Southwest Power Pool, Inc.

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1 Minutes No. 157 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 21-23, 2011 Dallas, TX / AEP Offices Summary of Motions Agenda Item 5: MWG Recommendation to MOPC Report Darrell Wilson (OGE) motioned and Aaron Rome (Midwest Energy) to approve the recommendation as outlined in the MWG recommendation report to MOPC: The MWG recommends proceeding with implementation of the Integrated Marketplace design as accepted by MOPC at their January 12, 2011 meeting with the following modifications: 1. Explicitly describe the process for adjusting the ARR nomination caps 2. Remove the provision allowing the Reserve Zone internal obligation transfers 3. Remove the provision allowing an operating Reserve Zone minimum to be equal to the available Operating Reserve in a zone. The motion passed with two abstentions from Gene Anderson (OMPA) and Richard Ross (AEP) and no oppositions. Agenda Item 11 Revision Requests: MPRR1 Darrell Wilson (OGE) motioned and John Varnell (Tenaska) seconded to expedite MPRR1. The motion passed with no abstentions or oppositions. Agenda Item 11 Revision Requests: MPRR1 Darrell Wilson (OGE) motioned and Shah Hossain (Westar) seconded to approve MPRR1. The motion passed with four oppositions from Gene Anderson (OMPA), Aaron Rome (Midwest), Jessica Collins (Xcel), and Matt Moore (GSE) and one abstention from Tenaska (John Varnell). Agenda Item 11 Revision Requests: PRR 234 Jessica Collins motioned (Xcel) and Gene Anderson (OMPA) seconded to wave notice for this meeting and support expedited and urgent status for PRR 234. The motion passed with two oppositions from Rick Yanovich (OPPD) and Shah Hossain (Westar) and no abstentions. Agenda Item 11 Revision Requests: PRR 234 Shah Hossain (Westar) motioned to approve PRR 234 and Patty Denny (KCPL) seconded to approve PRR 234. The motion passed with one opposition from Rick Yanovich and no abstentions. Agenda Item 11 Revision Requests: PRR 215 Gene Anderson (OMPA) motioned and Jessica Collins (Xcel) seconded to reject PRR 215. The motion passed with two oppositions from Darrell Wilson (OGE) and Richard Ross (AEP) and four abstentions from Bruce Walkup (AECC), John Varnell (Tenaska), Josh Kirby (WFEC), and Patty Denny (KCPL). 1 1 of 132

2 Minutes No. 157 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 21-23, 2011 Dallas, TX / AEP Offices MINUTES Agenda Item 1 Call to Order, Proxies, Agenda Discussion: Richard Ross (AEP) called the meeting to order at 1 p.m. The attendance was recorded and proxies were announced (Attachment 1 MWG Attendance March ). Proxies included Matt Moore (GSE) for Mike Wise (GSE), Josh Kirby (WFEC) for James Liao (WFEC), Bruce Walkup (AECC) for Keith Sugg (AECC), and John Varnell (Tenaska) for Ann Scott (Tenaska). The group reviewed the agenda (Attachment 2 MWG Agenda March _v4) and permitted Casey Cathey (SPP) to add PRR 234 to the agenda under Agenda Item 15 Revision Requests. Agenda Items 2 Review Position Papers The MWG edited and reviewed the remaining position papers on responses to the MOPC and SPP Board on the concerns by Boston Pacific and the SPP MMU on the Integrated Marketplace. (Attachments 3 Marginal Loss Allocation position paper _mwg, Attachment 4 Transmission Congestion Cost Management position paper _mwg) The papers will be submitted to the MOPC and SPP Board in April and as appendices to the MWG Recommendation Report to MOPC. Agenda Item 3 SPP Staff Recommendation on Implementation Date & Combined-Cycle to MOPC Sam Ellis (SPP) presented the Staff recommendation to MOPC on the Integrated Marketplace target implementation date and combined-cycle modeling design. (Attachment 5 SPP staff recommendation to MOPC on Implementation Date & Combined-Cycle) The MWG reviewed the language and made a few suggestions. They requested the differences between the Standard and Enhanced designs for combined-cycle modeling be further explained. Also, the MWG requested members concerns related to delaying implementation be included. Specifically, members expressed concern that Market Participants will have additional testing costs and as a result of delaying implementation of the Combined-Cycle enhanced design. Also, the delay would prevent the complete benefits anticipated from the Marketplace from being realized for an entire year after implementation. SPP staff will update the recommendation report to reflect the MWG s concerns before presenting it to MOPC. Agenda Item 4 SPP-MISO Settlements Comparison Wayne Camp (Accenture) presented on the improvements to Integrated Marketplace settlements design compared to the MISO markets as a follow up to an action item captured in the February 2 nd MWG meeting on RTO comparisons. (Attachment 6 SPP-MISO Comparisons - Settlements) After the presentation an action item was recorded for SPP staff to return with a presentation with examples of operational improvements for the SPP Integrated Marketplace compared to MISO related to operational concerns. Shah Hossain (Westar) to provide specific concerns for SPP staff to address in the presentation. Agenda Item 5 MWG Recommendation Report to MOPC The MWG reviewed a draft recommendation report for MOPC on the Integrated Marketplace design. (Attachment 7 MWG recommendation to MOPC on Marketplace ). The MWG decided to add the position papers as appendices to the recommendation report for the MOPC in effort to consolidate information. After a detailed review and several modifications to the structure and language, Darrell Wilson (OGE) motioned and Aaron Rome (Midwest Energy) to approve the recommendation as outlined in the MWG recommendation report to MOPC: 2 2 of 132

3 Minutes No. 157 The MWG recommends proceeding with implementation of the Integrated Marketplace design as accepted by MOPC at their January 12, 2011 meeting with the following modifications: 1. Explicitly describe the process for adjusting the ARR nomination caps, 2. Remove the provision allowing the Reserve Zone internal obligation transfers, 3. Remove the provision allowing an operating Reserve Zone minimum to be equal to the available Operating Reserve in a zone. The motion passed with two abstentions from Gene Anderson (OMPA) and Richard Ross (AEP) and no oppositions. Agenda Item 6 RTO/ISO Forklift Option Bart Tsala (PCI) presented on the possibility of a forklift of another RTO/ISO market. (Attachment 8 RTO/ISO Forklift Option) The members asked questions and debated the definition of a forklift: does a forklift consist of taking a baseline of another RTO/ISO design and modifying it slightly or simply taking a different RTO/ISO design and implementing it? Some members expressed concern about the possibility of a delay by choosing to change directions on market design. Others mentioned that several years of effort have been invested in the Integrated Marketplace design and the MWG chose not to forklift a design at the beginning of the process. After considerable discussion, the MWG determined there is no significant advantage to time or cost to move forward with a forklift at this time in the project. The position of the MWG on the forklift will be included in the MWG recommendation to MOPC. Agenda Item 7 Minutes Approval Richard Ross (AEP) asked the MWG for any changes or comments on the minutes posted for the February 15-17, March 8-9, and March MWG meetings. There were no requests for changes so Richard Ross (AEP) deemed the minutes approved as posted. (Attachment 9 Feb Minutes, Attachment 10 March 8-9 Minutes, Attachment 11- March Minutes) Agenda Item 8 Working Group/Committee Updates Due to time constraints this agenda item was not covered. It will be included in April MWG meeting agenda. Agenda Item 9 Regulatory Update Patti Kelly provided the MWG with a regulatory update. (Attachment 12 Regulatory Update March 2011). Agenda Item 10 MMU EIS Update Alan McQueen (SPP) provided the monthly MMU EIS report to the MWG. (Attachment MWG MMU Presentation). Agenda Item 11 April 2 Outage & Analysis of Failover to Disaster Recovery Systems CJ Brown (SPP) detailed to the group the plan for the April 2, 2011 market outage. (Attachment 14 Copy of High Level Failover Plan) SPP staff investigated if the market outage could be shortened by failing over to disaster recovery systems (DRS) during the system upgrades. After analysis, SPP staff determined that failing over to the DRS would not save significant time so a failover will not be used in April. However, in effort to improve processes, SPP plans to failover to DRS during a planned fall outage. Members asked questions to better understand why there will not be significant time savings by failing over to the DRS. SPP IT staff contributed to the discussion offering insight into both the system capabilities and limitations. Agenda Item 12 NLPS Schedule Verification CJ Brown (SPP), after talking with Patty Denny (KCPL), requested the MWG discuss the NLPS verification for registered resource maximums. The logic to prevent Market Participants from entering NLPS greater than a resource max in RTOSS has been turned off. Patty Denny (KCPL) feels this may be a problem because it could allow a Market Participant to accidently submit a very large NLPS, or enable 3 3 of 132

4 Minutes No. 157 an abuse of the NLPS tool. After discussing the issue, the MWG requested SPP turn the logic back on to verify resource maximums for NLPS to allow an additional layer of protection for Market Participants. SPP Operations staff will prepare a statement explaining the intent to turn the logic on in OATI and provide the information to the MWG, CWG, and Member Primary point of contacts list. Agenda Item 13 Dead Bus Logic Discussion Gary Cate (SPP) provided information on a new issue SPP operations staff has discovered related to offline resource shift factors (Attachment 15 Offline Resource Price Calculation_ ). After the implementation of the Phase 3 patch on 2/22/2011, Market Participants began experiencing large price divergences on their offline units. It was especially noticeable for the units electrically located at the same bus. There should not have been price divergence in that situation. After investigation, it was determined the issue was related to a piece of the Phase 3 patch. In this patch, shift factor rotation was moved from SPD to SFT. However, when doing this change, the code left the shift factors that were for offline units out of the rotation which caused the offline resource shift factors to be non-rotated, and in some cases different from surrounding elements. The issue was reported to the MOS vendor on 3/1/2011 and by 3/4/2011 the vendor reported the cause of the problem back to SPP. The vendor proposed a couple of solutions and SPP has already started testing a patch. As a result of the problem, re-pricing will be necessary. SPP staff will follow up with the actual magnitude of the re-pricing implications for the April MWG meeting. Agenda Item 14 MWG Action Items Review The latest action items had not been updated so this agenda was not addressed and will be added to the April MWG meeting. Agenda Item 15 Revision Requests It was decided during the discussion of Protocol Revision Requests to name PRRs pertaining to the Integrated Marketplace Protocols MPRRs, short for Marketplace Protocol Revision Requests. MPRR1 Removal of Internal Reserve Zone Transfers and Reserve Zone Minimum Clause Wayne Camp (Accenture) introduced MPRR1 (Attachment 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause) to the group in response to the motion from the March 8-9 MWG meeting to remove internal reserve zone transfers and a specific reserve zone minimum clause from the Integrated Marketplace Protocols. He requested expedited on the MPRR in order to waive the required 14 day comment period. Darrell Wilson (OGE) motioned and John Varnell (Tenaska) seconded to expedite MPRR1. The motion passed with no abstentions or oppositions. Next, Wayne Camp (Accenture) walked through each area in the Protocols the language needed to be changed, including the Settlements appendix. After review of the language, Darrell Wilson (OGE) motioned and Shah Hossain (Westar) seconded to approve MPRR1. The motion passed with four oppositions from Gene Anderson (OMPA), Aaron Rome (Midwest), Jessica Collins (Xcel), and Matt Moore (GSE) and one abstention from Tenaska (John Varnell). PRR 215 Darrell Wilson (OGE) presented revised language on PRR 215 for the group to review (Attachment 17 PRR 215 OG&E Comments _2). Some members voiced concern that the revised language may create additional confusion, counter to the intent of the PRR. After considerable discussion, the group struggled with how to improve the language. Gene Anderson (OMPA) motioned and Jessica Collins (Xcel) seconded to reject PRR 215. The motion passed with two oppositions from Darrell Wilson (OGE) and Richard Ross (AEP) and four abstentions from Bruce Walkup (AECC), John Varnell (Tenaska), Josh Kirby (WFEC), and Patty Denny (KCPL). PRR 216 Notification of New Registration This PRR is tabled until SPP receives a FERC Order on Demand Response. 4 4 of 132

5 Minutes No. 157 PRR 221 Validation of Profit Prior to Applying Under Scheduling Disgorgement Logic Due to time constraints this PRR was not discussed during the meeting. It will be added to the April MWG meeting. PRR 227 Keep Whole Payments for Out of Merit Commitment Due to time constraints this PRR was not discussed during the meeting. It will be added to the April MWG meeting. PRR 232 Handling of Incorrect Schedule Adjustments Due to time constraints this PRR was not discussed during the meeting. It will be added to the April MWG meeting PRR 234 RCF Exception for Market Flow Priority Casey Cathey (SPP) introduced PRR 234 (Attachment 18 PRR234 RCF Exception for Market Flow Priority) and requested expedited and urgent status of the PRR to waive the 14 day comment period and allow implementation (as quickly as possible) for more equitable treatment of market flow relief obligation for SPP Market Participants on Reciprocally Coordinated Flowgates(RCFs). After discussion on the status of the PRR, Jessica Collins motioned (Xcel) and Gene Anderson (OMPA) seconded to wave notice for this meeting and support expedited and urgent status for PRR 234. The motion passed with two oppositions from Rick Yanovich (OPPD) and Shah Hossain (Westar) and no abstentions. Next, the group discussed the PRR language and asked questions. The PRR removes language that utilizes the lower of the adjusted Allocation methodology and the net impact of CAT schedules on all coordinate flowgates and assigns to only to RCFs. After discussion, Shah Hossain (Westar) motioned to approve PRR 234 and Patty Denny (KCPL) seconded to approve PRR 234. The motion passed with one opposition from Rick Yanovich and no abstentions. Agenda Item 16 Integrated Marketplace Program Update Due to time constraints this item was not discussed during the meeting. It will be added to the April MWG meeting. Agenda Item 17 Review of Motions, Action Items, and Future Meetings Motions Agenda Item 5: MWG Recommendation to MOPC Report Darrell Wilson (OGE) motioned and Aaron Rome (Midwest Energy) to approve the recommendation as outlined in the MWG recommendation report to MOPC: The MWG recommends proceeding with implementation of the Integrated Marketplace design as accepted by MOPC at their January 12, 2011 meeting with the following modifications: 1. Explicitly describe the process for adjusting the ARR nomination caps 2. Remove the provision allowing the Reserve Zone internal obligation transfers 3. Remove the provision allowing an operating Reserve Zone minimum to be equal to the available Operating Reserve in a zone. The motion passed with two abstentions from Gene Anderson (OMPA) and Richard Ross (AEP) and no oppositions. Agenda Item 11 Revision Requests: MPRR1 Darrell Wilson (OGE) motioned and John Varnell (Tenaska) seconded to expedite MPRR1. The motion passed with no abstentions or oppositions. Agenda Item 11 Revision Requests: MPRR1 Darrell Wilson (OGE) motioned and Shah Hossain (Westar) seconded to approve MPRR1. The motion passed with four oppositions from Gene Anderson (OMPA), Aaron Rome (Midwest), Jessica Collins (Xcel), and Matt Moore (GSE) and one abstention from Tenaska (John Varnell). 5 5 of 132

6 Minutes No. 157 Agenda Item 11 Revision Requests: PRR 234 Jessica Collins motioned (Xcel) and Gene Anderson (OMPA) seconded to wave notice for this meeting and support expedited and urgent status for PRR 234. The motion passed with two oppositions from Rick Yanovich (OPPD) and Shah Hossain (Westar) and no abstentions. Agenda Item 11 Revision Requests: PRR 234 Shah Hossain (Westar) motioned to approve PRR 234 and Patty Denny (KCPL) seconded to approve PRR 234. The motion passed with one opposition from Rick Yanovich and no abstentions. Agenda Item 11 Revision Requests: PRR 215 Gene Anderson (OMPA) motioned and Jessica Collins (Xcel) seconded to reject PRR 215. The motion passed with two oppositions from Darrell Wilson (OGE) and Richard Ross (AEP) and four abstentions from Bruce Walkup (AECC), John Varnell (Tenaska), Josh Kirby (WFEC), and Patty Denny (KCPL). Action Items Agenda Item 4 SPP-MISO Settlements Comparison SPP staff to return with a presentation with examples of operational improvements for the SPP Integrated Marketplace compared to MISO related to operational concerns. Shah Hossain (Westar) to provide specific concerns for SPP staff to address in the presentation. Future Meetings Joint MWG/RTWG meeting March 30, 2011 (9 a.m. - 5 p.m.) Location: AEP Offices Room: 42nd Floor, Florence Room April 18, 2011 (1 p.m. - 5 p.m.) April 19, 2011 (8:15 a.m. - 5 p.m.) April 20, 2011 (8:15 a.m p.m.) Location: AEP Office Room: 8th Floor May 16, 2011 (1 p.m. - 5 p.m.) May 17, 2011 (8:15 a.m. - 5 p.m.) May 18, 2011 (8:15 a.m p.m.) Location: AEP Office Room: 8th Floor Agenda Item 18 Adjournment Richard Ross (AEP) thanked everyone and adjourned the meeting at 12:01pm. Respectfully Submitted, Debbie James Secretary 6 6 of 132

7 In Person = By Phone = X * Market Working Group March 21-23, 2011 By Proxy = Dallas, TX Attend Attend Attend Full Name Company Business Phone Other Phone Day 1 Day 2 Day 3 X X X Richard Ross (Chair) AEP rross@aep.com (918) (918) * * * Keith Sugg (V-Chair) AECC ksugg@aecc.com (501) X X X Debbie James (Sec.) SPP djames@spp.org (501) X X X Aaron Rome Midwest Energy (785) * * * Ann Scott Tenaska ascott@tnsk.com (817) X X X Darrell Wilson OGE wilsondw@oge.com (405) X X X Gene Anderson OMPA geneaengr@aol.com (405) * * * James Liao WFEC j_liao@wfec.com (405) Jessica Collins Xcel Energy jessica.l.collins@xcelenergy.com (303) (303) X X X Lee Anderson LES landerson@les.com (402) * * * Michael Wise Golden Spread Electric Coop mwise@gsec.coop (806) Patty Denny KCPL patricia.denny@kcpl.com (816) Randy Gillespie Kelson Energy randy.gillespie@kelsonenergy.com (443) Rick McCord EDE rmccord@empiredistrict.com (417) Rick Yanovich OPPD (402) X X X Shah Hossain Westar Shah_Hossain@wr.com (785) Alan Adams Utilicast contractor-aadams@spp.org Alan McQueen SPP Barry Spector Wright Talisman X Bart Tsala PCI btsala@powercosts.com (405) Ben Hefner SPP bhefner@spp.org Bill Nolte SECI bdnolte@sunflower.net (420) Bill Olson Xcel Energy bill.olson@xcelenergy.com Brenda Harris Oxy brenda_harris@oxy.com Brent Hebert Horizon Wind brent.hebert@horizonwind.com (713) Brett Kruse Calpine Brian Holmes Structure brian.holmes@thestructuregroup.com X X X Bruce Walkup AECC bwalkup@aecc.com (501) Bryn Wilson OGE wilsonwb@oge.com Carrie Cooper ETEC carrie.cooper@gdsassociates (770) X X X Carrie Simpson SPP csimpson@spp.org (501) Casey Cathey SPP ccathey@spp.org (501) CJ Brown SPP cbrown@spp.org Charles Waso cwaso@aol.com Chris Casale Iberdrola chris.casale@iberdrolausa.com Chris Jones Duke Energy chris.jones@duke-energy.com Chris Werner AEP cmwerner@aep.com Cliff Franklin Westar Cody Parker SPP cparker@spp.org Danielle Strain AECI dstrain@aeci.org Dave Savage RES-Americas david.savage@res-americas.com X X David Charles Basin Electric Power Co. dcharles@bepc.com com (701) David Hackett KEMA dhackett@us.kema.com (321) Derek Mosolf MCG Energy dmosolf@mcgenergy.com Doug Clark AEP dclark@aep.com Dowell Hudson SPP dhudson@spp.org Ed Hammons GRDA ehammons@grda.com Eric Jensen AREVA Farrokh Rahimi OATI farrokh.rahimi@oati.net (615) Gary Cate SPP gcate@spp.org Gay Anthony SPP ganthony@spp.org George Fee AEP George Kelly Accenture Gordon Scott EPIC Merchant Energy (281) Heather Starnes SPP hstarnes@spp.org Jack Moore SPP jmoore@spp.org Jaime McAlipine Chermac Energy mcalpinekl@chermacenergy.com James Fife PSI/EPV jfife1@entergy.com (281) James Sanderson KCC j.sanderson@kcc.ks.gov (785) Jessica Zahnow Argus Media jessica.zahnow@argusmedia.com Jim Guidroz Supervisor of Tariff Administration jguidroz@spp.org (501) X X X Jim Krajecki Customized Energy Solutions jkrajecki@ces-ltd.com Jim Stevens PSI/EPV jim@psisoft.net (713) JJ Guo AEP jguo@aep.com Jodi Woods SPP jwoods@spp.org Joe Taylor Xcel Energy josepth.c.taylor@excelenergy.com (303) John Baum Novis John Harvey John Deere Renewables harveyjohna@johndeere.com (515) (515) John Hyatt SPP jhyatt@spp.org John Luallen SPP jluallen@spp.org John Stephens City Utilities John.Stephens@cityutilities.net (417) John Stonebarger WAPA stonebarger@wapa.com John Sturm Aces Power Marketing (APM) jsturm@acespower.com (317) X X X John Varnell Tenaska jvarnell@tnsk.com (817) Jon Sunneberg NPPD jmsunne@nppd.com Josh Phillips SPP jphillips@spp.org X X X Joshua Kirby WFEC j_kirby@wfec.com (405) (405) Karen Thomas SPP kthomas@spp.org Katherine Prewitt SPP kprewitt@spp.org Kathy Schuerger Xcel Energy kathy.schuerger@xcelenergy.com Ken Donald Utilicast 7 of 132

