Southwest MARKET WORKING GROUP MEETING November 17 … minutes... · 2019-02-08 · Minutes No. [241] Southwest Power Pool MARKET WORKING GROUP MEETING November 17‐18, 2015 AEP

Southwest Power Pool

MARKET WORKING GROUP MEETING

November 17‐18, 2015

AEP Offices – Dallas, TX

• Summary of Motions •

Motions: Agenda Item 2 – Consent Agenda Ron Thompson (NPPD) motioned and Chris Lyons (Exelon) seconded to approve the consent agenda. The motion passed with no oppositions and no abstentions. Agenda Item 8 – RR32_MPRR218 – Market Registration Naming Conventions Kevin Galke (CUS) motioned and Valerie Weigel (Basin) seconded to approve RR32_MPRR218 as modified by the MWG. The motion passed with one opposition (WR) and one abstention (Exelon). Agenda Item 10 – RR125 Removal of Day‐Ahead Limited Must‐Offer Richard Ross (AEP) motioned and Kevin Galke (CUS) seconded to approve RR125 as submitted by the MWG. The motion passed with three oppositions (Midwest, GSEC, OPPD) and four abstentions (Xcel, WR, KMEA, NPPD). Agenda Item 11 – RR127 JOU Combined Option Jim Flucke (KCPL) motioned and Cliff Franklin (WR) seconded to approve RR127 as modified by the MWG accepting the impact analysis as presented. The motion passed with no opposition and seven abstentions (OPPD, GSEC, Xcel, CUS, KMEA, AECC, EDE). Agenda Item 12 – RR128 Rewriting Start‐Up Eligibility Ron Thompson (NPPD) motioned and Cliff Franklin (WR) seconded to approve RR128 as submitted. The motion passed with no oppositions and no abstentions. Agenda Item 13 – RR129 Settlement Clean‐Up Katie Mentzel (OMPA) motioned and Ron Thompson (NPPD) seconded to approve RR129 as submitted. The motion passed with no oppositions and no abstentions. Agenda Item 14 – RR130 Commitment Notification Enhancement Valerie Weigel (Basin) motioned and Carrie Dixon (Xcel) seconded to approve RR130 as submitted. The motion passed with one opposition (OPPD) and one abstention (WR). Agenda Item 19ciii – RR8_MPRR164 Mitigated Offer Clarifications Shawn McBroom (OGE) motioned and Cliff Franklin (WR) seconded to reject RR8_MPRR164 with guidance to staff to bring back a new updated RR of RR8_MPRR164 to the MWG. The motion passed with no oppositions and no abstentions.

Minutes No. [241]

Southwest Power Pool


November 17‐18, 2015

AEP Offices – Dallas, TX

• M I N U T E S •

Agenda Item 1 — Call to Order, Proxies, Agenda Discussion Richard Ross (AEP) called the meeting to order at 8:15 a.m. The attendance was recorded and proxies were announced (Attachment 1 ‐ MWG Attendance November 17‐18 2015). The following members were represented by proxy:

Cliff Franklin (WR) for Aaron Rome (Midwest) (Attachment 1a ‐ Aaron Rome Proxy) Katie Mentzel (OMPA) for Mike Mushrush (OMPA) (Attachment 1b ‐ Mike Mushrush Proxy) Terry Wright (EDE) for Rick McCord (EDE) (Attachment 1c ‐ Rick McCord Proxy) Mark Trumble (OPPD) for Rick Yanovich (OPPD) (Attachment 1d ‐ Rick Yanovich Proxy)

The group reviewed the agenda (Attachment 2 ‐ MWG Agenda for November 2015). Agenda Item 2 — Working Group/Committee Updates Richard Ross (AEP) updated the MWG on the BOD votes in October. All revision requests on the BOD’s agenda were approved. Agenda Item 3 — Consent Agenda Richard Ross (AEP) introduced the consent agenda items and asked if anyone would like to pull anything from that agenda. There were no requests to pull any items from the agenda. Ron Thompson (NPPD) motioned and Chris Lyons (Exelon) seconded to approve the consent agenda. The motion passed with no oppositions and no abstentions. Agenda Item 4 — Marketplace RR January 2016 MOPC Schedule Erin Cathey (SPP) displayed the January 2016 MOPC Schedule and pointed out the date of November 23, 2015 as the submission deadline for non‐expedited Revision Requests to make it to the January 2016 MOPC (Attachment 3 ‐ January Market Protocol RR MOPC Schedule). Agenda Item 5 — Trading Hubs Update Valerie Weigel (Basin) updated the MWG on activities of the Trading Hubs Focus Group. She told the group that two financial Market Participants will provide better insight to the MWG on the financial perspective and the group recommended the January MWG meeting for the presentation. Valerie updated the MWG that the Trading Hub Focus Group will have a conference call with ICE and Nodal Exchange to ask questions on the products and services they offer. Agenda Item 6 — Ramp Product Next Steps

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Matt Moore (GSEC) updated the MWG on the progress of the Ramp Product Focus Group (Attachment 4 ‐ RPFG November 2015 update). The Ramp Product Focus Group asked the MWG to defer the meetings on a ramp product and start a new focus group on price formulation. The Ramp Product Focus Group would like to research and discuss price transparency, headroom, scarcity pricing, VRL and Operating Reserve relaxation, RUC without proper compensation, no incentive for unit commitments prior to events verses RUC, and economics with reliability event. The topics listed above were discussed in the Ramp Product Focus Group. However, the scope of the Ramp Product Focus Group was limited to a ramp product. Members were concerned that if the ramp product went in before the other topics were considered, it could be viewed as a band aid approach to fixing potential issues in the Integrated Marketplace. Matt recommended to the MWG the Price Formation Focus Group would examine from a holistic perspective whether prices are appropriately incentivizing resources, capturing marginal costs, and providing sufficient price transparency. The MWG endorsed the creation of the Price Formation Focus Group. Richard Dillon (SPP) will further define the scope of the Price Formation Focus Group. Any parties interested in participating in the discussions, will send an email Debbie James at [email protected]. Agenda Item 7 — BOD Action Item for MOPC and MWG: MMU ASOM Recommendations Last month, Gay Anthony (SPP) facilitated a discussion with the MWG as part of fulfilling a SPP BOD action item assigned to MOPC and MWG to review the nine recommendations for market design changes or enhancements by the SPP MMU in their 2014 Annual State of the Market (ASOM) report (Attachment 5 ‐ BOD Action Item for MOPC‐MWG ‐ on MMU ASOM ‐ Nov 2015 ‐ with edits by MWG), and prepare responses/recommendations for presentation to the BOD in a future meeting. Gay reviewed the thoughts and proposed responses from the MWG on each of the MMU recommendations and updated some of the proposed responses to give to the BOD. The final recommendation is included in the MWG minutes background materials. The target date for presentation of responses to the BOD is January 2016. Agenda Item 8 — RR32_MPRR218 ‐ Market Registration Naming Conventions Erin Cathey (SPP) presented RR32 to the MWG (Attachment 6 ‐ ). Erin explained that the revision request was updated with the current Protocol language. Eddie Watson and Gerald Williams (SPP) presented the examples of the naming conventions to the MWG (Attachment 7 ‐ Updated SPP Naming Conventions Data Examples_v2). Kevin Galke (CUS) motioned and Valerie Weigel (Basin) seconded to approve RR32_MPRR218 as modified by the MWG. The motion passed with one opposition (WR) and one abstention (Exelon). Agenda Item 9 — Physical Withholding Penalty Discussion Catherine Mooney (SPP) discussed a propose design changes to add a penalty for violation of the Physical Withholding rules in Marketplace. Catherine explained that NYISO, MISO and New England have a Physical Withholding Penalty in their markets. Catherine explained that there would be no substantial changes to the triggers of Physical Withholding that are currently in the Protocols and Tariff. She explained that the Physical Withholding Penalty was a back stop for Market Power Issue. Members had concerns on the timing of the penalty. The members asked when the penalty occurred, that the notification happened as soon as possible so the members could correct the issue and not receive futher penalty.

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Agenda Item 10 — RR125 Removal of Day‐Ahead Limited Must‐Offer Jared Greenwalt (SPP) presented some potential impacts from SPP's perspective of removing the Limited Day‐Ahead Must‐Offer to the MWG (Attachment 8 ‐ Considerations for RR125). If the Limited Day‐Ahead Must‐Offer is removed, then there could be fewer Resources offering in the Day‐Ahead Market. There would be a potential for shortage of capacity in the Day‐Ahead Market. The shortage of capacity could lead to prices increasing and more reliability‐only Resources clearing. Additionally, it could lead to more virtual Resources clearing. There could be a decrease in Resource commitments out of the Day‐Ahead Market and an increase of commitments needed from the Day‐Ahead RUC. This could increase RUC Make‐Whole payments and decrease the number of Resources for RUC to choose from since RUC has a shorter lead‐time than the Day‐Ahead Market. Richard Ross (AEP) presented RR125 Removal of Day‐Ahead Limited Must‐Offer to the MWG (Attachment 9 ‐ RR125 Recommendation Report). He explained to the MWG that RR125 would eliminate a requirement that MWG members put on themselves that does not work, is inefficient and should be removed. Some MWG members had a concern that they did not want to remove the Limited Day‐Ahead Must‐Offer without first reviewing the Physical Withholding Penalty in detail. Richard reminded the MWG that as discussed in the Physical Withholding Penalty Discussion, the SPP MMU intended to bring forth a revision request regardless of the MWG approving or rejecting RR125. Richard Ross (AEP) motioned and Kevin Galke (CUS) seconded to approve RR125 as submitted by the MWG. The motion passed with three oppositions (Midwest, GSEC, OPPD) and four abstentions (Xcel, WR, KMEA, NPPD). Agenda Item 11 — RR127 JOU Combined Option Jim Flucke (KCPL) updated the MWG on RR127 JOU Combined Option (Attachment 10 ‐ RR127 Recommendation Report). He explained that RR127 was written in response to October’s MWG direction to develop a Revision Request that would implement the aggregate Energy Offer Curve option. Jim explained that RR127 eliminates the potential gaming opportunity by taking all share’s pricing point of a Combined Resource Option for a JOU and aggregating those price points into one Energy Offer Curve. This Revision Request makes all shares under a Combined Resource Option to start at a minimum capacity of zero for the first price point. If committed, all shares of that Combined Resource Option for that JOU will be eligible to recover Start‐Up and No‐Load costs as described in the Protocols. The shares will only receive a dispatch instruction greater than zero based upon the one new aggregated Energy Offer Curve thus eliminating the gaming opportunity. Micha Bailey (SPP) reviewed the RR127 Protocols and Tariff language to the MWG. Jim Flucke (KCPL) motioned and Cliff Franklin (WR) seconded to approve RR127 as modified by the MWG accepting the impact analysis as presented. The motion passed with no opposition and seven abstentions (OPPD, GSEC, Xcel, CUS, KMEA, AECC, EDE). Agenda Item 12 — RR128 Rewriting Start‐Up Eligibility Micha Bailey (SPP) presented RR128 Rewriting Start‐Up Eligibility to the MWG (Attachment 11 ‐ RR128 Recommendation Report). He explained to the MWG that RR128 did not have any system impacts. All system impacts are included in RR16_MPRR190 and RR118. The language on Start‐Up eligibility

Minutes No. [241]

recovery for the Day‐Ahead and Real‐Time Balancing Market has circular references and is not easy to read. RR128 deletes out the circular references and cleans up the language. Ron Thompson (NPPD) motioned and Cliff Franklin (WR) seconded to approve RR128 as submitted. The motion passed with no oppositions and no abstentions. Agenda Item 13 — RR129 Settlement Clean‐Up John Luallen (SPP) presented RR129 Settlement Clean‐Up to the MWG (Attachment 12 ‐ RR129 Recommendation Report). RR129 was drafted to include various Settlement clean up items that were found in the Protocols which include deleting attributes, adding a hashtag in front of billing determinates to indicate rounding, cleaning up various definitions in the variable table, adding 5min to Real‐Time Flags to indicate that those flags are 5 minutes and adding language to the Protocols that match the ER16‐130 Tariff Clean‐Up filing. Katie Mentzel (OMPA) motioned and Ron Thompson (NPPD) seconded to approve RR129 as submitted. The motion passed with no oppositions and no abstentions. Agenda Item 14 — RR130 Commitment Notification Enhancement Casey Cathey (SPP) presented RR130 Commitment Notification Enhancement to the MWG (Attachment 13 ‐ RR130 Recommendation Report). Currently SPP Resource commitments are confirmed by the Market Participant’s system. A timestamp of receipt log is maintained by SPP in order to provide assurance that a Market Participant received all SPP Resource commitment start‐up and shut‐down notifications. There is a gap in the current process where a Market Participant’s system provides a timestamp of receipt; however the operator does not receive the commitment instruction. RR130 will address this gap by requiring a manual acknowledgement via the Markets User Interface or Automatic Programmable Interface to confirm the notifications were received and ensuring the operator receives the commitment instruction. SPP will follow‐up with a phone call if the commitment instruction is not manually confirmed. Members were concerned that this would be an extra step for them and that RR130 is not needed. Valerie Weigel (Basin) motioned and Carrie Dixon (Xcel) seconded to approve RR130 as submitted. The motion passed with one opposition (OPPD) and one abstention (WR). Agenda Item 15 — Benefits of adding Stored Energy Rules to Marketplace Yasser Bahbaz (SPP) discussed with the MWG the benefits of adding Stored Energy Rules to the Integrated Marketplace (Attachment 14 ‐ SER Prelim Benefits). Yasser explained that other markets have reported benefits from Stored Energy Resources (SERs) specifically batteries. Yasser explained that some of the benefits to SPP will be potential Regulation requirement reduction, possible reduction in commitment costs, potential reduction in Market’s Regulation costs and SERs could smooth out ramping events for Variable Energy Resources (VERs). Agenda Item 16 — Action Item #241 Public and Private data Micha Bailey (SPP) discussed Action Item #241 Public and Private data with the MWG (Attachment 15 ‐ Action Item #241 ‐ Public and Private Data). Micha provided links to the members for Market, Settlements and Market to Market public data. He demonstrated how to navigate to the documents by using the links provided in the presentation. The MWG directed SPP Staff to close out Action Item #241.

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Agenda Item 17 — Action Item #242 Safety Net Offer Cap Micha Bailey (SPP) discussed Action Item #242 Safety Net Offer Cap with the MWG (Attachment 16 ‐ Action Item #242 ‐ Safety Net Offer Cap). He explained to the MWG that this action item was on hold until after FERC rules on PJM’s ER14‐1144. He presented a time line of action on ER14‐1144. He explained that SPP did not have an instance where offers exceeded the Safety Net Offer Cap. PJM did have an instance when offers exceeded their Safety Net Offer Cap and submitted the waiver to FERC. The MWG directed SPP Staff to close out Action Item #241. Agenda Item 18 — Action Item #276 SPP Registration and Onboarding Process Erin Cathey (SPP) presented Action Item #276 SPP Registration and Onboarding Process with the MWG (Attachment 17 ‐ SPP Response to MWG Action Item 276). Erin explained that SPP has taken steps to enhance the Model Update process. SPP has developed a User Guide for the Modeling Tool, enhanced training documentation, enhanced Model Coordination processes to improve distribution of registration data and developed RR to allow SPP to deny a registration change if all required information was not provided by the deadline. The MWG directed SPP Staff to close out Action Item #241. Agenda Item 19a — MMU Marketplace Update Catherine Mooney (SPP MMU) presented the MMU Marketplace Update and answered questions from the group (Attachment 18 ‐ 201510 MWG MMU Market Update). Agenda Item 19b — RTO Marketplace Update Gentry Crowson (SPP) presented the RTO Marketplace Update and answered questions from the group (Attachment 19 ‐ November 2015 RTO Update). Agenda Item 19c — Regulatory Report Marisa Choate (SPP) presented the Regulatory Report and answered questions from the group (Attachment 20 ‐ Regulatory Report to MWG 201511). Agenda Item 19ci — FERC NOPRs update Patti Kelly (SPP) updated the MWG on the status of the comments for the FERC NOPRs. Patty explained that SPP would not have time to take the comments through the stakeholder process since the due date is November 30, 2015. Agenda Item 19cii — Mitigated Offer FERC Filing ER15‐2268 Patti Kelly (SPP) updated the MWG on the Mitigate Offer FERC Filing. Patti explained that FERC rejected the filing and that no parties had filed for a request for rehearing with FERC. ER15‐2268 was considered closed. Agenda Item 19ciii — RR8_MPRR164 Mitigated Offer Clarifications Catherine Mooney (SPP MMU) discussed the status of RR8_MPRR164 Mitigated Offer Clarifications (Attachment 21 ‐ RR8_MPRR 164 Recommendation Report). The MWG approved RR8_MPRR164 and asked MOPC to approve RR8_MPRR164. MOPC remanded RR8_MPRR164 back to the MWG. At that time, the Mitigated Offer Task Force‐2014 drafted other revision requests and discussed those with MOPC and tabled RR8_MPRR164. Catherine explained that RR8_MPRR164 was still needed to clarify discrepancies between the Protocols and the Tariff. Some of the language in RR8_MPRR164 was outdated and needed to be rewritten. SPP MMU will draft a new revision request and present it at a

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future MWG meeting. Shawn McBroom (OGE) motioned and Cliff Franklin (WR) seconded to reject RR8_MPRR164 with guidance to staff to bring back a new updated RR of RR8_MPRR164 to the MWG. The motion passed with no oppositions and no abstentions. Agenda Item 20 — Reserve Zone Discussion Casey Cathey (SPP) presented the biannual Reserve Zone Discussion to the MWG (Attachment 22 ‐ Reserve Zone Update MWG 20151117). No reserve zone minimum or maximum has been used in the last biannual period. Casey concluded his presentation with no recommendation to change current reserve zone definitions. Agenda Item 21 — 2015 FCA Study John Hyatt (SPP MMU) presented the 2015 FCA Study to the MWG (Attachment 23 ‐ MWG FCA 2015 Study Draft Report Preliminary Results). According to Attachment AF of the Tariff Section 3.1.1, “the Market Monitor shall reevaluate the Frequently Constrained Areas at least annually…”. John explained that the study period covered from September 1, 2014 to September 1, 2015. The impact analysis used a $25/MWh threshold. John presented the preliminary study results and answered questions from the MWG. Agenda Item 22 ‐ Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 2 – Consent Agenda Ron Thompson (NPPD) motioned and Chris Lyons (Exelon) seconded to approve the consent agenda. The motion passed with no oppositions and no abstentions. Agenda Item 8 – RR32_MPRR218 – Market Registration Naming Conventions Kevin Galke (CUS) motioned and Valerie Weigel (Basin) seconded to approve RR32_MPRR218 as modified by the MWG. The motion passed with one opposition (WR) and one abstention (Exelon). Agenda Item 10 – RR125 Removal of Day‐Ahead Limited Must‐Offer Richard Ross (AEP) motioned and Kevin Galke (CUS) seconded to approve RR125 as submitted by the MWG. The motion passed with three oppositions (Midwest, GSEC, OPPD) and four abstentions (Xcel, WR, KMEA, NPPD). Agenda Item 11 – RR127 JOU Combined Option Jim Flucke (KCPL) motioned and Cliff Franklin (WR) seconded to approve RR127 as modified by the MWG accepting the impact analysis as presented. The motion passed with no opposition and seven abstentions (OPPD, GSEC, Xcel, CUS, KMEA, AECC, EDE). Agenda Item 12 – RR128 Rewriting Start‐Up Eligibility Ron Thompson (NPPD) motioned and Cliff Franklin (WR) seconded to approve RR128 as submitted. The motion passed with no oppositions and no abstentions. Agenda Item 13 – RR129 Settlement Clean‐Up Katie Mentzel (OMPA) motioned and Ron Thompson (NPPD) seconded to approve RR129 as submitted. The motion passed with no oppositions and no abstentions.

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Agenda Item 14 – RR130 Commitment Notification Enhancement Valerie Weigel (Basin) motioned and Carrie Dixon (Xcel) seconded to approve RR130 as submitted. The motion passed with one opposition (OPPD) and one abstention (WR). Agenda Item 19ciii – RR8_MPRR164 Mitigated Offer Clarifications Shawn McBroom (OGE) motioned and Cliff Franklin (WR) seconded to reject RR8_MPRR164 with guidance to staff to bring back a new updated RR of RR8_MPRR164 to the MWG. The motion passed with no oppositions and no abstentions. Action Items:

Ron Thompson (NPPD) to write a Revision Request to expand the Energy Curve Safety Offer

Cap and present it to the MWG.

Future Agenda Items: Removing BSSs from OCL discussion – December RR114 Add Energy Storage Rules to Marketplace– December Guest speakers for Trading Hub discussion – January RR Post Reserve Deployment ‐ January Future Meetings: December 15, 2015 (8:15 a.m. – 6:00 p.m.) December 16, 2015 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor January 19, 2016 (8:15 a.m. – 6:00 p.m.) January 20, 2016 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor Agenda Item 23 — RR2_MPRR 116 Settlement Area Tie‐Line Meter Data Submittal This item was postponed. Agenda Item 24 — RR4_MPRR 130b Must Offer Penalty Calculation and Clarification This item was postponed. Agenda Item 25 — RR7_MPRR 155 Modification of OOME Rules This item was postponed. Agenda Item 26 — RR10_MPRR 169 Clear and Unambiguous Must Offer Proposal This item was postponed.

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Agenda Item 27 — RR22_MPRR207 ‐ Staggered Start‐Up Time This item was postponed. Agenda Item 28 — RR104 DVER Minimum Limit This item was postponed. Agenda Item 29 — RR105 OOME Cap and Floor This item was postponed.

Agenda Item 30 – Adjournment Richard Ross (AEP) adjourned the meeting at 10:06 a.m.

Respectfully Submitted, Debbie James Secretary

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Attachments Attachment 1 ‐ MWG Attendance November 17‐18 2015 Attachment 1a ‐ Aaron Rome Proxy Attachment 1b ‐ Mike Mushrush Proxy Attachment 1c ‐ Rick McCord Proxy Attachment 1d ‐ Rick Yanovich Proxy Attachment 2 ‐ MWG Agenda for November 2015 Attachment 3 ‐ January Market Protocol RR MOPC Schedule Attachment 4 ‐ RPFG November 2015 update Attachment 5 ‐ BOD Action Item for MOPC‐MWG ‐ on MMU ASOM ‐ Nov 2015 ‐ with edits by MWG Attachment 7 ‐ Updated SPP Naming Conventions Data Examples_v2 Attachment 8 ‐ Considerations for RR125 Attachment 9 ‐ RR125 Recommendation Report Attachment 10 ‐ RR127 Recommendation Report Attachment 11 ‐ RR128 Recommendation Report Attachment 12 ‐ RR129 Recommendation Report Attachment 13 ‐ RR130 Recommendation Report Attachment 14 ‐ SER Prelim Benefits Attachment 15 ‐ Action Item #241 ‐ Public and Private Data Attachment 16 ‐ Action Item #242 ‐ Safety Net Offer Cap Attachment 17 ‐ SPP Response to MWG Action Item 276 Attachment 18 ‐ 201510 MWG MMU Market Update Attachment 19 ‐ November 2015 RTO Update Attachment 20 ‐ Regulatory Report to MWG 201511 Attachment 21 ‐ RR8_MPRR 164 Recommendation Report Attachment 22 ‐ Reserve Zone Update MWG 20151117 Attachment 23 ‐ MWG FCA 2015 Study Draft Report Preliminary Results

X = In PersonP = By Phone* = By Proxy

Day 1 Day 2 Full Name Company E-mail Business PhoneX X Richard Ross (Chair) AEP [email protected] (918) 599-2966X X Jim Flucke (V-Chair) KCPL [email protected] (816) 701-7836

P/* P/* Aaron Rome Midwest Energy [email protected] (785) 625-1431P X Ann Scott Tenaska [email protected] (817) 462-1514P P Brad Johnston AECC [email protected] X Carrie Dixon Xcel Energy [email protected] X Chris Lyons Exelon [email protected] (410) 470-2465X X Cliff Franklin Westar [email protected] (443) 226-7787X X Debbie James (Sec) SPP [email protected] (501) 614-3577X X Kevin Galke City Utilities, Springfield [email protected] (904) 360-1460X X Lee Anderson LES [email protected] (402) 467-7591X P Matt Moore Golden Spread Electric Coop [email protected] (806) 379-7766* * Mike Mushrush OMPA [email protected] X Neal Daney KMEA [email protected] (913) 660-0242

P/* * Rick McCord EDE [email protected] (417) 625-5129P/* * Rick Yanovich OPPD [email protected] (402) 514-1031X X Ron Thompson NPPD [email protected] (402) 845-5202X X Shawn McBroom OGE [email protected] (405) 239-0255X X Valerie Weigel Basin Electric Power Co. [email protected] (701) 557-5430P P Adam Schieffer MEAN [email protected] P Al Taylor East Texas Coops [email protected] Ashish Tripathi Ventyx [email protected] Ashwini Koppula Ventyx [email protected] P Austin Hoekman MREnergy [email protected] Bill Nolte SECI [email protected] (420) 272-5458

X Blake Gross AEPSC [email protected] (512) 481-4542P P Bob Wittmeyer Longhorn Power [email protected] P Carrie Simpson Invenergy csimpson@inevenergyX X Catherine Mooney SPP [email protected] Chad Unrein KS Corp Comm [email protected] (785) 271-5176X X Chandler Brown SECI [email protected] X Chris Winburn INDN [email protected] P Christina Labij Acciona [email protected] P Christine Stanley MEAN [email protected] P Douglas Clark SPP [email protected] Eddie Watson SPP [email protected] X Eric Alexander GRDA [email protected] (918) 824-7245X X Erin Cathey SPP [email protected] X Esat Guney SPP [email protected]

Market Working Group11/17-18/2015

Conference Call

mailto:[email protected]


























mailto:csimpson@inevenergy












X X Gary Cate SPP [email protected] Gay Anthony SPP [email protected] (501) 688-1722

P Gentry Crowson SPP [email protected] X Geoffrey M Rush Oklahoma Corp Comm [email protected] Gerald Williams SPP [email protected] P Hailey McKewon GRDA [email protected] P Heather Starnes MJMEUC/CUS/SCMCN [email protected] X Jack Madden GDS Associates [email protected] P Jared Greenwalt SPP [email protected] P Jerry Tielke MREnergy [email protected] P Jill Coffey KCPL [email protected] P Jill Jones MEAN [email protected] P Jim Gonzales SPP [email protected] Jim Jacoby AEP [email protected] P Jim Krajecki Customized Energy Solutions [email protected] P John Hyatt SPP [email protected] X John Krajewski NEPRBX X John Luallen SPP [email protected] John Powell Tri State [email protected] X John Tennyson City Utilities [email protected] X John Varnell Tenaska [email protected] (817) 462-1037X X Katie Mentzel OMPA [email protected] X Kim Sullivan WFEC [email protected] P Lori Frisk-Thompson BEPC [email protected] P Marisa Choate SPP [email protected] (501) 688-1707X X Mark Trumble OPPD [email protected] X Micha Bailey SPP [email protected] (501) 688-2522P Michael Daly SPP [email protected] Michael Erbrick MICS [email protected] (281) 687-0609P P Nicole Wagner SPP [email protected] P Patti Kelly SPP [email protected] (501) 614-3381P P Raleigh Mohr SPP [email protected] Randy Root GRDA [email protected] P Ray Kershaw ITC Transco [email protected] Rebecca Hohnstein LES [email protected] X Rebecca Schwarz AEP [email protected] P Richard Dillon SPP [email protected] (501) 614-3228P Ricky Finkbeiner SPP [email protected] P Robert Pick NPPD [email protected] P Robert Safuto Customized Energy Solutions [email protected] (917) 446-2579X X Roy True Aces Power Marketing (APM) [email protected] (317) 695-4146P P Russell Quattlebaum SPP [email protected] Ryan Turner CUS [email protected] Seth Cochran DC Energy [email protected] (512) 971-8767










































X P Shawn Geil KEPCo [email protected] Shawnee Claiborn-Pinto PUCT [email protected] (512) 936-7388P P Sherry Hamilton SPP [email protected] P Sonya Hall SPP [email protected] P Stephen B. McKee AEP [email protected] Steve Gaw Wind Capital Group [email protected] (573) 645-0727P Steve Haun LES [email protected] Terry Gates AEP [email protected] (614) 716-6232P P Terry Wright EDE [email protected] X Walt Shumate Shumate & Associates [email protected] (512) 496-7704P Yassar Bahbaz SPP [email protected] 73












1

Micha Bailey

From: Debbie JamesSent: Tuesday, November 17, 2015 7:06 AMTo: Rome, AaronCc: Erin Cathey; Ross, Richard C. (AEP); Franklin, Cifford; Micha BaileySubject: Re: Proxy for tomorrow's meeting

Thank you. Debbie James On Nov 16, 2015, at 10:40 PM, Aaron Rome <[email protected]> wrote:

Debbie – We have an internal CIP version 5 audit tomorrow. I will be off and on the call. When I am not present Cliff Franklin will have my Proxy. Thanks. Aaron Aaron Rome Manager of Transmission & Market Operations Midwest Energy Inc. 1330 Canterbury Hays, KS 67601 [email protected] Phone: 785‐625‐1431 Fax: 785‐625‐1487 CONFIDENTIALITY NOTICE: This email, including attachments, may include confidential and/or proprietary information, and may be used only by the person or entity to which it is addressed. If the reader of this email is not the intended recipient of his or her authorized agent, the reader is hereby notified that any dissemination, distribution or copying of this email is prohibited. If you have received this email in error, please notify the sender by replying to this message and delete this email immediately.

