southwest power pool schedule 1a task force meeting … minutes and... · 2019-03-27 · minutes...

Minutes No. 12

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Southwest Power Pool

SCHEDULE 1A TASK FORCE MEETING

March 25, 2019

Teleconference

• M I N U T E S •

Administrative Items Chair John Olsen called the meeting to order at 1:00 PM. The following individuals participated in the meeting:

John Olsen Evergy Jason Mazigian Basin Electric John Varnell Tenaska Robert Tallman OG&E David Mindham ITC Holdings Corp. Ray Bergmeier Sunflower Electric Alfred Busbee GDS Associates/ETEC Greg Garst OPPD Heather Starnes Healy Law Offices/MJMEUC Rob Janssen Dogwood Energy Tim Hall Southern Power Richard Ross AEP-Southwestern Electric Power Co. (TO) Bill Grant Southwestern Public Service – Xcel Energy Bernard Liu Xcel Energy Brian Rounds AESL Consulting Calvin Daniels Western Farmers Dennis Reed Midwest Regulatory Consulting, LLC Ella Caillouette NorthWestern Energy Jessica Meyer Lincoln Electric System Robert Pick NPPD Robert Safuto Customized Energy Solutions Ron Thompson NPPD Sandy Wirkus WAPA Jessica Kasparek Lincoln Electric System Jodi Endres WAPA Chris Green Liberty Utilities Tom Dunn SPP Mike Riley SPP Nicole Wagner SPP Dianne Branch SPP Patti Kelly SPP Denise Martin SPP David Daniels SPP Sam Loudenslager SPP Tony Alexander SPP Lee Elliot SPP

Minutes from the February 21, 2019 meeting were reviewed. Heather Starnes motioned to approve the minutes. The motion was seconded by Jason Mazigian. The minutes were unanimously approved by voice vote.

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The following proxies were in effect for the meeting – Bill Grant for Wes Berger and Richard Ross for Jim Jacoby (see attachments). Update on Action Items from February 21st Meeting

1) Staff to prepare formula templates for proposed rate schedules. UPDATE: Discussed under Agenda Item 5.

2) Staff to incorporate recommended edits to the white paper draft. UPDATE: Discussed under Agenda Item 6.

3) Staff to complete tariff language edits as discussed during meeting UPDATE: Discussed under Agenda Item 3.

Tariff Language Review Mike Riley presented the tariff language as revised to reflect comments from the February 21st meeting. The most noteworthy edit was the modification of the cap language in the opening paragraph to include the summation of costs from all rate schedules. The remaining changes made to the tariff language consisted of minor verbiage edits. There was a brief discussion on the necessity of the rate cap in light of the creation of the formula rate templates. John Olsen restated that it was the Task Force’s desire to continue the use of the rate cap calculation that would be included in the formula rate template annually for overall cost control purposes. Staff raised the issue as to the appropriateness of using Schedule 9 billing determinants for purposes of billing network service under RS 1, which was modeled after the current schedule 1A billing methodology. Currently, Schedule 1A is charged to network customers based on Schedule 9 demand which excludes GFAs. Alternatively, it was suggested that utilizing Schedule 11 might be more appropriate given that it includes GFAs. In response to this suggestion, concern was raised that GFAs being served via PTP service could theoretically be billed twice under RS 1 if Schedule 11 demand was utilized to bill network service - once for network service because the GFA load would be included within the Schedule 11 demand, and second because the PTP service would also be charged under RS 1. Because of this issue, the Task Force did not feel that it could approve the tariff language as currently constructed until staff performed further analysis of Schedule 9 vs 11 billing determinants and its effect on revenue associated with monthly assessments. Market Protocol Revisions Patti Kelly provided an overview of the current draft of the Revision Request Form, highlighting the market protocol revisions resulting from the proposed schedule 1A rate structure changes. There was a brief discussion and related questions that were addressed by staff. Formula Rate Template Review Nicole Wagner provided an overview of the current draft of the formula rate template, highlighting the structure of the underlying data (both cost and billing determinants) for all rate schedules. She emphasized that the template was still a work in progress and that staff was still in the process of

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validating the completeness and accuracy of the data to be included in the template. There was some general discussion by the Task Force. Staff will present a more completed version of the template at the next meeting. White Paper Review The Task Force briefly discussed the current version of the white paper as presented in the materials. While there were no suggested edits/modifications to the draft raised by the Task Force at this time, final approval will be delayed until all remaining outstanding issues have been resolved. Action Items

1) Staff to complete analysis of Schedule 9 vs Schedule 11 billing determinants and its impact to the current monthly assessment portion of the administrative fee.

Future Meetings Friday, April 12th 10AM-Noon – Teleconference/WebEx There being no further business, John Olsen adjourned the meeting at 2:50 PM. Respectfully Submitted, Dianne Branch Secretary

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. SCHEDULE 1A TASK FORCE MEETING

March 25, 2019 Teleconference

• A G E N D A •

1 – 5 PM CST

1. Administrative Items (10 minutes)

a. Call to Order…………………………………………………………………………...John Olsen

b. Attendance………………………………………………………………………...Dianne Branch

c. Review of Agenda…………………………………………………………………….John Olsen

d. Approve Meeting Minutes…………………………..……………………………….John Olsen

2. Review of Past Actions Items (10 minutes)…………………………………………………..Dianne Branch

3. Tariff Language Review (45 minutes)…………..………………………………………………… Mike Riley

4. Market Protocol Revisions (30 minutes)……………………………………………………………Patti Kelly

5. Formula Rate Template Review (60 minutes)...………..……………………………………Nicole Wagner

6. White Paper Review (45 minutes)……………………………..……………..………….……Dianne Branch

7. Outstanding Issues/Wrap-Up (15 minutes)………………………………..…………………….John Olsen

8. Closing Items (10 minutes)……………………………………………… ……………………Dianne Branch

a. Summary of Action Items

b. Future meetings

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Dianne Branch

From: Jacoby, JimSent: Sunday, March 24, 2019 10:16 AMTo: Olsen, John; Dianne BranchCc: David Erkin; Ross, Richard C. (AEP)Subject: **External Email** 1ATF proxy

John and Dianne, I won’t be on the 1ATF call Monday. Please accept Richard Ross as my proxy. Thanks Jim Jacoby AEP [email protected] 214‐777‐1144

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Dianne Branch

From: Berger, WesSent: Wednesday, March 20, 2019 8:57 AMTo: Dianne Branch; Olsen, JohnCc: Grant, WilliamSubject: **External Email** Proxy for SPP Sch1A meeting next week

I am unable to attend the meeting next week. Bill Grant will have my proxy. Thanks. Wes Berger Xcel Energy | Responsible By Nature Manager, Rate Cases 790 S. Buchanan St., 7th Floor, Amarillo TX 79101 P: 806.378.2891 C: 806.672.6080

Minutes No. 11

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Southwest Power Pool

SCHEDULE 1A TASK FORCE MEETING February 21, 2019

DFW Hyatt Regency – Dallas, TX

• M I N U T E S •

Administrative Items Chair John Olsen called the meeting to order at 8:00 AM. The following individuals participated in the meeting:

John Olsen Evergy Jim Jacoby AEP-Public Service Company of Oklahoma Jason Mazigian Basin Electric John Varnell Tenaska Robert Tallman OG&E David Mindham ITC Holdings Corp. Wes Berger Xcel Energy/SPS Ray Bergmeier Sunflower Electric Mike Riley SPP Dianne Branch SPP

Those participating by phone were as follows:

Alfred Busbee GDS Associates/ETEC Greg Garst OPPD Joel Dagerman NPPD Heather Starnes Healy Law Offices/MJMEUC Rob Janssen Dogwood Energy Calvin Daniels Western Farmers Chris Lyons Customized Energy Solutions Damir Domazet The Energy Authority David Erkin AEP David Kays OG&E Greg McAuley OG&E – Transmission J.P. Maddock Basin Electric Lee Anderson Lincoln Electric System Jessica Meyer Lincoln Electric System Ron Thompson NPPD Sandy Wirkus WAPA David Daniels SPP Steve Davis SPP Richard Dillon SPP Nicole Wagner SPP Chris Cranford SPP Lee Elliot SPP Patti Kelly SPP

Minutes from the February 5, 2019 meeting were reviewed. Jason Mazigian motioned to approve the minutes. The motion was seconded by John Varnell. The minutes were unanimously approved by voice vote.

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The following proxy was in effect for the meeting – John Varnell for Tim Hall (see attachment). Update on Action Items from February 5th Meeting

1) Task force members to contemplate the impacts to their respective companies as it relates to the various options for positioning new rate structure language into the tariff (e.g. all remain in 1A, only RS 1 remain in 1A, all in separate section). Members should be prepared to discuss at February 21st meeting. UPDATE: Discussed under Agenda Item 3.

2) Task force members to discuss within their respective companies the preference on removing/keeping a cap on the rate schedule(s). Members should be prepared to discuss at February 21st meeting. UPDATE: Discussed under Agenda Item 3.

3) Staff to incorporate illustrative timeline into the white paper to clearly explain the period for which billing determinants will be utilized in the annual rate setting process and the period for which the established rate would be in effect. UPDATE: Illustrative timeline was added to white paper (Agenda Item 4)

4) Staff to prepare formula templates for proposed rate schedules. UPDATE: This item remains open.

5) Staff to prepare analysis on monthly assessments illustrating materiality and the underlying components of the calculation UPDATE: Discussed under Agenda Item 3. Schedule was included in meeting materials. .

6) Staff to research current tariff language on bad debt, identifying exposure (if any) that would necessitate the inclusion of language in tariff sections under current revision. UPDATE: Discussed under Agenda Item 3. Memo was included in meeting materials.

Tariff Language Review Mike Riley facilitated the ongoing review and edit of the proposed tariff language as provided in the meeting materials. The Task Force worked through each of the sections representing the four rate schedules, providing numerous edits. There were several items/issues raised during the February 5th meeting that required additional analysis and consideration. A recap of those issues along with the ultimate resolution reached during this meeting is as follows:

(1) Rate Cap Issue: Current Schedule 1A explicitly sets a cap on the administrative fee that SPP can charge. Is a cap needed under the proposed new rate structure? At the conclusion of the February 5th meeting, Task Force members were asked to go back and discuss with their respective companies and be prepared to discuss at next meeting.

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Resolution: After a moderate amount of discussion, there was general agreement that a) some type of cap should remain in the tariff for the proposed rate structure and b) a cap for each rate schedule did not seem like a reasonable option. Wes Berger made the following motion related to the rate cap - “To retain the current administration cap in the tariff and develop a tab in the formula rate template that will duplicate the current methodology of calculating the 1A fee to compare the annual values to this cap.” Joel Dagerman seconded the motion. Staff expressed their concern with having a cap calculation that was disconnected from the rate setting calculations given the difference in the billing determinants utilized for each calculation. Rate cap calculation would be based on 12CP and proposed rate schedules 2-4 would be based on market billing determinants. Only rate schedule 1 is based on 12 CP. The motion passed by voice vote with MJMEUC abstaining.

(2) Location of New Tariff Language Issue: How should the new rate schedules be incorporated in the tariff? Options include leaving all in Schedule 1A, moving all to new section, or leaving only RS 1 in Schedule 1A while including all others in a separate section (e.g. 13 or AE). Moving any or all language from Schedule 1A would necessitate some TOs to make new filings with FERC and possibly trigger state filings for other entities. During the February 5th meeting, Task Force members were asked to go back and discuss impacts with their respective companies and be prepared to discuss at next meeting. Resolution: After a moderate amount of discussion, the Task Force agreed that the four proposed rate schedules should be retained within the current Schedule 1-A in some manner. Depending on further analysis of existing references in the tariff back to 1-A, it may make sense to create additional sections (B, C, and D) to accommodate the four rate schedules. In summary, the Task Force preferred that no new sections be created in the tariff for the four rate schedules (i.e. no Schedule 13 as previously proposed).

(3) Bad Debt Expense Reference Issue: Current Schedule 1A includes language to address bad debt expense. Under the new proposed rate schedules, is this language still necessary? During the February 5th meeting, staff was asked to research and prepare analysis for next meeting. Resolution: Dianne Branch provided an overview of the memo included in the meeting materials. In summary, current tariff language contains provisions to cover situations of non-payment for invoiced market and transmission activity. As described in the memo, situations that might give rise to bad debt expense in any given year would obviously impact the over/under recovery for that year and that impact would be included in the following year’s rate setting calculation as an adjustment to the NRR. Therefore, it is staff’s recommendation that there would be no special mention of bad debt expense in the tariff language supporting the new rate schedules given that it was really no different than any other variance to budget in a given year. While the Task Force agreed with staff’s recommendation to exclude from tariff language, they suggested a line for bad debt expense be incorporated into the formula rate templates to cover any future situation where such expense would be a component of the annual rate true-up.

(4) Monthly Assessments Issue: Under proposed new rate structure, should monthly assessments be eliminated? This current language resides in the by-laws and would require approval from the Corporate Governance Committee to remove. During the February 5th meeting, staff was asked to prepare analysis for next meeting.

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Resolution: Dianne Branch provided an overview of the analysis performed by staff since the last meeting. The conclusion of the analysis was that there was no load billed under the current methodology as a monthly assessment that would not be picked up in the proposed methodology either under Rate Schedule 1 as a TSR or under Rate Schedules 3 and 4 as market activity. This conclusion was confirmed during the meeting by SPP Settlements staff member, David Daniels. The Task Force concluded that no further consideration was needed for monthly assessments in the tariff language supporting the proposed four rate schedule structure. However, it was suggested that current monthly assessment language in the by-laws be reviewed further as there may be a need to remove reference to the Schedule 1-A billing practices.

White Paper Review The Task Force discussed the content of the white paper, identifying numerous items that need to be considered before the document can be finalized. Those items are summarized as follows:

1) Recent decisions made during this meeting need to be incorporated 2) MMU consultation and opinion should be more fully documented 3) Titles of rate schedules to be updated to match drafted tariff language 4) Transition/true-up processes should be more fully documented * 5) Language highlighting the correlation between Rate Schedule costs to FERC expense

accounts should be added 6) Remove vote counts/dissent comments 7) Refine definition of TCR Holder to more closely align to proposed tariff language 8) Add the rate schedule summary slide from previous presentations that summarizes by

rate schedule - costs to be recovered, who pays, billing determinants, etc. 9) Add language supporting the rationale as to the necessity for both Rate Schedule 3 and 4 10) Mention the decision to eliminate the virtual transactional fee charge. 11) Refine language in the Cash and Billing Determinant section to exclude some of the

discussions leading up to the final conclusions reached

*A separate motion was made by Bob Tallman to include transition/true-up language in the white paper. Motion was seconded by Wes Berger. The motion passed unanimously by voice vote.

Action Items

1) Staff to prepare formula templates for proposed rate schedules. 2) Staff to incorporate recommended edits to the white paper draft. 3) Staff to complete tariff language edits as discussed during meeting

Future Meetings Monday, March 25th 1AM-5PM – Teleconference/WebEx There being no further business, John Olsen adjourned the meeting at 2:05 PM. Respectfully Submitted, Dianne Branch Secretary

SCHEDULE 1-A

TARIFF ADMINISTRATION SERVICES

The Transmission Provider shall provide the administration services described in this

Schedule 1-A to carry out its responsibilities under this Tariff. Transmission Customers and

Market Participants must purchase these services from the Transmission Provider. Unless

otherwise collected under this Tariff, the Transmission Provider will recover 100% of its total

expenses incurred for the provision of these services, through the charges described herein, and

when such total expenses are divided by the total billing determinants of Schedule 1-A1, the

resulting rate will not exceed $.43 per MWh. The charges for these services are developed as

shown below.

1. Schedule 1-A1 Transmission Administration Service

Transmission administration service is provided by the Transmission Provider to all

Transmission Customers under this Tariff and includes the provision of: (1) reliability

coordination; (2) transmission scheduling; (3) system control; and, (4) transmission planning

services (“Schedule 1-A1 Service”).

a. Schedule 1-A1 Service Rate Calculation

The Schedule 1-A1 Service charge provides for the recovery of any costs incurred by

the Transmission Provider in providing this Schedule 1-A1 Service.

i. Costs

The costs to be recovered under this Schedule 1-A1 include without limitation, any costs

of direct resources, system maintenance, debt service for financing capital purchases associated

with providing Schedule 1-A1 Service, a proportionate allocation of corporate overhead

associated with providing Schedule 1-A1 Service, and other costs associated with providing

Schedule 1-A1 Service (“Schedule 1-A1 Costs”).

ii. Billing Determinants

Deleted: 13

Deleted: VE

Deleted: I. GENERAL ¶

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Deleted: 3

Deleted: In projecting and recovering its expenses,

Deleted: shall

Deleted: not otherwise collected under this Tariff, through the charges described in this Schedule 13.

Deleted: II.

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For Network Integration Transmission Service, the 12 month average of the Transmission

Customer’s coincident Zonal Demands used to determine the Demand Charges under Schedule 9

multiplied by the number of all hours for the applicable month.

For Point-to-Point Transmission Service, the MW of the reservation multiplied by the

number of hours reserved for the applicable month.

iii. Rate Formula

Annually, the Transmission Provider will determine the Schedule 1-A1 Service rate for each

calendar year as described in the Schedule 1-A1 template.

b. Schedule 1-A1 Charges To Transmission Customers

The Schedule 1-A1 charge is the product of the Schedule 1-A1 rate and the Transmission

Customer’s billing determinants.

2. Transmission Service Request Charges:

The Transmission Customer shall pay the Transmission Provider a charge for each new

Transmission Service Request as follows:

(a) For Firm Point-To-Point Transmission Service:

Reservations less than one month: $100

Reservations one month or longer: $200

(b) For Non-Firm Point-To-Point Transmission Service:

Each Reservation: $0.

However, the Transmission Customer shall have this fee rebated to it once the

Transmission Customer becomes legally obligated to pay the applicable Firm Point-To-Point

Transmission Service charges under this Tariff or if the requested Firm Point-To-Point

Transmission Service is denied by the Transmission Provider.

Deleted: ¶

Deleted: 13-1

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Deleted: .¶

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3. Schedule 1-A2 Transmission Congestion Rights Administration Service

Transmission Congestion Rights (“TCR”) administration service is provided by the

Transmission Provider to all Market Participants that hold TCRs issued and settled by the

Transmission Provider (“TCR Holder”). This service includes the provision of: (1) TCR

administration through allocation, assignment, auction or any other process under this Tariff; (2)

simultaneous feasibility tests and other applicable studies to determine the total TCRs that can be

accommodated by the Transmission System; (3) TCR tools; and, (4) a secondary market for

TCRs (“Schedule 1-A2 Service”).

a. Schedule 1-A2 Service Charge



i. Costs

The costs to be recovered under this Schedule 1-A2 include without limitation, any direct

resources, system maintenance, debt service for financing capital purchases associated with

providing Schedule 1-A2 Service, a proportionate allocation of corporate overhead, and all other

costs associated with providing Schedule 1-A2 Service (“Schedule 1-A2 Costs”).


The Schedule 1-A2 billing determinants are the total amount of TCR volume in MWh for

all TCR Holders for each billing period.

iii. Rate Formula

Annually, the Transmission Provider will determine the Schedule 1-A2 Service rate for

each calendar year as described in the Schedule 1-A2 template.

b. Charges To TCR Holders

Deleted: IV

Deleted: 13-2

Deleted: Administrative


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The Schedule 1-A2 charge is the product of the Schedule 1-A2 rate and the TCR

Holder’s billing determinants.

4. Schedule 1-A3 Integrated Marketplace Clearing Administration Service

Integrated Marketplace clearing administration service is provided by the Transmission

Provider to all Market Participants that participate in transactions pursuant to Attachment AE of

this Tariff or an applicable Market Participant Service Agreement as contained in Attachment

AH of this Tariff. This service includes the provision of: (1) market settlements; (2) credit

evaluation and risk mitigation services; (3) market monitoring functions; (4) information

technology support; and, (5) customer service (“Schedule 1-A3 Service”).

a. Integrated Marketplace Clearing Administration Service Charge

The Schedule 1-A3 Service charge provides for the recovery of any costs incurred by the

Transmission Provider in providing this Schedule 1-A3 Service.

i. Costs


resources, corporate overhead (including a proportionate allocation of indirect costs associated

with providing Schedule 1-A3 Service), and all other costs associated with providing Schedule 1-

A3 Service (“Schedule 1-A3 Costs”).


The Schedule 1-A3 billing determinants as expressed in MWh are: 1) all Real-Time

Energy injected into and withdrawn from the Transmission System; 2) all Import Interchange

Transactions in Real-Time and all Export Interchange Transactions in Real-Time; and, (3) all

cleared Virtual Energy Bids and all cleared Virtual Energy Offers.

iii. Rate Formula



Deleted: 13-2

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b. Charges To Market Participants

The Schedule 1-A3 charge is the product of the Schedule 1-A3 rate and the Market

Participant’s billing determinants.

5. Schedule 1-A4 Integrated Marketplace Facilitation Administration Service

Integrated Marketplace facilitation administration service is provided by the

Transmission Provider to all Market Participants that participate in transactions, except for

cleared Virtual Energy Bids and cleared Virtual Energy Offers, pursuant to Attachment AE of


AH of this Tariff. This service includes the provision and operation of the: (1) Day-Ahead

Market; (2) Real-Time Balancing Market; and, (3) Reliability Unit Commitment processes

(“Schedule 1-A4 Service”).

a. Integrated Marketplace Facilitation Administration Service Charge



i. Costs


resources, system maintenance, debt service (including costs of financing capital purchases

associated with providing Schedule 1-A4 Service), corporate overhead (including a proportionate

allocation of indirect costs associated with providing Schedule 1-A4 Service), and other costs

associated with providing Schedule 1-A4 Service (“Schedule 1-A4 Costs”).


The Schedule 1-A4 billing determinants are: 1) all Real-Time Energy injected into and

withdrawn from the Transmission System; and, 2) all Import Interchange Transactions in Real-

Time and all Export Interchange Transactions in Real-Time.

iii. Rate Formula

Deleted: 13-3

Deleted: 13-3

Deleted: VI

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Deleted: 13-4


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Revision Request Form SPP STAFF TO COMPLETE THIS SECTION

RR #: Date:

RR Title: System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes

SUBMITTER INFORMATION Name: Dianne Branch on behalf of Schedule 1-A Task Force

Company: Southwest Power Pool

Email: [email protected] Phone: 501-614-3223 Only Qualified Entities may submit Revision Requests.

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

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

a Revision Request “on their behalf”

SPP Market Monitor Staff of government authority with jurisdiction over

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

Working Group Transmission Customers or other entities that are parties to

transactions under the Tariff REVISION REQUEST DETAILS

Requested Resolution Timing: Normal Expedited Urgent Action

Reason for Expedited/Urgent Resolution:

Type of Revision (select all that apply):

Correction

Clarification

Design Enhancement

New Protocol, Business Practice, Criteria, Tariff

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

FERC Mandate (List order number(s))

REVISION REQUEST RISK DRIVERS

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

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

Compliance (Tariff, NERC, Other)

Reliability/Operations

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

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Market Protocols

Section(s): TOC, 4.2.2.6, 4.2.3.2, 4.5, 4.5.8, 4.5.8.20 (removing), 4.5.8.21 (renumbered), 4.5.8.22 (renumbered), 4.5.8.23 (renumbered), 4.5.8.24 (renumbered), 4.5.8.25 (renumbered), 4.5.8.26 (renumbered), 4.5.8.27 (renumbered), 4.5.8.28 (renumbered), 4.5.8.29 (renumbered), 4.5.9, 4.5.9.20, 4.5.11, 4.5.12, 4.6 (new), 4.6.1 (new), 4.6.2, 5.9 (new), Appendix G; G.2.5, G.6.4

Protocol Version: 66a

Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date:

Tariff (OATT)

Section(s): In the Main Body of the Tariff: Section 10.5 Transmission Provider Recovery Section 13.7 Classification of Firm Transmission Service Section 14.5 Classification of Non-Firm Point-To-Point Transmission Service Schedules: Schedule 1-A (Tariff Administration Services) Addendum 1 to Schedule 1-A (Formula Rate Template Protocols) Attachments to the Tariff: Attachment F (Service Agreement for NITS), Attachment 1 to the Network Integration Transmission Service Agreement Attachment H – where Schedule 1-A is referenced in various Addendums to Attachment H, those Addendums will be cleaned up to reflect Schedule 1-A1, as necessary, at a later time either by Participants or by SPP on their behalf – no changes included in the general sections of Attachment H necessary so nothing to attach here. Attachment L (Treatment of Revenues), Section IV Distribution of Other Revenues Attachment O (Transmission Planning Process), Section IV (Other Planning Studies) and Section IX (Recovering Costs Associated with the Planning Process) Attachment AE (Integrated Marketplace): Table of Contents 4.2.1 Virtual Energy Offers 4.3.2 Virtual Energy Bids 8.5.17 Day-Ahead Virtual Energy Transaction Fee Amount – (Remove Section) 8.10 Market Administration Services Amount – (New Section) Attachment AF (Market Mitigation Measures), Section 3.2 D and E

Business Practice Business Practice Number:

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Integrated Transmission Planning (ITP) Manual Section(s):

Revision Request Process Section(s): Minimum Transmission Design

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

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

SPP Communications Protocols Section(s):

OBJECTIVE OF REVISION

Objectives of Revision Request:

Currently, all of SPP’s administrative costs of providing all services are recovered through the application of Tariff Schedule 1-A. Schedule 1-A charges all load a certain rate that is determined each year, based on SPP’s projected costs to perform all services for the following year. Since its inception, only Transmission Customers pay Schedule 1-A charges.

In light of the expanded services provided by SPP in the Integrated Marketplace, SPP determined it was the right time to review the current cost recovery mechanism and determine a better mechanism to recover costs from all who use and benefit from SPP’s services.

The Schedule 1-A Task Force (“TF”) was tasked by the MOPC with developing a rate structure to allow SPP to recover its administrative costs of operations from users of SPP’s services as outlined in the Whitepaper developed by the TF. The TF has developed a rate methodology that adheres to the following broad principles of simplicity, better alignment of payer cost/benefits, and inclusion of energy transactions.

The Task Force reached general agreement that the proposed rate structure should include a mix of demand and energy charges. Generally, transmission-related charges would continue to be recovered through a demand charge and the market-related charges would be recovered through three different energy related charges.

Under the proposal, the energy-related charges will be recovered through three separate charges: 1) Transmission Congestion Rights Administrative Service (to be paid by all TCR Holders) and would cover the costs to administer the TCR Markets and related costs; 2) Integrated Marketplace Clearing Administrative Service (to be paid by all Market Participants including Virtuals) and would recover costs related to market settlement, credit services, market monitoring, and customer service; and 3) Integrated Marketplace Facilitation Administrative Service (to be paid by all Market Participants excluding Virtuals) and would recover costs to provide the Day Ahead Markets, Real Time Balancing Market, and RUC Processes.

Under the Task Force proposal, Schedule 1-A will remain and be broken into four rate schedules. The first being the original transmission service schedule (current 1-A) and it would become Schedule 1-A1 and the three previously mentioned Market Schedules would become Schedules 1-A2, 1-A3, and 1-A4.

Additional changes to the Tariff are also included to reflect the slight change in numbering of the current 1-A to 1-A1 and additional changes to reflect the rate schedule(s) throughout the Tariff including in Attachment AE. A currently effective rate in Attachment AE for Virtual Transactions is being removed as Virtuals are proposed to pay Schedule 1-A3 and that change has other changes to be made to AE to conform to this proposal. Changes are also proposed to the Marketplace Protocols and include similar changes to Attachment AE changes.

Describe the benefits that will be realized from this revision.

The benefits that will be realized from this revision is that the costs that SPP incurs to provide all of its current services will be allocated more appropriately to the customers who utilize those services.

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

Market Protocols

Market Protocols TABLE OF CONTENTS CURRENT REVISION ............................................................... Error! Bookmark not defined. TABLE OF CONTENTS ..............................................................................................................4

LIST OF EXHIBITS.................................................................... Error! Bookmark not defined. 1. Glossary .................................................................................. Error! Bookmark not defined. 2. Introduction ............................................................................ Error! Bookmark not defined.

2.1 Purpose ............................................................................... Error! Bookmark not defined.

3. SPP Integrated Marketplace Overview ............................... Error! Bookmark not defined. 3.1 Energy and Operating Reserve Markets ............................ Error! Bookmark not defined. 3.2 Transmission Congestion Rights Markets ......................... Error! Bookmark not defined.

4. Energy and Operating Reserve Markets Processes ............ Error! Bookmark not defined. 4.1 SPP System Requirements ................................................. Error! Bookmark not defined.

4.1.1 Reserve Zone Establishment ........................................ Error! Bookmark not defined. 4.1.2 Forecasting ................................................................... Error! Bookmark not defined.

4.1.2.1 Short Term and Mid-Term Load Forecasting ........ Error! Bookmark not defined. 4.1.2.1.1 Conforming Load ............................................. Error! Bookmark not defined. 4.1.2.1.2 Non-conforming Load ..................................... Error! Bookmark not defined. 4.1.2.1.3 Losses ............................................................... Error! Bookmark not defined. 4.1.2.1.4 Demand Response Adjustments ...................... Error! Bookmark not defined. 4.1.2.1.5 Reserve Zone Load .......................................... Error! Bookmark not defined. 4.1.2.1.6 Load Distribution ............................................. Error! Bookmark not defined.

4.1.2.2 Wind-Powered Generation Resource Output ForecastsError! Bookmark not defined. 4.1.2.3 Wind-Powered Generation Resource Data RequirementsError! Bookmark not defined. 4.1.2.4 Grandfathered Wind-Powered Generation Resource Data RequirementsError! Bookmark not defined.

4.1.2.5 Solar-Powered Generation Resource Output ForecastsError! Bookmark not defined. 4.1.2.6 Solar-Powered Generation Resource Data RequirementsError! Bookmark not defined.

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4.1.3 Operating Reserve, and Instantaneous Load Capacity RequirementsError! Bookmark not defined. 4.1.3.1 Reserve Zone Requirements .................................. Error! Bookmark not defined.

4.1.3.1.1 Minimum Reserve Zone Operating Reserve RequirementsError! Bookmark not defined. 4.1.3.1.2 Maximum Reserve Zone Operating Reserve LimitationsError! Bookmark not defined.

4.1.3.2 Instantaneous Load Capacity Requirements .......... Error! Bookmark not defined. 4.1.4 Violation Relaxation Limits ......................................... Error! Bookmark not defined.

4.1.4.1 Impact of VRLs on LMPs and MCPs .................... Error! Bookmark not defined. 4.1.4.2 Determination of VRLs.......................................... Error! Bookmark not defined. 4.1.4.3 VRL Reporting....................................................... Error! Bookmark not defined.

4.1.4.3.1 Annual Reporting ............................................. Error! Bookmark not defined. 4.1.5 Scarcity Pricing ............................................................ Error! Bookmark not defined.

4.1.5.1 Demand Curve Interaction with VRLs .................. Error! Bookmark not defined. 4.1.5.2 Operating Reserve Scarcity Factors ....................... Error! Bookmark not defined. 4.1.5.3 Regulation Base Demand Price ............................. Error! Bookmark not defined.

4.1.6 Ramp Sharing............................................................... Error! Bookmark not defined. 4.1.7 Outage Scheduling and Reporting ............................... Error! Bookmark not defined. 4.1.8 Joint Operating Agreements – Seams Coordination .... Error! Bookmark not defined. 4.1.9 Calculation of Net Benefits Test for Compensation of Demand Response LoadError! Bookmark not defined.

4.2 Pre-Day-Ahead Activities .................................................. Error! Bookmark not defined. 4.2.1 Must-Offer Requirement .............................................. Error! Bookmark not defined.

4.2.1.1 Day-Ahead Market................................................. Error! Bookmark not defined. 4.2.1.1.1 Penalty Calculation .......................................... Error! Bookmark not defined.

4.2.1.2 RUC and RTBM .................................................... Error! Bookmark not defined. 4.2.2 Offer Submittal ............................................................ Error! Bookmark not defined.

4.2.2.1 Resource Offer Parameters .................................... Error! Bookmark not defined. 4.2.2.1.1 Resource Ramp Rate Interaction – Energy and Operating ReserveError! Bookmark not defined. 4.2.2.1.2 Regulation-Up and Regulation-Down Service OffersError! Bookmark not defined. 4.2.2.1.3 Mitigated Regulation-Up and Regulation-Down Service OffersError! Bookmark not defined. 4.2.2.1.4 Mileage Factor Calculation .............................. Error! Bookmark not defined.

4.2.2.2 Resource Status ...................................................... Error! Bookmark not defined. 4.2.2.2.1 Commitment Status .......................................... Error! Bookmark not defined.

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4.2.2.2.2 Dispatch Status................................................. Error! Bookmark not defined. 4.2.2.3 Resource Limit Validation ..................................... Error! Bookmark not defined. 4.2.2.4 Resource Commitment Parameter Relationships... Error! Bookmark not defined.

4.2.2.4.1 Start-Up and Shut-Down Times....................... Error! Bookmark not defined. 4.2.2.5 Resource Modeling ................................................ Error! Bookmark not defined.

4.2.2.5.1 Dispatchable Demand Response Resource ...... Error! Bookmark not defined. 4.2.2.5.2 Block Demand Response Resource ................. Error! Bookmark not defined. 4.2.2.5.3 Combined Cycle Resource ............................... Error! Bookmark not defined. 4.2.2.5.4 Jointly Owned Unit .......................................... Error! Bookmark not defined. 4.2.2.5.5 Dispatchable Variable Energy Resources ........ Error! Bookmark not defined. 4.2.2.5.6 Non-Dispatchable Variable Energy Resources Error! Bookmark not defined. 4.2.2.5.7 External Dynamic Resource ............................ Error! Bookmark not defined. 4.2.2.5.8 Resources Pseudo-Tied Out of the SPP BAA . Error! Bookmark not defined. 4.2.2.5.9 Electric Storage Resource (ESR) ..................... Error! Bookmark not defined.

4.2.2.6 Virtual Energy Offers ..............................................................................................4

4.2.2.7 Import Interchange Transaction Offers .................. Error! Bookmark not defined. 4.2.3 Bid Submittal ............................................................... Error! Bookmark not defined.

4.2.3.1 Demand Bids .......................................................... Error! Bookmark not defined. 4.2.3.2 Virtual Energy Bids ...............................................................................................30

4.2.3.3 Export Interchange Transaction Bids..................... Error! Bookmark not defined. 4.2.4 Through Interchange Transactions .............................. Error! Bookmark not defined. 4.2.5 Ramp Reservation Requirements ................................. Error! Bookmark not defined. 4.2.6 Multi-Day Reliability Assessment ............................... Error! Bookmark not defined.

4.2.6.1 Multi-Day Reliability Assessment Inputs .............. Error! Bookmark not defined. 4.2.6.2 Multi-Day Reliability Assessment Analysis .......... Error! Bookmark not defined. 4.2.6.3 Multi-Day Reliability Assessment Results ............ Error! Bookmark not defined.

4.3 Day-Ahead Activities......................................................... Error! Bookmark not defined. 4.3.1 Day-Ahead Market....................................................... Error! Bookmark not defined.

4.3.1.1 DA Market Inputs .................................................. Error! Bookmark not defined. 4.3.1.2 DA Market Execution ............................................ Error! Bookmark not defined.

4.3.1.2.1 Clearing During Capacity Shortage ................. Error! Bookmark not defined.

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4.3.1.2.2 Clearing During Excess Generation ConditionsError! Bookmark not defined. 4.3.1.3 DA Market Results ................................................ Error! Bookmark not defined.

4.3.2 Day-Ahead Reliability Unit Commitment ................... Error! Bookmark not defined. 4.3.2.1 Day-Ahead RUC Inputs ......................................... Error! Bookmark not defined. 4.3.2.2 Day-Ahead RUC Execution ................................... Error! Bookmark not defined. 4.3.2.3 Day-Ahead RUC Results ....................................... Error! Bookmark not defined. 4.3.2.4 Update Current Operating Plan .............................. Error! Bookmark not defined.

4.4 Operating Day Activities ................................................... Error! Bookmark not defined. 4.4.1 Intra-Day Reliability Unit Commitment ...................... Error! Bookmark not defined.

4.4.1.1 Intra-Day RUC Inputs ............................................ Error! Bookmark not defined. 4.4.1.2 Intra-Day RUC Execution...................................... Error! Bookmark not defined. 4.4.1.3 Intra-Day RUC Results .......................................... Error! Bookmark not defined. 4.4.1.4 Update Current Operating Plan .............................. Error! Bookmark not defined.

4.4.2 Real-Time Balancing Market ....................................... Error! Bookmark not defined. 4.4.2.1 Managing Regulation Control Status Prior to Operating HourError! Bookmark not defined. 4.4.2.2 RTBM Inputs ......................................................... Error! Bookmark not defined.

4.4.2.2.1 Pre-Operating Hour Inputs: .............................. Error! Bookmark not defined. 4.4.2.2.2 In-Operating Hour Inputs:................................ Error! Bookmark not defined. 4.4.2.2.3 Control Status................................................... Error! Bookmark not defined.

4.4.2.3 RTBM Execution ................................................... Error! Bookmark not defined. 4.4.2.3.1 Quick-Start Resource Logic ............................. Error! Bookmark not defined. 4.4.2.3.2 Emergency Operations – Capacity Shortage ... Error! Bookmark not defined. 4.4.2.3.3 Emergency Operations – Excess Generation ... Error! Bookmark not defined. 4.4.2.3.4 Ensuring Reliable Operations .......................... Error! Bookmark not defined.

4.4.2.4 RTBM Results ....................................................... Error! Bookmark not defined. 4.4.2.5 Out-of-Merit Energy (OOME) Dispatch ............... Error! Bookmark not defined.

4.4.2.5.1 Fixed OOME .................................................... Error! Bookmark not defined. 4.4.2.5.2 OOME Cap and OOME Floor ......................... Error! Bookmark not defined. 4.4.2.5.3 Out-of-Merit Energy During Emergency ConditionsError! Bookmark not defined.

4.4.2.6 SPP Congestion Management ................................ Error! Bookmark not defined. 4.4.2.6.1 SPP Congestion Management under TLR OperationsError! Bookmark not defined.

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4.4.2.6.2 Congestion Management - Market Flow ......... Error! Bookmark not defined. 4.4.2.6.3 IDC Curtailments ............................................. Error! Bookmark not defined.

4.4.3 Energy and Operating Reserve Deployment ................ Error! Bookmark not defined. 4.4.3.1 Dispatchable Variable Energy Resource DeploymentError! Bookmark not defined. 4.4.3.2 Non-Dispatchable Variable Energy Resource DeploymentError! Bookmark not defined. 4.4.3.3 Regulation Deployment ......................................... Error! Bookmark not defined. 4.4.3.4 Contingency Reserve Deployment ........................ Error! Bookmark not defined. 4.4.3.5 Reserve Sharing Group Scheduling Procedures .... Error! Bookmark not defined. 4.4.3.6 Contingency Reserve Recovery ............................. Error! Bookmark not defined. 4.4.3.7 Market Storage Resource Development ................ Error! Bookmark not defined.

4.4.4 Energy and Operating Reserve Deployment Failure ... Error! Bookmark not defined. 4.4.4.1 Uninstructed Resource Deviation .......................... Error! Bookmark not defined.

4.4.4.1.1 URD Exemptions ............................................. Error! Bookmark not defined. 4.4.4.1.2 Load Deviation Exemptions ............................ Error! Bookmark not defined.

4.4.4.2 Regulation Deployment Failure Charges ............... Error! Bookmark not defined. 4.4.4.3 Contingency Reserve Deployment Failure Tests ... Error! Bookmark not defined.

4.4.5 Inadvertent Management ............................................. Error! Bookmark not defined. 4.4.5.1 Inadvertent Payback Reporting .............................. Error! Bookmark not defined.