8 In Person = X Market Working Group By Phone = By Proxy = * March 21-23, 2011 Dallas, TX Attend Attend Attend Full Name Company Business Phone Other Phone Day 1 Day 2 Day 3 Kim Farris SPP kfarris@spp.org Kristen Rodriguez Electric Power Engineers/Wind Coalition krodriguez@epeconsulting.com (254) Liam Noailles Xcel Energy Lyman Wilkes PSI/EPV lwilkes@psisoft.net (713) Mak Nagle SPP mnagle@spp.org X X X Marisa Choate SPP mchoate@spp.org (501) Mark Watson Platts markham_watson@platts.com Mark Wiggins PCI mwiggins@powercosts.com Mary Jo Montoya Xcel Energy mary.j.montoya@xcelenergy.com (303) X X X Matt Johnson TEA Matt Moore Golden Spread Electric Coop Matt Pawlowski NextEra Matt Wolf Entergy EMO Mark Lawlor Right of Wind Melissa Rinehart SPP mrinehart@spp.org Mike Mushrush OMPA mmushrush@ompa.com Mitch Williams WFEC m_williams@wfec.com Naomi Zottoli SPP nzottoli@spp.org Patti Kelly SPP pkelly@spp.org (501) Patty Harrell DC Energy harrell@dc-energy.com Paul Dietz Westar paul.a.dietz@ westarenergy.com Pete Kinney WAPA kinney@wapa.gov (605) Philip Bruich SPP pbruich@spp.org X X Phyllis Bernard SPP Board of Directors phyllis_bernard@sbcglobal.net Randy Root GRDA rroot@grda.com X X X Richard Dillon SPP rdillon@spp.org (501) Ron Chartier SECI rchartier@sunflower.net (785) X X X Ron Thompson NPPD rfthomp@nppd.com (402) Roy Klusmeyer WFEC X X X Roy True Aces Power Marketing (APM) royt@acespower.com (317) Ryan Garrett SPP rgarrett@spp.org Russ McRae ARVEA X Sam Ellis SPP sellis@spp.org Sam Kwong Edison Mission skwong@edisonmission.com Scott Smith SPP ssmith@spp.org Shari Brown SPP sbrown@spp.org Sonya Hall SPP shall@spp.org (501) Soren Nielsen nielsensoren@yahoo.com Steve Gaw Wind Coalition steve@windcoalition.org (573) Steve Haun shaun@les.com Stacy Rodgers SAIC stacy.l.rodgers@saic.com (214) Steve McDonald Aces Power Marketing g( (APM) smcdonald@acespower.com (317) Stuart Rein Boston Pacific srein@bostonpacific.com Tom Burke Aces Power Marketing (APM) tburke@acespower.com (512) Tom Fritsche SPP tfritsche@spp.org Tony Alexander SPP talexander@spp.org Tony Delacluyse PCI tony@powercost.com Trent Carlson JP Morgan trent.a.carlson@jpmorgan.com Trey Fleming SAIC trey.s.fleming@saic.com (713) Ty Mitchell SPP tmitchell@spp.org Tyler Wolford TEA twolford@teainc.org (904) X X Walt Shumate Shumate & Associates waltshumate@sbcglobal.net (512) Walt Yeager Duke Energy walt.yeager@duke-energy.com X X X Wayne Camp Accenture wayne.camp@accenture.com (856) Wendell Drost Alstom wendell.drost@areva-td.com (318) Wenchun Zhu Wind Capital Group zxhu@windcapitalgroup.com of 132

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10 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 21-23, 2011 AEP Offices / Dallas, TX AGENDA Day 1 1:00 p.m. 5:00 p.m. 1. Call to Order, Proxies, Agenda Discussion... Richard Ross 2. Review Position Papers... All a. Marginal Loss Allocation b. Transmission Cost Management 3. SPP Staff Recommendation on Implementation Date & Combined-Cycle to MOPC... Sam Ellis 4. SPP-MISO Settlements Comparison... Wayne Camp Day 2 8:15 a.m. 5:00 p.m. 5. MWG Recommendation to MOPC Report... All 6. RTO/ISO Forklift Option... Bart Tsala 7. Minutes Approval (Feb 15-17, March 8-9, March 14-15)... Richard Ross 8. Working Group/Committee Updates... Richard Ross 9. Regulatory Update... Patti Kelly 10. MMU EIS Update... John Hyatt Day 3 8:15 a.m. 12:00 p.m. 11. April 2 Outage & Analysis of Failover to Disaster Recovery Systems... Casey Cathey/CJ Brown 12. NLPS Schedule Verification... Casey Cathey/CJ Brown 13. Dead Bus Logic Discussion... Casey Cathey Relationship-Based Member-Driven Independence Through Diversity Evolutionary vs. Revolutionary Reliability & Economics Inseparable 10 of 132

11 14. MWG Action Items Review... Debbie James 15. Revision Requests (PRR submitter should be available)... Richard Ross a. PRR 215 Registration of Transmission Impacting Resources (Darrell Wilson, OGE) b. PRR 216 Notification of New Registration (Shah Hossain, Westar) Tabled until FERC Order on Demand Response c. PRR 221 Validation of Profit Prior to Applying Under Scheduling disgorgement Logic (Jessica Collins, Xcel) d. PRR 227 Keep Whole Payments for Out of Merit Commitment (Ann Scott, Tenaska) e. PRR 232 Handling of Incorrect Schedule Adjustments (Richard Ross, AEP) f. Marketplace-PRR1 Removal of Internal Reserve Zone Transfers and Reserve Zone Minimum Clause (Debbie James, SPP) g. PRR 234 RCF Exception for Market Flow priority (Casey Cathey, SPP) 16. Integrated Marketplace Project Status Update... Debbie James 17. Review of Motions, Action Items and Future Meetings... Debbie James 18. Adjournment... Richard Ross Relationship-Based Member-Driven Independence Through Diversity Evolutionary vs. Revolutionary Reliability & Economics Inseparable 11 of 132

12 Marginal Loss Allocation March 2011 Market Working Group 12 of 132

13 Revision History Date or Version Number Author Change Description Comments 2/15/2011 Richard Dillon Initial Draft 3/02/2011 Market Design MWG updates 3/09/2011 MWG MWG suggested changes 13 of 132

14 Southwest Power Pool, Inc. Market Working Group Table of Contents Revision History...1 Executive Summary...3 Definition of Issue...3 Boston Pacific Comments...3 Transmission Losses...3 a. Primer... 3 b. Our Recommendation... 4 c. Cautions and Work Plan... 4 SPP MMU Comments...5 Marginal Loss Method...5 MWG Analysis...6 MWG Response and Conclusion...6 MWG Vote...7 Marginal Loss Allocation 2 14 of 132

15 Southwest Power Pool, Inc. Market Working Group Executive Summary The Integrated Marketplace design includes marginal losses as part of the dispatch logic and the settlement. The objective of the marginal loss design is to reduce the cost of the delivered energy to the load while capturing the impact of losses on the network buses net injections. This functionality is included in the other RTO/ISO markets. Since the rate for losses is marginal, the normal tendency is that the net collections will be an excess. Different methodologies are used in the RTO/ISO markets for the allocation of the net collections to Market Participants. In order to balance economic incentives with recognition that Market Participants are paying the fixed costs of the transmission grid, a loss pool based overcollection allocation approach was chosen by the MWG. Improvements were also made on the methodology to address gaming issues and other inefficiencies experienced at other RTOs. The loss pool based overcollection allocation methodology is consistent with an approach approved by FERC. Both Boston Pacific and the SPP Market Monitoring Unit endorse the use of marginal losses in the dispatch solution. Boston Pacific proposes the use of a direct refund based overcollection allocation methodology. The SPP Market Monitoring Unit proposes removing export transactions from the overcollection allocation methodology. The MWG recommends that the Integrated Marketplace design be implemented with the loss pool based overcollection allocation methodology. Discussion with the SPP MMU resulted in removal of the recommendation to remove export transactions from the allocation methodology. Deleted: The cost of implementation of a direct refund overcollection allocation based methodology is not expected to be significantly different than that of the loss pool based allocation methodology. Definition of Issue Marginal losses are included in the dispatch and settlement logic of other RTO/ISO markets in order to improve the economic and physical delivery of energy to load. By the nature of the marginal pricing, more funds are collected than disbursed. The excess funds must be allocated to Market Participants. The loss pool based allocation methodology was chosen and is consistent with methodologies approved by FERC. Boston Pacific proposes the use of a direct refund based overcollection allocation methodology. Boston Pacific Comments Original Comments (December 2010) Transmission Losses Deleted: 2. a. Primer The intended benefit is to lower the costs of serving load by taking transmission losses Marginal Loss Allocation 3 15 of 132

16 Southwest Power Pool, Inc. Market Working Group more explicitly into account when choosing which power sources to use. Everyone understands that some of the electricity produced at a power plant over there is lost as it is transmitted to customers that use the power over here. So, for example, if we need 100 MWh to serve some customers at one location and we know we will lose 4% of the power that we send from the power plant, then we will have to actually produce about 104 MWh. Today, we generally take account of losses by recognizing the need for the extra 4 MWh this is referred to as the average loss method in which losses are modeled as additional customer load. The Integrated Marketplace proposes the use of the marginal loss method. With this method, we would take account of losses when we choose which power plants to use to meet each increase in load that is, we take account of losses from each power plant when we dispatch the system. In this way we would use a generator less if its losses made it more expensive than another source. b. Our Recommendation Boston Pacific s recommendation is to approve the proposal to use the marginal loss method except that the method for refunding over-collections would be modified as explained below under Cautions and Work Plan. One of the reasons for our recommendation to use the marginal loss method is the fact that this method is used in other RTOs and ISOs. In addition, we believe it will lower the overall production cost of electricity. Our reason for modifying the approach to refunding over-collections is that the proposed method may be unnecessarily complex. c. Cautions and Work Plan From the perspective of an advocate for simplicity, this is one of the features for which we would ask whether the complexity is worth it. That is, do the ratepayer benefits warrant the complexity of the initial software development and the complexity of the ongoing operation? This is one of the features for which we should advocate simplicity. The most complex part of the marginal loss method as proposed lies in refunding the over-collection of payments for losses. The proposal is to refund losses through a method based on loss pools. We understand that, at least in part, this complex method was proposed to accommodate the FERC opposition to direct refunds that is, refunding to each Market Participant the exact amount of over-collected losses for its account. We understand that FERC s objection is that direct refunds might blunt the incentive to minimize losses. To draw an analogy, consider the refunding of a gasoline tax a driver would not use less gasoline in response to a 50 cent per gallon gasoline tax if she knew she would simply get the 50 cents back. With electricity, however, we do not have to worry as much about blunting the incentive because the dispatch computer will always take account of marginal losses so the effect on which power plants are used has less to do with the method of refunding over-collected losses. Given this, we recommend that SPP promptly approach the FERC about allowing direct refunds. Then, presuming direct refunds are easier and less costly to implement than the loss pool approach, the proposal would be modified. Updated Comments (March 1, 2011) We recommended in our report that SPP (a) discuss with FERC the possibility of allowing a direct refunds approach to distributing over-collected transmission loss revenues and (b) implement a direct refunds approach if it would be easier and less costly to implement than the loss pool Marginal Loss Allocation 4 16 of 132

17 Southwest Power Pool, Inc. Market Working Group approach. We made this recommendation because the loss pool approach is very complex and we were under the impression that SPP and MWG arrived at its loss pool method because it wanted to accommodate the FERC opposition to direct refunds. However, after discussions with you and, separately, MWG, we now understand that the MWG and SPP believe that the loss pool method actually is viewed as the simplest method possible to implement direct refunds. We were also assured that in coming to this conclusion, the MWG and Staff looked into other direct refund methods. This new understanding alleviates our concerns. We also noted a few concerns in our report that result from utilizing a complex transmission loss distribution methodology. First, we noted that it would be extremely difficult for participants to perform shadow settlement calculations to ensure that they are receiving the correct allocation of loss revenues. We have since been told by Staff that all of the billing determinants needed for shadow settlement calculations will be provided to participants along with sample calculations. Second, we noted that because of the complex method for allocating loss revenues, SPP must be careful that the method chosen does not allow for gaming opportunities. As an example of gaming, we noted the gaming issues that took place in PJM. MWG and Staff have since informed us that the Market Monitor is aware of these concerns and will be vigilant in monitoring for gaming opportunities. These accommodations alleviate our concerns. Marginal Loss Method SPP MMU Comments Marginal loss pricing is a well-accepted and widely implemented methodology used to incorporate transmission losses into energy dispatch and pricing. Transmitting energy always results in some loss of power due to resistance of the transmission elements. These losses increase with the distance the power travels. Given SPP s expansive footprint - in which power may travel from Northwest Arkansas to the Texas Panhandle, or from Nebraska to Louisiana - transmission losses affect the efficiency of the dispatch. To further explain the issue, consider an example in which: MW load is located next to Generator A that produces at $31/MWh - Generator B is located some distance away and produces at $30/MWh Without accounting for transmission losses, dispatch will serve the load with Generator B since it offers the cheaper price. However, due to transmission losses, this may not be the efficient choice. If there is a transmission loss of 4 MW: - Generator B will have to generate 104 MW to serve the 100 MW load - Serving load from Generator B would cost $30 x 104 = $3,120 - Serving load with Generator A would cost $31 x 100 = $3,100 Marginal Loss Allocation 5 17 of 132

18 Southwest Power Pool, Inc. MMU Position Market Working Group The MMU supports pricing transmission losses at their marginal cost. The efficiency of marginal loss methodology in energy dispatch and pricing is well documented. This method is widely used in other RTO markets. Marginal cost pricing of transmission losses results in the RTO over-collecting. Due to the physical relationship between flow on the transmission line and losses, the marginal cost is approximately double the average cost of transmission losses. When losses are priced at marginal cost, the revenue exceeds the total cost of transmission losses. The proposed design uses a loss pool approach to allocate excess revenue back to the load settlement locations. A loss pool approach has been implemented at the Midwest ISO. The MMU supports the loss pool approach for allocating over-collections. Allocating the overcollection is a delicate issue. The excess should be returned to the parties that paid the transmission grid s fixed costs. However, if the allocation is not far enough removed from an individual Market Participant s transactions, the allocation method can alter the Market Participant s incentives and behavior. Ideally, the Market Participant should operate under the assumption that its behavior will not affect their allocation. In practice, this is difficult to achieve, but the loss pool approach is a valid method. The MMU does have one concern regarding the treatment of export transactions in the allocation. Under the proposed design it may be possible for a Market Participant to increase its allocation amount by scheduling exports out of the SPP footprint. The MMU recommends removing export transactions from the allocation methodology. MWG Analysis The MWG discussed with the SPP MMU the concerns regarding export transactions. Export transactions will still require acquisition of point-to-point transmission service. The transmission service charges offset the potential benefit of the loss allocation. The SPP MMU felt that the concern was adequately addressed without changing the loss allocation methodology. MWG discussed the Boston Pacific concerns related to the complexity of the loss pool methodology. Through the development of the Protocols, MWG worked diligently to develop and document an overcollection allocation methodology that would be fair. MWG believes the current method results in refunds that closely resemble a direct refund approach and in the simplest fashion that the group can conceive. Deleted: associated with the service Deleted: Deleted: MWG Response and Conclusion The MWG agrees with the direct refunding principles, and believes that the loss pool based overcollection allocation approach is the simplest approach to achieving the proper overcollection allocation. (Do we need to explain why?) Although it may appear complex, the allocation method has been developed and documented in the Protocols and provides a more equitable distribution of revenues compared to a load ratio share methodology. Deleted: While it agrees Deleted: the MWG Deleted: Marginal Loss Allocation 6 18 of 132

19 Southwest Power Pool, Inc. Market Working Group MWG Vote MWG motioned to approve the Boston Pacific recommendation that the overcollection allocation method should be modified. The motion failed with no approving votes and two abstentions. MWG motioned to agree with the direct refunding philosophy and believes that the loss pool approach is the simplest approach to achieving the proper overcollection allocation. The motion passed with no oppositions or abstentions. SPP staff supports the MWG s position on the overcollection allocation method. Marginal Loss Allocation 7 19 of 132

20 Transmission Cost Management March 2011 Market Working Group 20 of 132

21 Revision History Date or Version Number Author Change Description Comments 3/14/2011 Market Design Initial draft 21 of 132

22 Southwest Power Pool, Inc. Market Working Group Table of Contents Revision History...1 Executive Summary...3 Definition of Issue...3 Boston Pacific Comments...3 SPP MMU Comments...5 SPP Staff Comments...5 MWG Analysis...5 MWG Response and Conclusion...6 MWG Vote...6 Reserve Zones 2 22 of 132

