Southwest Power Pool TRANSMISSION WORKING GROUP …

Southwest Power Pool TRANSMISSION WORKING GROUP MEETING

April 9, 2019 SPP Corporate Campus – Little Rock, AR

• Summary of Actions Taken •

1. Approved March 14th, 2019 TWG Minutes 2. Endorsed the Draft RR for Planning Criteria Section 7


April 9, 2019 SPP Corporate Campus – Little Rock, AR

• M I N U T E S •

Agenda Item 1 – Administrative Items Call to Order Chair Travis Hyde (OKGE) called the meeting of the Transmission Working Group (TWG) to order at 8:32 am. The following members attended or were represented by proxy (Attachment 01a – WebEx Attendance.xls):

Travis Hyde (Chair), Oklahoma Gas & Electric Nathan McNeil (Vice-Chair), Midwest Energy, Inc. Daniel Benedict, Independence Power & Light Scott Benson, Lincoln Electric System John Boshears, City Utilities of Springfield Missouri Derek Brown, KCP&L and Westar, Evergy Companies Jarred Cooley, Xcel Energy Cliff Franklin, Sunflower Electric Power Corporation Joe Fultz, Grand River Dam Authority James Ging, Kansas Power Pool Kalun Kelley, Western Farmers Electric Cooperative John Knofczynski, East River Electric Power Cooperative Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Jim McAvoy, Oklahoma Municipal Power Authority Matt McGee, American Electric Power Shane McMinn, Golden Spread Electric Cooperative Nate Morris, Empire District Electric Company Michael Mueller, Arkansas Electric Cooperative Corporation Gayle Nansel, Western Area Power Administration Chris Pink, Tri-State G&T Jason Shook, GDS Associates, Inc. Matthew Stoltz, Basin Electric Power Cooperative Michael Wegner, ITC Holdings Noman Williams, Gridliance High Plains LLC

Proxies The following proxies were provided for all or portions of the meeting: Full Proxy

• Derek Brown (WERE/KCPL Evergy) gave his proxy to Katy Onnen (WERE/KCPL Evergy). • Gayle Nansel (WAPA) gave her proxy to Josie Dagget (WAPA) • Dan Lenihan (OPPD) gave his proxy to Josh Verzal (OPPD)

Aaron Stewart, TWG staff secretary, informed Travis that the group had a quorum. Antitrust Guidelines Aaron Stewart (SPP) noted to the TWG that the agenda for the meeting included Antitrust Guidelines and reminded the group that certain topics were not allowed for discussion during the meeting. Meeting Materials Review Travis Hyde (OKGE) asked the group if there were any edits to or comments regarding the meeting materials. There was no further discussion. Previous Meeting Minutes Approval (Action Item) Travis Hyde (OKGE) asked the TWG if there were any comments or changes that needed to be made to the March 14th, 2019 TWG Minutes (Attachment 01b - Draft TWG Minutes March 14, 2019.docx). Hearing none, Travis requested a motion.

Motion: Scott Benson (LES) made a motion to approve the March 14th, 2019 TWG Minutes. Jason Shook (ETEC) seconded the motion. The motion was approved unanimously.

Agenda Item 2 – Gridliance High Plains 10.3 Waiver Request Jody Holland (GHP) provided the group with a presentation explaining a potential 10.3 waiver request (Attachment 02a - GHP 10.3 Waiver Request_TWG Presentation.ppt). He gave the group a list of the reasons driving this 10.3 request as well as the expectations Gridliance High Plains (GHP) has for SPP staff in their evaluation of the inclusion of Gridliance’s Local Planning Process (LPP) projects. Following Jody’s presentation, Kelsey Allen (SPP) presented SPP’s comments on GHP’s 10.3 Request (Attachment 02b - 2019_ITP_GHP 10.3 Request_SPP.pptx). Kelsey explained the need for SPP staff to assess the local area of these projects for potentially new regional needs and how the impacts to the ITP schedule and resources would be impacted if new regional needs were identified. Kelsey also explained that there should be minor impacts to the ITP schedule providing a no-harm look at GHP’s LPP projects and evaluating if any of these projects mitigate any needs that have already been identified in the study. Kelsey also explained that while GHP is not requesting an economic analysis, SPP deems it necessary to satisfy our Tariff obligations. This analysis is not expected to affect the ITP schedule. In conclusion Kelsey explained that the initial efforts can be done outside of the regional study process, however, if new regional needs are identified GHP would need to continue with a 10.3 request in the 2019 ITP, wait for evaluation in the 2020 ITP or work with SPP to develop alternatives that do not have major study impacts.

Agenda Item 3 – Proposed NTC Assignment from KPP to Gridliance Tony Green (SPP) presented a proposed assignment of NTC 200479 from KPP to Gridliance (Attachment 03a, 03b - NTC 200479 Assignment to GridLiance_final.pptx, KPP NTC Assignment to GridLiance SPP Report.pdf). Tony provided background information on the Business Practice (BP) 7070 that governs the assignment of NTCs. Tony also provided information on the proposed project for assignment. A question was asked about the rate impacts to the local area due to the assignment that were listed in the report and why those were not included in the presentation. Tony said that he would look into incorporating information on the rate impacts into the presentation.

Agenda Item 4 – Holistic Integrated Tariff Team (HITT) Update Casey Cathey (SPP) provided the TWG with a verbal update on the activities of the HITT. Specifically he spoke about the work the HITT is doing to improve the Generation Interconnection (GI) process. The recommendation coming from the HITT will be for the MOPC to create a task force to modify the ERIS and NRIS. The TWG will be called upon as a supporting group to this task force. Casey also spoke about the direction the HITT is moving in regards to establishing a single LPC within each pricing zone.

Agenda Item 5 – Alternative Solutions as Transmission Assets Micha Bailey, (SPP), provided the group with a presentation on alternative solutions as transmission assets and how those solutions will be considered in the ITP study (Attachment 05 – Alternative Solutions as a Transmission Asset.pptx). This topic was introduced to the group because of the tariff obligation to consider alternative solutions and due to batteries being submitted as solutions during the DPP window for the 2019 ITP. Micha explained that this discussion today was centered on starting the conversations that would be coming to the group at future meetings.

Agenda Item 6 – Material Modification Definition Micha Bailey (SPP) presented a draft Revision Request (RR) defining material modification to the group (Attachment 06a, 06b – RR Definition of Material Modification for Network Upgrades and Transmission Interconnection.docx, Definition of Material Modification for Existing Transmission or End-user Facilities_Clean_Copy.docx). There was a lot of discussion on the language that was presented and edits were made to the original language during the meeting. It was mentioned that data supporting the use of +/-30% change in impedance be provided to the group at the next meeting.

Agenda Item 7 – SPP-MISO JCSP Update Casey Cathey (SPP) provided the group with an update on the SPP-MISO JCSP (Attachment 07 – CSP Projects - ITP Final Portfolio.pptx). The determination of the SPP-MISO cost allocation will be occurring in the next phase of the study. Once this is complete, results of the CSP analysis and the recommended projects will be presented to the Interregional Planning Stakeholder Advisory Committee (IPSAC), the Joint Planning Committee (JCP) and then go through the appropriate channels for SPP and MISO regional approval. The SPP regional approvals are scheduled for October 2019 and the MISO regional approval is scheduled for December 2019. Following the presentation, a question was asked about how the cost allocation used in the CSP would be used in the 2019 ITP. It was explained that cost sharing is being considered for projects that are being analyzed in the ITP study that could potentially be selected in the CSP.

Agenda Item 8 – Planning Criteria Section 7.2 Draft RR Eric Ruskamp (LES) presented a draft RR to the Planning Criteria Section 7.2 to the group (Attachment 08 – Planning Criteria Section 7.2 RR Form-draft 20190228.docx). This was first introduced to the TWG during the March meeting and was brought back to the group seeking endorsement to move forward with an official RR. Once submitted as an official RR, this will be brought back to the TWG at a future meeting for final approval.

Motion: Nathan McNeil (MIDW) made a motion to endorse the draft RR to Planning Criteria Section 7.2. John Boshears (CUS) seconded the motion. The motion was approved unanimously with 1 abstention.

Agenda Item 9 – Written Reports There was no discussion on the materials included in the written reports (Attachment 09a, 09b – 2019 ITP Schedule.pptx, 2020 ITP Schedule.pptx).

Agenda Item 9 – Closing Items Aaron Stewart (SPP) went over the schedule for upcoming TWG meetings. There was no further discussion. Seeing there was no further business, the meeting adjourned at 11:28 AM. Respectfully Submitted, Aaron Stewart Secretary

Participant Name Email1 Michael Odom (SPP) [email protected] Gail Elliott - ITC [email protected] Kevin Foflygen [email protected] Sherri Maxey (SPP) [email protected] Travis Hyde [email protected] Jerad Ethridge (OGE) [email protected] Ryan Yokley [email protected] sam mase [email protected] Ray Bergmeier (SEPC) [email protected]

10 Eric Ruskamp [email protected] Kalun [email protected] Jeff McDiarmid [email protected] Tony Green [email protected] Marisa Choate [email protected] Robert Pick (NPPD) [email protected] Shane McMinn (GSEC) [email protected] Dona Parks (GRDA) [email protected] John Knofczynski [email protected] Michael Mueller [email protected] matthew stoltz [email protected] John Allen (SPRM) [email protected] Jordan Lamb [email protected] Chenal WebEx [email protected] Rachel Ibuado [email protected] Jonathan Hayes [email protected] Brett Hooton [email protected] Jim McAvoy [email protected] Korey Wells (OPPD) [email protected] Josh Verzal [email protected] [email protected] [email protected] Brian Rounds (AESL) [email protected] Andy Berg (MRES) [email protected] Nate Morris (EDE) [email protected] Dustin Betz (NPPD) [email protected] chris pink [email protected] Jason Shook (GDS/ETEC) [email protected] Jerry Bradshaw (SPRM) [email protected] Nathan McNeil [email protected] Jason Davis [email protected] Daniel Benedict (INDN) [email protected] Raman Somayajulu [email protected] Steve Hardebeck [email protected] Jeff Knottek [email protected] Scott Rainbolt [email protected] John Boshears (SPRM) [email protected] Cristina Ortiz (Evergy) [email protected]

47 Joshua Pilgirm [email protected] [email protected] [email protected] Randy Lindstrom [email protected] Katy Onnen (Evergy) [email protected] Noman Williams [email protected] Moses Rotich [email protected] Pallab Datta [email protected] Marc Moor (Evergy) [email protected] Jason Speer [email protected] Josie Daggett [email protected] John O'Dell (SPP) [email protected] [email protected] [email protected] Scott Benson (LES) [email protected] Derek Sunderman [email protected] Jarred Cooley [email protected] Tyler Baxter [email protected] Sing Tay [email protected] Scott Mijin [email protected] Jeremy Harris (Evergy) [email protected] Joe Fultz [email protected] Scott Holland [email protected] Diego Toledo (GRDA) [email protected] Brooke Keene (SPP) [email protected] Tanner New [email protected] Ross Hohlt [email protected] Keith Cargill [email protected] Calvin Daniels (WFEC) [email protected] Neeya Toleman (SPP) [email protected] Aaron Vander Vorst [email protected] Rebekah Kelman [email protected] James Ging [email protected] Matt McGee [email protected] Jordan Schmick [email protected] Steve Hohman [email protected] Kalen [email protected] Michael Wegner (ITC) [email protected]


March 14, 2019 SPP Corporate Campus – Little Rock, AR

• Summary of Actions Taken •

1. Approved the Consent Agenda Items:

a. February 5, 2019 TWG Minutes b. RR 351: RR Withdrawal Process Update per MOPC Action Item 294 c. RR 343: Late Firm Acceptance Timing d. RR 344: Retirement of BP2500 – Interim Short Term Service Extended ATSS Delays e. RR 345: Identical Transmission Service Request Quantity Modification

