic Dispatch H H NA L L L H LSIR 30 - HITT S3: Energy Storage Resources and ESR Phase 2 L H L H H H M LSIR 7 - Decommitment M M L H M H L MSIR 9 - Enhanced Commitment M M M H M M M LSIR 35 - Reduce Self-Commitments and Consider Extending DA Market M M H M M H M LSIR 38 - RTBM Submit Timing and SIR22 - Limit Market Power Through Physical Parameters M NA L M M L L LSIR 22 - Limit Market Power Through Physical Parameters M NA L M M L L LSIR 32 - Price formation During Conservative Operations and Emergency Conditions L M M M M L M LSIR 42 - Transactional Incentives and Scheduling Inefficiencies M M L L L L H L

1 2 3 4 5 6 7 8


• Potential Value Add 1. Market Philosophy

Enhancement2. Strategic Plan Alignment3. MMU

issue/recommendation alignment

• Potential Short-term impact4. Design Complexity5. Implementation

Complexity• Potential Long-term impact

6. MCE performance7. Overall system change8. Number of systems

changed

50

2021• 8 new initiatives planned to start, 9 initiatives ongoing Rank New Initiatives Est. Research and

Analysis StartEst. MOPC Approval

13 SIR 24, SIR 45 - MCR Design Expansion and Enhancements & MCR Logic 2021 2022

15 SIR 29 - Overlapping Congestion Across Seams 2021 2022

16 SIR 8 - Distributed Energy Resources for Markets 2021 2023

17 SIR 36 - Reg-up for VERS 2021 2022

19 SIR 20 - Improved Economic Incentive of Regulation Mileage 2021 2022

21 SIR 44 - Ancillary Service Buyback Risk 2021 2022

22 SIR 25 - DC TIE Optimization 2021 2022

24 SIR 10 - FFE Exchange Process 2021 2022


Ongoing Initiatives4 SIR 18 - HITT R3c: Implement Marketplace Enhancements: Multi-Day Market (Phase 1 and 2) 2019 20225 SIR 16 - HITT R1-2: Study and Implement ERS and ORS Compensation Models Based on Study Results (Phase 1 & 2) 2019 2022

7 SIR 13, SIR 50 - HITT M2: Study Offer Requirements for VERs, Incentive for Renewables in Day Ahead Market (Phase 1)

2019 2021

8 SIR 14 - HITT M3: Study Mitigation of Unduly Low Offers that Create Uneconomic Dispatch 2019 20219 SIR 30 - HITT S3: Energy Storage Resources and ESR Phase 2 (phase 1) 2020 202110 SIR 7, SIR 9 - Decommitment and Enhanced Commitment 2020 202111 SIR 35 - Reduce Self-Commitments and Consider Extending DA Market 2020 202112 SIR 38 - RTBM Submit Timing and SIR22 - Limit Market Power Through Physical Parameters 2020 202114 SIR 32 - Price formation During Conservative Operations and Emergency Conditions 2020 2022

51

2021 A living work plan for enhancing SPP’s Future







changed

SIR 24 - MCR Design Expansion and Enhancements M L M M M M L M

SIR 45 - MCR Logic H L M L L H M L

SIR 29 - Overlapping Congestion Across Seams M L L M L M L L

SIR 8 - Distributed Energy Resources for Markets M M L H H H H H

SIR 36 - Reg-up for VERS L M NA L L L L L

SIR 20 - Improved Economic Incentive of Regulation Mileage L L NA M L L L M

SIR 44 - Ancillary Service Buyback Risk M L NA L M M H L

SIR 25 - DC TIE Optimization L H L M M H L L

SIR 10 - FFE Exchange Process L M L M L L L L

1 2 3 4 5 6 7 8

52

2022• 7 new initiatives planned to start, 11 initiatives ongoing

Rank New Initiatives Est. Research and Analysis Start

Est. MOPC Approval

23 SIR 5 - Coordinated Transaction Scheduling 2022 202425 SIR 31 - Pre Synchronization Unit Commitment 2022 202326 SIR 6 - DA Must Offer and Physically Withholding 2022 202328 SIR52 - DVER Ramp Rate Limits 2022 202329 SIR 21, SIR 49 - Interface Pricing & Interfacing Pricing Granularity 2022 202431 SIR 23 - Market-to-Market Allocations 2022 202334 SIR 34 - Real-Time Hedging Product 2022 2024


