southwest power pool market working group meeting … 8-28-15 minutes and attachments.pdfjim...
TRANSCRIPT
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
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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
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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 [email protected] (918) 599-2966 (918) 284-8702P Jim Flucke (V-Chair) KCPL [email protected] (816) 701-7836
Aaron Rome Midwest Energy [email protected] (785) 625-1431P Amber Metzker Xcel Energy [email protected] (303) 571-6202 (920) 650-2040P Ann Scott Tenaska [email protected] (817) 462-1514* Brad Johnston AECC [email protected]
Chris Lyons Exelon [email protected] (410) 470-2465Cliff Franklin Westar [email protected] (443) 226-7787
P Debbie James (Sec) SPP [email protected] (501) 614-3577P Kevin Galke City Utilities, Springfield [email protected] (904) 360-1460P Lee Anderson LES [email protected] (402) 467-7591P Matt Moore Golden Spread Electric Coop [email protected] (806) 379-7766
Mike Mushrush OMPA [email protected] Daney KMEA [email protected] (913) 660-0242Rick McCord EDE [email protected] (417) 625-5129 (402) 616-3522
P Rick Yanovich OPPD [email protected] (402) 514-1031P Ron Thompson NPPD [email protected] (402) 845-5202
Shawn McBroom OGE [email protected] (405) 239-0255 (405) 553-3267Valerie Weigel Basin Electric Power Co. [email protected] (701) 557-5430Aaron Doll EDE [email protected]
P Aaron Theisen RPM Access [email protected] Wangler Basin Electric Power Co. [email protected] Bigknife OGE [email protected] Cochran TNSK [email protected] Jordan Genscape [email protected] McKinnie MOPSC [email protected] (573) 522-8706Adam Schieffer MEAN [email protected] Sharma AEP [email protected] Smith SWPA [email protected] Joyce Basin Electric Power Co. [email protected] Bright WAPA [email protected] Taylor East Texas Coops [email protected] Adams Utilicast [email protected] McQueen SPP [email protected] Rukin JSS Law [email protected] Azanov Cargill [email protected] Busbee SPP [email protected] Wright SPP [email protected] Hayes SPP [email protected] George SECI [email protected] Wahrenberger Enel [email protected]
Market Working GroupAugust 28, 2015
Face to Face Conference
Amy Casavechia SPP [email protected] Jeffries AEP [email protected] Culham [email protected] Ferris BPU [email protected] Hall ACES [email protected] (317) 344-7151Andrew Hartshorn BETM [email protected] Vogel AEP [email protected] Holbert SPP [email protected] Hammond Midwest Ben [email protected] (917) 717-1842Anthony Lemaire TNSK [email protected] Lucas SPP [email protected] Tripathi Ventyx [email protected] Koppula Ventyx [email protected] Hoekman MREnergy [email protected] Stroope SPP [email protected] (501) 688-1792Barry Huddleston Clean Line [email protected] (832) 319-6358Barry Warren EDE [email protected] (417) 625-4234Bart Tsala The Kidiaga Group [email protected] (405) 896-5899Becky Gifford SPP [email protected] Stander OATI [email protected] Maher NMPP [email protected] Kinsella EDPR [email protected] Hume SPP [email protected] Miller Accenture [email protected] Watts Accenture [email protected] Grant Xcel Energy [email protected] (806) 378-2928Bill Leung BJLEUNG [email protected] Nolte SECI [email protected] (420) 272-5458Bill Olson Xcel Energy [email protected] Reid Climate Energy Project [email protected] (405) 816-5456
P Billy Cutsor MEAN [email protected] Yancey EPE Consulting [email protected] Erhardt BEPC [email protected] French Xcel [email protected] Burner Duke Energy [email protected] Tumilty AEP [email protected] Wittmeyer Longhorn Power [email protected] Hans MEAN [email protected] 402-474-4759Brenda Fite SPP [email protected] Fricano SPP [email protected] Lee Structure [email protected] Hebert PSI/EPV/KELSON/ETEC [email protected] (832) 663-1373Brent Hendrickson Nexant [email protected] (404) 276-9008Brent Wilcox SPP [email protected] (501) 688-8267Brett Hooton SPP [email protected] (501) 688-1684Brett Kruse Calpine [email protected] (713) 830-8732