2. Approved RR 340: PMU for New Generator Interconnections 3. Approved RR 350: Revise Section 8 of the Planning Criteria


March 14, 2019 SPP Corporate Campus – Little Rock, AR

• M I N U T E S •

Agenda Item 1 – Administrative Items Call to Order Chair Travis Hyde (OKGE) called the meeting of the Transmission Working Group (TWG) to order at 8:04 am. The following members attended or were represented by proxy (Attachment 01 – WebEx Attendance.xls):

Travis Hyde (Chair), Oklahoma Gas & Electric Nathan McNeil (Vice-Chair), Midwest Energy, Inc. Scott Benson, Lincoln Electric System John Boshears, City Utilities of Springfield Missouri Derek Brown, KCP&L and Westar, Evergy Companies Cliff Franklin, Sunflower Electric Power Corporation Joe Fultz, Grand River Dam Authority James Ging, Kansas Power Pool Kalun Kelley, Western Farmers Electric Cooperative John Knofczynski, East River Electric Power Cooperative Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Matt McGee, American Electric Power Shane McMinn, Golden Spread Electric Cooperative Michael Mueller, Arkansas Electric Cooperative Corporation Gayle Nansel, Western Area Power Administration Chris Pink, Tri-State G&T Jason Shook, GDS Associates, Inc. Matthew Stoltz, Basin Electric Power Cooperative Michael Wegner, ITC Holdings Noman Williams, GridLiance High Plains LLC

Proxies The following proxies were provided for all or portions of the meeting: Full Proxy

• Scott Benson (LES) gave his proxy to Alan Burbach (LES). • Derek Brown (WERE/KCPL Evergy) gave his proxy to Katy Onnen (WERE/KCPL Evergy).

Aaron Stewart, TWG staff secretary, informed Travis that the group had a quorum. Antitrust Guidelines Aaron Stewart (SPP) noted to the TWG that the agenda for the meeting included Antitrust Guidelines and reminded the group that certain topics were not allowed for discussion during the meeting. Meeting Materials Review Travis Hyde (OKGE) asked the group if there were any edits to or comments regarding the meeting materials. There was no further discussion. Consent Agenda (Action Item) The Consent Agenda included the following items:

a. February 5, 2019 TWG Minutes (Attachment 01ei - Draft TWG Minutes February 5, 2019_Redlines.docx)

b. RR 351: RR Withdrawal Process Update per MOPC Action Item 294 (Attachment 01eii - TWG RR 351.zip)

c. RR 343: Late Firm Acceptance Timing (Attachment 01eiii - RR 343 Recommendation Report.docx)

d. RR 344: Retirement of BP2500 – Interim Short Term Service Extended ATSS Delays (Attachment 01eiv - RR 344 Recommendation Report.docx)

e. RR 345: Identical Transmission Service Request Quantity Modification (Attachment 01ev - RR 345 Recommendation Report.docx)

Travis Hyde (OKGE) asked the TWG if there were any consent agenda items that needed to be removed, changed or added; Aaron Stewart (SPP) notified the group that an edit to the February 5, 2019 TWG Minutes was sent in after posting and presented the change to the group.

Motion: James Ging (KPP) made a motion to approve the Consent Agenda including the changes made to the February 5, 2019 TWG Minutes. Chris Pink (Tri-State) seconded the motion. The motion was approved unanimously.

Agenda Item 2 – RR 340: PMU for New Generator Interconnections (Action Item) Cody Parker (SPP) went over the comments report for RR 340 (Attachment 02 - RR 340 Recommendation Report.docx). Specifically he provided information on the Regional Tariff Working Group (RTWG) discussion and addressed concerns that were raised by the RTWG. Cody went over the edits that were made during the RTWG’s review of RR 340 and explained the rationale behind those edits.

Motion: Katy Onnen (WERE/KCPL Evergy), proxy for Derek Brown (WERE/KCPL Evergy), made a motion to approve RR 340: PMU for New Generator Interconnections. Joe Fultz (GRDA) seconded the motion. The motion was approved with 1 no vote by Michael Wegner (ITC).

After the meeting, the individual who voted no was provided the opportunity to submit their voting rationale. The submitted responses are provided below. Michael Wegner (ITC)

“ITC believes that the use of PMU’s will benefit everyone, and as such, they should be included as Network Upgrades and not TOIF; in other words, everyone should pay, not just the interconnecting customer.”

Agenda Item 3 – RR 350: Revise Section 8 of the Planning Criteria (Action Item) Kathryn Dial (SPP) presented RR 350 to the group (Attachment 03 - 03. RR350.zip). She provided a history of the changes from the System Protection and Control Working Group (SPCWG) and the RTWG and the rationale behind the changes that were proposed in the RR. She also provided information on PRC-012-2 and how this drove the need for the RR.

Motion: John Knofczynski (EREC) made a motion to approve RR 350: Revise Section 8 of the Planning Criteria. Matt McGee (AEP) seconded the motion. The motion was approved unanimously.

Agenda Item 4 – Planning Criteria Section 7 Draft RR Review Eric Ruskamp (LES) provided the group with an overview of a draft RR that is being proposed for Planning Criteria Section 7 (Attachment 04 – Planning Criteria Section 7.2 RR Form-draft 20190228.docx). Eric went over the draft RR and covered the changes that are being proposed for each portion of Section 7. There were questions asked about the reasoning for some of the minor language changes, such as “shall” to “should”. Eric explained that the reasoning behind this was to loosen the requirement that the Transmission Owner (TO) must rely on SPP’s Planning Criteria for methodology. This was due to NERC requirements that now require TOs to have their own so there is no longer the need to have language in the SPP Planning Criteria that requires TOs to reference the SPP methodology as their own.

Agenda Item 5 – Material Modification Definition Micha Bailey, (SPP), provided the group with a presentation covering the material modification definition from the Local Planning Process (LPP) and Local Planning Criteria (LPC) survey responses. (Attachment 05 – Definition of Material Modification.pptx). The definition presented was intended to be a starting point for the discussion on forming a definition for a future RR. There was discussion on the possibility of putting a range on the impedance changes and using this as a trigger for when a change should be considered a material modification or not. The group provided some additional thoughts on what changes they thought should be made to the language that staff is going to take into consideration and will reflect when brought back to the group at a future meeting.

Agenda Item 6 – LPC/LPP Coordination and Communication Walkthrough Michael Odom (SPP) provided the group with a presentation covering the process for coordination of TO planned projects (Attachment 06 – SPP_LPP_LPC_Process.pptx). He outlined some of the background information that is driving the need for this discussion, as well as the current process and how it should be coordinated moving forward. There were some concerns brought up by the group regarding the impact this might have to the timing of other processes. In addition, it was mentioned that this process could add additional burden for little improvement. To conclude the discussion staff mentioned that some discussion on this topic had already occurred at the Model Development Working Group meetings and there would be more conversations at future meetings.

Agenda Item 7 – 2020 ITP Base Reliability Powerflow Model David Duhart (SPP) provided the TWG with a presentation to communicate 2020 ITP Base Reliability (BR) Powerflow model updates received since model review posting and the associated next steps (Attachment 07 – 2020 ITP Powerflow and Load Review Update.pptx). David went over background information regarding the posting dates of the 2020 ITP BR Powerflow models and the 21 model updates that will be covered by the Section 10.3 evaluation process in the ITP Manual. There was no additional discussion.

Agenda Item 8 – Written Reports There was no discussion on the materials included in the written reports (Attachment 08a, 08b – 2019 ITP Schedule.pptx, 2020 ITP Schedule.pptx).

Agenda Item 9 – Closing Items Aaron Stewart (SPP) went over the schedule for upcoming TWG meetings. There was no further discussion. Seeing there was no further business, the meeting adjourned at 11:09 AM. Respectfully Submitted, Aaron Stewart Secretary

SPP Transmission Working GroupApril 9, 2019

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• Requesting SPP Staff utilize a subset of 2019 ITP models to ensure upgrades resulting from the GridLiance High Plains Local Planning Process (LPP) are not needed to address issues in the ITP and that projects approved in the 2019 ITP do not result in negating the need for the LPP projects.

• Needed to coordinate the output of GridLiance’s LPP with SPP’s regional planning process

• GridLiance’s 2018 LPP identified three upgrades in the Oklahoma Panhandle for which GridLiance is requesting coordination: two voltage support upgrades and one switching station

• GridLiance provided these projects to SPP as 2019 DPP submittals in an effort to provide SPP all necessary information to evaluate the projects

• Not requesting a material change to the 2019 ITP

Overview

1

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• GridLiance’s Oklahoma Panhandle transmission facilities are not included in the 2019 ITP models

• GridLiance became an SPP transmission owner for facilities located in the Oklahoma Panhandle on November 1, 2018, well after the model build for the 2019 ITP

• Performing the needed coordination requires SPP to update 2019 ITP models

Reason for 10.3 Request

2

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• Update the 2019 ITP reliability (BR) models to include the GridLiance transmission facilities

• Perform an evaluation on projects identified in the 2019 ITP to determine if those facilities negate the need for GridLiance’s LPP projects

• Perform an evaluation to determine if the GridLiance LPP projects address any currently-identified ITP needs

• Document the results in the 2019 ITP Report

Request

3

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Map of GridLiance system and LPP Projects

Texas County

Interchange

Cole Interchange

GLHP 115 kV Transmission LinesGLHP 69 kV Transmission LinesSubstationGHP Transmission Project

Oklahoma Panhandle

Texas

KansasColorado

One project

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• Not asking SPP to re-run needs assessment

• Not asking SPP to update the economic models

Not included in the Request

5

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• While unlikely, SPP’s analysis could result in the following:• Selecting a GridLiance LPP project to address a regional SPP issue, or• A determination that an SPP regional project negates the need for

one of the three GridLiance LPP projects

Potential Impacts

6

ITP2019

SPP Comments on GHP 10.3 Request2019 ITP

2SouthwestPowerPool SPPorg southwest-power-pool

https://www.facebook.com/SouthwestPowerPool/

https://twitter.com/SPPorg

https://www.linkedin.com/company/southwest-power-pool/

ITP2019

Comments• GHP: Perform an evaluation on projects identified

in the 2019 ITP to determine if those facilities negate the need for GridLiance’s LPP projects

• SPP: This request could have minor or major impacts to schedule/staff resources While GHP is not asking SPP to re-run the needs

assessment, this task must be done in the local area in order to identify if 2019 ITP projects can mitigate the issues driving the GHP projects None of the GHP requests can be accommodated without

significant schedule impacts if new regional needs are identified in this assessment

If new regional needs are not identified, this request can be accommodated by a simplified version of the process Using engineering judgement to identify projects in the area

and performing one-off analysis

3

ITP2019

Comments• GHP: Perform an evaluation to determine

if the GridLiance LPP projects address any currently-identified ITP needs

• SPP: This request should have minor impact as an “enhanced no-harm” analysis SPP will incrementally include the upgrades to

models developed for the previous analysis to determine their impact to on existing ITP needs

4

ITP2019

Comments• GridLiance is not requesting any economic

analysis at this time but SPP deems it necessary to satisfy our Tariff obligations

1. Update economic models through project automation to include the impact of the new impedance network

2. Review congestion differences on surrounding ITP needs for impacts and potential project adjustments

NOTE: The OK Panhandle facilities are a radial 69 kV system with no generation and therefore would not be included as economic model constraints and not produce new needs

5

ITP2019

Next Steps/Conclusions• Initial efforts can be reasonably done

outside of the regional study process This effort is not expected to cause impacts to the

regional study based on preliminary review of data

• In the unexpected event regional issues are identified, GridLiance would need to continue with a 10.3 request in the 2019 ITP, wait for evaluation in the 2020 ITP or work with SPP to develop alternatives that do not have major study impacts

6

Proposed Assignment of NTC 200479Tony Green

Manager, Engineering Support





Qualifications for Assignment-Business Practice 7070

• An “assignment” is the transfer of a DTO’s legal right to build a project pursuant to a NTC issued by SPP. Although the DTO has transferred its legal right to build a project pursuant to an assignment, the original DTO is still under a legal obligation to ensure that the project is built.

