Southwest Power Pool, Inc. JOINT QUARTERLY ... quarterly...M1 Antoine Lucas Micha Bailey M2 Bruce Rew Barbara Stroope M3 Bruce Rew Greg Sorenson M4 Bruce Rew Charles Cates Marketplace

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

Southwest Power Pool, Inc.

JOINT QUARTERLY STAKEHOLDER MEETING

April 27, 2020

Net Conference

Agenda

3:00 p.m.

Call to Order Quarterly Briefings

1. SPP’s Response to Pandemic………………………………………………………………………..……….Ms. Barbara Sugg

2. Federal Energy Regulatory Commission (FERC) Update……………………………………......Mr. Patrick Clarey

3. HITT Implementation Update………..……………………………………………………………………..……Mr. Paul Suskie

4. SPP RSC/OMS Seams Liaison Committee Update……………………………………………...Mr. Adam McKinnie

5. Integrated Transmission Plan (ITP) Assessment Update…………………………….…………Mr. Antoine Lucas

6. Integrated Marketplace Update………………………………………………………………………………….Mr. Bruce Rew

7. Western Operations……………………………………………………………………………………………………Mr. Bruce Rew

8. Corporate Metrics Update…………………………………………….………………………………………..Mr. Lanny Nickell

9. Strategic Planning Process……………………………………………………………………………..…… Larry Altenbaumer

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

HITT PROGRAM UPDATEPAUL SUSKIESTRATEGIC PLANNING COMMITTEEAPRIL 2020

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HITT PROGRAM UPDATE OUTLINE• HITT Program High-level Update & SPP Staff Lead Changes

• SPP BOD Approval Items – April 2020 • T2 – Est. Uniform Sch. 9 Local Planning Criteria (RR 391)• C3 – Eliminate ATT. Z2 Revenue Crediting Prospectively (RR 401)

• Status Updates • M1 – Implement Congestion Hedging Improvements

• Status Update on HITT Recommendation with Schedule Extensions

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HITT HIGH-LEVEL UPDATE&SPP STAFF LEAD CHANGESAPRIL 2020

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HITT PROGRAM SPONSORSHIP CHANGES• Transition of Ownership of the HITT Initiatives previously assigned to Lanny Nickell have been transferred to Antoine Lucas

• S3: Energy Storage Whitepaper – Lanny Nickell will be the executive sponsor for Implementation

• Electricity Storage Resources Steering Committee

• https://www.spp.org/organizational-groups/board-of-directorsmembers-committee/markets-and-operations-policy-committee/electric-storage-resources-steering-committee/

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https://www.spp.org/organizational-groups/board-of-directorsmembers-committee/markets-and-operations-policy-committee/electric-storage-resources-steering-committee/

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HITT PROGRAM STRUCTURE CHANGES

Started

Not Started

HITT Goal Complete (Implementation Required)

Additional Scope - Started(Implementation Required)

HITT Goal Complete

Legend

Note: Colors are not reflective of project health

M1Antoine LucasMicha Bailey

M2Bruce Rew

Barbara Stroope

M3Bruce Rew

Greg Sorenson

M4Bruce Rew

Charles Cates

Marketplace

R1a, R1b, R1cBruce Rew

Charles Cates

R2Bruce RewGary Cate

R3aBruce Rew

Debbie James

R3b-1Bruce Rew

Jim Gonzalez

Reliability

R3cBruce RewGary Cate

C1Paul Suskie

Charles Locke

C2Paul Suskie

Charles Locke

C3Paul Suskie

Tessie Kentner

C4Paul Suskie

Charles Locke

Cost Allocation

T1Antoine LucasSteve Purdy

T3Antoine Lucas

Jason Davis

T4Antoine LucasSteve Purdy

T5Antoine LucasAmber Greb

Transmission Planning

S1Barbara SuggJoshua Phillips

S2Barbara SuggJoshua Phillips

S3Paul Suskie

Richard Dillon

Strategic

R4Bruce Rew

Ryan Shoppe

R5Bruce Rew

Charles Cates

T2Antoine LucasDee Edmondson

R3b-2Bruce Rew

Jim Gonzalez

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HITT APPROVAL ITEMSSPP BOARD OF DIRECTORSAPRIL 2020

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SouthwestPowerPool SPPorg southwest-power-poolHelping our members work together to keep the lights on... today and in the future. 9

HITT T2 UPDATEESTABLISH UNIFORM SCHEDULE 9 LOCAL PLANNING CRITERIA

9

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#2 Establish uniform Schedule 9 local planning criteria

• Establish uniform local planning criteria within each Schedule 9 pricing zone

• Criteria can vary between zones• Transmission Owners (TOs) within each zone should be subject to

same local criteria in determining need for zonal reliability upgrades within zone

• Host TO should invite zone’s TOs & transmission customers to participate when developing zonal criteria before submitting to SPP

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HITT T2 - UNIFORM LOCAL PLANNING CRITERIA

• Changes the way Local Planning Criteria or Company Specific Planning Criteria is submitted to SPP for consideration of Zonal Reliability Upgrades.• Creates Zonal Planning Criteria

• Instead of each individual TO submitting their Local Planning Criteria to SPP, a Facilitating Transmission Owner may submit a single Zonal Planning Criteria for their Zone.• Determined by Network Customer with largest load

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HITT T2 – WORKING GROUPS ACTIONS (RR 391)• TWG

• Approved 12/18/2019 with 4 abstentions and 4 oppositions• Approved 2/4/2020 with 1 abstention and 6 oppositions

• ESWG – Unanimously Approved 3/5/2020

• RCWG – Approved 3/9/2020 with 2 oppositions

• RTWG – Approved 3/19/2020, 5 oppositions, 2 abstentions

• MOPC April 2020• RR 391 was approved with 74.3% approving.

• SPC April 2020• RR 391 was approved 9 For, 1 Against, 3 Abstaining.

• BOD Vote April 2020 13 of 154


HITT C3 UPDATEELIMINATE ATTACHMENT Z2 REVENUE CREDITING FOR NEW UPGRADES

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HITT RECOMMENDATION

• Eliminate Z2 revenue credits prospectively

• Retain incremental long-term congestion rights (ILTCRs) for new upgrades

• ILTCRs function as currently described in Tariff, except that the total compensation would be limited to each upgrade’s directly assigned upgrade costs plus interest

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RR 374

• Tariff language necessary to implement HITT Z2 recommendation

• To be implemented with a bright-line effective date• All agreements authorizing construction of an eligible

Network Upgrade that are executed on or after bright-line date will be eligible for ILTCRs.

• All agreements authorizing construction of an eligible Network Upgrade that are executed prior to bright-line date will continue to be eligible for Z2 revenue credits.

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RR 374 TIMELINE• October 2019- Approved by CAWG, MOPC and RSC.

• The MOPC approval of RR 374 also included the directive that an effective date of February 1, 2020 be requested for the Tariff revisions –the earliest possible effective date SPP staff indicated was an option.

• After MOPC approval, no SPP member appealed the matter to the SPP Board of Directors.

• November 22, 2019- SPP filed the Tariff changes in RR 374 at FERC in Docket No. ER20-453.• Joint protest was filed by the Renewable Developers.

• January 31, 2020- FERC issued an order rejecting SPP’s filing without prejudice.

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JANUARY 31 FERC ORDER• FERC found that the proposal to modify the existing term of compensation

for ILTCRs (i.e., 10 to 20 years) to 20 years or until the upgrade sponsor recovers the directly assigned upgrade costs with interest, whichever occurs earlier, was not just and reasonable.

• FERC rejected SPP’s filing, “without prejudice to SPP submitting a revised proposal that does not impose a cap that limits the term and potential value of ILTCRs.” • This statement addressed SPP’s proposal to limit the term to a period

shorter than that specified in the contract in the event that the upgrade sponsor receives full compensation for its directly assigned costs including interest.

• This was the only issue of concern raised by FERC in the order rejecting SPP’s filing.

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RR 401• SPP proposes changes to the Tariff language approved in RR 374 that will allow

SPP to submit a revised proposal consistent with FERC’s rejection of a term limit tied to the date of full compensation for the upgrade sponsor’s directly assigned costs including interest:• Attachment J, Section V- SPP proposes to remove the cap on the amount

recoverable through the candidate ILTCRs and revert back to the provisions that are currently effective in the SPP Tariff allowing for a term of at least 10 years but not more than 20 years for candidate ILTCRs.

• Attachment Z2, Section IV.A(e)- SPP proposes to remove the language that capped on the amount recoverable through the candidate ILTCRs to the directly assigned upgrades costs plus interest.

• Agreements in Attachments A, A-1, F, J and V- SPP removed the term “maximum” from the placeholder for the term of the ILTCR.

• All the other revisions contained in RR 374 remain unchanged.

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RR 401 TIMELINE• 2/27 – RTWG education• 3/3 – CAWG education• 3/19 – RTWG approved• 4/9 – CAWG approved• 4/14 - MOPC approved

• RR 401 was approved (1 No vote & 7 Abstentions) • 4/15 – SPC approved

• RR 401 was approved (1 Abstentions) • 4/27 – RSC review and vote• 4/28- BOD review and vote

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HITT STATUS UPDATEAPRIL 2020

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#1 Implement congestion hedging improvements

• Continue with market mechanism to hedge load against congestion charges

• Existing design should include modifications to implement counter-flow optimization limited to excess auction revenues

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#1 Implement congestion hedging improvements

2019 2020Aug. Sept. Oct. Nov. Dec. Jan. Feb. Mar. Apr. May June July Aug. Sept.

Staff straw proposal MWG develop policy white paperMOPC/

RSC endorse

Draft tariff language

MOPC/RSC

endorseFERC filing

Stakeholder completion goal April 2020Lead group MWGSecondary group RSC, CAWGHITT vote 14 to 0 with 1 abstention

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SUMMARY

• During the Jan 2020 MWG meeting, the MWG voted to keep the current Market Design for Congestion Hedging. In Feb, SPP staff asked the MWG why they believe that the current Market Design for Congestion Hedging is superior to the HITT approach of optimizing counter-flow. SPP staff also asked the MWG members if they had to pick from the three policy ideas presented, which one they would choose. • SPP staff has developed a white paper that optimizes counter flow after the TCR

Auction and assigns those counter flow ARR MWs to the annual ARR Surplus. • AEP has submitted a policy idea to optimize counter flow after the ARR Allocation and

assign the costs of those counter-flow ARR MWs directly to the MPs. • SECI has submitted a policy idea to optimize counter-flow in the LTCR Allocation

process and assign the costs of those counter-flow ARR MWs directly to the MP. When the counter-flow LTCR MWs become infeasible, then those infeasible LTCR MWs costs are assigned to the ARR Surplus.

• All three options failed to gain approval by the MWG in February25 of 154

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MOPC AND SPC ACTIONS ON M1

• MOPC Approved the following motion with 80.3% in favor:“MOPC does not support the current Option 2 for recommendation to the board and directs the MWG to further develop Option 1.”

• SPC to hold a Educational Workshop on HITT Recommendation M1: Implement Congestion Hedging Improvements.