4.5 Post Operating Day and Settlement Activities...................................................................31

4.5.1 Settlement Sign Conventions ....................................... Error! Bookmark not defined. 4.5.2 Commercial Model ...................................................... Error! Bookmark not defined.

4.5.2.1 Nodes ..................................................................... Error! Bookmark not defined. 4.5.2.2 Pricing Nodes ......................................................... Error! Bookmark not defined.

4.5.2.2.1 Aggregated Pricing Nodes ............................... Error! Bookmark not defined. 4.5.2.3 Settlement Locations .............................................. Error! Bookmark not defined.

4.5.2.3.1 Trading Hubs ................................................... Error! Bookmark not defined. 4.5.2.3.2 Resource Hubs ................................................. Error! Bookmark not defined.

4.5.2.4 Asset Owners ......................................................... Error! Bookmark not defined. 4.5.2.5 Market Participants ................................................ Error! Bookmark not defined.

4.5.3 Bilateral Settlement Schedules .................................... Error! Bookmark not defined. 4.5.3.1 Transition Mechanism for Pre-Existing Bilateral ContractsError! Bookmark not defined.

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4.5.3.2 GFA Carve Out or FSE Schedules – Internal ........ Error! Bookmark not defined. 4.5.3.3 GFA Carve Out or FSE Schedules – External ....... Error! Bookmark not defined. 4.5.3.4 GFA Carve Out or FSE Uplift ............................... Error! Bookmark not defined.

4.5.4 Calculation of LMPs, LMP Components and MCPs ... Error! Bookmark not defined. 4.5.4.1 LMP Calculations and LMP Components ............. Error! Bookmark not defined.

4.5.4.1.1 Marginal Losses Component Calculation ........ Error! Bookmark not defined. 4.5.4.1.2 Marginal Congestion Component Calculation. Error! Bookmark not defined. 4.5.4.1.3 Marginal Energy Component Calculation ....... Error! Bookmark not defined.

4.5.4.2 MCP Calculations .................................................. Error! Bookmark not defined. 4.5.5 Settlement Location LMPs and LMP Components ..... Error! Bookmark not defined.

4.5.5.1 Calculation of LMP at a Trading Hub Settlement LocationError! Bookmark not defined. 4.5.5.2 Calculation of LMP at a Load APNode Settlement LocationError! Bookmark not defined. 4.5.5.3 Calculation of LMP at an External Interface Settlement LocationError! Bookmark not defined.

4.5.6 Calculation of Actual Regulation Up/Down Mileage .. Error! Bookmark not defined. 4.5.7 Precision, Rounding and FERC Electric Quarterly ReportingError! Bookmark not defined.

4.5.7.1 FERC Electric Quarterly Reporting ....................... Error! Bookmark not defined. 4.5.8 Day-Ahead Market Settlement ....................................................................................32

4.5.8.1 Day-Ahead Asset Energy Amount......................... Error! Bookmark not defined. 4.5.8.2 Day-Ahead Non-Asset Energy Amount ................ Error! Bookmark not defined. 4.5.8.3 Day-Ahead Virtual Energy Amount ...................... Error! Bookmark not defined. 4.5.8.4 Day-Ahead Regulation-Up Service Amount ......... Error! Bookmark not defined. 4.5.8.5 Day-Ahead Regulation-Down Service Amount .... Error! Bookmark not defined. 4.5.8.6 Day-Ahead Spinning Reserve Amount .................. Error! Bookmark not defined. 4.5.8.7 Day-Ahead Supplemental Reserve Amount .......... Error! Bookmark not defined. 4.5.8.8 Day-Ahead Regulation-Up Service Distribution AmountError! Bookmark not defined. 4.5.8.9 Day-Ahead Regulation-Down Service Distribution AmountError! Bookmark not defined. 4.5.8.10 Day-Ahead Spinning Reserve Distribution AmountError! Bookmark not defined. 4.5.8.11 Day-Ahead Supplemental Reserve Distribution AmountError! Bookmark not defined. 4.5.8.12 Day-Ahead Make Whole Payment Amount .......... Error! Bookmark not defined. 4.5.8.13 Day-Ahead Make Whole Payment Distribution AmountError! Bookmark not defined. 4.5.8.14 Transmission Congestion Rights Funding AmountError! Bookmark not defined.

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4.5.8.15 Transmission Congestion Rights Daily Uplift AmountError! Bookmark not defined. 4.5.8.16 Transmission Congestion Rights Monthly Payback AmountError! Bookmark not defined. 4.5.8.17 Transmission Congestion Rights Annual Payback AmountError! Bookmark not defined. 4.5.8.18 Transmission Congestion Rights Annual Closeout AmountError! Bookmark not defined. 4.5.8.19 Day-Ahead Over-Collected Losses Distribution AmountError! Bookmark not defined. 4.5.8.20 Day-Ahead Demand Reduction Amount ...............................................................35

4.5.8.21 Day-Ahead Demand Reduction Distribution Amount ...........................................36

4.5.8.22 Day-Ahead Grandfathered Agreement Carve-Out Daily Amount ........................36

4.5.8.23 Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount ...................39

4.5.8.24 Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount ......................41

4.5.8.25 GFA Carve Out Distribution Daily Amount ..........................................................43

4.5.8.26 GFA Carve Out Distribution Monthly Amount .....................................................46

4.5.8.27 GFA Carve Out Distribution Yearly Amount ........................................................48

4.5.8.28 Day-Ahead Combined Interest Resource Adjustment Amount .............................50

4.5.9 Real-Time Balancing Market Settlement .....................................................................50

4.5.9.1 Real-Time Asset Energy Amount .......................... Error! Bookmark not defined. 4.5.9.2 Real-Time Non-Asset Energy Amount .................. Error! Bookmark not defined. 4.5.9.3 Real-Time Virtual Energy Amount ....................... Error! Bookmark not defined. 4.5.9.4 Real-Time Regulation-Up Service Amount........... Error! Bookmark not defined. 4.5.9.5 Real-Time Regulation-Down Service Amount ...... Error! Bookmark not defined. 4.5.9.6 Real-Time Spinning Reserve Amount ................... Error! Bookmark not defined. 4.5.9.7 Real-Time Supplemental Reserve Amount ........... Error! Bookmark not defined. 4.5.9.8 RUC Make-Whole Payment Amount .................... Error! Bookmark not defined. 4.5.9.9 Real-Time Out-Of-Merit Amount.......................... Error! Bookmark not defined. 4.5.9.10 RUC Make Whole Payment Distribution Amount Error! Bookmark not defined. 4.5.9.11 Real-Time Regulation-Up Service Distribution AmountError! Bookmark not defined. 4.5.9.12 Real-Time Regulation-Down Service Distribution AmountError! Bookmark not defined. 4.5.9.13 Real-Time Spinning Reserve Distribution AmountError! Bookmark not defined. 4.5.9.14 Real-Time Supplemental Reserve Distribution AmountError! Bookmark not defined. 4.5.9.15 Real-Time Regulation Service Non-Performance AmountError! Bookmark not defined. 4.5.9.16 Real-Time Regulation Non-Performance Distribution AmountError! Bookmark not defined.

Deleted: 4.5.8.20 Day-Ahead Virtual Energy Transaction Fee Amount 30¶

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4.5.9.17 Real-Time Contingency Reserve Deployment Failure AmountError! Bookmark not defined. 4.5.9.18 Real-Time Contingency Reserve Deployment Failure Distribution AmountError! Bookmark not defined. 4.5.9.19 Real-Time Regulation Service Deployment Adjustment AmountError! Bookmark not defined. 4.5.9.20 Over-Collected Losses Distribution Amount.........................................................59

4.5.9.21 Real-Time Joint Operating Agreement Amount .... Error! Bookmark not defined. 4.5.9.22 Real-Time Reserve Sharing Group Amount .......... Error! Bookmark not defined. 4.5.9.23 Real-Time Reserve Sharing Group Distribution AmountError! Bookmark not defined. 4.5.9.24 Real-Time Demand Reduction Amount ................ Error! Bookmark not defined. 4.5.9.25 Real-Time Demand Reduction Distribution AmountError! Bookmark not defined. 4.5.9.26 Real-Time Pseudo-Tie Congestion Amount .......... Error! Bookmark not defined. 4.5.9.27 Real-Time Pseudo-Tie Losses Amount ................. Error! Bookmark not defined. 4.5.9.28 Unused Regulation-Up Mileage Make Whole Payment AmountError! Bookmark not defined. 4.5.9.29 Unused Regulation-Down Mileage Make Whole Payment AmountError! Bookmark not defined. 4.5.9.30 Real-Time Combined Interest Resource Adjustment AmountError! Bookmark not defined.

4.5.10 ARR and TCR Auction Settlement .............................. Error! Bookmark not defined. 4.5.10.1 Transmission Congestion Rights Auction Transaction AmountError! Bookmark not defined. 4.5.10.2 Auction Revenue Rights Funding Amount ............ Error! Bookmark not defined. 4.5.10.3 Auction Revenue Rights Uplift Amount................ Error! Bookmark not defined. 4.5.10.4 Auction Revenue Rights Monthly Payback AmountError! Bookmark not defined. 4.5.10.5 Auction Revenue Rights Annual Payback AmountError! Bookmark not defined. 4.5.10.6 Auction Revenue Rights Annual Closeout AmountError! Bookmark not defined.

4.5.11 Miscellaneous Amount ................................................................................................50

4.5.12 Revenue Neutrality Uplift Distribution Amount ......... Error! Bookmark not defined. 4.5.13 Settlement Statement Process ...................................... Error! Bookmark not defined.

4.5.13.1 Meter Data and Bilateral Settlement Schedule SubmittalError! Bookmark not defined. 4.5.13.2 Daily Settlement Statement.................................... Error! Bookmark not defined. 4.5.13.3 Settlement Statement Access ................................. Error! Bookmark not defined. 4.5.13.4 S7 Scheduled Settlement Statements ..................... Error! Bookmark not defined. 4.5.13.5 S53 Scheduled Settlement Statements ................... Error! Bookmark not defined. 4.5.13.6 S120 Scheduled Settlement Statements ................. Error! Bookmark not defined. 4.5.13.7 Resettlement Statements ........................................ Error! Bookmark not defined.

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4.5.13.8 Settlement Timeline ............................................... Error! Bookmark not defined. 4.5.14 Settlement Invoice ....................................................... Error! Bookmark not defined.

4.5.14.1 Timing and Content of Invoice .............................. Error! Bookmark not defined. 4.5.14.2 Invoice Calendar .................................................... Error! Bookmark not defined. 4.5.14.3 Holiday Invoice Calendar ...................................... Error! Bookmark not defined.

4.5.15 Disputes........................................................................ Error! Bookmark not defined. 4.5.15.1 Dispute Submission Timeline ................................ Error! Bookmark not defined. 4.5.15.2 SPP Dispute Processing ......................................... Error! Bookmark not defined.

4.5.15.2.1 Dispute Status .................................................. Error! Bookmark not defined. 4.5.16 Invoice Payment Process ............................................. Error! Bookmark not defined.

4.5.16.1 Overview of Payment Process ............................... Error! Bookmark not defined. 4.5.16.2 Invoice Payments Due SPP .................................... Error! Bookmark not defined. 4.5.16.3 SPP Payments to Invoice Recipients ..................... Error! Bookmark not defined.

4.5.17 Billing Determinant Anomalies ................................... Error! Bookmark not defined. 4.6 Integrated Marketplace Administration Service

4.6.1 Integrated Marketplace Clearing Administration Service

4.6.2 Integrated Marketplace Facilitation Administration Service

5. Transmission Congestion Rights Markets Process ............. Error! Bookmark not defined. 5.1 Annual LTCR/ILTCR/ARR Verification Process ............. Error! Bookmark not defined.

5.1.1 Transmission Service Verification ............................... Error! Bookmark not defined. 5.1.1.1 TSR Modification for Resource Specific Source PointsError! Bookmark not defined.

5.1.2 Candidate LTCRs/ARRs .............................................. Error! Bookmark not defined. 5.1.3 ARR Nomination Cap .................................................. Error! Bookmark not defined.

5.2 Annual LTCR Allocation Process ..................................... Error! Bookmark not defined. 5.2.1 LTCR/ILTCR Surrender .............................................. Error! Bookmark not defined. 5.2.2 LTCR/ILTCR Nomination........................................... Error! Bookmark not defined. 5.2.3 LTCR Simultaneous Feasibility for LSEs and Incremental LTCRsError! Bookmark not defined. 5.2.4 Annual LTCR Awards for LSEs and Incremental LTCR AwardsError! Bookmark not defined. 5.2.5 LTCR Simultaneous Feasibility for Non-LSEs ........... Error! Bookmark not defined. 5.2.6 Annual LTCR Awards for Non-LSEs.......................... Error! Bookmark not defined. 5.2.7 LTCR /ILTCR Conversion to TCRs ............................ Error! Bookmark not defined.

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5.2.8 Initial ILTCR Award Process ...................................... Error! Bookmark not defined. 5.3 Annual ARR Allocation Process ....................................... Error! Bookmark not defined.

5.3.1 ARR Nominations ........................................................ Error! Bookmark not defined. 5.3.2 ARR Allocation ........................................................... Error! Bookmark not defined.

5.3.2.1 Transitional ARR Allocation ................................. Error! Bookmark not defined. 5.3.3 Simultaneous Feasibility .............................................. Error! Bookmark not defined. 5.3.4 Annual ARR Awards ................................................... Error! Bookmark not defined.

5.4 Annual TCR Auction ......................................................... Error! Bookmark not defined. 5.4.1 TCR Bid and Offer Submittal ...................................... Error! Bookmark not defined. 5.4.2 Annual TCR Auction Process ...................................... Error! Bookmark not defined. 5.4.3 Annual TCR Auction Clearing and Simultaneous FeasibilityError! Bookmark not defined. 5.4.4 Annual TCR Awards.................................................... Error! Bookmark not defined.

5.5 Monthly ARR Allocation Process ..................................... Error! Bookmark not defined. 5.5.1 Monthly ARR Transmission Service Verification ....... Error! Bookmark not defined. 5.5.2 Monthly ARR Nominations ......................................... Error! Bookmark not defined. 5.5.3 Simultaneous Feasibility .............................................. Error! Bookmark not defined. 5.5.4 Monthly ARR Awards ................................................. Error! Bookmark not defined.

5.6 Monthly TCR Auction Processes....................................... Error! Bookmark not defined. 5.6.1 TCR Bid and Offer Submittal ...................................... Error! Bookmark not defined. 5.6.2 Monthly TCR Auction Process .................................... Error! Bookmark not defined. 5.6.3 Monthly TCR Auction Clearing and Simultaneous FeasibilityError! Bookmark not defined. 5.6.4 Monthly TCR Awards.................................................. Error! Bookmark not defined.

5.7 ARR Allocation/TCR Auction Settlements ....................... Error! Bookmark not defined. 5.8 TCR Secondary Market ..................................................... Error! Bookmark not defined. 5.9 Transmission Congestion Rights Administration Service

6. Market Registration............................................................... Error! Bookmark not defined.

6.1 Registration of Resources .................................................. Error! Bookmark not defined. 6.1.1 Responsibilities of the Resource Asset Owner ............ Error! Bookmark not defined. 6.1.2 Energy Production Prior to Completion of Market RegistrationError! Bookmark not defined. 6.1.3 Common Bus ............................................................... Error! Bookmark not defined. 6.1.4 Dispatchable Demand Response Resource .................. Error! Bookmark not defined.

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6.1.5 Block Demand Response Resource ............................. Error! Bookmark not defined. 6.1.6 Jointly Owned Unit Resource ...................................... Error! Bookmark not defined.

6.1.6.1 Individual Resource Option ................................... Error! Bookmark not defined. 6.1.7 Combined Cycle Resource ........................................... Error! Bookmark not defined.

6.1.7.1 Multi-Configuration Combined Cycle Resource ... Error! Bookmark not defined. 6.1.8 Dispatchable Variable Energy Resource ..................... Error! Bookmark not defined. 6.1.9 Non-Dispatchable Variable Energy Resource ............. Error! Bookmark not defined. 6.1.10 Resources External to the SPP BA .............................. Error! Bookmark not defined.

6.1.10.1 External Dynamic Resources ................................. Error! Bookmark not defined. 6.1.10.2 Resources External to the SPP BA Pseudo-Tying InError! Bookmark not defined. 6.1.10.3 Resources Internal to the SPP BA Pseudo-Tying OutError! Bookmark not defined.

6.1.11 Operating Reserve Certification .................................. Error! Bookmark not defined. 6.1.11.1 Spin Qualified Resources ....................................... Error! Bookmark not defined. 6.1.11.2 Supplemental Qualified Resources ........................ Error! Bookmark not defined. 6.1.11.3 Regulation Qualified Resources ............................ Error! Bookmark not defined.

6.1.11.3.1 Regulation Testing Procedures ........................ Error! Bookmark not defined. 6.1.11.3.2 Regulation Testing Scoring.............................. Error! Bookmark not defined. 6.1.11.3.3 Regulation Qualified Resource Compliance RatingError! Bookmark not defined.

6.1.12 Resource Auxiliary Load Modeling............................. Error! Bookmark not defined. 6.1.13 Staggered Start Resource ............................................. Error! Bookmark not defined. 6.1.14 Combined Interest Resource Modeling ....................... Error! Bookmark not defined. 6.1.15 Market Storage Resource (MSR) ................................. Error! Bookmark not defined.

6.2 Registration of Load .......................................................... Error! Bookmark not defined. 6.2.1 Responsibilities of the Load......................................... Error! Bookmark not defined. 6.2.2 Non-Conforming Load................................................. Error! Bookmark not defined. 6.2.3 Demand Response Load Asset..................................... Error! Bookmark not defined. 6.2.4 Dispatchable Demand Response Load Settlement LocationError! Bookmark not defined. 6.2.5 Block Demand Response Load Settlement Location... Error! Bookmark not defined. 6.2.6 Loads External to the SPP BA Pseudo-Tying In ......... Error! Bookmark not defined. 6.2.7 Loads Internal to the SPP BA Pseudo-Tying Out ........ Error! Bookmark not defined. 6.2.8 Loads Transfers Relating to Bilateral Contracts .......... Error! Bookmark not defined.

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6.3 Registration of Meter Agent .............................................. Error! Bookmark not defined. 6.4 Network and Commercial Model Updates ........................ Error! Bookmark not defined. 6.5 Registration of External Participants in the Reserve Sharing GroupError! Bookmark not defined. 6.6 TCR/ARR Related Network and Commercial Model UpdatesError! Bookmark not defined.

6.6.1 Modeling with Future Effective Date .......................... Error! Bookmark not defined. 6.6.1.1 Future Effective Dated Resource Registration ...... Error! Bookmark not defined. 6.6.1.2 Future Effective Dated Load Registration ............. Error! Bookmark not defined.

6.7 Naming Conventions for Market Assets ............................ Error! Bookmark not defined. 6.7.1 General Requirements .................................................. Error! Bookmark not defined. 6.7.2 Resource Settlement Location /Asset Name ................ Error! Bookmark not defined. 6.7.3 Load Settlement Location Name/Asset Name ............. Error! Bookmark not defined. 6.7.4 Hub Settlement Location Name ................................... Error! Bookmark not defined. 6.7.5 Tie Interface Meter Data Submittal Location (MDSL) NameError! Bookmark not defined. 6.7.6 Source/Sink Name ....................................................... Error! Bookmark not defined. 6.7.7 Market and/or Reliability Data Developed and Named by SPPError! Bookmark not defined.

7. Market System Outage and Error Handling....................... Error! Bookmark not defined. 7.1 Market System Outages ..................................................... Error! Bookmark not defined.

7.1.1 Day-Ahead Market System Outages ............................ Error! Bookmark not defined. 7.1.2 SPP-Wide Real-Time Balancing Market System OutagesError! Bookmark not defined. 7.1.3 Islanded Real-Time Balancing Market System OutagesError! Bookmark not defined.

7.2 Procedures for Correcting LMPs and/or MCPs Resulting From Market Software and Data Errors ................................................................................. Error! Bookmark not defined.

7.2.1 Procedures for Revising Prices in Response to Market Software and Data ErrorsError! Bookmark not defined. 7.2.1.1 Notice to Market Participants and the Public ........ Error! Bookmark not defined. 7.2.1.2 Process for Recalculating DA Market Cleared Amounts and PricesError! Bookmark not defined. 7.2.1.3 Process for Recalculating RTBM Prices................ Error! Bookmark not defined. 7.2.1.4 Compensatory Payments to Market Participants ... Error! Bookmark not defined.

7.2.2 Disputes and Resettlement Provisions ......................... Error! Bookmark not defined.

8. Market Monitoring and Mitigation ...................................... Error! Bookmark not defined. 8.1 Market Monitoring Plan ..................................................... Error! Bookmark not defined.

8.1.1 Purpose and Objective ................................................. Error! Bookmark not defined.

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8.1.2 Resolution of Conflicts ................................................ Error! Bookmark not defined. 8.1.3 Independent Market Monitor ....................................... Error! Bookmark not defined.

8.1.3.1 Staffing and Resources .......................................... Error! Bookmark not defined. 8.1.3.2 Relationships and Notifications ............................. Error! Bookmark not defined. 8.1.3.3 Standards of Conduct ............................................. Error! Bookmark not defined.

8.1.4 Market Monitoring ....................................................... Error! Bookmark not defined. 8.1.4.1 Markets to be Monitored ........................................ Error! Bookmark not defined. 8.1.4.2 Monitoring Activities ............................................. Error! Bookmark not defined. 8.1.4.3 Instances of Market Power..................................... Error! Bookmark not defined. 8.1.4.4 Market Participant Behavior Warranting Possible MitigationError! Bookmark not defined.

8.1.5 Inquiries ....................................................................... Error! Bookmark not defined. 8.1.5.1 Requests ................................................................. Error! Bookmark not defined. 8.1.5.2 Conducting Inquiries .............................................. Error! Bookmark not defined. 8.1.5.3 Reporting................................................................ Error! Bookmark not defined.

8.1.6 Compliance and Corrective Actions ............................ Error! Bookmark not defined. 8.1.6.1 Compliance ............................................................ Error! Bookmark not defined. 8.1.6.2 Corrective Actions for Market Design ................... Error! Bookmark not defined.

8.1.7 Reporting...................................................................... Error! Bookmark not defined. 8.1.7.1 Annual State of the Market Report ........................ Error! Bookmark not defined. 8.1.7.2 Monthly, Quarterly and Annual Metrics Reports .. Error! Bookmark not defined. 8.1.7.3 Communication of Market Monitoring Reports .... Error! Bookmark not defined. 8.1.7.4 Other Reports ......................................................... Error! Bookmark not defined.

8.1.8 Performance Indices, Metrics and Screens .................. Error! Bookmark not defined. 8.1.8.1 Development .......................................................... Error! Bookmark not defined.

8.1.9 Referrals to the Commission ........................................ Error! Bookmark not defined. 8.1.10 Market Manipulation ................................................... Error! Bookmark not defined. 8.1.11 Monitoring for Potential Transmission Market Power ActivitiesError! Bookmark not defined. 8.1.12 Data Access, Collection and Retention ........................ Error! Bookmark not defined.

8.1.12.1 Confidentiality ....................................................... Error! Bookmark not defined. 8.1.12.2 Access to SPP Data and Information ..................... Error! Bookmark not defined. 8.1.12.3 Access to Market Participant Data and InformationError! Bookmark not defined.

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8.1.12.4 Data Created by the Market Monitor ..................... Error! Bookmark not defined. 8.1.13 Miscellaneous Provisions............................................. Error! Bookmark not defined.

8.1.13.1 Rights and Remedies.............................................. Error! Bookmark not defined. 8.1.13.2 Disputes.................................................................. Error! Bookmark not defined. 8.1.13.3 Review of Market Monitor .................................... Error! Bookmark not defined.

8.2 Market Power Mitigation and Monitoring ......................... Error! Bookmark not defined. 8.2.1 Purpose and Objectives ................................................ Error! Bookmark not defined. 8.2.2 Economic Withholding ................................................ Error! Bookmark not defined.

8.2.2.1 Mitigate Only in the Presence of Local Market PowerError! Bookmark not defined. 8.2.2.2 Mitigation Measures .............................................. Error! Bookmark not defined. 8.2.2.3 Mitigation Measures for Energy Offer Curves ...... Error! Bookmark not defined. 8.2.2.4 Mitigation Measures for Start-Up and No-Load OffersError! Bookmark not defined. 8.2.2.5 Mitigation Measures for Operating Reserve OffersError! Bookmark not defined. 8.2.2.6 Mitigation Measures for Transition State Offers ... Error! Bookmark not defined. 8.2.2.7 Local Market Power Test ....................................... Error! Bookmark not defined.

8.2.2.7.1 Frequently Constrained Areas.......................... Error! Bookmark not defined. 8.2.2.8 Additional Mitigation Measures for Resource Offer ParametersError! Bookmark not defined. 8.2.2.9 Market Impact Test ................................................ Error! Bookmark not defined. 8.2.2.10 Mitigated Offer Development Guidelines ............. Error! Bookmark not defined. 8.2.2.11 Participant Requested Mitigation Exceptions ........ Error! Bookmark not defined.

8.2.3 Uneconomic Production............................................... Error! Bookmark not defined. 8.2.4 Measures and Mitigation for Virtual Energy Bids and OffersError! Bookmark not defined.

8.2.4.1 Metric and Threshold Specifications ..................... Error! Bookmark not defined. 8.2.4.2 Excessive Divergence and Mitigation Measures ... Error! Bookmark not defined.

8.2.5 Offer Caps and Floors .................................................. Error! Bookmark not defined. 8.2.6 Physical Withholding ................................................... Error! Bookmark not defined.

8.2.6.1 Thresholds for Identifying Physical Withholding of Resource CapacityError! Bookmark not defined. 8.2.6.2 Thresholds for Identifying Physical Withholding of Transmission FacilitiesError! Bookmark not defined. 8.2.6.3 Sanctions for Physical Withholding....................... Error! Bookmark not defined.

8.2.7 Sanctions for Noncompliance with the Day-Ahead Market Must Offer RequirementError! Bookmark not defined. 8.2.8 Maintenance and Implementation of the Mitigation ProtocolsError! Bookmark not defined.

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9. Market Process and System Change Process ...................... Error! Bookmark not defined. 9.1 Root Cause Analysis .......................................................... Error! Bookmark not defined.

Appendix A Registration Portal ......................................... Error! Bookmark not defined. Appendix B XML Specifications.............................................. Error! Bookmark not defined. Appendix C Meter Technical Protocols ............................ Error! Bookmark not defined.

C.1 Scope .................................................................................. Error! Bookmark not defined. C.2 Purpose ............................................................................... Error! Bookmark not defined. C.3 Definitions.......................................................................... Error! Bookmark not defined. C.4 Applicable Standards ......................................................... Error! Bookmark not defined. C.5 General ............................................................................... Error! Bookmark not defined.

C.5.1 Introduction .................................................................. Error! Bookmark not defined. C.5.2 Existing Facilities......................................................... Error! Bookmark not defined. C.5.3 Physical Location of Meter .......................................... Error! Bookmark not defined. C.5.4 Metering of Net Interchange ........................................ Error! Bookmark not defined. C.5.5 Metering for Resources ................................................ Error! Bookmark not defined. C.5.6 Metering for Loads ...................................................... Error! Bookmark not defined. C.5.7 Measurement Quantity Verification ............................ Error! Bookmark not defined. C.5.8 Measurement Governance ........................................... Error! Bookmark not defined.

C.6 Timing Standard................................................................. Error! Bookmark not defined. C.6.1 Remote Terminal Unit (RTU) Freeze Contact or SignalError! Bookmark not defined. C.6.2 Accumulators / Register Values................................... Error! Bookmark not defined. C.6.3 Accuracy - Meter ......................................................... Error! Bookmark not defined. C.6.4 Accuracy – EMS/RTU ................................................. Error! Bookmark not defined.

C.7 Meters ................................................................................ Error! Bookmark not defined. C.7.1 Measurement Quantities .............................................. Error! Bookmark not defined. C.7.2 Measurement Configuration ........................................ Error! Bookmark not defined. C.7.3 Accuracy ...................................................................... Error! Bookmark not defined. C.7.4 Testing.......................................................................... Error! Bookmark not defined.

C.7.4.1 Testing Equipment ................................................. Error! Bookmark not defined. C.7.4.2 Acceptance Testing ................................................ Error! Bookmark not defined. C.7.4.3 In-Service Testing .................................................. Error! Bookmark not defined.

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C.7.4.4 Verification Records and Retention ....................... Error! Bookmark not defined. C.7.5 Real Time Metering ..................................................... Error! Bookmark not defined.

C.7.5.1 General ................................................................... Error! Bookmark not defined. C.7.5.2 Measurement Configuration .................................. Error! Bookmark not defined. C.7.5.3 Accuracy ................................................................ Error! Bookmark not defined. C.7.5.4 Testing.................................................................... Error! Bookmark not defined.

C.7.5.4.1 Testing Equipment ........................................... Error! Bookmark not defined. C.7.5.4.2 Acceptance Testing .......................................... Error! Bookmark not defined. C.7.5.4.3 Operating Conditions ....................................... Error! Bookmark not defined. C.7.5.4.4 Output Characteristics ...................................... Error! Bookmark not defined. C.7.5.4.5 In Service Testing ............................................ Error! Bookmark not defined. C.7.5.4.6 Verification Records and Retention ................. Error! Bookmark not defined.

C.7.6 New Current and Voltage Sensing Technologies ........ Error! Bookmark not defined. C.7.7 Current Transformers ................................................... Error! Bookmark not defined.

C.7.7.1 Nameplate .............................................................. Error! Bookmark not defined. C.7.7.2 Polarity ................................................................... Error! Bookmark not defined. C.7.7.3 Burden Testing ....................................................... Error! Bookmark not defined. C.7.7.4 Paralleling .............................................................. Error! Bookmark not defined.

C.7.8 Coupling Capacitor Voltage Transformers .................. Error! Bookmark not defined. C.7.8.1 General ................................................................... Error! Bookmark not defined. C.7.8.2 Nameplate .............................................................. Error! Bookmark not defined. C.7.8.3 Polarity ................................................................... Error! Bookmark not defined. C.7.8.4 Burden .................................................................... Error! Bookmark not defined.

C.7.9 Wire Wound Voltage Transformers ............................. Error! Bookmark not defined. C.7.9.1 Nameplate .............................................................. Error! Bookmark not defined. C.7.9.2 Polarity ................................................................... Error! Bookmark not defined. C.7.9.3 Burden .................................................................... Error! Bookmark not defined.

C.7.10 Ancillary Devices......................................................... Error! Bookmark not defined. C.7.10.1 Wiring .................................................................... Error! Bookmark not defined.

C.7.10.1.1 Phase Wiring .................................................... Error! Bookmark not defined. C.7.10.1.2 Neutral Returns ................................................ Error! Bookmark not defined.

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C.7.10.1.3 Induced Voltage on Wiring .............................. Error! Bookmark not defined. C.7.10.1.4 Fusing ............................................................... Error! Bookmark not defined. C.7.10.1.5 Test Switches ................................................... Error! Bookmark not defined.

C.7.11 Metering Site Procedures ............................................. Error! Bookmark not defined. C.7.11.1 General ................................................................... Error! Bookmark not defined. C.7.11.2 Site Verification Procedure .................................... Error! Bookmark not defined. C.7.11.3 Periodic Test Procedure ......................................... Error! Bookmark not defined.

C.7.12 Node Loss Compensation ............................................ Error! Bookmark not defined. C.7.12.1 General ................................................................... Error! Bookmark not defined. C.7.12.2 Methods for Compensation .................................... Error! Bookmark not defined.

C.7.12.2.1 Flat Percentage Adjustment ............................. Error! Bookmark not defined. C.7.12.2.2 Engineered Adjustment with Assumptions ...... Error! Bookmark not defined. C.7.12.2.3 Engineered Adjustment .................................... Error! Bookmark not defined.

C.7.12.3 Node Loss Compensation Variables and CalculationsError! Bookmark not defined. C.7.12.3.1 Transformer Test Data ..................................... Error! Bookmark not defined. C.7.12.3.2 Calculating data not supplied with Transformer Test DataError! Bookmark not defined. C.7.12.3.3 Transmission line losses .................................. Error! Bookmark not defined. C.7.12.3.4 Secondary line losses ....................................... Error! Bookmark not defined.

C.7.13 Record Retention ......................................................... Error! Bookmark not defined.

Appendix D Settlement Metering Data Management ProtocolsError! Bookmark not defined. D.1 Scope .................................................................................. Error! Bookmark not defined. D.2 Purpose ............................................................................... Error! Bookmark not defined. D.3 Definitions.......................................................................... Error! Bookmark not defined. D.4 Market Participants ............................................................ Error! Bookmark not defined.

D.4.1 Responsibilities ............................................................ Error! Bookmark not defined. D.4.2 Meter Agent(s) Designation ......................................... Error! Bookmark not defined.

D.5 Meter Agent ....................................................................... Error! Bookmark not defined. D.6 Data Format ....................................................................... Error! Bookmark not defined.

D.6.1 Unit of Measure ........................................................... Error! Bookmark not defined. D.6.2 Sign Convention of Data .............................................. Error! Bookmark not defined. D.6.3 Meter Technical Standards .......................................... Error! Bookmark not defined.

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D.6.4 Data Submission Standards.......................................... Error! Bookmark not defined. D.7 Settlement Meter Data Types ............................................. Error! Bookmark not defined.

D.7.1 Resource Metering ....................................................... Error! Bookmark not defined. D.7.1.1 Joint Owned Unit (JOU) Generation ..................... Error! Bookmark not defined. D.7.1.2 Generation Loss Compensation ............................. Error! Bookmark not defined.

D.7.2 Load Metering .............................................................. Error! Bookmark not defined. D.7.2.1 General ................................................................... Error! Bookmark not defined. D.7.2.2 Load Loss Compensation ....................................... Error! Bookmark not defined. D.7.2.3 Residual Load ........................................................ Error! Bookmark not defined.

D.7.3 Settlement Area Tie-Lines ........................................... Error! Bookmark not defined. D.7.3.1 Substitution for Missing Data ................................ Error! Bookmark not defined.

D.8 Settlement Location Anatomy ........................................... Error! Bookmark not defined. D.8.1 General ......................................................................... Error! Bookmark not defined. D.8.2 Making of a Settlement Location ................................. Error! Bookmark not defined.

D.8.2.1 Resource and Load Settlement Locations .............. Error! Bookmark not defined. D.8.2.2 Overview of Settlement Area Load Settlement LocationsError! Bookmark not defined.

D.9 Loss Compensation ............................................................ Error! Bookmark not defined. D.9.1 General ......................................................................... Error! Bookmark not defined. D.9.2 Loss Compensation Examples ..................................... Error! Bookmark not defined.

D.9.2.1 Loss Compensation to Node when Meter is on Distribution SystemError! Bookmark not defined. D.9.2.2 Loss Compensation to Node when Meter and Node at Different LocationError! Bookmark not defined.

D.9.3 Meter Data Exchange and Submission ........................ Error! Bookmark not defined. D.9.3.1 Actual Meter Data (Idata) ...................................... Error! Bookmark not defined. D.9.3.2 Alternate Settlement Meter Data ........................... Error! Bookmark not defined.

D.10 Data Source and Estimating ............................................... Error! Bookmark not defined. D.10.1 Actual Meter Data (Idata – Actual) ............................. Error! Bookmark not defined.

D.10.1.1 Primary Data Sources ............................................ Error! Bookmark not defined. D.10.1.2 Backup Data Sources ............................................. Error! Bookmark not defined.

D.10.2 Estimated Meter Data (Idata – Estimated) ................... Error! Bookmark not defined. D.10.2.1 Estimation Methods ............................................... Error! Bookmark not defined. D.10.2.2 Replacing Estimated Meter Data ........................... Error! Bookmark not defined.

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D.11 Verification Meter SL Values ............................................ Error! Bookmark not defined. D.11.1 Data Types and Verification Methods ......................... Error! Bookmark not defined.

D.11.1.1 Telemetered Pulses via Remote Terminal Unit (RTU)Error! Bookmark not defined. D.11.1.2 Register Transfer via Other Communication OptionsError! Bookmark not defined. D.11.1.3 Interval Data Recorder Collection System (IDRCS)Error! Bookmark not defined. D.11.1.4 Inter Control Center Protocol (ICCP) Data ........... Error! Bookmark not defined. D.11.1.5 Alternate Data for Verification .............................. Error! Bookmark not defined.

D.11.2 Periodicity of Verification ........................................... Error! Bookmark not defined. D.11.2.1 Telemetered Pulses via Remote Terminal Unit (RTU)Error! Bookmark not defined. D.11.2.2 Other Data Transfers .............................................. Error! Bookmark not defined.

D.11.3 Verification Uncovers Discrepancy ............................. Error! Bookmark not defined. D.11.3.1 Identify the Cause for the Discrepancy .................. Error! Bookmark not defined. D.11.3.2 Impact to Settlement Location Values Submitted . Error! Bookmark not defined.

D.11.3.2.1 Settlement Data Values Correct ....................... Error! Bookmark not defined. D.11.3.2.2 Settlement Data Values Incorrect .................... Error! Bookmark not defined.

D.11.3.2.2.1 Requirement for Resubmission .................. Error! Bookmark not defined. D.11.3.2.2.2 Good Utility Business Practices/Contractual RequirementsError! Bookmark not defined.

D.12 Real Time Data Reporting to SPP Balancing Authority .... Error! Bookmark not defined. D.13 Record Retention ............................................................... Error! Bookmark not defined.

Appendix E Network and Commercial Model Update TimingError! Bookmark not defined. Appendix F Settlement Examples............................................ Error! Bookmark not defined.

F.1 Introduction ........................................................................ Error! Bookmark not defined. F.1.1 Purpose ......................................................................... Error! Bookmark not defined. F.1.2 Definition of Terms...................................................... Error! Bookmark not defined. F.1.3 Outstanding Issues/Assumptions ................................. Error! Bookmark not defined.

F.2 Market Model..................................................................... Error! Bookmark not defined. F.2.1 Commercial Model ...................................................... Error! Bookmark not defined.

F.2.1.1 Financial Entities and Relationships ...................... Error! Bookmark not defined. F.2.1.2 Network Entities and Relationships ....................... Error! Bookmark not defined.

F.2.2 Transactional Legend ................................................... Error! Bookmark not defined.

Appendix G Mitigated Offer Development Guidelines .... Error! Bookmark not defined.

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G.1 Introduction ........................................................................ Error! Bookmark not defined. G.1.1 About These Guidelines ............................................... Error! Bookmark not defined. G.1.2 Intended Audience ....................................................... Error! Bookmark not defined. G.1.3 What is in this Manual? ............................................... Error! Bookmark not defined. G.1.4 Purpose ......................................................................... Error! Bookmark not defined. G.1.5 Mitigated Offer Methodology Approval Process ........ Error! Bookmark not defined.

G.2 Policies for All Resource Types ........................................ Error! Bookmark not defined. G.2.1 Heat Rates .................................................................... Error! Bookmark not defined.

G.2.1.1 Heat Content of Fuel .............................................. Error! Bookmark not defined. G.2.1.2 Heat Rate Curves ................................................... Error! Bookmark not defined.

G.2.2 Performance Factors .................................................... Error! Bookmark not defined. G.2.2.1 Engineering Judgment in Performance Factors ..... Error! Bookmark not defined. G.2.2.2 Calculation Methods of Performance Factors ........ Error! Bookmark not defined. G.2.2.3 “Like” Resources for Performance Factors ........... Error! Bookmark not defined.