Brian Gedrich Nextera [email protected] (512) 284-4168Brian Hurst GRDA [email protected] Skinner Tenaska [email protected] Moix SPP [email protected] Miller APSC [email protected] Rew SPP [email protected] Clark SPP [email protected] Wilson OGE [email protected] Tarwater CES LTD [email protected] Monroe SPP [email protected] Holly BP Energy [email protected] Shoemake OGE [email protected] Bumgarner Wright Talisman [email protected] Carrigan TEA [email protected] Cooper ETEC carrie.cooper@gdsassociates (770) 715-7189
P Carrie Dixon Xcel [email protected] Simpson Invenergy csimpson@inevenergy
P Casey Cathey SPP [email protected] (501) 614-3267Casey Strange OGE [email protected]
P Catherine Mooney SPP [email protected] Alonso OGE [email protected] Unrein KS Corp Comm [email protected] (785) 271-5176Chance Scott Xcel [email protected]
P Chandler Brown SECI [email protected] Cates SPP [email protected] Marshall ITC Transco [email protected] (248) 946-3276Chris Bevil Southern Power [email protected] Casale Iberdrola [email protected] Davis SPP [email protected] (501) 688-2546Chris Devon Michigan PSC [email protected] Giles TCEC [email protected] Jones Duke Energy [email protected] Lax SPP [email protected] (501) 614-3594Chris Matos GSEC [email protected] Matthes AEP [email protected] Standifer KCPL [email protected] Werner AEP [email protected]
P Chris Winburn INDN [email protected] Ziembko TEA [email protected] Nicolay Macquarie [email protected] Labij Acciona [email protected] Meyers WAPA [email protected] Payne SPP [email protected] Ireland AR PSC [email protected] Brown SPP [email protected] Savoy SPP [email protected] (501) 614-3590
Cody VandeVelde WR [email protected] Mehan Tenaska [email protected] Canezin Durable Power [email protected] Mosolf MISO [email protected] Lenihan OPPD [email protected] Trent AECI [email protected] Boyer SPP [email protected] Trent OGE [email protected] (405) 553-3687 (405) 550-5152Daniel Baker SPP [email protected] Harless SPP [email protected] Smith PSC MO [email protected] Wilson OGE [email protected] Almsted MCG Energy [email protected] (612) 240-9733Dave Charles ND PSC [email protected] Hines MISO [email protected] Osburn OMPA [email protected] Pettinger OPPD [email protected] Savage RES-Americas [email protected] Adamczyk KCPL [email protected] Charles ND PSC [email protected] Dan Power Settlements [email protected] Daniels SPP [email protected] Erickson AEP [email protected] (614) 583-7405David Hackett KEMA [email protected] (321) 600-1228David Hastings DHASTCO [email protected] (317) 217-9563David Hurtado SPP [email protected] Kays OGE [email protected] Kelley SPP [email protected] (501) 688-1671David Lee SPP [email protected] (501) 614-3333David Lemmons Xcel [email protected] Linton ITC-GP [email protected] (314) 341-5769David Marshall Southernco [email protected] Shaffer Wright Talisman [email protected] Smith Shell [email protected] Theobald OPPD [email protected] Roby JSS Law [email protected] Prater Oklahoma Corp Comm [email protected] (405) 521-6950Dena Giessmann SPP [email protected] Buffington KCPL [email protected] Reed Westar [email protected] Mosolf MCG Energy [email protected] Arthur SPP [email protected] Janicki Edison Mission [email protected] (312) 583-6028Dick Kahle LES [email protected] Kolkmann FERC [email protected] Dietz NPPD [email protected]
Dirk Ludwig NPPD [email protected] Gulley SECI [email protected] Clark SPP [email protected] Robinson KCPL [email protected] Watson SPP [email protected] Toro INV Energy [email protected] O'grady Argus [email protected] Nassar Ventyx [email protected] Whorley TNSK [email protected] Solano MISO Energy [email protected]
P Eric Alexander GRDA [email protected] (918) 824-7245Eric Barreveld APX [email protected] Brooks SPP [email protected] Cullum SPP [email protected] Lorimer Endure Energy [email protected] Inertia Power [email protected] Winsand DATC [email protected]
P Erin Cathey SPP [email protected] Esat Guney SPP [email protected]
Farris Wallace Southernco [email protected] Rahimi OATI [email protected] (612) 360-1654Frank Bristol Acciona [email protected] Harris Southernco [email protected] (205) 4827202Garrett Crowson SPP [email protected]