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HITT STATUS UPDATE GOAL EXTENSIONS

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HITT STATUS UPDATE – GOAL EXTENSIONSHITT Recommendation Disposition Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22

HITT R1a: Study ERS and ORS: Voltage/Reactive Supply In Progress Original Goal

HITT R1b: Study ERS and ORS: Frequency/Inertia Needs In Progress Original Goal

HITT R1c: Study ERS and ORS: Balancing Requirements For SPP In Progress Original Goal

HITT R2: Implement ERS/ORS Compensation Model Not Started Original Goal New Goal

HITT R3a: Implement Marketplace Enhance (Ramping Capability) Complete COMPLETE

HITT R3b-1: Implement Marketplace Enhance (Fast Start) Complete COMPLETE

HITT R3b-2: Implement Marketplace Enhance (Fast Start) In Progress Original Goal New Goal

HITT R3c: Implement marketplace enhance (Multi-Day, LT Mkt) In Progress Original Goal New Goal

HITT R4: Implement Uncertainty Market Product In Progress Original Goal

HITT R5: Study additional operational tools In Progress Original Goal

HITT M1: Implement congestion hedging improvements In Progress Original Goal

HITT M2: Study Offer Requirements for Variable Resources In Progress Original Goal

HITT M3: Study automatic mitigation of unduly low offers In Progress Original Goal

HITT M4: Study Economic Evals of Reliability In Progress Original Goal New Goal

HITT T1: ERIS Modifications & NRIS Accreditation/Delivery In Progress Original Goal New Goal

HITT T2: Establish Uniform Sched 9 Local Planning Criteria In Progress Original Goal New Goal

HITT T3: Implement new load addition modifications In Progress Original Goal New Goal

HITT T4: Study three-phase GI process effectiveness Not Started Original Goal

HITT T5: Evaluate benefit-to-cost ratio for economic project In Progress Original Goal New Goal

HITT C1: Decouple Schedule 9 & Schedule 11 pricing zones In Progress Original Goal

HITT C2: Establish byway facility cost allocation review proc In Progress Original Goal

HITT C3: Eliminate Attachment Z2 rev credit for new upgrades Complete COMPLETE

HITT C4: Study cost allocation for transmission storage In Progress Original Goal

HITT S1: Add technological advances to SPP strategic plan Complete COMPLETE

HITT S2: Continue to include seams in SPP strategic plan Complete COMPLETE

HITT S3: Storage white paper Complete COMPLETE 29 of 154


QUESTIONS

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CONTACT:Paul Suskie, HITT Executive [email protected]

Russell Quattlebaum, HITT Program Business [email protected]

Erica Brooks, HITT Program [email protected]

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mailto:[email protected]




1

RSC-OMS SEAMS LIAISON COMMITTEE UPDATEAPRIL 27, 2020SHARI ALBRECHT, KANSAS CORPORATION COMMISSION

ADAM MCKINNIE, MISSOURI PUBLIC SERVICE COMMISSION

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GOALS OF PRESENTATION______________________________________

• Provide an overview of SPP Regional State Committee SPP (RSC) – Organization of MISO States (OMS) Seams Liaison Committee (SLC) activities

• Provide updates on Seams Liaison Committee activities over the last quarter

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SLC MEMBERS______________________________________

• SPP RSC Members• Shari Feist Albrecht,

Kansas (lead)• Kristie Fiegen, South

Dakota• Kim O’Guinn,

Arkansas• DeAnn Walker, Texas

• OMS Members• Ted Thomas,

Arkansas (lead)• Eric Skrmetta,

Louisiana• Julie Fedorchak,

North Dakota • Matt Schuerger,

Minnesota• Nick Wagner, Iowa (ex

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SLC GOALS______________________________________

Identify potential improvements in the following areas and work with SPP and MISO on implementation:

• Increase benefits to ratepayers in both markets by improving market-based transactions and operations across the seam.

• Ensure equal consideration of beneficial regional and inter-regional projects in transmission planning, including evaluation of projects identified in the Coordinated System Plans.

• Support the timely interconnection of new resources that includes consideration of the dynamics of the interconnection queue in both RTOs.

• Improve inter-RTO relations through state-led cooperation.

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SLC MEETINGS______________________________________

Three meetings since January• In-person meeting at NARUC, February 9,

2020 (Washington D.C.)• Monthly Call, March 9, 2020• Monthly Call, April 13, 2020

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FEBRUARY 2020______________________________________• Reviewed stakeholder feedback on market monitors’ Tier 1

reports and recommended further follow-up with MISO IMM on joint dispatch benefits and with MISO and SPP on stakeholder comments regarding the unreserved use study

• Reviewed Tier 2 Market Monitor Scoping Documents Coordinated Transaction Scheduling (SPP MMU) Interface Pricing (MISO IMM)

• Presentation by MISO & SPP on Reliability Issues and Coordination for Interregional Planning describing how reliability projects are considered in both the regional and interregional processes

• Reviewed past Coordinated System Plan projects with 2019 M2M flowgates and agreed to work toward issue submission at MISO and SPP joint meeting on March 10th.

Meeting materials are available on the RSC and OMS websites. 37 of 154

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MARCH 2020______________________________________

Reviewed responses from market monitors on low Joint Dispatch benefit totals and scoping changes to the proposed Coordinated Transaction Scheduling study• Agreed to submit to MISO-SPP Joint Issue Meeting

requests related to:Interregional Reliability Coordination Projects, for

more transparency into coordination processes of individual TOs and for information about the RTOs’ roles in supporting coordination across the seamReciprocal Coordinated Flowgates, for updated

analysis of historical congestion Meeting materials are available on the RSC and OMS websites.

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APRIL 2020______________________________________

• Presentations by Market Monitors Coordinated Transaction Scheduling (SPP MM) Market-to-Market (MISO IMM)

• Stakeholder Presentations on TO Reliability Coordination (Xcel) and phone comments from Ameren and Entergy

• Update: Seam Congestion Analysis – SPP and MISOHistorical M2M SettlementsM2M flowgate review for congestion analysisCongestion cost analysis

• Overview of Incentives NOPR and discussed filing comments at FERC; no action was taken

• Meeting materials are available on the RSC and OMS websites.

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NEXT STEPS______________________________________

• Phone Call on May 11, 2020 at 1:00 p.m. to:• Follow-up on Action Items• Review Market Monitor Tier 2 reports• Evaluate need for additional information from

MISO and SPP regarding Seams Congestion analysis

• Continue NOPR discussion

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ITP

ITP QUARTERLY UPDATEANTOINE LUCAS

APRIL 2020

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2020 ITP42 of 154

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2020 ITP PROJECT STATUS

Project is under moderate risk• System needs identified and posted – March 25th

• Detailed Project Proposal (DPP) window – April 23rd Close• DPP volume most significant factor in project risk

• Staff solution development - Ongoing• Staff and stakeholder solution evaluation - Ongoing• Transmission Planning Summit – July

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MISO REGIONAL DIRECTIONAL TRANSFER (RDT)2020 ITP TARGET AREA DESCRIPTION

• Why a target area?• MISO request to study additional firm transfer between MISO

regions• Higher flows between MISO North & South regions in MTEP20

• What does the target area accomplish?• Additional focused analysis of potential impacts to SPP system• Broader ‘outside the box’ look at issues and solutions

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MISO RDT 2020 ITP TARGET AREASTAKEHOLDER ENGAGEMENT OPPORTUNITIES

• SPP ITP DPP Transmission Planning Response Window• Open now until April 23, 2020 at 11:59 p.m.• Submission of projects to address needs posted March 24, 2020

• SPP Working Group Meetings• Transmission Working Group (TWG) – May 5-6• Economic Studies Working Group (ESWG) - May 6-7• Operating Reliability Working Group (ORWG) – May 7• Seams Steering Committee (SSC) – May 13

• SPP/MISO IPSAC Meetings – TBD• SPP Planning Summit – July 2020

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https://www.spp.org/documents/61876/2020%20itp%20needs%20assessment%20transmittal%20(3-24-2020).pdf

https://www.spp.org/events/calendar/transmission-working-group-face-to-face-20200505-06/

https://www.spp.org/events/calendar/economic-studies-working-group-face-to-face-20200506-07/

https://www.spp.org/events/calendar/operating-reliability-working-group-net-conference-20200507/

https://www.spp.org/events/calendar/seams-steering-committee-net-conference-20200513/

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2021 ITP SCOPE46 of 154

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2021 ITP PROJECT STATUS

Project is on track with low risk• Scope

• Approved by MOPC in January subject to vetting of portfolio consolidation approach

• Portfolio Consolidation• Approach features benefit weighting specific to each planning

future• MOPC recommendation to weight futures 1 and 2 at 60% and 40%

respectively failed• Stakeholders and Staff will continue to evaluate options and

recommend a path forward in July47 of 154


ITP

COMPETITIVE PROJECT UPDATEAPRIL 2020

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SOONER-WEKIWA

• SPP issued RFP000002 Sooner-Wekiwa 345kV on December 6, 2019

• First Pre-Response Meeting with stakeholders held on January 6, 2020

• IEP guidance to bidders was published on March 2, 2020

• RFP Response/Deposit Deadline June 3, 2020

• Board selection decision expected October 2020

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WOLF CREEK – BLACKBERRY (WC-BB)

• 2020 AECI-SPP Joint Coordinated System Plan (JCSP) study• Official assessment of potential reliability impacts of WC-BB on

the AECI transmission system• Developing SPP-AECI Cost and Usage Agreement to execute

upon JCSP reliability impacts findings*• Overall study timeline of March – August

*Additional discussion with SPP stakeholders and RSC to determine next steps if reliability issues identified50 of 154

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WOLF CREEK – BLACKBERRY REQUEST FOR PROPOSAL (RFP)

• Oversight Committee will recommend to the SPP Board to suspend the project pending FERC approval of the SPP-AECI agreement (April)

• RFP issuance would result after;• Execution of the SPP-AECI agreement• FERC approval of executed SPP-AECI agreement

• Best case scenario for RFP issuance is early September

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INTEGRATED MARKETPLACE AND OPERATIONS UPDATEBRUCE REW, PE

SENIOR VICE PRESIDENT, OPERATIONS

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• Integrated Marketplace Operational Highlights

• Historical Load and Wind Trends

• Integrated Marketplace Highlights and Information

• Enhancements implemented and under development

SPP OPERATIONS UPDATE

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• Two new wind peaks during the quarter• Max Wind Output reached new peak of 18,259 MW on 01/08 at 06:08pm• Wind Penetration Peak of 71.3% on 02/03 at 03:15am

• Load forecast error average for the quarter was 1.68%, compared to 1.86% in Q1 2019

• Wind forecast error average for the quarter was 5.2%, compared to 5.44% in Q1 2019

• Currently 22.7 GW of wind registered in the market

Marketplace Operational Highlights

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SPP Weekly Average Load profile: January - March(comparing 2018, 2019, 2020 years at same date)

20000

22500

25000

27500

30000

32500

35000

37500

40000

42500

45000

1/1 1/15 1/29 2/12 2/26 3/11 3/25

Weekly Average Load

2018 2019 202055 of 154

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SPP Weekly Average Wind profile: January - March(comparing 2018, 2019, 2020 years at same date)

0

2000

4000

6000

8000

10000

12000

14000

16000

1/1 1/15 1/29 2/12 2/26 3/11 3/25

Weekly Average Wind

2018 2019 202056 of 154

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DISPATCH BY FUEL TYPE (ENERGY)

0

5

10

15

20

25

30

Gen

erat

ion

(TW

h)Real Time

Wind Solar Renewable Nuclear Hydro Coal Gas, combined-cycle Gas, simple-cycle Other

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FUEL ON THE MARGIN IN REAL-TIME

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Wind Coal Gas-CC Gas-SC Other

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REAL-TIME VERSUS DAY-AHEAD PRICING

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

0

5

10

15

20

25

30

Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20

Day-ahead price Real-time price Gas Price

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Min and Max Percent of Generation Mix Per Fuel Type – Q1 2020

44.0

64.9

47.1

9.5 7.712.2

3.5

10.3

2.6 2.7

27.332.7

27.7

6.9 5.10

10

20

30

40

50

60

70

Coal Wind Gas Nuclear Hydro

Perc

ent

Fuel Type

Average

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Min and Max Percent of Generation Mix Per Fuel Type - Last 12 Months

53.9

64.9

50.7

9.9 10.112.2

1.17.2

1.9 1.2

31.5 29.726.6

6.2 5.70

10

20

30

40

50

60

70

Coal Wind Gas Nuclear Hydro

Perc

ent

Fuel Type

Average

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WIND OUTPUT: JAN – MAR 2020

@ Max Wind Output

@ Min Wind Output

MW Wind 18,259.4 MW 973.7 MWTime 01/08 @ 18:08:00 03/23 @ 10:10:08

SPP Load 31,989.5 MW 28,731.4 MWGen Mix Percent

Coal 17.8% 40.0%Wind 56.6% 3.4%

Nat. Gas 13.6% 44.0%Nuclear 6.3% 6.2%

Hydro 5.6% 6.4%Other 0.1% 0.0%

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WIND PENETRATION: JAN – MAR 2020

Max Penetration Min PenetrationWind

Penetration 71.3% of load 3.4% of load

Time 02/03 @ 03:15:28 03/23 @ 10:10:12SPP Load 24,328.1 MW 28,717.8 MW

Wind Output 17,345.8 MW 973.7 MWGen Mix Percent

Coal 16.3% 40.0%Wind 64.8% 3.4%

Nat. Gas 12.0% 44.0%Nuclear 3.0% 6.2%

Hydro 3.7% 6.4%Other 0.2% 0.0%

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MARKETPLACE OVER LAST 12 MONTHS

• 249 Market Participants• 170 financial only and 79 asset owning

• SPP BA has successfully maintained NERC control performance standards (BAAL & CPS)

• High System availability• Day-Ahead Market results have posted 100% on time in past 12

months• Real-Time Balancing Market has successfully solved 99.9% of all

intervals

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Implemented with Settlement System Replacement Project:

• RR229 and RR333 – FERC ORDER 831 (Offer Caps)

• RR252 – OOME Cap and Floor Enhancement

• RR259 – Market Settlement Timelines

• RR273 – Market Settlements RNU Rounding

• RR328 – Settlement Automation for CR Deployment Tests

Upcoming Enhancements:

• RR365 – Day-Ahead Market Timeline enhancement• Implementation planned for May 12th 2020

• RR352 – DA RUC Process Timing • Implementation planned for May 12th 2020

• Markets/Credit Management System Interface Performance enhancements

INTEGRATED MARKETPLACE ENHANCEMENTS

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OUR MISSION: HELPING OUR MEMBERS KEEP THE LIGHTS ON … TODAY AND IN THE FUTURE.