G.2.3 Fuel Cost Policies ........................................................ Error! Bookmark not defined. G.2.3.1 Modifications to Fuel Cost Policies ....................... Error! Bookmark not defined. G.2.3.2 Fuel Cost Calculation ............................................. Error! Bookmark not defined. G.2.3.3 Total Fuel Related Costs ........................................ Error! Bookmark not defined. G.2.3.4 Types of Fuel Costs ............................................... Error! Bookmark not defined. G.2.3.5 Emission Allowances ............................................. Error! Bookmark not defined. G.2.3.6 Variable Fuel Transportation Equipment ............... Error! Bookmark not defined.

G.2.4 Total Variable Operation and Maintenance Cost ......... Error! Bookmark not defined. G.2.4.1 Escalation Index ..................................................... Error! Bookmark not defined. G.2.4.2 Maintenance Period ............................................... Error! Bookmark not defined. G.2.4.3 Average VOM Cost ............................................... Error! Bookmark not defined.

G.2.5 Mitigated Energy Offer Curve ..................................... Error! Bookmark not defined. G.2.6 Mitigated Start- Up Offer ............................................. Error! Bookmark not defined.

G.2.6.1 Start- Up Offer Definitions .................................... Error! Bookmark not defined. G.2.7 Mitigated No-Load Offer ............................................. Error! Bookmark not defined.

G.2.7.1 No-Load Definitions .............................................. Error! Bookmark not defined. G.2.7.2 No-Load Fuel ......................................................... Error! Bookmark not defined.

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G.2.8 Mitigated Spinning Reserve Offer ............................... Error! Bookmark not defined. G.2.9 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.2.10 Mitigated Regulation-Up and Regulation-Down Service OffersError! Bookmark not defined.

G.2.10.1 Uncompensated Costs: ........................................... Error! Bookmark not defined. G.2.10.2 Cost Increase due to Heat Rate increase during non-steady state:Error! Bookmark not defined. G.2.10.3 Cost increase in Variable Operations and Maintenance:Error! Bookmark not defined.

G.3 Nuclear Unit Guidelines .................................................... Error! Bookmark not defined. G.3.1 Nuclear Heat Rate ........................................................ Error! Bookmark not defined. G.3.2 Performance Factor ...................................................... Error! Bookmark not defined. G.3.3 Fuel Cost ...................................................................... Error! Bookmark not defined.

G.3.3.1 Basic Nuclear Fuel Cost......................................... Error! Bookmark not defined. G.3.3.2 Total Fuel-Related Costs for Nuclear Units........... Error! Bookmark not defined.

G.3.4 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.3.4.1 Hot Start Cost ......................................................... Error! Bookmark not defined. G.3.4.2 Intermediate Start Cost .......................................... Error! Bookmark not defined. G.3.4.3 Cold Start Cost ....................................................... Error! Bookmark not defined. G.3.4.4 Additional Components Applied to Hot, Intermediate and Cold Start-Up CostsError! Bookmark not defined.

G.3.5 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.3.6 VOM Cost .................................................................... Error! Bookmark not defined.

G.3.6.1 Configuration Addition VOM Cost ....................... Error! Bookmark not defined. G.3.6.2 Calculation of the Configuration Addition VOM Cost:Error! Bookmark not defined. G.3.6.3 Reductions in Total VOM Costs: ........................... Error! Bookmark not defined.

G.3.7 Mitigated Spinning Reserve Offer ............................... Error! Bookmark not defined. G.3.8 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.3.9 Mitigated Regulation Offers ........................................ Error! Bookmark not defined.

G.4 Fossil Steam Unit Guidelines............................................. Error! Bookmark not defined. G.4.1 Heat Rate ...................................................................... Error! Bookmark not defined. G.4.2 Performance Factor ...................................................... Error! Bookmark not defined. G.4.3 Fuel Cost ...................................................................... Error! Bookmark not defined. G.4.4 Hot Start Cost, Intermediate Start Cost, and Cold Start costError! Bookmark not defined.

G.4.4.1 Hot Start Cost ......................................................... Error! Bookmark not defined.

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G.4.4.2 Intermediate Start Cost .......................................... Error! Bookmark not defined. G.4.4.3 Cold Start Cost ....................................................... Error! Bookmark not defined.

G.4.5 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.4.6 VOM Cost .................................................................... Error! Bookmark not defined.

G.4.6.1 Configuration Addition VOM Cost ....................... Error! Bookmark not defined. G.4.6.2 Calculation of the Configuration Addition VOM CostError! Bookmark not defined. G.4.6.3 Reductions in Total VOM Costs ............................ Error! Bookmark not defined.

G.4.7 Mitigated Spinning Reserve Offer ............................... Error! Bookmark not defined. G.4.8 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.4.9 Regulation .................................................................... Error! Bookmark not defined.

G.5 Combined Cycle (CC) Guidelines ..................................... Error! Bookmark not defined. G.5.1 Heat Rate ...................................................................... Error! Bookmark not defined. G.5.2 Performance Factors .................................................... Error! Bookmark not defined. G.5.3 Fuel Cost ...................................................................... Error! Bookmark not defined. G.5.4 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.5.5 Mitigated Transition State Offer .................................. Error! Bookmark not defined. G.5.6 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.5.7 VOM Cost .................................................................... Error! Bookmark not defined. G.5.8 Mitigated Spinning Reserve Offer ............................... Error! Bookmark not defined. G.5.9 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.5.10 Mitigated Regulation Offers ........................................ Error! Bookmark not defined.

G.6 Combustion Turbine (CT) and Reciprocating Engine GuidelinesError! Bookmark not defined. G.6.1 Combustion Turbine and Reciprocating Engine Heat RateError! Bookmark not defined. G.6.2 Performance Factor ...................................................... Error! Bookmark not defined. G.6.3 Fuel Cost ...................................................................... Error! Bookmark not defined.

G.6.3.1 Combustion Turbine other Fuel-Related Costs...... Error! Bookmark not defined. G.6.4 Energy Offer Curve for Quick Start ............................. Error! Bookmark not defined. G.6.5 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.6.6 Mitigated No-Load Offer for CTs ................................ Error! Bookmark not defined. G.6.7 VOM Cost .................................................................... Error! Bookmark not defined. G.6.8 Mitigated Spinning Reserve Offer ............................... Error! Bookmark not defined.

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G.6.9 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.6.10 Mitigated Regulation Offers ........................................ Error! Bookmark not defined.

G.7 Hydro Guidelines ............................................................... Error! Bookmark not defined. G.7.1 Pumping Efficiency (Pumped Hydro Only) ................ Error! Bookmark not defined. G.7.2 Performance Factors .................................................... Error! Bookmark not defined. G.7.3 Fuel Cost ...................................................................... Error! Bookmark not defined.

G.7.3.1 Total Energy Input Related Costs for Pumped Storage Hydro Plant GenerationError! Bookmark not defined. G.7.4 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.7.5 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.7.6 VOM Cost .................................................................... Error! Bookmark not defined. G.7.7 Spinning Reserve: Hydro Unit Costs ........................... Error! Bookmark not defined. G.7.8 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.7.9 Mitigated Regulation Offers ........................................ Error! Bookmark not defined.

G.8 Demand Response Guidelines ........................................... Error! Bookmark not defined. G.8.1 Demand Response Resource (DRR) Cost for Behind the Meter GenerationError! Bookmark not defined. G.8.2 DRR Cost for Demand Reduction ............................... Error! Bookmark not defined. G.8.3 DRR Start-Up Cost ...................................................... Error! Bookmark not defined. G.8.4 DRR Cost to Provide Spinning and/or Supplemental ReservesError! Bookmark not defined. G.8.5 DRR Cost to Provide Regulation ................................. Error! Bookmark not defined.

G.9 Wind Guidelines ................................................................ Error! Bookmark not defined. G.9.1 Fuel Cost ...................................................................... Error! Bookmark not defined. G.9.2 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.9.3 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.9.4 VOM ............................................................................ Error! Bookmark not defined.

G.10 Solar Guidelines ................................................................. Error! Bookmark not defined. G.10.1 Fuel Cost ...................................................................... Error! Bookmark not defined. G.10.2 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.10.3 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.10.4 VOM ............................................................................ Error! Bookmark not defined.

G.11 Electric Storage Resource Guidelines ................................ Error! Bookmark not defined. G.11.1 Electric Storage Resource Loss Factor ........................ Error! Bookmark not defined.

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G.11.2 Performance Factor ...................................................... Error! Bookmark not defined. G.11.3 Fuel Cost ...................................................................... Error! Bookmark not defined.

G.11.3.1 Total Energy Input-Related Costs for Electric Storage Resource GenerationError! Bookmark not defined. G.11.4 Mitigated Start-Up Offer.............................................. Error! Bookmark not defined. G.11.5 Mitigated No-Load Offer ............................................. Error! Bookmark not defined. G.11.6 VOM Cost .................................................................... Error! Bookmark not defined. G.11.7 Mitigated Spinning Reserve Offer ............................... Error! Bookmark not defined. G.11.8 Mitigated Supplemental Reserve Offer ....................... Error! Bookmark not defined. G.11.9 Mitigated Regulation Offer .......................................... Error! Bookmark not defined.

G.12 Energy Market Opportunity Cost Guidelines .................... Error! Bookmark not defined. G.12.1 Basis for Opportunity Cost to be Included in Mitigated OffersError! Bookmark not defined.

G.12.1.1 Environmental Run-hour Restriction ..................... Error! Bookmark not defined. G.12.1.2 Physical Equipment Limitations ............................ Error! Bookmark not defined. G.12.1.3 Non-Regulatory Opportunity Cost: Fuel LimitationsError! Bookmark not defined.

G.12.2 Calculation Method ...................................................... Error! Bookmark not defined. G.12.2.1 Overview of the Opportunity Cost Calculation ..... Error! Bookmark not defined. G.12.2.2 Daily Opportunity Cost Calculation ...................... Error! Bookmark not defined.

G.12.2.2.1 Step 1: Forecast Hourly Resource LMPs ......... Error! Bookmark not defined. G.12.2.2.2 Step 2: Calculate the price-cost margin for each hour of the dayError! Bookmark not defined. G.12.2.2.3 Step 3: Determine the Opportunity Cost ComponentError! Bookmark not defined.

G.12.2.3 Long Term Opportunity Cost Calculation ............. Error! Bookmark not defined. G.12.2.3.1 Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPsError! Bookmark not defined. G.12.2.3.2 Step 2: Derive Historical Monthly LMP Basis Differential between the

Resource Settlement Location and the SPP Real-Time Marginal Energy Component of LMP ......................................... Error! Bookmark not defined.

G.12.2.3.3 Step 3: Derive hourly volatility scalars to incorporate hourly volatility into the LMP forecast .................................................... Error! Bookmark not defined.

G.12.2.3.4 Step 4: Create three sets of hourly forecasted Resource Settlement Location values ............................................................... Error! Bookmark not defined.

G.12.2.3.5 Step 5: Create a daily fuel volatility scalar ...... Error! Bookmark not defined. G.12.2.3.6 Step 6: Create three daily delivered fuel forecastsError! Bookmark not defined. G.12.2.3.7 Step 7: Create Resource(s) cost for each of the three forecastsError! Bookmark not defined.

of 156

G.12.2.3.8 Step 8: Calculate the margin for every hour in the three hourly forecastsError! Bookmark not defined. G.12.2.3.9 Step 9: Determine the opportunity cost componentError! Bookmark not defined.

G.12.2.4 Short Term Opportunity Cost Calculation ............. Error! Bookmark not defined. G.12.2.4.1 Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPsError! Bookmark not defined. G.12.2.4.2 Step 2: Derive Historical Monthly LMP Basis Differential between the

Resource Settlement Location and the SPP Real Time Marginal Energy Component of LMP ......................................... Error! Bookmark not defined.

G.12.2.4.3 Step 3: Derive hourly volatility scalars to incorporate hourly volatility into the LMP forecast .................................................... Error! Bookmark not defined.

G.12.2.4.4 Step 4: Create three sets of hourly forecasted Resource LMPsError! Bookmark not defined. G.12.2.4.5 Step 5: Fuel Price ............................................. Error! Bookmark not defined. G.12.2.4.6 Step 6: Create generating unit’s cost for each of the three forecastsError! Bookmark not defined. G.12.2.4.7 Step 7: Calculate the margin for every hour in the three hourly forecastsError! Bookmark not defined. G.12.2.4.8 Step 8: Determine the opportunity cost ........... Error! Bookmark not defined.

G.13 No-Load Calculation Examples ......................................... Error! Bookmark not defined. G.13.1 No-Load Fuel ............................................................... Error! Bookmark not defined.

G.13.1.1 Typical Steam Unit Example ................................. Error! Bookmark not defined. G.13.1.2 Typical Combustion Turbine Example .................. Error! Bookmark not defined.

G.13.2 No-Load Cost Adjustments.......................................... Error! Bookmark not defined. G.13.2.1 Combustion Turbine Zero No-Load Example ....... Error! Bookmark not defined.

REVISION HISTORY ................................................................ Error! Bookmark not defined. 4.2.2.6 Virtual Energy Offers Virtual Energy Offers are supported in the DA Market only. Virtual Energy Offers are purely

financial, only apply to Energy and are not associated with a physical Resource asset. The

following rules apply to Virtual Energy Offer submittal.

(1) A Virtual Energy Offer can be submitted by a Market Participant at any Settlement

Location;

(2) A Market Participant may submit a single Virtual Energy Offer for each Asset Owner at

any Settlement Location for a particular Hour in the form of a Virtual Energy Offer

Curve (MW, $/MWh, up to ten (10) price/quantity pairs and slope or block option). The

submitted MW values must be increasing and the submitted $/MWh values must be

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monotonically non-decreasing. A Virtual Energy Offer will clear when the price at the

applicable Settlement Location is greater than or equal to the specified curve price for

that Operating Hour. The highest MW quantity submitted in the Virtual Energy Offer

Curve representing the maximum MW amount that can be cleared. The minimum MW

amount that can be cleared is equal to zero;

(a) Block and slope pairs may not coexist. The Resource Offer in effect for any

given period of time must be comprised of all block or all slope price/quantity

pairs.

(b) If the LMP is less than the lowest $/MWh submitted in the curve, then the cleared

MWs will be zero.

(c) Under the slope option, the set of price points that are submitted are used as the

beginning and ending values for calculating a linear slope for each set of

beginning and ending values. Therefore, each MW between the two price points

has a different price due to the interpolation of the submitted price points. Under

the block option, each MW between the two MW points is offered at the price of

the larger MW point. Exhibit 4-9 illustrates Virtual Energy Offer curves

developed from submitted price/MWh pairs for both the slope and block options.

Exhibit 4-1: Virtual Energy Offer Curve Development

(3) Each Virtual Energy Offer must specify a start and stop Hour within the applicable

Operating Day;

MW $/MWh100 20.00200 40.00400 60.00500 80.00

Submitted Data

Slope Option

Block Option

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

0 100 200 300 400 500 600

$/M

Wh

MW

Virtual Energy Offer Curve

Slope Option

Block Option

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(4) Virtual Energy Offers may be submitted up to $2,000/MWh and are not subject to cost

verification.

4.2.3.2 Virtual Energy Bids Virtual Energy Bids are supported in the DA Market only. Virtual Energy Bids are purely

financial in nature, only apply to Energy and are not associated with a physical Load asset. The

follow rules apply to Virtual Energy Bid submittal.

(1) A Virtual Energy Bid can be submitted at any Settlement Location;

(2) A Market Participant may submit a single Virtual Energy Bid for each Asset Owner at

any Settlement Location for a particular Hour in the form of a Virtual Energy Bid Curve

(MW, $/MWh, up to 10 price/quantity pairs and slope or block option). The submitted

MW values must be increasing and the submitted $/MWh values must be monotonically

non-increasing. A Virtual Energy Bid will clear when the price at the applicable

Settlement Location is less than or equal to the specified curve price for that Operating

Hour. The maximum MW amount that can be cleared is equal to the highest MW

quantity submitted in the Virtual Energy Bid Curve. The minimum MW amount that can

be cleared is equal to zero. The price of all MWhs below the lowest MW amount

submitted is equal to the first pricing point price;

(a) Block and slope pairs may not coexist. The Resource Offer in effect for any

given period of time must be comprised of all block or all slope price/quantity

pairs.

(b) If the LMP is greater than the highest $/MWh submitted in the curve, then the

cleared MWs will be zero.

(c) Under the slope option, the set of price points that are submitted are used as the

beginning and ending values for calculating a linear slope for each set of

beginning and ending values. Therefore, each MW between the two price points

has a different price due to the interpolation of the submitted price points. Under

the block option, each MW between the two MW points is offered at the price of

the larger MW point. Exhibit 4-11 illustrates Virtual Energy Bid Curves

developed from submitted price/MWh pairs for both the slope and block options.

Deleted: <#>Virtual Energy Offers are subject to a transaction fee as described under Section 4.5.8.20.¶

Commented [RR229.1]: Awaiting FERC and System Implementation

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Exhibit 4-1: Virtual Energy Bid Curve Development

(3) Each Virtual Energy Bid must specify a start and stop Hour within the applicable

Operating Day;

(4) Virtual Energy Bids may be submitted up to $2,000/MWh and are not subject to cost

verification.

4.5 Post Operating Day and Settlement Activities Post Operating Day activities begin on the day immediately following the Operating Day. SPP

Settlement Statement process is outlined in Section 4.5.13. Settlement Statements will be

configurable by Market Participants to show hourly net amounts or to show that Market

Participant’s hourly and sub-hourly billing quantities at each Settlement Location to be paid or

credited resulting from the DA Market and RTBM settlements. All charge types and billing

determinants defined under Sections 4.5.8, 4.5.9, 4.5.100, 4.5.11, and 4.5.12 are available on the

Settlement Statement and Settlement Determinant Report unless specifically excluded as

identified in the table definitions under each charge type. Settlement Invoices are issued on

weekly basis.

Metering standards associated with submittal of actual load and Resource Energy quantities are

specified in Appendix C and settlement data reporting processes are specified in Appendix D to

these Market Protocols. Detailed explanations of all DA Market and RTBM charges types, along

with example calculations, are contained within Appendix F to these Market Protocols.

MW $/MWh50 120.00

100 100.00200 80.00400 60.00500 40.00550 20.00

Submitted Data

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

0 100 200 300 400 500 600

$/M

Wh

MW

Virtual Energy Bid Curve

Slope Option

Block Option

Deleted: <#>Virtual Energy Bids are subject to a transaction fee as described under Section 4.5.8.20.;¶

Commented [RR229.2]: Awaiting FERC and System Implementation

Deleted: SPP issues initial settlement statements for each Operating Day on the 7th day following the Operating Day and final settlement statements on the 47th day following the Operating Day.

Commented [RR259.3]: Awaiting FERC and Implementation

Deleted: s


Deleted: 4.5.8.21

Deleted: , 4.5.9.24


of 156

Exhibit 4-19 provides a representative overall timeline of Post Operating Day activities.

…

4.5.8 Day-Ahead Market Settlement Settlement calculations for Energy and Operating Reserve in the DA Market are performed on an

hourly basis for each Operating Day and are based upon the results of the DA Market clearing

for that Operating Day.

(1) Each Market Participant with cleared Offers is paid for each Settlement Location:

(a) For the amount of physical Energy sold, net of Bilateral Settlement Schedules for

Energy, at the associated LMP (see Sections 4.5.8.1 and 4.5.8.2);

(b) For the amount of virtual Energy sold at the associated LMP (see Section 4.5.8.3);

(c) For the amount of Regulation-Up Service sold at the associated Regulation-Up

Service MCP (see Section 4.5.8.4);

(d) For the amount of Regulation-Down Service sold at the associated Regulation-

Down Service MCP (see Section 4.5.8.5);

(e) For the amount of Spinning Reserve sold at the associated Spinning Reserve MCP

(see Section 4.5.8.6); and

(f) For the amount of Supplemental Reserve sold at the associated Supplemental

Reserve MCP (see Section 4.5.8.7).

(2) Each Market Participant with cleared Bids is charged for each Settlement

Location:

(a) For the amount of physical Energy purchased, net of Bilateral Settlement

Schedules for Energy, at the associated LMP (see Sections 4.5.8.1 and 4.5.8.2);

and

(b) For the amount of virtual Energy purchased at the associated LMP (see Section

4.5.8.3).

(3) Charges to Market Participants for Operating Reserve procured in the DA Market are

calculated on a Reserve Zone basis by multiplying the Reserve Zone Operating Reserve

procurement rate by each Asset Owner’s DA Market Operating Reserve Reserve Zone

Obligation. See Sections 4.5.8.8, 4.5.8.9, 4.5.8.10, and 4.5.8.11 for additional details;

Deleted: s

Deleted: and 4.5.8.20

Deleted: s

Deleted: and 4.5.8.20

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(a) The procurement rate within a Reserve Zone for each Operating Reserve product

is equal to the DA Market Operating Reserve product procurement costs to meet

the Reserve Zone DA Market Operating Reserve product obligation divided by

the DA Market Reserve Zone Operating Reserve obligation.

(b) For Reserve Zones where Operating Reserve procured is more than the entire

obligation in the zone, the DA Market Operating Reserve procurement cost is

equal to the clearing price for DA Market Operating Reserve for that zone,

multiplied by the zone obligation. For Reserve Zones where Operating Reserve

procured is less than the entire obligation in the zone, the DA Market Operating

Reserve procurement cost is the weighted average of (1) the clearing price for DA

Market Operating Reserve for that zone and (2) the average clearing price for the

DA Market Operating Reserve procured and imported from other zones,

multiplied by the zone obligation.

(4) Market Participants of SPP committed Resources in the DA Market will also receive a

Make Whole Payment if the total revenues received for Energy and Operating Reserve

sales in the DA Market settlement are less than the Resource’s Offer costs associated

with those sales. Make Whole Payments are calculated on a commitment period basis

and are collected on a daily basis from Asset Owners based upon their pro-rata share of

the sum of all Demand Bids, Export Interchange Transaction Bids and Virtual Energy

Bids cleared in the Day-Ahead Market for the Operating Day. See Sections 4.5.8.12, and

4.5.8.13 for additional details;

(5) Settlements related to congestion management are also performed as part of the Day-

Ahead Market settlement as follows;

(a) Holders of TCRs are paid (or charged) for the amount of TCRs held between a

particular source and sink at the difference between the sink MCC and the source

MCC. See Section 4.5.8.14 for additional details.

(b) To the extent that there are insufficient congestion revenues collected in an

Operating Day to fully fund TCR holders, TCR holders are charged a pro-rata

uplift amount to cover the under collection based upon each TCR holder’s net

charges or credits for the Operating Day. If there is excess congestion revenues

collected in an Operating Day, the excess is carried for use at the end of the

month. See Section 4.5.8.15 for additional details.

(c) At the end of each month, if there are excess congestion revenues available, these

revenues are used to reimburse TCR holders that received an uplift charge for

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Operating Days during that month. Each TCR holder is reimbursed a pro-rata

share of the uplift charges paid based upon the level of uplift charges paid until

they are fully reimbursed or the excess congestion revenues are depleted. To the

extent that there are excess congestion revenues remaining after fully reimbursing

TCR holders, this excess is carried forward for use at the end of the year. See

Section 4.5.8.16 for additional details.

(d) At the end of each year, if there are excess congestion revenues available, these

revenues are used to reimburse TCR holders that received an uplift charge for

Operating Days during that year that were not fully reimbursed. Each TCR holder

is reimbursed a pro-rata share of the remaining uplift charges paid based upon the

level of remaining uplift charges paid until they are fully reimbursed or the excess

congestion revenues are depleted. See Section 4.5.8.17 for additional details.

(e) To the extent that there are excess congestion revenues remaining at the end of the

year after fully reimbursing TCR holders, this excess is distributed back to ARR

holders pro-rata based upon their annual ARR Nomination Caps. See Section

4.5.8.18 for additional details.

(6) Settlement associated with revenue over collection due to the impact of marginal losses

on the DA Market LMPs is performed as desrcibe under Section 4.5.9.20.

(7) Demand reduction credits to Market Participants associated with a load Settlement

Location that contains a Demand Response Resource are calculated as part of the Day-

Ahead Market settlement in order to ensure that, on a net settlement basis, the charge

associated with that load Settlement Location is reflective of the net load (i.e. the load

including the impact of a cleared Demand Response Resource).

For example, consider a load Settlement Location that consists of a single PNode and that

PNode also represents a Demand Response Load that is associated with a Dispatchable

Demand Response (DDR) Resource. The Market Participant for the load Settlement

Location submits a fixed Demand Bid of 100 MW, which is reflective of that location’s

actual load consumption in real-time, assuming that there is No-Load reduction (i.e. this

value represents the baseline value for the DRL that will be submitted for use in real-

time). The Market Participant for the DDR Resource submits a Resource Offer that

results in the DDR clearing for 20 MWs of Energy. Therefore, the net load consumption

at the load Settlement Location is actually 80 MWs and the load settlement amount needs

to reflect that. If we assume that LMP is $50/MWh, the net settlement at the load

Settlement Location would be:

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Energy Charge: 100 MW * $50/MWh= $5000

Demand Reduction Credit = -20 MW * $50/MWh = ($1000)

Net Load Settlement Location Settlement = $4000

The net $4000 charge is the same as the charge that would have been calculated using the

net load of 80 MW multiplied by the $50/MWh LMP. However, in order to ensure

proper deviation accounting in real-time, the 100 MW of cleared load and the 20 MW of

cleared DDR output is used to calculate real-time deviations from cleared Day-Ahead

Market amounts. See Section 4.5.8.20 for additional calculation details.

(8) Charges to Market Participants for recovery of Day-Ahead Market demand reduction

credits are calculated on a system-wide basis by multiplying the demand reduction charge

rate by each Market Participant’s Day-Ahead Market demand reduction obligation. See

Sections 4.5.8.21 for additional details;

(a) The demand reduction charge rate is equal to the total amount of demand

reduction credits paid to load divided by the system-wide total cleared

withdrawals (Demand Bids, Virtual Bids and Export Interchange Transaction

Bids).

(b) Each Market Participant’s demand reduction obligation is equal to that Market

Participant’s total cleared withdrawals (Demand Bids, Virtual Bids and Export

Interchange Transaction Bids).

The following subsections describe the DA Market settlement charge types. For each charge

type, the calculation is performed at the hourly level for each Asset Owner at each Settlement

Location. In addition to the hourly values, daily values will be accessible on the Settlement

Statement for all charge types.

4.5.8.20 Day-Ahead Demand Reduction Amount

Deleted: 1

Deleted: 2

Deleted: ¶¶¶

4.5.8.20 Day-Ahead Virtual Energy Transaction Fee Amount¶

Deleted: <#>A DA Market credit1 or charge for each hour of the Operating Day in which a Virtual Energy Offer and Virtual Energy Bid is submitted as of the close of the Day-Ahead Market will be calculated for each Asset Owner for each Operating Day. Charges collected by SPP under this charge type are used by SPP to reduce the SPP budgeted expenses used to calculate the rate specified under Schedule 1-A of the SPP Tariff. The amount is calculated as follows:¶

#DaVTxnFeeAoAmt a, m, d = DaVTxnDlyCnt a, d * DaVTxnFeeDlyRate d¶

<#> For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net daily charge or credit is calculated as follows:¶

DaVTxnFeeMpAmt m, d =

Deleted: ∑a

Deleted: DaVTxnFeeAoAmt a, m, d¶¶

¶¶¶The above variables are defined as follows:¶

Variable¶ ...Deleted: 1

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4.5.8.21 Day-Ahead Demand Reduction Distribution Amount …

The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

DaDRDistHrlyAmt a, s, h $ Hour Day-Ahead Demand Reduction Distribution Amount per AO per Hour - The amount to AO a for AO a’s share of DA Market Demand Reduction costs per Settlement Location per Hour.

DaDRLoadHrlyQty a, s, h MWh Hour Day-Ahead Demand Reduction Load per AO per Settlement Location for Hour h – Asset Owner a’s load, virtual withdrawal and Export Interchange Transactions cleared in the DA Market at Settlement Location s for Hour h for use in Demand Reduction cost allocation.

DaDRDistHrlyRate h $/MWh Hour Day-Ahead Demand Reduction Distribution Rate per Hour – The rate applied to AO a’s Demand Reduction load in Hour h.

DaDRDistHrlyCost h $ Hour Day-Ahead Demand Reduction Distribution Cost per Hour – The cost of Demand Reduction in Hour h.

DaDRDistHrlyQty h MWh Hour Day-Ahead Demand Reduction Distribution Quantity per Hour – The total cost allocation quantity for Demand Reduction in Hour h.

DaDRHrlyAmt a, s, h $ Hour Day-Ahead Demand Reduction Amount per AO per Settlement Location per Hour - The value described under Section 4.5.8.20.

DaClrdHrlyQty a, s, h MWh Dispatch Interval

Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1 for AO a at Settlement Location s for Hour h.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3.

DaImpExp5minQty a, s, i, t MWh Dispatch Interval

Day-Ahead Interchange Transaction Quantity per AO per Transaction per Settlement Location per Dispatch Interval – The value described under Section 4.5.8.2.

Deleted: 2

Deleted: 1

of 156

Variable

Unit

Settlement Interval

Definition

DaDRDistAoAmt a, m, d $

Operating Day

Day-Ahead Demand Reduction Distribution Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for Demand Reduction for the Operating Day.

DaDRDistMpAmt m, d $

Operating Day

Day-Ahead Demand Reduction Distribution Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for Demand Reduction for the Operating Day.

DaDRDistDlyAmt a, s, d $ Operating Day

Day-Ahead Demand Reduction Distribution Amount per Settlement Location per Operating Day - The DA Market amount to Settlement Location s associated with AO a for Demand Reduction for the Operating Day.

a none none An Asset Owner.

s none none A Settlement Location.

h none none An Hour.

d none none An Operating Day.

m none none A Market Participant.

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4.5.8.22 Day-Ahead Grandfathered Agreement Carve-Out Daily Amount …

Deleted: 3

of 156

4.5.8.23 Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount … The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

DaGFAAoMnthlyAmt a, m, mn $

Month Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount per AO per Month– The net reversal of charges and credits from the settlement of Transmission Congestion Rights Monthly Payback & Auction Revenue Rights Monthly Payback to AO a modeled to represent a Grandfathered Agreement Carve-Outs and FSEs associated with Market Participant m for the Month

TcrPaybackMnthlyAmt a, m, mn $

Month Transmission Congestion Right Monthly Payback Amount per AO per Asset Owner per MP per Month – The amount calculated under Section 4.5.8.16.

ArrPaybackMnthlyAmt a, m, mn $

Month Auction Revenue Rights Monthly Payback Amount per AO per month - The amount calculated under Section 4.5.10.4.

AoIsGFAMnthlyFlg a, m, mn none Month Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Month – A Flag which indicates that the AO is exempt from Day-Ahead Transmission Congestion charge types, thus forcing the cost allocation of the exclusion into Non GFA Load Ratio Share

AoIsGFADlyFlg a, m, d none Month Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Day – The flag described under Section 4.5.8.22

DaGFAMpMnthlyAmt m, mn $

Month Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount per MP per Month – The net reversal of charges and credits from the settlement of Monthly Transmission Congestion Rights Paybacks & Monthly Auction Revenue Rights Paybacks to MP m modeled to represent a Grandfathered Agreement Carve-Out or FSE for the Month.



Deleted: 4

Deleted: 3

of 156

Variable

Unit

Settlement Interval

Definition

mn none none A Month.


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4.5.8.24 Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount …


Variable

Unit

Settlement Interval

Definition

DaGFAAoYrlyAmt a, m, yr $

Year Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount per AO per Year– The net reversal of charges and credits from the settlement of Transmission Congestion Rights Yearly Payback & Closeout, and Auction Revenue Rights Yearly Payback & Closeout to AO a modeled to represent a Grandfathered Agreement Carve-Out or FSE associated with Market Participant m for the Year

TcrPaybackYrlyAmt a, m, yr $

Year Transmission Congestion Rights Annual Payback Amount per AO - The amount calculated under Section 4.5.8.17.

TcrCloseoutYrlyAmt a, m, yr $ Year Transmission Congestion Rights Annual Payback Amount per AO – The amount calculated under Section 4.5.8.18.

ArrPaybackYrlyAmt a, m, yr $

Year Auction Revenue Rights Annual Payback Amount per AO per year - The amount calculated under Section 4.5.10.5.

ArrCloseoutYrlyAmt a, m, yr $ Year Auction Revenue Rights Annual Payback Amount per AO per Year - The amount calculated under Section 4.5.10.6.

AoIsGFAYrlyFlg a, m, yr none Year Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Year – A Flag which indicates that the AO is exempt from Day-Ahead Transmission Congestion charge types, thus forcing the cost allocation of the exclusion into Non GFA Load Ratio Share

AoIsGFADlyFlg a, m, d none Day Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Day – The flag described under Section 4.5.8.22

Deleted: 5

Deleted: 3

of 156

Variable

Unit

Settlement Interval

Definition

DaGFAMpYrlyAmt m, yr $

Year Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount per MP per Year – The net reversal of charges and credits from the settlement of Yearly Transmission Congestion Rights Paybacks & Closeouts, and Yearly Auction Revenue Rights Paybacks & Closeouts to MP m modeled to represent a Grandfather Agreement Carve-Out and FSE for the Year.


mn none none A Month

yr none none A Year.


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4.5.8.25 GFA Carve Out Distribution Daily Amount … The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

RtLoadMtr5minQty a, s, i MW Dispatch Interval

Real-Time Load Meter Quantity per Asset Owner per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Settlement Location s.

RtImpExp5minQty a, s, i, t MW Dispatch Interval

Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 for Reserve Zone z.

AoIsGFALoadDlyFlg a, s, d, t Operating Day

Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Operating Day – A Flag which indicates that the AO is exempt from the distribution of the GFA Carve Out Account

DaEnFinHrlyQty a, s, h, t MWh

Hour Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Asset Settlement Location s, for each transaction t, for the Hour. The buyer AO quantity is a positive value and the seller AO quantity is a negative value.

DaNEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Non-Asset Energy Bilateral Settlement Schedule for Energy per Transaction per AO per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Non-Asset Settlement Location s, for each transaction t, for the Hour. The buyer AO quantity is a positive value and the seller AO quantity is a negative value.

DaGFACarveOutDistDlyAmt a, s, d $ Operating Day

Day Ahead GFA Carve Out Distribution Daily Amount per AO per Settlement Location per Operating Day – The amount to distribute to AO a at Settlement Location s in an Operating Day d.

Deleted: 6

Deleted: RtBillMtr5minQty a, s, i

Deleted: MW

Deleted: Dispatch Interval

Deleted: Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Reserve Zone z.



of 156

Variable

Unit

Settlement Interval

Definition

DaGFACarveOutDistAoDlyAmt a, m, d $ Operating Day

Day Ahead GFA Carve Out Distribution Amount per AO per Operating Day – The amount to distribute to AO a associated with Market Participant m in an Operating Day d.

DaGFACarveOutDistMpDlyAmt m, d $ Operating Day

Day Ahead GFA Carve Out Distribution Daily Amount per MP per Operating Day – The amount for to distribute to MP m in an Operating Day d.

GFARevInadqcSppDlyAmt spp, d $ Operating Day

Grandfathered Agreement Carve-Out Revenue Inadequacy Daily Amount – The amount of charges and credits to GFA Carve-Out responsible entities and Western-UGP on an SPP-wide basis from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead Over-Collected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day.

RtNonGFAHrlyQty a, s, h Hour Real-Time Non-GFA Hourly Quantity per AO per Hour per Settlement Location – The value is calculated by taking the Load’s Real-Time Meter plus the Load’s Exports minus the GFA Carved Out Load MWs minus the FSE Load MWs per AO a at Settlement Location s in hour h

RtGFALoadRatioShareDlyFct a, s, d Operating Day

Real-Time GFA Load Ratio Share Daily Factor per AO per Hour per Settlement Location – The value is calculated by taking a single Asset Owner Load Settlement Location’s Real-Time GFA Exclusion Hourly Factor and divided it by the sum of all of the Asset Owner Load Settlement Location’s Real-Time GFA Exclusion Hourly Factor.

DaGFAMpAmt m, d $ Operating Day

Day-Ahead Grandfathered Agreement Carve-Out Amount per MP per Day - The value calculated under Section 4.5.8.22

a none None An Asset Owner.

s none none A Resource Settlement Location.




Deleted: 3

of 156

Variable

Unit

Settlement Interval

Definition


spp none none Southwest Power Pool.

of 156

4.5.8.26 GFA Carve Out Distribution Monthly Amount … The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

DaGFACarveOutDistMnthlyAmt a, s,

mn $ Month Day Ahead GFA Carve Out Distribution Monthly Amount per AO per

Settlement Location per Month – The amount to distribute to AO a at Settlement Location s in Month mn.

RtGFALoadRatioShareMnthlyFct a, s,

mn $/MW Month Real-Time GFA Share Load Ratio Share Distribution Factor per AO

per Month per Settlement Location – The ratio determining the portion of the total Grandfathered Agreement Carve-Out Revenue Inadequacy Monthly Amount assigned to AO a at Settlement Location s in Month mn.

DaGFACarveOutDistAoMnthlyAmt

a, m, mn $ Month Day Ahead GFA Carve Out Distribution Amount per AO per Month –

The amount to distribute to AO a associated with Market Participant m in Month mn.

DaGFACarveOutDistMpMnthlyAmt

m, mn $ Month Day Ahead GFA Carve Out Distribution Monthly Amount per MP per

Month – The amount for to distribute to MP m in Month mn.

GFARevInadqcSppMnthlyAmt spp, mn $ Month Grandfathered Agreement Carve-Out Revenue Inadequacy Monthly Amount – The amount of charges and credits to GFA Carve-Out responsible entities and Western-UGP on an SPP-wide basis from the settlement of Transmission Congestion Rights Payback Amount and Auction Revenue Rights Payback Amount for Month mn.

RtGFALoadRatioShareDlyFct a, s, d MW Hour Real-Time GFA Load Ratio Share per AO per Day per Settlement Location – The value calculated under Section 4.5.8.25

DaGFAMpMnthlyAmt m, mn $ Month Day-Ahead Grandfathered Agreement Carve-Out Amount per MP per Month - The value calculated under Section 4.5.8.23




Deleted: 7

Deleted: 6

Deleted: 4

of 156

Variable

Unit

Settlement Interval

Definition




spp none none Southwest Power Pool.

of 156

4.5.8.27 GFA Carve Out Distribution Yearly Amount … The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

DaGFACarveOutDistYrlyAmt a, s, yr $ Year Day Ahead GFA Carve Out Distribution Yearly Amount per AO per Settlement Location per Yearly – The amount to distribute to AO a at Settlement Location s in Year yr.

RtGFALoadRatioShareYrlyFct a, s,

yr none Year Real-Time GFA Load Ratio Share Factor per AO per Year per

Settlement Location – The ratio determining the portion of the total Grandfathered Agreement Carve-Out Revenue Inadequacy Yearly Amount assigned to AO a at Settlement Location s in Year yr.

DaGFACarveOutDistAoYrlyAmt a,

m, yr $ Year Day Ahead GFA Carve Out Distribution Amount per AO per Year –

The amount to distribute to AO a associated with Market Participant m in Year yr.

GFARevInadqcSppYrlyAmt spp, yr $ Year Grandfathered Agreement Carve-Out Revenue Inadequacy Yearly Amount – The amount of charges and credits to GFA Carve-Out responsible entities and Western-UGP on an SPP-wide basis from the settlement of Transmission Congestion Rights Payback Amount, Transmission Congestion Rights Closeout Amount, Auction Revenue Rights Payback Amount and Auction Revenue Rights Closeout Amount for Year yr.