• SPP Board approves assignments to a qualified entity based on criteria identified in SPP Tariff:Obtained all state regulatory authority necessary to construct,

own and operate transmission facilities within the state(s) where the project is locatedMeets the creditworthiness requirements of the Transmission

ProviderSigned, or capable and willing to sign, the SPP Membership

Agreement as a Transmission Owner upon the selection of its proposal to construct and own the projectMeets such other technical, financial and managerial

qualifications as are specified in the Transmission Provider’s business practices

3

Additional Information-Business Practice 7070

• SPP will provide information and supporting analysis regarding proposed assignments to the RSC, MOPC, and Members Committee, including:Identification of the project, current Designated Transmission

Owner (DTO), entity receiving the assignment, and any pertinent matters before FERC or state commissions related to the project

Comparison of the DTO and proposed entity of assignment for multiple financial elements of the project

Analysis for any changes to ROE, cost of capital, and overall costs for the project, along with other performance criteria that may affect ATRR due to the assignment

Whether the assigning party will own, operate and maintain the facility

Detail on what process was used in selecting the potential DTO

4

Proposed Project for Assignment- NTC 200479• Issued February 27, 2018 to Kansas Power Pool

(KPP) Accepted by KPP on April 23, 2018

• Regional Reliability upgrade identified in the Aggregate Study process 2016-AG2-AFS-2

• Reconductor 4 miles of 69 kV transmission line from City of Winfield to Rainbow Substation

• Current cost estimate from KPP $3,600,000 KPP’s acceptance changed project to a rebuild and

listed risk of possible airport restrictions in current line route

5

SPP Analysis• GridLiance High Plains, LLC (GridLiance)

identified as entity receiving Assignment

• SPP requested documents from GridLiance to support analysis of conditions identified in Attachment Y Section III and Business Practice 7070

• GridLiance provided necessary documents as well as SPP data requests allowing SPP to complete the required analysis

• Included in background material is a detailed report providing information required to meet the transparency guidelines of Business Practice 7070

6

Summary• GridLiance has provided documentation

that meets SPP Tariff requirements for assignment

• SPP will provide a cost comparison and review for RSC, Members Committee, and SPP Board per Business Practice 7070 Document Review Financial Review Pertinent Findings

7

KANSAS POWER POOL NTC

ASSIGNMENT TO

GRIDLIANCE HIGH PLAINS, LLC SPP-NTC-200479

April 2019

Southwest Power Pool

Southwest Power Pool, Inc.

CONTENTS

Section 1: NTC Assignment Review ................................................................................................................................. 1

Subsection A: Kansas Power Pool NTC Assignment to Gridliance High Plains LLC ................................... 1

Subsection b: Review Process ................................................................................................................... 1

Subsection c: Document Review ............................................................................................................... 1

Section 2: Financial Review ................................................................................................................................................. 4

Subsection A: GridLiance Assumed Cost ................................................................................................... 4

Section 3: Findings .................................................................................................................................................................. 7

Subsection A: Financial Findings ............................................................................................................... 7

Subsection B: Cost to Customers Findings ................................................................................................ 7

Subsection c: Operations Findings ............................................................................................................ 8

Subsection D: Assignment Approval Criteria per SPP Tariff ..................................................................... 8


KANSAS POWER POOL NTC ASSIGNMENT TO GRIDLIANCE HIGH PLAINS, LLC SPP-NTC-200479 1

SECTION 1: NTC ASSIGNMENT REVIEW

SUBSECTION A: KANSAS POWER POOL NTC ASSIGNMENT TO GRIDLIANCE

HIGH PLAINS LLC This report presents the review of Kansas Power Pool’s (“KPP”) request to assign Notification to

Construct (“NTC”) No. 200479 to GridLiance High Plains, LLC (“GridLiance”) conducted by Southwest

Power Pool (“SPP”).

This review was performed to satisfy the requirements established by SPP’s Open Access

Transmission Tariff (“Tariff”) Attachment Y and Business Practice 7070 regarding the assignment of

NTCs. Per SPP Business Practice 7070, an “assignment” is the transfer of a Designated Transmission

Owner’s (“DTO”) legal right to build a project pursuant to a NTC issued by SPP. Although the DTO

has transferred its legal right to build a project pursuant to an assignment, the original DTO is still

under a legal obligation to ensure that the project is built.

This report provides information to the SPP Board of Directors (“BOD”), Regional State Committee

(“RSC”), Markets and Operations Policy Committee (“MOPC”), and the SPP Members Committee on

the qualifications of GridLiance to be assigned Project ID 51249, which is directed in SPP’s NTC-

200479. Project ID 51249 is also referred to as Network Upgrade ID 71954, which is an upgrade

requiring the reconductoring of 4 miles of 69kV transmission line from the City of Winfield, Kansas

(“Winfield”) to Westar Energy, Inc.’s Rainbow Substation. SPP issued the NTC to KPP on February

27, 2018 with a cost estimate of $1,467,084. KPP accepted the NTC on April 23, 2018. As part of the

NTC acceptance, KPP provided an updated cost estimate of $3,600,000 based upon the need to

rebuild rather than reconductor the line. KPP also acknowledged the possibility of airport

restrictions causing a route change. KPP’s updated cost estimate assumes that the airport

restrictions can be satisfied without rerouting the line.

SUBSECTION B: REVIEW PROCESS SPP conducted the review and analysis in accordance with Attachment Y of the SPP Tariff and Section

3 of Business Practice 7070. This review included phone interviews with KPP, GridLiance, and

Winfield and review of the supporting documentation to compare and analyze the proposed NTC

assignment with respect to Regulatory, Managerial, and Financial factors.

SUBSECTION C: DOCUMENT REVIEW GridLiance provided two documents to SPP at the start of the review in August 2018, and six

additional documents over the course of the analysis in response to SPP additional inquiries. SPP

submitted two data requests to GridLiance during the review. The documents exchanged during the

review are shown in Table 1 below. During the review, GridLiance and SPP exchanged approximately

fifteen emails including data requests, responses to data requests, and clarification of responses that

may or may not be included in identified documents 1-9 in Table 1 below. Email exchanges and data

embedded within the emails are intended to be captured as part of Document No. 10 in Table 1 below.



Table 1 lists the documents/communications reviewed.

DOCUMENT NO.

DATE RECEIVED DOCUMENT NAME

1 8/6/2018 KPP_NTC_Acceptance_4_18_18.docx

2 8/6/2018 NTC Assignment-Winfield_KPP_GridLiance_Executed_7_19_18.pdf

3 9/7/2018 NTC Assignment Data Response_GL_KPP_9_7_18.docx

4 12/18/2018 Winfield NTC Response supporting data_09042018_bh.xlsx

5 01/03/2019 DOCS-#611412-v6-GL-NTC_Assignment_Agreement.docx

6 01/03/2019 GL NTC Assignment Agreement [Execution Version](11545.2).docx

7 01/03/2019 NTC Assignment-Winfield_KPP_GridLiance_Executed_7_19_18.pdf

8 01/08/2019 GL NTC Assignment Agreement Execution Version (11545.2)_TK.docx

9 02/21/2019 KPP GHP Assignment Agreement.pdf

10 8/2018-3/2019 Approximately 15 email exchanges between SPP and GridLiance providing data requests, responses to data requests, and clarification of responses



Observations from Document Review The documents provided by GridLiance show that –

Gridliance meets the financial requirements of the Transmission Provider as specified in

Section III.1(b)(ii) of Attachment Y of the SPP Tariff

GridLiance has signed the SPP Membership Agreement as a Transmission Owner

GridLiance meets the managerial requirements as specified in Section III.1(b) of Attachment

Y of the SPP Tariff

GridLiance, Winfield, and KPP jointly filed at the Kansas Corporation Commission (“KCC”) in

February 2019 requesting public utility status and a Certificate of Convenience and Authority

(“COC”) for GridLiance to operate and upgrade transmission facilities in the state of Kansas.

(KCC Docket No. 19-GLPE-338-ACQ)

GridLiance has a Federal Energy Regulatory Commission (“FERC”) approved formula rate

template that is the basis for the cost comparisons

o KPP currently has a FERC stated rate but indicates if it were to move forward with

the NTC, it would file for a formula rate with FERC to mimic the capital structure and

return on equity of its local partner, GridLiance.

o GridLiance will be the joint owner of other transmission assets with Winfield/KPP

There is a difference of 4.2 percentage points between the GridLiance Net Plant Carrying

Charge (“NPCC”) and the Winfield NPCC for the first five years of the project life as well as

over the entire service life. As discussed in Section 2 below, this NPCC difference results in

the GridLiance projected Annual Transmission Revenue Requirement (“ATRR”) being

approximately 26 percent higher than the projected ATRR if KPP or Winfield were the full

owner.

Winfield, with KPP acting as its agent, will co-own with GridLiance the final constructed

upgrade. For the full project cost, this joint ownership will dampen the difference in ATRR to

the extent of Winfield’s ownership.

Winfield will perform all Operations & Maintenance (“O&M”) services related to this project

The Winfield Commission selected GridLiance as its exclusive transmission partner in public

and open meetings

KPP selected GridLiance as its exclusive planning and development partner in 2015 and

codified this agreement in a Co-Development Agreement executed in 2016

Winfield has the right and intends to execute its right to own 35 percent of the project. This

means Winfield will contribute 35 percent of the capital and will recover through its ATRR

the cost of ownership of its 35 percent share



SECTION 2: FINANCIAL REVIEW

SUBSECTION A: GRIDLIANCE ASSUMED COST SPP’s financial review focused primarily on the responses to data requests one and two (email

exchanges noted in Document No. 10) and the spreadsheet titled “Winfield NTC Application

Supporting Data” (Document No. 04).

FERC has authorized a Return on Equity (“ROE”) of 10.3 percent for GridLiance, which is a 9.80

percent base return and a 0.50 percent adder for RTO participation.

Due to differences in the cost of debt, the Weighted Average Cost of Capital (“WACC”) of GridLiance

is projected as 8.2 percent vs 7.8 percent for KPP.

Since KPP does not currently have a formula rate, GridLiance considered certain assumptions to

remain constant. They indicated that the debt share of the capital structure, ROE, administrative and

general expense (A&G), and O&M were assumed the same whether the facilities were owned by

GridLiance or by Winfield with KPP acting as the agent.

GridLiance’s estimated NPCC is 4.2 percentage points higher than KPP. The factors that account for

the 4.2 percentage point variance are:

Franchise Fees: Represents 0.8 points of the NPCC. Winfield does not expect to pay itself a

Franchise Fee, but GridLiance will be required to pay a Franchise Fee. The Franchise Fee

accounts for GridLiance’s ability to use the municipality’s right-of-way.

Property Taxes: This represents 1.5 points of the NPCC. GridLiance is required to pay

property tax while Winfield is not.

Income Tax: This represents 1.5 points of the NPCC. GridLiance is required to pay income

tax while Winfield is not.

Debt Cost: Winfield can issue tax-free bonds, which GridLiance cannot, thereby lowering

the Winfield cost of debt. The difference between GridLiance’s and Winfield’s projected

debt cost creates a 0.4 percentage point difference in the WACC, which translates into a

corresponding difference in the NPCC.



