Southwest Power Pool MARKET WORKING GROUP MEETING … 8-28-15 minutes and attachments.pdfJim...

Southwest Power Pool

MARKET WORKING GROUP MEETING

August 28, 2015

Conference Call • M I N U T E S •

Agenda Item 1 — Call to Order, Proxies, Agenda Discussion Richard Ross (AEP) called the meeting to order at 9:00 a.m. The attendance was recorded and proxies were announced (Attachment 1 – MWG Attendance August 28 2015). The following members were represented by proxy:

Michael Massery (AECC) for Brad Johnston (AECC) (Attachment 1a – Brad Johnston Proxy)

The group reviewed the agenda (Attachment 2 - MWG Agenda for August 28 2015). Agenda Item 2 — JOU Combined Resource Option Market Design Changes Debbie James (SPP) presented the JOU Combined Resource Option Market Design changes to the MWG (Attachment 3 - JOU Combined Resource Analysis 20150828). She explained the unintended consequences under JOU Combined Resource Option that some shares of the JOU could be committed uneconomically and “free ride” the system. Some members expressed concerns that the definition of a “free rider” should not always include those shares with different fuel contracts. Debbie discussed SPP RTO’s process of analyzing the financial impacts to the Integrated Marketplace and Catherine Mooney discussed SPP MMU’s process. Debbie explained some of the possible solutions to the unintended consequence of the JOU Combined Resource Option. Jim Flucke (KCPL) and Cliff Franklin (WR) will work with SPP Staff to further refine the options presented or develop new options and bring a recommendation to the MWG. Agenda Item 3 — RR112 - ECC Clean Up Jim Gonzalez (SPP) explained to the MWG that SPP Staff has recently identified other proposed language that needs to be included in the ECC Clean Up, including language associated with the agenda item on ECC Overlapping MWPs being discussed at this 8/28 meeting. SPP will submit comments to RR112 ECC Clean Up with the additional proposed language and present those comments at the September MWG meeting (Attachment 4 - RR112 ECC Cleanup). Agenda Item 4 — ECC Overlapping MWPs Jim Gonzalez (SPP) presented the overlapping Make-Whole Payment (MWP) presentation to the MWG (Attachment 5 - ECC MWP). He explained that current logic allows RUC processes to move an ECC Resource to a higher configuration in an already committed period of time. This scenario would lead to a Resource having a Day-Ahead and Real-Time MWPs to overlap each other. Jim discussed three different options that SPP could write up in order to solve the overlapping MWP discussion. At the last MWG meeting, some members expressed concerns that RR112 states Offline Supplemental may only be offered for one ECC Resource configuration due to risks of performance. An alternative approach was discussed where online ECC Resources could potentially clear Offline Supplemental if the ECC Resource

Minutes No. [241]

had higher configurations available for commitment. Jim explained that the MCE would likely be able to support this without significant performance impacts. The MWG directed SPP Staff to submit comments to RR112 with proposed language to make the ECC Resource whole to the incremental costs due to the Real-Time commitment decision and to add the language to support the ECC Resource configurations to be able to clear Offline Supplemental. The MWG will review these comments at September’s MWG meeting. Agenda Item 5 — RR104 DVER Minimum Limit Gary Cate (SPP) presented the SPP RTO’s concerns with changing the Regulation Minimum Limit for DVERs offering Regulation Service to a non-zero amount, as requested in RR104 (Attachment 6 - DVER Minimum Limit & Ramp Rate Requirement Change). This change would not reflect the true capability of DVERs, it would reduce the amount of available dispatchable range in Real-Time, and would add Reliability concerns. Daniel Baker (SPP) presented the RTO’s concerns with the changes to Ramp Rate Limits for DVERs. Background information was provided on how and why the 20% threshold was established. Daniel summarized the Ramp Rate Limit design for DVERs and provided examples to illustrate the SPP RTO’s concern with increasing the Limit. The MWG reviewed the language in RR104 (Attachment 7 - RR104 Xcel Comments 7-8-2015). Amber Metzker (Xcel) will draft comments for September’s MWG meeting to change the proposed redline language previously submitted, as discussed during the meeting. Agenda Item 26 - Review of Motions, Action Items and Future Meetings

Motions: None recorded Action Items: None recorded Future Meetings: September 15, 2015 (8:15 a.m. – 6:00 p.m.) September 16, 2015 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor September 17, 2015 Hub Face to Face Location: AEP Office – Dallas, TX Room: 8th Floor October 20, 2015 (8:15 a.m. – 6:00 p.m.) October 21, 2015 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor

Minutes No. [241]

Agenda Item 31 – Adjournment Richard Ross (AEP) adjourned the meeting at 11:45 p.m.

Respectfully Submitted, Debbie James Secretary

Minutes No. [241]

Attachments Attachment 1 - MWG Attendance August 28 2015 Attachment 1a - Brad Johnston Proxy Attachment 2 - MWG Agenda for August 28 2015 Attachment 3 - JOU Combined Resource Analysis 20150828 Attachment 4 - RR112 ECC Cleanup Attachment 5 - ECC MWP Attachment 6 - DVER Ramp Constraint Attachment 7 - RR104 Xcel Comments 7-8-2015

X = In PersonP = By Phone* = By Proxy

Day 1 Full Name Company E-mail Business Phone Other PhoneP Richard Ross (Chair) AEP rross@aep.com (918) 599-2966 (918) 284-8702P Jim Flucke (V-Chair) KCPL jim.flucke@kcpl.com (816) 701-7836

Aaron Rome Midwest Energy arome@mwenergy.com (785) 625-1431P Amber Metzker Xcel Energy amber.l.metzker@xcelenergy.com (303) 571-6202 (920) 650-2040P Ann Scott Tenaska ascott@tnsk.com (817) 462-1514* Brad Johnston AECC brad.johnston@aecc.com

Chris Lyons Exelon chris.lyons@exeloncorp.com (410) 470-2465Cliff Franklin Westar clifford.franklin@westarenergy.com (443) 226-7787

P Debbie James (Sec) SPP djames@spp.org (501) 614-3577P Kevin Galke City Utilities, Springfield kgalke@teainc.org (904) 360-1460P Lee Anderson LES landerson@les.com (402) 467-7591P Matt Moore Golden Spread Electric Coop mmoore@gsec.coop (806) 379-7766

Mike Mushrush OMPA mmushrush@ompa.comNeal Daney KMEA daney@kmea.com (913) 660-0242Rick McCord EDE rmccord@empiredistrict.com (417) 625-5129 (402) 616-3522

P Rick Yanovich OPPD ryanovich@oppd.com (402) 514-1031P Ron Thompson NPPD rfthomp@nppd.com (402) 845-5202

Shawn McBroom OGE mcbroosr@oge.com (405) 239-0255 (405) 553-3267Valerie Weigel Basin Electric Power Co. vweigel@bepc.com (701) 557-5430Aaron Doll EDE adoll@empiredistrict.com

P Aaron Theisen RPM Access atheisen@rpmaccess.comAaron Wangler Basin Electric Power Co. aaronw@bepc.comAdam Bigknife OGE bigkniaw@oge.comAdam Cochran TNSK acochran@tnsk.comAdam Jordan Genscape ajordan@genscape.comAdam McKinnie MOPSC adam.mckinnie@psc.mo.gov (573) 522-8706Adam Schieffer MEAN aschieffer@nmppenergy.orgAditya Sharma AEP asharma@aep.comAiden Smith SWPA aiden.smith@swpa.govAJ Joyce Basin Electric Power Co. ajoyce@bepc.comAl Bright WAPA albright@wapa.govAl Taylor East Texas Coops al.taylor@hklaw.comAlan Adams Utilicast aadams@utilicast.comAlan McQueen SPP amcqueen@spp.orgAlan Rukin JSS Law arukin@jsslaw.comAlex Azanov Cargill alex_azanov@cargill.comAlfred Busbee SPP abusbee@spp.orgAlice Wright SPP awright@spp.orgAlison Hayes SPP ahayes@spp.orgAllan George SECI ageorge@sunflower.netAllison Wahrenberger Enel allison.wahrenberger@enel.com

Market Working GroupAugust 28, 2015

Face to Face Conference

Amy Casavechia SPP acasaechia@spp.orgAmy Jeffries AEP aejeffries@aep.comAndrew Culham andrewculham@comcast.netAndrew Ferris BPU aferris@bpu.comAndrew Hall ACES andrewh@acespower.com (317) 344-7151Andrew Hartshorn BETM andrew.hartshorn@betm.comAnne Vogel AEP amvogel@aep.comAnnette Holbert SPP aholbert@spp.orgAnthony Hammond Midwest Ben ahammond@lspower.com (917) 717-1842Anthony Lemaire TNSK alemaire@tnsk.comAntoine Lucas SPP alucas@spp.orgAshish Tripathi Ventyx ashish.tripathi@ventyx.abb.comAshwini Koppula Ventyx ashwini.koppula@ventyx.abb.comAustin Hoekman MREnergy ahoekman@mrenergy.comBarbara Stroope SPP bestroope@spp.org (501) 688-1792Barry Huddleston Clean Line bhuddleston@cleanlineenergy.com (832) 319-6358Barry Warren EDE bwarren@empiredistrict.com (417) 625-4234Bart Tsala The Kidiaga Group btsala@kidiaga.com (405) 896-5899Becky Gifford SPP bgifford@spp.orgBen Stander OATI ben.stander@oati.netBenjamin Maher NMPP bmaher@nmppenergy.orgBernie Kinsella EDPR bernie.kinsella@edpr.comBeth Hume SPP bhume@spp.orgBeth Miller Accenture beth.miller@accenture.comBeth Watts Accenture beth.j.watts@accenture.comBill Grant Xcel Energy william.a.grant@xcelenergy.com (806) 378-2928Bill Leung BJLEUNG bleung@bjleung.comBill Nolte SECI bdnolte@sunflower.net (420) 272-5458Bill Olson Xcel Energy bill.olson@xcelenergy.comBill Reid Climate Energy Project wmreid@sbcglobal.net (405) 816-5456

P Billy Cutsor MEAN bjcutsor@nmppenergy.orgBilly Yancey EPE Consulting byancey@epeconsulting.comBlaine Erhardt BEPC berhardt@bepc.comBlythe French Xcel blythe.f.french@xcelenergy.comBob Burner Duke Energy g.burner@duke-energy.comBob Tumilty AEP retumilty@aep.comBob Wittmeyer Longhorn Power bwittmeyer@longhornpower.comBrad Hans MEAN bhans@nmppenergy.org 402-474-4759Brenda Fite SPP bfite@spp.orgBrenda Fricano SPP bfricano@spp.orgBrenda Lee Structure brenda.lee@thestructuregroup.comBrent Hebert PSI/EPV/KELSON/ETEC brent.hebert@psisot.net (832) 663-1373Brent Hendrickson Nexant bhendrickson@nexant.com (404) 276-9008Brent Wilcox SPP bwilcox@spp.org (501) 688-8267Brett Hooton SPP bhooton@spp.org (501) 688-1684Brett Kruse Calpine brett.kruse@calpine.com (713) 830-8732

Brian Gedrich Nextera brian.gedrich@nee.com (512) 284-4168Brian Hurst GRDA bhurst@grda.comBrian Skinner Tenaska bskinner@tnsk.comBrian Moix SPP bmoix@spp.orgBrittney Miller APSC brittney_miller@psc.state.ar.usBruce Rew SPP brew@spp.comBryan Clark SPP bclark@spp.orgBryn Wilson OGE wilsonwb@oge.comC Tarwater CES LTD ctarwater@ces-ltd.comCarl Monroe SPP cmonroe@spp.orgCarla Holly BP Energy carla.holly@bp.comCarol Shoemake OGE shoemaca@oge.comCarrie Bumgarner Wright Talisman bumgarner@wrightlaw.comCarrie Carrigan TEA ccarrigan@teainc.orgCarrie Cooper ETEC carrie.cooper@gdsassociates (770) 715-7189

P Carrie Dixon Xcel carrie.e.dixon@xcelenergy.comCarrie Simpson Invenergy csimpson@inevenergy

P Casey Cathey SPP ccathey@spp.org (501) 614-3267Casey Strange OGE strangcl@oge.com

P Catherine Mooney SPP cmooney@spp.orgCelso Alonso OGE alonsoc@oge.comChad Unrein KS Corp Comm c.unrein@kcck.gov (785) 271-5176Chance Scott Xcel chance.scott@xcelenergy.com

P Chandler Brown SECI cwbrown@sunflower.netCharles Cates SPP ccates@spp.orgCharles Marshall ITC Transco cmarshall@itctransco.com (248) 946-3276Chris Bevil Southern Power cbevil@southernco.comChris Casale Iberdrola chris.casale@iberdrolausa.comChris Davis SPP cdavis@spp.org (501) 688-2546Chris Devon Michigan PSC devonc@mighigan.govChris Giles TCEC cgiles@tcec.coopChris Jones Duke Energy chris.jones@duke-energy.comChris Lax SPP clax@spp.org (501) 614-3594Chris Matos GSEC cmatos@gsec.coopChris Matthes AEP camatthes@aep.comChris Standifer KCPL chris.standifer@kcpl.comChris Werner AEP cmwerner@aep.com

P Chris Winburn INDN cwinbrun@indepmo.orgChris Ziembko TEA cziembko@teainc.orgChristi Nicolay Macquarie christi.nicolay@macquarie.comChristina Labij Acciona clabij@acciona-na.comChristopher Meyers WAPA cmeyers@wapa.govChristopher Payne SPP cpayne@spp.orgCindy Ireland AR PSC cireland@psc.state.at.usCJ Brown SPP cbrown@spp.orgClint Savoy SPP csavoy@spp.org (501) 614-3590

Cody VandeVelde WR cody.vandevelde@westarenergy.comCourtney Mehan Tenaska cmehan@tnsk.comCyril Canezin Durable Power ccanezin@durablepwr.comD Mosolf MISO dmosolf@misoenergy.orgDan Lenihan OPPD djlenhan@oppd.comDan Trent AECI dtrent@aeci.orgDana Boyer SPP dboyer@spp.orgDanny Trent OGE trentdw@oge.com (405) 553-3687 (405) 550-5152Daniel Baker SPP dbaker@spp.orgDaniel Harless SPP dharless@spp.orgDaniel Smith PSC MO daniel.smith@psc.mo.govDarrell Wilson OGE wilsondw@oge.comDave Almsted MCG Energy dalmsted@mcgenergy.com (612) 240-9733Dave Charles ND PSC dcharles@nd.govDave Hines MISO dhines@misoenergy.orgDave Osburn OMPA iphone_test@webex.comDave Pettinger OPPD dpettinger@oppd.comDave Savage RES-Americas david.savage@res-americas.comDavid Adamczyk KCPL david.adamczyk@kcpl.comDavid Charles ND PSC dcharles@nd.govDavid Dan Power Settlements david.dan@powersettlements.comDavid Daniels SPP ddaniels@spp.orgDavid Erickson AEP dgerickson@aep.com (614) 583-7405David Hackett KEMA dhackett@us.kema.com (321) 600-1228David Hastings DHASTCO david@dhast.com (317) 217-9563David Hurtado SPP dhurtado@spp.orgDavid Kays OGE kaysdl@oge.comDavid Kelley SPP dkelley@spp.org (501) 688-1671David Lee SPP dlee@spp.org (501) 614-3333David Lemmons Xcel david.f.lemmons@xcelenergy.comDavid Linton ITC-GP dlinton@itctranso.com (314) 341-5769David Marshall Southernco dcmarsha@southernco.comDavid Shaffer Wright Talisman shaffer@wrightlaw.comDavid Smith Shell dave.l.smith@shell.comDavid Theobald OPPD dtheobald@oppd.comDeb Roby JSS Law droby@jsslaw.comDebbie Prater Oklahoma Corp Comm d.prater@occemail.com (405) 521-6950Dena Giessmann SPP dgiessmann@spp.orgDenise Buffington KCPL denise.buffington@kcpl.comDennis Reed Westar dennis.l.reed@westarenergy.comDerek Mosolf MCG Energy dmosolf@mcgenergy.comDiane Arthur SPP darthur@spp.orgDiane Janicki Edison Mission djanicki@edisonmission.com (312) 583-6028Dick Kahle LES dkahle@les.comDillon Kolkmann FERC dillon.kolkmann@ferc.govDirk Dietz NPPD drdietz@nppd.com

Dirk Ludwig NPPD daludwi@nppd.comDon Gulley SECI dgulley@sunflower.netDouglas Clark SPP dclark@spp.orgDrew Robinson KCPL drew.robinson@kcpl.comEddie Watson SPP ewatson@spp.orgEdmundo Toro INV Energy etoro@invenergyllc.comEileen O'grady Argus eileen.ogrady@argusmedia.comElie Nassar Ventyx elie.nassar@ventyx.abb.comEli Whorley TNSK ewhorely@tnsk.comElizabeth Solano MISO Energy esolano@misoenergy.org

P Eric Alexander GRDA ealexander@grda.com (918) 824-7245Eric Barreveld APX eric.barreveld@apx.comErica Brooks SPP ebrooks@spp.orgErin Cullum SPP ecullum@spp.orgErin Lorimer Endure Energy e.lorimer@endureenergy.comEricka Inertia Power ericka@inertiaispower.comErik Winsand DATC ewinsand@atcllc.com

P Erin Cathey SPP ecathey@spp.orgP Esat Guney SPP eguney@spp.org

Farris Wallace Southernco fwallace@southernco.comFarrokh Rahimi OATI farrokh.rahimi@oati.net (612) 360-1654Frank Bristol Acciona fbristol@acciona-na.comFrank Harris Southernco faharris@southernco.com (205) 4827202Garrett Crowson SPP gcrowson@spp.org

P Gary Cate SPP gcate@spp.orgGary Clear OGE clearf@oge.comGary Hoffman WAPA ghoffman@wapa.govGary Rosenwald The Glarus Group gary.rosenwald@theglarusgroup.comGary Shannon AEP gwshannon@aep.com

P Gay Anthony SPP ganthony@spp.org (501) 688-1722Gayle Freier SPP gfreier@spp.orgGentry Crowson SPP gcrowson@spp.orgGeoff Coventry Trade Wind gcoventry@tradewindenergy.comGeoff Hocker SWPA geoff.hocker@swpa.gov

P Geoffrey M Rush Oklahoma Corp Comm g.rush@occemail.comGeorge Fee AEP gfee@aep.comGeorge Kelly Accenture george.kelly@accenture.com

P Gerald Deaver Xcel gerald.r.deaver@xcelenergy.comGerald Williams SPP gwilliams@spp.orgGerardo Ugalde SPP gugalde@spp.orgGerry Murphy Xcel gmurphy@xcel.com

P Ginny Watson SPP gwatson@spp.orgGina Wilson ITC Transco gwilson@itctransco.comGrant Wilkerson Westar grant.wilkerson@westarenergy.comGreg Adams Adams Wind adamswind@gmail.comGregory Pakela DTE Energy pakelag@dteenergy.com

Guadalupe Vazquez Acciona gvazquez@acciona-na.comH Lao AEP hlao@aep.comHailey McKewon GRDA hmckewon@grda.comHanhan Hammer SPP hhammer@spp.org (501) 688-8248Harry Skilton Director hskiltondra@comcast.netHarshikesh Panchal XO Energy hpanchal@xo-energy.comHassan Shah SPP hshah@spp.orgHeather Starnes MJMEUC/CUS hstarnes1969@gmail.comHoward Haas Monitoring Analytics howard.haas@monitoringanalytics.comHsin Foo KCPL hsin.foo@kcpl.comIshwar Saini Macquarie ishwar.saini@macquarie.comJack Clark NEE jack.clark@nee.com