RtGFALoadRatioShareDlyFct a, s, h MW Hour Real-Time GFA Load Ratio Share per AO per Day per Settlement Location – The value calculated under Section 4.5.8.25

DaGFAMpYrlyAmt m, yr $ Year Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount per MP per Year - The value calculated under Section 4.5.8.24





Deleted: 8

Deleted: 6

Deleted: 5

of 156

Variable

Unit

Settlement Interval

Definition


yr none none A Year


Spp none none Southwest Power Pool.

of 156

4.5.8.28 Day-Ahead Combined Interest Resource Adjustment Amount …

4.5.9 Real-Time Balancing Market Settlement Settlement calculations for the Real-Time Balancing Market are performed on a Dispatch

Interval basis for each Operating Day and are based upon the difference between the results of

the RTBM process and the DA Market clearing for that Operating Day. To calculate RTBM

actual Energy in a Dispatch Interval for Asset Owners that have not directly submitted 5-minute

interval meter data, SPP allocates the submitted hourly meter data for Resources and loads into

5-minute values using 5-minute telemetered or State Estimator profiles for the corresponding

hour. The profiling of the hourly meter data maintains the shape of the 5-minute telemetered or

State Estimator values even if there are both positive and negative values contained within the 12

intervals. All Dispatch Interval values are expressed in MW, not MWh. Exhibit 4-23 shows an

example of how the profiling will work for a Resource that submits an actual hourly meter

amount of -80 MWh.

Exhibit 4-1: Meter Profiling Example

Interval (1) State Estimator

MW

(2) Absolute Value of

Column (1)

(3) Normalize Column (2)

[Col (2) MW / Total Col (2)

MW]

(4) Profiled Hourly

Meter (-80 – (-66.25)) * 12 * Col (3) + Col

(1) 1 10 10 0.012 8 2 5 5 0.006 4 3 0 0 0.000 0 4 -50 50 0.061 -60 5 -60 60 0.073 -72 6 -70 70 0.085 -84 7 -80 80 0.097 -96 8 -90 90 0.109 -108 9 -100 100 0.121 -120

10 -110 110 0.133 -132 11 -120 120 0.145 -144 12 -130 130 0.158 -156

-66.25 MWh 825 (total) 1.000

-80 MWh (Meter) (submitted)

Deleted: 9

Commented [ELC8]: RR266 – Awaiting FERC and Implementation

of 156

RTBM results are presented on an hourly basis but Market Participants and Asset Owners have

access to the 5 minute data for verification purposes.

(1) Each Market Participant with actual Resource output is charged or paid for each

Settlement Location for the difference between the amount of actual RTBM physical

Energy sold and the amount of physical Energy sold in the DA Market, net of Bilateral

Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.1);

(2) Each Market Participant with Import Interchange Transactions or Through Interchange

Transactions (Resource Node) is charged or paid for each Settlement Location for the

difference between the amount of actual RTBM physical import Energy scheduled and

the amount of physical Energy sold in the DA Market, net of Bilateral Settlement

Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.2);

(3) Each Market Participant with virtual Energy purchased in the DA Market is paid for the

amount of virtual Energy purchased in the DA Market at the associated RTBM LMP (see

Section 4.5.9.3);

(4) Each Market Participant with cleared Operating Reserve Offers is:

(a) charged or paid for each Settlement Location for the difference between the

amount of Regulation-Up Service sold in the RTBM and the amount of

Regulation-Up Service sold in the DA Market at the associated RTBM

Regulation-Up Service MCP (see Section 4.5.9.4);

(b) paid for each Settlement Location for Excess Regulation-Up Mileage at the

associated Expected Regulation-Up Mileage MCP (see Section 4.5.9.4);

(c) charged for each Settlement Location for Unused Regulation-Up Mileage at the

associated Expected Regulation-Up Mileage MCP (see Section 4.5.9.4);

(d) charged or paid for each Settlement Location for the difference between the

amount of Regulation-Down Service sold in the RTBM and the amount of

Regulation-Up Service sold in the DA Market at the associated RTBM

Regulation-Down Service MCP (see Section 4.5.9.5);

(e) paid for each Settlement Location for Excess Regulation-Down Mileage at the

associated Expected Regulation-Down Mileage MCP (see Section 4.5.9.5);

of 156

(f) charged for each Settlement Location for Unused Regulation-Down Mileage at

the associated Expected Resource’s Regulation-Down Mileage MCP (see Section

4.5.9.5);

(g) charged or paid for each Settlement Location for the difference between the

amount of Spinning Reserve sold in the RTBM and the amount of Spinning

Reserve sold in the DA Market at the associated RTBM Spinning Reserve MCP

(see Section 4.5.9.6); and

(h) charged or paid for each Settlement Location for the difference between the

amount of Supplemental Reserve sold in the RTBM and the amount of

Supplement Reserve sold in the DA Market at the associated RTBM

Supplemental Reserve MCP (see Section 4.5.9.7).

(5) Each Market Participant with actual load consumption is charged or paid for each

Settlement Location for the difference between the amount of actual physical load

purchased and the amount of physical Energy purchased in the DA Market, net of

Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section

4.5.9.1);

(6) Each Market Participant with Export Interchange Transactions or Through Interchange

Transactions (Load Node) is charged or paid for each Settlement Location for the

difference between the amount of actual physical export Energy scheduled and the

amount of physical export Energy purchased in the DA Market, net of Bilateral

Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.2);

(7) Market Participants with SPP committed Resources in any of the RUC processes that

were not committed in the DA Market and MCRs that were committed in the DA Market

and committed by SPP as part of the RUC processes may receive a make whole-payment

if the total revenues received for Energy and Operating Reserve sales in the RTBM

settlement are less than the Resource’s Offer costs. See Section 4.5.9.8 for calculation

details. Certain costs are not eligible for recovery as follows:

(a) If the Resource operates outside of its Operating Tolerance in a Dispatch Interval,

costs associated with Energy provided in excess of the Resource’s Desired

Dispatch are not eligible for recovery in that Dispatch Interval;

(b) If Resource is in “Manual” Control Status in a Dispatch Interval, costs associated

with Energy provided in excess of the Resource’s Desired Dispatch are not

eligible for recovery in that Dispatch Interval; and

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(c) If the Resource increases its minimum limits in a Dispatch Interval above the

minimum limits used by SPP to make the commitment decision by more than the

Resource’s Operating Tolerance, costs associated with Energy provided in excess

of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch

Interval.

(8) Make Whole Payments for SPP committed Resources as described in (7) above are

collected on a daily basis from Market Participants based upon their pro-rata share of the

sum of following quantities for the Operating Day as described in detail under Section

4.5.9.10:

(a) The absolute value of the net Settlement Location deviations from DA Market

cleared amounts for load, Self-Charging MSRs, virtual transactions and

interchange transactions – excluding deviations resulting from actual load

consumption that is less than DA Market cleared load MWh during capacity

shortage condition Emergencies;

(b) The positive difference between RTBM Resource minimum limits and DA

Market Resource cleared Energy amount, subject to exclusion if certain criteria

are met. Special rules apply if a Resource cleared regulation in real-time but did

not clear regulation in the Day-Ahead Market;

(c) The positive difference between the DA Market Resource cleared Energy amount

and the RTBM Resource maximum limits, subject to exclusion if certain criteria

are met. Special rules apply if a Resource cleared regulation in real-time but did

not clear regulation in the Day-Ahead Market;

(d) A Resource’s DA Market cleared amount if that Resource is off-line in the

RTBM, subject to exclusion if certain criteria are met;

(e) The absolute value of the difference between a Resource’s actual output and the

Resource’s Desired Dispatch quantity if Resource is in “Manual” Control Status

or is an MCR and is not in the committed configuration;

(f) The actual Resource output for Resources that self-committed following the close

of the DA Market, subject to exclusion if certain criteria are met;

(g) A Resource’s Desired Dispatch quantity for Resources that were committed

following the close of the DA Market if that Resource is off-line in the RTBM,

subject to exclusion if certain criteria are met; and


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(h) The absolute value of a Resource’s Uninstructed Resource Deviation if that

Resource operated outside of its Operating Tolerance, subject to exclusion if

certain criteria are met.

(9) In addition, Resources may receive a Make Whole Payment related to an OOME as

described under Section 4.5.9.9, subject to certain eligibility requirements, as follows:

(a) If the Resource is issued a fixed MW level or an OOME cap and/or OOME floor

by SPP in any hour that creates Out-of-Merit Energy (OOME) MW in excess of

the Resource’s Dispatch Instruction and the Resource Offer costs associated with

the OOME MW are greater than the Energy revenue received for the OOME

MW, the Resource will receive the difference between the Energy Offer Curve

costs associated with the OOME MW and the OOME MW Energy revenue. The

OOME MW is calculated as Max (0, or the difference between (i) the (lesser of

actual Resource output or the Resource’s floor or fixed OOME MW) and (ii) the

Resource’s Desired Dispatch);

(b) If the OOME is for Energy in the down direction and the RTBM LMP is greater

than the DA Market LMP, the Asset Owner will receive a credit for the difference

multiplied by the OOME MW cap or fixed. The OOME MW is calculated as

Max (0, the difference between (i) the Resource’s DA Market cleared Energy

MW and (ii) the (greater of actual Resource output or the Resource’s OOME cap

or fixed MW)); and

(c) If during the period of time when an OOME is imposed, the RTBM cleared

amount of an Operating Reserve product is less than the DA Market cleared

amount of the corresponding Operating Reserve product and the RTBM MCP is

greater than the DA Market MCP, the Asset Owner will receive a credit for the

difference multiplied by the OOMOR MW. The OOMOR MW is calculated as

Max (0, the difference between the Resource’s DA Market cleared Operating

Reserve MW and the Resource’s RTBM cleared Operating Reserve MW).

Make Whole Payments associated with OOME are collected as part of revenue neutrality

uplift as described under Section 4.5.12.

(10) Charges for failure to deploy Regulation-Up Service or Regulation-Down Service and

charges for failure to deploy the specified amount of cleared Spinning Reserve or

Supplemental Reserve are collected from Market Participants as part of the RTBM

settlement as described under Sections 4.5.9.15 and 4.5.9.17 are distributed to Market

Participants on a load ratio share basis as described under Sections 4.5.9.16 and 4.5.9.18;

Deleted: n






of 156

(11) Charges to Market Participants for RTBM Operating Reserve procurement costs are

collected on a Real-Time load ratio share basis as described under Sections 4.5.9.11,

4.5.9.12, 4.5.9.13 and 4.5.9.14;

(12) Resources providing Regulation-Up Service and/or Regulation-Down Service will

receive a credit or charge associated with the regulation deployment energy as described

under Section 4.5.9.19 such that Resources maintain Energy margins that are equal to the

Energy margins that would have been attained absent the regulation deployment;

(a) For Regulation-Up Service, a credit is calculated if the cost rate of the Regulation-

Up Service Energy is greater than the associated LMP and a charge is calculated

if the associated LMP is greater the Regulation-Up Service Energy cost rate;2

(b) For Regulation-Down Service, a credit is calculated if the associated LMP is

greater than cost rate of the Regulation-Down Service Energy and a charge is

calculated if the cost rate of the Regulation-Down Energy is greater than the

associated LMP.3

(13) Settlement associated with revenue mismatch due to the impact of marginal losses on the

Day-Ahead Market LMPs and RTBM LMPs is also performed as part of the RTBM

settlement as follows. See Section 4.5.9.20 for calculation details;

(a) For each Loss Pool, a proxy loss charge contribution amount is developed for

each Settlement Location with a net RTBM withdrawal that is equal to the sum

of i) the positive difference between the MLC at the net withdrawal Settlement

Location and the weighted average MLC of all net injections (RTBM actual)

assumed to be serving the net withdrawal, multiplied by that Settlement

Location’s net withdrawal, and ii) the sum of charges for Real-Time pseudo-tie

Losses at the Settlement Location of the Sink of the pseudo-tie path. These values

are then summed to calculate a Loss Pool proxy loss charge contribution.

(i) The net injections assumed to be serving the net withdrawal are the net

injections at the Settlement Locations included in that the Loss Pool. To

the extent that the net injections in the Loss Pool are not sufficient to serve

the net withdrawals in the Loss Pool, net injections from an injection

exchange are included to make up the difference. To the extent that the

2 A charge is calculated here because this difference (opportunity cost) has already been included in the Regulation-Up MCP.

3 A charge is calculated here because this difference has already been included in the Regulation-Down MCP.

of 156

net injections in the Loss Pool are greater than the net withdrawals in the

Loss Pool, the excess is added to the injection exchange;

(ii) The injection exchange is comprised of quantities from Loss Pools in

which injection exceeds withdrawal. A weighted average of the MLC at

the source of these quantities establishes a reference for the component of

the loss charge contributions at Settlement Locations with net withdrawal

met from outside the Loss Pool.

(b) The Loss Pool proxy loss charge contribution calculated in (a) above are then

used to allocated to the total loss over-collections dollars to each Loss Pool on a

pro rata basis.

(c) Each Asset Owner’s credit or charge (all Asset Owner net withdrawals at

Settlement Location participate) in each Loss Pool at each withdrawal Settlement

Location within that Loss Pool is then equal a pro-rata share of the total marginal

losses over collection or under collection allocated to that Loss Pool. The pro-rata

share is calculated as an Asset Owner’s Settlement Location withdrawal divided

by the sum of all Asset Owner Settlement Location withdrawals within that Loss

Pool. Settlement Location withdrawal is equal to the maximum of (1) zero or (2)

the sum of the (i) Real-Time metered load (ii) Real-Time metered generation (iii)

Real-Time Export Interchange Transactions, (iv) Real-Time Import Interchange

Transactions, (v) Real-Time Bilateral Settlement Schedules for Energy, and (vi)

Day-Ahead Market Bilateral Settlement Schedules for Energy, including those

associated with GFA Carve Outs, at that Settlement Location. Asset Owner

credits associated with GFA Carve Outs are used to offset GFA Carve Out costs

through inclusion of such credits under Section 4.5.8.22.

…

Deleted: 3

of 156


Variable

Unit

Settlement Interval

Definition

RtDR5minAmt a, s, i $ Hour Real-Time Demand Reduction Amount per AO per Settlement Location per Hour - The RTBM amount to AO a for Demand Reduction at Settlement Location s for Dispatch Interval i.

RtLoadGrossUp5minQty a, s, i MW Dispatch Interval

Real-Time Load Gross-Up Quantity per AO per Settlement Location per Dispatch Interval - The sum of Demand Response deployed in the RTBM associated with AO a’s host load Settlement Location s in Dispatch Interval i.

RtLoadGrossUp5minQty a, s, ml, i MW Dispatch Interval

Real-Time Load Gross Up per AO per Meter Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 at Meter Data Submittal Location associated with host Settlement Location s for Dispatch Interval i.

DaLoadGrossUpHrlyQty a, s, h MWh Hour Day-Ahead Load Gross-Up Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.20 for AO a at host Settlement Location s for Hour h.

RtLmp5minPrc s, i $/MW Dispatch Interval

Real-Time LMP - The value defined under Section 4.5.9.1 at host Settlement Location s for Dispatch Interval i.

RtDRHrlyAmt a, s, d $

Operating Day

Real-Time Demand Reduction Amount per AO per Settlement Location per Hour - The RTBM amount to AO a for Demand Reduction at Settlement Location s for Hour h.

RtDRDlyAmt a, s, d $

Operating Day

Real-Time Demand Reduction Amount per AO per Settlement Location per Operating Day - The RTBM amount to AO a for Demand Reduction at Settlement Location s for the Operating Day.

RtDRAoAmt a, m, d $

Operating Day

Real-Time Demand Reduction Amount per AO per Operating Day - The RTBM amount to AO a associated with Market Participant m for Demand Reduction for the Operating Day.

RtDRMpAmt m, d $

Operating Day

Real-Time Demand Reduction Amount per Market Participant per Operating Day - The RTBM amount to Market Participant m for Demand Reduction for the Operating Day.


Deleted: 1

of 156

Variable

Unit

Settlement Interval

Definition



i none none A Dispatch Interval.



of 156

4.5.9.20 Over-Collected Losses Distribution Amount …


Variable

Unit

Settlement Interval

Definition

RtOclDistHrlyAmt a, s, lp, h $ Hour Real-Time Over Collected Losses Distribution Amount per AO per Settlement Location in Loss Pool lp per Hour - The amount to AO a for AO a’s share of total over/under collection due to marginal losses at Settlement Location s in Loss Pool lp for the Hour.

RtPseudoTieLossSpp5minAmt i $ Dispatch Interval

Real-Time SPP Total Pseudo-Tie Losses Amount per Dispatch Interval - The total amount for losses on Pseudo-Ties in Dispatch Interval i.

RtPseudoTie5minQty a, source, sink, i MW Dispatch Interval

Real-Time Pseudo-Tie Quantity per Asset Owner per source-sink path per Dispatch Interval – The value described under Section 4.5.9.26.

RtPseudoTieLoss5minAmt a, source,

sink,(s), i $ Dispatch

Interval Real-Time Pseudo-Tie Losses Amount per Asset Owner per source-sink path per Dispatch Interval - The value described under 4.5.9.27 for AO a on path source to sink in Dispatch Interval i. For the purpose of its inclusion in the calculation of the Loss Rebate Factor the sink (s) notation is an indication that value is collected at the sink Settlement Location.

RtNormLpRbtHrlyFct lp, h none Hour Real-Time Normalized Loss Rebate Factor per Loss Pool per Hour – The percentage of RtIncrOclHrlyAmt h allocated to Loss Pool lp for the Hour.

RtSlRbtHrlyFct s, lp, h $ Hour Real-Time Loss Rebate Factor per Settlement Location per Loss Pool per Hour – The sum of RtSlRbt5minFct s, lp, i at Settlement Location s in Loss Pool lp for the Hour.

RtSlRbt5minFct s, lp, i $ Dispatch Interval

Real-Time Loss Rebate Factor per Settlement Location per Loss Pool per Dispatch Interval– The amount of marginal loss dollars calculated at Settlement Location s in Loss Pool lp for the Dispatch Interval.

of 156

Variable

Unit

Settlement Interval

Definition

RtSppRbtHrlyFct h $ Hour Real-Time Loss Rebate Factor per Hour – The SPP total of RtLpRbtHrlyFct lp, h for the Hour.

RtLpRbtHrlyFct lp, h $ Hour Real-Time Loss Rebate Factor per Loss Pool per Hour – The amount of marginal loss dollars collected in Loss Pool lp for the Hour.

RtIncrOclHrlyAmt h $ Hour Real-Time Incremental Over Collected Losses Amount per Hour – The sum of RtIncrOcl5minAmt i for the Hour.

DaOclHrlyAmt h $ Hour Day-Ahead Over Collected Losses Amount per Hour – The amount of over collection in the DA Market due to marginal losses for the Hour.

RtIncrOcl5minAmt i $ Dispatch Interval

Real-Time Incremental Over Collected Losses Amount per Dispatch Interval – The amount of over/under collection in the RTBM due to marginal losses for the Dispatch Interval.

RtLpIntSupply5minFct lp, i none Dispatch Interval

Real-Time Loss Pool Internal Supply Factor per Loss Pool per Dispatch Interval – A ratio indicating the percentage of Loss Pool lp’s net withdrawals that are being served by net RTBM Energy injections inside of Loss Pool lp in Dispatch Interval i.

RtLpExtSupply5minFct lp, i none Dispatch Interval

Real-Time Loss Pool External Supply Factor per Loss Pool per Dispatch Interval – A ratio indicating the percentage of Loss Pool lp’s net RTBM Energy injections that are in excess of Loss Pool lp’s net RTBM Energy withdrawals in Dispatch Interval i.

RtLpIwaMlc5minPrc lp, i $/MWh Dispatch Interval

Real-Time Loss Pool Injection Weighted Average Marginal Loss Component per Loss Pool per Dispatch Interval - The weighted average RtMlc5minPrc s, i for all net RTBM Energy injections in loss pool lp in Dispatch Interval i.

RtSppIwaMlc5minPrc i $/MWh Dispatch Interval

Real-Time SPP Injection Weighted Average Marginal Loss Component per Dispatch Interval - The weighted average of RtMlc5minPrc s, i for all loss pool net RTBM Energy injections in excess of loss pool net RTBM Energy withdrawals in Dispatch Interval i.

RtLpInj5minQty , lp, i MW Dispatch Interval

Real-Time Net Injection Quantity per Loss Pool per Dispatch Interval – The net RTBM Energy injection quantity in Loss pool lp in Dispatch Interval i.

of 156

Variable

Unit

Settlement Interval

Definition

RtSlInj5minQty s, lp, i MWh Dispatch Interval

Real-Time Net Injection Quantity per Settlement Location per Loss Pool per Dispatch Interval – Settlement Location s’s net RTBM Energy injection quantity in Loss pool lp in Dispatch Interval i.

RtLpWdr5minQty lp, i MW Dispatch Interval

Real-Time Net Withdrawal Quantity per Settlement Location per Loss Pool per Dispatch Interval – The net RTBM Energy withdrawal quantity in Loss pool lp in Dispatch Interval i.

RtAoSlLpLrsHrlyFct a, s, lp, h

None

Hour Real-Time Loss Pool Load Ratio Share per AO per Settlement Location per Loss Pool per Hour – The ratio of AO a’s The net RTBM Energy withdrawal at Settlement Location s to the total The net RTBM Energy withdrawals in Loss pool lp in Hour h.

RtAoSlWdrHrlyQty a, s, lp, h MWh Hour Real-Time Net Market Energy Asset Owner Withdrawal per AO per Settlement Location per Loss Pool per Hour – The positive value of the sum of the difference between AO a’s RTBM Energy and its DA Market Energy instruments at Settlement Location s in Loss pool lp in Hour h.

RtAoLpWdrHrlyQty lp, h MWh Hour Real-Time Net Market Energy Withdrawal per Loss Pool per Hour – The sum of net RTBM Energy Asset Owner withdrawal in Loss pool lp in Hour h.

RtSlWdr5minQty s, lp, i MWh Dispatch Interval

Real-Time Net Withdrawal Quantity per Settlement Location per Loss Pool per Dispatch Interval – Settlement Location s’s net RTBM Energy withdrawal quantity in Loss Pool lp in Dispatch Interval i.

SltoLp5minMap s, lp, i none Dispatch Interval

Settlement Location to Loss Pool Map per Settlement Location per Loss Pool per Dispatch Interval - The portion of injection or withdrawal at Settlement Location s associated with Loss Pool lp for Dispatch Interval i.

SltoLpHrlyMap s, lp, h none Hourly Settlement Location to Loss Pool Map per Settlement Location per Loss Pool per Hour – The portion of injection or withdrawal at Settlement Location s associated with Loss Pool lp for Hour h.

RtLmp5minPrc s, i $/MWh Dispatch Interval

Real-Time LMP – The value described under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.

of 156

Variable

Unit

Settlement Interval

Definition

RtMcc5minPrc s, i $/MWh Dispatch Interval

Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of Real-Time LMP at Settlement Location s for Dispatch Interval i.

DaLmpHrlyPrc s, h $/MWh Hour Day-Ahead LMP – The value described under Section 4.5.8.1 at Settlement Location s for Hour h.

DaMccHrlyPrc s, h $/MWh Hour Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The value described under Section 4.5.8.14 at Settlement Location s for Hour h.

RtMlc5minPrc s, i $/MWh Dispatch Interval

Real-Time Marginal Losses Component of Real-Time LMP – The Marginal Losses Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i.

RtEnFinHrlyQty a, s, t, h MWh Hour Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.1 for AO a at Settlement Location s for Hour h.

RtNEnFinHrlyQty a, s, t, h MWh Hour Non-Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.2 for AO a at Settlement Location s for Hour h.

DaEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h.

DaNEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Non-Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1 for AO a at Settlement Location s for Hour h.

of 156

Variable

Unit

Settlement Interval

Definition

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Transaction per Hour in the DA Market – The value described under Section 4.5.8.3 for AO a at Settlement Location s in for transaction t for Hour h.

DaImpExp5minQty a, s, i, t MW Dispatch Interval

Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.8.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i.


Real-Time Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.9.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i.

RtBillMtr5minQty a, s, i MW Dispatch Interval

Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for AO a at Settlement Location s in for Dispatch Interval i.

RtNetInadvertentSpp5minAmt i

MW$ Dispatch Interval

Real-Time SPP Net Inadvertent Energy Amount per Dispatch Interval – The value calculated under Section 4.5.12.

RtOclDistDlyAmt a, s, lp, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool Operating Day - The amount to AO a for AO a’s share of total over/under collection due to marginal losses at Settlement Location s in Loss Pool lp for the Operating Day.

RtOclDistAoAmt a, m, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per AO per Operating Day- The amount to AO a associated with Market Participant m for AO a’s share of total over/under collection due to marginal losses for the Operating Day.

RtOclDistMpAmt m, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per MP per Operating Day- The amount to MP m for MP m’s share of total over/under collection due to marginal losses for the Operating Day.

RtAoSlActWdrHrlyQty a, s, h MWh Hour Real-Time Actual Withdrawal Quantity per Asset Owner per Settlement Location per Hour – The amount of actual MWs withdrawn for Asset Owner a’s at Settlement Location s in Hour h.

of 156

Variable

Unit

Settlement Interval

Definition

AoIsGFADlyFlg a, m, d none Month Grandfathered Agrement Carve-Out Asset Owner Flag per AO per Day – The flag described under Section 4.5.8.22.

AoIsGFALoadDlyFlg a, s, d, t none Operating Day

Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Operating Day – The flag described under Section 4.5.8.25.

RtSlBssHrlyFct s, h, t Ratio Hour Real-Time BSS Factor per Settlement Location per Hour per Transaction – The RtAoSlBssHrlyFct applied to BSS with Transaction t at Settlement Location’s s in Hour h.

RtSlBssGFAHrlyFct s, h, t Ratio Hour Real-Time BSS Factor per Settlement Location per Hour per Transaction for Grand-Fathered Agreements - The percentage of GFA BSSs compared to total withdrawal applied at Settlement Location’s s in Hour h.

RtAoSlGFAWdrHrlyQty a, s, h MWh Hour Real-Time GFA/FSE Withdrawal Quantity per Asset Owner per Settlement Location per Hour – The amount of BSS MWs associated with GFA/FSE withdrawal for Asset Owner a’s at Settlement Location s in Hour h.

RtAoSlBssWdrHrlyQty a, s, h MWh Hour Real-Time BSS Withdrawal Quantity per Asset Owner per Settlement Location per Hour – The amount of BSS MWs of withdrawal for Asset Owner a’s at Settlement Location s in Hour h.

RtAoSlBssHrlyFct a, s, h Ratio Hour Real-Time Asset Owner BSS Factor per Settlement Location per Hour – The ratio of BSS withdrawal over physical withdrawal for Asset Owner a’s at Settlement Location’s s in Hour h.

bs none none A buyer or a seller of a Bilateral Settlement Schedule.





t none none A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction.

Deleted: 3

Deleted: 6

of 156

Variable

Unit

Settlement Interval

Definition


lp none none A Loss Pool.


rsg none none An import or export resulting from a schedule created by a Reserve Sharing Event.

of 156

4.5.11 Miscellaneous Amount …

The above variable is defined as follows:

Variable

Unit

Settlement Interval

Definition

MiscDlyAmt a, ct, s, rnu, d

$ Operating Day

Miscellaneous Amount per AO per Settlement Location per Settlement Location per Operating Day – The miscellaneous amount to AO a for charge type ct at Settlement Location s in Operating Day d.

MiscAoAmt a, m, d $ Operating Day

Miscellaneous Amount per AO per Operating Day – The total miscellaneous amount to AO a in Operating Day d.

MiscMpAmt m, d $ Operating Day

Miscellaneous Amount per MP per Operating Day – The total miscellaneous amount to MP m in Operating Day d.

ct none none Any charge type specified under Sections 4.5.8, 4.5.8.20 or 4.5.9.24 or any other miscellaneous charges not specifically accounted for under a distinct charge type.


rnu none none A flag which instructs the settlement system to include the amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N).


Deleted: 1

of 156

4.5.12 Revenue Neutrality Uplift Distribution Amount …


Variable

Unit

Settlement Interval

Definition

RtRnuHrlyAmt a, s, h $ Hour Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Hour – The amount for revenue neutrality to AO a at Settlement Location s in Hour h.

RtRnuSppDistRate d $/MW Operating Day

Real-Time Revenue Neutrality Uplift SPP Distribution Rate per Operating Day – The rate applied to AO a’s

RtRnuDistHrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d.

RtRnuSppDlyAmt spp, d $ Operating Day

Real-Time Revenue Neutrality Uplift SPP Daily Amount – The total amount SPP is not revenue neutral, through all other charge types, in an Operating Day. The amount that is to be uplifted to the SPP market for Operating Day d.

RtRnuDistHrlyQty a, s, h

MWh Hour Real-Time Revenue Neutrality Uplift Quantity per AO per Hour

per Settlement Location – The total MWh RNU allocation determinant for AO a at Settlement Location s for Hour h.

RtRnuDistSppQty spp, d

MWh Operating

Day Real-Time Revenue Neutrality Uplift Quantity for SPP per Operating Day – The total MWh RNU allocation determinant for SPP on a system-wide basis.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour – The value defined under Section 4.5.8.3.

RtOomSppAmt spp, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.9.


of 156

Variable

Unit

Settlement Interval

Definition

RtRegAdjSppAmt spp, d $ Operating Day

Real-Time Regulation Deployment Adjustment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.18.

RtJoaSppAmt spp, d $ Operating Day

Real-Time Joint Operating Agreement Amount for SPP per Operating Day – The SPP system-wide total of the values calculated under Section 4.5.9.21.

DaRevInadqcSppAmt spp, d $ Operating Day

Day-Ahead Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total DA Market charges and DA Market credits for Operating Day d.

DaCirAdjMpDlyAmt m, d $ Operating Day

Day-Ahead Adjustment Amount per Market Participant per Operating Day – The value calculated under Section 4.5.8.28.

DaEnergyMpAmt m, d $ Operating Day

Day-Ahead Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.1.

DaNEnergyMpAmt m, d $ Operating Day

Day-Ahead Non-Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.2.

DaVEnergyMpAmt m, d $ Operating Day

Day-Ahead Virtual Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.3.

DaRegUpMpAmt m, d $ Operating Day

Day-Ahead Regulation-Up Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.4.

DaRegDnMpAmt m, d $ Operating Day

Day-Ahead Regulation-Down Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.5.

DaSpinMpAmt m, d $ Operating Day

Day-Ahead Spinning Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.6.

DaSuppMpAmt m, d $ Operating Day

Day-Ahead Supplemental Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.7.

DaRegUpDistMpAmt m, d $ Operating Day

Day-Ahead Regulation-Up Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.8.

DaRegDnDistMpAmt m, d $ Operating Day

Day-Ahead Regulation-Down Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.9.

Deleted: 9


of 156

Variable

Unit

Settlement Interval

Definition

DaSpinDistMpAmt m, d $ Operating Day

Day-Ahead Spinning Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.10.

DaSuppDistMpAmt m, d $ Operating Day

Day-Ahead Supplemental Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.11.

DaMwpMpAmt m, d $ Operating Day

Day-Ahead Make Whole Payment Amount per MP per Operating Day – The value calculated under Section 4.5.8.12.

DaMwpDistMpAmt m, d $ Operating Day

Day-Ahead Make Whole Payment Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.13.

TcrFundMpAmt m, d $ Operating Day

Transmission Congestion Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.8.14.

TcrUpliftDlyMpAmt m, d $ Operating Day

Transmission Congestion Rights Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.8.15.

ECFDlyAmt d $ Operating Day

Excess Congestion Fund Amount per Operating Day – The value calculated under Section 4.5.8.16.

ECFYrlyAmt yr $ Year Excess Congestion Fund Yearly Amount – The value calculated under Section 4.5.8.18.

ARFDlyAmt d $ Operating Day

Auction Revenue Fund Amount per Operating Day – The value calculated under Section 4.5.10.4.

ARFYrlyAmt yr $ Year Auction Revenue Yearly Fund – The value calculated under Section 4.5.10.6.

DaOclHrlyAmt h $ Hour Day-Ahead Incremental Over Collected Losses Amount per Hour – The value described under Section 4.5.9.20.

TcrAucTxnMpAmt m, d $ Operating Day

Transmission Congestion Right Auction Daily Amount per MP per Operating Day – The value calculated under Section 4.5.10.1.

TcrPaybackSppYrlyAmt yr $ Year Transmission Congestion Rights Annual Payback Amount – The value calculated under Section 4.5.8.18.

TcrCloseoutYrlyMpAmt my, yr $ Year Transmission Congestion Rights Annual Closeout Amount per MP per Year – The value calculated under Section 4.5.8.18.





of 156

Variable

Unit

Settlement Interval

Definition

ArrAucTxnMpAmt m, d $ Operating Day

Auction Revenue Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.10.2.

ArrUpliftMpAmt m, d $ Operating Day

Auction Revenue Rights Funding Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.10.3.

ArrPaybackSppYrlyAmt yr $ Year Auction Revenue Rights Annual Payback Amount per Year – The value calculated under Section 4.5.10.6.

ArrCloseoutYrlyMpAmt m, yr $ Year Auction Revenue Rights Annual Closeout Amount per MP per Year – The value calculated under Section 4.5.10.6.

DaDRMpAmt m, d $ Operating Day

Day-Ahead Demand Reduction Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.24

DaDRDistMpAmt m, d $ Operating Day

Day-Ahead Demand Reduction Distribution Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.25

RtRevInadqcSppAmt spp, d $ Operating Day

Real-Time Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total RTBM charges and RTBM credits.


Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.

RtBillMtrCir5minQty a, s, i MW Dispatch Interval

Real-Time Billing Meter Quantity per Asset Owner per Settlement Location share per Dispatch Interval – The value described under Section 4.5.9.30.


Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Virtual Energy Quantity per AO per Settlement Location per Hour per Transaction – The value described under Section 4.5.8.3.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Asset Energy Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.1.




of 156

Variable

Unit

Settlement Interval

Definition

DaImpExp5MinQty a, s, i, t MW Dispatch Interval

Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.8.2.

RtMcc5minPrc s, i $/MW Dispatch Interval

Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i.

RtEnergyMpAmt m, d $ Operating Day

Real-Time Energy Amount per MP per Operating Day – The value described under Section 4.5.9.1.

RtNEnergyMpAmt m, d $ Operating Day

Real-Time Non-Asset Energy Amount per MP per Operating Day – The value described under Section 4.5.9.2.

RtVEnergyMpAmt m, d $ Operating Day

Real-Time Virtual Energy Amount per MP per Operating Day – The value described under Section 4.5.9.3.

RtRegUpMpAmt m, d $ Operating Day

Real-Time Regulation-Up Service Amount per MP per Operating Day – The value described under Section4.5.9.4.

RegUpUnsedMileMwpMpAmt m, d $ Operating Day

Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section4.5.9.28

RtRegDnMpAmt m, d $ Operating Day

Real-Time Regulation-Down Service Amount per MP per Operating Day – The value described under Section 4.5.9.5.

RegUpUnsedMileMwpMpAmt m, d $ Operating Day

Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.29.

RtSpinMpAmt m, d $ Operating Day

Real-Time Spinning Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.6.

RtSuppMpAmt m, d $ Operating Day

Real-Time Supplemental Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.7.

RtMwpMpAmt m, d $ Operating Day

RUC Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.8

RtOomMpAmt m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per MP per Operating Day - The value described under Section 4.5.9.9.

of 156

Variable

Unit

Settlement Interval

Definition

RtMwpDistMpAmt m, d $ Operating Day

RUC Make Whole Payment Distribution Amount per MP per Operating Day – The value described under Section 4.5.9.10.

RtRegNonPerfMpAmt m, d $ Operating Day

Real-Time Regulation Non-Performance Amount per MP per Operating Day – The value described under Section 4.5.9.15.

RtCRDeplFailMpAmt m, d $ Operating Day

Real-Time Contingency Reserve Deployment Failure Amount per MP per Operating Day – The value described under Section 4.5.9.17.

RtRegAdjMpAmt m, d $ Operating Day

Real-Time Regulation Deployment Adjustment Amount per MP per Operating Day - The value described under Section 4.5.9.19.

RtOclDistMpAmt m, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.9.20.

RtNetInadvertentSpp5minAmt i $ Dispatch Interval

Real-Time SPP Inadvertent Energy Amount per Dispatch Interval – SPP net Inadvertent Energy for Dispatch Interval i valued at the Real-Time LMP MEC.

RtNetInadvertentSppAmt spp, d $ Operating Day

Real-Time SPP Inadvertent Energy Amount per Operating Day – The sum of RtNetInadvertentSpp5minAmt i for Operating Day d.

RtCongestionSppAmt spp, d $ Operating Day

Real-Time SPP Net Congestion Revenue Amount – The net amount of total Real-Time congestion revenue collected over Operating Day d.

RtNetActIntrchngSpp5minQty i MW Dispatch Interval

Real-Time SPP Net Actual Interchange per Dispatch Interval – SPP Net Actual Interchange in Dispatch Interval i.

RtNetSchIntrchngSpp5minQty i MW Dispatch Interval

Real-Time SPP Net Scheduled Interchange per Dispatch Interval – SPP Net Scheduled Interchange in Dispatch Interval i.

RtMec5minPrc i $/MW Dispatch Interval

Marginal Energy Component of Real-Time LMP per Dispatch Interval – The Real-Time LMP MEC in Dispatch Interval i.

RtJoaHrlyAmt a, h, f $ Hour Real-Time Joint Operating Agreement Hourly Amount - The value calculated under Section 4.5.9.21.

RtRegNonPerfDistMpAmt m, d $ Operating Day

Real-Time Regulation Non-Performance Distribution Amount - The value calculated under Section 4.5.9.16.

of 156

Variable

Unit

Settlement Interval

Definition

RtCRDeplFailDistMpAmt m, d

$ Operating

Day Real-Time Contingency Reserve Deployment Failure Distribution Amount - The value calculated under Section 4.5.9.18.

RtRegUpDistMpAmt m, d $ Operating Day

Real-Time Regulation-Up Service Distribution Amount – The value calculated under Section 4.5.9.11.

RtRegDnDistMpAmt m, d $ Operating Day

Real-Time Regulation-Down Service Distribution Amount – The value calculated under Section 4.5.9.12.

RtSpinDistMpAmt m, d $ Operating Day

Real-Time Spinning Reserve Distribution Amount – The value calculated under Section 4.5.9.13.

RtSuppDistMpAmt m, d $ Operating Day

Real-Time Supplemental Reserve Distribution Amount – The value calculated under Section 4.5.9.14.

RtRsgDistMpAmt m, d $ Operating Day

Real-Time Reserve Sharing Group Distribution Amount – The amount calculated under Section 4.5.9.23.

RtDRMpAmt m, d $ Operating Day

Real-Time Demand Reduction Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.24

RtDRDistMpAmt m, d $ Operating Day

Real-Time Demand Reduction Distribution Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.25.

RtRsgDlyAmt a, d $ Operating Day

Real-Time Reserve Sharing Group Amount – The amount calculated under Section 4.5.9.22.

MiscDlyAmt a, c, d $ Operating Day

Real-Time Miscellaneous Amount per AO per Charge Type per Operating Day – The miscellaneous amount to AO a for charge type c in Operating Day d as described under Section 4.5.10.4.

RtRnuDlyAmt a, s, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Operating Day– The amount for revenue neutrality to AO a at Settlement Location s in Operating Day d.

RtRnuAoAmt a, m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per AO per Operating Day – The amount for revenue neutrality to AO a associated with Market Participant m in Operating Day d.

of 156

Variable

Unit

Settlement Interval

Definition

RtRnuMpAmt m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per MP per Operating Day – The amount for revenue neutrality to MP m in Operating Day d.

RtPseudoTieCongSppAmt d $ Dispatch Interval

Real-Time SPP Total Pseudo-Tie Congestion Amount per Dispatch Interval - The total amount for congestion on Pseudo-Ties for the Operating Day.

RtPseudoTieLossMpAmt m, d $ Operating Day

Real-Time Pseudo-Tie Losses Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie losses on all paths for MP m for the Operating Day.

RtPseudoTieCongMpAmt m, d $ Operating Day

Real-Time Pseudo-Tie Congestion Amount per Market Participant per Operating Day - The value described under 4.5.9. 26 for MP m for the Operating Day.

RtCirAdjMpDlyAmt m, d $ Operating Day

Real-Time Adjustment Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.30.