Table 2 compares the financial assumptions between GridLiance and KPP the Designated

Transmission Owner (“DTO”).

TRANSMISSION OWNER

ACTUAL OR

PROJECTED D/E

RATIOS

ACTUAL OR

PROJECTED COST OF CAPITAL

ACTUAL OR PROJECTED

ROE OR APPLICABLE MEASURE

ACTUAL OR PROPOSED TYPE AND

AMOUNT OF CONSTRUCTION

FINANCING COSTS, I.E.

INTEREST RATE, AFUDC OR

CWIP

S&P AND MOODY'S

CREDIT RATINGS

ESTIMATED NPCC FOR THE LIFE OF THE

PROJECT AFTER IT IS PLACED IN-

SERVICE

KPP (DTO) 40% / 60% 7.8% 10.3% AFUDC (4.0%) Est. Cost of

Debt

Moody’s: A3

Fitch: A-

13.3% (Avg Yr 1-5) / 16.2%

(Lifetime Avg)

GridLiance (PDTO)

40% / 60% 8.2% 10.3% AFUDC (5.0%) Est. Cost of

Debt

Not Rated

17.5% (Avg Yr 1-5) / 20.4%

(Lifetime Avg)

Cost to Customers The data provided by GridLiance shows that the annual cost to SPP customers is expected to be greater than if KPP retained the NTC. The largest driving factor for this increase is that the tax requirements for GridLiance are greater than those for KPP/Winfield. GridLiance, KPP, and Winfield verified that if KPP/Winfield retained the NTC they would file with FERC to gain approval of a Formula Rate template that would mimic the FERC approved template of GridLiance.



Staffing and Project Management Needs GridLiance indicated that Winfield, with KPP acting as its agent, will co-own with GridLiance the final constructed upgrade. Winfield will perform all O&M services related to this project. The Winfield Commission, in public and open meetings has selected GridLiance as its exclusive transmission partner. Additionally, KPP selected GridLiance as its exclusive planning and development partner in 2015 and codified this in a Co-Development Agreement executed in 2016. GridLiance indicated that benefits of the agreements help to ensure the project is constructed and placed into service as required per the NTC with greater assurance than having less experienced municipalities carry out the requirements of the NTC. GridLiance noted that while Winfield owns transmission facilities, transmission ownership is not its business and the city must manage more priorities than running an electric utility. Partnering with GridLiance will bring a transmission-only focus to the project, along with capital resources. Along with expertise and proper staffing and capital, GridLiance also provides resource relief to Winfield as a small municipality and provides greater expertise when handling the NTC project to ensure it is constructed as required and is delivered on time. GridLiance indicated that these are benefits to be considered as offsets to any increased cost to develop and own the project without an assignment.



SECTION 3: FINDINGS

SUBSECTION A: FINANCIAL FINDINGS Due diligence findings with respect to Financing Assumptions SPP’s review resulted in a finding that the operating and maintenance (“O&M”) costs are estimated to be the same for GridLiance as for KPP/Winfield.

In making this determination, SPP reviewed supporting documentation provided by GridLiance indicating the projected cost for O&M would remain the same whether GridLiance or KPP/Winfield ultimately constructed the NTC. This is because Winfield intends to provide all O&M for the project.

SPP’s review resulted in a finding that the NPCC applicable to the project will be 4.2 percentage points higher if GridLiance were to construct the NTC as opposed to KPP/Winfield. This is the difference between the 20.4 percent NPCC estimated for GridLiance and the 16.2 percent NPCC estimated for KPP/Winfield, both of which are quantified over the facility’s life. The difference between the two is largely attributable to differences in the taxable status between the entities. The difference between the two NPCC values results in GridLiance having an estimated ATRR that is approximately 26 percent higher than the KPP/Winfield ATRR.

This analysis assumes that GridLiance will own and operate 100 percent of the facilities; however, Winfield has the right, and plans to execute the right, to own 35 percent of the project. This will require Winfield to contribute 35 percent of the capital that will be recovered through its ATRR. This means that the ATRR difference in ownership, if just comparing GridLiance ownership versus Winfield ownership, is overstating the cost since Winfield will own 35 percent of the project. GridLiance will be the transmission operator for 100 percent of the project, but the ownership is anticipated to be shared.

SPP’s review resulted in a finding that the tax costs would cause approximately a 3 percentage point difference between the NPCC for GridLiance and the NPCC for KPP/Winfield.

In making this determination, SPP reviewed supporting documentation regarding taxable status of the entities involved. GridLiance’s tax obligation would be higher as compared to the municipalities’ obligations as GridLiance is a tax-paying public utility and KPP/Winfield are tax-exempt.

SPP’s review resulted in a finding the WACC for GridLiance would be approximately 0.4 percentage points higher than it would be for KPP/Winfield.

In making this determination, SPP reviewed the supporting documentation that reflected the projected cost of capital would be 7.8 percent for KPP as compared to 8.2 percent for GridLiance. This is largely due to KPP/Winfield’s ability to issue tax-exempt bonds.

SUBSECTION B: COST TO CUSTOMERS FINDINGS Due diligence findings with respect to Cost to SPP Customers SPP’s review resulted in a finding that the calculation of the GridLiance and KPP/Winfield NPCC values is supportable based on the information provided. This calculation shows that the cost to SPP customers is higher after assignment of the project.

Based on the NPCC values provided, SPP calculated the service life sum of the increment in ATRR under 100 percent GridLiance ownership as approximately $3 million (25.9 percent)



over a 40-year period. This calculation is based on a current NTC cost of $3,600,000 and a projected increased service life NPCC of 4.2 percentage points, from 16.2 percent to 20.4 percent. It also assumes the same rate of straight-line depreciation over a 40-year period in both cases.

SUBSECTION C: OPERATIONS FINDINGS Due diligence findings with respect to Project Development, Operations, and Maintenance SPP’s review resulted in a finding that GridlLiance has demonstrated its managerial and engineering expertise/qualifications that are sufficient for GridLiance to construct, own, and operate the project in a manner that Winfield has not currently demonstrated.

Winfield/KPP indicated during the review process that transmission construction is not a business in which Winfield is experienced and, therefore, Winfield would likely seek to execute any assigned NTCs through a partnership with an experienced entity as it has in this case.

SUBSECTION D: ASSIGNMENT APPROVAL CRITERIA PER SPP TARIFF Due diligence findings with respect to approval criteria for Assignments per SPP Tariff Attachment Y SPP’s review resulted in a finding that GridLiance meets and has demonstrated proof that it is eligible to be assigned this NTC as required in both SPP Tariff Attachment Y Section VII.1 (a-d) and Business Practice 7070 Section 3. (3.1.1).

Attachment Y Section VII.1 (a), requires that prior to starting its construction activity, the entity must have obtained all state and regulatory authority necessary to construct, own, and operate transmission facilities within the state(s) where the project is located.

o GridLiance, KPP, and Winfield jointly filed with the KCC in Docket No. 19-GLPE-338-ACQ on February 20, 2019 seeking to gain the regulatory authority required for GridLiance to construct, own, and operate the project in Kansas. The KCC has 300 days from the date of the filing to issue a ruling. As part of the filing, however, the entities requested expedited treatment and requested to have approval by the KCC by August 20, 2019.

Attachment Y Section VII.1 (b), requires the entity to meet the financial requirements of the Transmission Provider as specified in Section III.1 (b) (ii) of Attachment Y.

o GridLiance has met this requirement through the Qualified RFP Participant requirements option 3 and is current in the submission of documentation proof of this requirement to SPP.

Attachment Y Section VII.1(c), requires the entity to have signed or be capable and willing to sign the SPP Membership Agreement as a Transmission Owner.

o GridLiance met this requirement and executed the SPP Membership Agreement as a Transmission Owner in June 2017. GridLiance became a Transmission Owner with facility costs recovered under the SPP Tariff on April 1, 2018.

Attachment Y Section VII.1 (d), requires the entity to meet other qualifications as specified in Section III.1 (b) of Attachment Y.

o GridLiance has met this requirement through the Qualified RFP Participant requirements under the Managerial Criteria section and is current in the submission of documentation proof of this requirement to SPP.

Alternative Solutions as a Transmission Asset





Alternative SolutionsAttachment O Section III)7)c)

c) The Transmission Provider will consider, on a comparable basis, anyalternative proposals which could include, but would not be limited to, generation options, demand response programs, “smart grid” technologies, and energy efficiency programs. Solutions will be evaluated against each other based on a comparison of their relative effectiveness of performance and economics.

3

Discussion• Batteries were submitted through the DPP

window

• Evaluating all batteries and comparing them to transmission solutions

4

Discussion• While comparing batteries as an

alternative, we notice a need for a more robust criteria and policy

• If an alternative proposal is selected in the ITP process, then it will only be a transmission asset (for now)

• Transparency and clarifications Tariff - Attachment O, J and/or Y ITP Manual clarifications Attachment AE – Integrated Marketplace

Registration

5

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Revision Request Form SPP STAFF TO COMPLETE THIS SECTION

RR #: Date: xx/xx/2019

RR Title: Definition of Material Modification for Network Upgrades and Transmission Interconnection System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes

SUBMITTER INFORMATION

Name: Micha Bailey on behalf of TWG Company: Southwest Power Pool

Email: [email protected] Phone: 501.688.2522 Only Qualified Entities may submit Revision Requests.

Please select at least one applicable option below, as it applies to the named submitter(s).

SPP Staff SPP Market Participant SPP Member An entity designated by a Qualified Entity to submit

a Revision Request “on their behalf”

SPP Market Monitor Staff of government authority with jurisdiction over

SPP/SPP member Rostered individual of SPP Committee, Task Force or

Working Group Transmission Customers or other entities that are parties to

transactions under the Tariff REVISION REQUEST DETAILS

Requested Resolution Timing: Normal Expedited Urgent Action

Reason for Expedited/Urgent Resolution:

Type of Revision (select all that apply):

Correction

Clarification

Design Enhancement

New Protocol, Business Practice, Criteria, Tariff

NERC Standard Impact (Specifically state if revision relates to/or impacts NERC Standards, list standard(s))

FAC-002

FERC Mandate (List order number(s))

REVISION REQUEST RISK DRIVERS

Are there existing risks to one or more SPP Members or the BES driving the need for this RR? Yes No

If yes, provided details to explain the risk and timelines associated:

Compliance (Tariff, NERC, Other) FAC-002

Reliability/Operations

Financial SPP Documents Requiring Revision: Please select your primary intended document(s) as well as all others known that could be impacted by the requested revision (e.g. a change to a protocol that would necessitate a criteria or business practice revision).

Market Protocols Section(s): Protocol Version: Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date: Tariff (OATT) Section(s):

Business Practice Business Practice Number: (new) Definition of Material Modification for Network Upgrades and Transmission Interconnections

of 3

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):

OBJECTIVE OF REVISION

Objectives of Revision Request: Describe the problem/issue this revision request will resolve.

FAC-002 - Facility Interconnection Studies, Application Guidelines states, “Entities should have documentation to support the technical rationale for determining whether an existing interconnection was “materially modified.” Recognizing that what constitutes a “material modification” will vary from entity to entity, the intent is for this determination to be based on engineering judgment.” SPP sent out surveys to the TWG members to ask the members what/how did they define material modifications. SPP is creating this definition from the member’s surveys as a guideline to help support the technical rationale of what constitutes a “material modification” to the SPP Transmission System, whether the change to the Transmission System is a new transmission facility (transmission interconnection) or a modification to an existing facility and how those changes will be evaluated

Describe the benefits that will be realized from this revision.