P Gary Cate SPP [email protected] Clear OGE [email protected] Hoffman WAPA [email protected] Rosenwald The Glarus Group [email protected] Shannon AEP [email protected]
P Gay Anthony SPP [email protected] (501) 688-1722Gayle Freier SPP [email protected] Crowson SPP [email protected] Coventry Trade Wind [email protected] Hocker SWPA [email protected]
P Geoffrey M Rush Oklahoma Corp Comm [email protected] Fee AEP [email protected] Kelly Accenture [email protected]
P Gerald Deaver Xcel [email protected] Williams SPP [email protected] Ugalde SPP [email protected] Murphy Xcel [email protected]
P Ginny Watson SPP [email protected] Wilson ITC Transco [email protected] Wilkerson Westar [email protected] Adams Adams Wind [email protected] Pakela DTE Energy [email protected]
Guadalupe Vazquez Acciona [email protected] Lao AEP [email protected] McKewon GRDA [email protected] Hammer SPP [email protected] (501) 688-8248Harry Skilton Director [email protected] Panchal XO Energy [email protected] Shah SPP [email protected] Starnes MJMEUC/CUS [email protected] Haas Monitoring Analytics [email protected] Foo KCPL [email protected] Saini Macquarie [email protected] Clark NEE [email protected]
P Jack Madden GDS Associates [email protected] King Constellation [email protected] Justice Aces Power Marketing [email protected] Springman Aces Power Marketing [email protected] Langthorn OGE [email protected] Thomas SPPJames Fife PSI/EPV/KELSON/ETEC [email protected] (281) 297-5406James Lewis Noble Power [email protected] Lemley SPP [email protected] (501) 614-3575James Meitner Westar [email protected] Sanderson KCC [email protected] (785) 271-3159James Sweatt Southernco [email protected] Johnson NMPP [email protected] Wheeler GRDA [email protected] Bagnall SWPA [email protected]
P Jared Greenwalt SPP [email protected] Woodcock Nextera [email protected] Friddle SPP [email protected] Bailey OGE [email protected] Chaplin OCC [email protected] Davis SPP [email protected] (501) 614-3374Jason Doerr Basin Electric Power Co. [email protected] (701) 557-5388Jason Fix LES [email protected] Hebert PCI [email protected] Minalga INV Energy [email protected] Robison SPP [email protected] (501) 688-1711Jason Russell SPP [email protected] Smith SPP [email protected] Tanner SPP [email protected] Terhune SPP [email protected] Caspary SPP [email protected] Goldman BETM [email protected] Sher FERC [email protected] DiSciullo Wright Talisman [email protected]
Jeff Knottek City Utilities, Springfield [email protected] Riles Enel [email protected] Flandermeyer KCPL jennifer.flandermeyer.comJennifer Swierczek SPP [email protected] Weatherford GRDA [email protected] Wofford CUS [email protected] Hodges TEA [email protected] Shipman Structure Group [email protected] Verzosa SPP [email protected] Purtee KBPU [email protected] Ohmes KCBPU [email protected] (913) 573-6816Jerry Stone SPP [email protected]
P Jerry Tielke MREnergy [email protected] Collins Xcel [email protected] Kasparek LES [email protected] Zhang CES-LTD [email protected]
P Jill Coffey KCPL [email protected] Jones MEAN [email protected] Fort TEA [email protected]
P Jim Gonzales SPP [email protected] Guidroz Supervisor of Tariff Administration [email protected] (501) 614-3900Jim Gunnell SPP [email protected] Hotovy NPPD [email protected] Jacoby AEP [email protected] Krajecki Customized Energy Solutions [email protected] Stevens PSI/EPV [email protected] (713) 253-9396JJ Guo AEP [email protected] Woods SPP [email protected] Sundsted WAPA [email protected] Byers SPP [email protected] Bumgarner SPP [email protected] Ghormley SPP [email protected] Lang LES [email protected] (402) 473-3401Joe Smith Joe [email protected] Taylor Xcel Energy [email protected] (303) 571-7462Joe Waszak OPPD [email protected] Bearden XO Energy [email protected] Schrepel BEPC [email protected] Allen Aces Power [email protected] Allen CUS [email protected]
P John Bell KCC [email protected] (785) 271-3139John Boshears CUS [email protected] Fernandes ResAmericas [email protected] Grotzinger MPUA [email protected] Harvey Exelon [email protected] (515) 221-5717John Henry [email protected]
John Holloway AEP [email protected] Hyatt SPP [email protected] Knofczynski Basin Electric Power Co. [email protected] (605) 270-1335John Krajewski Energy Consulting [email protected] (402) 440-0227