1

Micha Bailey

Subject: FW: MWG Attendance

From: Dave Osburn [mailto:[email protected]] Sent: Monday, November 09, 2015 3:38 PM To: Debbie James Cc: Ross, Richard C. (AEP); Flucke, Jim; Richard Dillon Subject: RE: MWG Attendance Thanks Debbie. Katie Mentzel will be his proxy. David W. Osburn General Manager Oklahoma Municipal Power Authority 405‐359‐2501

From: Debbie James [mailto:[email protected]] Sent: Monday, November 09, 2015 2:57 PM To: Dave Osburn <[email protected]> Cc: Ross, Richard C. (AEP) <[email protected]>; Flucke, Jim <[email protected]>; Richard Dillon <[email protected]> Subject: Re: MWG Attendance Dave, Do you have a proxy who can attend the meetings? Debbie James On Nov 9, 2015, at 10:36 AM, Dave Osburn <[email protected]> wrote:

Debbie, Mike Mushrush will be off work for an undetermined amount of time and will likely miss an MWG meeting. David W. Osburn General Manager Oklahoma Municipal Power Authority 405‐359‐2501

1

Micha Bailey

From: Debbie JamesSent: Tuesday, November 17, 2015 1:24 PMTo: McCord, Rick; Ross, Richard C. (AEP)Cc: Wright, Terry; Micha BaileySubject: RE: MWG Proxy for this afternoon

Thank you. Debbie James Southwest Power Pool Manager of Market Design Office: 501‐614‐3577|Mobile: 501‐960‐3338 201 Worthen Drive Little Rock, AR 72223‐4936 [email protected]

From: Richard McCord [mailto:[email protected]] Sent: Tuesday, November 17, 2015 1:18 PM To: Debbie James; Ross, Richard C. (AEP) Cc: Wright, Terry Subject: MWG Proxy for this afternoon I have to be away from 1:30 to about 3 pm today. Please accept Terry Wright as my proxy while I am not on the call today.

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1

Micha Bailey

From: Debbie JamesSent: Tuesday, November 17, 2015 1:24 PMTo: Yanovich, RickCc: Trumble, Mark; Micha BaileySubject: RE: Yanovich proxy

Thank you. Debbie James Southwest Power Pool Manager of Market Design Office: 501‐614‐3577|Mobile: 501‐960‐3338 201 Worthen Drive Little Rock, AR 72223‐4936 [email protected]

From: YANOVICH, RICK A [mailto:[email protected]] Sent: Tuesday, November 17, 2015 7:11 AM To: Matt Bailey; Debbie James Cc: Trumble, Mark Subject: Yanovich proxy Mark Trumble will be my proxy for this meeting as he will be there! Thanks, Rick

Rick Yanovich Manager-Asset Optimization Energy Marketing and Trading Omaha Public Power District 444 S. 16th St. Mall-10E/EP1 Omaha, NE 68102 (402) 514-1031 (desk) / (402) 616-3522 (cell) [email protected]

This e-mail contains Omaha Public Power District's confidential and proprietary information and is for use only by the intended recipient. Unless explicitly stated otherwise, this e-mail is not a contract offer, amendment, or acceptance. If you are not the intended recipient you are notified that disclosing, copying, distributing or taking any action in reliance on the contents of this information is strictly prohibited.

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable


November 17-18, 2015

AEP Office – Dallas, TX

• A G E N D A •

Day 1 – 8:15 a.m. – 6:00 p.m.

1. Call to Order, Proxies, Agenda Discussion ............................................................................ Richard Ross

2. Working Group/Committee Updates ................................................................................... Richard Ross

3. Consent Agenda (approval items)

a. MWG October 20-21 Minutes Approval ............................................................ Richard Ross

b. MWG November 3 Minutes Approval ................................................................ Richard Ross

4. Marketplace RR January 2016 MOPC Schedule ..................................................................... Erin Cathey

5. Trading Hubs Update ......................................................................................................... Valerie Weigel

6. Ramp Product Next Steps ..................................................................................................... Matt Moore

7. BOD Action Item for MOPC and MWG: MMU ASOM Recommendations .......................... Gay Anthony

8. RR32_MPRR218 - Market Registration Naming Conventions (approval item) ...................... Erin Cathey

9. Physical Withholding Penalty Discussion ................................................................... Catherine Mooney

10. RR125 Removal of Day-Ahead Limited Must-Offer (approval item) .................................... Richard Ross

11. RR127 JOU Combined Option (approval item) ......................................................................... Jim Flucke

12. RR128 Rewriting Start-Up Eligibility (approval item) ........................................................... Micha Bailey

13. RR129 Settlement Clean-Up (approval item) ....................................................................... John Luallen

14. RR130 Commitment Notification Enhancement (approval item) .......................................... Erin Cathey

15. Benefits of adding Stored Energy Rules to Marketplace ................................................... Yasser Bahbaz



16. Action Item #241 Public and Private data ........................................................................... Micha Bailey

17. Action Item #242 Safety Net Offer Cap ................................................................................ Micha Bailey

18. Action Item #276 SPP Registration and Onboarding Process ................................................ Erin Cathey

Day 2 – 8:15 a.m. – 12:00 p.m.

19. Marketplace Updates

a. MMU Marketplace Update ...................................................................... Catherine Mooney

b. RTO Marketplace Update ............................................................................. Gentry Crowson

c. Regulatory Report ........................................................................................... Marisa Choate

i. FERC NOPRs update ................................................................................. Patti Kelly

ii. Mitigated Offer FERC Filing ER15-2268 ................................................... Patti Kelly

iii. RR8_MPRR164 Mitigated Offer Clarifications (discussion) ........ Catherine Mooney

20. Reserve Zone Discussion .................................................................................................. Neil Robertson

21. 2015 FCA Study ........................................................................................................................ John Hyatt

22. Review of Motions, Action Items and Future Meetings ....................................................... Micha Bailey

23. RR2_MPRR 116 Settlement Area Tie-Line Meter Data Submittal (postponed) ................... Cliff Franklin

24. RR4_MPRR 130b Must Offer Penalty Calculation and Clarification (postponed) .......... Jared Greenwalt

25. RR7_MPRR 155 Modification of OOME Rules (postponed) ........................................... Jared Greenwalt

26. RR10_MPRR 169 Clear and Unambiguous Must Offer Proposal (postponed) ..................... Richard Ross

27. RR22_MPRR207 - Staggered Start-Up Time (postponed) ........................................................ Jim Flucke

28. RR104 DVER Minimum Limit (postponed) ............................................................................ Carrie Dixon



29. RR105 OOME Cap and Floor (postponed) .......................................................................... Raleigh Mohr

30. Adjournment ........................................................................................................................ Richard Ross

1

MWG RR January 2016 MOPC ScheduleMWG RR Submission Deadline for Non-Expedited

11/23/2015MWG RR Posting Deadline for Non-Expedited

12/1/2015MWG Meeting before MOPC for RRs

12/15/2015ORWG Meeting before MOPC for RRs

12/3/2015RTWG Meeting before MOPC for RRs

12/17/2015MOPC Meeting Materials due date

12/31/2015

Ramp Product Focus Group Update

MWG11/17/2015

Matt Moore (GSEC)

Agenda

• Brief History of Ramp Product Focus Group (RPFG) work and discussions

• October MWG Action Item: Define scope going forward and the timeline

• Recommendation

2

RPFG work and discussions

• June 8th, 2015 Conference Call

• July MWG Presentation

• August 12, 2015 Conference Call

• October 2, 2015 Conference Call

• October 9, 2015 Conference Call

• October MWG Presentation

• November 5, 2015 Conference Call

3

RPFG work and discussions• Performed research on three different market designs• Explored in further detail some of the aspects of those

designs• Explored economic benefits and potential estimated cost• Discussed some possible tweaks to other designs• Discussed issues and concerns with “ramp management”• Some concerns that the scope going beyond the

“boundaries” of traditional ramp product as seen in MISO, for example.

• Existing price formation needs additional study and perhaps modification prior to implementation of Ramp Product.

4

RPFG work and discussions• Topics and phrases that continue to pop up

– Price Transparency

– Headroom

– Scarcity Pricing – Recent FERC Docket No. RM15-24 (born from FERC Docket No. AD14-14 price formation proceedings)

– VRL and Operating Reserve relaxation

– RUC without proper compensation

– No incentive for unit commitments prior to events vs. RUC

– Align economics with Reliability events

– Fast and Quick ramping value

– Among other things

5

October MWG Action Item: Define scope going forward and the timeline• Recommendations:

– MWG form a “Price Formation Focus Group” (PFFG) to holistically examine other critical concerns and report back to MWG with a target date of July 2016 (with the ability to extend as needed).

– Keep the RPFG intact, save current work and research, and postpone future meetings until report from PFFG.

– RPFG to further analyze Ramp Product value and implementation after report from PFFG .

6

“Price Formation Focus Group” – (PFFG)

• Examine from a holistic perspective whether prices (Energy and A/S) are appropriately incentivizing Resources, capturing marginal costs, and providing sufficient price transparency.

• Bi-weekly calls initially with meetings and SPP staff time throttled back over time.

• Provide monthly updates to MWG.

• Present white paper outlining deficiencies in current design and recommended solutions as appropriate.

• Submit Revision Requests to implement solutions.

7

SPP Board of Director’s Action Item for MOPC and MWG - Re: MMU Recommendations from the 2014 Annual State of the Market Report

November 17, 2015

Background • During the July 2015 SPP Board of Directors (BOD) meeting, the SPP

MMU presented its Annual State of the Market (ASOM) report

• The ASOM includes nine recommendations from the MMU for changes or enhancements to the Integrated Marketplace design

• At the conclusion of the presentation, BOD Chairman Jim Eckelbergerasked the Chairs of the MOPC and MWG to review the ASOM and the MMU recommendations, look at the ideas that should be pursued if they are not already, and prepare responses/recommendations for presentation to the BOD in a future meeting

• The MWG discussed responses to the MMU recommendations in the October MWG meeting

– The following slides contain a summary of the proposed MWG responses –to be finalized by the MWG in November for presentation to the MOPC and BOD in January

2

1. Quick Start Logic

MMU Summary

• The MMU supports the development of new rules governing the dispatch of quick-start resources that (1) do not subject quick-starts to RUC commitment; and (2) do not provide make whole payment eligibility for RTBM dispatch.

MWG Response

• RR99-Short-Term RUC and RR116-Quick Start Enhancements have been approved and will be implemented in 2016

• MWG proposes to wait and see the results of RR99 and RR116 changes before taking any further action related to Quick-Start resources

3

2. Ramp-Constrained Shortage Pricing

MMU Summary

• Ramp-constrained operating reserve shortages should be priced in a manner similar to the operating reserve capacity shortages.

MWG Response

• FERC released a NOPR on 9/17/15 related to shortage pricing

– MWG proposes to wait for the associated FERC Order before taking any action towards revisions related to pricing during ramp shortages

• Additionally, MWG approved in November the creation of a “Price Formation Focus Group”, which will focus on several areas of Marketplace pricing, including shortage pricing, and will be reporting research results and information back to the MWG

4

3. Potential Manipulation of Make Whole Payment ProvisionsMMU Summary

• Potential for make whole payment manipulation for resources committed across the midnight hour, fixed regulation bids, Out-of-Merit energy payments, and jointly-owned units should be eliminated.

5

Area of potential MWP Manipulation

MMU Concerns/Recommendations

Resources committed across the midnight hour

Evaluate solutions adopted by other RTOs to reduce exposure to market manipulation in make whole payment provisions for resources committed across the midnight hours.

Fixed Regulation Bids

Disqualify resources with fixed Regulation bids from receiving the Regulation Deployment Adjustment Charge.

Out-of-Merit energy (OOME) payments

Utilize automatic mitigation provisions for local reliability commitments for local reliability OOME events.

Jointly-Owned Units (JOUs)

Remove the ability to manipulate make whole payments under the JOU Combined Resource Option and improve market efficiency in the JOU design.

3. Potential Manipulation of Make Whole Payment Provisions (cont’d)MWG Response

6

Area of potential MWP Manipulation

Proposed MWG Response

Resources committed across the midnight hour

SPP Staff and MMU will research further, including a look at what other RTOs/ISOs have done

Fixed Regulation Bids

SPP Staff and MMU will research further

Out-of-Merit energy (OOME) payments

MMU will research and submit a Revision Request

Jointly-Owned Units (JOUs)

On 11/17/15, the MWG approved Revision Request 127, which proposes market design changes to eliminate the ability to manipulate make whole payments under the JOU Combined Resource Option, and to improve market efficiency in the JOU design.

4. Day-Ahead Must-Offer RequirementMMU Summary• The MMU recommends that SPP eliminate the limited day-ahead must-

offer provision and revise the physical withholding rules to include a penalty for non-compliance. In the event that the limited must-offer provision is continued, SPP should address design weaknesses.

MWG Response• Regarding the limited day-ahead must-offer portion of this MMU

recommendation: – RR125-Removal of Day-Ahead Limited Must Offer was approved by the

MWG on 11/17/15

• Regarding the physical withholding revision portion:– MMU plans to submit a Revision Request for the December MWG meeting

with proposed revisions to include the penalty for Physical Withholding

• The final MWG response on this MMU recommendation is pending the results of RR125 as it continues to move through the Stakeholder Process, and of the Physical Withholding discussion and RR in December

7

5. TCR and ARR System AvailabilityMMU Summary• TCR and ARR system availability should be reduced to minimize the over-

allocation of TCRs and ARRs that Day-Ahead Market congestion revenues do not support

MWG Response• Note: RR91-Annual Allocation Percent Change will be implemented in time

for the 2016 TCR Annual Auction Process– This change may help with over-allocation of ARRs. Full affects of the change

will not be known until after the 2016-2017 TCR Year which will end in May 2017

• Note: Funding results so far for TCR Year 2015-2016 are consistently within the 90-100% range, which is greatly improved over last year’s results

• Based on the information above, the MWG proposes the following with regard to this MMU recommendation:

– SPP Staff will not propose any TCR enhancements or changes in 2016– Individual MPs may bring proposals (RRs) to the MWG for consideration– MWG will re-evaluate the TCR Market after seeing results of the TCR Year 2016-

20178

6. Transmission Outage Reporting and ModelingMMU Summary

• The MMU supports SPP’s current efforts to improve planned outage reporting and suggests adding flexibility to outage inclusion criteria for ARR and TCR modeling.

MWG Response

• MWG approved in October a change to add transmission outages with a “Proposed” status to the list of current outage types accepted in the models for the TCR Market

• MWG currently has no plans to pursue further changes or enhancements to Transmission Outage Reporting and Modeling. MWG understands that SPP Staff and ORWG will continue to research other possible enhancements and will keep the MWG informed

9

7. TCR Bidding at Electrically Equivalent Settlement LocationsMMU Summary• A systematic block of TCR bidding at electrically equivalent settlement locations

should be implemented to prevent ongoing tariff violations.

MWG Response

• MWG directed SPP Staff to complete the following in 2016:

– Research ERCOT’s “dead bus logic” and report results to the MWG

– Evaluate what it would require from a systems perspective to add the systematic block/validation, and report results to the MWG

– In the meantime, SPP Staff will continue its current approach, which is described as follows:

Post a list of prohibited settlement location pairs

Inform AOs when prohibited bids are submitted

Manually remove prohibited bids from ARR Allocations and TCR Auctions

10

8. Allocation of Over-Collected LossesMMU Summary• SPP should remove the Bilateral Settlement Schedule transactions from

the over-collected losses distribution calculation and consider over-collected losses (OCL) distributions to exports relative to interface transaction profit margins to assess potential distortion of market incentives.

MWG Response• Per MWG direction early in 2015, SPP Staff had begun work on a

proposed design to remove BSSs from OCL distribution, but halted that work when FERC issued Order ER15-763 on 3/31/2015

– Order ER15-763 conditionally accepted Tariff revisions in RR212 for OCL distribution

– The Order also stated disagreement with comments submitted by MMU and Xcel Energy regarding the removal of BSSs from the OCL distribution, saying that their concerns were “speculative and unsupported at this time”.

• MWG proposes that FERC did not necessarily reject the idea of removing BSSs from OCL distribution, and would like to bring this topic back up for discussion and consideration at MWG in Q1-2016

11

9. Market Power Mitigation Conduct Thresholds

MMU Summary

• The MMU supports a modest increase in offer conduct thresholds for start-up offers, regulation offers, and for energy offers for Frequently Constrained Areas.

MWG Response

• MMU has stated that they plan to:

– submit a Revision Request for the FCA threshold change by the end of 2015

– continue to do research and analysis on the threshold changes for start-up and regulation offers, and submit a Revision Request in 2016

• MWG will await submission of the RRs by MMU for consideration and possible approval

12

BALANCING AUTHORITY /MARKET FOOTPRINTSOUTHEAST POWER POOL - SEPP

SETTLEMENT AREAS WITHIN BALANCING AUTHORITY/MARKET FOOTPRINT (LEGACY BA)MAYBERRY CITY POWER & LIGHT COMPANY – MCPLMOUNT PILOT GAS AND ELECTRIC COMPANY - MPGEMYERS LAKE DAM AUTHORITY - MLDA

FIRST TIER BALANCING AUTHORITYVIRGINIA POWER SERVICE CORPORATION - VPSC

MARKET PARTICIPANTSMAYBERRY CITY POWER & LIGHT COMPANY – MCPLMOUNT PILOT GAS AND ELECTRIC COMPANY - MPGEMYERS LAKE DAM AUTHORITY – MLDAET BASS WIND LLC - BASS

RESOURCE NAMEResource 1 - Andy Taylor Steam Electric Station, Unit 1 (Coal)Resource 2 - Andy Taylor Steam Electric Station, Unit 2 (Coal)Resource 3a - Opie Taylor Wind Farm (PPA with MCPL) - INTERNAL PSEUDO TIEResource 3b - Opie Taylor Wind FarmResource 4 - Mount Pilot (Natural Gas)Resource 5 - Mount Pilot Wind FarmResource 6a - Ernest T Bass Wind FarmResource 6b - Ernest T Bass Wind Farm (PPA with MCPL)Resource 7 - Barney Fife (Natural Gas)Resource 8 - Myers Lake Dam HydroResource 9 - Aunt Bea Wind Farm - PSGO to VPSC

LOAD NAMELoad 1 - Mayberry Power & Light Company LoadLoad 2 - River City Municipal Load Load 3 - Beatric Municipal Load Load 4 - Mount Pilot Gas and Electric Company LoadLoad 5 - ET Bass Municipal Load Load 6 - Myers Lake Dam Authority Load

INTERNAL TIE INTERFACE1A - MCPL to MLDA1B - Reciprocal registered by MLDA2A - MCPL to MPGE2B - Reciprocal registered by MPGE

INTERCHANGE POINTS

LOAD

RESOURCES

EXTERNAL TIE INTERFACEExt Tie 1 - SEPP to VPSCMPCL to VPSC (Result of Resource 9 and other interchange transactions)

EXTERNAL INTERCHANGE POINTS

SETTLEMENT AREA MP REGISTERING REGISTERED SETTLEMENT LOCATION NAMEMCPL MCPL MCPL.ANDYTAYLOR.1MCPL MCPL MCPL.ANDYTAYLOR.2MPGE MCPL MCPL.OTAYLOR.WNDMPGE MPGE MPGE.OPTAYWND.1MPGE MPGE MPGE.MTPILOT.1MPGE MPGE MPGE.MTPILOT.WNDMPGE BASS MPGE.BASS.ETBWND.1MPGE MCPL MPGE.MCPL.ETBWNDMLDA MLDA MLDA.BARNEYFIFE.1MLDA MLDA MLDA.MYERLAKE.1MCPL N/A PSGO (SPP determines name)

SETTLEMENT AREA MP REGISTERING REGISTERED SETTLEMENT LOCATION NAMEMCPL MCPL MCPL_MCPLMCPL BASS MCPL_BASS_RIVLDMPGE MCPL MPGE_MCPL_BEALDMPGE MPGE MPGE_MPGEMPGE BASS MPGE_BASS_LOADMLDA MLDA MLDA_MLDA

NAMEMLDA.MCPLMCPL.MLDAMPGE.MCPLMCPL.MPGE

NAMEVPSC

VPSC.MPCL

SOURCE/SINK EXAMPLE (14 Character Limit)MCPL.ANDTAY.1MCPL.ANDTAY.2MCPL.OPTAYWNDMPGE.OTWINDMPGE.MTPILOT1MPGE.MTPILWNDMPGE.BASS.WNDMPGE.MCPLBASSMLDA.BARNFIFE1MLDA.MYLAKE1N/A

OMPA_GENHUB_H OMPA_GENHUB

Considerations for RR125November 17, 2015

Jared [email protected]

RR125 Potential Impacts

• Fewer Resources offering in Day-Ahead Market– Potential for shortage of capacity in Day-Ahead Market

Invoke SCUC logic for shortage conditions

– May commit Resources with a Commit Status of “Reliability” Invoke SCED logic for shortage conditions

– Scarcity Pricing would apply

– Reg-Up prices may increase due to less online capacity to choose from

– Potential increase in virtual Resources clearing

2

RR125 Potential Impacts (continued)

• Could decrease Resource commitments out of the DA Market– May reduce amount of Resources available for

commitment due to lead time

• Could increase commitments needed from DA RUC– Could increase RUC MWP

3

Page 1 of 13

Revision Request Recommendation Report

RR #: 125 Date: 10/2/2015

RR Title: Removal of Day-Ahead Limited Must-Offer

SUBMITTER INFORMATION

Name: C. Richard Ross Company: American Electric Power

Email: [email protected] Phone: 918.599.2966

EXECUTIVE SUMMARY AND RECOMMENDATION FOR MOPC AND BOD ACTION

OBJECTIVE OF REVISION

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

The Market Working Group voted to remove the limited Day-Ahead must offer language at the November 2014 MWG. The MMU indicated that the Day-Ahead must offer requirement does not appear to be necessary at the August MWG. The MMU recommended that the MWG, if it wanted to keep the current design, then it should close the loopholes, exempt VERs, and resolve JOU commitments. Data has shown that for hours in which a penalty has been levied, there was more than enough generation offered. The majority of Market Working Group members, given the choice of continuing the current limited must offer or eliminating the must offer entirely, prefer to eliminate the must offer requirement entirely.

Describe the benefits that will be realized from this revision.

This RR removes the Day-Ahead must-offer requirement as recommended by the MMU in the Annual State of the Market report. The Day-Ahead must-offer is not necessary in the Integrated Marketplace, and removing it will reduce SPP workload.

SPP STAFF ASSESSMENT

IMPACT

Will the Revision result in system and or process changes? No Yes

Is an Impact Assessment required? No Yes

If no, explain:

Estimated Cost: $ Estimated Duration: months

Primary Working Group Score:

SPP DOCUMENTS IMPACTED

Market Protocols Protocol Section(s): 4.2.1.1(deleted); 4.2.1.1.1(deleted); 4.2.1.2; 4.5.11; 6.2.8; 8.2.7(deleted)

Protocol Version: 33b

Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): AE [2.2; 2.11.1(deleted); 2.11.2]; AF [3.9(deleted)]

Business Practice Business Practice Number:


Page 2 of 13

WORKING GROUP REVIEWS AND RECOMMENDATIONS List Primary and any Secondary/Impacted WG Recommendations as appropriate

Primary Working Group: MWG

Date: 11/17/2015

Action Taken: Approved

Abstained: Xcel, WR, KMEA, NPPD

Opposed: Midwest, GSEC, OPPD

Reason for Opposition:

Secondary Working Group:

Date:

Action Taken:

Abstained:

Opposed:

Reasons for Opposition:


Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


MOPC

Date:

Action Taken:

Abstained:

Opposed:


BOD/Member Committee

Date:

Action Taken:

Abstained:

Opposed:

Page 3 of 13


COMMENTS

Comment Author:

Date Comments Submitted:

Description of Comments:

Status:

Comment Author:



Status:

PROPOSED REVISION(S) TO SPP DOCUMENTS

Market Protocols

4.2.1 Must-Offer Requirement

Market Participants are required to offer available Resources to the Day-Ahead Market, RUC, and RTBM

as described in this section below.

4.2.1.1 Day-Ahead Market

There is no requirement for any Resource to offer in the DA Market.

(A) Each Market Participant with registered load must satisfy the must offer obligation for each Asset

Owner associated with that registered load as set forth in Section 4.2.1.1 based on the following

criteria:

(1) A Market Participant’s load for an Asset Owner for purposes of this section shall be equal to

the Market Participant’s maximum hourly Reported Load for that Asset Owner for the

Operating Day. When an Asset Owner selling power under a bilateral contract has registered

the load of the Asset Owner that is buying power under the bilateral contract as described

under Section 6.2.8, the buyer’s Reported Load shall be reduced by the amount of the buyer’s

load registered by the seller and the seller’s Reported Load shall be increased by the amount

of the buyer’s load registered by the seller.

(2) A Market Participant’s daily Operating Reserve obligation for an Asset Owner shall be equal

to the sum of that Market Participant’s maximum daily Regulation-Up Service, Regulation-

Page 4 of 13

Down Service and Contingency Reserve obligation for that Asset Owner as calculated by

SPP as described in Section 4.1.3(4).

(3) Resources submitted with a Commitment Status of Market, Self or Reliability may be used

to satisfy this requirement.

(4) A load-serving Market Participant’s net resource capacity, for an Asset Owner for purposes

of this section shall include:

(a) Offered capacity by Resources identified in (3) above less the Operating Reserve

obligation identified in (2) above; and

(b) Firm Power purchases less the Firm Power sales, except that, if the seller has registered

the buyer’s load associated with a firm power sale, such firm power sale shall not act

to increase the buyer’s net resource capacity or act to reduce the seller’s net resource

capacity.

(i) For purposes of this Section 4.2.1.1, firm power purchases and firm power

sales shall mean sales and purchases that are deliverable with service

comparable to Firm Point-To-Point Transmission Service or Firm Network

Integration Transmission Service with the supplier assuming the obligation to

provide both capacity and energy. Additionally, firm power purchases shall

include an Asset Owner’s share of a Jointly Owned Unit to the extent that

such shares have not been registered as separate Resources either under the

JOU Individual Resource Option or the JOU Combined Resource Option as

described under Section 4.2.2.5.4. In order to verify firm power purchases

and firm power sales, supporting documentation must be provided to the

Market Monitor upon request. Market Participants have the option to input

information regarding firm power purchases and firm power sales into the

Market Monitor website. If no information is input into this website, the

Market Monitor will contact the Market Participant for that information. The

Market Monitor may confirm the firm purchase or sale with the counterparty

and will include the transacted MWs to calculate net resource capacity for

both purchaser and seller. If one of the parties dispute the firm purchase or

sale to the Market Monitor, then the firm purchase or sale will not be used in

the calculation of either the purchaser’s or seller’s net resource capacity.

Page 5 of 13

(B) A Market Participant’s compliance with the must-offer obligation for an Asset Owner is as

follows:

(1) A Market Participant that has offered all of its available Resources for an Asset Owner with

a Commitment Status of Market, Self, or Reliability for an hour of the Operating Day is

deemed to be compliant with the must-offer requirement for that Asset Owner for that hour

regardless of its maximum hourly Reported Load and/or Operating Reserve obligation.

(a) A Market Participant that does not have any registered Resources for an Asset Owner

has met the must-offer requirement for that Asset Owner because it does not have any

Resources with a Commitment Status of Not Participating for that Asset Owner.

(2) A Market Participant that does not meet the condition described in (B)(1) above for an Asset

Owner for an hour of the Operating Day, but has net resource capacity for that Asset Owner

for that hour greater than or equal to 90% of its load for that Asset Owner, as described in

(A)(1) above, is deemed to be compliant with the must-offer requirement for that Asset

Owner for that hour.

(3) To the extent a Market Participant does not meet the conditions for an Asset Owner described

in either Section (B)(1) and (2), the Market Participant shall be deemed noncompliant with

the must-offer requirement for that Asset Owner for that hour and will be assessed a penalty

for that Asset Owner for that hour as described in Section 4.2.1.1.1.

(4) Resources used as the source of a GFA Carve Out or FSE must be offered, if available, with

a sufficient capacity to cover the GFA Carve Out Schedule or FSE Schedule. GFA Carve

Out or FSE treatment is only available to the extent that the Resources are offered into the

DA Market using a Commitment Status of Market, Self or Reliability. To the extent the

source is external, an Import Interchange Transaction must be submitted in the DA Market

with a sufficient capacity to cover the GFA Carve Out Schedule or FSE Schedule.