Determining what constitutes a “material modification” to the SPP Transmission System and how those changes will be evaluated, creates more transparency. The reader will be able to use this definition as a guideline to determine what modifications are deemed material.

REVISIONS TO SPP DOCUMENTS In the appropriate sections below, please provide the language from the current document(s) for which you are requesting revision(s), with all edits redlined.

SPP Business Practices

BP XXXX - Definition of Material Modification for the SPP Transmission System NERC FAC-002 - Facility Interconnection Studies, Application Guidelines states, “Entities should have documentation to support the technical rationale for determining whether an existing interconnection was “materially modified.” Recognizing that what constitutes a “material modification” will vary from entity to entity, the intent is for this determination to be based on engineering judgment.”

This Business Practice shall define “material modification” to be applied for both OATT purposes of evaluating changes to existing or new Network Upgrades and NERC purposes for evaluating changes to existing or new transmission interconnections for FAC-002 compliance. If one or more “material modification” criteria have been met, SPP will require analysis of these changes under regional planning processes specified in the Tariff. SPP will also use the analysis to meet the requirements of FAC-002 as the Planning Coordinator.

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Material Modifications

Material Modifications to the SPP Transmission System are changes that directly impact the Bulk Electric System and/or facilities under SPP’s functional control including:

1) Network Upgrades associated with new transmission interconnections; 2) Transmission facility derate; 3) Changes of impedance greater than 20%; 4) Changes in line operating voltage; or 5) Changes in system configuration including the connection or disconnection of new or existing branches

(whether lines or transformer branches) to stations or lines in which they will be connected or disconnected for greater than 12 months.

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RR #: Date: xx/xx/2019

RR Title: Definition of Material Modification for Existing Transmission or End-user Facilities System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Micha Bailey on behalf of TWG Company: Southwest Power Pool

Email: [email protected] Phone: 501.688.2522 Only Qualified Entities may submit Revision Requests.











Correction

Clarification

Design Enhancement



FAC-002





Compliance (Tariff, NERC, Other) FAC-002



Market Protocols Section(s): Protocol Version: Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date: Tariff (OATT) Section(s):

Business Practice Business Practice Number: (new) Definition of Material Modification for FAC-002

of 3








FAC-002 - Facility Interconnection Studies, Application Guidelines states, “Entities should have documentation to support the technical rationale for determining whether an existing interconnection was “materially modified.” Recognizing that what constitutes a “material modification” will vary from entity to entity, the intent is for this determination to be based on engineering judgment.” SPP sent out surveys to the TWG members to ask the members what/how did they define material modifications. SPP is creating this definition from the member’s surveys as a guideline to help support the technical rationale of what constitutes a “material modification” to the Bulk Electric System (BES).


Determining what constitutes a “material modification” to the BES creates more transparency. The reader will be able to use this definition as a guideline to determine what modifications are deemed material.



BP XXXX - Definition of Material Modification for Existing Transmission or End-user Facilities NERC FAC-002 - Facility Interconnection Studies, Application Guidelines states, “Entities should have documentation to support the technical rationale for determining whether an existing interconnection was “materially modified.” Recognizing that what constitutes a “material modification” will vary from entity to entity, the intent is for this determination to be based on engineering judgment.”

This Business Practice shall define “material modification” to be applied for NERC purposes for evaluating changes to existing interconnections of transmission or electricity end-user Facilities for FAC-002 compliance. If one or more “material modification” criteria have been met, SPP will require analysis of these changes to meet the requirements of FAC-002 as the Planning Coordinator.

Material Modifications

Material Modifications are changes that are greater than 12 months and that directly impact the Bulk Electric System including:

1) Changes to transmission facilities that result in a derate;

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2) Proportional changes greater than +/- 30% from the facility’s original impedance value; 3) Changes in line operating voltage; or 4) Changes in system configuration including the connection or disconnection of new or existing branches

(whether lines or transformer branches) to stations or lines.

CSP Projects / ITP Final PortfolioESWG – March 2019

Adam Bell [email protected]

1

mailto:[email protected]

Overview • Purpose Review SPP’s methodology for treatment of potential SPP-MISO CSP

projects within the ITP

• Background

• Key Dates / Timeline

• SPP’s Approach

• Feedback / Questions

2

Background

3

SPP ITP

MISO MTEP

SPP-MISO CSP

Jun Jul Aug Sept Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec

Model Completion Needs Posted Initial Portfolio Selected

MOPC & Board Approval

Board Approval

Post “CSP” Needs

for IPSAC

IPSAC Solution

s

Interregional Project Eval

IPSAC, SPP-MISO JPC, SPP Board, and MISO Board Approvals

SPP-MISO Futures Coordination for 2020 Study

SPP-MISO Regional Needs Coordination

Determine SPP-MISO

Cost Allocation

SPP-MISO Regional Modeling Coordination


2018 2019

Model Completio

n

Needs Posted Initial Portfolio Selected

SPP-MISO Cost Allocation• SPP and MISO each calculate project benefits using their

respective regional models 20 year benefit APC Avoided Cost

• SPP and MISO’s share of project costs are based on the % of the total project benefit MISO Cost = (MISO Benefit)/(MISO Benefit + SPP Benefit) MISO Benefit = NPV of MISO’s benefits as calculated in MISO’s MTEP

process

SPP Cost = (SPP Benefit)/(MISO Benefit + SPP Benefit) SPP Benefit = NPV of SPP’s benefits as calculated in SPP’s ITP process.

5

SPP-MISO Cost Allocation -> Regional Processes• SPP and MISO will use the Interregional Cost Allocation to

evaluate potential projects against other potential regional and interregional solutions through the regional processes The solution will utilize the new cost responsibility for each RTO as

determined by the CSP

6

SPP ITP

MISO MTEP

SPP-MISO CSP


Model Completion Needs Posted Initial Portfolio Selected

MOPC & Board Approval

Board Approval

Post “CSP” Needs

for IPSAC

IPSAC Solution

s

Interregional Project Eval

IPSAC, SPP-MISO JPC, SPP Board, and

MISO Board Approvals

SPP-MISO Futures Coordination for 2020 Study

SPP-MISO Regional Needs Coordination

Determine SPP-MISO

Cost Allocation

SPP-MISO Regional Modeling Coordination


2018 2019

Model Completio

n

Needs Posted Initial Portfolio Selected

Coordinated System Plan and Regional Project Approvals• Results of CSP analysis and recommended projects presented

to the IPSAC

• Official Joint Planning Committee (JPC) Vote and Recommendation

• MISO Regional Approvals CSP study details provided with MTEP Report and presented to MISO

PAC Board of Directors approves project(s) for MTEP “Appendix A”

• SPP Regional Approvals Markets and Operations Policy Committee provide recommendation to

the Board on all ITP and CSP projects All projects with cost sharing between SPP and MISO must be approved

through the CSP Board of Directors approve all ITP and CSP projects

8

Key Dates & Timeline

9

Expected CSP / ITP Schedule

10

March 2019 SPP and MISO share

potential Interregional

Projects

Mid/Late April 2019

SPP and MISO share benefit numbers for

Individual Interregional

Projects

May 2019SPP shares initial

ITP Portfolio at the SPP Planning

Summit

July/August 2019MISO shares initial MTEP Portfolio w/

MISO PAC

October 2019SPP MOPC & Board

of Directors Approve ITP and

CSP Projects

December 2019MISO Board of

Directors Approves MTEP and CSP

Projects

Timeline• Due to the timing of SPP and MISO’s approval processes,

SPP will have to make decisions on approving potential Interregional Projects out of the CSP without knowing MISO’s final decision

• Potential Complexities SPP’s final portfolio could include an Interregional Project(s)

(assuming some level of cost sharing) with MISO that is not ultimately approved Potentially multiple projects Potential for the Interregional Project to still be the best regional option

assuming 100% of the cost Portfolio benefit numbers could be impacted if an Interregional Project

drops out Treatment of Baseline Reliability Projects

11

SPP’s Approach

12

SPP Approach • Develop a single final portfolio that is the most optimal and cost

efficient solution for SPP regardless if Regional or Interregional solutions are preferred

• Reasoning “No regrets” approach of making the best business decision for SPP on

which projects to include Keeps open the potential for cost sharing with MISO Hopeful for strong indications from MISO on the level of support they have

for potential Interregional Projects Only staffed to develop one portfolio without incurring additional cost Possibility of Interregional Projects falling out of the final portfolio is no

different than the possibility of a regional project being removed for various reasons

13

SPP Approach Cont. • In the event an Interregional Project falls out of the final portfolio due

to not gaining final approval from MISO, SPP will handle it like any other Regional project being removed or not being issued an NTC Use judgement on a case by case basis whether to replace the Interregional

Project with a Regional option or restudy the need in the next planning cycle

Assess the impact to any previously performed analysis and determine the appropriate next steps

14

Questions / Feedback ?

15


RR #: Date:

RR Title: Revise Section 7.2 of the SPP Planning Criteria System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Company:

Email: Phone: Only Qualified Entities may submit Revision Requests.











Correction

Clarification

Design Enhancement



FAC-008





Compliance (Tariff, NERC, Other)



Market Protocols Section(s): Protocol Version: Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): 7.2 Criteria Date: Tariff (OATT) Section(s): Business Practice Business Practice Number:








The TWG and RCWG believe much of the existing language in Section 7.2 of the SPP Planning Criteria is covered by NERC Reliability Standard FAC-008 and the specific equipment rating criteria can be preserved as guidance at the option of the member.


The TWG and RCWG believe the SPP Membership will benefit from a reduction in Criteria language where NERC Standards sufficiently cover the topic. This Criteria revision will minimize the potential for confusion and inconsistencies or conflict with current and future NERC Standards and revisions.


Market Protocols

SPP Tariff (OATT)

SPP Operating Criteria

SPP Planning Criteria

7.2 Rating of Transmission Facilities

All SPP transmission system equipment Facilities included in the SPP OATT shall have a Normal Rating and an Emergency Rating. Each SPP member shall establish the Normal Rating and Emergency Rating for their equipment owned under the SPP OATT. All Normal and Emergency Ratings shall respect the most-limiting maximum and minimum voltage, current, frequency, real

and reactive power flows under steady state, short-circuit and transient conditions for components that comprise the transmission equipment.

Consistent with FAC-008, each Transmission Owner shall have and implement a methodology for determining its Facility Ratings for the Facilities it solely and jointly owns.

SPP members may use circuitdevelop dynamic or seasonal ratings based on windspeed, ambient temperature or other variables higher than these minimums described in Section 7.2 based upon variables inif permitted by their respectiveindividual Facility rRatings methodology document (i.e windspeed, etc.). For certain equipment, (switches, wave traps, current transformers and circuit breakers), the Normal and Emergency Ratings are identical The following sections provide guidance and recommendations to Transmission Owners (for voluntary use) in developing their respective Facility Rating methodology document. 7.2.1 Power Transformer

Power transformer ratings are discussed in ANSI/IEEE C5791, IEEE Guide for Loading Mineral-Oil-Immersed Power Transformers. Every transformer has a distinct temperature rise capability used in setting its nameplate rating (either 55°C or 65°C). These temperature rise amounts reflect the average winding temperature rise over ambient that a transformer may operate on a continuous basis and still provide normal life expectancy.

7.2.1.1 Normal Rating

The recommended nNormal circuit rRating for power transformers shall be is its highest nameplate rating. The nameplate ratings shall include the effects of forced cooling equipment if it is available. For multi-rated transformer (OA/FA, OA/FA/FA, OA/FOA/FOA, OA/FA/FOA) with all or part of forced cooling inoperative, nameplate rating used is based upon the maximum cooling available for operation. Normal life expectancy will occur with a transformer operated at continuous nameplate rating.