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WEST ACTIVITIES UPDATEBRUCE REW, PE

SENIOR VICE PRESIDENT, OPERATIONS

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WESTERN ENERGY IMBALANCE SERVICE

2

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EIGHT PARTICIPANTS• Basin Electric

• Tri-State G&T

• WAPA Colorado River Storage Project (CRSP)

• WAPA Rocky Mountain Region (RMR)

• WAPA Upper Great Plains Region (UGP)

• Municipal Energy Agency of Nebraska (MEAN)

• Wyoming Municipal Power Agency (WMPA)

• Deseret Power CooperativePost-launch, onboard additional participants per onboarding timelines

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WEIS PRIOR PROGRESS

Executed WJDAs with 8 Participants

Established WMEC & Approved Charter

Initial Draft WEIS Tariff Pending WMEC Approval

Initiated Hiring Process for Incremental FTEs

Completed High-Level Functional Design With Market Vendor

Began Commercial Modeling and Onboarding of WEIS Participants

Conducted Initial Training for WEIS Participants70 of 154

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WEIS UPDATED PROGRESS

Established WMWG & Approved Charter

Completed Protocols set for WMEC Approval

Tariff Filing made (ER20-1059, ER20-1060)

SPP Answer to Filing Comments made

Completed Hardware System Requirements

Overall good progress on project

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WEIS FILING (ER20-1059 AND ER20-1060)

• Filing made by SPP on February 21, 2020 with and Order date of May 21, 2020 requested

• Several interventions: Fourteen different entities or groups

• Significant Support for WEIS

• Concerns and Protest into three primary areas• Governance• Costs and cost allocation• Seams issues

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IMPLEMENTATION TIMELINE – STILL ON TRACK

Conducted Initial Training for WEIS ParticipantsConducted Initial Training for WEIS ParticipantsSystem Build

Jan-Jun

System Testing

Jun-Nov

Parallel OpsDec-Jan

Go-Live Feb 2021

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RTO, RC AND WEIS FOOTPRINTS

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OUR MISSION: HELPING OUR MEMBERS KEEP THE LIGHTS ON … TODAY AND IN THE FUTURE.

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TOP 10 METRICS1Q2020

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RELIABILITY

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RELIABILITY

Conservative Operation Declarations

• None

Energy Emergency Alert

• None

Resource Alert

• None

Weather Alert

• Cold weather alert issued due to forecasted icing impacts across the Oklahoma/Texas panhandle, Kansas, Nebraska, and Western Missouri• January 16 - 17, 2020

Notable Near misses• None

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MARKET

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M.1.3. NET DAY-AHEAD CONGESTION REVENUE HEDGING SUCCESSJune 2019-March 2020

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M.2.4. CONGESTION – FLOWGATES

Flowgate Name Region Flowgate LocationTMP175_24736 North-central OklahomaTAHH59MUSFTS Arkansas/Oklahoma borderTMP109_22593 Eastern OklahomaTMP379_24692 North-central OklahomaFRAMIDCANCED Eastern KansasNEORIVNEOBLC* SE Kansas/SW MissouriTMP159_24149 Southern OklahomaTMP285_23829 NE Kansas/NW Missouri/SE NebraskaTMP421_24095 Central OklahomaTEMP42_25314 West Texas

* SPP Market-to-Market flowgate

Tahlequah-Hwy 59 161kV (GRDA-OKGE) ftlo Muskogee-Ft. Smith 345kV (OKGE)

Braman-Newkirk Tap 69kV ftlo Kildeer Tap-Chikaskia 138kV (OKGE)

Russett-South Brown 138kV (WFEC) ftlo Little City-Brown Tap 138kV (OKGE)

Braman-Newkirk Tap 69kV ftlo Hunter-Woodring 345kV (OKGE)

Franklin-Midwest 138kV (WFEC-OKGE) ftlo Cedar Lane-Canadian 138kV (OKGE)Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI)

Kelly-Goff 115kV (WR) ftlo Cooper-St. Joe (NPPD-MPS)Cimarron Xfmr 345/138kV ftlo Cimarron Xfmr 345/138kV (OKGE)Sundown2-Sundown 115kV ftlo Sundown2-Amoco Switch 230kV (SPS)

Stonewall Tap-Tupelo Tap 138kV (WFEC) ftlo Seminole-Pittsburg 345kV (CSWS-OKGE)

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Real-time average shadow price Day-ahead average shadow priceReal-time percent intervals congested Day-ahead percent intervals congested

April 2019-March 2020

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M.2.4. CONGESTION – FLOWGATESApril 2019-March 2020

Flowgate Name Region Flowgate Location Projects or operations that may provide mitigation

Short Summary

TMP175_24736 North-central Oklahoma


TOP and SPP RC are evaluating re-configuration option. No Projects identified at this time.

During high wind in North-central Oklahoma that causes North to South flow across Oklahoma 345 kV and 138 kV system, part of the transfer flow will use 69 kV between Chikaskia and Osage as parallel path in case of 345 kV contingency. Normal congestion management processes used to mitigate.

TAHH59MUSFTS Arkansas / Oklahoma border


SPP RC and TOP have an Operating Guide in place that considers multiple reconfiguration options if normal congestion management is not

During high North to South flow across East Oklahoma on the 345 kV and 161 kV transmission system, part of the transfer flow will use 161 kV between Tahlequah and Highway 59 as parallel path in case of 345 kV contingency. This constraint can be aggravated by outages of the Arkansas Nuclear One units. Normal congestion management processes used to mitigate. If normal congestion management is not effective, Operations will work with TOP's on

TMP109_22593* Eastern Oklahoma Stonewall Tap-Tupelo Tap 138kV (WFEC) ftlo Seminole-Pittsburg 345kV (CSWS-OKGE)

Tupelo 138 kV Terminal Upgrades (December 2020, 2017 ITP10). Operations has Operating Guide.

During West to East system flow across South of Oklahoma , the trip of the 345 kV contingency redirects flow onto the 138kV system. When insufficient dispatchable resources South of the constraint it is typically more difficult to manage. If normal congestion management is not effective, Operations will work with TOP's on reconfiguration options.





FRAMIDCANCED Central Oklahoma Franklin-Midwest 138kV (WFEC-OKGE) ftlo Cedar Lane-Canadian 138kV (OKGE)

No Projects identified at this time. During high North to South flow out of Oklahoma City going south wards on 138 kV, loss of parallel 138kV line loads alternate southern paths. Normal congestion management processes used to mitigate.

NEORIVNEOBLC* SE Kansas/SW Missouri

Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI)

Neosho - Riverton 161kV Rebuild (October 2023, ATSS SPP-2019-AG1-AFS-2)

During high North to South flow across East Kansas and East Oklahoma on the 345 kV and 161 kV transmission system, part of the transfer flow will use 161 kV between Neosho and Riverton as parallel path in case of 345 kV contingency. Normal congestion management processes including market-to-market used to mitigate.

TMP159_24149 Southern Oklahoma Russett-South Brown 138kV (WFEC) ftlo Little City-Brown Tap 138kV (OKGE)

No Projects identified at this time. [Related to an economic need in the 2020 ITP Assessment to be completed October 2020]

During high West to East flow across southern Oklahoma, part of the transfer flow will use 138 kV paths parallel to the Sunnyside to Hugo 345 kV Line. Normal congestion management processes used to mitigate. If normal congestion management is not effective, Operations will work with TOP's on reconfiguration options. Identified as an economic need in the 2020 ITP.

TMP285_23829 NE Kansas/NW Missouri/SE Nebraska

Kelly-Goff 115kV (WR) ftlo Cooper-St. Joe (NPPD-MPS)

No Projects identified at this time. [Related to a reliability need in the 2020 ITP Assessment to be completed October 2020]

Due to the outage on the 115 kV line Kelly - Tecumseh in May 2019, and the outage on the 345 kV line Cooper - Fairport - St. Joe in October 2019.

TMP421_24095 Central Oklahoma Cimarron Xfmr 345/138kV ftlo Cimarron Xfmr 345/138kV (OKGE)


During high wind in West Oklahoma that causes West to East flow across Oklahoma 345 kV system, part of the transfer flow will use 138 kV of Oklahoma City as parallel path. Normal congestion management processes used to mitigate.

TEMP42_25314 West Texas Sundown2-Sundown 115kV ftlo Sundown2-Amoco Switch 230kV (SPS)

Sundown 230/115 kV Transformer Upgrade (December 2020, 2018 ITPNT)

Due to forced generation outages in southern SPS, March 2020.

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M.4.3. ELECTRICITY/GAS PRICE COMPARISON

Average in $ Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20

DA LMP ($/MWh)

23.59 24.26 27.20 20.18 23.76 21.32 24.84 22.90 20.66 16.71 19.90 19.14 18.30 17.09 14.52

RT LMP ($/MWh)

22.89 23.44 21.49 21.88 24.24 20.69 23.64 22.64 19.14 13.62 18.94 17.45 16.62 16.73 14.39

PEPL GasCost ($/MMBtu)

2.91 2.51 2.72 1.82 1.88 1.37 1.68 1.56 1.71 1.45 1.89 1.72 1.59 1.56 1.28

$0

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M.7.1. EXCESS CAPACITY

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FINANCIAL

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F.1.1. ADMIN FEE MEASUREMENT

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RESOURCES

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F.4.1. HUMAN RESOURCES

QTR 2.19 QTR 3.19 QTR 4.19 QTR 1.20ANNUAL TO RATE 4.86% 4.66% 4.13% 4.24%SEPARATIONS 12 7 4 9

4.86% 4.66%4.13% 4.24%

0%

1%

2%

3%

4%

5%

6%

7%

ANN

UAL

TURN

OVE

R RA

TE

Turnover Rate

QTR 2.19 QTR 3.19 QTR 4.19 QTR 1.20VACANCY RATE 3.66% 4.70% 4.61% 4.86%# OF VACANCIES 23 30 30 32

3.66%

4.70% 4.61% 4.86%

0%

1%

2%

3%

4%

5%

6%

7%

VACA

NCY

RAT

E

Vacancy Rate

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar# 603 600 603 604 604 608 614 618 620 626 628 622

585590595600605610615620625630635

Headcount-12 Months

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P.2.1. IT SYSTEM PERFORMANCE

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PLANNING

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P.4.1. GENERATION INTERCONNECTION STUDIES

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STRATEGIC

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P.5. STRATEGIC PLAN

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CORPORATE METRICS

1st Quarter 2020

April 20, 2020

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Transmission and MarketFinanceEngineering Studies

M.1. TCR/ARR SummaryM.2. CongestionM.3. Regional Control PerformanceM.4. PricesM.5. Make Whole Payments / Revenue Neutrality UpliftM.6. Virtual ActivityM.7. Capacity and Commitments

Financial MetricsF.1. Admin Fee MeasurementF.2. CreditF.3. Settlement DisputesF.4. Human Resources

P.1. Regional Entity Compliance (no longer applicable)P.2. System PerformanceP.3. Transmission Service StudiesP.4. Generation Interconnection StudiesP.5. Strategic Plan

Metrics Definitions

SupplementsRegulatory Activity Update & OutlookGovernment Affairs Quarterly Activity Report

Southwest Power Pool Corporate Metrics

DISCLAIMERThe data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market advice or market settlement data. Southwest Power Pool (SPP) makes no representationor warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein.

SPP shall have no liability to recipients of this information or third parties for the consequences arising from errors or discrepancies in this information, or for any claim, loss or damage of any kind or nature whatsoever arising out of or in connection with (i) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (ii) any error or discrepancy in this information, (iii) the use of this information, or (iv) a loss of business or other consequential loss or damage whether or not resulting from any of the foregoing.