P Jack Madden GDS Associates jack.madden@gdsassociates.comJackson King Constellation jackson.king@constellation.comJacob Justice Aces Power Marketing jacobj@acespower.comJacob Springman Aces Power Marketing jacobs@acespower.comJake Langthorn OGE langthjs@oge.comJamel Thomas SPPJames Fife PSI/EPV/KELSON/ETEC jfife1@entergy.com (281) 297-5406James Lewis Noble Power lewisJ@noblepower.comJames Lemley SPP jlemley@spp.org (501) 614-3575James Meitner Westar james.meitner@westarenergy.comJames Sanderson KCC j.sanderson@kcc.ks.gov (785) 271-3159James Sweatt Southernco jmsweatt@southernco.comJamie Johnson NMPP jjohnson@nmppenergy.orgJamie Wheeler GRDA jamiewheeler@grda.comJan Bagnall SWPA jan.bagnall@swpa.gov

P Jared Greenwalt SPP jgreenwalt@spp.orgJarrald Woodcock Nextera jarrald.woodcock@nexteraenergy.comJarrett Friddle SPP jfriddle@spp.orgJason Bailey OGE baileyjd@oge.comJason Chaplin OCC j.chaplin@occemail.comJason Davis SPP jdavis@spp.org (501) 614-3374Jason Doerr Basin Electric Power Co. jdoerr@bepc.com (701) 557-5388Jason Fix LES jfix@les.comJason Hebert PCI jhbert@powercosts.comJason Minalga INV Energy jminalga@invenergyllc.comJason Robison SPP jrobison@spp.org (501) 688-1711Jason Russell SPP jrussell@spp.orgJason Smith SPP jsmith@spp.orgJason Tanner SPP jtanner@spp.orgJason Terhune SPP jterhune@spp.orgJay Caspary SPP jcaspary@spp.orgJay Goldman BETM jay.goldman@betm.comJay Sher FERC jay.sher@ferc.govJeff DiSciullo Wright Talisman disciullo@wrightlaw.com

Jeff Knottek City Utilities, Springfield jeff.knottek@cityutilities.netJeff Riles Enel jeff.riles@enel.comJennifer Flandermeyer KCPL jennifer.flandermeyer.comJennifer Swierczek SPP jswierczek@spp.orgJennifer Weatherford GRDA jweatherford@grda.comJeremi Wofford CUS jeremi.wofford@cityutilities.netJeremy Hodges TEA jhodges@teainc.orgJeremy Shipman Structure Group jeremy.shipman@thestructuregroup.comJeremy Verzosa SPP jverzosa@spp.orgJerin Purtee KBPU jpurtee@bpu.comJerry Ohmes KCBPU johmes@bpu.com (913) 573-6816Jerry Stone SPP jastone@spp.org

P Jerry Tielke MREnergy jtielke@mrenergy.comJessica Collins Xcel jessica.l.collins@xcelenergy.comJessica Kasparek LES jkasparek@les.comJianfeng Zhang CES-LTD jzhang@ces-ltd.com

P Jill Coffey KCPL jill.coffey@kcpl.comJill Jones MEAN jjones@nmppenergy.orgJim Fort TEA jfort@teainc.org

P Jim Gonzales SPP jgonzalez@spp.orgJim Guidroz Supervisor of Tariff Administration jguidroz@spp.org (501) 614-3900Jim Gunnell SPP jgunnell@spp.orgJim Hotovy NPPD jrhotov@nppd.comJim Jacoby AEP jwjacoby@aep.comJim Krajecki Customized Energy Solutions jkrajecki@ces-ltd.comJim Stevens PSI/EPV jim@psisoft.net (713) 253-9396JJ Guo AEP jguo@aep.comJodi Woods SPP jwoods@spp.orgJody Sundsted WAPA sundsted@wapa.govJoe Byers SPP jbyers@spp.orgJoe Bumgarner SPP jbumgarner@spp.orgJoe Ghormley SPP jghormley@spp.orgJoe Lang LES jlang@les.com (402) 473-3401Joe Smith Joe joe@joe.comJoe Taylor Xcel Energy josepth.c.taylor@excelenergy.com (303) 571-7462Joe Waszak OPPD jmwaszakjr@oppd.comJoel Bearden XO Energy jbearden@xo-energy.comJoey Schrepel BEPC jschrepel@bepc.comJohn Allen Aces Power jallen@acespower.comJohn Allen CUS john.allen@cityutilities.com

P John Bell KCC j.bell@kcc.ks.gov (785) 271-3139John Boshears CUS john.boshears@cityutilities.netJohn Fernandes ResAmericas john.fernandes@res-americas.comJohn Grotzinger MPUA jgrotzinger@mpua.orgJohn Harvey Exelon john.harvey@exeloncorp.com (515) 221-5717John Henry jh@yahoo.com

John Holloway AEP jpholloway@aep.comJohn Hyatt SPP jhyatt@spp.orgJohn Knofczynski Basin Electric Power Co. jknofczynski@bepc.com (605) 270-1335John Krajewski Energy Consulting jk@jkenergyconsulting.com (402) 440-0227

P John Luallen SPP jluallen@spp.orgJohn Olsen WR johnolsen@westarenergy.comJohn Seck KMEA seck@kmea.comJohn Snyder SPP jsnyder@spp.orgJohn Stephens City Utilities John.Stephens@cityutilities.net (417) 831-8470John Sturm Aces Power Marketing (APM) jsturm@acespower.com (317) 696-9031

P John Tennyson City Utilities john.tennyson@cityutilities.netJohn Varnell Tenaska jvarnell@tnsk.com (817) 462-1037John Weber MREnergy john.weber@mrenergy.comJon Olson MCG Energy jolson@mcgenergy.com (615) 253-8820Jon Sunneberg NPPD jmsunne@nppd.comJoseph Ferrari Wartsila joseph.ferrari@wartsila.comJosh Weinstein Chase weinstein@chase.netJoshua Roper KCPL joshua.roper@kcpl.com (816) 556-2038Judith Judson McQueeney CES jjudson-mcqueeney@ces-ltd.comJuliana Brint Platts juliana_brint@platts.comJulie Bittle SPP jbittle@spp.org

P Julie Gerush SPP jgerush@spp.orgJustin Cochran SPP jcochran@spp.orgKalen Coleman SPP kcoleman@spp.orgKaren Howland Southernco khowland@southernco.comKari Hollandsworth GSEC khollandsworth@gsec.coopKarl Pierce BP Energy karl.pierce@bp.comKara Sidman BP Energy kara.sidman@bp.comKatherine Prewitt SPP kprewitt@spp.org (501) 614-3518Kathy Schuerger Xcel Energy kathy.schuerger@xcelenergy.comKatie Seiverling CES-LTD kseiverling@ces-ltd.comKatie Sussen Basin Electric Power Co. ksussen@bepc.com (701) 557-5154Katy Onnen KCPL katy.onnen@kcpl.comKeith Tynes ETEC/GDS keith.tynes@gdsassociates.com (850) 490-2874Kelli Graff Xcel kelli.j.graff@xcelenergy.comKen Donald Utilicast kendonald@me.comKen Laughlin Tres Amigas klaughlin@tresamigasllc.com (484) 524-5052Ken Quimby SPP kquimby@spp.orgKen Rutter Basin Electric Power Co. krutter@bepc.com (701) 557-5390Kent Feliks AEP kdfeliks@aep.comKeven Szarkowski BEPC kszarkowski@bepc.comKevin Bates SPP kbates@spp.orgKevin Carter Duke-Energy kevin.carter@duke-energy.comKevin Drachenberg Calpine kdrachenberg@calpine.comKevin Galke CUS kgalke@teainc.orgKevin Kingsley MDU kevin.kingsley@mdu.com

Kevin Shipp Ameren kshipp@ameren.comKevin Warren SPP kwarren@spp.orgKim Sullivan WFEC k_sullivan@wfec.comKim Van Brimer SPP kvanbrimer@spp.orgKimberly Badenhop BEPC kbadenhop@bepc.comKip Fox AEP kfox@aep.comKoldo Basterra Acciona kbasterra@acciona.comKristen Rodriguez Electric Power Engineers/Wind Coalition krodriguez@epeconsulting.com (254) 399-8676 (512) 382-6700Kristy Tackett Empire ktackett@empiredistrict.comLaliya Agrawal Nexant lagrawal@nexant.com (972) 369-7572Lanny Nickel SPP lnickel@spp.org (501) 614-3232

P Larry HollowayLaura Manz Tres Amigas lmanz@viridityenergy.com (858) 354-8333Lauren Krigbaum SPP lkrigbaum@spp.orgLawson Arnett Xcel james.l.arnett@xcelenergy.comLee Robinson SPP lrobinson@spp.org

P Leeann Poteet SPP lpoteet@spp.orgLesley Bingham SPP lbingham@spp.orgLeslie Sink SPP lsink@spp.orgLevi Lyons SPP llyons@spp.orgLiam Noailles SPS liam.noailles@xcelenergy.com (303) 571-2794Linda Fellone SPP lfellone@spp.orgLisa Caserta SPP lcaserta@spp.orgLisa Flowers-Davis BEPC lflowers@bepc.com

P Lisa Szot Enel lisa.szot@enel.comLloyd Linke WAPA lloyd@wapa.govLloyd Prichard OPPD laprichard@rainbowenergy.comLonnie Lindekugel SPP llindekugel@spp.orgLori Frisk-Thompson BEPC lorift@bepc.comLorie Bailey SPP lbailey@spp.orgLuigi Sciaccaluga Enel luigi.sciaccaluga@enel.comLuke Haner OPPD lphaner@oppd.comLyle Larson Balch llarson@balch.comLyman Wilkes Physical Systems Integration lwilkes@psisoft.net (713) 443-4026 (281) 297-5449Lyudmila Siegel Constellation lyudmila.siegel@constellation.comMalcolm Booker OMPA mbooker@ompa.comManasa Ganoothula TEA mganoothula@teainc.orgMargaret Sailors OPPD msailors@oppd.com

P Marisa Choate SPP mchoate@spp.org (501) 688-1707Mark Buchholz WAPA buchholz@wapa.govMark Foreman TNSK mforeman@tnsk.comMark Holler TNSK mholler@tnsk.comMark McGrail EGPNA mark.mcgrail@enel.comMark Messerli WAPA messerli@wapa.gov

P Mark Trumble OPPD mtrumble@oppd.comMark Watson Platts markham_watson@platts.com

Mark Wiggins PCI mwiggins@powercosts.comMarquerite Wagner ICT Transco mwagner01@itctransco.comMartin Parizek CPV mparizek@cpv.comMarty Knight SPP mknight@spp.orgMary Jo Montoya Xcel Energy mary.j.montoya@xcelenergy.com (303) 571-7191Mary Lou Walker Charter marylouwalker@charter.netMatt Binette Wright Talisman binette@wrightlaw.comMatt Cupps Westar matt.cupps@westarenergy.comMatt Egger NPPD mdegger@nppd.comMatthew Harward SPP mharward@spp.orgMatthew Hazelwood TEA hazelwoodml@teainc.orgMatthew Johnson TEA mjohnson@teainc.org (904) 665-0388Maureen Ochola GDS Associates maureen.ochola@gdsassociates.comMeena Thomas Public State of Texas meena.thomas@puc.state.tx.usMehdi Assadian OATI mehdi.assadian@oati.net (925) 202-5017Mei Cheong CCI mei.cheong@ci.comMelissa Watts Southernco mlwatts@southernco.com

P Micha Bailey SPP mcbailey@spp.org (501) 688-2522Michael Billinger Midwest Energy mbillinger@mwenergy.comMichael Blackwell ACES Power mblackwell@acespower.comMichael Daly SPP mdaly@spp.orgMichael Desselle SPP mdesselle@spp.org

P Michael Erbrick MICS michael@dhast.com (281) 687-0609Michael Hutson RES Americas michael.hutson@res-americas.com

P Michael Massery AECC michael.massery@aecc.comMichael Nesmith Basin Electric Power Co. mnesmith@bepc.comMichael Ray SPP mray@spp.orgMichelle Trenary TNSK mtrenary@tnsk.comMike Berlinski Beacon Power berlinski@beaconpower.comMike Buyce CUS mike.buyce@cityutilities.netMike Chapman Kelson Energy mike.chapman@kelsonenergy.comMike Collins OGE collinmc@oge.com

P Mike Grimes EDP Renewables mike.grimes@eopr.com (713) 265-0316Mike Hood AECC mike.hood@aecc.comMike Mathsen Cargill michael_mathsen@cargill.comMike Moltane ITC mmoltane@itctransco.com (248) 946-3093Mike Oliver LES moliver@les.comMike Radecki WAPA radecki@wapa.govMike Riley SPP mriley@spp.orgMike Sheriff OGE sherifmd@oge.comMike Wech SWPA mike.wech@swpa.govMitch Elmore Xcel Energy mitch.elmore@xcelenergy.comMitch Williams WFEC m_williams@wfec.comMonica Strain KCPL monica.strain@kcpl.comMonty Baugh SPP mbaugh@spp.orgNarsi Vempati Nexant nvempati@nexant.com

Natalie McIntire natalie.mcintire@gmail.comNatasha Brown WFEC natasha.brown@wfec.comNathan Case Aces Power Marketing (APM) nathanc@acespower.comNeil Robertson SPP nrobertson@spp.org

P Nick Parker SPP nparker@spp.org (501) 614-3574Nicole King OCC n.king@occemail.comNicole Wagner SPP jwagner@spp.orgNoha Sidhom Inertia Power noha@inertiaispower.comNolan Conover TEA nconover@teainc.orgNoumvi Ghomsi MOPSC noumvi.ghomsi@psc.mo.govOmar Martino EDF omarmartino@edf-re.com (612) 618-6272Oliver Burke Entergy oburke@entergy.com (601) 985-2613Pamela Newberry OPPD pnewberry@oppd.comPat Bourne SPP pbourne@spp.orgPat Canfield XO Energy pcanfield@xo-energy.com 609-423-8004Pat Hayes Ameren phayes@ameren.comPat McGarry TEA pmcgarry@tea.inc (904) 993-9511Pat Mosier ARPSC pat_mosier@psc.state.ar.us

P Patti Kelly SPP pkelly@spp.org (501) 614-3381Patty Denny KCPL patricia.denny@kcpl.comPatty Harrell DC Energy harrell@dc-energy.comPaul Dietz Westar paul.a.dietz@ westarenergy.comPaul Krebs KCPL paul.krebs@kcpl.comPaul Mahlberg INDN pmahlberg@indepmo.orgPaul Malone NPPD pjmalon@nppd.comPaul Oleary YUMAELEC poleary@yumaelec.comPete Kinney WAPA kinney@wapa.gov (605) 882-7560 (605) 228-6758Peter Colussy Xcel peter.colussy@xcelenergy.comPeter Tucker SPP ptucker@spp.orgPhil Cox AEP epcox@aep.comPhil Stiles Acciona pstiles@acciona.com (312) 673-3027Philip Bruich SPP pbruich@spp.orgPhillip Vallejo Structure Group phillip.vallejo@thestructuregroup.comPhuong Phu KCPL phuong.phu@kcpl.comPhyllis Bernard SPP Board of Directors phyllis_bernard@sbcgobal.netPurvi Patel ITC Transco ppatel@itctransco.com (248) 946-3465Rachel Hulett SPP rhulett@spp.orgRaj Nagarsheth Denver Energy raj.nagarsheth@denverenergygroup.comRajesh Nelli AEP rbnelli@aep.com

P Raleigh Mohr SPP rmohr@spp.orgRandal Gerving MDU randal.gerving@mdu.comRandy Root GRDA rroot@grda.comRashmi Karnik Hartigen rashmi@hartigen.comRay Kershaw ITC Transco rkershaw@itctransco.com

P Rebecca Atkins MPUA ratkins@mpua.orgRebecca Gillespie FERC rebecca.gillespie@ferc.gov

Rebecca Hohnstein LES rhohnstein@les.comRebecca Sanders SPP rsanders@spp.orgRene Garza AEP rfgarza@aep.comRhonda Robinson Calpine rhonda.robinson@calpine.comRich Deming Citi richard.j.deming@citi.comRichard Dillon SPP rdillon@spp.org (501) 614-3228Richard Miller Structure Group rich.miller@thestructuregroup.comRick Kosch LES rkosch@les.comRick Mueller OPPD rjmueller@oppd.comRick Running rickrunning@hotmail.comRicky Finkbeiner SPP rfinkbeiner@spp.orgRob Jones GRDA rjones@grda.comRobert Janssen Kelson Energy rob.janssen@kelsonenergy.comRobert Pennybaker AEP rlpennybaker@aep.comRobert Pick NPPD rjpick@nppd.com

P Robert Safuto Customized Energy Solutions rsafuto@ces-ltd.com (917) 446-2579Robert Shields AECC rshields@aecc.comRobert Stillwell IPL rstillwel@indepmo.org (813) 325-7482Robert Walker Cargill robert_walker@cargill.com (952) 984-3747Roberto Rösner Enel roberto.rosner@enel.comRon Chartier SECI rchartier@sunflower.netRoy Boyer Xcel Energy roy.boyer@xcelenergy.comRoy Klusmeyer WFEC r_klusmeyer@wfec.com (405) 247-4275

P Roy True Aces Power Marketing (APM) royt@acespower.com (317) 695-4146 (317) 695-4146Russ McRae Alstom russ.mcrae@alstom.com

P Russell Quattlebaum SPP rquattlebaum@spp.orgRyan Burkhalter Citi ryan.burkhalter@citi.comRyan Hicks SPP rhicks@spp.orgRyan Kirk AEP rkirk@aep.comRyan Turner CUS ryan.turner@cityutilities.netRyan Stock AEP rtstock@aep.comSam Ellis SPP sellis@spp.orgSam Mall City of Denton sam.mall@cityofdenton.comSandeep Baidwan Lspower sbaidwan@lspower.comSanjoy Ksarawgi AEP sksarawgi@aep.com

P Sarah Pettus Wind Coalition sarah@windcoalition.orgScott Cassaday TNSK scassaday@tnsk.comScott Shepherd ABB scott.shepherd@abb.ventyx.comScott Smith SPP ssmith@spp.orgSeth Cochran DC Energy cochran@dc-energy.com (512) 971-8767Seth Hayik Monitoring Analytics seth.hayik@monitoringanalytics.comShah Hossain EDE shossain@empiredistrict.comShalini Gupta SPP sgupta@spp.orgShane Jensen OPPD sjenson@oppd.comShari Brown SPP sbrown@spp.org

P Shawn Geil KEPCo sgeil@kepco.org

P Shawnee Claiborn-Pinto PUCT shawnee.claiborn-pinto@puc.state.tx.us (512) 936-7388Shelly Trammell WFEC s_trammell@wfec.comSherman Elliott shermanelliott@comcast.netSherry Hamilton SPP shamilton@spp.orgShivram Sundar Denver Energy shivram.sundar@denverenergygroup.com

P Sonya Hall SPP shall@sppp.orgSteve Davis SPP sdavis@spp.orgSteve Gaw Wind Capital Group RSGaw1@gmail.com (573) 645-0727Steve Haun LES shaun@les.comSteve Maestrauzi Genscape smaestrauzi@genscape.com 817-790-0927Steve McDonald Aces Power Marketing (APM) smcdonald@acespower.com (317) 344-7113Steve Mckee AEP sbmckee@aep.comSteve Purdy SPP spurdy@spp.orgSteve Terelmes PCI sterelmes@powercosts.comSteve White SPP swhite@spp.orgSteven Harrington GSEC sharrington@gsec.coopSteven Larry Tenaska slarry@tnsk.comStuart Rein Boston Pacific srein@bostonpacific.comSusan Polk SPP spolk@spp.orgSusan Quinn Westar susan.quinn@westarenergy.comTamika Barker SPP tbarker@spp.orgTemper Williams SPP trwilliams@spp.orgTemujin Roach SPP troach@spp.orgTennille Tims SPP ttims@spp.orgTerri Wendlandt WR terri.wendlandt@westarenergy.com

P Terry Gates AEP tlgates@aep.com (614) 716-6232 (614) 361-5235P Terry Volkmann

Terry Wright EDE twright@empiredistrict.comTessie Kentner SPP tkentner@spp.orgTim Flanagan TEA tflanagan@teainc.orgTim Herr SPP therr@spp.org