GFARevInadqcSppAmt spp, d $ Operating Day

Grandfathered Agreement Carve-Out Revenue Inadequacy Daily Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead Over-Collected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount for Operating Day d.

DaGFACarveOutDistMpDlyAmt m, d $ Operating Day

Day Ahead GFA Carve Out Distribution Daily Amount per MP per Operating Day – The value calculated under Section 4.5.8.25

DaGFACarveOutDistMpMnthlyAmt m, mn $ Month Day-Ahead GFA Carve Out Distribution Amount per MP per Month – The value calculated under Section 4.5.8.26.

DaGFACarveOutDistMpYrlyAmt m, yr $ Year Day-Ahead GFA Carve Out Distribution Amount per MP per Year – The value calculated under Section 4.5.8.27.

GFARevInadqcSppMnthlyAmt spp, mn $ Month Grandfather Agreement Carve-Out Revenue Inadequacy Monthly Amount – The value calculated under Section 4.5.8.26.


Deleted: 6

Formatted: Comment Subject, Space After: 3 pt

Deleted: 7



Deleted: 8



Deleted: 7


of 156

Variable

Unit

Settlement Interval

Definition

GFARevInadqcSppYrlyAmt spp, yr $ Year Grandfather Agreement Carve-Out Revenue Inadequacy Yearly Amount – The value calculated under Section 4.5.8.27.

A none none An Asset Owner.

S none none A Resource Settlement Location.




f none none A flowgate identified in the applicable JOA.


rnu none none A flag which instructs the settlement system to include the amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N).




Deleted: 8


of 156

4.6 Integrated Marketplace Administration Services

The charges and credits to Asset Owners for Integrated Marketplace administration services as

described in Schedule 1-A3 and Schedule 1-A4 of the SPP Tariff. The charges and credits

resulting from Integrated Marketplace hourly activity and calculated on a daily basis will be

included on the Settlement Statements consistent with the timing of the DA Market settlement

and Real-Time Balancing Market settlement.

4.6.1 Integrated Marketplace Clearing Administration Service

(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner

for each hour to recover the Transmission Providers Integrated Marketplace clearing

administration service charge as described in Schedule 1-A3 of the SPP Tariff. The

amount to each applicable Asset Owner is calculated as follows.

# RtSched1A3HrlyAmt a, s, h = RtSched1A3DlyRate d * RtSched1A3HrlyQty a, s, h

Where,

(a) #RtSched1A3HrlyQty a, s, h = (∑i

ABS (RtBillMtr5minQty a, s, i +

RtBillMtrCir5minQty a, s, i ) / 12) +

(∑i∑

t[ (ABS (RtImpExp5minQty a, s, i, t, rsg(null) )/12) ] ) + (∑

tABS

(DaClrdVHrlyQty a, s, h, t))

(1) For each Asset Owner, a daily amount is calculated at each Settlement Location. The

amount is calculated as follows:

RtSched1A3DlyAmt a, s, d = ∑h

RtSched1A3HrlyAmt a, s, h

(2) For each Asset Owner associated with Market Participant m, a daily amount is calculated.

The daily amount is calculated as follows:

Field Code Changed


Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed

of 156

RtSched1A3AoAmt a, m, d = ∑s

RtSched1A3DlyAmt a, s, d

(3) For each Market Participant, a daily amount is calculated representing the sum of Asset

Owner amounts associated with that Market Participant. The daily amount is calculated

as follows:

RtSched1A3MpAmt m, d = ∑a

RtSched1A3AoAmt a, m, d

Field Code Changed

Field Code Changed

of 156


Variable

Unit

Settlement Interval

Definition

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour – The value defined under Section 4.5.8.3.







RtSched1A3AoAmt a, m, d $ Operating Day

Real-Time Schedule 1-A3 Amount per AO per Operating Day – The total amount of Schedule 1-A3 Integrated Marketplace clearing administration service charge to AO a associated with Market Participant m in Operating Day d.

RtSched1A3DlyAmt a, s, d $ Operating Day

Real-Time Schedule 1-A3 Amount per AO per Settlement Location per Operating Day– The total amount of Schedule 1-A3 Integrated Marketplace clearing administration service charge to AO a at Settlement Location s in Operating Day d.

RtSched1A3MpAmt m, d $ Operating Day

Real-Time Schedule 1-A3 Amount per MP per Operating Day – The total amount of Schedule 1-A3 Integrated Marketplace clearing administration service charge to MP m in Operating Day d.

RtSched1A3HrlyAmt a, s, h $ Hour Real-Time Schedule 1-A3 Amount per AO per Settlement Location per Hour – The amount for Schedule 1-A3 Integrated Marketplace clearing administrative service to AO a at Settlement Location s in Hour h.


of 156

Variable

Unit

Settlement Interval

Definition

RtSched1A3HrlyQty a, s, h MWh Hour Real-Time Schedule 1-A3 Quantity per AO per Hour per Settlement Location – The total MWh Schedule 1-A3 Integrated Marketplace clearing administrative service determinant for AO a at Settlement Location s for Hour h per Schedule 1-A3 of the Tariff.

RtSched1A3DlyRate d $/MW Operating Day

Real-Time Schedule 1-A3 Rate per Operating Day – The rate applied to AO a’s RtSched1A3HrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d per Schedule 1-A3 of the Tariff.









of 156

4.6.2 Integrated Marketplace Facilitation Administration Service


for each hour to recover the Transmission Providers Integrated Marketplace facilitation




Where,

(a) #RtSched1A4HrlyQty a, s, h = (∑i

ABS (RtBillMtr5minQty a, s, i +

RtBillMtrCir5minQty a, s, i ) / 12) +

(∑i∑

t[ (ABS (RtImpExp5minQty a, s, i, t, rsg(null) )/12) ] )











as follows:



Field Code Changed


Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed

of 156


Variable

Unit

Settlement Interval

Definition








Real-Time Schedule 1-A4 Amount per AO per Operating Day – The total amount of Schedule 1-A4 Integrated Marketplace facilitation administration service charge to AO a associated with Market Participant m in Operating Day d.


Real-Time Schedule 1-A4 Amount per AO per Settlement Location per Operating Day– The total amount of Schedule 1-A4 Integrated Marketplace facilitation administration service charge to AO a at Settlement Location s in Operating Day d.


Real-Time Schedule 1-A4 Amount per MP per Operating Day – The total amount of Schedule 1-A4 Integrated Marketplace facilitation administration service charge to MP m in Operating Day d.

RtSched1A4HrlyAmt a, s, h $ Hour Real-Time Schedule 1-A4 Amount per AO per Settlement Location per Hour – The amount for Schedule 1-A4 Integrated Marketplace facilitation administrative service to AO a at Settlement Location s in Hour h.

RtSched1A4HrlyQty a, s, h MWh Hour Real-Time Schedule 1-A4 Quantity per AO per Hour per Settlement Location – The total MWh Schedule 1-A4 Integrated Marketplace facilitation administrative service determinant for AO a at Settlement Location s for Hour h per Schedule 1-A4 of the Tariff.


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Variable

Unit

Settlement Interval

Definition











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5.9 Transmission Congestion Rights Administration Service


for each hour to recover the Transmission Providers transmission congestion rights




Where,

(a) #RtSched1A2HrlyQty a, s, h = ∑t

(TcrHrlyQty a, h, t )











as follows:



Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed


Variable

Unit

Settlement Interval

Definition


Real-Time Schedule 1-A2 Amount per AO per Operating Day – The total amount of Schedule 1-A2 transmission congestion rights administration service charge to AO a associated with Market Participant m in Operating Day d.


Real-Time Schedule 1-A2 Amount per AO per Settlement Location per Operating Day– The total amount of Schedule 1-A2 transmission congestion rights administration service charge to AO a at Settlement Location s in Operating Day d.


Real-Time Schedule 1-A2 Amount per MP per Operating Day – The total amount of Schedule 1-A2 transmission congestion rights administration service charge to MP m in Operating Day d.

RtSched1A2HrlyAmt a, s, h $ Hour Real-Time Schedule 1-A2 Amount per AO per Settlement Location per Hour – The amount for Schedule 1-A2 transmission congestion rights administration service charge to AO a at Settlement Location s in Hour h.

RtSched1A2HrlyQty a, s, h MWh Hour Real-Time Schedule 1-A2 Quantity per AO per Hour per Settlement Location – The total MWh Schedule 1-A2 transmission congestion rights administration service determinant for AO a at Settlement Location s for Hour h per Schedule 1-A2 of the Tariff.



TcrHrlyQty a, h, t MWh Hour Transmission Congestion Right Quantity - The value described under Section 4.5.8.14.

A none none An Asset Owner.

S none none A Resource Settlement Location.



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Variable

Unit

Settlement Interval

Definition





Appendix G Mitigated Offer Development Guidelines G.2.5 Mitigated Energy Offer Curve The Mitigated Energy Offer Curve is a set of up to ten price/quantity pairs (measured in

$/MWh and MW) describing the short-run marginal cost of providing energy based on the heat

rate curve, fuel cost, variable operations and maintenance costs and Schedules 1-A3 and 1-A4

charges.

𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝐸𝐸𝐸𝐸𝑀𝑀𝐸𝐸𝑀𝑀𝐸𝐸 𝑂𝑂𝑂𝑂𝑂𝑂𝑀𝑀𝐸𝐸 ($𝑀𝑀𝑀𝑀ℎ⁄) =

𝐻𝐻𝑀𝑀𝑀𝑀𝑀𝑀𝐻𝐻𝑀𝑀𝑀𝑀(𝑚𝑚𝑚𝑚𝑚𝑚𝑀𝑀𝑚𝑚𝑀𝑀𝑀𝑀ℎ⁄)∗𝑃𝑃𝑀𝑀𝐸𝐸𝑂𝑂𝑃𝑃𝐸𝐸𝑚𝑚𝑀𝑀𝐸𝐸𝑃𝑃𝑀𝑀 𝐹𝐹𝑀𝑀𝑃𝑃𝑀𝑀𝑃𝑃𝐸𝐸∗𝑇𝑇𝑃𝑃𝑀𝑀𝑀𝑀𝑇𝑇 𝐹𝐹𝑚𝑚𝑀𝑀𝑇𝑇 𝐻𝐻𝑀𝑀𝑇𝑇𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝐶𝐶𝑃𝑃𝐶𝐶𝑀𝑀𝐶𝐶($𝑚𝑚𝑚𝑚𝑚𝑚𝑀𝑀𝑚𝑚⁄)+𝐸𝐸𝑂𝑂𝐶𝐶

𝑉𝑉𝑂𝑂𝑀𝑀($𝑀𝑀𝑀𝑀ℎ⁄) + Schedule 1-A3 Charge ($/MWh) + Schedule 1-A4 Charge ($/MWh)

where EOC VOM is defined in Section 2.4.3, the heat rate is as defined in Section G.2.1, the

performance factor is as defined in Section G.2.2, and the Total Fuel Related Cost is as defined

in Section G.2.3. The EOC VOM is calculated using an allocated portion of the total VOM

calculated under Section 2.4. The currently approved Schedules 1-A3 and 1-A4 rates are published

in the SPP Tariff.

Note that the sum of total allocated $ used to calculate EOC VOM included here, the allocated

VOM $ used to calculate TFRC VOM under Section 2.3, the allocated VOM $ used to calculate

No-Load VOM under 2.7, the allocated VOM $ used to calculate Start-Up VOM under 2.6 and

the allocated VOM $ used to calculate Regulation VOM under 2.10 must not exceed the total

VOM $ calculated under Section 2.4.

G.6.4 Energy Offer Curve for Quick Start A Quick Start Resource is a Resource that dispatched directly by SCED in the RTBM.

A Quick Start Resource that is dispatched by the Real-Time Balancing Market (SCED, as opposed to

SCUC or RUC), may include start-up costs as part of the Mitigated Energy Offer Curve. If Start-Up

Adder and No-Load Adder are used here, the Mitigated Start-up Offer under Section 2.6 and the

Mitigated No-Load Offer under Section 2.7 must be equal to zero.

Mitigated Energy Offer ($/MWh) =

Deleted: and

Commented [MR33]: MMU requires the rates to be posted where they can be easily referenced. Could be OASIS, SPP web site or Tariff.

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(Heat Rate (mmBtu/MWh) * Performance Factor * Total Fuel Related Costs ($/mmBtu))

+ Start VOM ($/MWh) + Start-Up Adder ($/MWh) + No-Load Adder ($/MWh) + Schedule 1-A3

Charge ($/MWh) + Schedule 1-A4 Charge ($/MWh)

SPP Tariff (OATT)

SPP Tariff 10.5 Transmission Provider Recovery:

To the extent that the Transmission Provider is required to pay any money

damages or compensation or pay amounts due to its indemnification of any other

party, the Transmission Provider shall be allowed to recover any such amounts

(subject to crediting all amounts recovered by Transmission Provider through

insurance or through any indemnification it receives) under Schedule 1-A of this

Tariff as part of the Administrative Charges, provided that the cap in Schedule 1

shall not apply to or prohibit the recovery of these amounts.

13.7 Classification of Firm Transmission Service:

(a) The Transmission Customer taking Firm Point-To-Point Transmission

Service may (1) change its Receipt and Delivery Points to obtain service

on a non-firm basis consistent with the terms of Section 22.1 or (2) request

a modification of the Points of Receipt or Delivery on a firm basis

pursuant to the terms of Section 22.3.

(b) The Transmission Customer may purchase transmission service to make

sales of capacity and energy from multiple generating units that are

interconnected to the Transmission Provider's Transmission System. For

such a purchase of transmission service, the resources will be designated

as multiple Points of Receipt, unless (i) the multiple generating units are at

the same generating plant in which case the units would be treated as a

Deleted: , Section 1

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single Point of Receipt, or (ii) the generating units or plants comprise a

registered Resource Hub as defined in Attachment AE in which case the

units or plants also would be considered as a single Point of Receipt. In

the event of a change in the ownership or control of generation resources

previously aggregated as a single Point of Receipt under this provision,

such generation may be disaggregated and treated as multiple Points of

Receipt, provided that all other terms of this Tariff and the Service

Agreement are met.

(c) The Transmission Provider shall provide firm deliveries of capacity and

energy from the Point(s) of Receipt to the Point(s) of Delivery. Each

Point of Receipt at which firm transfer capability is reserved by the

Transmission Customer shall be set forth in the Firm Point-To-Point

Service Agreement for long-term firm Transmission Service along with a

corresponding capacity reservation associated with each Point of Receipt.

Points of Receipt and corresponding capacity reservations shall be as

mutually agreed upon by the Parties for short-term firm Transmission.

Each Point of Delivery at which firm transfer capability is reserved by the

Transmission Customer shall be set forth in the Firm Point-To-Point

Service Agreement for long-term firm Transmission Service along with a

corresponding capacity reservation associated with each Point of Delivery.

Points of Delivery and corresponding capacity reservations shall be as

mutually agreed upon by the Parties for short-term firm Transmission

Service. The greater of either (1) the sum of the capacity reservations at

the Point(s) of Receipt, or (2) the sum of the capacity reservations at the

Point(s) of Delivery shall be the Transmission Customer's Reserved

Capacity. The Transmission Customer will be billed for its Reserved

Capacity under the terms of Schedules 7 and 11. The Transmission

Customer may not exceed its firm capacity reserved at each Point of

Receipt and each Point of Delivery except as otherwise specified in

Section 22. In the event that a Transmission Customer (including third-

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party sales by a Transmission Owner) exceeds its firm reserved capacity at

any Point of Receipt or Point of Delivery or uses Transmission Service at

a Point of Receipt or Point of Delivery that it has not reserved, except for

an MSR under instruction as specified in Section 2.17 of Attachment AE,

the Transmission Customer shall pay the following penalty (in addition to

the applicable charges for all of the firm capacity actually used): 100% of

the Firm Point-To-Point Transmission Service charges under Schedules 7

and 11 for the period for which the unreserved service was actually used.

The charges for the unreserved service shall be based upon the duration of

the period when the unreserved capacity was used. For example, one hour

shall be billed at the charge for weekday deliveries, repeated daily use of

unreserved capacity within a seven day period shall increase the duration

of the period to a weekly duration and multiple instances of unreserved

use during more than one seven day period during a calendar month shall

increase the duration of the period to a monthly duration. The

Transmission Provider shall compensate the Transmission Owners for

100% of the (i) Firm Point-To-Point Transmission Service charge, (ii)

Base Plan Zonal Charge and (iii) Region-wide Charge for the period for

which they have provided service. The penalty revenues in excess of the

amount distributed to Transmission Owners shall be used to reduce the

Schedule 1-A1 charges collected by the Transmission Provider from the

Transmission Customers. All Transmission Customers, except the

penalized Transmission Customer, shall receive a reduction of Schedule 1-

A1 charges pursuant to this section. Such penalty revenues shall be

distributed by the Transmission Provider to Transmission Customers on a

pro-rata basis of each Transmission Customer’s monthly Schedule 1-A1

charge, except for the penalized Transmission Customer, for the next

billing period ending at least 15 calendar days after the date the

Transmission Provider collects the penalty revenues from the penalized

Transmission Customer. For the amounts exceeding reserved capacity,

Commented [A34]: Pending in ER19-460 – Order 841 compliance

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the Transmission Customer also must purchase losses as required by this

Tariff.

14.5 Classification of Non-Firm Point-To-Point Transmission Service:

Non-Firm Point-To-Point Transmission Service shall be offered under

terms and conditions contained in Part II of the Tariff. The Transmission

Provider and Transmission Owners undertake no obligation under the Tariff to

plan the Transmission System in order to have sufficient capacity for Non-Firm

Point-To-Point Transmission Service. Parties requesting Non-Firm Point-To-

Point Transmission Service for the transmission of firm power do so with the full

realization that such service is subject to availability and to Curtailment or

Interruption under the terms of the Tariff. The Transmission Customer will be

billed for its Reserved Capacity under the terms of Schedules 8 and 11. In the

event that a Transmission Customer (including third-party sales by a

Transmission Owner) exceeds its non-firm capacity reservation, except for an

MSR under instruction as specified in Section 2.17 of Attachment AE, the

Transmission Customer shall pay the following penalty (in addition to the charges

for all of the non-firm capacity used): 100% of the Non-Firm Point-To-Point

Transmission Service charges under Schedules 8 and 11 for the duration of the

period when the additional service was used as specified below not to exceed one

month for the amount in excess of such capacity reservation. An excess of one

hour or less shall be billed at the charge for weekday deliveries, repeated daily use

of unreserved capacity within a seven day period shall increase the duration of the

period to a weekly duration and multiple instances of unreserved use during more

than one seven day period during a calendar month shall increase the duration of

the period to a monthly duration. The Transmission Provider shall compensate

the Transmission Owners for 100% of the (i) Non-Firm Point-To-Point

Transmission Service charge, (ii) Base Plan Zonal Charge and (iii) Region-wide

Charge for the period for which they have provided service. The penalty revenues

Commented [ELC35]: Do we normally include forward looking tariff language in RRs?

Commented [A36]: Pending in ER19-460 – Order 841 compliance

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in excess of the amount distributed to Transmission Owners shall be used to

reduce the Schedule 1-A1 charges collected by the Transmission Provider from

the Transmission Customers. All Transmission Customers, except the penalized

Transmission Customer, shall receive a reduction of Schedule 1-A1 charges

pursuant to this section. Such penalty revenues shall be distributed by the

Transmission Provider to Transmission Customers on a pro-rata basis of each

Transmission Customer’s monthly Schedule 1-A1 charge, except for the

penalized Transmission Customer, for the next billing period ending at least 15

calendar days after the date the Transmission Provider collects the penalty

revenues from the penalized Transmission Customer. For the amounts exceeding

the non-firm capacity reservation, the Transmission Customer must purchase

losses as required by this Tariff. Non-Firm Point-To-Point Transmission Service

shall include transmission of energy on an hourly basis and transmission of

scheduled short-term capacity and energy on a daily, weekly or monthly basis, but

not to exceed one month's reservation for any one Application, under Schedules 8

and 11.

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SCHEDULE 1-A, TARIFF ADMINISTRATION SERVICES

The Transmission Provider shall provide administration services described in this

Schedule 1-A to carry out its responsibilities under this Tariff. Transmission Customers and

Market Participants must purchase these services from the Transmission Provider. Unless

otherwise collected under this Tariff, the Transmission Provider will recover 100% of its total

expenses incurred for the provision of these services, through the charges described herein, and

when such total expenses are divided by the total billing determinants of Schedule 1-A1, the

resulting rate will not exceed $.043 per MWh. The charges for these services are developed as

shown below.

1. Schedule 1-A1 Transmission Administration Service

Transmission administrative service is provided by the Transmission Provider to all

Transmission Customers under this Tariff and includes the provision of: (1) reliability

coordination; (2) transmission scheduling; (3) system control; and, (4) transmission planning

services (“Schedule 1-A1 Service”).

a. Schedule 1-A1 Service Rate Calculation



i. Costs

The costs to be recovered under this Schedule 1-A1 include without limitation, any costs of

direct resources, system maintenance, debt service for financing capital purchases associated

with providing Schedule 1-A1 Service, a proportionate allocation of corporate overhead

associated with providing Schedule 1-A1 Service, and other costs associated with providing

Schedule 1-A1 Service (“Schedule 1-A1 Costs”).


Deleted: Tariff Administration Service

Deleted: The

Deleted: i

Deleted: i

Deleted: S

Deleted: to be

Deleted: Charge

Deleted: :

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For Network Integration Transmission Service, the billing determinants are the 12 month

average of the Transmission Customer’s coincident Zonal Demands used to determine the

Demand Charges under Schedule 9 multiplied by the number of all hours of the applicable

month. For Point-to-Point Transmission Service, the billing determinants are the MW of the

reservation multiplied by the number of hours reserved for the applicable month.

iii. Rate Formula

Annually, the Transmission Provider will determine the Schedule 1-A1 Service rate for each

calendar year as described in the Schedule 1-A1 template.

b. Schedule 1-A1 Charges to Transmission Customers

The Schedule 1-A1 charge is the product of the Schedule 1-A1 rate and the Transmission

Customer’s billing determinants.

2. Transmission Service Request Charges:

The Transmission Customer shall pay the Transmission Provider a charge for each new

Transmission Service Request as follows:

(a) For Firm Point-To-Point Transmission Service:

Reservations less than one month: $100

Reservations one month or longer: $200

(b) For Non-Firm Point-To-Point Transmission Service:

Each Reservation: $0.

However, the Transmission Customer shall have this fee rebated to it once the

Transmission Customer becomes legally obligated to pay the applicable Firm Point-To-Point

Transmission Service charges under this Tariff or if the requested Firm Point-To-Point

Transmission Service is denied by the Transmission Provider.

3. Schedule 1-A2 Transmission Congestion Rights Administration Service

Deleted: An administration charge shall be applied to all transmission service under this Tariff to cover the Transmission Provider’s expenses related to administration of this Tariff. For Point-To-Point Transmission Service this charge shall be up to $0.43 per MW per hour for all capacity reserved.

Deleted: this charge shall be up to $0.43 per MW per hour for

Deleted: The charge per MW per hour shall be the same for Point-To-Point Transmission Service as for Network Integration Transmission Service.

Deleted: For each calendar year, the Transmission Provider shall establish a rate for this administration charge by dividing projected expenses based on its budget for the calendar year divided by the projected annual Schedule 1-A billing units for the calendar year. The Transmission Provider shall reconcile actuals to budgeted figures and shall adjust charges for the following calendar year to reflect either over or under recoveries of its costs for the prior year to allow the Transmission Provider to recover its actual costs. In projecting and recovering its expenses, the Transmission Provider shall recover 100% of its total expenses through this charge up to the cap of $0.43 per MW per hour for all transmission service under the Tariff.¶

Deleted: i

Deleted: ii

Deleted: 3. Bad Debt Expense:¶The Transmission Provider shall include in its charges under this Schedule a component to cover estimated bad debts. The Transmission Provider shall reconcile actuals to estimates and shall adjust future monthly charges to reflect either over or under recoveries.¶

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Transmission Congestion Rights (“TCR”) administration service is provided by the

Transmission Provider to all Market Participants that hold TCRs issued and settled by the

Transmission Provider (“TCR Holder”). This service includes the provision of: (1) TCR

administration through allocation, assignment, auction or any other process under this Tariff; (2)

simultaneous feasibility tests and other applicable studies to determine the total TCRs that can be

accommodated by the Transmission System; (3) TCR tools; and, (4) a secondary market for

TCRs (“Schedule 1-A2 Service”).

a. Schedule 1-A2 Service Charge



i. Costs


resources, system maintenance, debt service for financing capital purchases associated with

providing Schedule 1-A2 Service, a proportionate allocation of corporate overhead, and all other

costs associated with providing Schedule 1-A2 Service (“Schedule 1-A2 Costs”).


The Schedule 1-A2 billing determinant is the total amount of TCR volume in MWh for

all TCR Holders for each billing period.

iii. Rate Formula



b. Charges To TCR Holders

The Schedule 1-A2 charge is the product of the Schedule 1-A2 rate and the TCR

Holder’s billing determinants.

Commented [MR37]: What is this?

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4. Schedule 1-A3 Integrated Marketplace Clearing Administration Service

Integrated Marketplace clearing administration service is provided by the Transmission

Provider to all Market Participants that participate in transactions pursuant to Attachment AE of


AH of this Tariff. This service includes the provision of: (1) market settlements; (2) credit

evaluation and risk mitigation services; (3) market monitoring functions; (4) information

technology support; and, (5) customer service (“Schedule 1-A3 Service”).

a. Integrated Marketplace Clearing Administration Service Charge



i. Costs


resources, corporate overhead (including a proportionate allocation of indirect costs associated

with providing Schedule 1-A3 Service), and all other costs associated with providing Schedule 1-

A3 Service (“Schedule 1-A3 Costs”).


The Schedule 1-A3 billing determinants as expressed in MWh are: 1) all Real-Time

Energy injected into and withdrawn from the Transmission System; 2) all Import Interchange

Transactions in Real-Time and all Export Interchange Transactions in Real-Time; and, (3) all

cleared Virtual Energy Bids and all cleared Virtual Energy Offers.

iii. Rate Formula




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5. Schedule 1-A4 Integrated Marketplace Facilitation Administration Service

Integrated Marketplace facilitation administration service is provided by the

Transmission Provider to all Market Participants that participate in transactions, except for

cleared Virtual Energy Bids and cleared Virtual Energy Offers, pursuant to Attachment AE of


AH of this Tariff. This service includes the provision and operation of the: (1) Day-Ahead

Market; (2) Real-Time Balancing Market; and, (3) Reliability Unit Commitment processes

(“Schedule 1-A4 Service”).

a. Integrated Marketplace Facilitation Administration Service Charge



i. Costs


resources, system maintenance, debt service (including costs of financing capital purchases

associated with providing Schedule 1-A4 Service), corporate overhead (including a proportionate

allocation of indirect costs associated with providing Schedule 1-A4 Service), and other costs

associated with providing Schedule 1-A4 Service (“Schedule 1-A4 Costs”).


The Schedule 1-A4 billing determinants are: 1) all Real-Time Energy injected into and

withdrawn from the Transmission System; and, 2) all Import Interchange Transactions in Real-

Time and all Export Interchange Transactions in Real-Time.

iii. Rate Formula

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The Schedule 1-A4 charge is the product of the Schedule 1-A4 rate and the Market Participant’s billing determinants.

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Addendum 1 To Schedule 1-A

ANNUAL FORMULA RATE IMPLEMENTATION PROTOCOLS

SOUTHWEST POWER POOL

Section 1 Applicability

The formula rate template and these Annual Formula Rate Implementation

Protocols (collectively, the “Formula Rate”) comprise SPP’s filed Schedule 1-A

Tariff Administration Services rates. SPP shall follow the Formula Rate to

calculate annually its Transmission Administration Service Rate (“Schedule 1-A1

Rate”), Transmission Congetstion Rights Administration Service Rate (“Schedule

1-A2 Rate”), Integrated Marketplace Clearing Administration Service rate

(“Schedule 1-A3 Rate”), and Integrated Marketplace Facilitation Administration

Service rate (“Schedule 1-A4 Rate”); (collectively “Rates”). The Formula Rate

and the charges produced thereunder shall be effective for service on and after

January 1, 2021. The Formula Rate shall be applicable on and after January 1 of

each calendar year for service from January 1 – December 31 of each calendar

year (the “Rate Year”), subject to the true-up procedures of this Addendum 1.

Section 2 Annual Updates

a. During or before the fourth quarter of each calendar year, SPP, shall determine

and post, at a time to coincide with the SPP annual budget report to the SPP

Board of Directors being posted, its Annual Update to be effective during the next

Rate Year. The Annual Update shall consist of the following:

(i) a data-populated version of the Formula Rate template setting forth the

projected Rates for the next Rate Year (“Projected Rates”) plus any

applicable True-up Adjustment, as defined in Section 3.a., produced by

operation of the Formula Rate;

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(ii) supporting documentation, including, but not limited to, fully functioning

Excel files (or such other native format files), required to support,

demonstrate and explain information upon which the Annual Update is

based;

(vi) disclosure of the following changes to the extent any has taken effect since

January 1, 2021, and affects the Formula Rate or calculation of the Annual

Update or the allocation of costs or revenues to SPP’s Rates: changes in

(a) any FERC ratemaking orders applicable to the SPP Formula Rate and

(b) the accounting policies, practices or procedures of SPP, (changes in

items (a) and (b) collectively referred to as “Material Changes”);

b. SPP shall contemporaneously post and notify its customers via the SPP Board of

Director email exploder, of the availability of the Annual Update on SPP.org

website. The posting shall include fully functioning Excel file (or such other

native format file) of all materials contained in the Annual Update.

c. The Annual Update for the new Rate Year shall:

(i) be based upon SPP’s most recent budget and other information for the new

Rate Year, that reasonably projects costs properly recorded (or to be

recorded) on the books and records of SPP consistent with FERC’s orders

establishing generally applicable ratemaking policies, SPP’s policies, and

the SPP OATT; and

(ii) compute the Projected Rates.

Section 3 True-up Adjustment

Assuming an effective date of January 1, 2021, the true up process for the 2021

budget year would occur over two budget cycles. During the 2022 budget

process, we would calculate the estimated over/under recovery for 2021 using

forecasted data, consisting of actual data available for 2021 and forecasted data

for the remainder of 2021. Comparing the forecasted data available for both our

tariff administrative fee revenue and our net revenue requirement to the respective

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budgeted amounts, we would arrive at a projected over/under recovery for 2021 to

be included as a true-up adjustment in the 2022 budget assumptions. During the

2023 budget cycle, we would calculate the final over/under recovery for 2021

using actual results for both the tariff administrative fee revenue and net revenue

requirement in comparison to the 2021 approved budget. The final over/under

recovery for 2021 would then be compared against the estimated true-up

calculation included in the 2022 budget, and the difference would be included as a

true-up adjustment in the 2023 budget assumptions. Also included in the 2023

budget assumptions, would be the estimated over/recovery true-up adjustment for

2022.

An example is provided below, in Exhibit A, to illustrate the process that would

occur with each rate schedule as it relates to true up process.

Section 4 Changes to Formula Rate Initiated by SPP

Any changes to the Formula Rate initiated by SPP, including any changes

necessitated by Material Changes, may only be implemented as a result of a filing

with FERC under Section 205 or 206 of the FPA.

Section 5 Changes to the Stated Inputs in the Formula Rate

a. The following Formula Rate inputs shall be stated values to be used in the

Formula Rate (both for the Annual Update and True-up Adjustment) until

changed by a filing pursuant to Section 205 of the FPA or by a proceeding under

Section 206 of the FPA: (a) the allocation percentages to determine salary,

benefits and direct employee cost; and (b) the allocation percentages to determine

network and communication expenses.

EXHIBIT A

EXAMPLE OF 2021 TRUE-UP ADJUSTMENT:

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Example – RS X

Budget Year 2021, RS X assumed a Net Revenue Requirement (and Administrative Fee

Revenue) of $50.0MM.

During the 2022 budget cycle work in the summer of 2021, the forecasted Net Revenue Requirement and Administrative Fee Revenue for 2021 is $49.0MM and $52.0MM, respectively.

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Attachment F, Attachment 1 to the NITS Agreement ATTACHMENT 1 TO THE NETWORK INTEGRATION TRANSMISSION

SERVICEAGREEMENT

BETWEEN SOUTHWEST POWER POOL AND _______________ SPECIFICATIONS FOR NETWORK INTEGRATION TRANSMISSION SERVICE

1.0 Network Resources

The Network Resources are listed in Appendix 1.

2.0 Network Loads

The Network Load consists of the bundled native load or its equivalent for Network

Customer load in the _______________ Zone(s) as listed in Appendix 3.

The Network Customer’s Network Load shall be measured on an hourly integrated basis,

by suitable metering equipment located at each connection and delivery point, and each

generating facility. The meter owner shall cause to be provided to the Transmission

Provider, Network Customer and applicable Transmission Owner, on a monthly basis

such data as required by Transmission Provider for billing. The Network Customer’s

load shall be adjusted, for settlement purposes, to include applicable Transmission Owner

transmission and distribution losses, as applicable, as specified in Sections 8.5 and 8.6,

respectively. For a Network Customer providing retail electric service pursuant to a state

retail access program, profiled demand data, based upon revenue quality non-IDR meters

may be substituted for hourly integrated demand data. Measurements taken and all

metering equipment shall be in accordance with the Transmission Provider’s standards

and practices for similarly determining the Transmission Provider’s load. The actual

hourly Network Loads, by delivery point, internal generation site and point where power

may flow to and from the Network Customer, with separate readings for each direction of

flow, shall be provided.

3.0 Affected Zone(s) and Intervening Systems Providing Transmission Service

The affected Zone(s) is/are ______________. The intervening systems providing

transmission service are _______________.

4.0 Electrical Location of Initial Sources

Deleted: ¶

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See Appendix 1.

5.0 Electrical Location of the Ultimate Loads

The loads of _______________ identified in Section 2.0 hereof as the Network Load are

electrically located within the ________________ Zone(s).

6.0 Delivery Points

The delivery points are the interconnection points of _______________ identified in

Section 2.0 as the Network Load.

7.0 Receipt Points

The Points of Receipt are listed in Appendix 2.

8.0 Compensation

Service under this Service Agreement may be subject to some combination of the charges

detailed below. The appropriate charges for individual transactions will be determined in

accordance with the terms and conditions of the Tariff.

8.1 Transmission Charge

Monthly Demand Charge per Section 34 and Part V of the Tariff.

8.2 System Impact and/or Facility Study Charge

Studies may be required in the future to assess the need for system reinforcements in light

of the ten-year forecast data provided. Future charges, if required, shall be in accordance

with Section 32 of the Tariff.

8.3 Direct Assignment Facilities Charge

8.4 Ancillary Service Charges

8.4.1 The following Ancillary Services are required under this Service Agreement.

a) Scheduling, System Control and Dispatch Service per Schedule 1 of the

Tariff.

b) Tariff Administration Service per Schedule 1-A1 of the Tariff.

c) Reactive Supply and Voltage Control from Generation Sources Service

per Schedule 2 of the Tariff.

d) Regulation and Frequency Response Service per Schedule 3 of the Tariff.

e) Energy Imbalance Service per Schedule 4 of the Tariff.

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f) Operating Reserve - Spinning Reserve Service per Schedule 5 of the

Tariff.

g) Operating Reserve - Supplemental Reserve Service per Schedule 6 of the

Tariff.

The Ancillary Services may be self-supplied by the Network Customer or

provided by a third party in accordance with Sections 8.4.2 through 8.4.4, with the

exception of the Ancillary Services for Schedules 1, 1-A, and 2, which must be

purchased from the Transmission Provider.

8.4.2 In accordance with the Tariff, when the Network Customer elects to self-supply

or have a third party provide Ancillary Services, the Network Customer shall

indicate the source for its Ancillary Services to be in effect for the upcoming

calendar year in its annual forecasts. If the Network Customer fails to include this

information with its annual forecasts, Ancillary Services will be purchased from

the Transmission Provider in accordance with the Tariff.

8.4.3 When the Network Customer elects to self-supply or have third party provide

Ancillary Services and is unable to provide its Ancillary Services, the Network

Customer will pay the Transmission Provider for such services and associated

penalties in accordance with the Tariff as a result of the failure of the Network

Customer’s alternate sources for required Ancillary Services.

8.4.4 All costs for the Network Customer to supply its own Ancillary Services shall be

the responsibility of the Network Customer.

8.5 Real Power Losses - Transmission

The Network Customer shall be responsible for losses in accordance with Attachment M

of the Tariff.

8.6 Real Power Losses - Distribution

8.7 Power Factor Correction Charge

8.8 Redispatch Charge

Redispatch charges shall be in accordance with Section 33.3 of the Tariff.

8.9 Wholesale Distribution Service Charge

8.10 Network Upgrade Charges

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8.11 Meter Data Processing Charge

8.12 Other Charges

9.0 Credit for Network Customer-Owned Transmission Facilities

10.0 Designation of Parties Subject to Reciprocal Service Obligation

11.0 Other Terms and Conditions

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ATTACHMENT L, TREATMENT OF REVENUES … IV. Distribution of Other Revenues

1. Revenues associated with redispatch service will be paid to the Resource owner

providing the service for the Transmission Provider in accordance with the

settlement procedures specified in Attachment AE.

2. Revenues associated with Reactive Supply and Voltage Control from Generation

Sources Services under Schedule 2 of the Tariff will be paid to the generation

owner providing the service for the Transmission Provider consistent with the

development of the charges under Schedule 2.

3. Energy or revenues received as compensation for transmission losses shall be

distributed consistent with Attachment M to the Tariff.

4. Revenues associated with Scheduling, System Control and Dispatch Service

under Schedule 1 shall be allocated to the Transmission Owners within the

transmission system that provide such service as follows:

a. For Firm or Non-Firm Point-To-Point Transmission Service, for

through and out transactions, Schedule 1 charge revenues shall be

allocated to Transmission Owners in proportion to the respective

scheduling revenue requirement of each such Transmission Owner

associated with the provision of this service.

b. For Customers taking Firm or Non-Firm Point-To-Point Transmission

Service, for transactions into and within the Transmission System,

Schedule 1 charge revenues shall be allocated to Transmission Owner

whose Zone is the Point of Delivery.

c. For Customers taking Network Integration Transmission Service,

Schedule 1 charge revenues shall be allocated to Transmission Owner

in whose Zone the load is located.

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5. Revenues associated with Tariff Administration Service under Schedule 1-A1

will remain with the Transmission Provider to pay for the costs of providing that

service.

6. Payments associated with penalties imposed under this Tariff will be used to

reduce the Transmission Provider's Scheduling and Tariff Administration Service

costs (though the non-penalty portion of the charge will go back to the

Transmission Owner(s) that actually provided the service).

7. Transmission Owner costs associated with System Impact and Facilities Studies

compensated by the Transmission Customer shall go to the appropriate

Transmission Owner(s).

8. The revenues associated with Direct Assignment Facilities shall go directly to the

Transmission Owner(s) owning the facilities.

9. The revenues associated with Network Upgrades, not otherwise provided for in

Section III of this Attachment L, shall be first assigned to the Transmission

Owner building the Network Upgrades to meet the annual revenue requirements

of such facilities. If multiple Transmission Owners construct the facilities, the

revenues shall be shared in accordance with each Transmission Owner’s

respective revenue requirement for such facilities or as otherwise agreed by the

Transmission Owners. The remaining revenues shall be allocated in accordance

with Section II of this Attachment L.

10. The revenues associated with Wholesale Distribution Service shall go directly to

the Transmission Owner(s) owning the facilities consistent with Schedule 10.

11. Any additional revenues received under Section 22.1 of the Tariff shall be treated

in the same manner as revenues under Section II.B.2 for single-owner Zones, and

Section II.C.2 for multi-owner Zones, of this Attachment L.