(C) The Market Monitor shall monitor a Market Participant’s load, Operating Reserve obligation,

offered Resources and net resource capacity, for an Asset Owner for each hour of the Operating

Day to determine whether the Market Participant has complied with the must offer obligation for

that Asset Owner set forth in Section 4.2.1.1 B.

4.2.1.1.1 Penalty Calculation

For each hour of the Operating Day that a Market Participant is found to be noncompliant as determined

by the conditions set forth in Sections 4.2.1.1 B, that Market Participant shall be assessed a penalty. The

penalty amount and the distribution of penalty revenues shall be determined as follows:

(1) An Asset Owner’s penalty amount in each hour is calculated by multiplying the Asset Owner’s

Must-Offer Penalty MW by the maximum of zero or the Asset Owner’s Must-Offer Penalty LMP

for that hour.

Commented [MPRR2391]: Awaiting FERC Filing and Implementation




Page 6 of 13

(a) Asset Owner Must-Offer Penalty MW is equal to the minimum of (i) the Asset Owner

Shortage MW or (ii) the Asset Owner Not Offered MW;

(i) Asset Owner Shortage MW is calculated as the difference between:

(1) 90% of the Market Participant’s load for an Asset Owner as described in

4.2.1.1A.(1); and

(2) The Market Participant’s net resource capacity for an Asset Owner as

described in 4.2.1.1 A(3).

(ii) Asset Owner Not Offered MW is calculated as the sum of the reference levels for

the Maximum Economic Capability Operating Limit, as determined by the process

in Section 8.2.2.8, less derate MW amounts approved and recorded in the outage

scheduler tool for the Market Participant’s Resources for that Asset Owner with a

Commitment Status of Not Participating.

(b) The Must-Offer Penalty LMP is calculated as the weighted average of the Day-Ahead LMP

for the Market Participant’s Resources for that Asset Owner with a Commitment Status of

Not Participating, where the weights for the calculation are the corresponding Not Offered

MWs.

(2) In any hour in which must-offer penalty revenues are collected, such revenues shall be distributed

to Market Participants for an Asset Owner on a pro-rata basis for that Asset Owner’s Resources

that were offered in compliance with the must-offer requirement in Section 4.2.1.1. The pro-rata

share shall be equal to the ratio of (i) each compliant Asset Owner load, as described in 4.2.1.1 for

that hour to (ii) the sum of all compliant Asset Owner loads for that hour.

4.2.1.2 RUC and RTBM

For the RUC and RTBM, Market Participants must submit Resource Offers for all Resources, for each

product for which it is qualified, to the extent these Resources are available (e.g. not on forced outage,

planned outage, or Reserve Shutdown). Market Participants must include in their Resource Offers the full

amount of physical capacity available as reflected in the Resource’s submitted Maximum Normal

Capacity Operating Limit and Maximum Emergency Capacity Operating Limit.

4.5.11 Miscellaneous Amount

(1) In certain circumstances, it may be necessary to recalculate or make changes to previously billed

charges that cannot be handled though a standard final settlement or resettlement execution for

that operating day. This is anticipated to occur only on an exception basis. SPP will manually

calculate the adjustment and post as a manual adjustment to the initial, final, and/or resettlement

statement, regardless of the Operating Day in question. A comment will be added to the Bill

Statement to alert the reader to the reason for the adjustment and the effective Operating Day(s).

SPP will post supporting documentation for the manual calculation of any miscellaneous charge

to the Portal no later than the time the Settlement Statement including the miscellaneous charge

has been posted. In some situations the charge or credit assessed must be excluded from Revenue

Page 7 of 13

Neutrality Uplift calculations such that SPP is left with a net receivable or payable amount for the

settlement of the OD.

(2) In addition, through Balancing Authority Agreements with adjacent external Balancing

Authorities, SPP may supply Emergency Export Interchange Transactions when requested by the

applicable external Balancing Authority or SPP may request, under SPP Emergency conditions,

that applicable external Balancing Authorities supply Emergency Import Interchange Transactions

to SPP. To the extent that such transactions are confirmed, credits to SPP for Emergency Export

Interchange Transactions and charges to SPP for Emergency Import Interchange Transactions are

included in this charge type.

(3) In addition, a local transmission operator may require commitment, decommitment, or dispatch

instructions to be issued to one or more Resources in order to solve a reliability issue. Payments

to Resource Asset Owners as described under Sections 4.5.9.8, 4.5.9.9 and charges to Asset

Owners as described under Section 4.5.9.10 associated with such commitment, decommitment, or

dispatch instructions are included in this charge type.

(4) In addition, SPP may impose penalties for noncompliance with the Day-Ahead Market must-offer

requirement as described under Section 4.2.1.1.1. Any penalties assessed to noncompliant Asset

Owners, and the distribution of those penalties by load-ratio share, excluding the noncompliant

Asset Owners, are included in this charge type.

(5)(4) A miscellaneous charge type will be utilized for each distinct charge type and any other

charges and credits not specifically accounted for under a distinct charge type. Miscellaneous

charges and credits to the affected Asset Owners are represented for each Operating Day as

follows:

MiscDlyAmt a, ct, s, rnu, d

(6)(5) For each Asset Owner associated with Market Participant m, a daily amount is

calculated. The net daily amount is calculated as follows:

MiscAoAmt a, m, d = ∑ct

∑s∑rnu

MiscDlyAmt a, ct, s, rnu, d

(7)(6) 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:

MiscMpAmt m, d = ∑a

MiscAoAmt a, m, d

Page 8 of 13

6.2.8 Loads Transfers Relating to Bilateral Contracts

A Market Participant that is selling firm power to another Market Participant under a bilateral contract

may, with the agreement of the buyer, register all or a portion of the buyer’s load as its load asset as

described under Section 2.2(11) of Attachment AE to the Tariff. For the purposes of Section 4.2.1.1, such

registration of the buyer’s load by the seller shall be accounted for by including such load in the seller’s

Reported Load and not including such load in the buyer’s Reported Load, as described under Section

4.2.1.1(A)(1), and such associated bilateral contracts shall not be included in either the buyer’s or seller’s

net resource capacity described under Section 4.2.1.1(A)(4).

8.2.7 Sanctions for Noncompliance with the Day-Ahead Market Must Offer Requirement

In the case that a Market Participant with registered load is found to be noncompliant for an Asset Owner

associated with that registered load as determined by the conditions set forth in Sections 4.2.1.1, the

Market Participant shall be assessed a penalty for that Asset Owner as described in 4.2.1.1.1 (1)(a). The

penalty amount shall be equal to the Day Ahead Market LMP associated with the withheld capacity as

described in Section 4.2.1.1.1(1)(b).

The Market Monitor will monitor for, and report to the Commission’s Office of Enforcement (“OE”),

manipulative behavior associated with Day Ahead Offers, including (but not limited to) monitoring load-

serving Market Participants who purposefully underestimate peak loads. The Market Monitor will also

report to OE 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 real-time market by limiting Day Ahead offers, and the effects of any such efforts upon make whole

payments.

SPP Tariff (OATT) ATTACHMENT AE

Integrated Marketplace

2.2 Application and Asset Registration

…

(11) A Market Participant that is selling firm power to the load asset under a bilateral contract

may, with the agreement of the buyer, register all or a portion of the buyer’s load as its

load asset. For purposes of this Section 2.2(11) of this Attachment AE, the sale of firm

Page 9 of 13

power shall refer to power sales deliverable with firm transmission service, with the

supplier assuming the obligation to serve the buyer’s load with both capacity and energy.

For the purposes of Section 2.11.1 of this Attachment AE, such registration of the buyer’s

load by the seller shall be accounted for by including such load in the seller’s Reported

Load and not including such load in the buyer’s Reported Load, as described under

Section 2.11.1(A)(1) of this Attachment AE, and such associated bilateral contracts shall

not be included in either the buyer’s or seller’s net resource capacity described under

Section 2.11.1(A)(4) of this Attachment AE.

…

2.11 Must-Offer Requirement

2.11.1 Day-Ahead Market

There is no requirement for any Resource to offer in the DA Market.

A. Each Market Participant must satisfy the must offer obligation for an Asset Owner as set forth in

Section 2.11.1(B) of this Attachment AE based on the following criteria:

(1) A Market Participant’s load for an Asset Owner for purposes of this section shall be equal

to that Market Participant’s maximum hourly Reported Load for an Asset Owner for the

Operating Day. Such Asset Owner’s Reported Load shall include load registered as

described under Section 2.2(11) of this Attachment AE, where the buyer’s Reported Load

shall be reduced by the amount of the buyer’s load registered by the seller and the seller’s

Reported Load shall be increased by the amount of the buyer’s load registered by the seller.

(2) A Market Participant’s daily Operating Reserve obligation for an Asset Owner shall be

equal to the sum of that Market Participant’s maximum daily Regulation-Up Service,

Regulation-Down Service and Contingency Reserve obligations for an Asset Owner as

estimated by the Transmission Provider in accordance with Section 3.1.4(3) of this

Attachment AE.

(3) A Market Participant may satisfy this requirement by offering Resources for an Asset

Owner with a commitment status indicating either that the Market Participant is self-

committing the Resource, the Resource may be committed by the Transmission Provider,

or the Resource may be committed by the Transmission Provider only to alleviate an

anticipated Emergency Condition or Local Reliability Issue, as specified in Sections

Page 10 of 13

4.1(10)(a), 4.1(10)(b), and 4.1(10)(c) of the Attachment AE.

(4) A Market Participant’s net resource capacity for an Asset Owner, for purposes of this

section shall include:

i. Offered capacity by Resources identified in Section 2.11.1(A)(3) of Attachment AE

less the Operating Reserve obligation identified in Section 2.11.1(A)(2) of

Attachment AE; and

ii. Firm power purchases less firm power sales, except that, if the seller has registered

the buyer’s load associated with a firm power sale as described in Section 2.2(11)

of this Attachment AE, such firm power sale shall not act to increase the buyer’s

net resource capacity or act to reduce the seller’s net resource capacity. For

purposes of this Section 2.11.1 of this Attachment AE firm power purchases and

firm power sales shall mean sales and purchases that are deliverable with

transmission service comparable to Firm Point-To-Point Transmission Service or

Firm Network Integration Transmission Service with the supplier assuming the

obligation to provide both capacity and energy. Additionally, firm power purchases

shall include an Asset owner’s share of a Jointly Owned Unit to the extent that such

shares have not been registered as separate Resources either under Jointly Owned

Unit individual Resource option or the Jointly Owned Unit combined Resource

option as described under Section 2.2(4) of this Attachment AE.

In order to verify firm power purchases and firm power sales, supporting

documentation must be provided to the Market Monitor upon request. Market

Participants have the option to input information regarding firm power purchases

and firm power sales into the Market Monitor website. If no information is input

into this website, the Market Monitor will contact the Market Participant for that

information. The Market Monitor may communicate with the counterparty to

confirm the firm purchase or sale and will include the transacted MWs to calculate

net resource capacity for both purchaser and seller. If one of the parties disputes

the firm purchase or sale to the Market Monitor, then the firm purchase or sale will

not be used in the calculation of either the purchaser’s or seller’s net resource

capacity subject to any dispute resolution.

B. A Market Participant’s compliance with the must offer obligation for an Asset Owner is as follows:

(1) A Market Participant that has offered all of its available Resources for an Asset Owner,

with a commitment status described in Sections 4.1(10)(a), 4.1(10)(b), and/or 4.1(10)(c) of

Page 11 of 13

this Attachment AE, for an hour of the Operating Day is deemed to be in compliance with

the must offer requirement for that Asset Owner for that hour regardless of its maximum

hourly Reported Load and/or, Operating Reserve obligation.

(2) A Market Participant that does not meet the condition described in Section 2.11.1(B)(1) of

this Attachment AE for an Asset Owner for an hour of the Operating Day, but has net

resource capacity for that Asset Owner for that hour greater than or equal to 90% of its load

for that Asset Owner as described in Section 2.11.1(A)(1) of this Attachment AE is deemed

to be in compliance for that Asset Owner with the must offer requirement for that hour.

(3) To the extent that a Market Participant does not meet the conditions described in either

Section 2.11.1(B)(1) or (2) for an Asset Owner, the Market Participant shall be deemed

noncompliant with the must offer requirement for that Asset Owner for that hour and will

be assessed a penalty for that hour as determined in Section 3.9 of Attachment AF of this

Tariff.

C. Market Monitor shall monitor a Market Participant’s Load, Operating Reserve obligation, offered

Resources and net resource capacity, for an Asset Owner for each hour of the Operating Day to

determine whether the Market Participant has complied with the must offer obligation set forth in

Section 2.11.1(B).

2.11.1 Reliability Unit Commitment and the Real-Time Balancing Market

For the RUC processes and RTBM, Market Participants must submit Resource Offers for

all Resources to the extent these Resources are available. Market Participants must include in their

Resource Offers the full amount of physical capacity available as reflected in the Resource’s

submitted Maximum Normal Capacity Operating Limit and Maximum Emergency Capacity

Operating Limit.

ATTACHMENT AF

MARKET POWER MITIGATION PLAN

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

Page 12 of 13

the mitigated offer by more than the relevant conduct threshold, as specified in

Section 3.2, 3.3, 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

Page 13 of 13

in the RTBM by limiting Day-Ahead Offers, and the effects of any such efforts

upon make whole payments.

SPP Criteria

SPP Business Practices

Page 1 of 19


RR #: 127 Date: 11/4/2015

RR Title: JOU Combined Option - Aggregate Energy Offer Curve


Name: Jim Flucke Company: Kansas City Power & Light

Email: [email protected] Phone: (816) 701-7836




In the current market design of a Combine Resource Option for JOUs, an Asset Owner could potentially game the Energy Offer Curve of Make-Whole Payments. Each share of a Combine Resource Option is allowed to put in their own independent offer based on their costs for energy. The potential gaming opportunity is achieved by putting in a larger than normal Energy Offer Curve and getting dispatch to their minimum. Since the entire JOU plant is committed or none at all, the Asset Owner with the higher than normal Energy Offer Curve is made whole to that curve.

This Revision Request eliminates the potential gaming opportunity by taking all share’s pricing point of a Combined Resource Option for a JOU and aggregating those price points into one Energy Offer Curve. This Revision Request makes all shares under a Combined resource Option to start at a minimum capacity of zero for the first price point. If committed, all shares of that Combined Resource Option for that JOU will be eligible to recover Start-Up and No-Load costs as described in the Protocols. The shares will only receive a dispatch instruction greater than zero based upon the one new aggregated Energy Offer Curve thus eliminating the gaming opportunity.


This Revision Request will eliminate a potential gaming opportunity. Currently, one share of a Combine JOU Option could be dispatch to minimum uneconomically and could potentially receive a higher than normal Make-Whole-Payment based on their Energy Offer Curve because the JOU plant is dispatched as a whole picks up all of the individual share(s). This Revision Request will make all shares of a Combine JOU Option start at zero for the first price point and then aggregate all of the price points into one new Energy Offer curve. If committed, the shares will only be dispatched off of zero if that share is economically.


IMPACT



If no, explain:

Estimated Cost: $ Low - $118,440; Target - $148,050; High - $177,660 Estimated Duration: months

Primary Working Group Score: 410

Page 2 of 19


Market Protocols Protocol Section(s): 4.2.2.1; 4.2.2.5.4; 6.1.6.2

Protocol Version: 34a

Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): Attachment AE 2.2; 4.1.2.3

Business Practice Business Practice Number: WORKING GROUP REVIEWS AND RECOMMENDATIONS

List Primary and any Secondary/Impacted WG Recommendations as appropriate


Date: 11/17/2015


Abstained: OPPD, GSEC, Xcel, CUS, KMEA, AECC, EDE

Opposed: None


Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


MOPC

Date:

Action Taken:

Abstained:

Opposed:


Page 3 of 19


Date:

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author:



Status:

Comment Author:



Status:


Market Protocols

4.2.2.1 Resource Offer Parameters

The following Resource Offer parameters must be submitted to constitute a valid offer for use in either

the DA Market or RTBM:

(1) Resource Name (as specified during Market Registration and cannot be changed as part of

Resource Offer submittal);

(2) Start-Up Offer ($/Start, Hot, Intermediate and Cold – Hourly Unit Commitment Parameter)1;

(3) Mitigated Start-Up Offer ($/Start, Hot, Intermediate and Cold – Hourly Unit Commitment

Parameter) 1;

(4) No-Load Offer ($/Hour)1;

(5) Mitigated No-Load Offer ($/Hour) 1;

1 For Market Participants that have registered a JOU under the Combined Resource Option (see Section 6.1.6.2), this value must be submitted by or on behalf of the designated Asset Owner and represents the value for the entire Physical JOU Resource. See Section 4.2.2.5.4).

Page 4 of 19

(6) Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically non-decreasing

$/MWh, increasing MW and slope or block option);

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

of time must be comprised of by all block or all slope price/quantity pairs.

(i) For a JOU under the Combined Resource Option, the block or slope option must be

selected by or on behalf of the designated Asset Owner. All other JOU Share

Resource owners of that JOU must use the option selected by the designate Asset

Owner. All other JOU Share Resource owners of that JOU will be converted to the

option selected by the designated Asset Owner if submitted differently.

(b) The price of all MWhs below the first pricing point MWh is equal to the first pricing point

price. The price of all MWhs above the last pricing point MWh is equal to the last pricing

point price.

(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 4-5 illustrates

Energy Offer Curves developed from submitted price/MWh pairs for both the slope and

block options.

Exhibit 4-1: Energy Offer Curve Development

(7) Mitigated Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically non-

decreasing $/MWh, increasing MW and slope or block option);

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

Energy Offer Curve

Slope Option

Block Option

Page 5 of 19

(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.

(i) For a JOU under the Combined Resource Option, the block or slope option must be

selected by or on behalf of the designated Asset Owner. All other JOU Share

Resource owners of that JOU must use this selected option. All other JOU Share

Resource owners of that JOU will be converted to the option selected by the

designated Asset Owner if submitted differently.

(8) Regulation-Up Offer ($/MW);

…

4.2.2.5.4 Jointly Owned Unit

Jointly Owned Unit (JOU) owners may elect to model their individual ownership shares as separate

Resources using either the Individual Resource Option or the Combined Resource Option as specified

during market registration as described under Section 6.1.6. Otherwise, the Resource is modeled like any

other single Resource with an associated single Asset Owner. Resource offers may be submitted for each

Asset Owner’s JOU ownership (“JOU Share Resource”) the same as any other Resource subject to the

following Resource Offer validation rules and exceptions.

(1) As part of market registration, the following offer parameters representing the ownership and

physical characteristics of the entire JOU (“Physical JOU Resource”) must be submitted either by

or on behalf of the Asset Owner identified at registration (“designated Asset Owner”):

(a) JOU maximum physical capacity operating limit;

(b) JOU minimum physical capacity operating limit;

(c) maximum physical 10-minute response from an off-line state (if a Quick-Start Resource);

and

(d) JOU Ownership Percent Share by Asset Owner (Default value. May be updated as part of

DA Market and RTBM Offer. Only required if registered under Combined Resource

Option).

(2) The following Offer parameters as submitted by or on behalf of each Asset Owner for its JOU

Share Resource must meet the following criteria in order to be accepted as valid offers, otherwise,

all Offers related to the Physical JOU Resource will revert to the last valid offer;

(a) The sum of the Maximum Emergency Capacity Operating Limits of each JOU Share

Resource associated with the Physical JOU Resource must be less than or equal to the

Physical JOU Resource maximum physical capacity operating limit; and

Page 6 of 19

(b) The sum of the Minimum Emergency Capacity Operating Limits of each JOU Share

Resource associated with the Physical JOU Resource must be greater than or equal to the

Physical JOU Resource minimum physical capacity operating limit;

(3) Commitment of individual JOU Share Resources that have registered under the Individual

Resource Option will be evaluated by SCUC based on the individually submitted Offers for each

JOU Share Resource;

(4) Commitment of JOU Share Resources that have registered under the Combined Resource option

will be evaluated by SCUC based on a combination of the individually submitted Offers for each

JOU Share Resource and the Offer parameters submitted by or on behalf of the designated Asset

Owner that apply to the entire Physical JOU Resource (see Section 4.2.2.1 for footnoted

parameters to be submitted by or on behalf of the designated Asset Owner and Section 4.2.2.2

regarding Commitment Status) given the additional constraint that if one of the JOU Resources is

committed, all JOU Share Resources associated with the Physical JOU Resource must be

committed. This rule also applies to clearing of Supplemental Reserve from off-line Quick-Start

Resources. Each Asset Owner of a JOU Share Resource under the Combined Resource Option

must submit a zero for Minimum Emergency Capacity Operating Limit, Minimum Normal

Capacity Operating Limit, and Minimum Economic Capacity Operating Limit. The JOU

minimum physical capacity operating limit submitted in registration can be achieved by any

combination of JOU Share Resource(s) during the commitment period. The designated Asset

Owner of that JOU under the Combined Resource Option will designate for all shares either the

slope or block option when submitting the Energy Offer Curve. A JOU under the Combined

Resource Option will be dispatched using an aggregated Energy Offer Curve. This aggregated

Energy Offer Curve is made up of all price points from each JOU Share Resource’s Energy Offer

Curve associated with that JOU. When committed each JOU Share Resource is eligible for

recovery of Start-Up Offer and No-Load Offer costs proportional to that Asset Owner’s JOU

Ownership Percent Share whether or not that JOU Share Resource was dispatched greater than

zero MWs as described under Section 4.5.8.12 and 4.5.9.8. Prior to evaluation by SCUC, each

JOU Share Resource associated with the Physical JOU Resource is assigned the following unit

commitment parameters as submitted by or on behalf of the designated Asset Owner:

(a) The Start-Up Offer of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is calculated by multiplying the Start-Up Offer submitted for the

Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share and this

value will be used for make-whole-payment calculation purposes;

(b) The Mitigated Start-Up Offer of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the Mitigated Start-Up Offer

submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent

Share and this value will be used for make-whole-payment calculation purposes;

Page 7 of 19

(c) The No-Load Offer of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is calculated by multiplying the No-Load Offer submitted for the

Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share and this

value will be used for make-whole-payment calculation purposes;

(d) The Mitigated No-Load Offer of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the Mitigated No-Load Offer


Share and this value will be used for make-whole-payment calculation purposes;

(e) The Sync-To-Min Time of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Sync-To-Min Time submitted for the Physical

JOU Resource;

(f) The Min-To-Off Time of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Min-To-Off Time submitted for the Physical

JOU Resource;

(g) The Start-Up Time of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Start-Up Time submitted for the Physical JOU

Resource;

(h) The Hot to Intermediate Time of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is set equal to the Hot to Intermediate Time submitted for the

Physical JOU Resource;

(i) The Hot to Cold Time of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Hot to Cold Time submitted for the Physical

JOU Resource;

(j) The Maximum Daily Starts of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is set equal to the Maximum Daily Starts submitted for the


(k) The Maximum Weekly Starts of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is set equal to the Maximum Weekly Starts submitted for the


(l) The Maximum Daily Energy of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the Maximum Daily Energy


Share;

(m) The Minimum Run Time of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Minimum Run Time submitted for the Physical

JOU Resource;

Page 8 of 19

(n) The Minimum Down Time of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is set equal to the Minimum Down Time submitted for the


(o) The Maximum Run Time of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Maximum Run Time submitted for the Physical

JOU Resource;

(p) The Maximum Quick-Start Response Limit of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is calculated by multiplying the Maximum

Quick-Start Response Limit submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share; and

(q) The Commitment Status of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Commitment Status submitted for the Physical

JOU Resource.

(5) If committed, each JOU Share Resource under the Individual Resource Option will be considered

separately for the purposes of dispatch, Operating Reserve clearing and settlement and the Physical

JOU Resource will receive an aggregate Setpoint Instruction for the purposes of Energy and

Operating Reserve deployment;

(a) If a JOU Share Resource is committed by SPP in the DA Market, that JOU Share Resource

is cleared for Energy based on the submitted Energy Offer Curve and Ramp Rate and is

cleared for Operating Reserve based on the submitted Operating Reserve Offers and Ramp

Rate;

(b) Each JOU Share Resource committed by SPP in the DA Market is eligible to receive a DA

Market make-whole payment under the same eligibility rules as any other Resource as

described under Section 4.5.8.12;

(c) In the RTBM, each JOU Share Resource is dispatched for Energy based on the submitted

Energy Offer Curve, Ramp-Rate-Up and Ramp-Rate-Down and is cleared for Operating

Reserve based on the submitted Operating Reserve Offers, Ramp-Rate-Up and Ramp-

Rate-Down. SPP sends to each Asset Owner it’s independent Dispatch Instruction,

Setpoint Instruction, and cleared amount(s) of Operating Reserve for its individual JOU

Share Resource.

SPP will also, for information purposes, send to the JOU Operating Owner each Asset

Owner’s independent Dispatch Instructions and the sum of these independent Dispatch

Instructions, and each Asset Owner’s independent Setpoint Instructions and the sum of the

Asset Owner’s independent Setpoint Instructions.

Page 9 of 19

The SPP provided Setpoint Instruction(s) for each JOU Share and the actual output

submitted for each JOU Asset Owner(s) as submitted by respective Meter Agent(s) shall

be used for monitoring according to (ii) below and for settlements.

(i) If a JOU Share Resource is committed by SPP in any RUC process, that individual

JOU Share Resource is eligible to receive a RUC make-whole payment under the

same eligibility rules as any other Resource as described under Section 4.5.9.8.

(ii) Each JOU Share Resource will be subject to charges associated with Uninstructed

Resource Deviation that exceeds the JOU Share Resource Operating Tolerance as

described under Sections 4.5.9.8 and 4.5.9.10, Regulation deployment failure

charges as described under Section 4.5.9.15 and Contingency Reserve deployment

failure charges as described under Section 4.5.9.17, under the same eligibility rules

as any other Resource.

(6) If committed, each JOU Share Resource under the Combine Resource Option will be considered

separately for the purposes of dispatch, Operating Reserve clearing and settlement and the Physical

JOU Resource will receive an aggregate Setpoint Instruction for the purposes of Energy and

Operating Reserve deployment;

(a) If a JOU Share Resource is committed by SPP in the DA Market, that JOU Share Resource

is cleared for Energy based on the aggregated Energy Offer Curve as described in (4) above

and the submitted Ramp Rate and is cleared for Operating Reserve based on the Operating

Reserve Offers and the submitted Ramp Rate;

(b) Each JOU Share Resource committed by SPP for a MW amount greater than zero in the

DA Market is eligible to receive a DA Market make-whole payment under the same

eligibility rules as any other Resource as described under Section 4.5.8.12;

(c) Excluding the designated Asset Owner of that JOU, each JOU Share Resource committed

by SPP for a MW amount of zero in the DA Market is eligible to recover Start-Up and No-

Load costs proportional to that Asset Owner’s JOU Ownership Percent Share as described

under Section 4.5.8.12.

(d) In the RTBM, each JOU Share Resource is dispatched for Energy based on the aggregated

Energy Offer Curve as described in (4) above, the submitted Ramp-Rate-Up and Ramp-

Rate-Down and is cleared for Operating Reserve based on the Operating Reserve Offers,

the submitted Ramp-Rate-Up and Ramp-Rate-Down. SPP sends to each Asset Owner it’s

independent Dispatch Instruction, Setpoint Instruction, and cleared amount(s) of Operating

Reserve for its individual JOU Share Resource.

SPP will also, for information purposes, send to the JOU Operating Owner each Asset

Owner’s independent Dispatch Instructions and the sum of these independent Dispatch

Page 10 of 19

Instructions, and each Asset Owner’s independent Setpoint Instructions and the sum of the

Asset Owner’s independent Setpoint Instructions

The SPP provided Setpoint Instruction(s) for each JOU Share and the actual output

submitted for each JOU Asset Owner(s) as submitted by respective Meter Agent(s) shall

be used for monitoring according to (iii) below and for settlements.

(i) If a JOU Share Resource is committed by SPP for a MW amount greater than zero

in any RUC process, that individual JOU Share Resource is eligible to receive a

RUC make-whole payment under the same eligibility rules as any other Resource

as described under Section 4.5.9.8.

(ii) Excluding the designated Asset Owner of that JOU, if a JOU Share Resource is

committed by SPP for a MW amount of zero in any RUC process that individual

JOU Share Resource is eligible to recover Start-Up and No-Load costs proportional

to that Asset Owner’s JOU Ownership Percent Share as described under Section

4.5.9.8.

(ii)(iii) Each JOU Share Resource will be subject to charges associated with

Uninstructed Resource Deviation that exceeds the JOU Share Resource Operating

Tolerance as described under Sections 4.5.9.8 and 4.5.9.10, Regulation deployment

failure charges as described under Section 4.5.9.15 and Contingency Reserve

deployment failure charges as described under Section 4.5.9.17, under the same

eligibility rules as any other Resource.