P Tim Hooker GRDA thooker@grda.comTim Larson Host Integrity Systems tim.larson@hostintegritysystems.comTim Miller SPP tmiller@spp.orgTim Phillips SPP tphillips@spp.orgTim Murphy AEP tsmurphy@aep.comTingting Wang AEP twang@aep.comTJ Sandoz OPPD tjsandoz@oppd.comTodd Pilcher Aces Power Marketing (APM) toddp@acespower.comTom Burke Aces Power Marketing (APM) tburke@acespower.com (512) 788-4901Tom DeBaun KCC t.debaun@kcc.ks.govTom Dunn SPP tdunn@spp.orgTom Fritsche SPP tfritsche@spp.orgTom Hestermann Sun Flower tkhestermann@sunflower.netTom Kleckner RTO Insider tom.kleckner@rtoinsider.comTom Mayhan OPPD tmayhan@oppd.com

Tom Paff Duke Energy tom.paff@duke-energy.comTom Saitta KMEA saitta@kmea.comTony Alexander SPP talexander@spp.orgTony Brill TNSK abrill@tnsk.comTony Delacluyse PCI tony@powercost.com (405) 326-1496Travis Allen EnBridge travis.allen@enbridge.comTrent A. Campbell OCC t.campbell@occemail.comTrent Carlson JP Morgan trent.a.carlson@jpmorgan.comTrey Fleming SAIC trey.s.fleming@saic.com (713) 345-0753Troy Via OPPD trvia@oppd.com (804) 318-0250Turner Crow SPP tcrow@spp.orgTy Mitchell SPP tmitchell@spp.orgTyler Wolford TEA twolford@teainc.org (904) 360-1460Tyson Boatler GSEC tboatler@gsec.coopValerie Barros valerie.barros@edf-re.comVeronica Bosquez CES-LTD vbosquez@ces-ltd.com

P Vince Vandaveer CUS vince.vandaveer@cityutilities.netVincent Musco Boston Pacific vmusco@bostonpacific.comVirat Kapur Electric Power Engineers/Wind Coalition vkapur@epeconsulting.com (512) 382-6700W. H. Thompson AEP whthompson@aep.comWalt Cecil MOPSC walter.cecil@psc.mo.govWalt Shumate Shumate & Associates waltshumate@sbcglobal.net (512) 496-7704Walt Yeager Duke Energy walt.yeager@duke-energy.comWayne Camp Accenture wayne.camp@accenture.com (856) 204-0298Wenchun Zhu Wind Capital Group zxhu@windcapitalgroup.comWendell Drost Alstom wendell.drost@areva-td.com (318)348-0014Will Johnson Adapt 2 Solutions william.johnson@adapt2solutions.comWill Tootle SPP wtootle@spp.orgWoody Lally AEP welally@aep.comY Mei Dufossat ymei@dufossat.comYassar Bahbaz SPP ybahbaz@spp.orgYohan Sutjandra TEA ysutjandra@teainc.orgZac Edstrom Cargill zac_edstrom@cargill.comZac Hager OGE hagerzc@oge.comZachary Sharp SPP zsharp@spp.org (501) 688-2548

Micha Bailey

From: Debbie JamesSent: Friday, August 28, 2015 8:39 AMTo: Johnston, Brad; Ross, Richard C. (AEP); Micha BaileyCc: Massery, MichaelSubject: RE: 08/28/2015 MWG, Prox

Thank you. Debbie James Southwest Power Pool Manager of Market Design Office: 501‐614‐3577|Mobile: 501‐960‐3338 201 Worthen Drive Little Rock, AR 72223‐4936 djames@spp.org

From: Brad Johnston [mailto:Brad.Johnston@aecc.com] Sent: Friday, August 28, 2015 8:31 AM To: Ross, Richard C. (AEP); Debbie James; Micha Bailey Cc: Massery, Michael Subject: 08/28/2015 MWG, Prox Michael Massery will be my proxy for the MWG meeting on 08/28/2015. Brad Johnston Manager‐Market Optimization Phone: 501‐570‐2414

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

MARKET WORKING GROUP Conference Call

August 28, 2015

• A G E N D A •

Day 1 – 9:00 a.m. – 12:00 p.m.

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

2. JOU Combined Resource Option Market Design Changes ................................................. Debbie James

3. RR112 - ECC Clean Up (expedite) ............................................................. Jim Gonzalez and John Luallen

4. ECC Overlapping MWPs ........................................................................... Jim Gonzalez and John Luallen

5. RR104 - DVER Minimum Limit (approval item) ............................................................... Amber Metzker

6. Adjournment ........................................................................................................................ Richard Ross

JOU Combined Resource Analysis MWG Conf. Call 8/28/2015

Debbie James 501.614.3577 djames@spp.org

Unintended Consequences

• Under JOU Combined Resource Option, individual shares that are not economic could be committed – Generator shares that might not be committed on a

stand alone basis due to high energy costs are committed because they are part of a JOU (free riders)

– If they have a non-zero economic minimum, the high cost share will be dispatched to minimum

– These shares will then receive make-whole payments (MWPs) for their percent share of Start-Up, No-Load and will be made whole to the higher Energy Offer Curve

Background • SPP staff explained JOU Combined Resource unintended

consequence at 6/16/15 MWG meeting

– 9 options were presented as potential ways to resolve the issue

• Options discussed at 7/21/15 MWG meeting included:

1. Economic Minimum coordination by JOU shares

2. Individual shares dispatched to minimum will not receive a MWP

3. All JOU Combined Resource shares must have a zero minimum

• MWG requested SPP staff provide the risk of no market design change and the estimated impact of the issue

Risk of No Market Design Change

• Load continues to pay inefficient MWPs for JOUs

• Market exposed to potential manipulation

• Monitoring and enforcement is less effective than prevention

SPP RTO JOU COMBINED RESOURCE IMPACT ANALYSIS

Assumptions – SPP RTO

• Calculated DAMKT JOU MWPs related to only Energy and Operating Reserve (OR) costs – Unintended consequence is related to higher energy

offers

• (1) Identified JOU shares that were potentially “free riding” ($200k) – Only included Energy and OR MWPs in estimated

impact if one or more shares did not receive an actual MWP while other shares did receive a MWP

• (2) Calculated regardless of whether all shares received actual MWPs ($2M)

Process – SPP RTO (Analysis 1) • DAMKT Energy and OR MWPs were calculated for all

JOU shares – Identified instances when one share received an actual MWP

and the other JOU shares did not receive actual MWP Assumed these were only instances of “free riding”

– Subtracted Start-up and No-load costs from total DAMKT MWP costs to get Energy and OR costs

– Compared Energy and OR costs to Energy and OR Revenues for all shares to determine if MWP was required

– Added up all Energy and OR MWPs

– Total estimated impact is $200k for 1st year of the market

Process – SPP RTO (Analysis 2)

• DAMKT Energy and OR MWPs were calculated for all JOU shares – Assumed all instances of an actual MWP for all shares

were potential “free riders” – Subtracted Start-up and No-load costs from total

DAMKT MWP costs to get Energy and OR costs – Compared Energy and OR costs to Energy and OR

Revenues for all shares to determine if MWP was required

– Added up all Energy and OR MWPs – Total estimated impact is $2M for 1st year of the market

Process – SPP RTO Summary

• Analysis 1 - $200k – Inaccurate due to assuming that only instances when

one share received an actual MWP and the other JOU shares did not receive actual MWP were the only “free riding” occurrences

• Analysis 2 - $2M – Inaccurate due to assuming that all Energy and OR

MWPs were potential “free riders”

• JOU shares could have different energy costs due to contracts

SPP MMU JOU COMBINED RESOURCE IMPACT ANALYSIS

Assumptions – SPP MMU

• For an efficiently offered and dispatched JOU with similar costs among owners, the relative MWPs among the owners should be reflective to the relative ownership shares.

• For a JOU with differing costs among owners, estimates of energy costs are required to assess the impact of offers above cost.

Process – SPP MMU (equal costs)

A, 80%

B, 10%

C, 10%

Ownership Share

A, 60%

C, 35%

MWP Share

• If one share of the JOU receives a disproportionately large share of the MWPs, it indicates differing dispatch due to a higher energy offer and the JOU operating on the margin at times.

• A conservative estimate of the MWP impact of the higher offers is

Actual MWPs for Owner – Ownership Share * Total JOU MWPs

Process – SPP MMU (differing costs)

• For the case where costs differ among JOU owners, estimates of marginal cost are required to assess the impact of offers exceeding marginal cost.

• The impact is assessed as the difference between the energy costs in any DA MWP and the estimate of actual costs based on market participant data.

Findings – SPP MMU

• The MMU finds a total MWP impact of about $2 million for the first twelve months of the market.

• In both scenarios, the estimate is conservative, because, in many cases, no MWP would be calculated at all in the absence of offers above marginal cost.

• Further analysis using a rerun of the DA Market shows that in some cases make whole payments to the JOU are eliminated completely by lowering offers to marginal cost.

Revision Request Form SPP STAFF TO COMPLETE THIS SECTION

RR #: 112 Date: 8/14/2015

RR Title: Combined Cycle Clarification

Impact Analysis Required? No Yes Included in MPRR101 IA

SUBMITTER INFORMATION

Name: Jim Gonzalez Company: SPP

Email: jgonzalez@spp.org Phone: 501-688-2538

REVISION REQUEST DETAILS Requested Resolution Timing: Normal Expedited Urgent Action

Reason for Expedited/Urgent Resolution: This RR is expedited to allow more time to review the revision changes.

Type of Revision (select all that apply):

Correction Clarification

Design Enhancement New Protocol, Business Practice, Criteria, Tariff

Regulatory Mandate (describe)

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

Market Protocols

Protocol Section(s): 4.2.2.1 Resource Offer Parameters; 4.2.2.5.3 Combined Cycle Resource; 4.5.8.12 Day-Ahead Make-Whole-Payment Amount; 4.5.9.8 RUC Make-Whole-Payment Amount; 6.1.1 Responsibilities of the Resource Asset Owner; 6.1.7 Combined Cycle Resource; 8.2.2.6 Mitigation Measures for Transition State Offers

Protocol Version: 32.a

Criteria Criteria Section(s): Criteria Date:

Tariff (OATT) Tariff Section(s): Attachment AE 4.1 Offer Submittal; 8.6.5 Reliability Unit Commitment Make Whole Payment Amount Attachment AF 3.4 Mitigation Measures for Transition State Offers

Business Practice Business Practice Number:

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

Forward looking changes from pending RRs have been accepted and blacklined for easier review by the working groups.

Language was left in 4.5.9.8 (4) (a.3) when the adjustment to Operating Reserve Cost for RTBM buy-back was moved to sections 4.5.9.8 (4) (g), (h), (i) & (j). While documenting requirements related to Day-Ahead Market committed combined cycle Resources which are subsequently modified by a RUC process, additional complexity in calculating Operating Reserve buy-back and the need for energy buy-back were uncovered. Section 8.6.4 as modified in MPRR 101 was not subsequently modified in MPRR 140, which only modified the corresponding Tariff language. Clarified how Primary and Alternate physical units are applied per Configuration. Limit total number of Configurations to 3 at Registration. Adding that all Configurations are capable of Starting/Stopping. Offline Supplemental offers may only be submitted for one Configuration.

Describe the benefits that will be realized from this revision.

The benefit to making these changes is clarifying the language will help in the designing the ECC.

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

Market Protocols

1. Glossary Multi-Configuration Combined Cycle Resource (MCR)

A combined cycle Resource that is modeled with multiple combined cycle configurations, with each configuration being treated as a separate Resource.

4.2.2.1 Resource Offer Parameters

The following Resource Offer parameters must be submitted to constitute a valid offer for use in either the DA Market or RTBM:

… (29) Group Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter) - Only

applicable to MCRscombined cycle Resources that have registered under the option described under Section 6.1.7.1(4);

(30) Plant Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter) - Only applicable to MCRscombined cycle Resources that have registered under the option described under Section 6.1.7.1(4);

(50) Transition State Offer (Only applicable to combined cycle ResourceMCRs that have registered under the option described under Section 6.1.7.1; . See Section 4.2.2.5.3(4));

(51) Mitigated Transition State Offer (Only applicable to combined cycle ResourceMCRs that have registered under the option described under Section 6.1.7.1; . See Section 4.2.2.5.3(4));

(52) Transition State Time (Only applicable to combined cycle ResourceMCRs that have registered under the option described under Section 6.1.7.1; . See Section 4.2.2.5.3(4)); and

(53) JOU Ownership Percent Share (Daily Unit Commitment Parameter)1.

4.2.2.5.3 Combined Cycle Resource

Combined cycle modeling will be accommodated as follows for Resources registered as a combined cycle Resource. Market Participants that jointly own a combined cycle Resource that desire to use the Jointly Owned Unit modeling options described under Section 4.2.2.5.4 must register as a Jointly Owned Unit and cannot register the Resource as a combined cycle Resource.

Market Participants will have to select from one of the four following options regarding submitting Resource Offers for their registered combined cycle Resources which will need to be declared during asset registration as described under Section 6.1.7:

(1) A Resource Offer may be submitted for a single aggregate combined cycle Resource, where the aggregate will represent a Market Participant selected operating configuration of combustion turbines (CT) and steams turbines (ST) (i.e. a 1CT x 1ST, 2CT x 1ST, 3CT x 1ST, etc.). Under this option, the combined cycle Resource will be committed, dispatched and settled the same as any other Resource; or

(2) A Resource Offer may be submitted for each combined cycle Resource combustion turbine and/or steam turbine and each component will be committed and dispatched independently and settled the same as any other single Resource; or

(3) A Resource Offer may be submitted for each pseudo combined cycle Resource, where each pseudo combined cycle Resource will represent the combination of one combustion turbine and a portion of the steam turbine. Under this option, each pseudo combined cycle Resource must be capable of being committed and dispatched independently the

1 Only applicable for the designated Asset Owner identified by the Market Participant that has registered a JOU under the Combined Resource Option (see Section 4.2.2.5.4). A value for each Asset Owner must be submitted by or on behalf of the designated Asset Owner and represents each Asset Owners percentage share of the Physical JOU Resource and must add up to 100%.

same as any other Resource and each pseudo combined cycle Resource will be settled the same as any other Resource.

(4) A Resource Offer may be submitted for each combined cycle Resource configuration, where each configuration is defined during market registration and the combined cycle Resource must be registered as a MCR.

(a) Each configuration will be modeled as a separate Resource in order to select the most economic configuration for economic commitment and dispatch. Configuration rules defining which Resources are eligible for Start-Up, what configurations are valid when moving from one configuration to another, and transition costs and minimum run times associated with moving between configurations are defined during market registration as described under Section 6.1.7. The Offer parameters described under Sections 4.2.2.1 and 4.2.2.2 must be submitted for each configuration with the following exceptions and additional parameters:

(i) All operational configurations are assumed capable of starting up from an off-line state and capable of being de-committed from its current state. Therefore, Markets Participants should submit Start-Up Offers and Start-Up Times for all operational configurations, which may need to include transition costs and transition times.

(b) Start-Up Offer is only applicable to valid configurations associated with committing the Resource from an off-line state to an on-line state; and

(ii) Transition State Offers and Transition State Times are only valid for moving from one configuration to another once the Resource becomes a Synchronized Resource.

(i)(iii) Offline Supplemental offers may only be submitted for one configuration.

(c)(b) For the DA Market, configuration changes will be determined on an hourly basis. For the RTBM, a configuration will be determined prior to the Operating Hour and that configuration will generally remain fixed for dispatch purposes within the Operating Hour. However, SPP may make configuration changes within the Operating Hour to address a reliability issue to the extent that the transition can be accomplished in a timely manner.

(d)(c) Meter data for use in RTBM settlement must be submitted at the combined cycle Resource plant output level and is not dependent upon which configuration the Resource has operated under.

(e)(d) If the combined cycle Resource is committed by SPP in the DA Market, and during the DA Market Commitment Period the Resource was moved from one configuration to another within the commitment period, any transitions costs incurred will be included in the DA Market make-whole-payment calculation described under Section 4.5.8.12. Moving from one configuration to another will not be considered as the start of a new DA Market Commitment Period.

(f)(e) If the combined cycle Resource is not committed by SPP in the DA Market and is committed during the RUC process and during the RUC Commitment Period the Resource was moved from one configuration to another within the commitment period, any transitions costs incurred will be included in the RUC make-whole-payment calculation described under Section 4.5.9.8. Moving from one configuration to another will not be considered as the start of a new RUC Commitment Period.

(g)(f) If the combined cycle Resource was committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved by SPP into a configuration that is different from the configuration used in the DA Market Commitment period, any transitional costs incurred are eligible for recovery as described under Section 4.5.9.8.

4.5.8.12 Day-Ahead Make-Whole-Payment Amount

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

Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the time the commitment decision was made except under the situation described under Section (b).a.i below.

(a) There may be more than one DA Market Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single DA Market Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(b) A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following DA Market Make-Whole Payment Eligibility Periods:

(a) Any DA Market Make-Whole Payment Eligibility Period that is adjacent to the end of a RUC Make-Whole Payment Eligibility Period except as described in (i) below;

(i) As described under Section 4.5.9.8(3)h, to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the adjacent RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the adjacent Day-Ahead Make-Whole Payment Eligibility Period.

(b) Any DA Market Make-Whole Payment Eligibility Period resulting from a DA Market Commitment Period that contains a DA Market Self-Commit Hour; and

(c) Any DA Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min Time.

(c) For each DA Market Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s DA Market Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest hour or (2) 24 Hours, and that portion of the Start-Up Offer is included as a cost in each hour of the DA Market Make-Whole Payment Eligibility Period until the sum of these hourly costs are equal to the DA Market Start-Up Offer or until the end of the DA Market Make-Whole Payment Eligibility Period, whichever occurs first.

(d) To the extent that the full amount of the DA Market Start-Up Offer is not accounted for in the last DA Market Make-Whole Payment Eligibility Period in the Operating Day, any remaining DA Market Start-Up Offer costs are carried forward for recovery in the first DA Market Make-Whole Payment Eligibility Period of the following Operating Day. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $10,000. The DA Market Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For DA Market Make-Whole Payment calculation purposes, the DA Market Commitment Period is split into two separate DA Market Make-Whole Payment Eligibility Periods as described in (2).b above. The first DA Market Make-Whole Payment

Eligibility Period will include $1000/hour of Start-Up Offer costs ($10,000 / 10 Hours) in hours 23 and 24. The second DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs in hours 1 through 8.

(e) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Contingency Reserve in the Day-Ahead Market and must buy back that position in Real-Time at an average Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, such cost is not due to any independent action of the Market Participant and such cost is not incurred during a RUC Make-Whole Payment Eligibility Period. The Market Participant may also be eligible for a make-whole payment for cost incurred during transition if the Resource is transitioned by a local transmission operator to address a Local Emergency Condition, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a DA make whole payment for these costs. In such cases, the additional costs are equal to the difference between the Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared ContingencyOperating Reserve MW amounts. Recovery of these costs is limited to the time period defined as the Transition State Time submitted in the Resource Offer.