12. All revenues received by the Transmission Provider to compensate a

Transmission Owner(s) not party to a generation interconnection agreement for

the construction of Network Upgrades and Distribution Upgrades (as defined in

Attachment V to the Tariff) associated with such generation interconnection

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agreement will be distributed by the Transmission Provider to the applicable

Transmission Owner(s).

ATTACHMENT O, TRANSMISSION PLANNING PROCESS

IV. Other Planning Studies

1) Sponsored Upgrade Studies

Any entity may request that a Sponsored Upgrade be built. SPP will evaluate the

impact of any proposed Sponsored Upgrade on Transmission System reliability

and identify any necessary mitigation of these impacts. The proposed Sponsored

Upgrade shall not be approved as a Sponsored Upgrade if it has been previously

identified and included in the current SPP Transmission Expansion Plan as either

1) an upgrade required to satisfy requests for transmission service; 2) an upgrade

required to satisfy a Generator Interconnection Request; 3) an approved ITP Upgrade;

4) an upgrade within approved Balanced Portfolios; or 5) an approved high priority

upgrade. Such entity must be willing to assume the cost of such Sponsored

Upgrade, study costs, and any cost associated with such necessary mitigation.

The proposed Sponsored Upgrade will be submitted to the proper stakeholder

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

2) 20-Year Assessments

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

once every five years, or more frequently if approved by the SPP Board of

Directors.

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

planning horizon and address, at a minimum, facilities 300 kV and above

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needed in year 20. This assessment is not intended to review each

consecutive year in the planning horizon.

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

develop the scope for each 20-Year Assessment and post the scope on the

SPP website.

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

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

criteria, assumptions and data underlying the report shall be posted on the

SPP website.

3) High Priority Studies

a) The Transmission Provider shall perform high priority studies in

accordance with Attachment O of this Tariff and the Integrated

Transmission Planning Manual which shall be maintained on the SPP

website.

b) Potential Balanced Portfolios, as developed through the process specified

in Section IV.4 of this Attachment O, shall be considered to be high

priority studies.

c) The stakeholders may request high priority studies, including a request for

the Transmission Provider to study potential upgrades or other

investments necessary to integrate any combination of resources, whether

demand resources, transmission, or generation, identified by the

stakeholders. Annually, the costs of up to three high priority studies

requested by the stakeholders and performed by the Transmission Provider

shall be recovered pursuant to Schedule 1-A1 of this Tariff. A high

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priority study of a potential Balanced Portfolio initiated by the

Transmission Provider will not be considered a stakeholder request

pursuant to this Section IV.3.c of this Attachment O.

d) The Transmission Provider, in consultation with the stakeholders, shall

develop the scope for each high priority study and post the scope(s) on the

SPP website.

e) Each study shall include:

i) Quantification of benefits and costs in accordance with this

Attachment O and the Integrated Transmission Planning Manual;

and

ii) An analysis of the sensitivity of the economics of the upgrades

included in the high priority study to changes in assumptions.

f) The Transmission Provider shall solicit input from the stakeholders and

the Regional State Committee regarding the appropriate sensitivity

analyses to be performed.

g) For each high priority study the Transmission Provider shall publish a

report, including but not limited to, the study input assumptions, the

estimated cost of the upgrades, any third party impacts, the expected

economic benefits of the upgrades, and identify reliability impacts, if any,

of the upgrades. The report and related studies and the criteria,

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

website, with password protected access if required to preserve the

confidentiality of information in accordance with the provisions of the

Tariff and the SPP Membership Agreement and to address Critical Energy

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Infrastructure Information (CEII) requirements. The CEII compliant

redacted version of the report shall be posted on the SPP website. The

redacted version shall include instructions for acquiring the complete

version of the report.

h) The Transmission Provider may recommend, based on the results of a high

priority study, a high priority upgrade for inclusion in the SPP

Transmission Expansion Plan in accordance with the approval process set

forth in Section V of this Attachment O.

4) Evaluation of Potential Balanced Portfolios

a) The Transmission Provider shall solicit input from stakeholders on

combinations of potential economic upgrades to be evaluated as potential

Balanced Portfolios.

b) Each economic upgrade to be included in a potential Balanced Portfolio:

i) Must include a 345 kV or higher voltage facility;

ii) May include lower voltage transmission facilities needed to

integrate the 345 kV or higher facilities and achieve the benefits;

however, the cost of the lower voltage transmission facilities

cannot exceed the cost of the 345 kV or higher facilities included

in the economic upgrade; and

iii) An economic upgrade that includes lower voltage transmission

facilities for which the cost of such facilities exceeds the cost of

the 345 kV or higher facilities constituting the economic upgrade

may be included in the evaluation of a potential Balanced

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Portfolio, if a Project Sponsor agrees to bear the portion of the cost

of the lower voltage facilities that is in excess of the cost of the 345

kV or higher facilities.

iv) Will include an evaluation of the costs of the upgrades, including

any cost impacts potentially allocable to the Transmission Provider

or a Zone(s) from a third party upgrade(s) required to relieve

congestion on a neighboring system due to the construction of the

potential Balanced Portfolio.

c) The Transmission Provider shall determine for each Zone the net present

value of the revenue requirements of each potential Balanced Portfolio as

follows:

i) The revenue requirements for each potential Balanced Portfolio

shall be calculated as if all of the upgrades associated with the

potential Balanced Portfolio are simultaneously available to the

power system. This requirement is for evaluation purposes only

and shall not restrict the timing of the construction of individual

upgrades within a Balanced Portfolio approved by the SPP Board

of Directors.

ii) Based on input from the Transmission Owners and other pertinent

information, the Transmission Provider shall estimate the

construction costs of each upgrade in the potential Balanced

Portfolio.

iii) For each upgrade in the potential Balanced Portfolio, the

Transmission Provider shall use the transmission fixed charge

rate(s) for the appropriate Transmission Owner(s) to estimate the

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revenue requirements. In each annual planning cycle, the

Transmission Owner shall supply its fixed charge rate to the

Transmission Provider.

iv) The fixed charge rate(s) shall take account of all costs necessary to

support the upgrade in the potential Balanced Portfolio, including

but not limited to, operation and maintenance expenses,

depreciation, property and payroll taxes, income taxes, if

applicable, return on investment and any other factors affecting the

revenue requirement associated with the upgrade.

v) The revenue requirements also shall include any specific costs that

are projected to be incurred by the Transmission Provider or a

Zone(s) as a result of third-party impacts due to one or more

upgrades within a proposed Balanced Portfolio.

vi) The revenue requirements for the potential Balanced Portfolio shall

equal the sum of the revenue requirements of the upgrades that

comprise the potential Balanced Portfolio.

vii) The Transmission Provider shall estimate the cost for each Zone by

allocating the revenue requirements for the potential Balanced

Portfolio to each Zone based on its Region-wide Load Ratio Share

forecasted over the ten year period analyzed.

viii) If any costs of an upgrade in the potential Balanced Portfolio will

be borne by other funding mechanisms, such costs shall not be

included in the determination of the net present value of the

revenue requirements for the potential Balanced Portfolio.

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d) The Transmission Provider shall determine for each Zone the net present

value of the benefits of each potential Balanced Portfolio as follows:

i) The benefits from each potential Balanced Portfolio shall be

calculated as if all of the upgrades associated with the potential

Balanced Portfolio are simultaneously available to the power

system.

ii) The Transmission Provider shall use an adjusted production cost

metric to analyze the benefits of the potential Balanced Portfolio,

where adjusted production cost is the production cost minus

revenues from sales plus cost of purchases. As described in

Section IV.6 of this Attachment O, the Transmission Provider shall

continue to evaluate and explore with the stakeholders any

additional metrics and criteria which have quantifiable economic

effects.

iii) The adjusted production cost benefit for each Zone shall equal the

difference between the adjusted production cost with the potential

Balanced Portfolio modeled and without the potential Balanced

Portfolio modeled.

iv) The Transmission Provider shall estimate the annual benefits for

each Zone over the same ten-year period as used to determine the

costs by calculating the annual benefits for at least three specific

years in the ten-year time period and interpolating the annual

benefits for the remaining years.

e) A potential Balanced Portfolio shall meet the following conditions:

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i) Cost Beneficial: The sum of the benefits of the potential Balanced

Portfolio determined in Section IV.4.d of this Attachment O must

equal or exceed the sum of the costs determined in Section IV.4.c

of this Attachment O; and

ii) Balanced: For each Zone, the sum of the benefits of the potential

Balanced Portfolio determined in Section IV.4.d of this

Attachment O must equal or exceed the sum of the costs

determined in Section IV.4.c of this Attachment O. Additionally,

the balance may be achieved through the provisions set forth in

Section IV.5 of this Attachment O.

f) In developing a potential Balanced Portfolio, the Transmission Provider

shall timely publish a report, including but not limited to, the study input

assumptions, the estimated costs included in the potential Balanced

Portfolio, and the expected economic benefits of the potential Balanced

Portfolio. With regard to such report, the Transmission Provider shall

comply with the information sharing and reporting requirements in Part

VII (Information Exchange) and Section IV.3 (High Priority Studies) of

this Attachment O, including the requirements for treatment of

confidential information.

5) Options for Achieving a Balanced Portfolio

a) Section IV.4 of this Attachment O sets forth provisions to achieve a

Balanced Portfolio when there are deficient Zones. A deficient Zone is a

Zone where the costs allocated to the Zone in Section IV.4.c of this

Attachment O exceed the benefits allocated to the Zone in Section IV.4.d

of this Attachment O, including any additional costs or benefits derived

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from the application of the provisions in this Section IV.5 of this

Attachment O.

b) In order to achieve a Balanced Portfolio, the Transmission Provider may

include transmission upgrades that do not adhere to the voltage

requirements of Sections IV.4.b.i and ii of this Attachment O.

c) If including the lower voltage transmission facilities does not achieve a

Balanced Portfolio, the Transmission Provider may balance the portfolio

by transferring a portion of the Base Plan Zonal Annual Transmission

Revenue Requirement and/or the Zonal Annual Transmission Revenue

Requirement from the deficient Zone(s) to the Balanced Portfolio Region-

wide Annual Transmission Revenue Requirement. Transmission Provider

shall include the following constraints in this assessment:

i) Limit the amount to be transferred from the Base Plan Zonal

Annual Transmission Revenue Requirement and/or the Zonal

Annual Transmission Revenue Requirement to the Balanced

Portfolio Region-wide Annual Transmission Revenue Requirement

to the minimum amount that will balance the portfolio over the

ten-year period analyzed;

ii) Transfer from the Base Plan Zonal Annual Transmission Revenue

Requirement first, then, if necessary, transfer from the Zonal

Annual Transmission Revenue Requirement; and

iii) For each Zone, meet the conditions specified in Section IV.4.e.ii of

this Attachment O.

6) Development of Additional Benefit Metrics for Balanced Portfolios

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a) The Transmission Provider shall continue to evaluate and explore with the

stakeholders via the transmission planning process any additional metrics

and criteria which have quantifiable economic effects, such as:

i) Reduction in system losses;

ii) Differing environmental impacts;

iii) Improvement to capacity margin and operating reserve

requirements;

iv) Energy, capacity and ancillary service market facilitation;

v) Increased competition in wholesale markets;

vi) Reliability enhancement, including storm hardening and black start

capability; and

vii) Critical infrastructure and homeland security.

b) Any subsequent adjustment to the metrics and criteria for evaluating

potential Balanced Portfolios developed by the Transmission Provider,

with input from the stakeholders, shall be proposed through Tariff

amendments.

7) Evaluation of Proposed Interregional Projects

a) Proposed Interregional Projects shall be developed through the

Transmission Provider’s participation in an Interregional Planning Process

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with one or more Interregional Planning Regions in accordance with the

provisions of Section VIII of this Attachment O.

b) The Transmission Provider shall facilitate a regional review of the

proposed Interregional Projects identified in the Coordinated System Plan

(CSP) report developed and issued pursuant to the applicable Interregional

Planning Process. The regional review will be subject to the timelines

identified in the respective Interregional Planning Region procedures in

accordance with the applicable Addendum(s) to this Attachment O.

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

develop the Regional Review Methodology which shall be posted on the

Transmission Provider’s website. The methodology will contain, at a

minimum, the specific procedures to:

i) Determine the assumptions and criteria necessary to complete the

regional review of proposed Interregional Projects.

ii) Determine the regional models to be used in the evaluation of

proposed Interregional Projects.

iii) Determine the appropriate updates to the regional models to be

used in the evaluation of proposed Interregional Projects.

iv) Quantify the benefits of each proposed Interregional Project using

the Transmission Provider’s regional benefit metrics consistent

with Section III.7 of this Attachment O.

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d) For an Interregional Project that is reviewed pursuant to the Regional

Review Methodology, the Transmission Provider shall perform the

following types of transmission planning studies:

i) Projects Addressing Reliability Issues Description of Analyses:

The study scope will determine what types of analyses will be

performed. These analyses will be based on the issue that is being

addressed by the interregional transmission project. At a minimum,

a steady state N-1 analysis will be performed. If needed, the scope

will also include directives to perform stability and/or dynamic

analyses. Additional analyses can be performed if determined to be

needed by the Transmission Provider, in consultation with the

stakeholder working group assigned to analyze transmission

reliability issues.

ii) Projects Addressing Economic Issues Description of Analyses:

The analyses that will be performed will be based on the benefit

metrics that will be used as determined by the Transmission

Provider, in consultation with the stakeholder working group

assigned to analyze economic issues. At a minimum, a security

constrained unit commitment/security constrained economic

dispatch analysis will be utilized for the calculation of adjusted

production cost. Additional analyses will be included in the scope

as determined by the Transmission Provider, in consultation with

the stakeholder working groups, on what metrics to utilize.

iii) Projects Addressing Public Policy Issues Description of Analyses:

Public policy projects will be evaluated to determine whether or

not the transmission project will aid in meeting the applicable

public policy requirement, and if so, is it more efficient or cost

effective than regional solutions. The analysis will use a security

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constrained economic dispatch and unit commitment model to

perform a curtailment and dispatch study. Additional analyses

performed in the latest ITP may also be utilized as determined by

the Transmission Provider, in consultation with the applicable

stakeholder working groups.

e) For each regional review of a proposed Interregional Project, the

Transmission Provider shall publish a report which includes, but is not

limited to, the following:

i) The results of the regional review analysis and a comparison to the

results contained in the CSP report;

ii) The study input assumptions and criteria used to assess the

proposed Interregional Project;

iii) The proposed Interregional Project’s reliability impacts on the

Transmission Provider’s system and impacts on third parties not

participating in the applicable Interregional Planning Process;

iv) Any expected benefits of the proposed Interregional Project; and

v) The Transmission Provider shall make a recommendation whether

to approve the proposed Interregional Project and the allocation of

proposed Interregional Project costs between the Interregional

Planning Regions.

f) The Transmission Provider’s report shall be posted on the Transmission

Provider’s website. If the Transmission Provider’s report contains

confidential information in accordance with the provisions of the Tariff,

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the SPP Membership Agreement, or CEII requirements, the report will be

password protected to preserve the confidentiality of information and a

redacted version of the report shall be posted on the Transmission

Provider’s website. The redacted version shall include instructions for

acquiring the complete version of the report.

g) The Transmission Provider’s report shall be reviewed by the appropriate

stakeholder group(s) in accordance with the provisions of Section II of this

Attachment O. The stakeholder group(s) and the Transmission Provider

will each provide a recommendation to the Markets and Operations Policy

Committee. The Markets and Operations Policy Committee shall make a

recommendation to the SPP Board of Directors regarding the approval of a

proposed Interregional Project.

h) The SPP Board of Directors shall review all reports and recommendations

related to the regional review of the proposed Interregional Project.

i) The SPP Board of Directors may approve a proposed Interregional

Project only where the benefits equal or exceed the costs for the

SPP Region.

ii) The Transmission Provider shall notify the applicable interregional

joint planning committee whether a proposed Interregional Project

has been approved by the SPP Board of Directors.

i) To qualify as an approved Interregional Project, the proposed Interregional

Project must be approved by the SPP Board of Directors and the

corresponding Interregional Planning Region in accordance with the

applicable Interregional Planning Process.

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j) Upon approval by the corresponding Interregional Planning Region and

the SPP Board of Directors, the Transmission Provider’s portion of the

approved Interregional Project will be constructed in accordance with

Section VI of this Attachment O.

IX. Recovering Costs Associated with the Planning Process

1) The Transmission Provider’s costs associated with the planning process and associated studies set forth in this Attachment O shall be recovered pursuant to Schedule 1-A1 of the Tariff.

2) The Transmission Provider’s costs associated with studies for potential Sponsored

Upgrades, shall be the responsibility of the entities requesting such studies. 3) The Transmission Provider’s costs for studies associated with requests for long-

term firm transmission service shall be recovered pursuant to Sections 19 and 32 of the Tariff.

4) The Transmission Provider’s costs for studies associated with requests for

interconnection service shall be recovered pursuant to Attachment V of the Tariff.

Deleted: ¶

ATTACHMENT AE INTEGRATED MARKETPLACE

Attachment AE

Table of Contents 1. Introduction 1.1 Definitions and Acronyms 1.1 Definitions A 1.1 Definitions B 1.1 Definitions C 1.1 Definitions D 1.1 Definitions E 1.1 Definitions F 1.1 Definitions G 1.1 Definitions H 1.1 Definitions I 1.1 Definitions J 1.1 Definitions L 1.1 Definitions M 1.1 Definitions N 1.1 Definitions O 1.1 Definitions P 1.1 Definitions Q 1.1 Definitions R 1.1 Definitions S 1.1 Definitions T 1.1 Definitions U 1.1 Definitions V 2. Market Participant Obligations 2.1 Service Agreement 2.2 Application and Asset Registration 2.3 Market Manipulation 2.4 Commitment and Dispatch 2.5 Provision of Load and Generation Data 2.6 Dispatchable Demand Response Resource 2.7 Block Demand Response Resource 2.8 Aggregators of Retail and Wholesale Customers 2.8.1 Aggregators of Retail Customers 2.8.2 Aggregators of Wholesale Customers 2.9 Combined Cycle Resource 2.10 Operating Reserve Certification 2.10.1 Spin Qualified Resources

2.10.2 Supplemental Qualified Resources 2.10.3 Regulation Qualified Resources 2.11 Must-Offer Requirement 2.11.1 Day-Ahead Market 2.11.2 Reliability Unit Commitment and the Real-Time Balancing Market 2.12 Non-Conforming Load 2.13 Market Protocols and SPP Criteria 2.14 External Dynamic Resource 2.15 Provision of Wind Forecast Data 2.16 Grandfathered Agreement Carve Out 3. Transmission Provider Rights and Obligations 3.1 Transmission Provider Scope of Services 3.1.1 Trading Hub Establishment and Modification 3.1.2 Forecasting 3.1.3 Reserve Zone Establishment 3.1.4 Operating Reserve and Instantaneous Load Capacity Requirements 3.1.5 Outage Scheduling and Reporting

3.1.6 Resource Hub Establishment 3.2 Market Protocols 3.3 Integrated Marketplace Operations 3.4 Violation Relaxation Limit Reporting 3.5 Integrated Marketplace Pricing 3.6 Integrated Marketplace Settlements 3.7 Integrated Marketplace Participation Readiness

3.8 Integrated Marketplace Counterparty 3.9 Calculation of Net Benefits Test for Compensation of Demand Response Load 3.10 Electronic Delivery of Data to the Commission 4. Pre-Day-Ahead Period Activities 4.1 Offer Submittal 4.1.1 Offer Caps and Floors 4.1.2 Additional Provisions for Non-Traditional Resources 4.2 Provisions for Non-Resource Related Offers 4.2.1 Virtual Energy Offers 4.2.2 Import Interchange Transaction Offers 4.3 Bid Submittal 4.3.1 Demand Bids 4.3.2 Virtual Energy Bids 4.3.3 Export Interchange Transaction Bids 4.4 Through Interchange Transactions 4.5 Multi-Day Reliability Assessment 4.5.1 Multi-Day Reliability Assessment Inputs 4.5.2 Multi-Day Reliability Assessment Analysis 4.5.3 Multi-Day Reliability Assessment Results 5. Day-Ahead Period Activities

5.1 Day-Ahead Market 5.1.1 Day-Ahead Market Inputs 5.1.2 Day-Ahead Market Execution 5.1.3 Day-Ahead Market Results 5.2 Day-Ahead Reliability Unit Commitment 5.2.1 Day-Ahead Reliability Unit Commitment Inputs 5.2.2 Day-Ahead Reliability Unit Commitment Execution 5.2.3 Day-Ahead Reliability Unit Commitment Results 6. Operating Day Activities 6.1 Intra-Day Reliability Unit Commitment 6.1.1 Intra-Day Reliability Unit Commitment Inputs 6.1.2 Intra-Day Reliability Unit Commitment Execution 6.1.3 Intra-Day Reliability Unit Commitment Results 6.2 Real-Time Balancing Market 6.2.1 Real-Time Balancing Market Inputs 6.2.2 Real-Time Balancing Market Execution 6.2.3 Real-Time Balancing Market Results 6.2.4 Out-of-Merit Energy Dispatch 6.3 Energy and Operating Reserve Deployment 6.3.1 Regulation Deployment 6.3.2 Contingency Reserve Deployment 6.3.3 Reserve Sharing Group Scheduling Procedures 6.3.4 Contingency Reserve Recovery 6.4 Energy and Operating Reserve Deployment Failure 6.4.1 Uninstructed Resource Deviation 6.4.2 Regulation Deployment Failure Charges 6.4.3 Contingency Reserve Deployment Failure Tests 6.5 Inadvertent Management 6.5.1 Inadvertent Payback Reporting 7. Transmission Congestion Rights Markets

7.1 Annual Long-Term Congestion Rights/Incremental Long-Term Congestion Rights/Auction Revenue Right Verification 7.1.1 Transmission Service and Incremental Long-Term Congestion Rights

Verification 7.1.2 Candidate Long-Term Congestion Rights/Auction Revenue Rights 7.1.3 Auction Revenue Right Nomination Cap 7.2 Annual Long-Term Congestion Right Allocation

7.2.1 Long-Term Congestion Right and Incremental Long-Term Congestion Right Surrender and Nomination

7.2.2 Available Long-Term Congestion Rights for Load Serving Entities and Incremental Long-Term Congestion Rights

7.2.3 Available Long-Term Congestion Rights for Non-Load Serving Entities 7.2.4 Long-Term Congestion Right and Incremental Long-Term Congestion

Right Awards

7.2.5 Initial Incremental Long-Term Congestion Right Awards 7.3 Annual Auction Revenue Right Allocation 7.3.1 Auction Revenue Right Nominations 7.3.2 Auction Revenue Right Allocation 7.3.3 Annual Auction Revenue Right Awards 7.4 Annual Transmission Congestion Right Auction 7.4.1 Transmission Congestion Right Offer and Bid Submittal 7.4.2 Annual Transmission Congestion Right Auction 7.4.3 Annual Transmission Congestion Right Auction Clearing and Simultaneous Feasibility 7.4.4 Annual Transmission Congestion Right Awards 7.5 Monthly Transmission Congestion Right Auctions 7.5.1 Monthly Transmission Congestion Right Offer and Bid Submittal 7.5.2 Monthly Transmission Congestion Right Auction 7.5.3 Monthly Transmission Congestion Right Auction Clearing and Simultaneous Feasibility 7.5.4 Monthly Transmission Congestion Right Awards 7.6 Monthly Auction Revenue Right Allocation 7.6.1 Monthly Auction Revenue Right Transmission Service Verification 7.6.2 Reserved for Future Use 7.6.3 Monthly Auction Revenue Right Nominations 7.6.4 Monthly Auction Revenue Right Awards 7.7 Auction Revenue Right Allocation and Transmission Congestion Right Auction Settlements 7.8 Transmission Congestion Right Secondary Market 7.9 Liquidation of Transmission Congestion Rights in the Event of Market Participant Default 7.10 Reserved for Future Use

7.11 Transitional ARR Allocation 8. Post Operating Day and Settlement Activities 8.1 Settlement Sign Conventions 8.2 Bilateral Settlement Schedules, GFA Carve Outs and FSE 8.2.1 Default Procedures for Pre-Existing Bilateral Contracts Transitioning to Integrated Marketplace 8.2.2 GFA Carve Out 8.2.3 FSE 8.3 Calculation of Locational Marginal Prices, Locational Marginal Price Components, and Market Clearing Prices 8.3.1 Locational Marginal Price Calculations and Components 8.3.2 Violation Relaxation Limit 8.3.3 Impact of Violation Relaxation Limits on Locational Marginal Prices 8.3.4 Market Clearing Price Calculations 8.4 Price Corrections 8.5 Day-Ahead Market Settlement

8.5.1 Day-Ahead Energy Amount 8.5.2 Day-Ahead Regulation Service Amount 8.5.3 Day-Ahead Spinning Reserve Amount 8.5.4 Day-Ahead Supplemental Reserve Amount 8.5.5 Day-Ahead Regulation-Up Service Distribution Amount 8.5.6 Day-Ahead Regulation-Down Service Distribution Amount 8.5.7 Day-Ahead Spinning Reserve Distribution Amount 8.5.8 Day-Ahead Supplemental Reserve Distribution Amount 8.5.9 Day-Ahead Make Whole Payment Amount 8.5.10 Day-Ahead Make Whole Payment Distribution Amount 8.5.11 Transmission Congestion Rights Funding Amount 8.5.12 Transmission Congestion Rights Daily Uplift Amount 8.5.13 Transmission Congestion Rights Monthly Payback Amount 8.5.14 Transmission Congestion Rights Annual Payback Amount 8.5.15 Transmission Congestion Rights Annual Closeout Amount 8.5.16 Day-Ahead Over-Collected Losses Distribution Amount 8.5.17 Reserved for Future Use 8.5.18 Day-Ahead GFA Carve Out and FSE Daily Amount 8.5.19 Day-Ahead GFA Carve Out and FSE Monthly Amount 8.5.20 Day-Ahead GFA Carve Out and FSE Yearly Amount 8.5.21 GFA Carve Out and FSE Distribution Daily Amount 8.5.22 GFA Carve Out and FSE Distribution Monthly Amount 8.5.23 GFA Carve Out and FSE Distribution Yearly Amount

8.5.24 Day-Ahead Demand Reduction Amount 8.5.25 Day-Ahead Demand Reduction Distribution Amount 8.6 Real-Time Balancing Market Settlement 8.6.1 Real-Time Energy Amount 8.6.2 Real-Time Regulation Service Amount 8.6.3 Real-Time Spinning Reserve Amount 8.6.4 Real-Time Supplemental Reserve Amount 8.6.5 Reliability Unit Commitment Make Whole Payment Amount 8.6.6 Real-Time Out-of-Merit Amount 8.6.7 Reliability Unit Commitment Make Whole Payment Distribution Amount 8.6.8 Real-Time Regulation Service Distribution Amount 8.6.9 Real-Time Spinning Reserve Distribution Amount 8.6.10 Real-Time Supplemental Reserve Distribution Amount 8.6.11 Real-Time Regulation Service Non-Performance Amount 8.6.12 Real-Time Regulation Service Non-Performance Distribution Amount 8.6.13 Real-Time Contingency Reserve Deployment Failure Amount 8.6.14 Real-Time Contingency Reserve Deployment Failure Distribution Amount 8.6.15 Real-Time Regulation Service Deployment Adjustment Amount 8.6.16 Over-Collected Losses Distribution Amount 8.6.17 Real-Time Reserve Sharing Group Amount 8.6.18 Real-Time Reserve Sharing Group Distribution Amount

Deleted: Day-Ahead Virtual Energy Transaction Fee Amount

8.6.19 Unused Regulation-Up Mileage Make Whole Payment 8.6.20 Unused Regulation-Down Mileage Make Whole Payment

8.6.21 Real-Time Demand Reduction Amount 8.6.22 Real-Time Demand Reduction Distribution Amount

8.6.23 Real-Time Pseudo-Tie Congestion Amount 8.6.24 Real-Time Pseudo-Tie Losses Amount 8.7 Auction Revenue Rights and Transmissions Congestion Rights Auction Settlement 8.7.1 Transmission Congestion Rights Auction Transaction Amount 8.7.2 Auction Revenue Rights Funding Amount 8.7.3 Auction Revenue Rights Uplift Amount 8.7.4 Auction Revenue Rights Monthly Payback Amount 8.7.5 Auction Revenue Rights Annual Payback Amount 8.7.6 Auction Revenue Rights Annual Closeout Amount 8.8 Revenue Neutrality Uplift Distribution Amount 8.9 GFA Carve Out or FSE Uplift 8.10 Market Administration Services Amount 9. Release of Offer Curve Data 10. Billing 10.1 Settlement Statements 10.2 Invoices 10.3 Invoice Disputes 10.4 Interest on Unpaid Balances 10.5 Market Participant Default

10.6 Further Clarification Regarding Right to Net 10.7 Integrated Marketplace Counterparty Limitation of Liability

11. Confidentiality Provisions 11.1 Restrictions on Confidential Information Provided to Receiving Party 11.1.1 Procedures for Confidential Information 11.1.2 Exceptions 11.1.3 Injunctive Relief and Specific Performance 11.1.4 Market Participant Access and Transmission Provider Use of Confidential Information 11.1.5 Required Disclosure 11.1.6 Limitations 11.2 Confidentiality Provisions Applicable to the Market Monitor Reporting to the Board of Directors 11.3 Disclosure to Commission or CFTC 11.4 Disclosure to Authorized Agencies 11.4.1 Basic Requirements for Disclosure 11.4.2 Schedule of Authorized Requestors 11.4.3 Use of Confidential Information 11.4.4 Limited Oral Disclosures 11.4.5 Information Requests

11.4.6 Limited Discussion of Confidential Information Among Authorized Requestors Sponsored By Different Authorized Agencies 11.4.7 Breach of Non-Disclosure Obligations 11.5 Preservation of Rights 11.6 Notice Addendum 1 Violation Relaxation Limit Values (“VRLs”) Addendum 2 Bilateral Settlement Schedule Example System Power Sale

4.2.1 Virtual Energy Offers

(1) Virtual Energy Offers are submitted in the Day-Ahead Market only.

(2) A Virtual Energy Offer consists of an Energy Offer Curve only.

(3) A Market Participant may submit no more than one Virtual Energy Offer for itself

at each Settlement Location for each Operating Hour. Where a Market

Participant represents multiple Asset Owners, the Market Participant may submit

no more than one Virtual Energy Offer for each Asset Owner it represents at each

Settlement Location for each Operating Hour.

4.3.2 Virtual Energy Bids

(1) Virtual Energy Bids may be submitted in the Day-Ahead Market only.

(2) Virtual Energy Bids only apply to Energy, are not associated with a physical load

asset and can be submitted at any Settlement Location in the form of a Virtual

Energy Bid Curve.

(3) A Market Participant may submit no more than one Virtual Energy Bid at each

Settlement Location for each Operating Hour. Where a Market Participant

represents multiple Asset Owners, the Market Participant may submit no more

than one Virtual Energy Bid for each Asset Owner it represents at each Settlement

Location for each Operating Hour.

8.10 Market Administration Services Amount

The Transmission Provider will perform calculations at each Settlement Location

for each Asset Owner for each hour consistent with Schedules 1-A2, 1-A3 and 1-A4 of

this Tariff.

Deleted: (4) Each Market Participant submitting Virtual Energy Offers shall be subject to a transaction fee for each Virtual Energy Offer submitted as described under Section 8.5.17 of this Attachment AE.¶

Deleted: (4) Each Market Participant submitting Virtual Energy Bids shall be subject to a transaction fee for each Virtual Energy Bid submitted as described under Section 8.5.17 of this Attachment AE.¶

Deleted: ¶8.5.17 Day-Ahead Virtual Energy Transaction Fee Amount¶

Deleted: A Day-Ahead Market charge for each submitted Virtual Energy Offer and Virtual Energy Bid will be calculated for each Asset Owner for each Operating Day. Charges collected by the Transmission Provider under this charge type are used by the Transmission Provider to reduce the Transmission Provider budgeted expenses used to calculate the rate specified under Schedule 1-A of the Tariff and are calculated as follows: ¶

Day-Ahead Virtual Energy Transaction Fee Amount = ¶[(Day-Ahead Virtual Energy Transaction Daily Count) * (Day-Ahead Virtual Energy Transaction Fee Rate)]¶(1) Day-Ahead Virtual Energy Transaction Daily Count is equal to the sum of Virtual Energy Bids and Virtual Energy Offers submitted as of the close of the Day-Ahead Market for all Settlement Locations and hours in the Operating Day.¶(2) Day-Ahead Virtual Energy Transaction Fee Rate is $0.05 for each Virtual Energy Offer or Virtual Energy Bid.¶

Deleted: ¶

Attachment AF – Market Mitigation Measures 3. Mitigation Measures for Economic Withholding – Market Power in Energy and Operating Reserve

This section sets forth the market power mitigation measures that are applied in the Day-

Ahead Market, Reliability Unit Commitment processes and the Real-Time Balancing

Energy Markets, collectively referred to as the Energy and Operating Reserve Markets.

3.1 Local Market Power Test

A Resource satisfying at least one of the following conditions is determined to

have local market power:

(1) The Resource is located in a Frequently Constrained Area, as described in

Section 3.1.1, and one or more of the transmission constraints that define

the Frequently Constrained Area is binding or the Reserve Zone that

defines the area is binding;

(2) The Resource is not in a Frequently Constrained Area and

(a) has a Resource-to-Load-Distribution factor less than or equal to

negative five percent (-5%) relative to a binding transmission

constraint; or

(b) is located in a binding Reserve Zone;

(3) The Resource is committed to address a Local Reliability Issue.

3.1.1 Frequently Constrained Areas

A Frequently Constrained Area is an electrical area identified by the

Market Monitor that is defined by one or more binding transmission

constraints or binding Reserve Zone constraints that are expected to be

binding for at least five-hundred (500) hours during a given twelve (12)-

month period and within which one (1) or more suppliers are pivotal. All

Frequently Constrained Area designations along with supporting analysis

shall be posted on the Transmission Provider’s website.

3.1.1.1 Pivotal Supplier Test

A supplier is pivotal when the energy output or provision of

operating reserves by any or some of its Resources jointly must be

increased or decreased to resolve the binding transmission

constraint or binding Reserve Zone constraint during some or all

hours. This will be determined utilizing transmission load flow

cases or RTBM market cases reflecting a variety of market

conditions.

These load flow or market cases will be used to estimate: (i) the

generation shift factors for all relevant Resources and relevant

resources outside the SPP Balancing Authority Area relative to

each potentially constrained flowgate; (ii) the capability of all

Resources to meet the requirements of each binding Reserve Zone

constraint; (iii) the base loadings of Resources; (iv) the base

allocation of Operating Reserves on Resources; and (v) the base

flows on each flowgate. A supplier is pivotal when a binding

transmission constraint or a binding Reserve Zone constraint

cannot be relieved by changing the base loadings for other

suppliers’ Resources.

3.1.1.2 Initial Designation of Frequently Constrained Areas

The Market Monitor will define and recommend the Frequently

Constrained Areas to the SPP Board of Directors prior to the start

of the Integrated Marketplace.

3.1.1.3 Changes to Frequently Constrained Area Designation

The Market Monitor shall reevaluate the Frequently Constrained

Areas at least annually. A reevaluation may be performed more

frequently if the Market Monitor believes that conditions have

changed with respect to the binding transmission constraints or

binding Reserve Zone constraints that define a Frequently

Constrained Area, or if congestion on constraints that are not

designated as a Frequently Constrained Area warrant a new

analysis. The Transmission Provider may also propose an area be

designated or undesignated as a Frequently Constrained Area to

the Market Monitor. The Market Monitor will post the updated

Frequently Constrained Area information along with the associated

analysis on the Transmission Provider’s website at least 14

calendar days prior to the Frequently Constrained Area updates

becoming effective and will notify Market Participants of the

posting. Market Participants may contact the MMU within the 14

day posting period if there are concerns with the Market Monitor’s

proposed updates. The Market Monitor will consider and respond

to Market Participant concerns and will make updates if needed.

The Market Monitor will notify Market Participant when updates

become effective.

3.2 Mitigation Measures for Energy Offer Curves

Mitigated Energy Offer Curves shall be submitted on a daily basis by the Market

Participant in accordance with the mitigated offer development guidelines in the

Market Protocols. For Multi-Configuration Resources (“MCR”), as defined in

Attachment AE, for which a single configuration allows physical units to be

swapped (e.g., Combustion Turbine 2 for Combustion Turbine 1), the costs used

in the mitigated offer development for that configuration shall be those of the

least cost physical unit that is available and can be swapped in such configuration.

The mitigated Energy Offer Curve may be updated up to the close of the Day-

Ahead Market as defined in Section 5.1 of Attachment AE of this Tariff for use in

the Day-Ahead Market. In the case a Resource is not committed by the Day-

Ahead Market, the mitigated Energy Offer Curve may be updated until the Day-

Ahead RUC begins. For Resources committed by the Day-Ahead Market, the

mitigated Energy Offer Curve submitted as of the close of the Day-Ahead Market

will apply to the Day-Ahead Market on the day before the Operating Day and the

RTBM on the Operating Day; for all other Resources the mitigated Energy Offer

Curve submitted at the time the Day-Ahead RUC begins will apply to the Day-

Ahead RUC on the day before the Operating Day, and the Intra-Day RUC

processes and the RTBM on the Operating Day.

A. The Energy Offer Curve conduct thresholds are as follows:

(1) For Resources located in a Frequently Constrained Area, the

conduct threshold is a 17.5% increase above the mitigated Energy

Offer Curve;

(2) For all other Resources the conduct threshold is a 25% increase

above the mitigated Energy Offer Curve.

B. The Transmission Provider shall apply mitigation measures by replacing

the Energy Offer Curve with the mitigated Energy Offer Curve if:

(1) The Resource’s Energy Offer Curve exceeds the mitigated Energy

Offer Curve by the applicable conduct threshold; and

(2) The Resource has local market power as determined in Section 3.1;

and

(3) The Resource either:

(a) Fails the Market Impact Test as described in Section 3.7, or

(b) Is manually committed by the Transmission Provider or by

a local transmission operator.

An Energy Offer Curve below $25/MWh will not be subject to mitigation

measures for economic withholding.

C. The Transmission Provider shall apply mitigation measures by placing a

cap on the Energy Offer Curve of 10% above the Mitigated Energy Offer

Curve if the Resource is committed to address a Local Reliability Issue.

An Energy Offer Curve below $25/MWh will not be subject to mitigation

measures.

D. The mitigated energy offer shall be the Resource’s short-run marginal cost

of producing energy as determined by the unit’s heat rate; fuel costs and

the costs related to fuel usage, such as transportation and emissions costs

(“total fuel related costs”); Energy Offer Curve (“EOC”) variable

operations and maintenance costs (“VOM”) as detailed in the Market

Protocols; and Schedules 1-A3 and 1-A4 of this Tariff.

E. Opportunity cost shall be an estimate of the Energy and Operating Reserve

Markets revenues net of short run marginal costs for the marginal forgone

run time during the timeframe when the Resource experiences the run-

time restrictions as detailed in the Market Protocols. The run-time

restrictions shall be updated as specified in the Market Protocols, with

more frequent updating to occur the fewer hours that remain available,

consistent with the Market Protocols. The Market Participant may include

in the calculation of its mitigated Energy Offer Curve an amount reflecting

the resource-specific opportunity costs expected to be incurred under the

following circumstances:

(1) Externally imposed environmental run-hour restrictions; or

(2) Physical equipment limitations on the number of starts or run-

hours, as verified by the Market Monitoring Unit and determined

by reference to the manufacturer’s recommendation or bulletin, or

a documented restriction imposed by the applicable insurance

carrier; or

(3) Fuel Supply Limitations.