(6)(7) The Meter Agent(s) assigned to the Physical JOU Resource must account for all physical

Energy produced and properly reflect this Energy in each individual JOU Share Resource meter

data submittal.

6.1.6 Jointly Owned Resource

In addition to the responsibilities described under Section 6.1.1, Market Participants wishing to model

each ownership share as a separate Resource must choose one of the two options described below and

provide the specified additional information. A Resource registered as a Combined Cycle Resource may

not register as a JOU.

6.1.6.1 Individual Resource Option

Under the Individual Resource Option, each ownership share is modeled as a separate Resource for the

purposes of commitment and dispatch and each Resource may be committed independent of the other

Resource shares. In order to qualify for this option, all Asset Owners must certify that if their ownership

share Resource is the only Resource committed, that their ownership share is greater than or equal to the

minimum physical capacity operating limit of the Physical JOU Resource. The following additional

information must also be provided and/or specified:

Page 11 of 19

(1) Specification of a single Asset Owner that will be responsible for submittal of the following

operating data representing the physical operating characteristics of entire JOU Resource for use

in data validation as described under Section 4.2.2.5.4;


(b) JOU minimum physical capacity operating limit; and

(c) Maximum physical 10-minute response from an off-line state.

(2) Specification of each Asset Owner and Settlement Location associated with each individual

ownership share.

The default presumption is that the operating owner’s Meter Agent will be the Meter Agent for that JOU

Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of

the Resource.

6.1.6.2 Combined Resource Option

Under the Combined Resource Option, each ownership share is modeled as a separate Resource for the

dispatch purposes but commitment related parameters are submitted representing the entire physical

Resource. Under this option, the commitment decision is made assuming that all Resource shares must

be committed or none at all. Each Asset Owner of a JOU Share Resource under the Combined Resource

Option must submit a zero for Minimum Emergency Capacity Operating Limit, Minimum Normal

Capacity Operating Limit, and Minimum Economic Capacity Operating Limit. The JOU minimum

physical capacity operating limit submitted in registration can be achieved by any combination of JOU

Share Resource(s) during the commitment period. The designated Asset Owner of that JOU under the

Combined Resource Option will designate for all shares either the slope or block option when submitting

the Energy Offer Curve. A JOU under the Combined Resource Option will be dispatched using an

aggregated Energy Offer Curve. This aggregated Energy Offer Curve is made up of all price points from

each JOU Share Resource’s Energy Offer Curve associated with that JOU. When committed each JOU

Share Resource is eligible for recovery of Start-Up Offer and No-Load Offer costs proportional to that

Asset Owner’s JOU Ownership Percent Share whether or not that JOU Share Resource was dispatched

greater than zero MWs as described under Section 4.5.8.12 and 4.5.9.8. This option must be selected if

the eligibility criteria stated under the Individual Resource Option cannot be met. The following additional

information must also be provided

(1) Specification of a single Asset Owner (“designated Asset Owner”) that will be responsible for

submittal by or on its behalf of all unit commitment related data and the following operating data

representing the physical operating characteristics of entire JOU Resource for use in data

validation as described under Section 4.2.2.5.4;


(b) JOU minimum physical capacity operating limit; and

Page 12 of 19

(c) Maximum physical 10-minute response from an off-line state.

(2) Specification of each Asset Owner, JOU Ownership Percent Share and Settlement Location

associated with each individual ownership share JOU Resource.

(a) Submitted JOU Ownership Percent Shares must add up to 100%.

The default presumption is that the operating owner’s Meter Agent will be the Meter Agent for that JOU

Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of

the Resource.

SPP Tariff (OATT)

Attachment AE

2.2 Application and Asset Registration

(1) Applications for a Market Participant to provide services in the Integrated Marketplace

must be submitted to the Transmission Provider prior to the expected date of participation

consistent with Section 6.4 of the Market Protocols. Applications must conform to the

procedures specified in the Market Protocols and may be rejected if not complete. New

Market Participants will follow the timeframe as specified in Section 6.4 of the Market

Protocols in addition to the detailed model update timing requirements in Appendix E of

the Market Protocols.

(2) As part of the application process, Market Participants must register all Resources and

load, including applicable load associated with Grandfathered Agreements (“GFAs”),

Non-Conforming Load and Demand Response Load with the Transmission Provider in

accordance with the registration process specified in the Market Protocols. As part of

Resource registration, Market Participants must specify whether settlement meter data

will be submitted on a gross basis or net basis, where gross meter data does not include

reductions for auxiliary load and net meter data is gross meter data reduced by auxiliary

load. Both Non-Conforming Load and Demand Response Load may only be associated

with a single Price Node except that Non-Conforming Load and Demand Response Load

may be associated with an aggregated Price Node that contains multiple electrically

equivalent Price Nodes. Non-participating embedded load and/or generation must either:

(i) register its load and/or generation in the Integrated Marketplace; or (ii) transfer its load

and/or generation to an external Balancing Authority.

Page 13 of 19

(3) Market Participants may elect to define a single Settlement Location that aggregates

multiple Meter Data Submittal Locations associated with their load assets. Market

Participants may not aggregate multiple Resource Meter Data Submittal Locations into a

single Resource Settlement Location unless the Resources are at the same physical and

electrically equivalent injection point to the Transmission System.

(4) In addition to the responsibilities described in Section 4.1.2 of this Attachment AE and

under the Market Protocols, Market Participants wishing to model each participant’s

share of a Jointly Owned Unit as a separate Resource must choose one of the two options

described below and provide the specified additional information. A Resource registered

as a combined cycle Resource may not register as a Jointly Owned Unit.

(a) Individual Resource Option

Under the individual Resource option, each participant’s share is modeled

as a separate Resource for the purposes of commitment and dispatch and each

Resource may be committed independent of the other Resource shares. In order

to qualify for this option, each Market Participant must register its share and

certify that it is greater than or equal to the minimum physical capacity operating

limit of the physical Jointly Owned Unit.

The operating owner’s Meter Agent will be the Meter Agent for that

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit; and • Maximum physical ten (10) minute response from an off-line state.

(b) Combined Resource Option

Under the combined Resource option each participant’s share is modeled

and must be registered as a separate Resource. Under this option, the

commitment decision is made assuming that all Resource shares must be

committed or none at all. Each Asset Owner of a Jointly Owned Unit share

Resource under the combined Resource option must submit a zero for the

Minimum Emergency Capacity Operating Limit, Minimum Normal Capacity

Operating Limit, and Minimum Economic Capacity Operating Limit. The Jointly

Page 14 of 19

Owned Unit minimum physical capacity operating limit can be achieved by any

combination of Jointly Owned Unit share Resource(s) during the commitment

period. A Jointly Owned Unit under the combined Resource option will be

dispatched using an aggregated Energy Offer Curve. Once committed, each

Jointly Owned Unit share is dispatched independently and is eligible for recovery

of Start-Up Offer and No-Load Offer costs as described under Sections 8.5.9 and

8.6.5 of this Attachment AE. This option must be selected if the eligibility

criteria stated under the individual Resource option cannot be met.

The operating owner’s Meter Agent will be the Meter Agent for that

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit;

• Maximum physical ten (10) minute response from an off-line state;

and

• Participant share percentage by Market Participant.

(5) Market Participants may modify their registered assets in accordance with the asset

registration procedures specified in the Market Protocols.

(6) All loads and all Resources, excluding Behind-The-Meter Generation less than 10

Megawatts (“MWs”), must register. Failure or refusal to register a Resource will result in

the Transmission Provider filing an unexecuted version of the service agreement as

specified in Attachment AH of this Tariff for that Resource with the Commission under

the name of the generation interconnection customer under an interconnection agreement

with the Transmission Provider or the applicable Transmission Owner. In the case of a

Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its

host utility, such registration will not require the Qualifying Facility to participate in the

Energy and Operating Reserve Markets or subject the Qualifying Facility to any charges

or payments related to the Energy and Operating Reserve Markets. Any Energy and

Operating Reserve Market charges or payments associated with the output of the

Qualifying Facility will be allocated to the Market Participant representing the host utility

Page 15 of 19

purchasing the output of the Qualifying Facility under PURPA, and the Market

Participant will be provided the settlement data required to verify the settlement charges

and payments.

(7) A Market Participant wishing to Offer an External Resource in the Energy and Operating

Reserve Markets will utilize an External Resource Pseudo-Tie in accordance with

Attachment AO. In addition to the responsibilities outlined in Attachment AO, the

Market Participant registering the External Resource will be responsible for registering

and performing all responsibilities that are required of Resources in the Energy and

Operating Reserve Markets.

(8) A Market Participant wishing to offer Demand Response Load as a Demand Response

Resource in the Energy and Operating Reserve Markets must include in its application

and registration a certification that participation in the Energy and Operating Reserve

Markets by its Demand Response Resource is not precluded under the laws or regulations

of the relevant electric retail regulatory authority. Consistent with Section 2.8.1 of this

Attachment, an aggregator of retail customers wishing to offer Demand Response Load

in the form of a Demand Response Resource on behalf of one or more retail customers

must also include in its application and registration a certification that participation of

each retail customer is either: (1) not precluded by the laws or regulations of the relevant

electric retail regulatory authority if the customer is served by a utility that distributed

more than 4 million MWh in the previous fiscal year; or (2) affirmatively permitted by

the laws or regulations of the relevant electric retail regulatory authority if the customer is

served by a utility that distributed 4 million MWh or less in the previous fiscal year.

Demand Response Resources must meet all application, registration and technical

requirements applicable to the Energy and Operating Reserve Markets. The

Transmission Provider is not responsible for interpreting the laws or regulations of a

relevant electric retail regulatory authority and shall be required only to verify that the

Market Participant has included such a certification in its application materials. The

Transmission Provider is not liable or responsible for Market Participants participating in

the Energy and Operating Reserve Markets in violation of any law or regulation of a

relevant electric retail regulatory authority including state-approved retail tariff(s).

(9) An aggregator of retail or wholesale customers offering Demand Response Load of one

or more end-use retail customers or wholesale customers as a Demand Response

Resource in the Energy and Operating Reserve Markets must be a Market Participant,

Page 16 of 19

satisfying all registration and certification requirements applicable to Market Participants

as well as certification consistent with Section 2.8 of this Attachment, as required.

(10) A wind-powered Variable Energy Resource with (1) an interconnection agreement

executed after May 21, 2011 or (2) an interconnection agreement executed on or prior to

May 21, 2011 and that commenced Commercial Operation on or after October 15, 2012

must register as a Dispatchable Variable Energy Resource. A wind-powered Variable

Energy Resource with an interconnection agreement executed on or prior to May 21, 2011

may register as a Dispatchable Variable Energy Resource if it is capable of being

incrementally dispatched by the Transmission Provider. Variable Energy Resources with

fuel sources other than wind may optionally register as a Dispatchable Variable Energy

Resource. Otherwise, Variable Energy Resources must register as Non-Dispatchable

Variable Energy Resources. A Qualifying Facility exercising its rights under PURPA to

deliver its net output to its host utility may register as a Non-Dispatchable Variable Energy

Resource or a Dispatchable Variable Energy Resource as described in the Market

Protocols. Any Resource that has previously registered as a Dispatchable Variable Energy

Resource shall not subsequently register as a Non-Dispatchable Variable Energy Resource.

(11) A Market Participant that is selling firm power to the load asset under a bilateral contract

may, with the agreement of the buyer, register all or a portion of the buyer’s load as its

load asset. For purposes of this Section 2.2(11) of this Attachment AE, the sale of firm

power shall refer to power sales deliverable with firm transmission service, with the

supplier assuming the obligation to serve the buyer’s load with both capacity and energy.

For the purposes of Section 2.11.1 of this Attachment AE, such registration of the buyer’s

load by the seller shall be accounted for by including such load in the seller’s Reported

Load and not including such load in the buyer’s Reported Load, as described under

Section 2.11.1(A)(1) of this Attachment AE, and such associated bilateral contracts shall

not be included in either the buyer’s or seller’s net resource capacity described under

Section 2.11.1(A)(4) of this Attachment AE.

(12) A Transmission Owner providing firm transmission service under a GFA eligible for GFA

Carve Out must request removal of congestion and marginal loss charges and designate the

GFA Responsible Entity within the timeframe set forth in Section 2.2 (1) of Attachment

AE.

Page 17 of 19

(13) A GFA Responsible Entity shall provide to the Transmission Provider the information

necessary to administer the GFA Carve Out. The required information shall include the

following:

(a) Resource Settlement Location;

(b) Load Settlement Location;

(c) The maximum MW capacity contracted under the GFA Carve Out;

(d) The identification of the GFA in Attachment W; and

(e) Any other information reasonably required by the Transmission Provider.

(14) Market Participants with assets interconnected to the Transmission System that are not

participating in the Energy and Operating Reserve Markets must pseudo-tie the Resource

or load out of the SPP Balancing Authority Area in accordance with Attachment AO.

Such assets shall continue to be registered in the Integrated Marketplace for the purposes

of accounting for congestion and loss charges between the Resource Price Node and the

applicable External Interface Settlement Location as described under Sections 8.6.19 and

8.6.20 of this Attachment AE.

(a) To the extent that the SPP Balancing Authority or associated external Balancing

Authority can no longer maintain the Resource pseudo-tie for reliability reasons,

the Market Participant representing the pseudo-tied Resource must immediately

reduce the output of the pseudo-tied resource to the available pseudo-tie

capability after receiving notification from the affected Balancing Authority of the

reduced capability. A Market Participant shall not generate any energy in excess

of the available pseudo-tie capability after receiving such notification and shall

not be compensated in the Energy and Operating Reserve Markets settlement for

any energy generated in excess of the available pseudo-tie capability.

(15) Western-UGP shall provide to the Transmission Provider the information necessary to

administer the FSE. The required information shall include the following:

(a) Resource Settlement Locations;

(b) Load Settlement Locations;

(c) The maximum MW capacity contracted under the FSE;

(d) The identification of the FSE Statutory Load Obligations as described in the SPP-

Western-UGP NITSA; and

Page 18 of 19

(e) Any other information reasonably required by the Transmission Provider.

(16) The Transmission Provider shall establish FSE Transfer Points consistent with the FSE

transmission service power flow impacts.

4.1.2.3 Jointly Owned Unit

Each Market Participant may submit Resource Offers for its share of the Jointly

Owned Unit as specified in the Market Protocols. Offer parameters must meet the

following criteria in order to be accepted as valid Offers, otherwise the last submitted valid

offer shall apply:

(1) The sum of the Maximum Emergency Capacity Operating Limits of all shares of

the Jointly Owned Unit must be less than or equal to the Jointly Owned Unit

maximum physical capacity operating limit; and

(2) The sum of the Minimum Emergency Capacity Operating Limits of all shares of

the Jointly Owned Unit must be greater than or equal to the Jointly Owned Unit

minimum physical capacity operating limit.

Commitment of individual Jointly Owned Unit shares that have registered under the

individual Resource option will be evaluated by security constrained unit commitment

(“SCUC”) based on the individually submitted Offers for each Jointly Owned Unit share.

Commitment of Jointly Owned Unit shares that have registered under the combined

Resource option will be evaluated by SCUC based on a combination of the individually

submitted Offers for each Jointly Owned Unit share and the commitment related Offer

parameters submitted by the designated Market Participant that apply to the entire Jointly

Owned Unit given the additional constraint that if one of the Jointly Owned Units is

committed, all Resource shares for each Jointly Owned Unit must be committed. This rule

also applies to clearing of Supplemental Reserve from off-line Quick-Start Resources.

Each Market Participant of a Jointly Owned Unit share under the combined Resource

option must submit a zero for Minimum Emergency Capacity Operating Limit, Minimum

Normal Capacity Operating Limit, and Minimum Economic Capacity Operating Limit. A

Jointly Owned Unit under the combined Resource option will be dispatched using an

aggregated Energy Offer Curve. When committed, each Jointly Owned Unit share is

eligible for recovery of Start-Up Offer and No-Load Offer costs as described under

Sections 8.5.9 and 8.6.5 of this Attachment AE.

Page 19 of 19

SPP Criteria

N/A


N/A

Page 1 of 16


RR #: 128 Date: 11/4/2015

RR Title: Clarification to the Start-Up Eligibility Rules


Name: Micha Bailey Company: Southwest Power Pool





The rules for the Start-Up eligibility for the Day-Ahead and RUC MWP has circular references and could be confusing when read.


This Revision Request will clarify the language for the rules for the Start-Up eligibility for the Day-Ahead and RUC MWP. The circular reference will be removed and the format of the language will change to allow a better read.


IMPACT


If yes, briefly explain: Note: Covered in RR118 and RR16_MPRR190


If no, explain:




Market Protocols Protocol Section(s): 4.5.8.12; 4.5.9.8


Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): AE sections 8.5.9, 8.6.5 Business Practice Business Practice Number:


Page 2 of 16


Date: 11/17/2015

Action Taken: Unanimously Approved


Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


MOPC

Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author:

Page 3 of 16



Status:

Comment Author:



Status:


Market Protocols

4.5.8.12 Day-Ahead Make-Whole-Payment Amount

(1) The Day-Ahead Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner

and is calculated for each Resource with an associated DA Market Commitment Period that was

committed by SPP with a Day-Ahead Market Resource Offer Commitment Status of “Market” or

“Reliability” as defined under Section Error! Reference source not found., or was committed as

part of the Multi-Day Reliability Assessment as defined under Section Error! Reference source not found.. A payment is made to the Resource Asset Owner when the sum of the Resource’s DA

Market Start-Up Offer costs, No-Load Offer costs, Transition State Offer costs, Energy Offer

Curve and Operating Reserve Offer costs associated with cleared DA Market amounts for Energy

and Operating Reserve is greater than the Energy and Operating Reserve DA Market revenues

received for that Resource over the Resource’s DA Market Make-Whole-Payment Eligibility

Period.

(2) A Resource’s DA Market Make-Whole-Payment Eligibility Period is equal to a Resource’s DA

Market Commitment Period except as defined below:

(a) For Resources with an associated DA Market Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two DA Market Make-Whole-Payment

Eligibility Periods are created. The first period begins in the first Operating Day in the

hour that the DA Market Commitment Period begins and ends in the last hour of the first

Operating Day. The second period begins in the first hour of the next Operating Day and

ends in the last hour of the DA Market Commitment Period.

1 Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.

Commented [MPRR101.1]: MPRR101 awaiting FERC filing

Page 4 of 16

(3) The following cost recovery eligible rules apply to each DA Market Make-Whole-Payment

Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the

time the commitment decision was made except under the situation described under Section

(b)(i)(1) below.

(a) There may be more than one DA Market Make-Whole Payment Eligibility Period for a

Resource in a single Operating Day for which a credit or charge is calculated. A single

DA Market Make-Whole Payment Eligibility Period is contained within a single Operating

Day.

(b) A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following

DA Market Make-Whole Payment Eligibility Periods except as described in (i)(1) and

(i)(2) below:

(i) Any DA Market Make-Whole Payment Eligibility Period for which the Day-Ahead

Market SCUC did not consider the Resource’s Start-Up Offer in the commitment

decision unless the Start-Up Offers are associated with manual commitments as

described under Sections 4.2.6.2 and 4.3.1.2(1)(b); or

(i)(ii) aAny Day-Ahead Make-Whole Payment Eligibility Period that is adjacent to the

end of a RUC Make-Whole Payment Eligibility Period; or that was created

subsequent to the Day-Ahead Market Make-Whole Payment Eligibility Period

during the day before the Operating Day for which the Day-Ahead Market Make-

Whole Payment Eligibility Period applies;

(1) As described under Section 4.5.9.8(3)(h), to the extent that the full amount

of the RTBM Start-Up Offer is not accounted for in the adjacent RUC

Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up

Offer costs are carried forward for recovery in the adjacent Day-Ahead

Make-Whole Payment Eligibility Period.

Start-Up Offers associated with manual commitments as described under

Sections 4.2.6.2 and 4.3.1.2(1)(b) are eligible for recovery.

(ii)(iii) Any DA Market Make-Whole Payment Eligibility Period resulting from a DA

Market Commitment Period that contains a DA Market Self-Commit Hour; and or

(iii)(iv) Any DA Make-Whole Payment Eligibility Period for which a Resource is a

Synchronized Resource prior to this commitment period at a time one hour prior to

that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min Time

unless such time is within a contiguous RUC Make-Whole Payment Eligibility

Period that is created subsequent to the DA Market Make-Whole-Payment

Eligibility Period.

Commented [MCB2]: RR16_MPRR190





Page 5 of 16

(c) As described under Section 4.5.9.8 (3)(h), to the extent that the full amount of the eligible

RTBM Start-Up cost is not accounted for in the adjacent RUC Make-Whole Payment

Eligibility Period, any remaining RTBM Start-Up cost is carried forward for recovery in

the adjacent Day-Ahead Make-Whole Payment Eligibility Period.

(c)(d) For each DA Market Make-Whole Payment Eligibility Period within an Operating

Day, a Resource’s DA Market Start-Up Offer is divided by the lesser of (1) the Resource’s

Minimum Run Time rounded down to the nearest hour or (2) 24 Hours, and that portion of

the Start-Up Offer is included as a cost in each hour of the DA Market Make-Whole

Payment Eligibility Period until the sum of these hourly costs are equal to the DA Market

Start-Up Offer or until the end of the DA Market Make-Whole Payment Eligibility Period,

whichever occurs first.

(d)(e) To the extent that the full amount of the DA Market Start-Up Offer is not accounted

for in the last DA Market Make-Whole Payment Eligibility Period in the Operating Day,

any remaining DA Market Start-Up Offer costs are carried forward for recovery in the first

DA Market Make-Whole Payment Eligibility Period of the following Operating Day. For

example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1

that has a Minimum Run Time of 10 hours and a Start-Up Offer of $10,000. The DA

Market Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of

Operating Day 2. For DA Market Make-Whole Payment calculation purposes, the DA

Market Commitment Period is split into two separate DA Market Make-Whole Payment

Eligibility Periods as described in (2).b above. The first DA Market Make-Whole Payment

Eligibility Period will include $1000/hour of Start-Up Offer costs ($10,000 / 10 Hours) in

hours 23 and 24. The second DA Market Make-Whole Payment Eligibility Period will

include $1000/hour of Start-Up Offer costs in hours 1 through 8.

(e)(f) If the Resource is a combined cycle Resource, additional costs associated with situations

in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must

buy back that position in Real-Time at an average Real-Time MCP that is greater than the

Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To

be eligible, these costs must be incurred during a time period in which the Resource is

transitioning between configurations, at the direction of SPP, such cost is not due to any

independent action of the Market Participant and such cost is not incurred during a RUC

Make-Whole Payment Eligibility Period. In such cases, the additional costs are equal to

the difference between the Real-Time MCP and the Day-Ahead MCP multiplied by the

Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs is

limited to the time period defined as the Transition State Time submitted in the Resource

Offer.

… Commented [MPRR101.7]: MPRR101 awaiting FERC filing

Page 6 of 16

Page 7 of 16

4.5.9.8 RUC Make-Whole-Payment Amount

(1) The RUC Make-Whole-Payment Amount is a credit or charge2 to a Resource Asset Owner and is

calculated for each Resource with a RUC Commitment Period that was committed by SPP with an

RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section

Error! Reference source not found.. Asset Owners of Resources committed by a local transmission

operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment,

except that, if the Market Monitor determines such Resources were selected in a discriminatory

manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment

AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such

Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission

operator commitments, a manual process is employed for the calculations and the make-whole-

payments will appear in the Miscellaneous Amount charge type defined in Section Error! Reference source not found.. The RUC Make-Whole-Payment Amount is also calculated for combined cycle

Resources with a RUC Commitment Period during which the Resource is moved into a configuration

that incurs additional costs over the Resource configuration used in the DA Market Commitment

Period for the corresponding time period. A payment is made to the Resource Asset Owner when the

sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve,

Transition State Offer costs and Operating Reserve Offer costs associated with actual MWh amounts

for Energy and cleared RTBM Operating Reserve is greater than the Energy and Operating Reserve

RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment

Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7

of Attachment AE.

(2) A Resource’s RUC Make-Whole-Payment Eligibility Period is equal to the Resource’s RUC

Commitment Period except as described below:

(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility

Periods are created. The first period begins in the first Operating Day in the Dispatch Interval

associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the

first Operating Day. The second period begins in the first Dispatch Interval of the next Operating

Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.

Exhibit Error! No text of specified style in document.-1: RUC Make-Whole Payment Eligibility Period – Multiple Operating Days


Operating Day 2 Operating Day 1 Real-Time Make-Whole Payment Eligibility Period

Real-Time Make-Whole Payment Eligibility Period



Page 8 of 16

(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an

RTBM hour within the DA Market Commitment Period, the Resource is moved into a

configuration that is different from the configuration used in the DA Market Commitment period

and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is

higher than the No-Load Offer cost associated with the configuration used in the DA Market, that

RTBM hour will be considered the start of a RUC Make-Whole-Payment Eligibility Period. The

end of this RUC Make-Whole-Payment Eligibility Period will be defined by the RTBM hour when

the configuration in that RTBM hour is the same configuration as the configuration used in the

corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end

of the Operating Day, whichever is less.

(3) The following cost recovery eligible rules apply to each RUC Make-Whole-Payment Eligibility

Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time

the commitment decision was made for start-up, no-load, and minimum-energy; and the RTBM Offer

prices in effect at the solving of a dispatch interval for incremental energy, Regulation-Up, Regulation-

Down, Spin, and Supplement Reserves.

(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment

Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive

reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset

Owners may request additional compensation through submittal of actual cost documentation to

the SPP. SPP will review the submitted documentation and confirm that the submitted information

is sufficient to document actual costs and that all or a portion of the actual costs are eligible for

recovery.

(b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility

Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the

RUC Make-Whole Payment Eligibility Period.

Time RUC

Commitment Period


Page 9 of 16

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-

Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch

Interval.

(d) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a

single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole

Payment Eligibility Period is contained within a single Operating Day.

(e) When a RUC Make-Whole Payment Eligibility Period is created after a Day-Ahead Make-Whole

Payment Eligibility Period which is adjacent and preceding the Day-Ahead Make-Whole Payment

Eligibility Period in which the Day-Ahead Start-Up Offer was considered, the eligible Day-Ahead

Start-Up Offer is used in place of the RUC Start-Up Offer costs.

(e)(f) A Resource’s RUC Make-Whole Payment Eligibility Period RTBM Start-Up Offer costs

are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period for which the RUC SCUC did not

consider the Resource’s Start-Up Offer in the commitment decision except that RTBM

Start-Up Offers associated with manual commitments as described under Sections

4.3.2.2(3)(c), 4.3.2.2(3)(d), 4.4.1.2(3)(c) and 4.4.1.2(3)(d) are eligible for recovery; or

when the subsequent RUC Make-Whole Payment Eligibility Period is contiguous and

preceding a Day-Ahead Make-Whole Payment Eligibility Period where the Day-Ahead

Start-Up Offer was consider in which case the Day-Ahead Start-Up Offer is used ;

(i)(ii) Any RUC Make-Whole Payment Eligibility Period for which a Resource is a Synchronized

Resource prior to this commitment period at a time one hour prior to that Resource’s RUC

Commit Time less the Resource’s Sync-To-Min Time; andor

(ii)(iii) Any RUC Make-Whole Payment Eligibility Period resulting from a RUC

Commitment Period that contains an hour for which the Resource Commitment Status is

Self-Commit.

(f)(g) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a

Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run

Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by

12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-

Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM

Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever

occurs first.

(g)(h) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the

last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM

Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment

Eligibility Period of the following Operating Day provided that the Resource has not been


Commented [MCB12]: RR118

Page 10 of 16

committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period

as described in (h) below. For example, consider a Resource that is committed starting at 10:00

PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000.

The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of

Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment

Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in

(2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of

Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-

Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1

through 8 intervals.

(h)(i) If the Resource has been committed in the DA Market in a period adjacent to and following

a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM

Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any

remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-

Whole Payment Eligibility Period.

(i)(j) If the Resource is a combined cycle Resource, additional costs associated with situations

in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back

that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the

Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be

incurred during a time period in which the Resource is transitioning between configurations, at the

direction of SPP, and such cost is not due to any independent action of the Market Participant. In

such cases, the additional costs are equal to the difference between the average Real-Time MCP

and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW

amounts. Recovery of these costs associated with Contingency Reserve is limited to the time

period defined as the Transition State Time submitted in the Resource Offer. Recovery of these

costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals

within the transition hour.

…

Proposed Tariff Language Revision Attachment AE

Bolded Blue text is from RR16_MPRR190 and RR118 approved by BOD but not yet filed with

FERC.