(4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each hour in a given DA Market Make-Whole Payment Eligibility Period is calculated as follows:

#DaMwpCpAmt a, s, c =

Max (0, ∑h

( DaMwpCostHrlyAmt a, h, s, c + DaMwpRevHrlyAmt a, h, s, c +

DaCcSpinAdjHrlyAmt a, s, h + DaCcSuppAdjHrlyAmt a, s, h) ) * (-1)

(a) DaMwpCostHrlyAmt a, h, s, c =

DaStartUpEligHrlyFlg a, h, s, c * DaStartUpHrlyAmt a, h, s, c

+ DaClrdComStatHrlyFlg h, s, c

* [ DaRucRmndrStartUpHrlyAmt a, s, h, c + DaTransitionHrlyAmt a, s, h, c

+ DaCcSpinAdjHrlyAmt a, s, h + DaCcSuppAdjHrlyAmt a, s, h

+ DaNoLoadHrlyAmt a, h, s, c + DaIncrEnHrlyAmt a, h, s, c

+ DaRegUpAvailHrlyAmt a, h, s, + DaRegDnAvailHrlyAmt a, h, s

+ ∑i

PotDaRegUpMileMwp5minAmt a, s, i

+ ∑i

PotDaRegDnMileMwp5minAmt a, s, i

+ DaSpinAvailHrlyAmt a, h, s, c + DaSuppAvailHrlyAmt a, h, s, c

+ DaRegUpforCRSubAvailHrlyAmt a, s, h, c ]

Where,

#DaIncrEnHrlyAmt a, h, s, c = ∫) s h, a,yQty (DaClrdHlr ABS

CurveOffer Energy Market DA

(a.1) IF RtTranistionStateFlg a, s, i = 1 THEN

DaCcSpinAdj5minAmt a, s, i =

IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )

Max (DaTransitionState5minFlg a, s, i, c -∑c

RtTransitionState5minFlg a, s, i, c ,

* (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i )

DaCcSpin5minAmt a, s, h = 0

(a.1.1) DaCcSpinAdjHrlyAmt a, s, h =

Max ( 0, ∑i

DaCcSpinAdj5minAmt a, s, i )

(a.2) IF RtTranistionStateFlg a, s, i = 1 THEN

DaCcSuppAdj5minAmt a, s, i =

IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )

Max(DaTranisitionState5minFlg a, s, i, c -∑c

RtTranisitionState5minFlg a, s, i, c ,

* (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i )

DaCcSupp5minAmt a, s, h = 0

(a.2.1) DaCcSuppAdjHrlyAmt a, s, h =

Max ( 0, ∑i

DaCcSuppAdj5minAmt a, s, i )

(b) DaMwpRevHrlyAmt a, h, s, c = DaClrdComStatHrlyFlg h, s, c

* [ ( DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h )

+ DaRegUpHrlyAmt a, h, s + DaRegDnHrlyAmt a, h, s

+ ∑i

DaRegUpUnusedMileMwp5minAmt a, s, i

+ ∑i

DaRegDnUnusedMileMwp5minAmt a, s, i

+ DaSpinHrlyAmt a, h, s + DaSuppHrlyAmt a, h, s ]

(c) DaRegUpAvailHrlyAmt a, h, s

= DaRegUpHrlyQty a, h, s * DaRegUpOffer a, h, s

(d) DaRegDnAvailHrlyAmt a, h, s

= DaRegDnHrlyQty a, h, s * DaRegDnOffer a, h, s

(e) DaSpinAvailHrlyAmt a, h, s, c

= DaOffSpinHrlyQty a, h, s * DaSpinOffer a, h, s

(f) DaSuppAvailHrlyAmt a, h, s, c

= DaOffSuppHrlyQty a, h, s * DaSuppOffer a, h, s

(g) DaRegUpforCRSubAvailHrlyAmt a, s, h, s, c

= DaRegUpforCRSubHrlyQty a, h, s * DaRegUpCapOffer a, h, s

(g.1) DaRegUpforCRSubHrlyQty a, h, s = DaOffRegUpHrlyQty a, h, s - DaRegUpHrlyQty a, s, h

(5) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows:

DaMwpDlyAmt a, s, d = ∑c

DaMwpCpAmt a, s, c

(6) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:

DaMwpAoAmt a, m, d = ∑s

DaMwpDlyAmt a, s, d

(7) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows:

DaMwpMpAmt m, d = ∑a

DaMwpAoAmt a, m, d

(8) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates DA Market Make-Whole Payment $ per DA Market Make-Whole-Payment Eligibility Period for each Asset Owner as follows:

(a) #EqrDaMwpHrlyPrc a, s, c = (-1) * DaMwpCpAmt a, s, c

(b) IF EqrDaMwpHrlyPrc a, s, c > 0 THEN #EqrDaMwpHrlyQty a, s, c = 1

The above variables are defined as follows:

Variable Unit Settlement Interval

Definition

DaMwpCpAmt a, s, c $ Eligibility Period

Day-Ahead Make-Whole-Payment Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market make-whole amount to AO a for DA Market Make-Whole-Payment Eligibility Period c at Resource Settlement Location s.

DaStartUpHrlyAmt a h, s, c $ Hour Day-Ahead Start-Up Cost Amount per AO per Settlement Location per Hour Per DA Market Make-Whole-Payment Eligibility Period - The DA Market Start-Up Offer associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c that is included in each Hour h of the DA Market Make-Whole-Payment Eligibility Period. This value is calculated by dividing DaStartUpAmt a s, c by the lesser of the Resource’s (DaMinRunTime a, h, s, c ) /60, rounded down to the nearest whole number of hours or 24 hours, except that, if DaMinRunTime a, h, s, c is less than 60 minutes, then DaStartUpAmt a, s, c is divided by 1. These hourly values are carried forward into the following Operating Day, if needed, to ensure recovery of any remaining DaStartUpAmt a s, c.

DaStartUpAmt a s, c

(Not Available on Settlement Statement)

$ Eligibility Period

Day-Ahead Start-Up Cost Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market Start-Up Offer used in the commitment decision, which includes the impacts of mitigation and the expected state of the Resource prior to the DA Market Commitment Period, associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c.

Definition

DaStartUpEligHrlyFlg a, h, s, c None Hour Day-Ahead Start-Up Recovery Eligibility Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – This flag is set equal to 1 in each hour of a DA Market Make-Whole-Payment Eligibility Period where the Resource is eligible to recover start-up costs, or 0 in each hour of the DA Market Make-Whole-Payment Eligibility Period where the Resource is not eligible to recover start-up costs.

DaClrdComStatHrlyFlg h, s, c None Hour Day-Ahead Commitment Status Hourly Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – This flag is set equal to 1 for each hour of a DA Market Make-Whole-Payment Eligibility Period in which its Commitment Status was “Market” or “Reliability, or 0 if its Commitment Status was “Self”.

DaRucRmndrStartUpHrlyAmt a, s, h, c $ Hour Day-Ahead RUC Remaining Start-Up Offer Amount per Hour per DA Market Make-Whole Payment Eligibility Period - the amount of Start-Up Offer recovery remaining associated with an adjacent RUC Make-Whole Payment Eligibility Period.

DaTransitionHrlyAmt a, s, h, c $ Eligibility Period

Day-Ahead Transition Cost Amount per AO per Settlement Location per Hour in DA Market Make-Whole-Payment Eligibility Period - The DA Market Transition State Offer associated with AO a’s eligible combined cycle Resource at Settlement Location s in Hour h of DA Market Make-Whole-Payment Eligibility Period c.

DaCcSpinAdjHrlyAmt a, s, h, c $ Hour Day-Ahead Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Hour for a DA Market Make-Whole-Payment Eligibility Period – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Hour h and DA Market Make-Whole-Payment Eligibility Period c.

Definition

DaCcSuppAdjHrlyAmt a, s, h, c $ Hour Day-Ahead Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Hour for a DA Market Make-Whole-Payment Eligibility Period – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Hour h and DA Market Make-Whole-Payment Eligibility Period c.

DaCcSpinAdj5minAmt a, s, i, c $ Dispatch Interval

Day-Ahead Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval for a DA Market Make-Whole-Payment Eligibility Period – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Dispatch Interval i and DA Market Make-Whole-Payment Eligibility Period c.

DaCcSuppAdj5minAmt a, s, i, c $ Dispatch Interval

Day-Ahead Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval for a DA Market Make-Whole-Payment Eligibility Period – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Dispatch Interval i and DA Market Make-Whole-Payment Eligibility Period c.

Definition

DaTranisitionState5minFlg a, s, i, c None Dispatch Interval

Day-Ahead Transition State Flag per AO per Settlement Location in DA Make-Whole-Payment Eligibility Period – This flag is set to 1 in Dispatch Interval i for Asset Owner a’s combined cycle Resource at Settlement Location s when both of the following conditions are met:

i) As indicated by its SCADA data, the Resource is actually transitioning into a configuration which is a part of a Day-Ahead Market Commitment Period for which its Commitment Status was “Market” or “Reliability” and

ii) The Dispatch Interval falls in the expected transition window as defined by the transition time, in minutes, prior to the start time of the Day-Ahead Market Commitment Period for the particular configuration.

… for Day-Ahead Market Make-Whole-Payment Eligibility Period c

RtTranisitionState5minFlg a, s, i None Dispatch Interval

Real-Time Transition State Flag per AO per Settlement Location in DA Make-Whole-Payment Eligibility Period – The value defined under Section 4.5.9.8.

RtRucComStat5minFlg a, s, i, c None Dispatch Interval

RUC Commitment Status Flag per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The value defined under Section 4.5.9.8.

DaMinRunTime a, h, s, c

Time Hour Day-Ahead Minimum Run Time per AO per Settlement Location Per Hour – The Minimum Run Time, in minutes, associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c as submitted as part of the DA Market Offer.

DaMwpCostHrlyAmt a, h, s, c $ Hour Day-Ahead Make-Whole Payment Cost Amount per AO per Settlement Location per Hour in the DA Market Make-Whole-Payment Eligibility Period - The hourly cost associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c.

Definition

PotDaRegUpMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.28

PotDaRegDnMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.29

4.5.9.8 RUC Make-Whole-Payment Amount

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

Eligibility Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made for start-up, no-load, and minimum-energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for incremental energy, Regulation-Up, Regulation-Down, Spin, and Supplement Reserves.

(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer unless precluded by (e) below. Asset Owners may request additional compensation through submittal of actual cost documentation to the SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery.

(b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period for which the RUC SCUC did not consider the Resource’s Start-Up Offer in the commitment decision except that RTBM Start-Up Offers associated with manual commitments as described under Sections 4.3.2.2(3)(c), 4.3.2.2(3)(d), 4.4.1.2(3)(c) and 4.4.1.2(3)(d) are eligible for recovery;

(ii) Any RUC Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s RUC Commit Time less the Resource’s Sync-To-Min Time; and

(iii) Any RUC Make-Whole Payment Eligibility Period resulting from a RUC Commitment Period that contains an hour for which the Resource Commitment Status is Self-Commit.

(f) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first. If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period, all of the eligible pro rata share of the Resource’s RTBM Start-Up Offer is allocated into the first interval of the RUC Make-Whole Payment Eligibility Period.

(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.

(h) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full

amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

(i) If the Resource is a combined cycle ResourceMCR that has been registered as described under Section 6.1.7.1, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time periods in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. The Market Participant may also be eligible for a make-whole payment for cost incurred during transition if the Resource is transitioned by a local transmission operator to address a Local Emergency Condition, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment for these costs. In such cases, the additional costs area equal to the difference between the average Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs associated with Contingency Reserve is limited to the time period defined as the Transition State Time submitted in the Resource Offer. Recovery of these costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals within the transition hour.

(h)(j) If the Resource is a MCR that has been registered as described under Section 6.1.7.1, additional costs associated with situations in which the Resource has cleared Energy in the Day-Ahead Market and is committed into a configuration which causes the Resource to buy back all or a portion of that position in Real-Time at a Real-Time LMP that is greater than the Day-Ahead LMP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. The Market Participant may also be eligible for a make-whole payment for cost incurred during transition if the Resource is transitioned by a local transmission operator to address a Local Emergency Condition, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to

Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment for these costs. In such cases, the additional costs are equal to the difference between (positive value) the average Real-Time LMP and the Day-Ahead LMP multiplied by the positive difference between Day-Ahead Market cleared Energy amount (positive value) and the actual output (positive value).

(i)(k) If a Resource’s self-commitment period is less than the Resource’s Minimum Run Time, SPP will relax the Resource’s Minimum Run Time to equal the self-commit period.

(j)(l) If SPP clears a Resource with a Commitment Status of Market or Reliability for a period adjacent to a self-commitment period in the RTBM, then the Resource will be eligible for recovery of Energy and No-Load offer costs for that period in the RUC Make-Whole Payment Eligibility Period.

(4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for a given RUC Make-Whole Payment Eligibility Period is calculated as follows:

#RtMwpCpAmt a, s, c = ( CncldStartAmt a, s, c

+ Max (0, ( { IF ( CncldStartRatio a, s, c = 0, THEN 1, ELSE 0) }

* ∑i

{ RtStartUpElig5minFlg a, s, i, c * RtStartUp5minAmt a, s, i, c

+ RtRucComStat5minFlg a, s, i, c * [ RtMwpCost5minAmt a, s, i, c

+ RtTransition5minAmt a, s, i, c – ∑c

DaTransitionHrlyAmt a, s, h / 12

+ RtMwpRev5minAmt a, s, i, c

+ RtOom5minAmt a, s, i + RtRegAdj5minAmt a, s, i

– RtURDAdj5minAmt a, s, i, c – RtStatusAdj5minAmt a, s, i, c

– RtLimitAdj5minAmt a, s, i, c ] }

( RtCcRegUpAdjHrlyAmt a, s, h, c + RtCcRegDnAdjHrlyAmt a, s, h, c

+ RtCcSpinAdjHrlyAmt a, s, h, c + RtCcSuppAdjHrlyAmt a, s, h, c )

+ ∑i

RtCcEnAdj5minAmt a, s, i, c) ) ) * (-1)

Where,

(a) #RtMwpCost5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c *

( RtIncrEn5minAmt a, s, i

+ Max ( 0, [ RtNoLoad5minAmt a, s, i, c

- ∑c

IF (DaClrdHrlyQty a, s, h < 0, THEN DaNoLoadHrlyAmt a, s, h, c , ELSE 0 ) ]

+ RtMinEn5minAmt a, s, i, c

+ RtRegUpAvail5minAmt a, s, i +

RtRegDnAvail5minAmt a, s, i,

+ PotRtRegUpMileMwp5minAmt a, s, i + PotRtRegDnMileMwp5minAmt a, s, i

+ RtSpinAvail5minAmt a, s, i, c + RtSuppAvail5minAmt a, s, i, c

+ RtRegUpforCRSubAvail5minAmt a, s, i, c ) / 12

(a.1) IF ABS (DaClrdHrlyQty a, s, h ) > = ABS ( RtBillMtr5minQty a, s, i )

RtIncrEn5minAmt a, s, i = 0

#RtIncrEn5minAmt a, s, i = ∫y

CurveOffer Energy Dispatched As RTBM

Where:

X = Max (ABS (DaClrdHrlyQty a, s, h ), RtEffMin5minQty a, s, i )

IF ControlStatus5minFlg a, s, i = “Regulating”

RtEffMin5minQty a, s, i = Min (

RtComMinRegCapOL5minQtya, s, i ,

RtDispMinRegCapOL5minQtya, s, i ,

Max (0, (-1) * RtBillMtr5minQtya, s, i )

RtEffMin5minQty a, s, i = Min (

RtComMinEconCapOL5minQtya, s, i ,

RtDispMinEconCapOL5minQtya, s, i ,

Max (0, (-1) * RtBillMtr5minQtya, s, i )

Y = Max ( (-1) * RtBillMtr5minQtya, s, i , 0)

(a.2) IF ABS (DaClrdHrlyQty a, s, h ) < RtEffMin5minQty a, s, i

#RtMinEn5minAmt a, s, i = ∫y

CurveOffer Energy Committed As RTBM

Where:

X = DaClrdHrlyQty a, s, h

Y = RtEffMin5minQty a, s, i

RtMinEn5minAmt a, s, i, c = 0

(a.3) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, i

RtRegUpAvail5minAmt a, s, i=

( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h] )

* RtRegUpOffer a, s, i, )

- ( RtRegUpMileOffer5minPrc a, s, i * RtRegUpExcessMile5minQty a, s, i )

RtRegUpAvail5minAmt a, s, i, =0

IF RtTranistionStateFlg a, s, i, c = 1 THEN

RtRegUpAvail5minAmt a, s, i, c =

DaRegUpHrlyQty a, z, s, h

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h )

RtRegUpAvail5minAmt a, s, i, c = RtRegUpAvail5minAmt a, s, i = 0

(a.4) If RtRegDn5minQty a, s, i > RtFixedRegDn5minQty a, s, i

RtRegDnAvail5minAmt a, s, i =

( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h] )

* RtRegDnOffer a, s, i, )

- ( RtRegDnMileOffer5minPrc a, s, i * RtRegDnExcessMile5minQty a, s, i )

RtRegDnAvail5minAmt a, s, i =0

(a.5) If RtOffSpin5minQty a, s, i > RtFixedSpin5minQty a, s, i

RtSpinAvail5minAmt a, s, i, c =

Max ( 0, [ RtOffSpin5minQty a, z, s, i - ∑z

DaOffSpinHrlyQty a, z, s, h] )

* RtSpinOffer a, s, i, c

RtSpinAvail5minAmt a, s, i, =0

(a.6) If RtOffSupp5minQty a, s, i > RtFixedSupp5minQty a, s, c, i

RtSuppAvail5minAmt a, s, i, c =

Max ( 0, [ RtOffSupp5minQty a, z, s, i - ∑z

DaOffSuppHrlyQty a, z, s, h] )

* RtSuppOffer a, s, i, c

RtSuppAvail5minAmt a, s, i, =0

(a.7) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i

RtRegUpforCRSubAvail5minAmt a, s, i, c

= RtRegUpforCRSub5minQty a, i, s * RtRegUpCapOffer a, s, i

RtRegUpforCRSubAvail5minAmt a, s, i, c = 0

(a.7.1) RtRegUpforCRSub5minQty a, s, i =

RtOffRegUp5minQty a, i, s - RtRegUp5minQty a, i, s

- DaRegUpforCRSubHrlyQty a, h, s

(b) #RtMwpRev5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * [ ( ( RtLmp5minPrc s, i

* Min (0, [ RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h ] ) ) / 12 )

+ RtRegUpRev5minAmt a, s, i, c + RtRegDnRev5minAmt a, s, i, c

+ RtSpinRev5minAmt a, s, i, + RtSuppRev5minAmt a, s, i,

+ RegUpUnusedMileMwp5minAmt a, s, i

+ RegDnUnusedMileMwp5minAmt a, s, i ]

(b.1) RtRegUpRev5minAmt a, s, i, c =

* ( ( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h] )

* RtRegUpMcp5minPrc z, i ) / 12 ) + RtRegUpExcessMile5minAmt a, s, i

(b.2) RtRegDnRev5minAmt a, s, i, c =

*( ( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h] )

* RtRegDnMcp5minPrc z, i ) / 12 ) + RtRegDnExcessMile5minAmt a, s, i

(b.3) RtSpinRev5minAmt a, s, i, c =

(-1) * RtRucComStat5minFlg a, s, i, c

*( Max ( 0, [ RtSpin5minQty a, z, s, i - ∑z

DaSpinHrlyQty a, z, s, h ] )

* RtSpinMcp5minPrc z, i ) / 12

(b.4) RtSuppRev5minAmt a, s, i, c =

(-1) * RtRucComStat5minFlg a, s, i, c

*( Max ( 0, [ RtSupp5minQty a, z, s, i - ∑z

DaSuppHrlyQty a, z, s, h ] )

* RtSuppMcp5minPrc z, i ) / 12

(c) #CncldStartAmt a, s, c =

( RtStartUp5minAmt a, s, i, c * RtStartUpElig5minFlg a, s, i, c )

* CncldStartRatio a, s, c

CncldStartRatio a, s, c = (ElapsedTime a, s, c / StartUpTime a, s, c )

(d) In any Dispatch Interval in which the Resource has operated outside of its Operating Tolerance and that Resource has not been exempted from URD per Section 4.4.4.1, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The URD adjustment is calculated as follows:

IF ABS (URD5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

( XmptDev5minFlg a, s, i = 0 )

#RtURDAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c

* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i )) / 12

RtURDAdj5minAmt a, s, i, c = 0

(d.1) URD5minQty a, s, i =

Max ( RtBillMtr5minQty a, s, i * (-1), 0 ) - RtAvgSetPoint5minQty a, s, i

(d.2) ResOpTol5minQty a, s, i =

Min ( URDMaxTol5minQty i , Max (URDMinTol5minQty i ,

URDTol5minPct i * RtDispMaxEmerCapOL5minQty a, s, i ) )