Resource specific opportunity costs are calculated by forecasting

Locational Marginal Prices based on futures contract prices for natural gas

Deleted: and

and the historical relationship between the SPP system marginal Energy

component of LMP and the price of natural gas, as determined by the SPP

Market Monitoring Unit. The formulas and instructions in the price

forecast model shall be determined by the SPP Market Monitoring Unit

and published in the Market Protocols as part of the Mitigated Offer

Development Guidelines, updated, as needed, by the SPP Market

Monitoring Unit. Such forecasts of LMPs shall take into account

historical variability, and basis differentials affecting the Settlement

Location at which the Resource is located for the three-year period

immediately preceding the period of time in which the Resource is bound

by the referenced restrictions, and shall subtract therefrom the forecasted

costs to generate energy at the Settlement Location at which the Resource

is located, as specified in more detail in Appendix G of the Market

Protocols. If the difference between the forecasted Locational Marginal

Prices and forecasted costs to generate energy is negative, the resulting

opportunity cost shall be zero. The Market Monitoring Unit will verify all

Market Participants’ opportunity cost calculations for consistency and

accuracy. When the Market Monitoring Unit determines that the market

price for any period was not competitive, it will adjust the LMP

forecasting process used in the opportunity cost calculations to ensure that

forecasted LMPs do not reflect non-competitive market conditions.

The following formula shall apply to all mitigated Energy Offer Curves:

Mitigated Energy Offer ($/MWh) = HeatRate (mmBtu/MWh) *

Performance Factor * Total Fuel Related Costs ($/mmBtu) + EOC VOM

($/MWh) + Opportunity Costs ($/MWh) + Schedule 1-A3 Charge

($/MWh) + Schedule 1-A4 Charge ($/MWh)

F. The Market Participant shall submit heat rate curves, descriptions of how

spot fuel prices and/or contract prices are used to calculate fuel costs,

variable fuel transportation and handling costs, emissions costs, and VOM

to the Market Monitoring Unit. All cost data and cost calculation

descriptions are subject to the review and approval of the SPP Market

Monitoring Unit to ensure reasonableness and consistency across Market

Participants. The information will be sufficient for replication of the

mitigated Energy Offer Curve and shall include, among other data, the

following information:

(1) For fuel costs, Market Participants shall provide the Market

Monitoring Unit with an explanation of the Market Participants’

fuel cost policy, indicating whether fuel purchases are subject to a

fixed contract price and/or spot pricing and specifying the contract

price and/or referenced spot market prices. Any included fuel

transportation and handling costs must be short-run marginal costs

only, exclusive of fixed costs.

(2) For emissions costs, Market Participants shall report the emissions

rate of each of their units and indicate the applicable emissions

allowance cost.

(3) For VOM costs, Market Participants shall submit VOM costs,

calculated in adherence with the Appendix G of the Market

Protocols, reflecting short-run marginal costs, exclusive of fixed

costs.

Further details associated with the development, validation, and updating

of these costs are included in Appendix G of the Market Protocols.

G. For Demand Response Resources utilizing Behind-The-Meter Generation,

the mitigated Energy Offer Curve shall be developed in the same manner

as any other generating Resource as described above. For Demand

Response Resources utilizing load reduction, the mitigated Energy Offer

Curve shall reflect the quantifiable opportunity costs associated with the

reduction, net of related offsetting increases in usage.

H. For Dispatchable Variable Energy Resources, the mitigated Energy Offer

Curve may include, but shall not exceed, any quantifiable costs that vary

by MWh output, including short-run incremental VOM. Mitigation will

not apply to Non-Dispatchable Variable Energy Resources in the Real-

Time Balancing Market; monitoring of Energy Offers for Non-

Dispatchable Variable Energy Resources will occur.

I. Intra-day changes to the mitigated Energy Offer Curve are allowed under

the following conditions:

1) In the event that the Transmission Provider requests that a

Resource remain online past their commitment period by the Day-

Ahead Market or a RUC process, the Market Participant may

submit an updated mitigated energy offer curve that reflects the

procurement of higher cost fuel;

2) A Resource must switch fuels due to unforeseen operating

conditions; or

3) A Market Participant employing the Quick-Start Resource logic as

described in the Market Protocols may update its mitigated Energy

Offer Curve after the Day-Ahead RUC clears on the day before the

Operating Day, as described in Appendix G of the Market

Protocols.

Intra-day changes to the mitigated energy offer curve must follow the

mitigated offer development guidelines in Appendix G of the Market

Protocols. Any such changes will be validated by the Market Monitor.

J. In all cases under this Section 3.2, cost data submitted for the development

of mitigated offers, including opportunity cost data, shall be subject to the

confidentiality provisions set forth in Section 11 of Attachment AE of this

Tariff.

3.3 Mitigation Measures for Start-Up Offers and No-Load Offers

A mitigated Start-Up Offer and a mitigated No-Load Offer shall be submitted

daily by the Market Participant in accordance with the mitigated offer

development guidelines in the Market Protocols. The mitigated Start-Up and No-

Load Offers may be updated up to the close of the Day-Ahead Market for use in

the Day-Ahead Market. In the case a Resource is not committed by the Day-

Ahead Market, the Start-Up and No-Load Offers may be updated until the Day-

Ahead RUC begins. The mitigated Start-Up and No-Load Offers submitted at the

time the Day-Ahead RUC begins will apply to the Day-Ahead RUC on the day

before the Operating Day and the Intra-Day RUC on the Operating Day.

A. The Start-Up and No-Load Offer conduct threshold is a 25% increase

above the mitigated Start-Up or mitigated No-Load Offer, as applicable.

B. The Transmission Provider shall apply mitigation measures by replacing

the Start-Up or No-Load Offer with the applicable mitigated Start-Up or

No-Load Offer if:

(1) The Resource’s Start-Up or No-Load Offer exceeds the mitigated

Start-Up or mitigated No-Load Offer, as applicable, by the

applicable conduct threshold; and

(2) The Resource has local market power as determined in Section 3.1;

and



(b) Is manually committed by the Transmission Provider or by

a local transmission operator.


cap on the Start-Up Offer or No-Load Offer of 10% above the Mitigated

Start-Up Offer or No-Load Offer if the Resource is committed to address a

Local Reliability Issue.

D. The mitigated Start-Up Offer shall represent the cost per start as

determined from start fuel usage and the costs related to that fuel usage,

Performance Factor, cost of electricity for station use to start (“Station

Service”), maintenance costs attributed to starts, and additional labor

costs, if required above normal station staffing levels. The following

formula shall apply to all mitigated Start-Up Offers:

Mitigated Start-Up Offer ($/Start) = [Start Fuel (mmBtu/Start) *

Total Fuel Related Costs ($/mmBtu) * Performance Factor] +

[Station Service (MWh/Start) *

Station Service Rate ($/MWh)] + Start VOM ($/Start) +Start

Additional Labor Cost ($/Start)

The mitigated Start-Up Offer for Demand Response resources shall be the

cost to shut down or curtail load for a given period, which varies with the

number of deployments rather than the amount of response, and/or the

start cost of Behind-The-Meter Generation utilizing the mitigated Start-Up

Offer calculation applicable to other generation Resources as defined

above.

The mitigated Start-Up Offer for Variable Energy Resources shall be zero.

E. The mitigated No-Load Offer shall be the hourly fixed cost required to

create a monotonically increasing mitigated Energy Offer Curve. It shall

be calculated according to either of two methods:

(1) No-Load Fuel Approach

Mitigated No-Load Offer ($/hour) = No Load Fuel (mmBtu/hour)

* Performance Factor * (No-Load VOM ($/mmBtu) +

Total Fuel Related Cost ($/mmBtu)

(2) No-Load Cost Approach

Mitigated No-Load Offer ($/hour) =

(Heat Input at Minimum Economic Capacity Operating

Limit (mmBtu) * Performance Factor *

(Total Fuel Related Cost ($/mmBtu) + No Load VOM

($/mmBtu) ) ) –

(Incremental Cost up to Minimum Economic Capacity

Operating Limit ($/MWh) * Minimum Economic Capacity

Operating Limit (MW) )

The mitigated No-Load Offer for Demand Response Resources

utilizing Behind-The-Meter Generation shall adhere to the same

definition above as a generating Resource. For Demand Response

Resources utilizing load reduction, the mitigated No-Load Offer shall

not exceed the quantifiable ongoing hourly costs associated with load

reduction.

The mitigated No-Load Offer for Variable Energy Resources shall be

zero.

F. The Market Participant shall submit all inputs used in calculating

mitigated Start-Up and mitigated No-Load Offers to permit the Market

Monitor to verify submitted offers. Required information includes: heat

rate curves, descriptions of how spot fuel prices and/or contract prices are

used to calculate fuel costs, variable fuel transportation and handling costs,

emissions costs, and VOM. All cost data and cost calculation descriptions

are subject to the review and approval of the SPP Market Monitoring Unit

to ensure reasonableness and consistency across Market Participants.

Information to be provided by the Market Participant shall include the

following:


Monitoring Unit with an explanation of the Market Participants’

fuel cost policy, indicating whether fuel purchases are subject to a

fixed contract price and/or spot pricing and specifying the contract

price and/or referenced spot market prices. Any included fuel

transportation and handling costs must be short-run marginal costs

only, exclusive of fixed costs.

(2) For emissions costs, Market Participants shall report the emissions

rate of each of their units and indicate the applicable emissions

allowance cost.

(3) For VOM costs, Market Participants shall submit VOM costs

reflecting short-run marginal costs, exclusive of fixed costs.

Further details associated with the development, validation and updating

of these costs are included in Appendix G of the Market Protocols.

G. Intra-day changes to the mitigated Start-Up and mitigated No-Load Offers

are allowed under the following conditions:


Resource remain online past their commitment period, the Market

Participant may submit updated mitigated Start-Up and mitigated

No-Load Offers that reflect the procurement of higher cost fuel;


conditions; or

3) A Market Participant employing the Quick-Start Resource logic as

described in the Market Protocols may update its mitigated Start-

Up and mitigated No-Load offers as described in Appendix G of

the Market Protocols.

Intra-day changes to the mitigated Start-Up and mitigated No-Load offers

must follow the mitigated offer development guidelines Appendix G of in

the Market Protocols. Any such changes will be validated by the Market

Monitor.

H. In all cases under this Section 3.3, cost data submitted for the development



Tariff.

3.3.1 Mitigation Measures for Transition State Offers

The mitigation measures in this section apply only to MCRs. A mitigated

Transition State Offer shall be submitted daily by the Market Participant

in accordance with the mitigated offer development guidelines specified in

the Market Protocols for each potential transition state changes. The

mitigated Transition State offer may be updated up to the close of the

Day-Ahead Market before the Operating Day as defined in Section 5.1 of

Attachment AE of this Tariff for use in the Day-Ahead Market. In the

case a Resource is not committed by the Day-Ahead Market, the mitigated

Transition State Offer may be updated until the Day-Ahead RUC process

begins. The mitigated Transition State Offer submitted at the time the

Day-Ahead RUC process begins will apply to the Day-Ahead RUC

process on the day before the Operating Day and Intra-Day RUC

processes on the Operating Day.

A. The Transition State Offer conduct threshold is a 25% increase

above the mitigated Transition State Offer.

B. The Transmission Provider shall apply mitigation measures by

replacing the Transition State Offer with the mitigated Transition

State Offer if:

(1) The Resource’s Transition State Offer exceeds the

mitigated Transition State Offer by the applicable conduct

threshold; and

(2) The Resource has local market power as determined in

Section 3.1; and


(a) Fails the Market Impact Test as described in Section

3.7, or

(b) Is manually committed by the Transmission

Provider or by a local transmission operator.

C. The Transmission Provider shall apply mitigation measures by

placing a cap on the Transition State Offer of 10% above the

Mitigated Transition State Offer Curve if the Resource is

committed to address a Local Reliability Issue.

D. The mitigated Transition State Offer for an MCR shall represent

the costs of moving from the current configuration to another

configuration as determined from the fuel costs incurred during the

transition, the costs related to that fuel usage, Performance Factor,

additional maintenance costs incurred during the transition, and

additional labor costs incurred during the transition, if required

above normal station staffing levels. The following formula shall

apply to all mitigated Transition State Offers:

Mitigated Transition State Offer ($/Transition) =

(Transition Fuel Consumed (mmBtu/Transition) * Total

Fuel Related Costs ($/mmBtu) * Performance Factor) +

Transition VOM Cost ($/Transition) + Incremental Labor

Cost ($/Transition)

The Market Participant shall submit documentation of the method

and any cost data for calculating the mitigated Transition State

Offer that is necessary to allow the Market Monitor to validate

submitted offers. Further details associated with the development

of these costs are included in the Market Protocols.

E. Intra-day changes to the mitigated Transition State Offers are

allowed under the following conditions:

(1) In the event that the Transmission Provider requests that a

Resource remain online past their commitment period, the

Market Participant may submit an updated mitigated

Transition State Offer that reflects the procurement of

higher cost fuel; or

(2) A Resource must switch fuels due to unforeseen operating

conditions.

Intra-day changes to the mitigated Transition State Offers must

follow the mitigated offer development guidelines in Appendix G

of the Market Protocols. Any such changes will be validated by

the Market Monitor.

F. In all cases under this Section 3.3.1, cost data submitted for the

development of mitigated offers, including opportunity cost data,

shall be subject to the confidentiality provisions set forth in Section

11 of Attachment AE of the Tariff.

3.4 Mitigation Measures for Operating Reserve Offers

A mitigated offer for each Operating Reserve product shall be submitted daily by

the Market Participant in accordance with the mitigated offer development

guidelines in the Market Protocols. For MCRs for which a single configuration

allows physical units to be swapped (e.g., Combustion Turbine 2 for Combustion

Turbine 1), the costs used in the mitigated offer development for that

configuration shall be those of the least cost physical unit that is available and can

be swapped in such configuration. The mitigated Operating Reserve Offers may

be updated up to the close of the Day-Ahead Market for use in the Day-Ahead

Market. In the case a Resource is not committed by the Day-Ahead Market, the

mitigated Operating Reserve Offers may be updated until the Day-Ahead RUC

begins. For Resources committed by the Day-Ahead Market, the mitigated

Operating Reserve Offers submitted as of the close of the Day-Ahead Market will

apply to the Day-Ahead Market on the day before the Operating Day and the

RTBM on the Operating Day; for all other Resources, the mitigated Operating

Reserve Offers submitted at the time the Day-Ahead RUC begins will apply to the

RTBM on the Operating Day.

A. The offer conduct threshold for each of the Operating Reserve products is

a 25% increase above the mitigated offer for the applicable Operating

Reserve Offer.

B. Any Operating Reserve Offer exceeding the applicable threshold, except

offers below $10/MWh, will be deemed excessive. The Transmission

Provider shall apply mitigation measures by replacing the Operating

Reserve Offer with the applicable mitigated Operating Reserve Offer if:

(1) The Resource’s Operating Reserve Offer exceeds the applicable

mitigated offer by the conduct threshold; and

(2) The Resource has local market power as determined in Section

3.1; and



(b) Is manually committed by the Transmission Provider or by a

local transmission operator.


cap on the Operating Reserve Offer of 10% above the Mitigated Operating

Reserve Offer if the Resource is committed to address a Local Reliability

Issue. An Operating Reserve Offer below $10/MWh will not be subject to

mitigation measures.

D. The mitigated Spinning Reserve Offer shall be equal to zero for Resources

other than combustion turbines, reciprocating engines and hydro

Resources operating as a synchronous condenser. No known incremental

costs are incurred for providing Spinning Reserves from other resource

types.

Total mitigated Spinning Reserve Offer for combustion turbines,

reciprocating engines and hydro Resources operating as a synchronous

condenser shall not exceed any additional fuel related costs, maintenance

costs and power consumption costs necessary for the Resource to be

prepared for deployment of Spinning Reserve:

Mitigated Spinning Reserve Offer ($/MW) ≤

(Additional Fuel Cost($/Hr) + Additional Maintenance Cost

($/Hr) + Condensing Power Cost ($/Hr) ) /

Spinning Reserve MW

The mitigated Supplemental Reserve Offer shall not exceed labor costs necessary

for the Resource to be prepared for deployment of Supplemental Reserve:

Mitigated Supplemental Reserve Offer ($/MW) <

Additional Labor Cost($) / Average Supplemental Reserve

MW

E. The mitigated Regulation-Up Service Offer shall not exceed the sum of

the cost increase due to:

(1) the heat rate increase during non-steady state operation,

(2) increase in VOM due to non-steady state operation,

(3) uncompensated costs, as described in the Market Protocols:

Where:

Mitigated Regulation-Up Service Offer = Mitigated Regulation-Up

Offer ($/MW) + Mitigated Regulation-Up Mileage Offer

($/MW),

Mitigated Regulation-Up Offer ($/MW) ≤ Uncompensated Cost

($/MW), and

Mitigated Regulation-Up Mileage Offer ($/MW) ≤

(Cost Increase due to Heat Rate Increase during non-steady state

operation + Cost Increase in VOM) * Regulation-Up Mileage

Factor

F. The mitigated Regulation-Down Service Offer shall not exceed the sum of

the cost increase due to:

(1) the heat rate increase during non-steady state operation,

(2) increase in VOM due to non-steady state operation,

(3) uncompensated costs, as described in the Market Protocols:

Where:

Mitigated Regulation-Down Service Offer = Mitigated Regulation-

Down Offer ($/MW) + Mitigated Regulation-Down

Mileage Offer ($/MW),

Mitigated Regulation-Down Offer ($/MW) ≤ Uncompensated Cost

($/MW), and

Mitigated Regulation-Down Mileage Offer ($/MW) ≤

(Cost Increase due to Heat Rate Increase during non-steady state

operation + Cost Increase in VOM) * Regulation-Down Mileage

Factor

Further details associated with the development of the exact costs in the

formulas above are included in the Market Protocols.

G. Intra-day changes to the mitigated Operating Reserve Offers are allowed

under the following conditions:


Resource that is supplying Operating Reserves remain online past

their commitment period by the Day-Ahead Market or a RUC

process, the Market Participant may submit an updated mitigated

Operating Reserve offer curve that reflects the procurement of

higher cost fuel;


conditions; or

3) Intra-day changes to the mitigated Regulation-Up and mitigated

Regulation-Down Offers are allowed after the Day-Ahead RUC

clears on the day before the Operating Day under the following

condition:

a. The Resource incurs the uncompensated cost in Section

3.4(E)(3) of this Attachment AF, for which the mitigated

offer calculation is described in Appendix G of the Market

Protocols.

Intra-day changes to the mitigated Operating Reserve Offer curve must

follow the mitigated offer development guidelines in Appendix G and

Section 8.2.2 of the Market Protocols. Any such changes will be validated

by the Market Monitor.

H. The Market Participant may include in the calculation of its mitigated

Operating Reserve Offer an amount reflecting the Resource-specific

opportunity costs if the Market Participant is able to demonstrate to the

satisfaction of the SPP Market Monitoring Unit that such costs are

legitimate and verifiable and not otherwise included in market outcomes.

To the extent such costs include run-time restrictions, such run-time

restrictions shall be updated as specified in the Market Protocols, with

more frequent updating to occur the fewer hours that remain available,

consistent with the Market Protocols. The formulas and instructions in the

price forecast model for any such opportunity costs shall be determined by

the SPP Market Monitoring Unit and published in the Market Protocols as

part of the Mitigated Offer Development Guidelines, updated, as needed,

by the SPP Market Monitoring Unit. Opportunity costs for mitigated

Operating Reserve Offers shall not include Energy and Operating Reserve

Markets revenues associated with forgone Energy or other types of

Operating Reserve production to the extent that such costs are included in

market outcomes.

I. All cost data and cost calculation descriptions are subject to the review

and approval of the SPP Market Monitoring Unit to ensure reasonableness

and consistency across Market Participants. The information will be

sufficient for replication of the mitigated Operating Reserve Offers and

shall include, among other data, the following information:


Monitoring Unit with an explanation of the Market Participants’ fuel

cost policy, indicating whether fuel purchases are subject to a fixed

contract price and/or spot pricing and specifying the contract price

and/or referenced spot market prices. Any included fuel transportation

and handling costs must be short-run marginal costs only, exclusive of

fixed costs.

(2) For emissions costs, Market Participants shall report the emissions rate

of each of their units and indicate the applicable emissions allowance

cost.

(3) For VOM costs, Market Participants shall submit VOM costs,

calculated in adherence with the Appendix G of the Market Protocols,

reflecting short-run marginal costs, exclusive of fixed costs.

J. In all cases under this Section 3.4, cost data submitted for the development



Tariff.

3.5 Validation of Mitigated Resource Offer Parameters

The Market Monitor shall review the costs included in each mitigated Resource

Offer on an ex-post basis relative to the relevant Operating Day in order to ensure that the

Market Participant has correctly applied the formulas and definitions in Sections 3.2, 3.3,

3.3.1, and 3.4 of this Attachment AF and in the Market Protocols and that the level of the

mitigated offer is otherwise acceptable. If the mitigated offer determined by the Market

Monitor and the Market Participant differ, Market Participant shall use the mitigated

offer calculated by the Market Monitor going forward. If a Market Participant submits a

dispute over its mitigated offer, the previously approved mitigated offer shall be used

from the time the dispute is submitted until the dispute is resolved. The procedures for

submitting and processing disputes related to mitigated offers shall be those specified in

the Market Protocols. The Transmission Provider shall remedy mitigated offer disputes

resolved in favor of the Market Participant by providing make whole payments, as

necessary, to the Market Participant whose mitigated offer was improperly determined by

the Market Monitor.

Each Market Participant is obligated to provide to the Market Monitor any cost

data necessary to allow the Market Monitor to validate its mitigated Resource Offer.

The Market Monitor shall keep such data confidential, and all cost data submitted

under this Section 3.5, including any opportunity cost data, shall be subject to the

confidentiality provisions set forth in Section 11 of Attachment AE of this Tariff. The

Market Monitor shall develop and maintain on the Transmission Provider’s website the

mechanism and procedures to allow Market Participants to submit such cost data.

3.6 Additional Mitigation Measures for Resource Offer Parameters

The mitigation measures in this section apply to all Resource Offer parameters

expressed in units other than dollars and will only apply in the presence of local market

power as described in Section 3.1 of this Attachment AF. A reference level for each

applicable Resource Offer parameter that reflects the physical capability of the Resource

shall be determined prior to the start of the Energy and Operating Reserve Markets by

one or both of the following methods: (i) the reference levels will be determined through

consultation between the Market Participant and the Market Monitor; and/or (ii) the

reference levels will be based on averages of Resource Offer parameters from similar

Resources. This methodology for setting reference levels for Offer parameters shall

apply to all Resources at the start of the Energy and Operating Reserve Markets and to all

Resources that register subsequent to the start of the Energy and Operating Reserve

Markets. The Transmission Provider’s output forecast for a wind-powered Variable

Energy Resource shall be used as the reference maximum output limit for the wind-

powered Variable Energy Resource.

The following thresholds shall be used by the Transmission Provider to identify

Resource Offers that may warrant mitigation and shall be determined with respect to the

corresponding reference level:

Time-based Resource Offer parameters: An increase of three (3) hours, or an

increase of six (6) hours in total for multiple time-based Resource Offer parameters.

Resource Offer parameters expressed in units other than time or dollars: One

hundred percent (100%) increase for Resource Offer parameters that are minimum

values, or a fifty percent (50%) decrease for Resource Offer parameters that are

maximum values.

Minimum Economic Capacity Operating Limit threshold for Resources

committed to address a Local Reliability Issue: twenty-five percent (25%) increase.

In the case that a Resource Offer fails the thresholds described above, the Market

Monitor shall determine the impact on prices or make whole payments. If an impact

exceeds the LMP, MCP or make whole payment thresholds in Section 3.7, the Market

Monitor will initiate a discussion with the Market Participant concerning an explanation

of the parameter changes. The Market Monitor will inform the Transmission Provider of

any potential issue. If the Transmission Provider, in consultation with the Market

Monitor, concludes that the Market Participant has demonstrated the validity of the

submitted Resource Offer parameter, no further action will be taken. If not, the

Transmission Provider shall replace the Resource Offer parameter with the corresponding

reference level. Mitigation measures will remain in place until such time that the Market

Participant demonstrates the validity of the Resource Offer parameter or the Market

Participant notifies the Market Monitor that the Resource Offer parameter has been

changed to a value that is within the tolerance range as described above, and the Market

Monitor has verified that this change has occurred. In the event that the Market

Participant submits a dispute, the mitigation measure will remain in place until the

resolution of the dispute.

In all cases under this Section 3.6, cost data submitted for the development of

mitigated offers, including opportunity cost data, shall be subject to the confidentiality

provisions set forth in Section 11 of Attachment AE of this Tariff.

3.7 Market Impact Test

The Transmission Provider will apply the following market impact test in the

Day-Ahead Market, Day-Ahead RUC, Intra-Day RUC and Real-Time Balancing Market

in the event the conditions described in Section 3.1 are satisfied:

After an initial market solution is computed with no mitigation measures in place,

a second market solution, called the mitigated market solution, will be computed with the

appropriate mitigation measures applied. If an LMP or MCP at a Settlement Location

from the initial market solution exceeds the corresponding price from the mitigated

market solution by the applicable impact test threshold, or a make whole payment for any

Resource from the initial market solution exceeds the corresponding make whole

payment from the mitigated market solution by make whole payment impact test

threshold, then the mitigated market solution will be used for dispatch, commitment, and

settlement purposes.

The impact test thresholds are as follows: At market start, the LMP impact

threshold is five dollars ($5) per megawatt hour, the MCP impact threshold is five dollars

($5) per megawatt hour, and the make whole payment impact threshold is five dollars

($5) per megawatt hour. At the beginning of each six (6) month period after the market

start, the LMP and MCP impact thresholds will be increased ten dollars ($10) per

megawatt hour and the make whole payment impact threshold will be increased by ten

dollars ($10) per megawatt hour unless the Market Monitor finds market behavior that

warrants keeping the threshold constant for the next six (6) months. The periodic

increases will continue until the LMP impact threshold is twenty-five dollars ($25) per

megawatt hour, the MCP impact threshold is twenty-five dollars ($25) per megawatt

hour, and the make whole payment impact threshold is twenty-five dollars ($25) per

megawatt hour.

3.8 Mitigation Exceptions

A. The Market Monitor shall, as soon as practicable and if warranted in light

of the information available to the Market Monitor, contact a Market

Participant to request an explanation of its actions in cases when an impact

threshold in Section 3.7 of this Attachment AF is exceeded and the Market

Participant’s offer exceeded the mitigated offer by more than the relevant

conduct threshold, as specified in Section 3.2, 3.3, 3.3.1, or 3.4 of this

Attachment AF.

B. If a Market Participant anticipates submitting an offer that will exceed the

mitigated offer by more than the relevant conduct threshold, it may contact

the Market Monitor to provide an explanation of the changes in its offer. If

the Market Participant’s pre-offer explanation indicates to the Market

Monitor that the questioned behavior is consistent with competitive

behavior, the Transmission Provider will not impose mitigation with

respect to that offer unless and until circumstances are deemed to warrant

it, and the Transmission Provider or the Market Monitor so notifies the

Market Participant. In circumstances where, following a Market

Participant’s pre-offer explanation, both the conduct and impact thresholds

are violated but no mitigation is imposed, the Market Monitor will record

such instances and will report such instances to the Commission’s Office

of Enforcement, or its successor organization, every three months during

the first year of Integrated Marketplace operations, and yearly thereafter.

To the extent that the report contains sensitive data, the Market Monitor

should include any such data in a non-public version of the report.

3.9 Sanctions for Noncompliance with the Day-Ahead Market Must Offer Requirement

A. In the case that a Market Participant is found to be noncompliant for an

Asset Owner as determined by the conditions set forth in Section 2.11.1 of

Attachment AE, the Market Participant shall be assessed a penalty for that

Asset Owner by the Transmission Provider for each megawatt of withheld

capacity below the 10% tolerance band. The penalty amount shall be

equal to the Day-Ahead Market LMP associated with the withheld

capacity.

B. The Market Monitor will monitor for, and report to the Commission’s

Office of Enforcement, or its successor organization, manipulative

behavior associated with Day-Ahead Offers, including (but not limited to)

monitoring load-serving Market Participants who do not offer enough net

resource capacity to meet their maximum hourly Reported Load. The

Market Monitor will also report to the Commission’s Office of

Enforcement or its successor organization any locational problems, such

as deliverability issues, associated with load-serving Market Participants’

offers in the Day-Ahead Market, any identified efforts by Market

Participants to raise prices in the RTBM by limiting Day-Ahead Offers,

and the effects of any such efforts upon make whole payments.

DRAFTSummary Sch 1-A1 to 1-A4 Rates

LineNo.1 Total Schedule 1-A1 Rate/MWh (Schedule 1-A1 - Rate) $0.1912 Total Schedule 1-A2 Rate/MWh (Schedule 1-A2 - Rate) $0.0063 Total Schedule 1-A3 Rate/MWh (Schedule 1-A3 - Rate) $0.0224 Total Schedule 1-A4 Rate/MWh (Schedule 1-A4 - Rate) $0.057

These rates cannot be summed together to calculate a single rate

AMOUNTS IN TEMPLATE ARE FOR ILLUSTRATIVE PURPOSES ONLY

DRAFT

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A B C D E F G

Rate Schedule 1-A1 Rate

LineNo.

1 Scheduling, System Control, and Dispatch (Schedule 1-A1 - COST-1) 44,215,660$ 2 Reliability Planning & Standards Development (Schedule 1-A1 - COST-2) 27,221,109$ 3 Total Schedule 1-A1 Costs (ln 1 + ln 2) 71,436,769$

4 Prior Year Over or Under Recovery5 Projected (Budgeted) Schedule 1-A1 Revenue Income Statement from Financial Statements 15,000$ input6 Actual Schedule 1-A1 Revenue Income Statement from Financial Statements 12,000$ 7 Projected (Budgeted) Schedule 1-A1 Net Revenue Requirement ("NRR") Income Statement from Financial Statements 5,000$ 8 Actual Schedule 1-A1 NRR Income Statement from Financial Statements 6,000$ 9 Adjustment for Prior Year Over or (Under) Recovery ((ln 6 - ln 5)+(ln 7 - ln 8)) (4,000)$

10 Total Schedule 1-A1 Costs/Net Revenue Requirement (ln 3 - ln 9) 71,440,769$

11 Divisor12 Average 12 Coincident Peak Adjusted (MW) (Schedule 1-A1 - Divisor) 42,802

13 RATE/MWh (ln 10 /( ln 12 * 8760)) 0.191$

DRAFT

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A B C D E F

Rate Schedule 1-A1 - Scheduling, System Control, & Dispatch Costs

LineNo.

1 Salary and Benefits & Employee Direct Expenses2 Total Salary & Benefits & Employee Direct Expenses (Salary Benefit EE Direct Alloc) 19,810,097$

3 Other Direct Costs4 System Maintenance Expense (Sys Maint Exp Alloc) 1,275,000$ 5 Network and Communications Expense (Network & Comm Alloc) 1,113,000$ 6 Outside Service Expenses (Outside Services Alloc) 2,757,000$ 7 Other Direct Expenses (Other Direct Alloc) 50,000$ 8 Debt Service (Debt Service Alloc) 5$ 9 Bad Debt (Bad Debt Alloc) 10$

10 Total Other Direct Costs (sum lns 4 to 9) 5,195,015$

11 Total Direct Costs (ln 2 + ln 10) 25,005,112$

12 Corporate Overhead Allocation (Corp OH Alloc) 19,210,548$

13 Total Scheduling, System Control, & Dispatch Costs (ln 11 + ln 12) 44,215,660$

Note Letter

A

DRAFT

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A B C D E F

Rate Schedule 1-A1 - Planning & Standards Development Costs

LineNo.


3 Other Direct Costs4 System Maintenance Expense (Sys Maint Exp Alloc) 545,000$ 5 Network and Communications Expense (Network & Comm Alloc) -$ 6 Outside Service Expenses (Outside Services Alloc) 2,339,000$ 7 Other Direct Expenses (Other Direct Alloc) 20,000$ 8 Debt Service (Debt Service Alloc) 10$ 9 Bad Debt (Bad Debt Alloc) 5$

10 Total Other Direct Costs before Revenues (sum lns 4 to 9) 2,904,015$ 11 LESS: Revenues Associated with Engineering Studies (Rev Assoc with Eng Studies) -$ 12 Total Other Direct Costs (Net) (ln 10 - ln 11) 2,904,015$



15 Total Planning & Standards Development Costs (ln 13 + ln 14) 27,221,109$

DRAFT

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1011

A B C D E F

Revenues Associated with Engineering Studies

Line SPP AccountNo. No.

1 Dept 0440- Acc Series 49100-49120 GI Studies Revenues -$ 2 Dept 0420- Acc Series 49100-49120 Transmission Service Studies Revenue -$ 3 Dept 0410- Acc Series 49100-49120 DPA Studies Revenues -$ 4 Various Dept - Acc Series 49100-49120 Miscellaneous Study Revenues -$

5 Revenues Associated with Engineering Studies (sum lns 1 to 4) -$

DRAFT

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A B C D E

Rate Schedule 1-A 1 DivisorLineNo. Actual

Average MWs1 August (YR-2) (Transmission Load) 4,005 2 September (YR-2) (Transmission Load) 3,842 3 October (YR-2) (Transmission Load) 3,453 4 November (YR-2) (Transmission Load) 3,149 5 December (YR-2) (Transmission Load) 3,173 6 January (YR-1) (Transmission Load) 3,705 7 February (YR-1) (Transmission Load) 3,325 8 March (YR-1) (Transmission Load) 2,853 9 April (YR-1) (Transmission Load) 2,881

10 May (YR-1) (Transmission Load) 3,784 11 June (YR-1) (Transmission Load) 4,184 12 July (YR-1) (Transmission Load) 4,446 13 Sum of Zonal Average 12 Coincident Peak (12CP) (sum lns 1 to 12) 42,802

14 Adjustment for Known Future Impacts to Load Source of data input -

15 Average 12CP Adjusted (ln 13 + ln 14) 42,802

NoteLetter

A YR-1 represents the year prior to budget yearB YR-2 represents 2 years prior to budget year

i.e. For Budget Year 2021, the YR-1 would be 2020 and YR-2 would 2019.i.e. For Budget Year 2020, the YR-1 would be 2019 and YR-2 would 2018.

DRAFT

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891011121314151617181920212223242526272829303132333435363738

A B C D E F G H I J K L M N O P Q R

Transmission LoadZonal Transmission System Peak Loads (MW)August to December from the two years prior and January to July from the one year prior

Monthly Peak for Network and Point-to-Point Transmission Service Load (MW) Year 2018 2018 2018 2018 2018 2019 2019 2019 2019 2019 2019 2019 input

Zone August September October November December January February March April May June July Make sure point to point load is includedAEP 9,668.000 9,515.000 8,520.000 7,658.000 7,612.000 9,556.000 7,764.000 6,428.000 6,076.000 9,276.000 9,984.000 10,460.000 EDE 1,043.000 1,018.000 859.000 970.000 941.000 1,212.000 1,037.000 837.000 802.000 932.000 1,109.000 1,105.000 KCLP - GMO 1,846.724 1,783.705 1,589.607 1,319.431 1,376.411 1,697.528 1,496.470 1,227.372 1,273.372 1,732.548 1,911.607 1,960.626 GRDA 800.000 799.000 730.000 607.000 603.000 628.000 592.000 548.000 529.000 747.000 820.000 839.000 KCPL 3,738.949 3,561.262 3,208.747 2,550.491 2,519.485 3,095.723 2,811.099 2,365.343 2,416.758 3,476.231 3,957.592 3,997.452 LES 717.851 700.642 570.286 503.853 512.816 601.000 559.000 483.000 480.000 647.958 736.285 764.543 MKEC 620.300 612.300 544.400 460.700 459.500 456.100 446.600 411.500 418.500 537.400 667.500 615.300 MIDW 379.345 348.680 312.874 261.300 266.400 286.200 271.300 251.400 245.559 321.926 397.361 408.049 NPPD 3,164.313 2,406.674 1,890.728 2,313.345 2,261.439 2,634.658 2,462.917 2,097.269 2,162.557 2,281.758 2,939.758 3,467.012 OKGE 6,413.940 5,963.415 5,427.294 4,637.690 4,641.353 5,621.934 4,953.713 4,177.583 4,173.765 6,129.881 6,464.081 7,684.579 OPPD 2,358.708 2,300.969 1,919.318 1,623.066 1,678.304 1,931.378 1,791.395 1,608.276 1,534.444 2,233.742 2,405.928 2,470.043 SECI 453.800 405.500 395.600 311.100 331.300 328.300 329.200 327.400 329.800 418.200 463.800 528.000 SPRM 687.000 672.000 562.000 443.000 456.000 535.000 466.000 409.000 405.000 594.000 726.000 728.000 SPS 5,784.246 5,009.181 4,565.462 4,230.740 4,303.052 4,394.000 4,075.000 3,911.000 4,327.000 5,552.000 5,752.000 6,158.832 WFEC (ln 4 + ln 9) 1,362.193 1,230.131 1,310.689 1,309.874 1,625.738 1,422.078 1,130.193 1,222.644 1,379.781 1,446.663 1,520.895 WR 5,105.902 4,990.187 4,387.000 3,378.000 3,355.000 3,904.000 3,582.000 3,070.000 3,149.000 4,481.000 5,464.001 5,374.015 SPA 268.782 257.747 219.599 137.007 182.006 302.200 207.100 167.000 154.200 211.400 287.400 281.300 UMZ w/FSE 5,007.928 4,402.590 4,501.776 5,078.218 5,268.040 5,651.233 5,629.440 4,789.773 4,877.153 4,460.748 4,672.214 4,991.805

Total 48,058.788 46,109.045 41,433.822 37,793.630 38,076.980 44,460.992 39,896.312 34,239.109 34,576.752 45,413.573 50,205.190 53,354.451

Average 4,004.899 3,842.420 3,452.818 3,149.469 3,173.082 3,705.083 3,324.693 2,853.259 2,881.396 3,784.464 4,183.766 4,446.204

DRAFT

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A B C D E F


LineNo.

1 TCR Administration Costs (Schedule 1-A2 - COST) 3,290,926$ 2 Total Schedule 1-A2 Costs (ln 1) 3,290,926$

3 Prior Year Over or Under Recovery4 Projected (Budgeted) Schedule 1-A2 Revenue Income Statement from Financia 5,000$ 5 Actual Schedule 1-A2 Revenue Income Statement from Financia 2,000$ 6 Projected (Budgeted) Schedule 1-A2 Net Revenue Requirement ("NRR") Income Statement from Financia 6,000$ 7 Actual Schedule 1-A2 NRR Income Statement from Financia 5,000$ 8 Adjustment for Prior Year Over or (Under) Recovery ((ln 5 - ln 4)+(ln 6 - ln 7)) (2,000)$


10 Divisor11 TCR Volume MWh (Schedule 1-A2 - Divisor) 547,000,000

12 RATE/MWh (ln 9 / ln 11) 0.006$

DRAFT

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A B C D E

Rate Schedule 1-A2 - TCR Administration Costs

LineNo.


3 Other Direct Costs4 System Maintenance Expense (Sys Maint Exp Alloc) 745,000$ 5 Network and Communications Expense (Network & Comm Alloc) -$ 6 Outside Service Expenses (Outside Services Alloc) 10$ 7 Other Direct Expenses (Other Direct Alloc) 5$ 8 Debt Service (Debt Service Alloc) 5$ 9 Bad Debt (Bad Debt Alloc) 10$

10 Total Other Direct Costs (sum lns 4 to 9) 745,030$



13 Total TCR Administration Costs (ln 11 + ln 12) 3,290,926$

DRAFT

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A B C D E F

Rate Schedule 1-A 2 DivisorLineNo. Actuals

MWhs1 August (YR-2) (Note B) 50,000,000 input2 September (YR-2) (Note B) 75,000,000 3 October (YR-2) (Note B) 70,000,000 4 November (YR-2) (Note B) 60,000,000 5 December (YR-2) (Note B) 50,000,000 6 January (YR-1) (Note A) 30,000,000 7 February (YR-1) (Note A) 30,000,000 8 March (YR-1) (Note A) 25,000,000 9 April (YR-1) (Note A) 24,000,000

10 May (YR-1) (Note A) 26,000,000 11 June (YR-1) (Note A) 50,000,000 12 July (YR-1) (Note A) 57,000,000

13 Volume of TCRs cleared for TCR Holders (sum lns 1 to 12) 547,000,000

14 Adjustment for Known Future Impacts to TCR Volume Source of data input -

15 TCR volume (Adjusted) (ln 13 + ln 14) 547,000,000

NoteLetter


i.e. For Budget Year 2021, the YR-1 would be 2020 and YR-2 would 2019.