23 Southwest Power Pool, Inc. Market Working Group Executive Summary The Integrated Marketplace design allows Market Participants to participate in the Transmission Congestion Rights process; given the applicable credit requirements have been met. A Transmission Congestion Right is a financial instrument that entitles the holder to the difference in the congestion components of LMP in the Day-Ahead Market at the sink and source identified on the TCR. TCRs are intended to provide a hedge for Market Participants against congestion costs and facilitate the optimal unit commitment because it incents Market Participants to participate in the Day-Ahead Market. Boston Pacific agrees with the Integrated Marketplace design to introduce TCRs and ARRs to address transmission congestion costs but also offers a few cautions. Boston Pacific requests SPP ensure vigilant market monitoring, comply with FERC Orders 741 and 681, and requests MWG to develop language to address load migration for ARR Nomination Caps. MWG agrees with the Boston Pacific concerns and expects SPP to comply with FERC Orders 681 and 741. Additionally, MWG believes the SPP MMU has the necessary rules in place to ensure appropriate Market Mitigation measures and the MWG plans to alter the Protocol language for ARR nomination caps to create more explicit language. As a result of discussions with the MWG and SPP staff, Boston Pacific noted in their comments received March 1, 2011, as detailed below, that their recommendations have been satisfied in full. Definition of Issue Boston Pacific requests SPP ensure vigilant market monitoring, comply with FERC Orders 741 and 681, and requests MWG to develop language to address load migration for ARR Nomination Caps. FERC Order 681 subjects SPP to require long term transmission rights. FERC Order 741 requires SPP to modify its current unsecured credit requirements to comply with unsecured credit cap requirements. Original Comments (December 30, 2011) Transmission Congestion Cost Management a. Primer Boston Pacific Comments Today, the protection against paying for congestion is provided by scheduling ( physical transmission rights ). As background, note that, when there is transmission congestion, the locational imbalance prices (LIPs) include a component for congestion costs. Today, say a utility schedules the delivery of 100 MWh of power on a certain portion of the SPP transmission system. If it keeps with its schedule that is, it actually delivers 100 MWh in real-time the utility does not pay the LIP so it does not pay for Reserve Zones 3 23 of 132

24 Southwest Power Pool, Inc. Market Working Group congestion. Only to the extent that it deviates from its physical schedule does the utility pay the LIP and, thereby, pay for congestion; for example, if it delivers 95 MWh it would pay the LIP (including the congestion component) to buy 5 MWh. With the Integrated Marketplace, the protection against paying for congestion is achieved through Transmission Congestion Rights, or TCRs. Put simply, the holder of the TCR is entitled to a refund of the congestion component of the Day-Ahead locational marginal price (LMP). As to the higher-valued use, this reflects the fact that the Market Participants who are originally assigned the transmission rights that is, assigned the Auction Revenue Rights, or ARRs can sell those rights to others through the Annual and Monthly TCR Auctions. The thought is that the willingness to purchase the congestion protection at a higher price may reflect higher-valued transactions. Plus, this facilitates optimal unit commitment because it encourages Market Participants to participate in the Day-Ahead Market since they will be protected from paying congestion regardless of whether or not their physical resources are dispatched. b. Our Recommendation Boston Pacific s recommendation is to approve the approach proposed to address transmission congestion costs. This recommendation is based, in part, on the fact that ARRs and TCRs are not new and have been used by several other RTOs and ISOs. In addition, (a) since it is based on historical firm transmission use, the initial allocation should be fair, (b) the transmission rights are unlikely to be oversold, and (c) as noted above, there are ratepayer benefits that can accrue including protection from paying congestion costs and possible higher-valued used of the transmission system. c. Cautions and Work Plan Our first two cautions are driven by the fact that the ARR and TCR proposals give rise to other requirements that SPP will have to meet. The third is driven by the fact that TCRs increase the incentive for market power abuse. The fourth points to language that the Federal Energy Regulatory Commission (FERC) might find gives SPP too much discretion. The first caution concerns credit requirements for those participating in the TCR auctions. There was an incident in another RTO that helped prompt the FERC to issue new credit requirements in Order No. 741, dated October SPP will now have to comply with that Order. The second caution is that it appears SPP will now have to address long-term transmission rights. With its Integrated Marketplace proposal, SPP may now be considered an organized electricity market and, as such, will have to comply with Order No The third caution is that the addition of TCRs increases the potential payoff from a generating company causing congestion. Recall that a generator in a congested area can benefit if congestion drives up the LMP. Now that generator can also benefit if congestion increases the price paid for its TCRs. The action required in response to this caution is more vigilance by the Market Monitoring Unit (MMU) going 1 Credit Reforms in Wholesale Electric Markets, Order No. 741, 133 FERC 61,060 (2010) (Order No. 741). 2 Long-Term Firm Transmission Rights in Organized Electric Markets, Order No. 681, FERC Stats. & Regs. 31,226 (2006), reh g denied, Order No. 681-A, 117 FERC 61,201 (2006) (collectively, Order No. 681). Reserve Zones 4 24 of 132

25 Southwest Power Pool, Inc. Market Working Group forward. The fourth caution is that FERC may find SPP s proposal for adjusting the ARR nomination cap gives SPP too much discretion. Moderate changes in language would take care of this. Updated Comments (March 1, 2011) In our report, we made four recommendations related to congestion costs: 1) comply with FERC Order 681; 2) comply with FERC Order 741; 3) ensure MMU vigilance related to TCRs; and 4) develop more specific language for adjusting the ARR nomination cap. Our understanding from the conference call is that MWG has voted to adopt, or is already in the process of adopting, each of our recommendations. These actions address our recommendations in full. None SPP MMU Comments SPP Staff Comments SPP staff supports the Boston Pacific recommendation and the MWG decisions related to Transmission Cost Management. MWG Analysis In regards to the concerns related to complying with FERC Orders 681 and 741, the MWG agrees SPP must supply comply with the Orders following the Integrated Marketplace implementation. The MWG has action item to re-visit the subject of Long-Term Transmission Rights starting in January 2012 to consider whether changes are needed in the Marketplace, and make appropriate filings. Also, SPP staff is developing credit requirement rules, in coordination with the Credit Practices Working Group, consistent with Order 741. In response to Boston Pacific s concern regarding the potential for gaming, MWG believes the SPP Market Monitoring Unit s market mitigation measures are consistent with other RTO/ISO markets and the Market Monitor will monitor for gaming concerns. The Market Power Mitigation and Monitoring section of the Integrated Marketplace Protocols provides for the capping of Energy, Start-Up, and No-Load offers. The caps will be applied when and where Market Participants possess local market power. Mitigation Measures can also be applied to physical parameter offers. The offer caps and physical parameter mitigation measures will limit the ability of a Market Participant to manipulate the value of TCRs through economic physical withholding. The MWG agrees with Boston Pacific s recommendation to make language under Section 5.1.3(1) of the Integrated Marketplace Protocols more explicit regarding adjustments to Nomination Caps to account for transfers of load among Transmission Customers. A Protocol Revision Request will be created to address the issue. Reserve Zones 5 25 of 132

26 Southwest Power Pool, Inc. Market Working Group MWG Response and Conclusion MWG agrees with the Boston Pacific concerns and recommendations related to Transmission Cost Management. SPP will comply with FERC Orders 681 and 741 and MWG has an action item to consider Long-Term Transmission Rights in January 2012 and will be working with the CPWG to address credit related requirements. Additionally, MWG believes the SPP MMU has the necessary rules in place to ensure appropriate Market Mitigation Measures. Finally, the MWG plans to alter the Protocol language for ARR nomination caps to create more explicit language to handle Boston Pacific s concerns. MWG Vote MWG motioned to accept the Boston Pacific recommendation related to Transmission Cost Management. The motion passed with no oppositions or abstentions. Reserve Zones 6 26 of 132

27 Southwest Power Pool, Inc. INTEGRATED MARKETPLACE STAFF Recommendation to the Markets and Operations Policy Committee April 12, 2011 Target Integrated Marketplace Implementation Date and Combined Cycle Enhanced Functionality Background Since 2007 the Market Working Group (MWG) has been developing the design for the Integrated Marketplace. The mid-level design was presented to the Markets and Operations Policy Committee (MOPC) in January Integrated Marketplace Protocols began development in December 2009 and were presented to the MOPC in October 2010, with an update for final acceptance by the MOPC in January In late 2010 the SPP Board of Directors directed staff to implement the market no later than 1 st Quarter That timeline helps support other strategic goals of the organization, most notably supporting various membership expansion possibilities, and it provides an opportunity to realize most of the cost savings associated with the market design as early as possible. Given typical equipment maintenance and congestion patterns, SPP staff proposes that the project scope be managed to support an implementation date of March 1, Based on discussions with vendors, consultants and others with experience in Day 2 type markets, SPP staff is confident that most of the scope proposed in the Marketplace Protocols can be implemented by this date. However, staff has expressed that there is significant risk to the Marketplace program due to the software design, development and testing efforts associated with the Combined Cycle functionality as currently outlined in the Marketplace Protocols. Boston Pacific has also expressed concerns with the complexity and risk of the Combined Cycle design. Combined Cycle generation can operate in several configurations, providing different levels of output and economic efficiency. The ability to move between configurations requires advance notice and consideration of cost recovery. Midwest ISO s design supports the ability for Market Participants to model Combined Cycle plants in multiple configurations with the ability to choose which configuration to offer into the market ( Standard Design ). Recently, other markets have included enhanced handling for Combined Cycle generation that allows the unit commitment engine to select from simultaneously offered multiple configurations of Combined Cycle plants as well as the ability to alter the configuration of plants when economically efficient to do so ( Enhanced Design ). ERCOT went live with the Enhanced Design for Combined Cycle units in December 2010 while CAISO went live in February The MWG decided in October 2009 to pursue the Enhanced Design that was proposed at ERCOT and requested that staff assess the impact on the Marketplace program for the Enhanced Design. In August 2010, staff discussed with the MWG that the Enhanced Design would likely impact the timeline by three to six months at an incremental cost of $5 to $10 million. Staff recommended the Standard Design in lieu of what is outlined in the Marketplace Protocols. The MWG discussed the implementation risk and continued to support the inclusion of the Enhanced Design at the start of the Integrated Marketplace. 27 of 132

28 Analysis Combined Cycle generation comprises % of the energy production within the SPP region. With the current generation penetration, and anticipated expansion of that penetration, special handling of Combined Cycle generation is necessary. The Enhanced Design would increase the benefits through a more fluid evaluation of multiple configurations. The Integrated Marketplace has anticipated the Enhanced Design for Combined Cycle resources from inception. However, the Standard Design has a lower implementation risk because it has been in operation for several years at other RTOs/ISOs, and the SPP vendor (Alstom) has experience in it. The Enhanced Design has a higher implementation risk because of SPP vendor s lack of experience in developing this feature, and reported implementation and on-going challenges at ERCOT and CAISO. SPP staff is investigating whether the PJM design would recognize much of the benefit of the Enhanced Design without adding significant risk and complexity over the Standard Design. Implementation of the Integrated Marketplace on March 1, 2014 with Combined Cycle Standard Design and deferring the Enhanced Design until March 1, 2015 allows the Market Participants to begin receiving benefits earlier. The majority of consultants will be released after implementation of the Marketplace. Deferring until after implementation allows SPP to significantly reduce consulting costs for the implementation of this feature. The timeline and cost impact of including the Enhanced Design in the initial implementation is 3 to 6 months at an estimated cost of $5 to $10 million. If the Enhanced Design is deferred to post-implementation, the cost is estimated at $5 to $7 million. Recommendation MOPC approve implementation of the Integrated Marketplace with Combined Cycle Standard Design on March 1, 2014 and implementation of the Combined Cycle Enhanced Design on March 1, of 132

29 3/31/2011 SPP MISO Settlements Comparison March 21, 2011 Market Working Group 29 of 132 1

30 3/31/2011 Settlement Feature: 5 minute Settlement MISO energy settlement is hourly and includes a black box make whole payment calculation (Price Volatility Make Whole Payment or PVMWP) PVMWP included complicated rules and eligibility requirements Very difficult to Shadow Settle as insufficient billing determinants are provided SPP 5 minute settlement eliminates the need for a PVMWP mechanism Easy to Shadow hd Settle 3 Settlement Feature: Marginal Loss Overcollection SPP over collection allocation based on Loss Pool concept, very similar to MISO except for following improvements: SPP allocates DA Market loss over collection and RTBM loss overcollection separately which more accurately reflects market participation levels as opposed to lumping DA Market and RTBM over collection together More granular Loss Pool construction (at AO level net transactional level) as opposed to Settlement Area level which produces more equitable distribution of excess funds 4 30 of 132 2

31 3/31/2011 Settlement Feature: Make Whole Payments SPP DA Market and RUC Make Whole Payments very similar to MISO except for following improvements: SPP provides separate determinants for clawbacks as opposed to embedding reductions in MWP for non performance in intermediate calculations that are not available as determinants making SPP method more Shadow Settlement Friendly. SPP provides explicit determinants for all cost and revenue calculations to facilitate Shadow Settlements. 5 Settlement Feature: Make Whole Payment Cost Allocation RUC Make Whole Payment cost allocation much improved over MISO: Explicit formulas spelled out in Protocols which are not subject to interpretation Netting at Settlement Location level allowing offsetting deviations to net to zero Hourly cost allocation based on daily rate which eliminates hourly volatility 6 31 of 132 3

32 3/31/2011 Settlement Feature: Revenue Neutrality Uplift Hourly cost allocation based on daily rate which eliminates hourly volatility 7 32 of 132 4

33 Southwest Power Pool, Inc. MARKET WORKING GROUP Recommendation to the Market and Operations Policy Committee Integrated Marketplace Protocols April 12, 2011 Organizational Roster The following members represent the Market Working Group: Richard Ross, AEP, Chairman Keith Sugg, AECC, Vice Chairman Debbie James, SPP, Secretary Aaron Rome, Midwest Energy, Inc. Ann Scott, Tenaska Power Services Co. Darrell Wilson, OGE Gene Anderson, OMPA James Liao, WFEC Jessica Collins, Xcel Energy Lee Anderson, Lincoln Electric System Michael Wise, Golden Spread Electric Cooperative Patricia Denny, KCPL Randy Gillespie, Kelson Energy Rick McCord, EDE Rick Yanovich, OPPD Shah Hossain, Westar Energy, Inc Background & Introduction The SPP Markets and Operations Policy Committee (MOPC) endorsed the baseline Integrated Marketplace Protocols at their January 12, 2011 meeting. After the baseline Protocols endorsement, the MOPC requested that the Market Working Group (MWG) evaluate whether the benefits of the SPP unique design elements are sufficient to overcome the associated implementation costs and risks as compared to existing market designs. In addition, the MOPC requested the MWG provide a recommendation regarding the design SPP should implement for consideration by the MOPC and the Board of Directors (BoD) at their April 2011 meetings. Subsequently, the MOPC and the BoD requested the MWG review and respond to the market design reports from the SPP Market Monitoring Unit (MMU) and Boston Pacific. 33 of 132

34 This Recommendation report is MWG s response to the MOPC and BoD requests. It is divided into three Sections. The first Section provides a qualitative summary analysis of the SPP Integrated Marketplace design elements and their contrast with other RTOs to address the MOPC s request to evaluate the unique elements of the Integrated Marketplace design. The second Section provides a response to the issues raised in the Boston Pacific report and the SPP MMU report. The third Section is the MWG s final recommendation on SPP s Integrated Marketplace design. MWG dedicated significant meeting time and effort to the review of these design elements. To capture the details of the issues, the different perspectives on them, and MWG s resolution of the issue, the MWG developed Position Papers on each issue. These Position Papers are provided in the appendix to this report. 34 of 132

35 Section One MWG Response Qualitative RTO Designs Comparison This section of the report scope focuses on: Key market features, Contrasting the Integrated Marketplace key market features with respect to the following RTOs : PJM, ISO-NE and MISO. The table below provides the list of key market features presented for comparison in this report and an indication as to whether their implementation in other RTOs is different than within the Integrated Marketplace. The remainder of this section describes implementation differences between the other RTOs and the SPP Integrated Marketplace in greater detail. Comment [KS1]: Just duplicates what is in table 35 of 132

36 COMMENT: FIX THE SHADING IN THE TABLE. Market Feature ISO-NE PJM MISO SPP Integrated Marketplace Day-Ahead Market * * Real-Time Market Must-Offer in Day-Ahead Market * * * 88 Make-Whole Payment * Real-Time Market Settlement * * * Operating Reserve - Reserve Zones * * * Operating Reserve External Reserve Transfer Marginal Losses * * Co-optimization * * Combined Cycle Special Handling** * * * Transmission Congestion Rights/Auction Revenue Rights (TCRs/ARRs) Jointly Owned Resources * * * Virtual Transactions Forward Capacity Market : feature exists *: feature exists, some difference with Integrated Marketplace - : feature does not exist ** : An enhanced version is included in ERCOT and CAISO and Marketplace design is based this version. 36 of 132

37 Day-Ahead Market The Day-Ahead Market feature, a financially binding process through which resources offer and loads bid for the next operating day, exists in all four RTOs with the following: Submitted resources and loads are economically cleared hourly for the next operating day, Resources cleared in the Day-Ahead Market are normally expected to be available for the Real-Time Market, Market clearing is performed by use of Security Constrained Unit Commitment (SCUC) and Security Constrained Economic Dispatch (SCED) SPP Approach Differences: In PJM and ISO-NE, the Day-Ahead Market is an energy market only. Ancillary services obligations (referred to as Operating Reserve in the Integrated Marketplace) are cleared through a different mechanism. Also, resources are required to provide a single offer which will be used for all hours of the next operating day market clearing process. Resources that clear in the Day-Ahead Market cannot change their offers for the Real-Time Market. In addition, resources are required to submit cost-based offer information. In both MISO and the SPP Integrated Marketplace, the Day-Ahead Market is an Energy and Operating Reserve cooptimized market that allows resources to submit offers that may vary on an hourly basis for the next operating day. Resources that clear in the Day-Ahead Market can change their offers for the Real-Time Market. 37 of 132

38 Real-Time Balancing Market (RTBM) The Real-Time Balancing Market is used by all regions to balance the differences between the Day-Ahead Market clearing and Real-Time actuals. In all markets, this relies upon the status of resources identified during the Day- Ahead clearing and the Reliability Unit Commitment (RUC) processes. Some of its main characteristics are: Market clearing is performed on a five-minute basis for both Energy and Operating Reserve, Market clearing of resources is based on resources offers and short-term load forecast, Market clearing is performed by use of Security Constrained Economic Dispatch (SCED). SPP Approach Differences: In PJM and ISO-NE, only Energy and Spinning Reserve are cleared within the hour, Regulation is cleared ahead of the Operating Hour. In MISO and the Integrated Marketplace, the Real-Time Balancing Market is an Energy and Operating Reserve cooptimized market within the Operating Hour. 38 of 132

39 Day-Ahead Market Must-Offer requirement A Day-Ahead Must-Offer requirement exists in all four markets. The primary purpose of this requirement is to address two issues. First, allow access to sufficient capacity to be cleared in the Day-Ahead Market so that commitments through the RUC are minimized. This is important so that the commitment decisions are made as early as possible so that sufficient resources are available to meet the reliability needs of the system. Second, produce an efficient outcome whose results converge with Real-Time Balancing Market results. SPP Approach Differences: In PJM and ISO-NE, resources with Capacity Supply Obligation (CSO) are required to participate in the Day-Ahead Market. The capacity Supply Obligation status of a resource is determined through the results of a forward capacity market. In MISO, resources described as Designated Resources (DR) are required to participate in the Day-Ahead Market. In the Integrated Marketplace, each Market Participant must offer sufficient resources to the Day-Ahead Market to cover their load plus Operating Reserve obligation to the extent the resources are available. This requirement is administered by the MMU after-the-fact using actual data. 39 of 132

40 Make-Whole Payment The Make-Whole Payment feature allows Market Participants to recover the costs of resources committed and dispatched by the RTO. This payment exists in all four markets with the following characteristics: This payment, if necessary, is intended to guarantee recovery of startup, no-load, Operating Reserve and Energy Offer costs for resources committed by the RTO, Day-Ahead Market Make-Whole payments are funded by cleared withdrawals in the Day-Ahead Market, Real-Time Market Make-Whole payments are funded by Real-Time deviations from Day-Ahead cleared amounts and Real-Time resource non-performance. SPP Approach Differences: In general, the calculation of Make-Whole Payments is the same in the Integrated Marketplace and the three RTOs studied with only some slight differences in eligibility criteria. The only noteworthy exception is that the MISO market includes a complicated Price Volatility Make-Whole Payment (PVMWP) to address issues created by its five-minute dispatch and hourly settlement. This is not necessary in the Marketplace due to the decision to conduct RTBM settlements on a five-minute basis. 40 of 132