8.5.9 Day-Ahead Make Whole Payment Amount


Page 11 of 16

(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner and is

calculated for each Resource with an associated Day-Ahead Market Commitment Period

that was committed by the Transmission Provider with a Day-Ahead Market Resource

Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this Attachment

AE, or was committed as part of the Multi-Day Reliability Assessment as defined under

Section 4.5.3 of this Attachment AE. A payment is made to the Asset Owner when the

sum of the Resource’s costs is greater than the Day-Ahead Market revenues received for

that Resource over the Resource’s Day-Ahead Market make whole payment eligibility

period. The make whole payment is equal to this difference between these costs and

revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal to a

Resource’s Day-Ahead Market Commitment Period except as defined herein. For

Resources with an associated Day-Ahead Market Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two (2) Day-Ahead Market make whole

payment eligibility periods are created. The first period begins in the first Operating Day

in the hour that the Day-Ahead Market Commitment Period begins and ends in the last

hour of the first Operating Day. The second period begins in the first hour of the next

Operating Day and ends in the last hour of the Day-Ahead Market Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole payment

eligibility period. Offer costs are calculated using the Day-Ahead Market Offer prices in

effect at the time the commitment decision was made except under the situation described

under Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment eligibility

period for a Resource in a single Operating Day for which a charge or payment is

calculated. A single Day-Ahead Market make whole payment eligibility period is

contained within a single Operating Day.

(b) A Resource’s Day-Ahead Market Start-Up Offer costs are not eligible for recovery

in the following Day-Ahead Market make whole payment eligibility periods except

Day-Ahead Start-Up Offer costs described under Section 8.6.5(3)(hi) of this

Attachment AE and Day-Ahead Start-Up Offer costs associated with

commitments made under Sections 4.5 and 5.1.2(1)(b) of this Attachment AE:

Page 12 of 16

(i) For any Day-Ahead Market make whole payment eligibility period for

which the Day-Ahead Market SCUC algorithm did not consider the

Resource’s Start-Up Offer in the commitment decision; or

(ii) For any Day-Ahead Market make whole payment eligibility period that is

adjacent to the end of a RUC make whole payment eligibility period that

was created subsequent to the Day-Ahead Market make whole

payment eligibility period during the day prior to the Operating Day to

which the Day-Ahead Market make whole payment eligibility period

applies; where RUC make-whole payment eligibility period is as

defined under Section 8.6.5(2) of this Attachment AEexcept as

described under Section 8.6.5(3)(h); or

(iii) For any Day-Ahead Market make whole payment eligibility period

resulting from a Day-Ahead Market Commitment Period that contains a

Day-Ahead Market self-commit hour; or

(iiiiv) For any Day-Ahead make whole payment eligibility period for which a

Resource is a Synchronized Resource prior to this commitment period at a

time one (1) hour prior to that Resource’s Day-Ahead Market Commit Time

less the Resource’s Sync-To-Min Time unless such time is within a

contiguous RUC make-whole payment eligibility period that was

created subsequent to the Day-Ahead make whole payment eligibility

period; where RUC make-whole payment eligibility period is as defined

under Section 8.6.5(2) of this Attachment AE.

(c) For each Day-Ahead Market make whole payment eligibility period within an

Operating Day, a Resource’s Day-Ahead Market Start-Up Offer is divided by the

lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest hour

or (2) twenty-four (24) hours, and that portion of the Start-Up Offer is included as

a cost in each hour of the Day-Ahead Market make whole payment eligibility period

until the sum of these hourly costs are equal to the Day-Ahead Market Start-Up

Offer or until the end of the Day-Ahead Market make whole payment eligibility

period, whichever occurs first.

(d) To the extent that the full amount of the Day-Ahead Market Start-Up Offer is not

accounted for in the last Day-Ahead Market make whole payment eligibility period

in the Operating Day, any remaining Day-Ahead Market Start-Up Offer costs are

Page 13 of 16

carried forward for recovery in the first Day-Ahead Market make whole payment

eligibility period of the following Operating Day.

… 8.6.5 Reliability Unit Commitment Make Whole Payment Amount

(1) Asset Owners of Resources committed by the Transmission Provider with an RTBM

Resource Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this

Attachment AE, are eligible to receive a RUC make whole payment. Asset Owners of

Resources committed by a local transmission operator to address a Local Emergency

Condition are eligible to receive a RUC make whole payment, except that, if the Market

Monitor determines such Resources were selected in a discriminatory manner by the local

transmission operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE,

and such Resources were affiliated with the local transmission operator, then such

Resources are not eligible to receive a RUC make whole payment. A RUC make whole

payment is made to the Asset Owner when the sum of a Resource’s eligible RTBM Start-

Up Offer costs, No-Load Offer costs, Energy Offer Curve and Operating Reserve Offer

costs associated with actual Energy and cleared RTBM Operating Reserve is greater than

the Energy and Operating Reserve RTBM revenues received over the Resource’s RUC

make whole payment eligibility period. Recovery of such compensation shall be collected

in accordance with Section 8.6.7 of this Attachment AE.

(2) A Resource’s RUC make whole payment eligibility period is equal to that Resource’s RUC

Commitment Period. For Resources with a RUC Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two RUC make whole payment

eligibility periods are created. The first period begins in the first Operating Day in the

Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last

Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch

Interval of the next Operating Day and ends in the Dispatch Interval associated with the

Resource’s RUC De-Commit Time.

(3) The following cost recovery rules apply to each RUC make whole payment eligibility

period. Resource production costs are calculated using the RTBM Offer prices in effect at

the time the commitment decision was made for start-up, no-load, and minimum-energy;

and the RTBM Offer price in effect at the solving of a dispatch interval for the Energy

Page 14 of 16

above minimum energy, Regulation-Up, Regulation-Down, Spinning Reserve, and

Supplemental Reserve.

(a) If the Transmission Provider cancels a Commitment Instruction prior to the start of

the associated RUC make whole payment eligibility period, the Asset Owner will

receive reimbursement for a time-based pro-rata share of the Resource’s RTBM

Start-Up Offer unless precluded by Section 8.6.5(3)(e) of this Attachment AE.

Asset Owners may request additional compensation through submittal of actual

cost documentation to the Transmission Provider. The Transmission Provider will

review the submitted documentation and confirm that the submitted information is

sufficient to document actual costs and that all or a portion of the actual costs are

eligible for recovery.

(b) In order to receive the full amount of Start-Up Offer recovery within a RUC make

whole payment eligibility period, the Resource must be a Synchronized Resource

in at least one Dispatch Interval in the RUC make whole payment eligibility period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the

RUC make whole payment eligibility period, the Resource must be a Synchronized

Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period for a

Resource in a single Operating Day. A single RUC make whole payment eligibility

period is contained within a single Operating Day.

(e) When a RUC make whole payment eligibility period is created after a Day-Ahead

make-whole payment eligibility period which is adjacent and preceding a Day-

Ahead make whole payment eligibility period where the Day-Ahead Start-Up Offer

was considered, the eligible Day-Ahead Start-up Offer is used in place of the RUC

Start-up costs:

(ef) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the

following RUC make whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period for which the RUC

SCUC did not consider the Resource’s Start-Up Offer in the

commitment decision except that RTBM Start-Up Offer costs

associated with commitments made under Sections 5.2.2(3), 5.2.2(4),

6.1.2(3) and 6.1.2(4) of Attachment AE shall be eligible for recovery; or

when the subsequent RUC make whole payment eligibility period is

Page 15 of 16

contiguous and preceding a Day-Ahead make whole payment eligibility

period where the Day-Ahead Start-Up Offer was considered, in which

case the Day-Ahead Start-Up Offer is usedthat is adjacent to the end of

a Day-Ahead Market make whole payment eligibility period;

(ii) Any RUC make whole payment eligibility period for which a Resource is a

Synchronized Resource prior to this commitment period at a time one (1)

hour prior to that Resource’s RUC Commit Time less the Resource’s Sync-

To-Min Time; andor

(iii) Any RUC make whole payment eligibility period resulting from a RUC

Commitment Period that contains an hour for which the Resource was self-

committed.

(fg) For each RUC make whole payment eligibility period within an Operating Day, a

Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s

Minimum Run Time multiplied by twelve (12), rounded down to the nearest whole

interval, or (2) twenty-four (24) hours multiplied by twelve (12), and that portion

of the Start-Up Offer is included as a cost in each interval of the RUC make whole

payment eligibility period until the sum of these interval costs are equal to the

RTBM Start-Up Offer or until the end of the RUC make whole payment eligibility

period, whichever occurs first. If the Transmission Provider cancels a start-up order

prior to the start of the associated RUC make whole payment eligibility period, all

of the eligible pro rata share of the Resource’s RTBM Start-Up Offer is allocated

into the first interval of the RUC make whole payment eligibility period.

(gh) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for

in the last RUC make whole payment eligibility period in the Operating Day, any

remaining RTBM Start-Up Offer costs are carried forward for recovery in the first

RUC make whole payment eligibility period of the following Operating Day

provided that the Resource has not been committed in the Day-Ahead Market in

any hour of the first RUC make whole payment eligibility period as described in

(h) below.

(hi) If the Resource has been committed in the Day-Ahead Market in a period adjacent

to and following a RUC make whole payment eligibility period to the extent that

the full amount of the RTBM Start-Up Offer is not accounted for in the RUC make

whole payment eligibility period, any remaining RTBM Start-Up Offer costs are

Page 16 of 16

carried forward for recovery in the Day-Ahead make whole payment eligibility

period.

(ij) If a Resource has operated outside of its Operating Tolerance in any Dispatch

Interval, any cost associated with energy output above the Resource’s economic

operating point is not eligible for recovery for that Dispatch Interval where such

cost is calculated as described under Subsection 4(c) below.

(jk) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating point is

not eligible for recovery for that Dispatch Interval where such cost is calculated as

described under Subsection 4(c) below.

(kl) If a Resource’s minimum operating limit is increased above the Resource’s

minimum operating limit that was used to make the commitment decision, the

increase is greater than the Resource’s Operating Tolerance and the Resource

remains dispatchable in any Dispatch Interval, any cost associated with energy

output above the Resource’s economic operating point is not eligible for recovery

for that Dispatch Interval where such cost is calculated as described under

Subsection 4(c) below.

…

Page 1 of 31


RR #: 129 Date: 11/4/2015

RR Title: Settlements Clean-Up


Name: Micha Bailey Company: Southwest Power Pool





This Revision Request was drafted to include various Settlement clean up items that were found in the Protocols which include deleting attributes, adding a hashtag in front of billing determinates to indicate rounding, cleaning up various definitions in the variable table, adding 5min to Real-Time Flags to indicate that those flags are 5 minutes and adding language to the Protocols that match the ER16-130 Tariff Clean-Up filing.


These changes keep the Protocols and Tariff in sync and clean up various Settlement sections.


IMPACT


If yes, please briefly explain: Note: Covered in RR29_MPRR215 and RR18_MPRR196


Explain: Note: Covered in RR29_MPRR215 and RR18_MPRR196




Market Protocols

Protocol Section(s): 4.5.8.4; 4.5.8.5; 4.5.8.6; 4.5.8.7; 4.5.8.8; 4.5.8.9; 4.5.8.10; 4.5.8.11; 4.5.8.12; 4.5.9.4; 4.5.9.5; 4.5.9.6; 4.5.9.7; 4.5.9.8; 4.5.9.9; 4.5.9.20


Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): Business Practice Business Practice Number:

Page 2 of 31



Date: 11/17/2015

Action Taken: Unanimously Approved


Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


MOPC

Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


COMMENTS

Page 3 of 31

Comment Author:



Status:

Comment Author:



Status:


Market Protocols

4.5.8.4 Day-Ahead Regulation-Up Service Amount

… (5) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices

associated with this Charge Type for each Asset Owner as follows:

(a) #EqrDaRegUpHrlyQty a, s, h = ∑z

DaRegUpHrlyQty a, z, s, h

(b) #EqrDaRegUpHrlyPrc a, s, h = ∑z

( DaRegUpMcpHrlyPrc z, h + ( DaRegUpHrlyQty a, z, s, h *

0 ))

…

4.5.8.5 Day-Ahead Regulation-Down Service Amount



(a) #EqrDaRegDnHrlyQty a, s, h = ∑z

DaRegDnHrlyQty a, z, s, h

Page 4 of 31

(b) #EqrDaRegDnHrlyPrc a, s, h = ∑z

( DaRegDnMcpHrlyPrc z, h + ( DaRegDnHrlyQty a, z, s, h

* 0 ))

… 4.5.8.6 Day-Ahead Spinning Reserve Amount



(a) #EqrDaSpinHrlyQty a, s, h = ∑z

DaSpinHrlyQty a, z, s, h

(b) #EqrDaSpinHrlyPrc a, s, h = ∑z

( DaSpinMcpHrlyPrc z, h + ( DaSpinHrlyQty a, z, s, h * 0 ))

…

4.5.8.7 Day-Ahead Supplemental Reserve Amount



(a) #EqrDaSuppHrlyQty a, s, h = ∑z

DaSuppHrlyQty a, z, s, h

(b) #EqrDaSuppHrlyPrc a, s, h = ∑z

( DaSuppMcpHrlyPrc z, h + ( DaSuppHrlyQty a, z, s, h * 0 ))

…

4.5.8.8 Day-Ahead Regulation-Up Service Distribution Amount

… (b) #DaRegUpAoObligHrlyQty a, z, h = DaRegUpSppHrlyQty h

Page 5 of 31

* (∑s

RtRegUpRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh ) - ∑t

RegUpFinHrlyQty a, z, h, t

(b.1) RtLoadSppHrlyQty h = ∑m∑

a∑

s [ Max ( 0, ∑

i RtBillMtr5minQty a, s, i )

+ Max ( 0, ∑i∑

t RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ] / 12

(b.2) DaRegUpSppHrlyQty h =∑a∑

s∑

z DaRegUpHrlyQty a, z, s, h

(b.3) #RtRegUpRznLoadHrlyQty a, z, s, h = [ Max ( 0, ∑i

RtBillMtr5minQty a, s, i )

+ Max ( 0, ∑i∑

t RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ]

* PctSlinRznRegUpHrlyFct a, z, s, h / 12

…

Variable

Unit

Settlement Interval

Definition

PctSlinRznRegUpHrlyFct a, z, s, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’sa load at Settlement Location s that is contained within Reserve Zone z for use in Regulation-Up cost allocation.

…

4.5.8.9 Day-Ahead Regulation-Down Service Distribution Amount

… (b) #DaRegDnAoObligHrlyQty a, z, h = DaRegDnSppHrlyQty h

Page 6 of 31

* (∑s

RtRegDnRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh ) - ∑t

RegDnFinHrlyQty a, z, h, t

(b.1) DaRegDnSppHrlyQty h =∑a∑

s∑

z DaRegDnHrlyQty a, s, z, h

(b.2) #RtRegDnRznLoadHrlyQty a, z, s, h = [ Max ( 0, ∑i


+ Max ( 0, ∑i∑


* PctSlinRznRegDnHrlyFct a, z, s, h / 12

…

The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

PctSlinRznRegDnHrlyFct a, z, s, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’sa load at Settlement Location s that is contained within Reserve Zone z for use in Regulation-Down cost allocation.

…

4.5.8.10 Day-Ahead Spinning Reserve Distribution Amount

… (b) #DaSpinAoObligHrlyQty a, z, h = DaSpinSppHrlyQty h

* (∑s

RtSpinRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh ) - ∑t

SpinFinHrlyQty a, z, h, t

(b.1) DaSpinSppHrlyQty h =∑a∑

s∑

z DaSpinHrlyQty a, z, s, h

Page 7 of 31

(b.2) #RtSpinRznLoadHrlyQty a, z, s, h = [ Max ( 0, ∑i


+ Max ( 0, ∑i∑


* PctSlinRznSpinHrlyFct a, z, s, h / 12

… The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

PctSlinRznSpinHrlyFct a, z, s, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’sa load at Settlement Location s that is contained within Reserve Zone z for use in Spinning Reserve cost allocation.

…

4.5.8.11 Day-Ahead Supplemental Reserve Distribution Amount

… (b) #DaSuppAoObligHrlyQty a, z, h = ( DaSuppInterAoObligHrlyQty a, z, h

* DaSuppObligRatio h ) - ∑t

SuppFinHrlyQty a, z, h, t

(b.1) DaSuppInterAoObligHrlyQty a, z, h =

Max (0, DaSuppIniAoObligHrlyQty a, z, h - ∑t

ContrSuppHrlyQty a, z, h, t )

(b.2) DaSuppIniAoObligHrlyQty a, z, h =

( DaSuppSppHrlyQty h + ContrSuppSppHrlyQtyh )

* (∑s

RtSuppRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh )

Page 8 of 31

(b.2.1) ContrSuppSppHrlyQty h =∑a∑

z∑

t ContrSuppHrlyQty a, z, h, t

(b.2.2) DaSuppSppHrlyQty h =∑a∑

s∑

z DaSuppHrlyQty a, z, s, h

(b.3) DaSuppObligRatio h = DaSuppSppHrlyQty h

/ DaSuppInterObligSppHrlyQtyh

(b.3.1) DaSuppInterObligSppHrlyQtyh =∑a∑

z DaSuppInterAoObligHrlyQty a, z, h

(b.4) #RtSuppRznLoadHrlyQty a, z, s, h = [ Max ( 0, ∑i


+ Max ( 0, ∑i∑


* PctSlinRznSuppHrlyFct a, z, s, h / 12

…

The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

PctSlinRznSuppHrlyFct a, z, s, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’sa load at Settlement Location s that is contained within Reserve Zone z for use in Supplemental Reserve cost allocation.

…

4.5.8.12 Day-Ahead Make-Whole-Payment Amount

… (4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each hour in a

given DA Market Make-Whole Payment Eligibility Period is calculated as follows:

Page 9 of 31

#DaMwpCpAmt a, s, c =

Max (0, ∑h

( DaMwpCostHrlyAmt a, h, s, c + DaMwpRevHrlyAmt a, h, s, c ) ) * (-1)

(a) #DaMwpCostHrlyAmt a, h, s, c =

DaStartUpEligHrlyFlg a, h, s, c * DaStartUpHrlyAmt a, h, s, c

+ DaClrdComStatHrlyFlg h, s, c

* [ DaRucRmndrStartUpHrlyAmt a, s, h, c + DaTransitionHrlyAmt a, s, h, c

+ DaCcSpinAdjHrlyAmt a, s, h + DaCcSuppAdjHrlyAmt a, s, h

+ DaNoLoadHrlyAmt a, h, s, c + DaIncrEnHrlyAmt a, h, s, c

+ DaRegUpAvailHrlyAmt a, h, s, + DaRegDnAvailHrlyAmt a, h, s

+ PotDaRegUpMileMwp5minAmt a, s, i

+ PotDaRegDnMileMwp5minAmt a, s, i

+ DaSpinAvailHrlyAmt a, h, s, c + DaSuppAvailHrlyAmt a, h, s, c

+ DaRegUpforCRSubAvailHrlyAmt a, s, h, c ]

Where,

#DaIncrEnHrlyAmt a, h, s, c = ∫) s h, a,yQty (DaClrdHlr ABS

0

CurveOffer Energy Market DA

(a.1) IF RtTranistionStateFlg a, s, i = 1 THEN

DaCcSpinAdj5minAmt a, s, i =

∑i

∑i


Commented [MPRR215.2]: MPRR215 Awaiting FERC Filing

Page 10 of 31

IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )

* (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i )

ELSE

DaCcSpin5minAmt a, s, h = 0

(a.1.1) DaCcSpinAdjHrlyAmt a, s, h =

Max ( 0, ∑i

DaCcSpinAdj5minAmt a, s, i )

(a.2) IF RtTranistionStateFlg a, s, i = 1 THEN

DaCcSuppAdj5minAmt a, s, i =

IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )

* (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i )

ELSE

DaCcSupp5minAmt a, s, h = 0

(a.2.1) DaCcSuppAdjHrlyAmt a, s, h =

Max ( 0, ∑i

DaCcSuppAdj5minAmt a, s, i )

(b) #DaMwpRevHrlyAmt a, h, s, c = DaClrdComStatHrlyFlg h, s, c

* [ ( DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h )

+ DaRegUpHrlyAmt a, h, s + DaRegDnHrlyAmt a, h, s

+ DaRegUpUnusedMileMwp5minAmt a, s, i ∑i


Page 11 of 31

+ DaRegDnUnusedMileMwp5minAmt a, s, i

+ DaSpinHrlyAmt a, h, s + DaSuppHrlyAmt a, h, s ]

(c) #DaRegUpAvailHrlyAmt a, h, s

= DaRegUpHrlyQty a, h, s * DaRegUpOffer a, h, s

(d) #DaRegDnAvailHrlyAmt a, h, s

= DaRegDnHrlyQty a, h, s * DaRegDnOffer a, h, s

(e) #DaSpinAvailHrlyAmt a, h, s, c

= DaOffSpinHrlyQty a, h, s * DaSpinOffer a, h, s

(f) #DaSuppAvailHrlyAmt a, h, s, c

= DaOffSuppHrlyQty a, h, s * DaSuppOffer a, h, s

(g) #DaRegUpforCRSubAvailHrlyAmt a, h, s, c

= DaRegUpforCRSubHrlyQty a, h, s * DaRegUpCapOffer a, h, s

(g.1) DaRegUpforCRSubHrlyQty a, h, s = DaOffRegUpHrlyQty a, h, s - DaRegUpHrlyQty a, s, h

…

∑i


Page 12 of 31

… Variable Unit Settlement

Interval Definition

DaRegUpAvailHrlyAmt a, h, s $ Hour Day-Ahead Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Hour - The Regulation-Up Service Offer cost, in dollars, associated with AO a’s Resource at Settlement Location s for Hour h.

DaRegUpOffer a, h, s

$/MW Dispatch IntervalHo

ur

Day-Ahead Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Regulation-Up Service Offer associated with AO a’s Resource Settlement Location s for Hour h. Note that this value will be equal to the Regulation-Up Service Offer following Order 755 implementation or the Regulation-Up Offer prior to Order 755 implementation.

DaRegUpCapOffer a, h, s

$/MW Dispatch IntervalHo

ur

Day-Ahead Regulation-Up Service Capability Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Regulation-Up Offer associated with Regulation-Up Service capability associated with AO a’s Resource Settlement Location s for Hour h.

DaRegDnOffer a, h, s $/MW Dispatch IntervalHo

ur

Day-Ahead Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Regulation-Down Service Offer associated with AO a’s Resource Settlement Location s for Hour h.

DaSpinOffer a, h, s $/MW Dispatch IntervalHo

ur

Day-Ahead Spin Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Spinning Reserve Offer associated with AO a’s Resource Settlement Location s for Hour h.





Page 13 of 31

DaSuppOffer a, h, s $/MW Dispatch IntervalHo

ur

Day-Ahead Supplemental Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s for Hour h.

DaRegUpforCRSubAvailHrlyAmt a, s, h, c $ Dispatch IntervalHo

ur

Day-Ahead Cleared Substituted Regulation-Up CapabilityService for Contingency Reserve Offer Cost Amount per AO per Settlement Location per Hour in the DA Market Make-Whole-Payment Eligibility Period – The cost of the quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the DA Market on AO a’s Resource at Settlement Location s for Hour h.

DaRegUpforCRSubHrlyQty a, s, h MW Hour Day-Ahead Cleared Substituted Regulation-Up CapabilityService for Contingency Reserve MW Amount per AO per Settlement Location per Hour – The MW amount quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the DA Market on AO a’s Resource at Settlement Location s for Hour h.

…




Page 14 of 31

4.5.9.4 Real-Time Regulation-Up Service Amount

… (6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume

in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when

Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this

Charge Type for each Asset Owner as follows:

(a) RTBM Regulation-Up Service

(a.1) #EqrRtRegUp5minQty a, s, i =

∑z

Max ( 0, ( RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h ) / 12 )

+

{ IF #EqrDaRegUpHrlyQty a, s, h > 0 THEN

∑z

Min ( 0, ( RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h ) / 12 ) }

(a.2) IF #EqrRtRegUp5minQty a, s, i < > 0

THEN

#EqrRtRegUp5minPrc a, s, i = ∑z

( RtRegUpMcp5minPrc z, i + ( RtRegUp5minQty a, z, s, i * 0 ))

(b) RTBM Excess Regulation-Up Mileage

(b.1) #EqrRtRegUpExcessMile5minQty a, s, i = RtRegUpExcessMile5minQty a, s, i / 12

(b.2) EqrRtRegUpExcessMileMcp5minPrc a, s, i =

( 0 * EqrRtRegUpExcessMile5minQty a, s, i + RtRegUpMileMcp5minPrc i )

(c) RTBM Unused Regulation-Up Mileage

(c.1) #EqrRtRegUpUnusedMile5minQty a, s, i = RtRegUpUnusedMile5minQty a, s, i

/ 12

Field Code Changed

Page 15 of 31

(c.2) EqrRtRegUpUnusedMileMcp5minPrc a, s, i =

( 0 * EqrRtRegUpUnusedMile5minQty a, s, i + RtRegUpMileMcp5minPrc i )

…

4.5.9.5 Real-Time Regulation-Down Service Amount

… (a.1) #RtRegDnUnusedMile5minQty a, s, i =

Max ( 0, ( RtRegDn5minQty a, s, i * RtRegDnMile5minFct i )

- RtRegDnMile5minQty a, s, i )

… (c) IF

RtRegDnActMile5minQty a, s, i >= ( (1 - RtRegMileOpTolPct i ) *

RtRegDnInstrMile5minQty a, s, i )

THEN

RtRegDnMile5minQty a, s, i = RtRegDnInstrMile5minQty a, s, i

ELSE

RtRegDnMile5minQty a, s, i = RtRegDnActMile5minQty a, s, i

…

(6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume




(a) RTBM Regulation-Down Service

(a.1) #EqrRtRegDn5minQty a, s, i =

Page 16 of 31

∑z

Max ( 0, ( RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h ) / 12 )

+

{ IF #EqrDaRegDnHrlyQty a, s, h > 0 THEN

∑z

Min ( 0, ( RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h ) / 12 ) }

(a.2) IF #EqrRtRegDn5minQty a, s, i < > 0

THEN

#EqrRtRegDn5minPrc a, s, i = ∑z

( RtRegDnMcp5minPrc z, i + ( RtRegDn5minQty a, z, s, i *

0 ))

(b) RTBM Excess Regulation-Down Mileage

(b.1) #EqrRtRegDnExcessMile5minQty a, s, i = RtRegDnExcessMile5minQty a, s, i / 12

(b.2) EqrRtRegDnExcessMileMcp5minPrc a, s, i =

( 0 * EqrRtRegDnExcessMile5minQty a, s, i + RtRegDnMileMcp5minPrc i )

(c) RTBM Unused Regulation-Down Mileage

(c.1) #EqrRtRegDnUnusedMile5minQty a, s, i = RtRegDnUnusedMile5minQty a, s, i / 12

(c.2) EqrRtRegDnUnusedMileMcp5minPrc a, s, i =

( 0 * EqrRtRegDnUnusedMile5minQty a, s, i + RtRegDnMileMcp5minPrc i )

…

4.5.9.6 Real-Time Spinning Reserve Amount





Field Code Changed

Page 17 of 31

(a) #EqrRtSpin5minQty a, s, i =

∑z

Max ( 0, ( RtSpin5minQty a, z, s, i - ∑z

DaSpinHrlyQty a, z, s, h ) / 12 )

+

{ IF #EqrDaSpinHrlyQty a, s, h > 0 THEN

∑z

Min ( 0, ( RtSpin5minQty a, z, s, i - ∑z

DaSpinHrlyQty a, z, s, h ) / 12 ) }

(b) IF #EqrRtSpin5minQty a, s, i < > 0

THEN

#EqrRtSpin5minPrc a, s, i = ∑z

( RtSpinMcp5minPrc z, i + ( RtSpin5minQty a, z, s, i * 0 ))

…

4.5.9.7 Real-Time Supplemental Reserve Amount





(a) #EqrRtSupp5minQty a, s, i =

∑z

Max ( 0, ( RtSupp5minQty a, z, s, i - ∑z

DaSuppHrlyQty a, z, s, h ) / 12 )

+

{ IF #EqrDaSuppHrlyQty a, s, h > 0 THEN

∑z

Min ( 0, ( RtSupp5minQty a, z, s, i - ∑z

DaSuppHrlyQty a, z, s, h ) / 12 ) }

(b) IF #EqrRtSupp5minQty a, s, i < > 0

Field Code Changed

Page 18 of 31

THEN

#EqrRtSupp5minPrc a, s, i = ∑z

( RtSuppMcp5minPrc z, i + ( RtSupp5minQty a, z, s, i * 0 ))

…

4.5.9.8 RUC Make-Whole-Payment Amount

… (4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for a given RUC

Make-Whole Payment Eligibility Period is calculated as follows:

#RtMwpCpAmt a, s, c = ( CncldStartAmt a, s, c

+ Max (0, ( { IF ( CncldStartRatio a, s, c = 0, THEN 1, ELSE 0) }

* ∑i

{ RtStartUpElig5minFlg a, s, i, c * RtStartUp5minAmt a, s, i, c

+ RtRucComStat5minFlg a, s, i, c * [ RtMwpCost5minAmt a, s, i, c

+ RtTransition5minAmt a, s, i, c + RtMwpRev5minAmt a, s, i, c

+ RtOom5minAmt a, s, i + RtRegAdj5minAmt a, s, i

– RtURDAdj5minAmt a, s, i, c – RtStatusAdj5minAmt a, s, i, c

– RtLimitAdj5minAmt a, s, i, c ] }

+∑h

( RtCcRegUpAdjHrlyAmt a, s, h, c + RtCcRegDnAdjHrlyAmt a, s, h, c

+ RtCcSpinAdjHrlyAmt a, s, h, c + RtCcSuppAdjHrlyAmt a, s, h, c ) ) ) ) * (-1)

Where,

(a) #RtMwpCost5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c *

[ { ( RtIncrEn5minAmt a, s, i

+ Max ( 0, [ RtNoLoad5minAmt a, s, i, c

Field Code Changed



Commented [RR92.14]: Awaiting Implementation

Page 19 of 31

- IF (DaClrdHrlyQty a, s, h < 0, THEN DaNoLoadHrlyAmt a, s, h, c , ELSE 0 ) ] )

+ RtMinEn5minAmt a, s, i, c

+ RtRegUpAvail5minAmt a, s, i +

RtRegDnAvail5minAmt a, s, i,

+ RtSpinAvail5minAmt a, s, i, c + RtSuppAvail5minAmt a, s, i, c

+ RtRegUpforCRSubAvail5minAmt a, s, i, c ) / 12 }

+ PotRtRegUpMileMwp5minAmt a, s, i + PotRtRegDnMileMwp5minAmt a, s, i ]

…

(a.3) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, i

THEN

#RtRegUpAvail5minAmt a, s, i =

( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h] )

* RtRegUpOffer a, s, i, )

- ( RtRegUpMileOffer5minPrc a, s, i * RtRegUpExcessMile5minQty a, s, i )

ELSE

RtRegUpAvail5minAmt a, s, i, =0

IF RtTranistionStateFlg a, s, i, c = 1 THEN

RtRegUpAvail5minAmt a, s, i, c =

∑z

DaRegUpHrlyQty a, z, s, h

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h )

ELSE

Commented [RR92.15]: RR92. Awaiting Implementation





Page 20 of 31

RtRegUpAvail5minAmt a, s, i, c = RtRegUpAvail5minAmt a, s, i = 0

(a.4) If RtRegDn5minQty a, s, i > RtFixedRegDn5minQty a, s, i

THEN

#RtRegDnAvail5minAmt a, s, i =

( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h] )

* RtRegDnOffer a, s, i, )

- ( RtRegDnMileOffer5minPrc a, s, i * RtRegDnExcessMile5minQty a, s, i )

ELSE

RtRegDnAvail5minAmt a, s, i =0

(a.5) If RtOffSpin5minQty a, s, i > RtFixedSpin5minQty a, s, i

THEN

#RtSpinAvail5minAmt a, s, i, c =

Max ( 0, [ RtOffSpin5minQty a, z, s, i - ∑z

DaOffSpinHrlyQty a, z, s, h] )

* RtSpinOffer a, s, i, c

ELSE

RtSpinAvail5minAmt a, s, i, =0

(a.6) If RtOffSupp5minQty a, s, i > RtFixedSupp5minQty a, s, c, i

THEN

#RtSuppAvail5minAmt a, s, i, c =






Page 21 of 31

Max ( 0, [ RtOffSupp5minQty a, z, s, i - ∑z

DaOffSuppHrlyQty a, z, s, h] )

* RtSuppOffer a, s, i, c

ELSE

RtSuppAvail5minAmt a, s, i, =0

(a.7) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i

THEN

#RtRegUpforCRSubAvail5minAmt a, s, i, c

= RtRegUpforCRSub5minQty a, i, s * RtRegUpCapOffer a, s, i

ELSE

RtRegUpforCRSubAvail5minAmt a, s, i, c = 0

(a.7.1) RtRegUpforCRSub5minQty a, s, i =

Max ( 0, RtOffRegUp5minQty a, i, s - RtRegUp5minQty a, i, s

- DaRegUpforCRSubHrlyQty a, h, s )

…




Page 22 of 31

Variable

Unit

Settlement Interval

Definition

RtOffSpin5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Spinning Reserve MW represented by AO a’s cleared offered Spinning Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(ii).