DRAFT

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A B C D E F


LineNo.

1 Market Clearing Costs (Schedule 1-A3 - COST) 12,566,488$ 2 Total Schedule 1-A3 Costs (ln 1) 12,566,488$

3 Prior Year Over or Under Recovery4 Projected (Budgeted) Schedule 1-A3 Revenue Income Statement from Financial Statements 2,000$ 5 Actual Schedule 1-A3 Revenue Income Statement from Financial Statements 5,000$ 6 Projected (Budgeted) Schedule 1-A3 Net Revenue Requirement ("NRR") Income Statement from Financial Statements 5,000$ 7 Actual Schedule 1-A3 NRR Income Statement from Financial Statements 7,000$ 8 Adjustment for Prior Year Over or (Under) Recovery ((ln 5 - ln 4)+(ln 6 - ln 7)) 1,000$


10 Divisor11 Real Time Gen/Load, Import/Exports, and Virtuals MWh (Schedule 1-A3 - Divisor) 563,000,000

12 RATE/MWh (ln 9 / ln 11) 0.022$

DRAFT

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A B C D E

Rate Schedule 1-A3 - Market Clearing Costs

LineNo.


3 Other Direct Costs4 System Maintenance Expense (Sys Maint Exp Alloc) N/A5 Network and Communications Expense (Network & Comm Alloc) -$ 6 Outside Service Expenses (Outside Services Alloc) N/A7 Other Direct Expenses (Other Direct Alloc) 10$ 8 Debt Service (Debt Service Alloc) N/A9 Bad Debt (Bad Debt Alloc) N/A

10 Total Other Direct Costs (sum lns 4 to 9) 10$



13 Total Market Clearing Costs (ln 11 + ln 12) 12,566,488$

DRAFT

123

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A B C D E F G H I J K L M N O P

Rate Schedule 1-A 3 Divisor(A) (B) (C) (D) (E) (F) (G)

LineReal Time

GenerationReal Time

LoadReal Time Imports

Real Time Exports

Cleared Virtual Offers

Cleared Virtual Bids

Total (A) to (F)

No. Actuals Actuals Actuals Actuals Actuals ActualsMWhs MWhs MWhs MWhs MWhs MWhs

1 August (YR-2) (Note B) 10,900,000 13,800,000 11,300,000 10,080,000 1,540,000 1,400,000 49,020,000 2 September (YR-2) (Note B) 10,900,000 13,800,000 11,300,000 10,800,000 1,540,000 1,400,000 49,740,000 3 October (YR-2) (Note B) 10,900,000 10,900,000 11,300,000 10,800,000 1,540,000 1,400,000 46,840,000 4 November (YR-2) (Note B) 10,900,000 10,900,000 10,700,000 10,800,000 1,540,000 1,400,000 46,240,000 5 December (YR-2) (Note B) 10,900,000 10,900,000 14,500,000 10,800,000 1,540,000 1,400,000 50,040,000 6 January (YR-1) (Note A) 10,900,000 10,900,000 10,900,000 8,000,000 1,540,000 1,400,000 43,640,000 7 February (YR-1) (Note A) 10,900,000 10,900,000 11,300,000 8,000,000 1,540,000 1,400,000 44,040,000 8 March (YR-1) (Note A) 10,800,000 10,900,000 11,300,000 8,000,000 1,540,000 1,350,000 43,890,000 9 April (YR-1) (Note A) 10,800,000 13,800,000 11,300,000 8,920,000 1,540,000 1,350,000 47,710,000

10 May (YR-1) (Note A) 11,000,000 11,500,000 11,000,000 10,800,000 1,530,000 1,350,000 47,180,000 11 June (YR-1) (Note A) 11,000,000 11,500,000 11,000,000 10,800,000 1,530,000 1,350,000 47,180,000 - 12 July (YR-1) (Note A) 10,700,000 12,600,000 10,500,000 10,800,000 1,530,000 1,350,000 47,480,000 13 Volume of Market Billing Determinants (sum lns 1 to 12, col G) 563,000,000

14 Adjustment for Known Future Impacts to Market Determinants Source of data input -

15 Market Billing Determinants - Adjusted (ln 13 + ln 14) 563,000,000

NoteLetter



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A B C D E F


LineNo.

1 Market Facilitation Costs (Schedule 1-A4 - COST) 30,197,802$ 2 Total Schedule 1-A4 Costs (ln 1) 30,197,802$

3 Prior Year Over or Under Recovery4 Projected (Budgeted) Schedule 1-A4 Revenue Income Statement from Financial Statements 500$ 5 Actual Schedule 1-A4 Revenue Income Statement from Financial Statements 250$ 6 Projected (Budgeted) Schedule 1-A4 Net Revenue Requirement ("NRR") Income Statement from Financial Statements 700$ 7 Actual Schedule 1-A4 NRR Income Statement from Financial Statements 500$ 8 Adjustment for Prior Year Over or (Under) Recovery ((ln 5 - ln 4)+(ln 6 - ln 7)) (50)$


10 Divisor11 Real Time Gen/Load and Import/Exports MWh (Schedule 1-A4 - Divisor) 528,000,000

12 RATE/MWh (ln 9 / ln 11) 0.057$

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A B C D E

Rate Schedule 1-A4 - Market Facilitation Costs

LineNo.


3 Other Direct Costs4 System Maintenance Expense (Sys Maint Exp Alloc) 1,435,000$ 5 Network and Communications Expense (Network & Comm Alloc) 1,113,000$ 6 Outside Service Expenses (Outside Services Alloc) 373,000$ 7 Other Direct Expenses (Other Direct Alloc) 30,000$ 8 Debt Service (Debt Service Alloc) 2,500,000$ 9 Bad Debt (Bad Debt Alloc) 80,000$




13 Total Market Facilitation Costs (ln 11 + ln 12) 30,197,802$

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A B C D E F G H I

Rate Schedule 1-A 4 Divisor(A) (B) (C) (D) (E)

LineReal Time

Generation Real Time LoadReal Time Imports

Real Time Exports Total (A) to (D)

No. Actuals Actuals Actuals ActualsMWhs MWhs MWhs MWhs

1 August (YR-2) Notes letter 10,900,000 13,800,000 11,300,000 10,080,000 46,080,000 2 September (YR-2) Notes letter 10,900,000 13,800,000 11,300,000 10,800,000 46,800,000 3 October (YR-2) Notes letter 10,900,000 10,900,000 11,300,000 10,800,000 43,900,000 4 November (YR-2) Notes letter 10,900,000 10,900,000 10,700,000 10,800,000 43,300,000 5 December (YR-2) Notes letter 10,900,000 10,900,000 14,500,000 10,800,000 47,100,000 6 January (YR-1) Notes letter 10,900,000 10,900,000 10,900,000 8,000,000 40,700,000 7 February (YR-1) Notes letter 10,900,000 10,900,000 11,300,000 8,000,000 41,100,000 8 March (YR-1) Notes letter 10,800,000 10,900,000 11,300,000 8,000,000 41,000,000 9 April (YR-1) Notes letter 10,800,000 13,800,000 11,300,000 8,920,000 44,820,000

10 May (YR-1) Notes letter 11,000,000 11,500,000 11,000,000 10,800,000 44,300,000 11 June (YR-1) Notes letter 11,000,000 11,500,000 11,000,000 10,800,000 44,300,000 12 July (YR-1) Notes letter 10,700,000 12,600,000 10,500,000 10,800,000 44,600,000 13 Volume of Market Billing Determinants (sum lns 1 to 12, col E) 528,000,000

14 Adjustment for Known Future Impacts to Market Determinants Source of data input -

15 Market Billing Determinants - Adjusted (ln 13 + ln 14) 528,000,000

NoteLetter



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A B C D E F G H I J K L M N O P Q R S T U

Salary & Benefits & Direct Employee Allocator

LineNo. TOTAL RS 1 RS 1 RS 2 RS 3 RS 4

Department Input Scheduling Planning TCR Clearing Markets OH TOTAL1 Operations Analysis & Support (800) 1,008,000$ 100.00% 1,008,000$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 100.00%

2 Interegional Affairs (200) 786,000$ 100.00% 786,000$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 100.00%

3 Systems Operations (820) 9,923,000$ 83.00% 8,236,090$ 0.00% -$ 0.00% -$ 0.00% -$ 17.00% 1,686,910$ 0.00% -$ 100.00%

4 Operations Support (860 & 895) 8,503,000$ 44.00% 3,741,320$ 0.00% -$ 0.00% -$ 0.00% -$ 56.00% 4,761,680$ 0.00% -$ 100.00%

5 Market Operations (840) 4,077,000$ 44.00% 1,793,880$ 0.00% -$ 0.00% -$ 0.00% -$ 56.00% 2,283,120$ 0.00% -$ 100.00%

6 Information Technology 22,646,000$ 12.45% 2,819,427$ 2.64% 597,854$ 1.25% 283,075$ 8.13% 1,839,988$ 5.10% 1,153,814$ 70.44% 15,951,842$ 100.00%

7 Settlements (160) 2,882,000$ 40.00% 1,152,800$ 0.00% -$ 0.00% 50.00% 1,441,000$ 0.00% -$ 10.00% 288,200$ 100.00%

8 Credit (140) 736,000$ 3.00% 22,080$ 3.00% 22,080$ 0.00% -$ 43.00% 316,480$ 0.00% -$ 51.00% 375,360$ 100.00%

9 Customer Relations (320) 1,002,000$ 25.00% 250,500$ 15.00% 150,300$ 0.00% -$ 60.00% 601,200$ 0.00% -$ 0.00% -$ 100.00%

10 Customer Training (340) 1,706,000$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 29.55% 504,123$ 70.45% 1,201,877$ 100.00%

11 Engineering R & D and Tariff 4,563,000$ 0% -$ 100% 4,563,000$ 0% -$ 0% -$ 0% -$ 0% -$ 100.00%

12 Engineering Support 2,235,000$ 0% -$ 100% 2,235,000$ 0% -$ 0% -$ 0% -$ 0% -$ 100.00%

13 Engineering Planning (exc dept 450) 4,638,000$ 0% -$ 100% 4,638,000$ 0% -$ 0% -$ 0% -$ 0% -$ 100.00%

14 Congestion Hedging (450) 833,000$ 0% -$ 0% -$ 100% 833,000$ 0% -$ 0% -$ 0% -$ 100.00%

15 Interegional Relations (8200) 284,000$ 0% -$ 100% 284,000$ 0% -$ 0% -$ 0% -$ 0% -$ 100.00%

16 Market Policy (700) 312,000$ 0% -$ 0% -$ 0% -$ 0% -$ 100% 312,000$ 0% -$ 100.00%

17 Market Design (710) 845,000$ 0% -$ 0% -$ 0% -$ 0% -$ 100% 845,000$ 0% -$ 100.00%

18 Market Monitoring Unit 2,908,000$ 0% -$ 0% -$ 0% -$ 100% 2,908,000$ 0% -$ 0% -$ 100.00%

16 All Remaining Departments 15,000,000$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 0.00% -$ 100.00% 15,000,000$ 100.00%

17 Total Salary & Benefits & Direct Employee Costs 84,887,000$ 19,810,097$ 12,490,234$ 1,116,075$ 7,106,668$ 11,546,647$ 32,817,279$ 84,887,000$ -$ Check Total

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A B C D E F G H

System Maintenance Expense Allocators

Line Account No. No. Amount

1 0500-67800-4020-9350-00 System Maintenance Expense for Rate Schedule 1-A1-1 (Note B) 1,275,000$ 2 0500-67700-4020-9350-00 System Maintenance Expense for Rate Schedule 1-A1-2 (Note B) 545,000$ 3 0500-67600-4020-9350-00 System Maintenance Expense for Rate Schedule 1-A2 (Note A) 745,000$ 4 System Maintenance Expense for Rate Schedule 1-A3 N/A5 0500-67600-4020-9350-00 System Maintenance Expense for Rate Schedule 1-A4 (Note A) 1,435,000$ 6 TOTAL 4,000,000$

7 0500-67000 segment Total System Maintenance Expense Budgeted Income Statement from Financial Statements 18,586,000$ input8 Total System Maintenance Expense Allocated Above (ln 6) 4,000,000$ 9 Total System Maintenance Expense Allocated to Corporate Overhead (ln 7 - ln 8) 14,586,000$

NoteA Carve out from Budget for RS #4 - Budget for G/L Acc# less TCR Carveout one vendor with one annual fee (RS 2)B Directly assignable budget costs

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A B C D E F G H I

Network and Communications Expense

Line SPP Acct.No. No. % Amount

1 Network and Communications Expense for Rate Schedule 1-A1-1 (Note A) (ln 6 * ln 1 %) 50% 1,113,000$ 2 Network and Communications Expense for Rate Schedule 1-A1-2 (ln 6 * ln 2 %) 0% -$ 3 Network and Communications Expense for Rate Schedule 1-A2 (ln 6 * ln 3 %) 0% -$ 4 Network and Communications Expense for Rate Schedule 1-A3 (ln 6 * ln 4 %) 0% -$ 5 Network and Communications Expense for Rate Schedule 1-A4 (Note A) (ln 6 * ln 5 %) 50% 1,113,000$ 6 TOTAL 100% 2,226,000$ input

7 0585-66000 segment Network and Communications Expense Budgeted Income Statement from Financial Statements 2,274,000$ 8 Network and Communications Expense Allocated Above (ln 6) 2,226,000$ 9 Network and Communications Expense Allocated to Corporate Overhead (ln 7 - ln 8) 48,000$

NoteA 50 % of Budget for 2 G/L Acc#s - 0585-66330-4010-5611-00 and 0585-66120-4010-5611-00

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Outside Service Expense Allocator

LineNo. Amount

1 Outside Service Expense for Rate Schedule 1-A1-1 (Note A) 2,757,000$ 2 Outside Service Expense for Rate Schedule 1-A1-2 (Note C) 1,839,000$ 3 Outside Service Expense for Rate Schedule 1-A1-2 (Note D) 500,000$ 4 Outside Service Expense for Rate Schedule 1-A2 (Note E) 10$ 5 Outside Service Expense for Rate Schedule 1-A3 N/A6 Outside Service Expense for Rate Schedule 1-A4 (Note B) 373,000$ 7 TOTAL 5,469,010$

8 Outside Service Expense Budgeted Income Statement from Financial Statements 8,420,000$ input9 Outside Service Expense Allocated Above (ln 7) 5,469,010$

10 Outside Service Expense Allocated to Corporate Overhe (ln 8 - ln 9) 2,950,990$

NoteA Directly assignable budget costs (OATI Wrap Agreement, wind forecasting, weather service from SPP Account No. 0500-68600-4010-9230-00 (Note that other costs in th B Directly assignable budget costs from departments 0840, 0895, 0700, 0720, 0710 main account segment 68000 plus 60% SOC 1 Expenses C Directly assignable budget costs from all Engineering departments (400 series plus 8000 plus 8200), All Outside Services Accts (68000 series)D Approved RSC Budget included in Department 1000 - 2 accounts (acc#s 1000-65000-4010-9302-00 and 1000-68930-4010-9280-00)E Directly assignable budget costs dept 450 account 68000 series

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A B C D E F G

Other Direct Expense Allocator

LineNo. Amount

1 Other Direct Expense for Rate Schedule 1-A1-1 (Note A) 50,000$ 2 Other Direct Expense for Rate Schedule 1-A1-2 (Note C) 20,000$ 3 Other Direct Expense for Rate Schedule 1-A2 (Note D) 5$ 4 Other Direct Expense for Rate Schedule 1-A3 (Note D) 10$ 5 Other Direct Expense for Rate Schedule 1-A4 (Note B) 30,000$ 6 TOTAL 100,015$

7 Other Expense Budgeted Income Statement from Financial Statements 200,000$ input8 Other Direct Expense Allocated Above (ln 6) 100,015$ 9 Other Expense Allocated to Corporate Overhead (ln 7 - ln 8) 99,985$

NoteA Directly assignable budget costs B Directly assignable budget costs C Directly assignable budget costs

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A B C D E F G

Debt Service Allocator

LineNo. Amount

1 Debt Service for Rate Schedule 1-A1-1 (Note A) 5$ input2 Debt Service for Rate Schedule 1-A1-2 (Note A) 10$ 3 Debt Service for Rate Schedule 1-A2 (Note A) 5$ 4 Debt Service for Rate Schedule 1-A3 N/A5 Debt Service for Rate Schedule 1-A4 (Note A) 2,500,000$ 6 TOTAL 2,500,020$

7 Debt Service Budgeted Debt Service from Financial Statements 3,000,000$ input8 Debt Service Interest Expense Budgeted Income Statement from Financial Statements 25,000$ 9 Debt Service Allocated Above (ln 7 + ln 8) 2,500,020$

10 Debt Service Allocated to Corporate Overhead (ln 7 + ln 8 - ln 9) 524,980$

NoteA Directly assignable budget costs and applicable interest expense

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A B C D E F G

Bad Debt Allocator

LineNo. Amount

1 Bad Debt for Rate Schedule 1-A1-1 (Note A) 10$ 2 Bad Debt for Rate Schedule 1-A1-2 (Note A) 5$ 3 Bad Debt for Rate Schedule 1-A2 (Note A) 10$ 4 Bad Debt for Rate Schedule 1-A3 N/A5 Bad Debt for Rate Schedule 1-A4 (Note A) 80,000$ 6 TOTAL 80,025$

7 Bad Debt Budgeted Income Statement from Financial Statements 100,000$ input8 Bad Debt Allocated Above (ln 6) 80,025$ 9 Bad Debt Allocated to Corporate Overhead (ln 7 - ln 8) 19,975$

NoteA Directly assignable budget costs

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A B C D E F G

Corp OH Allocators

LineNo.

Amount %1 Corporate Overhead to be Allocated (Net) (ln 27) 51,047,194$

2 Direct Costs By Rate Schedule3 Schedule 1-A1 - Cost-1 (Schedule 1-A1 - Cost-1) 25,005,112$ 38%4 Schedule 1-A1 - Cost-2 (Schedule 1-A1 - Cost-2) 15,394,249$ 23%5 Schedule 1-A2 (Schedule 1-A2) 1,861,105$ 3%6 Schedule 1-A3 (Schedule 1-A3) 7,106,678$ 11%7 Schedule 1-A4 (Schedule 1-A4) 17,077,647$ 26%8 TOTAL (sum lns 3 to 7) 66,444,791$ 100%

9 Corporate Overhead 10 1-A1 - Cost - 1 19,210,548$ 11 1-A1 - Cost - 2 11,826,860$ 12 1-A2 1,429,821$ 13 1-A3 5,459,810$ 14 1-A4 13,120,155$ 15 TOTAL (sum lns 10 to 14) 51,047,194$

Coporate Overhead CostsSalary and Benefits & Employee Direct Expenses

16 Total Salary & Benefits & Employee Direct Expenses (Salary Benefit EE Direct Alloc) 32,817,279$

17 Other18 System Maintenance Expense (Sys Maint Exp Alloc) 14,586,000$ 19 Network and Communications Expense (Network & Comm Alloc) 48,000$ 20 Outside Service Expenses (Outside Services Alloc) 2,950,990$ 21 Other Direct Expenses (Other Direct Alloc) 99,985$ 22 Debt Service (Debt Service Alloc) 524,980$ 23 Bad Debt (Bad Debt Alloc) 19,975$ 24 Total Other (sum lns 18 to 23) 18,229,930$

25 Total Corporate Overhead (ln 16 + ln 24) 51,047,209$

26 LESS: Revenues Other Than Admin Fees SPP Account No. 0100-45200 through 49999 15$ input

27 Corporate Overhead to be Allocated (Net) (ln 25 + ln 26) 51,047,194$

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A B C D E F G

Total Costs

LineNo.

Costs Directly Assignable to Rate Schedules1 Salary and Benefits & Employee Direct Expenses2 Total Salary & Benefits & Employee Direct Expenses (Salary Benefit EE Direct Alloc) 52,069,721$

3 Other Direct Costs4 System Maintenance Expense (Sys Maint Exp Alloc) 4,000,000$ 5 Network and Communications Expense (Network & Comm Alloc) 2,226,000$ 6 Outside Service Expenses (Outside Services Alloc) 5,469,010$ 7 Other Direct Expenses (Other Direct Alloc) 100,015$ 8 Debt Service (Debt Service Alloc) 2,500,020$ 9 Bad Debt (Bad Debt Alloc) 80,025$


11 Total Costs Directly Assignable to Rate Schedules (ln 2 + ln 10) 66,444,791$

Corporate Overhead Costs12 Salary and Benefits & Employee Direct Expenses13 Total Salary & Benefits & Employee Direct Expenses (Salary Benefit EE Direct Alloc) 32,817,279$

14 Other Direct Costs15 System Maintenance Expense (Sys Maint Exp Alloc) 14,586,000$ 16 Network and Communications Expense (Network & Comm Alloc) 48,000$ 17 Outside Service Expenses (Outside Services Alloc) 2,950,990$ 18 Other Direct Expenses (Other Direct Alloc) 99,985$ 19 Debt Service (Debt Service Alloc) 524,980$ 20 Bad Debt (Bad Debt Alloc) 19,975$ 21 Total Other (sum lns 15 to 20) 18,229,930$

22 Corporate Overhead (ln 13 + ln 21) 51,047,209$

23 LESS: Revenues Other Than Admin Fees Corp OH Alloc) 15$

24 Corporate Overhead to be Allocated (Net) (ln 22 - ln 23) 51,047,194$

25 Total Directly Assignable Costs and Corp Overhead (ln 11+ ln 24) 117,491,985$

26 Total Schedule 1-A1 - Costs (Schedule 1-A1 - Rate) 71,436,769$ 27 Total Schedule 1-A2 - Costs (Schedule 1-A2 - Rate) 3,290,926$ 28 Total Schedule 1-A3 - Costs (Schedule 1-A3 - Rate) 12,566,488$ 29 Total Schedule 1-A4 - Costs (Schedule 1-A4 - Rate) 30,197,802$ 30 Total of Schedules 1-A1 to 1-A4 Costs (sum lns 26 to 29) 117,491,985$

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SCHEDULE 1A TASK FORCE WHITE PAPER

March2019

Schedule1ATaskForce

SouthwestPowerPool,Inc.

REVISION HISTORY

DATE OR VERSION NUMBER

AUTHOR CHANGE

DESCRIPTION COMMENTS

1/29/2019 D.Branch InitialDraft

2/13/2019 D.Branch Updates/Graph

3/5/2019 J.Olsen Updates

3/8/19 D.Branch Updates

3/11/19 D.Branch Updates


CONTENTS

RevisionHistory.........................................................................................................................................................................i

Section1:Introduction&Background...........................................................................................................................1

Rate Schedule Location Determination .................................................................................................... 1

Section2:ProcessOverview...............................................................................................................................................2

Section3:OverviewofRateSchedules...........................................................................................................................3

Rate Schedule #1 (RS 1) ‐ .......................................................................................................................... 3

Rate Schedule #2 (RS 2) ‐ .......................................................................................................................... 4

Rate Schedule #3 (RS 3) ‐ .......................................................................................................................... 5

Rate Schedule #4 (RS 4) ‐ .......................................................................................................................... 6

Section4:CashFlowandBillingDeterminantAnalysis..........................................................................................7

Section5:MiscellaneousAdjustments.........................................................................................................................10

Transition True‐Up .................................................................................................................................. 10

Other Direct Expenses to be Recovered ................................................................................................. 10

Continuation of Current Cap for Schedule 1A ........................................................................................ 10

Section6:Conclusion...........................................................................................................................................................10


Schedule1ATaskForceWhitePaper 1

SECTION 1: INTRODUCTION & BACKGROUND

SPP currently recovers the vast majority of its operating and capital costs from transmission customers who are taking service under the SPP tariff. This recovery approach was implemented when SPP solely provided transmission service under the SPP tariff. The SPP’s operating and capital costs increased with the addition of the Energy Imbalance Services market in 2007 and again in 2014 with the implementation of the Integrated Marketplace. These increases in services and costs warrant a review of SPP’s current cost recovery mechanism. There is a desire to have those who use and benefit from SPP’s services help pay for those services.

The Schedule 1A Task Force (the “Task Force”) was formed to develop a potential rate structure that would recover SPP’s costs from the various users of SPP’s services with the overarching principles of simplicity, better alignment of payer cost/benefit, and inclusion of energy transactions. The Task Force was comprised of the following members: John Olsen, Evergy (Chair) Joel Dagerman, Nebraska Public Power District David Mindham, ITC Holdings Corp. John Varnell, Tenaska Rob Janssen, Dogwood Energy Alfred Busbee, GDS Associates/ East Texas Electric Cooperatives R.J. Tallman, Oklahoma Gas & Electric Wes Berger, Southwestern Public Service Co. Ray Bergmeier, Sunflower Electric Power Corporation Greg Garst, Omaha Public Power District Heather Starnes, Missouri Joint Municipal EUC Tim Hall, Southern Power Jason Mazigian, Basin Electric Power Cooperative Jim Jacoby, American Electric Power-Public Service Company of Oklahoma

RATE SCHEDULE LOCATION DETERMINATION

TheTaskForcediscussedthebenefitsandissueswithcreatinganewscheduleinthetariffversuscontinuingtousethecurrentSchedule1A.ThedecisionwastokeepthesechargesinSchedule1AtominimizethenumberoftariffchangesnecessaryinboththeSPPtariffandineachindividualmembertariffthatreferstoSchedule1A.WithinSchedule1A,therewillbedifferentsectionsforeachoftherateschedulesdetailedbelow.



SECTION 2: PROCESS OVERVIEW

Before arriving at their final recommendation, the Task Force performed the following activities:

Reviewed extensively SPP’s cost in the FERC 668 reporting categories Examined RTO/ISO cost recovery methodologies for other regions Reviewed the current Schedule 1A billing processes Reviewed multiple iterations of strawman proposals (including staff whitepaper) Conducted multiple brain storming sessions on rate design Analyzed “cost shifts” between customer groups associated with proposed rate

structures Reviewed cash flow analysis to assess impact of the proposed rate structures on

SPP’s cash position Consulted with SPP’s market monitoring unit (MMU) to ascertain whether

proposed changes would be problematic from their perspective

Early in the process, the Task Force agreed to use the cost reporting framework that followed the FERC’s requirement under Order 668. In summary, all operating costs would be evaluated in the categories that include FERC accounts 575.7 - Market Facilitation, Monitoring & Compliance; 561.4 - Scheduling, System Control & Dispatch; and 561.8 – Reliability Planning & Standards Development. The Task Force quickly reached general agreement that the proposed structure should use a mix of demand and energy charges. The Task Force also reached general agreement that market costs should be recovered through energy charges and transmission planning costs should be recovered through demand charges. Additional discussions were necessary to determine the ultimate recommendation for 1) allocating Scheduling & Dispatch costs, 2) appropriate energy billing determinants, and 3) treatment of financial instruments (e.g. virtual transactions, TCRs).

After additional analyses and related discussions, the majority of the Task Force voted to 1) combine Scheduling & Dispatch costs with Reliability Planning under a demand based rate structure (similar to the current Schedule 1A billing practices); 2) include real time generation, load, and import/exports as energy billing determinants, 3) exclude day ahead market products; and 4) include TCRs and virtual transactions as billable transactions. Using these agreed upon concepts, the Task Force arrived at a four schedule cost recovery methodology summarized in the following section.

The market monitoring unit (MMU) was consulted by the Task Force on a couple specific issues, most notably was whether they (the MMU) would be receptive to market participants adding administrative service costs to mitigated offer curves. The MMU indicated they had no issue with the inclusion of these costs in the mitigated energy offer curves given administrative costs based on megawatt hours are considered short-run marginal costs and therefore could be included in the mitigated offers.



SECTION 3: OVERVIEW OF RATE SCHEDULES

RATE SCHEDULE #1 (RS 1) - TRANSMISSION ADMINISTRATIVE SERVICE RS 1 provides for the recovery of costs incurred by the Transmission Provider in providing; 1) reliability coordination; 2) transmission scheduling, 3) system control, and 4) transmission planning services. The costs to be recovered under RS 1 include any costs of direct resources, system maintenance, debt service for financing capital purchases associated with providing these services, a proportionate allocation of corporate overhead, and other costs associated with administering this service. Please note that the total costs recovered through RS 1 equals those costs reported by the Transmission Provider as being associated with FERC accounts 561.4 – Scheduling, System Control & Dispatch and 561.8 – Reliability Planning & Standards Development. RS 1 costs will be recovered by assessing customers who use Point-to-Point Transmission Service and Network Integration Transmission Service under the SPP tariff. The billing determinant used for this rate schedule assessed to Point-To-Point Transmission Service is the MW of the reservation multiplied by the number of hours reserved for the applicable month made by the Transmission Customers. The billing determinant used for this rate schedule assessed to Network Integration Transmission Service is the 12-month average of the Transmission Customer’s coincident Zonal Demands used to determine the Demand Charges under Schedule 9 of the Tariff multiplied by the number of all hours of the applicable month. The charge per MW per hour shall be the same for Point-To-Point Transmission Service as for Network Integration Transmission Service.

Below is an illustration of the calculation for RS 1 utilizing 2017 data for costs and 12CP estimate from the 2018 budget.



The majority of the Task Force also agreed that we should continue to charge the Transmission Customers for each transmission service request submitted as follows:

(i) For Firm Point-To-Point Transmission Service: Reservations less than one month: $100 Reservations one month or longer: $200

(ii) For Non-Firm Point-To-Point Transmission Service: Each Reservation: $0.

Additionally, the Task Force agreed that we should continue the practice of rebating the Transmission Customer this fee once the Transmission Customer becomes legally obligated to pay the applicable Firm Point-To-Point Transmission Service charges under this Tariff or if the requested Firm Point-To-Point Transmission Service is denied by the Transmission Provider.

RATE SCHEDULE #2 (RS 2) - TRANSMISSION CONGESTION RIGHTS ADMINISTRATIVE SERVICE

RS 2 provides for the recovery of costs incurred by the Transmission Provider to provide 1) TCR administration through allocation, assignment, auction, or any other process under this Tariff; 2) simultaneous feasibility tests and other applicable studies to determine the total TCRs that can be accommodated by the Transmission System; 3) TCR tools; and 4) a secondary market for TCRs. The costs to be recovered under RS 2 charges include any direct resources, system maintenance, debt service for financing capital purchases associated with providing these services, a proportionate allocation of corporate overhead, and all other costs associated with the Transmission Provider administering this service. The billing determinant used for RS 2 is the total amount of TCR volume for all TCR Holders expressed in MWh. The total TCR volume is the sum of the hourly TCR MWh for each billing period.

Below is an illustration of the calculation for RS 2 utilizing 2017 data for costs and billing determinants:



RATE SCHEDULE #3 (RS 3) - INTEGRATED MARKETPLACE CLEARING ADMINISTRATIVE SERVICE

RS 3 provides for the recovery of costs incurred by the Transmission Provider in providing; 1) market settlements; 2) credit evaluation and risk mitigation services; 3) market monitoring functions; 4) information technology support; and 5) customer service. The costs to be recovered under RS 3 are any direct resources, a proportionate allocation of corporate overhead, and all other costs associated with administering this service.

The primary reason for creating RS 3 was to provide a mechanism to assess an appropriate charge to virtual energy market participants. Task force members believed these market participants should be charged something for the benefits they receive from participating in the market, but the charge should be based on a cost structure smaller than that of the fully loaded marketplace facilitation administrative service charge. As a result, the clearing administrative charge was developed based on only those costs associated with clearing the market. In concert with this change, the Task Force also voted to eliminate the $0.05 transaction fee amount on virtual bids/offers as currently referenced in Attachment AE, Section 8.5.17. The billing determinants used for RS 3, as expressed in MWh are: 1) all Real-Time energy injected into and withdrawn from the Transmission System by Market Participants; 2) all Import Interchange Transactions in Real-Time and all Export Interchange Transactions in Real-Time; and 3) all cleared Virtual Energy Bids and all cleared Virtual Energy Offers. Below is an illustration of the calculation for RS 3 utilizing 2017 data for costs and billing determinants:



RATE SCHEDULE #4 (RS 4) - INTEGRATED MARKETPLACE FACILITATION ADMINISTRATIVE SERVICE RS 4 provides for the recovery of any costs incurred by the Transmission Provider in providing the 1) Day-Ahead Market; 2) Real-Time Balancing Market; and 3) Reliability Unit Commitment Processes. The costs to be recovered under RS 4 include any direct resources, system maintenance, debt service for financing capital purchases associated with providing these services, a proportionate allocation of corporate overhead, and all other costs associated with the Transmission Provider administering this service. Please note that the total costs recovered through RS 2, RS 3, and RS 4 equal those costs reported by the Transmission Provider as being associated with FERC account 575.7 - Market Facilitation, Monitoring & Compliance. The main objective in the design for Rate Schedules 2 through 4 was to assign those specific costs associated with Transmission Congestion Rights and Market Clearing Administrative Services to RS 2 and RS 3, respectively, and then use Rate Schedule 4 to recover all remaining costs under a Market Facilitation Administrative Service charge. The billing determinants used for RS 4, as expressed in MWh, are: 1) all Real-Time energy injected into and withdrawn from the Transmission System and 2) all Import Interchange Transactions in Real-Time and all Export Interchange Transactions in Real-Time.

Below is an illustration of the calculation for RS 4 utilizing 2017 data for costs and billing determinants -



The following table provides an overview of the important elements for all proposed rate schedules.

SECTION 4: CASH FLOW AND BILLING DETERMINANT ANALYSIS

Once the proposed rate structure was in place, SPP staff performed a review of the impact that the new structure would have on the organizations cash flows, including a sensitivity analysis to contemplate the impacts that fluctuations in billing metrics could have on cash flows. An exhibit from that analysis is presented below for illustrative purposes.



SPP Staff concluded their analysis of the cash flows with the following observations:

1) Seasonality in cash outflows exist today with notable spikes at quarter end (primarily due to debt payments)

2) Seasonal cash flow decreases noted in the periods examined are representative of historical trends

3) Cash flow position under proposed scenarios does not materially improve or worsen in comparison to actual results under current Schedule 1A methodology

4) Consistent with current practices, seasonal spikes can be managed with existing, short term financing arrangements

5) A net cumulative cash flow impact reaching negative $15.0 MM would create actionable concern and that it would take a 10% annual decrease in billing determinants to get close to that $15.0MM threshold in the periods examined in this analysis.

Recognizing that volatility of billing determinants could have an impact on over/under recovery, the Task Force also reviewed monthly billing determinant data for the market-based rate schedules (RS 2-4) using the following criteria:

1) 2015-2018 actual data 2) TCRs awarded and converted for RS 2 3) Real time generation, load, import/export, and virtual energy for RS 3 4) Real time generation, load, and import/export for RS 4

Exhibits from SPP staff’s analysis are presented below for illustrative purposes.



Based on the analysis of monthly trending and the rolling 12-month average from 2015-18, SPP staff summarized their observations as follows:

1) Rolling average for Rate Schedules 3 and 4 billing determinants is relatively flat with only a modest rise over the 4-year period

2) Rolling average for Schedule 2 billing determinants is relatively flat with moderate rise beginning in late 2017 (likely due to increased congestion from wind, increase in financial only asset owners, etc.)

Taking into consideration both the cash flow analysis and billing determinant trend information, the Task Force ultimately decided on an annual rate setting process for rates that would be in effect for the following calendar year. Rates would be estimated based on actual billing determinants for the previous 12 months (August-July to coincide with the timing of the budget preparation for the following calendar year). The chart below illustrates the time period utilized for estimating the billing determinants in relationship to the timing of the rate setting process and actual billing period.



SECTION 5: MISCELLANEOUS ADJUSTMENTS

TRANSITION TRUE-UP

Theinitialratesettingprocessunderthenewstructurewillneedtoconsidertheover/underrecoveryforthelastcalendaryearundertheoldschedule1AmethodologyasanadjustmenttotheRS1calculationfortheupcomingbudgetyear.Thetrue‐upadjustmentwouldbeexclusivetoRS1asitwouldconsistofthesamepopulationofpayers(i.e.transmissioncustomersonly).Duetothefactthatwedonothavefinalresults(forthecurrentyear)atthetimewearecalculatingtherateforthesubsequentyear,anestimateofover/underrecoverywillbefactoredintothefirstyearcalculationofRS1andanotherfinaladjustmentwillbemadeinthefollowingyeartotrue‐upthepreviousyear’sestimate.Afterthesecondyearratecalculation,normaltrue‐upprocesseswillbefollowedforRS1.

OTHER DIRECT EXPENSES TO BE RECOVERED

WhiletheTaskForcehasattemptedtoallocatealldirectlyassignablecoststothefourrateschedulesasappropriateandhasalsoconsideredtheallocationofcorporateoverhead,itisimpossibletocontemplateallrecoverableexpensesthatmightariseinthefuturethatwouldneedtobeassignedtoeitheraspecificratescheduleorallocatedtoallrateschedulesonaproratabasis.Suchitemscouldincludebaddebtexpense,regulatorypenalties,andanyothernon‐recurringexpensesincurredbySPP.Certainlineswillbeincludedintheformularatetemplatestocapturesuchitems.Whentheseadditionalcostsareaddedtothetemplate,afootnotewillbeaddedtothedetailthecharge.

CONTINUATION OF CURRENT CAP FOR SCHEDULE 1A

ThecurrentSPPtariffhasacapontherateforSchedule1A.TheTaskForcedebatedthebenefitandneedforsuchacapgoingforward.Thenewratescheduleshaveseveralmovingpartsandeachwillhaveatrueupadjustment,whichwouldmakecreatingacapforeachindividualratescheduleproblematic.TheTaskForcedidwanttocontinuetheuseofarateinsteadofaharddollarcaptoallowtheoverallcoststoadjustastheloadservedbymemberschanges.TheTaskForceagreedtocontinuecalculatingthecapthesameasisdonetodaybytakingthetotalSPPbudgetanddividingitbytheMWHsassociatedwiththeNITS12CPcalculationandthepointtopointtransmissionreservations.Thisratewillbecalculatedintheformularatetemplateannuallyandcomparedtothecapforoverallcostcontrolpurposes.

SECTION 6: CONCLUSION

SPP’s current administrative fee structure was established when SPP first provided transmission service under its tariff in 1998 and obviously never contemplated the additional energy market services currently provided. The overarching principles guiding the Task Force since its inception was to develop a rate structure that was simple to implement/administer, provided



better alignment of beneficiary with payer, and included energy transactions. The Task Force carefully researched and evaluated the costs comprising SPP’s administrative fee in relationship to our required reporting under FERC Order 668, considered the structure and methodology utilized by other RTO/ISOs, and deliberately examined the services provided by SPP through the lens of the beneficiary versus payer. Through much analysis and spirited debate, the Task Force has agreed upon a four-rate schedule cost recovery methodology described in detail in this document. This proposed methodology allocates a proportionate share of recoverable costs to our market participants including financial only entities. Additionally, staff believes that the current proposed structure will not translate to any material system or staffing costs to implement/administer. In conclusion, the Task Force recommends the four-rate schedule cost recovery methodology as described in this document for further consideration/approval by all relevant governing bodies to move forward with all activities necessary for full implementation.