P John Luallen SPP [email protected] Olsen WR [email protected] Seck KMEA [email protected] Snyder SPP [email protected] Stephens City Utilities [email protected] (417) 831-8470John Sturm Aces Power Marketing (APM) [email protected] (317) 696-9031
P John Tennyson City Utilities [email protected] Varnell Tenaska [email protected] (817) 462-1037John Weber MREnergy [email protected] Olson MCG Energy [email protected] (615) 253-8820Jon Sunneberg NPPD [email protected] Ferrari Wartsila [email protected] Weinstein Chase [email protected] Roper KCPL [email protected] (816) 556-2038Judith Judson McQueeney CES [email protected] Brint Platts [email protected] Bittle SPP [email protected]
P Julie Gerush SPP [email protected] Cochran SPP [email protected] Coleman SPP [email protected] Howland Southernco [email protected] Hollandsworth GSEC [email protected] Pierce BP Energy [email protected] Sidman BP Energy [email protected] Prewitt SPP [email protected] (501) 614-3518Kathy Schuerger Xcel Energy [email protected] Seiverling CES-LTD [email protected] Sussen Basin Electric Power Co. [email protected] (701) 557-5154Katy Onnen KCPL [email protected] Tynes ETEC/GDS [email protected] (850) 490-2874Kelli Graff Xcel [email protected] Donald Utilicast [email protected] Laughlin Tres Amigas [email protected] (484) 524-5052Ken Quimby SPP [email protected] Rutter Basin Electric Power Co. [email protected] (701) 557-5390Kent Feliks AEP [email protected] Szarkowski BEPC [email protected] Bates SPP [email protected] Carter Duke-Energy [email protected] Drachenberg Calpine [email protected] Galke CUS [email protected] Kingsley MDU [email protected]
Kevin Shipp Ameren [email protected] Warren SPP [email protected] Sullivan WFEC [email protected] Van Brimer SPP [email protected] Badenhop BEPC [email protected] Fox AEP [email protected] Basterra Acciona [email protected] Rodriguez Electric Power Engineers/Wind Coalition [email protected] (254) 399-8676 (512) 382-6700Kristy Tackett Empire [email protected] Agrawal Nexant [email protected] (972) 369-7572Lanny Nickel SPP [email protected] (501) 614-3232
P Larry HollowayLaura Manz Tres Amigas [email protected] (858) 354-8333Lauren Krigbaum SPP [email protected] Arnett Xcel [email protected] Robinson SPP [email protected]
P Leeann Poteet SPP [email protected] Bingham SPP [email protected] Sink SPP [email protected] Lyons SPP [email protected] Noailles SPS [email protected] (303) 571-2794Linda Fellone SPP [email protected] Caserta SPP [email protected] Flowers-Davis BEPC [email protected]
P Lisa Szot Enel [email protected] Linke WAPA [email protected] Prichard OPPD [email protected] Lindekugel SPP [email protected] Frisk-Thompson BEPC [email protected] Bailey SPP [email protected] Sciaccaluga Enel [email protected] Haner OPPD [email protected] Larson Balch [email protected] Wilkes Physical Systems Integration [email protected] (713) 443-4026 (281) 297-5449Lyudmila Siegel Constellation [email protected] Booker OMPA [email protected] Ganoothula TEA [email protected] Sailors OPPD [email protected]
P Marisa Choate SPP [email protected] (501) 688-1707Mark Buchholz WAPA [email protected] Foreman TNSK [email protected] Holler TNSK [email protected] McGrail EGPNA [email protected] Messerli WAPA [email protected]
P Mark Trumble OPPD [email protected] Watson Platts [email protected]
Mark Wiggins PCI [email protected] Wagner ICT Transco [email protected] Parizek CPV [email protected] Knight SPP [email protected] Jo Montoya Xcel Energy [email protected] (303) 571-7191Mary Lou Walker Charter [email protected] Binette Wright Talisman [email protected] Cupps Westar [email protected] Egger NPPD [email protected] Harward SPP [email protected] Hazelwood TEA [email protected] Johnson TEA [email protected] (904) 665-0388Maureen Ochola GDS Associates [email protected] Thomas Public State of Texas [email protected] Assadian OATI [email protected] (925) 202-5017Mei Cheong CCI [email protected] Watts Southernco [email protected]
P Micha Bailey SPP [email protected] (501) 688-2522Michael Billinger Midwest Energy [email protected] Blackwell ACES Power [email protected] Daly SPP [email protected] Desselle SPP [email protected]