Performance Metrics

Transmission & Market Indicators

Dashboards

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Transmission & Market DashboardMarkets Operational Indicators ● ■ ▲ ▼

Metric Chart Jan-20 Feb-20 Mar-20 Expected Monitor Concern Problem

TCR Funding M.1.2 ● ● ■ >= 90%, <= 100%

± 5% of Expected

± 10% of Expected

± 20% of Expected

CPS1 & BAAL Reporting M.3 ● ● ● <=20 mins or >120

>20 mins or =<120

>25 mins or <110

>=30 mins or <100

RT-DA Price Deviation M.4.4 ● ■ ▲ <= 25% <= 30% <= 35% > 45%

MWP Distribution per MWh M.5.3 ● ● ● <= $0.50 <= $0.75 <= $1.00 > $1.00

Monthly Average Gross Virtual Profitability per MWh M.6 ● ● ● <= $2.00 <= $2.50 <= $3.00 > $3.00

Excess Capacity (900 MW + X % of Peak Obligation) M.7.1 ● ● ● <= 0.5% <= 1% <= 1.5% > 1.5%

Real-Time Obligation Fulfilled by DA (% Committed Capacity) M.7.2 ● ● ● >= 95% >= 90% >= 85% < 85%

HR Operational Metrics (Year-to-date), Days Failed P.2.2 ● ● ● <= 14 <= 18 <= 25 > 25

Day-Ahead Mid-Term Load Forecast (% Error) P.2.3 ● ● ● <= 5% <= 10% <= 15% > 15%

Short-Term Load Forecast (% Error) P.2.3 ● ● ● <= 1% <= 1.5% <= 2.5% > 2.5%

On-Time Real-Time Posting P.2.3 ● ● ● >= 99.5% >= 99% >= 98.5% < 98%

On-Time Day-Ahead Posting P.2.3 ● ● ● >= 99% >= 98.5 % >= 98% < 98%

Please note: Dashboard metric criteria are reviewed and revised each year.* The current year Dashboard metric criteria have been published at the end of the document.** Each metric item is identified by a number that links the metric to its corresponding chart and criteria entry.

Das

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Q1 2020 IndicatorsIndicator Threshold Values

1Q2020

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Finance Dashboard 1Q2020

● ■ ▼Expected Monitor Concern

Admin Fee Measurement (Forecast vs Budget) Jan-20 Feb-20 Mar-20

Gross Revenue Requirement (GRR) F.1 ● ● ● < = $1.0 M $1.1 M to $2.2 M > = $2.3 M

Net Revenue Requirement (NRR) F.1 ● ● ● < = $1.0 M $1.1 M to $2.2 M > = $2.3 M

Admin Fee Revenue Collected F.1 ● ● ● < = $1.0 M $1.1 M to $2.2 M > = $2.3 M

Over/(Under) Recovery F.1 ● ● ● < = $1.0 M $1.1 M to $2.2 M > = $2.3 M

Billing Determinants (MWh millions) F.1 ● ● ● < = 3.0 3.1 to 5.0 > = 5.1

Credit Jan-20 Feb-20 Mar-20

Short Pays & Uncollected Amounts F.2 ● ● ● Short Pays = $0; Uncollected = $0

Short Pays > $0; Uncollected = $0

Short Pays > $0; Uncollected > $0

Settlement Disputes Jan-20 Feb-20 Mar-20

Number of Open Disputes F.3 ● ● ● < = 30 31 to 60 > 60

Average Days Outstanding F.3 ● ● ● < = 30 31 to 45 > 45

Average Dispute Amount (millions) F.3 ● ● ● < = $1.0 $1.1 to $2.0 > $2.0

Number of Resettlements F.3 ● ● ● < = 50 51 to 90 > 90

Human Resources Q3.19 Q4.19 Q1.20

Rolling 4 Qtr Turnover Rate F.4 ● ● ● < 6% 6 to 8% > 8%

Vacancy Rate F.4 ● ● ● < 5% 5 to 8% > 8%

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Metric Chart Previous Indicators

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Engineering Studies

● ■ ▼Study Type Q3.19 Q4.19 Q1.20 Expected Monitor Concern

Aggregate Facilities Studies P.3 ● ● ● 100% 80-99% > 80%

Delivery Point Transfer Screening Studies P.3 ● ● ● 100% 80-99% > 80%

Long-Term Service Request Screening Studies P.3 ● ● ● 100% 80-99% > 80%

Generator Interconnection Active Requests > 365 Days P.4 ▼ ▼ ▼ < 10% < 30% > 30%

Das

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1Q2020

SPP must report to the commission when more than 20% of Facilities Studies (not Screening Studies) are late in two consecutive calendar quarters. SPP is subject to penalty if 10% or more are late in the following two calendar quarters after breaking the 20% late threshold.

Chart

Indicator Threshold ValuesPercentage of study postings that were on-time during the quarter. Quarterly Indicators

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M.1.1. ARR Funding SummaryTr

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TCR Revenue ARR FundingARR Surplus Funding PercentCumulative Funding Percent - Prior Year Cumulative Funding Percent - Current Year

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M.1.2. TCR Funding SummaryTr

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M.1.3. Net day-ahead congestion revenueTr

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M.2.1. Congestion - TLR / CME Time

in hours Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 2018 2019 2020Prev 12

moNon-Firm Curtailments

66 30 34 14 24 5 31 49 24 45 9 58 34 0 48 33 33 27 29

Firm Curtailments

52 0 7 0 42 165 18 11 5 20 13 0 0 4 13 48 28 6 24

Total 118 30 41 14 66 170 49 60 29 65 22 58 34 4 61 81 60 33 53 CME Time (loading >90%) 4575 3704 3895 4086 3939 3674 3585 3430 5791 4592 5078 4712 3893 3340 3190

4,222 4,255 3,474 4,109

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01,0002,0003,0004,0005,0006,000

2018 2019 2020 Prev 12mo

Monthly Average CME Time (hrs)

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M.2.2. Congestion - Congested Intervals, real-time market

Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 2017 2018 2019 12 moUncongested Intervals

11% 13% 23% 16% 15% 16% 27% 24% 11% 13% 8% 17% 24% 22% 21% 13% 18% 16% 18%

Intervals with Binding Only

61% 57% 48% 39% 41% 43% 45% 40% 51% 39% 39% 36% 42% 59% 41% 53% 55% 45% 43%

Intervals with a Breach

28% 31% 29% 45% 44% 41% 28% 36% 38% 48% 53% 47% 34% 19% 38% 33% 27% 39% 39%

Interval = 5 minutes Average

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2017 2018 2019 12 mo

Uncongested Intervals

0%

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100%

Uncongested Intervals Intervals with Binding Only Intervals with a Breach

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2017 2018 2019 12 mo


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2017 2018 2019 12 mo


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M.2.2.1 Congestion - Congested Intervals, day-ahead market

Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 2017 2018 2018 12 moUncongested Intervals

0% 0% 3% 0% 0% 0% 1% 1% 0% 0% 1% 1% 0% 2% 2% 1% 1% 1% 1%


100% 100% 97% 100% 99% 99% 98% 99% 96% 100% 99% 99% 100% 98% 98% 99% 98% 99% 99%


0% 0% 0% 0% 1% 1% 1% 0% 4% 0% 1% 0% 0% 0% 1% 0% 0% 1% 1%

Interval = 1 hour Average

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2017 2018 2018 12 mo

Uncongested Intervals

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Uncongested Intervals Intervals with Binding Only Intervals with a Breach

0%

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2017 2018 2018 12 mo


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M.2.3. Price Contour Map (April 2019 - March 2020)

Day-Ahead Real-Time

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M.2.4. Congestion - Flowgates (April 2019 - March 2020)

Flowgate Name Region Flowgate LocationTMP175_24736 North-central OklahomaTAHH59MUSFTS Arkansas/Oklahoma borderTMP109_22593 Eastern OklahomaTMP379_24692 North-central OklahomaFRAMIDCANCED Eastern KansasNEORIVNEOBLC* SE Kansas/SW MissouriTMP159_24149 Southern OklahomaTMP285_23829 NE Kansas/NW Missouri/SE NebraskaTMP421_24095 Central OklahomaTEMP42_25314 West Texas


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Russett-South Brown 138kV (WFEC) ftlo Little City-Brown Tap 138kV (OKGE)


Franklin-Midwest 138kV (WFEC-OKGE) ftlo Cedar Lane-Canadian 138kV (OKGE)Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI)

Kelly-Goff 115kV (WR) ftlo Cooper-St. Joe (NPPD-MPS)Cimarron Xfmr 345/138kV ftlo Cimarron Xfmr 345/138kV (OKGE)Sundown2-Sundown 115kV ftlo Sundown2-Amoco Switch 230kV (SPS)

Stonewall Tap-Tupelo Tap 138kV (WFEC) ftlo Seminole-Pittsburg 345kV (CSWS-OKGE)

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Flowgate Name Region Flowgate Location Projects or operations that may provide mitigation

Short Summary





TAHH59MUSFTS Arkansas / Oklahoma border


SPP RC and TOP have an Operating Guide in place that considers multiple reconfiguration options if normal congestion management is

During high North to South flow across East Oklahoma on the 345 kV and 161 kV transmission system, part of the transfer flow will use 161 kV between Tahlequah and Highway 59 as parallel path in case of 345 kV contingency. This constraint can be aggravated by outages of the Arkansas Nuclear One units. Normal congestion management processes used to mitigate. If normal congestion

TMP109_22593* Eastern Oklahoma Stonewall Tap-Tupelo Tap 138kV (WFEC) ftlo Seminole-Pittsburg 345kV (CSWS-OKGE)

Tupelo 138 kV Terminal Upgrades (December 2020, 2017 ITP10). Operations has Operating Guide.

During West to East system flow across South of Oklahoma , the trip of the 345 kV contingency redirects flow onto the 138kV system. When insufficient dispatchable resources South of the constraint it is typically more difficult to manage. If normal congestion management is not effective, O ti ill k ith TOP' fi ti tiTMP379_24692 North-central

OklahomaBraman-Newkirk Tap 69kV ftlo Kildeer Tap-Chikaskia 138kV (OKGE)



FRAMIDCANCED Central Oklahoma Franklin-Midwest 138kV (WFEC-OKGE) ftlo Cedar Lane-Canadian 138kV (OKGE)

No Projects identified at this time. During high North to South flow out of Oklahoma City going south wards on 138 kV, loss of parallel 138kV line loads alternate southern paths. Normal congestion management processes used to mitigate.

NEORIVNEOBLC* SE Kansas/SW Missouri

Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI)

Neosho - Riverton 161kV Rebuild (October 2023, ATSS SPP-2019-AG1-AFS-2)

During high North to South flow across East Kansas and East Oklahoma on the 345 kV and 161 kV transmission system, part of the transfer flow will use 161 kV between Neosho and Riverton as parallel path in case of 345 kV contingency. Normal congestion management processes including

k t t k t d t iti tTMP159_24149 Southern Oklahoma Russett-South Brown 138kV (WFEC) ftlo Little City-Brown Tap 138kV (OKGE)


During high West to East flow across southern Oklahoma, part of the transfer flow will use 138 kV paths parallel to the Sunnyside to Hugo 345 kV Line. Normal congestion management processes used to mitigate. If normal congestion management is not effective, Operations will work with TOP's on reconfiguration options Identified as an economic need in the 2020 ITP

TMP285_23829 NE Kansas/NW Missouri/SE Nebraska

Kelly-Goff 115kV (WR) ftlo Cooper-St. Joe (NPPD-MPS)

No Projects identified at this time. [Related to a reliability need in the 2020 ITP Assessment to be completed October 2020]

Due to the outage on the 115 kV line Kelly - Tecumseh in May 2019, and the outage on the 345 kV line Cooper - Fairport - St. Joe in October 2019.

TMP421_24095 Central Oklahoma Cimarron Xfmr 345/138kV ftlo Cimarron Xfmr 345/138kV (OKGE)

No Projects identified at this time. [Related to an economic need in the 2020 ITP Assessment to be

l t d O t b 2020]

During high wind in West Oklahoma that causes West to East flow across Oklahoma 345 kV system, part of the transfer flow will use 138 kV of Oklahoma City as parallel path. Normal congestion management processes used to mitigate.

TEMP42_25314 West Texas Sundown2-Sundown 115kV ftlo Sundown2-Amoco Switch 230kV (SPS)

Sundown 230/115 kV Transformer Upgrade (December 2020, 2018 ITPNT)

Due to forced generation outages in southern SPS, March 2020.