RtOffSupp5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Supplemental Reserve MW represented by AO a’s cleared Offered Supplemental Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4 (3)(a)(iii).

DaOffSuppHrlyQty a, s, h MW Hour Day-Ahead Cleared Offered Supplemental Reserve Quantity per AO per Settlement Location per Hour - The quantity described in Section 4.5.8.12.

RtRegUpCapOffer a, s, i

$/MW Dispatch Interval

Real-Time Regulation-Up Capability Offer per AO per Resource Settlement Location per Dispatch Interval– The Regulation-Up Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i.

DaOffSpinHrlyQty a, s, h MW Hour Day-Ahead Cleared Offered Spinning Reserve Quantity per AO per Settlement Location per Hour - The quantity described in Section 4.5.8.12.

RtOffSpin5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Spinning Reserve MW represented by AO a’s cleared offered Spinning Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(ii).





Page 23 of 31

RtOffSupp5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Supplemental Reserve MW represented by AO a’s cleared Offered Supplemental Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4 (3)(a)(iii).

RtRegUpforCRSubAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Cleared Substituted Regulation-Up for Contingency Reserve Capability Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The cost of the quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the RTBM on AO a’s Resource at Settlement Location s for Dispatch Interval i.

RtRegUpforCRSub5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Substituted Regulation-Up Capability for Contingency Reserve MW Amount per AO per Settlement Location per Dispatch Interval – The MW amount quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the RTBM on AO a’s Resource at Settlement Location s for Dispatch Interval i.

DaRegUpforCRSubHrlyQty a, h, s MW Hour Day-Ahead Cleared Substituted Regulation-Up Service Capability for Contingency Reserve MW Amount per AO per Settlement Location per Hour – The quantity described in Section 4.5.8.12.

…




Page 24 of 31

4.5.9.9 Real-Time Out-Of-Merit Amount

(1) An RTBM credit or charge1 will be made to each Market Participant with a Resource that passes a primary

Contingency Reserve deployment test as described under Section 6.1.11.1(3)(b)(i) and/or otherwise receives

a Manual Dispatch Instruction from SPP or a local transmission operator that creates a cost to the Asset Owner

or that adversely impacts the Asset Owner’s DA Market position and/or if a Market Participant must buy back

its DA Market position for any Operating Reserve product at a RTBM MCP that is greater than that product’s

DA Market MCP. Resources issued Manual Dispatch Instructions by or at the request of a local transmission

operator in order to solve a Local Emergency Condition or a Local Reliability Issue are eligible for out-of-

merit credits as defined in this Section unless selection of the Resource by the local transmission operator was

performed in a discriminatory manner as determined by the MMU and the Resource was an affiliated

Resource; however, a manual process is employed for the calculation of the out-of-merit credits and they will

appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The cost allocation of out-of-

merit credits associated with Manual Dispatch Instructions issued by or at the request of a local transmission

operator will be determined hourly by multiplying an Asset Owner’s RTBM actual load in the impacted

Settlement Area by a rate determined by dividing the daily sum of all out-of-merit credits applicable to the

impacted Settlement Area by the daily sum of all Asset Owners’ RTBM actual load in the impacted Settlement

Area. A manual process is also employed for these calculations and the charges will appear in the

Miscellaneous Amount charge type defined in Section 4.5.11. Out-of-merit credits associated with Manual

Dispatch Instructions issued directly by SPP to address a reliability issue other than a Local Reliability Issue

will be recovered under Section 4.5.12. The amount will be calculated on a Dispatch Interval basis under the

following conditions:

(a) If the Manual Dispatch Instruction is for Energy in the up direction and the Energy Offer Curve

cost associated with the Out-Of-Merit-Energy (OOME) MW is greater than the RTBM LMP, the

Asset Owner will receive a credit equal to the difference multiplied by the OOME MW. The

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

of the actual Resource output or the Resource’s Manual Dispatch Instruction MW) and (ii) the

Resource’s Desired Dispatch);

(b) If the Manual Dispatch Instruction is for Energy in the down direction, including a Resource de-

commitment 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. The OOME MW is calculated

as Max (0, or the difference between (i) the absolute value of the Resource’s DA Market cleared

Energy MW and (ii) the (greater of the absolute value of the actual Resource output or the

Resource’s Manual Dispatch Instruction MW)); and/or


Page 25 of 31

(c) If a Manual Dispatch Instruction for Energy or Operating Reserve, or a Resource de-commitment

instruction, causes the RTBM cleared amount of an Operating Reserve product to be 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 Out-Of-Merit-Operating Reserve (OOMOR) MW. The OOMOR MW is

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

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

To the extent that additional costs are incurred as a direct result of a Manual Dispatch Instruction through the

compensation mechanisms described above, Market Participants may request additional compensation through

submittal of actual cost documentation to SPP. SPP will review the submitted documentation and confirm that

the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are

eligible for recovery.

The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each Dispatch Interval

is calculated as follows:

IF RtOom5minFlg a, s, i = 1 OR ResDeCommit5minFlg a, s, i = 1 OR RtReprice5minFlg a, s, i = 1

THEN

#RtOom5minAmt a, s, i = ( RtOomeIncr5minAmt a, s, i + RtOomeDecr5minAmt a, s, i

+ RtOomor5minAmt a, s, i ) * (-1)

ELSE IF RtDeSelectOr5minFlg a, s, i = 1

THEN

#RtOom5minAmt a, s, i = RtOomor5minAmt a, s, i * (-1)

ELSE

#RtOom5minAmt a, s, i = 0

Where,

(a) RtOomeIncr5minAmt a, s, i =

Max ( 0, Max ( 0, RtOomeIncrEn5minAmt a, s, i – RtOomeDesiredEn5minAmt a, s, i ) -

Max (0, Min (Min (0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i ) - RtOomeDesiredEn5minQty a, s, i )

Commented [MPRR196.35]: MPRR196 Awaiting FERC filing



Page 26 of 31

* Max( 0, RtLmp5minPrc s, i ) ) / 12

(a.1) #RtOomeIncrEn5minAmt a, s, i = ∫y

x

CurveOffer Energy Dispatched As RTBM

Where:

X = 0 Y = Min ( Min ( 0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i )

(a.2) #RtOomeDesiredEn5minAmt a, s, i = ∫

y

x

CurveOffer Energy Dispatched As RTBM

Where:

X = 0 Y = RtOomeDesiredEn5minQtya, s, i

(b) RtOomeDecr5minAmt a, s, i =

Max (0, (-1) * Max (Min ( 0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i

) - DaClrdHrlyQty a, s, h )

* Max ( 0, RtLmp5minPrc s, i - DaLmpHrlyPrc s, h ) / 12

(c) IF RtOom5minFlg a, s, i = 1 OR ResDeCommit5minFlg a, s, i = 1 OR RtReprice5minFlg a, s, i = 1

THEN

RtOomor5minAmt a, s, i =

∑z

[ ( Max (0, ∑z

DaRegUpHrlyQty a, z, s, h - RtRegUp5minQty a, z, s, i )

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h ) )

+ ( Max (0, ∑z

DaRegDnHrlyQty a, z, s, h - RtRegDn5minQty a, z, s, i )

* Max ( 0, RtRegDnMcp5minPrc z, i - DaRegDnMcpHrlyPrc z, h ) )


Page 27 of 31

+ ( Max (0, ∑z

DaSpinHrlyQty a, z, s, h - RtSpin5minQty a, z, s, i )

* Max ( 0, RtSpinMcp5minPrc z, i - DaSpinMcpHrlyPrc z, h ) )

+ ( Max (0, ∑z

DaSuppHrlyQty a, z, s, h - RtSupp5minQty a, z, s, i )

* Max ( 0, RtSuppMcp5minPrc z, i - DaSuppMcpHrlyPrc z, h ) ) ] / 12

ELSE IF RtDeSelectOr5minFlg a, s, i = 1

THEN

RtOomor5minAmt a, s, i =

∑z

[ (( Max (0, ∑z

DaRegUpHrlyQty a, z, s, h - RtRegUp5minQty a, z, s, i )

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h ) )

* RtDeSelectRegUp5minFlg a, s, i )

+ (( Max (0, ∑z

DaRegDnHrlyQty a, z, s, h - RtRegDn5minQty a, z, s, i )

* Max ( 0, RtRegDnMcp5minPrc z, i - DaRegDnMcpHrlyPrc z, h ) )

* RtDeSelectRegDn5minFlg a, s, i )

+ (( Max (0, ∑z

DaSpinHrlyQty a, z, s, h - RtSpin5minQty a, z, s, i )

* Max ( 0, RtSpinMcp5minPrc z, i - DaSpinMcpHrlyPrc z, h ) )

* RtDeSelectSpin5minFlg a, s, i )

+ (( Max (0, ∑z

DaSuppHrlyQty a, z, s, h - RtSupp5minQty a, z, s, i )

* Max ( 0, RtSuppMcp5minPrc z, i - DaSuppMcpHrlyPrc z, h ) )

* RtDeSelectSupp5minFlg a, s, i )] / 12 Commented [MPRR196.39]: MPRR196 Awaiting FERC filing

Page 28 of 31

…

Page 29 of 31

Variable

Unit

Settlement Interval

Definition

RtDeSelectOr5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Operating Reverse Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever a Manual Dispatch Instruction is sent to deselect a Resource for Operating Reserve that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

RtDeSelectRegUp5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Regulation-Up Service Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever a Manual Dispatch Instruction is sent to deselect a Resource for Regulation-Up Service that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

RtDeSelectRegDn5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Regulation-Down Service Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever a Manual Dispatch Instruction is sent to deselect a Resource for Regulation-Down Service that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

RtDeSelectSpin5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Spinning Reserve Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever a Manual Dispatch Instruction is sent to deselect a Resource for Spinning Reserve that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

RtDeSelectSupp5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Supplemental Reverse Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever a Manual Dispatch Instruction is sent to deselect a Resource for Supplemental Reserve that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

…






Page 30 of 31

4.5.9.20 Over-Collected Losses Distribution Amount

(1) The Marginal Losses Component of the Day-Ahead Market LMP and RTBM LMP that results from

the economic market solution which considers the cost of marginal losses, congestion costs and

incremental Energy costs creates an over collection (or under collection as a result of the Real-Time

deviation accounting) related to payment for losses (“ Over-Collected Losses”) that must be accounted

for. A credit or charge is calculated for each hour at each Settlement Location for which an Asset

Owner has a net RTBM Energy withdrawal in a Loss Pool that contributed positively to the over

collection or under collection or paid a charge for Real-Time Pseudo-Tie Losses at the Settlement

Location of the Sink of the Pseudo-Tie path for use of the SPP Transmission system. Each Loss Pool’s

contribution to the Over-Collected Losses is calculated based upon the Settlement Locations contained

within the Loss Pool. There are two types of Loss Pools: (a) Loss Pools defined by all Settlement

Locations within a Settlement Area (“Settlement Area Loss Pool”); and (b) a single Loss Pool defined

by all Hub and External Interface Settlement Locations (“System-Wide Loss Pool”).

Injection/withdrawal amounts associated with Settlement Locations spanning multiple Settlement

Area Loss Pools are allocated pro rata using the billable metering values submitted at the associated

Meter Data Submittal Locations. A loss rebate factor is calculated for each withdrawal Settlement

Location as the sum of i) the difference between the Marginal Loss Component at a withdrawal

Settlement Location and the injection weighted average Marginal Loss Component for the Loss Pool,

multiplied by the net RTBM Energy withdrawal at that Settlement Location and ii) the sum of charges

for Real-Time Pseudo-Tie Losses at the Settlement Location of the Sink of the pseudo-tie path. The

injection weighted average MLC for the Loss Pool is calculated assuming that injection in the Loss

Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools

which do not have sufficient injection to meet all withdrawal. The sum of the Settlement Location

loss rebate factors (positive value only, negative values are ignored) is a measure of that Loss Pool’s

payment for losses on a marginal basis. The Loss Pool sum of the Settlement Location loss rebate

factors are then normalized to allocate a pro-rata portion of the total over collection or under collection

in the hour to each Loss Pool. Within a Loss Pool, each Asset Owner is allocated a portion of the Loss

Pool subtotal at each Settlement Location based on a ratio share of its net RTBM Energy withdrawal

to that of the Loss Pool in total. Asset Owners with GFA Carve Out energy transactions are not

qualified to receive loss rebates associated with the GFA Carve Out transactions to the extent of load

it serves under GFA Carve Out Schedule(s). Western-UGP with FSE energy transactions are not

qualified to receive loss rebates associated with the FSE transactions to the extent of load it serves

under an FSE Schedule(s). The amount is calculated as follows:

… SPP Tariff (OATT)

Page 31 of 31

SPP Criteria


Page 1 of 5


RR #: 130 Date: 11/5/2015

RR Title: Commitment Notification Enhancement


Name: Casey Cathey on behalf of SPP Company: Southwest Power Pool

Email: [email protected] Phone: 501-614-3267




Currently SPP Resource commitments are confirmed by the Market Participant’s system. A timestamp of receipt log is maintained by SPP in order to provide assurance that a Market Participant received all SPP Resource commitment start-up and shut-down notifications.

There is a gap in the current process where a Market Participant’s system provides a timestamp of receipt, however the operator does not receive the commitment instruction. This Revision Request will address this gap by requiring a manual acknowledgement via the Markets User Interface or Automatic Programmable Interface to confirm the notifications were received and ensuring the operator receives the commitment instruction. SPP will follow-up with a phone call if the commitment instruction is not manually confirmed.

The additional Protocols language below explicitly states that Resource starts by the SPP RTO shall be confirmed. In the event a confirmation is not received, SPP will follow-up with a phone call.


Increased quality of the Reliability Coordination and Balancing Authority functions by ensuring Resource Commitments are received by Operators.


IMPACT


If yes, briefly explain:


If system/process impacts but no assessment is performed, please explain:




Page 2 of 5


Market Protocols Protocol Section(s): 4.2.6.3, 4.3.2.4, 4.4.1.4


Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): Business Practice Business Practice Number:



Date: 11/17/2015


Abstained: WR

Opposed: OPPD

Reason for Opposition:


Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:



Date:

Action Taken:

Abstained:

Opposed:


MOPC

Date:

Action Taken:

Abstained:

Opposed:


Page 3 of 5


Date:

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author:



Status:

Comment Author:



Status:


Market Protocols

4.2.6.3 Multi-Day Reliability Assessment Results

SPP staff communicates these start-up orders to the affected Market Participants. At the time of this

notification, the submitted Offers become binding and the selected Resource(s) Offers are included in the

DA Market with a Commitment Status similar to Self-commit. SPP confirms receipt of start-up and shut-

down orders for all Resource commitments. In the event a confirmation is not received, SPP will follow-

up with a phone call. Unlike Self-Committed Resources, however, the Multi-day Reliability Assessment

committed Resources will be eligible for DA Market make-whole payment guarantees as described under

Section 4.5.8.12. Resources committed out of the Multi-Day Reliability Assessment during Conservative

Operations as described under Section 4.2.6.2 (5) may only be de-committed by SPP to address

Emergency conditions consistent with Sections 4.3.2.4 and 4.4.1.4.

4.3.2.4 Update Current Operating Plan

Using the results from the Day-Ahead RUC analysis, SPP will update the Current Operating Plan and will issue start-up and shut-down orders to Resources other than DVERs and NDVERs for which SPP is calculating an output forecast (these Resources are always assumed to be self-committed if available) as appropriate. SPP confirms receipt of start-up and shut-down orders for all Resource commitments. In


Page 4 of 5

the event a confirmation is not received, SPP will follow-up with a phone call. SPP can only de-commit DA Market committed Resources or move a DA Market committed combined cycle Resource that has been registered to submit configuration based offers as described under Section 4.2.2.5.3(4) into a lower configuration to address an anticipated excess supply condition as described under Section 4.3.2.2(3)(b) and/or to address any other Emergency conditions. If SPP de-commits an SPP committed Resource or moves a combined cycle Resource into a lower configuration for any hour of the DA Market commitment schedule, and causes that Resource to buy back its Energy and/or Operating Reserve position at RTBM prices that exceed the DA Market prices for the comparable products, then that Resource is eligible for compensation under Section 4.5.9.9.

4.4.1.4 Update Current Operating Plan

Using the results from the Intra-Day RUC analysis, SPP will update the Current Operating Plan and will

issue start-up and shut-down orders to Resources other than DVERs and NDVERs for which SPP is

calculating an output forecast (these Resources are always assumed to be self-committed if available) as

appropriate. SPP confirms receipt of start-up and shut-down orders for all Resource commitments. In

the event a confirmation is not received, SPP will follow-up with a phone call. SPP may only issue

changes to shut-down orders issued as part of the DA Market results or move a DA Market committed

combined cycle Resource that has been registered to submit configuration based offers as described

under Section 4.2.2.5.3(4) into a lower configuration to address an anticipated excess supply condition

as described under Section 4.3.2.2(3)(b) and/or to address any other Emergency conditions. If SPP de-

commits an SPP committed Resource or moves a combined cycle Resource into a lower configuration

for any hour of the DA Market commitment schedule, and causes that Resource to buy back its Energy

and/or Operating Reserve position at RTBM prices that exceed the DA Market prices for the comparable

products, that Resource is eligible for compensation under Section 4.5.9.9.

SPP Tariff (OATT)

NA

SPP Criteria

NA


NA






Page 5 of 5

SERs - SPP Market Preliminary Benefits Analysis

Market Support11/13/2015

Background

3

• Interest in SPP’s Regulation Market from Stored Energy Resources (SERs)

• SERs participate in other markets (PJM and MISO)

• Other markets have reported benefits from these type of Resources, specifically batteries

• SPP is in discussions with the battery developers and other markets to investigate incorporating a market design that would maximize the mutual benefits between SPP as a Market and BA and the battery owners

What’s in it for SPP?

4

• Potential Regulation Requirement reduction due to quicker Regulation response from batteries

• Possible reduction in commitment cost

• Potential reduction in Market’s Regulation cost: Batteries may not participate in Energy and thus the MCP of the Resource may not include any Loss of Opportunity Cost (LOC) related to Energy

– Approximately 50% of today’s Reg MCP is due to the LOC of the marginal Resource

• SERs can smooth out ramping events for VERs which could further decrease the amount of Regulation needed at any time

What’s in it for the SER’s

• Regulation Performance driven compensation– On average, about 75MWMile is instructed every 5-

minutes for each Reg-Up and Reg-Dn

– Batteries can respond to the instructed Regulation and are compensated upon the Resource’s response to the instructions at the Regulation Mileage MCP Good ramp rate profile means fast response to the Regulation

instructions

5

Current Design Challenges

• Modeling the characteristics of these Resource types in AGC and the Market – Control the clearing and deployment of these Resources

– Managing the Energy Neutrality of these Resources

– Visibility into the state of these Resources (charge and discharge)

• Pricing the Regulation for these Resources differently due to no qualification for Energy

• Accounting for Resource’s Energy losses into the settlement

6

SPP’s Early Stance

• Current system can handle these Resources under different Resource types (DDR, BDR) with some benefit to SPP and batteries; however

• To realize maximized, full benefit potential to both SPP and batteries, design and protocol changes are required

– Regulation Selection, clearing and deployment changes

– Registration requirement changes

– Real-Time visibility and awareness of these Resources’ status is a must from BA standpoint

7

Action Item #241 Public and Private Data

Micha [email protected]


Action Item #241

SPP staff to provide a list of data posted by SPP, both publicly and privately, for discussion on what additional data MPs would like to see posted. In addition, staff will review Market-to-Market business processes and determine what components can be documented and publicly posted.

2

Action Item #241 - Public

• For Market side public data:– SPP Markets Public Data Guide and Sample Files

http://www.spp.org/spp-documents-filings/?id=21074

– The files are located on the SPP Marketplace Portal: https://marketplace.spp.org/web/guest/public-information

• For Settlement side public data:– The public files are located at the link below:

https://marketplace.spp.org/web/guest/settlements1

– Click on “Reports” tab

3

http://www.spp.org/spp-documents-filings/?id=21074

https://marketplace.spp.org/web/guest/public-information

https://marketplace.spp.org/web/guest/settlements1

Action Item #241 - Private

• Private Data

• Data access is limited– Settlement Reports

– Transmission Owner Reports

– Asset Owner Report for modeling

– Meter Agent Report for modeling

– Credit Limit Information

– Settlement Meter Data

4

Action Item #241 – M2M• M2M Public Data

– Seams Steering Committee Meeting Materials http://www.spp.org/organizational-groups/board-of-

directorsmembers-committee/markets-and-operations-policy-committee/seams-steering-committee/

– Binding Constraints and Shadow Prices https://marketplace.spp.org/web/guest/real-time-balancing-

market

• Other M2M Public Data– M2M Permanent Flowgate List– Allocations of SPP Flowgates– FFE on M2M Flowgates

https://marketplace.spp.org/web/guest/market-to-market

5

http://www.spp.org/organizational-groups/board-of-directorsmembers-committee/markets-and-operations-policy-committee/seams-steering-committee/

https://marketplace.spp.org/web/guest/real-time-balancing-market

https://marketplace.spp.org/web/guest/market-to-market

Action Item #242 Safety Net Offer Cap

Micha [email protected]


Action Item #242

Mitigated Offer Task Force will evaluate options for SPP Marketplace design in regards to handling extreme price variation days due to fuel cost spikes or other situations. Specifically evaluating the need for a Safety Net Offer Cap (or not) in Marketplace.

This item was put on hold until after FERC ruled on PJM Waiver - ER14-1144

2

Action Item #242 – PJM Waiver

• …to permit Generation Capacity Resource sellers that submit cost-based offers in PJM’s energy markets but would be barred by the $1,000/MWh offer cap from including all legitimate costs in their offers, to recover those legitimate costs that are in excess of the applicable clearing price…

• …effective tomorrow, January 24, 2014...that it be effective only through March 31, 2014

3

Action Item #242

• PJM Offer Cap Waiver Timeline:– PJM submitted Request for Waiver and Expedited

Commission Action 1/23/2014 (ER14-1144)

– FERC granted waiver 1/24/2014

– Protests and Motion to Intervene followed

– Request for Rehearing followed

– FERC Order on Rehearing issued 10/21/2014

– PJM Industrial Customers appealed FERC’s granting of the waiver to the DC Circuit on 2/4/2015

4

Action Item #242

• Review of the DC Circuit case

• Petitioners moved to dismiss the case 8/11/2015

• Court granted dismissal 8/14/2015

5

SPP Response to MWG Action Item 276 MWG Action Item 276: SPP staff to perform analysis of SPP Registration and Onboarding Processes to determine where opportunity for increases process efficiency may exist and report back to MWG during the August and September timeframe. SPP Response: SPP completed the requested analysis of the SPP Registration and Market Participant (MP) Onboarding Processes to determine where opportunity for increased process efficiency may exist. The results of the analyses indicate that recently implemented enhancements from recent LEAN Projects have helped to increase the efficiency and effectiveness of these processes and additional improvements are expected to continue in the future as other identified enhancements are fully implemented. Additionally, the analysis also identified that the timeframes used for implementing and performing Market Registrations and MP Onboarding activities are considered optimum and appropriate to accommodate the collaborative activities that SPP performs with both existing and perspective Market Participants. After implementing enhancements, SPP was able to make the SPP Model Update process run more smoothly and efficiently as well as effectively with less internal model implementation or data issues. However, we were not able to identify any general opportunity to specifically reduce the timelines for SPP Registration and Onboarding activities. Factors that affect the timeline include the following (Note - the factors apply to all MP Onboarding activities); 1. The time needed to secure, review, and approve all required registration and certification

documentation and information needed to register and model a new MP and/or a MP’s assets, 2. The time needed to completely setup a MP in all applicable SPP models, tools, etc., 3. The need to implement, review, and validate model data and changes in our lower

environments and test before going to the Quality Assurance (QA) environment, 4. The time needed for an MP to successfully complete all required training and testing

activities. 5. The need to implement, review, and validate model data and changes in our QA

environment and test before going to the Production (PROD), 6. The time needed to implement, review, and validate model data and changes in PROD It was also determined that due to the need to model and adequately test in the lower environments (MTE and QA), pushing model data to production environments earlier than seven days in advance of the production effective date is not feasible without also moving registration data submission deadlines. This would result in changes to the current registration and MP Onboarding timelines. Although the current timeframes used for implementing and performing Market Registration and MP Onboarding activities are considered optimum and appropriate, it is noted that it may be possible to consider implementing a specific type change in about 90 days instead of a 4-month timeline. This situation is for when an existing Financial Only MP requests to become an Asset Owning MP under specific conditions. (See the third paragraph under the “Discussed Registration and Onboarding Processes with Applicable SPP Management” section for details.