Ongoing Initiatives4 SIR 18 - HITT R3c: Implement Marketplace Enhancements: Multi-Day Market (Phase 1 and 2) 2019 20225 SIR 16 - HITT R1-2: Study and Implement ERS and ORS Compensation Models Based on Study Results (Phase 1 & 2) 2019 2022

13 SIR 24, SIR 45 - MCR Design Expansion and Enhancements & MCR Logic 2021 202214 SIR 32 - Price formation During Conservative Operations and Emergency Conditions 2020 202215 SIR 29 - Overlapping Congestion Across Seams 2021 202216 SIR 8 - Distributed Energy Resources for Markets 2021 202317 SIR 36 - Reg-up for VERS 2021 202219 SIR 20 - Improved Economic Incentive of Regulation Mileage 2021 202221 SIR 44 - Ancillary Service Buyback Risk 2021 202222 SIR 25 - DC TIE Optimization 2021 202224 SIR 10 - FFE Exchange Process 2021 2022

53








changed

SIR 5 - Coordinated Transaction Scheduling M M L H H L L M

SIR 31 - Pre Synchronization Unit Commitment M L M M H H H M

SIR 6 - DA Must Offer and Physically Withholding L M L M L L M L

DVER Ramp Rate Limits M L L L L L L L

SIR 21 - Interface Pricing M M L M L L H L

SIR 49 - Interfacing Pricing Granularity M M L L L L H L

SIR 23 - Market-to-Market Allocations L L L H H L L L

SIR 34 - Real-Time Hedging Product L L NA M M H L M

1 2 3 4 5 6 7 8

54

2023• 2 new initiatives planned to start, 8 initiatives ongoing

Rank New Initiatives Est. Research and Analysis Start

Est. MOPC Approval

27 SIR51 - Dynamic Scheduling Interchange 2023 202432 SIR 37 - Resource Ramp Rate Interaction 2023 2024


Ongoing Initiatives16 SIR 8 - Distributed Energy Resources for Markets 2021 202323 SIR 5 - Coordinated Transaction Scheduling 2022 202425 SIR 31 - Pre Synchronization Unit Commitment 2022 202326 SIR 6 - DA Must Offer and Physically Withholding 2022 202328 SIR52 - DVER Ramp Rate Limits 2022 202329 SIR 21, SIR 49 - Interface Pricing & Interfacing Pricing Granularity 2022 202431 SIR 23 - Market-to-Market Allocations 2022 202334 SIR 34 - Real-Time Hedging Product 2022 2024

55








changed

Dynamic Schedule Interchange M M L M M M H M

SIR 37 - Resource Ramp Rate Interaction L L NA L H L L L

1 2 3 4 5 6 7 8

56

2024

• 3 new initiatives planned to start, 5 initiatives ongoingRank New Initiatives Est. Research and


20 SIR 53 - Cost Allocation 2024 202630 SIR 11 - Generalized DC 2024 202533 SIR 1 - Actual meter data for Initials and State Estimator Load Value Tolerance 2024 2025


Ongoing Initiatives23 SIR 5 - Coordinated Transaction Scheduling 2022 202427 SIR51 - Dynamic Scheduling Interchange 2023 202429 SIR 21, SIR 49 - Interface Pricing & Interfacing Pricing Granularity 2022 202432 SIR 37 - Resource Ramp Rate Interaction 2023 202434 SIR 34 - Real-Time Hedging Product 2022 2024

57

Cost Allocation M L NA H H M L H

SIR 11 - Generalized DC L M L H H H L M

SIR 1 - Actual meter data for Initials and State Estimator Load Value Tolerance NA NA NA L L L L L

1 2 3 4 5 6 7 8








changed

58

PARKING LOT

• 3 initiatives not plannedRank Initiatives Est. Research and


PL SIR 33 - Protect Day-Ahead Margin TBD TBDPL SIR 3 - Cold Start Logic TBD TBDPL SIR 47 - Enhanced Visual Tools SPP Website TBD TBD


59

QUESTIONSErin CatheySenior Market Design Analyst, MWG Staff [email protected]


SUMMARY OF MOTIONS AND ACTION ITEMS

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