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M.3.1. Balancing Authority Report - CPS PerformanceTr

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Jul 18 Aug 18 Sep 18 Oct 18 Nov 18 Dec 18 Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19

CPS1 (statistical measure of 1 minute average ACE vs. Frequency)

> 120% >=110% and <=120% >=100% and <110% <100%

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> 120% >=110% and <=120% >=100% and <110% <100%

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M.3.2. Balancing Authority Report - BAAL Performance

Event Length Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20

>10 and <=20 min 0 0 0 1 0 1 0 0 1 0 0 0 0 1 0

>20 and <=25 min 0 0 0 0 0 1 0 0 0 0 0 0 0 0 0

>25 and <=30 min 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

>30 min 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

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>10 and <=20 min >20 and <=25 min >25 and <=30 min >30 min

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M.4.1. Price (April 2019 - March 2020)Tr

ansm

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Mar

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ator

s

$20.22

$19.39

$14

$16

$18

$20

$22

$24

$26

$28

AECC

/AEC

CAE

PE/B

PWN

AEPE

/CO

SNAE

PE/S

SCN

AEPE

/WTM

NAE

PM_X

/AEP

MBE

PM/B

EPM

BEPM

/NM

CA_X

BRPS

/BRP

SED

EP/E

DEP

ETEC

/ETE

CFR

EM/F

REM

GRDX

/GRD

XGS

EC/G

SEC

HM

MU/

HM

MU

INDN

/IND

NKB

PU/K

BPU

KCPS

/KCP

SKC

PS/U

CUKM

EA/E

MP1

_XKM

EA/E

MP2

_XKM

EA/E

MP3

_XKM

EA/E

UDO

_XKP

P/KP

PLE

SM/L

ESM

MEC

B/M

ECB

MEU

C/M

EUC

MID

W/M

IDW

MRE

S/M

UMZ_

XN

SPP/

NSP

PN

WPS

/NW

MT_

XN

WPS

/NW

PSO

GE/O

GEO

MPA

/OM

PAO

PPM

/OPP

MO

TPW

/OTP

R_X

REM

C/CW

EPRE

MC/

PRTT

SEPC

/SEP

CSP

SM/S

PSM

TEA/

FCU_

XTE

A/M

EAN

TEA/

NCU

_XTE

A/N

ELI_X

TEA/

NPP

MTE

A/SC

RITE

A/SP

RMTN

SK/G

ATE_

XTN

SK/T

NGI

_XTN

SK/T

NH

P_X

TNSK

/TN

HU_

XUG

PM/E

WA_

XUG

PM/M

MPA

_XUG

PM/O

TP_X

UGPM

/UGP

MW

FES/

WFE

SW

RGS/

1073

WRG

S/CH

ANW

RGS/

COW

PW

RGS/

KN01

WRG

S/PA

RLW

RGS/

PBEL

WRG

S/PE

OP_

XW

RGS/

PLW

CW

RGS/

WRG

S

LMP

($/M

Wh)

Day-ahead LMP Real-time LMP SPP day-ahead average LMP SPP real-time average LMP17 of 61110 of 154

M.4.2. Price Volatility - standard deviation (April 2019 - March 2020)Tr

ansm

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Mar

ket I

ndic

ator

s

11.0

51.1

0

10

20

30

40

50

60

70

AECC

/AEC

CAE

PE/B

PWN

AEPE

/CO

SNAE

PE/S

SCN

AEPE

/WTM

NAE

PM_X

/AEP

MBE

PM/B

EPM

BEPM

/NM

CA_X

BRPS

/BRP

SED

EP/E

DEP

ETEC

/ETE

CFR

EM/F

REM

GRDX

/GRD

XGS

EC/G

SEC

HM

MU/

HM

MU

INDN

/IND

NKB

PU/K

BPU

KCPS

/KCP

SKC

PS/U

CUKM

EA/E

MP1

_XKM

EA/E

MP2

_XKM

EA/E

MP3

_XKM

EA/E

UDO

_XKP

P/KP

PLE

SM/L

ESM

MEC

B/M

ECB

MEU

C/M

EUC

MID

W/M

IDW

MRE

S/M

UMZ_

XN

SPP/

NSP

PN

WPS

/NW

MT_

XN

WPS

/NW

PSO

GE/O

GEO

MPA

/OM

PAO

PPM

/OPP

MO

TPW

/OTP

R_X

REM

C/CW

EPRE

MC/

PRTT

SEPC

/SEP

CSP

SM/S

PSM

TEA/

FCU_

XTE

A/M

EAN

TEA/

NCU

_XTE

A/N

ELI_X

TEA/

NPP

MTE

A/SC

RITE

A/SP

RMTN

SK/G

ATE_

XTN

SK/T

NGI

_XTN

SK/T

NH

P_X

TNSK

/TN

HU_

XUG

PM/E

WA_

XUG

PM/M

MPA

_XUG

PM/O

TP_X

UGPM

/UGP

MW

FES/

WFE

SW

RGS/

1073

WRG

S/CH

ANW

RGS/

COW

PW

RGS/

KN01

WRG

S/PA

RLW

RGS/

PBEL

WRG

S/PE

OP_

XW

RGS/

PLW

C

Vola

tility

(sta

ndar

d de

viat

ion)

Day-ahead volatility Real-time volatility SPP day-ahead average volatility SPP real-time average volatility18 of 61111 of 154

M.4.3. Electricity/Gas Price Comparison

Average in $ Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20

DA LMP ($/MWh)

23.59 24.26 27.20 20.18 23.76 21.32 24.84 22.90 20.66 16.71 19.90 19.14 18.30 17.09 14.52RT LMP ($/MWh)

22.89 23.44 21.49 21.88 24.24 20.69 23.64 22.64 19.14 13.62 18.94 17.45 16.62 16.73 14.39PEPL GasCost ($/MMBtu)

2.91 2.51 2.72 1.82 1.88 1.37 1.68 1.56 1.71 1.45 1.89 1.72 1.59 1.56 1.28

Tran

smiss

ion

& M

arke

t Ind

icat

ors

$0

$1

$2

$3

$4

$0

$10

$20

$30

$40


Gas

Cost

(Pan

hand

le E

aste

rn P

ipel

ine)

$/M

MBt

u

DA LMP RT LMP Gas (PEPL)

Elec

tric

ity P

rice

($/M

Wh)

19 of 61112 of 154

M.4.3.1 Prices - annual

avg (in $) 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019Day-ahead Price ($/MWh)

32.36 22.84 22.43 23.11 25.11 22.04 Real-time Price* ($/MWh)

49.42 53.21 27.89 31.33 29.28 22.29 25.89 31.42 21.85 22.36 23.43 24.56 20.82 PEPL Gas Cost ($/MMBtu)

6.15 7.12 3.31 4.17 3.89 2.64 3.58 4.45 2.43 2.32 2.65 2.59 1.94

Tran

smiss

ion

& M

arke

t Ind

icat

ors

* 2014 RTBM includes last two months of LIP for the EIS market, and RTBM LMP for the first ten months of the Integrated Marketplace. All prior years use EIS LIP.

$0

$2

$4

$6

$8

$0

$20

$40

$60

$80

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

$/M

Wh

$/M

MBt

u

Day-ahead Price ($/MWh) Real-time Price* ($/MWh) PEPL Gas Cost ($/MMBtu)

20 of 61113 of 154

M.4.4. Price DivergenceTr

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21 of 61114 of 154

M.5.1. Revenue Neutrality Uplift

in thousands $ Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 2017 2018 2019 12 mo

Total Uplift 10,614 10,524 3,674 13,873 18,771 10,437 3,216 3,671 11,264 4,164 19,506 7,621 6,143 2,973 4,788 62,268 59,562 117,809 106,429

Revenue Neutrality Uplift (RNU) ensures settlement payments/receipts for each settlement interval equal zero.• Positive RNU - SPP receives insufficient revenue and collects from market participants.• Negative RNU - SPP receives excess revenue, which must be credited back to market participants.

Tran

smiss

ion

& M

arke

t Ind

icat

ors

Total

$0

$4

$8

$12

$16

$20in

mill

ions

$

$0

$25

$50

$75

$100

$125

2017 2018 2019 12 mo

Tota

l in

mill

ions

$

22 of 61115 of 154

M.5.1.1 Revenue Neutrality Uplift Table

in thousands $ Jan 19 Feb 19 Mar 19 Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20

DA Revenue Inadequacy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

RT Revenue Inadequacy -60 30 19 -226 -89 -178 -56 -78 -2,621 2,096 -155 17 16 -59 -65

RT OOME MWP -243 -187 -258 -390 -1,186 -189 -97 -182 -296 -732 -139 -750 -236 -51 -690

RT Regulation Deployment Adj -137 -61 -80 10 -4 -2 -49 275 3 -66 -573 -95 -62 23 -34

RT JOA Adj 1,458 3,652 2,531 1,631 3,755 -2,360 37 -197 -363 3,645 872 2,858 1,180 1,057 3,513

RT Congestion Adj -11,340 -13,712 -5,633 -14,628 -21,106 -7,288 -2,961 -3,200 -7,819 -9,228 -19,452 -9,830 -6,932 -3,865 -7,445

SUBTOTAL -10,322 -10,278 -3,421 -13,603 -18,630 -10,017 -3,127 -3,382 -11,096 -4,285 -19,447 -7,801 -6,034 -2,895 -4,722

Less RT Net Inadvertent Adj 292 247 253 270 142 420 89 289 168 -121 59 -179 109 78 66

TOTAL RNU 10,614 10,524 3,674 13,873 18,771 10,437 3,216 3,671 11,264 4,164 19,506 7,621 6,143 2,973 4,788

* This table is based on the latest available settlements data and is subject to change due to resettlement.

Tran

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& M

arke

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ors

23 of 61116 of 154

M.5.2. Make Whole PaymentsTr

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Mar

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ator

s

$0

$3

$6

$9M

illio

nsDay-Ahead

Coal Gas-CC Gas-CT Hydro Other Wind

$0

$3

$6

$9

Mill

ions

RUC (Real-Time)

Coal Gas-CC Gas-CT Hydro Other Wind

24 of 61117 of 154

M.5.3. All-In PriceTr

ansm

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Mar

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s

25 of 61118 of 154

M.6. Virtual ActivityTr

ansm

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Mar

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s

26 of 61119 of 154

M.7.1. Excess CapacityTr

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s

27 of 61120 of 154

M.7.2. Source of CommitmentTr

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ator

s

DA_RUC – Day-Ahead Reliability Unit CommitmentID_RUC – Intra-Day Reliability Unit CommitmentDAMKT – Day-Ahead Market

28 of 61121 of 154

F.1.1. Admin Fee MeasurementFi

nanc

ial M

etric

s

29 of 61122 of 154


nanc

ial M

etric

s

30 of 61123 of 154


nanc

ial M

etric

s

31 of 61124 of 154

F.2. Credit

Transmission ($000s) Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 12 moLate Payments $528 $72 $145 $834 $85 $0 $1 $1 $2,065 $33 $24 $131 $3,920Total Payments $56,208 $53,609 $54,355 $57,350 $56,948 $61,146 $61,122 $60,772 $70,445 $57,832 $59,132 $59,411 $708,330% Late Payments 1% 0% 0% 1% 0% 0% 0% 0% 3% 0% 0% 0% 1%

Market ($000s) Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 12 moLate Payments $0 $12 $0 $0 $0 $109 $0 $0 $78 $8 $0 $0 $206Total Payments $95,804 $80,347 $78,620 $106,423 $82,789 $81,102 $81,342 $82,963 $104,288 $74,035 $74,759 $77,439 $1,019,912% Late Payments 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Short Pays ($000s) Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 12 moTransmission $0 $0 $9 $0 $0 $0 $0 $0 $0 $0 $0 $0 $9Market $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Uncollectible ($000s) Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20 12 moTransmission $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Market $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Fina

ncia

l Met

rics

0%

3%

6%

9%

12%

15%%

of T

otal

Pay

out

% of Late Transmission Payments

0%

5%

10%

15%

20%

25%

% o

f Tot

al P

ayou

t

% of Late Market Payments

$0

$100

$200

$300

$400

in th

ousa

nds

Transmission Short Pays

$0

$10

$20

$30

$40

in th

ousa

nds

Market Short Pays

32 of 61125 of 154

F.3. Settlement Disputes

Apr 19 May 19 Jun 19 Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19 Jan 20 Feb 20 Mar 20Total # of Open Disputes (at month-end)