41 Real-Time Market Settlement The Real-Time Market Settlement feature identifies charges and payments to Market Participants based upon actual meter data. The process is set such that differences in cleared commodity amounts between Day-Ahead and Real- Time markets are settled at Real-Time prices. SPP Approach Differences: In PJM, ISO-NE and MISO the real-time energy settlement calculation and reporting is performed on an hourly increment (MISO does calculate Operating Reserve settlement using five-minute pricing) using an hourly average of the five-minute real-time prices. The Integrated Marketplace design performs Real-Time settlement calculations and reporting on a five-minute increment, in complete synchronization with Real-Time market clearing. Five-Minute settlement reflects the value established for that interval for both resources and load. Five-Minute settlement for resources was chosen to financially incent Market Participants to follow dispatch instructions and offer true ramp capability. This has been addressed in other market designs through other features, for example, the Price Volatility Make-Whole Payment (PVMWP). Five-Minute settlement for load was chosen to avoid any contribution to Revenue Neutrality Uplift (RNU) and establish consistency with Demand Response resource payments. 41 of 132

42 Operating Reserve - Reserve Zones Reserves zones are defined by the RTO as areas in which a minimum amount of Operating Reserve must be procured for reliable operations. All four markets have addressed this operational concern through slightly different instruments and mechanisms. SPP Approach Differences: With the elimination of the internal Reserve Zone obligation transfers approved by the MWG, the Integrated Marketplace design is closest to the MISO approach. In addition, SPP has added functionality to facilitate the transfer of Operating Reserve obligations between Market Participants within a zone. 42 of 132

43 Operating Reserve External Reserve The SPP Integrated Marketplace design provides Market Participants with the capability to meet their Contingency and Regulation Reserve obligations within a Reserve Zone from resources external to the SPP market footprint provided that the Market Participant has the required transmission service to the SPP market footprint. SPP Approach Differences: The other RTOs studied do not allow for this type of external Contingency or Regulating Reserve treatment. The other RTO markets require the external resource supplying the Operating Reserve be Pseudo-Tied into their market footprint. The Integrated Marketplace requires Pseudo-Tied or Dynamic Scheduling for Regulating Reserve only. 43 of 132

44 Marginal Losses Marginal losses are included in the dispatch and settlement logic in order to improve the economic and physical delivery of energy to load. All four RTO markets have included this feature, however, they differ in the way the associated revenue over-collection is allocated back to Market Participants. SPP Approach Differences: PJM and ISO-NE perform loss revenue over-collection allocation on load ratio share basis and transmission service reservation basis respectively. On the other hand, MISO and the Integrated Marketplace have designed their loss revenue over-collection allocation methodology on the concept of a loss pool, which more closely represents refunds in proportion to the amount of over payment. 44 of 132

45 Co-optimization The co-optimization feature is the process by which energy and Operating Reserve offers are simultaneously cleared during market system dispatch. While all four RTOs have implemented this feature, the scope of the market processes to which it applies differs. SPP Approach Differences: In PJM and ISO-NE, energy and non-regulation reserves are co-optimized through the Real-Time market fiveminute clearing process. In MISO and the Integrated Marketplace, energy and operating reserve are co-optimized in both the Day-Ahead and Real-Time markets. 45 of 132

46 Combined-Cycle Special Handling Combined-cycle plants are resources that can operate in several configurations. PJM, ISO-NE, MISO and SPP all offer modeling paradigms for combined-cycles; however they differ in how to capture the intricate relationships between the operational configurations and select the best configuration. SPP Approach Differences: PJM, ISO-NE and MISO allow Market Participants to offer their combined-cycle plants in the market in one of the following way: Single resource model: with this option, the market system sees the resource as any other single configuration resource, Multiple resources model: the market system allows Market Participants to register or describe multiple configurations; however, the Market Participant chooses which configuration to offer. In SPP, a configuration based model is proposed for the modeling of combined-cycle resources, similar to what has been recently implemented at CAISO and ERCOT. With this model, Market Participants can submit multiple configurations and rely upon the market to select the optimal configuration. 46 of 132

47 TCRs Auctioning / ARRs Allocation The TCR Auctioning feature allows Market Participants to hedge against system congestion. In PJM, ISO-NE, MISO and SPP RTOs, the process consists of both an annual auction and some seasonal (monthly) ones. The ARRs Allocation feature allows Market Participants with verified firm transmission service to self-convert their awarded ARR into a TCR or receive a share of the TCR Auction revenues. While the feature exists in all four RTOs, the main difference in its implementation resides in the allocation methodology. SPP Approach Differences: In PJM, ISO-NE and MISO, the ARR allocation methodology is based on Market Participants historical peak load and historical generation output. In SPP, the ARR allocation methodology is based on historical peak load and firm transmission reservations. 47 of 132

48 Jointly Owned Unit (JOU) The Jointly Owned Resource feature allows Market Participants with different ownership shares on the same physical resource to participate in the markets. All studied RTOs allow for Market Participants to offer these resources to the market, but with different resource offer flexibility and market handling scopes. SPP Approach Differences: In PJM and ISO-NE, a single resource offer is allowed for a jointly owned resource. Settlement of the resource is subsequently performed on an ownership share percentage basis. In MISO, each ownership share may be offered as a separate resource, which is considered and may be committed independent of the other shares. In SPP, each ownership share may be offered as a separate resource. Each ownership share may be committed independently if the minimum operating characteristics of the JOU are not violated. Otherwise, commitment offer parameters are aggregated for the physical resource commitment decisions while dispatch decisions are based on the individual energy and operating reserve offers. 48 of 132

49 Virtual Transactions The Virtual Transactions feature provides Market Participants with the capability of hedging on price differences between the Day-Ahead and Real-Time Markets. These financial instruments are submitted only in the Day-Ahead Market, also settled in the Real-Time Market and are not required to be tied to a physical resource. The feature has been found to be designed and implemented similarly in all four studied markets. SPP Approach Differences: There are no differences between the SPP Integrated Marketplace design and the three RTOs studied regarding the allowance of virtual transactions in the Day-Ahead Market. 49 of 132

50 Forward Capacity Market The Forward Capacity Market feature is designed to provide another mechanism to assure long-term capacity adequacy. Of all the studied RTOs, only PJM and ISO-NE currently have this feature implemented. SPP Approach Differences: The SPP design does not include a Forward Capacity Market. Market Participants in SPP will continue to meet their longer term resource adequacy independently. 50 of 132

51 Forklift The MWG has reviewed RTO designs and concluded that no single existing market design could meet the full needs of the region. The MWG has also concluded that a simple forklift of any other market design would not significantly reduce cost. 51 of 132

52 Section Two MWG Response - Boston Pacific and SPP MMU Concerns The detailed MWG review of each concern raised by Boston Pacific (December 30, 2010) and SPP Market Monitoring Unit (MMU) (January 18, 2011) is addressed in the seven position papers. These position papers are included as Appendices 1 through 7 of this report. The table below provides a list of Integrated Marketplace design issues raised by Boston Pacific or MMU. Market Feature/Process Boston Pacific MMU Transmission Congestion Cost Management Transmission Losses Virtual Bidding Must-Offer Requirement Manual Dispatch Combined-Cycle Modeling Settlements Reserve Zones Obligation Transfer * Reserve Zones Minimum Requirement Calculation : issue raised *: no issue originally found. Issue raised after further review - : no issue raised All of the Boston Pacific and MMU recommendations were resolved through either modifications of the Integrated Marketplace design or acceptance by Boston Pacific of the existing design with the exception of five-minute settlement, the must-offer provision and combined-cycle enhanced special handling. Section Three MWG Recommendation: The MWG recommends proceeding with implementation of the Integrated Marketplace design as accepted by MOPC at their January 12, 2011 meeting with the following modifications: 1. Explicitly describe the process for adjusting the ARR nomination caps 52 of 132

53 2. Remove the provision allowing the Reserve Zone internal obligation transfers 3. Remove the provision allowing an operating Reserve Zone minimum to be equal to the available Operating Reserve in a zone. 53 of 132

54 3/31/2011 Understanding Market Forklift Market Working Group March 21, of 132 1

55 3/31/2011 Motivation The SPP Integrated Marketplace design baseline has been completed and approved by MOPC in January 2011 SPP MWG has instructed SPP staff to perform a qualitative analysis of performing a forklift of another market design in lieu of adopting the current SPP Integrated Marketplace design This presentation provides a description of the fundamental mechanisms involved in the adoption of a market design. These mechanisms apply to any market design forklift and thus help answer questions centered around the perceived dbenefits of such a process 3 Agenda RTOs Market Processes RTO Market Supporting Functions MWG Design Analysis Process vs. Forklift Process Market Forklift Workflow SPP Integrated Marketplace Conclusion 4 55 of 132 2

56 3/31/2011 RTOs Market Processes The standard processes of any modern RTO include: Day Ahead Market Key features include: process timeline, capacity products scope, clearing methodology, pricing methodology, market instruments scope, scarcity pricing, etc Real Time Market Key features include: process timeline, capacity products scope, clearing methodology, pricing methodology, etc Reserve Market Key features include: process timeline, reserves products scope, clearing methodology, etc Long Term Capacity Market (optional) Key features include: process timeline, capacity products scope, clearing methodology, etc TCRs Auction / ARRs Allocation Key features include: process timeline, products scope, clearing methodology, etc Settlement Process Key features include: process timeline, process granularity, billing determinants scope, etc The processes above are designed such as to stay consistent with operational standards and regulatory environment of the RTO membership 5 RTOs Market Supporting Functions The standard supporting functions/tools of an operating market include: Market Rules Resources qualification, eligibility in process participation, triggering of capacity shortage pricing, etc. Market toperational lprocedures Operational guidelines associated with consolidated balancing authority role Credit Policies Procedures and requirements on Market Participants to provide financial assurance to RTO Market Monitoring market power mitigation and tracking of market efficiency Market Software Technology adopted for market features and rules implementation System Hardware Physical Infrastructure hosting market software The supporting functions/tools above should be designed to take advantage of the technology available at the time of design 6 56 of 132 3

57 3/31/2011 MWG Design Analysis Process MWG Design Analysis vs. Forklift Forklift Process Decide SPP Region needs Now Select an existing regional design Select an existing regional design that most closely meets the needs Modify the selected design to incorporate SPP Region needs System design and development Now Understand selected design Decide SPP Region needs Identify modifications to meet SPP Region needs Modify the selected design to incorporate SPP Region needs System design and development 7 A9 Market Forklift: Workflow Adoption of a market design usually starts with a survey of existing and proven (successful) market designs As the baseline design has been selected, each of its market processes will be reviewed Integration needs of any legacy architecture or policies will need to be considered Begin Select Baseline Market Process Study Baseline Market Process Modify Process to Meet desired design No Desired design? Adopt Process as standard design Yes Done 8 57 of 132 4

58 Slide 8 A9 I did not find these 2 slides easy to understand. Another approach may be to compare to the process used to derive the current protocols...every area would need similar review, but rather than looking for the best approach for each feature, the question would be is the candidate system approach suffice or do we need to change? Shooting for the best would likely lead to a very similar solution; settling for something less desireable would require criteria to apply for desciding what is good enough. These criteria would need to evolve over time. Author, 3/16/ of 132

59 3/31/2011 Market Forklift: Workflow Meeting the desired market design goal for a given market process will in turn require detailed analysis of each of its features as well as their impact on the market supporting functions and tools Market Feature Desired design? Yes No Change Feature to Meet desired design Market Feature Desired design? Yes No Change Feature to Meet desired design Market Feature Desired design? Yes No Change Feature to Meet desired design the affected functions to gn changes If needed, modify t market supporting f reflect feature desi Adopt Feature as standard design Adopt Feature as standard design Adopt Feature as standard design 9 Market Forklift: SPP Integrated Marketplace Which RTO market design was chosen as a result of the MWG Design Analysis process? The MISO design was selected as the baseline for the Market Operation Systems because it most closely resembles the design decisions made by the MWG. Is SPP Integrated Marketplace design identical to the MISO design? No. In its study of the MISO market design, the MWG has identified and improved on market processes and features it believes would provide additional benefits to SPP membership. And wherever needed, the MWG added features, some of which inspired by other RTOs of 132 5

60 3/31/2011 Market Forklift: SPP Integrated Marketplace How long did it take MWG to complete SPP Integrated Marketplace design? The MWG Design Analysis process took about 3 years. How is SPP Integrated Marketplace different from MISO market design from a project capital cost? Current SPP Integrated Marketplace capital cost is $101M. SPP staff has estimated that a market forklift of the MISO design would reduce this cost by less than 3 5% 11 Market Forklift: SPP Integrated Marketplace At this point in the Integrated Marketplace project, can SPP adopt a different baseline design (than MISO)? Theoretical answer is yes but practical answer lies in: Acceptance of a significantimplementationdelay implementation Identifying a market design that preserves the SPP regional needs Studying the detailed market features from an alternative market design Review of the PJM market design has identified differences in most market processes Recognizing the architecture/technology differences between the current SPP EIS system and the targeted market design to forklift SPP EIS market system on which the SPP Integrated Marketplace will be grafted was developed with a different architecture than the current PJM market of 132 6

61 3/31/2011 Market Forklift: SPP Integrated Marketplace At this point in the Integrated Marketplace project, can SPP adopt a different baseline design (than MISO)? Theoretical answer is yes but practical answer lies in (continued): Assessthe total cost of forklift ISO NE cost to forklift PJM in 2003 was $78 million» $91.4M in 2011 dollars (based on 2% inflation rate) This does not include costs or loss of benefits associated with delays related to the Staff and Members learning the PJM design Would be completed with less of the desired design features 13 Conclusion Forklifting consists of: adopting an existing market design (baseline) possibly making changes to it building the infrastructure (software, hardware and policies) to accommodate that design At this point in the Marketplace project, the forklift option would: cause schedule delay not provide significant cost savings depending on extent of allowed design changes, lose customized design features of 132 7

62 3/31/2011 Conclusion MWG has reviewed all RTOs designs and adopted MISO as a design baseline MISO closely resembles the regulatory environment and operational standardsspp Market Participants face MWG has identified and improved on market processes and features it believes would provide additional benefits to SPP membership. And wherever needed added features, some of which were inspired by other RTOs SPP Staff recommends SPP move forward with the implementation of SPP Integrated Marketplace of 132 8

63 Minutes No. 154 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING February 15-16, 2011 Dallas, TX / AEP Offices Summary of Motions Agenda Item 4 Review BP and MMU Concerns Transmission Cost Management Richard Ross (AEP) motioned and Shah Hossain (Westar) seconded to accept the Boston Pacific recommendation related to Transmission Cost Management. The motion passed with no oppositions or abstentions. Agenda Item 4 Review BP and MMU Concerns Transmission Losses Richard Ross (AEP) motioned and Shah Hossain (Westar) seconded to accept the Boston Pacific recommendation that the over-collection allocation method should be modified. The motion failed with no approving votes and two abstentions from Jessica Collins (Xcel) and Rick McCord (EDE). Agenda Item 4 Review BP and MMU Concerns Transmission Losses Richard Ross (AEP) motioned and Darrell Wilson (OGE) seconded that MWG agrees with the direct refunding philosophy and believes that the loss pool approach is the simplest approach to achieving the proper over-collection allocation. The motion passed with no oppositions or abstentions. Agenda Item 4 Review BP and MMU Concerns Must Offer Requirement Jessica Collins (Xcel) motioned and Patty Denny (KCPL) seconded to approve the Boston Pacific recommendation that all Designated Resources are required to offer in the Day-Ahead Market. The motion failed with four approving votes from Richard Ross (AEP), Jessica Collins (Xcel), Ann Scott (Tenaska), and Darrell Wilson (OGE), and no abstentions. Agenda Item 4 Review BP and MMU Concerns Combined-Cycle Modeling Keith Sugg (AECC) motioned and Richard Ross (AEP) seconded to accept the Boston Pacific recommendation on combined-cycle logic. The motion failed with two approving votes from Richard Ross (AEP) and Lee Anderson (LES) and one abstention from Shah Hossain (Westar) of 132

64 Minutes No. 154 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING February 15-16, 2011 Dallas, TX / AEP Offices MINUTES Agenda Item 1 Call to Order, Proxies, Agenda Discussion: Richard Ross (AEP) called the meeting to order at 10 a.m. The attendance was recorded and proxies were announced (Attachment 1 MWG Attendance February ). The proxies for the meeting included Mitch Williams (WFEC) for James Liao (WFEC), Rick Yanovich (OPPD) for Ann Scott (Tenaska) on Wednesday. The group reviewed the agenda (Attachment 2 MWG Agenda February ) and made no changes. Agenda Item 2 Minutes Approval Richard Ross (AEP) asked for feedback on the minutes for the Jan and Feb 2 meetings (Attachment 3 MWG_Minutes_Jan17-18_v2, Attachment 4 MWG_Minutes_Feb2_v2). No changes were made so Richard Ross (AEP) deemed the minutes approved as posted. Agenda Item 3 Boston Pacific and MMU Market Reports Approach Shah Hossain (Westar), Walt Shumate (Shumate), and Patty Denny (KCPL) presented a proposal on how to handle the outstanding action items from the MOPC and SPP Board. (Attachment 5 Feb 15 mtg proposal) They each expressed concerns about the need to document the MWG s due diligence on the decisions made for the Integrated Marketplace and how to respond to the items raised in the Boston Pacific and MMU Reports. They proposed to have the MWG walk through each item raised in the respective reports and document the action or decision made by the MWG in a Position Paper that can be delivered to the MOPC and SPP Board for review. Members weighed in on the proposal and eventually agreed to follow the approach. Agenda Item 4 Review the Boston Pacific and MMU Market Reports The MWG reviewed a presentation summarizing the major concerns from the Boston Pacific and MMU reports (Attachment 6 MWG Due Diligence , Attachment 7 BPC Review of SPP Integrated Marketplace, Attachment 8 BPC Summary of Review of SPP Integrated Marketplace, Attachment 9 MMU Integrated MP Recommendation Jan , Attachment 10 MMU IM Recommendation Presentation). As each concern was addressed the MWG debated the reasons for the Integrated Marketplace design. Responses to each concern were captured and will be included in the MWG Position Papers for MOPC and SPP Board review. Also during the meeting the MWG response on each topic was documented in the PowerPoint (Attachment 11 MWG Due Diligence _MWG responses) and below is summary, including additional detail from the meeting. Boston Pacific Concerns Transmission Cost Management Concern 1: FERC Order No SPP must modify current unsecured credit requirements to comply with unsecured credit cap requirements. MWG Response: Agreed: SPP Staff in coordination with CPWG is developing credit requirements rules consistent with Order 741 Concern 2: FERC Order No SPP will become an Organized Electricity Market as defined by FERC subjecting it to requirements of conforming to long-term transmission rights of 132