7.2.1.2 Emergency Rating

When operated for one or more load cycles above nameplate rating, the transformer insulation deteriorates at a faster rate than normal. The recommended eEmergency circuit rRating for power transformers shall beis a minimum of 100% of its highest nameplate rating. Member systems may use a higher eEmergency rRating if they are willing to experience more transformer loss-of-life.

7.2.1.3 Loss of Life

In ANSI/IEEE C57.91, a 65°C rise transformer can operate at 120% for an 8 hour peak load

Commented [JA1]: The TWG needs to review and update the technical references in the following sections.

cycle and will experience a 0.25% loss of life. If a 65°C rise transformer experiences 4 incidents where it operates at or below 120% for an 8 hour peak load cycle, it will still be within the target of 1% loss of life per year. In ANSI/IEEE C57.91, a 55°C rise transformer can operate at 123% for an 8 hour peak load cycle and will experience a 0.25% loss of life. Likewise, if a 55°C rise transformer experiences 4 incidents where it operates at or below 123% for an 8 hour peak load cycle, it will still be within the target of 1% loss of life per year.

7.2.1.4 Ambient Temperature

Average ambient temperature is an important factor in determining the load capability of a transformer since the temperature rise for any load must be added to the ambient to determine operating temperature. Transformers designed according to ANSI standards use a 30°C average ambient temperature (average temperature for 24 consecutive hours) when setting nameplate rating. Transformer overloads can be increased at lower average ambient temperatures and still experience the same loss of life. This allows seasonal ratings with higher nNormal and eEmergency rRatings. However, this circuit rating criteria does not call for seasonal transformer ratings are optional. In ANSI/IEEE C57.91, transformers can be loaded above 110% and experience no loss of life when the average ambient temperature is below 78°F. By not having seasonal ratings, the four occurrences that contribute to loss of life are limited to days when the average ambient temperature exceeds 78°F. The Power Transformer Rating Factors include:

(1) Nameplate rating, normal loss of life for 55°C and 65°C rise transformers with cooling equipment operating.

(2) Average ambient temperature, 30°C.

(3) Equivalent load before peak load, 90% of nameplate rating.

(4) Hours of peak load, 8 hour load cycle.

(5) Acceptable annual loss of life, 1%.

7.2.2 Overhead Conductor

Overhead conductor ratings are discussed in IEEE Standard 738, IEEE Standard for Calculating the Current-Temperature Relationship of Bare Overhead Conductors. Ampacity values are to be determined using the fundamental heat balance equation outlined in the House and Tuttle method. Because of the amount and complexity of the equations, this method lends itself to computer application. The recommended computer programs to be used for this calculation either include the BASIC program listed in Annex B of IEEE Standard 738 or an equivalent program, such as the DYNMAP program which is part of the EPRI TLWorkstation TM software package. While tables and graphs may be convenient to use, they fail to take into account the geographic location of the line and often lack either the desired ambient temperature and/or the desired conductor

temperature. The use of tables and graphs is not acceptablerecommended.

7.2.2.1 Conductor Properties

Some computer programs used to compute ampacity values have a conductor property library whereby a user simply specifies the conductor code name and the program will search the conductor property file and select the proper input properties. Those using the BASIC program from Annex B of IEEE Standard 738 or another computer program that does not have a conductor property library will should obtain conductor properties from an appropriate data source (Aluminum Electrical Conductor Handbook, EPRI Transmission Line Reference Book 345 kV and Above, Westinghouse Transmission and Distribution Book, etc.).

7.2.2.2 Line Geographic Location

These factors specify the location of the line, its predominant direction and its predominant inclination. These numbers can either be line specific or they can represent a general line within the control area. One ambient temperature shall should be agreed upon for tie lines traversing several geographic areas and interconnections among different control areas.

7.2.2.3 Radiation Properties

The two radiative properties of conductor material are solar absorptivity and infrared emissivity.

Solar Absorptivity The fraction of incident solar radiant energy that is absorbed by the

conductor surface. This value shall should be between 0 and 1. Recommended values are given in the following tables:

ALUMINUM CONDUCTORS

Service Years

Absorptivity

0<5

0.43

1.00

ALUMINUM CONDUCTORS

Service Years

Emissivity

COPPER CONDUCTORS

Oxidation Level

Absorptivity

None

Light

Normal

Heavy

0.23

0.5

0.7

1.0

Source: Glenn A. Davidson, Thomas E. Donoho, George Hakun III, P. W. Hofmann, T. E Bethke, Pierre R. H. Landrieu and Robert T. McElhaney, "Thermal Ratings for Bare Overhead Conductors", IEEE Trans., PAS Vol. 88, No.3, pp. 200-05, March 1969.

Infrared Emissivity The ratio of infrared radiant energy emitted by the conductor surface to the infrared radiant energy emitted by a blackbody at the same temperature. This value shall should be between 0 and 1. Recommended values are given in tables below:

COPPER CONDUCTORS

Oxidation Level

Emissivity

None

Light

Normal

Heavy

0.03 0.3

0.5

0.8

0 5-10

10-20

0.23 0.82 0.88 0.90

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Source: W. S. Rigdon, H. E. House, R. J. Grosh and W. B. Cottingham, "Emissivity of Weathered Conductors After Service in Rural and Industrial Environments," AIEE Trans., Vol. 82, pp. 891-896, Feb. 1963.

7.2.2.4 Weather Conditions

Ambient temperature represents the maximum seasonal temperature the line may experience for summer and winter conditions. Appendix PL-2.A contains a methodology to compute maximum ambient temperature. Wind speed is assumed at 2 ft/sec (1.4 mph) or higher. Wind direction is assumed perpendicular to the conductor.

7.2.2.5 Maximum Conductor Temperature

The selection of a maximum conductor temperature affects both the operation and design of transmission lines. Existing transmission lines were designed to meet some operating standard that was in effect at the time the line was built. That standard specified the maximum conductor temperature which maintained acceptable ground clearance while allowing for acceptable loss of strength. Over time, the required amount of ground clearance and the maximum conductor temperature needed to maintain acceptable ground clearance have changed. The changes are reflected in the revisions that have been made to the National Electric Safety Code (NESC) over the years. Although this Criteria specifies recommends a maximum conductor temperature that could be met by current line design practices, consideration must should be given to existing lines that were built according to an earlier standard. This Circuit Rrating Ccriteria specifies recommends a maximum conductor temperature (for both normal and emergency operating conditions) that shall should be used for if developing seasonal circuit ratings. For those existing lines that were designed to meet an earlier standard, it is the responsibility of the line owner to establish a rating that is consistent with the NESC design standards being practiced at the time the line was built. This Criteria specifies the use of maximum conductor temperatures that either maintain acceptable ground clearance requirements from earlier NESC's or meet the temperature requirements recommendations in SPP Planning Criteria section 7.2.2.6, whichever is lower.

7.2.2.6 Determination of Maximum Conductor Temperature

The maximum conductor temperature for nNormal rRatings may be limited by conductor clearance concerns. Normal rRatings are at a level where loss of strength is not a concern. The maximum conductor temperature for eEmergency rRatings have both conductor clearance and loss of strength concerns. By setting a maximum conductor temperature and the length of time a conductor may operate at this temperature, the maximum allowable loss of strength over the life of the conductor is prescribed. Unless conductor clearance concerns dictate otherwise, at least the following maximum conductor temperatures shall can be used. This allows for the efficient utilization of the transmission system while accepting minimal risk of loss of conductor strength

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during emergency operating conditions. These conductor temperatures are a result of the examination of SPP members practices.

Maximum Conductor Temperature

Normal Rating

Emergency Rating

ACSR

85°C

100°C

ACAR

85°C

100°C

Copper

85°C

100°C

Copperweld

85°C

100°C

AAC 85°C 100°C

AAAC

85°C

100°C

SSAC

200°C

200°C

Note: Annealing of copper and aluminum begins near 100°C.

7.2.2.7 Hours of Operation at Emergency Rating

The effect of conductor heating due to operating at the maximum temperature during emergency conditions

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is cumulative. If a conductor is heated under emergency loading for 4 hours 8 times during the year, the total effect is nearly the same as heating the conductor continuously at the temperature for 32 hours. Using a useful conductor life of 30 years, the conductor will have been heated to the maximum temperature for 1000 hours. For an all aluminum conductor (AAC), this results in a 7% reduction from initial strength. Since the steel core of an ACSR conductor is essentially unaffected by the temperature range considered for emergency loadings, for an ACSR conductor, this results in a 3% reduction from initial strength. Both of these amounts are acceptable loss of strength. The daily load cycle for operating at the eEmergency rRating shall should not exceed 4 hours. This load cycle duration for conductors operating at the eEmergency rRating is more restrictive than power transformers because power transformers have a delay in the time required to reach a stable temperature following any change in load (caused by a thermal lag in oil rise) and because seasonal ratings shall should allow transmission lines to achieve a maximum conductor temperature throughout the year, not just days when the ambient exceeds 78°F.

7.2.3 Underground Cables

Ampacities are calculated by solving the thermal equivalent of Ohm's Law. Conceptually, the solution is simple, however the careful selection of the values of the components of the circuit Facility is necessary to ensure an accurate ampacity calculation. The recognized standard for almost all steady-state ampacity calculations, in the United States, is taken from a publication, "The Calculation of the Temperature Rise and Load Capability of Cable Systems," by J.H. Neher and M.H. McGrath, 1957, hereafter referred to as the Neher-McGrath method. The procedure is relatively simple to follow and has been verified through testing. In recent years, some of the parameters have been updated, but the method is still the basis of all ampacity calculations.

7.2.3.1 Cable Ampacity

Cable ampacity is dependent upon the allowable conductor temperature for the particular insulation being used. Conductor temperature is influenced by the following factors:

(1) Peak current and load-cycle shape;

(2) Conductor size, material and construction;

(3) Dielectric loss in the insulation;

(4) Current-dependent losses in conductor, shields, sheath and pipe; (5) Thermal resistances of insulation, sheaths and coverings, filling medium, pipe or duct and covering,

and earth; (6) Thermal capacitances of these components of the thermal circuitFacility;

(7) Mutual-heating effects of other cables and other heat sources; and

(8) Ambient earth temperatures.

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Both steady-state and emergency ampacities depend upon these factors, although eEmergency rRatings have a greater dependency upon the thermal capacitances of each of the thermal circuit Facility components.

7.2.3.2 Conductor Temperature

The maximum allowable conductor temperature is 85°C for high-pressure fluid-filled (HPFF), pipe-type cables and 90°C for crosslinked, extruded-dielectric cables.

The table below summarizes allowable conductor temperatures for different insulation materials. Two values are given for each cable insulation. The higher temperature may be used if the thermal environment of the cable is well-known along the entire route, or if controlled backfill is used, or if fluid circulation is present in an HPFF circuitFacility. The maximum conductor temperatures allowed under steady-state conditions are limited by the thermal aging characteristics of the insulation structure of the cable. For emergency-overload operating conditions, maximum conductor temperatures are also limited by the thermal aging characteristics. The temperature is also limited by the melting temperature range of the insulation structure of the cable, its deformation characteristic with temperatures, restraints imposed by the metallic shield, deformation characteristic of the jacket, and the decrease in ac and impulse strengths with increases in temperature.

Insulation Material

Maximum Temperature

Normal

Emergency

Impregnated paper (AEIC CS2-90 for

HPFF and HPGF

(AEIC CS4-79 for SCLF)

85°C

(75°C)

105°C for 100 hr

100°C for 300 hr

Laminated paper-polypropylene (AEIC

CS2-90)

85°C

(75°C)

105°C for 100 hr

100°C for 300 hr

Crosslinked polyethylene (AEIC CS7-87) 90°C

(80°C)

105°C

cumulative for 1500 hr

Ethylene-propylene rubber (AEIC CS6-87) 90°C

(80°C)

105°C*

cumulative for 1500 hr

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Electronegative gas/spacer

Consult manufacturer for specific designs

* Emergency operation at conductor temperatures up to 130°C may be used if mutually agreed between purchaser and manufacturer and verified by qualification and prequalification tests.