2 3 - - 2 - - 1 4 2 1 2

Average Days Outstanding (granted in month)

3 - 7 1 - 2 2 1 2 1 3 3

Average Dispute Amount (granted in month)

$2.1 $26.3 $1.7 $13.2 $2.1 $71.7 $6.7 $11.9 $1.8 -$ $12.8 $12.1

# of Resettlements (published in month)

41 39 38 38 36 49 72 60 91 44 - -

Fina

ncia

l Met

rics

-

1

2

3

4

5Total # of Open Disputes (at month-end)

- 1 2 3 4 5 6 7 8 9

10Average Days Outstanding (granted

in month)

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

in th

ousa

nds

Average Dispute Amount (granted in month)

-

10

20

30

40

50

60

70

80

90

100# of Resettlements (published in

month)

33 of 61126 of 154

F.4.1. Human ResourcesFi

nanc

ial M

etric

s

QTR 2.19 QTR 3.19 QTR 4.19 QTR 1.20ANNUAL TO RATE 4.86% 4.66% 4.13% 4.24%SEPARATIONS 12 7 4 9

4.86% 4.66%4.13% 4.24%

0%

1%

2%

3%

4%

5%

6%

7%

ANN

UAL

TURN

OVE

R RA

TETurnover Rate

QTR 2.19 QTR 3.19 QTR 4.19 QTR 1.20VACANCY RATE 3.66% 4.70% 4.61% 4.86%# OF VACANCIES 23 30 30 32

3.66%

4.70% 4.61% 4.86%

0%

1%

2%

3%

4%

5%

6%

7%

VACA

NCY

RAT

E

Vacancy Rate

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar# 603 600 603 604 604 608 614 618 620 626 628 622

585590595600605610615620625630635

Headcount-12 Months

34 of 61127 of 154

P.2.1. IT System PerformancePe

rfor

man

ce

35 of 61128 of 154

P.2.2. Operational System AvailabilityPe

rfor

man

ce

STLF – Short-term load forecastRTLODF – Real-time Line Outage Distribution FactorDAMKT – Day-Ahead MarketDARUC – Day-Ahead Reliability Unit Commitment

36 of 61129 of 154

P.2.3. System AvailabilityPe

rfor

man

ce

STLF – Short-term Load ForecastMTLF – Mid-term Load ForecastDAMKT – Day-Ahead MarketID RUC – Intra-day Reliability Unit CommitmentRTBM – Real-time Balancing Market

37 of 61130 of 154

P.3. Transmission Service StudiesPe

rfor

man

ce100% 80-99% <80%

CurrentQ1-2020 Q4-2019 Q3-2019

Aggregate Facilities StudiesDelivery Point Transfer Screening StudiesLong-Term Service Request Screening Studies

SPP must report to the commission when more than 20% of Facilities Studies (not Screening Studies) are late in two consecutive calendar quarters. SPP is subject to penalty if 10% or more are late in the following two calendar quarters after breaking the 20% late threshold.

Study Type

Percentage of Study Postings that Were Made On-Time During the Quarter

Previous

0

10

20

30

40

50

60

70

Completed Completed Pending

2018-AG2 2019-AG1 2019-AG2

REQU

ESTS

Status of Long-Term Transmission Service Requests for Current and Recent Aggregate Studies

Study Results Pending

Withdrawn

Confirmed

0

10

20

30

40

50

60

70

Oct-17 Dec-17 Feb-18 Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19 Jun-19 Aug-19 Oct-19 Dec-19 Feb-20

Requ

ests

Month

Trend of Requests in the Aggregate Study Queue Over Time

2017-AG2 2018-AG1 2018-AG2 2019-AG1 2019-AG2

38 of 61131 of 154

P.4.1. Generation Interconnection StudiesPe

rfor

man

ce

In Progress 1Q19 2Q19 3Q19 4Q19 1Q20

Transfer IS Queue

DISIS-2015-001

DISIS-2015-002

DISIS-2016-001 4,563 4,569 1,895 510 -

DISIS-2016-002 12,465 12,087 12,087 10,480 7,815

DISIS-2017-001 15,990 15,494 15,845 15,643 15,705

DISIS-2017-002 27,686 24,313 24,073 23,913 23,913

DISIS-2018-001 10,605 11,025 11,005 10,865 11,125

DISIS-2018-002 11,438 11,941 12,061 11,911 11,709

DISIS-2019-001 125 7,697 8,329 7,996

DISIS-2020-001 350

FCS-2017-003

FCS-2018-001

FCS-2018-002 500

FCS-2018-004 1,070 1,070

FCS-2019-002 1,814 - -

FCS-2019-003 70 70 -

TOTAL 84,318 80,624 86,546 81,721 78,613

MW

- 5,000

10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 75,000 80,000 85,000 90,000

1Q19 2Q19 3Q19 4Q19 1Q20

MW

Generation Interconnection MW - In Progress

2015 Studies 2016 Studies 2017 Studies 2018 Studies 2019 Studies 2020 Studies

Battery, 6,756

CT/Gas, 254

Solar, 28,182

Wind, 43,422

Active Studies by Prime Mover (MW)

39 of 61132 of 154

P.4.2. Commercial Operation DatesPe

rfor

man

ce as of March 31, 2020

MW CapacityIA Fully Executed / On Suspension 1,751.8 IA Fully Executed / On Schedule 9,414.6 Total Scheduled or Suspended Generation 11,166.4

Charts above reflect Executed Generation Interconnection Agreements (GIA’s) with upcoming Commercial Operation Date (COD) milestones by year and month. Data based on Queue Status of “IA Fully Executed / On Schedule”.

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Apr

Jun

Aug

Oct

Dec Feb

Apr

Jun

Aug

Oct

Dec Feb

Apr

Jun

Aug

Oct

Dec Feb

Apr

Jun

Aug

Oct

Dec Feb

Apr

Jun

Aug

Oct

Dec

2017 2018 2019 2020 2021

MW

Cap

acity

Commercial Operation Month

0

1

2

3

4

5

2017 2018 2019 2020 2021

GW C

apac

ity

Commercial Operation Year

Battery, 20

CT/Gas*, 49

Solar, 190Wind, 9,156

On Schedule by Prime Mover (MW)

40 of 61133 of 154

P.5. Strategic Plan

Green: On target, or completedYellow: Objective in question, or on holdRed: Behind schedule, incomplete

Perf

orm

ance

41 of 61134 of 154

P.5.1 Strategic Plan: Variable Energy Resources Initiative TrackingPe

rfor

man

ce

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METRICS DEFINITIONS

Transmission and Market Indicators Two groups of metrics will be monitored to provide an overall health indication of the regional transmission system and market.

• Reliability Performance Indicators, which focus on the actual operations of the transmission system and whether or not it was operated within expected limits and standards.

• Market Performance Indicators, which focus on the performance of the market in terms of overall volume, prices and level of participation.

Reliability Performance Indicators This sub-group of metrics is designed to measure the operations of the transmission system from a reliability perspective.

• How well-funded are Transmission Congestion Rights (TCR). (see TCR/ARR Summary) • How much time was congested during the period. (see Congestion) • Was the system operated in compliance with the relevant control performance standards? (see Regional Control Performance)

M.1. TCR/ARR Summary

TCR/ARR funding is derived as follows: 1. Day-ahead revenue is collected daily 2. TCR holders are paid daily based on awarded TCR MW and Day-ahead clearing prices

a. Uplift is charged daily b. Surpluses are redistributed Monthly and Annually

3. TCR revenue is collected daily based on TCR MW and TCR ACPs (consistent through month/season) 4. ARR holders are paid daily based on ARR MW and TCR ACPs (consistent through month/season)

a. Uplift is charged daily b. Surpluses are redistributed Monthly and Annually

M.2. Congestion

M.2.1. TLR / CME Time

TLR Events by level (in hours)

• Non-Firm (Level 3) – curtailment of non-firm schedules and non-firm market flow • Firm (Level 5) – curtailment of all non-firm and some firm schedules and market flow

• CME (Congestion Management Events) where loading is greater than 90% (in hours)

M.2.2. Congested Intervals

Percent of intervals binding (flow = System Operating Limit [SOL]), breached (flow > SOL) and congested (either binding or breached) during the month. Charts are included for both the Day-Ahead Market (DAMKT) and the Real-Time Balancing Market (RTBM).

M.2.3. Price Contour Map

Graphic representation of average monthly prices by load area in both the Day-Ahead Market and Real-Time Balancing Market since the start of the Integrated Marketplace.

M.2.4. Congestion – Flowgates

• Congestion by flowgate ranked by average hourly shadow price in the RTBM for the last 12 months. DA values are also included.

• Table is included to show top ten most congested flowgates and any potential projects which may provide mitigation

to the congestion. 43 of 61136 of 154

M.3. Regional Control Performance

The SPP BA is not subject to CPS, but is subject to BAAL. CPS is reported here for informational purposes only. Measures the aggregate performance to the NERC CPS (Control Performance Standards) for SPP. This indicator is set based on the NERC real time control performance standards (known as BAL-001 – Real Power Balancing Control Performance and BAL-002 – Disturbance Control Performance).

• CPS1 requires compliance for 100% of the periods measured within the month.

• BAAL - each Balancing Authority shall operate such that its clock-minute average of reporting ACE does not exceed for more than 30 consecutive clock-minutes its clock-minute Balancing Authority ACE Limit (BAAL)

Market Performance Indicators

This sub-group of indicators provides a view of the effectiveness of the market in the context of answering the following questions:

• What was the average wholesale price paid in the region and what was its volatility? (see Price)

• How much Revenue Neutrality Uplift was generated during the month? (see Uplift)

• What was the level of available generation offered to the market and EIS related energy sales in the month? (see Market Liquidity)

M.4.1. M.4.2. M.4.3.

Price •

Shows the prices and volatility for both the DAMKT and RTBM for each market participant with load within the footprint. Also provides an SPP-wide average price for the period reported. Volatility (measured as the coefficient of variation, which is average divided by the standard deviation) is shown for each market participant as well as SPP as a whole. A higher volatility indicates more variability in prices.

• SPP-wide monthly average LMP and the Gas Cost at the Panhandle Eastern Pipeline hub.

M.4.4. RT-DA Price Deviation

• The Absolute Difference is the daily average of the absolute values of the hourly difference between Day-Ahead Market LMPs and Real-Time Market LMPs

• The Average Difference is the daily average of the hourly difference between Day-Ahead Market LMPs and Real-Time Market LMPs

• The Average LMP %Difference is the Absolute Difference divided by the average Day-Ahead LMP. 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐷𝐷𝐴𝐴 = (� 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐴𝐴𝑎𝑎𝐴𝐴ℎ𝐴𝐴𝐴𝐴𝑒𝑒 𝐿𝐿𝐿𝐿𝐿𝐿𝑝𝑝𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠 −𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑎𝑎𝐴𝐴𝐴𝐴𝑙𝑙𝑇𝑇𝐷𝐷𝑇𝑇𝐴𝐴 𝐿𝐿𝐿𝐿𝐿𝐿𝑝𝑝𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠

𝐷𝐷𝑠𝑠𝐷𝐷)

𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑙𝑙𝐴𝐴𝐴𝐴𝐴𝐴 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐷𝐷𝐴𝐴 = (� |𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐴𝐴𝑎𝑎𝐴𝐴ℎ𝐴𝐴𝐴𝐴𝑒𝑒 𝐿𝐿𝐿𝐿𝐿𝐿𝑝𝑝𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠 − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑎𝑎𝐴𝐴𝐴𝐴𝑙𝑙𝑇𝑇𝐷𝐷𝑇𝑇𝐴𝐴 𝐿𝐿𝐿𝐿𝐿𝐿𝑝𝑝𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝐷𝐷𝑠𝑠𝐷𝐷

|)

𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐿𝐿𝐿𝐿𝐿𝐿 % 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐷𝐷𝐴𝐴 = 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑙𝑙𝐴𝐴𝐴𝐴𝐴𝐴 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐷𝐷𝐴𝐴

𝐴𝐴𝐴𝐴𝐴𝐴(∑ 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐷𝐷𝐴𝐴𝑎𝑎𝐴𝐴ℎ𝐴𝐴𝐴𝐴𝑒𝑒 𝐿𝐿𝐿𝐿𝐿𝐿𝑝𝑝𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝐷𝐷𝑠𝑠𝐷𝐷 )

M.5.1. Uplift

Tracks amount of RNU (Revenue Neutrality Uplift) charged or credited to market participants during the month, along with the category of uplift. RNU ensures settlement payments/receipts for each settlement interval equal zero.