65 Minutes No. 154 MWG Response: SPP must comply with the FERC Order 681 following the Integrated Marketplace implementation. MWG will re-visit the subject of LTTRs starting in January 2012, consider whether changes are needed, and make the appropriate filings. Concern 3: TCRs increase the potential payoff from a generating company causing congestion. MWG Response: Market mitigation measures are consistent with other RTO/ISO markets and the Market Monitor will monitor for gaming concerns. The Market Power Mitigation and Monitoring section provide for the capping of Energy, Start-Up, and No- Load offers. These caps are to be applied when and where Market Participants possess local market power. Mitigation measures can also be applied to physical parameter offers. The offer caps and physical parameter mitigation measures will limit the ability of a Market Participant to manipulate the value of TCRs through economic and physical withholding. Concern 4: More explicit language on ARR nomination cap adjustments MWG Response: MWG agrees with the BP recommendation to make language under Section 5.1.3(1) of the Integrated Marketplace Protocols more explicit regarding adjustments to Nomination Caps to account for transfers of load among Transmission Customers. MWG will address the issue. BP Final Recommendation; Introduce TCRs and ARRs to address transmission congestion costs and to a) Ensure vigilant market monitoring b) Comply with FERC Order Nos. 741 and 681 c) Develop language to address load migration with ARR Caps MWG Final Recommendation: After reviewing and commenting on each concern, Richard Ross (AEP) motioned and Shah Hossain (Westar) seconded to accept the Boston Pacific recommendation related to Transmission Cost Management. The motion passed with no oppositions or abstentions. Transmission Losses Concern 1: Transparency issues for Market Participants in performing shadow settlements MWG Response: All Billing Determinants needed for shadow settlement will be provided as stated in the Integrated Marketplace Protocols Concern 2: Potential gaming opportunities for Market Participants MWG Response: Known gaming opportunities (PJM) have been addressed by defining Loss Pool at the Asset Owner level based upon net transactional activity by Settlement Location and elimination of Virtuals in participating in the over-collection distribution. Also, the Market Monitor will monitor for gaming concerns. Concern 3: Is complexity worth the benefit? MWG Response: MWG believes that this method results in refunds being proportional to overpayment and in the simplest fashion that the group can conceive. Allocation method has already been developed and documented in the Protocols. Concern 4: SPP should talk with FERC about simplifying method to Direct Refund (Load Ratio Share for example) MWG Response: MWG believes that Load Ratio Share does not come close to an equitable distribution of funds and is certainly not representative of a direct refund 3 65 of 132

66 Minutes No. 154 approach. The current SPP Loss Pool approach is more closely aligned to a direct refund approach and SPP believes it provides a more equitable distribution of revenues. MWG agrees with direct refunding and believes that the loss pool approach is the simplest approach to achieving the proper overcollection allocation. Concern 5 (MMU): It is possible for a Market Participant to increase its allocation amount by scheduling exports out of the SPP footprint. MWG Response: The Integrated Marketplace is consistent with other RTO/ISO markets, export transactions with physical energy flows receive allocations because they purchase transmission service. BP Final Recommendation; Implement loss overcollection distribution on the basis of a direct refund mechanism. MWG Final Recommendation: After reviewing and commenting on each concern, Richard Ross (AEP) motioned and Shah Hossain (Westar) seconded to accept the Boston Pacific recommendation that the over-collection allocation method should be modified. The motion failed with no approving votes and two abstentions from Jessica Collins (Xcel) and Rick McCord (EDE). Additionally during the discussion, Richard Ross (AEP) motioned and Darrell Wilson (OGE) seconded that MWG agrees with the direct refunding philosophy and believes that the loss pool approach is the simplest approach to achieving the proper over-collection allocation. The motion passed with no oppositions or abstentions. Virtual Bidding Concern 1: Market Participants active in both TCRs and Virtual Bidding could use these instruments to impact their net portfolio profit through uneconomic bidding MWG Response: Virtual trading activity will be actively monitored by the MMU. In the case that the MMU determines that a Market Participant is engaged in manipulative behavior, mitigation measures will be applied and the manipulative behavior will be reported to FERC. Concern 2: SPP has no explicit limitation on Virtual bid volumes. With unlimited Virtual bidding, computer systems may not consistently find a market solution. MWG Response: An action item taken that SPP Staff will discuss with the vendor the need for limits on the number of bids and offers that can be submitted and also limits on the MW volume. MWG will re-visit the possibility of Protocol changes. Concern 3: Integrated Marketplace design imposes uplift on both virtual supply and virtual demand regardless of the source of the uplift. BP recommends applying RUC uplift to only virtual supply and day-ahead uplift only to virtual demand. MWG Response: Separating the Virtuals into demand and supply does not accomplish a cost-causation effect because it is the net Virtuals that impact the unit commitment decision. Virtual Demand Bids should be allocated a portion of RUC MWP costs since they could cause RUC MWP costs to rise by depressing LMPs due to over-commitment in the DA Market. Additionally, an action item was recorded for SPP Staff to communicate with Boston Pacific on Concern 3 to better understand the BP recommendation and return to the MWG with more information. BP final recommendation: 4 66 of 132

67 Minutes No. 154 Implement claw back on TCRs revenues created by uneconomic virtual bidding Comply with FERC credit requirements in Order No. 741 Consider imposing virtual bidding volume limits Associate virtual demands with Day-Ahead uplift costs only and likewise virtual supply with RUC uplift costs MWG Final Recommendation: No motion or final recommendation was made regarding the topic because there remain outstanding action items for SPP Staff on Concerns 2 and 3. Must Offer Requirement Concern 1: the proposed Must-Offer definition does not line up with other RTOs practices MWG Response: SPP Staff believes the current Must-Offer requirement provides an adequate backstop to meet operational reliability concerns. However, to be consistent with other RTO must-offer requirements, Staff would also support a Must-Offer requirement for all available Capacity Resources as defined in the SPP Criteria. BP final recommendation: Remove current Must-Offer requirement definition Adopt a Must-Offer requirement definition based on the concept of Designated resource Establish a capacity payment mechanism for Designated resources MWG Final Recommendation: After discussion, Jessica Collins (Xcel) motioned and Patty Denny (KCPL) seconded to approve the Boston Pacific recommendation that all Designated Resources are required to offer in the Day-Ahead Market. The motion failed with four approving votes from Richard Ross (AEP), Jessica Collins (Xcel), Ann Scott (Tenaska), and Darrell Wilson (OGE), and no abstentions. Additionally, SPP Staff will capture the MWG history on the topic and document the details in the Must Offer position paper. Manual Dispatch Concern 1: non-designated resources provide the same service as Designated resources through Manual Dispatch but are not compensated for their capacity emergency procurement MWG Response: Generators that are interconnected to the grid should expect to provide assistance in emergency conditions. No capacity payment to non-designated resources. BP final recommendation: If adopting a Must-Offer requirement definition based on the concept of Designated Resource as described previously, then allow for non-designated resources to enjoy the same capacity payment when called on through Manual Dispatch MWG Final Recommendation: Due to time constraints a final recommendation was not made during the meeting. The issue will be discussed again at the March 8-9 MWG meeting. Combined-Cycle Modeling Concern 1: Overwhelming amount of data and registration requirements MWG Response: SPP Staff does not see this as a very big concern of 132

68 Minutes No. 154 Concern 2: Very complex implementation technology which adds system risk, as evidenced by ERCOT Nodal and CAISO MRTU MWG Response: SPP staff is in agreement with Boston Pacific however MWG members do not support delaying the complex (enhanced special handling) implementation. BP final recommendation: Delay of full feature implementation MWG Final Recommendation: The MWG and SPP staff discussed the concerns at length. SPP staff recommended delaying the implementation of the complex combined-cycle logic (enhanced special handling) until after initial implementation of the Integrated Marketplace due to the risk to project delivery and cost (at least three months and $5 million). Although recognizing risk for delay and increased cost, the MWG members voiced support for the enhanced modeling at market implementation due to the centralized optimization and the expected increase in combined cycle construction. Also, MWG intends to check on operational impacts of the enhanced modeling at ERCOT (to be reported in October 2011) and possibly reevaluate the initial implementation of enhanced handling for the Integrated Marketplace depending on the ERCOT results. After considerable discussion, Keith Sugg (AECC) motioned and Richard Ross (AEP) seconded to accept the Boston Pacific recommendation on combined-cycle logic. The motion failed with two approving votes from Richard Ross (AEP) and Lee Anderson (LES) and one abstention from Shah Hossain (Westar). Settlements Due to time constraints this issue was not address during the meeting. It will be included on the March 8-9 MWG meeting. MMU Concerns Reserve Zones Due to time constraints this issue was not address during the meeting. It will be included on the March 8-9 MWG meeting. Agenda Item 5a Working Group and Committee Updates: SUG Update Bill Olson (SPS), Chair of the Settlements User Group, presented to the MWG on EQR data available for Market Participants at MISO and PJM and compared it to what is planned for the Integrated Marketplace. (Attachment 12 SUG Action Items, Attachment 13 Integrated Marketplace Cost Allocation Charge Types, Attachment 14 SUG EQR Transaction Mapping) He reviewed MWP Cost Allocation differences between MISO and SPP and provided reasons why the Integrated Marketplace designed approach is preferred. Additionally, he mentioned that the SUG is planning to create a business practice manual specific to settlements examples that will not be included in the Integrated Marketplace Protocols but will be available as a reference. Agenda Item 6 Regulatory Update Patti Kelly (SPP) provided a regulatory update to the group related to the FERC filing status of several PRRs. (Attachment 15 Regulatory Report to MWG February 15) Agenda Item 7 MMU EIS Update 6 68 of 132

69 Minutes No. 154 John Hyatt (SPP) provided the MMU EIS update to the group. (Attachment MWG MMU presentation) He provided several charts including graphs detailing ramp violations, wind generation statistics, and a theoretical example of 5 minutes settlements versus hourly settlements in the EIS Market. Agenda Item 8 VRL Quarterly Report Casey Cathey (SPP) presented the VRL quarterly report to the group and opened the discussion for questions. (Attachment 17 4 th Quarter 2010 VRL, Attachment 18 4 th _Quarter_2010_VRL_Metric) Some members expressed concern about pricing signals between ramp violations and OC violations and requested specific examples for better understanding. There is an outstanding staff action item to provide updates to the VRL Education Session presented in January 2010 and the specific examples will be added to the action item. Agenda Item 9 RSS Synchronization Implementation Due to time constraints this item was not discussed and will be on the March 8 th -9 th MWG meeting. Agenda Item 10 January 8, 2011 Outage Due to time constraints this item was not discussed and will be on the March 8 th -9 th MWG meeting. Agenda Item 11 MWG Action Items Review Due to time constraints this item was not discussed and will be on the March 8 th -9 th MWG meeting. Agenda Item 12 Marketplace Project Status Update Due to time constraints this item was not discussed and will be on the March 8 th -9 th MWG meeting. Agenda Item 13 Protocol Revision Requests Due to time constraints this item was not discussed and will be on the March 8 th -9 th MWG meeting. Agenda Item 14 Review of Motions, Action Items and Future Meetings Motions Agenda Item 4 Review BP and MMU Concerns Transmission Cost Management Richard Ross (AEP) motioned and Shah Hossain (Westar) seconded to accept the Boston Pacific recommendation related to Transmission Cost Management. The motion passed with no oppositions or abstentions. Agenda Item 4 Review BP and MMU Concerns Transmission Losses Richard Ross (AEP) motioned and Shah Hossain (Westar) seconded to accept the Boston Pacific recommendation that the over-collection allocation method should be modified. The motion failed with no approving votes and two abstentions from Jessica Collins (Xcel) and Rick McCord (EDE). Agenda Item 4 Review BP and MMU Concerns Transmission Losses Richard Ross (AEP) motioned and Darrell Wilson (OGE) seconded that MWG agrees with the direct refunding philosophy and believes that the loss pool approach is the simplest approach to achieving the proper over-collection allocation. The motion passed with no oppositions or abstentions. Agenda Item 4 Review BP and MMU Concerns Must Offer Requirement Jessica Collins (Xcel) motioned and Patty Denny (KCPL) seconded to approve the Boston Pacific recommendation that all Designated Resources are required to offer in the Day-Ahead Market. The motion failed with four approving votes from Richard Ross (AEP), Jessica Collins (Xcel), Ann Scott (Tenaska), and Darrell Wilson (OGE), and no abstentions. Agenda Item 4 Review BP and MMU Concerns Combined-Cycle Modeling 7 69 of 132

70 Minutes No. 154 Keith Sugg (AECC) motioned and Richard Ross (AEP) seconded to accept the Boston Pacific recommendation on combined-cycle logic. The motion failed with two approving votes from Richard Ross (AEP) and Lee Anderson (LES) and one abstention from Shah Hossain (Westar). MWG Action Items Agenda Item 4 Review BP and MMU Concerns Virtual Bidding SPP Staff will discuss with the vendor the need for limits on the number of bids and offers that can be submitted and also limits on the MW volume. MWG will re-visit the possibility of Protocol changes. Agenda Item 4 Review BP and MMU Concerns Virtual Bidding SPP Staff to communicate with Boston Pacific on Virtual Bidding Concern 3 to better understand the BP recommendation and return to the MWG with more information. Future Meetings Two conference calls were scheduled the week of March 14 th to enable continued progress on the outstanding MOPC and Board motions. March 8, 2011 (10 a.m. - 5 p.m.) March 9, 2011 (8:15 a.m p.m.) Location: Dallas / AEP Office Room: 8th Floor March 14, 2011 (1 p.m. 4 p.m.) March 15, 2011 (9 a.m. 12p.m) Location: Netconference March 21, 2011 (1 p.m. - 5 p.m.) March 22, 2011 (8:15 a.m. - 5 p.m.) March 23, 2011 (8:15 a.m p.m.) Location: Dallas / AEP Office Room: 8th Floor Agenda Item 8 Adjournment Richard Ross (AEP) thanked everyone and adjourned the meeting at 12:01pm. Respectfully Submitted, Debbie James Secretary 8 70 of 132

71 Minutes No. 155 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 8-9, 2011 Dallas, TX / AEP Offices Summary of Motions Agenda Item 2 Review MMU and BP Reports Manual Dispatch - Keith Sugg (AECC) motioned and Ann Scott (Tenaska) seconded to accept Boston Pacific s recommendation that non-dr be compensated for the capacity serves they provide when called upon in an emergency and the RSC spearhead this effort. The motion failed with one approving vote from Ann Scott (Tenaska) and no abstentions. Agenda Item 2 Review MMU and BP Reports Reserve Zone Transfers Keith Sugg (AECC) motioned and Ann Scott (Tenaska) seconded to approve the MMU recommendation to remove internal Reserve Zone obligation transfers. The motion passed with three oppositions from Matt Moore (GSE), Gene Anderson (OMPA), and Aaron Rome (Midwest) and two abstentions from Jessica Collins (Xcel) and Rick Yanovich (OPPD). Agenda Item 2 Review MMU and BP Reports Reserve Zone Minimums Patty Denny (KCPL) motioned and Shah Hossain (Westar) seconded to accept the MMU recommendation to remove the language that restricts the operating reserve minimum to be less than or equal to the available operating reserves in a zone. The motion passed with three oppositions from Jessica Collins (Xcel), Matt Moore (GSE) and Rick McCord (EDE) and two abstentions from Rick Yanovich (OPPD) and Ann Scott (Tenaska). Agenda Item 2 Review MMU and BP Reports 5 Minute Settlements Darrel Wilson (OGE) motioned and Jessica Collins (Xcel) seconded to accept the Boston Pacific recommendation to replace 5- minute real-time settlement with 1-hour real-time settlements and provide additional incentives for resources to follow dispatch instructions under 1- hour real-time settlement approach. The motion failed with one approving vote from Steve Haun (LES) and two abstentions from Patty Denny (KCPL) and Rick Yanovich (OPPD) of 132

72 Minutes No. 155 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 8-9, 2011 Dallas, TX / AEP Offices MINUTES Agenda Item 1 Call to Order, Proxies, Agenda Discussion: Richard Ross (AEP) called the meeting to order at 10 a.m. The attendance was recorded and proxies were announced (Attachment 1 MWG Attendance March ). The proxies for the meeting included Josh Kirby (WFEC) for James Liao (WFEC), Ann Scott (Tenaska) for Rick Yanovich (OPPD), and Matt Moore (GSE) for Mike Wise (GSE) The group reviewed the agenda (Attachment 2 MWG Agenda March ) and made no changes. Agenda Item 2 Review the Boston Pacific and MMU Market Reports The MWG continued to review the presentation summarizing the major concerns from the Boston Pacific and MMU reports (Attachment 3 MWG Due Diligence _MWG responses, Attachment 4 BPC Review of SPP Integrated Marketplace, Attachment 5 BPC Summary of Review of SPP Integrated Marketplace, Attachment 6 MMU Integrated MP Recommendation Jan , Attachment 7 MMU IM Recommendation Presentation). As each concern was addressed the MWG debated the reasons for the Integrated Marketplace design. Responses to each concern were captured in summary below but the details of the analysis and decisions will be included in the MWG Position Papers for MOPC and SPP Board review. Boston Pacific Concerns Manual Dispatch Concern 1: non-designated resources provide the same service as Designated resources through Manual Dispatch but are not compensated for their capacity emergency procurement MWG Response: Generators that are interconnected to the grid should expect to provide assistance in emergency conditions. The Integrated Marketplace design allows for a RUC make-whole-payment or Out of Merit Energy payment if called upon by SPP. BP final recommendation: If adopting a Must-Offer requirement definition based on the concept of Designated Resource as described previously, then allow for non-designated resources to enjoy the same capacity payment when called on through Manual Dispatch MWG Final Recommendation: Keith Sugg (AECC) motioned and Ann Scott (Tenaska) seconded to accept Boston Pacific s recommendation that non-dr be compensated for the capacity serves they provide when called upon in an emergency and the RSC spearhead this effort. The motion failed with one approving vote from Ann Scott (Tenaska) and no abstentions. Five Minute Settlements Concern 1: There is increased complexity and administrative burden due to the large amount of data when implementing a 5-minute Real-Time settlement 2 72 of 132

73 Minutes No. 155 MWG Response: There is no additional burden on Market Participants except for EQR reporting. SPP will provide MPs the data necessary for the 5-minute EQR reporting. MWG believes the benefits outweigh the perceived complexity and cost. There will not be a need to separate MWP calculation within the hour to account for price volatility since pricing is accurate at the 5-minute level. Also, it creates incentive for generators to follow the 5-minute dispatch signal. BP final recommendation: Replace 5-minute Real-Time settlement with 1-hour Real-Time settlement Provide additional incentives for resources to follow dispatch instructions under 1-hour Real-Time settlement approach MWG Final Recommendation: Darrel Wilson (OGE) motioned and Jessica Collins (Xcel) seconded to accept the Boston Pacific recommendation to replace 5-minute real-time settlement with 1-hour real-time settlements and provide additional incentives for resources to follow dispatch instructions under 1- hour real-time settlement approach. The motion failed with one approving vote from Steve Haun (LES) and two abstentions from Patty Denny (KCPL) and Rick Yanovich (OPPD). MMU Concerns Reserve Zones Concern 1: allowing for reserve obligation to be physically transferred between zones would create an overall inefficient SPP market (non optimal use of transmission network, potential gaming opportunity, under-funding of TCRs) Matt Moore (GSE) made a proposal to change the Marketplace design for zonal reserve cost allocation by grouping the Reserve Zones into three cost zones and average the Reserve Zone Market Clearing Prices for each zone. In addition to this idea, the MWG discussed the complexity of internal reserve zone obligation transfers, the fact it is not used in any other RTO/ISO, and the use of a complicated element to mitigate a perceived problem when the actual issue may occur rarely. The MWG failed to reach a consensus on an alternative. Concern 2: defining a Reserve Zone minimum requirement as a function of supply resources availability in that zone would create inefficient reserve pricing. In addition to Scarcity Pricing concern, reducing Min down to available capacity will mask a potential operational reliability issue. The MWG discussed the relationship between the Security Constrained Unit Commitment (SCUC) and the Security Constrained Economic Dispatch (SCED) algorithms related to the facilitation of Reserve Zone minimums requirements and actual Operating Reserve resources allocation. Some members expressed concerns about establishing a Reserve Zone minimum higher than the available Operating Reserve in the zone. Other members supported the removal of that reserve zone minimum language out of concerns related to the potential masking of capacity shortage and/or transmission limitation. MWG Response: Given the operational challenges, implementation complexity and market inefficiency concerns, the MWG decided to remove from the Integrated Marketplace design 1) the Reserve Zone internal obligation transfer schedules and 2) the provision allowing an operating reserve zone minimum to be equal to the 3 73 of 132