SPP Registration and Onboarding Processes Analysis Results SPP performed the activities to analyze the SPP Registration and Onboarding Processes 1. Reviewed Current Registration and Onboarding Processes including recent process

evaluations covered by applicable LEAN Process and other activities 2. Discussed Registration and Onboarding Processes for possible enhancement with applicable

SPP Management personnel 3. Researched and reviewed available Registration and Onboarding process information from

other entities with Energy Markets Reviewed Current Registration and Onboarding Processes including recent process evaluations covered by applicable LEAN Process and other activities

Issues identified during LEAN activities MP Related

1) Time lapses between gaining access to Modeling Tool and creating projects 2) Reluctance to use Modeling Tool for registration changes 3) Knowledge/Understanding of how to use Modeling Tool 4) Submission of inaccurate or incomplete registration data on the deadline date 5) Delays in updating and finalizing documentations; i.e., MP Agreements, MA Agreements 6) Delays in securing required registration/technical information from Market Participants 7) Delays in coordinating requested changes with applicable TOPs/Settlement Areas

SPP Related

1) Rework of registration changes at hand-off between Model Coordination and Commercial/Network Modelers

2) Timeline accounts for “pre-work” which allows time to finalize registration information 3) Model Tool can be cumbersome if not used on a regular basis 4) Hand-off of registration data from Model Coordination to other downstream systems not

efficient 5) Reliability Input Deadlines are late in month requiring delayed modeling to coordinate

Commercial and Network Modeling As part of the LEAN process we developed four project teams to address the following issues:

• Process Efficiency • Automation/Consolidation • SPP Policy/Procedure • Training and Education

Steps taken to enhance the Model Update process

1) Developed User Guides and Quick Reference Guides for Modeling Tool 2) Enhanced training documentation 3) Enhanced Model Coordination processes to improve distribution of registration data 4) Developed RR to allow SPP to deny a registration change if all required information is

not provided by deadline

Discussed Registration and Onboarding Processes with Applicable SPP Management

SPP’s MP Onboarding process and activities are coordinated by SPP Customer Relations via the SPP Onboarding Specialist (Karen Johnson) in this group working with the Model Coordination group and other SPP personnel. Model Coordination contacted Russell Quattlebaum, Manager of SPP Customer Relations and the Onboarding Specialist and asked if they could identify any possible opportunity where for increases in process efficiency may exist especially in regards to reducing MP Onboarding timelines. Both indicated that recent and past review activities had helped to identify and implement enhancements to the process; however, the timelines were found to be optimum and appropriate for the level of activities that needed to be performed and completed by SPP and the new MPs.

Many of the Registration and MP Onboarding modeling activities are performed by SPP engineers responsible for the Commercial Models. Model Coordination contacted Casey Cathey, the former Manager for these engineers, and asked if he could identify any possible opportunity to increase process efficiency especially in regards to reducing Registration and MP Onboarding timelines. Casey indicated that he had previously researched this issue and concluded that if it were necessary, only for a situation where an existing Financial Only (FO) MP requested to become an Asset Owning (AO) MP, it may be possible to accomplish this type change in about 90 days instead of four months; however, changes must occur during MP Onboarding cycles.

However, specific criteria would apply including 1) all required completed documentation and information must be provided to SPP at least 90 days prior to scheduled MP Onboarding cycle in which the change would be implemented, 2) the FO MP must have a relationship with an existing AO MP, 3) the existing related AO MP must act as the Market Agent for the asset of the new AO MP, 4) new AO MP must use the communications systems (ICCP, XML, etc.) of the existing related MP, 5) the personnel for the existing AO MP must perform and or assist in all training, testing, and PROD activities for the new AO MP. (Note attestations may be used for training, if applicable.)

Research & Review of Registration and MP Onboarding Processes of other Entities

Model Coordination personnel reviewed the Registration and MP Onboarding/Addition processes for several entities with Energy Markets including MISO and ERCOT. Although the processes for these entities allowed for the addition of new MP in a shorter timeframe that SPP the level of interaction and collaboration provided by these entities was less than that of SPP. Specifically, SPP is highly collaborative in working with new MPs from the start of the process including preliminary activities through final activities when the MP becomes effective in PROD. However, the other entities require that all preliminary activities and the final version of the required documentation be completed by the new MP prior to submitting a new MP or it will be rejected. The new MP could also be rejected at other points in the process. SPP works to insure the new MP successfully completes the MP Onboarding process.

SPP October 2015 Marketplace Update

November 18, 2015 Market Monitoring Unit

Overview • LMPs and MCPs

• Summary of Scarcity Events

• DA Market Participation

• Make Whole Payments, OCL, M2M and RNU

• Congestion

• TCR Funding

• Day Ahead vs. Real Time Wind

• Mitigation

2

October Highlights

3

• Low Gas Prices

• Wind Very Volatile (Penetration Record)

• High Volume of OOMEs again this Month

• Several M2M Events

• Uptick in DA MWPs

• VMA Constraint Example

Monthly Average LMPs

4

0

2

4

6

0

5

10

15

20

25

30

35

40

$/M

MBT

U

$/M

WH

SPP NORTH HUB

DA LMP RT LMP Panhandle

0

2

4

6

0

5

10

15

20

25

30

35

40

$/M

MBT

U

$/M

WH

SPP SOUTH HUB

DA LMP RT LMP Panhandle

5

Loca

tiona

l Mar

gina

l Pric

e ($

/MW

h)

Daily Average SPP Hub Energy Prices October 2015

SPPNORTH_HUB - DAMKT SPPNORTH_HUB - RTBM SPPSOUTH_HUB - DAMKT SPPSOUTH_HUB - RTBM

Monthly Average RTBM Regulation Prices

6

$0

$6

$12

$18

$24

Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 Jul 15 Aug 15 Sep 15 Oct 15

$/M

Wh

Regulation Up

Reg Up RT Reg Up DA Reg Up Milage RT

$0

$6

$12

$18

$24


$/M

Wh

Regulation Down

Reg Down RT Reg Down DA Reg Down Milage RT

Regulation Mileage MWPs

7

0

0.2

0.4

0.6

0.8

1

1.2 $(400.00)

$(350.00)

$(300.00)

$(250.00)

$(200.00)

$(150.00)

$(100.00)

$(50.00)

$-MARCH APRIL MAY JUNE JULY AUGUST SEPTEMBER OCTOBER

2015

Thou

sand

s

Regulation Up Mileage MWPs

DaRegUpUnusedMileMwp5minAmt RtRegUpUnusedMileMwp5minAmt RtRegUpMile5minFct

Mileage Factor

0

0.2

0.4

0.6

0.8

1

1.2 $(400.00) $(350.00) $(300.00) $(250.00) $(200.00) $(150.00) $(100.00)

$(50.00) $-

MARCH APRIL MAY JUNE JULY AUGUST SEPTEMBER OCTOBER

2015

Thou

sand

s

Regulation Down Mileage MWPs

DaRegDnUnusedMileMwp5minAmt RtRegDnUnusedMileMwp5minAmt RtRegDnMile5minFct

Mileage Factor

8

0

2

4

6

8

10

12

14

Mar

ket C

lear

ing

Pric

e ($

/MW

) Daily Average SPP Regulation Up MCPs

October 2015

DAMKT RTBM

9

0

5

10

15

20

25

30

35

40

Mar

ket C

lear

ing

Pric

e ($

/MW

) Daily Average SPP Regulation Down MCPs

October 2015

DAMKT RTBM

Monthly Average RTBM OR Prices

10

$0

$2

$4

$6

$8

$10

$12


$/M

Wh

Spinning Reserves

Zone 1 DA Zone 1 RT Zone 2 DA Zone 2 RT Zone 3 DA Zone 3 RT Zone 4 DA Zone 4 RT

Monthly Average RTBM OR Prices

11

$0

$2

$4

$6


$/M

Wh

Supplemental Reserves

Zone 1 DA Zone 1 RT Zone 2 DA Zone 2 RT Zone 3 DA Zone 3 RT Zone 4 DA Zone 4 RT

12

$0

$1

$2

$3

$4

$5

$6

Mar

ket C

lear

ing

Pric

e ($

/MW

) Daily Average SPP Spinning Reserve MCPs

October 2015

DAMKT RTBM

13

$0

$2

$4

$6

$8

$10

$12

$14

Mar

ket C

lear

ing

Pric

e ($

/MW

) Daily Average SPP Supplemental Reserve MCPs

October 2015

SPP - DAMKT SPP - RTBM

14

$-

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

0

2

4

6

8

10

12

14

16

18

20

Aver

age

Syst

em M

argi

nal P

rice

($/M

Wh)

Coun

t of 5

Min

ute

Mar

ket I

nter

vals

RTBM Scarcity and Ramp Events October 2015

OR Scarcity REG Up Scarcity REG Dn Scarcity Spin Scarcity OR Ramp Scarcity Reg Down Ramp Scarcity Avg. SMP

Note : Where both capacity and ramp scarcity exist in the same interval, only the capacity scarcity is shown.

Average Hourly Load Participation in DA Market

15

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

101%

Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15

Cleared Demand as a Percent of Reported Load -Off Peak Cleared Demand as a Percent of Reported Load-On Peak

Virtual Participation in Marketplace

16

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15

Cleared Virtual Bids as Percent of Report Load Cleared Virtual Offers as Percent of Report Load

Virtual Participation – Hourly Volume

17

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

3,000

Aver

age

Hour

ly V

olum

e (M

Wh)

Hourly Average Uncleared Virtual Bids Hourly Average Cleared Virtual Bids Hourly Average Uncleared Virtual Offers Hourly Average Cleared Virtual Offers

Virtual Activity by Settlement Location Type

18

$(2,000)

$(1,500)

$(1,000)

$(500)

$-

$500Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct

2014 2015

Thou

sand

s

Virutal's Net Profit/LOSS by Location Type (negative is profit)

Hub Interface Load Resource

0

100

200

300

400

500

600

700

800

900

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

2014 2015

Thou

sand

s

Cleared Virtuals MWS by Location Type (sum of bids and offers)

Hub Interface Load Resource

Make Whole Payments

19

$0

$3

$6

$9

Oct14

Nov14

Dec14

Jan15

Feb15

Mar15

Apr15

May15

Jun15

Jul15

Aug15

Sep15

Oct15

Mil

lion

s

Day-Ahead

Nuclear Wind Renewable HydroCoal Gas-CC Gas-SC Other

$0

$3

$6

$9

Oct14

Nov14

Dec14

Jan15

Feb15

Mar15

Apr15

May15

Jun15

Jul15

Aug15

Sep15

Oct15

Mil

lion

s

RUC (Real-Time)

Nuclear Wind Renewable HydroCoal Gas-CC Gas-SC Other

Revenue Neutrality Uplift

20

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

May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15DA Revenue Inadequacy 7$ (23)$ (8)$ 122$ 96$ (62)$ RT Revenue Inadequacy 41,228$ 39,056$ 27,329$ 5,694$ 61,037$ 62,253$ OOME MWP 14,873$ 41,017$ 7,370$ 131,161$ 16,311$ 124,840$ RT Regulation Deployment Adj 43,602$ 48,115$ 127,207$ 61,899$ 52,316$ 42,466$ RT JOA (1,644,821)$ 253,548$ (56,516)$ 216,667$ (378,203)$ 584,928$ RT Congestion 3,051,571$ 1,517,937$ 2,250,633$ 1,934,581$ 1,908,145$ 3,365,872$ Sub-Total 1,506,460$ 1,899,650$ 2,356,015$ 2,350,124$ 1,659,702$ 4,180,297$ Less RT Net Inadvertent (551,902)$ (675,267)$ (1,065,726)$ (554,497)$ (287,206)$ (711,653)$ RNU * 2,058,362$ 2,574,917$ 3,421,741$ 2,904,621$ 1,946,908$ 4,891,950$

21

$(250)

$(200)

$(150)

$(100)

$(50)

$-Apr May Jun Jul Aug Sep Oct

2015

Thou

sand

s

Real Time OCL Payments by Settlement Location Type

Hub Interface Resource

$112,316.41

$285.15

$95,792.95

$(486,076.16)

$(209,809.09)

$74,623.29

$(111,455.65)

$45,794.34

$(75,859.52)

$149,643.84

$(79,431.47)

$(600,000)

$(500,000)

$(400,000)

$(300,000)

$(200,000)

$(100,000)

$-

$100,000

$200,000

Daily Net + MISO to SPP / - SPP to MISO

TEMP82_20951

TMP100_21136/ TEMP49_21150

TEMP49_21150

-$584,928.34

Market to Market Payments to SPP for October 2015

22

23

$330,212 $295,790

$103,622

$71,391 $56,417

$43,210 $28,476 $26,981 $25,592 $18,408 $11,390

-$1,084 -$5,919 -$28,425

-$63,226 -$70,318

-$96,782 -$107,862

-$142,648

-$160,539

-$376,458

-$543,157 -$600,000

-$500,000

-$400,000

-$300,000

-$200,000

-$100,000

$0

$100,000

$200,000

$300,000

$400,000

M2M by Constraint for October 2015 (Positive Payments to MISO, Negative to SPP)

October Off-Peak LMPs

24

WDWFPLATNOW

TEMP144_21263

NEORIVNEOBLC

October On-Peak LMPs

25

TMP168_21247

NEORIVNEOBLC

TEMP144_21263

BULMIDBUFNOR

Flowgate information can be found at https://www.oasis.oati.com/SWPP/index.html (look under “Transmission” Folder> “Flowgates”>Permanent Flowgates /Temporary Flowgates )

Flowgate Descriptions

26

Flowgates

WDWFPLTATNOW Woodward-FPL Switch 138kV ftlo Tatonga-Northwest 345kV (OKGE)

TMP168_21247-LN KNOLL1 - REDLIN 115 kV (WR)

TEMP49_21150-LN RUGBY230 - RUGBY 115 kV(WAUE)

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

TMP144_21263-LN CHAR_CK - RGHDRD 115 kV(WAUE)

BULMIDBUFNOR [MISO, M2M] Bull Shoals (SPA) – Midway (EES) 161kV ftlo Buford-Norfork (SPA) 161kV

TEMP56_21085 LN TUCO - LUBBOCKE 115 kV (SPS)

OSGCANBUSDEA Osage Switch-Canyon East 115kV ftlo Bushland - Deaf Smith 230kV (SPS)

SHAHAYKNOXFR South Hays-Hays 115kV ftlo Knoll Xfmr 345/115kV (MIDW) OSEWILSANSHE [M2M] Oseola-Wilson 161kV ftlo Sans Souci-Shelby 500kV (MISO_S)

https://www.oasis.oati.com/SWPP/index.html

https://www.oasis.oati.com/SWPP/SWPPdocs/Permanent_flowgates.xls

https://www.oasis.oati.com/SWPP/SWPPdocs/Posting_MasterTempFG.xls

https://www.oasis.oati.com/SWPP/SWPPdocs/Posting_MasterTempFG.xls

27

0

10

20

30

40

50

60

70

October Top 10 RT Breached/Bound Flowgates

by Shadow Price

RTBM DAMKT

28

-20%

-10%

0%

10%

20%

30%

40%

50%

60%

October Flowgates Impacts on RUC MWPS Negative is a Net Reduction on MWPs

October RUC Starts

29

($0.50)

($0.25)

$0.00

$0.25

$0.50

$0.75

$1.00

$1.25

Mill

ions

DA_REVENUE TCR_FUNDING SURPLUS_SHORTFALL

TEMP168_21247

October TCR Summary

30

WDWFPLTATNOW/TEMP56_21085

0%

20%

40%

60%

80%

100%

120%

$(10.00)

$-

$10.00

$20.00

$30.00

$40.00

$50.00

Mill

ions

DA_REVENUE TCR_FUNDING SURPLUS_SHORTFALL

FUNDING_PERCENT CUMULATIVE_PERCENT

TCR Summary by Month

31

99.0% Cumulative Funding

100%

105%

110%

115%

120%

125%

130%

135%

$-

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

Mill

ions

TCR_REVENUE ARR_FUNDING SURPLUS_SHORTFALL

FUNDING_PERCENT CUMULATIVE_PERCENT

ARR Summary by Month

32

125% Cumulative Funding

33

-10000

10000

30000

50000

70000

90000

110000

130000

DA Wind Cleared MW plus CLR Virtual Offers Vs RT Wind Generation October 2015

DAWND_PLUS_CLR_VRT_OFF RT_MW

34

0

1000

2000

3000

4000

5000

6000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA Wind Generation plus CLR Virtual Offers Vs RT Wind Generation October 2015

DAWND_PLUS_CLR_VRT_OFF RT_MW RT_MW

35

0

2

4

6

8

10

12

14

16

10/1/2014 11/1/2014 12/1/2014 1/1/2015 2/1/2015 3/1/2015 4/1/2015 5/1/2015 6/1/2015 7/1/2015 8/1/2015 9/1/2015 10/1/2015

Percent Mitigated Resource Starts by Commit Reason

DA MANUAL RUC

VMA CONSTRAINT EXAMPLE

Usual case

37

~ Generator

Step up transformer

Transmission lines

Load

RTBM with a line outage

38

~

DA Market (not anticipating outage)

39

~

Savvy Investor knows about outage and offers at lower price.

Investor also bids at higher price.

DA activates this GSU as a VMA constraint because virtual offers exceed the physical limit.

QUESTIONS? [email protected]

40

November MWG – Marketplace Update

• Regulation Performance

• Congestion Overview

• RUC Update

• Pricing

• Load Forecast accuracy

– Weather/Load forecast relationship

• Wind forecast accuracy

• DAMKT Update

• Appendix

2

REGULATION PERFORMANCESection 1

3

Notes1. Calculation expects resources to simultaneously drive towards their energy, CR and

regulation setpoints.

a. Expected setpoints are derived from RTGen setpoints that are ramped over the respective time periodsi. 5 minutes for energy

ii. 10 minutes for CR

iii. 4 seconds for regulation

2. Performance calculation is the same method used for mileage calculation.

3. % Score is: Regulation Response / Expected Regulation Setpoint.a. 75 cycle scores is rolled up into a 5 minute averaged score as long as they cycle is holding a deployment. Each deployment that

forces s start from 0MW or turns around is a given 3 cycle grace period before expected reg SP and scoring starts. If MW values received by SPP do not refresh every cycle, then the MW is interpolated.

b. 5 minute scores are rolled up into an weighted hourly averaged score. Weight is based on ExpectedRegulation5MinuteSum.

c. Hourly scores are rolled up into a monthly averaged score.

d. Resources that received deployment instructions for a minimum of 2,250 4-second intervals were included in each Regulation product. This percentage roughly correlates to a 5 minute period in 1 day.

4

October 2015 Regulation Up Performance

5

0123456789

101112131415161718192021222324252627282930313233

5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reso

urce

Cou

nt

Score (%)

Regulation Up Performance by Resource

Reg Up

October 2015 Regulation Down Performance

6

0123456789

10111213141516171819202122232425262728293031323334353637383940414243444546474849505152

5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reso

urce

Cou

nt

Score (%)

Regulation Down Performance by Resource

Reg Down

CONGESTION OVERVIEWSection 2

7

DA vs RT Constraints

• Top 10 Congested Constraints in DA

Constraint Intervals Binding/Breached Average Shadow PriceTEXAS_CO_TXPS_TXCO_PHSHFT_PS 741 1.74

TEMP56_21085 540 19.39

WDWFPLTATNOW 471 41.21

TMP169_21252 304 2.40

TEMP49_21150 255 11.00

TEMP48_20597 200 9.20

SUNAMOTOLYOA 195 5.49

TMP168_21247 163 20.05

VMA_TWA1XF1 151 3.00

MINDE3_MINDE3_MDSWP99_A_LN 139 0.85

8

99

SPS

SECIWR

NPPD

WFEC

EES

KCPL

MPS

EDE

MEC

AECI

AECC/EES

CSWSOKGE

SPA

LESOPPD

Colorado

Wyoming

New Mexico

Texas

Iowa

Arkansas

Missouri

Top 10 Congested Constraints in DA for October

Missouri

SECIWR

TEXAS_CO_TXPS_PHSHFT_PS

WDWFPLTATNOWWDWFPLTATNOW

T 56 TUCLUBTUCJON

T48 SETSCOSETHOL

SUNAMOTOLYOA

TMP168_21247

10

TEMP169_21256

TEMP49_21150

DA vs RT Constraints

• Top 10 Congested Constraints in RTBM

Constraint Intervals Binding/Breached Average Shadow PriceTEMP56_21085 4169 27.41

WDWFPLTATNOW 3557 63.60

TMP169_21252 2757 2.12

TMP144_21263 2622 32.83

OSGCANBUSDEA 1455 22.86

TEMP23_21218 1366 4.68

TMP168_21247 963 50.23

SUNAMOTOLYOA 895 2.10

TEMP48_20597 759 4.46

TEMP49_21150 750 37.73

10

1212

SPS

SECIWR

NPPD

WFEC

EES

KCPL

MPS

EDE

MEC

AECI

AECC/EES

CSWSOKGE

SPA

LESOPPD

Colorado

Wyoming

New Mexico

Texas

Iowa

Arkansas

Missouri

Top 10 Congested Constraints in RTBM for October

OSGCANBUSDEA

WDWFPLTATNOW

Missouri

SECIWRWR

T 56 TUCLUBTUCJON

T48 SETSCOSETHOL

SUNAMOTOLYOA

TMP168_21247

13

TEMP144_21263TEMP169_21256

TEMP23_21218

TEMP49_21150

RUC UPDATESection 3

14

• The commitment breakdown for the month of October is shown to the right of total commitments made by DAMKT, RUC, SELF, and MANUAL.

• 96% of the commitments came from DAMKT, while 1.5% were considered manual.

Commitment Breakdown by MW– October 2015

15

*SELF commits are post DAMKT

Study MWDAMKT 20,938,455.10

SELF 297,094.30 RUC 173,086.70

MANUAL 306,657.40

DAMKT, 96.4%

SELF, 1.4%

RUC, 0.8%

MANUAL, 1.4%

• 9% of manual commitments amounted to 637 commitments.

• Of these 637, roughly 172 (27%), were actual new commitment startups not tied to the front or back end of a case.

• The majority of these commitments are backend extensions where units are being staggered offline to manage the impact to BA and ACE.

• In conclusion, about 2.5% of the total commitments made in the month of October were actual new manual commitments

• ‘Bridge’ were manual commitments performed by the RUC operator to bridge two existing commitments

Manual Commitments by MW – October 2015

16

*SELF commits are post DAMKT

TYPE MWNew Commit 83,063.11

Back End 172,887.16Bridge 25,112.10

Front End 25,595.03

New Commit, 27%Back End, 56%

Bridge, 8%

Front End, 8%

OCTOBER PRICINGSection 4

17

18*=more info for anomalies included on next slide

-35

15

65

115

165

215

265

315

10/1/2015 0:00 10/6/2015 0:00 10/11/2015 0:00 10/16/2015 0:00 10/21/2015 0:00 10/26/2015 0:00 10/31/2015 0:00

Hourly Avg LMPDA LMP RT LMP

19

RT LMP Outliers• Highest LMPs (hourly avg)

– 10/8/2015 13:00 $63.77 Regulation Up shortage during the top of the hour change over in reg resources.

– 10/15/2015 16:00 $70.29 Elevated MECs during the last 90 minutes of afternoon load peak but there were no product

shortages.– 10/20/2015 19:00 $79.92

Operator error in choosing the wrong load offset case, these intervals have been repriced for the error and the high prices no longer exist.

• Lowest LMPs (hourly avg)– Multiple intervals

Low load and high wind during the early morning hours caused low LMPs. Higher SELF commits in and after the DAMKT closing.

20

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

1-Oct 1-Nov 1-Dec 1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct

LMP

DA LMP

RT LMP

Day Ahead 14-Oct 14-Nov 14-Dec 15-Jan 15-Feb 15-Mar 15-Apr 15-May 15-Jun 15-Jul 15-Aug 15-Sep 15-OctDA MEC $ 31.79 $ 32.67 $ 28.49 $ 25.63 $ 24.47 $ 23.40 $ 22.75 $ 22.64 $ 24.42 $ 28.09 $ 25.77 $ 22.59 $ 20.44

DA MLC $ (0.16) $ (0.14) $ (0.09) $ (0.11) $ (0.11) $ (0.06) $ (0.08) $ (0.09) $ (0.08) $ (0.07) $ (0.07) $ (0.08) $ (0.11)

DA MCC $ (0.15) $ (0.24) $ (0.15) $ (0.09) $ (0.12) $ (0.03) $ (0.03) $ (0.10) $ (0.10) $ (0.04) $ (0.02) $ (0.06) $ (0.16)

DA LMP $ 31.48 $ 32.29 $ 28.25 $ 25.43 $ 24.25 $ 23.31 $ 22.64 $ 22.44 $ 24.23 $ 27.97 $ 25.68 $ 22.45 $ 20.17

Real Time 14-Oct 14-Nov 14-Dec 15-Jan 15-Feb 15-Mar 15-Apr 15-May 15-Jun 15-Jul 15-Aug 15-Sep 15-OctRT MEC $ 31.84 $ 31.63 $ 28.31 $ 24.65 $ 24.83 $ 22.71 $ 23.17 $ 22.43 $ 23.55 $ 25.81 $ 23.42 $ 21.78 $ 18.43

RT MLC $ (0.14) $ (0.12) $ (0.05) $ (0.08) $ (0.08) $ (0.07) $ (0.09) $ (0.10) $ (0.07) $ (0.07) $ (0.08) $ (0.09) $ (0.14)

RT MCC $ (0.24) $ (0.25) $ (0.11) $ (0.11) $ (0.13) $ (0.08) $ - $ (0.11) $ (0.14) $ 0.15 $ 0.36 $ 0.41 $ 0.61

RT LMP $ 31.46 $ 31.26 $ 28.14 $ 24.46 $ 24.61 $ 22.56 $ 23.08 $ 22.22 $ 23.34 $ 25.89 $ 23.70 $ 22.10 $ 18.91

LOAD FORECASTSection 5

21

22

0

1

2

3

4

0

5

10

15

20

25

3010

/1

10/2

10/3

10/4

10/5

10/6

10/7

10/8

10/9

10/1

0

10/1

1

10/1

2

10/1

3

10/1

4

10/1

5

10/1

6

10/1

7

10/1

8

10/1

9

10/2

0

10/2

1

10/2

2

10/2

3

10/2

4

10/2

5

10/2

6

10/2

7

10/2

8

10/2

9

10/3

0

10/3

1

Erro

r Per

cent

GW

Mid Term Load Forecast

Daily AVG MTLF Daily AVG Actual Error Threshold % Forecast Error %

23* Load forecast data used from DA-RUC cases

0

1

2

3

4

5

6

7

8

9

0

5

10

15

20

25

30

35

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Erro

r Per

cent

age

GW

Hour

MTLF by Hour of the Day for October

AVG MTLF by Hour AVG Actual by Hour AVG Error % Error Threshold %

24

0

0.5

1

1.5

2

0

5

10

15

20

25

3010

/1

10/2

10/3

10/4

10/5

10/6

10/7

10/8

10/9

10/1

0

10/1

1

10/1

2

10/1

3

10/1

4

10/1

5

10/1

6

10/1

7

10/1

8

10/1

9

10/2

0

10/2

1

10/2

2

10/2

3

10/2

4

10/2

5

10/2

6

10/2

7

10/2

8

10/2

9

10/3

0

10/3

1

Erro

r Per

cent

GW

Short Term Load Forecast

Daily AVG STLF Daily AVG Actual Error Threshold % Forecast Error %

WIND FORECASTSection 6

25

26* Wind forecast data used from DA-RUC cases

0

5

10

15

20

25

30

35

40

0

1000

2000

3000

4000

5000

6000

7000

800010

/1

10/2

10/3

10/4

10/5

10/6

10/7

10/8

10/9

10/1

0

10/1

1

10/1

2

10/1

3

10/1

4

10/1

5

10/1

6

10/1

7

10/1

8

10/1

9

10/2

0

10/2

1

10/2

2

10/2

3

10/2

4

10/2

5

10/2

6

10/2

7

10/2

8

10/2

9

10/3

0

10/3

1

Erro

r Per

cent

GW

Mid Term Wind Forecast

Daily AVG MTWF Daily AVG Actual Error Threshold % Forecast Error %

27* Wind forecast data used from DA-RUC cases

0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Erro

r Per

cent

age

GW

Hour

MTWF by Hour of the Day for October

AVG MTWF by Hour AVG Actual by Hour AVG Error % Error Threshold %

28

0

5

10

15

0

1000

2000

3000

4000

5000

6000

7000

800010

/1

10/2

10/3

10/4

10/5

10/6

10/7

10/8

10/9

10/1

0

10/1

1

10/1

2

10/1

3

10/1

4

10/1

5

10/1

6

10/1

7

10/1

8

10/1

9

10/2

0

10/2

1

10/2

2

10/2

3

10/2

4

10/2

5

10/2

6

10/2

7

10/2

8

10/2

9

10/3

0

10/3

1

Erro

r Per

cent

GW

Short Term Wind Forecast

Daily AVG STWF Daily AVG Actual Error Threshold % Forecast Error %

DAMKT UPDATESection 7

29

DA Obligations vs RUC Obligations - October• DA (Cleared Load + NSI – Virtual Offers – Wind Offers)

• RUC (Load Forecast + NSI – Wind Forecast)

30

13000

15000

17000

19000

21000

23000

25000

27000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

RUC

DA

DA Obligations vs RUC Obligations - October

• All October days averaged into one “average” day

• Average 405 MW short

• Peak 1657 MW short

• Differences– Virtuals

– Wind offered in DA vs Wind forecast in RUC

31

DA Obligations vs RUC Obligations - October

Average MW Short by Hour

-1000

-500

0

500

1000

1500

2000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Shortfall

30

DA Fixed and PS Bid (with losses) vs MTLF

20000

21000

22000

23000

24000

25000

26000

27000

28000

29000

30000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MTLF

DemandBid

31

APPENDIX Section 8

34

35

Constraint Elements Reason

OSGCANBUSDEAMon: Osage-Canyon 115 kV

Con: Bushland – Deafsmith 230 kV NorthSouth loading in SPS primarily due to economic dispatch (resources in SPS south are usually not economic), as well as high wind north of this constraint.