• Positive RNU - SPP receives insufficient revenue and collects from market participants.

• Negative RNU - SPP receives excess revenue, which must be credited back to market participants. Tracks Make Whole Payments (MWP) for both the Day-Ahead Market and the RUC (Real-Time) with payments broken down by Fuel Type of the generation receiving the MWP.

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M.5.2. MWP Distribution

• The All-in Price cost of each MW is broken down into different components associated with different product or costdistribution.

• The DA MWP and RUC MWP make up the MWP distribution per MWh paid out as component of all-in cost for eachMW of energy.

M.6. Virtual Activity

• The Cleared Virtual Profitability is the daily average of the hourly DA LMP minus the hourly averaged RT LMP multiplied by the cleared virtual transactions from DA and all divided by the absolute value of the total cleared virtual transactions from DA.

• The Monthly Market Index is the monthly average of the cleared virtual profitability.• Volume of Cleared MWh is the daily average of the total cleared virtual transactions in DA.

M.7.1. Excess Capacity

• Excess Capacity is calculated as the MW capacity remaining (on dispatchable resources) that is not being dispatched for energy or reserved for online operating reserves (Reg Up, Spin, Online Supplemental). This Excess Capacity is calculated for each unit for every hour and that excess capacity is assigned to a “Commitment Source” that representswhere the unit’s commitment actually came from. Only excess capacity from the hour of the daily peak generation obligation (averaged by month) is considered. The final chart only includes those additional commitment changes made by SPP outside of DAMKT or MP-initiated decisions.

• Excess Capacity = Effective Max – Dispatch MW – Cleared Reg Up – Cleared Spin – Cleared Online Supplemental

M.7.2. Source of Commitment

• Commitments are determined and separated into 5 different cases SELF, MANUAL, ID_RUC, DA_RUC and DAMKT andare taken from the Current Operating Plan table.

• Depending on the process the commitment is made, they are categorized into groups. • For the purpose of the Metrics on the dashboard, the DA_RUC, DAMKT and DBDA commitments are considered DA

commitments fulfilling Real-Time obligation.

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Financial Metrics This group of metrics provides a view of the organization’s overall financial situation in terms of both the operating costs and settlement functions carried out.

F.1. Admin Fee Performance Measures actual costs incurred by SPP on an annual basis and compares this to the approved Admin Fee and Budgeted Net Revenue Requirement (NRR).

F.2. Credit Metric measures the timeliness of the financial settlements for both transmission billing and market billing and provides a proxy for the strength of the organization’s cash flow.

F.3. Settlement Disputes

Measures the number and value of disputes made with regard to the financial settlements of the markets. The objective in this area is twofold: (1) minimize the time to clear disputes; and (2) minimize the total value of dollars in dispute.

• The average dispute amount granted in the month.

• The number of disputes active at the end of the month, as well as the average days outstanding for those disputes is calculated. In addition, the number of resettlements during the month is tracked.

F.4. Human Resources

Measures turnover rates, as well as the number of position vacancies, for each quarter. • Turnover rates, on a quarterly basis, as well as annualized. • Percentage of positions vacant on a quarterly basis.

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Performance Metrics The metrics in this group focus on NERC Compliance, System Availability, Studies and the Strategic Plan.

P.2.1. IT System Availability Measures availability of SPP IT Systems.

P.2.2. Operational System Availability

• STLF – This includes a count of days that the STLF Error has exceeded 1% for more than 2% of the RTBM study intervals.

• DAMKT - This portion of the graph includes a count of days that the DAMKT posted past the deadline. • DARUC – This portion of the graph includes a count of days that DARUC failed to solve within 3 hours and 15 minutes

of DAMKT Posting. Note: This was changed January 2018 due to changes to DAMKT/DARUC timelines. • SE/RTLODF - This portion of the graph shows a count of days that the SE solution failed to solve every 4 seconds.

The metric indicator will be green if the failure counts falls between 0 & 7. The metric indicator will fall in the yellow category if the count falls between 8 & 14.

P.2.3. System Availability

• MTLF - Percentage of time that the Mid-Term Load Forecast Error (Actual Load vs MTLF) was within 5% for each of the three previous months as well as from the previous 12 months. Note: Data is now pulled from the last 12 months instead of from go live. It is a large amount of data and processing time to continue to retrieve some of these metrics back to go live. That information is contained in previous reports.

• STLF - Percentage of time the Short-Term Load Forecast error (Actual Load vs STLF) was within 1% for each of the three previous months as well as from the previous 12 months.

• Day Ahead Market – This portion of the graph shows the percentage of time that the DAMKT posted on time for each of the three previous months as well as from the previous 12 months.

• Intra Day RUC – This portion of the graph shows the percentage of time that IDRUC studies successfully ran every four hours for each of the three previous months as well from the previous 12 months.

• State Estimator – This portion of the graph shows the percentage of time that there was a SE solution every four seconds for each of the three previous months as well as from the previous 12 months.

• Real Time Balancing Market – This portion of the graph shows the percentage of time that RTBM solved and approved successfully every five minutes for each of the three previous months as well as from the previous 12 months.

P.3. Transmission Service Studies • Dashboard showing status of transmission service studies.

P.4. Generation Interconnection Studies Tracks status of Generation Interconnection Studies by MW, as well as upcoming commercial operation dates for Generation Interconnection Agreements.

P.5. Strategic Plan Tracks status of Strategic Plan initiatives and assignments.

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Regulatory Update - Activity in Significant Dockets First Quarter 2020

Page 1 of 10

SPP Tariff/Governing Document Revisions Docket Number Short Description Summary ER16-1341 18-1005 U.S. Court of Appeals --------------------------------------- 20-1062 U.S. Court of Appeals -------------------------------------- 20-1101 U.S. Court of Appeals

Petition of Southwest Power Pool, Inc. for Tariff Waiver Concerning the Crediting Process in Attachment Z2 Xcel Energy Services Inc. (“Xcel Energy”) v. Federal Energy Regulatory Commission (“FERC”): Petition for Review of Orders Issued in Docket No. ER16-1341 Regarding SPP’s Petition for Tariff Waiver Concerning the Implementation of the Revenue Crediting Process in Attachment Z2 --------------------------------------- Oklahoma Gas and Electric Company (“OG&E”) v. Federal Energy Regulatory Commission (“FERC”): Petition for Review of the Order on Remand and Order on Rehearing and Clarification issued in Docket No. ER16-1341 Regarding Attachment Z2 --------------------------------------- Southwest Power Pool, Inc. v. Federal Energy Regulatory Commission (“FERC”): Petition for Review of the Order on Remand and Order on Rehearing and Clarification issued in Docket No. ER16-1341 Regarding Attachment Z2

On February 20, 2020, FERC issued an Order on Rehearing and Clarification of the Order on Remand issued on February 28, 2019. The Commission denied rehearing and granted clarification of the Order on Remand. The Commission granted SPP's request for clarification that any interest owed on the refunds should be collected from the entities who received payments from SPP as a result of settlements under Attachment Z2 for the historical period, and not from SPP. On February 20, 2020, FERC issued an order denying SPP's motion for stay of the refund directive in the Order on Remand issued on February 28, 2019. ---------------------------------------------------------------------------------------------------------------------------- On March 2, 2020, OG&E filed a Petition for Review of the Order on Remand and the Order on Rehearing and Clarification in Docket No. ER16-1341 related to Attachment Z2 before the United States Court of Appeals in Case No. 20-1062. On April 3, 2020, OG&E filed its Nonbinding Statement of Issues. --------------------------------------------------------------------------------------------------------------------------- On March 31, 2020, SPP filed a Petition for Review of the Order on Remand and the Order on Rehearing and Clarification in Docket No. ER16-1341 related to Attachment Z2 before the United States Court of Appeals in Case No. 20-1101.

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Page 2 of 10

SPP Tariff/Governing Document Revisions Docket Number Short Description Summary ER18-939 EL16-91 EL18-19

Submission of Membership Agreement Revisions to Implement Refund Obligations for Non-Public Utility SPP Transmission Owners Consistent with Commission Orders in Docket Nos. EL16-91-000 and EL18-19-000 Section 206 Proceeding to Examine SPP's Open Access Transmission Tariff (“Tariff”) and Absence of Refund Commitment for Non-Public Utility Transmission Owners to Refund Revenues that they May Receive Associated with Service Provided due to their Status as Transmission-Owning Regional Transmission Organization (“RTO”) Members in the Same Manner Public Utility Transmission Owners Could be Required to Provide Refunds of Such Revenues Section 206 Proceeding to Examine SPP's Membership Agreement (and Other Jurisdictional Documents) and Absence of Refund Commitment for Non-Public Utility Transmission Owners to Refund Revenues that they May Receive Associated with Service Provided due to their Status as Transmission-Owning RTO

Commission action is pending on SPP’s compliance filing in Docket No. ER18-939.

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Page 3 of 10

SPP Tariff/Governing Document Revisions Docket Number Short Description Summary

Members in the Same Manner Public Utility Transmission Owners Could be Required to Provide Refunds of Such Revenues

ER19-460 Submission of Order No. 841 Compliance Filing to Incorporate Electric Storage Resources (Revision Request 323)

On February 27, 2020, FERC issued an order granting in part SPP's request for deferral of effective date and directing an effective date of August 5, 2021. Commission action is pending on SPP’s compliance filing submitted on December 16, 2019.

ER19-1954 Order Nos. 845 and 845-A Compliance Filing (Revision Request 353)

On January 23, 2020, FERC issued an order accepting SPP's Order No. 845 compliance filing in part, effective as of the date of the order, and directing SPP to submit a further compliance filing. On March 24, 2020, SPP submitted its compliance filing in response to the order issued on January 23, 2020. SPP requested an effective date as of the date the Commission issues an order accepting the compliance filing.

ER19-2522 EL19-11

Submission of Exit Fee Compliance Revisions in Response to Order on Complaint Issued in Docket No. EL19-11-000 Complaint of the American Wind Energy Association ("AWEA") and the Wind Coalition (collectively, "Complainants") Regarding SPP's Financial Obligations of Withdrawing Members

On January 24, 2020, SPP filed a Motion for Extension of T ime and Request for Expedited Ruling. SPP requested an extension of time to May 1, 2020 to submit the compliance filing required by the order issued on December 19, 2019. On February 3, 2020, FERC issued a Notice of Extension of T ime to May 1, 2020 for SPP to submit its compliance filing. On February 6, 2020, the Public Interest Organizations filed a Motion for Clarification of the order issued on December 19, 2019. On March 30, 2020, FERC issued an Order on Clarification and Rejecting Late-Filed Request for Rehearing. The Commission denied Public Interest Organization's requested clarification and instead clarified that non-transmission owners seeking to withdraw from SPP are still subject to the withdrawal deposit requirement. The Commission also rejected arguments in opposition to the deposit requirement as a late-filed rehearing request.

ER19-2845 Submission of Tariff Revisions to Require Phasor Measurement Units ("PMU") at New

On February 14, 2020, FERC issued an order accepting SPP's revisions to Attachment V of the Tariff in order to require Phasor Measurement Units at new generator interconnections. An effective date of November 20, 2019 was granted.

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Page 4 of 10


Generator Interconnections (Revision Request 340)

ER20-418 Submission of Tariff Revisions to Unbundle Schedule 1-A Tariff Administration Services to Include Market Services (Revision Request 358)

On February 6, 2020, FERC issued an order accepting SPP's revisions to Schedule-1A, Tariff Administration Services, to unbundle the rate to properly allocate the cost of the services to Market Participants who use the services and to revise other references and sections of the Tariff accordingly to accommodate the changes in Schedule 1-A. An effective date of January 1, 2021 was granted.

ER20-453 Submission of Tariff Revisions to Eliminate Attachment Z2 Transmission Revenue Credits (Revision Request 374)

On January 31, 2020, FERC issued an Order Rejecting Proposed Tariff Revisions.

ER20-572 EL19-101

Compliance Filing to Include Continuous Run-Time Requirement in Attachment AA of the Tariff in Response to Order Issued in Docket No. EL19-101-000 Section 206 Proceeding Directing SPP to Add the Resource Adequacy Minimum Run-Time Requirement to the Tariff

On January 27, 2020, SPP filed an answer in response to comments. Commission action is pending on SPP’s compliance filing submitted on December 12, 2019.