P Michael Erbrick MICS [email protected] (281) 687-0609Michael Hutson RES Americas [email protected]
P Michael Massery AECC [email protected] Nesmith Basin Electric Power Co. [email protected] Ray SPP [email protected] Trenary TNSK [email protected] Berlinski Beacon Power [email protected] Buyce CUS [email protected] Chapman Kelson Energy [email protected] Collins OGE [email protected]
P Mike Grimes EDP Renewables [email protected] (713) 265-0316Mike Hood AECC [email protected] Mathsen Cargill [email protected] Moltane ITC [email protected] (248) 946-3093Mike Oliver LES [email protected] Radecki WAPA [email protected] Riley SPP [email protected] Sheriff OGE [email protected] Wech SWPA [email protected] Elmore Xcel Energy [email protected] Williams WFEC [email protected] Strain KCPL [email protected] Baugh SPP [email protected] Vempati Nexant [email protected]
Natalie McIntire [email protected] Brown WFEC [email protected] Case Aces Power Marketing (APM) [email protected] Robertson SPP [email protected]
P Nick Parker SPP [email protected] (501) 614-3574Nicole King OCC [email protected] Wagner SPP [email protected] Sidhom Inertia Power [email protected] Conover TEA [email protected] Ghomsi MOPSC [email protected] Martino EDF [email protected] (612) 618-6272Oliver Burke Entergy [email protected] (601) 985-2613Pamela Newberry OPPD [email protected] Bourne SPP [email protected] Canfield XO Energy [email protected] 609-423-8004Pat Hayes Ameren [email protected] McGarry TEA [email protected] (904) 993-9511Pat Mosier ARPSC [email protected]
P Patti Kelly SPP [email protected] (501) 614-3381Patty Denny KCPL [email protected] Harrell DC Energy [email protected] Dietz Westar paul.a.dietz@ westarenergy.comPaul Krebs KCPL [email protected] Mahlberg INDN [email protected] Malone NPPD [email protected] Oleary YUMAELEC [email protected] Kinney WAPA [email protected] (605) 882-7560 (605) 228-6758Peter Colussy Xcel [email protected] Tucker SPP [email protected] Cox AEP [email protected] Stiles Acciona [email protected] (312) 673-3027Philip Bruich SPP [email protected] Vallejo Structure Group [email protected] Phu KCPL [email protected] Bernard SPP Board of Directors [email protected] Patel ITC Transco [email protected] (248) 946-3465Rachel Hulett SPP [email protected] Nagarsheth Denver Energy [email protected] Nelli AEP [email protected]
P Raleigh Mohr SPP [email protected] Gerving MDU [email protected] Root GRDA [email protected] Karnik Hartigen [email protected] Kershaw ITC Transco [email protected]
P Rebecca Atkins MPUA [email protected] Gillespie FERC [email protected]
Rebecca Hohnstein LES [email protected] Sanders SPP [email protected] Garza AEP [email protected] Robinson Calpine [email protected] Deming Citi [email protected] Dillon SPP [email protected] (501) 614-3228Richard Miller Structure Group [email protected] Kosch LES [email protected] Mueller OPPD [email protected] Running [email protected] Finkbeiner SPP [email protected] Jones GRDA [email protected] Janssen Kelson Energy [email protected] Pennybaker AEP [email protected] Pick NPPD [email protected]
P Robert Safuto Customized Energy Solutions [email protected] (917) 446-2579Robert Shields AECC [email protected] Stillwell IPL [email protected] (813) 325-7482Robert Walker Cargill [email protected] (952) 984-3747Roberto Rösner Enel [email protected] Chartier SECI [email protected] Boyer Xcel Energy [email protected] Klusmeyer WFEC [email protected] (405) 247-4275
P Roy True Aces Power Marketing (APM) [email protected] (317) 695-4146 (317) 695-4146Russ McRae Alstom [email protected]
P Russell Quattlebaum SPP [email protected] Burkhalter Citi [email protected] Hicks SPP [email protected] Kirk AEP [email protected] Turner CUS [email protected] Stock AEP [email protected] Ellis SPP [email protected] Mall City of Denton [email protected] Baidwan Lspower [email protected] Ksarawgi AEP [email protected]
P Sarah Pettus Wind Coalition [email protected] Cassaday TNSK [email protected] Shepherd ABB [email protected] Smith SPP [email protected] Cochran DC Energy [email protected] (512) 971-8767Seth Hayik Monitoring Analytics [email protected] Hossain EDE [email protected] Gupta SPP [email protected] Jensen OPPD [email protected] Brown SPP [email protected]