7.2.3.3 Ambient Temperature

The ambient temperature is measured at the specified burial depth for buried cables and the ambient air temperature is used for cables installed above ground. IEC Standard 287-1982 (2-5) recommends that in the absence of national or local temperature data the following should be used:

Climate

Ambient Air

Temperature °C

Ambient Ground

Temperature °C

Tropical

55

40

Sub-tropical

40

30

Temperature

25

20

The electrical resistance is composed of conductor dc resistance, ac increments due to skin and proximity effects, losses due to induced currents in the cable shield and sheath and induced

magnetic losses in the steel pipe. Heat generated in the cable system will flow to ambient earth and then to the earth surface. This heat passes through the thermal resistances of the cable insulation, cable jacket, duct or pipe space, pipe covering and soil. Adjacent heat sources, such as other cables or steam mains, will provide impedance to the heat flow and thus reduce cable ampacity. Further information concerning the components of the ampacity calculations are summarized in Appendix PL-2.B and fully detailed in the EPRI Underground Transmission Systems Reference Book. An example calculation, from the EPRI book, is also provided in Appendix PL-2.B.

7.2.4 Switches

Appendix PL-2.C contains a discussion on developing ratings for switches. In general, switches have seasonal ratings that are a function of the maximum ambient temperature. A switch part class designation is used to differentiate loadability curves that give factors which can be multiplied by the rated continuous current

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of the switch to determine temperature adjusted nNormal and 4 hour eEmergency rRatings. The summer nNormal and eEmergency Ratings for switches ratings can be computed by selecting the appropriate loadability factor curve for the switch part class, reading the loadability factors that are appropriate for the summer maximum ambient temperature (40°C or the summer maximum ambient temperature determined in Appendix PL-2.A), and multiplying the continuous current ratings by the loadability factor. The switch winter nNormal and eEmergency ratings for switches can be computed by multiplying the continuous current rating by the nNormal and eEmergency loadability factors that are appropriate for the winter maximum ambient temperature (0°C or the winter maximum ambient temperature determined in Appendix PL-2.A). Appendix PL-2.C contains loadability factor curves (both normal and emergency) for various switch part classes. The ANSI/IEEE standard referenced in Appendix PL-2.C allows for eEmergency rRatings to be greater than nNormal rRatings. This Criteria does not require the eThe Emergency rRating does not need to be greater than the nNormal rRating.

7.2.5 Wave Traps

Appendix PL-2.D contains a discussion on developing ratings for wave traps. The two types of wave traps are the older air-core type and the newer epoxy-encapsulated type. In general, both types have a continuous current rating based on a 40°C maximum ambient temperature. Both types have a loadability factor that can be used to determine seasonal ratings that are a function of the maximum ambient temperature. However, the older air-core type has another loadability factor that can be used to determine a four-hour eEmergency rRating that is also a function of the maximum ambient temperature. The newer epoxy encapsulated type does not have an eEmergency rRating.

7.2.6 Current Transformers

Appendix PL-2.E contains a discussion on developing ratings for current transformers. The two types of current transformers are the separately-mounted type and the bushing type. In general, both types have a continuous current rating based on a 30°C average ambient temperature.

7.2.6.1 Separately Mounted Current Tranformers

The separately-mounted type has an ambient-adjusted continuous thermal current rating factor that can be multiplied by the rated primary current of the current transformer to determine seasonal ratings. Separately-mounted current transformers do not have eEmergency rRatings.

7.2.6.2 Bushing Current Transformers

Bushing current transformers are subject to and influenced by the environment of the power apparatus in which they are mounted. Bushing current transformers can be located within circuit breakers and power transformers. Since bushing current transformers are subject to the environment within the power apparatus,

Commented [JA2]: Feedback from CLECO: Appendix PL-2.E contains a discussion on developing ratings for current transformers. The two types of current transformers are the separately-mounted type and the bushing type. In general, both types have a continuous current rating based on a 30°C average ambient temperature. However, current transformers used in high voltage applications, do not have a primary conductor and only conduct secondary currents through magnetic coupling. Therefore, the primary rating of the CT is only a derived value from the ratio of secondary turns and it does not represent an actual ampacity rating of a primary conductor. Therefore, the CT does not affect or limit the continuous current carrying capacity of the Facility.

of 17

they do not have ambient adjusted continuous thermal current rating factors. Rather, if the primary current rating of the ratio being used is less than the continuous current rating of the breaker or the power transformer, this restricts the breaker or power transformer to operate below its rated current which reduces the current transformer temperature. This allows the current transformer to be operated at a continuous thermal rating factor greater than 1.0. Having a bushing current transformer whose primary current rating of the ratio being used is less than the continuous current rating of the breaker or the power transformer is an unusual case. However, the formula to develop the rating factor for this case is located in Appendix PL-2.E. Although bushing current transformers have some short-term emergency overload capability, it must be coordinated with the overall application limitation of the other equipment affected by the current transformer loading. Consequently, this criteria does not recognize an eEmergency rRating for bushing current transformers.

7.2.7 Circuit Breakers

Appendix PL-2.F contains a discussion on developing ratings for circuit breakers. This discussion centers on the use of specific circuit breaker design information to set seasonal and eEmergency rRatings. This design information is not readily available to the owners of such equipment. To use the rating methodology discussed in Appendix PL-2.F would require contacting the manufacturer for detailed design information for each circuit breaker being rated. Rather than doing that, this circuit rating criteria specifies that the nameplate rating shall should be used for seasonal nNormal and eEmergency rRatings. The nameplate rating is based on a maximum ambient temperature of 40°C. If a circuit breaker is found to be a limiting element in a circuit and is experiencing loadings that limit operations, a member system may pursue the methodology outlined in Appendix PL-2.F to determine the circuit breakers seasonal nNormal and eEmergency rRating.

7.2.8 Ratings of Series and Reactive Elements

The series transmission elements rating will be in amps, ohms, and MVA. The series transmission elements current (amps) rating will be taken as the minimum rating of all internal components (e.g., breakers) that are in series with the interconnected transmission circuitFacility. Shunt reactive elements (e.g., capacitors, reactors) MVA ratings will be based on the nominal transmission interconnecting voltage.

The documentation of the methodology(ies) used to determine the rating of series and reactive elements shall be provided to SPP and/or NERC on request within five business days.

7.2.9 Ratings of Energy Storage Devices

The available real power rating, reactive power rating, control points, and availability of each electrical energy storage device will be provided to SPP upon request. The documentation of the methodology(ies) used to rate electrical energy storage devices shall be provided to SPP and/or NERC on request within five business days.

7.2.10 CircuitFacility Rating Issues

Commented [JA3]: This is covered by FAC-008 R8.

Commented [JA4]: This is covered by FAC-008 R8.

of 17

7.2.10.1 Dynamic (Real Time) Ratings

The calculation of static thermal ratings specified in SPP Planning Criteria section 7.2.2.6 uses worst case thermal and operational factors and therefore apply under all conditions. Often times, these worst case thermal and operational factors do not all occur at the same time. Consequently, a static rating may understate the thermal capacity of the circuitFacility. For operation purposes, some members have elected to monitor the factors that affect circuit Facility rRatings and use this information to set dynamic ratings. A member can develop and use a rating that exceeds the static thermal rating for operating purposes. The ratings developed by using this criteria are not intended to restrict daily operations but set a minimum rating that can be increased when factors for determining the equipment rating have changed. However, if transmission line rFacility Ratings are changed dynamically, the required clearances shall should still be met.

7.2.10.2 Non-Thermal Limitations

There may be instances when the flow on a transmission circuit Facility is limited by factors other than the thermal capacity of its elements. The limit may be caused by other factors such as dynamics, phase angle difference, relay settings or voltage limited.

7.2.10.3 Tie Lines

When a tie line exists between two member systems, use of this criteria shall should result in a uniform circuit Facility rRating that is determined on a consistent basis between the two systems. For tie lines between a SPP member and a non-member, the member shall should follow this criteria to rate the circuit elements owned by them and shall should coordinate the rating of the tie line with the non- member system such that it utilizes the lowest rating between the two systems.

7.2.10.4 Rating Inconsistencies

A member may have a contractual interest in a joint ownership transmission line whereby the capacity of the line is allocated among the owners. The allocated capacity may be based upon the thermal capacity of the line or other considerations. Members shall should use good faith effort to amend their transmission line agreements to reflect the effects of new circuit rFacility Ratings. There may exist other transmission agreements or regulatory mandates that use the thermal capacity of transmission circuitsFacilities in allocation of cost and determination of network usage formulas (for example, the MW-mile in ERCOT). These agreements and mandates may specify a methodology and/or factors for computing thermal capacity used in the formulas. Since these amounts are only used in assignment of cost or usage responsibility and not in actual operations of the transmission system, there is no conflict with using a different set of ratings for this specific purpose.

7.2.10.5 Damaged Equipment

There may be instances when a derating of a transmission line element is required due to damaged

of 17

equipment. The limit may be caused by such factors as broken strands, damaged connectors, failed cooling fans, or other damage reducing the thermal capability.

7.2.11 Reporting Requirements

Each member will administer this Criteria and will make available upon request the application of this Criteriarating methodology for those facilities that impact another member (i.e. force them to curtail schedules due to line loadings, denies them access to transmission service or requires them to build new transmission facilities or pay opportunity costs to receive transmission service).


Integrated Transmission Planning (ITP) Manual

Minimum Transmission Design Standards for Competitive Upgrades (MTDS)

Reliability Coordinator and Balancing Authority Data Specifications (RDS)

SPP Communications Protocols

Revision Request Process

ITP2019

2

2019 ITPScheduleJuliano Freitas

April 9, 2019

ITP2019Solutions Development &

Validation (Complete)• Start: 1/8/2019

• End: 3/20/2019

• Staff Leaders: Reliability: Kelsey Allen ([email protected]) Economic/Policy: Nikki Roberts ([email protected]) Operational: Will Tootle ([email protected]) Short Circuit: Jason Terhune ([email protected])

26





ITP2019Solutions Evaluations

(Complete)• Start: 1/8/2019

• End: 3/20/2019

• Staff Leaders: Reliability: Kelsey Allen ([email protected]) Economic: Liz Gephardt ([email protected]) Policy: Nikki Roberts ([email protected]) Operational: Will Tootle ([email protected]) Short Circuit: Jason Terhune ([email protected])

27






ITP2019Reliability Portfolio

Development – Phase 1• Start: 3/21/2019

• End: 4/03/2019

• Staff Leader: Kelsey Allen ([email protected])

28


ITP2019

Project Grouping – Phase 1(Conceptual Costs)

• Start: 3/21/2019

• End: 4/03/2019

• Staff Leader: Amber Greb ([email protected])

29


ITP2019

Study Cost Estimates – Round 1• Start: 4/04/2019

• End: 5/08/2019

• Member Response Time: 4/11/19 – 5/08/19 (20 days)

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

30


ITP2019

Project Grouping – Phase 2(Study Cost Estimates)• Start: 5/08/2019

• End: 5/14/2019


31


ITP2019

Reliability Portfolios Development – Phase 2• Start: 5/09/2019

• End: 5/14/2019


32


ITP2019

Initial Final Reliability Assessments• Start: 5/16/2019

• End: 5/28/2019

• Staff Leader: Dee Edmondson ([email protected])