(d.3) IF RtDesiredEn5minQty a, s, i < ABS (DaClrdHrlyQty a, s, h )

#RtDesiredEn5minAmt a, s, i = RtIncrEn5minAmt a, s, i

#RtDesiredEn5minAmt a, s, i = ∫y

CurveOffer Energy Dispatched As RTBM

Where:

X = Max (ABS (DaClrdHrlyQty a, s, h ) , RtEffMin5minQty a, s, i )

Y = Max ( X, RtDesiredEn5minQtya, s, i )

(e) In any Dispatch Interval in which a Resource is in “Manual” status, any incremental Energy costs associated with actual Energy output above the Resource’s Desired

Dispatch is not eligible for recovery. The status change adjustment is calculated as follows:

IF ControlStatus5minFlg a, s, i = “Manual”

AND ABS (URD5minQty a, s, i ) <= ResOpTol5minQty a, s, i

#RtStatusAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c

RtStatusAdj5minAmt a, s, i, c = 0

(f) In any Dispatch Interval in which a Resource has increased its Minimum Economic Capacity Operating Limit (or its Minimum Regulation Capacity Operating Limit if the Resource has cleared for Regulation-Up Service or Regulation-Down Service) above the Resource’s minimum limits used by SPP in the commitment decision or the minimum limits used to move from one configuration to another in the case of a combined cycle Resource, the Resource is not in “Manual” status and the increase in minimum limit is greater than the Resource’s Operating Tolerance, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The limit change adjustment is calculated as follows:

IF ControlStatus5minFlg a, s, i < > “Regulating” AND

ControlStatus5minFlg a, s, i < > “Manual” AND

( RtDispMinEconCapOL5minQty a, s, i

- RtComMinEconCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

ABS (URD5minQty a, s, i ) <= ResOpTol5minQty a, s, i

#RtLimitAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c

ELSE IF

ControlStatus5minFlg a, s, i = “Regulating” AND

( RtDispMinRegCapOL5minQty a, s, i

- RtComMinRegCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

ABS (URD5minQty a, s, i ) < =ResOpTol5minQty a, s, i

#RtLimitAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c

RtLimitAdj5minAmt a, s, i, c = 0

(g) In an hour containing a Dispatch Interval in which the Transition State is flagged for a combined cycle Resource registered as described under Section 6.1.7.1(4) and the Day-Ahead Market cleared Regulation Service exceeds the RTBM cleared quantity, the Resource is eligible to recover the cost of buying back the product. The combined cycle Regulation Service buy-back adjustments are calculated as follows:

If ∑i

RtTranistionStateFlg a, s, i, c > = 1 THEN

RtCcRegUpAdjHrlyAmt a, s, h, c =

RtTransitionStateHrlyFlg a, s, h, c

* Max ( [ 0, (DaRegUpHrlyAmt a, s, h + ∑i

( RtCcRegUpAdj5minAmt a, s, i c *

RtRucComStat5minFlg a, s, i, c ) RtRegUp5minAmt a, s, i ) ]

RtCcRegUpAdjHrlyAmt a, s, h, c = 0

(g.1) RtCcRegUpAdj5minAmt a, s, i, c =

(DaRegUpHrlyAmt a, s, h / 12 + RtRegUp5minAmt a, s, i )

RtCcRegUpAdj5minAmt a, s, i, c = 0

(h) If ∑i

RtTranistionStateFlg a, s, i, c > = 1 THEN

RtCcRegDnAdjHrlyAmt a, s, h, c =

RtTransitionStateHrlyFlg a, s, h, c

* Max ( [ 0, (DaRegDnHrlyAmt a, s, h + ∑i

( RtCcRegDnAdj5minAmt a, s, i c *

RtRucComStat5minFlg a, s, i, c ) RtRegDn5minAmt a, s, i ) ]

RtCcRegDnAdjHrlyAmt a, s, h, c = 0

(h.1) RtCcRegDnAdj5minAmt a, s, i, c =

(DaRegDnHrlyAmt a, s, h / 12 + RtRegUp5minAmt a, s, i )

RtCcRegDnAdj5minAmt a, s, i, c = 0

(i) IF RtTranistionStateFlg a, s, i, c = 1 THEN

(a) In a Dispatch Interval in which the Transition State is flagged for a combined cycle Resource registered as described under Section 6.1.7.1(4) and the Day-Ahead Market cleared Contingency Reserve exceeds the RTBM cleared quantity, the Resource is eligible to recover the cost of buying back the product. The combined cycle Contingency Reserve buy-back adjustments are calculated as follows:

RtCcSpinAdj5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i )

RtCcSpin5minAmt a, s, i, c = 0

(i.1) RtCcSpinAdjHrlyAmt a, s, h, c =

Max ([ 0, ∑i

RtCcSpinAdj5minAmt a, s, i, c ) ( RtTransitionState5minFlg a, s, i, c

* (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i ))]

(h.1) (j) IF RtTranistionStateFlg a, s, i = 1 THEN

RtCcSuppAdj5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i )

RtCcSupp5minAmt a, s, i, c = 0

(j.1) RtCcSuppAdjHrlyAmt a, s, h, c =

Max ([0, ∑i

RtCcSuppAdj5minAmt a, s, i, c( RtTransitionState5minFlg a, s, i, c

* (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i ) ) ]

(i) If, as a result of being instructed by RUC Commitment to be in a configuration in which it could not generate at least as much output as was cleared in the Day-Ahead Market, a combined cycle Resource registered as described under Section 6.1.7.1 has Day-Ahead Market cleared Energy that exceeds the actual Resource output quantity in a Dispatch Interval, the Resource is eligible to recover the cost of buying back Day-Ahead Energy at a Real-Time LMP above the Day-Ahead LMP. The combined cycle Energy buy-back adjustments are calculated as follows:

IF RtComMaxEconCapOL5minQtya, s, i < DaComMaxEconCapOLHrlyQtya, s, h

AND ResDeCommit5minFlg a, s, i < > 1 AND DispInstrucMaxHrlyFlg a, s, h = 1

RtCcEnAdj5minAmt a, s, i, c = CcDlyFlg a, s, d

* Min { RtTransitionState5minFlg a, s, i, c + RtRucComStat5minFlg a, s, i, c , 1 }

* Max (0, RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h )

* Max (0, RtLmp5minPrc s, i - DaLmpHrlyPrc s, h ) / 12

RtCcEnAdj5minAmt a, s, i, c = 0

(5) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows:

RtMwpDlyAmt a, s, d = ∑c

RtMwpCpAmt a, s, c

(6) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:

RtMwpAoAmt a, m, d = ∑s

RtMwpDlyAmt a, s, d

(7) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows:

RtMwpMpAmt m, d = ∑a

RtMwpAoAmt a, m, d

(8) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates RUC Make-Whole Payment $ per RUC Make-Whole-Payment Eligibility Period for each Asset Owner as follows:

(a) #EqrRtMwp5minPrc a, s, c = (-1) * RtMwpCpAmt a, s, c

(b) IF #EqrRtMwp5minPrc a, s, c > 0 THEN #EqrRtMwp5minQty a, s, c = 1

The above variables are defined as follows:

Variable

Settlement Interval

Definition

RtMwpCpAmt a, s, c $ Eligibility Period

RUC Make-Whole-Payment Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The amount to AO a for RUC Make-Whole-Payment Eligibility Period c at Resource Settlement Location s..

DaClrdHrlyQty a, s, h MWh

Hour Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.1 for AO a’s combined cycle resource at Settlement Location s for the Hour.

RtTransition5minAmt a, s, i, c $ Eligibility Period

Real-Time Transition Cost Amount per AO per Settlement Location in RUC Make-Whole-Payment Eligibility Period - The RTBM Transition State Offer associated with AO a’s eligible combined cycle Resource at Settlement Location s in Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

DaTransitionHrlyAmt a, s, h, c $ Eligibility Period

Day-Ahead Transition Cost Amount per AO per Settlement Location per Hour in DA Market Make-Whole-Payment Eligibility Period - The value as described under Section 4.5.8.12.

Variable

Settlement Interval

Definition

RtTransitionState5minFlg a, s, i, c Flag Dispatch Interval

Real-Time Transition State Flag per AO per Settlement Location in RUC Make-Whole-Payment Eligibility Period – This flag is set to 1 in Dispatch Interval i for Asset Owner a’s when a combined cycle Resource at Settlement Location s when both parts of either of the following pairs of conditions are met: 1) Dispatch Intervals for which:

i) As indicated by its SCADA data, the Resource is actually transitioning in to a configuration which is a part of a RUC Commitment Period for which its Commitment Status was “Market” or “Reliability” and

ii) The Dispatch Interval falls in the expected transition window as defined by the transition time, in minutes, prior to the start time of the RUC Commitment Period for the particular configuration.

or 2) Dispatch Intervals for which:

i) As indicated by its SCADA data, the Resource is actually transitioning out of a configuration which is a part of a RUC Commitment Period for which its Commitment Status was “Market” or “Reliability” at the end of a RUC Commitment Period and returning to a configuration which is part of a Day-Ahead Commitment Period and

ii) The Dispatch Interval falls in the expected transition window as defined by transition time, in minutes, following the end of the RUC Commitment Period

is transitioning from one configuration to another infor RUC Make-Whole-Payment Eligibility Period c.

Variable

Settlement Interval

Definition

RtTransitionStateHrlyFlg a, s, h, c Flag Hour Real-Time Transition State Flag per AO per Settlement Location in RUC Make-Whole-Payment Eligibility Period – This flag is set to 1 in hour h for Asset Owner a’s combined cycle Resource at Settlement Location s for each hour containing a Dispatch Interval in which the RtTransitionState5minFlg a, s, i, c value = 1for RUC Make-Whole-Payment Eligibility Period c.

RtStartUp5minAmt a s, i, c $ Eligibility Period

Real-Time Start-Up Cost Amount per AO per Settlement Location per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period - The RTBM Start-Up Offer associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c in Dispatch Interval i. This value is calculated by dividing RtStartUpAmt a s, c by the lesser of the Resource’s (RtMinRunTime a, i, s, c /5), rounded down to the nearest whole number of intervals or 288 intervals, except that, if RtMinRunTime a, i, s, c is less than 5 minutes, then RtStartUpAmt a s, c is divided by 1. These interval values are carried forward into the following Operating Day, if needed, to ensure recovery of any remaining RtStartUpAmt a s, c.

RtStartUpAmt a s, c

(Not Available on Settlement Statement)

$ Eligibility Period

Real-Time Start-Up Cost Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The RTBM Start-Up Offer used in the commitment decision, which includes the impacts of mitigation and the expected state of the Resource prior to the RUC Commitment Period, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

Variable

Settlement Interval

Definition

RtStartUpElig5minFlg a, s, i, c None Dispatch Interval

RUC Start-Up Recovery Eligibility Flag per AO per Resource Settlement Location per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period – This flag is set equal to 1 in each Dispatch Interval of a RUC Make-Whole-Payment Eligibility Period where the Resource is eligible to recover start-up costs, or 0 where the Resource is not eligible to recover start-up costs.

RtRucComStat5minFlg a, s, i, c None Dispatch Interval

RUC Commitment Status Flag per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – This flag is set equal to 1 for each Dispatch Interval of a RUC Make-Whole-Payment Eligibility Period in which a Resource’s Commitment Status was “Market” or “Reliability”, or 0 if its Commitment Status was “Self”.

CncldStartRatio a, s, c None Canceled Start Ratio per Resource Settlement Location in RUC Make-Whole-Payment Eligibility Period – The ratio of ElapsedTime a, s, c to StartUpTime a, s, c as calculated for each Dispatch Interval in RUC Make-Whole-Payment Eligibility Period c.

RtMinRunTime a, i, s, c

Time Dispatch

Interval Real-Time Minimum Run Time per AO per Settlement Location Per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period – The Minimum Run Time, in minutes, used in the commitment decision, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c as submitted as part of the RTBM Market Offer.

RtSynchToMinTime a, i, s, c Time Dispatch Interval

Real-Time Synch To Minimum Time per AO per Settlement Location Per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period – The Synch To Minimum Time, in minutes, used in determining Start-Up Recovery Eligibility, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c as submitted as part of the RTBM Market Offer.

Variable

Settlement Interval

Definition

RtNoLoad5minAmt a, i, s, c $ Dispatch Interval

Real-Time No-Load Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The No-Load Offer used in the commitment decision, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

DaNoLoadHrlyAmt a, s, h None Hour Day-Ahead No-Load Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The value as described under Section 4.5.8.12.

RtMwpCost5minAmt a, s, i, c $ Dispatch Interval

RUC Make-Whole-Payment Cost per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The total Energy and Operating Reserve cost at actual Resource output, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

PotRtRegUpMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.28

PotRtRegDnMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.29

RtMwpRev5minAmt a, s, i, c $ Dispatch Interval

RUC Make-Whole-Payment Revenue per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The total Energy and Operating Reserve revenue at actual Resource output, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

Variable

Settlement Interval

Definition

RtRegUpUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.28

RtRegDnUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.29

RtRegUpMileOffer5minPrc a, s, i $/MW Dispatch Interval

Real-Time Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - The value described under Section 4.5.9.28

RtRegUpExcessMile5minQty a, s, i MW Dispatch Interval

Real-Time Excess Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.4

RtRegDnMileOffer5minPrc a, s, i $/MW Dispatch Interval

Real-Time Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - The value described under Section 4.5.9.29

RtRegDnExcessMile5minQty a, s, i MW Dispatch Interval

Real-Time Excess Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.5

CncldStartAmt a, s, c $ Eligibility Period

Real-Time Cancelled Start Amount per AO per Settlement Location per for the RUC Make-Whole-Payment Eligibility Period – The Start-Up Offer cost reimbursement for an SPP cancelled start-up, in dollars, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

ElapsedTime a, s, c Time Eligibility Period

Elapsed Time per AO per Settlement Location per for the RUC Make-Whole-Payment Eligibility Period – The elapsed time, in minutes, between the start of a Resource’s StartUpTime a, s, c and the time SPP cancelled the start-up, in dollars, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

Variable

Settlement Interval

Definition

StartUpTime a, s, c Time Eligibility Period

Start-up Time per AO per Settlement Location for the RUC Make-Whole-Payment Eligibility Period – The Start-Up Time, in minutes, used in the commitment decision associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c as specified in the RTBM Offer submitted prior to the RUC Make-Whole-Payment Eligibility Period.

RtURDAdj5minAmt a, s, i, c $ Dispatch Interval

URD Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c when the Resource’s URD5minQty a, s, i is outside of the Resource’s ResOpTol5minQty a, s, i.

URD5minQty a, s, i MW Dispatch Interval

Uninstructed Resource Deviation per AO per Settlement Location per Dispatch Interval – The Uninstructed Resource Deviation associated with AO a’s Resource at Settlement Location s in Dispatch Interval i.

ResOpTol5minQty a, s, i MW Dispatch Interval

Resource Operating Tolerance per AO per Settlement Location per Dispatch Interval – The Resource Operating Tolerance associated with AO a’s Resource at Settlement Location s in Dispatch Interval i.

URDMaxTol5minQty i MW Dispatch Interval

Uninstructed Resource Deviation Maximum Tolerance per Dispatch Interval – The maximum value of ResOpTol5minQty a, s, i that is currently set at 20 MW.

URDMinTol5minQty i MW Dispatch Interval

Uninstructed Resource Deviation Minimum Tolerance per Dispatch Interval – The minimum value of ResOpTol5minQty a, s, i that is currently set at 5 MW.

URDTol5minPct i Percent Dispatch Interval

Uninstructed Resource Deviation Tolerance Percentage per Dispatch Interval – The percentage used to calculate the value of ResOpTol5minQty a, s, i that is currently set at 5%.

Variable

Settlement Interval

Definition

RtAvgSetPoint5minQty a, s, i MW Dispatch Interval

Real-Time Average Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The average Setpoint Instruction over Dispatch Interval i for AO a’s Resource at Settlement Location s.

XmptDev5minFlg a, s, i none Dispatch Interval

URD Exemption Flag per AO per Resource Settlement Location per Dispatch Interval – A flag associated with AO a’s eligible Resource at Settlement Location s indicating that a Resource that has operated outside of its Operating Tolerance is or is not exempt from any associated penalty charges in Dispatch Interval i. If the flag is equal to zero, the Resource is not exempt. Otherwise, the flag will be set to a positive integer number which will indicate the reason of the exemption as specified under Section 4.4.4.1.1

RtStatusAdj5minAmt a, s, i, c $ Dispatch Interval

Resource Status Change Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c when the Resource’s Control Status is set to “Manual”.

ControlStatus5minFlg a, s, i None Dispatch Interval

Control Status per AO per Settlement Location per Dispatch Interval – A Resource status indicator associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as set by SPP operators that indicates the current dispatchable status of the Resource.

RtDispMaxEmerCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Maximum Emergency Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Maximum Emergency Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

Variable

Settlement Interval

Definition

RtEffMin5minQty a, s, i MW Dispatch Interval

Real-Time Effective Minimum Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Effective Minimum Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

RtDispMinEconCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Economic Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Minimum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

RtDispMinRegCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Regulation Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Minimum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

RtLimitAdj5minAmt a, s, i, c $ Dispatch Interval

Resource Limit Change Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c for a Real-Time increase in minimum limit.

RtComMinEconCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Economic Capacity Operating Limit Quantity per AO per Settlement Location – The Minimum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as submitted in an RTBM Offer prior to the RUC Make-Whole-Payment Eligibility Period that was used in making the initial Resource commitment decision or was used in making the decision to move from one configuration to another in the case of a combined cycle Resource.

Variable

Settlement Interval

Definition

RtComMinRegCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Regulation Capacity Operating Limit Quantity per AO per Settlement Location– The Minimum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as submitted in an RTBM Offer prior to the RUC Make-Whole-Payment Eligibility Period that was used in making the initial Resource commitment decision or was used in making the decision to move from one configuration to another in the case of a combined cycle Resource.

RtIncrEn5minAmt a, s, i $ Dispatch Interval

Real-Time Incremental Energy Cost Amount per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i from the Effective Minimum Capacity Operating Limit to RtBillMtr5minQty a, s, i.

RtMinEn5minAmt a, s, i, c $ Dispatch Interval

Real-Time Energy Cost at Minimum Limit per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The average incremental energy offer cost at the Effective Minimum Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c

RtDesiredEn5minAmt a, s, i $ Dispatch Interval

Real-Time Energy Cost at Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i, in dollars, from the Effective Minimum Capacity Operating Limit to RtDesiredEn5minQty a, s, i.

Variable

Settlement Interval

Definition

RtDesiredEn5minQty a, s, i MW Dispatch Interval

Real-Time Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval – The Desired Dispatch MW for AO a’s eligible Resource for Dispatch Interval i at RtLmp5minPrc s, i as calculated from the Resource’s As Dispatched Energy Offer Curve using the As-Committed Minimum Capacity Limit (Economic or Regulating, as applicable) as an output floor and the As-Committed Maximum Capacity Limit (Economic or Regulating, as applicable) as an output ceiling.

RtOom5minAmt a, s, i

$ Dispatch Interval

Real-Time Out-Of-Merit Make-Whole-Payment Amount per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.9.

RtRegAdj5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation Deployment Adjustment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.19.

RtOffRegUp5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Offered Regulation-Up Service Quantity per AO per Settlement Location per Hour - The total quantity of Regulation-Up Service MW represented by AO a’s cleared offered Regulation-Up Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(i).

RtRegUp5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour –The value described under Section 4.5.9.4.

RtRegUpOffer a, s, i

$/MW Dispatch

Interval Real-Time Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval – The Regulation-Up Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i. Note that this value is equal to the Regulation-Up Service Offer following FERC Order 755 implementation or is equal to the Regulation-Up Offer prior to Order 755 implementation.

Variable

Settlement Interval

Definition

RtRegDnOffer a, s, i

$/MW Dispatch Interval

Real-Time Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval – The Regulation-Down Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i.