P Shawn Geil KEPCo [email protected]
P Shawnee Claiborn-Pinto PUCT [email protected] (512) 936-7388Shelly Trammell WFEC [email protected] Elliott [email protected] Hamilton SPP [email protected] Sundar Denver Energy [email protected]
P Sonya Hall SPP [email protected] Davis SPP [email protected] Gaw Wind Capital Group [email protected] (573) 645-0727Steve Haun LES [email protected] Maestrauzi Genscape [email protected] 817-790-0927Steve McDonald Aces Power Marketing (APM) [email protected] (317) 344-7113Steve Mckee AEP [email protected] Purdy SPP [email protected] Terelmes PCI [email protected] White SPP [email protected] Harrington GSEC [email protected] Larry Tenaska [email protected] Rein Boston Pacific [email protected] Polk SPP [email protected] Quinn Westar [email protected] Barker SPP [email protected] Williams SPP [email protected] Roach SPP [email protected] Tims SPP [email protected] Wendlandt WR [email protected]
P Terry Gates AEP [email protected] (614) 716-6232 (614) 361-5235P Terry Volkmann
Terry Wright EDE [email protected] Kentner SPP [email protected] Flanagan TEA [email protected] Herr SPP [email protected]
P Tim Hooker GRDA [email protected] Larson Host Integrity Systems [email protected] Miller SPP [email protected] Phillips SPP [email protected] Murphy AEP [email protected] Wang AEP [email protected] Sandoz OPPD [email protected] Pilcher Aces Power Marketing (APM) [email protected] Burke Aces Power Marketing (APM) [email protected] (512) 788-4901Tom DeBaun KCC [email protected] Dunn SPP [email protected] Fritsche SPP [email protected] Hestermann Sun Flower [email protected] Kleckner RTO Insider [email protected] Mayhan OPPD [email protected]
Tom Paff Duke Energy [email protected] Saitta KMEA [email protected] Alexander SPP [email protected] Brill TNSK [email protected] Delacluyse PCI [email protected] (405) 326-1496Travis Allen EnBridge [email protected] A. Campbell OCC [email protected] Carlson JP Morgan [email protected] Fleming SAIC [email protected] (713) 345-0753Troy Via OPPD [email protected] (804) 318-0250Turner Crow SPP [email protected] Mitchell SPP [email protected] Wolford TEA [email protected] (904) 360-1460Tyson Boatler GSEC [email protected] Barros [email protected] Bosquez CES-LTD [email protected]
P Vince Vandaveer CUS [email protected] Musco Boston Pacific [email protected] Kapur Electric Power Engineers/Wind Coalition [email protected] (512) 382-6700W. H. Thompson AEP [email protected] Cecil MOPSC [email protected] Shumate Shumate & Associates [email protected] (512) 496-7704Walt Yeager Duke Energy [email protected] Camp Accenture [email protected] (856) 204-0298Wenchun Zhu Wind Capital Group [email protected] Drost Alstom [email protected] (318)348-0014Will Johnson Adapt 2 Solutions [email protected] Tootle SPP [email protected] Lally AEP [email protected] Mei Dufossat [email protected] Bahbaz SPP [email protected] Sutjandra TEA [email protected] Edstrom Cargill [email protected] Hager OGE [email protected] Sharp SPP [email protected] (501) 688-2548
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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 [email protected]
From: Brad Johnston [mailto:[email protected]] 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 [email protected]
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
2
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
3
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
4
SPP RTO JOU COMBINED RESOURCE IMPACT ANALYSIS
5
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)
6
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
7
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
8
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
9
SPP MMU JOU COMBINED RESOURCE IMPACT ANALYSIS
10
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.
11
Process – SPP MMU (equal costs)
12
A, 80%
B, 10%
C, 10%
Ownership Share
A, 60%
B, 5%
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.
13
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.