33


ITP2019

Planning Summit• Start: 5/10/2019

• End: 5/30/2019

• Member Review Time: Summit Materials (7 days prior to meeting) Planning Summit: 5/29, 1-5pm; 5/30, 8-12pm

• Staff Leader: Ellen Bailey ([email protected])

34


ITP2019

Reliability Portfolios Development – Phase 3• Start: 5/30/2019

• End: 6/07/2019


35


ITP2019

Project Grouping – Phase 3(Summit Feedback)• Start: 5/30/2019

• End: 6/07/2019


36


ITP2019


• End: 6/26/2019

• Member Response Time: 6/13/2019 – 6/26/2018 (10 days)


37


ITP2019

Final Reliability Portfolios Development• Start: 6/27/2019

• End: 6/28/2019


38


ITP2019

Final Reliability Assessments• Start: 7/01/2019

• End: 7/02/2019


39


ITP2019

Project Grouping – Phase 4(Final)

• Start: 6/27/2019

• End: 6/28/2019


40


ITP2019

Project Grouping – Final Determination• Start: 7/01/2019

• End: 7/08/2019


41


ITP2019

Optimization• Start: 7/9/2019

• End: 7/17/2019

• Staff Leader: Kalen Coleman ([email protected])

42


ITP2019

Portfolio Consolidation• Start: 7/18/2019

• End: 8/2/2019

• Staff Leader: Liz Gephardt ([email protected])

43


ITP2019

Project Staging• Start: 8/5/2019

• End: 8/15/2019

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

44


ITP2019

Benefit Metrics Calculation• Start: 8/2/2019

• End: 8/26/2019

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

45


ITP2019

Stability Analysis• Start: 8/5/2019

• End: 8/26/2019

• Staff Leader: Chris Jamieson ([email protected])

46


ITP2019

Sensitivity Analysis• Start: 8/5/2019

• End: 8/26/2019

• Member Review Time: 8/19/2019 – 8/23/2019 (5 days)

• Staff Leader: Kirk Hall ([email protected])

47


ITP2019

Final Reliability Assessment• Start: 8/5/2019

• End: 8/27/2019


48


ITP2019

Rate Impacts/ATRR• Start: 8/15/2019

• End: 8/28/2019


49


ITP2019

Final Report• Start: 8/1/2019

• End: 9/18/2019


50


ITP2019

TWG/ESWG Final Approvals• Start: 9/26/2019

• End: 10/3/2019


• Staff Leaders: TWG – Aaron Stewart ([email protected]) ESWG – Amber Greb ([email protected])

51



ITP2019

MOPC and SPP Board • Start: 9/6/2019

• End: 10/29/2019

• Member Review Time: MOPC: 10/7/2019 – 10/15/2019 (7 days) SPP Board: 10/22/2019 – 10/29/2019 (5 days)

52

ITP2020

2

2020 ITPScheduleJuliano Freitas

April 9, 2019

ITP2020Powerflow Model (Complete)

• Start: 7/09/2018

• End: 2/22/2019 (Final Approval)

• Member Review Time: Pass 0 – Trial 1: 7/13/2018 – 7/20/2018 (5 days) Pass 0 – Trial 2: 8/03/2018 – 8/24/2018 (15 days) Pass 1: 9/14/2018 – 9/21/2018 (5 days) Pass 2: 10/05/2018 – 10/26/2018 (15 days) Pass 3: 11/16/2018 – 12/07/2018 (15 days) Pass 4: 12/21/2018 – 1/11/2019 (15 days) Final Data Submission Deadline: 1/11/2019 Final Initial ITP: 2/11/2019 – 2/15/2019 (5 days) Final Initial ITP Approval: 2/22/2019 Final ITP Approval with Oct. 2019 Board approved projects in Nov.

2019

• Staff Leader: David Duhart ([email protected])

• Working Group Approval: TWG 6


ITP2020

Short Circuit Model• Start: 11/14/2018

• End: 2/28/2019

• Member Review Time: Pass 1: 12/14/2018 – 1/11/2018 (6 days) Pass 2: 2/08/2019 – 2/15/2019 (6 days) Pass 3: 2/21/2019 – 2/28/2019 (6 days) (MDWG Approval) Complete Final ITP Approval with Oct. 2019 Board approved projects in Nov.

2019

• Staff Leader: Theva Coleman ([email protected])

• Working Group Approval: TWG

7


ITP2020

Load Review (Complete)• Start: 7/23/2018

• End: 2/20/2019 (Member’s Final Approval)

• Member Review Time: Load Pass 1: 9/17/2018 – 9/28/2018 (10 days) Load Pass 2: 10/15/2018 – 10/26/2018 (10 days) Load Pass 2 Update*: 10/18/2018 – 10/31/2018 (10 days) Load Pass 3: 11/26/2018 – 12/07/2018 (10 days) Final Posting for Approval: 2/08/2019 (7 days)


• Working Group Approval: ESWG

* Posting based on approved ESWG items

8


ITP2020

Generation Review (Complete)• Start: 7/23/2018


• Member Review Time: Gen Pass 1: 9/17/2018 – 9/28/2018 (10 days) RAR & Waiver Request to Stakeholders: 9/21/2018 – 10/26/2018

(25 days) Gen Pass 2: 10/15/2018 – 10/26/2018 (10 days) Gen Pass 2 Update*: 10/18/2018 – 10/31/2018 (10 days) Gen Pass 3: 11/26/2018 – 12/07/2018 (10 days) Final Posting for Approval: 2/08/2019 (7 days)



* Posting based on approved ESWG items

9


ITP2020Renewable Policy Review

(Complete)

• Start: 2/01/2019



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


10


ITP2020

Policy Renewable Resource Plan – Phase 1 (Complete)• Start: 2/22/2019



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


11


ITP2020

Renewable & Conventional Resource Plan – Phase 2• Start: 2/6/2019





12


ITP2020Siting Plan & Generator Outlet

Facilities (GOFs)• Start: 2/01/2019


• Member Review Time: Siting Plan

Site Prioritization: 5/17/2019 – 5/23/2019 (6 days) Site Assignment Renewable: 6/05/2019 – 6/11/2019 (6 days) Site Assignment Storage: 6/05/2019 – 6/11/2019 (6 days) Site Assignment Conventional: 6/05/2019 – 6/11/2019 (6 days) Site Assignment External: 6/05/2019 – 6/11/2019 (6 days) Siting Plan ESWG Approval: 6/13/2019

GOFs GOFs: 7/02/2019 – 7/10/2019 (5 days) GOFs TWG Approval: 7/10/2019

• Staff Leaders: Siting Plan: Joshua Norton ([email protected]) GOFs: Brooke Keene ([email protected])

• Working Group Approval: ESWG (Siting Plan)/TWG (GOFs)13



ITP2020

Market Economic Model Build• Start: 2/01/2019


• Member Review Time: Post 1: 5/08/2019 – 5/15/2019 (6 days) Post 2: 8/05/2019 – 8/09/2019 (5 days) Initial ESWG Member Approval: 8/14/2019 Post for Final Approval: 12/03/2019 – 12/10/2019 (6 days) Final ESWG Member Approval: 12/11/2019

• Staff Leader: Clayton Mayfield ([email protected])


14


ITP2020Market Economic

Benchmarking• Start: 4/30/2019


• Member Review Time: Post for Review: 6/13/2019 – 6/20/2019 (6 days) Post for Final Approval: 7/10/2019 – 7/17/2019 (6 days) Final ESWG Member Approval: 7/18/2019

• Staff Leader: Clayton Mayfield ([email protected])


15


ITP2020

Model Updates• Start: Pass 1 Powerflow Model (7/09/2018)

• Initial End: 2/15/2019

• Final End: 11/15/2019 (New NTCs and withdrawals approved by the Oct. 2019

MOPC/Board, and NTC re-evaluations)

• Staff Leader: David Duhart ([email protected])


16


ITP2020

Constraint Assessment• Start: 8/2/2019


• Staff Leader: Kirk Hall ([email protected])


17


ITP2020

Market Powerflow Models (BA Reliability)

• Start: 11/15/2019




18


ITP2020

Base Reliability Needs Assessment• Start: 11/15/2019

• End: 3/14/2020

• Staff Leader: Jason Speer ([email protected])

19


ITP2020

Market Powerflow Reliability Needs Assessment• Start: 1/02/2020

• End: 3/14/2020

• Staff Leader: Jason Speer ([email protected])

20


ITP2020

Economic Needs Assessment• Start: 1/02/2020

• End: 3/14/2020


21


ITP2020Public Policy Needs

Assessment

• Start: 1/02/2020

• End: 3/14/2020


22


ITP2020

Operational Needs Assessment

• Start: 1/02/2020

• End: 3/14/2020

• Staff Leader: Will Tootle ([email protected])

23


ITP2020

Short Circuit Needs Assessment

• Start: 1/02/2020

• End: 3/14/2020

• Staff Leader: Jason Terhune ([email protected])

24


ITP2020

DPP Window

• Start: 3/15/2020 12:00 a.m.

• End: 4/13/2020 11:59 p.m.

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

days)


25


ITP2020Solutions Development &

Validation• Start: 3/15/2020

• End: 6/10/2020

• Staff Leaders: Reliability: Kelsey Allen ([email protected]) Economic: Liz Gephardt([email protected]) Policy: Liz Gephardt([email protected]) Operational: Will Tootle ([email protected]) Short Circuit: Jason Terhune ([email protected])

26






ITP2020

Solutions Evaluations• Start: 3/15/2020

• End: 6/10/2020

• Staff Leaders: Reliability: Aaron Stewart ([email protected]) Economic: Amber Greb ([email protected]) Policy: Amber Greb ([email protected]) Operational: Will Tootle ([email protected]) Short Circuit: Jason Terhune ([email protected])

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ITP2020Reliability Portfolio

Development• Start: 2/15/2020

• End: 6/10/2020


28


ITP2020

Project Grouping & Ranking• Start: 3/15/2020

• End: 8/14/2020

• Staff Leaders: Nikki Roberts ([email protected])

29


ITP2020


• End: 6/25/2020


30


ITP2020

Planning Summit• Start: 6/25/2020

• End: 7/10/2020

• Member Review Time: Summit Materials (7 days prior to meeting)


31


ITP2020


• End: 7/25/2020


32


ITP2020

Final Reliability Portfolios Development• Start: 7/26/2020

• End: 8/14/2020


33


ITP2020

Optimization & Portfolio Consolidation• Start: 8/16/2020

• End: 9/18/2020

• Staff Leaders: Liz Gephardt ([email protected]) Amber Greb ([email protected])

34



ITP2020

Project Staging• Start: 8/14/2020

• End: 9/18/2020


35


ITP2020

Benefit Metrics Calculation• Start: 8/14/2020

• End: 9/18/2020


36


ITP2020

Stability Analysis• Start: 8/14/2020

• End: 9/18/2020


37


ITP2020

Sensitivity Analysis• Start: 8/14/2020

• End: 9/18/2020

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

38


ITP2020

Final Reliability Assessment• Start: 8/14/2020

• End: 9/18/2020

• Staff Leader: Aaron Stewart ([email protected])

39


ITP2020

Rate Impacts/ATRR• Start: 8/14/2020

• End: 9/18/2020


40


ITP2020

Final Report• Start: 8/1/2020

• End: 9/18/2020


41


ITP2020

TWG/ESWG Final Approvals• Start: 9/25/2020

• End: 10/2/2020

• Staff Leaders: TWG – Aaron Stewart ([email protected]) ESWG – Amber Greb ([email protected])

42



ITP2020

MOPC and SPP Board • Start: 9/6/2020

• End: 10/27/2020

• Member Review Time: MOPC: 10/2/2020 – 10/13/2020 (7 days) SPP Board: 10/20/2020 – 10/27/2020 (5 days)

43

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