74 Minutes No. 155 available operating reserves in a zone. A Protocol Revision Request will be created to modify the applicable Integrated Marketplace Protocol language. MMU final recommendation: Remove provision setting Reserve Zone minimum requirement as a function of resources availability Remove internal Reserve Zone obligation transfer MWG Final Recommendation: Keith Sugg (AECC) motioned and Ann Scott (Tenaska) seconded to approve the MMU recommendation to remove internal Reserve Zone obligation transfers. The motion passed with three oppositions from Matt Moore (GSE), Gene Anderson (OMPA), and Aaron Rome (Midwest) and two abstentions from Jessica Collins (Xcel) and Rick Yanovich (OPPD). Next, Patty Denny (KCPL) motioned and Shah Hossain (Westar) seconded to accept the MMU recommendation to remove the language that restricts the operating reserve minimum to be less than or equal to the available operating reserves in a zone. The motion passed with three oppositions from Jessica Collins (Xcel), Matt Moore (GSE) and Rick McCord (EDE) and two abstentions from Rick Yanovich (OPPD) and Ann Scott (Tenaska). Agenda Item 3 Review Position Papers The MWG reviewed position papers on elements of the Integrated Marketplace detailing the concerns raised by Boston Pacific and the MWG recommendations. (Attachments 8 Must Offer position paper _mwg, Attachment 9 Combined-Cycle position paper _mwg, Attachment 10 Marginal Loss Allocation position paper _mwg) The group edited the Must Offer Requirement, Combined-Cycle Modeling, and the Marginal Losses position papers and asked staff to include the latest MWG decisions on the remaining topics. SPP staff requested members provide changes and suggestions for each position paper by close of business on Thursday, March 10 th. Staff will consolidate the feedback and post the papers for member review on Friday, March 11 th. The position papers will be reviewed and edited for preparation for the MOPC and SPP Board during the March MWG net conferences. Agenda Item 4 MMU RTO/ISO Comparison John Hyatt (SPP) presented a comparison of Market Mitigation measures in other RTO/ISO markets. He walked through the SPP Integrated Marketplace design and compared it to PJM, MISO, and ISO-NE. (Attachment 11 Mitigation Comparison March 2011) Agenda Item 5 RSS Synchronization Implementation Rick McCord (EDE) requested MWG and SPP staff review implementation concerns related to the RSS logic implemented in (Attachment 12 RSS_Sync_Implementation_021011) Casey Cathey (SPP) explained the situations where the RSS synchronization is not meeting the needs as intended in the design. There are times when assistance schedules are not delivered to MOS in time due to performance issues in creation and timing lag. Also, if the timing of a trip occurs after the snap of SCADA MW for a SCED run, MOS will not detect it until the following interval. SPP Operations considers this a high priority issue and has developed possible solutions and has received a vendor assessment for a patch to correct the issue. The plan is to implement one or combination of 1) have RSS send Inter-BA schedule first 2)extend the pre-rss logic to hold previous SCADA one extra interval, or 3) have RSS logic sum initial schedules that arrive in the next RTB and subtract the amount from previous SCADA. It is expected to take six weeks to implement the patch and perform testing. Members requested the RSS logic fix be communicated to members once the correction has been determined and implemented. Agenda Item 6 January 8, 2011 Outage 4 74 of 132

75 Minutes No. 155 Jessica Collins (Xcel) raised a concern regarding the amount of RNU during the hours the EIS Market was on outage. Casey Cathey (SPP) provided information on the outage for discussion. (Attachment 13 Jan82011_Outage_021011) The MWG reviewed the rules on proxy pricing during market outages. After discussion the MWG requested an action item for SPP staff to analyze the EI between the Balancing Authorities during the January 8, 2011 EIS Market Outage to better understand what contributes to RNU during Market Outages. Also, MWG requested another action item for SPP settlements to contact each of the SPP Market Balancing Authorities and request verification the BA s are calculating proxy pricing consistent with the Tariff language (Attachment AE 4.4c) explaining the calculation methodology for proxy pricing. Agenda Item 7 MWG/RTWG Joint Meeting Discussion Heather Starnes (SPP) provided information on the upcoming joint MWG/RTWG meetings scheduled for March 30, June 29, and August 25. The goal of the meetings is to seek input and have discussion on the tariff language for the Integrated Marketplace. The new language will replace Attachment AE of the OATT. Agenda Item 8 Discussion of possible Joint CWG/MWG meeting Jessica Collins (Xcel) suggested the possibility of a joint CWG/MWG meeting in Little Rock the week of May 25th. CWG does not intend to address any policy issues that arise during the implementation of the Integrated Marketplace project and a discussion is needed to determine a process on how handle those issues. She also mentioned CWG is looking for a more detailed implementation schedule with defined milestones. SPP staff agreed to present high level milestones to the CWG during the March 24 th conference call. A more detailed schedule will be available once contracts have been executed with vendors. Agenda Item 9 MWG Action Items Review Debbie James (SPP) walked through the latest MWG action items (Attachment 14 MWG Action Items ) and updated the group on the status of each item. An updated action items list will be posted in the action items folder on the MWG website the week of March 16 th. Agenda Item 10 Marketplace Project Status Update Due to time constraints, this item was not reviewed. However, Debbie James (SPP) pointed the MWG to the new Integrated Marketplace webpage on the spp.org ( SPP staff intends to include educational information, the latest Integrated Marketplace Protocols, and other pertinent information on the webpage. Agenda Item 11 Protocol Revision Requests Due to time constraints this item was not covered during the meeting. It will be included on the March MWG meeting. Agenda Item 12 Review of Motions, Action Items, and Future Meetings Motions Agenda Item 2 Review MMU and BP Reports Manual Dispatch - Keith Sugg (AECC) motioned and Ann Scott (Tenaska) seconded to accept Boston Pacific s recommendation that non-dr be compensated for the capacity serves they provide when called upon in an emergency and the RSC spearhead this effort. The motion failed with one approving vote from Ann Scott (Tenaska) and no abstentions. Agenda Item 2 Review MMU and BP Reports Reserve Zone Transfers Keith Sugg (AECC) motioned and Ann Scott (Tenaska) seconded to approve the MMU recommendation to remove internal Reserve Zone obligation transfers. The motion passed with three oppositions from Matt Moore (GSE), Gene Anderson (OMPA), and Aaron Rome (Midwest) and two abstentions from Jessica Collins (Xcel) and Rick Yanovich (OPPD) of 132

76 Minutes No. 155 Agenda Item 2 Review MMU and BP Reports Reserve Zone Minimums Patty Denny (KCPL) motioned and Shah Hossain (Westar) seconded to accept the MMU recommendation to remove the language that restricts the operating reserve minimum to be less than or equal to the available operating reserves in a zone. The motion passed with three oppositions from Jessica Collins (Xcel), Matt Moore (GSE) and Rick McCord (EDE) and two abstentions from Rick Yanovich (OPPD) and Ann Scott (Tenaska). Agenda Item 2 Review MMU and BP Reports 5 Minute Settlements Darrel Wilson (OGE) motioned and Jessica Collins (Xcel) seconded to accept the Boston Pacific recommendation to replace 5- minute real-time settlement with 1-hour real-time settlements and provide additional incentives for resources to follow dispatch instructions under 1- hour real-time settlement approach. The motion failed with one approving vote from Steve Haun (LES) and two abstentions from Patty Denny (KCPL) and Rick Yanovich (OPPD). Action Items Agenda Item 2 Review MMU and BP Reports Combined-Cycle Modeling SPP staff to contact ERCOT and CAISO for feedback on the operational experience of the enhanced special handling of combined-cycle modeling in Fall of Agenda Item 2 Review MMU and BP Reports Reserve Zone Transfers SPP staff will draft a PRR to remove internal Reserve Zone obligation transfers from the Integrated Marketplace Protocols. Agenda Item 6 January Outage - SPP staff to analyze the EI between the Balancing Authorities during the January 8, 2011 EIS Market Outage to better understand what contributes to RNU during Market Outages. Agenda Item 6 January Outage - SPP settlements to contact each of the SPP Market Balancing Authorities and request verification the BA s are calculating proxy pricing consistent with the Tariff language (Attachment AE 4.4c) explaining the calculation methodology for proxy pricing. Future Meetings The MWG meeting scheduled for April 4-6 was changed to a conference call on April 5 th. March 14, 2011 (1 p.m. - 4 p.m.) March 15, 2011 (9 a.m p.m.) Location: Net Conference March 21, 2011 (1 p.m. - 5 p.m.) March 22, 2011 (8:15 a.m. - 5 p.m.) March 23, 2011 (8:15 a.m p.m.) Location: AEP Offices Room: 8th floor Joint MWG/RTWG meeting March 30, 2011 (9 a.m. - 5 p.m.) Location: AEP Offices Room: 42nd Floor, Florence Room April 5, 2011 (1 p.m. - 4 p.m.) Location: Net Conference 6 76 of 132

77 Minutes No. 155 Possible Joint MWG/CWG meeting Week of May 25 th in Little Rock Agenda Item 13 Adjournment Richard Ross (AEP) thanked everyone and adjourned the meeting at 12:01pm. Respectfully Submitted, Debbie James Secretary 7 77 of 132

78 Minutes No. 156 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 14-15, 2011 Dallas, TX / AEP Offices Summary of Motions No motions were made during the meeting of 132

79 Minutes No. 156 Southwest Power Pool, Inc. MARKET WORKING GROUP MEETING March 14-15, 2011 Net Conference MINUTES Agenda Item 1 Call to Order, Proxies, Agenda Discussion: Richard Ross (AEP) called the meeting to order at 10 a.m. The attendance was recorded and proxies were announced (Attachment 1 MWG Attendance March ). Matt Moore (GSE) was the proxy for Mike Wise (GSE) during the meeting. The group reviewed the agenda (Attachment 2 MWG Agenda March ) and made no changes. Agenda Items 2 & 3 Review Position Papers The MWG edited and reviewed position papers on recommendations for preparation for the MOPC and SPP Board on the concerns by Boston Pacific and the SPP MMU on the Integrated Marketplace. (Attachments 3 Must Offer position paper _mwg, Attachment 4 Combined-Cycle position paper _mwg, Attachment 5 Five Minute Settlement position paper _mwg, Attachment 6 Reserve Zone position paper _mwg, Attachment 7 Virtual Transaction position paper _mwg) The group completed the review and editing of the Must Offer Requirement, Combined-Cycle Modeling, Five Minute Settlement, Reserve Zones, and Virtual Transaction position papers during the two conference calls. No votes were made since the MWG decisions on each topic were made during the February and March face-to-face meetings. Two position papers on Transmission Cost Management and Marginal Loss Allocation were not reviewed due to time constraints and will be included on the March MWG meeting. Updated drafts of all of the position papers will be included in the background materials for the March MWG meeting. Agenda Item 4 Review of Motions, Action Items, and Future Meetings Motions No motions were made during the meeting. Action Item No action items were assigned during the meeting. Future Meetings March 21, 2011 (1 p.m. - 5 p.m.) March 22, 2011 (8:15 a.m. - 5 p.m.) March 23, 2011 (8:15 a.m p.m.) Location: AEP Offices Room: 8th floor Joint MWG/RTWG meeting March 30, 2011 (9 a.m. - 5 p.m.) Location: AEP Offices Room: 42nd Floor, Florence Room April 5, 2011 (1 p.m. - 4 p.m.) Location: Net Conference Agenda Item 5 Adjournment 2 79 of 132

80 Minutes No. 156 Keith Sugg (AECC), acting as chair for Richard Ross (AEP) thanked everyone and adjourned the meeting at 12:40pm. Respectfully Submitted, Debbie James Secretary 3 80 of 132

81 Regulatory Report to MWG March 21, PRR 200 and 211 are still in the stage of determination of an effective date before we can make the filings. They are not included in the same project of system changes so will have separate timelines. 2. LIP Repricing for May 30, 2010 was filed on February 14. Docket No. is ER Comment date ended on March 7. Golden Spread and Xcel filed timely interventions but no protests. No response yet from FERC. 3. PRR 214 (Offer Price Floor) filing is still pending at FERC. (ER ) Filed on 2/2/ PRR 213 (Block VRL) is still pending at FERC. (ER ) Filed on 1/24/ Watch list for FERC Open meeting on March 17: RM11 14 New rulemaking titled: Analysis of Horizontal Market Power under the Federal Power Act (unless it is struck prior to the meeting) 81 of 132

82 February 2011 Market Assessment Market tworking Group Presentation ti by SPP Market Monitoring Unit February 2011 Monthly Metrics Pi Prices Congestion Generation Ramp Metrics Dispatch Range SPP.org 2 82 of 132 1

83 Oklahoma City Tulsa Prices Electricity & Natural Gas Gas Cost/ Lip Comparison Gas Cost Electricity Price (Lip) Gas Panhandle[$/MMBtu] Electricity (LIP) [$/MWh] Last 12 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 month Product s Electricity (LIP) [$/MWh] Gas Panhandle[$/MMBtu] SPP.org 3 Price Contour Map February kv 345 kv Kansas City Area 230 kv 161 kv 138 kv 115 kv 69 kv SE Oklahoma Texas Panhandle Shreveport Area SPP.org 4 83 of 132 2

84 Congestion Report- February 2011 Region Flowgate Name Average Hourly Shadow Price ($/MWh) Total % Intervals (Breached or Binding) Detailed Description Texas Panhandle OSGCANBUSDEA $ % RANPALAMASWI % Congestion due to high N-S flow. Breaches generally occur in this area with high fluctuating wind along with limited transmission capability available. Shreveport Area TEMP03_16364 $ % Congestion due to generation outages in the region. Kansas City Area COOPER_S $ % LAKALASTJHAW $ % IASCLKNASJHA $ % Heavy North South flow from Nebraska into Kansas with high external wind impacts and high market flow in the Kansas City load pocket. SE Oklahoma LONSARPITVAL $ % Congestion due to generation outages in the region SPP.org 5 Average Hourly Price by Market Participant SPP.org 6 84 of 132 3

85 Fuel on the Margin SPP.org 7 Ramp Breaches Feb- 09 Mar- 09 Apr- 09 May -09 Jun- 09 Jul- 09 Aug -09 Sep- 09 Oct- 09 Nov -09 Dec- 09 Jan- 10 Feb- 10 Mar- 10 Apr- 10 May -10 Jun- 10 Jul- 10 Aug -10 Sep- 10 Oct- 10 Nov -10 Dec- 10 Jan- Feb Up Ramp Breaches Down Ramp Breaches SPP.org 8 85 of 132 4

86 Dispatchable Range 44% 42% 40% 38% 36% 34% 32% Average Dispatchable Range divided by Average Daily Peak Load SPP.org 9 Alan McQueen Market Monitoring and Analysis amcqueen@spp.org 86 of 132 5

87 High level Plan for Planned Failover of PRD MOS from MM t Pre Failover Preparation and Verification Pre Outage Stop MOS Apps at Maumelle Failover from Maumelle to Plaza West Verify DR e Terra Dataman for readiness to operate Verify DR SPD/SFT for readiness to operate Verify DR MOI for readiness to operate Verify DR Web Servers for readiness to operate Perform a Ping notification test to SPP Members via the Notifications Verify that MOS App servers can reach the DR MDB database Check Firewall access and Router Settings from DR MDB to external f Coordinate with IT Reliability, IT COS and IT Scheduling for data feeds Ramping Out MPs from Market Stop Dataman and Dataman 2 Stop CLU/Notifications/MUI Stop SPD/SFT Servers Stop MOI Perform Database Switchover and Incremental Restore from PRD MD DR NAS/Apps team makes necessary changes to connect MOS, EMS, DR MDB node(s) are active Start Dataman and Dataman 2 Startup of MOS Start CLU/Notifications/MUI Applications at Plaza West Start SPD/SFT Servers Start MOI Perform Complete MOS Verification Verify with IT Reliability and IT Scheduling for data feeds to and from Post Failover Verification Operations performs their validations Final Checkpoint Decision before ramping in Post Outage Market Operators Ramp in MPs to Market 87 of 132

88 to PW s GUI feeds s to and from MOS 2 Days Prior 30 Minutes 5 Minutes DB to DR MDB/Server team will re route from PRD NAS to Scheduling as needed(depends on the failover scenario) 110 Minutes 5 Minutes MOS 45 Minutes < 30 Minutes 88 of 132

89 3/31/2011 Offline Resource Price Calculation March 22 nd, 2011 Gary Cate of 132 1

90 3/31/2011 Section 1 OFFLINE RESOURCE PRICE CALCULATION RESETTLEMENT DISCUSSION 3 Offline Resource Shift Factor Analysis SPP is evaluating the effects of the inaccurately calculated Shift Factors Only offline resources during congested intervals (binding or violated) with Scheduled Amounts > 0MW This presentation is to let MPs know the issue SPP will follow up with actual magnitude by next faceto face MWG meeting 4 90 of 132 2

91 3/31/2011 Pre Quick Start Implementation (11/29/2010) How were offline resources handle before this patch? All offline resources used Near Bus Logic (NBL). Their LIP was the price of the next closet Load or Resource. The resource had no shift factor. SFT would look for an element at the same voltage level and move up voltage levels from there. It would then move to the nextstation if no elements were foundat any voltage level. This worked well and gives an accurate LIP in most situations. Why did we change the logic for Quick Start? The QS logic introduced the concept of dispatching a unit that was disconnected from the bus (offline) It was found early on in testing that if the unit did not have a shift factor, it would be dispatched based on the System Marginal Price only and not consider the Marginal Congestion Cost at the Pricing Node. Example: Congestion on system. Offer is $55 for 0 to 10MW. Resource LIP is $40. SMP is $80. Based on the Resource LIP, the QS should not be dispatched up. However, based upon SMP, the resource is dispatched up. 91 of 132 3

92 3/31/2011 What were our options for fixing this situation and which did we choose? MOS vendor presented two options: A hops logic that would search for live buses to use as the shift factor A one bus away logic (OBA) that was limited to only looking for a live bus one bus away for the shift factor We chose OBA for two reasons: The hops logic presents an issue where the logic could potentially hop all the way to the other side of a constraint, thus giving a very inaccurate shift factor. Since this logic was for Quick Start units, it was surmised that for a Quick Start unit, it would be extremely rare that the bus one bus away from the unit was not live. This has held true in our experiences to date. There were no issues with the calculation of QS shift factors and this logic has worked as designed. When did the issues begin, what were they, and why? The issues began with the implementation of Phase 3 on 2/22/2011. MP s began experiencing i large price divergences on their offline units. This was especially noticeable when the units were electrically located at the same bus. There should not have been price divergence in that situation. The issue was related to a piece of the Phase 3 patch. In this patch, shift factor rotation was moved from SPD to SFT. However, when doing this change, the code left the shift factors that were for offline units out of the rotation. This caused the offline resource shift factors to be non rotated and in some cases different from surrounding elements. When an offline resource was in close proximity to a constraint, shift factors for this resource, while still incorrect, were close to that of the elements with correct shift factors. As the distance between the resource and the constraint grew, the shift factor error increased. 92 of 132 4