14
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: [email protected] 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
0
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 ,
0)
* (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i )
ELSE
DaCcSpin5minAmt a, s, h = 0
(a.1.1) DaCcSpinAdjHrlyAmt a, s, h =
Max ( 0, ∑i
DaCcSpinAdj5minAmt a, s, i )
(a.2) IF RtTranistionStateFlg a, s, i = 1 THEN
DaCcSuppAdj5minAmt a, s, i =
IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )
Max(DaTranisitionState5minFlg a, s, i, c -∑c
RtTranisitionState5minFlg a, s, i, c ,
0)
* (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i )
ELSE
DaCcSupp5minAmt a, s, h = 0
(a.2.1) DaCcSuppAdjHrlyAmt a, s, h =
Max ( 0, ∑i
DaCcSuppAdj5minAmt a, s, i )
(b) DaMwpRevHrlyAmt a, h, s, c = DaClrdComStatHrlyFlg h, s, c
* [ ( DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h )
+ DaRegUpHrlyAmt a, h, s + DaRegDnHrlyAmt a, h, s
+ ∑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.
Variable Unit Settlement Interval
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.
Variable Unit Settlement Interval
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.
Variable Unit Settlement Interval
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.
Variable Unit Settlement Interval
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 ] }
+∑h
( 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 )
THEN
RtIncrEn5minAmt a, s, i = 0
ELSE
#RtIncrEn5minAmt a, s, i = ∫y
x
CurveOffer Energy Dispatched As RTBM
Where:
X = Max (ABS (DaClrdHrlyQty a, s, h ), RtEffMin5minQty a, s, i )
AND
IF ControlStatus5minFlg a, s, i = “Regulating”
THEN
RtEffMin5minQty a, s, i = Min (
RtComMinRegCapOL5minQtya, s, i ,
RtDispMinRegCapOL5minQtya, s, i ,
Max (0, (-1) * RtBillMtr5minQtya, s, i )
ELSE
RtEffMin5minQty a, s, i = Min (
RtComMinEconCapOL5minQtya, s, i ,
RtDispMinEconCapOL5minQtya, s, i ,
Max (0, (-1) * RtBillMtr5minQtya, s, i )
AND
Y = Max ( (-1) * RtBillMtr5minQtya, s, i , 0)
(a.2) IF ABS (DaClrdHrlyQty a, s, h ) < RtEffMin5minQty a, s, i
THEN
#RtMinEn5minAmt a, s, i = ∫y
x
CurveOffer Energy Committed As RTBM
Where:
X = DaClrdHrlyQty a, s, h
Y = RtEffMin5minQty a, s, i
ELSE
RtMinEn5minAmt a, s, i, c = 0
(a.3) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, i
THEN
RtRegUpAvail5minAmt a, s, i=
( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z
DaRegUpHrlyQty a, z, s, h] )
* RtRegUpOffer a, s, i, )
- ( RtRegUpMileOffer5minPrc a, s, i * RtRegUpExcessMile5minQty a, s, i )
ELSE
RtRegUpAvail5minAmt a, s, i, =0
IF RtTranistionStateFlg a, s, i, c = 1 THEN
RtRegUpAvail5minAmt a, s, i, c =
DaRegUpHrlyQty a, z, s, h
* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h )
ELSE
RtRegUpAvail5minAmt a, s, i, c = RtRegUpAvail5minAmt a, s, i = 0
(a.4) If RtRegDn5minQty a, s, i > RtFixedRegDn5minQty a, s, i
THEN
RtRegDnAvail5minAmt a, s, i =
( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z
DaRegDnHrlyQty a, z, s, h] )
* RtRegDnOffer a, s, i, )
- ( RtRegDnMileOffer5minPrc a, s, i * RtRegDnExcessMile5minQty a, s, i )
ELSE
RtRegDnAvail5minAmt a, s, i =0
(a.5) If RtOffSpin5minQty a, s, i > RtFixedSpin5minQty a, s, i
THEN
RtSpinAvail5minAmt a, s, i, c =
Max ( 0, [ RtOffSpin5minQty a, z, s, i - ∑z
DaOffSpinHrlyQty a, z, s, h] )
* RtSpinOffer a, s, i, c
ELSE
RtSpinAvail5minAmt a, s, i, =0
(a.6) If RtOffSupp5minQty a, s, i > RtFixedSupp5minQty a, s, c, i
THEN
RtSuppAvail5minAmt a, s, i, c =
Max ( 0, [ RtOffSupp5minQty a, z, s, i - ∑z
DaOffSuppHrlyQty a, z, s, h] )
* RtSuppOffer a, s, i, c
ELSE
RtSuppAvail5minAmt a, s, i, =0
(a.7) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i
THEN
RtRegUpforCRSubAvail5minAmt a, s, i, c
= RtRegUpforCRSub5minQty a, i, s * RtRegUpCapOffer a, s, i
ELSE
RtRegUpforCRSubAvail5minAmt a, s, i, c = 0
(a.7.1) RtRegUpforCRSub5minQty a, s, i =
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 =
(-1)
* ( ( 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 =
(-1)
*( ( 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 =
∑i
( 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 )
THEN
#RtURDAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c
* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i )) / 12
ELSE
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 )
THEN
#RtDesiredEn5minAmt a, s, i = RtIncrEn5minAmt a, s, i
ELSE
#RtDesiredEn5minAmt a, s, i = ∫y
x
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
THEN
#RtStatusAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c
* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i )) / 12
ELSE
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
THEN
#RtLimitAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c
* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i )) / 12
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
THEN
#RtLimitAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c
* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i )) / 12
ELSE
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 ) ]
ELSE
RtCcRegUpAdjHrlyAmt a, s, h, c = 0
(g.1) RtCcRegUpAdj5minAmt a, s, i, c =
(DaRegUpHrlyAmt a, s, h / 12 + RtRegUp5minAmt a, s, i )
ELSE
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 ) ]
ELSE
RtCcRegDnAdjHrlyAmt a, s, h, c = 0
(h.1) RtCcRegDnAdj5minAmt a, s, i, c =
(DaRegDnHrlyAmt a, s, h / 12 + RtRegUp5minAmt a, s, i )
ELSE
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 )
ELSE
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 )
ELSE
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
THEN
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
ELSE
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
Page 35 of 71
The above variables are defined as follows:
Variable
Unit
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.
Page 36 of 71
Variable
Unit
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.
Page 37 of 71
Variable
Unit
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.
Page 38 of 71
Variable
Unit
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.