ER20-644 EL18-35

Compliance Filing Revising Fast-Start Pricing Practices in Response to Order on Paper Hearing in Docket No. EL18-35-000 (Revision Request 375) Order Instituting Section 206 Proceeding and Commencing Paper Hearing Procedures Regarding Pricing of Quick-Start Resources

On January 21, 2020, the SPP Market Monitoring Unit filed a Motion to Intervene and Protest. On January 21, 2020, Golden Spread Electric Cooperative, Inc. filed Comments. On February 5, 2020, SPP filed an answer in response to the Limited Protest filed by the SPP Market Monitoring Unit on January 21, 2020. On February 5, 2020, SPP filed an answer in response to comments filed by Golden Spread Electric Cooperative, Inc. on January 21, 2020. On February 20, 2020, the SPP Market Monitoring Unit filed an answer in response to the answer filed by SPP on February 5, 2020.

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Page 5 of 10


Commission action is pending on SPP’s compliance filing submitted on December 19, 2019.

ER20-1059 ER20-1060

Submission of Western Energy Imbalance Service ("WEIS") Tariff Submission of Western Energy Imbalance Service ("WEIS") Rate Schedule Tariff

On February 21, 2020, SPP submitted its Tariff in order to implement the Western Energy Imbalance Service Market in the Western Interconnection. SPP also submitted Western Joint Dispatch Agreements executed by seven entities and the Western Markets Executive Committee Charter for Commission approval under the Western Energy Imbalance Service Rate Schedule Tariff. An effective date of February 1, 2021 was requested. SPP requested that the Commission issue an order by May 21, 2020. Several parties filed motions to intervene. On March 20, 2020, the SPP Market Monitoring Unit filed a Motion to Intervene, Comments in Support, and Recommendations. Several parties file comments or protests.

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Page 6 of 10

Other Filings of Interest Docket Number Short Description Summary EL17-21 Kansas Electric Power

Cooperative, Inc.'s ("KEPCo") Complaint Against SPP Concerning Direct Cost Assignment in Connection with the Attachment Z2 Revenue Crediting Process

Commission action is pending on the requests for rehearing of the order issued on November 6, 2017. On February 20, 2020, FERC issued an order denying SPP's motion for stay of the refund directive in the Order on Remand issued on February 28, 2019.

EL17-89 American Electric Power Service Corporation ("AEP") Complaint Against the Midcontinent Independent System Operator, Inc. ("MISO") and SPP Concerning Assessment of Duplicative Congestion Charges Associated with Southwestern Electric Power Company ("SWEPCO") Loads that are Pseudo-Tired from MISO to SPP

American Electric Power Service Corporation, the City of Prescott, Entergy Services LLC, and Southern Company Services, Inc. filed reply briefs. On March 4, 2020, SPP submitted its response to reply briefs filed by American Electric Power Service Corporation and Southern Company Services, Inc. On March 4, 2020, MISO filed an answer in response to reply briefs. On March 19, 2020, American Electric Power Service Corporation filed a motion to reject the answers filed by SPP and MISO on March 4, 2020.

EL18-9 Xcel Energy Services Inc.'s ("Xcel Energy"), on behalf of Southwestern Public Service Company ("SPS"), Complaint Against SPP Concerning the Attachment Z2 Revenue Crediting Process

Commission action is pending on the rehearing request of the order issued on March 6, 2018.

EL18-26

EDF Renewable Energy, Inc.'s ("EDF") Complaint Against the Midcontinent Independent System Operator, Inc. (“MISO”), Southwest Power Pool, Inc. (“SPP”), and PJM Interconnection, L.L.C. (“PJM”) (collectively, the “RTOs”) Regarding Affected System Coordination

On February 3, 2020, MISO and SPP submitted compliance filings in response to the Order on Complaint. On February 25, 2020, EDF Renewables, Inc. and Enel Green Power North America, Inc. filed comments in response to SPP's and MISO's filings. On February 26, 2020, RWE Renewables Americas, LLC filed comments in response to SPP's and MISO's filings. On March 10, 2020, SPP filed an answer in response to comments.

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Page 7 of 10

Other Filings of Interest Docket Number Short Description Summary ER20-940 ER20-943 ER20-945

Midcontinent Independent System Operator, Inc.'s ("MISO") Compliance Filing in Response to Order on Complaint Issued in Docket No. EL18-26-000 Southwest Power Pool, Inc.’s Compliance Filing in Response to Order on Complaint Issued in Docket No. EL18-26-000 (Part 1 of 2) Southwest Power Pool, Inc.’s Compliance Filing in Response to Order on Complaint Issued in Docket No. EL18-26-000 (Part 2 of 2)

On March 13, 2020, MISO filed an answer in response to comments.

EL19-62 Complaint of City Utilit ies of Springfield, Missouri ("CUS") Regarding Highway/Byway Cost Allocation Methodology

On January 23, 2020, FERC issued an order denying rehearing, denying clarification in part and granting clarification in part of the order issued on August 12, 2019.

EL19-75 Complaint to Enforce Attachment Z2 of EDF Renewables, Inc., Enel Green Power North America, Inc., NextEra Energy Resources, LLC and Southern Power Company ("Complainants")

On February 20, 2020, FERC issued an order denying SPP's motion for stay of the refund directive in the Order on Remand issued on February 28, 2019.

EL19-77 Oklahoma Gas and Electric Company's ("OG&E") Complaint Regarding Revenue Credits under the Sponsored Upgrade Agreement dated December 1, 2008

On February 20, 2020, FERC issued an order denying SPP's motion for stay of the refund directive in the Order on Remand issued on February 28, 2019.

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Page 8 of 10

Other Filings of Interest Docket Number Short Description Summary EL19-92 Section 206 Proceeding

Regarding Exemption from Order No. 1000 Requirement for Immediate Need Reliability Projects

American Electric Power Service Corporation, Developers Advocating Transmission Advancements, Edison Electric Institute and LSP Transmission Holdings II, LLC filed comments. On February 26, 2020, the Indicated SPP Transmission Owners filed an answer in response to the comments filed by LSP Transmission Holdings II, LLC. On March 26, 2020, LSP Transmission Holdings II, LLC filed an answer in response to the answer filed by the Indicated SPP Transmission Owners on February 26, 2020.

EL19-93 Western Farmers Electric Cooperative ("WFEC") Complaint Against SPP Seeking to Affirm WFEC's Right to Recover and Retain Revenue Credits to which WFEC is Entitled, and which WFEC has Collected, pursuant to the Terms of Attachment Z2 of the Tariff and WFEC's Network Integration Transmission Service Agreement ("NITSA") under the Tariff

Commission action is pending.

EL19-96 Complaint of Cimarron Windpower II, LLC ("Cimarron") Against SPP Requesting that the Commission Find SPP's Failure to Provide Attachment Z2 Credits to Cimarron in Accordance with Attachment Z2 Violated the Terms of the SPP Tariff and the Cimarron Generator Interconnection Agreement


ER19-477 Petition for Tariff Waiver of the 365-Day Limitation Period for Modifications to Settlement Statements Set Forth in Attachment AE, Section 10.1(3)


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Page 9 of 10

Other Filings of Interest Docket Number Short Description Summary

to Ensure that Market-to-Market ("M2M") Settlements Involving SPP and the Midcontinent Independent System Operator, Inc. ("MISO") are Accurate

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Page 10 of 10

State Cases Docket Number Short Description Summary Kansas 17-SPPE-117-GIE 19-SPPE-384-CPL

In the Matter of a General Investigation for the Purpose of Investigating Whether Annual or Periodic Cost/Benefit Reporting by the SPP and Kansas Electric Utilit ies that Participate in SPP is in the Public Interest


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FERC Last date for Discovery Responses (Order Establishing Procedural Schedule and Rules of Conduct of Hearing issued on July 29, 2019)

04/15/2020

ER15-2028

FERCAnnual Compliance Report Regarding Penalties for Unreserved Use is due

04/17/2020

OA08-5

FERC Deadline for parties to answer all outstanding discovery requests and last day for depositions (Order Adopting Procedural Schedule issued on July 31, 2019)

04/17/2020

ER18-2358

FERC Joint Statement of Positions on the Issues, Joint Witness List, and Index of Exhibits are due (Order Adopting Procedural Schedule issued on July 31, 2019)

04/21/2020

ER18-2358

FERC Telephonic Settlement Conference begins at 11 AM Eastern Time (Order Scheduling Settlement Conference issued on April 3, 2020)

04/21/2020

ER15-2115

FERC Joint Witness List, Joint Exhibit List, Joint Statement of Stipulated Facts, and Joint Statement of Contested Facts is due (Order Establishing Procedural Schedule and Rules of Conduct of Hearing issued on July 29, 2019)

04/22/2020

ER15-2028

FERC Telephonic Settlement Conference begins at 11 AM Eastern Time (Order Scheduling Settlement Conference issued on April 3, 2020)

04/22/2020

ER15-2028

FERC Post-Technical Conference Comments are due (Notice Inviting Post-Technical Conference Comments issued on March 27, 2020)

04/27/2020

RM19-12

FERC Settlement Conference begins at 10 AM Eastern Time (Order Scheduling Settlement Conference issued on March 12, 2020)

04/28/2020

ER19-2273

FERCFERC Reporting Requirment No. 582 is due

04/30/2020

4/8/2020 11:05:50 AM Page 1 of 3

Regulatory Outlook

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10-1178

FERC Compliance filing is due regarding SPP's membership exit fee (Order on Rehearing, Compliance, and Section 205 Filing issued on December 19, 2019; Notice of Extension of Time Issued on February 3, 2020)

05/01/2020

ER19-2522

FERC Compliance filing is due regarding SPP's membership exit fee (Order on Rehearing, Compliance, and Section 205 Filing issued on December 19, 2019; Notice of Extension of Time Issued on February 3, 2020)

05/01/2020

EL19-11

FERC SPP's response to letter requesting additional information is due (Letter issued on March 9, 2020; Notice Granting Extension of Time issued on March 19, 2020)

05/01/2020

ER20-941

FERCPre-Hearing Brief is due (Order Adopting Procedural Schedule issued on July 31, 2019)

05/11/2020

ER18-2358

FERC Telephonic settlement conference begins at 9 AM Eastern Time (Order Scheduling Telephonic Settlement Conference issued on April 6, 2020)

05/12/2020

ER18-2358

FERCSPP MMU's Annual State of the Market Report due at FERC

05/15/2020

ZZ19-4

FERC Technical Conference to be held to discuss opportunities for increasing real-time and day-ahead market efficiency and enhancing the resilience of the bulk power system through improved software (Notice of Technical Conference issued on February 14, 2020)

06/23/2020

AD10-12

State of Missouri Kansas City Power & Light Company's Interim Report is due (Order Granting Motion to Modify Stipulation Requirements issued on June 28, 2017)

06/30/2020

EO-2012-0135

State of Missouri KCP&L Greater Missouri Operations Company's Interim Report is due (Order Granting Motion to Modify Stipulation Requirements issued on June 28, 2017)

06/30/2020

EO-2012-0136

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State of Arkansas Arkansas Electric Cooperative Corporation's annual report is due (Arkansas Public Service Commission Order No. 4 issued on May 17, 2016)

07/01/2020

16-002-U

FERC Initial Comments due in response to the Notice of Inquiry regarding Virtualization and Cloud Computing Services (Notice of Inquiry issued on February 20, 2020; Notice of Extension of Time issued on April 2, 2020)

07/01/2020

RM20-8

FERC SPP's authorization for issuance of securities expires (Order Authorizing Issuances of Securities issued on July 10, 2018)

07/09/2020

ES18-33

FERC SPP's Eleventh Informational Report due detailing SPP's and MISO's progress on resolving issues related to their implementation methodologies for Interface Bus Pricing, and analyzing whether the benefits of implementation of a day-ahead firm flow entitlement exchange process outweigh its costs, until such issues are resolved (Order Conditionally Accepting in Part and Rejecting in Part Revisions to Joint Operating Agreement issued on January 22, 2015)

07/22/2020

ER13-1864

FERC Reply Comments due in response to the Notice of Inquiry regarding Virtualization and Cloud Computing Services (Notice of Inquiry issued on February 20, 2020; Notice of Extension of Time issued on July 31, 2020)

07/31/2020

RM20-8

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Government Affairs Quarterly Activity Report

1/1/2020 – 3/31/2020

Date Event Location

2/12/20

North Dakota Interim Legislative Committee on Energy Development

and Transmission Bismarck, ND

2/25/20 –

2/27/20 Meetings with Members of Congress and their staffs Washington, DC

3/13/20 Teleconference with Colorado Governor Bill Ritter Teleconference

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