RtSpinOffer a, s, i, c

Real-Time Spinning Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Spinning Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtSuppOffer a, s, i, c

Real-Time Supplemental Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtRegUpCapOffer a, s, i

$/MW Dispatch

Interval Real-Time Regulation-Up Offer per AO per Resource Settlement Location per Dispatch Interval– The Regulation-Up Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i.

RtOffSpin5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Spinning Reserve MW represented by AO a’s cleared offered Spinning Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(ii).

RtOffSupp5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Supplemental Reserve MW represented by AO a’s cleared Offered Supplemental Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4 (3)(a)(iii).

Variable

Settlement Interval

Definition

RtRegUpforCRSubAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Cleared Substituted Regulation-Up for Contingency Reserve Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The cost of the quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the RTBM on AO a’s Resource at Settlement Location s for Dispatch Interval i.

RtRegUpforCRSub5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Substituted Regulation-Up for Contingency Reserve MW Amount per AO per Settlement Location per Dispatch Interval – The MW amount quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the RTBM on AO a’s Resource at Settlement Location s for Dispatch Interval i.

DaRegUpforCRSubHrlyQty a, h, s MW Hour Day-Ahead Cleared Substituted Regulation-Up Service for Contingency Reserve MW Amount per AO per Settlement Location per Hour – The quantity described in Section 4.5.8.12.

RtFixedRegUp5minQty a, s, i

MW Dispatch

Interval Real-Time Fixed Regulation-Up Quantity per AO per Resource Settlement Location per Dispatch Interval – The Fixed Regulation-Up MW specified in the Regulation-Up Offer associated with AO a’s Resource Settlement Location s at the time of the RTBM in Dispatch Interval i.

RtFixedRegDn5minQty a, s, i

MW Dispatch

Interval Real-Time Fixed Regulation-Down Quantity per AO per Resource Settlement Location per Dispatch Interval– The Fixed Regulation-Down MW specified in the Regulation-Down Offer associated with AO a’s Resource Settlement Location s at the time of the RTBM in Dispatch Interval i.

RtFixedSpin5minQty a, s, i

MW Dispatch

Interval Real-Time Fixed Spinning Reserve Quantity per AO per Resource Settlement Location per Dispatch Interval – The Fixed Spinning Reserve MW specified in the Spinning Reserve Offer associated with AO a’s Resource Settlement Location s at the time of the RTBM in Dispatch Interval i.

Variable

Settlement Interval

Definition

RtFixedSupp5minQty a, s, i

MW Dispatch

Interval Real-Time Fixed Supplemental Reserve Quantity per AO per Resource Settlement Location per Dispatch Interval – The Fixed Supplemental Reserve MW specified in the Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s at the time of the RTBM in Dispatch Interval i.

RtRegUpAvail5minAmt a, s, i, $ Dispatch Interval

Real-Time Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval - The Regulation-Up Service Offer cost, in dollars, associated with AO a’s Resource at Settlement Location s for Dispatch Interval i.

RtRegDnAvail5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval - The Regulation-Down Service Offer cost, in dollars, associated with AO a’s Resource at Settlement Location s for Dispatch Interval i.

RtRegUpExcessMile5minAmt a, s, i $ Dispatch Interval

Real-Time Excess Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4.

RtRegDnExcessMile5minAmt a, s, i $ Dispatch Interval

Real-Time Excess Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5.

RtSpinAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Spin Offer Cost Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period - The Spinning Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtSuppAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Supplemental Offer Cost Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period - The Supplemental Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

Variable

Settlement Interval

Definition

RtLmp5minPrc s, i

Dispatch Interval

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

RtBillMtr5minQty a, s, i MW Dispatch Interval

Real-Time Actual Meter Quantity per AO per Location per Dispatch Interval - The value defined under Section 4.5.9.1 for Dispatch Interval i.

RtRegUpMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Regulation-Up per Reserve Zone - The value defined under Section 4.5.9.4.

RtRegDnMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Regulation-Down per Reserve Zone - The value defined under Section 4.5.9.5.

RtSpinMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Spinning Reserve per Reserve Zone - The value defined under Section 4.5.9.6.

RtSuppMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Supplemental Reserve per Reserve Zone - The value defined under Section 4.5.9.7.

RtCcRegUpAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Regulation-Up Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Up positions during transitions between configurations for Hour h.

RtCcRegDnAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Regulation-Down Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Down positions during transitions between configurations for Hour h.

RtCcSpinAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Hour h.

Variable

Settlement Interval

Definition

RtCcSuppAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Hour h.

RtCcRegUpAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Regulation-Up Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Up position during transitions between configurations for Dispatch Interval i.

RTCcRegDnAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Regulation-Down Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Down position during transitions between configurations for Dispatch Interval i.

RtCcSpinAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Dispatch Interval i.

RTCcSuppAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Dispatch Interval i.

Variable

Settlement Interval

Definition

RtCcEnAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Energy Cost Adjustment per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Energy position during RUC Commitment Periods instructing the Resource to be in a configuration in which it could not generate at least as much as output as was cleared in the Day-Ahead Market for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

CcDlyFlg a, s, d none Operating Day Combined Cycle Flag per AO per Settlement Location per Day – A flag, when = 1, indicating AO a’s combined cycle Resource at Settlement Location s is registered as an enhanced combined cycle Resource for Operating Day d.

ResDeCommit5minFlg a, s, i None Dispatch Interval

Resource De-Commitment Flag per AO per Dispatch Interval per Settlement Location – The value as described under Section 4.5.9.10.

DispInstrucMaxHrlyFlg a, s, h None Hour Dispatch instruction Maximum Flag per AO per Hour per Settlement Location – The value as described under Section 4.5.9.10.

RtRegUpRev5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Up Service Revenue Amount per AO per Settlement Location per Dispatch Interval – The Real-Time incremental Regulation-Up Service revenue associated with AO a’s Resource at Settlement Location s for Dispatch Interval i.

RtRegDnRev5minAmt a, s, i, $ Dispatch Interval

Real-Time Regulation-Down Service Revenue Amount per AO per Settlement Location per Dispatch Interval – The Real-Time incremental Regulation-Down Service revenue associated with AO a’s Resource at Settlement Location s for Dispatch Interval i.

6.1.1 Responsibilities of the Resource Asset Owner

Each Asset Owner shall be responsible for conducting its operations in accordance with all applicable SPP market rules and guidelines. Each Asset Owner shall supply operating characteristics of its Resource, including, but not limited to: location of physical Resource, Legal owner and Resource type as specified below. Registration shall also include identification of the Settlement Location and Settlement Area of the Resource. At the time of registration, SPP will populate the Resource Offer parameters defined in Section 4.2.2.1. These Resource Offer parameters must be updated by the Market Participant to reflect Resource specific parameters during the 7 days prior to the Resource’s effective date. The Market Participant representing the applicable Asset Owner is responsible for ensuring that real-time settlement meter data is submitted to SPP. Valid Resource Types are:

(1) Generating Unit (“Gen”);

(2) Plant (“PLT”);

(3) Dispatchable Demand Response (“DDR”) Resource;

(4) Block Demand Response (“BDR”) Resource;

(5) Combined Cycle (“CC”) Resource (if the MCR option described under Section 6.1.7.1 is not selected);

(6) Jointly Owned Unit (“JOU”) Resource (represents Physical JOU Resource only as defined under Section 4.2.2.5.4(1). Each individual JOU Share Resource, as described under Section 4.2.2.5.4(2), must register as “PLT”));

(7) Dispatchable Variable Energy Resource (“DVER”);

(8) Non-Dispatchable Variable Energy Resource (“NDVER”); and

(9) External Dynamic Resource (“EDR”);

(9)(10) Multi-Configuration Combined Cycle Resource (“MCR”) (represents Combined Cycle Plant for Resources selecting the modeling option described under Section 6.1.7.1);

For each Resource registered, the Asset must specify whether Settlement Meter Data will be submitted on an hourly basis or on a 5-minute basis.

6.1.7 Combined Cycle Resource

In addition to the responsibilities described under Section 6.1.1, Market Participants registering a Resource as a combined cycle Resource shall register their Resources for Commercial Modeling purposes using one of the four options described below.

(1) Each combustion turbine and steam turbine may be registered as a separate Resource asset. Each individual Resource asset will be assigned a unique Settlement Location and each Resource asset must be registered to the same Asset Owner.

(a) Each Resource asset will be committed and dispatched as an independent Resource. Each individual Resource asset will be settled at its Settlement Location. Telemetering and Settlement meter data must be submitted for each registered Resource asset.

(b) The Market Participant may optionally request that all Resource assets be registered at a Common Bus.

(2) An aggregate unit configuration may be registered as a single Resource asset in the Commercial Model and is assigned an APNode Settlement Location.

(a) The aggregate Resource asset will be committed and dispatched as a separate Resource and will be settled at its APNode Settlement location.

(b) Settlement meter data must be submitted for the aggregate Resource;

(c) Telemetering must be submitted for each component of the aggregate Resource that is modeled in the Network Model.

(3) The combined cycle Resource may be registered in the Commercial Model as several “pseudo” unit assets, each unit representing a combination of one combustion turbine and a portion of a steam turbine. Each pseudo unit asset is assigned an APNode Settlement Location.

(a) Each pseudo unit asset will be committed and dispatched as a separate Resource and will be settled at its APNode Settlement location.

(b) Settlement meter data must be submitted for each individual pseudo unit asset.

(c) Telemetering must be submitted for each component - of each individual pseudo unit asset that is modeled in the Network Model.

(d) The Market Participant may optionally request that all pseudo unit assets be registered at a Common Bus.

6.1.7.1(4) Multi-Configuration Combined Cycle Resource

The combined cycle Resource registered as a MCR may shall be registered as a single parent Resource Asset with associated separate Resources,each representing a valid operating configurations.

(a) Market Participants using thise combined cycle configuration based modeling option shall register the physical units that are part of the combined cycle Rresource as well as the logical operational configuration modes representing a “logical unitvalid operating configuration” of the combined cycle Resource. Each logical unitvalid operating configuration is treated as a separate Resource in the Commercial Modelmarket systems and may have Resource Offers submitted using the same Offer parameters as any other Resource. The physical unit data are referenced by the Network Model that needs detailed unit physical characteristics and parameters as inputs.

(b) Configuration Based modeling is only available for registered MCRs that are combined cycle Resources thatwhich can operate in more than one mode. SPP may limit tThe mostnumber of

logical operational configurations that can be submittedregistered per an combined cycle ResourceMCR is three if needed to address software performance issues.

(c) Market Participants shall supply operating characteristics for each logical operational configuration of an combined cycle ResourceMCR, including, but not limited to: location of physical Resource, Legal owner, Resource type set to combined cycleMCR (see section 6.1.1), and all of the non-price related operating parameters listed under Section 4.2.2.1 for each logical operational configuration.

(d) Market Participants shall define which operational configurations can be used when starting up or shutting down the combined cycle Resource. As an example, Exhibit 6-2 illustrates that the combined cycle Resource can only be started on configurations 1 and 3, while it can only be shutdown once it is operating in configuration 1 mode;

Exhibit 6-2: Combined Cycle Configuration Enabled Start/Shutdown Capability

Configuration

1 Configuration

2 Configuration

3 Configuration

4 Startup

(Yes/No): Yes No Yes No Shutdown (Yes/No): Yes No No No

(de) Market Participants shall supply a state transition matrix for each logical operational configuration. The state transition matrix describes the state transition relationship between the individual logical operational configurations, and includes the following:

(i) Transition Enabled: a flag describing whether a configuration transition is allowed between two given configurations, in the direction of ‘From’ configuration towards ‘To’ configuration;

(ii) Transition Cost: the additional operational cost associated with a configuration transition, in the direction of ‘From’ configuration towards ‘To’ configuration;

(iii) Transition Time: the additional time needed to prepare for a configuration transition, in the direction of ‘From’ configuration towards ‘To’ configuration. During Transition Time, the Resource will not be eligible for clearing Operating Reserve;

Exhibit 6-3 provides an example of a state transition matrix for Transition Costs which indicates that switching to configuration 2 will result in a transition cost of $300.00, assuming the plant is operating in configuration 1 mode when the transition occurs.

Exhibit 6-32: Combined CycleConfigurationMCR Transition Cost Matrix

From > To Configuration 1

Configuration 2

Configuration 3

Configuration 4

Configuration 1 300 2,000 600

Configuration 2 0 1,500 3,000

Configuration 3 0 0 6,000

Configuration 4 0 0 0

(ef) Market Participants shall submit a ConfigurationMCR cCapability cArray. The capability array stores information on the physical units that can participate in the operational state described by a logical operational configuration. Exhibit 6-4 provides an example sample of a configuration capability array, where a ‘P’ represents a primary resource available for the configuration and an ‘A’ represents an alternate resource that can participate in the configuration.

Exhibit 6-43: Combined Cycle Configuration MCR Capability Array

3 X 1 MCR Capability Array

Configuration 1 X 1 Configuration 2 X 1 Configuration 3 X 1

CT-1, ST CT-1, CT-2, ST CT-1, CT-2, CT-3, ST

CT-2. ST CT-2, CT-3, ST

CT3, ST CT-1, CT-3, ST

3x1 CC Configuration Capability Array

1 2 3 CT-1 P P P CT-2 P P CT-3 A A P ST-1 P P P

(g) Market Participants may optionally define groups of operational configurations to which a Group

Minimum Run Time will apply. The Group Minimum Run Time, if Groups are defined, will be used in addition to the Plant Minimum Run Time for more accurate operational modeling of the plant. Exhibit 6-45 shows an example of how a group definition might be defined for a 2 x 1 plant. Configuration 1 is CT1; Configuration 1 X 1 A2 is (CT1, ST); Configuration 1 X 1 B3 is (CT2, ST) and Configuration 42 X 1 is (CT1, CT2, ST).

Exhibit 6-54: Combined Cycle Configuration MCR Group Definition

Group Definition Configuration 1 X 1 A Configuration 1 X 1 B2 Configuration 32 X 1 4

Group 1 Yes YesNo Yes Yes Group 2 No Yes Yes

Exhibit 6-6 shows the impact of the use of Plant Minimum Run Time and Group Minimum Run Time on how the combined cycle plant is committed through various configurations.

Exhibit 6-65: Combined Cycle Configuration Group Definition

8.2.2.6 Mitigation Measures for Transition State Offers

(1) The mitigation measures in this section apply only to Resources registered using the combined cycle configuration based modeling option as described in Section 4.2.2.5.3(4)6.1.7.1. A Mitigated Transition State Offer shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines for each potential transition state change. The Mitigated Transition State Offer may be updated up to 1100 hours on the day before the Operating Day for use in the Day- Ahead

Market. In the case a Resource inis not committed by the Day-Ahead Market, the Mitigated Transition State Offer may be updated until the Day-Ahead RUC process begins. The Mitigated Transition State Offer submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day and the Intra-Day RUC processes on the Operating Day.

(2) The Transition State Offer conduct thresholds are as follows:

(a) For Resources with local market power as described in Section 8.2.2.7, the conduct threshold is a 10% increase above the mitigated Transition State Offer;

(a)(b) For all other Resources, the conduct threshold is a 25% increase above the Mitigated Transition State Offer.

(2)(3) The Transmission Provider shall apply mitigation measures by replacing the Transition State Offer with the applicable Mitigated Transition State Offer if:

(a) The Resource’s Transition State Offer exceeds the applicable conduct threshold; and (b) The Resource is subject to mitigation measureshas local market power as determined in Section

8.2.2.28.2.2.7; and (c) The Resource either (a) fails the Market Impact Test as described in Section 8.2.2.9, or (b) has

local market power as determined in Section 8.2.2.7(3).

SPP Tariff (OATT)

Attachment AE

4.1 Offer Submittal

Beginning seven (7) days prior to the Operating Day, Market Participants may begin to submit

Offers for use in the Day-Ahead Market and Offers for use in the RTBM. Day-Ahead Market Offers

may be updated up to 1100 hours Day-Ahead and RTBM Offers may be updated thirty (30) minutes

prior to each Operating Hour. Offer submittals shall conform to the following:

(1) Offers submitted in the Day-Ahead Market are independent from Offers submitted in the RTBM;

(2) Market Participants may specify that the Offers submitted in the Day-Ahead Market also apply

in the RTBM;

(a) Such an Offer shall be rejected in the RTBM if the Market Participant has submitted a

Resource commitment status of “not participating” as described in Section 4.1(10)(e) of

this Attachment AE and the Resource is not participating in the Day-Ahead Market.

(3) Submitted Resource Offers will automatically roll forward hour to hour until changed within

each respective market;

(4) Offers may be submitted that vary for each hour of the Operating Day, except the Offer

parameters related to unit commitment as defined in the Market Protocols for which a single

value is submitted. These unit commitment Offer parameters will automatically roll forward in

each hour until updated;

(5) Offers submitted for use in the RTBM are also used in the RUC;

(6) Resource Offers may only be submitted at Resource Settlement Locations, Import Interchange

Transaction Offers may only be submitted at External Interface Settlement Locations and Virtual

Energy Offers may be submitted at any Settlement Location, including a Market Hub;

(7) For Regulation Qualified Resources and Regulation-Up Qualified Resources, Market

Participants may submit Resource Offers for Regulation-Up, Spinning Reserve and

Supplemental Reserve. For Regulation-Down Qualified Resources and Regulation Qualified

Resources, Market Participants may submit Resource Offers for Regulation-Down. For Spin

Qualified Resources, Market Participants may submit Resource Offers for Spinning Reserve and

Supplemental Reserve. For Supplemental Qualified Resources, Market Participants may submit

Resource Offers for Supplemental Reserve. Resource qualifications are verified by the

Transmission Provider as part of the registration process as follows:

(a) A Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-

Down Qualified Resource must pass a specific regulation test as defined in Section 2.10.3

of this Attachment AE and must be capable of deploying one hundred percent (100%) of

cleared Regulation-Up and/or Regulation-Down within the Regulation Response Time

for a continuous duration of sixty (60) minutes and provide telemetered output data that

meets the technical requirements specified in the Market Protocols.

(b) A Spin Qualified Resource must self-certify that the Resource is capable of deploying

one hundred percent (100%) of cleared Spinning Reserve or cleared Supplemental

Reserve within the Contingency Reserve Deployment Period for a continuous duration of

sixty (60) minutes and provide telemetered output data that meets the technical

requirements specified in the Market Protocols.

(c) A Supplemental Qualified Resource must self-certify that the Resource is capable of

deploying one hundred percent (100%) of cleared Supplemental Reserve from an off-line

state within the Contingency Reserve Deployment Period for a continuous duration of

sixty (60) minutes and provide telemetered output data that meets the technical

requirements specified in the Market Protocols.

(8) Resource Offers are limited by the Offer caps and floors specified in Section 4.1.1 of this

Attachment AE;

(9) The Resource Offer parameters that constitute a valid Offer for use in either the Day-Ahead

Market or RTBM are submitted using the data formats, procedures, and information defined in

the Market Protocols and will include the following (as further defined in the Market Protocols):

• Resource Name

• Resource Type

• Start-up Offer

• No-Load Offer

• Energy Offer Curve

• Transition State Offer (configuration based combined cycle only)

• Transition State Time (configuration based combined cycle only)

• Regulation–Up and Regulation-Down Offers

• Spinning and Supplemental Reserve Offers

• Sync-To-Min and Min-To-Off Times

• Start-Up Time

• Hot to Intermediate and Hot to Cold Times

• Maximum Daily and Weekly Starts

• Maximum Daily Energy

• Maximum and Minimum Run Times

• Plant Minimum Run Time (configuration based combined cycle only)

• Group Minimum Run Time (configuration based combined cycle only)

• Minimum Down Time

• Minimum Emergency Capacity Operating Limit and Run Time

• Minimum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Emergency Capacity Operating Limits and Run Time

• Maximum Quick-Start Response Limit

• Ramp-Rate-Up and Ramp-Rate-Down

• Turn-Around Ramp Rate Factor

• Regulation Ramp Rate

• Contingency Reserve Ramp Rate

• Resource Status

• JOU Ownership Share

• Mitigated Transition State Offer (configuration based combined cycle only)

(10) Market Participants must specify a Resource commitment status as part of the Resource Offer

using the data formats, procedures, and information defined in the Market Protocols. Market

Participants use the commitment status to indicate;

(a) Whether they are self-committing a Resource;

(b) Whether the Resource may be committed by the Transmission Provider;

(c) Whether the Resource may be committed by the Transmission Provider only to alleviate

an anticipated Emergency Condition or local reliability issue; or

(d) Whether the Resource is unavailable.