93 3/31/2011 Finding and resolving the issue The first incident was reported by an MP on 2/24/2011. The issue involved the three units located at a Plant station bus. There are 3 units at this station, 2 are at the same voltage level and 1 is at a slightly highervoltage level. This issue was reported again during the weekend. Assuming that the bad prices were either due to DBL or just an inaccuracy in the OBA calculation, SPP staff posed a question to MOS vendor regarding a flat SFT run to mitigate the offline shift factor problem. Once further research was done by SPP staff to provide MOS vendor supporting documents on recent issues causing the want for a flat SFT run, the real problem of the incorrect shift factors was found. The issue was reported to MOS vendor on 3/1/2011. The MOS vendor figured out what the problem was on 3/4/2011 and reported the cause back to SPP. Subsequent Patch Issues A patch for this issue was delivered on 3/7/2011. Initial Testing was promising (the offline shift factors were being rotated and were correct), however it was found that if a unit was manually removed from the bus or removed from the bus by OUTSCHED, this unit would not report shift factors. Since this issue would not be very prevalent (and also because when a shift factor is not reported, we revert back to NBL and get the correct LIP) this patch was moved to PROD on 3/8/2011. The OUTSCHED issue fix went into PROD 3/15/2011. No Issues have been reported since the installation of the new patch. Shift Factors and LIP are correct and consistent. 93 of 132 5

94 3/31/2011 Repricing Implications and Complications Regardless of a Resource s status the Settlements calculation for a resource stays the same. (Scheduled d Amount Mt Meter Dt Data Amount) t)* LIP The LIP is an HOURLY average of the 12 five minute intervals within that hour. If there is no resulting imbalance between the SA and MDA, then the LIP for credit/debit purposes is irrelevant. 0 multiplied by anything will still be 0. So the question is what and how do we re price? Any Resource, for any given hour, in which there is imbalance between SA and MDA, and calculated LIP for that hour includes at least one bad LIP interval. Note: This is only during times of congestion. All LIPs are the same during non congested intervals. 94 of 132 6

95 EIS Market Integrated Marketplace Protocols Revision Request PRR No. Marketplace-PRR1 Protocol Section(s) Requiring Revision Impact Analysis Required Requested Resolution PRR Removal of Internal Reserve Zone Transfers and Reserve Zone Minimum Title Clause Section No: 1,4.1.3, , 4.5.3, Appendix F (3.3.2, 3.3.3, 3.3.4, 3.3.5, 3.3.6, 3.3.7, 3.3.8) Title: Glossary, Operating Reserve Requirements, Internal Reserve Zone Obligation Transfer Schedules, Financial Schedules and Reserve Zone Obligation Transfer Schedules, Appendix F (Initial Obligation, Intermediate Obligation, Final Obligation, Exchange Supply Rate, Day Ahead Zonal Cost, Day Ahead Zonal Distribution Rate, Day Ahead Zonal Distribution Charge Type Result) Protocol Version: 0.b Yes If yes, estimated cost: No SPP Staff will complete this section. Normal Expedited Urgent Action Provide explanation if Expedited and/or Urgent Action is selected: Revision Description Elimination of internal Reserve Zone transfers and removal of Reserve Zone minimum clause Reason for Revision Given the operational challenges, implementation complexity and market inefficiency concerns, the MWG decided to remove internal Reserve Zone transfer schedules from the Integrated Marketplace design. Additionally, as a result of concerns related to market inefficiencies, the MWG decided to remove the language that restricts the operating reserve minimum to be less than or equal to the available operating reserves in a zone. Tariff Implications or Changes Yes Section No: (Include a summary of impact and/or specific changes) No Tariff language is still being developed Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 1 of of 132

96 Criteria Implications or Changes Yes - Section No: (Include a summary of impact and/or specific changes) No Yes (Include a summary of impact and/or specific changes) Credit Implications No Date March 11, 2011 Sponsor Name Debbie James Address djames@spp.org Company Southwest Power Pool Phone Number Proposed Protocol Language Revision 1. Glossary Operating Reserve Requirements SPP calculates the amount of Operating Reserve required for the Operating Day, on both a system-wide basis and a Reserve Zone basis, to comply with the reliability requirements specified in the SPP Criteria. SPP calculates the hourly Regulation-Up, Regulation-Down and Contingency Reserve requirements on an SPP BAA basis and calculates minimum and maximum Operating Reserve requirements for each Reserve Zone. (1) SPP BAA Contingency Reserve requirements are set consistent with SPP Criteria and may vary on an hourly basis. (2) SPP BAA Regulation-Up and Regulation-Down requirements are set to ensure compliance with NERC control performance requirements and are based upon a percentage of forecasted load, adjusted up or down to account for resource output variability, and may vary on an hourly basis. Deleted: Internal Reserve Zone Obligation Transfer Schedule A schedule between Reserve Zones supported by firm transmission service that allows a Market Participant to transfer its Operating Reserve obligation from one Reserve Zone to another. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 2 of of 132

97 (3) The SPP BAA requirements and minimum and maximum Reserve Zone requirements are calculated and posted no later than 7:00 AM Day-Ahead. At this time, SPP will also communicate each Market Participant s estimated Operating Reserve obligations in each Reserve Zone using the BAA Mid-Term Load Forecast and the Market Participant load forecasts developed by SPP under Section (4) These Operating Reserve requirements are used by SPP as inputs into the DA Market and RTBM clearing and RUC processes. (a) SPP may increase Operating Reserve requirements for use in RTBM clearing and RUC processes above the requirements used in the DA Market clearing, including changes to Reserve Zone minimums and maximums, as required to meet increases in reliability requirements caused by changes in system conditions. (5) Reserve Zone minimum and maximum Operating Reserve requirements are determined through reserve zone studies prior to the DA Market. Reserve zone studies are performed as described under Section Deleted: <#>No later than 8:00 AM Day-Ahead, Market Participants must submit their Internal Reserve Zone Obligation Transfer Schedules, as described under Section SPP will evaluate these schedule submittals and adjust the minimum and maximum Reserve Zone requirements described under Section as required and SPP will repost the revised minimum and maximum Reserve Zone Operating Reserve requirements no later than 10:00 AM Day-Ahead Minimum Operating Reserve Requirements Using this base case commitment and dispatch, the loss of the largest Resource is simulated for each Reserve Zone and the unused import capability is assessed based on normal operating limits. Operating Reserve being supplied to a Reserve Zone from outside of the SPP BA as described under Sections and is included in this evaluation; (1) Power Transfer Distribution Factor ( PTDF ) interface flowgates for the import/export study will use appropriate ratings that do not reflect additional protection for transmission contingencies. (2) If unused import capability equals or exceeds the largest Resource MW, then Reserve Zone minimum is equal to zero. (3) If unused import capability is less than the largest Resource MW, then the Reserve Zone minimum Operating Reserve requirement is equal to the lesser of; 1) the difference between the largest Resource MW and unused import capability; or 2) the difference between the Reserve Zone load and import capability. The minimum requirement for each Operating Reserve product is determined as follows: Deleted: ; or 3) the sum of available Operating Reserve Resource MW within the zone whether the Resources are offered or not offered (a) The minimum Regulation-Up Requirement is equal to 25% of the product the SPP BAA Regulation-Up requirement and the ratio of the sum of the Maximum Regulation Capability of Resources within the Reserve Zone to the sum of the Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 3 of of 132

98 Maximum Regulation Capability of all Regulation Qualified Resources and Regulation-Up Qualified Resources; (b) (c) (d) (e) The minimum Regulation-Down Requirement is equal to 25% of the product the SPP BAA Regulation-Down requirement and the ratio of the sum of the Maximum Regulation Capability of Resources within the Reserve Zone to the sum of the Maximum Regulation Capability of all Regulation Qualified Resources and Regulation-Down Qualified Resources; The minimum Contingency Reserve requirement for a Reserve Zone is equal to the minimum Operating Reserve requirement of the Reserve Zone less the Regulation-Up requirement of the Reserve Zone but not less than zero (0) MW. The minimum Spinning Reserve Requirement for a specific Reserve Zone is equal to twenty-five (25) percent of the product of the minimum Contingency Reserve requirement for that Reserve Zone and the ratio of the SPP BAA Spinning Reserve requirement to the SPP BAA Contingency Reserve requirement; and The minimum Supplemental Reserve requirement for a specific Reserve Zone is equal to the minimum Contingency Reserve Requirement for the Reserve Zone less the minimum Spinning Reserve Requirement for the Reserve Zone Maximum Operating Reserve Requirements Using the base case commitment and dispatch, simulate the loss of the largest Resource in one Reserve Zone and assess the export capability in remaining Reserve Zones based on normal operating limits. Contingency Reserve being supplied to a Reserve Zone from outside of the SPP BA as described under Sections and is included in this evaluation. (1) Aggregate and proxy PTDF flowgates for the import/export study will use appropriate ratings that do not reflect additional protection for transmission contingencies. (2) The Reserve Zone maximum is equal to the unused Reserve Zone export capability. The maximum Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve requirement is equal to Reserve Zone obligation for these products multiplied by the ratio of the Reserve Zone maximum Operating Reserve requirement and the Reserve Zone Operating Reserve obligation. Deleted: <#>If a Market Participant submits an Internal Reserve Zone Obligation Transfer Schedule as described under Section : <#>the minimum requirement for the specified Operating Reserve product for the Reserve Zone in which the Market Participant s Operating Reserve obligation is being transferred out of is reduced by the minimum of (i) the MW amount specified in the transfer schedule or (ii) the Reserve Zone minimum requirement for the specified Operating Reserve product; and <#>the unused transmission system import capability into that Reserve Zone is increased by the MW of reduced Reserve Zone minimum requirement for the specified Operating Reserve product by reducing the transmission line limits associated with the Reserve Zone import capability, as applicable. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 4 of of 132

99 4.5.3 Financial Schedules and External Reserve Zone Obligation Transfer Schedules Financial Schedules Market Participants may create Financial Schedules for Energy and Operating Reserve obligation by registering and confirming the parameters of the agreement between buyer and seller such as the Schedule ID, Settlement Location, Reserve Zone, maximum allowable hourly quantity, market product, submitting party, auto-confirmation option and the effective & termination dates. Once this header information is validated and entered into the system by SPP, hourly quantities submitted reference the Schedule ID in order to be associated with all the parameters required for settlement calculations. In the event that either party no longer consents to participate in the Financial Schedule or if SPP staff encounter recurring settlement dispute activity related to its usage the header information may be ended in advance of the original termination date effectively preventing further submittal of hourly quantities. Market Participants may submit Financial Schedule quantities for Energy and Operating Reserve obligation up to 4 days following the applicable Operating Day for the Initial settlement. New submittals and revisions to previously submitted values may be submitted up to 44 days following the applicable Operating Day to be included in the Final settlement. The submittal timeline is subject to acceleration around holidays (see Section ). Auto-confirmation applies to only the first submittal per Operating Day and must occur prior to the cutoff for the Initial settlement. Submittals 1) for agreements not using the auto-confirmation option, 2) beyond the cutoff date for the Initial settlement or 3) which update previous submittals must all be explicitly confirmed by the submitting party and counterparty. Submittals not confirmed by both parties will not be included in any settlement execution. Transactions related to Financial Schedules for Energy must specify the Settlement Location, the MW amount, the buyer, the seller and which market it applies to (DA Market or RTBM). The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the specified MW amount (the equivalent of a Resource settlement) at the specified Settlement Location. Deleted: <#>If a Market Participant submits an Internal Reserve Zone Obligation Transfer Schedule as described under Section : <#>the maximum requirement for the specified Operating Reserve product for the Reserve Zone in which the Market Participant s Operating Reserve obligation is being transferred into is increased by the MW amount specified in the transfer schedule; and <#>the unused transmission system export capability out of that Reserve Zone is increased by the MW amount specified in the transfer schedule for the specified Operating Reserve product by reducing the transmission line limits associated with the Reserve Zone export capability, as applicable Internal Reserve Zone Obligation Transfer Schedules Market Participants with Network Integration Transmission Service ( NITS ) may meet their Operating Reserve obligations in a Reserve Zone from Designated Resources in another Reserve Zone through an Internal Reserve Zone Obligation Transfer schedule and Market Participants with firm Point-to-Point ( FPTP ) Transmission Service between the applicable Reserve Zones may meet their Operating Reserve obligations in the sink Reserve Zone from the specified Resource in the source Reserve Zone through an Internal Reserve Zone Obligation Transfer Schedule subject to the following: <#>If the Market Participant has an Operating Reserve obligation in a Reserve Zone that cannot be self-supplied ( Reserve Zone A ) using that Market Participant s Resources located within that Reserve Zone, that Market Participant may specify that the Operating Reserve Obligation is to be met from that Market Participant s Resource s that are located in a different Reserve Zone ( Reserve Zone B ), provided that sufficient Resources are available to meet the Operating Reserve obligation. This transaction will produce a reduction in Operating Reserve obligation in Reserve Zone A for that Market Participant and a corresponding increase in Operating Reserve obligation in Reserve Zone B for that Market Participant. <#>Optionally, a Market Participant may specify that its Operating Reserve obligation within Reserve Zone A is to be met by the Resource s of another Market Participant from Reserve Zone B, provided that the counterparty Market Participant is in agreement with the transaction. This transaction will produce a reduction in Operating Reserve obligation in Reserve Zone A for that Market Participant and a corresponding increase in Operating Reserve obligation in Reserve Zone B for the counterparty Market Participant. <#>In either case, the buying Market Participant may not reduce its Operating Reserve obligation by more than the difference between its estimated Operating Reserve obligations as calculated by SPP under Section and its available Operating Reserve supply within the applicable Reserve Zone. <#>Market Participants must submit their Internal Reserve Zone Obligation Transfer Schedules no later than 8:00 AM Day-Ahead and must specify the following information: <#>Asset Owner Buyer;... [1] Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 5 of of 132

100 Transactions related to Financial Schedules for Operating Reserve obligation must specify the buyer, the seller, the Operating Reserve product, the MW obligation transfer and the Reserve Zone within which the obligation transfer applies. The seller receives an increase in Operating Reserve obligation equal to the specified MW and the buyer receives a corresponding decrease in Operating Reserve obligation within the specified Reserve Zone External Reserve Zone Obligation Transfer Schedules Market Participants may submit External Reserve Zone Obligation Transfer Schedules for Operating Reserve as described under Section The buyer receives a corresponding decrease in Operating Reserve obligation in the sink Reserve Zone up to but not beyond the buyer s obligation. The above variables are defined as follows: Variable Unit Settlement Interval Definition DaRegUpDistHrlyAmt a, z, h $ Hour Day-Ahead Regulation-Up Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a s share of DA Market Regulation-Up procurement costs in Reserve Zone z in Hour h. DaRegUpDistHrlyRate z, h $/MW Hour Day-Ahead Regulation-Up Distribution Hourly Rate per Reserve Zone per Hour The rate applied to AO a s Regulation-Up obligation within Reserve Zone z in Hour h. ContrRegUpHrlyQty a, z, h, t MW Hour Contracted Regulation-Up per AO per Reserve Zone per Transaction per Hour AO a s contracted Regulation-Up transaction t being supplied to Reserve Zone z from external to the SPP BA to meet AO a s Regulation-Up obligation. Contracted Regulation-Up being supplied to AO a is a positive value. DaRegUpRznHrlyCost z, h $ Hour Day-Ahead Regulation-Up Reserve Zone Cost per Reserve Zone per Hour The total DA Market Regulation-Up procurement cost for Reserve Zone z in Hour h. Deleted: Internal Deleted: Deleted: The seller receives an increase in Operating Reserve obligation equal to the specified MW in the source Reserve Zone and t Deleted: An External Reserve Zone Obligation Transfer Schedule representing Contingency Reserve obligation being met from outside the SPP footprint, as described under Section , does not specify the seller AO or source Reserve Zone and no increase in Operating Reserve obligation to the seller is necessary since the seller is outside of the SPP Balancing Authority Area. Deleted: from outside Deleted: or AO a s contracted Regulation-Up being supplied from Reserve Zone z to another Reserve Zone in Hour h. Deleted: and contracted Regulation-Up being supplied from AO a is a negative value Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 6 of of 132

101 Variable Unit Settlement Interval Definition DaRegUpHrlyQty a, s, z, h MW Hour Day-Ahead Regulation-Up Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour The value described under Section in Reserve Zone z. DaRegUpAoObligHrlyQty a, z, h MW Hour Day-Ahead Regulation-Up Asset Owner Obligation Quantity per Reserve Zone per Hour Asset Owner a s DA Market Regulation-Up obligation in Reserve Zone z for Hour h. DaRegUpRznHrlyQty z, h MW Hour Day-Ahead Regulation-Up Hourly Quantity per Reserve Zone per Hour The total amount of cleared Regulation-Up in Reserve Zone z for Hour h. DaRegUpObligRznHrlyQty z, h MW Hour Day-Ahead Regulation-Up Obligation per Reserve Zone per Hour Reserve Zone z s DA Market Regulation-Up obligation for Hour h. ContrRegUpSppHrlyQty h MW Hour Contracted Regulation-Up per Hour The total of all ContrRegUpHrlyQty a, z, h, t for Hour h. RtLoadSppHrlyQty h MW Hour Real-Time SPP Load per Hour SPP total actual load and Export Interchange Transactions in Hour h. DaRegUpSppHrlyQty h MW Hour Total SPP Day-Ahead Regulation-Up Hourly Quantity per Hour The total amount of Regulation-Up cleared in the DA Market for Hour h. DaRegUpInterObligSppHrlyQty h MW Hour Day-Ahead SPP Regulation-Up Interim Obligation Quantity per AO per Reserve Zone per Hour The total of all Asset Owner s DA Market Regulation-Up interim obligation over all Reserve Zones for Hour h. DaRegUpInterAoObligHrlyQty a, z, h MW Hour Day-Ahead Regulation-Up Interim Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Regulation-Up interim obligation that includes treatment of ContrRegUpHrlyQty a, z, h, t but does not include allocation of excess ContrRegUpHrlyQty a, z, h, t in Reserve Zone z for Hour h. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 7 of of 132

102 Variable Unit Settlement Interval Definition DaRegUpIniAoObligHrlyQty a, z, h MW Hour Day-Ahead Regulation-Up Initial Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Regulation-Up initial obligation that does not include treatment of ContrRegUpHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaRegUpObligRatio h none Hour Day-Ahead Regulation-Up Asset Owner Obligation Ratio per Hour The percentage applied to Asset Owner a s DaRegUpInterAoObligHrlyQty a, z, h to account for allocation of any excess ContrRegUpHrlyQty a, z, h, t in Reserve Zone z in Hour h. DaRegUpSlObligHrlyQty a, s, z, h MW Hour Day-Ahead Regulation-Up Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a s DA Market Regulation-Up initial obligation that does not include treatment of ContrRegUpHrlyQty a, z, h, t at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. DaRegUpMcpHrlyPrc z, h $/MW Hour Day-Ahead MCP for Regulation-Up per Reserve Zone The value described under Section for Reserve Zone z. DaRegUpSpxHrlyRate h $/MW Hour Day-Ahead Regulation-Up SPP Exchange Rate per Hour The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Regulation-Up from other Reserve Zones in order to meet the Reserve Zone Regulation-Up obligation. RtRegUpRznLoadHrlyQty a, s, z, h MWh Hour Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h Asset Owner a s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Regulation-Up cost allocation. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 8 of of 132

103 Variable Unit Settlement Interval Definition RtBillMtr5minQty a, s, i MW Dispatch Interval Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section for Reserve Zone z. PctSlinRznRegUpHrlyFct a, s, z, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour The percentage factor of AO a s load at Settlement Location s that is contained within Reserve Zone z for use in Regulation-Up cost allocation. RtImpExp5minQty a, s, i, t MW Dispatch Interval Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction The value described under Section for Reserve Zone z. RsgCrdFlg t none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event A flag indicating that an import or export is a result of a schedule created by a Reserve Sharing Event. Normally, this flag is equal to zero. It is set equal to one for a Reserve Sharing Event. RegUpFinHrlyQty a, z, h, t MW Hour Financial Schedule for Regulation-Up per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Financial Schedule transaction t for Regulation-Up at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. DaRegUpDistDlyAmt a, z, d $ Operating Day DaRegUpDistAoAmt a, m, d $ Operating Day Day-Ahead Regulation-Up Distribution Amount per AO per Reserve Zone per Operating Day - AO a s share of DA Market Regulation-Up procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Regulation-Up Distribution Amount per AO per Operating Day - AO a s for total DA Market Regulation-Up procurement costs associated with Market Participant m in Operating Day d. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 9 of of 132