Page 39 of 71
Variable
Unit
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.
Page 40 of 71
Variable
Unit
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.
Page 41 of 71
Variable
Unit
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%.
Page 42 of 71
Variable
Unit
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.
Page 43 of 71
Variable
Unit
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.
Page 44 of 71
Variable
Unit
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.
Page 45 of 71
Variable
Unit
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.
Page 46 of 71
Variable
Unit
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
$/MW Dispatch Interval
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
$/MW Dispatch Interval
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).
Page 47 of 71
Variable
Unit
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.
Page 48 of 71
Variable
Unit
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.
Page 49 of 71
Variable
Unit
Settlement Interval
Definition
RtLmp5minPrc s, i
$/MWh
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.
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Variable
Unit
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.
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Variable
Unit
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.
…
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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.
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(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
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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
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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.
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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
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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
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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.
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(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
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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
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• 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;
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(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.
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(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
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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,
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(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.
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(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
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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
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 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.
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(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
Page 69 of 71
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)]
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(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
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(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.
2
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
3
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
4
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
MWPs
• 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
5
• 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.
7
• 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
8
Min Limit Change Request
2
• 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
3
• 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
4
• Update software to better handle current limitations
• Use lower ramp rate to account for rough blocks in controllability
How to Handle Issues Raised
5
Reload Ramp Rate Limit
6
• 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.
7
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
8
Overview - VER Large Ramp Rates
0
20
40
60
80
100
120
140
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
9
Overview – Benefits of Controlled Release
0
50
100
150
200
250
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
10
• System Obligation = Load + NSI
• Intervals where Net Obligation is moving down – 95% of intervals will be 200 MW/Interval or less
11
Reliability – Anticipated Ramp Requirement
0.00%
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
12
Reliability – Anticipated Ramp Requirements
0.00%
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
13
Reliability – Anticipated Ramp Components
0
200
400
600
800
1000
1200
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
14
Monthly Average Interval of DVER Curtailments
050001000015000200002500030000350004000045000
050
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
15
Page 1 of 6
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: [email protected] 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;
Page 2 of 6
(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”):
Page 3 of 6
(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
zero;
(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
AE.
Page 4 of 6
(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.
Page 5 of 6
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
zero;
(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
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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
AE.
SPP Criteria
N/A
SPP Business Practices N/A