(11) Market Participants must specify a Resource dispatch status as part of the Resource Offer using

the data formats, procedures and information defined in the Market Protocols. Market

Participants use the dispatch status to notify the Transmission Provider whether the Resource is:

(a) Eligible for Energy Dispatch;

(b) Eligible for Operating Reserve clearing; or

(c) Self-scheduled for Operating Reserve.

(12) Resource limits submitted as part of the Resource Offer must pass the validation rules defined in

the Market Protocols, otherwise, the Resource Offer will be rejected; and

(13) The Market Participant must comply with the must-offer requirements as defined in Section 2.11

of this Attachment AE. 4.1.2.2 Combined Cycle Resource

Market Participants shall select from one of the four following options regarding

submitting Resource Offers for their registered combined cycle Resources, which will be

declared during asset registration as described under Sections 2.2 and 2.9 of this Attachment AE:

(1) A Resource Offer may be submitted for a single aggregate combined cycle Resource,

where the aggregate will represent a Market Participant selected operating configuration

of combustion turbines and steam turbines. Under this option, the combined cycle

Resource will be committed, dispatched and settled the same as any other Resource;

(2) A Resource Offer may be submitted for each combined cycle Resource combustion

turbine and/or steam turbine and each component will be committed and dispatched

independently and settled the same as any other single Resource;

(3) A Resource Offer may be submitted for each pseudo combined cycle Resource, where

each pseudo combined cycle Resource will represent the combination of one combustion

turbine and a portion of the steam turbine. Under this option, each pseudo combined

cycle Resource must be capable of being committed and dispatched independently the

same as any other Resource and each pseudo combined cycle Resource will be settled the

same as any other Resource; or

(4) A Resource Offer may be submitted for multiple combined cycle configurations, with

each configuration being treated as a separate Resource. Under this option, Market

Participants must define valid configurations during asset registration, including valid

start-up and shutdown configurations and valid transitions between configurations as

defined in the Market Protocols. The Transmission Provider will determine the most

economic commitment configuration, if requested to do so by the Market Participant as

part of the submitted Resource Offer, and, once committed, the most economic

configuration to transition to on an hourly basis for use in both the Day-Ahead Market

and Real-Time Balancing Market. Each valid combined cycle Resource configuration

will be committed and dispatched and/or transitioned and dispatched the same as any

other Resource. Settlement for a combined cycle Resource will occur in the same manner

as any other Resource except that Transition State Offer costs will also be eligible for

recovery as described under Section 8.6.5 of this Attachment AE.

8.5.9 Day-Ahead Make Whole Payment Amount

(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner and is calculated

for each Resource with an associated Day-Ahead Market Commitment Period that was

committed by the Transmission Provider with a Day-Ahead Market Resource Offer commitment

status as defined under Sections 4.1(10)(b) and (c) of this Attachment AE, or was committed as

part of the Multi-Day Reliability Assessment as defined under Section 4.5.3 of this Attachment

AE. A payment is made to the Asset Owner when the sum of the Resource’s costs is greater than

the Day-Ahead Market revenues received for that Resource over the Resource’s Day-Ahead

Market make whole payment eligibility period. The make whole payment is equal to this

difference between these costs and revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal to a Resource’s

Day-Ahead Market Commitment Period except as defined herein. For Resources with an

associated Day-Ahead Market Commitment Period that begins in one Operating Day and ends in

the next Operating Day, two (2) Day-Ahead Market make whole payment eligibility periods are

created. The first period begins in the first Operating Day in the hour that the Day-Ahead

Market Commitment Period begins and ends in the last hour of the first Operating Day. The

second period begins in the first hour of the next Operating Day and ends in the last hour of the

Day-Ahead Market Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole payment

eligibility period. Offer costs are calculated using the Day-Ahead Market Offer prices in effect

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

Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment eligibility period

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

single Day-Ahead Market make whole payment eligibility period is contained within a

single Operating Day.

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

following Day-Ahead Market make whole payment eligibility periods:

(i) For any Day-Ahead Market make whole payment eligibility period that is

adjacent to the end of a RUC make whole payment eligibility period except as

described under Section 8.6.5(3)(h);

(ii) For any Day-Ahead Market make whole payment eligibility period resulting from

a Day-Ahead Market Commitment Period that contains a Day-Ahead Market self-

commit hour; or

(iii) For any Day-Ahead make whole payment eligibility period for which a Resource

is a Synchronized Resource prior to this commitment period at a time one (1) hour

prior to that Resource’s Day-Ahead Market Commit Time less the Resource’s

Sync-To-MinTime.

(c) For each Day-Ahead Market make whole payment eligibility period within an Operating

Day, a Resource’s Day-Ahead Market Start-Up Offer is divided by the lesser of (1) the

Resource’s Minimum Run Time rounded down to the nearest hour or (2) twenty-four

(24) hours, and that portion of the Start-Up Offer is included as a cost in each hour of the

Day-Ahead Market make whole payment eligibility period until the sum of these hourly

costs are equal to the Day-Ahead Market Start-Up Offer or until the end of the Day-

Ahead Market make whole payment eligibility period, whichever occurs first.

(d) To the extent that the full amount of the Day-Ahead Market Start-Up Offer is not

accounted for in the last Day-Ahead Market make whole payment eligibility period in the

Operating Day, any remaining Day-Ahead Market Start-Up Offer costs are carried

forward for recovery in the first Day-Ahead Market make whole payment eligibility

period of the following Operating Day.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given Day-Ahead

Market make whole payment eligibility period is calculated as follows:

Day-Ahead Make Whole Payment Amount =

Maximum of [Either Zero or Sum of ((Day-Ahead Make Whole Payment Cost Amount

in the Day-Ahead Market Make Whole Payment Eligibility Period) + (Day-Ahead Make

Whole Payment Revenue Amount in the Day-Ahead Market Make Whole Payment

Eligibility Period))] * (-1)

(a) An Asset Owner’s Day-Ahead Make Whole Payment Cost Amount for each eligible

Resource is equal the sum for all hours in the Day-Ahead Market Make Whole Payment

Eligibility Period of:

(i) Day-Ahead Market Start-Up Offer,

(ii) Day-Ahead Market No-Load Offer,

(iii) Day-Ahead Transition State Offer,

(iv) Energy cost associated with cleared Resource Energy from Resource Energy

Offers as described under Section 5.1.3 of this Attachment AE, as calculated by

multiplying cleared Resource Energy by the cost of such Energy as calculated

from the Resource’s Day-Ahead Market Energy Offer Curve,

(v) Regulation-Up cost associated with cleared Regulation-Up from Regulation-Up

Offers as described under Section 5.1.3 of this Attachment AE, as calculated by

multiplying Regulation-Up by the cost of such Regulation-Up as calculated from

the Resource’s Day-Ahead Market Regulation-Up Offer,

(vi) Regulation-Down cost, associated with cleared Regulation-Down from

Regulation-Down Offers as described under Section 5.1.3 of this Attachment AE,

as calculated by multiplying Regulation-Down by the cost of such Regulation-

Down as calculated from the Resource’s Day-Ahead Market Regulation-Down

Offer,

(vii) Spinning Reserve cost, associated with cleared Spinning Reserve from Spinning

Reserve Offers as described under Section 5.1.3 of this Attachment AE, as

calculated by multiplying Spinning Reserve by the cost of such Spinning Reserve

as calculated from the Resource’s Day-Ahead Market Spinning Reserve Offer,

(viii) Supplemental Reserve cost, associated with cleared Supplemental Reserve from

Supplemental Reserve Offers as described under Section 5.1.3 of this Attachment

AE, as calculated by multiplying Supplemental Reserve by the cost of such

Supplemental Reserve as calculated from the Resource’s Day-Ahead Market

Supplemental Reserve Offer.

(ix) For combined cycle Resources that are registered in accordance with the offer

submission option described under Section 4.1.2.2(4) of this Attachment AE,

additional costs associated when the Resource has cleared Contingency Reserve

in the Day-Ahead Market and must buy back that position in Real-Time at an

average hourly Real-Time MCP that is greater than the Day-Ahead MCP, the

Market Participant may be eligible for a make-whole payment if such costs are

not otherwise eligible for recovery under Section 8.6.5 of this Attachment AE. To

be eligible, these costs must be incurred during time periods in which the

Resource is transitioning between configurations, at the direction of the

Transmission Provider, and such cost is not due to any independent action of the

Market Participant. The Market Participant may also be eligible for a make-

whole payment for cost incurred during transition if the Resource is transitioned

by a local transmission operator to address a Local Emergency Condition, except

that if the Market Monitor determines such Resources were selected in a

discriminatory manner by the local transmission operator, as determined pursuant

to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were

affiliated with the local transmission operator, then such Resources are not

eligible to receive a Day-Ahead make whole payment for these costs. In such

cases, the additional costs are equal to the difference between the average hourly

Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market

cleared Contingency Reserve MW amounts. Recovery of these costs is limited to

the time period defined as the Transition State Time submitted in the Resource

Offer.

(b) An Asset Owner’s Day-Ahead Make Whole Payment Revenue Amount for each eligible

Resource is equal to the sum for all hours in the Day-Ahead Market Make Whole

Payment Eligibility Period of:

(i) Energy revenue associated with cleared Resource Energy from Resource Energy

Offers as described under Section 5.1.3 of this Attachment AE, calculated by

multiplying Resource Energy by Day-Ahead LMP at that Resource Settlement

Location, and

(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and 8.5.4 for that

eligible Resource.

8.6.5 Reliability Unit Commitment Make Whole Payment Amount

(1) Asset Owners of Resources committed by the Transmission Provider with an RTBM Resource Offer

commitment status as defined under Sections 4.1(10)(b) and (c) of this Attachment AE or committed by a local

transmission operator that the Transmission Provider determines were selected in a non-discriminatory manner

by the local transmission operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE, are

eligible to receive a RUC make whole payment. A RUC make whole payment is made to the Asset Owner

when the sum of a Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Transition State Offer

costs, Energy Offer Curve and Operating Reserve Offer costs associated with actual Energy and cleared RTBM

Operating Reserve is greater than the Energy and Operating Reserve RTBM revenues received over the

Resource’s RUC make whole payment eligibility period. Recovery of such compensation shall be collected in

accordance with Section 8.6.7 of this Attachment AE. Resources that are committed by a local transmission

operator that the Transmission Provider determines were selected in a discriminatory manner by the local

transmission operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE, are not eligible to

receive a RUC make whole payment.

(2) A Resource’s RUC make whole payment eligibility period is equal to that Resource’s RUC

Commitment Period unless;

(a) For Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next

Operating Day, two RUC make whole payment eligibility periods are created. The first period begins in the

first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the

last Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch Interval of the

next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time; or

(b) For combined cycle Resources that were registered in accordance with the offer submission option

described under Section 4.1.2.2.(4) of this Attachment AE that cleared in the Day-Ahead Market and that were

transitioned by the Transmission Provider into a different configuration in Real-Time, that Resource’s RUC

make-whole payment eligibility period that (i) begins in the first Dispatch Interval for the hour in which the

transition to the selected configuration is to be completed, as calculated based upon when the Transmission

Provider issues the order to transition and the Resource’s Transition State Time, and (ii) ends in the Dispatch

Interval in which the Transmission Provider issues an order to transition to same configuration used in the Day-

Ahead Market clearing, or the Dispatch Interval in which the combined cycle Resource no longer has Day-

Ahead Market cleared MWs or the end of the Operating Day, whichever is earliest.

(3) The following cost recovery rules apply to each RUC make whole payment eligibility period. Offer

costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made.

(a) If the Transmission Provider cancels a Commitment Instruction prior to the start of the associated RUC

make whole payment eligibility period and the Resource is not a Synchronized Resource, the Asset Owner will

receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners

may request additional compensation through submittal of actual cost documentation to the Transmission

Provider. The Transmission Provider will review the submitted documentation and confirm that the submitted

information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for

recovery.

(b) In order to receive the full amount of Start-Up Offer recovery within a RUC make whole payment

eligibility period, the Resource must be a Synchronized Resource in at least one Dispatch Interval in the RUC

make whole payment eligibility period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC make whole

payment eligibility period, the Resource must be a Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period for a Resource in a single

Operating Day. A single RUC make whole payment eligibility period is contained within a single Operating

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC make

whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period that is adjacent to the end of a Day-Ahead Market

make whole payment eligibility period;

(ii) Any RUC make whole payment eligibility period for which a Resource is a Synchronized Resource

prior to this commitment period at a time one (1) hour prior to that Resource’s RUC Commit Time less the

Resource’s Sync-To-Min Time; and

(iii) Any RUC make whole payment eligibility period resulting from a RUC Commitment Period that

contains an hour for which the Resource was self-committed.

(f) For each RUC make whole payment eligibility period within an Operating Day, a Resource’s RTBM

Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by twelve (12),

rounded down to the nearest whole interval, or (2) twenty-four (24) hours multiplied by twelve (12), and that

portion of the Start-Up Offer is included as a cost in each interval of the RUC make whole payment eligibility

period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC

make whole payment eligibility period, whichever occurs first.

(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC

make whole payment eligibility period in the Operating Day, any remaining RTBM Start-Up Offer costs are

carried forward for recovery in the first RUC make whole payment eligibility period of the following Operating

Day provided that the Resource has not been committed in the Day-Ahead Market in any hour of the first RUC

make whole payment eligibility period as described in (h) below.

(h) If the Resource has been committed in the Day-Ahead Market in a period adjacent to and following a

RUC make whole payment eligibility period to the extent that the full amount of the RTBM Start-Up Offer is

not accounted for in the RUC make whole payment eligibility period, any remaining RTBM Start-Up Offer

costs are carried forward for recovery in the Day-Ahead make whole payment eligibility period.

(i) If a Resource has operated outside of its Operating Tolerance in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating point is not eligible for recovery for

that Dispatch Interval where such cost is calculated as described under Subsection 4(c) below.

(j) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost associated with energy

output above the Resource’s economic operating point is not eligible for recovery for that Dispatch Interval

where such cost is calculated as described under Subsection 4(c) below.

(k) If a Resource’s minimum operating limit is increased above the Resource’s minimum operating limit

that was used to make the commitment decision, the increase is greater than the Resource’s Operating

Tolerance and the Resource remains dispatchable in any Dispatch Interval, any cost associated with energy

output above the Resource’s economic operating point is not eligible for recovery for that Dispatch Interval

where such cost is calculated as described under Subsection 4(c) below.

(l) For combined cycle Resources that are registered in accordance with the offer submission option

described under Section 4.1.2.2(4) of this Attachment AE, additional costs associated when the Resource has

cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at an

average hourly Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be

eligible for a make-whole payment. To be eligible, the cost must be incurred during time periods in which the

Resource is transitioning between configurations, at the direction of the Transmission Provider, and such cost is

not due to any independent action of the Market Participant. The Market Participant may also be eligible for a

make-whole payment for cost incurred during transition if the Resource is transitioned by a local transmission

operator to address a Local Emergency Condition, except that if the Market Monitor determines such Resources

were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section

6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator,

then such Resources are not eligible to receive a RUC make whole payment for these costs. In such cases, the

additional costs are equal to the difference between the average hourly Real-Time MCP and the Day-Ahead

MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. For Contingency Reserve,

recovery of the cost is limited to the time period defined as the Transition State Time submitted in the Resource

Offer. For Regulation-Up and/or Regulation-Down, recovery of the cost is limited to the hours in which the

Resource is transitioning between configurations.

(m) For combined cycle Resources that are registered in accordance with the offer submission option

described under Section 4.1.2.2(4) of this Attachment AE, additional costs associated when the Resource has

cleared Energy in the Day-Ahead Market and must buy back that position in Real-Time at an average hourly

Real-Time LMP that is greater than the Day-Ahead LMP, the Market Participant may be eligible for a make-

whole payment. To be eligible, the cost must be incurred during time periods in which the Resource is

transitioning between configurations, at the direction of the Transmission Provider, and such cost is not due to

any independent action of the Market Participant. The Market Participant may also be eligible for a make-

whole payment for cost incurred during transition if the Resource is transitioned by a local transmission

operator to address a Local Emergency Condition, except that if the Market Monitor determines such Resources

were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section

6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator,

then such Resources are not eligible to receive a RUC make whole payment for these costs. In such cases, the

additional costs are equal to the positive difference between the average hourly Real-Time LMP and the Day-

Ahead LMP multiplied by the positive difference between the Resource’s Day-Ahead Market cleared Energy

MW amount and the actual Resource output.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given RUC make whole

payment eligibility period is calculated as follows:

RUC Make Whole Payment Amount =

Maximum of [Either Zero or (RUC Make Whole Payment Cost Amount in the RUC Make Whole Payment

Eligibility Period + RUC Make Whole Payment Revenue Amount in the RUC Make Whole Payment Eligibility

Period – Uninstructed Resource Deviation Cost Disallowance – Non-Dispatchable Cost Disallowance –

Minimum Limit Cost Disallowance)]

(a) An Asset Owner’s RUC Make Whole Payment Cost Amount for each eligible Resource is equal to the

sum for all Dispatch Intervals in the RUC Make Whole Payment Eligibility Period of:

(i) Start-Up Offer used to make the commitment decision

(ii) No-Load Offers used to make the commitment decision, except when a combined cycle Resource

cleared in the Day-Ahead Market that was transitioned by the Transmission Provider into a different

configuration in Real-Time, in which case the positive difference between the hourly RTBM No-Load Offers

used to make the combined cycle Resource transition decision and the hourly Day-Ahead Market No-Load

Offers used to make the commitment decision is utilized;

(iv) The Transition State Offer used to make the transition decision for combined cycle Resources cleared in

the Day-Ahead Market that were transitioned by the Transmission Provider into a different configuration in

Real-Time;

(v) Energy cost at minimum output as calculated from the Energy Offer Curve used to make the

commitment decision except when a combined cycle Resource is cleared in the Day-Ahead Market that was

transitioned into a different configuration in Real-Time, in which case the cost shall be calculated based on the

positive difference between the Resource’s Real-Time Balancing Market applicable minimum limit and the

Resource’s Day-Ahead Market cleared quantity, where the Resource’s Real-Time Balancing Market applicable

minimum limit is equal to the lesser of the minimum limits submitted as part of the Real-Time Balancing

Market Resource Offer or the Resource’s actual output;

(vi) Energy cost above minimum output as calculated from the Energy Offer Curve that applied to the

current Dispatch Interval except when a combined cycle Resource is cleared in the Day-Ahead Market that was

transitioned into a different configuration in Real-Time, in which case the cost shall be calculated based on the

positive difference between the actual Resource output and the Resource’s Day-Ahead Market cleared Energy

quantity;

(vii) For Resources other than combined cycle Resources cleared in the Day-Ahead Market that were

transitioned into a different configuration in Real-Time, Operating Reserve cost associated with cleared Real-

Time Operating Reserve as calculated from the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-schedules are less than or equal to the

amount of Operating Reserve cleared shall be set equal to zero;

(viii) For combined cycle Resources cleared in the Day-Ahead Market that were transitioned into a different

configuration in Real-Time, the Operating Reserve cost associated with cleared Real-Time Operating Reserve

in excess of cleared Day-Ahead Market Operating Reserve as calculated from the Real-Time Operating Reserve

Offers except when self-scheduled Operating Reserve is less than or equal to the amount of Real Time

Operating Reserve cleared then the Operating Reserve cost shall be set equal to zero; and

(ix) For combined cycle Resources cleared in the Day-Ahead Market that were transitioned into a different

configuration in Real-Time and are transitioning into that configuration, the Operating Reserve cost adjustment

associated with cleared Day-Ahead Market Operating Reserve shall be equal to the maximum of (1) zero or (2)

the difference between the applicable Real-Time MCP and the applicable Day-Ahead MCP multiplied by the

cleared Day-Ahead Market Operating Reserve.; and

(x) For combined cycle Resources cleared in the Day-Ahead Market, the Energy adjustment associated with

cleared Day-Ahead Market Energy shall be equal to the maximum of (1) zero or (2) the difference between the

applicable Real-Time LMP and the applicable Day-Ahead LMP multiplied by the positive difference between

cleared Day-Ahead Market Energy and actual Resource output.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each eligible Resource is equal to

the sum for all Dispatch Intervals in the RUC Make Whole Payment Eligibility Period of:

(i) Dispatch Interval revenue associated with Energy calculated by multiplying actual Dispatch Interval

Energy output, in MW, by Real-Time LMP, except that for combined cycle Resources cleared in the Day-

Ahead Market that were transitioned into a different configuration in Real-Time, Dispatch Interval revenue

associated with Energy is equal to Real-Time LMP multiplied by one-twelfth of the positive difference between

actual Dispatch Interval Energy output, in MW, and Energy cleared on that Resource in the Day-Ahead Market;

(ii) the sum of the revenues calculated under Section 8.6.2, 8.6.3 and 8.6.4 of this Attachment AE for that

eligible Resource;

(iii) Energy revenue associated with payments made under Section 8.6.6 of this Attachment AE; and

(iv) amounts associated with settlement made under Section 8.6.15 of this Attachment AE.