TEXAS_CO_TXPS_TXCO_PHSHFT_PS This has always been “activated”, but it is just now showing up in the MDB solution constraint tables since the 1.12 release.

WDWFPLWDWTATMon: Woodward-Fpl Switch 138 kV

Con: Tatonga-Northwest 345 kVIt shows up during high NW to SE flows from the Texas Panhandle and West Kansas and also when there is high wind in the area.

TEMP56_21085 Mon: Tuco – Lubbock 115kVCon: Tuco – Jones Sub 230kV Inc resources were at a minimum to relieve loading on this constraint.

TEMP48_20597 Mon: Setab – Scott City 115kVCon: Setab – Holcomb 345kV Ongoing outages in the area with little generation to move up with heavy North-South flow.

TMP168_21247 Mon: Knoll – Redline 115kVCon: Gentleman – Red Willow 345kV Heavy flows into the area, along with multiple generation and transmission outages in the area.

SUNAMOTOLYOA Mon: Sundown – Amoco 230kVCon: Tolk – Yoakum 230kV

Shows up when trying to keep enough generation on in the area. This constraint can be impacted with or without outages in the area.

36

TMP169_21252 Mon: Waterford 230/1kVCon: Waterford 230/1kV Loading due to high load in the area.

VMA_TWA1XF1 DAMKT constraint driven to its limits by virtual market activity.

MINDE3_MINDE3_MDSWP00_A_LN DAMKT constraint driven to its limits by virtual market activity.

TMP144_21263 Mon: Charlie Creek – Rough Rider 115kVCon: Charlie Creek – Waterford 230kV Loading due to high load in the area.

TEMP23_21218 Mon: Eau Claire – Arpin 345kVCon: Stonelake – Gardner Park 345kV MISO FG that SPP is M2M coordinated on.

TEMP49_21150 Mon: Rugby 230/115 XFRCon: Rugby – Balta Jnct 230kV Loading due to high wind impacts from external entities.

Regulatory Report to MWG for November 2015

Current Filings

Description (Regulatory Lead)

FERC Docket No.

Activity Status

IM Motion for Clarification

ER12-1179 ER13-1173

Motion for Clarification made on July 11, 2014 regarding cost allocation for manual resource commitments to address local reliability issues. Order issued by FERC on August 11, 2014 granting rehearing. Order issued by FERC on December 18, 2014 granting motion for clarification and requiring compliance filing. Compliance filing made on January 20, 2015. Amendment to compliance filing made on February 6, 2015. Comments due by February 27, 2015.

Awaiting order.

Order No. 681—LTCRs (Phase II Project) (Marisa Choate)

ER14-2553 Filing (MPRRs 138 and 171) made on July 31, 2014 requesting a February 1, 2015 effective date. Comments due by August 21, 2014.

• Seven interventions were filed and two protests were filed. SPP filed a response on September 8, 2014.

• In reply to SPP’s response, two responses were filed. Order issued by FERC on October 28, 2014 conditionally accepting the filing with compliance requirements outlined in the order. Motion for Extension of Time filed on November 14, 2014. Order issued by FERC on November 25, 2014 accepting the motion for extension of time until January 30, 2015. Request for Rehearing filed on November 28, 2014 regarding Guideline (3). Compliance filing (MPRR 227) made on January 30, 2015. Comments due by February 20, 2015.

Awaiting order.


• Two doc-less interventions were filed. • AWEA filed comments.

Order issued by FERC on July 16, 2015 denying rehearing and conditionally accepting the filing with compliance requirements outlined in the order. Motion for Extension of Time filed on July 29, 2015. Order issued by FERC on August 10, 2015 accepting the motion for extension of time until October 30, 2015. Compliance filing (RR 119) made on October 30, 2015. Comments due by November 20, 2015.

MPRR 223—SPP Conservative Operations during Multi-Day RUC (Marisa Choate)

ER15-1293 Filing made on March 16, 2015 requesting a May 15, 2015 effective date. Comments due by April 6, 2015.

• One doc-less intervention was filed and one protest (SPP MMU) was filed. Deficiency letter issued by FERC on May 14, 2015. SPP filed its deficiency response on June 15, 2015. Comments due July 6, 2015. Order issued by FERC on August 14, 2015 conditionally accepting the filing with one compliance requirement outlined in the order. Compliance filing made on September 11, 2015. Order issued by FERC on October 21, 2015 accepting the filing with a May 15, 2015 effective date.

MPRR 234—Trading Hubs and Resource Hubs (Marisa Choate)

ER15-2265 Filing made on July 24, 2015 requesting a September 23, 2015 effective date. Comments due by August 14, 2015.

• Three doc-less interventions were filed, one protest was filed, and one comment was filed.

• One supporting comment (SPP MMU) was filed. • SPP filed a response on August 31, 2015.

Awaiting order.


Order issued by FERC on September 22, 2015 conditionally accepting the filing with three compliance requirements outlined in the order. Compliance filing made on October 22, 2015.

RR 100—Gas Electric Coordination Market Timeline Changes (Patti Kelly)

ER15-2377 Filing made on August 4, 2015 requesting an October 1, 2016 effective date. Comments due by August 25, 2015.

• Nine doc-less interventions were filed and two interventions with comments were filed.

• Five comments/protests were filed. • One supporting comment (AEP) was filed. • SPP filed a response on October 16, 2015.

Awaiting order.

RR 73—Attachment X Article 3 Credit Policy Revisions to Allow Use of IFRS (Patti Kelly)

ER15-2636 Filing made on September 10, 2015 requesting a November 9, 2015 effective date. Comments due by October 1, 2015. Order issued by FERC on November 4, 2015 accepting the filing with a November 9, 2015 effective date.

MPRR 233—Day-Ahead Reliability Unit Commitment Assessment (Marisa Choate)

ER15-2690 Filing made on September 22, 2015 requesting a November 21, 2015 effective date. Comments due by October 13, 2015.

• One doc-less intervention was filed.

Awaiting order.

RR 91—Annual Allocation Percentage Change (Marisa Choate)

ER16-13 Filing made on October 2, 2015 requesting a January 28, 2016 effective date. Comments due by October 23, 2015.

• Five doc-less interventions were filed. • One comment (SPP MMU) was filed.

Awaiting order.

TRR 097M—Order 760 Compliance Filing for Marketplace (Patti Kelly)

ER16-25 Filing made on October 5, 2015 requesting a March 1, 2014 effective date. Comments due by October 26, 2015.

Awaiting order.

RR 101—Real-Time Reg-Up/Reg-Down Service Margin Correction

ER16-37 Filing made on October 8, 2015 requesting an October 9, 2015 effective date. Comments due on October 29, 2015.

• One doc-less intervention was filed.

Awaiting order.


(Patti Kelly) RR 120—Ramp Scarcity Pricing (Marisa Choate)

ER16-158 Filing made on October 28, 2015 requesting a December 27, 2015 effective date. Comments due on November 18, 2015.

Awaiting order.


Future Filings

RR Title Status/Anticipated Filing Date 1

(MPRR 101) Combined Cycle Enhanced Design Target system implementation date 3/1/2017

5 (MPRR 140) Mitigated Transition State Offers Target system implementation date

3/1/2017 7

(MPRR 155) Modification of OOME Rules Approved by Board/Tabled by SPP Operations/Not filed at FERC

16 (MPRR 190) MWP Start Up Recovery Eligibility Clarifications 2/15/2016

18 (MPRR 196) Ancillary Service SPP Manual Override on Regulation 2/15/2016

25 (MPRR 211) Self-Commit Min Run Time Make Whole Payment Exemption 2/15/2016

29 (MPRR 215) Product Substitution Cost Allocation 2/15/2016

82 Modification of Make Whole Payment Grace Period 1Q2017

106 Outage Deviation 1Q2017

112 ECC Cleanup Target system implementation date 3/1/2017

116 Quick-Start Real-Time Commitment PMO review

118 RUC MWP Start-Up Offer Recovery Eligibility Clarifications 2/15/2016

Attachment 21 - RR8_MPRR 164 Recommendation Report 4/15/2014 Page 1 of 5

PRR Recommendation Report PRR No. Marketplace-PPR164 PRR

Title Mitigated Offer Clarifications

Timeline Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected:

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Impact Analysis Required Yes – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: Appendix G - Mitigated Offer Development Guidelines; 2.3.4; 2.4; 2.5.1; 4.3; 6.3.1; 6.7; 7.3; 8.6 Title: Types of Fuel Costs; Total Variable Operation and Maintenance Cost; Escalation Index; Fuel Cost; Combustion Turbine other Fuel-Related Costs; VOM Cost; Fuel Cost; VOM Cost Protocol Version: 17.0

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Timeline Go-Live Post Go-Live

Revision Description

The purpose of this MPRR is to improve sections of Appendix G where Market Participants have found the language or formulas to be unclear. Especially, Market Participants seek clarity around the use of FERC accounts for fuel and VOM. To be consistent with the purpose of the guidelines (see Appendix G 1.5) and with the requirements of the SPP Tariff, the costs derived from FERC accounts must only include short-run marginal production costs.

• Providing clarity that only the short-run marginal cost items in fuel and VOM FERC Accounts are includable in mitigated offers

• Correcting Hydro cost formula • Updating historical VOM inflation escalation factors

Tariff Implications or Changes

Yes – Section No: (Include a summary of impact and/or specific changes)

No

Criteria Impact or Changes

Yes – Section No: (Include a summary of impact and/or specific changes)

No

MWG Review PRR Recommendation

Date of Vote: 2/11/2014 Vote: Approved

Opposed: N/A

Abstained: AEP, Xcel, OGE, OPPD

Date of Vote:11/14/2015 Vote: Rejected

RTWG Review Date of Vote: 2/20/2014 Vote: Approved with no Tariff implications

EIS Market

Integrated Marketplace


ORWG Review Date of Vote: 3/6/2014 Vote: Approved with no Reliability impacts

MOPC Recommendation Date of Vote: 4/15/2014 Vote: Remanded to MWG

Board Review Date of Vote: Vote:

Date 1/24/2014

Sponsor Name Catherine Tyler Mooney E-mail Address [email protected] Company SPP Market Monitoring Phone Number (501) 688-8249

Comments Received Comment Author Micha Bailey of behalf of MWG Date 2/11/2014

Comment Description In MPRR164 Appendix G Section 4.3 and 6.3, the word “dollar” was deleted and replaced with “incremental cost”. In the same sections, the word “incremental” was added before fuel expenses to match the first change describe above.

Comment Status The MPRR was approved as modified in these comments. The approved language is reflected in this recommendation report.

Proposed Protocol Language Revision

Appendix G - Mitigated Offer Development Guidelines

2.3.4 Types of Fuel Costs

Basic fuel cost is the commodity cost of fuel calculated as stated in the company’s fuel cost policy.

NOTE: Basic Fuel Cost for each resource type will be addressed in subsequent sections.

Other fuel related cost includes the consists of additional incremental components of fuel cost required to operate a generating resource, such as transportation fees, taxes on fuel and water injection.

2.4 Total Variable Operation and Maintenance Cost

Total Variable Operation and Maintenance (VOM) costs are the parts and labor expenses of

maintaining equipment and facilities in satisfactory operating condition. A resource should reflect its

short-run incremental VOM costs by using the most current data available. This could include the

previous maintenance cycle period cost or actual short-run incremental cost where available.

𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝑉𝑉𝑉𝑉𝑉𝑉 ($) =



��𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑇𝑇𝑇𝑇 𝑉𝑉𝑉𝑉𝑉𝑉 𝐶𝐶𝑇𝑇𝐶𝐶𝑇𝑇($)𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐 ∗𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝑐𝑐𝑛𝑛𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐

𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐�

+ �𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑇𝑇𝑇𝑇 𝑉𝑉𝑉𝑉𝑉𝑉 𝐶𝐶𝑇𝑇𝐶𝐶𝑇𝑇($)𝑙𝑙𝑦𝑦𝑙𝑙𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐 ∗𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝑐𝑐𝑛𝑛𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐

𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑙𝑙𝑦𝑦𝑙𝑙𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐�

+ �𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑇𝑇𝑇𝑇 𝑉𝑉𝑉𝑉𝑉𝑉 𝐶𝐶𝑇𝑇𝐶𝐶𝑇𝑇($)𝑙𝑙𝑦𝑦𝑙𝑙𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐−1 ∗𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝑐𝑐𝑛𝑛𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐

𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑙𝑙𝑦𝑦𝑙𝑙𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐−1�+ ⋯

+ �𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑇𝑇𝑇𝑇 𝑉𝑉𝑉𝑉𝑉𝑉 𝐶𝐶𝑇𝑇𝐶𝐶𝑇𝑇($)𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐−𝑚𝑚𝑦𝑦𝑚𝑚𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑦𝑦𝑐𝑐𝑐𝑐𝑐𝑐 𝑝𝑝𝑐𝑐𝑐𝑐𝑚𝑚𝑝𝑝𝑝𝑝+1

∗𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝑐𝑐𝑛𝑛𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐

𝐸𝐸𝐶𝐶𝐸𝐸𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝐸𝐸𝑇𝑇𝐴𝐴 𝐼𝐼𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐−𝑚𝑚𝑦𝑦𝑚𝑚𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑦𝑦𝑐𝑐𝑐𝑐𝑐𝑐 𝑝𝑝𝑐𝑐𝑐𝑐𝑚𝑚𝑝𝑝𝑝𝑝+1𝑙𝑙𝑦𝑦𝑙𝑙𝑐𝑐 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐−𝑚𝑚𝑦𝑦𝑚𝑚𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑦𝑦𝑐𝑐𝑐𝑐𝑐𝑐 𝑝𝑝𝑐𝑐𝑐𝑐𝑚𝑚𝑝𝑝𝑝𝑝 𝑦𝑦𝑐𝑐𝑦𝑦𝑐𝑐𝑙𝑙+1��

The SPP MMU will review the development of the total maintenance costs for all resources pursuant to

the Mitigated Offer Methodology Approval Process.

The total VOM cost as calculated above is based on available maintenance expense history for the

defined Maintenance Period (See Section 2.4.2) regardless of mMarket Participantship participation.

Only expenses incurred as a result of short-run incremental electric production (short-run marginal

costs) qualify for inclusion.

2.5.1 Escalation Index

Escalation Index is the annual escalation index as derived from the July 1 Handy - Whitman Index for

the SPP applicable region, “construction cost electrical plant”. Otherwise, the Bureau of Labor Statistics Producer Price Index Series ID PCU3331203331208, Construction Machinery Manufacturing, Other Construction Machinery and Equipment shall be used for the Escalation Index as shown below.

Bureau of Labor Statistics Producer Price Index

2004: Index 104.7 – Escalation Factor 1.31433




2008: Index 125.6 - Escalation Factor 1. 096111



2011: Index 134.8 - Escalation Factor 1. 021 035

2012: Index 137.6(est) - Escalation Factor 1.000014

2013: Index 139.5 (est) – Escalation Factor 1.000


4.3 Fuel Cost

Note: The information in Section 2.3 contains basic Fuel information relevant for all unit types. The following information only pertains to fossil steam units.

Fossil fuel cost adjustments compensating for previous estimate inaccuracies should not be considered

when determining the basic fossil cost component of Total Fuel Related Cost.

Fossil Other Fuel-Related Costs - the dollars incremental costs in FERC Account 501 Fuel plus incremental expenses for fuel treatment and pollution control (excluding SO2 and NOX emission allowance costs) that were not included in Account 501; minus the incremental fuel expenses from FERC Account 151 that were charged into Account 501, all divided by the fuel (heat content or quantity) shifted from Account 151 into Account 501.

6.3 Fuel Cost

Note: The information in Section 2.3 contains basic Fuel Cost information relevant for all unit types including CTs, and reciprocating diesel engine units.

6.3.1 Combustion Turbine other Fuel-Related Costs

The dollars incremental costs in FERC Account 547, plus incremental expenses for fuel treatment and

pollution control excluding SO2 and NOX emission allowance costs that were not included in Account

547; minus the incremental fuel expenses from FERC Account 151 that were charged into Account 547,

all divided by the fuel (heat content or quantity) shifted from Account 151 into Account 547.

6.7 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to CT and diesel engine units.

Combustion Turbine - VOM Cost – The historical total dollars from FERC Account 553 should be

used to calculate the VOM $ specified under Section 2.4.

7.3 Fuel Cost

To be consistent with other SPP units within this manual the term fuel cost is used to account for the

energy necessary to pump from the lower reservoir to the upper reservoir.


Note: The information in Section 2.3 contains basic Fuel Cost information relevant for all unit types. The following additional information only pertains to pumped hydro units.

If, a Market Participant wishes to change its method of calculation of pumped storage TFRC, the Market

Participant shall notify the SPP MMU in writing by December 31 prior to the year of operation, to be

evaluated pursuant to the Mitigated Offer Methodology Approval Process before the beginning of the

cycle in which the new method is to become effective. The new cycle starts on February 1st and

continues for a period of one year.

Pumped Storage Fuel Cost – Pumped storage fuel cost shall be calculated on a seven (7) day rolling

basis by multiplying the real time bus LMP at the plant node by the actual power consumed when

pumping. The following equations govern pumping storage fuel cost:

𝑃𝑃𝐴𝐴𝑃𝑃𝑃𝑃𝐸𝐸𝐴𝐴𝑃𝑃 𝑃𝑃𝑇𝑇𝑃𝑃𝐼𝐼𝑃𝑃 𝐶𝐶𝑇𝑇𝐶𝐶𝑇𝑇($ 𝑉𝑉𝑀𝑀ℎ⁄ ) = ∑𝑅𝑅𝑐𝑐𝑦𝑦𝑙𝑙 𝑇𝑇𝑚𝑚𝑚𝑚𝑐𝑐 𝐿𝐿𝐿𝐿𝐿𝐿 ($/𝐿𝐿𝑀𝑀ℎ) ∗𝐿𝐿𝑐𝑐𝑚𝑚𝑝𝑝𝑚𝑚𝑐𝑐𝑃𝑃 𝐿𝐿𝑝𝑝𝑃𝑃𝑐𝑐𝑐𝑐 (𝐿𝐿𝑀𝑀ℎ)𝑇𝑇𝑝𝑝𝑐𝑐𝑦𝑦𝑙𝑙 𝐿𝐿𝑐𝑐𝑚𝑚𝑝𝑝𝑚𝑚𝑐𝑐𝑃𝑃 𝐿𝐿𝑝𝑝𝑃𝑃𝑐𝑐𝑐𝑐 (𝐿𝐿𝑀𝑀ℎ)∗𝐿𝐿𝑐𝑐𝑚𝑚𝑝𝑝𝑚𝑚𝑐𝑐𝑃𝑃 𝐸𝐸𝐸𝐸𝐸𝐸𝑚𝑚𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑦𝑦

Efficiency Pumping* (MWh) Power Pumping Total(MWh) Power Pumping*($/MWh) LMP Time Real

t tt∑,

where t indexes Real Time Balancing Market intervals during pumping.

8.6 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to hydro units.

The historical total dollars from the FERC accounts listed here should be used to calculate the VOM $

specified under Section 2.4. The cost of labor, materials used and expenses incurred in the maintenance

of plant, includible in Account 332, Reservoirs, Dams, and Waterways. (See operating expense

instruction 2). The cost of labor materials used and expenses incurred in the maintenance of fish and

wildlife, and recreation facilities, the book cost of which is includible in Account 332, Reservoirs,

Dams, and Waterways, includable in Account 545, Maintenance of Miscellaneous Hydraulic Plant.

Proposed Tariff Language Revision

N/A

Proposed Criteria Language Revision N/A

Commented [CTM1]: Remove, replace with equation below.

Field Code Changed

Reserve ZoneBi-Annual Review

November 17, 2015

SPP OPS Analysis

Bi-Annual Reserve Zone Review Summary

• No RZ Minimum or Maximum has been used in the last bi-annual period– Last RZ Min/Max used was in Sept 2014

• IS Region become a separate new reserve zone as part of the IS integration into the SPP IM

• No significant changes in “reserve zone relevant” congestion observed in the previous 6 months

• No changes to current reserve zone definitions recommended

• No RZ changes will be effective on December 1, 2015

2

Reserve Zone Map - North

3

5

1

*Reserve zone boundaries as shown on this map are approximate

Reserve Zone Map - South

4

42

3

*Reserve zone boundaries as shown on this map are approximate

2015 FCA Study Preliminary Results

November 18, 2015

Background - Section 3.1.1 of Attachment AF

• 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 a least 500 hours during a 12 month period and within which one or more suppliers are pivotal

• The Market Monitor shall reevaluate the Frequently Constrained Areas at least annually or more frequently as the Market Monitor deems necessary

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Background – Transparency Assurance

• Review with the MWG the assumptions to be used in upcoming study (September 2015)

• Present a draft FCA report to MWG

• Submit a tariff revision request to the RTWG to reflect changes in the FCA designation

• Present a report to the MOPC and BOD in support of tariff changes

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Assumptions & Data for 2015 Study

• The study period will cover from September 1, 2014 to September 1, 2015

• The study methodology will correspond to that used in the 2014 study; see Appendix A to this presentation (Update: There is a change in the methodology used to determine the shift-factor cut-off. See Slide 8 and additional details in Appendix A)

• RTBM congestion and dispatch data, and resource parameter offers for online resources to be used for the analysis

• The impact analysis will use a $25/MWh threshold

• Will monitor data after IS Integration to determine if special study warranted

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Preliminary Study Results

• Texas Panhandle area meets the criteria to maintain the designation as an FCA; Pivotal supplier hours are significantly lower but still exceed 500 hour threshold

• FCA Candidate in the Woodward, Oklahoma area meets the criteria for designation as an FCA

• Four other FCA Candidate areas studied but they do not meet the criteria for FCA designation

• The study will be completed and a report will be made available prior to the December MWG meeting

• A Tariff change Revision Request will be submitted to the RTWG for consideration at the December RTWG meeting

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Top 10 Binding Constraints

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ConstraintBinding

Hours

Pivotal

Supplier HoursMonitored Element Area

OSGCANBUSDEA 3751 3749 OSAGE to CANYON (115) Texas Panhandle

WDWFPLTATNOW 1704 875 WOODWARD to FPL SWITCH (138) Western Oklahoma

SUNAMOTOLYOA 896 857 SUNDOWN to AMOCO (230) Lubbock

IATSTRSTJHAW 668 192 IATAN TO STRANGER CREEK (345) Kansas City

TEMP56_21085 624 624 TUCO - LUBBOCK 115 kV Lubbock

WDWFPLWDWTAT 505 191 WOODWARD TO FPL SWITCH (138) Western Oklahoma

ARCKAMARCNOR 488 428 ARCADIA to JONES KAMO (138 ) Oklahoma City

TMP109_20517 467 398 SWISSVALE to GARDNER (345) Kansas City

NEORIVNEOBLC 430 319 NEOSHO to RIVERTON (161) Southeast Oklahoma

FCA Candidate Areas

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FCA Candidate Areas

FCA Candidate Pivotal Supplier Hours

Primary Constraint RLDF Cut-Off

Kansas City 1,400 IATSTRSTJHAW 3.5%

Lubbock 1,500 SUNAMOTOLYOA 32.2%

Oklahoma City 500 ARCKAMARCNOR 3.8%

Texas Panhandle 3,800 OSGCANBUSDEA 4.4%

Western Kansas 500 REDWILLOWMINGO 6.2%

Woodward 1,000 WDWFPLTATNOW 4.3%

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The process for computing the RLDF cut-off was changed because the initial calculations led to cut-offs as low as 1.8%. To address this issue we only consider relief megawatts with a RLDF magnitude of 3% or greater relative to the primary constraint, and we set the cut-off at the 90th percentile of the relief megawatts supplied by the three largest pivotal suppliers. See Appendix C of this presentation for additional details.

FCA Candidate Resources

FCA Candidate Number of Resources

Primary Constraint Relief Capability (MW)

Kansas City 233 1,700

Lubbock 16 850

Oklahoma City 8 170

Texas Panhandle 36 350

Western Kansas 112 1,000

Woodward 19 260

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Secondary Constraint

• A constraint for which the FCA Candidate Resource group provides at least 70% of the relief capability

• Temporary Flowgates that have been terminated are excluded

• Temporary Flowgates created to address loading due to outages are excluded

• Electrical proximity to the FCA Resource Candidate group is also a consideration for exclusion

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Impact Analysis

FCA Candidate Pivotal Supplier Hours $25 Impact Threshold

Kansas City 150

Lubbock 140

Oklahoma City 30

Texas Panhandle 510

Western Kansas 90

Woodward 1,100

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Impact Analysis 2014-1015 Comparison

FCA Candidate 2014 Pivotal Supplier Hours $25 Impact Threshold

2015 Pivotal Supplier Hours $25 Impact Threshold

Kansas City 58 150

Lubbock n/a 140

Oklahoma City n/a 30

Texas Panhandle 1,258 510

Western Kansas 84 90

Woodward n/a 1,140

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Impact Analysis – Threshold Sensitivity

FCA Candidate 2015 Pivotal Supplier Hours $25 Impact Threshold

2015 Pivotal Supplier Hours $15 Impact Threshold

Kansas City 150 220

Lubbock 140 260

Oklahoma City 30 60

Texas Panhandle 510 870

Western Kansas 90 150

Woodward 1,140 1,670

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Appendix A – FCA Methodology*

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* Section III in the 2014 FCA Report available on SPP.org at this link: SPP Market Monitoring Unit

http://www.spp.org/section.asp?pageID=17

1. Binding Hours Computation

The number of binding hours is computed for each modeled transmission constraint. A constraint is counted as binding in a five minute interval if the loading on the constraint is within the greater of five megawatts (5 MW) or 2% of the effective constraint limit.

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2. Pivotal Supplier Analysis

The number of pivotal supplier hours is computed for each modeled transmission constraint. A constraint is counted as having a pivotal supplier during a five minute interval if the supplier can cause a constraint to exceed the effective constraint limit by decreasing generation on resources that provide congestion relief and by increasing generation on resources that contribute to congestion. The re-dispatch of the potential pivotal supplier’s resources is governed by the submitted ramp rates, and the economic minimum and maximum capabilities. A thirty minute re-dispatch period is considered. The ability of the market to react to the actions of the potential pivotal supplier is accounted for by allowing a similar re-dispatch of all resources not owned or controlled by the potential pivotal supplier.

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3. Selection of FCA Candidates

Candidates for designation as a Frequently Constrained Area are chosen based on the binding hours and pivotal supplier analyses. Constraints that are in the same electrical proximity and have the same pivotal suppliers are grouped together. If the aggregate number of binding and pivotal supplier hours is significant, then the area is selected as a candidate FCA. A primary constraint for the candidate FCA is generally selected as the constraint with the highest number of binding hours.

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4. Identify candidate FCA Resources

A resource is a candidate FCA resource if its shift-factor relative to the candidate FCA primary constraint is less than or equal to the candidate FCA shift-factor cut-off. To determine the shift-factor cut-off we first compute the relief capability* of the three largest pivotal suppliers relative to the primary constraint. The shift-factor cut-off is then set at the shift-factor corresponding to the ninetieth percentile of the relief capability. In other words, ninety percent (90%) of the relief capability owned by the three largest pivotal suppliers’s relief capability has a shift-factor less than or equal to the candidate FCA shift-factor cut-off.

* Relief capability consists of megawatt impacts on the primary constraint from Resources with RLDFs ≤ -3%

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5. Identify candidate FCA secondary Constraints

A constraint is eligible to be defined as a secondary constraint for the candidate FCA if the candidate FCA resource group contributes at least seventy percent (70%) of the total relief capability on the constraint. Additional considerations for defining a constraint as a secondary constraint consist of (i) electrical proximity to the primary constraint, (ii) an expectation that the constraint is not a short-term or temporary constraint, and (iii) an expectation that the constraint will experience significant congestion in the upcoming year.

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6. Impact Analysis

An impact analysis is employed to determine the number of hours for which the candidate FCA Resource group has significant impacts on prices in the candidate FCA. For each five minute interval in the study period, the resource price impacts on each defining constraint are calculated by multiplying the shadow price and the candidate resource’s corresponding shift-factor. The resource price impacts are then summed over the candidate FCA defining constraints to obtain a five minute price impact for each candidate resource. This calculation is equivalent to finding the contribution from the candidate FCA defining constraints to the candidate resource’s marginal congestion component of the LMP.

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