104 Variable Unit Settlement Interval Definition DaRegUpDistMpAmt m, d $ Operating Day Day-Ahead Regulation-Up Distribution Amount per MP per Operating Day - MP m s share of total DA Market Regulation- Up procurement costs for in Operating Day d. a none none An Asset Owner. s none none A Settlement Location. h none none An Hour. z none none A Reserve Zone. i none none A Dispatch Interval. t none none A single tagged Interchange Transaction, a single virtual energy transaction, a single Financial Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. d none none An Operating Day. m none none A Market Participant. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 10 of of 132

105 The above variables are defined as follows: Variable Unit Settlement Interval Definition DaRegDnDistHrlyAmt a, z, h $ Hour Day-Ahead Regulation-Down Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a s share of DA Market Regulation-Down procurement costs in Reserve Zone z in Hour h. DaRegDnDistHrlyRate z, h $/MW Hour Day-Ahead Regulation-Down Distribution Hourly Rate per Reserve Zone per Hour The rate applied to AO a s Regulation- Down obligation within Reserve Zone z in Hour h. ContrRegDnHrlyQty a, z, h, t MW Hour Contracted Regulation-Down per AO per Reserve Zone per Transaction per Hour AO a s contracted Regulation-Down transaction t being supplied to Reserve Zone z from outside of the SPP BA to meet AO a s Regulation-Down obligation. Contracted Regulation-Down being supplied to AO a is a positive value. DaRegDnRznHrlyCost z, h $ Hour Day-Ahead Regulation-Down Reserve Zone Cost per Reserve Zone per Hour The total DA Market Regulation-Down procurement cost for Reserve Zone z in Hour h. DaRegDnHrlyQty a, s, z, h MW Hour Day-Ahead Regulation-Down Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour The value described under Section in Reserve Zone z. DaRegDnAoObligHrlyQty a, z, h MW Hour Day-Ahead Regulation-Down Asset Owner Obligation Quantity per Reserve Zone per Hour Asset Owner a s DA Market Regulation-Down obligation in Reserve Zone z for Hour h. DaRegDnRznHrlyQty z, h MW Hour Day-Ahead Regulation-Down Hourly Quantity per Reserve Zone per Hour The total amount of cleared Regulation-Down in Reserve Zone z for Hour h. DaRegDnObligRznHrlyQty z, h MW Hour Day-Ahead Regulation-Down Obligation per Reserve Zone per Hour Reserve Zone z s DA Market Regulation-Down obligation for Hour h. ContrRegDnSppHrlyQty h MW Hour Contracted Regulation-Down per Hour The total of all ContrRegDnHrlyQty a, z, h, t for Hour h. Deleted: from outside Deleted: or AO a s contracted Regulation-Down being supplied from Reserve Zone z to another Reserve Zone in Hour h Deleted: and contracted Regulation-Down being supplied from AO a is a negative value Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 11 of of 132

106 Variable Unit Settlement Interval Definition RtLoadSppHrlyQty h MW Hour Real-Time SPP Load per Hour The value described under Section DaRegDnSppHrlyQty h MW Hour Total SPP Day-Ahead Regulation-Down Hourly Quantity per Hour The total amount of Regulation-Down cleared in the DA Market for Hour h. DaRegDnInterObligSppHrlyQty h MW Hour Day-Ahead SPP Regulation-Down Interim Obligation Quantity per AO per Reserve Zone per Hour The total of all Asset Owner s DA Market Regulation-Down interim obligation over all Reserve Zones for Hour h. DaRegDnInterAoObligHrlyQty a, z, h MW Hour Day-Ahead Regulation-Down Interim Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Regulation-Down interim obligation that includes treatment of ContrRegDnHrlyQty a, z, h, t but does not include allocation of excess ContrRegDnHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaRegDnIniAoObligHrlyQty a, z, h MW Hour Day-Ahead Regulation-Down Initial Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Regulation-Down initial obligation that does not include treatment of ContrRegDnHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaRegDnObligRatio h none Hour Day-Ahead Regulation-Down Asset Owner Obligation Ratio per Hour The percentage applied to Asset Owner a s DaRegDnInterAoObligHrlyQty a, z, h to account for allocation of any excess ContrRegDnHrlyQty a, z, h, t in Reserve Zone z in Hour h. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 12 of of 132

107 Variable Unit Settlement Interval Definition DaRegDnSlObligHrlyQty a, s, z, h MW Hour Day-Ahead Regulation-Down Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a s DA Market Regulation-Down initial obligation that does not include treatment of ContrRegDnHrlyQty a, z, h, t at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. DaRegDnMcpHrlyPrc z, h $/MW Hour Day-Ahead MCP for Regulation-Down per Reserve Zone The value described under Section for Reserve Zone z. DaRegDnSpxHrlyRate h $/MW Hour Day-Ahead Regulation-Down SPP Exchange Rate per Hour The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Regulation-Down from other Reserve Zones in order to meet the Reserve Zone Regulation-Down obligation. RtRegDnRznLoadHrlyQty a, s, z, h MWh Hour Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h Asset Owner a s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Regulation-Down cost allocation. RtBillMtr5minQty a, s, i MW Dispatch Interval Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section for Reserve Zone z. PctSlinRznRegDnHrlyFct a, s, z, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour The percentage factor of AO a s load at Settlement Location s that is contained within Reserve Zone z for use in Regulation-Down cost allocation. RtImpExp5minQty a, s, i, t MW Dispatch Interval Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction The value described under Section for Reserve Zone z. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 13 of of 132

108 Variable Unit Settlement Interval Definition RsgCrdFlg t none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event The value described under Section RegDnFinHrlyQty a, z, h, t MW Hour Real-Time Financial Schedule for Regulation-Down per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Financial Schedule transaction t for Regulation-Down at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. DaRegDnDistDlyAmt a, z, d $ Operating Day DaRegDnDistAoAmt a, m, d $ Operating Day DaRegDnDistMpAmt m, d $ Operating Day Day-Ahead Regulation-Down Distribution Amount per AO per Reserve Zone per Operating Day - AO a s share of DA Market Regulation-Down procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Regulation-Down Distribution Amount per AO per Operating Day - AO a s for total DA Market Regulation-Down procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Regulation-Down Distribution Amount per MP per Operating Day - MP m s share of total DA Market Regulation- Down procurement costs for in Operating Day d. a none none An Asset Owner. s none none A Settlement Location. h none none An Hour. z none none A Reserve Zone. i none none A Dispatch Interval. t none none A single tagged Interchange Transaction, a single virtual energy transaction, a single Financial Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. d none none An Operating Day. m none none A Market Participant. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 14 of of 132

109 The above variables are defined as follows: Variable Unit Settlement Interval Definition DaSpinDistHrlyAmt a, z, h $ Hour Day-Ahead Spinning Reserve Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a s share of DA Market Spinning Reserve procurement costs in Reserve Zone z in Hour h. DaSpinDistHrlyRate z, h $/MW Hour Day-Ahead Spinning Reserve Distribution Hourly Rate per Reserve Zone per Hour The rate applied to AO a s Spinning Reserve obligation within Reserve Zone z in Hour h. ContrSpinHrlyQty a, z, h, t MW Hour Contracted Spinning Reserve per AO per Reserve Zone per Transaction per Hour AO a s contracted Spinning Reserve transaction t being supplied to Reserve Zone z from outside of the SPP BA to meet AO a s Spinning Reserve obligation. Contracted Spinning Reserve being supplied to AO a is a positive value. DaSpinRznHrlyCost z, h $ Hour Day-Ahead Reserve Zone Cost per Reserve Zone Spinning Reserve per Hour The total DA Market Spinning Reserve procurement cost for Reserve Zone z in Hour h. DaSpinHrlyQty a, s, z, h MW Hour Day-Ahead Spinning Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour The value described under Section in Reserve Zone z. DaSpinAoObligHrlyQty a, z, h MW Hour Day-Ahead Spinning Reserve Asset Owner Obligation Quantity per Reserve Zone per Hour Asset Owner a s DA Market Spinning Reserve obligation in Reserve Zone z for Hour h. DaSpinRznHrlyQty z, h MW Hour Day-Ahead Spinning Reserve Hourly Quantity per Reserve Zone per Hour The total amount of cleared Spinning Reserve in Reserve Zone z for Hour h. DaSpinObligRznHrlyQty z, h MW Hour Day-Ahead Spinning Reserve Obligation per Reserve Zone per Hour Reserve Zone z s DA Market Spinning Reserve obligation for Hour h. ContrSpinSppHrlyQty h MW Hour Contracted Spinning Reserve per Hour The total of all ContrSpinHrlyQty a, z, h, t for Hour h. RtLoadSppHrlyQty h MW Hour Real-Time SPP Load per Hour The value described under Section Deleted: from outside Deleted: or AO a s contracted Spinning Reserve being supplied from Reserve Zone z to another Reserve Zone in Hour h Deleted: and contracted Spinning Reserve being supplied from AO a is a negative value Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 15 of of 132

110 Variable Unit Settlement Interval Definition DaSpinSppHrlyQty h MW Hour Total SPP Day-Ahead Spinning Reserve Hourly Quantity per Hour The total amount of Spinning Reserve cleared in the DA Market for Hour h. DaSpinInterObligSppHrlyQty h MW Hour Day-Ahead SPP Spinning Reserve Interim Obligation Quantity per AO per Reserve Zone per Hour The total of all Asset Owner s DA Market Spinning Reserve interim obligation over all Reserve Zones for Hour h. DaSpinInterAoObligHrlyQty a, z, h MW Hour Day-Ahead Spinning Reserve Interim Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Spinning Reserve interim obligation that includes treatment of ContrSpinHrlyQty a, z, h, t but does not include allocation of excess ContrSpinHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaSpinIniAoObligHrlyQty a, z, h MW Hour Day-Ahead Spinning Reserve Initial Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Spinning Reserve initial obligation that does not include treatment of ContrSpinHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaSpinObligRatio h none Hour Day-Ahead Spinning Reserve Asset Owner Obligation Ratio per Hour The percentage applied to Asset Owner a s DaSpinInterAoObligHrlyQty a, z, h to account for allocation of any excess ContrSpinHrlyQty a, z, h, t in Reserve Zone z in Hour h. DaSpinSlObligHrlyQty a, s, z, h MW Hour Day-Ahead Spinning Reserve Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a s DA Market Spinning Reserve initial obligation that does not include treatment of ContrSpinHrlyQty a, z, h, t at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. DaSpinMcpHrlyPrc z, h $/MW Hour Day-Ahead MCP for Spinning Reserve per Reserve Zone The value described under Section for Reserve Zone z. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 16 of of 132

111 Variable Unit Settlement Interval Definition DaSpinSpxHrlyRate h $/MW Hour Day-Ahead Spinning Reserve SPP Exchange Rate per Hour The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Spinning Reserve from other Reserve Zones in order to meet the Reserve Zone Spinning Reserve obligation. RtSpinRznLoadHrlyQty a, s, z, h MWh Hour Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h Asset Owner a s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Spinning Reserve cost allocation. RtBillMtr5minQty a, s, i MW Dispatch Interval Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section for Reserve Zone z. PctSlinRznSpinHrlyFct a, s, z, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour The percentage factor of AO a s load at Settlement Location s that is contained within Reserve Zone z for use in Spinning Reserve cost allocation. RtImpExp5minQty a, s, i, t MW Dispatch Interval Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction The value described under Section for Reserve Zone z. RsgCrdFlg t none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event The value described under Section SpinFinHrlyQty a, z, h, t MW Hour Financial Schedule for Spinning Reserve per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Financial Schedule transaction t for Spinning Reserve at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. DaSpinDistDlyAmt a, z, d $ Operating Day Day-Ahead Spinning Reserve Distribution Amount per AO per Reserve Zone per Operating Day - AO a s share of DA Market Spinning Reserve procurement costs for Reserve Zone z in Operating Day d. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 17 of of 132

112 Variable Unit Settlement Interval Definition DaSpinDistAoAmt a, m, d $ Operating Day DaSpinDistMpAmt m, d $ Operating Day Day-Ahead Spinning Reserve Distribution Amount per AO per Operating Day - AO a s for total DA Market Spinning Reserve procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Spinning Reserve Distribution Amount per MP per Operating Day - MP m s share of total DA Market Spinning Reserve procurement costs for in Operating Day d. a none none An Asset Owner. s none none A Settlement Location. h none none An Hour. z none none A Reserve Zone. i none none A Dispatch Interval. t none none A single tagged Interchange Transaction, a single virtual energy transaction, a single Financial Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. d none none An Operating Day. m none none A Market Participant. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 18 of of 132

113 The above variables are defined as follows: Variable Unit Settlement Interval Definition DaSuppDistHrlyAmt a, z, h $ Hour Day-Ahead Supplemental Reserve Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a s share of DA Market Supplemental Reserve procurement costs in Reserve Zone z in Hour h. DaSuppDistHrlyRate z, h $/MW Hour Day-Ahead Supplemental Reserve Distribution Hourly Rate per Reserve Zone per Hour The rate applied to AO a s Supplemental Reserve obligation within Reserve Zone z in Hour h. ContrSuppHrlyQty a, z, h, t MW Hour Contracted Supplemental Reserve per AO per Reserve Zone per Transaction per Hour AO a s contracted Supplemental Reserve transaction t being supplied to Reserve Zone z from outside of the SPP BA to meet AO a s Supplemental Reserve obligation. Contracted Supplemental Reserve being supplied to AO a is a positive value. DaSuppRznHrlyCost z, h $ Hour Day-Ahead Reserve Zone Supplemental Reserve Cost per Reserve Zone per Hour The total DA Market Supplemental Reserve procurement cost for Reserve Zone z in Hour h. DaSuppHrlyQty a, s, z, h MW Hour Day-Ahead Supplemental Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour The value described under Section in Reserve Zone z. DaSuppAoObligHrlyQty a, z, h MW Hour Day-Ahead Supplemental Reserve Asset Owner Obligation Quantity per Reserve Zone per Hour Asset Owner a s DA Market Supplemental Reserve obligation in Reserve Zone z for Hour h. DaSuppRznHrlyQty z, h MW Hour Day-Ahead Supplemental Reserve Hourly Quantity per Reserve Zone per Hour The total amount of cleared Supplemental Reserve in Reserve Zone z for Hour h. DaSuppObligRznHrlyQty z, h MW Hour Day-Ahead Supplemental Reserve Obligation per Reserve Zone per Hour Reserve Zone z s DA Market Supplemental Reserve obligation for Hour h. Deleted: from outside Deleted: or AO a s contracted Supplemental Reserve being supplied from Reserve Zone z to another Reserve Zone in Hour h Deleted: and contracted Supplemental Reserve being supplied from AO a is a negative value Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 19 of of 132

114 Variable Unit Settlement Interval Definition ContrSuppSppHrlyQty h MW Hour Contracted Supplemental Reserve per Hour The total of all ContrSuppHrlyQty a, z, h, t for Hour h. RtLoadSppHrlyQty h MW Hour Real-Time SPP Load per Hour The value described under Section DaSuppSppHrlyQty h MW Hour Total SPP Day-Ahead Supplemental Reserve Hourly Quantity per Hour The total amount of Supplemental Reserve cleared in the DA Market for Hour h. DaSuppInterObligSppHrlyQty h MW Hour Day-Ahead SPP Supplemental Reserve Interim Obligation Quantity per AO per Reserve Zone per Hour The total of all Asset Owner s DA Market Supplemental Reserve interim obligation over all Reserve Zones for Hour h. DaSuppInterAoObligHrlyQty a, z, h MW Hour Day-Ahead Supplemental Reserve Interim Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Supplemental Reserve interim obligation that includes treatment of ContrSuppHrlyQty a, z, h, t but does not include allocation of excess ContrSuppHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaSuppIniAoObligHrlyQty a, z, h MW Hour Day-Ahead Supplemental Reserve Initial Asset Owner Obligation Quantity per AO per Reserve Zone per Hour Asset Owner a s DA Market Supplemental Reserve initial obligation that does not include treatment of ContrSuppHrlyQty a, z, h, t in Reserve Zone z for Hour h. DaSuppObligRatio h none Hour Day-Ahead Supplemental Reserve Asset Owner Obligation Ratio per Hour The percentage applied to Asset Owner a s DaSuppInterAoObligHrlyQty a, z, h to account for allocation of any excess ContrSuppHrlyQty a, z, h, t in Reserve Zone z in Hour h. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 20 of of 132

115 Variable Unit Settlement Interval Definition DaSuppSlObligHrlyQty a, s, z, h MW Hour Day-Ahead Supplemental Reserve Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a s DA Market Supplemental Reserve initial obligation that does not include treatment of ContrSuppHrlyQty a, z, h, t at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. DaSuppMcpHrlyPrc z, h $/MW Hour Day-Ahead MCP for Supplemental Reserve per Reserve Zone The value described under Section for Reserve Zone z. DaSuppSpxHrlyRate h $/MW Hour Day-Ahead Supplemental Reserve SPP Exchange Rate per Hour The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Supplemental Reserve from other Reserve Zones in order to meet the Reserve Zone Supplemental Reserve obligation. RtSuppRznLoadHrlyQty a, s, z, h MWh Hour Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h Asset Owner a s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Supplemental Reserve cost allocation. RtBillMtr5minQty a, s, i MW Dispatch Interval Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section for Reserve Zone z. PctSlinRznSuppHrlyFct a, s, z, h % Hour Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour The percentage factor of AO a s load at Settlement Location s that is contained within Reserve Zone z for use in Supplemental Reserve cost allocation. RtImpExp5minQty a, s, i, t MW Dispatch Interval Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction The value described under Section for Reserve Zone z. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 21 of of 132

116 Variable Unit Settlement Interval Definition RsgCrdFlg t none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event The value described under Section SuppFinHrlyQty a, z, h, t MW Hour Real-Time Financial Schedule for Supplemental Reserve per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Financial Schedule transaction t for Supplemental Reserve at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. DaSuppDistDlyAmt a, z, d $ Operating Day DaSuppDistAoAmt a, m, d $ Operating Day DaSuppDistMpAmt m, d $ Operating Day Day-Ahead Supplemental Reserve Distribution Amount per AO per Reserve Zone per Operating Day - AO a s share of DA Market Supplemental Reserve procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Supplemental Reserve Distribution Amount per AO per Operating Day - AO a s for total DA Market Supplemental Reserve procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Supplemental Reserve Distribution Amount per MP per Operating Day - MP m s share of total DA Market Supplemental Reserve procurement costs for in Operating Day d. a none none An Asset Owner. s none none A Settlement Location. h none none An Hour. z none none A Reserve Zone. i none none A Dispatch Interval. t none none A single tagged Interchange Transaction, a single virtual energy transaction, a single Financial Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. d none none An Operating Day. m none none A Market Participant. Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 22 of of 132

117 APPENDIX F The obligation to pay for OR procured in the DA Market is not only a function of zonal load, but also contracts for supply and Financial Schedules for OR obligation. Given the firm transmission available to affect the contract, AOs can meet the obligation from outside the footprint. The SPP clearing requirement is reduced for obligation met by external supply by contract. Financial Schedules merely swap obligation in a single RZN among 2 AOs. Deleted: move obligation between internal RZNs or Attach 16 - MPRR1 Remove Internal Reserve Zone Transfers & Minimum Clause.docx Page 23 of of 132