(c) An Asset Owner’s Uninstructed Resource Deviation Cost Disallowance, Non-Dispatchable Cost

Disallowance, or Minimum Limit Cost Disallowance is equal to the positive difference between the Resource’s

Energy cost at actual output as calculated from the Resource’s current Dispatch Interval Energy Offer Curve

and the Resource’s Energy cost at the Resource’s economic operating point as calculated from the Resource’s

current Dispatch Interval Energy Offer Curve.

(d)A Resource’s economic operating point is the MW output where the cost on the Resource’s current Dispatch

Interval Energy Offer Curve is equal to the Real-Time LMP for that Resource.

SPP Criteria

SPP Business Practices

ECC MWP Challenge

Overlapping MWPs

Overlapping MWPs Pre-ECC Logic

• No Overlapping MWPs between DAMKT and RT – Based on the current implementation, it is possible for

Settlements to receive data such that DAMKT and RT MWP periods appear to overlap This is related to Current Operating Plan (COP) management

and is not indicative of a defect.

– Since the Resource was already made whole in the DAMKT, Settlements ignores the RT commitment information where an overlap exists in the COP data.

ECC MWP Challenge

• Current ECC logic allows the RUC processes to move an ECC Resource to a higher Configuration in an already committed period of time – Higher Configuration is defined as having an emergency

max greater than or equal to committed configuration.

• This would lead to scenario where overlapping MWPs between DAMKT and RT would seem appropriate

ECC MWP Example

Three Options Overlap:

1. Only Make Whole to Costs in DAMKT

2. Do not allow SPP to move ECC to higher Configuration in already committed period

3. Make Resource whole to incremental costs due to RT commitment decision

Weighing the Options Option Pros Cons

1. Only DAMKT MWP • Matches pre-ECC implementation

• Simple Approach for Settlements

• Market more efficient

• ECC Resources not made whole to all costs

2. No Incremental RT Commitment Decisions

• Very Simple for all systems • No Overlapping ECC

• Market less efficient

3. Make ECC Resource Whole to DAMKT Costs and Incremental RT Costs

• Market more efficient • ECC Resources made

whole to all costs

• More complicated

• SPP believes that Option 3 above is the correct approach for dealing with overlapping MWPs for ECC Resources.

• SPP will submit comments related to this for September MWG.

ECC Supplemental Contingency Reserve

Offline SUPP

ECC Clearing Offline Supplemental CR

• RR112 states that Offline SUPP may only be offered for one Resource.

– This was to address known performance issues that exist when allowing MCE SCUC to make this determination

• At August MWG, Question was asked why can’t an ECC Resource clear offline SUPP on a higher configuration than what is currently online.

– SPP determined that MCE would likely be able to support this without significant performance impacts as long as only one configuration is offered to clear offline SUPP when no configurations are online.

• If all ECC configurations offline: – Only one ECC Resource

may offer offline SUPP for a given Operating Hour. Maximum Quick-Start

Response Limit (MW) should only be submitted for one Configuration per Operating Hour

• If an ECC configuration is committed: – Allow higher ECC

configuration to clear offline SUPP Need new offer

parameter in Transition Data that represents amount of offline SUPP that my be cleared due to specific FROM > TO transition.

Offline SUPP clearing for ECC Resources

Min Limit Change Request

• SPP Supports non-zero Regulation min for DVERs offering/providing regulation service

• SPP does not support non-zero economic minimums for all other situations

Overview – Min Limit

• Does not reflect true capability of DVER

• Will reduce amount of available dispatchable range in Real-Time

• Reliability concern for both transmission constraints and Max Gen situations – Would force operators to manage through OOMEs

Inequitable

Time Consuming

Non Zero Minimum Issues

• Update software to better handle current limitations

• Use lower ramp rate to account for rough blocks in controllability

How to Handle Issues Raised

Reload Ramp Rate Limit

• The 20% threshold was established in accordance with the traditional threshold on RSS events. – SPP has traditionally absorbed up to 50MW without adverse local or regional

reliability impacts, therefore in the design of the Marketplace, the 20% threshold was consistent with the step change of less than 50MW, which does not require an RSS event.

• Prevents System Oscillations due to wind

• Minimizes Down Ramp shortages when wind picks up

• Facilitates controlled release during congestion

• The magnitude of the release percentage is driven by reliability concerns.

Overview - DVER Ramp Constraint

• Wind can move very fast in the up and down direction

• These movements are not always the result of market instructions

• Difficult to forecast wind with these large swings

Overview - VER Large Ramp Rates

Wind Ramp Example

INITIALMW FORECASTMW

• Ramp Constraint provides controlled release

• Allows the market to reevaluate before full release

• Provides a safety net for wind forecast error

Overview – Benefits of Controlled Release

7/5/2015 4:30 7/5/2015 4:58 7/5/2015 5:27 7/5/2015 5:56 7/5/2015 6:25 7/5/2015 6:54 7/5/2015 7:22

DVER Release Example

EFFMAXLIMIT DISPATCHMW INITIALMW FOLLOWDISPATCH

Balancing Authority Reliability

• System Obligation = Load + NSI

• Intervals where Net Obligation is moving down – 95% of intervals will be 200 MW/Interval or less

Reliability – Anticipated Ramp Requirement

20.00%

40.00%

60.00%

80.00%

100.00%

120.00%

0 100 200 300 400 500 600

System Ramp Down Requirement

-400 -300 -200 -100 0 100 200 300 400

(Load + NSI) Delta Normal Distribution

• Average DVER curtailments 96.8 MW per interval – This would only give us 50% reliability

• 95% of intervals have curtailed MW of 310 MW or less

• Potential Impact of releasing these curtailed MW per interval – At 20% then .20*310 MW = 62 MW

– At 50% this would equate to 155 MW

Reliability – Anticipated Ramp Requirements

20.00%

40.00%

60.00%

80.00%

100.00%

120.00%

0 200 400 600 800 1000 1200

DVER Interval Curtailed MW

• Energy Ramp: 200 MW Obligation

• Regulation Down Ramp: – (20%) 62 MW DVERs + 150 MW Forecast Error + 130 MW Frequency = 342 MW

– (50%) 155 MW DVERs + 150 MW Forecast Error + 130 MW Frequency = 435 MW

Reliability – Anticipated Ramp Components

3/1/2014 6/9/2014 9/17/2014 12/26/2014 4/5/2015 7/14/2015

SPP System Solution Ramp Capability

UPREGCAPABILITY TOTALUPCAPABILITY

DOWNREGCAPABILITY TOTALDOWNCAPABILITY

Monthly Average Interval of DVER Curtailments

050001000015000200002500030000350004000045000

100150200250300350400450

Average Monthly DVER Ramp Constrained MWH

PARTIALRELEASE FULLRELEASE FOLLOWDISPATCH RELOADEDMWH RAMPCONSTRAINEDMWH DVERWINDCAPABILITYMWH

• Ramp Constrained MW = Effective Max – Dispatch • Effective Max = Lower(Actual MW, Forecast MW)

• Ramp Constrained MWH represent 0.17% of DVER online capability on average • The average constrained MWH*LMP is $218

• Less than the cost of 1 interval of ramp rate violation

• Controlled release of wind farms limited by a ramp rate value helps with reliability and BA obligations

• Any additional flexibility in the amount of the wind to reload may result in increase in regulation requirement

• In most cases wind farms are not limited by the system limited ramp, they are rather limited by their submitted ramp.

• Average constrained MW due to Ramp and its cost may be minimal compare to increase in ramp requirement.

Summary

Revision Request Comment Form

RR #:104 Date: 7/8/2015

RR Title: DVER Minimum Economic Operating Capacity Limit & Ramp Rate Requirement Change

SUBMITTER INFORMATION

Name: Amber Metzker Company: Xcel Energy Services Inc.

Email: Amber.L.Metzker@xcelenergy.com Phone: 303.571.6202

COMMENTS

This comment form is making a revision to the previous submitted ramp rate changes for the DVERs.

Objectives of Revision Request:

The purpose of this revision is to allow wind resources to submit a minimum economic operating capacity limit and minimum normal capacity operating limit to a value other than zero. The reason for this need is that wind farms with automatic operating capability (AGC) cannot be curtailed all the way to zero without going off of AGC. These resources need a way to submit the value they can obtain without going off AGC for more accurate representation of their actual dispatch capabilities.

In addition to changing the minimum economic operating capacity limit, Xcel felt the need to also change the ramping limitation set forth in the document. XES believes that this limit is too restrictive. XES believes that the regulation issue can be fixed by MPs working with the resources or SPP to discuss how the signal is sent or received. In many intervals the market dispatch would not be adversely impacted by a more rapid ramp rate and therefore the limit should not be enforced during all intervals. To work towards achieving a better ramp limitation for wind resources, the proposal below helps get to a less restrictive goal without removing the ramp limitation all together. XES still feels that this limitation should not be imposed on all hours.

All changes are highlighted in yellow.

PROPOSED REVISION Provide proposed modifications (redlined) to the revision request for which you are providing comments. Use language from the revision request and redline with your additional edits.

Market Protocols

4.2.2.5.5 Dispatchable Variable Energy Resources

The following rules apply to Resources registered as Dispatchable Variable Energy Resources (“DVER”):

(1) The Minimum Emergency Capacity Operating Limit, Minimum Economic Operating Capacity Limit and Minimum Normal Capacity Operating Limit submitted as part of the Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected;

(2) For DVERs with an Emergency Maximum Capacity Operating Limit of less than 200MW100MW, the maximum ramp rate between MW specified in the Ramp-Rate-Up Curve and Ramp-Rate Down Curve in the RTBM Resource Offer multiplied by 5 cannot exceed 40MW. For DVERs with an Emergency Maximum Capacity Operating Limit greater than or equal to 200MW, the maximum ramp rate between MW levels specified in the Ramp-Rate-Up Curve and Ramp-Rate-Down Curve in the RTBM Resource Offer multiplied by 5 cannot exceed 2050% of the DVER’s Emergency Maximum Capacity Operating Limit;

(3) For the RUC processes, the maximum operating limit shall be the lesser of the Emergency Maximum Capacity Operating Limit as specified in the DVER RTBM Offer and SPP’s output forecast for that DVER. DVERs for which SPP is calculating an output forecast are not eligible to receive RUC make whole payments as described under Section 4.5.9.8;

(4) For the Real-Time Balancing Market, DVER Dispatch Instructions are calculated assuming the DVER is dispatchable regardless of its Control Status. DVERs eligible to clear Regulation-Down must submit a Control Status of “Regulating” if capable of providing Regulation-Down. SPP will provide a dispatch flag to the DVER indicating whether or not the DVER should “follow” or “ignore” its Setpoint Instruction. Use of these dispatch flags in calculating Setpoint Instruction is described under Section 4.4.3.1. These flags are set as part of the RTBM solution as follows:

(a) The default value of the dispatch flag will be “ignore”. When the dispatch flag is “ignore”, the DVER’s maximum operating limit is set equal to the DVER’s actual output at the time of the current RTBM run;

(b) The dispatch flag will be set to “follow” if (i) the DVER is dispatched below its maximum operating limit or (ii) the DVER is cleared for Regulation-Down;

(5) For the Real-Time Balancing Market for the current RTBM run, if the dispatch flag is “follow” as set by the previous RTBM run, then the DVER’s maximum operating limit in each subsequent Dispatch Interval is set equal to either:

(a) The lesser of (i) SPP’s output forecast for that DVER or (ii) the DVER’s Emergency Maximum Capacity Operating Limit; or

(b) The Emergency Maximum Capacity Operating Limit as specified in the DVER Offer if the SPP output forecast is not available for that DVER; or

(c) SPP’s output forecast for that DVER if the Emergency Maximum Capacity Operating Limit: (i) Was not submitted in the DVER Offer; or

(ii) Was not updated in the Offer during the Operating Hour prior to the Operating Hour in which the Resource limit would apply but before the lead time described in Section 4.2.2; or

(iii) Exceeds the maximum physical rating of the DVER that was submitted at market registration.

Such maximum operating limit continues to be set as described above until such time that the Resource’s Dispatch Instruction is equal to the maximum operating limit, after which, the DVER’s maximum operating limit is calculated as described under (4)(a) above.

4.2.2.5.6 Non-Dispatchable Variable Energy Resources

The following rules apply to Resources registered as Non-Dispatchable Variable Energy Resources (“NDVER”):

(1) The Minimum Emergency Capacity Operating Limit, Minimum Economic Operating Capacity Limit and Minimum Normal Capacity Operating Limit submitted as part of the Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected;

(2) For the RUC processes, the maximum operating limit shall be as submitted in the Resource Offer, except that, for wind powered NDVERs, the lesser of the Resource Offer or SPP’s wind output forecast for that Resource shall be used to set the maximum operating limit;

(a) NDVERs for which SPP is calculating an output forecast are not eligible to receive RUC make whole payments as described under Section 4.5.9.8.

(3) For the Real-Time Balancing Market, the Resource’s Energy Offer Curve shall not apply and offer prices shall be assumed equal to zero for the purposes of calculating production costs relating to RUC make-whole payments and cost allocation thereof under Sections 4.5.9.8 and 4.5.9.10. The Resource must operate within Setpoint Instructions. The Setpoint Instructions will be an echo of actual SCADA output as updated every ten seconds. For NDVERs, the Control Status Mode is not required. If it is not provided, it will be set to Manual

SPP Tariff (OATT)

Attachment AE

4.1.2.4 Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Dispatchable Variable

Energy Resources using the same Offer parameters available to any other Resource,

except that:

(1) The Minimum Emergency Capacity Operating Limit submitted as part of the

Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW

The minimum operating limits specified in the Resource Offer must be equal to

(2) The maximum operating limits for use in the Day-Ahead RUC and the Intra-Day

RUC shall be calculated by the Transmission Provider as equal to the lesser of the

maximum operating limits submitted in the Resource Offer or the Transmission

Provider’s output forecast for that Resource to the extent that such output forecast

is available;

a) Dispatchable Variable Energy Resources for which the Transmission

Provider is calculating an output forecast are not eligible to receive RUC

make whole payments as described under Section 8.6.5 of this Attachment

(3) For the purposes of issuing Dispatch Instructions to Resources as described under

Section 4.1.2.4(6) of this Attachment AE, Dispatchable Variable Energy

Resources with a maximum capability of less than twoone-hundred (1200) MWs,

submitted ramp rates multiplied by five (5) cannot exceed forty (40) MWs;

(4) For the purposes of issuing Dispatch Instructions to Resources as described under

Section 4.1.2.4(6) of this Attachment AE, Dispatchable Variable Energy

Resources with a maximum capability of greater than or equal to twoone-hundred

(2100) MWs, submitted ramp rates multiplied by five (5) cannot exceed twenty

fifty percent (520%) of the maximum capability;

(5) For the RTBM, during times when the Transmission Provider issues a Dispatch

Instruction to a Dispatchable Variable Energy Resource to reduce output, the

Resource’s Setpoint Instruction shall be equal to the sum of the Resource’s

Dispatch Instruction and any Regulation-Down deployment, even if the Market

Participant has indicated that the Resource is not dispatchable;

(6) For the RTBM, during times when the Transmission Provider issues a Dispatch

Instruction to a Dispatchable Variable Energy Resource to increase output in

Dispatch Intervals immediately following a Dispatch Interval in which a Dispatch

Instruction was issued to reduce output as described in Section 4.1.2.4(5) of this

Attachment AE, the Transmission Provider shall calculate the Resource maximum

operating limit to be equal to:

(a) The lesser of the maximum operating limits submitted in the Resource

Offer or the Transmission Provider’s Dispatchable Variable Energy

Resource output forecast for that Resource to the extent the such forecast

is available, except that, the Transmission Provider’s output forecast for

the Resource shall be used for the maximum operating limits when: (i)

maximum operating limits have not been submitted; (ii) the maximum

operating limits submitted in the Resource Offer are more than thirty (30)

minutes old; or (iii) the maximum operating limits submitted in the

Resource Offer exceed the maximum physical rating of the Resource as

stated during market registration; or

(b) The maximum operating limits submitted in the Resource Offer if the

Transmission Provider’s Dispatchable Variable Energy Resource output

forecast for that Resource is not available.

The Transmission Provider shall continue to calculate such maximum operating

limits for each subsequent Dispatch Interval until the maximum operating limit is

equal to the lesser of the Transmission Provider’s Dispatchable Variable Energy

Resource output forecast for that Resource or the maximum operating limit

submitted in the Resource Offer, after which, the Dispatchable Variable Energy

Resource’s maximum operating limit shall be calculated as described in Section

4.1.2.4(7) of this Attachment AE.

(7) For the RTBM, during times other than those times described under Section

4.1.2.4(6) of this Attachment AE, the Resource’s maximum operating limit for

use in the current Dispatch Interval shall be equal to the Resource’s actual output

at the start of the Dispatch Interval and the ramping restrictions described under

Sections 4.1.2.4(3) and (4) of this Attachment AE shall not apply.

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-Dispatchable

Variable Energy Resources using the same Offer parameters available to any other

Resource, except that

(1) The Minimum Emergency Capacity Operating Limit submitted as part of the

Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW

The minimum operating limits specified in the Resource Offer must be equal to

(2) For the RTBM, the Resource’s Energy Offer Curve shall not apply;

(3) For the RTBM, the Resource’s Dispatch Instruction shall be equal to the

Resource’s actual output at the start of the Dispatch Interval and the Resources

must operate as non-dispatchable;

(4) Resource Energy Offer Curve prices shall be assumed equal to zero (0) for the

purposes of calculating production costs relating to RUC make whole payments

and cost allocation thereof under Sections 8.6.5 and 8.6.7 of this Attachment AE;

(5) For the RTBM, during times when it is necessary to issue a Manual Dispatch

Instruction to a Non-Dispatchable Variable Energy Resource to resolve an

Emergency Condition or reliability issue, the Transmission Provider will direct

the Resource to a specified MW output. In addition, the Transmission Provider

will issue the dispatch instruction to the Resource in accordance with Section

6.2.4 of this Attachment AE; and

(6) The maximum operating limits for use in the Day-Ahead RUC and the Intra-Day

RUC shall be calculated by the Transmission Provider as equal to the lesser of the

maximum operating limits submitted in the Resource Offer or the Transmission

Provider’s output forecast for that Resource to the extent that such output forecast

is available, otherwise the maximum operating limits shall be equal to those

submitted in the Resource Offer;

(a) Non-Dispatchable Variable Energy Resources for which the Transmission

Provider is calculating an output forecast are not eligible to receive RUC

make whole payments as described under Section 8.6.5 of this Attachment

SPP Criteria

SPP Business Practices N/A

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